جستجوی مقالات مرتبط با کلیدواژه "تزریق گاز" در نشریات گروه "مهندسی شیمی، نفت و پلیمر"

Severe slugging in risers hinders the steady production of oil, and it may also damage the equipment. Thus, finding a proper way to prevent such a phenomenon is of great importance. The aim of this study was to provide a mathematical model to investigate the three-phase flow of oil, water and gas in a riser-pipeline system. To do so, a bulk model was chosen to simulate the pipeline under two scenarios. In the first scenario, gas can penetrate the riser and flow upward whereas, in the second scenario, liquid holdup limits the gas flow in the riser. Moreover, the riser system was modeled with the assumption of a distribution parameter system that used dynamic nodes to evaluate the local conditions. Mass transfer between the oil and gas phase was also estimated by the black-oil approximation. After modeling the riser-pipeline system, gas injection at the riser base was simulated to stabilize the flow and prevent the upcoming issues. In addition, a criterion to determine the amount of the injected gas was proposed. Finally, results obtained from modeling were compared with the results of the OLGA simulation software which showed good agreement.

Naturally fractured reservoir account for 20% of world's oil reserves, in these reservoirs conductivity is mostly in the fracture network while the oil is mostly in the matrix and after primary recovery most of oil remains in the reservoir. Most of secondary or tertiary recovery methods such as water injection or gas injection are not efficient in fractured reservoirs. One of the remedy methods to control and improve volumetric sweep efficiency is foam injection. Foam in porous media is a dispersed gaseous phase within a continuous aqueous phase comprised mainly of thin films known as lamellae. The lamellae are stabilized by adsorption of surfactant at the gas/liquid interfaces. In the paper, experiments were performed to study the pertinent oil displacement mechanisms during gas and foam injection in a transparent fractured porous medium. Transparent material such as glass was used to construct micro models and to study various aspects of fluid displacement at pore scale. By using micro models, the displacement of the fluids can be observed and investigated in terms of micro-geometry and physical characteristics of the presented liquids, gases and solids. The classification of foams in based on their bubble size and gas fraction. The strength of foam is measured by the magnitude of the pressure drop that is generated along the medium. To create a large pressure drop very strong foams, and therefore very small bubbles, are required. Low productivity of gas injection in fractured reservoir leads to use foam instead of gas in order to increase resistance of fracture corridor against the injected fluid and to better control to mobility of gas.

Molecular diffusion is the controlling mechanism for oil recovery from fractured reservoirs with low permeable and low height matrixes during gas injection process. However, the application of conventional models for simulation of molecular diffusion process faces with some limitations. The main purpose of this study is to investigate the performance of different diffusion molecular models for oil recovery from fractured reservoirs during gas injection process and compare the results with a commercial simulator. Therefore, the models are introduced and implemented as a simulator, then the prepared simulator is validated by experimental data. Lastly, the developed simulator is applied for evaluation of CO2 and methane injection in one matrix block. The difference among the results of different models is based on using irreversible thermodynamic for calculating component concentration in gas-oil interface, using matrix form of molecular diffusion coefficients and using chemical potential gradient as the driving force in generalized Fick and Maxwell-Stefan verse classical Fick. In addition, the results of commercial simulator are near classical Fick model results because of same formulation. Also, mole fraction of methane and CO2 and oil viscosity verse time are compared for gas injection. Finally, the result of this work demonstrates that using classical Fick’s law or the commercial simulator for forecasting oil recovery from fractured reservoirs when the molecular diffusion is the main mechanism is not accurate, so generalized Fick and Maxwell-Stefan are more efficient models.

Decreasing reservoir pressure caused by hydrocarbon exploitation is one of the major problems related to oil reservoirs. In order to maintain the current production rate the lost energy should be compensated. Gas injection is a common method for increasing reservoir pressure and is mainly used in SW Iranian oil fields. Reactivation of pre-existing faults is one of the potential risks related to gas injection. In this study, using the analytical method of modified slip tendency, the reactivation possibility of four faults in an SW Iranian oil field has been investigated, and the critical pore pressure is estimated. Results suggest that all the faults are stable in the current stress field, and F2 is the most stable fault that can undergo a maximum pore pressure of 57 MPa before reactivation. Results of fracture stability analysis show that the highest increase in horizontal stress needed for reactivation is for F2. This means that faults with an east-west strike are more stable than the faults with a north east-south west strike in the field.

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.

One of the common methods of enhanced oil recovery in naturally fractured reservoirs is gas injection. The majority of Iranian hydrocarbon reservoirs are fractured reservoirs. Producing mechanisms is different in fractured reservoirs in comparison with conventional reservoirs. Molecular diffusion is one of the mechanisms that along with gravity drainage can increase oil recovery in fractured reservoirs during gas injection. In this work, the effect of molecular diffusion in CO2 and hydrocarbon gas injection as an EOR (enhanced oil recovery) process is investigated using compositional simulation in a single matrix block and a sector model of an Iranian natural fractured reservoir. The effect of the matrix permeability, matrix and fracture permeability difference, matrix porosity, matrix gas-oil capillary pressure and injection gas composition are checked in single matrix blocks, and then the influence of diffusion is investigated on the recovery of the sector model during the CO2 and hydrocarbon gas injection. The results show that molecular diffusion raises oil recovery by increasing the mass transfer rate between the matrix and fracture during miscible gas injection (CO2 and hydrocarbon gas). The low matrix permeability and high gas-oil capillary pressure within the matrix oil make smaller displacement efficiency during gravity drainage. In the sector model, the molecular diffusion increases the ultimate oil recovery by about %2 and %5 in CO2 and hydrocarbon gas injection, respectively by delaying gas breakthrough in an production well and maintaining reservoir pressure.

Asphaltene precipitation from reservoir fluids during oil production is a serious problem resulting in plugging of the formation, wellbore and production facilities. Generally, asphaltene precipitation has only been investigated from thermodynamic approach in literature, and it assumed that precipitation is relatively fast and has no kinetik effects. Without a good understanding of the associated kinetic effects during the precipitation of asphaltenes, the thermodynamic models can provide misleading predictions for asphaltene stability. So, it should be analyzed from two points of view, thermodynamic and kinetics stability. In this study a molar rich gas and CO2 programmed titration technique was used to evaluate the kinetics of gas-induced asphaltene precipitation from Iranian reservoir oil under isothermal and isobaric initial reservoir conditions in a solids detection system (SDS) and with kinetics of polymerization assumption for reaction between asphaltene and gas, the kinetics parameters of reaction is determined. The results show that asphaltene precipitation occurs in 0.9 mol of rich gas and 0.3 mol of CO2 injected per one mol of reservoir oil. Also, the reaction order of CO2 & rich gas is 2.7 times more than reaction order of asphaltene. So in gas injection, the rate of asphaltene precipitation is highly dependant to the volume of gas.

With respect to the fact that most of the Iran oil reservoirs have elapsed their period of natural depletion, the usage of gas injection techniques renders necessary for EOR purposes. The formation of organic precipitates such as asphaltene and its subsequent precipitation over reservoir rock during the gas injection process is considered a critical problem due to causing damage to the formation. Therefore, prior to conducting any industrial gas injection projects, it is necessary to perform experimental research with the same type of reservoir rock/fluid, and then a field-scale project can be implemented, once the analysis of the experimental results and the simulation of the reservoir are completed. In this research, the effect of pressure of injecting natural gas on asphaltene precipitation and alteration of core characteristics is analyzed. Live oil samples from one of the Iran offshore fields were used. The permeability reduction before and after gas injection were determined. In addition, the produced fluid was sampled at different time scales and its asphaltene content was determined using the IP143 standard. Using the mass balance equations, the reduction in core porosity and the power relation between permeability and porosity in the damaged core were established. The results suggest that the asphaltene coagulation and precipitation should increase along with gas injection, which causes permeability reduction. Such damages tend to decrease by lowering pressure, and the analysis indicates the mechanism of precipitation to be of mechanical blockage.

In this work, the MMFH model and Solid model performance in predicting sour gas injection effects on the asphaltene formation and precipitation in crude oils is investigated. The asphaltene is the heaviest and the most polar parts of the crude oil. The changes in pressure, temperature, and/or composition can cause instability of the asphaltene in petroleum system and finally lead to asphaltene precipitation and deposition. Herein, two models, i.e. MMFH and Solid models, are investigated to predict asphaltene instability in three real oil samples. The stability of the models and their compatibility with the experimental and field observation are assumed as the model application comparison basis. First, the model parameters are tuned via the experimental data and then the adjusted models are used for predicting the sour gas injection and pressure effects on the asphaltene precipitation. As it can be seen, the MMFH models is better than the solid model (this model is used in the commercial software for reservoir simulation) in both comparison criteria, namely the model stability and compatibility with the other results.

One of the common methods for reservoir screeining in EOR projects is comparison of prosperous projects is comparison between successfulcarried out projects and available reservoirs in the whole world. Because of lack of similar samples in this method, some of reservoirs are not considered for injection, so casing of another EOR method is necessary. In this paper, at first, by combination of Experimental design and Compositional simulation, rock and fluid effective parameters are detected in N2 and CH4 gas injections for pressure maintenance in reservoirs. Then, indirect and interaction effect of these parameters are analyzed and compared for both gas injections. separately for both gases injection are analyzed and compared. Finally, for estimation of oil recovery factor, empirical correlation is proposed. This correlation is used for primary screening in N2 and CH4 injection projects.

Water vaporization and its impact on the formation productivity and injectivity are important issues dealt with during gas injection into porous media. It is clear that there are many other issues associated with underground gas storage projects but water vaporization and its induced permeability impairment are particularly important issues during gas injection in the candidate reservoir in this work. This paper investigates water vaporization in a candidate reservoir for underground gas storage. It is important to encounter two parameters in this process، which are water saturation reduction and permeability reduction in reservoir rock sample to form salt precipitation. Water saturation reduction causes permeability improvement، but scale formation reduces permeability. According to the results، the medium with higher permeability experiences an improved injectivity during gas injection، while the medium with lower permeability experiences an impaired injectivity. It is worth mentioning that both media suffer from permeability impairment. Finally، injectivity and productivity changes caused by water vaporization differ from case to case depending on the porous medium characteristics and the properties of fluid within the porous medium. Therefore، independent experiments should be conducted for different systems، since there is no accurate formulation to predict the mentioned permeability impairments. Also، special experiments are necessary for different media which are related to pore structure.

The storage and disposal of greenhouse gases in underground aquifer reservoirs is a suitable option for the reduction of these gases in the atmosphere. Understanding the concepts and mechanisms involved in the storage process such as natural convection and their impact on the amount of time required for storage is very important. Natural convection is an effective mechanism to increase the solubility of carbon dioxide in the storage process. In this study، the injection of carbon dioxide (a major component of greenhouse gases) into aquifer has been studied and numerically simulated. The effect of aquifer salinity on the onset of natural convection phenomena has been studied. To this end، six scenarios revolving around the change of aquifer salt and keeping the other variables involved constant in the process are studied. The results reveal a direct effect of salinity on the activation of natural convection. Increasing aquifer salinity delays the onset of natural convection. As a result، the cumulative amount of gas dissolved after the specified time will be less.

This study investigates asphaltene precipitation and deposition due to miscible/immiscible gas injection as well as its impact on rock properties and gas injectivity in one of Iranian southwestern oilfields. Displacement characteristics like GOR, breakthrough time and oil recovery are also studied.According to experiments, induced miscible/ immiscible gas injection permeability impairments are negligible. Therefore, gas injection has no negative impact on the formation regarding asphaltene precipitation and deposition. Ultimate oil recoveries are about 73% and 66% for miscible and immiscible gas injections respectively. These approximate oil recoveries are obtained in laboratory core scale representing microscopic sweep efficiencies then to convert it to field recoveries it should be multiplied by macroscopic ones to be experienced in the field application.

A number of forced gravity drainage experiments have been conducted using a wide range of the physical and operational parameters, where the type, length and permeability of the porous medium as well as oil viscosity and injection rate were varied. Results indicate that an increase in Bond number has a positive effect on oil recovery whereas capillary number has an opposite effect. Furthermore, it was found that use of each number alone is insufficient to obtain a satisfactory correlation with recovery. A combined dimensionless group is proposed that combines the effect of all three forces. The exponent of the Bond number in the proposed group is larger than the capillary number suggesting a larger importance for the former. We then show that the same group provides a good correlation for recovery from addition experiments conducted in this work and another set of experiments in the literature.

In the present study, injection of different gases in a fractured reservoir of Iran were simulated by various techniques. Scince natural, nitrogen, separator and miscible gases were injected, also an economic evaluation was done in this field. Results indicate that the miscible gas exhibited the highest recovery factor (57.2%). This value for natural gas N2 were nearly the same. Using the Eclipse commercial simulator, the composition of black oil was simulated and economic calculations were carried out by measruing the amount of inection gas of the reservoir. The recovery factor of two gases were almost the same, however amount of methane is lower than N2. Based on economic calculations, it was revealed that methane is the most suitable injection gas for this field.

In this work, injection of CO2 as the main constituent of flue gas into an oil reservoir is studied. The Peng Robinson (PR) equation of states (EOS) was used to investigate phase behavior of flue gas/crude oil system. After tuning the (EOS), effect of impurities on the minimum miscibility pressure (MMP), saturation pressure, and swelling factor of reservoir oil was investigated. Results show that the PREOS can predict the saturation pressure with good accuracy. Also, such components as N2, CO, and NO increase saturation pressure and reduce oil swelling factor, while the sulfur oxides and NO2 have a reverse effect. The maximum allowable amount of each component in the injecting flue gas into reservoir is determined.

This paper presents a new empirically derived correlation for estimating the minimum miscibility pressure required for multicontact miscible (MCM) displacement of reservoir petroleum by hydrocarbon gas flooding. Only few empirical correlations exist for determining the MMP.These correlations are often used to estimate the MMP without considering the composition of the injected gas. On the other hand these correlations are based on a limited set of experimental data which are not quite applicable. In addition, in such correlations the complex condensing/vaporizing displacement process is not regarded. In this study, however, the derived correlation investigates the influence of the vaporizing/condensing drive mechanism and oil and gas composition on gas miscibility pressure. By comparing the calculated MMPs from the improved correlation data with currently used correlations and experimentally measured data, it was found that the novel correlation is significantly more accurate than other correlations.

In the fractured carbonate reservoirs the reimbibation process in the gas invaded zone is dominating on producing process. When the gravitational forces exceed the capillary forces, the matrix blocks, which are surrounded by gas, will release their oil. This oil imbibed by below block if possible up to produced. In this study, we used some experiment for finding the relations and effective parameters in reimbibatin process.