Enhanced Oil Recovery Processes Research Articles

In-situ emulsification in low-tension surfactant/polymer systems: Impacts on enhanced oil recovery

The flow of two immiscible liquids in porous media can lead to fluid mixing, resulting in emulsions—where one phase is dispersed as droplets in the other. In reservoir rocks, natural surfactants and polar molecules, like asphaltenes, can promote oil–water emulsion formation. During chemically enhanced oil recovery processes (CEOR) such as surfactant, alkali, or surfactant-alkali flooding, in-situ emulsification is often seen as key to enhancing frontal stability and facilitating the piston-like displacement of oil by water. However, this work reports a minimal effect of in-situ emulsification on oil production during surfactant-polymer (SP) flooding. Experimental studies show this by injecting prepared emulsions into a multi pressure-tap core holder and examining emulsion formation in one reservoir core before moving it into a second core for oil displacement. This helps us understand the specific role of emulsions in oil mobilization. Factors like surfactant concentration, interfacial tension, and the timing of introducing the surfactant-polymer solution do influence the intensity of in-situ emulsification. Yet, the incremental oil recoveries show no significant differences. Through similar experiments, it is observed that ultra-low interfacial tension (IFT) in our surfactant-polymer system is the primary mechanism for oil mobilization. The slight increase in pressures suggests that in-situ emulsification has a limited role in increasing flow resistance during the ultra-low IFT SP flood process, potentially not improving the swept volume. This research can guide the development of systematic approaches to analyze the effects of in-situ emulsification on oil mobilization and evaluate chemical flooding processes.

Advanced polymer‐based surfactant for improved heat and salinity stability in enhanced oil recovery processes

AbstractEnhancing oil recovery through surfactants has proven to be a successful strategy in recent times. However, traditional surfactants have their limitations, particularly in terms of stability under high temperatures and salinity levels. This study delved into a groundbreaking macromolecular polymeric surfactant, S‐AV, which holds the unique ability to transform rock surface characteristics, effectively stripping away residual oil while maintaining resilience against elevated temperatures and salinity. S‐AV was synthesized through a free‐radical copolymerization process, incorporating benzyl, perfluoroalkyl, alkyl‐, benzyl‐, ethylene glycol, and amide‐alkyl‐sulfonate groups, ultimately yielding a comb‐like molecular structure. S‐AV demonstrated exceptional prowess, swiftly reducing the underwater oil contact angle to 53.4° in just 48 h. This synthesized surfactant also retained its phase stability up to salinity levels of 36,000 ppm, with temperature having no disruptive impact on its phase stability performance. Furthermore, S‐AV showcased remarkable viscosity reduction in conditions of high temperature and salinity. The core flooding experiments underscored the potential of S‐AV, as its injection led to a significant oil recovery rate of up to 83%. These findings position S‐AV as a promising candidate for practical enhanced oil recovery applications.

Technology Focus: EOR Modeling (January 2024)

The oil and gas industry is at a critical juncture in addressing the pressing need to balance operational efficiency with environmental stewardship. With the world’s growing emphasis on climate change and sustainability, the industry is tasked with the dual objectives of refining operational efficiency and simultaneously diminishing its carbon footprint. This balancing act has become a strategic imperative crucial for the long-term viability of the industry. In light of the recent COP28 agreement, which emphasizes a “swift, just, and equitable energy transition,” the role of low-emission enhanced oil recovery (EOR) and operational optimization becomes increasingly significant. This period of transition, which may span several decades, demands a pragmatic approach where the existing hydrocarbon resources are used as efficiently and responsibly as possible. In the quest to optimize operations and reduce carbon footprint, three innovative technical papers present a cohesive story of advancement through modeling and machine learning. These papers underscore the industry’s shift toward more efficient practices, each contributing a crucial piece to the larger puzzle of EOR.The first paper introduces an advanced modeling approach for fractured reservoirs, a significant development in tight rock simulations that simplifies fracture heterogeneity characterization and enhances computational efficiency, crucial for optimizing asset development decisions in shale and tight oil resources. Building on the theme of efficiency, the second paper pivots to the realm of surfactants, exploring their role in wettability alteration within unconventional liquid-rich reservoirs. This research provides a systematic approach for screening thermally stable surfactants under reservoir conditions, crucial for improving hydrocarbon recovery without unnecessary field trials. The final piece of this narrative is a study using machine learning to predict gas-injection parameters in EOR processes. This approach addresses the lack of extensive gas-injection laboratory data, demonstrating the power of data-driven predictions in enhancing operational efficiency and decision-making. These papers weave a compelling narrative of technological innovation, highlighting the role of advanced modeling and machine learning. As the oil and gas industry progresses in its vital mission to supply the world’s energy needs, the pivotal role of technology innovation becomes increasingly evident. Advanced technologies focused on operational optimization and reducing carbon emissions are essential in reinforcing the industry’s adaptability and resilience in the context of this rapidly evolving energy landscape. Recommended additional reading at OnePetro: www.onepetro.org. SPE 215083 An Analytical Tool to Predict Fracture Extension and Elastic Desaturation for Polymer Field Projects by M.B. Abdullah, The University of Texas at Austin, et al. SPE 216822 First Pilot Design of Low-Tension-Gas (LTG) Flooding in Carbonate Field in North Oman by Mohammed Al-Abri, Petroleum Development Oman, et al. SPE 213037 Field-Scale Multistage and Multiobjective Optimization of Rate and Concentration for Polymer Flooding by Ruxin Zhang, Texas A&M University, et al.

The Influence of Pineapple Skin Eco-Enzyme on The Formation of Middle Phase Emulsion in Enhanced Oil Recovery Implementation

Oil requirement is constantly experiencing escalation, although at the current situation, the supply still depended on fossil and non-renewable fuel sources. The volume of crude oil production, especially in older wells, is starting to decrease. That is why, Enhanced Oil Recovery (EOR) method in form of chemical injection with surfactant is currently developed. The study aims to provide understanding on the influence of pineapple peel eco enzyme concentration in the formation of middle phase emulsion in EOR process. The method used in this research is a laboratory study of pineapple skin eco-enzyme as surfactant solution on brine with 20,000 ppm and 40,000 ppm sanities. The concentration levels of pineapple skin eco-enzyme surfactant were at 20%, 30%, and 40%. Phase behavior test was conducted on pineapple skin eco-enzyme with varied levels of salinities and concentrations. The middle phase emulsion test was conducted at 60°C. Middle phase emulsion test results for 20,000 ppm salinity produced 2.5% middle phase in all concentration variations (20%, 30%, and 40%). Meanwhile for 40,000 ppm brine salinity, 1.25% of middle phase was found at 20% and 40% concentration, however at 40% concentration, the middle phase was at 6.25%. The phase behavior test results show that the highest level of middle phase emulsion formation was at 40,000 ppm salinity and 30% concentration (6.25%). Based on the finding, we can conclude that eco-enzyme can be utilized as surfactant due to its ability to form a stable middle phase emulsion on certain levels of concentration and salinity.

Modeling and semi-analytical solution for immiscible and miscible fingers formation during enhanced oil recovery

ABSTRACT The fingering phenomenon arises during the secondary and tertiary oil recovery processes when injected fluid (water, gases, nano/biomaterials, or polymer particles) shoots through a porous medium at a relative speed. Oil recovery is influenced by various factors including the fluid type, capillary pressure, permeability, and porous material structure. All these elements play crucial roles in determining the success and efficiency of the oil recovery process. Many scientists have debated the fingering phenomenon from different perspectives. Here, we developed mathematical models with and without considering mass flow rates of oil and water for an inclined oil layer flowing through a homogenous porous medium to generate immiscible fingers. Furthermore, a mathematical model of miscible viscous finger formation with carbonated water injection (flooding) during the enhanced oil recovery process (EOR) has been analyzed in this paper. To solve each of these mathematical models, we used the recently developed approach known as the Method of Directly Defining the inverse Mapping (MDDiM). We found approximate solutions to the nonlinear partial differential equations (PDEs), which describe each modeling of the fingering phenomenon in a homogeneous porous medium by incorporating gravitational effects for several types of flooding and discussed the effects of the saturation rate.

Recent advances and challenges in gas injection techniques for enhanced oil recovery

Gas injection techniques have emerged as a pivotal method in Enhanced Oil Recovery (EOR), aimed at maximizing the extraction of oil from mature reservoirs. Recent advances in this domain have significantly improved the efficiency and effectiveness of gas injection methods, contributing to increased recovery rates and extended reservoir lifespans. This reviews the latest technological innovations and persistent challenges associated with gas injection techniques in EOR. One of the primary advancements in gas injection is the development of more sophisticated gas compositions, including the use of CO₂, nitrogen, and hydrocarbon gases. These gases have been optimized to improve miscibility with crude oil, thereby enhancing displacement efficiency and increasing oil recovery. Moreover, advancements in monitoring and modeling technologies, such as real-time reservoir simulation and 4D seismic monitoring, have enabled more precise control and assessment of gas injection processes, ensuring optimal gas utilization and minimizing environmental impact. Innovations in smart well technologies and downhole monitoring systems have further enhanced the ability to manage and optimize gas injection operations. These technologies provide continuous data on reservoir conditions, enabling dynamic adjustment of injection parameters to maximize recovery. Additionally, the integration of machine learning and artificial intelligence in EOR processes has facilitated predictive analytics, improving decision-making and operational efficiency. Despite these advancements, several challenges persist. The primary challenge lies in the high operational costs and economic feasibility of gas injection projects, particularly in volatile oil markets. Ensuring the long-term stability and effectiveness of injected gases in heterogeneous reservoirs also presents significant technical hurdles. Moreover, environmental concerns related to the use of CO₂ and other gases necessitate the development of more sustainable and eco-friendly injection methods. Addressing these challenges requires ongoing research and development, as well as collaboration between industry stakeholders, to refine gas injection techniques and mitigate associated risks. The future of gas injection in EOR looks promising, with continued innovation poised to overcome existing barriers and drive more efficient and sustainable oil recovery methods. In conclusion, while recent advances in gas injection techniques for EOR have demonstrated considerable potential, overcoming the economic, technical, and environmental challenges remains crucial for the widespread adoption and success of these methods.

Stability Evaluation of Nanofluids Suitable for Enhanced Oil Recovery

The evaluation of metal oxides nanoparticles stability in the base fluids has become a major aspect in enhanced oil recovery process in recent years. Physical and chemical properties of ZnO nanofluids have caught attention of many researchers because they are easily dispersed in the base fluids, better convective coefficient of heat transfer, and wider bandgap which make them remarkable nanofluids candidate compared to other metal oxides. In this study, the stability of nanofluid of zinc oxide nanoparticles was evaluated using different stability tests and analysis. However, ZnO nanoparticles were synthesized using sol-gel method and nanofluids of different concentrations were prepared. The prepared nanoparticles were characterized using various characterization techniques such as XRD, FTIR, TEM, and Zeta sizer. The stability of prepared nanofluids was investigated using sedimentation test, UV-vis spectrophotometer, and zeta analyzer. Based on physical investigation and UV-vis spectra observations, ZnO nanoparticles in base fluids have shown a good colloidal stability in addition to their high zeta potential values of-43.7 (mV) after seven days which makes it a successful potential candidate for enhanced oil recovery applications.

Impact of Injection Gas on Low-Tension Foam Process for EOR in Low-Permeability Oil-Wet Carbonates

Low-tension gas (LTG) flooding has been proven in lab-scale experiments to be a viable tertiary enhanced oil recovery (EOR) technique in low-permeability (~10 mD) oil-wet carbonates. Work carried out previously almost exclusively focused on water-wet cores. The application of LTG in oil-wet carbonates is investigated in this study along with the impact of a hydrocarbon (HC) mixture as the injection gas on oil–water microemulsion phase behavior. The optimum injection gas fraction (ratio of gas injection rate to total injection rate of gas and water) for the hydrocarbon gas mixture in oil-wet carbonates regarding the oil recovery rate was determined to be 60% as it resulted in around 50% residual oil in place (ROIP) recovery. It was shown that proper mobility control can be achieved under these conditions even in the absence of strong foam. The effect of HC gas dissolution in oil was clearly shown by replacing the injection HC gas with nitrogen under the same conditions. Furthermore, the importance of ultra-low interfacial tension (IFT) produced by the injection gas and surfactant slug is proven by comparing injection at sub-optimum salinity to injection at optimum salinity.

Synergistic effect of graphene oxide and partially hydrolyzed polyacrylamide for enhanced oil recovery: Merging coreflood experimental and CFD modeling approaches

The present study provides a comprehensive examination of GO-HPAM polymeric nanocomposite, contributing significantly to enhanced oil recovery (EOR). At the core of this investigation are a series of experimental tests and validations of simulations. The study examines the bonding effects, structural integrity, morphological interconnections, and stability of the GO-HPAM. The significance of reservoir and in-situ fluid conditions in the effort to improve EOR The GO-HPAM stabilization composite was developed, assessed, and examined for its extended core-flooding capabilities owing to its high energy characteristics. The simulation model was built on a Cartesian grid with fixed values for the bulk volume, injection rate, well completion, and rock-fluid properties using ANSYS Fluent. During the flooding experiment, the injections of 2 PV of brine, 0.50 PV of GO-HPAM, and 2 PV of chase water were precursors. The findings showed that 19.67% of the original oil could be recovered after injecting the nanocomposite fluid consisting of GO-HPAM. The GO-HPAM flooding gathered over 60% more oil than the traditional EOR polymer. Moreover, numerical modeling demonstrated a performance of the GO-HPAM combination comparable to the experimental results. The proposed synergetic fluid will assist researchers and industrialists in the design of an EOR process.

Molecular insights into the synergistic mechanisms of hybrid CO2-surfactant thermal systems at heavy oil-water interfaces

A hybrid thermal recovery process is a promising EOR (Enhanced Oil Recovery) method and has been widely applied to post-steamed heavy oil reservoirs. Due to the complexity of High Temperature and High Pressure (HTHP) reservoir environments, Molecules Dynamics (MD) simulations are conducted to investigate the interfacial behavior between multiphase multicomponent fluids and heavy oil over a wide temperature range. We select CO2 and a cost-effective anionic surfactant, SDS (Sodium Dodecyl Sulfate), to build hybrid thermal systems. The interfacial behavior in different systems is characterized by the local density distribution, cluster analysis, hydrogen bond characters, solvent accessible surface area, and interaction energy. Systematic MD simulations reveal a two-step interfacial tension (IFT) reduction process stimulated by thermal migration. Both CO2 and SDS can achieve an IFT decrement with different mechanisms. Moreover, a co-addition of CO2 and SDS can further efficiently reduce the IFT. Average Reduced Density Gradient (aRDG) results reveal that a unique asphaltenes-SDS-CO2 structure improves the interfacial activities and mobility of the heavy oil phase through a bidirectional mass exchange mechanism, which ultimately realizes the most significant IFT decrement. Furthermore, an optimal concentration (10C–20S) in a hybrid thermal system is recommended because of its balanced performance. This work sheds insight into the synergistic effects of multiphase multicomponent thermal fluids on hybrid thermal systems, which will guide future field applications of hybrid thermal EOR processes.

Study Evaluates CO2 Storage Potential During CO2 Mobility-Control Optimization

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212969, “Evaluation of CO2 Storage Potential During CO2 Mobility-Control Optimization for Enhanced Oil Recovery,” by Alvinda Sri Hanamertani, SPE, Ying Yu, SPE, and Omar El-Khatib, SPE, University of Wyoming, et al. The paper has not been peer reviewed. _ CO2 mobility control through foam technology has enabled better sweep efficiency and, consequently, better oil productivity during enhanced oil recovery (EOR) processes. Along with enhancing oil production, a sound potential exists for in-situ generated foam to enhance CO2 storage. However, the effect of the different in-situ foam generation strategies on the combined goal of maximum oil production and carbon storage is not well elucidated in the literature. In the complete paper, the authors methodically evaluate the simultaneous optimization of CO2 storage and oil recovery using multiple injection strategies. Introduction The current investigation is a continuation of two previous studies that provided a methodology for screening and using foaming agents for optimized CO2 storage in sandstone and carbonate formations. A base case of tertiary CO2 flooding was established for comparison with in-situ foam generation by two approaches: single-cycle surfactant-alternating-gas (SAG) flooding and coinjection of CO2 and surfactant. Additionally, the effect of surfactant concentration on foam efficiency, CO2 storage capacity, and oil recovery were evaluated in both approaches at reservoir conditions. Materials and Methods Fluids and Porous Medium. In this study, a synthetic brine with total dissolved solids of 20 wt% was used as blank brine and laden with a commercial zwitterionic surfactant that was used to prepare surfactant solutions with concentrations of 0.5 and 1 wt% active matter in the synthetic brine. Three core plugs were drilled from an Indiana limestone outcrop block. The cores were then cleaned and oven-dried at 95°C. Experimental Procedure. Vacuum saturation with brine was commenced for the three cores. The porosity of the cores was calculated using their dry and brine-saturated weights. Then, the 100% brine-saturated core was placed in a core holder and loaded into an oven set to 90°C. The pore pressure was fixed at 2,000 psi, and the confining pressure was controlled at 3,000 psi throughout the flooding experiment. The brine permeability of the core samples was evaluated by measuring the pressure drop across the core at different brine-injection flow rates. In the first experiment (IL1), oil drainage with a flow rate of 0.2 cm3/min was performed to establish irreducible water saturation of 46.9%. This total flow rate was kept the same throughout the three experiments. Then, a waterflooding stage was begun and the oil recovery was recorded. After reaching a plateau in oil recovery, supercritical CO2 (scCO2) was injected during the EOR process until the oil production plateaued.

Molecular insights of condensate trapping mechanism in shale oil reservoirs and its implications on lean gas enhanced oil recovery

The heterogeneous pore structure and the confinement effect of the narrow pore space lead to the differential release/retention phenomenon of hydrocarbons in unconventional reservoirs. So far, the mechanism of this phenomenon, in particular the dynamic process, requires further investigation since it affects the design of gas-based enhanced oil recovery (EOR) operations. In this work, we aim to numerically study the capillary condensate trapping mechanism that causes the differential release phenomenon by conducting molecular dynamics (MD) simulations.In our work, a two-bath MD model is set up, in which two baths are used to mimic the bulk pores and a nano-channel connecting the two baths is used to model the pore throat. Methane (C1) and decane (C10) molecules are used to represent the light and heavy component of the in-situ oil. The MD results show that at the early stage of the primary depletion, the light components release faster than the heavier components, leading to increasing gas oil ratio (GOR) above the system’s bubble point. As depletion continues, heavier hydrocarbons accumulate in the nano-channel due to the confinement effect, while light hydrocarbons tend to remain in the dead-end pores. During the gas EOR process, the injected gas ‘dissolves’ the liquid in the nano-channel and thus enhances the recovery of the ‘trapped’ hydrocarbons.This work systematically investigates the impact of pore throat on the differential release and trapping effect. We demonstrate that a significant amount of light hydrocarbons may be ‘trapped’ during the primary depletion of unconventional reservoirs, due to the capillary condensate trapping effect. The trapped hydrocarbons can be partly recovered through gas injection. Our study has implications for practical EOR operations.

Dynamics of two unequal micron-sized viscous emulsion drops flowing in a two-dimensional constricted microcapillary channel: A numerical study

Emulsions containing unequal-sized droplets are ubiquitous. Compared to the equal-sized emulsion droplet coalescence process in porous media, unequal-sized emulsion droplets show distinctly different dynamics and features when flowing through the capillary channel. In this paper, we numerically studied the flow of two unequal small micron-size emulsion drops flowing in a two-dimensional (2D) half-sine pulse shape constricted tube. The finite element method solves the momentum, continuity, and level set equations. The oil–water interface is tracked using the level set method. Effects of drop size, capillary number (interfacial tension), viscosity ratio, and geometrical shape constriction effects on the droplets' flow behavior across the throat, its flow velocities, and average viscous pressure across the tube were investigated. It is found when there is a significant difference in diameters of the two un-equalized droplets, they will flow separately through the throat, whereas when the two un-equalized droplets’ size is close to each other, they coalescence with each other after passing through the constriction. Higher interfacial tension leads unequal-sized droplets to coalescence more readily while droplets pass without coalescence at low interfacial tension cases. The highest pressure drop is recorded at the critical point where the two unequal-sized droplets begin to merge in the constriction throat. Increasing droplet viscosity reduces the chances of coalescence and increases the average viscous pressure drop hence leading to mobility reduction. In the case of geometrical constrictions, circular-shaped contracted tubes offer the least resistance to fluid flow and are more appropriate for enhanced oil recovery processes. We hope our numerical findings will provide more information to facilitate the enhanced oil recovery process.

Designing effective enhanced oil recovery fluid: Combination of graphene oxide, D118 SuperPusher, and Chuback surfactant

Enhanced oil recovery (EOR) is one of the most essential branches of petroleum engineering and aims to maximize oil extraction from reservoirs. This research focuses on the utilization of graphene oxide (GO) in combination with a D118 SuperPusher compound and a natural surfactant (Chuback) to enhance oil recovery. The objective is to optimize the efficiency of the EOR process through a multi-component approach. The application of Chuback leads to a substantial decrease in interfacial tension (IFT), particularly in carbonate rock formations. This is attributed to the unique characteristics of carbonate rocks, which exhibit greater susceptibility to wettability alterations. Moreover, GO nanoparticles (NPs) were synthesized, then characterized and incorporated into the surfactant-polymer system, creating surfactant-polymer-nanoparticle (SPN) fluids. The selection of optimum fluid formulations for the EOR process is facilitated through the utilization of Design Expert, a statistical software tool. Factors such as surfactant concentration, polymer concentration, NPs concentration, and two types of salt concentrations are specifically chosen as variables that can influence the fluid's performance during the flooding step. Parameters including IFT, contact angle (CA) (which affects wetting behavior), and shear viscosity (which impacts fluid flow) are considered responses. The efficacy of the suggested fluid formulation for EOR is validated through core flooding investigations. Core flooding investigations validated the efficacy of the suggested fluid for EOR, with recovery factors of up to 30% and 56% in sandstone and carbonate core samples, respectively. These findings underscore the potential of the proposed approach to significantly enhance oil recovery from both sandstone and carbonate reservoirs.

Exergy based assessment for decarbonization of CO2 foam flooding enhanced oil recovery process and energy transition with hydrogen

Water Flooding (WF) and CO2 Foam Flooding EOR (CFF) processes are exergy intensive and CO2 emissive in nature. Hence, the objective of this work is to investigate the ways to attain decarbonization and to evaluate hydrogen requirement for attaining energy transition during WF and CFF processes under different operational conditions. This was performed by using exergy-based evaluation metrics (i.e., Exergy-Return on Exergy-Investment (ERoEI), carbon emissions and hydrogen intensity). It was found that CFF process was 1.69 times more exergy intensive than WF process. Further, for every barrel of oil produced, WF process had net-CO2 emission of 5.18 kg, while CFF process had net-CO2 sequestration of 814.5 kg. Moreover, during CFF process, reducing the surfactant concentration from 2.5 wt% to 0.5 wt% had correspondingly decreased CO2 emissions from 70% to 31%. Further, to attain energy transition during production operations, it was evaluated that WF process requires 1.7 times more hydrogen than CFF process.

Laboratory Determination of Productivity of Bomu Oil Field (Oml 11 as Case Study) Using MEOR Process and Calcium Oxide Nanoparticles

The need for petroleum products in the world is increasing daily, this product can only be gotten from the refining of crude oil a naturally occurring mineral resource which is produced by degradation of organic materials. This crude is gotten from several wells drilled for the sole purpose of the production of this mineral resource but this wells are being shut-down and abandoned because of the decrease in the well’s productivity which causes losses to the operators and poor finances for the petroleum industry. Therefore, the need to increase the recovery of a well is been considered, these methods are called enhanced oil recovery method. These methods include Gas injection method, Steam Injection method, Chemical injection method (chemicals such as surfactants, polymers etc) Microbial method and the use of nanoparticles as additives to help increase the recovery process. The type of enhanced oil recovery used in this work is the microbial enhanced oil recovery, this method makes use of biosurfactants which can also be referred to as microbe surfactants. The biosurfactants are gotten from microorganism they act as surfactants which reduces the interfacial tension between the molecules of the substance and the interface, this biosurfactants can be used for many industrial purposes which includes bioremediation, oil recovery etc. Nanoparticles are also another aspect of the recent technology which can increase the recovery of our well providing more crude and finance for the petroleum industry. This work shows how biosurfactants and nanoparticles when used together can increase oil recovery. The ever-rising global demand for energy and the issue of large volumes of unrecovered oil after primary and secondary oil production operations are driving the development and/or advancement of enhanced oil recovery (EOR) techniques. Conventional EOR processes include thermal, immiscible and miscible gas injection, chemical, and microbial enhanced oil recovery

Influence of different nanoparticles on the gas injection performance in EOR operation: Parametric and CFD simulation study

AbstractThis study aims to simulate the process of enhanced oil recovery (EOR) during gas injection along with nanoparticles and investigate the affecting parameters in a conventional carbonate oil reservoir. Ansys Fluent software with a suitable multiphase model was used to simulate natural gas injection with a nanoparticle into a core sample. The simulation model was validated with a laboratory test of natural gas injection. Then, to obtain the optimal values of each of the parameters affecting the process of EOR during the natural gas injection along with nanoparticles, the design of the experiment was carried out with the help of Qualitek‐4 software and the Taguchi method. Therefore, three factors, including nanoparticle type (clay, titanium oxide, and silica nanoparticles), nanoparticle diameter (2–50 nm), and the volume fraction of nanoparticles in the base fluid (0.5–5 vol.%), as influential factors on the EOR during natural gas injection along with nanoparticles were chosen. The results of the numerical study indicated that silica nanoparticles significantly affect EOR more than clay and titanium oxide nanoparticles. Moreover, the smaller the diameter of nanoparticles (close to 2 nm) and the more significant the volume fraction of nanoparticles in the base fluid (close to 5 vol.%), the higher the oil recovery factor will be. This phenomenon occurs due to changes in the density and viscosity of the base fluid and, consequently, improves the mobility ratio of the injected fluid. On the other hand, the tiny size of nanoparticles allows them to easily enter the pores of the reservoir rock without entrapping and producing oil from them. Eventually, the highest oil recovery factor (59%) was obtained using silica nanoparticles with a diameter of 2 nm and a volume fraction of 5 vol.% in natural gas injection.

A Guide for Selection of Aging Time and Temperature for Wettability Alteration in Various Rock-Oil Systems.

Wettability alteration has been identified to be one of the important mechanisms to improve the microscopic recovery in many of the enhanced oil recovery (EOR) methods including polymer flood, surfactant flood, low salinity flood, microbial flood, alkaline flood, etc. Ensuring the oil-wet nature of the formation before flooding in the laboratory is necessary to study the efficiency of the EOR process, which targets microscopic recovery through wettability alteration. Nevertheless, altering the wettability depends on several parameters, such as aging time, aging temperature, core nature, oil properties, etc. Although several researchers investigated the effect of individual parameters on wettability alteration, the literature is scarce, and the question of what is the shortest and yet the most reliable aging time for ensuring wettability alteration for the specific rock-oil system at different temperatures remains unclear. This paper attempts to seek an answer to this question by compiling the relevant literature to find the effect of individual parameters such as different aging times, temperatures, oil compositions, and rock lithologies on wettability alteration. Results observed from data analysis showed different windows for aging conditions depending on the core sample lithology, initial wettability, and type of oil used. It was noticed that the higher the asphaltene content in the crude oil used, the lower the time and temperature that it takes to alter the sample wettability. Aging a sandstone core under 80 °C using crude oil with 11 wt % % asphaltene took 7 days to shift the core from strongly water-wet to neutral-wet. The same wettability alteration was achieved in 14 days when aging the sandstone sample at 90 °C using crude oil with 0.85 wt % asphaltene content. Generally, it was observed that the aging time decreased as the temperature increased. Moreover, as the sample has a lower initial water wettability condition, the time that it needs to be aged becomes higher. Results indicated that carbonates in general require less aging time to alter their wettability condition to oil-wet, around 1-7 days, compared with sandstones, around 14-21 days.

A New 3D Mathematical Model for Simulating Nanofluid Flooding in a Porous Medium for Enhanced Oil Recovery.

Two-phase Darcy's law is a well-known mathematical model used in the petrochemical industry. It predicts the fluid flow in reservoirs and can be used to optimize oil production using recent technology. Indeed, various models have been proposed for predicting oil recovery using injected nanofluids (NFs). Among them, numerical modeling is attracting the attention of scientists and engineers owing to its ability to modify the thermophysical properties of NFs such as density, viscosity, and thermal conductivity. Herein, a new model for simulating NF injection into a 3D porous media for enhanced oil recovery (EOR) is investigated. This model has been developed for its ability to predict oil recovery across a wide range of temperatures and volume fractions (VFs). For the first time, the model can examine the changes and effects of thermophysical properties on the EOR process based on empirical correlations depending on two variables, VF and inlet temperature. The governing equations obtained from Darcy's law, mass conservation, concentration, and energy equations were numerically evaluated using a time-dependent finite-element method. The findings indicated that optimizing the temperature and VF could significantly improve the thermophysical properties of the EOR process. We observed that increasing the inlet temperature (353.15 K) and volume fraction (4%) resulted in better oil displacement, improved sweep efficiency, and enhanced mobility of the NF. The oil recovery decreased when the VF (>4%) and temperature exceeded 353.15 K. Remarkably, the optimal VF and inlet temperature for changing the thermophysical properties increased the oil production by 30%.

Synergetic Interfacial Tension Reduction Potential of Silica Nanoparticles and Enzyme

The co-existence of multiphase fluids in the hydrocarbon reservoir rock pores plays a fundamental role in oil recovery processes because of the strong effect of interfacial forces that exist at the interface of these immiscible fluids. In this study, the effects of enzyme and silica nanoparticles on crude oil-brine interfacial tension were investigated under varied brine salinities and brine compositions. The results showed that the application of silica nanoparticles alone in brines of varied compositions and salinities does not significantly modify the crude oil-brine IFT. The use of enzyme and combined enzyme-nanoparticles however significantly reduced crude oil-brines IFT but the contribution of silica nanoparticles to the IFT reduction was not significant. The result of this study is relevant to the design and applications of enzyme and nanoparticles enhanced oil recovery processes.