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Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanisms, Productivity Prediction, and Novel Modelling Methods—3rd Edition

A special issue of Energies (ISSN 1996-1073). This special issue belongs to the section "H: Geo-Energy".

Deadline for manuscript submissions: 5 December 2025 | Viewed by 3470

Special Issue Editors

Dr. Juntai Shi

E-Mail Website
Guest Editor
State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum(Beijing), Beijing 102249, China
Interests: phase characteristics; percolation mechanism; productivity prediction and development technology of condensate gas reservoir; low permeability gas reservoir; coalbed methane gas reservoir; shale gas reservoir and other complex and unconventional gas reservoirs
Special Issues, Collections and Topics in MDPI journals
Dr. Zheng Sun

E-Mail Website
Guest Editor
State Key Laboratory of Coal Resources and Safe Mining, China University of Mining and Technology, Xuzhou 221116, China
Interests: nanoconfined hydrocarbon phase behavior; nanoconfined fluid flow mechanism; pore network modeling; numerical simulation on coalbed methane reservoirs; production data analysis method; shale gas/oil development; CO2 storage and utilization; condensate gas reservoir
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

We are pleased to share the success of our Special Issues “Oil and Gas Reservoirs: Seepage Mechanism, Productivity Prediction and Development Technology” and “Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanism, Productivity Prediction, and Novel Modelling Methods”.

In the first volume, we successfully published 15 papers:

https://www.mdpi.com/journal/energies/special_issues/oil_gas_seepage_productivity

In the second volume, we successfully published 13 papers:

https://www.mdpi.com/journal/energies/special_issues/R8KU9424ZC

We are now preparing to launch the third volume of this Special Issue, “Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanisms, Productivity Prediction, and Novel Modelling Methods—3rd Edition”.

In order to reach the carbon reduction and carbon neutrality advocated for to achieve global environmental goals, improving oil/gas recovery to balance increasing daily energy demands, rather than reinforcing dependence on coal consumption, is urgent. Meanwhile, after the depletion of regular oil/gas reservoirs, we are forced to redirect our attention to complex conventional and unconventional oil/gas reservoirs, such as condensate gas reservoirs, fractured oil/gas reservoirs, tight oil/gas reservoirs, shale gas/oil, coalbed methane, etc. However, this urgently calls for the phase behavior and seepage mechanisms of fluids in the mentioned complex and unconventional oil/gas reservoirs to be uncovered, and the corresponding productivity prediction and novel modeling methods are still lacking. In order to address this issue, we are pleased to invite you to submit papers to this new Special Issue of Energies, entirely devoted to “Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanisms, Productivity Prediction, and Novel Modelling Methods—3rd Edition”. This Special Issue  emphasizes the current challenges of the description of phase behavior and multiphase flow in the matrix pores of the mentioned oil and gas reservoirs. At the same time, studies focused on the productivity, prediction, and production modeling methods used for these reservoirs are also welcomed.

Potential topics of interest include, but are not limited to:

  • The characterization of nanopore morphology in shale/coal samples;
  • Fluid phase behavior in abnormal high-pressure and high-temperature reservoirs;
  • Fluid phase behavior in the nanopores of shale condensate gas reservoirs;
  • Original multiphase fluid occurrence states in deep oil/gas reservoirs;
  • Pore network modeling towards fluid flow in porous media;
  • Novel numerical simulation methods for complex development modes;
  • Fracture propagation characterization and long-term conductivity calculation;
  • Advanced production data analysis methods based on multiphase flow.

Dr. Juntai Shi
Dr. Zheng Sun
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 submissions that pass pre-check are 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 2600 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

  • phase behavior
  • multiphase seepage mechanism
  • tight oil/gas
  • shale oil/gas
  • gas condensate reservoirs
  • fractured oil/gas reservoirs
  • coalbed methane
  • production prediction
  • stimulation measures
  • data science

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Published Papers (5 papers)

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Research

23 pages, 3798 KB  
Article
Production Performance Analysis and Fracture Volume Parameter Inversion of Deep Coalbed Methane Wells
by Jianshu Wu, Xuesong Xin, Lei Zou, Guangai Wu, Jie Liu, Shicheng Zhang, Heng Wen and Cong Xiao
Energies 2025, 18(18), 4897; https://doi.org/10.3390/en18184897 - 15 Sep 2025
Viewed by 316
Abstract
Deep coalbed methane development faces technical challenges, such as high in situ stress and low permeability. The dynamic evolution of fractures after hydraulic fracturing and the flowback mechanism are crucial for optimizing productivity. This paper focuses on the inversion of post-fracturing fracture volume [...] Read more.
Deep coalbed methane development faces technical challenges, such as high in situ stress and low permeability. The dynamic evolution of fractures after hydraulic fracturing and the flowback mechanism are crucial for optimizing productivity. This paper focuses on the inversion of post-fracturing fracture volume parameters and dynamic analysis of the flowback in deep coalbed methane wells, with 89 vertical wells in the eastern margin of the Ordos Basin as the research objects, conducting systematic studies. Firstly, through the analysis of the double-logarithmic curve of normalized pressure and material balance time, the quantitative inversion of the volume of propped fractures and unpropped secondary fractures was realized. Using Pearson correlation coefficients to screen characteristic parameters, four machine learning models (Ridge Regression, Decision Tree, Random Forest, and AdaBoost) were constructed for fracture volume inversion prediction. The results show that the Random Forest model performed the best, with a test set R2 of 0.86 and good generalization performance, so it was selected as the final prediction model. With the help of the SHAP model to analyze the influence of each characteristic parameter, it was found that the total fluid volume into the well, proppant intensity, minimum horizontal in situ stress, and elastic modulus were the main driving factors, all of which had threshold effects and exerted non-linear influences on fracture volume. The interaction of multiple parameters was explored by the Partial Dependence Plot (PDP) method, revealing the synergistic mechanism of geological and engineering parameters. For example, a high elastic modulus can enhance the promoting effect of fluid volume into the well and proppant intensity. There is a critical threshold of 2600 m3 in the interaction between the total fluid volume into the well and the minimum horizontal in situ stress. These findings provide a theoretical basis and technical support for optimizing fracturing operation parameters and efficient development of deep coalbed methane. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanisms, Productivity Prediction, and Novel Modelling Methods—3rd Edition)
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24 pages, 11697 KB  
Article
Layered Production Allocation Method for Dual-Gas Co-Production Wells
by Guangai Wu, Zhun Li, Yanfeng Cao, Jifei Yu, Guoqing Han and Zhisheng Xing
Energies 2025, 18(15), 4039; https://doi.org/10.3390/en18154039 - 29 Jul 2025
Viewed by 423
Abstract
The synergistic development of low-permeability reservoirs such as deep coalbed methane (CBM) and tight gas has emerged as a key technology to reduce development costs, enhance single-well productivity, and improve gas recovery. However, due to fundamental differences between coal seams and tight sandstones [...] Read more.
The synergistic development of low-permeability reservoirs such as deep coalbed methane (CBM) and tight gas has emerged as a key technology to reduce development costs, enhance single-well productivity, and improve gas recovery. However, due to fundamental differences between coal seams and tight sandstones in their pore structure, permeability, water saturation, and pressure sensitivity, significant variations exist in their flow capacities and fluid production behaviors. To address the challenges of production allocation and main reservoir identification in the co-development of CBM and tight gas within deep gas-bearing basins, this study employs the transient multiphase flow simulation software OLGA to construct a representative dual-gas co-production well model. The regulatory mechanisms of the gas–liquid distribution, deliquification efficiency, and interlayer interference under two typical vertical stacking relationships—“coal over sand” and “sand over coal”—are systematically analyzed with respect to different tubing setting depths. A high-precision dynamic production allocation method is proposed, which couples the wellbore structure with real-time monitoring parameters. The results demonstrate that positioning the tubing near the bottom of both reservoirs significantly enhances the deliquification efficiency and bottomhole pressure differential, reduces the liquid holdup in the wellbore, and improves the synergistic productivity of the dual-reservoirs, achieving optimal drainage and production performance. Building upon this, a physically constrained model integrating real-time monitoring data—such as the gas and liquid production from tubing and casing, wellhead pressures, and other parameters—is established. Specifically, the model is built upon fundamental physical constraints, including mass conservation and the pressure equilibrium, to logically model the flow paths and phase distribution behaviors of the gas–liquid two-phase flow. This enables the accurate derivation of the respective contributions of each reservoir interval and dynamic production allocation without the need for downhole logging. Validation results show that the proposed method reliably reconstructs reservoir contribution rates under various operational conditions and wellbore configurations. Through a comparison of calculated and simulated results, the maximum relative error occurs during abrupt changes in the production capacity, approximately 6.37%, while for most time periods, the error remains within 1%, with an average error of 0.49% throughout the process. These results substantially improve the timeliness and accuracy of the reservoir identification. This study offers a novel approach for the co-optimization of complex multi-reservoir gas fields, enriching the theoretical framework of dual-gas co-production and providing technically adaptive solutions and engineering guidance for multilayer unconventional gas exploitation. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanisms, Productivity Prediction, and Novel Modelling Methods—3rd Edition)
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15 pages, 1918 KB  
Article
Innovative Application of the Ritz Method to Oil-Gas Seepage Problems: A Novel Variational Approach for Solving Underground Flow Equations
by Xiongzhi Liu, Hao Yang, Lifei Dong, Ming Lei, Jie Han and Hao Kang
Energies 2025, 18(12), 3207; https://doi.org/10.3390/en18123207 - 18 Jun 2025
Viewed by 369
Abstract
State-of-the-art commercial simulators (e.g., Eclipse, CMG) predominantly employ finite difference schemes, which face persistent challenges in modeling strongly nonlinear seepage dynamics. This study explores the application of the Ritz method, grounded in variational theory, to solve underground oil seepage problems in reservoir engineering. [...] Read more.
State-of-the-art commercial simulators (e.g., Eclipse, CMG) predominantly employ finite difference schemes, which face persistent challenges in modeling strongly nonlinear seepage dynamics. This study explores the application of the Ritz method, grounded in variational theory, to solve underground oil seepage problems in reservoir engineering. The research focuses on deriving the variational form of steady-state seepage equations and presents a systematic procedure for solving these equations in finite domains. Using a one-dimensional steady-state seepage problem as a case study (which can effectively represent a wide range of typical flow regimes), the study compares the approximate solutions obtained by the Ritz method (both monomial and binomial forms) with exact solutions. The results demonstrate that the binomial approximate solution achieves high accuracy, with an average deviation of only 0.30% from the exact solution, significantly outperforming the monomial solution. The findings validate the Ritz method as an effective tool for addressing seepage problems and highlight its potential for broader applications in oil and gas reservoir modeling. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanisms, Productivity Prediction, and Novel Modelling Methods—3rd Edition)
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17 pages, 8752 KB  
Article
Normalization of Relative-Permeability Curves of Cores in High-Water-Content Tight Sandstone Gas Reservoir
by Bo Hu, Jingang Fu, Wenxin Yan, Kui Chen and Jingchen Ding
Energies 2025, 18(9), 2335; https://doi.org/10.3390/en18092335 - 3 May 2025
Viewed by 812
Abstract
The gas–water relative-permeability relationship in tight gas is complex due to interactions between the gas and water phases within the porous media in the reservoir. To clarify the fluid occurrence and the gas–water relative-permeability behavior in such reservoirs, the Dongsheng tight water-bearing reservoir [...] Read more.
The gas–water relative-permeability relationship in tight gas is complex due to interactions between the gas and water phases within the porous media in the reservoir. To clarify the fluid occurrence and the gas–water relative-permeability behavior in such reservoirs, the Dongsheng tight water-bearing reservoir from the Ordos Basin of China is taken as the research object. A non-steady state method is employed to explore the co-permeability of gas and water phases under dynamic conditions. The irreducible water saturation of different core samples is analyzed using nuclear magnetic resonance (NMR) centrifugation. The Simplified Stone equation is applied for phase permeability normalization. The results indicate that with the decrease in core permeability, the irreducible water saturation increases, and the gas and water permeability decreases. When the displacement pressure difference increases, the gas phase permeability decreases, and the water phase permeability increases. The centrifugal method is effective in reducing the saturation of bound water in rock cores. The displacement method forms channels using gas, which effectively removes free water, particularly in larger or smaller pores. In contrast, centrifugation further displaces water from smaller or capillary pores, where flow is more restricted. Based on these experimental findings, a relationship between displacement pressure difference, critical irreducible water saturation, and residual gas saturation is established. The Stone equation is further refined, and a phase permeability normalization curve is proposed, accounting for the true irreducible water saturation of rock. This provides a more accurate theoretical framework for understanding and managing the gas–water interaction in tight gas reservoirs with a high water content, ultimately aiding in the optimization of reservoir development strategies. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanisms, Productivity Prediction, and Novel Modelling Methods—3rd Edition)
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24 pages, 22367 KB  
Article
Laboratory-to-Field Scale Numerical Investigation of Enhanced Oil Recovery Mechanism for Supercritical CO2-Energized Fracturing
by Xiaolun Yan, Ting Zuo, Jianping Lan, Yu Jia and Cong Xiao
Energies 2025, 18(3), 515; https://doi.org/10.3390/en18030515 - 23 Jan 2025
Viewed by 977
Abstract
This study systematically performs multi-scale numerical investigation of supercritical CO2-energized fracturing, widely employed for enhanced oil recovery (EOR) in tight oil and gas reservoirs. Two distinct models, spanning from core scale to field scale, are designed to explore the diffusion patterns [...] Read more.
This study systematically performs multi-scale numerical investigation of supercritical CO2-energized fracturing, widely employed for enhanced oil recovery (EOR) in tight oil and gas reservoirs. Two distinct models, spanning from core scale to field scale, are designed to explore the diffusion patterns of CO2 into the matrix and its impact on crude oil production at varying scales. The core-scale model employs discrete grid regions to simulate the interaction between fractures and the core, facilitating a comprehensive understanding of CO2 diffusion and its interaction with crude oil. Based on the core-scale numerical model, the wellbore treatment process is simulated, investigating CO2 distribution within the core and its influence on crude oil during the well treatment phase. The field-scale model employs a series of grids to simulate fractures, the matrix, and the treatment zone. Additionally, a dilation model is employed to simulate fracture initiation and closure during CO2 fracturing and production processes. The model explores CO2 diffusion and its interaction with crude oil at different shut-in times and various injection rates, analyzing their impact on cumulative oil production within a year. The study concludes that during shut-in, CO2 continues to diffuse deeper into the matrix until CO2 concentration reaches an equilibrium within a certain range. At the core scale, CO2 penetrates approximately 4 cm into the core after a 15-day shut-in, effectively reducing the viscosity within a range of about 3.5 cm. At the field scale, CO2 diffusion extends up to approximately 4 m, with an effective viscosity reduction zone of about 3 m. Results suggest that, theoretically, higher injection rates and longer shut-in times yield better EOR results. However, considering economic factors, a 20-day shut-in period is preferred. Different injection rates indicate varying fracture conduction capabilities upon gas injection completion. Full article
(This article belongs to the Special Issue Oil and Gas Reservoirs: Phase Behavior, Seepage Mechanisms, Productivity Prediction, and Novel Modelling Methods—3rd Edition)
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