The bottom-hole pressure of hydraulic fracturing in ductile reservoirs is much higher than that of the hydraulic fracturing simulation, and the fracture toughness inferred from the field data is 1–3 orders of magnitude higher than that measured in the laboratory. The rock apparent fracture toughness increases with the increase in the confining pressure. Excluding the influence of the fluid viscosity and the fluid lag on the apparent fracture toughness, the fracture process zone (FPZ) at the fracture tip can explain the orders of magnitude of difference in the apparent fracture toughness between the laboratory and the field. The fracture tip is passivated by plastic deformation, forming a wide and short hydraulic fracture. However, the size of the FPZ obtained in the laboratory is in the order of centimeters to decimeters, while an FPZ of 10 m magnitude is speculated in the field. The FPZ size is affected by the rock property, grain size, pore fluid, temperature, loading rate, and loading configuration. It is found that the FPZ has a size effect that tends to disappear when the rock specimen size reaches the scale of meters. However, this cannot fully explain the experience of hydraulic fracturing practice. The hydraulic fracturing behavior is also affected by the relation between the fracture toughness and the fracture length. The fracture behavior of type II and mixed type for the ductile rock is poorly understood. At present, the apparent fracture toughness model and the cohesive zone model (CZM) are the most suitable criteria for the fracture propagation in ductile reservoirs, but they cannot fully characterize the influence of the rock plastic deformation on the hydraulic fracturing. The elastic-plastic constitutive model needs to be used to characterize the stress–strain behavior in the hydraulic fracturing simulation, and the fracture propagation criteria suitable for ductile reservoirs also need to be developed.