Q & A > Heavy and Sour Feedstocks
Date  Replies
14/12/2020 Q: Here are a few points regarding the desalter issue in our refinery:
1. There are two desalter trains installed in parallel.
2. When the desalter current fluctuates, the brine water coming out of the desalter has an opaque black colour.
3. The events occur only at one train. In this case, the rest of the trains are fine with the same crude. 4. The events tend to occur at crude switch or introduction of slop oil, but this is uncertain.
What are the possible causes? Please advise what we should investigate and analyze to clarify the causes.
 		(4)
23/11/2020 Q: Our company has two serial desalters. Wash water at pH 7-7.5 level is injected, and brine of pH 6 is released. Not long ago, Brazilian crude(Lula) was mixed at about 30 percent, and the pH dropped to 4.5. The TAN value of Lula is low at 0.3 level. I cut naphtha and checked for organic acids, but this isn't a particularly large amount. Our chemical vendor gave the opinion that this was because there were a lot of salts crystallized in the crude oil. However, even after analyzing metal and ash, there was not much. We need to analyze the cause; does someone have similar experience? (4)
01/09/2020 Q: Could you please share your experiences and strategy regarding reprocessing light coker slop? I am interested in a dosing strategy when the tank for light coker slop should be filled by off-spec products during DCU unit start-up only or in case of upsets in the DCU unit; during normal DCU operation light slop should be sent back for reprocessing on the DCU and the tank will be empty till the next shut down.
Do you perform some laboratory analyses to optimize the dosage rate of polymerization additive into the light slop?
 
19/07/2020 Q: We are facing a problem in crude/condensate decanting which is received from local fields. Settling time for the oil tankers is one hour; after this a dip is taken, water observed in the dip is nil. Then we decant the tankers into our crude oil tanks. After settling time for the tanks we are observing raised water level. What can be the potential causes? (7)
04/01/2020 Q: Why is the diameter of top and/or bottom of a VDU smaller than rest of the column? (7)
08/08/2019 Q: Drag Reducing Agent is being added in crude oil during cross country pipeline transfers .Crude oil will be processed in the refinery Crude column along with Drag reducing agent. In crude column the crude oil is subjected to very high temperature . The remains of drag reducing agent after thermal stressing will land in which stream ? (1)
13/07/2019 Q: At our Stripper Column Overhead of Naphtha Hydro-treating Unit , we are injecting pure Chimec 1044 (from CHIMEC S.p.A)which is a blend of polymeric compound in heavy aromatic solvent @ Injection rate kg/hr : 0.02 kg/h of pure Chimec 1044 based on 10 wt. ppm chemical injection rate over the process rate.

Besides, Natural Gas Condensate (NGC) is used as a feed for Natural Gas Condensate Fractionation Distillation Coulmn (CFU) which is a by product from Natural Gas Plant having very low sulfur as well as salt. In fact, we are planning to blend 5% TG with high sulfur (from other crude oil refinery) together with the NGC for processing in CFU .
Can i use the same Corrosion Inhibitor (Chimec 1044) at the overhead of our (CFU)? 		 
12/06/2019 Q: What are the particular properties of Kissanje blend crude oil and the problems that might be encountered during its processing?  
31/05/2019 Q: What are the treatment methods for removal of butyl mercaptan from LPG stream? (2)
24/05/2019 Q: We have a problem at our CDU. It is observed that when we examine salt content at the start of crude charging tank after giving it 24 hour settling time, salts are in yhe range of 2 to 5 PTB. But when same tank is charged and sample is taken at CDU upstream, salt content is higher... Up to 50bPTB... What could be possible reasons? (7)
14/03/2019 Q: Our refinery has installed corrosion control system (filming and neutralizing amine injection) in our overhead distillation column system. However, since the water content isn't too high, we cannot have enough sample from water bootleg. Our Fe content in water bootleg sample is quite high (>100 ppm) with previous injection of filming amine is considerably high (up to 18 ppm). The chemical vendor suggested us to install wash water system. However, install wash water system may take longer period and we wonder if continue injecting amine is still effective without wash water system. Have anyone had this kind of experience and is there any suggestion to keep the corosion controlled without wash water system? (3)
18/12/2018 Q: I saw an answer in Q&A, that portable electric desalters will screen the demulsifiers. I would like to screen some of my demulsifiers using portable electric desalter (PED). Can anyone suggest the suppliers of PED? it would be a great help. (3)
13/12/2018 Q: Reprocessing slop oil is always a headache issue for refiners, in our refinery, we blend recovery oil (one of slop oil from crude tank cleaning) into heavy crude slates (API<28), but suffering problem on desalter operation, higher emulsion layer led to electric field trip and desalter brines contain oil which can result wastewater treatment plant in upset, we would like you could share the operating experience on reprocessing slop oil with minimal impact on these facilities, thank you~
Questions
(1). What kind of pre-treating methodology did you apply on slop oil before reprocessing? Water separation or any filtration steps?
(2). Did you use chemicals for slop oil pretreatment?
(3). How did you reprocess slop oil? In-line injection into CDU uint or blend slop oil into crude tank?

 		(6)
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.
 		(2)
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? 		(6)
27/06/2018 Q: High content of solid particles in crude oil or Delayed Coker feed can cause accelerated fouling in the furnace.
Has anyone experience on how to measure solid particles concentration and particle size distribution in crude and/or vacuum residue? I have seen the use of laser difraction or particle counter for other products (kerosene, lubricants, etc) to measure both total content and particle size, but I am not sure if this could be succesfully applied to vacuum residue.
What is the maximum solid concentration recommended to avoid fouling issues?
What is the maximum solid particle size recommended? 		(4)
17/03/2018 Q: I have a question on determining if the atmospheric residue is lighter from the atmospheric distillation unit. I know I can compare the T5 distillation of my residue to see this has been lower than historical values... I think if I were to check the delta across my stripping section has increased with a constant stripping stream ratio, that'll probably give some indication too.
Does anyone know what other methods can be used to check if I am actually dropping any HGO or light molecules down to the atmospheric resid layer?

Conclusion:
Yes, I have compared the T5 of my residue and also the T5 of the vacuum tower feed and they are lighter. My stripping steam, FZT were lower than usual during those period while my FZP was higher. I think in conclusion, those should have actually caused the drop of lighter molecules to bottoms due to insufficient uplift of molecules. 		(2)
24/09/2017 Q: I'm working in fixed bed catalytic reforming plant and would like to ask you about measuring the R-86 catalyst lifetime to help me out to initiate the catalyst utilization plan during the existing cycle. Also, has anyone have a catalyst performance report who is willing to share it with me to use it as a guidance when writing mine, it would be highly appreciated. (2)
24/03/2017 Q: I am facing an unusual problem of a localized fouling in vacuum column top section and i am trying to develop a solution for the ongoing problem , i am looking for any advice or insights or even prior experience with similar problems , any contributions are highly welcomed .
My problem is periodic formation of semi-solid fouling in the top section of the tower despite of operating at relatively low temperatures (Tray temperature 185 C ) and low Pressures (-0.955 kgf/cm2) , i assumed that cracking or coking at this conditions is highly unlikely at this conditions (correct me if i am wrong) and i assume that the problem might be caused by phase separation of asphaltenes entrapped in light hydrocarbons .... is there any way to exactly determine the problem , what kind of lab tests can be done? any one faced similar problems in vacuum columns?

Additional:
Thanks all for your valuable answers , I want to add some missing information to the original posts , first of all the fouling color is blackish and the top tower temperature is nearly 85 C ....the fouling seems to be of a hydrocarbons origin.......... it was noted that the fouling increase with the increase of overhead temperature
what steps and lab tests can i do to exactly characterize the fouling?

Further:
We Analyzed the solid fouling using x-ray analysis , it was 98.9 % Hydrocarbon, 0.7 % Sulfur , the rest are trace metals with various low percentages (0.01 ~0.02 % ) ... the lab analysis didn't indicate any chlorides , i am not sure if the x-ray analysis can or can't detect chlorides but will discuss it with the lab chemist , most of the replies suggested ammonium chlorides , but apparently it isn't the case.... 		(7)
16/02/2017 Q: We observed that our crude unit naphtha stabilizer column overhead water has become decolourized since few days. The colour is yellowish to brown. However, the main column overhead water is clear in colour as previously. Can anyone help me in identifying the possible causes for this? Some forming also has been observed while draining this water. Can overdosing of corrosion inhibitor (filming amine type) cause this issue?

Further info:
Thanks for valuable answers. The colour was observed while draining of the vessel boot. So, there is no much time to react with atmospheric oxygen. Is it any dissolved oxygen that react to give the colour? Also, I found some evidence of overdosing (almost double ) of the corrosion inhibitor for a short period of time. Once it was corrected the colour was improved. But, not sure whether it is due to that or due to anything else. 		(3)
03/01/2017 Q: We are facing plugging of 350 distillate pump strainers in the VDU (lube oil refinery). The 350 distillate is the middle cut of the distillation column.
Since Sunday, the pump strainer has been cleaned more than 5 times due to coke deposition. All operating parameters have been compared to the PFD and no deviation has been observed except that the pumparound flow above the 350 distillate bed is less than the required.
Also this problem started after a revamp on our vacuum distillation column in 2013. Since then there has been severe coking in this pump and it requires monthly cleaning. But as of now the problem has become severe and the strainer is getting plugged in a matter of hours.
Your advice/insight on troubleshooting the problem will be appreciated.

Additional info:
We have sent the samples for analysis and are waiting for the results.
The heater skin temperatures were running high, and we adjusted it.
However, we are still seeing coke in the strainer. Although the frequency of plugging is reduced.
How can I increase the flow on the 1st pumpdown. The flow of the 2nd and 3rd pumpdown is above 50 m3/h but the 1st pumpdown is less than 35 m3/h. 		(5)
22/12/2016 Q: We are operating CDU/VDU @ 110% throughput.
We have a Demister Pad installed at the top of the vacuum column.
The DP of the demister pad is increasing @ ~1mmHg/10 days. This is resulting into higher Flash zone pressure causing dropping of Vacuum gas oil into Vacuum residue. We operate the column at 23 mmHga top pressure.
Also we have noticed chlorides in our Vacuum diesel stream (First side cut of VDU) in the range of 10-20 ppm w.
What can be the cause of this fast increasing DP and what measures can be taken to arrest that?
(9)
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)
12/12/2016 Q: In our Naphtha Stabilization unit, feed after preheating leaves the HE through a 10" dia pipe and then immediately split in to two vertical risers of 4" dia and again joins back to a 10" dia pipe before entering the stabilizer. What is the purpose of this risers with reduced dia? In P& ID it is mentioned as two phase flow. (2)
08/10/2016 Q: Question is based on Desalter operation.
1. What can be possible reasons of mud in brine but no traces of oil during normal desalter operation? Is desalter paramters temperature, pressure and mixing delta P plays any role in it?
2. What is the role of Pressure and Temperature in desalter operation?
3. On what basis, Transformer KV setting to be changed in desalter?
4. What is the role of Mixing Valve DP in desalter operation and when does it require to be changed? 		(2)
29/08/2016 Q: In the vacuum distillation unit, we face problem with Gas Oil end point i.e., VGO 95%, Anyone have any idea how to solve this problem or anyone have seen this in any refinery? (5)
12/08/2016 Q: I have a question regarding desalter brine quality, as follows: The desalting of same crude is done by two desalters of different geometry (not two stage desalting, two CDUs). I underline that desalting is done efficiently in both units with respect to salt content in desalted crude. The difference is in the content of sulfides in desalter brine. The desalter that has lower sulfide content in brine is more cylindrical, while the another one "tends to be more spherical". The higher sulphide content represents higher load for waste water treatment plant. My opinion is that this behaviour can occur because of longer residence time of oil and wash water in emulsion volume (or the volume ratio of emulsion volume and total desalter volume). I think that perhaps the emuslifier dossage or or delP on mixing valve are higher. Has anybody faced similar issue in the refinery? Any opinion and experience would be helpful. (2)
28/06/2016 Q: Is it possible to remove metals (Fe,Ni,V) from vacuum slop or vacuum residue streams? If yes, how? (3)
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)
31/05/2016 Q: Our client has recently started processing heavy crude slates from Western Canada. They are having an issue with their Desalter Brine Treatment Unit (BTU, which is a pre-treatment plant for oily solids removal before being sent to the de-oiling train) with higher than design temperatures and light hydrocarbon carry over. Does anyone have experience with this issue? Is steam stripping prior to BTU an option for dealing with this issue?

Additional:
Thank you for the responses so far. This has provided some insight into the issue. As a follow up, is there any experience with steam stripping of the brine. I believe some refineries in US have this unit for BTEX removal. How efficient would this be for light hydrocarbon removal? Also any insight into requirement of an equalization tank upstream and if solids removal is recommended upstream of the stripper? 		(4)
10/05/2016 Q: Our crude vacuum distillation column overflash pump suction strainer gets fequently full of coke.
Overflash pump suction temperature is 374℃~385℃, flash zone pressure 21mmhg, top pressure 5mmhg.
Metal contents of overflash are 154.7ppmw(Ni 36ppm, vanadium 118.7ppm) and Metal contents of Vacuum Residue are 223.8ppmw(Ni 49.2ppm, Vanadium 174.6ppm). How can we prevent this? 		(7)
25/04/2016 Q: We are looking at alternative option(s) that could expedite the unloading of residue desulfurization unit catalyst (from reactors) other than typical vacuum-out/jack hammering approach.
We have heard about the CO2 explosive technique - and just wondering if anyone has any success stories with that?
Any other feasible approach to be explored?
 		(4)
10/03/2016 Q: Does anyone have any experience in using fuel oil for heaters/boilers firing?
What is the typical size of bucket filter (i.e. mesh size) at pump discharge that supplies acceptable particle size to the burners?
What would be the typical minimum filtration size, anything lower than < 10 micron with bucket filter? 		(2)
04/12/2015 Q: For the first startup of crude distillation unit, since we did not have any startup gas oil for flushing procedure (cold and hot circulation), we used the crude as flushing stream. According to operating manual, after establishing of gasoil we should store it into relevant storage tank and then stop the process. After that we should flush the system with existed gas oil, again. I want to know, when we are producing gas oil why should we stop the process and go back to flushing mode? (4)
16/11/2015 Q: We have recently observed a high production of off-gases from our Vacuum Distillation Column. We performed the distillation for the feed and observed that the initial and 5% boiling point had reduced significantly. Could this be the reason for the increase in the off-gases?
On the other hand, we suspect an air ingress into the system. Is there is any way to detect/prove that there is an air ingress into the system?

Added by questioner:
Thank you very much for your input. I gained a lot of insight from your answers.
After closely studying all your suggestions, we took into consideration a number of points and implemented them.
One of them was sampling the off-gases, from which we found a high % of Nitrogen which clearly indicated air ingress. As a result, we tightened the transfer line gasket and the off-gases flow reduced by 50%.
Thanks once again.
 		(6)
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)
30/04/2015 Q: we are facing problem of high skin temeprature in one of the pass of CDU charge heater (106,000BBl) refinery. After thermography, it shows even more. we have done following actions:
1. PUT manual the FC for that pass and manually maximized the flow through this pass only.
2. shut off the burner adjacent to this burner.
3. can not do the decoking for the crude heater. Furnace's Pigging is planned next year (2016).
But now, we are going to inject the LP steam online into one of the pass. LP steam is used only in case of:
- Furnace tripped due to pass flow low low.
- Furnace tube fire case.
What possible outcomes we can expect with this activity? will it benefit? is there any other technique to remove spalling?

Outcome:
Thanks for valuable comments.
In recent shutdown (planned turnedaround of the plant), we have managed to perform pigging of crude heater and after that, results are much better. no more skin temp issues. We have done pigging for pass more time, tube conditions are normal now. 		(4)
05/04/2015 Q: Are there approaches/techniques/instrumentation to gauge if you have fouling occurring (from salt deposition) in top trays on crude unit? One can measure top section tray DP, however, the DP may take time to build up. Are there other things besides DP that may give you quicker response on fouling taking place in top trays of crude tower? (2)
27/03/2015 Q: We are process tar sands crudes at this refinery. The issue is with our vacuum unit steam educators in the VDU, the primary inlet screens are plugging up. We inject a amine neutralizer into the steam to protect the vacuum condensers piping from corrosion. The steam flowrates have reduced drastically. If you have experienced similar issues please let us know. even though we have redundant eductors (3 in parallel) we would like to understand the root cause of the fouling. the deposit analysis have shown major components as C & O. N is also present in addition to Zn.  
13/03/2015 Q: Salt content in desalted crude oil should be less than one PTB. However due to some reasons the salt content of desalted crude oil is higher than a PTB , what can be the effects , or the changes it can create in the downstream process? (6)
18/01/2015 Q: When water travels with crude, through furnaces into the crude tower, what process indications reflects on process parameters/tower profile? (5)
10/01/2015 Q: Electrical Conductivity of the Turbine Fuel decreases with time , if it is 700 picosiemens at Merox outlet and after few days it declines to nearly 100 -200 picosiemens in the tanks, it is a normal phenomenon. We had found in certain cases the electrical conductivity has increased twice the observed value. Caustic, Surfactants were not found in the fuel. What are the reasons or factor , electrical conductivity of the fuel can increase ? (2)
20/10/2014 Q: What quantity of steam is required in distillation column and side strippers per barrel of crude/products. (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)
17/07/2014 Q: Need all your expert views on crude oil Basic N2 impact on fouling tendency. This is limiting on crude flex/ optimization as the refinery has CAM limit for basic N2 (150ppm). Need to understand the fouling tendency of Low N2 crude whether this is credible or perceived. Also understand the fouling tendency/reversibility. If credible, please provide if there are ways to mitigate (eg: every low N2 crude processing is followed by crude that can act as cleaning and recover any loss in duty?)
Low basic N2 could be good for LRCCU feed and also hope for HCU where as this limit could restrict such crudes from buying/processing… We always used to be on the basis of waxy vs. asphaltic… every waxy run followed by a aromatic/naphthenic crude run to provide cleaning effect. Antifouling was other alternate only in LR circuit and /or SR circuit.
Blending of crude based on compatibility to mitigate was another option…
There should get some clear guidelines for mitigation if the impact N2 is credible and proven… can you provide any such details and what is minimum technical solution for such mitigations as this will be a clear big lever for crude flexibility.
 		(1)
18/06/2014 Q: Do anybody have experience in treating Brine from desalters through Tricanters to separate Oil and sludge from Brine? (2)
29/04/2014 Q: We are processing a heavy crude of API 18. Salt content of the crude is 80-100ptb. BS&W is 0.8 to 1.2%.
We are using stripped sour water as wash water, made up by BFW. pH of wash water is between 7-7.5.
We are maintaining a desalter temperature of 150 deg C.
We are having two desalters in series, which is supposed to bring down the salt by 99%. but we reached up to 90% earlier.
Last two months we are having a high emulsion band. The BS&W of desalted crude is 2-3 and the oil in brine is 1-2% even at minimum delta P (0.3kg/cm2). Water injection rate is 3% to individual desalters (circulation not done as oil carryover with brine observed.
The voltage across the grid is as low as 6-10 KV (Tapping at 22KV). We have changed the secondary tapping to 18V and the deslater is showing an improvement in Voltage (10-12 KV)
1.what can be the reasons for this upset?
2. Can you explain the effect of change in secondary voltage?

Additional info:

We are not adding any scavenger to the crude.
Stripped water pH is 6-6.5 and brine water pH is in 7.5 range.
What parameters of crude oil should I check? 		(4)
21/02/2014 Q: In the crude distillation unit, we face problem with Gas Oil colour. Any one have any idea to solve this problem or any one have seen like this in any refinery?! (8)
31/01/2014 Q: Currently I am working in upgrading onshore crude facility plant we have a sour crude stripper column for H2s removal after desalted/dehydrator while existing plant having H2S stripping column first then crude is going to desalted/dehydrator. Is there any reason why? And is there any effect in desalted/dehydrator operation due to H2s presence in crude? (1)
10/01/2014 Q: We have a single stage desalter that will run more heavy crude about API=23, Wash Water about 7%, T=280F. There are 2 Transformer about 150 kVa each. Is there a good way to assess what this existing transformer can handle in term of max conductivity of crude ? Are there easy calculations one can do if you had crude conductivity, etc? (2)
10/01/2014 Q: For an existing single stage deesalter operation that plans to run a heavy crude API of 26, wash water 7%. Vessel has two 150 kva transformer. Are there easy ways to see what is the max crude conductivity that this existing desalter grids can handle? Are there any general guidelines to make such assessment.  
05/09/2013 Q: We operate our DCU main fractionator with Top Pr. 0.57 Kg/cm2g & Top Temp. 99 Deg C. We process VR with more than 5000 ppm normally. Recently column DP fluctuated a lot and we suspected salt deposition in trays. Steam was increased and DP become normal. Queries are:
1. How to calculate salt sublimation temp? What parameters I need to look into?
2. How to estimate salt quantity?
3. What are reasons for salt generation in system?
4. What kind of salts are expected - organic or inorganic?
5. Is it possible that if salt sublimes once and again it becomes vapour once temp increase ie. is phase reversal possible?
6. What are industry best practices to remove salts deposited?
7. Is there any way to avoid salts formation in system or avoiding ingress?
8. Any crudes responsible for high salts or its caustic dosing at crude desalters?
 		 
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)
26/05/2013 Q: Can anybody tell me the approx. cracking temperature of ADNOC Murban crude oil having API gravity 40.5?  
19/01/2013 Q: Why does the stripping steam trip close when there's a high level in tower? (3)
09/01/2013 Q: What was the particular properties of Napo crude and the problems that might be encountered during its processing? (1)
07/08/2012 Q: Our Desalter transformer has got three transformers supplying to individual grids. This step up transformers are facilitated with three outlet tappings with higher ratings. We always run the desalters with same outlet tappings for all three transformers. Is it advisable to run it with different outlet tappings in all three transformers in a desalter?
I would like to know electrical feasibility as well as process advantages? 		(2)
30/06/2012 Q: I am trying to build a model to optimize the operation of Crude Desalter and study its effect on Crude Column Overhead Corrosion.
The major salts present in Crude are NaCl, MgCl2 & CaCl2; but in our laboratory we measure only Total Salt Content of Crude (before and after Desalter); we do not measure individual salt.
My queries are:
1) How the individual salt affect Desalter performance and Crude Overhead corrosion
2) Is it required to measure the individual salt's content in Crude?
3) Can I assume some typical break-up of individual salt (Note that the type of crude we process changes very often).
 		(1)
13/06/2012 Q: Crude oil is likely to contain mercury as pure or as compound e.g. dimethylmercury. I would like to know if somebody can provide level of mercury contamination of crude from different sources. (4)
15/04/2012 Q: We need to build very small vacuum distillation unit . We cannot find out how many of oil will crack and we cannot evaluate how many m3 of gases will be generated . So our questions:
What should be a capacity of vacuum pump in m3 per 1t/h ?
How many gases are usually released ?
or give examples from your plants.

 		(2)
28/03/2012 Q: I have following questions on desalter:
What is typical salt content at crude out from 2 stage desalter?
Does mixing of crudes result in more salt slip from desalter than design?
Does wash water salt content affect the salt removal efficiency (more salt comes out from desalter)?
Does inadequate/inefficient demulsifier result in more salt slip from desalter than design?
 		(4)
16/03/2012 Q: if we want to reduce the Hydrogen purity in DIESEL HYDROTREATER the current H2 purity is 99.99 fro PSA Unit now we want to take from other plant (Rheniformer units),During hydrogen plant turnaround, PSA’s are not in operation and only the off gas from Rheniformer units, low purity hydrogen, is available. This make-up gas can be used as hydrogen for the DHT to keep it running for the duration of the whole hydrogen plant outage.
the hydrogen from PSA :
HYDROGEN ------> 99.99
C1------> 0.1
CO + CO2 -----> 20 MAX
H2S ----> ZERO
HCL < 1
***** new hydrogen make-up with a reduced purity, coming from Rheniformer units
H2 87.5
C1 5.8
C2 3.6
C3 1.6
C4 0.4
C5+ 1.1
- what is the side effect of low purity for all the plants, recycle compressor, make up compressor and the load in addition the make up it is suitable for for such low purity?
What is the impact on
-Reaction section
-Product quality
-Recycle compressor?






 		(3)
14/03/2012 Q: After commissioning of distillation unit we found that one of the passes of atmospheric furnace has encountered coke formation problem at the end of radiation zone. Is there any solution to continue the distillation process without doing shut down.
 		(3)
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)
21/11/2011 Q: We are having a NATCO EDD desalter in one of our crude units and of late we are facing reduced desalting. The outlet salts have been consistently above 1 ptb and sometimes we find inlet and outlet salts to be almost equal. we tried to balance the salt removal across the desalter and tried to do a chloride balance across the crude/prefrac columns, but unable to close the material balance. (4)
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. 		(3)
30/10/2011 Q: With regard to application of catalysts in Isomerisation process, I would like to know about the overall comparison between tradition catalyst i.e. Aluminium Chloride and novel catalysts based on platinium element. In point of view of economical criteria which case has been suggested? (3)
09/08/2011 Q: What are current views on twisted tube heat exchanger configurations in refineries, particularly in comparison with conventional shell and tube configurations? (7)
11/05/2011 Q: Our de-aerator conductivity is running high while de-aeration pressure is 0.3 kg/cm2g and temperature is 107 to 110 degree centigrade. Any thoughts on reasons and solutions? (3)
22/01/2011 Q: To what extent can we blend fuel oil into gas oil without affecting the viscosity characteristics and maintaining the flash point specifications for gas oil or to keep them within the allowed limits?

Additional info:
First of all we don't have neither FCC, Hydrocracker nor VDU...we only run a conventional CDU
the objective here is to maximize the yield of gas oil...(we call it solar in our national markets) by extra stripping out from fuel oil or residue...the question is; Is there any equations or experimental methods to calculate or estimate the resulting viscosity and flash point of either the gas oil or fuel oil?
Thanks a lot. 		(4)
09/11/2010 Q: Can you please advice what type of corrosion inhibitor, biocide, antifoulant and polyelectrolyte polymer can be used in Desalter effluent? (4)
09/10/2010 Q: My company aims at further processing the atm. distillation residue (Mazot); and a hydrocracker unit has been chosen for this task. We need to estimate the cost of the unit and its facilities like the vacuum tower and the vis-breaker. How would you suggest we get a rough initial estimate of the costs involved? (5)
25/07/2010 Q: Are variable speed drivers ever used in pumps?
If not, why not? 		(4)
08/07/2010 Q: We have a very strange problem, it's that the desalter outlet crude has greater salt content than that of the inlet... the lab examinations proved that more than once...this always happens when the injection water is cut off-while switching from a tank to another. What could explain this?

Additional info/response:
1. We cut off water while switching between tanks because of the existing water accompanied with the crude from the new tank; I mean the first 30 minutes after switching to a tank, the crude has too much water to inject more.
2. How could the NaOH type could affect this situation? 		(10)
06/07/2010 Q: What is the best way of judging the efficiency of a desalter? (6)
09/06/2010 Q: In our atmospheric distillation unit , reduced crude recovery was constantly coming 10-16% @ 360 deg C. We increased the bottom stripping steam but we are unable to decrease beyond 10%. Are there any other ways to improve the efficiency? (6)
21/05/2010 Q: What are the likely effects of water carry over from desalter on Crude heater and distillation column? What steps should be taken if this happens? (11)
19/05/2010 Q: Does installaton of static inline mixer in place of conventional mix type globe valve for mixing the wash water and crude before desalter help in improving desalter efficiency? (4)
18/05/2010 Q: In our Crude Unit we have LGO pump around heated Light kersosene stripper. The reboiler is no longer giving heat duty and hence Kero flash became limiting. We put stripping steam also in kero stripper, but no gain in kero flash.
Is anybody using antifoulant for correction? 		(2)
18/05/2010 Q: Does injecting wash water ahead of preheat exchangers improve desalter efficiency? (3)
13/05/2010 Q: What are the benefits of a top fired reformer versus a sided fired one? (5)
06/04/2010 Q: We are injecting Gaseous ammonia in crude column overhead line, also circulating the wash water in overhead line.
We are also injecting caustic in desalted crude. Corrosion is mostly due to desublimation of salt. Can someone recommend how we can avoid corrosion in overhead line? 		(5)
03/04/2010 Q: What are the possible reasons for increase in COD value of Brine. Is there any relationship with crude property? (2)
03/04/2010 Q: In our refinery Crude column overhead liquid is condensed in Fin fan coolers. Condensed liquid then collected in receiver. Recently we had problem of severe fouling in fin fan coolers inlet line. Can you explain the possible cause for that? Also suggest some recommendation to avoid such kind of fouling in fin fan inlet header. (4)
29/11/2009 Q: I am a Shift supeintendent of the CDU unit.
We could not stabilize the Brine treatment package - Hydrocyclones to separate the oil and sludge from the Brine of the Desalter outlet.
If anybody have the experience regarding the operations of Hydrocyclones (Brine treatment package) in the Brine system, please share with me.
If I can get the optimum dela pressure across, it will be helpful; I could not follow the vendor operational guidelines as it is not performing good. 		(3)
25/11/2009 Q: Do anyboby experience fouling in the preheat trains while processing Doba crude in CDU/VDU?
I heard that doba crude by nature is a solvency crude which won't foul the exchangers. Is it true?
Now we process the Doba crude with minimum of 4% and we want to increase the percentage.
What are the constraints while processing Doba and what pecentage can be added with some allowable constraints in hand? 		(2)
24/11/2009 Q: I am working as a superintendent in CDU/VDU unit.
We experience increase in the VDU off gasses due to cracking. We inject the Turbulising steam in the inlet and also before exit of the Vacuum heater pass flows. We never adjust the steam flows to see the reduction of cracking. We set high flow in the first tube pass and low flow in the last before tube of the exit.
Please share your operational experience in reduction of cracked off gasses from the VDU unit. 		(3)
24/11/2009 Q: I am shift superintendent working in a CDU/VDU unit. We face a problem of maintaining the flow rate of Heater recycle oil (Overflash in Vacuum column which normally contains 50-50 of HVGo-VR). We process the API of 24 and 29. We take LVGO, HVGO and VR products and the HRCO is being recycled back to the vacuum column through heater.
The HRCO generation suddenly drops down and increases due to some problem. We raise the HVGO IR and alter the coil outlet temp (COT) of the vacuum column to maintain the HRCO generation fearing that we could end up in coking up the packing bed. Furthermore we experience the packing bed Delta Pressure high across it. Hence we could not raise the temp of COT and reach the deep cut HVGO.
Please explain any of your experience into this particular subject. 		(5)
18/08/2009 Q: Is there an an agreed percentage of sulphur that determines whether a crude is classed as low or high sulphur? (3)
12/08/2009 Q: In DHDT unit suppose benzene converted to cyclohexane and then cyclohexane converted to normal hexane. What is the mechanism of this reaction? How is aromatic converted to cyclohexane then how cyclohexane ring broken and converted to n-hexane? (3)
11/08/2009 Q: My question concerns narrow or "light" naphtha. As a broker and trader, most of the product I see has an IBP (initial boiling point) low range of 40 degrees Celsius. I have a client seeking to purchase product with specs stating 35 degrees. I believe this to be highly unusual, or is this a common specification? Please advise. (2)
31/07/2009 Q: I am doing some research on the Cameron acquisition of Natco and was interested in learning if desalters are sold in the United States. My understanding is that they are installed in refineries when the refinery is built and inasmuch as there is no new refinery construction there are no desalter sales in the USA. Is that correct? (3)
12/07/2009 Q: What is the limitation of sulfur in a crude classified as a 'sweet crude' or what's the maximum amount of sulfur in a sweet sulfur beyond which it falls in the class of "sour crudes"? (2)
15/06/2009 Q: In technically evaluating any crude prior to its processing at a hydroskimming refinery, what is the significance of following properties of the crude:
Its Reid vapor pressure (RVP)
Total acid number (TAN)
Mercaptans sulfur
H2S
Pour point
Calorific value (Gross)
Copper strip corrosion
Conradson carbon residue
Kinematic viscosity @ 40C 		(2)
11/06/2009 Q: What is the advantage of heavy atmospheric gas oil draw in a crude column? Is it possible to provide a new heavy atmospheric gas oil draw for our crude column operating with 24 trays, diesel draw is between 11th and 12th tray, flash zone between 6th and 7th tray? Column operating pressure is 1.6kg/cm2 top. diesel draw temp is 300 degC. (1)
28/03/2009 Q: What is lube oil supply temperature for any pump or compressor? Like feed pump, makeup gas and recycle gas compressor. (2)
25/03/2009 Q: Why do we need to maintain gas oil ratio in our diesel hydrotreater? (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?  
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)
10/03/2009 Q: Is it possible to efficiently clean asphalt tank cars without excessive tank entry? (3)
09/03/2009 Q: Why is a minimum circulation line not provided in some centrifugal pumps? For instance, in our stripper reflux pump it is provided, while in our diesel hydrotreater stripper it is not. (2)
04/03/2009 Q: What is the exact meaning high/low severity in case of refinery catalytic unit? (5)
23/02/2009 Q: What are the methods to estimate cracked gas production in Vacuum Column (or Heater)?
Are there any correlations in the form of other process parameters?
Can anybody suggest the literature regarding this? 		(2)
07/02/2009 Q: Where can I obtain information about Vacuum distillation unit overhead sourgas minimization?
What are the parameters that effect the sour gas generation rate? Are there any correlations available to relate those parameters to sourgas rate?
What are the methods and ways to minimize the cracking of reduced crude oil in vacuum unit charge heater? what are the main effecting parameters of fouling the vacuum charge heater? 		(4)
03/02/2009 Q: Can anyone reference an article or research that comments on the effect lubricating oil from the makeup or recycle H2 compressors can have on catalyst life? (5)
16/01/2009 Q: If we process High TAN crude, what will be the consequences in ATF Merox Unit? Is there any effect on the ATF specifications? (1)
01/08/2008 Q: Can I use a jet mixer instead of conventional mechanical agitator in a tank stored at 55 deg C? (1)
17/07/2008 Q: Why aren't nano-scale dispersed catalysts for upgrading heavy crude gaining traction in the industry considering that their yields are reported to be >90%? (2)
22/06/2008 Q: How do you determine the cracking temperature for unknown heavy crudes in Atmospheric heater and vacuum heater? For vacuum heater does this cracking temperature depends on the vacuum and coil steam? Are there any lab methods or correlation methods to determine this? (1)
23/05/2008 Q: We have local crudes which are very waxy in nature. The reduced crude from these crudes has a wax content of 40 pct wax and 1 pct asphaltene. The pour point is very high requiring cutter and depressant.
We were thinking of a thermal process like visbreaking or thermal cracking, but this resid is very light and quite a lot of it vaporises at common visbreaking condition unless pressure is increased substantially.
We are trying some pilot runs using makeshift arrangement. Has anyone tried this for light waxy feed and what were the results and operating condition used? 		 
01/05/2008 Q: What are the conditions leading to brine production in a Catalyst cooler?  
29/04/2008 Q: How does the quality of wash water affect the desalting of crude? what are the parameters based on which quality of wash water is decided for desalting? (2)
27/04/2008 Q: How does presence of ammonia in the wash water or crude effects the desalting process? Does ammonia acts as an emulsifier that tends to cause lower desalting? (1)
25/04/2008 Q: Is there any non-manual method for cleaning tanks used for asphalt storage? We dilute as much as possible with recirculating hot HVGO, but we have to finish the job removing a several inches layer of sticky asphalt. (4)
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)
05/02/2008 Q: Heavy crude oil desalting in electrostatic desalter designed for normal crude creates interface level problem and results in more oil in desalter effluent. What best operating and design practices should be followed to overcome this problem? (8)
05/01/2008 Q: Do high nitrogenous crudes like plutonio, oman blend, zafiro play a role in deteriorating ATF saybolt color (KMU product), and if yes and if any detail analysis for such color instablity has done in the past, what is the correlation? (2)
09/11/2007 Q: We are looking for a chemical which can be used for removing Ni and V and also Fe from our hydrocracker unit feed (MVGO+LLC) by injection it to feed.
Also we think it is possible to eliminate these metals from crude oil source by adding chemicals to crude oil and removing metals in desalters.
Can anyone help us? 		(1)
05/09/2007 Q: We are trying to add heat to the front end (feed stream) of a vacuum unit (part of a crude unit) and wonder if anyone has done this in recent years by using skid mounted equip of some sort or small "package" units of exchangers/heaters, etc. We only want to do this on a temporary basis, say for 4-6 months (1)
05/09/2007 Q: What kind of additives are recommended for injecting in crude while processing high TAN crudes to prevent corrosion and fouling of preheat train / exchangers in general. Please provide commercially available additives / supplier details. (2)
04/09/2007 Q: Is designing wash section critical in vacuum column if my objective is to get only asphalt from vac column bottoms? VGO we will be selling as fuel oil.
Now it is a dry vacuum column. Is it possible to convert this into a wet vac column?
I am able to match the Flash zone temperature with HTSD data for RCO without assuming entrainment as mentioned by Golden in Deep Cut Vacuum feed characterization article. So can I assume the actual entrainment would be zero? 		(2)
24/07/2007 Q: What are some of the most appropriate technologies for upgrading residue? (3)
24/07/2007 Q: What processing capabilities should refiners have in place if they plan to process heavy sour Canadian crudes? (1)