Question 92: What experience is there with cracking whole crudes in the FCC? What are the considerations for new crude sources?
KOEBEL (Grace Catalysts Technologies)
This is a question that comes up relatively frequently and is an area where Grace has done extensive R&D work and publication. I will summarize a longer answer that appears in the Answer Book. So please refer to that response, as well as to some of the publications Grace has in the trade magazines. In order to be able to help customers with the thought of running whole tight oil to the riser, we ran a sample of Bakken crude straight to our Davison circulating riser pilot plant over a moderate Z/M catalyst. Our data for the feed sample is shown on the slide and compared to a published assay of Bakken. We felt it was relatively representative of a typical Bakken crude.
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To summarize, the data behaved much as you would expect. There was a fair amount of 650°F minus in the feedstock, so it made significant amount of gasoline. You can see that the cracking yield was on the order of 65% gasoline. A lot of that was the gasoline inherent in the crude initially; it had just come along for the ride. There was not much conversion of those molecules that were present in the feed. As a result, the overall FCC gasoline octane is moderately low. The feed actually did convert very well, although it made very low coke and low bottoms yield.
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These are the specifics of the FCC gasoline from those products. You can see that the RON is much lower than 80, even significantly lower than you would typically give an FCC naphtha. It did have the normal response to reactor temperature that you would expect with an increasing RON as a function of reactor temperature. But still, the overall magnitude of the octane was very, very low.
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On the other hand, the light cycle oil was a much better quality than you would get from a typical FCC light cycle oil. This, again, is partially due to the material that was inherent in the feed. But overall, the quality of the LCO was not really a function of reactor temperature. It was more a function of conversion level and how much of the material in the LCO you were cracking up the tower while leaving the paraffinic molecules in the LCO. The diesel index was on the order of 35 to 45; whereas with a typical FCC light cycle oil, the diesel index was usually in the single digits. So, the quality of the light cycle oil you get from processing shale oil with the riser is much better than what you normally get with FCC light cycle oil.
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The question also asked about some of the other considerations for doing this. One of the considerations is that, with the variability of the tight oil quality, from time to time you may get unusual contaminant metals in the FCC feed. This slide shows one example of a unit that was routinely running Bakken crude to the riser. Over the course of a 10-day period, a spike of sodium hit the unit hard. This spike cost them about 10 points in activity on their circulating inventory. Often, the refinery is not set up to desalt the FCC feed directly. So, if you have a raw crude coming to the riser, you may see this happen, either with sodium or other contaminant metals.
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BULL (Valero Energy Corporation)
At Valero, we process desalted pre-flash crude in several of our FCC units. We desalt the crude or remove as many of the contaminants as possible. We also may pre-flash the crude to take off the light gas and naphtha, which is shown in the drawing on the slide. We run it through a desalter to try and take out contaminants. It then goes into the pre-flash tower to take off any light gas and some of the light naphtha, and then take the bottoms of that to the FCC unit. We have done this at several refineries. The pre-flash crude is then sent directly to the FCC feed drawing process in the unit.
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In general, the naphtha boiling range material goes straight through, and then we can see a proportional increase in the gasoline FCC naphtha range. The naphtha also has a cat cooling effect without the cat cooler, so you must take that into account when processing crude directly to the FCC. Some of the diesel boiling range material passes through, but we do see some of the heavier components of the diesel crack. The remaining portion of the pre-flash crude is your typical FCC feed at that point. So, the net effects are a reduction in overall liquid yield on the unit and the shift in selectivity to more naphtha and diesel range material.
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Two primary considerations for investigating new crude sources for processing directly in the FCC are the contaminant levels that Jeff referred to earlier, as well as the effect of the light material and the impact that will have on your delta coke and heat balance.
SOLLY ISMAIL (BASF Corporation)
All of these tight oils are very low in aromatics components. They typically have shorter length hydrocarbons which, when mixed with vacuum resid, can create salting out or compatibility issues. One way to address the compatibility issues is to extend the analysis and include the peripheral unit; i.e., the furfural unit in a lube plant. We know that in a furfural unit the paraffins are being separated from the naphthenes and aromatics. These paraffins are then sent for dewaxing to make base stock for lube oil while the extract, which is rich in aromatics, and some naphthenes become an orphan stream of the refinery. In this case, I am assuming that refinery does not make grease with the extract. Because this furfural extract stream is rich in aromatics, it is difficult to crack and makes lots of coke, which has always been a problem. Therefore, FCC operators are reluctant to accept furfural extract for processing in their units.
Nevertheless, refineries do process lube extracts (in low concentrations) in the FCC and would generally like to process more or higher levels in their feed to the FCC.
As just mentioned, because of the high tendency for furfural extract to make coke in the regen, refiners have been having a tough time blending it away in the FCC feed. However, when a refiner is processing large amounts of tight oils, the situation is completely different. In the scenario when tight oils are being processed, the regenerators have the problem of running at low dense bed temperatures. I think when processing high concentrations of tight oils in the FCC unit, increasing the levels of furfural extract with tight oils might be a blessing. Not only will the furfural extract provide an increase in the level of coke in the FCC regen, but it should help improve the compatibility issues as this stream contains large hydrocarbon molecules that can keep the vacuum resid in the solution.
JEFFREY BULL (Valero Energy Corporation)
At Valero, we have processed desalted pre-flashed crude in several of our FCC units. We desalt the crude to remove as many contaminants as possible, and we pre-flash the crude to take off the light gas and light naphtha. The pre-flashed crude is then sent directly to the FCC feed drum and processed in the unit. In general, the naphtha boiling range material goes straight through the FCC and, in effect, blends with the traditional FCC-derived naphtha. The naphtha also has a “cat cooling” effect without the cat cooler. Some of the diesel boiling range material cracks and some of the naphtha material passes through the FCC reactor. The remaining portion of the pre-flashed crude is typical FCC feed. The net effect is a reduction in overall liquid volume yield and a shift in selectivity to more naphtha and diesel range material. The two primary considerations for looking at new crude sources for processing directly in the FCC are contaminant levels (metals, sodium, calcium, etc.) and the amount of light material that essentially takes a free ride through the FCC and has a significant impact on the heat balance.
JEFF KOEBEL (Grace Catalysts Technologies)
The introduction of novel drilling technologies has resulted in large amounts of oil from shale becoming available in North America. While fluid catalytic cracking is typically done to reduce the molecular weight of the heavy fractions of crude oil (such as vacuum gas oil and atmospheric tower bottoms), in some cases refiners are charging whole shale oil as a fraction of their FCC feed.5 Also, whole crude oil has been charged to FCC units when gas oil feed is not available due to maintenance on other units in the refinery6 and to produce a low-sulfur synthetic crude7 .
As a model case for understanding the cracking of whole crude oil in the FCC and the effect of process conditions on yields, a straight-run shale oil was processed in the Grace DCR™ pilot plant at three riser outlet temperatures: 970°F, 935°F, and 900°F. The whole crude oil was a light sweet Bakken crude with a degrees API gravity of 42. The properties of the crude were similar to those given in a publically published assay8 . Table 1 presents a comparison of the properties of the whole crude used by Grace and the publically available assay data. Additionally, the straight-run Bakken sample was distilled into a 430°F minus gasoline cut and a 430°F to 650°F LCO cut. The properties of these cuts were measured. Gasoline from the straight-run Bakken was highly paraffinic and had low octane numbers [a G-Con® RON software of 61 and MON (motor octane number) of 58]. The LCO fraction had an aniline point of 156°F and an API gravity of 37.6, resulting in a diesel index of 59.9.
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The catalyst used in the experiments was a high matrix FCC catalyst, deactivated metalsfree using a CPS (cyclic propylene steaming)-type protocol. The properties of the deactivated catalyst are given in Table 2. For the three different reactor outlet temperatures, plots of the catalyst-to-oil (C/O) ratio, dry gas, gasoline, LCO, bottoms, and coke yields versus conversion are shown in Figure 1. As expected, lowering reactor temperature increases the amount of LCO produced. As seen in the graphs, cracking straight-run shale oil produces little coke and bottoms. At the same conversion level, lowering reactor temperature results in slightly more gasoline yield (due to increased C/O), which is consistent with prior Grace work.
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Plots of gasoline olefins, isoparaffins and RON and MON estimated via G-Con software are shown in Figure 2. Cracking straight-run Bakken shale oil produces a low-quality gasoline with research octane less than 80 and motor octane less than 70.
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At constant conversion, increasing reactor temperature results in more gasoline olefins and higher research octane number. Diesel quality is of great interest to refiners. Syncrude produced in the DCR™ runs was distilled to recover the 430°F to 650°F LCO fraction. Aniline point and API gravity of the LCO were then measured to allow calculation of the diesel index, a measure of LCO quality [Diesel Index = (aniline point x API Gravity)/100]. Figure 3 presents data for LCO yield and LCO quality as a function of conversion. As seen in the data, increasing conversion lowers LCO quality as a result of increased cracking of the LCO range paraffins to lighter hydrocarbons. Similar to prior Grace work14, LCO quality follows LCO yield and did not appear to be influenced by reactor temperature at constant conversion. Diesel index values of the LCO produced by cracking whole shale oil were significantly higher than values obtained with typical VGO feeds.
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As seen in the results from this study, widely varying ratios of products and product quality can be obtained by changing process conditions. Information from pilot studies such as this one helps refiners to determine the optimum processing setup to maximize yields of desired products. The ability of the DCR to produce sufficient liquid product for properties testing assisted greatly in the measurement of LCO quality.
In addition to yields and operating conditions, contaminants and the impact they have on circulating catalyst inventory should be taken into consideration. A catalyst flushing strategy may be required to ensure that contaminants stay at reasonable levels in circulating inventory. For example, one refiner experienced high levels of sodium on e-cat while processing high amounts of whole crude. The sodium more than doubled and catalyst activity dropped more than 10 numbers, both of which impacted unit performance (Figure 3). The unit utilized purchased e-cat to help flush the sodium from circulating inventory.
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PAUL FEARNSIDE (Nalco Champion Energy Services)
The largest concern will be with the main fractionator performance. Issues with direct cracking of undesalted crudes revolve around the increased chloride loading and the resultant increase potential for ammonium chloride salting. Care must be taken to insure the upper section delta P does not increase to the point that daily operations are curtailed. Intermittent slumping of the tower while water-washing and the use of salt dispersant chemistries have worked well.
CHRIS CLAESEN (Nalco Champion Energy Services)
The increased metals content in the feed can lead to increased catalyst deactivation, coke formation, and hydrogen generation which can significantly reduce the FCC profitability. While the metals content should be kept as low as possible by pre-treatment in the tank farm and desalters, the effect of Ni and V can be significantly reduced with the use of a metal passivator program that is injected in the FCC feed.
Question 93: Which key process indicators (KPIs) are tracked in a typical FCC unit health monitoring program, and what is the frequency these indicators are measured?
INKIM (PETROTRIN)
There are several KPIs that are tracked in the monitoring of FCC. Liquidy yields is one parameter that is monitored daily to detect any changes in equipment and catalyst performance. The BS&W (base sediment and water) in the main column bottoms is checked daily as well to monitor the catalyst carryover from the reactor into the main column. The heat and material balance should be done at least weekly, if not daily, to detect changes in the catalyst and equipment performance and to detect any meter errors. In the lean gas stream, the hydrogen-to-methane ratio is monitored weekly as it indicates higher metals content in the feed.
Another KPI that we track at least weekly is the e-cat properties to detect any feed contaminant issues. There are other KPIs that we monitor, and these are mentioned in my Answer Book response.
LARSON (KBC Advanced Technologies, Inc.)
In all cases, it is important to establish the baselines. Then what you are really trying to do is track your standard deviation because you need to know the cause and effect versus normal deviation. The cat cracker conversion might vary as much as 1%. So, looking at absolute values, as opposed to relative deviation, is really important. You get some of the KPIs directly; others are calculated from lab data or rigorous modeling. It is important to differentiate so you know the accuracy of the values you are using and how much they will change. We have typically lumped things into operating things or operating instruction KPIs, and then we also look at planning because planning will give you targets to target. Planning is target to target. Boy! That is oxymoronic.
Planning Targets: You need to hit those. Make sure your lab and operating systems are set up to work in conjunction with operational moves. We will typically look at reactor temperature which will give an indication of octane in conversion. We also look at the debutanized octane material monitoring what the RVP (Reid Vapor Pressure) of the material is; because as RVP changes, you will be changing octane. Refiners do not check their feed quality as often as we would expect. Operators are often chasing product quality when, in reality, there was, a burp in the feed quality, and it was missed until it is three days down the road.
Key Constraints: Map your constraints if you are operating up against them. Know your air blower capacity limit, whether it is the horsepower, blower discharge, or wet gas compressor horsepower. Is it a DP (differential pressure)? Many units are now running a low DP on slide valves encroaching nearer the shutdown trip points, so monitor your unit constraints very well. On a longer term or monthly basis, monitor your catalyst activity for metals and look at your fines.
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One of the comments is taken this from the last NPRA (National Petrochemical and Refiners Association) Cat Cracking Session. The EPA (Environmental Protection Agency) came into the meeting and talked about the new regulations that will be coming to the FCC flue gas system. Particulate analysis that crosses your cat cracker will be one of the key criteria you will need to map, if you do not have it now. Many places that did not have upsets are not aware of what the particle distribution is on the slurry bottoms. They do not know the particle distribution of the fines caught. They do not know the particle distribution and are asked to do a cyclone analysis. Track your particle distribution on a regular basis, monthly or at least quarterly, so you have a baseline and know when things change.
We would also look at gasoline selectivity, as well as expansion on a unit, to ensure that catalysts are performing appropriately. We look at the LPG to LCO yield to make sure we are getting the correct cracking distribution and proper fractionating. This is an operator guideline. Are we getting good overlaps or gaps? What is the basis of your operation? How well are your operators performing against that basis?
On the utility side, we look at steam production and/or exchange or fouling to determine if we are getting the right value out of the preheat or if the steam generators are on the slurry circuit. These can be tracked daily or weekly. The bottom line is to monitor them frequently enough so that when you see deviation, you will know it is real as opposed to chasing ghosts. There are enough operator and engineer elements that we have to do now between HAZOP (Hazard and Operability) and environmental regulations, so you must have an efficient way to confirm that you are making as much money on your unit as possible.
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MUKESH PATEL (Reliance Industries Limited)
Under KPIs and field properties, are you monitoring total nitrogen or basic nitrogen? As I understand it, basic nitrogen is more important than total nitrogen.
LARSON (KBC Advanced Technologies, Inc.)
I recommend total nitrogen for a couple of reasons: First, as soon as you begin to crack a molecule, you will take that which was in a total system. You will actually create more basic nitrogen just due to the nature of the cracking of the molecule. Second, every refinery I have reviewed in the last 10 years has not really been set up to do a basic analysis. They have a total nitrogen analyzer because of their hydroprocessing units. So, tracking the total nitrogen is just as effective as tracking basic nitrogen and watching the delta impact. It is the relative change away from your normal average feed. I have worked in enough different models, besides the one that KBC is selling, to know that you can use total nitrogen just effectively as basic.
MUKESH PATEL (Reliance Industries Limited)
How do you include the basic nitrogen in your simulation?
LARSON (KBC Advanced Technologies, Inc.)
There are some rules of thumb that apply if you want total to basic. If it is virgin oil, we would apply a basic assumption that one-third of the total nitrogen is basic. If it is cracked, then more than one-third of it is basic. So, it depends upon its feedstock, but there are some rules of thumb that can be applied.
MUKESH PATEL (Reliance Industries Limited)
Many times, we see that the basic nitrogen thumb rule does not apply for various reasons.
LARSON (KBC Advanced Technologies, Inc.)
Nitrogen is a contaminant; so, it always applies, just that what it is in relationship with changes.
KEN BRUNO (Albemarle Corporation)
Please consult the Answer Book as we have provided a very thorough list of recommended Best Practices and KPIs that supplement the suggestions by the panel.
J.W. “BILL” WILSON (BP Products North America Inc.)
Many of these things are quite amenable to being tracked statistically, which helps a lot in actually identifying real deviation or, as Mel said, ‘chasing ghosts’ or chasing random deviations. It is very easy. You can do it with a spreadsheet. We have some specific programs to use, but you can do it about as well with an Excel or other spreadsheet.
WARREN LETZSCH (Technip USA)
I want to make a comment on nitrogen. I think total nitrogen is the best way to go. This is particularly true if you are running residual feeds because small nitrogen compounds in VGO really can affect the catalyst quite a bit. The nitrogen in the larger molecules and the 1050°F plus material really does not seem to be nearly as detrimental. It is typical to run 1500 or 2000 ppm of nitrogen with a residual feedstock. And if you run that with a VGO, you would see a serious deactivation of the catalyst. Total nitrogen is the best way to monitor this impact. I certainly agree with your one-third rule; we have always used that. And for regular VGOs, it is remarkably good.
CATHERINE INKIM (PETROTRIN)
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LARSON (KBC Advanced Technologies, Inc.)
Key process indicators, or KPIs, can be broken down into two broad areas of operations (daily) and performance-based indicators and can be further divided into fluid solids systems, operational, and yield for more detailed analysis.
In all cases, it is important to establish base lines and track standard deviation. There will be cause-and-effect change versus the normal deviation or operation of any FCC, given the dynamics of the control systems and typical various of feed and severity.
Some KPIs are calculated or used from daily logs or lab data while others are obtained through the use of rigorous modeling of the reactor regenerator system, as well as the hydrocarbon recovery section. Many refiners will have daily KPIs used to monitor the unit against the operating instructions from the planning group. Those KPIs that require rigorous heat and mass balance will be completed by the pacesetter refinery once a week, using a routine and defined time to collect stream and process data.
The direct laboratory and operating data used in concert with kinetic modeling enhances the performance monitoring of the unit. The use of the kinetic model can differentiate the impact between catalyst, feed quality, and severity. Utilizing TBP (true boiling point) yields versus as yield data can be enlightening for both Operations and Engineering using more rigorous troubleshooting assistance.
It is possible to optimize cost (laboratory) to reduce duplicate samples without jeopardizing the value and accuracy of much needed weight balance data. In general, samples and analysis have three values: actionable by Operations (deviation from the setpoint target), key mass and heat balance reconciliation necessary for LP updates (economic tools must be kept current), and historical trending. The latter is critical for both hydrocarbon and water systems. The frequency and accuracy of the mass and heat balance is an indication of the value a refiner places on the economics of operation.
A list of some of the typical KPIs are shown below:
• Typical Operation KPIs
– Operating Conditions (daily)
• Conversion, debutanized RON, LPG yield
• Steam usage
Dispersion wt% on feed
Stripping steam rate – Feed Quality (daily)
– Feed Quality (daily)
• Wt% Conradson carbon, 650°F minus, wppm (weight parts per million) nitrogen, wt% sulfur
– Key Constraints (daily)
• Air blower HP (horsepower), wet gas compressor HP, ΔP on slide valves, ΔP on trays that might indicate flooding, turbine efficiency
– Catalyst Properties (monthly)
• Catalyst losses/opacity
– daily
• Metals/activity
• KPIs to Monitor Optimization
– Yields
• Gasoline selectivity
• C3+ volume expansion
• Dry gas yield wt% [feed rate {scfb (standard cubic feet per barrel)}]
• LPG/LCO ratio
– Key Product Qualities
• RVP of gasoline, key separation (overlaps/gaps/light and heavy key component in bottoms and overheads of columns)
– Utilities
• Steam production
• Exchanger fouling
JACK WILCOX (Albemarle Corporation)
In order to monitor equipment reliability, as well as maintain optimum operation, the following KPIs should be tracked because they define the optimum FCCU operation:
On a continuous (daily) basis:
- Operating conditions, including:
a) Riser outlet temperature
b) Combined feed temperature
c) Catalyst circulation rate (catalyst/oil ratio)
- Feed rate and quality, including:
a) Density (API)
b) Boiling range
c) Key contaminant levels such as sulfur, nitrogen, heavy metals, etc.
- Catalyst properties
a) Fresh catalyst addition and withdrawal rates
- Key equipment constraints, including:
a) Main air blower limit
b) Wet gas compressor limit
c) Hydraulic constraints
d) Equipment temperature limitations
e) Key equipment operation, such as cyclone inlet vapor velocities, horsepower recovered (if unit has a PRT)
- Product yields and qualities
a) Product recovery limitations (fractionation, treating)
On a weekly basis:
- Test runs, including:
a) Complete heat and weight balance
b) Feed and product quality properties
c) Circulating catalyst, including both physical and chemical properties
d) Establishment of current limiting constraints
Once per year, and preferably a short time before and after a unit turnaround, a complete equipment and operational evaluation should be performed, including:
- A hydraulic survey, including:
a) A single-pressure gauge pressure survey of the entire reactor/regenerator section from the main column overhead to the flue gas recovery section; based on the single-gauge survey, a complete pressure balance of the reactor/regenerator is developed.
b) A single-gauge pressure survey of the main column and vapor recovery unit
- Thermography survey of the reactor/regenerator vessels
- Utility consumption, including all steam and air supply sources
- Critical equipment performance and limitations are established, including:
a) Cyclone solids and vapor loadings
b) Distributor pressure drops and nozzle exit velocities
c) Major rotating equipment, including the air blower, wet gas compressor, flue gas expander operation
- Establish flowing catalyst fluidization characteristics
Question 94: What methods do you use to determine the condition or remaining life of and regenerator cyclones?
GIM (Technip Stone & Webster)
Proper design of cyclones and cyclone support systems will extend the life of cyclones with proper maintenance. But like the tires on your car, it will need to be replaced towards its end-of-life. Just like checking for remaining treads on your tire, one common way to check the remaining life of your cyclone is to measure and log the thickness of your cyclones for each turnaround from their first installations to last turnaround dates. We can use that thickness in various locations on the cyclones and trend them to predict, before the next turnaround, whether a cyclone will need to possibly be replaced or even how much repair may be required on the next shutdown.
In general, cyclone systems are designed for at least 20 years of life. There are two components that determine the life of cyclones: the condition of the metal and the condition of the refractory. Obviously, steady-state operations with limited upsets and excursions will extend cyclone life. Any excursions beyond the original design temperature will obviously decrease the life of the cyclones.
The adoption of the so-called Life Fraction Approach will determine the allowable stress, which considers the normal operating range of temperatures over which cyclones are operated during the course of a year. Excursions beyond the design temperature reduce the allowable stress used for the design of cyclones. The use of this Life Fraction Approach for determining the allowable stress for design of cyclones will allow operators to analyze the life of the cyclone’s metallurgy by comparing its assumed annual temperature profile versus actual operations at temperatures below the designed temperature, as to life of cyclones. Obviously, operation at temperature above design temperature will reduce the life of cyclones.
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INKIM (PETROTRIN)
The inspection methods we use to determine the condition or remaining life of cyclones are visual, hammer, dye-penetrant, and ultrasonic testing. The results of the inspection and the thicknesses of the cyclones are compared to the original thicknesses and past values. Based on the findings, repairs or renewals are done. If there is significant erosion or thinning of about 40 to 50%, we will recommend replacement.
In the past, we have determined remaining expected life based on creep calculations, as Steve had said. There was an incident in the past where, due to a change in feedstock, we had to operate at abnormally high temperatures above the design temperatures. We consulted the cyclone vendor to get a revised life expectancy. They considered the past operating temperature profile, the original design, and the abnormally high conditions we wanted to run in the creep calculations. Thus, we were able to determine if we needed to shut down before the plant turnaround or whether we could use the cyclones up to the scheduled turnaround.
KEVIN KUNZ [Shell Global Solutions (US) Inc.]
Shell uses much of what the panelists mentioned; and like them, our methods have evolved for evaluating and checking cyclone remaining life. Years ago, Shell used techniques similar to those described by Catherine Inkim of PETROTRIN – visual inspection and hammering for integrity – but not a lot more. Today, though, Shell does more inspection at midlife using liquid penetration, particularly around high-stressed welds. Shell will selectively collect samples for carburization, sulfidation embrittlement, creep, and corrosion behind the refractory. The discovery of cracks often leads to weldability checks and testing for sigma phase in the regenerator and/or carburization and/or sulfidation, and creep in the reactor side. Shell also checks for cyclone erosion but rarely replaces the cyclones for erosion problems unless the cyclones are at the end-of-life. Strict adherence to velocity constraints and the advent of vortex stabilizer technology has improved cyclone system life. Vortex stabilization has dramatically extended cyclone life and minimized its repair. The norm is 15 years with little refractory repair in the cyclone cone.
Unlined portions of diplegs are checked with a mixture of remotely operated cameras, as well as a combination of manual and automated ultrasonic thickness measurement.
Shell selectively uses FEA (finite element analysis) in areas where metal degradation (creep and/or corrosion) is limiting cyclone system life. This guides local repairs and reinforcements rather than when complete cyclone system replacement may not be warranted. In some cases, we assess potential creep damage using actual historical temperature data pulled from the Process Engineering department, including monthly averages and detailed data around upsets.
We have sample plates with combinations of erosion-resistant refractory and metallic anchor materials placed in a number of regenerators. Data from these sample plates will be used to predict, rather than react to, corrosion behind the refractory.
KRISH KRAHEN (Marathon Petroleum Corporation)
Can you comment on techniques used to assess a decrease in weldability of cyclones as they age, and it becomes harder to do crack repairs?
KEVIN KUNZ [Shell Global Solutions (US) Inc.]
We check primarily for sigma phase. Now, the exact test that our mechanical department uses is not a specific ASTM (American Society for Testing and Materials) method. And if sigma phase is present, there is a limit to the amount of sigma phase that can be seen in the cyclones before you begin to run into trouble with weldability repairs. Shell checks for sigma phase primarily by doing in situ liquid penetrant inspection. The amount of cracking is trended TA turnaround) to TA. Based on the trending of number of cracks and the difficulty of doing local repair welds, we remove samples to represent the mix of plate and weld processes used to make the cyclones. These are polished and etched to reveal the extent of sigma and any remaining unconverted ferrite.
LARSON (KBC Advanced Technologies, Inc.)
This situation is not just in the U.S., although this is primarily a U.S. group here. I have seen locations where they cycled the cat cracker a lot more than we might do in the U.S., sometimes bringing down a unit every two years as opposed to every four years. Those up-and-down heating cycles degrade the run length of the unit even though you might think that cyclone should operate well. Cycles of startup and shutdown have caused a real degradation in the performance of those units. You will begin to actually see the barrels start to change and not be quite so round. As you are going in, you should monitor not just the metallurgy itself, but also the barrel to make sure it maintains its shape; because that will become a problem in your ability to maintain catalyst performance, and you will start to see erosion. We know of a company in Japan right now that is working on its 45th cycle on its cyclone. They cyclones were replaced last over 20 years ago.
STEVE GIM (Technip Stone & Webster)
Proper design of cyclones system, including the support system, will extend the life of the cyclones as will proper maintenance; but like tires on your car, they do wear out and need to be replaced at the end of their life. One refinery maintenance manager used to measure and log the thickness of his reactor and regenerator cyclones on each turnaround, from their first installation through the latest turnaround. He also used to measure the refractory thicknesses at various locations on the cyclones. He then could trend refractory loss from turnaround to turnaround and predict, before the next turnaround, whether the cyclones needed to be replaced or even how much repair would be needed. As his FCC tended to run the same rate and essentially the same feeds all of the time, the cyclone degradation over time could be trended.
I would also like to thank our friends at Emtrol for providing some empirical data from their knowledgebase.
Average Life of Cyclones: The average life of regenerator cyclones is about 20 years, when eliminating those systems that have been destroyed in the first operating campaign due to upset conditions and those operated well below design conditions extending life well beyond the norm. In general, cyclone systems are designed for a 20-year life. There are two components that determine the life of the cyclones: the condition of the metal and the condition of the refractory, both of which begin to deteriorate after the initial startup. Steady-state operation, limiting upsets, excursions, and afterburn extend the life of the cyclones. Utilizing a standard approach for determining allowable stress from the ASME code for a given design temperature does not directly address upset conditions that can greatly reduce the life of a cyclone system. For example, a one-hour upset at 1800°F will reduce the life of the cyclones by many years, depending on the actual design temperature used for design (1400°F, 1450°F or 1500°F).
Life Fraction Approach: Adoption of a “Life Fraction” approach for determining the allowable stress, which considers the normal operating range of temperatures that the cyclones are operated over the course of a year, including excursion temperatures (1500°F, 1600°F and even 1800°F), normally reduces the allowable stress used for the design of the cyclones but provides for operation at upset temperatures for a predetermined period of time. Use of a “life fraction” approach for determining the allowable stress for design of the cyclones will allow the refiner to analyze the life of the cyclone metallurgy by comparing the assumed annual temperature profile to the actual operating temperatures. Operation of the cyclones at temperatures below the design temperature adds life to the cyclone system, while operation at temperatures above the design temperature reduces the life.
CATHERINE INKIM (PETROTRIN)
During turnaround, the cyclones are inspected for cracks, erosion and corrosion, and thinning. The inspection methods used are visual, hammer, dye penetrant, and ultrasonic testing. Welds are examined for cracks. The cyclone supports and body are checked internally and externally for breakages, erosion, gouging, holes and thicknesses, lining and hex mesh for erosion/corrosion, and valves for movement.
The results of the inspection of the thicknesses of the cyclones are compared to the past values, as well as the original thickness of the cyclone material. Depending on the past history or severity of the findings at the current inspection, certain parts of the cyclones (for example, diplegs) may be renewed, as well as repairs done to the Resco lining and hex mesh and weld buildups. Some degree of repairs is always anticipated. However, if there is significant erosion/thinning of the order of 40 to 50%, then recommendations are made for replacement.
In the past, due to changing feedstock quality and mechanical issues with the air grid, we were forced to operate the regenerator at higher temperatures than originally designed. At that time, the cyclone vendor was consulted to provide a revised life expectancy for the cyclones if we continued to operate at the new abnormal conditions. Based on the historical operating temperature and the higher new temperatures, they provided the remaining expected life based on creep calculations and thus determined if a shutdown was warranted before the planned turnaround. Similar analyses can be used to determine if a particular operating mode would be economical, even though it may mean replacement of cyclones sooner than original design life.
Question 95: What failure mechanisms have you observed in cyclone or cyclone support systems? What is the typical time to failure?
INKIM (PETROTRIN)
In the history of our unit, there have been no outright failures of cyclones or cyclone supports, just partial failures. In our experience, the major cause of failure in cyclones and cyclone supports has been erosion leading to thinning, cracks, and breakages. We have observed varying severities of erosion in the reactor and regenerator cyclones throughout the history of the unit. In the very early years, failures due to erosion were more frequent, and cyclone repair and replacement were required within five years or less. However, subsequent to the introduction of Resco AA-22 lining, replacement was required less frequently while some repairs were usually done at every turnaround.
Another failure type we have observed in the past is overstressing due to improperly designed cyclone supports. That was as a result of insufficient hanger rod clearance. We have also observed thermal fatigue associated with the use of quench steam to the cyclone outlets. For cyclone and hanger systems, excessive thermal cycling and temperature excursions above the design temperatures can lead to reduced life and subsequent failure.
Our design standard specifies that the minimum total design life must be at least 100,000 hours, which is about 11.4 years, accounting for short-term temperature excursions. We have been able to operate for lengths longer than 11.4 years based on our inspection. For our reactor, we have managed to operate with the cyclones for 29 years without replacement, but we did have to do minor repairs to them. Those cyclones were changed out as part of an upgrade because of the remaining life of the reactor at that time. The current cyclones in the reactor are now 17 years, and we have done some partial replacements on those. The regenerator cyclones also had longer run-lengths in the more recent past, with the last total replacements coming at 14- and 17- year intervals. The current cyclones in the regenerator are now over 12 years.
GIM (Technip Stone & Webster)
We have seen cyclones that have been torn apart during a campaign due to excessive high vapor velocities and catalyst velocity. We have also observed cyclones which operated for only a few years due to poor cyclone design. Additionally, failures in support systems are usually correlated with degradation of cyclones. Feedstock change from sweet to high sulfur content can affect some of the older carbon steel straps and hangers. Depending on the operation and cyclone design, the time to failure could be short; meaning, one campaign, part of another, or extended over a number of campaigns.
The biggest effect of cyclone life appears to be the amount of time the cyclone operates within the original design parameters. Multiple shutdowns with temperature excursions will obviously shorten the life of cyclones and their supports. Also, the high velocity will wear on the refractor protection and eventually on the cyclone metal itself. Cyclones running within design parameters can expect to operate between 16 and 20 years. Those which often run above the design parameters and have frequent shutdowns will obviously have a shorter number of campaigns.
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ROBERT “BOB” LUDOLPH [Shell Global Solutions (US) Inc.]
We found that in regenerator service, cracking in the welds is by far more common for systems that are properly designed for thermal expansion. Older systems have shown creep. The key to design is allowance for upset conditions that you anticipate during the campaigns. In the reactor service, distress, distortion, and even cracking has been observed if coke builds up and prevents free thermal expansion of the system. Key to success is to design for minimum or no sliding parts. In designs where relative movement of adjacent pieces cannot be eliminated, the design accommodates a “breaking force” for the coke. In some cases, materials are used which have shown that coke adhesion is not as strong.
Where galling is a concern, stainless steel with Stellite® surfacing has been used. For carbon steel cyclones that operate with moderate sulfur in feed, carburization and sulfidation take place. In a number of cases, the hanger itself is not necessarily the weak link; but rather, the attachment to the cyclone body. For maximum life, Shell uses a mix of carbon steel and chrome-molybdenum alloys. Carbon steel is economical and easy to repair, but the chrome-molybdenum will extend the service life, especially in high stress applications.
J.W. “BILL” WILSON (BP Products North America Inc.)
You have a few options. From my experience, unfortunately they are not particularly universal. From the standpoint of time to failure, if the failing problem is related to erosion, you can usually develop a tracking mechanism using cumulative velocities over time. We actually use velocity to the cyclone. But as I said, the answer of how far that curve can go seems to be unique to each unit; so, you have to use unit’s maintenance history to figure out your actual limits.
Bob talked about coke buildup. What can also happen is that you can get a coke ratcheting effect where the coke can build up causing you to shut down the unit. Coke and the steel have different expansion coefficients, so there is usually a little space for coke to build up again. So gradually over time, this coke deposition just pulls part the system. That is another reason why repeated shutdowns and startups are not good.
I would like to discourage the idea of there being a defined maximum life to the cyclone. For years, I have been hearing people say it is 20 years. There are currently lots of cyclones older than 20 years that are working fine, so it is really matter of the condition of the cyclone and the metallurgy. For regenerator cyclones, sigma formation that usually shows up is from an inability to actually repair them. You can have thermal stresses that cause distortion to a cyclone. These stresses are usually related to improperly designed hanger systems or other support systems. Other reasons are repeated operation well above where it should operate or repeated thermal cyclings of the cyclone: getting hotter and colder, hotter and colder.
CATHERINE INKIM (PETROTRIN)
In the history of our unit, there has been no outright failure of all the cyclones, or all the cyclone supports, but there have been several partial failures. In our experience, the major cause of failure in cyclones and cyclone supports has been erosion leading to thinning, gouging, deformation, holes, cracks, and breakages. The cyclones are usually inspected at four-year intervals, and the cyclones are assessed by visual, hammer, dye penetrant, and ultrasonic testing.
We have observed varying severity of erosion in reactor and regenerator cyclones throughout the history of the unit. In the very early years, failures due to erosion were more frequent and cyclone repair/replacement was required within five years or less. Subsequent to the introduction of Resco AA-22 lining, replacement was required less frequently, while some repairs are usually done at every turnaround for both regenerator and reactor cyclones. The majority of repairs include repairs to Resco liner and hex mesh, removal and renewal of cracked welds, weld buildup on areas of eroded metal, and partial replacement of dustbowls and/or diplegs as necessary.
Other types of failures observed in the past include:
• Overstressing due to improperly designed cyclone supports: On one occasion, there were several cracks on the gas outlet tube weld attachment to the plenum and the hanger rods and stiffening bars showed signs of distortion and cracking. Reappraisal of the design by the fabricators indicated that there was insufficient hanger rod clearance.
• Thermal fatigue associated with the use of quench steam/water (both intentional/unintentional) to cyclone outlets and to the plenum resulted in several cracks in the gas outlet tube weld and severe distortion and failure of the plenum.
For cyclone and hanger systems, excessive thermal cycling and temperature excursions above design temperatures can also lead to reduced life and subsequent failure. In one instance, we had to replace cyclone supports prematurely owing to the expiration date of the creep life being before the next scheduled turnaround.
For the reactor, we have managed to operate with cyclones for 29 years without replacement and with only minor repairs at each turnaround before the entire reactor was replaced as part of an upgrade, in addition to the vessel reaching its end of life. The current reactor cyclones, which were installed at that upgrade, have been in service for approximately 17 years with partial (dustbowl) replacements done at the last turnaround and full cyclone replacement recommended for the next turnaround.
The regenerator cyclones have also had longer run-lengths in the more recent past, the last two total replacements coming at 14-year and 17-year intervals. The current regenerator cyclones have been installed for 12 years thus far.
Generally, we have found that some degree of weld buildup is anticipated at every turnaround (four-year cycle). Some breakages in cyclone supports and renewals in diplegs dust bowls are anticipated every eight years in the first instance after replacement and then every four years. While our design standard specifies that the minimum total design life must be 100,000 hours with accountability for short-term temperature excursions accounted for, we have managed to get longer run lengths based on inspection of our cyclones.
STEVE GIM (Technip Stone & Webster)
Observations: We have seen cyclones that have been torn apart during a campaign due to operation at very high vapor and catalyst velocity, and we have seen cyclones operating for only two years due to a poor cyclone design. Failures in support systems are usually correlated with the degradation of the cyclone. High internal reactor vapor and catalyst velocity can erode the cyclone supports over time. Feedstock change from sweet to higher sulfur content can affect older carbon steel straps and hangers.
Time to Failure
Depending on the operation and the cyclone design, the “Time to Failure” could be short – one campaign or a portion of it) or extend over a number of campaigns. The biggest effect on cyclone life appears to be the amount of time it operates within its design parameters. Multiple shutdowns or temperature excursions can shorten the life of both the cyclones and their cyclone supports. High and very high velocities wear on the refractory protection, and eventually on the cyclone metal itself, shortens lifespan. Cyclones that run within their design parameters can be expected to operate for 16 to 20 years. Cyclones that run often above their design parameters or have frequent shutdown of temperature excursions probably last for two campaigns and maybe a third with risk of failure during the campaign.
Support System is a Key
The support system is a key component of the cyclone system and needs to be considered when purchasing a cyclone system. A properly designed support system will adequately accommodate the differential expansion between the hot internals and the relatively cool vessel, which is further exasperated in larger diameter vessels. Furthermore, maximizing the load supported directly by the vessel minimizes the loads imposed into the plenum, which further extends the life of the cyclone system.
A poorly designed support system imposes additional stresses into the cyclones and/or plenum, which will not only greatly reduce the live of the cyclone system but also result in significantly greater maintenance costs and turnaround time.
A few tips for proper support systems:
1. With no bracing, the cyclones will dance and be fatigued.
2. Lateral bracings that are not free to expand from the shell.
3. Add pivot points with slots if bracings are mounted to shell.
4. Set in midpoint at the startup to move freely
CHRIS STEVES (Norton Engineering)
Failures due to erosion are very common in FCC cyclone systems. Cyclone age, flue gas velocities, and repair techniques all play into the erosion failure time. A new, properly designed regenerator cyclone will last a five year run without failure. As long as good inspections are done, repairs are identified, and the correct repairs are made, the cyclones can last 20 to 30 years without failure. Pay close attention to the catalyst losses during the run, especially if the cyclone velocities are not within the design guidelines of the OEM (original equipment manufacturer).
Case Study: A 50,000 bpd FCC unit has air rate was increased by adding a smaller air blower. The flue gas rate increased 14%, with a corresponding increase in regenerator cyclone velocity. Within two and half years, the cyclone barrels and transition ducts started to wear away. Catalyst loses increased from 1. to 20 7 tons per day (tpd) within a month. One month later, the losses were over 40 tpd. When the regenerator was first opened, a trickle valve was seen on the regenerator floor, and this was quickly assumed to be the problem. Only after repeated discussions was the decision made to build the scaffolding needed to properly inspect the cyclone barrels and transition ducts. Many holes, ranging in size from pinholes to holes large enough to fit an arm through, were found. These cyclones were 20 years old and had never had this extensive amount of damage in prior runs. Subsequent review of inspection records revealed that the repairs completed during the prior outage may have been less than adequate. A combination of age, prior substandard repairs, and increased cyclone velocities all played a role in the eventual failure mechanism.
Take into account the cyclone age, prior repairs, and current and anticipated cyclone velocity when evaluating the cyclone damage. All three aspects are part of the failure time. Start the paperwork for new cyclones when the refractory hex mesh telltale signs start showing, and pay closer attention to the catalyst losses when the cyclone velocities go above the OEM’s recommended max.
Question 96: What are the typical causes of dipleg plugging/fouling? How can the plugging/fouling be avoided? What is the experience with clearing diplegs online?
KOEBEL (Grace Catalysts Technologies)
]I am going to take the question in a few parts. I will cover the reactor side first. In the reactor side, dipleg plugging will generally be due to coke formation that can be subdivided into two categories: the coke formation that occurs either internal to the cyclone or externally. On the gas outlet tube of the cyclone, you will see the stereotypical coke formation on the backside of the gas outlet tube, perhaps from incomplete feed vaporization. It could also be a result of running a very low conversion operation for some time and leaving crackable material still in the slurry. You end up with a sheet of coke that forms on the back of the gas outlet tubes. Then, during a thermal cycle, that sheet of coke will fall off to the bottom of the dipleg; and since it is bigger than the dipleg diameter, it blocks the flow of the dipleg.
Alternatively, you can get coke formation external to the disengager at the diplegs. In these cases, the coke formation could be due to inadequate purge steam or dome steam. The dipleg valve can become ensconced in coke, as you see in the photograph. Physically, it just will not move. Effectively, you end up with a plugged dipleg. So, the question asks: What are the successes with clearing these types of blockages online? Because these are just physical obstructions, there is little chance that you will be able to fix them with the unit online.
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On the regenerator side, one common method of dipleg plugging is due to low melting point eutectics that you associate with iron and calcium contaminants in FCC catalyst. These contaminants tend to form a crust on the outside diameter of the catalyst particle. As the catalyst circulates through the unit, the fines chip off the outside and become extremely enriched in iron and calcium, which exaggerates the formation of eutectics. The formation of these eutectics is why iron, and calcium close off the porosity of the catalyst and become a problem with conversion. That same phenomena can cause the fines to melt locally, especially in high velocity areas where you can get some friction. Combine that with the temperatures in the regenerator, and you could develop a very solid cement-like deposit. I have seen it in the tops of cyclone diplegs, perhaps where the vortex extends down into the top of the dipleg. You get a disc of this sintered catalyst at the top of the dipleg. Again, those are very cement-like deposits, and they are hard to remove online.
The data on the slide is an example of an analysis of such a deposit. You can see that it has rare earth, as well as all of the other components you associate with FCC catalyst. Relative to the e-cat, the deposit is essentially double the contaminant level of iron and calcium. So, one way to avoid this type of deposit is just to keep iron and calcium under control to the maximum extent possible.
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Finally, one of the other causes of dipleg pluggage is fluidization issues around diplegs, particularly submerged diplegs. If you have diplegs that are submerged in the catalyst bed – either in the reactor or the regenerator – and if you have fluidization issues, either you are losing catalyst, and your average particle size is getting high, or you have a damaged distributor or just poor distribution in general in the bed. You can get localized defluidization around the dipleg opening, which results in the effective blocking of the flow out of the dipleg. You then get catalyst carryover from that type of event. For this type of blockage, you will have some moderate degree of success clearing these online. One option is to lower the reactor or the regenerator level down to below the bottom of the dipleg opening, raise it back up, and then re-seal the dipleg in an attempt to reboot the fluidization of the bed. Some refiners have success doing pressure bump procedures to help with fluidization in these cases.
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KEVIN KUNZ [Shell Global Solutions (US) Inc.]
Shell has had quite a bit of experience with occasional dipleg plugging from either coke formation or catalyst hang-up. I very much agree with a lot of what Jeff Koebel of Grace said. The coke formation in the reactor side is most often found to be caused by the lack of feed vaporization, particularly in resid cat crackers, and typically toward the end of the run when the feed nozzles begin to wear. To counteract that, obviously, good feed distribution and minimum droplet size are required to minimize the time required to vaporize the feed as much as possible. There are not too many FCCUs with cyclones external to the reactor, but Shell does have one. In this case, it is critical to make sure you have good, uniform heat to the diplegs. Checking for cold spots is a good practice.
As Jeff also pointed out, one of the challenges – online cleaning of a coked-up reactor dipleg – is tough to do. However, sometimes increasing riser temperature or decreasing the sour water use has helped improve the feed vaporization, particularly toward the end-of-run. On the regenerator side, catalyst hang-up can have multiple causes. Uncovering the dipleg termination devices or pressure bumps, and even cooldowns, have been successful at times.
Diplegs which contain obstructions that are operating with faulty termination systems are less likely to be successfully cleared online. Keep in mind that when planning and executing pressure bumps, the key is to do it very safely. You must consider everything that could go wrong and make sure that all of your proper safeguards are incorporated to prevent the plant or other unit shutdowns or upsets. This is very critical.
LEE WELLS (LyondellBasell Industries)
In the past, we have had issues with catalyst becoming defluidized in the reactor cyclone diplegs and plugging up the cyclones. Since we have improved our riser termination devices and lowered the catalyst flux in those diplegs, it has gotten even worse. But we have had success doing pressure bumps on the reactor side to free up that catalyst. The trick is recognizing that you are losing the catalyst before you carryover too much of it into your main fractionator.
MICHAEL WARDINSKY (Phillips 66)
One time we plugged up the diplegs in a third-stage separator due to what we believe was a combination of about three factors. The first was the existence of a lot of circulating fines in the inventory due to an attrition source that had developed during a startup. The second was relatively high concentrations of alkaline metals being present in the circulating inventory. We had been using a SOx reduction additive that contained a high level of magnesium. The third factor was that the unit experienced an exotherm due to a reversal scenario. The combination of those three factors led to the formation of a very hard ceramic like deposit in the TSS diplegs. I think we had to use a diamond-tipped drill bit to get them out.
JEFF KOEBEL (Grace Catalysts Technologies)
Dipleg deposits or blockages that lead to excessive catalyst losses happen as a result of a variety of causes. On the reactor side, dipleg plugging or blockages are often the result of coke formation. Coke can form on the internals of the cyclone gas outlet tubes, opposite from the gas inlet duct. This coke formation is generally stable and can build up to a thickness of several inches during normal operation. These sheets of coke can become dislodged during a thermal cycle and fall into the cyclone body where they come to rest at the top of the cyclone dipleg. This physical blockage restricts the flow out of the cyclone. The key to preventing these deposits is to prevent the coke formation in the first place. Make sure that feed is adequately atomized in the riser feed distributors because unvaporized feed can travel up to the top of the riser and lay down as coke in the cyclones. Additionally, a catalyst with adequate active alumina for bottoms cracking is critical to assure proper feed vaporization and pre-cracking, particularly when running a feed with any resid content.
Coke formation can also come in the form of generalized reactor coking throughout the reactor vessel. In this scenario, coke can form on dipleg outlet valves. This coking can restrict the proper movement of these valves, leading to catalyst losses.
Generally speaking, with either of these types of dipleg deposits caused by coke formation, there is little experience with successfully clearing the deposits with the unit operating.
On the regenerator side, dipleg deposits are often the result of the formation of low melting point eutectics. These eutectics occur when specific contaminant metals – such as Fe (iron), Ca (calcium), and Na (sodium) – are elevated. These deposits form a crust on the outside surface of the catalyst that can chip off during normal operation and cause the FCC catalyst fines in the inventory to be very highly enriched with these contaminants. When the fines are circulating in high velocity areas such as the bottom of a cyclone dustbowl, at the top of a cyclone dipleg, or perhaps orifice chamber plates, the combination of the heat from the regenerator and local friction heating is enough to cause the fines to melt and form hard deposits at the point of first contact with the internals. These deposits, when analyzed, will typically show Fe and Ca enrichment about two times the level of contamination in the circulating catalyst inventory. Table 1 is an example of a typical analysis of these deposits compared to e-cat. The deposits also often show that the zeolite is compromised, as if exposed to high temperatures which would not be present according to the unit data. These types of regenerators dipleg deposits are very hard and must often be physically chipped out of the cyclone. They cannot be cleared online.
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Finally, fluidization issues can also cause dipleg blockages. During times of catalyst losses, the FCC catalyst inventory can get very coarse with inadequate fines content. Fluidization issues can develop in a dipleg or around the dipleg openings for submerged diplegs, even if the catalyst circulation is unaffected by the change in the catalyst fluidization characteristics. This can be a problem, particularly after a turnaround when the catalyst inventory is reloaded into the unit. There has been some success with clearing these problems during unit operation. Pressure bumps or draining of the vessel level below the dipleg discharge level are solutions that have been successful in some circumstances and should be attempted as a last resort measure only, as the risk for a significant catalyst loss event is high. These types of blockages are particularly frustrating because they will often disappear during a unit shutdown when the catalyst is deinventoried, leaving behind no evidence as to what caused the blockage in the first place.
CATHERINE INKIM (PETROTRIN)
Though we have not experienced dipleg plugging or fouling, dipleg plugging can be a result of coke, refractory, or catalyst plugging. Typically, the diplegs in the reactor can be plugged by spalled coke after a thermal cycle or by defluidized catalyst in both the reactor and regenerator diplegs. Pressure bumps may help the latter.
CHRIS STEVES (Norton Engineering)
In reactor diplegs, plugs are often caused by coke, catalyst, and refractory. With the decreasing 6 oil market, the push to convert more of the bottom of the barrel is increasing. FCCs share in this effort, and some have been referred to as catalytic cokers. The heavy resids and tars are difficult to atomize and convert. Even if the conversion looks good, these high molecular weight molecules slowly build in all parts of the reactor, especially in areas of low velocity or adjacent to exposed “cold” surfaces. Thermal cycles from startups and shutdowns will eventually spall coke from the reactor internals, and this coke can end up plugging cyclone outlets and diplegs. Prevention of coke buildup is the key to avoiding this type of issue. Maintaining high enough riser temperatures to ensure vaporization of the feeds being processed and ensuring that cold wall reactors are well insulated to prevent coke formation is essential. Anti-coking baffles have successfully been installed in some reactors to allow for a steam purge of low velocity areas (typically above cyclones) so that coke will not form in these areas.
Catalyst can also plug reactor diplegs. Experience has shown the plugging is most frequent on unit restarts and likely from wet catalyst. The catalyst is wet either from oil or from steam/condensate from the restart or shutdown. To prevent wet catalyst from plugging diplegs, use of superheated steam in the stripper during startup, as well as early circulation of hot catalyst from the regenerator to the reactor, can help prevent wet catalyst from plugging diplegs.
In regenerator cyclone diplegs, refractory and defluidized catalyst can lead to dipleg plugging. Proper refractory inspection and repair during unit shutdowns is essential to prevent refractory damage and potential dipleg plugging. Defluidized catalyst “plugging” of diplegs may also occur, especially if the air distributors are damaged and zones of defluidized catalyst exist in the regenerator dense bed.
If dipleg plugging is observed during operation of the FCC unit (as diagnosed by high losses and sampling of the catalyst fines for PSD analysis), some online techniques have been successfully executed. Changes in bed level (for units with submerged diplegs) may help in changing the pressure balance in the cyclone dipleg enough so that the plug is dislodged. Rapid pressure swings on the unit can also be used to dislodge a blockage. With external diplegs, diagnosis of plugged diplegs can be easier (looking for cold spots). The use of vibrators, external heat, or a hot gas injection can be used to clear the blockage.
ROBERT TORGERSON and SYDNEY GARRETT (Gayesco International)
It is possible for diplegs to foul during the startup process if the dipleg is too cold. The resulting condensation can cause the catalyst to bridge and impede catalyst circulation. We have many customers who now require the attachment of removable skin thermocouples to the diplegs to monitor that temperature during startup. Removable thermocouples allow for easy replacement, simplified dipleg maintenance, and easier installation as the attachment hardware can be installed by the dipleg/cyclone manufacture during initial fabrication.
Question 97: What operational or design changes can be employed to address heat balance issues – e.g., catalyst circulation limits, low regenerator temperatures –associated with processing tight oil-derived feeds?
LARSON (KBC Advanced Technologies, Inc.)
This answer will be very similar to what was already discussed about how to treat the resids. The example shown on the slide is a Maya blend, a typical tight oil, and then a tight oil with resid. Again, we are seeing significant reductions in sulfur and Conradson carbon metals and also a much higher hydrogen content. So just by comparison, let us look at this at constant reactor temperature. What we would expect to see is low coke, which will raise our cat oil and pull a lot more heat out of the regenerator. We will get much more liquid yield, which is what is reported by those who are running more and more tight oil in the system.
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The question is: What can we do to operate these units? You are going to have some open capacity. So operationally, what can you do to hydraulically increase the feed to the unit? Given our economics is more feed, more feed, more feed, how far can we push the “more feed”? On the heat balance side, consider first getting all of the diesel out of the feed so you do not have an additional cooling effect with material going through that will not crack very well. Look at processes like deep cutting your VGO. How far are you going into the material? Are you going to 1000°F to 1050°F? Can you go to 1075°F? There are some people who have shut down the vacuum columns and are actually just running pure catalyst from the tight oil into the unit. And, we have already had a question on processing whole crude.
So, there are actions to consider. Again, look at catalyst change. We have been taking recycle out of the riser for years. We might put it back in now as a way to manage the coke balance. You should consider these questions: 1) What is your standpipe flux? and 2) What is the maximum catalyst flux rate that you can tolerate in your standpipe? You will not get to choke flow. You will get to a point where it will not flow any faster. Look at the slide valve opening. Most units have been designed with a slide valve that will run approximately 50 to 60% open under normal operation. Now with tight oil’s higher circulation rates, you might be looking at a slide valve that wants to operate at a much higher percentage opening. That may be your first point. It is not the pressure drop. It is the feeling of running at 80 or 90% open. Resize the slide valve. It may be a very easy modification to get you where you can run much higher cat to oil rates.
Make sure that you have the right pressure balance. Now that you may not have as much air demand, maybe you can change the pressure balance of the unit to raise coke make in the reactor and improve the ∆P across the system. You will have to be aware of additional catalyst erosion if you go to higher pressure drop on your slide valves. Look at the velocity profile in the regenerator itself. Make sure that you can push the unit or that the unit is down to where you can operate in a comfortable range. Again, I look at this as a perspective of something that occurs today and is not happening tomorrow, so what should we do? We might back some steam off the feed nozzles to make a little more additive coke. Perhaps we will lower the stripping steam again to manage it with more coke in the extreme conditions; and I do say ‘extreme.’ Adding torch oil to the regenerator would be an extreme if you are just trying to keep the unit on. We do not recommend that because it substantially chews up the catalyst. Keeping the unit on would be a last resort.
We have heard of people wanting to start the air heater in the bottom of the regenerator to add enough heat to the system. That would be a control issue. There are a lot of issues around the air heater with temperature profiles and the reliability of the air grid that the metallurgy would have to be checked out for a continuous long-term operation. But fundamentally, check your catalyst type. What are you using? What can you change in the catalyst system? What can you do to adjust your feed quality? You add carbon to the system. In the U.S., it has to be moving to a higher and higher percentage of tight oils because we are finding it; and by law, we have to process it. So this would be a new challenge. I think the catalyst manufacturers have done a great job, and they will continue to find ways to give us a catalyst that makes a little more coke and gives us the yields we want.
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GIM (Technip Stone & Webster)
Many of the available crude oil analyses of the tight oil show that the coke precursors in both the gas oil and the resid portions are very low. Those FCCs that were designed for heavy sour crudes may have some detrimental heat balance issues on the converter side, as well as light ends constraints on the gas plant side. I am going to discuss what you can do in terms of both operational and hardware changes. I will not repeat the redundant points that Mel Larson described previously.
First is riser outlet temperature. The obvious solution is to raise the riser outlet temperature not only to heat up the system but also to gain back some of the octane loss resulting from processing paraffinic feeds. This may be problematic because your gas plant will probably already be overloaded with the lighter ends stemming from the processing of tight oil.
Using higher feed preheat, if you have room, will certainly alleviate the higher catalyst circulation rates expected from the low delta coke feeds, such as tight oil.
Step jumps in the conversion level from the improved feed qualities need to be counterbalanced. Raising the reactor vessel pressure will certainly help in terms of increasing the unit delta coke directionally. That would add to the delta coke because of the higher hydrocarbon partial pressure. It will also help alleviate the light ends circuit in the gas plant. Reduction in dispersion steam and the addition of torch oil were already discussed by Mel.
Hardware Changes: I know it is a big-ticket item, but certainly the fired feed preheater could be an option. Again, that is with the installed TIC cost and permitting issues. We spent a great deal of our resources on conducting pilot plant testing of recycle streams in terms of both HCO (Heavy Cycle Oil) and slurry. Being derived from very paraffinic feeds, these high-quality feeds do not have much HCO and slurry yields to begin with. The amount of recycle stream that is available to recycle back to the riser is not there. So that is the problem one.
Second is the coke precursor for these HCO and slurry streams. Even if you are able to recycle them, you will not get as much coke out of these recycle streams as you would have in your conventional FCC feed.
Problem number three: We found that the actual conversion level for these streams – converting it into something other than the cycle oils, dry gas, LPG, gasoline, or coke – was also low. It was quite nonreactive in that sense and is another issue of recycling these streams.
Enlargement of catalyst standpipes and port openings of slide valves may be necessary for catalyst circulation step-jumps, even after making all other operational and hardware changes.
Continuous usage of air heater may also be evaluated, but this may require redesigning the air distribution system to ensure that the increase in the exit tip velocities will not result in unsustainable catalyst attrition.
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PAUL DIDDAMS (Johnson Matthey INTERCAT, Inc.)
One additional suggestion might be to consider oxygen enrichment and reducing your air rate to decrease the heat losses a little bit. Of course, you might also consider running a residue stream in directly with your feed.
KEN BRUNO (Albemarle Corporation)
The panel did an excellent job reviewing the operational and hardware changes. I want to point out that to help manage these changes, it is critical to use the right catalyst. To that end, Albemarle has developed a tight oil family of catalysts, in particular Upgrader T and Amber T. Again, please consult the Answer Book response for more information on the application of these products, as well as all of the commercial experience we have with those products.
LARSON (KBC Advanced Technologies, Inc.)
I want to highlight the need for you to have a good baseline of where you are currently operating. Jeff talked about unit monitoring earlier. When you know that you will be processing a higher percentage of tight oil, to the extent that you can either ratably, put it in or put some material in storage and regularly bring it into the unit. Controllable rates of tight oil will give you the chance to learn what the effects are as opposed to jumping out and saying, “We can handle 50%.” Get yourself a really good baseline in advance; so that when you do make changes, you will have a better educated starting point.
PARAG KANADE (Lummus Technology)
What do you think will be the major challenges in the fractionator and the VRU (vapor recovery unit) section? You mentioned that there will be excess capacity in the compressor and the overhead circuit; but at the same time, the debutanizer stripper bottoms will be loaded. All of these are very heat-integrated with the pumparounds on the reboilers. To utilize the compressor, I think the incentive will be to push more fill through the unit. However, you will also have problems in the stripper debutanizer in the downstream unit. So, my comment is that a small study will be helpful to determine the right throughput to your unit which will avoid the need for a major revamp.
LARSON (KBC Advanced Technologies, Inc.)
The answer is that on a hydraulic basis, you will have to find your pinch point. You would like to be able to analyze it with kinetic modeling and seeing where your pinch points may come up. Also, I appreciate the heat balance comment. I think some of our panelists have actually had experience with this issue. As you process more tight oils, you physically cannot run the riser top temperature; i.e., the heat going to the main column is less because you cannot tolerate 90% plus conversion in the unit. You have a different balance when you run more tight oil than we have been running in the last 20 years. So, there will be different pinch points.
MICHAEL WARDINSKY (Phillips 66)
I cringe every time I hear people talk about using torch oil to maintain regenerator temperature above some minimum for an extended period of time. Make sure you understand the environmental and process safety implications of trying to run long-term on torch oil. In addition, the catalyst will suffer accelerated attrition and activity loss. There are environmental concerns about firing torch oil. Any time you put torch oil in the regenerator, your CO emissions will go up. In some units, I think you will be challenged to stay under a 500-ppm limit. You also have process safety issues that deal with the consequences of the blower tripping. If there is no interlock on your torch oil supply system, you will be injecting a lot of fuel into your regenerator and could have a real problem. So, make sure you understand those consequences before you use torch oil outside of startup.
LARSON (KBC Advanced Technologies, Inc.)
Just as a follow-up, my comment on that was generally not regarding refineries in the U.S. We have people outside the U.S. who are, in fact, using torch oil and who do not have the same EPA and environmental constraints, or even some of the other safety issues you mentioned. I totally agree with what you are saying from our position here in the U.S. The window of operation is much tighter here than it is in other countries.
MEL LARSON (KBC Advanced Technologies, Inc.)
For the last 20 years, the industry has been driven by tighter gasoline and diesel sulfur specifications, as well as increased demands for propylene. The catalyst manufacturers and licensors have done a great job making improvements that focus on maximizing the profit from these operations.
Now with a greater percentage of tight oil in the refinery, what are the changes? The tight oil might be similar to a severely hydrotreated virgin gas oil FCC feed. The typical shift from typical WTI (West Texas Intermediate) to tight oil (not all tight oils are equal) will be as a result of:
• Increased hydrogen content;
• Lower contaminants, such as Conradson carbon, nitrogen, and sulfur; and/or,
• Low aromatic content.
As previously mentioned, the diesel content of the FCC feed should be reduced as much as possible since light boiling feed will reduce regenerator temperature. One point: Diesel quality from the tight oil has greater value as diesel than as FCC feed. Secondly, consider substantially increasing the HVGO/resid cutpoint or checking the quality of the overflash from the vacuum column as a potential feed to the unit.
As feed quality improves, the regenerator bed temperatures reduce, and catalyst circulation rates go up to a “limit”. There are a number of steps recommended to define the real limits in processing tight oils:
1. Define a base line of the circulation rate. This step is crucial for understanding the current or anticipated changes with tight oil. The base line should be consistent with typical or routine operation. Included in this step would be a single-gauge pressure survey to aid in system definition and base line.
2. Identify the limiting issue, i.e., the flux in the standpipe, the residence time in the stripper or regenerator, the slide valve (SV) position(s), or ΔP across the SV. From a flux rate perspective, there are a number of units operating successfully at mass flux rates in the standpipe well over 300 lbs/sec/ft2 (pounds per second per square foot). Historically, FCCs used to operate successfully with lower regenerator bed temperatures in the range of 1200°F to 1250°F and residual carbon on catalyst at levels of as high as 0.30 wt%.
Operational considerations are similar to those discussed previously:
• Consider different feed sources to add carbon, such as vacuum overflash and a Slip-Strip™ of vacuum residua.
• Change the pressure balance.
– Move from partial to total CO combustion in the bed, not just in the regenerator proper. Add (more) promoter to the regenerator.
• Change the catalyst.
• Recycle a cycle oil to add carbon.
• Increase reactor temperature.
• Use air heater continuously.
• Add external heat oil direct into the regenerator.
Hardware changes to consider for accommodating higher catalyst flux rates would include, but not be limited to, the size of the standpipe and slide valve and capacity expansion, given that the air blower is less constrained.
STEVE GIM (Technip Stone & Webster)
Cracking of paraffinic FCC feed derived from tight oil crude behaves similarly to severely hydrotreated feeds or cat feeds from other sweet crudes like West Texas Intermediate. As many of the available crude assays show, these crudes do not have many coke precursors in the gas oil or even in resid fractions. FCCs designed for sour heavy feeds may face heat balance constraints in the converter (reactor/regenerator) and light ends circuit constraints in the gas plant. Sometimes, too much of a good thing can be a bad thing.
Operational Changes
Higher reactor outlet temperature may be necessary not only to heat up the overall system, but also to make up the gasoline octane loss stemming from the paraffinic feed. This may not be easy, however, given the fact that the lighter feed would be already taxing for the light products circuit in the gas plant. Higher catalyst activity accompanied by more matrix content will help increase the catalytic coke.
Talking about catalyst, for partial-burn units, the addition rate of CO promoter can be increased to preferentially raise the regenerator bed temperature.
Higher feed pre-heat (if there is room in the pre-heat train) can help alleviate the expected increase in the catalyst circulation rate and also counterbalance the step jump-in conversion due to improvement in the feedstock qualities and higher operating severity I just described.
Raising the reactor pressure will directionally increase the delta coke due to the higher hydrocarbon partial pressure. It will also help alleviate the increased burden in the lighter ends of the recovery section.
I do not like this idea as much, but lowering feed dispersion can help increase the delta coke. There will be some debits in selectivity.
I also do not like the idea of injecting torch oil into regenerator, but that is always an option.
There is a possibility of a compatibility issue of highly paraffinic tight oil and asphaltenes. It could form two phases and may have to be injected separately into the riser.
Hardware Changes
A big-ticket item, in terms of cost and permitting issue, is to install a fire feed pre-heater to counteract the lower system-wide Btu (British thermal unit) posed by the lighter fresh feed.
Recycling HCO and slurry streams (preferably upper section, otherwise they will be entrained to regenerator) into stripper may also be an option. We have done some pilot tests of these recycles from light feeds. There are a few not-so-obvious issues. Issue 1: Quantities of these recycle streams are lower than those from heavy feeds since conversion levels are expected to be higher. Issue 2: Coke precursor level is low for even for these bottoms. Issue 3: Conversion level (i.e., converting into something other than the cycle oils such dry gas, LPG, or gasoline) is low. Depending on the starting point of delta coke for the operation without the recycles, only recycling the heaviest cut may be a delta coke additive.
Enlargement of catalyst standpipes and port openings of slide valves may be necessary if catalyst circulation step-jumps even after making all other operational and hardware changes.
Continuous usage of air heater may also be evaluated, but this may require redesigning the air distribution system to ensure that the increase in the exit tip velocities will not result in unsustainable catalyst attrition.
RAUL ARRIAGA and KEN BRUNO (Albemarle Corporation)
Tight oil (TO)-derived feeds, in general, show high API gravity and a high amount of paraffins compared to traditional VGOs being processed in FCCUs. On the other hand, TOs tend to come with higher amounts of some metals, particularly iron and calcium. This combination of properties makes TOs more crackable than traditional VGOs due to their molecular distribution, but it also results in a lower contribution towards delta coke, lower regenerator temperature, and increased catalyst circulation provided the iron and calcium are low. On the other hand, if the metals (usually iron and/or calcium) are high, TOs are conducive to increased deactivation rates, especially pore mouth blocking, which tends to increase catalyst mass transfer limitations and FCCU slurry yields. The increased slurry production can push a refiner to reduce feed rate in order to stay within limits, resulting in economic losses. To overcome mass transfer limitations and optimize delta coke, high accessibility catalysts such as AMBER™ and UPGRADER™ have been developed and proven successful for tight oil applications.
Based on the above, operational changes that can be employed to address heat balance issues include increasing activity via higher catalyst addition rates and HCO or slurry recycling. Another option is the processing of bi-modal types of feed; meaning that as a refiner increases the amount of TOs in the feed, the refiner could compensate for the TOs by lowering the API gravity of the rest of the material in the blend. However, care needs to be taken regarding the compatibility of the different components or asphaltene precipitation may occur.
It is not recommended to reduce stripping residence time as valuable product is burned in the regenerator. It is also not recommended to use torch oil to increase regenerator bed temperature due to the possibility of drastically higher catalyst deactivation rates and lower e-cat activity, which would create a negative contribution to delta coke and likely result in increased catalyst addition.
Question 98: What catalyst changes can be made to minimize the negative effects of low delta coke that result from processing increased amounts of tight oil-derived FCC feed?
KOEBEL (Grace Catalysts Technologies)
The schematic on the slide shows the representation of the coke yield and the coke balance from the FCC. Of course, the total overall weight percent coke yield is set by heat balance, but the sources of the coke vary significantly from one feed to the next. Everyone talked thoroughly about how the coke precursors are just not there in these lighter feeds. The contaminant metals will be drastically lower, so your FCC catalyst will be called upon to provide a much larger percentage of the overall coke yield than it does in a normal operation. That can call on the unit to run a much higher catalyst circulation rate than it is physically able to do, so certainly you change the catalyst as warranted in these instances.
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The next slide is a quick pilot plant representation of what happens in these cases. The darker blue represents a base VGO feed and the lighter blue: a shale oil type of feed. I will just pick a number here and say 2.5% coke yield in the pilot plant. In order to do that, we need about 5.5 cat-to-oil, which results in about 74% conversion in this operation on this catalyst. If we do nothing to the FCC catalyst and run the lighter feed, you can see that the required cat-to-oil to generate even that same 2.5% coke yield jumps up to 8%. So a full 50% increase in the catalyst circulation rate is required to keep the unit operating. We are talking about having to actually increase the coke yield, not hold it constant. That coke yield results in a little over 76% conversion. Clearly, a catalyst reformulation to a higher activity is in order here.
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BULL (Valero Energy Corporation)
I am probably going to commit sacrilege here, from a catalyst vendor standpoint; but in many cases, a shift to a less-coke-selective catalyst can help process these increased amounts of tight oil-derived feeds. A catalyst with less zeolite and a higher quantity of non-active, non-coke-selective matrix can help you maintain a minimum regenerator temperature. We have actually done this at one or two sites.
JOE McLEAN (BASF Corporation)
I will go back to the previous question that we had before the break about the benefits of catalyst porosity. One thing you can do is reduce the porosity to reverse the delta coke benefits. We have a number of customers who have gone back to more old-style, lower porosity catalysts that are less coke-selective but just as active. These catalysts work quite well in this application. Because of the increase in conversion and, specifically, a big boost in LPG, we have seen at least one client take out ZSM-5 completely and still maintain the same light olefin yields that were in the previous operation with a fair amount of ZSM-5. So, in that case, the side benefit was the ability to save on the additive cost.
KEN BRUNO (Albemarle Corporation)
We agree, Jeff. There are cases where a lower coke selectivity is beneficial. But related to accessibility or the diffusion character with this kind of feed, quite often there is overcracking or secondary reactions that you do not want. So, it remains critical to have the right accessibility and porosity to minimize those secondary reactions.
WARREN LETZSCH (Technip USA)
I want to remind people that the pilot plant data is quite accurate. But when you start increasing catalyst circulation rate like this, chances are that the stripper performance may well deteriorate. You will have a much shorter residence time; and basically, you may end up pulling a lot more hydrocarbons through. It will be different for every unit, depending upon where you are operating and the type of equipment you have in it. I think if you have what I would call conventional a disk-and-donut type of stripper, then these types of circulation rates will almost guarantee that you will need to have much higher hydrogen on cokes because the flux rate will be very, very high. So, every situation is really different.
JEFF KOEBEL (Grace Catalysts Technologies)
Delta coke is the difference between carbon on spent catalyst as it leaves the stripper and carbon on regenerated catalyst. Delta coke is the primary variable that determines the regenerator bed temperature.
There are four primary sources of coke in the FCC process. They are: feed Conradson carbon, contaminant metals, stripping coke, and the catalytic coke produced by the FCC catalyst. The sum total of these four components adds up to the total coke yield in the FCC. Since the FCC heat balance determines the overall weight percent coke yield in the FCC process, a reduction in the contribution of one of these four coke sources must typically be offset by an increase in one of the other sources. For example, let us consider an extreme case, which is represented in Figure 1, of a unit that experiences a change in feedstock from resid feed to a light shale oil feed. When the unit shifts from heavy or resid feed to lighter feed, the total weight percent coke requirement does not necessarily change; however, the contribution of coke from each source will shift. Assuming stripping coke stays relatively constant, the feed contributes less to the required coke (feed carbon and contaminant); thus, the catalyst must make up the difference.
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That means that the FCC catalyst will contribute a larger percentage of the overall heat required for the process. If the catalyst is not active enough, the catalyst circulation rate must increase so that conversion, and thus the coke yield from the catalyst, can increase to satisfy the FCC heat balance. This will lower the delta coke and the regenerator temperature. For a set riser outlet temperature, the lighter feed will require much higher catalyst circulation rates to satisfy the FCC heat balance. If the FCC catalyst section cannot physically circulate enough catalyst, it will be necessary to either reduce the unit charge rate or the reaction severity to stay within the FCC catalyst circulation limit.
In the pilot plant example below (Figure 2), an FCC unit operating on standard VGO is contemplating a move to lighter shale oil feed type. The base case catalytic coke of 2.5 wt% requires a cat/oil ratio of about 5.5 and results in 74% conversion. In order to keep the 2.5% coke yield with the lighter shale oil feed, a cat/oil ratio of over 8.0 is necessary with an increase in conversion to about 77%. Most FCC units are not capable of this dramatic increase in the catalyst circulation rate, and the catalyst circulation hydraulics will likely limit the unit severity or throughput.
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In this same example, we consider a catalyst reformulation to a more active catalyst with a different coke to conversion relationship (Figure 3). Here, Catalyst A is applied, and a much more modest cat/oil ratio of 6.5 is necessary to satisfy the coke yield. This is due to the inherent catalyst activity of Catalyst A. Because of the coke to conversion relationship of Catalyst A, higher conversion is achieved.
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Grace has had multiple experiences with reformulations such as these for processing lighter feeds from shale oil or traditional hydrotreated FCC feed. Using a high activity catalyst is required to counter the effects of low delta coke, but it is important to select a catalyst with the proper coke selectivity (coke-to-conversion relationship).
Lastly, another issue with processing shale oil is the possibility of Fe and Ca contamination. To minimize the effect of Fe and Ca poisoning, a high porosity, high diffusivity catalyst should be considered. Since processing shale oils will often result in both issues (lower delta coke and high Fe/Ca), a high activity and Fe/Ca tolerant catalyst should be considered.
RAUL ARRIAGA and KEN BRUNO (Albemarle Corporation)
From a catalyst formulation point of view, it is recommended to increase catalyst activity and tune the selectivity's, including delta coke, to the desired targets while keeping the FCCU against its constraints. When optimizing the catalyst formulation, it is important to maintain or improve the mass transfer character of the catalyst. The objective is to prevent increased pore mouth blockage rates due to the higher amount of iron and calcium often observed in tight oil (TO)-derived feeds.
It is better to achieve higher catalyst activity with the use of high accessibility technology than with additional active ingredients, particularly zeolite, in order to maximize catalyst tolerance to iron and calcium. If the catalyst applied does not have the optimal pore and surface architecture, the result could be increased slurry yields and additional bottlenecks. Albemarle’s AMBER™ and UPGRADER™ are proven catalysts for use with tight oil.
One tactic to increase activity is to raise the amount of rare earth on zeolite for increased delta coke. While case-dependent, another approach for consideration is to reduce the use of vanadium traps or nickel-selective matrices which would enhance the metals contribution to delta coke. By the same token, if a refiner is consuming a flushing catalyst of any kind, it is recommended to re-think that strategy and evaluate reducing its utilization because lower use of a flushing medium may be desired to let metals concentrate on the catalyst. It is recommended to consult with various catalyst suppliers to compare the merits of each manufacturing technology and for commercial references with this new type of feedstock.