Can IP-66 enclosure be air tight? 5

[krisys]

The question here is about Ingress Protection(IP) Level as per IEC standard 60529. As per this standard, I would like to know, whether the IP-66 enclosure is air tight?

or​

Air tight IP-66 enclosure is permitted for the Hazardous area application?

I have a 6.6 kV power junction box with below specifications:
Enclosure material : Stainless steel (316L), epoxy coated, (inside & outside)
Enclosure material thickness : 2mm (min)
Enclosure Protection : Ex 'e', Zone 1, IIB, T3
Enclosure Degree of Protection : IP 66 as minimum

This junction Box is installed in the classified area (Ex rated, Hazardous Area classified).
I know that the IP-66 Enclosure means "dust tight" (first numeral 6)and protected against heavy seas or powerful jets of water (second numeral 6). But not necessarily air tight.

I want to know, whether the Ex rated equipment enclosure is permitted to be air tight? It could be a violation, because the product of internal explosion cannot have controlled release to the atmosphere.

I appreciate if someone could throw some light on this issue.

 

[7anoter4]

See IEC 60079 Standard

https://en.wikipedia.org/wiki/Electrical_equipment_in_hazardous_areas#IEC_60079

 

[davidbeach]

Air tight exists in theory but not in practice. Nearly air tight enclosures pump in water vapor, which becomes liquid water, with every thermal cycle from cool to warm to cool. Better to figure out how to let it breathe and how to drain it if necessary. Or keep it positively pressurized. Or any of a few other approaches, but air tight just risks disappointment.

 

[krisys]

7anoter4, davidbeach - Thanks for your inputs.

My query here is more to do with the Ingress Protection (IP). In terms of IP classification, whether the enclosure IP 66 is expected to be air tight?

 

[ppedUK]

The IP rating of an enclosure only relates to its ability to keep out solids (dust) and fluids, not air. An Ex 'e' enclosure to EN 60079 is not required to contain an internal explosion, the enclosure is there only for ingress protection. Ex 'e' is the "increased safety" concept, where even if a flammable gas enters the enclosure, it cannot be ignited due to the use of high integrity (non incendive) terminations inside the box.

 

[Parchie]

@krisys,
IP ratings have specified ratings for: foreign body ingress protection (1st digit); protection against water (2nd digit) and protection from mechanical damage (3rd digit)! If you wanted "air-tight" protection, methinks thinks you have to go for a 7 or 8 on the second digit IP rating; IP67 or IP68! (protection against immersion and submersion, respectively)

 

[ScottyUK]

An Ex'e' enclosure relies upon reinforced insulation and increased creepage and clearances to prevent an internal ingition. If something does ignite a flammable atmosphere within the enclosure then the enclosure will rupture. If you want to withstand that scenario then you need an Ex'd' enclosure which will be massive and heavy, not to mention expensive. You're confusing the requirements of Ex'e' and Ex'd' protection concepts.

IP66 is acceptable for an Ex'e' enclosure, but the enclosure will 'breathe' as noted above by David Beach and it should therefore be provided with an Ex'e' breather-drain to prevent the buildup of moisture and formation of a saturated condensing atmosphere within the enclosure. Failure to do this may well result in a breakdown of the Ex'e' protection if, for example, damp salt-laden air condenses on insulator creepage paths leading to a flashover.

 

[krisys]

General:
Thanks for all the valuable inputs from the distinguished panelists. Your views have reaffirmed my own understandings and enhanced the thought process.

To give a perspective, I am elaborating the background and the intent as below:
6.6kV power junction boxes installed at offshore platforms (PF). These are unmanned mini platforms, the area of each platform is a bed room size. Around 25 such oil platforms are spread around the oil field. End to end distance of the oil field is about 25 kMs. The average power demand of each platform will be about 50 kVA. The 6.6 kV power to these PFs is supplied from an island in the center. Each PF has a step down transformer (6.6kV/415V). Five each PFs are grouped to form a 6.6kV ring. Each PF has a 6.6kV RMU to tap power. At the entry point of the submarine cable to each PF there is a Junction Box (6.6kV Power JB). From the JB it goes to one end of the RMU. Other end of the RMU returns back to the sea through a similar JB.

After couple of months of energization of these RMUs, few JBs were found ruptured. No marks of carbon deposition. Accumulation and Hydrogen gas was suspected as a reason for the rupture. Subsequent investigation has also established that H2 gas accumulation was the reason. The hydrogen is being generated from the submarines cables. The gas is entering into the JB though the termination at a small rate. But in a month the amount of is sufficient to cause the explosion, if there is an ignition inside the JB. Now we are in the process of exploring the mitigation.

The JBs are having the exact construction as David described here. It also complies the intents of others panelists descriptions.

I am listing out some of the key observations/questions for the forum to think and share their views to find out the mitigation.

a) Explosion of hydrogen gas does not leave any traces of charred marks. The product of H2 combustion is just water. But the explosions are very powerful.

b) The JB enclosure need not be air tight, but over a period of time, it can become air tight due to the corrosion, dust accumulation around the mating surface of the cover etc. Hence Ex ‘e’ breather ensures the seamless breathing.

c) Now the question arises, (ppedUK please take a note) how the ignition generated inside a JB. The connections were checked before energization. Even during the preliminary investigation post explosion, the connections were found intact.

d) Inside the JB there is a small bus bar link (which is bare tinned copper, length of about 300 mm) to terminate the incoming and outgoing cables.

e) The Ring is closed and the ring length could be about 20 kMs. Whether high surge voltage might have generated due to the parallel resonance during some switching activity? The surge voltage might have given rise to some kind of electrical discharge which could be a possible ignition source.

Now my task is to find out:-
What kind of mitigation possible to avoid further explosions/damage of JBs.

Your additional inputs would help me to find out a mitigation.

 

[Parchie]

@krisys,
If you intend to keep things sealed and that gases can't get inside JBs, there are a lot of products sold by 3M that you can find. One is thru the use of breakout boots to all cables entering JBs! Or you could fill the void inside the boxes with Duxseal or Scotchcast (electrical resin).

 

[ppedUK]

Hydrogen is a gas group IIC gas. You have a IIB enclosure......quite different. Hydrogen requires very low energy to ignite.

The terminations should be Ex'e' certified, so if you have busbars in the enclosure with no "Ex" marking, then they probably shouldn't be there.

 

[FreddyNurk]

ppedUK, I noted that as well, although I expect that the design criteria that specified the gas group would have been in relation to the production on the platforms rather than for generation of hydrogen. I did observe that its possible to get a IIC enclosure for 6.6kV power distribution as well.

This seems to be to be an anomalous condition, apparently via some interaction with the cabling that generates hydrogen.
I would have thought that such conditions would be an indication of issues with the cabling or something similar (partial insulation breakdown in the presence of salty water perhaps?) rather than something that requires a IIC gas group enclosure to mitigate. To me the approach would be to work out why you're getting hydrogen in your enclosures, or failing that, at least establish that such conditions are normal for your application, and then look at mitigating the risk of blowing up your enclosures, but I could be on the wrong path. If it is normal for offshore platforms to experience this sort of issue then someone else will have experienced this problem before.

 

[krisys]

FreddyNurk has precisely answered ppedUK’s query.

The JB was meant for the installation at Oil Producing platform. So Hydrogen gas from the facility is not expected to be present.

This is an unusual situation. It is an established fact that the H2 gas is entering from the cable. In one of the installations, we have tried to seal the cable with the resin. But still H2 gas is found accumulating. Suspected to be penetrating through the space around the conductor strands. Seems unbelievable, but it is the fact.

ppedUK, please note that for the present condition, even group IIC enclosure will not suffice. The JB itself is becoming the source of H2 gas. The H2 gas is now present inside the JB continuously! So the inside space of the JB shall be considered as classified area Zone-0. Further, in Zone-0, no electrical equipments are permitted. But we have a live bare copper bus bar inside the JB!

Our case is not fitting to any of the international standards. Hence the concern and the way forward is required to mitigate the situation.

 

[FreddyNurk]

Well (sorry...), if the source of the hydrogen really is from the cable, then the real solution is to deal with the cable, and likely replace it. Electrical equipment isn't, as you noted, designed to function correctly with hydrogen gas building up inside it. Anything else is just compounding a problem that shouldn't be there, including the consideration that its a safety issue if the enclosure lets go whilst personnel are onsite.

There is also the consideration that whatever is generating hydrogen is probably also doing further damage elsewhere and you'll probably have to find it at some point.


EDMS Australia

 

[krisys]

The facility might have invested few tens (if not hundreds) of million dollars for the cable procurement and installation of these submarine cables. These cable are procured from one of the best know manufacturer. Replacing the submarine cable installation of totaling about 75 kilometres at this stage is not a viable solution.

That does not mean that one can live with the prevailing H2 gas accumulation problem. So it is expected to propose a mitigation to reduce/eliminate the risk, keeping the cost implications in mind.

 

[FreddyNurk]

The only other thing I could think of is to ventilate the enclosure such that the build up of hydrogen never reaches a level where it's a problem. Of course, that in itself brings with it other issues, including dust, ingress of salt laden air that would probably accumulate over time and so on, as well as the compliance issues regarding the reason for the original selection of Ex E equipment.

EDMS Australia

 

[krisys]

FreddyNurk,
You are contributing a lot on the subject. Thanks for that.

As you rightly said, ventilation brings its own set of problems.

I have an idea. Why not do some filling inside the box. This would reduce the void space inside the JB. So there may not be a build up of H2.

But please share some thoughts on how to implement this idea. In terms of connection inspection, maintainability (say once in a year). It should be possible to remove/dismantle the filled material easily. Material shall be light weight, non-hygroscopic. It should be possible to re-install the same filling back.

 

[LionelHutz]

Use a purge system?

 

[ppedUK]

Some thoughts / further questions....

Any modification to the existing certified JB (filling or purging or whatever else) invalidates the certification.

Proprietary purging systems monitor air flow, and in a Zone 1 area, you normally have to cut the power on loss of air flow and not re-energise until a certain number of air changes have been proven. Not sure if you can do that on your 6.6kV system.

Evolution of Hydrogen gas from the cable must imply some form of decomposition of insulation etc., therefore you may have to accept inevitable future failure of the cable. Are these PILC cables?

Could you install cast resin joints to the sections of cable as they enter the platform and then have a short section of XLPE insulated cable from the Cast joints to the JBs.

Daft question.....why are the JBs there in the first place? Obviously they saved the day in your installation, as the Hydrogen gas would have ended up in the RMU cable boxes, but is that the reason for them?

 

[krisys]

This submarine cable is a composite cable consisting of power conductors as well as Fiber Optic (FO) section. The 96 fibers are split equally between electrical and Controls & Instrumentation application. So the FO portion is separated out in the JB and then divided equally to electrical and Controls & Instrumentation.

These are the newly installed latest XLPE insulated wet type cables. But without any lead sheathing.

Other than this, for the electrical isolation, testing and safety reasons and disconnection of submarine cable it becomes easy to do this in a JB rather than opening the RMU. This is the reason why these JBs were introduced. Therefore this is for the operational reasons and as an industry best practice.

Anecdotally, these JBs are called as “SPLITTER BOXES”, for the functional reason that the splitting of power cores and fibers are happening here.

Conventional purging is not possible in this case, because these are unmanned mini oil platforms. Not having many utilities. So high flow breathers which needs little day today monitoring is what we are planning to install now. Originally one normal breather is provided in the JB. But it is found clogged due to the corrosion. Now three (3) nos. of high flow breathers will replace the originally installed breather.

Here is a primer:

There are two categories of submarine cables; namely; Dry type and wet type.
Dry type are the one, the outer sheath will protect the cable mechanically as well as prevent any water penetration inside the cable. Thus keeping the cable inside completely dry.

Wet type are the one, the outer sheath will protect the cable mechanically but allow the water inside the cable. The cable is allowed to be wet upto the insulation outer area. Many of you may not be aware of this fact. I am not surprised, because I my self had this awareness during this investigation.

 

[FreddyNurk]

I admit I was unsurprised to learn that there are wet and dry types of cables, but during a judicious google search for your issues I did happen to locate a couple of articles that indicated that aluminium shouldn't be used in construction of undersea fibre optic cables, as the aluminium reacts with seawater and the resultant small amounts of hydrogen adversely affect the optic fibre's integrity. The articles were only related to fibre optic, rather than a composite cable such as you have.

I don't suppose you're also experiencing communications issues are you?


EDMS Australia