How Do Water and Impurities Change Alloy Selection for Wet CO2 Service?

CO₂ is often described as a corrosive gas, but this description is incomplete.

For conventional internal CO₂ corrosion, a water-containing phase is normally required. CO₂ dissolves into that water, changes the aqueous chemistry, and can cause carbon-steel dissolution. When the stream remains sufficiently dry and no separate aqueous or acidic phase develops, the internal-corrosion mechanism is fundamentally different.

The difficulty is that real process streams rarely contain only CO₂ and water.

H₂S, oxygen, chlorides, organic acids, SOx, NOx, CO, hydrogen, solids, and other contaminants can change:

• Whether a separate liquid phase forms
• The composition and pH of that liquid
• The stability of corrosion-product or passive films
• The risk of localized corrosion
• The risk of hydrogen-related or stress-corrosion cracking
• The material qualification standard that applies

Alloy selection for wet CO₂ service should therefore begin with the water state, CO₂ phase, impurity combination, temperature, pressure, and credible upset conditions—not with a generic ranking of stainless steel, nickel alloys, and titanium.

Image credit: Implicit Matrix, Wikimedia Commons, CC BY 4.0.

This article addresses wet CO₂ in hydrocarbon production, process equipment, injection systems, and gaseous or dense-phase CO₂ transport.

It does not address corrosion inside an aqueous amine solvent loop. That subject requires separate equipment-zone analysis, as discussed in alloy selection for amine carbon capture equipment.

First Determine What “Wet CO₂” Means

The word wet can describe several technically different conditions.

A dry-stream design should therefore specify more than a normal water concentration.

It should address:

• Maximum water content
• Measurement location
• Measurement method
• Dew-point margin
• Lowest metal temperature
• Pressure and temperature transients
• Startup and shutdown
• Low points and dead legs
• Water carryover
• Duration of off-spec operation

A pipeline can meet its normal water specification and still experience corrosion if water condenses during a transient or combines with reactive impurities to form an acidic liquid phase.

Separate Hydrocarbon Wet CO₂ From CCS CO₂ Transport

The same phrase—wet CO₂ corrosion—can refer to two different engineering contexts.

NORSOK M-506:2017 presents a recommended CO₂ corrosion-rate model for hydrocarbon production and process systems.

It should not be treated as a complete model for dense-phase CCS pipelines containing reactive capture impurities.

For CO₂ transport, ISO 27913:2024 and DNV-RP-F104 provide more relevant system frameworks.

Why Water Content Cannot Be Evaluated Alone

A single water limit may be useful for process control, but it does not describe the complete corrosion risk.

The critical question is:

What liquid phase can form from this exact CO₂ stream under the complete pressure and temperature envelope?

Reactive impurities may:

• Alter water solubility
• React with water
• Form strong acids
• Change droplet composition
• Concentrate at low points
• Create highly corrosive local environments
• Alter cracking behaviour

High-pressure testing has shown that CO₂ streams containing NO₂, or SO₂ plus O₂, can begin to corrode carbon steel at different water levels under otherwise controlled conditions.

Those experimental values should not be copied as universal pipeline specifications. They demonstrate that the water threshold depends on the impurity mixture.

How the Main Impurities Change Material Selection

H₂S: General Corrosion and Cracking Must Be Separated

H₂S does not simply add a fixed amount of corrosion to wet CO₂.

It can influence the system through:

• Formation of iron-sulfide corrosion products
• Changes in general corrosion rate
• Promotion of hydrogen entry into steel
• Sulfide stress cracking
• Hydrogen-induced cracking
• Stress-oriented hydrogen-induced cracking
• Stress corrosion cracking of susceptible CRAs

Iron-sulfide films may sometimes reduce general wall loss under particular conditions.

That does not mean the service is safe.

A material showing a low uniform corrosion rate may still be unacceptable because of cracking susceptibility.

Where the service falls within oil and gas production or natural-gas treatment, the current published ISO 15156-1:2020 and ISO 15156-3:2020 should be reviewed when contractually applicable.

The selection may depend on:

• H₂S partial pressure or fugacity
• pH
• Chloride concentration
• Temperature
• Elemental sulfur
• Material hardness
• Cold work
• Heat treatment
• Applied and residual stress
• Product form
• Weld condition

ISO 15156 addresses H₂S-related cracking resistance. It does not by itself calculate general CO₂ corrosion, establish corrosion allowance, or approve a material for every CCS transport stream.

Oxygen: Beneficial to Passivity but Potentially Harmful to the System

Oxygen can have different effects on different materials and environments.

For carbon steel, oxygen can support additional cathodic reactions and increase corrosion under some wet conditions.

For stainless steel, nickel-chromium alloys, and titanium, oxygen may support passive-film formation.

However, oxygen can also:

• Participate in reactions involving SO₂ or NO₂
• Change the chemistry of condensed droplets
• Increase localized corrosion potential
• Oxidize sulfide-containing species
• Change inhibitor or corrosion-product behaviour

The conclusion cannot be reduced to either:

• “Oxygen is always harmful,” or
• “Oxygen protects passive alloys.”

The correct conclusion depends on the complete water and impurity chemistry.

SO₂ and NO₂: Low Concentration Does Not Mean Low Importance

Captured CO₂ streams may contain sulfur- and nitrogen-oxide carryover.

When water is available, these species can contribute to strongly acidic liquid phases.

Their importance is not determined only by their gas-phase concentration.

Relevant factors include:

• Water content
• Temperature
• Pressure
• CO₂ phase
• Oxygen
• Reaction time
• Surface catalysis
• Mixing of streams from different capture sources
• Low-point accumulation

This is particularly important for CO₂ hubs receiving streams from several emitters. A combined stream may create interactions that were not present in the individual source specifications.

ISO 27913:2024 includes CO₂ stream-quality assurance and converging streams because composition control is an integrity requirement, not merely a product-purity issue.

Chlorides: Only the Aqueous Concentration Directly Describes the Localized-Corrosion Exposure

A chloride value reported for the total process stream does not automatically describe the chloride concentration at the metal surface.

Chlorides may enter through:

• Produced water
• Seawater contamination
• Upstream process carryover
• Cleaning water
• Condensation
• Salt deposits
• Concentrated low-point water

Once present in an aqueous phase, chlorides can contribute to:

• Pitting
• Crevice corrosion
• Chloride stress corrosion cracking
• Reduced passive-film stability
• More severe local chemistry beneath deposits

The risk depends on:

• Chloride concentration in the water phase
• Temperature
• pH
• H₂S
• Oxygen
• Alloy condition
• Crevice geometry
• Deposits
• Applied stress

There is no universal chloride concentration at which every stainless steel becomes unacceptable.

Likewise, a nickel alloy should not be approved solely because it contains more molybdenum than another grade.

Organic Acids

Acetic, formic, propionic, and other organic acids can be present in produced fluids or process contamination.

They may:

• Lower aqueous pH
• Increase metal-ion solubility
• Affect iron-carbonate scale formation
• Change the apparent CO₂ corrosion rate
• Increase the corrosivity of condensed water

Their impact depends on both total concentration and dissociated-acid concentration in the actual water phase.

A gas-phase organic-acid value without water chemistry, temperature, and pH is insufficient for material selection.

CO and H₂: Emerging High-Pressure CO₂ Integrity Questions

Current industry research is investigating whether CO, H₂, oxidizers, and high-pressure CO₂ combinations can create environment-assisted cracking risks in line-pipe steels and welds.

DNV’s CO/CO₂ cracking JIP is developing impurity limits, metallurgical limits, and qualification methods.

Until qualified guidance is available, buyers should avoid presenting one universal CO or H₂ limit as a proven material-selection boundary.

New or unusual CO₂ stream compositions may require project-specific testing of:

• Parent pipe
• Weld metal
• Heat-affected zone
• Actual strength level
• Actual hardness
• Applied stress
• Relevant condensate chemistry

Use a Mechanism-Based Material Screening Process

The material should be selected for the controlling mechanism rather than for the number of impurities listed on the process data sheet.

Preliminary Material Screening

This table identifies possible starting points only.

A material should be specified by:

• Formal grade
• UNS designation
• Product standard
• Product form
• Supplied condition
• Heat treatment
• Strength or hardness limits
• Welding requirements
• Environmental qualification limits

“Inconel equivalent,” “Hastelloy equivalent,” or “titanium alloy” is not a sufficient purchase description.

Is Alloy 625 the Default Choice for Severe Wet CO₂?

No.

Alloy 625 may be a strong candidate when the service combines:

• Chlorides
• H₂S
• Low pH
• High mechanical requirements
• Localized-corrosion risk
• Demanding fabrication or pressure requirements

The final decision should still verify:

• H₂S environment limits
• Chloride concentration in the aqueous phase
• Temperature
• pH
• Elemental sulfur
• Cold-work level
• Final heat treatment
• Weld filler and dilution
• Product standard
• Qualification test evidence

An Alloy 625 tube that meets its ASTM product standard has verified product properties.

It has not automatically been qualified for every wet CO₂ impurity combination.

Is Titanium a Suitable Upgrade?

Titanium is highly resistant in many oxidizing chloride-containing aqueous environments.

It is not the default upgrade for all wet CO₂ or sour service.

The review should include:

• Whether the water phase is oxidizing or reducing
• Fluoride content
• H₂S and hydrogen-generation conditions
• Temperature
• Crevice geometry
• Galvanic connection
• Cathodic protection
• Surface condition
• Titanium grade

A project should not select titanium solely because stainless steel has failed.

The actual failure mechanism must first be identified.

Apply the Correct Standards to the Correct Service

The contract should identify which standard is mandatory.

A material supplier should not decide that a standard applies solely because CO₂ or H₂S appears in the process description.

How Should Wet CO₂ Qualification Testing Be Designed?

A meaningful test should reproduce the variables that control the expected damage mechanism.

Test Inputs

Test Sequence Matters

The result may change depending on whether:

• Water is present before pressurization
• Impurities are premixed
• Water is introduced after reaching pressure
• The system is cooled through a phase boundary
• The material surface catalyses impurity reactions
• Acidic droplets are allowed to settle
• Test fluids are continuously renewed

A test report should describe the preparation and sequence, not only the nominal composition.

What Buyers Should Include in the RFQ

A supplier receiving only “wet CO₂ with H₂S and chlorides” cannot responsibly approve a final alloy.

Frequently Asked Questions

Is completely dry CO₂ corrosive to carbon steel?

Conventional carbonic-acid corrosion requires a water-containing phase. A sufficiently dry CO₂ stream can have low aqueous-corrosion risk, but the design must also consider condensation, dehydration failure, reactive impurities, low points, and startup conditions.

Is one maximum water concentration enough for a CO₂ pipeline specification?

Not always. The acceptable level depends on temperature, pressure, CO₂ phase, impurity combination, stream mixing, and whether acidic droplets can form.

Does H₂S always increase the general corrosion rate in wet CO₂?

No. H₂S can form iron-sulfide films that alter general corrosion. It simultaneously introduces hydrogen-related cracking risks, which may govern material selection even when general wall loss is low.

Does ISO 15156 apply to every wet CO₂ system containing H₂S?

No. Its primary scope is H₂S-containing oil and gas production and natural-gas treatment equipment. A CCS or other process project must explicitly determine whether and how it is invoked.

Can NORSOK M-506 be used for dense-phase CO₂ transport?

It is intended for CO₂ corrosion calculations in hydrocarbon production and process systems. Dense-phase CCS transport with O₂, SOx, NOx, CO, H₂, and other capture impurities requires a different stream-quality and integrity assessment.

Is Alloy 625 always the safest option?

No. It may be a strong candidate, but suitability depends on the water chemistry, H₂S, chloride, temperature, cold work, weld condition, strength, and product standard.

Is Alloy C-276 always better than Alloy 625?

No. C-276 may provide stronger resistance in some mixed acid environments, while Alloy 625 may offer another balance of strength, availability, fabrication, and corrosion resistance. Neither can be ranked without the actual environment.

Can titanium be used in wet CO₂ containing H₂S?

Possibly in selected environments, but titanium is not a universal sour-service material. Reducing acidity, hydrogen generation, fluorides, temperature, crevices, and galvanic conditions require specific review.

Are chlorides dangerous if the CO₂ stream is dry?

Chlorides have their main direct corrosion effect when they enter an aqueous or deposited phase at the metal surface. The design must consider whether condensation or water carryover can create that phase.

Can an ASTM G31 test qualify a material for dense-phase CO₂?

Not by itself. G31 is an immersion-testing guide. Dense-phase CO₂ qualification may require high-pressure testing with the real water and impurity combination, representative welds, and the expected phase behaviour.

Should the project always replace carbon steel with a CRA?

No. Water control, impurity specifications, corrosion allowance, inhibition, inspection, and operational safeguards may allow carbon steel in some systems. A CRA may be justified where those controls cannot keep risk within the project criteria.

What information should be sent with a wet CO₂ material enquiry?

Send the CO₂ phase, pressure, temperature, water specification, H₂S, O₂, SOx, NOx, CO, H₂, chloride, organic acids, condensation conditions, material form, dimensions, standard, condition, welding, testing, and documentation requirements.

Conclusion

Wet CO₂ material selection is controlled by the liquid phase that can exist at the metal surface.

The most important questions are:

1. Is bulk water, condensate, entrained water, or an acidic droplet possible?
2. What is the chemistry of that liquid?
3. Does the dominant risk involve general corrosion, localized corrosion, or environment-assisted cracking?
4. Which standard actually covers the service?
5. Has the proposed material been qualified in a representative environment?

H₂S, oxygen, chlorides, organic acids, SOx, NOx, CO, and H₂ do not act as independent checklist items.

They interact with water, pressure, temperature, flow, surface condition, weld metallurgy, and one another.

For buyers, the correct approach is to define the complete wet CO₂ operating and upset envelope before requesting a final material recommendation.

For nickel-alloy or titanium tube and bar enquiries, provide the exact stream composition, water basis, phase, temperature, pressure, dimensions, product standard, material condition, sour-service limits, welding requirements, testing, and documents.

Emily PIPE can review whether the requested nickel-alloy or titanium product form, size, condition, product standard, NDT, certification, and packaging requirements are manufacturable. Final environmental compatibility and materials approval should remain with the responsible process, pipeline, materials, or corrosion engineer.