CCUS Well Design: FAQs

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Carbon Capture, Utilization, & Storage (CCUS)

Frequently Asked Questions

The questions below were submitted by viewers of the World Oil Live Webcast “CCUS: Best Practices for Well Construction and Design”.

Answers have been provided by panelists Dan Morrell, Tommy Najar (CRA), and Lindsay Longman (Gulf Coast CO2 Engineering) in follow-up of their discussion covering the unique technical and regulatory challenges surrounding CCUS well design as these projects continue to gain momentum in the energy industry.

For those who missed the live discussion, full access to the recorded webinar is available here: CCUS: Best Practices for Well Construction and Design

What is the meaning of Carbon Sequestration?

Carbon sequestration is the process of capturing and storing atmospheric carbon dioxide. In our case, to store the CO2 in geological traps. Potential sources of CO2 are electric generation, such as gas and coal, cement, hydrogen plants, chemical plants, and biofuel plants.

Is the CO2 injected in a gaseous or liquefied state?

CO2 has to enter the reservoir in a liquid supercritical state. There are cases where it is gas at the wellhead but becomes supercritical at the reservoir with pressure and temperature changes. Planning is typically to have the CO2 in a supercritical state from the CO2 source plant.

Is CO2 leakage from the reservoir a concern?

It is the number one concern. CCS regulation and permitting process is set up to identify and understand the potential for CO2 leakage from the reservoir.

What is the typical life of a sequestration well?

Injector, 20 years injection and 30 years monitoring, but if the monitoring looks good, it allows for a faster P&A. Monitor wells 50 years, though California requires 100 years of monitoring.

If CO2 alone isn't corrosive, is there a way to purify CO2 before injection?

It’s correct that CO2 in its pure form is not corrosive. CO2 becomes an issue when exposed to water as it then forms carbonic acid. Water is typically present in the formation and/or possibly in the CO2 injectorate. If the water vapor in the injectorate condenses to form water beads, then sufficient water is present to form carbonic acid and any of the impurities in the CO2 stream that may react with water will also be an issue.

Noting that dry CO2 does not corrode, how dry is dry? (100ppm wtr, 50ppm wtr, 25ppm wtr?)

As long as the water stays in vapor in the CO2 stream, you are dry. Corrosion starts once the water vapor drops out and forms droplets on the casing/tubing material and begins wetting the material. The carry capacity of the CO2 stream will depend on volume, temperature, and pressure. So, in the right conditions, any of those values could result in corrosion. Offhand, in a typical scenario, there is not enough water vapor in the values referenced to drop out, but conditions would need to be evaluated for the aforementioned factors.

Is there an industry standard similar to NACE which provides guidelines on how to test the materials for CCUS applications? Considering the O2, H2S, NOx, H2O, H2, etc.? Is there a specific test matrix?

AMPP published AMPP GUIDE 21532: Guideline for Materials Selection for CO2 Transport and Injection in June 2023 to provide guidance on materials selection and corrosion control for engineers in the design and identification of operating limits for projects that involve CO2 transport and injection. It should be used as a guide to help identify specific requirements which can be tailored for each project rather than as definitive requirements used straight from the document.

However, it is a rapidly growing subject area and much exploratory technical work is still being executed, and as such this document should be seen as a starting point with future updates and new insights to be expected.

What are the trade-offs between surface treating of the gas to be injected vs. the cost of high-alloy tubulars?

The biggest trade-off is cost. Depending on the CO2 source plant and what is causing the generation and associated impurities, literally, tens of millions of dollars can be spent on scrubbing equipment. Increasing your downhole material capability may only be a few million dollars more.

With that being said, the reservoir needs to be compatible with your CO2 stream. You do not want something so toxic that if there is a surface leak it could cause issues. Pipelines can typically be adapted with minimal extra cost to handle a more corrosive stream.

Are internally coated tubing products, for the injection string, an option, or is cra material selection the primary integrity approach for CO2 injection streams with impurities?

Internally coated tubing could be used above the packer. Materials below the packer (and including the packer) need to have appropriate base materials. Casing that contacts the reservoir also needs to have appropriate base material as the OD is exposed and will likely probably be perforated.

Our team has supported many SWD, SWI, EOR, and now CCS projects. We discussed IPC briefly in the panel discussion, but there are concerns about IPC as compared to a cra. IPC is less money upfront, however, there is a risk to using them long-term. Well intervention (coil tubing, slickline, eline) can cause wear in the coatings. Any quality issue in the application of the coating (i.e. a holiday) could cause a problem. The connections themselves also have to be closely considered. Also, if IPC is being run above the packer, it is important to look at the long-term investment picture to replace the tubing in the event of a future failure. The overall cost of that operation (and downtime to injection) can often be far more expensive than the initial investment of cra tubulars.

Does the weight of the string play any critical role in reducing or accelerating the corrosion/cracking/yield change effects? Are customers looking at non-metallic solutions?

Stresses play an important part in corrosion and need to be factored in. Non-metallic solutions can be used, but they typically cannot handle the required lifetime of the well. (50 years or pressure of well design.) The higher the tensile stress, whether from hanging weight or pressure, the greater the risk of environmental cracking.

What's the most common wellbore design of existing CCS wells in injection interval (barefoot or cemented casing with perfs?) What are the pros/cons of each?

Cemented casing with perfs is more common. Barefoot does not provide as much control of CO2 mitigation. It is allowed, however, most designs seen for barefoot have been in directional and horizontal applications. Casing with cement would provide better formation support around the wellbore and control of the injection depth.

Is stage cementing considered in the wellbore design?

Most definitely, since there is a requirement to have cement to surface on the surface casing and production (long) string, then stage tools are permitted by EPA. The number of stage tools is not defined, so the important thing is that cement reaches surface with good cement sheaths. Issues with just running staging tools can arise, so it is recommended to run a casing packer below as known support.

What is needed for a packer fluid from a design perspective?

The EPA has some requirements on this. Packer fluid must be a CO2-buffered brine and should be weighted to provide a positive pressure on the top of the packer. As the annulus must be monitored for pressure at the surface, it’s also important to understand the effects of temperature on the expansion and contraction properties of the fluid.

What do you see as the most common failures during the CCUS campaign? Is it mainly failure of tubings and valves? Annular pressure build-up? Or the max pressure in the reservoir exceeding pump capacity?

The most common CCS failures in existing projects have been the development of corrosion in the tubulars. Annular pressure build-up would come in second.

Is CO2 injection pressure above or below frac pressure to design the tubular accordingly? How does frac pressure impact well pressure and tubular design?

EPA regulations state that well pressures cannot exceed 90% of formation fracture pressure. California limits it further to 80% of fracture pressure.

Is there any need/requirement to perforate deep monitoring wells in the injection zone for sampling? This is targeting fluid samples in the injection zone, in addition to Temperature and Pressure monitoring.

Yes, this is a requirement for the Deep Monitoring Well, the Above Confining Zone Well, the USDW monitoring, and Groundwater Wells. The USDW and Groundwater Monitoring Wells do not require temperature and pressure monitoring, but they do require sampling.

What are the liabilities of old P&A wells for new CCUS projects? (in terms of current regulations)

Legacy wells in the Area of Review are subject to a pressure plume from injection and CO2 plume. The pressure plume probably will not be a big issue, but the EPA cites examples of blowouts from abandoned wells and scenarios where P&A records did not truly reflect what was in the hole (missing plugs, improper depth, forgotten fish in the hole, etc.)

As the holder of the CCS permit, you are responsible for the legacy wells in the Area of Review. Since legacy wells are not typically designed for CO2, the cement and casing will be prone to CO2 corrosion and eventually fail. This leaves a potential path to the USDW (deepest fresh drinking water zone defined by 10,000 ppm total dissolved solids). CCS permitting is designed to understand potential leak paths to the USDW and determine if they can be successfully mitigated. If they cannot, the project is killed. If the project is allowed to go forward and the legacy wells show leakage, the whole project will be shut down until resolved. No tax credits are given unless CO2 has been injected into the ground which may translate to a huge potential for loss of revenue. There are also the liabilities local government may litigate due to potential contamination of their drinking water.

Remediating the legacy wells to be suitable for CO2 exposure can be expensive and in some cases, companies have put their projects on hold or closed them due to the potential costs involved. It’s one of the reasons you will typically see CO2 projects in remote areas with few wells. If they are in an old oil field they will typically choose a reservoir below the existing wells in the area. They may also convert an old EOR field as the wells were set up for CO2.

Is there a recommended approach to assess legacy well leakage risk? What are the dominant factors?

1. Yes, in general, you need to get the current well P&A status and make sure you have the directional surveys.
2. Assess any sidetracks, their depth, and where the sidetrack occurred. If the sidetrack is above the caprock, and the original hole and sidetrack both penetrate the caprock, then typically this well will not be considered a mitigation prospect as you cannot reenter the original hole to mitigate for CO2 contact. If possible, you would shift the plume away from this well.
3. Assess any fish and determine they have been P&Aed properly. If the fish has penetrated the caprock then the top of the fish needs to be cemented in the caprock.
4. Assess if the plugs, casing, and cement can withstand additional pressures due to the injection.
5. Assess if the plugs, casing, and cement are going to be exposed to CO2, and, if so, if they fail what is the path for CO2 mitigation to the Drinking water zones (defined by 10,000 ppm Total dissolved solids.)
6. Due to new state regulations in the US, if you enter an old P&A well you need to upgrade it to current standards.

Are currently abandoned wells in the area also of consideration for the state?

Abandoned wells in the Area of Review become the primary responsibility of the CCS permit holder. If the wells have a current owner, then the CCS operator needs to negotiate liabilities with them or sell. In cases where the previous operators are no longer around, the state has taken ownership and the CCS operator will need to negotiate liability issues with the state. Oddly enough, states may be more liberal about liabilities on these wells as the CCS projects are considered important to them.

Continuous CO2 Injection vs. Cyclic Injection makes a difference for steel selection, e.g. steel with Cr25 can be suitable for Continuous Injection while it is questionable for Cyclic Injection. What are your experiences/recommendations?

Operationally speaking, any cycles will be due to quarterly and annual maintenance, which should not cause major issues. However, that assumes you can maintain the planned stream specifications. Most of the cyclical stress would happen in the tubing, which can be replaced, so material options are available, with respect to well life expectations. Cyclic injection may also increase risk of introducing water, resulting in more corrosive conditions, which may require a more robust alloys selection. That leaves the casing below the packer, which causes more concern with the integrity of the cement than the casing, provided a suitable material is used.

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