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。     

高压注烃类气体过程中沥青质初始沉淀压力试验研究

为预防注烃类气体提高采收率过程中产生沥青质沉淀,对沥青质初始沉淀压力进行了试验研究.在分析注烃类气体过程中沥青质沉淀机理的基础上,通过自主研发的固相沉积激光探测装置,采用透光强度法测定了原油样品在不同温度下高压注气过程中沥青质的初始沉淀压力,并确定了沥青质沉淀的深度.试验得出,原油沥青质初始沉淀压力随温度升高而下降,测得44,80和123 ℃温度下原油的沥青质初始沉淀压力分别为44.1,39.7和35.2 MPa;每注入物质的量分数为1%的烃类气体,试验油样的沥青质初始沉淀压力升高0.5~0.6 MPa;井筒温度压力曲线与沥青质沉淀相包络线相结合预测井筒中出现沥青质沉淀的深度在1 800 m左右,与现场情况吻合较好.研究表明,原油中沥青质初始沉淀压力与注气量之间呈线性关系,可为现场注气驱油预防和清除沥青质沉积物提供理论依据.      

低温CO2驱替含沥青质原油模型化研究

为进一步了解CO2注入过程中含沥青质原油在注气井近井地带中的渗流规律和温度变化对沥青质沉淀的影响,在前人研究的基础上,综合考虑沥青质的沉积、能量的转化及CO2温度的变化,建立了注CO2含沥青质原油数值模型。以某实例油田为例,将该模型应用于注气井近井地带模拟,结果表明：低温CO2驱油过程存在液相驱替,并随注气压力的增大,温度的影响范围不断扩大;沥青质沉积主要发生在近井地带;低温CO2引发的沥青质沉淀比模拟的常温CO2引发的沥青质沉淀小。在模型计算过程中,将低温CO2驱油效率分两方面讨论,作出四类基本低温驱油机理图,认识到合理的注入参数选取是关键。     

超临界CO2动态混相驱过程机理研究

以国内CS油田注CO2混相驱典型实例为基础,在油藏地层流体注CO2驱膨胀实验和细管最小混相压力实验拟合基础上,建立一维组分注气驱细管模型.应用所建立的模型,模拟研究CO2注入过程中油气两相组成、油气两相黏度、密度和界面张力等动态特性参数沿注气井到生产井距离的变化规律.以及注气量和注气压力对动态特性参数的影响规律.研究结果显示:CO2在原油中的溶解能力强,工程混相条件下,摩尔含量达到0.7.注入CO2抽提原油中的中间烃,甚至C19+以上的重烃,与地层油在前缘达到混相.CO2注入量增加,混相带增长,CO2波及区域增加,有利于驱油效率增加.随着注入压力的提高,从非混相到混相,CO2在地层油中的溶解量增加,界面张力降低,油的黏度降低.达到混相后,继续增加压力对驱油影响变小.     

致密砂岩油藏CO_2驱固相沉积规律及其储层伤害特征

沥青质及金属无机沉淀对致密储层的伤害是注CO_2驱替中不可避免的问题。为探究沥青质及无机沉淀对储层的伤害机理,以鄂尔多斯盆地延长组长7储层为例,在明确(非)混相压力下原油中CO_2含量与沥青质沉淀量关系的基础上,通过开展CO_2驱替长岩心实验,研究了CO_2非混相和混相驱过程中沥青质和无机沉淀对储层的伤害特征,评价了有机和无机沉淀对储层渗透率和孔隙度的伤害程度。结果表明:当原油中CO_2含量达到临界值时,沥青质开始沉淀,沉淀量随CO_2含量的增加先快速上升后趋于稳定。混相压力下沥青质沉淀对渗透率和孔隙度的伤害程度均大于非混相。沥青质在混相压力下大量沉积部位为长岩心中后部,而在非混相压力下主要在长岩心前中部。当岩心中沥青质沉淀量达到最大时,后续岩心中的沥青质沉淀量将会逐渐降低,对渗透率造成的伤害也会逐渐减小。无机沉淀在非混相压力下对前中部岩心的渗透率伤害程度大,而在混相压力下则对中后部岩心的渗透率伤害程度大;无机沉淀对孔隙度的影响规律与对渗透率存在差异,主要与溶蚀作用及无机沉淀产生的位置有密切关系。若目标油藏采用非混相驱开发,预防重点为无机沉淀,预防沉淀部位为注入端附近储层;若采用混相驱开发,则预防重点为有机沉淀,预防沉淀部位为产出端附近储层。     

利用相平衡理论预测原油沥青质沉淀率

国内外大量CO2驱矿场实践均发现了沥青质沉淀现象,沥青质沉淀会吸附于孔隙表面、堵塞孔隙喉道,进而导致CO2驱油井产量的下降。为了准确计算CO2驱过程中的沥青质沉淀率,采用状态方程描述气-液相平衡,用正规溶液理论描述固相沥青质的非理想性,建立气-液-固三相相平衡热力学模型,结合物料守恒方程进行油气体系的相平衡计算,进而预测沥青质的沉淀率。运用该模型对某CO2驱原油体系进行了相平衡闪蒸计算,得到沥青质的沉淀率,与实验值相对比平均误差在允许范围之内。     

注天然气油井沥青质析出规律研究

目的 解决东河区块原油在注气开采过程中沥青质沉积堵塞井筒问题.方法 采用高温高压固相沉积规律测试装置,基于光散射理论,研究了温度、压力、气油比等因素对沥青质析出特征的影响.结果 温度升高会增加沥青质在原油中的溶解度,促进原油稳定;等温降压过程中,沥青质随着压力降低逐渐析出,在泡点压力附近达到最大析出量,发生沥青质沉积堵...     

二氧化碳对原油中胶质沥青质作用的可视化研究

为明确CO_2驱油过程中胶质沥青质沉淀原因,从原油中分离出胶质和沥青质分别与正庚烷和甲苯配置成胶质模拟液和沥青质模拟液,并用2种模拟液分别与CO_2组成不同摩尔分数的二元体系,通过高压显微固相沉淀实验,观察2个体系中固相颗粒的变化规律,探究CO_2对胶质沥青质的作用机理。实验表明:胶质模拟液-CO_2体系中CO_2的摩尔分数达到12.50%时,胶质颗粒发生沉淀,随CO_2含量增加沉淀半径增大;当CO_2摩尔分数增至35.00%时,胶质沉淀开始沉积,发生聚集;当CO_2的摩尔分数大于50.00%时,降低体系压力至泡点压力以下,CO_2先从正庚烷液相中析出,后从液状胶质聚集体中析出。沥青质模拟液-CO_2体系在泡点压力处颗粒半径最大;随CO_2含量增加,沥青质颗粒沉淀半径增大;当CO_2摩尔分数增至60.00%时,沥青质颗粒发生聚集形成沉积。该项研究对于分析CO_2驱过程中胶质沥青质对沉淀的贡献情况、沉淀生成的主要原因以及如何减小沉淀对生产造成的伤害具有重要指导作用,对于增强原油的运移能力进而提高储层原油采收率具有理论指导意义。     

CO2混相驱储层吸气能力预测

为了预测注 CO2时储层吸气能力,为 CO2驱配注及注气参数的优化设计提供理论基础,在前人研究的基础上,建立了二维 CO2混相段塞驱物理模型和数学模型,考虑混相段塞对注气过程的影响,经理论推导建立了 CO2混相驱吸气能力计算模型。模拟计算结果显示: CO2混相驱注入压力与注气速度近似成线性关系,且注入压力越大,注气速度也越大;地层压力呈阶梯状分布,表现为 3个不同的压力梯度,且超临界 CO2区和混相区的压降较小,压力主要消耗在地层原油渗流区;吸气能力随累积注气量和段塞长度的增加而不断增强,吸气指数随累积注气量的增加呈对数型增长,随段塞长度的增大呈线性增长。     

蒸发气驱与凝析气驱过程组分变化计算模拟及分析

为了优化注气驱方案设计,运用混相驱技术提高采收率,基于立方型状态方程和闪蒸计算理论,建立了蒸发气驱和凝析气驱烃类体系相态闪蒸计算模型。运用给定的温度与压力条件、原油组分和注入气组分,模拟多级接触混合过程中油气组分的变化,分析注气混相驱的动态变化,进而定量描述气液两相平衡的动态过程。通过绘制拟三元相图直观展示模拟注气过程中油气组分的变化,以判别注入气能否与地层原油实现混相或达到近混相状态。模拟结果表明:向原油中注入较轻质的气体,蒸发气驱机理主导气驱过程,但由于油气组分不匹配无法最终实现混相;向原油中注入重质组分较多的气体,混相机理复杂,应当是凝析和蒸发双重机理共同作用形成的近混相。建立的模型和编制的模块可以方便地应用于任意油气混相的实例计算,为实际开采提供重要参考。     

An Investigation of Asphaltene Precipitation During Natural Production and the CO2 Injection Process

Some of Iranian oil reservoirs suffer from operational problems due to asphaltene precipitation during natural depletion, so widely investigation on asphaltene precipitation is necessary for these reservoirs. In this study, a reservoir that is candidate for CO₂ gas injection process is selected to investigate asphaltene precipitation with and without CO₂ injection. In this case, asphaltene precipitation is monitored at various pressures and reservoir temperature. Then, a series of experiments are carried out to evaluate the amount of precipitated asphaltene by injection different molar concentrations (25%, 50%, and 75%) of CO₂. The results show that during primary depletion the amount of precipitated asphaltene increases with pressure reduction until bubble point pressure. Below the bubble point the process is reversed (i.e., the amount of precipitated asphaltene at bubble point pressure is maximum). The behavior of asphaltene precipitation versus pressure for different concentrations of CO₂ is similar to primary depletion. Asphaltene precipitation increases with CO₂ concentration at each pressure step. In the modeling part, solid model and Peng-Robinson equation of state are employed which show a good match with experimental results.     

A Comparison of Natural Depletion and Different Scenarios of Injection in the Reservoir From the Beginning of Oil Production

This research comprises natural depletion, associate, and CO2 gas injection with regard to asphaltene precipitation and permeability reduction. For the sake of achievement these goals experiments were undertaken by core flood and asphaltene static apparatus. Natural depletion was performed at 4500, 3050, 2250, 1450, and 900 Psig and it has been seen maximum amount of asphaltene precipitation located at saturation pressure. The results demonstrate that asphaltene precipitation during natural depletion was higher than CO2 and associate gas injection. Also it was seen asphaltene precipitation rate during CO2 and associate gas injection was lower than natural depletion. Based on results, amount of asphaltene precipitation was differing according to type of gas. The results of the study indicate asphaltene precipitation during CO2 injection was more than associate gas injection. Finally it was seen the permeability reduction during associate was less than CO2 and natural depletion for this kind of Iranian carbonate sample.     

Prediction of Asphaltene Precipitation during Pressure Depletion and CO2 Injection for Heavy Crude

Abstract

In this work, a thermodynamic approach is used for modeling the phase behavior of asphaltene precipitation. The precipitated asphaltene phase is represented by an improved solid model, and the oil and gas phases are modeled with an equation of state. The Peng-Robinson equation of state (PR-EOS) was used to perform flash calculations. Then, the onset point and the amount of precipitated asphaltene were predicted. A computer code based on the solid model was developed and used for predicting asphaltene precipitation data reported in the literature as well as the experimental data obtained from high-pressure, high-temperature asphaltene precipitation experiments performed on Sarvak reservoir crude, one of Iranian heavy oil reserves, under pressure depletion and CO₂ injection conditions. The model parameters, obtained from sensitivity analysis, were applied in the thermodynamic model. It has been found that the solid model results describe the experimental data reasonably well under pressure depletion conditions. Also, a significant improvement has been observed in predicting the asphaltene precipitation data under gas injection conditions. In particular, for the maximum value of asphaltene precipitation and for the trend of the curve after the peak point, good agreement was observed, which could not be found in the available literature.     

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.     

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.     

Modeling Asphaltene Precipitation Under Gas Injection and Pressure Depletion Conditions

Asphaltene precipitation is a major problem during primary oil production and enhanced oil recovery in the petroleum industry. In this work, a series of experiments was carried to determine the asphaltene precipitation of bottom hole live oil during gas injection and pressure depletion condition with Iranian bottom hole live oil sample, which is close to reservoir conditions using high pressure-high temperature equilibrium cell. In the majority of previous works, the mixture of recombined oil (mixture dead oil and associated gas) was used which is far from reservoir conditions. The used pressure ranges in this work covers wide ranges from 3 to 35 MPa for natural depletion processes and 24–45 MPa for gas injection processes. Also, a new approach based on the artificial neural network (ANN) method has been developed to account the asphaltene precipitation under pressure depletion/gas injection conditions and the proposed model was verified using experimental data reported in the literature and in this work. A three-layer feed-forward ANN by using the Levenberg-Marquardt back-propagation optimization algorithm for network training has been used in proposed artificial neural network model. The maximum mean square error of 0.001191 has been found. In order to compare the performance of the proposed model based on artificial neural network method, the asphaltene precipitation experimental data under pressure depletion/gas injection conditions were correlated using Solid and Flory-Huggins models. The results show that the proposed model based on artificial neural network method predicts more accurately the asphaltene precipitation experimental data in comparison to other models with deviation of less than 5%. Also, the number of parameters required for the ANN model is less than the studied thermodynamic models. It should be noted that the Flory and solid models can correlate accurately the asphaltene precipitation during methane injection in comparison with CO₂ injection.     

Developing a Scaling Equation as a Function of Pressure and Temperature to Determine the Amount of Asphaltene Precipitation

A simple and applicable scaling equation as a function of pressure, temperature, molecular weight, dilution ratio (solvent), and weight percent of precipitated asphaltene has been developed. This equation can be used to determine the weight percent of precipitated asphaltene in the presence of difference precipitants (solvents) and the amount of solvent at onset point. Since increasing the pressure of crude oil decreases the amount of asphaltene precipitation, the effect of reservoir pressure has been taken into account in developing this equation. The results obtained by using this equation are substantially different and more accurate from other developed scaling equations for asphaltene precipitation. By considering the effect of reservoir pressure in developing the scaling equation and application of a genetic algorithm, the unknown parameters of the scaling equation are simultaneously and without any reservation obtained. The most important application of this unique equation is in the determination of critical point of asphaltene precipitation, known as onset point, and asphaltene precipitation in gas injection operations for enhanced oil recovery. The results predicted using the scaling equations are compared with the authors' experimental and literature precipitation data and it is shown that they are in good agreement with our experimental data. The scaling equation can be used in the design of gas-injected reservoir to prevent precipitation of the asphaltene aggregates in the reservoir.     

气液固三相相平衡计算

根据对油气烃类体系相态特征的一般性认识与文章中提出的沥青组分特征化方法,导出了与之相应的有其自身特殊性的气液沥青三相相平衡物料平衡方程组.用考虑沥青沉降三相闪蒸数值算法,能对沥青沉降进行有效的量化模拟计算.此外,文章提出了大的交互作用系数可以描述沥青与原油中轻烃不相溶性的观点.结合实例计算,给出了沥青质参考逸度的计算、饱和压力和沥青沉降量的拟合方法.