Hydrate formation and its influence on natural gas pipeline: Simulation study

Ifeanyichukwu Michael Onyejekwe; Nnaemeka Uwaezuoke; George Ononien  Gborienemi; Ubanozie Julian Obibuike; Nnanna Onwuegbueha  Okoli

doi:10.62638/ZasMat1088

Authors

Ifeanyichukwu Michael Onyejekwe Petroleum Engineering Department, Federal University of Technology, Owerri, Imo State, Nigeria Author https://orcid.org/0000-0001-6489-6801
Nnaemeka Uwaezuoke Petroleum Engineering Department, Federal University of Technology, Owerri, Imo State, Nigeria Author https://orcid.org/0000-0002-4729-4072
George.O. Gborienemi Petroleum Engineering Department, Federal University of Technology, Owerri, Imo State, Nigeria Author https://orcid.org/0009-0006-9519-0864
Obibuike. U. Julian Petroleum Engineering Department, Federal University of Technology, Owerri, Imo State, Nigeria Author https://orcid.org/0000-0003-1382-9160
Nnanna O. Okoli Petroleum Engineering Department, Federal University of Technology, Owerri, Imo State, Nigeria Author https://orcid.org/0009-0007-9579-7946

DOI:

https://doi.org/10.62638/ZasMat1088

Keywords:

CO2 corrosion, model, simulation, hydrate, MATLAB

Abstract

This study simultaneously studied the twin problem of hydrate and corrosion that occurs in natural gas pipelines, establishing their interdependence using a simulation approach. CO₂ corrosion was simulated using the NORSOK M-506 standard model in Matlab. Major factors considered are the relationship between corrosion rate and temperature, corrosion rate and PH, corrosion-temperature relationship for varying CO₂ mole percent, and PH values. The result from this study established that both type I and type II hydrates could form at the operating conditions of 5^OC and 60 bar. The obtained result also shows that the rate of corrosion decreases and increases with an increase in PH values and temperature respectively to a certain temperature of approximately 78^OC, then a dip in the rate of corrosion. The result for the corrosion-temperature relationship for varying PH values and CO₂ mole percent shows a decrease in corrosion rate with an increase in PH and an increase with the increase in CO₂ mole percent. Furthermore, the obtained results highlight a rise as high as 5.7 mm/year at a 3 mole percent CO₂. This value and trend portray a bad omen for the affected pipeline. This study recommends that natural gas to be transported by pipeline should be sweetened and processed to remove H₂S, CO_2, and mercaptans if present.

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