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Special Issue "Flow and Transport Properties of Unconventional Reservoirs"

A special issue of Energies (ISSN 1996-1073).

Deadline for manuscript submissions: closed (20 December 2017).

Special Issue Editors

Prof. Dr. Qinjun Kang
E-Mail Website
Guest Editor
Computational Earth Science Group, Earth and Environmental Sciences Division, Los Alamos National Laboratory, Los Alamos, NM 87545, USA
Interests: flow and transport in porous media; lattice boltzmann method; multiscale modeling; CO2 sequestration; shale gas; energy storage and conversion devices
Special Issues, Collections and Topics in MDPI journals
Dr. Harpreet Singh
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Guest Editor
The University of Texas at Austin, Austin, TX 78705, USA
National Energy Technology Laboratory, Morgantown, WV 26505, USA
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Unconventional reservoirs have received a great deal of attention in recent years. A better understanding of the nano- and micro-scale structures of these reservoir rocks, and their transport properties, are critical for improving the efficiency of these energy systems. Due to the complexity of unconventional rocks, and the strong interactions between fluids and pore surfaces due to the reduced dimensionality, conventional approaches are typically not applicable to fluid flow in these porous reservoir rocks. Therefore, the accurate characterization of rocks with nano- to micro-scale pores is challenging and of great importance.

We invite investigators to submit original research articles, as well as review articles, which will stimulate the continuous efforts on new and modern methods and techniques for rock characterization and reconstruction, as well as on understanding mechanisms involved in transport physics of tight and ultra-tight porous media and unconventional rocks.

Prof. Dr. Jianchao Cai
Prof. Dr. Qinjun Kang
Dr. Harpreet Singh
Guest Editors

Manuscript Submission Information

Manuscripts should be submitted online at www.mdpi.com by registering and logging in to this website. Once you are registered, click here to go to the submission form. Manuscripts can be submitted until the deadline. All papers will be peer-reviewed. Accepted papers will be published continuously in the journal (as soon as accepted) and will be listed together on the special issue website. Research articles, review articles as well as short communications are invited. For planned papers, a title and short abstract (about 100 words) can be sent to the Editorial Office for announcement on this website.

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Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2200 CHF (Swiss Francs). Submitted papers should be well formatted and use good English. Authors may use MDPI's English editing service prior to publication or during author revisions.

Keywords

  • nano to micro-scale pores
  • rock characterization and reconstruction
  • theoretical and numerical models for upscaling
  • unconventional rocks
  • hydraulic fracturing and fracture dynamic characterization
  • capillary flow
  • nanofluids
  • non-linear porous flow
  • multiphase porous flow

Published Papers (11 papers)

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Research

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Article
Numerical Simulation of Fluid Flow through Fractal-Based Discrete Fractured Network
Energies 2018, 11(2), 286; https://0-doi-org.brum.beds.ac.uk/10.3390/en11020286 - 24 Jan 2018
Cited by 26 | Viewed by 2256
Abstract
Abstract: In recent years, multi-stage hydraulic fracturing technologies have greatly facilitated the development of unconventional oil and gas resources. However, a quantitative description of the “complexity” of the fracture network created by the hydraulic fracturing is confronted with many unsolved challenges. Given [...] Read more.
Abstract: In recent years, multi-stage hydraulic fracturing technologies have greatly facilitated the development of unconventional oil and gas resources. However, a quantitative description of the “complexity” of the fracture network created by the hydraulic fracturing is confronted with many unsolved challenges. Given the multiple scales and heterogeneity of the fracture system, this study proposes a “bifurcated fractal” model to quantitatively describe the distribution of induced hydraulic fracture networks. The construction theory is employed to generate hierarchical fracture patterns as a scaled numerical model. With the implementation of discrete fractal-fracture network modeling (DFFN), fluid flow characteristics in bifurcated fractal fracture networks are characterized. The effects of bifurcated fracture length, bifurcated tendency, and number of bifurcation stages are examined. A field example of the fractured horizontal well is introduced to calibrate the accuracy of the flow model. The proposed model can provide a more realistic representation of complex fracture networks around a fractured horizontal well, and offer the way to quantify the “complexity” of the fracture network in shale reservoirs. The simulation results indicate that the geometry of the bifurcated fractal fracture network model has a significant impact on production performance in the tight reservoir, and enhancing connectivity of each bifurcate fracture is the key to improve the stimulation performance. In practice, this work provides a novel and efficient workflow for complex fracture characterization and production prediction in naturally-fractured reservoirs of multi-stage fractured horizontal wells. Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Article
Gas Transport Model in Organic Shale Nanopores Considering Langmuir Slip Conditions and Diffusion: Pore Confinement, Real Gas, and Geomechanical Effects
Energies 2018, 11(1), 223; https://0-doi-org.brum.beds.ac.uk/10.3390/en11010223 - 17 Jan 2018
Cited by 22 | Viewed by 2438
Abstract
Nanopores are extremely developed and randomly distributed in shale gas reservoirs. Due to the rarefied conditions in shale strata, multiple gas transport mechanisms coexist and need further understanding. The commonly used slip models are mostly based on Maxwell slip boundary condition, which assumes [...] Read more.
Nanopores are extremely developed and randomly distributed in shale gas reservoirs. Due to the rarefied conditions in shale strata, multiple gas transport mechanisms coexist and need further understanding. The commonly used slip models are mostly based on Maxwell slip boundary condition, which assumes elastic collisions between gas molecules and solid surfaces. However, gas molecules do not rebound from solid surfaces elastically, but rather are adsorbed on them and then re-emitted after some time lag. A Langmuir slip permeability model was established by introducing Langmuir slip BC. Knudsen diffusion of bulk phase gas and surface diffusion of adsorbed gas were also coupled into our nanopore transport model. Considering the effects of real gas, stress dependence, thermodynamic phase changes due to pore confinement, surface roughness, gas molecular volume, and pore enlargement due to gas desorption during depressurization, a unified gas transport model in organic shale nanopores was established, which was then upscaled by coupling effective porosity and tortuosity to describe practical SGR properties. The bulk phase transport model, single capillary model, and upscaled porous media model were validated by data from experimental data, lattice Boltzmann method or model comparisons. Based on the new gas transport model, the equivalent permeability of different flow mechanisms as well as the flux proportion of each mechanism to total flow rate was investigated in different pore radius and pressure conditions. The study in this paper revealed special gas transport characteristics in shale nonopores and provided a robust foundation for accurate simulation of shale gas production. Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Article
Mixed Finite Element Simulation with Stability Analysis for Gas Transport in Low-Permeability Reservoirs
Energies 2018, 11(1), 208; https://0-doi-org.brum.beds.ac.uk/10.3390/en11010208 - 15 Jan 2018
Cited by 5 | Viewed by 1578
Abstract
Natural gas exists in considerable quantities in tight reservoirs. Tight formations are rocks with very tiny or poorly connected pors that make flow through them very difficult, i.e., the permeability is very low. The mixed finite element method (MFEM), which is locally conservative, [...] Read more.
Natural gas exists in considerable quantities in tight reservoirs. Tight formations are rocks with very tiny or poorly connected pors that make flow through them very difficult, i.e., the permeability is very low. The mixed finite element method (MFEM), which is locally conservative, is suitable to simulate the flow in porous media. This paper is devoted to developing a mixed finite element (MFE) technique to simulate the gas transport in low permeability reservoirs. The mathematical model, which describes gas transport in low permeability formations, contains slippage effect, as well as adsorption and diffusion mechanisms. The apparent permeability is employed to represent the slippage effect in low-permeability formations. The gas adsorption on the pore surface has been described by Langmuir isotherm model, while the Peng-Robinson equation of state is used in the thermodynamic calculations. Important compatibility conditions must hold to guarantee the stability of the mixed method by adding additional constraints to the numerical discretization. The stability conditions of the MFE scheme has been provided. A theorem and three lemmas on the stability analysis of the mixed finite element method (MFEM) have been established and proven. A semi-implicit scheme is developed to solve the governing equations. Numerical experiments are carried out under various values of the physical parameters. Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Article
Laboratory Investigation of Flow Paths in 3D Self-Affine Fractures with Lattice Boltzmann Simulations
Energies 2018, 11(1), 168; https://0-doi-org.brum.beds.ac.uk/10.3390/en11010168 - 10 Jan 2018
Cited by 7 | Viewed by 2389
Abstract
In this study, laboratory experiments and simulations have been conducted to investigate single water phase flow through self-affine rough fractures. It is the first time that 3D printing technology is proposed for the application of generating self-affine rough fractures. The experimental setup was [...] Read more.
In this study, laboratory experiments and simulations have been conducted to investigate single water phase flow through self-affine rough fractures. It is the first time that 3D printing technology is proposed for the application of generating self-affine rough fractures. The experimental setup was designed to measure the water volume by dividing the discharging surface into five sections with equal distances under constant injection flow rates. Water flow through self-affine rough fractures was simulated numerically by using the Lattice Boltzmann method (LBM). An agreement between the experimental data and the numerical simulation results was achieved. The fractal dimension is positively correlated to fracture surface roughness and the fracture inclination represents the gravity force acting on the water flow. The influences of fracture inclinations, fractal dimensions, and mismatch wavelengths were studied and analyzed, with an emphasis on flow paths through a self-affine rough fracture. Different values of fractal dimensions, fracture inclinations, and mismatch wavelengths result in small changes of flow rates from five sections of discharging surface. However, the section of discharging surface with the largest flow rate remains constant. In addition, it is found that the gravity force can affect flow paths. Combined with the experimental data, the simulation results are used to explain the preferential flow paths through fracture rough surfaces from a new perspective. The results may enhance our understanding of fluid flow through fractures and provide a solid background for further research in the areas of energy exploration and production. Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Article
Viscosity Models for Polymer Free CO2 Foam Fracturing Fluid with the Effect of Surfactant Concentration, Salinity and Shear Rate
Energies 2017, 10(12), 1970; https://0-doi-org.brum.beds.ac.uk/10.3390/en10121970 - 26 Nov 2017
Cited by 17 | Viewed by 3487
Abstract
High quality polymer free CO2 foam possesses unique properties that make it an ideal fluid for fracturing unconventional shales. In this paper, the viscosity of polymer free fracturing foam and its empirical correlations at high pressure high temperature (HPHT) as a function [...] Read more.
High quality polymer free CO2 foam possesses unique properties that make it an ideal fluid for fracturing unconventional shales. In this paper, the viscosity of polymer free fracturing foam and its empirical correlations at high pressure high temperature (HPHT) as a function of surfactant concentration, salinity, and shear rate are presented. Foams were generated using a widely-used surfactant, i.e., alpha olefin sulfonate (AOS) in the presence of brine and a stabilizer at HPHT. Pressurize foam rheometer was used to find out the viscosity of CO2 foams at different surfactant concentration (0.25–1 wt %) and salinity (0.5–8 wt %) over a wide range of shear rate (10–500 s−1) at 1500 psi and 80 °C. Experimental results concluded that foam apparent viscosity increases noticeably until the surfactant concentration of 0.5 wt %, whereas, the increment in salinity provided a continuous increase in foam apparent viscosity. Nonlinear regression was performed on experimental data and empirical correlations were developed. Power law model for foam viscosity was modified to accommodate for the effect of shear rate, surfactant concentration, and salinity. Power law indices (K and n) were found to be a strong function of surfactant concentration and salinity. The new correlations accurately predict the foam apparent viscosity under various stimulation scenarios and these can be used for fracture simulation modeling. Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Article
Research on Stress Sensitivity of Fractured Carbonate Reservoirs Based on CT Technology
Energies 2017, 10(11), 1833; https://0-doi-org.brum.beds.ac.uk/10.3390/en10111833 - 10 Nov 2017
Cited by 29 | Viewed by 2431
Abstract
Fracture aperture change under stress has long been considered as one of primary causes of stress sensitivity of fractured gas reservoirs. However, little is known about the evolution of the morphology of fracture apertures on flow property in loading and unloading cycles. This [...] Read more.
Fracture aperture change under stress has long been considered as one of primary causes of stress sensitivity of fractured gas reservoirs. However, little is known about the evolution of the morphology of fracture apertures on flow property in loading and unloading cycles. This paper reports a stress sensitivity experiment on carbonate core plugs in which Computed Tomography (CT) technology is applied to visualize and quantitatively evaluate morphological changes to the fracture aperture with respect to confining pressure. Fracture models were obtained at selected confining pressures on which pore-scale flow simulations were performed to estimate the equivalent absolute permeability. The results showed that with the increase of confining pressure from 0 to 0.6 MPa, the fracture aperture and equivalent permeability decreased at a greater gradient than their counterparts after 0.6 MPa. This meant that the rock sample is more stress-sensitive at low effective stress than at high effective stress. On the loading path, an exponential fitting was found to fit well between the effective confining pressure and the calculated permeability. On the unloading path, the relationship is found partially reversible, which can evidently be attributed to plastic deformation of the fracture as observed in CT images. Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Article
Rate Decline Analysis of Vertically Fractured Wells in Shale Gas Reservoirs
Energies 2017, 10(10), 1602; https://0-doi-org.brum.beds.ac.uk/10.3390/en10101602 - 13 Oct 2017
Cited by 11 | Viewed by 1859
Abstract
Based on the porous flow theory, an extension of the pseudo-functions approach for the solution of non-linear partial differential equations considering adsorption-desorption effects was used to investigate the transient flow behavior of fractured wells in shale gas reservoirs. The pseudo-time factor was employed [...] Read more.
Based on the porous flow theory, an extension of the pseudo-functions approach for the solution of non-linear partial differential equations considering adsorption-desorption effects was used to investigate the transient flow behavior of fractured wells in shale gas reservoirs. The pseudo-time factor was employed to effectively linearize the partial differential equations of the unsteady flow response. The production performance of vertically fractured wells in shale gas reservoirs under either constant flow rate or constant bottom-hole pressure conditions was analyzed using the composite flow model. The calculation results indicate that the non-linearities that develop in the gas diffusivity equation have significant effects on the unsteady response, leading to a larger pressure depletion and rate decline in the late-time period. In addition, gas desorption from the shale acts as a recharge source, which relieves the gas production rate of decline. Greater values for the Langmuir volumes or Langmuir pressures provide additional pressure support, leading to a lower rate decline while the flowing well bottom-hole pressure is maintained. The reservoir size mainly affects the duration of the pressure depletion and rate decline. In the case of ignoring the non-linearity and adsorption-desorption effect in the differential equation, a greater rate decline under constant bottom-hole pressure production can be obtained during the boundary-dominated depletion. This work provides a better understanding of gas desorption in shale gas reservoirs and new insight into investigating the production performances of fractured gas well. Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Article
Adsorption Properties of Hydrocarbons (n-Decane, Methyl Cyclohexane and Toluene) on Clay Minerals: An Experimental Study
Energies 2017, 10(10), 1586; https://0-doi-org.brum.beds.ac.uk/10.3390/en10101586 - 12 Oct 2017
Cited by 11 | Viewed by 2327
Abstract
Adsorption of hydrocarbons may significantly affect hydrocarbon migration in unconventional reservoirs. Clay minerals form the primary adsorbent surfaces for hydrocarbons adsorbed in mudstone/shale. To study the adsorption properties of hydrocarbons (n-decane (C10H22), methyl cyclohexane (C7H14) [...] Read more.
Adsorption of hydrocarbons may significantly affect hydrocarbon migration in unconventional reservoirs. Clay minerals form the primary adsorbent surfaces for hydrocarbons adsorbed in mudstone/shale. To study the adsorption properties of hydrocarbons (n-decane (C10H22), methyl cyclohexane (C7H14) and toluene (C7H8)) on clay minerals (i.e., cookeite, ripidolite, kaolinite, illite, illite/smectite mixed-layer, Na-montmorillonite and Ca-montmorillonite), hydrocarbon vapor adsorption (HVA) tests were conducted at 298.15 K. The results showed that (i) the adsorption amounts of C10H22, C7H14 and C7H8 ranged from 0.45–1.03 mg/m2, 0.28–0.90 mg/m2 and 0.16–0.53 mg/m2, respectively; (ii) for cookeite, ripidolite and kaolinite, the adsorption capacity of C10H22 was less than C7H14, which was less than C7H8; (iii) for illite, Na-montmorillonite and Ca-montmorillonite, the adsorption capacity of C10H22 was greater than that of C7H8, and the adsorption capacity of C7H14 was the lowest; (iv) for an illite/smectite mixed-layer, C7H14 had the highest adsorption capacity, followed by C10H22, and C7H8 had the lowest capacity. Adsorption properties were correlated with the microscopic parameters of pores in clay minerals and with experimental pressure. Finally, the weighted average method was applied to evaluate the adsorption properties of C10H22, C7H14 and C7H8 on clay minerals in oil-bearing shale from the Shahejie Formation of Dongying Sag in the Bohai Bay Basin, China. For these samples, the adsorbed amounts of C7H14 ranged from 18.03–28.02 mg/g (mean 23.33 mg/g), which is larger than that of C10H22, which ranges from 15.40–21.72 mg/g (mean 18.82 mg/g). The adsorption capacity of C7H8 was slightly low, ranging from 10.51–14.60 mg/g (mean 12.78 mg/g). Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Article
Effect of Permeability Anisotropy on the Production of Multi-Scale Shale Gas Reservoirs
Energies 2017, 10(10), 1549; https://0-doi-org.brum.beds.ac.uk/10.3390/en10101549 - 09 Oct 2017
Cited by 11 | Viewed by 3044
Abstract
Shales or mudstones are fine grained and layered reservoirs, which leads to strong shale permeability anisotropy. Shale has a wide pore-size distribution, and pores with different diameters contribute differently to the apparent permeability of shales. Therefore, understanding the anisotropy of multiscale shale gas [...] Read more.
Shales or mudstones are fine grained and layered reservoirs, which leads to strong shale permeability anisotropy. Shale has a wide pore-size distribution, and pores with different diameters contribute differently to the apparent permeability of shales. Therefore, understanding the anisotropy of multiscale shale gas reservoirs is an important aspect to model and evaluate gas production from shales. In this paper, a novel model of permeability anisotropy for shale gas reservoirs is presented to calculate the permeability in an arbitrary direction in three dimensional space. A numerical model which is valid for the entire Knudsen’s range (continuum flow, slip flow, transition flow and free molecular flow) in shale gas reservoirs was developed, and the effect of gas-water flow and the simulation of hydraulic fracturing cracks were taken into consideration as well. The simulation result of the developed model was validated with field data. Effects of critical factors such as permeability anisotropy, relative permeability curves with different nanopore radii and initial water saturation in formation on the gas production rate of multi-stage fractured horizontal well were discussed. Besides, flow regimes of gas flow in shales were classified by Knudsen number, and the effect of various flow regimes on both apparent permeability of shales and then the gas production has been analyzed thoroughly. Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Article
Acceleration of Gas Flow Simulations in Dual-Continuum Porous Media Based on the Mass-Conservation POD Method
Energies 2017, 10(9), 1380; https://0-doi-org.brum.beds.ac.uk/10.3390/en10091380 - 12 Sep 2017
Cited by 22 | Viewed by 1870
Abstract
Reduced-order modeling approaches for gas flow in dual-porosity dual-permeability porous media are studied based on the proper orthogonal decomposition (POD) method combined with Galerkin projection. The typical modeling approach for non-porous-medium liquid flow problems is not appropriate for this compressible gas flow in [...] Read more.
Reduced-order modeling approaches for gas flow in dual-porosity dual-permeability porous media are studied based on the proper orthogonal decomposition (POD) method combined with Galerkin projection. The typical modeling approach for non-porous-medium liquid flow problems is not appropriate for this compressible gas flow in a dual-continuum porous media. The reason is that non-zero mass transfer for the dual-continuum system can be generated artificially via the typical POD projection, violating the mass-conservation nature and causing the failure of the POD modeling. A new POD modeling approach is proposed considering the mass conservation of the whole matrix fracture system. Computation can be accelerated as much as 720 times with high precision (reconstruction errors as slow as 7.69 × 10−4%~3.87% for the matrix and 8.27 × 10−4%~2.84% for the fracture). Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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Technical Note
Brazilian Test for Tensile Failure of Anisotropic Shale under Different Strain Rates at Quasi-static Loading
Energies 2017, 10(9), 1324; https://0-doi-org.brum.beds.ac.uk/10.3390/en10091324 - 02 Sep 2017
Cited by 16 | Viewed by 2357
Abstract
Shale formations show obvious anisotropic characteristics in their mechanical properties due to pronounced bedding planes and natural fractures. This anisotropic behavior generally creates complex fracturing networks and is crucial to gas shale stimulation. Although much research has been done to study the anisotropic [...] Read more.
Shale formations show obvious anisotropic characteristics in their mechanical properties due to pronounced bedding planes and natural fractures. This anisotropic behavior generally creates complex fracturing networks and is crucial to gas shale stimulation. Although much research has been done to study the anisotropic compression behaviors of shale with static and quasi-static strain rates, there are limited investigations addressing the anisotropic tensile behaviors of shale at quasi-static strain rate. In this work, the anisotropic tensile behaviors of Longmaxi shales were studied systematically at different strain rates from 10−5 to 10−2 s−1 by performing Brazilian splitting tests. Testing results reveal the tensile strength anisotropy, rate dependency, and the stimulated fracture pattern morphology. The results show that the orientation between the applied force and bedding direction has an obvious effect on the tensile strength and fracture pattern. The rate dependency of shale under different loading rates is different for shale samples with various orientations. It was suggested that a complex tensile fracture pattern can be easily formed when using a high loading rate. The result sheds light on how to stimulate a complex fracturing network during field hydraulic fracturing treatment. Full article
(This article belongs to the Special Issue Flow and Transport Properties of Unconventional Reservoirs)
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