CO2 Pipeline – A Critical Link of CCUS, but Are We yet Ready for Safe Operations?

Back to the future?

The genesis of carbon capture technologies dates back to the 1920s, primarily emerging from the need to separate CO₂ from natural gas. By the 1970s, this technology had advanced to the point of capturing and utilizing CO₂ for Enhanced Oil Recovery (EOR). In 1977, the idea of intentionally capturing CO₂ to combat climate change emerged, but it was not until 2005 that governments formally recognized the need for industrial-scale carbon capture and storage (CCS) deployment. Longer ago than I care to admit, I remember bold statements from some prominent global leaders:  “All existing coal-fired power stations should be retrofitted with CCS, and all future coal-fired power stations should be built with CCS.”  Between 2005 and 2015, CCS projects flourished, and research into safe CO₂ transport by pipeline surged. Yet, we of course all know what happened back then, and CCS became a story of unfulfilled promises.

Today, CCUS has emerged as one practical solutions for reducing industrial greenhouse gas emissions from hard-to-abate sectors. Scientific and policy advancements throughout the world have accelerated the development of regional hubs with suitable underground storage geology, reigniting interest in CCUS and the critical role of CO₂ pipelines for transporting captured carbon over long distances. However, old challenges remain, and ‘new’ challenges have appeared on the radar. As the energy industry faces greater public scrutiny, the drive for ‘zero incidents’ and safe integrity management practices are even more critical to its sustainability. The ongoing public response and debate against the plans for U.S. CO₂ pipeline network expansion following an incident in Mississippi February 2020 underscores this. 

Challenges – A long road to safety

Currently, the CO₂ pipeline landscape consists of over 7,000 kilometers, with the overwhelming majority operated in the United States (U.S.). These pipelines range in diameter from small (4”-8”) to large (24”-30”) and have been in operation for 30-50 years, and many have been subject to regular internal inspection. According to the U.S. statistics, the operational experience is generally positive, with very few incidents. Given this, it is only natural to question the turmoil and uncertainties that surround safely operating dense CO₂ pipelines going forward. A key aspect of the existing U.S. CO₂ pipelines is that they transport CO₂ captured from natural gas production, ammonia, and ethanol production. However, as we shift to capturing CO₂ from industrial sources containing a wider variety of impurities, ‘new’ challenges emerge. The core of the next generation of CO₂ pipeline projects will aim at transporting man-made CO₂, which will carry a broader range of impurities (e.g., SO_X, NO_X, H₂S, O₂, H₂, CO). These can have significant implications for the realization of pipeline internal corrosion, cracking, and running ductile fracture, and how these are safely managed during design and operational stages. 

Corrosion & Acid Drop-Out: The management of internal corrosion in pipelines transporting anthropogenic CO₂ is a prominent topic. A key facet is the possibility of forming and dropping strong acids, such as sulfuric and nitric acids, due to the presence of SO_X and NO_X. Much research has been conducted to establish safe and practical specifications (composition limits) to address this issue. However, gaps remain, and the findings are limited by experimental challenges, artifacts and test conditions. For CO₂ applications, the motivation for enhanced detection, sizing accuracy, the ability to characterize corrosion profiles, and less conservative integrity assessment methods becomes even more vital due to the complex nature of the corrosion profiles (‘pits-in-pits’) and the aggressive nature of the corrosion processes. In this context, alternative inspection solutions, such as MFL data fusion, could play a valuable role in enhancing reliability and rationality of integrity management plans.

Hydrogen & Cracking – Again: H₂ can be present as a contaminant in CO₂ captured, e.g., from Steam-Methane Reforming processes (blue hydrogen). A growing body of evidence suggests that H₂, even at levels as low as <1% by volume, can impact the manifestation of hydrogen embrittlement (HE) and hydrogen-assisted fatigue cracking (HAFC) during CO₂ transportation. So far, there does not seem to be a minimum threshold below which the problem does not occur. Research is underway, and it is important to acknowledge that the rigorous diligence that the industry has undertaken to address integrity challenges in transporting gaseous hydrogen and hydrogen blends will be equally essential for CO₂ pipelines. We are working with the PRCI – Emerging Fuels Institute (EFI) on this issue for CO₂ pipelines.

Fracture Control: Running ductile fracture is a critical subject in the design and integrity assessment of transmission pipelines. Traditional fracture control methodologies, including the Battelle Two Curve Method (BTCM) developed for natural gas pipelines, are not directly applicable to dense phase CO₂ pipelines. These methodologies are often non-conservative because of the long plateau associated with high saturation pressures as a result of phase change during decompression. Although several correction factors have been introduced to extend the use of BTCM to dense phase CO₂, the resulting empirical correlations remain limited by the small number of full-scale test data. The methodologies presented in DNV-RP-F104 and ISO 27913 aim to predict whether a running ductile fracture in a CO₂ pipeline will arrest or continue propagating. Similar to BTCM, these approaches are empirical and restricted by limited experimental databases used for their calibration. Their application is further constrained to a narrow range of pipeline configurations, specifically large-diameter pipes (16”-36”), thick walls (10-26 mm), and high-strength grades (X60 to X65) and submerged-arc welded pipes (SAW). This limitation reduces their suitability for both new pipeline construction and conversion projects, in which the pipe diameter, wall thickness, or material grade falls outside the established validity range. Ongoing research aims to extend the validity range through additional full-scale testing and the development of more reliable alternatives that lessen dependence on costly experimental programs. A promising approach involves fluid–structure interaction (FSI) simulations that combine Computational Fluid Dynamics (CFD) and Finite Element Analysis (FEA) with advanced ductile damage and fracture models, providing a more physics-based framework for predicting running fracture behavior in dense-phase CO₂ pipelines.

A major cornerstone of addressing these challenges is defining a quality specification for limiting impurities in CO₂ streams. Overall, there is a general industry appetite to design a ‘one-size-fits-all’ specification. However, it is important to acknowledge that these specifications are generally derived from experimental testing, which comes with its own set of challenges. This testing has also been limited to specific (and somewhat simple) mixtures, as well as specific environmental conditions of pressure, temperature, and flow. Users need to understand the background and boundary limits of the testing to determine whether specifications derived from third parties can be safely applied to the targeted case, depending on the relevant CO₂ mixtures (contaminants) and operational envelopes. The reverse is also true: a ‘golden bullet’ specification can imply unnecessary conservatism, which may not be practical for all, depending on project economics, capture technology, process (treatment) limits, and local regulations. For example, the approach (contaminant limits) undertaken to manage internal corrosion should be different (and less onerous) in CO₂ streams from precombustion or SMR than that from post-combustion or industrial processes, where SO_X and NO_X could be present.
Momentum is building, but uncertainty around composition limits remains. This is compounded by the fact that, to date, there is still no operational pipeline transporting man-made CO₂ from fossil-fueled power plants, steam-methane reforming, waste fuels, or other complex industrial processes. How do we then move forward while managing the residual risks? A key part of the equation lies in the use of in-line inspection (ILI) to demonstrate the implemented compositional limits are safe and ensure operational integrity over the pipeline life cycle.

Oil & Gas to CCUS experience – How fit is the bridge?

The CCUS industry has largely relied on engineering expertise from the oil and gas sector. While this is natural and beneficial, it also introduces certain complexities. Project design approaches rooted in the oil and gas industry offer a foundation, but they must be reimagined to meet the holistic and interconnected nature of the challenges we face in achieving operational excellence, cost-effectiveness, and unwavering safety. Standards (e.g., ISO 15156/MR 0175 for sour cracking) and traditional tools (e.g., BTCM and corrosion models) are not directly applicable as we deal with new environments. Let’s not forget that CO₂ transportation brings its own peculiarities, which need to be reflected with thoughtful diligence.