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Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional...
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Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition)

A special issue of Processes (ISSN 2227-9717). This special issue belongs to the section "Chemical Processes and Systems".

Deadline for manuscript submissions: 20 November 2025 | Viewed by 11790

Special Issue Editors

Dr. Chao Zhang

E-Mail Website
Guest Editor
School of Petroleum Engineering, China University of Petroleum (East China), Qingdao 266580, China
Interests: CO2 flooding; CO2 geological sequestration; foam fluids EOR (enhanced oil recovery); heavy oil; tight oil; fracture-vuggy carbonate reservoir
Special Issues, Collections and Topics in MDPI journals
Dr. Tengfei Wang

E-Mail Website
Guest Editor
College of Chemistry & Environmental Engineering, Yangtze University, Jingzhou 434000, China
Interests: chemistry flooding; gas flooding; heavy oil development; tight oil development; oil shale development; fracture-vuggy carbonate reservoir development
Special Issues, Collections and Topics in MDPI journals
Dr. Xingbang Meng

E-Mail Website
Guest Editor
Department of Petroleum Engineering, Changzhou University, Changzhou 213164 China
Interests: foam fluids EOR (enhanced oil recovery); unconventional reservoirs; modeling

Special Issue Information

Dear Colleagues,

Unconventional reservoirs, including shale and tight oil and gas, heavy oil, coal bed methane (CBM), natural gas, and fracture-vuggy carbonate reservoirs, are widely distributed and abundant around the world. This is an important area for the strategic replacement and development of oil and gas resources. In contrast to conventional reservoirs, the multiphase fluid flow law and the development process in unconventional reservoirs are more complex. The pore scales of unconventional oil and gas reservoirs involve centimeter, micron, and nanometer scales. The formation environment is mostly of a high temperature, high pressure, and high salinity. The flow of a fluid in a porous medium is also a rather complicated course, combining intricate phase variations. These issues have all contributed to the difficulties involved in oil and gas development and are attracting increasing attention from academics.

This Special Issue focuses on the sustainable development of unconventional oil and gas resources, recent advances, and the challenges they are facing for sustainability. We aim to gather researchers in the aforementioned fields to highlight the current development of novel techniques; exchange the latest knowledge regarding the underlying mechanisms; present advanced algorithms for modeling and innovative experimental methods; and facilitate collaboration between researchers in different fields. We welcome the submission of both original research and review articles.

Potential topics include, but are not limited to, the following:

  • Multi-scale simulations of fluid flow in fracture-vuggy carbonate reservoirs;
  • Adsorption and desorption in shale and CBM;
  • New advances in natural gas hydrate development;
  • Gas injection assisting heavy oil development;
  • The efficient utilization of multifunctional foam fluid;
  • CO2-based enhanced oil recovery (EOR) in unconventional oil and gas reservoirs;
  • CO2 storage in abundant reservoirs.

Dr. Chao Zhang
Dr. Tengfei Wang
Dr. Xingbang Meng
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. Processes is an international peer-reviewed open access monthly 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 2400 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

  • unconventional reservoir
  • efficient development measures
  • green technologies
  • sustainability
  • carbon reduction

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Related Special Issue

Published Papers (13 papers)

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Research

18 pages, 5027 KiB  
Article
Investigation of Foam Mobility Control Mechanisms in Parallel Fractures
by Xiongwei Liu, Yibo Feng, Bo Wang, Jianhai Wang, Yan Xin, Binfei Li and Zhengxiao Xu
Processes 2025, 13(5), 1527; https://doi.org/10.3390/pr13051527 - 15 May 2025
Viewed by 104
Abstract
Fractured vuggy reservoirs exhibit intricate fracture networks, where large fractures impose significant shielding effects on smaller ones, posing formidable challenges for efficient exploitation. A systematic evaluation of foaming volume, drainage half-life, decay behavior, and viscosity under varying temperatures and salinities was conducted for [...] Read more.
Fractured vuggy reservoirs exhibit intricate fracture networks, where large fractures impose significant shielding effects on smaller ones, posing formidable challenges for efficient exploitation. A systematic evaluation of foaming volume, drainage half-life, decay behavior, and viscosity under varying temperatures and salinities was conducted for conventional foam, polymer-enhanced foam, and gel foam. The results yield the following conclusions: Compared to conventional foam, polymer-enhanced foam exhibits markedly improved stability. In contrast, gel foam, cross-linked with chemical agents, maintains stability for over one week at elevated temperatures, albeit at the expense of reduced foaming capacity. The three-dimensional network structure formed post-gelation enables gel foam to retain a thicker liquid film, exhibiting exceptional foam stability. As salinity increases, the base liquid viscosity of conventional foam remains largely unaffected, whereas polymer foam shows marked viscosity reduction. Gel foam displays a non-monotonic viscosity response—initially increasing due to ionic cross-linking and subsequently declining from excessive charge screening. All three systems exhibit significant viscosity decreases under high-temperature conditions. Visualized plate fracture model experiments revealed distinct flow patterns and mobility control performance; narrow fractures exacerbate bubble coalescence under shear stress, leading to enlarged bubble sizes and diminished plugging efficiency. Among the three systems, gel foam exhibited superior mobility control characteristics, with uniform bubble size distribution and enhanced stability. Integrating the findings from the foam mobility control experiments in parallel fracture systems with the diversion outcomes of mobility control and flooding, distinct performance trends emerge. It can be seen that the stronger the foam stability, the stronger the mobility control ability, and the easier it is to start the shielding effect. Combined with the stability of different foam systems, understanding the mobility control ability of a foam system is the key to increasing the sweep coefficient of a complex fracture network and improve oil-washing efficiency. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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20 pages, 6698 KiB  
Article
Research on Injection Profile Interpretation Method Based on DTS Logging
by Haitao Huang, Hongwei Song, Ming Li and Xinlei Shi
Processes 2025, 13(3), 733; https://doi.org/10.3390/pr13030733 - 3 Mar 2025
Viewed by 684
Abstract
Distributed temperature sensing (DTS) has been widely used in downhole dynamic monitoring. How to analyze its data and accurately interpret the flow profile using DTS data are still great challenges. Quantitative interpretation of downhole temperature measurements requires the development of an integrated flow [...] Read more.
Distributed temperature sensing (DTS) has been widely used in downhole dynamic monitoring. How to analyze its data and accurately interpret the flow profile using DTS data are still great challenges. Quantitative interpretation of downhole temperature measurements requires the development of an integrated flow and thermal model capable of handling multi-phase flow. The model must strike a balance between computational efficiency and achieving the highest possible accuracy. The finite difference method can solve the relevant problems well. The flow model and thermal model of reservoirs and wellbores are established. Combined with the single-phase flow theory, the coupling prediction model of wellbore and reservoir temperature is established through appropriate boundary and constraint conditions. The problem was solved iteratively using the finite difference method, and the coupled temperature prediction model’s reliability was confirmed through comparison with numerical simulation results. Based on the forward model, the sensitivity analysis of the influencing factors is carried out in this study which provides a theoretical basis for the inversion model. Taking the flow rate as the inversion parameter, the injection profile interpretation model based on DTS logging data is constructed. Four optimization methods are used in the inversion model which can balance the computational efficiency and model accuracy. The DTS data are preprocessed by the Kalman filter, and the inversion and interpretation evaluation of X injection well is carried out by the LSO-MCMC combined optimization algorithm. The results show that the method has high reliability in the interpretation accuracy of injection profile, and the inverted flow profile meets practical application requirements, confirming the method’s accuracy and effectiveness. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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18 pages, 8369 KiB  
Article
Remaining Oil Distribution and Enhanced Oil Recovery Mechanisms Through Multi-Well Water and Gas Injection in Weathered Crust Reservoirs
by Yuegang Wang, Wanjiang Guo, Gangzheng Sun, Xu Zhou, Junzhang Lin, Mingshan Ding, Zhaoqin Huang and Yingchang Cao
Processes 2025, 13(1), 241; https://doi.org/10.3390/pr13010241 - 15 Jan 2025
Cited by 1 | Viewed by 1038
Abstract
Weathered crust karst reservoirs with intricately interconnected fractures and caves are common but challenging enhanced oil recovery (EOR) targets. This paper investigated the remaining oil distribution rules, formation mechanisms, and EOR methods through physical experiments on acrylic models resembling the geological features of [...] Read more.
Weathered crust karst reservoirs with intricately interconnected fractures and caves are common but challenging enhanced oil recovery (EOR) targets. This paper investigated the remaining oil distribution rules, formation mechanisms, and EOR methods through physical experiments on acrylic models resembling the geological features of weathered crust reservoirs. Acrylic models with precision dimensions and morphologies were fabricated using laser etching technology. By comparing experiments under different cave filling modes and production well locations, it was shown that a higher cave filling extent led to poorer bottom water flooding recovery due to stronger flow resistance but slower rising water cut owing to continued production from the filling medium. Multi-well water and gas injection achieved higher incremental oil recovery by alternating injection–production arrangements to establish new displacement channels and change drive energy. Gas injection recovered more attic remaining oil from upper cave regions, while subsequent water injection helped wash the residual oil in the filling medium. The findings reveal the significant effects of fracture cave morphological configuration and connectivity on remaining oil distribution. This study provides new insights and guidance for EOR design optimization catering to the unique features of weathered crust karst fractured vuggy reservoirs. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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15 pages, 4570 KiB  
Article
Preparation of Heat and Salt Resistant Foam Composite System Based on Weathered Coal Particle Strengthening and a Study on Foam Stabilization Mechanism
by Yanyan Xu, Linghui Xi, Yajun Wu, Xin Shi, Zhi Kang, Beibei Wu and Chao Zhang
Processes 2025, 13(1), 183; https://doi.org/10.3390/pr13010183 - 10 Jan 2025
Viewed by 569
Abstract
Nitrogen foam is a promising enhanced oil recovery (EOR) technique with significant potential for tertiary oil recovery. This improves the efficiency of the oil displacement during the gas drive processes while expanding the swept volume. However, in the high-temperature, high-salinity reservoirs of the [...] Read more.
Nitrogen foam is a promising enhanced oil recovery (EOR) technique with significant potential for tertiary oil recovery. This improves the efficiency of the oil displacement during the gas drive processes while expanding the swept volume. However, in the high-temperature, high-salinity reservoirs of the Tahe Oilfield, conventional N2 foam systems show suboptimal performance, as their effectiveness is heavily limited by temperature and salinity. Consequently, enhancing the foam stability under these harsh conditions is crucial for unlocking new opportunities for the development of Tahe fracture-vuggy reservoirs. In this study, the Waring–Blender method was used to prepare weathered coal particles as a foam stabilizer. Compared to conventional foam stabilizers, weathered coal particles were found to enhance the stability of the liquid film under high-temperature and high-salinity conditions. Firstly, the foaming properties of the six foaming agents were comprehensively evaluated and their foaming properties were observed at different concentrations. YL-3J with a mass concentration of 0.7% was selected. The foaming stabilization performance of four types of solid particles was evaluated and weathered coal solid particles with a mass concentration of 15% and particle size of 300 mesh were selected. Therefore, the particle-reinforced foam system was determined to consist of “foaming agent YL-3J (0.7%) + weathered coal (15.0%) + nitrogen”. This system exhibited a foaming volume of 310 mL at 150 °C and salinity of 210,000 mg/L, with a half-life of 1920 s. Finally, through interfacial tension and viscoelastic modulus tests, the synergistic mechanism between weathered coal particles and surfactants was demonstrated. The incorporation of weathered coal particles reduced the interfacial tension of the system. The formation of a skeleton at the foam interface increased the apparent viscosity and viscoelastic modulus, reduced the liquid drainage rate from the foam, and mitigated the disproportionation effect. These effects enhanced the temperature, salinity resistance, and stability of the foam. Consequently, they contributed to the stable flow of foam under high-temperature and high-salinity conditions in the reservoir, thereby improving the oil displacement efficiency of the system. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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13 pages, 5380 KiB  
Article
Physical Modeling of High-Pressure Flooding and Development of Oil Displacement Agent for Carbonate Fracture-Vuggy Reservoir
by Jinghui Li, Wen Zhang, Bochao Qu, Enlong Zhen, Zhen Qian, Shufen Ma, Fei Qin and Qing You
Processes 2025, 13(1), 71; https://doi.org/10.3390/pr13010071 - 1 Jan 2025
Cited by 1 | Viewed by 895
Abstract
The fracture-cavity carbonate reservoir in Tahe oilfield is buried deep (more than 5000 m). The reservoir has low permeability, strong heterogeneity, large size, diverse forms of connectivity, and complex spatial distribution. In conventional water flooding, it is difficult to improve oil recovery effectively [...] Read more.
The fracture-cavity carbonate reservoir in Tahe oilfield is buried deep (more than 5000 m). The reservoir has low permeability, strong heterogeneity, large size, diverse forms of connectivity, and complex spatial distribution. In conventional water flooding, it is difficult to improve oil recovery effectively because of small water flood sweep and large injection pressure. Pressure flooding is a new water injection technique that can change the reservoir pore space. Combined with an oil displacement agent, pressure flooding is expected to improve the recovery rate of carbonate reservoirs. In this paper, the influence factors of pressure flooding technology are studied, and a set of surfactant systems suitable for high-temperature and high-salt reservoirs is developed. The results show that only an appropriate injection flow can produce microfractures. Only an appropriate displacement rate can optimize the effects of pressure flooding. With an increase in crude oil viscosity, the recovery rate after pressure flooding decreases gradually. A complex fracture network is formed in reservoirs after pressure flooding. The new surfactant system has good interfacial tension reduction properties and excellent stability. Pressure flooding experiments with the addition of a surfactant showed that the system can help to improve the recovery of pressure flooding. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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12 pages, 3737 KiB  
Article
Novel Scaling Prediction Model for Gathering and Transportation Station in Changqing Oilfield
by Ting Liu, Jiaqing You, Zheng Zhang, Shengfu Dongye, Jinlin Zhao, Fashi Zhang and Na Zhang
Processes 2024, 12(12), 2915; https://doi.org/10.3390/pr12122915 - 19 Dec 2024
Viewed by 750
Abstract
Scaling is a significant challenge in oilfield production gathering and transportation stations, and it not only constrains the economic efficiency but also affects the development of oil and natural gas. This study proposes a scaling prediction model based on chemical experimental analysis and [...] Read more.
Scaling is a significant challenge in oilfield production gathering and transportation stations, and it not only constrains the economic efficiency but also affects the development of oil and natural gas. This study proposes a scaling prediction model based on chemical experimental analysis and reservoir dynamic analysis methods for the gathering and transportation stations in the Changqing Oilfield. The objective of this study is to provide technical support for the oilfield to advance precise management and achieve cost reduction and efficiency enhancement. Initially, the water quality and scale samples of the oilfield were tested and analyzed using Inductively Coupled Plasma (ICP), Ion Chromatography (IC), and Scanning Electron Microscopy-Energy Dispersive Spectroscopy (SEM-EDS), and the distribution and patterns of scaling in the gathering and transportation pipelines were studied. Based on this, using the test data and the production liquid ratio of each development layer at the gathering and transportation stations, a reservoir dynamic correlation method was employed to construct a prediction model for the development layer with the highest similarity to the tested water samples at the stations and the types of scale samples. The results indicate that this prediction method can effectively reduce the scaling rate and provide guidance for the anti-scaling process in the Changqing Oilfield. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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14 pages, 10028 KiB  
Article
Molecular Dynamics Simulation on the Process of Ultrasonic Viscosity Reduction
by Jianchao Shi, Li Tong, Lin Sun, Tao Jiang, Xiaofeng Yu, Kaijie Yu, Shaobo Lu and Weiwei Xu
Processes 2024, 12(12), 2803; https://doi.org/10.3390/pr12122803 - 8 Dec 2024
Viewed by 817
Abstract
In this work, through experiments and molecular dynamics simulations, it was found that the viscosity of heavy oil decreased significantly after ultrasonic treatment, and the viscosity reduction rate can be up to 60%. The simulation results show that under the action of ultrasound, [...] Read more.
In this work, through experiments and molecular dynamics simulations, it was found that the viscosity of heavy oil decreased significantly after ultrasonic treatment, and the viscosity reduction rate can be up to 60%. The simulation results show that under the action of ultrasound, the macromolecules in the heavy oil were broken into small molecular hydrocarbons accounting for 89.2% with fewer carbon numbers (<6) and simple structures, as well as small molecules containing heteroatoms. The fracture rate of different bonds in the macromolecule under the action of ultrasound was in the range of 25% to 43%. The simulation results provide a theoretical basis for the industrial application of ultrasonic viscosity reduction. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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15 pages, 7235 KiB  
Article
Molecular Dynamics of CO₂ Stripping Oil on Quartz Surfaces
by Yawen Tan, Yiqun Zhang, Hao Xiong, Shouceng Tian and Fei Wang
Processes 2024, 12(12), 2776; https://doi.org/10.3390/pr12122776 - 6 Dec 2024
Cited by 1 | Viewed by 841
Abstract
The CO2-enhanced oil recovery (EOR) technology has the dual significance of enhancing oil recovery and realizing carbon storage in onshore and offshore oil and gas exploitation. This study investigates the adsorption of crude oil components on quartz surfaces and the microscopic [...] Read more.
The CO2-enhanced oil recovery (EOR) technology has the dual significance of enhancing oil recovery and realizing carbon storage in onshore and offshore oil and gas exploitation. This study investigates the adsorption of crude oil components on quartz surfaces and the microscopic mechanisms of CO2 stripping from crude oil using molecular dynamics simulations. A four-component model representing C6H14, benzene, resins, and asphaltenes was constructed to simulate the oil phase, while the quartz surface model was created using Materials Studio. Simulations were conducted under different temperature conditions to understand the distribution and adsorption behavior of crude oil components, as well as the impact of CO2 on the oil film at pressures up to 10 MPa. The results indicate that the resin–asphaltene interactions are significantly weakened at elevated temperatures, affecting the adsorption capacity. Furthermore, CO2 stripping primarily extracts light components such as C6H14 and aromatic hydrocarbons, while heavy components remain in the oil phase. The highest extraction efficiency and expansion effect of CO2 were observed at 35 °C, demonstrating optimal conditions for enhanced oil recovery through CO2 flooding. These findings provide insights into the effective use of CO2 for crude oil extraction and its interactions with oil components on a quartz substrate, which is crucial for optimizing CO2-enhanced oil recovery operations. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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10 pages, 3623 KiB  
Article
Production Law of Shielding Oil in Fractured Carbonate Reservoirs: A Case Study of Northwest Oilfield, China
by Jinghui Li, Bochao Qu, Enlong Zhen, Shufen Ma and Yifei Liu
Processes 2024, 12(11), 2432; https://doi.org/10.3390/pr12112432 - 4 Nov 2024
Viewed by 991
Abstract
Multi-scale fractures in Northwest Oilfield are extremely developed. Fractures in both oil flow channels and water channels lead to the phenomenon of water channeling in the later stages of reservoir development, which may be affected by the bottom water cone. Gel plugging agents [...] Read more.
Multi-scale fractures in Northwest Oilfield are extremely developed. Fractures in both oil flow channels and water channels lead to the phenomenon of water channeling in the later stages of reservoir development, which may be affected by the bottom water cone. Gel plugging agents are widely used in the treatment of this phenomenon because of their low cost and high-water plugging efficiency. However, because there is often residual oil in small-scale fractures, the pressure law of different grades of differential fractures on gel is not clear, thus leading to low gel application efficiency and low oil recovery. There is still a lack of effective means through which to understand the regularity of shielding the remaining oil with gel strength and fractures of different grades. In this study, we conducted a novel analysis of the law of shielding oil production in fractured reservoirs. The gelling and rheological properties of anti-temperature gels (ATGs) with different strengths were studied. The plugging rate of oil phase was 96.39%, and that of water phase was 25.37%. ATG showed good oil–water selectivity. The influences of different grades of differential fractures on the production law of shielding the remaining oil were also studied, as well as the corresponding influence law chart. When the gel strength was in the range of 2.0–28.1 Pa and the fracture grade difference was 5–10, the recovery ratio was increased by 10.6–24%. The enhanced oil recovery can be quantitatively predicted by the scale of reservoir fractures and the strength of gel used. It has a certain guiding role for the field application of gel to efficiently shield residual oil in differential fractures. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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18 pages, 7878 KiB  
Article
Flow Profiling Analysis of a Refractured Tight Oil Well Using Distributed Temperature Sensing
by Changhao Yan, Jiawei Ren, Qiong Shi, Xiangping Li, Yuen Bai and Wei Yu
Processes 2024, 12(10), 2106; https://doi.org/10.3390/pr12102106 - 27 Sep 2024
Cited by 1 | Viewed by 1004
Abstract
This study presents an in-depth analysis of a refractured tight oil well, focusing on both the initial and subsequent refracturing operations. After refracturing, daily oil production surged from 0.8 to 15.0 tons. The well sustained natural flow for 100 days before transitioning to [...] Read more.
This study presents an in-depth analysis of a refractured tight oil well, focusing on both the initial and subsequent refracturing operations. After refracturing, daily oil production surged from 0.8 to 15.0 tons. The well sustained natural flow for 100 days before transitioning to pump-assisted production, resulting in an additional cumulative oil production of 1412 tons. Leveraging distributed temperature sensing (DTS), high-resolution temperature monitoring was performed, revealing key insights into the behavior of both newly created and existing fractures. Older perforation stages outperformed newer ones, with average daily oil production of 4.66 m3 for older stages and 3.49 m3 for newer stages under a 2 mm choke size. Moreover, CO2 pre-fracturing significantly enhanced oil production, with the stages receiving CO2 injection achieving a median daily oil output of 4.04 m3, compared to 3.55 m3 for non-CO2 stages. These results demonstrate the effectiveness of integrating advanced monitoring techniques and innovative fracturing methods to optimize refracturing strategies, ultimately enhancing hydrocarbon recovery in tight oil reservoirs. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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14 pages, 4983 KiB  
Article
Inverse Problem of Permeability Field under Multi-Well Conditions Using TgCNN-Based Surrogate Model
by Jian Li, Ran Zhang, Haochen Wang and Zhengxiao Xu
Processes 2024, 12(9), 1934; https://doi.org/10.3390/pr12091934 - 9 Sep 2024
Cited by 3 | Viewed by 1013
Abstract
Under the condition of multiple wells, the inverse problem of two-phase flow typically requires hundreds of forward runs of the simulator to achieve meaningful coverage, leading to a substantial computational workload in reservoir numerical simulations. To tackle this challenge, we propose an innovative [...] Read more.
Under the condition of multiple wells, the inverse problem of two-phase flow typically requires hundreds of forward runs of the simulator to achieve meaningful coverage, leading to a substantial computational workload in reservoir numerical simulations. To tackle this challenge, we propose an innovative approach leveraging a surrogate model named TgCNN (Theory-guided Convolutional Neural Network). This method integrates deep learning with computational fluid dynamics simulations to predict the behavior of two-phase flow. The model is not solely data-driven but also incorporates scientific theory. It comprises a coupled permeability module, a pressure module, and a water saturation module. The accuracy of the surrogate model was comprehensively tested from multiple perspectives in this study. Subsequently, efforts were made to address the permeability-field inverse problem under multi-well conditions by combining the surrogate model with the Ensemble Random Maximum Likelihood (EnRML) algorithm. The research findings indicate that modifying the network structure allows for improved integration of the outputs, resulting in prediction accuracy and computational efficiency. The TgCNN surrogate model demonstrated outstanding predictive performance and computational efficiency in two-phase flow. By combining the surrogate model with the EnRML algorithm, the inversion results closely aligned with those from the commercial simulation software, significantly improving the computational efficiency. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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15 pages, 4620 KiB  
Article
Analysis of Electric Breakup Characteristics of Emulsion Droplets Based on Dissipative Particle Dynamics Method
by Yiyang Geng, Changhai Lv, Xin Yuan and Weiwei Xu
Processes 2024, 12(7), 1467; https://doi.org/10.3390/pr12071467 - 13 Jul 2024
Viewed by 952
Abstract
Crude oil desalination and dehydration are necessary for storage, transportation, and processing procedures. However, the behaviour of fine emulsion droplets under an electric field has always been questioned. This paper modified the dissipative particle dynamics method (DPD) to study the deformation process of [...] Read more.
Crude oil desalination and dehydration are necessary for storage, transportation, and processing procedures. However, the behaviour of fine emulsion droplets under an electric field has always been questioned. This paper modified the dissipative particle dynamics method (DPD) to study the deformation process of fine emulsion droplets under a high-strength electric field. Compared with the literature data, the reliability of the DPD method is confirmed. The influence of the crude oil properties and the electric field characteristics on the behaviour of the emulsion droplet was analysed, and the effect factors included electric field intensity, electric field frequency, emulsion droplet size, centre distance ratio, conservative force intensity, dissipative strength, and crude oil density. The relationship between critical electric field intensity and emulsion droplet deformation was formulated based on the simulational dates. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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13 pages, 4782 KiB  
Article
Research and Practice on Implementing Segmented Production Technology of Horizontal Well during Extra-High Water Cut Stage with Bottom Water Reservoir
by Dong Zhang, Yanlai Li, Zongchao Zhang, Fenghui Li and Hongjie Liu
Processes 2024, 12(6), 1142; https://doi.org/10.3390/pr12061142 - 1 Jun 2024
Cited by 1 | Viewed by 1171
Abstract
Bohai X oilfield has reached the extra-high water cut stage of more than 95%, dominated by the bottom water reservoir. The oilfield mainly adopts horizontal-well exploitation, with the characteristics of high difficulty and low success rate for well water plugging. To solve the [...] Read more.
Bohai X oilfield has reached the extra-high water cut stage of more than 95%, dominated by the bottom water reservoir. The oilfield mainly adopts horizontal-well exploitation, with the characteristics of high difficulty and low success rate for well water plugging. To solve the above problem, the segmented production technology of horizontal wells was developed to guide oilfield applications and tap their potential. In the segmented design stage, the horizontal section is objectively segmented by drilling condition analysis, optimally based on drilling through interlayers or permeability discrepancy formation, simultaneously combined with the numerical simulation method. When implementing measures, annulus chemical packer materials are squeezed between segments to effectively inhibit the fluid flow between the open hole and the sand-packing screen pipe. Moreover, the packers are used to seal between segments to effectively restrain the flow between the screen and the central tube, achieving the establishment of compartments. In the production process, the valve switch on the central tube can be independently controlled by a remotely adjustable method to achieve optimal production. This segmented production technology was successfully tested for the first time in Bohai oilfield. Up to now, a total of six compartment measures have been implemented, remarkably decreasing water cut and increasing oil production for horizontal wells in the bottom water reservoir. This method does not require water testing, and the optimal production section can be chosen through segmented independent production, greatly improving the success rate of water-plugging measures for horizontal wells. This technology opens up a new mode for the efficient development of horizontal wells in bottom water reservoirs and is planned to be widely promoted and applied in similar oilfields. Full article
(This article belongs to the Special Issue Multiphase Flow, and Efficient Development Methodology and Technology in Unconventional Reservoirs (2nd Edition))
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