Why is it important to control the water content of dense-phase CO2 pipelines?

While the corrosion of steel under low CO2 partial pressure conditions has received significant attention in the oil and gas industry, the issue of steel corrosion under high partial CO2 pressure during CCS transportation remains relatively understudied. This pertains to both the supercritical phase and liquid CO2 phase, both of which can be referred to as dense CO2 or a CO2-rich phase. Further research is needed to fully understand and address this aspect of steel corrosion in the CCS process.

CO2- H2O Phase Diagram

[Source: Principles of General Chemistry, Bruce A. Averill, 2012]

Carbon Steel pipeline corrosion in dense phase CO2 is dependent on the likelihood of free water formation under pipeline operating conditions. The behavior of dense phase CO2 with water as an impurity can be derived from existing literature. One should be able to specify the maximum water content which will not promote free water phase formation inside the pipeline during normal operation. If the solubility limit of water is not reached under pipeline operating conditions, one would not expect free water inside the pipeline. Without a separate water phase, corrosion will not be a concern for pipelines carrying dense-phase CO2.

Although it sounds like a very easy problem to solve, it is not that easy due to the presence of other impurities such as SOx, NOx, O2, CH4, Glycol, Methanol, H2S, etc. In the temperature range of 5-85°C and pressure of 7.3 – 30.0 MPa (range of CO2 pipeline transport conditions), the solubility of water in a pure CO2 system exceeds 1700 parts per million by volume (ppmv). These impurities not only interfere with the solubility limit of water in dense phase CO2, but they also interact with each other to produce harmful acids that promote corrosion inside the pipeline. The impurities in fact reduce the solubility limit of water in CO2 and promote conditions inside the pipeline conducive to the formation of free water, which will further absorb CO2 and other impurities (e.g. SOx, NOx, H2S, HCl, and O2), thus providing the aqueous environment required for electrochemical corrosion reactions. As previously discussed, reactions between various impurities in the water phase will create acids that will increase the corrosion of the pipelines.

Figure 1 – Water solubility in pure CO2 for varying temperatures as a function of pressure [de Visser E, Hendriks C, Barrio M, et al. Dynamis CO2 quality recommendations. Int J Greenh Gas Con. 2008]

The following table provides a summary of contaminants and their effect on carbon steel corrosion.

Table 1 - Summary of possible contaminants in dense phase CO2 pipeline and their effect on carbon steel corrosion

The literature values from past pilot projects show a range of 20-650 ppm for the water content allowed in the CO2 stream. However, the presence of impurities can reduce the solubility limit of water in the dense phase of CO2. There are no universally accepted limits for the impurities in Table 1. Varying limits are available in the literature based on the projects currently in service (Table 2). Careful observation of Table 2 indicates that limits imposed on NOx, SOx, and other impurities were mainly determined based on health and safety in the event of a sudden release, not in the context of maintaining pipeline integrity. In addition, these limits did not take into consideration of interaction effects between the impurities and their effect on reducing the solubility limits of water in dense phase CO2 Therefore, it is crucial to maintain the CO2 stream water-free or as minimum as possible to prevent corrosion. Research is underway in this area to understand the role of contaminants in altering the solubility limit. Without sufficient data on the water solubility limits for impurities-laden dense phase CO2, it is challenging to specify the safe limits for the impurities, determine the damage mechanisms and select appropriate materials to prevent corrosion.

Table 2 – CO2 quality recommendations

[Ref: de Visser E, Hendriks C, Barrio M, et al. Dynamis CO2 quality recommendations. Int J Greenhouse Gas Control. 2008]

There is no comprehensive data on the phase behavior of CO2 in the presence of the above-mentioned impurities. It is still an ongoing area of research. Without the thermodynamic data that considers the effect of all these impurities on the phase behavior of CO2-water mixtures, it is very hard to specify the upper limit for water content in dense phase CO2. Based on various existing CO2 pipeline projects the current water content specification ranges from 20-650 ppm of water.

Researchers have also observed that a critical relative humidity (RH) exists in supercritical CO2 environments. Similar to atmospheric corrosion, the corrosion rate increases significantly when the RH surpasses this critical point. RH is expressed as the ratio of actual water content to water solubility limit and provides an additional measure of moisture level, in addition to actual water content which is typically measured in ppmv.

It is also essential to consider the possibility of the formation of aqueous phases when decompressing a pipeline. Below the critical temperature, depressurizing the CO2 to less than the critical pressure will form a two-phase gas/liquid system. The impurities will partition between the two phases. The liquid phase formed during this non-standard operating condition will stay in the pipeline and the impurities dissolved will create a localized corrosive environment threatening the integrity of the pipeline.

Free water could also be introduced from hydrostatic test water left in the pipeline, generating high levels of corrosion. Stricter regulations should be enabled to remove the hydrostatic water 100% from the pipelines before putting it into service.

Hydrate formation is another issue with wet CO2 pipelines. Hydrates are lethal and can rupture the pipeline should they form and accelerate inside the pipeline. Design conditions should be carefully chosen to prevent hydrate formation. Lack of experience or data available regarding CO2 pipeline hydrates necessitates the need for the lowest possible water content in the pipeline.

Another lethal mode of damage that exists in CO2 pipelines is a ductile running fracture. Ductile fractures involve significant pipeline deformation. The more insidious brittle fractures on the other hand involve little deformation during fracture growth and hence may be left unnoticed until they become unstable by which time catastrophic pipeline failure has occurred. Ductile fractures may start due to an external force such as loss of material (corrosion or external third-party action), ground movement, or impact damage and grow when the pressure stresses within the pipeline exceed the pipeline's mechanical properties such as yield stress or fracture toughness. As failure will involve a continuous drop in the line pressure due to loss of fluid, the fracture will come to rest when the corresponding fluid decompression velocity within the pipeline exceeds the fracture propagation speed, or the crack is arrested.

CO2 pipelines are more susceptible to fast-running fractures as compared to hydrocarbon pipelines for the following reasons: i) CO2 exhibits a prolonged phase transition during depressurization. This means that the pressurize stresses driving the fracture remain relatively unchanged during failure despite the loss of material from the pipeline; ii) CO2 undergoes marked Joule-Thomson expansion cooling during rapid depressurization with temperatures reaching as low as 203K. The inevitable drop in the pipe wall temperature in contact with the escaping CO2 and the corresponding likely significant drop in fracture toughness will lead to significant localized thermal stresses in the defect plane thus promoting fracture propagation. Avoiding corrosion by controlling the water content of the CO2 pipeline reduces the likelihood of initiating ductile running fractures.

Considering the uncertainties involved with the impurities it is recommended to keep the water content as minimum as possible, which can be achieved by implementing appropriate dehydration techniques. Some pipeline operators follow very stringent limits of 50 ppm.

Additionally, selecting appropriate materials and coatings for pipelines can help prevent corrosion in the long run. Despite extensive research in the field, no effective inhibitors or internal coatings have been discovered to prevent corrosion in carbon dioxide pipelines in the long term. It is also important to continuously monitor the CO2 stream for water content and impurities and take corrective actions when necessary to prevent corrosion.