The economic feasibility of gas production from hydrate deposits is critical for hydrate to become an energy resource. Permeability in hydrate-bearing sediments dictates gas and water flow rates and needs to be accurately evaluated. Published permeability studies of hydrate-bearing sediments mostly quantify vertical permeability; however, the flow is mainly horizontal during gas production in layered reservoirs. Additionally, ASTM standards require a hydraulic gradient of 10–30 to be used during laboratory permeability measurements, but the gradient is much higher in the field, particularly near a production well. To address these issues, this study focuses on the hydraulic properties of a sandy silt subsample of the hydrate reservoir and a clayey silt subsample of the fine-grained, hydrate-free interbed recovered from a GC955 deep-water Gulf of Mexico gas hydrate reservoir. We characterize the sediment pore space with water retention curves for both hydrate-free and hydrate-bearing samples (hydrate saturation, S_h =80 %). Vertical deformation with increasing stress is also quantified while consolidating the samples to the 4 MPa in situ vertical effective stress. The customized permeameter measures both the horizontal and vertical permeability with increasing stress. Results show that high hydraulic gradients lower permeability in the flow direction, possibly due to increased flow tortuosity and local sediment compaction from the high seepage force. Assuming a single permeability value, even though hydraulic gradients decrease with distance from the well, is not realistic for field estimations. The results highlight that permeability anisotropy, hydrate saturation, stress conditions, and hydraulic gradient all substantially impact reservoir permeability during production.