Q & A > Process Modelling and Simulation
Date  Replies
24/07/2017 Q: Is a microbiological assay for storage tanks necessary? (2)
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)