Sulfidation Corrosion 2026 — Modified McConomy Curves + Cr Content Decoded

Sulfidation corrosion in refinery piping: the direct answer

Short answer: Sulfidation, also called sulfidic corrosion, is high-temperature thinning of carbon and low-alloy steel caused by sulfur compounds in hydrocarbon streams. API RP 939-C (second edition, 2019) addresses streams without hydrogen from roughly 500 °F (260 °C) up to about 1,000 °F (540 °C), with a lower threshold near 450 °F (230 °C) in hydrogen-containing service. The rate depends on temperature, sulfur content and chromium content, and on silicon content in carbon steel. Low-silicon components can thin much faster than the pipe next to them. That is why component-by-component inspection matters.

This section adds what the overview above leaves out: what the mechanism actually depends on, the Chevron Richmond lessons, what RP 939-C changed, and how an NDE programme for sulfidation is built in practice. A terminology note first. The industry correlation curves for sulfidation rates in hydrogen-free streams are the McConomy curves, published in modified form in API RP 939-C. They are not "McCoy" curves. For hydrogen and H2S environments, such as hydroprocessing units, RP 939-C and API RP 571 refer to the Couper-Gorman curves. Rate curves give a starting estimate. Measured thickness data always overrides them.

What drives the corrosion rate

Sulfidation is a direct chemical reaction between the steel surface and sulfur species, mainly H2S formed as sulfur compounds in the crude break down thermally. The product is an iron sulfide scale. It is not an electrochemical process in water, so it needs no free water and happens at temperatures where water cannot exist as liquid. The main variables are listed below.

• Temperature. Rates rise steeply with temperature through the sulfidation range. Thermocouple accuracy, heater outlet temperatures and process changes therefore matter as much as metallurgy. A crude slate change or a cut-point change can shift a circuit into a faster corrosion regime without any change to the equipment.
• Sulfur content and species. More reactive sulfur generally means faster corrosion. Total sulfur alone does not fully predict the rate, because sulfur species differ in how readily they produce H2S.
• Chromium content. Adding chromium (1¼Cr, 2¼Cr, 5Cr, 9Cr, 12Cr, then 300-series stainless) progressively lowers the rate. This is the basis for upgrading materials in hot sulfur service.
• Silicon content in carbon steel. Carbon steel with less than 0.10 weight percent silicon corrodes significantly faster in sulfidation service than steel with higher silicon. ASTM A106 pipe has a minimum silicon requirement. Some other carbon steel specifications historically did not, so a circuit built from "carbon steel" can contain a mix of components with very different sulfidation resistance.
• Naphthenic acid and flow. Naphthenic acid corrosion and high velocity can interact with sulfidation and change both rate and pattern. Mechanism reviews should consider them together.

The practical result is that thinning in a sulfidation circuit is often uneven from component to component. It can be fairly uniform within a single pipe spool or fitting while differing sharply between neighbouring spools or fittings. A CML programme that samples a few locations can miss the one fast-corroding elbow entirely.

The Chevron Richmond lesson and what changed in RP 939-C

On 6 August 2012, a carbon steel line on the #4 Crude Unit at the Chevron refinery in Richmond, California, ruptured. The US Chemical Safety Board (CSB) found that the 4-sidecut line had thinned from sulfidation corrosion, and that the failed component had low silicon content. The release formed a vapour cloud that engulfed 19 workers before igniting. In the weeks that followed, about 15,000 people in the surrounding communities sought medical treatment. The CSB's investigation is the most widely cited case study for this mechanism (CSB Chevron Richmond investigation).

The CSB made recommendations to API covering both RP 939-C and API 570. For RP 939-C it asked API to require users to:

• identify carbon steel circuits in sulfidation service that may contain low-silicon components;
• either inspect every component in those circuits once (100 percent component inspection) or replace the at-risk carbon steel with a more resistant alloy;
• designate any low-silicon or fast-corroding components found as permanent condition monitoring locations (CMLs) until they are replaced.

API published the second edition of RP 939-C in January 2019. The CSB reviewed it and in January 2021 closed that recommendation as "Closed - Acceptable Alternative Action". In its summary, the CSB noted that the new edition:

• specifies a 0.10 wt% minimum silicon for carbon steel piping components in sulfidation service;
• states that thickness surveys apply to carbon and low-alloy steel systems;
• calls for risk assessment when deciding on piping replacement;
• encourages more resistant materials to reduce reliance on inspection;
• designates low-silicon components as permanent CMLs inside an API 570 inspection programme.

The CSB also noted that the document keeps recommended-practice "should" language rather than mandatory "shall" language. RP 939-C was later reaffirmed. Check the current status in your licensed copy.

California also strengthened its refinery process safety regulations after the incident. Among other things, they now require damage mechanism reviews. Refineries elsewhere in the US cover the same ground through OSHA PSM mechanical-integrity programmes.

Building a sulfidation inspection programme under API 570

API 570 governs in-service piping inspection. For sulfidation circuits, a defensible programme usually works through these steps.

• Identify the circuits. Use operating temperature (including excursions), sulfur content and hydrogen presence against the RP 939-C applicability range. Typical candidates are crude and vacuum unit transfer lines, sidecuts and bottoms, coker feed and fractionator piping, FCC feed and slurry systems, and hot hydroprocessing feed and effluent piping.
• Establish material composition. For carbon steel circuits, find out whether every component's silicon content is known. Mill test reports help when they can be traced to individual components. Where they cannot, owners use positive material identification with a technique that can actually measure silicon. Silicon is a light element, and many handheld XRF analysers cannot quantify it reliably. Owners therefore commonly use spark optical emission spectroscopy or other silicon-capable methods. Confirm the instrument's capability before relying on it.
• Do 100 percent component inspection where the material is not proven. Every pipe spool, elbow, tee, reducer and fitting in the at-risk circuit gets at least one thickness assessment. The aim is to find the components that are thinning faster than the circuit average.
• Make fast or low-silicon components permanent CMLs. Track their corrosion rates individually until they are replaced.
• Calculate rates and remaining life per component. Use the long-term and short-term rate logic in API 570 instead of applying a circuit-average rate to every part. See our corrosion rate calculation guide.
• Set intervals by service class and remaining life. Intervals come from the API 570 piping class and remaining life, or from the owner's API 580/581 risk-based programme. RBI is an engineering analysis the owner commissions. It is not an NDE deliverable. See the API 570 Class 1 interval guide.
• Feed process changes back into the programme. Crude slate, temperature and throughput changes should trigger a review of the affected circuits. A management-of-change link between operations and inspection is what keeps the programme current.

NDE methods for sulfidation: what each one gives you

Sulfidation is a wall-loss mechanism, so most of the work is thickness measurement. It is often done at high temperature while the unit runs. The methods differ in coverage and in what they can do on hot piping.

For 100 percent component inspection, the practical answer is usually a mix. Profile RT or UT screens every component. Detailed UT or mapping follows on any component that reads thin or has unknown material, and the worst components become permanent CMLs. Method details: piping circuit inspection and CML surveys, corrosion mapping, radiographic testing and guided wave testing.

Worked example (qualitative): a crude unit sidecut circuit

A refinery's mechanism review flags a carbon steel sidecut circuit operating inside the RP 939-C temperature range. It was built decades ago, and component-level material records are incomplete. The owner orders a 100 percent component inspection.

Profile radiography screens every spool and fitting on-stream. High-temperature UT follows on components that show lower wall. Most components agree closely with the historical CML readings. Two elbows and one short spool read noticeably thinner. Material testing commissioned by the owner confirms that these components have low silicon.

The API 570 inspector designates the three components as permanent CMLs and calculates individual remaining lives. One component's remaining life is short enough that the owner schedules replacement with a higher-chromium alloy at the next opportunity. The rest of the circuit stays on its existing interval, and the review flags the circuit for a materials-upgrade study. No single circuit-average corrosion rate would have shown this risk.

Common mistakes in sulfidation programmes

• Relying on historic CMLs only. The Chevron failure came from a component that thinned faster than the rest of its circuit.
• Assuming "carbon steel" means one material. Silicon content can vary component by component unless every part is proven to a specification with a silicon minimum.
• Using handheld XRF to "confirm" silicon when the instrument cannot measure it reliably.
• Ignoring process changes. Hotter or higher-sulfur operation changes rates without any equipment change.
• Applying low-temperature corrosion mitigations. Coatings, cathodic protection and inhibitor programmes do not address high-temperature sulfidation. Material selection, temperature control and inspection do.
• Applying hydrogen-free curves to hydrogen services. RP 939-C and API RP 571 point to the Couper-Gorman curves for H2/H2S environments.
• Not correcting high-temperature UT for velocity changes. Uncorrected hot readings can bias corrosion rates.

Regulatory overlay in the US and Canada

Hot hydrocarbon piping in refineries is almost always inside a process covered by OSHA PSM (29 CFR 1910.119). Under that rule, mechanical-integrity inspection must follow recognised and generally accepted good engineering practice, and API 570 and API RP 939-C are the usual references. EPA's Risk Management Program (40 CFR 68) applies a parallel mechanical-integrity duty. California refineries also follow the state's strengthened refinery process safety regulations, including damage mechanism reviews. In Canada, process piping falls under provincial pressure-equipment regulators such as ABSA in Alberta and TSSA in Ontario. Owner integrity-management programmes are expected to address damage mechanisms such as sulfidation. Confirm the requirements with your jurisdiction.

How Atlantis supports sulfidation inspection

Atlantis NDT performs the NDE behind a sulfidation programme on circuits the owner identifies. ASNT-certified technicians under ASNT Level III oversight carry out spot and high-temperature UT thickness surveys, UT corrosion mapping, profile radiography by crews licensed where the work is done, and guided-wave screening. Results are reported component by component, so every spool and fitting carries a located reading that the owner's API 570 inspector can trend. Atlantis does not set intervals, perform RBI, or make replacement decisions. Material composition testing for silicon is arranged by the owner through a qualified provider. See API 570 piping inspection support and our API 570 code requirements overview. Quotes on request. Request a 100 percent component inspection scope.

More questions on sulfidation corrosion

What temperature does sulfidation corrosion start?

API RP 939-C addresses hydrogen-free sulfur-containing streams from about 500 °F (260 °C) to about 1,000 °F (540 °C), with a threshold near 450 °F (230 °C) for hydrogen-containing services. Confirm the values in the current edition.

Why does low-silicon carbon steel corrode faster?

Carbon steel with less than 0.10 wt% silicon has been shown to sulfidize significantly faster than steel with higher silicon. A circuit that mixes component specifications can therefore contain a few fast-thinning parts.

What is 100 percent component inspection?

Inspecting every pipe and fitting component in an at-risk sulfidation circuit at least once, instead of relying on sample CMLs, to find the components that are thinning faster. The CSB recommended it after Chevron Richmond.

What are McConomy curves?

Industry correlations, published in modified form in API RP 939-C, that estimate sulfidation rates for different steels by temperature and sulfur content in hydrogen-free streams. Measured thickness data takes precedence over them.

Can thickness be measured on hot piping?

Yes, using high-temperature UT probes and couplants with velocity correction, or profile radiography. The procedure has to be qualified for the temperature.

Does upgrading to 5Cr or 9Cr stop sulfidation?

Chromium reduces the rate a lot but does not eliminate it. Upgraded circuits still need thickness monitoring.

Talk to a Level III about hot-line UT and profile RT or get a quote for component-by-component thickness surveys.