Heat exchangers for corrosive gases: degradation mechanisms, materials and applicable standards
The selection of materials for finned-tube heat exchangers and gas-gas recuperators in the presence of corrosive industrial gases —H₂S, chlorine, HCl, SO₂, ammonia or HF— is one of the technical decisions with the greatest impact on equipment reliability and service life.
In the chemical, petrochemical, gas treatment and fertiliser production industries, heat exchangers frequently operate in contact with gaseous streams containing substances that are aggressive towards conventional metallic materials. An error in the selection of the material for the tubes, fins or headers can manifest itself months or years after commissioning, with consequences ranging from loss of performance to structural failure of the equipment. Understanding the degradation mechanisms specific to each gas is the starting point of any rigorous selection process.
1. Degradation mechanisms: the necessary technical vocabulary
The degradation mechanisms of metallic materials in the presence of corrosive gases are not limited to general corrosion through loss of thickness. In many industrial cases, the dominant mechanism is localised or mechanical-chemical in nature, with kinetics that can be difficult to detect before the damage is significant.
2. Most common corrosive gases in industrial process
The NACE MR0175 / ISO 15156 standard —Petroleum and natural gas industries — Materials for use in H₂S-containing environments in oil and gas production— is the reference technical document for material selection in H₂S environments. It defines the concept of «sour service», establishes the H₂S partial pressure thresholds that activate its requirements, and specifies the chemical composition, heat treatment and qualification testing conditions that materials must meet. Its application is not limited to oil and gas production: the standard is commonly referenced in refining, petrochemical and gas treatment projects wherever H₂S is present. The standard consists of three parts: the first establishes the general framework, the second applies to steels and cast irons, and the third to corrosion-resistant steels and other materials.
3. Specific implications for finned-tube heat exchangers
In finned-tube heat exchangers, the corrosive gas usually flows around the outside of the tubes —in contact with the fins— while the process fluid flows inside. This configuration means that the materials in contact with the gas are the tubes and the fins, and that the selection of one and the other cannot be made independently.
- The tubes are the primary barrier: the tube material is what determines the equipment's resistance to the corrosive gas. In H₂S or halogenated gas service, incorrect tube material selection is the main cause of premature failure. Carbon steel tubes are the lowest-cost solution, but their use must be confined to environments without H₂S in sour service, without significant chlorides and at moderate temperatures.
- Aluminium fins: suitable for general service, not for corrosive gases: aluminium is the standard material for fins in industrial heat exchangers due to its good thermal conductivity, low weight and cost. However, it is vulnerable to environments with HCl, HF, strong bases or ammonia with moisture. For gases containing these substances, the alternatives are stainless steel fins (greater resistance, lower conductivity) or fins with a specific protective coating (PVDF, Heresite or others, with temperature limitations).
- The tube-fin joint: a critical galvanic corrosion point: when the tubes and fins are of different materials —for example, stainless steel tubes and aluminium fins— the joint between them can be a galvanic corrosion site if the gas is humid or if occasional condensation occurs. In dry environments, the risk is much lower. The most robust solution is to use the same material for tubes and fins, although this increases cost.
- The headers and manifolds: in configurations with corrosive gas on the fin side, the internal fluid headers are not in contact with the gas. However, if the gas temperature is sufficiently high, the headers must be compatible with it from a mechanical standpoint, and their material must be compatible with the internal fluid.
4. The acid dew point: a design parameter with two possible strategies
In heat recuperators that cool combustion gases or process gases containing SO₂, SO₃, HCl or HF, there is a temperature below which the gas begins to condense acids on the equipment surfaces. This limit —the acid dew point— is specific to the gas composition and varies according to the fuel, the process conditions and the pressure. It is not a value that can be measured directly in operation: it must be calculated or estimated from the gas composition and verified where possible.
To address this phenomenon, two technically valid design strategies exist, with very different implications for materials, energy efficiency and cost:
The equipment is designed so that the minimum wall temperature of the exchanger remains above the acid dew point at every point, thereby avoiding condensation. This is achieved by controlling the cooling fluid temperature, the geometric design of the equipment and the selection of corrosion-resistant materials in the highest-risk zone. This is the usual strategy in conventional recuperators. Its limitation is that the gas outlet temperature is bounded above the dew point, which restricts the amount of recoverable heat and excludes the latent heat of the water vapour contained in the gases.
When the equipment is conceived specifically to work in condensing mode —condensing economisers or condensation recuperators— the gases are cooled below the dew point in a controlled manner. This allows recovery of not only the sensible heat of the gases but also the latent heat of condensation of the water vapour present in them, which in natural gas combustion gases is significant given the high proportion of H₂O resulting from the combustion of methane. The result is a higher overall thermal efficiency of the installation. This strategy is viable in combustion gases from natural gas, diesel, fuel oil and other fuels, provided the equipment is designed with materials suited to contact with the acid condensate generated, with geometry allowing correct condensate drainage, and with the condensate water management systems the process requires. The fuel composition —particularly its sulphur content— determines the aggressiveness of the condensate and therefore the material requirements.
The decision between avoiding condensation or conceiving the equipment to operate in it depends on several factors that must be assessed together: the gas composition and the expected aggressiveness of the condensate, the temperature of the available cooling fluid (a very cold fluid favours condensation, whether desired or not), the energy efficiency objective of the process, and the condensate management requirements. In installations where the cooling fluid enters at low temperature —such as in certain waste heat recovery processes or in district heating systems— condensation can be difficult to avoid even if it was not foreseen in the original design; in those cases, strategy B with appropriate materials is technically more robust than attempting to keep the wall temperature above the dew point when the process conditions do not allow it in a stable manner.
5. Reference standards for damage evaluation
Beyond the pressure calculation and certification codes (PED, ASME VIII, EN 13445), the evaluation of the condition of exchangers in service with corrosive gases relies on a set of technical documents specific to the process sector.
| Standard / Document | Organisation | Relevant content |
|---|---|---|
| NACE MR0175 / ISO 15156 | NACE International / ISO | Materials in H₂S environments; definition of sour service; hardness, composition and heat treatment requirements |
| NACE MR0103 | NACE International | H₂S-resistant materials specifically in refineries; complements MR0175 for this sector |
| API 571 | American Petroleum Institute | Comprehensive catalogue of damage mechanisms in fixed refinery equipment: SSC, HIC, SCC, HTHA, acid dew point corrosion, among others. Fundamental reference for inspection engineers. |
| API 941 | American Petroleum Institute | Nelson curves for material selection in high-temperature H₂ service; temperature and H₂ partial pressure limits by steel type |
| API 661 | American Petroleum Institute | Air-Cooled Heat Exchangers for refineries; mechanical design specification, materials and testing |
| ASTM G48 | ASTM International | Test methods for pitting and crevice corrosion resistance in stainless steels (ferric chloride test) |
| EN 10088-1/2/3 | CEN / AENOR | Stainless steels: composition, mechanical properties and technical supply conditions |
| PED 2014/68/EU | European Commission | Essential safety requirements, fluid classification (Group 1 includes H₂S, Cl₂, HF) and certification process for pressure equipment in the EU |
6. Selection criteria: key questions before specifying the material
- Does the gas contain H₂S? If the answer is yes and moisture is present, the application may fall within the scope of NACE MR0175 / ISO 15156 (sour service). The material hardness and the type of steel are then constrained, regardless of the H₂S concentration.
- Are chlorides or halogens present? Concentration, temperature and the presence of moisture determine whether the risk of pitting or SCC in austenitic stainless steels is significant. Above certain temperatures, pitting in SS can occur at relatively low chloride concentrations.
- Can acid condensation occur at any point in the equipment? The answer defines the design strategy. If the objective is to avoid condensation, the minimum wall temperature must be kept above the acid dew point under all operating conditions, including start-ups and load variations. If the equipment is conceived as a condensing economiser —to also recover the latent heat of the water vapour in the gases— condensation is an intended design condition, and the materials, geometry and condensate management system must be conceived specifically for it. Both strategies are technically valid; the choice depends on the process conditions, the gas composition and the energy efficiency objective.
- Are the tube and fin materials compatible with each other in the gas environment? Verification of galvanic compatibility is especially relevant in humid environments or with occasional condensation.
- What is the PED classification of the gas? Flammable, toxic or oxidising gases are Group 1 under the PED, which activates more demanding categorisation tables and may require the involvement of a Notified Body in the certification of the equipment.
BOIXAC works in the conception and supply of finned-tube heat exchangers and gas-gas recuperators for industrial installations with corrosive process gases. For each project, the BOIXAC technical team works with the actual gas composition, the temperature and pressure conditions, and the regulatory requirements to identify the appropriate combination of materials and configuration. The definitive compatibility of materials for a specific service must be validated by the materials or corrosion engineer in charge of the project.