From Lubbock, TX to 

Thompsons, TX

Amine Scrubbing 

for Commercial CO2 Capture

from Power Plants

GHGT-12

Gary T. Rochelle

Texas Carbon Management Program 

The University of Texas at Austin
Kubek, 2009

Gas

30 wt% MEA with oxidation inhibitor

(Chapel et al., 1999) 

Inflation adjusted Oil, $100-60/bbl

with 35 mile pipeline

30 wt % MEA with oxidation inhibitor

(Chapel et al., 1999) 

Inflation adjusted Oil, $100→60/bbl

Carbon Dioxide Technology Corp: Lubbock, TX

1000 mt/da CO2 from gas-fired boiler power plant

1983-84 for EOR
WA Parish CO2 Capture Project, 

Thompsons, TX

240 MW slipstream from coal-fired power plant

80-mile pipeline to EOR

Petra Nova: NRG Energy + JX Nippon Oil and Gas Exploration

(NRG factsheet, 2014; Petra Nova website)
Process Improvements since 1983

• Heat Duty reduced a factor of 2

• Solvent Selection

• Flowsheet Innovations

• Improved Equipment

• Solvent losses effectively managed

• Oxidation by solvent selection

• Amine aerosol by upgraded water wash

• Thermal degradation by stripper T

Fluor

Economine FGTM

Gas Turbine

Kansai Electric/MHI

KS-1TM

Cansolv

DC103TM

Coal

Applications (mostly gas) and suppliers
Fluor

Economine FGTM

Gas

Turbine

Kansai Electric/MHI

KS-1TM

Cansolv

DC103TM

Coal

Economine FG→KS-1

Effect of Solvent Development
KS-1 has greater intrinsic capacity 

than MEA

(Yagi et al., Kansai/MHI GHGT-8)

CO2 Loading 

(mol/mol amine)

At 9.8 kPa CO2

CO2 Capacity

(mol/mol amine)

40 oC 120 0C

1 M MEA 0.60 0.20 0.40

1 M KS-1 0.80 0.23 0.57
Advanced solvents give greater rate & capacity 

Solvent

Rate

kg'

avg @ 40 °C 

x107 CO2 Capacity

(m) mol/Pa s m2 mol/kg solv

7 MEA 4.3 0.5

5 PZ 11.3 0.63

KS-1

(est. from Yagi, GHGT-8 )

7.5 0.7

7 MDEA/2 PZ 6.9 0.8

4.8 AMP (hindered) 2.4 0.96
MHI ESP

Cansolv

DC103TM

+ LVC,IC

MHI Other

Effect of flowsheet enhancements

Estimated
MHI Energy Saving Process 

(ESP, Yagi et al., GHGT-8)

“For reduction of steam consumption, 

we employ ... lean solvent and steam condensate 

heat for regeneration inside the stripper”

“The improved KM-CDR process reduces

the regeneration energy...by 15%.”
Interheated Stripper using 8 m PZ

12

Rich Solvent

0.40 Ldg

Lean Solvent

0.28 Ldg 137 oC 

112 oC 

Cross exchanger

∆TLM=5 K

Inht. exchanger

∆TLM=5 K

Stripper

(2 m pkg)

Condenser

H2O

7.4 bar

Reboiler

150 oC

80% CO2

20% H2O 

117 oC 
Lean vapor compression using 8 m PZ

Flowsheet used by Fluor, Cansolv, et al.

13

11 bar

Stripper

(2 m pkg)

Reboiler

150 oC

Condenser

H2O

6.9 bar

Rich Solvent

0.40 Ldg

Lean Solvent

0.30 Ldg Recompressor

Opt. PR=1.6

144 oC

75% CO2

25% H2O 

Cross exchanger

∆TLM=5 K
Heat duty

8 m PZ, 150 oC regeneration

2

2.1

2.2

2.3

2.4

2.5

2.6

0.2 0.22 0.24 0.26 0.28 0.3 0.32 0.34

Heat duty (GJ/tonne CO

2

)

Lean loading (mol CO2/mol alkalinity)

AFS

Simple stripper

Interheated stripper

LVC

-15%
Electricity burden

8 m PZ, 150oC

,

150 bar CO2

190

200

210

220

230

240

0.2 0.22 0.24 0.26 0.28 0.3 0.32 0.34

WEQ (kWh/tonne CO

2

)

Lean loading (mol CO2/mol alkalinity)

AFS

Simple stripper

Interheated stripper

LVC

-10%
Steam supply variable

affects the electricity burden

• Lubbock 

• Supplemental boiler including flue gas

• Letdown turbines to extract steam work before reboilers

• Boundary Dam

• Refurbished turbine cycle giving steam at optimized P

• Thompsons

• Gas Turbine with heat recovery boiler to provide steam 
Minimum work to separate CO2 and compress to 150 bar 

Electricity Cost of Amine Scrubbing

Thompsons

Lubbock
Other notable improvements

• Absorber Intercooling

• MHI pilot reduced Qreb by 10% 

• (Iijima et al., MHI tech review, 2011)

• Cansolv, Fluor, et al.

• Random packing → Structured packing

• Absorber: Multiple round → Single Rectangular

• MHI at Plant Barry, 2011

• Metal absorber shell → Concrete absorber

• Cansolv at Boundary Dam, 2014
Solvent Losses are manageable

• Amine Degradation

• Thermal by acceptable regeneration T

• Oxidation by solvent selection

• Aerosol Losses

• Reduce Inlet SO3

• Design for Aerosol removal in the water wash 
0.1 1 10

monoethanolamine (MEA)

methyldiethanolamine

(MDEA)

piperazine (PZ)

aminomethylpropanolamine

(AMP)

Oxidation rate (mmol/kg-hr)

Amine Oxidation in a cycle from 55 to 120oC

H2N OH

HO

NH2
Amine Aerosol emissions

(MHI, Kamijo, GHGT-11) 

“One ... of MHI’s commercial plants experienced excess 

amine emissions due to higher... SO3 [in the flue gas]”

0

20

40

60

80

0 1 2 3 4

MEA (ppm) after water wash

SO3 before absorber (ppm)

SO3 causes aerosol emissions

in pilot plant testing
MHI Countermeasure

(MHI, Kamijo GHGT-11)

• “MHI ... developed a special multi stage wash... 

system to ... reduce SO3 related amine emissions ...”

before after

SO3 (ppm) 2.1-2.7 2.3-3.6

Amine emission (ppm) 12-35 0.7 - 3

Relative solvent use 1.0 0.25
Conclusions

• 2G amine scrubbing on coal will be realized at 

Thompsons and Boundary Dam

• 2G systems will use less energy than Lubbock

• 50% less reboiler duty, 30% less Weq

• Better solvent

• Better flowsheet

• 3G systems will not be much better

• 2G systems will manage solvent oxidation and 

aerosol emissions
Thompsons and Boundary Dam will 

demonstrate 

commercially available, 

energy-optimized 

amine scrubbing for CO2 capture 

from coal-fired power plants.