# From Lubbock, TX to Thompsons, TX Amine Scrubbing

for Commercial CO 2 

# Capture

from Power Plants

GHGT

- 12 Gary T. Rochelle
Texas Carbon Management Program The University of Texas at AustinKubek , 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 CO 2 from gas

- fired boiler power plant

1983

- 84 for EOR

## WA Parish CO 2 

## 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 TFluor

Economine FGTM Gas Turbine

Kansai Electric/MHI

KS

- 1TM

Cansolv

DC103TM Coal 

### Applications (mostly gas) and suppliersFluor

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)

CO 2 

### Loading ( mol / mol amine)

At 9.8 kPa CO 2 

### CO 2 

### Capacity ( mol / mol amine)

40 o 

### C 120 0 

### C

1 M MEA 0.60 0.20 0.40

1 M KS

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

Solvent Rate

k g ' avg @ 40 ° C

x10 7 CO 2 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 0.96MHI ESP Cansolv

DC103 TM

+ 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 o**  **C 112**  **o C** 

**Cross exchanger**

∆ **T LM**  **=5 K**

**Inht . exchanger** 

∆ **T LM**  **=5 K Stripper**  **(2 m**  **pkg )**  **Condenser**

**H 2**  **O 7.4 bar** 

**Reboiler**

**150 o**  **C 80% CO**  **2 20% H**  **2 O** 

**117 o**  **C**

## Lean vapor compression using 8 m PZ

Flowsheet used by Fluor, Cansolv , et al.

13 **11 bar**

**Stripper (2**  **m pkg**  **)**

**Reboiler**

**150 o**  **C Condenser** 

**H 2**  **O**

**6.9 bar Rich Solvent** 

**0.40 Ldg** 

**Lean Solvent**

**0.30 Ldg**  **Recompressor Opt. PR=1.6** 

**144 o**  **C 75% CO**  **2 25**  **% H**  **2 O** 

**Cross exchanger**

∆ **T LM**  **=5 K**

## Heat duty

8 m PZ, 150 o 

### C 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 CO 2**  **/mol alkalinity) AFS**  **Simple stripper**

**Interheated stripper**  **LVC** - 15%

## Electricity burden

8 m PZ, 150 o C

, 150 bar CO 2

**190 200**  **210 220**  **230 240** 

**0.2 0.22**  **0.24 0.26**  **0.28 0.3**  **0.32 0.34** **W EQ** **(kWh/ tonne** **CO 2** **)**

**Lean loading ( mol**  **CO 2**  **/ 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 steamMinimum work to separate CO 2 and compress to 150 bar 

### Electricity Cost of Amine Scrubbing

Thompsons Lubbock

## Other notable improvements

• Absorber Intercooling

• MHI pilot reduced Q reb 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 SO 3



### • Design for Aerosol removal in the water wash0.1 1 10 monoethanolamine (MEA) methyldiethanolamine (MDEA) piperazine (PZ) aminomethylpropanolamine (AMP)



### Oxidation rate (mmol/kg

- hr) Amine Oxidation in a cycle from 55 to 120 o 

### C

N H 2 O H O H N H 2

## Amine Aerosol emissions
(MHI, Kamijo

, GHGT

- 11)

“One ... of MHI’s commercial plants experienced excess
amine emissions due to higher... SO 3 [in the flue gas]”

0 20 40 60 80

0 1 2 3 4MEA (ppm) after water wash

SO 3 before absorber (ppm) SO 3 causes aerosol emissions in pilot plant testing

# MHI Countermeasure

(MHI, Kamijo GHGT

- 11 )



### • “MHI ... developed a special multi stage wash... system to ... reduce SO 3 

### related amine emissions ...”



## before after

SO 3 

## (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 l ess energy than Lubbock

• 50% less reboiler duty, 30% less W eq

• 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 CO 2 

## capture

from coal

- fired power plants.