Pipeline Integrity: Corrosion, Cathodic Protection and Smart Pigs
Key takeaways
- External corrosion occurs where coating is damaged and wet soil touches the steel; internal corrosion is driven by water with CO2, H2S, bacteria and sand.
- The first line of defence is coating; the second is cathodic protection, which protects the coating's weak points.
- A common protection criterion: pipe potential more negative than −850 mV against a Cu/CuSO4 electrode, with soil IR drop considered.
- In-line inspection (ILI) tools measure metal loss along the whole line, so repairs are made before a leak.
- In our example, a 20 in, 70 bar line in X52 steel needs about 6.9 mm, and a corrosion rate of 0.15 mm/y gives about 11 years before reaching that limit.
Educational content only: procedures and operating values vary between companies and sites. Always follow your company’s approved procedures, your supervisor’s instructions and the permits in force at your site.
Why does a pipe corrode?
Steel tends to return to its natural state as iron oxide. Water with salts or oxygen is enough to set up a small electrochemical cell: one part of the surface becomes an anode and loses metal, another becomes a cathode. The small current between them eats the iron slowly, but it never stops.
External corrosion happens where the coating is damaged (holidays), especially in wet or salty soil, where water collects, and with stray currents near power lines.
Internal corrosion happens when water collects in the pipe, especially at low points. It is accelerated by CO2 (sweet corrosion), H2S (sour corrosion), bacteria (microbiologically influenced corrosion), and sand scouring the wall (erosion).
First line of defence: coating
Coating isolates the steel from the soil. Common transmission-line coatings are fusion bonded epoxy (FBE) and three-layer polyethylene (3LPE) or polypropylene. Field welds are covered with special sleeves or tapes. But no coating is perfect: small scratches occur during transport and burial, and coatings age. This is where cathodic protection comes in.
Second line of defence: cathodic protection
The idea is to make the whole pipe a cathode, so it does not lose metal. There are two systems:
- Galvanic (sacrificial) anodes: magnesium or zinc blocks buried near the pipe and connected to it. Being more active than steel, they corrode instead of it. Suited to short or well-coated lines.
- Impressed current: a rectifier converts AC to DC and drives it from special anodes in the soil (groundbed) to the pipe. Suited to long lines; in the desert the rectifier may run on solar panels.
How do we know protection is enough?
We measure the pipe-to-soil potential with a voltmeter and a copper/copper sulfate (Cu/CuSO4) reference electrode placed on the soil above the pipe, at test posts along the line.
- Common criterion: −850 mV or more negative with protection applied, provided the soil IR drop is accounted for. That is why an "instant off" reading is often taken by interrupting the current for a fraction of a second.
- Another criterion: a polarization shift of at least 100 mV.
- Close interval survey: readings every metre or few metres along the line reveal weak zones between test posts.
- Coating defect surveys: methods such as DCVG locate coating holidays from the surface.
Protecting against internal corrosion
- Removing water: good processing at the plant, and regular pigging to sweep out water and deposits.
- Corrosion inhibitors: chemicals injected at calculated doses that form a protective film on the wall.
- Monitoring: corrosion coupons weighed after a period, and electrical resistance (ER) probes that give the corrosion rate directly.
- Biocides: where bacterial corrosion is present.
In-line inspection and remaining life
ILI tools travel inside the line like a pig and measure metal loss on every metre. The best known is magnetic flux leakage, which magnetizes the wall and picks up the flux leaking out where metal has been lost. Comparing two successive runs gives the corrosion growth rate, telling us where to dig and repair, and when to inspect again.
A line has an outside diameter D = 508 mm (20 in), design pressure 70 bar (7 MPa), X52 steel with specified minimum yield S = 359 MPa, and design factor F = 0.72. Barlow's equation gives the minimum wall:
t = P × D ÷ (2 × S × F)
t = 7 × 508 ÷ (2 × 359 × 0.72) ≈ 6.9 mm
Nominal wall is 9.5 mm. Two ILI runs 6 years apart show the deepest corrosion point went from 9.5 mm to 8.6 mm:
rate = (9.5 − 8.6) ÷ 6 = 0.15 mm/y
life ≈ (8.6 − 6.9) ÷ 0.15 ≈ 11 years
This is a simplified teaching estimate. Real assessment of a local defect uses approved methods such as ASME B31G and adds margins for tool accuracy.
Hazards and safety
- Third-party damage: digging near a line without coordination is one of the biggest causes of pipeline accidents, hence line markers, right-of-way patrols and excavation permits.
- Excavating a live line for repair: requires lowering pressure to a safe level, gas testing and shoring the trench walls.
- Rectifiers: carry electrical voltage and must be handled only by qualified technicians.
- Sour lines: a leak means H2S, so personal monitors and an emergency plan are required.
Takeaway for the engineer
Pipeline integrity is a connected chain: good coating, regularly measured cathodic protection, control of water and internal corrosion, and in-line inspection that measures what we cannot see. Barlow's equation and the corrosion rate turn those measurements into a decision: when to repair, and at what pressure to run the line until then.
Test your understanding
Related lessons
- Pigging: cleaning and inspecting pipelines
- Pipeline hydraulics and pump stations
- Hydrotreating and sulfur recovery (Claus)
Sources
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