Field Operations

Cathodic Protection: How Gathering Lines Stay Whole Underground

Corrosion is the leading integrity threat on aging gathering lines, and it works from the outside in. Soil chemistry, moisture, and stray currents all attack buried steel where no one can see it. Cathodic protection and routine corrosion monitoring are what keep that attack from becoming a leak, and the federal rules require both on buried metallic pipelines.

Why buried pipelines corrode

Steel in the ground wants to return to the ore it came from. In contact with moist soil, the pipe surface becomes a set of tiny electrochemical cells: some areas give up metal ions (the anodes), other areas accept them (the cathodes), and the anodic areas lose wall thickness year after year. Soil chemistry drives the pace. Clay soils hold water and dissolved salts and corrode pipe faster; sandy, well-drained soils are gentler. Fertilizer treatments, produced water spills, and other chemical contact on the right-of-way can make local conditions aggressive.

Stray currents add a second, independent cause. Direct current leaking from other systems, including a neighboring pipeline's impressed current rectifiers, finds the pipe as the easiest return path and leaves the steel where the current departs it. Where a line shares a corridor with high-voltage power lines, induced alternating current can create its own problems. Whatever the source, the result is external metal loss at exactly the spots the coating should have protected.

How cathodic protection works

Cathodic protection does not stop corrosion; it moves it. The system forces the whole buried pipe to act as the cathode of an electrochemical cell, so the pipe stops giving up metal. The corrosion happens instead at anodes installed for the job, which are replaced or serviced on a schedule. There are two established methods:

• Sacrificial anodes. Bars of magnesium or zinc are buried beside the pipe and connected to it. The anode metal is more active than steel, so it corrodes in place of the pipe. No power source is needed, which makes this method common on shorter lines and where electricity is not available.
• Impressed current systems. A rectifier converts utility power to direct current and drives it from a bed of anodes through the soil to the pipe. Output can be adjusted to match conditions, which makes this the usual choice for longer gathering systems.

Both methods share one dependency: a complete electrical circuit and a coating that carries most of the load. Coating does the heavy lifting, and cathodic protection covers the holidays, the small bare spots and coating damage where corrosion would otherwise start.

What the federal rules require

Corrosion control on buried metallic pipelines is regulation, not preference. Gas pipeline operators work to 49 CFR 192 Subpart I, and hazardous liquid pipeline operators work to 49 CFR 195 Subpart H. The pattern is the same in both: coat the pipe, install cathodic protection where the operator determines it is needed, and monitor the system to prove the protection is working.

The rules also require records. Each test station reading, each rectifier check, and each annual test has to be logged so a reviewer can see that protection was effective over time. A system that was protected last year but not this year has not met the rule, no matter how well it was designed.

Test stations, potentials, and rectifier checks

Monitoring starts at the test station, the small post or box set at intervals along the line to give access to the pipe. The crew measures pipe-to-soil potential: the voltage between the pipe and a copper-sulfate reference cell placed in the soil above it. The common criterion for protection is a potential of minus 0.85 volts or more negative, measured against that reference. Readings are compared to the criterion and, just as important, to the line's own history, because more negative is not always better.

The schedule is defined by the rules and by good practice:

• Rectifiers are checked several times a year. The crew records output voltage and current and notes anything that changed since the last visit.
• The effectiveness of cathodic protection is tested at least once each calendar year, with intervals between tests never exceeding 15 months.
• Test stations are read on the same rounds, and every reading is logged with its date and the person who took it.

When routine readings flag a problem, operators run close-interval surveys: crews walk the line and take potentials every few feet to pinpoint weak protection or failing coating. Where pipelines share corridors with power lines, AC mitigation is part of the program, with grounding and mitigation hardware checked on the same schedule. Industry practice for all of this work is documented in standards published by AMPP, formerly NACE International, which operators and integrity teams use alongside the federal rules.

The field routine that keeps records honest

Most of this work falls to the pumper or a corrosion technician walking the line. The routine is simple to describe: read each test station, check the rectifier, note exposed or damaged coating wherever the pipe is visible, and report anything that does not match the last readings. A rectifier running at zero output, a test lead cut by a mower, or a fresh excavation near the right-of-way should appear in the records within days, not months. On many leases this is part of the pumper's daily routine, sitting alongside the production checks that keep the battery running.

Records turn visits into trend data. A potential drifting less negative over several quarters is an early warning; the same drift discovered after a leak is a finding. Scheduling corrosion surveys and logging rectifier readings with field tickets keeps the inspection history in one place, so no one has to ask whether a station was read this quarter. Software like OpsFlo handles the tickets, dispatch, approvals, timesheets, and documents around this work, which matters most at audit time, when the records are the proof. The same discipline applies before burial: new pipe should be proven sound with hydrostatic testing before commissioning, so coating and metal start out right.

Sources and further reading

• 49 CFR 192 Subpart I: corrosion control for gas pipelines
• 49 CFR 195 Subpart H: corrosion control for hazardous liquid pipelines
• AMPP: the corrosion association, formerly NACE International