Predicting Hydrate Plugging Risk in Oil Dominated Systems using a Transient Hydrate Film Growth Prediction Tool

Abstract

Abstract The formation of gas hydrates is considered a major flow assurance issue resulting from high pressure and low temperature conditions during petroleum production in deep water developments (Sloan and Koh 2007). Gas hydrates are solid crystalline compounds, which can be formed when the pressure and temperature reaches the thermodynamically stable hydrate zone. Hydrates can plug deepwater flowlines, which may lead to the rupture of flowlines and spill or leakage of oil and gas (Sloan 2010). As a result, production and economic losses may exist during operation. illustrates the oil-dominated pipeline plugging mechanism caused by hydrates in an oil dominated pipeline. The process is fairly complex, with phenomena such as: (1) water entrainment or dispersion of water droplets in the continuous oil phase due to fluid shear and surface-active components in the oil; (2) hydrate formation, with hydrate growth at the water-oil/water-gas interface under a certain degree of thermal driving force; (3) hydrate agglomeration and deposition; (4) particle jamming and hydrate plugging. Among these mechanisms, film growth, deposition (bedding) can be categorized into hydrate deposition. Traditionally, thermodynamic approaches are used to prevent the formation of hydrates in flowlines, including the injection of thermodynamic hydrate inhibitors (THIs), such as methanol or glycols. THIs work by shifting the hydrate phase equilibrium conditions to a lower temperature and higher pressure, which makes the condition unfavorable for hydrates to form (Sloan and Koh, 2007). However, for THIs, large amounts of chemicals are needed, which will introduce high OPEX and CAPEX (Creek, et al. 2011). Hydrate risk management methods have gained popularity, as they will largely reduce the cost. The latter more recent concept suggests that by injecting low dosage hydrate inhibitors (LDHIs), including kinetic hydrate inhibitors (KHIs) and anti-agglomerants (AAs), the risk of flowline blockage can be controlled, even though the flowline may enter the hydrate stability zone. To support this concept, a comprehensive simulation tool is critical to predict the different hydrate plugging mechanisms mentioned above.