钻井液水活度对页岩井壁稳定性影响的实验研究——以秀山龙马溪组页岩为例
投稿时间:2022-02-27  修订日期:2022-04-28  点此下载全文
引用本文:杨现禹,蔡记华,蒋国盛,等.钻井液水活度对页岩井壁稳定性影响的实验研究——以秀山龙马溪组页岩为例[J].钻探工程,2022,49(3):1-12.
YANG Xianyu,CAI Jihua,JIANG Guosheng,et al. Experimental study on the effect of water activity of drilling fluid on shale wellbore stability—Taking Xiushan Longmaxi shale as an example[J]. Drilling Engineering, 2022,49(3):1-12.
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作者单位E-mail
杨现禹 中国地质大学(武汉)工程学院湖北 武汉 430074
中国地质大学深圳研究院广东 深圳 518000 
yxy@cug.edu.cn 
蔡记华 中国地质大学(武汉)工程学院湖北 武汉 430074
中国地质大学深圳研究院广东 深圳 518000 
caijh@cug.edu.cn 
蒋国盛 中国地质大学(武汉)工程学院湖北 武汉 430074
中国地质大学深圳研究院广东 深圳 518000 
jianggs65@vip.sina.com 
石彦平 中国地质大学(武汉)工程学院湖北 武汉 430074
中国地质大学深圳研究院广东 深圳 518000 
 
陈书雅 中国地质大学(武汉)工程学院湖北 武汉 430074
中国地质大学深圳研究院广东 深圳 518000 
 
基金项目:国家自然科学基金青年基金(编号:42002311);国家重点研发计划课题(编号:2018YFC1801705);中央引导地方科技发展资金自由探索类基础研究(编号:2021Szvup156);中央高校基本科研业务费专项资金资助项目(编号:CUG2019118);安徽省煤田地质局项目“两淮矿区地面定向多分支水平井高效钻进技术体系研究”(编号:WMDK2020-2)
中文摘要:通过压力传递实验,对秀山龙马溪组页岩进行了不同浓度和不同类型盐溶液影响下的渗流试验,确定不同水活度盐溶液对页岩渗流规律和井壁稳定影响机理。结果表明:(1)在相同浓度的盐溶液中,阻缓秀山龙马溪组页岩孔隙压力传递能力最强的盐类为HCOONa。(2)对于相同类型的盐溶液,最高的浓度并不总能具有最好阻缓能力。阻缓秀山龙马溪组页岩孔隙压力传递效果较好的前5种盐溶液是20% HCOONa、5% HCOONa、20% KCl、20% HCOOK和5% NaCl。(3)相对于人工压制页岩,在粘土矿物含量(20%)一致时,盐溶液贯穿龙马溪组页岩孔隙时间平均长90.11%,平均渗透率低99.14%。(4)在粘土矿物成分一致时,盐溶液在人工页岩中的渗流规律与龙马溪组页岩的一致性较好,但对于实际渗透率和渗流时间、表征系数与真实页岩相差大于90%。(5)针对龙马溪组页岩,提出了基于水活度的单位距离渗流时间模型,以及不同盐溶液的水活度-渗透率规律。研究成果可为适用于龙马溪组页岩钻进的水基钻井液体系遴选提供较好的理论和技术基础。
中文关键词:页岩  井壁稳定  盐溶液  水活度  水基钻井液
 
Experimental study on the effect of water activity of drilling fluid on shale wellbore stability—Taking Xiushan Longmaxi shale as an example
Abstract:A series of fluid flow tests on different concentrations and different types of salt solutions were conducted on the shale samples through the pressure transfer experiment device to study the influence mechanism of salt ions with different water activities on shale seepage. The experimental results show that the salt solution with the strongest ability to block the pore pressure transmission of Xiushan Shale in Longmaxi Formation is HCOONa among the same concentration of different brines. In addition, the five types and concentrations of salt solutions with better resistance to pore pressure transmission are 20% HCOONa, 5% HCOONa, 20% KCl, 20% HCOOK and 5% NaCl. The highest concentration does not always have the best ability to block shale pore fluid transfer for the same type of salt solution. When the mineral composition is almost the same, the time to penetrate the pores and average permeability of the Xiushan shale of the Longmaxi Formation is 90.11% higher and 99.14% lower than that of the artificially compressed shale. The seepage law of artificially suppressed shale with salt solution is consistent with the real shale. However, the difference between the characterization coefficient is more than 90% for the actual permeability and seepage time. Moreover, a unit distance seepage time model based on water activity and water activity-permeability formulas under different salt ions are proposed for the Xiushan shale of Longmaxi Formation. The research results can provide experimental and theoretical basis for maintaining shale wellbore stability of the Longmaxi Formation with brine drilling fluid.
keywords:shale  wellbore stability  salt solution  water activity  water-based drilling fluid
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