These tools are screening estimators only. Corrosion coupons, probes, thickness surveys, and lab testing almost always beat tabulated rates for real equipment. Use calculated values only when good measurements are missing or for early screening.
This page uses SI inputs and outputs (°C, kPa, m/s, mm/yr, etc.); USC table data are converted internally where needed. It implements digitized hydrochloric-acid tables and the carbon dioxide (CO₂) model as per (NORSOK M-506–based methodology). Verify against your standard/ report advice. Not a substitute for qualified corrosion / RBI judgment.
Mechanism descriptions on each tab are short technical summaries meant to reflect widely used industry understanding; they are not copied verbatim from any single publisher.
Rate calculators
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
Aqueous hydrochloric acid keeps most steels actively dissolving, so wastage is usually general unless condensation, crevices, or deposits steer the attack. Chloride activity and pH set severity; aeration and galvanic contact with nobler copper alloys can locally accelerate loss beyond a table midpoint.
Crude overheads (salt hydrolysis), hydrotreater effluents (organic chloride breakdown or carry-in), and reformer regeneration paths are common homes for dilute HCl. Shock condensation and ammonium/amine salt plating still drive many failures even when bulk chemistry looks mild.
This block is aimed at dilute acid screening. Pick the material family (carbon steel, 300-series, high alloys, B-2, or Alloy 400), temperature, and either pH or chloride when the bundled chloride–pH shortcut applies (no alkaline neutralizer assumed in that path).
The digitized grids interpolate inside published knots and clamp beyond the edges. Austenitics can pit or crevice corrode and may see chloride SCC—this tool does not replace alloy selection review. Nickel alloys accelerate if oxidizers appear or heat treatment drifts from solution annealed. Anchor any sustained rate with probes, UT, or coupons on matching duty. Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
Dissolved CO₂ acidifies condensed water on steel, producing largely uniform or flow-sensitive loss that tracks temperature, CO₂ fugacity, wall shear, and mitigation such as glycol films or inhibitors. The implementation keeps NORSOK M-506–style structure while you work in °C and kPa; Fahrenheit and psi remain inside the correlation kernel.
Combined rate: CR = CRB · min(Fglycol, Finhib). CRB (mm/yr) is the base corrosion rate, using f(T, pH) (temperature–pH function; step change ~80–90 °C), CO2 fugacity, and shear S, capped at 150 Pa. Optional screening (material, free water / dew point, liquid-HC velocity). Enter °C and kPa (abs.); pH correlations use °F and psi internally from converted T and pCO2. Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
Above roughly 200 °C, sulfur in the hydrocarbon phase can sustain steady metal loss on carbon and low-alloy steels. The attack is usually fairly uniform compared with pitting mechanisms. The same units often see naphthenic-acid-related damage depending on crude slate; where naphthenic acids matter, morphology tends toward localized grooves or pitting rather than a single flat wastage rate.
Crudes differ widely in which sulfur species dominate: some fractions are aggressive as-fed, while others become more aggressive only after heat breaks larger molecules down toward H2S. In hydrotreaters, sulfur can be driven toward H2S in the presence of hydrogen and catalyst; estimating that environment belongs with the dedicated H2S/H2 tool on this page, not this sulfidic/NAC grid.
Cyclic carboxylic acids (“naphthenic” acids) ride with many crudes and partition into heavier cuts during distillation—gas oils, resids, and vacuum streams are typical concentrators, while light naphthas are usually lean. Attack can be pit-like when acid levels are modest, or more directional (grooving) when acid load and velocity are high. Those acids can strip or prevent stable sulfide films, so sulfidation and NAC can reinforce each other rather than behaving like two isolated models.
Key levers include alloy, temperature, bulk sulfur reported as wt %, and (for NAC) the acid number of the liquid hydrocarbon in the actual piece of equipment, plus velocity where flow can sweep films. In brief:
Tabulated sulfidation curves are a coarse fit to real units: silicon in carbon steel, flow regime, and how “total sulfur” maps to reactive species all move observed rates away from the grid. Fresh surfaces after turnaround often read “hot” until scales mature; those scales are weak and can be torn off by acid or shear, resetting the cycle.
Velocities beyond about 30 m/s are associated with scale stripping and sharply higher loss. Stagnant or stratified pockets can instead concentrate acid or sulfur species locally. Silicon well below ~0.10 % in carbon steel has been linked to faster sulfidation surprises in otherwise similar circuits.
Atmospheric/vacuum crude, hydrotreater feeds, FCC, and coker circuits are common homes for these mechanisms; naphthenic acid is rarely the lead story downstream of hydrogen addition in hydrotreaters, while thermal units may destroy naphthenic acids unless unconverted feed carries through. Extract and lube trains can see acid concentration effects.
Match the fields below to the actual component and operating window. If numbers are uncertain, get alignment from process engineering.
The calculator reads a material-specific grid versus sulfur, TAN band, and temperature. Where naphthenic acid is absent, bias to the lowest TAN band for that alloy family. Naphthenic-acid-dominated cases remain order-of-magnitude estimates—update with UT, probes, or inspection feedback whenever possible.
If the stream velocity exceeds 100 ft/s (30.48 m/s), multiply the tabulated result by 5 to reflect enhanced film removal.
Implemented for carbon steel (legacy mpy mesh converted internally) and Type 316 / 317 bands (mm/yr mesh). Interpolation spans sulfur, TAN, and temperature (USC axis internally). High-velocity multiplier ×5 when V > 30.48 m/s. Other alloys need their own grids. Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
In hydroprocessing, sulfur can be converted to H2S in hydrogen-rich reactor effluent and related vapor streams. That chemistry usually needs a catalyst; without it, H2S may stay modest even at high temperature. Once H2S is present with hydrogen, carbon and low-alloy steels can see accelerated high-temperature wastage that is mostly uniform in appearance. This pathway is distinct from crude-unit sulfidation/NAC discussed in the other tab: here the driver is H2S in the process vapor phase after catalytic conversion, not the same crude-cut sulfur tables.
Chromium buys only incremental relief until roughly 12 % Cr, where rates drop more sharply; higher Cr and Ni continue to help. Hydrocarbon liquid often moderates attack versus an all-vapor H2S/H2 mix, but screening curves are still applied to both situations, with the understanding that predictions climb steeply at high temperature and high H2S.
Align inputs with the stream you are rating; ask process support when lab data are thin.
Pick alloy family, stream class, temperature, and H2S, then interpolate inside the digitized mesh. Tie results back to probes, UT, or reactor effluent analyses when you have them.
Carbon steel / low Cr–Mo mesh (Couper–Gorman family) with interpolation on H2S, temperature, and naphtha vs gas oil; out-of-range inputs clamp. Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
Sulfuric acid is ubiquitous in refining and chemicals—alkylation acid, drying trains, and acid shipping, among others. Severity swings with concentration, temperature, halides, and oxidizers. Velocity changes whether protective sulfate films stay put or are continually washed away.
Carbon steel is still common for strong, cool acid because an iron sulfate layer can throttle attack once it accumulates—until turbulence pulls it off. Above roughly 0.9 m/s, mass-transfer-controlled models show much higher loss, and fittings multiply effective attack compared with straight pipe runs. Published “upper bound” curves may overshoot what well-managed circuits experience.
Stainless and nickel alloys lean on passive films; oxidants often help unless the alloy is sensitive to them (notably some nickel alloys such as B-2). The embedded tables assume de-aerated acid unless a specific tool branch asks about air/oxidizers.
Each alloy subsection below has its own mesh; gather consistent stream data before picking a grid.
B-2 and oxidizers: Small oxidizer traces can explode the rate—get specialist input instead of a blind table lookup.
Choose the alloy block, interpolate within its concentration–temperature–velocity box, clamp beyond the edges if your procedure allows, and reconcile with inspection history. Verify with your licensed Engineer.
Digitized H2SO4 / carbon steel grid (mm/yr): trilinear interpolation in wt %, °C, and m/s. Values beyond the table clamp to the nearest edge. Low vs higher velocity tracks the underlying table bands (~0.91 m/s split per methodology); non-aerated acid. Verify with your licensed Engineer.
Lookup grid (H₂SO₄, Type 304 SS, mm/yr): trilinear interpolation in wt %, °C, and m/s. Values beyond the table are clamped to the nearest edge. Some reference prints show a typo at 75 % / 40 °C / 2.13 m/s; this tool uses 25.37 mm/yr there to match surrounding cells. Verify with your licensed Engineer.
Lookup grid (H₂SO₄, Type 316 SS, mm/yr): same axes as reference table—trilinear interpolation; inputs clamped to table edges. Verify with your licensed Engineer.
Lookup grid (H₂SO₄, Alloy 20, mm/yr): temperatures 38 / 52 / 70 / 91 °C; velocities 0.91 / 2.59 / 3.05 m/s; concentrations 5–98 wt %. Trilinear interpolation; values beyond the table clamp to the nearest edge. Verify with your licensed Engineer.
Lookup grid (H₂SO₄, Alloy C-276, mm/yr): temperatures 52 / 59 / 73 / 86 °C; velocities 0.91 / 2.59 / 3.05 m/s; concentrations 5–98 wt %. Trilinear interpolation; values beyond the table clamp to the nearest edge. Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
HF alkylation relies on concentrated HF as the catalyst. The acid is acutely toxic by liquid and vapor routes, and releases can form dense, low-lying clouds—treat handling as a major process safety topic, not just a corrosion topic.
Metal loss tracks HF-in-water concentration and temperature first, but velocity, aeration, and contaminants can dominate locally. Many alloys grow a fluoride surface layer; if flow or turbulence strips it, rates jump. Roughly ≥80 % HF-in-water is often grouped with anhydrous HF behavior; weaker acid is more sensitive to temperature and velocity swings.
Typical alkylation acid strengths (~96–99+ %) and moderate temperatures favor carbon steel for bulk equipment, while tight-clearance machines and warmer zones may move to Alloy 400. Water trapped in low points after poor dry-out can dilute acid and trigger aggressive pockets.
The two calculators cover carbon steel (HF %, T, velocity split) and Alloy 400 (HF %, T, aeration). Other alloys need lab or vendor data.
Early life can read very high until a fluoride scale steadies; disturbance restarts the cycle. Plain carbon steel often outperforms many alloy steels in HF; dissimilar welds can galvanically accelerate the less noble member. Residual Cu–Ni–Cr in some CS heats has been tied to faster HF attack. General thinning is typical unless galvanic or hydrogen-related modes appear—evaluate hydrogen damage under your site program. Interpolate inside tabulated knots; clamp outside if allowed. Verify with your licensed Engineer.
Lookup grid (HF, carbon steel, mm/yr). Strong dependence on HF-in-water concentration and temperature; velocity < vs > 1.524 m/s selects separate rows. First temperature band 21.1–37.78 °C uses midpoint 29.44 °C when interpolating to the next knot. ≥80 % HF-in-water is handled like the high-concentration / AHF column in the methodology. Alloy 400 calculator follows below. Verify with your licensed Engineer.
Lookup grid (HF, Alloy 400, mm/yr). Alloy 400 uses temperature, HF-in-water concentration, and aerated vs non-aerated (not velocity). Oxidizers can greatly accelerate Alloy 400 attack; use aerated when air/oxidizers may be present. Interpolation between tabulated concentrations and temperatures; inputs beyond the table clamp to the nearest edge. Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
Sour-water strippers and linked equipment juggle ammonia, hydrogen sulfide, and sometimes cyanides. Ammonium bisulfide can plate where the chemistry cools or concentrates. The embedded method expects you to judge whether H2S partial pressure or NH4HS deposition is controlling, then apply the baseline adjustments encoded in the calculator.
Baseline CR (mm/yr) follows the H2S partial-pressure path bundled with the reference tables. In two-phase flow, use vapor velocity when vapor is continuous and liquid velocity when the line is liquid-full. pH₂S = mole % H2S × total absolute pressure. When speciation is missing, rough weight-percent shortcuts estimate NH4HS: if wt % H2S < 2×(wt % NH3), take NH4HS ≈ 1.5×(wt % H2S); if wt % H2S > 2×(wt % NH3), use NH4HS ≈ 3.0×(wt % NH3). Prefer ionic modeling or lab data when the decision matters. Verify against your licensed corrosion engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
Amine sweetening exposes carbon steel to lean/rich chemistry, heat-stable salts (HSAS), and velocity-driven film removal. Rates hinge on amine type and strength, HSAS, temperature, and loading-dependent velocity bands. This sheet digitizes the carbon-steel mesh for MDEA up to about 50 wt %, and for MEA/DEA with HSAS (2–4 wt %) on the same reference axes used elsewhere on the page. For acid-gas loading < 0.1 mol/mol versus liquid feed, split velocity at ≤6.1 vs >6.1 m/s; at ≥ 0.1 mol/mol, split at ≤1.5 vs >1.5 m/s. Interpolate across loading (0.1–0.7 mol/mol), HSAS, and 88–132 °C, then apply the amine-strength multiplier from the table. Enter MDEA HSAS as wt % organic acid salts in the lean-amine sense modeled by the table. Stainless metallurgies are not implemented here. Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
Thick, growing oxide scales dominate once steel temperatures enter furnace ranges. The first mesh spans roughly 496–802 °C; the hotter extension covers about 829–1135 °C (mm/yr per the embedded tables). Between 802 and 829 °C the tool linearly bridges the two sources. Below 496 °C it holds the first column; above 1135 °C it holds the last column; em-dash cells mean that combination is not applicable. Screening for carbon steel often starts near 482 °C, with higher thresholds for more oxidation-resistant alloys. Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
This block sits between mineral-acid-dominated conditions (use the hydrochloric acid calculator) and ammonia-rich strippers (use alkaline sour water). It assumes hydrogen sulfide is the main driver, with ammonia, CO2, and cyanide small enough not to take over, and dissolved oxygen near typical ≤50 ppb operation.
CR = CRpH·Fo·FV. CRpH and Fo come from the reference tables. FV is 1.0 when v < 1.83 m/s, ramps linearly from 1.0 at 1.83 m/s to 0.5 at 6.10 m/s, and stays 0.5 when v > 6.10 m/s (SI counterpart to the familiar 6–20 ft/s band). Switch to the hydrochloric acid tool when pH < 4.5 or chlorides matter, and to alkaline sour water when pH > 7. Other alloys judged suitable for the service are often screened near ≤2 mpy (~0.051 mm/yr). Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
CR = CRB·FT·FV. Untreated fresh water (recirculating or once-through, <1000 ppm Cl−) pulls CRB from the embedded table: for RSI > 6, split on velocity above vs at/below 2.4 m/s; for RSI ≤ 6 (more scale-forming), the tool uses the legacy mild-scale column converted to mm/yr—cross-check against your licensed table copy. FT and FV come from their respective tables. RSI = 2·pHs − pHa; optional pHs uses pHs = 9.3 + C2 + C3 − C1 − C4 from the same coefficient table your standard references. Seawater uses its own CRB mesh for 0–6.1 m/s. Non–carbon steel in the figure is capped at 0.5 mpy (~0.013 mm/yr). Chemical treatment programs, MIC, and coupon programs are not modeled explicitly. Verify with your licensed Engineer.
Qualitative corrosivity bands describe broad steel loss ranges compared with coupon experience; they do not define total dissolved solids (TKS) limits by themselves. The mapper below converts bands to mm/yr using 1 mpy = 0.0254 mm/yr. Optional TKS pathways apply illustrative mg/L breakpoints for screening—tune them to local hydrogeology and specialist guidance before relying on them for decisions.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
CR = CRB·FSR·FT·FCP·FCE for buried carbon steel (aboveground tank bottoms use the AST tab). CRB is the soil-category baseline; FSR scales bulk resistivity; FT tracks operating temperature; FCP reflects cathodic protection per NACE SP0169; FCE captures coating type, age, and maintenance (1.0 if bare). Factors are taken from the digitized source tables—pair them with CP surveys, excavations, and coupons whenever possible. Verify with your licensed Engineer.
Screening estimator only. Corrosion coupons, fixed or retractable electrical probes, repeated thickness measurements (for example UT), and laboratory exposure tests usually give more reliable rates than these tabulated estimates. Prefer measured data when setting rates for integrity decisions.
Tank bottoms corrode from product-side water chemistry and from soil, pads, drainage, and cathodic protection on the outside. CRS is the soil-side rate built from CRSB with factors FSR (resistivity), FPA (pad), FTD (drainage), FCP (CP), FTB (bottom type), and FST (soil-side temperature). CRP is the product-side rate from CRPB with FPC (product condition), FPT (temperature), FSC (steam coil), and FWD (water draw). When no inspection history exists, the sheet falls back to about 5 mpy soil-side base and 2 mpy product-side base as placeholders, not calibrations. Combine as sum when both sides erode broadly, or max when one side is clearly localized or pitting—match the convention your RBI basis document requires. The reported combined rate is not reduced below 2 mpy (0.0508 mm/yr). Verify with your licensed Engineer.