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Carbon Capture, Utilization, and Storage (CCUS) in Unconventional Oil and...
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Carbon Capture, Utilization, and Storage (CCUS) in Unconventional Oil and Gas

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

Deadline for manuscript submissions: 30 November 2025 | Viewed by 2639

Special Issue Editors

Dr. Bin Liang

E-Mail Website
Guest Editor
State Key Lab Oil & Gas Reservoir Geol & Exploita, Southwest Petroleum University, Chengdu 610500, China
Interests: chemical EOR; machine learning; CO2-EOR; unconventional reservoirs
Special Issues, Collections and Topics in MDPI journals
Dr. Zhan Meng

E-Mail Website
Guest Editor
State Key Lab Oil & Gas Reservoir Geol & Exploita, Southwest Petroleum University, Chengdu 610500, China
Interests: enhanced oil recovery; CCUS; spontaneous imbibition; mathematical modeling; numerical simulation
Special Issues, Collections and Topics in MDPI journals
Dr. Qingbang Meng

E-Mail Website
Guest Editor
School of Earth Resources, China University of Geosciences, 388 Lumo Road, Wuhan 430074, China
Interests: imbibition and capillary action in ideal and natural materials; multiphase flow in porous/fractured media; enhanced oil recovery; CCUS; reservoirs numerical simulation
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

Carbon dioxide (CO2) has been used for decades to enhance oil recovery (EOR) in reservoirs, and, in recent years, its utilization and storage in gas reservoirs have also gradually gained attention. Utilizing CO2 in oil and gas reservoirs to enhance oil or gas recovery (EOR/EGR) while achieving its geological storage is a win–win in terms of both economic and social benefits.

For oil fields, improving CO2 utilization efficiency, increasing oil recovery, is very important and largely depends on the phase behavior of CO2 and crude oil, displacement and EOR mechanisms, CO2 injection strategies, and the prevention of gas channeling, among others. From an environmental perspective, the goal is to maximize CO2 storage capacity, which involves different reservoir storage mechanisms, dynamic and static evaluations of storage capacity, and risk and economic assessments. Additionally, managing the synergistic relationship between CO2 utilization and storage in oil and gas reservoirs while simultaneously improving both is a crucial aspect of current carbon capture, utilization, and storage (CCUS) efforts in oil and gas reservoirs.

This Special Issue aims to collect recent advances in new analytical and numerical methods, mechanism studies, and field applications for CCUS in unconventional oil and gas reservoirs.

The topics include but are not limited to the following:

  • CCUS in low-permeability reservoirs;
  • CCUS in tight/shale oil reservoirs;
  • CCUS in natural gas reservoirs;
  • CCUS in shale gas reservoirs;
  • Lab studies and field cases.

Dr. Bin Liang
Dr. Zhan Meng
Dr. Qingbang 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

  • CCUS
  • Oil and gas reservoirs
  • EOR
  • EGR
  • CO2 storage

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Further information on MDPI's Special Issue policies can be found here.

Published Papers (3 papers)

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Research

13 pages, 5004 KiB  
Article
Molecular Dynamics Simulation of Phase Behavior of Fluid in Confined Nanopores
by Jiahao Gao, Ke Zhang, Weifeng Lyu, Yu Zhang, Mingyuan Wang, Yaoze Cheng, Ao Li and Xv Chen
Processes 2025, 13(2), 506; https://doi.org/10.3390/pr13020506 - 12 Feb 2025
Viewed by 655
Abstract
The reservoir proportion with deep and low permeability, where oil and gas exist widely in nanopores, has been discovered increasingly in China. Affected by the nano-confinement effect, the phase behavior of fluid in nanopores varies with nanopore size rather than being constant. In [...] Read more.
The reservoir proportion with deep and low permeability, where oil and gas exist widely in nanopores, has been discovered increasingly in China. Affected by the nano-confinement effect, the phase behavior of fluid in nanopores varies with nanopore size rather than being constant. In this paper, the density, viscosity, and saturation pressure of pure and mixed fluids in nanopores are studied by molecular dynamics (MD) simulation combined with statistical physics. The feasibility of using the MD method to investigate fluid behavior in nanopores was verified with laboratory data. It was found that the fluids’ phase behavior parameters in nanopores are lower than those in the bulk phase due to the confinement effect. The boundary of confinement effect (BCE) is defined as a size range of nanopores that separates the pore scale into the confinement scale and bulk scale. Each fluid has a specific BCE influenced by the molecular size of fluid. The phase behavior of crude oil in shale and tight oil reservoirs is most affected by the molecular adsorption and interaction energy between the fluid molecule and pore wall. Clarifying a specific BCE in shale reservoirs can significantly enhance the understanding of reservoirs and guide reservoir development strategies. Full article
(This article belongs to the Special Issue Carbon Capture, Utilization, and Storage (CCUS) in Unconventional Oil and Gas)
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16 pages, 4003 KiB  
Article
Flow and Corrosion Analysis of CO2 Injection Wells: A Case Study of the Changqing Oilfield CCUS Project
by Wei Lv, Tongyao Liang, Cheng Lu, Mingxing Li, Pei Zhou, Xing Yu, Bin Wang and Haizhu Wang
Processes 2025, 13(2), 439; https://doi.org/10.3390/pr13020439 - 6 Feb 2025
Viewed by 638
Abstract
In carbon dioxide capture, utilization and storage (CCUS) technology, CO2 flooding and storage is currently the most effective geological storage method and the flow law of the gas injection wellbore is the key to achieving safe and efficient CO2 injection. The [...] Read more.
In carbon dioxide capture, utilization and storage (CCUS) technology, CO2 flooding and storage is currently the most effective geological storage method and the flow law of the gas injection wellbore is the key to achieving safe and efficient CO2 injection. The existing wellbore flow model lacks research on the corrosion law. To this end, this paper established a gas injection wellbore flow-heat transfer-corrosion coupling model based on the actual situation of Huang 3 District of the CCUS Demonstration Base of Changqing Oilfield. The field measured data verification showed that the relative average error of the model in predicting pressure and temperature was less than 7.5% and the R2 of the predicted value and the measured value was greater than 0.99. The model was used for sensitivity analysis to evaluate the effects of different gas injection temperatures (15–55 °C), pressures (15–55 MPa), displacements (10–500 t/d) and CO2 contents (50–100%) on wellbore temperature, pressure and corrosion rate, and the wellbore flow law under different gas injection conditions was clarified. The results show that the wellbore temperature, pressure and corrosion rate are significantly affected by gas injection parameters. The wellbore temperature increases with the increase of gas injection temperature and decreases with the increase of gas injection displacement. The wellbore pressure is positively correlated with the gas injection pressure and CO2 content and the gas injection temperature and displacement have little effect on the pressure. The corrosion rate increases with the increase of gas injection temperature and displacement and decreases with the increase of gas injection pressure. In the wellbore, it shows a trend of first increasing and then decreasing with depth. The wellbore corrosion rate is affected by many factors. Reasonable adjustment of gas injection parameters (lowering temperature, increasing pressure, controlling displacement and CO2 content) can effectively slow down the wellbore corrosion loss. The research results can provide a theoretical basis for the optimization of gas injection system. Full article
(This article belongs to the Special Issue Carbon Capture, Utilization, and Storage (CCUS) in Unconventional Oil and Gas)
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13 pages, 2761 KiB  
Article
CO2-Enhanced Gas Recovery in Offshore Carbon-Rich Gas Reservoirs—Part 1: In Situ Gas Dispersion Behaviors
by Ping Jiang, Yuqiang Zha, Qing Ye, Runfu Xiong, Nan Zhao, Fengyang Mo, Lei Sun, Minxuan Li, Yuqi Zeng and Bin Liang
Processes 2024, 12(11), 2479; https://doi.org/10.3390/pr12112479 - 8 Nov 2024
Cited by 1 | Viewed by 886
Abstract
In the middle and late stages of offshore carbon-rich gas reservoir development, insufficient reservoir energy poses significant challenges and difficulty in improving gas recovery. Injecting CO2 back into the reservoir is a promising development approach that can address both carbon emissions and [...] Read more.
In the middle and late stages of offshore carbon-rich gas reservoir development, insufficient reservoir energy poses significant challenges and difficulty in improving gas recovery. Injecting CO2 back into the reservoir is a promising development approach that can address both carbon emissions and enhanced gas recovery (EGR). During the CO2 injection process, the CO2–CH4 dispersion significantly impacts the recovery of CH4. To understand the mass transfer and dispersion laws of CO2 and high-carbon natural gas under current in situ reservoir conditions, this study conducted 1-m-long core experiments to investigate the effects of different gas compositions and permeabilities on gas recovery and diffusion laws in offshore reservoirs, taking into account the evolution of permeability in the porous medium. The experimental results indicate that the higher carbon concentration helps reduce mixing with formation gas, which consists of 70% methane, 25% nitrogen, and 5% carbon dioxide, resulting in a smaller diffusion coefficient. Under the conditions of an injection rate of 0.4 mL/min, a temperature of 81 °C, and a pressure of 7 MPa, the diffusion coefficient decreases by 27.5% as the carbon dioxide concentration increases from 70% to 90%, resulting in a 1.5% increase in recovery efficiency. As the permeability decreases, the viscous resistance of the fluid increases, leading to longer breakthrough times, and the reservoir fluid becomes more akin to piston displacement, reducing the degree of dispersion. The findings of this study provide guidance for optimizing gas injection strategies by reducing CO2 dispersion and further enhancing natural gas recovery. Full article
(This article belongs to the Special Issue Carbon Capture, Utilization, and Storage (CCUS) in Unconventional Oil and Gas)
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