The current hydrate kinetics model implemented in the multiphase flow simulator OLGA treats hydrate growth in oil-continuous systems by considering the solidification of emulsified water droplets to form a hydrate-in-oil slurry that is assumed to be stable. To date, the validity of this model has not been established for gas-dominant systems, where gas void fractions can exceed 90 vol %. Here, six experimental data sets, collected using a 40-m single-pass gas-dominant flowloop operating in the annular-flow regime, were compared with predictions made using the current hydrate kinetics model. The comparison identified discrepancies in the predicted flow regime and the gas–water interfacial area that significantly affect kinetic hydrate-growth-rate calculations; these discrepancies might be due, in part, to differences in dynamic similarity between flowloop experiments and industrial-scale simulations. By adjusting only the kinetic rate scaling factor, it was not possible to match the pressure drop observed experimentally, illustrating that the formation of a viscous hydrate slurry alone cannot account for the resistance to flow observed in gas-dominant systems. We demonstrate that it is possible to emulate deposition in the current model by adjusting the slip ratio between the hydrate particles and the condensed phases; this approach allowed stenosis-type restrictions to occur in the simulation, as well as pressure-drop behavior similar to that observed experimentally. Utilizing a simple in-house model with empirical correlations to predict the hydrodynamics, it is possible to match relatively closely the measured growth rate and pressure drop simultaneously. Such agreement could not be reached using the current hydrate implementation available in OLGA, highlighting the need for a gas-specific hydrate growth model that is capable of capturing both hydrate growth from suspended droplets in the gas phase and solid growth at the flowline wall, as well as the extent of hydrate deposition on the wall.

Methane bubble dispersions in a water column can be observed in both vertical subsea piping as well as subsea gas seepages. Hydrate growth has been shown to occur at the gas−water interface under flowing conditions, yet the majority of the current literature is limited to quiescent systems. Gas hydrate risks in subsea piping have been shown to increase in late life production wells with increased water content and with gas-in-water bubble dispersions. The dissolution of subsea methane seepages into seawater, or methane release into the atmosphere, can be affected by hydrate film growth on rising bubbles. A high-pressure water tunnel (HPWT), was used to generate a turbulent, continuous water flow system representative of a vertical jumper line to study the relationship between bulk methane hydrate growth and bubble size during a production-well restart. The HPWT comprises a flow loop of 19.1 mm inner diameter and 4.9 m length, with a vertical section containing an optical window to enable visualization of the bubble and hydrate flow dynamics via a high-speed, high-resolution video camera. Additional online monitoring includes the differential pressure drop, viscosity, temperature, flow rates, and gas consumption. Experimental conditions were maintained at 275 K and 6.2 MPa during hydrate formation and 298 K and 1.4 MPa during hydrate dissociation. Hydrate growth using freshwater and saltwater (3.5 wt % NaCl) was measured at four flow velocities (0.8, 1.2, 1.6, and 1.9 m s −1 ). The addition of salt is shown in this work to alter the surface properties of bubbles, which introduces changes to bubble dynamics of dispersion and coalescence. Hydrate volume fractions and growth rates in the presence of salt were on average ∼32% lower compared to that in freshwater. This was observed and validated to be due to bubble size and dynamic factors and not due to the 1.5 K thermodynamic inhibition effect of salt. Throughout hydrate growth, methane bubbles in pure freshwater maintained larger diameters (2.4−4.2 mm), whereas the presence of salt promoted fine gas bubble dispersions (0.1−0.7 mm), increasing gas−water interfacial area. While gas bubble coalescence was observed in all freshwater experiments, the addition of salt limited coalescence between gas bubbles and reduced bubble size. Consequently, earlier formation of solid hydrate shells in saltwater produced early masstransfer barriers reducing hydrate growth rates. While primarily directed toward flow assurance, the observed relationship between hydrates, bubble size, and saltwater also applies to broader research fields in subsea gas seepages and naturally occurring hydrates.

Subsea oil and gas flowlines can provide favorable conditions for gas hydrate formation, which can lead to flow assurance issues as hydrate particles agglomerate and accumulate in the flowline. Shut-in and restart operations are particularly critical for hydrate plug formation. Traditional strategies to mitigate hydrate plugging use total hydrate avoidance with thermodynamic inhibitors; however, thermodynamic inhibition can become cost-prohibitive as oil production moves towards harsher environments associated with deeper drilling. Hydrate management strategies using low dosage hydrate inhibitors (LDHI), such as anti-agglomerants (AA), are an attractive alternative to reduce operational and capital expenditures in offshore oil and gas production. In order to successfully deploy anti-agglomerants to mitigate hydrate plugging, a comprehensive understanding of the variables affecting the performance of these additives, such as oil composition and mixture velocity, is needed. Industrial-scale flowloop studies are valuable to investigate the influence of these variables on hydrate particle transportability when using AAs. These experimental setups could be also useful to assess AA performance during transient operations (i.e. shut-in and restart); however, large-scale flowloop data at these conditions is limited. High pressure industrial-scale flowloop tests were conducted using a non-dispersing oil at 50 vol. % water content and 70 vol. % liquid loading. The aqueous phase is a 3.5 wt. % NaCl solution and the gas phase comprises a natural gas favoring the formation of sII gas hydrates. The AA used in these tests is a quaternary ammonium salt. Both baseline (without AA injection) and AA dosed (2 vol. % AA) tests were conducted in order to compare the influence of mixture velocity on hydrate transportability using AAs with respect to systems without AA injection. Three different mixture velocities (2.3, 3.7 and 5.8 ft s) were employed. The experimental procedure included shut-in and restart operations. A combination of different data, such as temperature and pressure drop profiles, mass flow rate and droplet/particle size evolution was used to analyze the effects of AA injection at the different studied velocities. Additionally, water/oil dispersion tests were carried out in order to investigate the influence of the AA on the properties of the dispersion. Both hydrate growth rate and droplet/particle size were influenced by mixture velocity in baseline tests; however, experiments with 2 vol. % AA showed similar hydrate growth rates and droplet/particle sizes regardless of the mixture velocity. In addition, despite AAs reducing hydrate bedding at all mixture velocities with respect to baseline experiments, a certain velocity was needed to completely suppress any indication of hydrate bedding in these systems. Moreover, AA injection successfully inhibited hydrate particle size increase (agglomeration) under static conditions (shut-in), allowing solid material flow after restarting the system. Finally, dispersion tests showed that this particular AA formulation modifies the surface chemistry properties of the system and favors water-continuous dispersions at room conditions with respect to systems without addition of AA.

We present the development of a new model to predict hydrate growth and transport in gas-dominant systems, based on experimental observations of hydrate film growth and particle deposition. Incorporated as a user-defined plugin in a transient flow simulator, we present predictions of hydrate blockage formation using this tool for three of eight Tommeliten field trials: (i) depressurized restart; (ii) thermodynamic inhibitor injection failure and; (iii) pressurized restart. Deposition plays a key role in these predictions, and the new model predicts significant hydrate stenosis occurring in the same timescale as blockage formation in the field trials. The mechanism of sloughing, a key precursor to the formation of hydrate plugs, is not incorporated in a transient simulation environment. However, shear stress predictions as a deposit develops may exceed the threshold previously reported in literature to generate a sloughing event. This represents a key way forward in the development of a comprehensive hydrate prediction tool for oil and gas flowlines.