Simultaneous Removal of SO2 and CO2 From Flue
Gases at Large Coal-Fired Stationary Sources
Y. F. Khalil(1) and AJ Gerbino(2)
(1) Chemical Engineering Department, Yale University, New Haven, CT 06520
(2) AQSim, Inc., Glen Ridge, NJ 07028
OLI’s 24th User Conference
Hyatt Hotel, Morristown, NJ
October 23 – 24, 2007
Presentation Outline
 Motivation for developing alternative technologies for CO2 capture:
- U.S. GCCI
- Integrated control technologies (ICTs)
- Technical and economic barriers of CO2 capture using MEA
 Research objectives
 Research apporach for modeling CO2 and SO2 capture using:
- OLIs’ ESP
- ICEM (DOE model)
 Results and discussion: IECM and ESP
 Summary
 Roadmap for future work
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Motivation #1: The U.S. Global Climate Change Initiative (GCCI)
 GCCI is one of the primary drivers for CO2 emission reduction.
 Between 2002 and 2012, this initiative targets 18% reduction in the greenhouse gases
(GHGs) intensity.
 A second goal of this initiative is to provide a portfolio of commercially-ready CO2 removal
technologies for 2012 assessment.
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Motivation #2: Integrated Control Technologies (ICTs)
 More cost effective compared to single-effect
technologies
 Less footprint and, hence, easier to retrofit
 Possibility of sharing some unit operations
 Possibility of shared raw materials
 Example: simultaneous removal of CO2 and SO2
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Motivation #3: Monoethanolamine (MEA) Scrubber for CO2 Capture
 MEA scrubbing is the conventional technology for CO2 capture from flue gases
 Unfortunately this technology is energy-intensive -- a significant amount of energy is
required for recovering the MEA solvent:  67% of the MEA plant operating cost is attributed
to steam requirements for solvent regeneration and  15% of the cost is for MEA makeup.
 MEA is corrosive and requires adding corrosion inhibitors
 For a 500 MWth coal-fired plant,
MEA makeup ~ 22.7 tons/hr
 MEA recirculated ~ 6,599 tons/hr
Some CO2 remains in the
regenerated MEA
MEA makeup
 Additional drawback of MEA
technology:
 Low CO2 loading, i.e., grams of
CO2 absorbed per gram of
absorbent.
MEA
HEX
5
Total Energy Usage for Recovery &
Compression: MEA System
3.4 million BTU/ton CO2
5.2%
5.2%
4.5%
Absorption
Feed Compr
1st stage - 1- 10 atm
2nd stage - 10 - 100 atm
85.1%
Total Energy: 3.41 MBtu/ton CO2
 Slightly compress the feed gas to 1.2 bar
 0.15 MBtu/ton CO2
 Desorb CO2 in the stripper
 2.9 MBtu/ton CO2
Source: J. L. Anthoney, Dept. of
Chem. Eng, Kansas State U.
 Compress the CO2 off-gas to 100 bar
 2 stages at 0.18 MBtu/ton CO2 each
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Cost of Raw Materials
Costs are based on 2005 dollars (as provided by the IECM program)
Conventional MEA scrubbing for CO2
removal
Proposed process for CO2 removal by
scrubbing with using Ca(OH)2 slurry
MEA cost, $/ton: 1,293
Limestone cost, $/ton: 19.64
Corrosion inhibitor cost, $/ton: 258.6
(20% of MEA cost)
Lime, $/ton: 72.01
Activated carbon (AC) for MEA cleaning,
$/ton: 1,322
Note:
In the proposed process, CaO will be
produced in-situ.
Caustic (NaOH), $/ton: 624.7
(needed for MEA reclaiming)
Make-up could be in the form of CaCO3 or
CaO to compensate for Ca loss as CaSO3
or CaSO4
 5.1 kg MEA (pure solvent) per 1 kg CO2 removed
 From reaction stoicheometry:
~ 1.16 kg Ca(OH)2 per 1 kg SO2 removed
~ 1.68 kg Ca(OH)2 per 1 kg CO2 removed
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Research Objectives
 Model the simultaneous removal of SO2 and CO2 gases by
chemi-sorption in a slurry of hydrated lime [Ca(OH)2].
 Benchmark the performance/effectiveness of this proposed
technology with:
- MEA scrubbing approach for CO2 removal
- Wet flue gas desulfurization (FGD) for SO2 removal
- These separate-effect technologies (MEA and FGD) are typically
connected in series in a fossil-fired power plant
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Research Approach
Three-Fold Approach:
1. Use OLI’s Environmental Simulation Program (ESP, v-7.0-55) to
model the simultaneous removal of SO2 and CO2 gases by scrubbing
into a slurry of hydrated lime [Ca(OH)2].
• Three hypothetical flue gas compositions are to be evaluated : CO2
concentrations of 3%, 14%, and 25%; representative of exhaust
streams of a NG-fired power plant, coal-fired power plant, and a
cement production plant, respectively.
- Only the coal-fired plant (11 – 15% CO2) is discussed in this
presentation
• Concentration of SO2 in the flue gas is assumed to be 2000 ppm
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Research Approach
Three-Fold Approach (cont’d):
1. Use the OLI’s Environmental Simulation Program (ESP, v-7.0-55)
to model the simultaneous removal of SO2 and CO2 gases by
scrubbing into a slurry of hydrated lime [Ca(OH)2].
• Flue gas flow rate was kept constant at ~ 1.6x106 acfm (~ 2.7x106
m3/hr); such flow rate is typical of a 500 MWth coal fired power
plant.
• The proposed process includes a SO2 scrubber, a CO2 scrubber, a
calciner, a lime slaking reactor, and a few auxiliary unit operations
such as heat exchangers, filters and dryers.
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Research Approach
Three-Fold Approach (cont’d):
2. Use the Integrated Environmental Control Model (IECM)
software to predict the performance of a coal-fired plant that
uses MEA scrubbing for CO2 capture and wet FGD unit for SO2
removal
• IECM software has been developed by the Center for
Energy and Environmental Studies, Carnegie Mellon
University for DOE in 2007 (Current Version: 5.21;
February 2, 2007)
3. Compare ESP predictions with IECM predictions for CO2 and
SO2 removal
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Importance of the Proposed Integrated Technology
The proposed integrated technology for simultaneous
removal of CO2 and SO2 could be of interest to many
industrial facilities including:
 Fossil-fuel-based power generation stations; which
contribute about 30% of the World’s CO2 emissions
 Coal-fired gasification combined cycle (IGCC) turbines
 Cement production plants
 Petrochemical plants
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Chemical Reactions for CO2 Removal
CO2 Gas Absorption Reaction (carbonation reaction):
Ho298 K  -113 kJ/mole
CO2 (g) + Ca(OH)2  CaCO3 + H2O
Calcination Reaction:
Ho298 K  178 kJ/mole
CaCO3  CaO + CO2 (g)
Lime Slaking Reaction:
Ho298 K  -65 kJ/mole
CaO + H2O  Ca(OH)2
H2O
Lime Slaker
Ca(OH)2
CO2 in flue gas
Carbonator
CaO
CaCO3
Calciner
CO2
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Carbonator: Exothermic Reaction
GR at 298oK = -72.643 kJ/mole
HR, kJ/mole
G, kJ/mole
CO2 (g) + Ca(OH)2  CaCO3 + H2O
HR at 298oK = -113.03 kJ/mole
GR ad HR are calculated by HSC software
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Calciner: Endothermic Reaction
CaCO3 (s)  CaO (s) + CO2 (g)
GR at 1198oK = -5.528 kJ/mole
GR at 1273oK = -16.169 kJ/mole
G, kJ/mole
Typical Calciner Temperature Range
1220oK – 1420oK
HR, kJ/mole
HR at 1198oK = 164.949 kJ/mole
HR at 1273oK = 163.207 kJ/mole
GR ad HR are calculated by HSC software
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Lime Slaker: Exothermic Reaction
CaO (s) + H2O  Ca(OH)2
G, kJ/mole
GR at 298oK = -57.804 kJ/mole
HR, kJ/mole
HR at 298oK = -65.145 kJ/mole
GR ad HR are calculated by HSC software
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Chemical Reactions for SO2 Removal
SO2 Gas Absorption Reaction:
Ho298 K  -163 kJ/mole
SO2 (g) + Ca(OH)2  CaSO3 (s) + H2O
Forced Oxidation of CaSO3 to CaSO4:
Ho298 K  -556 kJ/mole
CaSO3 (s) + 1/2O2 (g)  CaSO4 (s)
CaSO3 or CaSO4
SO2 in flue gas
Lime Slaker
Ca(OH)2
Makeup CaO to
compensate for Ca lost
in CaSO3 or CaSO4
H2O
Lime Slaker
Ca(OH)2
CaO
CO2 in flue gas
Carbonator
CaCO3
Calciner
CO2
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G, kJ/mole
HR, kJ/mole
SO2 Absorption: Exothermic Reaction
GR at 298oK = -114.736 kJ/mole
GR ad HR are calculated by HSC software
HR at 298oK = -162.509 kJ/mole
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G, kJ/mole
HR, kJ/mole
Forced Oxidation of CaSO3: Exothermic Reaction
GR at 298oK = -498.504 kJ/mole
GR ad HR are calculated by HSC software
HR at 298oK = -556.469
kJ/mole
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Chemical Reactions for Co-Production of SynGas
Co-Production of Lime and Syngas:
CaCO3 + CH4 (g)  CaO + 2CO (g) + 2H2 (g)
Ho 298 K  426 kJ/mole
 Typical Calciner Temperature Range
1220oK – 1420oK
 Hence, co-production of Syngas can
take place within the calciner
temperature range
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HR, kJ/mole
G, kJ/mole
SynGas Production: Endothermic Reaction
GR ad HR are calculated by HSC software
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Mitigation of Operating Risks of the Calciner
 Lime Sintering (decrease in surface area and pore size of CaO)
Reducing the operating temperature of the calciner results in less
sintering of the produced calcium oxide and, hence, more reactive
lime (CaO) in the lime slaker.
 Cost of CaO Makeup Due to Loss of Reactivity
Because calcium is used continuously in a cyclical manner, sintering
and corresponding reduction in reactivity is a cumulative process
that may require periodic makeup of calcium oxide. If calcium can be
recycled say 500 times, then it may easily be considered to be cost
effective.
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Process Flow Diagram (PFD) as Simulated in ESP
Slaked Lime
Lime
Split 2
H2O/CaOH2 Feed
Lime
Split 1
V-1
Vent Gas
SO2 Scrubber Vent
C
C
Flue Gas
Quench
CO2
Scrubber
SO2
Scrubber
Quench Water
Slaker
CaCO3 Filtrate
Quenched
flue Gas
Blowdown
CaO
CaSO3
Filtrate
CO2 Scrubber Bottoms
SO2 Scrubber Bottom
Quench Liquid Out
CaCO3
Filter
CO2
CaCO3 Cake
CaSO3
Filter
Dryer
Dry Cake
Calciner
CaSO3 Blowdown
CaSO3 Blowdown
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Simulation of CO2 Removal Using DOE/IECM
User defined
HR = -84.6
kJ/mole CO2
HR (30 wt% MEA in water) = -84.6 kJ/mole CO2
MEA solution
& Mass of MEA (30 wt%) to absorb 1 kg CO2 = 17 kg
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Simulation of SO2 Removal Using DOE/IECM
User defined
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Simulation Results of MEA-Based Technology for
CO2 Removal Using the Integrated Environmental
Control Module (IECM)
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CO2
Coal-Fired
Boiler
Absorber
• Remove heat of chemisorption
• Cool lean regenerated MEA solvent by removing sensible heat
Stripper
• Heat the rich MEA solvent by extracting sensible heat from the lean MEA solvent
• Supply heat of desorption using steam in the reboiler
Possible Power Plant Capture Add-ons
• Cool flue gas to absorber conditions (25oC)
• Compress flue gas to overcome pressure drop in Absorber
• Post compression of CO2 to desired product pressure
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CO2 removal = (2.667E6 tons/yr) / 6575 hrs/yr ~ 406 tons/hr for a 500 MWth coal-fired plant
31
CO2 (mole%) in input flue gas = 2.048E4 lb-mole/hr / 1.706E5 lb-mole/hr ~ 12%
CO2 removal efficiency = 90% (user defined) and CO2 escape with flue gas = 10%
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MEA scrubber plant cost about $281M / $700M ~ 37% of the 500 MWth plant cost
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Simulation Results of Wet-FGD Technology for
SO2 Removal Using the Integrated Environmental
Control Module (IECM)
36
37
38
39
40
41
Air
Preheater
42
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ESP Simulation Results
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ESP Simulation Results
Flue Gas Stream
Flue Gas Composition, kg/hr (1)
700000
600000
500000
400000
H2O
300000
CO2
200000
100000
0
Flue Gas
Quench
Flue Gas
SO2
Sump
Gas
SO2
Scrub
Vent
CO2
Sump
Gas
CO2
Scrub
Vent
CO2 To
Process
46
ESP Simulation Results
Flue Gas Stream
Flue Gas Composition, kg/hr (2)
7000
6000
5000
4000
3000
SO2
2000
1000
0
Flue Gas
Quench
Flue Gas
SO2 Sump SO2 Scrub CO2 Sump CO2 Scrub
Gas
Vent
Gas
Vent
CO2 To
Process
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ESP Simulation Results
Flue Gas Stream
Flue Gas Composition, kg/hr (3)
100
90
80
70
60
H2S
50
SO3
40
HCL
30
20
10
0
Flue Gas
Quench
Flue Gas
SO2 Sump SO2 Scrub CO2 Sump CO2 Scrub
Gas
Vent
Gas
Vent
CO2 To
Process
48
ESP Simulation Results
Utility Water
Utility Water Composition, lmol/hr (1)
25000
20000
15000
C(+4)
10000
5000
0
Quench Liq
Out
SO2 Scrub
Bot
SO2 Sump
Bot
CaSO3
Filtrate
CO2 Scrub
Bot
CO2 Sump
Liq
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ESP Simulation Results
Flue Gas Stream
Utility Water Composition, lmol/hr (2)
250
200
150
S(+4)
100
50
0
Quench Liq
Out
SO2 Scrub
Bot
SO2 Sump
Bot
CaSO3
Filtrate
CO2 Scrub
Bot
CO2 Sump
Liq
50
ESP Simulation Results
Flue Gas Stream
Utility Water Composition, lmol/hr (3)
10
9
8
7
6
5
S(-2)
4
S(+6)
3
2
1
0
Quench Liq SO2 Scrub
Out
Bot
SO2 Sump
Bot
CaSO3
Filtrate
CO2 Scrub
Bot
CO2 Sump
Liq
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Summary
 OLI’s ESP was a useful simulation tool for
modeling CO2 and SO2 capture using Ca(OH)2
slurry
 Other insights and opportunities for improving the
ESP simulation capabilities
52
Roadmap for Future Work
 Simulate CO2 capture using the monoethanolamine
technology
 Compare performance/CO2 capture efficiency and raw
materials requirements versus CO2 capture using
Ca(OH)2 slurry
 Calculate the energy requirements for the Ca(OH)2
technology and compare to MEA energy requirements
 Demonstrate improved Ca utilization in the proposed
technology (i.e., Ca consumed to remove S and C)
 Estimate calcium make-up requirements (tons/hr) for
the simultaneous removal of CO2 and SO2
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