The formation and accumulation of natural gas hydrates in deep subsea pipelines is one of the most challenging flow assurance problems. Typical high pressure/low temperature operation conditions in deep subsea facilities promote rapid formation of gas hydrates. Recent observations in flowloop experiments in gas/water systems suggested a relationship between hydrate volume and flow regime on pressure drop. In the current work, a simple hydrodynamic slug flow model, based on fundamental multiphase flow concepts, is coupled with a transient hydrate kinetics model and a pressure drop model to study the effect of hydrate formation on slug flow in gas/water systems.
Gas hydrates are crystalline inclusion compounds, where water cages trap or enclathrate lighter hydrocarbon species (e.g., methane) typically under high-pressure and lowtemperature conditions (1, 2). Naturally occurring gas hydrates may be found in ocean sediment – typically near thermogenic or biogenic methane sources – and represent a significant potential energy source (3–5). Gas hydrates may also form in conventional energy transport lines (e.g., oil/gas pipelines), representing both a production and safety hazard (1). The present work focuses on enhancing our ability to probe how multiphase flow characteristics for simple systems (gas and water) may change when a hydrate phase is introduced. Our current conceptual picture for hydrate particle formation in water-dominated systems is divided in four steps (Figure 1): gas bubble entrainment in water; hydrate film growth around the interface; particle packing, bedding, or agglomeration; and deposition or plugging (6, 7). The present work is our first attempt to gain greater understanding on how these processes involving hydrates (a third, solid phase) affect the multiphase flow properties of the system (gas and liquid). Current modeling approaches treat the condensed phase (including water and oil) as a homogeneous mixture, with hydrate formation simply augmenting the bulk phase properties (8–11).