The fluid catalytic cracking (FCC) process received heavy attention, as usual, at the 1996 National Petroleum Refiners Association question and answer session on refining and petrochemical technology (Oct. 15-18, 1996, Anaheim, Calif.).
At this renowned meeting, processing industry personnel from around the world meet to exchange experience and expertise in refinery operations. A panel of experts presents answers to presubmitted questions on a variety of subjects (see box). Following the panel's response, audience members may respond to the answers or ask additional questions.
This article is the first in a three-part series of excerpts from the 1996 NPRA Q&A transcript. It includes exchanges on fractionator dry-out procedures, regeneration issues, CO combustion control strategies, and ethylene production maximization.
The second article will include discussion about hydroprocessing and reforming catalysts. The final article will include portions of the transcript dealing with an important support operation-crude desalting.
Fractionator dry-out
What methods do refiners use to dry out their FCC main fractionators on start-up? What are the critical steps of this operation and what should be monitored to ensure a smooth start-up?Hunkus: We use a fairly standard combination of low-point drains from the heavy cycle, light cycle, and naphtha pumps and circuits, switching pumps, stroking valves, and bypasses. After steaming, we begin cascading raw oil down the fractionator, inventorying the overhead receiver with naphtha, circulating the bottoms circuit on raw oil, and backing steam through the slurry generators to provide heat to drive the water up the tower. We do this at low pressure and heat the bottoms up to about 315-340° F.
With a little experience, you can tell if you have water coming out of the bottoms or not and when you have the bottoms hot enough. Do not forget that a little water in the flush will cavitate your bottoms pumps. A little water in a spare pump or a bypass line can wreck your entire tower, especially if you put it into the bottom of a hot tower.
Jackson: After steaming out the main fractionator at start-up, our refineries use similar but subtly different methods of drying out the column and associated systems.
All vent valves are fully open, as are the drain valves. The unit is warmed up and brought up to 15 psig (1 barg). Fuel gas is brought in and the pressure maintained at 7 psig (0.5 barg). As the steam cools, the pressure drops.
Light cycle oil (LCO) connections have their blinds removed at the battery limit and the column and circuits filled. The LCO is then circulated and the system is heated using high-pressure steam via the pumparound exchangers.
All the low-point drains are checked for water. The bottom of the tower is heated to 250-265° F. (120-130° C.) using the pumparound heating. Once well above 212° F. (100° C.), the heat-up is ramped 45-55° F./hr (25-30° C./hr).
When the column base is at around 320° F. (160° C.), the LCO is slowly flushed out and fresh feed is added. The overhead is filled with naphtha from the crude unit and fill drum and return lines, as well as the secondary absorber. All the time, low-point drains are checked.
The heat continues at the same rate until the bottom temperature is at 645-660° F. (340-350° C.) and the main fractionator is ready to go. All the way through the warm-up procedure, and even now, the low-point drains are checked for water.
On one of our bigger FCCs flushes the main fractionator with cold feed from the top of the main fractionator, then out the bottom and back to tankage for water separation. When the drains have stopped pouring water, the oil is heated using the fired preheater, and the flushing is continued from top to bottom-feed drum through the heater to the top pumparound and the return nozzle. This way the feed system and the main fractionator are dewatered, dried out, and heated up.
The critical steps in the operation are:
- Steam out everywhere and long enough to get the air out of the system.
- Drain all low points.
- Fill the system with either LCO or fresh feed.
- Circulate and keep draining.
- Heat up the circuit and keep draining.
- Fill the overhead systems and keep draining.
Kimbrell: We use the same technique. We bring in fresh feed through the feed heater and then back out to tankage.
Kooiman: My experience has been to operate without a feed heater, similar to that described by Mr. Hunkus. The big thing again is to drain the low spots of the water.
C. Manoharan (Indian Oil Corp. Ltd.): We are using the same procedures. Regular draining of water from each circuit-heavy naphtha, light naphtha, LCO, and heavy cycle oil (HCO)-and from whatever low-point drains there are, including the drains of pumps and the spare pumps. We find this draining very satisfactory.
James D. Weith (Unocal Corp., 76 Products Co.): I have had experience in starting up FCC units (FCCUs) using steam anywhere from 100 psi up to 650 psi, and that is quite a temperature range to be dealing with. Quite frankly, when I have used 100-psi steam, it did not seem to make any more difference than when I have had the really hot stuff. So, I just wondered if it is time for a reality check, and whether we go through all this effort for a legitimate purpose.
True, it does get the oil in the bottom of the main column, but is it hot enough to do any good? Could it be perhaps that when you start circulating catalysts and put steam to the riser that you are heating that 20-psi steam up to about 1,000°, and that is what really affects the dry out of the main column?
Hunkus: I agree with most of what you say. Our high-pressure steam is 150 psi. We do not have 600-psi steam. I will tell you that we had problems when we tried to use a lot of riser steam with a new start-up procedure after a reactor modification, and pulled our system down to about 115 psi. We could not get our bottoms pumps to run properly.
What we found was that we could not get the water out of the bottom of the tower with the pressure balance that we had and our ability to heat up the bottoms. We had to get the pressure on the main column down well below 10 psi then and put a third slurry-steam generator on-line, backing steam through it.
So it is a pressure-temperature relationship, and if you do not drive the water out of the bottom of the tower you may find your bottoms pumps will not pump. If you cannot circulate the bottom circuit, you are not going to be able to be sure that you are not going to put water in the main column.
Having a column that has had the trays ripped out of it is not pleasant. I want to caution anyone on your "reality check." Systems are different, and you need to fully understand all the reasons and differences before you recommend changes.
Regeneration
When an FCC feed is hydrotreated, the delta coke declines significantly. How can the resulting low regenerator dense-bed temperature be controlled or raised? Can the continuous use of the air preheater be employed?Hunkus: Some of the obvious things are: slurry or HCO recycle; reduction of reactor stripping steam; higher pressure on the reactor; reduced feed preheat; controlled addition of non-hydrotreated feed; "hotter," more-aggressive catalyst; and some residual feed cracking; not to mention increasing charge rate to the FCC.
Some of these actions are quick fixes, but economic optimization will require careful evaluation. More charge, higher conversion, more-active catalyst, adding heavy feed, and running for octane top our list.
The air preheater may seem to be a solution, but safety considerations would seem to make this undesirable. I would recommend against this practice with a traditional air heater design and instrumentation installation. It would also seem that a more economical way to exploit this unit opportunity can be found.
Jackson: I agree with most things that Mr. Hunkus said, bar one: that is I would not use stripping steam as a control of regenerator temperature. We have had problems resulting from this practice.
First, it depends on the regeneration mode the unit is operating in. In partial burn, the regenerator can operate at low temperatures quite stably (assuming feedstock quality is stable). Temperatures as low as 1,220-1,240° F. (660-680° C.) have been common and stable.
The problems associated with running in partial burn at low temperatures are usually associated with the efficiency of the regeneration step and the carbon on regenerated catalyst (CRC). This has not been a problem at low regenerator bed temperatures, even though the regenerator bed temperature has an effect on the combustion kinetics.
We have found that the selectivity of the unit is affected detrimentally at CRCs above 0.4 wt %, based on one of our European FCCUs running in partial burn (experience between 0.15 wt % and 0.6 wt % CRC).
In full burn, the only problem we have seen is the afterburn, but it can usually be controlled by CO Promoter. That said, we do not run any of our FCCUs with fully hydrotreated residue and have sold off our last refinery running hydrotreated feedstocks last year to Tosco Corp.
There are a number of possible ways of raising the regenerator bed temperature, but let us redefine the fact that regenerator temperature is proportional to delta coke. With that in mind, the methods that can be used are:
- The old method of recycling slurry to the riser is a sure way to increase the regenerator temperature, but at the expense of conversion and selectivity. We have also fed vacuum residue to our units that have room to move on regenerator bed temperature and limited fresh-feed availability. This too will raise the regenerator bed temperature.
- Increasing equilibrium catalyst (E-cat) activity by increasing fresh catalyst additions, increasing fresh catalyst activity/surface area, or by using additives with very high surface area effectively do the same. All these will increase the E-cat microactivity (MAT) and surface area, and the delta coke, and hence the regenerator bed temperature. The refinery may hit other constraints in the main fractionator and gas recovery unit, because all of the above will increase the unit's conversion too.
- Recycling spent catalyst to the reactor riser will also increase the unit's delta coke and regenerator bed temperature. This principle is implicit in the UOP X-Pot technology and is ideally suited to very clean feed, low delta coke (short contact time riser cracking and riser termination devices with efficient feed nozzles) operations. BP has examined the technology and process closely. Contact UOP for further details. The following are a number of unit operations that BP would suggest refiners consider carefully before undertaking.
- Reducing feed nozzle dispersion steam. To see any delta coke effect by reducing modern, high-efficiency feed nozzle steam, the steam has to be substantially reduced, so much so that the integrity of the feed nozzles would be in question (catalyst ingress and erosion). The yield selectivities would also be very badly affected.
- Reducing steam to the main stripping ring is not recommended, as mentioned earlier. The effect will increase the delta coke of the operation by allowing hydrocarbons to pass into the regenerator, increasing the hydrogen in coke and hence the apparent delta coke. This will create a number of potential undesirable effects, such as increased catalyst hydrothermal deactivation and compromised integrity of the steam ring. One of our units in the U.S. reduced steam to their stripping steam ring and experienced severe catalyst deactivation that took over a month to fully recover.
- Using torch oil rapidly deactivates the E-cat in a unit and should only be used at start-up and restarts.
- From a catalyst deactivation point of view, using the air preheater to heat up the regenerator bed is preferable to using torch oil. The main concern is the safety of this operation as a continuous operation. Some sites still have start-up procedures requiring an operator to sit by the air preheater viewing port and ensure a flame remains present. This is with a much lower regenerator temperature, too. We have estimated the effect on one of our FCCs.
This would effectively increase the regenerator bed temperature.
Obviously, increasing the regenerator bed temperature will decrease the catalyst-to-oil ratio and affect the yield selectivities adversely. Consequently, BP recommends that one of the first set of options above be considered, based on the particular unit's feed options, constraints, hardware, and capital expenditure constraints.
Hunkus: I wanted to clarify that I was not recommending raising the pressure or reducing stripping steam. Those are things that are obvious, but what you are doing is burning product in the regenerator. There are better ways to optimize the unit.
Kimbrell: Feed to our FCCU is 100% hydrotreated. We have been able to control the regenerator temperature by using a high-surface-area, high-rare-earth catalyst, and it does not take very much addition. That is about 0.5 wt % of the inventory per day addition, and it seems to work out fine. We have tried some of the other things that Mr. Hunkus has mentioned and we agree there are more economical solutions.
Lemmon: First off, lower generator temperature is a good thing from a catalyst deactivation standpoint. So you need to ask yourself why you are asking this question. We have a fully hydrotreated unit that operates at about 1,240° F. in full combustion, and the partial combustion unit operates about 1,270°. This is good for a catalyst's life, but each refiner needs to explore the unit's capabilities.
Some units are unstable and they have a tendency to lose combustion. Basically, the kinetics become unfavorable. Unit operators need to know that a rapid introduction of feed tends to drop the regenerator temperature suddenly, and they need to be prepared equally to cut feed rapidly if they see the regenerator temperature plummeting.
If you are operating in partial combustion and you see the regenerator temperature dropping, you certainly would not want to add torch oil. So the operators need to know how to respond to a loss of regenerator temperature.
At our hydrotreated-feed unit, we choose to recycle slurry oil or heavy cycle oil to increase regenerator temperature, if need be. The preferred route is to go up on catalyst activity. When you recycle slurry, you are basically making coke and some LPG feed for the alkylation plant.
While continuous firing of the air preheater is possible, you need to have a plan for what you are going to do when the preheater burner fails from extended use. How are you going to restart the unit, for instance, without having an extended shutdown to go in and fix it? Also, if you are already out of regeneration air, firing the preheat burner is just going to force you to cut rate.
Barker: We have a few examples to quantify some of the moves recommended earlier.
First, on raising the feed temperature, every 100° F. increase in feed temperature increases the regenerator dense-bed temperature by about 20° F.
Second, in terms of raising the reactor temperature, every 3° F. increase in the reactor temperature increases the regenerator dense bed temperature by about 2° F. However, there are limitations to how high one can raise the reactor temperature, so this move is not very practical if you want to increase the regenerator dense-bed temperature quite a bit.
Third, once the unit is fully up and running, one can increase the temperature of the combustion air to increase the regenerator dense-bed temperature. The mass flow rates of both the air and the feed are about the same; however, the specific heat of the air is about a third that of the liquid hydrocarbon.
Increasing the air temperature will have about a third the impact as increasing the feed temperature. That is, every 100° F. increase in combustion air temperature will increase the regenerator dense-bed temperature by about 6° F. However, as this is done, the pressure drop through the air grid increases, and one may end up running out of air blower capacity.
Gentry: The other panelists have covered all of the points well. I just wanted to reiterate a couple of them. The easiest ways is to increase regenerator temperature are often the worst. Torch oil or reducing stripping-steam rate are not good solutions to controlling regenerator temperature because these practices hurt catalyst activity while negating the improved coke selectivity.
With regard to air heaters, air heaters are one of the more hazardous aspects of FCC operations. FCC air heater firing should be limited to unit start-ups.
CO combustion
Before the advent of complete CO combustion in the regenerator, the regenerator would operate at a CO2-to-CO ratio of about 1.0. In the mid-'70's the operation was converted to complete combustion. Now we are considering operating with a CO2-to-CO ratio of between 3 and 10. Please discuss the best possible method to control this operation, if combustion promoters are necessary and at what level, and will too much promoter lead to high carbon on regenerated catalyst?Lemmon: Our Bayway refinery operates with a CO2-to-CO ratio of 2.5 to 4 and our Avon refinery operates in partial combustion occasionally. Both units utilize on-line CO monitors in regenerator offgas and make minor adjustments to blower air vents to keep the CO within target range.
The range of CO they can operate with is controlled by CO boiler limitations-both on the high and low range of CO-by regenerator temperature targets, and by high and low carbon-on-regenerated-catalyst limits. I agree with what Mr. Jackson said earlier; we find that CRC up to 0.35 wt % is fine. If you go over that, you rapidly begin to see a loss of catalyst selectivity.
When we are operating slightly in partial combustion, we do see higher afterburning. If the regenerator dense phase is below 1,300° F., we do add promoter and we do see some benefit. At our California refinery, the regenerator does not respond well to CO promoter; afterburn tends to increase to as high as 80° when we are in partial combustion.
If a combustion promoter is used, it should also reduce the maximum CO that can be run before reaching catalyst regeneration carbon limits. Afterburn, in itself, is not a bad thing. If it does not uneconomically reduce cyclone or catalyst life, it may allow you to run more rate or severity. As with a lot of things, these answers need to be found out for your specific unit.
Hunkus: There probably are many FCCUs that are successfully running in partial combustion. Possible adverse effects associated with partial combustion include afterburning and higher carbon on regenerated catalyst.
Afterburning is generally not a problem in a regenerator with adequate air-catalyst distribution, but your adequate promoted unit may turn into an inadequate partial combustion unit. One particular FCCU with only a mediocre air-to-catalyst ratio runs a "cool" regenerator (about 1,250° F.) without combustion promoter, and sees only 40° F. of afterburning. Higher carbon on regenerated catalyst is likely, but may still be profitable if margins on incremental throughput are favorable.
One of the catalyst companies, Grace, has a relationship between CRC and microactivity. It shows a decline of 5 MAT while going from 0 wt % to 0.3 wt % CRC. My experience on 10+ FCCUs is that, once you get below 0.24 to 0.18 carbon on regenerated catalyst, depending on your distribution system and your catalyst system, you probably have gotten 90+% of the yield advantage associated with running low carbon on catalyst.
Recall that MAT numbers are generally reported after burning off any residual coke, so they may not represent the activity which the FCCU will see. In this type of partial burn operation, it is very important to match the catalyst to the unit.
We also believe the relationship of CO2 to CO to be a strong function of vanadium content of the equilibrium catalyst. Obviously, this is more pronounced on resid crackers or in crackers like ours that crack very long resid. We run with high metals on an Akzo-based catalyst system, and, for us, a cold regenerator without promoter is in the 1,200° F. class. We also have run as high as 1,460° F.
This may be an area of lost knowledge in your organization. You may have an entire shift of operators, engineers, and supervisors who may not ever have knowingly run in partial or non-autopromoted, incomplete combustion.
We had that experience after our 1995 turnaround, when we started up with very clean catalyst because of a larger inventory due to unit modifications, and a 150° F. cooler regenerator from a much improved stripper we got from Stone & Webster. We had a 200° F. afterburn-and I am talking about the difference in the dense phase vs. cyclone outlet-for 1 or 2 hr before I realized that we had dropped out of promote (plenty of time to visualize what might be wrong on the inside of the regenerator).
Jackson: We have a number of FCCUs that operate in partial-burn operation in the range of 1.0 to 3.0 CO2-to-CO ratio. To ensure you can control the CO2-to-CO ratio in your partial-burn FCCU, it is very probable that you will have to use CO promoter. The promoter will control the afterburning in the unit by pulling the burn back into the regenerator bed.
The higher the CO2-to-CO required in the flue gas, the more promoter will have to be added. The dense bed temperature will rise, and the carbon on regenerated catalyst will fall.
One of our residue units that has high metals on the E-cat (very high Ni) operates with a CO2-to-CO ratio of 3 to 4 with no promoter. If too much promoter is added, the effect will not be increased CRC, as stated in the question, but decreased CRC (clean it up) and increased bed temperature.
One of our partial-burn units sees no yield-selectivity deterioration for a CRC from 0 wt % to 0.4 wt %. Above this, 0.5+ wt %, the selectivity is affected. They only get into this operating spiral when they cut back on the air to try to decrease the CO2-to-CO ratio. With the feedstock run, the regenerator geometry, hold-up, and air-catalyst distribution, they can achieve no higher than 6 vol % CO in their flue gas.
If the FCCU has variations in feedstock quality, the refiner should keep the CO promoter as a separate particle and not inclusive on the parent catalyst. If the feedstock changes and the controls or operations group does not react quickly enough in reducing feed and increasing air slowly (if the feedstock becomes heavier), then the CO promoter will have to be added to enable the burn to be brought back into the regenerator bed and the CO2-to-CO ratio increased, and hence, the CRC reduced, or at least manageable (< 0.3 wt %).
Almost all of our refineries have the CO promoter as a separate particle, and even the ones with impregnated promoter have bags of promoter in reserve. Our dosage levels vary from 15 lb in 300 tons (1 lb of promoter/20 tons of E-cat inventory) to 4 kg in 65 tons (1 lb of promoter/8 tons of inventory).
One interesting point is that one of our refineries ran out of CO promoter. It scared the operators so much that every operator has a bag of CO promoter in his personal locker in the changing rooms. That only ever happens once.
Johnson: Operating the regenerator at a 3 to 10 CO2-to-CO ratio is similar to a conventional partial-CO-combustion operation, except that a higher level of combustion is used. The resulting dense-bed temperature will be higher, and usually combustion promoter is required to maintain the CO combustion.
Although it is possible to use too much promoter and cause the available oxygen to be consumed directly to CO2 and leave a high level of carbon on the catalyst, it is not very common. Only enough promoter to keep the CO combustion in the dense bed should be used. This would be about 1 ppm platinum, based on catalyst inventory.
Barker: One of our engineers operated a unit this way several years ago and found it to be a very stable operation. He noted the regenerator was about 2% oxygen deficient. A CO promoter was tried, and there did not seem to be any measurable difference between when it was used and when it was not. During this time, they noticed no increase in coke on the regenerated catalyst when it was being used.
Gentry: Refiners who run with a CO2-to-CO ratio in the range of 3 to 10 are usually using platinum combustion promoters in what is sometimes referred to as partially promoted operation. The operation is controlled by adjusting promoter addition to keep the temperature in the dilute-phase afterburn and carbon on regenerated catalyst in the desired range. Constraints include metallurgical temperature limits on air grids, cyclones, and downstream equipment, such as expanders and third-stage separators.
Many units also have minimum firing requirements for the CO boiler, which limit the amount of CO combustion done in the regenerator.
Most partially promoted units run with carbon on regenerated catalyst between 0.1 wt % and 0.2 wt %. Care must be taken to avoid overpromoting the operation. It has been found in some units that too much promoter leads to preferential combustion of CO, which starves carbon burning and can lead to a buildup of carbon on regenerated catalyst.
In addition to the above, the addition rate of promoter depends on other factors, such as platinum content of the additive, regenerator residence time, metals on catalyst, and type of catalyst in use.
We are aware of two partially promoted units running a flue gas CO2-to-CO ratio of 7. The larger inventory unit of the two uses 0.05 lb promoter/day per ton of catalyst inventory. The smaller inventory unit uses 0.13 lb/day per ton of inventory.
James D. Weith (Unocal Corp., 76 Products Co.): In the late 1970s, another catalytic cracker I was associated with was in Farmington, N.M. We used to practice a technique of going back and forth from complete combustion to partial burn, depending on where we wanted to run the unit.
This FCCU had been relocated from Winnipeg, Man., where the elevation was much lower than in Farmington. Consequently, the main air blower could not keep it in complete combustion at its design feed rate of 5,000 b/d.
We could run it in complete combustion up to about 4,000 b/d. If we wanted to go higher, we had to be in partial burn above 4,500 b/d. (Between 4,000 and 4,500 b/d was kind of no man's land.) We would make this transition by simultaneously increasing the feed rate and cutting the air, or vice versa.
As we went back and forth-we called this going across the hump-the dense-bed temperature in the regenerator on both sides was about 1,320° F. As the regenerator was moved from one side of the hump to the other, the temperatures would get up to 1,420-1,450° F. at its apex. If you are going to do this, you need to learn to get through that regime fairly quickly.
I tried the CO promoter, as Ms. Barker mentioned, but I did not see any difference as we were making these transitions.
Joseph W. (Bill) Wilson (Caltex Petroleum Corp.): Well, the gentleman from Unocal stole half of my response. I was going to warn people about the transition range. There has been some comment about the effect of carbon on regenerated catalyst on the effective activity inside the riser. I have an equation that can be used to estimate this effect: Effective Activity = MAT - 5.05 (CRC) - 5.081 (CRC)2
FCC ethylene production
Refiners are continuing to seek ways to increase production of petrochemical feedstocks. What process or catalyst technologies significantly increase ethylene production from an FCCU?Jackson: BP already produces light olefins for the chemical industry from the FCCU, but predominantly produces propylene (C3=). We have considered the production of ethylene (C2=) on numerous occasions and studied the potential and the economics associated with this operation.
It should first be understood that C2= is produced from thermal reactions, whereas C3= and higher olefins are produced catalytically in the FCCU.
We have to look at each operating variable in isolation to determine the magnitude of each variable's effect on C2= production. The major variables considered were: riser outlet temperature, reactor pressure, catalyst-to-oil ratio, catalyst variables (ZSM-5 and rare earth), feed quality, and short-contact-time operation.
The only variable that has any real effect on the C2= yield is riser outlet temperature. Reactor operating pressure has a small but negligible effect, too. The rest are insignificant.
A typical C2= yield from an FCCU runs at 0.6 wt % to 1.0 wt % maximum, depending on the operation. Considering a sensible maximum riser outlet temperature of 610° C., the maximum C2= production can be increased to around 5 wt %.
The associated dry gas production (H2, C1, C2, and C2=) is approaching 15 wt %, with approximately equal C1 to C2= by weight. This is assuming a commercially sensible conversion of 85 wt %.
There are two commercially available processes operating in China that have been specifically designed for maximum olefins production: Deep Catalytic Cracking (DCC) and Maximum Liquefied Gas plus Gasoline (MGG). A third process is being developed, which is called Maximum Iso-Olefins (MIO).
The quoted yields from a DCC are between 3.5 wt % and 6 wt % in maximum C3= mode. The MGG process is obviously a lot lower for C2=, due to the objective of this process.
In summary, the maximum C2= is achieved by maximum riser outlet temperature and reactor operating pressure and minimum catalyst-to-oil in an FCCU. This ensures that, for a given conversion, the maximum amount of conversion is from thermal reactions and not catalytically.
Barker: I agree with Mr. Jackson's comments and note that it gets back to the basics of the kinetics of the reaction.
The cracking mechanism in an FCCU is beta carbonium ion cracking. Therefore, catalytically cracked products must be propylene and heavier. Ethylene is produced by thermal cracking side reactions and is not controlled catalytically.
Thermal cracking will occur in the reactor if the catalytically cracked vapors are allowed a long residence time. This results in a large loss in gasoline to LPG. So I agree that it is a very inefficient way to generate ethylene.
The panel...
John H. Arndt, process coordinator, Chevron Products Co., Richmond, Calif.;Mario C. Baldassari, technology manager, ABB Lummus Global, Bloomfield, N.J.;Ellen S. Barker, advising engineer, Unocal Corp.-76 Products Co., Rodeo, Calif.;Tom W. Davis, process engineer, Cenex Inc., Laurel, Mont.;David J. DiCamillo, technical service coordinator, Criterion Catalyst Co. LP, Houston;Paul Fearnside, senior technical service engineer, Nalco/Exxon Energy Chemicals LP, Sugar Land,Tex.;Arthur R. Gentry, product director, The M.W. Kellogg Technology Co., Houston;Stephen F. Hunkus, manager-operations and oil movements, Mapco Petroleum Inc., Memphis;Ian Jackson, FCC refinery support team manager, BP Oil International Ltd., Sunbury-on-Thames, U.K.;Brian H. Johnson, director-technical services, UOP, Des Plaines, Ill.;Michael R. Kimbrell, process specialist, ARCO Products Co., Anaheim, Calif.;Randall R. Kooiman, consultant, Koch Development Group, Wichita, Kan.; Charles B. Lemmon, technical services manager, Tosco Refining Co., Martinez, Calif.;Terry R. Smith, engineering division head, Saudi Aramco, Ras Tanura, Saudi Arabia;Terrence S. Higgins (moderator), technical director, National Petroleum Refiners Association, Washington, D.C.Copyright 1997 Oil & Gas Journal. All Rights Reserved.
