Ringworm Corrosion | Oil Authority

Ringworm corrosion is a specific type of localized bimetallic (galvanic) corrosion that develops on oilfield tubular goods (drillpipe, casing, production tubing) in a distinctive ring-shaped pattern located several inches from the pipe's upset zone (the thickened end where the tool joint or threaded coupling is welded or forged onto the pipe body) — the corrosion ring may appear as either a smooth, uniform circumferential band of metal loss or as a severely pitted band with discrete corrosion pits distributed around the pipe circumference; the underlying cause of ringworm corrosion is the metallurgical inhomogeneity created during the upsetting process used to manufacture pipe ends, where the heat applied to forge the upset region creates two adjacent zones with different grain structures (a fine-grained, hardened upset zone and a coarser-grained, slightly different microstructure in the adjacent pipe body); this microstructural transition zone has slightly different electrochemical potential from both the upset and the bulk pipe body, creating a galvanic couple where the transition zone becomes the anode and is preferentially attacked by corrosive fluids during the pipe's service life; the operational mitigation for ringworm corrosion is normalizing the entire pipe (heating to approximately 800 to 900°C and slow-cooling to allow grain structure equilibration) after the upsetting process, eliminating the metallurgical inhomogeneity and the resulting galvanic couple before the pipe is shipped to the field; pipe that has not been properly normalized is susceptible to ringworm corrosion in service environments containing CO2, H2S, or other corrosive species at typical concentrations.

Key Takeaways

Pipe upsetting process at the manufacturing facility forms the upset (thickened end) for tool joint welding or threaded connection through hot-forging operations where the pipe end is heated to approximately 1100 to 1200°C and compressed against a forming die to produce the increased wall thickness — the upsetting process creates the desired increased wall thickness for connection but unavoidably introduces a heat-affected zone (HAZ) adjacent to the upset where the heat soaked into the pipe body during upsetting altered the grain structure; the HAZ extends typically 4 to 8 inches from the upset transition; if the entire pipe is not subsequently normalized, the HAZ remains as a region of slightly different grain structure than the adjacent pipe body, with the transition between the two grain structures being the location susceptible to ringworm corrosion; modern manufacturing standards require normalizing of the upset region or full normalizing of the pipe to prevent ringworm susceptibility, with the choice depending on the steel grade and intended service environment.
Galvanic corrosion mechanism in ringworm corrosion arises from the small but significant electrochemical potential difference between the fine-grained HAZ adjacent to the upset and the coarser-grained pipe body — even though both regions are nominally the same alloy composition (typical drilling pipe is API 5DP grades L80, S135, or G105, all variants of low-alloy steel), the different grain structures result in different electrochemical activities; the fine-grained region typically has slightly higher electrochemical potential and acts as the cathode, while the coarser-grained region acts as the anode and is preferentially attacked; the small potential difference (typically 10 to 30 mV) is sufficient to drive significant localized corrosion when the pipe is exposed to corrosive electrolytes (CO2-saturated brine, H2S-containing produced water); the corrosion is geometrically concentrated in the narrow transition zone, producing the characteristic ring-shaped pattern; the mechanism is similar to other forms of galvanic corrosion but is unique in being entirely due to manufacturing-induced microstructural inhomogeneity rather than to mixing of dissimilar alloys.
Normalizing heat treatment is the standard manufacturing process that prevents ringworm corrosion by establishing a uniform grain structure through the entire pipe — the pipe is heated to approximately 850 to 900°C (above the austenitizing temperature for the specific steel grade) and held at temperature for sufficient time to fully transform the structure to austenite, then air-cooled at controlled rate; the air cooling produces a fine, uniform pearlite-ferrite grain structure throughout the pipe length, eliminating both the HAZ and the upset's hot-forging structure; properly normalized pipe has uniform mechanical properties (tensile strength, yield strength, hardness) along its full length and is essentially immune to ringworm corrosion in service; API 5CT and 5DP specifications include normalizing requirements for various pipe grades and intended service conditions, with sour service grades (designed for H2S environments per NACE MR0175 / ISO 15156) having particularly stringent heat treatment specifications; however, some lower-cost pipe products may not be fully normalized, leaving residual susceptibility to ringworm corrosion that becomes apparent after extended service in corrosive environments.
Detection and inspection of ringworm corrosion in field pipe inspection programs requires careful examination of the pipe-to-upset transition zone using both visual inspection (the smooth ring is sometimes visible to the eye on cleaned pipe) and quantitative inspection methods including magnetic particle inspection (visualizes surface and near-surface flaws), wet fluorescent magnetic particle inspection (higher sensitivity for surface flaws), and ultrasonic thickness gaging at multiple azimuthal positions around the pipe circumference (to identify localized wall thickness reduction characteristic of ringworm corrosion); pipe inspection facilities (TenarisHydril, Vallourec, Tubacex, and major service companies) routinely include ringworm corrosion screening as part of standard inspection protocols for pipe destined for sour service or corrosive applications; pipe with ringworm corrosion exceeding the API 5C5 acceptance criteria (typically 12 to 20 percent wall thickness reduction depending on grade and service) is downgraded or rejected for the original service environment, with the corrosion typically being non-recoverable due to the fundamental microstructural inhomogeneity rather than surface damage that could be repaired.
Service environment effects on ringworm corrosion severity vary significantly with the specific corrosive species present in the production or drilling fluid — CO2-containing systems (typical of natural gas production with CO2 partial pressures of 1 to 50 bar) cause the greatest ringworm corrosion intensity because the carbonic acid produced by CO2 dissolution is sufficiently aggressive to attack the susceptible HAZ but not aggressive enough to cause uniform corrosion of the entire pipe; H2S-containing systems (sour service) cause ringworm corrosion combined with sulfide stress cracking risks, requiring particular vigilance; high-salinity oxygenated drilling fluids cause ringworm corrosion in drillpipe used in coiled tubing applications where some surface oxygen exposure may occur; ringworm corrosion is generally not observed in clean produced fluids without dissolved corrosive gases, even on pipe with susceptible microstructure, because the corrosion driving force is absent; service environment screening is part of the pipe selection process, with proper steel grade and heat treatment matched to the expected service conditions.

Fast Facts

Ringworm corrosion was first systematically documented in the 1950s and 1960s as oilfield tubular failures from the form became more common with increased CO2 and H2S exposure in deeper, more corrosive wells. The American Petroleum Institute developed the modern API 5CT and 5DP specifications that include heat treatment requirements specifically addressing ringworm corrosion susceptibility, with subsequent NACE International standards (NACE MR0175 / ISO 15156) extending the requirements for sour service applications. Modern pipe manufacturing facilities (TenarisHydril, Vallourec, Sumitomo Metals, U.S. Steel, NSGRP) have largely eliminated ringworm corrosion from new pipe production through standardized heat treatment protocols, but the issue persists in legacy pipe inventories and in pipe from manufacturers without rigorous heat treatment quality control. Field pipe inspection programs continue to identify ringworm corrosion failures in older wells where pipe vintage predates modern manufacturing standards, with the failures typically occurring after 10 to 30 years of service depending on environmental conditions.

What Is Ringworm Corrosion?

Oilfield tubular goods — drillpipe, casing, and production tubing — are subjected to demanding service conditions including high pressure, mechanical stress, and exposure to corrosive fluids. Most of the pipe length experiences relatively uniform service conditions and corrodes uniformly if it corrodes at all. But occasionally, pipe in service shows a distinctive form of localized corrosion: a ring-shaped band of metal loss several inches from the upset zone where the tool joint or threaded coupling attaches to the pipe body. This is ringworm corrosion, named for the visual resemblance to a fungal skin infection that creates ring-shaped patterns.

The cause is metallurgical rather than environmental. When pipe ends are upset (forged to form the thickened end needed for connection), the heat applied during forging creates a heat-affected zone in the adjacent pipe body where the grain structure differs from both the upset itself and the bulk pipe body. This transition zone has slightly different electrochemical properties from the adjacent metal, creating a galvanic couple that drives preferential corrosion in the transition zone when the pipe is exposed to corrosive fluids. The result is the characteristic ring of metal loss that defines ringworm corrosion. The mitigation is straightforward: normalize the entire pipe after upsetting to establish uniform grain structure, eliminating the galvanic couple. But pipe manufactured without proper normalizing — particularly older pipe vintages — remains susceptible to this form of corrosion in service.

Ringworm Corrosion Detection and Mitigation in Field Operations

Detection of ringworm corrosion in field operations requires inspection methods sensitive to localized wall thickness variations near the pipe upset. Visual inspection of cleaned pipe ends sometimes reveals a slight ring-shaped depression that indicates underlying corrosion. Quantitative inspection methods including ultrasonic thickness measurement at multiple positions around the pipe circumference, magnetic particle inspection for surface and near-surface flaws, and electromagnetic inspection for wall thickness anomalies provide more reliable detection. Pipe inspection facilities typically perform multi-method inspection on pipe destined for critical applications, with ringworm corrosion identification triggering automatic downgrade or rejection of the pipe for sour service or other demanding applications. The fundamental mitigation — proper heat treatment during manufacturing — must be implemented at the manufacturing facility because field treatment cannot reverse the metallurgical inhomogeneity. Operators procuring new pipe specify normalizing requirements in the procurement specification and verify compliance through manufacturer certification and independent inspection of selected pipe samples. Pipe with susceptible microstructure (older vintage, lower-cost manufacturers) should be deployed in less corrosive service environments where the ringworm corrosion risk is lower.

Ringworm Corrosion Across International Tubular Specifications

Canada (CSA / API): Canadian pipe standards reference API 5CT and 5DP specifications that include heat treatment requirements addressing ringworm corrosion; AER's pipe specifications for wells in sour service applications require pipe certified to API 5CT sour service grades (L80, C95, T95, P110 sour) with the rigorous heat treatment that prevents ringworm corrosion susceptibility; major Canadian operators verify heat treatment compliance through manufacturer certification and routine inspection of pipe samples; legacy pipe inventories from earlier vintages may have susceptible microstructures and are typically restricted to less corrosive service environments.

United States (API / NACE): API 5CT and 5DP specifications define the standard heat treatment requirements for oilfield tubular goods that prevent ringworm corrosion when properly implemented; NACE MR0175 / ISO 15156 imposes additional requirements for sour service applications including specific heat treatment protocols and acceptance criteria; US pipe manufacturers (US Steel, Tenaris USA, Vallourec USA, Borusan Mannesmann) maintain quality control programs that ensure compliance with the heat treatment requirements; pipe procurement specifications for major US operators include detailed heat treatment specifications and verification requirements that supplement the API and NACE standards.