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Title: Application of a Heat Integrated Post-combustion CO2 Capture System with Hitachi Advanced Solvent into Existing Coal-Fired Power Plant

Abstract

The goal of this final project report is to comprehensively summarize the work conducted on project DE-FE0007395. In accordance with the Project Management Plan (PMP), Revision F dated 5/10/2019, and Statement of Project Objectives (SOPO) within, the University of Kentucky (UK) Center for Applied Energy Research (CAER) (Recipient) has successfully demonstrated a unique, versatile CO2 capture system (CCS) using a heat integrated process combined with two-stage stripping for process intensification, heat recovery and demineralized (DM) water generation. This project involved the design, fabrication, installation, testing of and data analysis from the UK CAER 0.7 MWe small pilot scale CO2 capture process installed at Kentucky Utilities (KU) E.W. Brown Generating Station in Harrodsburg, KY. During each of the four project Budget Periods (BPs), UK CAER met all project deliverables, all project milestones, with National Energy Technology Laboratory (NETL) approved adjustments made to the campaign long-term hours during BP4. The CCS was constructed in modular skids. Two solvent campaigns were initially conducted; the first with a 30 wt% monoethanolamine (MEA) as a baseline, and the second with the Hitachi H3-1 advanced solvent. Additional tests were performed with two advanced solvents including CAER and Proprietary Solvent C. Short-period testing with a higher concentrationmore » of 40 wt% MEA was conducted to evaluate the potential saving with high alkalinity. From the various solvent campaigns, unique aspects of the UK CAER CCS technology, as well as its flexibility and versatility were experimentally validated and demonstrated. With respect to solvent evaluation efforts in identifying candidates with significant operational and capital cost savings potential, performance of solvents were evaluated to determine the energy requirements for regeneration; environmental impacts from secondary emissions and degradation products; degradation rates, solvent make-up rates and stability. The assessments were done from parametric tests that determined optimum operating conditions for the individual solvents to maximize process efficiency and minimize the parasitic load of the power plant, and from long term campaigns (1000 hours for 30 wt% MEA and 1000 hours for H3-1) which collectively informed the techno-economic analyses (TEA) of the process. The long term campaigns included corrosion studies which used three types of metal coupons in different sections of the process: (absorber, primary stripper, lean carbon-loaded and rich carbon loaded flow streams in process) to mimic heat and flow dynamics process equipment were exposed to. The estimated corrosion rates were used to elucidate corrosion mechanisms and to further guide process material selection for potential capital cost savings. The scope of the technology evaluation was broadened towards the end of the project by the addition of two major components: (i) a pre-concentrating membrane separation unit and (ii) a solid-assisted solvent recovery system. The membrane was used to increase the CO2 content in the stream fed to the bottom of the absorber for enhanced rich carbon loading by pre-concentrating the incoming flue gas. The solvent recovery system involved a novel concept of addition of activated carbon as nucleation site to recover entrained solvent that could have been lost as aerosols emissions. Tests were performed to evaluate the effectiveness of the membrane-absorption hybrid process on solvent performance for CO2 capture and the solvent recovery system for reducing solvent emissions from the top of the absorber. Among the various innovative aspects of the process and studies performed, some of the key findings are: (i) The effectiveness of the secondary air stripper in the additional stripping, with the resultant leaner solvents it provided to the absorber for enhanced CO2 absorption. (ii) The impact of the secondary air stripper to oxidative degradation of solvents shown to be negligible. (iii) The performance of MEA and H3-1 shown to validate TEA projected energy of regeneration. The energy savings attainable with H3-1 as an advanced solvent as well as ~70% lower solvent degradation in comparison with MEA was also demonstrated. (iv) Process temperatures and solvent carbon loadings affected extent of corrosion in different parts of the process. Notably, the corrosion in the absorber and CO2-lean amine piping sections were negligible compared to the significant corrosions detected in the stripper and CO2-rich amine piping sections. The presence of chemical additives in H3-1 resulted in significantly reduced corrosion compared to MEA with no inhibitors. (v) Use of effective corrosion inhibitors to avert corrosion concerns with higher amine concentration would promote assessing associated energy savings of ~20% observed with 40 wt% MEA tests relative to 30 wt% MEA. (vi) Addition of the solvent recovery system significantly reduced amine losses entrained with gas exiting from the top of the absorber with the amine concentration being less than 1ppm. (vii) The net efficiency of the UK CAER integrated pulverized coal (PC) power plant with CO2 capture changes from 26.2% for the Reference Case (RC) 10 plant in 2010 revised U.S. Department of Energy (DOE)/NETL baseline report to 27.6% for MEA and 29.1% when utilizing the Hitachi advanced solvent. The CAER Process + Hitachi case also produces an extra 60.9 MW more than DOE RC 10. Levelized Cost of Electricity (LCOE) ($/MWh) values are $157.65/MWh considered in comparison to $189.59/MWh in January 2012 dollar for RC 10. (viii) The pre-concentrating membrane could result in high carbon loading but the effectiveness of high gas CO2 in the incoming stream was observed to have close relationship with solvent temperature exiting the packing bottom. Other findings and lessons learned during the various stages of the project are highlighted together with recommendations for the advancement of the post-combustion CO2 capture technology. Overall, the successful demonstration of the UK CAER CCS shows that this process can be scaled up to help pave the way to achieve the DOE CO2 capture performance and cost targets, as indicated in the project TEA.« less

Authors:
 [1];  [1];  [1];  [1];  [1];  [1];  [1];  [1];  [1];  [1];  [1];  [1];  [1];  [2];  [3];  [3]
  1. Univ. of Kentucky, Lexington, KY (United States)
  2. Smith Management Group, Lexington, KY (United States)
  3. Electric Power Research Inst. (EPRI), Palo Alto, CA (United States)
Publication Date:
Research Org.:
Univ. of Kentucky, Lexington, KY (United States)
Sponsoring Org.:
USDOE Office of Fossil Energy (FE)
OSTI Identifier:
1635102
Report Number(s):
DOE/FE0007395-4
DOE Contract Number:  
FE0007395
Resource Type:
Technical Report
Country of Publication:
United States
Language:
English
Subject:
01 COAL, LIGNITE, AND PEAT; 20 FOSSIL-FUELED POWER PLANTS; 37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CHEMISTRY; 42 ENGINEERING; 99 GENERAL AND MISCELLANEOUS; heat integration; carbon dioxide capture; solvent management; power generation; efficiency improvement; power plant; carbon management; gas separation; corrosion; solvent development; CO2; carbon capture and storage; combustion; flue gas; scrubber; stripper; pilot plant; slipstream; CO2 capture; mass transfer; kinetics; acid gas absorption

Citation Formats

Liu, Kunlei, Nikolic, Heather, Thompson, Jesse, Frimpong, Reynolds, Richburg, Lisa, Abad, Keemia, Bhatnagar, Saloni, Irvin, Bradley, Landon, James, Li, Wei, Matin, Naser Seyed, Pelgen, Jonathan, Placido, Andrew, Whitney, Clayton, Bhown, Abhoyjit, and Du, Yang. Application of a Heat Integrated Post-combustion CO2 Capture System with Hitachi Advanced Solvent into Existing Coal-Fired Power Plant. United States: N. p., 2020. Web. doi:10.2172/1635102.
Liu, Kunlei, Nikolic, Heather, Thompson, Jesse, Frimpong, Reynolds, Richburg, Lisa, Abad, Keemia, Bhatnagar, Saloni, Irvin, Bradley, Landon, James, Li, Wei, Matin, Naser Seyed, Pelgen, Jonathan, Placido, Andrew, Whitney, Clayton, Bhown, Abhoyjit, & Du, Yang. Application of a Heat Integrated Post-combustion CO2 Capture System with Hitachi Advanced Solvent into Existing Coal-Fired Power Plant. United States. https://doi.org/10.2172/1635102
Liu, Kunlei, Nikolic, Heather, Thompson, Jesse, Frimpong, Reynolds, Richburg, Lisa, Abad, Keemia, Bhatnagar, Saloni, Irvin, Bradley, Landon, James, Li, Wei, Matin, Naser Seyed, Pelgen, Jonathan, Placido, Andrew, Whitney, Clayton, Bhown, Abhoyjit, and Du, Yang. 2020. "Application of a Heat Integrated Post-combustion CO2 Capture System with Hitachi Advanced Solvent into Existing Coal-Fired Power Plant". United States. https://doi.org/10.2172/1635102. https://www.osti.gov/servlets/purl/1635102.
@article{osti_1635102,
title = {Application of a Heat Integrated Post-combustion CO2 Capture System with Hitachi Advanced Solvent into Existing Coal-Fired Power Plant},
author = {Liu, Kunlei and Nikolic, Heather and Thompson, Jesse and Frimpong, Reynolds and Richburg, Lisa and Abad, Keemia and Bhatnagar, Saloni and Irvin, Bradley and Landon, James and Li, Wei and Matin, Naser Seyed and Pelgen, Jonathan and Placido, Andrew and Whitney, Clayton and Bhown, Abhoyjit and Du, Yang},
abstractNote = {The goal of this final project report is to comprehensively summarize the work conducted on project DE-FE0007395. In accordance with the Project Management Plan (PMP), Revision F dated 5/10/2019, and Statement of Project Objectives (SOPO) within, the University of Kentucky (UK) Center for Applied Energy Research (CAER) (Recipient) has successfully demonstrated a unique, versatile CO2 capture system (CCS) using a heat integrated process combined with two-stage stripping for process intensification, heat recovery and demineralized (DM) water generation. This project involved the design, fabrication, installation, testing of and data analysis from the UK CAER 0.7 MWe small pilot scale CO2 capture process installed at Kentucky Utilities (KU) E.W. Brown Generating Station in Harrodsburg, KY. During each of the four project Budget Periods (BPs), UK CAER met all project deliverables, all project milestones, with National Energy Technology Laboratory (NETL) approved adjustments made to the campaign long-term hours during BP4. The CCS was constructed in modular skids. Two solvent campaigns were initially conducted; the first with a 30 wt% monoethanolamine (MEA) as a baseline, and the second with the Hitachi H3-1 advanced solvent. Additional tests were performed with two advanced solvents including CAER and Proprietary Solvent C. Short-period testing with a higher concentration of 40 wt% MEA was conducted to evaluate the potential saving with high alkalinity. From the various solvent campaigns, unique aspects of the UK CAER CCS technology, as well as its flexibility and versatility were experimentally validated and demonstrated. With respect to solvent evaluation efforts in identifying candidates with significant operational and capital cost savings potential, performance of solvents were evaluated to determine the energy requirements for regeneration; environmental impacts from secondary emissions and degradation products; degradation rates, solvent make-up rates and stability. The assessments were done from parametric tests that determined optimum operating conditions for the individual solvents to maximize process efficiency and minimize the parasitic load of the power plant, and from long term campaigns (1000 hours for 30 wt% MEA and 1000 hours for H3-1) which collectively informed the techno-economic analyses (TEA) of the process. The long term campaigns included corrosion studies which used three types of metal coupons in different sections of the process: (absorber, primary stripper, lean carbon-loaded and rich carbon loaded flow streams in process) to mimic heat and flow dynamics process equipment were exposed to. The estimated corrosion rates were used to elucidate corrosion mechanisms and to further guide process material selection for potential capital cost savings. The scope of the technology evaluation was broadened towards the end of the project by the addition of two major components: (i) a pre-concentrating membrane separation unit and (ii) a solid-assisted solvent recovery system. The membrane was used to increase the CO2 content in the stream fed to the bottom of the absorber for enhanced rich carbon loading by pre-concentrating the incoming flue gas. The solvent recovery system involved a novel concept of addition of activated carbon as nucleation site to recover entrained solvent that could have been lost as aerosols emissions. Tests were performed to evaluate the effectiveness of the membrane-absorption hybrid process on solvent performance for CO2 capture and the solvent recovery system for reducing solvent emissions from the top of the absorber. Among the various innovative aspects of the process and studies performed, some of the key findings are: (i) The effectiveness of the secondary air stripper in the additional stripping, with the resultant leaner solvents it provided to the absorber for enhanced CO2 absorption. (ii) The impact of the secondary air stripper to oxidative degradation of solvents shown to be negligible. (iii) The performance of MEA and H3-1 shown to validate TEA projected energy of regeneration. The energy savings attainable with H3-1 as an advanced solvent as well as ~70% lower solvent degradation in comparison with MEA was also demonstrated. (iv) Process temperatures and solvent carbon loadings affected extent of corrosion in different parts of the process. Notably, the corrosion in the absorber and CO2-lean amine piping sections were negligible compared to the significant corrosions detected in the stripper and CO2-rich amine piping sections. The presence of chemical additives in H3-1 resulted in significantly reduced corrosion compared to MEA with no inhibitors. (v) Use of effective corrosion inhibitors to avert corrosion concerns with higher amine concentration would promote assessing associated energy savings of ~20% observed with 40 wt% MEA tests relative to 30 wt% MEA. (vi) Addition of the solvent recovery system significantly reduced amine losses entrained with gas exiting from the top of the absorber with the amine concentration being less than 1ppm. (vii) The net efficiency of the UK CAER integrated pulverized coal (PC) power plant with CO2 capture changes from 26.2% for the Reference Case (RC) 10 plant in 2010 revised U.S. Department of Energy (DOE)/NETL baseline report to 27.6% for MEA and 29.1% when utilizing the Hitachi advanced solvent. The CAER Process + Hitachi case also produces an extra 60.9 MW more than DOE RC 10. Levelized Cost of Electricity (LCOE) ($/MWh) values are $157.65/MWh considered in comparison to $189.59/MWh in January 2012 dollar for RC 10. (viii) The pre-concentrating membrane could result in high carbon loading but the effectiveness of high gas CO2 in the incoming stream was observed to have close relationship with solvent temperature exiting the packing bottom. Other findings and lessons learned during the various stages of the project are highlighted together with recommendations for the advancement of the post-combustion CO2 capture technology. Overall, the successful demonstration of the UK CAER CCS shows that this process can be scaled up to help pave the way to achieve the DOE CO2 capture performance and cost targets, as indicated in the project TEA.},
doi = {10.2172/1635102},
url = {https://www.osti.gov/biblio/1635102}, journal = {},
number = ,
volume = ,
place = {United States},
year = {2020},
month = {6}
}