Corrosion and hydrate formation in natural gas pipelines
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Gas industry annually invests millions of dollars on corrosion inhibitors in order to minimize corrosion implications on flow assurance; however, attention has never been focused on possibilities of these chemicals to promote hydrate formation along deepwater pipelines, which would equally result in another flow assurance problem of high magnitude. This study investigated the possibilities of corrosion inhibitors to aid the formation of gas hydrate along offshore (or underwater) pipeline systems; developed a predictive model on corrosion rate for natural gas pipelines with gas hydrates as the corroding agent and finally investigated the ability of pure N2 and H2 gases to inhibit the formation of gas hydrates.All experiments in this thesis were conducted by forming various water-gas systems in a cylindrical cryogenic sapphire cell. The first investigative work on hydrate-corrosion relationship was conducted by allowing contacts between an industrial grade natural gas (with 20% CO2 content) and five different corrosion inhibitors that are commonly used at offshore fields. The equipment, consisting of several fittings could operate at a temperature range of -160oC – 60oC (with accuracy of ± 0.10oC) and pressure range of 1bar to 500bar (with accuracy of ± 0.5bar). Using the ‗Temperature Search‘ method, the hydrate formation temperature point for each inhibitor was located at 500ppm and 100bar and the result compared with that of control experiment. Due to observed significant influence, further investigations were conducted on Dodecylpyridinium Chloride (DPC) at various concentrations and pressures. The corrosion model was developed based on hydrate‘s thermodynamic properties such as the operating temperature, pressure, fluid fugacity, wall shear stress, superficial velocity, enthalpy, entropy and activity coefficient amongst others, and a Matlab computer code was written to simulate the generated solution algorithm. Finally, components interaction study was conducted on various gas mixtures inside the sapphire cell to investigate the ability of pure N2 and H2 gases to inhibit the formation of gas hydrates.The obtained results established that all corrosion inhibitors aid hydrate promotion; this was attributed to their surfactant and hydrogen bonding properties which were essential for hydrate formation. The five investigated inhibitors showed different promotional rates with DPC having the highest promotional ability. The different promotional rate is due to their different sizes and structures, active functional groups and affinity for water molecules which determine the type(s) of hydrogen bonding exhibited by each inhibitor while in solution. The significant performance of DPC compared to other inhibitors was justified by the specific available active functional group which obeys electronegativity trend of periodic table to determine whether the resulting bond type will be polar covalent, ionic or ionic with some covalent characteristic in nature. Also, DPC hydrates revealed strong influence of the chemical‘s surfactant properties at all pressures and concentrations while its Critical Micelle Concentration (CMC) was believed to be 5000ppm due to the various anomaly behaviors exhibited at this particular concentration.The developed mathematical model adequately predicted corrosion rates with gas hydrate as the corroding agent and its effectiveness was confirmed by the level of agreement between its generated results and existing literatures. The resulting corrosion rate from hydrates could be as high as 174mm/yr (0.48mm/day). This is extremely alarming compared to the industry‘s aim to operate below 2mm/yr. At this rate, an underwater pipeline would be subjected to full bore rupture within some days if corrective measures are not quickly taken.Furthermore, the components interaction study revealed that CH4 played key roles on hydrate formation patterns during natural gas transportation through offshore pipeline system; the higher a natural gas CH4 content, the higher the risk of hydrates promotion. It also showed that when alone, CO2 does not form hydrate at low concentrations but showed a remarkable ability to aid hydrate formation when mixed with CH4. This is not surprising since it is also a former with ability to form Type I hydrate due to its very small size. Again, the ability of pure N2 and pure H2 gases to inhibit the formation of gas hydrate was confirmed but with H2 showing more significant effects. This was ascribed to their individual pressure condition to form hydrate. Though, N2 gas with small molecules forms Type II hydrate at a relatively higher pressure above the investigated pressures, it still forms hydrate within higher operating pressures practiced at gas fields during the transportation. However, H2 gas can never form hydrate at any natural gas transportation conditions. H2 gas only forms hydrates at extremely high pressure of about 2000bar because its molecules are too small and usually leaked out of hydrate cage, thus, reducing the amount that could be stored. By extension, these individual properties affect their interactions with natural gas during the hydrate formation process.Conclusively, this study has essentially revealed a new hydrate-corrosion relationship and established the need for comprehensive investigations in this research area. At all the investigated pressures, it was realized that DPC prolonged the complete blockage of the glass orifice at 10000ppm. This special characteristic may suggest the potential in applying the chemical as an additive for natural gas transportation and storage in slurry forms. Finally, the use of pure N2 or H2 as hydrate inhibitor in the offshore pipeline would be very cost effective to the industry. However, extreme care should be taken during the selection process since there are needs to further investigate the safety factors, material availability, cost implication and recovery from the main gas stream in order to choose the better option.
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