Use of Carbon Steel for Construction of Post-Combustion CO2

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Use of Carbon Steel for Construction of Post-Combustion CO2 Capture Facilities: A Pilot-Scale Corrosion Study Wei Li, James Landon, Bradley Irvin, Liangfu Zheng, Keith Ruh, LIANG KONG, Jonathan Pelgen, David Link, Jose´ D Figueroa, Jesse Thompson, Heather Nikolic, and Kunlei Liu Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.7b00697 • Publication Date (Web): 03 Apr 2017 Downloaded from http://pubs.acs.org on April 8, 2017

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Industrial & Engineering Chemistry Research

1

Use of Carbon Steel for Construction of PostCombustion CO2 Capture Facilities: A Pilot-Scale Corrosion Study Wei Li,† James Landon,† Bradley Irvin,† Liangfu Zheng,† Keith Ruh,† Liang Kong,† Jonathan Pelgen,† David Link,‡ Jose D. Figueroa,§ Jesse Thompson,† Heather Nikolic,† Kunlei Liu,†,∥ †

Center for Applied Energy Research, University of Kentucky, 2540 Research Park Drive, Lexington, Kentucky 40511, United States

‡

Louisville Gas and Electric and Kentucky Utilities, Louisville, Kentucky, 40202, United States

§

National Energy Technology Laboratory, US Department of Energy, 626 Cochran Mill Road, Pittsburgh, Pennsylvania 15236, United States

∥Department

of Mechanical Engineering, University of Kentucky, 151 Ralph G. Anderson Building, Lexington, Kentucky 40506, United States



Corresponding author. Email address: [email protected]

ACS Paragon Plus Environment


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ABSTRACT Corrosion studies were carried out on metal coated and non-coated carbon steel as well as stainless steel in a pilot-scale post combustion CO2 capture process. Aqueous 30 wt.% monoethanolamine (MEA) solvent was used without any chemical additive for anti-oxidation to examine a worst-case scenario where corrosion is not mitigated. The corrosion rate of all carbon steels was almost zero in the absorber column and CO2 lean amine piping except for Ni-coated carbon steel (< 1.8 mm/yr). Ni2Al3/Al2O3 precoated carbon steels showed initial protection but lost their integrity in the stripping column and CO2 rich amine piping, and severe corrosion was eventually observed for all carbon steels at these two locations. Stainless steel was found to be stable and corrosion resistant in all of the sampling locations throughout the experiment. This study provides an initial framework for the use of carbon steel as a potential construction material for process units with relatively mild operating conditions (temperature less than 80 °C), such as the absorber and cold lean amine piping of a post-combustion CO2 capture process. It also warrants further investigation of using carbon steel with more effective corrosion mitigation strategies for process units where harsh environments are expected (such as temperatures greater than 100 °C).

Keywords: CO2 capture; Pilot-scale; Carbon steel; Corrosion; Mass loss; SEM; XRD.


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1. Introduction

For post-combustion carbon dioxide (CO2) capture operations at coal-fired power plants, capital expenditures for process units such as the absorber and stripper as well as piping, make up a significant percentage (approximately 50%) of the cost of electricity.1 Although a variety of materials have been used for these process units (e.g., concrete is sometimes employed for building absorber columns), stainless steel is still the predominant construction material.2,3 An aqueous CO2-containing operating environment is expected to be highly corrosive.4 For utility flue gas applications, the high CO2-loading environment could bring corrosion challenges to the process units, as amine-based solvents with high CO2 capacity are continuing to be developed5,6 to reduce the CO2 capture associated energy penalty. Although stainless steel has good corrosion resistance, less expensive construction materials are being sought to reduce capital costs.7–10 Carbon steel offers satisfactory mechanical properties and has been widely used in many industrial sectors.11–16 Nonetheless, its corrosion resistance is low17,18, especially for CO2 capture applications.2 Internal corrosion, therefore, becomes an obvious concern as it could necessitate unit maintenance or replacement in short periods of time (i.e., much shorter than the design life). To mitigate corrosion, corrosion inhibitors or protective internal coatings are often used.19 Heavy metal corrosion inhibitors, e.g., vanadium compounds, were found to be effective.20 However, these inhibitors are often toxic with other environmental concerns,21 which makes them currently less attractive. In addition, some field and laboratory studies have shown that vanadium compounds were not an effective corrosion inhibitor, and even led to an increase of solvent degradation6. The effectiveness of organic inhibitors in harsh operation environments, such as stripper conditions (e.g., temperature greater than 100 °C), is questioned as degradation may occur.21,22 Moreover, it remains a concern that the



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addition of organic inhibitors may introduce environmental impacts, and can change the physical and/or chemical properties of the solvents and affect the absorption performance23. The use of protective coatings is another promising approach to mitigate internal corrosion in CO2 capture processes. Coatings protect equipment, structure and piping by providing a physical barrier between the substrate and the corrosive environment. As opposed to chemical additives, coatings normally adhere to the substrate without affecting/contaminating the solvent in the process, which makes them more environmentally compatible. In laboratory environments, coatings on carbon steel have already shown significant corrosion resistance under post-combustion CO2 capture process conditions. For example, a nickel aluminide intermetallic coating with a heat treatment at 900 °C, was found to effectively retard corrosion (by four orders of magnitude) in a 5 M aqueous MEA solution with lean carbon loading at 80°C.24 The viability of using such coatings in a real environment toward commercial scale CO2 capture processes (e.g., in much larger pilot-scale facilities) with more complex and harsher conditions, remains unclear. Due to these previously encouraging corrosion coatings at the laboratory scale24, the corrosion behavior of coated and non-coated carbon steel in various process locations of a pilot-scale CO2 capture process was investigated in the present study. The corrosion rates were calculated using a conventional mass loss method; the surface morphologies and chemical composition were documented using scanning electron microscopy (SEM), energy-dispersive X-ray spectroscopy (EDS), and X-ray diffraction (XRD).

2. Experimental

2.1. Pilot-Scale CO2 Capture Process


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The present study was carried out in a 0.7 MWe pilot-scale CO2 capture process at Kentucky Utilities (KU) E.W. Brown Generating Station in Harrodsburg, KY. This CO2 capture process treats a slipstream of the power generation flue gas and is withdrawn just before the stack, after emissions controls including low-NOx control, a desulfurization unit for SO2 removal and an electrostatic precipitator. Figure 1 shows a generalized schematic of the process with the corrosion sampling locations clearly shown. PRIMARY HEAT RECOVERY EXCHANGER

CO2 LEAN AMINE PIPING CORROSION (CL) COUPON LOCATION

ABSORBER

PRETREATMENT COLUMN

4

SECONDARY HEAT RECOVERY 2 EXCHANGER

3 RICH HEAT RECOVERY EXCHANGER

1 ABSORBER POLISHING EXCHANGER

PRETREATMENT COOLER

ABSORBER COLUMN CORROSION (A) COUPON LOCATION

2

FLUE GAS FEED BLOWER

1

1: COOLING WATER SUPPLY 2: COOLING WATER RETURN 3: STEAM SUPPLY 4: CONDENSATE RETURN 5: CHILLED WATER SUPPLY 6: CHILLED WATER RETURN

LEAN/RICH EXCHANGER

PRIMARY STRIPPER

CO2 RICH AMINE PIPING CORROSION COUPON LOCATION (HR)

REBOILER

4

2 1

SECONDARY AIR STRIPPER

4

STRIPPER COLUMN CORROSION COUPON LOCATION (S) RECLAIMER

DESICCANT PREHEATER

3

2 WATER EVAPORATOR WATER EVAPORATOR BLOWER

COOLING TOWER

4 DESICCANT COOLER 2

1 6

3 3

INTERCOOLER

1

5 DESICCANT CHILLER

LEAN/ DESICCANT EXCHANGER

COOLING TOWER BLOWER

Figure 1. The four corrosion sampling points (marked by dash lines) in the 0.7 MWe CO2 capture unit at KU’s E.W. Brown Station. Within the absorber column (A), in the CO2 lean amine piping (CL), within the stripper column (S), and in the CO2 rich amine piping (HR).

The University of Kentucky Center for Applied Energy Research (UKy-CAER) has developed a unique CO2 capture system (CCS) with secondary stripping and a heat integrated liquid desiccant loop that recovers waste heat from the CCS. The water saturated liquid desiccant stream recovers waste heat from the secondary air stripper bottom stream and the primary stripper overhead stream before passing



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through the water evaporator column, where water is transferred from the liquid desiccant stream to the air stream. The liquid desiccant stream is cooled and utilized in the two stage cooling tower, to remove moisture from the air stream before it passes to the top stage, lowering the wet bulb temperature and allowing for additional cooling to be achieved in the top stage. The secondary stripping unit is an airswept column utilizing the warm, water saturated air stream generated from regeneration of the liquid desiccant stream in the water evaporator column to strip additional CO2 from the amine. An extra CO2 lean amine stream entering the absorber column allows for an increased CO2 absorption driving force in this column and a higher CO2 loading to be achieved at the absorber exit. A highly CO2 loaded amine stream entering the primary stripper leads to a lower solvent regeneration energy, in terms of steam requirement. Additionally, a pretreatment column is used to reduce the SO2 concentration of the inlet flue gas stream to < 5 ppm. The solvent used in this process was benchmark 30 wt.% monoethanolamine (MEA) aqueous solution with no additional additives. Two corrosion sampling locations were chosen within the two primary process columns: the absorber (A) and the primary stripper (S); while two additional corrosion sampling locations were chosen within the process piping: the CO2 lean amine stream (CL) after the polishing heat exchanger and just prior to entering the absorber, and the CO2 rich amine stream (HR) after the crossover heat exchanger and just before entering the stripper. These four locations represented varied process conditions such as flow, temperature, and pressure, which were chosen to gain a more comprehensive understanding of the corrosion behavior in the CO2 capture process. The stripper and hot rich amine piping were expected to have more corrosion issues, as the temperature and pressure are higher at these locations2.

2.2. Corrosion Specimens


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Through this study, the corrosion of four different specimen types was investigated at four different process locations. The specimen types included ASTM (American Society for Testing and Materials) A106 (grade B) carbon steel as a representative carbon steel material, Ni-coated A106 carbon steel, Ni2Al3/Al2O3-coated A106 carbon steel, and AISI (American Iron and Steel Institute) 304 stainless steel. The nominal chemical composition for carbon steel and stainless steel is listed in Table 1. The purpose of this study was to determine the viability of using commercially available carbon steel, and two UKyCAER developed coatings on carbon steel in a deployed CO2 capture process, while using stainless steel as a benchmark construction material.

Table 1. Chemical composition of A106 carbon steel and 304 stainless steel (wt.%).

Steel type

C

Cr

Ni

Cu

Mn

Mo

P

S

Si

Fe

A106 carbon steel

0.27

0.12

0.15

0.21

0.86

0.04

0.01

0.02

0.26

Bal.

304 stainless steel

0.05

18.22

8.04

0.52

1.74

0.30

0.03

0.001

0.30

Bal.

Specimens of all types were cut to a rectangular cuboid with dimensions of 3.81 cm x 1.27 cm x 0.16 cm (3/2 in x 1/2 in x 1/16 in). A hole was drilled at one end of the specimen for hanging on a PTFEcovered sample rod on the corrosion rack with non-conductive spacers as shown in Figure 2. All of the exposed surface (including the surface of the hole) of the specimen was ground with SiC sand paper from 240, 400, to 600 grit, and then ultrasonically cleaned with deionized (DI) water and acetone.



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Figure 2. Corrosion sample rod containing six specimens.

After grinding, Ni plating and aluminizing were carried out for the Ni-coated A106 and Ni2Al3/Al2O3coated A106 specimens. The Ni coating was electrodeposited by a galvanostatic method from a conventional Ni-plating bath containing 150 g/L NiSO4∙6H2O, 35 g/L H3BO3, 12 g/L NaCl, and 120 g/L C6H5Na3O7∙2H2O (sodium citrate dihydrate). After all of the salts were dissolved in DI water, the electrolyte was kept at 80 °C for 2 h. Thereafter, the electrolyte was filtered before use. The current density was set to 2.5 A/dm2; the temperature was 35 °C; the stirring rate was 400 rpm; and the plating time duration chosen was 2.5 h. After plating, specimens were washed with DI water and acetone then stored in a desiccator. To produce the Ni2Al3/Al2O3-coated A106 samples, a mixture of powders consisting of 40 wt.% Al (particles size: 74 µm) + 55 wt.% Al2O3 (particle size: 74 -– 177 µm) + 5 wt.% NH4Cl was used as an aluminizing source. After weighing, all of the powders were put into a mortar and ground with a pestle


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for approximately 15 minutes. The abovementioned Ni-plated A106 corrosion specimens were placed into a small reactor cell and packed tightly with the prepared powder mixture. The specimens were separated by powder so that every specimen received enough aluminizing source. The reactor cell was then placed into a tube furnace and continuously purged with ultrahigh purity Ar gas at a flow rate of 300 ml/min. After 5 minutes, the furnace temperature was set to 615 °C with a heating rate of 5 °C/min. When the designated furnace temperature was reached, it was held steady for 5 h. After that, the furnace was allowed to cool to room temperature. After the temperature fell below 100 °C, Ar purging was stopped. When the furnace cooled to room temperature, the reactor cell was removed. The specimens were ultrasonically cleaned with DI water. Thereafter, the specimens were cleaned with boiling water for 20 minutes to remove contaminants and any loose particles from the aluminizing powders. The specimens were dried and subjected to a heat treatment at 900 °C for 2 h in air to promote the formation of a corrosion-resistant alumina layer (~ 2 µm).24,25 Finally, they were placed in a vacuum desiccator for storage until installation in the CO2 capture process. Prior to the corrosion study, the fabricated Ni-coated A106 had an initial nickel coating thickness of around 100 µm, while the Ni2Al3/Al2O3-coated A106 had a surface nickel aluminide layer of approximately 60 µm, with a remaining nickel plating layer of 50 µm underneath.

2.3. Experimental Methods Prior to installation in the CO2 capture unit, each prepared specimen was numbered, weighed, and the dimensions measured and documented. The hole in each specimen was measured and taken into account for calculations. In total, 384 specimens were produced, 96 specimens each of A106, Ni-coated A106, Ni2Al3/Al2O3-coated A106 (denoted hereafter as Ni2Al3-coated A106), and SS304. These specimens were then installed into the four sampling locations of the CO2 capture unit. For each location, 24



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specimens of each material type, a total of 96 specimens, were placed in a corrosion rack using 16 corrosion sample rods (see Figure 2). Each rod held six specimens, three of each material type. The actual specimen numbering and location arrangement, as well as configuration of corrosion rack assembly, can be found in the supporting information (Figure S1 and Figure S2). During each corrosion sampling event, two corrosion sample rods for a total of 12 corrosion specimens, three corrosion specimens of each material type, were removed from each location. The removed corrosion specimens were immediately cleaned with DI water and acetone, sequentially. After drying, the specimens were stored in a desiccator and transported to the laboratory for analysis. Two of the three corrosion specimens of each type were used for the corrosion rate calculations and the third specimen was used for surface analyses. In the laboratory, all of the obtained specimens were cleaned with DI water and acetone again prior to further study. For the mass loss corrosion rate calculation, the carbon steel (with/without coatings) and stainless steel specimens were chemically cleaned for removal of the corrosion product according to the ASTM G1-90 standard26. A 1000 mL solution containing 500 mL of hydrochloric acid (HCl, specific gravity 1.19) and 3.5 g of hexamethylene tetramine was used for the carbon steel specimens; while 1000 mL solution containing 100 mL nitric acid (HNO3, specific gravity 1.42) was used for the stainless steel specimens. Subsequently, the specimens were flushed with DI water and weighed after drying with compressed air. The corrosion rate (𝐶𝑅, mm/yr) was calculated using the following equation: 𝐶𝑅 =

8.76×106 ×(𝑚0 −𝑚1) 𝑆×𝑡×𝜌

(1)

where 𝑚0 , 𝑚1 , 𝑆, 𝑡, and 𝜌 are the mass before corrosion (g), mass after removal of corrosion product (g), specimen surface area (mm2), experiment duration (h), and density of the tested material (g/cm3), respectively. 8.76×106 is a unit conversion factor.


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A Hitachi S-4800 field emission SEM was used to characterize the surface morphology of the specimens. A voltage of 15 kV and a current of 15-20 mA were used for SEM characterizations. The chemical composition of the specimens was analyzed by XRD using a Rigaku Smartlab 1 kW powder system equipped with a Cu target. The operation voltage and current were 40 kV and 44 mA, respectively. Scan ranges from 20 to 90° were used with a scan rate of 0.5 °/min.

2.4. Process Run Time vs. Total Exposure Time Unlike stable laboratory environments, the pilot-scale CO2 capture process in the present study was operated intermittently, with repetitive process startups and shutdowns due to the work shifts and operating schedules of the power station, which may result in a high corrosion rate due to thermal cycling27. The specimens were exposed to the process environments for the entire experiment as a more representative study of actual commercial processes. To document the results, two time definitions, process run time and total exposure time, were used. Process run time is counted only when the CO2 capture process was operating while total exposure time is counted from initial installation of the specimens into the process until sampling (removal), regardless of the process operating status. The accumulated process run time as well as the corresponding total exposure time for each sampling event can be found in the supporting information (Table S1). Without further clarification, the results reported below are based on the process run time.

3. Results and Discussion

3.1. Operating Conditions at the Pilot Plant



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The operating conditions in the pilot plant were constantly monitored during the experiment. Due to the frequent process shutdowns, a significant amount of transitional time was observed during the experiment, which significantly affected operating parameters, for example, temperature. A large fluctuation of temperature was observed, as exemplified in the supporting information (Figure S3). Nevertheless, the ranges of characteristic operating conditions for the individual process unit locations were identified. Table 2 shows typical operating conditions, in order to demonstrate how the conditions vary depending on the location within the process. The absorber column and the cold CO2 lean amine piping had moderate operating conditions, while the conditions were much harsher within the stripper column and in the hot CO2 rich amine piping with a significantly higher maximum temperature and pressure observed. Therefore, the latter two locations were more susceptible to internal corrosion problems. In addition, it is noted that the upper limit of the CO2 loading at the absorber outlet occasionally reached higher values (up to 0.65 mol CO2/mol amine in Table 2). Fluctuations in the MEA concentration (and alkalinity of the solvent) led to high CO2 loading values, some of which were out of the normal CO2 loading range for a 30 wt.% MEA solvent.


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Table 2. Typical operating conditions in the pilot-scale CO2 capture process.

Range Flue gas inlet CO2 (vol.%)

14 – 16

Flue gas inlet O2 (vol.%)

6 – 12

Flue gas inlet SO2 (ppm)

5 mm/yr) in each of these locations. The results indicate that Ni-coated carbon steel shows no marked benefit over bare carbon steel in this process. Interestingly, it is also noted that Ni-coated carbon steel suffered more corrosion in the cold lean piping than in the absorber column. Recalling the fact that the operating temperature in the absorber at the corrosion sampling location was much higher than in the CO2 lean amine piping prior to entering the absorber (Table 2), this suggests that either the flow effect in the piping on corrosion was significant, or the temperature (lower in the CO2 lean amine piping) played a role in the nickel dissolution process. Regarding the Ni2Al3-coated carbon steel, the relatively low corrosion rates prior to 250 hours suggest that this coating was quite protective, initially. However, the corrosion rate eventually reached the same level as that of other carbon steels, which indicates that the protective Ni2Al3 coating lost its integrity after 250 hours. It is noted that under the harsh conditions in the stripper, all A106 carbon steel-based specimens (A106, Ni-coated A106, Ni2Al3-coated A106) were lost after 500 hours, which highlights the


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need for proper materials of construction in the stripper. To provide a reference, corrosion rates for carbon steels in the stripper after 500 hours were calculated, assuming a final specimen mass of zero (denoted by dash lines in Figure 3(c)). While carbon steels showed substantial corrosion in certain locations, stainless steel (SS304) was found to be stable and corrosion resistant in all of the sampling locations at all sampling events. To compare the corrosion behavior of all materials, Figure 4 and Figure 5 show representative pictures of each specimen at all four sampling locations after approximately 500 and 1000 hours of process run time, respectively. Immediately apparent in Figure 4 is the substantial loss of specimen thickness/mass for the A106, Ni-coated A106, and Ni2Al3-coated A106 carbon steel in the stripper column (S). In addition, substantive thickness loss is seen for all of these carbon steel-based specimens in the CO2 rich amine piping prior to entering the stripper (HR) while they are stable for the absorber (A) and CO2 lean amine piping prior to the absorber (CL) process locations. Similar corrosion behavior was observed for specimens after 1000 process run hours (shown in Figure 5). In fact, the corrosion rate of all carbon steels in the stripper was so high that specimens were lost at that time. The results suggest that these coatings on carbon steel eventually showed no corrosion benefit in the process.



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Figure 3. Mass loss corrosion rates based on process run time for A106, Ni-coated A106, Ni2Al3-coated A106, and SS304 in the (a) absorber column, (b) CO2 lean amine piping, (c) stripper column, and (d) CO2 rich amine piping. For the stripper (c), corrosion rates for carbon steels after 500 process run hours are calculated values (dash lines), assuming a final specimen mass of zero.


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Figure 4. Corrosion specimens after approximately 500 hours of process run time in the carbon capture unit in the absorber column (A), CO2 rich amine piping prior to the stripper (HR), CO2 lean amine piping prior to the absorber (CL), and stripper column (S).



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Figure 5. Corrosion specimens after approximately 1000 hours of process run time in the carbon capture unit in the absorber column (A), CO2 rich amine piping prior to the stripper (HR), CO2 lean amine piping prior to the absorber (CL), and stripper column (S). A106 specimens in the stripper column are not shown due to loss of specimen after 500 hours.

3.3. Surface Characterizations

In addition to examining the corrosion rate, surface analyses were carried out to determine the type of corrosion that occurred. The post-test surface morphology of all specimens was examined with SEM. Figure 6 shows representative images of all types of materials from the stripper column after 500 hours of process run time, and substantial corrosion of carbon steel is observed. The bare carbon steel Figure 6(a) showed a uniformly-corroded surface, while no appreciable corrosion was observed for stainless


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steel Figure 6(d). Local damage and removal of the top layers can be clearly seen for the Ni-coated and Ni2Al3-coated carbon steels (see Figure 6(b) and (c)).

Figure 6. SEM images of corrosion specimens after 500 hours of process run time in the stripper column: (a) A106 carbon steel, (b) Ni-coated A106, (c) Ni2Al3-coated A106, and (d) SS304 stainless steel.

XRD analysis was carried out to determine the presence and type of corrosion products for each of the corrosion specimens at each sampling location. Phases were identified by matching the measured peaks to reference phases in the ICDD-PDF (International Centre for Diffraction Data – Powder Diffraction



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File) database. Shown in Figure 7 are the XRD patterns for stainless steel (SS304) at all four sampling locations at 125, 500, and 1000 hours of process run time. The only peaks present in these patterns correspond to the major chemical constituents of stainless steel such as iron, chromium and nickel, and the characteristic peak positions are similar to those of SS304 reported in the literature28. These results were anticipated as the corrosion rate of SS304 was zero, and corrosion specimens appeared unaffected at all sampling locations. It is noted that the corrosion-resistant passive films (normally chromium-rich oxides) formed on the stainless steel surface were not detected by XRD, which is due to the very thin thickness of these films (on the order of nm)29. A106 carbon steel corrosion specimens differed significantly from the SS304 specimens. Shown in Figure 8 are the XRD patterns for A106 at all 4 sample locations. From locations with moderate corrosion (i.e., within the absorber and the CO2 lean amine piping), only the steel substrate (iron) was identified. On the other hand, corrosion products were found on specimens within the stripper and CO2 rich amine piping where more substantial corrosion of carbon steel took place. For example, iron carbide (Fe3C) was found in the stripper after 500 hours, and in the hot rich amine piping after 1000 hours. In addition, calcium carbonate (CaCO3) was seen on specimens from the CO2 rich amine piping after 1000 hours (as also evidenced by the SEM/EDS results in the supporting information, Figure S4). The source of the calcium was most likely related to the water used in this CO2 capture process or entrainment from the limestone-based wet flue gas desulfurization (WFGD) unit deployed for SOx control. The results indicate that carbon steel underwent severe corrosion attack in the stripper and CO2 rich amine piping. For the Ni-coated carbon steel specimens, only nickel was identified on specimens from within the absorber, from 125 hours throughout 1000 hours (Figure 9), which suggests that the nickel coating (initial thickness of ~100 um) still fully covered the steel surface even after 1000 hours. However, in the CO2 lean and CO2 rich amine piping sections, this nickel coating was lost after 500 hours and 125 hours,


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respectively, as only peaks related to iron were seen from that point forward. Iron was also seen in the stripper after only 125 hours, indicating the partial loss of this coating. It is noted that only peaks associated with nickel were seen after 500 hours in the stripper without the appearance of iron peaks. This can be also explained by the partial loss of the coating, if the XRD scanned on a portion of the surface where the nickel coating remained, as visually evidenced by Figure 4. For the Ni2Al3-coated carbon steel, when comparing the XRD patterns from all 4 sample locations (as seen in Figure 10), it was found that the Ni2Al3 coating was stable in the absorber and CO2 lean amine piping throughout 1000 hours of process run time. However, minor phases such as nickel and iron were also identified eventually on specimens from the stripper and CO2 rich amine piping, which indicates partial loss of the Ni2Al3 coating layer over time. In addition, CaCO3 was found in the CO2 rich amine piping section after 1000 hours again. This was likely due to the calcium-containing service water used in the process, and the low solubility of CaCO3 at high temperature30.



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Figure 7. XRD patterns of SS304 stainless steel specimens after 125, 500, and 1000 hours of process run time in the (a) absorber column, (b) CO2 cold lean amine piping, (c) stripper column, and (d) CO2 rich amine piping. Reference phases with PDF card numbers and peak positions are provided.


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Figure 8. XRD patterns of A106 carbon steel specimens after 125, 500, and 1000 hours of process run time in the (a) absorber column, (b) CO2 lean amine piping, (c) stripper column, and (d) CO2 rich amine piping. Reference phases with PDF card numbers and peak positions are provided. Patterns after 1000 hours from the stripper column are not shown due to loss of the specimens.



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Figure 9. XRD patterns of Ni-coated A106 carbon steel specimens after 125, 500, and 1000 hours of process run time in the (a) absorber column, (b) CO2 lean amine piping, (c) stripper column, and (d) CO2 rich amine piping. Reference phases with PDF card numbers and peak positions are provided. Patterns after 1000 hours from the stripper column are not shown due to loss of the specimens.


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Figure 10. XRD patterns of Ni2Al3-coated A106 carbon steel specimens after 125, 500, and 1000 hours of process run time in the (a) absorber column, (b) CO2 lean amine piping, (c) stripper column, and (d) CO2 rich amine piping. Reference phases with PDF card numbers and peak positions are provided. Patterns after 1000 hours from the stripper column are not shown due to loss of the specimens.



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Particularly interesting for the Ni-coated and Ni2Al3-coated carbon steel specimens in both the corrosion rate results (as shown in Figure 3) and the XRD results (as shown in Figure 9 and Figure 10) is the apparent loss of the coatings over time, subsequently resulting in corrosion rates or XRD patterns resembling bare A106 carbon steel. To confirm loss of these coatings, cross-sectional samples of the specimens were prepared, and analyzed by SEM/EDS. For example, the cross-sections with EDS line scans of the Ni-coated and Ni2Al3-coated specimens in the stripper after 250 hours and 500 hours of process run time are shown in Figure 11 and Figure 12, respectively. Both coatings suffered corrosion damage after 250 hours. Part of the Ni coating was lost, where severe localized corrosion of the underlying steel substrate occurred (see Figure 11(a)). For Ni2Al3-coated carbon steel, although a continuous top Ni2Al3 layer (~50 µm) was still visible, local thickness loss of this layer was observed (see Figure 11(b)). This is consistent with the fact that a substantial corrosion rate (~2.5 mm/yr) for Ni2Al3-coated carbon steel in the stripper after 250 hours was observed (Figure 3(c)), which may be due to dissolution of the top protective Al2O3 thin layer25 and subsequent corrosion of the underlying Ni2Al3 coating and carbon steel. For both specimens after 500 process run hours, the coatings completely lost their integrity and a large surface area of the steel substrate was directly exposed to the corrosive environment, where severe local corrosion damage of the underlying iron substrate was seen (see Figure 12(a) and (b)). The results demonstrated that neither of these coatings were stable or protective under the extreme conditions of this process, e.g., the stripper and CO2 rich amine piping conditions. Moreover, local breakdown of these coatings resulted in severe corrosion damage of the underlying carbon steel substrate.


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Figure 11. Cross-sectional SEM images of corrosion specimens with EDS line scan results from within the stripper column: (a) Ni-coated A106 after 250 hours, (b) Ni2Al3-coated A106 after 250 hours. EDS scans follow the yellow lines.



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Figure 12. Cross-sectional SEM images of corrosion specimens with EDS line scan results from within the stripper column: (a) Ni-coated A106 after 500 hours, (b) Ni2Al3-coated A106 after 500 hours. EDS scans follow the yellow lines.

3.4. Discussion

In the present study, the Ni2Al3 coating was found to provide short-term protection for certain highly corrosive aqueous environments (such as in contact with spray, as in the stripper column) in a postcombustion CO2 capture process. The protection may be from the top alumina layer of the Ni 2Al3 coating, and the lack of continuous formation of dense Al2O3 layers in the absence of effective oxygen content and favorable temperature prohibits long-term protection. This is consistent with previous findings carried out in a laboratory environment that the Ni2Al3 coating alone did not improve corrosion resistance, but the alumina layer formed on the coating surface did24. Once this thin layer (~ 2 µm)25 was


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depleted, more significant corrosion took place. As evidenced by Figure 3 (c) and (d), dramatic corrosion increases were found for Ni2Al3 coating after 250 hours in the stripper and after 500 hours in the CO2 rich amine piping. Apparently, protective alumina surface layers did not survive in this high temperature high pressure CO2-loaded aqueous amine solution over longer time periods. Ultimately a very thick as-tested alumina coating would be needed to ensure equipment integrity. It is found in the literature that alumina may gradually dissolve in alkaline solutions at elevated temperatures with the formation of tetrahydroxoaluminate ions.31 This may be the reason why the as-tested Ni2Al3 coating only provided short-term protection, but eventually broke down. Furthermore, Ni-coated carbon steel was tested in this study. Generally, nickel has outstanding corrosion resistance in caustic alkaline solutions.32,33 However, the Ni coating showed no corrosion protection over carbon steel in the present study. This study investigated long-term corrosion in MEA capture solutions where the presence of other compounds in this solvent from degradation or dissolved gas phase contaminants may have hastened the corrosion rate of this coating, and ultimately the underlying carbon steel. The present study shows that the combination of high temperature, high pressure, high CO2 loading, and complex solution chemistry remains a concern for corrosion prevention and control in a postcombustion CO2 capture process7. Seeking a more stable corrosion coating is therefore still a topic of interest. For example, thick nonmetallic coatings could be an economic option.6,19 Research efforts have also been put into promoting the formation of protective iron carbonate layers,34,35 a natural corrosion product of carbon steel in certain aqueous CO2 environments.12,17 This could be another direction to pursue for corrosion mitigation. Seeking stable corrosion inhibitors with less environmental impact is an alternative option.21 While these inhibitors may be consumed or degraded over time, they are more easily replenished than



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conventional coatings in process units of CO2 capture operations. However, their potential influence on solvent performance needs to be considered.

4. Conclusions

In this research, the corrosion behavior of coated and non-coated carbon steel as well as stainless steel was investigated in a pilot-scale post combustion CO2 capture process with a 30 wt.% aqueous monoethanolamine (MEA) solvent. Based on the presented results, several conclusions can be drawn:  It appears that for a post-combustion CO2 capture process, corrosion issues in process units such as the absorber and CO2 lean amine piping sections are rather low as all of the carbon steel specimens showed adequate corrosion performance. Changing the construction material from stainless steel to carbon steel could substantially reduce the capital cost in future carbon capture projects for utility flue gas applications.  A significant amount of corrosion occurred in the stripper and CO2 rich amine piping sections with harsh operating conditions for all carbon steel-based specimens. Ni2Al3/Al2O3-coated carbon steel ultimately showed no corrosion benefit at those locations, although initial protection was found prior to 250 hours of process run time. The results suggest that bare carbon steel and carbon steel with the as-tested coatings are not suitable for use at locations where harsh environments are expected, such as the stripper column and CO2 rich amine piping sections. Either a more corrosion-resistant material (e.g., stainless steel) or carbon steel with a more effective corrosion mitigation strategy is required in that portion of the process. The latter option is currently a more economically sound direction for future investigation.


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 The presented study highlights the necessity for long-term testing of materials (e.g., > 500 hours) in the CO2 capture process. This study covered a process run time up to 1000 hours (the total exposure time in the process was much longer, up to 2500 hours); and the loss of the protective coating on carbon steel occurred after a fairly long testing time. For example, the Ni2Al3/Al2O3 coating initially appeared to be protective in the CO2 rich amine piping section until losing its integrity after 250 hours of process run time (600 hours of total exposure time). Unfortunately, long-term testing is often lacking, especially in laboratory environments. To more closely simulate the materials behavior in a real CO2 capture process, long-term investigation is therefore recommended for future studies.

Supporting Information

Images of corrosion sampling rack assembly and the actual specimen numbering, calculated values of process run time and total exposure time, temperature profile at the four sampling locations, and EDS results for A106 carbon steel in the CO2 rich amine piping.

Acknowledgements

The authors would like to acknowledge the Department of Energy National Energy Technology Laboratory (NETL) for the primary financial support of this project (DE-FE0007395). Additional financial support was provided by Louisville Gas & Electric (LG&E) and Kentucky Utilities (KU), Duke Energy, Electric Power Research Institute (EPRI), Kentucky Power, and the Kentucky Department of Energy Development and Independence (KY-DEDI). The authors would like to thank the UKy-



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CAER operations staff including Len Goodpaster, Otto Hoffmann, Marshall Marcum, Andy Placido and Amanda Warriner. The authors would also like to thank everyone at KU E.W. Brown Station for serving as the host site and for their support of this project.

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For Table of Contents (TOC)/Abstract graphic only


Use of Carbon Steel for Construction of Post-Combustion CO2

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