基于孔与裂隙网络模型的平行微裂隙对驱油的影响规律研究

认识双重多孔介质中油水两相微观渗流机制是回答形成什么类型的裂隙网络可提高油藏采收率的关键.微裂隙的分布可以提高多孔介质的绝对渗透率,但对于基质孔隙中的流体介质,微裂隙的存在会引起多孔介质中局部流体压力和流场的变化,导致局部流动以微裂隙流动为主,甚至出现窜流现象,降低驱油效率.本文基于孔与裂隙双重网络模型,在网络进口设定两条平行等长且具有一定间隔的微裂隙,分析微裂隙的相对间隔(微裂隙之间距离/喉道长度)和微裂隙相对长度(微裂隙长度/喉道长度)对于微观渗流特征的影响.结果表明:随微裂隙相对长度的增加,出现驱油效率逐渐降低,相对渗透率曲线中的油水共渗区水饱和度和等渗点增加,油水两相的共渗范围减小等现象;随着微裂隙之间相对间隔增大,周围越来越多的基质孔穴间的压力差减小,在毛管压力的限制下,驱替相绕过这些区域,而导致水窜现象.     

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.     

基于物理界面的双重介质有限裂隙渗流模型

基于连续介质或者离散裂隙假设,含裂隙的多孔介质渗流问题有多种数学力学模型。受物理界面的启发,提出一种新的有限裂隙连续介质力学模型,可以为宏观裂隙-多孔介质内的流体输运问题等提供近似计算方案。该模型属于一类双重介质模型,将曲面上低维度的流场转化为三维空间的流场,并且与连续的多孔介质的流场耦合,在数学上表示为统一的输运控制方程和初始边界条件。这个近似模型为不方便实施高维度-低维度耦合求解的数值计算方法提供新的模拟思路,如光滑粒子流体动力学等无网格粒子类方法。     

动边界双重介质油藏低速非达西渗流试井模型

裂缝性油藏中基质岩块的渗透率一般很低,大量岩心测试实验证实在基质岩块内的液体渗流和在一定含水饱和度下的气体渗流将偏离达西渗流,往往出现低速非达西渗流,表现出启动压力梯度以及流体流动边界不断向外扩展等特殊现象。本文充分考虑启动压力梯度与动边界的影响,建立了微可压缩双重介质油藏低速非达西渗流的试井数学模型,对时间和空间变量...     

基于图像识别的裂隙煤层气非Darcy渗流模拟

煤层气在煤岩裂隙中流动时,由于其粘度系数较小,很容易产生非Darcy现象.因此,考虑煤层气的非Darcy渗流将会使得研究结果更加客观和准确,对煤层气开采具有实际意义.首先将实物裂隙高清拍照导入Matlab软件中进行图像二值化处理,再利用COMSOL软件对二值图像进行模型重构和数值模拟.模拟结果显示,煤层气渗流速度随着裂隙尺度的变化而不断改变,速度随时间不断增加,但区域渗流速度分布状态保持不变.与Darcy结果的对比分析可知,相同压力梯度下,考虑非Darcy因素的产气量要明显小于仅考虑Darcy因素的情况.同时,结果显示,在渗透率不同的煤裂隙中,煤层气的渗流速度不同.渗透率较大时,渗流速度相对较大,同样,渗透率较小时,渗透速度较小.     

油水两相渗流压力脉动的实验及数值分析

本文用高精度的压差传感器和高速度的数据采集设备同时测量出油水两相流体在多孔介质流动时产生的较大压力降和微小压力脉动,应用自行研制的大型数据处理软件对恒流速水驱油的两相渗流压力脉动实验数据进行了分析,发现不同阶段压力脉动具有明显的频谱特性和时间相关特性的不同,在第三阶段（油为主,水增加阶段）谱能增加最大,时间正相关程度最强。     

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.     

裂隙岩体非稳态渗流数值模型及其应用

为解决裂隙岩体非稳态渗流问题, 发展了一种新的数值模型. 对于单裂隙渗 流求解, 其控制方程是基于一定假设的简化Navier-Stokes方程, 数值方法采用有限差分法 和流体体积法. 在裂隙网络中, 交界处渗流可以由专门的控制方程求解. 计算结果表明, 该 数值模型既可以大幅提高非稳态渗流的计算效率, 还可以避免孤立裂隙所带来的影响. 最后, 通过两个工程算例验证该数值模型的适用性.     

考虑介质微观非均质特征的乳状液渗流模型

油水乳化渗流是三元复合驱和热力采油过程中常见的现象,地层介质的微观孔隙结构特征对乳状液流动有着重要影响.现有描述乳状液渗流的理论模型都属于确定性方法,只能反映出介质孔隙结构的体积平均效果.当介质内部微观非均质性相比其尺寸不能被忽略时,采用确定性方法描述会与实验结果存在偏差.基于连续时间随机游走理论建立了描述乳状液渗流的随机理论模型.该模型引入反映液滴微观运动特征的跃迁时间和跃迁位移两个概率分布函数来反映多孔介质微观非均质特征.研究结果表明该模型能很好地刻画实验曲线中出现的与介质尺度相关的拖尾现象,可作为更一般的过滤模型.     

金沙江某水电站上下坝址岩体卸荷差异研究

油水乳化渗流是三元复合驱和热力采油过程中常见的现象,地层介质的微观 孔隙结构特征对乳状液流动有着重要影响. 现有描述乳状液渗流的理论模型都属于确定性方 法,只能反映出介质孔隙结构的体积平均效果. 当介质内部微观非均质性相比其尺寸不能被 忽略时,采用确定性方法描述会与实验结果存在偏差. 基于连续时间随机游走理论建立 了描述乳状液渗流的随机理论模型. 该模型引入反映液滴微观运动特征的跃迁时间和跃迁位 移两个概率分布函数来反映多孔介质微观非均质特征. 研究结果表明该模型能很好地刻画 实验曲线中出现的与介质尺度相关的拖尾现象,可作为更一般的过滤模型.     

Numerical Analysis of Imbibition Front Evolution in Fractured Sandstone under Capillary-Dominated Conditions

Fractures serve as primary conduits having a great impact on the migration of injected fluid into fractured permeable media. Appropriate transport properties such as relative permeability and capillary pressure are essential for successful simulation and prediction of multi-phase flow in such systems. However, the lack of a thorough understanding of the dynamics governing immiscible displacement in fractured media, limits our ability to properly represent their macroscopic transport properties. Previous experimental observations of imbibition front evolution in fractured rocks are examined in the present study using an automated history-matching approach to obtain representative relative permeability and capillary pressure curves. Predicted imbibition front evolution under different flow conditions resulted in an excellent agreement with experimental observations. Sensitivity analyses, in combination with direct experimental observation, allowed exploring the competing effects of relative permeability and capillary pressure on the development of saturation distribution and imbibing front evolution in fractured porous media. Results show that residual saturations are most sensitive to matrix relative permeability to oil, while the ratio of oil and water relative permeability, rock heterogeneity, boundary condition, and matrix–fracture capillary pressure contrast, affect displacement shape, speed, and geometry of the imbibing front.     

Pore-scale Simulation of Water Alternate Gas Injection

We use a three-dimensional mixed-wet random network model representing Berea sandstone to compute displacement paths and relative permeabilities for water alternating gas (WAG) flooding. First we reproduce cycles of water and gas injection observed in previously published experimental studies. We predict the measured oil, water and gas relative permeabilities accurately. We discuss the hysteresis trends in the water and gas relative permeabilities and compare the behavior of water-wet and oil-wet media. We interpret the results in terms of pore-scale displacements. In water-wet media the water relative permeability is lower during water injection in the presence of gas due to an increase in oil/water capillary pressure that causes a decrease in wetting layer conductance. The gas relative permeability is higher for displacement cycles after first gas injection at high gas saturation due to cooperative pore filling, but lower at low saturation due to trapping. In oil-wet media, the water relative permeability remains low until water-filled elements span the system at which point the relative permeability increases rapidly. The gas relative permeability is lower in the presence of water than oil because it is no longer the most non-wetting phase.     

Oil Displacement for One-Dimensional Three-Phase Flow with Phase Change in Fractured Media

In this article, the numerical simulations for one-dimensional three-phase flows in fractured porous media are implemented. The simulation results show that oil displacement in matrix is dominated by oil–water capillary pressure only under certain conditions. When conditions are changed to decrease the amount of water entering into the fractured media from the boundary of the flow field, water in fracture may be vaporized to superheated steam. In these cases, the appearance of superheated steam in fracture rather than in matrix will decrease the fracture pressure and generate the pressure difference between matrix and fracture, which results in oil flowing from matrix to fracture. Assuming that oil is wetting to steam, the matrix steam–oil capillary pressure will decrease the matrix oil-phase pressure as the matrix steam saturation increases. After the steam–oil capillary pressure finally exceeds the pressure difference due to the appearance of superheated steam in fracture, the oil displacement in matrix will stop. It is also shown that variations of the water relative permeability curve in matrix do not result in different mechanisms for oil displacement in matrix. The simulation results suggest that the amount of liquid water supply from the boundary of flow field fundamentally influence the mechanisms for oil displacement in matrix.     

Enhancing Immiscible Fluid Displacement in Porous Media by Capillary Pressure Discontinuities

Fluid displacement in porous media plays an important role in many industrial applications, including biological filtration, carbon capture and storage, enhanced oil recovery, and fluid transport in fuel cells. The displacement front is unstable, which evolves from smooth into ramified patterns, when the mobility (ratio of permeability to viscosity) of the displacing fluid is larger than that of the displaced one; this phenomenon is called viscous fingering. Viscous fingering increases the residual saturation of the displaced fluid, considerably impairing the efficacy of fluid displacement. It is of practical importance to develop suitable methods to improve fluid displacement. This paper presents an experimental study on applying the discontinuity of capillary pressure to improve immiscible fluid displacement in drainage for which the displacing fluid (air) wets the porous media less preferentially than does the displaced fluid (silicone oil). The concept involves using a heterogeneous packing system, where the upstream region features large pores and small capillary pressure, and the downstream region features small pores and large capillary pressure. The increase in capillary pressure prevents fingering from directly crossing the media interface, thus enhancing the displacement. The experimental apparatus was a linear cell comprising porous media between two parallel plates, and glass beads of 0.6 and 0.125 mm diameter were packed to compose the heterogeneous porous media. The time history of the finger flow was recorded using a video camera. Pressure drops over the model from the inlet to the outlet were measured to compare viscous pressure drops with capillary pressures. The results show that the fluid displacement was increased by the capillary discontinuities. The optimal displacement was determined through linear regression by adjusting the relative length of the large- and small-pore region. The results may assist in the understanding of fingering flow across the boundaries of different grain-sized bands for the gas and oil reservoir management, such as setting the relative location of the injection and production wells. The findings may also serve as a reference for industrial applications such as placing the grain bands in an adequate series to improve the displacement efficacy in biological filtration.     

Investigation of Generalized Relative Permeability Coefficients for Electrically Assisted Oil Recovery in Oil Formations

Evaluation of relative permeability coefficients is one of the key steps in reliable simulation of two-phase flow in porous media. An extensive body of work exists on evaluation of these coefficients for two-phase flow under pressure gradient. Oil transport under an applied electrical gradient in porous media is also governed by the principles of two-phase flow, but is less understood. In this paper, relative permeability coefficients under applied electric field are evaluated for a specific case of two- phase fluid flow in water-wet porous media, where the second fluid phase is oil. It is postulated that the viscous drag on the oil phase, exerted by the electro-osmotic flow of the water phase, is responsible for the transport of oil in the absence of a pressure gradient. Reliable prediction of the flow patterns necessitates accurate representation and determination of the relative permeability coefficients under the electrical gradient. The contribution of each phase to the flow is represented mathematically, and the relative permeability coefficients are evaluated through electro-osmotic flow measurements conducted on oil bearing rock cores.     

A Multi-Scale Approach to Model Two-Phase Flow in Heterogeneous Porous Media

The immiscible displacement of a wetting fluid by a non-wetting one in heterogeneous porous media is modeled using a multi-scale network-type analysis: (1) The pressure-controlled immiscible displacement of water by oil in pore-and-throat networks (1st length scale ~ 1?mm) is simulated as a capillary-driven process. (2) The pressure-controlled immiscible displacement in uncorrelated cubic lattices (2nd length scale ~ 1?cm) is simulated as a site percolation process governed by capillary and gravity forces. At this scale, each node represents a network of the previous scale. (3) The rate-controlled immiscible displacement of water by oil in cubic networks (3rd length scale ~ 10?cm), where each node represents a lattice of the previous scale, is simulated by accounting for capillary, gravity, and viscous forces. The multi-scale approach along with the information concerning the pore structure properties of the porous medium can be employed to determine the transient responses of the pressure drop and axial distribution of water saturation, and estimate the effective (up-scaled) relative permeability functions. The method is demonstrated with application to data of highly heterogeneous soils.     

Effects of Fines Migration on Low-Salinity Waterflooding: Analytical Modelling

We discuss the governing system for oil–water flow with varying water composition. The model accounts for wettability alteration, which affects the relative permeability, and for salinity-variation-induced fines migration, which reduces the relative permeability of water. The overall ionic strength represents the aqueous phase composition in the model. One-dimensional displacement of oil by high-salinity water followed by low-salinity-slug injection and high-salinity water chase drive allows for exact analytical solution. The solution is derived using the splitting method. The analytical model obtained analyses the effects of wettability alteration and fines migration on oil recovery as two distinct physical mechanisms. For typical reservoir conditions, the significant effects of both mechanisms are observed.     

Pore Scale and Macroscopic Displacement Mechanisms in Emulsion Flooding

The flow properties of complex fluids through porous media give rise to multiphase flow displacement mechanisms that operate at different scales, from pore-level to Darcy scale. Experiments have shown that injection of oil-in-water emulsions can be used as an effective enhanced-oil recovery (EOR) method, leading to substantial increase in the volume of oil recovered. Pore-scale flow visualization as well as core flooding results available in the literature have demonstrated that the enhanced recovery factor is regulated by the capillary number of the flow. However, the mechanisms by which additional oil is displaced during emulsion injection are still not clear. In this work, we carried out two different experiments to evaluate the effect of emulsion flooding both at pore and macro scales. Visualization of the flow through sand packed between transparent plexiglass parallel plates shows that emulsion flooding improves the pore-level displacement efficiency, leading to lower residual oil saturation. Oil recovery results during emulsion flooding in tertiary mode (after waterflooding) in parallel sandstone cores with very different absolute permeability values prove that emulsion flooding also leads to enhancement of conformance or volumetric sweep efficiency. Combined, the results presented here show that injection of emulsion offers multiscale mechanisms resulting from capillary-driven mobility control.     

湿润性对孔隙介质两相渗流驱替效率的影响

孔隙介质中多相渗流的驱替效率对二氧化碳封存效率和石油采收率具有决定性影响, 是实际工程调控中的一个关键指标. 湿润性是影响多相渗流驱替模式及其效率的一个重要因素. 本文通过微流体模型-显微镜-高速相机可视化实验平台, 对基于真实砂岩孔隙结构的微流体模型进行湿润性修饰, 开展了5种流量和2种湿润性的两相驱替可视化实验, 研究了湿润性对砂岩孔隙结构中两相渗流驱替模式及其效率的重要影响. 实验结果表明: 随着流速的增大, 两相渗流驱替模式由毛细指流向稳定流发生转变; 在低流速条件下, 由于毛细力的主导效应, 亲水性介质中指进的宽度和被驱替流体团簇的数目均小于疏水性介质, 而被驱替流体团簇的最大半径、平均半径和方差均大于疏水性介质. 实验结果还证实了亲水性介质中由于单支优势通道和"绕流"现象的发生, 驱替效率显著小于疏水性介质. 最后, 通过考虑接触角效应对毛细管数进行修正, 建立了考虑湿润性影响的驱替效率和毛细管数之间的统一关系式, 为不同湿润性条件下驱替效率的预测提供了一种潜在方法.      

Pore-scale flow characterization of low-interfacial tension flow through mixed-wet porous media with different pore geometries

The low-interfacial tension flow through porous media occurs in surfactant-based enhanced oil recovery (EOR), soil clean-up, underground removal of the non-aqueous phase liquid and dense non-aqueous phase liquid, etc. In surfactant-based EOR processes, numerous works have been carried out to characterize - either qualitatively or quantitatively - the micro- and macro-scale flow behavior. What has been lacking is to link the statistics of oil blobs population (e.g., distribution of blob length and diameter) to the pore-scale phenomena and macro-scale quantities. In particular, no work has been reported to elucidate the effect of the ratio of pore body to throat diameter (i.e., aspect ratio) on the pore-scale characterization based on the blobs population statistics. The significance of the aspect ratio lies in that it describes the geometry of a porous medium and is one of the foremost morphological features. The aspect ratio is also one of the fundamental factors governing the pore-level events. This study presents the effect of aspect ratio on the statistical distribution of the blob length and equivalent diameter and links the blobs population statistics to the observed pore-level events. The pore-scale variation of the ratio of viscous-to-capillary forces acted on the oil blobs at the threshold of displacement is utilized to characterize the effect of blob length distribution at different aspect ratios. It also provides some insight into correlating the change in oil recovery efficiency and capillary number, by change in aspect ratio, with the change in blobs population statistics.