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CO₂ Enhanced Oil Recovery and Carbon Sequestration

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

Deadline for manuscript submissions: closed (20 July 2023) | Viewed by 12875

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Dr. Huazhou Li

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Guest Editor

School of Mining and Petroleum Engineering, Faculty of Engineering, University of Alberta, Edmonton, AB T6G 1H9, Canada
Interests: engineering thermodynamics; equation of state models; phase behavior in conventional reservoirs; phase behavior in unconventional reservoirs; modeling of multiphase flow in wellbore

Dr. Daoyong Yang

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Co-Guest Editor

Petroleum Technology Research Centre (PTRC), Petroleum Systems Engineering, Faculty of Engineering, University of Regina, Regina, SK S4S 0A2, Canada
Interests: reservoir description and dynamics; reservoir geomechanics; phase behavior; heat and mass transfer; assisted history matching; formation evaluation; production optimization; CO2 EOR and storage; pressure/rate transient analysis; reservoir nanoagents; jet dynamics; artificial lift methods; thermodynamics; heavy oil recovery; unconventional resources exploitation; and hydrate development and optimization

Prof. Dr. Shengnan Chen

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Co-Guest Editor

Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, Canada
Interests: tight/shale reservoir development; enhanced oil recovery; machine learning and data analytics; reservoir performance optimization
Special Issues, Collections and Topics in MDPI journals

Dr. Yin Zhang

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Co-Guest Editor

Department of Petroleum Engineering, College of Engineering and Mine, University of Alaska Fairbanks, Fairbanks, AK, USA
Interests: chemical (polymer and solvents) EOR techniques; oilfield produced fluids treatment; assisted history matching; reservoir simulation; petrophysical properties estimation; uncertainty quantification; core flooding experimentation; CO₂ EOR and storage

Dr. Xiaoli Li

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Co-Guest Editor

Chemical & Petroleum Engineering, University of Kansas, Lawrence, KS 66045, USA
Interests: CO₂ enhanced oil recovery; petroleum fluids properties; phase behavior in unconventional reservoirs; gas transport in nanoscale porous media; natural gas hydrates phase behavior

Dr. Zhaoqi Fan

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Co-Guest Editor

Department of Chemical & Natural Gas Engineering, Texas A&M University – Kingsville, Kingsville, TX 78363, USA
Interests: multiphase fluid flow; wormhole modeling in heavy oil and carbonate formations; assisted history matching algorithms; reservoir simulation and optimization; and enhance oil recovery in unconventional reservoirs

Special Issue Information

Dear colleagues,

The Paris Agreement, which came into effect in 2016, laid out a mandate to limit the global warming to well below 2^oC, preferably to 1.5^oC, compared to the pre-industrial levels. To achieve such a goal, we first need to significantly reduce the CO₂ emissions of various civil and industrial activities. Second, we need to develop CO₂ sequestration technologies that could sequester CO₂ in a permanent and safe manner. Combined CO₂ enhanced oil recovery (EOR) and carbon sequestration provides a promising solution in this regard. In a CO₂ EOR and carbon sequestration project, CO₂, which is captured from various industrial emitters, is injected into a hydrocarbon reservoir for EOR purposes. During the EOR process, part of the injected CO₂ will be sequestered in the reservoir, while the produced CO₂ is continuously being separated from the production stream and re-injected into the reservoir. Once the reservoir is depleted, all the remaining CO₂ or the additionally captured CO₂ could be injected into the depleted reservoir to achieve carbon sequestration. Further research and development are drastically needed to address the many technical challenges associated with CO₂ EOR and carbon sequestration. In this Special Issue, we invite experts to submit articles which report on the recent technological developments in the following areas of CO₂ EOR and carbon sequestration: laboratory studies and experimental measurements, theoretical studies and numerical simulations, phase behavior and PVT studies, miscibility mechanisms (including the measurement and modelling of minimum miscibility pressure), modified CO₂ injection techniques (including the water-alternating-gas process), wellbore technologies, multiphase flow in wellbore, multiphase flow in reservoir, wellbore integrity, evaluation of storage capacity, caprock integrity, leakage detection and measurement technologies during CO₂ storage, geochemical reactions during CO₂ injection and storage, geomechanical aspects of CO₂ injection and storage, coupled thermal/hydrological/mechanical simulation of CO₂ injection, CO₂-based hydraulic fracturing techniques, effect of impurities on the process efficiency, robust optimization of CO₂ EOR and sequestration, economic analysis, life-cycle analysis, etc. Both original research articles and review articles will be welcome.

Dr. Huazhou Li
Dr. Daoyong Yang
Dr. Shengnan Chen
Dr. Yin Zhang
Dr. Xiaoli Li
Dr. Zhaoqi Fan
Guest Editors

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Keywords

CO₂ EOR
enhanced oil recovery
phase behavior
carbon sequestration
monitoring and surveillance techniques
production and optimization
multiphase flow in wellbore
caprock integrity
wellbore integrity
storage capacity
life-cycle analysis
experimental study
theoretical study
simulation and optimization
unconventional reservoirs
field-case study

Published Papers (7 papers)

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Research

17 pages, 4888 KiB

Open AccessArticle

Mass Transfer Analysis of CO₂-Water-Rock Geochemical Reactions in Reservoirs

by Rui Xu, Tie Yan, Xu Han, Jingyu Qu and Jinyu Feng

Energies 2023, 16(16), 5862; https://0-doi-org.brum.beds.ac.uk/10.3390/en16165862 - 08 Aug 2023

Viewed by 650

Abstract

It is difficult to exploit low-permeability reservoirs, and CO₂ flooding is an effective method to improve oil recovery from low permeability reservoirs. However, in the process of CO₂ flooding, acidic fluids dissolved in formation water will react with rock to cause dissolution and precipitation, resulting in pores and precipitates, changing the evolution law of seepage channels, destroying formation integrity, and affecting the effect of CO₂ oil displacement. The change in rock’s physical properties and the mass transfer law between CO₂-water-rock are unclear. This paper considers the coupling effects of seepage, mechanics, and chemistry when CO₂ is injected into the formation. The mass transfer model of CO₂-water-rock in the geochemical reaction process is established on this basis. The physical properties of the reservoir after CO₂ injection are quantitatively studied based on the microscopic mechanism of chemical reaction, and the migration law of solute in the reservoir rock during CO₂ flooding under the coupling effects of multiple fields is clarified. The experimental results show that with the increase in reaction time, the initial dissolution reaction of formation rocks will be transformed into a precipitation reaction of calcite, magnesite, and clay minerals. The porosity and permeability of the rocks near the well first increase and then decrease. The far well end is still dominated by dissolution reactions, and the average values of formation porosity and permeability show an upward trend. Although the dissolution reaction of CO₂-water-rock can improve the physical properties of reservoir rocks to a certain extent, the mutual transformation of the dissolution reaction and precipitation reaction further exacerbates the heterogeneity of formation pore structure, leading to the instability of CO₂ migration, uneven displacement, and destruction of formation stability. The research results of this paper solve the problem of quantitative calculation of physical parameters under the coupling effect of multiple fields after CO₂ injection into reservoirs and can predict the changes in formation physical properties, which can provide a certain theoretical basis for evaluating formation integrity and adjusting CO₂ injection under the condition of CO₂ flooding. Full article

(This article belongs to the Special Issue CO₂ Enhanced Oil Recovery and Carbon Sequestration)

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16 pages, 4455 KiB

Open AccessArticle

Unsteady-State CO₂ Foam Generation and Propagation: Laboratory and Field Insights

by Zachary Paul Alcorn, Aleksandra Sæle, Metin Karakas and Arne Graue

Energies 2022, 15(18), 6551; https://0-doi-org.brum.beds.ac.uk/10.3390/en15186551 - 07 Sep 2022

Viewed by 1113

Abstract

This work presents a multiscale experimental and numerical investigation of CO₂ foam generation, strength, and propagation during alternating injection of surfactant solution and CO₂ at reservoir conditions. Evaluations were conducted at the core-scale and with a field-scale radial simulation model representing a CO₂ foam field pilot injection well. The objective of the experimental work was to evaluate foam generation, strength, and propagation during unsteady-state surfactant-alternating-gas (SAG) injection. The SAG injection rapidly generated foam based upon the increased apparent viscosity compared to an identical water-alternating-gas (WAG) injection, without surfactant. The apparent foam viscosity of the SAG continually increased with each subsequent cycle, indicating continued foam generation and propagation into the core. The maximum apparent viscosity of the SAG was 146 cP, whereas the maximum apparent viscosity of the WAG was 2.4 cP. The laboratory methodology captured transient CO₂ foam flow which sheds light on field-scale CO₂ foam flow. The single-injection well radial reservoir simulation model investigated foam generation, strength, and propagation during a recently completed field pilot. The objective was to tune the model to match the observed bottom hole pressure data from the foam pilot and evaluate foam propagation distance. A reasonable match was achieved by reducing the reference mobility reduction factor parameter of the foam model. This suggested that the foam generated during the pilot was not as strong as observed in the laboratory, but it has propagated approximately 400 ft from the injection well, more than halfway to the nearest producer, at the end of pilot injection. Full article

(This article belongs to the Special Issue CO₂ Enhanced Oil Recovery and Carbon Sequestration)

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22 pages, 6708 KiB

Open AccessArticle

Time-Series Forecasting of a CO₂-EOR and CO₂ Storage Project Using a Data-Driven Approach

by Utomo Pratama Iskandar and Masanori Kurihara

Energies 2022, 15(13), 4768; https://0-doi-org.brum.beds.ac.uk/10.3390/en15134768 - 29 Jun 2022

Cited by 4 | Viewed by 1688

Abstract

This study aims to develop a predictive and reliable data-driven model for forecasting the fluid production (oil, gas, and water) of existing wells and future infill wells for CO₂-enhanced oil recovery (EOR) and CO₂ storage projects. Several models were investigated, such as auto-regressive (AR), multilayer perceptron (MLP), and long short-term memory (LSTM) networks. The models were trained based on static and dynamic parameters and daily fluid production while considering the inverse distance of neighboring wells. The developed models were evaluated using walk-forward validation and compared based on the quality metrics, span, and variation in the forecasting horizon. The AR model demonstrates a convincing generalization performance across various time series datasets with a long but varied forecasting horizon across eight wells. The LSTM model has a shorter forecasting horizon but strong generalizability and robustness in forecasting horizon consistency. MLP has the shortest and most varied forecasting horizon compared to the other models. The LSTM model exhibits promising performance in forecasting the fluid production of future infill wells when the model is developed from an existing well with similar features to an infill well. This study offers an alternative to the physics-driven model when traditional modeling is costly and laborious. Full article

(This article belongs to the Special Issue CO₂ Enhanced Oil Recovery and Carbon Sequestration)

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16 pages, 2101 KiB

Open AccessArticle

Predicting Adsorption of Methane and Carbon Dioxide Mixture in Shale Using Simplified Local-Density Model: Implications for Enhanced Gas Recovery and Carbon Dioxide Sequestration

by Yu Pang, Shengnan Chen and Hai Wang

Energies 2022, 15(7), 2548; https://0-doi-org.brum.beds.ac.uk/10.3390/en15072548 - 31 Mar 2022

Cited by 9 | Viewed by 1684

Abstract

Carbon dioxide (CO₂) capture and storage have attracted global focus because CO₂ emissions are responsible for global warming. Recently, injecting CO₂ into shale gas reservoirs is regarded as a promising technique to enhance shale gas (i.e., methane (CH₄)) production while permanently storing CO₂ underground. This study aims to develop a calculation workflow, which is built on the simplified local-density (SLD) model, to predict excess and absolute adsorption isotherms of gas mixture based on single-component adsorption data. Such a calculation workflow was validated by comparing the measured adsorption of CH₄, CO₂, and binary CH₄/CO₂ mixture in shale reported previously in the literature with the predicted results using the calculation workflow. The crucial steps of the calculation workflow are applying the multicomponent SLD model to conduct regression analysis on the measured adsorption isotherm of each component in the gas mixture simultaneously and using the determined key regression parameters to predict the adsorption isotherms of gas mixtures with various feed-gas mole fractions. Through the calculation workflow, the density profiles and mole fractions of the adsorbed gases can be determined, from which the absolute adsorption of the gas mixture is estimated. In addition, the CO₂/CH₄ adsorption selectivity larger than one is observed, illustrating the preferential adsorption of CO₂ over CH₄ on shale, which implies that CO₂ has enormous potential to enhance CH₄ production while sequestering itself in shale. Our findings demonstrate that the proposed calculation workflow depending on the multicomponent SLD model enables us to accurately predict the adsorption of gas mixtures in nanopores based on single-component adsorption results. Following the innovative calculation flow path, we could bypass the experimental difficulties of measuring the multicomponent mole fractions in the gas phase at the equilibrium during the adsorption experiments. This study also provides insight into the CO₂/CH₄ competitive adsorption behavior in nanopores and gives guidance to CO₂-enhanced gas recovery (CO₂-EGR) and CO₂ sequestration in shale formations. Full article

(This article belongs to the Special Issue CO₂ Enhanced Oil Recovery and Carbon Sequestration)

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30 pages, 7844 KiB

Open AccessArticle

Effects of Hydrogeological Heterogeneity on CO₂ Migration and Mineral Trapping: 3D Reactive Transport Modeling of Geological CO₂ Storage in the Mt. Simon Sandstone, Indiana, USA

by Babak Shabani, Peng Lu, Ryan Kammer and Chen Zhu

Energies 2022, 15(6), 2171; https://0-doi-org.brum.beds.ac.uk/10.3390/en15062171 - 16 Mar 2022

Cited by 9 | Viewed by 2859

Abstract

We used three-dimensional (3D), high-resolution simulations facilitated by parallel computation to assess the effect of hydrogeological heterogeneity in the Mt. Simon Sandstone on CO₂ plume evolution and storage and geochemical reactions in a portion of the Illinois Basin, Indiana. Two scenarios were selected to investigate the effects of the hydrogeological heterogeneity in 3D reactive transport simulations: a heterogeneous case with variable porosity and permeability, and a homogenous case with constant porosity and permeability. The initial pressure, temperature, and mineralogical distributions are consistently applied in both the heterogeneous case and the homogeneous case. Results indicate that including hydrogeological heterogeneity in 3D reservoir simulations for geological CO₂ storage significantly impacts modeling results for plume migration patterns, CO₂-water-mineral interaction, reservoir quality, and CO₂ plume containment. In particular, results indicate that (1) the CO₂ plume reached the top of the Mt. Simon Sandstone in the homogeneous case, but was restrained to the lower third of the formation when hydrogeologic heterogeneity was considered; (2) the dominant trapping mechanism in the heterogeneous case was mineral trapping (43%), while it was solubility trapping (47%) in the homogeneous case (at 10,000 years); (3) incorporating reservoir heterogeneity in the model leads to a higher likelihood of long-term containment. Full article

(This article belongs to the Special Issue CO₂ Enhanced Oil Recovery and Carbon Sequestration)

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18 pages, 4555 KiB

Open AccessArticle

A Modified Multiple-Mixing-Cell Method with Sub-Cells for MMP Determinations

by Lingfei Xu and Huazhou Li

Energies 2021, 14(23), 7846; https://0-doi-org.brum.beds.ac.uk/10.3390/en14237846 - 23 Nov 2021

Cited by 3 | Viewed by 1380

Abstract

Minimum miscible pressure (MMP) is an essential design parameter of gas flooding for enhanced oil recovery (EOR) applications. Researchers have developed a number of methods for MMP computations, including the analytical methods, the slim-tube simulation method, and the multiple-mixing-cell (MMC) method. Among these methods, the MMC method is widely accepted for its simplicity, robustness, and moderate computational cost An important version of the MMC method is the Jaubert et al. method which has a much lower computational cost than the slim-tube simulation method. However, the original Jaubert et al. method suffers several drawbacks. One notable drawback is that it cannot be applied to the scenario where the oil-gas MMP is lower than the saturation pressure of the crude oil. In this work, we present a modified MMC method that is more versatile and robust than the original version. Our method can handle the scenario where the oil-gas MMP is lower than the saturation pressure of the crude oil. Besides, we propose a modified MMC model that can reduce the computational cost of MMP estimations. This modified model, together with a newly proposed pressure search algorithm, increases the MMP estimation accuracy of the modified method. We demonstrate the good performance of the modified MMC method by testing it in multiple case studies. A good agreement is obtained between the MMPs calculated by the modified method and the tie-line-based ones from the literature. Full article

(This article belongs to the Special Issue CO₂ Enhanced Oil Recovery and Carbon Sequestration)

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27 pages, 4786 KiB

Open AccessArticle

Technical and Economic Evaluation of CO₂ Capture and Reinjection Process in the CO₂ EOR and Storage Project of Xinjiang Oilfield

by Liang Zhang, Songhe Geng, Linchao Yang, Yongmao Hao, Hongbin Yang, Zhengmiao Dong and Xian Shi

Energies 2021, 14(16), 5076; https://0-doi-org.brum.beds.ac.uk/10.3390/en14165076 - 18 Aug 2021

Cited by 5 | Viewed by 1792

Abstract

CO₂ capture and reinjection process (CCRP) can reduce the used CO₂ amount and improve the CO₂ storage efficiency in CO₂ EOR projects. To select the best CCRP is an important aspect. Based on the involved equipment units of the CCRP, a novel techno-economic model of CCRP for produced gas in CO₂ EOR and storage project was established. Five kinds of CO₂ capture processes are covered, including the chemical absorption using amine solution (MDEA), pressure swing adsorption (PSA), low-temperature fractionation (LTF), membrane separation (MS), and direct reinjection mixed with purchased CO₂ (DRM). The evaluation indicators of CCRP such as the cost, energy consumption, and CO₂ capture efficiency and purity can be calculated. Taking the pilot project of CO₂ EOR and storage in XinJiang oilfield China as an example, a sensitivity evaluation of CCRP was conducted based on the assumed gas production scale and the predicted yearly gas production. Finally, the DRM process was selected as the main CCRP associated with the PSA process as an assistant option. The established model of CCRP can be a useful tool to optimize the CO₂ recycling process and assess the CO₂ emission reduction performance of the CCUS project. Full article

(This article belongs to the Special Issue CO₂ Enhanced Oil Recovery and Carbon Sequestration)

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