Policy: Energy in an Election Year and Future of ICE Bans
Question 73: What is the current design philosophy in the lower section of a coker main fractionator (from tower bottoms up to first product draw) for controlling product quality and coke fines buildup?
SRIVATSAN (Foster Wheeler USA Corporation)
The main objective is to keep the coke fines agitated and then efficiently remove them from the bottom of the fractionator. A properly designed coke drum with low vapor velocity helps minimize the coke fines carryover to the fractionator. Proper C factor for tower sizing is critical to achieving the HCGO quality in low pressure cokers.
Now from a licensee standpoint, I am going to discuss the Foster Wheeler design illustrated on the slide. The DCU feed in our design is introduced directly into the fractionator, and the residence time is built into the fractionator. The feed is introduced through two rings: an outer ring and an inner ring which has holes in the bottom. It also has open ends directed towards the standpipe that is above the heater charge nozzle. What is happening is continuous agitation of the fractionator bottoms. We also provide an effective fines removal system that consists of a bar cage inside the fractionator, an external basket strainer, and a fines removal pump. On the slide, the bar cage is shown next to the standpipe. The objective of the bar cage is to remove relatively large particles out of the fractionator and trap them in the basket strainer that is outside. A fines removal pump takes a slipstream of the heater charge and then pumps it to the heater suction and out of the fractionator. The standpipe itself prevents particles – one-half inch and larger – from entering the heater. So, it is all filtered within the fractionator itself. The heater charge pump also has a coke-crushing impeller that can remove particles that are one-half to three-quarter inch in size.
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The coke drum overhead vapor enters below the shed trays. We employ shed trays for a couple of reasons: 1) They distribute the vapor, and 2) they serve as entrainment trays for the coke and tar particles. One could do away with the sheds, but there would be a slight effect on your HCGO quality. As the coke drum overhead vapor rises, it is contacted with a wash oil stream above. Since the cokers that are designed for maximum liquid yields operate under the lowest recycle possible, we employ an open wash zone. We do not have trays or sheds. It is an open wash zone using spray headers and full cone nozzles. The wash zone sprays help maintain the HCGO quality and also provide good control of the recycle. We also have a heat shield to prevent contact of the flash zone vapor with the pool of liquid. Again, this is an effective way to control your recycle operation. Further, for the HCGO and LCGO draws, we employ total draw pans in the fractionator. The two pictures on the slide show the fractionator internals. On the left is the standpipe, and on the right is the bar cage. You can also see the ring.
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SLOLEY (CH2M Hill)
I will focus mainly on the section above the bottom boot. Different licenses have different approaches in this area depending on their balancing capacity, reliability, and performance. There is no real clear-cut answer for this, but there are various combinations that are more common. The bottom section typically includes some type of recirculation system along with the coke catcher design and coke crusher pumps in the bottoms.
Two major purposes of the area above the feed entry are the entrainment of coke fines and the control of the recycle at the heavy ends of the coke drum. The overall product yields and unit capacity favors minimum recycle. This creates a severe combination of operating conditions and mechanical design criteria. Within these constraints, what is most common are (1) spray chambers and (2) baffle trays which may be either disc-and-donut trays in smaller units or shed trays in larger units.
In some older units, you saw conventional sieve trays. In modern units, spray chambers or spray chambers combined with baffle trays are the most commonly used configuration. High recycle rate units, however, make a grid wash more attractive.
Spray chambers have the major benefit of maximum reliability. There is nothing in the area underneath the sprays for coke to form onto, thus minimizing coking. Nevertheless, coke stalactites can form from the spray header itself; so the spray header needs to be strong enough to support this weight without collapsing.
Overall, spray chambers work well because they operate at low liquid rates. Against these benefits, spray chambers have a relatively low capacity for the same product quality because they are not as effective in the entrainment.
Baffles, either shed trays or disc-and-donut trays, require high liquid rates to be truly effective for de-entrainment. Few delayed cokers really have recycle liquid rates high enough for the trays to create a liquid curtain that makes them truly effective for entrainment removal. At low liquid rates, the trays also tend to coke because even small issues with installation of the trays out-of-level lead to zones on them where they have very low liquid at one end and high liquid rate at the other.
However, even when coked, the baffles rarely shut down the unit because of the large spacing between the baffles gives lots of space for coke to form without imposing pressure drop or flooding of the unit. A few units have used fresh feed to the unit going onto the shed trays to create the liquid curtain. However, this has a dramatic effect on the fractionator’s heat balance because it is cooling the vapors as they go up the tower and reduces total liquid yield.
The overall best approach tends to be a mixture of baffles and sprays. It gives better performance than a simple spray chamber. However, the baffles are still not completely effective. Grid washes are typically used in units that have high liquid recycle rates for process reasons. They are very effective in entrainment removal. However, they still have a risk of coking that is more significant. It is seen as an overall risky operation.
Conventional trays are rarely used below the heavy coke or gas oil for new units. If you look at the figures, highlighting a point previously mentioned, you will see that the first three designs all use a total collector tray above the spray, baffle trays, or grid wash. This gives better overall control of the low liquid recycle rate. Most units with trays in them have a partial draw of liquid which gives relatively poor control of the liquid rate, and one reason that makes them truly only suitable for high recycle units.
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Equipment cost differences between these are fairly limited. You should never let equipment cost between these configurations drive the selection process criteria, unless it significantly affects tower diameter. It should be the selection driver.
HERLEVICH (Marathon Petroleum Corporation)
I want to share some experiences from our cokers. We were able to achieve a seven-year run on our main fractionator when employing the flash zone gas oil strainer system, and we also have experiences from other cokers that only made a three-year run. In the area of fines removal, I would point out that there is also a proprietary design being used which employs sloped trays and a sump as another alternative to the method that Srini discussed. So, there are a few ways to design these systems.
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JOHN GORDON (The Dow Chemical Company)
What kind of monitoring methods does the industry use to track the accumulation of solids in the bottom of the coker fractionator?
PRIBNOW (CITGO Petroleum Corporation)
I think we ran 10 years on our coker for the turnaround cycle. You saw the pictures of the standpipes and how plugged they can get, so we monitor delta P on the standpipes. We also did thermal scans on the bottom where we pulled insulation from the bottom of the tower. We could often see how high the coke level was in the bottom of the tower relative to the location of the nozzles and the standpipes. It is not perfect, but at least it gave us some idea of whether we could make a 10-year run or if we would have to take it down in a year.
SRIVATSAN (Foster Wheeler USA Corporation)
You also have the nuclear level gauges at the bottom of the fractionator which should give you an indication of the coke level.
SRINI SRIVATSAN (Foster Wheeler USA Corporation)
The main objective is to keep the coke fines agitated and efficiently remove them from the fractionator. A properly designed coke drum with low vapor velocity helps minimize coke fines carryover to the fractionator. Proper C factor for tower sizing is critical for achieving HCGO quality in low pressure cokers.
In Foster Wheeler designs, the bottom section of the fractionator is kept agitated by bringing the entire feed through an inner and outer ring with rightly oriented holes in the bottom and open ends. The bottom section of the fractionator also has a tall standpipe and a bar cage with a fines removal system that serve as internal “filters” for coke fines removal.
The heater charge pump is equipped with a coke crushing impeller.
Coke drum overhead vapor flows to the coker fractionator and enters below the shed section. The sheds serve to distribute the vapor and as de-entrainment trays for coke and tar particles that could be entrained with the coke drum overhead vapor. Eliminating the shed trays could lead to slightly increased contaminant levels in the HCGO.
As the coke drum vapor passes upwards through the shed section, it is “washed” by an induced reflux, and a recycle stream is condensed. For ultra-low recycle designs, in order to optimize yields, we employ an open wash zone below the HCGO pumparound draw and above the shed decks. Wash oil is sprayed using spray headers with full cones ensuring full coverage. The wash oil serves to maintain HCGO quality in terms of asphaltene, metals and CCR.
Low recycle control is facilitated by segregating the feed liquid pool from the hot flash zone vapors utilizing a heat shield and feed arrangement that eliminates splashing.
Above the wash section of the coker fractionator, heavy coker gas oil (HCGO) pumparound and product are withdrawn from a total draw pan.
The schematic below illustrates the Foster Wheeler fractionator internals.
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EBERHARD LUCKE (CH2M Hill)
As far as I know, the fractionator bottom design has not changed much over the last years. The bottom draw (heater feed) has a slotted standpipe to keep coke particles in the tower, protect the heater charge pumps, and maintain a decent heater runtime between decoking shutdowns. Most heater charge pumps are also protected by suction strainers and/or a coke-crushing impeller design. The tower should also have a carefully designed bottom circulation system that takes the bottom product and routes it through a filter system before returning back to the tower bottom. If designed properly, a big portion of the coke fines will be caught in those filters and be removed from the system. Between drum vapor inlet and HCGO draw, the gas oil recycle system in the wash zone not only quenches the drum vapors to condense part of the stream, it also removes coke fines from the vapor stream and washes those down into the bottom. Wash zone designs vary from open spray chambers to disk and donut sections. Both can work if the required wash oil flow rate is maintained. In many cases, coker economics and ultra-low wash oil rates allow more coke fines to move up into the HCGO section. I would like to add that the same careful consideration needs to be given to the source of the coke fines, coke drum vapor outlet, and vapor velocities in the coke drum and in the vapor outlet nozzle, as well as any foaming issues observed in the coke drums.
Question 74: How effective are the following decoke methods in a delayed coker furnace: online spalling, mechanical pigging, and steam air decoking?
HERLEVICH (Marathon Petroleum Corporation)
The way the panel decided to answer this question was for me to give an overview of the different methods and a few of the pros and cons. Then one of the other panelists will present his actual experience. The mechanical method employs metal studded pigs which are pushed in water. You typically have multiple runs in several directions because of the changing sizes of the heater tubes. Water quality and pressure indicate the cleanliness of the tubes. The whole process is typically accomplished in 18 to 24 hours. One advantage is that this process removes all of the coke.
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The disadvantages of the mechanical method are it requires a heater shutdown and specialty contractor, and there is a significant amount of operator and maintenance involvement.
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The next method is steam/air decoking. Here the coke is spalled with a high steam rate at elevated temperatures, and then air is introduced to burn the residual coke. You accomplish this method in 24 to 48 hours; so, it takes a little bit longer than the other way. The advantages are that it removes all of the coke again and the firebox does remain hot.
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Then there are several disadvantages. The steam/air method requires a heater shutdown. There are environmental permitting issues for the emissions generated from the coke combustion. There is also the potential for tube damage. If you get a really hot spot, the metallurgy may be affected. It is hindered by any inorganic foulants, and you will have residual foulant in the tubes. Any residual will be problematic in the next cycle. This method requires significant operator and maintenance effort, as well as a fair amount of technical oversight. We station engineers on shift monitoring the combustion.
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One additional point does not show on the slides is that we have had issues with combustion products around nearby structures. Care must be taken because there are often people working in the vicinity and the combustion sources are at relatively low elevations. So, there are safety issues that need to be mitigated. I can remember one experience where people working in a column nearby had to stop their work after the continuous air monitoring system indicated problems. Here combustion products were naturally drafting into the open distillation column. Please be mindful of these hazards.
The last method we have is online spalling. This is more popular in our plants. We keep the heater running and then thermally shock the tubes by varying the steam and firing rates. Typically, you would have a multi-pass furnace configuration so that one of the sections is online spalling while the other sections remain charging the unit. The advantages are that the overall coker operates in parallel; the method has the shortest overall time from start to finish; there is no waste generated; and, the operators can completely execute the procedure. Our engineers are used to determining when it is time to spall, but the operators execute the procedure quite well.
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The disadvantage of the online method is that it achieves the lowest end-of-run temperatures. Unlike the mechanical methods, heater tubes are not being physically swept; so there could be some residual materials. The online method requires more frequent spalling intervals for that very reason. You can get tube and u-bend erosion because of the solids that are flaking off and then flying along at very high velocity as they pass through all downstream tubes and into the online drum. There is also a potential for tube plugging if a large chunk flakes off.
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PRIBNOW (CITGO Petroleum Corporation)
At CITGO, we actually perform all of those methods. We also do an offline spalling method, which is a modified steam-only decoke. If we want to measure effectiveness, we look at performance effectiveness. We also look at the cost in dollars for the company effectiveness.
Performance effectiveness: When we look at our startup run’s tube skin temperatures, mechanical pigging wins. Mechanical pigging scrapes that tube to bare metal. Tubes are like new again. Steam air decokes are the second most effective, but inorganics are left on the tube wall, which can be seed sites for coking. The third most effective technique is online or offline spalling. This is just from a cleanliness and effectiveness perspective.
Depending on your heater design, you may or may not be able to do some of these different methods. It depends if your heater has U-bends as to whether or not you can perform mechanical pigging. The bottom line is that the economics of each coker should be evaluated based on your oil-to-oil duration, how well the decoke can be executed, and which is the most cost-effective method. For example, at CITGO, we have four cokers, and each heater method is different. One heater utilizes mechanical pigging; one likes to steam air decoke; one, online spalls; and, one, offline spalls. It is not that we cannot decide; it’s about the economics. I think it is more about what is right for your coker. You can do an economic evaluation and evaluate your tube life; because with mechanical pigging, there is some potential of scoring tubes and shortening your tube life. Just evaluate that, and then go with what you feel is best, economically, for your company.
One comment on steam air decokes: You must have good instrumentation. There is a lot of risk with heating up tubes using this method. If there is not adequate instrumentation, accurate monitoring, or experienced engineers watching the decoke, you can do damage. We have brought in IR (infrared) scanning companies and monitor the steam air decokes with an IR gun throughout the whole process. That helps us watch the burn go through the tubes and push to make sure the operators are not slacking off and prolonging the outage. So, I think that extra monitoring helps prevent damage and minimizes downtime.
We have two identical heaters. We performed a mechanical decoke and a steam air decoke side-by-side. We sent a camera in the tubes and could see inorganics and coke were left on the inside diameter of the steam air decoke. This material can potentially be seeds to coking. That is the reason why we, at Lemont, feel a mechanical decoke is more effective than a steam air decoke for our heaters. We observed a 10% improvement in mechanical decoke run-length compared to the steam air decoke on that run.
Lastly, we have employed smart pigging. We have utilized smart pigs which can tell how much coke is left in the heater tubes. Inspectors will use smart pigs to measure the tube wall thickness. One concern with mechanically pigging is tube wall thickness. Earlier we talked about seeing coking in different places in your heaters or higher coking rates than normal due to tight oils. Yes, we have observed this also, which is why we used the smart pig. We saw that we had more coking in the convection section and had to go back and decoke further. Smart pigging is more expensive, but it is one way to tell how much coke you have left in your tubes.
SRIVATSAN (Foster Wheeler USA Corporation)
I want to highlight just one point. In terms of maintaining feed throughput, online spalling is probably the most effective technique as you remove only one pass at a time. Also, the duration to spall a pass is generally shorter than that of the other decoking methods. Over the years, we have modified our online spalling procedure. It is extremely effective in restoring clean tube metal temperatures on our proprietary double-fired furnace. As illustrated by the results shown on this slide, we start the online spall when the skins reach about 1200°F to 1250°F; and then after you complete the spalling procedures, the clean tube metal temperatures are about 900°F to 950°F.
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If you have a single-fired heater, it is possible to see the ratchet effect after every spall; that is, after every subsequent spall, you will not be able to get to the same tube metal temperature as the previous spall. You will eventually have to shut down and do a steam-air decoking or pigging. Since there is a more uniform heat flux in a double-fired heater, we have observed that we are able to hit the clean tube metal temperature each time. We know of refiners who just do an online spalling and shut the heater only during turnarounds.
JOHN BASING (CVR Energy, Inc.)
Are there any type of heaters or experiences that would justify definitely not trying the online spalling? Have you used it as a stopgap in between piggings?
EBERHARD LUCKE (CH2M Hill)
My experience as an operator is from working with a coker heater that was two-pass in one box. In that case, it was really difficult to separate the two passes and then do online spalling. We did manage to get it done, but efficiency was quite limited because we could only separate the radiation part. The convection section still stays. It was combined and generally stays in service, even with one pass online. So it is best if you have a bigger unit or two separate heaters. If you have just one big heater with two passes, online spalling is probably not the best way to go.
HECTOR GAMBOA-ARIZPE (CITGO Petroleum Corporation)
Is there an upper limit on the amount of water you would use during an online spall so that the coke morphology is adversely affected where you run a safety risk of not being able to cut it too hard; or worse, if it gets too soft on you and changes in oil properties?
SRIVATSAN (Foster Wheeler USA Corporation)
We have an elaborate procedure during which the water rates are varied during the spalling. I can put you in touch with our Operations folks who do this regularly.
HECTOR GAMBOA-ARIZPE (CITGO Petroleum Corporation)
I mean at Corpus Christi, we prefer to do the online spall. We do maybe three online spalls and then the steamer decoke, roughly in that frequency. I am just curious if there is an upper limit not to exceed; because if you do the procedure, there will definitely be a problem.
SRIVATSAN (Foster Wheeler USA Corporation)
I am not aware.
SRINI SRIVATSAN (Foster Wheeler USA Corporation)
These comments are primarily based on Foster Wheeler units having Foster Wheeler-designed delayed coking heaters. Please also refer to the 2005 Q&A and Technology Forum P&P presentation on “Fired Heater Design and Decoking Techniques” for more information on this topic.
Online spalling is the best selection for maintaining coker throughput as it only removes one pass from process operations at a time for spalling. The duration for spalling a pass and the whole heater is generally shorter than other decoking methods as the heater does not need to be shutdown. However, the effectiveness of spalling is dependent on the type of heater (single- or double-fired) and the spalling procedure used. Single-fired coker heater can have limitations on the recovery to clean tube metal temperature (TMT) due to less uniform heat flux as a result of burner firing from one side only. We have seen a ratchet effect in single-fired heaters where the after-spalled ‘clean TMT’ gradually rises on each spall until the time between spalls requires another type of decoke operation. Double-fired coker heaters with more uniform firing achieves a ‘near-new’ TMT almost every spall. As mentioned before, the spalling procedure/operation is the key to the effective spall. Foster Wheeler has evolved the spalling operation such that some DCUs run essentially without shutdown for five years plus between turnarounds using only spalling operations. The following plot shows the effectiveness of online spalling on a proprietary Foster Wheeler double-fired heater.
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EBERHARD LUCKE (CH2M Hill)
The original heater decoking method – steam air decoking – requires the operators to follow a very strict procedure to achieve a highly effective decoking. This decoking method has been proven in removing organic material like coke/hydrocarbon. In the past years, the processing of heavy oils derived from tar sands and similar sources brought inorganic materials into the refinery systems which found their way into the coker heaters. Those materials cannot efficiently be removed with steam air decoking. For that reason, many operators switched to the mechanical decoking method: the pigging of the heater tubes. The latest heater designs and procedures allow for very quick and efficient heater pigging. The only area of concern could be deformation of heater tubes over time (more oval than round) and areas/pockets of coke laydown that are not cleaned properly. However, use of smart pigs and documentation of heater tube conditions and deformation will mitigate most of these concerns.
The other concern I have heard is that of scratching the internal surface of the tubes, leaving an area that is more prone to fast fouling and coking and potentially thermal deformation. Online spalling is a method of decoking heater tubes while part of the unit stays in operation. There are various procedures for online spalling that can be applied depending on the unit/heater configuration. It is a very good tool to increase the heater runtime between pigging/decoking shutdowns, but it will never replace the need for steam air decoking or pigging. In most cases, online spalling can only be applied to the radiation section of the heater, not to the convection section (especially when the heater has a combined convection section for two radiant sections). Spalling also never removes all the scaling and coke laydown in the tubes; so the more often spalling is applied, the less efficient the procedure. In some cases it was reported that since the coke layer was in the heater for a longer period of time, pigging was more difficult and took longer. So in summary: Mechanical pigging seems to be the most efficient method, in most cases. Online spalling may be used to increase the time between pigging shutdowns.
Question 75: What are the potential problems or negative impacts of utilizing FCC slurry/decant oil as coke drum OH (overhead) line quench oil?
SRIVATSAN (Foster Wheeler USA Corporation)
Again, FCC slurry/decant oil has a similar distillation range to HCGO but a higher endpoint. Although it could possibly be used as just overhead quench, we caution that if the slurry/decant oil is not be filtered properly, it will contain catalyst fines that could accelerate the coke deposition by settling in equipment or piping. We normally recommend using the blowdown tower bottoms as the primary source for quenching the overhead vapor line. The secondary means of quenching is provided using HCGO. LCGO and other gas oils, including slops, can also be used as desired.
PRIBNOW (CITGO Petroleum Corporation)
We do not have any experience using slurry oil as coke drum overhead quench. We utilize slop oil, as Srini mentioned, as a way to vaporize and reprocess that material. We charged slurry oil to our coker when excess capacity was available. However, we found that it degraded the heavy coker gas oil quality back to the FCC. The FCC conversion drops, and catalyst becomes dark; so, we tend not to do that much anymore.
SRINI SRIVATSAN (Foster Wheeler USA Corporation)
The purpose of the coke drum overhead quench oil is to reduce coking reaction by lowering vapor temperature and mitigating coke formation. A portion of the overhead quench is also condensed and forms recycle. Foster Wheeler recommends using the blowdown tower bottoms liquid as the primary means to quench the overhead vapor line, the secondary being the use of HCGO. LCGO and other gas oils including slops can also be used as desired. FCC slurry/decant oil has a similar distillation range as HCGO with a higher endpoint. Although it could possibly be used as an overhead quench, we caution that if the slurry/decant oil is not filtered properly, it may contain catalyst fines that could accelerate coke deposition by settling in equipment or piping.
EBERHARD LUCKE (CH2M Hill)
Although I never worked in a unit that used FCC slurry/decant oil as quench oil, we used it as coker feed; so, my concerns are based on that experience. FCC slurry/decant oil carries a significant amount of cat fines that are difficult to remove from the stream. So I would assume that with the injection of the slurry/decant oil, these cat fines will be introduced into the coke drum overhead system. The fines will end up either on the inside of the vapor line, in the bottom of the fractionator, or carried even further through the system and will act as seeds for coke buildup and cause accelerated fouling/coking of equipment. The cat fines will also most likely cause erosion in the nozzle that is used for quench oil injection. Additionally, quench oil distribution will be poor (but can be fixed by the selection of the correct material).
ROBERTSON (AFPM)
Before we get to the last question, I want to remind you that the Crude P&P is this afternoon at 2:00. During that time, a lot of these issues we have covered will be discussed in more depth. Tomorrow, the Light Tight Oil and FCC P&Ps are run concurrently. If you have any other issues you want to discuss that were not raised in this forum, please attend those P&Ps.
Question 76: What has been the industry experience in mitigating the impact of solids in the feed or coke fines in the fractionator side draws and recycled cutting water?
SHENKLE (Flint Hills Resources, Ltd.)
We use settling mazes in the water section to minimize fines without chemical injection, and then we vacuum out individual cells on a periodic frequency to recover the fines. We also fluff our freshwater tank and circulate it when we enter cooldown to minimize the fines buildup in the tank. We do not do anything in particular to minimize fines in the feed to the unit. We have a feed surge drum and maintain coarse suction screens on vacuum tower bottoms pumps in all of our crude units, which is not necessarily as common anymore.
Regarding products, spray wash obviously helps, but it a competing factor with minimizing recycle. We use the slotted screen standpipe for minimizing material at the bottoms pumps. We also filter heavy coker gas oil with automated filters at the unit. For the combined gas oil stream at the hydrotreaters, we have typical cartridge filters.
HERLEVICH (Marathon Petroleum Corporation)
Good crude unit desalter operation is always priority and actually does affect the coker unit. The coke drum velocity is very important. Expanding coker rate increases the drum velocity and results in fines carrying over from the drum into the main frac. Try to estimate actual drum velocity as this may become the unit limit at some point. It will also be helpful to strain overflash before sending it to the furnace recycle.
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In our flash zone gas oil section, we have a dual-spray configuration to capture particulates. On the heavy gas oil, we filter with 25-micron back-washable filters, which are actually quite complex contraptions. Gas oil filtration is important for the protection of downstream units. The newer gas oil filtration systems seem to run reliably, but we did struggle with older models for many years.
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Waterside quality is also very important to manage. Some of the Best Practices require the crane operator to clean out the settling basin two hours after the drum cut. We typically do this three times per week. The quench water tank has a cone bottom that is sparged to suspend the solids, and then that is partially drained into the maze. Coke hardness actually impacts the fines formation: harder coke yields more fines in the cutting water. Another consideration is the drill bit and piping erosion from fines in the cutting water. Also note that worn bits result in much sloppier cutting and will tend to generate more fines.
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HODGES (Athlon Solutions)
Cleaning coke fines out of your recycled cutting water is a key process that enables efficiency. As Bob mentioned, most modern designs use a maze to settle fines out. Typically, these processes cannot work without chemical addition. However, if you are having some challenges, I encourage you to contact your chemical provider. He can provide aids that, in most cases, will help settle the fines. We still occasionally run into systems designed to float the fines. So, depending on your design, you can get the appropriate chemistry to address your specific requirement.
BOB SHENKLE (Flint Hills Resources, LP)
In water, a settling maze is used without chemical addition, and solids that have settled in the maze are vacuumed out periodically from the individual cells. The freshwater tank is fluffed with water circulation during cooldown to minimize the accumulation of fines in the freshwater tank.
In feed, we do not do anything special. Our crude units have some course VTB pump suction screens in the crude units, and we have a feed surge drum upstream of the heater at the coker.
In column products, spray wash helps and also trying to minimize recycle to the heater. A slotted and screened standpipe is used to keep the solids out of the bottom's pumps.
We do filter the HCGO from the coker with automatic backflushing filters and then with conventional cartridge filters on the combined gas oil stream that goes to the hydrotreater.
EBERHARD LUCKE (CH2M Hill)
This question touches multiple issues in the coker unit and would deserve a very long and detailed answer. But to make it short, I will try to summarize the highlights. Solids in the feed have the potential to cause fouling in the pre-heat train of the coker, accumulate, and cause problems in the bottom of the fractionator, and they will cause increased fouling in the coker heater. If the problem cannot be dealt with upstream of the coker unit, the bottom circulation at the fractionation tower would be a good place to remove those solids. Unfortunately, this will not protect any pre-heat exchangers and may require a higher frequency of tube bundle cleaning or a change in heat exchanger design to better handle the solids in the feed.
Solids inside draws should mainly occur in the HCGO stream. The industry offers a number of filtration technologies that deal with this problem. Should solids also be detected in lighter streams like LCGO or even coker naphtha, a detailed study should be performed to determine the cause of this problem. In most cases, minor modifications to the tower design and/or unit operation will help eliminate this problem. Solids in the cutting water will always be a problem in units that are pushing capacity by reducing drum cycle times. The coke fines removal from the cutting water starts with managing the coke pit or coke pad. In my experience, one of the best filter media for coke fines is petroleum coke itself. So, if operators can create a barrier of coke that the cutting water flowing towards the maze has to go through, they will see that works nicely as coke fines filter.
The second issue to look at is the design and operation of the maze. Water should have sufficient residence time in the maze to allow for the settlement of coke fines which need to be removed frequently so as not to accumulate and cause coke fines carryover into the pump sump.
The last place for coke fines settling is the cutting water tank. Again, sufficient residence time needs to be provided for coke fines to settle. The bottom of the tank should be designed to allow for easy removal of accumulated coke fines, and the suction nozzle for the jet pump should be high enough above the bottom to not suck in coke fines once they accumulated in the water tank. Other technologies that can be applied to reduce the fines content of the cutting water are settlers, hydrocyclones, and customized filtration systems.
ROBERTSON (AFPM)
Those were the last remarks from the panel. Since there are no additional or comments from the audience, that concludes this Crude session. I want to thank the panelists. They did a great job. Thanks to Harold Eggert, the coach for this group. Please fill out the survey forms and deposit them in the box in the back. They are really important. I want to also thank you guys. The lunch is in the Exhibit Hall at 12:00. We finished a little early, so I am sure you are happy about that. Thank you very much.
Question 78: What procedures (maintenance and operational) are being used to minimize risk when swinging the blind between the reactor/main fractionator?
INKIM (PETROTRIN)
There are two scenarios to consider: shutdown and startup. I will address the shutdown scenario first.
For the shutdown scenario, catalyst is de-inventoried from the reactor and regenerator systems, and the main column and reactor are cooled down to 350°F. There are certain operational conditions that must be satisfied before the blind is installed. The reactor is gas-freed and being purged with steam. The vapor line blind flanges are soft-bolted and hot-bolted in preparation for the removal of the spacer and installation of the blind. The blind on the warm-up line is removed to allow the reactor to continue to purge and cool when the vapor line blind has been installed. The hydrocarbon level in the main column will be lowered to minimize risk of flashing and fire and to prevent any hydrocarbon vapors from coming in contact with Maintenance personnel. At this time, steam would be introduced via the try lines to provide a purge.
The pressure in the main column and the reactor will be reduced to a minimum, below 1 psi (pound per square inch), and the over-pressure valve would be placed in manual mode to lower the steam and gas from the main column to go towards the flare. The installation of the blind is a fresh air mask job, and all personnel involved would be required to wear the requisite PPE (personal protective equipment). The fire equipment would be available in the vicinity for the activity of installing the blind. The installation of the blind is done via a chain block operation. Once the blind has been installed, gaskets are placed on either side of the blind. Prior to their installation, gaskets are normally wrapped with a GRAFOIL™ material to keep them intact during the installation.
For the startup scenario, this is done after the regenerator has been dried out. The temperatures in the main column and the reactor would have been brought up: the main column to at least 250°F; the reactor to 300°F. At that time, again, the levels in the main column would be lowered to prevent any risk of flashing, fire, and any contact with Maintenance personnel. We would also reduce the reactor pressure down to around 1 psi. Similar safety precautions will apply as for shutdown; e.g., PPE, etc. Once the blind has been removed for startup, the spacer will be installed and flanges guaranteed; and then, we will continue with the normal startup process.
LARSON (KBC Advanced Technologies, Inc.)
In this particular situation, we considered that in general, some people may be changing this blind in what is called a hot operation. This was covered in an MPRA (Munich Personal RePEc Archive) 2010 Q&A Session. This procedure evaluates the benefits of using the blind in the open position all the time, which we have represented on the slide.
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We suggest that when Maintenance turns over the system to Operations, the unit must be air-free. In general, you will have refractory work after turnaround, so you must dry out the system. The blind can be in the open position as you continue to dry out the circuit with the blind open and let that air go all the way through the fractionator to further dry out the system. There will be a point in time when you will you need to introduce steam to air-free the system. That additional water is not a problem.
Then, as you have the system “air-free,” the next step will be to establish a catalyst seal. By the way, I am not really trying to represent anyone’s cat cracker here as a commercial, but you will want to establish a catalyst seal in the stripper and in the regenerator to isolate those vessels. As soon as you have circulated catalyst to establish a catalyst seal, you can then continue to heat up the reactor regenerator with torch oil and circulating catalyst. With the blind open, you continue to put oil in the main column as you would normally do to heat up the fractionator. The key step in this is that when you are doing this process, you will want the pressure gradient such that the pressure in the fractionator is over the reactor, which is over the regenerator.
This pressure balance allows you, with the blind open, to have any vapor that may come through the system to move back towards the reactor. You are burning torch oil in the regenerator, so it is not a problem if a little hydrocarbon vapor would actually back into the system. Having done this myself, I know that we did not see any hydrocarbon vapor back into the system. This procedure works fine. When we started up the unit this way, we saved about 16 hours. If you read the some of the material in the 2010 transcript, you will see that there is anywhere between 16- and 48-hours’ worth of time savings as a result of leaving the blind open during a startup.
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MICHAEL WARDINSKY (Phillips 66)
Phillips 66 operates 15 FCC units. Some of them follow an open blind startup procedure, and others have blind devices that are initially closed during startup. There are advantages and disadvantages to both approaches. I also want to point out that on the open blind procedure, you will really have to be careful if you are curing refractory on the converter side. If that hot flue gas gets over into the main fractionator (frac) bottoms where you have coke in bottom pumparound lines, you could start a fire down there and destroy those bottom pumparound lines. The other issue is that with the open blind procedure, we really advocate keeping the reactor pressure elevated above both the frac and regenerator (regen) sides; because if your blower trips during that process, the resulting pressure gradient will drive hydrocarbons down into the regenerator. At that point, you will have hydrocarbons in your regen flue gas line, which could lead to potential safety scenarios.
LARSON (KBC Advanced Technologies, Inc.)
The other point I want to make is that we learned about this practice when it was presented in 2010 as primarily a safety issue. At that time, a lot of people had installed delta valves or other devices in the circuit, so they were not exposed to flipping a blind and a hot service and potentially having an event. Unfortunately, I have seen a situation where this was done, and a flange fire occurred. Luckily, no one was hurt. So, I have firsthand knowledge of the value of doing this in a way that it is safe for personnel and reliable for Operations.
CHRIS GREEN (Marathon Petroleum Corporation)
When you are starting up with the blind in the open position, are there any risks around pyrophoric iron sulfide residue left in the packing if you have a packed fractionator? That would be worth discussing before you put steam through that system; essentially, when you still have warm air there.
LARSON (KBC Advanced Technologies, Inc.)
Yes, you should have that consideration. I should have prefaced my comment by saying that I considered this after a turnaround where you would have gone into the unit, done sufficient cleaning of critical pieces of hardware to eliminate the coke, and removed the coke from the packed section. We would probably recommend a slightly different procedure if you are going to have a blind opened without having the unit clean prior to this action. Absolutely, you have to consider the pyrophoric material and how you might manage it. The point is that I would still try to find mechanisms, either through a valve or with the blind opened, to where you do not expose personnel to poor safety situations.
J.W. “BILL” WILSON (BP Products North America Inc.)
You really do need to worry about that pyrophoric iron because there has been at least one fire of which I am aware where we literally burned down the main fractionator. It was pyrophoric iron and hot air that ignited.
CATHERINE INKIM (PETROTRIN)
There are two scenarios to consider: shutdown and startup. Let’s address the shutdown scenario first.
A. For the shutdown scenario, the vapor blind is inserted after the main column and reactor are cooled down (below 350°F) and the catalyst is de-inventoried from the reactor and regenerator systems. To insert the blind the following operational conditions must be satisfied:
1. Reactor is gas-freed and being purged with steam.
2. The main column is cooled, and the catalyst flushed from the system by circulating and flushing with gas oil.
3. The vapor line blind flanges are soft-bolted and hot-bolted in preparation for removal of the spacer and the installation of the vapor line blind.
4. The blind on the warmup line is removed as the warmup line to the flue gas stack is to be opened to allow the reactor to continue to purge and cool when the blind is installed.
5. The gas oil circulation is stopped and the level in the main column pumped away to a minimum. This is done to minimize the volume of hydrocarbon in the vessel and therefore minimize the risk of flashing and fire, as well as prevent any oil from coming in contact with maintenance personnel. Steam is then introduced to the column via the try lines to provide a purge.
6. Steam is opened on both sides of the vapor line blind to form a steam curtain, and the valve on the warmup line is cracked open.
7. Reactor pressure is reduced to a minimum (0.5 psi to 1 psi) by shutting down the MAB (main air blower), if in service, and reducing the steam flow to the reactor.
8. The main column pressure is reduced and maintained at less than 1 psi by reducing the gas makeup to the main column to a minimum and opening the overpressure valve to flare. At this time, the overpressure valve is operated on manual mode to ensure continued flow of gas and steam from the column to the flare system.
9. During the installation of the vapor line blind, the purge to the reactor instruments is changed from gas to air.
During normal operations, the blind is usually stored in close proximity to the vapor line flanges and is protected against weather elements to minimize corrosion. A chain block operation is used to insert the blind with new gaskets installed on both sides of the blind. Prior to the job being commenced, each gasket is wrapped with GRAFOIL® tape (graphite tape) to assist with keeping it intact during installation. Three gaskets are made available onsite in the event that one is damaged.
Contractors used for installing the blind are usually rotated so that there is more than one contractor with experience in the installation and removal of the blind. The blind installation is a fresh air mask operation as hydrocarbon vapor can be present and usually lasts less than 45 minutes with a crew of seven people. During the blind installation operation, all other maintenance activities in the vicinity are suspended and fire equipment – steam hoses and dry powder extinguishers – are made easily available. Insulation jackets are used to cover any hot lines that contractors may come into contact with during this operation.
B. At startup, the blind is usually removed following dryout of the regenerator. If the unit is new, hot air can be used to dry out the reactor prior to blind removal. If the startup is from a turnaround and there is coke present, preliminary reactor dryout is done with steam prior to the blind removal; however, the reactor dryout is completed when catalyst circulation is being established. To remove the blind, the following operational conditions must be satisfied:
1. The main column must be air-freed and inventoried with gas oil, circulation established, and circuits dried (i.e., all water removed). Temperatures must be warm enough to prevent steam condensation when the blind is removed. Efforts are made to achieve a main column overhead temperature of at least 250°F.
2. The reactor should be steaming to atmosphere via the warmup line with the reactor temperature being maintained above 300°F.
3. One hour prior to removing the blind, the purge to the reactor instruments should be changed from air to gas.
4. Once the required reactor and main column temperatures are attained, the MAB is shut down to allow for the reduction of the reactor pressure while maintaining a negative vessels differential pressure in preparation for blind removal.
5. Prior to the blind removal, the main column gas oil circulation is stopped and the level in the main column pumped away to a minimum. This is done to prevent any oil from coming in contact with maintenance personnel during blind removal. At this time, steam is introduced to the column via the try lines to provide a purge.
6. Reactor pressure is reduced to a minimum (0.5 to 1 psi) by reducing steam flows.
7. The main column pressure is reduced and maintained at less than 1 psi by adjusting the gas makeup to the main column and the overpressure valve to flare. At this time, the overpressure valve is operated on manual mode to ensure continued flow of gas and steam from the column to the flare system.
8. Steam is opened on both sides of the blind to form a steam curtain, and any accumulated condensate is bled from the vapor line via the bleed immediately upstream the blind.
Similar safety precautions and PPE are used as for blind installation. On removal of the blind, the spacer is installed in its place using two new gaskets. Once the flange is guaranteed, steam rates are increased and circulation of oil in the main column is reestablished. The warmup line valve is shut, its blind installed, and the reactor pressure increased in preparation for restarting the MAB.
MEL LARSON (KBC Advanced Technologies, Inc.)
The basics of this question suggest that the blind is being opened in a “hot” operation. This was partially covered in the AFPM 2010 NPRA Cat Cracker Seminar during the Operations/Technology and Reliability/Maintenance/Turnaround Q&A. The preferred option to minimize risk with improved personnel safety on startup is with the blind open.
Note that this procedure focuses on reduced personnel risk from opening the blind in a hot hydrocarbon system; thus, safety is priority No.1.
A general procedure is as follows:
1. When Maintenance turns over the system to Operation, the unit must be air freed. If refractory work was completed, there will be a defined stepwise heat up and hold sequence for the refractory repairs. Consider using the heat of the dryout procedure going all the way through the column (blind open) to further “dry out” the system.
2. After the refractory dryout is completed and the blind is in the open position, continue with the standard startup procedures to air-free the system.
3. Establishing catalyst seals in the reactor stripper and sufficient level in the regenerator are key steps in the process. With catalyst seals established, procedural changes can be utilized that adjust the pressure of the system to simultaneously heat up the reactor, regenerator, and main column with the blind in the open position.
4. Considering elevation difference of vessels and transfer lines, it is possible to prevent oxygen to the fractionation system by pressure adjustment. In general, consider a pressure profile such that main column pressure is greater than reactor pressure which is greater than regenerator pressure.
5. The unit heat-up process continues per the normal use of the air heater, torch oil, and catalyst circulation.
On the fractionator side, normal oil-in and heat-up can continue in parallel to the regenerator and reactor heat-up. This can be achieved as the pressure gradient is aimed toward the regenerator minimizing the possibility of oxygen into the fractionator. Once the systems have achieved the normal temperatures and feed to the riser is the next step, the unit the pressure profile can be adjusted to “typical” startup, followed by the introduction of feed in the normal manner. Companies indicate that between 24 to 48 hours of improvement in startup timing and lower risk to personnel from using an open-blind startup. There are a number of companies that have installed a valve in the reactor vapor with positive results. For more an in-depth discussion on valves, consider reviewing the transcript from 2010.
The blind or valving can be used as a means to isolate systems during maintenance. However, unit startups should avoid a closed blind with “hot” opening procedure in startup.
Question 77: What are the consequences associated with continuing to operate the FCC without main fractionator bottoms cooling circulation?
LARSON (KBC Advanced Technologies, Inc.)
We considered this question as three parts: What is the action to follow in the event of a loss of bottoms’ cooling? What is the consequence if you lose the net slurry product? What are the operational possibilities if you have a well-planned outage of the slurry circuit?
In situations one and two where you have lost circulation or you have lost the net bottoms’ product in the system here, we expect that you would shut down the unit consistent with your licensure’s emergency shutdown procedures. The consequence of losing the bottom circuit is that all this heat will transfer up the tower; however, your other pumparound circuits will be insufficient to handle the step change in heat removal. One of the consequences could also be that if the temperature continues to increase, you will, in fact, coke off the bottom of the tower.
Part Three of the Question: There are the rare instances where your specific configuration will allow you a planned outage. I have a colleague whose equipment has this capability because of its specific configuration. This client could take the bottom circuit offline after reducing feed rate and taking a number of actions to make sure there is enough heat removal up the tower to be able to service the pumparound pump. That is a unique situation, but it is one that may exist in the facility.
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MEL LARSON (KBC Advanced Technologies, Inc.)
This question is considered in three parts:
1) What is the action to follow in the event of a loss of bottoms (slurry) cooling circulation? 2) What is the consequence from a loss in net bottoms product withdrawal? 3) Discuss operating with a well-planned outage of bottoms circulation.
In situation one or two where there is an immediate loss of bottoms cooling and/or net bottoms product removal, the unit should be shut down in accordance with licensor or company emergency shutdown procedures. The loss of bottoms cooling will result in excessive heat moving up the tower which will exceed the ability of the intermediate pumparound or reflux systems to adequately cool the column for continuous operations. Depending upon the tower design, temperature excursions beyond the design may exceed metallurgical stress allowances. The consequence of immediate loss of cooling and/or net product with the attempt of continuous operation likely results in the bottom of the FCC main column coking rapidly.
Part 3 considers the limited possibility that in a planned manner, the combination of unit feed rate reduction and tower heat balance adjustments may allow for the bottoms system to be taken out of service. A rigorous review of the specifics on the tower heat balance and hydraulics with each pumparound system would be required. Product must be removed from the bottom of the column in any case.
CHRIS STEVES (Norton Engineering)
Each FCC main fractionator is designed differently; but in general, it will not be possible to run for very long without the bottom pumparound. In many cases, this pumparound stream provides up to 50% of the total heat removal required for the tower; so operating without it would require a significant rate reduction. Additionally, the bottom pumparound is used to desuperheat the reactor vapors as they enter the main fractionator. Operation without the bottom pumparound in service will significantly raise temperatures in the main fractionator and could lead to mechanical damage or coke formation in the HCO (heavy cycle oil) or LCO (light cycle oil) sections. With the loss of lower pumparound, it would be expected that catalyst fines will migrate into the HCO and LCO sections of the tower in higher concentrations than normally seen, which could lead to plugging issues.
JACK WILCOX (Albemarle Corporation)
The main column bottoms circulation circuit removes the largest portion of heat from the reactor effluent. If this circulation is lost for more than a few minutes, the unit must be shut down; otherwise, the following will occur:
- The bottoms liquid level will increase flooding the reactor effluent vapor line inlet line to the main column.
- The bottoms liquid residence time will increase, leading to increased coke formation.
- The internal temperature will increase, potentially damaging the column internals.
- As the column bottoms liquid level increases, catalyst fines suspended in this material will be carried up the tower.
Question 79: How do you mitigate the risk of falling coke deposits from the reactor plenum chamber and vapor line during initial vessel entry?
INKIM (PETROTRIN)
We have not had the experience of falling coke deposits on vessel entry. We usually experience difficulty in removing the coke deposits, and we do this by mechanical means. Prior to entry into the reactor, a visual inspection is made from the manway. It is typical to see stalactites from the reactor plenum. However, there have not been any cases of falling coke deposits. On the reactor vapor line, there is usually a thin coating of coke throughout. Generally, the vessel entry is done from the manway above the reactor stripper. Scaffolding is built from the top of the reactor stripper upwards. During the coke removal process, the top section of the reactor is totally boarded off to prevent any coke from falling to the areas below where work may be ongoing.
BULL (Valero Energy Corporation)
are various methods to mitigate the risk of coke falling. One of them is a proactive approach we have taken in various locations where we have seen coke form. We installed anchors to try and stabilize the coke. On our initial entry, we will go from the top to the bottom; starting at the plenum chamber. From the manways, they will initially go in and probe for coke and try to knock it down. From there, we will go down the reactor structure and then install seal decks at different locations in the structure.
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As part of the coke removal process, we have also put lugs at various locations inside the reactors to allow scaffolding to be put in more quickly. From a process standpoint, we also attempt to maintain a high enough flux to the reactor and vapor line to minimize the amount of coke that is formed. If there are any stagnant areas, we will also use a steam flow to try and keep some flux in the area. The last part of the question is about the vapor line. Before we startup, we will look at how much coke formation is there; and then depending on the quantity, we will actually go in to clean that out as well.
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ROBERT “BOB” LUDOLPH [Shell Global Solutions (US) Inc.]
I have found the effectiveness of dome steam to be hit-or-miss. What are the experiences of the panelists?
BULL (Valero Energy Corporation)
We have standards, Bob, that we work towards at each refinery. We have significantly increased our dome steam rates to four or five times the early design numbers, and we have seen improvements in those reactors after we have left.
INKIM (PETROTRIN)
When our reactor was replaced, we initially did not have any dome steam. At the first turnaround following the replacement, we found a heavy layer of coke deposits in the reactor dome which we had to jackhammer out. We have subsequently introduced dome steam, and now we have just the stalactites that could be removed. That was what worked for us.
LARSON (KBC Advanced Technologies, Inc.)
I agree with you that it is hit-and-miss over the number of cat crackers I have been on and on which I have worked with clients. I would lump them into this statement: Those people who have it in believe it works, as opposed to really having done any analysis to prove that it is positively giving a value. I have been in places where they do not use it all, and they are quite happy not to put it in. They do not see a benefit one way or the other. So, I agree with you that there is not a single answer. I think configuration of how that dome and the disengages are being put in has changed the industry quite a bit, so it is not clear to us. Opinion seems to be a bigger issue than hard analytics.
PUI-NANG LIN (Flint Hills Resources)
We do have dome steam application in our cat reactors. The key appears to be the ability to maintain a good steam chamber seal because the steam purge velocity is always hard to maintain after one or two turnarounds. These seal baffle gaps get bigger and bigger because they get warped from coke buildup. When we cannot maintain that perfect seal between the baffle plate, vessel wall, and explosion doors, we end up with even more coke buildup, both above and below the baffle. So, I think after the first turnaround, if you can maintain a good steam chamber seal, you should be fine.
CATHERINE INKIM (PETROTRIN)
We have not had the experience of falling coke deposits on vessel entry. We usually experience difficulty in removing coke deposits which is done by mechanical means.
Prior to entry to the reactor, a visual inspection is made from the manways. It is usual to see stalactites from the reactor; however, there have been no cases of falling coke deposits. On the reactor vapor line, there is usually only a thin coating of coke throughout.
Generally, vessel entry is done from the manway above the reactor stripper. Scaffolding is built from the top of the stripper section upwards. During the coke removal process, the top section of the reactor – plenum and cyclone area – is totally boarded off to prevent coke falling to areas below where work may be ongoing. Tarpaulin is used to aid in the collection of falling coke material.
JEFFREY BULL (Valero Energy Corporation)
We have used various methods to mitigate the risk of falling coke. One of those methods is to place anchors in areas where coke has historically formed in the reactor to give the coke a surface to which to adhere so that it is not prone to falling off either by being thermally shocked or during initial vessel entry. At most of our refineries, we will open all the manways on the reactor and probe for heavy coke deposits prior to entry. We start at the plenum chamber and move down the reactor structure. Most of the time, we are able to knock down some of the deposits from the support beams. The coke on the cyclone exteriors is normally much harder, and we have found that part difficult to remove. We then enter below the plenum at the manways and start chipping away where we can. This can be a slow process. In some cases, a seal deck is installed to allow work at multiple levels in the vessel. We have installed lugs in several sections of our reactors to provide extra support for the scaffolding. First, the reactor vapor line is often hydroblasted, and then another apparatus is used to remove the remaining deposits.
From a process standpoint, we try to maintain a high enough flux through the reactor and vapor line to minimize the amount of coke that is formed. In stagnant areas, we will use a steam flow to keep some flux in that area. Dome steam is common in the top of many of our reactors. We also try to keep our hot wall lines adequately insulated to keep cold spots from forming.
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