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Energies
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Oil Recovery and Simulation in Reservoir Engineering
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Oil Recovery and Simulation in Reservoir Engineering

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

Deadline for manuscript submissions: 30 September 2024 | Viewed by 2280

Special Issue Editor

Prof. Dr. Ganesh Thakur

E-Mail Website
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:

  1. Essential lab research and data gathering;
  2. Developing a robust pilot program to test the oil recovery process;
  3. Simulation and scale-up at field level;
  4. Engineering an economically viable plan;
  5. Implementing the plan;
  6. Monitoring and evaluating performance;
  7. 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

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

  • 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 (3 papers)

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Research

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20 pages, 8914 KiB  
Article
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 492
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 [...] Read more.
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  
Article
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 433
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 [...] Read more.
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  
Review
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
Viewed by 1042
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, [...] Read more.
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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