CO2-grade drilling package addresses safety concerns of CCS wells

According to Zach Bruton, Noble’s senior business developer, the equipment package is designed to integrate with existing rigs while providing advanced CO₂ handling capabilities. It will include:

• An electrical shut-in device to isolate the legacy well control equipment from CO₂ exposure while directing any CO₂ flow through the new system;
• A choke mitigation station to manage temperature drops caused by the Joule-Thomson effect, which can lead to rapid cooling of CO₂, potentially causing material embrittlement or hydrate formation; 
• A mud gas separator and degasser unit, engineered to handle CO₂’s solubility and toxicity; and
• An alternative vent line to safely eject processed CO₂ below the hull of the rig, preventing gas from settling on the drill floor.

Retrofitting this equipment, he stressed, would not require any selected rigs in Noble’s fleet to be idle for long during installation.

“This was part of the reason for the modular build concept," he added. "It only requires non-invasive upgrades to an existing rig, which can be done while it’s on another job. Plus, the modular CO₂ drilling package can be fully tested shoreside, so installation will only take days and not weeks when the time comes.”  

Guidance and game plans

For last year’s qualification program, Noble set out to understand all possible requirements for a rig working in a CO₂ environment, with DNV’s subject matter specialists providing guidance.

“We went into all the safety aspects, well control and rig challenges the new CO₂ testing required and how to integrate it into a rig," Bruton said. That’s the physical equipment, but at the same time, the existing onboard process will have to be updated. It was a cascading waterfall of trying to understand the equipment challenges, and integrating them with a ton of manual work. But that’s all wrapped up now, so we feel confident that we’ve correctly assessed and reviewed all the different challenges for the rig. 

“With DNV, we did the whole review process, identifying up to 50 key action items. They know what needs to be done now; they have gone through all the challenges. It’s up to us now over the next three years to enact all these measures. That includes internal research in order to make this happen by 2028-30 timelines.”

Technology qualification for the new modular equipment package started last November. Noble has discussed its plans with more than 90% of the players involved in CO₂ storage or considering this market, Bruton said.

“We organized a workshop where we brought in offshore drillers, different operators and others," he continued. "This idea of doing a modular drilling package came about because the notion of building a CO₂-proof BOP rig was simply prohibitive. Instead, we reasoned, what if you just picked a couple of key aspects like the little sub-systems that do need to be upgraded, then added a CO₂ diversion system so that the CO₂ won’t have to be handled by the well control? It can be processed and the mud can be cleaned in this new drilling package. Then the cleaned mud can be directed into the system and back into the legacy systems. That idea was first kicked around in June-July last year.

“It’ll take a couple of years to manufacture this equipment package. Operators we have talked to like the fluidity of the concept. It’s modular, with minimal retrofitting work. They also appreciate that this equipment can be ready on the shore side when needed. So, for example, if you found yourself having to perform a CO₂ intervention job, or to drill a relief well, this system could be called upon and plugged in within a week.”

No special rigs should be needed to drill the initial carbon capture and storage (CCS) wells or to recomplete old legacy wells prior to CO₂ injection starting. But no CCS project has progressed from Phase 1 to injection to Phase 2 drilling. For the current developments, Bruton explained, “people typically have line of sight for 2027-28 for first injection. That creates a whole new ecosystem of uncertainty. These guys are saying to us, what if I need to do an intervention on the second day?

“We don’t know the likely levels of CO₂," Bruton said. "There are no guarantees with upstream systems. There are also a lot of nuances around CO₂ impurities. It’s amazing how the phase changes, and the diagram can change just by introducing a little SO_X or NO_X or some other heavy metals. So the operators are telling us, I may need to call you right after we start injecting just to clean the well or to take action if something goes wrong. They want to be able to re-engage with these wells if a situation arises.”

He continued, “Our game plan is to have several of our jackups/floaters based in the North Sea region pre-prepared to take on the CO₂-grade system, with the personnel trained to use it. In support of this, we envision having a couple of the modular packages on standby and ready to go once the operators start injecting at their sites. With the 2027-28 timelines, it’s imperative for both suppliers and operators to make sure everyone knows what they’re doing and get the ball rolling this year so that we can hit those deadlines. That’s why we’re really trying to develop partnerships with the operators now.”

Bruton sees scope for expanding the industry’s current practice of pooled access to emergency equipment such as capping stacks.

He added, “These assets are shared across the operators…they all pay into the equipment, they call upon it, they use it. I’d love to have be able to adopt a similar model that’s efficient for our CO₂-certified rigs and to be able to plan ahead. Ideally, an operator might say, 'I need these units for six months in 2027; can we figure out how to work it into your schedule?' That way we could work effectively with the client to make sure it happens when the time comes.”

Industry alignment and collaboration needs

David Buchmiller, DNV's principal engineer in drilling in well and technology, said his company had held discussions with other drilling contractors and operators on the CO₂ unknowns, “similar to our engagement with Noble and bp, but those talks have not been as detailed or come so far as this development."

He continued, "Since Noble first came to us two years ago, we have worked collaboratively on identifying the risks, differences and nuances of CO₂-related well control for personnel, equipment and operations. It’s something DNV does see as new and challenging to the industry.

“There are some operators that have the ramifications clearly on their radar. Others think in terms of projects that are close to startup such as Northern Lights in the Norwegian North Sea, or those where the focus has been purely on the first wells that need to be put in for CO₂ injection. I do see more operators starting to realize that they may need interventions sooner than they expected. Noble and bp have been great about going first and pushing the agenda. I’m not personally aware of too much other work on this subject within the industry, aside from some well control, PHD-type studies, but it’s a bit fragmented. There appears to be less industry alignment and collaboration than there should be.”

For the CO₂ Certified Rig program, the partnership followed the procedures covered in DNV’s Recommended Practice-RP-A203 for Technology Qualification.

“It was a chicken and egg situation,” Buchmiller explained. “This is the standard methodology for situations where you don’t have standards for new technology or industry guidelines available. That systematic approach is a good way to take a new development forward, also aligned with the philosophy of many regulators as a method for implementing new technologies. During the process, DNV systematically examines the new technology and the associated threats. For the Noble project, we considered the materials selection, corrosion aspects, flow technology, to determine if there were flow-related issues. 

“Developing a new technology is dependent on the complexity. Here, there were a lot of building blocks that were well known, but how to apply them with a different application was what was really new. In general, the process followed normal timelines and at a good project speed. It wasn’t a full test, full functioning or piloting program, more early concept proving. We facilitated the risk and hazard identification process, systematized this and evaluated it continuously, systematically throughout the project to understand the effects on operations, equipment, and the impacts on rules, regulations and HSE. Noble’s list of wants for the CO₂-grade drilling package shows some of the risks we came up with to consider, such as toxicity, vent lines [and] the safety focus.

“One of the key takeaways we’ve had so far is, when you think about well control of CO₂ versus, say, methane or hydrocarbon well control—if you have a gas well control incident, the gas will go up, whereas CO₂, being heavier than air, goes down. That has a different impact on rig safety, rig procedures, overall general preparedness and the mindset that individuals on the rig should have.”

In February, Nishant Koti, DNV's project manager/principal engineer in Oslo, and his team were updating the DNV drilling plan DNV OSE101 to serve as a qualification process for a CO₂ drilling unit.

We have taken the learnings from this technology qualification,” Koti said. “Based on these, we have made our first attempt at coming up with the rules for drilling equipment or drilling facilities specifically for CO₂ wells. Upon compliance with these rules, the units may get a Drill (CO₂) class notation.”

In February, the draft rules were made available for questions or comments during a six-week period. After reviewing the feedback and making any changes, the plan is to publish “DNV ES101 with requirements for CO₂ wells” by July 1.

Buchmiller and his team have also held talks on the development with various offshore safety authorities such as Havtil in Norway. “They are very supportive. They think that it’s good that the industry is starting to analyze and identify threats and to take these risks seriously. But they depend more on the industry to advance this process; they’re more observers.

“This is one of the least recognized areas within drilling wells for CO₂ storage—legacy wells, integrity, intervention wells. The design has had a lot of coverage, also the materials selection. But the drilling risk of CO₂ wells is an under-appreciated topic where the industry really needs to move forward.”