1995 NPRA Q&A - Heavy Oil Processing

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II. HEAVY OIL PROCESSING A. Fluid Catalytic Cracking Mechanical QUESTlON 1. How could on stream factors be improved, and what are the most frequent causes of unscheduled down- time? Does anyone utilize a formalized program to improve FCC on stream factor? ROSS: Many oil companies monitor the maintenance records of their catalyric crackers and develop proactive repair and replacement strategies to avoid surprises duringoperation. This is becoming increasingly important as refiners extend the run length between major turnarounds. For refiners with fewer units and less historical data, either a somewhat more reactive approach, or a conservative frequent re- placement policy may be appropriate to avoid problems with older equipment results. With computer data acqui- sition and control now common, every refiner should be monitoring not only process variables and yields but also engineering or calculated performance parameters, such as velocities throughout the unit, to anticipate problems. Improved operator training is a must to minimize human errors and avoid stressing the equipment by staying within design and safety specifications of the equipment. Ther- mal scans twice a year are also recommended to monitor refractory integrity. The most often cited reasons for unscheduled down- time include: power and utility failures; compressor or turbine problems; coking in a reactor/transfer line or slurry circuit; cyclone problems; expansion joint and/or slide valve failures; cracking in hot wall components (w-ye section, standpipe, etc.); and corrosion in the main frac- tionator overhead system. Of course, refractory failures and human error show up on most lists as well. ABRAHAMS: Some of our more frequent causes of unplanned shut- downs on FCC units have been instrument problems. One recent shutdown was caused by a broken wire on a shutdown circuit. A program to do preventive mainte- nance on all critical alarms and shutdowns has helped minimize this, although we have had to find the right balance at our plants between the advantages of preven- tive maintenance and the inadvertent trips that happen every time instruments are taken off-line. Another key to keeping FCCUs on-line, in our case, has been the opera- tion of the wet gas compressor. At one of our refineries, we have the luxury of having two compressors. So an outage there just results in a slowdown. Other formalized programs on the FCCUs include ultrasonic pipe thickness testing for corrosion monitoring, and thermographic surveys of refractory lined areas. We also have had either shutdowns or delayed restarts after revamping portions of our units during turnarounds, and we would recommend extra attention to modification design and installation. This has occurred both in reac- tor/regenerator type work and in gas plants. EMANUEL: Our two catalytic crackers each have their own weak- nesses that are inherent in any FCCU. But in our older unit in Big Spring, Texas, the most frequent downtime is typically caused by erosion in a reactor overhead system and erosion in the slurry section of the main fractionator. This is caused mainly because we are pushing the older unit way beyond its original design. Our newer unit, which is at Port Arthur, Texas, was started in 1991 and experienced typical start-up problems. We did have initial problems with a catalyst cooler, but the main problem with that unit has been, as mentioned earlier, power failures. We are still trying to work through a problem upstream on our power system to give us better reliability. As far as items that are formalized to improve our on stream factor, we practice thermal scanning for refractory hot spots. Also, on the newer units where there is gener- ally only one blower and one compressor, on-line moni- toring for rotating equipment is becoming more and more important. KELLER: On stream factors can be improved by implementing a consolidated Operating, Preventive Maintenance, and Proactive Reliability program that encompasses the fol- lowing: Operator awareness and support of operating guide- lines that can impact on stream reliability. Effective maintenance repair and troubleshooting, coupled with a strong PM program. Piping and pressure vessel corrosion monitoring. Vibration monitoring and oil analysis for critical rotating equipment. 44 Heavy Oil Processing

Transcript of 1995 NPRA Q&A - Heavy Oil Processing

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II. HEAVY OIL PROCESSING

A. Fluid Catalytic Cracking

Mechanical

QUESTlON 1.How could on stream factors be improved, and whatare the most frequent causes of unscheduled down-time? Does anyone utilize a formalized program toimprove FCC on stream factor?

ROSS:Many oil companies monitor the maintenance records

of their catalyric crackers and develop proactive repair andreplacement strategies to avoid surprises duringoperation.This is becoming increasingly important as refiners extendthe run length between major turnarounds. For refinerswith fewer units and less historical data, either a somewhatmore reactive approach, or a conservative frequent re-placement policy may be appropriate to avoid problemswith older equipment results. With computer data acqui-sition and control now common, every refiner should bemonitoring not only process variables and yields but alsoengineering or calculated performance parameters, such asvelocities throughout the unit, to anticipate problems.Improved operator training is a must to minimize humanerrors and avoid stressing the equipment by staying withindesign and safety specifications of the equipment. Ther-mal scans twice a year are also recommended to monitorrefractory integrity.

The most often cited reasons for unscheduled down-time include: power and utility failures; compressor orturbine problems; coking in a reactor/transfer line orslurry circuit; cyclone problems; expansion joint and/orslide valve failures; cracking in hot wall components (w-yesection, standpipe, etc.); and corrosion in the main frac-tionator overhead system. Of course, refractory failuresand human error show up on most lists as well.

ABRAHAMS:Some of our more frequent causes of unplanned shut-

downs on FCC units have been instrument problems.One recent shutdown was caused by a broken wire on ashutdown circuit. A program to do preventive mainte-nance on all critical alarms and shutdowns has helpedminimize this, although we have had to find the rightbalance at our plants between the advantages of preven-tive maintenance and the inadvertent trips that happenevery time instruments are taken off-line. Another key to

keeping FCCUs on-line, in our case, has been the opera-tion of the wet gas compressor. At one of our refineries,we have the luxury of having two compressors. So anoutage there just results in a slowdown.

Other formalized programs on the FCCUs includeultrasonic pipe thickness testing for corrosion monitoring,and thermographic surveys of refractory lined areas. Wealso have had either shutdowns or delayed restarts afterrevamping portions of our units during turnarounds, andwe would recommend extra attention to modificationdesign and installation. This has occurred both in reac-tor/regenerator type work and in gas plants.

EMANUEL:Our two catalytic crackers each have their own weak-

nesses that are inherent in any FCCU. But in our olderunit in Big Spring, Texas, the most frequent downtime istypically caused by erosion in a reactor overhead systemand erosion in the slurry section of the main fractionator.This is caused mainly because we are pushing the olderunit way beyond its original design.

Our newer unit, which is at Port Arthur, Texas, wasstarted in 1991 and experienced typical start-up problems.We did have initial problems with a catalyst cooler, but themain problem with that unit has been, as mentionedearlier, power failures. We are still trying to work througha problem upstream on our power system to give us betterreliability.

As far as items that are formalized to improve our onstream factor, we practice thermal scanning for refractoryhot spots. Also, on the newer units where there is gener-ally only one blower and one compressor, on-line moni-toring for rotating equipment is becoming more andmore important.

KELLER:On stream factors can be improved by implementing a

consolidated Operating, Preventive Maintenance, andProactive Reliability program that encompasses the fol-lowing:

Operator awareness and support of operating guide-lines that can impact on stream reliability.Effective maintenance repair and troubleshooting,coupled with a strong PM program.Piping and pressure vessel corrosion monitoring.Vibration monitoring and oil analysis for criticalrotating equipment.

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On-line monitoring systems (critical variables, per-formance trending, etc.) for critical equipment,Infrared thermography for mechanical and electricalequipment.Sound root cause failure analysis and solution engi-neering to reduce failure re-occurrence.

The most common cause of unscheduled FCC down-time is heat exchanger failure (leaks due to corrosion,fouling, etc.), especially in the associated HF alkylationand butamer units.

Yes, most refineries utilize formalized reliability pro-grams that include some of the elements mentioned in thelist above. It is rare, however, to find fully integrated/com-prehensive programs that derive the maximum on streambenefit that is achievable.

QUESTION 2.What parts of the unit become susceptible to failurewhen operating with run lengths greater than threeyears?

DEADY:I have a laundry list of the areas of the FCCU that

generally provide the most trouble after long run lengths.The first is refractory problems where refractory is comingoff and plugging catalyst circulation lines, or causing hotspots or bulges. The feed nozzles may also show wearand/or plugging. The slide valve or plug valve can havedamage or erosion, and there may be damage to air gridsor air rings. We have also seen damage to ESP plates andwires, regenerator stack valve damage, and erosion damageto the expansion joints.

EMANUEL:The top five problems we experience are refractory

failures, primarily in catalyst transfer lines; reactor over-head lines, as I mentioned earlier; flue gas scrubber ducts;regenerator cyclone lining problems, in the older units;and major rotating equipment such as the blower and wetgas compressor.

FRONDORF:In our Corpus Christi, Texas refinery, we are on a 4-year

turnaround cycle on the catalytic cracker. We concur withseveral of the other problem areas that already have beenmentioned. We would add that on units with a powerrecovery train, the expander will definitely become anissue. On single stage expanders, primary blade erosionhas been prevalent, and on multi-blade units, secondaryblade erosion may be expected. We have also, over theyears, experienced problems with expansion joints, par-ticularly the flue gas expansion joint.

At Lake Charles, Louisiana we have three identicalcatalytic crackers without power recovery trains. Review-ing our unscheduled outage history for the last 25 years

on those three units, roughly 50% of the unscheduledoutages were related to failures of the cyclone systems.Approximately 30% of the outages were related to slidevalves or transfer line problems. And the remaining 20%were miscellaneous other failures, e.g., expansion joints,compressor, and rotating equipment type items. We arealso on a 4-year cycle at Lake Charles.

KELLER:

Our total downtime is 8%. We have a planned turn-around that lasts a month and a half, every four years. Thatis 3%. All the unscheduled downtime adds up to theremaining 5%. That is 1% for heat exchangers; 0.6% forthe main air blower and expander; 0.1% for the reactorregenerator cyclones, the riser, and the air grid nozzles;0.3% for the flue gas cooler and piping; 0.2% for thereactor steam rings; 0.8% for the compressors; and allother causes account for the remaining 2%.

POTSCAVAGE:

Corrosion can cause premature failures of equipmentin a main fractionator overhead and the saturated gasplant. When we talk about corrosion, it is typically notgeneral corrosion but rather hydrogen blistering that is themajor problem. In trying to control hydrogen blistering,make sure you have an appropriately applied water wash.We will talk more about that in one of the later questions.Also, try to have a filmer in use that is designed specificallyto deal with hydrogen blistering. For example, the filmersused on crude unit overheads are not effective at control-ling hydrogen blistering. And having a good monitoringprogram is imperative. There are some on-line monitorsavailable in the marketplace. Preferably you should haveone that is hooked up to a data logger to determinenon-steady state hydrogen blistering activity. The mostreliable, accurate, and easy to use monitor we have seen isour HPC-11. It is readily moved from location to location,gives a quick response, and hooks to a data logger to helpmonitor non-steady state conditions.

ROSS:Although many refiners target 4- to 5-year runs, most

anticipate a short 2-week shutdown midway into the runfor minor repair work on chronic maintenance problemssuch as cyclone erosion; refractory repairs; compressorseals; and expansion joint and slide valve inspection/re-pair. Flue gas systems including tertiary cyclones, COboilers or incinerators, scrubbers and ESPs should also beinspected either as preventive measures or due to regula-tory requirements. Although thermal cycling is one of themajor contributors to refractory and equipment failures,a planned shutdown for inspection and preventive main-tenance is generally considered prudent.

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SHEN:There was an industry-wide survey conducted about

two years ago. The results show that there are two maincauses that contribute to about 90% of the unit shut-downs; 55% are caused by cyclone erosion and 35% arecaused by rotating equipment failure.

JAMES D. WEITH (Unocal Corporation):I am a representative of the other refinery in Wilming-

ton, California, (re: Mr. Keller), and we are proud of thefact that between our February 1992 and February 1995turnarounds our catalytic cracker had a 97.1% on streamefficiency. Of the 2.9% of the time it was down, 1% wasdue to six different electrical power outages, 1.5% wasbecause of flue gas steam generator leaks, and the remain-ing 0.4% was due to miscellaneous mechanical problems.

PETER G. ANDREWS (Consultant):Both Questions 11 and 12 are similar, and you can cite

anything on the FCC menu as to what shuts you down,all being unit-specific. Mr. Shen confirmed my experience:the major causes of FCCU shutdowns are cyclones androtating equipment. With this knowledge, review yourspecific FCCU operation to determine if a revamp/redes-ign is necessary to eliminate unscheduled shutdowns inthese two major areas.

DAVID S. McCAFFREY (Exxon Research & Engineering Company):Questions 11 and 12 are related and my comments

apply to both. Exxon’s FLEXICRACKING units aredesigned for run lengths of more than three years, and infact four-plus-year runs are becoming common. In theseunits, much attention is paid to the design of criticalcomponents like slide valves, cyclones, reactor riser andtransfer lines, regenerator grid, and the various vessel andgrid penetrations. We found that the major factors im-pacting run lengths are: running at conditions above aunit’s design rates and starting up after a turnaround withworn hardware. We do have a systematic research anddevelopment program for reviewing the conditions ofunits as they have turnarounds. The objective of thisprogram is to upgrade service factors and reliability. Theresults from this program are continually incorporatedinto all our new designs.

MARK GREGORY (Koch Refining Company):My question regards expansion joints and flue gas lines.

Are they typically run to failure or are they scheduled forroutine replacement on a set interval?

PARKER:Most of the flue gas expansion joints we are now

installing are double ply, and we can check the inside wallto see if it is leaking on the run. So we can tell ahead of

time if it needs a change out during turnaround. We havehad no failures in recent history, to my knowledge.

ABRAHAMS:On the last couple of questions several people have

talked about power failures as though they are beyondpeople’s control, and in many cases they are. But one ofthe things that we have found useful in answering powerreliability problems is to apply a little science and take areliability view of it, going through the fault tree analysisand looking at the individual components. While manyrefineries are susceptible to main power grid failures fromoutside, a lot ofshutdowns are within your own hardware.You can determine the odds of those and focus on the weakspots to improve reliability.

QUESTION 3.

Has anyone experienced weld cracks in stainlesssteel strip-lining in main fractionators? What was thecause? What changes in material selection or appli-cation can alleviate the problem?

VAN IDERSTINE:

We have a fractionator that has a 1/8" type 405 ferriticstainless liner from the heavy cycle oil draw down to thebottom head. We have had that situation since 1961, andwe have not experienced any problems with that cladlining.

The maximum width of the strip lining is dependenton the maximum operating temperature in the vessel. Fora temperature range of 950°F to l000°F, the maximumwidth should be 3” and the maximum length 36". Eachstrip should be welded to the vessel shell individually witha fillet weld. Adjoining strips are placed so that they arewelded directly to the shell. One final weld pass should fillthe cavity between the two fillet welds.

KELLER:Our FCC main fractionator was built 13 years ago. It

was originally clad with 410 stainless steel. We have hadno history of weld cracking.

ROSS:Thermal cycling, temperature excursions, and high

sulfur feed operation can result in cracking in the clad-ding. Once the cracking begins, further work or mainte-nance becomes problematic, and ultimately replacementis required.

REZA SADEGHBEIGI (RMS Engineering, Inc.):Weld cracks are primarily caused by thermal expansion

of the stainless steel lining. Our recommendation wouldbe to install a 410 SS clad in the bottom section of themain fractionator.

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QUESTION 4.Our regenerator flue gas pipe is unlined and it mustbe replaced soon due to corrosion. What are the prosand cons of installing a cold wall flue gas pipe versusstaying with the original design? Has anyone madethis type of conversion?

SOLIS:Our flue gas line is hot wall, with internal lining of

¾" abrasion-resistant lining-castable (hexagonal mesh)and externally isolated. No corrosion has been seen, butwe have had serious stress problems, causing a completeredesign of the whole line. We have installed new expan-sion joints, relocation of spring support, and 80% are newones.

It is common practice today to use a cold wall designfor the regenerator flue gas line. The advantage of this isless thermal expansion, and the piping run is easier todesign with fewer expansion joints. Problems with 304 SSstress corrosion cracking are eliminated. The disadvan-tages of the cold wall design are the larger size pipe requireddue to the internal lining, and the increased weight forsupport. If an existing hot wall flue gas duct is to bereplaced with a cold wall design, the routing of the ductmust be checked to see that the larger size will fit properlyin the pipe rack.

EMANUEL:Our regenerator flue gas overhead line is lined through

the waste heat boiler and orifice chamber. Downstream ofthe orifice chamber, we go to a hot wall design. We havenot experienced any problems in the unlined section. Inmy experience with other catalytic crackers, I have neverreally seen a major problem with a cold wall design.

KELLER:Ultramar made this conversion in December 1993 after

experiencing creep cracking in the original hot wall line.The line was 11 years old. The new line with the cold walldesign operates at 300°F to 500°F and is more forgiving toprocess temperature excursions. We expect to get a 20-yearlife on this installation, and it is the technology advocatedby UOP. The reliability of the cold wall design depends onthe integrity of the refractory lining. One small failure inthe lining requires immediate identification and externalcooling, or it will result in an unplanned FCCU shutdown.The installation of the cold wall design requires about 10%more expenditure and additional engineering time to makethe modifications to the pipe, structure, and hangers.

QUESTION 5.What new methods are refiners using to clean fouledslurry exchangers, (e.g., on-line cleaning, chemicalwashes)? Have slurry antifoulants been used success-fully?

POTSCAVAGE:We are not familiar with any on-line cleaning or chemi-

cal wash type approaches that can be utilized to cleanslurry exchangers. This is probably because the chemicalcomposition of the slurry itself results in fouling materialthat is typically very tenacious. From the standpoint of theslurry antifoulants, we have seen them work successfullyin some situations. In some slurry systems, the operatingconditions and the slurry’s physical properties are so severethat the slurry antifoulants have difficulty actually doingwhat they are intended to do. It is not uncommon for aslurry antifoulant to need assistance by controlling someunit operating parameters. A key parameter is the velocityof a system where 8 fps co 10 fps is ideal. Over 10 fpstypically starts to cause erosion in exchangers. Controllingviscosity is also important. The viscosity target varies fromunit to unit.

ROSS:The refiners I have spoken to are very familiar with the

chemical additives, but few seem to be using them. Theusual operational techniques described in previous Q&A'srelating to tube velocity, temperature, residence time,composition, and elimination of recycle are generally fol-lowed with good results.

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Two methods have been mentioned in the past, perhapsnot quite so new, that seem to be the most frequently usedto clean the systems. The first is periodic flushes with a hotlight cycle oil (LCO) to dislodge the sludge, with polymerchunks collecting in a good filtering system. I have heardfrom one refiner that occasional use of a heavy naphtha hasbeen used, with a caution that you break free almost all thedeposits in the circuit and you have a good filtering system.

Another interesting method that has been used success-fully in several refineries has been piping of the nonsparedslurry exchangers to be able to reverse the flow periodically.For a few minutes each week the flow is actually reversedthrough these exchangers and the deposits that are build-ing up are broken free and caught within filters. With thisarrangement, they are able to operate without a spare andrun continuously for three plus years.

There are also in-line scraping systems, which have,been marketed through ELF and Total, to continuallybreak free deposits. In every instance, the use ofgood filtersat the exchanger inlets is mandatory.

Finally, if you look back over the last several years at allthe techniques to monitor operation andcomposition, theone that sounds the most promising is monitoring of theC7 insolubles (asphaltenes). This procedure has a stronganalogy to what is done to monitor primary fractionatorfouling in ethylene plants. As I understand from theliterature, people tend to control to between 2% and 5%and have fairly good results without fouling.

VAN IDERSTINE:Our fouling of slurry exchangers has dramatically de-

creased in the past 2 to 3 years. We have increased ourfocus on maintaining adequate exchanger tube velocities.Our rule of thumb is a little bit lower than the velocitiesmentioned earlier. We control between 4 fps and 7 fps. Wealso control the slurry gravity to about -5” API.

We do have the LCO hot flush connections that Mr.Ross mentioned. Once or twice a year we use that systemfor a period of five to eight hours to circulate hot LCOflush back to our fractionator. As a cost reduction method,we stopped adding antifoulant into the system and did notsee an increase in our fouling frequency.

DEADY:Generally we think that slurry antifoulants will do a

good job of preventing the pumparound system fromfouling. However, they are not necessarily very effective incleaning an already fouled system. I have a couple ofstoriesfrom refiners who have been successful in using antifou-lants. One was operating a slurry system that had to beshut down about every 11 months to clean the fouledexchangers. When they switched to a good slurry antifou-lane program, the pumparound system operated continu-ously for about 27 months. It probably would haveoperated longer, but the unit went down for a scheduled

turnaround. Another refinery was shutting down every 2days to clean the slurry exchangers. Since they institutedan antifoulant program, the shutdowns have been moreon the order of 9 to 12 months.

EMANUEL:I do not have a horror story quite that bad. We peri-

odically back flush the slurry exchangers on-line, but thattends to have a fairly small effect. So we revised our pipingso that we can pull exchangers one at a time and hydroblastwhile the unit is on-line. That tends to be on a yearly cycle.We still have not been able to justify the antifoulants inslurry service.

HANSEN:We have successfully used an antifoulant program in

the slurry loop for several years. The program was origi-nally started to reduce and control fouling in the packedsections of the main fractionator. The program uses hightemperature dispersant and inhibitor chemistry, whichwas selected by the chemical vendor based on testing ofour slurry. There have been instances when excessive cata-lyst carryover has caused fouling of the slurry loop steamgenerators, which have required mechanical cleaning. Thefouling deposits were loose and mainly catalyst, and wereeasily removed by hydroblasting.

JOHNS:Fouling will usually occur two ways: from coking and

from asphaltene precipitation. If you stay in a certainrange, usually antifoulants will work. A rule of thumb onthe asphaltene precipitation is that if you are using a chargefrom highly paraffinic crudes, 3% of the naphchenic-typecrude into that will usually be the limit. Above that youwill get precipitation of asphaltenes in hot slurry exchang-ers and preheat heaters. On the other side, with thenapthenic crude, you can go up to 15% paraffinic mate-rial. If you get out of those ranges, generally, an antifoulantwill not work.

JAMES W. JONES (Turner, Mason & Company):One thing that has not been mentioned is that good

control over your main column bottoms temperature canprevent a lot of slurry exchanger fouling. We found this tobe as effective, and sometimes more effective, than the useof antifoulants. Antifoulant programs that provide on-sitetechnical service do improve operator control over unitoperating parameters. This type of program significantlyreduced slurry exchanger fouling in one refinery withwhich we are familiar.

REZA SADEGHBEIGI (RMS Engineering, Inc.):Depending on the configuration of the FCC bottoms

pumparound, an effective on-line cleaning could be acontinuous injection of 3% to 5% of either HCO or LCO

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into the inlet of the bottoms exchangers. You may also wantto have a spare bundle on hand to minimize downtime.

to reject shipments based on samples, so we do test ourECAT when we receive it.

Catalysts

QUESTION 6.How is the quality of fresh FCC catalyst monitored bythe refiner? What is the frequency of testing? Whatare the properties monitored and what tests used?What is the recourse for qualify problems?

If we suspect a problem, or if there is a discrepancy witha vendor, we conduct testing at our research center. Theycan test all the properties, and typically before we run anynew catalysts in the unit they conduct a full range of freshand de-activated catalyst property tests. This provides areference point for specifications and vendor tests on thenew catalyst because there are such discrepancies betweenthe different vendor tests.

SOLIS:ROSS:

We have developed a very extensive process of selectionbefore any changing of catalyst. This process is designedto choose the optimum catalyst for our feedstock and unitoperating conditions. Once we have selected the vendor,we include a clause in the purchase order that we have theright to take samples of the fresh catalyst that they supply.The quality control program to carry out with the sampleshas been previously agreed upon with the catalyst pro-ducer. If the sample does not meet specifications, we canreject the truck or ask for liquidation damages. The testalways includes MAT Activity (>72%); Na2O (<0.45%);and Attrition Index (DI<8). Be sure to cross-correlate, aswell as possible, the analytical methods of the refiner andthe catalyst supplier. If you do not, you will have seriousproblems comparing results.

Some refiners rely on the quality assurance programsand certifications of the catalyst vendors, whereas othersare more proactive. Typically, fresh catalyst is sampledrandomly or each batch received is sampled with samplesretained but tested randomly by the refiner’s central labo-ratory or research and development facility. Propertiessuch as pore volume, surface area, chemical composition(zeolite, alumina, rare earth, and promoter/platinum con-tent), attrition index, and particle size analysis are per-formed on perhaps 20% to 30% of the samples. Onerefiner cautions that particle size distribution can be trickyas sampling a large truck is not trivial due to settling/seg-regation during transit.

One of the major concerns of this program is sampling.We have developed a procedure in which we take onesample from the truck for the supplier, one as referenceand one for testing. We have developed this program oversix years, and we have only observed problems on twooccasions. One was low attrition and the other was a casewhere they sent the truck to the wrong refinery. Generallyspeaking, we are very satisfied with the quality of oursupplier.

Sophisticated high-volume users may request vendorprocess control charts and trend manufacturing controlpoints and variables. Average values of variables can bemonitored, as well as deviations from the manufacturers’set points, to track consistency and control of the processto identify irregular batches.

PARKER:Generally, we monitor the fresh catalyst using the data

sheets from the vendor. We receive most of the tests listedon the data sheets for each shipment with the exceptionof attrition, MAT, and surface areas. Those are only doneoccasionally, maybe every third or fourth truck. We docompare these numbers to the specifications we have forour catalyst. If there is a problem, we call the vendor andusually we are compensated on the next shipment or bymaking a price adjustment. We have really not had manyproblems. One problem that we have had occasionally isthat we may be getting material that is within specifica-tions, but continuously on the low side of the range on aparticular property. We call and usually get an adjustmenttoward the target value.

As for ECAT analyses, samples are taken either weeklyor twice a week for analysis by the vendor. Response timesof about one week are reported. When unit performancechanges unexpectedly, samples are sent to the research anddevelopment or central laboratory for independent analysisof MAT, metals level, chemical composition, etc., andperhaps operation in a pilot unit using the feedstock fromthe unit in question. Results of these tests are then discussedwith the catalyst vendor, possibly resulting in compensa-tion. Good sampling and sample retention procedures areessential.

ABRAHAMS:

Once in a while we will put equilibrium catalyst (ECAT)in our resid cracker. We have had instances where we had

Our practices are similar co those of Mr. Parker. We relyheavily on our supplier’s analysis and crosscheck peri-odically. We also have been very successful in dealing withthe vendors directly for recourse on the rare occasions wehave had problems. There was one instance a few yearsback, though, in which a supplier was unable to deliversuitable quantity and quality of a new catalyst. While itwas painful, we parted ways for a couple of years and wentwith another supplier.

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DEADY:A handful of our customers continue to monitor fresh

catalyst properties. Several others have in the past, butmost of that has been discontinued due to refinery andresearch and development cutbacks. The refiners who stilldo their own analyses analyze every shipment. The prop-erties they monitor include chemical and physical proper-ties, especially particle size and attrition and catalytictesting to measure activity and coke selectivity. Somerefiners without internal laboratory facilities have sentrandom samples for third-party testing.

One important caveat before starting this kind of test-ing would be to establish a correlation with your supplier’slaboratory analysis. This would eliminate potential labo-ratory biases due to analytical differences and allow you toestablish a baseline should discrepancies arise in the future.The refiner also needs to make sure they obtain a repre-sentative sample for testing.

HANSEN:We also generally rely on the quality control sheets

provided by the catalyst suppliers. In our case, the itemsof major interest are the fresh activity, rare earth, particlesize distribution and hardness. We have found the need onoccasion to send samples to third parties to confirmshipment quality and, like most, we would change suppli-ers if we felt we had a problem.

WILLIAM D. HENNING (Conoco Inc.):We monitor fresh catalyst quality in a central technical

support group and laboratories. We collect both vendorlot samples and truck samples of the fresh catalyst at therefinery. Typically, each truck sample is tested for compo-sition by x-ray and for surface area. For some units, we alsoconduct attrition and particle size distributions tests. Wehave found in the past that some incidents of FCC per-formance loss have correlated to catalyst quality. We haveworked closely with our catalyst vendors and have put inplace quality control agreements for various compositionand physical properties. There are specified ranges for eachshipment and a narrower range for a six truck movingaverage. There are economic penalties associated withfalling outside of some of these ranges.

I might add that a refiner seeking a formal qualityagreement with their catalyst vendor should understandnot only what catalyst properties are important to theirunit, but also the capabilities and driving economics of theFCC catalyst manufacturing process.

STEVEN K. PAVEL (Coastal Catalyst Technology, Inc.):Previous responses illustrate the importance of testing

refinery fresh catalyst deliveries to avoid getting a roguedelivery of a catalyst meant for another refiner, or a catalystthat does not meet specifications. Most often problems aredetected in the unit; to eliminate fresh catalyst from the list

of potential contributors, testing and analysis are essential.In any case, units with high addition rates relative to thesize of the circulating catalyst inventory ate most sensitiveto fresh catalyst property changes.

Fresh catalyst shipments are routinely sampled andtested. Delivered fresh catalyst properties are compared tospecifications, shipment inspection reports, and previousdeliveries. Minimum testing includes XRF and XRD forcomplete elemental analysis and crystallinity on each de-livery. Profiles on new catalysts might include: XRF; XRD;surface areas, pore volumes and pore size distributions bynitrogen and mercury; pore volume by water; bulk andskeletal density; particle size distribution and attrition;TCLP; and full MAT yield tests unsteamed and aftersteaming for 4 hours and 16 hours. If a fresh delivery showsa significant change in XRF or XRD results, more testingis performed.

Analyses of feedstock elements usually do not includeall the deactivating contaminant elements in the feed-stock, which are deposited on the fresh catalyst eitherroutinely or as a spiked anomaly. Fresh catalysts are asource of the spent catalyst elemental constituents; with-out analysis of the fresh material it is difficult to calculatethe deposition of contaminant elements. Fresh catalystelements are analyzed by XRF, and, in certain cases, byICI? X-ray diffraction is used to measure unit cell size andcrystallinity, and to provide a qualitative analysis of min-eral composition or phase. In several instances, the X-raydiffraction analyst was the first to identify changes in thefresh catalyst composition.

It is generally accepted that “any system under observa-tion changes.” The occurrence ofquality control situationscan only be determined by sampling and testing.

PETER G. ANDREWS (Consultant):Most refiners have operated for a long time without

testing fresh catalyst. Terry, it would be of interest to knowhow many refiners are now testing catalyst all the time.

HIGGINS:Could we have a show of hands of who tests fresh

catalysts all the time? The audience show indicates five orsix.

QUESTION 7.What success have refiners had at reducing FCC naph-tha olefins wifhout losing octane (e.g., reactor risertemperature, catalyst formulation changes or catalystadditive use)?

DEADY:Many of the ways that refiners can reduce FCC naphtha

olefins have been discussed in the 1994 NPRA Q&ASession transcript, and they were also summarized in theOil and Gas Journal, April 24, 1995.

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To reduce FCC naphtha olefins, refiners should usemoderate reactor temperature, maximize catalyst-to-oilratio, increase catalyst rare earth level to increased zeoliteunit cell size, minimize catalyst matrix surface area, anduse ZSM-5 to crack naphtha olefins. In order to reduceFCC naphtha olefins without losing octane, a combina-tion of these approaches is probably necessary. If a refineris currently using a low or no rare earth USY catalyst, wewould recommend switching to a high REUSY catalystplus ZSM-5.

The switch to REUSY will reduce gasoline olefins byabout 25% on a relative basis with an octane penalty ofabout two numbers, depending on the base octane level.The ZSM-5 addition will easily recover the loss in octanewith no increase in gasoline olefin content. In fact, somestudies actually show a decrease in gasoline olefins withthe addition of ZSM-5.

We know of other refiners who are already usingREUSY catalyst. In these cases, they are planning to dropreactor temperature, then add ZSM-5 to regain the lostoctane and LPG olefins. A drop of about 30°F in thereactor temperature will decrease gasoline olefins by about8% relative and an addition of approximately 7% olefinsplus ZSM-5 containing additive will maintain octane andLPG olefins relative to the base.

EMANUEL:We were one of the “lucky” refiners that were construct-

ing a catalytic cracker during the 1990-91 time period, sowe had to apply for a “Work In Progress” adjustment inour refinery baseline. Olefins have been a problem for us.Currently we control olefins by maximizing catalyst-to-oilratio in our FCC unit. We have tried moving reactortemperature moderately, i.e., 10°F one way or the other,but have not seen much change in olefins. We havescheduled a trial of ZSM-5 early next year to see if thatwill help us.

I would like to comment that the EPA approvedmethod for testing olefins in gasoline works fairly well forblended gasoline. But we have found that the test forstreams such as light catalytic naphthas, which have ahigher percentage of olefins, is very erratic. I would like tohave some comments from the floor if anyone else has hadthat same problem.

ERNEST L. LEUENBERGER (ARCO Products Company):We recently completed a test run at our Los Angeles

refinery where we analyzed olefin content using the EPAmethod, an NIR technique, and a GC technique. TheEPA-approved method had the poorest reproducibility.We hope to use the NIR technique for process control.

In addition to the methods that Ms. Deady mentionedto control olefins, I would add that if you have an FCCfeed hydrotreater, you can reduce olefins by increasinghydrotreat severity. If the hydrotreater has the capacity to

handle extra feed, any loss in FCC naphtha octane due toincreased severity could be overcome by recycling LCO tothe hydrotreater.

G. ANDREW SMITH (INTERCAT Inc.):While we agree with everything the panel said, some

refiners would like to maintain gasoline volume and in-crease octane without increasing olefinicity, and high sil-ica-to-alumina ratio pentasils offer this possibility. Thereis also, as Mr. Hansen has indicated, a reluctance to dropthe reactor temperature more than 10°F. However, we havecustomers who have reduced the reactor by greater than10°F. They are adding a bottoms upgrading additive,BCA-105, to maintain or reduce bottom yields whilemaintaining or increasing gasoline yield with the lowerreactor temperatures.

QUESTION 8.What level of sulfur reduction in FCC naphtha is pos-sible by changing FCC catalyst? What is the impact ofthis Change on other FCC yields and properties, espe-cially the coke yield? Are there any other operationalimpacts (e.g., increased flue gas SOx emissions)?

DEADY:This year we completed two refinery trials of our GSR

technology for gasoline sulfur reduction described in re-cent NPRA papers. This additive technology convertsgasoline sulfur species to H2S. In the commercial trials, weobserved up to a 25% reduction in full range gasolinesulfur. This reduction was corrected for changes in feedsulfur and gasoline end point. We saw no other changesin any of the other yields or the gasoline octanes. Furthercommercial testing is scheduled while work continues onimproving the performance of GSR.

Regarding conventional FCC catalysts, we have seenthat changing from a low hydrogen transfer catalyst to ahigh hydrogen transfer catalyst will reduce gasoline sulfurby about 6%, based on our circulating riser pilot planttesting. Matrix surface area also impacts gasoline sulfur. InMAT testing, we have seen a correlation in gasoline sulfurreduction with the steamed matrix surface area ofcatalysts.The range of matrix surface area tested was from about 20to 125 meters squared per gram. The higher matrix surfacearea catalysts gave a 15% to 25% sulfur reduction, com-pared to the low matrix surface area catalysts.

From past experience, the percent reduction we haveobserved in microactivity testing has been somewhathigher than what we have observed in riser testing. Wenormally attribute this to the difference in contact timebetween the MAT and the riser. In commercial units, wedo not always observe a significant reduction in gasolinesulfur when the matrix surface area is increased.

The yield shifts associated with increasing matrix sur-face area depend on the specific type of matrix surface area,

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but can include better bottoms cracking with the penaltyof increased coke and dry gas, particularly with very highmatrix surface area catalyst. If the FCC unit is constrainedby the air blower or gas compressor, increasing catalystmatrix surface area may not be a practical option to reducegasoline sulfur. That is the major reason we concentratedon the additive approach to reducing gasoline sulfur. Therefiner avoids having to deal with significant selectivitychanges in the base catalyst.

JOHNS:I would cite some pilot unit testing at our Port Arthur

research facility. We have seen on a variety of catalysts upto 10% reduction in FCC naphtha sulfur. Usually, highrare earth and high matrix activity catalysts tend to reducethe sulfur the most. The sulfur is observed to go to H2Sand LPG products rather than to flue gas. We have alsocommercially tested a proprietary sulfur reducing additivein one of our units.

ROSS:Circulating pilot ‘plant work by one refiner has con-

firmed the 20% target reduction in full range gasolinesulfur when using these additives. But there seems to bethe following trade-off with constant catalyst-to-oil ratioand riser temperature, i.e., a 3% absolute reduction inconversion, 1.5% absolute reduction in light catalyticnaphtha with the heavy naphtha unchanged, and a 10%relative increase in the coke yield. Also, there is a reductionin the gasoline olefins, resulting in an octane loss of 0.6RON and 0.4 MON. Obviously, the technology is newand developing, and these are only pilot plant resultsreported by one refiner.

An important consideration is the conversion level atwhich the sulfur level reduction is attempted. At lowconversion with some aliphatic species containing sulfurin the gasoline, the ability to achieve the hydrogen transferor react out the sulfur would seem to be much more likelythan at high conversion where most of the sulfur specieswould be aromatic. When attempting to attack the aro-matics, coke production will likely increase. Although thefine-tuning of sulfur levels may be possible via this route,at present it would appear that feed treatment would bemore effective.

As an interesting aside, in our short residence timecracking pilot plant work, similar sulfur reductions wereobserved. A reduction in secondary reactions, possiblythose creating stable aromatic sulfur species, has beentheorized. However, there is also some dilution effect as thegasoline selectivity is increased at very short residence time.

SOLIS:I will add new information on this subject based on

recent pilot plant work. Also, I have to mention that theEuropean auto/oil program will result in a sulfur reduction

in gasoline, and this reduction will very much affect theFCC naphtha as a component of the gasoline.

By changing the actual commercial catalysts, e.g.,changes in rare earth (RE) content and/or different matri-ces, very little, if any, reduction of sulfur occurs. Whenusing specific additives for sulfur removal, reductions upto 35% are achieved. However, the extent of that reduc-tion strongly depends on the feedstock (crude source, EBP,sulfur content, etc.). Generally speaking, we have observeda linear relationship between the FQP (feed quality pa-rameter, which depends on feed density, VABP, S, andaniline point) and the feed sulfur content, and the naphthasulfur reduction achieved.

Naphtha S FeedReduction (%) FQP S %

5 76.8 1.915 79.2 1.32 5 81.5 0.7

Thus, in some cases, sulfur reduction is clearly below15%. On the other hand, the present catalysts (additives)seem to simultaneously increase the coke and H2 yields.As a matter of fact, coke yield increases 0.5 wt% for anaphtha sulfur reduction of 15 wt% to 20 wt%. Finally,although most of the sulfur is retained by the additive andhydrolyzed to H2S in the stripper, some still goes to theregenerator, increasing the SOx emissions.

G. ANDREW SMITH (INTERCAT Inc.):

In recent trials of INTERCAT’s bottoms upgradingadditive, we have achieved reductions of gasoline sulfursranging from 20% to 30% with a significant portioncoming out of the heavy gasoline cut. Refiners directlyattribute these reductions to the use of the additive andnot to cut point changes. However, at this time, the resultsof the sulfur balances have not been released; most of thesulfur removed is assumed to be in the form of H2S. Theother benefits include improved bottoms upgrading andreduction of slurry viscosity. There were no changes incoke and C2 minus gas yield.

QUESTION 9.

What are the current dispositions for FCC catalystfines?Are there anyproperties of the fines that restrictthe method of disposal?

DEADY:

The current disposition for FCC catalyst fines is similarto that for FCC equilibrium catalyst. You can either use itin cement or use it in asphalt as road base. For cement use,the cement manufacturers really do not care much aboutthe particle size distribution since cement is fairly fine,even finer than FCC fines.

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We currently have discussed this application with ce-ment manufacturers both in the U.S. and in Europe. InEurope, there are some metals limits on the equilibriumcatalyst (ECAT). This would presumably be the same forthe fines. The metals levels are 4000 ppm nickel, 8000ppm vanadium, and 1500 ppm antimony. In the U.S. themajor limit appears to be vanadium at about 8000 ppmto 10,000 ppm. Cement manufacturers worry about thevanadium content because it could attack the brick in thecalcines and cause deterioration.

As for using the fines in road base, we have experiencewith this application in Europe and over in the Asia-Pa-cific area. In Europe they have restrictions on the particlesize distribution. What probably will cause a problem isthat the fraction below 10 microns must be minimized,so I am not sure how practical this use would be for FCCfines in Europe. There are metal limits in Europe as well:4000 ppm nickel, 7000 ppm vanadium, and 1500 ppmantimony.

In the Asia-Pacific area, we are not aware of any restric-tions on the particle size, so fines are probably appropriatefor this use. Again, there is a limit of about 7000 ppmnickel on the ECAT or the fines.

FRONDORF:Current disposition of FCC fines from both our refin-

eries is to landfill facilities. Periodically we explore dispo-sition to cement kilns when economical and available.FCC fines are classified on a characteristic basis per normalEPA guidelines such as metals, organics, etc., and, fortu-nately, not on a definition basis such as sewer sludges orwaste water sludges. The characteristic classification hasbeen nonhazardous industrial waste for typical fine prop-erties of today.

HANSEN:We currently dispose of the fines caught in the under-

flow system with the equilibrium catalyst, which is sold toa local landfill. We have also disposed of this as a nonhaz-ardous waste and have used it in cement manufacture. Wealso collect fines through our wet flue gas scrubber system.These are collected separately and sent out of the plant asa nonhazardous waste.

KELLER:Our dry FCC fines are transported by pneumatic truck

to a local cement manufacturer and “blown” into a dryhopper for later mixing. Wet FCC fines are transportedto a different local cement manufacturer and bottom-dumped into a liquid holding tank equipped with amechanical mixer. Wet fines are segregated from dry fines,otherwise they would form a cake, which would beunusable at either facility. There are no other restrictionsat this time.

Process

QUESTION 10.What corrective actions can be taken in the operationof an FCCU to reduce the flue gas opacity? Pleaseaddress only the operating aspects and not down-Stream equipment or technologies.

ROSS:The issue of troubleshooting catalyst loss problems has

been summarized from time to time and most recently byAkzo in an Oil & Gas Journal article, August 28, 1995.The usual operational changes made to reduce catalystlosses and stack opacity include: reducing air rate (not agood choice), or replacing oxygen enrichment for some ofthe air; increasing regenerator pressure; changing to a moreattrition-resistant catalyst with a higher particle density;reducing fresh catalyst addition and fines content of thefresh catalyst; reducing regenerator bed level, if cycloneflooding is the problem; monitoring and regularly unload-ing third stage cyclone catch vessels to avoid flooding; andconsidering SO3 reduction methods as condensibles in theflue gas impact on the opacity.

Very often, an overlooked attrition source is the actualcause of high opacity problems. High-velocity jets gener-ate fines which increase the overall loss and disproportion-ately increase the opacity reading. All possible attritionsources under direct operator control, such as jets frominstrument and equipment purges, must be checked andrechecked.

Other preventive actions include: continuous catalystaddition to avoid bursts of high losses; regular inspectionand maintenance of the opacity meter itself, ensuring thatthe purged media is hot and dry and the mirrors are clean;and continuous sonic-type soot blowers, instead of dailymechanical soot blowers, to avoid bursts of losses.

VAN IDERSTINE:I agree with most of those comments. I would empha-

size the verification of the regenerator level as probably oneof the most important and first things that an operator orengineer should do upon realizing high catalyst losses areoccurring. On the topic of attrition, monitoring your 0 to40 micron size in your equilibrium catalyst is important.If the quantity in that size range is either stable or increas-ing during periods of high catalyst loss, then you probablydo have an attrition source in your system somewhere.

PARKER:On the catalyst issue, where there is an electrostatic

precipitator operation downstream, you can alter the cata-lyst and sometimes that will change the electrical resistiv-ity, which will impact how well the precipitator will pickup. Also, regarding flue gas concentration, sometimes thecorona current on the precipitator will be impacted by the

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flue gas properties. We have observed that increased COwill actually help the corona current, and sometimes, onsome of our precipitators, lowering the excess oxygen willalso help. On the precipitators we operate, we do notnecessarily see the same magnitude of change with thesame adjustments.

DEADY:I basically agree with what has been said. You might

want to verify the regenerator catalyst inventory levels. Ifthe level is too high, you have a reduced free board andyou might be overloading the cyclones. If it is too low, youmight have uncovered the cyclone diplegs. You probablywant to check velocities of the primary and secondarycyclones to make sure they are in the proper ranges. Also,poor aeration and catalyst circulation could be causingpressure imbalances where you could have surging orfluctuating opacity problems. Poor wet gas compressorcontrol could also create pressure imbalances which wouldhave the same effect.

I want to add to Mr. Parker’s remarks on catalystresistivity. There is actually a narrow range in which youcan vary catalyst resistivity. Most catalysts used today havehigher resistivity than the actual ideal level for precipita-tors, which is why most refiners also use NH3 in the ESP(to lower the resistivity to the optimum level). So eventhough it is directionally a good idea to change catalystresistivity, it is not always practical to do so.

HANSEN:Flue gas opacity can be from catalyst fines or SO3 in

the flue gas. We have found that maintaining control ofthe regenerator level and underflow system is needed toprevent fines carryover, which causes erosion, deposits onthe flue gas expander, and potential stack gas opacity.Operation at low excess oxygen levels will minimize SO3

formation. We have the ability to inject sodium bicarbon-ate solid into the flue gas ahead of the wet gas scrubber forSO3 control, if needed.

KELLER:We have tried a number of ways to improve the perform-

ance of our electrostatic precipitators. We have injectedNH3 into the inlet of the electrostatic precipitators at aconcentration of approximately 10 ppm to try to increasethe efficiency of the precipitator operation. This was some-what effective but not dramatically so.

We have tried to reduce the visible SO3 particulate byadding SOx reducing additive — again with limited re-sults.

We have reduced the flue gas velocity by minimizingthe excess O2. This seems to help somewhat, but may berelated to pockets of catalyst that get swept into the fluegas at higher velocities.

Our most dramatic change in flue gas opacity occurredwhen we shut the unit down and water washed the insideof the catalyst hoppers. The hoppers were almost full ofcatalyst with only small openings to the dump valves.

SOLIS:FCC flue gas opacity is caused mainly by the amounts

of fines originated in the process and the type of technol-ogy to separate those fines from the flue gas. Catalystquality, makeup amount, air distributor, and catalyst ve-locity in the process are key factors to control fines pro-duction. Therefore, considering only operating aspects,opacity is clearly a function of FCC catalyst physicalproperties. Several models exist that allow the quantifica-tion of attrition index, particle size distribution, and cata-lyst density effects on the opacity measurement. As amatter of fact, for the U.S. ranges of commercial freshcatalyst properties, R.G. McClung (from Engelhard) cal-culated the impact on opacity of density and attritionindexes as follows:

Relative % Change in Opacity Range of Data

ABD -9 0.79 to 0.86

CBD -6 0.91 to 0.95

EAI +34 0.4 to 1.1

Clearly, attrition index has the largest impact on opac-iry. The particle sizes that contribute most of the measure-ment ofopacity are products ofcatalyst attrition; the lowerthe attrition resistance of a catalyst, the higher the propen-sity to produce fine particles that increase opacity.

JAMES D. WEITH (Unocal Corporation):We are particularly sensitive to the overuse of CO

promoter. If you use too much promoter, apparently thataffects the resistivity of the flue gas, which affects theefficiency of the precipitator.

DELBERT F. TOLEN (Rocky Mountain Salvage & Equipment):We deal in equilibrium catalysts, and we see a lot of

catalyst analyses. Several years ago we ran into one unitthat typically maintains a 50 co 55 average particle size andretains 30% to 35% of 0 to 40 micron catalyst. I couldnot figure that out, so I called the refinery and asked ifthey recycled fines. They said they did not; rather they hada third stage separator, but they made little catalyst off itor the electrostatic precipitator. They hauled it out aboutonce every 3 weeks, a couple hundred pounds.

This unit retains an average particle size of 50 to 55micron. They lose almost no catalyst. They have no prob-lem with stack opacity at all. I called Mr. Ed Tenney of GEEnvironmental Services and asked what design was usedfor these cyclones to give that kind of retention. I have notreceived an answer yet. The following chart provides par-ticle size data from this unit over the last 8 years.

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Equilibrium Fluid Catalyst Analyses Equilibrium Fluid Catalyst Analyses

Sample Physical Particle Size Sample Physical Particle SizeDate Properties (microns) Date Properties (microns)

A PV ABD 0-20 0-40 0-80 AVG A PV ABD 0-20 0-40 0-80 AVGm2/gm m3/gm gmm/cc m2/gm m3/gm gm/cc

09/05/9109/11/9109/18/91

11/13/9111/20/9111/27/9112/04/9112/12/9112/19/9101/01/9201/08/92

01/22/9201/29/9202/08/9202/05/9202/09/9202/13/9202/17/9202/19/9202/23/9203/01/9203/06/9203/08/9203/27/9204/01/9204/08/9204/10/9204/14/9204/23/9204/29/9205/05/9205/19/9201/05/9401/11/9401/20/9401/25/9402/04/9402/09/9402/09/9403/02/94

102 .28 .91 2 22 75 60

102 .27 .90 3 24 79 58101 .28 .91 3 28 77 59102 .28 .99 4 28 78 59112 .28 .93 2 25 79 57106 .25 .93 2 24 77 58105 .27 .91 3 27 82 56

106 .26 .91 2 26 75 58108 .27 .91 4 27 80 57110 .25 .92 5 29 81 55109 .26 .92 6 31 82 54116 .26 .91 7 35 87 51110 .25 .91 3 28 82 56111 .26 .92 6 29 83 55113 .26 .92 6 29 83 55114 .28 .91 5 28 82 55114 .27 .91 4 30 76 55110 .27 .90 4 29 80 55112 .26 .91 2 28 77 56115 .28 .92 2 27 76 57

119 .27 .91 4 27 80 58116 .27 .91 4 25 77 58118 .27 .91 5 24 78 58118 .27 .92 4 23 72 61119 .28 .91 3 26 72 57115 .27 .92 2 26 74 58116 .27 .92 2 25 74 59115 .28 .90 4 28 78 56112 .27 .93 3 24 75 61113 .26 .90 5 29 80 55114 .28 .91 5 26 73 59112 .26 .91 5 26 73 58115 .28 .92 4 29 77 58116 .25 .92 3 29 78 56127 .28 .86 2 31 87 53124 .27 .89 3 32 86 52124 .28 .86 0 32 82 53128 .29 .87 1 28 85 55125 .27 .86 2 27 80 55127 .27 .86 3 28 83 55126 .29 .87 3 28 83 55122 .27 .87 4 31 84 53

03/02/94 126 .28 .87 5 28 84 5404/05/94 109 .28 .88 3 31 89 52

04/12/94 110 .27 .92 2 31 89 5204/20/94 112 .27 .90 3 28 83 5504/27/94 118 .27 .90 1 25 81 5605/03/94 117 .27 .90 2 22 77 6005/10/94 109 .27 .95 3 25 81 5805/19/94 116 .29 .88 1 25 81 5705/25/94 117 .31 .88 1 22 82 5905/31/94 122 .28 .88 3 23 80 5906/09/94 127 .29 .88 3 22 76 5906/16/94 127 .29 .87 2 24 78 5906/22/94 130 .29 .89 2 25 81 5706/29/94 123 .30 .87 3 26 81 5607/07/94 126 .29 .87 0 24 80 5807/14/94 123 .29 .88 4 26 76 5807/20/94 124 .29 .87 2 25 80 5607/27/94 125 .30 .87 3 24 81 5508/03/94 125 .30 .87 2 25 85 5608/10/94 138 .29 .88 2 22 80 6008/16/94 124 .29 .88 3 22 71 6108/23/94 129 .31 .88 0 19 75 6208/31/94 127 .30 .89 1 21 78 6009/05/94 130 .29 .89 1 17 78 6209/14/94 131 .30 .88 2 19 77 6109/21/94 136 .30 .89 4 16 75 6409/28/94 135 .30 .88 2 14 72 6510/05/94 133 .31 .86 1 15 70 6510/11/94 131 .31 .86 2 18 76 6110/18/94 129 .31 .88 2 18 75 6210/25/94 130 .30 .88 0 17 79 6211/02/94 130 .30 .89 3 16 73 6411/09/94 128 .30 .89 0 15 75 6311/17/94 132 .30 .90 3 14 68 6711/22/94 128 .29 .90 2 17 75 63

EDWIN D. TENNEY (GE Environmental Services):Yes, for several years now Mr. Tolen has been accusing

us of designing special cyclones for one refiner and notoffering them to any other refiner. We can assure you thatmost of the specifications for these cyclones were givento us by the process licenser and they are the same

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We have implemented an overall revamping of ourFCCU at the Gibraltar refinery. We have installed a cata-lyst cooler and have increased by 20% the air flow to theregenerator. As a consequence we have also revamped andupgraded the third stage separator (TSS).

MANFRED DEHNE (Polutrol - Europe):

Our TSS is Shell type and employs the conventional“reverse-flow” cyclone principle. The particulate leveldownstream TSS must not exceed 100 100mg/Nm3.

Our original TSS had swirl vane tubes that were closedon the bottom and had two slots for the collected fines todrain. Any plugging of these slots will cause the separatorto not function properly. We have completely opened thosebottoms to allow easier catalyst fine drainage. We haveincreased the number of swirl vane tubes by 22%. Weproperly fitted the swirl assembly to keep it centered in thecan to avoid cracks in the ceramic lining as it expands.

The seal weld between the swirl vane tube and top tubesheet was done very carefully to be airtight, because sub-stantial catalyst bypassing can occur if it is not. These itemsshould be checked and maintained as required duringturnaround to maintain proper performance.

56

I think we all should keep reminding ourselves that athird stage cyclone is a true and typical mass transferdevice. All cyclones are typical mass transfer devices. Theirbehavior (operational), hence, is governed by the verysame physical laws as those ofsimilar mass transfer devices.The mathematical basis is the fundamental Euler equa-tions. In a sense, the principal design operants of cyclonesmay be compared to those of tubular heat exchangers, i.e.,their efficiencies are inversely proportional to their diame-ters. As the overall heat transfer coefficient of a smalldiameter tube will be higher as compared to that of a largepipe, the fractional collection efficiencies of small diame-ter cyclones will be considerably higher as compared tothose of large diameter cyclones. Hence,

Eff (small diameter cyclone) >> Eff (large diameter cyclone)

JAMES D. WEITH (Unocal Corporation):Based on conversations with Mr. Rick Miller of M. W.

Kellogg about two years ago, I was prompted to check theinstallation of our critical flow nozzle on the underflow ofthe third stage separator. The unit was shut down to plugsome tubes in the flue gas steam generator, and I discov-ered the nozzle was indeed in backwards. It makes anamazing improvement in efficiency if it is installed cor-rectly. The efficiency about doubled. This is compoundedby the problem that it was installed intuitively, or whatmaintenance people thought was intuitively the rightdirection, because it is easier to put together the way it wasrather than the correct way.

Heavy Oil Processing

EDWIN D. TENNEY (GE Environmental Services):Basically, there are two types of third stage cyclone

separators. One type has a large number of small diameter

In addition, it is very important to realize that designparameters utilized should be in tune with reality, i.e., theyshould closely correspond to and reflect operating condi-tions realized in the field later on. The old truism —garbage in, garbage out — holds value for the design ofthird stage separators as well. If the initial design parame-ters specified are wrong, the third stage separator, in alllikelihood, may not work properly as expected. However,not everything may be lost at this stage, as minor opera-tional instabilities usually can be corrected at a later timewith relatively little effort. Conventional cyclone systems(large diameter types), in general, react very unfavorablyto changing operating conditions (turndowns). Their vor-tex stability is a function of their relatively large bodygeometry and volumetric flow of the continuum. Conven-tional cyclone separation efficiencies, thus, can drop quitedrastically as a result. A perfect example is the changingoperating conditions of internal cyclones inside the reac-tor/regenerator vessels. (They most often are the source ofcatastrophic catalyst surges occurring). Consequently, athird stage cyclone having only a small number of large

specifications that we have used for about 80% of thecurrently operating units. We do not have an explanationfor why this refiner has been able to retain the fines thatthey do. Their operating conditions are not unique. How-ever, recently they have increased throughput, and theirfines level and average particle size have increased. There-fore, it appears they have not been pushing the unit. Ifthey continue to increase throughput, we expect theircatalyst analyses will be similar to those generally foundin the industry.

QUESTION 11.What upgrades are available to improve performanceof existing third stage flue gas separators?

SOLIS:

cyclones (10” I.D. or less). There are 50 or more of thesecyclones in the separator vessel. One will find that theseseparators protect expander turbines because they grindup the enter particles to less than 10 microns, but theoverall efficiency of this type of separator is only 40% to50%. The other type of separator consists of 6 to 20 largerdiameter cyclones (±40” I.D.), usually in a vessel. Becauseof the small number ofcyclones and because these cyclonescan have diplegs with valves, both of which tend tominimize circulation of gases from one cyclone cone toanother, this type of separator has a collection efficiencyin the range of 75% to 80%. The particle size analysis ofthe catalyst escaping from each type of separator is aboutthe same, but the losses from the second type of separatorare significantly less.

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diameter cyclone tubes is more susceptible to operationalinstabilities as compared to one having a multiplicity ofsmall diameter tubes, so-called modules, inscalled. Buteven a third stage cyclone with an assembly of a relativelylow number of large diameter cyclones, with a little bit ofeffort, can be made to operate quite stably. The diagramon page 58 shows a modern third stage cyclone requiringneither an UNDERFLOW System nor a FOURTHSTAGE COLLECTOR. In addition, in order to promotestable operations over a wide range of operating condi-tions, VORTEX STABILIZER DEVICES are installed.For orientation, the THIRD STAGE COLLECTORshown is subdivided into three distinct pressure chambers:A, D, and E. Dust-laden gases enter the system at theupper inlet nozzle and are immediately expanded insidethe FLUE GAS DISTRIBUTION PLENUM (A). There,the gas velocity is lowered to a level where solids backmixing is greatly minimized. A small size-large size solidsparticle disengagement process is initiated and promoted.In addition, a gas-solids separation mechanism is triggered(via saltation). Still traveling at a very low velocity, the fluegases are turned downward toward the horizontally ar-ranged modular collectors (C). Large size solids particles,debris (such as liner material, having been carried our ofthe regenerator vessel), and clusters ofsolids material (suchas catalyst surges), continue on their downward path -never entering the modular collectors - and are tempo-rarily collected inside the DEBRIS COLLECTION PLE-NUM (B). Material collected there is discharged via theDEBRIS/ROUGH CUT DISCHARGE (G).

Solids material - already having been pre-sized andbeing of sufficiently small size - will enter the modularcollectors via their tangential inlet horns. Inside eachmodular collector cell, a centrifugal force ofapproximatelya hundred g’s is imparted upon each solids particle intro-duced into the system via the gas stream. The internalcollector cells separate the solids particles from the gasstream and discharge them into the FINES COLLEC-TION PLENUM (D), where the dust is removed via theSOLIDS FINES DISCHARGE (F). Final removal of thesolids may be carried out by a typical underflow system,or by gravitational force only, e.g., into a separate FINESSTORAGE VESSEL arranged underneath the THIRDSTAGE VESSEL. Each modular collector cell movescleaned gases outward and toward the CLEAN GASPLENUM (E), where gases are discharged via CLEANGAS OUT (H) upward and back into the main stream.

All modular collectors are installed in a quasi-horizon-tal, helical fashion inside a pressure vessel, uninhibited bythermal expansion. The modular collector cells are inter-connected via a grid-like construction, thus allowing free,uninhibited radial and axial expansion of the internalsystem. This design minimizes the buildup of stresses.Each modular collector cell moves cleaned gases outwardand toward the CLEAN GAS PLENUM (E), where gases

are discharged via CLEAN GAS OUT (H) upwardly andback into the main stream.

As can be seen, each internal cyclone is fitted with aninternal vortex stabilizer device (patented), which turnsthis modern third staged cyclone into a very stable oper-ating device. Correct positioning of the vortex stabilizers,however, is very important. Their location is very impor-tant. The position, by and large, is determined by thenatural vortex procession. I need to point out that thegeometric axis of the cyclone structure and the axis of thevortex should not be confused. They are not identical. Viainstallation of vortex stabilizers, operations of the cyclonecollectors will become stable and predictable. As a result,the internal vortex finger will not jump to the wall whenoperating conditions change. Hence, it will not erode theinner liners and will not cut off diplegs as can be experi-enced often with old style, standard type cyclones.

As already mentioned, this particular third stage sepa-rator does away, without compromise, with UNDER-FLOW and FOURTH STAGE COLLECTORS. Itachieves collection efficiencies of around 80 mg/Nm3.Units rendering collection efficiencies of 50mg/Nm3 arealready in service.

On a final note, it is possible to revamp/upgrade exist-ing/older third stage cyclones to meet tougher emissionstandards.

STEVEN A. KALOTA (The M.W. Kellogg Company):In regard to swirl vanes of third stage separators, one of

the other factors that will influence the performance orefficiency is the underflow flue gas flow rate. It can beneither too high nor too low. You can get re-entrainmentor your cyclones will not be working very well. We haveseen many instances of people cutting these rates down,crying to push more gas to their expander and, of course,they suffered performance loss. If you go too high, thenyou get re-entrainment. These things function best whenthere is a certain downward velocity. That, of course, isrelated to the disengaging area underneath these swirl tubeassemblies. You do not want any gas-to-wall impingementcoming out of these tubes either. So typically, I think, theseunderflow rates should be about 3 wt % of the total fluegas coming in.

QUESTION 12.Has anyone used normal butane as lift gas or fluoridi-zation medium in the base of the riser? What yieldpattern changes were observed?

ROSS:Although I am not aware of any direct experience with

normal butane in the lift section of the riser prior to feedinjection, I have made a few simple estimates of thermalconversion and yield at typical catalyst temperatures priorto feed injection. For normal butane, thermal cracking

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completely without the influence of catalytic effects(which is a very simple chemistry to anticipate) at 1300°Fto 1350°F and residence times on the order of 1/2 secondto 1 second, conversion levels from 20% to 60% can beanticipated. One would expect the pyrolysis yield of theconverted butane to be on the order of 2% hydrogen, 15%methane, 45% ethylene, 20% propylene, and the rest C4S

and C5S, depending on the partial pressure in the systemat the time. Obviously, it is a very bad idea to use butaneas a lift gas as there is a lot of dry gas production.

ERNEST L. LEUENBERGER (ARC0 Products Company):I have some laboratory data that support Mr. Ross’s

calculations. We injected butane into a 1200°F laboratoryFCC riser reactor with a 2-second residence time. Butaneconversion was 40%. The yields from the converted bu-tane were 1 wt% hydrogen, 18 wt% methane, 24 wt%ethylene, 9 wt% ethane, 36 wt% propylene, 2 wt% pro-pane, 1 wt% isobutane, 8 wt% butylenes, and 1 wt% coke.The differences between our product distribution and Mr.Ross’s can be attributed to the hydrogen transfer activityof the FCC catalyst.

QUESTION 13.Have any refiners made mechanical or operatingchanges to the regenerator to reduce the gas environ-ment to the reactor system? Can the reduction bequantified?

DEADY:I have two stories on this, one operating and one

mechanical. In the operating story, one refiner modifiedthe aeration rates on the regenerator standpipe such thatthey operated between 90% and 115% of theoretical,compared to their previous operation where they wererunning about 130% to 140% of theoretical. In order tooperate in this manner, all the aeration air orifice plates,which fed off of a single header to the standpipe, werereplaced with individual aeration tap flow meters fed froma series of pressure-controlled headers. This allowed themto control accurately individual aeration rates so that thepressure profile would be as close to optimal as possible.

Using this strategy they were able to accurately changeaeration flows and patterns as the feed rates changed andas the catalyst circulation rates were varied in order toreduce entrainment back to the reactor. The amount of airactually transported to the reactor could be quantified intwo ways. The first was from the amount of CO and CO2

measured in the absorber offgas stream. The second wasby a proprietary design correlation that used catalyst cir-culation rate, catalyst flowing density, and catalyst skeletaldensity to correlate with the amount of gas entrained.

The mechanical story is of one refiner who installed asteam stripper for the regenerated catalyst in order to

reduce the flue gas entrainment back to the reactor. Whenthey turned the steam stripper off, they saw an increase ofabout ten numbers in ECAT microactivity. I am not sureif they quantified the amount of reduction in the gasentrainment they observed while the steam stripper wasin service. Needless to say, the steam stripper has remainedout of service.

ROSS:The key to success is the proper design of the catalyst

withdrawal system, including hopper and standpipe. Inmany cases, a unit has been expanded or the capacitysimply increased without modifying the catalyst with-drawal system. The catalyst must enter the withdrawalsystem at a velocity lower than the bubble rise velocity toallow the catalyst to degas. The hopper cannot be too large,however, as this will result in excessive deaeration.

Although tempting, steam stripping of the catalystleaving the regenerator is not a good idea. The flue gas andinerts will be effectively removed; however, there is com-mercial precedent for excessive catalyst deactivation whenstripping with steam at high temperature. In the stand-pipe, aeration is typically accomplished with air, this canbe changed to steam, with the same caveat as above, oreven fuel gas. One other note concerning other sources ofinerts in the reactor, if you have air purged instruments inthe reactor, replace them with steam or fuel gas.

STEVEN A. KALOTA (The M.W. Kellogg Company):

This question was kind of interesting because I won-dered what they were driving at. Were they really justinterested in reducing inerts to the reactor, or was this aquestion of getting amine consumption down in theirtreating section? I think the answer is not to mess withaeration rates and catalyst circulation stability for the sakeof a little amine consumption.

MARK SCHNAITH (UOP):

Unfortunately, if you want to maintain good catalystcirculation, you are going to have a certain amount ofentrainment of inerts. Good standpipe design can helpminimize, but never eliminate, this entrainment. How-ever, we do have a potential solution in the works today.We have a new technology under development called theX design. In that technology is a mechanism by which wecan remove the inerts from the regenerated catalyst beforeit enters the reactor.

QUESTION 14.

What has been recent experience with improved risertermination devices for reducing contact time andthermal cracking? What operational Changes wereimplemented to maintain conversion levels?

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ROSS:I hope you will bear with me. I will try to set the premise

for some of the direct experience some of the other refinerson the panel may have. The industry is now well aware ofthe detrimental effects of post-riser cracking and productdegradation, both catalytic and thermal. There are severalmodern end of riser separation or riser termination devices(RTDs) that improve both catalyst and vapor separationefficiency to avoid post-riser product degradation. Exam-ples of these RTDs include closed or close coupled cy-clones, vortex separator, and the Ramshorn Axial Cyclonelicensed by Stone & Webster. These systems provide veryhigh catalyst separation efficiency and deliver the productvapors from the outlet of the riser to the outlet of thereactor vessel in roughly five seconds. Start-up and oper-ability factors are important aspects of these systems.

When installing an advanced RTD, the amount ofimprovement is dependent on the type of separator re-placed, the reactor temperature, and the amount of post-riser residence time eliminated. Typical post-riserconversions of 4% to 5% are common with a residencetime of about 20 seconds. In one case, as much as 10%post-riser conversion was measured resulting from a resi-dence time of about 40 seconds.

The improved performance noted after installing anRTD is a drop in dry gas production and an increase invaluable liquid products. The refiner then adjusts operat-ing parameters to take advantage of the wet gas compressorcapacity to drive the unit back to its limit, usually byincreasing the riser temperature and reaping the benefitsof higher LPG olefins and gasoline octane. In some in-stances, the gasoline yield may actually remain about thesame even though overcracking would be expected athigher reactor temperature. In one case, we observed adrop in dry gas of more than 30%, in another a drop ofabout 20%, and in a third instance, an increase in feed rateof about l0%, made possible by the reduction in dry gas.

The “lost” conversion when eliminating post-riser ther-mal conversion can be compensated for by increasedcatalyst-to-oil ratio, catalyst activity, riser temperature, ora combination ofall three. The most effective is an increasein catalyst-to-oil ratio which also results in an increase inyield selectivity.

Another technology that reduces post-riser productdegradation is the Amoco post-riser quench licensed byStone & Webster. In this system, the product vapors arequenched after the catalyst has been removed or separatedin a RTD. Typically 5% to 7% recycle of LCO (or similarrefractory material) is injected just after vapor separationfrom the bulk of the catalyst. This results in cooling theproduct vapors by 50°F to 70°F without causing down-stream coking as has been demonstrated in a three-yearcoke-free run on a 2% to 3% Conradson carbon feedquench with product to about 950°F Thermal cracking is

effectively terminated in a low-cost, mechanically simplesystem, which requires no special operating procedures.

SOLIS:In November the reactor of our Huelva Refinery Exxon

FCCUs will be revamped to be retrofitted to Exxon shortcontact time technology. We have conducted extensivepilot plant work for catalyst screening, covering sevendifferent catalysts. I have to say that the results haveidentified substantial performance differences betweenthem. As a consequence, a proper catalyst selection isessential to get the benefits of the new technology.

VAN IDERSTINE:Consumers Co-op has a 20,000 bbl/d UOP stack

model FCCU, originally built in 1953. This summer werevamped the reactor with the UOP vortex separationdevice for riser termination and, at the same time, installedthe UOP Optimix elevated radial feed nozzle arrange-ment. Combined, these changes have improved our yields.Prior to the revamp, we had a standard elephant trunktermination off the riser, and for the feed we had a UOPpremix-type nozzle at the bottom of the Y piece.

Since start-up, we have seen yield changes that havebeen as expected, or maybe slightly better. Gas make isdown 25% to 30% for similar conditions. The LPG makeis reduced by about 5%. The gasoline to heavy cycle oilyield is up approximately 3% to 4%, with the majority ofthat improvement occurring between the gasoline and thelight cycle. Our slurry make increased slightly, as youwould expect for less overcracking.

One of the side benefits we realized as a result of notovercracking and less delta coke, was a reduction in regen-erator temperature of about 50°F. However, then by in-creasing the slurry recycle, we more than offset the initialincreased slurry make. We can increase slurry recyclebecause we are not at the maximum capacity on theFCCU.

The total cost of the revamp for the riser terminationplus the feed nozzle arrangement was about $2.5 million.The payout should be within two years.

PARKER:I am going to relate a recent experience from our

Borger, Texas refinery. We have recently revamped bothcatalytic crackers at that facility. The first unit is an oldSinclair side-by-side cracker. We installed radial feed noz-zles, an external cracking riser, and external rough-cutcyclones. We realized a dramatic reduction in the cokemake on the unit and some reduction in the dry gas make.

Following the start-up, we conducted a radioactivetracer study to evaluate the performance of the equipment.One thing we found that seems to be significant is we aregetting a higher product carrydown in the rough-cutdiplegs than we expected. From our instrumentation, etc.,

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we believe the diplegs are sealed. So we are continuing toevaluate the cyclone performance in that area.

The other unit is a Kellogg Model C cracker. Thatparticular unit has plug valves inside the regenerator. Thecatalyst flows through the plug valves up through the riser.It has three internal risers. We installed nozzles on the plugvalves using patented technology from Amoco and in-stalled inertial separators on the end of the risers. That unitappears to be performing very well. We have not donetracer studies to determine the residence time or theseparation efficiency.

ABRAHAMS:One of our plants’ experience with riser termination

devices began in 1987 when rough-cut cyclones wereinstalled. This allowed operating at slightly higher riseroutlet temperatures and slightly more catalyst activity toreplace thermal cracking with catalytic cracking. In 1995,this same unit was revamped to include a closed cyclonesystem, which further reduced thermal cracking as evi-denced by lower coke and dry gas production. We went tohigher riser temperatures, 1010°F up to 1040°F andhigher matrix catalyst activity, from 70 MAT to 73 MATThe unit was revised to allow higher catalyst circulationto stay in heat balance; we went from 55 to 68 tons aminute.

As further testimony to the old saying there is morethan one way to skin a cat, this year we are revamping threeFCCUs, one in each of our refineries. All of them arebetween 70,000 bbl/d and 90,000 bbl/d capacity, and weare using three different designs.

DEADY:I want to add to Mr. Abraham’s comments concerning

the catalyst. Of all the operating changes that could bemade, our preliminary work suggests that catalyst activityis probably preferred, and that the best yields are obtainedif this is achieved with selective matrix activity. We havesurveyed several refineries who did these types of revampsto determine the shifts they made in catalysts.

As expected, most refiners increased equilibrium mi-croactiviry rare earth level on the catalyst and total surfacearea to maintain conversion levels. Specifically, microac-tivity numbers increased by a range of 3 to 10 with theaverage being about 5 numbers. Rare earth levels increasedan average of 7%, with a range of 0.4 wt % to 1.1 wt %rare earth on the catalyst. And the range of the total surfacearea increase was between 10 meters squared per gram and40 meters squared per gram.

A refiner recently asked us when refiners are going tothese more active catalysts, before the revamp or after therevamp. There are basically two schools of thought onthat. If you think you will be able to address the severityloss with increased reactor temperature and catalyst-to-oilratio, then you can probably start up on the pre-turn-

around catalyst, quantify your mechanical changes, andthen switch to the more active catalyst. Refiners concernedthat they might not be able to circulate enough catalyst,or who are constrained in raising their reactor tempera-ture, would probably be better off adding the more activecatalyst before the revamp.

FRONDORF:At our Corpus Christi, Texas refinery, we have two

UOP catalytic crackers, one a 1950 vintage, revampedstacked unit, the other a 1975 vintage side-by-side. Wehave not made any recent changes to riser termination atthe Corpus Christi plant. The last one in 1987 involvedan elephant trunk design. I guess that is self-explanatory.In general, the expectations for improved terminationwould be higher reactor temperature and/or catalyst activ-ity to maintain the same conversion level.

At the Lake Charles, Louisiana refinery, we have three1944 vintage Kellogg Model 2 catalytic crackers. Theyhave been modified several times over the years and cur-rently have dual sloped risers and a combination of eitherinverted can or vented hood termination devices, depend-ing on which FCCU we are discussing. We are initiatinganother set of revamps to move to full vertical risers, withexternal rough cut cyclones.

The first unit is due to have its turnaround and revampin the spring of next year. The current plan on that unitwould be to increase catalyst activity to maintain conver-sion levels following the completion of the revamp. Ms.Deady was exactly correct because the team has already satdown with the catalyst vendor to lay out a plan on howwe want to handle catalyst activity at the time of therevamp start-up.

HANSEN:

We installed a close coupled cyclone system in October1994. Dry gas, coke, and diolefin production have beenreduced. We typically operated at maximum catalyst-to-oil ratio and found that in addition to this, increasingcatalyst activity by 2 to 4 MAT numbers and increasingriser temperature were needed to maintain conversion.

JOHNS:Texaco has installed their negative pressure Direct-

Coupled Cyclone design at three locations: Port Arthur,Valero, and Nerefeco. Results from all three locationsdemonstrate significant reduction in dry gas make, higheroleficinity from less hydrogen transfer reactions at the lowcontact time, and substantially lower delta coke resultingin lower regenerator temperature (30°F to 40°F). Conver-sion level was maintained in all cases by increasing catalystcirculation and increasing the rare earth content of thecatalyst to provide higher activity.

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GEORGE A. SMITH (Exxon Research & Engineering Company):Recent experiences with short contact time designs for

both grassroots and revamps have met or exceeded expec-tations for both yields and operability. Yields have beenexcellent and operations have been very robust over quitea wide range of operations. As contact time and thereforethermal cracking are reduced, other factors must be ad-justed to maintain conversion and achieve optimum yieldselectivities. The panel has already mentioned these factors;and we agree. They include catalyst activity, catalyst formu-lation, catalyst-to-oil ratio, and operating temperatures.

PAUL SESTILI (The M.W. Kellogg Company):Not to belabor the point, but as you all know Kellogg

offers Mobil closed cyclones as our improved riser termi-nation device. To give you a quick summary of our recentexperience, we have 19 units in operation that have beensuccessfully running since 1985, about 100 years of cumu-lative operating experience, and about a million barrels aday in current operation.

ROBERT GLENDINNING (ABB Lumus Global, Inc.):For anyone in the audience who may not be aware,

Lummus currently licenses FCC technology with Texaco.It is interesting to note that in the Phillips Borger radio-tracer study, a high dipleg vapor carryunder was detectedwith a positive pressure cyclone, despite sealing the diplegin the stripper bed. This will in turn lead to higherhydrocarbon carryover rates to the regenerator. Our risertermination device, as Mr. Johns pointed out, is a negativepressure cyclone system that minimizes hydrocarbon car-ryover to the regenerator. When we actually look at theperformance of the commercial units, what tends to hap-pen relative to a positive pressure cyclone system, is a dropin regenerator temperature of 25°F to 30°F, which pro-duces higher catalyst-to-oil ratios, increased conversion,and reduced dry gas production. So, whereas we agree thatthe riser termination device is important, we think theoperating characteristics of the riser termination device areequally important.

In a paper presented at the 1994 meeting of the JapanPetroleum Institute, we outlined the advantages of nega-tive pressure direct coupled cyclones relative to positivepressure systems, and this has been clearly demonstratedby the observation of these substantial decreases in regen-erator temperatures.

QUESTION 15.Excluding the effects of SOx reducing additives, whatare refiners’ experiences with NOx reduction from theFCC regenerator? Has afterburn become a problem?

DEADY:Some of this question was also covered last year in the

1994 transcript. Refiners have the ability to reduce NOx

from the FCC regenerator in a variety of ways. First of all,lower the excess O2. We know one refiner, an extreme case,who decreased his excess O2 from 6% to 2%, and elimi-nated a brown NOx plume.

Managing promoter additions is also a key way tocontrol the NOx. It is widely accepted that excess additionof standard CO promoters can increase FCC NOx emis-sions. Improving catalyst air distribution will also helpwith your NOx. Moving to a partial burn operation canhelp. However, sometimes the NOx from the CO boilercould still be a problem. You can also look at reducing thenitrogen in the feed by FCC feed hydrotreating, sinceincreasing feed nitrogen has been correlated with increas-ing NOx emissions.

We are investigating, in conjunction with a major oilcompany, additional additives that will reduce NOx bypromoting the reaction between the NO and reductantssuch as CO or coke. Laboratory testing shows reductionsof about 40% to 50% of NOx, and we expect to have atrial of this material by the end of the year.

In addition, we will be conducting a commercial evalu-ation of a low NOx combustion promoter that has shownpromise in the laboratory. This new combustion promoterhas activity for CO combustion similar to that of conven-tional production promoters, but produces about 30% lessNOx. Again, we are expecting a commercial trial of thismaterial by the end of the year.

HANSEN:Our operating permit limits the amount of NOx in the

flue gas. The most effective method ofcontrol is operationat lower excess oxygen levels, such as 0.5%, and careful useof platinum-based combustion promoter. Afterburn canbe a problem, especially at lower flue gas rates.

There is a wet DeNOx process available. In this processthe NO, which is typically the dominant species in NOx

and insoluble in water, is converted to NO2 using sodiumchlorite. The NO2 is then absorbed. A separate quenchcircuit is needed for this process because of the chemistrydifferences between NOx and SOx removals.

PARKER:There have been reports in the literature on a correla-

tion between basic nitrogen in the feed, and NOx. We triedto correlate that in our own plant because we run signifi-cant levels of basic nitrogen, in the 500 ppm to 1000 ppmrange, and we could not correlate with the stack NOx.During stack testing, we did discover that if you have anyammonia or cyanide compounds in the flue gas from aquench or anything like that, it will show up as NOx onsome of the stack tests.

G. ANDREW SMITH (INTERCAT Inc.)We have commercial experience in several units using

a low NOx promoter. We have found that a combination

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of a low-platinum promoter added at a constant platinumrate reduces NOx emissions and avoids afterburning.

PHILLIP NICCUM (The M. W. Kellogg Company):Given the effect of combustion promoter and excess

oxygen on NOx, units with good catalyst and air distri-bution, which can run at low excess oxygen with little orno combustion promoter, are going to show the best NOx

performance.In addition, it has been found that the NOx is the result

of nitrogen in the feedstock. Recent publications by W. R.Grace indicate that most of the nitrogen in the coke isconverted into nitrogen gas in the regenerator, with someof the nitrogen emerging as NOx. One of the reactionsthat occur in a regenerator is that the NOx initially formedcan react with the carbon in the regenerator bed and beconverted into nitrogen gas. In the countercurrent regen-eration process offered by Kellogg, the spent catalyst isintroduced evenly over the top of the regenerator bed; sothere is a greater opportunity for the NOx to be reducedto nitrogen.

The following chart shows the percent of the nitrogenin the coke that goes to NOx on the left side, and on the

bottom axis you have the percent oxygen in the flue gas.These are correlations of data from Mobil FCC units forthree different types of regenerators. The top curve is theso-called swirl regenerator, which is a side entry dense bedregenerator. The curve in the center is a combustor typeregenerator, and the lower curve is from the KelloggCountercurrent Regenerator. You can see from the chartthat the countercurrent regenerator provides a muchlower percentage of the nitrogen in the coke going toNO x .

KING YEN YUNG (Akzo Nobel Chemicals BV):My answer is in regard to the previous question about

NOx reduction. I agree that a good way to achieve NOx

reduction is through promoter management. In Europe,a refinery reduced the promoter addition by 40% andcould reduce NOx by 50%. The penalty was increasedafterburn to 40°C.

In a more recent example, we have an application thatwas using additive and they were suffering from afterburn,some 20°C. They switched to a more effective promotioncatalyst (INSITUPRO option). With this more effectivepromoter, they reduced the platinum on ECAT by 70%,

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decreased afterburn to 5°C and achieved a NOx reductionof 30%.

QUESTION 16.Several SOx reduction technologies are available tothe refiner (catalyst additives, scrubbers). How dorefiners determine which technology to use? Whenusing the catalyst additive approach are there anysignificant shifts in sulfur content of the various liquidproducts?

SOLIS:Selection of flue gas sulfur control technology is driven

by the cost of the wet gas scrubber and the cost of the SOx

additive. If the flue gas SOx level is less than 700 ppm to900 ppm, assuming a requirement to reduce it to less than300 ppm, the cost difference is about break-even. If theSOx level is higher than that, the lower operating cost ofthe scrubber will easily offset the higher initial capitalinvestment. The scrubber investment is used as a credit forthe electrostatic precipitator, which would not be neces-sary with the scrubber. Local economics may shift thebreak-even point, so it should be reviewed on a case-by-case basis.

For existing units, I feel that unless a scrubber is inplace, catalyst additives are the convenient solution. How-ever, it should be realized that additives are not very activein partial combustion mode units. Again, additive effi-ciency and prices are highly variable, and cost-effectivenesstests in pilot plants are recommended.

Regarding the second part of the question, the sulfurthat is removed is SOx from the regenerator and is con-verted to H2S in the reactor. The catalyst additive has nosignificant effect on the sulfur distribution of the liquidproducts, but we have observed that some SOx catalystadditives can slightly reduce the sulfur in the FCC naphtha.

DEADY:I agree with Mr. Solis, especially on his point that the

break-even point is highly unit-specific. We found that itis unit-specific because the SOx capture efficiency of SOx

reducing additives such as DeSox™ is extremely unit-specific. Based upon our experience, we see a slightly higherbreak-even point with DeSox™ technology. We see that theSOx reducing additives are most cost-effective if you haveSOx emissions below 2500 ppm base. Above about 3000ppm base SOx, the flue gas scrubbing economics canbecome much more attractive. In general, because this is sounit-specific, we would recommend a commercial trial ofSOx reducing additive just to quantify that performance.

As an example, the cost for the additive approach toreduce SOx from about 600 ppm to about 300 ppm isabout $4,000 a day for a typical 50,000 bbl/d unit, withan additional capital cost of about $50,000 for a loadingsystem. Based on feedback from our customers for the

scrubber scenario, the operating cost would be about$9,000 a day with a capital cost ofabout $20 million. Thisis in order to achieve the new source performance standardrequirement of 90% SO2 emissions reduction, or less than50 ppm SO2 emissions. The standards with the flue gasscrubber are a little different, because of the new sourceperformance standard requirements.

We have not observed increased sulfur (or decreasedsulfur, for that matter) in any of the liquid products withthe SOx additive approach. All the sulfur recovered fromthe flue gas leaves the unit as H2S.

FRONDORF:Our Corpus Christi, Texas refinery, operating on hy-

drotreated feed, does not have a flue gas scrubbing system.We use SOx reduction additive on an as-needed basis tomeet final stack specifications. The Lake Charles, Louisi-ana refinery, operating on nonhydrotreated feed, uses SOx

reduction additive on a regular basis to meet final stackspecifications. The Lake Charles refinery is in the processof installing an FCC feed hydrotreater and our plans atthis time would be to continue the SOx additive on anas-needed basis. We have no plans at this time to install aflue gas scrubber.

A spot reading from the Lake Charles plant for our SOx

additive reduction would be about 35 cents per pound ofSO2 removed. Neither refinery has seen a significant shiftin sulfur content of the liquid products following SOx

additive.

KELLER:We are currently using an SOx reducing additive, which

is effective in reducing the emissions to below our limit of99 ppm. We currently add a 40-lb dosage (110 ton catalystinventory), which lowers the SOx ppm about 20%. Thisreduction typically lasts from 4 to 16 hours. We have notseen any significant shifts in the sulfur content of theliquid products with the use of the additive.

ROSS:I understand there is a broad difference of opinion on

the breakpoint between the SOx level and when the cata-lyst additives are useful. In some of the analyses we havedone, it suggested somewhat less than 1500 ppm andperhaps closer to the 1000 number we heard before.Regarding its effectiveness in partial combustion, we haveseen trials measuring an effectiveness of 50% to 70% inthe first stage partial combustion regenerator of a two-stage regeneration resid unit.

Each SOx reduction technology has advantages anddisadvantages which are site-specific. Issues to be ad-dressed include the following:

Required reduction in SOx emissionsCapital costOperating and maintenance cost

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Compatibility with FCC process & ability to copewith catalyst finesAdaptability for dealing with other pollutants suchas NOx and particulatesDischarge issues — water discharge, solids disposal,opacityPlot space requirements

PAUL SESTILI (The M. W. Kellogg Company):To determine the most applicable technology for pol-

lution control in a refinery, an overall analysis of thebenefits of each system must be made. Kellogg recentlycompleted a study comparing a wet gas scrubber to a SO,reduction catalyst plus electrostatic precipitator. The wetgas scrubber tends to have a higher capital investment, butlower maintenance costs and operator attention. The over-all plot space requirement for the scrubber is higher;however, the purge treatment unit can be placed off-site.As a result, the on-site plot space requirement is muchlower for the scrubber. The catalyst plus precipitator op-tion has a lower capital cost, but requires more mainte-nance and operator attention due to the ESP. The wastedisposal for the scrubber is both solid and liquid, whereasthe ESP waste is a solid dust only. In summary, it isimportant to look at the big picture when determining themost applicable pollution control system for a given refin-ery. See following table.

Kellogg Comparison Of Pollution Control Options

G. ANDREW SMITH (INTERCAT Inc.):With the recent improvements in SOx additives, refin-

eries have a choice of purchasing an additive with equiva-lent performance to current deSOx additives that cost40% less, or purchasing ones with 40% greater pickupefficiencies at similar pricing. We would also advise refin-ers that are considering their options to run a short testwith a SOx additive, like the NO-SOx family, to deter-mine their economics. It is my opinion that the econom-ics will continue to favor the SOx additives overmechanical scrubbers for years to come in many cases.

VICENTE A. CITARELLA (Exxon Research & Engineering Company):We also agree with the remarks that have been made

regarding the fact that SOx control technologies are site-specific and depend on the costs and benefits of the variousalternatives. The only thing that I would like to add is thatscrubbing, such as the Exxon Wet Gas Scrubber System,is really the only option that controls both SOx andparticulates in one single unit. Our wet gas scrubbers canachieve SOx removal in excess of 90% and meet SOx

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emissions standards for FCC feeds with up to 3% sulfur,and can simultaneously meet the U.S. particulate removalspecification of 1 lb per thousand pounds of coke burned,or 50 mg per normal cubic meter, which is frequentlyspecified abroad.

MORGAN:Once a scrubber has been approved by a state, your

operating permit requires that the scrubber be in service.For that reason, if your scrubber has a malfunction, youmay find it necessary to shut down your FCCU. From anoperating standpoint, that, to me, greatly favors the deSOx

type operation.

THOMAS WALKER (Belco Technologies Corporation):Belco, in association with a New Jersey refinery, com-

pleted a study in regard to catalyst additive and scrubberoptions for deSOx Obviously, many environmental, proc-ess, and economic variables play an important role asmentioned by several of the people. However, I would liketo state that, at this time, that refinery had opted for theBelco EDV scrubber, and a review of the study’s contentand decision process can be found in a paper compiled byBelco entitled Flue Gas Cleaning on Fluid Catalytic Crack-ing. Please contact Belco at the address below to obtain acopy of this paper.

I would further like to mention to those of you attendingthe NPRA Environmental Conference in two weeks in SanFrancisco that Belco and Valero Refinery will be presentinga paper entitled FCC Offgas Cleaning at the Valero Refineryin Cops Christi. Again, this paper reviews Valero’s decisionand operating experience with the Belco EDV.

VICENTE A. CITARELLA (Exxon Research & Engineering Company):

With respect to the need to shut down an FCCUbecause of a scrubber malfunction, we have a very longhistory (over 150 unit-years) of Exxon wet gas scrubbersin operation and have not had any situation where anFCCU has had to be shut down because of a wet gasscrubber malfunction.

JAMES D. WEITH (Unocal Corporation):Regarding flue gas scrubbers being part of the operating

permit, per Mr. Morgan’s comment, ESPs are part of theoperating permit where we live, too.

QUESTION 17.

We have moved from once-a-day to continuous FCCcatalyst addition. Due to common lines, we have toshut this system down periodically to make batchwithdrawals. Does anyone have a continuous catalystwithdrawal process? Do you see any benefits in doingthis?

JOHNS:For this response I would like to relate an experience I

had on a unit several years back. This unit had continuouscatalyst additions, and we tried continuous withdrawal forseveral months with no noticeable effects. I suppose wewere lucky at this, but there should be no difference if youare withdrawing from a location that preferentially re-moves the older, larger, aged particles of catalyst in eithercontinuous or non-continuous mode.

ROSS:I am aware of the IFP-Total design employed in two

resid crackers and a system used by BP for continuouswithdrawal and addition of catalyst. Both systems useconventional dilute phase withdrawal and injection sys-tems with the IFP-Total system using a special flow regu-lation valve utilizing a ceramic lining for long life.Generally speaking, continuous withdrawal is not re-quired unless a special off-line catalyst demetalizationprocess is considered where very large movements of cata-lyst out of and back into the unit are required.

Continuous addition is considered best practice as thecatalyst activity level is maintained at a nearly constantlevel. Adedicated line is typically provided for this purposeand should not interfere with withdrawal operations. Forresidue cracking operations, continuous addition andwithdrawal almost become a necessity due to the largequantities ofcatalyst involved and the cyclic catalyst activ-ity which would result with a single large batch addition.Continuous addition also levels out the catalyst loss asso-ciated with fresh addition to avoid peaks in catalyst loss.

SOLIS:There are operational stability benefits from using con-

tinuous catalyst addition rather than short, large batchesof catalyst addition. The spike of fresh catalyst activity canresult in a short-term overcracking situation with an in-crease in coke and gas products. These product increasescan be seen in the main column and gas concentrationfacilities and the disturbances prevent continuous opera-tion at the highest throughput.

Catalyst withdrawal is usually done on a batch basissince it does not change the composition of the ECATinventory, and no process performance issues are seen. Aslong as the time for withdrawal is relatively short, say 1 to2 hours, it is unlikely that an interruption in fresh catalystaddition will be seen. In RCC units, where catalyst addi-tion is quite large, withdrawals are made on a daily basis.In this case, there is a continuous withdrawal system, butits purpose is mainly to cool the withdrawn catalyst so itcan safely be sent to the storage hopper.

MARK SCHNAITH (UOP):There is a large RCC unit in the Far East operating with

a continuous catalyst withdrawal system, fully automated,

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that can operate at rates of 30 tons per day withdrawal.The high rate is necessary to control metals levels on theequilibrium catalyst. In a system like this, one key is tohave an effective cooling system to avoid overheating thestorage hopper. This system has been in operation for morethan one year.

STEPHEN J. YANIK (Akzo Nobel Chemicals Inc.):I am aware of a couple of locations in the Asia-Pacific

area where people have justified the use of a second freshcatalyst silo just to make sure that catalyst addition is notinterrupted while they are pulling a vacuum to load fromtrucks or containers into the other silo. It has a couple ofbenefits. It gives you more fresh catalyst inventory and alsogives you some flexibility in possibly blending a couple ofcatalysts. So, having two fresh catalyst silos is becomingrather common on those big residual cracking units.

QUESTION 18.Have the etched disc or porous metal type fillrationsystems been used commercially in FCC slurry serv-ice? What are typical solids removal efficiencies andoil recoveries? What are the alternatives for disposingof the backflush material besides recycling back to theFCC riser? What are the maintenance histories?

EMANUEL:We currently operate a Gulftronics filtration system for

our slurry, which reduces catalyst content of the slurryfrom 0.2% ash to a clarified slurry oil product with0.005% ash. We have had very few maintenance problemswith the system to date. We backflush the Gulftronicfilters with heavy vacuum gas oil and send the backflushto our riser. We considered sending the backflush to ourNo. 6 fuel stream, but the content of the ash was too highand would have brought the fuel oil off specification.

Backflushing to the riser does create unique problemswith control on your FCCU, and that is a constantproblem for us as far as cycling the unit is concerned. Bightnow that is the best place that we have found to put thematerial.

ABRAHAMS:One of our plants used a porous metal filtration system

on its slurry oil. The backflush material was sent to theriser and caused opacity problems since the stack was theonly place for fines to go. The unit is not equipped withan electrostatic precipitator. As a result, the filter systemwas removed from service and moved to another location.Our suggestion for disposal of backflush in this situationis to send it to a coker if possible.

As a contrast to what Mr. Emanuel was saying a minuteago, we had a Gulftronics filtration system in one of ourrefineries, and we got rid of it.

DEADY:I know a refiner who tried some of the porous metal

filtration systems in their slurry system a couple of yearsago, and all of those tested were unsatisfactory. While theremoval rates were very good, the systems were plaguedwith poor operability and inability to adequately back-flush the fine material from the pores of the filter media.These difficulties made these systems extremely unpopu-lar with the operations personnel, and, in addition, main-tenance was high. Since then, they have not tried thesefilters again.

ROSS:One resid unit that I am aware of used the sintered mesh

filtering system with excellent results over three years, anda new unit about to start up will use the same system. Acake of catalyst builds up, forming on the filter with thecut point on particle size typically between 10 to 20microns. Periodically, the cake must be removed by back-flushing into the FCC riser to limit pressure drop. Thebackflush sequencing valves and recycle pump are the areasrequiring attention as the fines content is high and caremust be taken to maintain the equipment. One refinernotes that good equipment layout for access and qualityvalving for automatic backflush are vital components of asuccessful design and are not areas to try to cut corners orcosts.

Efficiency is very good with virtual exclusion of parti-cles greater than about 15 microns. The oil retained on thecaptured catalyst is recycled back to the riser with thebackflush. A typical product oil stream will contain about50 ppm catalyst or less.

Control of the filter size/efficiency is important if thematerial is to be recycled to the riser. A very fine filter willsimply recycle small particles resulting in an increase inthe fines concentration in the oil as well as a very highpressure drop across the filter. The selection of a 10 to 10micron cut point recycles only that material which can bepartially retained and eventually lost to the flue gas system.A finer filtration will likely require disposal means otherthan recycle.

Another refiner we are aware of has experience withboth the sintered mesh and filter systems. When a sinteredmetal filter is used without dependence on the cake, theelements must be periodically cleaned off-line, as well asperiodically backflushed. Disposal is typically limited tothe FCC riser, coker, or asphalt, if specifications allow.

SIM ROMERO (BP Oil):We have two sintered metal filters in Ohio. The first

filter was commissioned about 5 years ago and is notcurrently in service. The second filter has been in servicefor the last 3 years and is operating with little to noproblems. The key to the operations was the location ofthe filter. The first filter was located in the tank farm with

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feed at 300°F. to 350°F — too cold. This filter had The third case involves the high pressure absorberplugging problems and required frequent cleaning (about tower. This is for a grassroots plant, and our studies showevery 3 to 6 months). The other filter was located at the that a higher pressure absorber tower is actually moreunit and had a much hotter feed. The hot feed reduced economical than the cryogenic system. In this case, thethe plugging in the filter. The filter has been in operation absorber tower runs about 260 psi and the propylenefor 3 years and has been cleaned only once. recovery is 92%.

ROBERT L. BROWN (Pall Process Filtration Co.):Pall Rigimesh® backwash systems are now being com-

mercially used in refineries throughout the world. To date,there have been twelve systems sold, and there are cur-rently four in operation. The oldest has been in operationfor over 3 years with minimal maintenance problems. Theother eight are now in the design and construction stage.The typical influent for the solids is between 3000 ppmand 5000 ppm with the effluent consistently being below50 ppm, and in all cases the backwash fluid is designed togo back to the riser. The quantity or the volume of thebackwash fluid is typically less than 2% of the amount ofslurry oil that is being processed.

We also did a process study for a low pressure FCC gasplant. In this case the gas plant absorber was limited to140 psi operating pressure. We used refrigeration to coolthe naphtha for the absorber and the lean oil for thesponge absorber. Because the gas and the oil containmoisture, we had to watch hydrates formation. It limitedthe temperature on the top of the absorber to no lowerthan 60°F. The result showed increased propylene recov-ery from 81% to 89%.

SOLIS:

STEVEN A. KALOTA (The M. W. Kellogg Company):In fairness to everybody who makes slurry separators,

there’are other alternatives: liquid cyclones or hydrocy-clones made by Dorr Oliver or Vortoil. The etched dishand Gulftronics are very good if you need to get a very lowsolids concentration. But if you are looking for concentra-tions just under 500 ppm, then one of these liquid cy-clones is a good alternative that is not quite as expensiveor as maintenance-unfriendly.

We have a conventional absorption and stripping sec-tion and a high-efficiency fractionation system to recoverand purify propylene. The role of the absorption andstripping section is to remove C2, H2S and, COS. Ourpropylene recovery in this section is 93%.

The fractionation system consists of a high performerpropane-propylene splitter (see Petrochemical ProcessingSession, Question 1) to separate propane from propylene.We have a loss of 5% of propylene in the propane bottomstream. Downstream of this splitter we have a molecularsieve treater to remove the traces of COS.

QUESTION 19 .Propylene recovery from the Gas Concentration Unitis a concern. What is the current technology availablefor improved C3= recovery? What are other refineriesdoing for C3= recovery? What is their normal recoveryefficiency?

SHEN:Propylene recovery depends heavily on the yield struc-

ture coming out of the reactor. So it is difficult to compareone case to another because often they are not on the sameyield basis.

Ofconcern in propane/propylene splitters is the poten-tial buildup of trace contaminants in the column. Inparticular, methyl acetylene and propadiene, when presentin trace quantities in the column feed, have volatilitiesbetween those of propane and propylene. Thus, thesecomponents do not readily leave the column with theoverhead or bottoms product. Rather, they tend to buildup in large quantities in the middle trays of the column.Generally, the presence of these components in the col-umn does not affect column performance or productquality. However, when the column is upset, potentially alarge quantity of methyl acetylene or propadiene couldleave the column with either the overhead or bottomproduct, causing either stream to go off-specification.

PARKER:We have seen refineries improve the propylene recovery

through various methods. The first is a combination ofincreased lean oil circulation and adding trays to thede-ethanizer absorber tower. One data point we had for a175 psig absorber system showed an increase in the pro-pylene recovery from 79% to 87%.

The second approach is the addition of a cryogenic unitfor the tail gas. At least one refinery we know of, afterinstalling the cryogenic unit, shut down the sponge oilabsorber altogether. The numbers we have in this case arefrom 81% to 90% recovery.

At our Borger, Texas refinery we replaced trays withpacking in the top three trays and the bottom twelve traysin the lean oil absorber. We believe it was successful. I donot have the efficiency gain numbers, but the currentrecovery percent is in the mid-90s. On our newest cata-lytic cracker at Sweeny, Texas, we handle this somewhatdifferently. The overhead vapor out of the lean oil ab-sorber is combined with the lean oil prior to the lean oilcooler, and then goes to a separation drum, with lean oilpumped from the separation drum to the absorber. Thereis probably a name for this, but I do not know it. Our

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recovery there runs about 3% propylene in the offgasduring the summer months.

ROSS:A new lean oil system with sponge absorber will recover

about 93% to 95% of the propylene, with losses to theoffgas system. A common step to improve the efficiencyis to chill the lean oil to about 50°F resulting in about a95% to 97% recovery.

A more effective and economical approach than in-creased lean oil circulation is the addition of a cryogenicrecovery system, which may include turbo expansionand/or refrigeration. If ethylene recovery is also desireddue to the proximity to a petrochemical complex, a self-refluxing dephlegmator exchanger-based system should beconsidered. An example of this type of system can befound at Mobil’s Beaumont, Texas facility, which has beenin operation since 1987 processing FCC offgas with asimple payback of 11 months. Any of these cryogenicsystems will recover essentially all of the propylene.

EMANUEL:In addition to cryogenic-type processes, we are begin-

ning to look at a new process that uses ultra high pressurelean oil absorption. The system is based on a typical leanoil design, which can be found in your FCC unit, but itis designed to operate at high pressures with a proprietarylean oil. The company currently marketing this process isAdvanced Extraction Technologies, Inc.

FRONDORF:Our Corpus Christi refinery operates with a primary

and a sponge absorber system, similar to what has pre-viously been mentioned, with cooling water for heat re-moval. We see a recovery efficiency of around 93% on thatsystem. At the Lake Charles refinery, we operate with aprimary absorber only with a chilled lean oil system,approximately GOOF, and see normal recovery efficienciesapproaching 95%.

KELLER:We currently recover about 92 wt % of the C3=. We

have a UOP Gas Concentration Unit, which uses a pri-mary absorber to absorb 91.6% of the C3s and almost allof the C4s out of the fuel gas. Debutanizer bottoms is thelean oil at the top, and main column overhead liquid isfed 10 trays down in our 40-tray primary absorber.

ANDREW SLOLEY (Process Consulting Services Inc.):Increased propylene production more than proportion-

ally increases losses at any given concentration unit. Re-coveries in the range of 92% to 95% can be consideredcurrent good performance. Improving yields from below90% to this range is usually straightforward and includesmaximized absorber pressure to the compressor limits,

reducing the absorption oil temperature, increasing theintercooler duties and increasing C2s that might be al-lowed in the alkylation unit feed. With chilling and im-proved process designs, recoveries to 98%+ are possiblewithin the unit.

Sponge oil (typically LCO) has little effect on C3

recovery in the primary absorber unless C3 recovery ispoor. Absorber efficiency has little impact on C3 recoveryunless the column is flooded. The stripper (or de-ethan-izer) performance can have a significant impact on recov-ery, especially if the absorber is stacked on the stripper (norecycle to the high pressure receiver condenser).

Once the existing process has been optimized, theprocess and equipment designs that should be looked atinclude chilled lean oil and main fractionator overheadliquid, chilled intercoolers, presaturator, and process con-trol issues.

Stand-alone refrigerated propylene recovery units havebeen used with varying degrees of success. From what wehave seen, the major concern for these units is includingsufficient flexibility to maintain recoveries over a reason-able operating yield range.

DELBERT F. TOLEN (Rocky Mountain Salvage & Equip.):Typical propylene recoveries from gas conservation

units are from 92% to 95%. They principally depend onthe pressure and how you run your stripper to strip theH2S. Twenty-five years ago we built a refrigerated gasabsorption plant in a 20,000 bbl/d refinery to recover thepropylene and butylene. The payout on that operation wasabout nine months. So, the economics are very clear cuton installing refrigerated gas absorption.

REZA SAOEGHBEIGI (RMS Engineering, Inc.):Another option to improve the C3/C4 recovery is to

install a presaturated drum. This drum will use the cooleddebutanized gasoline as the lean oil. We have seen recoveryimprovement anywhere from 3% to 5%.

QUESTION 20.What is the preferred contact time between catalystand oil, upstream of a primary separation device, tominimize the production of dry gas and achieve maxi-mum conversion?

ROSS:There are several distinct zones in the FCC riser: cata-

lyst/fied mixing, feed vaporization, riser vapor phase cata-lytic cracking, product vapor, and catalyst separation.Circulating pilot plant work has demonstrated significantgasoline yield and selectivity benefit when reducing theriser vapor phase catalytic cracking step under conditionswhere the initial contacting, mixing, and vaporization arenearly ideal. At constant conversion, the catalyst circula-tion rate must increase from about 6 to 7.5 and the riser

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temperature increase from 980°F to about 1000°F whenthe residence time-is reduced from 1.6 seconds (conven-tional) to 0.4 seconds based on outlet moles. The gasolineyield increases by about 3 wt % to 4 wt % with theselectivity increased by several points, at the same conver-sion. The improvement comes largely at the expense ofLPG, but the dry gas is also reduced by more than 20%as a result of the reduced time, higher catalyst-to-oil ratio,and lower regenerator temperature. These results wereobtained using conventional catalyst withdrawn from acommercial unit, and therefore the catalyst was not anoptimized formulation for short residence operation.

In order to obtain the reduction in residence time toabout 0.5 seconds in the riser vapor phase cracking section,a very efficient feed injection and catalyst mixing/contact-ing system is required. The order of magnitude of timerequired for vaporization is 0.1 seconds and becomes asignificant part of the total residence time.

New high-efficiency feed injection techniques combin-ing efficient atomizing feed nozzles and novel injectionorientation have demonstrated extremely rapid reductionin riser density after feed injection. Gamma scans of acommercial riser configured with new feed injection tech-niques demonstrated a density decrease from dense cata-lyst below feed injection to riser outlet density in about 1meter. This type of performance will be required to realizethe benefits of ultra short residence time.

Another consideration of short residence time systemsis that of product quench. The rapid end of riser separationtechniques used today will be inadequate. Just as theethylene industry moved from simple mechanical layoutdesigns to control residence time to quench fluid injectionto freeze degradation reactions, the refining industry willlikely move this way as well.

VAN IDERSTINE:Historically, the conventional residence time in risers

has been on the order of 1 to 3 seconds. We are currentlyat a 2.3 second residence at 17,500 bbl/d after our revamp.The optimum residence time for each refiner depends onwhat their hardware configuration is, and what theirconversion objectives are.

JOHNS:For the direct coupled system previously discussed, at

Texaco we design for maximum conversion with mini-mum gas make and a contact time of 1.5 to 2 seconds.This is dependent on paraffin content and carbon residuein the charge.

PETER G. ANDREWS (Consultant):I am sure Mr. Dave Bartholic of BAR-CO is pleased

with Mr. Ross’s remark about 0.4 seconds, since theMSCC design is about 0.001 seconds; the preferred timeis between 0.001 and 3, and is feedstock dependent.

TUAN NGUYEN (The M. W. Kellogg Company):The optimum contact time between catalyst and oil in

the riser depends on several factors: the type of feed beingprocessed, the type of catalyst being used, and the desiredproduct slate. Modern FCC units equipped with closedcyclones for rapid catalyst/oil disengaging and state-of-the-art feed injection system for rapid feed atomizationand vaporization allow the use of higher activity catalyst,higher riser outlet temperature, and shorter riser residencetime in order to maximize conversion while minimizingthe over-cracking of gasoline to LPG and dry gas.

At the M. W. Kellogg Technology Development Cen-ter, we have conducted a number of FCC pilot plantexperiments to look at very short contact time cracking.So, we have seen little or no advantage for going to “ultrashort contact time” cracking. High conversion cannot bemaintained in ultra short contact time cracking becausethere is a minimum residence time required for atomizingand vaporizing the feed, diffusion of these high molecularweight feed molecules into the active sites on the catalyst,cracking the feed to product, and diffusion of the hydro-carbon products out of the catalyst.

MARK SCHNAITH (UOP):We need to keep in mind an important principle with

regard to residence time. As you reduce the total systemresidence time in the reactor, you can improve your yieldselectivity dramatically. Of course, what you give up issome conversion of that feedstock. A severity increase isrequired to gain back conversion, and some of the selec-tivity gains can be lost. Although traditional riser systemshave operated in the 2 to 3 second range, the goal of themodern systems today is to reduce that residence or con-tact time without losing a substantial amount of conver-sion.

One such system, the BAR-CO MSCC process, elimi-nates the reactor riser and features an ultra short contacttime while maintaining effective conversion. Low dry gasand good gasoline selectivity have been demonstrated intwo commercial installations. In May 1995, UOP andBAR-CO signed an agreement that gives UOP exclusivelicensing rights for the MSCC technology. In June 1995,UOP licensed a 100 mbpd MSCC unit in the U.S., whichis currently in design and construction.

DELBERT F. TOLEN (Rocky Mountain Salvage & Equipment Co.):I continually hear extremely low numbers for preferred

contact times. As I remember chemical thermodynamics,the reaction rate is proportional to the contact time timesthe temperature, and as 1 see it, you are going to have torun the reactor at a higher temperature than you run theregenerator in order to get the reaction you want.

My observation of a unit with extremely short contacttime was that once they reached a conversion level of about78, very little of the diesel boiling range material in the

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feed was converted. It almost totally goes through uncon-verted. This unit made light cycle oil of 36 cetane number,which says the diesel fuel went through untracked. Almostall of the bottoms was cracked in that short contact unit.It only made 3% slurry with a 1% carbon residue feed.

So it simply says, yes, all the heavy oil can be crackedin a very short contact time. But when you want to cracksomething in a 650°F to 750°F boiling range, you aregoing to have to increase contact time or increase tempera-ture. The unit I am referring to ran at 1025°F reactortemperature. So how high do we have to go to convertdiesel boiling range in a catalytic cracker?

QUESTION 21.If you had to make a choice between installing radialfeed nozzles on the reactor riser or installing modernriser termination devices in the reactor, which wouldyou choose?

VAN IDERSTINE:This is one of those “it depends” responses. It depends

on what you are changing from. In our particular case, wechose to change both feed nozzles and termination devicesat the same time. It would have been nice to change oneand then the other, and then evaluate both of them; butwe thought, to obtain the maximum benefit, we would dothem both at the same time.

The one thing I can say though, is that the risertermination in the reactors is going to be more expensive.In our case, we spent $2.5 million total for both of thechanges, and the riser termination change to the vortexseparator was probably 50% more costly than the feednozzle revamp. Again, you must examine your situation.Ask yourself what your configuration is today, what youwant to change to, and what your process objectives are.Then apply your own economics.

MORGAN:Yes, we recently completed a study to determine what

would give us the best return on our investment, as I amsure everyone else is, we are also very tight on capital. Ouranswer to that question was clearly the feed nozzles giveyou the greatest return on your investment, and we choseto delay doing any work with riser termination devicesuntil a later time.

ROSS:Stone & Webster and other licensors have converted

many axial feed injection systems to radial injection sys-tems with dramatic results. Typically, the dry gas reducesby 20% relative, the gasoline increases by about 5% abso-lute or more, and the coke selectivity is improved, allowingeven further yield gains. Improvements when changingfrom one radial feed injection system to another are

roughly half of the above, but typically have a projectpayback measured in months.

When differentiating between feed injection and risertermination the distinction between the two must beappreciated. Feed injection creates the yield pattern thatriser termination seeks to maintain. Once one has opti-mized the feed injection system, the focus should be risertermination as there is no point in preserving an inferioryield.

SHEN:I agree with all the panelists’ comments that, all other

things being equal, we would choose the radial feed noz-zles over riser termination devices. When I asked thisquestion to one of our process engineers who holds tworiser termination device design patents, he selected thefeed nozzle over the riser termination device.

HANSEN:Valero chose to install both improved feed nozzles and

close coupled cyclones in the unit. The improved feednozzles were installed in 1989, and a close coupled cyclonesystem was installed in 1994. Installation of the new feednozzles did result in improved yields, but we are not sureif improved coke make was fully realized. Installation ofthe close coupled cyclone system resulted in reduced drygas, coke, and diolefin production. It is difficult to quan-tify the relative economics of these two items as other unitchanges impacted unit yield patterns, feed rate and feedcomposition, were made at the same time.

KELLER:Ideally we would like to install both upgrades to our

unit. If we had to choose one step first, we would selectthe high pressure radial feed nozzles on the reactor riserover a modern riser termination. The feed nozzles are aquicker, lower cost upgrade to the unit. A new feed systemwould cost on the order of $l.5 million and would providebetter selectivity and an estimated 4% increase in conver-sion. A “minimum residence time” modern riser termina-tion system would cost several times more and would haveto be part of a total unit upgrade to be able to handle thechanges. The riser termination would increase conversionby minimizing coke, which would allow more catalystcirculation. If we installed the modern riser terminationwithout other modifications, we would be limited oncatalyst circulation and minimum coke make.

PETER G. ANDREWS (Consultant):I am glad to hear the panel agrees with me. There is no

doubt in my mind that if you must take one or the other,you take feed nozzles. They are faster and cheaper, andradial nozzles can give you excellent results. We had theluxury of only installing nozzles when we were looking atboth nozzles and riser termination. But we just put in the

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nozzles, and the subsequent yields destroyed any furtherpayout for installing the extensive, expensive riser termi-nation design(s). It is good, radial feed nozzles all the way.

DELBERT F. TOLEN (Rocky Mountain Salvage & Equip.):I agree that feed nozzles are far more important than

termination devices. The speed of mixing the oil andcatalyst is most important.

IAN JACKSON (BP Oil Company):I totally agree with everyone so far regarding installing

good atomizing feed nozzles as a priority before changingthe riser termination device (RTD). If you change out aRTD for a short contact time (SCT) RTD, without firstmodifying the feed nozzles (e.g., keep old-style showerhead nozzles or open pipe systems), you will coke thereactor transfer line. Two of our competitors’ refineries inEurope installed direct coupled cyclones (DCC) and kepttheir existing shower head feed nozzles. The refineries hadto shut down within the year due to coke buildup in thereactor transfer line (RTL). They were basically not vapor-izing and cracking the feedstock in the riser, thus condens-ing the reaction vapors in the RTL as coke precursorliquid. This did not occur prior to SCT RTD installation,as the reactor vapors leaving the riser spent a long time inthe reactor disengaging vessel where they cracked further.Thus, only stable reaction vapors passed into the RTL.

PHILLIP NICCUM (The M. W. Kellogg Company):Going from an axial feed injection system to a radial

feed injection system will pay out in almost every case. Thepayout for a closed cyclone system or a dusted cyclonesystem that eliminates vapor residence time in the disen-gager is a much more variable calculation. There are severalthings that come into play. For a unit with a very largedisengager, the payout is going to be higher. For a unitwhere the product slate and the capacity allow operationat very high temperatures, the payout is going to be higherfor a closed cyclone system. And also, if you are startingwith an inertial separator device, rather than a moreefficient riser cyclone, the payout is going to be higher. Sothe payout for the closed cyclone system is more variable.

REZA SADEGHBEIGI (RMS Engineering, Inc.):Any FCC mechanical upgrade should start by installing

a set of “high-efficiency” feed nozzles as well as “uniform”delivery of a regenerated catalyst. The two main advan-tages of radial versus axial feed injection are improvedcatalyst hydrodynamic (uniform catalyst density) and pro-tection against reversal of feed into the regenerator.

QUESTION 22.What FCC operational changes can be made to reducethe sulfur of the FCC gasoline with minimum impacton octane?

DEADY:Gasoline sulfur can be decreased by the following op-

erational changes: decreasing reactor temperature, de-creasing catalyst-to-oil ratio, decreasing gasoline endpoint, and increasing naphtha recycle. The most commonoption that refiners appear to be doing today is loweringthe gasoline cut point. For example, from some ofour pilotplant data, we see that lowering the cut point from a T90of about 380°F to about 300°F reduces the gasoline sulfurby about 40%, and also reduces the gasoline volume byabout 15 vol%.

The impact on RON is variable and will depend on thespecific boiling point curve of the gasoline, i.e., the shapeof the gasoline boiling point curve for each refiner. Sinceeach refiner has a unique gasoline boiling point curve, theonly way to quantify the octane change is to look at theactual distillation.

Also related to changing cut point, refiners shouldmake sure that their column operation is well controlledso that there is good control in the gasoline end point. Ifa refiner has a sloppy cut or the end point fluctuates, thegasoline sulfur can also fluctuate greatly and changing thecut point might not have as great an effect on reducing thegasoline sulfur.

Regarding the other variables, we have laboratory datathat show that decreasing reactor temperature by about40°F decreases the sulfur in gasoline by about 7% anddecreases octane about 1.5 numbers. Decreasing the cata-lyst-to-oil ratio will also decrease the gasoline sulfur andRON. These changes were reported in the 1993 NPRApaper number AM-93-55. Neither of these, lowering re-actor temperature or changing catalyst-to-oil ratio, is avery satisfactory way of reducing sulfur while maintaininggasoline octanes.

Another option that was reported in both the 1993 and1994 NPRA transcripts is to recycle naphtha to the riserwhich can result in about a 20% reduction in gasolinesulfur with up to one number increase in RON. In the1994 transcripts feed hydrotreating and product hydro-treating were also discussed as options.

EMANUEL:We feel, of course, the cheapest way to get out of this

without spending a lot of capital is to change the cut pointon the heavy FCC naphtha. In our particular stream, theheaviest 10% of the heavy FCC naphtha contains about30% of the sulfur in the whole stream. Right now we aremoving that cut point around as the conventional gasolinelimits dictate.

SOLIS:The sulfur distribution in the products is largely con-

trolled by sulfur in the feed. At a given conversion level,assuming maximum gasoline product is desired, there isnot much control over the gasoline sulfur. If there is room

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to reduce the gasoline boiling range, a significant amountof sulfur can be moved into the LCO product. Typicallyabout 50% of the sulfur in gasoline boils between 380°Fand 430°F This can be an octane rich portion of thegasoline, however, and eliminating it from the gasolineproduct can have an impact on octane. Catalyst manufac-turers have tested formulations that will reduce the sulfurin gasoline. This work is still in its early days, but theprinciple has been demonstrated in commercial trials.This route appears to have more sulfur-reducing potentialfor the front end of the gasoline, whereas the end pointdistillation change reduces the back end sulfur. Finally,there have been announced several processes for down-stream of the FCC, which will remove sulfur from thegasoline product with minimum reduction of octane.

QUESTION 23.

In fluid catalytic cracking units practicing riser lift gastechnology, what is the preferred operating procedurewhen lower quality feed causes an increase in theyield of fight gases? In units with lift gas, processinghigh metals feedstocks, does the use of a metalspassivation agent provide additional benefits?

DEADY:

I am only going to address the second part of thisquestion. I looked at our ECAT database for the secondquarter of 1995 to see which refiners who use lift gas werealso using antimony in their operation, and I only foundone refiner. They reported their experience in the 1994transcript. In it, they reported antimony-to-nickel ratioson the order of 0.15 to 0.2, compared to the more typicalFCC operations on the order of 0.25 to 0.3 antimony-to-nickel. The implication is that the lift gas is doing someof the passivation, and the antimony is doing additionalpassivation. This has not been quantified, but I suspectthat the effects are somewhat additive.

Another refiner who uses lift gases is also usingacatalystthat contains a nickel passivating matrix. Their hydrogendropped when they switched from their previous catalystto their current catalyst, indicating that the use of a metalspassivation matrix also provides benefits over and abovethose obtained from lift gas.

EMANUEL:

We currently use lift gas in our UOP FCCU. We donot use antimony. During situations of increased yield oflight gases to the point where we are wet gas compressorlimited, we have reduced the lift gas to the riser. In somecases in the summertime, we have removed lift gas com-pletely to try to maintain FCC feed rates. We typically runwith a nickel plus vanadium in the neighborhood of 2000ppm to 2500 ppm.

PAUL FEARNSIDE (Nalco/Exxon Energy Chemical Company):It has been our experience that the benefits of metals

passivation technology on units with lift gas are 50% ofthe benefits you would receive on the units that do nothave the lift gas.

QUESTION 24.What water rate is required for adequate washing ofFCC overhead systems as well as gas plant systems?What quality of water is typically used? Can the ratebe reduced when FCC feedstocks are hydrotreated?

POTSCAVAGE:We are aware of two rules of thumb concerning how

much washwater should be used on an FCCU. One says2 gpm/l000 bbl of feed is adequate. The other one says 1gpm/1000 bbl of feed is adequate. Having said that, I haveto tell you that we are not comfortable with either one ofthem. These obviously are predicated on the fact that thereare certain operating conditions on a unit, but not all unitsoperate under the same conditions. We prefer to use aSimulation Sciences program and model the overhead andcompressor after-coolers to determine how much water isactually required to do what it is supposed to do. If toomuch water is added, we can create a situation where therewill be serious erosion/corrosion; that actually would be aworse problem to deal with than if we did not have a waterwash in the system. Conversely, if too little water is addedin the overhead, since normally main fractionator over-head water is recirculated in this situation, all the waterflashes and whatever solids are carried back with the waterare going to stay in the system where the water was injectedand flashed. That also will cause an extremely seriouscorrosive environment.

The flow of the washwater is extremely important.People have used two different schemes: one is countercurrent, the other co-current. Counter current typicallyhas achieved mixed results. We suggest that people go withthe co-current flow whereby the flow goes from mainfractionator overhead, to first stage after cooler, to secondstage after cooler.

The next part of the question deals with washwatersources. As I said earlier, the most commonly used sourceis main fractionator overhead water. We have also seenstripped sour water used successfully as a washwater.Where people have extremely high cyanide levels or aserious problem with hydrogen blistering, they have actu-ally gone to the extent of using boiler feedwater.

On the last part of the question, our feeling is that evenif the feed is hydrotreated, it is not appropriate to reducethe amount of washwater that is used on the overhead. Ifthe calculation was done correctly, and keeping in mindthat you are trying to both dilute cyanides and removesome of the solids from the system, then the same amountof washwater is required.

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SHEN: JAMES D. WEITH (Unocal Corporation):

I agree with most of the comments Mr. Potscavagemade, and I want to emphasize that we agree co-currentis better than counter current in the flow arrangement.

On the topic of the water quality, I have one comment.When you inject polysulfide material into the water forcyanide control, it is important that the water have a highconductivity level to ensure the polysulfides will suspendin the washwater. Because of this, we feel that the strippedsour water is a very good resource. Steam condensate is notonly more expensive, it may also be low in conductivity.

Pertaining to the third part of the question, we justcommissioned a high pressure hydrotreater ahead of theFCC. We did not change our washwater rate, but that didallow us to trim back considerably on the polysulfide use.We monitor with the spot test for cyanides using iodineand starch solutions, making sure that it stays negative.

PAUL FEARNSIDE (Nalco/Exxon Energy Chemical Company):

An article published by NACE can be used as goodreference: NACE Paper, No. 206, “Carbonate Stress Cor-rosion Cracking of Carbon Steel in Refinery FCC MainFractionator Overheat Systems,” April 1990.

We are finding it is not so much a question of howmuch washwater, but how that washwater is contactedagainst the flowing gas stream. If you do not have theproper nozzle technology in place and do not have ade-quate scrubbing/contact between the water and the gasstream, you are just not going to do the proper job,regardless of the washwater flow rate.

ROSS:This issue was discussed at length in several recent

Q&AS and by Mr. Potscavage. The preferred injectionmeans has been shown to be from low pressure to highpressure or co-current with the process flow to take advan-tage of the higher contaminant solubilities at higher pres-sures. Although a total washwater rate of about 1 gpm to2 gpm/l000 bbl/d of feed is typically reported, themakeup is often unclear — fresh or recycle sour water. Themakeup of this recycle water depends on the amount of“fresh” water entering the overhead system as reactorsteam (dispersion steam, stripping steam, etc.). If the FCCis a resid unit, the total reaction system steam rate canapproach the total 1 gpm to 2 gpm, thereby allowing foronly intermittent or infrequent use of additional freshwater injection. For a gas oil cracker, over half of the totalwater “recycled” may be fresh, i.e., not coming from thereactor.

QUESTION 25.What are maximum attainable catalyst flux rates forstandpipes and spent catalyst strippers?

SOLIS:

Approximately 0.5 gpm to 1.0 gpm of sour water per1000 bbl/d of feed is typically recycled to the overhead lineon a continuous, but sometimes intermittent, basis. Asnoted, care must be taken to simulate the system to ensurethat there will be liquid to wash the tubes and that not allof the water vaporizes upon injection. At the WGC inter-stage cooler, 1 gpm to 2 gpm of sour water is injected per1000 bbl/d of feed and collected for injection into thehigh- pressure receiver where it is collected and directedto the sour water stripper.

As unit capacities are pushed to the limit, usually airblower or wet gas compressor limitations bottleneck theunit, not catalyst circulation limitations. Most UOP FCCunits run to other limits before catalyst circulation limitsare reached. The ultimate standpipe circulation limit willdepend on catalyst entry condition and physical proper-ties, standpipe angle, configuration, and length. Manyunits run up to 900,000 1b/sq ft/hr with some approachingl,000,000 1b/sq ft/hr. The reactor stripper will circulateeverything the standpipe can handle since it is larger, butstripping performance will deteriorate as flux rates overdesign are used. The usual remedy for an over-fluxedstripper is to increase the stripping steam rate to try toimprove its performance. Eventually, the combination ofthe high catalyst flux and high steam rate can result in acatalyst flow stoppage in the stripper.

ROSS:

KELLER:We follow UOP’s recommendation of 2 gpm/ 1000 bbl

of feedstock. We use cold condensate which also has acorrosion inhibitor injected to lay down a corrosion bar-rier. The cold condensate is monitored for excessive oxy-gen content, less than 100 ppb. Cyanide production is afunction of Total N in the feed, nitrogen type, and reactoroperating conditions.

Standpipe velocity and flux rate limits are somewhatsubjective. In a long, well aerated, vertical standpipe witha good catalyst hopper design, a flux rate of 275 1b/sec/sqft to 300 1b/sec/sq ft has been demonstrated. Normally adesign range of about 100 1b/sec/sq ft to 200 1b/sec/sq fiis used with an upper limit of about 250 1b/sec/sq ft forrevamps. In some bend, slanted, or U-bend configura-tions, the higher flux and velocity are actually preferred toreduce the time for deaeration in the nonvertical sectionof the standpipe.

The more interesting question is what are the turndownconcerns? A flux range of about 50 1b/sec/sq ft to 1001b/sec/sq ft, depending on the catalyst properties, is adifficult transition zone where bubbles in the standpipetend to stagnate — the catalyst velocity equals the bubble

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rise velocity resulting in stagnant bubbles. This is a diffi-cult region and is observed during each start-up where thebest method is to push through this zone as quickly aspossible. Below this flux, the flow becomes extremelystable again as the flow is now dense or pack flow. The onlyproblem is that very large line sizes must be used if onedesigns at this flux rate.

As for catalyst strippers, typical flux rates of 6001b/min/sq ft to 1200 1b/min/sq ft have demonstrated goodperformance. The flux rate indirectly reflects stripper resi-dence time and vapor-catalyst relative velocity. A flux ashigh as 1500 1b/min/sq ft has been encountered, but theperformance was fairly poor as measured by high hydrogenin coke values. A theoretical choke condition can becalculated at fluxes above about 1200 1b/min/sq ft depend-ing on the baffle spacing.

PHILLIP NICCUM (The M. W. Kellogg Company):I would like to discuss some experiences related to

annular strippers, which typically have a riser running upthrough the center of the stripper. Experience has shown

that often in these strippers the mass flux is in the neigh-borhood of 1200 lb of catalyst per foot squared perminute, and there is excessive entrainment of hydrocar-bons to the regenerator or, if you will, a poor strippingefficiency. The curves on the graph below show, on the left,the stripper efficiency versus the mass flux rate. At a certainpoint the efficiency falls. The curve on the right is thedensity curve, and it also falls at a high mass flux rate andis falling because of the entrainment of the gas down thestripper.

Mobil has developed a proprietary baffle design that hasbeen demonstrated to extend the efficient range of anannular stripper. This new baffle design is being offeredby Kellogg, and it is commercially being demonstrated inthree FCC units. In one case where it was installed, thecommercial unit saw a 40°F decrease in regenerator tem-perature and enjoyed the result of increased catalyst circu-lation rate and conversion. In another case, detailedsurveys around the stripper showed that the percentage ofthe coke that was entrained hydrocarbons dropped from15% before the revamp to 5% after the revamp.

Effect of Mass Flux on Stripper Efficiency

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QUESTION 26. HANSEN:What are maximum attainable superficial velocitiesin a bubbling bed regenerator as they relate to cycloneperformance?

ROSS:As the velocity in a bubbling bed increases beyond

about 2 fps to 2.5 fps, the bed becomes turbulent and theterm “bubbling” does not technically apply. However, theentrainment rate of catalyst to the cyclones clearly in-creases dramatically and almost exponentially with veloc-ity such that losses will increase even though the cycloneefficiency will increase with higher loadings. Cyclones canbe made to handle very high catalyst loadings, howeverthe diplegs must be long enough to properly pressurebalance and large enough in diameter to handle the flow.

Valero has implemented advanced controls on theheavy oil cracker, which include pressure balance andregenerator pressure control. There have been no problemswith the expander caused by implementation of thesecontrols. System problems that have been encounteredrelate to interactions between the various pressure control-lers on the combustion air blower, regenerator, and ex-pander. One should examine interactions specific to one’sunit when implementing advanced controls.

KELLER:Our FCC advanced control scheme has worked very

well with no real problems to the unit operation or theexpander. However, our multivariable advanced control-ler does not directly control the expander.

Most refiners tend to limit the operation of their regen-erators to about 3.5 fps to maintain catalyst retention withlosses near original design. In one refinery we are aware of,the regenerator velocity is about 4 fps with catalyst lossesroughly twice that expected in a new unit designed forabout 2.5 fps. In another unit, 4.25 fps superficial velocityis claimed with no added catalyst losses. For reference, ageneral rule of thumb I use is 2 1b/hr loss per 1000 bbl/dfor a typical high-efficiency, two stage cyclone system in amoderate pressure regenerator operating at about 2.5 fpsto 3 fps. (Losses due to fresh catalyst addition must beadded to this figure.)

Our expander inlet and bypass control valves are con-trolled by the reactor/regenerator differential pressure(hard-wired) controller. Its set point can be changed by asingle output (software) controller to minimize the ex-pander bypass control valve opening. The hard-wiredcontroller is allowed to range from +5 psi to -5 psi reac-tor-regenerator differential pressure; the advanced con-troller is restricted to +2 psi to 0 psi reactor-regeneratordifferential pressure. The regenerated catalyst slide valvedifferential pressure is also programmed to restrict theadvanced controller during unusual conditions; but it isnot the controlling signal during normal operation.

JOHNS:Practical cyclone loadings of 2.5 fps to 3 fps are a good

design range. Lower velocities will shift the CO combus-tion and heat to the regenerator bed and away from thecyclones and will reduce afterburn. This requires less steamin the cyclone area and generally will provide smootherregenerator burn operations.

Our multivariable advanced FCC controller directlysets the suction pressure to the wet gas compressor, whichindirectly determines the reactor, regenerator, and ex-pander pressure.

QUESTION 28.Can any of the panelists suggest a method that worksfor measuring cyanide? What levels of cyanide havebeen found to cause problems?

QUESTION 27. POTSCAVAGE:What problems have been experienced with flue gasexpander operations when implementing FCC ad-vanced controls?

FRONDORF:Part of the optimization program involves lowering

regenerator pressure by partially bypassing flue gas aroundthe expander. There are several points that should beconsidered. First, the power recovery economics should beincluded in theoptimization software. Second, if you haveconstraints on downstream equipment from the expander,particularly temperature constraints, they also need to beconsidered in the optimization software. We have installedand are operating our advanced control/optimization con-trols on our Corpus Chrisri, Texas refinery catalyticcracker without problems in the expander section.

We are aware of an extensive distillation method thatis described in “Standard Methods of Water and WasteWater Analysis.” It gives very good results. It will give youtotal cyanide by proper treating of the sample, or anexisting cyanide by running the sample as is. However, itis a very tedious test. The results obtained are very accu-rate, but our feeling is that they are of academic valuebecause the absolute cyanide value in the overhead is notnecessarily indicative of whether there are going to beproblems or not.

We prefer to use what is called a spot or Prussian bluetest. It is a much simpler test to run and easy for operatorsto do. All one has to do is take a piece of filter paper, poursome overhead water on it, and put a couple drops of ferricchloride onto the filter paper. If the filter paper turns blue,there is a ferrocyanide complex. This shows that the

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cyanide is reacting with the metal in the overhead and isa clear indication that a better corrosion-control programis needed. As I said, this is a very quick and easy test forthe operators. So, you can generate more data and have amuch better understanding of what is going on in the unit.

KELLER:EPA method 335 is a reliable method used by Ultramar

and most regulatory agencies. We charge only hydro-treated feed (less than 3000 ppm Total N) to our FCCunit. Our free cyanides vary from 1 wppm to 4 wppm inthe washwater effluent at 2 gpm per MB/D of FCC feed.We have seen hydrogen activity jump above 3 psi per dayfrom our probes when the free cyanides jump above 10wppm. We replaced our primary absorber from hydrogenblistering after 7 years of operation without always pro-viding 2 gpm of washwater per MB/D of FCC feed.However, no other vessels showed any damage. TheASTM grade 516 - 70 carbon steel plate used in ouroriginal primary absorber exceeded the specification forinclusions caused by impurities.

ROSS:The ASTM methods for measuring cyanides in waste

water are D2036 and D4282. Absolute control of thecyanide level is difficult without frequent analyses, how-ever some operators have noted a simple color check of thewashwater where a yellowish tint indicates adequate poly-sulfide additive to control corrosion, and a bluish tintindicates ferrocyanides and trouble. Although the actuallevels of cyanide that cause problems are unclear, manycontrol to about 20 ppm to 30 ppm in the washwater.

REZA SADEGHBEIGI (RMS Engineering, Inc.):How the water sample is collected is also important in

obtaining accurate cyanide results. The sample should becollected to ensure no air is allowed into the sample bottle.

JAMES D. WEITH (Unocal Corporation):Mr. Keller mentioned something about hydrogen

probes. We put hydrogen probes on our FCCU in Wil-mington, California in 1992. We have yet to see anypressure buildup in them. I am not satisfied with the waythey are put together. They consist of a pad that is weldedon the vessel. Then a top assembly that consists of thepressure gauge and a thermometer that snaps on throughan O-ring. I think that if the hydrogen were tenaciousenough to get through a steel shell, it could probably passthat O-ring as well.

Since then, a Canadian company has come up with adesign called Beta Foil that looks much better to me. Ithas several salient features that I like. It covers severalsquare feet. It has a vacuum-type attachment, and youmonitor for a vacuum being broken rather than looking

for a pressure increase. It just seems to be much morepractical.

QUESTION 29.What markets exist for FCC slurry oil, and what aretypical specifications?

ABRAHAMS:We have been in two markets for FCC slurry oil. One

market is heavy cutter for fuel oil, and typical specifica-tions are: viscosity 250 centistoke, sulfur 6.0 wt%, flash140°F, BS&W 1%, ash 0.1 wt%, pour 60°F, vanadium300 ppm, aluminum 200 ppm, and SFH 0.15.

Another market is carbon black feedstock. Typicalspecifications are: API of 0, sulfur 3%, viscosity @ 210°Fof 80, flash 150°F, ash 0.05%, BS&W 0.5%, pour 60°F,potassium 2 ppm, sodium 10 ppm, BMCI 126, pentaneinsolubles 20%, and asphaltenes 6%. The consensus in theearlier panelists’ discussions was that whatever you have,if you can get into the market, the specifications can bedifferent.

ROSS:Slurry oil is typically blended into the fuel oil pool or

disposed of in a coker. Occasionally the quality of the feedand HCO or bottoms oil are in the narrow range requiredfor carbon black or needle coke applications and thebottoms oil is then a high-value component. The feed-stock must be very aromatic and the cracker operationcarefully controlled with a bottoms cracking catalyst toproduce this material. Filtration may be required to meetsolids content specifications.

Increasingly tighter specifications are placed on fueloils and now alumina content must be controlled to avoidengine fouling. A limitation of 200 ppm alumina typi-cally sets the maximum catalyst content at about 1000ppm. Power stations can accept higher levels with atypical sulfur specification of 2%. Carbon black andneedle coke are attractive markets if the stringent productspecifications of density, viscosity, and boiling range canbe met. For carbon black a 500 ppm ash limit and 2% Slimit are imposed. Other outlets include asphalt or cokerfeed.

KELLER:Almost all West Coast FCC slurry oil goes into the

carbon black market or 0.5% sulfur Fuel Oil market whichis exported to China or Korea. A small amount is sold intothe domestic industrial market.

Typical specifications range as follows:

Gravity, °AP1 less than 1 to 8

Visc, cst @ 122°F 80 to 180

Sulfur, wt % 0.2 to 1.1

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JAMES D. WEITH (Unocal Corporation): SOLIS:We feed our slurry to our coker to prevent it from

making shot coke. I have co caution, however, and this hasbeen in NPRA QSLA transcripts before, to make sure notto set up a refractory recycle if coker gas oils are chargedto the FCCU. We counsel about this, but the cokersupervisors keep forgetting, and we have to keep remind-ing them to keep their coke drum temperature up. As Iunderstand it, the lower the slurry °API the better it is forthe coker. The °API of our slurry is typically around zero.

It is quite clear that the solvent deasphalted oil (DAO)properties affect the FCC yields. We have observed thatthe catalytic cracking selectivities may correlate with theDAO carbon content. When this value is relatively low(MCRT=1.7 wt%), the conversion, gasoline, and LPGyields are higher than that for a typical VGO. The higherparaffin content in the DAO (versus VGO) explains theseresults. However, if the DAO has a large carbon content(MCRT=2.8 wt%), conversion, gasoline, and gas yieldsare lower for the same coke production.

QUESTION 30.When processing solvent deasphalted oil in an FCCU,how do incremental yields and performance correlateto solvent deasphalted oil properties?

The following data are provided as an example of theprevious statements.

DEADY:The most important parameter is Conradson carbon

residue (CCR). Our rule of thumb for the effect of CCRon FCC yields is that a 1 wt% increase in CCR willdecrease conversion by approximately 2 LV% and willincrease regenerator temperature approximately 50°F. Thesecond parameter is aromatic carbon CA content, meas-ured by the n-d-M method. An ~ 1 wt% change in CA

affects conversion by ~ 2 vol% and regenerator tempera-ture by -20°F. The next important parameter is nitrogen,especially basic nitrogen, due to the immediate effect onconversion and yield selectivities. Approximately 500 ppmnitrogen affects conversion by -3.75 vol% and regeneratortemperature by ~ 10°F. The final parameter is contaminantmetals, especially Ni and V. A change of ~ 330 ppmequivalent Ni (Ni + 0.25V) affects conversion by ~ 1 vol%and regenerator temperature by ~ 20°F. A refiner mightalso want to look at sulfur levels, due to environmentalconstraints, in the flue gas and products.

Aniline point, °C

Density, Kg/m3 @ 15°C

MCRT, wt %

Viscosity, cst @ 100°C

MAT Activity, %

Gasoline Yield, %

Total Gas Yield, %

LPG Yield, %

Coke Yield, %

H. DAVID SLOAN (The M. W. Kellogg Technology Company):

ROSS:As with the previous question on deasphalted oil

(DAO) quality monitoring, the quality of DAO is reallyon a sliding scale between VGO and VR, depending onthe depth of deasphalting. The FCC operation thereforewill also be variable between clean gas oil and contami-nant-laden resid performance with all of the usual warn-ings about metals contaminants.

In general, however, the DAOs we have encounteredhave conversion precursors or gasoline precursors 30% to50% lower than VGO of the same source. The poly-aro-matics are generally higher, resulting in more catalytic cokefor a given conversion level, and the contaminant coke isalso a factor. The feed-derived coke due co contaminantsas measured by Conradson carbon tests may well be lessthan equivalent asphaltene rich resids; however, precisecommercial measurements are difficult as the amount ofDAO in the feed blend is typically less than 20%.

This quest-ion is supplementary to Question 11 fromthe General Processing Session. I must admit when I firstsaw the question, I hoped that by the time of this meetingwe would have some pilot plant data co share on thecharacterization of deasphalted oil as FCC feed. Giventhat there is very little in the literature on the subject andspecific results of our work are not yet ready for publica-tion, I can only offer the following remarks. We heardseveral rules of thumb this morning on the effect of FCCproperties on conversion. Reports from our ROSE licen-sees indicate that as an incremental FCC feed, Conradsoncarbon in the deasphalted oil may behave in the FCC as agas oil with Conradson carbon residue of the square rootof the DAO Conradson carbon. For example, a fourConradson carbon deasphalted oil will make coke morelike a two Conradson carbon heavy gas oil. Other yieldsshould follow correlations for heavy gas oils since thedeasphalted oil is a product of physical separation and nota cracked material.

RICHARD STREET (Criterion Catalyst Company):We see a trend in refiners charging heavier fractions,

including deasphalted oil (DAO), to FCC feed hydrotreat-ing units. We have designed catalyst systems chat are inFCC feed hydrotreating units which process as much as40% deasphalted oil. These catalyst systems provide amuch higher stability in overall activity than a conventional

VGO DAO-1 DAO-2

92.4 114.8 112.4

905.9 912.5 921.3

0.24 1.70 2.80

8.93 46.1 59.4

66 74 63

44.5 48.5 43.5

17.0 21.0 15.0

15.7 18.8 13.6

4.5 4.5 4.5

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FCC feed hydrotreating catalyst system processingdeasphalted oil. The net effect has been achieving therefiners’ FCC feed specifications and several of the per-formance targets at economically attractive FCC feed hy-drotreating cycle lives.

QUESTI0N 31.What are the incremental yields and performancechanges expected from the FCCU when processingvisbreaker gas oil?

ROSS:One refiner reports the following yield shift when

replacing 15% of a VGO feed with visbreaker gas oil:

Gas+ 1.0 wt %

LPG -2.7

Gasoline (190°C) -4 .4

LCO +4.3

DO +1.6

Coke +0.2

In general terms this is consistent with a lower feedstockquality similar to DAO where one might expect about halfof the yield potential of virgin gas oil. (All of the usualconditional statements regarding crude type and process-ing severity apply.)

DEADY:In general, the visbreaker gas oils are fairly aromatic and

refractory, and tend to make more coke and gas thanconventional FCC VGO feeds, i.e., a lot like coker gas oil.I have data from a couple of MAT studies comparing VG0feed and visbreaker feed by themselves, and then anotherstudy that compares the VGO feed with 5% and 10%blends of the visbreaker feed.

QUESTION 32.What is the industry experience when processing usedtube oil in the FCCU? What pretreatment is recom-mended for this stream?

DEADY:To answer the first part of this question on industry

experience when processing used lube oil in the FCC, wehave actually observed a number of refiners in the past yearthat have operated this way. Generally, lube oil stockscontain fairly high amounts of FCC catalyst contami-nants. Examples of this are sodium, magnesium, potas-sium, and vanadium. All those tend to deactivate thecracking catalyst. Additional contaminants (for example,copper, zinc, manganese, and vanadium) will producehigher coke and gas. In addition, the additive solventpackage can contain halogenated hydrocarbons, whichcan act to redisperse and activate nickel that is already on

the ECAT, causing additional coke and gas. Finally, lubestocks can be either very paraffinic or very aromatic.Obviously, if there is a choice, you would rather processthe paraffinic ones. But I found that most refiners do nothave a choice. In fact, sometimes they do not even realizethat they are running it in the FCCU until they see adecrease in conversion and an increase in trace metalcontaminants on their ECAT.

When processing lube oils, FCC operators generallysee a dramatic decrease in their ECAT activity and unitconversion, and that is probably their first clue thatsomething is going on. When we look at our ECATdatabase, we typically see an increase in calcium and/orzinc that tracks identically with the loss in conversion.The loss of conversion ranges from about 0.2 of a mi-croactivity number to 0.6 of a microactivity number forevery 100 ppm of calcium oxide increase. And for zincwe see a range anywhere from 0.9 of a microactivitynumber to about 2 microactivity numbers for every 100ppm of zinc oxide. These levels are directly associatedwith lube oils. The highest calcium numbers that we haveseen are about 6000 ppm. The highest zinc numbers thatwe have seen are about 3300 ppm, indicating significantamounts of lube oil being processed.

Finally, we observed something this year that wasinteresting. It appears that one mechanism by which usedlube oil deactivates catalysts is by pore plugging andshutting off the active sites. One refiner saw a 4 numberdrop in the microactivity and also noticed a loss of thewater pore volume that we report on their ECAT sheet.However, the surface area that is measured by nitrogenmethod was unaffected. We thought that was interestingand took a closer look. When we measured the porevolume with mercury, which looks in more detail at thelarger pores, we saw that the larger pores in the 700 to2000 A range were reduced and were actually shifteddown to the 100 to 700 A range, indicating plugging ofthe larger pores.

SHEN:Tests and operating data show that the used lube oils

convert very well at the FCCU. The high paraffinicmolecules crack easily. However, because the amount oflube oil fed into the FCCU was relatively small, the datadid not show a noticeable impact on gasoline octane andolefin yield.

In general, used lube oils tend to contain plenty ofalkali metals (calcium, magnesium, zinc, etc.), and thesemetals can rapidly deactivate FCC catalyst if any signifi-cant volume is processed. A typical approach people useis to process this stream through a rerun fractionationtower (or vacuum tower). The metals, as a general rule,will have the tendency to stick with higher boiling rangemolecules. The distillate from the rerun tower can eitherfeed to the FCC directly, or, if you have spare capacity in

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the FCC feed hydrotreater, you can send it there toremove these metals. The fractionation bottoms can besent to the coker.

SOLIS:We have never directly processed used lube oil in our

units. But, upon request from the Madrid EnvironmentalAuthorities, we have made a trial with a distillate cut(350°C to 550°C) from a used oil collecting factory. Themetals content in this cut were as follows:

Fe 137 ppm Cr not detected

V <10 ppb Zn 300 ppb

Ni not detected Al 38 ppbCu <20 ppb Pb not detected

Na 20 ppb

When we compared the catalytic cracking of this cutto that of a typical VGO, we observed the followingdifferences:

Conversion, %

Total Gas, %

Gasoline, %

LCO, %

HCO, %

Coke

VGO 350°C to 550°CUsed Oil Cut

62 81

43 58

14 20

26 15

17 7

5 3

DELBERT F. TOLEN (Rocky Mountain Salvage & Equipment):

If you would like to come out, ninety miles west of meis the smallest commercial FCCU in the world, 500 bbl/d,and it runs on nothing but used lube oils.

Environmental Control

QUESTION 33.What levels of particulate removal from FCC flue gascan be achieved by the various technologies?

ROSS:The types of commercially proven particulate removal

technology available fall into three categories — cyclonic,wet scrubbing, and electrostatic capture. Cyclonic separa-tion systems, which range from multiple moderately sizedcyclones housed in a separate vessel to many very smallhorizontal cans or vertical swirl tubes in a separate vessel,can achieve particulate emissions reduction to about 75mg to 150 mg/Nm3 on a consistent basis. The newer thirdstage cyclones with many small cyclones fitted inside avessel claim efficiencies approaching 50 mg/Nm3 in thedischarge. However, Stone &Webster would be reluctant

to recommend such a system when regulatory limits areless than 75 mg/Nm3

. The varying influence of freshcatalyst additions and normal catalyst attrition make reli-ance on this type of system for very low discharge levelsrisky.

When present or future flue gas treatment for SOx

and/or NOx is required, a wet scrubber system similar tothe Belco or Exxon scrubber can be used. Due to therequirement to provide efficient contact between a finemist of water and flue gas, catalyst capture automaticallyresults. Effluent concentrations of 50 mg/Nm3 or less arecommon.

When very strict regulations are in force, an electro-static precipitator is the clear choice. Effluent levels as lowas 10 mg/Nm3 have been achieved — at a price — withtypical levels well below 50 mg/Nm3.

Other systems, such as sintered metal or ceramic filters,are still in the proving stages but potentially offer ex-tremely low effluent levels.

Another consideration when looking at particulatecontrol is the level and control of condensibles which aretypically included in particulate tests. The SO3 in the fluegas stack is a prime example. Sulfur transfer agents in theregenerator offer a simple means of controlling this “addi-tive” particulate matter and can make the difference be-tween say 120 mg/Nm3 and 100 mg/Nm3, which for somerefiners, has been the difference between compliance andnon-compliance in the past.

As a word of caution, when the environmental limitsare below about 200 mg/Nm3, cyclones in the regeneratorwill not meet this specification by themselves. The designof these cyclones should not be pushed in an attempt tomeet the limits; rather the appropriate downstream unitsshould be designed to handle normal regenerator emis-sions. Do not jeopardize the regenerator cyclone design bypushing the design limits in a futile attempt to meetemission limits.

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ABRAHAMS:At one of our plants, we had one of those million dollar

“Oh-shoot” projects. We installed a multi-cyclone separa-tor downstream of our CO boiler in an attempt to influ-ence our opacity without having to go to the highermetallurgies required upstream of the CO boiler where itis hotter. The device was successful in removing mass fromthe stack up to about a ton and a half per day, but it hadlittle impact on opacity because it was ineffective in mov-ing particulates below 10 microns. The trial was madebecause of some success that had been reported in reducingopacity in the power industry with this kind of device.

HANSEN:Valero installed a Belco EDV Scrubber on the HOC

unit flue gas in October 1994. The scrubber easily makesthe permit maximum allowable particulate level of 0.57 lbof particulates per 1000 lb coke burned. The EDV scrub-ber filtering modules employ condensation of water vaporonto submicron particles to increase their mass. The en-larged particles and mist droplets are removed from theflue gas by mechanical impaction created by the filteringspray nozzles. The scrubber was instrumental in allowingValero to be the first petroleum refiner to win the TexasGovernor’s Award for Environmental Excellence in 1995.

Electra filtering modules can be used if significantlylower emission levels are required. These are similar tofiltering modules but have a rigid pipe electrode axiallymounted inside each module. The ionizing effect of theelectrode gives the wetted particles and mist droplets anegative electrical charge. A positive electrical charge isalso induced on the filtering spray which allows the parti-cles and mist droplets to be subjected to two removalmechanisms, mechanical impaction and electrostatic at-traction. Power usage by the electrodes is very low sincethe current levels are on the order of 10 milliamps. Electrafiltering modules have been used extensively on incinera-tion and SO3 applications.

KELLER:Our FCCU was built in 1982 with an electrostatic

precipitator. We lose 50 tons of catalyst a month. Threego out the stack, 40 are precipitated, and 7 are in the slurryoil. Our recent stack tests have measured 24 mg to 34 mgof total particulate matter per dry standard cubic meter.

MANFRED OEHNE (Polutrol — Europe):I would like to submit a statement in favor of the

modern, dry/cyclonic rype third stage collectors. Thereseems to be just no alternative to a modern third stagecollector whenever a power recovery installation operatesdownstream of the FCC generator. But even to checkemission levels for purely environmental reasons, thiscollector type is a wise choice.

Cyclonic third stage separators have come a long way.Over the years their design, overall functionality, andcatalyst collection capabilities have been improved dra-matically. Nowadays, to arrive at emission levels of 70mg/Nm3 to 80 mg/Nm3 (dry) is absolutely no problem.Modern third stage separators (dry type) have proven theyare capable of rendering emission levels in the vicinity of50 mg/Nm3 (dry) and below. And this impressive per-formance can be achieved without any underflow systemand/or fourth stage collector required.

A series of recent tests performed at two Europeanrefineries involving our modern dry type third stage col-lector, EURIPOS series, has produced clear evidence thatfractional particle efficiencies on the order of dsm(5e) = 0.8to 1.2 micron can be achieved without a hitch. Suchperformance is very much in the range of scrubbers andESPs.

The basis of such impressive performance, of course, isnot an outdated seat-of-the-pants design approach, butinstead relies upon modern, up-to-date, and highly ad-vanced mathematical modeling processes. Where do wego from here-what does the future hold in store? Withgreat certainty, the mathematical modeling will be steadilyimproved, allowing even better designs via fine tuning ofthe rather complex processes taking place inside a cyclone.Testing of operating systems in the field, i.e., allowing anactual check of the mathematical models, is a requirementthat should be pursued with diligence by everybody in-volved. For example, the apparent nonlinear behavior ofparticle densities in a force field needs to be exploredfurther. This undoubtedly will require a closer cooperationbetween the catalyst manufacturer, the refiner, the engi-neering companies and, last but not least, the designer ofdry type cyclonic third stage collectors.

On a final note, referring to a previous question (Ques-tion 21), I take objection to a statement offered by aspeaker from the floor who suggested that third stagecollectors that have a number of small diameter cyclonetubes inside a common vessel will protect expander tur-bines by grinding up particles, but their overall efficiencynormally would be in the 40% to 50% range. He further-more claimed that based upon an identical particle inputanalysis, so-called large diameter cyclones (he defined40-inch diameter to be the preferred size) are capable ofachieving drastically higher collection efficiencies in thevicinity of 75% to 80%.

Although his statement may have been made in a purelyself-serving manner, it nevertheless leaves the impressionthat a few large diameter cyclones, under the premises ofidentical operational constraints applied, would be capa-ble of rendering almost twice the collection efficiency ascompared to that of a so-called multiclone cyclonic device(employing a series of small diameter tubes). His state-ment, of course, is wrong, unproven, and unscientific.

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Contrary to what was claimed, I want it to be known that testing, laser inspections). What results were ob-it is really the other way around. tained and what were the approximate costs?

ROBERT L. BROWN (Pall Process Filtration Company):

Pall blowback filtration systems remove more than99.9% of the solids in the flue gas. At this efficiency,emission standards of 6 mg per normal cubic meter canbe met without additional separation equipment.

FRONDORF:

B. Residual Oil Upgrading-Delayed Coking

Mechanical

QUESTION 34.

Has anyone automated a Wilson-Snyder type switchvalve for totally remote operation? It so, how was thelowering and raising of the collar accomplished?

CITGO has used acoustic emission (AE) testing forlocating cracks in coke drums. These tests are performedduring the normal coking cycle and do not disrupt opera-tions other than the building of scaffolding for the place-ment of the AE sensors. We will follow up with UT andvisual testing of the suspected points. We have had a highrate of success locating cracks before they become leaks.We have also utilized high temperature strain gages tomonitor coke drum stresses during the coke cycles, par-ticularly in the areas of recurring cracking and bulging.This has aided in predicting when cracks and bulges arebeginning to develop. We also use these data for finiteelement analysis when designing new drums.

JOHNS:We have not had any experience with the Wilson-Sny-

der type valve.

KELLER:We have purchased, but not installed, an electro-hy-

draulic actuator from Wilson-Snyder. The new actuatorshould reduce operator exposure to the existing Wilson-Snyder coke switching valve. The new actuator uses hy-draulic pistons to hammer seat and unseat the plug of thishighly mechanical valve, as well as rotate the plug portsfor flow direction changes. This type of hydraulic actua-tion replaces the upper jackscrew collar of the valve, whichis normally used to raise and lower the plug assembly. Wewill automate this electro-hydraulic unit with an on-boardProgrammable Logic Controller (PLC) which will be tiedinto our Distributed Control System (DCS). The PLCwill control the time-sequenced piston operation eitherlocally or from our remote DCS. To ensure proper drumisolation during coke cutting, an operator will still manu-ally close an isolation valve between the Wilson-Snyderswitching valve and the full drum.

We have utilized automated laser bulge mapping to sizeand track the growth of bulges in the coke drums. Thistechnique has proven to be a very useful tool in evaluatingthe condition of drums, particularly older drums, andcomparing that over time. The mapping is performedutilizing the existing drill stem rigging. It is done imme-diately after coke drum cutting is complete. Normally itcan fit into your cycle on a reasonable drum cycle time, sothere is not a lot of disruption to normal operations.

We have been very satisfied with all three techniques.The costs are fairly high, so we do not use them on a regularbasis; rather, we use them periodically on a planned basis,either during the year or before a scheduled turnaround.

There is one other method that our Corpus Christirefinery utilizes, but I am not very familiar with it. It isnamed U Plus and uses an ultrasonic imaging techniquefor crack detection. It may replace acoustic emissions inthe future and they say it is considerably less expensive.

KELLER:In January 1995 CIA was contracted to conduct a laser

evaluation and videotaping of our four 24-ft ID cokedrums. These four clad-lined coke drums have been inservice 14 and 25 years. The laser evaluation cost $80,000and indicated no bulging.

FRONDORF:We are aware that Wilson-Snyder has developed a

system to fully automate their switch valve. We do nothave direct experience with one, to date. The use of ballvalves in this service is becoming more common, and thistype application has also been fully automated. We arepreparing to buy two such valves for one of our LakeCharles cokers.

In 1993 a WFMT examination of the coke drum ODsidentified a crack in a girth weld of one of the drums. Thelaser evaluation conducted in 1995 did not identify bulg-ing associated with this crack.

ABRAHAMS:

QUESTION 35.

Please discuss new technologies to monitor cokedrum bulging and cracking, (e.g., acoustic emission

We can confirm the approximate price. We used Cus-tom Industrial Automation of Canada to inspect our fourcoke drums. We found no bulges, but we are going to usethose data to provide a baseline for future reference and tosupport our plan to extend the shutdown interval on thatunit by 12 months.

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KEITH OSBORN (Farmland Industries, Inc.):I would like to poll the panel and the floor. Have you

ever experienced, or are you aware of, a catastrophic failurein terms of a rupture of a coke drum? Or has the failuremode been constrained to cracking and bulging?

ABRAHAMS:We have not heard of anything catastrophic.

MORGAN:We have two cokers, and I am not aware of any failures

of that nature.

FRONDORF:All the failures that I am familiar with have been in the

cracking mode.

QUESTION 36.Is anyone using the “new” 9Cr V tubes in their fur-nace? How have they performed?

JOHNS:We have not used the “new” 9Cr V tubes. We believe

we do not have justification for the metallurgy yet, sincethere are usually other mechanical items at the coker whichpreclude the use of this material allowing a longer cyclelength for the heater tubes.

MORGAN:Neither of our facilities has 9Cr V tubes. Both facilities

have nine-chrome.

QUESTION 37.Does anyone experience extremely high corrosionrates in coker cutting water systems? We have iden-tified our cause to be microbiological and have sus-picions that our problem is aggravated by cokingsludge. We have not found a cost-effective way to treatit. Chemical treatment is a very expensive option.What solutions have been successful?

SHEN:My answer to this question could be off the mark, so

I will keep it short. We have not seen a cutting watersystem corrosion problem caused by microbiological fac-tors. What we have seen is that most problems are erosionrather than corrosion. We believe that erosion is causedby coke particles. The key to solving this problem is tohave a good water settling tank operation and to keep thewater velocity in the cutting water system below 6 fps or7 fps.

JOHNS:At one of our plants, we have seen increased corrosion

rates from pitting type corrosion in the coker cutter water

system. We have not noticed anything due to biologicalcauses. I think it would be possible to shock the system ifit is truly a biological problem.

QUESTION 38 .Describe your experience with mechanically decoking(“pigging”) coker heaters, specifically in the follow-ing areas:

a) impact on tube life from metal loss;

b) downtime required as compared to steam/air decoking;c) impact on heater run length;

d) success at removing coke formed as a result of highsodium in the feed as compared to steam/air decoking.

JOHNS:We use slides of a thermographic scan of the large lines

coming out of the coker drum, which show, from athermal color gradient, a coke ball near the top. This ishow we detected plugging and high pressure drop in thisline. The intensity of color gives you the degree of tem-perature.

With regards to the exact question on pigging, oneplant has successfully mechanically pigged the lines. Wehad observed that usually all laydown material had beencleaned by this pigging until this last time in July. For somereason, after pigging, we now have a short cycle on thisparticular heater for the first time. Perhaps somethingwent wrong in the procedure. We are usually quite suc-cessful.

One needs to consider that heater design may have alot to do with the ease and even the feasibility of piggingmost heaters.

VAN IDERSTINE:We do not do any mechanical pigging of our coker unit

heater. We do a steam/air decoke. On the vacuum unitheater, we used mechanical pigging once, but really didnot find very much coke, so we have not done anydecoking of that heater in the last three years.

Steam/air decoking on our coker heater is a procedurewe have done for many years and can complete with a 24-to 36-hour feed outage.

We optimized our coker unit operation such that thecycle time between steam/air decokes has increased fromabout 40 days to over 200 days. Furthermore, we areconsistently producing anode grade green coke.

GARY HUGHES (Conoco Inc.):We have practiced pigging a number of times on the

cokers in two of our refineries. To date, we have notexperienced any significant metal loss due to the pigging.The stream-to-stream downtime required for pigging afurnace is typically 2 to 2½ days. Due to the relatively highcost of pigging, we have been reevaluating the steam/air

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decoking technique. And since doing so, we have been ableto improve our steam/air decoking procedure, allowing usto reduce the stream-to-stream time from 4 days to 3 days.

Concerning heater run lengths between decoking, wesee similar run lengths between furnace decoking whenutilizing the pigging technique versus steam/air decoking.Therefore, we believe the utilization of pigging versus thesteam/air decoking method must be evaluated on a case-by-case situation.

Concerning Item D of the question, we have found thatthe pigging technique does a much better job of removingnonorganic deposits, which sometimes build up in thereturn bins of the furnace tubes.

Process

QUESTION 39.During the coke drum cooling/cutting part of the cok-ing cycle, immediately after switching to blowdown,steam is injected into the bottom of the full drum(called “big steam") for one-half to one hour. After thebig steam step, water is injected into the bottom ofthe drum. Has anyone eliminated the “big steam”step in order to reduce cycle time? If so, have changesin coke quality or drum integrity been observed?

SHEN:The answer to this question is yes. We have seen several

refiners skip the big steam step to shorten cycle time. Asfor the question of coke quality and drum integrity, we areconcerned more about drum integrity than coke quality.

After the small steam cycle, the coke bed and the drumare still at very high temperatures. Any water injectionwould convert to steam. People adjust the water rate bywatching how fast the pressure rises, but there is alwaysthe potential of over-pressuring the drum. The otherconcern we have is that when you add water to a hot cokedrum, the water does not distribute as well as the steam,and the coke in the drum is not always in a homogeneousform. There is a possibility that channels in the coke bedexist. If a channel is directed toward the vessel wall, coldwater can hit the hot metal wall. The resulting localizedthermal stresses could potentially cause vessel cracking.

As for coke quality, feedback indicates that refinerscannot tell any difference.

FRONDORF:The Lake Charles, Louisiana refinery still has a big

steam step, but it is considerably shorter than the half hourto one hour mentioned in the question. It is more on theorder of 5 to 10 minutes. At the Corpus Christi plant, webegin the quench cycle immediately after switching toblowdown, i.e., the big steam step has been eliminated.We feel that the stress on the drums is minimized more by

maintaining a total cool-down time, which we have doneas we have shortened cycle times over the years. We havenot seen a coke quality change when we have eliminatedthis step.

QUESTION 40.What are refiners doing with their coker naphtha be-sides sending it to reformers and FCC units?

VAN IDERSTINE:We split our naphtha in the coker. We take a 350°F end

point on our light naphtha and we send that over to ourheavy naphtha unifiner. The heavier coker naphtha goesto our distillate hydrotreater. The obvious negative aspectof feeding coker naphtha to any hydrotreater is siliconpoisoning from silicon in the antifoam.

JOHNS:We have, at certain economic times, charged some of

the light coker naphtha material to our hydrocracker andthat has usually been in the range of a 360°F to 370°F endpoint. This has been done when we were either short ofHCU feed or long on reformer charge. You need to watchthe heat transfer on the preheat exchangers, of course, andan inhibitor/disbursement material will be required forthis light coker.

QUESTION 41.Do you regularly drain your coke drums by opening thebottom head flange? What safety issues need to beconsidered? How is the quench water collected andreturned to the quench water storage?

KELLER:Our cokers are designed to drain the quench water

through a line teed into the bottom head gooseneck. Thewater goes directly into the sluiceway and is recovered inthe dewatering/clarifier system. Occasionally we get aplugged drum or drain line. To drain the drum in this case,we follow a written procedure. It requires that a two-manteam wearing proximity suits remove a continuous quarterto half section of the bottom head bolts. They start withthe bottom head bolts furthest away from the catwalk andwork their way back to the platform. Rarely do more thanhalf the bottom head bolts need to be removed to establishan adequate drain.

SHEN:We would not recommend draining the drum by open-

ing the bottom head. We believe it could be a hazardousoperation. The only situation that we know of whenrefiners do this is when the draining system is completelyblocked and there are no other options.

If the operator is having difficulty draining the drumbecause of blockage, or for any other reason, we would

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recommend putting in additional drain lines located inthe straight side of the coke drum shell approximately 1 ftto 2 ft above the conical section, or simply making thedrain line larger. If the drain line restriction problem(blockage) happens frequently, it may be because of shotcoke production.

VAN IDERSTINE:I agree with the previous comment. It is something you

would normally try to avoid. The only time you get intothat situation is if your bottom drain becomes plugged forsome reason. If you ever open the bottom head flangewithout proper draining, three steps are recommended.First, ensure that the drum has been adequately cooled.Second, ensure that the bottom head can be held in placewhile the flange bolts are removed. Most drums areequipped with some type of hydraulic or pneumatic liftfor raising and lowering the bottom head. Personnel in-volved in this step should wear protective equipment whenunbolting the head. Last, but not least, evacuate the areabelow the drum prior to lowering the head. Try to run yourdelayed cokers in a manner that will avoid the potential ofplugging your bottom drain.

FRONDORF:I agree with the others. We do not regularly drain the

drum by dropping the bottom head. Where that wouldbecome necessary, we have a written procedure that fol-lows the same guidelines that were previously mentioned.At our Corpus Christi, Texas refinery, we have an auto-matic remote-operated unheading device that gives usmore flexibility when this problem occurs. We are cur-rently on 13-hour cycles and are considering going to12-hour cycles. Several safety issues that could come up ifone decided to go to a drain-by-a-bottom-head methodwould be: the conversion of the bottom flange to a re-motely operated studless flange along with the spool pieceon the feed line, which would automatically swing out;how to control the spilling of the hot water and loose cokeon the deck; barricades; etc.

QUESTION 42.Is anyone pressure draining coker drums using nitro-gen, and if so, what has been the impact on drain time?

SHEN:We do not know of any refinery pressure draining the

coke drum using nitrogen or steam. If something must beused, steam would be a lower cost selection over nitrogen.At least you can recover the water. One potential problemwith pressure draining is that too high a pressure differenceacross the coke bed could collapse your coke bed, resultingin a blockage problem in the lower section of the cokedrum.

QUESTION 43.What has been the experience processing used lubeoil in coker units? What pretreatment is done, if any,and what were the benefits? Has corrosion been ex-perienced in the fractionator overhead lines?

JOHNS:At one of our plants, we have had a very positive

experience for 2 to 3 years collecting used motor oil andinjecting it at a slow rate into the coker, just upstream ofthe preheat furnace. We have had essentially no pretreat-ment. We made sure that the oil did not contain any freewater after transfer to an existing fuel oil tank. We esti-mated the benefits to be that the oil, in addition toproviding recycled benefits, would break down to a yieldof 4% butane, 3% pentane, 8% naphtha, 82% gas oil, and3% coke. No corrosion problems have been associatedwith this procedure.

ABRAHAMS:We do not have experience on a delayed coker, but we

do on our fluid coker. We have been collecting used lubeoil from local company service stations and also fromDelaware. We have not had any corrosion problems or anyother operating problems as a result of this. Most of thebenefit has been in public relations from working with thelocal authorities.

FRONDORF:Our LYONDELL-CITGO joint venture had been

processing used lube oil as vapor quench to the coke drumoverhead vapor line. No pretreatment was performed onthis oil. No corrosion problems were noted in the cokeritself. However, the downstream hydrotreater that proc-esses the coker naphtha experienced corrosion from theoutlet of the reactors through the cold flash drum circuit.One line failure was experienced. The cause of this corro-sion was apparently organic chlorides contained in the usedlube oil fractionated into the coker naphtha stream. Chlo-ride levels as high as 40 ppm were noted in the naphtha.We have since discontinued processing the used lube oil.

1995 NPRA Q&A Session on Refining and Petrochemical Technology 85