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Hydrate formation along the natural gas pipeline has been identified as a serious threat to the survival of oil and gas industry. The formation if not quickly removed may plug the flowline to collapse the system. This problem costs the industry billions of dollars in revenue loss annually. While all the available literatures on hydrate formation process have focused on its ability to plug the flow line, there has been little or no recognition of its ability to initiate internal corrosion of the pipeline which is a bigger problem to the industry, hence, the importance of this study. This work focuses on this new area for research interest aimed at revolutionalizing the field of corrosion science and technology. In this study, the composition of the lattice which includes methane (CH 4 ), carbondioxide (CO 2 ) or hydrogen sulphide (H 2 S) and water molecules (H 2 O) amongst others is considered. These gases have the ability to easily undergo chemical and/or electrochemical reactions with the pipeline's internal surface while the lattice is in place. The reaction(s) will easily initiating corrosion of the pipe. The study further identifies the fact that even after the successful removal of the hydrate, the initiated corrosion process may continue with the continuous flow of the fluid within the pipeline thereby leading to gradual degradation of the material and deterioration of the pipe's integrity. Over time, the pipeline will begin to leak and/or may undergo full bore rupture (FBR). This, apart from the economic consequences will also generate environmental and political consequences and may lead to complete replacement of the pipe-length. Various management schemes including the necessity for the industry to heavily invest in research and development are recommended.

Pipeline industry annually invests millions of dollar on corrosion inhibitors in order to minimize corrosion's implication on flow assurance; however, attention has never been focused on the possibilities of these chemicals to promote hydrate formation along deepwater pipeline which is also a flow assurance problem. Five inhibitors were investigated in this study at different concentrations and pressures in a cryogenic sapphire cell at static condition. The changes in the formation temperature established that all the inhibitors promote hydrate but at different rates while their hydrate formation patterns also differ from one another. Their ability to promote hydrate could be attributed to their hydrogen bonding properties which is required for hydrate formation. Also, the difference in the promotion rate is attributed to their different sizes and structures, active functional groups and affinity for water molecules which determine the type of hydrogen bonding exhibited by each inhibitor while in solution. The structure and size of each inhibitor also affect its electronegativity and ionization energy since the active electrons of some of the inhibitors have direct exposure to the nucleus while for others; the active electrons at the outermost shell have been shielded from direct influence of the attractive force. Furthermore, the active functional groups obeys electronegativity trend of periodic table to determine whether the resulting bond type will be polar ionic, covalent or ionic with some covalent characteristic in nature. Though, all the inhibitors are foamy; Dodecylpyridinium chloride (DPC) was however the foamiest. DPC also exhibited its highest promotion ability at 200ppm and exhibited specific behaviour at 5000ppm to suggest a change in the hydrate formation rate beyond the critical micelles concentration (CMC). Again, increase in agitation rate prolonged the complete solidification time of the hydrates probably due to the gas solubility. Finally, the feasibility of using this chemical as an additive at high concentrations for natural gas transportation and storage in slurry form was observed due to some exhibited properties, this however requires further investigations.

Monoethylene glycol (MEG), a common hydrate inhibitor in natural gas transportation pipelines is usually regenerated and reused to minimize operating costs. In this study, three corrosion inhibitors and a scale inhibitor were investigated to understand how production chemicals contribute to scaling (salt loading) at pretreatment and reclamation sections of the regeneration process. The first set of study involved the use of ScaleSoftPitzer software to investigate the possibility of salt deposition at the pretreatment stage. Experiments were then conducted at pretreatment stage for inhibitor doses of 250 ppm and 1000 ppm. The same sets of experiments were repeated by adding equal concentration of scale inhibitor with each corrosion inhibitor. In the second part of the study, rich MEG recovered from the pretreatment stage was regenerated by reconcentration and vacuum distillation techniques. The solids formed in the liquor were filtered, dried and weighed and the experiments performed at the pretreatment stage repeated. The results showed that level of scaling in the pretreatment stage was well predicted by the software. The experimental results were also consistent with the software predictions. Corrosion inhibitors produced salts that add up to the scaling problems while the scale inhibitor showed more adverse scaling effects comparatively. This is attributed to reduced hydration ability of scale inhibitors compared to corrosion inhibitors that contained smaller functional groups and large alkyl groups. Benzyl dimethyl hexadecylammonium chloride (B.D.H.C) showed higher scale formation ability compared to the other two corrosion inhibitors due to its polarity that influences its affinity for water. Alkalinity was another factor affecting scale formation; the higher the alkalinity, the higher the scale formation. Furthermore, the reclamation stage was found to be highly prone to corrosion and other impacts due to high total dissolved solids (TDS). Besides, a combination of corrosion and scale inhibitors in MEG regeneration system resulted in higher scaling effects compared to the effect of individual inhibitor due to the synergistic interaction between the two inhibitors. The findings of this study show significant implications in large scale continuous operation where salts dissolved in MEG could precipitate to cause scaling, corrosion and gunking amongst others. Escaping less soluble divalent ions are also capable of salting out downstream to cause the same problems within the pipeline and refinery. All these will adversely influence the process safety and the environment.

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