I was of the opinion operating reactor below dew point temp leading to liquid sulphur upset the catalyst and I thought that's the main reason for operating with a dew point margin. Now with this sulphur wash liquid what's the impact on catalyst. Then why do we need to have dew point margin.. could you clarify the doubt
Thank you for your question! You are correct that liquid sulphur does deactivate the catalyst by collecting in and filling the catalyst pores. However, please note the following important factors. First, the deactivation is 100% reversible when the catalyst bed is raised back above the dewpoint; all of the liquid sulphur is vapourized and removed, with no residual deactivation. Second, when you do drop below the dewpoint, it will usually take a day or more for enough liquid sulphur to collect in the catalyst pores to start affecting efficiency, and another day or more before the catalyst pores are “full” of liquid sulphur and the catalyst is fully (temporarily) deactivated. So the usual procedure for a sulphur wash is to drop below the dewpoint long enough for the wash to be effective, but short enough that complete deactivation doesn’t occur. Then the catalyst is raised back above the dewpoint, and all liquid sulphur is vapourized and all deactivation reversed. If you continuously operate below the dewpoint, then the catalyst bed will be fully deactivated after a few days (and you will correspondingly have lower overall sulphur recovery efficiencies for the plant) and will stay deactivated until you heat it back above the dewpoint. This is why normal operation involves operating the catalyst bed at least 8 to 15C (15-25F) above the dewpoint. Please let us know If you have further questions!
pressure drop is building up due to lack of heating in the first run down line, when there is continuous flow, the run down tends to block, and the increase in pressure drop is there, if the run down line is isolated once/twice in a shift, the stuff in the seal leg gets properly heated and flows out easily after opening the run down block valve, confirming the decrease in pressure drop. Is there any suitable way to resize/modify the seal leg with considerable heat transfer even while operating at minimum load, the seal leg is 7meters underground and takes a toll on maintenance. The steam traps drains are also kept open all the time to drain condensate
Plugging of rundown lines and seal legs from frozen sulphur should not be occurring under any flowing conditions - low, normal, or high flows. If these areas are freezing, then this is not a process problem but instead is definitely a heating problem. Sulphur plant heating is a long discussion, but here are a few items to consider. - Jacketing should be used - NO normal steam tracing. - Steam heat medium should be minimum 3.5bar (50psi) and maximum 5.0bar (80psi). If steam traps are left open, you need to make sure that this doesn’t decrease the steam pressure in the jacketing below 3.5bar. - There should be NO unheated areas. Common unheated cold spots include flanges and direction changes. - Jacketing should be regularly tested to ensure it is working (i.e. steam traps are functioning). Simple way to do this is to scratch solid sulphur onto the jacketing surface - if it will melt the external sulphur scratch, then it will keep the internal sulphur molten as well. - Insulation should be included outside the jacketing. - Bolt-on jacketing bands, like ControTrace®, are available in most countries and may offer cost and maintenance advantages over traditional jacketing. - Above ground “trap” devices, like SulTrap™ or SxSeal® are also available in most countries, and also offer maintenance advantages over traditional below ground seal legs. Please reach out to us on our website for further assistance.
There are no additives available to de-choke the rundown lines. If the choking is due to solid sulphur, which melts are 119C/246F, then proper heating will remove the solids. If the choking is due to other contaminants which won’t melt at these temperatures, then mechanical removal (“rodding” or drilling of the lines) is used. This mechanical cleaning can be done on line as long as suitable safety procedures are used to avoid exposure to process gas or liquid, or can be done with the plant offline. One other de-choking mechanism used at some plants is to blow through the rundown line and / or seal leg using low pressure (typically 3.5bar / 50psi) steam or nitrogen. This might be able to blow the contaminants clear, but it will also blow sulphur through the line and maybe release process gas, so again suitable safety measures should be used. If you require further assistance, please reach out to us on our website!
Hello! I want to perform this procedure for first reactor in a Claus Unit with the Gas feed coming from waste heat boiler. How can i get at the dew point temperature in this case?
I am suspecting soot formation in my plant as my RGG burner gets choked frequently, perhaps soot is coming all the way down to tail gas , and there is heavy choke in the quench filter whenever the tail gas is diverted to TGTU , it is already running off ratio because the main air valve performance is poor on low throughput. Any suggestions for the butterfly valve to operate efficiently for turndown case, as the valve doesn't control air flow within the lower range, it is often put into manual, and due to feed constantly changing with respect to flow and concentration, it results in off ratio. The trim air valve is compensating the air demand, instead of trimming and the process is unsteady and cyclic. But my doubt is if there is soot production, it has not impacted much on the back pressure of the reaction furnace air PT. Could it possible be because of the low throughput. We are running on High CO2 case, 62% and H2S 32% and the reaction furnace temperature has gone low to 800 'C
To avoid soot, we add steam, how i can obtimize the steam to fuel ratio? TGT line heater always on sub stochiometry is it enough to maintain steam to fuel ratio and watch delta p at the TGT reactor bed? Any other parameter i can watch to confirm my ratio is OK and I don't have soot formation? TGT reactor soot formation is irreversible because no sulfur wash possible?
Hello! The standard steam:fuel ratio to minimize the risk of soot formation in any substoichiometric burner is 1kg of steam / 1kg of fuel gas. We are not aware of any evidence that higher ratios will provide better soot suppression, so most plants simply set this 1:1 ratio and do not experiment with any other ratios. Steam addition will help minimize the risk of soot formation at reasonable substoichiometric operations of 80-99% of stoichiometry, however, at lower stoichiometries than this (i.e. due to poor metering, poor burner mixing, etc.) there will be an elevated risk of soot formation even with steam addition. Delta P monitoring is the most common way to monitor for soot formation, however you can also do simple tests on the process gas to directly look for soot formation. This involves opening the sample valve downstream of the TGT line heater (but before the TGT reactor) and checking for evidence of soot. You can either flow this gas through a white filter material for a few minutes (we use a clear tube filled with white fiberglass wool, but others have used filter paper, Kleenex, white cotton, etc.) or bubble the gas into a clear bottle with clean water in it. In either case, if you are making soot in the line heater then it will show up as small black particulate on the filter or in the water, and you can adjust the line heater ratio to see if the soot formation can be reduced or eliminated. Always blow the sample point clear for a brief period before conducting the soot test - you don’t want contaminants present in the sample valve to contaminate the test for soot in the process gas. A second way to confirm if the stoichiometry is low enough to be resulting in soot formation is to test for the H2 and CO contents of the process gas stream into and out of the TGT line heater. Proper stoichiometry (80-99%) will result in a specific formation of H2 and CO across the line heater (which can be calculated with a good sulphur plant simulator), and actual formation rates in excess of these values would indicate that the stoichiometry is lower than optimal and that the corresponding risk of soot formation is elevated. This type of H2 and CO testing, however, is something that normally requires outside testing companies (Sulphur Experts provides this service) and most refinery labs are not able to do this type of testing themselves. Soot deposition on a TGT reactor is considered to be irreversible - a “sulphur wash” on this reactor is not possible. A few plants have had some success with trying to “burn” the soot away on line (either accidentally or on purpose) using excess oxygen from the line heater, however this procedure involves a high risk of further damaging the catalyst and / or melting the reactor itself and is not generally recommended. Prevention of soot formation is the priority, and replacement of catalyst is the standard procedure if the pressure drop due to soot deposition gets too high. Please let us know if you have further questions!
How does steam help is reducing soot. In equipment like fired heater steam helps in blanketting. How does steam support here. Could you clarify the same.also I read during start up with reduced air, steam is suggested for soot minimisation but actual principle is unclear to me. Could you explain
Thank you very much for another great SRU video training!
Love the way u explain
Can you do a separate video about dew point and its significance in SRU plants
I was of the opinion operating reactor below dew point temp leading to liquid sulphur upset the catalyst and I thought that's the main reason for operating with a dew point margin. Now with this sulphur wash liquid what's the impact on catalyst. Then why do we need to have dew point margin.. could you clarify the doubt
Thank you for your question! You are correct that liquid sulphur does deactivate the catalyst by collecting in and filling the catalyst pores. However, please note the following important factors. First, the deactivation is 100% reversible when the catalyst bed is raised back above the dewpoint; all of the liquid sulphur is vapourized and removed, with no residual deactivation. Second, when you do drop below the dewpoint, it will usually take a day or more for enough liquid sulphur to collect in the catalyst pores to start affecting efficiency, and another day or more before the catalyst pores are “full” of liquid sulphur and the catalyst is fully (temporarily) deactivated.
So the usual procedure for a sulphur wash is to drop below the dewpoint long enough for the wash to be effective, but short enough that complete deactivation doesn’t occur. Then the catalyst is raised back above the dewpoint, and all liquid sulphur is vapourized and all deactivation reversed.
If you continuously operate below the dewpoint, then the catalyst bed will be fully deactivated after a few days (and you will correspondingly have lower overall sulphur recovery efficiencies for the plant) and will stay deactivated until you heat it back above the dewpoint. This is why normal operation involves operating the catalyst bed at least 8 to 15C (15-25F) above the dewpoint.
Please let us know If you have further questions!
Thank you. Explanation is very clear. Can you add a video on SRU start up and shutdown key points.
@@ManikandanTamilan We will cover this topic in 2021!
In our SRU unit, most of the time condenser is getting plug with black coloured stickey material.Pleae help us by saying how to avoid it?
pressure drop is building up due to lack of heating in the first run down line, when there is continuous flow, the run down tends to block, and the increase in pressure drop is there, if the run down line is isolated once/twice in a shift, the stuff in the seal leg gets properly heated and flows out easily after opening the run down block valve, confirming the decrease in pressure drop. Is there any suitable way to resize/modify the seal leg with considerable heat transfer even while operating at minimum load, the seal leg is 7meters underground and takes a toll on maintenance. The steam traps drains are also kept open all the time to drain condensate
Plugging of rundown lines and seal legs from frozen sulphur should not be occurring under any flowing conditions - low, normal, or high flows. If these areas are freezing, then this is not a process problem but instead is definitely a heating problem. Sulphur plant heating is a long discussion, but here are a few items to consider.
- Jacketing should be used - NO normal steam tracing.
- Steam heat medium should be minimum 3.5bar (50psi) and maximum 5.0bar (80psi). If steam traps are left open, you need to make sure that this doesn’t decrease the steam pressure in the jacketing below 3.5bar.
- There should be NO unheated areas. Common unheated cold spots include flanges and direction changes.
- Jacketing should be regularly tested to ensure it is working (i.e. steam traps are functioning). Simple way to do this is to scratch solid sulphur onto the jacketing surface - if it will melt the external sulphur scratch, then it will keep the internal sulphur molten as well.
- Insulation should be included outside the jacketing.
- Bolt-on jacketing bands, like ControTrace®, are available in most countries and may offer cost and maintenance advantages over traditional jacketing.
- Above ground “trap” devices, like SulTrap™ or SxSeal® are also available in most countries, and also offer maintenance advantages over traditional below ground seal legs.
Please reach out to us on our website for further assistance.
is there some kind of additives that helps to de-choke the run down lines 😀
There are no additives available to de-choke the rundown lines. If the choking is due to solid sulphur, which melts are 119C/246F, then proper heating will remove the solids. If the choking is due to other contaminants which won’t melt at these temperatures, then mechanical removal (“rodding” or drilling of the lines) is used. This mechanical cleaning can be done on line as long as suitable safety procedures are used to avoid exposure to process gas or liquid, or can be done with the plant offline. One other de-choking mechanism used at some plants is to blow through the rundown line and / or seal leg using low pressure (typically 3.5bar / 50psi) steam or nitrogen. This might be able to blow the contaminants clear, but it will also blow sulphur through the line and maybe release process gas, so again suitable safety measures should be used.
If you require further assistance, please reach out to us on our website!
Hello! I want to perform this procedure for first reactor in a Claus Unit with the Gas feed coming from waste heat boiler. How can i get at the dew point temperature in this case?
I am suspecting soot formation in my plant as my RGG burner gets choked frequently, perhaps soot is coming all the way down to tail gas , and there is heavy choke in the quench filter whenever the tail gas is diverted to TGTU , it is already running off ratio because the main air valve performance is poor on low throughput. Any suggestions for the butterfly valve to operate efficiently for turndown case, as the valve doesn't control air flow within the lower range, it is often put into manual, and due to feed constantly changing with respect to flow and concentration, it results in off ratio. The trim air valve is compensating the air demand, instead of trimming and the process is unsteady and cyclic. But my doubt is if there is soot production, it has not impacted much on the back pressure of the reaction furnace air PT. Could it possible be because of the low throughput. We are running on High CO2 case, 62% and H2S 32% and the reaction furnace temperature has gone low to 800 'C
To avoid soot, we add steam, how i can obtimize the steam to fuel ratio? TGT line heater always on sub stochiometry is it enough to maintain steam to fuel ratio and watch delta p at the TGT reactor bed? Any other parameter i can watch to confirm my ratio is OK and I don't have soot formation? TGT reactor soot formation is irreversible because no sulfur wash possible?
Hello!
The standard steam:fuel ratio to minimize the risk of soot formation in any substoichiometric burner is 1kg of steam / 1kg of fuel gas. We are not aware of any evidence that higher ratios will provide better soot suppression, so most plants simply set this 1:1 ratio and do not experiment with any other ratios. Steam addition will help minimize the risk of soot formation at reasonable substoichiometric operations of 80-99% of stoichiometry, however, at lower stoichiometries than this (i.e. due to poor metering, poor burner mixing, etc.) there will be an elevated risk of soot formation even with steam addition.
Delta P monitoring is the most common way to monitor for soot formation, however you can also do simple tests on the process gas to directly look for soot formation. This involves opening the sample valve downstream of the TGT line heater (but before the TGT reactor) and checking for evidence of soot. You can either flow this gas through a white filter material for a few minutes (we use a clear tube filled with white fiberglass wool, but others have used filter paper, Kleenex, white cotton, etc.) or bubble the gas into a clear bottle with clean water in it. In either case, if you are making soot in the line heater then it will show up as small black particulate on the filter or in the water, and you can adjust the line heater ratio to see if the soot formation can be reduced or eliminated. Always blow the sample point clear for a brief period before conducting the soot test - you don’t want contaminants present in the sample valve to contaminate the test for soot in the process gas.
A second way to confirm if the stoichiometry is low enough to be resulting in soot formation is to test for the H2 and CO contents of the process gas stream into and out of the TGT line heater. Proper stoichiometry (80-99%) will result in a specific formation of H2 and CO across the line heater (which can be calculated with a good sulphur plant simulator), and actual formation rates in excess of these values would indicate that the stoichiometry is lower than optimal and that the corresponding risk of soot formation is elevated. This type of H2 and CO testing, however, is something that normally requires outside testing companies (Sulphur Experts provides this service) and most refinery labs are not able to do this type of testing themselves.
Soot deposition on a TGT reactor is considered to be irreversible - a “sulphur wash” on this reactor is not possible. A few plants have had some success with trying to “burn” the soot away on line (either accidentally or on purpose) using excess oxygen from the line heater, however this procedure involves a high risk of further damaging the catalyst and / or melting the reactor itself and is not generally recommended. Prevention of soot formation is the priority, and replacement of catalyst is the standard procedure if the pressure drop due to soot deposition gets too high.
Please let us know if you have further questions!
How does steam help is reducing soot. In equipment like fired heater steam helps in blanketting. How does steam support here. Could you clarify the same.also I read during start up with reduced air, steam is suggested for soot minimisation but actual principle is unclear to me. Could you explain
@@ManikandanTamilan Gas-Water shift reaction sir: H2O+CO -> H2 + CO2.