致密砂岩逆向渗吸作用距离实验研究

中国致密油储量丰富, 但多数致密储层波及效率低, 衰竭开发效果较差. 逆向渗吸是致密油藏注水开发过程中的一种重要的提高采收率途径, 目前许多学者主要针对致密油藏渗吸采收率及其影响因素开展研究, 而对于渗吸作用距离(表征致密油藏渗吸作用范围)研究较少. 本文采用CT在线扫描装置建立了致密岩心逆向渗吸作用距离量化方法, 明确了逆向渗吸的作用范围, 进一步研究了流体压力、含水饱和度、岩心渗透率和表面活性剂对逆向渗吸作用距离的影响, 阐明了逆向渗吸作用距离与渗吸采收率的关系, 为提高致密油藏采收率提供指导. 研究结果表明, 渗透率为0.3 mD的致密岩心逆向渗吸作用距离尺度仅为1.25 ~ 1.625 cm; 5 MPa条件下渗透率为0.302 mD的岩心逆向渗吸作用距离为1.375 cm. 在本实验条件下, 流体压力和初始含水饱和度对致密岩心逆向渗吸作用距离的影响较小, 而渗透率和表面活性剂对致密岩心逆向渗吸作用距离的影响显著, 渗透率为0.784 mD的岩心逆向渗吸作用距离相较于渗透率为0.302 mD的岩心提高2.63倍. 逆向渗吸作用距离是渗吸采收率表征的重要参数, 决定了逆向渗吸作用的波及范围.      

致密油储层毛细管力自发渗吸模型分析

部分致密油井压后关井一段时间,压裂液返排率普遍低于30%,但是致密油气井产量反而越高,这与压裂液毛细管力渗吸排驱原油有关。然而,致密油储层致密,物性差,渗流机理复杂,尚没有形成统一的自发渗吸模型。本文基于油水两相非活塞式渗流理论,建立了压后闷井期间压裂液在毛细管力作用下自发渗吸进入致密油储层的数学模型,采用数值差分方法进行求解,并分析了相关影响因素。结果显示渗吸体积、渗吸前缘移动距离与渗吸时间的平方根呈线性正相关关系,与经典Handy渗吸理论模型预测结果一致,说明毛细管力自发渗吸模型可靠性较高。数值计算结果表明毛细管水相扩散系数是致密储层自发渗吸速率的主控参数,毛细管水相扩散系数越高,自发渗吸速率越大。毛细管水相扩散系数随着含水饱和度先增加后减小;随着束缚水饱和度、油相和水相端点相对渗透率增加而增加;随着相渗特征指数、油水黏度比和残余油饱和度增加而减小。该研究有助于深入认识致密油储层压裂液渗吸机理,对优化返排制度、提高致密油井产量具有重要意义。     

致密油藏动态裂缝扩展机理及应用

致密油藏采用注水吞吐补充地层能量取得了一定效果. 但多轮次注水吞吐后, 地层压力和产量降低快. 本文考虑了致密油藏复杂的裂缝形态, 根据艾尔文理论及弹性力学剖析I型裂缝尖端附近的应力场分布, 基于渗流力学、裂缝性致密油藏特征及动态裂缝渗流规律, 建立了多裂缝交叉裂缝扩展渗流模型, 结合注水诱导裂缝扩展机理及断裂力学能量守恒原理, 得到裂缝扩展长度. 依据致密油藏逆向渗吸原理, 提出将注水吞吐转为不稳定脉冲注水. 对比分析注水吞吐、脉冲注水2种能量补充发方式, 预测10年累计采油、压力及剩余油分布. 结果表明, 裂缝净内压随着注水量的增加而升高, 当应力场强度因子达到断裂韧度, 在裂缝尖端会发生扩展. 扩展及延伸的天然裂缝相互沟通, 呈现不规则复杂缝网, 在复杂缝网中主要发生逆向渗吸作用. 脉冲注水累计产油高、注水波及面积广、逆向渗吸作用强. 裂缝性致密油藏水平井注水吞吐转变为脉冲注水方式, 能够充分发挥动态缝网的逆向渗吸及线性驱替作用, 实现有效驱油的目的.      

基于改进LBM的气液自发渗吸过程中动态润湿效应模拟

微通道内气液自发渗吸是广泛发生在自然界及诸多工业领域的物理现象,而动态接触角是影响整个渗吸过程的关键因素.针对该问题,本文使用改进的伪势多相流格子玻尔兹曼方法 (LBM),直接捕捉微通道内气液自发渗吸过程中的实时接触角,并分析接触角的动态变化特性及其对渗吸长度的影响.首先,本文在原始的伪势多相流LBM的基础上耦合Peng-Robinson (PR)状态方程,改进流体-流体作用力以及流-固作用力格式,并采用精确差分方法将外力添加至LBM框架中.然后,通过校准模型的热力学一致性,模拟测试界面张力,静态平衡接触角等界面现象验证了模型的准确性.最后,基于建立的模拟方法,在水平方向上模拟微通道内气液自发渗吸过程.结果表明:渗吸过程中的接触角呈现动态变化特征,在渗吸初期,因受到惯性力的影响存在较大波动;随着渗吸距离的增大,其逐渐减小并趋近于静态平衡接触角.渗吸过程中的接触角与微通道尺寸及静态接触角有关,随着微通道宽度增大,实时的动态接触角与静态接触角相差大;随着静态接触角增大,实时的动态接触角与静态接触角的相差增大.此外,忽略动态接触角的Lucas-Washburn (LW)方程所预测的弯液面位置...     

基于核磁共振技术的非均质岩心中泡沫动态稳定性评价方法及应用

基于有效孔隙体积守恒和核磁共振技术建立了泡沫在岩心中的动态稳定性的评价方法. 利用油、水标定方法测量了岩心中油相和泡沫液的体积, 计算了泡沫在岩心驱替过程中的动态稳定因子. 测试了双层非均质岩心的横向弛豫谱线及核磁共振图像, 比较了纳米颗粒强化泡沫和表面活性剂泡沫的驱油效果和动态稳定因子. 结果表明, 岩心中的含水体积在注入2.0 PV泡沫前快速上升随后基本稳定; 而含气体积逐渐上升, 注入5.0 PV泡沫后上升速率变小. 泡沫的动态稳定因子经历了骤减、递增和平稳3个阶段. 泡沫前期的驱油效果主要依赖于水相, 随着含水体积基本稳定, 岩心的产油速率和泡沫动态稳定因子的增长速率具有明显正相关关系, 即中后期取决于泡沫气体对剩余油的驱替能力. 与表面活性剂泡沫相比, 纳米颗粒强化泡沫提高了低渗层的波及能力和驱油效率, 抑制了泡沫发展的不稳定阶段并且提高了动态稳定因子最终的平衡值. 该稳定性评价方法可用于反映泡沫渗流特点并筛选适合储层特征的稳定泡沫体系.      

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.      

储层含水条件下致密砂岩/页岩无机质纳米孔隙气相渗透率模型

页岩及致密砂岩储层富含纳米级孔隙,且储层条件下页岩孔隙(尤其无机质孔隙)及致密砂岩孔隙普遍含水,因此含水条件下纳米孔隙气体的流动能力的评价对这两类气藏的产能分析及生产预测具有重要意义.本文首先基于纳米孔隙内液态水及汽态水热力学平衡理论,量化了储层孔隙含水饱和度分布特征;进一步在纳米孔隙单相气体传质理论的基础上,考虑了孔隙含水饱和度对气体流动的影响;最终建立了含水饱和度与气相渗透率的关系曲线. 基于本文岩心孔隙分布特征,计算结果表明:储层含水饱和度对气体流动能力的影响不容忽视,在储层含水饱和度20%的情况下,气相流动能力与干燥情况相比将降低约10%;在含水饱和度40% 的情况下,气相流动能力将降低约20%.      

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.      

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.     

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.     

Analysis of capillary interaction and oil recovery under ultrasonic waves

Although, the effects of ultrasonic irradiation on multiphase flow through porous media have been studied in the past few decades, the physics of the acoustic interaction between fluid and rock is not yet well understood. Various mechanisms may be responsible for enhancing the flow of oil through porous media in the presence of an acoustic field. Capillary related mechanisms are peristaltic transport due to mechanical deformation of the pore walls, reduction of capillary forces due to the destruction of surface films generated across pore boundaries, coalescence of oil drops due to Bjerknes forces, oscillation and excitation of capillary trapped oil drops, forces generated by cavitating bubbles, and sonocapillary effects. Insight into the physical principles governing the mobilization of oil by ultrasonic waves is vital for developing and implementing novel techniques of oil extraction. This paper aims at identifying and analyzing the influence of high-frequency, high-intensity ultrasonic radiation on capillary imbibition. Laboratory experiments were performed using cylindrical Berea sandstone and Indiana limestone samples with all sides (quasi-co-current imbibition), and only one side (counter-current imbibition) contacting with the aqueous phase. The oil saturated cores were placed in an ultrasonic bath, and brought into contact with the aqueous phase. The recovery rate due to capillary imbibition was monitored against time. Air–water, mineral oil–brine, mineral oil–surfactant solution and mineral oil-polymer solution experiments were run each exploring a separate physical process governing acoustic stimulation. Water–air imbibition tests isolate the effect of ultrasound on wettability, capillarity and density, while oil–brine imbibition experiments help outline the ultrasonic effect on viscosity and interfacial interaction between oil, rock and aqueous phase. We find that ultrasonic irradiation enhances capillary imbibition recovery of oil for various fluid pairs, and that such process is dependent on the interfacial tension and density of the fluids. Although more evidence is needed, some runs hint that wettability was not altered substantially under ultrasound. Preliminary analysis of the imbibition recoveries also suggests that ultrasound enhances surfactant solubility and reduce surfactant adsorption onto the rock matrix. Additionally, counter-current experiments involving kerosene and brine in epoxy coated Berea sandstone showed a dramatic decline in recovery. Therefore, the effectiveness of any ultrasonic application may strongly depend on the nature of interaction type, i.e., co- or counter-current flow. A modified form of an exponential model was employed to fit the recovery curves in an attempt to quantify the factors causing the incremental recovery by ultrasonic waves for different fluid pairs and rock types.     

Micromodel Observation of the Role of Oil Layers in Three-Phase Flow

We have studied the flow of a non-aqueous phase liquid (NAPL, or oil), water and air at the pore scale using a micromodel. The pore space pattern from a photomicrograph of a two-dimensional section through a Berea sandstone was etched onto a silicon wafer. The sizes of the pores in the micromodel are in the range 3–30,m and are the same as observed in the rock from which the image was taken. We conducted three-phase displacement experiments at low capillary numbers (in the order of 10^-7) to observe the presence of predicted displacement mechanisms at the pore scale. We observed stable oil layers between the wetting phase (water) and the non-wetting phase (gas) for the water–decane–air system, which has a negative equilibrium spreading coefficient, as well as four different types of double displacements where one fluid displaces another that displaces a third. Double imbibition and double drainage are readily observed, but the existence of an oil layer surrounding the gas phase makes the other double displacement combinations very unlikely.     

Microtomography of Imbibition Phenomena and Trapping Mechanism

Water imbibition during the waterflooding process of oil production only sweeps part of the oil present. After water disrupts the oil continuity, most oil blobs are trapped in porous rock by capillary forces. Developing an efficient waterflooding scheme is a difficult task; therefore, an understanding of the oil trapping mechanism in porous rock is necessary from a microscopic viewpoint. The development of microfocused X-ray CT scanner technology enables the three-dimensional visualization of multiphase phenomena in a pore-scale. We scanned packed glass beads filled with a nonwetting phase (NWP) and injected wetting phase (WP) in upward and downward injections to determine the microscopic mechanism of immiscible displacement in porous media and the effects of buoyancy forces. We observed the imbibition phenomena for small capillary numbers to understand the spontaneous imbibition mechanism in oil recovery. This study is one of the first attempts to use a microfocused X-ray CT scanner for observing the imbibition and trapping mechanisms. The trapping mechanism in spontaneous imbibition is determined by the pore configuration causing imbibition speed differences in each channel; these differences can disrupt the oil continuity. Gravity plays an important role in spontaneous imbibition. In upward injection, the WP flows evenly and oil is trapped in single or small clusters of pores. In downward injection, the fingering phenomena determine the amount of trapped oil, which is usually in a network scale. Water breakthrough causes dramatic decrease in the oil extraction rate, resulting in lower oil production efficiency.     

Numerical Simulation of Diagenetic Alteration and Its Effect on Residual Gas in Tight Gas Sandstones

In this study, we numerically cemented a segmented X-ray microtomography image of a sandstone to understand changes to pore space connectivity, capillary control on gas, and water distributions, and ultimately production behavior in tight gas sandstone reservoirs. Level set method-based progressive quasi-static algorithm (a state-of-the-art direct simulation of capillarity-dominated fluid displacement) was used to find the gas/water configurations during drainage and imbibition cycles. Further, we account for gas?Cwater interfacial tension changes using 1D burial history model based on available geologic data. We have found the displacement simulation method robust, and that diagenetic changes impart a significantly larger effect on gas trapping compared with interfacial tension changes.     

SPONTANEOUS CAPILLARY IMBIBITION MODEL IN TIGHT OIL RESERVOIRS 1)

部分致密油井压后关井一段时间，压裂液返排率普遍低于30%，但是致密油气井产量反而越高，这与压裂液毛细管力渗吸排驱原油有关。然而，致密油储层致密，物性差，渗流机理复杂，尚没有形成统一的自发渗吸模型。本文基于油水两相非活塞式渗流理论，建立了压后闷井期间压裂液在毛细管力作用下自发渗吸进入致密油储层的数学模型，采用数值差分方法进行求解，并分析了相关影响因素。结果显示渗吸体积、渗吸前缘移动距离与渗吸时间的平方根呈线性正相关关系，与经典Handy渗吸理论模型预测结果一致，说明毛细管力自发渗吸模型可靠性较高。数值计算结果表明毛细管水相扩散系数是致密储层自发渗吸速率的主控参数，毛细管水相扩散系数越高，自发渗吸速率越大。毛细管水相扩散系数随着含水饱和度先增加后减小；随着束缚水饱和度、油相和水相端点相对渗透率增加而增加；随着相渗特征指数、油水黏度比和残余油饱和度增加而减小。该研究有助于深入认识致密油储层压裂液渗吸机理，对优化返排制度、提高致密油井产量具有重要意义。     

A Semi-analytical Model for Pressure-Dependent Permeability of Tight Sandstone Reservoirs

In tight gas reservoirs, permeability is pressure dependent owing to pore pressure reduction during the life of the reservoir. Empirical models are commonly used to describe pressure-dependent permeability. In this paper, it was discussed a number of issues which centered around tight sandstone pressure-dependent permeability experiment, first to apply core aging on permeability test and then to develop a new semi-analytical model to predict permeability. In tight sandstone permeability test experiment, the microinterstice between core and sleeves resulted in over estimation of dependency of permeability on pressure. Then, a new semi-analytical model was developed to identify the relation between permeability and fluid pressure in tight sandstone, which indicates there is a linear relation between pore pressure changes and the inverse of permeability to a constant power. Pressure-dependent permeability of 8 tight sandstone core samples from Ordos Basin, China, was obtained using the modified procedure, and results were perfectly matched with the proposed model. Meanwhile, the semi-analytical model was also verified by pressure-dependent permeability of 16 cores in the literature and experiment results of these 24 cores were matched by empirical models and the semi-analytical model. Compared with regression result of commonly used empirical models, the semi-analytical model outperforms the current empirical models on 8 cores from our experiment and 16 cores from the literature. The model verification also indicates that the semi-theoretical model can match the pressure-dependent permeability of different rock types. In addition, the permeability performance under reservoir condition is discussed, which is divided into two stages. In most tight gas reservoirs, the permeability performance during production is located in stage II. The evaluation result with proposed experiment procedure and the stress condition in stage II will reduce permeability sensitivity to stress.     

Capillary Pressure at a Saturation Front During Restricted Counter-Current Spontaneous Imbibition with Liquid Displacing Air

The ultimate driving force for counter-current spontaneous imbibition of a fluid into a porous material is the capillary pressure developed under dynamic conditions at the imbibition front. This is a difficult variable to measure. We report experiments using restricted counter-current spontaneous imbibition to find the maximum capillary pressure developed during imbibition of a light mineral oil (and brine) into initially air-filled sandstone core samples with one end-face open. The production of air from the core was prevented by covering its open face with a low permeability core segment set against the main test segment. The location of the imbibition front and the pressure resulting from compression of air ahead of the imbibition front were monitored. In some cases, in order to achieve stabilized gas pressures with the front still advancing through the core, the air in the core was compressed at the start of the imbibition test. The subsequently measured stabilized air pressures dropped only slightly as imbibition slowed. The measured pressures are directly related to the effective capillary pressures that drive spontaneous imbibition. After spontaneous imbibition ceased, the pressure was released by flow of air through the sealed end of the core and further spontaneous imbibition occurred in co-current mode. Comparison of the stabilized pressures with previously published oil/brine imbibition results showed close agreement after compensation for the difference in interfacial tension.     

Capillary Pressure at the Imbibition Front During Water–Oil Counter-Current Spontaneous Imbibition

Counter-current spontaneous imbibition (COUCSI) in porous media is driven by capillary forces. Capillary action results in a high capillary imbibition pressure at the imbibition front and a low capillary drainage pressure at the outlet face. It is the difference between these two pressures that draws in the wetting phase and pushes out the non-wetting phase. A technique for measuring the capillary pressure at an imbibition front under restricted flow conditions has been developed and applied to Berea sandstone with a range of permeabilities. In the experiments, brine was the wetting phase and refined oil was the non-wetting phase. One end face of a sandstone core was butted to a short section of a finer-pored rock. The composite core surface was then sealed, apart from the end face of the low-permeability segment. A connection to a pressure transducer was set in the opposite end face of the core. Initially, the main core segment was filled with oil. In most cases, the finer-pored segment was filled with brine. Imbibition was started by immersing the core in brine. The purpose of the finer-pored segment was to prevent the escape of non-wetting phase from the open face. For some tests there was an initial period of co-current spontaneous imbibition (COCSI) created by allowing production of non-wetting phase through an outlet tapping in the sealed end face. The outlet was then connected to the transducer and the imbibition changed to COUCSI. There followed an increase in the monitored end pressure to a maximum as fluid redistributed within the core. For the tests in which the fine-pored segments were pre-saturated with brine, even without an initial period of co-current imbibition, limited invasion of the main core segment by brine resulted in an asymptotic rise of the end pressure to a maximum as the imbibition front dispersed. To confirm that the dispersing front did not reach the dead end of the core, the distance of advance of the wetting liquid was detected by a series of electrodes. The maximum value of the end pressure provides an estimate of the capillary pressure at an imbibition front for COUCSI. The maximum capillary pressure generated by the invading fluids ranged from 6.6 kPa to 42 kPa for sandstone with permeabilities between 1.050 (μm)² and 0.06 (μm)².     

The Impact of Pore Water Chemistry on Carbonate Surface Charge and Oil Wettability

Water chemistry has been shown experimentally to affect the stability of water films and the sorption of organic oil components on mineral surfaces. When oil is displaced by water, water chemistry has been shown to impact oil recovery. At least two mechanisms could account for these effects, the water chemistry could change the charge on the rock surface and affect the rock wettability, and/or changes in the water chemistry could dissolve rock minerals and affect the rock wettability. The explanations need not be the same for oil displacement of water as for water imbibition and displacement of oil. This article investigates how water chemistry affects surface charge and rock dissolution in a pure calcium carbonate rock similar to the Stevns Klint chalk by constructing and applying a chemical model that couples bulk aqueous and surface chemistry and also addresses mineral precipitation and dissolution. We perform calculations for seawater and formation water for temperatures between 70 and 130°C. The model we construct accurately predicts the surface potential of calcite and the adsorption of sulfate ions from the pore water. The surface potential changes are not able to explain the observed changes in oil recovery caused by changes in pore water chemistry or temperature. On the other hand, chemical dissolution of calcite has the experimentally observed chemical and temperature dependence and could account for the experimental recovery systematics. Based on this preliminary analysis, we conclude that although surface potential may explain some aspects of the existing spontaneous imbibitions data set, mineral dissolution appears to be the controlling factor.