Carbon capture is no longer a concept under debate. Projects are moving, permits are being filed, and the questions engineers and procurement teams are working through have gotten specific fast. The material selection decisions being made now will determine well integrity for decades.
The following draws from a panel discussion hosted by World Oil — “CCUS: Best Practices for Well Construction and Design” — featuring Dan Morrell, Tommy Najar of Corrosion Resistant Alloys (CRA), and Lindsay Longman of Gulf Coast CO2 Engineering. The questions came directly from the industry. These are the answers.
CCUS FAQS
Carbon sequestration is the capture and long-term storage of atmospheric CO2, typically underground in geological formations. In the oilfield context, that means injecting CO2 into a reservoir and keeping it there. The well design, material selection, and monitoring program all follow from that single requirement: it has to stay down.
It has to enter the reservoir in a liquid supercritical state. In some cases it starts as a gas at the wellhead and transitions downhole, so the injection string needs to be designed around that phase change. This isn’t just a fluid dynamics question. It affects temperature, pressure, and corrosion risk all the way down the string.
It’s the primary concern in every CCS permitting process. Regulations are specifically structured around identifying and understanding potential leakage pathways before a permit is issued. This is one reason well integrity, from tubular selection to cement design, carries more regulatory weight in CCUS than in conventional injection applications.
A typical sequestration well is designed for roughly 20 years of injection, followed by 30 years of monitoring. That’s a 50-year commitment on the tubulars and completion equipment. If monitoring data supports it, regulators can allow permit transfer earlier, but you’re selecting materials for a multi-decade service life from day one.
Yes and no. Pure CO2 isn’t the issue. The problem is water. Once CO2 combines with water, you get carbonic acid, and the corrosion risk becomes real. Purifying the CO2 stream before injection is technically possible, but the economics depend heavily on the source and what’s generating the contamination in the first place.
There’s also a reservoir compatibility piece. You can’t just strip impurities and call it solved if the resulting stream still reacts with formation fluids. The whole system has to be considered together.
The threshold is phase-based, not a fixed PPM number. As long as water stays in the vapor phase within the CO2 stream, you’re operating dry. Corrosion starts when water drops out and forms a liquid phase. The actual ppm level where that happens depends on pressure and temperature conditions, which is why every well needs its own analysis rather than a one-size cutoff.
Yes, and it’s an area where the standards are actively evolving alongside the projects themselves.
AMPP Guide 21532, published in June 2023, was the first dedicated framework for materials selection and corrosion control for CO2 transport and injection. It remains a useful reference, but the more significant development is AMPP SP21632, published in July 2025. This is a full standard practice, not just a guideline. It sets requirements and recommendations for materials selection and corrosion control across the full CCS project chain, from CO2 processing and compression through transport and injection, with a focus on ensuring long-term integrity through an acceptable CO2 specification and defined failure mode controls.
SP21632 is the first in a growing suite. Additional documents currently in development include SP21632-2 (CO2 specification definition and control), SP21632-3 (materials selection and testing for CO2 injection in wells), and SP21632-4 (materials selection and corrosion control for CO2 transport). A separate corrosion testing document, AMPP Guide 21577, covering laboratory corrosion testing for CO2 transport and injection, is also in development, with cracking testing to be incorporated into SP21632-3.
Once the full suite is published, AMPP Guide 21532 will be superseded. For now, both documents are applicable. Teams selecting materials for CCUS service today should be working from the most current published guidance and keeping a close eye on what’s still in development.
Cost, primarily. Treating the CO2 stream upstream can reduce the corrosivity of what goes down the well, but treatment infrastructure has its own capital and operational cost. Higher-alloy tubulars cost more upfront but eliminate ongoing treatment dependency. Most decisions land somewhere in between, with partial treatment and a material selection that accounts for residual impurity levels.
The reservoir compatibility issue applies here too. You still need the injection stream to be compatible with formation conditions regardless of how you approach surface treatment.
Internally coated tubing can work above the packer. Below the packer, and including the packer itself, the corrosion exposure is more severe, and that’s where CRA material selection becomes the more reliable integrity approach. Coatings have been discussed in the industry, but track record matters. CRA teams have supported saltwater disposal, saltwater injection, EOR, and CCS projects across a range of conditions, and the consensus is that coatings below the packer carry more risk than they’re worth on long-life sequestration wells.
Stress is a real variable and has to be factored into any complete corrosion analysis. Stress corrosion cracking is a known failure mode in CRA tubulars under certain conditions. Non-metallic solutions can be viable for some applications, but they come with their own load limitations and need to be evaluated against the full well design.
Cemented casing with perfs is the more common design in existing CCS wells. Barefoot completions don’t provide the same level of control over CO2 migration, and the regulatory environment increasingly favors designs with clear zonal isolation. The trade-off is cost and complexity, but most operators working in a serious CCS regulatory framework end up at cemented casing.
Yes, routinely. Surface casing typically requires cement to surface, and production casing often follows the same requirement under CCS permitting. Stage cementing helps ensure full coverage in long casing strings where a single-stage job might not reach.
The packer fluid must be a CO2-buffered brine, weighted to maintain pressure balance with the wellbore. The EPA has specific requirements on this and they’re not optional. It’s part of what gets reviewed in the permitting process. Getting the packer fluid design right matters for both regulatory compliance and long-term well integrity.
Corrosion in the tubulars is the most frequent issue seen in existing projects. Annular pressure build-up comes up as well. Most failures trace back to either an underestimation of water presence in the CO2 stream, or material selection that wasn’t adequately matched to the actual injection conditions. That’s exactly why the upfront analysis is worth doing carefully.
EPA regulations cap well pressure at 90% of formation fracture pressure. Some states, California included, apply stricter limits. The tubular design has to account for the full pressure range, not just operational steady-state, but the transient conditions that can occur during startup, shut-in, and maintenance cycles.
Deep monitoring wells typically require perforation in the injection zone for fluid sampling, in addition to temperature and pressure monitoring. There are also requirements for Above Confining Zone monitoring wells and USDW (Underground Sources of Drinking Water) monitoring. The monitoring program is part of the permit, not an afterthought.
This is one of the more complicated liability questions in CCS project development. Any legacy wells within the Area of Review are subject to the CO2 pressure plume from injection. As the CCS permit holder, you’re responsible for them, including remediating them to be suitable for CO2 exposure if they’re not already.
That can be expensive. In some cases, depending on the age and condition of those wells, it becomes a project-level decision about whether the sequestration site is economically viable. It’s worth doing the legacy well inventory early, before the permit is far along.
Start with the current P&A status and confirm you have directional surveys showing where those wellbores actually go. Identify what the original casing and cement design was, whether the cement is still competent, and whether the wellbore materials are compatible with CO2 exposure. The dominant factors are cement integrity, casing condition, and proximity to the CO2 plume.
No. Abandoned wells within the Area of Review become the primary responsibility of the CCS permit holder. If the state plugged them, there may be some recourse or shared liability depending on jurisdiction, but in general, the permit holder inherits the risk. This is another reason a thorough AOR assessment before permitting is not optional.
For typical CCS operations, cycles due to quarterly or annual maintenance shouldn’t significantly change the material selection decision. Where cyclic injection becomes a real concern is in more aggressive cycling regimes. In those cases, 25CR duplex alloys need closer evaluation. They can be appropriate for continuous injection but require more scrutiny under true cyclic conditions. The recommendation is to discuss the specific injection schedule with a materials engineer before finalizing selection.
The Bottom Line for Procurement and Engineering Teams
CCUS well design is a discipline that’s still being built in real time. Standards are developing, regulators are learning alongside operators, and material selection decisions are being made with limited precedent compared to conventional oilfield work. That’s exactly the kind of market condition where having access to current supply, verified specs, and direct relationships with qualified suppliers matters more than it does in a mature commodity market.
PipeSearch connects buyers and suppliers across the CRA and specialty tubular market, with real-time visibility into availability, specs, and the conversations shaping procurement decisions right now. Still have questions? Speak to an expert on our team.
Content developed in partnership with Corrosion Resistant Alloys (CRA), a leading manufacturer of corrosion resistant alloy tubulars for oil and gas, CCUS, and industrial applications.
