Fluid
flow modeling of coalbed methane (CBM) wells is effective
in predicting gas production and designing appropriate depressurization
schemes. Moreover, hydraulic fracturing is an important measure for
improving the permeability of CBM reservoirs. In this work, we assumed
the hydraulic fracture area near the main fracture to be rectangular.
We developed a gas–water two-phase flow model considering the
difference in stress sensitivity between the hydraulic fracturing
area and the original coal reservoir. The numerical simulation results
indicate that our model can accurately predict the production of CBM
wells. In the early stage of CBM extraction, gas production increased
with the increase of gas relative permeability. When the water saturation
was below 0.7, the relative permeability of the gas phase was difficult
to increase. At this time, the absolute permeability of the hydraulic
fracturing area continued to decrease, leading to a decrease in gas
production. Thus, if the difference of permeability evolution between
the two areas is not considered, the production of CBM wells will
be overestimated. In the process of CBM extraction, both reservoir
pressure and water saturation decreased, but the distribution was
inconsistent. The variation in reservoir pressure was mainly affected
by absolute permeability and gas desorption, while the variation of
water saturation was further affected by the distribution of relative
permeability and initial water saturation. Therefore, the evolution
of water saturation is generally more complex than that of reservoir
pressure. In the hydraulic fracturing area, the effect of fracture
compressibility on gas production was greater than the initial permeability.
In the original coal reservoir, the larger initial permeability was
more beneficial than the fracture compressibility for improving the
production of CBM wells.