Safe, efficient, and economical gas recovery from hydrate-bearing sediments (HBS) is a severe issue that determines if natural gas hydrate (NGH), as an alternative energy in the future as fossil fuels approach depletion, is applied. Researchers worldwide are committed to developing a safe, efficient, and economical method of gas recovery from HBS. However, until now, most methods are still being validated and not have not been identified to exploit NGH commercially. Therefore, it is appropriate and significant to discuss researchers’ achievements to exploit NGH and summarize their potential benefits and challenges. This paper introduces nearly all the conventional and latest NGH exploitation methods and reviews field trials’ development characteristics. On the basis of laboratory experiments and field trials, key challenges restricting safe and efficient NGH development, and the existing research gaps reflecting these challenges, are also presented from the gas production, security, and economic aspects. The unfavorable situation mainly comprises the insufficient sensible heat, extremely low thermal conductivity, and ultralow permeability of HBS, lower gas production rate and its intense fluctuations, higher water-to-gas ratio (WGR), geological deformation, and subsidence of HBS attributed to excessive sand production, driving the consideration of some possible solutions. Given this, a new method for enhanced gas production from HBS based on the combination of depressurization (DP) and an in-situ heat generation method is proposed. Benefiting from multiple theoretical enhancement mechanisms such as replenishing energy to HBS with in-situ heat generation powders, cementing and strengthening the HBS skeleton, improving the gas permeability in HBS, decreasing the WGR based on blocking water, and removing gas characteristics of hydration products, this method could be expected to achieve promising long-term performance of gas production, which will be theoretically and practically significant to study commercial gas production.

In the drilling process for deepwater and hydrate formations, adding salty components to drilling fluids is an important way to avoid secondary generation of hydrates in the annulus, and the effect of salt solutions on the hydrate generation lays a basis for drilling fluid design. In this study, an evaluation device for the effect of drilling fluid additives on hydrate formation and phase equilibrium is designed based on their interaction characteristics. In addition, hydrate generation experiments were carried out for pure water and three commonly used salty additives for drilling fluids. As such, the hydrate phase equilibrium equations under different conditions are established, and the hydrate phase change latent heat is further calculated. The results show that hydrate formation can be divided into four stages, i.e., gas dissolution, hydrate crystal nucleation, hydrate particle mass aggregation, and stabilization. Compared with pure water, sodium chloride and potassium formate solutions can effectively inhibit hydrate formation. At lower ambient temperature, the higher the concentration of potassium formate, the lower the phase equilibrium pressure. On the contrary, at higher ambient temperature, the higher the concentration of potassium formate, the higher the phase equilibrium pressure. The incomplete presence of sodium silicate in water in the form of ions is found to promote methane hydrate formation. Based on the experimental results of methane hydrate generation in potassium formate and sodium silicate solutions with different mass concentrations, the phase equilibrium calculation models for methane hydrate in both salt solutions were finally established. The latent heat of the phase change distribution of hydrate under different conditions was further calculated. The results of this paper can provide a theoretical basis for the study of deepwater drilling fluid systems and multicomponent annular flow.

CO2 sequestration is a kind of technology that can effectively mitigate the greenhouse effect, and the wellbore integrity of the storage system is the key issue to ensure successful CCUS. Failure to timely diagnose tubing leakage in offshore gas wells with high CO2 will lead to annular pressure risk and wellbore corrosion problems. The annular pressure caused by tubing leakage is characterized by high pressure and rapid rise rate, resulting in wellhead jacking, gas leakage, and wellbore structure corrosion, which has become the main cause of wellbore integrity failure in offshore gas wells. Therefore, a model of heat and mass transfer and distribution in offshore gas wells was established firstly, and the physical process of gas leakage and accumulation was described based on the pinhole model and the principle of gas PVT characteristics and volume compatibility. The results show that the depth and equivalent size of the leakage point are two important factors affecting the pressure rise process and leakage rate. Taking case well parameters as an example, after inversion calculation, the annulus pressure in case well was 23.0 MPa, the leakage point equivalent diameter was 2.3 mm, the maximum leakage rate was 0.30 m3/min, and the wellbore safety risk is relatively high. Mechanical repair and chemical plugging agent are recommended to seal the tubing leakage. These risk assessment technologies provide reference for wellbore integrity design and management to reduce CO2 leakage risk caused by wellbore integrity failure.

Sour gas reservoirs (including CO2 and H2S) are vulnerable to gas invasion when drilling into reservoir sections. The high solubility of the invaded gas in drilling fluid makes the gas invasion monitoring “hidden” and “sudden” for later expansion, and the blowout risk increases. Accurate prediction of gas dissolution is highly significant for monitoring gas invasion. In this study, the gas–liquid flow control equations considering gas dissolution were established. Focusing on the gas dissolution effect, a solubility experiment for CO2 and CH4 in an aqueous solution was performed using a phase equilibrium device. The experimental and simulation results revealed that the addition of CO2 can significantly increase gas dissolution, and the presence of salts decreases it. For solubility prediction of pure CH4 and CO2, the fugacity–activity solubility model, calculated using the Peng–Robinson equation of state, was more accurate than the Soave–Redlich–Kwong equation of state. The Soave–Redlich–Kwong equation of state has higher accuracy for the CO2 and CH4 gas mixture. If the gas dissolution effect is considered for wellbore gas–liquid flow, the time required for the mud pit gain to reach the early warning value increases. When the contents of CO2 and H2S in intrusive gases are higher, the time for mud pit gain change monitored on the ground increases, the concealment increases, and the risk of blowout increases.