Hydrajet fracturing could be a promising technique for increasing hydrate production; however, the pressure distribution law inside the perforation tunnel must first be investigated. This study established a two-dimensional axisymmetric model of the submerged water jet, employing the shear-stress transport k − ω turbulence model, to analyze the pressure distribution. The study examines the impact of various factors on pressure distribution, including well completion, perforation tunnel root diameter, hole diameter on the casing wall, nozzle diameter, nozzle pressure drop, confining pressure, and jet distance. Results reveal that the pressure inside the perforation tunnel exceeds the confining pressure due to jet flow, resulting in pressurization within the erosion tunnel, unaffected by the confining pressure. As the perforation tunnel root diameter increases, the pressurization drops sharply in a parabolic manner in both open hole and uncemented casing completion wells. For cemented casing completion wells, the pressurization is dependent solely on the hole diameter on the casing wall, and the perforation tunnel root diameter has no influence. As the nozzle diameter expands, the pressurization increases exponentially, with a more pronounced effect in open-hole conditions. The pressurization rises linearly in proportion to the nozzle pressure drop. In open-hole wells, a larger nozzle diameter leads to a greater linear increase. For uncemented casing completion, the rate of linear change first increases and then decreases as the hole diameter on the casing wall increases. As the jet distance increases, the pressurization first rises and then falls. The optimal jet distance for maximizing pressurization in open-hole wells decreases with increasing nozzle diameter. In uncemented casing completion wells, increasing the distance between the nozzle and the casing leads to greater pressurization. The results provide theoretical support for the application of hydraulic jet fracturing technology in hydrate extraction.

The efficient extraction of natural gas from marine natural gas hydrate (NGH) reservoirs is challenging, due to their low permeability, high hydrate saturation, and fine-grained sediments. Hydraulic fracturing has been proven to be a promising technique for improving the permeability of these unconventional reservoirs. This study presents a comprehensive triaxial experimental investigation of the fracturing behavior and fracture initiation mechanisms of NGH-bearing sediments, using large-scale ice-saturated synthetic cubic models. The experiments systematically explore the effects of key parameters, including the injection rate, fluid viscosity, ice saturation, perforation patterns, and in situ stress, on fracture propagation and morphology. The results demonstrate that at low fluid viscosities and saturation levels, transverse and torsional fractures dominate, while longitudinal fractures are more prominent at higher viscosities. Increased injection rates enhance fracture propagation, generating more complex fracture patterns, including transverse, torsional, and secondary fractures. A detailed analysis reveals that the perforation design significantly influences the fracture direction, with 90° helical perforations inducing vertical fractures and fixed-plane perforations resulting in transverse fractures. Additionally, a plastic fracture model more accurately predicts fracture initiation pressures compared to traditional elastic models, highlighting a shift from shear to tensile failure modes as hydrate saturation increases. This research provides new insights into the fracture mechanisms of NGH-bearing sediments and offers valuable guidance for optimizing hydraulic fracturing strategies to enhance resource extraction in hydrate reservoirs.

Marine gas hydrates are recognized as a promising offshore energy resource. Self-heat fluid injection is an innovative thermal-enhanced gas recovery technique for hydrate exploitation engineering. This study numerically investigates hydrate saturation during the self-heating reagent injection process in a sub-sea hydrate reservoir, decoupled from gas production interference. This process employs two consecutive stages: reactive chemical flow stage followed by non-reactive flow stage. The simulation output parameters encompass reservoir temperature, fluid saturation, thermal conductivity, and heat flow rate. The base case demonstrates that fluid injection elevates reservoir temperature from 13.0 °C to 29.3 °C and reduces hydrate saturation from 0.40 to 0.21 through coupled heat–mass transfer mechanisms during the reactive flow stage. In the consequent non-reactive flow stage, hydrate saturation decreases to zero. Sensitivity analysis reveals that initial permeability variation governs the hydrate saturation and temperature during the non-reactive phase. The permeability range of less than 15 mD is the optimal threshold preventing hydrate reformation during fluid injection. 55–70 mD permeability triggers severe secondary hydrate generation, which decreases the fluid application feasibility. Fluid flooding demonstrates superior hydrate dissociation efficacy compared to in situ thermal stimulation. This study develops a novel simulation approach to characterize marine hydrate saturation dynamics.