Tracking Corrosion in Real Time in a Carbon Dioxide Capture Plant

Carbon dioxide (CO₂) capture and sequestration (CCS) technologies can play an important role in decreasing greenhouse gas emissions by greatly reducing the amount of CO₂ released from new and existing coal- and gas-fired power plants as well as large industrial sources such as cement production and natural gas processing facilities.¹ The U.S. Inventory of Greenhouse Gas Emissions and Sinks estimates that more than 40% of CO₂ emissions in the United States is a result of electric power generation;² and according to the International Risk Governance Council, electric power plants are responsible for approximately one third of global CO₂ emissions.³

Burning fossil fuels­ (e.g., coal) to produce electricity emits flue gase­s that contain CO₂, water vapor, sulfur oxides (SOx), and nitrogen oxides (NOx). There are several methods currently utilized to capture CO₂ from flue gases. The post-combustion method, which can reduce a power plant's carbon emissions by 80 to 90%, is well understood and widely used in the natural gas industry. This method uses a reactive absorption process with amine solvents to separate and capture the CO₂ from the flue gases after the fossil fuel is burned, explains NACE International member Sridhar Srinivasan, global business leader—Corrosion Center of Excellence with Honeywell International, Inc. (Houston, Texas) and chair of NACE’s Technology Exchange Group (TEG) 100X, Sensors: Corrosion and Corrosiveness Sensor Technology, and vice chair of Specific Technology Group (STG) 62, Corrosion Monitoring and Measurement—Science and Engineering Applications. The CO₂ is captured by passing the flue gases through the liquid amine solvent and the amines selectively dissolve and absorb the CO₂ gas. The solvent can be regenerated by heating, which releases the water vapor and leaves a concentrated stream of CO₂ that can be transported to storage. Different types of amines are typically used (e.g., monoethanolamine [MEA], methyldiethanolamine [MDEA], and others depending on the type of application and operating conditions).

According to Srinivasan, CO₂ gas is extremely corrosive when it comes into contact with water; and once the amines are loaded with the absorbed CO₂ gas, they can be very corrosive to the metallurgy of the CO₂ capture plant due to their high oxygen and CO₂ levels as well as impurities such as fly ash, SOx, and NOx. Corrosion mechanisms seen in CO₂ capture plants include general corrosion, stress corrosion cracking (SCC), crevice corrosion, pitting corrosion, and erosion-corrosion. Additionally, corrosion can be exacerbated by oxidative and thermal degradation of the amine solvent, which can vary with a CO₂ capture plant’s run time and gas throughput.

“Corrosion is a profound safety issue in industry,” says Srinivasan. “Most plant accidents happen because there is either inadequate or ineffective corrosion management.” He notes that corrosion is a dynamic phenomenon—it changes in real time as the process changes. “When you look at corrosion, it is similar to looking at the changes in blood pressure of a person who is undergoing different activities. The changes in corrosion are a function of a number of process variables [feed rates, temperature excursions, variations in product purity, etc.].” Because of that, he adds, process plants have to be extremely careful when managing and mitigating corrosion, especially with acid gases like CO₂.

The way to accurately and meaningfully track corrosion is with online corrosion monitoring in real time, Srinivasan says. For decades, however, process corrosion has been monitored with manual, offline techniques that indicate the presence of corrosion after it has occurred in the process equipment. This, he notes, leads to the accumulation of corrosion that can cause failures and outages, and corrosion management that is reactive rather than proactive. While common corrosion monitoring techniques, such as linear polarization resistance (LPR) probes, can be used in online monitoring systems, typically the protocols to link corrosion data to a plant’s process control systems have not been sufficient.

Now, due to advanced plant process control system technology that is being used to regularly monitor plant process conditions, it is possible to incorporate a relatively new corrosion monitoring approach. Industrial plants have a distributed control system (DCS) where process data are sent and evaluated for production optimization. Online corrosion monitoring technology can also send real-time corrosion data to the plant’s DCS where they can be regularly monitored along with process control data, making it possible to correlate changes in corrosion rates with process events. This proactive, online approach allows plant operators to determine the presence and cause of corrosion and make process changes before substantial corrosion damage occurs.

Real-Time, Online Monitoring Technology

The online corrosion monitoring technology measures the minuscule electrical current that results from corrosion occurring in the system. The technology utilizes a sensor device that comprises a three-electrode corrosion probe and a transmitter. The three electrodes are identical and function as the working electrode, reference electrode, and auxiliary/counter electrode (which supplies current to the working electrode). Since they are constructed of the same metallurgy as the piping material being monitored, the electrodes are essentially replicating the corrosion behavior of the pipe, says Srinivasan. The transmitter measures and analyzes the current flow and sends it to the DCS.

By integrating measurements from multiple electrochemical monitoring techniques—LPR, harmonic distortion analysis (HDA), and electrochemical noise (ECN)— the technology is able to characterize the corrosion rate and pitting factor every 30 seconds, and provide four output variables to accurately quantify corrosion  that stems from oxidation of the metal.  The LPR technique, Srinivasan explains, defines the polarization resistance by applying a potential to the working electrode and measuring the current flow between the working electrode and the counter electrode. By finding the polarization resistance, which is inversely proportional to the measured corrosion current, he adds, the technique can determine the overall rate of metal loss (corrosion rate).

Because each corroding system has its own unique behaviors (signatures), the HDA technique is used to determine variations in the current, known as the harmonics, to find the localized Stern Geary constant (B value). The B value represents a system’s “constant,” which is determined by the mechanism and kinetics of the system’s corrosion process. The B value can be different for each corroding system depending on the characteristics of the system and the type of corrosion activity (i.e., the anodic and cathodic currents and potentials, which can vary quite a bit from system to system). However, the LPR technique typically uses a default B value to calculate the corrosion rate, which can lead to significant errors when computing the corrosion rate. By using a measured B value, a more accurate corrosion rate can be determined.

The corrosion process also generates ECN, which is the low-amplitude (<1 mV), low-frequency fluctuation of corrosion current and potential. The ECN technique measures these low-level fluctuations between working and counter electrodes, which can determine the type and speed of corrosion. Based on the magnitude of the variations in the corrosion current (intrinsic current noise), Srinivasan comments, the ECN measurement can establish whether the corrosion is likely to be uniform or localized and be used to determine the pitting factor, which indicates the probability of the corrosion mechanism generating localized corrosion over time. Typically, general corrosion processes have low levels of ECN, but the onset of localized corrosion (e.g., pitting) leads to increasingly higher levels of ECN.

The last output delivered by the electrochemical monitoring techniques is the corrosion mechanism indicator (CMI), which shows the presence and likely effects of surface films. This is determined by the characteristics of the interface between the metal and the environment (electrolyte) and its influence on the behavior of the corrosion current.

The four output variables from the monitoring device are calculated continuously at time intervals determined by the plant operator, and immediately communicated to the plant DCS via hardwire or wireless channels, or stored remotely for later download. Since the reported corrosion data represent real-time measurements, Srinivasan notes, the plant operators are able to correlate corrosion events with specific process changes (temperature, flow rate, injection of neutralizers or catalysts, etc.) and determine potential cause-effect relationships.

Corrosion Monitoring in a CCS Pilot Plant

To investigate the corrosion process at the post-combustion CCS pilot plant at the Maasvlakte coal-fired power plant in Rotterdam, The Netherlands, the advanced, real-time online corrosion monitoring technology was implemented in the unit’s CO₂ capture process. The objective of the study was to verify the interrelationship between amine solvent degradation, ammonia (NH3) emissions from oxidative solvent degradation, and corrosion, as well as validate the accuracy of the online corrosion monitoring system in terms of reporting the correct corrosion rate. The study was conducted over two monitoring campaigns during a two-year period, with each campaign running about five to six months. Corrosion coupons were also installed parallel to the online corrosion monitoring device to provide baseline corrosion data for validating results from the online corrosion monitoring system. A review of the monitoring approach and results of the case study were presented during the CORROSION 2015 symposium, “Corrosion Monitoring Technologies: Past Present and the Future,” sponsored by TEG 100X.

The CCS pilot plant components are mainly comprised of 304L (UNS S30403) and 316L (UNS S31603) austenitic stainless steel (SS) to minimize general corrosion. For both monitoring campaigns, 30 wt% MEA was used as the CO₂ capture solvent. Based on an evaluation of the plant’s CO₂ capture process, the online corrosion monitoring device was placed in an area suspected to be particularly susceptible to corrosion—between the lean solvent pump and the amine stripper. In this portion of the process, changes in amine composition, as well as degradation products and impurities, operating temperature, local flow rates, and localized turbulence corrosion, often affect the corrosion rate. “Corrosion behavior is a function of the solvent concentration,” Srinivasan notes. “Depending on the solvent, you will see different corrosion behaviors.”

The First Campaign

The first monitoring campaign ran for ~149 days and comprised ~2,200 operating hours. The campaign was divided into four periods. The same solvent was used for the first 128 days, then completely replaced for the remainder of the campaign. The flue gas contained 13 vol% CO₂ and 7 vol% O2 for the first, third, and fourth operating periods, and 4 vol% CO₂ and 17 vol% O2 during the second operating period. Online, real-time corrosion monitoring was done during the third and fourth periods.

Two days after start-up during the third period (Day 110), the corrosion rate peaked at ~800 µm/y. On Day 115, pure MEA was added to the unit as solvent make-up, and the corrosion rate value decreased. With continued operation, however, the corrosion rate increased to a peak of ~1,400 µm/y after several weeks. On Day 128 the unit was cleaned and the solvent completely replaced, and the corrosion rate decreased to <20 µm/y with only periodic low-level peaks during the rest of the campaign.

The pitting factor values were also tracked during the campaign and varied between 0.2 and 0.4, which is within the range for pitting (0.1 to 1.0). The highest pitting factor values were recorded during periods when the general corrosion rate measurements were low; and periods with high corrosion rates showed very low pitting factor values. According to the presenters, these measurements suggest that the corrosion was likely general in nature and not related to pitting attack of the process unit. They also note that the peak corrosion rate measured would be considered high for SS, but the time-averaged corrosion rate values indicated a maximum metal thickness loss rate of 600 µm/y. While this corrosion rate would have produced a metal thickness loss of only 0.03 mm during the 20 days of the campaign when corrosion rates were high, the presenters point out that this corrosion rate would have resulted in a thickness loss of 0.06 mm/y had the situation continued for a year, which is considered excessive for SS in amine service.

The corrosion coupons placed in the hot lean solvent stream were lost in the system during this campaign, and corrosion data from the online monitoring process could not be validated.

The Second Campaign

The second monitoring campaign ran for ~140 days for a total of ~1,700 operating hours, and was divided into three periods. The CO₂ capture plant operated intermittently during the first period and continuously during the second period; and then the solvent was completely replaced and the plant ran continuously during the third period. The flue gas during all three periods usually contained 13 vol% CO₂ and 7 vol% O2. Corrosion monitoring was performed over the entire duration of the campaign.

The corrosion rate measurements varied during the intermittent operation, with peak corrosion rates ranging from 10 to 25 µm/y. During continuous operation, the corrosion rates typically ranged between 2 to 5 µm/y, but peaked at 30 µm/y prior to the solvent replacement on Day 65 and then remained stable at ~5 µm/y. Based on the corrosion coupon inserted during this campaign, the calculated corrosion rate was 0.3 µm/y, which was comparably low to the much more sensitive online monitoring results. According to the presenters, the consistently low corrosion rate values for both the online and coupon readings are considered acceptable for SS in a passive condition in amine service. Generally, the pitting factor values did not fall within the range of values that indicate pitting, which suggests very low rates of general corrosion although pitting factor readings did reach ~1.0 in transient periods during intermittent operation.

The presenters report that a major corrosion effect observed in both campaigns was an increase in the general corrosion rate over time during continuous operation. The first campaign, however, showed higher corrosion rates than the second. After a supplemental analysis of the amine solvent for metal ions, they found that the metal ion concentration for the first monitoring campaign was higher than it was for the second. The flue gas in the first campaign also had higher oxygen content. They noted these conditions are known to promote degradation of the amine solvent and formation of corrosive reaction products. While in situ corrosion most likely contributed to the metal ions being present in the amine solvent, the presence of metal ions promoted oxidative degradation of the solvent, which resulted in conditions that further degraded the solvent and led to increased corrosion in the unit. To reduce the corrosion rate, the solvent needed to be completely replaced.

Srinivasan notes that the study demonstrated the efficacy and accuracy of the real-time, online monitoring system and its value in immediately identifying corrosive operating modes during plant operation, which will enable plant operators to take remedial actions to restore acceptable corrosion conditions on a real-time basis so corrosion damage can be avoided. “Corrosion is hard to see, it happens over a period of time,” he says. “If we’re able to monitor it in a reasonable time frame—real time—we’re going to be able to catch it, fix it, or prevent it.”

More information on the real-time online monitoring technology and the monitoring campaigns at the Maasvlakte coal-fired power plant can be found in CORROSION 2015 paper no. 5954, “Plant Applications of Online Corrosion Monitoring: CO₂ Capture Amine Plant Case Study,” by R.D. Kane, S. Srinivasan, P. Khakharia, E. Goetheer, and J. Mertens.

References

1. “Carbon Dioxide Capture and Sequestration,” U.S. EPA, http://www.epa.gov/climatechange/ccs (April 13, 2015).
2. “Draft Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2013,” National Greenhouse Gas Emissions Data, U.S. EPA, February 2015, http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html (April 13, 2015).
3. “Power plant CO2 capture technologies,” International Risk Governance Council, http://www.irgc.org/issues/carbon-capture-and-storage/power-plant-co2-capture-technologies (April 13, 2015).