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Energies
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Reservoir Simulation Studies for Enhanced Oil Recovery
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Reservoir Simulation Studies for Enhanced Oil Recovery

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

Deadline for manuscript submissions: closed (20 September 2021) | Viewed by 9887

Special Issue Editor

Prof. Dr. Mojdeh Delshad

E-Mail Website
Guest Editor
Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, Austin, TX 78712, USA
Interests: geologic carbon storage; enhanced oil recovery; reservoir engineering; unconventional resources; reservoir simulation
Special Issues, Collections and Topics in MDPI journals

Special Issue Information

Dear Colleagues,

We are soliciting high-quality technical papers for this Special Issue “Reservoir Simulation Studies of EOR Technologies”. Many EOR techniques have been tested in pilot studies and at commercial scales with three major processes of miscible gas, and chemical and thermal methods. There are new hybrid EOR methods currently under field testing to improve the cost and recovery efficiencies, such as low salinity water/polymer, gas/surfactant (low tension foam), and CO2 storage in oil reservoirs, among others.

There has been growing motivation and contribution to EOR projects for improving reservoir characterization and process modeling for predicting recovery responses. Practically all EOR methods require a high-resolution description of the reservoir to capture the variations in reservoir properties more accurately. All EOR methods require specific correlations for phase behavior, fluid properties, and relative permeability/capillary pressure, among others. An understanding of the interactions of fluids/rock and the role of geochemistry in low salinity water, chemical, and CO2 floods have also been receiving increasing attention.

Prof. Dr. Mojdeh Delshad
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 simulation
  • EOR methods
  • low salinity/smart water/designer water flood
  • polymer
  • surfactant/polymer
  • alkaline/surfactant/polymer
  • CO2 storage/utilization
  • hybrid EOR methods
  • shale oil EOR methods
  • laboratory/field scales
  • naturally fractured reservoirs
  • scale-up methodologies

Published Papers (4 papers)

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Research

16 pages, 2010 KiB  
Article
Modeling Oil Recovery in Brazilian Carbonate Rock by Engineered Water Injection Using Numerical Simulation
by Fabio Bordeaux-Rego, Jose Adriano Ferreira, Claudio Alberto Salinas Salinas Tejerina and Kamy Sepehrnoori
Energies 2021, 14(11), 3043; https://doi.org/10.3390/en14113043 - 24 May 2021
Cited by 6 | Viewed by 1951
Abstract
Waterflooding remains the most commonly used method to improve oil recovery. Although the injected brine type is mainly dependent on its availability, few of its characteristics can be controlled during project design. Published laboratory work indicates that the adjustment of injected brine composition [...] Read more.
Waterflooding remains the most commonly used method to improve oil recovery. Although the injected brine type is mainly dependent on its availability, few of its characteristics can be controlled during project design. Published laboratory work indicates that the adjustment of injected brine composition can cause an increase in oil production by wettability alteration. This research objective is to propose a novel four-step framework for modeling improved oil recovery by Engineered Water Injection from laboratory to numerical simulation for carbonate formations. We use a geochemical-based model that estimates contact angles to predict wettability alteration. The steps are (1) screening criteria, (2) geochemical evaluation, (3) wettability alteration modeling, and (4) coreflood history-match. We validate our framework by conducting history-match simulations of Brazilian Pre-Salt corefloods. Incremental oil recovery factors are between 5 to 11%, consistent with those reported during experiments. The reduction in residual oil saturation varied from 3 to 5%. This work is a new systematic procedure to model oil recovery using a comprehensive approach that is fundamental to understanding the underlying wettability alteration mechanisms by Engineered Water Injection. Full article
(This article belongs to the Special Issue Reservoir Simulation Studies for Enhanced Oil Recovery)
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14 pages, 4898 KiB  
Article
Modeling Near-Miscible Gas Foam Injection in Fractured Tight Rocks and Its Challenges
by Haishan Luo and Kishore K. Mohanty
Energies 2021, 14(7), 1998; https://doi.org/10.3390/en14071998 - 05 Apr 2021
Cited by 8 | Viewed by 1582
Abstract
Unlocking oil from tight reservoirs remains a challenging task, as the existence of fractures and oil-wet rock surfaces tends to make the recovery uneconomic. Injecting a gas in the form of a foam is considered a feasible technique in such reservoirs for providing [...] Read more.
Unlocking oil from tight reservoirs remains a challenging task, as the existence of fractures and oil-wet rock surfaces tends to make the recovery uneconomic. Injecting a gas in the form of a foam is considered a feasible technique in such reservoirs for providing conformance control and reducing gas-oil interfacial tension (IFT) that allows the injected fluids to enter the rock matrix. This paper presents a modeling strategy that aims to understand the behavior of near-miscible foam injection and to find the optimal strategy to oil recovery depending on the reservoir pressure and gas availability. Corefloods with foam injection following gas injection into a fractured rock were simulated and history matched using a compositional commercial simulator. The simulation results agreed with the experimental data with respect to both oil recovery and pressure gradient during both injection schedules. Additional simulations were carried out by increasing the foam strength and changing the injected gas composition. It was found that increasing foam strength or the proportion of ethane could boost oil production rate significantly. When injected gas gets miscible or near miscible, the foam model would face serious challenges, as gas and oil phases could not be distinguished by the simulator, while they have essentially different effects on the presence and strength of foam in terms of modeling. We provide in-depth thoughts and discussions on potential ways to improve current foam models to account for miscible and near-miscible conditions. Full article
(This article belongs to the Special Issue Reservoir Simulation Studies for Enhanced Oil Recovery)
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23 pages, 5314 KiB  
Article
Surfactant-Polymer Interactions in a Combined Enhanced Oil Recovery Flooding
by Pablo Druetta and Francesco Picchioni
Energies 2020, 13(24), 6520; https://doi.org/10.3390/en13246520 - 10 Dec 2020
Cited by 19 | Viewed by 3648
Abstract
The traditional Enhanced Oil Recovery (EOR) processes allow improving the performance of mature oilfields after waterflooding projects. Chemical EOR processes modify different physical properties of the fluids and/or the rock in order to mobilize the oil that remains trapped. Furthermore, combined processes have [...] Read more.
The traditional Enhanced Oil Recovery (EOR) processes allow improving the performance of mature oilfields after waterflooding projects. Chemical EOR processes modify different physical properties of the fluids and/or the rock in order to mobilize the oil that remains trapped. Furthermore, combined processes have been proposed to improve the performance, using the properties and synergy of the chemical agents. This paper presents a novel simulator developed for a combined surfactant/polymer flooding in EOR processes. It studies the flow of a two-phase, five-component system (aqueous and organic phases with water, petroleum, surfactant, polymer and salt) in porous media. Polymer and surfactant together affect each other’s interfacial and rheological properties as well as the adsorption rates. This is known in the industry as Surfactant-Polymer Interaction (SPI). The simulations showed that optimum results occur when both chemical agents are injected overlapped, with the polymer in the first place. This procedure decreases the surfactant’s adsorption rates, rendering higher recovery factors. The presence of the salt as fifth component slightly modifies the adsorption rates of both polymer and surfactant, but its influence on the phase behavior allows increasing the surfactant’s sweep efficiency. Full article
(This article belongs to the Special Issue Reservoir Simulation Studies for Enhanced Oil Recovery)
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19 pages, 4511 KiB  
Article
The Numerical Simulation Study of the Oil–Water Seepage Behavior Dependent on the Polymer Concentration in Polymer Flooding
by Qiong Wang, Xiuwei Liu, Lixin Meng, Ruizhong Jiang and Haijun Fan
Energies 2020, 13(19), 5125; https://doi.org/10.3390/en13195125 - 01 Oct 2020
Cited by 5 | Viewed by 1567
Abstract
It is well acknowledged that due to the polymer component, the oil–water relative permeability curve in polymer flooding is different from the curve in waterflooding. As the viscoelastic properties and the trapping number are presented for modifying the oil–water relative permeability curve, the [...] Read more.
It is well acknowledged that due to the polymer component, the oil–water relative permeability curve in polymer flooding is different from the curve in waterflooding. As the viscoelastic properties and the trapping number are presented for modifying the oil–water relative permeability curve, the integration of these two factors for the convenience of simulation processes has become a key issue. In this paper, an interpolation factor Ω that depends on the normalized polymer concentration is firstly proposed for simplification. Then, the numerical calculations in the self-developed simulator are performed to discuss the effects of the interpolation factor on the well performances and the applications in field history matching. The results indicate that compared with the results of the commercial simulator, the simulation with the interpolation factor Ω could more accurately describe the effect of the injected polymer solution in controlling water production, and more efficiently simplify the combination of factors on relative permeability curves in polymer flooding. Additionally, for polymer flooding history matching, the interpolation factor Ω is set as an adjustment parameter based on core flooding results to dynamically consider the change of the relative permeability curves, and has been successfully applied in the water cut matching of the two wells in Y oilfield. This investigation provides an efficient method to evaluate the seepage behavior variation of polymer flooding. Full article
(This article belongs to the Special Issue Reservoir Simulation Studies for Enhanced Oil Recovery)
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