Empirical Correlations for Viscosity of Polyacrylamide Solutions with the Effects of Salinity and Hardness

A series of experiments have been conducted to characterize and quantify the effects of shear rate, salinity, and hardness on the viscosity of polymer solutions. A set of correlations were developed to predict the viscosity of polymer solutions. These correlations consider the individual and combined effects of shear rate, salinity, and hardness on the viscosity of polymer solutions. The power-law model for the viscosity behavior has been modified to accommodate the influence caused by these three factors. Nonlinear regression was performed on the experimental data to develop the proposed correlations. The proposed correlations can be integrated into any reservoir simulator for polymer injection and should prove useful for the initial screening for the selection of the polymer for enhanced oil recovery applications in oil reservoirs.      

Stability of Nanoporous Silica Aerogel Dispersion as Wettability Alteration Agent

This work studies the stability of silica aerogel aqueous dispersion for wettability alteration in enhanced oil recovery (EOR) processes. Modified silica aerogel is synthesized with cheap water glass as the precursor, and ambient pressure drying method. Brine composition, brine concentration and temperature of oil reservoirs are the most important parameters for success of wettability alteration processes in EOR. Stability of Silica aerogel aqueous dispersions in NaCl, MgCl₂ and combinations of them are surveyed. Brines at different concentrations, 10000, 20000, 40000 ppm, are used to determine stability conditions. Stability at 30°C and 75°C are surveyed, and the results are reported. DLVO and non-DLVO theories are used for modeling the stability of nanodispersion.     

Effect of Nanofluid Treatment on Water Sensitive Formation to Investigate Water Shock Phenomenon,An Experimental Study

Permeability reduction in porous media as a result of frail and tenuous fine particles migration would decrease the productivity index in the subterranean reservoirs. During reservoir stimulation by injecting fluids into the reservoir, as the salinity condition of the formation brine changes, fine particles initiate the triggering process. In this study, MgO-based nanofluid as a fines fixation agent was stably prepared based on the particle size distribution and characterized through transmission electron microscopy analysis. Afterward, several core flooding tests were performed using Berea sandstone cores to study the effect of nanofluid injection on fines fixation in the water shock phenomenon. Permeability reduction occurred up to 95% of inchoate permeability for no treatment case, which was also confirmed by scanning electron microscopy analysis. Finally, MgO nanofluid with 0.03 wt% concentration and 120 minutes soaking time in the core mitigated the fine particles release and fixed them on the pore walls' surfaces critically reducing the formation damage. The analysis shows that outweighing the attraction potentials compared to repulsions was the main mechanism after nanofluids treatment.     

Investigation on the Adaptability of the Polymer Microspheres for Fluid Flow Diversion in Porous Media

Large amounts of water producing from producers have been a great concern for petroleum engineers. In an attempt to inhibit water production and promote oil productivity, various water control agents and techniques have been devised for enhanced oil recovery purpose for decades with some good successes reported commercially. Mainly field-targeted specifically, however, these chemicals are limited in expansive reservoir applications for failing to tolerate harsh formation conditions of high temperature (HT) and high salinity (HS). Besides, their low injectivity is also another proper impediment. In this presentation, we synthesized a new agent of polymer microspheres using inverse emulsion polymerization technique to divert fluid patterns in deep porous media for reservoirs encountered recovery enhancement problems. These microspheres are made to tolerate HT and HS conditions, and can be pumped into deep pore space with relative ease. With the help of nuclear magnetic resonance (NMR) and nuclear pore membrane filtration techniques, a series of experimental procedures were conducted to test the adaptability of newly produced polymer microspheres to targeted pore structure in enhancing the sweeping efficiency of injection fluids. Both laboratory core tests and NMR data show good characteristics of polymer microspheres in modifying injection profile, demonstrating a good capability to divert fluid flow patterns in deep porous media and enhance oil productivity.     

Effects of CO2 Injection on Phase Behavior of Crude Oil

CO₂ flooding is a win-win technology, sequestrating greenhouse CO₂ while producing a significant amount of crude oil to help defray the cost of CO₂ sequestrating and enhancing oil recovery. However, due to the difference of sedimentary environment and poor properties of formations, physical properties of the crude oil and the effect of CO₂ flooding are not always satisfactory in most oilfields of China. Therefore, in this article, to improve the understanding of the oil recovery mechanisms and feasibility of CO₂ flooding in China, based on the oil and gas of Mao-3 oilfields, phase behavior of the CO₂ and crude oil system was investigated. Parameters like saturated pressure, volume factor, gas oil ratio, and viscosity were measured and their relationships analyzed. Results show that crude oil of Mao-3 reservoir and CO₂ has good mutual dissolution under reservoir conditions, and CO₂ could expand the oil and reduce the oil viscosity greatly. As a result, formation energy could be enhanced and flow characteristics of the oil could be improved by CO₂ flooding.     

Application of response surface methodology for optimization of the stability of asphaltene particles in crude oil by TiO2/SiO2 nanofluids under static and dynamic conditions

In this work, the onset of asphaltene flocculation for an Iranian crude oil by titration of samples with heptane in the presence and absence of the TiO₂/SiO₂ nanofluids was obtained by Near-IR spectroscopy. Nanoparticles and nanocomposites were characterized by BET, FESEM, EDX, XRD, and XRF analysis. Modeling and optimization of inhibition of asphaltene flocculation process by TiO₂/SiO₂ nanofluids were conducted by response surface methodology (RSM). Under optimum conditions (nanocomposite composition = 0.04 wt% (80%TiO₂:20%SiO₂), salinity = 4.01 wt%, and pH = 3.42), the onset point increased. For nanofluids stability analysis, the optimum nanofluid was compared with the two other nanofluids (SiO₂ and TiO₂) by visual observation method. The results indicated that high stability and surface area of the 80%TiO₂ nanocomposites increase asphaltene adsorption on the particles surface that subsequently increases the onset point. In addition, the optimum nanofluid performance on the carbonate rocks was evaluated by contact angle and core flooding experiments. The 80% TiO₂ nanofluid changed the wettability of carbonate rocks from strongly oil-wet to strongly water-wet condition and also decreased the residual oil saturation and enhanced the oil recovery with an increase in the recovery factor of about 15%.     

CO2 Mobility and CO2/Brine Interfacial Tension Reduction by Using a New Surfactant for EOR Applications

The synthesis and use in enhanced oil recovery applications of a novel CO₂-philic surfactant derived from maleic anhydride and 2-butyl-1-octanol is reported. The synthesis involved the esterification of maleic anhydride to produce diester followed by sulfonation of the esterified product. The esterification reaction parameters were optimized for the maximum yield of 98.4%. By employing a silica sulfuric acid catalyst, the reaction kinetics of esterification were also investigated. The activation energy was found to be 45.58 kJ/mol. The sulfonation reaction of the esterified product was performed by using sodium bisulfite, and a yield of 82% of surfactant was achieved. The synthesized surfactant lowered the interfacial tension between CO₂/brine to 3.1 mN/m and effectively reduced the CO₂ mobility. This surfactant has a great potential to be used for CO₂ mobility control for CO₂?EOR applications.      

Polymers for Enhanced Oil Recovery Technology

Recently enhance oil recovery (EOR) technology is getting more attention by many countries since energy crises are getting worse and frightened. One of the reasons for this is due to the shortage of current oil resources and difficulties in finding a new oil field. Indonesia is one of the examples, before 2004 Indonesia is a net oil exporting country but after that Indonesia is a net oil importing country. The oil demand in the country is increasing while the oil production capacity is decreasing. In fact, when a new oil reservoir is drilled, the oil amount obtained from it is about 20-40% of the potential and hence there is still 60-80% oil left in the reservoir. Application of EOR technology gives an additional chance to get out more oil from the reservoir, possibly about another 20%. Polymer is the material that plays an important role in the application of EOR technology, especially surfactant and hydrogel polymers. In the technology, surfactant polymer is injected to the reservoir to reduce an interfacial tension between oil and water and is able to wipe out the trapped oil from the reservoir rock and hence increase the oil production. While an injection of hydrogel polymer to the reservoir is to increase a viscosity of fluid containing water so that the fluid is more difficult to flow than the oil, and as a result, the oil production increases. The most common polymer used for this application is polyacrylamide group.     

Rheological properties of surface-modified nanoparticles-stabilized CO2 foam

This study investigates the rheological properties of surface-modified nanoparticles-stabilized CO₂ foam in porous media for enhanced oil recovery (EOR) applications. Due to the foam pseudo-plastic behavior, the foam apparent viscosity was estimated based on the power law constitutive model. The results show that foam exhibit shear-thinning behavior. The presence of surface-modified silica nanoparticles enhanced the foam bulk apparent viscosity by 15%. Foam apparent viscosity in the capillary porous media was four times higher than that in capillary viscometer, and foam apparent viscosity increased as porous media permeability increases. The high apparent viscosity of the surface-modified nanoparticles-stabilized foam could result in effective fluid diversion and pore blocking processes and enhance their potential applications in heterogeneous reservoir.     

Foam Flooding with Ultra-Low Interfacial Tension to Enhance Heavy Oil Recovery

Severe viscous fingering during water flooding of heavy oil leaves a large amount of oil untouched in the reservoir. Improving sweep efficiency is vital for increasing heavy oil recovery. Previous researches have proved that foam flooding can increase the sweep efficiency and oil recovery. The polymers could make the foam more stable and have better plugging capacity, but the interfacial tension (IFT) of oil and water increase which could decrease the displacement efficiency of the heavy oil. In view of the deficiency of conventional foam flooding, it is necessary to research the ultra-low interfacial tension foam which could improve macro-swept volume and micro-displacement efficiency in heavy oil reservoir. In this paper a novel foam agent is developed by the combination of surfactant and additives to lower the IFT of oil and water. The operating parameters including foam injections modes and gas liquid ratio were investigated by core flooding experiments. Field test performance shows that oil production per day increased from 85.6 to 125.7 t, water cut declined from 92.1 to 83.6% after 3 months injection. This study provides a novel method to improve heavy oil recovery with an ultra-low interfacial tension foam flooding system.     

Inhibition of Scale Formation Using Silica Nanoparticle

Because of the wide use of water injection for enhanced oil recovery in the oil fields in order to displace oil into the production well, many reservoirs experience scale deposition problems. Scale formation can cause the production path to be blocked and also cause significant reduction in productivity. One of the most common methods for preventing or lowering the amount of scale formation is applying the scale inhibitors. In this work, silica nanoparticles are used as a scale inhibitor. Conductivity is used as a property of the fluid to show the amount of ion in the solution, leading us to predict the amount of scale formed in the solution. An optimum amount of silica nanoparticles could reduce the rate of conductivity decreasing the solution and consequently lowering the scale deposition, which is the aim of this challenging subject in the oil industry.     

Effects of Magnetic Nanofluid Fuel Combustion on the Performance and Emission Characteristics

Although the compression ignition engines are a significant source of power, their detrimental emissions create considerable problems to the environment as well as to humans. The objective of the present experimental investigation is to examine the effects of the magnetic nanofluid fuels on combustion performance characteristics and exhaust emissions. In this regard, the Fe₃O₄ nanoparticles dispersed in the diesel fuel with the nanoparticle concentrations of 0.4 and 0.8 vol% were employed for combustion in a single-cylinder, direct-injection diesel engine. After a series of experiments, it was demonstrated that the nanoparticle additives, even at very low concentrations, have considerable influence in diesel engine characteristics. Furthermore, the results indicated that the nanofluid fuel with nanoparticle concentration of 0.4 vol% shows better combustion characteristics in comparison with that of 0.8 vol%. Based on the experimental results, NO _x and SO₂ emissions dramatically reduce, while CO emissions and smoke opacity noticeably increase with increasing the dosing level of nanoparticles.     

Wettability alteration of carbonate rocks from strongly liquid-wetting to strongly gas-wetting by fluorine-doped silica coated by fluorosilane

Wettability alteration is an important mechanism to increase recovery from oil and gas reservoirs. In this study, effect of fluorine-doped silica coated by fluorosilane nanofluid on wettability alteration of carbonate rock was investigated. The nanoparticle synthesized by sol-gel method was characterized using XRD, FTIR, SEM, and DLS. Adsorption of nanoparticle on rock was characterized by FESEM, and composition of rock after treatment was determined by EDXA. Effect of nanofluid on wettability was investigated by measuring static, advancing, and receding contact angle and surface free energy, imbibition of water, crude oil, and condensate of untreated and treated carbonate rock. Also, stability of contact angle and thermal stability of nanofluid were studied. ?Results show that contact angles for water, condensate, and crude oil were altered from 37.95°, 0°, ?and 0° to 146.47°, 145.59°, and 138.24°. In addition, water, condensate, and oil imbibition ?decreased more than 87, 88, and 80%, indicating that wettability was altered from strongly oil wet, ?condensate wet, and water wet to strongly gas wet. The ultraoleophobic and ultrahydrophobic stability were >48 hours and 120 minutes. Surface free energy of treated rock for water, crude oil, and condensate was ?2.24, 1.17, and 1.47mN/m. Thermal stability of nanofluids and adsorbed nanoparticle was up to 150°C.     

Prediction of Surfactant Retention in Porous Media: A Robust Modeling Approach

Demands for hydrocarbon production have been increasing in recent decades. As a tertiary production processes, chemical flooding is one of the effective technologies to increase oil recovery of hydrocarbon reservoirs. Retention of surfactants is one of the key parameters affecting the performance and economy of a chemical flooding process. The main parameters contribute to surfactant retention are mineralogy of rock, surfactant structure, pH, salinity, acidity of the oil, microemulsion viscosity, co-solvent concentration, and mobility. Despite various theoretical studies carried out so far, a comprehensive and reliable predictive model for surfactant retention is still found lacking. In this communication, a mathematical method based on machine learning approach, namely, least square support vector machine modeling is evolved for this purpose. To this end, the model was developed and tested using experimental dynamic surfactant retention data over a wide range of conditions. The results show that the developed model provides predictions in good agreement with experimental retention data. Moreover, it is shown that the developed model is capable of simulating the actual physical trend of surfactant retention versus three most important input parameters: total acid number of oil, pH, and mobility ratio. Finally, for detection of the probable doubtful retention data, outlier diagnosis was performed on the whole data set.     

Viscosity modification of lubricating oil based on high-concentration silica nanoparticle colloidal system

In this study, colloidal systems with SiO₂ nanoparticle as viscosity modifier additive were synthesized in the lubricating oil via an in situ Stober sol-gel method. The fluid characters of lubricating oil and viscosity variation were carefully investigated via rheological methods. The results showed that the lubricating oil transformed from Newtonian fluid to non-Newtonian fluid with increasing the concentration of nanoparticles, and smaller particles displayed better thickening effect toward lubricating oil. For the system with highly concentrated nanoparticle (20?wt%), the rheological behavior mainly depends on the size of nano-SiO₂. The lubricating oil with smaller nano-SiO₂ particles displayed higher structural strength and response rate, resulting in good recoverability after high-speed shear. The viscosity changed with temperature and also displayed a thermo-responsive behavior, which significantly alleviated the effect of shear thinning on the viscosity under high temperature. This study presented a new strategy for effectively tuning the fluid characters and modifying the viscosity of lubricating oils by adding highly concentrated inorganic nanoparticles.     

The Wettability Alteration and the Effect of Initial Rock Wettability on Oil Recovery in Surfactant-based Enhanced Oil Recovery Processes

Wettablity alteration of rock surface is an important mechanism for surfactant-based enhanced oil recovery (EOR) processes. Two salt and temperature-tolerant surfactant formulations were developed based on the conditions of high temperature (97–120°C) and high salinity (20 × 10⁴ mg/L) reservoirs where a surfactant-based EOR process is attempted. Both the two sufactant formulations can achieve ultralow interfacial tension level (≤10^?3 mN/m) with crude oil after aging for 125 days at reservoir conditions. Wettability alteration of core slices induced by the two surfactant formulations was evalutated by measuring contact angles. Core flooding experiments were carried out to study the influence of initial rock wettabilities on oil recovery in the crude oil/surfactant/formation water/rock system. The results indicated that the two formulations could turn oil-wet core slices into water-wet at 90–120°C and 20 × 10⁴ mg/L salinity, while the water-wet core slices retained their hydrophilic nature. The core flooding experiments showed that the water-wet cores could yield higher oil recovery compared with the oil-wet cores in water flooding, surfactant, and subsequent water flooding process. The two surfactant formulations could successfully yield additional oil recovery in both oil-wet and water-wet cores.     

Performance evaluation of a new nanocomposite polymer gel for water shutoff in petroleum reservoirs

Abstract

A new polymer gel nanocomposite is fabricated for excess water production control (water shut off) in petroleum reservoirs and its rheological behavior is evaluated in the presence of sea water and formation water at the temperature of 100?°C. It is shown that at a high salinity without using SiO₂ nanoparticles, the elastic modulus of synthesized polymer gel in the presence of sea water and formation water are 12.5?Pa and 9.8?Pa respectively. However by incorporation of SiO₂ nanoparticles in the polymer gel matrix, the elastic modulus of synthesized polymer gel in the presence of sea water and formation water can be improved to 13.56?Pa and 11.57?Pa respectively, which is quite interesting from reservoir engineering viewpoint. Equilibrium Swelling Ratio (ESR) of the nanocomposite polymer gel in sea water and formation water decreases as the concentration of the SiO₂ increases. Thermal stability of the polymer gel is investigated by differential scanning calorimetry (DSC) measurements. The inflexion temperature of the polymer gel is improved by incorporation of 2000?ppm SiO₂ nanoparticles. The fabricated polymer gel nanocomposite in this work can have potential application in reduction of excess water production during enhanced oil recovery (EOR) operations in petroleum industry.     

Nonequilibrium Features of N2 and Oil System

Nonequilibrium state is a universal phenomenon in gas injection development. However, in previous researches and applications, it tends to be regarded as quasi-equilibrium state, or even equilibrium state. Based on research work by pioneers, a simple model for measuring diffusivity of N₂ in oil has been developed. In addition, laboratory experiments were performed in this study. Results indicate that an infinitely thin layer exists between N₂ zone and oil zone in the pressure-volume-temperaturacelda (PVT) cell. Gas and oil molecules will slowly diffuse into one another across the sharp interface by convection, dispersion, and diffusion. Viscosity and gas oil ratio (GOR) are two important parameters representing the phase behavior features of the N₂ and oil system. These dependent variables are related to parameters like pressure, temperature, and oil viscosity.     

Characterization of Remaining Oil After Polymer Flooding by Laser Scanning Confocal Fluorescence Microscopy

In the mid- to late period of oil field development, it is important to consider the microscopic distribution of remaining oil of the reservoir in time, for it is the foundation of enhanced oil recovery. Focusing on the present insufficient research status of microscopic distribution of remaining oil after polymer flooding, this article first put forward and developed a set of fluorescence microscope technology of frozen core analysis of remaining oil, and used this technology combined with laser confocal microscopic detection technology to study microscopic distribution rules of remaining oil before and after polymer flooding. Through comparison and analysis on the difference of microscopic distribution form of remaining oil, the experimental results show that polymer flooding has different effects on different types of remaining oil. Using this technology, analysis of many different distribution forms of remaining oil involving the same mode of occurrence in different layers, different parts of the same layer, and different types of the same layer can be more clearly distinguished. Using polymer flooding pertinently according to the different distribution form of remaining oil will make the use of polymer more efficiently and the recovery higher.     

Application of SiO2–water nanofluid to enhance oil recovery

The present study aims to investigate effects of nanofluid flooding on EOR and also compares its performance with water flooding in field scale using the published experimental data provided from core-scale studies. The nanofluid is based on water including silica nanoparticles. The relative permeability curves of water, nanofluid and oil for a light crude oil core sample obtained in an experimental study are used in this numerical investigation. A 2D heterogeneous reservoir model is constructed using the permeability and porosity of the last layer of SPE-10 model. It has been shown that nanofluid flooding can substantially improve the oil recovery in comparison with the water flooding case. Afterward, the operational parameters of the 13 injection and production wells have been optimized in order to meet the maximum cumulative oil production. First, pattern search (PS) algorithm was implemented which has a good convergence speed, but with a high probability of trapping in local optimum points. Particle swarm optimization (PSO) approach has also been employed, which requires a large number of population (to approach the global optimum) with so many simulations. Accordingly, a hybrid PSO–PS algorithm with confined domain is proposed. The hybrid algorithm starts with PSO and depending on the distribution density of the values of each parameter, confines the searching domain and provides a proper initial guess to be used by PS. It is concluded that the hybrid PSO–PS method could obtain the optimal solution with a high convergence speed and reduced possibility of trapping in local optimums.