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Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs

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A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H1: Petroleum Engineering".

Deadline for manuscript submissions: closed (15 December 2021) | Viewed by 21227
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Special Issue Editors

Prof. Dr. Jianchao Cai

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Guest Editor

College of Geosciences, China University of Petroleum, Beijing 102249, China
Interests: porous media; nanofluids; EOR; fractal; capillary pressure; imbibition; mutlphase flow in porous media
Special Issues, Collections and Topics in MDPI journals

Prof. Dr. Reza Rezaee

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Guest Editor

Western Australian School of Mines: Minerals, Energy and Chemical Engineering, Curtin University, Kent St, Bentley WA 6102, Australia
Interests: formation evaluation; petrophysics; unconventional gas (tight gas sand and shale gas); reservoir characterization and modeling
Special Issues, Collections and Topics in MDPI journals

Prof. Dr. Victor Calo

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Guest Editor

1. Department of Applied Geology, Curtin University, Kent Street, Bentley, Perth, WA 6102, Australia
2. Mineral Resources, Commonwealth Scientific and Industrial Research Organisation (CSIRO), Kensington, Perth, WA 6152, Australia
Interests: modelling and simulation of geomechanics; fluid dynamics; flow in porous media; phase separation; fluid-structure interaction; solid mechanics; high-performance computing

Special Issue Information

Dear Colleagues,

Petrophysics in unconventional reservoirs, especially multiscale characterization and multiphase flow modeling, are relevant to multi-disciplinary porous media research (e.g., hydrocarbon extraction, environmental issues, hydrology). Reliable characterization at different scales, advances in theoretical modeling and numerical methods of multiphase flow are crucial for many applications, including studies of residual oil in hydrocarbon reservoirs and long-term storage of supercritical CO₂ in geological formations.

We invite investigators to submit original research articles, case studies, and review papers to address the most significant challenges in multiscale petrophysics characterization and multiphase flow in unconventional reservoirs. This Special Issue will compile descriptions and applications of modern methods and techniques to model petrophysical processes relevant to unconventional reservoirs.

Prof. Dr. Jianchao Cai
Prof. Dr. Reza Rezaee
Prof. Dr. Victor Calo
Guest Editors

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Keywords

Rock characterization and reconstruction
Hydrofracturing methods
Tight porous media analysis
Pore network modeling
Upscaling
Multiphase flows
Fractal modeling
Multiscale modeling of porous media flow
Coupled transport phenomena
Gas capture and storage
Capillarity
Wettability of geological media and its variation

Published Papers (12 papers)

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Editorial

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2 pages, 155 KiB

Open AccessEditorial

Recent Advances in Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs

by Jianchao Cai, Reza Rezaee and Victor Calo

Energies 2022, 15(8), 2874; https://0-doi-org.brum.beds.ac.uk/10.3390/en15082874 - 14 Apr 2022

Cited by 2 | Viewed by 1257

Abstract

Petrophysics in unconventional reservoirs, especially multiscale characterization and multiphase flow, is relevant to multi-disciplinary porous media research (e [...] Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

Research

Jump to: Editorial

13 pages, 5551 KiB

Open AccessArticle

Molecular Simulation of Adsorption in Deep Marine Shale Gas Reservoirs

by Cheng Chang, Jian Zhang, Haoran Hu, Deliang Zhang and Yulong Zhao

Energies 2022, 15(3), 944; https://0-doi-org.brum.beds.ac.uk/10.3390/en15030944 - 27 Jan 2022

Cited by 8 | Viewed by 2190

Abstract

Deep marine shale gas reservoirs are extremely rich in the Sichuan basin in China. However, due to the in situ conditions with high temperature and high pressure (HTHP), in particular reservoir pressure being usually much higher than the test pressure, it is difficult to accurately clarify the adsorption behavior, as seepage theory plays an important role in shale gas reserves evaluation. Therefore, three kinds of sorbent, including illite, quartz and kerogen, and two simulation methods, containing the grand canonical ensemble Monte Carlo method and molecular dynamics method, are synthetically used to determine the methane adsorption behavior under HTHP. The results show that both absolute adsorption and excess adsorption decrease with the increase of temperature. When the pressure increases, the absolute adsorption increases quickly and then slowly, and the excess adsorption first increases and then decreases. The superposition of wall potential energy is strongest in a circular hole, second in a square hole, and weakest in a narrow slit. The effect of pore size increases with the decrease of the pore diameter. Under HTHP, multi-layer adsorption can occur in shale, but the timing and number of layers are related to the sorbent type. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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16 pages, 2166 KiB

Open AccessArticle

Optimization Algorithm of Effective Stress Coefficient for Permeability

by Xiaolong Zhang, Jianjun Liu and Jiecheng Song

Energies 2021, 14(24), 8345; https://0-doi-org.brum.beds.ac.uk/10.3390/en14248345 - 10 Dec 2021

Cited by 2 | Viewed by 1816

Abstract

The effective stress coefficient for permeability is a significant index for characterizing the variation in permeability with effective stress. The realization of its accuracy is essential for studying the stress sensitivity of oil and gas reservoirs. The determination of the effective stress coefficient for permeability can be mainly evaluated using the cross-plotting or response surface method. Both methods preprocess experimental data and preset a specific function relation, resulting in deviation in the calculation results. To improve the calculation accuracy of the effective stress coefficient for permeability, a 3D surface fitting calculation method was proposed according to the linear effective stress law and continuity hypothesis. The statistical parameters of the aforementioned three methods were compared, and the results showed that the three-dimensional (3D) surface fitting method had the advantages of a high correlation coefficient, low root mean square error, and low residual error. The principal of using the 3D surface fitting method to calculate the effective stress coefficient of permeability was to evaluate the influence of two independent variables on a dependent variable by means of a 3D nonlinear regression. Therefore, the method could be applied to studying the relationship between other physical properties and effective stress. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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16 pages, 2711 KiB

Open AccessArticle

Analysis of Controlling Factors at Separate Imbibition Stages for Ultra-Low-Permeability Reservoirs

by Hailong Dang, Hanqiao Jiang, Binchi Hou, Xiaofeng Wang, Tao Gao, Chengjun Wang and Chunhua Lu

Energies 2021, 14(21), 7093; https://0-doi-org.brum.beds.ac.uk/10.3390/en14217093 - 30 Oct 2021

Cited by 3 | Viewed by 1270

Abstract

Spontaneous imbibition is an important mechanism in naturally fractured reservoirs. In our previous studies on the effect of imbibition efficiency of ultra-low permeability reservoirs, we mostly focused on the relationship between macroscopic core recovery rate and influential factors. Additionally, we also mainly focused on the factors that control the final imbibition recovery for ultra-low permeability reservoirs. Through a large number of experiments, it was found that the factors affecting imbibition are different in separate stages. However, the relative importance of those factors in different imbibition stages was hardly studied. In this work, we tested six key factors, i.e., the core length, RQI, salinity, interfacial characteristics, initial oil saturation, and oil viscosity, in natural sandstone samples from Chang 6 in the Zichang area. Based on experimental results, we divided the imbibition process into three stages (i.e., the early stage, the middle stage, and the late stage) to quantify the effects of the controlling factors. The results show that the relative importance of the controlling factors is changing during the imbibition process. The weight of importance is obtained for those factors at each stage. In addition, a comparative model is established for the dual-porosity media from Chang 6 formation. The results show that the increase of the rock size can extend the imbibition period for the early and middle stages. Moreover, the weight of importance for the initial oil saturation, interfacial characteristics, and salinity are also analyzed in three imbibition stages. This study provides theoretical support to guide water injection in ultra-low-permeability reservoirs and to understand the formation of energy supplements and oil recovery during the imbibition process. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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18 pages, 11749 KiB

Open AccessArticle

Influences of Roughness Sampling Interval and Anisotropy on Shear Failure Mechanism of Rock Joint Surface

by Fan Chen, Hongming Yu, Yilin Yang and Daoyong Wu

Energies 2021, 14(21), 6902; https://0-doi-org.brum.beds.ac.uk/10.3390/en14216902 - 21 Oct 2021

Cited by 4 | Viewed by 1586

Abstract

Roughness is an important factor affecting the engineering stability of jointed rock masses. The existing roughness evaluation methods are all based on a uniform sampling interval, which changes the geometrical morphology of the original profile and inevitably ignores the influence of secondary fluctuations on the roughness. Based on the point cloud data obtained by 3D laser scanning, a non-equal interval sampling method and an equation for determining the sampling frequency on the roughness profile are proposed. The results show that the non-equal interval sampling method can successfully maintain the morphological characteristics of the original profile and reduce the data processing cost. Additionally, direct shear tests under constant normal load (CNL) conditions are carried out to study the influence of roughness anisotropy on the shear failure mechanism of joint surfaces. It is found that with the increase in shear displacement, the variations in the shear stress are related to the failure mechanisms of dilatancy and shear fracture of the joint. Finally, the distributions of shear stress, dilatancy and fracture areas on the rough joint in different shear directions are calculated theoretically. Results show that the anisotropy and failure mechanism of rough joint can be well characterized by the modified root mean square parameter Z₂′. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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15 pages, 32241 KiB

Open AccessArticle

Clarifying the Effect of Clay Minerals on Methane Adsorption Capacity of Marine Shales in Sichuan Basin, China

by Hongyan Wang, Shangwen Zhou, Jiehui Zhang, Ziqi Feng, Pengfei Jiao, Leifu Zhang and Qin Zhang

Energies 2021, 14(20), 6836; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206836 - 19 Oct 2021

Cited by 6 | Viewed by 1786

Abstract

The effect of clay minerals on the methane adsorption capacity of shales is a basic issue that needs to be clarified and is of great significance for understanding the adsorption characteristics and mechanisms of shale gas. In this study, a variety of experimental methods, including XRD, LTNA, HPMA experiments, were conducted on 82 marine shale samples from the Wufeng–Longmaxi Formation of 10 evaluation wells in the southern Sichuan Basin of China. The controlling factors of adsorption capacities were determined through a correlation analysis with pore characteristics and mineral composition. In terms of mineral composition, organic matter (OM) is the most key methane adsorbent in marine shale, and clay minerals have little effect on methane adsorption. The ultra-low adsorption capacity of illite and chlorite and the hydrophilicity and water absorption ability of clay minerals are the main reasons for their limited effect on gas adsorption in marine shales. From the perspective of the pore structure, the micropore and mesopore specific surface areas (SSAs) control the methane adsorption capacity of marine shales, which are mainly provided by OM. Clay minerals have no relationship with SSAs, regardless of mesopores or micropores. In the competitive adsorption process of OM and clay minerals, OM has an absolute advantage. Clay minerals become carriers for water absorption, due to their interlayer polarity and water wettability. Based on the analysis of a large number of experimental datasets, this study clarified the key problem of whether clay minerals in marine shales control methane adsorption. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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20 pages, 4938 KiB

Open AccessArticle

Comparative Study of Lattice Boltzmann Models for Complex Fractal Geometry

by Dong Zhang, Enzhi Wang and Xiaoli Liu

Energies 2021, 14(20), 6779; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206779 - 18 Oct 2021

Cited by 2 | Viewed by 1488

Abstract

A standard model, one of the lattice Boltzmann models for incompressible flow, is broadly applied in mesoscopic fluid with obvious compressible error. To eliminate the compressible effect and the limits in 2D problems, three different models (He-Luo model, Guo’s model, and Zhang’s model) have been proposed and tested by some benchmark questions. However, the numerical accuracy of models adopted in complex geometry and the effect of structural complexity are rarely studied. In this paper, a 2D dimensionless steady flow model is proposed and constructed by fractal geometry with different structural complexity. Poiseuille flow is first simulated to verify the code and shows good agreements with the theoretical solution, supporting further the comparative study on four models to investigate the effect of structural complexity and grid resolution, with reference results obtained by the finite element method (FEM). The work confirms the latter proposed models and effectively reduces compressible error in contrast to the standard model; however, the compressible effect still cannot be ignored in Zhang’s model. The results show that structural error has an approximately negative exponential relationship with grid resolution but an approximately linear relationship with structural complexity. The comparison also demonstrates that the He-Luo model and Guo’s model have a good performance in accuracy and stability, but the convergence rate is lower, while Zhang’s model has an advantage in the convergence rate but the computational stability is poor. The study is significant as it provides guidance and suggestions for adopting LBM to simulate incompressible flow in a complex structure. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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16 pages, 2709 KiB

Open AccessArticle

Prediction of Refracturing Timing of Horizontal Wells in Tight Oil Reservoirs Based on an Integrated Learning Algorithm

by Xianmin Zhang, Jiawei Ren, Qihong Feng, Xianjun Wang and Wei Wang

Energies 2021, 14(20), 6524; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206524 - 11 Oct 2021

Cited by 4 | Viewed by 1559

Abstract

Refracturing technology can effectively improve the EUR of horizontal wells in tight reservoirs, and the determination of refracturing time is the key to ensuring the effects of refracturing measures. In view of different types of tight oil reservoirs in the Songliao Basin, a library of 1896 sets of learning samples, with 11 geological and engineering parameters and corresponding refracturing times as characteristic variables, was constructed by combining numerical simulation with field statistics. After a performance comparison and analysis of an artificial neural network, support vector machine and XGBoost algorithm, the support vector machine and XGBoost algorithm were chosen as the base model and fused by the stacking method of integrated learning. Then, a prediction method of refracturing timing of tight oil horizontal wells was established on the basis of an ensemble learning algorithm. Through the prediction and analysis of the refracturing timing corresponding to 257 groups of test data, the prediction results were in good agreement with the real value, and the correlation coefficient R² was 0.945. The established prediction method can quickly and accurately predict the refracturing time, and effectively guide refracturing practices in the tight oil test area of the Songliao basin. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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16 pages, 7297 KiB

Open AccessArticle

In Situ Deformation Analysis of a Fracture in Coal under Cyclic Loading and Unloading

by Zhihui Liu, Yongfei Yang, Yingwen Li and Jiaxue Li

Energies 2021, 14(20), 6474; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206474 - 10 Oct 2021

Cited by 4 | Viewed by 1460

Abstract

The deformation analysis of fractures is vital for advantageous development of oil and gas fields, especially the coalbed methane (CBM) reservoir, since the change of fracture parameters can be directly evaluated through fracture deformation analysis. Then the flow capacity of CBM and the effect of various stimulation methods can be analyzed. In this study, X-ray CT image analysis is used to quantitatively characterize the deformation of a coal fracture in situ, and the evolution of fracture aperture under cyclic loading is presented. Furthermore, dimensionless permeability at different confining pressures by the Lattice Boltzmann method is simulated. The current results indicate that the fracture deformation changes significantly under cyclic loading. A dramatic change is observed in the initial loading stage, in which the coal is strongly compacted, and the fracture aperture and permeability are reduced to 13.9% and 0.1%, respectively, when the confining pressure is loaded to 10 MPa. When unloading to 0 MPa, the fracture aperture and dimensionless permeability are far less than that of the initial 0 MPa. It is worth noting that the deformation of the second cycle fracture is weaker, and the change range of permeability and aperture of coal fracture becomes smaller, but when unloading to 0 MPa in the second cycle, the fracture permeability can be restored to 50.8% compared with 0 MPa of the loading stage. Additionally, a special phenomenon has been observed that under cyclic loading, even when the confining pressure reaches 10 MPa, some areas of the fracture are still not closed. We infer that there are some large pore structures in fracture space, and high confining pressure leads to fracture closure, but the deformation of the pore structure is not prominent compared with the fracture space. These characteristics of fracture deformation are of great significance for the production of CBM and are worthy of further study. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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23 pages, 21273 KiB

Open AccessArticle

Numerical Investigation for Three-Dimensional Multiscale Fracture Networks Based on a Coupled Hybrid Model

by Xulin Du, Linsong Cheng, Jun Chen, Jianchao Cai, Langyu Niu and Renyi Cao

Energies 2021, 14(19), 6354; https://0-doi-org.brum.beds.ac.uk/10.3390/en14196354 - 05 Oct 2021

Cited by 4 | Viewed by 1618

Abstract

The mismatching between the multi-scale feature of complex fracture networks (CFNs) in unconventional reservoirs and their current numerical approaches is a conspicuous problem to be solved. In this paper, the CFNs are divided into hydraulic macro-fractures, induced fractures, and natural micro-fractures according to their mode of origin. A hybrid model coupling various numerical approaches is proposed to match the three-dimensional multi-scale fracture networks. The macro-fractures with high-conductivity and wide-aperture are explicitly characterized by a mimetic Green element method-based hierarchical fracture model. The induced fractures and natural micro-fractures that have features of low-conductivity and small-openings are upscaled to the dual-medium grid and enhanced matrix grid through the equivalent continuum-medium method, respectively. Subsequently, some benchmark cases are implemented to confirm the high-precision and high-robustness of the proposed hybrid model that indeed accomplishes accurate modeling of fluid flow in multi-scale CFNs by comparing with commercial software tNavigator^®. Furthermore, an integrated workflow of simulation modeling for multiscale CFNs combined with a field example in Sichuan from China is used to analyzing the production information of fractured horizontal wells in shale gas reservoirs. Compared with the field production data from this typical well, it can be proved that the hybrid model has strong reliability and practicability. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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12 pages, 14013 KiB

Open AccessArticle

A Novel Temperature Prediction Model Considering Stress Sensitivity for the Multiphase Fractured Horizontal Well in Tight Reservoirs

by Yonggang Duan, Ruiduo Zhang and Mingqiang Wei

Energies 2021, 14(16), 4760; https://0-doi-org.brum.beds.ac.uk/10.3390/en14164760 - 05 Aug 2021

Cited by 3 | Viewed by 1277

Abstract

An accurate temperature profile of the multi-stage fractured horizontal well is the foundation of production profile interpretation using distributed temperature sensing. In this paper, an oil-water two-phase flow multi-stage fractured horizontal well temperature prediction model considering stress sensitivity effect and the Joule–Thomson effect is constructed. Based on the simulation calculation, the wellbore temperature variation under different formation parameters, water cuts, and fracture parameters is discussed. The wellbore temperature distribution in multistage fractured horizontal wells is affected by many factors. According to the principle of orthogonal experimental design, the difference between wellbore temperature and initial formation temperature is selected as the analysis condition. Sixteen groups of orthogonal experimental calculations are designed and conducted. By analyzing the experimental results, it is found that the fracture half-length, water production, and formation permeability are the main controlling factors of the wellbore temperature profile. Finally, the production profile of the well is determined by calculating the temperature profile of a tight oil well and fitting it to the measured data of distributed temperature sensing. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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10 pages, 25603 KiB

Open AccessArticle

Microscale Evaluation of Tight Oil Mobility: Insights from Pore Network Simulation

by Yongchao Wang, Yanqing Xia, Zihui Feng, Hongmei Shao, Junli Qiu, Suping Ma, Jiaqiang Zhang, Haoyuan Jiang, Jiyong Li, Bo Gao and Lingling Li

Energies 2021, 14(15), 4580; https://0-doi-org.brum.beds.ac.uk/10.3390/en14154580 - 28 Jul 2021

Cited by 3 | Viewed by 1374

Abstract

Pore network modeling based on digital rock is employed to evaluate the mobility of shale oil in Qingshankou Formation, Songliao Basin, China. Computerized tomography technology is adopted in this work to reconstruct the digital rock of shale core. The pore network model is generated based on the computerized tomography data. We simulate the dynamics of fluid flow in a pore network model to evaluate the mobility of fluid in shale formation. The results show that the relative permeability of oil phase increases slowly in the initial stage of the displacement process, which is mainly caused by the poor continuity of the oil phase. In the later stages, with the increase in the oil phase continuity, the range of relative permeability increases. With the increase of organic matter content, the permeability of the water phase remains unchanged at low water saturation, but gradually increases at high water saturation. At the same time, it can be seen that, with the increase in organic matter content, the isosmotic point of the oil–water phase permeability shifts to the left, indicating that the wettability to water phase gradually weakens. Full article

(This article belongs to the Special Issue Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs)

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