Increase Oil Recovery Research Articles

Waterflooding optimization based on the CRM and solving the linear programming problem

Among the many technologies for increasing the efficiency of oil field development using waterflooding, the least economically expensive include hydrodynamic methods for increasing oil recovery, based on changing the directions of filtration flows. Thus, one of the key tasks of increasing the efficiency of waterflooding at a late stage of development is to reduce the volume of ineffective injection. The article discusses the problem of redistributing volumes of injected water between injection wells for a given total injection volume in order to increase oil production. An analytical relationship is proposed for assessing injection efficiency, based on known displacement characteristics and calculated well interference coefficients based on CRMP. The optimization problem is formulated as a linear programming problem. Using the example of a fragment of an oil deposit, the possibility of assessing the injectivity of injection wells is shown, which makes it possible to increase the predicted oil production by changing the direction of filtration flows in the formation. As a result of applying the developed algorithm, the predicted increase in cumulative oil production amounted to 19683 m³ (9.5%) over 15 years. Keywords: waterflooding optimization; capacitive-resistive model; CRM; linear programming; injection efficiency; interwell connectivity.

Forecast of technological indicators for the implementation of carbon dioxide injection in conditions of depleted deposits of the Ural-Volga region

This article presents the results of theoretical studies of the mechanism of the effect of CO₂ on residual oil in depleted fields. The task of studying the filtration processes of gas-liquid mixtures has been solved using mathematical modeling. A hydrodynamic model of the process of oil displacement by carbon dioxide is proposed, from which, under certain assumptions, equations describing various mechanisms of displacement can be obtained. In addition, methods for calculating the process of flooding of reservoirs with the use of carbon dioxide are considered. Using the example of a landfill site of one of the Ural-Volga deposits, the forecast technological efficiency of using carbon dioxide to increase oil recovery is calculated. Keywords: efficiency improvement; modeling; oil displacement; injection; carbon dioxide; oil recovery.

To the question of increasing oil recovery of formations with isolation of water influctions of the foundation of the «White Tiger» field

The article deals with the problem of enhanced oil recovery (EOR), which arises in connection with the steady decline in oil production and active depletion of reserves. The water cut of production wells leads to a decrease in oil production and a decrease in the rate of recovery of recoverable reserves. Among the factors influencing this process, both an increase in the water cut of the productive formation itself and the presence of cracks in the layers below the productive formation lead to a decrease in the effectiveness of the third methods of treatment. In this case, water ingress into the reservoir from fractured reservoirs below the reservoir or inefficient use of a certain part of the water injected into the reservoir to displace oil from the reservoir through fractures leads to a decrease in the oil recovery factor. Therefore, creating a screen at the bottom of the productive formation can ensure the efficiency of work. For this purpose, experiments were carried out in the direction of preparing a composition for waterproofing works using certain reagents. Here, the mechanism of interaction of aluminum chloride with alkaline reagents was studied and their optimal ratio in EOR technologies was evaluated. Water-insoluble precipitates are formed as a result of the interaction of aluminum chloride and alkaline reagents. Keywords: field; oil recovery; reaction; alkali; reagents; temperature; foundation.

Structuring and preliminary selection of enhanced oil recovery methods for the current reservoir conditions of Block C2N, Joint Venture Petrovictoria (Venezuela)

Global heavy oil reserves are the largest hydrocarbon resource in the world, with Venezuela's heavy oil reserves accounting for 87% of initial oil reserves; 258.3 out of 297.7 billion barrels. Primary oil production from such formations does not allow achieving a high recovery factor, which is only 5 to 10% due to the high viscosity of the reservoir oil and low mobility. The main purpose of the work is to determine the hierarchy and, with its help, preliminary selection of enhanced oil recovery (EOR) methods for the current reservoir conditions of the Carabobo 2 North block of the Petrovictoria joint venture, Venezuela. The methodology for selecting promising enhanced oil recovery methods for the created geological model of one of the objects for the potential application of enhanced oil recovery (EOR) methods in Venezuela (Orinoco Belt, Carabobo 2 North Block) is formed using applicability criteria. An EOR for an object based on the theory of fuzzy sets is proposed and evaluated. The main purpose of the work is to create a hierarchy and preliminary selection of methods for increasing oil recovery for the current conditions of the formation of the Carabobo 2 North block of the Petrovictoria joint venture, Venezuela. The method of selection (screening) of promising methods of increasing oil recovery for the created geological model of one of the objects of potential application of the Venezuelan EOR (North, Orinoco Belt), formed using the criteria of applicability and selection of the most promising EOR for the object, based on the theory of fuzzy sets, is presented and tested Keywords: heavy oil; enhanced oil recovery (EOR); EOR selection (screening); Orinoco Belt.

HORIZONTAL WELL COMPLETION SYSTEMS WITH MULTI-STAGE HYDRAULIC FRACTURING FOR LOW-PERMEABILITY, POORLY DRAINED, HETEROGENEOUS AND DISMEMBERED RESERVOIRS

Currently, the most effective method of intensifying the inflow of hydrocarbons and increasing oil recovery in productive formations in wells, in particular with a horizontal well, remains the technology of hydraulic fracturing (HF). In many regions, according to some domestic and foreign researchers, this is the only technology for developing fields with hard-to-recover hydrocarbon reserves confined to lowpermeability, poorly drained, heterogeneous and dissected reservoirs, which can significantly increase hydrocarbon production and make wells economically viable.Multi-stage hydraulic fracturing (MSHF) has established itself as one of the main methods of reservoir stimulation in the Russian Federation. The main goal of this method is to create highly conductive fractures in an oil and gas saturated reservoir throughout the horizontal section of the wellbore. To do this, an alternate series of hydraulic fracturing is performed, the result of which is the maximum production rate of hydrocarbons.Over time, oil and gas companies in the Russian Federation are becoming more demanding on the technical and technological parameters of MSHF in terms of the number of stages, the length of the horizontal section of the well, the possibility of re-fracturing and management of intervals/ports after its commissioning, and much more.The authors of the article propose to consider and analyze modern horizontal well completion systems with multi-stage hydraulic fracturing for low-permeability, low-drainage, heterogeneous and dissected reservoirs in order to form their rating.

Nano-stabilized foam for enhanced oil recovery using green nanocomposites and anionic surfactants: An experimental study

With the decline in hydrocarbon resources around the world, the use of different enhanced oil recovery (EOR) methods became more attractive. Recently, gas foams have been considered by researchers as one of the most effective ways to increase oil recovery. Despite its functions, the conventional foams have low stability. Recently, nanomaterials, as appropriate agents, are used to increase the stability of foams in enhances oil recovery. In this study, the synthesized nanocomposites (NCs), SiO2/KCl/Xanthan NCs was used to stabilize the foams obtained from sodium dodecyl sulfate (SDS) and cetyltrimethylammonium bromide (CTAB) surfactants. Thus, the synergic effect of the surfactant and NCs was investigated along with the salinity, foam quality, alkalinity and oil properties. The experimental measurements of conductivity, pH, surface tension (ST), interfacial tension (IFT), contact angle (CA) and oil displacement were performed. The obtaining results showed that the SDS and CTAB surfactants have the critical micelle concentration (CMC) of 2000 and 300 ppm, respectively. In terms of the foam stability, both surfactants demonstrated the same behavior of equal stability, while it is improved under the influence of NaCl and NaOH at different concentrations with reducing the ST, IFT and foam generation time (tg). In addition, the optimal NCs concentrations for SDS and CTAB surfactants which improved the foam stability significantly, reduced the CA by 73.27 and improved the oil recovery by 20 % original oil in place (OOIP) were 1000 ppm and 500 ppm, respectively. This was also confirmed by macroscopic analysis of the formulated nano-surfactant systems. On the other hand, the viscosity, density and the gas rate had the inverse influence on the foam stability.

Evaluating Factors Impacting Polymer Flooding in Hydrocarbon Reservoirs: Laboratory and Field-Scale Applications.

Polymer flooding is an enhanced oil recovery (EOR) method used to increase oil recovery from oil reservoirs beyond primary and secondary recovery. Although it is one of the most well-established methods of EOR, there are still continuous new developments and evaluations for this method. This is mainly attributed to the diverse polymers used, expansion of this method in terms of application, and the increase in knowledge pertaining to the topic due to the increase in laboratory testing and field applications. In this research, we perform a review of the factors impacting polymer flooding in both laboratory studies and field-based applications in order to create guidelines with respect to the parameters that should be included when designing a polymer flooding study or application. The main mechanism of polymer flooding is initially discussed, along with the types of polymers that can be used in polymer flooding. We then discuss the most prominent parameters that should be included when designing a polymer flooding project and, based on previous laboratory studies and field projects, discuss how these parameters impact the polymer itself and the flooding process. This research can provide guidelines for researchers and engineers for future polymer flooding research or field applications.

Enhancing foam stability and addressing asphaltene deposition for improved oil recovery in CCUS applications using aerogel nanoparticles

Carbon capture, utilization, and storage (CCUS) is critical for reducing CO2 emissions and mitigating climate change. However, two major technical hurdles must be addressed for efficient implementation of CCUS. Sandpack experiments were conducted to examine the efficacy of silica aerogel nanoparticles in enhancing oil recovery and inhibiting asphaltene deposition. The nanoparticle co-injection increases oil recovery from 49.39% to 73.21% compared to sole CO2 flooding. Meanwhile, the CO2 sequestration rate within sandpacks rises remarkably from 45.35% to 83.37% with added nanoparticles. Additionally, produced oil asphaltene content increases from 4.33 wt% to 7.25 wt%. Experimental results show aerogel undergo flow diffusion from aqueous to oil phases, modifying interfacial properties. Aerogel-stabilized CO2-in-oil foams exhibit reduced interfacial tension and enhanced stability, impeding CO2 mobility. Molecular dynamics simulations reveal aerogel pores adsorb asphaltene molecules, preventing deposition. Overall, the multifunctional capabilities of aerogel nanoparticles to modify interfaces, stabilize foams, and inhibit asphaltene deposition provide pathways for optimizing CCUS efficiency.

Enhanced oil recovery through alternating gas Re-injection to reduce gas flaring in the Bakken

Environmental performance is a significant driver of energy production today, and providing attractive methods to reduce flaring remains a high priority for oil producers. The Energy & Environmental Research Center (EERC), with support from the Bakken Production Optimization Program (BPOP), is investigating the reinjection of the associated gas into producing wells to reduce flaring.The project's main objectives are to evaluate technically and economically the feasibility of deploying alternating gas re-injection in the Bakken formation as a means to increase oil recovery, reduce flaring and maintain compliance. The approach addresses the compression capacity constraints, mineral ownership types, and gas availability. Gas reinjection has the added benefit of producing incremental oil that can offset installation and operational costs associated with gas compression and nonproducing time for a well during injection. A flow simulation model is created to investigate alternating gas injection of a four-well pad and to assess the possibility of incremental oil production. Extensive numerical simulation is conducted. Capital expenditure, operating costs and the revenue from oil recovery were considered. Results indicate that gas injection within rates of 100–200 Mcfd can produce incremental oil. The gas volume needed is greater than what is typically flared from a facility, however, less than the total produced gas volume, and, therefore, possible. Communication of gas is likely to occur between wells within 1500 feet and wells positioned heel to heel that are common to the well-pad facility. The most promising injection period appeared to be within a 2-week to 1-month cycle. Thus, the proposed approach can be employed as an efficient Enhanced Oil Recovery (EOR) technique, alternating gas injection of 3 MMcfd may potentially increase the produced oil rate by 70 %. The findings support continued work to further investigate well configurations that can best benefit from the technique and to mature economic case studies.

Laboratory Study of Analysis of the Effect of ABS Surfactant Injection on Increasing Oil Recovery

The decline in oil recovery in oil and gas fields is a problem that must be faced now and in the future along with the increasing need for petroleum energy. Increasing oil recovery reserves requires an advanced method, namely Enhanced Oil Recovery (EOR). Surfactants are one of the enhanced oil recovery (EOR) methods to increase oil recovery. This laboratory research will use a surfactant solution, namely ABS Surfactant (Alkyl Benzene Sulfonate). There are five concentrations for each surfactant, namely 0.3; 0.5; 0.75; 0.9; and 1% with the same salinity of 7,000 ppm. In this study, ABS surfactant was used because the surfactant has the characteristic of being able to reduce interfacial tension. This research carried out a phase behavior test to determine the stability of the emulsion with a measurement time of 7 days at a temperature of 80 °C. Making an ABS surfactant solution, 70% ABS fluid is available where the surfactant raw material will be mixed with brine with a salinity of 7,000 ppm. There are several stages carried out, namely density test, phase behavior, interfacial tension, and core flooding. After making a sample of the ABS surfactant solution, the second step was to carry out a density test using a DMA-4100 densitometer to determine the density of the ABS surfactant solution at temperatures of 30 °C and 80 °C. The third is a phase behavior test where the surfactant solution will be mixed with oil and then placed in an oven at a temperature of 80 °C for 336 hours to obtain emulsion results that are close to the midpoint so that the stability of the emulsion is more optimal. The fourth is to determine the IFT value with a surfactant sample that has the highest volume of microemulsion stability. Finally, the core flooding test is to determine how much oil is recovered from the sandstone when surfactant injection is carried out. In the IFT results, the ABS surfactant solution was able to reduce the interfacial tension well between oil and formation water in the reservoir, where the interfacial tension value was 0.0055654 dyne/cm. The results of core flooding with ABS surfactant with a concentration of 0.9% salinity of 7,000 ppm obtained a recovery factor of 14.545%.

”Increasing oil recovery by injecting an air composition of the surface active substance (SAS) in the irrigated layers”

The introduction of a water-gas mixture into the reservoir necessitates gas production along with oil in the field. This creates difficulties in the old fields of Azerbaijan. Therefore, unlike the water-gas mixture injected into the layers, the use of a solution of surfactant (SAS) in water instead of air water instead of gas guarantees that the process is both cheap and effective. During the injection of the mixture, the air, being a non-wet phase, will enter the small permeable pores of the layer, helping to displace the oil from it, as well as prevent the formation of water tongues in the layer. The solution from the SAS reagent to be added to the water will not only increase the oil-washing capacity, but also relieve the surface tension at the border with the oil, causing weakening of the capillary forces. Thus, the impact coverage of the reservoir will increase, which will ensure the rise of the oil recovery of the reservoir. By replacing the injection of water with the injection of a solution-air composition through an injector to remove residual oil from the irrigated reservoir, the oil yield coefficient increased by 27%. The injection of the solution-air composition through the reservoir injector increased the oil recovery and also led to a decrease in the volume of the outgoing water.

ПОЛИМЕРЛІ ЕРІТІНДІЛЕРДІҢ РЕОЛОГИЯЛЫҚ ҚАСИЕТТЕРІН ЗЕРТТЕУ

Annotation. The long-term operation of the deposit, the alternation of reservoir zones with high and degraded filtration and capacitance properties due to the heterogeneity of the reservoir, the deformation of the development system due to downtime and inactivity of wells predetermined the selective movement of water through the most permeable layers. As practice shows, the widespread use of traditional flooding technology does not ensure the effective production of residual reserves from low-permeable and highly watered formations. Therefore, increasing the degree of oil extraction from the depths of the developed fields using effective methods of active impact on water-oil-saturated formations is an important scientific and technical task facing the oilmen of the republic. One of the most effective and promising methods of stabilizing oil production is physics-chemical technologies based on the use of injection of polymer compositions. The main purpose of injection of polymer compositions is to equalize the heterogeneity of productive layers by reducing the mobility of the displacing agent in highly conductive interlayers and increasing the coverage of the reservoir by flooding both in power and in stretch. As is known, the effectiveness of the use of technologies based on polymer solutions depends on their good selective filterability into zones with high water saturation, which allows creating water-insulating screens in the desired direction and to a sufficient depth. It is known that the effective use of polymer solutions depends on the influence of various factors: molecular weight, polymer concentration in solution, filtration rates, reservoir permeability, as well as such an important parameter as the rheological properties of polymer solutions. The study of the rheological properties of polymer solutions allows us to substantiate and propose for practical implementation effective integrated technologies for increasing oil recovery during the operation of the oil fields under consideration. In this work, the rheological properties of polyacrylamide, physical parameters, taking into account their physics-chemical properties, are studied. The influence of mineralization and water hardness on polymer solutions is considered. The issues of mechanical destruction of polymers have been studied. The degree of mechanical destruction of the polymer is estimated based on the results of the study of the rheological properties of the polymer sample.

Involvement in the development of underexploited reserves of the Zhetybai oilfield

The issue of optimizing oil production has always been one of the pressing issues. The article discusses technological methods for involving in the development of non-drained reserves of the Zhetybai oilfield. The technologies of field development that have been used in recent years are presented. Of all the methods to increase oil recovery, hydraulic fracturing is the most effective. Hydraulic fracturing is considered one of the well-known and more effective methods in increasing oil production. Hydraulic fracturing can be used both in primary oil production and to improve the efficiency of existing wells. This method is widely used in the oil industry in many countries. Initially, this method was applied to lower permeable reservoirs in order to obtain narrow, deep-penetrating cracks. later, they began to be used for highly permeable collectors. In order for production to be more efficient, it is recommended to change the directions of fracturing fractures in the development of poorly drained reserves, this method was applied in the Povkhovsky oilfield. At the Povkhovskoye fields, in order to change the direction of fracturing fractures, a twostage fracturing was carried out in hard-to-recover formations, and the result was positive.

Extraction of Green Grass Jelly Leaves as An Alternative Biopolymer in Polymer Flooding

Biopolymer from Green Grass Jelly Leaves attracts attention due to its friendlier environmental profile and cost-effectiveness in providing raw materials. This research aims to explore the potential of biopolymers from Green Grass Jelly Leaves as an alternative to synthetic polymers in an effort to increase oil recovery involving sequential pretreatment, extraction, and characterization stages to obtain essential pectin compounds. This experiment centers on a biopolymer sourced from Green Grass Jelly Leaves, involving sequential steps of pretreatment, extraction, and characterization to obtain essential pectin compounds. Characterization employed scanning electron microscopy (SEM) and Fourier-transform infrared spectroscopy (FTIR). The recorded peak viscosity for Green Grass Jelly Leaves biopolymer was 2.04 cp at 3000 ppm concentration, contrasting with pectin's 1.98 cp viscosity. In comparison, industrial biopolymer Xanthan Gum displayed significantly higher viscosity at 95.01 cp for 3000 ppm concentration. Thermal stability assessment under reservoir conditions (30°C and 60°C) demonstrated that Green Grass Jelly Leaves biopolymer pectin exhibited peak viscosities of 55.29 cP and 51.77 cP at 3000 ppm concentration, respectively. These results show that the comparison between biopolymer and synthetic polymer is not too far and there is an increase in viscosity as the concentration increases, which can increase sweep efficiency.

Investigation of gravity influence on EOR and CO2 geological storage based on pore-scale simulation

Gravity assistance is a critical factor influencing CO2–oil mixing and miscible flow during EOR and CO2 geological storage. Based on the Navier–Stokes equation, component mass conservation equation, and fluid property–composition relationship, a mathematical model for pore-scale CO2 injection in oil-saturated porous media was developed in this study. The model can reflect the effects of gravity assistance, component diffusion, fluid density variation, and velocity change on EOR and CO2 storage. For non-homogeneous porous media, the gravity influence and large density difference help to minimize the velocity difference between the main flow path and the surrounding area, thus improving the oil recovery and CO2 storage. Large CO2 injection angles and oil–CO2 density differences can increase the oil recovery by 22.6% and 4.2%, respectively, and increase CO2 storage by 37.9% and 4.7%, respectively. Component diffusion facilitates the transportation of the oil components from the low-velocity region to the main flow path, thereby reducing the oil/CO2 concentration difference within the porous media. Component diffusion can increase oil recovery and CO2 storage by 5.7% and 6.9%, respectively. In addition, combined with the component diffusion, a low CO2 injection rate creates a more uniform spatial distribution of the oil/CO2 component, resulting in increases of 9.5% oil recovery and 15.7% CO2 storage, respectively. This study provides theoretical support for improving the geological CO2 storage and EOR processes.

Multiscale study of Janus nanosheets’ interfacial activity

As the challenge of enhancing oil recovery from reservoirs continues to grow, it becomes increasingly crucial to seek out new materials for oil displacement. Janus graphene oxide (JGO) with excellent interfacial activity stands out as a promising candidate, which enables it to locate crude oil and effectively displace it towards production wells. One key advantage of JGO is its ability to reduce interfacial tension and create interfacial films, attributed to JGO nanosheets adsorbing at oil–water interfaces. Another noteworthy property of JGO is its capacity to transform oil-wet rock surfaces into water-wet surfaces, which is because JGO nanosheets can interact hydrophobically with crude oil molecules on rock surfaces. In addition, JGO helps mitigate capillary resistance by altering the concave oil–water front to a flat state. Microscopic displacement shows that JGO nanosheets enlarge the sweep efficiency and oil-washing efficiency of water. Nuclear magnetic resonance experiment indicates that JGO nanofluid can increase oil recovery by 17.1 %. This research presents a comprehensive exploration of the interfacial activity of Janus nanofluid, spanning from the molecular scale to the micro and core scales.

NUMERICAL SIMULATION METHOD IN LOW PERMEABLE ANISOTROPIC RESERVOIRS IN ORDER TO INCREASE OIL RECOVERY


 
 The object of study is the filtration process in weakly permeable anisotropic formations (SAP). The work is devoted to the evaluation of the process of oil-bearing formation depletion, using as a criterion the distribution of reservoir pressure near the system of production and injection wells, taking into account the anisotropy of the permeability of the oil phase. In the course of the study, a combined numerical modeling method based on the finite element and finite difference methods is presented, which allows determining the value of reservoir pressure at any point in the computational domain. The finite-element-difference method proposed in this paper, which combines the advantages of the finite-element method and the finite-difference method to solve the nonstationary piezoelectric conductivity problem, taking into account the heterogeneous distribution of various filtration parameters within the deformed formation and at its boundaries, allows us to adequately calculate the distribution of reservoir pressure in real-world well operation conditions, which gives a number of advantages over existing methods. It was found that the effect of oil phase permeability in the shear direction dominates the effect of permeability in the axial directions. This is due to the fact that, according to the information obtained, for the effective use of anisotropic low-permeability formations, it is necessary to place production and injection wells in areas with relatively low anisotropy of formation permeability, especially to avoid areas with the presence of shear permeability of the formation. It is important to locate wells so that, on the one hand, there is no blockage of oil from the low permeability side, and, on the other hand, there is no rapid depletion of the formation from the high permeability side and the mutual exchange between the production and injection wells does not stop. When placing a system of production and injection wells in anisotropic formations of an oil field, it is necessary to conduct a systematic analysis of the surrounding anisotropy of the formations in order to place them in such a way that would ensure effective dynamics of filtration processes around these wells and increase oil recovery.
 
 
 
 
 

Технологии увеличения нефтеотдачи на месторождениях Северного Каспия

Permanent modernization of production processes for the extraction of hydrocarbon raw materials is an integral part of rational subsoil use. Research and implementation of the latest technologies in the process of oil produc-tion ensures production and economic efficiency. In the world practice of oil production, vast experience has been accumulated in experimental research and practical implementation of various methods that can significantly increase oil recovery. In the process of choosing a method or combination of methods for increasing oil recovery, many criteria are taken into account, but the geological conditions of the deposit under development, as well as the composition and physico-chemical characteristics of reservoir fluids are of primary importance. Of all the methods of increasing oil recovery, the biological method has become the least common today due to its little knowledge. The relevance of the research and further implementation of the technology of enhanced oil recovery by the biological method is primarily due to the criterion of environmental safety. A significant advantage of the biological method of increasing oil recovery is that microorganisms are capable of multiplying and enhancing biochemical activity depending on the physico-chemical conditions of the environment. One of the biological methods of increasing oil recovery is the activation of reservoir microflora. This technology consists in cyclic injection of nutrient medium into the formation, which stimulates an increase in the number of certain types of microorganisms in it that can affect the fluid and rock. The article considers the technology of activation of reservoir microflora, namely silicate bacteria, as a method of increasing oil recovery at the sites of the Northern Caspian.

Impact of interfacial tension on oil-water flow in a narrow gap

Numerous researchers have examined the co-current flow of oil-water and aqueous solutions containing polymers and surfactants in thin gaps for oil recovery. While some have focused on charges and forces at the interfaces of oil-surfactant solutions during flow. The study of flow structures, interface behavior, and relative permeabilities of oil and aqueous phases of surfactant flow through thin gaps has been less explored. For the first time, this research aims to comprehensively investigate the flow of oil-water and oil-surfactant solutions through a thin gap (Hele-Shaw cell) with a particular focus on the impact of sodium dodecyl sulfate (SDS). The experiments reveal that SDS forms an emulsion near the oil-water interface, capturing oil droplets and enabling their flow along with the SDS solution. Microscopic studies confirm this, showing that when SDS contacts oil, it creates channels through the oil phase, leading to the accumulation and division of oil into small round-shaped droplets, resulting in an oil-in-water emulsion. The addition of SDS to the injecting water significantly enhances relative permeabilities, leading to a remarkable 90% increase in oil recovery from the cell. The research suggests that the optimal SDS concentration range for maximum oil recovery is between 1.5 and 2 wt%, as it achieves the minimum interfacial tension between oil and water.

Formation and characterization of nanoparticle assisted surfactant stabilized oil-in-water nanoemulsions for application in enhanced oil recovery

Nanoemulsions (NEs) are emerging as attractive injecting fluids for enhanced oil recovery because of their abilities to reduce interfacial tension, alter the rock wettability, improve the mobility ratio, become miscible with trapped crude oil, plug the pores, etc. The present study deals with the formulation, characterization, and performance of alumina (Al2O3) nanoparticle-aided AOS (alpha-olefin sulfonate) surfactant stabilized oil in water NEs in improving oil recovery. Dynamic light scattering (DLS) confirms the dispersion of nanoscale oil droplets with an average size of 192 nm and 172 nm for NEs stabilized by AOS surfactant and Al2O3 nanoparticle-aided surfactant, respectively. The corresponding Zeta potential (ζ) values are −60.2 mV and −63.4 mV, which indicate the higher kinetic stability of the NEs. The phase behaviour study shows a stable middle-phase emulsion with 0.75 wt% surfactant at optimum salinity of 0.5 wt% NaCl and the IFT values in the 10−5 mN/m range as measured by Chun Huh equation. On the other hand, the IFT between decane and nanoemulsion measured at 343 K by pendant drop is observed to be 26.42 mN/m, which is further reduced to 13.89 mN/m by inducing nanoparticles into the nanoemulsion. The NEs have significant potential to alter the wettability of sandstone rock from oil-wet to water-wet. It has been observed that the formulated NEs have good miscibility with crude oil, and the viscosity of crude oil is reduced significantly, which implies an improvement in displacement efficiency. Core flooding studies on two cores were performed by injecting both the formulated slugs to test their effectiveness in improving oil recovery. The injection of one pore volume of AOS-stabilized nanoemulsion and Al2O3 assisted AOS stabilized nanoemulsion increased oil recovery by 17.71 % and 23.97 % respectively over conventional water flooding.