Steve Philoon and Ka Lok (UOP)
This topic has been discussed in 2008 NPRA Q&A session, below is some of the key points.
VCFE Cleaning
Pulling the VCFE tube bundle can be very difficult. Removing and re-installing the bellows is also a difficult task. Care should be taken not to damage the exchanger when pulling or installing the tube bundle. In addition, setting the bundle in the horizontal will, in most instances, cause damage such as tube to tubesheet leaks. UOP does not recommend removing the bundle unless absolutely necessary. It is recommended to wash the exchanger with water in order to remove ammonium chloride salts. Washing with reformate is recommended if the fouling is due to gums or PNA. Removing the bundle should only be done as a last resort.
Cleaning of the tube side is typically successful using high-pressure (up to 10,000 psi) water blasting. This cleaning (hydroblasting) can be done without removing the bundle, as both ends can be made accessible. If the tubeside of the VCFE is plugged, remove the top flange and expose the tubes. The high-pressure water jet lance can be inserted in order to clean the tubes. The shell side is more difficult to clean. Removal of the bundle and hydroblasting has, in most cases, been able to clean away shell-side deposits. But in at least one case, was not effective at cleaning the outside diameter of tubes in the center of the bundle. In-situ attempts at cleaning by washing with reformate or permanganate solutions have produced varying results. Use of hot solvent will help the solubility.
On-line washing procedure for the hot side of CFE by adjusting the last reactor outlet temperature hasbeen done by refineries. The effectiveness of this procedure yields mixed results for improvements.
Troy Small and Ka Lok (UOP)
Typical operating conditions in a reformer do not result in platinum volitization. However, it is possible for Platinum to become volatile and come off the catalyst at very high temperatures. One place this can occur is in the Chlorination zone of the CCR Regeneration Tower, where slipping coked catalyst into an oxygen rich atmosphere can result in very high temperatures. To prevent this, the refiner should make sure that the regeneration tower is operated according to the design.
UOP's experience is that these questions often arise as the result of an assay difference with the reclaimer rather than volatilizing platinum. The assay differences can be due to unrepresentative sampling or poor/biased analyses.
Soni O. Oyekan (Prafis Energy Solutions)
In order to fully answer the questions, it is relevant in my brief response to separate the precious metal catalyst platinum management into five distinct stages to cover a platinum catalyst manufacture to spent catalyst platinum reclamation life cycle. The stages that are pertinent for our review are:
•Reforming catalyst manufacture by the catalyst supplier and platinum settlement
•Reforming catalysts storage and catalyst loading
•Catalyst as used in the reforming units
•Catalyst dumping and transfer to platinum reclamation company
•Platinum settlement with the platinum reclamation company
It must be clearly understood that platinum losses can occur at any of the stages of the catalyst cycle. Some of the losses are due to contractual agreements as agreed upon in the first and fifth stages as a consequence of platinum settlement. The platinum or precious metals manager for an oil refining company should have the necessary expertise to aid in minimization of platinum losses for the oil refiner for the first and fifth stages above. In the fresh catalyst manufacture stage, the agreement with the catalyst manufacturing company for platinum settlement could stipulate 98 % to 99.5 % platinum return for the settlements. The platinum settlement requires that the oil refiner and catalyst manufacturer or platinum reclamation companies for the platinum settlement have appropriate analytical data (platinum assay, LOI for solid content) to permit effective conduction of the platinum settlement. Some oil refiners conduct platinum settlement with the catalyst suppliers, and some do not. I recommend conducting fresh catalyst platinum settlements to establish a reference initial platinum in use for the specific process unit that would be utilizing the fresh catalyst load and that the nominal platinum concentrations not be relied on as indicative of the reference fresh catalyst platinum. In the years that I managed precious metals for two oil refiners as a refinery technologist, several excess platinum troy ounces were returned to my companies’ platinum pool accounts after fresh catalyst platinum settlements with the catalyst manufacturers. In addition, the fresh catalyst platinum settlement data provided a good reference basis for the subsequent platinum inventory in the reactors after the catalyst loading.
In the spent catalyst platinum reclamation, a similar legal agreement could stipulate another 98 to 99 % platinum settlement with some additional platinum percent penalties for coke, catalyst alumina state (alpha or delta) and metals impurities. Thus, based on the two platinum settlements for fresh and spent catalyst for a catalyst life cycle, platinum losses due to contractual agreements and lack of the appropriate level of platinum management expertise by the oil refiner could lead to platinum losses in the range of 3 to 5 wt. % for the oil refiner.
Major additional significant losses could occur in stages 2 to 4 listed above. These combined areas of catalyst loading, in unit catalyst usage, catalyst dumping, and precious metals management are so intertwined and extensive that I strongly recommend securing the services of experienced technical experts who understand clearly the three major catalytic reforming technologies – semi regen, cyclic and continuous catalytic regeneration reformers and how their operations could greatly contribute to significant platinum losses. If you also own paraffin isomerization units and other process units that use platinum catalysts seek the assistance of a technical expert who fully understands platinum or precious metals management as well as the operations of the relevant oil refining process units that utilize platinum catalysts. An excellent oil refining expert could also work with your engineers and other relevant oil refinery personal on proactive steps for cost efficient catalyst management, process monitoring, and optimization and equipment management to minimize platinum losses.
Sandie Brandenberger and Ka Lok (UOP)
Directionally the higher O2 level is better for metal dispersion during oxidization. UOP recommends a minimum of 5% with typical maximum O2 content of 8-10 mol% based on the seal oil combustion limits. Dry seals or nitrogen purge seals allow higher O2 content without explosive conditions. If there is a history of coke ball formation or damage to reactor internals, maintaining a maximum of 3 mol% oxygen during the oxidation step should be considered and should be determined on case-by-case basis. When O2level is lower than desirable level, extending the hold time during the oxidization step will directionally improve metal dispersion.
Peter Eckels and Ka Lok (UOP)
If the coke content is very low in comparison with the coke burn capacity of the CCR unit, the operation can be limited in one of a few ways. A minimum gas flow is required to ensure the catalyst is properly dried before leaving the regenerator and returning for reduction. Sufficient flow must be maintained to protect the electric heaters and heat the catalyst for chlorination at low coke regeneration conditions. In some cases, the regeneration vent gas valve or makeup air valve to the regenerator is/are not in a stable control range. These are the consideration factors operating the CCR in standby mode.
There are several basic means of operation if normal White Burn cannot be maintained continuously. These may not all be available for all units.
Grey Burn mode is an operation with a mixture of nitrogen and air to the bottom of the Regeneration Tower to overcome the low flow limitation of the electrical heater. But the oxygen concentration for oxychlorination will be lower than normal operating conditions, reducing effectiveness of metals redistribution. Oxygen control could be harder in this operation.
Black burn catalyst circulation with regeneration allows an even laydown of coke on the catalyst inventory. Catalyst regeneration is operated in intermittently when coke on catalyst reaching the target level. The CCR will have to start with black burn mode first before switching to white burn mode and therefore a small portion of the whole catalyst inventory may not be regenerated in white burn mode. This operation mode uses 100% of catalyst inventory in the system to build up coke and therefore it maximizes the time interval between intermittent regeneration. This mode allows operation to monitor chloride and coke levels on catalyst and enables operation adjustment accordingly.
No catalyst circulation allows coke laydown of coke on catalyst inventory only in the reactor stacks. The catalyst regeneration is done in intermittent manner. This operation mode allows the regeneration in white burn mode continuously. The advantage of this operation mode is operation simplicity because operation does not require switching between black burn and white burn modes. However, the time interval between regeneration could be shorter due to not all the catalyst inventory in the system is available to build up coke.
Soni O. Oyekan (Prafis Energy Solutions)
The current challenges of low coke naphtha operation for the CCRs have been forced due to low severity operations. The low severity operations have been caused by factors such as ethanol blending and diesel to gasoline price incentives which have led to lower endpoint cut naphtha and low octane severity operations for catalytic reformers. Operating the catalyst regenerator section in the reactivation of catalyst with low coke can lead to significant catalyst and equipment damage. In addition, over several cycles of catalyst circulation, significant catalyst activity declines would occur due to inadequate catalyst reactivations. The greatest challenges, however, in low coke naphtha reforming in CCRs are operations with attendant risks of significant catalyst and equipment damage in the catalyst regenerator.
Catalyst circulation is typically recommended to ensure minimizing the chances for stagnant catalyst layers in transfer pipes that can become plugged leading to possible additional significant challenges in the reactor section. The methods utilized to manage the low coke operation is usually the preference of a specific oil refinery staff and what they are comfortable with. I also recommend catalyst circulation to minimize catalyst transfer plugs and to permit catalyst fines removal. Catalyst circulation would also permit getting a good assessment of the catalyst coke and when to re-start the regenerator section. One of the CCR technology licensors has recommended that their catalyst regenerator equipment could be modified to permit operating at lower coke levels in the low range of 2.0 to 2.5 wt. % coke and you can avail yourself of their services.
To use a proactive process based novel inventions to optimize low coke naphtha operations in CCR units, please review Oyekan, S. O., Rhodes, K. D., Newlon, N. K., US Patent 8,778,823, July 2014 assigned to Marathon Petroleum Company and Oyekan, S. O., Robicheaux, M. G., US Patent Application 2014/0138282 A-1, May 2014.
Jim Norton and Chris Steves (Norton Engineering)
The caustic treating off gas stream is primarily air that has been partially depleted of oxygen during the oxidation of mercaptides to disulfides in the caustic regeneration step. The off gas also contains entrained mercaptide and disulfide species as well as entrained water and caustic. The stream will also carry over LPG or gasoline that is entrained in the caustic and is then stripped out during the oxidation step.
Many refiners dilute the off gas with fuel gas to ensure that even with residual oxygen it stays above the upper flammability limit. The off gas may then pass through a KO drum to remove liquid carry over andis normally incinerated in some sort of thermal oxidizer (such as at the sulfur recovery unit) or combusted as a waste gas stream in a fired heater or boiler. The make up the stream containing residual oxygen mixed with residual hydrocarbons make it difficult to send the stream anywhere other than for full combustion oxidation.
The line is subject to plugging but can usually be cleared by steaming. It should be set up for easy steam out. Corrosion is also an issue can be minimized be eliminating any dead legs that could allow caustic material to accumulate.
Matthew Meyers (Western Refining)
One way to increase refinery distillate yield if there is not an O2 or regenerator temperature limit is to increase the upstream distillation efficiency to minimize the amount of 700 F minus boiling point material to the FCC. Reducing lighter material in the VGO reduces the crackability of the feed. The typical results of this are lowering the API gravity and the aniline point while slightly increasing the VGO tail, sulfur and Conradson carbon number. The end point should be monitored to make sure the feed nozzles can maintain good vaporization. The effects of this shift alone will cause higher LCO, slurry bottoms and coke yields. The best way to mitigate the increased slurry yield is by changing the catalyst formulation to target the optimum zeolite/matrix surface area ratio. As more bottoms are converted to LCO, the coke yield will increase. If the feed is left alone and riser temperature dropped by 40 – 50 F, the increased coke yield from increasing the matrix can utilize the air blower capacity to some extent. If blower capacity still remains, the refiner may increase the VGO draw from the crude unit and thus the amount of residue in the VGO while increasing catalyst addition rate to guard against metals and not allow activity to drop too much. Care should be taken not to exceed the feed nozzle vaporization limit or the metallurgical temperature limits in the regenerator. It’s also important to closely monitor sodium levels in the HVGO as well as metals on ecat.
Another option, if available, is to recycle slurry bottoms or HCO after the riser temperature has been decreased. If the air blower or regenerator temperature is near a limit or there are environmental concerns with increasing SOx, recycling HCO might be a better option since it will produce less coke with less sulfur. However, the slurry API and viscosity must be watched to make sure it doesn’t go off spec. Also, the slurry reflux and LCO pump down might need to be increased and the heat balance of the column will require adjustment to maintain good LCO distillation spec. As HCO is removed, the pump down will decrease, allowing the potential for an increase in LCO end point. It should be noted that the cracked stock will make more coke and dry gas and can rapidly deplete the excess air availability or wet gas compressor capacity. Also, decreasing riser temperature will increase the crackability of the slurry bottoms circuit, increasing the chances of exchanger fouling. Therefore, the recycle should be added slowly for every 10 deg decrease in riser temperature with 2 to 3 days between each increase to account for diurnal fluctuation.
Western Refining Company recently conducted a trial utilizing the first option above resulting in increasing the LCO yield from 20.2 to 24.3 % while maintaining similar slurry bottoms yield of 4.2%. For the catalyst change to lower z/m to be economical, the value of LCO must be at least 30% over LCC due to a decrease in conversion and loss of volume yield. As the zeolite SA is reduced there is also less of a requirement for rare earth, which can affect the economics, favoring the transition. This also assumes that the alkylation unit is able to remain fully utilized by either zsm additive addition or outside olefin purchase.
Ray Fletcher (Intercat)
The standard process variables influencing LCO production include:
1. Reduce riser outlet temperature (+0.75 wt% for -10°F)
2. Increase preheat temperature (+0.15 wt% for +10°F)
3. Reduce gasoline and point (+1.7 wt% for -10°F)
4. Recycle slurry (LCO ~30-40% of conversion)
5. Increase CRC for partial burn units (~1-2 wt%) 6. Reduce catalyst activity (0.25 wt% for -1 wt%)
FCC optimization rarely proceeds through single variable shifts. The most typical variable shifts for maximum LCO include reduced riser outlet, reduce gasoline and point, reduce catalyst activity via lower catalyst addition rate, and recycle slurry up to the unit constraints (typically main air blower or wet gas compressor) plus optimization of catalyst circulation rate via preheat temperature.
The standard catalytic variables for LCO maximization include:
1. Decrease zeolite concentration
2. Decrease rare earth on zeolite
3. Increase matrix composition (acid sites residing in pores greater than 8 Å)
4. Optimized catalyst architecture. This may be defined as pore volume or accessibility depending on your catalyst supplier.
As stated in the question, the primary impact of reducing riser outlet temperature by 40-50°F is a substantial increase in slurry production. Slurry production, as described above, is best controlled through a balance of process variable and FCC catalyst optimization.
An additional independent variable available to the FCC operator is to manipulate the zeolite-to-matrix ratio of the circulating inventory of the use of additives. This can be carried out through various additives currently available on the marketplace. Intercat has experience in utilizing Bottoms Cracking Additives in over 41 cat crackers. One unusual characteristic of Intercat's BCA is the observation that this additive does not negatively impact the main air blower or wet gas compressor thus enabling the refiner to base load 10% of this additive into the circulating inventory within a seven-day period.
This enables the refiner to achieve maximum LCO yield when the market is demanding LCO with the ability to "turn off" the additive when it is no longer profitable. This enables the refiner to avoid long change out times with the base catalyst. It is possible to swiftly return the unit to a more typical zeolite-to-matrix ratio on the back side via the introduction of a maximum zeolite bearing additive.
David Hunt (Grace Davison Refining Technologies)
In general the following process changes should be made as a refinery moves from a maximum FCC:
• Gasoline/ conversion operations to a maximum LCO operation:
• Remove Diesel range material from the FCC feedstock
• Reduced Gasoline endpoint
• Reduce FCC conversion by o Reducing Riser Outlet Temperature; o Higher Feed Temperature and o Lower Ecat Activity
• HCO or Slurry Recycle
• Catalyst Optimization
Increased slurry cracking, maintaining C3+ liquid yield and gasoline octane are key requirements of a maximum LCO catalyst system. In general, a maximum LCO catalyst is a low zeolite/matrix surface area catalyst with low to moderate activity and excellent slurry cracking qualities.
The primary challenge with a maximum LCO operation is high slurry yield when conversion is reduced. Grace recommends a MIDAS® or a zero rare-earth REBEL™ catalyst to ensure low slurry yields while maximizing LCO.
OlefinsUltra®, Grace Davison’s high activity ZSM-5 additive, is often required in maximum LCO operations to maintain C3+ liquid yield and gasoline octane. Operating at reduced conversion to maximize LCO will reduce the total product volume. Lower product total volume can reduce the total profitability during maximum LCO operations despite additional LCO production. OlefinsUltra® is critical to ensure profitability by increasing gasoline octane and liquid yield.
Lower riser outlet temperature in the order to 40 to 50 deg F will greatly increase LCO but will also create other challenges including:
• Lower C3+ liquid yield and gasoline cetane
• Higher slurry yield
• Potentially poor feed vaporization and riser/reactor coking OlefinsUltra® can be used to recover gasoline octane and liquid yield as discussed above. Reduced feed vaporization can be an issue when operating at reduced riser outlet temperature particularly when processing residual feedstocks. There is a practical minimum riser outlet temperature to minimize coking and ensure good catalyst stripping efficiency. Generally, operations less than 920 deg F are not commonly practiced and the minimum riser outlet temperature for some units could be considerably higher than 920 deg F.
Injection of a recycle stream downstream of the FCC feedstock will increase the riser mix temperature at the base of the riser which will increase feed vaporization at reduced riser outlet temperature. Of course, recycle and the use of a good slurry cracking catalyst like MIDAS® or REBEL™ will minimize slurry production. Optimal recycle streams to maximize LCO and total profitability were discussed by Hu. (2) A high porosity catalyst like MIDAS® or REBEL™ can help ensure fast feed vaporization at lower reactor temperature and minimize slurry yield or reactor coking (1). Feed injection nozzles that atomize the feed well are also critical to ensure the feed is efficiently vaporized at reduced riser outlet temperatures.
When reactor temperature is reduced and the feed temperature is increased to boost LCO yield, the air blower demand will be reduced. The wet gas compressor load will also be reduced because of less LPG and dry gas production. The refiner can take advantage of this additional capacity in many ways such as:
• Increased feed rate
• OlefinsUltra® ZSM-5 to increase LPG olefins to the wet gas compressor or alkylation unit constraint
• Heavy cycle oil or slurry recycle to minimize slurry production To ensure full profitability the FCC should operate fully constrained whether it’s operating in maximum LPG, gasoline or LCO modes.
(1) Hunt, et al, „Maximizing FCC Light Cycle Oil Operating Strategies“, Catalagram No. 104, 2008, pg
(2) Hu, et al, „Strategies for Maximizing Light Cycle Oil“, NPRA Annual Meeting 2009, San Antonio TX, AM 09
Mike Teders (Valero)
Valero participates in the Solomon survey that benchmarks the refinery process units for energy and reliability. Independent to that commercial survey, we have benchmarked our FCC’s on a yield basis using a constant pricing model, accounting for the feed quality differences. The results of the yield benchmarking are used to identify underperforming assets for potential capital improvements. Most recently, we have embarked on an aggressive unit monitoring program that utilizes the refinery data historian to report over 100 key process indicators of performance and reliability in a central data base.
The goal is to prevent unplanned downtime by monitoring key variables such as cyclone velocity and air distributor pressure drop. Valero has a separate energy stewardship program that each refinery uses to monitor energy efficiency on a unit-by-unit basis. We also utilize the catalyst supplier to review operating, yield and catalyst data to identify any issues as early as possible.
Dwight Agnello-Dean (BP)
This topic of slurry oil flash point and control has been a recent discussion topic at our FCC units. Collective inputs indicate the range of flash points temperatures are from 140degF to 220degF. We have demonstrated that greater than 200 deg F flashpoints can be achieved with main column bottom steam stripping. These represent units with both internal fractionator steam stripping and external slurry oil strippers. This question is similar to one addressed in the 2008 Q&A. In the responses Sexton reported substantial gains in flashpoint resulting from moderate amounts of stripping steam. Stripping steam tests conducted at BP units confirm the reported higher flashpoints at higher steam rates although with varying degrees of success. One unit only realized 10 deg F of increased flashpoint for every 1000lb/hr of steam. Storage temperature guidelines specify storage temperatures are not to exceed the slurry flashpoint temperature. Storage temperatures range from 100 -200 deg F.
Matthew Meyers (Western Refining)
The typical slurry oil flash point can be maintained well over 200 F on average if the quench is well distributed. If the quench stream(s) are not well distributed, stripping steam may have little effect on the subcooled regions of the bottoms. For a 100 lb/hr increase in steam, the flash can increase by as much as 20 F in a well distributed bottom. However, if there is not a quench distributor and the quench flow is too high relative to the feed rate, the increase may not be noticeable. Also, too much steam can adversely affect tower operation, especially bottoms level indication. The increased steam flow is likely to form large bubbles that may break around the cool, denser quench streams to cause fluctuating and false level indication. The problem may be exacerbated at reduced feed rates. One alternative to assist the stripping efficiency is to route some of the quench directly to the bottoms pumps, allowing for the bottoms liquid to be more uniform and closer to its bubble point. Care should be taken to make this change gradually to ensure the bottoms temperature remains well below 700 F.
The asphalt and chemical cleaning industry have documented the observation that oily residue and asphalt blending components release VOC’s after processing. This cannot be predicted from the flash point of the material and is most likely due to thermal cracking. According to the article, “Better understanding needed for asphalt tank-explosion hazards,” Oil and Gas Journal Sept 1989: The amount of cracking that may produce combustibles increases with tank storage temperature and decreases with time.
One tank at a storage temperature between 160F and 180F had a vapor space LEL above range and H2S of 210ppm. Another tank at a much lower storage temperature, between 120F and 140 F, and had much lower levels of combustibles and H2S.
Dwight Agnello-Dean (BP)
For us, as I'm sure for it is for others, minimizing FCC slurry exchanger cleaning has been a continuous improvement effort for quite some time. As a result we have implemented best practices in the areas of slurry circuit and fractionator operations and design. Through these efforts we have some units that only need to clean during cycle ending turnarounds. Others look for strategic opportunities during turndown periods for cleaning. At my own location which has two FCC units feeding mostly hydrotreated gasoil we clean approximately one exchanger per year.
Mike Teders (Valero)
Slurry exchanger cleaning frequency can range from as little as a few days (from an upset) to several years depending on the service and configuration. A few of the FCC’s in the Valero system have spare slurry exchangers so on-line cleaning does not impact unit availability. Slurry antifoulants have extended the time between slurry exchanger cleanings in many of our FCC’s. One of our FCC units increased time between cleanings from 1 year to 4 years by utilizing a chemical additive and using best practice methods for mitigating fouling in lain column bottoms service. These best practices include maintaining good velocity (4 – 9 fps) in the main column bottoms heat exchanger tubes and main column bottoms quench to mitigate coke formation in the main column bottoms circuit. In some units we have improved the quench efficiency by using a pipe distributor.. Units without quench limit the main column bottoms temperature to 690 F maximum. We put limits on the main columns bottoms product gravity and/or LCO 90% point to minimize main column bottoms heat exchanger fouling. Typical slurry gravity limit is -4 API and LCO 90% point of 685 F maximum. In some locations we have backwash connections on the slurry lines to periodically reverse flow through the main column bottoms heat exchangers and remove any loose catalyst fines and small coke particles from the exchanger tubes. The backflush connections are typically used where the heat exchanger tube velocity cannot be maintained at greater than 4 fps.