Multiphase Flow Modeling of Gas-Water-Hydrate Systems

Abstract

Abstract The risk of plugging due to hydrate formation remains one of the most prevailing flow-assurance problems in deep subsea oil and gas operations. Due to potentially severe economic impact of forming a hydrate plug, it is critical to develop hydrate formation models, which predict temporal and spatial hydrate plug formation in flowlines. Hydrate formation and accumulation mechanisms depend on the flow regimes of the system; in turn, hydrate formation can affect the flow regime of fluid flow. Currently, there are no multiphase tools that account for this coupling and interdependence factor of hydrate formation and flow regime. A simple hydrodynamic slug flow model (Danielson, 2011), based on fundamental multiphase flow concepts, coupled with a transient hydrate formation model, is used to study the effect of hydrates in a gas/water system fluid flow. The model includes a hydrate kinetic model, mass and energy balances, and pressure drop components. The validity of the model is tested against data measured in an industrial flowloop (Joshi, 2012). Using this model to simulate hydrate formation in subsea pipelines shows higher hydrate accumulation with increasing water-hydrate slip (L. Zerpa, Rao, Sloan, Koh, & Sum, 2012). Flowline geometry is also considered to predict the slugging and accumulation of hydrates. This hydrodynamic model predicts flow regime transitions among stratified, stratified-wavy, slug, and bubble flow with and without hydrates. Using a specific model for the slip relations between the phases, the model can predict the classical gas-liquid flow regime map and the impact of hydrates as a third, solid phase on such flow regime maps. This contribution shows that a relatively simple model can be useful in the predictions of multiphase flow and in particular how hydrates affect the flow behavior and must be explicitly accounted as a separate phase. Introduction Clathrate hydrates are crystalline solid compounds, formed at low temperatures and high pressures, comprising of water and gas molecules (Sloan & Koh, 2008). Hydrogen bonded water molecules form the " host" cage entrapping the " guest" gas molecules like methane, ethane, hydrogen sulfide, propane etc., which are also prominent components of natural gas. The formation of natural gas hydrates in deep subsea pipelines is one of the most challenging flow assurance problems (Sloan, 2005), involving significant design efforts to prevent the formation of undesirable hydrate plugs. Various hydrate prediction tools allow accurate predictions of the amount of thermodynamic inhibitor (e.g., methanol or monoethylene glycol) required to completely prevent hydrate formation. The oil and gas industry is gradually shifting from prevention towards hydrate management, approaches, where hydrates are allowed to form, but the plugging risk is minimized (Creek, 2012; Sloan, 2005). Models for hydrate formation kinetics coupled with multiphase flow aspects will be helpful during the design and assessment of hydrate management approaches and in estimating hydrate-plugging risk. A hydrate kinetics model was developed for oil-dominated systems based on the conceptual model presented in Figure 1, which represents an approximation to the mechanism of hydrate plug formation divided in four steps: gas bubble and water droplet entrainment in oil; hydrate film growth at the interface of the droplet/bubble; particle packing, agglomeration, bedding, and deposition; plugging. In the oil phase, these hydrate-encrusted water droplets agglomerate into larger hydrate masses (Taylor, 2006), leading to an increase in the slurry viscosity, which can eventually form a plug (Turner, 2005).