In heat recovery steam generators (HRSGs), a few degrees can separate normal service from ruptured economizer tubes. The fix is deceptively simple: hold feedwater and metal temperatures above the flue gas’s acid dew point—and pick tube materials that can take a hit when operations drift.
Cold-end corrosion in an HRSG (a heat recovery steam generator that harvests waste heat from gas turbine exhaust to make steam) is a classic condensation problem: sulfur dioxide (SO₂) oxidizes to sulfur trioxide (SO₃) and, below the acid dew point, reacts with water vapor to form sulfuric acid (H₂SO₄). High‑pressure boiler studies put sulfuric‑acid dew points around 115–138 °C, and even if bulk flue gas is warmer, tube metal below that threshold condenses acid locally—metal temperature, not just gas temperature, drives the risk (IJSER). The resulting condensate is unforgiving: 50–80 wt% H₂SO₄ (wt% = weight percent) aggressively attacks carbon steel (IJSER).
One widely cited guideline notes flue‑gas corrosion and fouling “rapidly increase below gas temperatures of 140 °F (60 °C),” the water dew point (Veolia Water Technologies handbook). In practice, moderate sulfur fuels (e.g., 0.1–0.5% fuel S) drive acid dew points into the 65–95 °C band. A technical table pegs “maximum flue gas dew point” against sulfur: natural gas (<0.1% S) ~150 °F (66 °C), #2 oil (~1% S) ~180 °F (82 °C), low‑S oil (~2% S) ~200 °F (93 °C) (Kewanee Boiler/Scribd). That puts an HRSG on ~1% S fuel in the 80–90 °C dew‑point range, and any operation pushing economizer surfaces below ~60–90 °C can trigger attack (Scribd).
Figure 1 in one engineering set shows the stakes: a ruptured carbon‑steel economizer tube where acid condensed, and a flue‑gas dew‑point example underpinning the temperature limits (Kewanee Boiler estimates; desalination plant case study via IJSER).
Feedwater temperature setpoints
Because economizers transfer heat from hot flue gas into the coldest water in the HRSG, the feedwater inlet temperature largely sets the cold‑end metal temperature. Keeping that inlet above the acid dew point—often with a 10–20 °C buffer—is a proven safeguard. One industry guide pairs dew points with minimum allowable feedwater temperatures: for natural gas (acid dew ~66 °C), the minimum feedwater inlet is ~210 °F (≈99 °C); for #2 fuel oil (~82 °C dew), 210 °F; for low‑sulfur oil (~93 °C dew), 220 °F (≈104 °C). The same source suggests holding the stack outlet ~100 °F above dew point, which translates to tube/feedwater surfaces on the order of 200–275 °F (Scribd).
Field data echo the math. In one HRSG, feedwater was normally held at ~195 °C, comfortably above an ~135 °C sulfuric‑acid dew point, with no corrosion observed. After a mode change dropped feedwater to ~125 °C, severe acid condensation and pitting began immediately; investigators concluded that “when the feed water temperature dropped to the dew‑point or below, the sulfuric acid condenses, which is an indication of the onset of corrosion,” and recommended raising the feedwater temperature above the dew point—and reducing fuel sulfur to lower the dew point (IJSER case data; explicit recommendation in IJSER).
Design features backstop those setpoints. Operators use bypass valves or recirculation to keep the economizer exit ≥~110 °C at all loads, and feedwater heater networks to eliminate “cold pockets.” Locating economizers as close to the furnace breech as practical helps ensure hotter gas at the section inlet, and some boiler designs insert a spine of superheat ahead of the economizer to raise metal temperatures (Scribd).
Cold-end temperature control hardware
Front‑end temperature control trades a bit of efficiency for reliability. Steam‑coil or hot‑air preheaters keep the air preheater and stack surfaces above the acid dew point—Veolia explicitly recommends steam‑coil air preheaters to maintain average metal temperature above the acid dew point (Veolia Water Technologies handbook). That is consistent with broader guidance that cold‑end issues rise rapidly as gas crosses the water dew point (~60 °C) (Veolia).
Combustion chemistry and air management
Lowering fuel sulfur directly lowers the acid dew point. Combustion tuning helps too: running at very low excess air (~5%) can significantly reduce SO₃ formation, and “operating with ≤5% excess O₂” is cited for markedly cutting SO₃ content and the acid dew point; minimizing air infiltration is part of the same playbook, as air ingress accelerates SO₃ formation on tube oxides and catalyst dust (Veolia Water Technologies handbook). Moisture matters as well: reducing flue‑gas water vapor—by fixing leaks and avoiding wet carryover—can shave a few degrees off the dew point (Veolia).
Layup protection with inhibitors
Shutdowns are a vulnerable window: cold, humid soak can condense acid on idle economizer surfaces. Plants increasingly deploy vapor‑phase corrosion inhibitors (VCIs, chemicals that form a protective film in the vapor space) instead of nitrogen blanketing. One UK combined‑cycle site reported an ~£2,000/month nitrogen purge cost; switching to VCI fogging cut two‑year preservation costs from ~£48k to under half, with no failures thereafter (Power Magazine). The plant “now experiences zero failure because of corrosion” after repeated VCI applications (Power Magazine). In practice, VCI strategies sit alongside conventional corrosion‑inhibitor programs; facilities often align application hardware and procedures with established corrosion inhibitor standards for consistency.
Routine cleaning of cold sections
Deposits magnify risk by shifting local chemistry. Acid smut and iron‑sulfate fouling on air preheaters and economizers not only trap moisture but also catalyze SO₃ formation (e.g., vanadium pentoxide V₂O₅ and iron oxides Fe₂O₃). Frequent soot‑blowing and periodic washing with water or ammonia reduce these catalytic sites and help cold‑end surfaces shed condensate (Veolia Water Technologies handbook; operational guidance also in Veolia). Where in‑house bandwidth is tight, facilities lean on a dedicated boiler cleaning service to keep cold‑end deposits in check.
The payoff is material: one survey attributed ~10–15% of utility boiler tube failures to economizer acid‑corrosion issues—avoidance is a direct hit to forced‑outage statistics (IJSER).
Economizer tube material selection
Operations help, but startups, shutdowns, and off‑design conditions still deliver occasional acid wetting. Material choices for the coldest economizer rows therefore matter. Stainless steels—both austenitic (304H, 321H, 347H) and ferritic (Type 439, 2CR13)—add chromium to form protective oxides. Duplex stainless 2205 (UNS S32205) is widely used for feedwater/economizer duty; in lab tests simulating acidic dew, UNS S32205 showed “passivation behavior” and much smaller weight loss than carbon steels in 5–10% H₂SO₄, while plain carbon and conventional “acid‑resistant” HSLA steels corroded severely—even in dilute acid (ResearchGate).
In extreme duty, high‑nickel alloys such as Incoloy 800 see use, though costs are higher. Some ferritic steels deliberately add Cu and Sb (antimony) to stabilize a sulfuric‑acid surface film—one such “S‑TEN” category (aliases include SA333 Grade 6 / SA192) forms a thin FeSO₄ barrier. In 50% H₂SO₄ immersion tests, SA192‑type steels outperformed duplex stainless by building that stable FeSO₄ layer; at more moderate acid levels (5–10%), duplex stainless was far superior, underscoring that worst‑case exposure should drive the spec (ResearchGate; comparative performance also in ResearchGate).
For low‑sulfur gas‑turbine service (S < 0.05%), carbon steel may suffice if temperatures are tightly controlled. Many operators compromise in moderate‑sulfur duty by specifying carbon‑steel tubes clad or overlaid with stainless or nickel alloys (e.g., Inconel 625), or using polymer‑based linings—so long as coatings tolerate thermal stresses.
Field evidence is stark. Photomicrographs show carbon‑steel economizer tubes attacked across much of the wall when run near the acid dew point; even austenitic 304 can thin under under‑deposit acid at high acid concentrations, with “honeycomb” pitting on welds and contours. By contrast, well‑chosen duplex alloys (e.g., SS2205) may lose only fractions of a millimeter over the same interval (BCInsight/CRU Group; micrographic contrasts also discussed in BCInsight/CRU Group).
Material economics and outage risk
Alloy selections cost real money: duplex stainless typically runs ~3–5× the price of carbon steel by weight, which is why many plants confine exotic grades to the lowest, highest‑risk tube rows. Outage math often decides the ROI. One high‑availability unit suffered an economizer tube leak attributable to cold‑end corrosion; a duplicate unit re‑lined the economizer with stainless at the next outage (IJSER case note). Another study’s bottom line was operational, not metallurgical: “It is recommended to decrease sulfur in fuel and to raise feedwater temperature above dew point” to avoid needing exotic materials in the first place (IJSER).
Operating envelope and sources
Put together—higher feedwater inlet, hotter cold‑end metal, lower sulfur, tight air management, dry layup, cleaner surfaces—modern plants can largely avoid cold‑end corrosion. One site reached “zero corrosion failures” after tightening dew‑point controls (higher feedwater temperatures and VCI layup) (Power Magazine). Industry references throughout include boiler engineering handbooks and chemistry guidance (Veolia Water Technologies; additional dew‑point context in Veolia; air‑management practices in Veolia), failure post‑mortems (IJSER; condensation onset and prevention in IJSER), and materials studies (BCInsight/CRU Group; duplex vs. carbon steel performance in ResearchGate). All numeric values (dew points, temperatures) and material comparisons cited here are drawn directly from those sources.
