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carbon capture and storage (CCS)

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Presentation on theme: "carbon capture and storage (CCS)"— Presentation transcript:

1 carbon capture and storage (CCS)
Evaluation of carbon capture and storage (CCS) technologies for Integrated Gasification Combined Cycle (IGCC) power plants Calin-Cristian Cormos “Babeş – Bolyai” University, Faculty of Chemistry and Chemical Engineering 11 Arany Janos, RO400028, Cluj – Napoca, Romania

2 Content Introduction Plant configurations & major design assumptions Modeling and simulation of IGCC-based power generation with and without CCS Mass and energy integration aspects Techno-economic and environmental evaluations Conclusions

3 Introduction The following work was performed within the project:
“Innovative systems for carbon dioxide capture applied to energy conversion processes”, PNII-CT-ERC ; 2ERC Specific project objectives: - Investigation of combustion & gasification processes - Energy vector poly-generation (e.g. power, hydrogen) - Evaluation of carbon capture & storage technologies (gas-liquid absorption, chemical looping) - Techno-economical and environmental evaluations of power plants with CCS

4 II. Plant configurations IGCC power plant without CCS
Gasification O2 Coal + Transport gas (N2) Air Syngas Boiler and Cooling Steam Slag Acid Gas Removal (AGR) Claus Plant and Tail gas Treatment Sulphur Combined Cycle Gas Turbine Power N2 Flue gas to stack Air Separation Unit (ASU) and O2 / N2 Compression

5 IGCC power plant with CCS
(pre-combustion capture based on gas-liquid absorption) Water – Gas Shift CO2 to storage CO2 Drying and Compression Gasification Air Separation Unit (ASU) and O2 / N2 Compression O2 Coal + Transport gas (N2) Air Syngas Boiler and Cooling Steam Slag Acid Gas Removal (AGR) Claus Plant and Tail gas Treatment Sulphur Combined Cycle Gas Turbine Power N2 Flue gas to stack

6 IGCC power plant with CCS
(post-combustion capture based on gas-liquid absorption) CO2 Capture (post-combustion) CO2 to storage CO2 Drying and Compression Gasification Air Separation Unit (ASU) and O2 / N2 Compression O2 Coal + Transport gas (N2) Air Syngas Quench and Cooling Steam Slag Acid Gas Removal (AGR) Claus Plant and Tail gas Treatment Sulphur Combined Cycle Gas Turbine Power N2

7 IGCC power plant with CCS
(pre-combustion capture based on chemical looping) Fuel (syngas) reactor CO2 to storage CO2 Drying and Compression Gasification Air Separation Unit (ASU) and O2 / N2 Compression O2 Coal + Transport gas (N2) Air Syngas Quench and Cooling Steam Slag Acid Gas Removal (AGR) Claus Plant and Tail gas Treatment Sulphur Combined Cycle Gas Turbine Power N2 Condensate Fe/FeO Fe3O4

8 Major design assumptions
Plant size: ~400 MW net power, 0 – 150 MWth H2 (LHV) Shell gasifier (entrained-flow type) Gas turbine: M701G2 gas turbine (MHI) 4. Carbon capture rate: >90 % 5. H2 purity & pressure: >99.95 % (vol.) / 70 bar 6. CO2 capture: Selexol & MDEA (G-L) / Iron cycle (CL) 7. CO2 purity & pressure: >95 % (vol.) / 120 bar 8. Fuel type: Bituminous coal

9 III. Modeling and simulation of
IGCC-based power generation with/without CCS Investigated power plant concepts: Case 1: IGCC without CO2 capture Case 2: IGCC with pre-combustion CO2 capture using physical gas-liquid absorption (Selexol®) Case 3: IGCC with post-combustion CO2 capture using chemical gas-liquid absorption (Methyl Diethanol-Amine - MDEA) Case 4: IGCC with pre-combustion CO2 capture using iron-based chemical looping system

10 Simulation tools for evaluations of
IGCC-based power generation with/without CCS Investigated case studies were simulated using process flow modelling (ChemCAD and Thermoflex) Power island Case 2: IGCC with CCS (pre-combustion capture – Selexol®) Gasification island Syngas Conditioning & Water Gas Shift Acid Gas Removal & CO2 Drying and Compression

11 IV. Mass and energy integration aspects
Investigated mass and energy integration aspects: - Steam integration between fuel processing units (gasification), syngas conditioning line, carbon capture unit and power block (combined cycle) - Heat and power integration for Acid Gas Removal unit (solvent pumping & regeneration, chemical looping cycle, captured CO2 stream drying and compression) - Integration of combustible gas flows between syngas conditioning line, power block and hydrogen purification unit (for H2 and power co-production cases)

12 Steam integration Case 1 (no CCS) Case 2 (CCS) HP steam from process
t/h 573oC / 118 bar 338oC / 120 bar HP steam to HP Steam Turbine 576oC / 118 bar 576oC / 118 bar MP steam after MP reheat 465oC / 34 bar 446oC / 34 bar MP steam to process units 418oC / 41 bar 415oC / 41 bar MP steam AGR (solvent reg.) 265oC / 6.5 bar 251oC / 6.5 bar LP steam from process units 206oC / 3 bar 202oC / 3 bar LP steam to LP Steam Turbine 196oC / 3 bar 180oC / 3 bar Cooling water 15oC / 2 bar 15oC / 2 bar Hot condensate to HRSG 115oC / 2.8 bar 115oC / 2.8 bar Flue gas at stack 105oC / 1.1 bar 101oC / 1.1 bar Steam turbine generated power MWe 224.01 210.84

13 heat and power integration (Selexol® solvent)
Acid Gas Removal heat and power integration (Selexol® solvent) Case 1 Case 2 Air Separation Unit (ASU) MWe 27.81 31.33 Oxygen compression 12.10 13.40 Gasification island consumption 8.38 9.12 Acid Gas Removal (AGR) - Selexol® 6.12 13.12 CO2 drying and compression 0.00 26.69 Power island consumption 19.09 18.78 Ancillary power consumption 73.50 112.44 Heat consumption (carbon capture) MJ/kg CO2 0.22

14 heat and power integration
Acid Gas Removal heat and power integration Evaluated AGR solvents (pre-combustion capture): - Selexol® (dimethyl ethers of polyethylene glycol) - Rectisol® (refrigerated methanol) - Methyl-diethanol-amine (MDEA) Ancillary duty Units Selexol® Rectisol® MDEA Power duty kWh/kg captured CO2 0.1080 0.1186 0.0950 Heating duty MJ/kg captured CO2 0.2238 0.3740 0.7015 Cooling duty 0.5590 0.6156 3.3141

15 Evaluation of heat integration for IGCC power plant with CCS – Case 2
Composite curves for gasifier & syngas treatment line

16 Evaluation of heat integration for IGCC power plant with CCS – Case 2
Composite curves for hydrogen-fuelled CCGT

17 environmental evaluations
V. Techno-economic and environmental evaluations Key plant performance indicators: - Technical indicators (fuel consumption, net and gross power output, ancillary consumptions, plant efficiency, CO2 capture energy penalty) - Economic indicators (capital costs, specific capital investment, fixed and variable O&M costs, levelised cost of electricity, CO2 capture cost penalty, cash flow) - Environmental indicators (carbon capture rate, specific CO2 emissions, CO2 removal and avoided costs)

18 IGCC power plants with and without CCS
Plant indicator Case 1 Case 2 Case 3 Case 4 Coal flowrate [t/h] 147.80 165.70 148.18 162.34 Coal energy [MWth] Gas turbine [MWe] 334.00 Steam turbine [MWe] 224.01 210.84 135.67 199.45 Expander power [MWe] 0.68 0.78 1.45 1.50 Gross power output [MWe] 558.69 545.62 471.12 534.95 Air separation unit [MWe] 39.91 44.73 39.98 43.82 Gasifier island [MWe] 8.38 9.12 8.21 15.06 Acid gas removal [MWe] 6.12 39.81 27.76 15.18 Power island [MWe] 19.09 18.78 19.12 22.00 Total consumption [MWe] 73.50 112.44 95.07 96.06 Net power output [MWe] 485.19 433.18 376.05 438.89 Net power efficiency [%] 46.61 37.11 36.03 38.38 Carbon capture rate [%] 0.00 90.79 90.36 99.55 CO2 emissions [kg/MWh] 741.50 86.92 90.11 3.08

19 IGCC power plants with and without CCS
Plant indicator Case 1 Case 2 Case 3 Net power output [MWe] 485.19 433.18 376.05 Gross efficiency [%] 53.67 46.75 45.14 Net efficiency [%] 46.61 37.11 36.03 Capital costs [M€] 909.63 Capital investment [€/kWe gross] Capital investment [€/kWe net] Fixed O&M costs [€/kWe net] Variable O&M costs [€/kWe net] LCOE [¢/kWe] 5.413 7.328 8.642 CO2 removal cost [€/t] - 22.68 37.41 CO2 avoided cost [€/t] 29.28 49.61

20 IGCC power plants with and without CCS Cumulative cash flow analysis
(Cases 1 to 3) Sensitivity analysis (Case 2)

21 Hydrogen and power co-generation
Plant flexibility: Hydrogen and power co-generation Gasification Air Separation Unit (ASU) O2 Coal + Transport gas (N2 ) Air Syngas Quench and Cooling Steam Slag Acid Gas Removal (AGR) Claus Plant and Tail gas Treatment Sulphur Combined Cycle Gas Turbine Purified hydrogen CO2 to storage Power H2 compression N2 CO2 Drying and Compression Fuel (syngas) reactor Desulphurised syngas reactor H2 Condensate Fe3O4 Fe/FeO

22 Co-generation plants with CCS Hydrogen and power co-generation
Plant indicator Power only Hydrogen and power co-generation Coal flowrate [t/h] 162.34 Coal energy [MWth] Gross power [MWe] 534.95 504.01 474.22 444.43 Hydrogen output [MWth] 0.00 50.00 100.00 150.00 Air separation unit [MWe] 43.82 Gasifier island [MWe] 15.06 Acid gas removal [MWe] 15.18 H2 compression [MWe] 0.56 1.13 1.70 Power island [MWe] 22.00 20.67 19.33 17.99 Total consumption [MWe] 96.06 95.29 94.52 93.75 Net power output [MWe] 438.89 408.72 379.70 350.68 Net power efficiency [%] 38.38 35.75 33.21 30.67 Hydrogen efficiency [%] 4.37 8.74 13.12 Cumulative efficiency [%] 40.12 41.95 43.79 Carbon capture rate [%] 99.55 CO2 emissions [kg/MWh] 3.08 2.92 2.79 2.68

23 Co-generation plants with CCS
Efficiency (%) Hydrogen output (MW) Variation of plant energy efficiencies vs. hydrogen output (Case 4)

24 VI. Conclusions  Introduction of CCS technologies imply significant
energy, capital and O&M costs penalties  Pre-combustion capture slightly more efficient than post-combustion capture (both based on G-L absorption)  Specific capital and O&M costs for pre-combustion capture lower than post-combustion capture  Chemical looping capture looks very promising but further developments and scale-ups are needed  IGCC technology more flexible than other conversion processes in term of fuel used and energy vector poly- generation capability (power, hydrogen, SNG, liquid fuels)

25 Thank you for your attention! Calin-Cristian Cormos
Contact: Calin-Cristian Cormos This work has been supported by Romanian National Authority for Scientific Research, CNCS – UEFISCDI, project number PNII-CT-ERC ; 2ERC

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