In recent years, marine hydrate has attracted more and more attentions. As a creative way to efficiently exploit marine hydrate, the method of solid fluidization exploitation is to excavate and crush hydrate, transport hydrate particles to sea surface platform through airtight pipeline, and obtain methane gas finally. When hydrate particles are transported up, as temperature rises and pressure drops, hydrate will decompose at a certain critical position and produce a large amount of gas, bringing complicated gas‐liquid‐solid multiphase non equilibrium pipe flow, and seriously threating well control securities. Thus, we establish mathematical models of wellbore temperature and pressure, hydrate phase equilibrium, hydrate dynamic decomposition in riser pipe flow and wellbore multiphase flow coupling hydrate dynamic decomposition, and propose and verify numerical calculation method. Then numerical model application analysis under different construction parameters is carried out, influence behaviors of multiphase non equilibrium pipe flow are obtained, and field construction measures are put forward. Properly increasing solid throughput can increase production of natural gas. However, problems such as well control risks will intensify. Therefore, delivery capacity, liquid density, and wellhead back pressure should be increased appropriately at the same time. This study provides important technical support for solid fluidization exploitation of marine hydrate.

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.

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.