Influence of injection rate and fracturing fluid viscosity on hydraulic fracture geometry in coal

Key words:  coalbed fracturing physical simulation  injection rate  fracturing fluid viscosity  hydraulic fracture geometry  coalbed methane

Abstract:

Injection rate and fracturing fluid viscosity are two important controllable parameters in the fracturing design of coalbed methane (CBM) well. They not only are the factors that affect the breakdown pressure of the borehole and treatment pressure during the fracturing treatment, but also can control the geometry of hydraulic fracture. Through several groups of large scale true tri-axial tests, influences of injection rate and fracturing fluid viscosity on hydraulic fracture geometry and treatment pressure in coal specimens collected from Daning-Jixian coal field, southeast of Ordos Basin were studied. The results show that low injection rate and low fracturing fluid viscosity reopen the coal cleats, and branch joints connect with the main fractures to form fracture networks with a dominating direction along the direction of maximum horizontal stress. With injection rate or fracturing fluid viscosity increasing, hydraulic fracture complexity is greatly reduced and a planar fracture tends to form. Increasing injection rate or fracturing fluid viscosity will also increase the treatment pressure. Optimal design of the injection rate and fracturing fluid viscosity can enhance the drainage volume of single CBM well by generating a complex fracture network at a certain distance from the wellbore after the creation of a planar fracture near the wellbore.