8 replies to this topic

[Kat]

Hi,
I start a new project which needs to simulate the hydrogenation / hydrotreating / hydrocracking process to maximize the kerosene production. There are quite a few simulators, i.e Aspen RefSys, Aspen Hysys, Aspen Hysys Hydrocracker, Aspen Hysys Petroleum Refining...that I have very little experience working with. Any one has idea which Aspen Hysys simulators should I use for my purpose and the main advantage of these simulators? What will be the starting point for building this process simulation?
Best regards,
Kat

Edited by Kat, 14 September 2010 - 02:21 PM.

[Padmakar Katre]

Hi,
I start a new project which needs to simulate the hydrogenation / hydrotreating / hydrocracking process to maximize the kerosene production. There are quite a few simulators, i.e Aspen RefSys, Aspen Hysys, Aspen Hysys Hydrocracker, Aspen Hysys Petroleum Refining...that I have very little experience working with. Any one has idea which Aspen Hysys simulators should I use for my purpose and the main advantage of these simulators? What will be the starting point for building this process simulation?
Best regards,
Kat

Dear,
Can you tell us further about the scope of this project. Is it for the sake of self study or a new grass root project/revamp if existing facility. These are the licensed units and I am doubtful about the credibilities of the results of these simulators.But just to understand the concept I think these are good starting point. The catalyst performance data is always with the specific licensor and you will hardly find the same with these simulators.Waiting for your comments.

[Kat]

Dear Padmakar,
it is an upgrading project where an additional fractionator will be installed together with the stripping column in the diesel hydrotreating unit for better separation of naphtha and kerosene in the stripping section. As far as I know about the RefSys, this simulator is necessary in case we need to measure the catalyst performance against the actual plant operation but in my case for the upgrading unit, the actual performance for the upgraded unit is not yet available so it is over the top to use RefSys package. From this point I am thinking about using basic Aspen Hysys for simulation. In comparison to other simulators like Aspen Petroleum Refining and Aspen Hydrocracker, Aspen Hysys is not that specific for a particular unit but at least is for general use.
Any one has idea or experience, what will be the starting points or specific problems for the simulation of this kind of revamping/upgrading?
Regards,
Kat

Edited by Kat, 15 September 2010 - 04:28 PM.

[Zauberberg]

A common flowsheeter is more than sufficient since no catalyst process is involved in the revamp project, and you are dealing only with fractionation unit. Moreover, you can do it even without a flowsheeter or at least without relatively expensive tool such is Hysys - there are several simulators on the market, some of them much cheaper than Aspen software. Design II is one of those. You also have an option to submit a request to distillation equipment vendors (Sulzer, Koch-Glitsch) and they will do that part of the work for you.

Your second question: if you can upload a sketch of what is that you propose for revamp, it will be much easier for us to comment on.

[Chellani]

Few inputs from my side
First, you should try to estimate max stretch capacity of major equipments of the unit for typical hyroprocessing unit it should be – feed heater, reactor, stripper, main column & may be compressor as feasibility of debottlnecking can change if any of them needs to be replaced.
As far as reactor is concerned, talk to your catalyst vendor and he can give you yield estimate. Get typical reactor effluent properties from catalyst vendor’s offer and model downstream separation in any steady state simulator. You may validate your model first by design or actual plant data and then use yield estimate for revamp.
Once you are done with that, start analyzing other equipments i.e. heat exchangers, pumps, pipes etc. and add new ones in line or replace them.
Typically for hydroprocessing unit, end of run governs max stretch capacity estimation as your heater would be running at it’s design temperature and column flooding (mostly jet and not downcomer) would be at its peak.
So to answer your question – your starting point would be reactor effluent stream defined using yield estimate given by catalyst vendor.

One question from my side – can you share the typical yield estimate of your unit after revamp? I am interested in % of kero it has for which you are planning for a fractionator. Typically cracked kero doesn’t blend in ATF (except few cases) and blending it with diesel gives higher margin. I haven’t seen anyone fractionating kero in DHT / DHDS.

All the best.

Edited by Chellani, 17 September 2010 - 03:16 AM.

[Kat]

One question from my side – can you share the typical yield estimate of your unit after revamp? I am interested in % of kero it has for which you are planning for a fractionator. Typically cracked kero doesn't blend in ATF (except few cases) and blending it with diesel gives higher margin. I haven't seen anyone fractionating kero in DHT / DHDS.

All the best.

Thanks for your helpful comments. I also think to start with the estimated yieds and go backward.
The revamp is to get kerosene out of the existing gasoil stream, which contains about 30 % kerosene by using a Fractionator upstream of the Stripper. The naphtha & kerosene will be separated from diesel at the Fractionator. Kerosene then will be separated from naphtha at the Stripper downstream of the Fractionator.

Edited by Kat, 18 September 2010 - 07:44 AM.

[Chellani]

[/quote]
Thanks for your helpful comments. I also think to start with the estimated yieds and go backward.
The revamp is to get kerosene out of the existing gasoil stream, which contains about 30 % kerosene by using a Fractionator upstream of the Stripper. The naphtha & kerosene will be separated from diesel at the Fractionator. Kerosene then will be separated from naphtha at the Stripper downstream of the Fractionator.
[/quote]


I am a bit confused. Where is this fractionator being proposed Diesel Hydrotreater (DHT) or vacuum gas-oil hydrotreater (VGOHT). From your earlier explanation I assumed it to be in DHT and from your latest comments it seems to be in VGOHT.
I am also not sure why is fractionator being placed in the upstream of stripper; it would increase diameter of fractionator. Typical VGOHT configuration would be product stripper (stripping H2S and C1-C4) and then product fractionator. Condenser liquid from product fractionator would be naphtha (C5+ to 160°C) and bottoms would be sweet VGO (360+°C). In between it would be kero+diesel (160 - 260°C & 260 - 360°C). We actually had a configuration which had only one side stripper which was known as kero-diesel side stripper. Whenever kero price was good, this stripper was used to strip out light ends from kero and its product would be kero; diesel would be taken out without stripping and whenever diesel price was better, kero was dropped in diesel (by not withdrawing kero itself) and use the side stripper to strip out light ends from diesel. This operation was also dependent on how much of kero could be blended in ATF. The draw of kero and diesel was taken from different stages and both stages were connected to kero-diesel stripper.

[Kat]

I am a bit confused. Where is this fractionator being proposed Diesel Hydrotreater (DHT) or vacuum gas-oil hydrotreater (VGOHT). From your earlier explanation I assumed it to be in DHT and from your latest comments it seems to be in VGOHT.
I am also not sure why is fractionator being placed in the upstream of stripper; it would increase diameter of fractionator. Typical VGOHT configuration would be product stripper (stripping H2S and C1-C4) and then product fractionator. Condenser liquid from product fractionator would be naphtha (C5+ to 160°C) and bottoms would be sweet VGO (360+°C). In between it would be kero+diesel (160 - 260°C & 260 - 360°C). We actually had a configuration which had only one side stripper which was known as kero-diesel side stripper. Whenever kero price was good, this stripper was used to strip out light ends from kero and its product would be kero; diesel would be taken out without stripping and whenever diesel price was better, kero was dropped in diesel (by not withdrawing kero itself) and use the side stripper to strip out light ends from diesel. This operation was also dependent on how much of kero could be blended in ATF. The draw of kero and diesel was taken from different stages and both stages were connected to kero-diesel stripper.

Hi Chellani,
this unit is to hydrotreate the VGO from a coker unit. Different configurations have been proposed including the side stripper option to meet kerosene flash point spec. The problem with this option is that if the kero draw from above the feed of the stripper, the flooding level in the stripper is too high. If kero is drawn below the feed, the top section of the stripper will be flooded and the end point spec of kero is not met. The flooding problem can be solved but the end point spec of kero will be too high to blend with jet fuel.
The configuration as you described is also considered with naphtha being drawn from the overhead of the stripper, the column is flooded.

[Chellani]

Thanks, all the best for your new configuration. Do let us know what you finally implement and its performance in the actual unit.
For flooding, I hope you've checked performance with different tray configurations.