The safe and efficient production of marine natural gas hydrates faces the challenges of seabed geological risk issues. Geological risk issues can be categorized from weak to strong threats in four aspects: sand production, wellbore instability, seafloor subsidence, and submarine landslides, with the potential risk of natural gas leakage, and the geological risk problems that can cause secondary disasters dominated by gas eruptions and seawater intrusion. If the gas in a reservoir is not discharged in a smooth and timely manner during production, it can build up inside the formation to form super pore pressure leading to a sudden gas eruption when the overburden is damaged. There is a high risk of overburden destabilization around production wells, and reservoirs are prone to forming a connection with the seafloor resulting in seawater intrusion under osmotic pressure. This paper summarizes the application of field observation, experimental research, and numerical simulation methods in evaluating the stability problem of the seafloor surface. The theoretical model of multi-field coupling can be used to describe and evaluate the seafloor geologic risk issues during depressurization production, and the controlling equations accurately describing the characteristics of the reservoir are the key theoretical basis for evaluating the stability of the seafloor geomechanics. It is necessary to seek a balance between submarine formation stability and reservoir production efficiency in order to assess the optimal production and predict the region of plastic damage in the reservoir. Prediction and assessment allow measures to be taken at fixed points to improve reservoir mechanical stability with the numerical simulation method. Hydrate reservoirs need to be filled with gravel to enhance mechanical strength and permeability, and overburden need to be grouted to reinforce stability.

Natural gas hydrate (NGH) is a potential future energy resource. More than 90% of NGH resources exist in the pore medium of seafloor sediments. During the development of deep-sea oil and gas fields, wellbore pipelines are often clogged due to the synthesis of gas hydrates, and the addition of thermodynamic inhibitors is a common solution to prevent hydrate synthesis. In this paper, the effects of two single inhibitors, sodium chloride and ethylene glycol, as well as hybrid inhibitors combining these two inhibitors on the synthesis of methane hydrates were investigated using the self-developed one-dimensional gas hydrate exploitation simulation test apparatus. The effects of single and hybrid inhibitors were investigated in terms of the hydrate synthesis volume and gas–water two-phase conversion rate. The results show that the hybrid inhibitor has a better inhibitory effect on hydrate synthesis with the same initial synthesis driving force. When the concentration of inhibitors is low, salt inhibitors can have a better inhibitory effect than alcohol inhibitors. However, in the mixed inhibitor experiment, increasing the proportion of ethylene glycol in the mixed inhibitor can more effectively inhibit the synthesis of hydrates than increasing the proportion of sodium chloride in the mixed inhibitor.

The stepwise depressurization method offers substantial advantages in terms of mitigating the risk of pipeline blockages, ensuring production stability, and reducing environmental impact. This study employs a self-developed two-dimensional production simulation test system for natural gas hydrate. It enables precise control of depressurization rates through a servo system, allowing for stepwise depressurization within a single horizontal well at three different rates: high, medium, and low. The experiment investigates the temperature–pressure responses within the reservoir during the production, as well as gas production characteristics, including gas production and gas production rate. The results reveal that choosing a medium depressurization rate significantly increases gas production, achieving a gas production proportion of 59%. However, there is a considerable risk associated, with a peak gas production rate of 8.894 l/min, severely impacting reservoir stability and jeopardizing well control safety in the late-stage production. In the third depressurization stage, there is a relatively weak linear relationship between the normalized multiples of average gas production rate and depressurization rate, with the average gas production rate increasing to 5.78 times and 5.76 times the original rate when the depressurization rate is raised to 1.5 times and 3 times, respectively.