There are substantial economic and operational incentives to reduce the volumes of thermodynamic inhibitors (THIs) injected in deepwater oil and gas pipelines to a minimum threshold necessary to achieve a flowable hydrate slurry and prevent hydrate deposition; however, there is uncertainty about whether this underinhibited condition may worsen hydrate transportability and increase plugging potential. In this study, hydrate formation rate and hydrodynamic pressure drop were measured over a range of temperatures and subcoolings using a one-inch single-pass flowloop containing aqueous monoethylene glycol (MEG) solutions (0−40 wt %) at a liquid loading of 5 vol % and a synthetic natural gas at an initial pipeline pressure of 10.3 MPa (1500 psia). Measured average formation rates in this gas dominant flow were within a factor of 2 of the kinetic rate and about 250 times faster than that expected for oil dominant flows. When the system was underinhibited with MEG, the pressure drop behavior over time was consistent with a proposed conceptual description for hydrate plugging in gas-condensate pipelines based on the mechanisms of stenosis (narrowing of the pipeline due to the deposition of a hydrate coat at the pipe wall) and sloughing (shear breaking of the hydrate deposits). The results from experiments performed at constant temperature showed that increasing the MEG dosage reduced hydrate formation rates and improved hydrate transportability. However, at decreasing temperatures, increasing the concentration of MEG to maintain a constant subcooling (and formation rate) appeared to promote hydrate sloughing. In certain experiments, it was possible to estimate the average deposition rate over the entire flowloop in addition to the average formation rate. Although formation rates were correlated with subcooling (rather than MEG concentration), the deposition rates were constant over the subcooling range (3.1 to 5.5°C) achieved with MEG concentrations of 0 to 20%.

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Natural gas hydrates have attracted interest as a potential future energy resource to meet the expected growth in the global energy demand. One of the key challenges to be tackled for commercial production is gas hydrate re-formation in production lines. Such hydrate blockages have been a major concern of flow assurance in the oil and gas industries, and typically occur during start-up, shut-in, and restart operations. This study sheds light on the behavior of methane hydrate slurries in pure water systems under shut-in conditions and their transition to solid blockages during system restart: a key risk factor in gas hydrate production. Flowloop experiments were conducted to measure the critical stress required to restart flow in hydrate slurries, which were accompanied by visual observations using an in-line video camera. A transition from smooth restart to a critical stress requirement was observed at 4−5 vol % of hydrate; visually, this corresponded to complete occupancy of the flow cross section with porous aggregated hydrate particles in a loosely packed network. The critical stress increased with higher hydrate volume fractions per the behavior of yield stress for a general suspension: it was not affected by the shut-in period, suggesting that annealing was not a factor at the volume fractions measured. Further, hydrate blockage occurred in several restart operations at approximately 18 vol % of hydrate even though the video camera had captured partial yielding before the blockage occurred. These results show a progression in slurry behavior as a function of hydrate volume fraction, offering insights into varied mechanisms for blockage formation, and operational strategies to minimize blockage risk.