Also, we use the method of Design of Experiment to perform sensitivity studies with six uncertain parameters such as reservoir permeability, bottom hole pressure, fracture conductivity, initial reservoir pressure, porosity, and fracture spacing to screen insignificant parameters and obtain critical parameters that control this process.
Eight parameters are considered as input factors to build the model: reservoir permeability, initial dissolved gas-oil ratio, rock compressibility, gas relative permeability, slope of gas oil ratio, initial reservoir pressure, flowing bottom hole pressure, and hydraulic fracture spacing.
In particular, the formation pressure is equal to the bottom hole pressure on the fracture surface.
With the depressurization of the reservoir during the primary production, liquid condenses from the gas phase and builds up once the in situ reservoir pressure drops below the dew-point pressure, especially around the fractures and the well bottom hole.
Figure 2 shows that the induced stress of seam fractures is positively correlated with the net pressure on the fracture surface, which also means that the induced stress of seam fractures is negatively correlated with the bottom hole pressure.
For example, when the bottom hole pressure is 1 MPa, the net pressure on the fracture surface ( P_{i} ) is − 10 MPa.
Therefore, the induced stress of seam fractures is positively correlated with the net pressure on the fracture surface ( p_{i} ) and negatively correlated with the bottom hole pressure ( p_{wf} ).
In order to avoid the breakout of the coal seam around hydraulic fracture during drainage process, the model of the reasonable bottom hole pressure is also built.
Also induced hydraulically fracture increases well injectivity by decreasing pressure difference between well bottom hole and the reservoir.
The result shows that increasing the permeability of artificial fractures is a suitable strategy to raise the actual bottom hole pressure, but only in low-permeability matrices.
