Natural gas hydrates in sediments can never reach thermodynamic equilibrium. Every section of any hydrate-filled reservoir is unique and resides in a stationary balance that depends on many factors. Fluxes of hydrocarbons from below support formation of new hydrate, and inflow of water through fracture systems leads to hydrate dissociation. Mineral/fluid/hydrate interaction and geochemistry are some of the many other factors that determine local hydrate saturation in the pores. Even when using real sediments from coring it is impossible to reproduce in the laboratory a natural gas hydrate reservoir which has developed over geological time-scales. In this work we discuss the various stages of hydrate formation, with a focus on dynamic rate limiting processes which can lead to trapped pockets of gas and trapped liquid water inside hydrate. Heterogeneous hydrate nucleation on the interface between liquid water and the phase containing the hydrate former rapidly leads to mass transport limiting films of hydrate. These hydrate films can delay the onset of massive, and visible, hydrate growth by several hours. Heat transport in systems of liquid water and hydrate is orders of magnitude faster than mass transport. We demonstrate that a simple mass transport model is able to predict induction times for selective available experimental data for CO₂ hydrate formation and CH₄ hydrate formation. Another route to hydrate nucleation is towards mineral surfaces. CH₄ cannot adsorb directly but can get trapped in water structures as a secondary adsorption. H₂S has a significant dipole moment and can adsorb directly on mineral surfaces. The quadropole-moment in CO₂ also plays a significant role in adsorption on minerals. Hydrate that nucleates toward minerals cannot stick to the mineral surfaces so the role of these nucleation sites is to produce hydrate cores for further growth elsewhere in the system. Various ways to overcome these obstacles and create realistic hydrate saturation in laboratory sediment are also discussed.

The amount of energy in the form of natural gas hydrates is huge and likely substantially more than twice the amount of worldwide conventional fossil fuel. Various ways to produce these hydrates have been proposed over the latest five decades. Most of these hydrate production methods have been based on evaluation of hydrate stability limits rather than thermodynamic consideration and calculations. Typical examples are pressure reduction and thermal stimulation. In this work we discuss some of these proposed methods and use residual thermodynamics for all phases, including the hydrate phase, to evaluate free energy changes related to the changes in independent thermodynamic variables. Pressures, temperatures and composition of all relevant phases which participate in hydrate phase transitions are independent thermodynamic variables. Chemical potential and free energies are thermodynamic responses that determine whether the desired phase transitions are feasible or not. The associated heat needed is related to the first law of thermodynamics and enthalpies. It is argued that the pressure reduction method may not be feasible since the possible thermal gradients from the surroundings are basically low temperature heat that is unable to break water hydrogen bonds in the hydrate–water interface efficiently. Injecting carbon dioxide, on the other hand, leads to formation of new hydrate which generates excess heat compared to the enthalpy needed to dissociate the in situ CH₄ hydrate. But the rapid formation of new CO₂ hydrate that can block the pores, and also the low permeability of pure CO₂ in aquifers, are motivations for adding N₂. Optimum mole fractions of N₂ based on thermodynamic considerations are discussed. On average, less than 30 mole% N₂ can be efficient and feasible. Thermal stimulation using steam or hot water is not economically feasible. Adding massive amounts of methanol or other thermodynamic inhibitors is also technically efficient but far from economically feasible.

The formation of natural gas hydrates during processing and transport of natural has historically been one of the motivations for research on hydrates. In recent years, there has been much focus on the use of hydrate as a phase for compact transport of natural gas, as well as many other applications such as desalination of seawater and the use of hydrate phase in heat pumps. The huge amounts of energy in the form of hydrates distributed in various ways in sediments is a hot topic many places around the world. Common to all these situations of hydrates in nature or industry is that temperature and pressure are both defined. Mathematically, this does not balance the number of independent variables minus conservation of mass and minus equilibrium conditions. There is a need for thermodynamic models for hydrates that can be used for non-equilibrium systems and hydrate formation from different phase, as well as different routes for hydrate dissociation. In this work we first discuss a residual thermodynamic model scheme with the more commonly used reference method for pressure temperature stability limits. However, the residual thermodynamic method stretches far beyond that to other routes for hydrate formation, such as hydrate formation from dissolved hydrate formers. More important, the residual thermodynamic method can be utilized for many thermodynamic properties involved in real hydrate systems. Consistent free energies and enthalpies are only two of these properties. In non-equilibrium systems, a consistent thermodynamic reference system (ideal gas) makes it easier to evaluate most likely distribution of phases and compositions.

In recent years, the exploitation and utilization of offshore oil and gas resources have attracted more attention. In offshore gas reservoir production, wellbore temperature and pressure change continuously when water-bearing natural gas flows upward. The wellbore temperature is also affected by the low-temperature sea water. The combination of temperatures and pressures controlled by the upward flow, and cooling from the surrounding seawater frequently leads to the conditions of temperature and pressure for hydrate formation. This can lead to pipeline blockage and other safety accidents. In this study, we utilize mathematical models of hydrate phase equilibrium, wellbore temperature, wellbore pressure to study hydrate formation and decomposition in offshore gas reservoir production. Numerical solution algorithms are developed and numerical solutions are validated. The sensitivity influence of different parameters on the regions and regularities of hydrate formation and decomposition in wellbores are obtained through numerical simulations. It is found that increased daily gas production, water content, or geothermal gradient in offshore gas reservoir production pipelines results in less hydrate formation in the wellbores. Accordingly, the risk of wellbore blockage decreases and production safety is maintained. Decreased tubing head pressure or seawater depth results in similar effects. The result of this study establishes a set of prediction methods for hydrate formation and decomposition that can be used in the development of guidelines for safe construction design.

During the trial production of marine gas hydrate in the former Soviet Union, Canada, North Slope of Alaska, South Sea Trough of Japan and Shenhu Sea of South China Sea, the problem of sand and water production cannot be avoided. The problems of sand production and water production in the process of natural gas hydrate depressurization exploitation have seriously restricted the exploitation efficiency and production of natural gas hydrate. The problems of sand production and water production are some of the main factors that prevent natural gas hydrate being commercially exploited. Therefore, it is urgent to carry out useful, relevant and cutting-edge research on the efficient drainage of sand and water from the wellbore in the process of natural gas hydrate mining. This paper innovatively proposes liquid-carrying and solid-carrying technology under foam circulation purging to address the existing problems of sand removal and drainage technology in hydrate mining. At present, no scholar has used this technology to solve the problem of sand removal and drainage in hydrate mining. Therefore, the research on efficient drainage is imperative. In this paper, We mainly studied the liquid-carrying and solid-carrying of vertical wellbore under the condition of foam cycle purging. We have revealed the relevant the liquid-carrying law and solid-carrying law through the above research.

Horizontal well drilling is a highly effective way to develop marine gas hydrate. During the drilling of horizontal wells in the marine gas hydrate layer, hydrate particles and cutting particles will migrate with the drilling fluid in the horizontal annulus. The gravity of cuttings is easy to deposit in the horizontal section, leading to the accumulation of cuttings. Then, a cuttings bed will be formed, which is not beneficial to bring up cuttings and results in the decrease of wellbore purification ability. Then the extended capability of the horizontal well will be restricted and the friction torque of the drilling tool will increase, which may cause blockage of the wellbore in severe cases. Therefore, this paper establishes geometric models of different hole enlargement ways: right-angle expansion, 45-degree angle expansion, and arc expanding. The critical velocity of carrying rock plates are obtained by EDEM and FLUENT coupling simulation in different hydrate abundance, different hydrate-cuttings particle sizes and different drilling fluid density. Then, the effects of hole enlargement way, particle size, hydrate abundance and drilling fluid density on rock carrying capacity are analyzed by utilizing an orthogonal test method. Simulation results show that: the critical flow velocity required for carrying cuttings increases with the increase of the particle size of the hydrate-cuttings particle when the hydrate abundance is constant. The critical flow velocity decreases with the increase of drilling fluid density, the critical flow velocity carrying cuttings decreases with the increase of hydrate abundance when the density of the drilling fluid is constant. Orthogonal test method was used to evaluate the influence of various factors on rock carrying capacity: hydrate-cuttings particle size > hole enlargement way > hydrate abundance > drilling fluid density. This study provides an early technical support for the construction parameter optimization and well safety control of horizontal well exploitation models in a marine natural gas hydrate reservoir.