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Enhanced Oil Recovery 2020

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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 (28 February 2021) | Viewed by 39018

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Special Issue Editor

Prof. Dr. Dandina N. Rao

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Guest Editor

Craft & Hawkins Department of Petroleum Engineering, Louisiana State University, Baton Rouge, LA 70803, USA
Interests: enhanced oil recovery; gas-assisted gravity drainage; wettability; miscibility
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Dear Colleagues,

In addition to being a source of energy, crude oil is the basic raw material for innumerable products that we use every day. Even when the alternate sources of energy, such as solar and wind power, become competitive, they will never be able to serve as raw material for these petrochemical products, which range from perfumes to insecticides and fertilizers, and eyeglasses to heart valves. Hence, the world will continue to depend on crude oil for the foreseeable future. However, where will this crude oil come from to meet this ever-increasing demand? Enhanced oil recovery (EOR) is the answer. Therefore, this Special Issue is dedicated to the topic of EOR.

The target for EOR is over 407 billion barrels in onshore US reservoirs and over 2 trillion barrels around the world. It is known that an increase in the capillary number by four orders of magnitude or more is required of any EOR process to reduce the residual oil saturation significantly below that of a waterflood.

The literature has established ways to accomplish such a large change in capillary number in the producing reservoirs by means of reducing the interfacial tension and by altering wettability. Both these aspects have been explored through several research studies using surfactants and recently through low-salinity waterflooding.

Thermal EOR has to overcome the economic challenges of producing relatively lower-priced heavy oil using an expensive injectant (such as steam). Novel techniques of downhole steam generation and comingling steam with additives are being attempted to bring down the costs.

Shale oil is the new big story of this decade. Although they have played a significant role in setting the new energy scene in the world, shale oil resources direly require EOR technologies, since their primary production rates drop rapidly in the first few years, with reported recoveries only in the range of 3–7% OOIP.

This Special Issue on EOR-2020 aims to address all the above resources by bringing together the knowledge and experience of experts in various disciplines in this one volume.

Prof. Dr. Dandina N. Rao
Guest Editor

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Keywords

enhanced oil recovery
crude oil
waterflood
surfactants
thermal EOR

Published Papers (14 papers)

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Research

20 pages, 6222 KiB

Open AccessArticle

A Single-Well Gas-Assisted Gravity Drainage Enhanced Oil Recovery Process for U.S. Deepwater Gulf of Mexico Operations

by Bikash D. Saikia and Dandina N. Rao

Energies 2021, 14(6), 1743; https://0-doi-org.brum.beds.ac.uk/10.3390/en14061743 - 21 Mar 2021

Cited by 4 | Viewed by 1830

Abstract

The U.S. Deepwater Gulf of Mexico (DGOM) area that has some of the most prolific oil reservoirs is still awaiting the development of a viable enhanced oil recovery (EOR) process. Without it, DGOM will remain severely untapped. Exorbitant well costs, in excess of $200 million, preclude having extensive injection patterns, commonly used in EOR design frameworks. Aside from injection patterns, even operationally waterflooding has met with significant challenges because of injectivity issues in these over pressurized turbidities. The gas-assisted gravity drainage (GAGD) EOR process, that holds promise for deepwater environments because of lesser injectivity issues, among others, has been adapted in this work to overcome these limitations. A novel design in the form of a single well—gas assisted gravity drainage (SW-GAGD) process, has been demonstrated to emulate the benefits of a GAGD process in a cost-effective manner. Unlike conventional GAGD processes, which need multiple injectors and separate horizontal production wells, the SW-GAGD process just uses a single well for injection and well production. The performance of the process has been established using partially scaled visual glass models based on dimensional analyses for scale up of the process. The recovery factor has been shown to be in the range of 65–80% in the immiscible mode alone, and the process is orders of magnitude faster than natural gravity drainage. A toe-to-heel configuration of the SW-GAGD process has also been tested and for the configuration to be immune from reservoir layering, the toe of the well should ideally end at the top of the payzone. Better sweep of the payzone and consequent high recovery factor of 80% OOIP was observed, if the heel part of the bottom lateral is located in a lower permeability zone. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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28 pages, 15113 KiB

Open AccessArticle

Simulation Analysis of CO₂-EOR Process and Feasibility of CO₂ Storage during EOR

by Maja Arnaut, Domagoj Vulin, Gabriela José García Lamberg and Lucija Jukić

Energies 2021, 14(4), 1154; https://0-doi-org.brum.beds.ac.uk/10.3390/en14041154 - 22 Feb 2021

Cited by 12 | Viewed by 3476

Abstract

In this study, oil production and retention were observed and compared in 72 reservoir simulation cases, after which an economic analysis for various CO₂ and oil prices was performed. Reservoir simulation cases comprise different combinations of water alternating gas (WAG) ratios, permeabilities, and well distances. These models were set at three different depths; thus different pressure and temperature conditions, to see the impact of miscibility on oil production and CO₂ sequestration. Those reservoir conditions affect oil production and CO₂ retention differently. The retention trend dependence on depth was not monotonic—optimal retention relative to the amount of injected CO₂ could be achieved at middle depths and mediocre permeability as well. Results reflecting different reservoir conditions and injection strategies are shown, and analysis including the utilization factor and the net present value was conducted to examine the feasibility of different scenarios. The analysis presented in this paper can serve as a guideline for multiparameter analysis and optimization of CO₂-enhanced oil recovery (EOR) with a WAG injection strategy. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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16 pages, 7054 KiB

Open AccessArticle

CO₂ Injection and Enhanced Oil Recovery in Ohio Oil Reservoirs—An Experimental Approach to Process Understanding

by Manoj Kumar Valluri, Jimin Zhou, Srikanta Mishra and Kishore Mohanty

Energies 2020, 13(23), 6215; https://0-doi-org.brum.beds.ac.uk/10.3390/en13236215 - 26 Nov 2020

Cited by 4 | Viewed by 2095

Abstract

Process understanding of CO₂ injection into a reservoir is a crucial step for planning a CO₂ injection operation. CO₂ injection was investigated for Ohio oil reservoirs which have access to abundant CO₂ from local coal-fired power plants and industrial facilities. In a first of its kind study in Ohio, lab-scale core characterization and flooding experiments were conducted on two of Ohio’s most prolific oil and gas reservoirs—the Copper Ridge dolomite and Clinton sandstone. Reservoir properties such as porosity, permeability, capillary pressure, and oil–water relative permeability were measured prior to injecting CO₂ under and above the minimum miscibility pressure (MMP) of the reservoir. These evaluations generated reservoir rock-fluid data that are essential for building reservoir models in addition to providing insights on injection below and above the MMP. Results suggested that the two Ohio reservoirs responded positively to CO₂ injection and recovered additional oil. Copper Ridge reservoir’s incremental recovery ranged between 20% and 50% oil originally in place while that of Clinton sandstone ranged between 33% and 36% oil originally in place. It was also deduced that water-alternating-gas injection schemes can be detrimental to production from tight reservoirs such as the Clinton sandstone. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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19 pages, 11118 KiB

Open AccessArticle

Experimental Investigation of the Effects of Water and Polymer Flooding on Geometric and Multifractal Characteristics of Pore Structures

by Xianguo Zhang, Chengyan Lin, Yuqi Wu, Tao Zhang, Hongwei Wang, Hanwei Wang, Xiaoxiao Wu and Derong Huang

Energies 2020, 13(20), 5288; https://0-doi-org.brum.beds.ac.uk/10.3390/en13205288 - 12 Oct 2020

Cited by 5 | Viewed by 1517

Abstract

During water and polymer flooding for enhanced oil recovery, pore structures may vary because of the fluid–rock interactions, which can lead to variations in petrophysical properties and affect oil field production. To investigate the effects of fluid flooding on pore structures, six samples were subjected to brine water, dual-system, and alkaline–surfactant–polymer (ASP) polymer displacement experiments. Before and after experiments, samples were scanned by X-ray CT. Thin sections, X-ray diffraction, and high pressure mercury injection tests were also carried out to characterize mineralogy and fractal dimension of pore systems before experiments. Experiment results show that water flooding with low injection pore volume ratio (IPVR) can improve reservoir quality since total porosity and connected porosity of samples rise after the flooding and the proportion of large pores also increases and heterogeneity of pore structure decreases. However, water flooding with high IPVR has reverse effects on pore structures. Polymer flooding reduces the total porosity, connected porosity, the percentage of small pores and enhances the heterogeneity of pore structures. It can be found that pore structures will change in fluid flooding and appropriate water injection can improve reservoir quality while excessive water injection may destroy the reservoir. Meanwhile, injected polymer may block throats and destroy reservoirs. The experimental results can be used as the basis for oil field development. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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22 pages, 6092 KiB

Open AccessArticle

Insights into Nanoscale Wettability Effects of Low Salinity and Nanofluid Enhanced Oil Recovery Techniques

by Dayo Afekare, Jayne C. Garno and Dandina Rao

Energies 2020, 13(17), 4443; https://0-doi-org.brum.beds.ac.uk/10.3390/en13174443 - 27 Aug 2020

Cited by 12 | Viewed by 2522

Abstract

In this study, enhanced oil recovery (EOR) techniques—namely low salinity and nanofluid EOR—are probed at the nanometer-scale using an atomic force microscope (AFM). Mica substrates were used as model clay-rich rocks while AFM tips were coated to present alkyl (-CH₃), aromatic (-C₆H₅) and carboxylic acid (-COOH) functional groups, to simulate oil media. We prepared brine formulations to test brine dilution and cation bridging effects while selected concentrations (0 to 1 wt%) of hydrophilic SiO₂ nanoparticles dispersed in 1 wt% NaCl were used as nanofluids. Samples were immersed in fluid cells and chemical force mapping was used to measure the adhesion force between polar/non-polar moieties to substrates. Adhesion work was evaluated based on force-displacement curves and compared with theories. Results from AFM studies indicate that low salinity waters and nanoparticle dispersions promote nanoscale wettability alteration by significantly reducing three-phase adhesion force and the reversible thermodynamic work of adhesion, also known as adhesion energy. The maximum reduction in adhesion energy obtained in experiments was in excellent agreement with existing theories. Electrostatic repulsion and reduced non-electrostatic adhesion are prominent surface forces common to both low salinity and nanofluid EOR. Structural forces are complex in nature and may not always decrease total adhesion force and energy at high nanoparticle concentration. Wettability effects also depend on surface chemical groups and the presence of divalent Mg²⁺ and Ca²⁺ cations. This study provides fresh insights and fundamental information about low salinity and nanofluid EOR while demonstrating the application of force-distance spectroscopy in investigating EOR techniques. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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18 pages, 1987 KiB

Open AccessArticle

Effect of Environment-Friendly Non-Ionic Surfactant on Interfacial Tension Reduction and Wettability Alteration; Implications for Enhanced Oil Recovery

by Omid Mosalman Haghighi, Ghasem Zargar, Abbas Khaksar Manshad, Muhammad Ali, Mohammad Ali Takassi, Jagar A. Ali and Alireza Keshavarz

Energies 2020, 13(15), 3988; https://0-doi-org.brum.beds.ac.uk/10.3390/en13153988 - 02 Aug 2020

Cited by 77 | Viewed by 4468

Abstract

Production from mature oil reservoirs can be optimized by using the surfactant flooding technique. This can be achieved by reducing oil and water interfacial tension (IFT) and modifying wettability to hydrophilic conditions. In this study, a novel green non-ionic surfactant (dodecanoyl-glucosamine surfactant) was synthesized and used to modify the wettability of carbonate reservoirs to hydrophilic conditions as well as to decrease the IFT of hydrophobic oil–water systems. The synthesized non-ionic surfactant was characterized by Fourier transform infrared spectroscopy (FTIR) and chemical shift nuclear magnetic resonance (HNMR) analyses. Further pH, turbidity, density, and conductivity were investigated to measure the critical micelle concentration (CMC) of surfactant solutions. The result shows that this surfactant alters wettability from 148.93° to 65.54° and IFT from 30 to 14 dynes/cm. Core-flooding results have shown that oil recovery was increased from 40% (by water flooding) to 59% (by surfactant flooding). In addition, it is identified that this novel non-ionic surfactant can be used in CO₂ storage applications due to its ability to alter the hydrophobicity into hydrophilicity of the reservoir rocks. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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33 pages, 7279 KiB

Open AccessEditor’s ChoiceArticle

Unlocking the Effects of Fluid Optimization on Remaining Oil Saturation for the Combined Sulfate-Modified Water and Polymer Flooding

by Muhammad Tahir, Rafael E. Hincapie and Leonhard Ganzer

Energies 2020, 13(12), 3049; https://0-doi-org.brum.beds.ac.uk/10.3390/en13123049 - 12 Jun 2020

Cited by 7 | Viewed by 2493

Abstract

Interfacial interactions and wettability alteration remain as the main recovery mechanism when modified water is applied seeking to obtain higher oil recoveries. Fluid-fluid interaction could lead to the development of the called viscoelastic layer at the interface in oil-brine systems. This interfacial layer stabilizes thanks to the slow chemical interaction between oil polar compounds and salts in the brine. This study investigates the role of sulfate presence in injection brine that could possible lead to develop the interfacial viscoelastic layer and hence to contribute to the higher oil recovery. Furthermore, polymer flooding is performed in tertiary mode after brine flood to investigate/unlock the synergies and potential benefits of the hybrid enhanced oil recovery. Brine optimization is performed using the composition of two formation brines and four injection brines. Moreover, interfacial tension measurements and oil drop snap-off volume measurements are performed in parallel with the core flooding experiments to define the role of interfacial viscoelasticity as the recovery mechanism other than wettability alteration. Synthetic seawater spiked with double amount of sulfate depicted potential results of interfacial viscoelastic layer development and hence to contribute the higher oil recovery. Total oil recovery after secondary-mode using sulfate-modified water and tertiary-mode polymer flood was higher than the combination of seawater brine in secondary-mode and polymer flood in tertiary-mode. Nevertheless, experiments helped us concluding that the amount of sulfate added is a critical factor to obtain maximum oil recovery and to avoid pore-plugging problems. We, therefore, demonstrate that executing a detailed fluid optimization leads to promising laboratory results, potentially linked with an improvement in the economics of the field applications. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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14 pages, 1616 KiB

Open AccessArticle

Screening of the Effective Additive to Inhibit Surfactin from Forming Precipitation with Divalent Cations for Surfactin Enhanced Oil Recovery

by Nao Miyazaki, Yuichi Sugai, Kyuro Sasaki, Yoshifumi Okamoto and Satohiro Yanagisawa

Energies 2020, 13(10), 2430; https://0-doi-org.brum.beds.ac.uk/10.3390/en13102430 - 12 May 2020

Cited by 6 | Viewed by 2075

Abstract

Surfactin, which is an anionic bio-surfactant, can be effective for enhanced oil recovery because it decreases interfacial tension between oil and water. However, it forms precipitation by binding with divalent cations. This study examined the countermeasure to prevent surfactin from forming precipitation for applying it to enhanced oil recovery. Alcohols, chelating agents, a cationic surfactant and an ion capturing substance were selected as the candidates for inhibiting surfactin from forming precipitation. Citric acid and trisodium citrate were selected as promising candidates through the measurements of turbidity of the mixture of the candidate, surfactin and calcium ions. Those chemicals also had a function as a co-surfactant for surfactin. However, the permeability of the Berea sandstone core into which the solution containing surfactin and trisodium citrate was injected was decreased significantly, whereas citric acid could be injected into the core without significant permeability reduction. Citric acid was therefore selected as the best inhibitor and subjected to the core flooding experiments. High enhancement of oil recovery of 9.4% (vs. original oil in place (OOIP)) was obtained and pressure drop was not increased during the injection of surfactin and citric acid. Those results suggest that citric acid has a dual role as the binding inhibitor and co-surfactant for surfactin. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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14 pages, 3509 KiB

Open AccessArticle

Experimental Studies of Immiscible High-Nitrogen Natural Gas WAG Injection Efficiency in Mixed-Wet Carbonate Reservoir

by Mirosław Wojnicki, Jan Lubaś, Marcin Warnecki, Jerzy Kuśnierczyk and Sławomir Szuflita

Energies 2020, 13(9), 2346; https://0-doi-org.brum.beds.ac.uk/10.3390/en13092346 - 08 May 2020

Cited by 4 | Viewed by 2423

Abstract

Crucial oil reservoirs are located in naturally fractured carbonate formations and are currently reaching a mature phase of production. Hence, a cost-effective enhanced oil recovery (EOR) method is needed to achieve a satisfactory recovery factor. The paper focuses on an experimental investigation of the efficiency of water alternating sour and high-nitrogen (~85% N₂) natural gas injection (WAG) in mixed-wetted carbonates that are crucial reservoir rocks for Polish oil fields. The foam-assisted water alternating gas method (FAWAG) was also tested. Both were compared with continuous water injection (CWI) and continuous gas injection (CGI). A series of coreflooding experiments were conducted within reservoir conditions (T = 126 ℃, P = 270 bar) on composite cores, and each consisted of four reservoir dolomite core plugs and was saturated with the original reservoir fluids. In turn, some of the experiments were conducted on artificially fractured cores to evaluate the impact of fractures on recovery efficiency. The performance evaluation of the tested methods was carried out by comparing oil recoveries from non-fractured composite cores, as well as fractured. In the case of non-fractured cores, the WAG injection outperformed continuous gas injection (CGI) and continuous water injection (CWI). As expected, the presence of fractures significantly reduced performance of WAG, CGI and CWI injection modes. In contrast, with regard to FAWAG, deployment of foam flow in the presence of fractures remarkably enhanced oil recovery, which confirms the possibility of using the FAWAG method in situations of premature gas breakthrough. The positive results encourage us to continue the research of the potential uses of this high-nitrogen natural gas in EOR, especially in the view of the utilization of gas reservoirs with advantageous location, high reserves and reservoir energy. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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15 pages, 3724 KiB

Open AccessArticle

A Novel Assisted Gas–Oil Countercurrent EOR Technique for Attic Oil in Fault-Block Reservoirs

by Kang Ma, Hanqiao Jiang, Junjian Li, Rongda Zhang, Kangqi Shen and Yu Zhou

Energies 2020, 13(2), 402; https://0-doi-org.brum.beds.ac.uk/10.3390/en13020402 - 14 Jan 2020

Cited by 5 | Viewed by 2561

Abstract

As the mature oil fields have stepped into the high water cut stage, the remaining oil is considered as potential reserves, especially the attic oil in the inclined fault-block reservoirs. A novel assisted gas–oil countercurrent technique utilizing gas oil countercurrent (GOC) and water flooding assistance (WFA) is proposed in this study to enhance the remaining oil recovery in sealed fault-block reservoirs. WFA is applied in our model to accelerate the countercurrent process and inhibit the gas channeling during the production process. Four comparative experiments are conducted to illustrate enhanced oil recovery (EOR) mechanisms and compare the production efficiency of assisted GOC under different assistance conditions. The results show that WFA has different functions at different stages of the development process. In the gas injection process, WFA forces the injected gas to migrate upward and shortens the shut-in time by approximately 50% and the production efficiency improves accordingly. Compared with the basic GOC process, the attic oil swept area is extended 60% at the same shut-in time condition and secondary gas cap forms under the influence of WFA. At the production stage, the WFA and secondary gas cap expansion form the bi-directional flooding. The bi-directional flooding also displaces the bypassed oil and replaced attic oil located below the production well, which cannot be swept by the gas cap expansion. WFA inhibits the gas channeling effectively and increases the sweep factor by 26.14% in the production stage. The oil production increases nearly nine times compared with the basic GOC production process. The proposed technique is significant for the development of attic oil in the mature oil field at the high water cut stage. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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32 pages, 14602 KiB

Open AccessArticle

Performance Evaluation of an Anti Gas-Channeling System (Asphalt-Rigid Particle-Xanthan Gum) Applied in High-Temperature and High-Salinity Fractured Reservoir

by Nanjun Lai, Yiping Wen, Xiaohu Wen, Wei He, Xiaosha Lin, Chao Jia and Dong Hu

Energies 2019, 12(24), 4766; https://0-doi-org.brum.beds.ac.uk/10.3390/en12244766 - 13 Dec 2019

Cited by 6 | Viewed by 2874

Abstract

Asphalt and rigid particles have been chosen as the main blocking agent for solving the anti gas-channeling in high-temperature and high-salinity reservoirs. Particle size range and the concentration of suspending agent were firstly determined, and the influence factors on bonding effect between two materials in the high-temperature environment were then studied. An orthogonal experiment involving three factors (the content of rigid particles and asphalt, and softening point) and four levels was designed to investigate the impact order of the three factors on anti gas-channeling performance, and the optimization scheme has been identified. Results showed that the importance sequence of the factors was C _{rigid particles} > C _asphalt > softening point. By verifying the optimization scheme, the plugging ratio of this agent can reach more than 86.24% for 2 mm fractured core in high-temperature and high-salinity environments. The system was evenly distributed in the internal fractures, occupied the fractures completely, and had a certain height of accumulation. The micromorphology observations of the optimal scheme showed that the softened asphalt demonstrated its ‘amoeba’ characteristic and bonded with the surrounding rigid particles. The asphalt filled in the pore which was formed by bridging rigid particles to guarantee the blocking layer did not collapse or was carried by high-pressure N₂-flow. This approach can potentially solve gas-channeling problems in reservoirs with serious environments. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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15 pages, 5629 KiB

Open AccessArticle

Optimization Design of Injection Strategy for Surfactant-Polymer Flooding Process in Heterogeneous Reservoir under Low Oil Prices

by Hong He, Yuqiu Chen, Qun Yu, Xianli Wen and Haocheng Liu

Energies 2019, 12(19), 3789; https://0-doi-org.brum.beds.ac.uk/10.3390/en12193789 - 07 Oct 2019

Cited by 9 | Viewed by 3155

Abstract

Surfactant–polymer (SP) flooding has significant potential to enhance oil recovery after water flooding in mature reservoirs. However, the economic benefit of the SP flooding process is unsatisfactory under low oil prices. Thus, it is necessary to reduce the chemical costs and improve SP flooding efficiency to make SP flooding more profitable. Our goal was to maximize the incremental oil recovery of the SP flooding process after water flooding by using the equal chemical consumption cost to ensure the economic viability of the SP flooding process. Thus, a systematic study was carried out to investigate the SP flooding process under different injection strategies by conducting parallel sand pack flooding experiments to optimize the SP flooding design. Then, the comparison of the remaining oil distribution after water flooding and SP flooding under different injection strategies was studied. The results demonstrate that the EOR efficiency of the SP flooding process under the alternating injection of polymer and surfactant–polymer (PASP) is higher than that of conventional simultaneous injection of surfactant and polymer. Moreover, as the alternating cycle increases, the incremental oil recovery increases. Based on the analysis of fractional flow, incremental oil recovery, and remaining oil distribution when compared with the conventional simultaneous injection of surfactant and polymer, the alternating injection of polymer and surfactant–polymer (PASP) showed better sweep efficiency improvement and recovered more remaining oil trapped in the low permeability zone. Thus, these findings could provide insights into designing the SP flooding process under low oil prices. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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28 pages, 2093 KiB

Open AccessArticle

Polymer Gels Made with Functionalized Organo-Silica Nanomaterials for Conformance Control

by Bahador Najafiazar, Dag Wessel-Berg, Per Eirik Bergmo, Christian Rone Simon, Juan Yang, Ole Torsæter and Torleif Holt

Energies 2019, 12(19), 3758; https://0-doi-org.brum.beds.ac.uk/10.3390/en12193758 - 30 Sep 2019

Cited by 2 | Viewed by 2617

Abstract

Deep placement of gel in waterflooded hydrocarbon reservoirs may block channels with high water flow and may divert the water into other parts of the reservoir, resulting in higher oil production. In order to get the gel constituents to the right reservoir depths, a delay in the gelling time in the order of weeks at elevated temperatures will be necessary. In this work, a methodology for controlled gelation of partially hydrolyzed polyacrylamide using hybrid nanomaterials with functional groups as cross-linkers was developed. Two delay mechanisms with hybrid materials and polyelectrolyte complexes were designed and tested. Both mechanisms could significantly delay the gelation rate, giving gelling times ranging from several days to several weeks in synthetic sea water at 80 °C. Gelling experiments in sandstone cores showed that gel strength increased with aging time. For long aging times, strong gels were formed which resulted in almost no water permeability. A series of coreflooding experiments with polymer and deactivated nanomaterial were performed. In addition to differential pressures and concentration profiles, the experiments enabled calculation of retention and inaccessible pore volumes. A novel numerical model of 1D two-phase flow has been developed and tested with results from core flooding experiments. The model can track the age distribution and concentrations of the nanomaterial (and therefore water viscosity) throughout the porous medium at every time step. The model generated a good fit of experimental results. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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15 pages, 4170 KiB

Open AccessArticle

Morphology and Rheological Properties of Polyacrylamide/Bentonite Organic Crosslinking Composite Gel

by Jun Li, Wen Zhou, Zhilin Qi, Taotao Luo, Wende Yan, Honglin Xu, Keyang Cheng and Hui Li

Energies 2019, 12(19), 3648; https://0-doi-org.brum.beds.ac.uk/10.3390/en12193648 - 24 Sep 2019

Cited by 4 | Viewed by 2921

Abstract

The use of polymer gel for water control and oil addition is a common technical method in oilfield development. The polymer and hydrated bentonite react under the action of an organic crosslinking agent to form a composite gel. The particle-size change and microstructure of the composite gel were analyzed via shear thinning, thixotropic, viscoelastic, and start-up stress rheology experiments. The experimental results show that the polyacrylamide/bentonite organic crosslinked composite gel was a gel system with bentonite as the core aggregate structure, and the large particle-size distribution was mostly increased with increasing crosslinker content. The composite gel presented shear thinning characteristics, the content of bentonite or crosslinking agent was increased, and the shear resistance was stronger at a high shear rate. The composite gel exhibited positive thixotropic properties, and the thixotropy increased with increasing bentonite content. The composite gel had good viscoelastic characteristics, the elastic characteristics of the composite gel showed more significantly with bentonite increases, and the viscosity of the composite gel showed its characteristics more significantly with the crosslinking agent increased. After loading at a rate on the composite gel, the shear stress increased significantly with time and reached its maximum value, and then the shear stress decreased and gradually stabilized. Full article

(This article belongs to the Special Issue Enhanced Oil Recovery 2020)

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