Fracturing Fluid Distribution in Shale Gas Reservoirs Due to Fracture Closure, Proppant Distribution and Gravity Segregation

2017 ◽  
Author(s):  
Yongzan Liu ◽  
Juliana Y. Leung ◽  
Rick Chalaturnyk ◽  
Claudio J.J. Virues
Keyword(s):  
Shale Gas ◽  
Fluid Distribution ◽  
Fracturing Fluid ◽  
Gas Reservoirs ◽  
Gravity Segregation ◽  
Shale Gas Reservoirs ◽  
Fracture Closure

New Insights on Mechanisms Controlling Fracturing-Fluid Distribution and Their Effects on Well Performance in Shale-Gas Reservoirs

2019 ◽  
Vol 34 (03) ◽  
pp. 564-585
Author(s):  
Yongzan Liu ◽  
Juliana Yuk Leung ◽  
Richard J. Chalaturnyk ◽  
Claudio Juan José Virues
Keyword(s):  
Shale Gas ◽  
Fluid Distribution ◽  
Well Performance ◽  
Fracturing Fluid ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs

scholarly journals History Matching and Forecast of Shale Gas Production Considering Hydraulic Fracture Closure

Energies ◽  
2019 ◽  
Vol 12 (9) ◽  
pp. 1634 ◽  
Author(s):  
Juhyun Kim ◽  
Youngjin Seo ◽  
Jihoon Wang ◽  
Youngsoo Lee
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
History Matching ◽  
Gas Flow ◽  
Fluid Pressure ◽  
Gas Production ◽  
Hydraulic Fractures ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Fracture Closure

Most shale gas reservoirs have extremely low permeability. Predicting their fluid transport characteristics is extremely difficult due to complex flow mechanisms between hydraulic fractures and the adjacent rock matrix. Recently, studies adopting the dynamic modeling approach have been proposed to investigate the shape of the flow regime between induced and natural fractures. In this study, a production history matching was performed on a shale gas reservoir in Canada’s Horn River basin. Hypocenters and densities of the microseismic signals were used to identify the hydraulic fracture distributions and the stimulated reservoir volume. In addition, the fracture width decreased because of fluid pressure reduction during production, which was integrated with the dynamic permeability change of the hydraulic fractures. We also incorporated the geometric change of hydraulic fractures to the 3D reservoir simulation model and established a new shale gas modeling procedure. Results demonstrate that the accuracy of the predictions for shale gas flow improved. We believe that this technique will enrich the community’s understanding of fluid flows in shale gas reservoirs.

scholarly journals Study on the Spontaneous Imbibition Characteristics of the Deep Longmaxi Formation Shales of the Southern Sichuan Basin, China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-13
Author(s):  
Chao Qian ◽  
Xizhe Li ◽  
Weijun Shen ◽  
Wei Guo ◽  
Yong Hu ◽  
...  
Keyword(s):  
Pore Structure ◽  
Shale Gas ◽  
Inhibitory Effect ◽  
Spontaneous Imbibition ◽  
Structure Evolution ◽  
Gas Wells ◽  
Fracturing Fluid ◽  
Gas Reservoirs ◽  
Longmaxi Formation ◽  
Shale Gas Reservoirs

Deep shale gas reservoirs are a significant alternative type of shale gas reservoir in China. The productivity of deep shale gas wells is lower than that of shallow shale, and the imbibition characteristics of deep shale have a significant effect on the retention and backflow of fracturing fluid and the productivity of shale gas wells. In this study, the pore structure characteristics of organic-rich deep shale in the Lower Silurian Longmaxi Formation of Weiyuan-Luzhou play were analyzed by low-temperature nitrogen adsorption experiments, and then the imbibition characteristics and factors influencing deep shale were extensively investigated by spontaneous imbibition and nuclear magnetic resonance experiments. The results show that mainly micropores and mesopores are growing in the deep organic-rich shale of the Longmaxi Formation. The spontaneous imbibition curve of deep shale can be divided into an initial spontaneous imbibition stage, an intermediate transition stage, and a later diffusion stage, and the imbibition capacity coefficient of deep shale is lower than that of shallow shale. The transverse relaxation time (T2) spectrum distributions suggest that clay hydration and swelling produce new pores and microcracks, but then some pores and microfractures close. Deep shale reservoirs have an optimal hydration time when their physical properties are optimal. The increasing pore volume and the decreasing TOC content can enhance the imbibition capacity of shale. An inorganic salt solution, especially a KCl solution, has an inhibitory effect on the imbibition of shale. Higher salinity will result in a stronger inhibitory effect. It is crucial to determine the optimal amount of fracturing fluid and soaking time, and fracturing fluid with a high K+ content can be injected into the Longmaxi Formation deep shale to suppress hydration. These results provide theoretical guiding significance for comprehending the spontaneous imbibition and pore structure evolution characteristics of deep shale and enhancing methane production in deep shale gas reservoirs.

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