New Concept for Evaluating the Risk of Hydrate Formation during Processing and Transport of Hydrocarbons
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Transport of hydrocarbons from reservoir to gas processing plants and for supply to delivery terminals is predominantly done using pipelines, particularly within reasonable distance. In the North Sea of Norway, there are about 8000 km network of pipelines transporting hydrocarbons. Transport and processing operations of hydrocarbons in the North Sea are typically at elevated pressures. The seafloor temperatures are normally low; because of the seawater salinity it could be as low as 272.15 K in the northern part, and seldom rise above 279.15 K in the south. If liquid water condenses out of hydrocarbon gas streams at these conditions of high pressures and low temperatures, with favourable mass and heat transport, nucleation and growth of natural gas hydrate is expected to occur. The typical technique the industry currently apply to examine the risk of hydrate formation is based on estimation of water dew-point for the gas in question. And if any condition of temperature and pressure in the pipeline or processing equipment is above water dew-point so that water condenses out, then the amount of water that will drop out is evaluated. This is followed by hydrate formation evaluation, including maximum amount of hydrate that can be expected to form from the condensed water. Prevention of hydrate formation with this classical approach known as dew-point method therefore involves estimating the maximum amount of water that can be permitted in the hydrocarbon gas without the risk of liquid water dropping out and eventually leads to hydrate formation. The shortcoming of the classical scheme is that it totally disregards another (a new) concept which involves water dropping out of the bulk through the mechanism of adsorption on rusty surfaces. Pipelines and some equipment are generally rusty even before they are mounted together and put in place. Rust is a mixture of iron oxide and in this study refers to Hematite (Fe2O3) which is one of the most thermodynamically stable forms of rust. These rusty surfaces provide water adsorption sites that can also lead to hydrate formation. However, hydrate formation cannot occur directly on the surfaces covered by Hematite. This is because the distribution of partial charges of hydrogen and oxygen in the lattice are incompatible with the atom charges in the rusty (Hematite) surfaces. But the rusty surfaces act as catalyst that help to take out the water from the gas stream via the process of adsorption, and hydrate formation can follow slightly outside of the first two or three water layers of about one nanometre. In this project, real hydrocarbon mixtures are studied for the first time using a novel thermodynamic scheme, with composition data which is openly available for the Troll gas and Sleipner gas from the North Sea. The model has been comprehensively validated in this work for pure and mixtures of hydrocarbons, CO2, H2S, and hydrocarbon mixtures with these inorganic gases with experimental data from 35 established literature. Estimates of maximum concentration of water tolerable in hydrocarbon gas systems containing structure I and structure II guest molecules during processing and pipeline transport with the classical dewpoint technique is in order of 18-21 times higher than the estimates with the new concept of evaluating the risk of hydrate formation based on water dropping out by the process of adsorption on Hematite. This alternative route to hydrate formation through adsorption of water on hematite absolutely dominates in evaluating the risk of water dropping out from the gas mixtures (and pure components investigated) to form a separate water phase and eventually lead to hydrate formation. This reason is because the average chemical potential of the water adsorbed on Hematite is approximately 3.4 kJ/mol less than the chemical potential of liquid water. And thermodynamics favours minimum free energy. The typical trend exhibited by methane, methane-dominated gas mixtures like Troll gas and Sleipner gas, and carbon dioxide is decline in the upper limit of water with increasing pressure. The heavier hydrocarbon (ethane, propane, and isobutane) gases exhibits opposite trend to that of CH4 and CH4-dominated gas mixtures where the permitted maximum water content increases with increase in pressure. This manifestation is due to the high density nonpolar phase at the high pressures of the C2+. The non-polar heavier hydrocarbons (especially of structure II hydrate formers) will act to draw down the maximum concentration of water that can be permitted in the gas mixture to a point where they completely dominate or dictate the trends. This is why the safe-limit of water tolerable in Sleipner gas is lower than that of Troll gas which contains lesser amount of C2+. The safe-limit of water to prevent the risk of hydrate formation during processing and pipeline transport of CO2 is only very slightly less than that CH4. Higher concentrations of H2S up to 5% and above would have a significant impact of reducing the maximum concentration of water that can be permitted in hydrocarbon gas mixtures during processing and pipeline transport operations.