The problem is gas passes through a horizontal knockout then passes through a gas flow meter. Some of the gas condensates and liquid gets into the compressor. I am planning to place a condensate trap to minimize the pressure drop. The operator plans to replace the gas flow meter. Right now is horizontally installed in line. He plans to move it on the vertical pipeline where the pipe comes out of the knockout. I don't think that will solve the issue. Any thoughts? I will appreciate any input on this matter.
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Liquid into compressors
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Gas is hydrocarbon. I don't know the type of compressor . I have asked for compressor size and data. I saw the compressor pics. Small size.
The suction is low in pressure just to prevent vacuum. With low suction pressure the compression ratio increases and the average temperature of gas and cylinder go up.r
The valve and packings have temperature limits.
The suction is low in pressure just to prevent vacuum. With low suction pressure the compression ratio increases and the average temperature of gas and cylinder go up.r
The valve and packings have temperature limits.
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jas2000s,
in order for people to help you, the questions posed to you by zdas04 and SeanB need to be answered.
are you sure "some gas" condenses? what is the gas that condenses or has the liquid been determined? what are the process pressure and temperature upstream & downstream of the condensate? any gas analysis information upstream and downstream is helpful. a PID or schematic is helpful.
applying heat trace may/may not be the best solution to the problem.
fyi, to "recirculate back to knock out vessel" implies that the pressure is lowest in "knock out vessel" or other means are available to get the condensate into the vessel.
good luck!
-pmover
in order for people to help you, the questions posed to you by zdas04 and SeanB need to be answered.
are you sure "some gas" condenses? what is the gas that condenses or has the liquid been determined? what are the process pressure and temperature upstream & downstream of the condensate? any gas analysis information upstream and downstream is helpful. a PID or schematic is helpful.
applying heat trace may/may not be the best solution to the problem.
fyi, to "recirculate back to knock out vessel" implies that the pressure is lowest in "knock out vessel" or other means are available to get the condensate into the vessel.
good luck!
-pmover
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I don't have gas analysis. Wet gas from well enters glycol contactor. Gas contains hydrocarbon. Rich glycol from bottom of the contactor enters to a boiler for regeneration.
Rich glycol contains water, and entrained hydrocarbon. The boiler operates at 315F.
vapor from boiler enters to a horizontal knockout vessel which operates at
atmospheric pressure. The vapor outlet is the suction line to the compressor.
Triethylene glycol boiling point is 545F.
Condensate recirculated back to the knock out vessel by gravity.
This is all I know at this point.
Rich glycol contains water, and entrained hydrocarbon. The boiler operates at 315F.
vapor from boiler enters to a horizontal knockout vessel which operates at
atmospheric pressure. The vapor outlet is the suction line to the compressor.
Triethylene glycol boiling point is 545F.
Condensate recirculated back to the knock out vessel by gravity.
This is all I know at this point.
Montemayor
Chemical
After reading the ten prior posts, I believe I can identify what is going on in this application.
This is a TEG dehydration unit drying moist natural gas (or a light hydrocarbon with methane). The rich TEG (glycol that has absorbed the water moisture) exits the sump of the contactor tower and is sent to the TEG regeneration section of the dehydration unit. The rich TEG enters a TEG Stripper tower that sits on a TEG reboiler that generates the stripping vapors that vaporize the water in the falling TEG and allows the water vapor generated there to exit the top of the Stripper (together with stripping natural gas) and on to a recovery unit or to an incinerator where the stripped light hydrocarbon gas is either recovered or burnt. The light hydrocarbon gas is usually natural gas that is fed into the reboiler section to assist in removing the absorbed water moisture from the rich TEG and convert it into lean TEG that is re-circulated back to the TEG Contactor tower.
What Jas2000s is trying to describe is that the water vapor + stripping gas mixture exiting the top of the Stripper is being compressed (recovered) by a compressor and sent elsewhere for storage or another type of recovery. In compressing the gas (which should be a relatively small flow rate), some liquid droplets of TEG or water moisture may be entrained over the top of the Stripper tower and towards the horizontal inlet separator that is being described. The compressor’s discharge is probably cooled and it here that water condensation obviously takes place. Therefore, there is a lot of confusion being created by describing condensation but not specifying where and what.
I suspect that the excessive condensation being described is after the compressor’s aftercooler – and that is to be expected normally. If the inlet separator is properly designed, I doubt if it is causing any liquid to enter the compressor.
All this confusion can be averted if the OP furnishes a detailed PFD with indicated flow conditions at the required process points.
I hope this helps to clear this up. Bother David and PMover are right on to the need for proper process description – as usual.
Many Thanks Art!
Art & others, a couple of questions . . .
if the gas stream contains heavy hydrocarbons (C6+), the heavier hydrocarbons have a higher attraction for water. Thus potential carryover of water from the TEG unit - yes/no? Not only that, the C6+ hydrocarbons may very well condense when cooled too - yes/no? Limited knowledge on my part, I recall learning/reading something like this before.
jas2000s, i hope you understand that people will help you, but having accurate and essential criteria is needed.
keep up the effort and analysis.
-pmover
Art & others, a couple of questions . . .
if the gas stream contains heavy hydrocarbons (C6+), the heavier hydrocarbons have a higher attraction for water. Thus potential carryover of water from the TEG unit - yes/no? Not only that, the C6+ hydrocarbons may very well condense when cooled too - yes/no? Limited knowledge on my part, I recall learning/reading something like this before.
jas2000s, i hope you understand that people will help you, but having accurate and essential criteria is needed.
keep up the effort and analysis.
-pmover
Oil and water don't really mix much. The C4 and heavier molecules have a strong attachemnt for glycol, not water. This is the reason that the reboiler overhead has such a disproportionate BTEX content (2% C4+ in the stream can become 90% of the non-water in the reboiler exhaust, the EPA is currently writing regulations to "fix" this). Stuff smaller than C3 doesn't get absorbed by the glycol as much and when it is in the reboiler it is because something hicuped and belched some gas into the rich glycol.
As to condensing, isoPentane has a boiling point of 88F, so there is a chance that it could condense in the process that the OP mentioned. n-Hexane boils at 155F so it is almost certainly going to condense. The thing is, the reboiler overhead is well over 95% water vapor, so compressing it without going through a condenser first is very risky (especially with a PD compressor, a dynamic compressor might be able to deal with it for a while).
When I had a project that made me think about this I proposed a steam jet ejector to boost the reboiler exhaust a couple of ratios in front of a condenser so I would have some pressure in the non-condensibles to start with (if you can't vent them you have to boost them even into a flare). That project didn't fly for a lot of reasons so I never knew if it was really a good idea.
David
As to condensing, isoPentane has a boiling point of 88F, so there is a chance that it could condense in the process that the OP mentioned. n-Hexane boils at 155F so it is almost certainly going to condense. The thing is, the reboiler overhead is well over 95% water vapor, so compressing it without going through a condenser first is very risky (especially with a PD compressor, a dynamic compressor might be able to deal with it for a while).
When I had a project that made me think about this I proposed a steam jet ejector to boost the reboiler exhaust a couple of ratios in front of a condenser so I would have some pressure in the non-condensibles to start with (if you can't vent them you have to boost them even into a flare). That project didn't fly for a lot of reasons so I never knew if it was really a good idea.
David
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