Question 96: What is the CO boiler start-up and shutdown sequence with respect to the FCCU start-up and shutdown timing? What are the reasons for this sequence?
BROOKS (BP Refining)
As I mentioned briefly in an earlier question, most of our FCCs with CO boilers start-up with the CO boilers bypassed. If we run partial-burn on any of these FCCs, we tend to start-up in full-burn at reduced rates. Once the feed is in the unit and considered stable, most sites will cut into their CO boiler with the process flow. Our partial-burn units will then move back into parital-burn. Basically, the CO boilers are started up while the FCC is routed to the bypass stack. As you start up the CO boiler, you fire it initially on fuel gas. Then when the FCC flue gas flow is brought back into the CO boiler, you reduce the fuel gas firing accordingly. We do this in order to prevent running directly through the CO boiler when transitioning from full-burn to partial-burn, which can cause issues with a combustible environment.
Shutdown sequences are similar. We shut down the unit, move all of our partial-burns into full-burns, take flow out of the CO boiler, and then route it to the bypass stack. We have some units that rely on their CO boilers to make steam for the rest of the refinery. Thus, we will go out the bypass sack, isolate it with a blind, and then continue running it online with fuel gas. It is fairly basic, but most of our CO boilers are run that way.
SCHOEPE (Phillips 66)
In our units, the CO boiler is one of the first pieces of equipment that is started and one of the last pieces of equipment taken down, unless you have a flue gas scrubber. If you do have a scrubber, you will usually start the scrubber first and then the CO boiler. In some sites, the main air blower partially depends on the steam supply from the CO boiler. We already went through the whole vapor line scenario. If you have a valve, you can then go directly to catalyst loading and oil-in. If not, then shut down all of this equipment, pull the vapor line blind, and start up the equipment again.
In terms of a shutdown, which is shown on the next slide, our units typically de-energize the ESP first. After that, catalyst is circulated to decoke the catalyst. The catalyst is then unloaded, and the air blower is shut down. Shut down your CO boiler last. That way, you will still be supplying steam to the refinery and your main air blower while minimizing potential CO emission during this catalyst cleanup step.
LALL (UOP, A Honeywell Company)
Although UOP does not dictate when the CO boiler is to be started up on auxiliary firing, our procedure specifies that the FCC is to be started up in complete combustion with flue gas diverted to the bypass stack. The flue gas is diverted to a CO boiler only after the feed has been introduced to the FCC and the regenerator operation has transitioned from complete combustion to stable partial-burn. UOP considers this to be the safest way for the following reasons: 1. There is a minimal chance of the presence of unburned hydrocarbons being in the flue gas as a result of unsuccessful lighting of the torch oil. 2. The feed is routed to the FCC, and the FCC operation and pressure balance is steady. In the event of a pressure upset, there is the potential of a reversal, which could introduce a significant concentration of hydrocarbons into the CO boiler and cause a major upset. 3. The transition from full- to partial-burn is very dynamic and may be unpredictable. UOP’s preference is to not swing from the bypass to the CO boiler during this unstable situation until after feed is introduced to the riser at low rates and after the regeneration has transitioned from full-burn to stable partial-burn. Some refiners may have an ESP or wet gas scrubber downstream of the CO boiler. They must run these whenever feed is in the unit, and they could be forced to run through the CO boiler in this situation; but from a safety perspective, it is not preferred.
PIMENTEL (CITGO Petroleum Corporation)
Our experience is very similar. Our CO boiler start-up and shutdown is relatively independent from the FCC. Actually, we start the CO boiler in advance of the FCC mainly because our air blower turbine requires the steam to run at full capacity. To do this, of course, your boiler must be equipped with an adequate number of auxiliary fuel burners. For the same reason, the FCC shuts down in advance of the CO boiler. The boiler can be kept in operation through the bypass, as was already explained. We shut down later for scheduled work. If there is no work scheduled for the CO boiler during the turnaround, it can continue to run isolated through the entire FCC outage.
MICHAEL LEMESHEV (Zimmerman & Jansen)
At some point, everyone on the panel indicated that during the start-up, you begin to divert some flow into the CO boiler. Is that correct?
BROOKS (BP Refining)
We do not divert any flow to the CO boiler until the FCCU unit is started up.
BROOKS (BP Refining)
BP sites with CO boilers typically start their FCCUs with the CO boilers bypassed. Our partial-burn units will start the unit up in full-burn operation (at reduced feed rates). When feed is in the unit and the unit is considered as stable, sites typically bring the CO boiler into the process flow. Partial-burn units then move from full-burn back to typical partial-burn operations. The CO boiler is typically started up on fuel gas while the FCCU flue gas is routed to the bypass stack. Fuel gas is cut back as the FCC flue gas is routed through the CO boiler. The CO boiler must be fired with fuel gas before the FCC is brought back into partial-burn service in order to avoid an explosion risk. Shutdown sequences are similar. Partial-burn units are brought into full-burn operations (at reduced feed rates) before the CO boiler is taken out of FCC service. Some of our units rely on the CO boiler to provide steam to the refinery. These units typically increase fuel gas firing when the FCCU is routed through the bypass stack on shutdown.
SCHOEPE (Phillips 66)
The start-up sequence is different for units with electrostatic precipitators (ESPs) and units with flue gas scrubbers. Units with ESPs typically start the CO boiler first while units with flue gas scrubbers start the scrubber before the CO boiler is started. Some sites need the steam from the CO boiler to drive the main air blower turbine. After the CO boiler start-up, the main air blower and the in-line air heater are started and the unit is heated for refractory dryout. After refractory dryout, the start-up paths diverge for units with vapor line isolation blinds in comparison to units with vapor line isolation valves.
Units with vapor line isolation blinds steam out the reactor and then shut down the main air blower, the inline air heater, and the CO boiler in preparation for pulling the vapor line isolation blind. After the isolation blind has been pulled, the CO boiler the main air blower and the inline air heater are started up again and the regenerator is heated in preparation for catalyst loading. Units with a vapor line isolation valve simply keep the CO boiler, the main air blower and the in-line air heater running and proceed directly from refractory dryout to catalyst loading.
Just before the introduction of torch oil, the CO boiler combustor temperature is maximized in order to minimize the CO emission during the operation with torch oil.
During shutdown, the CO boiler is usually tripped after catalyst has been unloaded. This way, steam is provided to drive the main air blower and the potential for CO emission is minimized.
PIMENTEL (CITGO Petroleum Corporation)
In our experience, the CO boiler starts up in advance of the FCC, since the air blower turbine depends on the steam from the CO boiler to run at full capacity and the CO boiler is equipped with an adequate number of auxiliary fuel burners. For the same reasons, the boiler is kept in operation (although at a reduced rate) until after the FCC is completely down; exporting steam to the grid and shutting down when required to perform the scheduled maintenance work. If no maintenance work is required, the CO boiler remains in operation during the FCC outage.
LALL (UOP, A Honeywell Company)
Commissioning of the FCCU requires ample steam availability especially for start-ups. In FCCUs equipped with CO boilers, the CO boiler is a major producer of HP steam for the refinery in normal operation. The timing of the CO boiler start-up may be dependent upon the need of the CO boiler to supplement the refinery steam system during start-up of the FCC.
Although UOP does not dictate when the CO boiler is to be started up on auxiliary firing, our procedures specify the FCC is to be started up in complete combustion with the flue gas diverted to the bypass stack. The flue gas is diverted from the bypass stack to the CO boiler only after the feed has been introduced to the FCC and the regenerator operation has transitioned from complete combustion to stable partial-burn mode. UOP considers this to be the safest way as the unit will be stable before the diverter valve is directed to the CO boiler for the following reasons:
a) There is minimum chance for unburned hydrocarbons in the flue gas from unsuccessful lighting off of torch oil.
b) Feed is routed to the FCC riser and the FCC operation and pressure balance is steady - in event of a pressure upset there is the potential of a reversal which could introduce a significant concentration of hydrocarbons into the CO boiler and cause a major upset.
c) The transition from full-burn to partial-burn is very dynamic and may be unpredictable. UOP preference is not to swing from bypass to CO boiler during this unstable situation until after feed is introduced to the riser at low feed rate and the regeneration has transitioned from full-burn to stable partial-burn operation.
Some refiners may have an ESP or wet gas scrubber downstream of CO boiler and must run these whenever feed is in the unit and may be forced to run through the CO boiler in this situation, but it is not preferred from a safety perspective.
If the CO boiler is required to be commissioned in early in the overall FCC start-up sequence to supplement refinery steam production, this will most likely occur before start of the air blower. The CO boiler will be operated on auxiliary firing (refinery gas) at start up with forced draft fans in operation. Start-up will be performed with the electric driven fan, supplying maximum combustion air and the burner(s) at minimum load (when no HP steam is available for the steam turbine users). The steam demand on steam network determines the degree of firing.
The CO boiler can be shut down any time after feed is removed from the unit to ensure any residual CO production from coke combustion is converted unless the CO boiler is required for refinery steam production. The procedure following feed cut out is to open the diverter valve to the bypass stack and reduce burner load till minimum load, then stop the auxiliary firing and burner(s).
Question 97: What equipment do you employ to help eliminate ESP hopper and downcomer plugging with catalyst fines? What additional operating practices are used? What type of level detectors are in use on the ESP hoppers and/or catalyst storage silos? Are there any new level detection technologies that could be applied, perhaps from coke drum measurement detectors?
PIMENTEL (CITGO Petroleum Corporation)
Our main problem with the ESP is fines accumulation in both the ESP hoppers and the transfer line from the hoppers to the fine's storage bin. We have incorporated some design improvements that have helped us minimize, but not completely eliminate, the main problems of condensation in the system and plugging. So, we added a second vibrator or rapper on the opposite side of the hopper, and we run them on alternate cycles of one minute each. The second improvement was to increase insulation of the hopper to a point where we now have it completely encapsulated. We have steam tracing as well. We believe there is still room for improvement.
At this time, we know that we can minimize the run of the piping from the hopper to a storage bin. We are also aware that there is a possibility of actually installing the fines storage directly below the ESP to basically eliminate the problem of plugging the transfer line.
Part of the question asked about our experience with level detectors. We do not have any. We mostly use an infrared gun if we suspect a high level in the hopper.
BROOKS (BP Refining)
BP uses an industry consultant to help us guide our operation on most of our ESPs. This industry consultant has a multitude of experience in ESPs over many years. Because of that, we have similar systems on most of our ESPs and in our ESP hopper systems. We have found that when we target keeping our hoppers warm, we help prevent some of the issues from condensation. Almost all of our hoppers that operate well have electric-traced hoppers to prevent condensation and keep the hoppers warm.
We also focus on trying to keep our hoppers as empty as possible since overfilling causes outages of the TRs (transformer rectifiers). Because of this, some of our sites have a system that continuously empties the hoppers. I do not know a great deal about it, but I am aware that they do this to prevent catalyst fines levels from building up in the hoppers. We have other hoppers that gauge their typical fines generation and develop a schedule of manually emptying their hoppers based on the fines make they expect.
From a level gauge perspective, we use nuclear level gauges on the majority of our units. Again, the same ESP consultant recommends this as the best technology for hopper level indication, and that is why we have employed them at the majority of our sites. A lot of our sites that do not employ these are up against limits for radiation sources on their site, so they are unable to use nuclear level gauges on their ESP hoppers. Those sites have resorted to high-level switches and regular manual dumping of their hoppers. However, these switches can be rather unreliable.
We have also seen issues with the nuclear level gauges. We will sometimes have ledges of catalyst that are sitting over the level gauge making it look like you have a level of catalyst. In those cases, we will back-check our TR operation to determine if we actually have a level or if it is a false indication. We will typically make sure to empty our hoppers more frequently if we feel we have a bad reading on the gauge.
SCHOEPE (Phillips 66)
In our system, ESPs use most of the features that were already mentioned. We make sure that our hoppers are well-insulated and heated and that vibrators are used to keep the hoppers from plugging. Fines are typically dumped on a timed interval, but not so much on level control. However, some of the units do have a gamma ray-type of indicator that can generate a high-level alarm.
PIMENTEL (CITGO Petroleum Corporation)
Our ESP hoppers are equipped with automatic rappers, which create enough vibration to prevent catalyst accumulation. We use a single vibrator on each hopper; hoppers have steam tracing and insulation. We initially had insulation jacketing and then beefed this up with a second layer of insulation that completely encapsulated each hopper. We have also added additional steam tracing on some hoppers. These moves helped to reduce, but not eliminate, the downcomer plugging problem. We think that a second vibrator on each hopper opposite the first hopper would help. We have also increased the vibration frequency in steps so that each hopper vibrator now vibrates once every minute. We have experienced plugging in the transfer line from the hoppers to the catalyst fines storage at times, due to condensation. A good design practice is to minimize the length of the transfer line to the fines storage, or store the fines directly underneath the ESP. We do not have any level detectors in the hoppers (use of I.R. camera when high level is suspected).
BROOKS (BP Refining)
BP uses an industry consultant with a multitude of ESP experience to help guide our ESP operations and optimization efforts. As such, many of our ESPs employ similar systems to manage fines handling. Our hoppers are typically equipped with electric heaters to maintain temperatures. We have found that keeping hoppers warm is one of the biggest keys to prevent pluggage. Warm hoppers prevent liquid condensation from causing fines clumping and sticking to walls. Most ESPs employ hopper rappers and have an ability to vacuum out hoppers if necessary.
Our sites typically work to keep the hoppers as empty as possible to prevent overfilling and outages of the TRs. Some sites have continuously empting hoppers. Others have gauged their typical fines makes and have regularly scheduled times to manually empty hoppers.
The ESP consultant we use recommends nuclear level gauges as a best technology for the hopper levels, thus these are employed at the majority of our sites. These gauges tend to work well; however, the following are key concerns around using nuclear gauges:
• Gauges require nuclear sources onsite. Some of our sites have had to remove these due to restrictions in the amount of nuclear material onsite. These sites have typically resorted to high level switches and regular manual dumping of hoppers. However, these high-level point readings are often not very reliable.
• It is important to note that the nuclear sources need to be appropriately isolated when work is done in the ESP. It is recommended to include this isolation as a safety interlock.
• Some sites have seen “ledges” of catalyst causing false level indication in the hoppers. This phenomenon is not exclusive to the use of nuclear level gauges. Our sites typically handle this by using tracking TR performance and hopper weigh cells if available to determine if hopper levels are actually too high or if the reading is false. If the reading is false, sites will typically resort to manual emptying of hoppers to maintain levels.
As with any type of indication, there can always be issues associated with these level gauges. However, we feel that the nuclear gauges are the best level indication technology available for this service.
SCHOEPE (Phillips 66)
Electrostatic precipitator hoppers are well insulated and use small heaters and vibrators to prevent plugging. Fines are typically dumped on a regular interval, but gamma ray type level indicators are used which can trigger a high-level alarm.
Question 98: What is your experience with the use of ammonia or steam in the FCC flue gas line in order to improve the operation of the ESP? Please comment on system configuration and operational issues
PIMENTEL (CITGO Petroleum Corporation)
We have extensive experience with the use of ammonia in the FCC flue gas line in order to improve the conductivity of the particles and improve the operation of the ESP. We inject ammonia at the target level of 10 parts per million or less. It is very effective at that concentration and has helped us reduce our baseline opacity level from about 15% to less than 10% or 5%. It also reduced the peaks. The peaks that you see in the chart are related to soot blower operations of the waste heat boiler. Thanks to the ammonia, we now operate the soot blowers more often without the fear of violating the opacity limit. So it is also an energy-saving project.
In our unit, the ammonia is injected directly downstream of the waste heat boiler from cylinders or from a storage tank located outside of the FCC battery limits. The only issue I can recall with this operation has been the loss of ammonia flow due to the regulators plugging with ice. If the ammonia is not completely dry, it will freeze in your regulator. That is easy to fix by putting some steam tracing in the lines. The chart shows typical performance before and after starting the injection of ammonia. As you can see in the chart, it helps us operate the soot blowers more often.
BROOKS (BP Refining)
As Sergio mentioned, the common use for putting in steam and ammonia is to reduce the resistivity of the particulate so it can be picked up easier in the ESP. We do not have a lot of experience with steam helping our ESP operations, apart from the example I mentioned about using steam on start-up before meeting temperatures necessary to use ammonia.
We do have quite a bit of experience with ammonia injection. All of our ammonia injection systems are fairly similar because, again, we use the same consultant for the vast majority of our ESPs. We also found that it is key to focus on your ammonia injection system providing good dispersion in the flue gas stack and good vaporization of your ammonia. Typically, all of our systems include heaters for vaporization and metering injection pumps, so we know how much ammonia we are injecting. The systems also include good dispersion nozzles for the flue gas stacks.
When we use ammonia in our unit, we typically try to optimize it. As shown in the example of an ammonia step test in the slide, the blue and orange lines are essentially the same. They both tell you how much ammonia we are injecting. However, we tend to double-check the meter on the pump stroke versus the actual amount coming in just to make sure we are getting good readings.
You can see that the test includes our stepping up injection rates until we meet a level where we feel like the opacity – the green line – has leveled out. You keep stepping up your ammonia until you believe you have leveled that on opacity, and then you step back down until you feel like your opacity has gone back up. Those are the areas where you would target your ammonia injection rates because you know that is the minimum necessary to maintain your opacity.
I also want to add that I am not sure if other sites have seen instances similar to what we have noticed. Some, but not all, of our sites with ammonia injection into their ESPs also saw a reduction in NOx as a result. It makes sense because you use ammonia in a SNCR (selective non-catalytic reduction) and also in a SCR (selective catalytic reduction) to reduce NOx. However, we do not see it in all of our units.
Those units with high NOx tended to show a good step down and leveling out similar to what we saw with the opacity, which can be seen in the purple line representing NOx. So, you may get an added NOx reduction benefit if you use ammonia on some of your units. We also did the same step test on other units and saw no response to NOx; so, it is not a guarantee.
SCHOEPE (Phillips 66)
I do not have much to add. Halle highlighted all of the points. Phillips 66 has a few installations where we inject ammonia into the ESP. Collection efficiencies were increased by 25% to 50%. It is critical to have good ammonia injection quilts which inject ammonia across the entire duct. Typically, we have not seen any issues with ammonium salt deposition anywhere in the downstream equipment.
MARTIN EVANS (Johnson Matthey Intercat)
To give a contrary comment, I heard a few people talk about the importance of dispersion. We recently had one refiner start ammonia injection and have trouble with the quill. When the quill was removed and the ammonia was injected straight into the nozzle, he got a similar reduction in opacity as he had been getting with the quill. So go figure. It is always the same with the FCC. You can prove something on one unit and then prove the exact opposite in another unit. Another point I want to make is that we have seen that opacity can increase when refiners go to low SOx emissions, typically below 50 ppm and certainly below 20 ppm. This occurs, if you are not using ammonia, because the SO2 (sulfur dioxide) actually acts in the same way as does the ammonia to decrease the resistivity of the catalyst and improve the efficiency of the ESPs. So, when you take out the SO2, you have to replace it with ammonia. Otherwise, you will lose ESP efficiency when you get down to very low SOx levels.
PIMENTEL (CITGO Petroleum Corporation)
We have extensive experience using ammonia in the FCC flue gas line to improve the performance of the ESP. NH3 is a very effective way to improve the conductivity of the flue gas at the levels as low as 10 ppm. In our experience the use of ammonia helped to reduce the flue gas opacity from an average of 15% to less than 5%. Ammonia is injected directly in the flue gas line downstream of the waste heat boiler (at about 500°F) from cylinders or directly from an ammonia storage tank located outside of the unit battery limits. The only operational issue with this system was plugging the regulators with ice, which was solved by steam tracing upstream of the regulator/orifice plate. We do not have experience injecting steam in the flue gas line to improve the operation of the ESP.
BROOKS (BP Refining)
BP does not have a great deal of experience using steam to improve ESP operations. We have one site that uses steam in the ESP during start-up to improve efficiency before the ESP is hot enough to add NH3 injection. This is to prevent possible salt formation that can result from adding NH3 into a cold ESP. The majority of our units use ammonia (NH3) injection successfully to improve ESP collection efficiencies. The purpose of using steam or NH3 injection upstream of the ESP is to condition the particulates by decreasing their resistivity. Decreasing particulate resistivity makes them easier to attract to the walls of the ESP, thus leading to higher collection efficiencies.
As mentioned above, BP uses an industry consultant with a multitude of ESP experience to help guide our ESP operations and optimization efforts. The majority of our NH3 injection systems are similar and follow the consultant’s guidelines, which typically include heaters for vaporization and metering injection pumps. Some sites have basic injection nozzles in the ducts while others have full injection grids. The key considerations for this injection system are around ensuring the injection point provides good dispersion in the flue gas duct and that they NH3 is sufficiently vaporized. Un-vaporized NH3 injection can cause issues with particles remaining on the collecting plates and falling off in chunks or hopper pluggage caused by sticky fines which leads to difficulty evacuating hoppers.
BP has also done a series of NH3 step-tests to optimize NH3 injection. These tests are simple adjustments to NH3 flow rates that are compared to improvements in stack opacity for each step as can be seen in the example graph below. During these tests we have seen that the reduction in opacity with increasing amounts of NH3 injection lines typically lines out at some point, as can be seen in the graph below.
Our experience with NH3 injection has generally been very good at sites with good injection systems. In addition to improvements in opacity with NH3 injections, BP has also seen some reduction in NOx at some of our sites. Generally, we have seen sites with higher base NOx levels see reductions in NOx with NH3 injections and others with lower base NOx levels may not see any change in NOx emissions with NH3 injection.
SCHOEPE (Phillips 66)
Ammonia has been used effectively in a number of refineries to increase electrostatic precipitator (ESP) collection efficiency. Ammonia decreases the resistivity of the catalyst which makes it easier for a catalyst particle to accept a charge. Depending on the ESP design aqueous ammonia injection can increased the ESP collection efficiency by 25% to 50%. A successful installation requires good distribution of the aqueous ammonia. Injection quilts need to be designed to distribute the ammonia equally across the area of the flue gas duct upstream of the ESP and resist catalyst erosion. Deposition of ammonium salts is typically not an issue.
Question 99: Have refineries experienced an increase in particulate emissions in the regenerator flue gas caused by oxygen enrichment of air to the regenerator?
BROOKS (BP Refining)
We have quite a few refineries that use oxygen enrichment. One of them uses it in very high concentration. None of the sites – and I spoke with them specifically about this – say that they have seen an increase in particulate emissions as a result of increasing their oxygen enrichment. As I mentioned earlier in response to a question, a lot of our units use oxygen enrichment to help reduce the superficial velocity in their regenerators in order to make their cyclones last longer and perhaps operate more efficiently. In essence, the oxygen enrichment is used to make the cyclones better and thus reduce losses.
LALL (UOP, A Honeywell Company)
Regarding Paul Diddams’ earlier comment, if you are at a regenerator cyclone velocity limit, reducing the blower air rate, or shutting any portable blowers and supplementing oxygen, then particulate emissions will be reduced due to a significant reduction in nitrogen moles and decrease in air volume entering the regenerator.
AVERY (Albemarle Corporation)
Oxygen enrichment will reduce superficial velocity in the regenerator and increase the O2 partial pressure. This alone would not favor SO3 (sulfur trioxide) formation since the rate of SO3 development, which is in equilibrium with SO2, is not instantaneous. However, increased oxygen will also raise regenerator temperature, which will then lower the rate of SO3 formation since SO2 is favored at higher temperatures. These two rates move opposite of each other. Since each regenerator is different, it is difficult to say with certainty that the overall effect may be the rate of bulk SO3 formulation in the regenerator. SO3 formulation will be at its maximum in the region of the highest oxygen partial pressure, which is just above the air grid. Using supplemental oxygen will increase the oxygen partial pressure in this region and can directly result in increased SO3.
Now downstream from the regenerator, oxygen concentration present in the flue gas is a key factor. Technically, this is unrelated to whether or not supplemental oxygen is used, but it depends on how the refinery chooses to operate the unit. Again, increased oxygen here increases SO3 formation over SO2. Lower temperature drives equilibrium towards SO3 until about 1,110ºF. At this point, the kinetics of SO3 formation are sufficiently hindered, so little SO3 is formed at temperatures below 1,060°F.
If a refiner is having an issue with the emissions compliance due to condensable particulates, then it is recommended that they minimize the oxygen content of the flue gas and, if possible, operate the flue gas cooler in a manner that will reduce minimize the amount of time the flue gas is between 1,050°F and 1,200°F. This will help minimize the condensable particulate formation from SO3. A scrubber, if present, will do a good job removing most of the SO2 in the flue gas, but it may only remove a small to moderate amount of SO3. SO3 will be measured as a condensable particulate in stack testing.
SCHOEPE (Phillips 66)
I do not have any additional comments on this question.
JACK OLESEN (Praxair, Inc.)
Someone made a good point about oxygen in the flue gas line and how that impacts the SO2 and SO3. But if you are buying oxygen and running excess O2 coming out the flue gas, then you are throwing away money. So, you need to keep the excess oxygen down to probably less than 2%.
MARTIN EVANS (Johnson Matthey Intercat)
I am being told that I am cutting into people’s drinking time, so I will be fast. With regard to reducing condensable particulates, SOx additive is great to use. We have some refiners who add SOx additives in small amounts simply to reduce condensable particulates. It works very well.
BROOKS (BP Refining)
Oxygen enrichment is typically put in place to provide some relief in air blower limited operations. Additionally, most of our sites that employ this technology also use it to reduce superficial velocity in the regenerator. This can reduce wear on the cyclones and improve cyclone efficiency which may result in a net effect of lower losses.
AVERY (Albemarle Corporation)
Oxygen enrichment will reduce the superficial velocity in the regenerator and increase the O2 partial pressure. This alone would favor SO3 formation since the rate of SO3 development (which is in equilibrium with SO2) is not instantaneous. However, increased oxygen will also increase the regenerator temperature, which lowers the rate of SO3 formation since SO2 is favored at higher temperatures. These two rates move opposite of each other. Since each regenerator is different, it is difficult to say with certainty what the overall effect may be on the rate of bulk SO3 formation in the regenerator.
SO3 formation will be at its maximum in the region of highest oxygen partial pressure, which is just above the air grid. Using supplemental oxygen will increase the oxygen partial pressure in this region and can directly result in increased SO3 formation.
Downstream of the regenerator, the oxygen concentration present in the flue gas is the key factor. Technically this is unrelated to whether or not supplemental oxygen is used, but it depends on how the refiner chooses to operate the unit. Again, increasing oxygen here will increase SO3 formation over the SO2. Lower temperature drives the equilibrium towards SO3, until about 600°C. At that point, the kinetics of SO3 formation are sufficiently hindered, so very little SO3 is formed at temperatures below 570°C. If a refiner is having an issue with emissions compliance due to condensable particulates, then it is recommended that they minimize the oxygen content of the flue gas and, if possible, operate the flue gas cooler in a manner that will minimize the amount of time the flue gas is between 570°C and 640°C (1,050°F to 1,200°F). This will help minimize condensable particulate formation from SO3.
A scrubber (if present) will do a good job of removing most of the SO2 in the flue gas, but it may only remove a small to moderate amount of the SO3. The SO3 will be measured as a condensable particulate in stack testing.
LALL (UOP, A Honeywell Company)
Oxygen enrichment option is typically considered by refiners to achieve incremental feed processing. In general, oxygen enrichment marginally increases particulates due to a richer oxidizing environment; however, it is highly dependent upon whether regenerator net vapor and cyclone velocities increase or decrease. In cases where the air blower is limited and oxygen is added on the grounds of economics for additional feed processing, the regenerator vapor velocity increases, leading to marginal increases in catalyst entrainment to the regenerator cyclones and catalyst loss increases slightly. If, on the other hand, the regenerator is operating at a vapor velocity limit and the blower air rate is reduced or supplemental portable blowers are turned down, the particulate emissions reduce due to the significant reduction in the N2 moles and decreasing air volume entering the regenerator. This results in lowering the overall regenerator vapor velocity and catalyst entrainment to the cyclones. Lower cyclone velocities reduce the particulate fines generation by reducing the force of catalyst particle collision with the cyclone wall.
ROBERTSON (AFPM)
That concludes this FCC session. I want to thank the panel for all the work they have done in the last four or five months. We really appreciate it. And, we ended 50 minutes earlier than last year. Also, I want to thank Cheryl Joyal who was the coach for this team; she did a really good job. This concludes the Q&A portion of the meeting. I appreciate all of you coming. I hope you have gained a lot of insight from this session and will take it back with you to your facilities. Thank you.
Question 1: What is a typical hydrofluoric (HF) acid inventory (pound of acid per bpdC5+ alkylate), and what steps are refiners considering reducing this volume? What other risk mitigation steps are refiners considering for their HF units?
BULLEN (UOP LLC, A Honeywell Company)
As you can see on the slide, there is a big variation in the design HF-to-alkylate ratios. The order of older units, as denoted by old Heritage-Phillips and old Heritage-UOP types, has fairly high ratios. The more modern ones were designed with lower ratios. The actual observed ratios are even less than that. A lot of this depends on whether units have been revamped. If they have a higher throughput, then the ratio will reduce further. If you have an old-designed UOP vertical mixer settler, you can take advantage of reducing the ratio by eliminating that mixer and then just having the settler. However, you will increase your organic fluorides and your product streams approximately two times. There are some other things in the design that you can do to help reduce it down further.
Regarding risk mitigation steps, if you follow the mitigation options in the API (American Petroleum Institute) 751, you can reduce your risk. Some of these include utilizing acid leak detection systems, water spray mitigation systems, rapid acid inventory systems, remotely operated isolation valves, and passive mitigation systems. You can find more details in my Answer Book response to this question.
MELDRUM (Phillips 66)
Phillips 66 has seven operating HF alkylation units. Based on these units, our average acid inventory is 16 pounds per barrel of alkylate. The range is from 11 to 20 pounds of acid per barrel of alkylate. Our UOP pumped acid unit is on the low end of that range.
Inventory minimization is accomplished principally through two areas. One is process design. The older units were designed with a riser of about 50 feet. Newer designs have risers of about 30 feet. The shorter riser then equates to a lower settler level. The reduction in this riser height also reduces the acid-to-hydrocarbon ratio from 4:1 to about 3.5:1. The second way that acid in the unit is minimized is through limiting the stored fresh acid inventory. In my Answer Book response, I have provided some of the risk management methods grouped in the areas of prevention, detection, and mitigation.
PATRICK BULLEN (UOP LLC, A Honeywell Company)
The acid inventories of the HF alkylation units in operation vary significantly and depend on the type of reactor section design and the actual operating isobutane-to-olefin (I/O) ratio. Lower I/O ratio allows higher alkylate throughput in a given unit, which reduces acid inventory when measured in pound of HF/bpd (barrel per day) alkylate. The table below indicates the ratio range of various types of HF alkylation units.
Proper control of the acid settler level, maintaining sufficient level to prevent hydrocarbon carry under into the circulating acid stream can minimize the acid inventory in any given design. Reliable level indication in the settler helps to achieve good acid level control. Also, good coordination between the refiner and acid supplier to deliver acid at the right time will prevent excessive acid inventory in the acid storage drum. Elimination of the 20-tray mixing section from the vertical mixer-settlers in the older Heritage-UOP design units can be the biggest step toward inventory reduction. Eliminating the mixing section has been done at several units. The downside of eliminating the mixing section is that the number of organic fluorides in the product streams (propane, n-butane, and alkylate) approximately doubles.
Depending on the specific unit design, there may be other design changes that can be made to achieve relatively smaller reductions in acid inventory.
There is a good summary of the various risk mitigation options in Section 6 and Appendix H of the new 4th Edition of API RP 751 which was released in May 2013. In general, the basic risk mitigation options are:
• acid leak detection (which includes sensors, cameras, and flange paint),
• water spray mitigation systems,
• rapid acid de-inventory systems,
• remotely-operated isolation valves, and
• passive mitigation systems (such as barriers, acid inventory control, and vapor suppression additives).
Continuous acid leak detection and remotely operated and controlled water spray mitigation are generally considered to be requirements in an HF alkylation unit.
CRAIG MELDRUM (Phillips 66)
A Quantitative Risk Assessment (QRA) study can give valuable information on the benefits of reducing acid inventory compared to other mitigation options. Risk management is based on prevention, detection and mitigation.
• Prevention: proper equipment design (including management of change for equipment or process changes), routine maintenance, effective inspection, well trained and disciplined operators and maintenance, and ongoing risk assessments studies and corrective action
• Detection: rapid and reliable HF detection (point and/or open path), HC detection as a surrogate for HF, visual detection (camera and acid detection paint), and alert personnel (operations, maintenance, technical, and management)
• Mitigation: isolation valves, acid transfer, water spray, barriers (used principally by one operating company), and modified acid additive (limited use in the industry)
Question 2: Have seal-less pumps (magnetic drive or canned pumps) been used successfully in HF and sulfuric acid alkylation units? What services are considered for this equipment?
MELDRUM (Phillips 66)
Yes, sealless pumps have been successfully used in both HF and sulfuric alkylation processes, typically in the acid rerun system for the HF process and fresh acid service for the sulfuric process. However, the API-610 sealed pump is, by far, the most commonly used pump based on the fact that API 610 pumps are familiar within the refinery for the Maintenance and Projects groups and also because of their robust design and relatively low initial cost.
As I reviewed some of Phillips’ process design specifications, I found a statement referring to both magnetic drive and canned pumps: “We do not have enough experience with this type of pump to recommend features and styles.” It was also mentioned in the specification: “Because of the slightly magnetic nature of nickel copper alloys, the containment shell of the mag-drive pump for HF service should be Hastelloy C-276.”
The interest in sealless pumps is due to the lower risk from potential seal leaks. However, it is now quite common practice to use dual seals for acid service. Also, the seal reliability has improved over the years. Therefore, the risk of a sealed pump in HF acid service, in particular, has been reduced. One risk consultant stated that the limited history on sealless pumps in HF acid service results in his refinery using the same failure rate as that of a dual-sealed pump when they conduct their quantitative risk assessment studies. What I have concluded is that when considering sealless pumps for new construction or major equipment replacements, you should work with a risk consultant to determine if the sealless pump is effective at achieving your risk management objectives. I have also provided, in my Answer Book response, several considerations to review as you look at selecting a pump for HF acid service.
BULLEN (UOP LLC, A Honeywell Company)
UOP has limited experience with sealless pumps in HF units. The one concern we have is that these types of pumps are different than most of the other pumps in the refinery; so, you really need to have Operations and Maintenance crews who are experienced dealing with this type of pump. A lot of human error can creep in and cause the pumps to fail. The experience we have had has been in relatively small-sized applications such as the acid rerun feed pump. One of our customers in Europe has actually been successfully using three pumps in circulating acid, settled acid, and isostripper reflux operations since 1994. So, it is possible to have a long run with these types of pumps. Also, sealless pumps tend to not meet requirements for API standards; they are ASME (American Society of Mechanical Engineers) standard type pumps; so that can be an issue. As Craig said, dual seals have gotten a lot better in the past 20 years and become more reliable; so, it is questionable whether you are actually safer with the sealless system, in terms of reliability and leaks.
ROBERTSON (AFPM)
Does anyone else in the audience have experience with sealless pumps?
CHRIS GREEN (Marathon Petroleum Corporation)
I work at the Galveston Bay Refinery. We use the mag drive style pump on the rerun to our feed. We had previously experienced a bolting failure on the conventional style pump and the case opened up. We had good reliability. We have been using them since about 2003, and they have proven to be reliable in that service.
CRAIG MELDRUM (Phillips 66)
Some consideration for HF acid pump selection:
• Service Conditions: Temperature (mag-drive pumps limited to ~350°F, canned pumps can take up to 1000°F) and solids content of the pumped fluid (sealless pumps can be more sensitive to solids in the fluid)
• Durability: Operation under upset conditions or from poor operations such as dead-headed and run dry
• Cost: Initial pump cost plus the seal cost plus ongoing maintenance costs. Sealed pumps will likely have a lower initial cost, but long-term seal maintenance costs may favor sealless pumps.
• Alignment and Foundation Requirements: Pump-to-driver alignment and foundation requirements are minimal for canned pumps.
• Containment against Catastrophic Failure: Canned pumps have secondary containment by design.
• Failure Scenarios and Mitigation: Sealed pumps are most likely to fail at the seal; sealless pumps are most likely to fail at the bearing.
• Maintenance: Onsite knowledge for repairs versus factory service and spare parts inventory needs
• Technical Support: Factory support to assist in working through any ongoing issues
PATRICK BULLEN (UOP LLC, A Honeywell Company)
There are two basic types of sealless pumps: magnetic drive and canned motor. UOP has limited experience with both types in HF alky units. In general, UOP’s experience is that the magnetic drive and canned motor pumps can work in HF alkylation service, but they are sufficiently different from standard single-stage process pumps that require special design considerations, maintenance, and operating procedures for successful operation. UOP is aware of several cases where a refiner installed a sealless pump and experienced serious damage to that pump within a very short time due to issues such as incorrect operating procedures or insufficient spillback or flush supply. This type of damage to a sealless pump is typically VERY expensive to fix and typically requires shipment of the pump back to the manufacturer, causing the pump to be out of service for several weeks.
Most of the sealless pumps used in HF alkylation units have been relatively small sized pumps. One specific service where a few refiners have used a sealless pump is the acid rerun column feed pump.
One UOP licensed unit in Europe has had good experience with canned pumps in HF service. This refiner installed three canned pumps in 1994, and those pumps are still used today. The specific pump services are circulating acid, settled acid, and isostripper reflux. This same refiner had negative experience with a magnetic drive pump in isostripper reflux service. This refiner uses sealless pumps in other applications in the refinery such as FCC sour water.
Another licensee in Europe uses magnetic drive pumps in two very large flow services. One is the acid circulation pump, and the other is the isostripper feed pump. The experience has been good with both of these pumps. These pumps receive special mechanical attention and service, which are probably keys to their successful performance.
It is worth noting that some of these sealless pumps are not built to be compliant with all of the requirements of the API standard for refinery service pumps. Instead, they are built to ASME standards that are used predominantly in the chemical industry.
Many refiners have chosen dual seals over sealless pumps because the reliability of dual seals in acid service has improved significantly over the past 20 years or so. In addition, the dual seals have a lower cost to install on existing pumps, and the maintenance and operation of the dual seals is typically well-understood by the refinery staff.
Question 3: What drives the decision to load presulfided, presulfurized, or oxidized catalyst in naphtha hydrotreaters? What are the different safety considerations for each case?
MELDRUM (Phillips 66)
I would like to begin my responses by grounding us in some definitions. Pre-sulfided catalyst is the catalyst that is delivered with an active metal sulfide site. Pre-sulfurized catalyst is catalyst in the oxide form but which then has added to it an organic sulfur compound. The metal sulfide sites are then formed in-situ during the startup process. Finally, sulfiding is the process of injecting a sulfur compound into the reactor for in-situ sulfiding after the catalyst is loaded.
At Phillips 66, we use pre-sulfided catalyst in naphtha units when there is no off-test product line or tankage or where we want to save our startup time. We plan for about one to two days to complete an in-situ sulfiding step which can be eliminated using the pre-sulfided catalyst. We will also use pre-sulfided catalyst if we skim and replace a portion of a catalyst bed. If we are skimming more than 20 to 25% of the bed, we will come in with the pre-sulfided catalyst. If we are only skimming and replacing about 15% of the bed, then non-sulfided catalyst will be used; so there will be no need to do a separate sulfiding step during startup.
We generally do not use pre-sulfurized catalyst in naphtha service based on a slight concern about how the passivating agent might come off causing a sulfur slip to the reformer. This is not a major issue, but it might impact the downstream reformer for a couple of days.
Most of our naphtha high-treating catalysts are loaded in the oxide form and then sulfided in-situ as part of the startup process. When we do use pre-sulfided or pre-sulfurized catalysts, we make it a practice to order some of the inventory in the oxide form so that it can be returned if it is deemed surplus material. Once the catalyst has been sulfided or treated with the sulfurization chemical, then any surplus catalyst will be difficult to return. As precaution, we load sulfided and pre-sulfurized catalysts under inert conditions to prevent self-heating. We also use respiratory protection, usually supplied air, regardless of the catalyst condition to protect against any of the dust.
STREIT (KBC Advanced Technologies, Inc.)
I will mostly confirm what Craig just said. Pre-sulfided and pre-sulfurized catalysts do not require sulfiding agents. That is really one of the drivers for why you might want to purchase that material. Also, it avoids personal exposure and odors. It is less of a problem than it was in the past with the modern injection facilities and sulfiding agents, but still a concern.
Pre-sulfurized catalyst: One point that should be noted on a naphtha unit is that because of the vapor phase and the reaction, you can end up with some temperature issues when you are activating it. So be a little wary of this when using pre-sulfurized catalyst in this service. The activation of pre-sulfided catalyst is a lot easier to control, and the typical driver is just startup time. You can get the unit up a lot more quickly.
Oxidized Catalyst: If you decide to go with oxidized catalyst and have to go through the sulfiding step, then you will need to use some solid sulfurizing agent. In other services, you could use the feed sulfur to sulfurize a catalyst. In naphtha service, that is usually not high enough to be the case. The advantage of oxided catalyst is that you do not need inert loading facilities.
ERIC STREIT (KBC Advanced Technologies, Inc.)
Sulfiding with sour feed is usually not preferred in naphtha hydrotreaters because the low feed sulfur results in an H2S partial pressure too low to adequately activate the catalyst. So, the catalyst does need to be sulfided in some way.
If oxidized catalyst is used, the refiner must use a stream with a high H2S content or add a sulfiding agent of some type to activate the catalyst. DMDS (dimethyl disulfide) is the best sulfiding agent for this service. Other sulfiding agents, like polysulfides, have the potential to produce solid sulfur when no hydrogen is present. There are concerns with personnel exposure and odors with any sulfiding agent. Many refiners choose to avoid these issues by ordering catalyst with the sulfur already on the catalyst. With modern injection systems, leakage of sulfiding agents is usually a minor issue.
Presulfurized catalyst, where the sulfur has added to the catalyst but has not been activated, can cause problems in naphtha hydrotreater service. Because the reactions are occurring in the vapor phase, temperature control during the sulfiding step can be difficult, and the operator may experience a temperature excursion that could damage the catalyst. This is exacerbated by the fact that most naphtha hydrotreaters do not have bed thermocouples, so it is particularly difficult to control the heat release.
Adding presulfurized catalyst as makeup from a reactor skim can usually be done without major problems. In this case, only a small portion of the bed is being replaced; so, the exotherm during activation is not great. Loading presulfided catalyst, where the catalyst has been fully sulfided and activated by the supplier, provides the fastest way to bring the unit online. Presulfided catalyst is more expensive but can be justified in some instances. Examples of where presulfided catalyst may be justified include 1) units where pre-heat is limited and proper activation temperatures are hard to reach and 2) units where a fast startup is required, such as when the only hydrogen source in the refinery is the reformer.
Using catalyst with sulfur already on it should be done in an inert environment. Loading oxidized catalyst does not require an inert atmosphere, so operators who want to avoid loading under these conditions should choose oxidized catalyst.
STEVE TREESE (Phillips 66)
The following are a few definitions to establish a foundation for the answer.
• Presulfided: Catalyst manufactured and delivered with active metal sulfide sites on the catalyst.
• Presulfurized: Catalyst in the oxide form that has an organic sulfur compound added in the manufacturing step then passivated with a heavy organic material. Sulfiding occurs in-situ as part of the startup process, but the sulfur compound does not need to be injected onsite.
• Sulfiding: The process of injecting a sulfur compound into the reactors after catalyst loading for in-situ sulfiding as part of the startup process.
We use presulfided catalyst in naphtha units where there is no off-spec product line or tankage or where we need to save startup time (one to two days to sulfide in-situ). We also use it if we have skimmed and replaced more than about 20 to 25% of the bed (~15% of the bed can be skimmed and replaced with non-sulfided catalyst and without sulfiding as a separate startup step). The presulfided catalyst is handled under inert conditions as a precaution.
We generally do not used presulfurized catalyst in naphtha services based on slight concerns over the heavy, high endpoint passivation material going to the reformer and the amount of sulfur slip to the reformer. This is not a big issue, but it may hit the reformer for a couple of days. Most of our naphtha hydrotreating catalysts are loaded in the oxide form and then sulfided in-situ as part of the startup process.
When presulfided or presulfurized catalyst is used, we order some of the catalyst in the oxide form so it can be returned if there is surplus material. Once catalyst has been sulfided or loaded with sulfurization chemicals, then any surplus catalyst will be difficult to return. +
For presulfided and presulfurized catalysts in any service, we load under inert conditions to prevent self-heating. In theory, the catalysts are often passivated so they can be handled in air, but we are concerned about how long that protection lasts (one to two days) compared to how long it takes to load the beds (should be one to two days; but if delayed, it could be three to four days). In all cases, respiratory protection (usually supplied air) is used, regardless of the catalyst condition to protect against the dust
Question 4: Is there any experience producing on-specification jet fuel without any sulfur/mercaptan treating, including any form of caustic, from feedstocks produced from ‘tight’ formations? What other jet specifications are adversely impacted by the changed feedstock?
STREIT (KBC Advanced Technologies, Inc.)
The main idea here is that there is no real change to the way you make jet fuel based on tight oil. There may be slight changes to the freeze point due to the paraffinicity of the tight oil, but that is actually just dependent on the tight oil itself. If that is the case, really all that is required is a cutpoint adjustment in the crude unit to get on-spec on the freeze. You normally have to do some sort of treating through a clay treater in order to get on-spec for JFTOT (Jet Fuel Thermal Oxidation Test) and WSIM (Water Separation Index Modified), but that is not really different with tight oil versus conventional oil. You do not strictly have to treat for sulfur/mercaptan to make jet fuel, but most places like to do some sort of treating as a safety net to make sure that the final product is on-spec, particularly on mercaptan.
GROPP (GE Water & Process Technologies)
In support of what Eric said, we are not aware of anyone consistently producing on-specification jet fuel without some type of processing or treatment to address sulfur compounds including H2S, mercaptans, and thiophenols. Typically, we see refiners using hydrotreating and/or caustic extraction processes to remove these trace contaminants. It only takes a small amount of sulfur in the right form to throw the fuel off specification. Without removing the contaminants, refiners can expect to fail the JFTOT, as well as the Copper Strip Corrosion and Mercaptan or Doctor tests. In addition, without treatment, the fuel may not pass acidity specifications.
TERRY HIGGINS (Hart Energy Research and Consulting)
Regarding the freeze point, I would have thought that freeze point would be more of an issue for people who are running a large amount of Eagle Ford crude. I think you indicated that it was not too much of an issue, just a small cutpoint. Are you familiar with situations where there were large volumes of the tight oils that would have been difficult to make at all, in terms of having a strong impact on that freeze point?
STREIT (KBC Advanced Technologies, Inc.)
I am not personally aware of any particular issue with that situation. It is more of an assumption based on the presumed paraffinicity of the tight oils, which may or may not be true, depending on the specific tight oil we are discussing. I would be very interested to hear if anyone else has any issues with that. R.E. “ED” PALMER (Wood Group Mustang, Inc.) I know that in some designs we are doing on these condensate splitters, where we are making distillates, that distillation cutpoint is limited by the freeze point of the product.
RONALD GROPP (GE Water & Process Technologies)
We are not aware of any finished, on-specification jet fuel produced without some sort of processing to remove sulfur and/or sulfur compounds including H2S (hydrogen sulfide), mercaptans (thiols), and thiophenols. Typically, we see caustic extraction and/or sweetening processes or hydrotreating processes utilized to remove sulfur or change the sulfur compounds to less objectionable forms. If these sulfur contaminants are not addressed, the fuel will likely fail to meet specifications including Thermal Stability (ASTM D3241), Copper Corrosion (ASTM D130), Mercaptan Sulfur (ASTM D3227), and/or Doctor Tests (ASTM D4952-12). In addition, caustic treating or hydroprocessing methods may be required to meet Acidity (ASTM D3242) specifications.
ERIC STREIT (KBC Advanced Technologies, Inc.)
Virtually all jet fuel needs to be processed through a clay treater to ensure that the product meets JFTOT and WSIM specifications. Tight oil processing does not really change this requirement. Although there may be some freeze point differences due to the higher paraffinicity of some tight oils, this can be countered by changing the cutpoint upstream.
Jet fuel can be produced without treating for sulfur or mercaptans due to its high sulfur specification. Some refiners have had success doing this. However, operating with no treatment can be risky. To avoid the risk of producing off-spec jet, many refiners use some type of caustic treating or hydrotreating to ensure that they will not have problems with mercaptans. In any case, tight oil is lower in sulfur content than conventional oil; so, it should only help lower the jet fuel sulfur level. In cases where sulfur may be an issue and hydrotreating is not used, adjustments to upstream cutpoints can be made to marginally reduce sulfur.
Refiners producing jet fuel from tight oils should be aware that the jet fuel final boiling point may need to be decreased due to the freeze point. The economics of processing tight oil should consider this, and linear program cutpoints should be adjusted accordingly. However, it is unlikely that any adjustments to jet fuel final boiling points will influence whether or not to process tight oil.
Question 5: Reforming of feedstocks from ‘tight oil’ crudes offers unique challenges such as low naphthene and aromatic (N+A) content, lighter feed, and differences in coke yield.What are refiners doing to address these challenges and generate opportunities for these new crudes?
BULLEN (UOP LLC, A Honeywell Company)
From a project standpoint, there have been inquiries related to tight oil and proposals generated, but not a significant number of actual projects realized for revamping units. It appears that most refiners are able to accommodate the tight oil in their existing units. Some of this accommodation has to do with the naphtha area capacity issues in the U.S. of which I am sure everyone is aware. There are opportunities to change the catalyst types to be a more active type and come up with a more coke-tolerant type catalyst to address the higher coke make you get with more paraffinic feeds.
MELDRUM (Phillips 66)
This whole subject of tight oils or shale oils is interesting. I am not sure there has been an event in the industry that has had as quick and broad of an acceptance as the bringing of tight oils to market. A typical operating company could probably anticipate seeing a doubling (or greater) of their use of tight oils over the next five years from where they are currently processing. Tight oils are typically more paraffinic and lighter than many of the current crude oils. As such, the naphtha cut being fed to the reformer unit from these oils will be leaner and have a lower naphthene and aromatics content. Additionally, the quantity of that cut will increase, which will impact the reformer in all areas of activity, selectivity, and stability, the extent of which depends upon the type and amount of the tight oil or shale crude that is processed.
One of our sites processes 20% of an Eagle Ford crude. They have experienced a 4 to 6- number drop in their naphtha feed quality as measured by the naphthene and aromatic content (N+2A). The process impact was a 1-number drop in the octane number that was offset by adding 4 to 6°F additional reactor temperature to hold the previous octane target. The associated yield decline has been about 1.5 liquid volume percent C5 plus. The coke make is expected to increase by about 10% due to the added severity on the unit. This would then have an associated shorter cycle life to the catalyst from regeneration to regeneration.
Another of our sites processing 35% of Bakken crude has seen a 5-number drop in its naphtha feed quality (N+2A), which has lowered the reformate octane. The additional naphtha from that processing, which is not able to fit into the reformer unit, bypasses the unit and goes directly to fuel blending.
STREIT (KBC Advanced Technologies, Inc.)
I do not have a lot to add, more of a confirmation. We alluded to it in the last question. We make some assumptions or generic statements about tight oil; but in fact, it is a rather broad spectrum. It does tend to be more paraffinic, but it is not, by definition, more paraffinic. It is not really worse than any of the Arabian crudes that have been processed through the years, as far as N+2A. Typically, it will be a little more paraffinic, which means you need a little more severity for the same octane target, as was stated before. This results in a slightly higher yield loss through the reformer; but in general, no major changes are needed to process this material. Because of ethanol blending and the corresponding lack of demand for octane from a reformer, most reformers in the United States now have the room to go up on severity. So, there is likely available capacity to make up for that additional severity that you need.
I want to point out that it is very possible that the LP (linear program) models, which are making the decisions on what kinds of crudes to buy and the economic value of those feedstocks, may not properly reflect the yield loss that you might see from a tight oil. So those LP vectors need to be updated to make sure the LP is up to speed to properly reflect that yield loss. The final point outside of the N+2A or the paraffinicity issue is that there seems to be a lot more contaminants which we have not seen in the past that are showing up, and those may be a larger concern than the actual N+2A or the reformer feed quality.
VICTOR TAILER (Commonwealth Engineering & Construction)
I have a general question. Since the quantity of tight oil processing is going to increase, how does this increase impact delayed coker units which operate at the low pressure, and how will the coker yields will change? How does tight oil processing impact the fractionator operation? Do they need any revamp, or is it done with any equipment modification?
MEL LARSON (KBC Advanced Technologies, Inc.)
If I understand the question correctly, you are asking about the impact of the tight oils that would go through the coker. The issue is going to be with the quantity. We would expect that quantity of material because there is not as much bottoms within 50-plus in the material. In general, for that material, if the Conradson carbon residue content is about the same, we would not expect the yield shift to be too much more dramatic or even the yield profile to be an issue. Most of what we have seen so far in the coking conferences I have attended are strictly hydraulic rate issues about the minimum feed rate. If those change, the coker distillate or coker naphthas will not be too much different than they are today, as far as their properties; only the mass rate will drop quite substantially.
JESUS CABELLO (Foster Wheeler USA Corporation)
What we have seen with some of the clients processing tight oils is some kind of incompatibility between tight oils and conventional oils that is creating issues in the heaters.
TERRY HIGGINS (Hart Energy Research and Consulting)
I have a quick comment on the crude N+A (naphthene plus aromatic content). One of the biggest impacts has to do with the crude oil you are backing out. For example, many people have had to back out Nigerian crude in order to accommodate the excess domestic light crudes. There you have a significant N+A shift. However, it is true that if you start backing out crude oil such as Arabian, you will not see that much difference.
PATRICK BULLEN (UOP LLC, A Honeywell Company)
Refiners are looking at potential options such as CCR (continuous circulation rate) Platforming™ process unit regeneration section revamps to increase coke burn capacity or even catalyst volume increases via reactor additions. Other options include catalyst changes to more active and more coke-tolerant catalysts.
The general activity for revamps is not particularly high for tight oil-related additions presently. Some of the potential reasons for this are the following:
a. Tight oil is difficult to define as the assays vary within the field and over time, depending on the recovery. This difficulty makes long-term predictions and economics harder to calculate. This, in turn, makes projects more difficult to justify.
b. Tight oil in the naphtha range is not too different from some paraffinic crudes, such as Saudi Light, so the general effects are known and can be put into existing systems that may be underloaded.
c. The volumes of tight oil are still growing and being established.
Contaminants vary in tight oil as well due to the unique processing to recover these oils. Combined nitrogen and olefin spikes have been noted by refiners. These types of contaminants tend to require severe hydrotreating similar to that required for coker naphthas.
ERIC STREIT (KBC Advanced Technologies, Inc.)
First of all, reformer feed from tight oil is not any worse than Arabian crudes, which many folks processed for a number of years without major issue. Tight oil naphtha does tend to be more paraffinic and, therefore, makes worse reformer feed than naphtha from most conventional crudes.
More paraffinic reformer feed means higher severity, higher coke makes, and lower hydrogen yield for the same octane. However, in the U.S. and elsewhere, there has been a big drop in reformer octane target (due to ethanol/oxygenates use) on units that are not making BTX (benzene, toluene, and xylene). As a result, there is likely room for handling the additional severity required due to tight oil.
A separate challenge may be due to the various contaminants that might be in the naphtha from various chemicals used in the production field. This may require tighter monitoring of contaminants in the naphtha and better management of the naphtha hydrotreater performance. A particular contaminant that may be present in higher-than-expected concentrations is nitrogen. High levels of nitrogen can result in severe corrosion and fouling in the reformer, so anyone changing crudes should be regularly monitoring naphtha nitrogen content in the reformer feed.
SONI OYEKAN (Prafis Energy Solutions)
First, we know that the cheaper ‘tight oils' or unconventional oils have had the beneficial economic impact of lowering overall average prices of crude slate processed by oil refiners who are favorably positioned to capitalize on processing the tight oils. Within the refineries, there are some processing challenges due to some changes in the compositions of the resultant oil fractions. The challenges with low naphtha N+A qualities from ‘tight oil’ crudes are typically and reasonably managed by co-processing ‘tight oil’ crudes with crude oils that produce more naphthenic naphthas. Via the processing of mixed crude oil slates, total naphtha qualities can be adjusted over a broad range to meet fixed-bed semi-regenerative reformers cycle targets and regeneration frequency schedules if those are of concerns to the refiners. If product selectivity is a concern, moderating the low naphtha quality of such oils via co-processing with crude oils that produce naphthenic naphtha would also aid in improving product selectivity.
In the case of CCR reformers that are being operated with low coke naphtha reforming operations challenges, the lower N+A quality of the total naphtha feed is a bonus for the reformer as that would lead to increased catalytic coke make and aid in maintaining steady-state, complete, continuous catalyst regenerator operations at constant reforming process conditions. By complete regeneration, I mean that due to the higher coke make as a consequence of reforming lower N+A, quality naphtha could lead to steady-state white burn operations and full catalyst regeneration and redispersion of the metals in reforming bimetallic catalysts. Therefore, in the case of a continuous catalyst regeneration reformer, the reforming of lower N+A quality naphtha at constant reforming process conditions could aid in optimizing the reforming operations of the previous low coke reforming operations and non-steady-state catalyst regenerations and activation. All of the above could help minimize some of the reformate octane barrel losses from processing a more paraffinic naphtha from ‘tight oils’ crudes.