132625592
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.
130275783
Evaluation Status and Development Trend of Unconventional Gas in Coal Measure
There is practical necessity of comprehensive geological research and exploration and development of coal- bearing basin because of extensive developed coal and symbiosis multiple energy resources in coal measure. There is a long coal accumulating time,widely distributed coal measure strata,and large coal accumulating area in China. Characteristics of coal measure strata like high organic matter content,strong cyclicity of the sediments,main kerogen of Ⅲ type,rich terrigenous materials,and multi- period teclonothermal evolution set a good foundation for development of unconventional gas in coal measure strata. Aiming at the basic characteristics and research status of unconventional gas in coal measure strata like coalbed methane,shale gas,tight sandstone gas and natural gas hydrates,the mode of symbiotic occurrence of unconventional gas was proposed,and several scientific issues and development trend for comprehensive study were discussed. The research can provide a theoretical basis and guide direction for geology and development of unconventional gas in China.
67851477
Fractured shale-gas systems
The first commercial United States natural gas production (1821) came from an organic-rich Devonian shale in the Appalachian basin. Understanding the geological and geochemical nature of organic shale formations and improving their gas producibility have subsequently been the challenge of millions of dollars worth of research since the 1970s. Shale-gas systems essentially are continuous-type biogenic (predominant), thermogenic, or combined biogenic-thermogenic gas accumulations characterized by widespread gas saturation, subtle trapping mechanisms, seals of variable lithology, and relatively short hydrocarbon migration distances. Shale gas may be stored as free gas in natural fractures and intergranular porosity, as gas sorbed onto kerogen and clay-particle surfaces, or as gas dissolved in kerogen and bitumen. Five United States shale formations that presently produce gas commercially exhibit an unexpectedly wide variation in the values of five key parameters: thermal maturity (expressed as vitrinite reflectance), sorbed-gas fraction, reservoir thickness, total organic carbon content, and volume of gas in place. The degree of natural fracture development in an otherwise low-matrix-permeability shale reservoir is a controlling factor in gas producibility. To date, unstimulated commercial production has been achievable in only a small proportion of shale wells, those that intercept natural fracture networks. In most other cases, a successful shale-gas well requires hydraulic stimulation. Together, the Devonian Antrim Shale of the Michigan basin and Devonian Ohio Shale of the Appalachian basin accounted for about 84% of the total 380 bcf of shale gas produced in 1999. However, annual gas production is steadily increasing from three other major organic shale formations that subsequently have been explored and developed: the Devonian New Albany Shale in the Illinois basin, the Mississippian Barnett Shale in the Fort Worth basin, and the Cretaceous Lewis Shale in the San Juan basin. In the basins for which estimates have been made, shale-gas resources are substantial, with in-place volumes of 497‐783 tcf. The estimated technically recoverable resource (exclusive of the Lewis Shale) ranges from 31 to 76 tcf. In both cases, the Ohio Shale accounts for the largest share.
93974071
Nanoscale pore morphology and distribution of lacustrine shale reservoirs: Examples from the Upper Triassic Yanchang Formation, Ordos Basin
Abstract Pore structure plays an important role in the gas storage and flow capacity of shale gas reservoirs. Field-emission environmental scanning electron microscopy (FE-SEM) in combination with low-pressure carbon dioxide gas adsorption (CO 2 GA), nitrogen gas adsorption (N 2 GA), and high-pressure mercury intrusion (HPMI) were used to study the nanostructure pore morphology and pore-size distributions (PSDs) of lacustrine shale from the Upper Triassic Yanchang Formation, Ordos Basin. Results show that the pores in the shale reservoirs are generally nanoscale and can be classified into four types: organic, interparticle, intraparticle, and microfracture. The interparticle pores between clay particles and organic-matter pores develop most often, l with pore sizes that vary from several to more than 100 nm. Mercury porosimetry analysis shows total porosities ranging between 1.93 and 7.68%, with a mean value of 5.27%. The BET surface areas as determined by N 2 adsorption in the nine samples range from 10 to 20 m 2 /g and the CO 2 equivalent surface areas ( 2 /g. Together, the HPMI, N 2 GA, and CO 2 GA curves indicate that the pore volumes are mainly due to pores
122781887
A Numerical Study of Microscale Flow Behavior in Tight Gas and Shale Gas Reservoir Systems
Various attempts have been made to model flow in shale gas systems. However, there is currently little consensus regarding the impact of molecular and Knudsen diffusion on flow behavior over time in such systems. Direct measurement or model-based estimation of matrix permeability for these “ultra-tight” reservoirs has proven unreliable. The composition of gas produced from tight gas and shale gas reservoirs varies with time for a variety of reasons. The cause of flowing gas compositional change typically cited is selective desorption of gases from the surface of the kerogen in the case of shale. However, other drivers for gas fractionation are important when pore throat dimensions are small enough. Pore throat diameters on the order of molecular mean free path lengths will create non-Darcy flow conditions, where permeability becomes a strong function of pressure. At the low permeabilities found in shale gas systems, the dusty-gas model for flow should be used, which couples diffusion to advective flow. In this study we implement the dusty-gas model into a fluid flow modeling tool based on the TOUGH+ family of codes. We examine the effects of Knudsen diffusion on gas composition in ultra-tight rock. We show that for very small average pore throat diameters, lighter gases are preferentially produced at concentrations significantly higher than in situ conditions. Furthermore, we illustrate a methodology which uses measurements of gas composition to more uniquely determine the permeability of tight reservoirs. We also describe how gas composition measurement could be used to identify flow boundaries in these reservoir systems. We discuss how new measurement techniques and data collection practices should be implemented in order to take advantage of this method. Our contributions include a new, fit-for-purpose numerical model based on the TOUGH+ code capable of characterizing transport effects including permeability adjustment and diffusion in micro- and nano-scale porous media.
119858113
Mass transfer within the gas-phase of porous media
Abstract The laws of various transport modes—viscous flow, diffusion and Knudsen flow—can be caused by the gradients of concentration, total and partial pressure. Their combined transports are derived and proved by selected experiments in the continuum as well as in the Knudsen region. The combination of these transport modes leads to phenomena like pressure diffusion, slip flow and diffusive slip. The three transport coefficients—the permeability, the binary diffusion coefficient and the Knudsen coefficient—can be determined by steady-state permeability and diffusion measurements. Nonsteady-state measurements deliver additional information about the pore structure of the porous medium. The presented measurements were carried out at cylindrical samples of rock salt with low porosity. Hydrogen and nitrogen were used as nonadsorbing gases. The binary diffusion experiments confirm Graham’s law with good accuracy.
98573028
New insights into natural gas diffusion coefficient in rocks
Abstract Based on the analysis of measuring methods and results of natural gas diffusion coefficient in rocks and the measurement of methane diffusion coefficient in the Upper Paleozoic rocks of the Ordos basin, this paper clarifies the meaning of natural gas diffusion coefficient in rocks and discusses its application in gas diffusion simulation and some influencing factors. There are three methods for measuring natural gas diffusion coefficient in rocks, including free gas method, water-dissolved method, and time delay method. The meanings of diffusive concentration and the influencing factors are different for the natural gas diffusion coefficients measured by these three methods. The diffusion coefficient measured by the free gas method is 1 to 2 order of magnitude less than that measured by the water-dissolved method, and 2 to 3 order of magnitude less than that measured by the time delay method. The meanings of diffusive concentration in the diffusive volume calculation must be in line with that in the diffusion coefficient measurement during the process of diffusive volume calculation. Natural gas diffusion coefficient in rocks has a linear relationship with porosity and a dynamic relationship with temperature, and it logarithmically decreases with pressure.
102292480
Slip flow in porous media
Abstract The dynamics of fluids and their interaction with surfaces in Unconventional Gas Reservoirs (UGRs) are very different from those in conventional systems. The physics of flow through the matrices of these reservoirs are not well understood. The small size of flow conduits which is comparable to the gas mean free path results in a deviation from Darcy to slip, transition and free molecular flow regimes. Solving Navier–Stokes (N–S) equations with modified boundary conditions has so far been the best practical approach to describe these flow behaviours. In this paper, a study of slip flow in shale gas reservoirs is presented. Several permeability measurements were performed using three shale rock samples to study the slip permeability. The Maxwellian type slip boundary conditions were used in N–S equations to obtain the slip coefficients and tangential momentum accommodation coefficient (TMAC) in porous media from the experimental data. Our results show that slip coefficients in porous media are higher than those in non-porous systems. In addition, it is found that the TMAC is smaller in porous media in comparison to flow in non-porous materials. These observations, which are attributed to greater surface area and roughness, are in agreement with literature data, which are limited to flow through individual micro conduits. The outcomes of this study will be useful for accurate prediction of gas flow rate in shale/tight gas reservoirs when using slip boundary conditions.
119881823
Dynamic molecular collision (DMC) model for rarefied gas flow simulations by the DSMC method
The Dynamic Molecular Collision (DMC) model is constructed for accurate and realistic simulations of rarefied gas flows of nonpolar diatomic molecules by the Direct Simulation Monte Carlo (DSMC) method. This model is applicable for moderate temperatures (up to a few hundred K for nitrogen), where most molecules are in the vibrational ground state and the vibrational degree of freedom can be neglected. In this range, moreover, the rotational energy can be considered as a continuous one. The collisions of diatomic molecules are simulated many times by the Molecular Dynamics (MD) method at various initial conditions. The site to site potential is used as an intermolecular one. The collision cross section is developed from the database obtained by MD simulation and kinetic theory of viscosity coefficient of diatomic molecules. The probability density function of energy after collision is also developed using the database. In order to verify the DMC model, two flow fields are simulated. First, the DMC model is...
31188664
Molecular Simulations of Knudsen Wall-slip: Effect of Wall Morphology
This work involves a molecular simulation study of the phenomena of wall slip occurring in rarefied gases flowing through micro- and nano-channels. A simulation strategy that mimics a scattering experiment is developed in order to compute the tangential momentum accommodation coefficient (f) which governs the degree of slip at the wall surface. Noninteracting gas molecules are bombarded at an atomic wall composed of rigid atoms with suitably distributed velocities and a tangential drift velocity that simulates flow. The accommodation coefficient is computed from the loss in the tangential momentum of these molecules. The accommodation coefficient is observed to be strongly dependent on the physical roughness of the wall, as characterized by the parameter sgr wg/L, and the attractiveness of the wall to the fluid, as characterized by the parameter ε wg/k B T, where sgr wg and ε wg are the Lennard–Jones interaction parameters of the wall and gas atoms while L is the lattice unit length. The accommodation coefficient is found to be independent of the tangential drift velocity at small drift velocities commensurate to those observed in micro devices. The accommodation coefficient is also found to be independent of the inertial mass of the gas molecules. The dependence of f on the two main governing factors has been presented in convenient “phase diagrams” plots. We also show a means of separating gases based on the differences in the accommodation coefficients of the various components in the mixture. Using molecular dynamics simulations, we show that separation factors higher than 20 are achieved for gases flowing through nanometer wide channels in the Knudsen regime. We also present a simple analytical model to determine the lower bound on the separation factor of the two gases.
110775237
Modified Reynolds Equation for Ultra-Thin Film Gas Lubrication Using 1.5-Order Slip-Flow Model and Considering Surface Accommodation Coefficient
A 1.5-order modified Reynolds equation for solving the ultra-thin film gas lubrication problem is derived by using an accurate higher-order slip-flow model. This model features two key differences from the current second-order slip-flow model. One is the involvement of an accommodation coefficient for momentum. The other is that the coefficient of the second-order slip-flow term is 4/9 times smaller than that for the current model. From the physical consideration of momentum transfer, the accommodation coefficient is found to have no affect on the second-order slip-flow term. Numerical calculations using the 1.5-order modified Reynolds equation are performed
129541328
Nanopores and Apparent Permeability of Gas Flow in Mudrocks (Shales and Siltstone)
Gas-producing mudrock systems are playing an important role in the volatile energy industry in North America and will soon play an equally important role in Europe. Mudrocks are composed of very fine grained particles, and their pores are very small, at the scale of nanometers. Gas production from these strata is much greater than what is anticipated given their very low Darcy permeability. In this paper, images of nanopores obtained by Atomic Force Microscopy (AFM) are presented for the first time. Gas flow in nanopores cannot be described simply by the Darcy equation. Processes such as Knudsen diffusion and slip flow at the solid matrix separate gas flow behaviour from Darcy-type flow. We present a formulation for gas flow in the nanopores of mudrocks based on Knudsen diffusion and slip flow. By comparing this new gas flow formulation and Darcy flow for compressible gas, we introduce an apparent permeability term that includes the complexity of flow in nanopores, and it takes the form of the Darcy equation so that it can easily be implemented in reservoir simulators. Results show that the ratio of apparent permeability to Darcy permeability increases sharply as pore sizes reduce to smaller than 100 nm. Also, Knudsen diffusion's contributions to flow increase as pores become smaller. Unlike Darcy permeability, which is a characteristic of the rock only, permeation of gas in nanopores of mudrocks depends on rock, gas type and operating conditions.
54042399
The Permeability Of Porous Media To Liquids And Gases
The standard procedure for determining the permeability of porous media according to APZ Code No. 27 (first edition, October 1935) is based on the fundamental assumption that, as long as the rate of flow is proportional to the pressure gradient, the permeability constant of a porous medium is a property of the medium, and is independent of the fluid used in its
44952428
REPORT: A MODEL FOR FLOWS IN CHANNELS, PIPES, AND DUCTS AT MICRO AND NANO SCALES
Rarefied gas flows in channels, pipes, and ducts with smooth surfaces are studied in a wide range of Knudsen number (Kn) at low Mach number (M) with the objective of developing simple, physics-based models. Such flows are encountered in microelectromechanical systems (MEMS), in nanotechnology applications, and in low-pressure environments. A new general boundary condition that accounts for the reduced momentum and heat exchange with wall surfaces is proposed and its validity is investigated. It is shown that it is applicable in the entire Knudsen range and is second-order accurate in Kn in the slip flow regime. Based on this boundary condition, a universal scaling for the velocity profile is obtained, which is used to develop a unified model predicting mass flow rate and pressure distribution with reasonable accuracy for channel, pipe, and duct flows in the regime (0 Kn). A rarefaction coefficient is introduced into this two-parameter model to account for the increasingly reduced intermolecular collisions...
137323382
Isothermal mass flow measurements in microfabricated rectangular channels over a very wide Knudsen range
Measurement and modeling of gas flows in microelectromechanical systems (MEMS) scale channels are relevant to the fundamentals of rarefied gas dynamics (RGD) and the practical design of MEMS-based flow systems and micropumps. We describe techniques for building robust, leak-free, rectangular microchannels which are relevant to micro- and nanofluidic devices, while the channels themselves are useful for fundamental RGD studies. For the first time, we report the isothermal steady flow of helium (He) gas through these channels from the continuum to the free-molecular regime in the unprecedented Knudsen range of 0.03–1000. On the high end, our value is 20-fold larger than values previously reported by Ewart et al (2007 J. Fluid Mech. 584 337–56). We accomplished this through a dual-tank accumulation technique which enabled the monitoring of very low flow rates, below 10−14 kg s−1. The devices were prebaked under vacuum for 24 h at 100 °C in order to reduce outgassing and attain high Kn. We devised fabrication methods for controlled-depth micro-gap channels using silicon for both channel ceiling and floor, thereby allowing direct comparisons to models which utilize this simplifying assumption. We evaluated the results against a closed-form expression that accurately reproduces the continuum, slip, transition, and free-molecular regimes developed partly by using the direct simulation Monte Carlo method. The observed data were in good agreement with the expression. For Kn > ~100, we observed minor deviations between modeled and experimental flow values. Our fabrication processes and experimental data are useful to fundamental RGD studies and future MEMS microflow devices with respect to extremely low-flow measurements, model validation, and predicting optimal designs.
96543399
Characteristics of the Nanoscale Pore Structure in Northwestern Hunan Shale Gas Reservoirs Using Field Emission Scanning Electron Microscopy, High-Pressure Mercury Intrusion, and Gas Adsorption
Nanostructure morphology and pore size distributions (PSDs) of 10 samples from the Lower Cambrian Niutitang Formation in northwestern Hunan were investigated using field emission scanning electron microscopy (FE-SEM), high-pressure mercury intrusion (HPMI), low-pressure nitrogen gas adsorption (LP-N2GA), and carbon dioxide gas adsorption (LP-CO2GA). In combination with the geochemical parameters and mineral composition, the factors influencing the nanoscale pore structure were analyzed. The results indicate that the pores in the shale reservoirs are generally nanoscale and can be classified into four types: organic pores, intraparticle pores, interparticle pores, and microfractures, of which the most common are organic nanopores and interparticle pores between clay particles. The nanoscale pores primarily consist of slit-shaped pores with parallel plates and ink-bottle-type pores. The combination of the HPMI, LP-N2GA, and LP-CO2GA curves enabled the creation of the PSD for micro-, meso-, and macroporositi...
98186605
Nature of the porosity in American coals
Abstract The nature of the porosity in a number of 40 × 70 (i.e. − 40 + 70) mesh size American coals, varying in rank from anthracite to lignite, has been studied using the following characterization techniques: gas adsorption, helium and mercury displacement, and mercury porosimetry. Surface areas calculated from carbon dioxide adsorption at 298 K are consistently higher than those calculated from nitrogen at 77 K, indicating the molecular sieve character of the coals. Total pore volumes have been measured in the diameter range 12–29 600 A and then divided into macropores (300-29 600 A), transitional pores (12–300 A), and micropores (4–12 A). Coals vary widely in their total pore volumes (porosities range between 4.1 and 23.2%). In the lower-rank coals (carbon content less than 75%), porosity is primarily due to the presence of macropores. In coals having a carbon content in the range 76–84%, about 80% of the total open pore volume is due to micro and transitional pores, whereas in the coals of higher carbon content microporosity predominates. Coals having about 35–55% of their total open pore volume in the transitional range are expected to be most suitable for use for adsorption of organic molecules from solution. Thus, they are of interest as possible materials to be used in water purification. In general, these results are considered to be of importance in understanding the extent and rate of interaction of coals with gases and liquids.
130385712
Pore types in the Barnett and Woodford gas shales: Contribution to understanding gas storage and migration pathways in fine-grained rocks
The identification of organoporosity (microscale and nanoscale pores within organic matter in shales), its importance to storage and perhaps transfer of gas molecules through shales, and methods for gathering three-dimensional images of the pores, such as by argon-ion milling and/or field emission scanning electron microscopy, have all been well documented and discussed for unconventional gas shales. However, other types of pores exist within shales that can be important to storage and migration of gas (and oil), and other technologies are available for their identification and imaging. The different pore types found in the Barnett and Woodford shales are described and classified in this article. Scanning electron microscopy revealed the presence of porous floccules in both the Barnett and Woodford shales, which appear similar to laboratory-produced floccules and to those in other ancient shales. Published experimental and observational studies indicate that floccules are hydraulically equivalent to coarser grains and are transported by traction processes. Current-induced microsedimentary structures and textures within the Barnett and Woodford shales, as well as the preserved floccules, suggest such processes were active during transport and deposition. Pore spaces between the floccules are open and can provide storage space as well as permeability pathways for gas molecules through the shales. Pores are also found within organic matter that occurs both as discrete particles and as adsorbed coatings around clay grains in the shale. They are referred to here as “organopores.” Porous fecal pellets are also common in the Barnett Shale. Preserved fossil fragments such as organic-walled spores and inorganic sponge spicules have hollow central chambers, which may remain partially or completely open even after burial. Intraparticle pores occur between grains of various minerals (e.g., pyrite framboids). Microchannels within shale matrix, which may be the bounding surfaces of scours or microsedimentary structures, may also provide permeability pathways for hydrocarbon migration. Mircrofractures are also common, and their initiation might be related to mineral crystal structure. When present in sufficient quantity, these pore types offer potential gas (and oil) molecule storage spaces and permeability pathways through the shales.
52885519
Spectrum of pore types and networks in mudrocks and a descriptive classification for matrix-related mudrock pores
Matrix-related pore networks in mudrocks are composed of nanometer- to micrometer-size pores. In shale-gas systems, these pores, along with natural fractures, form the flow-path (permeability) network that allows flow of gas from the mudrock to induced fractures during production. A pore classification consisting of three major matrix-related pore types is presented that can be used to quantify matrix-related pores and relate them to pore networks. Two pore types are associated with the mineral matrix; the third pore type is associated with organic matter (OM). Fracture pores are not controlled by individual matrix particles and are not part of this classification. Pores associated with mineral particles can be subdivided into interparticle (interP) pores that are found between particles and crystals and intraparticle (intraP) pores that are located within particles. Organic-matter pores are intraP pores located within OM. Interparticle mineral pores have a higher probability of being part of an effective pore network than intraP mineral pores because they are more likely to be interconnected. Although they are intraP, OM pores are also likely to be part of an interconnected network because of the interconnectivity of OM particles. In unlithifed near-surface muds, pores consist of interP and intraP pores, and as the muds are buried, they compact and lithify. During the compaction process, a large number of interP and intraP pores are destroyed, especially in ductile grain-rich muds. Compaction can decrease the pore volume up to 88% by several kilometers of burial. At the onset of hydrocarbon thermal maturation, OM pores are created in kerogen. At depth, dissolution of chemically unstable particles can create additional moldic intraP pores.
130334404
Critical geological characteristics and gas-bearing controlling factors in Longmaxi shales in southeastern Chongqing, China
The southeastern Chongqing area, one of the highest potential shale gas accumulation areas in China, experienced strong tectonic movements. Due to the tectonic uplift in Himalayan period, the target shale formation is characterized by shallow burial depth and abundant fractures. The Lower Silurian Longmaxi shale was deposited under deep and shallow continental shelf environments with abundant pyrites and graptolite fossils. The lithology of the formation includes black carbonaceous shale, calcareous shale, and siliceous shale. The thickness of the shale varies greatly from 40 to 200 m from southeast to northwest with obvious zonation. Total organic carbon (TOC) content ranges from 1.0 to 4.0% and decreases upward in the formation owing to the change of sedimentary facies. The organic matter reaches dry gas zone. Porosity ranges from 0.5 to 7.9%, and the permeability is measured in the microdarcy to nanodarcy range. Abundant fragile minerals exist in the shales which benefit the hydraulic stimulation. Isothermal adsorption tests show that the sorption gas content in place of the Longmaxi shale ranges from 1.0 to 4.5 m3/t and the gas content in place reaches the standard of commercial exploitation. Factors impacting gas-bearing characteristics were analyzed using a mathematical statistic method, which demonstrates that TOC is the most important factor, especially to the sorption gas content. Meanwhile, clay content, thermal maturity, porosity, and mineral components are also significant factors regarding shale gas-bearing characteristics.
55493569
Permeability evolution in sorbing media: analogies between organic‐rich shale and coal
Shale gas reservoirs like coalbed methane (CBM) reservoirs are promising targets for geological sequestration of carbon dioxide (CO2). However, the evolution of permeability in shale reservoirs on injection of CO2 is poorly understood unlike CBM reservoirs. In this study, we report measurements of permeability evolution in shales infiltrated separately by nonsorbing (He) and sorbing (CO2) gases under varying gas pressures and confining stresses. Experiments are completed on Pennsylvanian shales containing both natural and artificial fractures under nonpropped and propped conditions. We use the models for permeability evolution in coal (Journal of Petroleum Science and Engineering, Under Revision) to codify the permeability evolution observed in the shale samples. It is observed that for a naturally fractured shale, the He permeability increases by approximately 15% as effective stress is reduced by increasing the gas pressure from 1 MPa to 6 MPa at constant confining stress of 10 MPa. Conversely, the CO2 permeability reduces by a factor of two under similar conditions. A second core is split with a fine saw to create a smooth artificial fracture and the permeabilities are measured for both nonpropped and propped fractures. The He permeability of a propped artificial fracture is approximately 2- to 3fold that of the nonpropped fracture. The He permeability increases with gas pressure under constant confining stress for both nonpropped and propped cases. However, the CO2 permeability of the propped fracture decreases by between one-half to one-third as the gas pressure increases from 1 to 4 MPa at constant confining stress. Interestingly, the CO2 permeability of nonpropped fracture increases with gas pressure at constant confining stress. The permeability evolution of nonpropped and propped artificial fractures in shale is found to be similar to those observed in coals but the extent of permeability reduction by swelling is much lower in shale due to its lower organic content. Optical profilometry is used to quantify the surface roughness. The changes in surface roughness indicate significant influence of proppant indentation on fracture surface in the shale sample. The trends of permeability evolution on injection of CO2 in coals and shales are found analogous; therefore, the permeability evolution models previously developed for coals are adopted to explain the permeability evolution in shales.
126728472
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.
130095724
Fracture permeability evaluation of a coal reservoir using geophysical logging: A case study in the Zhengzhuang area, southern Qinshui Basin
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.
130916570
Characteristics of in-situ stress field in Southern Qinshui Basin and its research significance
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.
119610055
Effective Correlation of Apparent Gas Permeability in Tight Porous Media
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.
122009808
Knudsen’s Permeability Correction for Tight Porous Media
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.
98170933
On the experimental evaluation of permeability in porous media using a gas flow method
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.
93056990
A unified method to evaluate shale gas flow behaviours in different flow regions
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.