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LALL (UOP, A Honeywell Company)

UOP specifies two special check valves in the blower discharge line. The first special check valve is installed a minimum distance from the blower discharge downstream in the snort (or anti-surge) valve in a horizontal pipe run. A second check valve is installed in the regenerator inlet line a minimum distance upstream of the air heater. The slide shows the typical arrangement of the special check valve, which is a swing-style check valve with a spring-loaded air cylinder that provides spring force-assisted closing.

An oil-filled dashpot provides dampening action on openings preventing hammering or damage. Construction is of a heavy wall of steel with 11% to 13% chrome-stainless trim. There is a stainless-steel shaft which is connected to the dashpot and lever arm as a counterweight. The counterweight supports 75% of the disc weight to minimize pressure drop. The air cylinder consists of a small piston opposed by a spring. Under normal conditions, air is supplied to the piston which moves up to compress the spring and allows the disc to open freely.

Uninterrupted operation of the FCC has led to situations during which the flapper has become stuck open. When the blower trips, the flapper does not close; and in some instances, hot regenerator catalyst is reversed into the casing of the blower. A manually operated air test valve is provided to permit equalization of the pressure on both sides of the air cylinder piston so that the spring force will move the piston downwards and exercise the valve during operation.

UOP does not know of any refiner who regularly exercises the special check valve. In our experience, check valves are frequently neglected during turnaround maintenance. During each turnaround, the check valves should be exercised to confirm ease of shaft rotation in the packing, correct operation of the air cylinder and oil dashpot, and correct counterweight and seating.

WILLIAMS (KBR)

KBR also recommends two ISO (International Organization for Standardization) check valves within the blower discharge system itself. However, due to distance in some revamp cases, we have installed one ISO check valve instead of two for blower protection. KBR also recommends the same ISO check valve type: the internal disc with external counterweight location that my colleague just described. One additional fact is that the ISO check close to the air heater should be 300-pound flange ready because of the potential exposure to high temperatures. Also, the ISO check near the blower discharge should be 150-pound flange ready.

We believe that the additional check valve is wear-warranted as it provides extra protection for the blower while only generating an added quarter to a half pound of pressure drop within the system. To ensure that the valve is properly closed, we recommend that Operations visually verify its closure with the valve position indicator, while applying pressure to the counterweight in the direction, to ensure that the check valve is completely closed.

BROOKS (BP Refining)

From an operator’s perspective, I want to add that this has become a recent focus for us at BP. We have had a few recent incidents as a result of our check valves failing. We actually had one incident where, as recommended by UOP, we rebuilt the entire check valve during the turnaround. Then during our start-up, we realized that we had actually made some errors in calculating the clearances; so, the valve hung open, despite the fact that we had done the rebuild. Therefore, you should watch for inaccurate clearance calculations that could cause valves to hang open or lock shut.

We recently had another issue when, per design, we actually had the check valve trip closed. The unit came down on a PRT (power recovery turbine) trip, and all of the equipment seemed fine; but when we came back up, the check valve did not open fully. We were then restricted on airflow from our main air blower, which affected the rest of the run before we could come down. So, despite some of our better efforts to make sure these valves worked right, and even despite the fact that the valves were working properly when we had a shutdown, we have still had other problems around these valves. We are in the initial stages of collecting information about our check valves in the BP FCC systems.

SCHOEPE (Phillips 66)

I want to quickly mention one experience. We just came out of a turnaround during which we actually opened up our check valve to inspect the internals and observed the response of the disc by pressurizing the dashpot. You also want to make sure that the valve is clean and that nothing has accumulated to prevent the special valve from closing. Unfortunately, when we started up, we forgot to commission the air to the air cylinder. After a few days, we found that this valve was in a partially closed position. Fortunately, this valve was designed with a mechanical jack that we could use to actually force the disc into a closed position. We were able to very carefully use this mechanical device until it touched the valve disk. Then, we commissioned the air to the dashpot and slowly opened the valve again.

BROOKS (BP Refining)

Most of our units do rebuilds and/or inspections on these valves at each turnaround. During a post-turnaround start-up, the check valve hung open which caused the main air blower to spin backward, destroying the turning gear motor. This failure was after a full re-build of both check valves. An incident investigation showed that the valve was rebuilt during turnaround with clearances that were too tight. Upon heat up and metal expansion, the valve hung open. Emergency steam to the air grids prevented a large portion of the catalyst from backing into the line and minimal damage was done to the air blower. However, the turning gear motor did not have a clutch disengagement mechanism when spun backwards which resulted in 20,000+ rpm and complete failure of the motor.

During another unit’s recent start-up after a power outage, the check valve hung open which caused back flow of catalyst into the casing of the main air blower motor. The FCCU was shut down, and the machine casing was found packed solid. Fortunately, there was no damage to the blower, and it was cleaned, inspected and brought back online.

A different unit experienced a failure in this check valve during a unit trip. When this unit tripped, the valve closed but failed to reopen fully upon restart, which caused a significant reduction in air rates to the unit.

Due to the abundance of failures around these check valves, we have recently started an investigation around our sites’ valve characteristics (close/open assists, external weight assists, reliability, types, etc.) and are in the initial stages of data collection with the intent of developing recommendations to our sites.

WILLIAMS (KBR)

KBR typically installs at least one ISO check valve in the air blower’s discharge line. The ISO check consists of an internal disc with external counter weight to help hold the valve open during normal operations and a spring assist to help close the valve in the event that air blower operations are interrupted. Some refiners use an air-assist ISO check instead of the spring to fully close the valve during emergency situations. Here air applies pressure to a hydraulic piston that closes the valve when the low flow alarm is triggered.

In cases where the distance from the air blower to the regenerator is excessive, KBR recommends an additional ISO check within the system. One ISO check is located at a minimum distance from the blower (downstream of the anti-surge vent valve), and a second ISO check valve is at minimum distance from the air heater. The check at the air heater is to prevent catalyst back flow from the unit if air is lost. The additional check valve near the blower serves two basic purposes. First, in the event that the second check does not seal properly, this check valve provides an additional level of protection for the blower. Also, as the check valve closest to the air heater closes, the higher pressure air volume trapped upstream of the check valve does not reverse-flow through the anti-surge valve against the blowers discharge as it is relieving. KBR believes that the additional check valve is well warranted as the additional valve typically only provides an additional pressure drop of ½ psi (pounds per square inch) to the system at normal flow rate. The check near the blower is 150-pound rated, and the check near the air heater is 300- pound rated because of the potential high temperature.

To ensure that the valve is properly closed, we recommend that Operations visually verify its closure with the valve position indicator while applying pressure to the counterweight lever in the direction to ensure the check valve is completely closed.

LALL (UOP, A Honeywell Company)

UOP specifies two special check valves in the blower discharge line. The main air blower special check valve is installed on the discharge of the air blower. The regenerator inlet air special check valve is installed just upstream of the inlet to the direct-fired air heater. If the blower starts to surge, the large volume of the regenerator must be isolated from the blower. Otherwise, serious damage could occur to the blower. The main air blower discharge special check valve helps protect the blower during surges. Fluidized catalyst can easily flow back through the air heater if pressure is lost. The regenerator inlet air special check valve helps to prevent backflow of catalyst to the blower. Figure 1 and Figure 2 show the check valve and its associated equipment.

The special check valve is a swing style check valve with a spring-loaded air cylinder that provides spring force assisted closing. An oil filled dashpot provides a damping action on opening to prevent hammering and damage. Construction is of heavy wall steel, to resist temperature and pressure stresses, with 11% Cr (chrome) to 13% Cr or stainless trim. The stainless-steel shaft is supported by hardened stainless steel bushings with GRAFOIL® packing used to prevent leakage. The shaft is connected to the dashpot and to a lever arm that has counterweights. The counterweights support 75% of the disc weight to minimize the pressure drop through the valve. The counterweight should never hold the disc open when there is no air flow. The lever arm is usually cut to the proper length in the factory, and the weights are set in the field.

The air cylinder consists of a small piston opposed by a spring. Under normal conditions, air is supplied to the piston, which moves up to compress the spring. The piston rod moves freely between two small lever arms attached to the check valve shaft. As the piston rod rises, the valve is free to open. Air flow from the blower forces the valve open. The air to the piston is supplied through a three-way valve that will vent off cylinder pressure when actuated. For new units that have venturi meters on the blower discharge line, a low flow signal will alert the valve to cut off the air supply to the special check valve. Instrument air failure will also vent off pressure from the cylinder. Upon initial venting, the spring provides a sharp thump to the valve shaft to help free the disc in the event that it has become slightly stuck in the open position. The force of the spring is not enough to close against the normal operating air flow from the main air blower.

A manually operated air test valve is provided which permits equalization of the pressure on both sides of the air cylinder piston so that the spring force moves the piston downward and exercises the valve during operation.

Extended periods of uninterrupted operation of the FCC with the check valve in the open position have led to situations in which the flapper has “stuck” to the top of the check valve body over time. When the blower trips, the flapper in the special check valve does not close; and in some instances, hot regenerated catalyst has reversed into the casing of the main air blower.

UOP does not know of any refiner that regularly “exercises” the special check valve at the discharge of the main air blower. Some refiners do activate the air actuator mechanism periodically, but we are not aware of anyone who exercises or moves the check valve flapper.

At each turnaround, it is recommended that the special check valve be opened, inspected, and maintained by qualified personnel. In our experience, special check valves are frequently neglected during turnaround maintenance. During each turnaround, with the air blower shutdown and after any maintenance has been completed, the check valve should be exercised to confirm ease of shaft rotation in the packing, correct operation of the air cylinder and oil dash pot, and correct counterweighting. Contact the check valve manufacturer for additional recommendations.

WILLIAMS (KBR)

To obtain a more consistent reading, plant personnel should examine three phases: the transmitter, its physical location, and its instrument gas system. As for the transmitter, the technician should analyze it to ensure that it is within the accuracy specified by the manufacturer. In other words, you will never get all three transmitters to read 4 mADC (milliamps direct current) to 20 mADC. If within the Accu-Read meter range, the manufacturer’s tolerance for this transmitter can only read 19.8 mADC to 20.02 mADC.

In addition, the transmitter has a drift tolerance. For transmitters with drift tolerance, all you can do is identify which transmitter is drifting and then develop a frequent maintenance recalibration schedule for that device. Transmitters outside of the manufacturer’s tolerance should be repaired or replaced. As far as the physical location and routing beyond the transmitter itself, plant personnel should ensure that the location and physical condition of the three transmitters are acceptable.

Ideally, each transmitter will be physically located at the same elevation with impulse tools routed to separate process taps. Dissimilar routing will include additional bends or lines and could create small deviations in process variables. In addition, tubing that is slightly damaged, in comparison to the others, can also produce slight deviations in process variables.

Operations should also verify that none of the impulse tubes are in direct contact with a hot surface. In this case, it may be a standpipe itself. We have found that contact with hot surfaces can lead to a temperature difference, as compared to the other tubing, which may lead to a process deviation, compared to the other instruments.

As far as the purge gas system itself, each side of the slide valve, whether regenerated or spent, will incorporate the specified purge gas medium for each tap. Plant personnel should first make sure the recommended purge gas medium is dry, and then they should confirm that the suggested flow rate is being maintained at each tap. Since an individual flow indicator for each tap is seldom present, there a properly sized restriction orifice installed with steady purge gas supply pressure to ensure that the ideal purge flow rate is obtained.

In summary, if inconsistent readings continue, prepping lids with the proper medium is the first choice. Examining, replacing, or repairing the transmitter is another option. Evaluating the routing to ensure that there are no bends or additional lines will help alleviate the deviation between the three readings.

LALL (UOP, A Honeywell Company)

I have a few additional comments. Primary contributing factors that could be considered the cause of inconsistent readings include the following:

• Instrument tapping orientation: All three sets of taps should be located in the active catalyst flow of the standpipe on the disc opening side.

• Transmitter module range selected: A range-to-span ratio greater than 10:1 can lead to a decrease in accuracy.

• Erratic impulse line purge rates, as a consequence of utilizing devices such as rotameters, can result in inconsistent purge rates being used as the critical flow orifice approach with adequate purge gas pressure.

• The physical location of the transmitters affects the readings. The closer the transmitter is to the process, the better.

• Excessive lengths greater than 15 feet can dampen the response.

• Notification or alarm on loss of purge medium is necessary to address potential catalyst plugging.

• Frequent surveillance and reaming of the process connections is recommended.

PIMENTEL (CITGO Petroleum Corporation)

Yes, we do experience some variation between different slide valve DP (differential pressure) readings. These variations are normally caused by swings in the pressure in the purge headers. We have some design practices to minimize this effect. First, all of the taps should be equidistant from the slide valve. Second, all orifices in the taps should be the same size. Our standard is one-sixteenth of an inch. Third, you should have enough header pressure – normally 25 pounds – over the internal pressure and pipe to accommodate for fluctuations in the gas. This is especially important when you have different media in both sides of the slide valve; sometimes you have gas or inert in the reactor side and the air or inert in the regenerator side.

We recommend extending the pipe through the internal refractory layer to avoid plugging and also installing all taps on the same side of the standpipe. We do not recommend installing the taps across the standpipe, especially when your standpipe is not completely vertical. Finally, on the maintenance side, we recommend setting an alarm in your console both for variations between different DPs and also for lack of movement.

LALL (UOP, A Honeywell Company)

No reference has been provided as to what the statement “inconsistent readings” implies. In these applications, UOP generally recommends a “pre-trip” or alarm setting of 1 psi with a “trip” setting of 0.5 psi. While small inconsistencies would be expected and not considered detrimental, inconsistencies greater than approximately ± 0.25 psi could result in spurious shutdowns or even prevent a necessary shutdown from happening. Primary contributing factors that could be considered the cause of inconsistent readings would be:

1. Instrument tapping orientation: All three sets of tappings should be located in the active catalyst flow of the standpipe, i.e., they should all be in the catalyst dense phase on the disc opening side. The topside of the standpipe could experience an accumulation of gas bubbles, and this could lead to erratic readings.

2. Transmitter capabilities regarding accuracy and performance are dependent on the manufacturer.

3. Transmitter module range selected: the range/span ratio >10:1 can decrease the accuracy.

4. Erratic impulse line purge rates: Using devices such as rotameters can result in inconsistent purge rates. UOP uses the critical flow restriction orifice approach with adequate purge gas header pressure.

5. Physical location of transmitters: The closer the transmitter is to the process the better the response. Excessive lengths greater than 15 feet can dampen the response.

6. Notification or alarm on loss of purge medium is effective for addressing potential catalyst plugging of impulse lines.

7. Frequent surveillance and frequent reaming of the process connections because of the importance of these measurements as part of the shutdown system.

PIMENTEL (CITGO Petroleum Corporation)

FCC slide valve DP taps typically have one purge medium such as natural gas or inert on the reactor side of the slide valve and air on the regenerator side of the slide valve. Significant variations in pressure on one header may not be matched by the pressure on the other header. The header pressures need to be consistent. Most variations in header pressure can be buffered adequately by properly sized restriction orifices. Our typical orifice diameter on standpipe instrument taps is 1/16”. Our header pressures are normally 25 psi or more above the standpipe pressure that the purge is going into to overcome variations in process and instrument purge header pressures. Taps should be located equidistant from the slide valve. We also think that the taps on each side of the slide valve should be located reasonably close to each other versus being on opposite sides of the standpipe radially. Extend the tap pipe all the way through the refractory on the inside of the stand pipe.

Maintenance should include 1) clearing the taps if the readings are off, 2) using a hand pump to check the diaphragm of the transmitters, 3) checking the vent valves on the transmitters to see if they are closed, and 4) setting up alarms on the console to check for differentials between the transmitters, as well as for lack of movement on each transmitter, to check for stuck transmitters or plugged taps.

WILLIAMS (KBR)

To obtain more consistent readings plant personnel should examine the transmitter, its physical location and its instrument purge gas system. The technician should analyze the transmitters to ensure they are within the accuracy specified by the manufacturer. In other words, you will never get three transmitters to read 4 mADC to 20 mADC and 0 to 15 psig exactly. A transmitter can be within manufacture tolerance and only read 19.98 mADC or 20.02 mADC. Transmitters also have a drift tolerance. For transmitters within the drift tolerance, there is nothing you can do except identify which transmitter is drifting and develop a frequent maintenance recalibration schedule for that device. Transmitters outside the manufacturer’s tolerances should be repaired or replaced.

Beyond the transmitter itself, plant personnel should ensure the location and the physical condition of the three transmitters are acceptable. Ideally each transmitter will be physically located at the same elevation with impulse tubes routed to separate process taps. Dissimilar tube routings which include additional bends and/or lengths could create a small deviation from process variables. In addition, tubing that is slightly damaged in comparison to the others can produce slight differences. Verify that one impulse tube is not contacting a hot surface (standpipe, etc.). This temperature difference has also led to process deviation in comparison to the other transmitters.

Finally, check the purge gas system to each pressure tap. Each side of the slide valve, whether regenerated or spent, will incorporate a specified purge gas medium for each tap. Plant personnel should make sure the recommended purge gas medium is dry and the suggested flow rate is maintained to each tap. Since an individual flow indicator is seldom present, verifying the proper size restriction orifice is installed with a steady purge gas supply pressure will ensure the ideal purge flow rate is obtained.

If inconsistent readings continue, then pumping each lead with the proper solution will help close the gap between process readings.

BROOKS (BP Refining)

I would like to address this question as two different parts, beginning with the flue gas expanders. BP has three flue gas expanders in its system. These expanders are all set up with slightly different configurations. We have one FCCU flue gas expander that is directly coupled to the main air blower. We have another that is coupled to a main air blower, but this site has onsite redundant air blowers. We also have one that is just connected into the electrical grid.

We have different expander trip setups and systems and corrective actions and alarms for each of these because they do not have the same configurations. All of these systems include typical rotating equipment trips around high expander and turbine speed, high expander compressor turbine displacement, low lube oil pressure, and typical anti-surge control; so, they are all usually included in anything we would have around an expander.

As I said, we have various configurations and setups for how the flue gas expander trips the FCC. One of our flue gas expanders goes directly to the electrical grid and actually just trips to a bypass; it does not trip off the FCC. Basically, any trips for that flue gas expander are just for equipment protection. Our expander that is directly coupled to the main air blower will trip the FCC offline. It is part of the safety interlock system (SIS); because if you lose that expander, you will lose your main air blower and need to shut down your FCC.

Our expander, which is built into the one that I mentioned with redundant air blowers, actually does not go into a safety interlock system. It goes into what we call a Critical Corrective Action System which starts taking corrective action to reduce flow rates to the unit without operator intervention, cutting back the FCC automatically. The unit can then run on the other available air blowers, but it does not actually trip it off.

The critical correction action system is part of our distributed control system (DCS). The operators can turn it off if they desire. My point is that you need to consider your trip system setups for tripping off the FCC with respect to the configuration of your expander. We also include typical rotating equipment alarms, as well as all of these high-bearing temperatures and high-winding temperatures, for example, as shown on the slide.

Again, we have multiple configurations for our CO boilers. Most of our units actually run in full-burn and do not have CO boilers. We do have one unit that runs in full-burn and also has a CO boiler. We run the FCCU flue gas through it to provide additional heat and steam generation, but it runs mostly on fuel gas firing.

With that unit, we have a bypass stack; and if the CO boiler needs to trip offline, then the FCCU flue gas flow will go directly to the bypass stack. Another configuration we have is a partial-burn CO boiler that is actually going to trip into a bypass. Then we tend to bring our unit under control and come out of the bypass and back to the CO boiler. We consider that our CO boilers should fall under fired-heater standard trip conditions.

API RP 556 is a recommendation for protective systems around fired heaters. The main concern is typically going to be around flameout, so fire eyes/flame scanners usually have two-out-of-three voting systems for all of these: loss of air to the burners, loss of fuel gas pressure, and loss of fuel gas purged. Obviously, all of these are focused around preventing a fuel-rich environment in your CO boiler. With this, since it is a boiler, we also have typical convection section trips to help protect the convection section. So if you have boiler feed water going through circulation pumps, those pumps would actually trip. And then, since you have additional consideration from the flow of your flue gas through the CO boiler, you will also need to add extra controls to the CO boiler that would trip to a bypass around low FCC riser outlet temperatures, low air, or loss of air, which are typical conditions that trip off an FCC.

SCHOEPE (Phillips 66)

On the expander, we have very similar trips as those of BP. The expander also has an expander trip on high flue gas temperature, low lube oil pressure, high axial vibration, and overspeed. We are also, however, considering an axial position trip which will monitor the health of your thrust bearing. Also under consideration is a radial vibration trip.

The expander: Depending on the recovery train, the expander basically determines if your FCC shuts down or not. So if your air blower is directly connected to your expander and that is the only air blower, then the FCC SIS would also be activated. If you have a gen set or multiple air blowers, then the FCC would typically stay online.

CO boilers: Typically, a CO boiler trip only trips the burner; it will not trip the FCC unit. Even in resid units, they typically try to move as quickly as possible to complete combustion, and then they relight the CO boiler. The trips are listed on the slide.

LALL (UOP, A Honeywell Company)

The technical standard that UOP follows is the Functional Safety Instrumented Systems for the Process Industry Sector, which is ANSI/ISA-84.00.01-2004 [IEC 61511 Part 1 modified]. I have included the UOP strip inputs and shutdown matrix in the Answer Book

BROOKS (BP Refining)

One BP unit’s expander is directly coupled to their air blower, which also has a steam “helper” turbine. The expander and motor are referred to as the power recovery train (PRT). The PRT trips on this unit are tied into the safety interlock system with an SIL-2 (safety integrity level-2) rating which results in a unit shutdown due to loss of the main air blower powered by the PRT in typical operation. The unit has developed methods to run the main air blower with the PRT offline via the “helper” steam turbine and an auxiliary air line from other refinery air compressors. The trips in this system are typically normal rotating equipment protection trips and include the following:

• high expander and turbine speed (two-out-of-three vote),

• high expander, compressor, and turbine displacement (two-out-of-three vote),

• low lube oil pressure (two-out-of-three vote), and

• compressor anti-surge controls.

In addition to the trips just mentioned, alarms to prompt operator action are included for the following:

• high bearing temperatures,

• high motor winding temperatures,

• high expander inlet temperatures,

• high expander inlet pressures, and

• low rotor cooling steam.

Another BP unit is fortunate to have multiple air blowers for its FCC complex. One of these air blowers is powered by a flue gas expander. Due to the redundancy in the air delivery system, this unit does not employ a safety interlock system with automatic trips. Instead, its critical corrective action (CCA) system is a series of automatic unit moves designed to take the unit to minimum feed and air rates but not shut down the FCCU. These minimum rate target settings are based on the capacity of the remaining air blowers in the system. The CCA includes the inputs listed above.

Our final BP expander is not coupled to an air compressor; it supplies electricity directly to the refinery energy grid. Trips around this expander include those already mentioned and result in flue gas routing around the expander via large bypass lines in the flue gas system. Systems linked to electrical grids should include a bypass trip in the event that the expander decouples from the grid to prevent excessive expander over-speed damage.

Trips should also be in place to bypass or shut down the expander on FCCU shutdown and automatic trips to protect the equipment.

The majority of the BP FCCUs operate as full-burn units without CO boilers. We have two joint venture sites that operate in partial-burn with CO boilers and one resid FCCU with a two-stage regenerator equipped with a CO boiler on the first stage flue gas outlet. None of our CO boilers are fired with fuel oil.

We have one additional site that previously ran in partial-burn and has retained its CO boiler, which is used in refinery steam generation. In this capacity, the majority of the steam is generated by firing fuel gas burners. Additional steam generation is provided by the hot FCCU flue gas running through the boiler.

At BP, we consider a CO boiler to fall under the same safety requirements as a typical fired boiler. We have central required safety trips based on API RP 556 (Instrumentation, Control, and Protective Systems for Gas-Fired Heaters). API RP 556 does not cover CO boilers specifically, but it does include information on gas-fired heater protective systems in Section 3.4. BP specifies additional safety trip/bypass requirements for CO boilers.

For CO boilers and fired heaters, safety instrumented systems are implemented to mitigate possible hazardous explosions of fired heaters due to the accumulation of combustible material on burner flameout. Our CO boilers have fire eyes or flame scanners to detect flameout. These are included (typically based on two-out-of-three voting) in the trip/bypass instrumentation system. Fired heater burner (main and pilot) flameout can result from a number of situations, which are also included in our trip systems, such as:

• loss of air to burners,

• loss of fuel gas pressure and/or flow, and

• fuel gas pressure surge (snuffing flame).

These are boilers that generate steam in the convection section of the furnace, which has additional trips. These trips protect the convection section of the boiler from overheating and include loss of boiler feed water circulation pumps and low level in the boiler feed water drum.

Additional considerations are necessary for CO boilers as another source of combustible material is present. BP considers a CO boiler trip or bypass as necessary any time highly combustible material could be present in the flue gas. Thus, in addition to the trips for fired heaters, our CO boilers also trip, and are routed to a bypass stack, on

• low riser outlet temperature (which can lead to oil-soaked catalyst in the regenerator due to lack of feed vaporization),

• low air or loss of air to the regenerator (that can lead to a flow reversal of oil into the regenerator),

• low differential pressure on regenerated catalyst slide (or plug) valves (which can lead to a flow reversal of oil into the regenerator) [This trip does not apply to R2R regenerator designs with separate flue gas systems as a reversal would send oil to the second stage of the regenerator], and

• during any phases of FCCU start-up and shutdown that involve initial firing of torch oil (which may be unstable) to the regenerator and/or feed introduction to the riser.

Our CO boilers trip by opening valves to divert flow to a bypass stack until the upset can be resolved and brought back into control.

SCHOEPE (Phillips 66)

Expanders: Experience Layout: If an expander trip initiates the FCC oil out logic, depends on the configuration of the expander power train. Expander trains that connect the expander directly to a single main air blower can initiate a FCC trip if the expander trips. If the expander is used to generate electricity only, or if multiple air blowers are available, an expander trip does not trip the FCC oil out logic. The flue gas expanders in the Phillips 66 system trip on high flue gas temperature, low lube oil pressure, high axial vibrations, and over-speed.

Trips on axial position and radial vibration are currently under consideration. Some of these trips were developed based on guidelines from API 617 (Axial and Centrifugal Compressors and Expander-compressors for Petroleum, Chemical and Gas Industry Services).

CO boilers: CO boiler trip does typically not initiate the FCC SIS oil out logic. In case of a CO boiler trip, the FCC is typically moved from partial-burn to complete combustion as quickly as possible to remove CO from the flue gas in preparation for relighting the boiler. Moving a Resid FCC into complete combustion makes it necessary to reduce the feed to minimum. Since this operation may take several hours, some units choose to pulled feed for a short period of time to relight the CO boiler.

The burner(s) in the CO boiler will trip at the following conditions: high burner pressure, low fuel gas pressure, high combustor temperature, flame failure, low airflow, low steam drum level, and low circulating water flow.

LALL (UOP, A Honeywell Company)

The technical standard which sets out practices in the engineering of safety instrumented systems that UOP follows is ANSI/ISA-84.00.01-2004 (IEC-61511-1: Mod) – Functional Safety: Safety Instrumented Systems for the Process Industry Sector.

LALL (UOP, A Honeywell Company)

These are two broad categories for the use of these indicators. The first category is capacity utilization and yield performance, which covers process performance, operating constraints, and optimal use of any inherent design margins. Operating envelopes define the limits of maximum/minimum ranges of key process parameters to avoid potential equipment damage, trigger action, and report it.

Second is reliability and health monitoring by maintaining FCC operating parameters within acceptable equipment limits. Health monitoring is the historical trending of defined parameters, which may or may not be in the operating envelope, to gauge the current condition of the unit health. This monitoring can provide an early warning of availability impacts. Examples are cyclone velocities and slurry ash content. In terms of tools being used to monitor the FCC performance, a customized monitoring tool for the refiner extracts data from the data historian and populates the KPIs (key performance indicators).

UOP’s OpAware™ software is one example of a monitoring tool. We understood the reference to expectations in the last part of the question as asking how you use the benchmarking monitoring in KPI data you gather. For example, a KPI parameter outside the limits of its operating envelope can be automatically flagged by the monitoring tool to generate a report, which is then followed up on by the business team and other parties who are accountable. Examples of KPIs are shown in my Answer Book response.

SCHOEPE (Phillips 66)

The operating envelope on all FCC units within Phillips 66 is framed by safety operating limits and, just recently, reliability operating and environmental limits. In terms of tools, we are using daily, weekly, and monthly tools. The SOLs, ROLs, and DCS (distributed control system) alarms are being communicated directly to the operators. We also get email notifications and offspec lab--notifications; and of course, spreadsheets and live graphic programs. On a weekly basis, most sites do a test run, which means that during that designated day, all of the necessary lab data is taken in order to do a complete material balance. That material balance will then be processed in our FCC simulator. We also check our catalyst properties once a week.

On a monthly basis, we do a catalyst fines analysis on the slurry and flue gas on the catalyst site. The fines analysis will tell you the state of your cyclone and can also alert you to any attrition sources present in your unit. Management has a standard KPI report which is also rolled out monthly. In addition, almost all sites do a cyanide survey which assesses the corrosion potential in the unit. Some partial-burned units do it quarterly. We also have an FCC health check done by a third-party FCC specialist once per year. The health check focuses on the hydraulic conditions of the units, catalyst densities, and steam distributors, for example.

I listed some KPIs on this slide and also put them in the Answer Book. The expectation is basically to optimize the FCC within the operating envelope of SOLs, ROLs, and environmental limits.

BROOKS (BP Refining)

BP’s KPIs and tools are very similar to what Christian said are being used at Phillips 66 and which I assume are what other companies also employ. I want to add that we have recently started implementing a new web-based monitoring tool. It is more of a consolidation type of tool. Engineers and Operations teams still have to input some of the data.

In general, all of the data coming from our historization software is being pooled from the unit. We can set up standard calculations in the software. It is web-based, so it can be accessed from multiple locations. The software presents a consistent view of your monitoring sheets. That way, when engineers are transitioning, it becomes easier for them to understand and recognize the monitoring tools being used across units and spot KPIs. Management teams can run reports with the software, and engineers can post limits that can go directly to the Operations team, which can then use these limits for their log books and Rounds data.

This is a new tool for us. Some of our first implementers have had great reviews of its flexibility and functionality. We have only been using a small portion of its capabilities, and we are actually looking into some of the new functionalities that we will be able to employ later.

AVERY (Albemarle Corporation)

From Albemarle’s perspective, FCC performance is centered on evaluating FCC catalyst, hardware, and feed effects. All methods depend on the tools available, the time allowed to evaluate data, and the quality of that data. The most common methods are kinetic modeling, pilot plant testing, side-by-side comparison, and benchmarking to crossplots. Before using these techniques, the refiner should ensure the collection of quality and mass-balanced data that will account for extraneous streams to the FCC and downstream units.

Kinetic models need the most complete set of data to develop a base case. They also require substantial funds to either purchase the model or resources or the expertise to develop such a model. Using kinetic models allows for the correction of feed effect, operating conditions (such as rise of temperature in cat/oil), cutpoint corrections, and catalyst activity effects. Running the model to seasonal constraints is key to getting realistic output. Results are most reliable when looking at conditions with historical ranges. This method is commonly used to measure FCC catalyst hardware changes. I have an example of the kinetic modeling when we talk about the severe hydrotreating case.

Small scale testing, shown on the slide, is a method that can remove the feed and operating conditions. Ideally, the refiners use e-cat (equilibrium catalyst) data that should be at least 90% changed-out when they look at it. The way you look at this data is very important. You can either look at ISO conversion or ISO coke. In this particular example, you will see several catalysts reviewed. Looking at a constant conversion, you can see that the green catalyst, or Catalyst E, has the lowest amount of coke for conversion. But if you are looking at ISO conversion, then the blue catalyst, which is Catalyst A, is the best catalyst. So, when looking at ISO conversion or ISO coke, your constraints are probably the most important.

Benchmarking through cross plots is a common method. There is no need to look at outside models and testing labs. Results can compare catalyst, heating unit, and hardware changes. Care needs to be taken to plot yields versus their dependent variables. Examples are conversion versus feed basic nitrogen and conversion versus cat/oil. I have two examples.

In the first example, you will see the AI (attrition index) on the X axis, which is accessibility. It is a measurement of large molecules going in and out of the catalyst. You also have light cycle-to-bottoms ratio. You can see that a higher accessibility catalyst will give you a better LCO (light cycle oil)-to-slurry ratio. So once again, you need dependent variables when you plot them.

Another example shows two different catalysts: Catalyst A and the old catalyst. We plotted gasoline yield versus conversion. You can see that one has superior gasoline selectivity.

NAVEEN DIMRI (Reliance Industries Limited)

What is the KPI for the reactor cyclone velocity, and what is the basis? Is it similar to a regen cyclone? Under the reliability KPI, do you want it with the reactor cycle and velocities?

SCHOEPE (Phillips 66)

For the reactor cyclone, the velocities are managed as part of the ROL system. It depends on the kind of reactor system. The ROL for direct-connect riser cyclones is typically 65 fps (feet per second). If you have some sort of a primary disengaging device, then the secondary cyclone will limit this cyclone velocity. For a secondary cyclone, the maximum sustainable cyclone inlet velocity is about 75 fps, although it is highly unit-specific.

NAVEEN DIMRI (Reliance Industries Limited)

What is the life you achieve with that 75 fps? Is it a based on the reliability of the unit? What is the run-length of the operation: four, five, or six years.

SCHOEPE (Phillips 66)

Yes, the number of years varies. We have a question coming up which talks about cyclone lives, so we will cover that a little bit on the regenerator side. On the reactor side, it is anywhere between three and five years.

LALL (UOP, A Honeywell Company)

Key performance indicators (KPIs) define the important FCC unit variables and parameters for monitoring the FCC performance and unit health (also known as “health monitoring”). There are two broad categories for use of these indicators:

1. Capacity utilization and yield performance covering process performance and operating constraints and limits, and optimal use of any inherent design margins.

2. Reliability and health monitoring by maintaining FCC operating parameters within acceptable equipment limits, such as cyclone velocities.

Increasingly, energy targets, process management and safety related KPIs are also being captured in the monitoring tools.

A customized monitoring tool specific for the refiner, extracts data real time from the data historian and populates the KPIs. UOP’s OpAwareTM monitoring system is an example of a monitoring tool encompassing all of the above categories in one unit monitoring tool.

Operating envelopes define the limits of maximum and minimum ranges of key process parameters to avoid potential equipment damage and to trigger action and reporting. Health monitoring is historical trending of defined parameters (which may or may not be in the operating envelope) to gauge the current condition of the unit ‘health’ which can provide an early warning of availability impacts.

We have understood the reference to “expectations” in the last part of the question as asking how you can use the benchmarking, monitoring and KPI information you gather. For example, a KPI parameter outside the limits of its operating envelope can be automatically flagged by the monitoring tool to generate a report, which is then followed up by the accountable business unit team, refinery management and/or corporate management personnel, and the corporate FCC subject matter expert. These reports also permit missed opportunities to be quantified and enable discussion of key missed opportunities across all levels of the organization, facilitating decisions on prioritizing resources, maintenance and improvement projects.

Generally, FCC engineers, operations and advanced process control systems drive the FCC unit to achieve effective utilization of the available equipment design margins up to safe operating constraints and limitations. The following are proposed operating items for which key process performance and health monitoring parameters can be defined. It is recommended for your specific unit design; the target and actual values should be routinely reviewed to improve unit reliability predictions.

SCHOEPE (Phillips 66)

The operational envelop of FCC units at Phillips 66 sites is framed by the Safety Operating Limits (SOL), environmental limits and Reliability Operating Limits (ROL). Within these limits, the FCC is optimized according to economic targets set by the Planning/Optimization department.

Daily tools:

• SOLs and environmental limits are monitored through alarms from the distributed control system. These alarms trigger pre-determent action from the board operator, the shift supervisor, the process engineer and the inspection department.

• ROLs and off-spec lab results are communicated to operations and technical service through email notifications.

• Planning/optimization targets are often communicated through the intranet.

• Daily unit monitoring is done by using spreadsheets or live graphical programs.

Weekly tools:

FCC optimization is done by using FCC simulators based on data from weekly Operating data and catalyst property data supplied by the catalyst venders.

Monthly tools:

• The size distribution of catalyst fines in slurry oil and/or the flue gas fines collection equipment (ESP fines or flue gas scrubber circulating water) is done to identify catalyst attrition sources and/or cyclone damage. This data is typically supplied by the catalyst vender.

• Standard FCC performance reports are issued for upper management with focus on catalyst retention, mass balance quality and slurry exchanger performance.

• Cyclone life calculations are done to assess the remaining life of the regenerator cyclones (See Question 19).

Quarterly to yearly, cyanide surveys are done to assess changes in corrosion potential in the hydrocarbon recovery section.

A yearly FCC health check is often done by a third-party FCC consultant. This check includes a detailed evaluation of the catalyst hydraulics, an evaluation of all gas distributors etc.

The key performance indicators (KPIs) differ, depending onsite specific Optimization targets, site specific unit constrains and hardware limitations. The table below lists some common FCC KPIs.

BROOKS (BP Refining)

Similar to the other operating companies, at BP we use our internal FCC process model and excel based tools to monitor our units. We also use data historizing software to pull and store large amounts of data out of our plant instrumentation system. Our Excel based tools pull laboratory data and data from the historizing software to feed into our process monitoring calculations.

Additionally, we are currently implementing a web-based monitoring tool across our sites. This tool can be accessed from multiple locations via the web and is meant to streamline the unit health monitoring process. It can be set up with standard calculations for data conditioning, mass balance reconciliation, and process specific KPIs. It pulls data directly from our data historizing system and laboratory data system. The presentation of the data is standardized so that process engineers transitioning from other units are used to the data presentation formatting. Management can run specific reports regularly via the software to track items of interest. Engineers can adjust operating targets online. The tool had functionality to allow for storage of operator logs and Rounds data. First implementers of this new tool have been pleased with its flexibility and functionality. We are still working on implementing it at additional sites. We are also not currently using all the tool’s capabilities fully and plan to explore additional functions in the future.

AVERY (Albemarle Corporation)

From Albemarle’s perspective, FCC performance is centered on evaluating FCC catalyst, hardware, and feed effects. All methods depend on the tools available, the time allowed to evaluate, and the quality of data. Most common methods are kinetic modeling, pilot plant testing, side-by-side comparison and benchmarking through crossplots. Before utilizing these techniques, the refiner should assure that they are collecting quality mass balanced data that accounts for extraneous streams to the FCCU and downstream units.

Kinetic models need the most complete set of data to develop a calibrated base case. They also need substantial funds to either purchase a model or resources, and expertise to develop such a model. Using kinetic models allows for correction of feed effects, operating conditions (such as riser temperature and cat/oil, etc.), cutpoint corrections, and catalyst activity (FST). Running the model to seasonal constraints is key to getting a realistic output. Results are most reliable when looking at conditions within historical ranges. This method is commonly used to measure FCC catalyst and hardware changes.

Small scale testing is a method that can remove feed and operating condition changes. Ideally, the refiner should use e-cat from the unit when the circulating inventory is at least 90% changed out for post-trial audits. Using the feed from the unit is a must. The refiner can review results at ISO conversion, ISO coke, or a condition that is determined to be the constraint. This method will not reveal the accessibility and stripability benefits/changes.

Benchmarking through cross plots is a common method. There is no need to use outside models and testing labs. Results can compare catalyst, feed, and unit hardware changes. Care needs to be taken to plot the yields versus their dependent conditions. Examples are conversion versus feed basic nitrogen, conversion versus cat/oil, etc. Results are not at unit constraints and do not account for feed nor conditions outside the plotted relationships.

SUBHASH SINGHAL (Kuwait National Petroleum Company)

Gasoline barrels and LPG (liquefied petroleum gas) yields are two main KPIs for FCC performance. Catalyst loss and FCC cycle length are additional KPIs for the FCC units, depending on their design.

ROSANN SCHILLER (Grace Catalysts Technologies)

There are many tools that are available to monitor FCC unit performance. Most FCC operators monitor in-process or “as produced” yields and operating conditions; additionally, they complete unit mass balances at routine intervals (often weekly or more frequently).

Of primary importance is the net product value produced by running the FCC. This is most often examined using mass balanced data from the unit, in conjunction with refinery specific product and feed values (pricing). In many refineries, FCC profitability is driven by overall volume gain, so this is an important KPI.

Unit reliability is also a very important profitability parameter, and (along with a strong routine maintenance program), many refiners monitor in process operating parameters to ensure that limits are not being exceeded. Some of these parameters are directly measured in the unit, and some are calculated using in-process or mass balanced data.

Measured parameters include unit temperatures (at various points in the unit, including reactor outlet, regenerator bed, reactor and regenerator dilute phases, and others), unit pressures (reactor and regenerator), wet gas compressor suction and power, regenerator emissions, and slide valve/standpipe differential pressures.

Calculated parameters which are important to monitor include yield selectivity's (yields/conversion), coke make, superficial velocities (especially in cyclones), and catalyst circulation (or cat-to-oil ratio).

The recommended ranges for all of these parameters are specific to the FCC unit’s configuration, feed and catalyst type, and operating strategy.

As a routine service to its customers, Grace provides routine technical service reports, including equilibrium catalyst analysis. These reports can be a critical tool to monitor FCC unit performance, and to troubleshoot the various problems that can arise in typical FCC unit operation. They are most effectively used when they are incorporated into routine operating reviews with the catalyst supplier. During the reviews, recommendations are often made to adjust operating strategies or fresh catalyst formulation to address future operations or issues that are expected/anticipated for the refinery. These routine reviews are a critical component of the successful operation of the FCC.

The catalyst KPIs (key performance indicators) include cracking data [ACE or MAT (advanced cracking evaluation or micro activity test)], physical properties of the catalyst, and chemical analysis of the catalyst. As with yield and operating KPIs, the expectation for these KPIs varies greatly depending on the feed processed, unit design, catalyst type, and operating strategy of the refinery.

In addition, equilibrium catalyst data can be used to benchmark unit performance against similar units, feed types, catalyst types, or a number of other variables. Advanced analytical tool and methods have been developed by catalyst suppliers to understand how age distribution, cyclone performance, contaminant metals, and other variables may impact the performance of the FCC catalyst. These analyses are typically performed “on request” as problems arise.

SCHOEPE (Phillips 66)

Processing Hydrotreated Feed: First of all, let’s define what ‘severely’ hydrotreated feed means. One unit in our system hydrotreats the feed down to 50 ppm sulfur and 50 ppm nitrogen, so you can see that processing that type of feedstock has tremendous yield benefits. You can expect conversions of 90% and higher. In some cases, you can recycle this slurry to extinction. However, there were a lot of issues. Some were anticipated, and some were not.

Operational Issues: The most obvious issue everyone expected was the regenerator temperature. Because of the low amount of coke precursors in the feed, it is very hard to keep your regenerator temperature high enough for efficient coke combustion. Our units have tried several options. In the extreme cases, we have used torch oil. One unit used the direct-fired air heater for some period of time. Sometimes stripping steam was reduced in order to increase regenerator temperature. Of course, slurry recycle is used first. All of these steps were done to increase the regenerator temperature. If you start processing hydrotreated feed, the gas make will increase. Your wet gas compressor and absorber train have to be designed for that change.

Reliability Issues: Two units experienced alkaline carbonate stress corrosion cracking after they switched feed. As a result, Phillips 66 developed an ROL that monitors the ratio of sulfur to nitrogen in FCC feed. I put that ratio in the Answer Book also. Additionally, the slurry system has to be designed for a higher catalyst concentration and lower flow. If you have a unit that is accustomed to much higher slurry yields, then the ash content can easily double. During my tech service times, I had a unit that ran in distillate mode and then switched to 100% hydrocracker bottoms. Their slurry pumps that used to last for years now eroded within a matter of months. So, the slurry system has to be reevaluated.

The catalyst losses on the reactor are basically the same. But because your slurry yield is so much lower, the ash content in slurry is increasing.

Another issue is the reliability of the flue gas system. If you do recycle slurry to extinction, the only way for the catalyst to get out of the system is through the flue gas section. Therefore, all of that equipment has to be designed to handle the additional dust load.

Environmental Concerns: On the environmental side, we actually ran into unanticipated issues. I already spoke about increased particulate emissions. Stack opacity can also increase because the SO2 almost disappears. The reason is that the SO2 decreases the resistivity of the catalyst particles; therefore, it is more difficult for the particle to accept a charge if SO2 is missing. On at least one unit, after switching to hydrotreated feed, we had to install an ammonia injection system to compensate for that effect.

CO Combustion: This slide was presented by Bill Hennings in a previous NPRA meeting. It shows the relationship between CO and NOx (nitrogen oxide) of one unit after the switch to hydrotreated feed. All of a sudden, their CO emissions went way up 3,000 ppm while their CO limit was 500 ppm. It did not matter how much excess O2 was used. They operated with 3% to 6% excess oxygen, and it was still not possible to reduce the CO.

When the production plan called for processing a little heavier feed, which included more contamination, they noticed that as the NOx came up, the CO decreased. Once they discovered that relationship, they tried to purposely increase the NOx in flue gas in order to stay below 500 ppm. They settled for an ammonia injection system at the main air blower outlet. Another unit which processes the same kind of feed did not have this strange behavior. We, therefore, think that the aforementioned can be related to inadequate air distribution.

WILLIAMS (KBR)

My colleague has already highlighted the impacts on the unit’s heat balance. As far as yield shifts go, with more improved crackable feedstock and a higher cat/oil ratio, one should expect an increase in conversion, which ultimately should yield a higher gasoline and LPG yield for the unit with corresponding reductions in light cycle oil, slurry, and coke at a cost of reactor outlet temperature. The LCO and slurry yields will crack into the gasoline/LPG range. The impact of coke yield will result from the improved feed quality, higher hydrogen content in the feed, reductions in metals content, and Conradson carbon residue content. One should also expect to the see the gasoline octane decline to some extent because the aromatic content in the naphtha is reduced as the aromatic content in the feed stream is saturated.

Operational problems for a full combustion regenerator include lower temperature operations which will impair the regenerator performance and can lead to poor combustion kinetics. These lower temperatures often result in higher afterburn conditions and higher carbon on regenerated catalyst. From a hydraulics standpoint, elevated catalyst circulation will be observed, resulting in lower catalyst slide valve differential pressures and elevated stripper flux rates.

As far as potential process solutions, the most favorable option is to increase catalyst activity. This can be done in multiple ways, such as increasing the catalyst makeup rate, changing the catalyst ingredient itself to increase the catalyst surface area, or even adjusting the rare earth content to help stabilize the unit. Another option is to increase the unit feed rate, but you should be mindful of the downstream processing units to ensure that they can handle the increased capacity to the unit.

If you do have a feed furnace, increasing the feed preheat temperature can generate some flexibility for the unit itself. In this case, a typical rule of thumb is to increase the preheat temperature by 15°F to 20°F. This change would typically generate about a 1°F increase in regenerator temperature. Another option is to recycle slurry oil to the riser itself. Before you do this, we recommend that you communicate with your feed nozzle licenser to ensure that the maximum solutes concentration to those feed nozzles is not violated.

If the FCC was formally processing resid to the unit and you have cat coolers, then you have the flexibility of turning them down to reduce the duty in order to regain the regenerated temperature itself. Because of the potential catalyst deactivation, KBR does not recommend long-term conventional torch oil operations or decreasing the stripping steam rate in order to restore the regenerator bed temperature.

LALL (UOP, A Honeywell Company)

Technology offered by UOP for delta coke-challenged operations is RxCat™, which decouples the traditional heat balance by recycling a slipstream of spent catalyst back to the reactor riser and permits variable amounts of recycled spent catalyst to achieve the minimum regenerator operating temperature. RxCat has been utilized in UOP’s new unit designs and revamp applications for low delta coke operations.

AVERY (Albemarle Corporation)

Most of my answers have already been covered by the previous panelist. I do want to say that when you have a lower delta coke on the catalyst side, you need to increase your activity. In other words, if you increase rare earth, then you should increase delta coke and hydrogen transfer.

We are fortunate to be a leader in hydrotreating and FCC catalysts. On the slide is an example showing a time when we used hydrotreating severity to make a higher activity FCC pretreater (hydrotreating) catalyst and changed the operating conditions on the hydrotreater. This slide shows an example of how when we increased hydrotreater severity, the gravity went from 25 to 27 and the sulfur went from 0.5 to 0.1. There are also other various effects to the feed. You can also see that we kept the catalyst effects the same except for the metals on the equilibrium catalyst, which is going to go down due to the higher severity hydrotreating.

The next slide shows you some typical yields. We have five different cases. The first column shows the base case where the regenerator temperature is 1276ºF with a conversion of 77ºC. By going to this more severely hydrotreated feed, the lower delta coke represented in the region goes down to 1233ºF and the cat/oil ratio goes from 6.1 LV% (liquid volume percent) to 7.2 LV%. You can also see an increase in the gasoline yield.

What happens when you go to these higher severity feeds is that you will hit some other kind of constraint. In the second column, you see that you are not hitting any constraint. One of the most common constraints for FCC units is catalyst circulation rate, which is the first added category. Wet gas compressor constraint is also common, as is minimum regenerator temperature. So in this case, we used the kinetic model to put in the constraints for catalyst circulation rate, wet gas compressor, or regenerator temperature. So based on the location of your constraint, your economics – which are represented on the very top on the gross margins – can vary quite a bit.

JACK OLESEN (Praxair, Inc.)

I believe that this topic was covered at the 2012 AFPM CAT conference. There was some discussion about torch oil and cutting back on stripping steam. Betsy Mettee answers this question well in the Answer Book. At Praxair, we have experience with refiners who have decided to cut back on their air blower rate, add oxygen to minimize the amount of nitrogen going through the regenerator, and reduce cooling due to that nitrogen in the air.

KEVIN PROOPS (Solomon Associates)

Christian, regarding your severe operation, am I correct in understanding that the main reason you were operating that severely is because the light cycle oil product has to make diesel ULSD (ultra-low sulfur diesel) specs?

SCHOEPE (Phillips 66)

Yes, that is true.

KEVIN PROOPS (Solomon Associates)

Thank you. I also want to point out that if you have an LCO sulfur constraint, there are hydrotreating technologies that allow you to make diesel sulfur without having to go quite so severe on cat feed sulfur. While Rik Miller was at Unocal, he wrote an excellent paper describing the situation when you severely hydrotreat feed and can actually end up making coke out of hydrogen you pumped in. So that may not be an optimum case.

On the plus side, our data shows that units which are severely hydrotreated (0.1 wt% sulfur or better) tend to see forgiveness of the hardware that is not optimal. For example, in units with sloped risers or units with feed nozzles that are not state-of-the-art, because you tend to run hotter feed, some of these hardware deficiencies are masked. The hydrotreated feeds tend to look better, across the board, just because these hardware issues become less relevant.

SCHOEPE (Phillips 66)

Processing severely hydrotreated feed (sulfur less than 50 ppm, nitrogen less than 50 ppm) in the FCC has significant yield benefits. The FCC conversion can be increased to over 90% and in some cases slurry can be recycled to extinction. Such a change in feedstock, however, can cause operational, reliability and environmental issues.

Operational Issues:

Due to the very low amount of coke precursors in hydrotreated feed, the regenerator temperature can decrease to such a degree, that coke is not burned efficiently off the catalyst in the regenerator. The low regenerator temperature will also increase the catalyst circulation rate which decreases the regenerator catalyst residence time and which further contributes to poor catalyst regeneration.

To increase coke yield in order to increase the regenerator temperature, the catalyst had to be reformulated for higher delta coke. Our FCC units have recycled slurry, used the start-up air heaters on occasion and/or torch oil or reduced stripping steam to keep the regenerator temperature high enough for adequate catalyst regeneration.

Processing hydrotreated feed increase the unit conversion, but it also increases the gas make from the FCC. The wet gas compressor and the absorber system have to be designed to process the increased gas load.

Reliability Issues:

Carbonate Stress Corrosion Cracking (ACSCC): Some sites have experienced significant amounts of Alkaline Carbonate Stress Corrosion Cracking (ACSCC) after switching to hydrotreated feed. This type of cracking can occur in piping and vessels in areas with residual stress. In most cases, the feed nitrogen to feed sulfur ratio is greater than 100 [N ppm / (wt% S *100)], the PH in the main fractionator and high pressure receiver water boot is above 8.5 pH and if the carbonate (CO3=) concentration is larger than 400 ppm. As a result of this type of cracking, new stress relieving guidelines were developed and the feed sulfur to feed nitrogen ratio is monitored on all Phillips 66 units as part of the Reliability Operating Limits (ROL).

Slurry System Reliability: Units designed for much larger slurry yield can see the catalyst content (ash content) in the slurry increase after switching to hydrotreated feed. The catalyst content in slurry increases because the reactor side catalyst losses remain constant while the slurry yield is much lower. The equipment in the slurry circuit has to be designed to handle the higher catalyst in slurry content.

Flue gas section reliability: If slurry is recycled to extinction, all catalyst fines leave the FCC through the regenerator with the flue gas. The catalyst fines collection system in the flue gas section has to be designed for the increased dust load.

Environmental Issues:

Particulate Emission: Units with electrostatic precipitators (ESP) can see an increase in stack opacity and particulate emissions as the SO2 content in flue gas decreases. The lack of SO2 in flue gas makes it more difficult to charge a catalyst particle. Some units have compensated for this effect by installing ammonia injection at the inlet of the ESP.

CO combustion: If the nitrogen in feed is reduced to such a degree that little or no NOX is made, the CO content in flue gas might increase. The data below shows the relationship between NOX and CO content in flue gas from one Phillips 66 unit. This data was previously published by Bill Henning during the August NPRA meeting in 2008. In order to keep the flue gas CO emission below 500 ppm, this particular FCC now injects ammonia into the air blower discharge in order to generate some NOX. Another unit that was processing the same feedstock did not have these CO emission issues. It is believed that better catalyst/air distribution might explain the different response to this feedstock change.

AVERY (Albemarle Corporation)

More and more refiners are hydrotreating (HT), or more severely hydrotreating, their FCC feed to meet fuel sulfur specifications. Hydrotreating the feed yields higher conversion, improved gasoline selectivity, lower octane, and lower delta coke.

Due to the lower delta coke, catalyst circulation rate limits can be reached. When this occurs, the refiner will need to increase the delta coke through higher catalyst activity, increase rare earth (delta coke increase), increase reactor pressure, increase slurry recycle, reduce stripping steam, or utilize torch oil. Reducing stripping steam and, in particular, using torch oil, should be avoided if possible. These methods introduce high hydrogen content combustibles that lead to localized exotherms. These effects will be covered on Question 81 in the Operations section.

Albemarle is a leading supplier in FCC and hydrotreating catalysts. These combined strengths give us the experience and opportunities to demonstrate the effects of changing FCC feed through increased hydrotreating severity. To demonstrate the effects, we have run a test case where the HT severity was increased by changing to a more active FCC pretreat catalyst and operating at higher temperatures over a shorter run length.

WILLIAMS (KBR)

Severe hydrotreating FCC feed [VGO (vacuum gas oil) feed with high Watson K-factor and low Conradson carbon content] will largely affect the FCCU heat balance by lowering delta coke, thus reducing regenerator temperature while increasing the catalyst to oil ratio for a constant Reactor Temperature.

As far as yield shifts go, a more crackable feedstock and higher cat-to-oil ratio will result in higher unit conversion with increases in gasoline and LPG and corresponding reductions in dry gas, LCO, slurry, and coke. Gasoline octane will be lower due to the reduction of aromatic content in the naphtha as more aromatic compounds in the feedstock are saturated. LCO and slurry yield will decrease as more will crack into gasoline and LPG range materials. The impact on coke yield is a result of better feed quality: higher hydrogen content, lower nitrogen, metals, Conradson carbon, etc.

Excessive high cat-to-oil ratios can create unit issues as catalyst circulations are increased at lower regenerator temperatures. For full combustion regenerators, low temperature operations will impair the regenerator performance which can lead to poorer combustion kinetics often resulting in higher afterburn, higher catalyst circulation and higher carbon on regenerated catalyst. One should determine whether adequate stripper residence time and catalyst slide valve differential pressure can be maintained at the increased catalyst circulation rates.

To address these issues, refiners have incorporated several options to increase regenerator temperatures while processing hydrotreated FCC feed. Often the best approach to addressing the low delta coke issue is to increase the catalyst activity. Several options to increasing catalyst activity include increasing catalyst surface area, rare earth content or catalyst addition rate. As e-catalyst activity increases, the amount of coke generated per pass through the riser increases and therefore increases regenerator bed temperature.

Another option is to recycle slurry oil to the riser. Most refiners elect to inject slurry recycle with the feed to the riser while others elect to inject the slurry in a separate nozzle. One should be mindful of the process issues when considering injecting slurry and feed the same nozzles. For long-term reliable operations, feed nozzles are design for a maximum solids handling. Proper feed nozzle design is essential for robust operations when processing streams with high solids content. In addition, on rare occasions, injecting slurry within the same nozzle can allows asphaltenes to drop out of solution and potentially plug the nozzle. KBR designs for injection the slurry mixed with the fresh feedstock. Finally, slurry recycle often increases dry gas make, so one should evaluate downstream systems to ensure the increase capacity can be handled. Increasing unit feed rates and/or feed preheat temperature are other options, if the unit has the flexibility.

Increasing the unit feed rate is favorable option if downstream processes can handle increase capacity. As far as feed temperatures, one should expect about a 1ºF increase in regenerator bed temperature for every 15ºF to 20ºF increase in feed temperature to the riser.

FCC units processing residue and equipped with catalyst coolers will be able to maintain regenerator temperature by adjusting catalyst cooling. Because of the potential catalyst deactivation, KBR does not recommend long-term torch oil usage using traditional torch oil nozzles or decreasing stripping steam rates to increase regenerator temperatures.

LALL (UOP, A Honeywell Company)

Hydrotreating of the FCC feeds has become more popular and widespread as refiners choose to remove more of the sulfur-containing contaminants in the feed to avoid post treating of the FCC products. Severe hydrotreating of the FCC feed promotes hydrogen saturation of the feed molecules, as well as removal of much of the sulfur, nitrogen and metal contaminants. FCC feed crackability is improved, yielding increased liquid volume conversions (approaching 90%) of valuable transportation fuels (gasoline and lighter) and reduced dry gas yields. One of the main challenges in processing severely hydrotreated feeds is the resulting low delta coke operation and low regenerator temperatures. We have observed regenerator temperatures dropping to 1220°F (660°C) and lower the regenerator can become limiting in achieving satisfactory coke combustion kinetics to the extent excessive afterburning leads to regenerator internals’ temperature reaching design limits. Maintaining the unit within “acceptable” heat balance range therefore becomes a major consideration. A number of operational adjustments can be undertaken to offset low regenerator temperatures including increased reactor temperature, increased unit catalyst activity, suboptimum stripping steam rates, and recycle of heavy cycle oil and/or slurry streams. Considerations to increasing the cutpoint/endpoint of the FCC feed should also be given as should elimination of 650°F- boiling range material (light gas oil) in the feed.

Some refiners have resorted to using continuous firing of the air heater or torch oil. Further options include a fired feed heater. The economics of fired feed heater versus continuous operation of the air heater should be evaluated on a case-by-case basis. An alternative technology offered by UOP is its RxCat™ technology, which decouples the traditional heat balance by recycling a slip stream of spent catalyst back to the reactor riser and permits variable fraction of spent catalyst recycle to achieve the desired minimum regenerator operating temperature. UOP utilizes RxCat™ technology in its new unit designs and revamp applications for low delta coke operations.

A risk of carbonate stress corrosion cracking (CSCC) exists in certain areas of FCC units running heavily hydrotreated feeds having sulfur levels below 1,000 wppm (weight parts per million) or 0.1 wt% (weight percent). This leads to more basic sour water in the 9 pH to 10 pH range due to a higher ratio of feed nitrogen-to-sulfur than exhibited by non-hydrotreated or less severe or mild hydrotreated feeds. UOP specifies “special” post-weld heat treatment (PWHT) requirement for units with feed sulfur ≤ 0.1 wt%. Application of “special” PWHT includes all of the wet gas compressor system in hydrocarbon sour water services (piping and equipment) from the top half of the main column through the absorbers and stripper in the gas concentration unit.

ROSANN SCHILLER (Grace Catalysts Technologies)

Severe hydrotreating of the FCC feed offers a mix of benefits and challenges for the typical FCC operator. Benefits can include dramatically lower sulfur content in products, lower flue gas SOx (sulfur oxide) or NOx, and improved yields; however, the price for these benefits is often a dramatically lower coking tendency of the feedstock. Many units which operate with severely hydrotreated feed struggle to make enough coke to maintain heat balance within unit circulation constraints. In addition, one may see slurry yield decrease to minimum acceptable levels, increased bottoms circuit fouling due to the lower volumes, heat removal limits in the gas concentration units due to higher volumes of light and wet gases, and lower overall product olefinicities. To counteract that challenge, several operating changes are possible.

These include:

• Use of Higher Activity FCC Catalyst: For units which will run severely hydrotreated feed for long periods of time, reformulation to a higher activity FCC catalyst is often the most cost-effective means of increasing the e-cat activity and bringing the unit into heat balance.

• HCO (heavy cycle oil) Recycle: HCO can be recycled to the reactor to aid in additional coking and to reduce the heat requirement on the reactor side. This strategy causes an economic penalty when the unit is operating at maximum fresh feed rates, as fresh feed will need to be backed out.

• Use of Regenerator Torch Oil: Torch oil is often used in the regenerator to add additional heat. However, the severe hydrothermal environment, coupled with the high velocities near the injection point(s) creates a very challenging environment for FCC catalyst particle integrity. In addition, many refineries use LCO material as torch oil, which is a substantial hidden cost.

• Use of Fired Air Heater: Some units will activate the fired air heater to reduce the heat requirement in the regenerator. In some cases, this air heater does not offer a great deal of flexibility in its duty, so its use can “swing” the unit from very low regenerator temperatures to much higher regenerator temperatures.

• Reduction in Stripping Steam: Some refiners elect to reduce stripping steam, sending some unstripped hydrocarbon with the catalyst into the regenerator. While this is a viable source of heat on the regenerator side, it results in a net loss of total liquid volume, and unit profitability can suffer. Additionally, the hydrogen-rich unstripped hydrocarbons burn rapidly creating local hot spots which can deactivate the catalyst.

• Higher FCC Catalyst Addition Rates: For units that process severely hydrotreated feeds intermittently, catalyst reformulation may not be practical. However, a short-term increase to the FCC catalyst addition rate can increase the equilibrium activity and bring regenerator temperatures up, which will allow the unit to maintain heat balance.

Each of these methods should be evaluated for both its feasibility in a given refinery and for its economic impact to the plant. It is often the case that higher catalyst addition rates, or a high activity catalyst reformulation, are the most economically favorable option.

MARK ANDERSON (ThioSolv, LLC)

One change to expect is that the production of ammonia to the sour water will increase substantially. Each ton of ammonia in the sour water increases the load on the Claus by four times it weights in H2S. Claus capacity is not measured by the rate of sulfur captured; the equipment is sized for the gas flow, not the sulfur rate, and H2S in sour water produces as much tail gas flow as about three times as much H2S alone. To deal with the added load on SRU, consider diverting the sour water stripper gas to a SWAATS (sour water ammonia to ammonium thiosulfate) process to convert it to ammonium thiosulfate fertilizer, freeing up Claus capacity for the incremental H2S produced from the VGO hydrotreate.

SCHOEPE (Phillips 66)

We do not have much experience with continuous torch oil firing. We do have one unit that fires torch oil if the bed temperature drops below 1250ºF. However, that unit is not set up for slurry recycle. So, on most units, we prefer slurry recycle over an operation with torch oil. In one case, after an extended use of the inline air heater, a Phillips 66 unit actually caused mechanical damage after switching to hydrotreated feed.

Torch Oil: When using torch oil, your emissions and catalyst fines generation will increase. You might have noticed that during and after start-up, as it always takes a few days for the fines to work themselves out of the system.

Continuous Air Heater Operation: The equipment is typically not designed for continuous operation. However, if it is decided to use it as such, it would not be difficult to design the air heater for this operation.

Other Considerations in Our Tech Network: We discussed the case when one unit was starting up and the air blower tripped, but the torch oil was left on. You can imagine that the restart ended up being very exciting when the torch oil lit up during the restart. If you intend to operate that way, an automatic shut-off on the lower air flow should probably be considered as part of the SIS.

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LALL (UOP, A Honeywell Company)

Use of continuous torch oil and/or air preheater firing can occur in numerous instances, such as abnormal circumstances following unit upsets, safe park holding modes, or during operations when addressing low delta coke operation with very low Conradson carbon residue feeds or hydrotreater feeds. In addition to high air grid exit velocities, when increasing the risk of erosion and catalyst attrition through continuous air heater firing, the air heater flame pattern should be monitored and controlled by adjusting the air splitting damper to prevent damage to the internal refractory lining.

If heater firing is to be considered on a continuous basis, then the air grid should be designed for jet velocities below 200 fps during operation, with and without the air heater at all times. As Christian already described, the continuous torch oil firing is not good because excessive heat release can sinter catalyst. If it is necessary to use torch oil, care should be taken to properly atomize the oil. A high concentration of oil in one spot can result in hot localized temperatures being undetected by the regenerator temperature indicator. More even distribution of torch oil in the regenerator would be desirable by using more torch oil nozzles.

WILLIAMS (KBR)

KBR recommends limiting conventional air heater and torch oil firing as extended periods will only accelerate catalyst deactivation and catalyst attrition. However, on rare occasions, we have witnessed a client who has elected to utilize torch oil for an extended period as a primary approach to address problems with the upstream units where the FCCU feed become lighter and also to maintain heat balance for that period of time. In another case, the client elected to hold the regenerator temperature for extended periods while addressing the processing issues in the VRU (vapor recovery unit).

A traditional alternative approach when the feed becomes lighter is that the plant personnel, instead of going with torch oil, may elect to increase the endpoint on the feed by making adjustments at the VDU (vacuum distillation unit). Recycling slurry would be another option to do this. Slightly reducing the hydrotreating severity to increase the coke make precursors may help restore the temperature in the regenerator itself.

KBR has a non-traditional alternative for mitigating the catalyst damage associated with conventional torch oil. We have developed a system for distributing liquid fuel in the regenerator. This system was initially commercialized for our KBR SUPERFLEX™ process. It also can be utilized for severe hydrotreating operations. Since its inception, KBR has adopted this technology for use in conventional FCC units with particular list return configurations. So, before you consider this, we have to evaluate your configuration to see if these configurations will be applicable for you.

In addition to the system for liquid fuels, a system for firing the regenerator with fuel gas, which is alternately lower-cost fuel, has also been commercialized. So, for this situation of severe hydrotreating, this approach of additional fuel gas firing in the regenerator is a non-traditional alternative a refiner could consider.

PIMENTEL (CITGO Petroleum Corporation)

We have some experience with continuous torch oil operation for about three to seven days. Christian already covered most of the reasons, so I will only add a few more. First, a very light FCC feed was coming from a crude oil unit at start-up. That unit was slopping the distillates to the FCC tank rather than to the slop oil system. Another reason could be very inactive FCC catalyst coming from an extended start-up operation and/or from a standby operation due to fractionator emergency work. Then again, torch oil should be your last resort. Alternatives were already covered: increase vacuum cutpoint, increase severity in the unit, recycle slurry, or even detune your stripper or feed nozzles.

Consequences have also already been covered. Again, continuous torch oil firing increases the catalyst attrition and deactivation due to localized hot zones around any of your torch oil nozzles, as well as causes incremental fines generation due to increased exit velocity from the air grid nozzles.

AVERY (Albemarle Corporation)

I agree with the comments already discussed and have just two more points. We have seen some refiners using torch oil not just for days, but for months on end. So it has happened, and it does happen right now. Also, speaking as a catalyst supplier, if you want to keep doing it, it is fine with me.

LALL (UOP, A Honeywell Company)

This situation can arise in numerous circumstances. It can arise during unit upsets or safe park holding modes, in low delta coke operations associated with clean (low Conradson carbon) and hydrotreated feeds, with refinery crude slate changes or crude and/or vacuum distillation operating changes. Some refiners have resorted to using continuous firing of the air heater or torch oil. In addition to higher air grid jet exit velocities increasing the risk of distributor jet erosion and catalyst attrition, the air heater flame pattern must be monitored and controlled by adjusting the air splitting damper to ensure no damage to the air heater internal refractory lining occurs. There have been many recorded instances of hot spots and refractory damage occurring to the air heater internal refractory lining during start-ups. If air heater firing is to be considered on a continuous basis, the air grid should be designed for jet exit velocities below 200 fps during operation with and without the air heater.

Continuous torch oil is generally not desirable because the excessive heat release can sinter catalyst, resulting deactivation. When it is necessary to use torch oil, care should be taken to properly atomize the oil. A high concentration of oil in one spot can result in hotter localized temperatures undetected by the regenerator temperature indicators. A more even distribution of torch oil into the regenerator catalyst is therefore desirable. We have seen operations where torch oil was fired continuously over a seven-day period to maintain a regenerator in “warm” condition (regenerator dense bed temperatures of 1,025°F to 1,100°F) while the unit was in a safe hold position without any noticeable impact to catalyst activity.

SCHOEPE (Phillips 66)

Phillips 66 has very little experience with continuous torch oil firing. One unit fires torch oil when the feed gets so light that the regenerator temperature drops below 1250°F.

Operation with torch oil sinters catalyst and generates catalyst fines. Many units see higher amounts of catalyst fines during the first few days after start-up. It also increases CO and NOx in flue gas. Poorly designed torch oil systems can cause mechanical damage.

Most sites do not tie the torch oil into their safety instrumented system. If a unit fires torch oil continuously, then consider a torch oil trip on low airflow. For example, if the main air blower trips, the catalyst could become oil soaked and cause damage if the oil ignites during unit restart.

One Phillips 66 FCC unit experienced damage in the spent catalyst/air distributor after firing the air preheater continuously for several months. The air heater needed to keep the regenerator temperature high enough after this unit had switched to hydrotreated feed.

PIMENTEL (CITGO Petroleum Corporation)

We have limited experience with continuous torch oil operation (for one to three days maximum) for several reasons. First, very light FCC combined feed from crude start-up operations slopping to FCC feed tanks or very inactive FCC catalyst due to extended start-up operations leads to a relatively low regenerator temperature (<1250°F). Another reason for operating on torch oil is prolonged standby operation of the reactor/regenerator section to perform maintenance activities in the workup section; for example, the fractionator or WGC. The use of torch oil should still be the last resort to keep the regenerator hot. Preferred options are include increasing FCC preheat/severity and making the feed heavier by achieving a deeper cut in the vacuum unit or recycling slurry oil to the riser. The effect of extended torch oil operation is accelerated catalyst activity decline due to the localized hot zones adjacent to the torch oil nozzles. Prolonged air preheater firing may also increase fines generation due to increased nozzle exit velocities.

AVERY (Albemarle Corporation)

Yes, there are some units practicing continuous torch oil and/or continuous firing of the direct-fired air heaters (DFAH). This practice has been used in an attempt to compensate for very low delta coke operations in order to keep the regenerator hot enough to maintain control of the catalyst circulation. Neither practice is desirable, especially long term. Other means of increasing delta coke, such as complete CO combustion, adding a heavy feed component, or utilizing a less coke selective catalyst should be investigated. Burning torch oil does not typically heat the catalyst bed uniformly, leading to thermal gradients in the dense phase and increased catalyst deactivation. If the dense phase level is not carefully controlled, significant afterburn can occur, as well as damage to cyclone diplegs. Continuous firing of the DFAH is probably worse, as there are certainly safety concerns with flameouts, overfiring, and more. Potential damage due to thermal stress to the combustion air distributor is also possible, especially when the distributor temperature cycles. Also, increased catalyst deactivation can occur due to non-uniform heating.

WILLIAMS (KBR)

Continuous torch oil firing, though normally only used during start-up, has been practiced. On rare occasions, Operations has elected to maintain converter temperatures with torch oil firing for several days while Maintenance teams address downstream equipment issues. During upstream operational upsets where the feed delta coke is reduced, Operations may also elect to introduce torch oil to maintain unit heat balance. KBR recommends limiting conventional torch oil firing as extended periods only accelerate catalyst attrition and deactivation. To mitigate the catalyst damage associated with conventional torch oil firing, KBR has developed a system for distributing liquid fuel in the regenerator which was initially commercialized in the KBR SUPERFLEX™ process. Since its inception, KBR has adapted this technology for use in conventional FCC units. A patent pending version is also available for use in conventional FCC operations. In addition to this system for liquid fuels, a system for firing the regenerator with fuel gas, which is often a lower cost fuel, has also been commercialized. Continuous air heater firing has been utilized for continuous support of the heat balance, but this practice can have an adverse impact on the velocities through the regenerator air distributors which can lead to catalyst attrition, as well as the practical issues associated with monitoring the heater firing.

ROSANN SCHILLER (Grace Catalysts Technologies)

The use of “dry circulation” is a common event in many refineries. Often upstream or downstream problems in a refinery can cause the FCC to pull feed, and during these times, many units elect to continue “hot” catalyst circulation to avoid a complete thermal cycle on the FCC. Typically, these events are short-lived (up to about one week). During this time, refiners may add fresh, or more typically, equilibrium catalyst to the unit to maintain catalyst bed levels. Using torch oil creates a severe hydrothermal environment, with temperatures at the nozzle tips often eclipsing metallurgical recommendations, and velocities well over 100 fps.

These nozzle tips are often buried in the dense bed of the regenerator, causing areas of severe stress on the catalyst particles. Attrition and catalyst deactivation are the outcomes of this activity.

The use of torch oil or fired air heating while feeding oil is less common. In units that process severely hydrotreated feedstocks, operators often use torch oil to create additional heat in the regenerator to maintain the heat balance. This operating strategy often comes at a high cost, as many refineries use LCO material for torch oil. A more economically attractive option is to add higher amounts of FCC catalyst and to pursue a reformulation to higher fresh FCC catalyst activity.

We have noted one refinery that, after a turnaround, started up on a substantially lighter feed. This unit started up using the fired air heater and did not turn it off, as the new feed made substantially less coke than the pre-turnaround feed. Catalyst addition rates were increased, and eventually, the unit reformulated to a higher activity catalyst. This reformulation, along with other moves in the operation, allowed them to discontinue the use of the fired air heater.

Another refinery with a similar short term “lightening” of the feedstock elected to fire torch oil to maintain heat in the regenerator. This unit continued this practice until they shut down for a planned turnaround. We observed increased fines generation, and complete destruction of the torch oil nozzle tip. After their turnaround, the refiner reformulated to a more active catalyst to remove their dependence on torch oil to keep the regenerator hot

PIMENTEL (CITGO Petroleum Corporation)

We have some experience recycling BBs (butane-butylenes) from the gas plant back to the FCC reactor, and even some C5s. I will start by saying that this is a very unusual operation. Its sole purpose is actually to reduce the production of the BBs or the C5s due to limitations in downstream units, such as alkylation, treating, or their inability to blend this material into the gasoline pool as a result of RVP (Reid vapor pressure) limitations. So the purpose was actually to destroy some of these materials rather than produce propylene. This is not a good alternative to increasing your propylene production. Better options are, of course, to use ZSM-5 additive or increase severity.

Our experience is with recycling BBs, along with gas oil, into the feed nozzles. We found that feed dispersion improved and delta coke reduced because of the cooling effect of BBs vaporizing in the riser. We found a very low conversion per pass – 10% or less – to propylene or lighter. However, we did find a sharp decrease in the olefinicity of the C4s and C5s. In our refinery, we typically have about 55% olefins in the BBs and the 45% iso- and normal butane. After a while, these percentages were the opposite with this operation. We soon found more paraffins than olefins, suggesting that only the olefins would react under this environment; the paraffins will remain unreactive.

If you require higher conversion of this material, we recommend that you install a special feed nozzle below your gas oil nozzles in the riser. That way, you will probably achieve a reactor mixed temperature over 1200ºF, which is required in order to crack light paraffins.

LALL (UOP, A Honeywell Company)

The practice of recycling heavy C5-bearing streams, such as LCN (light coker naphtha), has long been practiced by refiners with the general intent of achieving incremental gains and valuable C3 and C4 olefins. Some refiners have also been known to route or dispose of very high sulfur-bearing naphtha, such as coker naphtha, where no alternative deposition exists at the refinery. UOP is currently investigating conventional and non-conventional solutions, including recycle streams for maximizing propylene.

SUBHASH SINGHAL (Kuwait National Petroleum Company)

Does the recycle of C4/C5 streams to FCC impact the fresh feed to the unit? Does it impact the total feed to the unit? For instance, if you recycle any stream, does the feed to the unit come down?

PIMENTEL (CITGO Petroleum Corporation)

It could, although it was not our experience. We were not limited in the hydraulics of the feed system, but it will depend on where you inject the BBs. In our refinery, we injected the BBs upstream of the feed heater and downstream of some of the heat exchangers. So, you will have vaporization there. Can you take that additional ΔP (delta P; differential pressure) in your heater, or do you have a fired heater for your feed? Those are the kinds of questions you have to ask. If you have a marginal pressure drop or hydraulic limitations, then yes, it will surely limit your capacity.

LALL (UOP, A Honeywell Company)

To add to Sergio’s comments, look at your cyclone velocities. Clearly, putting in some light material and cracking will increase the velocity in the cyclones; so be aware of that.

DR. PAUL DIDDAMS (Johnson Matthey Intercat)

Your observation about the C4/C5 olefinicity decreases is not likely to be due to olefin cracking and paraffins being preserved. C4 and C5 olefins are not cracked via a carbenium ion mechanism in the FCC because the C2 carbenium ion intermediate required in the mechanism is unstable; therefore, the reaction does not occur catalytically. It is much more likely that your olefins are subject to hydrogen transfer that saturates them through to the paraffins. However, if you increase severity in the FCC by getting the reactor temperature above about 565°C, and if you use a lot of ZSM-5, then you will get into a regime where the C4/C5 olefins can oligomerize temporarily and then re-crack to lighter olefins. But this really only happens under quite severe conditions with high levels of ZSM-5 present.

DILIP DHARIA (Technip Stone & Webster Process Technology)

I agree with Dr. Diddams’ comment. We have seen, and have already said in our Answer Book response, that recycling C4 and LCN results in the benefits of increased propylene in our DCC (deep catalytic cracking) units where severity is high; for instance, when the temperature is at 565ºC and a lot of ZSM-5 additives are present. We suspect that the oligomerization which follows happens prior to cracking, which increases the propylene yield.

JOSEPH McLEAN (BASF Catalysts LLC)

Again, talking about slurry recycling in the last question and LCN recycle here, no one mentioned the heat balance. If you are air blower-constrained, then any recycle you put back in the riser is an extra load system. So if you are air blower-limited and increase the recycle of any kind, you may need to back out fresh feed or change something else to be able to live with that change. Always keep the heat balance effects of these things in mind. You can talk about yield effects, crackability, and olefinicity changes. These situations are all true, but also keep in mind that you must have some air to make these reactions happen.

PIMENTEL (CITGO Petroleum Corporation)

We have limited experience with the recycle of light hydrocarbons (C4/C5) from the gas plant back to the FCC. The main reason to try this operation should be limitations in downstream units (alkylation or treating) or the inability to blend these streams in the gasoline pool. If the goal is to boost propylene production, the preferred option should be to increase FCC severity or the use of ZSM-5 additive. In our experience, the C4/C5 stream was recycled to the riser in combination with the gas oil to the feed nozzles. As expected, there is an increase in cat/oil due to the cooling effect of vaporizing the light materials and some improvement in feed atomization. We found a relatively low conversion per pass (about 10% conversion to C3s and lighter) and a sharp decrease in the olefinicity of the C4/C5 cut (from 55% to 45%), which suggests that mostly the olefins react under these conditions. In order to achieve higher conversion or crack light paraffins, a separate feed nozzle located below the gas oil injection in the riser is required.

LALL (UOP, A Honeywell Company)

The practice of recycling heavy C5 bearing streams, such as LCN, has been practiced by refiners with the general intent of achieving incremental gains in valuable C3 and C4 olefins. Some refiners have also been known to route or dispose of very high sulfur bearing naphtha where no alternative disposition, such as coker naphtha, exists at the refinery.

DILIP DHARIA (Technip Stone & Webster Process Technology)

Technip Stone &Webster has licensed a high severity deep catalytic cracking unit in the Middle East that recycles C4s and LCN to the riser with the main objective of increasing propylene yield. It should be noted that only the olefinic portion of these streams are reactive and the increase in propylene yield was confirmed.

BROOKS (BP Refining)

I will start by saying that everyone should reference Question 84 of the 2011 NPRA Q&A because this question is an exact replica of what was answered by BP and Western Refining last year. To very briefly recap what was covered, from the BP perspective, we see flashpoints in the 140ºF to 220ºF range. We are typically able to meet the flashpoints greater than 200ºF with our internal stripping rings, which we have on the majority of our cats. We do have some units with small external stripping towers, but most of them have internal stripping stream rings that provide enough of an upgrade to the flashpoint that we can typically meet our storage recommendations.

In addition to the points referenced in last year’s question, API RP 2003 recommends that you store all materials at 15ºF below the flashpoint if they are in fixed roof tanks. The one consideration on slurry oil storage is that there is a rather narrow safe storage temperature because you do not want to rundown slurry at temperatures too low due to difficulties with flowing properties, which means you want it as close to the flashpoint as possible. You may have some pour point and viscosity problems if you try to pump the slurry oil at temperatures too low, which makes it a bit more difficult to meet some of these flashpoint regulations.

An additional note is that there was a detailed response from Marathon Oil at the 2008 NPRA Q&A. At that time, they indicated having seen external strippers which were much more efficient. FCCs can use much less steam to get the same flashpoint upgrade with external strippers than would be required on an internal stripping steam ring.

A final thought is that low flashpoint issues may not necessarily just be due to a need for additional stripping. If you are having issues, then you should also look at other possible low flashpoint causes, such as poor fractionation problems, thermal degradation in your slurry bottoms, slurry exchanger tube leaks, or flushing oil that is coming in with a low flashpoint. This is another consideration when you are reviewing your storage temperatures and determining how to meet your flashpoint for your slurry oil storage.

SCHOEPE (Phillips 66)

When I surveyed Phillips 66 units, I found a large range in flashpoint for slurry. For example, one of the units that does have a steam ring in the main fractionator is able to keep its slurry flash between 190ºF and 210ºF, just with steam injection to the fractionator. A second unit, also with a steam distributor, has a flash of between 120ºF and 170ºF, but it is rate dependent. So, at a low rate, this unit gets a slurry flash of 170ºF; at higher rates, the slurry flash drops down to 120ºF. A third unit struggled with that issue and recommissioned an external slurry steam stripper, which was very successful. This unit is now able to keep the flash greater than 220ºF.

We have the same rundown guidelines as BP. At one of the units, the chemical vendor uses an H2S scavenger to keep the H2S content in the tank below 10 ppm.

LALL (UOP, A Honeywell Company)

In a properly operated FCC main fractionator, the slurry or flash can usually be increased to approximately 150ºF to 160ºF without any modification to the system. When slurry flashpoint specifications exceed this range, the addition of a stripping steam distributed to the main column bottom will deliver a small flash improvement of approximately 10ºF to 14ºF. To achieve slurry flashpoints of about 175ºF, either a side cap stripper or a vacuum flasher can be added to permit flashpoints in the range of 230ºF to 240ºF. A low flashpoint is not typically an issue of poor column fractionation; rather, it is due to excessive thermal cracking in the fractionator bottoms. If there is tray damage to the column internals, then a large quantity of LCO could be dumped into the bottoms and sub-cool it. As a result, tray damage can depress the flashpoint.

HOWARD LEE (BP Products North America Inc.)

I am Halle’s colleague, and I want to say that you did a good job with the response. I just realized that we did not get to discuss this question with Halle. I want to ask the panel and the audience if anyone has thought about the pumparound rate, as far as this question. We have units with pumparound rates on the magnitude of fresh feed rate; in other words, fairly large volumes. We have other units running lower pumparound rates; for instance, 6 gpm/ft2 (gallons per minute per square foot). So I have always wondered if a very high pumparound rate had to do with absorbing light ends down to the bottom and if it is affected by it. Has anyone considered that parameter or made any observations?

PIMENTEL (CITGO Petroleum Corporation)

Yes, absolutely. You are right for two reasons. First of all, a very high pumparound rate will surely carry more light material back into the fractionator bottoms because they are contacting with the light gases coming from the reactor, which will reduce the residence time in the bottoms compartment. So your steam will probably have a lower efficiency when you run at higher pumparound rates.

BROOKS (BP Refining)

This question is identical to a question answered during last year’s NPRA Q&A. Please reference Question 84 in the 2011 NPRA Q&A Answer Book for the full response. BP and Western Refining provided responses on this question during that session. This is a brief summary of their responses:

• BP’s typical slurry oil flashpoints range from 140°F to 220°F.

• BP has multiple units that meet flashpoints of greater than 200°F with internal steam stripping rings.

• Some units use small external stripping towers (less than 10 trays).

• Other units use internal stripping steam rings below the liquid level in the base of the main fractionator. This ring is typical of a slurry pool quench system, but it has been also shown to be somewhat effective at stripping the DCO (decanted oil) product and increasing its flashpoint.

• BP has performed stripping steam tests that confirm higher flashpoints at higher steam rates.

• The effect of internal stripping rings on flashpoint is highly dependent on the steam distribution.

• Too much internal stripping steam can cause issues with bottoms level indication.

• Our storage temperature guidelines specify temperatures below slurry flashpoint temperatures.

• This question is similar to another question addressed during the 2008 NPRA Q&A which included detailed responses from Marathon.

• Per documents from the asphalt and chemical cleaning industry, volatile organic compounds (VOCs) can be released after processing. The levels of combustibles and H2S in the vapor space can increase over time depending on the storage temperatures.

Additional considerations around DCO storage are as follows:

• In most cases, DCO is stored in un-blanketed, fixed roof tankage, thus the DCO needs to be stored below its flashpoint temperature.

• API RP 2003 recommends that the storage temperature be at least 15ºF below the flashpoint.

• The safe storage temperature range is typically very narrow due to pour point and viscosity concerns around pumping and solids settling in DCO streams.

• Based on the 2008 Q&A Marathon response, external DCO strippers required 10% to 50% of the steam rates necessary to see the same flashpoint improvements with internal stripping rings.

• When investigating low flashpoint issues, consider some of these possible causes: poor fractionation, thermal degradation, slurry exchanger tube leaks, and low flashpoint flushing oil.

LALL (UOP, A Honeywell Company)

This is the same question posted in the 2011 FCC Q&A (see Question 84). UOP’s additional comments are that in a properly operating FCC main fractionator, the slurry oil flash can usually be increased to approximately 150°F to 160°F (65°C to 70°C) without any modifications to the system. When slurry flashpoint specifications exceed this range, the addition of a stripping steam distributor to the bottom of the main fractionator will deliver a small flash improvement of approximately 10°F to 18°F (6°C to 10°C) to a flashpoint range of 165°F to 175°F (75°C to 80°C). To achieve slurry flashpoints over 175°F (80°C), either a sidecut stripper or a vacuum flasher can be added, capable of achieving flashpoints around 230°F to 240°F (110°C to 115°C). Low flashpoint is not typically an issue of poor column fractionation; rather, it is due to excessive thermal cracking in the fractionator bottoms. However, if there is damage to the column internals, a large quantity of LCO could be dumping into the bottoms and subcooling it. As a result, tray damage can suppress the flashpoint of the fractionator bottoms. UOP recommends that the rundown tank temperature always operate below the flashpoint by providing adequate rundown cooling to meet these specifications.

SCHOEPE (Phillips 66)

Slurry flashpoint differs significantly from unit to unit. One Phillips 66 unit is able to achieve a flashpoint of 190°F to 210°F by adding stripping steam to the bottom of the main fractionator. A different unit with stripping steam in the main fractionator sees a correlation of slurry flashpoint with respect to FCC feed rate. At low FCC rates, a flashpoint of about 170°F can be achieved while the flashpoint can drop to 120°F at high rates. A third unit recommissioned an external slurry stripper after struggling with this issue. This unit is now able to increase the slurry flashpoint to 220°F. Slurry typically has to be cooled 15°F to 20°F below the flashpoint. One site controls the H2S in the vapor space of the tank down to 10 ppm by using a H2S scavenger.