煤粉挤压流型输送特性

具有高固气比、低流速的挤压流型气固两相输送技术已在高技术领域的工程中得到应用.本文从实验和理论两方面研究了煤粉挤压流型的输送特性.试验的范围是:输送的固气比 m=280-770,空隙率8=0.37-0.58,单位面积管道煤粉输送流量 G_s/A=96-453g/s·cm~2.理论上用剪切应力模型进行分析,得到单位管长的压力降计算式.理论预测与实验结果是一致的.     

电爆炸丝的电气特性

根据金属导体电阻与比作用量的关系和A.Hobson提出的金属丝阻抗随时间的变化规律分别建立了2种仿真模型研究电爆炸丝断路开关的电气特性;测量了电爆炸过程中金属丝两端的电压,结果表明:A.Hobson模型只有在电爆炸丝汽化前有效;电阻率-比作用量模型适用于整个电爆炸过程的宏观描述.因此,对含电爆炸丝元件的电路仿真模拟采用...     

水平管内气液两相螺旋流实验研究

为研究水平管内气液两相螺旋流的流动特性,开展了以空气和水为实验介质,含气率为10％～90％,气相折算速度为0.01～3.4m/s,液相折算速度为0.05～2.7m/s的气液两相螺旋流实验.利用高速摄影机记录并参考借鉴相关研究结果分析和划分了不同工况下的流型;给出了水平管内气液两相螺旋流的流型图;研究了不同流速、不同起旋参数对流动特性(压降、流型衰减、螺距、螺旋直径以及流型转换边界等)的影响.实验结论如下:将水平管内气液两相螺旋流的流型划分为螺旋波状分层流、螺旋泡状流、螺旋团状流、螺旋线状流、螺旋轴状流、螺旋弥散流6种;将绘制的流型图与经典Mandhane流型图进行对比,出现了线状流、弥散流和轴状流3种新的流型;泡状流的分布基本不变,层状流的分布发生变化,当气相流速在2m/s以内时是线状流和轴状流,而不是层状流;随着液相流速的提高,管内两相流动的损失逐渐变大,流型的衰减程度变弱,螺旋扭矩逐渐变大,螺旋直径逐渐变小.另外,随着叶轮角度的增大或者随着叶片面积的减小,流型转换边界均向进气量增大的方向推移.而当进气量一定时,随着叶轮角度的增大或者随着叶片面积的减小,同样流型转换边界趋于进水量增大的方向.最后,随着起旋角度的增大或者随着叶片面积的减小,压降均有逐渐变大的趋势.     

可降解性表面活性剂体系下水平管内气液两相螺旋流实验研究

通过气液两相螺旋流实验仪器,研究具有可降解性的天然椰子油新型添加剂对于气液两相螺旋流流型影响以及流型的转变规律,并与表面活性剂十二烷基苯磺酸钠(SDBS)进行对比研究。实验工况设定为:实验介质为空气和水,含气率10%~90%,气相折算速度0.01~4.0m/s,液相折算速度0.01~4.0m/s,表面活性剂采用从植物提取的可降解性椰子油和SDBS,起旋装置为叶轮。实验观察到天然椰子油对于螺旋轴状流、螺旋团状流、螺旋弥散流转换特性的影响与SDBS的效果相类似,该三种流型发生条件相比于以往都有所提前,且存在范围被拓宽。浓度为500ppm时椰子油体系下的主要流型为螺旋弥散流,而SDBS体系下则以螺旋团状流为主。     

垂直向下管内两相流泡状-弹状流型转换研究

建立实验系统,在维持管道出口压力为0.2MPa的条件下,对内径分别为15mm、25mm、40mm、65mm的垂直向下管内空气-水气液两相流动进行了实验研究,获得了两相流泡状-弹状流型分布。实验研究发现:管径对于泡状流与弹状流流型特征有较大影响,并且进一步影响流型转换边界,随着管径增加,泡状流-弹状流的流型转换边界向折算气速减小的方向移动。基于理论推导及实验数据,建立了垂直向下管内气液两相流泡状流-弹状流流型转换预测模型,该模型对本文实验工况条件下的垂直向下管内空气-水气液两相流流型转换具有良好的预测效果,预测模型的计算结果与实验数据之间的误差小于10%。     

基于三维网络模型的水驱油微观渗流机理研究

利用逾渗网络模型在微观水平进行随机模拟来研究水驱油的微观渗流规律,通过模型计 算结果与油水稳态相对渗透率驱替实验结果对比验证了网络模拟的有效性. 在此基础上,讨 论了在不同润湿条件下、水驱不同阶段的剩余油微观分布规律. 将剩余油分布形态归纳为4 种状态：孤粒/孤滴状、斑块状、网络状和油水混合状态. 研究表明,网络状剩余油的块数 较少,但所占体积比例较大. 随着剩余油饱和度的降低,最大网络状油所占孔隙数减少,剩 余油饱和度在40{\%}$\sim$50{\%}附近开始以较快速度减少. 润湿性不仅影响驱油效率,也影响剩余油分布形态. 在驱替过程中,剩余油分布总的变化趋势是逐渐趋于分散.     

弱界面压电／压磁层状结构中的SH波

研究了弱界面压电层/压磁半空间结构中SH波的频散特性, 界面性能由 ``弹簧'模型表征, 压电层的表面考虑电学短路和电学开路两种边界条件. 推导了显函形式的 频散方程, 并结合算例分析了界面性能和电学边界条件对SH波传播特性的影响. 数值结果表 明: 弱界面降低了SH波传播的相速度; 对于短路电边界条件, 弱界面可以使一阶模态的相速 度小于B-G表面波的速度; 对于开路电边界条件, 一阶模态的相速度总是大于剪切体波的波 速.     

微喷混合问题的初步研究

基于颗粒轨道模型,采用二元碰撞假设,在二维拉氏流体动力学程序上实现了气-粒两相混合程序的研制.使用气-粒两相混合程序对不同充气压力条件下的微喷混合问题进行了数值模拟,给出了喷射场随时间演化过程,计算结果与实验定性一致.     

变开度岩体裂隙多相渗流实验与有效渗透率模型

岩体裂隙的有效渗透率是描述岩体非饱和或多相渗流的关键参数,而裂隙开度是影响有效渗透率的重要因素.通过自主研发的粗糙裂隙多相渗流可视化实验平台,针对天然岩体裂隙复制而成的裂隙模型开展变开度条件下的多相渗流可视化实验,研究开度变化对多相渗流流动结构以及有效渗透率的影响.研究表明:非湿润相流体运动通道,在低流量比条件下呈现出气泡流流动结构,而在高流量比条件下呈现较为稳定的通道流流动结构.随着开度的增加,非湿润相流动通道的分支变少、等效宽度增加,两相流体的有效渗透率均增大,流动结构趋于稳定.可视化结果还阐明了柱塞流流动结构下,两相流体交替占据裂隙空间的竞争机制:当非湿润相流体通道由连续转变为不连续时,裂隙进出口压差显著增加;反之,当该通道由不连续转变为连续时,压差显著减小.最后,基于分形理论以及渗透率统计建模方法,建立了考虑开度效应的岩体裂隙多相渗流有效渗透率理论模型,并通过实验测定的有效渗透率数据验证了该模型的正确性与有效性.     

不同界面计算方法对液滴在电场作用下变形数值模拟精度的影响

液滴在电场作用下的变形是电流体动力学的基础课题之一,表面张力的计算精度对液滴变形量的模拟结果有重要影响。本文以开源计算流体动力学平台OpenFOAM的VOF模型为框架,研究了MULES和isoAdvector两类界面更新算法与相分数梯度和RDF函数两类曲率算法对电场作用下液滴变形模拟精度的影响。研究表明,isoAdvector算法相比MULES算法对网格密度的要求更低,但其耦合相分数梯度算法计算表面张力的误差较高。isoAdvector算法耦合RDF函数算法计算误差较低,并且在使用轴对称网格时,只有该算法能够同时处理液滴平行于电场和垂直于电场方向的变形,得到的数值结果与解析解吻合较好。     

水平管内油——水两相流动压降规律的实验研究

设计和建造了内径为26．1mm,长30m的水平不锈钢多相流实验环道,利用白油与水进行了油－水两相流流型和压降实验。本文针对各种流型,分析了油－水两相流动的压降规律和油－水混合液有效粘度,指出有效粘度法只适用于油－水分散流型的压降预测,对于分层流型式其它混合流型使用合适该种流型的压降预测模型来计算压降。研究结论对油田现场的油水混输管路的经济运行具有较大的指导意义。     

Experimental study on the transition between stratified and non-stratified horizontal oil-water flow

The effect of oil and water velocities, pipe diameter and oil viscosity on the transition from stratified to non-stratified patterns was studied experimentally in horizontal oil-water flow. The investigations were carried out in a horizontal acrylic test section with 25.4 and 19 mm ID with water and two oil viscosities (6.4 and 12 cP) as test fluids. A high-speed video camera was used to study the flow structures and the transition. At certain oil velocity, stratified flow was found to transform into bubbly and dual continuous flows as superficial water velocity increased for both pipe diameters using the 12 cP oil viscosity. The transition to bubbly flow was found to disappear when the 6.4 cP oil viscosity was used in the 25.4 mm pipe. This was due to the low E?tv?s number. Transition to dual continuous flow occurred at lower water velocity for oil velocity up 0.21 m/s when 6.4 cP oil was used in the 25.4 mm ID pipe, while for U_so > 0.21 m/s, the transition appeared at lower water velocity with the 12 cP oil.The effect of pipe diameter was also found to influence the transition between stratified and non-stratified flows. At certain superficial oil velocity, the water velocity required to form bubbly flow increased as the pipe diameter increased while the water velocity required for drop formation decreased as the pipe diameter increased. The maximum wave amplitude was found to grow exponentially with respect to the mixture velocity. The experimental maximum amplitudes at the transition to non-stratified flow agreed reasonably well with the critical amplitude model. Finally, it was found that none of the available models were able to predict the present experimental data at the transition from stratified to non-stratified flow.     

Slip ratio in dispersed viscous oil-water pipe flow

In this article, dispersed flow of viscous oil and water is investigated. The experimental work was performed in a 26.2-mm-i.d. 12-m-long horizontal glass pipe using water and oil (viscosity of 100 mPa s and density of 860 kg/m³) as test fluids. High-speed video recording and a new wire-mesh sensor based on capacitance (permittivity) measurements were used to characterize the flow. Furthermore, holdup data were obtained using quick-closing-valves technique (QCV). An interesting finding was the oil-water slip ratio greater than one for dispersed flow at high Reynolds number. Chordal phase fraction distribution diagrams and images of the holdup distribution over the pipe cross-section obtained via wire-mesh sensor indicated a significant amount of water near to the pipe wall for the three different dispersed flow patterns identified in this study: oil-in-water homogeneous dispersion (o/w H), oil-in-water non-homogeneous dispersion (o/w NH) and Dual continuous (Do/w & Dw/o). The phase slip might be explained by the existence of a water film surrounding the homogeneous mixture of oil-in-water in a hidrofilic-oilfobic pipe.     

Upward and downward inclination oil–water flows

The effect of upward (+5°, +10°) and downward (−5°) pipe inclinations on the flow patterns, hold up and pressure gradient during two-liquid phase flows was investigated experimentally for mixture velocities between 0.7 and 2.5 m/s and phase fractions between 10% and 90%. The investigations were performed in a 38 mm ID stainless steel test pipe with water and oil as test fluids. High-speed video recording and local impedance and conductivity probes were used to precisely identify the different flow patterns. In both positive and negative inclinations the dispersed oil-in-water regime extended to lower mixture velocities and higher oil fractions compared to horizontal flow. A new flow pattern, oil plug flow, appeared at both +5° and +10° inclination while the stratified wavy pattern disappeared at −5° inclination. The oil to water velocity ratio was higher for the upward than for the downward flows but in the majority of cases and all inclinations oil was flowing faster than water. At low mixture velocities the velocity ratio increased with oil fraction while it decreased at high velocities. The increase became more significant as the degree of inclination increased. The frictional pressure gradient in both upward and downward flows was in general lower than in horizontal flows while a minimum occurred at all inclinations at high mixture velocities during the transition from dispersed water-in-oil to dual continuous flow.     

Multiphase flow with a simplified model for oil entrapment

A computationally simple procedure is described to model effects of oil entrapment on three-phase permeability-saturation-capillary pressure relations. The model requires knowledge of airwater saturation-capillary pressure relations, which are assumed to be nonhysteretic and are characterized by Van Genuchten's parametric model; scaling factors equal to the ratio of water surface tension to oil surface tension and to oil-water interfacial tension; and the maximum oil (also referred to as nonwetting liquid in a three-phase medium) saturation which would occur following water flooding of oil saturated soil. Trapped nonwetting liquid saturation is predicted as a function of present oil-water and air-oil capillary pressures and minimum historical water saturation since the occurrence of oil at a given location using an empirically-based algorithm. Oil relative permeability is predicted as a simple function of apparent water saturation (sum of actual water saturation and trapped oil saturation) and free oil saturation (difference between total oil and trapped oil saturation), and water relative permeability is treated as a unique function of actual water saturation. The proposed method was implemented in a two-dimensional finite-element simulator for three-phase flow and component transport, MOFAT. The fluid entrapment model requires minimal additional computational effort and computer storage and is numerically robust. The applicability of the model is illustrated by a number of hypothetical one- and two-dimensional simulations involving infiltration and redistribution with changes in water-table elevations. Results of the simulations indicate that the fraction of a hydrocarbon spill that becomes trapped under given boundary conditions increases as a nonlinear function of the maximum trapped nonwetting liquid saturation. Dense organic liquid plumes may exhibit more pronounced effects of entrapment due to the more dynamic nature of flow, even under static water table conditions. Disregarding nonwetting fluid entrapment may lead to significant errors in predictions of immiscible plume migration.     

水击谐波流场中乳化油液滴粒径的PIV测量

为了掌握乳化油液滴在水击谐波流场中的碰撞、破裂、聚集和变形等微观形态的变化规律,采用粒子图像测速(PIV)技术对水平方管中乳化油液滴的水击谐波流场进行了测量,分析了在水击谐波流场中,不同激振力作用下乳化油液滴的粒径变化。测量结果表明,在水击谐波流场作用下,乳化油液滴平均粒径的增长率随着激振力的减小而减小,随着作用时间的增大呈增加趋势,直至粒径处于一种动态平衡;乳化液滴随着激振力增大到达波节聚集位置的时间减少,可见增大水击谐波激振力有利于乳化液滴的聚集并合并为大尺度的液滴,从而有效地提高了水击谐波流场作用下的油水分离效果。     

Effect of pipe inclination on holdups/velocity ratios of oil-water flow without and with addition of drag-reducing polymer

In petroleum industries, the demand for effective design and operation of the oil-water transport systems is very high, and holdup of each phase is one of the important hydrodynamic parameters needed for such design and operation. This parameter can be affected by several factors one of which is the presence of the drag-reducing polymers in the oil-water flow. Therefore, the focus of this experimental study is on the effect of the drag-reducing polymer on the holdups and by extension, velocity ratios of the oil-water flow. Specifically, the investigation of the holdups and velocity ratios of the oil-water flow before and after the addition of the drag-reducing polymer was carried out in horizontal (0^ᴼ) and different inclined (−5^ᴼ, +5^ᴼ and +10^ᴼ) acrylic pipe with 30.6-mm ID. The investigation was conducted using flow conditions of 0.4, 0.8 and 1.6 m/s mixture velocities and 0.1–0.9 input oil volume fractions at each inclination. In each experimental run, the holdup of each phase was measured after steady flow was achieved using quick closing valves. Thereafter, the master solution of the polymer which was prepared at 2000 ppm water was injected at controlled flow rates to provide 40 ppm of the polymer in the water phase and the measurement was repeated. It was found generally that the water holdups and hence, the velocity ratios were increased after the addition of the polymer particularly in water-dominated flow regions. The velocity ratios also increased with the increase in the mixture velocities at these same flow regions. Finally, water was found to flow faster for separated flow at 0.4 m/s while for the dispersed flow regions at higher mixture velocities, the dispersed phase was in general the faster flowing phase.     

A theoretical model for core-annular flow of a very viscous oil core and a water annulus through a horizontal pipe

A theoretical model has been developed for core-annular flow of a very viscous oil core and a water annulus through a horizontal pipe. Special attention was paid to understanding how the buoyancy force on the core, resulting from any density difference between the oil and water, is counterbalanced. This problem was simplified by assuming the oil viscosity to be so high that any flow inside the core may be neglected and hence that there is no variation of the profile of the oil-water interface with time. In the model the core is assumed to be solid and the interface to be a solid/liquid interface.By means of the hydrodynamic lubrication theory it has been shown that the ripples on the interface moving with respect to the pipe wall can generate pressure variations in the annular layer. These result in a force acting perpendicularly on the core, which can counterbalance the buoyancy effect.To check the validity of the model, oil-water core-annular flow experiments have been carried out in a 5.08 cm and an 20.32-cm pipeline. Pressure drops measured have been compared with those calculated with the aid of the model. The agreement is satisfactory.     

Influence of gas injection on phase inversion in an oil–water flow through a vertical tube

An experimental study has been made of the influence of gas injection on the phase inversion between oil and water flowing through a vertical tube. Particular attention was paid to the influence on the critical concentration of oil and water where phase inversion occurs and on the pressure drop increase over the tube during phase inversion. By using different types of gas injectors also the influence of the bubble size of the injected gas on the phase inversion was studied. It was found that gas injection does not significantly change the critical concentration, but the influence on the pressure drop is considerable. For mixture velocities larger than 1 m/s, the pressure drop over the tube increases with decreasing bubble size and at inversion can become even larger than the pressure drop during the flow of oil and water without gas injection.     

Investigation on heavy crude-water two phase flow and related flow characteristics

In this paper, heavy crude oil–water flows are studied in a horizontal stainless steel test section with 25.4 mm ID and overall length of 50 m. Crude oil (viscosity = 628.1 mPa s, interfacial tension with water = 10.33 mN/m at 60 °C) and water, collected from an oilfield, were used as test fluids. Visual observations, local sampling and pressure drop measurements were used to identify the flow patterns and their transitions. It was found that in all conditions studied there was a water-in-oil emulsion present. At low mixture velocities and water fractions this occupied the whole pipe cross section. As the velocity or the volume fraction increased water appeared to segregate. At high water fractions and mixture velocities annular flow appeared with the water-in-oil emulsion in the core surrounded by a water layer. The results were compared with those from a model oil with the same viscosity. At low water fractions there was a similarity between the patterns observed with the two oil systems characterized by water segregation from an oil continuous dispersion with increasing water fraction or mixture velocity. However, at high water fractions an oil-in-water dispersion formed with the model oil that was not seen with the crude oil. Pressure drop was generally higher for the crude oil system compared to the model one, while in both cases it decreased when water started to segregate and form layers in contact with the pipe wall. The differences between the two oil systems are attributed to the natural surfactants present in the heavy crude oil (such as asphaltenes and resins), which tend to accumulate on the water/oil interface, retard film drainage and maintain the stability of water drops in oil.