Enhanced Oil Recovery Processes Research Articles

An environmental risk assessment framework for enhanced oil recovery solutions from offshore oil and gas industry

Environmental risk assessments are necessary to understand the risk associated with enhanced oil recovery (EOR) solutions and to provide decision support for choosing the best technology and implementing risk-reducing measures. This study presents a review of potentially relevant environmental/ecological risk assessment (ERA) guidelines and, based on this review, proposes an initial suggestion of an ERA framework for understanding the environmental impacts from EOR solutions. We first shortlist the important elements necessary for conducting an ERA of EOR solutions from the selected guidelines. These elements are then used to build the suggested ERA framework for produced water discharges, drilling discharges and emissions to air from EOR solutions, which is the primary objective of the present study. Furthermore, the emphasis is placed on identifying the knowledge gaps that exist for conducting ERA of EOR processes. In order to link the framework with the current best environmental practices, a review of environmental policies applicable to the marine environment around the European Union (EU) was conducted. Finally, some major challenges in the application of ERA methods for novel EOR technologies, i.e. uncertainties in the ERA due to lack of data and aggregation of risk from different environmental impacts, are discussed in detail. The frameworks suggested in this study should be possible to use by relevant stakeholders to assess environmental risk from enhanced oil recovery solutions.

Numerical simulation of the heat losses through the steam injection in enhanced oil recovery process

In this study, a numerical investigation of the effect of using a new insulation of Yttrium oxide with thermal painting of (5 wt.%) on the heat losses from steam injected in the enhanced oil recovery process. ANSYS Fluent v.16 was used in the simulation. Results were obtained for inlet oil velocity of 5 m/s, temperature of 313 K, and inlet steam velocity of 0.1 m/s, temperature of 373 K. The length of tube is 0.5 m. Pressure through the oil decreases along the distance, while through the steam seems to be unchanged. The insulation does not affect on the pressure distribution. Velocity through the oil decreases along the distance and decreases slightly through the steam. Using the insulation lead to reduce the velocity of oil. Steam temperature decreases through before using the insulation and slightly decrease after using the insulation. Using the insulation leads to make the temperature of steam along the distance greater than the temperature before using the insulation. The pressure through the oil decreases along the distance, while through the steam seems to be unchanged. The insulation does not affect on the pressure distribution. The velocity through the oil decreases along the distance and decreases slightly through the steam by 7.14%. Using the insulation lead to reduce the velocity of oil. Using the insulation leads to make the temperature of steam along the distance greater than the temperature before using the insulation by 9.42%.

Improving oil recovery rates in THAI in situ combustion process using pure oxygen

In-situ-combustion-type processes such as the Toe-to-Heel Air Injection (THAI) process have been shown to have advantages over other thermal enhanced oil recovery processes. The THAI process uses in situ combustion to mobilise and upgrade bitumen or heavy oil within the reservoir. This study compares the effect of injecting pure oxygen instead of air on the performance of the THAI process. It is found that over the 833 days of the process time, an additional 3.85% of oil originally in place (OOIP) was recovered with injecting pure oxygen compared to with injecting air. It is found that as the combustion front advances, higher axial length fraction of the HP well is used for oil production. Observing the oil production rate distribution along the HP well, it is concluded that highest oil flow rate enters the HP well at the toe in both models. It has been shown that it is likely that gas production might have negatively affected the oil production when air is the injected fluid (i.e. in the air model).

Micellar solubilization of petroleum fractions by heavy alkylbenzene sulfonate surfactant

The primary mechanism of surfactant enhanced oil recovery (EOR) has always been ascribed to ultralow interfacial tension (IFT) between oil and dispalcing fluid by forming middle-phase microemulsion. However, it is found in field trials that oil can be largely produced by low concentration surfactant flooding without producing microemulsion. Herein, a widely used EOR surfactant, heavy alkylbenzene sulfonate (HABS) was selected to investigate its micellar solubilization behavior for petroleum fractions, alkanes and aromatics, by using UV–Vis spectroscopy, dynamic light scattering, transmission electron microscopy, small-angle neutron scattering (SANS) and fluorescent microscope. Increasing the surfactant concentration resulted in increase of solubilization capacity, and the micellar size increases with the addition of additives, accompanied by an appearance transition from transparent to opaque before and after the maximum solubilization capacity. Alkanes is situated in the micellar core, while aromatics resides in the palisade layer. The evolution from micelle to emulsion has been proved to be a disperse phase mutations once the maximum solubilization capacity is reached. These findings provide support for the contribution of micellar solubilization to surfactant EOR process.

Isolating, identifying and evaluating of oil degradation strains for the air-assisted microbial enhanced oil recovery process.

Due to the inefficient reproduction of microorganisms in oxygen-deprived environments of the reservoir, the applications of microbial enhanced oil recovery (MEOR) are restricted. To overcome this problem, a new type of air-assisted MEOR process was investigated. Three compounding oil degradation strains were screened using biochemical experiments. Their performances in bacterial suspensions with different amounts of dissolved oxygen were evaluated. Water flooding, microbial flooding and air-assisted microbial flooding core flow experiments were carried out. Carbon distribution curve of biodegraded oil with different oxygen concentration was determined by chromatographic analysis. The long-chain alkanes are degraded by microorganisms. A simulation model was established to take into account the change in oxygen concentration in the reservoir. The results showed that the optimal dissolved oxygen concentration for microbial growth was 4.5~5.5mg/L. The main oxygen consumption in the reservoir happened in the stationary and declining phases of the microbial growth systems. In order to reduce the oxygen concentration to a safe level, the minimum radius of oxygen consumption was found to be about 145m. These results demonstrate that the air-assisted MEOR process can overcome the shortcomings of traditional microbial flooding techniques. The findings of this study can help for better understanding of microbial enhanced oil recovery and improving the efficiency of microbial oil displacement.

Double-Chain Single-Head modification of extracted saponin from Anabasis Setifera plant and its effects on chemical enhanced oil recovery process by surfactant-alkali slug injection into carbonate oil reservoirs

Recently, several studies have dealt with the use of plant-derived surfactants in chemical water injection into oil reservoirs as a main method of Enhanced Oil Recovery (EOR). Some of the advantages of using them in comparison with using expensive chemical surfactants are being environmentally friendly, cheap and available. There are plenty of plants that could be employed as sources of natural surfactants owing to the saponin in their tissues. Even though the plants extracts have weaker performances than engineered surfactants in reducing Interfacial Tension (IFT), synthesizing and modifying the structure of the saponin of these plants can increase its surface activity and result in the optimal values of EOR parameters. The current work was conducted to modify the structure of the saponin of Anabasis Setifera plant through esterification as Double-Chain Single-Head. Thermal Gravimetric Analysis (TGA), Proton Nuclear Magnetic Resonance (1H NMR), and Fourier-Transform Infrared Spectroscopy (FTIR) were performed for temperature stability analysis and characterization. Surface tension experiments were performed in order to estimate the Critical Micelle Concentration (CMC) of the modified surfactant. Additionally, to prove the surfactant performance in EOR process, we did IFT and oil drop Contact Angle (CA) tests, evaluation of the salinity effects of Formation Water (FW), and various salts on IFT, CA, and flooding with optimum fluid in a carbonate plug. The results indicate low-IFT creation at CMC, carbonate rock wettability alteration to moderate wettability, and an increase in the oil recovery factor of about 19% in surfactant-alkali slug injection at optimal alkali and salinity conditions.

Fabrication of a highly efficient new nanocomposite polymer gel for controlling the excess water production in petroleum reservoirs and increasing the performance of enhanced oil recovery processes

A new nanocomposite polymer gel is synthesized for reduction of excess water production in petroleum reservoirs at real operating conditions. This new nanocomposite gel contains SiO 2 nanoparticles, partially hydrolyzed polyacrylamide (HPAM) and chromium triacetate. High pressure and high temperature tests using porous carbonate core are carried out to evaluate the effects of nanoparticles on the synthesized polymer gel performance. It is shown that the residual resistance factor ratio of water to oil using the synthesized polymer gel nanocomposite in this work is much higher than that of the ordinary polymer gels. The presented results confirm the high performance of the synthesized nanocomposite polymer gel for decreasing the water flow through porous carbonate bed. A mathematical model for description of oil and water flow behavior in the presence of synthesized nanocomposite polymer gel is also presented. The presented nano polymer gel leads to considerable cost saving in enhanced oil recovery (EOR) processes.

SENSITIVITY ANALYSIS FOR POLYMER INJECTION TO IMPROVE HEAVY OIL RECOVERY – SMALL-SCALE SIMULATION STUDY

Polymer flooding has been widely used for enhancing oil recovery, due to the growing number of successful applications around the world. The process aims to increase water viscosity and, thus, decrease the water/oil mobility ratio, thereby improving sweep efficiency. The understanding of the physical mechanisms involved in this enhanced oil recovery process allows us to forecast the application potential of polymer flooding. This work aims to assess physical phenomena associated with heavy oil recovery through polymer flooding using 1D small-scale simulation models. We evaluate the influence of different levels of adsorption, accessible pore volume, residual resistance factor, and polymer concentration on the results and compare their magnitude effect on the results. The models used in this study were built using data from previous lab work and literature. For each one of the mentioned parameters, this work compares the histories of water cut, cumulative water-oil ratio, average pressure, and oil recovery factor. Additionally, water saturation, water viscosity, and water mobility profile were determined for specific periods of the flooding process. The sensitivity analyses showed that high levels of adsorption influence the polymer loss of the advance front, delaying oil recovery. Low values of accessible pore volume lead to a slightly faster polymer breakthrough and oil recovery anticipation. A high residual resistance factor increases the average pressure and improves oil recovery. Higher polymer concentration enhances the displacement efficiency and enhances the recovery factor.

Activation of Carbonated Brine with Surfactants and Sulfate Anion for Using the Enhanced Oil Recovery Process

Activation of Carbonated Brine with Surfactants and Sulfate Anion for Using the Enhanced Oil Recovery Process

Experimental Evaluation of the Mobility Profile of Enhanced Oil Recovery Gases

The mobility profiles of gases used in enhanced oil recovery (EOR) have been thoroughly investigated through the coupling operations of data mining of oilfield data and experimental data analyses. Mobility as an EOR objective function has not been previously applied to characterize potential reservoirs for EOR selection and application, even though it is a robust combinatorial function that benefits from two petrophysical variables, permeability and viscosity. The data mining approach identified mobility as a reliable objective function for reservoir characterisation. The data distribution and clustering results indicate that Gas EOR reservoirs have relatively higher mean mobility than Thermal, Microbial and Chemical EOR reservoirs. The experimental approach investigated EOR gases, CO2, CH4, N2, and Air. A modified Darcy Equation of State for gas flow through porous media was applied to evaluate which gas would competitively attain the oil displacement optimisation criterion for mobility ratio, M ≤ 1. Coupling the data mining with the experimental data results reveals that gas reservoirs can be further categorized by mobility. CH4 (18.16 mD/cp) was observed to have the highest mobility followed by Air (14.60 mD/cp), N2 (13.61 mD/cp), and CO2 (12.96 mD/cp). The gas mobility order significantly corresponds with the mobility distribution of reservoirs that implemented gas EOR processes. It was concluded that CO2 offers relatively lower mobility, therefore, it is the most competitive EOR gas to approach the mobility ratio criterion of unity or less.

Modification Wettability and Interfacial Tension of Heavy Crude Oil by Green Bio-surfactant Based on Bacillus licheniformis and Rhodococcus erythropolis Strains under Reservoir Conditions: Microbial Enhanced Oil Recovery

Oil spill contamination in soil is still problematic. At the same time, petroleum-contaminated soil in oil reservoirs contain various microbes, which have the ability for biosurfactant production. Extracting these biosurfactants is a very promising and cost-effective strategy for the microbial enhanced oil recovery process. Biosurfactants production using Bacillus licheniformis AnBa7 and Rhodococcus erythropolis sp., isolated from Egyptian crude oils, was enhanced using various carbon sources. The best biosurfactant characteristics were observed when 1% of crude oil was used as a carbon source. The production was further improved by using a developed fed-batch cultivation strategy depends on using 1% Glucose as a single addition at the beginning of the culture. Then 1% of crude oil was added three times during the production process. This strategy enhanced surfactin and trehalose productivity by 1.8 and 4.7 fold higher than the normal conditions, respectively. The surface-active and thermodynamic properties were studied. The results indicated that the calculated values of ΔGmic for surfactin complex, and trehalose complex were −18.47 and −18.28 kJ/mol at 60 °C, respectively while ΔGads values were −30.42 and −29.46 kJ/mol at 60 °C. The interfacial tension (IFT) values of surfactin complex and trehalose complex systems were ranging from 0.75 to 0.19 mN m–1 and from 0.93 to 0.26 mN m–1 at 60 °C, respectively. However, the (IFT) for the blank solution was ∼11.57 mN m–1, and the wettability was changed to an excellent water-wet state (θ = ∼ 17.42–24.0°). The core-flooding studies showed that the enhanced oil recovery for surfactin complex and trehalos complex, at maximum concentration 6 g/L, were 59.21% and 51.83%, respectively. A predicted mechanism was illustrating through the text.

Effect of different low salinity flooding schemes and the addition of alkali on the performance of low-salinity waterflooding during the recovery of heavy oil from unconsolidated sandstone

Low salinity waterflooding (LSW) is a promising enhanced oil recovery process. The LSW advantage has been associated to changes in rock wettability toward a more water wet state. This study evaluated the effect of different flooding schemes on the performance of LSW in terms of production rate and incremental oil recovery from sand-pack systems. This work also investigated the main mechanism prompting sand wettability changes during LSW.Flooding Scheme-1 consisted of high salinity waterflooding, low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-2 consisted of low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-3 consisted of alkali aided low salinity flooding and low salinity waterflooding. The main mechanism causing wettability reversal was verified employing contact angle analysis, inductively coupled plasma spectrometry, and scanning electron microscopy.This new study reveals in a straightforward manner the effect of low salinity waterflooding schemes on both production rate and incremental oil recovery. LSW in secondary mode, as conducted in FS-2, expedited the oil production rate by 15% and increased the overall oil recovery by 20% relative to flooding schemes FS-1 and FS-3. Furthermore, this study determined that multi-component ionic exchange was the dominant mechanism for the reversal of sand wettability to a more water wet state.This paper provides new insights for heavy oil producers on the relevance of the flooding schemes during LSW and on the dominant mechanism for wettability alteration during the recovery of heavy oil from unconsolidated sands.

Experimental evaluation of the mechanical degradation of HPAM polymeric solutions used in Enhanced Oil Recovery

With the design of experiments (DoE), this study analyses the influence of physical (capillary diameter and pressure drop) and chemical variables (salinity, polymer concentration, and molecular weight) on the mechanical degradation of partially hydrolyzed polyacrylamide-type polymer solutions (HPAM) used in enhanced oil recovery processes. Initially, with the help of a fractional factorial design (2k-p), the variables with the most significant influence on the polymer's mechanical degradation were found. The experimental results of the screening demonstrate that the factors that statistically influence the mechanical degradation are the molecular weight, the diameter of the capillary, and the pressure differential. Subsequently, a regression model was developed to estimate the degradation percentages of HPAM polymer solutions as a function of the significant factors influencing the mechanical degradation of polymer solutions. This model had a 97.85% fit for the predicted values under the experimental conditions. Likewise, through the optimization developed by the Box Behnken response surface methodology, it was determined that the pressure differential was the most influential factor. This variable was followed by the capillary diameter, where less than 50% degradation rates are obtained with low polymer molecular weight (6.5 MDa), pressure differentials less than 500 psi, and diameters of the capillary greater than 0.125 inches.

Effect of ionic strength in low salinity water injection processes

Low salinity water injection has been frequently studied as an enhanced oil recovery process (EOR), mainly due to promising experimental results and because operational needs are not very different from those of the conventional water injection. However, there is no agreement on the mechanisms involved in increasing the displacement of crude oil, except for the effects of wettability changes. Water injection is the oil recovery method mostly used, and considering the characteristics of Colombian oil fields, this study analyses the effect of modifying the ionic composition of the waters involved in the process, starting from the concept of ionic strength (IS) in sandstone type rocks.
 The experimental plan for this research includes the evaluation of spontaneous imbibition (SI), contact angles, and displacement efficiencies in Berea core plugs. Interfacial tension and pH measurements were also carried out. The initial scenario consists in formation water (FW), with a total concentration of 9,800 ppm (TDS) (IS ~ 0.17) and a 27 °API crude oil. Magnesium and Calcium brine were also used in a first approach to assess the effect of the divalent ions.
 Displacement efficiency tests are performed using IS of 0.17, 0.08, and 0.05, as secondary and tertiary oil recovery and the recovery of oil increases in both scenarios. Spontaneous imbibition curves and contact angle measurements show variations as a function of the ionic strength, validating the displacement efficiencies.
 Interfacial tension and pH collected data evidence that fluid/fluid interactions occur due to ionic strength modifications. However, as per the conditions of this research, fluid/fluid mechanisms are not as determining as fluid/rock.

Polymeric surfactants as alternative to improve waterflooding oil recovery efficiency

Chemical formulations, including surfactants, polymers, alkalis, or their combinations, are widely used in different oil recovery processes to improve water injection performance. However, based on challenging profit margins in most mature waterfloods in Colombia and overseas, it is necessary to explore alternatives that could offer better performance and greater operational flexibility than the conventional technologies used for enhanced oil recovery (EOR) processes.
 Polymeric surfactants are compounds widely used in the manufacture of domestic and industrial cleaning, pharmaceutical, cosmetic, and food products. These compounds represent an interesting alternative as they can simultaneously increase the viscosity in water solution and reduce the interfacial tension (IFT) in the water/oil system, which would increase the efficiency of EOR processes.
 This article shows a methodological evaluation through laboratory studies, numerical reservoir simulation, and conceptual engineering design to apply polymeric surfactants (Block Copolymer Polymeric Surfactants or BCPS) as additives to improve efficiency in water injection processes. Block copolymer type products of ethylene oxide (EO) - propylene oxide (PO) - ethylene oxide (EO) in aqueous solution were studied to determine their rheological and surfactant behavior under the operating conditions of a Colombian field.
 In the conditions studied, these products allow to reduce the interfacial tension up to 2x10-1 mN/m values and also cause a shear-thinning rheological behavior following the power law at very low shear rates (0.1 s-1– 1 s-1), which corresponds to an increase up to four orders of magnitude in the capillary number (Nc). The IFT and the viscosity reached are maintained in wide ranges of salinity, BCPS concentration, and shear rates, making it a robust performance formulation.
 In a model porous medium, BCPS tested have moderate adsorption, less than conventional surfactants but higher than HPAM polymers, in any way allowing a favorable wettability condition. Additionally, it was observed that they offer a resistance factor up to 16 times, causing greater displacement efficiency than water injection, allowing better sweeping in low permeability areas without injectivity restrictions.
 Numerical simulation shows that it is possible to reach incremental production up to 238,5 TBO by injecting a continuous slug of 0.15 pore volumes of BCPS and HPAM, each with 2,000 ppm concentration and a flow rate of 2,500 BPD. As BCPS are simple handling and dilution products, these could be injected directly in water injection flow using a high precision dosing pump with high pressure and flow rate operational variables.

Surfactant-Polymer Interactions in a Combined Enhanced Oil Recovery Flooding

The traditional Enhanced Oil Recovery (EOR) processes allow improving the performance of mature oilfields after waterflooding projects. Chemical EOR processes modify different physical properties of the fluids and/or the rock in order to mobilize the oil that remains trapped. Furthermore, combined processes have been proposed to improve the performance, using the properties and synergy of the chemical agents. This paper presents a novel simulator developed for a combined surfactant/polymer flooding in EOR processes. It studies the flow of a two-phase, five-component system (aqueous and organic phases with water, petroleum, surfactant, polymer and salt) in porous media. Polymer and surfactant together affect each other’s interfacial and rheological properties as well as the adsorption rates. This is known in the industry as Surfactant-Polymer Interaction (SPI). The simulations showed that optimum results occur when both chemical agents are injected overlapped, with the polymer in the first place. This procedure decreases the surfactant’s adsorption rates, rendering higher recovery factors. The presence of the salt as fifth component slightly modifies the adsorption rates of both polymer and surfactant, but its influence on the phase behavior allows increasing the surfactant’s sweep efficiency.

Preparation and characterization of temperature sensitive iron oxide nanoparticle and its application on enhanced oil recovery

To increase oil production, temperature sensitive iron oxide nanoparticles (TSIO) were prepared and used in enhanced oil recovery process. Iron oxide (IO) was synthesized by hydrothermal method, and then modified in situ with poly (N-isopropylacrylamide) (PNIPAM) and styrene sulfonate groups. The morphology and the structure of the TSIO nanoparticles were characterized by FTIR and TEM. The contact angle and the interfacial tension were carried out. The results showed that TSIO not only changed the wettability of the rocks, but also reduced the interfacial tension of the oil and water, which was conducive to improving the efficiency of oil recovery. When the temperature was higher than the critical temperature, the size of the nanoparticles gradually decreased, which greatly reduced the wettability of the rocks and the interfacial tension of the oil and water. Interestingly, TSIO was not only stably dispersed in water, but was also present in salt water. Microscopic displacement experiments had confirmed that the effect of TSIO-based nanofluid on oil recovery at room temperature increased from 65.78% to 74.15%. When the temperature raised to 50 °C, the recovery rate raised to 84.02%. The results indicated that TSIO-based nanofluids had the potential to enhance oil recovery.

A semi-analytical method for optimizing the gas and water bidirectional displacement in the tilted fault block reservoir

In tilted fault block reservoirs with edge water, the remaining oil is usually formed and located at the structurally highest. The gas and water bidirectional displacement process is an effective method to recover this type of remaining oil in these reservoirs. However, there is no optimizing method to design the injection-production schedule of this process for the maximum oil recovery. In this study, the imaging and superposition principle, Pollock method, equivalence principle, and Buckley-Leverett method were combined to develop a novel semi-analytical method for optimizing the injection-production schedule. An example study was carried out for verifying the proposed semi-analytical method and validated with the numerical simulation method. Furthermore, sensitive factors of this displacement process were quantitatively analyzed by the proposed method. The results showed that the optimized synergy of the gas and water can maximize the oil recovery for the bidirectional displacement process. Compared with no injection, inadequate injection, and excess injection of gas, the breakthrough recovery can be increased by 3.7%, 0.8%, and 4.88%, respectively, by controlling the gas-water synergy. Meanwhile, under the gas-water synergy displacement condition, the oil recovery is increasing with the tilt angle of the reservoir increasing and the distance of well from edge water decreasing. This enhanced oil recovery process is more sensitive to low-middle tilt angles and more effective for small distances. The results obtained from this study can be used to improve the exploitation strategies of tilted fault block reservoir with edge water.

An introductory investigation of a polymeric surfactant from a new natural source in chemical enhanced oil recovery (CEOR)

Greater than 50% of the original oil in place turns into immobile or trapped oil because of unfavored mobility and capillary forces problems. More efficient methods should be introduced in the tertiary oil recovery section as a scheme of Enhanced Oil Recovery (EOR). Surface-active-agents presented as surfactants play an important role in chemical EOR by their ability to optimize the operative parameters of interfacial/surface tension, wettability state, and modify the mobility of fluids in EOR processes. Beside all these optimizations induced to the fluid and rock of the reservoir, surfactants like other materials experience molecule losses by adsorption of solid/liquid interface. Great loss of surfactant molecules causes expensive materials cost and ineffectiveness of the benefits of these surface-active agents. Also, as literature reported, natural surfactants possess lower production costs, lower adsorption capacity, and environmentally friendly. This study introduces a new natural polymeric surfactant governed from the Acanthephyllum plant. Aqueous extraction process conducted and the extract was characterized by Fourier Transform Infrared spectroscopy (FTIR), Thermo-Gravimetric Analysis (TGA), and Proton Nuclear Magnetic Resonance spectroscopy (H-NMR). Characterization tests confirmed the polymeric state of the extract and the existence of surface-active functional groups in the extract. Interfacial tension (IFT) and surface tension (ST) between water-oil and water-air was measured respectively and showed a 92.6 and 61.6 percent optimization in their initial values in turn. Wettability alteration evaluated on a carbonate rock/crude oil/natural surfactant solution system and changed the oil wetness state of the initial oil-wet carbonate rock to a water wetness state because the wettability alteration measurements showed a reduction of the contact angle from 146° to 64° for only 80 min as the equilibrium time. Adsorption experiments conducted as adsorption isotherms and kinetic models. Freundlich isotherm fitted as the best model, and comparison of kinetic adsorption models for Acanthephyllum plant root extract as polymeric surfactant uptake shows that the pseudo-second-order model has the best accuracy and the pseudo-first-order model has the lowest accuracy.

Continuous monitoring of crude oil movement in an electromagnetic-assisted enhanced oil recovery process using a modified fiber Bragg grating sensor

The Fiber Bragg grating (FBG) sensor used for distinguishing the oil movement offers detailed insights about the reservoir oil and is the key to quantifying the impact on improvement and the integrity and efficiency of the wells. The modified FBG sensors proposed in this paper through a partially un-cladding process and magnetostrictive nanolayer coating could advantageously monitor the crude oil mobility in electromagnetic-assisted enhanced oil recovery operations. The remaining ∼400 nm thickness of cladding after partial removal was coated with ∼100 nm magnetostrictive Ni-Fe nanolayer. The structures of Ga-doped magnetite and Ga-doped hematite were found orthorhombic with Pnma space group and rhombohedral with R3C space group, with the corresponding remnant magnetization (retentivity) value of 94 Oe and 150 Oe, respectively. The magnetization values at 1.5 T were 30 for Ga-doped magnetite and 21 emu/g for Ga-doped hematite nanoparticles. The interfacial tension of crude oil and brine dropped for 16.9 % and 4.1 % when the Ga-doped magnetite and the Ga-doped hematite nanofluid were injected, respectively. The correlated contact angle for the Ga-doped magnetite was 65.2˚, while for the Ga-doped hematite, it was 57.4˚. The FBG’s responses to different nanofluids and surfactant injection at the presence of electromagnetic field indicated the high sensitivity of the probe against the induced magnetic field, which was varied as a function of distance, nanofluids type, and nanoparticles accumulation near the FBG sensing point. The increase in the wavelength shift of FBG by flowing the nanofluids through the sandstone and opposite behavior was recorded by surfactant flowing. The maximum wavelength shift was 0.21 nm when Ga-doped magnetite nanofluid was injected, whereas it was 0.14 when Ga-doped hematite was injected.