One of the major issues in flow assurance includes pipeline plugging due to hydrate formation and deposition. A key uncertainty in gas pipelines is hydrate deposition on the pipe wall. This work demonstrates hydrate formation and deposition on a cold surface in water-saturated gas systems. Methane hydrate deposition can be achieved in a laboratory-scale apparatus by formation of hydrates from the gas phase on the outer surface of a cold surface. The deposit evolves from the initial formation to growth to hardening stages, observed to be initially a porous deposit that later anneals to a relatively nonporous deposit. The hydrate deposit thickness gradually reaches a limit as the hydrate surface approaches the hydrate equilibrium temperature. Performing the measurements at higher initial subcooling in the system results in a thicker hydrate deposit. The average calculated hydrate deposit porosity decreases during the experiment and reaches ∼5% during the annealing stage.
The formation of natural gas hydrates in deep subsea pipelines is one of themost challenging flow assurance problems. The development of a comprehensivehydrate model (CSMHyK), which predicts temporal and spatial hydrate formationand plugging in flowlines of oil-, water- and gas-dominated systems, will havesignificant utility in flow assurance. This empowers the engineer to design andassess oil/gas transport facilities, with a focus on prevention, management orremediation of gas hydrate formation and blockages. In the current work, wepresent improvements to the hydrate aggregation module used for oil-dominatedsystems, based on experimental data, which account for temperature, particle-particle contact time, excess water, and the presence of surfaceactive compounds. Second, we have extended CSMHyK to water- and gas-dominatedsystems, and have developed fundamental models based on flowloop and laboratorydata. In water-dominated systems, we present a new mass transfer-based growthmodel and hydrate plugging criterion, based on fluid velocity. In gas-dominatedsystems, we present a combined heat and mass transfer model for hydrate filmgrowth on pipe walls. These models are applied to a typical well/flowline/risergeometry used in offshore facilities. This model improves our capability topredict hydrate formation and blockages, by considering dynamic aggregationphenomena in oil-dominated systems, flow regime transition in high water cutsystems, and hydrate film growth in gas saturated systems. Introduction Natural gas hydrates form when small guest molecules contact liquid water athigh pressure and low temperature (Sloan and Koh, 2008), which are typicaloperation conditions of subsea pipelines. The formation of natural gas hydratesin deep subsea pipelines is one of the most challenging flow assurance problems(Sloan, 2005), involving significant design efforts to prevent the formation ofundesirable hydrate plugs. It had been recognized that predicting hydrate formation conditions usingthermodynamic calculations (with excellent accuracy) is not sufficient toestimate hydrate plugging risk (Sloan, 2005). Instead, this can be used todesign hydrate avoidance methods (e.g., chemical injection, thermal insulation, active heating, and pressure reduction), keeping the systems out of the hydratestability region (Creek et al., 2011). The offshore oil/gas industry hasprogressed toward using longer tiebacks (Ronalds, 2005) to connect subsea wellswith platforms, rendering hydrate avoidance methods economically unfeasible. The alternative would be to consider hydrate management approaches, wherehydrates are allowed to form, but the plugging risk is low (Creek et al., 2011;Sloan, 2005). Models for hydrate formation kinetics coupled withtransportability models may be helpful during the design and assessment ofhydrate management approaches, providing estimates of the amount of hydratesthat could form and its transportability in specific scenarios, to estimatehydrate plugging risk.
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).
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