Q & A > Process Modelling and Simulation
Date  Replies
10/04/2021 Q: During precommissioning a diesel unit why we can not start the recycle gas compressor with 100 % hydrogen before catalyst sulfiding as per the licensor: 50% nitrogen with 50% hydrogen? (2)
19/10/2020 Q: Why aren't the draw off temperatures close to the IBP, FBP of the products? For example, the draw temperature of kerosene is 193degC where as the lab results suggest 140degC IBP and 240degC FBP. (1)
04/10/2020 Q: What is the typical discount rate in an oil refinery feasibility study to get an optimum result for NPV? (3)
05/03/2020 Q: I am working on a process for aviation fuel and gasoline production from biomass gasification via Fischer-Tropsch synthesis using cobalt based catalyst.

I would like some insights on how to convert the Fischer-Tropsch wax (C5-C40 both paraffins and olefins) to Aviation fuel and Gasoline. Do we need to use both hydrotreating and hydrocracking? Will it be different compared to gas-oil hydrotreating? 		(3)
04/03/2020 Q: Could any one tell me what is the cost of refining a barrel of crude oil or how can i predict it for typical refineries ,as well as the forecast ,thank you in advance (4)
22/02/2020 Q: In the isomerisation of light naphtha, how often dp you regenerate or replace the catalysts (Pt/chlorinated alumina, Pt/zeolite and Pt/sulfated-zirconia) in the reactor and the adsorbent (Zeolite Beta) in pressure swing adsorption?
(1)
18/02/2020 Q: A boiler to produce low pressure steam
• Boiler has a rudimentary design. • Total volume is 1 m3
. • Check valve, pressure and level indicators are present. The check valve opens when the required pressure is achieved. It
can also be manually operated. • Mode of operation of boiler is unchanged- Half of the boiler volume filled with water, then fired. Steam builds up to the
required pressure. When the required pressure is achieved, check valve opens letting out steam. Once steam generation
begins, level of the water in boiler is maintained and continuous operation is achieved. • A flow measuring device is installed upstream to measure steam flow rate. • The start-up requires 352 seconds. • Due to severe clogging, boiler is swapped with a temporary one. The new boiler is double the size of the previous one.
The heat input rate and the check valve characteristics remain unchanged. • 400 seconds after firing the new boiler, it is observed that the pressure indicator is faulty. The level in the tank has shown
little deviation and the check valve has not opened. • What would be the most safe and efficient course of action? The boiler has emergency PRV, and is functioning at one
fourth of the pressure it is built to handle, and the maintenance of the clogged boiler will take 6 hours. If the issue with
the pressure indicator was diagnosed 1200 seconds after firing, with the check valve still being closed, would your
course of action have deviated from the previous one? If so, how? 		(1)
04/01/2020 Q: Why is the diameter of top and/or bottom of a VDU smaller than rest of the column? (7)
12/12/2019 Q: For a Cracked Gas Compressor in an Ethylene Plant, I am doing a simulation for determining optimum wash oil rate for the CGC. As a rule of thumb, 0.01 to 0.25 percent of cracked gas rate is taken as wash oil rate in plant. But I want to know how to calculate it using simulation now. I do not have compressor curves, so to start with I am doing it like this : three phase separator I have taken . I am flashing cracked gas outlet from compressor and wash oil and wash water in this three phase separator here. Now I want to know what is the point where I can say that it is an optimum flow of wash oil ? Do I need to run more wash oil to get dienes from the cracked gas outlet into the wash oil ?
 		(1)
07/12/2019 Q: For part of a project, I am dealing with SR naphtha reforming reactors. The process is four reactors in series that use Pt-Alumina catalysts. Due to the high-temperature generation in the regeneration step, one of the reactors can not be in the service anymore.
I want to know does anyone have the same experience?
Is it possible to work with three reactors?
Could you please inform me to find some useful resources to find a similar study and situation?
 		(3)
07/12/2019 Q: In a case study for safety improvement and process analysis for SR naphtha reforming, I want to know If one of four reactors can not be in service is it possible to work with three?
Is it safe to work with three reactors?
Does anyone have such experience?
Could anyone please inform me to find some useful resources to find a similar study and situation? 		(2)
08/10/2019 Q: Can someone explain what does the pressure ratio and the critical pressure ratio mean in the following link? Also, does anyone have an Excel related to steam silencer design?
https://www.geothermal-energy.org/pdf/IGAstandard/WGC/2005/1345.pdf
 		 
10/09/2019 Q: What is the best way to theoretically blend isomerate and reformate for octane number from gc data linear blending vs index blending using blending octane number Further what is the source of obtaining blending octane number of individual hydrocarbon
(3)
25/08/2019 Q: Hi All
I'm trying to simulate naphtha hydrotreater in Hysys v 8.8 and facing following problem. I tried to change pressure and temperature as well but not getting converged.
1-OOMF Line search failure.
2-Calibration page sulphur and Nitrogen is not in feed message is coming.
Can anyone explain what is OOMF and how to solve it.
Best Regards
 		 
23/06/2019 Q: Two streams mix together:
1. A liquid or oil stream @ 160 degC and 110 kg/cm2(g).
2. A gas stream (mainly H2 gas) @ 160 degC and nearly 85 kg/cm2(g).
The "mixer" consists of a pipe, in which oil is flowing from right to left.
The gas entering at right angle from above. The gas is introduced in the oil by means of a nozzle in form of a smaller dia pipe with an elbow, directing ALONG the flow of liquid.
(if direction of flow of oil is --> , then the elbow also directs the smaller pipe towards ---> direction).
There is no pressure indicator just before or after the "mixer".
The questions are:
1. What will be the resulting pressure, downstream of the mixer? (after the nozzle or smaller dia pipe).
2. Why does liquid oil not enter the smaller pipe which introduces the H2 gas into the oil?
3. Does the nozzle in the pipe act as an "ejector"? and the gas being pulled along the oil?
4. What will happen if the nozzle is removed along with its elbow, and the gas introduced in to the liquid just using the pipe attached at right angle? Will the gas flow in to the oil or the oil will flow in to the gas?
The approximate flow rates are:
Liquid: 112 STD m3/hr (94,000 kg/hr).
Gas: 74,000 Nm3/hr (12,000 kg/hr). 		 
15/06/2019 Q: What is the suitable configuration of Deisohexanizer column to produce Pharma Grade hexane? We have existing DIH column which was designed to separate C5 & C6 isomers from overhead, unconverted n-hexane from side cut as recycle and Cyclohexane, methyl cyclohexane, c7+ components from bottom of the column. Now, we are planning to reconfigure DIH column to separate Pharma Grade hexane. New column should be able to separate PGH during PGH production and should separate isomerates properly during normal gasoline mode. In this context, how should column look like in terms of draw locations e.t.c  
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)
27/05/2019 Q: How do you calculate actual flow rate of Fuel Gas from the flow meter reading?
In our process plant we have Fuel Gas FTs which gives us reading in Nm3/hr and we want to calculate from this reading actual fuel gas flow taking into account temperature, pressure and density corrections.
Which is the most accurate formula for calculating flow rate? What are the best practices followed by other refineries in order to calculate the fuel gas flow, do they apply temperature and pressure correlations? Pressure or density which is better to take in account? 		(3)
01/03/2019 Q: In a naphtha stabilizer, top tray (tray 46) temperature is controlled by the reflux and the bottom tray (tray 3)temperature is cascaded with the hot light gas oil flow (reboiler's hot medium). Top pressure (overhead vapor pressure not the OVHD drum pressure) is controlled by the removal of non-condensed vapors from OVHD accumulator. Here, when I increase the bottom tray temperature, top pressure is getting increased slightly (very minimum) and then OVHD vapor pressure is getting decreased faster. Can anyone explain this phenomenon? Note: Distillation tower - 48 trays column; OVHD product - LPG; Bottom product - Stabilized naphtha. (4)
12/02/2019 Q: What is the deltaP value changing limit(+/-) into the fuel line during the leak test for crude oil furnace burn with natural gas. Is there any calculation method, standarts extc?
NFPA 86 says in a table A.7.4.9, can we use these values? 		 
08/12/2018 Q: Prior to the use of simulators or for preliminary calculations, how the draw off temperature for a specific cut like gasoil or kerosene is determined using TBP data. (1)
08/12/2018 Q: I need to compare the current residue cut of my atmospheric distillation unit to the TBP/ complete Assay of earlier used crude feed. My question is how can i correlate both of them, how does the operating conditions /temperature and yields be compared with the TBP Analysis? If a process simulator like HYSYS can be of help.  
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)
10/03/2018 Q: Why hysys process simulator don't have actual volume flow among inputs, when you have only the volume flow, although the stream is gas you must put the liquid volume flow, so i make manually calculation before i put the value to prevent errors? (1)
14/02/2018 Q: Can anyone please tell me how to identify whether the liquid is forming a channel in the reactor packed bed?
Also please confirm the effect of pressure drop across the bed if channelling occur? will it increase or decrease?
In my understanding, the pressure drop will increase. But I need documents to support my argument.
Please help! 		(3)
28/12/2017 Q: We want to increase the capacity of the stripper in our hydrocarbon unit. There is an aerocondeser for the stream leaving the top of the column. We want to increase condensing capacity by means of a trim cooler that would be placed next to the condensers.
It will receive a total of 7,3 tones/h, 1,3 t/h vapour and 6 ton/h liquid.
I have simulated with ASPEN EDR the new trim-cooler that will operate with cooling water (tubeside).
To avoid revaporization downstream of the trim-cooler the liquid needs to be cooled down as well as the condensing vapour.
The software indicates that the required area for cooling the liquid is 45% of the total number of tubes.
I am specifying 30% cut baffles but doing a quick number tells me that liquid will just pass and there won't be any flooding.
Has anyone ever designed a trim-cooler? How do you accomplish the flooding of the heat exchanger?
There are several options, I find that the most suitables ones are:
1)A dam baffle that will flood the shell until the desired level.
2) A level control loop (level transmitter control valve)
We have other trim-cooler installed in other units, hydrocracker for example, but I have reviewed the trim-coolers drawings but there is not dam baffle or any level controlling loop.


 		(4)
06/12/2017 Q: I wanted to understand the constituents that cause the coloring in say natural gasoline. I'm working on an NGL fractionation unit & the Debutanizer bottoms is routed to a Decolorizer column. Now, I'm not sure what is removed to actually meet the D-156 saybolt color 20 specification. its gas condensate...C5-C20, mercaptans inc heavy mercaptans i.e c5,c6 mercaptab, BTEX. No MEROX unit on the feed stream..so no DSO. Also no N2/ nitrogenous compounds.
I would be very grateful if somebody could share the HC compounds contributing to color other than the obvious DSO/ N2 compounds. 		(1)
24/07/2017 Q: Is a microbiological assay for storage tanks necessary? (3)
15/05/2017 Q: Our CDU overhead air cooled heeat exchanger is designed with 156 tubes and 3 passes. we have recently shutdown the unit to plug 32 leaked tubes:
- 20/52 tubes plugged in pass 1
- 12/52 tubes plugged in pass 2 .
We would like to estimate the effect of tubes plugging on the overhead ACHE performance by simulation (example wtih PRO II ).
How could we do that ?
(2)
21/04/2017 Q: How can I find the amount of flow passing through a control valve at a given output? (3)
20/04/2017 Q: What is the relation between the amount of overflash used in a vacuum distillation tower and the stripping steam injected at the bottom of this tower? (3)
20/04/2017 Q: For a cooling top pumparound for a vacuum tower, which is more useful: to use a larger flow rate (140 m3/h) at higher temperature (78C) or use smaller flow rate (100 m3/h) at lower temperature (70C) (2)
15/02/2017 Q: In a CDU overhead drum reflux, which are the advantages of a three phase separator versus a flooded one with a naphtha + gas outlet, a naphtha to reflux outlet and a water separation? And how can you estimate them? In both cases the reflux temperature is the same. (1)
19/01/2017 Q: We have a 50,000 bbl/d capacity crude unit designed for Iranian light crude oil. The main crude column needs to be replaced due to ageing. We would like to take this opportunity to revamp to unit capacity as well to about 70,000 bbl/d. Based on a previous study carried out, the unit capacity can be increased up to 70,000 bbl/d by installing a pre-flash drum before the charge heater. However, now we have to replace the main column. In another study carried out, it has been identified that the some modifications are required to be done to the charge heater such as re-tubing with different metallurgy and changing the passes from 1 to 2 etc. if the unit capacity is increased up to 70,000 bbl/d (without a pre flash drum).
I would like to know whether installation of straight 70,000 bbl/d capacity column or installation of same capacity 50,000 bbl/d along with a new flash drum (to avoid charge heater modifications) is more economical. 		(4)
04/01/2017 Q: In my refinery there is a 15 kBPSD LSRG sweetening unit in which caustic washing procedure followed by MEROX oxidation process. In case of feed change scenario, is there any solution in terms of gas condensate sweetening by means of before mentioned facilities? If yes, what are the changes in terms of capacity, chemical consumption, and mercaptan removal efficiency? If there is any revamp, which sections need to be resized? (2)
15/04/2015 Q: Has somebody experience with petroleum hydrocarbon resin simulation and separation?
 		 
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)
18/12/2014 Q: I'm doing a work about octane rating, but I haven't find the Research Octane Numbers of cis-1,2-dimethylcyclopentane and trans-1,2-dimethylcyclopentane. Who can tell me? (3)
19/08/2014 Q: I'm currently working on a VGO hydrocracker simulation. I want to know some common problems in normal industrial operation in this kind of process. (1)
27/05/2014 Q: How could I simulate a Boiling Feed Water dearator on PRO II. flash drum? distillation column?  
29/04/2014 Q: I'm working on Kerosene hydrotreating unit simulation to remove sulphur from kerosene by using hydrogen. What are the possible components when it mixed? (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)
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)
09/05/2013 Q: I have laboratory ASTM D7169 data for Vacuum residue of Vacuum unit & Clarified slurry oil from FCC. I want to use them in simulation. As per literature information it is mentioned that for Vacuum residue ASTM D7169 data can be used as True boiling point data in Wt% & i have seen it is giving ok type of match for simulated properties. However, for FCC Clarified Slurry oil (cracked stream) when i input (in simulator) as TBP wt% then even there is lot of mismatch in density itself. Can you please tell me whether for cracked stream is it appropriate to use ASTM D7169 data as TBP wt%? if no, then how to model it in a simulator like Aspen plus? (2)
15/03/2013 Q: We are using RPMS for refinery LP modelling. Can any one tell what are the other packages and their advantages over RPMS? (1)
23/12/2012 Q: In our CDU column we draw off naphtha (overhead) , kerosene , light diesel , heavy diesel and AGO fractions and 4 pumparound circuits (on kero, light diesel , heavy diesel and AGO sections). The top of the column is cooled by reflux (overhead –air coolers-receiver – column) . From a simulation it appears that approximately 55 % of heat from the atmospheric column is wasted in overhead line (air coolers) and the rest 45% is recovered in pumparounds heat-exchangers. We would like to introduce the additional pumparound (TPA) and recover some of the heat in new heat exchanger(s) upstream the desalter - of course the exact location of the added heat exchanger will be analyzed with pinch study. What do you think about the solution of introducing the additional pumparound in order to recover some of the heat which is currently wasted in air coolers? Maybe some other recommendations about recovering this heat to the process. (7)
24/09/2012 Q: I work on CDU/ VDU plant as a process engineer . We commissioned performance of the feasibility study concerning revamp of the vacuum system. It appears that we may achieve different vacuum at the top of the vacuum column with different solutions, so we have to consider the best option in terms of the yields of the fractions.
Is it possible to simulate in Sulzers proprietary application SULCOL how the yields will change from the vacuum column
1. when I set various pressures at the top of the column (without modification to vacuum column)
2. when I change the structured beds from current structured packing Mellapack to Mellapack Plus or other.
I would be very grateful for some information with regard to technical capabilities of this program or maybe some recommendations for other free software of this kind.
(3)
23/08/2012 Q: One of our condensers --using cooling water as coolant media -- is located at elevated position. We can periodically isolate and dismantle this condenser, and upon inspection , the tube side (cooling water side) of this condenser always suffers from signifcant amount of fouling.
One of our colleagues suggests we install an "inline centrifugal pump " on the cooling water supply line into this particular exchanger in order to increase the amount of water flowing through condenser's tube hence minimizing the fouling rate.
I'm a bit doubtful about this suggestion, as this exchanger receives the cooling water supply from network header, thus the amount of water supplied to the inline pump will still be the same as the amount of water supplied directly to the exchanger without inline pump. An inline pump, in my opinion, will only increase the inlet pressure of cooling water into this particular exchanger. In my opinion, any attempt to increase the discharge valve opening of inline pump cavitate the pump if discharge flow is higher than suction flow received from network header.
I would like to hear the opinion from experts about the inline pump of cooling water network.

Additional:
Thanks for all..
The suggestion from Mr. Banik sounds interesting, and I'm going to evaluate it.
Anyway, I'm still curious with the case of inline pump installed in the cooling water supply line of an elevated exchanger, whether it will be able to pull more water supply from network.
My premises are :
1. Let's imagine an elevated exchanger is normally supplied with cooling water flow of X m3/hr.
2. The original supply pipe runs on the same elevation with main header of H m , then turning up towards exchanger.
3. If I reconfigure the supply pipe to turning down of H m below main header, then turning up again H m before further going up to reach the exchanger, the pressure profile inside this reconfigured pipe at elevation of H m will still same with pressure profile of original pipe at elevation of H m.
4. Hence flow of water in supply pipe no. 2 and 3 will still same.
5. If I put a pump in lowest section of reconfigured supply pipe no. 3, then the amount of water flowing into pump suction will still same X m3/hr.
6. As centrifugal pump doesn't suck, but it only pushes, so the amount of water pumped will still same X m3/hr. The only different thing is water inlet pressure to exchanger increases hence water outlet pressure from exchanger also increases.
7. Thus operating the pump discharge above X m3/hr will cause transient inventory loss in the pump casing hence cavitation.
Do I miss something or make mistakes in my premises above ? 		(5)
11/08/2012 Q: Are there any correlations available for finding the pressure drop for limpet coil? Presently we have a reactor with limpet coil. Water is flowing through the limpet coil (made of 3 " pipe). I want to understand the pressure drop calculation for water which is flowing inside the limpet.  
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)
19/09/2011 Q: How can we simulate Hydrotreater in Hysys? Do we have to add reaction for Hydrotreater to simulate? If yes, what are the kinetics of the reaction or where can I find such information? (1)
06/07/2011 Q: In template Hydrocracker, Aspen Hysys Refining (formerly RefSYS), what must I modify because that template does not accept the naphtha feed? It always says error "One or more feeds not solved". If I put 0.3% wt for a heavy component, Hysys will adjust it to 48% and change the feed character. How can I fix that error? (1)
30/06/2011 Q: Has anyone had trouble with "one or more feed not solved" on RefSys, template Hydrocracker? I need to simulate a HDS unit for cat cracked naphtha, but I always have problem with the feed. The default feed type in Library (Feed Data tab) is too heavy for naphtha, and it not contains C4, C5. What should I do to solve that problem? How can I create another Feed Type instead of that default? I made a chromatography for my feed, but when I modified lump weight percents conform my chromatography, it didn't work.  
23/03/2011 Q: We would like to go for absorber to remove water from methyl acetate.
Feed composition: Methyl Acetate: 99% and water 0.75 % and rest are methanol and acetic acid.
I would like to know which type of absorbent I have to choose to absorb water from methyl acetate.
It will be great help, if someone can throw light on this.
 		(1)
01/01/2011 Q: Most of the time while rating a shell and tube heat exchanger, we are given baffle cut percentage based on the area. Can anybody tell me that how to convert this percentage area to percentage dia baffle cut? (1)
06/12/2010 Q: We have a methanol-Water stripping column, which uses direct injection of LP steam for stripping.
I want to know if it is better to use reboiler instead of steam injection.
Is there is any advantage in using direct injection of steam in methanol-Water stripping column? 		(3)
18/11/2010 Q: There is continuous increase and decrease in our column delta pressure in water methanol column. At the same time we noted that our temperature profile of the bottom and middle bed is also fluctuating.
I feel that our column is having vapor cross channeling.
There is some variation in feed flow and steam flow, but column is somewhat running at 100 % load.
If anybody experienced such problem in your plant, please throw some light to understand what causes this fluctuation in delta pressure and temperature profile in the bed and what action to be taken.
Additional information:
Steam direct injection for stripping
There are three bed made of PP intolox saddels
Steam flow is controlled by mid bed temp
Reflux is controlled by feed flow

More information:
This is a packed distillation column to strip methanol from water. We are using steam stripping in our case because there are some traces of Acetic acid in the bottom. To prevent corrosion we have to strip at low temperature, so we are using steam stripping. There is huge variation in temperature profile of the middle bed, at 100 % load First indication of channeling is the change in delta pressure and disturbance in temperature profile. Disturbance in temperature profile is caused by improper distribution of vapor flow in the bed. So thinking this is because of vapor cross channeling.
If it is channeling or flooding how can we deal with it?

More information:
Thanks a lot for all your suggestions, we have opened our tower found that steam deflector plate was installed wrongly, so steam was injecting directly into the packing, which caused packing to expand and that caused channeling in our tower. After rectifying this, now we don't face this problem. 		(5)
18/09/2010 Q: I am working in a diesel hydrotreater. Can we simulate a hydrotreater in Aspen HYSYS refsys - hydrocracker? While calibrating the factors, what inputs we are supposed to give. What will be general values for HDS, HDN, SAT, Cracking, Ring opening activity for diesel hydrotreater and what does the term "treating bed to cracking bed mean"? Please explain.  
17/06/2010 Q: how can we see the astm and tbp curves for outlet streams in distillation units in hysys? (2)
04/05/2010 Q: My question is regarding Heat Ex. When I was simulating an Exchanger in HTRI which was of BHU type, I came to know that it is not providing any TUBE pass arrangement for 6 Tube pass and 10 Tube pass. The same thing is happening when I use the U-Tube combination with H or G type shells.
Can anyone explain me what is the reason it is not accepting (providing Tube pass arrangements) 6, 10, 14 Tube passes with H-U (shell-Rear end) and G-U (shell-Rear end) combination? 		 
21/10/2009 Q: Is it safe to consider back pressure of 50-70 kg/cm2g when my PSV set pressure is at 229 kg/cm2g? Why are we limited to 3-5 kg/cm2g back pressure maximum when we are designing the HP flare? API 520 part 1 says that I can consider up to 50% of set pressure of balanced PSV, so can I consider up to 100 kg/cm2 g when my PSV is set at 220 kg/cm2g? If not, then what is the reason? (4)
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. 		 
23/07/2009 Q: How should we size a PSV outlet line when we are considering liquid relief as the determining factor?
Our understanding is that if vapor is relieved then for PSV inlet line size, pressure drop is the design criteria and for outlet line size sonic velocity is the design criteria. 		(2)
20/07/2009 Q: How can we simulate a flare gas recovery system for a refinery? (1)
24/02/2009 Q: Does any one know how to simulate the cylindrical vacuum heater with velocity steam injection at radiation zone, using HTRI?
What is the procedure for generating the heat curve and other transport properties for vacuum heater whose process side is (RCO+Slop Wax+ Steam) Reduced crude oil? 		 
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)
18/11/2008 Q: What are the maximum allowable limits for following?
1- Jet Flooding %
2- Downcomer Flooding %
3- Downcomer Froth Backup %
4- Downcomer clear liquid (inch)
5- Weir Loading (gpm/in)
6- Pressure Drop across MV trays (psi) 		(2)
07/07/2008 Q: In general, where has the influence of good fractionation allowed for significant improvements in meeting stringent petrochemical product specifications (e.g., propylene, styrene, etc.) at higher charge rates? Besides the recent improvements to fractionation column internals, what is the extent to which automation & control systems can be leveraged to deliver higher efficiency, run-lengths and resistance to corrosion in product recovery trains?  
22/06/2008 Q: We have a crude preflash column where crude after being heated is flashed.
the column has three streams. One is the top which is light naphtha which is taken from the reflux drum via reflux pump as one stream. The other is sent as reflux on temp control The column has a fired reboiler.
A side cut is Heavy Naphtha below Hnaphtha cut is a pump around. Bottom is kerosene plus which is separated in another tower.
We wanted to reduce the EP of lt naphtha. We carried simulation on hysis and were getting the desired EP using HEPT OF 2 FT for CMR 1 as there is packed bed of 10 ft between LT and H naphtha we were getting five theoretical trays
on the plant we adjusted all perimeter as per simulation but we could not get even close to it the ep remained high. Increasing reflux severalfold could not achieve the end point.
We took delta p across the bed. It is low and pct flood predicted by Hysis is 16pct far from flood.
We reduced capacity but no avail. Could it be low flood which is responsible? We want to check all angles before we open it up. There are no gamma scan facilities available so we can't do a scan.
Can someone suggest what angle to look for? 		(1)
11/04/2008 Q: Kindly confirm what will be man hours required (all discipline viz, process, mechanical, electrical, piping, structural, instrumentation, safety and pipelines ) for carrying out CONCEPT stage of engineering (approximate number)  
02/04/2008 Q: We are facing a problem in the plant of piping noise and vibration exceeding the design limit. Can anybody tell me which software is used during the project inception stage for calculating the same. Whose responsibility is it: process or piping department?  
21/01/2008 Q: How can I predict HETP for Sulzer's structured packings (BX, Mellapak 250.Y or EX) when reflux is not total, i.e., when some distillate is taken off (e.g., 10, 20, 50 or 75 %)? Does it depend on the mixture to distill or is it an inherent characteristic of the packing? (2)
03/01/2008 Q: How can we redesign a crude preheater for better efficiency? What is the pinch point of the total crude preheater train using simulation package hysys? How can we do pinch analysis in hysys? (1)
16/09/2007 Q: In the crude coluumn , I want to put one more side draw. To allow for draw tray, how much tray does one have to actually remove from the column to accommodate this modification? (1)
05/09/2007 Q: Many concerns are being raised about ethanol and other biofuels because of the high amount of energy required for successful fuels synthesis. Some reports suggest that more energy (from natural gas or electricity) is required than is contained in the product fuel. Can you point to definitive papers on this issue?  
05/09/2007 Q: How can we improve fluidizing in a stand pipe regenerator FCC? (1)
23/07/2007 Q: What are the opportunities for pinch technology in crude distillation units? (2)
22/07/2007 Q: Can you comment on advances in tray and packing design software for modelling mass transfer and heat transfer effects in a fractionation tower? Can you briefly site any recent refinery or petrochemical product-recovery optimisation projects where actual separations were accurately simulated? (2)