During the 2017 American Fuel and Petrochemical Manufacturers Operations & Process Technology Summit (formerly Q&A and Technology Forum), Oct. 2-4, 2017, in Austin, Tex., US domestic and international refiners addressed fluid catalytic cracking (FCC) operations, with an extended focus on topics of innovation, catalysts, mechanical reliability, and meeting environmental regulations.
This annual meeting addresses real problems and issues refiners face in their plants and provides an opportunity for members to sort through potential solutions in a discussion with panelists and other attendees.
This is the final installment based on edited transcripts from the 2017 event. Part 1 in the series (OGJ, Sept. 3, 2018, p. 70) highlighted discussion surrounding hydroprocessing operations. The second installment addressed gasoline processes (OGJ, Oct. 1, 2018, p. 46).
The session included a six-person panel comprised of industry experts from refining companies and other technology specialists responding to selected questions and then engaging attendees in discussion of the relevant issues (see accompanying box).
The only disclaimer for panelists and attendees was that they discuss their own experiences, their own views, and the views of their companies. What has worked for them in their plants or refineries might not be applicable to every situation, but it can provide sound guidelines for what would work to address specific issues.
The panel
Sanjay Bhargava, principal consultant-senior advisor, downstream operations, KBC Advanced Technologies Inc.
Bryan Dinkel, FCC technologist, Marathon Petroleum Corp.
Michael Federspiel, chief FCC technologist, W.R. Grace & Co.
Darin Foote, FCC operations superintendent, Laurel refinery, CHS Inc.
Alex Maller, senior process engineer, TechnipFMC Process Technology
Steve Tragesser, chief technology engineer, FCC & Alkylation, KBR Inc.
The respondents
Paul Diddams, Johnson Matthey PLC
Dave Ferguson, Tracerco Ltd.
Pui-Nang Lin, Flint Hills Resources LLC
Bob Ludolph, Shell Global Solutions (US) Inc.
Phillip Niccum, KP Engineering LP
Alexis Shackleford, BASF Corp.
Melike Yersiz, Chevron USA Inc.
Marathon Petroleum Corp. is executing the South Texas Asset Repositioning (STAR) program at its now 571,000-b/d Galveston Bay refinery, which aims to further integrate Marathon’s former Texas City, Tex., refinery into the adjacent Galveston Bay site to improve efficiency and reliability by increasing residual oil processing capabilities, upgrading the crude unit, and integrating associated logistics. Slated for full commissioning in 2022, the STAR program will result in a fully integrated 585,000-b/d Galveston Bay refining complex. Photo from Marathon.
Innovation
What recent innovations have you made to instrumentation that can be applied to FCC units?
Foote: I’ll just share some of what we’ve done that has impacted and improved safety, reliability, maintainability, and operability in the last 10 years on our cat units. One innovation has been adding vortex and ultrasonic flow meters in slurry service. I think we’ve installed six in our main-column bottoms circuits. The advantage of these flow meters is that they don’t require any flush oil addition. We’ve seen good reliability and accuracy with them. We also found that the ultrasonic meters have a better turndown than, say, the vortex meters, but we’ve yet to inspect them after a 5-year run. I suspect that they’ll look just fine, because they’re still reading reliably. The second innovation we applied is smart-accelerated valve positions. Having this feature has improved the controllability of our operations. Position readback, advanced diagnostics, and partial stroking functions that we already discussed are the types of smart valve positions which are nice to have on control valves.
Next is electronic remote sensor or pressure differential (dP) transmitters. Traditionally, for pressure differential and reactor level, we’ve installed the dP transmitter above the highest tap and then run the impulse lines down to lower taps. Sometimes those impulse lines can be 100 ft long; some systems are longer. This application takes a different approach. It basically installs two pressure transmitters that are factory matched and electronically linked. You put a pressure transmitter at your two taps, and those two are linked, which then provides your electronic remote sensor. We recently implemented the application on our reactor head and stripper project that will be installed this spring, and we’ve dramatically reduced the amount of impulse lines running along the structure. We’re excited to see the outcome. I believe there is another refiner who has done a similar application, too. I think those impulse lines really make me nervous when you’re using small-bore piping. If one of them comes loose, it could result in a bad situation. So, reducing small-bore piping is a big deal to me.
Regarding modern hydraulic power units for FCC slide valves, we’ve talked about the benefits from a safety perspective. We’ve also seen a control benefit from the control systems on two of our units that we’ve modernized. The controllability of critical parameters around slide valves has really improved and enabled us to operate our full-burn unit—in compliance for carbon monoxide (CO)—with a highly hydrotreated feed. It’s also worth mentioning an automated ultrasonic-testing (UT) inspection technique called automated ultrasonic testing (AUT). Your inspection group may refer to it as such. Basically, it’s just an automated UT external inspection of pressure vessels that are online. It’s limited to vessels that are 350° F. or less, but we’ve been able to identify anomalies. It’s really cut down our pressure-vessel discovery work during turnaround and, in terms of value, generated a big benefit to us in the last 10 years. We just don’t have very many pressure vessel “Aha!” moments during turnaround anymore.
Maller: As far as innovations in instrumentation, our standard on the reactor regenerator remains the purged-pressure taps. So, nothing has changed there, and we don’t really see anything new coming. The remote sensor mentioned by Mr. Foote is very interesting and could warrant further investigation.
For level instruments, we’ve seen guided-wave, radar-type level instruments becoming more popular, particularly for interface level measuring. Nuclear-type level instruments have been applied in a main fractionator bottom service, and that subject will be talked about later in another question. Nuclear-type level instruments have also been applied to catalyst hoppers. It seems like it should be feasible to apply them for the reactor-regen level, but I’m not aware of anywhere it’s been done successfully yet.
Lastly, I agree with Darin’s point about the ultrasonic-flow instruments applied in slurry service. I’ve seen those working well, and it seems to provide a good deal of improvement in terms of reliability.
Bhargava: In addition to what the panel members just said, we’ve focused more on the data quality. From the perspective of monitoring the FCC, we think having good mass-balance closures is most important. Good mass-balance closure not only helps us monitor the unit; but when we do step tests or test runs, we’re able to find small changes in the operation of the unit that help us identify the most profitable operation. We’ve installed Coriolis meters to get better mass-balance closures. We’ve also started recommending and installing tunable diode-laser spectroscopy meters for flue-gas analysis. These meters allow you to improve the flue-gas analysis composition detection into ppb, if needed. We’ve been looking for CO in very small levels, because knowing these levels helps improve the flue-gas analysis.
From an equipment-care and conditioning perspective, we’re installing more and more wireless vibration monitors for compressors and pumps in the FCCs. And finally, Yokogawa Electric Corp. has a list of its EJX transmitters for dP measurements. These transmitters are much more accurate than what you have in service today.
Ferguson: Sanjay, where are you installing the Coriolis meters?
Bhargava: The Coriolis meters are being installed on the external boundary of the FCC to allow us to look at the feed meters, gasoline meters, and diesel meters to get the mass-balance closures. These Coriolis meters are expensive, so you’re better off installing them across the mass-balance boundary.
Diddams: I have a question for the audience. Is anyone using online feed analyzers these days? How many people are using a near-infrared (NIR), nuclear magnetic resonance (NMR), or some other online feed analyzer? Is anyone doing that? None? Interesting. Okay, thanks.
Catalyst
We are reformulating our FCC unit catalyst. What are your best practices to postaudit the catalyst change?
Federspiel: Evaluating an FCC catalyst reformulation isn’t something you’re able to do overnight. It’s a long commitment to postaudit 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 postaudit effectively. You’ll 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 should be at least 20 days. This timeframe might be a fast reformulation effort to some units that go to an average age of 100+ days. During that time, how many people in the audience draw straight lines on the distributed control system (DCS) for 6 months in a row? I’m not going to pull up the polling app, but I guess the response is zero.
Using chronological plots by themselves isn’t an effective way to evaluate catalyst reformulation, so we must introduce some other methods. Using crossplots is one way you plot process variables. Instead of just against time, you plot them against other process variables. Further, you can use advanced-cracking (ACE) testing or pilot-plant testing. Modeling can be used as well.
There are complications you’ll have to consider when you’re planning for reformulation and the postaudit of it; for example, feedstock availability. Ideally, you’d 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 the economics that force you to change your operating mode, you’ll have to consider that scenario, too. If you move from gasoline mode to try to produce propylene to take advantage of that market, the postaudit will clearly be more difficult. 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’re 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 expensive and will certainly complicate the catalyst trial. If you don’t plan for and risk-mitigate it properly, you’ll end up cutting the trial short, which will be costly for you.
Bhargava: Catalyst change is one of my favorite topics, so it’s appropriate that I answer this question. We’ve conducted catalyst evaluations for several clients; and not only have we been effective at executing these base catalyst changes, but we’ve also found improvements for selecting the right catalysts for additives. We evaluated ZSM-5 additives from different vendors and have been successful at differentiating ZSM-5 that comes from 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. What we do is use simulation models. We install a test-run program to do a test run every 2 weeks during the catalyst transition, and we develop 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 6 months. While the catalyst is changing out, your operating conditions and 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. Don’t rely on the vendor estimates because they can be very different from what you see on the unit. You absolutely want to employ an independent third-party company that either does benchmarking or uses a pilot plant to give you yield estimates on your feedstock. It must be done on your feedstock by an independent party to give you yield estimates at different cat oils and different reactor operating temperatures (ROT). Look for metal-tolerance tests.
KBC has seven tests required to be done for each catalyst if you’re going to do the full catalyst evaluation. Once you get those results, you can’t 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 must be normalized so they’ll 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’re seeking. Then, do a postaudit and compare it with the catalyst results.
Dinkel: I’ll echo that we like to look at multiple methods for confirmation; but within Marathon, we have our own circulating riser unit. That’s where we heavily rely on looking at both the catalyst assessments for changeout, as well as the postaudit data. As Mike was saying, we can 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 6 months down the road.
Niccum: 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’ll 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’m not a fan of using pilot plants to test it, because you can’t be certain of the testing protocol itself. The catalyst may be better in the pilot plant than it will be in your commercial unit. So, I believe in benchmarking of the actual data and collection of reliable data on a routine basis, as well as watching the trial from the beginning. If it starts to go south, correct it before it gets bad.
Ludolph: As part of the preplanning Mike outlined, don’t 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’re changing out, to check if you’ll be able to appreciate the projected yield structures. Just make that a part of your preplan.
Mechanical reliability
Do you know of factors that are likely to lead to deposit formation on power-recovery turbine blades? Is there anything that can be done to prevent these deposits from laying down on the blades? Once the deposits have been formed, what are the consequences, and is there any way to remove the deposits online?
Bhargava: In summary, it’s all about turbine-blade deposition in the expander on the flue gas. First, I’ll 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 regenerator cyclone efficiencies drop. From a catalyst perspective, if you’re 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 gas oil and your sodium and vanadium levels go up, the catalyst will start to get stickier and 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 to keep up the efficiencies, but that isn’t a recommended solution because it makes the situation worse on the turbo expander. So, those were the causes.
What is the mitigation? It’s important to understand the cause of the depositions. You want to make sure you analyze the deposits. If you don’t have that luxury, then track the 20-µm-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’re having a problem. One option to help reduce the turbine-blade deposition is to run close to the design temperature and pressure.
Consequences? You lose power-generation efficiency, but more serious is excessive depositions. If you have deposition on the blade and have uneven breaking of 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’s also a thermal shock to the unit, so we don’t recommend it. Finally, if the deposits have been there for a long time, you don’t have any choice but to shut down the expander.
Federspiel: 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’s 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 can 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 present. 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 scanning electron microscopy and X-ray diffraction can look at not just the shape of the deposit but can also identify crystal structure.
Lin: Another area we found very important for the expander fouling is the quality of your expander cooling and impingement steam. That’s another source of sodium that can accelerate the blade deposits.
Shackleford: 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.
Yersiz: How often do you recommend inspecting the blades with the strobe lights?
Bhargava: 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: 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’s 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.
Niccum: I want to refer to a paper written by David Linden with Ingersoll Rand back in the 1980s.1 The topic of the paper was the composition of these deposits. It’s a seminal work on this subject, and I recommend it. In the paper is a reference to tables of these eutectic mixtures; it’s pages and pages of eutectic mixtures with many elements from FCC with which you’re very familiar. It’s quite a useful reference.
Ludolph: Calcium and iron 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.
Environmental
In order to meet the pending International Convention for the Prevention of Pollution from Ships/International Maritime Organization (MARPOL/IMO) 0.5 % sulfur fuel oil standards in 2020, what options do you have available to implement within FCC units to improve slurry quality, adjust yield, or find alternate dispositions, both within the overall facility and as a saleable product?
Bhargava: In the absence of doing configurational studies in changing crude, the options you have for reducing sulfur and fuel oil are very limited. The IMO standards of 0.5 wt % will make slurry a discounted product because the slurry sulfur will most likely be molten into 0.5 %. Further, because of the ash content, you’ll need to have a bigger discount, and you may not even be able to put the slurry back into fuel oil anymore.
So, what are the potential solutions within the FCC boundary? One way to solve the problem is to reduce slurry yields to hopefully get to a net-zero slurry product, which is impossible. You do want to reduce the slurry, however. One of the places where you can find a home for slurry is the coker unit. If you have an FCC and a coker and you put the slurry back into a coker, you’ll create an infinite recycle of the unconverted products. The only way that will work is if you have a partial slurry recycle or if you have a coker and a hydrotreater in between the coker gas oil and the FCC. This arrangement will help you break the cycle because it will reduce the amount of slurry you make and reduce the polynuclear aromatic (PNA) buildup.
If you don’t have a coker, the cheaper option is to recycle the slurry into the FCC riser and destroy slurry that way. You’ll still end up having a net product which will be of very poor quality. The last option is to do catalyst reformulation with a pore-sized active matrix or additives to reduce your slurry make on a once-through basis.
The only dispositions for slurry are very limited. One is carbon-black feedstock. The spec on carbon-black feedstock is 4 wt % on sulfur. You should be able to make that feedstock. The only word of caution is that the ash content there is tight: 0.5 wt %; so, you might have to upgrade your filtration facilities to meet the ash limit. The other place people have now started putting slurry is road asphalt. Those are the only two options.
Foote: To meet the IMO standard on one of our operating units, our model suggests that we need to get down to about 0.1 wt % feed sulfur to meet the 0.5 wt % in the slurry. You also need to meet the IMO standard for ash content, and this can be challenging. Often, if we could somehow control how our cyclones work, we probably wouldn’t be here. So, that’s not really the handle we have outside of just the general sound design of the cyclones. But if you have two run-down tanks, consider running down to one tank, letting it settle, and then running down to the other tank. In this way, you’d be using two tanks for settling out the ash, which will make your loaded slurry a little better.
If reducing sulfur isn’t an option, consider slurry recycle. In the riser, the slurry in the coker yields 30 wt % coke on feed vs. slurry recycled to the riser, which makes about 15 wt % coke on feed. So, I think that the FCC yield slate would be better with slurry recycle than when putting slurry in the coker.
Bottoms-cracking additive is a low-risk, high-value proposition. There aren’t very many drawbacks to it. If it pays out big by uplifting the difference between the cost of slurry and the additive, especially after the IMO standard comes out, then uplifting to light-cycle oil (LCO) is huge. So, if you think it might work, try it. Also, denitrification performance on gas-oil hydrotreater or cat-feed hydrotreater catalyst is important. Nitrogen has a worse conversion effect than sulfur.
Next, look at crude purchases to ensure that your linear program (LP) is calibrated to reflect the effect of gas, oil, and nitrogen on cat yields. Make sure you’re debiting those crudes that have high nitrogen in them.
Niccum: A vacuum distillation column can be used for upgrading slurry oil from the FCC unit by removing light cycle and heavy cycle to reduce the net slurry or yield. As you know, vacuum conditions are required to keep the temperatures down to a level that won’t terminally degrade the oils. That is why the vacuum tower is required.
References
1. Linden, D.H., “Catalyst Deposition in FCCU Power Recovery Systems,” Katalistiks Fluid Catalytic Cracking Symposium, Venice, May 12-13, 1986.