Fracture propagation law of temporary plugging and diversion fracturing in shale reservoirs under completion experiments of horizontal well with multi-cluster sand jetting perforation

This study conducted temporary plugging and diversion fracturing(TPDF)experiments using a true triaxial fracturing simulation system within a laboratory setting that replicated a lab-based horizontal well completion with multi-cluster sand jetting perforation.The effects of temporary plugging agent(TPA)particle size,TPA concentration,single-cluster perforation number and cluster number on plugging pressure,multi-fracture diversion pattern and distribution of TPAs were investigated.A combination of TPAs with small particle sizes within the fracture and large particle sizes within the segment is conducive to increasing the plugging pressure and promoting the diversion of multi-fractures.The addition of fibers can quickly achieve ultra-high pressure,but it may lead to longitudinal fractures extending along the wellbore.The temporary plugging peak pressure increases with an increase in the concentration of the TPA,reaching a peak at a certain concentration,and further increases do not significantly improve the temporary plugging peak pressure.The breaking pressure and temporary plugging peak pressure show a decreasing trend with an increase in single-cluster perforation number.A lower number of single-cluster perforations is beneficial for increasing the breaking pressure and temporary plugging peak pressure,and it has a more significant control on the propagation of multi-cluster fractures.A lower number of clusters is not conducive to increasing the total number and complexity of artificial fractures,while a higher number of clusters makes it difficult to achieve effective plugging.The TPAs within the fracture is mainly concentrated in the complex fracture areas,especially at the intersections of fractures.Meanwhile,the TPAs within the segment are primarily distributed near the perforation cluster apertures which initiated complex fractures.

Complex fracture propagation model and plugging timing optimization for temporary plugging fracturing in naturally fractured shale

In this paper,a viscoelasticity-plastic damage constitutive equation for naturally fractured shale is deduced,coupling nonlinear tensile-shear mixed fracture mode.Dynamic perforation-erosion on fluid re-distribution among multi-clusters are considered as well.DFN-FEM(discrete fracture network combined with finite element method)was developed to simulate the multi-cluster complex fractures propagation within temporary plugging fracturing(TPF).Numerical results are matched with field injection and micro-seismic monitoring data.Based on geomechanical characteristics of Weiyuan deep shale gas reservoir in Sichuan Basin,SW China,a multi-cluster complex fractures propagation model is built for TPF.To study complex fractures propagation and the permeability-enhanced region evolution,intersecting and competition mechanisms between the fractures before and after TPF treatment are revealed.Simulation results show that:fracture from middle cluster is restricted by the fractures from side-clusters,and side-clusters plugging is benefit for multi fractures propagation in uniformity;optimized TPF timing should be delayed within a higher density or strike of natural fractures;Within a reservoir-featured natural fractures distribution,optimized TPF timing for most clustered method is 2/3 of total fluid injection time as the optimal plugging time under different clustering modes.

Plugging behaviors of temporary plugging particles in hydraulic fractures

Using the visualized experimental device of temporary plugging in hydraulic fractures, the plugging behaviors of temporary plugging particles with different sizes and concentrations in hydraulic fractures were experimentally analyzed under the conditions of different carrier fluid displacements and viscosities. The results show that the greater the carrier fluid viscosity and displacement, the more difficult it is to form a plugging layer, and that the larger the size and concentration of the temporary plugging particle, the less difficult it is to form a plugging layer. When the ratio of particle size to fracture width is 0.45, the formation of the plugging layer is mainly controlled by the mass concentration of the temporary plugging particle and the viscosity of the carrier fluid, and a stable plugging layer cannot form if the mass concentration of the temporary plugging particle is less than 20 kg/m^(3)or the viscosity of the carrier fluid is greater than 3 mPa·s. When the ratio of particle size to fracture width is 0.60, the formation of the plugging layer is mainly controlled by the mass concentration of the temporary plugging particle, and a stable plugging layer cannot form if the mass concentration of the temporary plugging particle is less than 10 kg/m^(3). When the ratio of particle size to fracture width is 0.75, the formation of the plugging layer is basically not affected by other parameters, and a stable plugging layer can form within the experimental conditions. The formation process of plugging layer includes two stages and four modes. The main controlling factors affecting the formation mode are the ratio of particle size to fracture width, carrier fluid displacement and carrier fluid viscosity.

Numerical investigation of refracturing with/without temporarily plugging diverters in tight reservoirs

Refracturing is an importa nt technique to tap the potential of reservoirs and boost production in depleted oil and gas fields.However,fracture propagation during refracturing,including both conventional refracturing and temporary-plugging refracturing remains poorly understood,especially for cases with non-uniform distribution of formation pressure due to long-term oil production and water injection.Therefore,taking pilot tests of refracturing with sidetracking horizontal wells in tight reservoirs in the Changqing Oilfield,China as an example,we establish a three-dimensional numerical model of conventional refracturing and a numerical model of temporary-plugging refracturing based on the discrete lattice method.Non-uniform distributions of formation pressure are imported in these models.We discuss the effects of key operating parameters such as injection rate,cluster spacing,and number of clusters on the propagation of multi-cluster fractures for conventional refracturing.For temporaryplugging refracturing,we examine the impacts of controlling factors such as the timing and number of temporary plugging on fracture propagation.In addition,we analyze a field case of temporaryplugging refracturing using well P3 in the Changqing Oilfield.The results show that fractures during re fracturing tend to propagate preferentially and dominantly in the depleted areas.Improved stimulation effect can be obtained with an optimal injection rate and a critical cluster spacing.The proposed model of temporary-plugging refracturing can well describe the temporary plugging of dominant existingfractures and the creation of new-fractures after fracturing fluid is forced to divert into other clusters from previous dominant clusters.Multiple temporary plugging can improve the balanced propagation of multi-cluster fractures and obtain the maximum fracture area.The established numerical model and research results provide theoretical guidance for the design and optimization of key operating parameters for refracturing,especially for temporary-plugging refracturing.

Quantitative investigation of multi-fracture morphology during TPDF through true tri-axial fracturing experiments and CT scanning

Due to the reservoir heterogeneity and the stress shadow effect, multiple hydraulic fractures within one fracturing segment cannot be initiated simultaneously and propagate evenly, which will cause a low effectiveness of reservoir stimulation. Temporary plugging and diverting fracturing(TPDF) is considered to be a potential uniform-stimulation method for creating multiple fractures simultaneously in the oilfield. However, the multi-fracture propagation morphology during TPDF is not clear now. The purpose of this study is to quantitatively investigate the multi-fracture propagation morphology during TPDF through true tri-axial fracturing experiments and CT scanning. Critical parameters such as fracture spacing, number of perforation clusters, the viscosity of fracturing fluid, and the in-situ stress have been investigated. The fracture geometry before and after diversion have been quantitively analyzed based on the two-dimensional CT slices and three-dimensional reconstruction method. The main conclusions are as follows:(1) When injecting the high viscosity fluid or perforating at the location with low in-situ stress, multiple hydraulic fractures would simultaneously propagate. Otherwise, only one hydraulic fracture was created during the initial fracturing stage(IFS) for most tests.(2) The perforation cluster effectiveness(PCE) has increased from 26.62% during the IFS to 88.86% after using diverters.(3) The diverted fracture volume has no apparent correlation with the pressure peak and peak frequency during the diversion fracturing stage(DFS) but is positively correlated with water-work.(4) Four types of plugging behavior in shale could be controlled by adjusting the diverter recipe and diverter injection time, and the plugging behavior includes plugging the natural fracture in the wellbore, plugging the previous hydraulic fractures, plugging the fracture tip and plugging the bedding.

Integrated hydraulic fracturing techniques to enhance oil recovery from tight rocks

Two main challenges exist in enhancing oil recovery rate from tight oil reservoirs,namely how to create an effective complicated fracture network and how to enhance the imbibition effect of fracturing fluid.In response to the challenges,through modeling experiment in laboratory and evaluation of field application results,a set of integrated efficient fracturing and enhanced oil recovery(EOR)techniques suitable for tight oil development in China has been proposed.(1)Fracturing with temporary plugging agents to realize stimulation in multiple clusters,to form dense fracture network,and thus maximizing the drainage area;(2)Supporting induced fractures with micro-sized proppants during the prepad fluid fracture-making stage,to generate dense fracture network with high conductivity;(3)Using the liquid nanofluid as a fracturing fluid additive to increase oil-water displacement ratio and take advantage of the massive injected fracturing fluid and maximize the oil production after hydraulic fracturing.

Optimization of refracturing timing for horizontal wells in tight oil reservoirs: A case study of Cretaceous Qingshankou Formation, Songliao Basin, NE China

Tight oil reservoirs in Songliao Basin were taken as subjects and a novel idealized refracturing well concept was proposed by considering the special parameters of volume fracturing horizontal wells, the refracturing potential of candidate wells were graded and prioritized, and a production prediction model of refracturing considering the stress sensitivity was established using numerical simulation method to sort out the optimal refracturing method and timing. The simulations show that: with the same perforation clusters, the order of fracturing technologies with contribution to productivity from big to small is refracturing between existent fractured sections, orientation diversion inside fractures, extended refracturing, refracturing of existent fractures; and the later the refracturing timing, the shorter the effective time. Based on this, the prediction model of breakdown pressure considering the variation of formation pressure was used to find out the variation pattern of breakdown pressure of different positions at different production time. Through the classification of the breakdown pressure, the times of temporary plugging and diverting and the amount of temporary plugging agent were determined under the optimal refracturing timing. Daily oil production per well increased from 2.3 t/d to 16.5 t/d in the field test. The research results provide important reference for refracturing optimization design of similar tight oil reservoirs.

基于坐封受力模型的暂堵球封堵效果影响因素与参数优化

暂堵球在射孔孔眼及压裂裂缝中的坐封状态影响其封堵稳定性,暂堵球封堵效果决定暂堵转向压裂技术的成败。通过建立暂堵球坐封受力计算模型,研究了压裂液排量、密度、暂堵球及孔眼参数对暂堵球坐封受力状态及其封堵效率的影响,实验模拟了不同射孔参数、压裂排量及暂堵球/压裂液性能对封堵效果的影响。结果表明:暂堵球受拖拽力、脱离力及持球力随压裂液排量的增加而增大,暂堵球更易坐封;压裂液及暂堵球密度对暂堵球坐封封堵效率影响不大;暂堵球粒径大于孔眼直径时,暂堵球坐封封堵效率随粒径增加而增大,当暂堵球直径小于孔眼直径时,暂堵球不容易坐封;射孔孔眼数增加影响暂堵球坐封封堵效率。实验评价暂堵球最佳直径为9.0 mm,最佳泵送排量大于4.0 m^(3)/min时,有助于提高暂堵球坐封成功率,增强暂堵压裂设计的可靠性。

非常规致密油储层压裂增能一体化技术分析

针对试验区非常规致密油储层常规缝网压裂改造体积有限,压后递减快、稳产差,采出程度低的问题,采用压裂增能一体化工艺,从平衡压力、提高缝控体积及保持能量入手,总结出“补、压、闷、控”的技术思路,通过前置补充能量、增大裂缝与储层接触面积、闷井扩散压力、控制返排等方式,达到压裂增能一体化的目的。现场实施效果表明,采用多级暂堵技术改造体积提高1倍以上,闷井扩散25~30d,无效返排率降低近15个百分点,达到了入井液保持地层能量的目的。与以往单井缝网压裂、整体缝网压裂相比,增油强度分别提高0.27t/(d·m)、0.34t/(d·m);压后前3个月平均单井日增油3.0t,是同期甜点压裂和整体压裂的1.2倍和1.8倍,提产效果显著。结合现场实施及效果分析,优化完善参数设计,形成压裂增能一体化设计原则。

改性聚乙醇酸暂堵剂研发及其在河南油田的应用

酸溶性暂堵剂对地层伤害较大,解堵较麻烦,油溶性暂堵剂不适合高含水的油层;河南油田低渗透油藏地层温度为50~120℃,注水驱油见水快,常规水溶性聚乙醇酸暂堵剂和聚乳酸暂堵剂水解温度大于80℃,不能完全满足低渗透油藏暂堵压裂的需求。结合颗粒类水溶性聚乙醇酸暂堵剂和聚乳酸暂堵剂的特性和暂堵原理,采用催化剂和抑制剂使聚乙醇酸和聚乳酸发生酯化反应,生成聚乙醇酸和聚乳酸融合物,再加入成核剂及结晶促进剂,可得到改性聚乙醇酸暂堵剂。经测试,改性聚乙醇酸暂堵剂在50~120℃温度下具有常规聚乙醇酸暂堵剂的溶解性能和暂堵强度;当改性聚乙醇酸暂堵剂的总用量占比达到18%、粗粒径与细粒径质量配比接近1:1时,其封堵强度大于40 MPa,暂堵性能良好。现场试验7井次,加入改性聚乙醇酸暂堵剂后,单井施工压力最高增加了6.1 MPa,日增油5.3 t,取得了明显的增油效果。

致密砂岩气藏暂堵压裂裂缝起裂扩展实验模拟

针对鄂尔多斯盆地SD区块盒8段储层低孔低渗、非均质性强、常规压裂裂缝形态单一等问题,基于断裂力学理论,考虑缝内流体压降,结合盒8段储层岩石力学参数,开展暂堵压裂裂缝与初次压裂裂缝在整个接触过程中的相互作用力学研究。计算分析了不同裂缝走向、井斜角、方位角等参数对压裂裂缝参数的影响规律,起裂压力随井斜角和方位角的增加而减小;起裂角随井斜角增加而减小直至为0°,随方位角先增加而后减小。通过制备人工水泥试样,利用大尺寸真三轴物模实验系统模拟了暂堵压裂中新缝起裂及其转向行为,评价了不同井斜角、方位角下新缝起裂、转向及延伸行为和起裂压力及裂缝改造面积等参数。实验结果表明:井斜角增大,初次及二次起裂压力呈减小的趋势,裂缝更易转向且改造面积越大。井斜角相同时,裂缝起裂压力随井筒方位角增加而逐渐减小,裂缝改造面积随方位角增加而增大。方位角90°螺旋射孔相比方位角0°螺旋射孔形成的裂缝更为复杂,定面射孔可调控水平井破裂压力及初始破裂位置,初始破裂产生于射孔井筒界面、孔道中部等不同位置,控制射孔射角介于75°~90°。研究结果为低渗透致密砂岩气藏暂堵压裂设计提供了依据。

沁水盆地南部郑庄区块中北部煤层气直井增产新技术研究与应用

为提高沁水盆地郑庄区块中北部煤层气直井产量,基于研究区评价井地应力测试资料、压裂裂缝监测资料,分析了研究区直井增产效果差的原因,提出了针对性增产技术,开展了现场对比试验,并对结果进行了分析,结果表明郑庄中北部直井产量低、措施增产效果差的主因为:①研究区以垂直裂缝为主、压裂缝长较短,且随着埋深增加,相同压裂规模形成的裂缝尺寸减小;②随着埋深增加,支撑剂嵌入深度增加,裂缝闭合加快,导致稳产时间短,产气曲线主体形态为“单峰型”;③经初次压裂后煤体结构更加破碎,新裂缝容易进入初次压裂裂缝,造新缝难度增加。针对上述原因,创新提出的充填预堵+大规模压裂+远端支撑增产技术,“充填预堵”即先采用相对较低的排量、砂比、规模充填初次压裂裂缝,然后再进行大规模重复压裂,实现堵老缝、造新缝。“大规模”压裂即大排量、大液量、高砂比压裂,将压裂液量由600~800 m^(3)提高至1300~2000 m^(3)以上,增加改造体积;将排量由6~8 m^(3)/min提高至10~14 m^(3)/min以上,增加裂缝长度和携砂性能;采用低黏压裂液体系配合低密度支撑剂,将砂比由7%~8%提高至10%~15%以上,提高铺砂强度,降低裂缝闭合程度。“远端支撑”即采用自悬浮支撑剂与大排量相结合,增长支撑剂运移距离,提高支撑裂缝比例。充填预堵+大规模压裂+远端支撑增产技术实施后平均单井日产量达到1380 m^(3),比措施前增产1190 m^(3),比邻井稳产气量增加近1000 m^(3),实现了郑庄中北部中深储层连片低产区直井产量突破。现场对比试验表明:实施“充填预堵”后再进行大规模压裂,平均净施工压力比初次压裂增加了3.3 MPa,形成了新裂缝,比直接进行大规模压裂增量提高1000 m^(3)。总体上,充填预堵+大规模压裂+远端支撑增产技术关键参数数值越大,增产效果越好。

多级暂堵诱导分支缝开启规律

缝内多级暂堵是提高缝内净压力,激活侧向分支缝,增大侧向改造带宽,提升层内油气动用程度的有效手段之一。研究缝内多级暂堵转向规律对指导优化暂堵方案至关重要,其难点是建立缝内暂堵模拟方法。针对裂缝性超低渗储层,基于等效黏度方法,建立了缝内多级暂堵数值模型,系统研究了逼近角、应力差、暂堵次数对分支缝开启的影响规律,研究结果表明:当水平应力差≥5 MPa且逼近角较大(≥60°)时,水力裂缝倾向于穿过天然裂缝,沿当前方向扩展,无法激活天然裂缝;水平应力差≤5 MPa时且逼近角较小(≤30°)时,水力裂缝遇到天然裂缝后能够开启钝角分支;缝内初次暂堵能够有效开启高逼近角下一级分支缝,缝内二次暂堵能够开启二级分支缝;采用缝内多级暂堵能够提高单井最高日产油量至2倍,平均日产油量提升至3倍。本文研究成果对缝内多级暂堵压裂设计奠定了模型和方法基础。

低温转向压裂自降解暂堵颗粒的制备与性能评价研究

为解决低温致密油藏储层转向压裂暂堵剂的降解问题,通过溶液聚合法以丙烯酸、丙烯酰胺、PA-1交联剂和过硫酸铵引发剂制备了适用于低温致密油藏转向压裂的自降解凝胶颗粒暂堵剂,评价了凝胶颗粒的吸水性能和降解性能。同时采用单因素变量法研究了丙烯酰胺、丙烯酸、交联剂、引发剂和矿化度对凝胶颗粒性能的影响,研究了暂堵颗粒的封堵性能。结果表明,凝胶颗粒的吸水倍数为82倍,降解时间为3~6 d,通过调节配方组分可以调节暂堵剂的吸水倍数和降解时间,同时该暂堵剂具有较强的封堵能力,封堵率为99.81%,耐压20.66 MPa。注入水体积为20 PV时,封堵率仍能保持95%以上,暂堵剂可满足低温施工作业要求。

韩城区块煤层气井顶板控底重复压裂技术研究与应用

针对鄂尔多斯盆地韩城区块碎软煤层气老井采用常规重复压裂技术效果不佳的难题,以X井为研究对象,分析了初次压裂改造效果及剩余气产能特征,结合二次加砂与顶板压裂,提出顶板控底重复压裂技术。利用实验与数值模拟软件优化施工参数,优选100目石英砂控底并暂堵老缝、40/70目+20/40目石英砂支撑新缝的三级加砂工艺,优化射孔位置为距煤层顶部3~5 m,施工排量为9 m^(3)/min,平均加砂比例为9%,形成增大储层改造体积、提高储层动用程度的顶板控底重复压裂技术。在X井进行现场试验,重复压裂后新增产气量268.1万m^(3),累计应用18口井,平均单井日产气量增加1 210.42 m^(3),有效解决了碎软煤层气老井重复压裂改造效果差的问题,可以满足煤层气老井二次开发及压裂作业降本增效的需求,具有良好的推广应用价值。

页岩气水平井暂堵坐封机制与可控暂堵压裂工艺

水平井暂堵转向压裂技术是页岩气增产的关键技术之一。文中采用流体动力学软件FLUENT与离散元方法(DEM)相结合的数值建模方法,研究了水平井暂堵转向压裂技术中暂堵球在井筒中的运移规律以及颗粒间的相互作用。通过建立DEM-DDPM耦合模型发现,施工排量、暂堵球密度、暂堵球直径和压裂液黏度是影响暂堵球坐封效果的主要因素。模拟结果表明:当施工排量在4~6 m^(3)/min时,暂堵球的密度小于或等于流体密度;射孔炮眼磨蚀率在6.15%以内可以有效提高封堵效率;同时,随着压裂液黏度的增加,封堵效率先升后降。该研究结果对于优化水平井压裂暂堵球用量以及施工工艺具有重要的理论意义和指导价值。

页岩水平井多簇喷砂射孔暂堵转向压裂裂缝扩展规律

采用真三轴压裂模拟系统开展了页岩水平井多簇喷砂射孔暂堵转向压裂模拟实验,研究了暂堵剂粒径、暂堵剂浓度、单簇射孔数和簇数对封堵提压、多裂缝转向规律及暂堵剂分布的影响。结果表明:缝内小粒径组合+段内大粒径组合暂堵剂有利于提高封堵压力并促进裂缝多期性转向,添加纤维的组合可快速憋压至超高,但易产生沿着井筒扩展的纵向缝;暂堵峰值压力随暂堵剂浓度的增加而提升,但暂堵剂浓度达到一定值后,进一步增加暂堵剂浓度并不能显著提高暂堵峰值压力;岩样破裂压力和暂堵峰值压力随单簇射孔数增加呈下降趋势,较少的单簇射孔数有利于提高破裂压力及暂堵峰值压力,对多簇裂缝扩展的控制作用更显著;较少的簇数不利于人工裂缝总数及复杂程度的提升,较多的簇数难以实现有效封堵。缝内暂堵时暂堵剂主要分布在复杂裂缝区域,特别是多裂缝相交处,而段内暂堵时暂堵剂优先分布于形成复杂缝的射孔簇孔眼附近。

转向压裂暂堵剂的研究与应用进展

将油田转向压裂用暂堵剂进行了梳理分类,运用统计方法分析了近年来暂堵剂研究成果,提出普适性较强的暂堵剂的评价指标。比较分析了各种暂堵剂的性能,介绍了暂堵剂的应用发展现状和各类暂堵剂的优缺点,并对暂堵剂的发展方向提出见解。

松辽盆地致密气藏暂堵转向压裂裂缝扩展规律研究

松辽盆地致密气藏是深层天然气勘探开发的重要领域,由于气藏埋藏深(3000~5500 m)、低孔、低渗,天然裂缝欠发育,压力差值大(8~12 MPa),常规压裂裂缝形态单一,储层改造体积小,产量低,因此实现深部致密气藏人工裂缝复杂化,是提高改造效果的主攻方向。通过真三轴压裂模拟系统开展松辽盆地致密气藏井下全直径岩心暂堵转向压裂模拟实验,论证暂堵转向压裂形成复杂裂缝的可行性,评价致密气藏储层在不同粒径砾石情况下,水力压裂裂缝起裂扩展与暂堵转向特征。结果表明,致密气藏在两向应力差值高的情况下,压裂后形成双侧对称单一裂缝,采用暂堵转向压裂后,裂缝复杂程度大幅度提高,裂缝形态复杂化。粒径大的砾石致使水力裂缝局部迂曲,围绕砾石形成大量剪切微裂缝,裂缝形态更为复杂,不含砾石岩样整体裂缝形态复杂性低于含砾石岩样。

致密储层缝内暂堵转向压裂裂缝扩展规律数值模拟

基于损伤力学理论,建立了储层渗流-应力-损伤耦合裂缝扩展数值模型,将模型结果与室内真三轴水力压裂物理模拟实验结果进行了对比,验证了模型的准确性,并基于该模型探讨了压裂液黏度、排量、水平地应力差以及储层岩石非均质性对缝内暂堵转向压裂效果的影响。研究结果表明:(1)储层渗流-应力-损伤耦合裂缝扩展数值模型是联合流体流动控制方程与岩石变形方程形成整体控制方程,通过在初始裂缝扩展路径上某一区域人为设置高强度的岩石物理力学参数和较小的储层渗透率值,实现缝内暂堵的模拟。(2)缝内暂堵转向压裂裂缝扩展模型数值模拟的分支缝数量、主裂缝面积、主裂缝延伸方向等与室内真三轴水力压裂物理模拟实验的结果基本一致,该模型可实现缝内暂堵后基质的破裂与新裂缝扩展模拟,对缝内暂堵转向压裂裂缝扩展情况也具有较好的模拟效果。(3)压裂液的黏度和排量越大,缝内暂堵转向压裂裂缝长度、改造面积及偏转角度均明显增大,且逐渐由单一裂缝向复杂裂缝转变。当水平地应力差小于7.5 MPa时,缝内暂堵转向压裂的效果较好;当水平地应力差为10~15 MPa时,压裂效果变差;当水平地应力差大于15 MPa时,裂缝几乎不偏转;储层非均质性会影响裂缝局部的扩展路径,但对裂缝总体扩展趋势影响甚微。