MDEA Corrosion problem in gas plant

[gosooners]

Hi all experts,

Here is the situation in my gas processing plant :

MDEA of 50.5% is used to absorb CO2 and H2S with loading 0.37 m/m. I have corrosion problem in exit of lean/rich exchanger pipe to entry of the stripper(first 4 trays) and bottom of the tower. I have checked following analysis :
HSS(0.12-0.2 wt%)
Temperature in the reboiler : 250 F
Filtering system is working fine. But one think i noticed with modelling is high velocity(13 ft/sec) in the pipeline entering to stripper column. The tower operates at 9 psig. Control valve is at the ground level and vertical pipe of 75 ft goes to top of the stripper column. My model says high velocity in the vertical pipeline somewhere in the vertical pipeline after exiting from control valve.

There is no significant corrosion problem in L/R exchanger.
Corrosion in top of the tower and pipeline that enters to the tower is significant appx 80 mils/year. Right now we started temporary corrosion inhibitor solution. But still I am thinking high velocity is the factor of this problem.

Can you suggest me probable reason for this. I need quick suggestions for this.

thanks in advance for your suggestions.

 

[GregLamberson]

gosooners

I like that handle, I live in Tulsa, my folks live in Norman.

80 mpy - wow! My experience has been with gas and multi-phase flow & pipleines. I assume you've calculated the minimum velocity - Ve = c/(pm)^0.5? If so, what C value did you use?

Another factor, at least in pipleines, is wall shear stress (should not exceed 1,000 Pascals). You're chem corrosion inhibitors should be qualified to the shear stress or adjusted slightly downward. You'll see inhibitors qualified in the lab up to 1000Pascals, but field experience shows more in the 250-300Pascals. Shear stress can strip of passive corrosion films and inhibitors and filming corrosion inhibitors.

There may be enough levels of CO2 and H2S to worsen the problem?

I'm just throwing out some ideas.


Greg Lamberson, BS, MBA
Consultant - Upstream Energy
Website:

http://www.oil-gas-consulting.com

 

[gosooners]

Greg,

I used Promax software to calculate velocity. Yes, it's two phase flow with intermittent regime.

We have already place corrosion coupon before we started our corrosion inhibitor circulation last week. we will wait for results of inhibitor success for 3 months & then i am thinking of increase pipeline diameter.

do you think HSS concentration of 0.2% is issue ? Because i think high velocity and HSS are responsible.

gosooners.

 

[CJKruger]

gosooners,

1) Get your MDEA analyzed by the supplier and ask them what is outside normal limits.

2) It is standard to have the rich amine control valve just before the tower nozzle (at same elevation on platform) and SS pipe from the control valve to the tower.

3) Also, it is standard to have the top of the tower till a few trays below the feed SS cladded.

4) All CS should be HIC resistant.

CKruger

 

[gosooners]

CKruger,

Thank you for suggestions. But what do you think about high velocity just after control valve. Flashing of gas occur after control valve and it is appx 2%. Before the control valve velocity is only 5 ft/sec and there is no significant corrosion issue on that part.

gosooners

 

[GregLamberson]

gosooners

I just don't think it is velocity. Thresholds for single phase gas velocity and multiphase should be, depending on what mixture you're flowing, press & temp, in the 25-75 fps (common rule is "under 100 fps) range, you're under that. If you'r calcs show the threshold lower than 13 fps, then again, have to question why at those parameters. What C factor is being used?

What I've seen in pipelines/flowlines, is the process of erosion/corrosion is accelerated by one or all of the following - high fluid velocities, presence of sand, corrosive contaminants such as C02, HSS, and H2S, and fittings.

I don't think it is velocity, I doubt sand is the issue (wasn't mentioned), so that really leaves contaminants, so if you have started inhibitors, I suspect that will improve your mpy loss.

Greg Lamberson, BS, MBA
Consultant - Upstream Energy
Website:

http://www.oil-gas-consulting.com

 

[GregLamberson]

gosooners

A coupole of follow up thoughts on this. Be sure & check to make suyre your corrosion inhibitor is qualified for the wall shear stress you have.

Also, there is velcoity enhanced corrosion (erosion-corrosion). Again, I don't think velocity alone is the culprit, but corrosion in general is and there are a few models available that can predict it, FLOPAT is one I have heard of, there may be others. I know FLOPAT considers wall shear stress, as well as the other common factors, as part of the model results.

Some of the corrosion guys will have a better idea on other models.

Greg Lamberson, BS, MBA
Consultant - Upstream Energy
Website:

http://www.oil-gas-consulting.com

 

[SJones]

Greg,

It is velocity in a sense. The rich amine is corrosive and requires film formation on carbon steel to keep corrosion rates down. When this film is removed by turbulent flow and/or flashing gas, corrosion rates are substantial to say the least. Hence the observation that corrosion is acceptable before the control valve. The answer is to change the valve and the downstream piping to 316(L). The flow into the column may also result in film stripping but I wouldn't class it as 'usual' to clad the regenerator column; however, it may be a necessary option in the case under discussion if it proves more economic than continuous dosing of chemicals. Unfortunately, there aren't any models for this type of service; it's all down to (bitter) experience.

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[dcasto]

It's corrosion from the acid gases breaking out of solution. Look at the still column across from where the stripping steam enters your still and also where your feed enters the still to see if you have corrsion there to. You have a very high loading and high amine concentration and this is to be expected. This is why the specialty amines where developed. I'm suprised you have not

Do you feed the still on the first tray or third tray? For my fact of the day, bottom temperature on an amine still has very little meaning and should not be a control point..

 

[gosooners]

dcasto & SJones,

Yes, feed enter on tray 3. as i mentioned we don't have corrosion issue on bottom part of stripping column and reboiler. First 15 trays have significant corrosion issue and nozzle that enter to column.
We have SS304L pipeline not 316L.

Do you think this problem is because of flashing of liquid occurs because of pressure drop and high velocity ?


gosooners.

 

[SJones]

You are corroding an austenitic stainless steel? Boy! You have got problems!

DCasto has already given the process approach and your quick answer will lie in juggling the process parameters of amine type and concentration, temperature, and circulation rates. Good luck.

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[0707]

“Process stream velocity will influence the amine corrosion rate and nature of attack. Corrosion is generally uniform however high velocities and turbulence will cause localized thickness losses. For carbon steel, common velocity limits are generally limited to 3 to 6 fps for rich amine and about 20 fps for lean amine.


Corrosion rates increase with increasing temperature, particularly in rich amine service. Temperatures above about 220oF (104oC) can result in acid gas flashing and severe localized corrosion if the pressure drop is high enough.”


luismarques

 

[SJones]

Also, check the chloride content of your amine solution. If it is creeping up - it won't do either carbon steel or stainless steel any good.

Look at:

NACE, Corrosion 97, Paper 340, Experiences With Combined Corrosion Effects On Stainless Steel Due To Chlorides & H2S

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/