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

Due to the necessity and importance of considering risks, attention is generally given to the identification, assessment, and control of risks in EOR (Enhanced Oil Recovery) studies. The aim of this article is to provide a preliminary and comprehensive research methodology for EOR risk assessment using the FMEA (Failure Mode and Effects Analysis) method. In addition, the results of its application for EOR risk assessment and prioritization in an oil field located in southwest Iran are presented step by step. Due to the variations in the fracture network distribution and, consequently, the divergent performance of Enhanced Oil Recovery (EOR) scenarios in different parts of the reservoir, the study focused on three sectors: western, central, and eastern. The critical risks identified across all three sectors include the “Insufficient number of valid laboratory data related to the physical properties and fluid phase behavior in relation to the samples taken,” “Weakness of the fluid phase behavior prediction model,” “Weakness in matching the history of simulation of the base model of the reservoir,” and “Weakness in analyzing the data gathered from performance monitoring of EOR.” In conclusion, control actions necessary for eliminating the root causes or mitigating the effects of these critical risks were outlined.

In the last two decades, due to the establishment of environmental protocols and international laws such as the Kyoto and Copenhagen agreements, simultaneous storage and EOR using carbon dioxide as the main greenhouse gas has been considered. Injecting gases from combustion is one of the methods of extracting hydrocarbon gases that can minimize problems and challenges. In this study, the technical and economic analysis of the idea of injecting combustion gases (Flue gas) as an efficient, available, and cheaper method than other gas injection methods is discussed. The technical results of this project include laboratory studies and simulation outputs of the actual reservoir model performance and economic studies based on the latest price evaluations.

Research topic: One of the new methods in the processes of increasing oil recovery from hydrocarbon reservoirs is the method of using ultrasonic waves. In this research, using ultrasonic waves and their application in a large-scale sample tank, its effect on increasing oil extraction by the numerical method is investigated.

In this research, the modeling process has been performed using MATLAB software. First, by determining the porous environment, the amount of pressure increases due to ultrasonic waves due to solving the sound equations (Helmholtz) by MATLAB k-waves toolbox is investigated. Finally, considering the cumulative production at a specific time from the production well and determining the oil recovery from the reservoir in the presence of a wave, to examine the effect of well location parameters and its distance from the wave generation source, wave production starts time, wave application methods (Pulsed and continuous), is performed at an optimal frequency and power.

According to the modeling results, the closer the wave start time is to the first days of production, the higher the oil recovery rate; So that by starting the application of ultrasonic wave under the power of 5 kW and frequency 20 kHz simultaneously with the production of well oil from the first day, oil recovery compared to oil recovery in the case of starting the wave from the fifty and ninety days, respectively 4/5% and 8% more. Oil recovery is 1.8% higher if the wave is applied continuously to the reservoir at a given time than when pulsed at the same time. The modeling results show that the shorter the distance between the wave source and the production well, the lower the pressure drop in the reservoir area and the higher the oil recovery. According to the results, if the source of wave production is located at a distance of 200 feet from the production well, it will increase by 7.1% compared to the distance of 1800 feet from the oil recovery well.

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.

A large part of reservoir rocks is composed of carbonate rocks, which are more complicate. The most important challenge in oil production form the carbonate reservoirs, which decreased the ultimate oil recovery is that a great volume of oil remains in the rock. Enhanced oil recovery (EOR) techniques play an important role in improving oil production. Injecting smart water into the oil reservoir is one of the new methods of increasing oil extraction, which is designed by adjusting and optimizing the composition of ions in the injected water. Smart water injection into oil reservoirs is widely used in the oil industry due to its low cost compared to other methods of EOR. Generally, the objective of this study is better utilization of water flooding methods to increase the oil recovery efficiency from the carbonate reservoirs. Therefore, in this research, the effect of magnesium, sulfate and calcium ion concentrations in the process of enhanced oil recovery by smart water injection method on oil recovery coefficient from carbonate rock is investigated. By comparing the recovery factors for the double-distilled water and water types containing divalent ions, it was found out that the presence of divalent ions has a positive effect on the ultimate recovery from the carbonate reservoirs. In addition, changing the divalent ion concentrations in the designed smart water proved that an increase in the concentration of magnesium, sulfate, and calcium promotes the oil recovery factor. By comparing the final oil recovery coefficient of smart waters 4, 5 and 6 compared to smart water 3, it was found that by increasing of ions concentration of  Mg+2, SO4-2 and Ca+2 increase of the final oil recovery coefficient from 55%, 57.7%, 56% and 59% are in carbonate rocks, respectively. In other words, increasing the concentration of calcium ions had the greatest effect on oil recovery factor and increasing the concentration of sulfate ions had the least effect on the oil recovery factor.

 Global energy demand is increasing, so enhanced oil recovery techniques have incorporated in production processes. Water flooding is a common technique in oil recovery processes. One of the major challenges in this technique is heterogeneity of the reservoir structure which results in increased water production and reducing the oil recovery factor. Moreover, long-term water or chemical injection might lead to the increased horizontal and vertical heterogeneities in the reservoir. Selective blockage of high permeability areas and consequently improved production from low permeability regions is important for increasing the oil recovery factor. In recent years, using hydrogels in injection processes, has been associated with various field successes, indicating the ability of these materials for selectively blocking the areas of high permeability. Hydrogels are injected after water or polymer flooding to conduct the injected fluid to low permeability areas.

 In this paper, hydrogel injection process was simulated in glass micromodels using Comsol Multiphysics software. Hydrogel functionality was studied in low permeability areas in porous media. Moreover, the optimized conditions for water flooding process was studies. For this purpose, after model validation, sensitivity analysis was performed on effective parameters on oil recovery factor and a mathematical model was presented to predict the oil recovery factor.

Oil recovery factors obtained from experimental and simulation studies, were in good agreement with each other with absolute error values of 2.29% and 4.06%, for water and hydrogel flooding, respectively. Four parameters of injection rate, contact angle, oil viscosity, and injection fluid viscosity were considered as effective parameters on oil recovery factor. Among them, contact angle was the most important parameter. In water flooding, the most important interacting parameters are viscosity and contact angle and the least important parameters are injection temperature and rate. In water flooding simulation studies, the thickness of the contact surface was obtained hmax/5, where  is 230 micrometers. For hydrogel injection, the contact surface thickness was obtained terpf.ep_default / 5.65. Terpf.ep_default is the thickness of contact surface, equal to 631 micrometers

Sulphate reducing bacteria (SRB) have been identified in oil reservoirs since 1920s. They reduce sulphate to sulphide resulting in production of hydrogen sulphide. H2S is a corrosive, toxic and flammable gas which causes operational and capital costs for oil industry. Classification of microbial activity as the main source of H2S generation in flooded reservoirs is followed by the increasing number of water-based EOR projects in the few last decades. Failure in precise prediction of reservoir souring onset in the reservoir may lead to severe health and safety issues. Once the prediction and simulation phase is accomplished, appropriate mitigation method should be selected. However, many simulators capable of considering the reservoir souring are available, urgent need to quick prediction of this phenomenon looks necessary. A novel souring screening approach is presented to investigate the souring potential using simple information. Comparing the reservoir conditions with the required criteria for microbial activity is the main idea of this method. In addition, some new methods to mitigate the souring effects are proposed. The most inspiring method is to utilize (per) chlorate group to inhibit bacterial activity.

One of the common problems in porous media, such as oil reservoirs and surface facilities, is the mineral scale formation that directly affects the production rate. Controlling and mitigating scale formation have therefore been investigated intensively in both research and industrial fields for many years. Recently, due to the limitations applied by the international community for environmental protection and according to the point that laboratory investigations of any scale inhibitors under oilfield conditions is essential prior to its use in oil industries, environmentally friendly green inhibitors have attracted a great attention. In the present study, the performance of two green scale inhibitors and one commercial phosphate-based inhibitor against calcium carbonate and calcium sulfate formation were investigated using standard static tests (Jar tests) and XRD analysis to determine the performance of appropriate inhibitor. The results demonstrate that to achieve reasonable inhibition efficiency, inhibitor A is more efficient than B, although higher amount of green inhibitors is consumed in comparison with the commercial phosphonate-based ones.

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.

In gas injection processes, due to a large viscosity contrast, sweep efficiency is incomplete and large volume of oil is left behind in the reservoir. Polymer alternating CO2 gas (CO2-PAG) injection can be used to improve sweep efficiency and increase oil recovery. This method benefits form an improved microscopic displacement with the injection of gas, and an enhanced macroscopic sweep efficiency with the injection of polymer. To the best of our knowledge, this method has not been studied in the micr scale. The purpose of this study is to investigate the mechanisms of oil production in the CO2-PAG injection process using glass micromodels. Two-dimensional water-wet micromodel with a diagonal injection-production pattern was utilized to visualize the pore-scale oil recovery mechanisms. The micromodel was well equipped with a high resolution camera to capture microscopic phenomena during the oil displacement. A paraffinic model oil with a viscosity of 0.028 Pa.s was used as the representative of viscous crude oil. Moreover, partially hydrolyzed polyacrylamide with a concentration of 1500 ppm was used to control the mobility of the aqueous phase. Initially, the micromodel was saturated with saline water i.e., fully saturation, then oil was injected to achieve an irreducible water saturation. Afterwards, to investigate the EOR potential of CO2-PAG, the alternate cycles of gas and polymer were injected at two PAG ratios of 1:1 and 2:1. Microscopic phenomena affecting oil displacement during the process of CO2-PAG injection were investigated. Therefore, it was possible to identify several effective mechanisms that improve oil recovery. Results show that both the formation of mobile gas clusters and polymer elasticity increased oil recovery. Mobile gas clusters caused double drainage and imbibition in the micromodel system. A pore to pore oil displacement by polymer solution, the formation of continuous and discontinuous polymer strings, the existence of mobile blobs and gas clusters were observed and identified during the CO2-PAG injection process. Results confirmed that an improvement in the volumetric sweep efficiency was achieved by the CO2-PAG injection. In 1: 1 PAG ratio, a higher volume sweep efficiency was obtained.

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 efficient methods for enhanced oil recovery from a petroleum reservoir is the surfactant injection in the presence of alkaline material. Moreover, the contact angle of water and reservoir rock is reduced in the presence of surfactants. On the other hand, this material changes the interfacial tension. The alkaline materials in the present of surfactants also help the reduction of interfacial tension and the wettability alteration of reservoir rock. In this research, the effect of concentration (0.05, 0.1, 0.3, 0.5 wt %) and shelf-life of surfactant dodecyltrimethylammonium bromide in the presence of different concentrations of sodium carbonate (0.5, 1, 1.5, 2, 2.5 wt %) on the interfacial tension and wettability alteration of carbonated rocks of the Asmari petroleum reservoir were analyzed. The results of these experiments showed that surfactant dodecyltrimethylammonium bromide reduces the interfacial tension and alters the wettability of reservoir rock to the water-wet state. Furthermore, the interfacial tension and contact angle is reduced in the presence of sodium carbonate to a great extent which is one of the effective factors in the amount of oil recovery. By increasing the shelf life of the reservoir rock in contact with the solution containing surfactant and sodium carbonate for 7 days, the minimum contact angle was reduced from 59 to 46 degrees. At 0.3 wt.% micelle concentration of dodecyltrimethylammonium bromide and sodium carbonate with an optimum concentration of 0.5 wt.%, the most reduction in interfacial tension was obtained.

According to increasing human energy requirements and energy source limitation, production of fossil energy is an important issue. Enhanced oil recovery techniques have been developed for increasing the amount of crude oil that can be extracted from oil fields. Recently, the application of nanoparticles (NPs) suspension flooding for EOR purposes has been proved. In addition, NPs can improve fluid-rock interaction characteristics such as wettability. In this work, alpha-Alumina nanofluid effects have been investigated in wettability alteration of carbonated rocks. Contact angle is used to analyze the alteration of surface wettability. Different nanofluids concentration in the range from 0.1 to 0.5 wt.% is used. Finally, the result clearly indicates the improvement wettability of reservoir to highly water-wet when it is treated with nanofluids.

In this report, brief description of modeling process to reach proposal scenarios, main results, conclusions and recommendations will be presented. WAG as an EOR method is being considered for Ilam reservoir, located onshore in south- west Iran. The reservoir under study is a reservoir with high amount of H2S and asphaltene. The only drive mechanism is Solution gas drive and it has no active aquifer so although it had good flow potential. By using new reservoir management techniques and enhanced oil recovery in order to pressure maintenance one can recover a lot more oil. The scope of this project was to evaluate in terms of impact of surface facilities, reserves and recovery factor by:  Natural Deletion  Water Injection  Gas Injection  Water alternating gas There are several wells in model and this was possible to change function of production well to injector if needed. Sector model was run for different scenarios and realizations and the best EOR method was selected by considering reservoir rock and fluid data and different injecting fluid composition and different injection pressure. After comprehensive study and technical evaluation it was found that. Gas injection was the best scenario allowing longer plateau compared to Natural depletion and other scenarios.

Applicability of nanoparticle in oil and gas industry has brought much attention, particularly in enhanced oil recovery. Various factors including reservoir type, geological properties, wettability of the surface and fluid distribution influence efficient production from reservoir. Employing nanofluid for wettability alteration has been of great importance and provide favorable wettability state. Wettability alteration of reservoir rock increases production rate and reduces the residual saturation of the fluid in the porous medium. Reservoir rock surface consists of minerals with different adsorption properties that can influence wettability of the rock. In this paper, a fundamental of wettability is explained furthermore, the ability of different nanoparticles in wettability alteration of different rock types are investigated for enhanced recovery from oil and gas reservoirs with certain rock type.