What Pipe for Carbon Capture? CO2 Transport and Injection Material Guide

The question "what pipe do you need for a CO2 project?" has a more useful answer than the one most sources give. The reflex answer — that CO2 is corrosive, so a carbon capture project needs corrosion-resistant alloy — is wrong often enough to be expensive. The real driver is water: dry dense-phase CO2 is essentially non-corrosive to ordinary carbon steel, and it is free water that makes CO2 aggressive. Get the CO2 dry and keep its impurities in check, and carbon steel line pipe and carbon-steel injection tubulars are the field-proven, economical choice. Fail to, and no reasonable grade survives. This guide walks the material decision for the two halves of a CCUS chain — the CO2 transport pipeline and the CO2 injection well — the way an EPC actually has to make it.

ZC Steel Pipe supplies API 5L line pipe for CO2 transport and API 5CT casing and tubing for injection wells, and CCUS enquiries increasingly reach us with the material already assumed rather than derived. The most valuable thing we do on these projects is send the buyer back to the CO2 specification, because the pipe follows from the stream, not the other way round.

The One Thing That Decides the Pipe: Dry vs Wet CO2

The material decision for a CO2 project is, underneath, a decision about water. The chemistry is simple and well evidenced: if the local water content of the CO2 stream stays below its solubility limit, the water stays dissolved in the CO2 and the steel is safe; if water content exceeds that limit, a separate aqueous phase drops out, becomes saturated with CO2, and forms carbonic acid on the pipe wall — and that attacks carbon steel.

The corrosion rates put numbers on it:

• Dry supercritical CO2: roughly 0.01–0.02 mm/year on carbon steel — effectively negligible. Field data backs this up: the SACROC CO2 pipeline, built in X60 carbon steel and held to a 50 ppm water limit, corroded at just 0.25–2.5 µm/year over twelve years.
• Water-saturated supercritical CO2: X65 carbon steel corrodes at about 0.38–1.0 mm/year — one to two orders of magnitude faster.
• A water-rich phase: corrosion can reach 5–30 mm/year, which no line pipe wall tolerates for a design life.

Note what this reframes. The choice between carbon steel and a corrosion-resistant alloy is really a choice between dehydrating the CO2 and building the whole line out of expensive alloy. For the great majority of dense-phase CO2 pipelines, dehydration wins on cost, and carbon steel is the correct, field-proven answer.

How Dry Is "Dry"? The Water-Content Question

Here is where specifications go wrong, and where being precise is worth more than being confident. There is no single universal water limit for CO2 pipelines. The figures in circulation span an order of magnitude:

• 50 ppm — the strict end, recommended by the ENCAP project and used by several operators.
• 500 ppm — the value the DYNAMIS project raised the limit to, and the figure most commonly quoted in the literature — though, as the literature itself notes, with limited scientific justification for that exact number.
• ~1,700 ppm — roughly the amount of water pure CO2 can actually hold in solution across CCS pressures and temperatures (about 5–85 °C, 7.3–30 MPa) before free water precipitates.

Impurities Change Everything

A captured CO2 stream is not pure CO2. Depending on the capture process, it carries some combination of water, O2, N2, H2S, and — the dangerous ones — SOx and NOx. These do not just ride along; they change the corrosion problem:

• NO2 is the worst actor. In wet CO2 it forms nitric acid and collapses the pH. Around 100 ppm of NO2 has been measured driving carbon-steel corrosion on the order of 11.6 mm/year — dramatically worse than the same concentration of SO2.
• O2 raises wet-CO2 corrosion rates by roughly 50–120%.
• SO2 forms its own acids, and H2S, where present, brings sulphide stress cracking into scope under NACE MR0175 / ISO 15156.

This is why two CO2 streams at the same water content can need different materials. A high-purity CO2 stream and a flue-gas-derived stream carrying SOx, NOx, and O2 are different design problems, and the pipe grade has to be chosen against the actual composition, not the label "CO2."

The CO2 Transport Pipeline — Carbon Steel, If Dry

For the pipeline itself, the material logic resolves cleanly:

• Dry, dehydrated, impurity-controlled dense-phase CO2: carbon steel line pipe — typically API 5L X65 PSL2 — is the standard, field-proven choice. It is what the operating CO2 pipelines are built from.
• Wet or impurity-laden CO2: the usual answer is not to change the pipe but to fix the stream — dehydrate it and control the impurities to a defensible limit. A CRA line, or a carbon-steel line with a corrosion allowance and tight monitoring, is reserved for cases where dry conditions genuinely cannot be guaranteed.

For the grade itself, see the API 5L X65 line pipe specifications guide →, and for why CO2 service should be PSL2, the PSL1 vs PSL2 selection guide →.

But Strength Isn't the Design Driver — Fracture Control Is

The corrosion answer is only half the pipe. The property that most distinguishes a CO2 pipeline from a natural gas line is running ductile fracture control, and it is the thing a strength-only design misses.

When a pressurised pipeline is breached, the contents decompress and a crack can run along the pipe if the steel cannot absorb energy fast enough to arrest it. In natural gas, decompression drops the pressure quickly and the driving force fades. Dense-phase CO2 behaves differently: as it decompresses it hits a phase change that holds the pressure up on a plateau, sustaining the force behind the crack for much longer. The result is that a running fracture in a CO2 pipeline is harder to arrest, and the toughness needed to stop it is higher than for natural gas at comparable conditions — so a wall sized purely for pressure containment can be inadequate.

Critically, the fracture-arrest models validated for natural gas (the Battelle two-curve approach) are known to be non-conservative for CO2 — they under-predict the toughness a CO2 line actually needs. This is why CO2 pipeline material selection is governed by fracture control, and why the design toughness and wall thickness, not the grade's yield strength, often set the specification. DNV-RP-F104 is the recommended practice that addresses these CO2-specific design and material aspects.

The CO2 Injection Well — Casing and Tubing

At the injection well, the same dry-versus-wet logic applies to the tubulars, with two well-specific twists:

• For dry CO2: carbon-steel OCTG — grades such as L80 or N80 — is generally suitable for the injection string.
• Watch low-temperature toughness. Injected CO2 cools through Joule-Thomson expansion, and during venting or blowdown a wellhead and upper tubulars can chill well below ambient. That brings low-temperature toughness and brittle-fracture avoidance into scope for the tubulars and wellhead, which a standard sweet-service specification may not cover.
• For wet, impure, or dual-service wells: where free water cannot be excluded, the stream carries aggressive impurities, or the well also produces formation fluids, a CRA — 13Cr, Super 13Cr, or duplex — is the safer choice. This is the point where a CCUS injector converges with conventional CO2-corrosion material selection — the same 13Cr tubulars we supply for CO2-bearing production wells. For an African operator we shipped 3,800 pieces of L80-13Cr flowline tubing, 4½" plain-end, chosen because 13Cr forms a passive chromium-oxide film that arrests CO2 corrosion without ongoing inhibitor injection — the same passive-film logic that governs material choice for a wet-CO2 injection string. See the CRA grade selection guide for CO2 and H2S → and Super 13Cr tubing for CO2 corrosion →.

Elastomer seals and packers deserve a separate note: supercritical CO2 permeates elastomers and can destroy them by explosive (rapid gas) decompression, so seals must be specifically qualified for CO2 service — a metallurgy-adjacent issue that catches out projects treating a CO2 well like a gas well.

The Standards to Cite

CCUS material selection sits across several references, and knowing which says what avoids over- or under-specifying:

• DNV-RP-F104 — design and operation of CO2 pipelines, including materials and the CO2-specific properties (fracture, phase behaviour). The primary document an EPC cites for the pipeline.
• ISO 27913 — CO2 transport systems (pipelines).
• NACE MR0175 / ISO 15156 — applies where H2S co-exists in the stream, for sulphide stress cracking.
• API 5CRA / ISO 13680 — the standard for CRA tubulars, where the injection string needs an alloy.

One point ties them together: none of the major references fixes a single mandatory CO2 composition. DNV, ISO 27913, and the EU CCS Directive (2009/31/EC) all require the operator to assess CO2 stream quality on a project-by-project basis, which is exactly why the pipe cannot be chosen from a rule of thumb.

When NOT to Default to a Corrosion-Resistant Alloy — and When You Must

• Do not default to CRA for a dry CO2 pipeline — carbon steel is field-proven for dehydrated dense-phase CO2, and dehydration is usually cheaper than an alloy line.
• Do not specify carbon steel for a wet or high-impurity stream — free water plus NO2, SO2, or O2 will consume it; either dry and clean the stream or move to a CRA.
• Do not size a CO2 pipeline on pressure containment alone — running-fracture toughness can govern, and the natural gas models under-predict what CO2 needs.
• Do not carry a sweet-service well spec straight onto a CO2 injector — add low-temperature toughness for Joule-Thomson cooling and qualify elastomers for explosive decompression.
• Do specify a CRA where free water genuinely cannot be excluded, impurities are aggressive, or the well runs dual service.

The Recommendation, in One Line

Dry, dehydrated, impurity-controlled CO2 runs in carbon steel — API 5L X65 line pipe and L80/N80 injection tubulars — designed for fracture control on the pipeline and low-temperature toughness at the well; wet or impure CO2 means fixing the stream or moving to a CRA. The pipe follows the CO2 specification. For the broader energy-transition context, the same "the fluid decides the pipe" logic applies to hydrogen-ready pipelines →, and CRA options are compared in the duplex 2205 and super duplex 2507 selection guide →.