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Oil Recovery and Simulation in Reservoir Engineering

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

Deadline for manuscript submissions: closed (31 March 2025) | Viewed by 8877

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Prof. Dr. Ganesh Thakur

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Guest Editor

Department of Petroleum Engineering, University of Houston, Houston, TX 77204, USA
Interests: injection optimization; waterflooding; CO₂ EOR; CO₂ storage; machine learning; proxy modelling; reservoir management

Special Issue Information

Dear colleagues,

The purpose of oil recovery management is to provide facts, information, and knowledge necessary to control operations at appropriate times and to obtain the maximum possible economic recovery in an environmentally safe manner. Guidelines for oil recovery management should include information on (1) reservoir characterization, (2) estimation of pay areas containing recoverable oil, (3) analysis of pattern performance, data gathering and analytics, (4) well testing and reservoir pressure monitoring, and (5) an information database.

A reservoir description is the foundation for designing, operating, and evaluating an oil recovery project. It largely determines the selection of an oil recovery plan and the simulation model used to estimate project performance. The development of a reservoir description, which requires extensive human and computer resources, should start early in the life of a reservoir. It is important to remember that a reservoir description is an iterative process. Every description requires the modification of interactions between geologists, geophysicists and engineers working the field matures.

A reservoir model is not just an engineering or a geoscience model; rather, it is an integrated model that is prepared jointly by geoscientists and engineers. An integrated reservoir model requires a thorough knowledge of the geology, rock and fluid properties. A geological model is derived by extending localized core and log measurements and well tests to the full reservoir using many technologies such as geophysics and depositional environment. The definition of geological units and their continuity and compartmentalization is an integral part of geostatistical and, ultimately, reservoir simulation models.

An integrated team approach involving geoscience and engineering professionals, oil recovery research scientists, field personnel and management is essential for oil recovery asset management. Efficient and successful operations require the following:

Essential lab research and data gathering;
Developing a robust pilot program to test the oil recovery process;
Simulation and scale-up at field level;
Engineering an economically viable plan;
Implementing the plan;
Monitoring and evaluating performance;
Revising plans and strategies, including AI and Machine Learning, fluid flow and recovery mechanisms, drilling and well completions, and past production performance.

This Special Issue presents and disseminates the most recent advances related to the theory, design, modeling and simulation, application, control, and surveillance and monitoring of most commonly applicable recovery processes, e.g., secondary recovery using water and/gas injection, CO₂ injection, WAG process, steam flooding, and other techniques.

Prof. Dr. Ganesh Thakur
Guest Editor

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Keywords

reservoir engineering, simulation, characterization and management
oil recovery and simulation
surveillance and monitoring
implementation, AI and Machine Learning
fluid flow and recovery mechanisms
oil recovery and recovery efficiency
lab research
data gathering
scale-up and integrated reservoir model
pattern performance
geoscience applications
pilot program
computer resources
human resources and multidisciplinary teamwork
CO₂ injection and WAG process
well test
steam flooding
rejuvenating mature fields
reservoir continuity and compartmentalization

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Published Papers (7 papers)

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Research

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20 pages, 9044 KiB

Open AccessArticle

Simulation of Low-Salinity Water-Alternating Impure CO₂ Process for Enhanced Oil Recovery and CO₂ Sequestration in Carbonate Reservoirs

by Kwangduk Seo, Bomi Kim, Qingquan Liu and Kun Sang Lee

Energies 2025, 18(5), 1297; https://doi.org/10.3390/en18051297 - 6 Mar 2025

Viewed by 471

Abstract

This study investigates the combined effects of impurities in CO₂ stream, geochemistry, water salinity, and wettability alteration on oil recovery and CO₂ storage in carbonate reservoirs and optimizes injection strategy to maximize oil recovery and CO₂ storage ratio. Specifically, it compares the performance of pure CO₂ water-alternating gas (WAG), impure CO₂-WAG, pure CO₂ low-salinity water-alternating gas (LSWAG), and impure CO₂-LSWAG injection methods from perspectives of enhanced oil recovery (EOR) and CO₂ sequestration. CO₂-enhanced oil recovery (CO₂-EOR) is an effective way to extract residual oil. CO₂ injection and WAG methods can improve displacement efficiency and sweep efficiency. However, CO₂-EOR has less impact on the carbonate reservoir because of the complex pore structure and oil-wet surface. Low-salinity water injection (LSWI) and CO₂ injection can affect the complex pore structure by geochemical reaction and wettability by a relative permeability curve shift from oil-wet to water-wet. The results from extensive compositional simulations show that CO₂ injection into carbonate reservoirs increases the recovery factor compared with waterflooding, with pure CO₂-WAG injection yielding higher recovery factor than impure CO₂-WAG injection. Impurities in CO₂ gas decrease the efficiency of CO₂-EOR, reducing oil viscosity less and increasing interfacial tension (IFT) compared to pure CO₂ injection, leading to gas channeling and reduced sweep efficiency. This results in lower oil recovery and lower storage efficiency compared to pure CO₂. CO₂-LSWAG results in the highest oil-recovery factor as surface changes. Geochemical reactions during CO₂ injection also increase CO₂ storage capacity and alter trapping mechanisms. This study demonstrates that the use of impure CO₂-LSWAG injection leads to improved oil recovery and CO₂ storage compared to pure CO₂-WAG injection. It reveals that wettability alteration plays a more significant role for oil recovery and geochemical reaction plays crucial role in CO₂ storage than CO₂ purity. According to optimization, the greater the injection of gas and water, the higher the oil recovery, while the less gas and water injected, the higher the storage ratio, leading to improved storage efficiency. This research provides valuable insights into parameters and injection scenarios affecting enhanced oil recovery and CO₂ storage in carbonate reservoirs. Full article

(This article belongs to the Special Issue Oil Recovery and Simulation in Reservoir Engineering)

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23 pages, 8595 KiB

Open AccessArticle

Phase Behavior and Flowing State of Water-Containing Live Crude Oil in Transportation Pipelines

by Si Li, Haiyan Yang, Run Liu, Shidong Zhou and Kaifeng Fan

Energies 2025, 18(5), 1116; https://doi.org/10.3390/en18051116 - 25 Feb 2025

Cited by 1 | Viewed by 351

Abstract

To address the challenges and risks associated with the declining crude yield, an optimization project for the surface production facilities at ZY Oilfield is underway. Upon the completion of this project, the oilfield’s export pipelines will transport water-containing live crude oil. To ensure pipeline transportation safety, it is essential to clarify the phase behaviors and flow state of water-containing live oil. For this purpose, the VLLE characteristics of water-containing live oil were analyzed with Aspen HYSYS V12 software and validated through PVT tests. Additionally, the pressure variations in multiphase flow pipelines under different operating conditions were calculated using the Beggs and Brill–Moody–Eaton method with Pipephase 9.6 software. The results indicated that the bubble point pressure and vapor fraction of water-containing live oil were higher than those of dehydrated dead crude within the operating temperature range. Liquid–gas flow was likely to occur in the presence of low soil temperatures, low oil output, low outlet pressure, high outlet temperatures, or small water fractions, particularly at the pipeline ends. Moreover, the optimized technological processes for stations and pipeline operations were proposed. The findings offer a new approach for the safe transportation of low-output live oil and provide valuable insights for optimizing surface production in aging oilfields. Full article

(This article belongs to the Special Issue Oil Recovery and Simulation in Reservoir Engineering)

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24 pages, 7652 KiB

Open AccessArticle

Economic Optimization of Enhanced Oil Recovery and Carbon Storage Using Mixed Dimethyl Ether-Impure CO₂ Solvent in a Heterogeneous Reservoir

by Kwangduk Seo, Bomi Kim, Qingquan Liu and Kun Sang Lee

Energies 2025, 18(3), 718; https://doi.org/10.3390/en18030718 - 4 Feb 2025

Viewed by 657

Abstract

CO₂ is the main solvent used in enhanced oil recovery (EOR). However, its low density and viscosity compared to oil cause a decrease in sweep efficiency. Recently, dimethyl ether (DME), which is more efficient than CO₂, has been introduced into the process. DME improves oil recovery by reducing minimum miscible pressure (MMP), interfacial tension (IFT), and oil viscosity. Since DME is an expensive solvent, price reduction and appropriate injection scenarios are needed for economic feasibility. In this study, a compositional model was developed to inject DME with impure CO₂ streams, where the CO₂ was derived from one of these three purification methods: dehydration, double flash, and distillation. It was assumed that such a mixed solvent was injected into a heterogeneous reservoir where gravity override was maximized. As a result, lower oil recovery is achieved for the higher impurity content of the CO₂ stream, lower DME content, and more heterogeneous reservoir. When a high-purity CO₂ stream is used, the change in oil recovery according to DME content and heterogeneity of the reservoir is increased. When the lowest-purity CO₂ stream is used, the net present value (NPV) is the highest. For a homogeneous reservoir, the NPV is highest for all impure CO₂ streams. This optimization indicates a greater impact on revenue from reduced CO₂ purchase cost than on profit loss due to reduced oil recovery by impurities. Additional benefits can be expected when considering solvent reuse and carbon capture and storage (CCS) credits. Full article

(This article belongs to the Special Issue Oil Recovery and Simulation in Reservoir Engineering)

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17 pages, 5387 KiB

Open AccessArticle

Microscopic Effect of Mixed Wetting Capillary Characteristics on Spontaneous Imbibition Oil Recovery in Tight Reservoirs

by Yu Pu, Erlong Yang and Di Wang

Energies 2025, 18(2), 324; https://doi.org/10.3390/en18020324 - 13 Jan 2025

Viewed by 590

Abstract

The understanding of the mechanisms that govern water spontaneous imbibition in mixed wetting capillary channels plays a significant role in operating the oil extraction and energy replenishment for the tight oil reservoirs. In this work, the conservative form phase-field model together with the Navier–Stokes equation is employed to investigate the influence of the mixed wetting distribution and the wetting degree on the imbibition oil recovery effects and microscopic flow characteristics. Results indicate that there exist different oil detachment modes of spontaneous imbibition, and these modes are determined by the coupled effect of mixed wetting fraction and contact angle size. For the mixed wetting capillary with strong oil wetting, when f_w is low, spontaneous imbibition can only partially detach the oil. Low f_w slows down the fluid flow velocity and leads to the small imbibition oil recovery rate. After that, the influence of the surface contact angle size of the mixed wetting capillary is discussed. For the complete detachment mode, the capillary tube presents a form of water phase saturated filling, achieving the optimal imbibition oil recovery effect. For the mixed wetting capillary tube with the combination of weak water wetting and strong oil wetting (i.e., θ_w = 75° and θ_o = 165°), local spontaneous imbibition turbulence can only detach very little oil at the inlet of the water wetting area, ultimately achieving a recovery efficiency of less than 10%. This work illuminates the spontaneous imbibition oil recovery mechanisms and flow potentiality for the different mixed wetting capillary channels. Full article

(This article belongs to the Special Issue Oil Recovery and Simulation in Reservoir Engineering)

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20 pages, 8914 KiB

Open AccessArticle

Improved Amott Method to Determine Oil Recovery Dynamics from Water-Wet Limestone Using GEV Statistics

by Ksenia M. Kaprielova, Maxim P. Yutkin, Mahmoud Mowafi, Ahmed Gmira, Subhash Ayirala, Ali Yousef, Clayton J. Radke and Tadeusz W. Patzek

Energies 2024, 17(14), 3599; https://doi.org/10.3390/en17143599 - 22 Jul 2024

Viewed by 1306

Abstract

Counter-current spontaneous imbibition of water is a critical oil recovery mechanism. In the laboratory, the Amott test is a commonly used method to assess the efficacy of brine imbibition into oil-saturated core plugs. The classic Amott-cell experiment estimates ultimate oil recovery, but not the recovery dynamics that hold fundamental information about the imbibition mechanisms. Retention of oil droplets at the outer core surface and initial production delay are the two key artifacts of the classic Amott experiment. This retention, referred to here as the “external-surface oil holdup effect” or simply “oil holdup effect”, often results in stepwise recovery curves that obscure the true dynamics of spontaneous imbibition. To address these holdup drawbacks of the classic Amott method, we modified the Amott cell and experimental procedure. For the first time, using water-wet Indiana limestone cores saturated with brine and mineral oil, we showed that our improvements of the Amott method enabled accurate and reproducible measurements of oil recovery dynamics. Also for the first time, we used the generalized extreme value (GEV) statistics to describe oil production histories from water-wet heterogeneous limestone cores with finite initial water saturations. We demonstrated that our four-parameter GEV model accurately described the recovery dynamics, and that optimal GEV parameter values systematically reflected the key characteristics of the oil–rock system, such as oil viscosity and rock permeability. These findings gave us a more fundamental understanding of spontaneous, counter-current imbibition mechanisms and insights into what constitutes a predictive model of counter-current water imbibition into oil-saturated rocks with finite initial water saturation. Full article

(This article belongs to the Special Issue Oil Recovery and Simulation in Reservoir Engineering)

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17 pages, 3043 KiB

Open AccessArticle

Infill Well Location Optimization Method Based on Recoverable Potential Evaluation of Remaining Oil

by Chen Liu, Qihong Feng, Wensheng Zhou, Shanshan Li and Xianmin Zhang

Energies 2024, 17(14), 3492; https://doi.org/10.3390/en17143492 - 16 Jul 2024

Viewed by 1203

Abstract

Infill well location optimization poses significant challenges due to its complexity and time-consuming nature. Currently, determining the scope of infill wells relies heavily on field engineers’ experience, often using single indices such as the remaining oil saturation or abundance of remaining oil reserves to evaluate the potential of remaining oil. However, this approach lacks effectiveness in guiding the precise tapping of remaining oil in ultra-high water cut reservoirs. To address this, our study comprehensively considers the factors influencing the recoverable potential of remaining oil in such reservoirs. We characterize the differences in reservoir heterogeneity, scale of recoverable remaining oil reserves, water flooding conditions, and oil–water flow capacity to construct a quantitative evaluation index system for the recoverable potential of remaining oil. Recognizing the varying degrees of influence of different indices on the recoverable potential of remaining oil, we determine the objective weight of each evaluation index by combining an accelerated genetic algorithm with the projection pursuit model. This approach enables the construction of a recoverable potential index for remaining oil and forms a quantitative evaluation method for the recoverable potential of remaining oil in ultra-high water cut reservoirs. Subsequently, we establish a mathematical model for infill well location optimization, integrating and optimizing the infill well location coordinates, well length, well inclination angle, and azimuth angle. Using the main layer sand body of an oilfield in Bohai as a case study, we conducted evaluations of the remaining oil potential and infill well location optimization. Our results demonstrate that the assessment of the remaining oil potential comprehensively characterizes the influence of the reservoir’s physical properties and oil–water diversion capacity on the remaining oil potential across different regional positions. This evaluation can effectively guide the determination of infill well location ranges based on the evaluation results. Furthermore, infill well location optimization can effectively enhance reservoir development outcomes. Full article

(This article belongs to the Special Issue Oil Recovery and Simulation in Reservoir Engineering)

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Review

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35 pages, 27119 KiB

Open AccessReview

Recent Advances in Geochemical and Mineralogical Studies on CO₂–Brine–Rock Interaction for CO₂ Sequestration: Laboratory and Simulation Studies

by Muhammad Noman Khan, Shameem Siddiqui and Ganesh C. Thakur

Energies 2024, 17(13), 3346; https://doi.org/10.3390/en17133346 - 8 Jul 2024

Cited by 10 | Viewed by 3633

Abstract

The urgent need to find mitigating pathways for limiting world CO₂ emissions to net zero by 2050 has led to intense research on CO₂ sequestration in deep saline reservoirs. This paper reviews key advancements in lab- and simulation-scale research on petrophysical, geochemical, and mineralogical changes during CO₂–brine–rock interactions performed in the last 25 years. It delves into CO₂ MPD (mineralization, precipitation, and dissolution) and explores alterations in petrophysical properties during core flooding and in static batch reactors. These properties include changes in wettability, CO₂ and brine interfacial tension, diffusion, dispersion, CO₂ storage capacity, and CO₂ leakage in caprock and sedimentary rocks under reservoir conditions. The injection of supercritical CO₂ into deep saline aquifers can lead to unforeseen geochemical and mineralogical changes, possibly jeopardizing the CCS (carbon capture and storage) process. There is a general lack of understanding of the reservoir’s interaction with the CO₂ phase at the pore/grain scale. This research addresses the gap in predicting the long-term changes of the CO₂–brine–rock interaction using various geochemical reactive transport simulators. Péclet and Damköhler numbers can contribute to a better understanding of geochemical interactions and reactive transport processes. Additionally, the dielectric constant requires further investigation, particularly for pre- and post-CO₂–brine–rock interactions. For comprehensive modeling of CO₂ storage over various timescales, the geochemical modeling software called the Geochemist’s Workbench was found to outperform others. Wettability alteration is another crucial aspect affecting CO₂–brine–rock interactions under varying temperature, pressure, and salinity conditions, which is essential for ensuring long-term CO₂ storage security and monitoring. Moreover, dual-energy CT scanning can provide deeper insights into geochemical interactions and their complexities. Full article

(This article belongs to the Special Issue Oil Recovery and Simulation in Reservoir Engineering)

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