Q & A > Coking
Date  Replies
30/03/2017 Q: What is the typical composition of VGO (Vacuum gasoil) and what is its cracking temperature? (3)
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....
(6)
21/03/2017 Q: ASTM D2887 method claims to be applicable for petroleum fractions having FBP up to 538 C.
But, as per method, GC is typically operated within range of 360-390 C.
So, is it possible to vaporize HCGO (370-530 C) sample (0.5-1 micro liter) at this operating temperature and hence, evaluate the TBP profile of HCGO?
(2)
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)
16/12/2016 Q: Can anyone pls let me know the best practices being followed in the industry to estimate the Delayed Coker product yield and qualities wrt to feed properties.
(4)
02/08/2016 Q: We are going to plan for introducing PFO in our delayed coking VR feed (not more that 5 MT/Hr). PFO having higher diolefine content. as i heard that it can create problem in down stream unit hydrocracker like gum formation. so kindly give your comments can we go for PFO introducing in VR feed? what actions we have to take before introducing PFO? can diolefins create problem in our heater? because previous study tells that high parafinic & napthanic feed not good as a feed for DCU but they didn't tell regarding diolefins. (1)
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)
13/06/2016 Q: Why is heater outlet temp of VR feed ie COT temp maintained at 498C not 487 or 467 or 477 or 475 or 482 or above 500? And what is effect of temp and pressure on coke yield inside drum? (3)
01/06/2016 Q: How can we calculate the recycle ratio in coker unit?  
31/05/2016 Q: What is the typical Distillation D-86 we maintain for LCGO and HCGO streams in Delayed Coker unit?
When trying to maintain the D-86 Distillation for LCGO heavier what are the specific issues we can face in Coker fractionator? We want to achieve D-86 T95 at 385 deg C, is it possible or we can face issues related to mis-operation or coking in the column?

Additional info:
Our worry is related to initiation of coking for HCGO stream if we try to cut the LCGO heavy up-to 380 deg C or 385 deg C. As per typical guideline of Licensor, 370 deg C should be the end -point of LCGO stream.
(2)
28/03/2016 Q: What is the correlation of increase in Delayed Coker yield with increase in Coke Drum inlet temperature? (5)
19/02/2016 Q: About DCU. Can someone tell me if there's a mathematical correlation, study, paper or model that relates furnace metal tube´s temperature and transfer line temperature?. I need to estimate operative circles between decoking with different scenarios and I don't have much data about these. (1)
17/02/2016 Q: We are facing some problems of coke carryover from drums even on low throughput. This problem, as per analysis done by us, was caused by deagglomeration of coke particles which in turn were easily getting lifted at lower overhead vapor velocities.
What are the properties of Crude which help in agglomeration of coke particles?
(1)
26/01/2016 Q: I am looking after delayed coker unit. We are operating 4 drum coker with 1kg pressure, 496 COT. We are frequently facing problems during coke cutting, in terms of Hot spots, bed collapse, lot of stem comes out at cutting deck during intial drilling operation.. When ever we tried to increase cot , coke drum cone portion cutting becomes very difficult. Can anybody tell me what are the reason's for this, how to avoid? (2)
20/01/2016 Q: Can someone tell me why steam is not introduced in Delayed Coker Main Fractionator like other fractionator columns in refinery??
(5)
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)
20/08/2015 Q: We have a two coke drum DCU. We are facing issue of high Sulphur content in our pet coke. The feed quality has been fairly consistent. Normally we have been operating with a cycle time of 18 hrs & COT of 501 Deg C since last two years. The issue of high sulphur has surfaced over the last two months only. Can anyone suggest the reason? (5)
19/08/2015 Q: We are operating our DCU with COT at 501 Deg C. The feed quality is also more or less constant. For the last month and a half months we have seen increased sulphur in our coke in excess of 9 wt %. Can anyone suggest the probable reasons?
(2)
31/07/2015 Q: In our wet Gas compressor we experience frequent seal oil migration/leak into lube oil. Wet seals exhibit low MTBF. How can we eliminate seal leak and enhance sealing performance? Is dry gas seal a reliable solution in wet gas compressor? (4)
01/05/2015 Q: I am looking after Delayed Coker Unit.
One of the most obvious problem occurred in DCU is high skin temperature of heater coil due to different reason. Due to high skin temperature we are forced to run the unit with low throughput. Online spalling is not permitted by management due to some reason.
My query is to avoid high skin temperature in some section of the tube should we put off the burner near that section or can we pinched the burner?
But putting off the burner will increasing firing at the other section which may lead to coking up at that section.
So what should I do?
(2)
22/04/2015 Q: There are several different options to increase liquid production and reduce coke yield in residue coker units. One of the most widely used is try to operate coker drum at low pressure.
But what are the possible options to reduce further the operating pressure in the coker drum?
Could the minimum pressure limit (alarm) at the wet gas compressor inlet be reduced? We currently operate at 0,4 kg/cm2. Has anyone experience operating at lower pressure at this point?
Has anyone experience installing an on-line water wash in top of main fractionator or condenser to remove salts? In that case, which is the maximum DP reduced with this option?
Has anyone experience implementing any other modifications (increase vapor lines diameter, etc)?
(2)
21/04/2015 Q: I would like to ask about required H2/HC ratio and coker naphtha processing in a naphtha hydrotreater.
We have a unit processing a mix of straight run and coker light naptha. Unit consists of two reactors, one for diolefin saturation and one for HDS and olefin saturation, both use regenerated NiMo catalyst. Colleagues intend to raise coker naphtha ratio, which is currently maximized in 12%. I made some calculations which resulted, that coker naphtha has around 90 Nm3/m3 chemical H2 consumption, and the units H2/HC ratio is around 60-100 Nm3/m3 depending on throughput. 12% naphtha results in ~16 Nm3/m3 chemical H2 consumption. If I remember well, the H2/HC ratio should be at least 5 times the chemical consumption, in this case 5*16=80. Am I right, or can this value safely be reduced? Does anything else restrict the max ratio of coker naptha processing? Temperature raise is about 25-28 °C on HDS reactor with an inlet temperature of 290 °C.
(4)
25/03/2015 Q: I would like to know if when we design a transfer line of CDU or VDU heater then do we consider erosional velocity as a constraint? The mixed phase velocities in transfer line are frequently higher than calculated erosional velocity (from API-14E). (4)
28/01/2015 Q: We are installing SS 310 skin thermocouple with heat shield in our DCU. The tube material is A335 P9. Our integrity department insist we perform buttering and PWHT for the installation. My questions:
1. Anybody have experience in such installation of skin TI where you have buttering and PWHT due to the dissimilar material weld? Does the TI's perform properly?
2. Is it a practice to have buttering and pwht for the installation? Buttering is due to dissimilar metal welding and PWHT is the requirement due to P9 material.
3. Our existing skin TI does not have buttering layer, and in our record, there is no PWHT done for the existing installation. Is it a practice? Any code or standards does it refers to?
 
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)
04/02/2014 Q: We are trying to figure out how to improve the feed control to our new Hydrocracking and Hydrotreater Units, since one of the feeds comes from the Coker Unit, we want to know how variable are the quality and flow of the HCGO, Naphtha and LCGO, because we are aware it would be changing while coker cycles are taking place. We don't have tanks to store LCGO and Naphtha as feed to the units, so these streams go to the hydrocracker and hydrotreater directly from the coker stripper, and if there is a sudden change in composition or flow, it could lead on a runaway. (3)
16/01/2014 Q: In our DCU main fractionator we have refractory laid on first tray (chimney tray), and this is done to prevent coke formation on this tray (coke drum ovhd vapours @420 deg cel comes in immediate contact with HCGO in this tray), i would like to know whether there is any way to identify if coke starts forming on this tray even after laying this refractory. our operating pressure is bottom- 0.77 kg/cm2 (g) and 310 deg cel. top - 0.53 kg/cm2(g) and 105 deg cel.
we have pressure transmitters and temperature transmitters across this chimney tray.
(our DCU plant will get commissioned by jan 2014 end, I am relatively inexperienced in this unit)
(1)
17/10/2013 Q: We have heard in many technical forums about ‘Unit Quench Factor’.
We would like to know more on this term, monitoring experiences, correct technical formula & accuracy of this term in predicting stress build-up in coke drums.
What are other ways for monitoring stress on coke drums? Are there any standard references/values for water quenching, steam quenching & vapour heating - rates and Deg C/Min?
(1)
06/09/2013 Q: My question is related with the effect of pressure and HCGO recycle in yields and HCGO properties.
We would like to improve the properties of the HCGO product. If you increase the pressure or the recycle, the HCGO quality will be better but the yields will be worse (more coke yield).
I would like to know if there is some difference between increase the recycle or the pressure.
What option is more recommendable? Both variables produce the same effect (in yields and HCGO quality)?
(1)
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: My question is related to arsenic and mercury contents in delayed coking products.
We were thinking of sending coker naphta ang gas to the olefins cracker without hydrotreating beforehand. Both arsenic and mercury could cause problems in this unit. I would like if somebody have had some similar experience or if somebody know the level of these contaminants in these feeds.
(3)
02/07/2013 Q: Issue : Since commissioning our coker naphtha yield remains always on higher side by 1 to 1.5 wt%. The quality of the Naphtha end point also remains on higher side 145-150 Deg C than the design value of 125-130 Deg C. We are operating our fractionator with top temperature 99 Deg C & pressure of 0.56 Kg/cm2 G. Top temperature, reflux flow rate & pressure are same as design conditions. We tried simulating the scenario but could not get any clues from that.
Queries:
1. What may be the probable causes of deviation in Naptha end point from design?
2. To what extent can we reduce our top temperature, to drop heavy end of Naptha to LCGO cut below?
3. What are concerns foreseen for low fractionator top temperature operation?
4. To what extent Naptha quality degrades if section trays are damaged or reflux distributor is not working properly?
(3)
19/01/2013 Q: What causes foaming in coke drum?  
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)
23/06/2012 Q: 1. What is the purpose/function of Steam Ejector in Vacuum distillation column and how it works?
2. Why it is placed at the top of column and why not the bottom in refinery? please explain the barometric concept regarding this installation
(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)
16/09/2011 Q: For the improvement of run length, we would like to replace about 1/3 of total radiation tubes of 9 Cr 1 Mo with SS 347 H.
1) How much % improvement in runlength is feasible between two spalling?
2) How much max TMT is allowed in such combination of radiation tubes?
3) What will be Spalling temp limit?
4) What precaution to be taken care for welding of two dissimilar joints?
 
14/06/2011 Q: What are the effects of decreasing the coke drum cycle time from 24 hrs to 20 or 18Hrs on WGC capacity? (4)
03/05/2011 Q: In our refinery, there is a proposal to utilize treated water from Effluent Treatment Plant in our Delayed Coking Unit as Coke Cutting Water. Can somebody throw some light on the suitability of ETP water for coke cutting purpose and the problems expected, if any? (3)
21/04/2011 Q: During vapor heating of the idle chamber the bottom temperature of Main Fractionator goes as low as to 350 degC which is below the specified limit of 370 degC which in turn increases the fuel burning in the furnace leading to high skin temperature and less operating days. We maintain COT at around 495 degC and Chamber pressure of 1.8kg/Cm2. Can someone suggest better operating condition to avoid such a problem. (2)
08/04/2011 Q: In our wet gas centrifugal Compressor (capacity-130TPH), dry gas seal system (nitrogen) is given as primary, secondary and separation gas. The N2 header pressure is 7.5 kg/cm2g. Is any back-up facility (N2 bottles, booster etc.) required for safe and smooth operation of WGC in case of header pressure low or failure of supply? (2)
22/03/2011 Q: I want to know importance of Real Density and Vibrated bulk density for various type of coke? What does it indicate? (1)
25/02/2011 Q: We are having excessive rate of rise in skin temperatures of our coker heaters. Can somebody tell us the reason for such rise? It is to be noted that the coke formation in the tubes is a very thin layer. (2)
21/02/2011 Q: We are facing high delts temperature rise in coker heater tubes which necessitates heater tube cleaning owing to high coke deposition. We are trying to correlate this with feed VR quality. Currently the parameters which are being closely monitored are SARA (saturates, Asphaltenes, Resins and Aromatics contents of feed), metal contaminants etc. Can anybody suggest what other feed characterization needs to be done to perfectly correlates the high temp rise in heaters? What others test can be carried on so as to limit those values to keep heater functioning for longer time? (2)
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)
08/06/2010 Q: What is the purpose of a flood nipple in a nozzle of a Column which goes to reboiler?  
21/10/2009 Q: With Increased pressure, Increased COT, Increased Temperature, & low Residence Time in the Coke Drum, we are facing high gas make with increased Methane in the Gas. High Coking is also seen. The API of the Coker Feed is 3.544. Can anyone explain the reasons why we are achieving high amount of Methane make in the process? (1)
21/10/2009 Q: How can one predict the composition of off gases from Coker? What are feed characteristics used to get a better prediction of olefins in Coker off gases and LPG?  
21/10/2009 Q: We operate one of the largest cokers in the world and are keen to increase the distillate yield. There is lots of information currently floating around wrt concepts like 'zero recycle', use of additives to reduce coke yield, recycling of LCGO to recover distillates, etc. As zero recycle is promising, our questions are:-
1. Yield improvement obtained with zero recycle?
2. Quality of HCGO post implementation of zero recycle wrt Metals, CCR, particulates, etc.
3. Destination of any extra heavier HCGO stream (from main fractionator bottom) along with quality of this stream.
4. Any issue wrt reliability of the plant post zero recycle option.
(1)
23/09/2009 Q: We are stress-modelling existing coker drum piping for major piping upgrades, eventually for both static and dynamic modes. We came across the "banana effect" phenomena which is thermal bowing of the drums at quench cycle, and asked that such lateral movements be included with our upper-level piping analysis. We were told to model as much as 1 foot or more of movement, but very difficult to satisfy this. To date, we can only input as much as 4" and above that, results show failure or large overstress. The field says historically there is not much movement at the drum top for years now, which we are quite reluctant to accept.
Can anyone share their experiences with delayed cokers in other facilities, in particular, this banana effect? Any related input, especially with piping movements, thermal cycling, etc. should greatly help with our analysis dilemma.
 
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)
12/05/2009 Q: Flow measurement into cokers is traditionally done with DP meters (orifice, wedges , venturi etc). I am trying to get an idea about the maintenance costs associated with DP devices (pressure line purging, purging liquids etc)  
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)
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: How are existing distillate hydrotreaters revamped to process higher volumes of feedstocks performing? What are some of the latest reactor and catalyst improvements that permit processing higher volumes of FCC LCO, coker naphtha or light coker gas oil through the distillate hydrotreater, and what are the corresponding benefits to downstream naphtha hydrotreater performance? (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?  
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)
11/02/2008 Q: Recently we have started using refinery slop oil as reactor overhead quench. Due to presence of some water (free as well as emulsified) in slop oil the fractionator operation is getting disturbed. What is the most efficient way of separation of water from slop oil (along with proper tank preparation)? Would putting a coalescer in slop oil service (density varies from 0.8 to 0.9) be effective?  
07/11/2007 Q: We are processing reduced crude oil coming out from CDU bottoms (35 API). The feed to the coker has a typical API of around 15 to 17.5. The chamber is operated at 2.2 to 2.3 kg/cm2g and the furnace coil O/L temp maintained at 498 deg C. The recycle ratio is maintained at around 0.9-1.
Now we want to increase Naphtha and c3/c4 yields, which are 8% (95% volatility 110 deg C) and 4% respectively. Please suggest which way to approach.
(2)
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)