Demin water closed loop cooling and heating medium systems - need for corrosion inhibitor?

[AndersE]

Hi all,

I am currently working on a FEED phase study for a large, offshore gas production plant. The current design includes three closed loop cooling and heating medium systems, briefly described below:

- Main cooling medium system, normal operating temperatures 34 to 55 °C
- Turbine inlet air cooling medium system, normal operating temperatures 4 to 16 °C
- Heating medium system, normal operating temperatures 140 to 177 °C (pressurized water, not steam)

An amine based acid gas removal system will also be included, which requires continuous high quality demineralized water make-up with the following specifications:

- Max oxygen content: 10 ppmw (ppm by weight)
- Max chloride content: 2 ppmw
- Max calcium (Ca2+) content: 50 ppmw

The current design is based on using this demineralized water as make-up and first fill of the closed loop heating medium and cooling medium systems described above, even though this is not strictly required. The reason for this is that generating two different qualities of water adds more complexity and increases cost.

All closed loop systems are based on carbon steel piping and equipment, and are fitted with nitrogen blanketed expansion tanks. Our current design includes for the batch dosing of corrosion inhibitor, scale inhibitor, pH controller and oxygen scavenger (exact number of chemicals still to be decided) into those closed loop systems, in order to minimize corrosion. The turbine inlet air cooling medium system includes glycol (MEG) for antifreeze protection, while the other systems use only water (except for the corrosion prevention chemicals).

However, one of the engineers from our client is arguing that no chemicals should be needed unless we can calculate the yearly corrosion rate and prove that this is needed. The design plant life time is 30 years. I have been trying to explain that to my knowledge, there are no models that can accurately predict the corrosion rate and that all designs I have seen for other projects add corrosion inhibitor and other chemicals to their closed loop cooling and heating medium systems, but with litte success so far.

The oxygen content of the make-up demineralized water is low, and so is the chloride concentration. But in the closed loop systems, oxygen may enter during maintenance of equipment when flages are opened. Chlorides could potentially enter into the cooling medium system in case of a pin-hole leak in one of the seawater plate heat exchangers. Therefore I am still arguing that it is too risky to design without the provision for corrosion prevention chemicals and that if serious corrosion occurred it could have huge economical consequences. So my question is:

- Is there any reliable and accepted method for calculating the corrosion rate in these systems?
- Would it be possible to achieve a 30 year life time without adding corrosion prevention chemicals?

 

[georgeverghese]

Dont have answers for the queries posed, but in my experience, CI injection for the reasons you've mentioned are typical even with demin water closed loop systems. Leak in rates from HP process HXs' will be even worse with shell and tube units through tube to tube sheet joints; and other all welded PHE if materials used are not completely corrosion resistant. Moreover, reliable readings for dissolved O2 at low concentrations are a challenge, so shock dosing with O2 scavenger is typical.

I'd stay clear of printed circuit heat exchangers for any process heat exchange service despite the sales talk and the weight advantages.

Getting to 177degC for heating apps with hot water will require pumping pressures that will maintain the water in liquid phase at up to TAHH (185degC or so ?) on the hot water medium WHRUs exit.

 

[SJones]

1. No. There are models for corrosion by dissolved oxygen, e.g. Andijani & Turgoose, but there may be other corrosion mechanisms acting on the systems. Pilot scale tests would probably offer the best insight, but will probably not be a practical proposition at the current stage of design.

2. How lucky does the end user feel? If they are set on not using chemicals from the word go, perhaps offer them a monitoring strategy with the equipment capability to add such chemicals if the monitoring indicates a problem in subsequent operation?

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[EdStainless]

Perhaps if it were an all stainless steel system, but CS, no way.
You would have to keep the oxygen very low (1ppm or less) and keep the water conductivity low.
If the water is conductive you will get corrosion of some form.
I have seen systems that are continuously polished through ion exchange, but that is more costly than chemical treatment.

= = = = = = = = = = = = = = = = = = = =
P.E. Metallurgy, Plymouth Tube

 

[AndersE]

Thank you for the replies!

Including for corrosion prevention chemicals is what I consider good engineering practice, and a very cheap "insurance" with low CAPEX impact compared to the overall cost of the plant. Since the required dosing concentrations of these chemicals are low, OPEX would be small as well. The main cooling medium system has a design duty of around 400 MW and a total flow rate of roughly 18 000 m3/h, that gives you some idea of the dimensions.

I will have to continue persuading our client to include for chemical dosing from day one, and to accept the fact that some design decisions are based on experience and good engineering practice, and not necessarily detailed calculations.

Getting to 177degC for heating apps with hot water will require pumping pressures that will maintain the water in liquid phase at up to TAHH (185degC or so ?) on the hot water medium WHRUs exit

We will maintain the expansion tank at a pressure that is sufficient to prevent boiling inside the WHRU tubes, based on the maximum film temperature calculated by the WHRU supplier, plus a margin. So if the calculated film temperature is 200 °C, we will maintain the expansion tank at a pressure that corresponds to the water saturation pressure at for example 210 °C. The pressure in the expansion tank is maintained via nitrogen.

2. How lucky does the end user feel? If they are set on not using chemicals from the word go, perhaps offer them a monitoring strategy with the equipment capability to add such chemicals if the monitoring indicates a problem in subsequent operation?

In addition to adding chemicals, we will also recommend corrosion monitoring coupons to be installed at strategic locations, so that the actual degree of corrosion within the system can be assessed. We need to convince our client to include a chemical injection system, so that these chemicals can be added when necessary. Since it is a closed loop system it would not be continuous injection, but rather batch dosing based on laboratory measured concentrations of chemicals or testing kits provided by the chemical suppliers.

 

[AndersE]

Perhaps if it were an all stainless steel system, but CS, no way.
You would have to keep the oxygen very low (1ppm or less) and keep the water conductivity low.
If the water is conductive you will get corrosion of some form.
I have seen systems that are continuously polished through ion exchange, but that is more costly than chemical treatment.

Stainless steel is out of the question due to cost, as our client is very specific when it comes to one requirement: lowest possible CAPEX. Of course we could exclude chemical dosing to reduce CAPEX even further, but we need to engineer a system that will actually work for the intended life time of 30 years...
Your points regarding oxygen concentration and conductivity are very interesting though, thank you!

 

[georgeverghese]

The bank of compressor turbine WHRUs' would usually be just downstream of the hot water recirc pumps, and the expansion drum would be downstream of all users after the regulating valve on each user, and is usually the component with the lowest operating pressure. So the WHRU pressure would be about the same as that on the discharge of the recirc pumps. Setting the pressure here to be equal to the highest tube ID film temp seen on the WHRU at the lowest operating flow through any one unit sounds good - would be a good idea to have the tube bank in the WHRU to be self venting, so the tubes will be liquid filled all the time. Tubes would most likely need to be seal welded to the tubesheet to prevent water from getting into the turbine exhaust stream. All CRA construction would be required on the water wetted parts of the WHRUs (SS316 L or better??).

From a process safety perspective, would you need to add MEG to the cooling water closed loop ? - if you had a pinhole leak on a process HX in this loop with low temps created on the CW side, you could freeze the path to the CW side PSV??

 

[AndersE]

The bank of compressor turbine WHRUs' would usually be just downstream of the hot water recirc pumps, and the expansion drum would be downstream of all users after the regulating valve on each user, and is usually the component with the lowest operating pressure. So the WHRU pressure would be about the same as that on the discharge of the recirc pumps. Setting the pressure here to be equal to the highest tube ID film temp seen on the WHRU at the lowest operating flow through any one unit sounds good - would be a good idea to have the tube bank in the WHRU to be self venting, so the tubes will be liquid filled all the time. Tubes would most likely need to be seal welded to the tubesheet to prevent water from getting into the turbine exhaust stream. All CRA construction would be required on the water wetted parts of the WHRUs (SS316 L or better??).

From a process safety perspective, would you need to add MEG to the cooling water closed loop ? - if you had a pinhole leak on a process HX in this loop with low temps created on the CW side, you could freeze the path to the CW side PSV??

The pressure downstream the pumps (and hence in the WHRUs) is determined by the expansion tank operating pressure, plus the differential head of the pumps. We could take this pump differential pressure into account when setting the expansion tank operating pressure, but the advantage of keeping the pressure sufficient already in the expansion tank is that we prevent boiling also if the pump differential pressure is lower than normal, or if the pumps trip. Yes, this requires a somewhat higher design pressure of the system, but the difference is not dramatic and we are in any case in the 300# piping region.

Regarding the pinhole leak and potential freezing issues, it is unlikely that this would be a problem since the PSV nozzles are typically located some distance away from the tube sheets, which are the most likely locations of pin hole leaks.

 

[georgeverghese]

Okay, so you have the TCV on each hot water HX upstream of the the HX and not downstream. Agreed, that will push up the design pressure of the drum quite a bit. But this TCV upstream will help with the open path to the HO expansion drum PSV for the tube rupture case ?

If the tube rupture scenario relief load is accomodated at this drum, then freezing of this relief path would occur? Or is this drum design pressure high enough to keep the lowest predicted tube rupture relief stream temp at above 0degC ?

 

[weldstan]

A corrosion inhibitor or mix thereof will be required for your carbon steel systems to meet your design life criteria and a corrosion monitoring system is highly recommended.

 

[AndersE]

Ok, so the conclusion is - as I had expected - that we do need to add corrosion inhibitor to these systems.

My next question is: what type of chemicals would be required? Would we for example need both corrosion inhibitor and oxygen scavenger, or is it enough with only one of them?

The demineralized make-up water contains only 10 ppmw oxygen, and the expansion vessel of each closed loop system is blanketed with 99.9 % nitrogen. So the amount of oxygen scavenger needed to remove 10 ppmw to say 1 ppmw should be relatively small.

 

[SJones]

Speak to several appropriate chemical suppliers for their analysis and recommendations, with justification. It is more than likely that a biocide will also need to be included in any treatment package for the main system. Just keep in the back of your mind when reviewing the recommendations that the chemical supplier's goal is to sell as much chemical as possible.

Steve Jones
Corrosion Management Consultant

http://www.linkedin.com/pub/8/83b/b04

All answers are personal opinions only and are in no way connected with any employer.

 

[bimr]

It may solve your problem if you installed stainless steel piping and painted it so it looks cheap when it is finished!

 

[Mushahid Nauman]

Andinaji and Turgoose, Oldfield and Todd and Beger & Hau are all used for oxygen corrosion rates calculations in (ppb)concentrations. There is some literature corrosion rates which you can reference in terms of water velocity (m/s), oxygen concentration (ppm) and temperature given in Subsea Pipeline Engineering, A.C Palmer & R.A.KIng, Penwell, page 222, 2004. It is available online as well. This can partially justify the need to put monitoring and inhibition place. As Steve said earlier, there might be other mechanisms working as well during the service life.

 

[chemcorr1]

It is not uncommon to apply biocide in the system you described.