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There are major problems in offshore hydrate production tests, such as low gas production, limited hydrate decomposition area, and short stable production duration. Hydraulic fracturing is regarded as an effective way to improve gas production from a natural gas hydrate (NGH) reservoir. However, the fracture initiation, propagation, and morphology of hydraulic fracturing in the NGH reservoir are rarely investigated. In this work, a 2D numerical model based on the cohesive element is built to study the effects of reservoir properties and fracturing execution parameters on hydraulic fracturing of the NGH reservoir. With the increase of gas hydrate saturation, the fracture initiation pressure increases obviously, and the fracture becomes longer and narrower, which can be attributed to the increase of the strength and elastic modulus of hydrate-bearing sediments. Fracture initiation pressure decreases with the increase of reservoir intrinsic permeability due to the filtration of fracturing fluid. The stress in the normal direction of the fracture surface has a more significant influence on the initiation, propagation, and size of the fracture. With the increase of in situ horizontal stress, the strength of hydratebearing sediments increases, leading to an obvious increase of fracture initiation pressure and the formation of wider and shorter fractures. In addition, a higher injection rate of fracturing fluid is conducive to the formation of wider and longer fractures. At high injection rates, the effects of fracturing fluid viscosity on fracture initiation pressure and fracture morphology are more obvious. The results obtained in this work will bring a better understanding of hydraulic fracturing in NGH reservoirs and help to construct potential reservoir stimulation strategies.

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