co2 capture by amine scrubbing by gary t. rochelle

CO2 Capture by Amine ScrubbingBy

Gary T. Rochelle

Luminant Carbon Management Program

Department of Chemical Engineering

The University of Texas at Austin

Workshop on CO2 Capture

UNAM, Mexico City,

March 28, 2012

Central Messages

• Amine Scrubbing is THE technology for CO2

capture from Coal Power plants

• Energy consumption by amines is approaching 20 % of the plant output, a practical lower limit.

• Solvent degradation & contamination will probably limit the chemical cost to less than $5/lb.

40% of US CO2 emissions are From Electricity Generation

CO2 Capture & Storage

Boiler ESP

Flyash

Abs/Str

Disposal

Turbines

150 atm CO2

3-6 atm stm

12% CO2

10 ppm SO2

Packed

Absorber

Stripper

Packing

or Trays

30 wt% MEA CO2

Reboiler

45 psig stm

Amine Scrubbing (Bottoms, 1930)

Aqueous Abs/Str: Near commercial

– 100’s of plants for treating H2 & natural gas

• MEA and other amine solvents

• No oxygen

– 10’s of plants with combustion of natural gas

• Variable oxygen, little SO2

• Fluor, 30% MEA, 80 MW gas, 15% O2

• MHI, KS-1, 30 MW, <2% O2

– A few plants with coal combustion

• Abb-Lummus, 20% MEA, 6, 8, & 33 MW

• Fluor, 30% MEA, 3 small pilots, 5 MW

• CASTOR, 30% MEA, 1 MW pilot

• MHI, KS-1, <1 MW pilot, 25 MW

Tail End Technology Ideal for Development, Demonstration, & Deployment• Low risk

– Independent, separable, add-on systems

– Allows reliable operation of the existing plant

• Failures impact only Capture and Sequestration

• Low cost & less calendar time

– Develop and demonstrate with add-on systems

– Not integrated power systems as with IGCC

• Reduced capital cost and time

– Resolve problems in small pilots with real gas

– Demo Full-scale absorbers with 100 MW gas

• Ultimately 500 MW absorbers

Other Solutions for Coal• Oxy-Combustion

– O2 plant & compression require more energy

– Gas recycle, boiler modification for high CO2

– Gas cleanup, compression including air leaks

• Coal Gasification / Combined Cycle

– O2 plant, complex gasifier, cleanup, CO2 removal

– Not ready for deployment

– Relatively more expensive on PRB or lignite

– New plants only

• Neither is Tail end: More suitable for new plants

– Require higher development cost, time, and risk

– Not suitable for on/off to address peaking

Issues of absorption/stripping

Practical Problem is Cost

$40-70/ton CO2 removed = $40-70/MWh

• Energy = 20-30% of power plant output

– $20/ton CO2

– Theoretical Minimum is 11%

• Capital Cost $500-1000/kw – Absorber for 500 MW:20x20x20 m

– $20-40/ton CO2 for capital charges & maint

• Amine degradation/environmental impact

– $1-5/ton CO2

History RepeatsCaCO3 Slurry:::Amine Scrubbing

CaCO3 Event Amine

1936 1st commercial plant 1980

1958 Too commercial for Gov. support

“Nearly Insurmountable” issues

1960-75 Government funds advanced alts 1990-

1970-85 Govern. & EPRI fund test facilities 2010-

1968 60-250 MW prototypes 2015

1977 500+ MW deployed per regulations

First choice dominates

Messages on Energy• Reversibility is King

• Greater Capacity reduces Sensible Q

• Saturation Stripping is more reversible

• Faster Solvents Enhance Reversibility

• Greater Heat of Absorption Reduces Energy

• Greater Stripping T is more reversible

• Enhanced Stripping is more reversible

• Energy is approaching 50% of theoretical, a practical limit

T H E U N I V E R S I T Y O F T E X A S A T A U S T I N

Outline

2G/3G Amine scrubbing is available, e.g. PZ at high T

Reduced Energy use requires high DHCO2 & large T swing

Inefficiency of mechanical compression eliminates membranes, P swing adsorption, and oxycombustion.

Competitive cross-exchanger efficiency will be difficult to achieve with solids and viscous liquids.

Adequate CO2 absorption & stripping mass transfer rate is achievable with aqueous amines.

Water is significant but manageable.

Aqueous amine energy performance will not be beat by advanced capture technologies.

Advanced Capture Technologies

Claim to Reduce Energy Use Separation Driven by Mechanical Compression

Membranes

Pressure Swing Adsorption

Oxycombustion

Separation Driven by Thermal Swing Heat

Amine Scrubbing with high T stripping

Thermal Swing Adsorption

Nonaqueous Solvent Scrubbing

The “MEA” 1G Standard

Amine scrubbing with absorption/stripping

Post-combustion technology

80 years experience in acid gas treating

Amine capture processes (Econamine & KS-1)

30 wt % (7 m) MEA benchmark (1st generation)

Fast, high DHabs, good capacity, low m, low cost

Not thermally or oxidatively stable

Background

Concentrated Piperazine (8 m, 40 wt %)

Representative 2G/3G amine technology

Fastest rate of CO2 absorption

Resistant to oxidation & thermal degradation

High-T 2-stage flash process for piperazine

Twice the capacity of 7 m MEA

Acceptable DHabs = 65-70 kJ/mol

Published performance

Higher chemical cost, greater viscosity, constrained by solid precipitation

Background

PZ High Temperature 2-Stage Flash

Process Flowsheet

Absorber

40 °C

Flash Tank

17 bar

150 °C

Flash Tank

11 bar

150 °C

Cross-Exchanger

T Approach = 5 °C

Scrubbed Flue Gas

Flue Gas

Intercooling

High Temperature 2-Stage Flash

Concentrated Piperazine

Solvent

Energy Analysis

Ldg = 0.31

Ldg = 0.41

Overall Energy Analysis

of Thermal Swing Regeneration

for Amine Scrubbing & Adsorption

1. Energy analysis must consider

Regeneration P & T/P value of steam

2. Good Energy Performance requires

Greater DHCO2 abs/ads

Maximum regeneration T/P

Minimum abs/ads T (intercooled)

Total Equivalent Work Single-Stage Flash

Calculate total equivalent work for generic single-stage flash

ΔHCO2 for 60, 70, 80 kJ/mol

T = 90 to 150 °C

Correlate to

1HH H2OCO2

pumpcompequivtotal WWWW

T5TQ75.0W

sinkflashflashequiv

Energy Analysis

Thermal Compression increases Stripper P at greater DHabs &Tstrip (lower comp work)

Thermal Compression reduces heat for water vapor at greater DHabs &Tstrip (less stripping steam)

stripabs

stripCO

P 11ln

STRIPABS

STRIPCO

P 11)(22

Maximizing T Swing & DHCO2 Swing Reduces Weq

5 10 15 20 25 30 35

(DHCO2-DHH20)D(1/T) (kJ/gmol-K)

DHCO2=60 kJ/mole

Wtotal= Wequiv+Wcomp+Wpump

Piperazine

150 °C

MEA 120 °C

90 °C

Single-stage flash at 90-150 °C

Compression to 150 bar

Lean PCO2 = 0.5 kPa at 40 °C

Energy Analysis

2000 2004 2008

Minimum Work = 109 kWh/tonne

Estimated Total Equivalent Work 12% CO2, 90% Removal, 150 bar, 40 °C

Energy Analysis

CO2 Separation = 46 kWh/tonne

Compression = 63 kWh/tonne

pumpcomp

sinkstmequiv WW

TTQ75.0W

Thermodynamic Efficiency of Common Separation Processes

Process Efficiency (%)Wminimum / Wactual

CO2 Capture by Amine Scrubbing 50

Cryogenic Air Separation 25

Common Distillation 15-35

Water Desalination by Reverse Osmosis 21

Therefore it is improbable that we will be better than 200 kwh/ton CO2,with any technology.

Many advanced solvents and sorbents do

not have competitive DHCO2

High DHCO2 is difficult to manage in

intercooled solid adsorber

Irreversibilities of Two-Stage Flash

ABSORBER

40 °C

150 °C 150 °C

WIDEAL = 104 kWh/tonne, WREAL = 219 kWh/tonne

25 kWh/

14 kWh/

tonne9 kWh/tonne

34 kWh/tonne

22 kWh/tonne

Energy Analysis

Multi-stage compressor Reversibilityto 150 Bar, 40 oC Intercooling, P/P<2.0, 72% eff

2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5

ln (150/Pin)

0.8 atm20 atm

MCOMP Work from Aspen Plus®

Correlation

Compression work, P/P<2

2 3 4 5

Inlet Pressure (bar)20 7.5 2.75 1

η=0.80, ε=0.2

η=0.72, ε=0η=0.72, ε=0, 2 piece eqn

Capture processes driven by mechanical compression are not energy competitive

Work(kwh/tonne)

Efficiency(%)

Minimum Work(Isothermal, ideal compression)

111 100

PZ with 2-stage regeneration at 150 °C 219 50

Ideal process driven by real compression72% eff, 40 oC cooling, Pj/Pj-1 =2

(Ideal Membranes or Pressure Swing Adsorption)

206+ 55

Oxycombustion with Ideal air separationReal compressors for Air & CO2

1.35 mol O2/mol CO2

217+ 52

Real Oxycombustion (Darde et al., 2008) 284 40

CROSS-EXCHANGER

IRREVERSIBILITY

Thermal Swing Regeneration requires

Good Cross Exchange

Close approach T (5C)

High Capacity

Low viscosity

11th IEA GHG Capture Network Meeting –May 20-21st, 2008 8

0.2 0.25 0.3 0.35 0.4 0.45 0.5

Loading (mol CO2/Equiv PZ)

CO2 solubility in PZ at 40oC4.0 m (Ermatchkov 2006), 3.6 to 8.0 m (This Work)

0.88 mol CO2/kg"8 m PZ"

0.48 for MEA

1.23 for 2-PE

Cross-Exchanger Exergy Loss – 25 kWh/tonneSteam Make-up for Unrecovered Sensible Heat Loss

capacity/TCQ D p

)mole/kg 88.0/(K5*)KJ/mole 5.3(

C 155at Steam CO kJ/mole 20 2

sinkstmloss

TTQ75.0W

3600*44

273155

40155*20*75.0

2CO kWh/tonne 25

Energy Analysis

Significance of viscosity

0 5 10 15

N alkalinity (m)

Viscosity

Capacity

Optimum PZ Concentration

0 5 10 15 20 25

N alkalinity (m)

5 m MDEA/5 m PZ

Capacity normalized for viscosity

Implications for Thermal Swing

advanced liquids & solid adsorbents Viscosity should be low

Hard to achieve <10-20 cP with advanced liquids

Cross-exchange should provide close approach T

Hard to achieve 5-10 oC with solid adsorbents

CO2 Working Capacity should must be high

>0.7 mol CO2/kg sorbent

Primary target of materials development

Working capacity is Dloading not rich loading

Mass transfer coefficients

Bulk gas

liquid

Gas film Liquid film

35 4/19/2011

CO2 flux = k (∆ CO2)

PCO2, bPCO2, i

[CO2]i

[CO2]b

(=PCO2*)

∙ (PCO2,b – PCO2*)CO2 flux =

CO2 flux

= kg (PCO2,b- PCO2,i) = kl ([CO2]i – [CO2]b)

= kg’ (PCO2,i – PCO2*)

Gas-Liquid

Interface

Henry’s Law:

PCO2i= He * [CO2]i

Gas Film Reaction Film Diffusion Film

PRODl, ][CO

[Am]kD

Bulk Gas Bulk Liquid

PCO2,b PCO2,i

G-L Interface

[CO2]i

[CO2]b

(PCO2*)

fast chemical rxn

36 4/19/2011

Pseudo 1st order kinetics

CO2 removal = area ∙ KG (∆PCO2) ≈ f(area, kg’)Packing Solvent

10 100 1000 10000

PCO2* @ 40 °C (Pa)

8 m PZ

7 m MEA

Absorber ReversibilityCO2 Mass Transfer at 40 °C (Wetted Wall Column)

Energy Analysis

5 %0.5 %

Absorber Exergy Loss – 14 kWh/tonneEstimated Packing Area from kg‟

Ln mean kg’DP = 2.4e-3 gmol/s-m2

Lean: kg’(Pout-Plean*)= 2.2e-6 *(0.012 – 0.005)*105

Rich: kg’(Pin-Prich*) = 5e-7*(0.12-0.05)*105

Absorber packing volume

1.9e3 m3 for 800 MW, 250 m2/m3

0.9 tonne CO2 removed/MW-hr

25 x 25 x 13.5 m

1.5 m/s gas velocity

Exergy lost/mole CO2

RTln(Pg/P*bulk liq) =RTln(0.12/0.05)= 14 kwh/tonne CO2

Energy Analysis

Thermal Degradation PZ and its Structural Analogs

100 120 140 160 180

Temp to match MEA deg.(°C)

High Temperature Amines

Morpholine (Mor), 169°C

2-Amino-2-methyl-1-propanol (AMP), 139°C

Pyrrolidine (Pyr), 140°C

1-Methylpiperazine (1-MPZ), 148°C

2-Methylpiperazine (2-MPZ), 152°C

Piperazine (PZ), 164°C

Piperidine (PD), 164°C

MDEA in MDEA/PZ Blend, 139°C

HomoPZ, 137°C

Hexamethylenediamine (HMDA), 157°C

8 m PZ Provides High P at 150 °C

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45 0.5

CO2 Loading (moles/equiv PZ)

160 ºC

0.005 ΔHabs

Energy Analysis

Do anhydrous solvents reduce Energy?

Condenser Work loss results from water

PH2O generates valuable stripper P: Anhydrous

solvents/adsorbents generate less P at a given T.

Optimized regeneration, e.g. interheated stripping

eliminates energy loss from water.

Anhydrous solvents/adsorbents pick up water which

must be removed anyway.

Ideal Anhydrous Solvents Reduce Energy

5 10 15 20 25 30 35

(DHCO2-DHH20)D(1/T) (kJ/gmol-K)

60 kJ/mole

Wtotal= Wequiv+Wcomp+Wpump

Piperazine

150 °C

MEA 120 °C

90 °C

Single-stage flash at 90-150 °C

Compression to 150 bar

Lean PCO2 = 0.5 kPa at 40 °C

Energy Analysis

Anhydrous

Water for reflux

CO2 Multistage, Intercooled Compressor

Stripper

Liquid drawoff

<10% H2O

0.20 0.25 0.30 0.35

Lean Loading (mol CO2/mol alk)

8 m PZ

0.40 rich loading

150 °C in reboiler(s)

loading

1-Stage Flash

2-Stage Flash

Simple Stripper

Adiabatic Lean Flash

Interheated Column

0 0.2 0.4 0.6 0.8 1 1.2

∙m2)

CO2 Capacity (mol CO2/kg solvent)

4/19/201145

PZ Derivatives

Primary

EDAHindered

Amines

MDEA/PZ

PZ based

solvents

Two-dimension comparison of solvents

Fast Solvents

Amine (m)Capacity

-∆Habs

@PCO2 =1.5kPa

kg,’avg x1e-7

@40 °C

Deg T (oC)

k1= 3e-6 s

mol/kg solv kJ/mol mol/s·Pa·m2 3e-9 s-1

PZ 8 0.79 70 8.5 163

1-MPZ 8 0.83 67 8.4 148

MDEA/PZ 5/5 0.99 70 8.3 138

2-MPZ/PZ 4/4 0.84 70 7.1 155

MDEA/PZ 7/2 0.80 68 6.9 138

2-MPZ 8 0.93 72 5.9 151

HEP 7.7 0.68 69 5.3 130

MEA 7 0.47 82 4.3 120

Slow Solvents

Amine (m)Capacity

-∆Habs

@PCO2 =1.5kPa

kg,’avg x1e-7

@40 °C

k1=3e-9 s-1

mol/kg solv kJ/mol mol/s·Pa·m2 oC

PZ 8 0.79 70 8.5 163

MEA 7 0.47 82 4.3 120

DGA® 10 0.38 81 3.6 132

AEP 6 0.66 72 3.5 121

2-PE 8 1.23 73 3.5 120

MAPA 8 0.42 84 3.1 114

AMP 4.8 0.96 73 2.4 137

Conclusions

Aqueous Amine & Advanced liquid solvents

– Use solvents with DHCO2>65 kJ/mol

– Run strippers at max T with thermally stable amines

– Intercool absorbers to ambient sink

– Use configurations to recover heat from water vapor

• Anhydrous solvents lose P benefits of water

– Maximize solvent capacity/viscosity

Conclusions

• Mechanical compression is not energy competitive– Membranes

– Pressure Swing Adsorption

– Oxycombustion

• Thermal Swing Adsorption is no magic bullet– Needs DHCO2 > 65 kJ/mol with thermally stable materials

– Must Intercool adsorber

– Must cross exchange solids to 5 oC approach

– Needs Dloading >0.7 mol/kg

– Must maintain efficient mass & heat transfer rates

Solvent Management

Messages on Solvent Management• Thermal Degradation

– Limits max Stripper T

– TMEA < TMDEA <TAMP< TPZ

• Free Radical Autooxidation– If fast, in absorber:: if slow, in heat exchanger

– Alkanolamine > tertiary > Hindered > cyclic(PZ)

– Catalyze by Fe+2, Cu+2, Mn+2

– Inhibit by peroxide/radical scavengers, tertiary amine

• Volatility of amines and degradation products– Absorber water wash may work

– Reduced by hydrophilic groups & speciation

– Nitrosamines from NO2/NO2- + secondary amine

– Reclaiming required for coal impurities

Where is degradation most likely to occur?

Flue Gas

10% CO2

5-10% O2

Purified Gas

1% CO2

30% MEA

a = 0.4-0.5

1 mM Fe+3

30% MEA

a = 0.3-0.4

Reboiler

Absorber

40 -70 oC

Stripper

120 oC

Exchanger

Oxidative

Degradation

Thermal Degradation

5 Mechanisms for Thermal Degradation

• 1. Carbamate Polymerization - MEA

• 2. Cyclic Urea - Ethylenediamine

• 3. Arm Switching/Elimination - Tertiary Amine

• 4. SN2 Ring Opening – Piperazine

• 5. Blend Synergism – Piperazine/MEA

Carbamate Polymerization

• ↔

MEA Carbamate Oxazolidone

MEA HEEDA

NHOH CO2-

OHNH2 + OH

NHNH2 +

Primary & Secondary Alkanolamines Deg TAmine k1 = 2.91 × 10-8 s-1 Structure T (oC)

2-methyl-aminoethanol 103

Monoethanolamine 120

3-amino-propanol 126

2-piperidine ethanol 127

Diglycolamine® 133

2-methyl-2-amino-propanol 137

Cyclic urea

NH2 + O O

1o & 2o Diamines = cyclic ureas Deg TAmine Structure T (oC)

Dimethylethylenediamine 100

Diethylenetriamine 105

Methylaminopropanolamine 114

Hydroxyethylethylenediamine 114

Ethylenediamine 121

Hexamethylenediamine 156

2 Tertiary ↔ Quaternary + Secondary

+ OHNH

Tertiary1 + Secondary2 ↔ Tertiary2+ Secondary1

Tertiary1 + Quaternary2 ↔ Tertiary2+ Quaternary1

Elimination

OH ++CH3

3o amines→2o amines + other 3o aminesAmine Structure T (oC)

Dimethylmonoethanolamine 122

Tetramethylethylenediamine 125

Methyldiethanolamine 128

N-(2-Hydroxyethyl)PZ 132

N,N’-Dimethylpiperazine 139

1-methyl-piperazine 148

CH3 N N CH3

Ring Opening

NH NH2

NH NH +

OOH NH O + OH2

Ring Closing

Cyclic ↔ LinearAmine Structure T (oC)

Diglycolamine® 133

Homopiperazine 133

Pyrrolidine 135

2-Methyl-Piperazine 152

Hexamethylenediamine 156

Piperazine 162

Morpholine 169

Interactive Blends• Carbamate Polymerization

NHNHNH

O O+ N

+ OHNH2

NHNH NH+

Secondary2 + Tertiary1 ↔ Tertiary2+ Secondary1

Total Amine Loss in BlendsAmine (m) Structure T (oC)

MEA/PZ 104

MEA/AMP 123

4 AMP/6 PZ 135

7 MDEA/2 PZ 138

4 PZ/4 2MPZ 155

3.9 PZ/3.9 1MPZ/0.2 14DMPZ

Oxidation

O2 solubility & Mass Transfer

2.E-04 2.E-03 2.E-02

Oxygen Rate Constant (s-1)

Absorber

ExchangerSump

PZMEAMDEA

0 100 200 300 400

Experiment Time (hrs)

8 m PZ

7 m MEA

7 m MEA +

100 mM Inhibitor A

Avoid Oxidation with PZ or Inh A

Oxidation Conditions:

55°C, 1400 rpm

98% O2 / 2% CO2

0.4 mM Fe2+

0.1 mM Cr3+

0.05 mM Ni2+

Inhibitors in MEA at 70 C, 98kPa air, 2kPa CO2

0 1 2 3 4 5

Inhibitor (wt%)

Citric acid

IA + HP

Autoxidation of MEA

InitiationMEAOOH + Fe+2

MEAO• + Fe+3

MEAOOH + Fe+3MEAOO• + Fe+2

Propagation

MEAO• + MEA MEAOH + MEA•

MEAOO• + MEA MEAOOH + MEA•

MEA• + O2MEA-OO•

Termination R• + R• mol. Prod.

Inhibition R• + Inh RH + Inh•

MEAOOH + InhMEAOH + InhO

7 m MEA with transition metalsConditions: 70 C, 98kPa air, 2kPa CO2

0 5 10 15 20 25 30 35 40

Time (hrs)

1 mM Fe2+

1 mM Cu2+ 1 mM Mn2+

Mild effect: V, Cr

No significant effect:Ti, Mo, Co, Ni, Sn, Se, Ce, Zn

9 m pilot plant MEA with HEDP70 C, 98kPa O2, 2kPa CO2, 0.5mM Fe

0 10 20 30 40 50

Time (hrs)

HEDP +0.06 to 1.5 wt%

NH3 rate stable for >48hrs →

+ 0.4 wt% DTPA

OHO OH

Environmental Impact of Degradation Products

Volatile ProductsRequire water wash

Nonvolatile productsRequire Reclaiming

Some Oxidation Products of MEA

Product Structure

Ammonia (V) NH3

Formaldehyde (V, NV) H2CO

Formate (NV) HCOO-

N-(2-hydroxyethyl)-formamide (V)

N-hydroxyethyl-imidazole (V)

N-(2-hydroxyethyl)-2-[(2-hydroxyethyl) amino] acetamide (NV)

Eide-Haugmo

7 m MDEA/2 m PZ Oxidized at 120oC

Products (CO2 carrying)C-Loss

Diethanolamine/Methylaminoethanol 40

1-methyl PZ 8.4

1,4-Dimethyl PZ 0.9

Aminoethyl PZ 3.5

N-formyl PZ (amide) 8.3

Formate & other acids 2.5

Bicine 5.3

Hydroxyethyl sarcosine 10.5

PZ thermal products, 165oCProduct Structure N loss

N-Formyl PZ (V) 32

NH3 (V) 14

Aminoethylpiperazine(NV)

2-Imidazolidone (V) 6

Hydroxyethylpiperazine(NV)

Degradation of 5 M MEA120oC, 0.4 mol CO2/mol MEA

Volatility Issues

• Amine volatility– In H2O

– In loaded solution

– As a methylated degradation product, e.g. 1.4 dimethylpiperazine, methylamine

• Oxidation products– HEI

– Formamide

– Ammonia

– Nitrosamine from sec amine and NO2/NO2-

Amine Volatility (Pa) at 40 oC

Amine Ldg = 0 Ldg: PCO2=500 Pa

@ 40oC

5m MDEA/5m PZ 0.17/3.43 0.16/0.51

7m MDEA/2m PZ 0.56/0.91 0.42/0.21

8m PZ (8.8) 0.78

12m EDA 87 1

7m MEA 10 2.7

5m AMP 14.2 11.2

Nitrosamine Characteristics• Organic compounds containing -N-N=O

• Secondary amine reacts with nitrosating agent

– Nitrous acid in acidic conditions In Vivo

– Nitrite in basic conditions for amine scrubbing

MNPZ and Decomposition at High Temperatures

0 2 4 6 8

Time (Day)

150C 50 mM NO2

150C 15 mM NO2

Aerosols

Message on Thermal Degradation

• Stripper energy is constrained by the max T permitted by Degradation

– Linear alkanolamines and diamines degrade by polymerization & urea formation at 100-130oC

– Tertiary amines degrade by arm switching &elimination at 120-140oC

– Piperazine and related cyclic amines degrade by ring opening at 150-165oC.

Message on Oxidation

• As amines become more resistant, oxidation shifts from the absorber to the heat exchanger

– MEA & alkanolamines readily oxidize in the absorber unless inhibited by radical or peroxide scavengers

– Tertiary amines inhibit self oxidation, probably by scavenging peroxides

– Piperazine oxidizes only at the higher T of the heat exchanger exit

Message on Environmental Impact

• Amine degradation must be minimized to manage secondary environmental impact.

– Volatile Products can leave with flue gas• Aldehydes, formate, ammonia, volatile amines,

amides

– Nonvolatile products make up reclaimerwaste• Polyamines, Cyclic urea, amino acids

Conclusions

• Amine Scrubbing can be Deployed by 2019

• Improved Amine Solvents and Processes– Reduce Energy from 400% to 200% of Minimum W

– Provide Stable, Benign Solvents

– Simplify systems to reduce capital Cost

• As Limestone Slurry Rules FGD after 30 yrs; Amine Scrubbing will dominate CO2 capture.

• Other technologies are unlikely to compete for Post-combustion capture.

co2 capture by amine scrubbing by gary t. rochelle

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