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%.
Electrolytes can thermodynamically inhibit clathrate hydrate formation by lowering the activity of water in the surrounding liquid phase, causing the hydrates to form at lower temperatures and higher pressures compared to their formation in pure water. However, it has been reported that some thermodynamic hydrate inhibitors (THIs), when doped at low concentrations, could enhance the rate of gas hydrate formation. We here report a systematic study of model natural gas (a mixture of 90% methane and 10% propane) hydrate formation in strong monovalent salt solutions in a broad range of concentrations, using a high pressure automated lag time apparatus (HP-ALTA). HP-ALTA can apply a large number (>100) of cooling ramps to a sample and construct probability distributions of gas hydrate formation for each sample. The probabilistic interpretation of data enables us to mitigate the stochastic variation inherent in the nucleation probability distributions and facilitates meaningful comparison among different samples. The electrolytes used in this work are lithium chloride (LiCl), lithium bromide (LiBr), lithium iodide (LiI), sodium chloride (NaCl), sodium bromide (NaBr), sodium iodide (NaI), potassium chloride (KCl), potassium bromide (KBr), and potassium iodide (KI). We found that (1) some salts may act as kinetic hydrate promoters at low concentrations; (2) the width of the probability distributions (stochasticity) of natural gas hydrate formation in these salt solutions was significantly narrower than that in pure water. To gain further insight, we extended the study of the solutions of the same nine salts to the formation of ice and model tetrahydrofuran (THF) hydrate for comparison.
A 130 ft single-pass, gas-dominant flowloop has been constructed to study hydrate formation in an annular flow regime by exposing warm process fluids to a cold pipe wall. Hydrate was formed in six experiments from a natural gas mixture, with 6−18 °F subcooling from hydrate equilibrium. At lower subcooling values a stenosis-type hydrate film growth model without adjustable parameters was used to estimate the resulting pressure drop and yielded an average deviation of 15.8 psi from the experimental value. The accuracy of this model decreases appreciably with increasing subcooling, suggesting the occurrence of a transition after which the pressure drop becomes dominated by additional hydrate phenomena such as particle deposition or wall sloughing. For experiments with 18 °F subcooling, the pressure drop signal contained periodic peak-and-trough behavior and the primary hydrate restriction was observed to migrate downstream at a rate of 3 ft/min over the course of the experiment. Average hydrate growth rates varied linearly with subcooling over a range of 0.2−1.2 L/min and were an order of magnitude larger than formation rates predicted using models developed for water-dominant systems. These results demonstrate the need for a new gas-dominant hydrate formation model, which incorporates stenosis-type growth, particle deposition from the liquid phase, and deposit sloughing from the wall.
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