The document discusses amine treating processes for gas plants and refineries, outlining topics such as equipment, operations, chemistry, and the various types of amines used. It details the purpose of amine plants, including CO2 recovery and emissions minimization, as well as the chemical reactions involved in CO2 and H2S removal. Additionally, it covers the characteristics and efficiencies of different amine types, emphasizing the importance of reaction rates and conditions in optimizing gas treatment operations.

1. Amine Treating
1-Day Course for Starborn Chemical
17 July, 2017

2. Amine Treating
Course Topics
Process
Equipment
Operations
Control
Analysis
Foaming
Corrosion/HSS
Troubleshooting

3. Process Principles
Chemistry and Amine
Selection

4. Typical Sour Gas Plant – Flow Diagram

5. Feed Components
• Hydrocarbons
 C1 to C7+ , aromatics, NGL
• Acid Gas
 CO2 and H2S
• Sulphur bearing gases
 COS , RSH
• Water and others
 H2O, N2, O2, S
• Transients
 Compressor oil, upstream chemicals, fracture acids,
FeS, silica (sand)

6. Amine Plant Flowsheet

7. Purpose of the Amine Plant
• Recover CO2 from natural gas
• Minimize CO2 emissions
• CO2 to be incinerated
• Optional : sell to other industries or re-inject into ground

8. Amine Treating : Gas Plants
• Single absorber for each generator
• Wide range of both H2S and CO2 in gas feed
• Potential for oxygen in feed gas – solution gas
treaters
• Problems with amine degradations
• Typical specification sales specifications : 4
ppm H2S, 2 % CO2

9. Amine Treating : Refinery
• Both Gas and Liquid Streams
• Multiple absorbers with common regenerator
• Predominantly H2S removal
 Some CO2 removal
• Complication of inlet contaminants
• Organic acids, ammonia, etc.
• Problems with Heat Stable Salts

10. Typical Amine Treating Plant – Refinary

11. Amine Treating : Tail Gas
• Used to minimize Sulphur emissions on sour
plants
• Low pressure absorption
7- 28 kPag (1-4 psig)
• Low H2S specification
• Low CO2 removal (High Slip)
• Potential inlet Contaminants – SO2

12. Other Treating Schemes
• Acid gas enrichment
• CO2 slip important
• Low pressure operation
• CO2 only removal (ammonia plants)
• Degradation and corrosion are big issues
• Syngas treating
• H2 and CO ; no hydrocarbons in feed so amine
temperatures can be very low
• Carbon capture
• Extremely low pressure; high oxygen content in feed; CO2
only, loose spec

13. Types of Amines
Used for
Gas / Liquid Treating

14. Amine Samples - Refinery
Amine Samples – Gas Plant

15. Gas Treating Solvents
Primary amines
• MEA, DGA®
Secondary amines
• DEA, DIPA
Tertiary Amines
• MDEA, formulated MDEA
Sterically hindered amines (Flexsorb)
Physical Solvents
Mixed Amines (Sulfinol)

16. Molecular Structures of Amines
• Ammonia
• Too volatile
N
H
H
H

17. Primary Amines
• MEA
• Monoethanolamine M.wt = 61
• DGA
• Diglycolamine M.wt = 105
N
H
H
– CH2 – CH2 – OH
N
H
H
– CH2 – CH2 – O – CH2 – CH2 – OH

18. Primary Amines
MEA
• Strong base ; high heat of reaction
• More energy required to strip acid gas
• Degradation (corrosion, high usage)
• Will degrade in the presence of CO2
• Can be reclaimed on-site (in process)
• Degradation products have higher boiling points than MEA
• Nearly total removal of CO2 at any operating pressure
• High vapour pressure so significant vaporization losses
• Lowest HC solubility
• MEA typically used at 15 – 20 wt%.

19. Primary Amines
DGA®, ADEG®
• Strong base ; high heat of reaction
• However, high solution strength reduces circulation rate as well as
energy required to strip acid gases
• Comparable lean loadings to secondary amines
• High acid gas holding capacity per unit volume
• Degrades in the presence of CO2, COS
• Degradation products (urea and thiourea) can be converted back to
DGA in reclaimer
• Higher HC solubility than MEA
• Perform well at high temperatures
• typically used at 50 wt %.

20. Secondary Amines
• DEA
• Diethanolamine M.wt = 105
• DIPA
• Diisopropanolamine M.wt = 133
N
H
– CH2 – CH2 – OH
HO – CH2 – CH2 –
N
H
– CH2 – CH – OH
HO – CH – CH2 –
CH3 CH3

21. Secondary Amines
• Less basic so lower heat of reaction than
primary amines
• Degradation less prevalent
• Removes CO2 but requires deeper level of
regeneration to get similar performance
• DEA not reclaimable in-situ, not normally
required
• DEA typically used 25 – 30 wt %
• DIPA typically used from 40 – 50 wt%

22. Tertiary amines
• MDEA
• Methyldiethanolamine M.wt = 119
N
CH3
– CH2 – CH2 – OH
HO – CH2 – CH2 –

23. Tertiary amines
• Weakest base so lowest heat of reaction
• Lowest reboiler duty of the amines
• Virtually no CO2 degradation
• Capable of CO2 slip while removing all the H2S
• Poor COS, CS2, mercaptan, removal from inlet gas
• MDEA used at 35 – 50 wt% strength
• Higher HC solubility than MEA or DEA
• Weak base means the importance of all other
operating parameters become amplified

24. Reboiler Steam
Requirements (SI)
(Reaction Heat Only – highest conc.)
Amine Type kJ/kg H2S kJ/kg CO2
15 % MDEA 1500 1902
60 % DGA 1570 1972
30 % DEA 1140 1510
40 % DIPA 1230 1750
50 % MDEA 1045 1340

25. Formulated Tertiary Amines
All major vendors have some form of formulated
MDEA solvent
• Generally, formulations contain stronger “base”
additives to enhance CO2 absorption – can custom
design a slip
• Some formulations contain stripping enhancers to
achieve low lean loadings
• Some additives improve CO2 slip

26. Activated MDEA (aMDEA)
• Developed by BASF, features a “activator”
molecule (piperazine) mixed with MDEA solution
• Capable of very high removal of CO2
• Low corrosion rates, low reboiler duty, high rich
loadings capability
• Competitive formulations now available

27. Why So Many MDEA –
Based Solvents Today ?
• Stability
MDEA
𝐶𝑂2
𝐻𝑒𝑎𝑡
▷ only slight degradation
• Reactivity with CO2
MDEA < DEA < MEA
• Enhancement
MDEA + additive  enhanced CO2 slip
MDEA + additive  improved CO2 removal
• Lower CO2 related corrosion rates

28. Types of Amine - Summary
• Primary
• Effective low pressure removal
• Strong acid gas removal
• Secondary
• Good all-purpose sweetening
• Tertiary
• CO2 slip
• Formulated
• Customized CO2 removal

29. Types of Amine –
Summary Con’t
• Hindered
• Extremely high CO2 slip
• TGTU / AGE
• Physical
• Bulk H2S and Sulphur Species Removal
• Mixed
• Mercaptan and Trace Sulphur Removal

30. Molarity
Is a measure of the “potency” of the solvent
– the number of moles of amine per liter of
solution

31. Molarity vs Solution Strength
Amine mole weight vary from 133 - 61
DIPA
133
MDEA
119
DEA
105
DGA®
105
MEA
61
0
0.5
1
1.5
2
2.5
3
3.5
4
4.5
5
DIPA MDEA DEA DGA ® MEA
2.3 2.5
2.9 2.9
4.9
So a 30 wt % amine solution yields a ?? Molarity (300 g/L/M.wt)

32. Molarity
For example, at typical operating strengths, the
amines have the following molarities :
Amine Strength Molarity
MEA 15 wt% 2.48
DEA 30 wt% 2.90
DGA® 50 wt% 5.10
MDEA 50 wt % 4.40
DIPA 40 wt % 3.30

33. Amine Plant Flowsheet

34. Gas Mixtures – Partial Pressure
Dalton’s Law
P = ∑ppi
• P = system total pressure
• ppi = partial pressure component i
ppi = xi . P
• Where xi = mole fraction component i
Partial Pressure is the driving force to get a gas
into a solution

35. Partial Pressure
It is the partial pressure of the 21 % oxygen in
the air that forces the oxygen into our blood
when we breathe
ppO2 = 100 kPa X 0.21 = 21 kPa ( 3 psia)
• At higher elevation (low pressure) we become oxygen starved (climbing Mt.
Everest)
• When we take in pure oxygen to our lungs, the higher concentration means a
higher partial pressure and easier absorption into the blood

36. Gas Mixtures – Partial Pressure
• Total system pressure P = 10000 kPa
• Partial pressure of :
• Methane = 10000 kPa x 0.75 = 7500 kPa
• CO2 = 10000 kPa x 0.20 = 2000 kPa
• H2S = 10000 kPa x 0.03 = 300 kPa
• H2O = 10000 kPa x 0.02 = 200 kPa
Note : ∑𝑝𝑝i = 10000 kPa = P

37. Partial Pressure – CO2
• For example, the partial pressure of a gas
containing 1 % CO2 at various pressures would
be :
• At 7000 kPa (1000 psi) pp co2 = 70 kPa ( 10 psi)
• At 700 kPa (100 psi) pp co2 = 7 kPa ( 1 psi)
• At 60 bar a, 2 % of CO2 has a partial pressure
of 1.2 bar (this would be equivalent to the top
packaging partial pressure)

38. CO2 removal profile –
Simulation Output

39. Mass Transfer

40. Reaction Rates
• The chemical reaction between the acid gases
and the amine is affected by both mass
transfer and reaction kinetics
• Viscosity of the fluid (mass transfer)
• Residence time in the fluid (mass transfer)
• Contamination of the fluid/layers (mass transfer)
• Temperature of the fluid (kinetics)

41. Basic Chemistry
Amine Treating

42. Absorption Fundamentals
• Absorption is the transfer of gas phase
component (CO2) to a liquid phase (amine)
• The tendency of a component to move from
the gas to the liquid phase is determined by
the partial pressure of that component
• Absorption favored by low temperature

43. Absorption Chemistry
• Acid gases react with weak liquid bases to
form thermally regenerable salts
acid + base  salt + heat
• Caustic (NaOH or KOH)  too strong
• Ammonia (NH3)  too volatile
• Alkanolamines  good balance
+ amine  salt + heat
H2S
CO2

44. Regeneration Chemistry
• Adding energy (heat) to the salts reverses the
reaction to form the original bases and acids
acid + base ⟸ salt + heat
CO2 + amine ⟸ rich amine + heat

45. Reaction Mechanism
• CO2 reactions (primary and secondary amines)
– carbamate formation
2 [R1R2NH] + CO2 ⟺ [R1R2NH]H+ + [R1R2N-COO]–
(fast)
“carbamate reaction”

46. Reactions Mechanism
• CO2 (primary and secondary)
Acid- base reaction (slow)
CO2 + H2O ⟺ H2CO3 (carbonic acid)
H2CO3 ⟺ H+ + HCO3
- (bicarbonate)
H+ + R1R2NH ⟺ R1R2NH2
+
CO2 + H2O + R1R2NH ⟺ R1R2NH2
+ + HCO3
-

47. Reactions Mechanism
CO2 reactions
• Tertiary Amines
CO2 + H2O ⟺ H2CO3
(slow)
[R1R2NR3] + H2CO3 ⟺ [R1R2NR3]H+ + HCO3
-
(fast)

48. Activated MDEA (aMDEA)
• MDEA solution formulated with piperazine
• Capable of very high removal of CO2
Amine Reaction rate constant (L mol-1s-1)
MEA
DGA
DEA
DIPA
Piperazine
MMEA
MDEA
6000
4500
1300
100
59000
7100
4
Table 1. Reaction Rate constants with CO2 of common gas treating amines

49. CO2 Absorption in Amine Solvent
Physical Reaction
• Driving forced by mass transfer between CO2
concentration in gas phase toward liquid (amine) phase
Chemical Reaction
• Acid-base reaction in liquid phase. CO2 in water is weak
acid while MDEA is weak base
Reaction between weak acid and weak base is thermally reversible.
B−OH
−
+ A−H (B−OH2
+
) + E
20 Amine + CO2
Prontonated Amine + Amine Carbamate
Tertiary Amine do not have a labial H available to react. CO2 must hydrolyze to
react with Tertiary Amine

50. CO2 Absorption in Amine Solvent
CO2 hydrolysis is rate limiting
 CO2 must hydrolyze to carbamate before it can react as a base
 CO2 hydrolysis is slow, therefore rate limits CO2 removal
 Tertiary Amine (MDEA, TEA) do not have labial H needed to form an amine
carbamate, therefore only react with carbonic acid
CO2 + H2O
𝑺𝑳𝑶𝑾
HOCO2
−
+ H
+
MDEA + CO2 + H2O
𝑨𝒄𝒄𝒆𝒍𝒆𝒓𝒂𝒕𝒐𝒓
HOCO2
−
+ Amine Carbamate
Using chemistry to advantage:
 The slow hydrolysis reaction can be used to advantage, preferential H2S
removal is possible with tertiary amines
 Reaction accelerators/activator have been developed to increase rate of CO2
reaction
 Suitable activator should have ability to enhance the reaction rate with low
heat of reaction

51. CO2 Absorption in Promoted Amine Solvent
Because of the low reaction rate of the CO2 removal by alkanolamines or alkaline salts,
promotors or activators are needed to improve the absorption process. The following
compounds can be used to increase the reaction rate:
 Formaldehyde
 Methanol
 Phenol
 Ethanolamine
 Glycine
 Hindered amine
The art of activated MDEA formulation is to find the suitable chemistry which
gives higher CO2 absorption rate, lower heat of reaction, and higher selectivity
to benefit the total treating cost.