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PIMENTEL (CITGO Petroleum Corporation)

We have extensive experience with the use of ammonia in the FCC flue gas line in order to improve the conductivity of the particles and improve the operation of the ESP. We inject ammonia at the target level of 10 parts per million or less. It is very effective at that concentration and has helped us reduce our baseline opacity level from about 15% to less than 10% or 5%. It also reduced the peaks. The peaks that you see in the chart are related to soot blower operations of the waste heat boiler. Thanks to the ammonia, we now operate the soot blowers more often without the fear of violating the opacity limit. So it is also an energy-saving project.

In our unit, the ammonia is injected directly downstream of the waste heat boiler from cylinders or from a storage tank located outside of the FCC battery limits. The only issue I can recall with this operation has been the loss of ammonia flow due to the regulators plugging with ice. If the ammonia is not completely dry, it will freeze in your regulator. That is easy to fix by putting some steam tracing in the lines. The chart shows typical performance before and after starting the injection of ammonia. As you can see in the chart, it helps us operate the soot blowers more often.

BROOKS (BP Refining)

As Sergio mentioned, the common use for putting in steam and ammonia is to reduce the resistivity of the particulate so it can be picked up easier in the ESP. We do not have a lot of experience with steam helping our ESP operations, apart from the example I mentioned about using steam on start-up before meeting temperatures necessary to use ammonia.

We do have quite a bit of experience with ammonia injection. All of our ammonia injection systems are fairly similar because, again, we use the same consultant for the vast majority of our ESPs. We also found that it is key to focus on your ammonia injection system providing good dispersion in the flue gas stack and good vaporization of your ammonia. Typically, all of our systems include heaters for vaporization and metering injection pumps, so we know how much ammonia we are injecting. The systems also include good dispersion nozzles for the flue gas stacks.

When we use ammonia in our unit, we typically try to optimize it. As shown in the example of an ammonia step test in the slide, the blue and orange lines are essentially the same. They both tell you how much ammonia we are injecting. However, we tend to double-check the meter on the pump stroke versus the actual amount coming in just to make sure we are getting good readings.

You can see that the test includes our stepping up injection rates until we meet a level where we feel like the opacity – the green line – has leveled out. You keep stepping up your ammonia until you believe you have leveled that on opacity, and then you step back down until you feel like your opacity has gone back up. Those are the areas where you would target your ammonia injection rates because you know that is the minimum necessary to maintain your opacity.

I also want to add that I am not sure if other sites have seen instances similar to what we have noticed. Some, but not all, of our sites with ammonia injection into their ESPs also saw a reduction in NOx as a result. It makes sense because you use ammonia in a SNCR (selective non-catalytic reduction) and also in a SCR (selective catalytic reduction) to reduce NOx. However, we do not see it in all of our units.

Those units with high NOx tended to show a good step down and leveling out similar to what we saw with the opacity, which can be seen in the purple line representing NOx. So, you may get an added NOx reduction benefit if you use ammonia on some of your units. We also did the same step test on other units and saw no response to NOx; so, it is not a guarantee.

SCHOEPE (Phillips 66)

I do not have much to add. Halle highlighted all of the points. Phillips 66 has a few installations where we inject ammonia into the ESP. Collection efficiencies were increased by 25% to 50%. It is critical to have good ammonia injection quilts which inject ammonia across the entire duct. Typically, we have not seen any issues with ammonium salt deposition anywhere in the downstream equipment.

MARTIN EVANS (Johnson Matthey Intercat)

To give a contrary comment, I heard a few people talk about the importance of dispersion. We recently had one refiner start ammonia injection and have trouble with the quill. When the quill was removed and the ammonia was injected straight into the nozzle, he got a similar reduction in opacity as he had been getting with the quill. So go figure. It is always the same with the FCC. You can prove something on one unit and then prove the exact opposite in another unit. Another point I want to make is that we have seen that opacity can increase when refiners go to low SOx emissions, typically below 50 ppm and certainly below 20 ppm. This occurs, if you are not using ammonia, because the SO2 (sulfur dioxide) actually acts in the same way as does the ammonia to decrease the resistivity of the catalyst and improve the efficiency of the ESPs. So, when you take out the SO2, you have to replace it with ammonia. Otherwise, you will lose ESP efficiency when you get down to very low SOx levels.

PIMENTEL (CITGO Petroleum Corporation)

We have extensive experience using ammonia in the FCC flue gas line to improve the performance of the ESP. NH3 is a very effective way to improve the conductivity of the flue gas at the levels as low as 10 ppm. In our experience the use of ammonia helped to reduce the flue gas opacity from an average of 15% to less than 5%. Ammonia is injected directly in the flue gas line downstream of the waste heat boiler (at about 500°F) from cylinders or directly from an ammonia storage tank located outside of the unit battery limits. The only operational issue with this system was plugging the regulators with ice, which was solved by steam tracing upstream of the regulator/orifice plate. We do not have experience injecting steam in the flue gas line to improve the operation of the ESP.

BROOKS (BP Refining)

BP does not have a great deal of experience using steam to improve ESP operations. We have one site that uses steam in the ESP during start-up to improve efficiency before the ESP is hot enough to add NH3 injection. This is to prevent possible salt formation that can result from adding NH3 into a cold ESP. The majority of our units use ammonia (NH3) injection successfully to improve ESP collection efficiencies. The purpose of using steam or NH3 injection upstream of the ESP is to condition the particulates by decreasing their resistivity. Decreasing particulate resistivity makes them easier to attract to the walls of the ESP, thus leading to higher collection efficiencies.

As mentioned above, BP uses an industry consultant with a multitude of ESP experience to help guide our ESP operations and optimization efforts. The majority of our NH3 injection systems are similar and follow the consultant’s guidelines, which typically include heaters for vaporization and metering injection pumps. Some sites have basic injection nozzles in the ducts while others have full injection grids. The key considerations for this injection system are around ensuring the injection point provides good dispersion in the flue gas duct and that they NH3 is sufficiently vaporized. Un-vaporized NH3 injection can cause issues with particles remaining on the collecting plates and falling off in chunks or hopper pluggage caused by sticky fines which leads to difficulty evacuating hoppers.

BP has also done a series of NH3 step-tests to optimize NH3 injection. These tests are simple adjustments to NH3 flow rates that are compared to improvements in stack opacity for each step as can be seen in the example graph below. During these tests we have seen that the reduction in opacity with increasing amounts of NH3 injection lines typically lines out at some point, as can be seen in the graph below.

Our experience with NH3 injection has generally been very good at sites with good injection systems. In addition to improvements in opacity with NH3 injections, BP has also seen some reduction in NOx at some of our sites. Generally, we have seen sites with higher base NOx levels see reductions in NOx with NH3 injections and others with lower base NOx levels may not see any change in NOx emissions with NH3 injection.

SCHOEPE (Phillips 66)

Ammonia has been used effectively in a number of refineries to increase electrostatic precipitator (ESP) collection efficiency. Ammonia decreases the resistivity of the catalyst which makes it easier for a catalyst particle to accept a charge. Depending on the ESP design aqueous ammonia injection can increased the ESP collection efficiency by 25% to 50%. A successful installation requires good distribution of the aqueous ammonia. Injection quilts need to be designed to distribute the ammonia equally across the area of the flue gas duct upstream of the ESP and resist catalyst erosion. Deposition of ammonium salts is typically not an issue.

MELDRUM (Phillips 66)

Promoted or multi-metallic reformer catalysts have been a topic of research since at least the early 1970s. They have been tried commercially in various forms over the years, all with the objective of improving yields by suppressing the demetallization reactions. The current promoted catalysts have advanced the formulation of manufacturing techniques to new levels of performance. Recently, Phillips 66 has selected promoted catalysts for future reloads in at least three of our sites. The additional cost of the catalyst is justified when considering increased product yield and improved activity that allows a lower reactor temperature requirement, which both provide for a very quick payback on the additional catalyst cost.

The example shown on the slide indicates the additional yields – both in the C5+, as well as hydrogen – and some improved activity that might be expected with a promoted catalyst. When selecting the promoted catalyst, regeneration procedures should be reviewed with the catalyst vendor to ensure that maximum catalyst performance from regeneration to regeneration is achieved, particularly in the area of reduction and dryout steps.

BULLEN (UOP LLC, A Honeywell Company)

We have two catalysts that we offer in the semi-regenerator market and also for cyclic reforming applications. One of them is the R-98 catalyst that was introduced in 2005 and which has over 50 installed applications. We have a new catalyst called R500 that has better activity and stability, and we have put it in 10 units. As Craig said, proper regeneration procedures are very important for any semi-regeneration unit, and maybe even more so for these tri-metallic systems, because of the issues related to dryout and reduction. It is important to get consistency with this procedure because you will lose the advantage of the tri-metallic system if you do not do the dryout and reduction correctly. Getting that repeatability is very important.

CRAIG MELDRUM (Phillips 66)

Regeneration procedures should be reviewed with the catalyst vendor to ensure maximum catalyst performance from regeneration to regeneration. For example, UOP R-72 was a promoted catalyst offered about 15 years ago and required a different reduction procedure than the non-promoted catalyst for hydrogen concentration, pressure, temperature, and dry-down schedule.

PATRICK BULLEN (UOP LLC, A Honeywell Company)

Trimetallic catalysts containing rhenium are typical for use in fixed-bed reforming applications, both semi-regenerative and cyclic reforming applications. In recent years, both additional metals and oxides have been added to platinum-rhenium reforming catalysts. Metal promoters have been added to increase selectivity and product yields. The additional metal partially suppresses platinum-rhenium activity, reducing metal-catalyzed hydrogenolysis that lowers selectivity.

Over the past decade, UOP successfully developed the proper catalyst base, formulations (including promoter type), and manufacturing techniques needed to generate catalysts that demonstrate excellent yield stability and regenerability. UOP’s R-98 catalyst was introduced in 2005 and has over 50 successful applications with many regeneration cycles, and our customers are benefiting from the higher yields. UOP recently introduced a new product, R-500, that shows even great activity and stability, with over 10 commercial applications. It is well suited for reforming units where even longer cycle lengths are desirable or where higher activity is needed to push more barrels. The gradual acceptance of promoted catalysts is analogous to that of the bimetallic catalysts having higher rhenium content that preceded them in this market.

Proper regeneration procedures are critical for the success of any semi-regeneration catalyst; and in particular, promoted formulations that have reduced metal activity. One Best Practice is to ensure proper dry-down, reduction, and sulfiding. Cyclic reforming applications are a little more demanding due to the regeneration environment (higher moisture and sulfur, for example), but new promoted formulations have been demonstrated in these applications as well.

SONI OYEKAN (Prafis Energy Solutions)

This question needs some more definition to elicit appropriate responses with respect to what is truly a “trimetallic” catalyst. My initial response is that my experiences in the use of “trimetallic” platinum-rhenium catalysts for fixed-bed cyclic regeneration reformer operations were good. The catalysts performed as projected by the catalyst and technology supplier for catalysts containing a third metal that was specifically added for modifying the acidic functionality of the catalysts.

Having written that, it is important to understand the type of catalysts commonly referred to as “trimetallic” catalysts. The term could cover Pt/Re (platinum/rhenium) catalysts with a third metal as a modifier for the alumina to moderate the acidic functionality of the catalysts or those in which the third metals are added to modify the hydrogenation functionality of the platinum or to moderate rhenium hydrocracking activity. In other trimetallic catalyst formulations, the third metal can work in conjunction with the rhenium as co-promoters for the platinum functionality.

The performance objective of the third metal is crucial in order to assess long-term performance and benefits of the third metal. Metals on catalytic reformer catalysts typically undergo varying degrees of reduction to different oxidation states at different temperatures and adequate metals redispersion are achieved at different oxidative conditions. Trimetallic catalysts’ expected performances and potential limitations should be well understood by oil refiners before acquiring them for use. Catalyst suppliers should provide test data to show multiple regenerations and adequate reactivations of the three metals, even if the other two metals are acting as co-promoters for the platinum. Another key factor is to ensure that optimal metals distributions are achieved during catalyst manufacture. There are other factors to consider that are beyond inclusion in this short response on trimetallic catalysts.

If the third metal has been added to moderate catalyst acidic functionality and reactivation of that third metal is not an important factor other than decoking, then the refiners’ challenges are lessened to some extent. It should be recalled, however, that the history of catalytic reforming is dotted with an oil refiner’s experiences with second metals that had been added to the platinum and which led to significant performance problems. The problems were related to inadequate metals activation, especially poor redispersion of the promoter metals, and these problems led to poor catalyst performance for subsequent cycles after the first cycle for fixed-bed catalytic reforming systems. Furthermore, in reforming catalyst development programs, the addition of metals to Pt/Re catalysts led to increased feed sulfur sensitivity challenges for the resultant trimetallic catalysts. Feed sulfur sensitivity and catalyst regeneration challenges should be studied sufficiently by the catalyst and technology supplier during that supplier’s catalyst development studies leading to the production of “trimetallic” catalysts.

MELDRUM (Phillips 66)

Carbon monoxide can form in reformer units as the hydrocarbon reacts with moisture under very low-unit pressure conditions. Typically, semi-regeneration reformer net gas would have nil CO and only a minimal amount in a CCR-type unit. I expect it to probably be on the order of 5 ppm (parts per million), though some units report routine measurements of 10 to 20 ppm CO in their net hydrogen off gas.

One of our cyclic units that was operating at 400-pound had CO as high as 20 ppm in its net hydrogen stream when the recycled moisture rose to around 300 ppm. The excessive water entered the reformer from a leaking side reboiler on a wet debutanizer that used a slipstream of the reformer reactor effluent as the heat source. The water then returned to the reformer product separator. The high CO caused deactivation in the catalyst in a downstream isomerization unit.

Accurate measurements of CO in the net gas are difficult. Reformer units are not expected to have much CO, so they seldom have an online analyzer. A colorimetric tube – Gastec or Dräger type – can be used to give an indication of the presence of CO, but accuracy for a quantified number is difficult and requires the use of a carbon pre-tube to remove the hydrocarbons.

CO is detrimental to downstream hydrogen-using units in three principal areas. CO in hydrogen being fed to a distillate hydrotreater will methanate, consuming the hydrogen that would have otherwise been used for the desulfurization reactions. This will have the effect of lower catalyst activity. CO in hydrogen fed as a makeup stream to an isomerization unit will also methanate and form moisture that will deactivate the isomerization catalyst. CO that did not methanate in the second example could act as a poison to the platinum metal function of the isomerization catalyst. UOP suggests a CO limit of 1 ppm max for isomerization hydrogen makeup gas. My Answer Book response also includes some of the common steps used to minimize CO formation in reformer units, particularly in a CCR unit.

BULLEN (UOP LLC, A Honeywell Company)

As you can see in this table, we have correlated some different types of operation and ranges of CO levels. As Craig alluded, the numbers vary quite a bit, which can be due to conditions in the unit, as well as analytical capabilities. There seems to be a trend that the lower pressure units generate more CO than higher pressure units.

The laboratory method we recommend using is UOP 603, which is a laboratory method for CO and CO2 and hydrogen. However, a lot of refiners cannot do this method. The gas detection tube route is fairly common. Our point of view is that with the gas detection tubes, if one carbon pre-tube is good, then two is better. So, we usually ask them to use two tubes instead of one to help eliminate the breakthrough of hydrocarbons that can make a false high value for CO.

As Craig said, the issue with chloride and alumina isomerization catalyst is that you will deactivate the catalyst. However, if you are using another type of catalyst, like the Par-Isom catalyst or zeolitic catalyst, the actual suppression you will get will be very dependent on what temperatures you are running. As you approach the 400°F temperature, you tend to methanize the CO in the first part of the bed. So CO tends to have less of an effect on the metal function of the isomerization catalyst and becomes more of an issue of activity suppression due to the water on the acid sites. The same would apply if you had a saturation unit with platinum catalyst. It would also behave in a similar manner to these higher temperature isomerization units.

R.K. (RICK) GRUBB (Chevron Products Company)

Another aspect needs to be mentioned for the lower pressure reforming units. You have to take into consideration your nickel carbonyl formation when you shut down a hydroprocessing unit that is using the reformer hydrogen. You may have to either swap the hydrogen source or think of another shutdown procedure that will ensure no nickel carbonyl formation.

CRAIG MELDRUM (Phillips 66)

CO is detrimental to downstream hydrogen using units for three principal reasons:

1) CO will methanate in HDS (hydrodesulfurization) units consuming hydrogen, which will take away catalyst activity.

2) Much of the CO will methanate in isomerization units, forming water that will deactivate the isomerization unit catalyst.

3) The non-methanated CO in the isomerization unit will poison the metal function of platinum on the catalyst.

Note: The UOP suggested CO limit on isomerization unit hydrogen makeup gas is 1 ppm (10 ppm for CO + CO2). UOP reports that CO levels greater than 6 ppm will not allow the isomerization unit catalyst to meet its cycle life guarantee.

The common steps to minimize CO formation in the reformer are:

• Minimize moisture in the system (feed water control and good regeneration drying),

• Minimize the last reactor temperature,

• Maximize the H2/HC ratio, and

• Minimize catalyst circulation rate in a CCR.

PATRICK BULLEN (UOP LLC, A Honeywell Company)

The CO concentration in reforming unit net gas can be impacted by a number of factors: system pressure, temperature, and moisture in the recycle gas, as well as the H2/HC (hydrogen/hydrocarbon) of the operation. Operating pressure has the most significant impact on CO production in a reforming unit. CO formation in reforming operation is produced via steam reforming of hydrocarbons:

H2O + CH4 ↔ CO +3H2

Thermodynamically, this CO formation reaction is more favorable at lower pressures. CO production is inversely proportional to the pressure squared. As such, a semi-regeneration reforming unit, being significantly higher pressure than typical continuous reforming units, will tend to produce less CO than a typical continuous reforming operation. Likewise, the lower pressure high severity reforming unit operation is more favorable for CO productions.

Commercial reforming net gas CO data from CCR Platforming™ process units can range from 1 to 40 mol ppm. The table below indicates typical ranges for various unit types. Typically, CO levels in the semi-regeneration reforming units are at trace ppm levels due to the high pressure and low-moisture range operation.

For testing of CO in reformer net gas, UOP recommends method UOP 603 for trace CO and CO2 in hydrogen. For CO in light gaseous hydrocarbons, analysis by GC is recommended. Analysis by gas detector tubes can also be considered for measuring CO at elevated levels when used with several carbon adsorbing pre-tubes.

CO in reforming net gas can have an impact on downstream users that may be sensitive to CO or H2O that may be formed due to the reverse steam reforming reaction, also known as the methanation reaction. In the case of a Butamer™ and Penex™ catalyst, water is a permanent deactivator. A typical rule of thumb is that 1 pound of H2O kills 62 pounds of Butamer™ and Penex™ catalyst.

For other types of catalysts, such as Par-isom™ Process and zeolitic isomerization catalysts that operate at higher temperature, the water generated from methanation of CO is a temporary activity suppressant. Platinum-based BenSat™ catalyst behaves similarly to these isomerization catalysts.

GARY HAWKINS (Emerson Process Management)

With respect to the second part of the question, the carbon monoxide content, as well as other components in the net gas of a naphtha reforming unit, can be measured with a variety of measurement principles depending upon the accuracy and reliability required, other species present that may interfere with a particular technology, and the expected range of concentration of carbon monoxide. These same comments apply to measuring other refinery gases, such as the net hydrogen and PSA (pressure swing adsorption) tail gas from steam reforming units for hydrogen production.

SRIVATSAN (Foster Wheeler USA Corporation)

Again, FCC slurry/decant oil has a similar distillation range to HCGO but a higher endpoint. Although it could possibly be used as just overhead quench, we caution that if the slurry/decant oil is not be filtered properly, it will contain catalyst fines that could accelerate the coke deposition by settling in equipment or piping. We normally recommend using the blowdown tower bottoms as the primary source for quenching the overhead vapor line. The secondary means of quenching is provided using HCGO. LCGO and other gas oils, including slops, can also be used as desired.

PRIBNOW (CITGO Petroleum Corporation)

We do not have any experience using slurry oil as coke drum overhead quench. We utilize slop oil, as Srini mentioned, as a way to vaporize and reprocess that material. We charged slurry oil to our coker when excess capacity was available. However, we found that it degraded the heavy coker gas oil quality back to the FCC. The FCC conversion drops, and catalyst becomes dark; so, we tend not to do that much anymore.

SRINI SRIVATSAN (Foster Wheeler USA Corporation)

The purpose of the coke drum overhead quench oil is to reduce coking reaction by lowering vapor temperature and mitigating coke formation. A portion of the overhead quench is also condensed and forms recycle. Foster Wheeler recommends using the blowdown tower bottoms liquid as the primary means to quench the overhead vapor line, the secondary being the use of HCGO. LCGO and other gas oils including slops can also be used as desired. FCC slurry/decant oil has a similar distillation range as HCGO with a higher endpoint. Although it could possibly be used as an overhead quench, we caution that if the slurry/decant oil is not filtered properly, it may contain catalyst fines that could accelerate coke deposition by settling in equipment or piping.

EBERHARD LUCKE (CH2M Hill)

Although I never worked in a unit that used FCC slurry/decant oil as quench oil, we used it as coker feed; so, my concerns are based on that experience. FCC slurry/decant oil carries a significant amount of cat fines that are difficult to remove from the stream. So I would assume that with the injection of the slurry/decant oil, these cat fines will be introduced into the coke drum overhead system. The fines will end up either on the inside of the vapor line, in the bottom of the fractionator, or carried even further through the system and will act as seeds for coke buildup and cause accelerated fouling/coking of equipment. The cat fines will also most likely cause erosion in the nozzle that is used for quench oil injection. Additionally, quench oil distribution will be poor (but can be fixed by the selection of the correct material).

ROBERTSON (AFPM)

Before we get to the last question, I want to remind you that the Crude P&P is this afternoon at 2:00. During that time, a lot of these issues we have covered will be discussed in more depth. Tomorrow, the Light Tight Oil and FCC P&Ps are run concurrently. If you have any other issues you want to discuss that were not raised in this forum, please attend those P&Ps.

BULL (Valero Energy Corporation)

I will initially address this question from a CO standpoint and then discuss the NOx. CO emissions typically increase if the regenerator falls below a certain temperature threshold. That temperature threshold will vary based on your regenerator configuration and definitely on the type of air distribution. In general, well-mixed regenerators with longer residence times can be run at significantly lower temperatures before CO emissions increase, compared to a poorly mixed regenerator with lower residence time.

In the absence of a CO combustion promoter, large variations in the CO2 (carbon dioxide)-to-CO ratios are observed. At the catalyst surface, it is believed that that CO2-to-CO ratio is an intrinsic function of the temperature at the burning site. However, the CO exiting the burning site may be further oxidized to CO2 at a rate dependent on the temperature, amount of CO and O2, water partial pressure, and active metals on the catalyst.

To mitigate CO emissions at low regenerator temperature, we add a non-platinum CO promoter to limit the NOx. Other solutions include increasing 1) your delta coke, 2) the pressure in the regenerator, or 3) the mixing by modifying the regenerator. The amount of NOx emitted from the regenerator is highly dependent upon several variables such as operation regenerator style, excess O2, promoter concentration co-distribution, feed nitrogen, and dense bed temperatures. So, there are many variables that determine the overall NOx equation. NOx formation chemistry inside the regenerator is difficult to pin down. Studies have shown that about half of the feed nitrogen becomes coke on the catalyst, but only a small portion of that actually becomes NOx. It is also believed that NOx emissions are limited by the reaction of CO plus NO (nitric oxide) to form N2 (nitrogen gas) and CO2. Thus, when you have platinum CO promoters added to the unit, CO is converted to CO2 so quickly that there is less CO available for that reaction to occur.

We do have an experience of the regenerator being in true countercurrent flow. With platinum promoter in the unit, it is able to run NOx levels that are very low; but, I will say that is a rarity. In our system, if there is normally a platinum promoter, then you will see elevated NOx levels. In partial-burn operation, there is always CO available to react with the NOx; so emissions are lower. Good coke and air distribution is important to ensure that the concentration of CO, O2, and NOx are evenly distributed throughout the regenerator. The results have been better and more efficient control of the burn zone so that oxygen is used more efficiently and the regenerator can be operated at lower levels of excess oxygen to completely burn the coke to CO2. Generally, you do not need to use platinum promoter. Finally, uniform residence time distribution minimizes the duration that spent catalyst remains the regenerator.

Due to the interaction between CO, NOx, and the FCC regenerator, I recommend that you actually conduct testing to determine the tipping point where you start going up in CO emissions because there are benefits from lowering the oxygen at that time. Running O2 in excess slightly above that tipping point provides a good NOx baseline of your minimum level on the unit. If that level is still too high, then you have other options which include LoTOx™, WGS+™, CONOx™, and SCR (selective catalytic reduction). We have all of these applications across our system. We have very little experience with NOx reduction additives.

GIM (Technip Stone & Webster)

The low regen temperature used to be beneficial. However, with the advent of tight oil and light feed stock, actually too much of a good thing is now bad. So let us first consider what causes some of these low regen temperature phenomena.

The first cause is a result of better feed stock qualities, such as lower Conradson carbon, lower nitrogen, and metals. Second, lower operating severities, such as lower reactor outlet temperature and lower catalyst activity, will reduce regenerator temperatures. The third cause is catalyst regeneration, including full- versus partial-burn, CO promoters (platinum-based or non-platinum-based), and supplemental oxygen that has been turned off.

Jeff described many of these aspects, but I thought it would be worthwhile to summarize all of the factors into three main categories. One is, obviously, the combustion kinetics. Second is the hardware of the actual generator design; and third, to a certain aspect, are the feed contaminants such as feed nitrogen. In terms of combustion kinetics, a lot of these items have been discussed multiple times in past panels, so I will just go over the basics and summarize them. The lower regenerator temperature increases the CO but decreases the NOx or NO2; the promoter lowers the CO. But in terms of the distinction between a platinum and non-platinum base, the promoters can be either increased NO2 or NO2 neutral. The higher O2 concentration lowers the CO and increases the NOx. Again, these are some of the factors that you can use to counteract the formation of CO and NO2.

BART de GRAAF (Johnson Matthey INTERCAT, Inc.)

All of the speakers mentioned that the low temperature does affect the CO oxidation and the formation of NOx. The nitrogen kinetics in the regenerator are not affected by the lower temperature. Nitrogen in coke can be converted into nitrogen in NOx, hydrocyanide, and ammonia. As was suggested, non-platinum combustion promoter can be used to steer the oxidation reactions from HCN and NH3 towards N2 instead of NOx. Partial-burn operation is one example where you can see that the CO concentration does affect high NOx. But at the same time, in a partial-burn operation, after the CO boiler, you frequently see a higher NOx level than you would have in a full-burn operation because of the high temperature oxidation in CO boiler.

KEN BRUNO (Albemarle Corporation)

I want to point out that Albemarle has a detailed answer in the Answer Book. But in summary, Albemarle’s non-platinum promoter, ElimiNOx™, provides high CO promotion, excellent afterburn, and minimal impact on NOx emissions.

ROBERT “BOB” LUDOLPH [Shell Global Solutions (US) Inc.]

If you are an oxygen enrichment operator or considering oxygen enrichment, this is your opportunity to raise your bed temperature at the same coke burning rate and shift the CO and NOx distribution within the bed. In turn, the control of NOx and CO emissions could improve.

MICHAEL WARDINSKY (Phillips 66)

We have done a lot of modeling around NOx and CO emissions for additive use. We have seen NOx emissions decrease with higher regen temperatures in almost all of the modeling cases. From our experience, we also know that the non-platinum promoters can increase NOx emission, although not as severely as a platinum-based promoter. We have moved partial-burn units from deep partial-burn to full-burn and observed the NOx emissions decrease substantially. I think it was from the gentleman from INTERCAT who mentioned that in partial-burn, you are releasing ammonia and HCN (hydrogen cyanide) off the regenerator in greater quantities than during full-burn operations. However, these reduced nitrogen species are combusted across the CO boiler to NOx, so your partial-burn units always appear to emit higher NOx emissions than operating in full-burn, even after accounting for thermal NOx generated in the CO boiler.

JEFFREY BULL (Valero Energy Corporation)

CO emissions will increase if the regenerator falls below a certain temperature threshold. That temperature threshold varies based on the regenerator configuration and the type of air distribution. In general, well mixed regenerators with longer residence times can be run at significantly lower temperatures before CO emissions increase compared to a poorly mixed regenerator with lower residence times. In the absence of a CO combustor promoter, large variations in CO2/CO ratios are observed. At the catalyst surface, it is believed that the ratio of CO2/CO is an intrinsic function of the temperature at the burning site (“Arthur's ratio”). However, the CO exiting the burning site may be further oxidized to CO2 at a rate dependent on temperature; CO, O2, and H2O partial pressures; active metals on the catalyst; carbon/oxygen distributions within the fluidized bed; and even the catalyst presence.

To mitigate CO emissions at low regenerator temperatures you can:

• Add non-Pt (platinum) CO promoter to limit NOx,

• Modify your operation to increase your delta coke (catalyst or operational changes),

• Increase pressure in the regenerator, and/or

• Modify the regenerator to increase mixing.

The amount of NOx emitted from the regenerator is highly dependent upon several variables such as mode of operation, regenerator style, excess O2, promoter concentration, coke distribution, feed N2, and dense bed temperature. Studies have shown that about half of the feed N2 goes to coke on catalyst, but only a small portion of the N2 in coke goes to NOx. It is believed that the NOx emission is limited by the reaction of CO + NO to form N2 and CO2. Thus, when Pt CO promoter is added to a unit, CO is converted to CO2 so quickly that there is less CO available to react with the NOx; so NOx emissions increase. We do have experience with a regenerator that is in true countercurrent flow, and the operator is able to run at low NOx levels with platinum promoter in the unit. In a partial-burn operation, there is always CO available to react with the NOx formed; so, emissions are lower. Good coke and air distribution are important so that concentrations of CO, O2, and NOx are evenly distributed throughout the regenerator.

The results of the better, more efficient control of the burn zone in a regenerator are that:

• Oxygen is used more efficiently so that lower levels of excess oxygen are required to completely burn the coke to CO2 while minimizing CO emissions.

• Generally, no Pt combustion promoter is needed (at design rates) to accelerate the burn to completion.

• The uniform residence time distribution permits the time spent in the regenerator to be minimized.

Due to the interaction between CO and NOx in an FCC regenerator, testing should be conducted for your individual regenerator to determine the “tipping point” where a reduction in excess O2 causes CO emissions to increase dramatically. Running at an excess O2 slightly higher than the “tipping point” provides a baseline NOx that you can expect for your unit. If this level is too high, then you will either need to modify your regenerator for better mixing or use an alternate method of NOx reduction like LoTOx™, WGS+™, CONOx™, or an SCR. We have four LoTOx™ applications, one WGS+, one CONOx™, and one SCR in our system. In some cases, a catalyst additive can reduce NOx, but we have limited experience with this application.

STEVE GIM (Technip Stone & Webster)

Why lower regenerator temperatures? Let us first examine some of the factors leading to lower regenerator temperatures: first, better feedstock qualities (such as lower Conradson carbon), lower nitrogen, and metals. Second, lower operating severities, such as lower reactor outlet temperature and lower catalyst activity, will lower regenerator temperatures. Third, catalyst regeneration, including full versus partial-burn, CO promoters (platinum-based or non-platinum-based), and supplemental oxygen turned off are additional options.

Factors Directly Affecting CO and NOx: Many of these directly affect the formation of both CO and NOx in the regenerator. Some of these factors influence the formation of these two species in opposite direction. I have summarized these factors into three categories and their directional changes of the CO and NOx. Many of these items are obvious and have been extensively discussed in the past panels, but I thought it would be a good summary.

Interactions Between CO and NOx: Reductant-like CO converts NOx to elemental nitrogen in the presence of O2. Lower regenerator temperature can be the direct result of higher CO to CO2 ratio in partial-burn units, which in turn will lower the NOx.

CHRIS STEVES (Norton Engineering)

The impact of low regenerator temperature on CO and NOx emissions can be very unit-specific, depending especially on regenerator design and the distribution of air and coke in the regenerator. In full-burn units, operation at low regenerator temperature will generally result in higher CO emissions and lower NOx emissions. The use of CO promoter can help in reducing CO formation, but use of platinum-based promoters is well documented as increasing NOx emissions. Non-Pt-based promoters are widely used today to allow for control of CO (and afterburning associated with CO) while limiting NOx emissions.

RYAN NICKELL (Albemarle Corporation)

Though not directly stated, this question is most applicable to FCC units concerned with after-burn. Lowering the regenerator temperature can indeed lead to an increase in CO and NO to N2 and CO2. A platinum-based combustion promoter can be used to reduce CO emissions with excellent success. However, NO will increase as intermediates, such as HCN and NH3 (ammonia), are also oxidized by platinum. As a result, many refiners prefer a non-Pt-based promoter such as Albemarle’s ElimiNOx™. This additive provides high CO promotion activity but acts less on the aforementioned intermediates containing nitrogen. ElimiNOx™ provides excellent after-burn control and minimal impact on NOx emissions.

KOEBEL (Grace Catalysts Technologies)

When talking about catalyst mesoporosity, we are referring to the matrix contribution, especially the 100 to 600 ǻngström pores found in the catalyst matrix activity. Catalyst matrix activity is really important, particularly in the Type I cracking depicted here, in the mix zone of the riser where the mix zone can be on the order of 1100°F. Even in VGO types of operations, you can have a significant portion of the total feed that may not vaporize at those conditions. Having effective diffusion is important for pre-cracking these types of feeds so that the zeolite can efficiently crack it further later on up the riser. Certainly, even in VGO operations, we think that avoiding diffusion limitations in the mix zone can be tremendously important.

I queried the Grace database on FCC feed. Even in gas oil and VGO operations, the average was that about 10% of the feed boiled over at 1000°F; so clearly this is not just a resid phenomenon. This is a factor in FCC operation that Grace considers to be very important in even the VGO operations.

The next slide shows a commercial example of a refinery that was running on a catalyst and implemented 50% of Grace’s MIDAS® catalyst into the blend. MIDAS® is a catalyst for which Grace specifically maximizes the mesoporosity and matrix surface area in the mesopore range. You can see that over a wide range of conversion, the slurry yield was reduced by 2.0% absolute. This is a gas oil operation. Even though this would not be a feed you would consider to be heavy resid, clearly the matrix contribution to the efficiency of the cracking was obvious.

The question also asks about possible disadvantages of mesoporosity. I believe that it might be a disadvantage to have too much mesoporosity in the catalyst when there is a need for high zeolite activity, which is certainly very important, particularly in this Type II cracking where you are going to try and de-alkylate side chains off of naphthenic and aromatic cores. This cracking is very efficiently done by zeolite. If you have a catalyst system that is too biased towards matrix surface area (MSA), you may have a deficit in zeolite activity. So, you certainly want to make sure you have the proper Z/M (zeolite/matrix) ratio on all feeds.

JOE McLEAN (BASF Corporation)

We introduced a catalyst called NaphthaMax® back in about 2000. Really, the only difference between NaphthaMax® and its predecessor-type technologies was that there was a higher porosity version. It has been, by far, our best-selling gas oil catalyst line ever since. We are continuing to refine and introduce newer versions of it. Obviously, I agree with Grace, and certainly with Jeff, that it does make a difference, even in gas oil applications, because it has. We have added over 100 NaphthaMax® users over the past decade or so who could attest to that benefit.

It should not surprise you that we will differ in our opinion a little. I am talking about the zeolite versus the matrix; because with our DMS (dimethyl sulfide) technology, we can put in the mesoporosity. We actually use the external zeolite surface that now gets exposed and available in the larger pores as it functions the way that catalyst is manufactured. So even with the higher porous systems, we are able to get just as high of a zeolite content; and in fact, better zeolite efficiency and activity than what we have with less porous systems generated with the predecessor technologies that we had.

KEN BRUNO (Albemarle Corporation)

Indeed, we agree that mesoporosity is important; but when you talk about diffusion, it extends beyond mesoporosity. In addition to intra-particle diffusion, what is also critical is surface diffusion. To quantify that, Albemarle often talks about the Accessibility Index. Again, mesoporosity is important, but what is more important is the combination of surface and intra-particle diffusion as measured by the Accessibility Index.

PAUL DIDDAMS (Johnson Matthey INTERCAT, Inc.)

Just a quick comment: Do not forget that there are also concentrated additives which contain these kinds of mesoporous cracking sites.

JEFF KOEBEL (Grace Catalysts Technologies)

Effective bottoms cracking involves a three-step bottoms cracking mechanism which was discovered by Zhao1 (Figure 1). The first step is largely dependent on the catalyst matrix and porosity, and that is the effective pre-cracking of large molecules in the feed.2 Since the riser mix zone temperature can be on the order of 1050°F, feed components over 1000°F+ will not readily vaporize. Thus, these molecules need to pre-crack on the catalyst matrix before the catalyst zeolite can further crack them to desired products.

Grace’s FCC feed database contains many examples of units processing VGO and GO that still have a significant portion of the total feed to the unit with a boiling point above 1000°F. In fact, the average 1000°F+ in VGO and GO FCC feed is approximately 10% across our database (Figure 2). Thus, pre-cracking is a real consideration, even in a non-resid operation.

The pore volume of an FCC e-cat (equilibrium catalyst) sample is typically analyzed and reported by each vendor. However, the size distribution of the pores is also a critical component of the effectiveness of the catalyst porosity. Liquid phase diffusion, like one can find in the mix zone of the riser, is typically 2 to 3 orders of magnitude slower than gas phase diffusion, especially if the pores are small (less than 100 Å).4 High mesoporosity in the 100 Å to 600 Å range mentioned in the question is critical for achieving effective pre-cracking of heavy molecules without diffusion limitations. Excess small pores less than 100Å will lead to high coke and gas make, while an abundance of large pores greater than 1000 Å will have ineffective bottoms cracking and perhaps poor attrition characteristics.

Grace’s MIDAS® catalyst family is specifically designed to provide higher matrix surface area (MSA) with an optimal pore size distribution that provides excellent mesoporosity. Grace has many commercial examples of GO and VGO operations that have benefited from the inclusion of some portion of MIDAS® in the fresh catalyst mix. This commercial example shows that inclusion of MIDAS® into a catalyst system for a VGO application improved bottoms conversion by 2% absolute (Figure 3).

The question also asks about possible disadvantages of mesoporosity. As was mentioned previously, there are multiple steps to effective bottoms cracking. Another step in the conversion of bottoms is dealkylation of side chains from aromatic and naphthenic cores (Figure 1). This is a step that is most efficiently catalyzed by zeolite activity. If a catalyst formulation is too heavily biased towards MSA in an effort to achieve high porosity, it is possible that the formulation may not have adequate ZSA to efficiently drive this type of bottoms conversion. The proper balance between matrix and zeolite is heavily dependent on feed properties and unit yield objectives. Optimization of matrix porosity and zeolite activity is critical to achieve the most effective bottoms cracking, even in light feed applications.

CAREL POUWELS (Albemarle Corporation)

Mesoporosity is typically considered an important feature for enhanced bottoms conversion. This is not only valid for resid applications, but also holds for VGO operations. The effect, however, depends on many aspects, such as the type of VGO, severity of operation, and the base catalyst in use: the more crackable material present in the slurry fraction, the more potential impact by additional mesoporosity. This is particularly valid when the additional mesoporosity is applied within the same catalyst technology. Changing catalyst technology with additional mesoporosity will not necessarily yield the desired effect as the activity, and selectivity of the mesopores between the catalyst technologies can be different. Another aspect that plays a role is catalyst accessibility, which is often confused with catalyst porosity. Poorly designed catalysts can measure high mesoporosity but are not effective as constricted pore openings act as bottlenecks and result in a low accessibility. Thus, it is key to design a catalyst with high mesoporosity and high accessibility.

While mesoporosity (and accessibility) plays an important role in bottoms conversion, it also contributes to the preservation of important primary cracking products such as olefins in the gasoline range. These are important components for high gasoline RON (research octane number) and also precursors for the production of propylene.

Another potential benefit of catalysts with reduced mass transfer limitations in VGO applications becomes evident in units with advanced riser termination devices (RTDs) and short contact times. Under these circumstances, reactants can travel faster to the active sites, and products can egress from the pores before the catalyst is separated from the hydrocarbons in the RTDs, resulting in higher conversion and reduced rate of secondary reactions (everything else constant, compared to a catalyst with inferior pore architecture).

Albemarle offers a wide suite of products for different VGO applications with a varying range in mesoporosity and accessibility, such as AMBER™ for lowest slurry, GO-ULTRA™ for maximum gasoline, ACTION® for superior gasoline octane and alky-feed, and AFX™ for record high propylene.

LARSON (KBC Advanced Technologies, Inc.)

For the purpose of this answer, we will look at this as a resid cat cracker that would have a catalyst cooler or be in a two-stage operation. Any increase in feed hydrotreating which increases the portion of hydrotreated feed, or an increase in hydrotreating severity, will obviously improve the feed quality. The slide shows a representative material of a gas oil plus resid and then what it might look like on the basis of a hydrotreated feed. You will notice that by using Watson K or refractive indices, the quality of the feed improves quite substantially. We see that the Concarbon (Conradson carbon) is dropping quite significantly. In those cases, you will have a substantially different coke balance in the unit, and you will see the regenerator fall.

So, what are some of the conditions that you might evaluate to change the operation? One condition is that you will see a much higher cat-to-oil in the unit. Operationally, catalyst circulation itself will go up. The slide valve may need to be increased further. So, then what will be the counter-condition you will need to examine? Can you circulate the catalyst rate that is needed to operate? If you have a two-stage system and a cat cooler, can you keep the cat cooler in operation? Do you just turn it off completely?

Make sure you can get as much trapped diesel out of the unit as possible; because if you distill it in, even if it is only 10%, it will be acting like another cat cooler. With regard to catalyst change, we have a lot of catalyst vendors here. That may be one of the first product you examine in order to maintain the heat balance. You might also consider adding carbon. If you have hydrotreated feed, you can add carbon through the HCO recycle overflash, provided you can maintain the sulfur specifications on your products. You also need to consider the pressure balance to keep the unit operating within targeted range.

In a step change on the existing unit, if you are far enough away from turnaround, you might have to take actions that you would not do in an optimized situation, like reducing the actual steam to the feed nozzle to reduce mixing to allow the addition of carbon. Because it is a situation that exists now and has to be lived with it until the next shutdown, we have clients who have actually pulled steam out of the stripper and let hydrocarbon slip into the regenerator to keep up the profile, which allows them to run the unit. These are non-ideal situations and are done in lieu of mechanical adjustments so you can stay online. Before doing any of the above recommendations, you should consider first a catalyst change.

KOEBEL (Grace Catalysts Technologies)

I want to add one comment about hydrotreated resid. I made a quick query of Grace’s worldwide catalyst database and found some examples of people running hydrotreated resid or partially hydrotreated resid. There were still very, very high levels of metals: much higher than you would consider for a traditional hydrotreated feed operation. Certainly, from a catalyst standpoint, a unit running some hydrotreated resid and a portion of actual resid can still have very high metals; so, you need to make sure you are considering that as part of your solution on the catalyst side as well.

Another phenomenon we see regularly is that the unit running some hydrotreated feed and some resid has a dumbbell-type distribution – a lot of light feed but also some 1300°F plus material – so that type of feed will not behave as if it was blended properly. So, consider the overall distillation of the feed when selecting catalyst as well.

JEFF KOEBEL (Grace Catalysts Technologies)

One catalytic challenge related specifically to resid units that process hydrotreated feed is delivering the proper balance of catalyst activity, metals tolerance, and bottoms cracking. Hydrotreated resid, or a mix of resid and some sort of hydrotreated feed, can still contain a significant amount of contaminant metals. One example of a unit processing hydrotreated resid has in excess of 1600 ppm Ni and 3500 ppm V on e-cat, which is much higher than traditional hydrotreated gas oil operations (Figure 1 and Figure 2). With this level of metals contamination, it is important that the catalyst have proper metals tolerance, which one does not normally think of when considering a hydrotreated feed. Having the proper balance of zeolite and matrix activity is also critical to achieve an optimal level of bottoms conversion. In instances where the feed is a mixture of hydrotreated and untreated resid, the resulting feed blend will not behave at all like a feed with its blended API and K factor. Therefore, the capability to optimize the zeolite and matrix balance in the FCC catalyst becomes even more critical.

MEL LARSON (KBC Advanced Technologies, Inc.)

For the purposes of this answer, the designation of resid FCC will be defined by those units with either a catalyst cooler or a two-stage operation. Any increase in feed hydrotreating (either increased hydrotreater severity or an increased portion of the feed being hydrotreated) will improve the feed quality resulting in a lower regenerator temperature. Resid cat crackers, which are designed to burn large amounts of coke, often have problems maintaining sufficiently high regenerator temperature with treated feeds.

When the coking tendency of the feed drops or lowers dramatically, it is a good time to review the crude and vacuum unit operations and any post-hydrotreating fractionation to ensure that the diesel content of the FCC feed is reduced as much as possible since light boiling feed will reduce regenerator temperature. We have found several instances where a minor revamp of the vacuum unit allowed an increase in the vacuum gas oil cutpoint by up to 90°F (or more). This results in more and heavier charges to the FCC, which will increase regenerator temperature.

The normal considerations with lower regenerator temperatures are catalyst circulation issues and regenerator combustion profiles and carbon removal from the catalyst that are very different than the design basis. Therefore, the objective is how to maintain regenerator temperatures that keep the unit within reasonable operating parameters. Operational changes are defined as follows:

• Minimize heat removal via catalyst coolers or quench systems as much as possible. Longer term and depending upon the situation, eliminating regenerator heat removal system could be considered.

• With two-stage regeneration systems, minimize air rate and coke burning in the first stage and shift it to the second stage so a greater percentage of the coke is burned in the total combustion mode. For single-stage regenerators with cat coolers, move toward total combustion with minimum excess oxygen in the flue gas if the unit is in partial combustion.

• Consider a catalyst change. RFCC (resid FCC) units typically use catalyst with low coke selectivity to help minimize regenerator temperatures. Whenever a significant change in feed quality is anticipated, a catalyst evaluation should be conducted to assure that the best catalyst for the new operation is selected. Moving from a low coke-selective catalyst to a high coke-selective catalyst can add 30°C to 50°C to the regenerator temperature.

• Add slurry recycle to the riser.

• Lower stripping steam.

• Lower dispersion steam.

• And lastly, introducing torch oil (in the extreme case) can be considered. The addition of an external fuel source directly to the regenerator (torch oil) has a deleterious effect on the FCC catalyst.

Lower coke yield or lower regenerator temperatures can be an especially severe problem for units with two-stage regenerators. With some of these designs, some coke must be burned in partial combustion; so, there may well be insufficient heat available to run the unit on gas oil or severely hydrotreated resids. This really highlights the need to consider feed flexibility when designing new units as changes in relative crude prices, crude availability, or product specifications (especially sulfur content) can make resid cracking unattractive.

Despite the drawbacks of reducing stripping steam mentioned earlier, we have at least two clients who, after exhausting the other options, have found it economical to do this rather than continue to charge resid to the FCC. In one case, this was a temporary solution used until a catalyst reformulation could be put into effect. In the other, it is still used as a trim variable.

Hardware changes to consider accommodating higher catalyst flux rates would include, but not be limited to:

• Elimination of heat removal system on regenerator,

• Review of standpipe and slide valve sizing, and

• Expansion of capacity given that the air blower is less constrained.

Consider post-treat options that allow a more carbonatious feed.

WATKINS [Advanced Refining Technologies (ART)]

Arsenic is a big concern because it is a permanent poison that causes fairly significant activity. We generally see around a 60° Floss per weight percent pickup; so you will want to pay attention to it. As a side note, it is also common in most fractions of hydrotreating: so anything from naphtha to heavy gas oil. Since there are a large number of process variables, catalysts, and operating conditions, the level that would define where a dedicated trap is actually needed will really depend on how much arsenic is coming into your reactor and possibly what other catalyst is present there as well. Generally, we like to monitor how many pounds of arsenic per day are coming into your hydrotreater; then, we look at the controlling mechanisms for deactivation.

The chart on the left side of the slide compares relative arsenic pickup on the catalyst to the actual amount of nickel present in the reactor. One of the major factors for how much arsenic your reactor can hold is how much nickel is sitting at the top of your reactor, or even in the whole reactor. So, as you go from left to right, you can see you can pick up quite a bit more arsenic.

What also controls arsenic pickup is the operating temperature of your hydrotreater. You can generally look at the weighted average bed temperature or the actual temperature of where the catalyst is located. Something like a diolefin reactor down at 250°F to 300°F will pick up a very low level of arsenic. Whereas if you get up into the 650°F to 700°F range, that same catalyst can pick up a significant amount if it is in the right location. So, these two factors will really define how much volume we need to place, in terms of a guard catalyst in your reactor.

With phosphorus, there is the same problem. In this case, at about 1 wt% (weight percent) pickup, we see somewhere in the order of 10°F loss in activity. That number goes up as you get significant levels of phosphorus on the catalyst, but the first amount is not necessarily as important. On the bottom of the slide is a table showing a spent catalyst analysis from a reactor. You can see that this unit was able to pick up phosphorus even on some of our guard material. So, in some of our rings and support, you can actually pick up quite a bit of phosphorus. Again, that is related to temperature. It is also related to alumina surface area, similar to silicon trappings. So that should be your focus. Really, the amount of catalyst in your hydrotreater will determine where you define your need for dedicated trap material. We recommend spent catalyst analysis for looking at things like that.

SIVADASAN (UOP LLC, A Honeywell Company)

Arsenic is a poison for hydroprocessing catalysts and tends to be specific to crude sources. We have seen that how they apply to catalysts is mainly determined by the type of reactions being carried out. So for example, in a ULSD (ultra-low sulfur diesel) unit, if you see where an indirect hydrogenation route is the preferred part, then concentrations as low as 500 to 1,000 ppm (parts per million) of arsenic can affect the activity of the catalyst by more than 50%. But in a unit that is processing around 500 ppm of diesel, the catalyst will be able to withstand up to 1 wt% of arsenic before you see a 50% reduction of the life. Due to the broad range of arsenic concentrations, electro, and cycle lengths, we believe that it is not possible to confidentially cite a specific threshold concentration above where its dedicated arsenic trap system may be required.

Phosphorus, again, can enter into the hydrotreater unit from various sources like crudes, drilling fluids, and phosphated trendsetters. They are the same biofeeds. We believe that the phosphorus generally tends to be quite similar to the sodium. Around 1 wt% of sodium may affect the activity of the catalyst by more than 50%. The catalyst performance and maximum allowable limit are highly dependent on the source and form of the phosphorus.

MUKESH PATEL (Reliance Industries Ltd.)

What is the Best Practice for analyzing arsenic and phosphorus? Should it be done weekly or on some other frequency? Because arsenic is very important when the crudes are changing every now and then, what should be the frequency and what is the industrial experience?

SIVADASAN (UOP LLC, A Honeywell Company)

The determination of arsenic is a bit difficult, as you pointed out, because it interferes a lot with the lab analysis. What people generally do is run a cycle, do a spent catalyst analysis, and then back-calculate how much amount of arsenic is in the feed.

MUKESH PATEL (Reliance Industries Ltd.)

When we say spent catalyst analysis, it is some sort of analysis of used catalyst, right? But what is a better predictive estimate we can do? Because when you want to capture, you can decide on some limit on the arsenic and then put in an arsenic trap. But if you keep putting on an arsenic trap, you will ultimately have a challenge because you will be compromising on cycle life. What I mean to say is that spent catalyst analysis is done after the completion of the cycles, which tells you what the true level of arsenic was in your feed. For example, suppose you are deciding about some loading for the new cycle and how to capture arsenic. Once you start putting in more and more arsenic traps or any demetallizing catalyst, you will be compromising the cycle because your volume will be less in the main catalyst. So, has there been any development where the conventional arsenic traps have a certain capacity for absorbing the arsenic? Is there any new development to help us capture three or four times the arsenic with the same type of volumes?

WATKINS [Advanced Refining Technologies (ART)]

The amount of trap will really depend on your main bed catalyst and your guard catalyst up at the top. If using a high-nickel catalyst, you could actually trade off and balance that activity; so you will maximize your cycle. If you have nickel catalyst in your entire reactor, you could extend your cycling because you can actually pick up a lot more arsenic that way. It is a constant battle, though, to define your cycle length and the amount of arsenic you can pick up. It is all dependent on temperature and how many pounds per day you are going to put in. I recommend that you work with your catalyst supplier to figure out an optimum system and what their products can actually hold without losing any activity or cycle length.

BRIAN WATKINS [Advanced Refining Technologies (ART)]

Arsenic

Arsenic (As) is found in many crudes including some from West Africa and Russia, as well as many synthetic crudes. It is becoming a common contaminant as use of these crudes, especially synthetic crudes, has been increasing in recent years. The arsenic is believed to bind with the metal sulfide sites (and in particular, the active nickel on the catalyst) forming nickel arsenide. This has a dramatic impact on catalyst activity. To demonstrate the effect of arsenic on catalyst activity, ART obtained a series of spent catalysts containing different levels of arsenic. These samples were carefully regenerated in the laboratory and were then activity tested using a diesel feed containing 50% cracked stocks under conditions producing less than 500 ppm sulfur. Figure 1 summarizes the results of that work. At 1,000 ppm, arsenic on the catalyst shows 5°F HDS (hydrodesulfurization) activity loss and nearly 15°F loss in HDN (hydrodenitrogenation) activity. The activity loss quickly increases to over 50°F with 1 wt% arsenic on the catalyst.

Canister data for a variety of catalysts also indicates that catalysts containing nickel are more effective for trapping arsenic. Figure 2 summarizes the arsenic pickup values for several NiMo (nickel molybdenum) catalysts. As this data shows, both high metals ULSD catalyst NDXi and AT580 as compared to our recent guard catalysts AT724G and AT734G, which are quite effective for trapping arsenic. The data also indicates that the active ring materials and demetallization catalysts used are also effective for trapping arsenic.

Other canister data also shows that the ultimate arsenic pickup is heavily dependent on temperature. Figure 3 shows the arsenic pickup as a function of temperature for a NiMo catalyst. These results were obtained by analyzing spent samples of a high metals NiMo catalyst from a three-reactor unit processing 100% cracked naphtha from a synthetic crude source. The first reactor was operated at very low temperature (about 275°F) in order to saturate diolefins. The second reactor was designed to saturate mono-olefins and operated at about 430°F. The last reactor had an inlet of 570°F and an outlet temperature of approximately 650°F. The arsenic content on the catalyst correlated with the temperature of the reactor as depicted in the figure. The data demonstrates that a high nickel catalyst can pick up very high arsenic levels if the operating temperature and feed concentration are high enough.

Noting that there are a wide range of arsenic levels, unit operating conditions, and expected cycle lengths, the ability to define a single-set threshold for when a trap is needed is difficult. It is recommended that if arsenic is found to be a problem contaminant, you will need to consult your supplier to determine if it is impacting the cycle and if and how much guard catalyst is needed.

Phosphorous

Phosphorous contamination in oil has been traced to fracturing fluids that are often used in crudes from the Western Canadian Sedimentary Basin. The source is diphosphate esters which are soluble in the crude oil. Refineries that run large percentages of light Western Canadian crude have reported crude column and crude furnace fouling for many years. Improvements made to crude columns to minimize fouling have transitioned the depositing of phosphorous to the downstream hydrotreaters.

Other sources of phosphorous include gasoline slop tanks, imported feeds, and lube oil wastes. If phosphorous does manage to make its way into the hydrotreater, it will poison the active sites of the catalyst causing a loss in activity. A level of 1 wt% of phosphorous on the catalyst results in roughly 10°F loss in activity. ART recommends that a feed content of less than 0.5 wppm (weight parts per million) be maintained whenever possible, as well as the use of feed filters to assist in trapping of phosphorous sediment.

An ART catalyst case study of the detrimental impacts of feed poisons on hydrotreater performance involved a ULSD unit which had recently started up with ART catalysts. Shortly after startup, the unit began to experience extremely rapid catalyst deactivation. It was so severe that within a couple months, the unit required an unplanned turnaround and the installation of fresh catalyst. Samples of spent catalyst representing the whole catalyst charge were collected and analyzed in the laboratory. The results are summarized in Table 1. It is apparent from these results that the catalysts were exposed to high levels of several poisons including arsenic, sodium, phosphorous, and iron. The contaminants penetrated well into the catalyst bed. Catalyst at the bottom of the reactor was not yet poisoned, but the coke content was extremely high for catalyst which had been onstream such a short time. The level of contaminants indicates the catalyst in the top half of the bed lost over 60°F of activity while the bottom was providing most of the HDS conversion. This required very high temperatures, which is reflected in the high carbon content at the bottom of the bed.

ART has a suite of options in order to protect the main bed from these and other contaminants which may be present in the feed to a typical hydrotreater. The use of several of these materials combined together can adequately provide protection and extend the cycle life of your hydrotreater.

RAJESH SIVADSAN (UOP LLC, A Honeywell Company)

Arsenic (As) is a very potent poison for hydroprocessing catalysts. Although As tends to be limited to specific crude sources (e.g., crudes from the U.S. and Canadian Rocky Mountains, Russian Urals, specific Chinese and West African sources, and “synthetic crudes” from Canada and Venezuela), it is usually present in all boiling fractions of those crudes.

Arsenic tends to poison the nickel sites of hydroprocessing catalyst, and the amount required to reduce catalyst activity by ≥50% depends strongly on the type of reactions being catalyzed. For instance, in diesel hydrotreating where ULSD is produced and product quality depends heavily on hydrogenation route desulfurization, as little as 500 to 1,000 wppm arsenic on catalyst can reduce HDS activity by 50%. On the other hand, for hydroprocessing applications where direct desulfurization is the primary mechanism for reaching product targets, higher levels of arsenic contamination on catalyst (about 1 wt% As) may be tolerated while retaining HDS activity greater than 50% of fresh catalyst activity.

Because of the broad range of as concentrations on catalyst that will poison the catalyst, as well as the broad ranges of LHSVs (liquid hourly space velocities) and cycle lengths for various hydroprocessing applications, UOP believes it is not possible to confidently cite a specific threshold concentration for as in feed above which a dedicated as trap system is absolutely required.

Phosphorus (P) can enter the hydrotreater feed from numerous sources: crudes, drilling fluids, phosphated ZSM (Zeolite Socony Mobil), phosphorus-based corrosion inhibitors and flow improvers, and biofeeds.

In one UOP commercial experience, about 3 wt% phosphorus on the catalyst terminated all the exotherm in the catalyst bed. Organic phosphorous can penetrate into catalyst pores. In general, our understanding is that the poisoning is similar to sodium where about 1.0 wt% concentration reduces the catalyst activity by 50%.

Based on UOP’s experience, we have found that the quantitative effects of phosphorus on hydroprocessing catalyst performance and the maximum allowable level are highly dependent on the source and form of the phosphorus compound, catalyst properties, and the process application, which all need to be considered when designing a trap system. Thus, UOP believes it is not really possible to confidently cite an absolute threshold concentration for phosphorus in feed above which a dedicated trap system is definitely required.

PER ZEUTHEN (Haldor Topsøe, Inc.)

Arsenic and phosphorous compounds are both known as permanent catalyst poisons; however, they each have very different deactivation mechanisms. Arsenic species found in the crude oil, particularly in the heavy ends, act as a true catalyst poison during titration of the nickel- or cobalt-promoted catalytically active sites. Although the concentration typically is rather low in ppb (parts per billion) levels, content of more than 50 ppb, for example, will have a significant negative impact on the catalyst performance. Arsenic compounds are very poisonous to the working catalysts, a typical high-activity catalyst has lost most activity after accumulation of as little as 1% As. Besides, shale oil and other new crude types (Russian and Canadian crudes) contain significant arsenic levels.

Haldor Topsøe has developed a number of dedicated arsenic pickup catalysts to protect the downstream bulk catalyst from very severe poison. The arsenic pickup capacity of this catalyst, TK-45, is as high as 10 wt%, but the actual pickup capacity will depend on the arsenic level in the feed and the operating temperature. With improved diffusion and preparation, Topsøe has recently launched a new dedicated arsenic trap, TK-49, with improved arsenic pickup for all hydrotreating applications.

Phosphorous species are rarely found in typical crudes; however, some opportunity crudes (and in particular, renewable feeds) often contain significant amounts of phosphorous. Moreover, phosphorous containing anti-corrosion additives can be found in the diesel and VGO (vacuum gas oil) fractions. The phosphorous compounds are decomposed in the hydrotreater, and the phosphates react with the alumina support, forming very stable alumina phosphates. Accumulated amounts of phosphates will reduce the accessibility to the active sites of hydrotreating catalysts and lower the activity accordingly.

Topsøe has a specialty product, TK-31, with a capacity of more than 5 to 6 wt% phosphorus, where reaction sites for phosphates have been improved the most. Topsøe recommends installing this phosphorous trap if the feed level is higher than 2 ppm phosphorus for protecting the downstream bulk catalyst from contamination.