Fluid-solid coupling model for studying wellbore instability in drilling of gas hydrate bearing sediments

• Published in: Applied mathematics and mechanics Vol. 34; no. 11; pp. 1421 - 1432
• Main Author: 程远方 李令东 S. MAHMOOD 崔青
• Format: Journal Article
• Language: English
• Published: Berlin/Heidelberg Springer Berlin Heidelberg 01.11.2013; College of Petroleum Engineering, China University of Petroleum, Qingdao 266580, Shandong Province, P. R. China
• Subjects: Applications of Mathematics; Classical Mechanics; Drilling; Fluid- and Aerodynamics; Mathematical Modeling and Industrial Mathematics; Mathematics; Mathematics and Statistics; Partial Differential Equations; 井壁失稳; 井壁稳定性; 井眼不稳定; 分解行为; 天然气水合物; 沉积物; 流固耦合模型; 钻井流体; gas hydrate bearing sediment; TU411; wellbore stability; mechanical property; 74R99; fluid-solid coupling; drilling fluid
• ISSN: 0253-4827; 1573-2754
• DOI: 10.1007/s10483-013-1756-7

As the oil or gas exploration and development activities in deep and ultra- deep waters become more and more, encountering gas hydrate bearing sediments （HBS） is almost inevitable. The variation in temperature and pressure can destabilize gas hydrate in nearby formation around the borehole, which may reduce the strength of the formation and result in wellbore instability. A non-isothermal, transient, two-phase, and fluid-solid coupling mathematical model is proposed to simulate the complex stability performance of a wellbore drilled in HBS. In the model, the phase transition of hydrate dissociation, the heat exchange between drilling fluid and formation, the change of mechanical and petrophysical properties, the gas-water two-phase seepage, and its interaction with rock deformation are considered. A finite element simulator is developed, and the impact of drilling mud on wellbore instability in HBS is simulated. Results indicate that the re- duction in pressure and the increase in temperature of the drilling fluid can accelerate hydrate decomposition and lead to mechanical properties getting worse tremendously. The cohesion decreases by 25% when the hydrate totally dissociates in HBS. This easily causes the wellbore instability accordingly. In the first two hours after the formation is drilled, the regions of hydrate dissociation and wellbore instability extend quickly. Then, with the soaking time of drilling fluid increasing, the regions enlarge little. Choosing the low temperature drilling fluid and increasing the drilling mud pressure appropriately can benefit the wellbore stability of HBS. The established model turns out to be an efficient tool in numerical studies of the hydrate dissociation behavior and wellbore stability of HBS.