15 replies to this topic

[adeliry]

Dear,
I am working on "styrene monomer' plant for 8 years as plant engineer,
to recovery of valuable hydrocarbons from vent gas stream( after reaction section) we use scrubber/stripper columns, and we use "flux oil" ( heavier H.C than three ethyl benzene that produced in Ethyl benzene unit) as scrubbing media.

at srubber we absorb HC fron vent gas stream and resulted media is subjected to steam stripper to recovery of HC from Flux oil and Fux oil return to scrubber.

in last years we need to make up flux oil 1 time per week, but todays we have 3 time per day make up.

I am not shure that steam flow transmitter is shurely working correctly, but i will be thankfull if you said what parameters can cause this problem. also i will be thankfull if you give me a good refrence about steam distillation and steam stripping.
thanks

[Zauberberg]

If I understood your question well, you are experiencing flux oil losses in absorber/stripper system, 3 times higher than design (or acceptable) value?

If this is the case, on-site plant troubleshooting will definitely show you where the problem originates. First, you should determine whether you are losing flux oil in absorber overhead stream, stripper overhead stream, or both. I assume overhead vent gas KO drum and stripper overhead condenser/drum are provided.

You could be losing flux oil in absorber due to excessive vent gas rate, excessive flux oil circulation rate, foaming, tower internals malfunction (or mechanical damage). Similarly, you can experience flux oil losses in the regenerator section caused by the same reasons (excessive stripping medium flow, flux oil circulation rate, foaming/flooding, tray/packing mechanical damage etc.)

If regenerator system is designed with a reflux, malfunctioning of overhad receiver LC could cause refluxing water back into the tower and severe flooding problems.

You haven't provided more data required for thorough troubleshooting, but I believe you have now a starting point for battling against absorber/regenerator system malfunctioning.

Good luck,

[adeliry]

Thanks for your reply

for more details i must be say:

vent gas rate every time is variable and todays are not very high, in the stripper there is not provided any reflux stream and also out going stream dont pass from a exchanger because it is mixed with reactor effluent after air fans, therefor it is hard to inspect flux oil in this stream.
in a patent provided by "UOP" they said that if steam rate that used in stripper will be high it is caused steam condensing in top trays and flooding, i am not shure but it is important also.
if you are interested and also have time i will send you "P&ID" of this section.

[Zauberberg]

Yes, providing P&ID would definitely be a step forward.
Meanwhile, have you tried to implement any operational changes - together with actions recommended by UOP?

Simple performance test could give you a lot of valuable information. Sometimes, these problems can be rather trivial in nature, such are: malfunctioning of absorber/stripper bottom LC, steam flow control, inaccurate temperature indication etc.

Give yourself time and space to monitor unit performance under different operating conditions, and please come again with your comments and copy of P&ID. Maybe we can bring some conclusions together.

Best regards,

[Padmakar Katre]

Dear,
I will suggest you first thing to do is get calibrated your all transmitters like Flow Transmitters,Temp Transm, Level Transm and all. So you could have the confidence mass balance monitoring across the unit. See the probable parts of the unit where you have chance of the solvent loss as Zauberberg commented. I hope that all those streams where chances of the solvent carryover will have the Flow Instruments with the DCS signal and HM backup to recall the data for the last 24hrs or one shift. Get the avergae sampling analysis reports for the inlet and outlet gas and liquid streams and try hand calculations to perform the hand calculations. Compare these calculations with the Flow transmitters place in the lines of the Scrubber or Stripper ovhd flow. Check for any discrebancy.
If you come up the sketch of the unit by showing all the consitions of the inlet and outlet streams it will help us to analyse the issue in a better way.
Waiting for your comments.

[adeliry]

Hi,

unfortunately there is not provided any flow transmitter on overhead streams of towers,
i started to inspecting some ponts, but i thought to upload a PFD of this section untill if you will have a idea during this step, can tell me.

thanks.
http://www.cheresour...e_types/gif.gif

Attached Files

•  PFD.gif   40.92KB   41 downloads

[Zauberberg]

Hi Adeliry,

While you are in search for answers on previously raised questions, I would like to put some more comments from my side:

1. If you are 100% sure you are not losing flux (absorption) oil in the scrubber (which can be checked easily by monitoring oil level build-up in the knockout drum 22-V-312), and if you are sure that the amount of circulating absorption oil is as it should be (a tricky one), then what is remaining is the stripper tower overhead stream - which cannot be checked, if I understood you well.

2. In case you are increasing the amount of circulating oil in the system by opening the valve from EB Unit (oil make-up), the likelihood of tower(s) flooding would be increased. Re-check the flow indicator on regenerated oil flow line. Ensure you are circulating the amount of oil which is within the tower design margins (maximum liquid capacity and turndown). Oil rates above the maximum value would precipitate liquid flood, while operating the tower below turndown capacity results in blowing/entrainment regime - both followed by reduced performance and flux oil losses.

3. Try to play with oil rate (reduce make-up) and stripping steam rates (increase/decrease). Give sufficient time to the system to accept changes, and watch for the effects.

Let us know the results.
Good luck,

[adeliry]

thanks for your ideas,

we checked many items and finaly (think) found problem. we drain the T-303 and there was a lot of water and we thought may be it caused flooding. we drain it 3 time and finaly we cut steam and sirculate fluxoil and make up fresh fluxoil until all waters removed. after this step for 2 days we didn'n need to make up and every hour check to water contaminant, some times there was some water and we drained it. because we were using a saturated steam( p=1.05 bar, t=105 0c), therefore we replaced it with LLS steam ( 2.5 bar and 125 0c), but water accumulation not completely solved, we test the conductivity of water and it is not cooling water( if imagine that exchanger tube fail accured). i am not shure how we can solve the problem completely, todays condition is very better than previous becase i said that we had to make up 3 time per day and now 1 time per 2 day. but!!!

can anyone say what is the effect of steam flow rate in process because in steam stripping or steam distillation pressure is not affected by mole fraction.

[Zauberberg]

Saturated steam must never be used for stripping applications. Why? Because it will condense while upflowing in the tower. Reliable source of dry, superheated steam has to be provided for such applications.

What could have happen in your system are two things at least:

- Stripper tower flooding due to condensation of steam across the trays (and probably losses of flux oil into the overhead stream if condensation was massive)
- Absorber tower malfunctioning and deterioration of performance due to recycling of flux oil + water mixture from stripper bottoms

In steam stripping application, the amount of steam used is of great importance: the higher the partial pressure of steam, the lower the partial pressure of hydrocarbon(s) which is required in order to remove them from bottoms liquid. So there is an optimum steam/flux oil ratio at given concentration of absorbed hydrocarbons. Increasing the steam flow above this value will not give you any improvement in stripper operation, and after some point it can only precipitate further problems if total vapor flow in the stripper exceeds maximum (design) hydraulic capacity.

[Qalander (Chem)]

Superheated steam must never be used for stripping applications. Why? Because it will condense while upflowing in the tower. Reliable source of dry, superheated steam has to be provided for such applications.

What could have happen in your system are two things at least:

- Stripper tower flooding due to condensation of steam across the trays (and probably losses of flux oil into the overhead stream if condensation was massive)
- Absorber tower malfunctioning and deterioration of performance due to recycling of flux oil + water mixture from stripper bottoms

In steam stripping application, the amount of steam used is of great importance: the higher the partial pressure of steam, the lower the partial pressure of hydrocarbon(s) which is required in order to remove them from bottoms liquid. So there is an optimum steam/flux oil ratio at given concentration of absorbed hydrocarbons. Increasing the steam flow above this value will not give you any improvement in stripper operation, and after some point it can only precipitate further problems if total vapor flow in the stripper exceeds maximum (design) hydraulic capacity.

Dear zauberberg,
Probably you meant/implied 'Saturated' superheated steam?
Best regards
Qalander

[Zauberberg]

Thank you very much Qalander, that was my point (I will edit the previous post).
Conclusion: never use saturated steam for stripping applications.

[adeliry]

Dear Zauberberg,

thanks for your reply,

if imagine that total pressure is constant (P=onstant), increasing steam caused to increasing in partial pressure of steam(P1 increasing), therefor partial pressure of hydrocarbones decreases(P2 decrease because P=P1+P2), in this case is it possible that P2 is very very small that cause flux oil itsef vaporise,( normaly in p=233 mmHg and T=225 fluxoil is liquid in fractination section of EB unit).

[Zauberberg]

In general - yes. In particular, steam will stripout the hydrocarbons from flux oil if the oil is close to its saturation (bubble) point. If the oil is subcooled fluid at operating conditions of the system, steam will remove insignificant amounts of flux oil.

For example, if initial boiling point of flux oil at 1bar is, let's say, 100C and you operate the tower at 3bar and flux oil temperature of 80C, steam will not strip hydrocarbons contained in the flux-oil. Notice that I am speaking about the hydrocarbon fractions of which flux oil is made, and not about the volatile hydrocarbons absorbed from the vent gas. In your case, excessive steam flowrate can choke the tower in terms of hydraulic capacity (jet flooding), and it will generate problems especially if steam is saturated (instead of being superheated) - condensation of water inside the tower will definitely cause foaming and, subsequently flooding, when large deterioration of system performance occurs, followed by losses of liquid phase in the overhead stream. In addition, the appearance of water at the bottom of T-303 is an evidence that steam is being condensed inside the regenerator (stripper) tower and, as such, recycled back to the absorber together with flux oil. Otherwise, how to explain the presence of water at the bottom of T-303?

I think your troubleshooting is still not 100% completed, so please revert back with additional findings.
Best regards,

[Qalander (Chem)]

Dear adeliry hello/good morning,

Although much is already explained &explicitly exchanged; but the saturated steam usage could be the real culprit I assume.
Based on operational observation it is customary with saturated steam be at time wet with water droplets that can effect adversely the process of stripping in two ways

Water droplets if enter into lower(than water boiling point) temperature system they do not support the partial pressure phenomenon used to ensure stripping process and may cause excessive liquids down flow to the flooding extent as mentioned by zauberberg

Water droplets if enter much higher(than water boiling point)temperature system than sudden flash-vaporization to a great extent may occur even to the tone of upsetting stripping system internals.
These are cautionary suggestions may be helping to resolve the prevalent issue.
Best Regards
Qalander

[adeliry]

Thanks,

But I said that we replaced saturated like steam with LLS steam( 2.5bar and 126oc), why problem isn't solved, other parameters like input temprature of rich fluxoil to stripper is accurding to PFD (110oc) and every thing is checked, do you have any idea?

also do you know any complete refrence about steam distillation?(like book, ebook,....)

[Qalander (Chem)]

Dear aderily,

Just a few wild thoughts

have you changed the flux oil in near past close to the trouble starting period?

have you changed the supply source or vendor of flux oil?

Did you analyze/match the present in use flux oil composition with the original design/vendor specs?

Arrange a fresh analysis to check for any contaminants/emulsifying impurities making emulsion of flux oil & water and loss of flux oil along with water being drained.

Also carry-out steam analysis for contaminants/particulates may be affecting emulsifying effect
Hope above steps may help to resolve the issue and get rid off. Sorry if something was previously discussed/posted already.for website please google you will find good help directly.
Best regards
Qalander