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What Is a Corrosion Inhibitor
A corrosion inhibitor is a low-dosage chemical treatment that suppresses the electrochemical degradation of process metal by adsorbing onto, and thereby electrically insulating, the wetted steel surface from aggressive aqueous condensates; in refinery overhead service it is most commonly an organic surface-active molecule that carries a polar head group such as an imidazoline ring, a primary or secondary amine, an amide, a carboxylate or a phosphonate to anchor onto the negatively charged steel, paired with a long nonpolar hydrocarbon tail that extends outward to repel water film and dissolved acid gases from the wall. Unlike metallurgy upgrades, which solve corrosion by replacing the carbon steel itself, a corrosion inhibitor is applied continuously in the parts-per-million range through overhead injection quills or vacuum-top feed lines, and its true economic value is measured not in the laboratory flask but on the turnaround schedule: how many additional months of run length it adds between exchanger bundle pullings, how few tube leaks it allows, and how quickly the iron concentration in sour overhead water is driven below the 1 to 2 milligram per liter target that operators use as their day-to-day proof that the film is intact.
Where Corrosion Actually Occurs Inside the Distillation Train
Crude distillation corrosion separates cleanly into two physical families that demand completely different defenses. The first is low-temperature light-oil corrosion, which requires a water phase to exist at all and is driven by HCl, H2S and condensed water; it appears inside the upper trays of the atmospheric column, in the overhead vapor line, in the shell-and-tube condensers and in the overhead accumulator or reflux drum, and it is the family against which process chemistry, water washing, neutralizers and film-forming inhibitors are all aimed. The second family is high-temperature heavy-oil corrosion, which occurs above roughly 250 degrees Celsius in the absence of free water and is driven by elemental sulfur, hydrogen sulfide and naphthenic acids attacking carbon steel and low-alloy steel directly; its characteristic locations are the furnace radiant outlet, the furnace-to-column transfer line, the vacuum column bottom draw-off and the vacuum residue exchange train, and the only reliable defense there is metallurgy upgrade to 5Cr, 9Cr, 12Cr or 316L stainless steel, because a liquid-phase film cannot survive at those wall temperatures. Chemical inhibition therefore has no serious role in the high-temperature heavy-oil circuit, and specifying a film inhibitor for furnace tubes is a wasted expense; conversely, choosing stainless steel for the overhead condenser is usually also a wasted expense, because the HCl-H2S-H2O environment is cheaply and reliably controlled by good process chemistry.
Within the low-temperature family, the single most important micro-location is the initial condensation zone, the spot on the wall where water first appears as a continuous film rather than as molecular vapor. Field inspection programs consistently show that the most severe pitting and the highest local metal loss are not spread uniformly across the condenser bundle but are concentrated at this dew-point location, because the very first droplets carry essentially all of the HCl present in the overhead vapor and have not yet been diluted by the larger water volume that condenses further downstream. This is the engineering reason wash water is deliberately injected ahead of the first condenser: it moves the corrosive condensation event to a controllable and inspectable point, dilutes the initial acid, and sweeps away the ammonium chloride salts that would otherwise deposit just downstream of the neutralization reaction. It is also the reason neutralizer injection must reach the dew-point droplet rather than the bulk vapor, a requirement that ammonia fails and modern organic amines satisfy.
Equipment | Typical wall temperature | Dominant corrosive species | Failure mode observed | Primary protection |
Atmospheric column upper trays | 110 - 140 C | HCl, H2S, condensed water | Uniform thinning, pitting on downcomers | Neutralizer + overhead inhibitor |
Overhead vapor line | 100 - 160 C | HCl-rich initial condensate | Localized pitting at dew-point elbow | Wash water + neutralizing film inhibitor |
Overhead condenser tubes | 60 - 120 C | NH4Cl, NH4HS, HCl | Under-deposit pitting; copper ammine attack if Cu-alloy | Wash water; carbon-steel tubes preferred over copper |
Overhead accumulator / reflux drum | 40 - 50 C | Dissolved H2S, brine | Water-phase wall thinning | Continuous film inhibitor in sour water |
Furnace radiant outlet & transfer line | 350 - 480 C | Naphthenic acid, elemental S, H2S | High-temperature sulfidation; naphthenic acid attack | Alloy metallurgy (9Cr / 316L), not chemical inhibition |
Table 1. Corrosion distribution across a typical atmospheric-vacuum distillation train and the matched protection route.
Why Ammonia Is Being Replaced by Neutralizing Amines
Ammonia entered the refinery overhead package as the cheapest available neutralizer and it still works in the sense that it does neutralize HCl according to the simple stoichiometry NH3 plus HCl gives NH4Cl, and it also captures roughly 20 to 30 percent of the H2S to form ammonium bisulfide or ammonium sulfide, neither of which is itself corrosive at low concentration. The practical difficulty is that ammonia is an extraordinarily volatile molecule whose boiling point is minus 33 degrees Celsius at atmospheric pressure, so at the 100 to 140 C, roughly 0.5 kg per square centimeter gauge conditions of an atmospheric overhead it exists almost entirely in the vapor phase, with only about 0.98 percent dissolved in the water phase at 0.6 kg per square centimeter and 105 C; the neutralizing fraction that actually reaches the HCl-rich initial condensate is therefore on the order of one tenth or less of what a plant operator thinks he has injected. Compounding this, ammonia is extremely easy to over- or under-dose: comparison tests between ammonia and organic amines show that when pH 6.5 is the target, a plus or minus five percent change in ammonia injection rate is enough to swing the system outside the pH 6 to 7 operating band, whereas the same relative change in an organic amine shifts pH by only a small fraction of a unit, so operators using ammonia are permanently fighting the controller rather than stabilizing the film.
Organic amines solve the vapor-liquid distribution problem structurally. Their dew point is far closer to that of HCl, which means they condense together with the acid droplets rather than floating above them in the vapor; their liquid-phase to vapor-phase partition ratio is on the order of 3 to 2, compared with ammonia's 1 to 10, so they deliver a stable, predictable pH to the very first droplets that need neutralization. The amine salts they form with HCl are also soluble in the process water and do not crystallize on condenser tubes the way ammonium chloride does, which removes the under-deposit corrosion cycle that has long been the quiet failure mode of ammonia-based overhead systems. Field experience with multi-component organic-amine neutralizing-film products, such as the DSF-2 class of combined neutralizer-inhibitors built on blended organic amines with a high-performance filming component, reports four to six times the protection level of the older ammonia-plus-inhibitor arrangement, and because one injected product simultaneously neutralizes HCl, disperses salts and lays down a covalent and coordinate bonded multi-layer film on the steel, it removes the separate ammonia injection point entirely and cuts the number of chemicals operators must manage. The recommended field treatment is to dilute the product 10 to 15 times with water and inject it through the former ammonia quill into the overhead vapor line, hold the overhead condensate at pH 6.0 to 7.0, and keep a wash-water stream running at the same injection point so that the neutralizer never has to work against concentrated salt deposition.
Characteristic | Ammonia | Organic neutralizing amine |
Boiling point | minus 33 C (very volatile) | High; condenses with HCl droplets |
Typical liquid/vapor partition at 100 - 140 C | About 1:10 (mostly vapor) | About 3:2 (mostly liquid) |
pH stability to dose changes | Poor; +/-5% rate breaks pH 6 - 7 window | Good; same dose shift barely moves pH |
Neutralization of initial HCl condensate | Weak; most ammonia is upstream in vapor | Strong; amine condenses with HCl |
Salt formed | NH4Cl, crystallizes and deposits | Amine salt, water-soluble, no deposition |
Copper-alloy condenser attack | Forms soluble ammine complexes at pH 7.0 - 8.5 | Minimal |
Field protection level | Baseline | 4 - 6 times that of ammonia + separate inhibitor |
Table 2. Engineering comparison of ammonia and organic neutralizing amines for atmospheric overhead service.
Field Dosage, pH Window and Common Troubleshooting Cases
Once a film-forming or neutralizing-film inhibitor is on injection, the day-to-day control parameters are few but they must be read every shift. The product is typically diluted 10 to 15 times with water and injected at the original ammonia injection point on the overhead vapor line, or alternatively through the reflux line if the protection target is the top trays rather than the condenser; continuous overhead wash water should be running at the same time, and the target overhead condensate pH is held at 6.0 to 7.0 with the preferred band at 6.0 to 6.5. Injection rate is calculated on total overhead distillate and typically lands at 10 to 20 parts per million for a combined neutralizing-film product, or 6 to 12 parts per million for a pure film-type inhibitor such as the imidazoline grades, with the exact number refined against corrosion-probe metal-loss and sour-water iron readings rather than against the supplier's nominal range. Under-injection shows up as rising sour-water iron and rising probe corrosion rate within days; over-injection shows up first as an oil carryover problem in the sour water, because the same surface-active molecule that protects the wall will also stabilize a crude-water emulsion if it is allowed to accumulate in the accumulator.
Three field complaints repeat themselves so often that they deserve explicit diagnosis. First, when reflux-circulation water is used as the overhead wash water and the pH will not climb even with more neutralizer, the usual cause is that the reflux-drum water has become a buffered ammonium-ammonia or organic-amine system that refuses to move; the remedy is to drain the reflux drum completely and switch to fresh or softened water for a short wash. Second, when the accumulator sour water carries excessive oil, three root causes are typically checked in order: overhead emulsification caused by pH drifting too high or inhibitor overdose, an excessively low oil-water interface level that leaves insufficient residence time for settling, or an accumulator temperature that is too low to allow clean separation; the corresponding fixes are to lower wash-water pH or trim inhibitor dose, raise the interface level to lengthen settling time, and adjust condenser duty so that the oil-water temperature is held at 40 to 50 degrees Celsius. Third, when a previously stable pH suddenly will not hold, the operator should first check whether the wash-water source itself changed quality, typically a drop in inlet water pH, and second whether the crude slate changed, either by an increase in crude total acid number or a rise in salt content after desalting; the correct response is to raise wash-water pH, increase inhibitor or neutralizer rate, possibly run a small ammonia trim on top of the organic amine, and above all return the desalting unit to design performance, because no amount of overhead injection can compensate for a poorly performing desalter upstream.
Field symptom | Likely root cause | Recommended action |
pH cannot be raised when reflux water is used as wash water | Reflux-drum water has formed a buffer solution | Drain the reflux drum fully; inject fresh water during the correction period |
Excess oil in sour water from accumulator | Emulsion from high pH or inhibitor overdose; low interface level; low accumulator temperature | Lower wash-water pH or reduce inhibitor dose; raise oil-water interface; cool to 40 - 50 C |
Previously stable pH suddenly drops | Wash-water source pH fell; crude TAN or desalted salt content rose | Raise wash-water pH or increase inhibitor dose; improve desalting; trim ammonia if required |
Sour-water iron rising above 2 mg/L | Inhibitor film broken, dose too low, or crude slate shifted | Step inhibitor dose up until probe rate plateaus; re-check desalting efficiency |
Condenser tube pressure drop rising | NH4Cl or amine-salt deposition; wash-water rate too low | Increase wash-water rate; confirm distribution; consider organic amine switch |
Table 3. Common overhead-inhibitor operating problems, likely causes and field remedies.
UNPChemicals CIMET Series Corrosion Inhibitors
UNPChemicals' CIMET series is a purpose-built family of refinery and oilfield corrosion inhibitors whose chemistry centers on imidazoline compounds for durable film formation blended with fatty-amine derivatives for rapid initial surface coverage, with grades available as oil-soluble, oil-soluble/water-dispersible and water-soluble products so that the same product platform can be specified for atmospheric overheads, vacuum distillation transfer lines, heat exchangers, vacuum column internals, downhole tubing and wet-gas pipelines; the range covers CIMET 515 (oligomeric ester), CIMET 18 and CIMET 13 (proprietary surfactant blends for hydrochloric-acid and sulfuric-acid service), CIMET TOI, CIMET TOI-7 and CIMET TOI-9 (tall-oil imidazoline with 0, 7 or 9 ethylene oxide units), CIMET TOI-A (oleic-acid imidazoline polyacrylate), CIMET O (oleic-acid imidazoline hydroxyethylated), CIMET TOH (tall-oil hydroxyethyl imidazolinium), CIMET TO (mixed tall-oil acid imidazolinium), CIMET TA (fatty-amine ether) and PCMOT PE1650 (phosphate ester), with total active matter typically between 50 and 100 percent, pour points from below minus 5 C to minus 15 C, and inhibition profiles specified against CO2, H2S and high-temperature sulfidation; for crude-overhead application, UNPChemicals recommends continuous injection of the selected CIMET grade through the existing neutralizer quill at a rate of approximately 6 to 20 parts per million on overhead distillate, tuned against electrical-resistance probe readings and sour-water iron, and paired with overhead wash water so that the imidazoline adsorption film can rebuild itself on every freshly wetted wall under the micro-acidic pH 6.0 to 7.0 window that this class of chemistry is designed for.