• Energy Research

Abstract The hydrate reformation in marine gas hydrate production system can significantly affect the accuracy control of the production pressure differential and even cause pipeline blockage problems. In this paper, a transient temperature and pressure calculating model was established to predict the risk of hydrate reformation in production pipelines during offshore gas hydrate development, which considering the coupling interactions between the real-time drainage of electric submersible pump (ESP), the downhole preheating of electric induction heater (EIH), the wellbore multiphase flow and heat transfer. Using the model, the dynamic evolution laws of gas–liquid two-phase flow behaviors in different pipelines of mixed transportation, drainage and gas production were studied. Furthermore, the region of hydrate reformation in production pipelines was predicted quantitatively. The results indicate the risk of hydrate reformation in the drainage pipe is the highest relative to other pipes, and the main flow pattern in this pipe is bubbly flow. Besides, the conventional hydrate management method through inhibitor injection was applied to prevent the hydrate reformation. It can be found that the required Ethylene glycol (MEG) minimum concentration reaches 22% in order to completely eliminate the risk of hydrate reformation. To this end, a new hydrate management strategy by adding additional pumps and heaters was proposed, and the prevention effect of hydrate reformation in different scenarios was discussed in detail. The simulated results demonstrate that this method can effectively address the potential hydrate reformation risks without the use of inhibitors. This work will provide theoretical references for the hydrate flow assurance operations in marine gas hydrate production testing.

Abstract Hydrate plugging in pipes is a serious issue that affects flow safety in the trial production of offshore natural gas hydrates. Current research on hydrate flow assurance has primarily focused on conventional oil-and-gas production and transportation processes. Therefore, models for predicting the hydrate formation region and hydrate deposition in the trial production pipes of offshore natural gas hydrate were developed in the present study, which can be used to estimate the risk of hydrate plugging in the production pipes. The results revealed that hydrate formation conditions could be satisfied in the water production pipe at a low water production rate, and hydrate generation was possible in a certain region in the gas production pipe. The hydrate deposition layer formed in the gas production pipe grew in a non-uniform manner; the longer the production time, the more obvious was the non-uniform distribution; this resulted in a high risk of hydrate plugging after a certain process time. Additionally, as the rate of gas production increased, the hydrate formation region in the gas production pipe gradually moved upward and decreased in size, and the degree of hydrate deposition also slightly decreased. Finally, the installation of a heater at the bottom of the gas pipe at a high production rate was proposed to increase the gas temperature, thereby decreasing the possibility of hydrate formation and plugging. For the water production pipe, a low dose of kinetic inhibitors or anti-agglomerants could be injected to avoid the risk of hydrate plugging and reduce the corresponding prevention costs. This study can provide a theoretical basis and technical support for the efficient prevention of hydrate plugging during production trials or long-term production of offshore natural gas hydrates.