低渗透砂岩渗吸驱油规律实验研究

低渗透油田的开发比较复杂,其生产能力和注水能力很差,水的自发渗吸对原油的开采十分有利。文中采用自行研制的实验装置,通过大量的室内实验研究了低渗透砂岩常温常压以及脉冲压力条件下的渗吸规律及其影响因素。结果表明:常温常压渗吸实验中基质岩块的渗吸规律满足r=rmax(1-e-λt);常压或脉冲压力条件下,最终渗吸采收率均随着岩心渗透率、孔隙度的增大而增加,这与常规认识不符,主要与实验岩心的特低孔低渗性质有关;脉冲渗吸驱油效果优于常压渗吸驱油效果,随着脉冲次数及脉冲压力的增加,渗吸采收率会有不同程度的提高。     

低渗裂缝性油藏渗吸注水实验研究

由于裂缝性油藏储集空间物理性质的复杂性和特殊性,渗吸效果控制着低渗透裂缝性水驱开发动态与开发效果.通过室内实验研究,获得了低渗裂缝性油藏基质岩块自然渗吸动态规律和脉冲渗吸动态规律,为制定低渗裂缝性油藏合理的渗吸注水开发方式提供了理论依据.     

脉冲渗吸水驱油机理实验研究与分析

由于裂缝性油藏储集空间物理性质的复杂性和特殊性,渗吸效果控制着低渗透裂缝性油藏水驱开发动态与开发效果,而脉冲渗吸驱油一直被认为是低渗透裂缝性油藏有效的开发方式。在室内实验研究的基础上,结合油藏工程等理论知识对脉冲渗吸驱油机理进行了研究,得出脉冲增压改善基质岩块孔隙中渗吸条件是脉冲注水方式提高渗吸驱油效率的根本原因。     

低渗透砂岩油藏渗吸规律研究

随着越来越多的低渗透油田的发现，石油生产的目标逐渐集中在低渗透油田开发上。由于低渗透油藏的生产能力和注水能力很差，渗吸采油在油田开发中发挥着重要的作用。在介绍了一种新的渗吸设备的基础上，利用其研究了低渗透岩心反向渗吸规律。利用X—Ray变化度检测仪，研究了岩心长短对反向渗吸动态、最终渗吸采收率的影响，以及渗吸过程中不同阶段岩心中含水变化度的变化过程。并得出如下结论：反向渗吸是裂缝性低渗透砂岩油藏的主要采油机理；由于低渗透油藏的特点，毛管力作用有效性受到限制，渗吸缓慢，渗吸采收率较低；X-Ray扫描结果揭示了渗吸初期渗吸速度快，渗吸前沿到达边界后渗吸速度变缓。     

致密油气储层基质岩心静态渗吸实验及机理

致密油气藏已经成为非常规油气领域的开发重点。渗吸作用作为致密油气渗流机理的重要内容,可以有效地提高致密油气藏的采收率,但目前这方面的研究较少。选取中国典型致密油气储层基质岩心,进行不同条件下的渗吸实验。对实验现象与实验结果进行深入分析,提出新的致密油气储层基质岩心渗吸机理——层渗吸理论,即渗吸是从岩心表层开始逐层向岩心内部进行的。根据修正质量法计算渗吸效率的公式得到准确的室内渗吸实验数据,并将数据标定为实际地层尺度。结果表明,致密油气储层基质岩心在地层条件下的油水渗吸效率为12%~18%,渗吸速度数量级为1×10~(-4)cm/min。应用渗吸作用开发致密油气需要与其他开发方式相结合,才能提高致密油气产量的最终效果。     

岩心尺度静态自发渗吸的数值模拟

基于渗流理论、化学势以及嵌入式离散裂缝模型,推导了新的静态渗吸数学模型,模型考虑了毛细管力、重力、溶质浓度差导致的渗透压3种渗吸驱动力对渗吸采油的影响,并利用现有研究验证了模型的准确性。通过数值计算,着重研究了不同驱动机制对渗吸采出程度的贡献,分析了浸泡液矿化度、岩块壁面膜效率、岩块尺寸对采出程度的影响。结果表明:静态渗吸采油过程中,毛细管力、重力以及渗透压都为重要的渗吸驱动力;受多种渗吸驱动力影响,岩块内部含水饱和度呈一定规律变化;早期渗吸中,毛细管力、重力对采出程度的贡献较大;长远来看,渗透压主导的持续渗吸作用对采出程度的贡献也不可忽视。浸泡液矿化度与岩块采出程度呈近线性负相关;岩块尺寸与采出程度非线性负相关;岩块壁面膜效率与采出程度非线性正相关,并且膜效率的增加可以延长高渗透压主导渗吸采油的时长。在水力压裂作业和注水开发过程中,适当降低压裂液和注入流体矿化度值以及增加水力改造裂缝网络复杂程度,可以强化初期渗吸采油效果,缩短渗吸时间,提高最终采收率。     

裂缝性油藏低渗透岩心自发渗吸实验研究

裂缝性低渗透油藏注水开发时,注入水沿裂缝窜流,油井含水率高,地下注水波及效果差,油层水淹后仍有大量原油滞留在基质岩块中.渗吸排油是裂缝性低渗透油藏重要的采油机理,为研究各种因素对渗吸效果的影响,采用胜利油区纯梁采油厂天然低渗透岩心,通过在地层水和表面活性剂溶液中的自发渗吸实验,研究了润湿性、温度、粘度、界面张力等因素对渗吸的影响规律.实验结果表明:温度不是影响渗吸的直接因素,而是通过改变模拟油的粘度来间接影响渗吸;润湿性、模拟油粘度以及界面张力是影响自发渗吸的主要因素,岩石越亲水,模拟油粘度越低,渗吸采收率越高;对于亲水岩心,渗透率和界面张力控制着渗吸发生的方式;不同渗透率级别对应一个最佳的界面张力范围,在该范围内,渗吸的采收率最高;对于亲水—弱亲水岩心,岩心渗透率越大,所对应的最佳界面张力越低.     

致密砂岩动态渗吸排驱核磁共振在线实验——以松辽盆地北部扶余油层为例

为进一步明确致密油藏动态渗吸过程基质孔隙的动用特征，分析闷井渗吸转排驱的时机对致密油开发效果的影响。利用核磁共振在线扫描开展致密砂岩渗吸排驱过程中不同孔隙流体动用实验，选取松辽盆地北部扶余油层致密砂岩岩心，开展动态渗吸排驱与核磁共振联测实验，结合矩阵转换法建立弛豫时间与孔隙半径的关系，量化分析渗吸排驱过程中基质内油和压裂液的分布情况，并推算了基质渗吸作用距离。结果表明：压裂液渗吸阶段，大孔主要起渗吸排油通道作用，中孔和小孔对渗吸采收率起主要贡献，占总渗吸采收率的75.22%，渗吸速度在前8 h内保持较高水平，初期由中孔和大孔贡献，中期以小孔和微孔为主；渗吸96 h转排驱后的总采收率和压裂液返排率达到最高值，分别为40.73%和55.38%；实验模拟的基质动态渗吸作用距离约为11 cm，通过相似原理换算出现场闷井时间30 d。研究成果对松辽盆地致密油开发方案制定具有指导意义。     

红河油田长8致密储层渗吸采油影响因素分析及矿场应用

为进一步提高红河油田长8致密油藏渗吸采油效果,针对渗吸压力、储层岩石润湿性和油水界面张力范围调整等施工因素对渗吸采油效果影响规律不明确的问题,选取红河油田长8致密砂岩露头岩心,利用自行研制的高压渗吸实验装置,评价渗吸压力、储层岩石润湿性和油水界面张力等因素对渗吸效果的影响,并使用多元线性回归法对各影响因素进行相关系数计算。结果表明：增加渗吸压力能大幅提升渗吸采收率和渗吸速率,相比大气压条件下,增压0.5 MPa时,渗吸采收率增加7.40～10.76个百分点,渗吸速率提高1.39～1.81倍;同一块岩心中,通过逐级提升渗吸压力也能提高渗吸效果,当渗吸压力由0.5 MPa提升至3.0 MPa时,渗吸采收率提高了7.61个百分点;实验表明调整岩石润湿性比调整油水界面张力对影响渗吸效果更为显著,保持岩石润湿角50°,油水界面张力10^-2 mN/m时,更有利于发挥二者协同作用;多元线性回归法计算各相关系数由大到小依次为渗吸压力、岩石润湿性和油水界面张力。该研究成果对优选致密油藏渗吸增效剂和优化施工参数具有指导意义。     

利用径向积边界元方法计算动态逆向渗吸累积采收率

在开采超低渗透或致密油藏的过程中,水平井井筒周围会形成复杂的缝网,缝网将油藏分割成不同形状的基质块,当压裂液或者水在裂缝中流动时会与基质块大面积接触,在毛管压力作用下发生以动态逆向渗吸为主导的传质现象。为了准确描述针对任意形状基质块的动态逆向渗吸作用,利用基于边界元和径向积分理论的径向积边界元方法,建立适用于逆向渗吸的数学模型,通过与差分方法数值模拟结果和实验数据以及解析解进行对比,验证了所建渗吸模型的正确性,同时说明了径向积边界元方法适用于复杂形状基质块逆向渗吸累积采收率的计算;相对于差分方法,径向积边界元方法不用在基质块内部空间划分网格,使得动态逆向渗吸累积采收率的计算过程变得简单高效并且切合实际。     

Experimental investigation of shale imbibition capacity and the factors influencing loss of hydraulic fracturing fluids

Spontaneous imbibition of water-based fracturing fluids into the shale matrix is considered to be the main mechanism responsible for the high volume of water loss during the flowback period. Understanding the matrix imbibition capacity and rate helps to determine the fracturing fluid volume, optimize the flowback design, and to analyze the influences on the production of shale gas. Imbibition experiments were conducted on shale samples from the Sichuan Basin, and some tight sandstone samples from the Ordos Basin. Tight volcanic samples from the Songliao Basin were also investigated for comparison. The effects of porosity, clay minerals, surfactants, and KCl solutions on the matrix imbibition capacity and rate were systematically investigated. The results show that the imbibition characteristic of tight rocks can be characterized by the imbibition curve shape, the imbibition capacity, the imbibition rate, and the diffusion rate. The driving forces of water imbibition are the capillary pressure and the clay absorption force. For the tight rocks with low clay contents, the imbibition capacity and rate are positively correlated with the porosity. For tight rocks with high clay content, the type and content of clay minerals are the most important factors affecting the imbibition capacity. The imbibed water volume normalized by the porosity increases with an increasing total clay content. Smectite and illite/smectite tend to greatly enhance the water imbibition capacity. Furthermore, clay-rich tight rocks can imbibe a volume of water greater than their measured pore volume. The average ratio of the imbibed water volume to the pore volume is approximately 1.1 in the Niutitang shale, 1.9 in the Lujiaping shale, 2.8 in the Longmaxi shale, and 4.0 in the Yingcheng volcanic rock, and this ratio can be regarded as a parameter that indicates the influence of clay. In addition, surfactants can change the imbibition capacity due to alteration of the capillary pressure and wettability. A 10 wt% KCl solution can inhibit clay absorption to reduce the imbibition capacity.     

Beneficial effects of wettability altering surfactants in oil-wet fractured reservoirs

In fractured reservoirs, an effective matrix-fracture mass transfer is required for oil recovery. Surfactants have long been considered for oil recovery enhancement, mainly in terms of their ability to reduce oil–water interfacial tension. These surfactants are effective when the fractured formations are water-wet, where capillary imbibition of surfactants from the fracture into the matrix contributes to oil recovery. However, another beneficial aspect of surfactants, namely their ability to alter wettability, remains to be explored and exploited. Surfactants capable of altering wettability can be especially beneficial in oil-wet fractured formations, where the surfactant in the fracture diffuses into the matrix and alters the wettability, enabling imbibition of even more surfactant into the matrix. This sequential process of initial diffusion followed by imbibition continues well into the matrix yielding significant enhancements in oil recovery.In order to test this hypothesis of sequential diffusion–imbibition phenomenon, Dual-Drop Dual-Crystal (DDDC) contact angle experiments have been conducted using fractured Yates dolomite reservoir fluids, two types of surfactants (nonionic and anionic) and dolomite rock substrates. A new experimental procedure was developed in which crude oil equilibrated with reservoir brine has been exposed to surfactant to simulate the matrix-fracture interactions in fractured reservoirs. This procedure enables the measurements of dynamic contact angles and oil–water interfacial tensions, in addition to providing the visual observations of the dynamic behavior of crude oil trapped in the rock matrix as it encounters the diffusing surfactant from the fractures. Both the measurements and visual observations indicate wettability alterations of the matrix surface from oil-wet to less oil-wet or intermediate wet by the surfactants. Thus this study is of practical importance to oil-wet fractured formations where surfactant-induced wettability alterations can result in significant oil recovery enhancements. In addition, this study has also identified the need to include contact angle term in the dimensionless Bond number formulations for better quantitative interpretation of rock–fluids interactions.     

考虑接触面积与压差的致密砂岩气藏水相自吸行为

钻完井过程中,水相通过毛管自吸和正压差进入储层,会引起致密砂岩气藏水相圈闭损害,导致储层测井解释错判为水层,阻碍致密砂岩气藏的及时发现和准确评价。为了揭示致密砂岩气藏水相自吸行为,选取典型致密砂岩气藏柱塞岩样,分别模拟了钻开储层时水相接触岩石的岩样端面自吸、裂缝水淹后的岩样浸泡自吸和正压差下的毛管强制渗吸实验,分析了接触面积与压差对致密砂岩水相毛管自吸的影响。结果表明:自吸速率受到渗吸面积与裂缝发育程度的影响,裂缝越发育,接触面积越大,渗吸速率越快,渗吸越易达到平稳阶段;正压差促进岩石毛管渗吸作用,但受岩石物性影响明显,当岩石物性低到一定程度时,渗吸作用主要受到毛管力的控制;裂缝的存在既增加渗吸接触面积,又进一步强化正压差作用,使渗吸能力显著增加。结合实验研究认为,在钻完井过程中,预防致密砂岩气藏水相侵入应以封堵裂缝、控制压差来减少水岩接触面积和水相侵入量为主。      

Influence of wettability on petrophysical properties during imbibition in a random dense packing of equal spheres

Wettability, defined in terms of the value of contact angle of wetting–nonwetting–solid phase interface, is an important feature governing flow and transport processes in porous media. In this work we investigate the influence of wettability on the capillary pressure vs. saturation curve and on relative permeability during imbibition.To describe imbibition, we propose a new way of modeling it, based upon a physically consistent dynamic criterion for the imbibition of an individual pore, originally suggested by Melrose. We illustrate this approach in a simple but physically representative porous medium, the “ideal soil” (a dense random packing of equal spheres). Complete knowledge of the pore space geometry allows making a priori predictions of pore-level processes, without invoking adjustable parameters.This approach allows modeling imbibition for different values of contact angle and different initial conditions (as different drainage endpoints). The simulation yields the pore-level configuration of both fluid phases at each value of saturation. Relative permeabilities are calculated by simulating steady flow through the pore space occupied by each phase. The geometric and topological features of the flow network are directly connected to the geometry of the model rock and distribution of liquid phases in it.The simulated imbibition capillary pressure curves and relative permeability to the wetting phase are very sensitive to the value of contact angle in the whole range of wetting phase saturation. At the same time, relative permeability to the non-wetting phase is not much influenced by the wettability. Predicted capillary pressures and relative permeabilities compare favorably with experimental data for a range of wettabilities, providing strong support for the dynamic imbibition criterion.     

天然裂缝性油藏渗吸规律

为了研究渗吸作用对天然裂缝性油藏的影响,改善该类油藏的开发效果,以数值模拟为手段,通过建立概念地质模型,以静态和动态2种方式研究了毛细管压力、孔隙均匀程度、相渗曲线、基质和裂缝渗透率、原油黏度和基质含油饱和度对基质渗吸速度的影响,并在静态下对相关参数进行了公式拟合.静态下,渗吸速度与毛细管压力、基质渗透率、残余油饱和度、束缚水饱和度下的油相相对渗透率呈直线关系,与束缚水饱和度呈指数关系,与原油黏度呈幂指数关系;动态下,对于不同润湿性的油藏提出了不同的开发方式.     

润湿程度,渗透率对吸渗排油作用的影响

利用美国ＳＳＩ公司的ＣＯＭＰ模拟软件，考察了润湿性、基质渗透率和裂缝渗透率对吸渗排油过程的影响，岩石的润湿程度对基质吸渗速度有显著影响，一般亲水性越强，吸渗排油速度越快，适宜于采用较大的采油速度开采。基质渗透率同样影响吸渗速度，其值越高，吸渗排油越快；如果基质渗透率较低，因其吸渗排油速度低，不宜采用较高的采油速度。裂缝渗透率对整个基质－裂缝系统的驱替过程有显著影响，当裂缝渗透率过高时，整个系统的驱替过程很短，但基质的吸渗排油过程可能还未完毕，从而导致采收率不高。     

Pressures acting in counter-current spontaneous imbibition

Four water/oil and four oil/air linear counter-current spontaneous imbibition experiments were performed on Berea sandstone cores with permeabilities ranging from 0.065 to 1.094 μm². The cores were initially 100% saturated with non-wetting phase and all faces except one end were sealed. The experiments showed a clear frontal displacement mechanism. Capillary pressure was the driving force of the imbibition process. As well as viscous drag in both phases between the imbibition front and the open face, there is a significant opposing capillary back pressure associated with production of non-wetting phase at the open face. The location of the imbibition front, the overall changes in core saturation, and the pressure in the nonwetting phase in the dead end space ahead of the imbibition front, were monitored during the course of imbibition. The dead end pressure was essentially constant after a short start-up period. The distance advanced by the imbibition front was proportional to the square root of time. Based on the assumption that the properties of Berea sandstone of different permeabilities can be scaled, the experimental data were matched by numerical simulation to predict the saturation and pressure profiles, the saturation and capillary pressure at the imbibition front, and the capillary back pressure at the open face. The ratio of the capillary back pressure to the estimated capillary pressure at the imbibition front ranged from approximately 1/3 to 2/5, for oil displacing air, to approximately 1/9 to 1/4, for water displacing oil.     

碳酸盐岩气层岩电参数实验

储层含油气饱和度是储量评价的基础。在以Archie公式为核心的储层含油气饱和度评价方法中,岩电参数是Archie公式应用的基础。通过开展岩电参数研究实验,对利用风干法和自吸增水法建立碳酸盐岩岩心含水饱和度进行了对比。研究结果表明,由于碳酸盐岩岩心孔隙结构、润湿性复杂,依靠自吸水方式,含水饱和度高于一定值后岩心将表现出不再自吸水的现象。自吸增水法所能够达到的最高含水饱和度一般都低于50%,相对于自吸增水建立的岩心低含水饱和度时的电阻率,被模拟地层水100%饱和时的岩心电阻率R_o 普遍偏高,100%饱和状态下的岩心电阻率大都偏离了低饱和度数据点拟合线的延长线。风干法和自吸增水法获得的指数n和系数b数值上具有明显区别,但变化趋势一致,且两种饱和度建立方法获得的指数n都与孔隙度具有较高的相关性,且都随孔隙度增大而降低。对基质孔隙度、渗透率都差的碳酸盐岩储层岩石的岩电研究中,含水饱和度建立十分困难。根据碳酸盐岩气藏成藏后气水运移规律及气藏内部气水平衡过程,风干法所获得的岩电实验关系更符合碳酸盐岩气藏含气饱和度评价的需要。     

Simulation of counter-current imbibition in water-wet fractured reservoirs

Counter-current imbibition, where water spontaneously enters a water-wet rock while oil escapes by flowing in the opposite direction is a key recovery mechanism in fractured reservoirs. Fine grid, one- and two-dimensional simulations of counter-current imbibition are performed and the results are compared with experimental measurements in the literature. The experimental data are reproduced using two sets of relative permeabilities and capillary pressures. One set is derived from a counter-current experiment and one set is computed using pore-scale modelling.Two-dimensional simulations of water flow through a single high permeability fracture in contact with a lower permeability matrix are run. The results are compared with experimental measurements of fracture flow and matrix imbibition in the literature and with one-dimensional simulations that account for imbibition from fracture to matrix using an empirical transfer function. It is shown that with this transfer function the behavior of the two-dimensional displacement can be predicted using a one-dimensional model.     

Wettability alteration and oil recovery by water imbibition at elevated temperatures

This investigation adopts a new perspective on wettability alteration as a function of temperature. Colloidal (i.e., DLVO) theory and calculations are used to interpret results from laboratory-scale displacements. Water imbibition tests were conducted with 9 reservoir cores from a diatomaceous reservoir. Permeability and porosity of cores varied from 0.2 to 0.7 md and 46% to 65%, respectively. The experiments included spontaneous counter-current water imbibition followed by forced co-current water imbibition to residual oil saturation. The fluids were 34° API crude oil and synthetic formation brine. All tests were isothermal and temperatures ranged from 45 to 230 °C at pressures sufficient to maintain liquid water. The experimental results show that an increase in temperature results in: (1) a substantial increase in imbibition rate and extent of oil recovery, (2) a slight reduction in residual oil saturation, and (3) a significant shift in the Amott wettability index from intermediate and weakly water wet to strongly water wet. DLVO calculations illustrate detachment of fines from pore surfaces at high temperature. Fines detachment is a mechanism for altering wettability. Release of fines coated with oil exposes clean water-wet pore surfaces. Further calculations indicate the water–oil contact angle decreases as temperature increases indicating a systematic increase in water wettability consistent with experimental measurements of the Amott index.