request for assistance with overhead condenser on process tank 1

[leakyseal]

Hi folks,

I've been asked to assist with some design which is a bit beyond my experience and I keep getting trapped in some circular thinking -- I'm hoping someone can help me sound this out a bit.

An existing process tank contains a hydrocarbon below its boiling temperature. The tank is currently protected with a conservation vent and a rupture disk. In the interest of minimizing the organic vapours that exit the conservation vent, we have been asked to install a condenser at the top of the tank to capture the vapours and return them to the tank. We've tentatively selected a fairly vanilla shell and tube with cooling tower water on the shell. Sizing assumes that the solvent is at its boiling point to provide a conservative vapourization (and hence, condensation) requirement, but in practice the solvent will not boil and the vap gen rate will be lower than the design point.

The client asked us to size the exchanger "in isolation", but we are now being asked to review the proposed installation. Here's where my befuddlement starts. For some reason they want the vapor subcooled, and have piped it up to have the vapor enter the top of the vertically mounted exchanger, and drip condensate back into the vessel. First problem is that there's nothing preventing the vapour from entering the "downstream" side of the exchanger. I assume this may be addressable with some kind of thermostatic valve to block the upward flow of vapour but allow the downstream flow of condensate (similar to a steam trap).

My concern is ensuring that the vapour preferentially goes into the condenser rather than through the conservation vent. The cons vent is set to crack at 10" wc. It seems to me that if the pressure drop through the condenser is less than this (and the condensation rate exceeds the net vapour gen rate) then we'll be okay. If this assumption is reasonable, I want to make sure I'm thinking about the pressure drop appropriately.

I've determined the pressure drop per unit length of pipe under the flowing vapour condition, and (inlet pipe loss + hx loss) is less than 10" wc. All good. BUT: how do I properly account for the elevation changes? Pipe inlet and outlet at the vessel head are both at the same elevation. Vapour is heavier than air, so the inlet leg elevation loss is calc'd via (rho-vap)gh?. Condensate volume will be quite small relative to vapour volume and is falling under gravity through an unflooded pipe (notwithstanding the condensate trap...hey, it just occured to me, can we just P-trap the piping?)...so how the heck do I calculate the head "gain" on the discharge side?

I'm not as boneheaded in real life as this may make me appear, honest. Any feedback (assuming any meaning can be teased out of this) would be greatly appreciated. Thanks!

 

[mbeychok]

leakyseal:

Perhaps I have not understood your problem. If you want to condense the vapors escaping from a tank of sub-cooled liquid (i.e., a hydrocarbon liquid below its boiling point), then your condenser must be able to cool the escaped vapors to somewhat below the temperature of the liquid temperature in the tank. Are you sure that you can do that with your available cooling water temperature?

You haven't told us what the hydrocarbon liquid is or the temperature and pressure of the tank liquid. That would be helpful.

The more commonly used method of tankage vapor recovery is to use a compressor to compress the vapors and then to condense and, if needed, sub-cool the compressed vapors.

Milton Beychok
(Visit me at www.air-dispersion.com)
.

 

[Compositepro]

It is air or nitrogen that must be vented from the tank to keep it from over or under pressure that would structuraly damage the tank. The pupose of the condenser is to lower the amount hydrocarbon vapor that is carried by the non-condensible air or nitrogen. The vapor pressure of hydrocarbon at the condenser temp. determines the the amount of vapor in the air that is vented. The condenser must cool the flow to the conservation vent.

 

[katmar]

This is not a simple single component condensation problem. The important factor is the vapor pressure of the hydrocarbon in the air/nitrogen that makes up the balance of the vapor space above the liquid. Even if you cool the combined hydrocarbon and air stream there will still be a quantity of hydrocarbon in the exiting air stream determined by the new temperature.

The maximum flow rate of vapor through the exchanger will be most probably be determined by the rate at which the hydrocarbon is pumped into the tank. The "breathing" of the tank due to temperature changes will likely be much less than this.

It is clear that you are an intelligent engineer, but I would recommend getting someone onto the job who has relevant experience, and you can learn from them.

Katmar Software
Engineering & Risk Analysis Software

http://katmarsoftware.com

 

[sshep]

Hello,

A plain vanilla shell and tube exchanger on top of the tank seems unusual, there are direct coupled alternatives for tank vent condensers which seem more common. A simple search can reveal several standard alternative designs and papers on the subject.

Usually these devices need a chiller to get the HC partial pressure down to target removal levels. The chilled water also reduces the exchanger size and weight. The assumption of a pure hydrocarbon vapor condenser (elevated temp, high condensing heat transfer rate) is likely to result in an exchanger which doesn't remove much organic vapor in practice. As requested by our peers, some data would be helpful.

best wishes always,
sshep

 

[leakyseal]

mbeychok: liquid is xylene, temp is 120 degC MAX (vs boiling temp of ~140 degC for mixed xylenes). Tank pressure is atmospheric plus a couple of inches of inert blanketing.

The exchanger as currently sized, with the available cooling tower water at 25 degC, will provide plenty of subcooling provided we can "direct traffic" appropriately with respect to the condensate and vapour flows.

compositepro: yes, you are correct, the purpose of the CV is to outbreathe the slight excess of blanket gas when the tank is filled, and with this newly proposed process for the tank there will be an undesirable amount of organic vapour present in the stream (due either to outbreathing or excess vapour pressure). I had envisioned the condenser in-line to the conservation vent as you describe, but for some reason the client wants to install it elsewhere on the vessel head with dedicated inlet and outlet. One of the facets I am now trying to sort out is the consequences of this.

katmar:I fully agree that under normal circumstances the max outbreathing will occur when the tank is being filled; these rates have been characterized and verified against the CV sizing. The vent line currently is connected to a manifold which runs in turn to either GAC or a thermal oxidizer, I am not sure which. Hence, some residual solvent in the vent stream is okay. I think the client's need is more in terms of minimizing product loss rather than reducing emissions.

To an extent, our problem is that the client started out saying, "we don't want any engineering done, just get us a condenser and we'll install it" and the more we dig into it and ask questions the more complicated the situation becomes. I've been dragged in at this late stage since I've got the most experience in our office with relief systems (API 2000, ASME Sec VIII) but the h/x - cond end of it has me a bit bamboozled. I agree that the way we're going about it may not be the best, but a large amount of it has been client driven and is essentially a fait accompli at this point.

Thank you everyone for your input so far, it's clarified my thinking somewhat. Wouldn't mind some feedback on the issue of pressure drop in a condenser...