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QUINTANA (Valero Energy Corporation)
The spent Isom regenerant will contain butanes that are attractive to recover. They can come from generally any of three sources: either the treated normal butane feed downstream of the on-stream dryer, the fractionated isobutene from the Deisobutanizer fractionator overhead, or the isomerate product is used as the regenerant source. The spent regenerant also contains all of the sulfur and oxygenate impurities that were previously accumulated on the sieve; and after the spent regenerant coalescer, it will also be saturated with water. We should also keep in mind that these impurities will generally co-boil with the normal butanes since that’s how they got to the Isom feed dryer to begin with. This should be kept in mind when determining disposition of the spent regenerant. Furthermore, while the impurity concentrations vary during the regeneration, you will generally hit a peak during hottest part of the regeneration as well. That high level can possibly overload some of the downstream systems that the regenerant is directed to.
The spent regenerant may be attractive to recover as alkylation unit feed, especially where it has significant amounts of isobutene. Clearly, if you’re using the Isom feed (with low amounts of isobutene) as your regenerant, then it’s just going to take up hydraulic space in the alky unit, and another alternative may be preferred.
The feed dryers at the alky unit won’t remove much of these impurities other than moisture with three primary consequences. You’ll get consumption of acid from sulfur and oxygenate reactions, but they won’t be completely converted. Then, these acid consumption byproducts will increase the load on the acid regenerator while the unconverted impurities that remain will end up back in the fractionated normal butane cut that goes to the Isom unit feed. As a result of that, the recycled impurities from the spent regenerant will add on to the level that is in the fresh C4 feed. As the level builds, it will wind up in the feed to the Isom dryers and potentially overload it, leading to breakthrough between regenerations, and possibly deactivate Isom catalyst.

The windup effect is illustrated in this figure where the dotted line represents the recycle of the spent regenerant to the alky feed. Each time a regeneration is under way, the impurity level in the alky unit will likely increase, which will increase that load on the alky regenerator and produce more ASO. And as Allen indicated back in Question 72, oxygenates in an HF unit are particularly a problem as they will make lighter ASO compounds. We’ve seen as much as a 100°F drop in the ASO IBP from oxygenates in alky unit feeds. In order to get rid of those byproducts in the acid regenerator, you have to drop your regenerator cut-point, which will substantially increase the physical acid losses that go out with the spent regenerant.
Since the conversion of the impurities to ASO compounds is not complete, those residual impurities in an alky unit will wind up, again, in the Isom feed and load up the dryers, and the cycle is repeated. The tolerance of a given unit to that wind-up really depends on the amount of available dryer capacity. But if you have a unit that has increased throughput over the years and you have less time between regenerations, you may not have enough drier capacity between regenerations to tolerate that wind-up. And additionally, depending on how much sulfur you have in the refinery, clearly that will have an impact on how much load there is on those dryers as well.
So the most effective alternative is to break the wind-up loop and not have a recycle that’s going to contribute to that increased concentration and basically send the spent regenerant to where it can be more completely converted. What we found to be most effective is to send it to a hydrotreating unit, typically the naphtha unit, and there the impurities will be completely converted; subsequently, the treated butanes can combine with other refinery butanes and be sent back to the Isom feed. In this way, you don’t have the accumulation effect described earlier.
Gasoline ProcessesGasoline Processes•Tolerance to sulfur wind-up varies with the amount of slack drier capacity, amount of sulfur in the refineryIsom Regenerant DispositionAlky UnitDIBIsomDriersIsomUnitAlkylateSpent IsomRegenerantC4 FeedASOiC4 RecyclenC4
Other alternatives can include fueling spent regenerant although that depends on the refinery fuel balance and may present an economic downgrade of butane. It may also affect stack emissions because of the sulfur compounds in that regenerant. Alternately, you could recycle it further upstream to the butane sweetening unit; but again, you’re not going to get as completed conversion as in the hydrotreating unit itself.
We have seen some units, in my previous days at UOP overseas, that were equipped with a large spent regenerant drum that was large enough to contain all of the spent regenerants from the full regeneration. That way, variability of the contaminant concentration could be limited and it could be sent ratably to the downstream destination.
METKA (Sunoco, Inc.)
We operate a Butamer within our HF alky complex. Originally, normal butane was used as the dryer guard bed regenerant, and we routed the spent stream to gasoline blending. Over the years, we had no reported issues resulting from this operation. Approximately three years ago, we performed a study to evaluate using stabilizers bottoms from the Butamer as the regenerant stream and then subsequently reprocessing it in the alky.
The stabilizer bottoms is a dry stream and its relatively high isobutane content results in less alkylation unit impact than would be expected with a normal butane stream. As part of the study, the cycle up of contaminants that Javier discussed was reviewed and its potential impact on the unit was determined to be manageable. We made the piping modifications to route the stabilizer bottoms to the guard beds and to also allow the spent stream to be rerouted back to the HF alky where it is treated and then dried with the BB feed. We’ve had no adverse effects to date with this operation.

KAISER (Delek Refining Ltd.)
In my experience, the cooling water exchangers in an HF alkylation unit are really no more problematic than any other exchanger in the refinery when you’re looking at the waterside only. If you have an exchanger in the HF alkylation unit that suffers from low flow or it’s at the end of a header, trapped scale, and there are certainly critical exchangers inside the alkylation unit that you want to keep clean, it’s really no different if it’s in the alkylation unit or in some other unit in the refinery. You’re going to have water problems and that’s going to generate issues for you.
Generally, what I’ve been able to see is that most of those exchangers will tend to make two to three years. Some of them will go longer than that—four to five, depending on what service they’re in. The things that I’ve seen is that we’ll typically have process-side corrosion issues that generate leaks and that would force us to take that exchanger offline for repair any cleaning before we had significant enough fouling on the waterside solely to force a cleaning by itself.
Both alkylation units that I have experience with have their own dedicated cooling towers. Whether that’s by choice or by design, I’m not sure. What it does allow you to do is minimize the impact of any leaks upon any other process unit or refinery. And certainly when you have a leak in any acid service, be it sulfuric or HF, the key is to track down which exchanger is leaking rapidly and isolate that from the cooling water system so that you minimize damage to your cooling water circuits. Most refineries will tend to monitor pH, ORP (oxidation reduction potential), fluoride, or some combination of these, either on a shift or continuous basis, to help them determine when they have a leak.
Most cooling towers will operate a fairly standard cooling water package. They’ll use phosphates for corrosion control, polymer dispersants, and various other bits and pieces of chemicals. It’s nothing really any different than what you would use in any other cooling tower in the refinery.
METKA (Sunoco, Inc.)
Sunoco has a separate cooling tower at the HF alky complex as well. Our experience is very similar to what was just discussed. We don’t have a special chemical treatment program. We do perform additional pH monitoring for leak detection, and the process side can limit the run for several services.
ZMICH (UOP LLC)
I would like to share some thoughts provided by our Tech Service experts in our Engineering department. At UOP, we have seen corrosion in cooling water exchangers and
alkylation units on both process and water side. Typically, the corrosion rate on the process side of the reactor bundles and on the acid cooler bundles is relatively low at normal conditions, but excessive temperature or higher concentration of percent water in the circulating acid can cause corrosion and plugging on the process side.
Refiners have reported corrosion rates on the process side of water cool condensers, especially if the water content of the circulating acid is high. Low water flow rate can lead to fouling of the tubes from biological growth or calcium scaling, both of which can lead to under-deposit corrosion. Inadequate treatment or blowdown of the cooling water can also cause corrosion on the water side of these exchangers.
An important point is UOP strongly recommends a separate cooling water tower for HF alkylation service, and I believe we include that in our new unit design specifications.
Finally, at UOP, we have seen some new unit activity for alkylation units. Generally speaking, permitting does not prohibit installation of an alkylation unit; but if one is considering addition of an alkylation unit, it should go through what’s considered a quality-risk assessment.
MIKE FACKER (Western Refining Company)
We have a couple of heat exchangers, water coolers, ahead of our KOH, and there’s a temperature limitation there. I am wondering how people try to limit their temperature at that point, whether you try to do it on the water side and take your fouling there. I understand there’s about 100°F limit you want to go into your KOH system. Are you all familiar with that part of the treating or do you know what you do for temperature control there?
KAISER (Delek Refining Ltd.)
What service are these in?
MIKE FACKER (Western Refining Company)
This is behind the alumina.
KAISER (Delek Refining Ltd.)
Is this on propane or alkylate?
MIKE FACKER (Western Refining Company)
Well, we have both propane and butane. The coolers go under the KOH and it is HF, yes.
KAISER (Delek Refining Ltd.)
And this is off your isostripper and depropanizer towers?
MIKE FACKER (Western Refining Company)
Right.
KAISER (Delek Refining Ltd.)
There’s generally not a better cold-sink anywhere than the cooling water, and cooling water is typically used there, from what I’ve seen. No, there’s not a whole lot you can do other than take the hit on the water side and suffer through some high skin temperatures. The thing that you ought to try and do as best you can is to work with your water vendor and do your best to keep the cooling water as clean and solids-free as it can be. You might have to give up some cycles on your cooling tower, get the total dissolved solids down, and keep a close eye on your phosphate.
The other thing that your water vendor ought to be able to do is help you understand what your failure mechanism is. Is it the calcium carbonate? Is it silicate carbonate? Then, maybe the vendor can tailor the water treatment program a little bit more specifically around these particular exchangers if they foul out. The best case situation, which you probably don’t have, is parallel exchangers where you’ll be able to switch back and forth between the two and just plan on a routine cleaning before the deposition gets bad enough to precipitate an under-deposit corrosion.
METKA (Sunoco, Inc.)
That particular service has not typically been a problem for us on the process side, but it has had some issues on the water side. In some of these problem services, we’ve had the opportunity to install some piping connections and we’ve put a little rental booster pump in for the summer operation to increase the pressure and get a little bit more water flow. We have also used the same methods to address water side issues that Allen discussed: adjusting the chemistry and working with the water vendor to try to help prevent it in the first place.
DARYL DUNHAM (UOP LLC)
The particular issue on the cooler ahead of the KOH treater is pretty widespread, and I’ll try and explain how this works. It’s a very common problem. When you’re removing organic fluorides in the LPG Defluorinators, both on propane and butane, the Defluorinators make water as a byproduct. The KOH treater is intended to remove the water. Now in between, you condense and cool the LPG before it gets to the KOH treater. If you have relatively high organic fluorides, you make a lot of water. And if you cool the stream below the water dew point or fallout point, it will form a separate phase. When it forms that separate phase, it will do that on the coldest surface, which is usually the tube wall in that cooler. When it forms that separate phase, any HF present will go with water. So you have a very small amount of water, usually it’s droplets that form with maybe a couple ppm HF coming out of the LPG. So now you have a weak acid and it eats those carbon steel tubes.
So the first indication you’ll see is pitting of the bottom row of tubes in that condenser. And if it goes far enough, you’ll get holes in those tubes and you can get corrosion in the shell.
You can get corrosion in the downstream piping. A lot of people have tried to solve this by putting in Monel tubes in the condenser, and then you start eating the condenser shell. And then if they put in a layer Monel on a condenser, then it starts eating the outlet piping. And so they put in Monel outlet piping, and it starts eating the inlet nozzle on the KOH treater.
A couple of things that we’ve seen refiners do to try to solve this problem is: One, they’ll pinch the water flow trying to limit the outlet temperature so you don’t reach the dew point. One refiner has put in a coalescer downstream of the water cooler to knock any free water out before it eats any more piping up. We had one refiner that had an innovative approach of injecting steam into the cooling water to raise the cooling water temperature so they didn’t reach the dew point on the exchanger tubes.

KAISER (Delek Refining Ltd.)
Again, just to re-emphasize, I’m not currently on an HF unit so part of this response will rely on some former colleagues of mine. I would not make a blanket recommendation to change the material specification for carbon steel in HF alkylation units. To me, the risk is too great. I understand that there are certain times when things are tight and you might need immediate material delivery and there’s no other option, but I would not make a blanket relaxation in the material specifications. I would only relax the material specifications in very particular circumstances, with a conscious and informed choice by everyone in the refinery, and only with an inspection and maintenance program that has been thought out in advance and allowing for the response plan developed to be able to handle leaks if they do happen to occur.
The second part of the question, API RP 751 does recommend post-weld heat treat for all welds, and they specify a limit of 200 Brinell hardness for the welds. Welding procedures can be adapted to provide you with a lower hardness weld, but they, in and of themselves, are not sufficient always to provide you with that. So you should probably plan to post-weld heat-treat all of the welds that are made during your turnarounds or during your projects.
The third part of the question: We believe small bore piping should be flanged. Not only does this provide more consistent material selection for the refinery for the purchasing agents, but it also provides a more consistent maintenance program and inspection program for those departments inside the refinery. Again, RP 751 does have provisions in there to use screwed connections and inspection procedures, if those are existing, but it would be our recommendation to make all new connections be flanged. There are some addition references in a couple of NACE papers: NACE 03651, “Specification for Carbon Steel Materials for HF Acid Alkylation Units,” and NACE 5A171, “Materials for Receiving, Handling, and Storing Hydrofluoric Acid.” Both contain good references for materials selection in HF alkylation units.
DARYL DUNHAM (UOP LLC)
As we mentioned earlier, ConocoPhillips sold their HF alkylation technology to UOP. I used to work for ConocoPhillips; now I work for UOP. When UOP took over that technology, they retained their existing HF technology and gained this technology that they bought from ConocoPhillips so they have two sets of specifications now that we’re dealing with. So some of these issues about how you fabricate equipment and how you do small bore piping can be addressed by two sets of recommendations: historical UOP recommendations and the historical ConocoPhillips or Phillips recommendations. So if you’re operating an HF alky and you have any questions about that, you might want to contact us and we can work those issues out. There’s a little more flexibility than it used to be on how you do that.
We do have a team working to get the one set of specifications in the future. Right now, we are trying not to isolate anybody. If your existing specifications are fine, we’re not going to ban anything; but, we’re going to try and merge these into one consistent set of recommendations where we have a main recommendation and acceptable backup position in a lot of places, like screwed piping versus socket weld and four-bolt flanges versus eight-bolt flanges, things like that.
MIKE FACKER (Western Refining Company)
We’re having a little trouble in our same KOH treaters, a little carryover with the KOH. The question is: Is there a good way to stop that carryover and/or is there a good way to wash it before you get your product tunics?
HAZLE (NRPA)
Michael, are you looking at me like you want to respond? I didn’t think so.
NEWTON (Roddey Engineering Services, Inc.)
I’m looking to see what Allen says. [laughter]
KAISER (Delek Refining Ltd.)
I’ve seen this exact same problem before. Unfortunately, I wish I had the true answer because I never found out truly what it was or if it’s been fully fixed. So maybe we can get together with some of the Coffeyville guys and chat about it a little bit later on. I do know that that’s a problem out there and we had talked with UOP about the KOH treater design. There was some maybe thought about caustic carryover, the dilute KOH carryover, in some downstream lines, may be related to the particular velocity that we were sending through there. There was also some talk about some organic fluorides that might be carrying through and causing some issues, so maybe we can chat about it a little later on.
DARYL DUNHAM (UOP LLC)
You guys, come on up to the suite tonight and we’ll talk about this. [laughter]
I do want to make one comment on the solid bed KOH treaters on the LPG; I assume that’s what you’re talking about. Like I said earlier, the LPG stream is wet going to the treater. The solid KOH will absorb the water. You form a sludge and it falls off. Now historically, the ConocoPhillips KOH treaters were up-flow and the UOP treaters are down-flow. There’s a little bit of difference in how the sludge is handling in those two. One issue I’ve seen is in the down-flow there’s a baffle in the bottom. If you’ve had problems with that baffle, you’re more likely to carryover some of that sludge downstream. So that’s probably the first thing you’ll look at is if that baffle is in good shape in the bottom. And then, the second one would be if you running too high velocities in that bottom and can you be lifting some of that sludge and taking it out with the product stream.
RICHARD DOSS (CITGO Petroleum Corporation)
It’s been a long time since I worked with that type unit; but also in that bottom, there’s an interface level that has to stay working or that bottom starts carrying over very badly.

GRUBB (Chevron USA, Inc.)
I consulted our corporate experts for this, Shingou Lou and Dave Kohler. We built one in Pascagoula and their basic response was that there’s really no reason to expect any more instability problems than you would have with normal olefins. And as with the other olefins, if you let them go unchecked, they could lead to an insoluble gum residue. These can be mitigated effectively with some antioxidants—the phenylenediamine-hindered phenol. They do recommend that you inject them very close to the source unit. Like I said, Pascagoula converted an MTBE plant and we had no instability issues at our plant. Corporate-wide, we actually have experience with two ion exchange resin-type catalyst units, two solid phosphoric acids distributed on solid support-type catalyst units, and we have experience with Dimersol-type units. We haven’t experienced any instability problems in any of those. Some instability problems could come with feed contaminants that could lead to further gum formation. That would be diolefins or mercaptans, if they were in the feed, but those could both also be mitigated with antioxidants. So we use antioxidants in all of our units and haven’t experienced any problems.
QUINTANA (Valero Energy Corporation)
Similar to Allen’s response, we have several isooctene units in operation. They emerged from our MTBE phase-out strategy. We have some that have FCC BB feed stocks, as well as dehydrogenated feed stocks. We haven’t had any issues with stability. We do inject the antioxidant immediately at the rundown point when it comes out of the cooling water exchanger. We monitor the stability with a stability test, such as ASTM 525, and adjust the dosage as needed based on the analytical result. Your chemical treatment vendor should be able to provide some new guidance on specific chemicals and dosage rates that are appropriate.

ZMICH (UOP LLC)
This question refers to or asks about benzene hydrogenation and how it affects to isomerization reactions, maximum levels in the feed, and where does it happen in the reactors. So what I thought we would do is start out with what am I talking about: benzene saturation.

If you look at the slide, you see that benzene in the presence of hydrogen over a platinum-containing catalyst will generate heat and saturate to cyclohexene. Now, this benzene saturation reaction is fast and it happens near the inlet of the isomerization reactor; or if you have a saturation reactor, near the inlet of this benzene saturation reactor.

If you look at point number 2 and 3, in order to assure a maximum octane and yield from an isomerization unit, it is necessary to saturate the benzene. There are two things that happen: One, benzene is an acid function poison that will basically increase the effective space velocity through the remainder of the reactors. Benzene reaction is also highly exothermic, so it tends to increase, the temperature of the reactant as it progresses through the reactor. So the reactor outlet temperature is higher.

There are problems with higher reactor temperatures. If we look at the graph here, we see the equilibrium of isopentane relative to total pentanes. The “y” axis is the iso-to-normal ratio and the “x” axis is the reactor outlet temperature. Increasing temperature in the case of benzene saturation, or having to operate at a higher reactor inlet temperature to effectively get the same level of conversion, forces you to the right on this graph. So that forces you to a lower iso-to-normal, a lower octane at the reactor outlet or lower PIN number: paraffin iso-to-normal ratio.

Gasoline ProcessesGasoline ProcessesIsomerization-Feed Benzene•Saturation happens near reactor inlet•Benzene saturation necessary for max octane & yield•Acid function poison-activity loss for isom reaction•High dHrxnincreases reactant temperature•>3% benzene-multiple reactors with intercooling •>5% benzene possible with UOP PenexPlusTMBenzene+ 3H2HeatCatalystHydrogenCyclohexane

The fourth comment is about greater than 3% benzene and multiple reactors. In general, multiple reactors with inner-cooling may be required to process a feed with more than 3 vol% benzene because of the high heat of reaction. And then for most purposes, what we see as a general rule is anywhere from 0 vol% to 5 vol% is pretty typical for chlorided alumina isomerization unit. For units that are processing benzene or desire to process benzene with greater than 5 vol% in the feed, then we need to look at perhaps revamping the unit to include or add a separate benzene saturation reactor upstream of the isomerization unit.

KAISER (Delek Refining Ltd.)
In the Isom units that I’ve run, we have periodically run with as much as 5 vol% benzene in the feed and as much as 8 vol% total benzene plus material, not always on purpose. We’d rather those heavies be down in the reformer feed where they belong, but we did have experience with that. Again, it was a multi-bed reactor with quench between a few of the reactors to handle any exotherms that might have developed.
Gasoline ProcessesGasoline ProcessesEquilibriumiC5/C5P Equilibrium CurvesiC5/C5P = iC5/(iC5 + nC5) x 100%687072747678808284200225250275300325350375400Reactor Outlet Temperature, FiC5/C5P, wt%Vapor Phase Liquid Phase

QUINTANA (Valero Energy Corporation)
Our experience is similar to what Joe and Allen have indicated. We’ve processed Isom feed as high as 5 vol% benzene without a dedicated saturation reactor and, of course, see the exotherm that results. The inter-reactor cooling capacity and the resulting temperature to the lag reactor inlet will determine the isomerate product quality that results, in line with the equilibrium charts that Joe showed earlier.

KAISER (Delek Refining Ltd.)
The question is very well phrased in that the introduction of ethanol into the blend pool does tend to reduce the need to run the isomerization unit in that ethanol is a very high RVP blend component, and it has enough octane to be able to possibly offset the need for the octane boost that you’re getting out of your isomerization unit. So when a refiner wants to introduce the ethanol into their blend pool, there are three likely scenarios that they’ll go through in their unit operations. The first is obviously shut the isomerization unit down. And again, the ethanol stream is large enough and has enough octane to be able to overcome the octane boost that you’re losing by not having run the Isom unit. Ethanol, in that case, is likely to be cheaper than the processing cost of running the isomerization feed in your unit. There can be potential drawbacks to that, and we’ll talk about those here in a second.

The second move is likely to reduce the cut-point so to speak on your naphtha splitter and lighten up the isomerization unit feed. Directionally, your reformer can do a few more things with those heavier molecules with the C6s and C7s that your isomerization can’t. There’s probably still some incentive to upgrade the octane on your pentanes and you’ll choose to run your Isom in that situation. Directionally, you get kind of a slight improvement in your overall reformate and isomerate blend pool. And if you’re running petrochemical applications, then definitely the C6s and C7s, as much as possible, belong down in your reformer.
The third option is you keep going like you’re going. In that case, you’re probably running the isomerization unit not necessarily for octane boost, but probably for benzene destruction or other compliance reasons, in which case you’ll have to make changes in other units within the refinery to accommodate the higher vapor pressure ethanol. You may be in a tight spot constrained by debutanizers in your cat or gasoline hydrotreater or some other unit. What it might mean is that during the summer, you may need to store some of your isomerate or store some of your Isom feed for offsite storage and then bring it back in the wintertime when the RVP schedule changes and you have room to blend it again.

At Delek, we let our isomerization unit idle about two years ago, which was unrelated to ethanol. We got into a situation where we had enough flexibility in our blending to be able to save the processing costs of our isomerization unit. We introduced ethanol into our blend pool. We’re making 100% E10 right now. What it does mean for us is that we have some periodic storage during the summer months of our otherwise isomerate feed stream and we’ll bring it back in the wintertime when our blend schedule allows.

QUINTANA (Valero Energy Corporation)
We agree with Allen that the main impact of ethanol blending will be to reduce the refinery octane requirement and constrain RVP. Furthermore, as our keynote speaker yesterday indicated, we also see essentially flat to declining gasoline demand from refineries, net of the impact of ethanol and imports in the overall pool.
As a result of this, we expect C5 Isom economics to be negative with 100% CBOB blending in the national gasoline pool, while C6 economics alone may be slightly better. However, most refineries don’t have the equipment to separate C5s from C6s and with the isomerization function that occurs on the C6 paraffins through the reforming unit, there is not much incentive to necessarily build new equipment or convert equipment to provide that C6 cut by itself.
Gasoline ProcessesGasoline ProcessesLN Isomerization Feedstocks•The Renewable Fuels mandate has impacted Isomerization unit economics due to:–Reduced octane requirements in refinery CBOB (Conventional Blendstock for Oxygenate Blending) gasoline pool–Increased vapor pressure constraints, as RVP specifications must be met after ethanol splash blending at the distribution rack–Flat gasoline demand from US refineries
As such, we expect that the MSAT II requirements will likely lead to shutdown of the Isom units, and benzene that was previously saturated in the Isom unit will likely be dropped in the reformer feed, as Allen suggested will likely happen. And then, post-treating of the reformate to either extract or saturate the benzene. If saturation is the preferred option, then the Isom unit could be converted to benzene saturation alone without impacting RVP of the pool.

SUBHASH SINGHAL (KNPC)
Are there Isom units doing the octane of 91 or close with the recycle options?

HAZLE (NRPA)
Are you asking if they make 91 octane with recycle?

SUBHASH SINGHAL (KNPC)
Right.

QUINTANA (Valero Energy Corporation)
In the past, I’ve come across some overseas where there is integration with an absorptive separation unit on the recycle. Occasionally with the diisohexanizer recycle, you might achieve close to that, but you might be limited about 89 or 90 in most cases. In the U.S., you don’t see many with this scheme.
Gasoline ProcessesGasoline ProcessesLN Isomerization Feedstocks•Each refinery’s situation is unique, but in general:–C5 isomerization economics will be marginal / negative–C6 isomerization economics likely slightly better, but:•Would need additional equipment to isolate C6 species from C5 fraction –may be difficult to justify•Reforming units provide isomerization function on C6 fraction•MSAT II regulations may drive benzene containment post-reformer, leading to more C6 fraction in reformer feed–Some isom units may be converted to saturation only.

KAISER (Delek Refining Ltd.)
The Isom tip that I had experience on, we saw about 95% conversion of pentanes and about the same on hexanes. We ended up with a stabilized product of about 88 to 89 octane, but very rarely it would be on that. The TIP process is one that uses zeolite absorbent beds where you recycle the reactor product through there, absorb the normals, and recycle those back to the reactor.

ZMICH (UOP LLC)
This question relates very well with Question #80 that we discussed a few minutes ago, and what I’d like to do is touch upon some of the key points that we mentioned there. So Item #1 on the slide relates to the naphtha isomerization units being flexible in their ability to handle benzene. Typically, 3% benzene in the feed and in a range of 0 vol% to 5 vol% is normal. For item #2, as benzene increases, the reactor ΔT increase because of the heat of reaction, decreasing the research octane number or the PIN. The higher temperature means lower isomerization or lower iso ratio. Also, as benzene increases, it poisons more of the catalyst in the reactor, which effectively is increasing the space velocity across the reactor, forcing one to operate at a higher average reactor inlet temperature, which drives the reactor outlet temperature up and pushes the RON or the PIN number down. Item #3: As I mentioned before, a chloride alumina catalyst system typically operates up to 5 vol%. The last item: For an Isom process unit containing less than 5%, we can add a saturation reactor upstream of that, revamp a typical Isom unit by adding a saturation reactor, to be able to handle up to 30 vol% benzene up to and greater than 30 vol% benzene in the feed.

KAISER (Delek Refining Ltd.)
As an operator of a refining company and facing the MSAT II regulations, the objective is clearly stated: You need to get the benzene out of the gasoline pool. There are two ways to do it: You can either extract it or you can turn it into something else. When we approach the problem, we started out with the extraction route. But as a small refiner far enough from any potential sales sources or consumption sources for benzene, extraction is not going to be an economic choice for us. We’d be a small producer and a high cost producer, and it’s likely that a lot of the refiners that are extracting now are going to be increasing their volumes. There are probably even going to be other refiners who are not currently making benzene that are going to start. And so for us, extraction is kind of out the window.

We turn, then, to saturation and there are two choices there. You can do kind of a post-treatment saturation plant where the benzene has already been made and you’re trying to destroy it. Or, you can do a pretreat-type option where you take the benzene precursors in your reformer feed and you try to isomerize those to get some octane boost, but it reduces the amount of benzene that you produce.

The other thing that we’re considering and wanting to do as much as possible, because this is an environmentally driven project with technically no return, is that we want to be able to reuse as much equipment as we have. We do have this idle isomerization unit, as I’ve stated before. Being able to reuse those assets and minimize our capital investment, again, minimizes the financial impact upon the refinery itself.
So the things that we’ve done: We’ve been looking at our reformer feed splitter to see what we can do there. Are we going to be able to push enough of the benzene precursors out of the reformer feed to get the benzene content low enough in the reformate.

And then, once we see
Gasoline ProcessesGasoline ProcessesIsomerization-Benzene•Light paraffin isom units flexible to handle benzeneBenzene T RONBenzene effective LHSV RON•PenexTMunit to 5% benzene•PenexPluscapable >30% benzene
whether or not we can get away with that, what is the feed to the isomerization look like? Is it too heavy? Is there too much benzene in there? Are there too many heavies in there? Is it just totally worthless as isomerization feed? If we start looking at the backend of the reformer, if we take a light cut or a hard cut of the reformate, what does that look like for an Isom feed? Is there too much benzene in there? Are we going to install a dedicated saturation bed? Is the equipment that we have going to be sufficient for that? You couple that with the fact that to saturate benzene, it takes 4,500 scfb of hydrogen to saturate the benzene. Now we’re looking at hydrogen balance within the refinery between all of our other hydrotreaters and the production off of our Platformer. And the fact that ethanol has reduced the need to run higher severity on the reformer for gasoline octane, there’s a potential that we’ll be running the reformer for hydrogen and not for octane. So this becomes a very convoluted situation, and we’re trying to minimize capital investment.

The other thing that we’re seeing recently with some other projects that we’ve accomplished is that for major pieces of equipment—reactors, vessels, compressors, heaters, we’re looking at 52 weeks of delivery. So just a warning for everyone out there, if you haven’t already started on this and you don’t already know what you’re going to do, you’re out of time. You need to figure it out right now because between six months of engineering, a year of procurement, and six months of construction, it’s 2011.

QUINTANA (Valero Energy Corporation)
Joe and Allen have covered this very well already. As we’ve indicated earlier, we can handle up to 5% benzene in an Isom unit with a dedicated lead saturation reactor. The specific limitation for any given unit is determined by the inter-reactor cooling capacity and the lag reactor performance target. As Joe was further indicating, you can go to higher levels of benzene in the feed, but you may need to recycle some low benzene product to dilute the feed benzene if you are beyond the per-pass limit on the saturation reactor inlet. We should note also the impact on hydrogen consumption that Allen has covered. We also see that many of our reformers in the future are likely to be driven by the refinery hydrogen balance. And given the excess octane in the future, we’re going to likely see a fair amount of octane giveaway as a result of that.

Now if you do convert your Isom unit to saturation alone, one possible benefit is that it could eliminate some chloride-related corrosion issues, so you may get some reliability improvements as a result.

I like most of the things that the panel has discussed here. One of the things I really want to ask a question about is: If we are looking at a feed benzene level of 5%, typically what might be the x factor for the feed? I think one of the concerns we have is with the 5% benzene content feed. There could be up to about 100°F exotherm in the lead reactor and the refiner could be incapable of operating with a 5% benzene feed.

KAISER (Delek Refining Ltd.)
Yes, earlier when we were talking about the 5% benzene in the feed and up to 8% benzene-plus, I don’t remember exactly what the X factor of that was, but it was significant enough to impact the overall yields on that isomerization unit. That’s something that you’ll need to work with your technology provider on once you’ve decided pre-fractionation, post-fractionation. They’ll need to do yield projections for you on that and account for the very high exotherms that you will see in that lead isomerization reactor because it does have a large impact on your isomerate yields and what they look like.

METKA (Sunoco, Inc.)
We operate four solvent extraction units. The literature reports that there are alternative solvents available that have more capacity and are more selective than the traditional solvents. The degradation products, however, can still be corrosive. The use of any of these new solvents should be carefully reviewed and evaluated. Comprehensive review of your existing unit design and how it relates to a new solvent is essential. Our experience is that the corrosion tendency and acidity of the tradition solvents can be controlled if the solvent is properly monitored and maintained.

The keys to good solvent quality control are minimizing air infiltration, effective regeneration and removal of light organic acids, and solvent filtration. This can be accomplished by using direct feeds or nitrogen blanketed tanks, effectively de-aerating imported feed stocks, and eliminating air leaks in the regeneration systems. Helium testing and pressure tests, specifically hydros, have proven to be effective tools for leak identification. Maintenance of the regeneration and filtration system is also essential.

Establishing good monitoring practices can readily identify issues. Typical process indicators include solvent pH, color, and acid number. Our experience has shown that the solvent quality can be greatly improved and corrosion tendency reduced by addressing these items. One of our units was challenged to maintain solvent quality and control corrosion for an extended period.

A concerted effort to identify the air sources and repair the regeneration system resulted in significant improvement in solvent quality as can be seen on the slide. You’ll see on the first one that pH was low for a very long period. We repaired our overhead fin fans in our solvent recovery section in repaired the regenerator condenser. There was significant improvement in the pH.

Gasoline ProcessesGasoline ProcessesSulfolane pH History23456789pHRepaired Ovhd FinFansRepaired Regen Condenser

This is also seen in the acid number presented in this next slide. Once both things were repaired, we had a significant decrease in acid number.

Gasoline ProcessesGasoline ProcessesSulfolane Acid# History00.050.10.150.20.250.30.350.4ACID #
Repaired Ovhd FinFansRepaired Regen Condenser

Another one of our units that historically had adequate solvent quality began to deteriorate due to solvent regenerator charge limitations. There were mechanical issues on our condensate system, which limited the regenerator reboiler system. We repaired the condensate system, the performance improved, and we increased charge to the regenerator. As you can see, once we made the repairs, solvent pH significantly improved and our color number dropped.

QUINTANA (Valero Energy Corporation)
Valero also has four extraction units. We have three different solvent systems among those units. All of them are subject to oxidative decomposition and corrosion associated with that if the solvent treatment methods and recommendations are not followed. As such, we agree with John that it’s best to deal with the root cause of oxygen ingress and improve solvent quality rather than consider an expensive solvent change-out. Since different solvent systems have different optimal heat exchanger configurations, you may incur additional equipment costs to look at a change of solvent system.

Gasoline ProcessesGasoline ProcessesUDEX Solvent Quality012345678910Solvent pH0123456Solvent ColorSolvent pHSolvent ColorRepaired Solvent RegeneratorRegenerator SD for Exchanger Cleaning
The key sources of oxygen are either through the feed or leaks in the vacuum section, as John has suggested. The main strategies to limit oxygen ingress via the extraction feed are summarized on this slide and in The Answer Book, so I won’t go through them all in detail here. But the main objective is to reduce the dissolved oxygen in the feed to less than 0.5 ppm.

We should note conventional Sulfolane units with a liquid phase extractor are likely at more risk to feed oxygen than extractive distillation units because an extractive distillation configuration will tend to strip the oxygen overhead, and you don’t necessarily contact the dissolved oxygen with the solvent phase in the hotter parts of the unit. John has already mentioned helium leak testing as providing help to identify vacuum leaks. Furthermore, it’s important to monitor flange-face finishes, especially in older units. Over time, if you do a lot of blinding, you may scratch up some of those flange faces and you may have to reface them in order to prevent vacuum leaks.

Another consideration is around pumps. When you’re doing pump maintenance, if you use temporary blinds, you can affect the alignment of the pump. That may give a greater tendency in the vacuum section of the unit for oxygen ingress. In that case, you might consider installing permanent spectacle blinds or spacers to eliminate those misalignment problems.