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What Is a Corrosion Inhibitor
A corrosion inhibitor is a chemical substance that, when added in small concentrations to an aggressive process environment, typically in the range of a few to a few tens of parts per million, retards the electrochemical corrosion of metallic equipment by adsorbing onto the metal surface and forming a continuous protective film, thereby blocking the direct contact between the steel substrate and corrosive media such as hydrogen chloride, hydrogen sulfide, organic acids and saline brine. In refinery overhead service, almost all commercial inhibitors belong to the filming organic family, typically imidazolines, fatty amines, amide-imidazolines, quaternary ammonium salts or carefully balanced blends of them; they do not alter the bulk chemistry of the hydrocarbon stream the way an acid neutralizer does, but rather lower the corrosion current at the metal-water interface where the electrochemical cell actually operates. Field performance is judged neither by laboratory weight-loss coupons alone nor by laboratory salt-spray ratings, but by two operational numbers that plant operators read every shift: the residual iron and chloride content in the sour overhead drain water, and the metal-loss rate measured by electrical-resistance or linear-polarization probes installed directly in the overhead vapor line, both of which must be driven down and held stable across weeks of continuous injection under changing crude slate and distillate draw rates.
The HCl-H2S-H2O Attack in Atmospheric Tower Overheads
The low-temperature, light-oil section of a crude distillation column is attacked by what refinery corrosion engineers conventionally call the HCl-H2S-H2O corrosion type, a system in which each of the three components amplifies the damage of the other two rather than acting independently. The hydrogen chloride enters the overhead as the volatile hydrolysis product of magnesium chloride and calcium chloride salts that survive even a well-operating electric desalting unit, and because HCl is the strongest acid in the overhead condensate it is the species that dominates the early dew-point attack; hydrogen sulfide, formed by thermal decomposition of organic sulfur in the crude, converts the soluble ferrous chloride film into a porous ferrous sulfide scale that cannot protect the steel; and the water phase, without which neither acid can dissociate into corrosive ions, appears first as microscopic droplets exactly at the thermodynamic dew point, that is, at the wall temperature where the first milligrams of water condense out of the vapor stream. The single most damaging observation recorded in decades of overhead monitoring is that roughly 50 percent of the free HCl present in the overhead vapor concentrates into only about 5 percent of the very first condensate, and essentially all of the HCl is found in the first 20 percent of condensed water, which means the initial-condensate acidity at the dew-point location can be as much as ten times higher than the acidity of the water collected downstream in the final condenser, and this is precisely why pitting and localized metal loss are almost always found at the first condensation point rather than at the cooler tail end of the condenser train.
The temperature ranges over which the principal corrosive species become active overlap rather than line up neatly, which is why no single injection strategy can be designed around only one of them: inorganic chlorides become corrosive between about 120 and 310 degrees Celsius, naphthenic acids attack between 230 and 420 degrees Celsius, and sulfur-containing species remain corrosive from 120 all the way up to 480 degrees Celsius. This overlap forces a careful compromise on pH. Hydrogen sulfide becomes more soluble in water as pH rises, so that when the overhead condensate is pushed into the alkaline range of pH 7.0 to 8.0 the additional dissolved sulfide is converted by injected ammonia into large quantities of ammonium bisulfide, which dissociates back into bisulfide ions and actually accelerates attack; yet the neutralization of HCl itself is more complete when the aqueous phase is pushed toward the alkaline side. Reconciling these two conflicting demands is what leads refinery engineering standards to specify an overhead condensate pH of 5.5 to 7.0 as the acceptable window, with a preferred operating target of 6.0 to 6.5, a range that simultaneously keeps HCl neutralization acceptably complete and prevents the bisulfide concentration from entering its most-corrosive regime.
多点的
| Corrosion regime | Dominant media | Temperature range | Typical locations | Main protection route |
|---|---|---|---|---|
| Low-temp light-oil | HCl, H2S, water | 120 - 250 C | Tower internals, overhead line, condensers, accumulator | Process chemistry (one removal, four injections) |
| High-temp heavy-oil | Elemental S, H2S, naphthenic acid | 250 - 480 C | Furnace radiant outlet, transfer line, bottom draw-off | Alloy metallurgy (5Cr / 9Cr / 316L) |
| Initial condensation zone | Concentrated HCl micro-droplets | At dew point (~100 - 140 C) | First condenser tubes, horizontal vapor line | Prompt neutralizer + filming inhibitor |
| Under-deposit corrosion | NH4Cl / amine salt + H2S | Salt deposition zone | Condenser tube bundle, downstream piping | Water wash + organic amine neutralizer |
Table 1. Principal corrosion regimes in a crude distillation overhead system and the protection route matched to each.
The One-Removal Four-Injection Process and Its Evolution
Since the 1960s, refineries worldwide have addressed overhead corrosion not with a single chemical but with a coordinated process-chemistry package that Chinese refiners call the one-removal four-injection scheme: one electrical desalting step upstream, plus four continuous injections of water, caustic, ammonia and corrosion inhibitor into the overhead. The desalting step removes brine and suspended salts at source; the water injection deliberately relocates the dew-point corrosion to a designed location in the horizontal overhead line, dilutes the initial HCl concentration, and sweeps ammonium salts out of the condenser tubes before they can deposit; the caustic injection converts hydrolyzable magnesium and calcium chlorides into comparatively stable sodium chloride before they can reach the column; the ammonia injection neutralizes the residual HCl and a portion of the H2S in the condensate; and the filming inhibitor lays down the organic barrier that the neutralizer itself cannot provide. Water injection is normally located on the horizontal segment of the overhead vapor line: Chinese practice most often places it downstream of the ammonia and inhibitor injection points, while many overseas refiners prefer to place it at the very front of the horizontal run so that the water reaches the first condenser tubes already mixed with the vapor. Typical injection rate is 7 to 16 percent of the overhead distillate, and the rate is tuned online using measured pH, iron and chloride in the sour water rather than fixed by commissioning design. Under-injection or poor distribution causes localized salt fouling, while over-injection shortens the oil-water residence time in the accumulator and destabilizes the interface; softened water is acceptable, but the most economical choice is recycled overhead sour water, which simultaneously recovers residual neutralizer and inhibitor, cuts fresh-water demand and reduces effluent volume.
Of the four injections, caustic has been progressively withdrawn because its side effects outweigh its benefits: it promotes coking in the furnace tubes, plugs exchanger tube bundles with sodium salts, causes caustic embrittlement of the injection nozzle, raises residue-fuel ash content, and most importantly carries sodium through to the fluid catalytic cracking unit, where sodium permanently poisons the Y-zeolite catalyst and increases catalyst makeup. Overhead caustic injection has the additional disadvantage, compared with ammonia, of generating tenacious salt deposits that create exactly the under-deposit corrosion the program was meant to prevent. Ammonia injection itself is now widely recognized as an imperfect neutralizer: ammonia boils at minus 33 degrees Celsius, so under atmospheric tower conditions (about 0.5 kg per square centimeter gauge, 100 to 140 C) injected ammonia is overwhelmingly 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, which means it barely neutralizes the HCl that is already condensing at the dew point. It is also difficult to dose precisely: a mere plus or minus five percent change in injection rate is enough to push the system out of the pH 6 to 7 window, swinging between acid attack and ammonium-bisulfide acceleration. The ammonium chloride formed by neutralization is insoluble in hydrocarbons and deposits on tubes, and in the presence of H2S it sustains a self-accelerating corrosion cycle in which NH4Cl hydrolyzes back to HCl, HCl dissolves iron to FeCl2, FeCl2 reacts with H2S to FeS and releases fresh HCl that attacks new metal. When copper-alloy condenser tubes are used, ammonia in the pH 7.0 to 8.5 range additionally forms soluble copper ammine complexes that corrode the tubes themselves. These limitations are the technical reason many overseas refineries have shifted from neat ammonia to mixed ammonia-organic-amine neutralizers, or to organic amines alone, paired with continuous corrosion monitoring.
Neutralizer | Typical liquid/gas partition at overhead conditions | pH control sensitivity | Salt deposition risk | Copper-alloy risk | Field protection level |
Ammonia (NH3) | About 1:10 (mostly vapor) | Very sensitive; +/-5% dose breaks pH window | High (NH4Cl deposits) | High at pH 7.0 - 8.5 | Baseline |
Organic amine | About 3:2 in favor of liquid | Stable; small dose shifts move pH little | Low; amine salts stay soluble | Low | 4 - 6x better than ammonia + inhibitor |
Mixed ammonia + organic amine | Intermediate | Intermediate | Moderate | Moderate | Good; lower chemical cost |
Table 2. Comparison of ammonia and organic amine neutralizers under real atmospheric-tower overhead conditions.
Optimizing Inhibitor Concentration and the Operating pH Window
Film-forming inhibitors are not dose-linear reagents, and running them by rule-of-thumb concentration is the most common reason plants see poor protection. Each formulation has a threshold concentration below which essentially no adsorbed film forms and the metal corrodes exactly as if no inhibitor were being injected at all, and an upper boundary beyond which excess surface-active molecules stop helping and begin to do harm by promoting oil-water emulsification, stabilizing crude emulsions, fouling product water separators and, in extreme cases, actually increasing metal dissolution. The correct working concentration is therefore not a supplier number but a plant-specific number found by stepping up injection gradually while watching the corrosion-probe metal-loss rate: the minimum injection rate at which the corrosion rate collapses to its plateau is the optimum, and field experience from operators such as Exxon places this optimum between roughly 6 and 12 parts per million on total overhead distillate for a well-formulated imidazoline-film product, with multi-functional neutralizing-film products such as combined organic-amine inhibitors typically injected at 10 to 20 ppm. Because the optimum also shifts with crude type, overhead vapor velocity, exchanger geometry and wash-water rate, the number must be re-established whenever the crude slate changes materially.
The pH window over which a film-forming inhibitor actually works is narrower than plant operators often assume. At low pH, H2S solubility is low and sulfide-driven corrosion is mild, but HCl attack itself becomes the dominant risk; as pH climbs, H2S dissolves more readily, and by pH 7.0 to 8.0 the ammonium bisulfide concentration peaks and the bisulfide-driven corrosion reaches its maximum. Laboratory comparison of several commercial inhibitors shows that when pH is held below 7.5 the inhibitor dosage can be trimmed as pH rises, but once pH exceeds about 7.5 most industrial filming inhibitors lose most of their efficiency, because a complete protective film can only build on a metal sulfide surface and the sulfide film itself tends to dissolve under alkaline conditions. The practical operating window therefore converges on pH 6.0 to 7.0, a micro-acidic band that suppresses both HCl and H2S corrosion and lets the inhibitor film establish itself cleanly; literature reports an effective envelope of roughly pH 4.5 to 8.0, below which economically unreasonable doses are needed and above which the film simply will not form. Solubility design follows directly from this picture: a purely oil-soluble inhibitor protects the hydrocarbon-washed wall but leaves the water film exposed, so modern overhead inhibitors are deliberately built with a balance of oil solubility and water dispersibility, and the global trend of merging neutralizer and inhibitor into a single injected neutralizing-film product is the direct engineering response.
Operating parameter | Recommended value | Source / basis | Action if off-spec |
Overhead condensate pH | 6.0 - 7.0 (target 6.0 - 6.5) | HCl neutralization vs H2S solubility balance | Adjust neutralizer dose; do not chase pH > 7.0 |
Wash-water rate | 7% - 16% of overhead distillate | Dilute HCl, dissolve NH4Cl, sweep salts | Raise if sour-water Fe rises; lower if accumulator interface unstable |
Film inhibitor dosage | 6 - 12 ppm (film-type); 10 - 20 ppm (neutralizing-film) | Exxon probe experience; DSF-2 type products | Step dose until probe rate plateaus |
Sour-water iron target | < 1 - 2 mg/L | General refinery practice | Increase inhibitor; check desalting and water quality |
Accumulator temperature | 40 - 50 C | Adequate oil-water separation | Adjust condenser cooling |
Table 3. Typical operating parameters used to tune overhead corrosion-inhibitor injection in real refinery service.
UNPChemicals CIMET Series Corrosion Inhibitors
UNPChemicals' CIMET series is a dedicated product line of high-performance refinery and oilfield corrosion inhibitors built around imidazoline chemistry blended with fatty-amine derivatives and quaternary ammonium surfactants, offered in oil-soluble, oil-soluble/water-dispersible and water-soluble grades so that a single chemical family can cover atmospheric overheads, vacuum distillation transfer lines, heat exchangers, downhole tubing and wet-gas pipelines; representative grades include CIMET TOI (tall-oil imidazoline), CIMET TOI-7 and CIMET TOI-9 (ethoxylated tall-oil imidazoline), CIMET TOI-A (oleic-acid imidazoline polyacrylate), CIMET TOH (tall-oil hydroxyethyl imidazolinium), CIMET TO (mixed tall-oil acid imidazolinium), CIMET O (oleic-acid imidazoline hydroxyethylated), CIMET 515, CIMET 18, CIMET 13, CIMET TA (fatty-amine ether) and PCMOT PE1650 (phosphate ester), with total active matter typically 50 to 100 percent, pour points from below minus 5 C down to minus 15 C, and inhibition profiles tuned specifically to CO2, H2S and high-temperature sulfidation in vacuum distillation service; for crude-overhead application the CIMET family is typically injected continuously at the original ammonia or neutralizer quill at rates in the 6 to 20 ppm range on overhead distillate, diluted 10 to 15 times with water and paired with overhead wash-water so that the imidazoline head anchors to the freshly formed ferrous-sulfide film and the fatty-amine tail delivers rapid surface coverage before the next dew-point droplet arrives.