The cold-end line that decides HRSG uptime: staying above the acid dew point

Cold-end corrosion is the quiet saboteur inside many HRSGs (heat recovery steam generators). When sulfuric or hydrochloric acids, formed from SO₂/NO₂/O₂ reactions with moisture, condense on steel surfaces that are too cool, they eat through economizer tubes and force outages. The acid dew point for typical flue gas is often 100–150 °C, depending on fuel sulfur/chlorine and moisture content (digitalrefining.com).

The failure mechanism is plain in field reports. “The metal had fallen below the acid dew point, and thus H₂SO₄ had condensed on the outer surface of the economizer tubes, causing severe corrosion,” one boiler-service analysis concluded (researchgate.net). Another plant burning high-sulfur oil traced economizer leaks to “acid dew point corrosion” from fuel sulfur (researchgate.net).

The chemistry is unforgiving: when any tube wall drops below dew point, condensing acids rapidly strip protective oxides, pit the metal, and thin the wall. Corrosion rates peak roughly 15–20 °C below the dew point; letting flue gas fall just 20–30 °C below dew point can “max out” acid deposition and corrosion rate (vganapathy.tripod.com; tetra-eng.com).

Acid dew point, defined and quantified

Acid dew point is the temperature at which acid vapors (such as H₂SO₄ or HCl) in flue gas condense into liquid on cooler surfaces; it varies with fuel sulfur/chlorine content and moisture. For HRSGs with ~15% H₂O in the exhaust, it is often 100–150 °C (digitalrefining.com). Kewanee guidance lists dew points of ~150 °C for natural gas and up to 180–200 °C for oil fuels (scribd.com). If economizer tube walls dip below those temperatures, sulfuric acid condenses and attacks the steel (researchgate.net; tetra-eng.com).

Natural gas can be benign, but not always. Even with low sulfur, plants still apply a margin: conservative practice keeps the coldest economizer surfaces at least ~10–20 °C above the highest expected acid dew point (vganapathy.tripod.com).

Setpoint strategy: feedwater above dew point

Design and operational rule: keep the coldest economizer tube above the acid dew point of the flue gas so acids stay in the vapor phase. In practice, plants raise feedwater/deaerator temperature or add high‑pressure feedwater preheaters to ensure the economizer inlet water is hot enough. Kewanee’s classic table implies economizer feedwater ≳210 °C to cover dew points up to ~200 °C; operators keep the economizer exit (feedwater inlet) 10–60 °C above dew point (scribd.com).

Rules of thumb back this up: raise economizer feedwater at least ~10–15 °C above the acid dew point; Ganapathy’s note shows lowering economizer feed by 40 °F (≈22 °C) typically improves cycle efficiency by ~1%, but only if acid corrosion is addressed (vganapathy.tripod.com; vganapathy.tripod.com). Raising flue gas temperature has little impact on economizer wall temperature, which closely follows the water temperature (vganapathy.tripod.com).

For context (implied by the same Kewanee data), “safe” temperatures look like this: natural gas dew point ~40–100 °C with feedwater ≳60–110 °C (depends on specifics); #2 fuel oil (∼0.3–0.5% S) dew point ~150–180 °C with feedwater ≳210 °C; Low‑Sigit fuel oil (∼2% S) dew point ~180–200 °C with feedwater ≳220 °C (scribd.com).

Startup, shutdown, and layup controls

Shutdowns are a prime risk. At one site, upper economizer tubes cooled to ~80 °C during layup and later failed from acid dew point corrosion (powermag.com). Plants counter with recirculation of warm water or purging with dry gas. At the Terry Bundy combined‑cycle plant, dedicated recirculation pumps run during layup “to mitigate acid dew point corrosion” on HP/LP circuits (power-eng.com).

Chemistry helps too. Some operators switch to a protected layup chemistry—[oxygen scavengers and corrosion inhibitors](https://beta.co.id/en/blog/inside-the-hrsg-feedwater-playbook-scavenge-oxygen-raise-ph-cut-corrosion)—to passivate surfaces. In practice, this can mean introducing an oxygen scavenger program in the layup circuit. Complementarily, a targeted corrosion inhibitor can reduce corrosion rates by 90%+ (product specification). South Humber Bank (UK) used a VpCI fog to protect economizer tubes (~80 °C during shutdown) after repeated dew‑point corrosion failures (powermag.com). Alternatively, full drying and nitrogen or dry‑air blanketing prevent condensation, though such methods can fail if seals leak.

Design details matter: insulation should eliminate cold spots; routing and baffles should avoid drafts and ensure even heat transfer. Monitoring with online dew point sensors, frequent SO₂/SO₃ analyses, and even stack condensate pH offers early warning so operators can raise feedwater or adjust firing before condensation starts.

Economizer materials and corrosion resistance

Materials are the second line of defense. Carbon steel (e.g., ASME SA178 GrA/P1) is common and cost‑effective, but has essentially no inherent resistance to condensing acids. Designs assume only a small corrosion allowance (≈1/32″) and expect no condensation (esteemprojects.com).

Stainless steels raise the bar. Austenitics like SS304L and SS316L resist acid attack; 316L, with 2–3% Mo, is preferred for H₂SO₄. Tests show 316L suffering minimal attack versus carbon steel in sulfuric acid (researchgate.net). A 316L or 317L economizer can essentially eliminate dew point corrosion; several units with high‑S or high‑chloride risks retrofit these tubes. The trade‑offs: 3–5× the material cost of carbon steel, sometimes reduced thermal conductivity, and weld considerations.

Duplex/ferritic stainless steels offer moderate H₂SO₄ resistance (better than 304, less than 316) but are not a solution under condensing conditions below ~150 °C; 5–9%Cr steels (P91, etc.) have little resistance to sulfuric or hydrochloric acids. [Nickel alloys—Inconel 625/825, Incoloy 800/825](https://beta.co.id/en/blog/inside-nickels-acid-gauntlet-how-hpal-plants-pick-metals-that-survive)—are much more resistant to H₂SO₄ and HCl (Incoloy 825 can withstand concentrated sulfuric acid), yet costs push them to critical sections only. Clad options (carbon steel base with SS or Ni alloy cladding) isolate the substrate; 304‑clad economizers are used. Thermally sprayed and epoxy coatings generally lack durability for continuous HRSG service.

Other materials, including polymers/composites, have been proposed for below‑dew‑point heat recovery—thermoplastics like PPS‑GRP were tested—but these remain experimental and not mainstream for utility HRSGs (digitalrefining.com; bcinsight.crugroup.com). In practice, the choice is an economic trade‑off: one economizer tube failure can cost tens of thousands in repairs plus megawatts in lost output, while upgrading all economizer tubing to 316L might raise material cost by only a few percent of a new HRSG budget, potentially reducing failures to near‑zero. Many units on sulfur‑bearing fuels specify stainless or NEWS (Ni alloy) cladding in sensitive sections; some CCGTs in petrochemical service deploy 316L or even Incoloy bundles.

Note: even with robust materials, acid exposure can still occur during wet layup or if chlorine drives HCl condensation at ~30–50 °C.

Efficiency targets versus corrosion margins

Operators naturally chase lower flue gas temperatures for efficiency. Halving flue gas outlet temperature by ~40 °F (≈22 °C) typically improves cycle efficiency by ~1% (vganapathy.tripod.com). But as the gas approaches—and crosses—the acid dew point, corrosion escalates. Conservative practice holds a 10–20 °C cushion above dew point for the coldest tubes. Industry analysis also notes that recovering an extra 2–3% of flue heat by approaching the dew point can deliver several MW of additional output on a large unit (digitalrefining.com), underscoring the tension between heat rate and reliability.

Monitoring and diagnostics

Plants track economizer outlet temperature and flue gas composition to ensure the lowest tube wall never dips below dew point. Residual risk can be monitored via SO₂/SO₃ concentration and stack condensate pH. If dew point nears the planned tube temperature, operators raise feedwater temperature or adjust firing to steer clear of condensation (tetra-eng.com).

Indonesia’s fuel and policy context

Indonesia’s combined‑cycle fleet largely burns natural gas or distillate, which are very low in sulfur. Emission policy reinforces this. The Ministry of Environment and Forestry’s MOEF Reg. 15/2019 pushes toward low‑sulfur fuels or scrubbers. For coal units, flue gas desulfurization (FGD) routinely washes SO₂ to <5% of inlet; one Indonesian coal project demanded ~95% SO₂ removal (irt.co.id). Indonesia caps SO₂ at 750 mg/Nm³ for ≥100 MW units (cybertig.com). With modern LNG and diesel at <0.5% S, typical acid dew points may only be ~50–100 °C. Even so, dew‑point margins and careful layups are required; globally, HRSG tube failures remain common, with flow‑accelerated corrosion and acid dew‑point corrosion together often accounting for >50% of tube damage cases.

The practical playbook

The guidance is consistent across studies: keep economizer feedwater above the acid dew point of the flue gas, and design for the coldest tube to maintain the margin (vganapathy.tripod.com; scribd.com). Combine this with disciplined layup practices, targeted chemistry, and—where justified—corrosion‑resistant tubing. That combination preserves availability and heat rate by keeping acids in the vapor phase and away from steel.

Sources for mechanism, setpoints, and cases: researchgate.net; tetra-eng.com; vganapathy.tripod.com; layup/chemistry practices and site examples: powermag.com; shutdown circulation: power-eng.com; materials and allowances: esteemprojects.com; policy and efficiency context: irt.co.id, cybertig.com, digitalrefining.com.