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CO2 Injection and Storage in Reservoir
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CO2 Injection and Storage in Reservoir

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

Deadline for manuscript submissions: closed (16 October 2023) | Viewed by 8886

Special Issue Editors

Dr. Sai Wang

E-Mail Website
Guest Editor
PRRC-NMT
Interests: EOR; CCUS; Carbon Mineralization; Hydrogen Production and Storage; Field Operation; Regulation, etc.
Dr. Wei Jia

E-Mail Website
Guest Editor
Energy and Geoscience Institute (EGI), University of Utah, Salt Lake City, UT 84112, USA
Interests: carbon capture utilization and storage (CCUS); CO2 geological sequestration; risk assessment; uncertainty quantification; machine learning
Dr. Jiawei Tu

E-Mail Website
Guest Editor
Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology, Socorro, NM 87801, USA
Interests: CO2 sequestration; CCUS; reservoir simulation; unconventional reservoirs; EOR
Dr. Xincheng Wan

E-Mail Website
Guest Editor
Energy & Environmental Research Center, University of North Dakota, Grand Forks, ND 58202, USA
Interests: reservoir simulation; hydraulic fracturing; CO2 EOR; refracturing simulation; unconventional reservoir
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

For decades, special interest has been focused on the underground injection CO2 stream, which is used to enhance oil and gas recovery. More recently, the research on and technologies for the geologic sequestration of CO2 are under development in order to trap or transform CO2 emitted from stationary anthropogenic sources permanently underground and ultimately reduce the emissions of GHGs from these sources into the atmosphere. More unique technologies and studies are requested to understand, predict, and monitor the migration and ultimate fate of injected CO2 in the reservoirs at the lab and field scale.

The purpose of the Special Issue is to assist in advancing the existing and potential research and development of carbon injection and storage technologies. The relevant research should address key technical challenges; facilitate data collection, sharing, and analysis; evaluate data sets; and promote the interdisciplinary transfer of technology. Moreover, in support of those goals, the topic on improved mapping and characterization of all significant CO2 sources and potential storage zones and transport pathways for CO2 in the reservoirs will also be considered.

This Special Issue, entitled “CO2 Injection and Storage in Reservoir”, has been proposed for the international journal Energies, which is indexed by SSCI and SCIE (2021 IF = 3.004). This Special Issue will mainly cover original research and studies on the above-mentioned topics, including, but not limited to, improving the efficiency of oil recovery by CO2, CO2 geological storage, geochemical and geomechnical property alternation of CO2 injection and storage, numerical simulation, CO2 plume detection and monitoring, risk analysis associated with CO2 geological sequestration, environmental issues and regulations, machine-learning-associated research on CO2 pathway identification, and so on. Papers selected for this Special Issue will be subject to a rigorous peer-review procedure with the aim of rapid and wide dissemination of research results, developments, and applications.

I am writing to invite you to submit your original work to this Special Issue. I look forward to receiving your outstanding research.

Dr. Sai Wang
Dr. Wei Jia
Dr. Jiawei Tu
Dr. Xincheng Wan
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

  • CO2-enhanced oil recovery
  • CO2 sequestration
  • numerical simulation
  • geochemistry and geomechanics (CO2 storage)
  • machine learning associated research on CO2 pathway identification
  • risk analysis, environmental issues and regulations on CO2 storage
  • CO2 plume detection and monitoring
  • other topics related to CO2 EOR and CO2 storage

Published Papers (5 papers)

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Research

40 pages, 12055 KiB  
Article
Applying Reservoir Simulation and Artificial Intelligence Algorithms to Optimize Fracture Characterization and CO2 Enhanced Oil Recovery in Unconventional Reservoirs: A Case Study in the Wolfcamp Formation
by Xincheng Wan, Lu Jin, Nicholas A. Azzolina, Shane K. Butler, Xue Yu and Jin Zhao
Energies 2022, 15(21), 8266; https://doi.org/10.3390/en15218266 - 04 Nov 2022
Cited by 4 | Viewed by 1646
Abstract
Reservoir simulation for unconventional reservoirs requires proper history matching (HM) to quantify the uncertainties of fracture properties and proper modeling methods to address complex fracture geometry. An integrated method, namely embedded discrete fracture model–artificial intelligence–automatic HM (EDFM–AI–AHM), was used to automatically generate HM [...] Read more.
Reservoir simulation for unconventional reservoirs requires proper history matching (HM) to quantify the uncertainties of fracture properties and proper modeling methods to address complex fracture geometry. An integrated method, namely embedded discrete fracture model–artificial intelligence–automatic HM (EDFM–AI–AHM), was used to automatically generate HM solutions for a multistage hydraulic fracturing well in the Wolfcamp Formation. Thirteen scenarios with different combinations of matrix and fracture parameters as variables or fixed inputs were designed to generate 1300 reservoir simulations via EDFM–AI–AHM, from which 358 HM solutions were retained to reproduce production history and quantify the uncertainties of matrix and hydraulic fracture properties. The best HM solution was used for production forecasting and carbon dioxide (CO2)-enhanced oil recovery (EOR) strategy optimization. The results of the production forecast for primary recovery indicated that the drainage area for oil production was difficult to extend further into the low-permeability reservoir matrix. However, CO2 EOR simulations showed that increasing the gas injection rate during the injection cycle promoted incremental oil production from the reservoir matrix, regardless of minimum miscibility pressure. A gas injection rate of 25 million standard cubic feet per day (MMscfd) resulted in a 14% incremental oil production improvement compared to the baseline scenario with no EOR. This paper demonstrates the utility of coupling reservoir simulation with artificial intelligence algorithms to generate ensembles of simulation cases that provide insights into the relationships between fracture network properties and production. Full article
(This article belongs to the Special Issue CO2 Injection and Storage in Reservoir)
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22 pages, 9301 KiB  
Article
A Novel Tripod Methodology of Scrutinizing Two-Phase Fluid Snap-Off in Low Permeability Formations from the Microscopic Perspective
by Xue Bai, Jian Tian, Na Jia and Ezeddin Shirif
Energies 2022, 15(17), 6141; https://doi.org/10.3390/en15176141 - 24 Aug 2022
Viewed by 1156
Abstract
According to the requirements of carbon-neutral development, this study explores the comparison and new discussion of replacing nitrogen with carbon dioxide in the conventional two-phase microfluid flow. Thus, carbon dioxide application in various fields can be more precise and convenient. This research uses [...] Read more.
According to the requirements of carbon-neutral development, this study explores the comparison and new discussion of replacing nitrogen with carbon dioxide in the conventional two-phase microfluid flow. Thus, carbon dioxide application in various fields can be more precise and convenient. This research uses an artificially continuously tapering micro model to mimic the natural rock channel in low permeability formation, where the liquid imbibition process is entirely under surface tension-dominant. The tested capillary number decreased to 8.49 × 10−6, and the thinnest observed liquid film was reduced to 2 μm. The comparison results in two gas groups (nitrogen and carbon dioxide) show that CO2 gas fluid in microscopic porous media would have more tendency to snap off and leave fewer residual bubbles blocked between the constrictions. However, the N2 gas fluid forms smaller isolated gas bubbles after snap-off. By combining the experimental data and numerical output with the theoretical evolution equation by Beresnev and Deng and by Quevedo Tiznado et al., the results of interface radius, temporal capillary pressure, and velocity profiles for axisymmetric and continuously tapering models are presented and validated. Those findings create a paradigm for future studies of the evolution of microscopic multiphase fluid and enhance a deeper understanding of geological underground fluid properties for greenhouse gas storage and utilization in low permeability formations. Full article
(This article belongs to the Special Issue CO2 Injection and Storage in Reservoir)
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20 pages, 7342 KiB  
Article
A Thermodynamic Model for Carbon Dioxide Storage in Underground Salt Caverns
by Yi Zhang, Wenjing Li and Guodong Chen
Energies 2022, 15(12), 4299; https://doi.org/10.3390/en15124299 - 11 Jun 2022
Cited by 1 | Viewed by 1582
Abstract
In the context of green energy and decarbonization, carbon dioxide storage in underground facilities, such as salt caverns, is one promising technical solution that has aroused attention. However, the thermodynamic behavior of CO2 and the geomechanical response of salt cavities have not [...] Read more.
In the context of green energy and decarbonization, carbon dioxide storage in underground facilities, such as salt caverns, is one promising technical solution that has aroused attention. However, the thermodynamic behavior of CO2 and the geomechanical response of salt cavities have not been studied comprehensively. In this study, we proposed a thermomechanical model that integrated a salt cavity and wellbore and implemented a series of simulations for carbon dioxide storage in a salt cavern. The model was verified by gas capacity calculations using field testing data. The thermodynamic behaviors of CO2 were determined and compared to methane. The results showed that the critical point coordinates of carbon dioxide were within the storage operation conditions, a phase transition could occur, and the thermodynamic properties around the critical point varied dramatically. For a short CO2 withdrawal operation, the salt cavity remained stable, while the near-wellbore area (NWA) was prone to fracture due to tensile stress concentration. Thus, we concluded that the proposed thermomechanical coupling numerical simulation method provided a comprehensive and quantitative tool for the feasibility analysis of CO2 storage in underground salt caverns. Full article
(This article belongs to the Special Issue CO2 Injection and Storage in Reservoir)
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13 pages, 3677 KiB  
Article
A New Adsorption Equation for Nano-Porous Shale Rocks and Its Application in Pore Size Distribution Analysis
by Yuanyuan Tian, Qing Chen, Changhui Yan, Hongde Chen, Yanqing He and Yufeng He
Energies 2022, 15(9), 3199; https://doi.org/10.3390/en15093199 - 27 Apr 2022
Cited by 1 | Viewed by 1408
Abstract
Adsorption equations are important to analyze the pore size distribution (PSD) of shale and the adsorption behavior on it. However, the accurate description of nitrogen adsorption on shale by current adsorption equations is difficult to achieve due to the heterogeneous pore structure of [...] Read more.
Adsorption equations are important to analyze the pore size distribution (PSD) of shale and the adsorption behavior on it. However, the accurate description of nitrogen adsorption on shale by current adsorption equations is difficult to achieve due to the heterogeneous pore structure of shale. In our study, new adsorption isotherms that can properly depict the adsorbed amount of nitrogen were built for shale rocks considering both the processes of nitrogen adsorption and the cylindrical pore shape property of shale. When performing a regression analysis on five sets of experimental adsorption data using the developed adsorption equations, the R-square ranged from 0.739 to 0.987. Based on the pore shape determined by adsorption–desorption curves, the distinct R-square indicated that our equation is not valid for shale samples with ink-bottle pores and pores formed by schistose materials, but that it is suitable for shale samples with cylindrical pores and slit pores. Meanwhile, we precisely analyzed the PSDs of shale rocks based on the developed adsorption equations as capillary condensation volume is involved in the total adsorbed amount. Thus, the PSDs of shale rocks with cylindrical pore and slit pore were analyzed by the new adsorption equation. Full article
(This article belongs to the Special Issue CO2 Injection and Storage in Reservoir)
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10 pages, 1994 KiB  
Article
Study on the Influential Factors of CO2 Storage in Low Permeability Reservoir
by Ping Yue, Rujie Zhang, James J. Sheng, Gaoming Yu and Feng Liu
Energies 2022, 15(1), 344; https://doi.org/10.3390/en15010344 - 04 Jan 2022
Cited by 9 | Viewed by 2103
Abstract
As the demands of tight-oil Enhanced Oil Recovery (EOR) and the controlling of anthropogenic carbon emission have become global challenges, Carbon Capture Utilization and Sequestration (CCUS) has been recognized as an effective solution to resolve both needs. However, the influential factors of carbon [...] Read more.
As the demands of tight-oil Enhanced Oil Recovery (EOR) and the controlling of anthropogenic carbon emission have become global challenges, Carbon Capture Utilization and Sequestration (CCUS) has been recognized as an effective solution to resolve both needs. However, the influential factors of carbon dioxide (CO2) geological storage in low permeability reservoirs have not been fully studied. Based on core samples from the Huang-3 area of the Ordos Basin, the feasibility and influential factors of geological CO2 sequestration in the Huang-3 area are analyzed through caprock breakthrough tests and a CO2 storage factor experiment. The results indicate that capillary trapping is the key mechanism of the sealing effect by the caprock. With the increase of caprock permeability, the breakthrough pressure and pressure difference decreased rapidly. A good exponential relationship between caprock breakthrough pressure and permeability can be summarized. The minimum breakthrough pressure of CO2 in the caprock of the Huang-3 area is 22 MPa, and the breakthrough pressure gradient is greater than 100 MPa/m. Huang-3 area is suitable for the geological sequestration of CO2, and the risk of CO2 breakthrough in the caprock is small. At the same storage percentage, the recovery factor of crude oil in larger permeability core is higher, and the storage percentage decreases with the increase of recovery factor. It turned out that a low permeability reservoir is easier to store CO2, and the storage percentage of carbon dioxide in the miscible phase is greater than that in the immiscible phase. This study can provide empirical reference for caprock selection and safety evaluation of CO2 geological storage in low permeability reservoirs within Ordos Basin. Full article
(This article belongs to the Special Issue CO2 Injection and Storage in Reservoir)
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