Question 69: What are some of the advantages and challenges in processing FCC slurry in a vacuum tower along with conventional atmospheric residue streams?
SLOLEY (CH2M Hill)
If you feed FCC slurry to the vacuum unit, the major benefit is recovery of diesel range material. High temperature limits in the bottom of the heavy cycle oil slurry fractionation system limit diesel recovery from slurry. Typical limits in this section in the FCC are 720°F, or 382°C; above that, coking starts to be a major issue. Significant diesel is still present at this condition. Diesel content of the slurry varies from 10 to 12% at a minimum, but many units run much higher. Industry average is in the range of 14 to 15% of the slurry.
Processing the slurry in a separate vacuum flasher is one method of recovering this diesel. The vacuum flasher typically suffers from solids deposit from the catalyst present. Processing slurry in the crude vacuum tower allows for some recovery of the diesel, and that implies that you have a diesel recovery section in the vacuum tower. However, it puts the FCC catalyst in the vacuum residue. As long as the solids in the vacuum residue do not get too high, this may be acceptable.
Most refiners processing FCC slurry in the vacuum unit produce asphalt as the vacuum tower bottoms product. The largest problem with slurry processing is that the slurry is a reactive product that is not going to a stable reactive equilibrium. High temperature plus the reactive slurry components tend to cross-link and see higher fouling rates in the vacuum residue circuit. Keeping the slurry percentage low and quenching in the vacuum tower bottoms to keep the temperature below 700°F, or 371°C, helps reduce fouling rates in the vacuum residue exchanges.
SRIVATSAN (Foster Wheeler USA Corporation)
We see limited advantage in processing FCC slurry in a vacuum tower. However, as Andrew mentioned, in some cases a dedicated vacuum flasher to recover the gas oil fraction could be beneficial. FCC slurry has a distillation range similar to HVGO (heavy vacuum gas oil), but it is inferior in properties compared to straight-run material, making it more difficult to hydrotreat.
A much more common option of disposing the FCC slurry oil is to introduce it as feed to the delayed coking unit. A number of discussions have taken place in previous Q&A forums on how much of the slurry oil can be introduced into the delayed coker. We normally recommend a maximum limit of 10%. Depending on the coker unit design, though, you may have to cut back on your vacuum residue feed rate. Only a small portion of slurry oil converts to coke; most of it just goes for a ride in the coke drum and ends up with the HCGO (heavy coker gas oil) fraction. If this HCGO is sent directly to the FCC without be hydrotreated, it will build a recycle loop that is difficult to handle. Also, if the coke drums are velocity-limited as opposed to coke-make limited, the addition of slurry oil, while still retaining residue capacity, could lead to excess velocity in the coke drum which may result in carryover to the fractionator.
SIMON ARENDS (Marathon Petroleum Corporation)
Are there any concerns about fouling with the catalyst or on the vacuum tower exchangers? Is it filtered or not filtered?
SLOLEY (CH2M Hill)
There are some concerns on coking. Normally, the content of slurry is restricted to such a low percent (less than 10%) that the additional solids do not present a major problem. Vacuum residue itself is not the easiest stream to deal with, and reprocessing slurry does not make the operation easier. But if the slurry content is low enough, it is not a catastrophic increase in the severity in the operation on fouling in most units.
VILAS LONAKADI (Foster Wheeler USA Corporation)
Andrew, you mentioned that you will be putting the slurry into the vacuum tower itself, right? If you do that in the main vacuum unit, the slurry will likely contain solids. Most of the transfer lines and velocities there are at the sonic velocities. So the catalyst and that velocity are going to these internals. Have you seen any kind of erosion which can happen to these internals and damage them?
SLOLEY (CH2M Hill)
There has been evidence of erosion. It is clear it is not a huge issue, but it has to be managed and tracked. Absolutely, there has been erosion.
XIOMARA PRICE (GE Water & Process Technologies)
I have a question about processing SCC (stress corrosion cracking) slurry in the vacuum tower. It is my understanding that the recommended wash oil rate is 0.3 to 0.5 gallons per minute per square foot for that tower. So if you are going to process slurry oil that has higher amounts of contaminants through there, do you recommend that they not change to help with the fouling?
SLOLEY (CH2M Hill)
There is some difference of opinion about that number, but I think the two issues are separate. The presence of slurry does not change what packing wetting rates need to be in the wash section.
JOHN HUGGINS (Huggins & Associates)
I want to emphasize the point made a moment ago about yields in a vacuum tower. That slurry is predominantly gas oil. So, if it is put back to the vacuum tower, it will predominantly recycle back to a catalytic cracker, if that is where gas oil goes in that unit. If that is the situation, why not recycle the slurry in the catalytic cracker and recycle the HCO (heavy cycle oil)? It is usually a bad economic decision because you can make more money by running virgin stocks through the catalytic cracker.
SRINI SRIVATSAN (Foster Wheeler USA Corporation)
We see limited advantages for processing FCC slurry in a vacuum tower. However, a dedicated vacuum flasher to recover the gas oil portion could be beneficial in some cases. FCC slurry has a distillation range similar to HVGO, but the properties are inferior (cetane, sulfur, and nitrogen, two-ring aromatics, etc.) compared to straight-run (SR) material, making it more difficult to hydrotreat. A more common option of disposing FCC slurry is to introduce it as feed to the delayed coking unit (DCU). We typically limit this amount to approximately 10% of feed; and depending on the limitations of the coking unit, you may have to cut back on vacuum residue (VR) feed rate. Since only a small portion of the FCC slurry/decant oil converts to coke, the remaining portion goes through the coker along with the rest of the cracked VR and mostly ends up with the HCGO. If the HCGO is sent directly to the FCC without hydrotreating, this may create a recycle stream that could become difficult to handle due to buildup of refractory type material. If the coke drums are velocity-limited (as opposed to coke-limited), the addition of slurry oil, while still retaining residue capacity throughput, could lead to excess velocity issues in the coke drums.
CHRIS STEVES (Norton Engineering)
Care must be taken if processing FCC slurry in a vacuum tower with atmospheric residue. In some cases, the condensed asphaltenes present in the FCC slurry oil may precipitate when mixed with the more paraffinic atmospheric residue, leading to fouling and plugging problems.
Question 70: What are the key areas to target when contemplating crude unit modifications to enable effective tight oil processing? In addition to these modifications, what other problem areas become evident once the actual processing begins?
HERLEVICH (Marathon Petroleum Corporation)
We run tight oil in six of our seven plants, and it is mixed in the basket of the other 10 to 20 crudes normally processed. Tight oils are not the predominant crude in most places, so we have not needed many modifications. In two instances, we did have tray fouling from drilling mud; so, we installed low fouling trays.
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We have projects underway to increase the amount of tight oil received at two plants. The general theme is to install equipment to knock out water, a new pre-splitter, and heat exchange. One of the configurations will employ a pre-splitter for just the tight oils. We will take the overhead into the naphtha circuit and the bottoms to the desalter. One refinery also requires a gas plant expansion to process the incremental light ends.
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The next two slides were prepared with a larger question in mind: What happens directionally on all the units in the refinery when processing tight oils? I will not go over these slides right now because there is quite a bit of detail on them. The second slide is just the other half of the plant.
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HODGES (Athlon Solutions)
Needless to say, there have been some interesting challenges discovered over the past several years of the running and processing of tight oils. I would like to offer another plug for the P&P sessions later on. Please check your program. There are two P&Ps that specifically address tight oil, and there will be a lot more information presented.
The biggest challenges really have to do with the unique composition of each of these tight oil's formation and the huge variation within a given field from cargo to the next. Often, tight oils are very paraffinic and have significant naphtha yields and very little resid production. If your normal slate is heavy blends, then your light ends processing ability might be inadequate to handle the higher naphtha yields.
Additionally, you might be forced to process blends of tight oils and heavy crude just to keep your coker running. Blending various crudes to meet the distillation profile, though, can often create compatibility issues with forced asphaltene precipitation. Some refiners, as was discussed earlier, have segregated crudes and tankage, added asphaltene inhibitors to the raw crude, and installed pre-flash drums or towers to reduce the light ends content in the hot pre-heat train. Less paraffins in the hot train, like C5 and lighter will induce asphaltene precipitation in the hot train.
Wax precipitation in the cold train has been observed as well. Wax inhibitors fed to the crude tankage or to the transportation of the crude can be used to address very severe issues. It is a good practice to use a simulation program to predict crude incompatibility and wax issues and then adjust your blends, if possible, prior to relying on chemical additives.
Since the gathering and distribution system for tight oils is still in its infancy, there is a significant amount of variation in the crudes that reach the market via trucks and railcars. I discussed this a few questions back as well. This often brings about huge variability in each of the trucks or railcars, depending upon which ranch it was produced on, and this fact demands that you develop a well-considered sampling testing and segregation plan. These shipments often require higher usages of H2S scavengers, which could create issues with tower fouling and increased COD (chemical oxygen demand) in the wastewater plant.
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SRINI SRIVATSAN (Foster Wheeler USA Corporation)
A good overview of problems when processing shale oil was presented by C. Sandu and B. Wright of Baker Hughes in the July 2013 issue of Hydrocarbon Processing. Some of the problems include:
• Corrosion in crude units due to addition of amine-based products in upstream production;
• Problems due to incompatibility of asphaltenic crudes and paraffinic shale oils affecting all areas from tank farm to CDU. Concerns are in tankage, crude pre-heat, desalter operation (dark brine with potential high COD), heater fouling in both VDU and DCU, and exchanger fouling in both the cold and hot trains;
• Problems due to high solids loading affecting desalter operation; and,
• The quality of the finished products.
GREG SAVAGE (Nalco Champion Energy Services)
Refiners processing high levels of tight oil, 75% and greater, often are outside of design as tight oil contains very little gas and residual oil content. As a result, several refiners have experienced major shifts in the heat balance and velocity profiles on the pre-heat train. Evaluation of changes in crude cuts and the impact to pre-heat and furnace fouling is recommended for refiners considering processing high levels of tight oil. Changes in pre-heat configuration, blending with crudes in compatible ratios, and the use of antifoulant chemicals have reduced fouling rates for several refineries.
In general, the higher the desalter operating temperature, the lower the crude viscosity will be and the faster the coalescence of water droplets, which results in improved dehydration and desalting. However, some tight oils contain high levels of light ends, which can limit the desalter operating temperature due to pressure constraints. Refiners increasing the amount of tight oil processed are recommended to evaluate the impact on desalter operating temperature and performance.
As light tight oils may contain high levels of inorganic solids, a mud-wash study and solids handling evaluation is recommended when processing tight oil. Oily brine has been reported by refiners processing tight oil due to solids and low interfacial tension (likely due to surfactants in the crude). Refineries processing tight oil are recommended to review brine handling operations and develop strategies for reducing oil undercarry like the use of reverse emulsion breakers.
Question 71: How do you rebalance your coker operation when processing atmospheric tower bottoms at your FCC during tight oil processing?
SHENKLE (Flint Hills Resources, Ltd.)
Our particular configuration for tight oil processing allows us to operate one of our cats with ARC (atmospheric reduced crude) without any impact to our coker operation. We typically have sufficient feed, but the obvious answer might be to purchase additional number 6 fuel oil or vacuum tower bottoms for operation. At times in our Pine Bend facility, we also have recycle heavy coke or gas oil, but not for extended periods of time. We do not have information on the long-term effects of recycling heavy coker gas oil, and we recommend consulting with your licensor for that mode of operation.
SRIVATSAN (Foster Wheeler USA Corporation)
It will be a challenge to fill up the coking unit if you do not have a residue fraction. In that ca.
BOB SHENKLE (Flint Hills Resources, LP)
At FHR, we have sufficient VTBs (vacuum tower bottoms) for maintaining coker operation. Other possible considerations:
• Run at turndown,
• Purchase number 6 fuel oil, asphalt, or vacuum bottoms on the market, or
• Recycle HCGO to the heater. FHR has done this for a short period, but we do not have history of its effects. The licensor should be able to provide guidance.
SRINI SRIVATSAN (Foster Wheeler USA Corporation)
Increasing the amount of tight oil production with hardly any residual fraction will lead to challenges in filling up the delayed coking unit (DCU). In order to maintain the DCU capacity, external purchase of HFO (heavy fuel oil) or VR will have to be made. If purchasing external feed is not an option, and if you have multiple drums, you may have to shut a module down. The DCU could also be operated in turndown mode with or without high recycle.
FCC slurry oil, if available, could be sent to the DCU as feed. As mentioned earlier, the quantity of FCC slurry that can be processed in a DCU as feed is limited to approximately 10%.se, external purchase of heavy fuel oil or vacuum residue may be required. If purchasing external feed is not an option and if you have multiple drums, then you could consider shutting down a module. The DCU could also be operated in turndown mode with or without a high recycle. As mentioned before, FCC slurry oil up to a certain point (10%) could be introduced as feed to the coker.
Question 72: What are potential causes of damage to the top section of coker main trays? What mechanical and process considerations are used in designing the top section trays for more reliable operation?
SRIVATSAN (Foster Wheeler USA Corporation)
Damages to the top section of the coker trays could be due to process-related reasons or mechanical or operational issues. One process-related reason is salt deposition. Usually, the salt is ammonium chloride. It is water-soluble, corrosive, and rapidly deposits at the right conditions, leading to severe loss of tray capacity and efficiency. The deposition is accelerated at low overhead temperatures, which may happen when you have too low of a reflux temperature or water coming in with your reflux stream. Low overhead temperatures could also result if you have too low a naphtha-LCGO (light coker gas oil) cut point. If you want to maximize your diesel fraction and are operating in a maximum diesel mode, the lower naphtha endpoints could lead to lower top section temperatures in the fractionator which accelerate the deposition of ammonium chloride. Normally the deposition is between LCGO draw and the column overhead. Some operations have also experienced salt deposition due to the presence of organic chlorides. Also, if you are adding slops directly to the fractionator, you must be careful to watch for the free water and salt content. We normally recommend having an external heater to dewater the oily slops before they are introduced into the fractionator.
Considerations for proper design include identification of the chlorides in both the crude and VR feeds and improving desalter operation. While this may help avoid deposition of inorganic chlorides, organic chlorides are not removed in the desalter. By introducing water intermittently though the reflux line, your ability to wash the top section of the trays will also help mitigate salt formation. The water is drawn off of several trays below and disposed.
Increasing the overhead temperatures is probably one of the better ways to control salt deposition and prevent the salts from precipitating in the trays. You could also balance the heat removal between your overhead condenser and the pumparound streams. If you have a low naphtha endpoint, a backend naphtha splitter could be used. Finally, the fractionator overhead drum has to be designed for adequate hydrocarbon and water separation. Operational issues can occur when water is introduced into the fractionator, which then causes a blowout of the vaporized water. We know of one instance during a startup operation when the spare LCGO pumparound pump, which had not been completely drained of water, was started. The rapid expansion of the vaporized water caused by the high temperature in the fractionator blew the top section of the trays between the LCGO section and the overheads. These slides show that event.
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Incorrect metallurgy in the top section could also result in damage to the fractionator top section. The correct metallurgy depends on the feed stock and contaminants. Normally, the material of construction – if you are processing, say, an Arab medium-type feed – is killed carbon steel from the bottoms up to the LCGO draw with 1/8-inch corrosion allowance and 410 stainless clad. Above the LCGO, it is normalized carbon steel with a 1/8-inch corrosion allowance. The trays are 410 stainless, and the distributor pipe and spray nozzles are 304L stainless. Foster Wheeler designs the overhead piping, fractionator condenser tubes, and the water boot in the reflux drum for a much higher corrosion allowance.
SLOLEY (CH2M Hill)
I want to reiterate that the occurrence of chlorides in most delayed cokers is nearly inevitable. Nearly everyone with a delayed coker will eventually end up waterwashing it, at least intermittently, in the top. When we have put the water back in the tower in the reflux, we have seen relatively few events of it causing tray damage because of that operation. If you look at the mechanical design limits that are standard in the industry for trays, you will see that trays are designed for a 60-pound per square foot distributed load on top and 300-pound point load for installation purposes. The key point is that all of the load is on top pushing down, and the tray rests on the tray ring. When you have an incident, as Srini just discussed, where water is being put in the tower lower down in a hotter section, the stress load is coming up the tower and trays are inherently extremely weak for a load coming up beneath them.
That is the real risk of tray damage comes from pressure surges from below Risks from water wash introduced in the naphtha are relatively modest to low You should not let that perception of risk prevent you from waterwashing the tower. If you damage trays more than once during water washing, you should really investigate your procedures around how you are adding the water. You should also look at mechanical solutions that make the trays much stronger. These are relatively inexpensive. However, the procedures and operational issues count as well.
SRINI SRIVATSAN (Foster Wheeler USA Corporation)
Damages to the top section of the coker main fractionator trays mainly occur due to Process related issues or Operational/Mechanical issues. Process related causes include:
• Salt deposition in the upper section of the trays, accelerated by low operating temperatures in the section. Usually the salt is ammonium chloride (NH4Cl) formed when chlorides in the VR feed, carried as a result of improper desalting, react with NH3 formed as a byproduct of thermal cracking. The ammonium chloride salt is water-soluble, corrosive, and deposits rapidly leading to severe loss of tray capacity and efficiency. Deposition is normally between the LCGO draw and the column overhead. If the overhead temperature in the fractionator approaches the salt deposition temperature, there is an increased risk of salt deposition and corrosion.
• We have also observed that some operations are prone to salt deposition in the top section of the fractionator due to the unexpected presence of organic chloride species. The temperature at the heater outlet is high enough to break the C-Cl bonds forming HCl as a result of hydrolysis, which then reacts with NH3.
• Introduction of slops straight into the fractionator also increases the risk of fractionator fouling if the slops contain free water and chlorides.
• Too low of a reflux temperature or too much water entrained with reflux can cause salt deposition and subsequent corrosion. Considerations for proper design include:
• Identification of chlorides in both crude and VR feeds.
•Improvements in desalter operation: While this may help avoid deposition of inorganic chlorides, organic chlorides are not removed in the desalters.
• Water-washing tower online: Foster Wheeler fractionator designs now include the ability to wash the top section of the trays by introducing water intermittently through the reflux line. The water is drawn off several trays below using draw-off pans to a flow-through waterwash coalescer, followed by their disposal.
• Increasing overhead temperature to ensure sublimation of salts, thus preventing the salts from precipitating in the trays: The salts are carried with the overhead vapor from the fractionator. Intermittent waterwash and condensation of the overhead vapor results in the salts dissolving in water and being drawn out as sour water. Low overhead temperatures can also occur when you have a low naphtha-LCGO cutpoint. A backend naphtha splitter could be used if lower naphtha cutpoint is desired.
• Balance heat removal between overhead condenser and pumparound streams: Optimizing the heat removal between the overhead condenser and LCGO/HCGO pumparound streams will lead to more desirable top tray temperatures
• Fractionator Overhead Drum: Design these drums for adequate HC-water separation.
• Fractionator Overhead Drum: Design these drums for adequate HC-water separation.
Operational issues occur when water is introduced into the fractionator causing a blowout of the vaporized water. We know of one instance during a startup operation when the spare LCGO pumparound pump, which had not been drained completely of water, was started. The rapid expansion of the vaporized water caused by the high temperature in the fractionator blew the top section of the trays between the naphtha and LCGO sections in the fractionator. Below are photographs showing the damage.
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Incorrect metallurgy in the top section could also result in damage to the fractionator top section. The correct metallurgy depends on the feedstock and contaminants. Typical material for the construction of a coker main fractionator processing typical Arab medium feed is as follows: - Bottom-up to LCGO Stripper Draw-Off: normalized KCS clad with 1/8” 410S SS - Above LCGO Stripper Draw-Off: normalized KCS: 1/8” Corrosion Allowance - Trays: 410-S stainless steel (SS) - Distributor Pipe and Spray Nozzles: 304L SS Foster Wheeler also designs the overhead piping, fractionator condenser tubes, and water boot in the overhead reflux drum for a higher corrosion allowance.
DENNIS HAYNES (Nalco Champion Energy Services)
One potential cause of damage is the deposition of ammonium chloride salts plugging the top section and also causing underdeposit corrosion. This type of deposit can form due to hydrogen chloride and ammonia partial pressure levels and temperature requirements for the system. Therefore, feed quality is another consideration. In systems where this becomes a concern, salt dispersant additives have been applied to minimize ammonium chloride deposition, plugging, and corrosion.
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