Field Operations

Inside the Line: Monitoring Internal Corrosion in Pipelines

A pipeline can fail from the outside or from the inside. External corrosion gets more attention because crews can see coatings fail. Internal corrosion is harder to see. The wall thins from the inside while the line keeps moving product, and the first sign of trouble can be a leak or a rupture. Operators manage internal corrosion by knowing what is in the fluid, measuring how fast the metal is thinning, and running inspection tools through the line on a schedule. This article explains what causes internal corrosion, how operators watch it, and what the federal rules require. Corrosion on the outside of the pipe is a separate fight, covered in the article on cathodic protection and corrosion monitoring.

What Corrodes a Pipeline From the Inside

Corrosion needs metal, water, and something in the water that attacks the metal. Plain water alone will corrode steel over time. Add carbon dioxide and the water becomes a weak acid that eats steel at a steady rate. Natural gas and crude often carry carbon dioxide, so CO2 corrosion is one of the most common internal problems in oil and gas lines.

Hydrogen sulfide makes the problem different. Sour gas and sour crude carry H2S, which cracks and pits steel in a different way. Microbes add a third layer. Bacteria form colonies on the pipe wall, and the activity under those colonies attacks the metal. Water is the common thread: wherever it settles and sits, corrosion finds a way to work. Produced water, condensation, and solids that hold water are the real enemies inside a line.

The corrosion rate depends on the fluid. High flow can scour, low spots collect water, and solids settle and create wet, active cells underneath. The same line can corrode slowly in one section and quickly in another, so operators measure instead of guess.

Watching Corrosion Day to Day

The oldest tool is the corrosion coupon. A coupon is a strip of the same metal as the pipe, installed through a fitting in the line. Product flows over it just as it flows over the pipe wall. Crews pull it out on schedule, clean it, weigh it, and compare it with the starting weight. The weight loss over time gives a direct measure of how fast the metal is thinning. Coupons are simple and cheap, and they have been the backbone of internal corrosion monitoring for decades.

Probes do the same job electronically. An electrical resistance probe measures the metal thickness as it erodes, and the readings trend over time. Probes give a faster picture than coupons, and some can be read from a control room. They do not replace coupons; many operators run both.

Water sampling is the third piece. Crews take samples from separators, drips, and sample points and test them in the field or send them to a lab. The tests look for the things that drive corrosion: water content, chlorides, carbon dioxide and hydrogen sulfide, bacteria, and pH. When the water chemistry turns aggressive, operators change the treatment or raise the inhibitor dose.

In-Line Inspection and Cleaning Pigs

Coupons and probes measure corrosion at specific points, not the whole pipe. In-line inspection tools, sometimes called smart pigs, travel through the line with the product and inspect the wall as they go. Magnetic and ultrasonic tools map wall thickness and find pits, cracks, and metal loss before they become leaks. The tools run on a schedule, and results are compared run to run so operators can see how fast defects are growing. See the article on pipeline pigging and inspection for how these tools work and how often they run.

Cleaning pigs scrape wax, scale, and solids off the wall and push them downstream to a trap. Solids hold water against the metal and create the wet, active cells where corrosion works, so a clean line corrodes slower and gives inspection tools a clearer reading. Many operators run cleaning pigs first and inspection tools after.

What the Federal Rules Require

In the United States, the federal code regulates pipelines by what they carry. Hazardous liquid pipelines, the lines that carry crude oil and refined products, fall under 49 CFR Part 195. Gas lines fall under 49 CFR Part 192. Both parts require operators to control external and internal corrosion and to document what they do.

The hazardous liquid rules require operators to test, inspect, and maintain corrosion control systems and keep records of those activities. The gas rules lay out similar requirements, including internal corrosion monitoring where conditions make it a risk. The details differ between the two parts, but the shape is the same: find the threat, watch it, control it, and prove it in writing.

Operators should read the actual regulations rather than rely on summaries; the eCFR versions of both parts are public and authoritative. There is also an industry standard, API Standard 570, that covers inspection, repair, alteration, and rerating of in-service piping systems, and many operators use it to run their inspection programs.

The Integrity Management Program and Its Records

An integrity management program is the operator's plan for keeping a pipeline safe over its whole life. It starts with knowing the threats: internal corrosion, external corrosion, outside force damage, and manufacturing flaws. For each threat the operator picks a way to find it, a way to watch it, and a schedule for doing both. For internal corrosion that means coupons, probes, sampling, and in-line inspection, tied together in one program.

The program is written down and reviewed as new data comes in. When an inspection run finds a thinning area, the operator assesses whether the line still has enough wall thickness to run safely, decides whether to repair, replace, or monitor the section, and sets the next inspection date. The same data feeds the corrosion control records and the inspection records, so the whole picture stays in one place.

Records matter because compliance is judged on paper and because the next crew needs to know what the last one saw. Inspection reports, coupon weights, probe readings, sample results, and repair records are the evidence that the program is actually running. Orderly records keep an operator ready for an audit and the crew working from facts instead of memory. Inspection records join the same document flow as OpsFlo, where operators keep tickets, dispatch, approvals, and timesheets together with the inspection paperwork for each job.

Sources and further reading

• eCFR: 49 CFR 195
• eCFR: 49 CFR 192
• API Standard 570