Some questions:

1) Was this HX designed for this specific service or has it been bouncing around the plant for a long time with periods in the bone yard ?

2) Can you share with us the drawing ? Is it a TEMA standard design ? If so which one ? Is it a TEMA BEM ?

3) What are the design and operating pressures on both sides of the HX ?

4) What specifically are the materials ? "copper nickle alloy" is not good enough.

5) Because of accelerated corrosion, there are maximum recommended velocities of liquids for various materials contained in design guidelines. Has anyone calculated your actual liquid velocities and compared them to the maximums recommended for your "copper nickel" ?

6) Are there many plugged tubes ? Plugging tubes increases the liquid velocity on the remaining tubes and shortens their life.

7) Where, specifically is your corrosion ? Tube entrances ? shell nozzles ? where ?

Not enough information ......

When you have trouble with your truck, do you tell your Mechanic "Truck broke ... not move"

MJCronin
Sr. Process Engineer

Strongly suggest to have an expert to collect all process and operation info related to the damaged tubes, perform a failure analysis for the root cause of the failure, and provide an engineering solution.

Hi,
MJcronin,
This HX is very old (you can't image it, because this refinery is in operation since 1960, very little details are available from old guys, I checked personally no detail was printed on name plate but i will ask and share here if got some information.
Operating pressure: 75 psig
Operating temperature: 260 F but now they are operating at 320 F. cooling water is coming from seawater pump discharge and there is no particulate filter.
I asked to one senior guy here in refinery he told me that tube material is copper nickle alloy. I went in workshop and found the same material as said by senior guy.
This refinery is very old fashion refinery designed by EXXON and initially operated by ESSO but now days being operated by Libyans.
MK3223,
Can you please share your past experience for root cause analysis what are the main points of tube failures of this type of HX.
Regards

Copper Nickle either 70/30 or 90/10 is velocity sensitive. These are not very hard alloys.
There are published velocity limits, but be aware that even at the published limits the tubes are expected to erode.
Typically if they can keep the general wall loss down to 0.0005"/yr they consider it useful.
320F is getting rather hot for CuNi, and very hot for seawater cooling.
This will scale like crazy at 130F.
There are alloys that are much more erosion resistant, but you still need to address the scaling.

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P.E. Metallurgy, Plymouth Tube

Dear MIANCH,

Find out and go through the data card and history card for this exchanger.

Regards.

DHURJATI SEN

https://www.nace.org/people/dhurjatisen

Tube material is admiralty SB-111-C70600 (90/10 copper nickle alloy). And HX type is TEMA AEP.
these photos are visual observation, today i will try to get more information then share with you guys for more discussions.
Regards

it seems like localized corrosion due to condensation. You must identify why in that specific places.

Collect deposits, corrosion products, clean damaged metallic surfaces to confirm/discard flow assisted corrosión or erosion.

Take a look inside the exchanger or in the surroundings for leaks or other sources of fluid taht could be the origin of the mechanism.

Marriolav
for your information this exchanger is condenser, Naphtha vapors are being cooled down in this exchanger, yes condensation is there as you said.
May be naphtha contain H2S and water vapor and while condensing this create localized corrosion.
I would like to listen from you guys how to avoid this problem and what actions need to be taken for trouble shooting.
Regards

This 60 year old heat exchanger is at the end of it's design life .... It must be replaced ... nothing lasts forever.

You seem have what is typical of most process plants .... all of the drawings are gone, no maintenance records exist and all of the nameplates/dataplates have been ripped off. Maintenance departments all over the world do this because it ensures that they will never have to work on the equipment (no information) and the problem then can be kicked downfield to the engineering consultant

I suggest that you hire a HX consultant and at least get the cost for a new TEMA AEP Seawater duty unit with an upgraded tube material. You will have to establish the necessary HX duty

I believe that you consider a slightly larger diameter replacement HX made from a superaustenitic SS, or perhaps titanium, or perhaps C276. A larger diameter/number of tubes will mitigate the erosion problem. A material upgrade will ensure corrosion.

Now, your MBA boss will tell you that he doesn't have enough money and scream at you that you "must come up with another plan !!!! "

His extensive background in taxes and accounting are no help to him here ...

Explain to him that the only alternative plan is to rebuild the bundle an be prepared to replace it every 3 years ...

MJCronin
Sr. Process Engineer

MJCronin,
The last sentence sounds appropriate solution.
Best regards

MIANCH ..... Buy this superb book and read it:

https://www.amazon.com/Tubular-Heat-Exchanger-Insp...

MJCronin
Sr. Process Engineer

MJC is on the money, except that the rebuilt units won't last any 3 years at the new operating conditions.
They changed the process, now change the equipment. period.

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P.E. Metallurgy, Plymouth Tube

IMO, the best practice of the risk based inspection (API-580) may be implemented to the heat exchangers service in your plant, and to improve the operation efficient and safety.

Hi All,
Thank you for your valuable comments.
Best Regards

Hello
Can Cu-Ni 70-30 and 90-10 alloys suffer severe corrosion by water containing H2S ? I heard that sulfur species may corrode copper alloys quite fast, do you have good experience with copper alloys seawater coolers condensing sour water, for example in hydrotreating units ?
Same question for Monel, Alloy 400, Ni-Cu 70-30...
Thanks
Regards

Yes, H2S will cause the passive film on Cu alloys to become very soluble leading to very rapid metal loss.
Read the Special Metals Monel handbook, the information is there.

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P.E. Metallurgy, Plymouth Tube

thanks Ed
I cannot find Special metal Monel Handbook after seeking on their website...
http://www.specialmetals.com/assets/smc/documents/... does not give information.
regards

Chumpes
Try this one
http://www.specialmetals.com/assets/smc/documents/...

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P.E. Metallurgy, Plymouth Tube

Dears,
Here is two more picture for another exchanger for same service, E-103A, its type is TEMA R.
Hot inlet side have copper salt but outlet side no salts deposited.


Regards

Simply looks like they have gone beyond the max service temp for CuNi in this application.

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P.E. Metallurgy, Plymouth Tube

Edstainless,
Operating temperature is 250F , and water inlet temperature is 75F, H2S is 190 ppm, can this temperature (250F) and H2S destroy like this and rapidly, please elaborate the phenomena bit.
Thanks

It only takes a few PPM (0.5 ppm or greater) sulfide to start corroding CuNi at any temperature.

https://pdfs.semanticscholar.org/a0ea/2e5be6d786af...

H2S is extremely reducing, when some of the oxygen is removed from the oxides and hydroxides that protect the surface the film them becomes soluble and metal dissolves rapidly.

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P.E. Metallurgy, Plymouth Tube

Additional information today I received,
Cl-:6-18
Ph:4.5-8
I requested to check more samples also for water side and process side as well. Low Ph is not always but some days go down.
Regards

Low pH is murder on CuNi.
What also happens is that one film will form, but when the pH shifts most of the original film will slough off and be replaced by one with a new composition. Each of these cycles removes more metal also.

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P.E. Metallurgy, Plymouth Tube

Naphtha Drum boot water analysis has been carried out as per below and I'm very new bundle of tubes will also soon start leaking.
Water Ph: 4.6
Iron content (ppm):4.8
SO-2:(ppm):----
H2S (ppm):0.42

Seawater
Ph:8.0
Iron (ppm):1.1
SO4-2 (ppm): 3205.5
H2S:0
Please comment on this issue.
Regards

Why is the pH so low?
You need to start looking at other alloys.

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P.E. Metallurgy, Plymouth Tube

Explore the replacement of the shell-and-tube design with single or multiple plate frame HXs..... the design pressures and temperatures seem to be within the plate frame maxima.

Make sure that the plate frame unit has additional "rack space" available for future HX expansion...... should your process condition change yet again

You will free up additional floor space in the plant...

Use C276 for the plate material and PTFE for the gaskets ..... keep spare plates and gaskets and instruct plant personnel on how to repair the unit.

Do the job right .... install a new functioning duplex SS strainer on the seawater side and clean it frequently evaluate the new pump operating points on both sides of the HX and adjust existing pumps accordingly....

Or .... like EdStainless says, be prepared to replace thetube bundle frequently if you want to stay with your exsiting MOC

https://www.platetypeheatexchanger.com/plate-type-...

MJCronin
Sr. Process Engineer

Titanium has always been the go to to plate material for sea water applications. C276 seems expensive for this application.

Tug .....

C276 has come down in price, but TI may be a better choice .... you have to get prices of material alternatives and compare

My point, of course, is to do some REAL ENGINEERING, develop and price different alternate designs and come up with a plan.

Yes, this will cost money .... compare the plate frame prices with a tube bundle made of the correct material.

Sixty years ago plate frame HXs did not even exist and may be a good alternative for this ever-changing corrosive application.

It will easy, cheap and simple to do this HX evaluation ..... My question is, why hasn't it already been done ?

MJCronin
Sr. Process Engineer

Quote (mk3223)

Strongly suggest to have an expert to collect all process and operation info related to the damaged tubes, perform a failure analysis for the root cause of the failure, and provide an engineering solution.

I emphatically concur.
Failure analysis is not done by committees or by crowdsourcing.

Quote (MJCronin)

This 60 year old heat exchanger is at the end of it's design life .... It must be replaced ... nothing lasts forever.

Absolutely; 60 years is far beyond what can reasonably be expected from chemical process equipment. Bite the bullet and replace the entire HX. The best guide to alloy selection will come from petroleum corrosion engineers; the best industry source for this information is NACE (or else Steve Jones on Eng-Tips).

Bear in mind that the quality of crude oil has degraded massively in 60 years, and many equipments have been forced to climb what I call the 'alloy ladder' to keep up with ever more aggressive raw materials.

"Everyone is entitled to their own opinions, but they are not entitled to their own facts."

Ironic,
Look 60 year mean dose not this exchanger is 60 year old, i collected information for this exchanger more in detail and found that there is three exchanger for same service and frequency of tube leak is very high (say every six month or year refinery guys repair or plug tubes and replace the tube bundle with refurbished tube bundle)
Corrosion department in refinery is failed to establish the root cause of failure, last month they requested to process engineering department to investigate the root cause.
I receive very good recommendation and found that localized corrosion is the main cause of failure of this corrosion, old system is existing for crude oil distillation column overhead corrosion control that is ammonia injection. Ammonia is not very effective for overhead ph control while H2S condensing in the presence of water reducing the ph to below 4.5.
tube side is seawater and shell side column overhead vapor containing 190 ppm H2S and water,I think you have better history of this exchanger to understand failure causes.
Regards

Here is a study that is very closely related to your situation, low pH high H2S.

https://www.google.com/url?sa=t&source=web&...

Tugboat ....

Based on your fine paper, I stand corrected .... C276 does not seem to be a good choice for this extremely corrosive service. Because of corrosive conditions ON BOTH the tubeside and shellside, the titanium option seems best

Please note that I still recommend paid engagement of an experienced corrosion specialist, developing a report and following those recommendations.

On a parallel path, I suggest getting a budgetary quote on a replacement HX with Grade 2 titanium tubes, titanium clad tubesheet and having a surface area about 10-15% greater than the existing units.

Find the number of weeks necessary to get delivery of a replacement unit

MIANCH

Again, I suggest that you perform an economic evaluation of all of your current replacement and repair costs for replacement tube bundles.

We now understand that there was tube plugging as the bundles degraded, thereby increasing the fluid velocity on the remaining tubes and accelerating corrosion.

Please respect us ... Do not simply drop this thread

Tell us of your final solution and your reasons for selecting it ....



MJCronin
Sr. Process Engineer

I doubt that you will need more surface area with Ti.
Ti does have very poor fatigue resistance. Ask to see vibration analysis on the new HS+X, especially if they suggest thinner walled tubes in Ti.
With this small of unit they may use a solid Ti tubesheet.

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P.E. Metallurgy, Plymouth Tube

EdStainless
MOC change already suggested by corrosion department but it was rejected because of costly. I suggested to install micro filter but operation is reluctant to install due to frequency of plugging & cleaning. Ammonia carbonate is being injected to control pH but looks not working very well.
Regards

If I had a list of everyone that I have seen that is willing to spend millions of dollars on repairs and downtime rather than spend thousands on the correct equipment it would make your head spin.
Often the issue is that people do not report information accurately up the chain of command.

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P.E. Metallurgy, Plymouth Tube

EdStainless ...

This thread is a waste of time. We ask for informaton ... and we are ignored ! ... We make suggestions and get "Oh, management doesn't want to do that" .... "management says this will be too costly."

This is yet another third-world game ....

MJCronin
Sr. Process Engineer

MJCronin
I posted all information which I have it, even though I posted photos of exchanger. My area of responsibility is limited. working in MENA is not easy.
MOC change should be accepted by operation not by process engineering or corrosion department.
What you say about, if refinery a is being operated without flare system since commissioning 1960.
Best Regards