Deep coalbed methane (CBM)reservoirs have become an important growth driv

er for China’s natural gas production. Field practices have revealed that fracturing sand backflow frequently occurs during the wiper trip or workover operations in deep CBM wells. This phenomenon leads to issues such as tubing erosion

sand accumulation and blockage

and production decline

which directly affect the estimated ultimate recovery (EUR)of a single well. The variation in the conductivity of supporting fractures is therefore a critical factor influencing gas production performance in deep CBM reservoirs and plays a key role in establishing appropriate fluid drainage strategies. However

existing commercial simulators fail to incorporate the influence of velocity-sensitivity effects and thus cannot characterize proppant transport and fracture conductivity evolution during the drainage and production process. As a result

the production forecast accuracy for CBM wells remains low

making it difficult to establish a scientifically based and quantitatively optimized flowback strategy. To address these challenges

core flooding experiments and particle mechanics analyses were first conducted to investigate the influence mechanisms of factors such as sand concentration

proppant particle size

and effective stress on the velocity sensitivity characteristics of fracture conductivity in deep coal seams. Based on the experimental findings

a dynamic conductivity characterization model considering the effect of flow velocity was then developed. By coupling this model with a discrete fracture model and a dual-porosity single-permeability coal seam model

the study establishes a numerical simulation method considering the effects of fracture conductivity changes. This method ultimately enables the determination of a reasonable flowback strategy. The results indicate that:(1)With the increasing of flow velocity

the fracture conductivity in deep coal seams first rises and then declines

exhibiting a peak at the flow velocities between 2.5 and 7.5 mL/min. The variation amplitude of conductivity is positively correl

ated with proppant placement concentration

particle size

and fluid viscosity

while being negatively correlated with effective stress. (2)The intrinsic mechanism governing the dynamic variation of fracture conductivity in coal rock systems lies in the dual effect of fluid flow on proppant behavior. At low flow velocities

the flushing and sand-carrying action of the fluid on small-sized proppant particles exerts a positive effect by clearing and widening the flow channels. In contrast

at high flow velocities

the fluid tends to displace large-sized proppant particles that provide structural support

producing a negative effect by promoting fracture closure. (3)Numerical simulation results that incorporate the velocity sensitivity characteristics of fracture conductivity indicate that the velocity sensitivity effect significantly reduces gas production performance. Therefore

it is necessary to control the flowback rate to mitigate the adverse impact of velocity sensitivity effects. (4)The production practices in Daji block have verified that the fracturing sand backflow volume and gas production performance of CBM wells are both governed by the liquid production rate. Based on comprehensive analyses combining physical experiments

numerical simulations

and field monitoring data

it is recommended that the flowback rate for a single layer of vertical well should be maintained at 20-23 m

3

/d

with a maximum daily liquid production not exceeding 23 m

3

/d. For horizontal wells with the single-stage fracturing parameters and stimulation effects similar to those of vertical wells

the maximum daily liquid production should not exceed (number of stages × 23)m

3

/d. The field application in Daji Block demonstrates that the maximum daily liquid production of CBM horizontal wells has been effectively reduced from 634 m

3

/d to below 230 m

3

/d. As a result

the occurrence of fracturing sand backflow is significantly mitigated

and gas production performance is markedly imp

roved. These findings provide both theoretical support and technical guidance for formulating a reasonable flowback strategy for deep CBM wells.