Special Issue "Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs"

A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "G1: Petroleum Engineering".

Deadline for manuscript submissions: 15 December 2021.
Submit your paper and select the Journal “Energies” and the Special Issue “Multiscale Petrophysics Characterization and Multiphase Flow in Unconventional Reservoirs” via: https://susy.mdpi.com/user/manuscripts/upload?journal=energies. Please contact the first guest editor or the journal editor ([email protected]) for any queries.

Special Issue Editors

Prof. Dr. Reza Rezaee
E-Mail Website
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
grade E-Mail Website
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

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.

Submitted manuscripts should not have been published previously, nor be under consideration for publication elsewhere (except conference proceedings papers). All manuscripts are thoroughly refereed through a single-blind peer-review process. A guide for authors and other relevant information for submission of manuscripts is available on the Instructions for Authors page. Energies is an international peer-reviewed open access semimonthly journal published by MDPI.

Please visit the Instructions for Authors page before submitting a manuscript. The Article Processing Charge (APC) for publication in this open access journal is 2000 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

  • 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 (9 papers)

Order results
Result details
Select all
Export citation of selected articles as:

Research

Article
Analysis of Controlling Factors at Separate Imbibition Stages for Ultra-Low-Permeability Reservoirs
Energies 2021, 14(21), 7093; https://0-doi-org.brum.beds.ac.uk/10.3390/en14217093 - 30 Oct 2021
Viewed by 260
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 [...] Read more.
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
Show Figures

Figure 1

Article
Influences of Roughness Sampling Interval and Anisotropy on Shear Failure Mechanism of Rock Joint Surface
Energies 2021, 14(21), 6902; https://0-doi-org.brum.beds.ac.uk/10.3390/en14216902 - 21 Oct 2021
Viewed by 321
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 [...] Read more.
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
Show Figures

Figure 1

Article
Clarifying the Effect of Clay Minerals on Methane Adsorption Capacity of Marine Shales in Sichuan Basin, China
Energies 2021, 14(20), 6836; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206836 - 19 Oct 2021
Viewed by 266
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 [...] Read more.
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
Show Figures

Figure 1

Article
Comparative Study of Lattice Boltzmann Models for Complex Fractal Geometry
Energies 2021, 14(20), 6779; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206779 - 18 Oct 2021
Viewed by 347
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) [...] Read more.
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
Show Figures

Figure 1

Article
Prediction of Refracturing Timing of Horizontal Wells in Tight Oil Reservoirs Based on an Integrated Learning Algorithm
Energies 2021, 14(20), 6524; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206524 - 11 Oct 2021
Viewed by 347
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 [...] Read more.
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
Show Figures

Figure 1

Article
In Situ Deformation Analysis of a Fracture in Coal under Cyclic Loading and Unloading
Energies 2021, 14(20), 6474; https://0-doi-org.brum.beds.ac.uk/10.3390/en14206474 - 10 Oct 2021
Viewed by 406
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 [...] Read more.
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
Show Figures

Figure 1

Article
Numerical Investigation for Three-Dimensional Multiscale Fracture Networks Based on a Coupled Hybrid Model
Energies 2021, 14(19), 6354; https://0-doi-org.brum.beds.ac.uk/10.3390/en14196354 - 05 Oct 2021
Viewed by 300
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 [...] Read more.
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
Show Figures

Figure 1

Article
A Novel Temperature Prediction Model Considering Stress Sensitivity for the Multiphase Fractured Horizontal Well in Tight Reservoirs
Energies 2021, 14(16), 4760; https://0-doi-org.brum.beds.ac.uk/10.3390/en14164760 - 05 Aug 2021
Viewed by 384
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 [...] Read more.
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
Show Figures

Figure 1

Article
Microscale Evaluation of Tight Oil Mobility: Insights from Pore Network Simulation
Energies 2021, 14(15), 4580; https://0-doi-org.brum.beds.ac.uk/10.3390/en14154580 - 28 Jul 2021
Viewed by 419
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 [...] Read more.
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
Show Figures

Graphical abstract

Back to TopTop