1. Corrosion Control on Amine Plants: New Compact Unit Design for High Loadings Michel BONIS, Total Jean KITTEL, IFP Gauthier PERDU, Prosernat
Good afternoon
Corrosion has always been a matter of concern for the operation of gas sweetening plant with amine solvent. But the corrosion experience can open the way to optimized designs, to reduced operating costs and to debottlenecking perspectives when attached to higher loadings of solvent.
I first thank my co-authors : Michel Bonis from Total for his feed back of amine plants and Jean Kittel from IFP for his skilled analysis of recent issues; special thanks to Jean for his contribution to the preparation of the paper.
I will develop the Total experience in this field. This Company has decades of back ground in management of gas plants, in optimized maintenance, as well as in construction of grass root projects. It brought strong innovations and benefits into plants mainly built in CS.
As CRA also gives way to improved design, new analysis made at IFP secure the use of CRA as a solution to high intensity operation of gas sweetening units, especially in the perspective of high chloride content in the solvent.
Hand over of presentation:
The factor and the location of corrosion in an amine gas plant
The risks
The reiterated use of CS as basic construction material, the drawbacks, how it can bring us to high loadings. With the help of CRA at the good place.
CRA : is there any drawbacks, the NACE.
Conclusion.
OAPEC IFP joint Seminar – 17th 19th June 2008

2. Outlook Introduction Overview of corrosion likelihood in amine units
Key factors of corrosion in amine plants
An illustrative case Study
From operating old CS units to handling high amine loadings
More than 50 years REX
The present operating basis
High loadings - Lessons learnt from experience
The use of stainless steels in amine sour units – the question raised by NACE MR0175 / ISO
Main conclusions – a path to compacted designs
Lets start with the presentation
After a exposure of the places where we can face corrosion in gas sweetening units with amine, we will see what are the factors and catalysts.
Secondly I will present you the TOTAL experience on corrosion, the feedback and the benefits
Thirdly I will question the use of CRA with the requirement of NACE in sour environment
We will finish with the overview a the solution proposed by the technology.

3. Outlook Introduction Overview of corrosion likelihood in amine units
Key factors of corrosion in amine plants
An illustrative case Study
From operating old CS units to handling high amine loadings
More than 50 years REX
The present operating basis
High Loadings - Lessons learnt from experience
The use of stainless steels in amine sour units – the question raised by NACE MR0175 / ISO
Main conclusions – a path to compacted designs
Quick passing by

4. Five Decades of Operations Experience
Total has operated and licensed amine units for more than 50 years:
The 1st units :
DEA units, sour gas, 16% H2S & 10% CO2, started in 1957
Now :
141 units licensed on 42 different locations over the world,
75 DEA units,
66 Selective or energized MDEA units,
25 units operated by Total
Many of them have been debottlenecked for higher intensity operation
Most are used for H2S removal, from 30 ppm to 50% H2S in, i.e. up to very high amine loads!
CO2 removal units mostly licensed during the last 10 years,
Extensive use of CS with monitoring and aggregated feed back
Prosernat - an IFP subsidiary is now the licensor
That is the story of the Lacq plant in South part of France in production since mid 50’s.
As far as our experience is concerned, various solvent, various processes including elaborated schemes with integrated reflux of double split flows.
Canada
Russia
More recent businesses linked to the LNG plants. Mid 1990
The story written by new hands

5. A Typical Scheme of an Amine Unit
Wet sweet gas
Sour
Gas
Absorber
Tank
Acid gas
Demin
water
Exchanger
Regenerator
Flash drum
Flash gas
LP steam
Reboiler
Absorber
The solvent route : the rich amine
The solvent route the lean amine
The gas route (HP)
The wet acid gas route (BP)
The stripping effort
The reflux system

6. Amine Unit Corrosion: Key Factors
Temperature
Thermal
activation
Amine loading pH
Oxygen entry
HSS
type of amine
& concentration
MEA > DEA ≥ MDEA
pH - Conductivity
Velocity
Turbulences
Inadequate design
Too high flow rates
Intrinsic corrosivity of amine solution
Protectivity of sulfide / carbonate layer
On one side we have got the corrosivity of the solution, on the second side we a have the protection of material by a protective layer . This is the fondamental : we can afford high coorisivity of the solution if we are sure that the layer will protect the CS material that equipment are made of.
How can we say that an amine solution can be corrosive ?
A Lean solvent solution is not corrosive and it is a well known passivator of CS.
Some elements drive it to corrosive substance to its environnement:
Type of solvent : from MEA to MDEA on the route to high corrosivity
High loadings of solvent : from MEA to MDEA on the route to high corrisivity
High temperature on the route to high corrosivity
But even with a corrosive solution, the metal wall can be protected.
How loose the protection of material?
The oxygen : high Hss to high corrosion rate desctruction of layer
Inadequate velocities : destruction of layer…
If the corrosivity / protection balance is not reached, it results in the 3 forms of corrosion : weight loss, erosion corrosion, amine stress
Uniform weight loss corrosion
Erosion – corrosion
Amine stress corrosion cracking

7. Wet Acid Gas Corrosion: Key Factors
- Amine wall wetting
- Condensation
- Water accumulation
Inadequate design
Inadequate metallurgy (PWHT, sour grades...)
Too low gas flow rates
Flue gas composition
Inadequate scrubbing
- H2S / CO2 ratio
- Condensation
CO2 content in treated gas
Condensation in the treated gas lines
Again the balance between the intrinsic corrosivity vs the protection of iron walls.
Corrosivity : high H2S content , high CO2 content with presence of liquid water.
Protection layer: Iron Sulfide protection always better than iron carbonate. High H2S content is better.
A good policy is not too have too low velocity of wet gas, in presence of CO2 especially.
Promoters:
Early degradation of sulfide carbonate layer, slow regeneration of it and presence of water traps, stagnant water.
Results:
Sour service with effects of hydrogen : in reference to NACE HIC SSC SOHIC corrosion ,
As a results it has been found Hydrogen cracking corrossion and weight loss corrosion.
Intrinsic corrosivity of condensed acid water
Protectivity of sulfide / carbonate layer
Hydrogen cracking (HIC, SSC...)
Weight loss corrosion

8. Wet Acid gas corrosion condensed water Corrosion of CS reboiler coils
Main Corrosion Areas
Wet Acid gas corrosion condensed water
Wet sweet gas
Acid gas
Erosion – Corrosion
Sour
Gas
Demin
water
So where did we find the corroded places:
And what kind of corrosion?
At the bottom of the absorber with spot all around the outlet rich amine nozzle.
On high velocity spots such as valves manifold.
At the top of the absorber with top of line corrosion (low velocity piping and water pockets).
At the top of the regenerator on the wet acid gas line (low velocities / pockets).
It shall be underlined that even in very corrosive environment, piping with high velocity have not been deffective. Provided that plant trend was about 100%.
Coil of reboilers : CS tubes has never been the solution with high temp solvent. Cone found ok.
Corrosion of CS reboiler coils
LP steam

9. Illustrative Case Study: Sweet Gas Unit
Wet sweet gas
Acid gas
AISI 410 (13% Cr)
Trays, valves & down-comers
Flash gas
Sour
Gas
CS shell
Demin
water
The Horror picture show….
LP steam

10. Outlook Introduction Overview of corrosion likelihood in amine units
Key factors of corrosion in amine plants
An illustrative case Study
From operating old CS units to handling high amine loadings
More than 50 years REX with CS
The present operating basis
High loadings - Lessons learnt from experience
The of use stainless steels in amine sour units – the question raised by NACE MR0175 / ISO
Main conclusions – a path to compacted designs
Il y a quatre points, voici comment je vais vous les présenter. Et dans quel ordre.
From operation with CS to operation with high loadings.
Rex from CS is wide.
High loadings has been introduced in design along with the wish to reduce the operatings cost and boost energy savings.

11. Experience from Initial CS Units
More than 40 years after start-up some of the initial CS units are still in operation today
Most encountered type of corrosion
Erosion - corrosion in the rich amine route
Most susceptible areas
Bottom of absorber (unappropriate design – Impingement...)
Rich amine lines (too high velocities, degassing effects...)
Top of the regenerator (unappropriate protection of walls)
Analysis got from inspection reports
Maintenance frequency and overhaul : 3 to 5 years
Problems were faced:
Bottom of absorber (unappropriate design – Impingement...)
Rich amine lines especially in valves manifold with line reduction and in elbows.
Top of the regenerator (splashing on walls)

12. CS Units: Lessons learnt to updated design
A combination of GOOD PRACTICE & selective replacement with CRA
Efficient policy to minimize amine degradation
prevent oxygen entry
strict blanketing of amine tank
deaeration of make-up water
avoid high reboiler temperature
control HSS concentration < 5000 mg/L
Moderate velocities / reduced turbulences
rich amine piping in CS:
a < 0.35  flow < 2 m/s // a < 0.9  flow < 1.4 m/s
bottom of Absorber / top of Regenerator
Avoid jetting with CRA deflectors
The good practise:
Maintain the solvent as nice as possible;: Upto 8 years operations without complete solvent overhaul.
O2, Reboiler, HSS monitoring
Check your profile : reduce fatigues, check that moderate velocities in pipe does not mean moderate velocity everywhere: elbows, manifold.
Check your internals. Check wall are wetted with lean solvent.
Practise UT test some times.

13. Updated design to High Solvent Loadings
A combination of good practise & SELECTIVE REPLACEMENT WITH CRA’s.
Allows high intensity operation and debottlenecks
Upgrade Bottom of Absorber & Top of Regenerator
CRA cladding where appropriate
or CRA weld overlay
or CRA lining
Select rich amine piping in CRA from Absorber to Regenerator
allows Solvent Loadings a > 0.9 & velocities > 2 m/s
The response to local troubles
The response to already-in-trouble areas.
Simplify your routine procedure of control and do not pressure your piping engineers too much!
Go to CRA on critical service!
CRA gets your rid of local trouble and difficult valves and isometrics arragement.
Reduced diameters of CRA piping.

14. High Amine Loadings : the Experience
More than 50 years of experience on various fields...
Amine
Type
H2S (% v)
CO2 (%v)
Loading
Start-up year
DEA
15.8
9.8
0.85
1957 (first unit)
34.6
6.1
0.90
1972
8.5
9.5
0.77
1980
21.5
14.7
0.82
1987 (first train)
DEAMDEA
4.2
6.0
0.64
1984
Formulated MDEA
Traces
9.2
0.72
1996
MDEA
4.0
5.6
0.71
2001
The experience is spread between fields in France(Lacq), Canada, AbuDhabi, Russia and Norway.
... Mostly with CS, to extended lifecycle, with reduced investments and energy costs … without major corrosion problems…

15. High Amine Loadings – Corrosion Impact
High Loadings
Enhanced corrosivity to CS
Enhanced flashing
Unit design
Too high velocities
Turbulences
Impingement
From Highloadings : low pH and local vapor locks.
Avoid local problems. The story of high average velocities. Often means local troubles.
Turbulences
Impingement
And the results are….
Stable protective layer
No Corrosion
Unstable or mechanically damaged layer
 Severe erosion - corrosion

16. High Amine Loadings : Lessons Learned
High Loadings
Enhanced corrosivity to CS
Enhanced flashing
Unit design
Too high flow rates
Turbulences
Impingement
Good design &
good practises:
No degradation,
Flow < 1.4 m/s
CRA:
- Rich Amine Lines
- Bottom Abs. + Top Reg.
The way to being safe
CRA where protective layer is not always maintained
The good point should be to maintain velocity below 1.4 m/s.
This reduces the erosion of layer, locally or generally.
 No Corrosion
Loading up to a > 0.9
High velocities (> 2 m/s)
Compact designs
Reduced maintenance
Stable protective layer
Unstable or mechanically damaged layer
 Severe erosion - corrosion

17. Outlook Introduction Overview of corrosion likelihood in amine units
Key factors of corrosion in amine plants
An illustrative case Study
From operating old CS units to handling high amine loadings
More than 50 years REX with CS
The present operating basis
High Loadings Lessons learnt from experience
The use of stainless steels in amine sour units – the question raised by NACE MR0175 / ISO
Main conclusions – a path to compacted designs
Chlorides and austenistic CRA : is it only a sour service question?

18. Use of CRA's in sour amine units: the NACE
NACE MR 0175/ISO "Petroleum & natural gas industries –Materials for use in H2S containing environments in oil & gas production – Part 3: Cracking-resistant CRAs and other alloys" (2003)
The facts
Recommended limits of use of austenitic grades (304, 316, 321)
60°C, pH2S > 15 psi
60°C, 15 psi > pH2S > 50 psi, Chlorides (Cl-) must be < 50 mg/L
 Strict application of standard would drastically restrict the use of austenitic CRA’s in amine units

19. CRA's in Sour Amine Units : the Experience
 A specificity of many sour amine environments
304L and 316L have been used in sour amine units for several decades
A practical experience of austenitic CRA in operation with chlorides up to 2000 mg / litre in highly sour service
Should-be-sensitive material are commonly present:
Lean / Rich cross heat exchanger plates, mm thick / SS316L
No internal failure
Additional laboratory tests have been performed at IFP over a long period:
Amine
Solvent load T°
Cl-
Steel type
Result
DEA 4N
10 bar H2S
7 bar CO2
110°C
6 g/L
AISI 321
No cracking-No pitting
MDEA 40%
4.7 bar H2S
1.8 bar CO2
AISI 304L
AISI 316L
No cracking- No pitting
The story in amine service and the set of tests.
Especial mateiral : the case of plate and frame heat exchanger.
Usually problems of gaskets!
Satus of platesis then easily checked!

20. NACE and Sour Amine Service
The U-bend test :
A detailed view : no cracking – no pitting
Strict application of NACE MR0175/ISO is questioned from Lab Tests and Long Term Monitoring of amine gas plants with Cl-
NACE MR0175/ISO is based on acidic systems data which does not fit the alkaline pH of liquid amine solvents
The results of test.
The piece
The views
The advanced conclusion; Sour service does not mean amine service since pH is 8 to 10!

21. Outlook Introduction Overview of corrosion likelihood in amine units
Key factors of corrosion in amine plants
An illustrative case Study
From operating old CS units to handling high amine loadings
More than 50 years REX with CS
The present operating basis
High loadings - Lessons learnt from experience
The of stainless steels in amine sour units – the question raised by NACE MR0175 / ISO
Main conclusions – a path to compacted designs

22. Main Conclusions – 1
Corrosion control in DEA and MDEA amine units is a simple combination of:
A few key operating practices
Avoid amine degradation
careful blanketing + deO2 of Make-up Water and Nitrogen + controlling heat flux to reboiler
Avoid high velocities with CS
A consistent design
Carefully manage turbulences & impingement areas with dedicated arrangements
Use CRA at selected locations (Bottom of absorber, top of regenerator, rich amine lines)
 Successful results with high amine concentrations and high amine loading (a > 0.9 mol/mol)
Read
Be aware the areas are weaker than others!
Use CRA with confidence.
Take your advantages! Go to high acid gas content of raw gas!

23. An Up-Dated Design of High Loadings Sour Units
Wet sweet gas
Acid gas
Prevent oxygen entries
Blanketting
 > 300 k.cm
Controlled chloride
Flash gas
Demin
water
An overwiew of the updated design for relaible and quiet operation.
Reduced Project engineering mangement for rich amien piping
Quiet long term operation ,with no need for solvent overhauls.
LP steam
Fluid monitoring
HSS < 5000 mg/l Cl- < 500 mg/l
Use of 316L stainless steel

24. Main Conclusions – 2
Present design and operating practice are based on more than 50 years of positive experience
Rely on extended use of the 316L SS on corroded sensitive areas
No cracking in sour media, documented by Feed Back & Lab Tests
Keep all flexibility to any future process change or solvent swap
Keep the possibility for upgrading during scheduled maintenance phases to allow operation with higher loadings
Use specific design rules for sweet service units
Keep quiet with SS316L CRA in amine service.
Do not forget to investigate the upgrade before your maintenance period.
Prepare you upgrade as a revamp project.
If you use CS lines : check them; Go to the weak points if your are in the red zone.
Keep a look upon service without H2S, with increased consideration for need of CRA.

25. Thank you very much for your attention
OAPEC IFP joint Seminar – 17th 19th June 2008