Securing energy means grasping the key link in the national development and security strategy. Under the goals of carbon peak and carbon neutrality, the overall tendency of energy development is to increase the proportion of natural gas while stabilizing oil consumption, and the global primary energy is entering the era of natural gas. Gas hydrate in deep seabed shallow strata and extremely cold permafrost regions has piqued the interest of researchers due to its abundant resources, widespread distribution, and high energy density. Although the drilling of hydrate wells is still fraught with unknowns and challenges due to the technological barriers between countries, complex on-site working conditions, and unique physical chemical properties, accumulation forms, and occurrence characteristics of gas hydrate, more than ten successful trial productions around the world have opened the door of hope for the development of this potentially new energy. The gas hydrate reservoir drilling technique is the frontier and hotspot of scientific and technological innovation and competitiveness around the globe today, reflecting the level of oil and gas technical advancement. At the national level, it possesses strategic and revolutionary features. Innovative drilling techniques, scientific well location layout, appropriate wellbore structure and well trajectory design, efficient drilling fluid, qualified drilling and completion equipment, and successful pressure-temperature preserved coring may all provide a strong guarantee for the successful completion of gas hydrate wells. This review comprehensively reviews the drilling techniques and engineering measures that can be used to develop gas hydrate. It focuses on the research advancement of important hydrate drilling technologies and the enlightening significance of these developments in the application of hydrate drilling. This work will deliver valuable experience as well as comprehensive scientific information for gas hydrate exploration and drilling.

We have proposed a consistent thermodynamic scheme for evaluation of enthalpy changes of hydrate phase transitions based on residual thermodynamics. This entails obtaining every hydrate property such as gas hydrate pressure-temperature equilibrium curves, change in free energy which is the thermodynamic driving force in kinetic theories, and of course, enthalpy changes of hydrate dissociation and formation. Enthalpy change of a hydrate phase transition is a vital property of gas hydrate. However, experimental data in literature lacks vital information required for proper understanding and interpretation, and indirect methods of obtaining this important hydrate property based on the Clapeyron and Clausius-Clapeyron equations also have some limitations. The Clausius-Clapeyron approach for example involves oversimplifications that make results obtained from it to be inconsistent and unreliable. We have used our proposed approach to evaluate consistent enthalpy changes of hydrate phase transitions as a function of temperature and pressure, and hydration number for CH₄ and CO₂. Several results in the literature of enthalpy changes of hydrate dissociation and formation from experiment, and Clapeyron and Clausius-Clapeyron approaches have been studied which show a considerable disagreement. We also present the implication of these enthalpy changes of hydrate phase transitions to environmentally friendly production of energy from naturally existing CH₄ hydrate and simultaneously storing CO₂ on a long-term basis as CO₂ hydrate. We estimated enthalpy changes of hydrate phase transition for CO₂ to be 10–11 kJ/mol of guest molecule greater than that of CH₄ within a temperature range of 273–280 K. Therefore, the exothermic heat liberated when a CO₂ hydrate is formed is greater or more than the endothermic heat needed for dissociation of the in-situ methane hydrate.

In the process of deep-water drilling, gas hydrate is easily formed in wellbores due to the low temperature and high pressure environment. In this study, a new, systematic, and accurate prediction method of temperature, pressure, and hydrate formation region in wellbores is developed. The mathematical models of wellbore pressure and transient heat transfer are established, the numerical solution method based on fully implicit finite difference method is developed, and the accuracy is verified by comparing with the field measured data. Combined with the hydrate phase equilibrium model, the hydrate formation region in wellbore is predicted, and the sensitivity effects of nine factors on wellbore temperature, pressure, and hydrate formation region are analyzed. Finally, the influence regularities and degree of each parameter are obtained. The increases of circulation time, geothermal gradient, displacement of drilling fluid, and injection temperature will inhibit the formation of hydrate in wellbores, and the influence degree increases in turn; the increases of wellhead backpressure and seawater depth will promote the formation of hydrate in wellbores, and the influence degree increases in turn. The changes of drilling fluid density, well depth, and hole deviation angle have little effect on the formation of hydrate in wellbores.

Hydrates that form during transport of hydrocarbons containing free water, or water dissolved in hydrocarbons, are generally not in thermodynamic equilibrium and depend on the concentration of all components in all phases. Temperature and pressure are normally the only variables used in hydrate analysis, even though hydrates will dissolve by contact with pure water and water which is under saturated with hydrate formers. Mineral surfaces (for example rust) play dual roles as hydrate inhibitors and hydrate nucleation sites. What appears to be mysterious, and often random, is actually the effects of hydrate non-equilibrium and competing hydrate formation and dissociation phase transitions. There is a need to move forward towards a more complete non-equilibrium way to approach hydrates in industrial settings. Similar challenges are related to natural gas hydrates in sediments. Hydrates dissociates worldwide due to seawater that leaks into hydrate filled sediments. Many of the global resources of methane hydrate reside in a stationary situation of hydrate dissociation from incoming water and formation of new hydrate from incoming hydrate formers from below. Understanding the dynamic situation of a real hydrate reservoir is critical for understanding the distribution characteristics of hydrates in the sediments. This knowledge is also critical for designing efficient hydrate production strategies. In order to facilitate the needed analysis we propose the use of residual thermodynamics for all phases, including all hydrate phases, so as to be able to analyze real stability limits and needed heat supply for hydrate production.

The drilling fluid invasion into hydrate-bearing sediments will change the geomechanical properties of the reservoir and may lead to uncontrolled geological disasters in the worst case. Native sediments are replaced with artificial samples in this study to investigate the effect of drilling fluid invasion on the strength behaviors of hydrate-bearing sediments. The triaxial test is used primarily to assess the strength behaviors of hydrate-bearing sediments at varying temperatures, pressures, and hydrate saturation levels. The process of water-based drilling fluid penetrating into hydrate-bearing sediments is then experimentally imitated under various experimental conditions, with reservoir temperature of 4°C and pore pressure of 10 MPa. The possible repercussions of drilling fluid invasion and hydrate phase transition are identified by testing the mechanical properties of sediments under various invasion times and temperatures. The findings reveal that when hydrate saturation rises from 5% to 35%, the gas hydrate sediments shift from strain hardening to strain softening, with the critical hydrate saturation value of transition is between 15% and 25%. Peak strength increases with increasing hydrate saturation and pressure, and decreases with increasing temperature, whether drilling fluid invasion is present or not. The peak strength, Young’s modulus, shear modulus, and secant modulus of hydrate sediments all decreased significantly after drilling fluid invasion, although the Poisson’s ratio rose. These mechanical parameters are related to temperature and pressure under the action of drilling fluid. Finally, engineering and research recommendations for reducing the risk of drilling fluid invasion and hydrate dissociation are made based on experimental findings and theoretical analysis. This study innovatively examine the geomechanical mechanical properties of drilling fluid invading hydrate reservoir, which is critical for avoiding production concerns.

Many oil/gas wells are abandoned or approaching their end-of-life. Converting them into geothermal wells can significantly improve the economics of oil/gas field operations and reduce carbon emissions. While such conversion has proven viable in some areas, this technology has not yet been considered in many other areas. It is highly desirable to investigate the feasibility of converting abandoned oil/gas wells into geothermal energy production wells in local geological conditions. A new mathematical model was developed in this study for analyzing the feasibility of converting oil/gas wells into geothermal wells. This model predicts the deliverable fluid temperature of a well by simulating the heat transfer from the geothermal zone through the wellbore to the surface wellhead, considering pipe and wellbore insulation. Factors affecting heat transfer efficiency were investigated with the model for a generic data set. Results indicate that without pipe insulation, the temperature of the returning fluid is very close to that of the injected fluid. The use of pipe insulation can significantly increase the temperature of the returning fluid. For a system with a thermal conductivity of insulation pipe Kp = 0.03 W/m-C, the deliverable fluid temperature can be increased from 30 °C to 124 °C. Adding an insulation cement sheath can efficiently further increase the temperature of the returning fluid. For a system with a cement thermal conductivity of 0.20 W/m-C, the deliverable fluid temperature can be further increased from 124 °C to 148 °C. Increasing the length of the horizontal wellbore in the geothermal zone from 2000 m to 8000 m can further increase the temperature of the returning fluid from 148 °C to 159 °C. Merely by increasing the vertical depth of the well from 7000 m to 7800 m, the deliverable fluid temperature can be enhanced from 148 °C to 161 °C. However, vertical depth is limited by the temperature-sensitivity of drilling technologies, such as the thermal stability of drilling fluids and downhole drilling instruments.