Hydrotreating Kerosene for S and N removal 4

[sshep]

I am seeking general advice at this time.

I have been recently assigned to a team (opns, engr, R&D) which is tasked to upgrade a kerosene hydrotreating unit for sulfur and nitrogen. The upgraded unit is to handle kerosenes containing 3000ppm S, and 60ppm N and meet a spec of 0.1ppm S and <0.1ppm N. The design conditions of the existing unit are unfortunately limited to only about 1000psi, 700F. Currently we are running feeds of 300ppm S, and 15ppm N; and getting 0.4ppm S, and < 0.1ppm N. I am not certain yet what analytical methods this data is based on.

We currently have two seperate Ni-Mo catalyst beds in series, with no inter-stage heat transfer equipment. We are using only a single feed of H2 to the first bed. Our make-up H2 is 85mol%, although higher purity is available. Currently we are not taking any H2 purge or do any recycle H2 cleanup- we are just beginning a sample program on the recycle H2. An added economic objective is to avoid excessive H2 consumption associated with hydrogenating all the unsaturated feed components. I wish to use as much of the existing equipment as practical, but will be able to add new bed vessels, internals, heat exchangers, piping, alternate catalysts, etc as required.

I appreciate any clarifying questions, comments, advice, or contacts. Thanks in advance, sshep.

 

[jay165]

My first phone calls would be to your existing catalyst vendor and one or two competitors to get some free simulation work and see what they identify as a bottleneck. A change in catalyst type and volume may be all you need. I would also look at what could be done to raise the MAOP of the unit. Additional H2 purification would help (85% seems low to me, but my memory may be off).

I'm assuming that your unit is in a refinery that normally runs sweet crudes and you are switching to a more sour feed or you're running some FCCU or coker material in it. I think your bigger issues will be upstream (metalluurgy in the crude unit) and downstream (increase in acid gas, amine loading and sulfur production). Someone needs to look at those areas as well.

 

[sshep]

Thanks Jay.

To clarify, this is not a refinery application, although the shift to a sour feed may be refinery driven. This kerosene is used as a chemicals plant feedstock for which S and N are poisons to the downstream process. We are working on catalyst options with vendors.

Further ideas which can maximize the performance of my hydrotreating process are appreciated.

 

[25362]

jay165 is absolutely right in advising you to look and ask for catalyst makers' support. They should provide a level of technical support to include a combination of the following capabilities:

(1) writing guidelines for catalyst sulfiding, start up
and operation,
(2) pilot plant studies, or computer process model
simulations, for process optimization including
factors such as feed and product quality and their
changes, reaction temperatures, gas:feed ratios, make-
up hydrogen purity, hydrogen partial pressures, space
velocities, effects of gas contaminants such as
carbon oxides and nitrogen, whether or not to have
two beds with cold recycle gas quenching between the
beds when treating unsaturated feedstocks to
compensate for excessive temperature rises,
(3) on-site technical support on item (1),
(4) trouble-shooting advice,
(5) periodic monitoring of performance assessing the
parameters affecting catalyst operation,
(6) cycle life predictions,
(7) advice to maximize catalyst performance,
(8) diagnose temperature profiles on the catalyst beds,
(9) assess product quality and yields,
(10) catalyst regeneration procedures (in situ or off-
site).

Above considerations are necessary to optimize economics. For example, a higher gas rate (m³/m³ feed) by using recycle gas may assist in maintaining the desired hydrogen partial pressure in severe reactor operations, thereby ensuring adequate desulfurization and minimizing carbon laydown. On the other hand higher gas rates may incur extra heating and cooling costs, which may outweigh other advantages.

Cat vendors should be able to tell you, for example, whether using temperatures above 660^oF could induce the production of olefins (as with lighter naphthas) which may recombine with H2S forming mercaptans which dissolve in the product. Thus increasing its sulfur level, instead of reducing it, as might have been expected.

Etc., etc.

 

[sshep]

Obviously catalyst selection and vendor support is a key factor. I would like to get ideas on changing my process to get an operational advantage. Our team generated some ideas such as:
1) Having multiple stages of hydrotreating each with a different catalyst, and/or operating conditions.
2) Better use of H2 such as using the make-up to create a second higher purity loop.
3) Intermediate heat transfer (to allow both current beds to be the same or different temp).
4) Recycle H2 purge and/or scrubbing (I have amine supply and return available).
5) Some sort of polishing bed on the hydrotreated product.
6) Better bed distributor design.
Any comments on these or new ideas is also appreciated!

 

[Chemtech2]

Improving Catalyst is an option. You might also have 2 more points :

Since it is a exothermic reaction : A cooler hydrogen stream can be added between the Two beds . This compensated for lost h2 / increase H2 partial press. and removes some heat.
The liquid hourly Space velocity can be changed but it will affect the throughput.
Cleaning of recycle gas is also a very effective method to increase h2 purity.

 

[RogerH]

For kerosene HDS units the liquid load varies quite much from SOR to EOR so the need for very good distributors are crucial. Combining this with deep HDS as it is in your case emphasises this need. You can pick whatever catalyst but if you dont have good distribution you will not make use of the good catalyst. Apart from catalyst choice most of todays new or revamped deep HDS units have gas scrubbers, this will improve ppH2 but also to some extent increase reaction rate (since pH2S is in the denominator in the rate expression). It will also reduce pH2S for recombination which is most predominant in EOR conditions (i.e. at +370°C.
Improving reactor effluent cooling can also be advantageous, i.e. increasing pH2 but also improving H2/oil ratio. You do mention that you dont have any interbed cooling, I would look into installing quench if the distributors are to be replaced. Optimising cat-volume is also an cheap option that should utilised by e.g. using types like flat outlet collectors, and flat mixing/quench/mixing/distributor tray. If you are lucky you can squeeze an additional 5-10% catalyst into the reactor and lastly I assume that you already are dense loading the reactor, if not , this will give 5% more cat into the reactor.