Research on key fracturing technology for deep shale oil in Gaoyou Sag, Subei Basin

HUANG XIAOKAI; HUANG YUE; JIN ZHIRONG; HE LEIYU

doi:10.13809/j.cnki.cn32-1825/te.2024389

Engineering Techniques | Views : 0 下载量: 17 CSCD: 0 CNKI被引量: 0 Scopus: 0 更多指标

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Research on key fracturing technology for deep shale oil in Gaoyou Sag, Subei Basin
Vol. 16, Issue 2, Pages: 443-450(2026)
Received：11 February 2025，

Published：26 March 2026
DOI： 10.13809/j.cnki.cn32-1825/te.2024389
稿件说明：

移动端阅览

黄晓凯, 黄越, 金智荣, 等. 苏北盆地高邮凹陷深层页岩油压裂关键技术研究[J]. 油气藏评价与开发, 2026, 16(2): 443-450. DOI： 10.13809/j.cnki.cn32-1825/te.2024389.

HUANG Xiaokai, HUANG Yue, JIN Zhirong, et al. Research on key fracturing technology for deep shale oil in Gaoyou Sag, Subei Basin[J].Petroleum Reservoir Evaluation and Development, 2026, 16(2): 443-450. DOI： 10.13809/j.cnki.cn32-1825/te.2024389.

摘要

苏北盆地高邮凹陷花庄地区是江苏油田页岩油勘探的重点区块。其中，花庄Ⅱ区块页岩埋深超4 000 m，其资源量占花庄地区页岩油总资源量的42%，实现该区块高效开发对江苏油田的页岩油勘探开发工作具有重大战略意义。然而，随着埋深增加，该区块页岩油压裂面临施工压力高、加砂难度大等挑战。针对上述问题，研究团队以提高复杂度、扩大支撑面积和提升导流能力等思路为目标，开展了水力压裂物理模拟实验，分析不同排量和压裂液黏度对裂缝形态的影响规律，并采用数值模拟方法对分段分簇设计、投球暂堵工艺、支撑剂组合等进行优化。研究表明：采用中高黏度压裂液高排量注入，可提高裂缝穿层能力，但会导致开启的层理数量减少，且裂缝扩展面积相对较小；而采用低黏度压裂液和常规排量注入，更易于沟通开启层理缝。在分段分簇设计方面，单段少簇布缝有利于集中造缝能量，促进各簇裂缝均衡进液、进砂。模拟结果显示：单段设置5~6簇时，能满足裂缝均衡扩展和裂缝支撑效果，同时开展不同送球排量、暂堵球数量和直径下暂堵球对炮眼暂堵影响模拟研究，并对投球暂堵工艺参数进行优化，送球排量在12~14 m³/min之间、暂堵球直径为15 mm、暂堵球数量为孔眼数的50%~60%。结合复杂裂缝支撑剂运移铺置模拟，通过模拟确定最佳支撑剂组合及泵注参数，提高改造效果。该工艺在HY7井成功实施，峰值日产油量达到52.3 t，单井最终可采储量为4.6×10

t，为江苏油田花庄Ⅱ区块深层页岩勘探带来重大突破，对同类型页岩油开发具有重要的借鉴意义。

Abstract

The Huazhuang area in the Gaoyou Sag of the Subei Basin is a key block for shale oil exploration in the Jiangsu Oilfield. The shale in the Huazhuang Ⅱ block is buried at depths exceeding 4 000 m

accounting for 42% of the total shale oil resources in the Huazhuang area. Therefore

achieving efficient development of this block is of great significance to the Jiangsu Oilfield. However

with increasing burial depth

shale oil fracturing faces chal

lenges such as high operational pressure and difficulty in sand addition. To address these issues

the research team conducted hydraulic fracturing physical simulation experiments with the goals of increasing fracture complexity

expanding supported fracture area

and improving fracture conductivity. The influence of different injection rates and fracturing fluid viscosity on fracture morphology was analyzed

and numerical simulations were used to optimize multi-stage cluster design

ball-throwing temporary plugging techniques

and proppant combinations. The results showed that injecting medium- to high- viscosity fracturing fluid at high displacement improved fracture penetration capability but reduced the number and area of opened bedding planes. Using low-viscosity fracturing fluid with conventional displacement injection facilitated the connection and formation of bedding fractures. A single-stage design with fewer clusters was beneficial to improve the energy of each cluster

promoting more balanced fluid and sand injection among fractures. Simulation results showed that having 5-6 clusters per stage could achieve balanced fracture propagation and proppant support. At the same time

simulations were conducted to examine the impact of temporary plugging balls under different injection rates

quantities

and diameters. The optimized parameters for the temporary plugging of ball throwing were determined as follows: injection rate of 12-14 m³/min

ball diameter of 15 mm

and ball quantity of 50%-60% of the number of perforation holes. Combined with simulations of complex fracture proppant transport and placement

the optimal proppant combination and pumping parameters were determined to improve the transformation effect. This technology was successfully implemented in well HY7

yielding a peak daily oil production of 52.3 t and a single well estimated ultimate recovery of 4.6×10

t. The results represent a major breakthrough in deep shale oil exploration in the Huazhuang Ⅱ block of the Jiangsu Oilfiel

d and provide important reference for the development of similar shale oil reservoirs.

关键词

Keywords

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