高温深井高密度砾石充填液

Mayur Deshpande, Shamit Rathi, S. Songire, Ravikant S. Belakshe, John Davis
{"title":"高温深井高密度砾石充填液","authors":"Mayur Deshpande, Shamit Rathi, S. Songire, Ravikant S. Belakshe, John Davis","doi":"10.2118/205577-ms","DOIUrl":null,"url":null,"abstract":"\n Southeast offshore India reservoirs have high-temperature deep water wells with significantly high pressures and unconsolidated sandstone formations. Controlling sand production is a major issue from inception to well completion and throughout the life of the well. A high density brine is required due to the high bottom hole pressures, thus executing sand control operations using such a high density brine as the base fluid for the gravel pack carrier fluid combined with the elevated temperatures is a significant challenge. A case is presented where a high-density temperature-resistant gravel packing fluid was optimized for a BHT of 320°F using a high-density brine. Additionally, the pH of the fluid was crucial considering the significant presence of CO2 in the formation, which was anticipated to affect asset integrity due to corrosion at low pH.\n A biopolymer-based fluid with oxidizing breaker was required in 14.2 ppg potassium-cesium formate brine and 12.5 ppg potassium formate brine. The fluid required evaluation for rheology and stability at 320°F, and at a shear rate of 170 s-1 with two conditions of viscosity to be sustained in the range of 75- 150 cP and 150-250 cP for the initial four-hour duration. The same fluid, after four hours, was also required to be broken within fourteen days. The fluid with the optimized formulation in regard with stability and rheology was further required to pass an acceptable sand suspension of ≤ 5% settling. Finally, the optimized fluid was required to show negligible corrosion effects on the downhole metallurgies. The stability and rheology were studied using a HPHT concentric cylinder viscometer. The sand suspension and corrosion characteristics were studied using an HPHT autoclave. The same fluid was studied with an acid breaker as a contingency for wells without CO2-related issues.\n After an extensive study, 12.72 gal/Mgal liquid gel concentrate of biopolymer when hydrated in 14.2 ppg and 15.45 gal/Mgal liquid gel concentrate of biopolymer, when hydrated in 12.5 ppg, providing viscosity in the range of 150-250 cP with 3 gal/Mgal and 5 gal/Mgal oxidizing breaker were selected, respectively.\n The optimized formulations passed sand suspension and had a pH in the range of 8-10, which imparted negligible corrosion loss to chrome- and nickel-based metallurgies. At the same conditions, the fluid showed acceptable results with 20 gal/Mgal organic acid breaker where the pH was ≤ 7.\n The combination of a commonly used biopolymer and a mixed formate brine produced a thermally stable fluid with unconventional chemistry, applicable for high-temperature, high-density conditions. With further study, it is expected that the temperature limit of this fluid can be extended beyond 320°F.\n The formulation for potassium formate brine was also tested at using field scale equipment to check for ease of mixing, reproducibility of results and for determining friction values when pumped at a certain rate via shunts. The fluid was mixed with relative ease using standard batch mixers and replicated the properties that were determined on a lab scale. The fluid also depicted superior proppant carrying capacities and lower friction numbers than expected which would enable lowering of overall surface pressures and surface pumping requirements.","PeriodicalId":11017,"journal":{"name":"Day 2 Wed, October 13, 2021","volume":null,"pages":null},"PeriodicalIF":0.0000,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":"0","resultStr":"{\"title\":\"High Density Gravel Packing Fluid for High-Temperature Deep Water Wells\",\"authors\":\"Mayur Deshpande, Shamit Rathi, S. Songire, Ravikant S. Belakshe, John Davis\",\"doi\":\"10.2118/205577-ms\",\"DOIUrl\":null,\"url\":null,\"abstract\":\"\\n Southeast offshore India reservoirs have high-temperature deep water wells with significantly high pressures and unconsolidated sandstone formations. Controlling sand production is a major issue from inception to well completion and throughout the life of the well. A high density brine is required due to the high bottom hole pressures, thus executing sand control operations using such a high density brine as the base fluid for the gravel pack carrier fluid combined with the elevated temperatures is a significant challenge. A case is presented where a high-density temperature-resistant gravel packing fluid was optimized for a BHT of 320°F using a high-density brine. Additionally, the pH of the fluid was crucial considering the significant presence of CO2 in the formation, which was anticipated to affect asset integrity due to corrosion at low pH.\\n A biopolymer-based fluid with oxidizing breaker was required in 14.2 ppg potassium-cesium formate brine and 12.5 ppg potassium formate brine. The fluid required evaluation for rheology and stability at 320°F, and at a shear rate of 170 s-1 with two conditions of viscosity to be sustained in the range of 75- 150 cP and 150-250 cP for the initial four-hour duration. The same fluid, after four hours, was also required to be broken within fourteen days. The fluid with the optimized formulation in regard with stability and rheology was further required to pass an acceptable sand suspension of ≤ 5% settling. Finally, the optimized fluid was required to show negligible corrosion effects on the downhole metallurgies. The stability and rheology were studied using a HPHT concentric cylinder viscometer. The sand suspension and corrosion characteristics were studied using an HPHT autoclave. The same fluid was studied with an acid breaker as a contingency for wells without CO2-related issues.\\n After an extensive study, 12.72 gal/Mgal liquid gel concentrate of biopolymer when hydrated in 14.2 ppg and 15.45 gal/Mgal liquid gel concentrate of biopolymer, when hydrated in 12.5 ppg, providing viscosity in the range of 150-250 cP with 3 gal/Mgal and 5 gal/Mgal oxidizing breaker were selected, respectively.\\n The optimized formulations passed sand suspension and had a pH in the range of 8-10, which imparted negligible corrosion loss to chrome- and nickel-based metallurgies. At the same conditions, the fluid showed acceptable results with 20 gal/Mgal organic acid breaker where the pH was ≤ 7.\\n The combination of a commonly used biopolymer and a mixed formate brine produced a thermally stable fluid with unconventional chemistry, applicable for high-temperature, high-density conditions. With further study, it is expected that the temperature limit of this fluid can be extended beyond 320°F.\\n The formulation for potassium formate brine was also tested at using field scale equipment to check for ease of mixing, reproducibility of results and for determining friction values when pumped at a certain rate via shunts. The fluid was mixed with relative ease using standard batch mixers and replicated the properties that were determined on a lab scale. The fluid also depicted superior proppant carrying capacities and lower friction numbers than expected which would enable lowering of overall surface pressures and surface pumping requirements.\",\"PeriodicalId\":11017,\"journal\":{\"name\":\"Day 2 Wed, October 13, 2021\",\"volume\":null,\"pages\":null},\"PeriodicalIF\":0.0000,\"publicationDate\":\"2021-10-04\",\"publicationTypes\":\"Journal Article\",\"fieldsOfStudy\":null,\"isOpenAccess\":false,\"openAccessPdf\":\"\",\"citationCount\":\"0\",\"resultStr\":null,\"platform\":\"Semanticscholar\",\"paperid\":null,\"PeriodicalName\":\"Day 2 Wed, October 13, 2021\",\"FirstCategoryId\":\"1085\",\"ListUrlMain\":\"https://doi.org/10.2118/205577-ms\",\"RegionNum\":0,\"RegionCategory\":null,\"ArticlePicture\":[],\"TitleCN\":null,\"AbstractTextCN\":null,\"PMCID\":null,\"EPubDate\":\"\",\"PubModel\":\"\",\"JCR\":\"\",\"JCRName\":\"\",\"Score\":null,\"Total\":0}","platform":"Semanticscholar","paperid":null,"PeriodicalName":"Day 2 Wed, October 13, 2021","FirstCategoryId":"1085","ListUrlMain":"https://doi.org/10.2118/205577-ms","RegionNum":0,"RegionCategory":null,"ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":null,"EPubDate":"","PubModel":"","JCR":"","JCRName":"","Score":null,"Total":0}
引用次数: 0

摘要

印度东南部近海储层具有高温深水井,具有明显的高压和松散的砂岩地层。从开始到完井,以及在井的整个生命周期中,控制出砂都是一个主要问题。由于井底压力高,因此需要高密度的盐水,因此使用高密度盐水作为砾石充填携砂液的基液并结合高温进行防砂作业是一个重大挑战。本文介绍了一种高密度耐温砾石充填液,使用高密度盐水对BHT达到320°F进行了优化。此外,考虑到地层中存在大量的二氧化碳,流体的pH值至关重要,预计在低pH值下,二氧化碳会腐蚀资产的完整性。在14.2 ppg甲酸钾-铯盐水和12.5 ppg甲酸钾盐水中,需要一种含有氧化破盐剂的生物聚合物基流体。该流体需要在320°F、170 s-1剪切速率、75- 150 cP和150-250 cP两种粘度条件下进行流变学和稳定性评估,持续时间为4小时。同样的液体,在4小时后,也被要求在14天内打破。在稳定性和流变性方面,进一步要求具有优化配方的流体通过可接受的砂悬浮沉降≤5%。最后,要求优化后的流体对井下冶金的腐蚀影响可以忽略不计。用HPHT同心圆筒粘度计对其稳定性和流变性进行了研究。利用高温高压灭菌器研究了砂的悬浮和腐蚀特性。在没有二氧化碳相关问题的井中,研究人员使用了一种酸破剂,作为应急措施。经过广泛的研究,选择了14.2 ppg水合时12.72 gal/Mgal的生物聚合物液体凝胶浓缩液和12.5 ppg水合时15.45 gal/Mgal的生物聚合物液体凝胶浓缩液,分别具有150-250 cP范围内的粘度和3 gal/Mgal和5 gal/Mgal的氧化破剂。优化后的配方通过了砂悬浮,pH值在8-10之间,对铬基和镍基冶金的腐蚀损失可以忽略不计。在相同的条件下,当pH≤7时,20 gal/Mgal有机酸破胶剂的效果可以接受。将一种常用的生物聚合物与一种混合的甲酸盐盐水结合,产生了一种具有非常规化学性质的热稳定流体,适用于高温、高密度条件。通过进一步的研究,预计该流体的温度极限可以扩展到320°F以上。还使用现场规模设备对甲酸钾盐水配方进行了测试,以检查混合的容易程度、结果的可重复性以及通过分流器以一定速率泵送时的摩擦值。使用标准批量混合器相对容易地混合了该流体,并复制了在实验室规模上确定的性质。该流体的支撑剂携带能力也比预期的要好,摩擦数也比预期的低,这将降低地面总压力和地面泵送要求。
本文章由计算机程序翻译,如有差异,请以英文原文为准。
查看原文
分享 分享
微信好友 朋友圈 QQ好友 复制链接
本刊更多论文
High Density Gravel Packing Fluid for High-Temperature Deep Water Wells
Southeast offshore India reservoirs have high-temperature deep water wells with significantly high pressures and unconsolidated sandstone formations. Controlling sand production is a major issue from inception to well completion and throughout the life of the well. A high density brine is required due to the high bottom hole pressures, thus executing sand control operations using such a high density brine as the base fluid for the gravel pack carrier fluid combined with the elevated temperatures is a significant challenge. A case is presented where a high-density temperature-resistant gravel packing fluid was optimized for a BHT of 320°F using a high-density brine. Additionally, the pH of the fluid was crucial considering the significant presence of CO2 in the formation, which was anticipated to affect asset integrity due to corrosion at low pH. A biopolymer-based fluid with oxidizing breaker was required in 14.2 ppg potassium-cesium formate brine and 12.5 ppg potassium formate brine. The fluid required evaluation for rheology and stability at 320°F, and at a shear rate of 170 s-1 with two conditions of viscosity to be sustained in the range of 75- 150 cP and 150-250 cP for the initial four-hour duration. The same fluid, after four hours, was also required to be broken within fourteen days. The fluid with the optimized formulation in regard with stability and rheology was further required to pass an acceptable sand suspension of ≤ 5% settling. Finally, the optimized fluid was required to show negligible corrosion effects on the downhole metallurgies. The stability and rheology were studied using a HPHT concentric cylinder viscometer. The sand suspension and corrosion characteristics were studied using an HPHT autoclave. The same fluid was studied with an acid breaker as a contingency for wells without CO2-related issues. After an extensive study, 12.72 gal/Mgal liquid gel concentrate of biopolymer when hydrated in 14.2 ppg and 15.45 gal/Mgal liquid gel concentrate of biopolymer, when hydrated in 12.5 ppg, providing viscosity in the range of 150-250 cP with 3 gal/Mgal and 5 gal/Mgal oxidizing breaker were selected, respectively. The optimized formulations passed sand suspension and had a pH in the range of 8-10, which imparted negligible corrosion loss to chrome- and nickel-based metallurgies. At the same conditions, the fluid showed acceptable results with 20 gal/Mgal organic acid breaker where the pH was ≤ 7. The combination of a commonly used biopolymer and a mixed formate brine produced a thermally stable fluid with unconventional chemistry, applicable for high-temperature, high-density conditions. With further study, it is expected that the temperature limit of this fluid can be extended beyond 320°F. The formulation for potassium formate brine was also tested at using field scale equipment to check for ease of mixing, reproducibility of results and for determining friction values when pumped at a certain rate via shunts. The fluid was mixed with relative ease using standard batch mixers and replicated the properties that were determined on a lab scale. The fluid also depicted superior proppant carrying capacities and lower friction numbers than expected which would enable lowering of overall surface pressures and surface pumping requirements.
求助全文
通过发布文献求助,成功后即可免费获取论文全文。 去求助
来源期刊
自引率
0.00%
发文量
0
期刊最新文献
Technological Features of Associated Petroleum Gas Miscible Injection MGI in Order to Increase Oil Recovery at a Remote Group of Fields in Western Siberia Interdisciplinary Approach for Wellbore Stability During Slimhole Drilling at Volga-Urals Basin Oilfield A Set of Solutions to Reduce the Water Cut in Well Production Production Optimiser Pilot for the Large Artificially-Lifted and Mature Samotlor Oil Field Artificial Neural Network as a Method for Pore Pressure Prediction throughout the Field
×
引用
GB/T 7714-2015
复制
MLA
复制
APA
复制
导出至
BibTeX EndNote RefMan NoteFirst NoteExpress
×
×
提示
您的信息不完整,为了账户安全,请先补充。
现在去补充
×
提示
您因"违规操作"
具体请查看互助需知
我知道了
×
提示
现在去查看 取消
×
提示
确定
0
微信
客服QQ
Book学术公众号 扫码关注我们
反馈
×
意见反馈
请填写您的意见或建议
请填写您的手机或邮箱
已复制链接
已复制链接
快去分享给好友吧!
我知道了
×
扫码分享
扫码分享
Book学术官方微信
Book学术文献互助
Book学术文献互助群
群 号:481959085
Book学术
文献互助 智能选刊 最新文献 互助须知 联系我们:info@booksci.cn
Book学术提供免费学术资源搜索服务,方便国内外学者检索中英文文献。致力于提供最便捷和优质的服务体验。
Copyright © 2023 Book学术 All rights reserved.
ghs 京公网安备 11010802042870号 京ICP备2023020795号-1