Return condensate is nearly pure and worth millions—until a single ppm of CO₂ drops its pH to ~5.5 and eats pipelines. Refineries are turning to neutralizing and filming amines to defend their steam loops and their balance sheets.
Refinery steam systems recover a big slice of their energy through condensate return—often around 50% of steam recovered (oilinwatermonitors.com). Operators call this nearly pure return “liquid gold.” But dissolved CO₂ from feedwater bicarbonates transforms to carbonic acid in condensate, and just 1 ppm CO₂ can crash pH from neutral 7 to ~5.5 (openchemicalengineeringjournal.com).
At that acidity, ferrous steel corrodes fast: Fe + 2H₂CO₃ → Fe(HCO₃)₂ + H₂ (watertechnologyreport.wordpress.com). The ferrous bicarbonate then precipitates as iron carbonate that is soft and brittle; flow strips it away, exposing fresh metal so attack continues (inspectioneering.com). The field signature is deep channeling or “grooving” along the bottom of condensate lines and elbows (watertechnologyreport.wordpress.com).
Oxygen makes it worse. Even trace dissolved O₂ intensifies carbonic acid attack (“worming”), creating iron oxides and yet more CO₂ (watertechnologyreport.wordpress.com; watertechonline.com). Left unchecked, ppm-level iron oxide particulates foul steam traps and boiler tubes and trigger leaks (watertechonline.com). A global survey estimates optimizing steam/condensate loops can save more than 5% of annual steam energy cost and up to 50% of boiler make‑up water—translating to several million dollars per year in typical refineries (researchgate.net).
Condensate carbonic acid corrosion
Carbonic acid forms when CO₂ dissolves in condensate (condensed steam). The resulting acidity accelerates iron dissolution and produces corrosion products that do not passivate. Rapid flow or turbulence strips weak iron carbonate layers, so corrosion continues at active sites (inspectioneering.com). When O₂ sneaks in, carbonic attack intensifies and more CO₂ is generated, creating a feedback loop (watertechnologyreport.wordpress.com).
Neutralizing amines: pH control and distribution
Neutralizing (volatile) amines—tertiary or secondary amines such as morpholine, cyclohexylamine (CHA), and diethylaminoethanol (DEAE)—neutralize carbonic acid by raising condensate pH. One mole of amine neutralizes roughly one mole of carbonic acid, so feed is set stoichiometrically to the CO₂ load; operators target about pH 8.5–9.2 (for mixed copper/iron systems often 8.8–9.2) (watertechnologies.com; watertechnologyreport.wordpress.com). Lower molecular weight generally means greater neutralizing capacity per unit dose: DEAE ~2.6 ppm amine per ppm CO₂ versus morpholine ~2.0 (watertechnologies.com). Distribution also matters: high‑vapor‑pressure “long‑run” amines like CHA travel far downsteam, while lower‑distribution amines concentrate in receivers; blends (e.g., 50:50 CHA/DEAE) are common to protect both long runs and feedwater zones.
In practice, plants start with an initial dose estimated from make‑up alkalinity (for example, around 1 kg amine per 0.5–2 kg/h CO₂) and tune to condensate pH. Adding a neutralizing amine can dramatically cut corrosion products: power‑sector experience, including U.S. Navy and NRC/NIST‑referenced work, shows switching from ammonia‑only to organic amine blends restores condensate pH near ~9.0 and drives iron concentrations well below ppm levels (ccj-online.com).
Limits apply. Neutralizers only consume carbonic acid; they do not handle oxygen or other impurities (watertechnologyreport.wordpress.com). Overdosing is wasteful because volatiles are not recovered in boilers, so operators monitor and adjust routinely. For regulated steam use, U.S. FDA caps cyclohexylamine and morpholine at ≤10 ppm, DEAE at ≤15 ppm, and octadecylamine (an example filming amine) at ≤3 ppm (casetext.com). OSHA PELs and CFR 21–173 rules similarly cap exposures and doses.
Accurate chemical feed is essential; many refineries pair amines with a dedicated dosing pump to maintain target pH windows under load swings.
Filming amines: hydrophobic barrier formation
Filming (film‑forming) amines—often long‑chain C₁₆–C₂₂ primary amines like octadecylamine (ODA) or newer ethoxylated amines such as ethoxylated soya amine (ESA)—deposit a thin hydrophobic monolayer on steel that blocks both acids and oxygen (handbook.ashrae.org; chemaqua.com). The polar amine “head” chemisorbs to metal; the nonpolar “tail” repels water. Typical feed is low ppm—about 0.5–10 ppm into steam headers or condensate collectors—to cover all return surfaces (handbook.ashrae.org).
These products often sit within a broader corrosion inhibitor program and are frequently paired with neutralizers. Industry guidance recommends starting low and increasing slowly to avoid sloughing deposits; film presence is verified by water‑beading on coupons or spool pieces (chemaqua.com; chemaqua.com). Because heavy oils and waxes can strip films, continuous injection is advised (handbook.ashrae.org). Performance is gauged via corrosion coupon weight loss and particle counts, rather than pH (watertechnologyreport.wordpress.com).
Field data are compelling. In one combined‑cycle unit, neutralizing amine addition brought pH control and pushed iron below ppm levels; adding a filming amine cut corrosion rates further (ccj-online.com). A Dutch refinery study reported 5–15 ppm of C18 amine virtually eliminated pitting in return lines, with corrosion coupons falling to <0.01 mm/year versus ~0.1–0.2 mm/year untreated. ASHRAE notes that combining a neutralizer with a filming amine “is a successful alternative to protect against both acid and oxygen attack” (handbook.ashrae.org).
Program design: dosing, monitoring, and targets
Best practice starts with maximizing bone‑dry condensate recovery (via engineered steam traps, flash tanks), then feeding neutralizers downstream of deaerators to hold pH near 8.5–9.0. In parallel, a filming amine is dosed at a steam header or condensate receiver to blanket return piping. Oxygen is removed in boiler feedwater using scavengers so returned condensate is essentially oxygen‑free (handbook.ashrae.org).
Refineries often pair their feedwater program with an oxygen scavenger to minimize dissolved O₂ before condensate returns. For return‑side clarity after heat exchange cooling, some sites add a condensate polisher to capture fines while the amine program reduces corrosion at the source.
Monitoring is multi‑parameter: condensate pH above ~8.5; dissolved/total iron and copper held to sub‑ppb to a few ppb (watertechnologyreport.wordpress.com); and corrosion coupons well under 0.1 mm/year. In petrochemical/refinery service, total organic carbon (TOC) is tracked to catch hydrocarbons. One utility warns condensate iron can reach “part‑per‑million” levels if CO₂ and O₂ go uncontrolled (watertechonline.com), so programs aim to hold iron well below that—often <0.1 ppm typical. Infrared cameras and hydrocarbon monitors help spot leaks early.
Upgrades pay back fast. A plant moving from ammonia‑only to ammonia + neutralizing amine cut corrosion coupon rates by ~30%; adding a low‑dose film (about ~1 ppm ODA) delivered another ~50% reduction, with fewer line leaks and less iron oxide deposition (ccj-online.com).
Hydrocarbon contamination: oil management in condensate
Refinery condensate is prone to hydrocarbon ingress—from light distillates to lube oil. Even trace oil complicates amine performance by forming emulsions and competing films, and by promoting under‑deposit corrosion. Plants deploy online monitors and, at times, crude‑oil coalescers to detect and triage leaks (oilinwatermonitors.com).
Treatment programs respond in stages: mechanical oil/water separation ahead of condensate treatment, demulsification where needed, and amine selection tuned for organic tolerance. Facilities handling free oil often integrate an oil removal unit upstream of polishing. Where emulsions are persistent, a refinery‑grade demulsifier is dosed to break them and stabilize downstream chemistry. Filming amines, being hydrophobic, can concentrate at metal/water interfaces and sometimes displace thin hydrocarbon layers; very heavy contamination, however, typically demands removal by gravity separation or polishing filters alongside chemical protection.
Regulatory and safety parameters
For food‑contact steam (e.g., sterilization), U.S. FDA limits morpholine and cyclohexylamine to ≤10 ppm, DEAE to ≤15 ppm, and octadecylamine to ≤3 ppm (casetext.com). While many refinery services are not in direct food contact, these thresholds signal caution; OSHA/ACGIH exposure limits also apply. In Indonesia, operators follow general boiler standards and environmental rules; any amine discharge to drain must meet effluent guidelines, though specific amine limits are not codified.
Key performance and savings data
With a tuned amine program, condensate pH stabilizes above ~8.5—often 8.8–9.2 in mixed Cu/Fe systems—and corrosion coupon losses fall toward ~0.01 mm/year or lower, versus ~0.1–1 mm/year untreated (watertechnologies.com). Iron in return condensate drops from hundreds of µg/L (untreated) toward near‑zero when neutralizing and filming amines work together (watertechnologyreport.wordpress.com). Improving condensate recovery—from, say, 40% to 80%—can halve boiler make‑up demand and save several million dollars annually in a 150 kbpd refinery (researchgate.net).
References and practitioner guides
Authoritative guides such as Veolia/WTR’s water handbook (watertechnologies.com) and ASHRAE (handbook.ashrae.org), industry case studies (ccj-online.com; watertechonline.com), and regulatory codes (casetext.com) underpin the data cited above. For physical plant upgrades that support chemistry, refineries also deploy targeted equipment such as primary oil/water separation systems to reduce hydrocarbon carryover before condensate returns to the steam cycle.
