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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.

LARSON (KBC Advanced Technologies, Inc.)

A review of our clients worldwide did not find any client that was blending any FCC product with just sweetening into jet. Limiting issues would be olefins (gum formation) and aromatic and potentially naphthalene content of unhydrotreated FCC jet boiling range components. Hydrotreated FCC product has the potential to be blended to jet provided the blended product meets the jet specification closely monitoring gum, aromatics, smoke, and/or naphthalene content. Some corporate policies prohibit any cracked stocks blended to jet fuel.

BULL (Valero Energy Corporation)

At Valero, we have a centralized group in the Planning & Economics area that is responsible for the kinetic modeling for all of the major process units. The primary driver behind the kinetic models at Valero is to get good data into our LP (linear program) models. The data from the FCC simulation is translated into LP vectors, which are used by our LP group to build LP models for each refinery. Using this data, we then do all of our crude selection, as well as our weekly, one-month, and three-month optimization plans in the LP.

 

 

 

 

 

 

The other influence on simulation models is the engineers who use kinetic models at the refineries and also at the corporate level for different applications. Our group calibrates the kinetic models that are used throughout the company. We have put the kinetic models into unit monitoring applications at Valero to validate LP vectors. These models are also used to conduct what-if studies. The monitoring application also helps us generate our daily operating data. Usage varies greatly amongst the plants at Valero. Some of our refineries are running the kinetic models on a weekly basis. There are other plants that have probably not touched the kinetic model in the entire eight years that I have been at Valero; so, it is hit or miss.

 

 

 

 

 

One of our main goals is to train the engineers to leverage kinetic models to do optimizations, look at case studies, or troubleshoot. We need to make it easier for them to use so they will utilize the kinetic models. That is why we have a central group. It is our job to calibrate the model, ensure its accuracy, and then put it in a format that is easy to use.

 

STEVE GIM (Technip, Stone & Webster)

I have had the luxury of observing more than 200 units around the world over the last 20- plus years. As Jeff alluded, there is a great variation in terms of the quality of data that we get from our customers and how we go about using it to propose or benchmark future changes. Ideally, you would like to have test-run quality data and a stable unit operation associated with laboratory data, but this is not always the case. In terms of the actual use of the kinetic model for optimization and proposal of the operational changes, that would be the most ideal way to look at the operation. But in the absence of these conditions (for example, we only had access to raw pi data), another extreme way to monitor and engage their performance would be either simple time-based benchmarking or statistical benchmarking. My Answer Book response includes actual examples of these different types of benchmarking, ranging from easy to hard. For the sake of time, you can look at those examples and definitions at your convenience.

 

STUART FOSKETT (BASF Corporation)

I want to add an additional use that we have in service. We use the FCC simulation model from KBC. We have had a very successful experience using a catalyst database that we developed for catalyst factors for all of our various technologies, in combination with the optimizer, to fine-tune offerings for catalyst reformulations.

 

KEN BRUNO (Albemarle Corporation)

While some already use models, Albemarle strongly encourages all refiners to use their simulation model to do very careful post-audits, particularly around catalyst changes. Make sure that what got in the unit is, for example, what your laboratory would show in catalyst testing. It is critical to post-audit your units to make sure you are making the right decisions. If lab testing is also involved, use these results to make adjustments to how you translate your lab data to commercial projections.

 

LARSON (KBC Advanced Technologies, Inc.)

Since we were mentioned, one of the other strong values beyond the catalyst evaluation—the kinetic modeling—the platform actually gives you an extreme value in troubleshooting other elements of the unit: cycle velocities and bed velocities. The other values are gotten with kinetic modeling and go beyond simple yields. Based on my experience at KBC, I echo what Jeff said. Quite frankly, with the age of computers, kinetic models are actually underutilized. We are not getting the value of the information available, particularly as a training tool.

As younger engineers are coming through, using a model to train with is a safer alternative to adjusting an operating unit. You can go out and cultivate the models to teach them some of the fundamentals of the unit processing, so they will become better engineers in a more rapid startup into the process. We advocate not just for the purpose of kinetic modeling, but also for the training and troubleshooting aspects, to help you make a long-term profit potentially in your refinery.

 

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

When it comes to model calibration/fitting, are unit material balances used or are special tests surveys conducted? Once calibrated, do you attempt to validate the model with newly collected plant data?

 

BULL (Valero Energy Corporation)

Bob, to address that with the most recent version I will tell you that we utilize KBC models for all of our applications. The recent version 4.1 that is being implemented in our system contains a data reconciliation function, so we are using plant data to feed data reconciliation functions. The data reconciliation function actually trues up the mass balance to 100% before any information goes into the model. Within that platform, we also have designed the capacity for you to bring your data directly from the historian into the kinetic model. There is also data conditioning so we can go through and trap errors in the data. We can use data from a different timeframe when you have a bad flue gas analysis or a TI (temperature indicator) has failed. One of the benefits of the model is that it has allowed us to pin down the location of bad indicators in the laboratory or if it is a TI or flow meter. By performing this data reconciliation, we have more information to identify these issues.

In the past, engineers tried to show this on spreadsheets and then justify it with unreconciled plant data. Now we have it all on a database, so we know where the meters are off when doing the reconciliation. You also have the whole heat balance function which also goes into the evaluation, and you can back into some of your thermocouples and other analyses. Having historical data helps us with our justification to get meters or indicators fixed.

 

J.W. “BILL” WILSON (BP Products North America Inc.) I would like to ask Jeff for a little bit more clarification. As I understand, your group calibrates the models, generates the LP vectors, and puts them into the LP. Do you perform the actual LP work as well or turn it over to the refinery to operate?

 

BULL (Valero Energy Corporation)

We have a central LP group that is separate from our Kinetic Model group, so we have people who specialize in just the LPs. That is where the interface comes between our groups. We will generate the data and then check it ourselves. When we send it over to them, there is another check that is done inside the LP; so, there are two rounds before it actually gets sent to the plant.

 

J.W. “BILL” WILSON (BP Products North America Inc.)

But then the plant actually uses the LP for its short-term planning?

 

BULL (Valero Energy Corporation)

That is correct. All the planning work is done at the plant. We purchase all of our crude centrally, so that group is a strong user of these LPs as well.

 

JOE McLEAN (BASF Corporation)

I agree with all the good comments that have been said. We do use the KBC model extensively and incorporate it into all of our other data management systems that use for tech service, but there are drawbacks as well. One of the drawbacks of the model is that it is a steady-state predictive model. It will give you a prediction, but then it will assume that you will just sit there at those fixed conditions until you get to steady state. Of course, FCCs in the real world never run that way.

So, what we found works very well as a companion tool to accompany with the model is to include statistical analysis and multi-variable statistical regression, which is not that scientific by any means, but which is much better at handling transients. Just depending on the specific unit and how well it runs at constant conditions or how far it deviates from that, we may use one versus the other, or a combination of both, to get the best compromised solutions.

 

LARSON (KBC Advanced Technologies, Inc.)

To add to Bob’s point, one of the concerns that refiners have in collecting data is that they are going to overload the lab with certain laboratory analysis; so, there has been a trend to reduce the amount of lab schedules. I have personally done this. You can sequence your lab collection information so that it does not change the lab schedules or overload the lab. As a result, you can get weekly rigorous test data that is of high quality. If you look at your lab schedule appropriately and mirror what Jeff said Valero is doing in reconciliation of your data, as well as fine-tune the instruments that exist, you could have a reliable, high-quality set of data on a routine basis. But really, go to the lab work to make sure that you do not have the ghost of too many lab samples going in.

 

JEFFREY BULL (Valero Energy Corporation)

At Valero, we have a Central Refinery Models Group that is part of our Planning & Economics organization. The Refinery Models Group is responsible for the maintaining the kinetic models for every major process unit. FCC simulation models are used as part of routine optimization in two ways. As part of our planning process, the LP models are updated using data generated from the kinetic models. The LP models are used for refinery optimization on a weekly basis. This is an established work process used at all of our sites.

The other way that FCC simulation models are used for optimization is at the process engineer level. This is done in a less formal manner and varies from site to site. Some sites look at the unit performance on a weekly basis or conduct periodic case studies, and other Process Engineering departments do not use the kinetic models. It really depends on the culture at that site and the actual process engineer. As far as routine monitoring, we have recently explored using the kinetic models as a backbone for mass and heat balancing FCC units and then comparing actual performance to model predictions. We see benefits in establishing this work process but still need to quantify the best means to roll this out to our system.

 

STEVE GIM (Technip Stone & Webster)

Usage of FCC simulation models has to be put into a context of what is workable for day-to-day operation and what is not. For proper usage of FCC simulation models, it is prudent to have test-run quality data with unit stability and accurate lab data that correspond to the set of data we want to analyze. In the absence of these two conditions, we use descriptive and statistical analysis of available data on day-to-day basis. As required, FCC simulation models are used in three main areas of performance monitoring and optimization: (1) analyzing and benchmarking the performance of the FCC unit, (2) recommendations for improved unit performance, and (3) routine updates of FCC sub-model vectors in refinery LP.

Monitoring and Benchmarking

Time-Based Benchmarking

Time-based benchmarking offers visual interpretation of change in both the inputs (feed, catalyst, hardware changes, and independent operating variables, for example) and corresponding outputs (yields and dependent operating variables). These are simple plots that are routinely produced as part of weekly reports. Some of the examples are shown for clarity:

 

 

 

 

 

 

 

 

Statistical Benchmarking

Statistical analyses of various operating parameters serve several purposes. First, provide deeper understanding of distribution in both inputs and outputs of the unit has operation, as shown on the charts below.

 

 

 

Secondly, create potentially valuable correlations, which are illustrated below:

 

 

 

 

Physical Benchmarking

Periodic check of the unit performance against various hardware of each FCC identifies both the bottlenecks and opportunities to improve the operation by installation of new technologies and/or revamping of the existing hardware. Yields and operating conditions can be checked against our physical simulation of the FCC as it is actually built. Catalyst fluxes, superficial velocities, and residence times in stripper and regenerator bed are some of the examples of physical attributes of as-built model against industry-accepted criteria.

Kinetic Benchmarking

Technip utilizes an in-house kinetic model co-developed with Axens, IFP, and Total for FCC yield prediction. Periodic “tuning” of the model using the actual operating data serves three purposes: (1) benchmarking the current performance of the unit in various key performance indicators, (2) forecasting and/or recommending future operation of the unit from fine-tuning operational parameters and/or inputs (feed blends, for example), and (3) back-testing the model to close the gap between predicted versus actual to fine-tune the capabilities of the kinetic model built specific for each unit.

Reconciliation

Sizable shifts in feedstock properties, unit hardware, and operating conditions are reconciled using simulation models. Kinetic models can segregate individual effects to better understand the differing contribution of major shifts.

 

 

 

 

Update of LP Vectors for FCC Sub-model

Updates of the FCC sub-model of the linear program (LP) can be provided by FCC models. Perturbations of bulk feed properties and operating conditions, as well as their resulting yields vectors, are provided for the LP. They provide valuable refresh of FCC’s operations upon a step change in the feed qualities and/or hardware changes that provide a sizable shift in the unit has performance.

 

ALAN KRAMER (Albemarle Corporation)

Albemarle routinely uses FCC simulation models to support our customers’ operations. Simulator models provide an excellent platform for evaluating the impact of changes on an FCC unit, whether they are catalyst, feed, operational, or mechanical. There are four main ways by which we use models as part of our routine technical service support:

1. Forecasting with Optimization: We use simulators to help select the optimal catalyst formulation and operating parameters to maximize profitability. Most often, these results are used in a standalone manner; however, they can be fed to other process simulators (such as those for feed or product hydrotreaters) or used as inputs to refinery-wide LP models.

2. Unit Monitoring: We routinely feed unit operating data into our FCC simulators, especially during transition periods such as when changing catalysts. The model is used to predict what would have happened had the change not occurred. This is accomplished by applying the calibration factors determined from the previous catalyst as the new catalyst replaces it in the unit. A delta will appear between the predicted and actual dependent process variables and product yields, corresponding directly to the impact of the change. Economics can be applied to the deltas and the value of the change directly quantified.

3. Unit Optimization: Part of the routine technical services we provide is to optimize the current operation against unit constraints to maximize the objective function. We pass along our findings from the process simulators as suggested actions for our customers pursue.

4. Post-Audit/Side-by-Side Analysis: This is similar to unit monitoring but performed after the change is complete. We project time periods, both before and after the change, back to a consistent basis. This allows us to measure the impact of the change and evaluate it economically versus the initial projections.

Albemarle views FCC simulators as very powerful tools for assisting with routine performance monitoring and optimization. When coupled with our other technical service tools (such as equilibrium catalyst and fines analysis, equilibrium catalyst performance testing, and our extensive technical service knowledge and experience base), they help Albemarle provide best-in-class, high value-added technical support to our customers.

 

 

BULL (Valero Energy Corporation)

Some light hydrocarbons can be found in the flue gas in very small quantities, depending on the unit. The factors that contribute to light hydrocarbons in the flue gas are poor stripping in the reactor and maldistribution of the spent catalyst and very high catalyst circulation rates. Several industry trends have pushed the FCC units to operate in these undesirable regimes. Lower flue gas oxygen concentrations used to reduce NOx content of the flue gas or increase unit capacity have contributed to these materials being in the flue gas portion of the system. In the past, higher excess oxygen often masked distribution issues in regenerators that were not mixed well. Resonance times have decreased as FCC units have gone closer to their maximum mechanical operation, which has increased the superficial velocity of the regenerator in the flue gas system. Higher catalyst circulation rates often tax older reactor stripper designs, which can lead to hydrocarbon undercarry to the regenerator.

 

 

 

We have experience with an R2R first-stage regenerator where we installed a new CO boiler on the first-stage flue gas line; and when we calculated the efficiency of the burners, we were getting numbers at or above 100%. After thoroughly analyzing the flue gas, we found several peaks which had not previously been taken into account by the laboratory. These peaks turned out to be light hydrocarbons. When we adjusted the efficiency calculations to take into account the additional light hydrocarbon from the flue gas, we found that the efficiency came in at around 85%, which is what we had anticipated. We revalidated this finding when we installed the CONOx system on the same line. It consumed twice as much oxygen as we had anticipated for the same result on NOx reduction. We attributed the higher consumption to the light hydrocarbons. Now we believe a lot of this is not really due to the original licensor at all, but rather some installation of a spent catalyst distributor that we later added onto this unit. I want to put that caveat in there.

 

GIM (Technip Stone & Webster)

There are two possible reasons for such phenomenon to occur. First is the source. Poor catalyst stripping will create the opportunity for these hydrocarbons to escape to the regenerator. For the actual hydrogen-rich molecules to escape to the regenerator, the hydrogen coke has to be quite high. Many of the cat crackers operate way beyond their original design capacity which, frankly, taxes the traditional disc-and-doughnut or baffle stripper. It can benefit a lot from a more modern pack stripper technology, which is quite circulation-independent with high flux tolerance.

The actual distribution of stripping steam has also come into play. For example, if you have a stripper with a spent catalyst standpipe, then using two half-steam rings would be better than one full ring to distribute the steam in the stripper. And depending on the residence time and temperature, the severity of the stripper could also result in new formation of these light hydrocarbons.

Now when these molecules actually do escape to the regenerator, as Jeff alluded, the distribution of the spent catalyst into the regenerator will play a big role, in terms of how it promotes these light hydrocarbons, in enabling them to escape to the dilute phase. There would be less flash if the spent catalyst was evenly distributed into the regenerator, which becomes especially problematic for those regenerators with a larger diameter.

 

 

 

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

The light hydrocarbon can be a carrier of NOx and SOx precursors. So, if you experience a step change increase in SOx or NOx, look at your stripper operation for any performance changes.

 

J.W. “BILL” WILSON (BP Products North America Inc.)

On the unit that runs in partial burn, we have seen that if you watch the calculated hydrogen on coke, as you change the amount of CO combustion that is going off, you will actually see a change in hydrogen and coke. Nothing else is affected. Whether the absolute number is right or wrong, the fact is that it is changing with no change in the stripping steam: not a really significant change in catalyst circulation rate, just a change in the amount of excess oxygen being put into the unit. In this case with the amount of oxygen or the air we are putting in the unit, the excess oxygen is still quite low. This is because we never get out of partial burn.

So, one of the things we think might be happening, and we are still investigating, is that we may actually be forming, under certain circumstances, some of these light hydrocarbons, especially methane, in there. Since methane does not show up in your normal flue gas analysis, the hydrogen that is involved in that methane is now lost from the calculation for hydrogen on coke.

 

JEFFREY BULL (Valero Energy Corporation)

Some light hydrocarbons can be found in the flue gas in very small quantities, depending on the FCC unit. Poor stripping in the reactor, maldistribution of spent catalyst and air in the regenerator, and high catalyst circulation rates are all potential causes of hydrogen or light hydrocarbon in the flue gas. Several industry trends have pushed FCC units to operate in these undesirable regimes:

• Lower flue gas and excess oxygen used to reduce NOx content of the flue gas or to increase unit capacity has contributed to these materials in the flue gas portion of the system. In the past, higher excess oxygen often masked distribution issues in the regenerator.

• Residence times have decreased as FCC units are pushed closer to maximum operation, which increases the superficial velocity through the regenerator and flue gas systems.

• Higher catalyst circulation rates often tax older reactor stripper designs, which can lead to hydrocarbon under carry to the regenerator.

We have experience with an R2R first-stage regenerator where we installed a new CO boiler on the first-stage flue gas line; and when we calculated the efficiency of the burners, we were getting numbers at or above 100%. After thoroughly analyzing the flue gas, we found several peaks that had previously not been accounted for by the laboratory. These peaks turned out to be light hydrocarbons. When we adjusted the efficiency calculations to take the additional light hydrocarbon from the flue gas into account, we found that the efficiency came in at around 85%, which is what we anticipated. We revalidated this finding when we installed the CONOx system on the same line. It consumed twice as much oxygen as we had anticipated for the same result on NOx reduction. We attributed this to the light hydrocarbons. We feel that some of this is due to a spent catalyst distributor that we installed several turnaround cycles ago outside the scope of the original licensor.

Light hydrocarbons in the regenerator flue gas have historically not affected unit operation and are primarily a concern from an environmental standpoint. Most of the actions that the industry is taking to lower emissions in the FCC flue gas would tend to lower the light hydrocarbon content in the regenerator flue gas as well.

 

STEVE GIM (Technip Stone & Webster)

There are two possible reasons such phenomenon can occur: source and escape.

Source:

Poor catalyst stripping will let these hydrocarbons have a chance to escape to the regenerator. For actual hydrogen molecules to escape to the regenerator, the “hydrogen on coke” must be quite substantial. Many cat crackers operate way beyond their original design capacity, and traditional baffle or disc and donut designs can greatly benefit from modern packed stripper technology, which is really cat circulation-independent with its high flux tolerance. Distribution of steam is also important in the efficiency of stripper. For example, for strippers with a side spent catalyst standpipe, two half-steam rings are better than one full ring. You want both sides to have less potential for bypassing and the same residence time. You could be wasting steam on one side. Depending on the residence time and temperature, the severity of stripper can result in new formation of these molecules in the stripper.

Escape:

Poor catalyst distribution into the regenerator allows these light hydrocarbon escapees to continue their journey to the dilute phase. There will be less flash if spent catalyst is evenly distributed into the dense phase. This is especially problematic for regenerators with large diameters or catalyst entry is not optimal for introduction of the spent catalyst into the combustion sites.

 

JACK WILCOX (Albemarle Corporation)

Entrained un-stripped hydrocarbons resulting from inefficient or poor spent catalyst stripper operation are a common source of trace hydrocarbons in the regenerator flue gas. These entrained hydrocarbons are not burned due to maldistribution of the combustion air and/or spent catalyst allowing the light hydrocarbons to leave the regenerator with the flue gases. At the elevated flue gas temperature, and if there is, in fact, excess oxygen in the flue gas, the hydrocarbons will burn in the flue gas system potentially causing significant damage to the downstream equipment, particularly power recovery expanders, flue gas coolers, electrostatic precipitators, etc.

GIM (Technip Stone & Webster)

First of all, acetone is hard to detect by itself. It requires a special column in GC (gas chromatography) to pick up the polar species. Normal GC just picks up the regular hydrocarbons. We have seen acetone concentration in the C4 stream, butane and butylene (or BB, to be specific) as high as 800 ppm. In the same unit, we also measured average acetone concentration of 300 ppm over the course of the same month with values as low as 50 ppm. So, what are these sources of acetone? Oxygenates are byproducts of entrained oxygen in the regenerator and hydrocarbons in the reactor. Entrained oxygen from the regenerator to the reaction zone provides an opportunity for acetone formation in the reactor. Excess oxygen in the regenerator standpipe increases with higher catalyst circulation rate. High catalyst circulation rate entrains more air from the regenerator because the entrainments are among the catalyst particles.

Now, what are some of the potential ways to reduce this acetone formation? A few solutions for preventing acid formations are as follow:

1. Replace the instrument air in the reaction taps from air to nitrogen.

2. Tweak the operating variables may lead to some unnecessary increase in catalyst circulation rates such lowering the ROT (reactor outlet temperature), raise feed preheat, or use a higher activity and lower catalyst cooler duty, if you have them. Many of these will decrease the cat circulation rate and, therefore, the formation of the acetone.

3. Properly design the C3/C4 contaminant removal bed to help remove this acetone as well. Keep in mind that there may be other sources of oxygenates that had been introduced into the FCC system, such as external oxygenates or oxygenates that are being recycled, as well as some of the oxygenate-containing sludge in pipings.

 

 

 

 

BULL (Valero Energy Corporation)

We have seen levels of 50 to 200 ppm acetone in the BB stream in our refineries. Now for refiners in general, a move from 50 to 200 ppm is normally not that large; but if you are selling the stream as a chemical feedstock, the difference between the 50 and the 200 ppm can be significant on the downstream plants. That is definitely a consideration. Another concern about acetone in the feed to the alkylation unit is that it does result in higher acid consumption and can increase the ASO (acid-soluble oils) formation; but in low levels, this can normally be managed.

 

MICHAEL WARDINSKY (Phillips 66)

This question came up in 2007 when I was on the panel, and I remember answering it. You might want to consider making sure you have a good washwater rate going to your main frac overhead system because acetone should partition out to the sour water system when contacted with washwater.

 

MARTIN EVANS (Johnson Matthey INTERCAT, Inc.)

A question for Steve: You mentioned the use of contaminant removal beds to remove acetone. What type of beds are you suggesting?

 

GIM (Technip Stone & Webster)

We are talking about the activated alumina adsorbent bed.

 

STEVE GIM (Technip Stone & Webster)

Measuring Acetone: First, acetone is hard to detect by itself. It requires a special column in GC to pick up the polar species such as acetone, other oxygenates, and ECL. Normal GC just picks up regular hydrocarbons. We have seen acetone concentration in the C4 stream (butanes/butylenes or BB) as high as 800 ppm, but the same unit also measured acetone concentration averaged 300 ppm in daily measurements over the course of the same month, with values as low as 50ppm.

Source of Acetone: Oxygenates are byproducts of entrained oxygen and hydrocarbons. Entrained oxygen from regenerator to the reaction zone provides an opportunity for acetone formation in the reactor. O2 in the regenerated catalyst standpipe increases with higher catalyst circulation rate; higher catalyst circulation entrains more air from the regenerator because most of the entrainments are among the catalyst particles.

Reducing Acetone Formation: Some of the solutions for acetone are:

(1) replacement of instrument air on reaction taps from air to nitrogen.

(2) tweaking of operating variables that may result in an unnecessary increase in catalyst circulation rates such as lower ROT, higher feed pre-heat, higher catalyst activity, and lower catalyst duty; and,

(3) properly designing C3/C4 contaminant removal bed (such as activated alumina adsorbents).

It is also important be keep aware of potential other sources [of?] oxygenates that get introduced to the system including external oxygenates, oxygenates that are being recycled, and oxygenate containing sludge in pipings.

 

JEFFREY BULL (Valero Energy Corporation)

Ketone formation in the FCC is heavily dependent on the amount of air entrained from the regenerator into the reactor through the regenerated catalyst. As catalyst circulation is increased, more air is entrained and the formation of ketones will increase; so any operating variable that raises catalyst circulation can contribute to the formation of acetone. Specifically, reactor temperature, catalyst formulation, and stripping steam all have a strong correlation to catalyst circulation. Valero does not have much data on concentrations of acetone in the LPG product, but we have seen it in the 50 to 200 ppm range. We had a recent experience with not being able to sell some of our LPG product due to high acetone numbers. For refiners, the change in acetone formation from 50 to 200 ppm usually will have no effect on product quality. However, if the LPG is being sold as a chemical feedstock, this shift in concentration can adversely affect the downstream chemical plant. Acetone in the feed to the alkylation unit does result in higher acid consumption and increased acid soluble oil (ASO) formation; but in low levels, this can be managed. I will also refer you to the 2007 NPRA FCC Q&A response to Question 14 for further information on this topic.

 

JACK WILCOX (Albemarle Corporation)

Oxygen entrained in the circulating catalyst resulting from excessive instrument and standpipe aeration using air as a source, as well as excessive excess combustion air for catalyst regeneration, can provide the oxygen necessary for the generation of acetone. Instrument tap and standpipe aeration air rates should be properly controlled by utilizing appropriately sized restriction orifices in these locations. If possible, the aeration media should be changed to sweet fuel gas or nitrogen. Excess flue gas oxygen levels should be optimized to maintain the desired level of carbon on regenerated catalyst and carbon monoxide in the flue gas. Acetone is formed from the reaction between propylene and benzene plus oxygen. Avoid, if possible, charging extraneous streams to the vapor recovery unit containing cumene which reacts with oxygen to form acetone. High FCC reactor temperature will produce more propylene and benzene, the combination of which can react to produce cumene. The use of ZSM-5 additive will obviously produce higher levels of propylene as well. Units operating at elevated cracking temperatures to maximize light olefin will see acetone levels in the debutanizer overhead C3 + C4 stream as high as 1500 ppm. Acetone levels in the range of about 100 to about 1200 ppm have been observed in the C4 fraction.

KOEBEL (Grace Catalysts Technologies)

This is a question that comes up relatively frequently and is an area where Grace has done extensive R&D work and publication. I will summarize a longer answer that appears in the Answer Book. So please refer to that response, as well as to some of the publications Grace has in the trade magazines. In order to be able to help customers with the thought of running whole tight oil to the riser, we ran a sample of Bakken crude straight to our Davison circulating riser pilot plant over a moderate Z/M catalyst. Our data for the feed sample is shown on the slide and compared to a published assay of Bakken. We felt it was relatively representative of a typical Bakken crude.

 

 

 

To summarize, the data behaved much as you would expect. There was a fair amount of 650°F minus in the feedstock, so it made significant amount of gasoline. You can see that the cracking yield was on the order of 65% gasoline. A lot of that was the gasoline inherent in the crude initially; it had just come along for the ride. There was not much conversion of those molecules that were present in the feed. As a result, the overall FCC gasoline octane is moderately low. The feed actually did convert very well, although it made very low coke and low bottoms yield.

 

 

 

These are the specifics of the FCC gasoline from those products. You can see that the RON is much lower than 80, even significantly lower than you would typically give an FCC naphtha. It did have the normal response to reactor temperature that you would expect with an increasing RON as a function of reactor temperature. But still, the overall magnitude of the octane was very, very low.

 

 

 

On the other hand, the light cycle oil was a much better quality than you would get from a typical FCC light cycle oil. This, again, is partially due to the material that was inherent in the feed. But overall, the quality of the LCO was not really a function of reactor temperature. It was more a function of conversion level and how much of the material in the LCO you were cracking up the tower while leaving the paraffinic molecules in the LCO. The diesel index was on the order of 35 to 45; whereas with a typical FCC light cycle oil, the diesel index was usually in the single digits. So, the quality of the light cycle oil you get from processing shale oil with the riser is much better than what you normally get with FCC light cycle oil.

 

 

 

The question also asked about some of the other considerations for doing this. One of the considerations is that, with the variability of the tight oil quality, from time to time you may get unusual contaminant metals in the FCC feed. This slide shows one example of a unit that was routinely running Bakken crude to the riser. Over the course of a 10-day period, a spike of sodium hit the unit hard. This spike cost them about 10 points in activity on their circulating inventory. Often, the refinery is not set up to desalt the FCC feed directly. So, if you have a raw crude coming to the riser, you may see this happen, either with sodium or other contaminant metals.

 

 

 

BULL (Valero Energy Corporation)

At Valero, we process desalted pre-flash crude in several of our FCC units. We desalt the crude or remove as many of the contaminants as possible. We also may pre-flash the crude to take off the light gas and naphtha, which is shown in the drawing on the slide. We run it through a desalter to try and take out contaminants. It then goes into the pre-flash tower to take off any light gas and some of the light naphtha, and then take the bottoms of that to the FCC unit. We have done this at several refineries. The pre-flash crude is then sent directly to the FCC feed drawing process in the unit.

 

 

 

In general, the naphtha boiling range material goes straight through, and then we can see a proportional increase in the gasoline FCC naphtha range. The naphtha also has a cat cooling effect without the cat cooler, so you must take that into account when processing crude directly to the FCC. Some of the diesel boiling range material passes through, but we do see some of the heavier components of the diesel crack. The remaining portion of the pre-flash crude is your typical FCC feed at that point. So, the net effects are a reduction in overall liquid yield on the unit and the shift in selectivity to more naphtha and diesel range material.

 

 

 

Two primary considerations for investigating new crude sources for processing directly in the FCC are the contaminant levels that Jeff referred to earlier, as well as the effect of the light material and the impact that will have on your delta coke and heat balance.

 

SOLLY ISMAIL (BASF Corporation)

All of these tight oils are very low in aromatics components. They typically have shorter length hydrocarbons which, when mixed with vacuum resid, can create salting out or compatibility issues. One way to address the compatibility issues is to extend the analysis and include the peripheral unit; i.e., the furfural unit in a lube plant. We know that in a furfural unit the paraffins are being separated from the naphthenes and aromatics. These paraffins are then sent for dewaxing to make base stock for lube oil while the extract, which is rich in aromatics, and some naphthenes become an orphan stream of the refinery. In this case, I am assuming that refinery does not make grease with the extract. Because this furfural extract stream is rich in aromatics, it is difficult to crack and makes lots of coke, which has always been a problem. Therefore, FCC operators are reluctant to accept furfural extract for processing in their units.

Nevertheless, refineries do process lube extracts (in low concentrations) in the FCC and would generally like to process more or higher levels in their feed to the FCC.

As just mentioned, because of the high tendency for furfural extract to make coke in the regen, refiners have been having a tough time blending it away in the FCC feed. However, when a refiner is processing large amounts of tight oils, the situation is completely different. In the scenario when tight oils are being processed, the regenerators have the problem of running at low dense bed temperatures. I think when processing high concentrations of tight oils in the FCC unit, increasing the levels of furfural extract with tight oils might be a blessing. Not only will the furfural extract provide an increase in the level of coke in the FCC regen, but it should help improve the compatibility issues as this stream contains large hydrocarbon molecules that can keep the vacuum resid in the solution.

 

JEFFREY BULL (Valero Energy Corporation)

At Valero, we have processed desalted pre-flashed crude in several of our FCC units. We desalt the crude to remove as many contaminants as possible, and we pre-flash the crude to take off the light gas and light naphtha. The pre-flashed crude is then sent directly to the FCC feed drum and processed in the unit. In general, the naphtha boiling range material goes straight through the FCC and, in effect, blends with the traditional FCC-derived naphtha. The naphtha also has a “cat cooling” effect without the cat cooler. Some of the diesel boiling range material cracks and some of the naphtha material passes through the FCC reactor. The remaining portion of the pre-flashed crude is typical FCC feed. The net effect is a reduction in overall liquid volume yield and a shift in selectivity to more naphtha and diesel range material. The two primary considerations for looking at new crude sources for processing directly in the FCC are contaminant levels (metals, sodium, calcium, etc.) and the amount of light material that essentially takes a free ride through the FCC and has a significant impact on the heat balance.

 

JEFF KOEBEL (Grace Catalysts Technologies)

The introduction of novel drilling technologies has resulted in large amounts of oil from shale becoming available in North America. While fluid catalytic cracking is typically done to reduce the molecular weight of the heavy fractions of crude oil (such as vacuum gas oil and atmospheric tower bottoms), in some cases refiners are charging whole shale oil as a fraction of their FCC feed.5 Also, whole crude oil has been charged to FCC units when gas oil feed is not available due to maintenance on other units in the refinery6 and to produce a low-sulfur synthetic crude7 .

As a model case for understanding the cracking of whole crude oil in the FCC and the effect of process conditions on yields, a straight-run shale oil was processed in the Grace DCR™ pilot plant at three riser outlet temperatures: 970°F, 935°F, and 900°F. The whole crude oil was a light sweet Bakken crude with a degrees API gravity of 42. The properties of the crude were similar to those given in a publically published assay8 . Table 1 presents a comparison of the properties of the whole crude used by Grace and the publically available assay data. Additionally, the straight-run Bakken sample was distilled into a 430°F minus gasoline cut and a 430°F to 650°F LCO cut. The properties of these cuts were measured. Gasoline from the straight-run Bakken was highly paraffinic and had low octane numbers [a G-Con® RON software of 61 and MON (motor octane number) of 58]. The LCO fraction had an aniline point of 156°F and an API gravity of 37.6, resulting in a diesel index of 59.9.

 

 

 

The catalyst used in the experiments was a high matrix FCC catalyst, deactivated metalsfree using a CPS (cyclic propylene steaming)-type protocol. The properties of the deactivated catalyst are given in Table 2. For the three different reactor outlet temperatures, plots of the catalyst-to-oil (C/O) ratio, dry gas, gasoline, LCO, bottoms, and coke yields versus conversion are shown in Figure 1. As expected, lowering reactor temperature increases the amount of LCO produced. As seen in the graphs, cracking straight-run shale oil produces little coke and bottoms. At the same conversion level, lowering reactor temperature results in slightly more gasoline yield (due to increased C/O), which is consistent with prior Grace work.

 

 

 

Plots of gasoline olefins, isoparaffins and RON and MON estimated via G-Con software are shown in Figure 2. Cracking straight-run Bakken shale oil produces a low-quality gasoline with research octane less than 80 and motor octane less than 70.

 

 

At constant conversion, increasing reactor temperature results in more gasoline olefins and higher research octane number. Diesel quality is of great interest to refiners. Syncrude produced in the DCR™ runs was distilled to recover the 430°F to 650°F LCO fraction. Aniline point and API gravity of the LCO were then measured to allow calculation of the diesel index, a measure of LCO quality [Diesel Index = (aniline point x API Gravity)/100]. Figure 3 presents data for LCO yield and LCO quality as a function of conversion. As seen in the data, increasing conversion lowers LCO quality as a result of increased cracking of the LCO range paraffins to lighter hydrocarbons. Similar to prior Grace work14, LCO quality follows LCO yield and did not appear to be influenced by reactor temperature at constant conversion. Diesel index values of the LCO produced by cracking whole shale oil were significantly higher than values obtained with typical VGO feeds.

 

 

 

 

 

 

 

As seen in the results from this study, widely varying ratios of products and product quality can be obtained by changing process conditions. Information from pilot studies such as this one helps refiners to determine the optimum processing setup to maximize yields of desired products. The ability of the DCR to produce sufficient liquid product for properties testing assisted greatly in the measurement of LCO quality.

In addition to yields and operating conditions, contaminants and the impact they have on circulating catalyst inventory should be taken into consideration. A catalyst flushing strategy may be required to ensure that contaminants stay at reasonable levels in circulating inventory. For example, one refiner experienced high levels of sodium on e-cat while processing high amounts of whole crude. The sodium more than doubled and catalyst activity dropped more than 10 numbers, both of which impacted unit performance (Figure 3). The unit utilized purchased e-cat to help flush the sodium from circulating inventory.

 

 

 

 

PAUL FEARNSIDE (Nalco Champion Energy Services)

The largest concern will be with the main fractionator performance. Issues with direct cracking of undesalted crudes revolve around the increased chloride loading and the resultant increase potential for ammonium chloride salting. Care must be taken to insure the upper section delta P does not increase to the point that daily operations are curtailed. Intermittent slumping of the tower while water-washing and the use of salt dispersant chemistries have worked well.

 

CHRIS CLAESEN (Nalco Champion Energy Services)

The increased metals content in the feed can lead to increased catalyst deactivation, coke formation, and hydrogen generation which can significantly reduce the FCC profitability. While the metals content should be kept as low as possible by pre-treatment in the tank farm and desalters, the effect of Ni and V can be significantly reduced with the use of a metal passivator program that is injected in the FCC feed.

INKIM (PETROTRIN)

There are several KPIs that are tracked in the monitoring of FCC. Liquidy yields is one parameter that is monitored daily to detect any changes in equipment and catalyst performance. The BS&W (base sediment and water) in the main column bottoms is checked daily as well to monitor the catalyst carryover from the reactor into the main column. The heat and material balance should be done at least weekly, if not daily, to detect changes in the catalyst and equipment performance and to detect any meter errors. In the lean gas stream, the hydrogen-to-methane ratio is monitored weekly as it indicates higher metals content in the feed.

Another KPI that we track at least weekly is the e-cat properties to detect any feed contaminant issues. There are other KPIs that we monitor, and these are mentioned in my Answer Book response.

 

LARSON (KBC Advanced Technologies, Inc.)

In all cases, it is important to establish the baselines. Then what you are really trying to do is track your standard deviation because you need to know the cause and effect versus normal deviation. The cat cracker conversion might vary as much as 1%. So, looking at absolute values, as opposed to relative deviation, is really important. You get some of the KPIs directly; others are calculated from lab data or rigorous modeling. It is important to differentiate so you know the accuracy of the values you are using and how much they will change. We have typically lumped things into operating things or operating instruction KPIs, and then we also look at planning because planning will give you targets to target. Planning is target to target. Boy! That is oxymoronic.

Planning Targets: You need to hit those. Make sure your lab and operating systems are set up to work in conjunction with operational moves. We will typically look at reactor temperature which will give an indication of octane in conversion. We also look at the debutanized octane material monitoring what the RVP (Reid Vapor Pressure) of the material is; because as RVP changes, you will be changing octane. Refiners do not check their feed quality as often as we would expect. Operators are often chasing product quality when, in reality, there was, a burp in the feed quality, and it was missed until it is three days down the road.

Key Constraints: Map your constraints if you are operating up against them. Know your air blower capacity limit, whether it is the horsepower, blower discharge, or wet gas compressor horsepower. Is it a DP (differential pressure)? Many units are now running a low DP on slide valves encroaching nearer the shutdown trip points, so monitor your unit constraints very well. On a longer term or monthly basis, monitor your catalyst activity for metals and look at your fines.

 

 

 

One of the comments is taken this from the last NPRA (National Petrochemical and Refiners Association) Cat Cracking Session. The EPA (Environmental Protection Agency) came into the meeting and talked about the new regulations that will be coming to the FCC flue gas system. Particulate analysis that crosses your cat cracker will be one of the key criteria you will need to map, if you do not have it now. Many places that did not have upsets are not aware of what the particle distribution is on the slurry bottoms. They do not know the particle distribution of the fines caught. They do not know the particle distribution and are asked to do a cyclone analysis. Track your particle distribution on a regular basis, monthly or at least quarterly, so you have a baseline and know when things change.

We would also look at gasoline selectivity, as well as expansion on a unit, to ensure that catalysts are performing appropriately. We look at the LPG to LCO yield to make sure we are getting the correct cracking distribution and proper fractionating. This is an operator guideline. Are we getting good overlaps or gaps? What is the basis of your operation? How well are your operators performing against that basis?

On the utility side, we look at steam production and/or exchange or fouling to determine if we are getting the right value out of the preheat or if the steam generators are on the slurry circuit. These can be tracked daily or weekly. The bottom line is to monitor them frequently enough so that when you see deviation, you will know it is real as opposed to chasing ghosts. There are enough operator and engineer elements that we have to do now between HAZOP (Hazard and Operability) and environmental regulations, so you must have an efficient way to confirm that you are making as much money on your unit as possible.

 

 

 

MUKESH PATEL (Reliance Industries Limited)

Under KPIs and field properties, are you monitoring total nitrogen or basic nitrogen? As I understand it, basic nitrogen is more important than total nitrogen.

 

LARSON (KBC Advanced Technologies, Inc.)

I recommend total nitrogen for a couple of reasons: First, as soon as you begin to crack a molecule, you will take that which was in a total system. You will actually create more basic nitrogen just due to the nature of the cracking of the molecule. Second, every refinery I have reviewed in the last 10 years has not really been set up to do a basic analysis. They have a total nitrogen analyzer because of their hydroprocessing units. So, tracking the total nitrogen is just as effective as tracking basic nitrogen and watching the delta impact. It is the relative change away from your normal average feed. I have worked in enough different models, besides the one that KBC is selling, to know that you can use total nitrogen just effectively as basic.

 

MUKESH PATEL (Reliance Industries Limited)

How do you include the basic nitrogen in your simulation?

 

LARSON (KBC Advanced Technologies, Inc.)

There are some rules of thumb that apply if you want total to basic. If it is virgin oil, we would apply a basic assumption that one-third of the total nitrogen is basic. If it is cracked, then more than one-third of it is basic. So, it depends upon its feedstock, but there are some rules of thumb that can be applied.

 

MUKESH PATEL (Reliance Industries Limited)

Many times, we see that the basic nitrogen thumb rule does not apply for various reasons.

 

LARSON (KBC Advanced Technologies, Inc.)

Nitrogen is a contaminant; so, it always applies, just that what it is in relationship with changes.

 

KEN BRUNO (Albemarle Corporation)

Please consult the Answer Book as we have provided a very thorough list of recommended Best Practices and KPIs that supplement the suggestions by the panel.

 

J.W. “BILL” WILSON (BP Products North America Inc.)

Many of these things are quite amenable to being tracked statistically, which helps a lot in actually identifying real deviation or, as Mel said, ‘chasing ghosts’ or chasing random deviations. It is very easy. You can do it with a spreadsheet. We have some specific programs to use, but you can do it about as well with an Excel or other spreadsheet.

 

WARREN LETZSCH (Technip USA)

I want to make a comment on nitrogen. I think total nitrogen is the best way to go. This is particularly true if you are running residual feeds because small nitrogen compounds in VGO really can affect the catalyst quite a bit. The nitrogen in the larger molecules and the 1050°F plus material really does not seem to be nearly as detrimental. It is typical to run 1500 or 2000 ppm of nitrogen with a residual feedstock. And if you run that with a VGO, you would see a serious deactivation of the catalyst. Total nitrogen is the best way to monitor this impact. I certainly agree with your one-third rule; we have always used that. And for regular VGOs, it is remarkably good.

 

CATHERINE INKIM (PETROTRIN)

 

 

 

 

 

LARSON (KBC Advanced Technologies, Inc.)

Key process indicators, or KPIs, can be broken down into two broad areas of operations (daily) and performance-based indicators and can be further divided into fluid solids systems, operational, and yield for more detailed analysis.

In all cases, it is important to establish base lines and track standard deviation. There will be cause-and-effect change versus the normal deviation or operation of any FCC, given the dynamics of the control systems and typical various of feed and severity.

Some KPIs are calculated or used from daily logs or lab data while others are obtained through the use of rigorous modeling of the reactor regenerator system, as well as the hydrocarbon recovery section. Many refiners will have daily KPIs used to monitor the unit against the operating instructions from the planning group. Those KPIs that require rigorous heat and mass balance will be completed by the pacesetter refinery once a week, using a routine and defined time to collect stream and process data.

The direct laboratory and operating data used in concert with kinetic modeling enhances the performance monitoring of the unit. The use of the kinetic model can differentiate the impact between catalyst, feed quality, and severity. Utilizing TBP (true boiling point) yields versus as yield data can be enlightening for both Operations and Engineering using more rigorous troubleshooting assistance.

It is possible to optimize cost (laboratory) to reduce duplicate samples without jeopardizing the value and accuracy of much needed weight balance data. In general, samples and analysis have three values: actionable by Operations (deviation from the setpoint target), key mass and heat balance reconciliation necessary for LP updates (economic tools must be kept current), and historical trending. The latter is critical for both hydrocarbon and water systems. The frequency and accuracy of the mass and heat balance is an indication of the value a refiner places on the economics of operation.

A list of some of the typical KPIs are shown below:

• Typical Operation KPIs

– Operating Conditions (daily)

• Conversion, debutanized RON, LPG yield

• Steam usage

 Dispersion wt% on feed

 Stripping steam rate – Feed Quality (daily)

– Feed Quality (daily)

• Wt% Conradson carbon, 650°F minus, wppm (weight parts per million) nitrogen, wt% sulfur

– Key Constraints (daily)

• Air blower HP (horsepower), wet gas compressor HP, ΔP on slide valves, ΔP on trays that might indicate flooding, turbine efficiency

– Catalyst Properties (monthly)

• Catalyst losses/opacity

– daily

• Metals/activity

• KPIs to Monitor Optimization

– Yields

• Gasoline selectivity

• C3+ volume expansion

• Dry gas yield wt% [feed rate {scfb (standard cubic feet per barrel)}]

• LPG/LCO ratio

– Key Product Qualities

• RVP of gasoline, key separation (overlaps/gaps/light and heavy key component in bottoms and overheads of columns)

– Utilities

• Steam production

• Exchanger fouling

 

JACK WILCOX (Albemarle Corporation)

In order to monitor equipment reliability, as well as maintain optimum operation, the following KPIs should be tracked because they define the optimum FCCU operation:

On a continuous (daily) basis:

- Operating conditions, including:

a) Riser outlet temperature

b) Combined feed temperature

c) Catalyst circulation rate (catalyst/oil ratio)

- Feed rate and quality, including:

a) Density (API)

b) Boiling range

c) Key contaminant levels such as sulfur, nitrogen, heavy metals, etc.

- Catalyst properties

a) Fresh catalyst addition and withdrawal rates

- Key equipment constraints, including:

a) Main air blower limit

b) Wet gas compressor limit

c) Hydraulic constraints

d) Equipment temperature limitations

e) Key equipment operation, such as cyclone inlet vapor velocities, horsepower recovered (if unit has a PRT)

- Product yields and qualities

a) Product recovery limitations (fractionation, treating)

On a weekly basis:

- Test runs, including:

a) Complete heat and weight balance

b) Feed and product quality properties

c) Circulating catalyst, including both physical and chemical properties

d) Establishment of current limiting constraints

Once per year, and preferably a short time before and after a unit turnaround, a complete equipment and operational evaluation should be performed, including:

- A hydraulic survey, including:

a) A single-pressure gauge pressure survey of the entire reactor/regenerator section from the main column overhead to the flue gas recovery section; based on the single-gauge survey, a complete pressure balance of the reactor/regenerator is developed.

b) A single-gauge pressure survey of the main column and vapor recovery unit

- Thermography survey of the reactor/regenerator vessels

- Utility consumption, including all steam and air supply sources

- Critical equipment performance and limitations are established, including:

a) Cyclone solids and vapor loadings

b) Distributor pressure drops and nozzle exit velocities

c) Major rotating equipment, including the air blower, wet gas compressor, flue gas expander operation

- Establish flowing catalyst fluidization characteristics