Q & A > Sulphur Removal and Recovery
Date  Replies
26/04/2021 Q: We are facing lots of solid formation in the quench tower circuit of our TGT Unit. What can be the reason and how are solids/salts formed in this circuit?  
20/02/2021 Q: We have 2-stage Claus with SCOT TGTU. Whenever we have a long shutdown, we keep the Claus section & TGTU section in hot stand-by mode. The Claus Reaction furnace is fuel gas firing and diverted to an incinerator (bypassing the TGTU). The TGTU section has nitrogen circulation in hot mode. The SCOT reactor temperature is maintained at operating temperature (290C).
The problem: we observe that every time the quench pH drops after a few days. What would be the reason?
29/01/2021 Q: This is about a LPG Merox unit in our refinery. Since the content of RSH(mercaptan) in the feedstock has more than doubled, this makes it difficult to regenerate the caustic. The content of mercaptide and disulphide in regenerated caustic has greatly increased. Frequent replacement of caustic and increased air flow and temperature in the oxidizer doesn't solve the problem. How can we solve the problem if we can not change the feedstock?
29/09/2020 Q: What are good practices to hand over sour water feed storage tanks in refineries?
15/08/2020 Q: Why is the reduction furnace in the SRU so called? Although the reaction chemistry indicates that NH3 is oxidized to N2 what is the reason behind the nomenclature "reduction furnace"?  
12/08/2020 Q: We had serious corrosion issues in the amine regeneration column of the TGTU. We also measured significant HSS levels in the amine solution. We are about to replace the quench tower in our TGTU, upstream of the amine absorber. We are considering installing a demister in the overhead of the quench column, to increase the system’s capability to avoid SO2 entrainment in the amine system. We assume that the cons for doing this step are increased pressure drop and risk of sulphur deposits in the demister. Is it a common practice to install a demister in the TGTU quench tower overhead? Does somebody have experience of doing this? Any known issues with this demister?  
28/07/2020 Q: What is the reason for sulphur pit overpressure? A few days ago the sulphur plant’s sulphur pit temperature suddenly reached 190°C+. Its normal temperature is around 140°C. 1)iIs this because of a small fire in the sulpgur pit, or any other reason? 2) Sweep air with moisture or sweep air without moisture - any effect on sulphur pit pressure?

27/06/2020 Q: We have been facing issues in one of our sour water stripping units wherein we observe continuous plugging of the feed control valve to the stripper column with greenish black hard deposits. The temperature of sour water passing through this control valve is in the range 146-152 deg C. Could anyone suggest the testing we should carry out to understand this heavy deposit? Does anyone have experience with hard greenish black deposits in their sour water stripping units? (5)
07/06/2020 Q: in a SRU final condenser demister pad, dislocations occurred two times recently. Due to this the tail gas line to the TGTU filled with sulphur. What may be the reasons and remedies?
Also, in case of carryover of sulphur what ways are there for early removal of sulphur.
26/05/2020 Q: In our regenerative caustic treatment system a disulfide stream is generated. Which is the best destination for this stream in the refinery (FCC, coke drum, hydrotreater, naphtha feed, others)? (4)
25/05/2020 Q: In HPCL Vizag Refinery the SRU plant was commissioned in 2009 with the plant designed by M/s KTI italy. The Thermal Reactor Burner Design was provided by AirOil. It is a Lance in Lance type with manual insertion and retraction . The problem we are facing is with the short life of the AAG Diffuser, frequent plugging of the FG tip, and frequent damage to the FG tip resulting in difficult insertion and retraction. The FG gun is provided with a N2 cooling system to keep the tip clear and for cooling when the train is in AAG mode; it is ensured all the time that N2 is continuously fed to the FG gun. Even after this we are facing the above problems. Can anyone can throw some light on the following:
1) Why is the AAG diffuser life short even though we are operating the train well within design feeds.
2) Why is the FG gun tip i plugged even though N2 flow is continuous and the FG to gun is provided with a strainer to provide good quality FG.
3)Why is the FG gun tip getting damaged resulting in difficult insertion and retraction
4)Are any new advanced burner designs available which can overcome these problems
5)Are there have any best operating procedures / troubleshooting reports to avoid these problem

19/05/2020 Q: I would like to know the configuration of an amine system for refineries having multiple hydroprocessing units with multiple ARU / SRU.

Are common lean amine and common rich amine pipelines connecting all units, or is each hydroprocessing unit independently assigned to an exclusive ARU / SRU unit (with rich amine and lean amine pipelines running between these two units, oor is one hydroprocessing unit i connected to two ARU / SRU units for flexibility in operation?

Kindly share your views stating the pros and cons of each configuration. You may share specific experience from your own refinery on the reliability of units having any one of the above.
15/03/2020 Q: We are operating a Naphtha Hydrotreater with two reactors. The first reactor is for diolefin saturation. We are facing high DP issues in the 2nd reactor. What could be the cause? (2)
01/01/2020 Q: My question is related to an amine absorber used to strip out H2S from fuel gas or recycle gas. We know thatthe optimum temperature difference between gas and amine is to be maintained at 8 to 11 degrees Celsius.

1) Why does absorption decrease when delta T is below 8 & above 11? Please answer for individual case.
2) Moreover, does only delta T matter or do individual temperatures of gas and lean amine also matter for determining absorption efficiency ?
3) If individual temperatures do matter then what should be the optimum range of both?
25/09/2019 Q: Sour water from the SRU quench column is routed to the sour water stripper normally.My doubt is whether this will go to the Phenolic Sour water Stripper or Non-phenolic sour water stripper? Request the professionals of SRU to clarify. Please also explain the reason if it is routed to the Phenolic Sour water stripper unit. (2)
11/06/2019 Q: Iam working in Indian Refining company.Our company is in the process of putting up two SRU (one working and one standby).Two trains of SRU with common TGTU has been planned. Whether common Incinerator+ WHB or dedicated Incinerator+WHB should be preferred is the question. (2)
31/05/2019 Q: What are the treatment methods for removal of butyl mercaptan from LPG stream? (2)
31/05/2019 Q: We are designing an LPG sweetening unit. The sour LPG consists of H2S, methyl mercaptans, ethyl mercaptans, propyl and butyl mercaptans , COS as the sulphur impurities. To remove H2S we are using amine absorption tower using MDEA solvent. Then it is followed by caustic wash for mercaptan removal. We observe that butyl mercaptan is not removed effectively from caustic wash. The caustic wash circulation has to be increased to a very high unreleastic values to achieve 10ppmw sulfur at the downstream of caustic wash. Can you please inform on the various options for butyl mercaptan / H2s levels of sour LPG after amine absorption :
(in ppmw) Sour LPG
Methyl Mercaptan : 0.966
Ethyl Mercaptan : 6.877
Propyl Mercaptan: 12.529
Butyl Mercaptan: 108.822
Hydrogen Sulfide: 15.000
Carbonyl Sulfide :36.316
29/04/2019 Q: Is there any way of knowing by Amine regenerator inlet or outlet temperatures whether there is a hydrocarbon carryover to system ? Is there any way to just predict foaming tendencies in Regenerator with just temperature profiles across it ? (1)
19/01/2019 Q: In our TGTU section of SRU, We have Stripper column which strips out H2S from the amine. The H2S will routed to SRU as feed from the Reflux drum O/H of Stripper Column. In recent days, it has been found that, all of Sudden Stripper Column level is decreasing and the same time The reflux drum get full and get overflow in the Overhead line(O/H). During this time there is a sharp increase in column PDI.
After a while, everything gets Normal after taking some actions (Reboiling steam cutting, reducing amine circulation rate,increasing reflux flow etc..,). This case happens rarely but we couldn't stop it.
What could be the reason for the above case. How to avoid it?
28/12/2018 Q: We are operating a small refinery processing sweet crude (less than 0.4 wt % sulphur). The crude is heated in a heat exchanger network and sent to a preflash column. The overhead from preflash column are condensed as naphtha and sent for stabilization after removing free water in overhead reflux receiver boot followed by coalescer. The naphtha is reboiled in the column and refluxed by a overhead stab in condenser. Vapour from the column are sent as fuel.
Recently when the column was opened up after one year of service the overhead condenser was badly corroded. In fact all the tubes had holes (condenser uses cooling water in the tubes). The strange thing which was noted that elemental sulphur embedded in the corrosion product covering the outside of tubes.
We are wondering where this elemental sulphur was formed? The overhead operating temperature is 100°F.
We are using antifouling agent in our crude but the vendor says that there is no possibility of elemental sulphur from their product.

1. Preflash overhead goes through a prefilter followed by a sand bed coalescer. We have observed no emulsion and water haze after these filters and coalescers. However, we are recycling boot water to overhead condenser in the preflash. There is no water wash in the stabilizer as it is a simpler stripper with no overhead condenser and drum.
2. No outside naphtha is being processed; however, demin water solution is prepared with neutralizer which is injected in preflash overhead. We are wondering about this Claus type reaction that take place under these mild conditions without catalyst.
27/10/2018 Q: VDU OVHD off gas after treatment in amine (MDEA) absorber routed to VDU furnace to serve as secondly source of firing along with Refinery FG (low in Sulfur)..
H2S in treated offgas is 100ppm (design 0.1%). However, Sox (SO2) in final four gas is high?? Reason?
We checked other Sulfur species's presence which are contributing high SOx. Any way to treat other Sulfur compound and bring Final emission under control??

27/10/2018 Q: In Our Sour Water Stripper Unit, The quality of Stripped Water is as follows:
H2S :0.4 PPM(Max.10 PPM)
NH3: 2.4 PPM (Max 50 PPM)
Ph: 8.9(6-8)

The H2S and NH3 are in desirable range but still we couldn't get lower Ph in stripped water? Is any other factor causing low Ph?
30/08/2018 Q: After cracking at VDU Heater, part of the Sufur on the AR(ATM Residue) is changed to H2S or Mercaptans and the stream flow to VDU Column.
Part of the H2S and Mercaptan go to the VDU overhead.
To catch the Sulfur (Specifically, H2S or Mercaptan) at Off gas Stream, Amine adsorber is installed at that line.
However, when I review the Heat and Material balance (HMB), only H2S is considered at the stream and Amine cannot catch the mercaptan well. It is useful to catch the H2S only.
Why the designer normally do not consider mercaptan catcher on the off gas stream?
Is there any specific reason?
For example, mercaptan cannot go to the VDU column overhead.
15/08/2018 Q: We are facing problem while collecting Regen cat sample and spent cat sample.
The sample point is located upstream of Regenerated Catalyst Slide Valve (RCSV). RCSV dp take-off points are also located near to the sample point take-off points. While trying to collect the regen cat sample, only hot dry gas is coming out from the sample point drain. No catalyst power is observed. At the same time, slide valve Dp is fluctuating badly and reaching trip value.
We did reaming of the sample collecting line. Line is observed to be clear. Due to above problem, we could not collect regen catalyst samples for last few weeks. Kindly provide inputs on this, if any other refineries have similar experience.

Similar problem is experienced with spent catalyst sampling also. The sample point is located upstream of Spent Catalyst Slide Valve (SCSV). While collecting the sample. Only dry gas is coming out and no catalyst powder is observed from the sample point. Kindly provide inputs on this, if any other refineries have similar experience.

28/06/2018 Q: Currently, I am trying to reduce the sulfur concentration from the hydro-treated naphtha. After reading up a few articles I came to the conclusion that the sulfur concentration is due to improper stripping of H2S from the stripper column. I have to improve the performance of the stripper column to reduce the sulfur concentration by adjusting pressure and R/F.
How do I proceed? Is there any other sources of sulfur that I have to pay attention to?
14/06/2018 Q: What is WSIM for ATF ?
How will it affect the product performance/ quality??
What are the measures to be taken to control WSIM ?
31/05/2018 Q: On the top of a flare tower, there are certain "star" shaped objects surrounding the top. What are the uses of those? (1)
13/05/2018 Q: What are the differences between hydrogenation and hydrodesulphurization? (2)
30/10/2017 Q: We are interested in reducing treatment load on spent caustic treatment unit. Then we are going to idle visbreacker gasoline treatment process by feeding it to other units. At present we use sweetening process (washing with caustic and converting with Merox) for visbreacker gasoline product. The problem regarding to produced spent caustic as byproduct is unreliable spent caustic treatment process to meet the environmental specs. The alternatives are suggested as follows:
1- introducing to heavy naphtha hydrotreater unit (unifiner)
2- introducing to Kerosene/diesel hydrotreater unit
3- introducing to hydrocracker unit
4- sending to crude storage and refine it again
Would you please explain pros and cons about the abovementioned alternatives? What is the best alternative?
24/10/2017 Q: Is stripped water useful for amine dilution and caustic dilution? (1)
22/10/2017 Q: In my unit, Main fractionator is running steady all parameters are normal, suddenly one day, CLO Flash point came very low compared to earlier it was high(75-89 C) and used to fluctuate by 10 C. Now flash is always coming below 60 C. We have increased HCO Stripper stripping steam and Main Column bottom stripping(Agitation) steam to maximum but still CLO flash is not improving. Checked for FLO to bottom circuit, all locations blinded. Main Column Flash zone temp & bottom temperature are 356 C and 349 C respectively. Kindly suggest best ways to improve CLO flash and how to find out the problem? (3)
14/06/2017 Q: In a SCOT unit, what can produce black solids accumulation in the quench water column? (1)
14/06/2017 Q: Are there ways to monitor pressure drop on-stream across reheat exchangers, condensers and catalytic reactors in a sulfur recovery unit? Manual pressure survey is being done using pressure gauges attached to Strahman piston valves are the only current way to do this in our plant. What is an effective way in forecasting high pressure being experienced in the system?  
29/05/2017 Q: How LHSV in a pilot plant reactor can be calculated with the following data: feed flow rate=30grams/hour,hydrogen to hydrocarbon ratio=400 Nm^3/m^3 and temperature and pressure conditions are 270 degree celsius and 20 bar respectively? (1)
14/03/2017 Q: Is there any nitrogen species that may be present in LVN but is not present in HVN? We are detecting high nitrogen content in LVN but not in HVN. Also, our sulfur content is low. Even though we may see nitrogen in HVN (poison to reactor), the endotherm of the reforming reactor is not affected. Are there nitrogen species that can be detected by NSX but is not readily available for breaking down/reaction? (3)
08/06/2016 Q: A trip is provided on high tail gas temperature of Sulfur Recovery Unit. It will bypass the amine system & tail gases will be directly routed to Incinerator. Why this trip is provided?
05/12/2015 Q: TLV and STEL of H2S is 10ppm and 15ppm, for SO2 it is 2ppm and 5ppm! But H2S is considered more toxic than SO2. Why? (1)
13/04/2014 Q: We have a Steam methane reformer having side fired self respiratory burners. To attain the correct O2 in flue gas of primary reformer, burner dampers are being adjusted. What is the correct sequence for throttling the burners? Should the bottom most burners should be throttled more than the top ones or vice versa?  
04/06/2013 Q: If the tail gas of SRU contains more SO2 , is there any chance of smoke formation in stack after incinerator. If H2S slip smoke formation happens and increasing air ratio to control the stack some free. But sometimes in low throughput smoke is coming. is it because of more SOx and NOx...? (1)
10/04/2012 Q: When you have a scenario of low sulfur diesel (50 ppm), what is the impact of Diesel viscosity at 40°C on vehicle emissions? (1)
17/11/2011 Q: How to calculate the SOx and NOx emission rate in a heater stack? (2)
11/11/2011 Q: We find the crude heater tubes started slightly bowing towards the burner inside the radiation zone. The investigation drives my mind over the below written questions...
1. What can be the maximum height of the Fired heater's radiation zone (or) the maximum tube height allowed inside the radiation zone (vertical coil type) as per standard?
2. What is the efficient ratio which can be achieved between the radiation:convectional zone heat transfer(in percentage)? Its a balanced type heater and we could heat the combustion air up to 275 C max?
3. We use P9 material tubes inside the furnace (cylindrical-twin zone). We are puzzled as to why the bowing is towards the burner side? Why not towards the side and backwards?
4. What is the maximum pressure drop across the burners allowed? As we go increasing the throughput in varying the Fuel oil and Fuel gas burning, the skin temperature response in all the section of the heater is not uniform. So the heat flux variance is also expected. I would like to know the methods available to find the heat flux variance inside the radiation zone.
5. The burners (Low NOx/SOx) used are stretching over the design sometimes due to the lower inlet temperatures. Flue gas recirculation is also included in the design. What can be the problem when a burner is running over the design limits? We have oxygen, CO, NOx/SOx analysers but they don't seem to be reliable most of the time.
16/09/2011 Q: I have a question about DeSOx Unit of RFCC
Our plant has a DeSOx unit that removes SOx and spent Cat’ (=dust) in Regenerator flue gas to meet environment standard.
After removing SOx and spent Cat’ by Mg(OH)2 solution, the waste water that includes suspended solid like spent cat’ is removed through filter press.
Filter press is dual type. When one is working, the other is stand-by. (Running time :18~30hr)
Because operation time of the two filter presses is not fixed and unknown, the cleaning man has to stay on or near the filter press to clean it, when switching.
So I want to ask:
1. How do you treat resulting waste water to meet environment regulation?
2. If you use filter press, what is the best way of managing it?
26/07/2011 Q: I'm getting ahead of work on emission-reducing additives in diesel engines, I want to know experiences about the use of additives based on polyisobutylene, some information reports levels of NOx emissions reduction close to 25% and Reduction of particulate matter of 47%. Does someone have some information about this topic to help me?
11/05/2011 Q: What is the standard value of sox/nox in atmosphere if emitting from hydrogen generation unit reformer for fg/naphtha/off gas firing? (1)
21/01/2010 Q: In a sulfur recovery unit incinerator (where calus process in front end followed by CBA process), presently incinerator control temperature is 605 Deg C. Can I bring down to 550 DegC? What will be the consequences? What will be the ground level SO2 content? (3)
14/01/2010 Q: There are four SRU units in our refinery. During start up period, we face the SOx emission problem since bypass TGU (Tail Gas treating Unit) operation. We use MDEA as absorbent to H2S recovery in TGU, and bypass this unit during pre-sulfidation stage of start up. On the other hand, we face the SOx emission problem too because sulfur burning out before turn around. Please advise.  
01/12/2009 Q: For reducing SOx contents in exhaust of Gas Turbine (power plant operations), what could be suitable process?
I was thinking about scrubbers, but not sure if it is practical to handle a flow of 30MMSCFD flue gases for scrubbing?
04/06/2009 Q: In what situation is a pneumatic test at one kg/cm2 to be preferred to a hydro test at the design pressure of a vessel? (2)
10/04/2009 Q: If off gases contain nitrogen and they fired in fired heaters how will it affect NOx levels? (2)
17/03/2009 Q: How will impending changes in marine diesel specifications affect bunker and residual fuels? Is there a long-term shift away from bunkers and residuals? Will this result in some niche opportunities for refiners? (1)
07/02/2009 Q: What is the standard value of SOX & NOX in furnace stack outlet? Are the Values different in case of fuel oil firing and fuel gas firing? (3)
25/04/2008 Q: I have read in analyzer vendor literature that NOx formation is the indication for best combustion in boilers (than Oxygen in flue gas). But we have to limit it. How far is it correct? can anybody give technical reference? (1)
28/02/2008 Q: While processing heavier and cracked feeds in Diesel Desulfurisation units the decativation could not take place due to metals poisoning or coke deposition. What are the views on predominant factor? If it is because of coke, is the only solution to make the feed lighter and process less of cracked stuff? However, if poisoning is due to metals, could a small bed of demet catalyst in the first bed prolong the life of the catalyst? (2)
12/02/2008 Q: Quite a large amount of Hydrogen is consumed in desulphurisation of fuels and hydrotreatments for product quality improvement which generate Hydrogen sulphide. A more economic process is required like catalytic decomposition of hydrogen sulphide into hydrogen and sulphur and the separation of the products of said decomposition to H2 and Elemental Sulphur. This would enable recovery of costly hydrogen and same can be re-utilised in the process of treatment. Are there any catalyst development taking place for such purposes? (1)
22/01/2008 Q: How much does it cost a refinery and/or petrochemical plant to produce 1 (one) tonne of CO2? I have worked out how much CO2 is produced per barrel of oil, for example, but now want to put a monetary value (or indeed an energy value) on to that tonnage of CO2. Thanks.  
09/10/2007 Q: What are the various processes for Recovery of Sulfur from Acid Gas? (4)
19/09/2007 Q: Please advise on reduction of ammonia emissions from a fertiliser plant.
Our emissions from a urea plant stack is about 150 ppm, and we need to reduce them to 50 pp to comply with EPA regulations. I know some plants are provided with an acid washing system.
I would be grateful for advice from anyone with experience in this field.
07/09/2007 Q: What is the factor of amount of particulate in the flue gas from boiler? The fuel of boiler is fuel gas and fuel oil from the Olefins plant. (1)
28/07/2007 Q: What role does oxygen availability play in controlling FCC regenerator NOx emissions? What regeneraor design improvements are recommended for minimizing NOx emissions? (2)
28/07/2007 Q: What analytical techniques are recommended for predicting FCC regenerator NOx emissions and monitoring NOx additive performance? (2)
22/07/2007 Q: Can you comment on one or more unit-specific cases where additives reduced NOx emissions by up to 80%? In other cases, what conditions existed where "only" a 20% NOx reduction was observed --- and what (if anything) was done to further reduce NOx emissions? (3)
22/07/2007 Q: What role does oxygen availability play in controlling FCC regenerator NOx emissions? What regenerator design improvements are recommended for minimising NOx emissions? (3)
09/07/2007 Q: What are the most effective SOx reduction technology improvements the refining industry is investing in? What is some of the latest feedback on their performance, particularly with regard to their effect on FCCU maintenance and operations? (3)