Modeling and evaluation of integration of SNG plants with Carbon Capture and Storage Technologies Claudia Bassano, Paolo Deiana, Nicola Verdone, Lorenza Pacetti 19-22 May 2014, Dresden, Germany
ENEA Italian National Agency for New Technologies, Energy And Sustainable Economic Development Casaccia Research Center – Rome University of Rome “La Sapienza”, Department of Chemical Engineering, Materials and Envronment
Agenda
• Introduction
• SNG plant process description
System modeling Mass and energy balance Efficiency
• SNG plant performance evaluation
• Conclusions
IFC 2014 19-22 May 2014, Dresden
ENEA is the Italian National Agency for New Technologies, Energy and Sustainable Economic Development (Law n. 99 of July 23rd, 2009)
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IFC 2014 19-22 May 2014, Dresden
To evaluate the performance of a coal to SNG plant and its implementation with Carbon Capture and Storage Technologies
To chose a configuration plant by integration
of various process block
Analysis and modeling of coal-based SNG plants
To compare two different SNG plant configuration
IFC 2014 19-22 May 2014, Dresden
To improve the thermal efficiency
Study: CCS Technologies Integrated into SNG Plants
Sulcis
Basin
1 ) CO2 storage
Sulcis Basin
Site to test CCS throught
ECBM
acquifers tecniques
Mine mouth plant
Sulcis Coal Mine
South-West Sardinia Italy
Plant size: plant location
Coal mine availability 1 Mtons/y
Technical analysis of SNG plant
2) Absence of regional natural gas supply
IFC 2014 19-22 May 2014, Dresden
Mass and Energy Balance
Equilibrium Gibbs Reactors, yeld reactor
Process Integration
System modeling
The simulations were carried out using a commercial software AspenPlus
Two different plant configurations have been developed:
1. Case A Case A + CCS
2. Case B Case B + CCS
Highly Exothermic Reaction
CO + 3H2 CH4 + H2O
DH°298 = - 206 kJ/mol
Increase of the temperature in the reactor
Optimal use of reaction heat
CO feed → Potential formation of carbonyls
IFC 2014 19-22 May 2014, Dresden
SNG
H2S vs Claus
COAL
METHANATION GASIFIER SOUR SHIFT
Steam
CO2 vent
CH4
AGR
ASU
Air
N2
O2
Heat control by product recycle
Removal of H2S & CO2
Molar ratio
CO/H2=3 adjusted
Gasification
System modeling: CASE A
IFC 2014 19-22 May 2014, Dresden
COAL
METHANATION GASIFIER SWEET SHIFT
Steam
CH4
AGR
ASU Air
N2
O2
AGR
CO2 vent
H2S vs Claus
SNG Removal
of CO2
Heat control gas dilution
with CO2
Molar ratio
CO/H2=3 adjusted
Removal of
H2S Gasification
System modeling: CASE B
IFC 2014 19-22 May 2014, Dresden
CO2 vs storage
H2S vs Claus
COAL
METHANATION GASIFIER SOUR SHIFT
Steam
CH4
AGR
ASU
Air
N2
O2
CO2 COMPRESSION
COAL
METHANATION GASIFIER SHIFT
H2S vs Claus
Steam
CH4
AGR
ASU Air
N2
O2
AGR
CO2 COMPRESSION
CO2 vs storage
System modeling: CASE CCS
IFC 2014 19-22 May 2014, Dresden
CCS CASE A
CCS CASE B
System modeling: assumptions
Gasifier Fixed Bed Dry Bottom O2:coal= 0.67 kg/kg (daf); Steam: coal 2.5 kg/kg (daf); Pressure = 30 bar ASU section: 175 kWhe/tO2 O2 purity of 94.3%
WGS section Two catalytic reactors operating in series HT-WGS THT=300°C LT-WGS TLT=200°C Adiabatic Gibbs reactor Chemical equilibrium
AGR section CASE A Rectisol L/G=3 kg/kg p design 30 bar Gas clean H2S= 1 ppm CO2 =1 % H2S rich gas H2S % vol.>20 %
AGR section CASE B
2 Rectisol section p design 30 bar Gas clean H2S= 1 ppm
CO2 compression 3 compressor stages with inter-coolers CO2 liquid purity CO2 = 95 % H2S<200 ppm CO2 liquid pressure p=150 bar
IFC 2014 19-22 May 2014, Dresden
200
250
300
350
400
450
500
550
600
40 50 60 70 80 90 100
Tem
pera
ture
(°C)
% vol. CH4 dried
Case A: methanation section
R-A401 R-A402 R-A403
SNG
CONDENSATE
RECYCLE COMPRESSOR
SYNGAS FEED
from AGR
CO/H2= 3.1
R-A401
R-A402
R-A403
in
R-401 out
R-401 out
R-402 out
R-403
% vol. % vol. % vol. % vol.
H2 24.5 12.4 2.4 0.6 CO 5.1 0.4 0.0 0.0
CO2 3.0 3.6 1.4 0.9
CH4 41.1 50.3 55.9 56.9
H2O 24.1 31.3 38.2 39.5
N2 2.2 2.2 2.3 2.3 % vol. CH4 dried 54 73 90 94
STEAM 200 t/h p=30 bar T=270 °C
IFC 2014 19-22 May 2014, Dresden
150
200
250
300
350
400
450
500
550
600
0 10 20 30 40 50
Tem
pe
ratu
re (
°C)
% vol. CH4 dried
Case B: methanation section
R-B401 R-B402 R-B403
CO2 rich SNG
CONDENSATE
SYNGAS FEED
from WGS
CO/H2= 3.1
STEAM 150 t/h p=30 bar T=270 °C
R-B401
R-B402
R-B403
in
R-B401 out
R-B401 out
R-B402 out
R-B403
% vol. % vol. % vol. % vol.
H2 46.8 5.5 0.01 0.0 CO 15.4 3.0 0.00 0.0
CO2 29.7 40.3 43.0 43.0
CH4 7.0 29.2 32.6 32.8
H2O 0.0 20.7 22.7 22.9
N2 0.9 1.3 1.3 1.3 % vol. CH4 dried 6.97 36.87 42.39 42.50
IFC 2014 19-22 May 2014, Dresden
COAL
Steam
O2
ash
pyrolysis gas
Q dryng
Q pyrolysis
Syngas
Dryng zone
Pyrolysis zone
Gasification Combustion
zone
Temp
height
DRYNG
DEVOLATILIZATION
GASIFICATION
COMBUSTION
PREHEATING OF
AIR AND STEAM
COAL SYNGAS
ASH AIR AND
STEAM
AND
Temp
height
DRYNG
DEVOLATILIZATION
GASIFICATION
COMBUSTION
PREHEATING OF
AIR AND STEAM
COAL SYNGAS
ASH AIR AND
STEAM
AND
System modeling: updraft gasifier
IFC 2014 19-22 May 2014, Dresden
Gasification pressure bar 30
Coal mass flow kg/s 52
O2/coal mass (daf basis) a 0.67
Steam/coal mass (daf basis) m 2.5
Nm3 Syngas/kgcoal (daf basis) 2.4
Syngas LHV MJ/kg 10.7
Cold Gas Efficiency CGE 0.7
Raw gas composition % mol (dry basis)
H2 42.8
CO 19.2
CO2 29.4
CH4 6.8
H2S+COS 0.82
CnHm 0.51
N2 1.6
System modeling: updraft gasifier results
Syngas from Aspen model
IFC 2014 19-22 May 2014, Dresden
Assumptions and results
Rectisol process
Case A: Acid Gas Removal section
H2S & CO2 Absorber T=-40°C
Clean gas H2S =1ppm CO2 =1 % vol.
CO2 vs. vent/storage H2S 20 % vol. vs. Claus
Raw gas from Sour WGS
L/G Kg/kg 3.2
W refrigeration MWe 40
p bar 30 IFC 2014 19-22 May 2014, Dresden
Case CCS A & CASE CCS B CO2 compression section
CO2 compression/liquefaction
Three compressor stages
14 bar, 40 bar, 80 bar
inter-coolers T=25 °C
CO2 liquid: 95 % in CO2, H2S<200 ppm, H2O< 300 ppm
(CO2 stream quality requirements transport)
H2O
CO2
IMPURITIES
CO2 LIQUID K-603 K-604 K-605 P-604
IFC 2014 19-22 May 2014, Dresden
SNG
81465 Nm3/h
807 MWth
Coal
4500 ton/d
Coal to SNG plant
Ash 691 ton/d
CO2 vent 5106 ton/d
BASE CASE A
SNG
81400 Nm3/h
805 MWth
Coal to SNG plant
Ash 691 ton/d
CO2 vent 5195 ton/d
BASE CASE B
System modeling: main results base case
Coal
4500 ton/d
IFC 2014 19-22 May 2014, Dresden
SNG
81465 Nm3/h
807 MWth
Coal
4500 ton/d
Coal to SNG plant
Ash 691 ton/d
CO2 vent 360 ton/d
CASE A
SNG
81400 Nm3/h
805 MWth
Coal to SNG plant
Ash 691 ton/d
CO2 vent 470 ton/d
CASE B
Coal
4500 ton/d
CO2 storage 4747 ton/d
CO2 storage 4734 ton/d
System modeling: main results CCS CASE
CO2 removal efficiency = 93 %
CO2 removal efficiency = 91 %
IFC 2014 19-22 May 2014, Dresden
CASE A CASE A + CCS CASE B CASE B + CCS Coal t/h 187.5 187.5 187.5 187.5 SNG Nm3/h 81466 81466 81407 81407 Thermal input MWth 1320 1320 1320 1320 Auxiliary loads MWe 76.4 86.8 57.3 67.8 Efficiency h 0.52 0.51 0.53 0.52 CO2 capture % 0 93 0 91 Nm3CH4 /kg Coal 0.43 0.43 0.43 0.43
Main performance of SNG plant
Auxiliary loads
IFC 2014 19-22 May 2014, Dresden
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
CASE A CASE A + CCS
CASE B CASE B + CCS
MWe
CO2 compression
Methanathion
AGR
ASU
Gasifier
Conclusions
The analysis evaluates different scenarios in order to underline potential benefits of SNG production from low rank coal.
1) Comparative performance of two SNG plant configurations
Case A One AGR section Methanation section
Higher production of superheated HP steam Energy consumption of the compressor Increase volumetric flow in the first reactor
Case B
Two AGR section Methanation section
Low temperature process (Tmax = 550°C) No recycle compressor
IFC 2014 19-22 May 2014, Dresden
Conclusions
2) Energy efficiency Comparative performance analysis shows similar efficiencies for the two cases 3) CCS implementation The capture of CO2 is strictly integrated into SNG plant. In order to meet the pipeline requirements for natural gas is in fact necessary to remove part of the CO2 produced in the process. This analysis indicates a powerful synergism among SNG plant and CO2 capture systems. The introduction of CCS in SNG plant shows a modest decrease of efficiency
IFC 2014 19-22 May 2014, Dresden
