Q & A > Fluid Catalytic Cracking
Date  Replies
06/02/2021 Q: We have recently commissioned a 0.74 MMTPA RFCCU with mainly reduced crude oil (85%) and coker gas oils (10-12 %) as feed. We are getting a very high benzene content (~ 2-3%) in our light cycle naphtha (LCN), leading to problems in the finished MS pool due to a benzene limit of 1%. The downstream naphtha hydrotreater unit is only able to desulfurize the LCN with no benzene saturation. What methods will control the formation of benzene in the reactor, by either a change in feed composition or the operating parameters? (1)
30/08/2020 Q: Is the UOP qualified vendor list for different process units such as NHT, DHT, ISOM, FB Platformer, CCR, FCC and Uniflex publicly available?

 		(1)
06/07/2020 Q: Our catalytic reforming unit is running at 500°C . A short length flame and smoke was seen at the heater outlet flange; we have a steam ring which we have used to extinguish the fire. Now my query about hot bolting: is it safe to tighten the bolt at 500°C to stop the leak? If not then what should be the maximum temperature and safe procedure for hot bolting? (3)
02/07/2020 Q: In our catalytic reforming unit, DM water and CCl4 are used as dosing to keep the water and chloride balance within the prescribed limit. Material of both injection lines is stainless steel 304 whereas the main line of the feed (DSN) is carbon steel as per design. Line pressure and temperature of feed line are 24 kg/cm2 and 151deg C and both injection points are connected to the feed line. From a corrosion point of view, if i replace the injection line of DM water & CCl4 with carbon steel pipe will there be any problem ? If no then please give me the reason for using SS 304, or what type corrosion can take place in the injection line for DM water and CCl4?. Currently we are facing some leakage at the elbow weld joint. In addition, when we tried to repair by welding, again a leak/fissure was found just ahead of the welded point. (2)
25/06/2020 Q: I am currently working on designing a flue gas system for a Fluid Catalytic Cracking unit on the regenerator side. The typical set-up is regen effluent flue gas comes out of the regenerator at 1300F. It passes through the Waste Heat Boiler, generating 600 psig (high pressure steam) by recovering heat from the effluent flue gas. The flue gas then passes through a series of pressure let down devices (double disc slide valve, followed by an orifice chamber (bunch of orifice plates lined in a duct)), before going through the wet gas scrubber (caustic wash for any catalyst carryover) into the stack and vent to the atmosphere.

Normally the slide valve (one of the pressure let down devices) is used to control regenerator pressure. This valve is also designed with a minimum cut out and/or a mechanical stop, that prevents the slide valve from going completely closed, the reason being this serves as a path of relief in case the slide valve goes slam shut, causing a source of overpressure on the regenerator. In this case the regenerator is designed for 38 psig.



One of the scenarios to be considered, credible under the current setup, is if the tube in the WHB ruptures, high pressure BFW on the shell side of the WHB can pass through the tube (process gas side), which is open to the regenerator and creates an overpressure. As mentioned above the minimum opening in the slide valve, through the orifice chamber, through the wet gas scrubber, will be a relieving path for this fluid.



Question: I am trying to calculate the amount of relief that will be generated through the tube. Since BFW on the shell side is at saturated conditions, there will be flashing (two-phase flow) passing through the tube. As the relieving flow exits the tube, it should be under sonic conditions (choked flow).

I need to determine how much flashing will occur across the tube as it exits the tube, and secondly the amount of flow that will exit the end of the tube (probably a two-phase restriction orifice calculation needs to be performed) to determine the flow.



I would greatly appreciate if someone can guide me as to how to perform this calculation as I have not done much two-phase through tube (at sonic conditions) and two-phase RO calculation.



 		(2)
17/04/2020 Q:
Is there any way of online cleaning a CCR regenerator without opening it?
(1)
22/03/2020 Q: What are the reasons for a drop in DP of a spent catalyst slide valve in a FCCU? (5)
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)
03/11/2019 Q: What are the adverse conditions which may lead to formation of clinker and syntering during FCCU catalyst regeneration?  
07/10/2019 Q: I am currently working in Exxon Flexicracking FCC model. During start-up of the unit, when we establish catalyst circulation, sour water received in the MF O/H drum is acidic. When we introduce feed to the reactor, it becomes neutral. Why is it so? I am interested in the chemistry of the process leading to acidic boot water. Can we reduce the acidity by changing operating conditions of the MF or R-R section? (1)
07/10/2019 Q: I am currently working in Exxon Flexicracking FCC model. During start-up of the unit, when we establish catalyst circulation, sour water received in the MF O/H drum is acidic. When we introduce feed to the reactor, it becomes neutral. Why is it so? I am interested in the chemistry of the process leading to acidic boot water. Can we reduce the acidity by changing operating conditions of the MF or R-R section?  
05/10/2019 Q: Why is sour water from the main fractionator O/H drum acidic in the FCC during initial catalyst circulation without feed but becomes neutral after introducing feed to the reactor? I am interested in the chemistry of the process leading to acidic sour water? Are there any ways to reduce the acidity of sour water by changing the operating conditions of the reactor or fractionator? (1)
04/09/2019 Q: Does any one has info on blending RON for gasoline linear vs indexed OR blending RON number of component hydrocarbon determined from GC analysis and where to get blending RON numbers
 
03/09/2019 Q: Why does the FCCU main fractionator column bottom level need feed make up during low throughput? Why is the level not maintained properly during low throughput?
 		(4)
24/06/2019 Q: How do you minimize slurry concentration in the MF bottom/slurry circuit system? What operational parameters can be checked/adjusted? (2)
24/06/2019 Q: For the FCC slurry circuit, can you recommend ways to address/mitigate control valve erosion? What adjustments in FCC operation can aid in minimizing the erosion in control valves?  
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
 		(3)
20/05/2019 Q: Why we are using high pressure steam in heaters? (2)
14/03/2019 Q: what is the role of DMDS in adding to the platformer unit feed? (4)
14/03/2019 Q: In the our hydrotreating naphtha plant total sulfur is increased more than .5 ppm (this is my specification) and this hydrotreated naphtha (HTN) used to Aromizing unit to produce Aromatics. As you know, in the furnace of CCR platformer DMDS is used to passivate furnace tubes ,but when total sulfur increase more than .5 ppm in the feed of CCR platformer we stop injection of DMDS in the feed of CCR platformer and the question is :
can we stop the injection of DMDS in the feed of CCR platformer in case of total sulfur increase more than 0.5 ppm in HTN?
does the increase of TS in HTN can do the role of DMDS in furnace tube ? 		(2)
06/03/2019 Q: How to remove pyrophoric material from FCC Reactor, if any, Does any refinery face such kind of issue during turnaround? (1)
16/02/2019 Q: When our VDU column products, vacuum slop and vacuum residue were tested for H2S it showed H2S presence >10 ppm.What could be the possible reasons for high H2S?
We are maintaining VDU bottom level and temperature low to avoid cracking still H2S reported is high.Coil steam and Velocity steam were increased and kept 120% of the PFD values. Chances of exchanger leak was also checked and observed no leak. 		(4)
03/12/2018 Q: what is the cause of co (monoxide carbon) formation in the catalytic reforming unit? (2)
09/11/2018 Q: How to monitor performance of CO promoter additive? What is CO index and its significance?  
29/08/2018 Q: Our FCC plant Downstream debutanizer tower having pressure increase issue due to exchanger perforamance and cooling water temperature issue,
If only reboiler steam is reduced, Debutanizer OVHD C3’s composition is started increasing,Though Debutanizer’s purpose is to separate C3&C4 LPG (to Top) and Naphtha (To bottom),in case of sudden reducing reboiler steam, C4 component starts accumulation in Debutanizer column and C3 concentration at OVHD starts increasing,In fact, after only reducing reboiler steam, Debutanizer OVHD temp temperature started decreasing and Debutanizer OVHD pressure started increasing simultaneously.OVHD pressure may increase tentatively due to composition profile change in the column, then it was come down.
Above Phenomena little tough to understand. Anyone kindly explain?

 		(6)
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.

 		 
06/08/2018 Q: What can possibly cause an implosion inside FCC Reactor Riser. We presently have an implosion inside our Reactor Riser. The section /area assumed triangular in shape rather than the original circumferential shape. The incident has drastically reduced the I.D of the riser in that location, restricting normal flow through it.  
03/08/2018 Q: Anyone suggest me about increasing Propylene production in FCC without affecting stripper dp. In our refinery 2 Reactors or working in poly Propylene unit (PPU) for poly Propylene production and feed sent from FCC to PPU. Now 3 rd Reactor is commissioned in PPU but not any changes in FCC for increase Propylene production. So kindly suggest me which type of changes is required in FCC technology or process data's to increase Propylene production. (4)
22/07/2018 Q: How does an FCC engineers control the riser residence time? What are the factors that affecting cracking residence time in riser? How do I calculate the residence time (1)
09/07/2018 Q: This is question is related to high potential gum in gasoline ex FCC. We have 2 gasoline merox reactors (A&B) and recently we have bypassed 1 reactor(A). Thereafter we observed some abnormal results of high potential gum (as high as 1300 ppm). On further analysis, we have checked merox inlet (B) and outlet(B) as well as combined outlet(A&B) i.e., Rundown. we have found high gum at inlet (1200 ppm) and immediate out let (500 ppm) and combined outlet (900). As per literature and my experience gasoline merox reactor doesn't contribute or treat potential gum but couldn't able to find the source. Also inlet is higher side, we have checked olefins at inlet (28% reported). what could be possible reasons for high gum at inlet and why are we observing gum abnormalities across reactor? (3)
12/05/2018 Q: In case of fluidized naptha cracking heat balance is an isssue, where not enough coke is generate to provide the endothermic heat. In such cases can pet coke be used in the regenerator to produce the reequired heat? If Possible what adverse effects can it have?  
25/03/2018 Q: In our FCC, we process two feeds namely, Coker Gasoline and Mixed feed (Mixture of Residual crude Oil & Coker Fuel Oil). In one of our unit shutdowns, we found very hard coke formed in the Riser at the area of feed nozzles. We did not observe this type of phenomenon in past. What would be the probable causes for formation coke in the Riser? (4)
14/03/2018 Q: In our FCC unit regenerator outlet flue gas goes to flue gas boiler and generate 95 TPH high pressure steam.
We are doing 3 times soot blowing in a day (24 hrs) for remove catalyst from water tubes. Can water tubes damage or effected due to many times of soot blowing? 		(1)
25/02/2018 Q: In FCC unit, Does PSD of the catalyst effect the catalyst loss through stack? (3)
25/02/2018 Q: In our FCC unit, We have two temperature indications in the stripper bed. During start-up of the unit, we observe the two temp. indications show almost same temperature, but during normal operation of the unit, the temp. difference of nearly 100 deg. C between the two temp. indications is being observed. What would be the reason? (1)
13/02/2018 Q: In our FCC, catalyst has been observed to get carried over to the fractionators during start up activity. This upsets the fractionators bottom pumps. What can be probable reasons for such carry over and how this can be mitigated? (4)
14/01/2018 Q: In our FCC 4 PDT A,B,C,D are provide to show RCSV Differential pressure , all PDTs are N2 purged with flow orifice and flow orifice bypass. from some days we are facing dp problems in C and D. If we are open flow orifice bypass of C and D than DP maintain and when we are close flow orifice bypass DP disturb of C and D.
What may be reason? 		(1)
27/12/2017 Q: At the beginning of our NHT project ( catalyst HR 506), sulfiding was done by pre-wetting condition and still now same oil in procedure has been followed that means Oil in start with DSN at 140 degC through reactor and DMDS injection start at 180 degC to maintain the H2S at 180 to 200 ppm. Finally at 280 deg C, DSN is replaced by Heavy Naphtha (HN). Mentionable that our HN is sweet so we have to inject DMDS all the time to maintain H2S limit within 180-200 ppm in the recycle gas to keep the catalyst in active phase. Now my question is that what is the demerit now to do the normal start-up by starting oil-in directly with HN at 280 degC without pre-wetting ? Is there any chance of losing Sulfur from catalyst during H2 rich gas circulation within 6 hrs to raise the temperature to 280? Is there any impact on catalyst to increase the differential Pressure (dp)of catalyst bed for pre-wetting or direct oil-in procedure? Currently dp across the reactor bed observed increasing little bit after each normal start-up by pre-wetting oil-in procedure -what could be the root cause of it? (1)
17/11/2017 Q: I'm working in ExxonMobil licensed FlexiCracking unit. After emergency shutdown in unit, Slurry PA, HCO PA, LCO PA flows are disturbing. Slurry PA flow is establishing after 2 - 3 trials. Whereas LCO PA & HCO PA were unable to maintain even after opening cutter to both the circuits. Immediately after unit trip, we are closing stripping steam to LCO, HCO strippers, LCO PA, HCO PA pumps are drained thoroughly before placing it in service. LCO PA, HCO PA are slowly dropping to zero. that time main fractionator top temp increasing too high to >170 C. How can I maintain steady LCO PA, HCO PA flows during unit startup, while maintaining main column top temp at 140 C. Please help me how can i maintain steady PA flows during startup so that MF temp profile is steady. (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? 		(3)
23/10/2017 Q: In our plant, we have 7 heaters for Distillation unit, NHT and CRU unit. Fuel Gas that is generating from CRU Unit (80% H2) is being used for all those heaters. But, gum or glue is observed at the pressure regulating system which is situated on fuel gas line which mean it is depositing at the reduced area due to restricted flow path. My question is that if the olefin/unsaturated compound present in the desulfurized naphtha ( CRU Feed), is it getting Oxygen from Oxygenated compound like MTBE, TAME or Methanol and so on to form gum or is it getting O2 from the existing system? If this is not the case then what could be the reason of forming gum in the fuel gas? (3)
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)
02/10/2017 Q: What is the animation video link of FCC reactor and regenerator working, cracking and catalyst circulation? (1)
08/09/2017 Q: I am working in UOP hydrocracker unit. In our feed filter backwash frequency is very high since one month. We have cleaned the filter elements one by one. After cleaning of filter some improvement seen for some days but then filter starts backwashing again. we have also checked CCR and asphaltene and all are within range. we process VGO and HCGO in our hydrocracker unit . It is recycle type with 97% conversion. please suggest remedy. (8)
14/08/2017 Q: What is the uses of Decant Oil or clarified oil or slurry oil which is generated from the Catalytic Converter? What are the valuable chemicals recoverable for it? What is the different technology behind this to convert it to a useful fractions? Which company provides the technology? (7)
14/06/2017 Q: What is the latest UOP method of analyzing C5+ content for the Platforming product (Reformate)? (2)
27/05/2017 Q: In our refinery,straight run LPG is used as Automotive fuel LPG to meet the minimum MON spec of 88. Why is cracked LPG not used for Auto-LPG ? Will it not meet the MON spec ? What is the composition wise difference in Straight run and Auto LPG ? (2)
14/05/2017 Q: We are using AXENS Catalyst RG-682 (Naphtha Reforming) and HR-538 (Naphtha Hydrotreating).
Now, my question is what is the actual life time of these two Catalyst? How many times it can possible to regenerate RG-682 & HR-538? 		(6)
02/05/2017 Q: How can I calculate Reforming Heat of reaction and reactor Delta T. From the catalytic reaction guideline I know that the Napthene dehydrogenetion heat of reaction -50 Kcal/mole. Now I want to calculate reactor delta T.
Additionally I know the reformer feed flow rate, feed detail hydrocarbon analysis, feed density, feed molecular weight
In practical operation, we have three reactor in series, 1st reactor delta T 117F, 2nd reactor delta T 48F and 3rd reactor delta T 16 F; Now I want to calculate this delta T in theoretically. How can I prove/calculate that this practical delta T as like theoretical? 		(2)
01/05/2017 Q: What are the effects of continuous usage of FCCU direct fires air heater during normal operation to support Regenerator base temperature especially at a condition of limited fresh catalyst availability? (1)
03/02/2017 Q: Our FCC feedstock is 30% AR, 20% SR VGO, 50% CR VGO.
Our Vapor line DP increases steadily (sometimes drops) and now it became over 0.43kg/cm2.
We have some ideas about developing during TA but is there anyone who has ideas about dropping
the coke during normal operation?
We are trying
1. ROT increase
2. Feed Temp increase
3. Rx STM increase(ex. Lift STM)
4. Excluding Crude which has high asphaltene component
Is there someone who had suffered from vapor line dp and has some clue about dropping vapor line dp? 		(4)
22/01/2017 Q: We are operating Full combustion FCC with hydro treated VGO from VGO hydrotreater. Sometimes VGO HDT sends their back was material along with Hot hydro treated feed to FCC. Unfortunately many of the times their backwash filter is in bypassed condition. We commissioned our plant one year ago and till now no issues related bottom circuits propped up. We are having 3 MFC bottom pumps with dual bucket strainers for each of the bottom pump. For one month we are not developing flow though CLO pump around pumps (normal flow 800MT/hr for each pump).For present T'put we operate one bottom pump with one suction strainer in line. But for one month the bottom pumps are cavitating and not developing flow and it is observed that the pumps are not getting proper suction flow from the main fractionator column.We are continuously cleaning our suction strainers and some times we are getting soft coke & catalyst but sometimes finding not much. We lowered T'put due to this issue and running two pumps instead of one pump and all the strainers are in line. Still day to day the condition is deteriorating and not improving. Reason is not known for suction lines chokage issue. We are maintaining MF column levels on lower side but to our surprise the suction lines seem to got choked. Our slurry BS&W didn't cross 0.3wt% at any point of time during the period.
Anyone suggest --
1) How to mitigate the problem while plant is in running condition
2) How to avoid this type of problems what corrective actions to be taken wrt feed, Circuit flow and all.
3) Any system available to clear the MF column bottom circuit chokage issue.
 		(4)
22/12/2016 Q: What are the main contributes to CDU (crude distillation unit) and what is the benchmark or reasonable percentage of loss across CDU? (2)
09/12/2016 Q: what is partial and post burning in FCC regenerator ? (2)
29/10/2016 Q: How does one measure how much dispersion steam to inject, relative to the feed? (2)
29/10/2016 Q: How does the Regenerator/Disengager slide valve operate with regards to slide valve DPs? (1)
18/10/2016 Q: In our FCC (Deep Catalytic Cracking) Unit Spent catalyst slide valve(SCSV) DP suddenly decreased from 0.70 to 0.35 kg/cm2. All parameter such as aeration purge point pressure and flow, all types of steam flow, reactor and re-generator DP are normal. What is the reason for this? (5)
11/07/2016 Q: We are facing a problem due to the high content of phenol in LPG treatment spent caustic. Due to this high levels, we are having problems to discard this to the wastewater system.
I do not expect to have such levels of phenol (over than 5000 wppm) in a caustic solution used only to treat LPG. Is it normal to have high phenol content in these type of spent caustic? The sulphides level is lower than this.
The LPG is produced in a Delayed Cooking Unit and is previously treated in a amina section to remove H2S. The caustic treatment is a Merox type, but due to some operational problems, the caustic strengh used is 17%. The phenol level is high even in the spent caustic of the extraction section. 		(5)
04/07/2016 Q: I wish to know whether it is possible to install a H2S analyzer in the FCC gascon section stripper column bottom liquid stream. The composition is C3-C10 hydrocarbons (propylene to naphtha range) and a little H2S and ethane. Also, a bit of RSH and COS are present too.
The requirement is to have an H2S analyser in this stream so that any slippage of H2S from stripper can be detected immediately and appropriate corrective action taken with minimum effect on downstream process. Is there any other indication of H2S slippage which can be used for monitoring purpose.
 		(2)
27/06/2016 Q: In case of heavy residue upgrading, we are encountered with vacuum residue as feed. The main features of this feed especially about contaminants and problematic materials are as below:
Total sulfur>4.5 wt%
Conradson Carbon >25 wt%
Ni+V >500 ppmwt
Nitrogen ~ 1 wt%
We have two cases for VR upgrading project, One is RCD+RFCC and another is HOIL(Hydrocracking)+FCC. Both of these cases use huge amount of fresh catalysts because of high possibility of catalyst deactivation and poisoning. So the operating cost should be high.
Is this rational to charge such a feed to the catalytic system directly or is it better to use the process to somehow get rid of metals at least? If we need to use the solvent deasphalting system at the upstream of two before-mentioned cases and draw off about 20% of feed as pitch, we will succeed to lower the operating cost and increase the reliability of catalytic system because of the elimination of the major part of the metals. But in the opposite side, we have missed 20% of primary feed as pitch that it is a low value product. So the profit margin of the residue upgrading cases will decrease. However, as a second question, can we miss 20% of feed charge at the expense of increment of catalyst life cycle?
 		(5)
16/06/2016 Q: What are the potential causes for higher pressure drop in FCC stripper column? (4)
31/05/2016 Q: What are the potential problems if we have higher grid pressure drop than expected at conditions? (7)
06/05/2016 Q: We experience quite at lot of catalyst in the riser bottom after shutdown. What can be done to avoid this catalyst slumping during the course of shutdown? (1)
10/03/2016 Q: 1. What is the contribution of lower/upper LCN recycles and lower/upper C-4 recycles towards dry gas and c3/c4 yields, assuming that riser outlet and regenerator dense bed temperature are constant.
2. What is the contribution of lower and upper slurry recycles towards coke and slurry make? We have a low CCR feed and coke/slurry yield is low. So, continuous torch oil injection is there to maintain regenerator dense bed temperature. 		(3)
02/03/2016 Q: Which are the causes of an temperature increasing inside of an absorber tower amine-gas? anf if this happens what are the amount of increasing, our operational inlet temperature amine is 45°C (113°F), gas 39°C (102 °F), outlet gas temperature is 60 °C (140 °F).
 		(1)
25/01/2016 Q: Our Deep Catalytic Cracking unit Wet Gas Compressor (WGC) seems to be an over-designed one as its operating at the minimum governing speed(MGS) with the anti-surge valves around 35% open even at 90% plant capacity. Due to this the speed/performance controller is operated in manual mode making it difficult to control the reactor pressure.
Is it possible to change/lower the MGS of turbine so as to bring the speed control in the unit's operating range and thus keeping the reactor pressure control in AUTO. If not, is it advisable to tune the ASVs so that they close at a lower load? 		(5)
26/12/2015 Q: Our Deep Catalytic Cracking unit, commissioned an year ago, is constrained with high stripper/absorber pressure drop problems. When stripper feed temp was 42 deg, stripper exhibited high del pr even at 80% loads. After failure of HPS inlet condensers cooling water exchangers, the stripper feed temp increased to 67 deg C. Though the stripper del P peaked around at 95% load, but absorber column del P exceeded the max operating value.
What may be reasons behind stripper del P incursions? What is the optimum stripper feed temperature? 		(4)
21/12/2015 Q: In our FCC, we are facing problem i.e. flue gas line TSS-FSS flange leak, causing heavy erosion of the flange and catalyst loss through the leak. Therefore, i request you to confirm whether is it possible to do lip seal joint for these flanges or any other parameter to check the compatibility for lip seal joint of these flanges.. (3)
22/11/2015 Q: We have some LPG Merox units with amine absorber before the Merox unit. We use MDEA in the amine absorber and we have experienced some problems of amine carryover in the LPG.
Can anyone comment on the impact of the amine contamination in the Merox units? Besides the possible formation of emulsions, could there be any other problem? 		(6)
22/09/2015 Q: Is it possible to reduce reactor stripping steam ring steam flow below minimum, if min dP criteria is passing? This is to increase regenerator dense phase temperature as we are not able to make required coke. (3)
31/08/2015 Q: How is 'COS' formed in FCCU riser-reactor section and what are the measures necessary to minimize its concentration to avoid slippage of 'COS' into product LPG/Propylene? (4)
28/08/2015 Q: Any experience about neutraliser, filmer dosage and wash water incection into the O/H line of mail fractionator on FCC Unit. Is it allowed to mix neutraliser anf filmer into the washwater line? What is common practice for injection of neutralizer, filmer and washwater and why? (5)
30/07/2015 Q: I am measuring the level of the catalyst in regen with d/p transmitter,the distance between taps is 498 " the density of lower section 25#/ft^3 and upper 3#/ft^3
What is the cal range " WC? It's continuous purge. 		(1)
30/07/2015 Q: Please advise as to how catalysis bed levels are measured in FCC REGEN using differential pressure also how density is calculated from d/p.
Are dip tubes used similar to bubble system? 		(2)
16/06/2015 Q: We are observing high CS2 content in our straight run naphtha. This is not on regular basis but frequent and sometime it goes up to more than 20-25 ppm also. Please advise what can be source of such high CS2 content in naphtha intermittently.
The sources may be narrowed down to:
1. Presence of CS2 in Crude itself- Please suggest the probability of the same and if any known crude with high CS2?
2. Since CS2 formation requires very high temp, can it be formed in crude heaters? or any other process?
3. Though probability is less, can it come from recycle hydrotreated naphtha? 		(2)
12/05/2015 Q: Is it possible to inject DCU Coke fine particles (~ equivalent PSD of FCC Catalyst) into FCC regenerator to avoid using torch oil and afterburning? What are the Pros and Cons of using the same? Please share the experience if any refinery tried the same. (1)
18/04/2015 Q: What is the minimum FCC riser velocity to be maintained to avoid catalyst slumping or back mixing in the riser? (1)
24/03/2015 Q: We have FCC (DCC) commissioned last year, full combustion regenerator. We are facing following problems:
a. Both DFAH and torch oil were in line to satisfy heat balance requirement of Rx-Reg. Torch oil firing results in high afterburning in regenerator ovhd line. Also slurry recycle (feed recycle to MF, not slurry generation) injected at reactor stripper section. Is there any possibility of increase in coke make if we stop fresh feed preheater and inject feed at low temperatures? what are other solutions?
b. Even after stopping DFAH and torch oil, we are facing problems of afterburning in regenerator. Is the afterburning due to slurry injection at rx stripper section (afterburning temp comes down when reducing slurry recycle), or any maldistribution in combustion air distribution?
c. Regenerator Flue gas stack SPM is high when doing soot blowing of Flue gas cooler tubes. Is this due to inefficient working of TSS-FSS or more fines in the circulating catalyst? 		(2)
01/01/2015 Q: What will be the impact of crude blend on FCC product yield? if we are processing 95% hydrotreated VGO and 5% of non-hydrotreated VGO (i.e. Sour VGO). although the feed to the FCC is mainly hydrotreated, will crude blend affect the product yield? (2)
22/12/2014 Q: In our RFCC we have a purge treatment unit to remove the catalyst fines from the flue gas before leaving through the stack. The PTU utilizes about 25 m3/hr water for scrubbing and this water after clarification and oxidation leaves the unit as discharge. I would like to know about the possible destinations for the treated PTU water and availability of alternate methods which does not require water for scrubbing. (1)
21/12/2014 Q: We have an RFCC with a downstream purge treatment unit which consumes about 25 m3/hr of water in the scrubber. This water is clarified and aerated in towers before being discharged. Presently due to certain limitations we are required to reduce this quantity and route the effluent to BTP. What other alternates are available for treating/routing this water from purge treatment unit?  
20/12/2014 Q: Our problem is catalyst tapping blockage.
1- Tapping are for regenerated catalyst slide valve differential pressure ( high leg )
2-Stand pipe is sloped (about 25 degree)
3- Tapping located below stand pipe and there is cold : It shows catalyst don't flow there (Top of stand pipe is hot )
4-Purge air could not enter to tapping but amazing catalyst comes out from tapping. (It's like a check valve)
Have you had similar experience like our problem ?
 		 
30/11/2014 Q: What's the best way to clean out the main column after reactor catalyst lost? (1)
07/11/2014 Q: I'm going to implement APC in a FCCU soon. What's the best source of information to learn the complete (even the minute) details of FCCU so as to complete it successfully? (1)
29/10/2014 Q: Our FCCU (Stone & Webster) shows high BS&W in CLO stream, even though charge rate is low at around 150 tonns/hr. Design capacity is 215 tonnes/hr without any bottom (CLO) recycle to the feed. Now lab result of BS&W shows in the range 0.4 to 0.7 . Our intension is it keep it always below 0.4 . What are the remedies to tackle this problem without shutdown? (1)
09/10/2014 Q: We have two level transmitters for FCC reactor. Since last few months back we are facing malfunction of one of the level transmitter. We use to flush/ blast the High pressure tapping of that level transmitter for few minutes. The transmitter works well again for few days after flushing. We observed that there is no any effect to the other transmitter. The Low pressure tapping of both transmitters are at same elevation and High pressure tapping are at different. What could be the possible reason for this case? Or it was only due to bubbling bed fluidization issue or due to damaged/ plugged air grid. (1)
09/10/2014 Q: We are facing problem with debutanizer reboiler operation due to fouling and we didn't get enough reboiling and bottom temperature. It forces us to reduce the plantload and reduce debutanizer feed. Can increase in debutanizer feed temperature help us to process more feed? And if we increase the stripper bottom temperature, what are other precautions to be considered? Like increase in stripper pressure with respect to temperature for fuel gas specification. (3)
25/09/2014 Q: Can we process FCC's Clarified oil (CLO) or Decant oil as feed to Hydro cracker? My question is that Unconverted oil from Hydro cracker is usually good feed to FCC, So I would like to know if we process FCC CLO in hydrocracker then how much of it will it to convert to Unconverted oil in Hydrocracker? We will use filters to reduce catalyst content in CLO so that hydro treater won't get affected. (2)
15/09/2014 Q: What are the best operational practice to res-use the catalyst fines collected from Third Stage Separator (TSS) installed in the down stream of regenerator?. Whether these catalyst fines can also be utilized to improve the other thermal cracking process ? (1)
07/09/2014 Q: We are having reflux drum for primary absorber. the entrained net overhead liquid is collected in the reflux drum. the liquid of reflux drum is pumped out internittently to high pressure seperator. I want to know that can we line up this hydrocarbon back to main fractionator or to deutanizer feed line? If we line up it to main fractionator then it wont accumulate in primary absorber reflux drum and build up the level in reflux drum. (2)
03/09/2014 Q: We found a high TAN, ca. 0,4 mgKOH/g (usually 0,1), on a LCO cut.
What could be the explanation? 		(3)
25/08/2014 Q: What would be the good choice as an absorbent in Sponge absorber? Either Light cycle oil or heavy cracked naphtha (Lean Oil) from main fractionator. (1)
13/08/2014 Q: Recently we have suffered some problems of Cupper Corrosion test failure in LPG. The LPG came from a caustic treatment for mercaptan sulphur removal. After caustic treatment, the LPG pass through a decanter (with NaOH/MEA solution) and sand filter, which are supposed to remove any caustic carryover from LPG. We do not see any caustic collected in the sand filter, however we have detected Na and nitrogen in LPG, so we suspect that it is not working properly. The sand filter seems not only not working, but also accumulating some contaminants: we have seen sometimes that LPG pass the cupper corrosion test in the inlet, but not in the outlet of the sand filter.
We are evaluating the possibility of substituting the sand by any other more effective adsorbent for caustic / nitrogen (amines). The possibilities are: activated carbon, Anthracite or alumina.
Has anyone experience with adsorbents for contaminant (caustic, amine, etc..) removal in LPG? Any idea / recommendation regarding the operation of the sand filter?
 		(2)
03/07/2014 Q: Does anybody use MDEA on Amine treating on FCC?
We proceed hydrotreating feed on FCC, and we use DEA on Amine treating. We want to switch DEA with MDEA.
What should I pay attention to during this switching? 		(2)
14/05/2014 Q: I have question about S content in heavy i light FCC naphtha.
We have Texaco FCC unit and processed hydrotreating feed, in RF riser we processed heavy fcc naphtha. We tried to processed little amount of VBB, but we had problem with the S. In VBB we have 30% RSH and 0,8% H2S, other 70% we do not know which sort of S is. Our laboratory can not define which sort of S we have.
With processing VBB we normaly rise S content in heavy and light FCC naphtha.
Does anybody have advice how to reduce S content in FCC naphtha if we processed some amount of VBB? 		(1)
08/04/2014 Q: We are processing HHCGO in our FCCU. My question is that whether we have to process it as combined feed in feed surge drum or we have to process it by injection through individual feed nozzle a higher elevation. Which is the best option and why? And what is the impact on yield pattern? (4)
04/04/2014 Q: For a given feed quality and constant Reactor temperature,
Which of the following gives Optimum yields.
a) Higher feed preheat & Low Cat/oil ratio
or
b) Higher Cat to oil ratio & low feed preheat?
 		(5)
25/01/2014 Q: We are facing problem of low heat duty of the debutanizer reboiler. Tube side heating media is saturated high pressure steam. Our steam flow was decreased gradually. We opened steam flow supply valve more to increase the heat duty, but still we did not succeed. We use saturated high pressure steam as heating medium and operating temperature is 482 Deg F (250 C). We as of now ruled out the reason of polymerization because of the low heating medium temperature, but question is that higher shell side tube wall temperature due to low pressure drop and it may lead into polymerization. Can it happen?
One more point is that, we have one online sealing clamp at steam inlet line and we injected sealing material three times to arrest leak. I thought that this sealing material might have blocked the control valve upstream cadge/ filter and reduce the steam flow. We had reduced the condensate pot pressure and we observed that the steam flow was increased.
What can be the reason for low reboiler heat duty? Is it because of polymerization or chocking of the steam control valve? How can we conclude this problem?
(8)
03/12/2013 Q: The Normal feed for FCC unit is HVGO & HCGo from coker. In case of HCGO not processed
1) Can we get Regenrator temperature?
2) what is the behaviour of FCC unit? 		(2)
15/10/2013 Q: 1) What are the technologies available for FCC flue gas desulphurisarion other than caustic scrubbing?
2) We have FGD using 20% caustic. Can we change to other cost effective methods in the same setup? 		(1)
05/10/2013 Q: In FCC we are having start up steam/lift steam at riser bottom & atomizing at u/s of feed nozzles.
If I need to increase the partial pressure of hydrocarbon, which one is effective? 		(2)
05/07/2013 Q: We have a liquid product named HCGO; ideally it's 280-430 cut material. We are analyzing its distillation by D86 method. same liquid sample when tested with D1160 recovery results were different. Since there is huge difference between 350+ recovery points we are confused as to which method to follow.
1. How to compare D86 & D1160 values - which are more accurate?
2. What is the range of D86 & D1160 test methods wrt. recovery points?
Below is table for reference. Both the results are reported up to atmospheric values and in DegC. (OOR = Out of Range)

S. No Distillation D-86 D-1160
1 IBP 287 280
2 5% 339 337
3 10% 347 354
4 30% 363 385
5 50% 374 403
6 70% 384 420
7 85% 396 437
8 90% OOR 446
9 95% OOR 461
10 FBP OOR 497 		(3)
04/07/2013 Q: I want to know the effect of excess air on dilute phase temperature. Regenrator (Full combustion) is operating at 2% excess oxygen. If excess oxygen is increased to 5% for some reason, what is the effect on dilute phase temperature with same cat/oil ratio and cat circulation rate. (3)
01/06/2013 Q: Our fcc unit works good up to now. In routine checks we find out that the torch oil nozzles are plugged
I would like to ask what can be done (the steam atomizing is ok):
Can we try to inject oil through the atomizing steam side without steam, in case we need it?
Can we try to unplug them using water pressure 50-100bars?

Let me explain further. As you know, the torch oil gun has 2 pipelines (externally for steam and internally for oil). In current operation, the steam flows through the torch oil nozzle (external pipeline) and finally routes to the Regenerator. However, we observe that the oil stream cannot flow, due to plugging of the internal pipeline of the torch oil gun. We want to unplug the oil pipeline, via let’s say water or other oil quality (e.g. light cycle oil). Are they convenient? Other ideas? 		(4)
05/04/2013 Q: For a FCC unit processing 50% DVGO and 50% VGO, sulfur content of 0,5-1%, where it can expect the highest corrosion rate? (1)
12/03/2013 Q: In one of our FCCUs we have problems closing heat balance due to the processing of a very hydrotreated feedstock. We have to use torch oil (LCO or fresh feed) to maintain regenerator at its minimum temperature.
We are evaluating the possibility of using other feedstock as torch oil. Has anyone experience in using fuel gas or natural gas as torch oil in the regenerator? What major modifications in hardware are required?
(2)
12/03/2013 Q: Some weeks ago we saw some cracks in the FCC expander blades in one of our FCC units. The cracks appeared suddenly, from one month to another.
The fresh catalyst addition rate are very low, so catalyst turnover is slow. It has provoked the ageing of our e-cat inventory. We have measured the attrition of the e-cat, with Jet Cup method (Davison Index), and there is a decrease from 2-3 to 1-2. My question is could this decrease in DI of the e-cat (harder catalyst) be responsible for the mechanical problem in the expander?
 		(2)
11/02/2013 Q: In one of our FCCUs we have an automatic pneumatic fresh catalyst injector to load the catalyst from the catalyst tank to the regenerator. Some weeks ago we start having problems with the fresh cat injection. After inspection of the pneumatic injector, we could see a very hard deposit on catalyst in the injector valve. We found some other catalyst agglomerates in the tank. We believe it could be formed due to a leak in an steam line in the fresh catalyst vessel.
After several weeks and trials we have not been able to run again with the pneumatic injector and we must load the catalyst manually, straight from the tank, through the by-pass line of the pneumatic injector. After a very exhaustive inspection, everything seems to be OK mechanically in the all the system (vessels, piepes, etc). The catalysts deposits in the tank have disappeared. We are also having several fluidization problems in the loading pipe to the regenerator, both using the pneumatic or the manual loading.
Have anyone experienced similar problems? Could the properties of the fresh catalyst be related to the problem (losses on ignition, humidity, atrition, PSD)? 		(1)
19/01/2013 Q: Why does the stripping steam trip close when there's a high level in tower? (3)
27/09/2012 Q: We have a problem in the hydrotreated filters when feeding HCGO. In these filters, we usually feed VGO and we haven´t any problems, but when we try feed HCGO from coker unit, the filters are plugged at the few minutes.
The ratio between HCGO and VGO is 30/70% aprox. and the temperature of these filters is 170ºC.
The filter element are wedge wire with 75 microns.
When the filter is plugged, although the filters are backwashed, the AP don´t go down, and It´s necessary to shut down the unit to clean up the filters mechanically.
We are doing some studies to identify the origin of the problem.
- Filtration studies to cuantify the solids of both of feeds: HCGO has 150-500 ppm of solids, which are mayoritary coke. VGO has 300 ppm of solids, which are mayoritary inorganics particles.
- Asphaltene determination (IFP method): HCGO has 200-500 ppm and VGO has 100-300 ppm.
- Compatibility studies: We have done a compatibility study in laboratory, which consists of adding gradually HCGO to VGO, then the mix is viewed in the optical microscope to identify the asphaltene precipitation. In this study we have seen that the feeds are unstable above 15-30% in function of temperature. The higher temperature the higher unstable is the mix, and the asphaltene precipitate at lower HCGO percentage.
Therefore, we think the plugging problems are due to the precipitation of asphaltene forming an impermeable layer on the filter, which doesn´t disappear even when the filters are backwashed.
My first question is if somebody has experience of this sort of event? We think the solution is not to increase the filter area, but eliminate the problem at its source, to reach a HCGO cleaner wiht less asphaltene content.
My second question is related to the effect the asphaltene precipitation with the temperature. I thought that the higher temperature the lower precipitation but we have seen the oppsoite effect. 		(8)
05/03/2012 Q: I am currently exploring the possibility of selling Slurry as Carbon Black Feedstock. Although most of the expected qualities of slurry are able to meet the specs required of the Carbon Black Feedstock, the slurry is still high in CCR (~20 wt% in Max LPG mode) versus the required spec of < 10 wt%. For an RFCC, is there any operational adjustment that can be done to meet the CCR specs? (4)
15/02/2012 Q: Can anybody help me to calculate the total gas flow in the riser section of FCCU (2)
28/01/2012 Q: In one of our FCC units (Kellog Orthoflow model), we are suffering severe problems of fouling (fines deposition) in the turboexpander. The scheme of the flue gas circuit is: two stage cyclones in the regenerator + Shell Third Stage Separator before turboexpander + 4th Stage Separator (cyclon) to recover flue gas from fines coming from TSS.
We have also observed high level of moisture in the fines from 4th Stage Separator (10-15%wt). So we suspect that the fouling of the expander is due a cold point in the flue gas circuit (where flue gas humidity is condensed) or an uncontrolled inlet of water / steam.
Has anyone experienced this kind of problems in an FCCU? What could be the potential causes of the severe fouling of the expander?
 		(2)
23/01/2012 Q: My question relates to the minimum MAT activity that can be reached in an FCC unit. The main objective in one of our FCC units is maximum middles distillates, and we run this unit at very low severity. The MAT activity of the e-cat is 54-55%wt, with some punctual values of 52-53%wt.
We would like to decrease e-cat activity even further, but we have some concerns and doubts about potential problems that could arise, like definitive loss of cracking activity, significant increase in bottoms production, etc.
Has anyone experience running and FCC unit at MAT activity below 52-53%wt? What problems could appear with so low MAT activity? 		(2)
15/01/2012 Q: My question relaters to the maximum temperature that can be reached in the feed preheater furnace in FCC unit. We operate one of our FCC units in maximum distillates mode and we want to decrease cat/oil to minimum. Currently, we have the following design limits in the feed preheater furnace: 360C (680 F) in the process size and 419C (786F) in the skin points of the furnace tubes. According to a study by our engineering department, temperature in the skin points could be increased to 467C (873F). But our main concern is that an increase in temperature in furnace tubes could cause coking of the feed. Although the feed to the unit is Mild Hydrocracker residue, that has low tendency to coking.
Has anyone experience running FCC units at feed preheat temperatures higher that 360C (680F) in process / 419C (786F) in skin point? 		(2)
26/12/2011 Q: My question is related to the potential problems that could appear when the feedrate in a FCCU is reduced to the technical minimum (turn-down) or below.
- According to your experience, what is the minimum feedrate that can be processed in a FCCU? 60% of nominal feedrate or does anyone operated below this point?
- Which are the most likely limitations that could appear in this point?
1. Insufficient gas flow rate to the wet gas compressor?
2. Insufficient pressure or delta P in feed nozzles? Problems to obtain a suitable vaporization?
3. Insufficient coke production to close heat balance?
4. Insufficient liquid-vapour traffic in the main fractionation?
5. Any other limitation? 		(2)
13/12/2011 Q: My question is related with a problem of copper corrosion strip failure (ASTM-D130) in gasoline. We have two tanks of off-spec gasoline:
- Copper strip corrosion 3B; SH2=0ppm, mercaptans = 9ppm. Does not improve copper strip corrosion test adding corrosion inhibitor
- Copper strip corrosion 2C; SH2=0ppm, mercaptans = 5ppm. Improves copper strip corrosion test adding corrosion inhibitor
My questions are:
- Could the low level of mercaptans present cause a failure in copper corrosion strip?
- Could a NaOH carryover from the Merox unit cause a failure in copper corrosion test?
- Any other sulfur compound, besides SH2 and mercaptans, could cause this copper strip corrosion test failure?
- Does anyone know any commercial additive for mercaptan removal that could be useful for this problem? 		(5)
18/11/2011 Q: Regarding the LPG Sulfrex Unit in RFCC, I have some questions.
We experience the increase of C4 sulfur content last Saturday (11/12) by the forming of the amine absorber(T-20701). ** a brief unit description is bottom of this writing: sulfur content of C4 goes up from 1~3 ppm to 16~18 ppm
Thus we replace the caustic of prewash drum(D-20702) & Extractor(T-20702). But the sulfur content of C4 is not decreased.
Investigating the cause of amine absorber foaming, we find the significant change of amine absorber condition.
First is difference of amine inlet/outlet flow. Inlet lean amine flow is +6~8 m3/hr higher than outlet amine flow in amine absorber.
There is amine carry over to overhead LPG side in amine absorber.
Second is LPG carry under to rich amine side in amine absorber. Rich amine goes with LPG to amine flash drum before amine regenerator.
So the pressure of amine flash drum sometimes rise to almost drum design pressure.
Finally we replace the activated carbon filer in rich amine side, but there is nothing wrong in amine quality.
After that, Inlet and outlet amine flow is same and the delta P of amine absorber increase to normal condition
We wonder why LPG absorber goes back to the normal condition after replacement of rich amine filter.
Q1. Could you explain the reason for this phenomenon?
Q2. If amine quality is main cause, could you recommend the new guide of amine or other countermeasure?
**Brief LPG Sulfrex unit description :
LPG feed from R2R GAS Recovery unit is sent to the Amine absorber(T-20701). Hydrogen sulfide is removed by counter current of amine solution and the LPG leaves the top of the column and flows into the amine settler D-20701 and rich amine is leaves the bottom of the absorber to amine regenerator.
LPG flows into the caustic prewash drum D-20702 for removal the last traces of H2S not removed in the amine absorber.
D-20703 is Caustic Settler. The settler drum allows to separate and return the entrained caustic to the oxidizer T-20703 		(1)
12/10/2011 Q: Are there any rules of thumb for the upper limit for basic nitrogen content and/or feed density in the VGO before hydrotreating is recommended/necessary when the VGO is going to be used as FCC feed ? (1)
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? 		(3)
17/08/2011 Q: Recently we have a failure ( leak ) of RCSP (Regenerated catalyst stand pipe) bellow.
Following are the details of the bellow:
Bellow type : Two ply double elementpurgeless bellow with with pentographic linkage design.
Size: Element Length: 646mm(compressed), 7 convolutions each, MOC: Inconel 625LCF, pipe OD: 1982mm, bellow is providede with equalising & leak detection arrangement, packed with cerawool with wore wire mesh&silica cloth.
Operating temp: 343deg cent, (510 design) with axial expansion 210mm.
Leak detail: leak observed from 2nd crest of the top bellow element (inlet end) at approx 11 'o' clock position looking from outlet end. Opening (crack) was of 3.5" length
We are in the process of analysing the failure, kindly let us know various reasons for failure ? 		(1)
15/08/2011 Q: What is the impact on olefins and isobutane production when slurry oil is recycled? (1)
15/08/2011 Q: Does someone have experience of all feed pump cavitation and subsequently unit trip while changing over the feed pump from one to another. Or what are the probable reasons of feed pump cavitation while doing pump change over? (1)
28/07/2011 Q: I have some question about R2R(RFCC) VOV (Variable orifice valve) in #2 Regenerator Flue Gas Duct .
Recently we experienced the hot spot of VOV Body.
Its temperature by thermo vision is 590 ‘C.
So we concerned about damage of VOV body Refractory.
Could you suggest the possible cause or countermeasure for this problem? (steam jacketing?)
P.S.
In 2010 TA we plugged 5 orifice hole of total 10 orifice hole. And the half of VOD Disc is eroded. And current VOV opening is 65% and Delta P is 1.2 kg/cm2 G. 		(2)
11/06/2011 Q: How can we separate catalyst fines (up to 74 micron size) from RFCCU slurry oil at around 90 - 100 Deg C temperature? Can it be done through filtration and what will be the type of filters, type of backwash required etc? (7)
18/05/2011 Q: Following is a brief overview of the problem we are currently facing at our Diesel Max Unit (Mild Hydrocracking Unit),
Incident:
Our Diesel Max unit reactor having four beds, is equipped with three Quenches. MV for the 3rd Quench Gas Flow Valve started to increase and reached to a maximum value of 100% within 08 hrs. With increase in the MV opening of this Quench valve, flow across the valve remained consistent initially at around 4700 - 5000 Nm³/hr and then gradually started to decrease to a much lower value of 3,100 Nm³/hr at 100% opening at DCS at 70% Unit load.
Observations:
Field observation was taken for the Quench valve and maximum opening found was 85% from field.
Field observation for any abnormal sound across the NRV was checked and found normal.
Similarly, Pressure drop across the reactor in the field on local PIs and across DPT,Delta T and Radial Spread across the reactor beds is observed and found no abnormality.
Actions Taken:
FT installed at the Quench valve was also drained and purged and found no error.
Unit load reduced to turn down ratio.
2nd Quench Gas flow at bed#3 increased to compensate for the reduction at Bed#4 Quench (3rd Quench).
Your expert opinion and guidance is requested on the Issue.
 		(4)
17/05/2011 Q: In case of flue gas power recovery turbine small amount of seal air is always leaking. The temperature of this air is about 200 deg C. Does this create any hot unsafe atmosphere around FGPRT? (1)
17/05/2011 Q: In flue gas power recovery turbine there is small amount of seal air is continuously leaking into atmosphere. Is this condition is acceptable operation wise?  
29/03/2011 Q: What is Reverse seal in an FCC Riser? How to maintain it at a certain value? (1)
23/02/2011 Q: Is there any possibility of an FCC catalyst dust explosion in confined space because of static charge? (1)
18/02/2011 Q: Clarified Oil (CLO) is coming from bottom of fractionator in FCC. Does it relate to catalyst-oil circulation and catalyst properties? How can we reduce the CLO quantity from main fractionator bottom? (3)
17/02/2011 Q: Normally VGO feed temp. in FCC reactor is 350°C-390°C. Because of upstream side heater trip temp. goes down to 290°C.
What will be the effect on reactor regenerator operation? And using this low temp feed can I run Reactor-Regenerator for some hrs? 		(3)
12/01/2011 Q: Is there any commercial FCC process available in downer configuration? Hydrodynamics of Downer favours FCC process but still why there is very little information about downer FCC commercial units. (3)
01/11/2010 Q: I am interested in knowing more about the options of value addition to C4 stream produced in FCC / CDU.
C4 produced consists of a mixture of N-Butane, Iso-Butane and Butylenes.
Following value addition routes exist:
a) Recover Butylenes and convert them to Propylene using OCT (Olefins conversion technology).
b) Recover Butylenes, Isobutane and convert them to Alkylate in Alkylation.
c) Recover Iso-butane and use as a feed to Alkylation.
I would like to know if there are other routes of value addition available or any synergy with a Petrochemical complex. What are the options for N-Butane for value addition? 		(4)
01/11/2010 Q: Can someone advise me of what a multi arm catalyst distributor in the regen looks like? This is with a spent cat riser carrying 100% of air and catalyst. This was a design probably done way back in 1940s (long long before I was born :).. Can someone guide me of how this thing works and even if there are any design guidelines to design one? I have heard of one refinery in California (Martinez) which has this 12 arm distributor, called dodecapus... (1)
15/10/2010 Q: What would be a typical product distribution of Coker light gas oil (diesel range) on an FCC Unit when the Coker light gas oil has gone through a VGO Hydrotreater? (1)
11/08/2010 Q: What is the typical value of Hydrogen content in Coke for Resid FCC? (2)
11/08/2010 Q: What are the potential problems if feed remains un-vaporized because of heavy tail end of the feed? I know un-vaporized feed leads to increase in coke, which eventually burns in regenerator. Does anybody have any experience about how much portion of un-vaporized feed ends up in coke? Also in case of operating unit how one can figure it out whether feed is fully vaporized or not? (1)
30/07/2010 Q: What are the most important aspects taken in to consideration when designing a feed injection system for a FCC reactor? (4)
29/07/2010 Q: What are the potential problems in a feed injection system of using feed containing high carbon residues , i.e. more than 10 CCR? If feed injection through feed nozzles are a problem for high carbon residue feeds, how can such feeds be vaporized efficiently in RFCC reactor? (2)
20/04/2010 Q: What will happen with FCC products if visbreaking gasoline and HDS wild gasoline (H2S content up to 10%) are sent to FCC riser? Will these gasoline crack? Will the olefins be saturated? What will happen with sulphur content in FCC gasoline and could Merox of gasoline cope with that? It is important especially in the case of low sulphur feed at FCC. (3)
15/03/2010 Q: Since FCC feed quality is varying from refinery to refinery due to their own refinery configuration, like some one is using hydrocracker bottom, hydrotreated VGO, RCO, reside, or fresh VGO. Therefore, cost of the FCC feed or VGO is different for all refineries and it may the based on the quality of VGO . What are the parameters which may decide the cost of VGO which may charged to FCC? (2)
09/03/2010 Q: What is the typical phenol content in FCC waste water? (2)
16/11/2009 Q: For FCCU Fractionator bottoms to slurry circulating pumps, is there a preference of side inlet/bottom outlet coke strainers over side inlet/side outlet coke strainers?  
15/11/2009 Q: For the FCCU Fractionator Column bottoms to the slurry circulating pumps, what are the preferred coke strainer types between side inlet/ bottom outlet coke strainer and side inlet /side outlet coke strainer? Are there any precautions to be taken for use of side inlet/side outlet coke strainers?  
25/08/2009 Q: Does anyone have experience with reactor overhead sampling and analyses? Is this technique in use at all?  
24/07/2009 Q: The Delayed Coker Unit (DCU) and the FCC GasCon Dry Gas is treated in an Amine Unit (with MDEA), in order to eliminate H2S, prior to injection into the refinery fuel gas system. However, operational problems have been experienced at the Amine Unit, due to MDEA degradation and the presence of heat stable salts (HSS), among other factors.
We know that HSS formation is due to an irreversible reaction between some contaminants (strong acids anions such as formate, acetate, thiosulfate, thiocyanate and chloride) and the amines molecules. Furthermore, we know that the DCU Gas contains anions such as acetate, formate and cyanide.
However, we have no available information about the contaminant concentration in the DCU Gas or FCC GasCon Dry Gas.
Do you have any information related to a typical contaminant concentration (e.g. strong acids anions) for a DCU and/or FCC GasCon Dry Gas? Moreover, any additional information would be appreciated (E.g. What kind of process do you think would be appropriate for reducing contaminants concentration? We have heard that a water wash stage previous the amine treating could be useful). 		(3)
13/06/2009 Q: Our problem relates to treated gas from Amine absorber. Our plant has SPONGE ABSORBER and water wash for heat stable salt. The treated gas H2S varies from 0 to 600 ppm at same amine flow/ temperature and plat throughput. What are the reasons for H2S variation and how do we bring H2S below 100 ppm? (2)
11/04/2009 Q: Our FCC has a throughput of 1900 Ton per Day. The total gas make of the plant is 24 wt %. The Gasoline make of the Unit is 52 wt %. There is a recycle stream of 8 % from the main column bottom. The Reactor design is having a T type disengager with Rough cut Cyclones. The Riser Outlet Temperature is 496 deg C.
We would like to process 5% Atmospheric Residue (AR) in the FCC. Please give a possible implications for processing AR and steps to be taken for processing the same. 		(5)
19/03/2009 Q: With some experts projecting crude prices to creep back up to $75/bbl by mid-summer 2009, should we expect to see a higher level of refinery intermediates (e.g., heavy gas oil, "lifted" DAO, etc.) being exchanged among "networked" refining facilities?  
18/12/2008 Q: What is the common kinematic viscosity value for slurry from residue processing in FCC plant? (1)
08/08/2008 Q: Are recent improvements to FCC cyclone technology adequate enough to lower solids concentration in slurry oil down to a level (e.g., < 250 ppm) that the slurry oil can be sold without need for filtering? (1)
14/07/2008 Q: What is the typical analysis of a FCC product gas going for Propylene recovery? Please assume an old unit (15 years old). Lower reactor temp. Very less cracked VGO in feed. Lighter VGO with lower CCR.
Compare this with modern resid FCC gas analysis for propylene recovery. High reactor temp. High VGO CCR . Larger % of cracked VGO in feed. 		 
07/07/2008 Q: Under what circumstances is it cost effective to revamp the FCC main fractionator so that the amount of heavy FCC naphtha feed to ULSD hydrotreaters can be increased while still meeting finished ULSD product flash and distillation requirements? Are most ULSD hydrotreaters designed with a three-product stripper using a fired heater, or is a simple steam stripper adequate? (1)
21/06/2008 Q: Is there a noticeable increase in blending clarified FCC slurry oil into No. 6 fuel oil? Since this obviously circumvents the need for blending lighter, higher-value products into the No. 6 fuel oil, how much of an impact on total refinery profitability can be expected? Are some refiners instead opting to use higher percentages of slurry oil as feedstock to a coker unit or a hydrocracker? (1)
12/06/2008 Q: When processing highly aromatic (>650 deg F material) bitumen derived feedstocks through a refinery, they become saturated to various extents due to the primary upgrading and secondary hydrotreating of these heavy aromatics. Therefore, the refinery's FCCU will need to crack a significant amount of naphtheno aromatic ring structures. In order to crack these ring structures to gasoline and distillate, what catalyst functionalities are required to perform these ring-opening reactions? How do these catalyst functionalities differ from those used in processing more conventional VGO feeds, which involve more paraffinic chain (rather than ring) cracking? (1)
28/05/2008 Q: We've been quoted a revamp time for our FCC unit of 120 days, which is prohibitive.
Has any refinery got experience of FCC revamp involving shutdown duration of 35-45 days? 		(7)
01/05/2008 Q: What are the conditions leading to brine production in a Catalyst cooler?  
06/04/2008 Q: Certain refiners are feeding vacuum residue and FCC slurry oil to the coker unit as part of their strategy for reducing (or eliminating) fuel oil production. To this end, what operational and hardware changes should be made to the vacuum tower and FCC main fractionator? (2)
04/03/2008 Q: We have a problem with our Hydrocracker VGO feed filters resulting in frequent backwash operations due to high Del P. Can you please ascertain the reason for the same as we do not get any FeS or suspended solids in the backwash stream analysis. Is it because of the asphaltenes as we process deep cut VGO (360-580+ degC) along with Heavy gas oil? (8)
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.  
21/12/2007 Q: Is there any pilot plant scale-up data available WRT conversion of recalcitrant fibrous biomass materials into "reasonable" quality biocrudes? Do FCC or hydrotreating catalysts suppliers have any specific concerns WRT feeding small amounts of biocrudes into FCCUs or hydrotreaters? (1)
07/12/2007 Q: Can someone tell me how a Millisecond Catalytic Cracker works? (1)
24/10/2007 Q: How do you measure the CO2 emissions from your plant and can you specify the CO2 emissions from individual pieces of equipment? (2)
14/10/2007 Q: in our refinery we treat the LPG produced from the FCC unit by extraction merox unit.
In the pretreatment to remove the H2S from LPG, the absorber shows low efficiency. What is the problem?
(the abs. press. 10.5 bar
amine conc. % vol.= 19
regenerator good efficincy
H2S in rich Amine = 0.034 WT%) 		(2)
13/10/2007 Q: we have problem in our FCC unit where the temperature of the dilute at regenerator is higher than the temperature of flue gas, and we have abnormal loss in catalyst...can anyone help?
 		(6)
16/09/2007 Q: Is Gasoline RON predicted by volumetric blending of different chemical species like MTBE, FCC gasoline, hydrotreated naphtha, straight run naphtha accurate? Is there any way to quantify the interaction between these chemical species and its effect on RON?  
06/09/2007 Q: In the off gases from our vacuum distillation column hydrogen % has been up to 30-35% by volume.This vacuum unit is mild severity dry distillation with designed VGO end point of 510 deg C.
The overhead boot water PH also remains on the lower side (~5) even though the neutraliser is added in large quantities (more than 100 ppm). The same neutraliser has used earlier for the same type of crudes.
Has anyone had this type of experience? What may be the reason for the same? 		(1)
05/09/2007 Q: How can we improve fluidizing in a stand pipe regenerator FCC? (1)
05/09/2007 Q: Why do certain FCC Units need to use CO-promoters? (3)
08/08/2007 Q: What procedure should be employed to ensure that FCC-LPG is on-spec for sulphur and mecaptants (and to meet copper corrosion specs) immediately following startups from turnarounds or outages? Are there any additional best practices for treaters? (1)
06/08/2007 Q: In the FCCU, the main fractionator bottoms slurry settler typically has a pressure safety valve (PSV) for over-pressure protection. Is this PSV sized to relieve pressure from water vaporization that might occur during start-up as the system is heating up? (1)
31/07/2007 Q: Recycle gas compressor of CRU had ammonium chloride salt deposition in its impeller vanes during regeneration activities. Can we wash the rotor with DM water or steam condensate without opening the machine. If yes, can you suggest some guidelines?

 		(6)
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: What role does oxygen availability play in controlling FCC regenerator NOx emissions? What regenerator design improvements are recommended for minimising NOx emissions? (3)