Institut für Energieverfahrenstechnik und Chemieingenieurwesen Advanced Modelling of ICC-Power Plant Concepts Effects of ASU-Integration on Plant Performance and as Turbine Operation Dipl.-Ing. Mathias Rieger, Dipl.-Ing. Robert Pardemann, Prof. Dr.-Ing. Bernd Meyer, TU Bergakademie Freiberg Dr.-Ing. Alexander Alekseev, Linde Engineering TU Bergakademie Freiberg I Institut für Energieverfahrenstechnik und Chemieingenieurwesen Reiche Zeche I 9596 Freiberg I Tel. +49()3731/39 4511 I Fax +49()3731/39 4555 E-Mail evt@iec.tu-freiberg.de I Web www.iec.tu-freiberg.de
P-471 Coal based ICC with CO 2 -capture asification mill and feeding system feedstock B HP-steam to CC clean gas saturator O2 saturated clean gas to CC clean dry gas CO2 coal excess N2 to environment pure AN A IP-steam from CC gasifier quench room raw gas scrubber CO-shift stage 1 CO-shift stage 2 condensate from CC make up H2S to Claus-plant Air Separation Unit slag discharge acid gas removal discharge make up discharge N2 to CC ambient air to MAC T-extraction air O2 to CC (preheating) make up cooling make up F E F E D C D B C saturated, diluted, preheated fuel gas Diluent N2 from ASU A 2
asifier unit Boundary conditions Main reactions within gasifier: C + O 2 CO 2 C + CO 2 2 CO C + 2 H 2 CH 4 CO + H 2 O H 2 + CO 2 Feedstock information: Pittsburgh No. 8 Proximate Analysis Ultimate Analysis (waf) Fixed Carbon (wt %) 5.15 C (wt %) 83.4 Volatile Matter (wt %) 36.98 H (wt %) 5.7 Moisture (wt %) 5.5 O (wt %) 6.38 Ash (wt %) 7.37 N (wt %) 1.56 Total 1. Cl (wt %).6 S (wt %) 3.26 LHV (MJ/kg) 29.888 Total 1. Modelling principle: - Thermodynamic equilibrium assumed - Steam/Oxygen ratio is adjusted to a specified carbon conversion rate at a given gasifier temperature 3
asifier unit Results and interface parameters asification temperature: 15 C 19.5 Sm³/J 4 kg/j η Cold gas 82.8 % 157 Sm³/J (wet) 73 Sm³/J (dry) as composition [mol %] CO 27.6 N 2 1.9 H 2 15.4 Ar.4 CH 4.1 CO 2.9 H 2 S.4 H 2 O 53.3 LHV 6.272 kj/kg 235 C S/ ratio = 1.32.1 J/J mol H2O S/ ratio = mol dry syngas 4
asifier unit Results quench temperature [ C] 235 225 215 25 195 185 Steam / Dry gas ratio 175 12 13 14 15 16 17 18 gasification temperature [ C] Conclusions: - Increasing quench temperature and increasing gasification temperature cause a higher steam / dry gas ratio => important for design of CO-shift cycle!! 5
P-471 Coal based ICC with CO 2 -capture as conditioning mill and feeding system feedstock B HP-steam to CC clean gas saturator O2 saturated clean gas to CC clean dry gas CO2 coal excess N2 to environment pure AN A IP-steam from CC gasifier quench room raw gas scrubber CO-shift stage 1 CO-shift stage 2 condensate from CC make up H2S to Claus-plant Air Separation Unit slag discharge acid gas removal discharge make up discharge N2 to CC ambient air to MAC T-extraction air O2 to CC (preheating) make up cooling make up F E F E D C D B C saturated, diluted, preheated fuel gas Diluent N2 from ASU A 6
as conditioning section Overview Main oals: - Recovery of CO-shift reaction heat => HP-steam generation - Recovery of evaporation enthalpy => Quench and saturation preheating - As little as possible interfaces to other ICC-sections HP-steam generation 8.4 % heat recovery based on gasifier input Quench preheating 7.8 % heat recovery based on gasifier input Saturation preheating 5.1 % heat recovery based on gasifier input η en 91 % 7
P-471 Coal based ICC with CO 2 -capture as turbine mill and feeding system feedstock B HP-steam to CC clean gas saturator O2 saturated clean gas to CC clean dry gas CO2 coal excess N2 to environment pure AN A IP-steam from CC gasifier quench room raw gas scrubber CO-shift stage 1 CO-shift stage 2 condensate from CC make up H2S to Claus-plant Air Separation Unit slag discharge acid gas removal discharge make up discharge N2 to CC ambient air to MAC T-extraction air O2 to CC (preheating) make up cooling make up F E F E D C D B C saturated, diluted, preheated fuel gas Diluent N2 from ASU A 8
as turbine Model and boundary conditions after H 2 O-dilution H 2 72.4 N 2 3.3 CO 2.5 Ar.6 CH 4.2 CO 2.7 H 2 O 2.3 LHV 25 MJ/kg Composition after AR H 2 9.4 N 2 4.1 CO 3.1 Ar.8 CH 4.3 CO 2.9 H 2 O.4 LHV 49 MJ/kg Turbine Loss Characteristics Main parameters for model tuning: P el,ref = 286.6 MW η el,ref = 39.5 % π compressor,ref = 17.9 T hot gas,ref = 1425 C TIT ref = 124 C cool frac = 2.9 % TOT ref = 577.1 C T blade,ref = 9 C Δη turbine 1 Ma relative Cooling fraction for off-design calculations is determined by combustion chamber pressure loss and throttle coefficient for the cooling air ducts! 9
as turbine Effects of N 2 -dilution (no air extraction) N 2 -dilution hot gas mass flow cooling effort, but cooling fraction const. blade temperature De-rating hot gas temperature! ΔT blade = T blade,syngas T blade,ref -2-4 -6-8 -1-12 -14 7 1 13 16 19 22 25 1
as turbine Effects of N 2 -dilution (no air extraction) N 2 -dilution hot gas mass flow π compressor Surge margin! ΔT blade = T blade,syngas T blade,ref -2 Δπ compr = π compr,syngas / π compr,ref -4-6 -8-1 -12-14 7 1 13 16 19 22 25 11
as turbine Effects of N 2 -dilution (no air extraction) N 2 -dilution hot gas mass flow P el,t Limitations through shaft limit or generator capacity! ΔT blade = T blade,syngas T blade,ref -2 Δπ compr = π compr,syngas / π compr,ref -4 ΔP el = ΔP el,syngas / ΔP el,ref -6-8 -1-12 -14 7 1 13 16 19 22 25 12
as turbine Effects of N 2 -dilution (no air extraction) P el,syngas > 1.2 * P el,ref Operating window with possible operating points! ΔT blade = T blade,syngas T blade,ref T blade,syngas > T blade,ref -2 Optimization: m& compr Δπ compr = π compr,syngas / π compr,ref -4 ΔP el = ΔP el,syngas / ΔP el,ref -6-8 -1 Limitations for example gas turbine: 1. T blade,syngas,max T blade,ref 2. π compr,syngas,max 1.7 * π compr,ref -12 3. P el,syngas,max 1.2 * P el,ref -14 7 1 13 16 19 22 25 π compr,syngas > 1.7 * π compr,ref 13
as turbine Effects of N 2 -dilution and air extraction -2-4 -6-8 -1-12 -14 7 1 13 16 19 22 25 Air extraction hot gas mass flow T blade ; π compressor ; P el,t Operating window without air extraction -2-2 -4-6 -8-4 -1-12 -14 7 1 13 16 19 22 25-2 -4-6 -8-6 -8-1 -1-12 -14 7 1 13 16 19 22 25-12 -2-4 -6-8 -14 7 1 13 16 19 22 25-1 -12-14 7 1 13 16 19 22 25 14
as turbine Effects of N 2 -dilution and air extraction -2-4 -6-8 -1-12 -14 7 1 13 16 19 22 25 Air extraction hot gas mass flow T blade ; π compressor ; P el,t Operating window at 4 % air extraction -2-2 -4-6 -8-4 -1-12 -14 7 1 13 16 19 22 25-2 -4-6 -8-6 -8-1 -1-12 -14 7 1 13 16 19 22 25-12 -2-4 -6-8 -14 7 1 13 16 19 22 25-1 -12-14 7 1 13 16 19 22 25 15
as turbine Effects of N 2 -dilution and air extraction -2-4 -6-8 -1-12 -14 7 1 13 16 19 22 25 Air extraction hot gas mass flow T blade ; π compressor ; P el,t Operating window at 8 % air extraction -2-2 -4-6 -8-4 -1-12 -14 7 1 13 16 19 22 25-2 -4-6 -8-6 -8-1 -1-12 -14 7 1 13 16 19 22 25-12 -2-4 -6-8 -14 7 1 13 16 19 22 25-1 -12-14 7 1 13 16 19 22 25 16
as turbine Effects of N 2 -dilution and air extraction -2-4 Air extraction hot gas mass flow T blade ; π compressor ; P el,t -6-8 -1 Operating window at 12 % air extraction -12-14 7 1 13 16 19 22 25 Conclusions: -2-4 -6-8 -2-4 - Air extraction extends gas turbine operating window -1-12 -14 7 1 13 16 19 22 25-2 -4-6 -8-1 -6-8 -1 - Air extraction reduces the amount of hot gas temperature de-rating - Air extraction reduces the need for blading/stage modifications -12-14 7 1 13 16 19 22 25-12 - Air extraction requires turbine modification and increases complexity -2-4 -6-8 -14 7 1 13 16 19 22 25-1 -12-14 7 1 13 16 19 22 25 17
as turbine Effects of integration to -/steam cycle as turbine behavior for selected operating points air extraction rate [% of compressor mass flow] Relative exhaust gas mass flow (related to natural gas) depending on air extraction rate and syngas dilution (LHV) 12 1 8 6 4 2 P el,steam turbine air extraction rate [% of compressor mass flow] Turbine Outlet Temperature change (related to natural gas) depending on air extraction rate and syngas dilution (LHV) 12 1 8 6 4 2 η steam cycle ; P el,steam turbine 7 1 13 16 19 22 25 7 1 13 16 19 22 25 18
P-471 Coal based ICC with CO 2 -capture Water-/steam cycle mill and feeding system feedstock B HP-steam to CC clean gas saturator O2 saturated clean gas to CC clean dry gas CO2 coal excess N2 to environment pure AN A IP-steam from CC gasifier quench room raw gas scrubber CO-shift stage 1 CO-shift stage 2 condensate from CC make up H2S to Claus-plant Air Separation Unit slag discharge acid gas removal discharge make up discharge N2 to CC ambient air to MAC T-extraction air O2 to CC (preheating) make up cooling make up F E F E D C D B C saturated, diluted, preheated fuel gas Diluent N2 from ASU A 19
Water-/steam cycle Configuration and interfaces Three-pressure reheat -/steam cycle Interfaces for: - syngas-, diluent- and oxygen-preheating - extraction air cooling - gasifier steam supply - CO-shift steam superheating 2
ICC-Performance and concept evaluation OutputICC,net [MW] 41 4 39 38 37 36 35 ICC-Output depending on ASU-integration level reduced % air integration 22 % air integration 44 % air integration 68 % air integration compressor mass flow (IV) 7 8 9 1 11 12 13 14 41 4 ICC-Output depending on ASU-integration level % air integration Auxiliary load ICC [MW] 13 12 11 1 9 8 45.5 49.7 51.5 53.4 56.6 57.9 59.3 43.1 47.8 55.2 6.6 H2-content [Vol. -%] ICC-auxiliary load depending on ASU-integration level reduced % air integration 22 % air integration 44 % air integration 68 % air integration compressor mass flow (IV) Output ICC,net [MW] 39 38 37 22 % air integration 44 % air integration 68 % air integration 7 7 8 9 1 11 12 13 14 η ICC,net [% ] 39. 38.5 38. 37.5 37. 36.5 36. 45.5 49.7 51.5 53.4 56.6 57.9 59.3 43.1 47.8 55.2 6.6 H2-content [Vol. -%] ICC-Efficiency depending on ASU-integration level 7 8 9 1 11 12 13 14 45.5 49.7 51.5 53.4 56.6 57.9 59.3 43.1 47.8 55.2 6.6 H 2-content [Vol. -%] 68 % air integration 44 % air integration 22 % air integration % air integration reduced compressor mass flow (IV) 36 35 reduced 7 8 9 1 11 12 13 14 43.1 45.5 47.8 49.7 51.5 53.4 55.2 56.6 57.9 59.3 6.6 H 2 -content [Vol. -%] compressor mass flow (IV) Air- and N 2 -integration Output 21
ICC-Performance and concept evaluation OutputICC,net [MW] Auxiliary load ICC [MW] η ICC,net [% ] 41 4 39 38 37 36 35 13 12 11 1 9 8 7 39. 38.5 38. 37.5 37. 36.5 36. ICC-Output depending on ASU-integration level reduced 7 8 9 1 11 12 13 14 45.5 49.7 51.5 53.4 56.6 57.9 59.3 43.1 47.8 55.2 6.6 H2-content [Vol. -%] ICC-auxiliary load depending on ASU-integration level reduced compressor mass flow (IV) 7 8 9 1 11 12 13 14 45.5 49.7 51.5 53.4 56.6 57.9 59.3 43.1 47.8 55.2 6.6 H2-content [Vol. -%] % air integration 22 % air integration 44 % air integration 68 % air integration compressor mass flow (IV) % air integration 22 % air integration 44 % air integration 68 % air integration ICC-Efficiency depending on ASU-integration level 7 8 9 1 11 12 13 14 45.5 49.7 51.5 53.4 56.6 57.9 59.3 43.1 47.8 55.2 6.6 H 2-content [Vol. -%] 68 % air integration 44 % air integration 22 % air integration % air integration reduced compressor mass flow (IV) Auxiliary load ICC [MW] 13 12 11 1 9 8 7 ICC-auxiliary load depending on ASU-integration level High pressure ASU reduced compressor mass flow (IV) Low pressure ASU 7 8 9 1 11 12 13 14 43.1 45.5 47.8 49.7 51.5 53.4 55.2 56.6 57.9 59.3 6.6 H 2 -content [Vol. -%] % air integration 22 % air integration 44 % air integration 68 % air integration Air- and N 2 -integration Output Air-integration ; N 2 -integration Aux load 22
ICC-Performance and concept evaluation OutputICC,net [MW] ICC-Output depending on ASU-integration level 41 4 39 38 37 36 reduced 35 % air integration 22 % air integration 44 % air integration 68 % air integration compressor mass flow (IV) 7 8 9 1 11 12 13 14 39. 38.5 ICC-Efficiency depending on ASU-integration level Auxiliary load ICC [MW] 13 12 11 1 9 8 7 45.5 49.7 51.5 53.4 56.6 57.9 59.3 43.1 47.8 55.2 6.6 H2-content [Vol. -%] ICC-auxiliary load depending on ASU-integration level reduced % air integration 22 % air integration 44 % air integration 68 % air integration compressor mass flow (IV) 7 8 9 1 11 12 13 14 ηicc,net [%] 38. 37.5 37. 68 % air integration 44 % air integration 22 % air integration % air integration η ICC,net [% ] 39. 38.5 38. 37.5 37. 36.5 36. 45.5 49.7 51.5 53.4 56.6 57.9 59.3 43.1 47.8 55.2 6.6 H2-content [Vol. -%] ICC-Efficiency depending on ASU-integration level 7 8 9 1 11 12 13 14 45.5 49.7 51.5 53.4 56.6 57.9 59.3 43.1 47.8 55.2 6.6 H 2-content [Vol. -%] 68 % air integration 44 % air integration 22 % air integration % air integration reduced compressor mass flow (IV) 36.5 36. reduced 7 8 9 1 11 12 13 14 43.1 45.5 47.8 49.7 51.5 53.4 55.2 56.6 57.9 59.3 6.6 H 2 -content [Vol. -%] compressor mass flow (IV) Air- and N 2 -integration Output Air-integration ; N 2 -integration Aux load Marginal efficiency spread (for optimized concepts) 23
Conclusion and outlook Optimized and harmonized operating concepts yield to highest efficiencies for coal based CCS-ICC! Non or low integrated ICC concepts do not necessarily lead to poor plant-efficiencies! Further optimization and concept simplification should improve economics and push ICC to commercialization! Thank you for your attention! 24