Internal corrosion can occur in the natural gas transmission pipelines when aqueous electrolytes are present. The presence of water results from the condensation of wet gas or liquid water from upstream plant upsets. Dissolved contaminants such as salts, CO2, and H2S make the electrolyte more corrosive. The ability to monitor internal corrosion in natural gas transmission pipelines before it occurs could have a significant impact on preventing methane leaks as well as catastrophic events resulting from corrosion. A recent concept for early corrosion on-set detection involves the use of proxy materials integrated with the optical fiber sensor platform that corrode at a rate which provides insight into the conditions for which pipeline corrosion is expected to occur. Successful realization of this class of sensors requires a detailed understanding of the corrosion behavior of relevant thin film systems. In support of this goal, Fe thin film of different thicknesses (25, 50, 100 nm) on quartz substrates were tested in CO2 saturated 3.5%wt. NaCl solutions at 30 °C. The effects of CO2 and thickness on the corrosion of Fe thin films were studied using optical transmission technique and in situ electrochemical method. The increase in light transmission corresponded to the corrosion of Fe thin films. CO2 accelerated the corrosion of Fe thin films due to the lower pH and promoted corrosion reactions, resulting in a faster increase of light transmission over time than without CO2. While the corrosion rate (CR) increased with the film thickness, the CR of Fe thin films were of the same order of magnitude with the API 5L X65 bulk pipeline material, verifying that Fe thin films can serve as a corrosion proxy when integrated with the optical fiber based sensing platform.
Internal corrosion can occur in the natural gas transmission pipelines when aqueous electrolytes are present. Inside the pipelines, electrochemical corrosion takes place in the water phase condensed from wet gas or liquid water from upstream plant upsets. The inherently existing corrosive gases such as CO2 and H2S could dissolve in the water forming corrosive electrolytes.1 Over the last 30 years, internal corrosion accounts for 61% of the incidents caused by corrosion in natural gas transmission and gathering pipeline incidents, according to Pipeline and Hazardous Materials Safety Administration (PHMSA) database. Natural gas consists of nearly 33% of the energy consumption in the United States in 2016 according to the U.S. Energy Information Administration (EIA).2 The natural gas delivery system includes 528,000 km (328,000) miles of natural gas transmission and gathering pipelines.3 Therefore, it is important to monitor corrosion inside the gas pipelines to mitigate corrosion and ensure the structure integrity. Of particular interest is an ability to identify localized conditions which are known to initiate internal corrosion before the onset of significant pipeline corrosion occurs.