February 2018 SRU Troubleshooting Webinar Questions & Answers

 

Question 1:  What is the value in having a front end AG analyzer?

Answer:  The front end Acid Gas analyzer typically works in a feed forward control with the main air flow rate based on the reactants in the feed stream (can measure H2S, CO2, H2O, HC’s, NH3, BTEX).  Therefore it will improve the operation of the Reaction Furnace and help minimize swings from swinging feed stream compositions.  Further, it is very beneficial to be able to trend the compositional data of your feed stream reactants and contaminants when attempting to troubleshoot SRU and Amine unit issues.  SRE finds that the common issue with the front end analyzer is that it is not measuring the compounds correctly.  Here, SRE can verify the correct measurements of feed stream reactants with a side by side comparison with the gas chromatograph results.

 

Question 2:  Can SRE help with Feed Forward Control Tuning?

Answer:  Yes, SRE can provide a full compositional analysis of the feed stream for comparison with the analyzer.  We can then simulate the RF and sulfur plant at varying feed stream flow rates/compositions if possible, and determine if the feed forward control is providing adequate air flow rates

 

Question 3:  What is the composition of Sulcrete?

Answer:  Sulcrete can be various carbonaceous compounds combined with sulfur, whether it be from dust, soot, or catalyst dust.  

 

Question 4:  What is the maximum O2 content in the air stream for an Oxygen Enrichment facility?

Answer:  Typically 24% O2 but we have seen as high as 28%.  Equipment bottlenecks are the main limiting factor for oxygen enrichment.  SRE's Capacity Evaluation service can determine those bottlenecks for you.

 

Question 5:  Why does over-circulation of amine lead to higher hydrocarbon contents in the AG?

Answer:  Amines have specific mechanisms for hydrocarbon pick-up such that much more will be picked up if the circulation rates are too high.  Further, if the amine temperature is too low then hydrocarbons will condense out of the gas stream.  Usually you want 8 to 10 deg C warmer solvent than the gas stream.  

 

Question 6:  What would be the benefit in a continuous purge on the reflux drum?

Answer:  Some plants will have a low continuous purge of their reflux water to attempt to continuously remove the hydrocarbons.  This can also help with removing more ammonia, methanol, and chlorides from the reflux water before they absorb into the Acid Gas much.  An extreme case in a refinery would be to send the reflux water directly to the sour water unit, instead of letting it re-circulate back into the regenerator.

 

Question 7:  What is the minimum residence time for sufficient NH3(ammonia) destruction in the RF?

Answer: It will depend on a number of factors like feed stream preheating, NH3 concentration, RF temp, # of RF zones.  But a typical standard is 1 second residence time in a 1-zone RF.

 

Question 8:  What are typical catalysts in first and second converters?  Are deactivation mechanisms are similar for both titania and alumnia catalsyts?

Answer:  Typically there should be Titania in the first converter for the best hydrolysis of COS and CS2, while promoting the Claus reaction at lower temperatures.  The best setup is to have a small sacrificial layer of Alumina on top.  All downstream converters should have full Alumina beds. Converters in tail gas units will have different specialized catalyst depending on the TGTU technology in place.  Deactivation mechanisms are similar for both Ti & Al catalyst, but not exactly the same.  In general, Titania catalyst is more sensitive to poisons and temperature excursions.  The best way to tell if your catalyst is deactivated is via detailed gas analysis of the inlet and outlet streams.

 

Question 9:  What is the catalyst deactivation mechanism Sulfation, and can it be reversible?

Answer:  Sulfation is the term used for the oxidation reaction of residual sulfur on a catalyst.  This reaction can only take place when there is excess oxygen, from a burner, carrying over into a catalyst bed. The sulfation mechanism can be reversible if it is dealt with early on.  Sulfation reversal involves high H2S and higher than normal operating temperatures.  Some plants do it on a routine PM interval.  This rejuvenation technique known as a Sulfur Wash is used to reverse the deactivation process caused by sulfation.  The first step is a 24-hour heat soak to remove the elemental sulfur from the catalyst bed. The plant load should be reduced considerably, if possible, to minimize excessive emissions.  A ‘reducing atmosphere’ should then be established by cutting back on the air to the Reaction Furnace, this will create excess H2S in the tail gas and reverse sulfation.  This oxygen-deficient condition should be maintained for another 24 to 36 hours.  The plant can then be slowly returned to normal operating conditions.

 

Question 10:  Can you explain the catalyst deactivation mechanism called Sintering?

Answer:  Sintering is a non-reversible deactivation mechanism where the catalyst beads fuse together and become inactive.  This is caused by drastically overheating the catalyst bed, typically during a shutdown or start-up. 

Identifying Symptoms

  1. Temperature rise across the bed lessens over time.  Can be abrupt if overheating is severe.
  2. Catalyst activity/Conversion rates lessen over time.  Can be abrupt if overheating is severe.
  3. Channelling may be observed in the thermocouples.
  4. Hydrolysis rates will also decrease for the First Converter.

Note:     Titania catalyst is more sensitive to overheating than Alumina catalyst. 

Causes

  1. Converter is operated at high heat (above 600°C) for a significant amount of time.
  2. Repeated instances of high heat, even for short durations, can result in sintering.

Treatment and Prevention

Sintering is a non-reversible deactivation mechanism and can only be prevented by maintaining steady operation and following recommended shutdown and start-up procedures.  Converter temperature profiles should be closely monitored during these procedures, and reheater operation should be optimized and reviewed regularly.

 

Question 11:  Is there a way to identify the aging of the catalyst just by analyzing catalyst samples at different levels in the reactor? 

Answer:  Catalyst samples can be sent out for lab analysis, or SRE can assess the performance of the entire catalyst bed.  Here, it is important to note the difference between the two measurement techniques.  The former will tell you how that portion of catalyst is performing, whereas the latter will tell you how the whole converter is performing (all of the catalyst as a whole).  When dealing with losses to the overall recovery efficiency, the latter is preferred.

 

Question 12:  What are the risks of hydro-thermal deactivation and how severe could it be?  Would adding cooling steam put the unit at risk for catalyst deactivation? 

Answer:  Hydrothermal aging occurs when the catalyst is exposed to significant quantities of condensed steam (i.e. water).  During our shutdown procedures we require steam to be added to the main burner, and the burning of fuel gas creates H2O as well.  Further, during normal operation, the process gas going through the SRU is 30% H2O.  So, the addition of steam at the front end for cooling is not of concern, unless there is a risk of the steam condensing onto the catalyst.

 

Question 13:  How low of an H2S concentration can we achieve in liquid sulfur?  Are there regulatory requirements for this before transport?  What impact could glycol have in liquid sulfur?

Answer: A typical specification for dissolved H2S in liquid sulfur before prilling is 10ppm .  Glycol will change the color and be a problem for achieving QC specifications.  SRE can verify the quality of your liquid sulfur onsite.

 

Question 14:  How can we validate that the sulfur pit agitators and pump nozzles are still functioning well? 

Answer:  SRE validates the operation of a sulfur pit by it’s degassing capabilities.  If the pit was capable of producing on-spec liquid sulfur (less than 10 ppm H2S), then any changes to that level would be a cause for concern about the agitators and the pump nozzles.   Visual inspections of the agitators and pump nozzles can be performed to confirm their potential capabilities.

 

Question 15:  For liquid sulfur degassing, would you recommend any chemical addition like Morpholine injection?

Answer:  There are three factors to sulfur degassing: (1) agitation, (2) sweep air, (3) residence time.  If the system is properly designed, then these factors alone should allow for the liquid sulfur to get to the 10 ppm H2S specification.  Chemical addition is an additional factor to assist with the degassing, but only necessary when the optimized three main factors are still not achieving the specification.  If the degassing pits are under-performing, there could be clues to damaged equipment, corroded steam lines, etc. with which  SRE’s design review service can help out.

 

Question 16:   What are typical sweeping gas types? Is using air dangerous due to explosion and fire hazards?

Answer:  Air (most common), N2 and Claus tail gas are the common sweep gases SRE has seen.  The LEL for H2S is 4%, so ensuring a functioning eductor to the incinerator of the pit vent is important in reducing the potential for a fire or explosion.  Further, ensuring that thermocouples are in good working order is important because they have been found to be the ignition source (the spark).  SRE’s turnaround inspection service can help out with this.

 

Question 17:  Are there H2S or SO2 analyzers on the sulfur pit sweep gas?

Answer: Yes there are often analyzers on the sulfur pit vent gas.  In SCOT units, the sulfur from the pit can account for 1/3 of the total SO2 in the stack.  Therefore it is important to choose a well designed analyzer. 

 

Question 18:  Do you have any experience with Comprimo SuperClaus & Super Condenser?

Answer:  Yes we have a lot of experience with SuperClaus and EuroClaus.  A common problem in SuperClaus units is the actual trace O2 level at the outlet of the oxidation catalyst.  The setpoint is 0.5 percent, but we’ve seen drastically difference numbers, which requires re-tuning of the oxidation air.  This is a great service check for our clients.

 

Question 19:  How can methanol content be measured in a gas stream?

Answer:  SRE can measure methanol contents in any gas stream with our specialized sampling technique and proprietary gas chromatograph analysis.

 

Question 20:  Is your equipment good for all hazardous classifications, such as Class 1, Div. II?   Have you done any baseline analyses on SRUs? 

Answer: Yes and yes.  A typical SRE Performance Evaluation would include initial baseline testing, followed by unit optimization and subsequent testing.