特低渗油藏多段压裂水平井注水可行性分析

摘要：针对特低渗油藏中多段压裂水平井注水开发的可行性问题,论文采用流线模拟方法,研究了多段压裂水平井在一注一采下的生产动态特征,探讨了影响压裂水平井注水开发的主控因素。模拟结果表明：在不发生水窜的情况下,压裂水平井注水能增大单井注入量,提高采油速度和阶段采出程度。同时,交错部署裂缝,裂缝穿透比为02~04时利于注水开发。裂缝水窜增大压裂水平井注水风险,边部水窜、多条裂缝水窜,加速油井水淹,从而丧失压裂水平井注水的优势。在地质条件稳定,裂缝规模可控的条件下,可以尝试开展多段压裂水平井注水实验。研究结果可为特低渗油藏中多段压裂水平井注水提供理论支持。     

安塞油田注水开发技术研究

安塞油田特低渗透油藏的非均质性较强,注水开发启动压力梯度大、天然微裂缝较发育和油井见水后采液、采油指数下降等因素对注水开发效果的影响日益突出,根据安塞油田多年实际注水开发试验,从注水参数优化、精细注水单元划分、注水剖面调整和优化注采井网方面分析总结了安塞油田注水开发的基本方法和基本特点,在注水参数优化方面提出了超前注水及油井投产的时机选择,以及强化注水、不稳定注水的特点和方法,针对油层的非均质性提出了三分精细注水的核心和方法,对剖面调整技术和井网优化技术的实际应用效果进行了分析评价.为油田开发提供了技术借鉴和指导.     

芦子沟地区长6油藏井网系统论证

芦子沟地区长6油层组属于特低渗透储层,井网系统的合理性直接制约着该油藏注水开发效果的好坏。通过对研究区进行生产动态分析,发现研究区出现的单井产能下滑等一系列开发矛盾与井网适应性相关。结合油藏工程论证及油藏数值模拟技术对研究区的井网系统进行评价,得出研究区最佳井网形式为菱形反9点注采井网,井排方向应与主裂缝方向一致(北偏东70度),合理井网密度为35.02口/km2;通过对排状注水进行论证,得出目前研究区不适宜进行排状注水。     

裂缝性低渗透油藏合理注水开发对策研究

鄂尔多斯盆地西峰油田白马中区延长组长8油藏是典型的裂缝性低渗透油藏,极高的储层非均质性和复杂的油水运动规律给注水开发方案制定带来较大困难。本次研究以生产动态分析和数值模拟为主要手段,针对注水开发中出现的矛盾与问题提出相应的解决方案和技术政策,为油田的有效开发提供科学依据。研究表明该油田在注水开发中存在三大矛盾,即注采井网与裂缝系统之间的矛盾,地层压力与单井产能之间的矛盾以及含水上升与注水参数之间的矛盾。研究结果认为深部调剖、高含水井转注、周期注水、优化注采参数、局部井网加密等开发政策的调整可以有效缓解上述矛盾。     

低渗透油藏菱形反九点井网不等缝长优化研究

在低渗透油藏开发中广泛使用菱形反九点井网,但针对不同位置生产井及注水井的裂缝缝长配比关系还缺少广泛深入的研究。基于长庆油田某低渗透油藏参数,建立了数值模拟模型,在菱形反九点井网中分别设置不同的边井、角井和注水井裂缝穿透比,研究不同裂缝配置模式对水驱开发效果的影响。流线模拟及数值模拟计算结果表明,在注水开发中,注水井缝长是影响油田产液量及水驱效果的关键因素;边井裂缝较角井裂缝更易见水,对油田综合含水影响较大,在菱形反九点井网中需要进行不等缝长优化设计;边井裂缝缝长对水驱效果的影响分为早、中、晚期(Ⅰ、Ⅱ、Ⅲ)曲线段,随着注水井裂缝穿透比增加,早期(Ⅰ)曲线段增长,中期(Ⅱ)曲线段缩短,而晚期(Ⅲ)曲线段变化较小;随着角井裂缝穿透比增加,采出程度逐渐增大,当角井裂缝穿透比较大时,存在“反转”现象;随着注水井裂缝穿透比增加,角井裂缝优化穿透比减小,而边井裂缝优化穿透比增加。该研究成果对于指导低渗透油藏菱形反九点井网裂缝优化设计,提高波及系数和开发效果具有重要的指导意义。     

低产低渗裂缝油田吞吐采油试验研究

头台油田是构造—岩性油藏。裂缝型、特低渗透是其显著特点，常规注水开发后经常出现严重的油井水淹，造成油田开发低效。本文以头台油田研究为例，认为对于裂缝型特低渗透油田，采用注水吞吐采油技术，通过套管直接向地层注水，利用储层毛管力作用，进行油水置换，实现单井自注自采吞吐采油，可以改善油田开发效果，减缓产量递减。适合注水吞吐采油基本条件是岩石润湿性为弱亲水和岩石饱和非润湿相。影响注水吞吐采油效果的主要因素是储层吸水状况、微缝发育状况、储层非均质性、注入体积和关井压力等。吞吐采油技术可作为改善裂缝型特低渗透油藏开发效果的一种新的模式来研究和推广。     

白豹油田长6油藏裂缝见水类型研究

白豹油田长6油藏储层天然裂缝发育、人工压裂缝大量存在,裂缝系统复杂,导致注水开发矛盾加剧;通过吸水剖面、试井及脉冲中子饱和度测试等方法监测油藏动态变化,认为裂缝的存在对开发的影响主要表现出三方面:造成单井产能损失严重、井组内油井受效不均、降低储层动用程度;基于储层地质及开发特征的认识,将裂缝见水类型及特征归纳为三类:天然裂缝开启见水型、天然裂缝-压裂缝沟通见水型、压裂缝沟通见水型,并提出了分类治理对策,矿场应用中取得了较好的控水增油效果。     

中国东部深层油藏隔层裂缝及其地质意义

中国东部深层油藏隔层由于其破裂压力小，受地静压力、构造应力的作用而形成裂缝，降低了其封闭性，从而影响油田注水开发的效果。以冀东油田高尚堡Es3^2 3油藏为例，综合地质、地震、测井和生产动态资料，应用一系列先进技术，对我国东部深层油藏隔层裂缝的基本特征、分布规律进行了深入的研究，分析了隔层裂缝的形成原因及其对注水开发的影响，并提出了解决措施。     

缝洞型碳酸盐岩油藏自吸驱油作用及其在开发中的利用

缝洞型碳酸盐岩油藏的多孔基质岩块是主要的储集空间,裂缝为主要的渗流通道,储油层具有非常复杂的孔隙空间结构,影响油层的注水驱油效率,从而影响油藏的最终采收率。实验表明在不具渗透性的多孔基质岩块内,毛管自吸驱油是改善基质岩块内石油动用程度的重要作用;储层在不同含水饱和度下均存在自吸作用,毛管自吸驱油系数随自吸时间延长而提高,最高可达35%;周期注水是利用毛管自吸驱油改善开发效果的有效开发方式,实验中最佳压力变化幅度为1.5倍～2倍,且投注初期即实施周期注水的效果最好;塔河油田数值模拟研究表明周期注水开发效果明显好于依靠天然能量、连续注水的效果,其优点是既保持地层能量,避免注入水的突进,同时又充分利用毛管自吸驱油作用,周期注水是很好的提高采收率方法。     

低渗透油藏井网优化及开发技术政策研究

通过综合分析国内外对低渗透油藏井网优化、开发技术政策、改善开发效果的综合调整试验等研究成果,针对油田开发中存在的问题,加强渗流理论及数值模拟技术研究,确定合理的井底流压、注水强度、注水时机、注水压力、注采比等,不断优化和调整开发技术政策,从而满足低渗透油藏开发的实际生产需要。     

特低渗砂砾岩油藏多段压裂水平井合理注水开发方式

在特低渗砂砾岩的储层条件下,采用长井段压裂水平井弹性开发时,常出现产能随地层能量衰竭较快,难以收回开发成本的问题,采用多相渗流理论和油藏数值模拟的方法,以盐家地区特低渗砂砾岩油藏盐227块为例,根据现场实际资料,建立油藏数值模型,对盐家地区砂砾岩油藏的注水开发的可行性进行研究。基于不同开发方式的渗流机理和开发规律,研究了常规注水、超前注水、注水吞吐开发等措施的合理性,提出了针对特低渗油藏多段压裂水平井的有效开发方案,研究结果表明:与弹性开发相比,采用注水开发能解决地层能量衰竭较快的问题的同时,增大了储层动用面积及驱替时效;注水吞吐的最终含水率比常规注水降低25%左右,超前注水在前期能提高常规弹性开发产量的30%左右,可见这两种新型开发方式有利于抑制水淹和提高采收率。     

低渗透油藏CO2驱油开发方式与应用

CO₂驱是一种能大幅度提高原油采收率的三次采油技术,国内该项技术的研究和应用起步较晚,多以先导试验为主。苏北盆地溱潼凹陷经过10余年的探索,已经在5个低渗油田开展了CO₂驱先导试验和推广应用,针对这5个油藏利用一维细管模拟和油藏数值模拟方法开展了注气时机、段塞尺寸和注气部位的研究,并应用典型实例进行了分析,认为先期注入提高混相压力,可更有效地缩短两相区过渡带,增加油相中溶解的CO₂含量,降低油相粘度和油气界面张力,进而提高混相程度,更有利于驱油;采用大尺寸段塞可加大CO₂波及区域,较好地保持地层能量,从而提高油井见效率,增强驱替效果;高部位注气可有效地抑制重力超覆,减少CO₂气体过早地产出和突破的机会。就苏北盆地低渗油藏而言,采用先期注入、大尺寸段塞和高部位注气不失为一种成熟有效的提高采收率方法。     

Fast 3D Reservoir Simulation and Scale Up Using Streamtubes

This paper presents an implementation of a semianalytical method for oil recovery calculation in heterogeneous reservoirs that is both fast and accurate. The method defines streamline paths based on a conventional single-phase incompressible flow calculation. By calculating the time-of-flight for a particle along a streamline and assigning a volumetric flux to each streamline, the cumulative pore volume of a streamtube containing the streamline can be calculated. Subsequently, the streamtube geometries are kept constant and the effects of the time varying mobility distribution in two-phase flow are accounted for by varying the flow rate in each streamtube, based on fluid resistance changes along the streamtube. Oil recovery calculations are then done based on the 1D analytical Buckley–Leverett solution. This concept makes the method extremely fast and easy to implement, making it ideal to simulate large reservoirs generated by geostatiscal methods. The simulation results of a 3D heterogeneous reservoir are presented and compared with those of other simulators. The results shows that the new simulator is much faster than a traditional finite difference simulator, while having the same accuracy. The method also naturally handles the upscaling of absolute and relative permeability. We make use of these upscaling abilities to generate a coarse curvilinear grid that can be used in conventional simulators with a great advantage over conventional upscaled Cartesian grids. This paper also shows an upscaling example using this technique.     

Development Plan of East Unity Oil Field, Sudan, Using Reservoir Simulation Study

Simulation study was applied in the development planning of East Unity oil field, Sudan. A grid consisting of 2 000 cells was constructed. A major challenge of the study was to evolve a full field development and future reservoir management strategy that would ensure maximum recovery of oil based on well Un51. Simulation shows that Un51 as injection well in AradiebaC would yield better oil recovery than to be production well.     

软基真空预压加固的注气增效机制与数值分析

无砂垫层真空预压技术已成功应用于软土地基加固工程,但软土的低透水性致使其工期很长。为此提出联合间歇性注气以改进真空预压技术,提高其排水速率、缩短工期。建立联合注气的真空预压法有限元分析模型,通过注气位置与注气压力的改变,对比分析注气前后土体中渗流速度、排水速率、渗透比降等的变化规律。结果表明,注气能显著提高真空预压法的排水速率,增强真空预压法的加固效果;由于气体的轻质特性,在排水板下方注气更有利于排水效果;在不冲破土层的情况下,注气压力越大,促进加固的效果越好。联合注气能有效增强真空预压加固软土地基的排水效率,有着较好的工程应用前景。     

油藏精细地质模型网格粗化算法及其效果

在前人研究基础上, 根据DP(Dykstra-Parsons)系数能定量评价储层非均质性, 微网格块的渗透率值粗化后, 其等效渗透率的上、下限(C_min、C_max)能反映渗透率的各向异性的特点, 提出了一种运算速度快和相对有效的网格粗化算法。该算法能考虑到储层非均质性对不同方向渗透率值的影响, 且求解过程相对简单。应用该方法对鄂尔多斯盆地中部某油藏的陆相储层的精细地质模型进行了网格粗化计算, 然后在粗化后的模型上进行油藏数值模拟研究, 同时针对研究区地质背景和产出流体微可压缩的物性特征, 首次利用流线模拟器对精细地质模型进行了油藏数值模拟研究, 并以此结果为标准, 对该网格粗化算法时效性进行了系统评价。分析表明, 该算法具有较快的计算速度和较高的可靠性, 是解决储层非均质强、物性差的陆相成因油藏精细油藏数值模拟的一种行之有效的手段。      

察尔汗盐湖固体钾盐溶解对溶剂注入速率响应机制研究

察尔汗盐湖浅部储卤层赋存有储量可观的固体钾盐资源, 目前正处于溶解液化开采阶段。储卤层中固体钾盐矿物溶解及储卤层结构变化特征受到溶剂注入速率控制, 但其控制机制尚不明确。本文以察尔汗盐湖浅部储卤层典型钻孔岩芯为研究对象, 通过开展室内岩芯柱渗流模拟实验, 研究岩芯在三种流速条件下储卤层渗透系数和固体钾盐矿物溶出的变化规律。结果表明: (1)随着注入溶剂速率的增大, 岩芯渗透系数呈现逐渐增大的趋势, 渗出液中钾离子浓度呈现持续减小的趋势, 但在流速改变的时间节点处, 岩芯渗透系数和其对应溶出液中钾离子浓度均出现异常增加现象。矿物的溶解引起储层孔隙度增加, 而溶剂流速的改变会导致松散盐类矿物颗粒重组。(2)储卤层岩芯固体钾盐矿物溶解受到溶剂注入速率的影响明显。注入速率增加引起矿物颗粒重组以及滞留孔隙高浓度水体释放是造成渗出液中K+浓度短暂性升高的主要原因。本次实验研究对于研究区低品位固体钾盐的水溶开采具有一定理论指导意义。     

Modeling semi-steady state near-well flow performance for horizontal wells in anisotropic reservoirs

This paper presents a novel methodology to model semi-steady state horizontal well flow performance in an anisotropic reservoir taking into account flow in the near-well region for an arbitrary well trajectory. It is based on an analytical productivity model describing coupled axial reservoir flow and radial well inflow. In order to apply this model in an anisotropic reservoir, the permeability field relative to the radial direction perpendicular to the well trajectory and the axial direction along the well trajectory must first be determined. A classical space transformation is used in concert with rotational transforms to obtain a virtual isotropic model. The transformation preserves the volumes and pressures. It is not a novel concept, but different from previous approaches in the sense that it is only applied in the near-well domain to formulate an equally isotropic media. As a result, the use of this virtual isotropic model requires the Dietz shape factor for an ellipse, transformed from the original cylindrical near-well domain. The Dietz shape factors are determined numerically in this research. The semi-steady state well/near-well model is implemented in a numerical simulator incorporating formation anisotropy and wellbore hydraulics. The specific productivity index along the well trajectory is generated using the virtual configuration. Numerical results for different anisotropy ratios and also incorporating frictional losses in the well are presented. Furthermore, the well/near-well model is applied in coupling with streamline reservoir model for a water flooding case. This appears to be the first coupling of a well hydraulics model and a streamline simulator. It presents the application of the well/near-well model in integrated reservoir simulation in an efficient and accurate manner. The results demonstrate that the coupling approach with a streamline reservoir model and the well/near-well is of great potential for advanced well simulation efficiently.     

A flow-based pattern recognition algorithm for rapid quantification of geologic uncertainty

Geologic uncertainties and limited well data often render recovery forecasting a difficult undertaking in typical appraisal and early development settings. Recent advances in geologic modeling algorithms permit automation of the model generation process via macros and geostatistical tools. This allows rapid construction of multiple alternative geologic realizations. Despite the advances in geologic modeling, computation of the reservoir dynamic response via full-physics reservoir simulation remains a computationally expensive task. Therefore, only a few of the many probable realizations are simulated in practice. Experimental design techniques typically focus on a few discrete geologic realizations as they are inherently more suitable for continuous engineering parameters and can only crudely approximate the impact of geology. A flow-based pattern recognition algorithm (FPRA) has been developed for quantifying the forecast uncertainty as an alternative. The proposed algorithm relies on the rapid characterization of the geologic uncertainty space represented by an ensemble of sufficiently diverse static model realizations. FPRA characterizes the geologic uncertainty space by calculating connectivity distances, which quantify how different each individual realization is from all others in terms of recovery response. Fast streamline simulations are employed in evaluating these distances. By applying pattern recognition techniques to connectivity distances, a few representative realizations are identified within the model ensemble for full-physics simulation. In turn, the recovery factor probability distribution is derived from these intelligently selected simulation runs. Here, FPRA is tested on an example case where the objective is to accurately compute the recovery factor statistics as a function of geologic uncertainty in a channelized turbidite reservoir. Recovery factor cumulative distribution functions computed by FPRA compare well to the one computed via exhaustive full-physics simulations.     

Thermo-hydro-mechanical modeling of carbon dioxide injection for enhanced gas-recovery (CO2-EGR): a benchmarking study for code comparison

The objective of this paper was to investigate the THM-coupled responses of the storage formation and caprock, induced by gas production, CO₂-EGR (enhanced gas recovery), and CO₂-storage. A generic 3D planer model (20,000?×?3,000?×?100?m, consisting of 1,200?m overburden, 100?m caprock, 200?m gas reservoir, and 1,500?m base rock) is adopted for the simulation process using the integrated code TOUGH2/EOS7C-FLAC3D and the multi-purpose simulator OpenGeoSys. Both simulators agree that the CO₂-EGR phase under a balanced injection rate (31,500?tons/year) will cause almost no change in the reservoir pressure. The gas recovery rate increases 1.4?% in the 5-year CO₂-EGR phase, and a better EGR effect could be achieved by increasing the distance between injection and production wells (e.g., 5.83?% for 5?km distance, instead of 1.2?km in this study). Under the considered conditions there is no evidence of plastic deformation and both reservoir and caprock behave elastically at all operation stages. The stress path could be predicted analytically and the results show that the isotropic and extensional stress regime will switch to the compressional stress regime, when the pore pressure rises to a specific level. Both simulators agree regarding modification of the reservoir stress state. With further CO₂-injection tension failure in reservoir could occur, but shear failure will never happen under these conditions. Using TOUGH-FLAC, a scenario case is also analyzed with the assumption that the reservoir is naturally fractured. The specific analysis shows that the maximal storage pressure is 13.6?MPa which is determined by the penetration criterion of the caprock.