Multilayered reservoirs with coexisting free gas and hydrates are primary targets for commercialization, nevertheless, the extremely low permeability greatly limits their extraction efficiency. Herein, multilayer commingled production using horizontal wells stimulated by hydraulic fracturing and thermal fluid injection was proposed to enhance productivity, and the effects of key factors on co-production performance were numerically examined, with the reservoir located in the Shenhu Area as the geological background. The results indicated that due to severe interlayer contradictions, the stimulation capabilities of using fracturing or thermal fluid injection alone were limited, in particular, the extraction of hydrates severely lagged behind. However, their combination exhibited tantalizing productivity due to strengthened inter-well interaction. Reducing the fracture spacing was more effective than increasing fracture conductivity in shortening the production cycle, and intensive fractures with adequate flow capacity were suggested for gas enhancement and water control. When the fracture spacing was reduced from 30 to 5 m and the fracture conductivity increased from 10 to 100 D·cm, the horizontal section length for commercial production (average daily gas production of 50,000 m³ and recovery ratio of 0.7) was reduced from 1758 to 146 m, which is lower than the on-site horizontal section length of 250–300 m. Therefore, the proposed development mode is promising for the commingled production of gas and hydrates.

The exploitation of challenging oceanic gas hydrate reservoirs with low permeability and permeable boundary layers faces the challenges of methane leakage and low production. Considering this aspect, a novel five-spot injection–production system combined with hydraulic fracturing was proposed. In particular, the potential of this development mode, including hydrate dissociation, gas production, and gas capture, was evaluated in comparison with a three-spot injection–production system. The results showed that increasing the fracture conductivity cannot prevent CH₄ leakage in the three-spot, and the leakage accounted for 5.6% of the total gas production, even at the maximum fracture conductivity of 40 D·cm. Additionally, the leakage amount increased as the well spacing increased, and the leakage accounted for 36.7% of the total gas production when the well spacing was 140 m. However, the proposed development mode completely addressed CH₄ leakage and significantly increased gas production. The average gas production rate reached 142 m³/d per unit length of the horizontal section, which was expected to reach the commercial threshold. The variance analysis indicated that optimal plans for the challenging hydrates in the Shenhu area were well spacing of 100–120 m and fracture conductivity greater than 20 D·cm.

Advancements in drilling technology are pivotal to optimizing the production and sustainability of oil and gas wells. One of the emerging innovations is the application of a specialized fluid known as “Fuzzy-ball” fluid. This paper comprehensively reviews the historical evolution and advancements in the utilization of fuzzy-ball fluid in drilling and well-repair processes. Fuzzy-ball fluid has been discovered to bolster a formation’s pressure-bearing capabilities and systematically augment resistance against oil, gas, and water flow. These attributes have been instrumental in the phased integration of fuzzy-ball fluid into procedures aiming to enhance production in oil and gas wells. This paper bridges the knowledge gap in the industry regarding the application of fuzzy-ball fluid, thereby circumventing the challenges of inadequate understanding and suboptimal designs. However, the study acknowledges the potential limitation of information loss despite the extensive data collection from diverse sources, such as articles, patents, and reports. As a future direction, this paper emphasizes the need for a more encompassing and critical evaluation of fuzzy-ball fluid’s performance and applications. This will enable a more informed decision-making process, fostering the expanded use and understanding of this fluid’s mechanism within the industry.

Reservoir fracturing combined with thermal stimulation is a highly promising strategy for the development of challenging hydrates. However, the synergistic influence mechanisms of multiple engineering parameters on productivity remain poorly understood. In this study, based on the geological condition of the SH2 site in the Shenhu Area of the South China Sea, a numerical model was built to investigate the development efficiency of challenging hydrates under fracturing and thermal co-stimulation. Using average gas production rates (m³/d) at recovery rates of 0.70 and 0.85 as assessment indicators, eXtreme Gradient Boosting (XGBoost) and SHapley Additive exPlanations (SHAP) algorithms were employed to quantitatively measure multivariable importance. The results indicated that enhancing the inter-well interaction through reservoir fracturing can increase development efficiency by 2 to 5 times; however, it is not the case that larger-scale fracturing is always preferable, as it can lead to more severe water flooding. Additionally, data-driven models revealed that fracture length (SHAP values of 15.55 and 9.19) was the primary factor influencing development efficiency, followed by the fracture conductivity (SHAP values of 6.65 and 6.32), whereas injection pressure (SHAP values of 2.90 and 2.17), injection temperature (SHAP values of 2.41 and 2.13), and production pressure (SHAP values of 2.37 and 1.82) had relatively limited influences. Most importantly, the positive interaction effect between fracture length and fracture conductivity cannot be ignored. In our simulation, the recommended fracture length and conductivity were 40 m and 100 D·cm, respectively. These findings provide important insights and guidance for implementing this novel co-stimulation method in challenging hydrates.