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Enhanced Oil Recovery by Hydrophilic Silica Nanofluid: Experimental Evaluation of the Impact of Parameters and Mechanisms on Recovery Potential
Abstract and Figures
Nanofluids as an EOR technique are reported to enhance oil recoveries. Among all the nanomaterial silica with promising lab results, economic and environmental acceptability are an ideal material for future applications. Despite the potential to enhance recoveries, understanding the two-fold impact of parameters such as concentration, salinity, stability, injection rate, and irreproducibility of results has arisen ambiguities that have delayed field applications. This integrated study is conducted to ascertain two-fold impacts of concentration and salinity on recovery and stability and evaluates corresponding changes in the recovery mechanism with variance in the parameters. Initially, silica nanofluids’ recovery potential was evaluated by tertiary flooding at different concentrations (0.02, 0.05, 0.07, 0.1) wt. % at 20,000 ppm salinity. The optimum concentration of 0.05 wt. % with the highest potential in terms of recovery, wettability change, and IFT reduction was selected. Then nano-flooding was carried out at higher salinities at a nanomaterial concentration of 0.05 wt. %. For the mechanism’s evaluation, the contact angle, IFT and porosity reduction, along with differential profile changes were analyzed. The recovery potential was found at its highest for 0.05 wt. %, which reduced when concentrations were further increased as the recovery mechanisms changed and compromised stability. Whereas salinity also had a two-fold impact with salinity at 30,000 ppm resulting in lower recovery, higher salinity destabilized the solution but enhanced recoveries by enhancing macroscopic mechanisms of pore throat plugging.
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... Al Mishaal [12] and Tajik [13], respectively, improved the recovery rate of heavy crude oil by synthesizing molybdenum-based catalysts and evaluating the role of ligand structures in the catalysts. Chandio [14] evaluated the effect of nanofluids on enhancing oil recovery under experimental conditions, demonstrating the potential of nanotechnology in improving the recovery efficiency of tight oil reservoirs. Bello [15] focused on how CO 2 foam technology enhances reservoir recovery by improving fluid mobility within the reservoir and reducing CO 2 channeling. ...
Surfactant huff-n-puff (HnP) has been shown to be an effective protocol to improve oil recovery in tight and ultratight reservoirs. The success of surfactant HnP for enhanced oil recovery (EOR) process depends on the efficiency of the designed chemical formula, as the formation of an in situ microemulsion by surfactant injection is considered to be the most desirable condition for achieving an ultra-low interfacial tension during the HnP process. In this work, we conducted experimental studies on the mechanism of in situ microemulsion EOR in the Mahu tight oil reservoir. Salinity scan experiments were carried out to compare different surfactants with crude oil from the Mahu reservoir, starting with the assessment of surfactant micellar solutions for their ability to form microemulsions with Mahu crude oil and examining the interfacial characteristics. Subsequently, detailed micromodels representing millimeter-scale fractures, micron-scale pores, and nano-scale channels were utilized to study the imbibition and flowback of various surfactant micellar solutions. Observations of the in situ microemulsion system revealed the mechanisms behind the enhanced oil recovery, which was the emulsification’s near-miscibility effect leading to microemulsion formation and its performance under low-interfacial-tension conditions. During the injection process, notable improvements in the micro-scale pore throat heterogeneity were observed, which improved the pore fluid mobility. The flowback phase improved the channeling between the different media, promoting a uniform movement of the oil–water interface and aiding in the recovery of a significant amount of the oil phase permeability.
... The recovery potential and stability of SNF was studied in a recent study at various nanoparticle concentrations (0.1, 0.07, 0.05, 0.02wt%) and salinities of 20 thousand, 30 thousand, and 40 thousand ppm [26]. The test was split into two parts: the optimum concentration of NP had been determined at 20 thousand ppm, and the salinity effect on the recovery mechanisms was investigated. ...
Many enhanced oil recovery techniques have been adopted in oil production to recover as much oil as possible. However, enhanced oil recovery techniques are complex and costly. Therefore, nanofluids have been modified in the laboratory to be consistent with reservoir fluids and rocks while also being environmentally benign. This study aims to investigate the role of silica nanofluid in plugging the high permeable zones after oil is recovered from the reservoir to divert pressure to the low permeable zone for enhanced oil production from the low permeable zones. A digital gas permeameter (DGP-300-B) was used to determine the permeability of the core by injecting nitrogen gas. In addition, a DHP-100-M Digital Helium Porosimeter was used to determine bulk volume, grain volume, and grain density porosity. The experiment was conducted with different percentages of silicon dioxide nanoparticles to observe the effect of plugging in each stage. Results show that a 52% reduction in core permeability was observed when using 0.5wt.% of silica nanoparticles, a 72% reduction in core permeability when using 1wt.% of silica nanoparticles and a 94% reduction in core permeability when using 2wt.% of silica nanoparticles.
... However, in polymer flooding for EOR applications, cellulose ethers improve sweep efficiency and mobility, ultimately enhancing oil recovery. 12 In all these operations, the fluids are displaced from the surface to the wellbore and reservoir, requiring a high shear rate for displacement. 13 Furthermore, these fluids encounter formation fluid and an elevated thermal reservoir temperature. ...
The applications of cellulose ethers in the petroleum industry represent various limitations in maintaining their rheological properties with an increase in both concentration and temperature. This paper proposed a new method to improve the rheological properties of hydroxyethyl methyl cellulose (HEMC) by incorporating diethyl carbonate (DEC) as a transesterification agent and alkali base solutions. Fourier transform infrared (FTIR) analysis confirmed the grafting of both composites onto the HEMC surface. The addition of sodium hydroxide (NaOH) improved the stability of the polymeric solution as observed from ζ-potential measurement. Shear viscosity and frequency sweep experiments were conducted at concentrations of 0.25–1 wt % at ambient and elevated temperatures ranging from 80–110 °C using a rheometer. In the results, the increase in viscosity at specific times and temperatures indicated the activation of DEC through the saponification reactions with alkali solutions. All polymeric solutions exhibited shear-thinning behavior and were fitted well by the Cross model. NaOH-based modified solution exhibited low shear viscosity compared to the DEC-HEMC solution at ambient temperature. However, at 110 °C, its viscosity exceeded that of the DEC-HEMC solution due to the activation of DEC. In frequency sweep analysis, the loss modulus (G″) was greater than the storage modulus (G′) at lower frequencies and vice versa at higher frequencies. This signifies the viscoelastic behavior of modified solutions at 0.50 wt % and higher concentrations. The flow point (G′ = G″) shifted to a low frequency, indicating the increasing dominance of elastic behavior with the rising temperature. At 110 °C, the NaOH-based modified solution exhibited both viscous and elastic behavior, confirming the solution’s thermal stability and flowability. In conclusion, modified HEMC solution was found to be effective in controlling viscosity under ambient conditions, enhancing solubility, and improving thermal stability. This modified composite could play a significant role in optimizing viscoelastic properties and fluid performance under challenging wellbore conditions.
... They determined the minimum reaction time required for a sample to transition from hydrophobic to hydrophilic. Chandio et al. [7] used hydrophilic silica nanofluids to determine the effects of nanofluid salinity and particle concentration on oil recovery and stability. They found that wettability alteration and reduced interfacial tension maximized oil recovery at a salinity level of 20,000 ppm and a nanoparticle concentration of 0.05 wt.%. ...
This study analyzes the impact of injection condition design factors of (3-glycidoxypropyl)trimethoxysilane (GPTMS)–SiO2 nanofluid on improving wettability and oil recovery through flotation and core flooding tests, respectively. Flotation tests were conducted to assess improvements in wettability that resulted from varying nanoparticle concentration, reaction time, and treatment temperature. The test results demonstrated that the hydrophilic sample ratio increased by up to 97.75% based on the nanoparticle reaction, confirming significant wettability improvement in all samples. Additionally, time-dependent fluid-flow experiments were conducted to validate oil recovery and rock–fluid interactions. In these experiments, for a 24-h reaction time, nanofluid injection caused a decrease in the maximum contact angle (43.4° from 166.5°) and a remarkable enhancement in the oil recovery rate by over 25%. Moreover, variations in contact angle and sample permeability were observed as the reaction time increased. Subsequently, the core flooding test revealed a critical reaction time of 24 h, maximizing oil recovery while minimizing permeability. Below this point in time, wettability improvement did not significantly enhance oil recovery. Conversely, beyond this threshold, additional adsorption due to particle aggregation decreased permeability, causing reduced oil recovery. Therefore, GPTMS–SiO2 nanofluid can be utilized as an injection fluid to enhance oil recovery in high-temperature and high-salinity carbonate reservoirs.
... The findings demonstrate that various wettability characteristics enhance oil recovery only by interfacial tension reduction, and the impact of wettability alterations can differ because of various states of preliminary wettability. Chandio et al. (2021) conducted an empirical assessment of the effects of concentration, salinity, and the mechanisms of enhanced oil recovery using hydrophilic silica nanofluid. The results indicated the optimal concentration of 0.05%wt in elevated salinities with the greatest potential for recovery, wettability alteration, and interfacial tension reduction. ...
The use of nanofluids is showing promise as an enhanced oil recovery (EOR) method. Several reviews have been published focusing on the main mechanisms involved in the process. This new study, unlike previous works, aims to collect information about the most promising nano-EOR methods according to their performance in core-flooding tests. As its main contribution, it presents useful information for researchers interested in experimental application of nano-EOR methods. Additional recoveries (after brine flooding) up to 15% of the original oil in place, or higher when combined with smart water or magnetic fields, have been found with formulations consisting of simple nanoparticles in water or brine. The functionalization of nanoparticles and their combination with surfactants and/or polymers take advantage of the synergy of different EOR methods and can lead to higher additional recoveries. The cost, difficulty of preparation, and stability of the formulations have to be considered in practical applications. Additional oil recoveries shown in the reviewed papers encourage the application of the method at larger scales, but experimental limitations could be offering misleading results. More rigorous and systematic works are required to draw reliable conclusions regarding the best type and size of nanoparticles according to the application (type of rock, permeability, formation brine, reservoir conditions, other chemicals in the formulation, etc.)
In this study, novel pre-crosslinked gel particles were synthesized to form a new heterogeneous composite system with a weak alkaline-surfactant-polymer (ASP) system. The microscopic visualization model is used for oil flooding and macroscopic core flooding experiments and advanced testing methods to describe the microscopic morphology of the pre-cross-linked gel particles and their retention state in the porous medium, revealing the microscopic plugging mechanism of the novel heterogeneous composite system in the porous medium. Scanning electron microscope images showed a uniform force on the pre-crosslinked gel particle network structure during the stressing process, with no mechanical weak points and improved tensile properties. The maximum pressure induced by the pre-cross-linked gel particles passing through the 0.5 mm diameter pore plate was 4.8 times higher than that of the conventional bulk particles. The elasticity factor of the pre-cross-linked gel particles was eight times higher than that of the conventional body expansion particles. Adding pre-cross-linked gel particles to the composite system improves the interfacial tension stability and effectively reduces the amount of chemicals under the same interfacial tension level. In a three-tube parallel core flooding experiment, the final heterogeneous composite flooding recovery after polymer flooding was 7.3% higher than that of ASP. The heterogeneous composite flooding system improves the recovery of crude oil after polymer flooding by blocking pore flow steering, wetting reversal, co-emulsification, and poly merging oil zone mechanisms. Thus, the implementation of heterogeneous composite flooding after polymer flooding can achieve the synergistic effect of blocking the dominant seepage channel and improving the oil washing efficiency, which can significantly improve the degree of remaining oil utilization. To clarify the microscopic blocking mechanism of the heterogeneous composite system, it is important to guide the development of post-polymer flooding composite flooding technology and research its microscopic flooding mechanism.
Determining additional oil recovery from a silica nano-fluid enhanced oil recovery project is essential prior to its field scale application to prepare economic feasibility of the project. Measurement of oil recovery is conventionally done through expensive and time-consuming laboratory methods. In pursuance of saving measurement’s cost and time, it is fundamental to develop fast and precise method, especially during the initial screening. This study uncovers the potential machine learning models, such as decision tree (DT) and extreme gradient boosting (XGBoost), as tools for predicting the expected oil recovery of silica-based nano-fluid flooding in sandstone reservoir. The application of mentioned tools for predicting the expected oil recovery has not been reported in the open literature. The models were developed using the results of 108 experiments. The model outputs were analyzed by performance matrices, such as root mean square error (RMSE), mean absolute error, mean square error, and co-efficient of determination (R2). The input features were size of nano-particles, concentration of nano-particles, oil viscosity, oil density, salinity of water, and porosity and permeability of the rock. The results showed that both DT and XGBoost models are reliable to predict the oil recovery with high R2 and low RMSE values of 0.9690 and 1.5837, and 0.9806 and 1.2608, for DT and XGBoost respectively. Heatmap analysis with Pearson's correlation co-efficient criterion showed that the porosity of rock, permeability of rock, concentration of nano-particles, and oil density have significantly more importance on the additional oil recovery.
The enhanced oil recovery mechanisms in fractured reservoirs are complex and not fully understood. It is technically challenging to quantify the related driving forces and their interaction in the matrix and fractures medium. Gravity and capillary forces play a leading role in the recovery process of fractured reservoirs. This study aims to quantify the performance of EOR methods in fractured reservoirs using dimensionless numbers. A systematic approach consisting of the design of experiments, simulations, and proxy-based optimization was used in this work. The effect of driving forces on oil recovery for water injection and several EOR processes such as gas injection, foam injection, water-alternating gas (WAG) injection, and foam-assisted water-alternating gas (FAWAG) injection was analyzed using dimensionless numbers and a surface response model. The results show that equilibrium between gravitational and viscous forces in fracture and capillary and gravity forces in matrix blocks determines oil recovery performance during EOR in fractured reservoirs. When capillary forces are dominant in gas injection, fluid exchange between fracture and matrix is low; consequently, the oil recovery is low. In foam-assisted water-alternating gas injection, gravity and capillary forces are in equilibrium conditions as several mechanisms are involved. The capillary forces dominate the water cycle, while gravitational forces govern the gas cycle due to the foam enhancement properties, which results in the highest oil recovery factor. Based on the performed sensitivity analysis of matrix–fracture interaction on the performance of the EOR processes, the foam and FAWAG injection methods were found to be more sensitive to permeability contrast, density, and matrix block highs than WAG injection.
In enhanced oil recovery, different chemical methods utilization improves hydrocarbon recovery due to their fascinating abilities to alter some critical parameters in porous media, such as mobility control, the interaction between fluid to fluid, and fluid to rock surface. For decades the use of surfactant and polymer flooding has been used as tertiary recovery methods. In the current research, the inclusion of nanomaterials in enhanced oil recovery injection fluids solely or in the presence of other chemicals have got colossal interest. The emphasis of this review is on the applicability of nanofluids in the chemical enhanced oil recovery. The responsible mechanisms are an increment in the viscosity of injection fluid, decrement in oil viscosity, reduction in interfacial and surface tension, and alteration of wettability in the rock formation. In this review, important parameters are presented, which may affect the desired behavior of nanoparticles, and the drawbacks of nanofluid and polymer flooding and the need for a combination of nanoparticles with the polymer are discussed. Due to the lack of literature in defining the mechanism of nanofluid in a reservoir, this paper covers majorly all the previous work done on the application of nanoparticles in chemical enhanced oil recovery at home conditions. Finally, the problems associated with the nano-enhanced oil recovery are outlined, and the research gap is identified, which must be addressed to implement polymeric nanofluids in chemical enhanced oil recovery.
Recently, polymer-coated nanoparticles are proposed for enhanced oil recovery (EOR) due to their improved properties such as solubility, stability, stabilization of emulsions and low particle retention on the rock surface. This work investigated the potential of various polymer-coated silica nanoparticles (PSiNPs) as additives to the injection seawater for oil recovery. Secondary and tertiary core flooding experiments were carried out with neutral-wet Berea sandstone at ambient conditions. Oil recovery parameters of nanoparticles such as interfacial tension (IFT) reduction, wettability alteration and log-jamming effect were investigated. Crude oil from the North Sea field was used. The concentrated solutions of PSiNPs were diluted to 0.1 wt % in synthetic seawater. Experimental results show that PSiNPs can improve water flood oil recovery efficiency. Secondary recoveries of nanofluid ranged from 60% to 72% of original oil in place (OOIP) compared to 56% OOIP achieved by reference water flood. In tertiary recovery mode, the incremental oil recovery varied from 2.6% to 5.2% OOIP. The IFT between oil and water was reduced in the presence of PSiNPs from 10.6 to 2.5–6.8 mN/m, which had minor effect on EOR. Permeability measurements indicated negligible particle retention within the core, consistent with the low differential pressure observed throughout nanofluid flooding. Amott–Harvey tests indicated wettability alteration from neutral- to water-wet condition. The overall findings suggest that PSiNPs have more potential as secondary EOR agents than tertiary agents, and the main recovery mechanism was found to be wettability alteration.
Fluid/fluid and fluid/rock interfaces have large influence on the microscopic sweep efficiency of an enhanced oil recovery process. Therefore, modification of these interfaces using nanoparticles to suitable conditions might lead to better recovery factors. Particularly, wettability alteration and interfacial tension reduction are the two key mechanisms which should be considered. This study was designed to address the capability of nanoparticles to be used as a chemical agent for enhanced oil recovery by several core flooding experiments. The injected chemical solution was prepared using synthetic brine containing %3 NaCl, silica nanoparticles, and SDS surfactant. Contact angle in rock/oil/solution system and interfacial tension between oil/solution were measured. In addition, SEM pictures and XRD analysis were taken to conduct a more thorough investigation of effect of nanoparticles on sandstone core plugs. Nanoparticles and surfactant mixture were flooded with various concentrations under different scenarios. The results show the incremental oil recovery of nanoparticles floods in sandstone core samples which ranged from 4.85 to 11.7%. Conversely, the enhanced oil recovery of high concentration of nanoparticle floods in cores was small. It is deduced that the mechanisms responsible for incremental oil recovery are mainly interfacial tension reduction and wettability alteration toward water-wet condition. However, the flooding results as well as experimental study of possible retention revealed that nanoparticles can be considered as an effective chemical agent in enhanced oil recovery.
The Mancos Shale core sample investigated in the present research has been extracted from the late Cretceous (upper cretaceous) geologic formation of USA. Shale gas is usually obtained by horizontal drilling which induces fractures to increase the flow ability of hydrocarbons. Therefore, it is important to understand the mechanical properties, heterogeneity and their complexities associated with elastic properties of shale. An experimental study was conducted to examine the morphological characteristics of the Mancos Shale core sample both pre and post treatment with cryogenic liquid nitrogen (LN2) for various immersion times namely 30, 60 and 90 minutes respectively. Atomic Force Microscopy (AFM) technique is used to understand the surface roughness, irregularities in core samples and for more accuracy. Scanning Electron Microscopy (SEM) results were employed to visualise the formation of cracks caused by cryogenic liquid nitrogen. Results from SEM showed an increase in fracture size from 2 to 25 µm with increase in ageing time up-to 90 minutes under the atmosphere of cryogenic LN2. Nano- indentation measurements revealed that the Nano- indentation moduli of the Mancos samples subjected to applied forces of 50 mN and 200 mN underwent a decrease from 24.6 to 16.8 GPa and 15.6 GPa respectively with increase in cryogenic liquid nitrogen treatment to 90 minutes. The permeability of the shale samples after LN2 treatment showed a significant increase whereas, increasing net confining stress (NCS) from 1000 to 7000 psi for all untreated and treated rock samples exhibited a decrease in permeability, which is attributed to increased compaction between the pore spaces. Moreover, the porosity of the Mancos shale rose from 3.78 to 6.92% for pre-treated and treated rock samples.
We discover a novel nanoparticle (NP) - crude oil interaction and propose a mechanism of NP-based enhanced oil recovery. This NP–crude oil interaction and its’ effect on oil recovery are systematically investigated conducting microfluidic experiments in both single-pore scale and “reservoir-on-a-chip” scale. It is confirmed that hydrophilic silica NPs in an aqueous phase could lead to dramatic swelling, de-wetting and disjoining of crude oil. The swelling ratio increased with decreased aqueous phase salinity and with increased concentrations of negative charging of NPs. Natural polar components in crude oil is shown to play a very important role. From a pore-scale perspective, this oil swelling and de-wetting increased the flow resistance in the swept region and re-directed flooding liquid towards the unswept region. From a reservoir perspective, the mobility ratio was reduced because oil swelling and de-wetting modified the relative permeabilities. This improvement in sweep efficiency resulted in approximately 11% incremental oil recovery in a completely homogeneous porous micromodel, with 2000 ppm NPs suspended in seawater.
Renewable and non-renewable energy sources remain the two fronts for meeting global emergent energy demand. Non-renewable energy sources such as crude oil, in meeting energy needs, is a function of new hydrocarbon discoveries and improving the recovery of existing oil fields. However, new crude oil discoveries are made at a decreasing rate; likewise, existing fields are at a declining phase with conventional recovery techniques not being able to produce as much as two-thirds of the oil in place. In complementing existing oil recovery techniques, research into the use of nanotechnology has emerged as a potential alternative for tertiary oil recovery scheme. Despite the promising results, there has not been any reported large-scale field application of nanotechnology in the oil and gas industry except for some small-scale field trials. In this paper, a detailed review of developments on nano-enhanced oil recovery (Nano-EOR) and its attendant challenges are presented. Furthermore, key recommendations were given for future research on Nano-EOR. While the adoption of new technologies has its associated risks, the future prospects of Nano-EOR remains very high.
The present study examines and compares the effect of surface treatments of nano-silica using internal olefins sulphonates (IOS20–24 and IOS19–23), anionic surfactants. The effect of surface modification on colloidal stability, wettability alteration and oil-water interfacial tension reduction were analyzed. Silica nanoparticles were characterized using Field Emission Scanning Electron Microscope (FESEM) and integrated energy-dispersive X-ray spectroscopy (EDX) before and after surface treatment. Using Turbiscan classic, the optimal nanosilica concentration and inspection of the coated particles dispersion stability with the help of light transmission behavior through the nanofluid was carried out. The stability was found to be enhanced as the mean light transmission declined only after surfactant treatment in both IOS coated nano-silicas but IOS19–23 O-342 coated dispersions proved to be more stable among all three. RAME-HART Goniometer was used to perform interfacial tension (IFT) and contact angle measurements. IFT was found to be reduced by 48% after the surfactant treatment in case of IOS19–23 O-342 coated nanosilica. Both surface treatments of nanosilica and increasing silica concentration caused significant reduction and altering wettability towards more water wet. The results revealed that IOS coatings improved the efficiency of NPs dispersion in terms of altered wettability and reduced IFT that mimics their potential for EOR applications.
