Journal of Electrical & Electronic Systems

CO2 utilization as hydrates in vacated natural gas hydrate formations can be considered as viable approach to take emission control measures and preventive actions. In this analytical study, we build a dynamically coupled mass and heat transfer mathematical model which elaborates the unsteady behavior of CO2 flowing into porous medium and converting itself into hydrates. It is targeted to unfold, at what physical and geological conditions hydrate growth rate can be increased with minimal induction time. The simulation results show that formation pressure and temperature distribution becomes stable at early stage of hydrate nucleation process and always remains stable afterwards. At higher pressure and low temperature conditions, the hydrate growth rate is rapid with minimum induction time, which makes it less time consuming to propagate the hydrates inside porous media sample. While, at lower pressure values the outcomes are other way around. The lower formation temperature facilitates hydrate nucleation process by pushing the equilibrium pressure limits to lower value. The hydrate growth rate increases by increasing injection pressure it also expands overall hydrate covered length in same induction period.

The results also show that the injection pressure conditions and hydrate growth rate affect other parameters like, CO2 velocity, CO2 permeability, CO2 density, CO2 and H2O saturation inside porous medium.The termination and restoration of hydrate growth is also witnessed at right boundary of intermediate region which merges it in hydrate-free region a bit due to weak concentration flux between upper and low limit of CO2 solubility concentration. Hydrates of CO2 and water can form during aquifer storage if the reservoir has regions where conditions of pressure and temperature are inside the hydrate forming conditions. Storage of CO2 in natural gas hydrate reservoirs may offer stable long term deposition of a greenhouse gas while benefiting from methane production, without requiring heat. By exposing hydrate to a thermodynamically preferred hydrate former, CO2, the hydrate may be maintained macroscopically in the solid state and retain the stability of the formation. One of the concerns, however, is the flow capacity in such reservoirs.

This in turn depends on three factors; 1) thermodynamic destabilization of hydrate in small pores due to capillary effects, 2) the presence of liquid channels separating the hydrate from the mineral surfaces and 3) the connectivity of gas- or liquid filled pores and channels. This paper reports experimental results of CH4-CO2 exchange within sandstone pores and measurements of gas permeability during stages of hydrate growth in sandstone core plugs. Interactions between minerals and surrounding molecules are also discussed. The formation of methane hydrate in porous media was monitored and quantified with magnetic resonance imaging techniques (MRI). Hydrate growth pattern within the porous rock is discussed along with measurements of gas permeability at various hydrate saturations. Gas permeability was measured at steady state flow of methane through the hydrate-bearing core sample. Experiments on CO2 injection in hydrate-bearing sediments was conducted in a similar fashion. By use of MRI and an experimental system designed for precise and stabile pressure and temperature controls flow of methane and CO2 through the sandstone core proved to be possible for hydrate saturations exceeding 60 %. A very common assumption is that formed hydrate will be stable and will block the flow in all directions in regions where hydrate is formed, and as a consequence hydrate could seal incomplete sealing of clay or shale. In some limits this could be practically true but in general hydrates formed in sediment cannot be thermodynamically stable. Even if the hydrate is inside stability region of pressure and temperature, the hydrate may be unstable with respect to the different component concentrations (and corresponding chemical potentials) in the different phases. In this work we present a first order Taylor expansion for thermodynamic properties outside of equilibrium and apply classical nucleation theory to estimate kinetic rates for hydrate formation kinetics and similar rates in cases of under saturation.

Results are applied in model studies of hydrate formation and dissociation in a model reservoir. Reservoirs of clathrate hydrates of natural gases (hydrates), found worldwide and containing huge amounts of bound natural gases (mostly methane), represent potentially vast and yet untapped energy resources. Since CO2-containing hydrates are considerably more stable thermodynamically than methane hydrates, if we find a way to replace the original hydrate-bound hydrocarbons by the CO2, two goals can be accomplished at the same time: safe storage of carbon dioxide in hydrate reservoirs, and in situ release of hydrocarbon gas. We have applied the techniques of Magnetic Resonance Imaging (MRI) as a tool to visualize the conversion of CH4 hydrate within Bentheim sandstone matrix into the CO2 hydrate. Corresponding model systems have been simulated using the Phase Field Theory approach. Our theoretical studies indicate that the kinetic behaviour of the systems closely resembles that of CO2 transport through an aqueous solution. We have interpreted this to mean that the hydrate and the matrix mineral surfaces are separated by liquid-containing channels. These channels will serve as escape routes for released natural gas, as well as distribution channels for injected CO2.

The hydrocarbon reserves of conventional/unconventional sources will remain a major source of the world’s energy supply even with the fastest growth of other energy sources including renewable energy. The petroleum and energy industry must be capable of low-energy intensive extraction and transportation of these resources, in an environmentally benign manner. Drilling wellbores is one of the most important part of extracting petroleum resources from the reservoirs. Very complex spatio-temporal flow patterns of multiphase flow, which are often observed in annuli during drilling fluid circulation and wellbore production, are not fully understood. Fundamental understanding of the effects of complex multiphase flow regime on hydrodynamic scaling and geometric scaling is an open challenge. This understanding is essential for substantial economic growth of oil and gas industry. The talk will be based on an experiments and numerical simulations project that helps to understand the multiphase (gas/liquid/solid) flow behavior in annuli under various operating, hydrodynamic and geometric conditions.

The objectives of the project are as follows: 1) to develop a tool or model which will optimize  and suggest meaningful surface operating parameters for efficient wellbore cleaning and drill cuttings transmittal to surface, particularly during horizontal drilling wells (cuttings settling in the tangential section), 2) to predict multiphase volume fractions (flow metering) and pressure loss in annuli with a wide range of operating, hydrodynamic and geometric conditions, and 3) early detection of mini-kicks (formation gas invasion to circulating fluids) and provide real-time changes to surface operating parameters before it turns to a well control event and a possible blow-out. Mean velocity and the corresponding Reynolds shear stresses of Newtonian and non-Newtonian fluids have been measured in a fully developed concentric flow with a diameter ratio of 0.5 and at a inner cylinder rotational speed of 300 rpm. With the Newtonian fluid in laminar flow the effects of the inner shaft rotation were a uniform increase in the drag coefficient by about 28 percent, a flatter and less skewed axial mean velocity and a swirl profile with a narrow boundary close to the inner wall with a thickness of about 22 percent of the gap between the pipes. These effects reduced gradually with bulk flow Reynolds number so that, in the turbulent flow region with a Rossby number of 10, the drag coefficient and profiles of axial mean velocity with and without rotation were similar. The intensity of the turbulence quantities was enhanced by rotation particularly close to the inner wall at a Reynolds number of 9,000 and was similar to that of the non rotating flow at the higher Reynolds number.

The effects of the rotation with the 0.2 percent CMC solution were similar to those of the Newtonian fluids but smaller in magnitude since the Ross by number with the CMC solution is considerably higher for a similar Reynolds number. Comparison between the results of the Newtonian and non-Newtonian fluids with rotation at a Reynolds number of 9000 showed similar features to those of non rotating flows with an extension of non-turbulent flow, a drag reduction of up to 67 percent, and suppression of all fluctuation velocities compared with Newtonian values particularly the cross-flow components. The results also showed that the swirl velocity profiles of both fluids were the same at a similar Ross by number. The fluids which do not follow linear relationship between rate of strain and shear stress are termed as non-Newtonian fluid. The non-Newtonian fluids are usually categorized as those in which shear stress depends on the rates of shear only, fluids for which relation between shear stress and rate of shear depends on time and the visco in elastic fluids which possess both elastic and viscous properties.

 It is quite difficult to provide a single constitutive relation that can be used to define a non-Newtonian fluid due to a great diversity found in its physical structure. Non-Newtonian fluids can present a complex rheological behaviour involving shear-thinning, visco elastic or thixotropic effects. The rheological characterization of complex fluids is an important issue in many areas. The paper analyses the damping and stiffness characteristics of non-Newtonian fluids (waxy crude oil) used in squeeze film dampers using the available literature for viscosity characterization. Damping and stiffness characteristic will be evaluated as a function of shear strain rate, temperature and percentage wax concentration etc. By using the basic equation of fluid motion (conservation of mass and momentum) the boundary layer parameters for a Non-Newtonian, incompressible and laminar fluid flow, has been evaluated. As a test, the flat plate boundary layer is first analized and afterwards, a case with pressure gradient, allowing separation, is studied. In the case of curved surfaces, the problem is first developed in general and afterwards particularized to a circular cylinder. Finally suction and slip in the flow interface are examined. The power law model is used to represent the stress strain relationship in Non-Newtonian flow. By varying the fluid exponent one can then, have an idea of how the Non-Newtonian behavior of the flow influences the parameters of the boundary layer. Two equations, in an appropriate coordinate system have been obtained after an order of magnitude analysis of the terms in the equations of motion is performed.

Crude oil and water are produced together in the production of crude oil. The reduction of water levels in the crude oil is essential to meet pipeline and export specifications. Several gravitational, thermal, mechanical, and chemical treatment   methods are used to minimize the water levels associated with oil, but when the emulsion is formed between oil and water; such as water-in-oil emulsion, the process for separating one from each other is difficult. This is because of stabilization of water droplet inside of the oil. Electrostatic separation is found to be the optimum technology to overcome the interfacial active surface of the oil around water droplet. Dispersed water drops in organic liquids, such as water-in-crude oil emulsions, are commonly encountered in the oil, chemical and biochemical industries. The formation of water-in-crude oil emulsion during oil production is undesirable from both a process and product quality point of view. Natural coalescence of drops in such emulsion is constrained because of a thin film of oil between drops not allowing their spontaneous coalescence, and consequently water-in-crude oil emulsions, despite being thermodynamically unstable, can be kinetically very stable for long periods of time. In this work, the water droplets coalescing process was observed under the application of electric field. The coalescing rates were proportionally increased with the increasing of the electric strengths.

The increasing of the coalescing rates has a positive effect on the degree of separation of water from crude oil. For the separation of dispersed water drops from oils an electric field may be used to enhance their coalescence. Water droplets can be removed from a continuous oil phase by several methods such as chemical demulsifiers, gravity or centrifugal separation, pH adjustment and heating treatment and membrane filtration separation. However, nowadays one of the most effective and utilized method from viewpoint of energy efficiency is electrostatic demulsification. The combination of high energy efficiency, since it permits a reduction of the use of heat, and also the fact that it avoids the use of chemical demulsifiers makes this technique environmentally friendly. The utilization of electrical methods for dehydrating crude oil emulsions is not new and has been well reviewed. In the petroleum industry, the first work on electrocoalescence dates from the work of Cottrell in applying external electric fields to crude-oil emulsions. Electro-coalescence is a process to assist approach, contact and finally coalescence of water droplets in oils with a low dielectric permittivity in order to increase their size, thus accelerating their settling velocity and reducing their separation time. The electrostatic effects arise from differences in properties of oil and water, where water has dielectric permittivity and conductivity values much higher than those of the oil, leading to polarization effects in water drops. The amount of dispersed aqueous phase is a key feature to choose the type of electric field. Historically the alternative current (AC) electric field is the oldest and commonest configuration used extensively in crude oil emulsion treatment, as it can tolerate high water contents. In contrast, the direct current (DC) electric field has been less common in the past and has been used more in the treatment of refinery emulsions with low water content in order to reduce electrolytic corrosion.

Generally, the presence of an electric field promotes contacts between drops, enhancing drop–drop and drop–interface coalescence. Hence, research has been carried out on the application of various types of electric fields in the electrocoalescence at a micro-scale level. However, this process could cause some undesirable phenomena such as secondary droplets formation, reducing the separation efficiency. Here the effect of pulsatile electric fields (PEF) on the secondary droplets formation has been investigated.  The emulsion stability can be due to the presence of naturally occurring surfactants in the crude oil, such as asphaltenes, resins, waxes, and naphthenic acids. Asphaltenes and resins are the heaviest and the most polar fraction of the 2 crude oil and are believed to be the major components responsible for emulsion stabilization. In the presence of a very low frequency PEF or DC electric field three distinct drop-drop and drop-interface interaction patterns are observed: complete coalescence, partial coalescence and rebound without coalescence. The first is the ideal pattern not leaving any secondary droplets. It has previously been shown that an increase in the electric field strength and/or a decrease in the interfacial tension result in non-ideal patterns in drop interface coalescence.

The application of PEF shifts the coalescence pattern from a non-ideal to an ideal one in both drop-drop and drop-interface coalescences. Three waveform types, i.e. square, sinusoidal and sawtooth waves have been applied to the coalescence process. It is shown that the sawtooth waveform is the most effective in reducing the secondary droplets formation in drop interface coalescence, followed closely by the sinusoidal one. The observation of videos sequences suggests that a threshold frequency exists above which a non-ideal pattern switches to an ideal one. For drop-drop coalescence this threshold frequency depends on the PEF amplitude and the size of primary drop pairs, as for bigger primary drop pairs and larger amplitudes of PEF the threshold frequency would be higher. When using pulsatile electric fields higher field strengths can be applied for systems having a high water content without causing field breakdown, as compared to constant DC field. This is useful in optimizing the electro-coalescence process.               

Gas hydrates are crystalline compounds made up of water and gas at high pressure and low temperature. Subsea and permafrost region pipelines favor such pressure and temperature conditions for hydrate formation. Ionic liquids (ILs) are popular designer green chemicals with great potential for use in diverse energy-related APPLICATIONS. Apart from the well-known low vapor pressure, the physical properties of ILs, such as hydrogen-bond-forming capacity, physical state, shape, and size, can be fine-tuned for specific applications. Natural gas hydrates are easily formed in gas pipelines and pose potential problems to the oil and natural gas industry, particularly during deep sea exploration and production. This review summarizes the recent advances in IL research as dual-function gas hydrate inhibitors. Almost all the available thermodynamic and kinetic inhibition data in the presence of ILs have been systematically reviewed to evaluate the efficiency of ILs in gas hydrate inhibition compared to other conventional thermodynamic and kinetic gas hydrate inhibitors.

The principles of natural gas hydrate formation, types of gas hydrates and their inhibitors, apparatuses and methods used, reported experimental data, and theoretical methods are thoroughly and critically discussed. The studies in this field will facilitate the design of advanced ILs for energy saving through the development of efficient low-dosage gas hydrate inhibitors. Gas hydrate solids occurrence is considered as one of the serious challenges in flow assurance as it affects the hydrocarbon production significantly, especially in deep water gas fields. The most cost-effective method to inhibit the formation of hydrate in pipelines is by injecting a hydrate inhibitor agent. Continuous studies have led to a comprehensive understanding on the use of low dosage hydrate inhibitors such as ionic liquid and quaternary ammonium salts which are also known as dual function gas hydrate inhibitors. This paper covers the latest types of quaternary ammonium salts (2020–2016) and a summary of findings which are essential for future studies. Reviews on the effects of length of ionic liquids alkyl chain, average suppression temperatures, hydrate dissociation enthalpies, and electrical conductivity to the effectiveness of the quaternary ammonium salts as gas hydrate inhibitors are included. Unless complete dehydration is performed or inhibitors are used, gas hydrates are to be expected in subsea flow lines. Since complete dehydration is not possible, the most functional & practical solution is the use of hydrate inhibitors .

The objective of this paper is to review the entire literature about gas hydrate inhibition to comprehend the existing techniques & latest development in hydrate inhibition technology, which would work as a guide to further develop this potentially interesting and important area of research. Traditionally, prevention of hydrate formation has been achieved with addition of thermodynamic inhibitors, commonly methanol or glycols. These inhibitors have the ability to shift hydrate equilibrium curves toward higher pressures and lower temperatures by lowering the activity of water molecules. However, in last two decades, economic and environmental factors have motivated research and development to identify new inhibitors like low dosage hydrate inhibitors (LDHI) for cost effectiveness & for environment friendliness. LDHI are divided into 2 class kinetic hydrate inhibitors (KHI) & Anti Agglomerates (AA).There are three ways to prevent hydrate plug formation: (i) prevent hydrate crystal nucleation, (ii) prevent hydrate growth (iii) prevent agglomeration of hydrate crystals. KHIs act as anti-nucleators & also delay hydrate growth. AAs prevent Hydrate crystals from agglomerating. A KHI polymer has a hydrophobic & a hydrophilic part.

Hydrophobic part is the backbone carbon structure (alkyl) while hydrophilic part is the incorporated functional group which is amide in most polymers. High molecular weight Polymer prevents hydrate crystal growth. But very high percentage of high molecular weight groups makes the polymer water-insoluble. Low molecular weight polymer performs better for gas hydrate nucleation inhibition. Controlling both nucleation stage and crystal growth stage gives the best results. This work will leads to search for new & better combinations of Polymers, Ionic Liquids and synergents that can prevent the pugging of natural gas pipelines by preventing or delaying hydrate formation. Simulation models have been used widely to help design, operate, control and optimize the processes of exploration and exploitation of natural gas hydrates and been responsible for many of the most important technology breakthroughs. Currently, a rich body of literature exists and is still evolving. This paper presents a critical review of the most influential works that are recognised as representative and important simulation models and links to the techniques commonly used in natural gas hydrate exploration and exploitation. Model background, ideal assumptions and main results are presented. Models are broadly classified into two categories: physically and empirically based models. Models are reviewed with comprehensive, although not exhaustive, publications. The strengths and limitations of the models are discussed. The paper is concluded by outlining open questions and new directions for future work. The review is useful for understanding the innovation process and the current and future status of simulation models on exploration and exploitation of natural gas hydrate and highlights the key aspects of model improvement.

Reservoir oils PVT properties are of primary importance for determination of nearly all the aspects of petroleum engineering computations such as well testing, material balance, volumetric reserve estimates and numerical reservoir simulation. PVT data are essential in reservoir engineering calculations. It is important to obtain reservoir fluid samples to determine PVT properties. To determinate such quantities in laboratory is expensive and time consuming and also results are dependent on the validity of the reservoir fluid sample In case no fluid samples are taken or experimental PVT data is not available, For saving time and money, correlation methods can be used to estimate PVT data. This study presents a novel model of correlation for the prediction of the pressure, volume, and temperature (PVT) properties of crude oil samples. It illustrates a methodology with which to obtain higher prediction precision of parameters by applying this newly developed model of correlation to a set of crude oil samples from different wells of oil reservoirs. The correlations based on a large PVT database and was considered nitrogen content, viscosity of oil and methane content of crude oil, in order to evaluate more accurate correlation.

The new model developed in this paper would suit a large number of reservoirs from different geographical location in worldwide with different properties. In addition, in contrast to most existing correlations which have several parameters in mathematical equations, the new model developed in this paper has only one parameter which can easily be applied to any oil sample. Reservoir oil properties are usually measured at reservoir temperature and are estimated at other temperature using empirical correlations. Fluid properties correlations cannot be used globally because of different characteristics of fluids in each area. Here, based on Iranian oil PVT data, new correlations have been developed to predict saturation pressure and oil formation volume factor at bubble point pressure. The calculation of reserves in an oil reservoir or the determination of its performance and economics require good knowledge of the fluids physical properties. Bubble point pressure, GOR, and OFVF are of primary importance in material balance calculation. These data can be obtained either by conducting a laboratory study on reservoir fluid samples or estimated by using empirically derived PVT correlations. Although laboratory results give better accuracy where controlled conditions are imposed, the results are heavily dependent on the validity of the reservoir fluid samples, especially when the reservoir has depleted below the bubble point pressure. In situations where the experimental data are not available, empirically derived correlations are used to estimate the physical reservoir fluid properties. Fundamentally, there are two different types of correlations in the literature. The first group of correlations is developed with randomly selected data sets; we will refer to such correlations as "generic" correlations.

The second group of correlations is developed using a known geographical area or a certain class/type of oil. Correlations using randomly selected data sets may not be suitable for certain types of oils or for some geographical areas. Even though the authors of the generic correlations attempt to cover a wide range of data, such correlations still work better for certain types of oils. Specialized correlations represent the properties of a certain type of oil or geographical area (for which they have been developed) better than the generic correlations. and output data as compared to linear and nonlinear regression techniques Reservoir fluid properties such as bubble point pressure, oil formation volume factor and viscosity are very important in reservoir and petroleum production engineering computations such as outflow–inflow well performance, material balance calculations, well test analysis, reserve estimates, and numerical reservoir simulations. Ideally, these properties should be obtained from actual measurements. Quite often, however, these measurements are either not available or very costly to obtain.

In such cases, empirically derived correlations are used to predict the needed properties using the known properties such as temperature, specific gravity of oil and gas, and gas–oil ratio. Therefore, all computations depend on the accuracy of the correlations used for predicting the fluid properties. Almost all of these previous correlations were developed with linear or nonlinear multiple regression or graphical techniques. Artificial neural networks, once successfully trained, offer an alternative way to obtain reliable and more accurate results for the determination of crude oil PVT properties, because it can capture highly nonlinear behavior and relationship between the input. The new correlations were developed using genetic programming approach. The new models were developed and tested using linear genetic programming (GP) technique. The models efficiency was compared to existing correlations. Average absolute relative deviation, coefficient of correlation, and cross plots were used to evaluate the proposed models, and their outputs indicate the accuracy of the GP technique and the superiority of the developed models in comparison with the commonly utilized models tested. PVT (pressure-volume-temperature) properties of reservoir fluids in the oil and gas industry constitute an integral part of the required data for a thorough study of the reservoir, optimally compilation of oil production and operation schemes. In the absence of PVT data that measured in laboratory conditions, empirical correlation is used to evaluate these properties. These correlations cannot be applied universally due to the differences of crude oil composition, the working condition of geographical and oil environment. In the article widespread correlations and models was investigated in the field of prediction of PVT properties of reservoir oil from different regions. Their accuracy and productivity was thoroughly analyzed too.

Polymer flooding is a most important chemical EOR methods that uses to increase oil recovery by decreasing the water/oil mobility ratio by increasing the viscosity of the displacing water. Polymer flooding can be as a secondary oil recovery method, but more often it is used as a tertiary oil recovery method based on classical flooding.  Polymer flooding consist of adding polymer to the injected water to increase the viscosity and also a decrease of aqueous phase permeability that occurs with some polymers, led to a lower mobility ratio. This lowering increases the efficiency of the water flood through greater volumetric sweep efficiency and a lower swept zone oil saturation. Generally, a polymer flood will be economic only if the water flood mobility ratio is high, the reservoir heterogeneity is high, or a combination of these two occurs. This study evaluated using of polymer flooding in one of the Iranian heavy oil reservoirs and compared between obtained results of polymer flooding simulated with and water flooding process in different scenarios.

Results also show that the polymer flooding scenario has higher oil recovery in comparison to other displacement methods such as natural depletion and water flooding. In addition, In this study, it was investigated that solving the problem of determining the viscosity of polymer solutions in the case of polymer flooding in one of the Iranian heavy oil reservoir. Primary and secondary recovery methods do not give the maximum oil recovery in certain oil fields, and have a high water cut. Enhanced oil recovery (EOR) methods can solve these issues. CO2 has been used to recover oil for more than 40 years. Currently, about 43% of EOR production in U.S. is from CO2 flooding. CO2 flooding is a well-established EOR technique, but its density and viscosity nature are challenges for CO2 projects. Polymer flooding that falls under chemical EOR is one of these methods.

The mechanisms of polymer flooding leads to increasing the viscosity of the displacing fluid, water, and reduces the mobility to be lower than the displaced fluid, oil. This gives a better sweeping efficiency, which translates into higher oil recovery and lower water cut because of the delay of viscous fingering and water breakthrough. To select a suitable polymer for a particular field, parameters such as; polymer viscosity, concentration, slug size should be studied carefully. The EOR techniques are employed to recover more oil from mature reservoirs after the primary and secondary oil production stages. Polymer flooding as a chemical EOR method involves adding polymer molecules in order to increase water viscosity. Low density (0.5 to 0.8 g/cm3) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir. Low viscosity (0.02 to 0.08 cp) leads to poor volumetric sweep efficiency. So water-alternating-gas (WAG) method was used to control the mobility of CO2 and improve sweep efficiency. However, WAG process has some other problems in heavy oil reservoir, such as poor mobility ratio and gravity overriding. To examine the applicability of carbon dioxide to recover viscous oil from highly heterogeneous reservoirs, this study suggests a new EOR method--polymer-alternating gas (PAG) process.

The process involves a combination of polymer flooding and CO2 injection. To confirm the effectiveness of PAG process in heavy oils, a reservoir model from Liaohe Oilfield is used to compare the technical and economic performance among PAG, WAG and polymer flooding. Simulation results show that PAG method would increase oil recovery over 10% compared with other EOR methods and PAG would be economically success based on assumption in this study. This study is the first to apply PAG to enhance oil recovery in heavy oil reservoir with highly heterogeneous. Besides, this paper provides detailed discussions and comparison about PAG with other EOR methods in this heavy oil reservoir. Increasing water viscosity will improve the mobility ratio of injected fluid to reservoir fluid toward a more favorable value. Therefore, vertical and areal sweep efficiencies are increased compared to typical water flooding. Polymer flooding will be most effective if applied in the early stages of a water flood while the mobile oil saturation is still high. Polymer is also a critical component when considering other chemical EOR technologies such as alkaline-polymer or alkaline-surfactant-polymer.

The presence of a polymer in water increases the viscosity of the injected fluid, which upon injection reduces the water-to-oil mobility ratio and the permeability of the porous media, thereby improving oil recovery. The objective of this work is to investigate strategies that would help increase oil recovery. For that purpose, we have studied the effect of injection pressure and increasing polymer concentration on flooding performance. This work emphasizes on the development of a detailed mathematical model describing fluid saturations, pressure, and polymer concentration during the injection experiments and predicts oil recovery. The mathematical model developed for simulations is a black oil model consisting of a two-phase flow (aqueous and oleic) of polymeric solutions in one-dimensional porous media as a function of time and z-coordinate. The mathematical model consisting of heterogeneous, nonlinear, and simultaneous partial differential equations efficiently describes the physical process and consists of various parameters and variables that are involved in our lab-scale process to quantify and analyze them. A dimensionless numerical solution is achieved using the finite difference method.