The Effect of Temperature and Pressure on the Reversibility of Asphaltene Precipitation

A lot of hindrances are seen in petroleum operation, production, and transportation as a results of factors that related to asphaltene precipitation. It has great importance to investigate the reversibility of asphaltene precipitation under changes of effective factors on thermodynamic conditions such as pressure, temperature, and composition. In the present work the reversibility of asphaltene precipitation under changes of pressure and temperature was investigated for two kind of Iranian heavy oil. The stability test shows these samples are located at unstable region in aspect of asphaltene precipitation. The experimental procedure includes two parts, (a) decreasing pressure from initial reservoir pressure to near saturation pressure and surveying asphaltene content hysteresis with redissolution process at reservoir temperature, and (b) investigation of precipitated asphaltene in both precipitation and redissolution processes at different temperature and reservoir pressure. At each step IP143 standard test was used to measure precipitated asphaltene. It was concluded that above bubble point pressure, asphaltene precipitation is nearly reversible with respect to pressure for both samples and it was partially reversible with respect to the temperature for sample A, and accordingly pressurizing is acceptable method for solving the problem in both heavy asphaltenic crude oil samples and increasing temperature is acceptable method for solving asphaltene problem in crude oil sample A. Also density measurement of flashed oil confirmed that there is a little hysteresis in asphaltene content during redissolution and precipitation processes.     

Methodology for Predicting the Phase Envelope of a Heavy Crude Oil and Its Asphaltene Deposition Onset

Abstract

We have presented general ideas to develop a new theoretical methodology, based on molecular simulation and equations of state, for obtaining the phase envelope and to predict pressure, volume, temperature (PVT) conditions of asphaltene precipitation by only taking into account the composition of the heavy crude oil and an asphaltene average molecular structure. Those results show that asphaltene precipitation is a reversible thermodynamic process. The precipitated phase is a liquid phase which consists of mainly asphaltene and some heavy fractions from the crude. This methodology can be applied to find complete phase diagrams of different crude oils based on an asphaltene average molecular structure and the composition of crude oil.     

Prediction of asphaltene precipitation during gas injection

Maintaining the flow of multiphase fluid from the reservoir to the surface has been an important issue with wide economic importance for the petroleum industry. Asphaltene precipitation due to change in temperature, pressure, and composition of oil can adversely affect the oil flow to the surface by reducing the available diameter of the tubing. In this study, the precipitation of asphaltene from an Iranian crude oil was investigated. To do our study, through information about asphaltene instability in the live oil during both natural depletion and gas injection conditions about oil sample from Iranian oil field was gathered. Then, the solid model and scaling model were utilized to predict the weight percent of precipitated asphaltene at a wide range of the pressure and temperature. Results of the work revealed that both models predict the increase in weight percent of precipitated asphaltene when lean gas injected to the live oil at the maximum point of asphaltene instability. In addition, the study showed that both models are capable of predicting the experimental data of asphaltene precipitation; while scaling modeling is more reliable when the gas is injected to the oil.     

Prediction of asphaltene precipitation by the extended Flory–Huggins model using the modified Esmaeilzadeh–Roshanfekr equation of state

Asphaltene precipitation is caused by a number of factors, such as the variation of pressure and temperature, the change in composition and the mixing of oil with diluting solvents. The deposition of asphaltene precipitation is one of the main problems with the oil industries, appearing in the well bore, the well tubing and the refining processes. This causes an increase in the operating costs and imposes the costs of cleaning and washing well tubing as well. Therefore, it would be economically beneficial to know under what conditions and to what amount the asphaltene precipitates.In this paper, a model is presented based on the Flory–Huggins theory of polymeric solutions. Because the interaction parameter term plays a key role in the asphaltene precipitation, a correlation is proposed to account for the effect of the solvent ratio in addition to molecular weight. Several adjustable parameters in terms of the interaction parameter are determined in this work using a series of experimental precipitation data from a crude oil sample of a field located in the southwest of Iran (oil sample 1), and applying a robust optimization method (the differential evolution). Regarding the influence of the solubility parameter on the accuracy of the final results, a comparison is made between the m-ER, PR and the SRK EOSs. Finally, the obtained results from the comparison between the asphaltene precipitation amounts of various solvents and the existing experimental values for another group of data from oil sample 1, and two other oil samples verify the accuracy of the presented model.     

An Experimental Investigation of Asphaltene Precipitation During Natural Production of Heavy and Light Oil Reservoirs: The Role of Pressure and Temperature

Abstract

Many oil reservoirs encounter asphaltene precipitation as a major problem during natural production. In spite of numerous experimental studies, the effect of temperature on asphaltene precipitation during pressure depletion at reservoir conditions is still obscure in the literature. To study their asphaltene precipitation behavior at different temperatures, two Iranian light and heavy live oil samples were selected. First, different screening criteria were applied to evaluate asphaltene instability of the selected reservoirs using pressure, volume, and temperature data. Then, a high pressure, high temperature filtration (HPHT) setup was designed to investigate the asphaltene precipitation behavior of the crude samples throughout the pressure depletion process. The performed HPHT tests at different temperature levels provided valuable data and illuminated the role of temperature on precipitation. In the final stage, the obtained data were fed into a commercial simulator for modeling and predicting purposes of asphaltene precipitation at different conditions. The results of the instability analysis illustrated precipitation possibilities for both reservoirs which are in agreement with the oil field observations. It is observed from experimental results that by increasing the temperature, the amount of precipitated asphaltene in light oil will increase, although it decreases precipitation for the heavy crude. The role of temperature is shown to be more significant for the light crude and more illuminated at lower pressures for both crude oils. The results of thermodynamic modeling proved reliable applicability of the software for predicting asphaltene precipitation under pressure depletion conditions. This study attempts to reveal the complicated role of temperature changes on asphaltene precipitation behavior for different reservoir crudes during natural production.     

An experimental study on electrical effect on asphaltene deposition

Asphaltene generally existed in colloidal form in cruds and will precipitate in non-equilibrium conditions. Asphaltene instability may take place in the reservoir leading to permeability damage and contributing to flow restriction issues. It may also occur in production strings and surface facilities causing pipe blockage. Any change in oil composition or pressure and temperature at any stage of production will destabilize crude oil producing asphaltene precipitation. In this paper, the stability of target crude oil under the influence of a direct current and contacting with polar fluid, water, is investigated. The amount of the asphaltene deposit and its electrical charge at various operating conditions are investigated. The fact that deposits form on the anode surface proves that asphaltene particles possess a positive charge. The amounts of asphaltenes precipitation were increased considerably by increasing water as polar component.     

Modeling of Coprecipitation of Resin and Asphaltene in Crude Oil by Association Equation of State

Abstract

Resin content is an effective parameter that has adverse effect on precipitation of asphaltene in crude oil. Fluctuations in temperature, pressure, or oil composition disturb the chemical equilibrium in a reservoir, which results in coprecipitation of resin and asphaltene. In this work, coprecipitation of resin and asphaltene has been modeled using an association equation of state (AEOS) in which asphaltene and resin are considered associate components of oil. According to association fluid theory, the total compressibility factor is assumed to be the sum of physical and chemical compressibility factors. Liquid–liquid and liquid–vapor equilibrium calculations are accomplished with the assumption that asphaltene and resin do not contribute in the vapor phase. Comparison of experimental asphaltene precipitation with that obtained from the model developed proves the acceptability of the proposed model.     

Experimental and Modelling Investigations of Asphaltene Precipitation During Pressure Depletion and Gas Injection Operations

Asphaltene precipitation problems manifest themselves in different stages of oil reservoirs production. Experimental and modeling investigations are, therefore, employed as promising tools to assist in predictions of asphaltene precipitation problems and selection of proper production facilities. This study concerns experimental and modeling investigations of asphaltene precipitation during natural production and gas injection operations for a heavy Iranian crude oil at reservoir conditions. First, with design and performance of high pressure–high temperature experiments, asphaltene precipitation behavior is comprehensively investigated; the effects of pressure and temperature are fully studied during pressure depletion tests and the role of injection gas composition on precipitation is described in gas injection experiments. In the next stage, the obtained experimental results are fed into a commercial simulator to develop the asphaltene precipitation model. The results for the pressure depletion experiments indicate that the maximum amount of asphaltene precipitation takes place at fluid bubble point pressure. Increase in the temperature, as seen, causes to reduce the amount of precipitation for the entire range of pressures. For gas injection experiments, the onset of precipitation for CO₂, associated, and N₂ gases takes place at around 0.20, 0.28, and 0.50 gas to mixture mole ratios, respectively. Carbon dioxide shows the highest asphaltene precipitation values and nitrogen has the lowest amounts for the whole range of gas mole fractions. Finally, the results for modeling indicate successful asphaltene precipitation predictions for both pressure depletion and gas injection processes.     

注气对固溶物沉淀影响的研究与应用

注气采油是提高原油采收率的主要方式之一,在此过程中准确描述含有沥青质等高分子有机固相物质的油气体系相平衡十分必要。为此,将沉淀的沥青质视为固相,假设标准状态下必须有沥青质沉淀,将标准状态压力和温度引入沥青质固相逸度计算,并同时考虑了标准状态压力和温度对沥青质固相逸度的影响,建立了能模拟沥青质沉淀的气、液、固三相相平衡热力学模型。据该模型计算的结果表明:①能通过比较液相沥青质逸度和固相沥青质逸度大小来判断固相沥青质沉淀的出现。②当注入某油的气体为烃类混合气体时,烃类混合气体的添加使得含沥青质原油的组分发生变化;温度相同时,注气浓度越高,沉淀的压力越大;浓度相同时,温度越低,沉淀的压力越大;当沉淀量一定时,随着注气浓度增加,油品的饱和压力随之增大;相同注气浓度下,当压力高于饱和压力时,随着压力增大,沉淀量减少。③在温度不变的情况下,注入某油的气体为CO2时,其沥青质沉淀量是注CO2浓度的函数且随着CO2浓度的增加,固相(沥青质)的沉淀量不断增大。④在注气驱油过程中,气体的注入极易引发含沥青质原油中沥青质等重质有机物的沉积。     

气-液-固三相相平衡热力学模型预测石蜡沉积

在油气开采过程中,当体系的温度、压力或组成等热力学条件发生改变时,油气体系内的蜡质、胶质、沥青质等有机固相物质将会从体系中析出而沉积,给油气田生产带来严重的危害.采用状态方程和溶液理论相结合而建立了能模拟石蜡沉积的气液固三相相平衡热力学模型.根据正规溶液理论描述固相混合物的非理想性,采用状态方程描述气相和液相的相态.运用该模型对某一含气原油进行了蜡固相沉积模拟计算,计算结果表明,压力对蜡沉积有较大的影响,压力对蜡沉积点温度的影响在低于饱和压力下比高于饱和压力下的影响更为显著.