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TRAGESSER (KBR)  

Advanced Riser Termination Systems are, by definition, a way to quickly terminate the reactions occurring in the riser. The goal is to rapidly separate the catalyst from the hydrocarbon vapors and then quickly minimize the time the hydrocarbon vapors are at reaction temperature before being quenched in the main fractionator. If these two goals are accomplished, post-riser reactions are minimized. The most undesirable of these reactions is thermal cracking reactions that reduce gasoline yield and increase dry gas make. 

Riser termination systems have evolved from the early days of riser cracking that commonly used inertial separators where the riser hydrocarbon product and catalyst were discharged into the reactor where non-desirable post-riser cracking reactions occurred. The next major advancement was to add efficient catalyst separation devices – such as riser cyclones to the end of risers – to quickly separate the catalyst from the hydrocarbon products. While this terminated that catalytic cracking, it still allowed the hydrocarbons to undergo thermal cracking reactions as they were discharged into the large disengager vessel, which resulted in long hydrocarbon residence times. 

Just a little history: In the mid-1980s, Mobil recognized a need to eliminate these undesirable thermal cracking reactions that occurred in disengager and developed the first Advanced Riser Termination System – commonly called ‘closed cyclones’ – where they coupled the riser cyclones directly to the upper cyclones. Mobil pioneered the use of advanced riser termination and installed it in eight of their own units in the late 1980s. In 1990, KBR formed an FCC alliance with Mobil and began licensing the technology. While Mobil’s development and commercialization worked out many of the issues prior to KBR’s involvement, there have been improvements in the technology since then, which I will discuss. 

Many of the improvements in KBR’s 27 years of experience have been operational-related. For example, we have been able to reduce startup steam requirements by lowering the required riser cyclone inlet velocity requirement without any negative impact. 

One of the keys to a successful startup is to avoid overloading the cyclone system during initial steam circulation. This means making small increases in catalyst circulation and letting things stabilize before making another increase. Once feed is in the unit and cyclone velocities are increased, then the system becomes very stable and resilient. 

One improvement that has been developed is referred to as ‘self-stripping closed cyclones’ where small holes are placed in the lower cone section of the riser cyclones where the stripping steam flows through. The purpose of this modification is to eliminate the small 2% underflow of hydrocarbon that is normal for a closed cyclone system. This improvement further reduces thermal cracking, thereby increasing the gasoline yield. Another version of this process is referred to as ‘direct stripping’, where external steam is supplied separately to the cone section and the normal cyclone hoods are maintained. This gives the operator flexibility to optimize the cyclone stripping steam. 

Another change we are implementing on newer projects is to use an intermediate plenum between the riser cyclones and the upper cyclones, as shown in the figure. The main reason for this change is that it allows the catalyst to be redistributed to the upper cyclones and makes the system more resilient to an upset of a primary riser cyclone. Another advantage is that it allows the use of a different number of upper cyclones than that of the riser cyclones. This can have a layout advantage, especially on larger units where we can have two large riser cyclones and maybe four or five upper cyclones. Due to the ability to use smaller upper cyclones, the required vertical space will be reduced as a result of the cyclones being shorter compared to the layout of a system with two large upper cyclones.  

MALLER (TechnipFMC Process Technology) 

The evolution of our technology at TechnipFMC is similar. We initially had the inertial separator, which had vented gas tubes to the upper reactor section to be close to the reactor cyclone inlets. Now we have a totally closed system. What is shown on the slide is the RS2 (riser separator) technology. One important point I want to make is that the ability to maintain ease of operation during startup, shutdowns, and upsets – without the risk of massive catalyst carryover – is important. With this technology, the diplegs are very large and not prone to flooding. It is essentially an inertial separator, so there is not a high velocity requirement to maintain adequate separation; therefore, there are no emergency steam requirements for startup. If we get enough velocity to transport catalyst, it is enough velocity to achieve good separation. Therefore, the RS2 does not experience any massive catalyst carryover events during startup. 

Our recent improvements: We are now learning that we have more units go through turnarounds. Unfortunately, the cycle for these lessons on reliability is every five years when a unit shuts down. We are currently making mechanical and reliability improvements to each situation when we see the requirement. We have made some changes to the slip joint design that allow for the independent thermal expansion of the lower section versus the upper section. We are also working continually with the cyclone vendors to try to improve the overall system efficiency for catalyst collection. 

DAVID HUNT [Shell Global Solutions (US) Inc.] 

I would like to add that in the FCCs we operate at Shell, as well as at several of our third-party customers, the cyclone technology uses what we call a ‘coke catcher’ which keeps coke from falling into the reactor cyclone dipleg and potentially blocking the dipleg during the run. Other developments in our Shell cyclone system include the use of a vortex stabilizer in the secondary cyclones to control the vortex and avoid dust bowl/dipleg erosion. 

ALEX MALLER (TechnipFMC Process Technology) 

The primary goal of a modern riser termination system which considers the close coupling of the primary and secondary separating devices is the reduction of residence time and, thus, the minimization of undesirable thermal cracking reactions. This post-riser cracking usually translates to dry gas yield at the expensive of other, more valuable products. By revamping an older type of system to a close-coupled advanced system, we have seen a typical reduction of dry gas yield of about 20% with corresponding increase in liquid product volume. 

Another important goal of a modern riser termination system is the efficient separation of catalyst particles from the reactor gasses, implemented with the aim of preventing excessive catalyst accumulation in the main fractionator bottoms circuit. This goal is important for all modes of operation, including startup/shutdown and transient periods. The system we have now is extremely efficient during normal operation, but most notably retains very high levels of efficiency at all times when catalyst is circulating. The primary separator is a positive pressure type, and the diplegs are very large and not prone to flooding. This arrangement ensures that any velocity sufficient to transport catalyst up the riser is enough to achieve adequate separation. No emergency steam is required. No massive catalyst carryover events have occurred on any of our installations.  

Our focus for technology improvements in recent years has focused on the reliability, as well as incremental improvements to the above-mentioned primary goals. For reliability, we have updated the design for the slip joint that ties together the upper cyclone portion of the system to the lower termination device. The new slip joint design has proven to be extremely robust without any issues reported on any units.  

MATTHEW WOJTOWICZ (Honeywell UOP)  

Evolution of UOP’s Vortex Separation Riser Termination Technology 

Before evolving to the vortex separation riser termination technology, UOP gained experience with all types of riser termination technology. Since 1983, UOP’s designs for riser termination devices have focused on reducing the post-riser vapor residence time in the reactor vessel. Since many of UOP’s efforts have involved technology upgrades in existing units (revamps), a variety of mechanical systems have been implemented to accommodate the wide variety of existing reactor sizes and styles. All of the UOP designs emphasize operating flexibility and mechanical reliability.  

UOP’s current riser termination design incorporates the state-of-the-art vortex separation technology to minimize the vapor passing into the reactor vessel and thereby minimize non-desirable reactions. 

In 1995, UOP commercialized the VSS™ (vortex separation system) technology which was specifically designed for higher capacity units with an internal riser while maximizing hydrocarbon containment, operating flexibility, and mechanical reliability. UOP’s VDS™ technology offers the same benefits for units with external risers. The VSS technology has evolved since it was initially commissioned in 1995. These enhancements have further improved hydrocarbon containment, operating flexibility, and mechanical reliability. A few of these enhancements are summarized below. 

Hydrocarbon Containment Advantage 

Vortex separation technology represents the highest hydrocarbon containment technology available, as it provides more than 99% containment of the hydrocarbon product vapor relative to only 94 to 97% for the next best system (direct-connected cyclone systems). The containment advantage is based on the quantity of hydrocarbon product vapor that is entrained with and adsorbed on the catalyst discharging from the first-stage cyclones. This hydrocarbon is equivalent to as much as 6% of the riser vapor. The hydrocarbon carryunder spends relatively long residence times in the reactor vessel before finally exiting out through pressure equalizing tubes. 

The vortex separation technology is designed to eliminate the hydrocarbon flow that exits at the bottom of the conventional riser separation devices, as well as efficiently separate the catalyst from vapor exiting the riser. The top of the stripper and the bottom of VSS chamber are integrated with each other thereby allowing the riser and stripper vapors to be contained. These vapors are prevented from entering the reactor vessel where they can undergo nonselective thermal cracking due to long residence times. The containment advantage of the VSS technology is illustrated in Figure E-1. Since the original implementation in 1995, the design has been tweaked to further improve hydrocarbon containment. The bed level has also been optimized further improving yields. 

Figure E-1. VSS Hydrocarbon Containment Advantage 

The superior hydrocarbon containment performance of the vortex separation technology provides improved yield performance over all competitive systems. The hydrocarbon not contained by the primary separation device undergoes significant nonselective thermal cracking due to long residence times in the reactor vessel. This results in a significant increase of dry gas, as well as major losses of gasoline, LCO (light cycle oil), and overall product olefinicity. Dry gas production – at the expense of the gasoline and LCO production – represents an opportunity loss which limits the profitability of the FCC unit. Additionally, the reduced olefin content of the gasoline will result in a reduction in the octane of final FCC gasoline product. The VSS technology reduces nonselective, post-riser cracking and can help maximize the profitability of the FCC unit through improved gasoline selectivity, improved gasoline octane, and reduced dry gas. 

Operability and Reliability Advantage 

UOP has significant experience within fluid catalytic cracking technology and has garnered a reputation for designing technologies for maximum operability and reliability. The vortex separation technology offers clear operational advantages over previous generation riser termination devices (RTDs), including ease of startup, turndown flexibility, reduction in reactor coke formation, and reduced incidents of severe erosion of internal components. 

During FCC unit startups, operations can experience pressure upsets which quickly send large amounts of catalyst into the reactor vessel. Pressure upsets of this kind are known to quickly overload other RTD designs and send large amounts of catalyst to the main column, causing costly high-catalyst makeup rates and problems in the main column or the main column bottoms product. Conversely, the vortex separation technology can easily handle pressure surges and reduce the risk of catalyst carryover through the use of its unique primary separation design. This operational advantage manifests itself as smoother and more robust operation of the FCC unit during upsets and is relatively more forgiving during unit startups. 

Not only does the vortex separation technology offer process and operability advantages, but it also can provide several reliability advantages. Coke formation in a reactor is largely influenced by the reactor technology and appropriate use of steam. The coke produced in the reactor space can build up on the reactor walls or refractory, pressure equalization openings, and other flexible joints, which can lead to either equipment failure or increased maintenance costs. The latest vortex separation technology creates a hydrocarbon-free environment in the dilute phase of the reactor by maximizing riser hydrocarbon containment. Coke has been completely eliminated from the reactor annular space. The vortex separation technology has been used as a process revamp improvement, as well as a technology upgrade to address coke formation. 

UOP’s design methods include several considerations and features which have dramatically reduced the incidents of severe erosion of internal components over time. Internals are designed with appropriate orientation and velocities to minimize erosion potential in critical areas such as cyclone inlets. UOP also specifies proven refractory- and abrasion-resistant lining materials in these areas which often survive a run with only small sections requiring repair. Utilizing these design methods, the vortex separation technology offers improved mechanical reliability of the reactor internals, improved unit availability, and reduced maintenance costs over the next best RTD alternative. Also contributing to the high mechanical reliability of the technology is the fact that over 95% of the catalyst separation occurs in the low-velocity VSS chamber, meaning that less than 5% of the catalyst will enter the higher velocity cyclones. There are multiple refiners with UOP’s latest VSS technology who achieve 99+% onstream efficiency with minimal maintenance required to internals following a campaign of more than five years. 

FOOTE (CHS Inc.) 

I prepared a few tables about technology and the principle of operation pros and cons of each of the demonstrated level of technologies and main column bottoms level transmitter. Again, it goes without saying that accurate measurement of the main column bottoms level is essential for reliability and safety. First, what I will talk about is nuclear. One of the benefits of nuclear technology is that it does not require any additional nozzles in the vessels. So, if you are looking for redundancy and do not want to go through the expense of installing a nozzle, this is a good option for you. Nuclear also does not require flush connections. Every bit of HCO (heavy cycle oil) flush you put back into the bottom circuit will affect your fractionation, so minimizing HCO flush is a big deal. Nuclear technology also gives you a true level measurement. The drawbacks to nuclear are obviously site management and nuclear sources; but likely, you already have these in your refineries. RT (radiographic testing) inspection and tower scanning can mess up your level indication. Just make sure people are communicating when they are doing x-rays in their work areas. 

The next technology is the torque tube. Basically, it is a cylinder that operates inside of a chamber where the fluid exerts a buoyant force on the cylinder. The difference in the weight is detected and corresponds to a level. Torque tube technology has been the standard offering from licensors for years now. The drawbacks to it are that it is a little mechanical; not terribly mechanical, but there are pieces that can fail on it. It also changes in process. Fluid density on startup, shutdown, and malfunction can affect the level measurement. The torque tube also requires flush oil. 

The third technology is guided-wave radar. Again, it gives you a true level measurement and has no moving parts. The common pitfall here is probe selection. Make sure your manufacturer knows that there is the potential for solids in these circuits and that he/she gives you the right type of probe. Sometimes the probes can be too tight, and you can plug them up. Guided-wave radar also requires flush oil to keep the taps operational.  

The last technology is pressure differential, which is very similar to torque tube. It is a proven technology; but again, it does not give you a true level if you have gasoil, say, at the bottom of the main column on startup. 

The next slide gives us the Point Level Technology. So, in addition to level transmitters, we also want to have point level indication. For years, the standard from licensors has been the try lines with the cooler. Obviously, the taps are open and you either have vapor or liquid there. The try line taps provide you with the means of telling you where the level is within the column. Obviously, there are safety concerns with try lines because you have H2S vapor and auto-ignition possibilities.  

The second technology – Ram’s Horn Thermocouple – is one that I am not sure has been commercially demonstrated in an FCC unit but which I think has been used in crude and in vacuum columns. Basically, the sub-cooled liquid is detected as the level goes up. There is no personnel exposure here. Retrofitting this technology can be costly, because it does require one nozzle for the thermocouple and another one for the ram’s horn drain that goes down below.  

Armored-level gauges have also been used. This equipment is not very commonly chosen. With purging, you can keep the glasses clean, although it is tough to do. Also, because of the thermal cycles you run on the startup, shutdown, or malfunction, keeping that glass sealed can be challenging. So, there are some challenges with that technology. 

Regardless of the technology we are using, redundancy is important. Right? I think it is best to use two different types of technology, if possible. However, Best Practice is to employ two level transmitters with the selector switch from the main column bottoms level control. For displacers, guided-wave radar, dP transmitters, and redundant transmitters need their own individual taps. So, do not try to put them on one set of vessel taps, because that is a single point of failure. For point level measurement, at least two points should be measured for high and low levels. 

At CHS, we operate our Laurel, Montana FCC. We use nuclear and a guided-wave radar with flush oil, and we use try lines for point level indication. We are strongly considering going to the ram’s horn thermocouples because of safety concerns at that FCC. At our McPherson refinery, we use two redundant level displacers and two armored gauge glasses that have LCO flush and fuel gas flush or fuel gas purge as well. We also have tried lines at McPherson. 

MALLER (TechnipFMC Process Technology)  

The TechnipFMC standard is a diaphragm-type pressure differential level instrument. We use continuous HCO flushing. We would like to see multiple instruments there for redundancy. I would go as far as to say that three separate instruments should be used. That way, you have the chance that two of them read the same, rather than having to discern which is correct with only two different readings. Also, I like to see a local gauge for field verification, which I have seen successfully applied via magnetic-type float gauges in service. 

TRAGESSER (KBR) 

KBR’s normal practice is to offer a tried-and-true method that uses simple level transmitters for main fractionator bottoms. Both level transmitters are pressure differential types and share the nozzles at the vessel. Multiple transmitters are provided for improved reliability. The board operator has the option to switch between the two measurements.  

Both level transmitters use a diaphragm seal to prevent slurry and solids from getting into the transmitter. 

The main fractionator measurement nozzles at fractionator shell are purged. We use fuel gas to purge the low pressure tap and flushing oil to purge the high-pressure tap. The tubing for the transmitters is electric or steam-traced to minimize the potential for blockage if the purge is lost. 

MELVIN LARSON (KBC Advanced Technologies, Inc.) 

How far up do you take your top tap on your level transmitter? 

MALLER (TechnipFMC Process Technology) 

Typically, we have a reduced diameter boot at the bottom of the fractionator and we take the top tap at the top of that area. We do not take it up into the flash zone. 

DARIN FOOTE (CHS Inc.) 

The following tables list the demonstrated technologies to reliably measure main column bottoms (MCB) level. Regardless of the technology used, it is important to have redundant level indication. The Best Practice is to employ two level transmitters with a selector switch for MCB level control. For displacers, guided-wave radar, and dP level transmitters, redundant transmitters should be on independent vessel taps. There are benefits to having two different level technologies employed. For point level measurement, at least two points should be measured for high and low levels. 

Table 1. Level Technologies for Main Column Bottoms Level Transmitters 

Table 2. Demonstrated Methods for Point Level Indication in the Main Fractionator Bottoms 

At our Laurel, Montana FCC, we use nuclear and guided-wave radar for redundant indication and try lines for point indication. We are strongly considering getting rid of our try lines and replacing them with ram’s horn thermocouples due to safety concerns. In our McPherson, Kansas FCC, we use redundant level displacers and two armored gage glasses for point indication. 

ALEX MALLER (TechnipFMC Process Technology) 

We use diaphragm-type pressure differential level instruments with continuous HCO flushing oil provided to the connection at the vessel. Multiple instruments are typically used to provide redundancy and some confidence in the readings. A magnetic-type float gauge can also be provided for verification in the field, but it should be insulated, steam-traced, and provided with continuous flushing. With these arrangements, level measurement at the main fractionator bottoms is not typically a big issue. Some units have applied nuclear-type instruments successfully for this service, but it is not our standard to do so. 

FEDERSPIEL (W.R. Grace & Co.) 

Evaluating an FCC catalyst reformulation is not something you are able to do overnight. It is a long commitment to post-audit the catalyst reformulation. Because of that, preplanning really is critical. Right? You want to make sure that you plan out for the trial in a manner that will let you do your post-audit effectively. You will want to define the objections and constraints very clearly in the beginning of the trial and establish sample and data collection, both the timing on that and the methods. Then, you should develop an evaluation plan. What does success look like for this reformulation? Because of the time commitment it takes to do a catalyst trial, the average age of catalysts inside an FCC unit could be anywhere from 20 days. This timeframe might be a fast reformulation effort to some units that go to an average age of 100+ days, which is a lot longer timespan. During that time, how many people in the audience draw straight lines on the DCS (distributed control system) for six months in a row? I am not going to pull up the polling app, but I guess the response is zero. 

Using chronological plots by themselves is not an effective way to evaluate catalyst reformulation, so we have to introduce some other methods. Using cross-plots is one where you plot process variables. Instead of just against time, you plot them against another process variables. Further, you can use ACE (Advanced Cracking Evaluation) testing or pilot plant testing. Modeling can be used as well. 

There are complications you will have to consider when you are planning for reformulation and the post-audit of it. Feedstock availability: Ideally, you would be able to run at least some period – both on your initial catalyst and your reformulated catalyst – using the same feed. That will eliminate a major variable in the evaluation. If you have shifts in economics that force you to change your operating mode, clearly you will have to consider that scenario, too. If you move from gasoline mode to trying to produce propylene to take advantage of that market, the post-audit will clearly be more difficult to extra out of the trial. On longer trials, you can run into summer or winter effects on blowers and compressors that will change your constraints; so, plan and account for such seasonal effects. There are logistical concerns with handling the catalyst, especially if you are reformulating from Vendor A to Vendor B. You might not use the same logistics company, so consider that as well. Lastly, putting in the wrong catalyst can be really expensive and will certainly complicate the catalyst trial. If you do not plan for and risk-mitigate it properly, you will end up cutting the trial short, which will be costly for you. 

BHARGAVA (KBC Advanced Technologies, Inc.) 

Catalyst change is one of my favorite topics, so it is appropriate that I answer this question. We have conducted catalyst evaluations for several clients; and not only have we been successful executing these base catalyst changes, but we have also found improvements for selecting the right catalysts for additives. We evaluated ZSM-5 additives from different vendors and have been successful differentiating ZSM-5 that comes with the base catalyst vendor with ZSM-5 coming from another catalyst vendor that just sells ZSM-5. We understand that small changes in the FCC yields are difficult to find, and these small changes – in themselves – equal millions of dollars of improvements you can do on a catalyst. One of the ways we bring value to the table is by putting in a very rigorous system of evaluating catalyst. As was just said, we also must do the preplanning, which I will talk about in my last bullet point. What we do is use simulation models. We installed a test run program to do a test run every two weeks during the catalyst transition, and we developed calibration factors. 

What are calibration factors? These calibration factors are an indication of the mechanical efficiency of the unit. Given the mechanicals are the same, it helps you track the catalyst changes. So, the calibration factors are a proxy for what the catalyst is doing in the unit. Once you have the calibration factors, you can then make an apples-to-apples comparison. The feed changes in six months. While the catalyst is changing your operating conditions, constraints change. So, we make that comparison at constant constraints, and then we evaluate the results. We do sensitivities on different situations to determine which catalyst will work under which situations. 

We benchmark. We find the cracking property on the catalyst to tell us what sort of changeout we have from the catalyst analysis. We do the analysis at 25% changeout, 50% changeout, and 75% changeout to validate the results when we do the analysis. Do not rely on the vendor estimates because they can be very different from what you actually see on the unit. You definitely want to employ an independent third-party company that either benchmarks or uses the pilot plant to give you yield estimates on your feedstock. It has to be done on your feedstock by an independent party to give you yield estimates at different cat oils at different ROTs (reactor operating temperature). Look for metal tolerance tests. 

KBC has seven tests required to be done for each catalyst, if you are going to do the full catalyst evaluation. Once you get those results, you cannot use those results for any comparison on how good the catalyst will be, even at constant conversion, which is typically what the vendors or independent lab will give you. You need to change that data into a heat-balance model. These estimates have to be normalized so they will represent your unit. So, you need a base run calibration of your unit and then superimpose the catalyst effects on the base case calibration under heat-balance situations to get the right estimates you are seeking. Then, do a post-audit and compare it with the catalyst results. 

DINKEL [Marathon Petroleum Corporation (MPC)] 

I will echo that we like to look at multiple methods for confirmation; but within Marathon, we have our own circulating riser unit. That is where we heavily rely on looking at both the catalyst assessments for changeout, as well as the post-audit data. As Mike was saying, we are able to isolate variability from the commercial unit which allows us to focus on catalyst performance. We can look at the original feedstock at the end of the catalyst changeover, as well as the feedstock at the end of the run, which may be as much as six months down the road. 

During the Annual Meeting in March, we co-presented a paper with Albemarle that detailed a catalyst changeout and got into more discussion on our uses of pilot plant. You can refer to the paper for more details, which was entitled “An Action Plan to Improve FCC Unit Performance at the Marathon Galveston Bay Refinery”.6 

PHILLIP NICCUM (KP Engineering, LP) 

I wholeheartedly agree with the suggestion to use a model to adjust the data. What I found and observed to be the most successful is that you can also do this leading up to the catalyst change. Take some routine tests, perhaps once a week. Get some good data, and then adjust it to some basis of a feed quality in operating conditions. Then, continue this process as you go into the trial. You will then have a way to isolate the feedstock quality changes and the operating condition changes that are inevitable and required in the operation. Using that data, you can then reflect on the effect of the catalyst. I am not a fan of using pilot plants to test it, because you cannot be certain of the testing protocol itself. The catalyst may be better in the pilot plant then it will be in your commercial unit. So, I believe in the benchmarking of the actual data and the collection of reliable data on routine basis, as well as watching the trial from the beginning. If it starts to go south, correct it before it gets bad. 

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

As part of the preplanning Mike outlined, do not forget the operability of the catalyst. For example, you may not get the opportunity to see the yield shifts if the catalyst circulation is challenged. So, go through the various unit operating parameters, identify where the unit operation could become constraining, and prevent your full realization of what the new catalyst has to offer. Try to put in some milestones early, while you are changing out, to check if you will be able to appreciate the projected yield structures. Just make that a part of your preplan. 

MICHAEL FEDERSPIEL (W.R. Grace & Co.) 

Preplanning is an important part of ensuring that the catalyst reformulation and post-audit are successful. Before the catalyst trial begins, it is important to define catalyst objectives and establish a clear evaluation plan on how these objectives will be monitored and evaluated for the trial. Sample and data collection guidelines and establishing a good base case should be done before the trial. It is critical that the samples and processed data needed to monitor the reformulation are routinely collected before and during the trial. It is also suggested to work closely with Operations, the refinery lab, and your catalyst supplier to guarantee that samples are being collected and the proper analyses are being performed.  

After the process data and samples are collected and analyzed, there are several different methods – such as cross-plots, lab testing, and modeling – that can be applied to evaluate the benefits of a reformulation. The first method is the use of cross-plots. Cross-plots are an extremely useful tool to look at operating data and e-cat data on a similar basis. One example of a cross-plot is shown in Figure 1 where a refinery reformulated the catalyst to improve bottoms upgrading. At similar conversion, the refinery was able to achieve lower bottoms. 

Figure 1. Slurry LV% (liquid volume percent) versus Conversion LV% 

Other cross-plots, such as gas factor versus equivalent nickel or gasoline octane versus reactor temperature, could be useful to help determine the benefits of a catalyst reformulation. The catalyst objectives will determine which cross-plots are the most meaningful for the trial. When drawing conclusions on cross-plots, different operating conditions, feed quality, and catalyst health should be taken into consideration. This is why laboratory testing and models should be used in conjunction with cross-plots. 

Laboratory testing can be used to help evaluate the catalyst reformulation. ACE testing and Grace’s DCR® (Davison Circulation Riser) testing can be conducted on the equilibrium catalyst to help determine the benefits of the reformulated catalyst. The advantage of lab testing is that it is conducted using fixed operating conditions and a fixed feedstock, thereby removing the uncertainty in results solely derived from unit operating data due to variability in these parameters over the course of the evaluation. Lab testing should be done with the refinery feed, base equilibrium catalyst, and reformulated equilibrium catalyst. The equilibrium catalyst should be chosen with similar metals levels which may not be possible during the trial if the unit experiences a shift in metals levels. 

Another method to evaluate catalyst reformulation is the use of models. Models are tooled used to quantify catalyst reformulation benefits since they can be developed to predict yields shifts at defined conditions. When developing, calibrating, and using models, it is important to make sure that data input contains no errors. Before using a model to determine catalyst reformulation benefits, model-predicted yields should be compared to actual yields to validate the accuracy of the model. If the model cannot be validated, it should not be used in the evaluation.  

Two model methods can be used to determine catalyst reformulation benefits. The first method is to calibrate and validate the model for the base catalyst. After the new catalyst is fully turned over, this model can predict what the yields would have been on the base catalyst at similar operating conditions. The predicted yields are then compared to actual yields to determine the benefit of the reformulation. The second method is a double-check of the first method. The model needs to be calibrated and validated for the reformulated catalyst. This model can then determine what the yields would have been on the new catalyst at base catalyst conditions. These predicted yields can be compared to the actual yields before the trial to determine the benefit. The results from both methods should be compared to make sure that the methods show similar benefits. 

In conclusion, evaluating a catalyst reformulation can be very complicated since it is extremely rare for a unit to run in a stable manner with similar operating conditions, similar feed quality, and similar catalyst health. This variability in operation is why several methods need to be used to quantify the benefits of the catalyst reformulation.  

SANJAY BHARGAVA (KBC Advanced Technologies) 

Post-audits are very important to verify if the catalyst performed to its original estimates from the catalyst vendor and if it shows the same yield and property shifts as originally proposed. We prefer a very detailed post-audit consisting of high-quality, stable, and data-validated test runs (four to eight) performed on a weekly basis on the base catalyst followed by weekly test runs during the transition. A key catalyst parameter (such as rare-earth or alumina) is used to track the transition of the existing catalyst to the new catalyst. The unit performance (yields, properties, coke/gas selectivity, etc.) is also tracked and normalized using a simulation model and projecting several different simulations runs under constant conditions and constraints. This procedure is done with calibrated models at the base catalyst at 25% changeout, 50% changeout, and 75 to 80% changeout. Economics are applied to all the cases to determine the value of the catalyst change and then compared with the original delta estimates from the vendor. Next, the values are converted into heat-balanced yields, properties under constant conditions and current constraints to determine the success of the catalyst change. 

This exercise is difficult since small changes are frequently expected which have a major economic benefit. So, there is a big incentive to have sophisticated tools and methodologies to perform stable test runs and do additional data validations. 

BRYAN DINKEL [Marathon Petroleum Corporation (MPC)] 

Best Practice for post-auditing catalyst changes on a unit includes using multiple types of reviews to provide assurance that all of the data is pointing in the same direction. We will use commercial data reviews, catalyst supplier assessments, and pilot plant testing – coupled with the utilization of a kinetic model – to translate pilot plant results to better reflect commercial unit results. In my experience, review of commercial data alone is often muddled with feed quality shifts; so typically, there are challenges getting clean baseline and post-changeout data sets for review. Catalyst supplier reviews will usually isolate catalyst performance based on their standard feeds and ACE (Advanced Catalyst Evaluation) run data, which is insightful but not as reflective as circulating riser unit (CRU) results. Within MPC, we utilize our internal circulating riser unit upfront in the catalyst selection phase and in the post-auditing period. The CRU allows us to isolate catalyst performance shifts and then plug that information into our kinetic model to optimize the unit against operating constraints. You can refer to the March 2017 AFPM Annual Meeting paper, co-written and presented by Albemarle and MPC, entitled “An Action Plan to Improve FCC Unit Performance at the Marathon Galveston Bay Refinery”7 for discussion in more detail. 

REBECCA KUO (BASF Corporation) 

In a perfect world, during a catalyst change there would be no feed or operational changes. However, this rarely occurs; therefore, the best way to post-audit a catalyst change is to track the equilibrium catalyst (e-cat) yields by ACE (Advanced Cracking Evaluation) testing, as the testing is done with a standard feed at constant operating conditions, so any deltas are attributed to the catalyst only. It is important to note, when comparing ACE yields reported by different catalyst suppliers, that the absolute yields will not be comparable as all suppliers use different feeds and operating conditions. The trends from baseline are the most crucial to track. Another option is to conduct lab testing (such as ACE or circulating riser unit) using the FCCU feed with both e-cats to post-audit the catalyst changes at apples-to-apples conditions. If using this option, make sure that important e-cat properties – such as Ni (nickel) and V (vanadium) – are similar between the two catalysts. If post-auditing the catalyst change with the operating data and reactor yields, a Best Practice is to use a kinetic model – such as FCC-SIM or a statistical model – to normalize the data for changes in operating variables and feed properties. Build a comprehensive and statistically-sound base case with the incumbent catalyst and project forward to the new catalyst. Any deviation from the model will be due to the catalyst change. Finally, when conducting a post-audit of a catalyst change, it is crucial to understand the turnover of the catalyst inventory. A rule of thumb is to start tracking the catalyst effects around 50% turnover; as at this time, about 75% of the activity will come from the new catalyst. At 75% turnover, about 90% of the activity will come from the new catalyst. 

FEDERSPIEL (W.R. Grace & Co.) 

With the next few slides, I will show you some data we compiled. I will explain the data as I talk through the slides. On the first slide are histograms of data that is sent to us from FCC units of both Grace customers and non-Grace customers. Each unit is represented by one number. Looking at the number of units on the Y axis, you see that they are grouped into different contamination levels. The histogram shows globally where we have received data for the year 2017 and also gives you an idea of the distribution of those contaminants across the industry. 

The question asked: With these new types of feeds that are coming in, what new metal contaminants are we seeing? At Grace, we have broken them down into three different types of groups. We group it out as alkaline and alkaline earth metals, which went into the potassium, magnesium, calcium, and barium. They tend to act similar to sodium in that they will ultimately destroy zeolite. And then at high enough concentrations, they can help aid the forming of eutectics, which can further degrade access to the catalyst diffusion to the catalyst sites or even cause service and more morphology problems. 

There are other metals which we classify such as molybdenum, cobalt, copper, zinc, and lead. These metals often act with dehydrogenation effects similar to nickel and vanadium. So, they are tied, again, to the traditional metal contaminants we have been studying for a while. Molybdenum is interesting in that it is particularly destructive but not particularly common. If you look at the distribution of units, you see that not very many units have any kind of real concentration of molybdenum on them, but that molybdenum is said to be five to 10 times dehydrogenating as nickel and vanadium. However, the concentrations are so little that they do not really impact FCC unit performance. 

Lead is one of those metals that has been around. It is known to reduce promoter effectiveness, even at levels of around 100 ppm. But if you build up lead, you can start to impact the activity of the catalyst when the lead reaches levels around 800 ppm. And again, by looking at the distribution, you can see that there are just not many units out there with very high concentrations of lead, at least in the activity reduction zone. There are a few where the lead could be impacting the promoter effectiveness. We do see other elements – including phosphorous, silicon, mercury and arsenic – present in FCC e-cat (equilibrium catalyst). 

With respect to the time, I will just quickly talk about arsenic. It is interesting because depending on how the lab that you are using is analyzing for it, you can actually get a false positive or a false high result. The reason is that the method can confuse lanthanum, which is present on FCC catalyst, as arsenic because the peaks are overlapped. So, there is a specific type of ICP (inductively coupled plasma) mass spectroscopy that you should be using if you are trying to analyze for arsenic, which is present in some crudes and imported feedstocks. Arsenic can produce some bad downstream effects. 

DINKEL [Marathon Petroleum Corporation (MPC)]  

I will just confirm our experience from Mike’s laundry list of contaminants. We have seen some barium show up in units that process tight oil, but the concentrations were so low that we did not see any impact to unit operation. 

ALEXIS SHACKLEFORD (BASF Corporation) 

For barium, BASF has done some laboratory tests looking at the impacts. As long as there is a rare-earth on the catalysts, the impacts are minimal, if any. Silicon normally comes from the coke unit (recycle) due to the antifoams used. FCC catalysts already contain a high amount of Si, and additional Si (silicon) will have no impact. You do not have any of the concerns you would for hydrotreating. Now, arsenic is volatile under FCC conditions. Due to its volatility, it does not deposit on the catalyst and has no negative effects. You will see it downstream in the propylene steam as they both have similar boiling points. If your propylene stream is routed to any chemical operations, you must remove that arsenic because it will kill the catalysts. There are plenty of solutions for arsenic removal in these streams. 

MICHAEL FEDERSPIEL (W.R. Grace & Co.) 

In addition to the “standard” contaminants of nickel, vanadium, iron, and sodium, there are a variety of other feed contaminants that can impact FCC performance. For example, tight oils (also known as shale oils) can contain high levels of potassium, magnesium and calcium in addition to the iron normally found in them8. While bio-based feedstocks are not yet widely processed in commercial units, they would be expected to contain higher levels of calcium, sodium, magnesium, and potassium than conventional feed sources since these elements all play an important role in biological systems. High levels of phosphorous have been found on synthetic crudes. Opportunity crudes can contain a variety of non-standard metals including copper, zinc, silicon, mercury, and arsenic. Molybdenum and cobalt can also find their way into FCC feedstock. At times, it seems like every element in the periodic table can wind up in the FCC. 

These metals can be considered in three groups: (a) alkali and earth alkaline metals, (b) other metals, and (c) other contaminants. For many elements, histograms of contaminant levels on e-cat are presented. These histograms are based on a worldwide survey of more than 270 FCC units, and the data is a one-year average for each unit of the e-cat samples tested.  

Alkali and Earth Alkaline Metals 

Similar to sodium, the alkali metal potassium will reduce activity by poisoning active sites and will also result in zeolite destruction. Alkaline metals in feed (such as calcium, magnesium and barium) will result in zeolite degradation similar to that seen with sodium. Classic work by Letzsch and Wallace9 found that on an added weight-percent basis, potassium is about 0.5 to 1.0 times as destructive as sodium and that calcium and magnesium are less destructive than sodium. Barium was found to be less destructive than the other alkaline earth metals. Calcium, in combination with iron, can be especially detrimental. As described in the answer to Question 44 at the 2009 NPRA Q&A, calcium – along with other elements such as iron and sodium – can act as a fluxing agent to form low melting-point phases on the surface of the catalyst. This could help the operation results in the collapse of the pore structure on the surface of the catalyst particle and a reduction in conversion since it is harder for feed molecules to enter the catalyst particle. As seen in Figure 1, levels of potassium on equilibrium catalyst are generally low, with the worldwide average at 0.05 wt% (weight percent).  

Figure 1. Average Concentrations of Potassium on E-Cat for FCC Units Worldwide 

This level on e-cat contrasts with sodium which has an average level on e-cat of 0.26 wt%. Most magnesium in equilibrium catalyst comes from SOx-reduction additives or metals-trapping components instead of feed. Figure 2 presents a histogram of magnesium oxide concentration in e-cat for units worldwide.  

Figure 2. Average Magnesium Oxide Concentrations on E-Cat for FCC Units Worldwide 

Calcium can come from feed, although there are a few units that use calcium containing additives. As seen in Figure 3, more than 90% of the world’s FCC units run at calcium levels below 0.5 wt% on e-cat.

Figure 3. Average Calcium Concentrations on E-Cat for FCC Units Worldwide 

As seen in Figure 4, barium levels are generally low, with 95% of the world’s FCC units at barium levels below 0.1 wt% on e-cat. 

Figure 4. Average Concentrations of Barium on E-Cat for FCC Units Worldwide 

Other Metals

Many metals (like molybdenum, cobalt, copper, and zinc) act as dehydrogenation catalysts, like nickel and vanadium. Molybdenum is a rare feed contaminant that can cause zeolite destruction, as well as an increase in coke and hydrogen. It can be present in feed either from the starting crude oil or from carryover of hydroprocessing catalyst. While cases of molybdenum poisoning are rare, it can have a very detrimental effect. In one refinery, a severe increase in molybdenum, by 1700 ppmw (parts per million by weight), resulted in a six-number drop in e-cat MAT (microactivity test) – a tripling of the e-cat gas factor – and a more than 50% increase in the e-cat coke factor. In another refinery, an increase in molybdenum from 40 to 180 ppmw resulted in the doubling of hydrogen production in e-cat testing. While the detrimental effects of molybdenum will vary with regenerator conditions (full-burn versus partial-burn and temperature), as a rough approximation, molybdenum appears at least five times as active as vanadium on a weight basis. Fortunately, molybdenum is a rare contaminant in most units. As seen in Figure 5, with the exception of one unit, molybdenum levels on e-cat are below 100 ppmw. 

Figure 5. Average Concentrations of Molybdenum on E-Cat for FCC Units Worldwide 

While cobalt is not typically found in the feed unless it comes in from hydrotreaters ahead of the FCCU, it can result in increased hydrogen and coke. As seen in Figure 6, cobalt levels are generally low, with 90% of the world’s FCC units at cobalt levels below 200 ppmw. 

Figure 6. Average Concentrations of Cobalt on E-Cat for FCC Units Worldwide 

The dehydrogenation activity of copper is typically about the same as that of nickel on a weight basis10. The copper content of most FCCU feeds is very low, so it is normally not a problem. As seen in Figure 7, copper levels are generally low, with 95% of the world’s FCC units at copper levels below 100 ppmw. 

Figure 7. Average Concentrations of Copper on E-Cat for FCC Units Worldwide 

Zinc from feed is another metal with dehydrogenation activity. In a 1996 NPRA Q&A, one respondent to Question 18 (about processing used lube oils) stated that he had found that zinc tended to have lower dehydrogenation activity than nickel. We have observed several North American units experience spikes of zinc on e-cat of 1,000 to 2,000 ppmw in the last two years, possibly from zinc additives in their crude slate. In addition to coming from feed, zinc is used in some gasoline sulfur-reduction additives; zinc from this source will also appear on e-cat reports. Zinc in gasoline sulfur-reduction additives does not have the dehydrogenation activity of zinc introduced from feedstock. Figure 8 presents average zinc levels on e-cat worldwide with known zinc-based GSR (gasoline sulfur reducing) additive users removed. As seen in Figure 8, 90% of FCC units have less than 500 ppmw zinc on e-cat.

Figure 8. Average Concentration of Zinc on E-Cat for FCC Units Worldwide (with known Zinc-based GSR Additive Users Excluded) 

Lead can come from the source crude oil or – very rarely – from recycled aviation gasoline slop streams fed to the FCC. It is well known that lead can cause the deactivation of combustion promoter, which results in detrimental effects at levels of even 100 ppmw11. Work in 1987 established that in large enough concentrations on e-cat, lead can also cause a loss in catalyst activity and conversion. In that work, 800 ppmw lead resulted in a loss of 2 to 4 numbers of MAT activity12. Experience with equilibrium catalyst suggested that 1,000 ppmw lead would result in a loss of 1% conversion13. However, there are almost no units operating at these levels of lead in the industry today. Nine five percent of units are below 300 ppmw lead on e-cat, and 85% of units are below 100 ppmw lead on e-cat. Figure 9 presents industry average data for lead on e-cat. 

Figure 9. Average Concentrations of Lead on E-Cat for FCC Units Worldwide 

Other Elements 

High levels of phosphorous can be found in shale oils and in Western Canadian crudes. The phosphorous appears to come from fracking fluids and gelling agents used in well stimulation. In our experience, we have seen P2O5 (phosphorus pentoxide) on e-cat increase by up to 0.1 wt% with a change in FCC feedstock slate. The levels are not high enough to affect FCC catalyst, but the phosphorous is often a problem in the main fractionation tower and the hydrotreater. Questions 31, 36, and 65 from the 2013 AFPM Q&A address the effects of phosphorous in units other than the FCC. 

Silicon can come from crude oil or antifoaming agents. Since silicon oxide is present in the composition of the base catalyst, we would not expect silicon from feed to have an effect on FCC catalyst and have not observed any effects. However, silicon is a significant poison for hydroprocessing catalysts. This topic has been discussed in earlier AFPM Q&A and Technology Forums14. 

Mercury can be found in trace levels in many hydrocarbons. Under FCC conditions, mercury is very volatile and would not be expected to build up on FCC catalyst. While mercury would not affect FCC catalyst, it can concentrate in cooler downstream units. For example, there is a reported case of pooled mercury having been found in an FCC flue gas line during a unit shutdown15. 

Arsenic is naturally found in crude oil. The arsenic compounds in FCC feedstock primarily react to arsine (AsH3); additionally, some arsenic leaves the unit in the liquid products. Arsenic is highly reactive towards nickel and noble metals, and arsenic compounds have a negative effect on the catalysts of downstream units for reactions such as polymerization, reforming, and hydrotreating16. Guard beds are often used to remove the arsenic-containing compounds and protect catalyst in downstream units. Arsenic in FCC feedstock has not been found to deactivate the cracking catalyst, probably because arsenic is not reactive towards the silica-alumina structure of the zeolite. Levels that Grace has seen for arsenic on e-cat are typically below 20 ppmw. An important consideration in measuring arsenic in e-cat and fines is the analysis method. Inductively coupled plasma atomic emission spectroscopy (ICP-AES) is not suitable for determining arsenic levels in e-cat since the lanthanum in the e-cat will interfere with the arsenic line such that incorrect high levels of arsenic will be reported. Difficulties with ICP-AES analysis – for samples with both arsenic and lanthanum – have been observed in other industries17. Preferred techniques for determining arsenic on e-cat and fines are inductively coupled plasma mass spectroscopy (ICP-MS) and neutron activation analysis (NAA). Potential interferences also exist in these two methods, and any lab doing analysis should be informed of the presence of lanthanum. The topic of arsenic in FCC is covered further in the answers to Question 4 from the 2016 APFM Cat Cracker Q&A. 

BRYAN DINKEL [Marathon Petroleum Corporation (MPC)] 

We have seen trace amounts of barium at one of our units, but the levels were low enough that there was no impact. Barium has been linked back to tight oils in literature discussion and in follow-up conversations with the catalyst supplier on this particular unit. 

ALEXIS SHACKLEFORD (BASF Corporation) 

Other contaminants that are seen include calcium (Ca), barium (Ba), potassium (K), phosphorus (P), mercury (Hg), arsenic (As), magnesium (Mg), and lead (Pb). The elements that are alkali metals or alkaline earth metals – Ca (calcium), Mg, and K (potassium) – will all act similarly to sodium, in terms of neutralizing acid cracking sites, if they come in contact with the feed. Ca and Mg can also be present in vanadium traps, although these chemicals do not cause adverse catalytic effects. Currently, Ca is showing up in greater quantities than before with new opportunity feeds. Mitigation strategies include improved desalting and increased catalyst addition rates to make up for the loss in activity or the use of flush catalyst. These metals, especially Ca, may plug catalyst pores, so be sure to use a catalyst with proper pore architecture. Barium can come in with some tight oil feeds and can be present in some vanadium traps. Barium shows no impact on activity if the catalyst contains rare-earth. Arsenic is still uncommon; but occasionally, it is seen and volatile under FCC conditions. It does not affect yields and leaves with the C3= stream where it will need to be removed as small quantities will poison petrochemical catalysts (more than 20 ppb). Phosphorus is found in ZSM-5 additives and some catalysts. If coming from the feed (found more prevalently in tight oil feeds), it can leave with the products or deposit on the catalyst; however, there are no adverse yield impacts. Lead is still uncommon but will poison CO promoters if they are present. Mercury is also still uncommon and will leave with the products, often in the heavy naphtha stream. If sent to a reforming unit, a few ppb of mercury will poison the precious metals catalyst and needs to be removed. 

FEDERSPIEL (W.R. Grace & Co.) 

As I said earlier, the average age of FCC e-cat in a unit inventory is between 20 and 100 days. Clearly, there is a distribution of particles. Some are much newer; some are much older. So, it is not at all practical to mimic exactly what is going on in the FCC to judge how a catalyst might break apart. Therefore, we use an accelerated wear test as a proxy for measuring the probability of attrition on a catalyst. There are several different types of accelerated wear tests. There are cyclone tests, which are a more elaborate method because they do require a large quantity of catalyst. There is the air jet method. The primary mechanism for attrition there is particle-to-particle impact. And then, there is the jet cup method, which has both particle-to-particle and particle-to-wall effects. 

This next slide just shows the details about the most common attrition mechanism: abrasion. Using an accelerated wear test that simulates abrasion is a realistic method to pursue. The test procedure separates the elements that are uniformly distributed within the particle from those elements that are expected to be concentrated on the surface. The test method then compares the ratio between the fines and the e-cat for those elements. So, what we see is that elements which are concentrated on the surface are shown or overrepresented in the fines or they have a higher ratio in the fines. What that tells us is that the main attrition mechanism inside an FCC unit is driven by abrasion of catalyst particles. That makes sense, too, because fracturing has a higher energy requirement to fracture a particle than it does to abrade the surface. 

Now I will talk really quickly about the different mechanisms. The jet cup, the air cup, and the cyclones will have similar rankings, but they will not have the same number scale. You do need to find a single laboratory to compare them, because the method – and even the apparatus used in that same method – will have an impact on the result you get for the attrition testing. 

DINKEL [Marathon Petroleum Corporation (MPC)] 

In an earlier response, I mentioned that we have our own pilot plant, so we do our own jet cup analysis via the original Grace method to supplement our activities there. We utilize a pass/fail test, which is a good indication of whether or not we will have circulation issues within the pilot plant. We have also used that analysis to help with troubleshooting on some of our commercial units in the past. 

The second bullet point mentions ASTM (American Society of Testing and Materials) Round Robin tests for comparing the variety of different test methods utilized in industry. Our central lab participated in the test, along with approximately 10 different suppliers and independent labs. We know what Grace uses from Mike’s response. BASF and Albemarle utilize different equipment and test methods than Grace and each other. PSRI (Particulate Solid Research Inc.) has also done testing on the jet cup. In their research, PSRI found some issues with attrition not being quite as reflective as they would have liked to have seen. As a result, PSRI developed their own test method, including equipment and procedures. The end goal is the analysis of all of this data from this ASTM study to see if ASTM can possibly come up with a standardized test. 

The last part of the question is about independent labs for testing. I mentioned PSRI. As a member company, we have access to their attrition testing findings. PSRI also conducts contract research, so they are one option for independent testing. CPERI (Chemical Process & Energy Resources Institute) in Greece does independent testing. Cat Testing Labs in Savannah is another option that would allow you to evaluate catalysts from different suppliers and have an independent view of the test results. 

RIK MILLER (Phillips 66) 

Phillips 66 operates a standard jet cup test to measure catalyst attrition. About 12 years ago, we became very interested in not just measuring the attrition indices of catalysts, but also measuring the particle size distribution of the attrited products. It was very important for us to know not just how much of a catalyst broke up, but also what it broke into, because flue gas particulate capture equipment varies in efficiency. So, we began to analyze the attrited products from the jet cup test to determine their particle size distribution, and we found significant differences from one catalyst to another. The catalysts might have the same attrition index but produce a very different attrited particle distribution. We found the results of this test to be very important as they were predictive of the performance of catalysts in our commercial units. 

MICHAEL FEDERSPIEL (W.R. Grace & Co.)  

A number of operating factors influence catalyst losses from the regenerator that can lead to particulate matter (PM) emissions. These factors include: the number of fines present in the freshly added catalyst, the number of fines generated in the unit, the amount of catalyst transport to the cyclones by entrainment, and the cyclone performance. Fines are the most important factor in catalyst losses, because the fines are most readily lost by the cyclones and the collection efficiency of cyclones drops as particle size drops. FCC catalyst fines (0-20 micron) can come from either fresh catalyst that is added to the unit or be generated via attrition while the catalyst circulates in the unit. Catalyst can experience attrition in the unit from either fracture (catalyst breaking into smaller fragments due to severe impact of the particle against a solid surface, severe impact against other particles, or impact from a jet of steam or air) or due to abrasion were rubbing against a solid surface or other particles erodes the particle at the outer surface and produces fines. Abrasion has a lower threshold energy than fracture18. While both fracture and abrasion occur in FCC units, abrasion is the dominant mechanism of fines generation in most FCC units. The evidence for this is that the fines for most units are enriched in surface contaminants such as calcium, iron, and nickel. If abrasion is the dominant mechanism, one would expect fines to be enriched in surface contaminants; while if fracture were the dominant mechanism, one would expect the fines composition to be the same as the bulk e-cat. Figure 1 presents data for 94 units where the concentration ratio of an element in fines versus e-cat is presented. As seen in the graph, there is no enrichment in fines in elements that are uniformly distributed in a particle (such as aluminum, silicon, and titanium), but there is strong enrichment of the fines of many units in the surface contaminants such as calcium, nickel and iron.

Figure 1. Abrasion is the most common mechanism, based on evidence that fines for most units are enriched in surface contaminants such as Ca, Fe, and Ni. 

There are a variety of lab methods that have been used to simulate – in the lab – the particle attrition that occurs in a commercial unit. They all involve subjecting catalyst to more severe attrition than is experienced in a commercial unit. One sophisticated method involves passing the catalyst through a series of cyclones at high velocity19. These cyclone tests provide insight into attrition fundamentals, but the large amount of sample required, and the long testing times prevent their use for routine testing of catalysts for attrition. The most common test methods for routine catalyst testing are methods based on the air jet and the jet cup. In both methods, the catalyst is subjected to a high-velocity air stream, which results in fines generation. The number of fines generated is a measure of the attrition resistance of the catalyst. In the air jet method, most of the collisions are particle/particle; while in the jet cup method, both particle/particle and particle/wall collisions occur. Examples of attrition testing equipment based on the air jet method are ASTM D575720 and the designs of Forsythe and Hertwig21 and Gwyn22. Examples of attrition testing apparatus based on the jet cup method include the Davison Index (DI)23,24 and jet cup equipment developed by PSRI25 and other labs26. There are several jet cup designs reported in the literature. It is important to note that the dimensions, volume, and configuration of the jet cup all play a role in its performance and that some jet cups – described as “Davison-type” jet cups – are not the same as the jet cup used in the Davison Index test method practiced by Grace. 

We are often asked how jet cup methods compare to the ASTM D5757 air jet method. Attrition resistance measured by ASTM D5757 (an air jet method) and by Grace’s DI test (a jet cup method) give comparable results in that lower values on each scale are more attrition resistant. It is not possible to directly correlate the scales of the two tests since they are different apparatus, but they tend to give values of the same order of magnitude. In round robin testing with an external lab, Grace found that those two methods gave the same ranking regarding catalyst attrition27. Similarly, a recent paper by Kukade, et. al.28 found that the performance ranking of catalysts did not vary between ASTM D5757, a cylindrical jet cup, and a conical jet cup. While the methods give similar rankings, it is important to remember that their scales differ; so, testing with the same method is necessary for an “apples-to-apples” comparison between catalysts. 

For third-party testing of catalyst systems, we are aware of two organizations that conduct this testing: CPERI (Chemical Process & Energy Resources Institute) and PSRI (Particulate Solid Research Inc.) 

BRYAN DINKEL [Marathon Petroleum Corporation (MPC)] 

MPC uses a jet cup analysis to evaluate catalyst attrition. Testing follows the original Grace Davison procedure and generates a Davison Index (DI) value. MPC uses the jet cup analysis as a pass/fail test. Fresh catalyst samples possessing a DI value of less than 10 pass the test, while samples showing DI values greater than 20 fail. FCC e-cat (equilibrium catalyst) samples have DI values below 2, while fresh catalyst samples typically have DI values between 3 and 10. Samples that fail the attrition test are flagged for further testing. Commercially, we have encountered opacity problems when catalyst samples consistently fail the attrition test.  

Each supplier has different equipment and/or conditions for testing, which makes it difficult to compare results from the different suppliers. ASTM D32.02 is developing a formal test procedure for the jet cup (WK34893), which may lead to a standard test.  

As members of Particulate Solid Research Inc. (PSRI), we are aware of some of the deficiencies of the traditional jet cup test identified through their research efforts, which have included CFD modeling and high-speed video with a Plexiglas apparatus. PSRI used this information to develop its own testing equipment which can be used for membership testing or on a contract basis with individual companies. Additional information on this test equipment can be found in the article entitled “Jet Cup Attrition Test”29. In addition to PSRI, CPERI and Cat Testing Labs Inc. are other independent testing labs that can provide subjective testing when comparing catalyst options from multiple suppliers.  

MELISSA CLOUGH (BASF Corporation)  

There are many test methods available to evaluate attrition resistance, each with pros and cons. The best test method will meet the following criteria: It 1) is able to match the unit’s attrition profile, either predominantly abrasion or fracture, 2) is standardized and repeatable so that data are comparable, and 3) matches the FCCU’s overall material loss over the test period. The most common methods include the ASTM Air Jet, DI Jet Cup, and PSRI Conical Jet Cup. The Air Jet is the only ASTM-certified test method and thus represents the most standardized and repeatable test available. Air Jet also is predominantly abrasion (breakage into little particles from the surface of a catalyst particle) as opposed to fracture (e.g., breakage in half). An assessment of over a dozen refinery FCCU attrition mechanisms via population balance modeling indicates that the majority of attrition happening in the unit is via abrasion. Thus, Air Jet is both standardized and represents the majority of the attrition mechanism that can be seen in an FCCU. Air Jet can also mimic material loss of an FCCU over the test period. The DI Jet Cup method is predominantly fracture. Further, the mass loss is heavily hindered due to stagnation of material in the bottom of the cylindrical cup. Therefore, the majority of the catalyst is not being tested during the one-hour duration. The PSRI Conical Jet Cup improved on this by changing the shape of the holding vessel, which removes the stagnation problem. Third-parties available for this type of testing include PSRI in Chicago and CPERI in Greece. 

BHARGAVA (KBC Advanced Technologies, Inc.) 

In summary, it is all about turbine blade deposition in the expander on the flue gas. First, I will talk about the causes, catalyst loading being the number one and the only cause for most of the turbine blade deposition. The catalyst loading on the flue gas inlet is what determines the amount of deposition. From a mechanical standpoint, the blade deposition increases as the performance of a third-stage separator goes down – for whatever reason – or the loss in regenerator cyclone efficiencies. From a catalyst perspective, if you are trying to put in a new catalyst, that catalyst will have different attrition properties. Evidence of mechanical damage in the unit that results in more catalyst fines will have the same effect. Increasing fresh catalyst additions will produce the same result, because fresh catalyst contains more fines. Also, as you start processing resid or heavy metal gasoil and your sodium and vanadium levels go up, the catalyst will start to get stickier and will create eutectic mixtures at certain temperatures, resulting in more catalyst sticking on the blades. From an operational standpoint, if you increase flue gas rates when you increase air rates, the amount of catalyst loss through the cyclones will increase and result in more deposition. 

At some sites, we found additional steam being injected upstream of the expander, a practice that is done for different reasons. One reason could be to maintain temperature and pressure on the inlet of the expander in order to keep up the efficiencies, but that is not a recommended solution because it actually makes the situation worse on the turbo expander. So, those were the causes. 

What is mitigation? It is important to understand the cause of the depositions. You want to make sure you analyze the deposits. If you do not have that luxury, then track the 20-microns or less size range, the catalyst’s physical properties, and monitor the e-cat metals. From a mechanical perspective, you want to do a routine monitoring of the bearing temperatures and vibration, and then check the process temperatures and pressures to identify if you are having a problem. One option to help reduce the turbine blade deposition is to run close to the design temperature and pressure. 

Consequences: These are obvious consequences. You lose power generation efficiency, but more serious are excessive depositions. If you have deposition on the blade and have uneven breaking off the deposits, the expander can become unbalanced, which goes back to the previous point about monitoring vibrations for early detection. How do people remove the deposits? First, you need to monitor the deposits via a viewport using a strobe light. This light will allow you to quickly detect the buildup of deposits. This monitoring is more important because if the deposit just builds up, it will be easier to remove the deposits. You can even do that with an online riser walnut shell cleaning. Some people have resorted to thermal cycling by bypassing the expander. Again, that is also a thermal shock to the unit, so we do not recommend it. Finally, if the deposits have been there for a long time, you do not have any choice but to shut down the expander. 

FEDERSPIEL (W.R. Grace & Co.) 

Like what was previously mentioned, some of the hard deposits that may form on the expander blades might consist of fine catalyst particles but may be enriched with other contaminants like sodium, potassium, calcium or chlorides, vanadium, iron, and other trace elements. The theory is that they might form a eutectic that drops out on areas of high velocity and pressure drop. It is a little counterintuitive; but the expander, of course, is one such place. Further, if you build up the deposit to a sufficient thickness where it starts to cause friction on the machine, those deposits can then be enriched with the expander metallurgy. And if they get hot enough, those deposits could then sinter and be very hard to remove. 

So, one of the key takeaways is to send in the deposit for analysis. We can do chemical analysis and look at what material is actually there. There are more advanced techniques as well, like microprobe or line scanning, which can tell us where the different elements are lining up in that deposit or how they are formed over time. Even SEM (scanning electron microscopy) and X-ray diffraction can look at not just the shape of the deposit but can also identify crystal structure. 

PUI-NANG LIN [Flint Hill Resources (FHR)] 

Another area we found very important for the expander fouling is the quality of your expander cooling and impingement steam. That is another source of sodium that can accelerate the blade deposits. 

ALEXIS SHACKLEFORD (BASF Corporation) 

Another element you should look for is sulfur. Sulfur is often enriched in these deposits. Occasionally, you may also see evidence of refractory in these deposits. Please see BASF’s response in the Answer Book that shows you what these deposits look like compared to e-cat and compared to fines samples.  

MELIKE YERSIZ (Chevron U.S.A., Inc.) 

How often do you recommend inspecting the blades with the strobe lights? 

BHARGAVA (KBC Advanced Technologies, Inc.) 

If you have a viewport in a strobe light, then you should be routinely monitoring the blades once every couple of weeks, depending on the severity of the situation. You can then increase or reduce the frequency, depending on how your deposition goes. 

FEDERSPIEL (W.R. Grace & Co.) 

When I worked at Hovensa, we would do it weekly. We often found out that staying ahead of the problem was a lot easier than trying to address it after it became an issue. So, if you have the facilities there that look to the viewport or take the pictures, it is probably easiest to set it up on a regular basis – like on Saturday – just to have the Inspection guys go out, take the pictures, and monitor it. 

PHILLIP NICCUM (KP Engineering, LP) 

I want to make a reference to a paper written by David Linden with Ingersoll Rand back in the 1980s. The topic of the paper was the composition of these deposits. It is a seminal work on this subject, and I recommend it. In the paper is a reference to tables of these eutectic mixtures, and I have some of them. It is pages and pages of eutectic mixtures with many elements from FCC with which you are very familiar. It is quite a useful reference.30 

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

Calcium and iron also play into those eutectics as well and can have a dramatic effect. As far as the sodium goes, make sure your desalter is being checked for its effectiveness, because a dramatic shift in its performance could really result in a much larger change in the expander operation. 

SANJAY BHARGAVA (KBC Advanced Technologies) 

Deposit formation is usually linked to catalyst depositing on the turbine blades. The deposits are mostly a function of catalyst loading of the inlet flue gas. An increase in catalyst loading could be due to several factors, including performance of the third-stage separator, loss in cyclone efficiency, change in catalyst attrition properties, excess fines in fresh catalyst, an increase in fresh catalyst additions, and/or an increase in flue gas rates due to higher air rates.  

In addition, KBC has seen locations where steam is introduced between the regenerator outlet and tunable diode laser spectroscopy third-stage separator. The addition of steam is used to control the temperature within the guidelines of the expander. The use of steam and the added “humidity” increase the deposition potential of the catalyst on the blades. Further, high levels of sodium and vanadium on equilibrium catalyst can also form a sticky, eutectic mixture which would tend to stick to the blades more easily and lead to accelerated deposition rates. 

Rigorous monitoring of catalyst balance and fines generation – specifically, sub-20-micron particles – helps us understand the deposition rate on the blades. Minimizing deviations from design pressure and temperature also helps reduce the rate of deposition. Monitoring catalyst physical properties and Na/V (sodium/vanadium) to ensure good cyclone efficiencies is as important. Early or regular action to correct the deposition problem by routine monitoring of bearing temperatures and vibration, along with process temperature and pressure, will provide the required information for corrective course of action. 

Deposits can be monitored via a view port with a strobe light to allow weekly photographing of the blades. This information can then be used to establish the frequency of regular online cleaning of the blades. Cleaning can be done with rice, walnut shells, or a less preferred method of thermal cycling of the turbine by partial bypassing of the flue gas to cool down the blades. If the deposits are allowed to build up over extended time periods, online cleaning is not recommended as chunks of deposits are likely to be removed non-uniformly, which can unbalance the blades and result in excessive vibration. 

MICHAEL FEDERSPIEL (W.R. Grace & Co.) 

The paper, “Catalyst Deposition in FCCU Power Recovery Systems” by David H. Linden31 at Ingersoll-Rand, refers to four types of deposits that occur in flue gas lines, equipment, and power recovery turbines. The first type (A) are powdery catalyst deposits that cling to surfaces in the flue gas train. The second type (B) occurs when those powdery catalyst deposits get wet and then harden after drying out. Upon analysis, these deposits appear similar in chemical makeup to equilibrium catalyst or third-stage separator fines. 

The third type (C) of deposit is made up of very small catalyst particles, along with elevated levels of alkali metals (sodium, potassium, and calcium), chlorides, vanadium, and iron, as well as other trace contaminants from unique or challenging feedstocks. It is theorized that these contaminants form a low melting point eutectic. These deposits are very hard and are often found in areas of high gas velocity and pressure drop, and the expander is just such a place. If these deposits form along the expander blade tips to sufficient thickness to cause rubbing, the friction will increase the temperature enough to sinter the deposit into a new type (D) of deposit which has increased metals content from the expander metallurgy.  

By reducing catalyst traffic to the flue gas and preventing condensation, these types of deposits can be minimized. Keeping the regenerator cyclones and third-stage separator mechanically healthy and operating within design specifications will help. Ensuring catalyst coolers are leak-free will prevent boiler feed water chemicals from further contaminating catalyst and eliminate an attrition source. Running the expander at design conditions can keep the flow path through the expander fully developed, thus mitigating eddy currents and dead spaces. Suppressing the contaminant metals (particularly those that accumulate on the surface of the catalyst particle and then abrade off) or using a catalyst with a low attrition tendency can help to reduce blade depositions. There are also several options for expander coatings which can reduce or prevent the accumulation of deposits. 

Monitoring deposits during the run can help a refiner be prepared for work that needs to be done during the next available outage. Taking pictures through view ports and vibration monitoring are two common methods used to quantify and track deposit formation.  

Once formed, deposits can cause loss of expander efficiency and threaten the mechanical integrity of the machine, as well as force a shutdown due to high vibrations. While these deposits can be removed through the injection of walnut shells or rice, a regular program aimed at preventing the formation of deposits is generally more effective at achieving longer run lengths than attempting to fix a vibration issue after it develops. Varying the size of the media can help reach the different places these deposits form. Other methods include thermal shocking or thermal cycling of the expander, which takes advantage of the different thermal expansion coefficients of the deposits and the turbine metallurgy to release accumulated deposits from the surface of the blades.  

ALEX MANNION (BASF Corporation) 

Below are deposit examples from a cyclone and expander blade. Typically, these deposits are rich in elements such as Fe (iron), Ca, Na, Mg and S. These elements can act as a “glue,” binding catalyst fines together. 

Factors that could lead to deposit formation include high catalyst attrition, high catalyst losses from cyclones, poor water quality being used from steam injection, water condensation and precipitation at cold spots, and high metals content in the FCC feed. 

Several measures can be taken to avoid deposits from laying down on the blades. To minimize fines generation, an attrition-resistant catalyst can be used, and fresh catalyst additions should be minimized. Also, all steam ROs (restriction orifices) should be in place, and excess velocities should be avoided. High-quality water should always be used while minimizing water injection, when possible. “Cold spots” in the overhead line or expander should be avoided. Crude desalting additives can be used to minimize metals (e.g., Ca) in the feed. Finally, effective soot blowing of CO boiler tubes can mitigate deposit formation as well. 

Deposits can lead to expander vibrations and blade erosion, potentially leading to catastrophic equipment failure. If deposits have begun to form, regular walnut shell cleaning can be conducted and thermal spalling if required.