In situ mathematically simulation for CO2 internal corrosion in wet natural gas gathering pipelines system by HYSYS

In situ mathematically simulation for CO2 internal corrosion in wet natural gas gathering pipelines system by HYSYS

Gathering pipelines

ASPEN HYSYS

CO internal corrosion

NORSOK M−506 Standard

Wet natural gas

The rate of corrosion due to the presence of carbon dioxide in a carbon steel pipe is an important design consideration for gathering pipelines, particularly in the transport of wet natural gas. To evaluate the corrosion rate in a gathering pipeline, in situ simulation study using HYSYS program employed to predict CO2 corrosion in natural gas gathering pipelines system. The effects of operational conditions, inhibitors, pipe parameters and flow regime on the CO2 corrosion are studied in this paper. Increasing operating pressure leads to increase the pH and decrease the CO2 corrosion rate when the operating pressure over 10 MPa and the solution contents 0.85kmol/m3 iron carbonate. The CO2 corrosion rate does not always increase with temperature, and which will reach a maximum value at 45 °C. A high gas velocity will lead to a high corrosion rate. Less free water present in pipeline may lead to more serious corrosion than that of a large amount of free water. The corrosion rate may be inhibited by liquid hydrocarbon and glycol, and the glycol is not an economic inhibitor, especially when there is a large amount of free water in pipeline. The large diameter and flat pipe are useful for decreasing CO2 corrosion rate. The shear stress and corrosion rate will increase sharply when the slug flow forms in pipeline. Through comparing the data of simulation with field corrosion rate data, feasibility of this numerical simulation method is proved.

Engineering Failure Analysis

2021-04-01

Dai, Min

journalArticle

4WRSRZ2J

1350-6307

10.1016/j.engfailanal.2021.105265