{"title":"页岩的液体吸收:在压裂作业后的关井期间估算失水的工作流程","authors":"K. Makhanov, A. Habibi, H. Dehghanpour, E. Kuru","doi":"10.1016/j.juogr.2014.04.001","DOIUrl":null,"url":null,"abstract":"<div><p>The imbibition of fracturing fluid into the shale matrix is identified as one of the possible mechanisms leading to high volumes of water loss to the formation in hydraulically fractured shale reservoirs. In an earlier study (Makhanov et al, 2012), several spontaneous imbibition experiments were conducted using actual shale core samples collected from Fort Simpson, Muskwa and Otter Park formations, all belonging to the Horn River shale basin. This study provides additional experimental data on how imbibition rate depends on type and concentration of salt, surfactants, viscosifiers and sample orientation with regard to the bedding plane. The study also proposes and applies a simple methodology to scale up the laboratory data for field-scale predictions.</p><p>The data show that an anionic surfactant reduces the imbibition rate due to the surface tension reduction. The imbibition rate is even further reduced when KCl salt is added to the surfactant solution. Surprisingly, viscous XG solutions show a considerable spontaneous imbibition rate when exposed to organic shales, although their viscosity is much higher than water viscosity. This observation indicates that water uptake of clay-rich organic shales is mainly controlled through preferential adsorption of water molecules by the clay particles, and high bulk viscosity of the polymer solution can only partly reduce the rate of water uptake.</p><p>The field scale calculations show that water loss due to the spontaneous imbibition during the shut-in period is a strong function of fluid/shale properties, fracture-matrix interface, and soaking time. The presented data and analyses can be used to explain why some fractured horizontal wells completed in gas shales show poor water recovery and an immediate gas production after extended shut-in periods.</p></div>","PeriodicalId":100850,"journal":{"name":"Journal of Unconventional Oil and Gas Resources","volume":null,"pages":null},"PeriodicalIF":0.0000,"publicationDate":"2014-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.1016/j.juogr.2014.04.001","citationCount":"217","resultStr":"{\"title\":\"Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations\",\"authors\":\"K. Makhanov, A. Habibi, H. Dehghanpour, E. 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The imbibition rate is even further reduced when KCl salt is added to the surfactant solution. Surprisingly, viscous XG solutions show a considerable spontaneous imbibition rate when exposed to organic shales, although their viscosity is much higher than water viscosity. This observation indicates that water uptake of clay-rich organic shales is mainly controlled through preferential adsorption of water molecules by the clay particles, and high bulk viscosity of the polymer solution can only partly reduce the rate of water uptake.</p><p>The field scale calculations show that water loss due to the spontaneous imbibition during the shut-in period is a strong function of fluid/shale properties, fracture-matrix interface, and soaking time. The presented data and analyses can be used to explain why some fractured horizontal wells completed in gas shales show poor water recovery and an immediate gas production after extended shut-in periods.</p></div>\",\"PeriodicalId\":100850,\"journal\":{\"name\":\"Journal of Unconventional Oil and Gas Resources\",\"volume\":null,\"pages\":null},\"PeriodicalIF\":0.0000,\"publicationDate\":\"2014-09-01\",\"publicationTypes\":\"Journal Article\",\"fieldsOfStudy\":null,\"isOpenAccess\":false,\"openAccessPdf\":\"https://sci-hub-pdf.com/10.1016/j.juogr.2014.04.001\",\"citationCount\":\"217\",\"resultStr\":null,\"platform\":\"Semanticscholar\",\"paperid\":null,\"PeriodicalName\":\"Journal of Unconventional Oil and Gas Resources\",\"FirstCategoryId\":\"1085\",\"ListUrlMain\":\"https://www.sciencedirect.com/science/article/pii/S221339761400024X\",\"RegionNum\":0,\"RegionCategory\":null,\"ArticlePicture\":[],\"TitleCN\":null,\"AbstractTextCN\":null,\"PMCID\":null,\"EPubDate\":\"\",\"PubModel\":\"\",\"JCR\":\"\",\"JCRName\":\"\",\"Score\":null,\"Total\":0}","platform":"Semanticscholar","paperid":null,"PeriodicalName":"Journal of Unconventional Oil and Gas Resources","FirstCategoryId":"1085","ListUrlMain":"https://www.sciencedirect.com/science/article/pii/S221339761400024X","RegionNum":0,"RegionCategory":null,"ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":null,"EPubDate":"","PubModel":"","JCR":"","JCRName":"","Score":null,"Total":0}
引用次数: 217
摘要
压裂液在页岩基质中的渗吸作用被认为是导致水力压裂页岩储层大量失水的可能机制之一。在早期的一项研究中(Makhanov et al, 2012),使用从Fort Simpson、Muskwa和Otter Park地层收集的实际页岩岩心样本进行了几次自发渗吸实验,这些岩心都属于Horn River页岩盆地。这项研究提供了额外的实验数据,说明吸胀率如何取决于盐的类型和浓度、表面活性剂、增粘剂和样品在层理平面上的取向。该研究还提出并应用了一种简单的方法,将实验室数据扩大到野外规模预测。数据表明,阴离子表面活性剂由于表面张力的降低而降低了渗吸速率。当表面活性剂溶液中加入KCl盐时,渗吸速率进一步降低。令人惊讶的是,尽管黏性XG溶液的黏度远高于水的黏度,但当接触有机页岩时,它们表现出相当大的自吸速率。这表明富泥页岩的吸水主要通过粘土颗粒对水分子的优先吸附来控制,聚合物溶液的高体积粘度只能部分降低吸水速率。现场规模计算表明,关井期间由自吸引起的失水与流体/页岩性质、裂缝-基质界面和浸泡时间密切相关。本文所提供的数据和分析可以用来解释为什么一些在页岩中完成的压裂水平井在长时间关井后,水采收率很低,并且立即产气。
Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations
The imbibition of fracturing fluid into the shale matrix is identified as one of the possible mechanisms leading to high volumes of water loss to the formation in hydraulically fractured shale reservoirs. In an earlier study (Makhanov et al, 2012), several spontaneous imbibition experiments were conducted using actual shale core samples collected from Fort Simpson, Muskwa and Otter Park formations, all belonging to the Horn River shale basin. This study provides additional experimental data on how imbibition rate depends on type and concentration of salt, surfactants, viscosifiers and sample orientation with regard to the bedding plane. The study also proposes and applies a simple methodology to scale up the laboratory data for field-scale predictions.
The data show that an anionic surfactant reduces the imbibition rate due to the surface tension reduction. The imbibition rate is even further reduced when KCl salt is added to the surfactant solution. Surprisingly, viscous XG solutions show a considerable spontaneous imbibition rate when exposed to organic shales, although their viscosity is much higher than water viscosity. This observation indicates that water uptake of clay-rich organic shales is mainly controlled through preferential adsorption of water molecules by the clay particles, and high bulk viscosity of the polymer solution can only partly reduce the rate of water uptake.
The field scale calculations show that water loss due to the spontaneous imbibition during the shut-in period is a strong function of fluid/shale properties, fracture-matrix interface, and soaking time. The presented data and analyses can be used to explain why some fractured horizontal wells completed in gas shales show poor water recovery and an immediate gas production after extended shut-in periods.