Empirical Correlations for Viscosity of Polyacrylamide Solutions with the Effects of Temperature and Shear Rate. II

Apparent viscosity measurements have been made to characterize the effects of shear rate and temperature on the partially hydrolyzed polyacrylamide solutions. The power-law model for the viscosity behavior has been modified to develop empirical correlations that combine effects of shear rate and temperature. Nonlinear regression was performed on the experimental data to develop the proposed correlation. The viscosities of the polymer solutions were measured in the temperature range of 25°C to 80°C, while the shear rate was varied from 1 to 1000 1/s. The proposed correlation should prove supportive for the preliminary selection of the polymers for enhanced oil recovery applications.     

Experimental Study and Numerical Modeling of Rheological and Flow Behavior of Xanthan Gum Solutions Using Artificial Neural Network

This study investigated effect of temperature, concentration, and shear rate on rheological properties of xanthan gum aqueous solutions using a Couette viscometer at temperatures between 25°C and 55°C and concentrations of 0.25 wt% to 1.0 wt%. The Herschel–Bulkley model described very well the non-Newtonian behavior of xanthan gum solutions. Shear rate, temperature, and concentration affected apparent viscosity and an equation was proposed for the temperature and concentration effect valid for each shear rate. This article also presents an artificial neural network (ANN) model to predict apparent viscosity. Based on statistical analysis, the ANN method estimated viscosity with high accuracy and low error.     

Experimental Design Approach to Investigate the Effects of Operating Factors on the Surface Tension,Viscosity, and Stability of Heavy Crude Oil-in-Water Emulsions

In this article, the effects of various operating factors on the surface tension, viscosity, and stability of two heavy oil types in water emulsions for pipeline transportation are studied using the Taguchi experimental design approach. The surface tension of heavy crude oil-in-water emulsion is decreased by increasing the emulsifier concentration while the stability of emulsions is increased. The viscosity and stability are increased by an increase in oil content. An increase in the salinity and mixing speed leads to an increase in the stability of emulsion.     

Similarities and Differences of Low Salinity Polymer and Low Salinity LPS (Linked Polymer Solutions) for Enhanced Oil Recovery

Linked polymer solution (LPS) is nano-size particles made of hydrolyzed polyacrylamide (HPAM) cross-linked with aluminum citrate. The propagation of LPS has been compared to non-cross-linked polymers at low brine salinity condition. The possible differences in properties and potentials for oil recovery have been investigated using water-wet and intermediate-wet cores. The target oil for polymer flooding (PF) is assumed to be the portion of the reservoir that has been bypassed by water during waterflooding and not the residual oil saturation in flooded zones. Our recent studies have shown that a positive synergy can be obtained by combining low salinity and PF. It has been claimed in the literature that cross-linking polymer such as colloidal dispersion gels (colloidal dispersion gels (CDG), micron-size aggregates) or LPS (nano-size particles) would extend the application of polymers to also include change in residual oil saturation. The results of this study indicated higher pressure buildup when low salinity LPS was propagated through brine saturated cores compared to low salinity polymer solution. The pressure buildup was even stronger for high salinity LPS injection. In two phase flow experiments, both polymer and LPS under low salinity condition, showed approximately similar propagation and oil recovery potential when injected into water-wet and intermediate-wet cores.     

Experimental Investigation on Yield Stress of Water-in-Heavy Crude Oil Emulsions in Order to Improve Pipeline Flow

An experimental study on yield stress of water-in-heavy crude oil emulsions has been carried out by using a HAAKE RS6000 Rheometer with a vane-type rotor. Several factors such as oil volume fraction, shear rate, temperature, and emulsifying agent on the yield stress of emulsions were investigated. Zero shear viscosity of heavy crude oil was 6000 mPas at 30°C, with a density 955 kg/m³. This study shows that the yield stress increases linearly with the increasing shear rate, and displays an exponential decay with increasing the temperature and oil volume fraction. Although the addition of emulsifying agent enhanced the stability of the emulsion, to some extent it also increased the yield stress, especially for the emulsions with high oil volume fractions. Therefore, to reduce the start-up force for the pipeline transport of water-in-heavy crude oil emulsions, the starting rate should be decreased, temperature increased, or oil volume fraction increased. These results are helpful to improve the transportation of water-in-heavy crude oil in pipeline.      

Strain-Dependent Rheological Model and Pressure Wave Prediction for Shut in and Restart of Waxy Oil Pipelines

Waxy oil gelation and rheology is investigated and modeled using strain-dependent viscosity correlations. Rotational rheometry shows a sharp viscosity increase upon gel formation. High creeping flow viscosities are observed at small deformation conditions prior to yielding. A new strain-dependent rheological model, following analogous formulation to the Carreau–Yasuda shear rate-dependent model, captures viscosity reduction associated with yielding. In addition, shear viscosity and extensional viscosity are investigated using a capillary rheometry method. Distinct shear-thinning behavior is observed in the shear mode of deformation, while distinct tension-thinning behavior is observed in the extensional mode of deformation for the model fluid systems. High Trouton ratios are obtained for the gelled model fluid systems, confirming strongly non-Newtonian fluid rheology. Finally, axial pressure wave profiles are computed at real pipeline dimensions for idealized moderate yield stress fluids using a computationally efficient 1D pipeline simulator. The Rønningsen time-dependent gel degradation model is used to emulate the fluid rheology in the simulator. Axial stress localization phenomena are shown to depend on the overall magnitude of gel degradation as established by the reduction in yield value. A high degree of gel degradation serves to afford flow commencement in a timely manner.     

Rheological Behavior of Viscoelastic Wormlike Micelles in CTAB/SSS/H2O Systems

The effect of the addition of sodium 4-styrenesulfonate (SSS) and KNO3 as well as temperature and shear rate on the structural transition of aqueous micellar solutions of the cationic surfactant cetyl trimethyl ammonium bromide (CTAB) was studied by viscosity. The effect of hydrocarbons on viscoelastic CTAB solutions was also examined. Possible mechanism for formation of CTAB wormlike micelles in the presence of sodium 4-styrenesulfonate (SSS) and KNO3 was discussed. The rapid increase in the apparent viscosity of CTAB solutions on the addition of SSS and KNO3 was due to the transition in micellar shape from spheres to wormlike ones. The rheological properties of CTAB solutions fit Maxwell model at low shear frequency. AFM image indicated a structure of transient network of CTAB/SSS/KNO3/H2O solution.     

Mechanistic Simulation Studies on Viscous-Elastic Polymer Flooding in Petroleum Reservoirs

Based on the theory and application developments of polymer flooding on enhancing oil recovery, an improved mathematical model has been developed to simulate the mechanism of viscous-elastic polymer flooding. IMPES method has been presented to solve the polymer flooding model considering the viscosifying effect of elasticity, the effect of decreasing residual oil and the degradation of polymer molecules. The validation of the model is approved by an experiment. A simulation example was carried out using the developed numerical simulator. The enhanced oil recovery mechanism was discussed for viscous-elastic polymer flooding, and corresponding influencing factors were also studied.     

Applying a Smart Technique for Accurate Determination of Flowing Oil-Water Pressure Gradient in Horizontal Pipelines

Two-phase flow of liquids in pipelines is crucial subject in many industries such as chemical and petroleum. Accurate prediction of pressure gradient will lead to a better design of an energy efficient transportation system. Although numerous studies for prediction of two-phase flowing pressure drop have been reported in the literature, the accurate prediction of this parameter has been a topic of debate in many research areas. In this article, a novel model based on least square support vector (LSSVM) was proposed for calculation of two-phase flowing pressure drop in horizontal pipes. The inputs of this model are oil and water superficial velocities, pipe diameter, pipe roughness, and oil viscosity. To develop and test the model, more than 700 experimental dataset from open literature were utilized. The results of proposed model were compared against the well-known empirical correlations. Statistical error analysis showed that the LSSVM model outperforms existing predictive models. Finally, an outlier diagnosis was performed to detect the doubtful experimental.      

Interfacial Tension Measurements Between Oil Fractions of a Crude Oil and Aqueous Solutions with Different Ionic Composition and pH

Dynamic and equilibrium interfacial tensions between crude oil fractions and aqueous solutions of various compositions and pH were measured. The basic oil components seemed to determine the interfacial tensions at pH 2, while the non-dissociated and dissociated acidic components governed the interfacial tension at the natural pH and pH 9, respectively. The ionic composition of the aqueous phase influenced the degree of dissociation of the acidic components at pH 9: Na⁺ ions in the aqueous phase promoted dissociation of the interfacial acidic components (compared to pure water), while Ca²⁺ ions resulted in complexation with the dissociated acids and most likely formation of stable interfacial films. The amount of Ca²⁺ determined which of these phenomena that dominated when both ions were present in sea water solutions. Generally, the interfacial tensions of the oil fractions were lower when measured against the high salinity aqueous solutions than against the corresponding low salinity solutions.      

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.     

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.     

Effect of Gas-Wetness of Cores on Imbibition

Gas-wetness of cores plays an important role on imbibition. Gas-wetness of cores, treated by various concentration fluorocarbon polymer Zonyl8740 (aq), was measured by the captive bubble. Subsequently, co-current and counter-current spontaneous imbibition were conducted on the various gas-wet cores both in air/wate and air/oil systems. Experimental results showed that, with the increase of concentration of Zonyl8740 solutions, gas-wetting ability against liquid on the cores gets stronger, gas recovery decreases, and the trapped gas saturation increases. Meanwhile, on the cores treated by the same concentration Zonyl8740 solution, air/water systems have a stronger gas-wettability than that of air/oil systems.      

Synthesis and Interfacial Activity of Nonyl Phenol Polyoxyethylene Ether Carboxylate

In order to study the interfacial activity of the anionic-nonionic surfactant, five nonyl phenol polyoxyethylene ether carboxylates were synthesized and mass spectra were used to characterize their structures. The tensions of the anionic–nonionic surfactant aqueous solutions against crude oil were measured and the effects of the surfactant structure, concentration, and salinity on the interfacial activities were discussed. It was shown that nonyl phenol polyoxyethylene (6) ether carboxylate can produce ultralow interfacial tension when the concentrations are not lower than 0.10%, exhibiting a high interfacial activity and a good anti-dilution resistance. Moreover, it was proved that there exists synergism between NaCl and MgCl₂ (or CaCl₂), which is crucial to achieve the ultralow interfacial tension.     

Experimental Investigation of the Effects of Different Parameters on the Rate of Asphaltene Deposition in Laminar Flow and Its Prediction Using Heat Transfer Approach

In this study, asphaltene deposition from crude oil on the pipe surface has been studied experimentally using a novel designed test loop. Washing technique is used to quantitatively measure the rate of asphaltene deposition during laminar flow in the steel pipe. The effects of oil velocity, asphaltene content, and surface temperature on the thickness of asphaltene deposition are investigated. The results show that the asphaltene deposition rate increases with increasing surface temperature, results in asphaltene content reduction of the flowing crude oil. As the oil velocity increases, less deposition was noticed on the surface of the pipe. Besides, thermal approach was applied to the experimental procedure which shows good agreements between the predicted thickness and the measured value from the test loop.     

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.     

Investigation of Asphaltene Aggregate Size Distribution Under Aggregation and Breakage Phenomena Using Monte Carlo Simulation

In this article, the aggregation and breakage processes are simulated through Monte Carlo method for asphaltene aggregates under shear-induced petroleum mixtures. The simulation results are verified by the aggregate size distributions of two types of asphaltenes having different fractal dimensions extracted from Iranian crude oil types. The obtained aggregate size distributions are affected by shear rate, toluene to heptane ratios and the oil type. The dynamic evolution of asphaltene aggregates shows an ascendant trend with time until they reach a maximum average diameter and then descent to a steady-state size. The asphaltene fractal dimension affects the aggregation process.