Materials Selection for Capture, Compression, Transport and Injection of CO2

doi:10.1016/B978-008044570-0/50143-4

Carbon Dioxide Capture for Storage in Deep Geologic Formations

Results from the CO2 Capture Project

Volume 2, 2005, Pages 937-953

Carbon Dioxide Capture for Storage in Deep Geologic Formations

https://doi.org/10.1016/B978-008044570-0/50143-4 Get rights and content

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The principal alternative for long-distance transportation of CO₂ from source to storage site is in pipelines. To a large extent pipelines can be made in carbon steel as pure, dry CO₂ is essentially non-corrosive. More corrosion-resistant materials or corrosion inhibition must be considered when the CO₂ contains water that condenses out during transportation. This will occur where it is impossible to dry CO₂ to a dew point well below the ambient temperature. Water-saturated CO₂ is corrosive when water precipitates, but experiments exhibit that corrosion rates at high CO₂ pressures in systems containing only water or water/MEG (monoethylene glycol) mixtures are considerably lower than predicted by corrosion models. This applies particularly at low temperatures that are typical for sub-sea pipelines in northern waters. This chapter focuses on determining the corrosion rate as function of CO₂ pressure up to 80 bar. The results are compared to existing corrosion models that have been developed to cover a pressure range relevant for oil and gas transportation, that is, pressures up to 20 bar. The experiments show that the models overestimate the corrosion rate when they are used above their CO₂ partial pressure input limit. At low temperature the models predict more than 10 times the measured corrosion rate. Finally, the results indicate that the corrosion rate has a maximum as function of CO₂ pressure at 40 and 50 ℃. The maximum is at 30-50 bar depending on temperature.

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Cited by (51)

Corrosion of C110 carbon steel in high-pressure aqueous environment with mixed hydrocarbon and CO<inf>2</inf> gas
2016, Journal of Petroleum Science and Engineering
Corrosion is a major issue in the oil industry, especially in presence of aqueous carbon dioxide under high-pressure high-temperature (HPHT) conditions. Exposing tubular materials to aqueous CO₂ (carbonic acid) environment causes severe corrosion. This paper presents results of an experimental study conducted to investigate effects of CO₂ partial pressure ratio (i.e. ratio of CO₂ partial pressure to the total pressure) and total pressure on corrosion behavior of C110 carbon steel. In addition, effect of CO₂ corrosion on mechanical strength was investigated to identify presence of microscopically undetectable localized corrosion such as intergranular attack that can cause substantial mechanical degradation.
To perform corrosion experiments, test specimens were cut from C110 casing and machined. In order to improve accuracy and reduce machining-induced defects, water-jet cutting and milling machines were utilized. Corrosion tests were conducted by exposing the specimens (three specimens in one batch) to 2% NaCl solution saturated with mixed gas containing CH₄ and CO₂. CO₂ partial pressure ratio (CPPR) and total system pressure were varied. Tests were performed at a constant temperature (38±1 °C) for one week duration. Corrosion rate was measured using weight loss technique. In addition, corroded specimens were examined using a digital microscope to inspect corrosion product and detect presence of localized corrosion. Localized corrosion is known for degrading mechanical properties of carbon steel. To identify existence of undetectable localized corrosion, the specimen load-carrying-capacity (LCC) was measured using tensile strength measuring apparatus.
When CPPR was varied from 0 to 100%, similar corrosion rate trends were observed at 41.37 and 62.05 MPa. Corrosion rate increased to a maximum value and subsequently decreased as the CPPR was increased to 100%. A dense and compact corrosion product was formed at 41.37 MPa and 100% CPPR. To detect presence of localized corrosion, total reduction in Load Carrying Capacity (LCC) and reduction in LCC due to uniform corrosion were determined and compared. Results show no mechanical property degradation after exposure indicating absence of localized corrosion. The total reduction was slightly higher than the reduction due to uniform corrosion. One possible explanation for this observation could be minor variation of corroded specimen thickness, which resulted in underestimation of LCC reduction due to uniform corrosion.
A review of the protection strategies against internal corrosion for the safe transport of supercritical CO<inf>2</inf> via steel pipelines for CCS purposes
2014, International Journal of Greenhouse Gas Control
Citation Excerpt :
However, the increased pressure, combined with the presence of free water (carried over water from capture processes or hydro-test operations) in the CO2 mixture stream poses a real risk to the durability of the pipeline (Maciej and Osiadacz, 2012). Hence, the pipeline is normally dried upstream to reduce or potentially eliminate the amount of free water to ensure minimal corrosion rates (Seiersten and Kongshaug, 2005). In comparison to oil and gas pipelines where CO2 is not the main transport component, the corrosion rate of wet carbon steel in supercritical CO2 (SCCO2) is potentially higher (Thodla et al., 2009).
The transport of carbon dioxide (CO₂) from its source to a storage site is a key component of the carbon capture and storage (CCS) process. CO₂ transportation by steel pipelines presents a durability risk in the form of internal corrosion damage from supercritical or liquid CO₂ transmission. This risk is due to the formation of carbonic acid as a result of any H₂O presence, and in situ speciation of acids such as sulphurous (H₂SO₃), sulfuric (H₂SO₄), hydrochloric (HCl), and nitric acids (HNO₃) due to the presence of impurities. This review paper aims to present three key potential protection strategies to mitigate or reduce the threat of corrosion damage for reliable and potentially cost-effective transport of CO₂. This includes review of (a) relevant corrosion inhibitors, (b) corrosion resistant alloys (CRAs) for CO₂ transport pipeline, and (c) the role and physical properties of a protective iron carbonate layer (FeCO₃).
Wellbore integrinanoty and corrosion of low alloy and stainless steels in high pressure CO<inf>2</inf> geologic storage environments: An experimental study
2014, International Journal of Greenhouse Gas Control
Citation Excerpt :
Our previous researches (Choi and Nesic, 2009; Choi and Nešić, 2011; Choi et al., 2010) showed that the corrosion rate of carbon steel in supercritical CO2 conditions without a protective iron carbonate (FeCO3) layer is very high (∼20 mm/y). High corrosion rate of carbon steel under supercritical CO2 conditions has been also reported by other authors (Han et al., 2011, 2012; Lin et al., 2006; Loizzo et al., 2009; Mohammed Nor et al., 2011; Seiersten and Kongshaug, 2005). Considering this high corrosion rate of carbon steel, it has been suggested that 5Cr low alloy steel and 13Cr stainless steel could be good replacements for carbon steel in high pressure and supercritical CO2 system.
CO₂ corrosion behavior of three different steels that are commonly used as casing material in CO₂ geologic storage environments (i.e., 1018 carbon steel, 5Cr steel, and 13Cr steel) was studied at 30 and 80 bar CO₂ partial pressures and 60 °C in the presence of a simulated brine for the Weyburn-Midale reservoir system. Electrochemical techniques including linear polarization resistance (LPR), and potentiodynamic polarization measurements, were used to monitor the corrosion rate during experiments and study the corrosion mechanism. Scanning electron microscopy (SEM), energy dispersive X-ray spectroscopy (EDS), X-ray diffraction (XRD), and Raman spectroscopy were used for surface analysis. A weight loss technique was also employed to measure the corrosion rate. Carbon steel showed very high corrosion rates of ∼20 mm/y under the test conditions of this research. 5Cr steel can be considered as a replacement for the carbon steel under these conditions by the reduction in the corrosion rate by a factor of 3. However, corrosion rate was still high (∼6 mm/y). 13Cr steel showed the best corrosion resistance under testing conditions employed for this research, and can be considered as the best option for combating high pressure CO₂ corrosion if materials selection is considered as the best option for corrosion mitigation.
Estimating the likelihood of pipeline failure in CO<inf>2</inf> transmission pipelines: New insights on risks of carbon capture and storage
2014, International Journal of Greenhouse Gas Control
Previous studies of risks associated with CO₂ pipelines for future carbon capture and storage (CCS) activities have used either the frequency of incidents associated with existing CO₂ pipelines or from natural gas pipelines as a proxy. Risks of CO₂ pipeline failure have been estimated as in the range of 1.2 × 10⁻⁴ to 6.1 × 10⁻⁴ km^–1 yr. This paper demonstrates that for U.S. natural gas pipeline data, incident/failure metrics are not correlated with fatality rates. Both CO₂ and natural gas pipelines are fabricated from the same grades of carbon steel, and both are installed using the same equipment and practices. However, natural gas is lighter than air and explosive in air, whereas CO₂ is nonflammable but toxic (and heavier than air). Their risk profiles are therefore not identical, and the differences in hazard certainly impact the nature of individual and societal risk. This study focuses on the likelihood of events that could result in fatalities or injuries. The average fatality rate for natural gas transmission pipelines constructed over the last 3 decades is 1.0 × 10⁻⁶ km^–1 yr. This value can be viewed as an upper bound for estimating individual risks associated with CO₂ transmission pipelines. Use of incident rates to model individual risks for CO₂ pipelines, has overestimated these risks by 2–3 orders of magnitude. When pipelines are designed with factors of safety required by regulators for populated areas, analysis of natural gas pipeline data demonstrates that risks of significant accidental releases are extremely low. These results require a significant rethinking of previous notions of the risks associated with CO₂ pipelines.
Corrosion and bulk phase reactions in CO<inf>2</inf> transport pipelines with impurities: Review of recent published studies
2014, Energy Procedia
A limited number of papers report experimental corrosion data in the presence of flue gas impurities like SO_x, NO_x and O₂. When SO₂, water and O₂ are present, sulphurous and/or sulphuric acid (H₂SO₃ and H₂SO₄) might form. The minimum water concentration required for acid formation is not known, but the presence of FeSO₃ and/or FeSO₄ on the corroded surface in some experiments indicate that the reactions occur at water concentrations far below the water solubility in pure CO₂-water systems.
The corrosiveness increases considerably when NO_x is present. NO₂ is highly soluble in water and reacts with water to produce nitric acid and NO under atmospheric conditions. The same type of reaction probably occurs in the dense phase CO₂ system. Experimental results indicate that the rust-like dusty products formed does not efficiently reduce the corrosion rate.
There is limited number of papers presenting data and discussing the effect of combined impurities on corrosion. When both, NO₂ and SO₂ are present, NO₂ catalyzes the oxidation of SO₂ to form sulphuric acid. In addition, in the presence of H₂S, elemental sulphur can form.
Such interactions between impurities are especially dangerous when network pipeline systems are considered and CO₂ streams from different sources and with different impurities are mixed. As a result two non-corrosive streams can become very corrosive if highly corrosive acids are formed as a result of the reaction between added impurities.
The influence of impurities on the transportation safety of an anthropogenic CO<inf>2</inf> pipeline
2014, Process Safety and Environmental Protection
Citation Excerpt :
However, the influence of other impurities contained in transported CO2 on the solubility of water in CO2 pipelines is not well researched. According to the literature (Seiersten and Kongshaug, 2005; Heggum et al., 2005; Austegaard et al., 2006), experimental measurements and calculations both show that water solubility decreases with the increase of CH4 in the system of CO2 + CH4 + H2O. However, de Visser and Hendriks (2007) found that the solubility of water increases with the increase of H2S content in the system of CO2 + H2S + H2O based only on the calculated models.
Transportation safety is a key aspect of carbon capture and storage (CCS), which is a major technology used to reduce greenhouse gas emissions. Supercritical CO₂ pipelines have been certified as an optimised choice for CO₂ transportation. The results of this study show that the Peng–Robinson (PR) equation of state is recommended for analysis of the properties of supercritical CO₂. The influence of nonpolar and polar impurities on the two-phase region and the location of the sharp discontinuity in the density are found by analysing the ternary phase equilibrium and physical parameters using the PR equation of state. A transitional area between the supercritical phase and the dense phase, where the density changes abruptly, is defined as the quasi-critical region. This study describes the functional relation between the temperature and the pressure that defines the quasi-critical line by calculating the partial derivative equations and then determines the effect of impurities on the quasi-critical region of transported CO₂. Operational recommendations for pipeline transportation of flue CO₂ are developed using a pipeline operated by Sinopec as an example, demonstrating the influence of impurities in flue CO₂ on saturation pressure for control and prevention of fractures in CO₂ pipelines.

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Chapter 16 - Materials Selection for Capture, Compression, Transport and Injection of CO2

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Chapter 16 - Materials Selection for Capture, Compression, Transport and Injection of CO₂