Estimating the Fracturing Fluid Recovery in Shale Gas Reservoirs: Experiments and Field Data Analysis
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RESEARCH ARTICLE-PETROLEUM ENGINEERING
Estimating the Fracturing Fluid Recovery in Shale Gas Reservoirs: Experiments and Field Data Analysis Bin Yang1,2 · Zhang Hao1 · Lijun You2 · Yili Kang2 · Zhangxin Chen3 Received: 19 May 2019 / Accepted: 19 June 2020 © King Fahd University of Petroleum & Minerals 2020
Abstract In shale gas reservoirs, the fluid flowback rates have become one of the key parameters to evaluate the fracturing operation and manage fracturing fluid after well stimulation. Based on experimental tests and a field data analysis, this paper proposed a method to estimate the fracturing fluid recovery. First, fracturing fluid imbibition and flowback experiments were conducted with fractured and matrix downhole shale plugs, and the average flowback rates for matrix and fractured samples were tested. Then, using a material balance model, the percentages of fluid retained in matrix and fractures are determined with the earlystage well production data. Combining the experimental and field results, a linear superposed model was adopted to compute the final fracturing fluid recovery. The values for the selected two wells were 23.3% and 26.2%, respectively, slightly smaller than the field-recorded values, which may be attributed to the underestimation of the flowback rate in fracture networks. A sensitivity analysis demonstrated that the recovery was more sensitive to the fluid flowback rate in fractures as more than a half of the fracturing fluid stayed there. The outcomes of this paper may explain the reasons why the fracturing fluid recovery of shale gas wells fluctuates in a wide range and wells with low flowback rates usually have a high productivity. Keywords Gas shale · Imbibition and flowback · Fluid recovery · Well productivity
1 Introduction Hydraulic fracturing has become a key technology for the commercial development of shale gas reservoirs, and during a multistage fracturing treatment, a huge amount of fracturing fluid is injected into a shale formation to create complex fracture networks [1, 2]. However, only a small fraction of the injected fluid can be recovered, and the extensive effects of the remaining fracturing fluid have attracted serious technical, economic and environmental concerns [3–5]. To respond to these issues, it is very essential to investigate the fluid retention mechanisms and forecast a fluid flowback rate after fracturing and shut-in operations.
B
Zhang Hao [email protected]
1
College of Energy Resources of Chengdu University of Technology, Chengdu, Sichuan 610059, China
2
State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, China
3
Department of Chemical and Petroleum Engineering, University of Calgary, Calgary, AB T2N 1N4, Canada
As gas shale usually has characteristics of sub-irreducible water saturation, strong water wettability, rich nanopores and a large capillary force [6–10], many papers attribute the fracturing fluid retention and low flowback rates to the water spontaneous imbibition
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