جستجوی مقالات مرتبط با کلیدواژه « eor » در نشریات گروه « مهندسی شیمی، نفت و پلیمر »

The growing demand of the world for energy has caused to exploit the non-renewable resources using best techniques to enhance the recovery. Gas injection is one of the most common techniques in the exploitation of reservoir’s hydrocarbon. In addition, carbon dioxide is used widely for gas injection processes in oil reservoirs due to the good results obtained by executing numerous field projects. It should be noted that there exist problems in the process of gas injection into reservoirs. Low density and viscosity of gas is caused unfavorable movement of gas in the porous environment as well as early gas breakthrough in production wells. These factors cause gravitational separation as well as fingering phenomenon in reservoirs. To reduce gas injection problems, foam is replaced instead of gas as injecting material. Implementing the foam injection techniques would result better sweeping efficiency than solely gas flooding since foam has a higher apparent viscosity than gas. Fingering and early breakthrough of gas are reduced by foam injection in oilfields. In this research, by using deionized water at atmospheric temperature and pressure, in the first step, the foaming ability of the designed solutions was investigated. At a critical concentration of 0.24% (weight percent of surfactant), the effect of various parameters on the foaming ability were investigated. In addition, the stability of these solutions were measured based on the foam half-life and the optimal parameters of the different solution were determined to be injected into the micromodel. At the end, the solution obtained from the optimal parameters was prepared for running the injection scenarios. Then the amount of produced oil for different solutions was evaluated by micromodel experiments. It should be stated that presence of silica nanoparticles increased the half-life of the foam by about 25%. In addition, adding the Xanthan gum polymer to injecting foam structure along with the silica nanoparticle increased foam half-life to about 60%.

Reservoir oil recovery and efficiency of EOR projects include designed water injection influenced by factors such as oil composition, porosity, permeability, rock mineral composition, porous space distribution, and pore size. The injection of designed water into the carbonate reservoir has always faced many ambiguities. This category of ambiguities has been further investigated and analyzed in this study by examining one of the influential factors, such as polar compounds of oil and its Physico-chemical interactions during the production process. Polar components in crude oil affect the electrostatic interactions at the mineral surfaces, affecting the wettability conditions. This study performed experiments measuring contact angle and spontaneous vascular process on limestone samples. For this purpose, cores with the same conditions are saturated in different oils regarding the percentage of polar compounds. Moreover, they are adjacent to specific components of active ions in designed water. In this regard, using the collected results, we can interpret and study how to participate in the reaction and the effectiveness of polar compounds in the oil. The results show that the amount of oil production due to water injection depends on the chemical composition of the oil and the interaction between water and oil, and in addition to the amount of asphaltene in the oil, it is also affected by the amount of organic carboxylic acids in crude oil.

The process of injecting smart water into carbonate reservoirs has always faced many challenges. In this study, by examining one of the effective factors such as ionic compounds active in smart water, these ambiguities have been further investigated and analyzed. The reaction between three phases, oil, rock and saline, which leads to a change in wettability, requires the presence of ionic compounds active in smart water and active compounds in oil. The presence of these compounds in the desired concentrations is the driving force required to perform ion exchange reactions followed by a change in wettability. In fact, the optimal concentration of active ions leads to the formation of a stable water film and a change in the wettability of the rock. In this study, experiments measuring the contact angle and the spontaneous imbibition deferens process were performed on samples of limestone.  For this purpose, the cores with the same conditions are located in the vicinity of different compounds of active ions in smart water. In this regard, using the collected results, it is possible to interpret and study how to participate in the reaction and the effectiveness of the active compounds of smart water. It can also be concluded that cations in the presence of sulfate ions can have a positive performance at the minimum concentration in seawater and have acceptable efficiencies of about 41% in experimental conditions.

ASP flooding aims to remove oil trapped due to capillary forces and improve mobility ratios. In this study, the effects of reservoir heterogeneities (i.e. high permeable channels) on waterflooding, polymer, AS + polymer, polymer + AS + polymer flooding have been studied. In particular, the role of the front, resistance factor,  the rate of injected fluids per volume of injected fluid and concentrations of injected fluids have been investigated. The simulation results showed that the P+AS+P gives higher recovery (20%) compared to the water flooding. Also, it was observed that the optimum slug size of each system such as water or polymer slugs or AS in P+AS+P flood and polymer in P+W+P flood can be determined. For heterogeneous models with permeable channels, channel aspect ratio and the direction of channels are observed to be the effective factors for oil recovery.

In the primary oil recovery, which is done using natural mechanisms in the reservoir, less than one third of the volume of petroleum is produced in the best cases for various reasons, including the process of reducing the pressure caused by production. In addition, by adopting secondary methods of oil recovery, such as water injection, despite the widespread use, due to the high mobility of water relative to oil, a large part of the resources will not be able to be produced. Therefore, in order to meet the demand for crude oil, which is constantly increasing, there is always a need to use EOR methods of overdraft to increase the recycling rate after the start of production. One of the efficient methods to increase the efficiency of the crude oil sweeping process is polymer injection (or flooding), which has been used as one of the chemical methods of oil recovery for many years. Since Case Study is a wide, in-depth, and detailed study of a particular case and thus accesses a wide range of knowledge for the analysis of complex systems, the assurance of case study research that all components have been examined is assured. In this study, after a comprehensive review of successful case studies, EOR by polymer flooding operations, the factors and conditions affecting each of the stages of polymer selection, injection operations and then its impact on the rate of increase in production rate and also the rate of reservoir oil recovery has been studied. The results of this operation in different oil fields show the addition of suitable polymer to water in the flooding process and in different conditions, the potential to reduce water production and also reduce the amount of oil saturation remaining in the reservoirs and thus increases oil recovery factor.

In recent years, many studies have been done on the use of surfactant to enhancement oil recovery from reservoirs; in which the performance of biosurfactant with chemical surfactant was compared. But so far no study has been conducted focusing on comparing the performance of biosurfactant with polymers as well as the effect of temperature on oil recovery. Therefore, the present study was dedicated to study the effect of temperature on the rhamnolipid biosurfactant performance using glass micromodel and to compare its performance with anionic polyacrylamide polymer. Thus, the results of the biosurfactant flooding tests were compared with saltwater and polyacrylamide flooding tests. Experiments were conducted at two temperature, 25 and 75 Celsius degrees, in two homogenous and non-homogenous micromodels. Results indicated that in the homogenous model, for two mentioned temperatures, enhanced oil recovery due to flooding with rhamnolipid biosurfactant was 48 and 62, respectively, in which there was 9 and 12.7 percent improvement in compare to saltwater. Meanwhile, the results of polymer flooding showed 61 and 70 percent enhancement, respectively. The same results were obtained in non-homogenous model. The enhanced oil recovery due to rhamnolipid biosurfactant injection in two temperatures were 41 and 51 percent, respectively, which it is higher compared to saltwater and lower compared to polymer. In general, at higher temperature, oil recovery increased in both homogenous and non-homogenous models under three floods.

Foam is a fluid that consists of water, gas, and surfactant, so that its properties are a combination of the two. Water-soluble surfactant is used to stabilize the fluid. From the late 50s and early 60s, foam as a promising technique to control gas mobility and adaptability to porous media, as well as solving problems such as finger phenomenon, early gas breakthrough, gravity override, etc. that are created by gas injection are presented. Applications of foam injection including: EOR, matrix acidizing, prevention of gas leakage, repair of aquifer layers, closing the path in the porous medium in order to control the flow and direct it. To understand the physicality of this fluid, it has been modeled in the past with two general techniques of population balance and local equilibrium. In this article, these approaches and models are explained. Also, a general comparison has been made between the presented techniques. The population balance pattern, which is based on the rules of bubble balance, is classified into two versions: 1- dynamic texture and 2- local equilibrium. The main difference between the two versions is in how to obtain the foam texture. The results show that the local-implicit texture equilibrium technique requires fewer parameters than the population balance model versions. Also, due to the algebraic solution of equations, it takes less computational time in reservoir simulators and is more useful due to its experimental nature.

During recent years, Gemini ionic liquids (ILs), as a new type of surfactants, have gained much attention due to their significant interfacial activity. Accordingly, use of these materials to reduce crude oil-water interfacial tension (IFT) and to enhance oil recovery is much advantageous. In this study, effects of concentration, temperature and pH on the crude oil-water IFT in the presence of Gemini IL surfactants were investigated. For this aim, alkyl chain length imidazolium based gemini ILs of [C4im-C4-imC4][Br2] and [C8im-C4-imC8][Br2] were synthesized and used. By measuring IFT of the system, under different conditions, the corresponding variations were considered. Results revealed the strong effect of alkyl chain length and concentration on the IFT, leading to, respectively, 72.5 and 97.5% reductions under critical micelle concentrations and temperature of 298.2 K. The Gemini IL surfactants were stable at high temperatures and under a wide range of pH, and that their performance was significantly promoted with these factors. In theoretical investigation, it was revealed that the experimental data were nicely consistent with the Frumkin adsorption isotherm and the obtained parameters with reasonable variations.

Uncertainty in the upstream oil sector, especially in the early stages of field development, is high due to the lack of reservoir data and the multiplicity of uncertain parameters. Therefore, the calculation of quantities such as oil in place, recovery factor, and the net present value of production scenarios require uncertainty analysis. In this paper, response surface methodology and Monte Carlo simulation were used to analyze the uncertainties in a giant heterogeneous undeveloped oil reservoir and its effect on the selection of the Best EOR scenario was investigated. Then, the application of loss function, expected value, and semi-standard deviation and the best scenario under uncertainty were investigated considering uncertainty. The results show that parameters such as permeability, transmissibility multiplier, water-oil contact, and net to gross have the greatest impact on oil production from the reservoir. Also, after uncertainty analysis, different loss functions affect the best estimate of each production scenarios. The total utility function also is a good way to rank production scenarios and decide to choose the best scenario under uncertainty.

Conventional production methods in heavy oil reservoirs are not efficient due to high viscosity of oil. Therefore, several new methods such as VAPEX and ES-SAGD have been developed to overcome production challenges from these reservoirs, which mainly rely on oil viscosity reduction. Solvent injection dilutes the oil and produces a complex asymmetric mixture. It is difficult to study the phase behavior of oil due to diversity of its components, and it gets more complicated by addition of solvent. One of the assumptions to simplify the problem is considering heavy oil as a single pseudo component and to investigate thermophysical properties of binary mixtures with diluents/mixtures. In this study, more than 1000 experimental data of various types of heavy oil/bitumen and several hydrocarbon and non-hydrocarbon solvents were collected and evaluated. The data were divided into two groups, below and above the critical temperature of the solvent, according to experimental temperatures. Also, modeling mixture phase behavior as a binary mixture was done using the advanced Peng-Robinson equation of state (APR-EoS). EoS tuning to match the experimental data was done by optimizing the binary interaction coefficient (kij). The results showed that binary mixture assumption could be used as a practical approach to construct P-X diagrams. Optimized kij was proposed according to dimensionless ratio Tco/Tcs (oil critical temperature to solvent critical temperature) for each solvent. The model constructed using suggested kij shows an average deviation of about 13% compared to experimental data. It is necessary to note that vapor-liquid-liquid three phase region may occur in a heavy oil/bitumen and solvent mixture. But according to the Gibbs phase rule, with two components and three phases in the system, the degree of freedom equals one. Therefore, investigating impacts of pressure change on three phase region is not possible using this model.

One of the enhanced oil recovery methods that has been recently received more attention is low salinity water injection (LSW). Among the proposed mechanisms to describe LSW, geochemical reactions seem to mainly affect rock wettability alteration and thus incremental oil recovery. The goal of this paper is to investigate the effect of geochemical reactions of calcite dissolution and ion exchange on the performance of LSW in a sandstone reservoir by using the concept of threshold salinity. Fluid flow equations according to Buckley-Leverett theory were numerically coupled with the PHREEQC software. Results showed that as LSW was injected, initial equilibrium between reservoir rock surface and aqueous phase was disturbed leading to calcite dissolution and also cation exchange between aqueous phase and rock surface. Analysis of geochemical reaction near the injection well showed that cation exchange may cause to separation of organic compound from rock surface leading to wettability alteration to more water- wet. Also, pH profile through the reservoir showed that rate of calcite dissolution was very high near injection well, but only partial dissolution of calcite induced by cation exchange occurs at farther distance. Fractional flow analyses in line with total salinity profile showed that two distinct saturation shock fronts were established during LSW injection: first one represents high salinity condition with a water saturation of 0.43, and the second one represents low salinity condition with a water saturation as much as 0.58. Under the conditions of this study and selection of a salinity threshold of 3000 ppm, such increase of water saturation reveals EOR potential of LSW by which an incremental oil recovery of 10% of the oil initially in place was obtained as compared to high salinity water injection.

The aim of this work is to study stability and mobility of modified nanoparticle-stabilized foam. Adding oppositely charged surfactant to the hydrophilic silica nanoparticle leads to variation in the hydrophobicity of nanoparticles. Surfactant’s adsorption on the nanoparticle’s surface is compared with different mixtures by a new criterion which is calculated by measuring conductivity. The adsorption criterion in domain of surfactant concentration has a maximum close to 1 CMC where nanoparticle reaches to maximum hydrophobicity. NPS-stabilized CO2 foam formed with simultaneous injection of CO2 and foam agent dispersion through a glass bead pack at reservoir pressure. Nanoparticle alone is not surface active. By adding appropriate surfactant concentration to nanoparticle dispersion¡ it becomes surface active. The complementary study of both pressure behaviour and morphology of foam using foam’s dynamic characterization apparatus¡ shown in the domain of surfactant concentration¡ apparent viscosity of the foam has a maximum about 6.034 cp which is consistent with the maximum adsorption criterion. Also¡ adding nanoparticle to the solution of surfactant forms more uniform¡ and the smaller foams and the apparent viscosity increase significantly. Increasing at a CO2 injection rate will also increase the size of the bubbles and reduce the apparent viscosity which means an increase in mobility.

The low salinity water flooding caused an increased secondary and tertiary oil recovery in many laboratory and field tests. The extent of the reactions and interactions of this type of flooding led researchers to investigate and find the main mechanisms¡ governing this process. To describe the interactions¡ numerous mechanisms such as¡ fines migration¡ increase in pH¡ multiple ion exchange and electric double layer effect have been noted¡ but none of them¡ has not been accepted as a comprehensive mechanism due to the complexity of the crude-oil-brine-rock interactions. So far¡ most of what has been suggested in previous research was creating a favorable wettability state with dilute brine injection. In this laboratory experiments that take place on sandpacks¡ the effects of brine salinity¡ aging of oil in packs and the fines have been investigated on recovery of oil¡ end point water relative permeability in each salinity and wettability alteration. The obtained results from dilute brine injections show that without the presence of minerals and divalent ions and with NaCl brine¡ tertiary recovery was increased¡ and of course this increase was higher for the aged sample. Also¡ the wettability alteration towards more water wet has been probed by means of flooding data.

One of the major problems in Enhanced Oil Recovery (EOR) processes is the precipitation and deposition of asphaltene. This may lead to formation damage or partial and utter obstruction of flow passages around the well, deposition of asphaltene on the surface of reservoir rock as well as wettability alteration from water- to oil-wetted, and deposition in processing units. The present study investigates the miscibility of synthetic oils with or without asphaltene and compares it with that of crude oil from one of the Iranian oil fields in the presence of CO2 gas using vanishing interfacial tension (VIT) technique. The experiments were conducted at a given temperature but for different pressures. The experimental results showed that normal paraffin, in the oil phase, served as instability agent for the precipitation of asphaltene. The higher content of n-paraffin resulted in more and faster precipitation of asphaltene at the gas/oil interface. Once this occurred then the slope of IFT curve between gas and oil increased resulting in decreased CO2 solubility. Furthermore, based on IFT measurements, the speed of approaching to miscibility is reduced in vicinity of the onset of asphaltene precipitation. Thus, asphaltene aggregation in the gas/oil interface is accompanied by reduced slop of VIT curve which made the miscibility condition harder to reach.