NPRA Cat Cracker Transcript

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CAT CRACKER SEMINAR TRANSCRIPT August 8-9, 2000 Houston, Texas N A T I O N A L P E T R O C H E M I CAL & R E F I N E R S A S S O C I A T I O N SUITE 1000 # 1899 L STREET, N.W. # WASHINGTON, DC 20036

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Transcript of NPRA Cat Cracker Transcript

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CAT CRACKERSEMINAR

TRANSCRIPT

August 8-9, 2000 Houston, Texas

N A T I O N A L P E T R O C H E M I CAL & R E F I N E R S A S S O C I A T I O NSUITE 1000 # 1899 L STREET, N.W. # WASHINGTON, DC 20036

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NPRA CAT CRACKER SEMINARAUGUST 8-9, 2000

HOUSTON, TEXAS

TABLE OF CONTENTS

Panelists..................................................................................... ii

Refractory, Materials, Internals, Expansion Joints, and SlideValves .........................................................................................3

Rotating Equipment................................................................32

Turnaround/Maintenance/Inspection....................................40

Process/Performance Related Issues......................................51

Exhibitors ................................................................................61

IMPORTANT NOTICE

The information and statements herein are believed to be reliable but are not to be construed as awarranty or representation for which the participants assume legal responsibility. Users should undertakesufficient verification and testing to determine the suitability for their own particular purpose of anyinformation or products referred to herein. NO WARRANTY OF FITNESS FOR A PARTICULARPURPOSE IS MADE.

Nothing herein is to be taken as permission, inducement, or recommendation to practice anypatented invention without a license.

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PANELISTS

Larry Carper FCCU Mechanical Equipment ConsultantBP AmocoNaperville, IL

Frank DeMartino PresidentShared Systems TechnologyThorofare, NJ

Mike Drosjack Engineering AdvisorReliability & Process SafetyWesthollow Technology CenterEquilon Enterprises LLCHouston, TX

C. J. Farley FCC Technical Services ManagerKellogg Brown & RootHouston, TX

Jim Marlowe Reliability EngineerSunoco, Inc.Toledo, OH

Spence Cousar Process EngineerWilliams Refining LLCMemphis, TN

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2000 Cat Cracker SeminarAdams-Mark Hotel

Houston, TXAugust 8-9, 2000

CRAIL:Good afternoon. I’d like to welcome you to the 2000 Cat Cracker Seminar. I want to

thank you all for coming. My name is Jerry Crail of Equilon LLC and I am the chairman of thisyear’s seminar.

First, I want to welcome everybody. I think we have a record turnout this year, which isgreat. I hope everyone finds this seminar as fruitful as it has been in the past, and after looking atthe agenda I am sure it will be.

To start with, I'd like to introduce some of the committee members - the ones that haveworked very hard to put on this seminar. They are Jon Carlson of Koch Petroleum, Fred Collierof Williams Energy, Shailendra Gupta of BP, Pat Lysaght of Marathon Ashland, and CharliePauls of Cooperative Refining. If you're here, could you stand up? I'd like to thank them againfor their fine work. [applause]

I'd also like to thank the NPRA staff that has worked very hard to make all of thesearrangements for the meeting facilities and the tabletop area. They are Jeff Hazle, Yvette Brooks,Stacy Lane and Kelly Healy. If you're around, could you stand up? [applause] Thank you.

I also want to thank the exhibitors. This is the first year of having a larger exhibit hall,and I want to thank them for putting on, from what I can see, a fantastic tabletop show, and Ihope you all appreciate it. I think their participation is one of the things that will really make thisconference one that's worthwhile to everyone.

I'm looking forward to the agenda. We're going to start off today with a Q&A Session,and we have the panelists here. We'll talk to them in a minute. Tomorrow, we will have theworkshops and there will be a series of them with six starting in the morning, and six more in theafternoon. As you will notice, some of them are repeated, which will enable people to go todifferent workshops. The tabletop exhibit will be open this evening after the Q&A Session. Itwill also be open tomorrow morning, and tomorrow morning we will have coffee, and that willonly be coffee - there will not be any continental breakfast. The tabletop will also be opentomorrow at lunch for you to see all of the fine things they have out there.

Also, the transcripts of the last two Cat Cracker Q & A Sessions are available. For thoseof you that attended the meeting two years ago, you should have received your copy by mailwithin the last week. If you have not received the 1996 or 1998, you can pick them up at theNPRA registration desk.

With that, I'd like to go ahead and start the conference and turn it over to Jeff Hazle forthe Q&A.

HAZLE:Thank you, Jerry, for introducing the Q&A Session. We're employing the usual Q&A

format where we solicit questions from past attendees of these conferences. The ProgramCommittee puts together a panel of experts, who then edit those questions submitted to NPRAand select the ones that they will use in the session. The Panelists then prepare their responses,often consulting other people in the places where they work, and put their answers together. This

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year, we have tried to organize the answers as much as possible in the following way: The firstresponder will give some background on the question. The second responder will describe howthe problem was addressed initially, and then the third responder, if there is one, will talk abouthow the solution to the problem has evolved as technology has advanced.

We have a different stage setting this year. Hopefully, it’s more informal, and moreconversational. It is intended to represent a dialogue with you, the attendees, and the panel.

As usual, the session will be recorded and a transcript will be made. For that reason, weask that you use the microphone when you address questions to the panel. We have microphonesin both aisles and one in the back. We also have people who will be carrying the microphones toyou, so if you have a question to ask of the panel, raise your hand, and somebody will bring themicrophone to you. When they do that, if you would, please state your name and affiliation, andhand a business card to the microphone handler, because when we finish the transcript, we willmail it out to everybody who speaks, and you will have a chance to edit your comments, ifnecessary, or make changes - make sure we understood what your question was.

As usual, there is a disclaimer for this. The panel is representing their experiences. Thereis no legal responsibility or liability that goes along with their answers. Anything that you hearhere, of course, you need to test to see whether or not it’s appropriate for your own facility.

With that, we will introduce the panelists. I will ask each of them to describe the kind ofFCC units that they work with, and then we’ll go to the questions. Next to me is Mike Drosjackwith Equilon. Mike?

DROSJACK:Hi. I’m with Equilon Enterprises, which was formed by Shell and Texaco’s refining arms

a couple of years ago. I’m in the Westhollow Technology Center, which is up the road here, inHouston, and we provide support to the various refining locations we have. My particularfunction is providing support in the rotating machinery area. And in our company right now, wehave eight Cat Crackers scattered around the country from Delaware City to Louisiana toHouston, and have a little bit of everything in that package.

HAZLE:The next panelist is Spence Cousar. He’s a late fill-in for Jeff Warmann at Williams

Energy. They had some problem at the refinery, and Jeff couldn’t make it, so Spence is filling inat the last moment. Spence, what do you have at Williams?

COUSAR:I’m a process engineer at the Williams refinery in Memphis, TN. We have a 75,000 bbd

FCC that processes 100% atmospheric tower resid. We completed an FCC revamp in November1999. We replaced both our reactor and regenerator and installed UOP’s VSS catalyst separationtechnology in both vessels.

HAZLE:Thanks. The next panelist is C. J. Farley of Kellogg Brown & Root.

FARLEY:I joined KBR in 1997; prior to that, I worked for a major refining company for just over 7

years. My job is to perform FCC technical service work for KBR, which means I travel aroundthe world to visit different locations where we have projects as well as heading to places wherewe have extended service agreements. The units I typically interface with are Kellogg/KBR

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designs that are anywhere from five years to thirty years old. I also work with a good number ofUOP geometries, such as side-by-side, stacked and high-efficiency designs.

HAZLE:The next panelist is Jim Marlowe of Sunoco’s Toledo refinery.

MARLOWE:I’ve been with the Sun Toledo Refinery for about ten or fifteen years, and we have a

150,000 bpd fuel facility refinery, and our Cat Cracker is around a 60,000 bpd. Before that I hadservice with Amoco and with ARCO.

HAZLE:Next is Larry Carper, who works in BP Amoco’s Refining Technology Group in

Naperville, Illinois.

CARPER:BP Amoco currently has 22 Fluid Units utilizing various designs and technologies

throughout the world. Some of the units are gas oil units and some are resid units. My exchangetoday will focus on experience with the heritage Amoco units as my exposure to the heritage BPunits is limited. I have over 23 years experience within the company, and shortly will become afree agent.

HAZLE:Alright, last is Frank DeMartino.

DEMARTINO:I don't have a Cat Cracker, but I've been working with FCCU’s for 25 years. I'm the

president of Shared Systems Technology. I've been involved in at least 50 Cat Crackerinstallations and I've probably seen the full spectrum of FCCU technology. I don't work just forone company, I work for many companies. So that's why I am glad to come here and try to sharesome information with you.

HAZLE:Thank you panelists. Let’s go to the first question. Following each question, after the

panelists’ responses, I will ask for questions from the audience. For the first question and the firstresponse, C. J., could you lead on this, please?

I. REFRACTORY, MATERIALS, INTERNALS, EXPANSION JOINTS,AND SLIDE VALVES

Question 1. Has anyone experienced a packed expansion joint failure due topolythionic corrosion and how do you prevent it from occurring?a) What causes this type of corrosion?b) How are stainless steel joints affected?c) Are exotic metallurgies a solution?d) Any new developments?

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FARLEY:Polythionic acid (PTA) stress corrosion is caused by acid formation on "sensitized"

stainless steel when air and water contact a sulfur contaminated hydrocarbon. The"sensitization" of stainless steel occurs when the carbon content is "unstabilized" and allowsmicrostructural intergranular paths to form by carbide precipitation during heating (such aswelding) when temperatures exceed about 800 °F.

Stainless steel expansion joints have surfaces that exceed the limits of the onset of stresscorrosion. There are natural cavities where water can be trapped in these surfaces, and somaterials like 304, 316 or chemically stabilized 321 are not immune in the expansion jointdesign. For high temperature designs, we usually require an H grade to maintain hightemperature strength, but this still allows carbide precipitation or sensitization to take place.

In terms of exotic metallurgies to avoid polythionic attack, or other forms of stresscorrosion, you have to look at the costs and benefits when reviewing all of the alternatives. Wewould generally say Inconel 625 is a respectable choice. It has good resistance to sensitizationand PTA attack, as well as low temperature chloride attack. We have looked at things like 800Hand 800HT. Generally, we tend to stay away from these things, because they are not immune tosensitization.

DROSJACK:We've had these problems in our facilities more than once. And really, there are two

general areas to look at to keep this from occurring. It's choosing the appropriate materials ofheat treatment that can handle the manufacturing processes unsensitized and also keeping theprocess stress heat moisture away from these bellows and keep the polythionic attack (PTA)from occurring.

CARPER:We have struggled with bellows metallurgy for years. The current thinking within our

metallurgy community is Inconel 625-LCF. Previously we specified Incoloy 825 and Inconel625 as an alternate. Our successes with either material is mixed. We recently experienced afailure with Inconel 625 bellows. The internal shroud failed exposing the bellows to the hightemperature flue gas.

Bellows temperature design is critical. Too cool and you risk dewpoint corrosion orpolythionic acid stress corrosion cracking. Too hot can embrittle the bellows material. Internalpacking/insulation minimizes catalyst entering the convolutions maintaining the functionality ofthe bellows or expansion joint. But now you risk cooling the bellows below dewpoint. Thesolution is to insulate externally, but too much external insulation can overheat the bellows. Wesuggest monitoring the bellows temperature during and after startup, then adjusting as necessary.

Recently we learned that a refinery experienced a bellows failure due to overheatingwhich was caused by excessive external insulation. Anyone care to discuss?

DEMARTINO:We've had the opportunity to work with a cross-link inorganic compound that's good to

500°F. If you're above the dewpoint where the acid maybe wouldn't be so much of an issue, ifyou apply this post-cure coating above the dewpoint where the material may be at 500°, it's notan issue. But if you're below the dewpoint, the dewpoints change, there's a chance that thecoating will resist the acid attack for a long time. I can give you an 800 number, for AdvancedPolymer Sciences. The number is 1-800-334-7193. We've put this material in some pretty

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adverse conditions, including some high sulfur, high temperature applications and had some realgood success. So that may be one thing you want to consider to stop some of your acid attack.

Question 2. Has anyone experienced coke formation on the outside diameter ofreactor cyclone gas outlet tubes?a) How can coke formation be eliminated?b) Has anyone used anchors to hold the coke in place? Why not?c) How important is removal of the coke?

FARLEY:Question Two is about coke formation on the outside diameter of reactor cyclone gas

outlet tubes, and that’s what you can see here in this photograph (Figure 1). To improve yourperspective, the cyclone inlet horn is located over here (right side of photo), and the gas flow ismoving towards the left. What we see is coke formation that has occurred over two to three yearsof operation. This is a pretty well-known problem, and it happens quite often on the back side ofthe gas outlet tube, inside the cyclone.

FIGURE 1Coke forms for several reasons, but primarily, this area is pretty inactive in the cyclone

body, so it is not scoured by solids. You can have literally heavy components that form liquiddroplets that coalesce in this area, which then thermally crack; this makes a very hard coke, andit gets pretty thick over the run length. You can have two or three inches of material build up.

We say that there are basically two root causes for this problem. Generally when we seethis, we tend to start looking at the riser operation and start asking whether or not we are gettinggood atomization in the riser. What kind of temperatures do we have in the riser? Do we haveenough catalyst/oil mixing? Is there enough steam in the riser to easily vaporize thehydrocarbon? This has been of particular importance in resid units, where feed can be verydifficult to vaporize.

We have also seen that one way to help mitigate this is to use a little bit of sweep steamin the reactor vessel disengager. This has been effective for inhibiting this kind of cokeformation. But generally, we point to the riser, when we start seeing this type of coke formation.

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CARPER:Until recently, we have seen coke form on the OD (outside diameter) of gas outlet tubes

in resid operations. The coke was both hard and soft. Most recently we found coke in one of ourgas oil units. We are continuing efforts for understanding and prevention.

Removal? - Adamantly recommend removal. Coke on the OD of a gas outlet tube isunstable and can plug diplegs. We recently experienced a situation where thermal cycling thereactor was sufficient to dislodge the coke from the outlet tube, plugging a dipleg which resultedin an unplanned outage. So, once again, we are very adamant about coke removal.

Regarding the question of anchoring coke, I am not gutsy enough to try and sell thisconcept!

I would like to offer one point of observation, we have found coke to form on bothcarbon steel, low chrome steel cyclones and refractory. However, we have not experienced cokeforming on austenitic stainless steel cyclones in a reactor vessels. It is an interesting observation.

DEMARTINO:We happen to work for one customer that has a resid unit that put many, many anchors in

place, just to hold the immense amount of coke so they could go inside and get some inspectionsand then chip away the coke so there was no accidents. So they are using some refractoryanchors, at least one of my customers is.

And then the discussion was made, you know, if it was a stainless steel vessel and thecoke wouldn’t attach itself to the vessel, there are ways of arc spray metallizing 304 or 300 gradestainless to carbon steel. The bond strengths are up around 10,000 psi, and there’s a chance thatthe coke would not attach itself to the stainless steel. It’s a relatively inexpensive method ofapplication, but it’s something that somebody may want to try if they’re having a lot of cokebuildup.

FARLEY:One part of the question, part C, was how important is removal of this coke? And the

easy answer is that it’s absolutely critical to remove this coke. If you go into the unit and you seethis present, you really have to take it out, because there are two main issues with that.

The first one is, dryout time. You may have to do an air dryout when you restart and asyou get up to temperature with air, this coke can be a fuel source. So, how do you keep awayfrom having hot spots? There is not an easy way. That’s the first issue.

The second issue is that this material will spall off and end up in a dipleg. And it’s very,very common around the world to have units that come down for turnaround, see this cokepresent in the cyclone system, and decide not to spend the time to get it out. And when thishappens, there is a very real chance that all they are doing is buying about two or three weeks oftime, because they are going to go back in the vessel to get the material out of the dipleg. It’svery important for the coke to be removed if you see it on the gas outlet tube.

QUINCY SUMMERS (Countrymark Co-op):Quincy Summers with Countrymark, Mt. Vernon, Indiana. What are some of the best

methods to remove the coke?

DEMARTINO:We’re going to show a sketch here (Figure 2) of some demolition hammers, which is the

answer to your specific question. Later in the session, my response to question #20 will alsocover explosive demolition, hydrodemolition, and robotic demolition. Of everything we’ve seen

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in all of these refineries I talk to across the United States, basically, a rivet buster is the mosteffective. And we brought some pictures to show you on the screen of this. It’s not a great thing.Everybody ends up covered in coke dust at the end of the shift and you get bigger muscles. Thatstill seems to be the best way for the demolition.

FIGURE 2There are some robotic systems out there, but they’re one entity demolition pieces

whereas you can have six, eight, ten rivet busters working in the same unit, it gets you off thecritical path pretty quickly. There are some sketches coming up of that.

LEWIS FREDERICKSON (Chevron Products Company):I’m Lew Frederickson from Chevron. I stood up in front of the NPRA Q&A panel about

ten years ago and said Chevron doesn’t have a coking problem inside of cyclones. I haveevidence now that if you stick around FCC units long enough, the darn things will make you aliar about everything you say. PHOTO 1X

This is a sample (Photo 1x) of the kind of coke we found on the backside of the cycloneoutlet tubes in one of our FCC reactors. It’s beautiful. It’s got about a 30-inch arc on the backsideand it’s got imprints of hex mesh on that backside. It’s got very nice horizontal erosion marks on

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the other side. It was really easy to figure out where it came from. The scary part was thatexperienced inspectors were in those cyclones, and they didn’t see it. As you all know, it wasblack in there, everything was shiny, and sometimes the deposits are a lot smoother than this oneis. Unless you’re really looking for it, you might not find coke deposits like this. We missed itduring the shutdown, and when we tried to startup, a lot of this coke spalled off. It went throughthe diplegs okay, but it plugged the spent catalyst slide valve. We also had a large pile of coke inthe bottom of the spent catalyst stand pipe. We took several more bucketfuls of coke out of thetwo cyclones in this FCC unit. I fully support the recommendation the panel made - if you findcoke in the cyclones, you need to take it out. It will cause a problem somewhere sooner or later.And you’ve really got to be alert in looking for it, or you might have the same problem we did.In another FCC shutdown following the coke incident mentioned above, we tried inspecting thereactor cyclones with a video camera due to really tough accessibility. We did not identify cokewith the video camera, but when we did get someone into the cyclones to look specifically forcoke, we found deposits in the same location.

EDWIN D. TENNEY (Marsulex Inc.):We’ve also seen, or had reported in a number of our cyclones that people have had coking

in the reactors for all the reasons that were mentioned. Back in the mid-80s, we did someexperimental work with filling up the back area with some special refractory and a specialdesign. We put it into two units, and the reports that we got were good. If anybody’s interested,we’ll certainly talk to you.

The other thing Larry Carper mentioned about the difference between stainless steel andthe low chrome and the carbon steels, we’ve also seen that with regards to coke buildup on thingslike counter-weighted valves. We attribute it to the fact that the low chrome and the carbonsteels will have an oxide surface on them, and a rough surface, or much rougher than thestainless steel which, of course, is pickled and does not particularly corrode.

JOSEPH W. WILSON (Barnes and Click, Inc.):Not so much a question as a comment. I’m Bill Wilson, an FCC consultant with Barnes

and Click. One of the questions they had here was about using anchors to hold the coke in place.Another option that works sometimes, and Lou Frederickson kind of demonstrated, is that ittends to stay on refractory lined surfaces better than it does on a steel surface. This is primarilyimportant in the sense that as it forms during operation, it’s less likely to break off from a smallupset, if you have refractory lining on the outside of that outlet tube. Lou’s stayed on until theystarted back up again, apparently, and then it came off. But we actually have had one case wherejust lining that tube prevented unexpected shutdowns from plugged diplegs after spalling off theoutlet tube. So just another option to at least alleviate some of the downside of this coke buildup.I agree it needs to come off, once you find it.

Question 3. What is your experience with erosion in regenerator secondary cyclonedust bowls? Explain the effect of cyclone size and catalyst loading onexpected cyclone life. What is the experience with different refractorysystems for regenerator cyclones?

MARLOWE:The picture (Figure 3) shows what happened to our unit on our last inspection, which was

in March 2000. This is a picture of our secondary hopper on our secondary cyclone. This SunRefinery has regen cyclones that are too small for the throughput that we desire. We’ve elected

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to live with that limit as long as possible. We had to do some research with cyclone experts. Wetalked to Ed Tenney, we talked to Tony Schultz, and Kellogg specialists. About six monthsbefore our last outage in March, we decided that we were running velocities that were too high inour cyclones. We had known since ’93 that our cyclones are too small.

FIGURE 3So we presented much of what I’m telling you today to our upper management. And we

told them that in ’85, we had new cyclones. They were put in for the high temperatureregeneration. In ’89, we increased our design conditions to 55,000 bbd. We added wear plates tothe secondary hoppers to try to avoid some of this wear through on the secondary cyclones. In’95, we put new secondary hoppers in on that outage, and we added more wear plates. We alsoput some wear plates on the diplegs where we found some more wear out areas.

In preparing for the 2000 turnaround, we were anticipating to have as many as 104 wearareas that we would be prepared to patch. The history in ’89 with our cyclone wear was that wehad excessive wear to our secondary hoppers and diplegs. We were about a month away fromhole through. So we added wear plates, hoping that we would be able to run a little longerwithout having a hole through.

In '95, we did run longer. We had a five year and three month run. We had excessivewear also in the secondary hoppers, even with our improvements. We did add some more wearplates and we improved the secondary hoppers by adding some length to them and putting in 1"refractory in lieu of the ¾". But still, we were one month away from a hole through in both thesesituations.

This is the kind of wear we've seen. This is a picture (Figure 4) looking down into thebottom of the secondary hopper. And what you're seeing there is circular wear at the very top ofthe dipleg and that is what's worn the most. You can see that we lost the refractory, we lost thehex, and we were wearing into the metal. That was on the same hopper that you saw a picture ofjust a minute ago. Seven out of our eight hoppers had those kinds of holes in them when weopened them up in the year 2000 after a five year run.

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FIGURE 4

FIGURE 5But we’ve slowed our velocities down from the 86 or 87 feet per second at the inlet of thesecondary hoppers. We had given our management a choice of shutting down earlier or limitingour velocities. So we found a way to limit our velocities and we did make it to the turnaround.But as you can see, we couldn’t have run much longer. We’d have only made it maybe one ortwo more months.

That’s another picture (Figure 5) of the holes where you can see the white dusting therecoming down. Each one of those is an actual hole through the hopper area and the dipleg.

From this photograph (Figure 5) I’ve got some more comments, I guess, in relation to thevelocities. We had run different run lengths at different velocities, so we had a pretty goodhistory on this unit. We could tell that in a four-year run, before we had done some of theimprovements, we had an average velocity of about 81 feet per second at the inlet of this secondstage hopper. Then for the five year and three month run we had in our ’95 outage, we had an

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average of about 82 feet per second. So we knew that was the range that we could live with inour situation.

So we had good history, we had good inspection, and we didn’t change to anything thatwas a larger size or different, so we knew what to expect. We knew with a maximum velocity of85 and an average of 83 we would be able to hold out. And that’s basically what we’re doingnow. For our next run, we’re going to give them these same limits. We know we’re not going tobe able to wear the cyclones out at the secondary hoppers if we control these velocities.

FARLEY:Regarding the cyclones, we think it’s pretty common to see wear on the secondary

cyclones’ dust bowls. And just as the picture shows, it's not uncommon to see holes this size inthe dust bowls. Inlet and outlet velocities in the secondary cyclones are higher than the primarycyclones. That gives you a really high swirling velocity found in the dust bowl area, which leadsto a much more erosive condition.

In the primary cyclone you have high catalyst loading and that loading provides a kind ofcushion for the particles to ride along each other. The high loading exerts some drag on that gas,so you have a reduced swirling velocity.

The upper cyclone in the secondary cyclones has low solids loading so it has higherswirling velocities. Primary cyclones’ high solids loading and fairly low pressure drop meansgas usually flows down the dipleg. But in the secondary cyclones, generally, vapor comes up thedipleg, which makes for very poor conditions in that dust bowl. So it's very easy to have erosion.

KBR strongly believes you want to limit the secondary cyclone inlet velocity to about 75feet per second; we think there is more flexibility in outlet velocity, but we believe you shouldstay below 175 fps. We think that controlled inlet velocity is critical for having long run length.It's also a very common industry practice to go well over 75 feet a second on the inlet velocity.The reason is that companies want to take advantage of capacity in the unit. They have anexisting cyclone there and they can make money today by running over 75 feet a second. It'sfairly common to do that.

Increasing the cyclone size gives you a lower velocity, which gives you lower swirlingvelocities, and so you have less erosion potential. It is important to note that most people believeerosion is a factor of velocity to at least the third power (cubed). Some people believe it is evenhigher than this. There is a substantial change in erosion potential with a small increase invelocity.

We also believe that high L/D (length to diameter) ratios will improve cycloneefficiencies. However, in terms of minimizing secondary cyclone erosion, high L/D in the firststage is more useful. And then, in terms of erosion, we think it is a marginal improvement. Thisis not to say we do not believe in high L/D. This is a critical parameter for maximum efficiency.We do not, however, think this is a large factor in erosion in the secondary cyclone.

BAZIL BURGESS (Premcor, retired):My name is Bazil Burgess, and I’ve just taken a package from the Premcor refinery in

Lima, which used to be the BP Refinery there before it was sold. In the regenerator cyclone,they have a continual problem, which I believe they're planning on solving by replacing thecyclones next time. But in '93, we had a cyclone holed just below the dipleg in the secondarycyclones. We went in, installed boxes, refilled them with refractory. And on the next majorshutdown in '94, we went in, increased the length of the cyclone dust pots, and brought it backup, and took the boxes off, of course.

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We had an opportunity to go back in about two and a half or three years later, because ofa failure elsewhere in the unit, and discovered that the entire bottom half of the cone of thecyclone on the secondary cyclones had eroded to bare metal. And right at the junction of thedust pot and the dipleg, we’d eroded to bare metal there also. At that time, we didn’t have anyidea what had caused it, but we went ahead and made appropriate repairs, talked to our vendor,and he had informed us that our cyclones were borderline on length the first time around whenthey were built. And we were probably increasing our velocity. We got a recommendation fromthem on velocities for that particular cyclone, and talked to our process engineer, and he made usup a set of charts based on airflow of the air going into the regenerator, temperature coming outof the regenerator and also pressure. And we operated by that. We still had a little problemwhen we went back in in ’99, but it wasn’t as bad. We had the same circumstances. I believetheir plans at this point are to replace those cyclones, because they’re also planning on going upin capacity.

DONALD F. SHAW (Carmagen Engineering, Inc.):My name is Don Shaw. I’m currently with Carmagen Engineering, formerly with Exxon,

with about 37 years experience in the Cat Cracking business. I just wanted to reinforce andmaybe offer a few new comments to what were made.

I listed what I think might be root causes for this problem, and the assumption is youmight have a clean sheet of paper and you’re designing new cyclones. But on the other hand, ifyou’re trying to fix something during a turnaround, you might try to accommodate some of theseissues.

I think people have already mentioned inlet velocities as a key item. The numbers that Ilike to see are probably between 75 and 85 feet per second in inlet. I’ve heard people talk aboutslightly lower limits. But I think that also depends on the overall system that you have.

The other one, which I think cyclone vendors will talk about, is the L over D ratio of thecyclone bodies. At least in some circles, that is considered to be a critical aspect. If the cyclonebodies are longer, then there’s more time for the vortex kinetic energy to be dissipated before itgets into the dust bowls. Realizing again, you can’t always lengthen your cyclones, because anexisting unit that might shorten the dipleg, and you have to be able to work that out.

The other item that was alluded to is the gas outlet velocities. I think it’s pretty wellknown if you talk to the cyclone vendors, that if you have a higher outlet velocity, you generate adeeper vortex, and it’s driven down into the dust bowl. And people with cyclones that have put insmaller outlet tubes have seen this erosion occur.

The last item, which I don’t think has been mentioned, but I think we’ve seen in somecases, is a primary cyclone that’s not the best cyclone in the world and may not be as efficient asit should be, I sort of call it a dysfunctional primary cyclone. You might be putting higherloadings and more catalyst and larger particle sizes into the secondary cyclone. And sometimesthe fix is to try to improve the primary cyclone, if indeed you can.

One other comment. Obviously, everybody has done the wear plate scheme. One thingthat I guess I was surprised to see several years ago — we've seen where people have boxed in,put a wear plate on, and actually there was enough kinetic energy in the gap between wear plateand the old metallic body pieces, that the erosion occurred in that little gap, and people holethrough in that area. So, sometimes the wear plates, unless they're filled with refractory andreally tight to the surface, can be problems in that area.

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EDWIN D. TENNEY (Marsulex Inc.):We did some work on this some years ago, and we found that the shape of the hopper

makes a significant difference. And we have been putting some of those in here for the lastseveral years, so we’re still waiting to get the final results. But we have seen the same designs insome online petrochemical cyclones and there we have seen a night and day change from theerosion to no erosion.

JOSEPH L. ROSS (IFP North America):I thank you for the comment on the 82 or 83 foot a second and four and five year run

length you observed. But could you share with us the L over D and the outlet velocitiesassociated with that?

MARLOWE:Yes. I guess we didn’t really change the L over D. It doesn’t make a whole lot of

difference, from what I understand, on the secondary cyclone, but it makes much moredifference on the primary cyclone. Maybe Ed can address it, I’m not sure. We didn’t reallyconcern ourselves too much with that.

We were worried about the wear point in the secondary hopper. The location of our wearwas right at the bottom of the vortex from the cone. And we had a couple of options there. Wecould cut back the cone a little bit, and we could lengthen the secondary hopper.

We elected to do both. We trimmed the cone back a little bit so it was a little wider, afterthe cone comes into the secondary hopper. We had the secondary hopper made longer so thatwhere our vortex ended, we would be above our lower transition cone into the dipleg. So thatseemed to make a little difference. But, as you can see, it didn’t stop the wear. It still was thehighest velocity right there at the bottom of the cone.

Question 4. Who is using on-line refractory wear indicators?

CARPER:Several of our unit asset managers have asked our technology groups to investigate the

development of cyclone wear indicators. Funding did not follow the requests, resulting in nodevelopment.

I would like to poll the audience to determine who is using and who is interested. Isanybody currently using cyclone wear indicators and what type? Is there any interest in it?Please raise your hands. (Response: One).

DEMARTINO:Bill Dawes of United Refining is in the audience this afternoon. He and I came up with

an idea and we had some patent searches done on it, which is basically is to embed a material ata specific thickness in the refractory lining. We assumed that this would be more for the thinwall abrasion linings. If you’re on a stand pipe or a regenerator wall, you can do a thermalimaging, but this probably wouldn’t help you because elevated temperatures are certainly goingto tell you that you have refractory loss.

But this system is for a typical hot wall installation with a thin abrasion-resistant lining,like aa-22. What we do is embed a detectable material that is encapsulated in the material ofchoice for the thin wall of various linings - could be plastic, could be Atchem, could be A22.The material is built inside the capsule to the point that it would embed itself midpoint in a 1"lining or a 3/4" lining. As the unit comes online, and this refractory that’s in the face of this

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abrades away, this detectable material would release itself in the operational environment of theCat Cracker, or a petroleum coke gasifier.

We’ve already had some discussion with the catalyst companies that do the testing of thecatalyst for the refineries at least every week. And this material is detectable. So, in essence,what we’re saying is if you run your cyclones for 20 months and you have a release, and you pickup a certain ppm, you know that you have a problem somewhere where you had determined toinstall these devices. And if you know that you ran 20 months and you have a release, it’s time tostart thinking that in 20 months, you’re going to start to hole through some of these cyclones,diplegs or internal stand pipes or other things like that.

This is patent pending at this point. I don’t have the financial resources to marketsomething like this. And I really don’t want to be bothered. So we’ve been talking to Vesuviusand RHI and Resco and a couple of the others to see if they could purchase it and market it. It’smuch more than a company my size can handle, but we think that it’s going to help a lot ofcompanies down the line.

KEITH E. BLAIR (Valero Refining Company):Keith Blair, Valero Refining, Paulsboro, New Jersey. Frank, you were talking about

actually taking a sample stream of the internal material, whatever the hydrocarbon is off of there.Are you saying something tubing-wise is actually sampling something off of there, or is this athermocouple-type installation?

DEMARTINO:There is no mechanical attachment in electronics or pressure taps or anything like that.

This simply releases a specific material, which travels with the catalyst and won’t affect the unityou’re running.

KEITH E. BLAIR (Valero Refining Company):Okay, I’ve got you. So you haven’t come across anything where somebody is embedding

something like thermocouples halfway through a refractory lining?

DEMARTINO:We thought about thermocouples, but then you have a multitude of lines running out the

cyclone and through the shell. And it’s just a mess. We couldn’t see how you could encapsulatethe lines with A22 and then Bob Jenkins is inspecting more of our stuff, so who would want topay for that?

But on a weekly basis or twice a week, typically the catalyst companies will check thecatalyst. And for a nominal fee, they can look for this type of material. Once you say “Hey, wehave a release”, you have a potential problem down the line. And then so you don't throw 100tons of catalyst out after your first run, you have a benchmark of say 1 ppm of the material. Sothe next time you have a release in there of say 2 ppm, you have another potential problem downthe line.

BAZIL BURGESS (Premcor, retired):When we installed close coupled cyclones in '94, we put a number of thermocouples in

the cyclones going to the outside. We also talked to vendors at that time and they suggestedthere is also a possibility of using this type of cyclone or a thermocouple insulation for arefractory cyclone wear indicator. I don't think anybody has done anything with it, but it was apossibility at that time, so it's probably still suitable, because I do know the thermocouples

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they’ve got inside the reactor now are still functional, and they are the type of thermocouples thatyou would need to be able to install in the cyclones that we’re talking about.

DEMARTINO:Bazil, are these vibration casted cyclones?

BAZIL BURGESS (Premcor, retired):These are all in a high density, abrasion resistant refractory such as the plastics, the

rammables. Most of the cyclones we’re talking about do have a 1" or 3/4" of high density,abrasion resistant refractory, both in the reactor and the regenerator.

Question 5. What do you do about severe erosion of air grid nozzles? What are theadvantages and disadvantages of upward and downward pointednozzles?

MARLOWE:At the Sun Toledo refinery, we have around 1000 air grid nozzles about an inch and a

half in diameter. In the ’95 turnaround, we tried about four different types of repairs after muchdiscussion with different people. Kellogg Engineering agreed that these would be about the bestfour different methods we could try.

FIGURE 6

So we tried ceramic nozzles on the air grid on a small scale basis. We had some directreplacement and we had some oversized sleeves that we had tried in the past. We took a look atthose and we saw that neither one of those actually solved our problem. We were getting a lot oferosion and backflow into the nozzles. As you can see from this picture (Figure 6), we have acouple different types of nozzles. But the wear is pretty typical for anything that projects outsidethe refractory. We could see that you get outside wear and you get wear from the catalystrecirculating inside the nozzle.

What was interesting to us is, in ’95, once we cut back the nozzle to the refractory linesthe eroding lessened or stopped. At least it seemed that way. So we did cut a number of them

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back flush to the refractory line and we left those that had cut themselves back alone. We had anorder in for a couple hundred of the ceramic nozzle inserts, and installed around 40. That’s whatyou see with the white circles here. Actually, the picture (Figure 6) is from the year 2000 thislast spring. They start out pretty square and flat at the surface, and then wear pretty uniformly inmore of a dome shape.

The other thing we did was replace a number of in-kind nozzles and we did try someoversized sleeves that fit over the worn nozzle tips. But by far, the best thing we could see afterwe opened up on the year 2000 spring turnaround, was that just cutting back the nozzles to therefractory line worked well. Unless you have a nozzle that actually has recirculation and goesback inside the nozzle past the refractory line, you really don’t have to worry about adverseeffects. Kellogg will tell you, that you want to make sure your nozzle length still has criticaldimensions or you will still have wear problems. You have to keep a minimum dimension fromthe orifice of your nozzle out to the end, whether it’s at the refractory line or whether it’s at theend of the nozzles you put in.

FARLEY:Jim, you’re right. KBR will tell you about that. In terms of erosion on the air grid, we see

a couple of main things. And these were alluded to in Jim’s section.First, we definitely recommend the use of dual diameter nozzles. That is a nozzle that

has an orifice at the beginning of the nozzle, and then a specific length of piping before the airdischarges into the bed. The orifice takes pressure drop to make sure there is even airdistribution. That helps eliminate catalyst backflow in one section of the grid and which thengets discharged through another section of the grid. When catalyst backs into a grid on a routinebasis, it’s pretty bad. Grids just do not last.

You would generally target air grid pressure drop for around 1.5 psi, or ~ 30% of thestatic head of the bed at turnaround conditions.

And, you have to be careful about catalyst attrition, which can be caused by high velocityjets being discharged from the nozzles. This was actually discussed in 1996 at this meeting.

I would like to mention the nozzle length is very important. You want to avoid having anozzle where the orifice is located too close to the nozzle discharge; this gives you a highvelocity jet discharging into the catalyst bed because the flow is not fully developed in thenozzle. That can cause catalyst attrition.

KBR also fully refractory lines the external portion of the air grid to improve mechanicalreliability. This reduces the temperature the grid operates at as well as cuts down on thetemperature differences between the top and bottom surfaces of the grid.

There is a portion of the question about upward and downward pointing nozzles. I thinkthe industry experience has been that both types of nozzles will work. KBR prefers thedownward pointing nozzles. We believe it’s harder to plug these types of nozzles during upsets.We also believe this has better resistance to backmix erosion. We think there is somemechanical reliability to be gained by having downward point nozzles.

BAZIL BURGESS (Premcor, retired):When I was working for Charter back in the ’80s, we installed a new UOP dome air grid

and had the occasion to try several different nozzles in that air grid. We came up with twodesigns that worked for us. First of all, we coated the dome itself with 1" of high density,abrasion resistant refractory. At each hole for the nozzle, we installed ceramic nozzles with atapered configuration that would match the flow distribution as it came out and the inside was

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rounded so we had an exact diameter for the orifice. That worked fairly well, both the ceramicwas hard enough for resistance similar to the refractory, and when we came back down andlooked at it, we had actually maybe just a few signs of some erosion in the nozzles, but very littleif any at all. They probably would have gone for several more runs without any trouble. We didhave a flow problem, because the designs we were given were based on a square edged orifice,and we put in a rounded edge orifice.

So we changed to a design similar to that which Kellogg mentioned where we’re lookingat a section of pipe with an orifice at the bottom. I believe that’s about a 4 to 1 ratio on the pipeand the length. But you should consult someone else on that, since it’s been a while since I’vedone this work. But what we did is we used a thin wall piece of pipe, either tubing or somethinglike Schedule 5 or Schedule 10 stainless, and we put the top of the pipe right at the surface of ourrefractory. This worked exceptionally well. What would happen is you’d get a polishing of therefractory on - we were looking at 1" thin wall pipe. We had about a 6" diameter polishing of thetop of the refractory, and the metal was barely worn after several years. So I would anticipateagain, that design also would work for several years. This was reported to this meeting probablyin the mid-’80s.

RICHARD BINKS (Dynamic-Ceramics Ltd.):Good afternoon. Historically, there has been a problem in joining ceramics to metals due

to the difference in thermal expansion. Dynamic-Ceramics has got around that by patenting adesign. What experience does the panel have in joining ceramics to metals and getting aroundthe problem of the differential in thermal expansion?

MARLOWE:You mean as far as attaching the two?

RICHARD BINKS (Dynamic-Ceramics Ltd.):Yes.

MARLOWE:This was a Corhart design. It was a ceramic insert inside and it had two pieces of steel

outside the ceramic. There was one piece of steel that was shaped for the header similar to asockolet. And then there’s an outer pipe sleeve on top of that. And those two pieces werewelded together and that locked in the ceramic insert. Of course, there’s a little gap there so youhave this difference for thermal growth.

RICHARD BINKS (Dynamic-Ceramics Ltd.):Did the gap cause you any problems for vibration?

MARLOWE:On vibration? No. We didn't see any cracking or anything like that if that's what you’re

referring to.

JOHN PRICE (Corhart Refractories):John Price with Corhart Refractories. We're the ones that manufactured the Corguard,

and the one that has come up with that design. We've used it in other areas other than the air gridnozzle, but what we do, because the thermal expansion differential is about half of that of thestainless steel, we allow enough play on both sides of the collar to take care of that expansion

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and have the surface sealed with the gaskets on both sides so that you can allow for thatdifferential to take place within the nozzle or within the joint and still then, just you’ll be weldingthe steel to steel whether you’re on a pipe grid or a dome or whatever. And we haven’t had anyleakage that I’m aware of since we’ve gone to that two-piece design. Initially, there was a one-piece collar design that relied too much on the installer to make sure that the seal was good, andwe had a few installations where there were a couple that leaked. But when we went to the two-piece design and we controlled the sealing of the ceramic to the steel in our shop, then thoseproblems went away.

Question 6. Compare wet gunning of refractory materials in a coke impregnationservice v. regular gunning. Are the shell temperature (k) values or testresults affected? Is coke impregnation affected?

DEMARTINO:We have the opportunity to do either wet or dry, based on the application of any specific

turnaround. The big thing you have to remember is if you have enough volume, and I’m sure theother competitors will agree with this, by the time you set up all your equipment and slick thehose, get your mixes just right, waste the first ton up in the unit to get it nice and gelled and theproper water/cement ratios, you can dry gun by that time.

If you’re doing a few hundred square feet or a thousand square feet in your regenerator oreven your reactor, there are some wonderful pluses to doing the wet gunning of refractories.There’s no dusting. The application is extremely precise versus the dry gunning. There are nolaminations. Plus you can have multiple crafts doing simultaneous workscopes like studwelding, scaffolding modifications, stick welding all at the same time. So, it really has a chanceto reduce some of the critical path that you may have on your turnaround. The waste factor isdown around 5%, maybe a little bit higher on the overhead applications. And the set times of therefractories that are being applied can be adjusted.

There are retardants that can be put into it so it gives you a little bit more working time.The material will gel, but it won’t have an exothermic reaction right away. Those are the obviousadvantages to wet gunning.

Applications can exceed ten tons an hour, if you have continuous feed mixers and a tenton per hour rockvalve swing tube refractory pump.

Question 7. Has anyone used a “no cure” refractory and has the experience beensatisfactory?

DEMARTINO:The “No cure” refractory that we dealt with made by the John Zink Company is called

Thermbond. It uses an acid as the liquid to reduce the heat cure schedules sometimes down tozero. We have gunited the material in large quantities and have hand applied it to many areas ofCat Crackers.

There are pros and cons to these types of materials. If you're hand packing, ramming orcasting them they are a pleasure to work with. Gunite applications require a large amount ofpersonal protective equipment. This is due to the dust and the acid used for wetting the materialat the nozzle. Some applications may not be justified for the use of such materials due to the fact

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that the cost and time of application may outweigh the cost and time associated with the heatcure.

CARPER:I am not aware of any low or no cement castable used in our units. The question you

should ask yourself is why do you need to use them? If the argument is you want to save time onthe startup due to refractory dryout, seriously challenge the argument. These units aretremendous in size and you cannot heat them fast enough. Our approach to refractory dryout isquite simple. Use the total installed cost approach with repairs which includes refractory dryout.

Before startup, we have a multi-disciplinary team review the refractory repairs, includinglocations, refractory types and quantity of material installed and the startup procedure. By thetime you start the air blower, perform an air test, purge the reactor, light the air heater pilot, loadcatalyst, heat the catalyst, light the torch oil - this is a slow process. The vessels and catalyst arelarge heat sinks and the start up process is sufficiently slow enough to avoid adding time forrefractory dryout.

DEMARTINO:I would agree with you in the reactor and the regenerator, but we’ve had the opportunity

to apply these materials in the air heaters of the Cat Cracker. They weren’t heat cured and wereramped up to operating temperature quickly with no spalling at all.

Question 8. What is the experience with form and pump casting technique v. wetgunning refractory?

MARLOWE:In talking about refractories, at our refinery, we’ve got a lot of different refractories. The

units are pretty old, have been there since the ’70s. And we try to replace part of the walls. In theregenerator, we try to get about a third of it done at every major turnaround, i.e. every four orfive years. We try to take a certain square footage of the regenerator and try to get it replaced.We know, in talking with our refractory specialist and others in the business, that you’re notgoing to get that refractory to hold up too much longer than 15 or 20 years without having someproblems with it spalling, cracking, deteriorating to the point where you’ll have hot spots.

Well, we had some material here that we’d already replaced and it was less than 15 yearsold, and we were getting hot spots. So, we had some refractory that was not cured right, notmixed right, or it wasn’t exactly the right material. Between 1995 and the year 2000 for ourturnaround, we actually had to cool our regenerator walls with some steam spray nozzles. So wewere concerned, and we were monitoring, getting thermal pictures to make sure that we weren’tgetting larger or different spots.

But it turned out to be only in the upper third of the shell on the regenerator. And wewere planning on replacing this with conventional refractory. In the meantime, we heard aboutsome people that were trying some of this pump casting material. Some of our corporate peoplegot together, went and saw, and got some information from people who had seen this materialfirst-hand after it had been in service for a while.

We went back in with about two-thirds of our regenerator with this pump castingmaterial, so this is a picture (Figure 7) of what it looks like when they forming up one of thesections. They stack on top of each other and keep moving the forms up. It doesn’t take it a reallong time, and we’re very hopeful that this is going to hold up just like it has in the couple of

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locations we’ve seen. We’re hoping to get 15 or 20 years without any spalling or cracking. So thisis one of the options we have over a light gunned refractory material.

FIGURE 7DEMARTINO:

The system that Jim’s talking about is a patented system. Including myself, we cannotinstall this. But there are some other, maybe slightly better ways to approach the installation.

For form and pump casting, you would start by welding a 3/8" carbon steel stud onspecific centers. You would attach a naturally a footed anchor around the stud, and then a flarednut to retain the base of the footed anchor. Screwed to that would be a piece of 3/8" stainlesssteel rod that has a thread for a few inches, and then a little bitty dent or “snap configuration”, sothat it can be removed once the pumping is done. After that it would have another nut, and thenthere's a fender washer. This would support the Masonite or plywood. On Jim Marlowe'sphotograph, you could see this plywood and 2 X 4 whaler that's two 2 X 4's with a 3/8" spacerbetween them. A rod would come through the 3/8" spacers, have another fender washer and anut, and then what you would do is simply fill in this cavity with other refractory that you wantto use.

Once that's complete, you simply strip everything out to this point, put a pair of vise gripson above the snap configuration, torque it, and it would snap off, and would certainly fill thatlittle void up with the refractory that you were pumping.

With the lightweight and the medium weight refractory, it's a non-issue. When you startto get up into the higher density refractories, there is an issue with cracking, I guess it's likepouring a concrete driveway and you're putting a column every six feet. You're going to get amyriad of cracks from this stud to the next stud to the next stud, because just in the pouringapplication, you're going to set up some tremendous stresses with the higher density refractories.But for the medium and the lightweight refractories, it works well.

There are some other systems out there to circumvent the patent system whereby they'llbuild a set of wooden welders or rent steel forming systems and have supports back to thecyclone system. But please bear in mind, by the time you set all this up, and you may havemultiple crafts involved, because the carpenters want to do it and the iron workers want to do it,and everybody gets involved in some of this stuff. By the time you set up this form system, you

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could shotcrete it. Again, you need quite a bit of volume just to warrant the application. Right,Jim? You need more than 100 square feet.

MARLOWE:Yes, ours was a large area. Say 20 feet tall and the circumference of the 35 feet diameter

regenerator.

DEMARTINO:Right. The other thing I see, if you drop a coffee cup in there or something like that,

maybe a pair of glasses, but that’s still within spec, if you know what I mean ( laughs ). You dohave some issues with making a cavity and filling it with refractory.

Question 9. What is your operating experience with a slide valve that has “boltless”internals?

COUSAR:During our October 1999 revamp, we installed boltless slide valves in place of our

existing Regenerated catalyst and new Recirculating catalyst slide valves. Our experience withbolted slide valves is that the bolts coming loose tend to cause the valve to ultimately fail (Figure8 “Bolting Failure”). During every turnaround in the past, we would have to repair and/orreplace these bolts. We'd end up cutting the bolts out and tacking the nuts back to the orificeplate anyway. The boltless design seems to cure these problems; however, we haven’t had a fullrun with them yet. (Figure 9 “Boltless” Weld-in Design”) (Figure 10 “Traditional vs. BoltlessDesign”).

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One problem that we had was due to a design anomaly. The Recirculation valve is veryclose to our combustor due to our structure limitations. The radiant heat affects the recirculationslide valve body in such a way that there is up to a 250ºF differential across the valve. The valvewas designed to have less than 100ºF across it. Due to the thermal difference and the tighttolerances in the slide valve tongue and guides, the slide valve tongue would hang up at 60%open. We solved this problem by installing a 1" thick thermal blanket on the bottom of the valve.Since then, we have had no problems operating the valve with up to a 150ºF differential across it.

Question 10. What do you use to purge the slide valve stem? Are there any advantagesfor a “purgeless” system?

CARPER:I am aware of success stories within the heritage BP units using “purgeless” slide valves.

However, I am also aware of two miserable failures.

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Both failures were on flue gas valves. Damaged items included stems, stuffing boxes andactuator seals due to the catalyst laden gas. We were not able to determine the root cause for thefailures. Our solution was to revert to purged valve stems.

For purge control we currently recommend restriction orifice plates. We have usedrestriction orifice unions which leak and restriction orifice valves, ROV’s. We foundmanufacturing variances in ROV’s which eventually lead us to restriction orifice plates. Purgemedium is dependent service. We recommend using steam or nitrogen for regenerated or catalystcontrol valves and air or nitrogen for flue gas valves. If you elect to use steam, ensure the steamis properly trapped and dry. The preferred medium is nitrogen.

We size our restriction orifices using an exit velocity criteria. We design for a limit at 90feet per second at the annular area between the stem outside diameter and backseat bushinginside diameter using downstream conditions.

MARLOWE:As Larry talked about there are many mediums you can use for purge. We do purge the

stems of our slide valves - our spent catalyst slide valves and our regenerator slide valves, andthe purge medium that we use right now is steam. Not necessarily as dry as we'd like to have it,but it's what we have available. We do restrict the flow to these purge connections. The optionsthat we have for purge in our refinery are steam, air, and nitrogen. We've tried all these purgemediums in other locations, and some of them are on our butterfly valves, usually dry orificedair.

Right now, we've just installed three new Enpro butterfly valves out of about six orseven butterfly valves we have on our Cat Cracker. For each of those Enpro valves, themanufacturer recommends we either leave it purgeless or that we can purge it partially. We'veelected to see if we can go purgeless, and so far, so good. We've had one packing that gave us alittle trouble and will continue monitoring, and the other one seems to be holding up very well.

But the flow, the amount of flow, and keeping the flow consistent is always critical to anyof our purge systems. It seems like you can't go four or five years without having some kind ofupset or interruption to the purge medium, whether it's in your purge system or in other systems.Once this happens the risk is not getting the purge back or becoming less and less effective.

As soon as you get a stop of the flow or you get too much flow or too little flow you areheaded for problems with the purge. Too high a flow gives you a lot of circulation and getscatalyst flowing in there and you're going to wear some things down. If you don't have enoughflow, you're going to plug things up with catalyst and you might not be able to clear it back out.You need to try to establish the right flow just like Larry was talking about, and keep it there asconsistently as you possibly can and hope it doesn't stop to the point where you plug things up.

COUSAR:We have experienced slide valve stem erosion from too much purge and coking of the

packing area with too little purge (Figure 11“Too Much Purge” and Figure 12 “Too LittlePurge”). We currently have all purgless systems on slide valves (Figure 13 “Purge-less StuffingBox”).

We did experience a packing failure, but it was due to an engineering bust related to thespring can hangers on the slide valves. We have since installed the proper springs to remedy theproblem. We do recommend that a detection system be placed on the “purge” port. If a failure ofthe primary packing occurs, the detector will sense it and more packing material can be addedinto the packing area thereby sealing off the leak.

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Question 11. How have stud welded refractory anchors held up in service? How longa run did they have?

DEMARTINO:Stud welded refractory anchors have caught on, it appears in the northeastern United

States, and have performed extremely well, but it seems to be less accepted out West. We haveinstalled about three million stud welded anchors in seven years with minimal failure. When wetalk to the customer about the hex anchor productivity rates, they’re three times faster than stickwelded hex steel linings. There’s also reduced labor, because we’re using bricklayers versusboilermakers. The welding flash hazard is near zero, because the flash is contained in theceramic ferrule, so just safety glasses are acceptable, you don’t need a welding shield.

With the single power source, you can stud weld with up to three guns nearlysimultaneously. If you pull the trigger on two of them at the same time, they will not actuate. Butif they’re seconds apart, they will actuate. So there’s some reduced costs in equipment use.You’re going to get a more consistent weld application, and it’s a very, very easy weld test, whichis an AWSD1.1. And all that means is you’re going to put a an apparatus over the weld and bendit 30º to one side, 30º to the other side. It's not like taking a 20 lb. sledge hammer and makingthe anchor look like a tortilla until it falls to the bottom of the unit, and the inspector says hethinks it's no good.

The savings are about 40% over the hex steel applications. And there have also beensome of the refiners (I won't mention names) who have been through at least two runs on theirCats with the hex anchors and the v-anchors and things like that. It's a wonderful way to savemoney, especially if you're going up in cyclones hex steel.

I think I have photos (Figures 14 and 15) of a cyclone that we were doing. That's a studwelded hex anchor that happens to be made by Causeway. This is a cyclone conical shape. Weput premier Atchem in there, and that was for Foster Wheeler cyclones for China. The jobturned out very well. A little bit tougher to stud weld a specific pattern in a conical shape ratherthan in a barrel.

FIGURE 14

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FIGURE 15

MARLOWE:I wasn’t aware that a lot of people were afraid or worried about the stud anchors because

our experience at Sun has been very, very good with them. We've been using it in '85 '89,’95,and the year 2000 turnarounds. We put in stud anchors, and most recently we stud lined the K-bars for the air grid. But we have had good experience with them. I don't know whether that'sjust because we make sure we put them in right or we make sure we get the surface preparationyou need. We did some testing on the stud anchors and came to the conclusion that they werejust as apt to bend and break at the anchor as they were to snap at the weld out.

This picture here (Figure 16) shows the surface of our regenerator, and as you can see, wehave had the stud welding and we've had the stick welds and anchors on the surface. But thereare still some areas where we have the stick welds. We do prefer to use the stud weldingapplications. It's much faster and easier to use with no adverse problems related to the manyinstallations that Sun has.

FIGURE 16

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DEMARTINO:There’s one more application. Working with Bob Jenkins and doing some vibration

casting of refractory applications, they recommend that anchors be solution annealed beforethey’re installed, because the heavy vibration, if they’re not solution annealed, have a tendency tofatigue and snap during the refractory installation. But if you stud weld the carbon steel stud,which you see in the flared nut and put the solution-annealed anchor onto it, there’s no heataffected zone from re-welding a solution-annealed anchor to a carbon steel. It probablydecimates the solution annealing of it anyhow. It seems to help out some of the otherapplications that we have.

Question 12. We have experienced extensive cracking on a 304H stainless steel lineand its welds due to sigma phase change after 25 years of service. Whatis the life of 304H stainless steel and can its remaining life be predicted?

MARLOWE:This relates to 304 stainless steel material, 304H specifically. I know we’ve had

discussions about this before at the NPRA meetings, and about Cat Crackers and concerns aboutwhat is the predicted age for how long can you live with 304 stainless steel material.

We’ve been concerned about that for quite a few years and in ’95 we did find quite a fewcracks in our overhead line between the third stage separator and our power recovery turbine. Wefound some cracks and we sampled those for sigma phase, some samples had up to 9 % sigmaphase. Our ducting is over 20 years old, and we were getting these cracks, and we wanted toknow if we were going to have a shorter life than we were anticipating.

We found over 200 cracks at that time and we did repair them. We had welders in therealmost the entire turnaround time, over three weeks, and were able to grind down and repair mostof the cracks. Most of the cracks were related to cracks in the weld area or the heat affected areain the parent metal. But the majority of it was right around the heat affected area and the weldsfor the 308 rod material. Larry’s going to have some comments in that direction.

Between the ’95 and the year 2000 turnarounds, we ended up developing some veryserious cracks on stream. We developed an 18" crack along this area (Figure 17). This was alongour 30" bypass line that goes around the PRT (Power Recovery Turbine), and it ties into a 54"line, where the two lines come together (Figure 18). We had to bring in specialty people sincethis was 1350oF material with catalyst fines coming out. We brought in some specialists withaluminum suits and cooling devices and were only able to work twenty to thirty minutes at atime. They had to put stiffeners across this crack area (Figure 19) and boxed it up on each end.Then they put additional material on top with valves to vent off away from themselves. It was arather expensive repair and this didn’t stop our problem. We had to do another one before ournext planned turnaround. They estimated that they would be back within 40 days, and 40 days itwas. So once it starts, you really have a big problem.

We were able to get this 304H line out of service and change it during the turnaround, sowe were glad to get this behind us. We still have a few other pieces of 304H that are over 20years old, but they’re not in the same temperature cycle.

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FIGURE 17

FIGURE 18

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FIGURE 19

CARPER:Well, just looking at the picture there, I’ve seen similar and it looks too familiar. The

crack is through the center of the weld. We installed a PRT at one of our refineries in the early’80s. Shortly afterwards we began experiencing weld failures due to stress rupture.

This forced us to look at weld metals. After several years, a weld metal study concludedE308 filler metal was not optimum. This resulted in changing our specifications from E308 toE347 filler type weld metals when welding 304 stainless steels. We found the stress ruptureproperties of E308 filler metal were about 80 percent of the parent metal at elevatedtemperatures.

The design for this duct was to use minimal or no corrosion allowance. Use as thin ofsections as practical and 100 percent radiograph the welds. In the mid ‘90s we experienced afailure through the middle of a weldment. Repairs consisted of replacing a section of the duct,decreasing the operating temperature and pressure, and developing a long termrepair/replacement strategy. We eventually replaced several sections of duct in key areas andreplaced the filler metal in many of the longitudinal seams.

Currently we specify E347-16 as the filler metal when the operating temperature is above1000ºF and use E308 when the operating temperature is below 1000ºF. We also recommendcontrolling the ferrite number below 6.

I had an opportunity to visit one of our refineries in Europe earlier this year. The PRTwas the same vintage. In looking at the system, the duct wall thickness was substantial whencompared to the previous unit resulting in substantially lower hoop stresses. A result was theywere not experiencing weld failures.

ROBERT GOSSELIN (ExxonMobil Refining & Supply):Robert Gosselin, ExxonMobil, Beaumont. We've had problems, just like what you're

talking about, but it wasn't as old as your line. We had a line that was in service for close to 26years. We had problems all throughout the 26 years. We put a new line in. Less than 4 years, wehad the same problem again. What we found - what you mentioned about the ferrite content - ifit was too low, you had cracking when you welded. If it was too high, you had cracking when

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you started up. We felt like the problem was during the startup going from low ambienttemperatures to operating temperature. So we put acoustic emissions monitors in the locationswhere we had problems and kind of listened for cracks, basically.

But EPRI talked about a different rod. It was, I don’t remember now, it was an E1864,something like that. I know the numbers are wrong. E1682. We haven’t tried it yet, but we’rehoping maybe that will help. But I guess the only thing that I’ve heard as far as a solution fromthe panel was basically thicker metals to give you lower stress to extend the life. Is that prettymuch the only solution? I guess one of the concerns, one of the options that somebody proposedwas use a different material. But I don’t know what else. I think that anything else would be waytoo expensive. I guess I’m asking if anybody had experience, even looking at a different metal,that was affordable to use?

CARPER:We looked at other filler metals during the study discussed earlier. An alternate welding

electrode was E16-8-2. We found this welding electrode was not readily available during a late1980’s project. The cost was prohibitive when compared to E347. E16-8-2 has about 95 to 105percent of the stress rupture properties of the parent metal. Like I said earlier, one solution is touse thicker metal.

BAZIL BURGESS (Premcor, retired):All we're talking about right now seems to be ductwork. Has anybody had any experience

with cyclones? I've had sigma phase cracking after about ten to twelve years in cyclone welds. Isthis common also?

CARPER:Bazil, we've seen cracking in cyclones. A solution is to design the cyclones and

especially the hanger system for lower stress. We have seen very little sigma phase cracking inour cyclones and we have one unit where the cyclones are 36-37 years old and another withcyclones 33 years old.

BAZIL BURGESS (Premcor, retired):Also on the ductwork, has anybody considered using refractory lined carbon steel,

because back in the late '80s, that's what most of the refineries were going to.

MARLOWE:No, we had looked at just what other stainless steels would be acceptable for material.

Since we weren't considering this line to be redesigned we stayed with the 304H, as we didn'thave the time. We might look into that later.

DEMARTINO:What would be the temperature of this, Bazil, if you were going to have a carbon steel

and put a refractory on the front of the tube? This kind of points to carbon. What kind oftemperatures are you looking at?

BAZIL BURGESS (Premcor, retired):I've actually run overhead lines made out of stainless steel with AA22 in it at 1450oF

design temperature at about 50 psig. We did replace that piping with carbon steel, 5" of abrasion

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resistant refractory at a later date, probably in the late ’80s, early ’90s. So that was the solution forus at the time for regenerator overhead line.

DEMARTINO:Okay, but there’s not an issue since you put such a massive amount of refractory that

you’ve reduced the cold wall temperature. Do you need some kind of a membrane system,because you’re riding the carbon?

BAZIL BURGESS (Premcor, retired):Well, with what I just described, you’re running about 400 o F - 500 o F shell temperature

on that line, and you’ve increased the size of it. Again, the point is, you’ve increased the weightof it so you’ve got to go to new hanger designs and a whole lot of other things. But, with theproblems we were running into with stainless, that looked like the best solution for us, becausenot only were we getting sigma phase cracking, we were getting thermal fatigue cracking,because the shell wall of the line was so thick that we were actually getting cracking on theoutside due to expansion of the outside wall from pressure from the inside of the shell, and thenwhen it tried to shrink, it couldn’t. So we started getting cracking there, also. Between those twophenomena, we decided it was safer for us to go with the cold wall, when we had to change it.

JOSEPH W. WILSON (Barnes and Click, Inc.):Bill Wilson with Barnes and Click. Just as a point of clarification, I believe the gentleman

from Sun mentioned this was a line that was tied into a flue gas expander. In that particularcircumstance, you wouldn’t want refractory on that line at all, because if it comes loose and goesthrough the expander, it will take out the rotor pretty thoroughly.

Question 13. Is anyone experiencing problems with E309 stainless steel weld crackingin high temperature service and extended age (>10 years)?

MARLOWE:This question pertains to a problem that hit home with us. We have a reactor head that is

a low chrome material, but it also has a SS clad liner inside of it. This was in the flue area of theplenum. It’s all lined with a 410 strip material or a clad 405 material. And where they make thewelds, the dissimilar metal welds for the attachment of the liner, they used a 309 rod. And as aresult of that, we were suspicious that we’ve had a defect that has started and propagated at thatlocation,

During a run between 1995 and the year 2000, we did get a crack to the atmosphere in thedollar plate at the top of this head. It turned out to be about a 40" long crack along that area. Butit had propagated itself all the way out from the liner dissimilar metal welder out to the surface.

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FIGURE 20

So it took some time to get to this condition and it was complicated by some flexing ofthe platform at the top. It was a combination of the defect being generated and then propagatedby the flexing of this platform at the top. To make the repair, we ground out all the crack andwent back in and got rid of the 309 rod connections, ground that out, too.

That’s a picture (Figure 20). Here it is where we had to grind out the area where the oldwelds were, and then welded it back up with new 309 rod. So we ended up at the turnaround,went in and repaired all of the defect areas that we could find in the top of the head. Hopefully,we’ll replace that head at our next outage.

CARPER:As part of the study discussed earlier, we also looked at E309-16 weld rods. We found

E309-16 welds to have poor stress rupture properties. There was also difficulty in controlling theferrite number. The ferrite numbers ranged from 7 to 15 with an average around 11.

Currently we restrain ourselves to using E309-16 for bimetallic structural welds andwhere the structure is not critical. Our metallurgists are recommending using Incoweld A andInconel 182 filler metals for 300 series stainless steel to carbon steel bimetallic welds.

II: ROTATING EQUIPMENT

Question 14. What is the state-of-the-art for air blower discharge check valves?

DROSJACK:The question here concerns check valves in the air blowers failing. And we’ve seen them

do that once in a while. Whenever that occurs, the problem is you get the catalyst back there.You turn your air blower into a catalyst hopper. And that’s not what they were designed for. Andin terms of why is this a bad thing, the question is what happens?

In the best of cases, you’ve got to get the catalyst out of the air blower. If you’re reallylucky, we’ve had the occasion where you can open the case screens and actually just pour it out.

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That’s kind of lucky, but more often than not, you have to open the machine up and cleanit out physically. Okay, that stuff is going to take you a day, a few days.

The next thing that occurs, even if you get the catalyst out, in a lot of cases, putting hotcatalyst into the air blower cases, which really aren't high temperature machines, can cause themto distort, and you can end up with flange leaks and sometimes warping the things bad enough tocause the machines to rust.

If you really get yourself in bad shape, you can end up with a more catastrophic failure.And in that case, you might be able to drop catalyst in the machine while it's still rotating, butwhat might be more likely is you don't know you've got catalyst in the bottom in the case andyou restart the machine again, with some catalyst in there. If you have an axial air blower, you'vegot a good chance of blowing all the blades off of it.

So if you look at the whole scenario, you're going to lose a day, two days, three days,maybe up to ten days if you're lucky, and have all the parts available. If you don't have sparerotors, if you do severe damage to the case, your time can go on up from there.

But the issue here is it is not a good thing to have your check valves fail and let thecatalyst get back into the machines. Some of the other guys here are going to talk about whatkind of check valves we have and how they work.

MARLOWE:We have an Atwood-Morrell check valve for this type of service and we have a couple of

refinery locations that have this check valve. We have them in Toledo, also. We're alwaysreconditioning this and repairing it at each outage. We've never really had an incident where itbackflowed for us through the blowers.

But we have had that situation at our Philadelphia Refinery, and they've had some seriousbackflows turning their blower into a catalyst hopper, like Mike mentioned. But they arechanging their specification and they're looking at some improvements so they wanted me topass along that they have a new design specification and Adams is a brand that is able to meetthose new improvements. They're going to try the Adams in their unit this fall when they havetheir shutdown. They'll also have some kind of actuator that's going to have automatic flows onit, so it will be a little quicker response time.

FARLEY:At KBR, we generally look at the Atwood-Morrell swingcheck or isocheck valve. It

seems to be the world leader. Every time we've looked at units, it's the valve we tend to comeacross. And I'd like to reiterate what Mike talked about initially on some of these types offailures.

These are not theoretical failures, OK? These things have happened. Units in the industryhave been down 30 days because a check valve in this service failed. Insurance companies haveestimated losses of upwards of $55 million from one incident of a check valve in this servicefailing. It's absolutely critical that this valve works.

Having said that, a good way to make sure the valve works is to always do properpreventative maintenance (PM) checks on this valve. Generally, these valves have an actuator,they're counterweighted, and they have some sort of assist to help this valve close. It's importantto periodically exercise these things. Make sure these valves aren't hung up or frozen in place. Ithink several locations have had problems where the proper PM was not done. These PMprocedures were generally listed either in the technical bulletins from the valve manufacturers orin the original documentation with the valve. We always urge you to follow these PM

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procedures. That’s generally the most significant problem we’ve seen with these types of valves,that the PM procedures were not followed.

BAZIL BURGESS (Premcor, retired):I can certainly testify to the problems they cause, because I had the opportunity to repair

an axial blower that got hot catalyst in to it. But I would like to make one other point that somepeople might not think of, and I certainly didn’t at the time. The first unit I worked on was adirect line up and down from the blower to the regenerator, a Peabody heater was right under theregenerator, and it was a straight drop to the axial blower.

On the unit I worked on recently, the blowers were slightly farther away, and the pipingactually had a trap, similar to what you have underneath a sink, where the air line went down andthen up into the Peabody heater, and then that was actually above the level of the catalyst in theunit. And in that unit, although it’s a 50 year old Cat Cracker, from what I’ve been able to seefrom the records, they’ve never had a problem with catalyst getting back in their blowers. So youmight want to take a look at piping configuration to help you prevent major damage in yourblowers.

UNKNOWN:Yes sir, I think this question was originally mine. What we’re looking for is an alternative

to the flapper type check valve. We’ve had all the bad experiences that the panel and other peoplehave named. Except we have radial blowers, so we haven’t wrecked a blower. We have pluggedit up where we had to take it apart several times. What I’m wondering is has anybody had anyluck with something like a trip valve? Not a trip throttle valve, but a trip valve like on a turbineor any other non-swing type check valve.

BAZIL BURGESS (Premcor, retired):The first unit I worked on with the axial blower actually had a trip check valve on it. The

problem we had is that we were not testing our trip mechanism and as a result, when the checkvalve was caught un-operated, it didn’t work. So if you do get some kind of trip valve or tripcheck valve, you need to make sure that you’ve got a way of testing it without shutting your unitdown while you’re online, and that needs to be done at least once every three months.

DARRYL BERTRAM (BP Amoco p.l.c.):Darryl Bertram, BP Australia. We recently installed a Mannesman axial movement check

valve on our resid unit at Kwinana. And to date have had pretty good service from that. It’s afairly expensive option compared with the traditional check valve, but it offers quite lightpressure drops compared with the normal lever operated swing check type valve. So that mightbe an option for the gentleman as something different to look at.

FRED COLLIER (Williams Energy Services):I’d just like to reiterate the fact that when you’ve got this check valve, PM is so important.

And most of them have these big weighted arms on them and when you walk by those valves, ifyou’ll just shake those weighted arms - you can’t move them far, but you can move them justenough to make sure that flapper stays loose. And if you love your blower, if you love your CatCracker, you’d better shake that handle every once in a while.

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Question 15. How many refineries have a emergency lube oil supply tank thatsupplies lube oil in the case of a pump failure?

DROSJACK:In a number of our refineries, we have rundown tanks in the Cat Crackers and other units.

Some of them are just a head tank. Others have nitrogen pressure on top in case the lube oilpumps give out for whatever reason, power outage, what have you.

One of the things to understand about these, though, is they’re only rundown tanks. Youcan’t have a big enough tank to run the machine until it stops. And you have to be tied into thetrip so that you quit producing any head out of the blower, whatever is attached to, you shut stuffoff. And it only gives you a very short period of time to run down to get most of the load off themachine and then it’s going to coast.

We have not had serious incidents in my experience, in our Cat Crackers. But we didhave a number of years ago a catastrophe at one of our refineries in which we had threeassociated ethylene plants with nine compressors. The one that had the rundown tanks did notdamage any of the rotors. The two that didn’t had to change out the rotors and it scored thempretty badly.

Question 16. What factors should be considered in changing the main air blowerdriver from a steam turbine to a flue gas expander?

DROSJACK:This concerns why or what you do if you want to change your main air blower driver

from a steam turbine to a flue gas expander. And there’s a couple of things you’ve got to look atthat are pretty important. One is your pressure ratio. How much power you can actually generatefrom the expander itself, and see if it’s worth the cost. The second one is turnaround intervals.The expander power recovery trains are going to be one of the shortest lived machinerycomponents in the Cat Cracker. And if you look at the life - there’s some discussion of that later -most everybody can get two years, a few people have gotten six years, and you’re going to besomewhere in the middle. And part of the issue you have to look at is how long you’re planningto run this unit between turnarounds, because it’s quite likely that that power recovery train willbe the limiting factor on the run length between turnarounds.

Another part of this is what your separation system does. The separators are one of thebig drivers in terms of how long an expander can run. In a minute I will show some picturesabout the ugly things that can happen if your separation system isn’t up to snuff. If you don’t havea good one, don’t think about an expander power recovery turbine in there, because you’re notgoing to be very happy.

And then maybe one last factor. If you put one of these in, there has to be room. You’regoing to need maybe 15, 20, 30 feet of physical space to drop the machine in. And then another20 or 30 feet of horizontal run from the inlet pipe if you want to have any hope of beingsuccessful. So one of the things you do have to have is a fairly long open space at the end of yourair blower to get this thing in.

Those are some of the principle issues in terms of just deciding. And one of the big thingsis economics. It’s going to cost you a fair amount of money to put one of these in. And thequestion is whether that power recovery is really worth the cost of putting that machine in.

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BAZIL BURGESS (Premcor, retired):A couple of other things you probably need to consider is that normally, if you lose or

have to dump your air or something like that, you risk over-speeding the entire train. So youneed to make sure that you’ve got some kind of mechanism to control the speed of the unit sothat you can dump the flue gas going into your expander before it gets above some kind ofcritical speed, dictated by your vendor. That’s one thing you need to look at.

And the other thing you need to look at is these are going to start up differently from astandard blower. Normally, your expander will provide 100% of your power during operation ormaybe some percentage lower, depending on how you design it. But you have to have either asteam turbine and/or an electric motor to start up and get up to operating speed. The unit Iworked on used a steam turbine up to about 3200 RPM, and then kicked in a 4,000 HP motor tocome up to speed, the remainder of the time. And that motor was an induction motor and acted asa brake also, to slow down the overspeed so that the control systems could catch it.

Other than that, with a little bit of care and thought in installing it, I don’t see any reasonwhy you shouldn’t be able to get four to five years out of an expander. We started off not quiteknowing how to operate it. And by the time we learned how to operate it and how to maintain it,we were easily expecting four to five years out of it.

Question 17. What is the affect of the third stage separator on the power recoveryturbine’s performance?

DROSJACK:There are two effects of malperformance or lack of performance on a separation system.

One is simply that passing too much catalyst will cause fouling. It will cause deposition ofcatalyst either on the blades or in the worst case, between the blade tips and the shroud. And thisis what can happen (Figure 21). If you look at this, this isn’t supposed to have a piece missing.Between the blade tips and the shroud, the machine may have 60 to 100 or so thousandthsclearance. If that fills up with catalyst and the blade tips rub, you can generate thermal cracksand then you’ll cause a piece of blade to fall off. The crack can progress and have a piece fall out.This thing is about as big - I have a blade up here if anybody wants to look at it later - it’s abouthalf as big as a half dollar. And in terms of this machine, that accounts for about 1 or 2 mils extravibration. And the issue here is if you lose these pieces, you unbalance the rotor, and you get tothe point where you simply can’t stand the vibration.

This is a rotor that just came off (Figure 22), and if you look closely, you can see thenumbers 1, 2, 3, 4, 5, 6, 7. Those are the pieces that fell off during the course of about six monthsor a year on this particular machine. Before we brought this down, it was putting out about tenmils vibration. To have some perspective on that, you could feel this thing moving the groundabout 300 yards away from the machine. And the only reason we ran to this point in time wassimply to get to a particular time when we could shut this down. This type of failure is not thatunusual. Many of the expanders will have tip cracking. An awful lot is seen from the catalystdeposition. And then some of them will progress to have the blade tips fall off. So that’s thedeposition issue.

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FIGURE 21

Next slide shows another problem that can occur (Figure 23). This is erosion. If theseparators are not separating out the large particles, passing too many of them, they’ll blast themetal away on the machine. And these particular blades are made of waspalloy. They’re coatedwith D-Gun. And that’s pretty hard stuff, and you see what happens here. This has gone throughthe D-Gun into the waspalloy. This is after two years of operation. At the end of four years, therewould have been a hole through here, or somewhere between three and four years. And a lot ofthat is tied to how your separator performs, whether or not you’re going to make it. When thisoccurs, one of the things that happens is you’re going to lose performance. You’re going to losehorsepower, because you’ve screwed up the aerodynamic flowpath. The other thing that canhappen, this erosion will progress to the point where pieces start to flake off the end of the blade,and again you get into unbalance.

This kind of phenomenon occurs in all expanders. The question is how much you see inyours, whether indeed the erosion is sufficient to shorten your run length and whether it can runas long as you want.

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FIGURE 22

FIGURE 23MARLOWE:

We were concerned about these issues before our spring turnaround. We have a Shellthird stage separator that’s been in service since ’74 and we’ve never done any major work on it.We’ve had some issues with expansion joint cracking, but as far as the ceramic sleeves that are inthere and the swirl tube arrangement, we’ve never really done anything with it just inspected it,patched the ceramics a little bit with some mud and let it go. But the concern was when does it

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become a problem? What kind of clearances do you need to look for? What kind of wear shouldyou really see on a third stage separator? So getting involved with that investigation and findingout what to look for, was really the challenge.

I did contact Jason Horwege at Shell Technology, and he had some different scenarios forus to look at. He had one scenario if you saw some wear quite often, and had problems withyour unit periodically, or another if you had a long run. He gave us something else to look at,and some of the things that I can share with you. He said the design clearance was originally fora thermal growth plus approximately 0.1" for the fit up between the ceramic can and the stainlesssteel swirl tube. He said that the performance loss is proportional to Pi, as the Pi number timesthat clearance. He related that a 5% increased opening would be like a 5% efficiency loss inyour third stage separator.

So we looked at our history, looked at some of the different criterion that he gave us, anddetermined that we’d been running well for quite a long time and we really didn’t know what ourclearances were, but we assumed that over time, we had had some wear. So we took Jason’snumbers and figured that we would be somewhere between 30% and 50% range for areplacement of the ceramics and the stainless steel swirl tubes. This would probably guarantee asafe run for another four years.

So he agreed to that. And so we decided that of the 120 that we had, we’d take out 40 inloss. That was our game plan for the turnaround, and when we went in there, I just marked theones that had the worst clearances. When we looked at it, the clearance had probably doubled insize over that 20 or 30 years, but it still was not that noticeable. So we did have a good runningunit and we didn’t have a problem up to this point. Replacing the number of ceramics and swirltubes that we did will only help avoid a future problem and make our next run on the separator asuneventful as in the past.

DROSJACK:One more comment following onto that. This was after a two-year run. On this same unit,

applying some of those fixes, after another two years, we had blades which didn’t have anyerosion. And it does work. One of the other things that’s done with that is you can use isokinetictesting on the stack dust samples to determine how much catalyst is coming out and what the sizedistribution is and use that as one of the triggers as to when to work on the separator.

CARPER:Last fall, we had the opportunity to go inside a third-stage separator. The separator was in

service since 1981 and ignored throughout the years. This was one of the first opportunities totake a good thorough look.

There are 144 tubes in this separator, one of the larger separators. Thirty-eight percent ofthe top outlet tubes to tubesheet welds were cracked. Over 85% of bottom tube sheet welds werealso cracked. The ceramic liners were in relatively good shape. I can’t remember precisely howmany we replaced. It was an insignificant number.

The cracks were in the welds. Again, we suspected a E308 filler metal issue. Tomorrowduring the workshop session a discussion on PRTs and separators is planned.

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III: TURNAROUND/MAINTENANCE/INSPECTION

Question 18. How do you inspect an expansion joint when the unit is in operation orduring turnaround?

CARPER:This is a question we have struggled with for many years. There really isn’t a good

answer. Sorry, but your options are pretty much limited, about what you can and can’t do. Theitems of interest are the bellows and hardware. Today, bellows are usually packed. You do nothave a good method of inspecting internally unless you remove the internal shroud. Shroudremoval is risky. You risk damaging the bellows. Similarly for an outside inspection. Werecommend removal of the external shroud and penetrant testing the bellows including theattachment welds. Internally, we recommend ensuring the packing is intact and repairing anydamage due to erosion. We are hearing stories of people using fiberoptics to inspect bellows. Iam not aware of any of our plants attempting this and if anybody has any stories, please sharewith the audience.

We also recommend inspecting the joints for travel from the cold to hot positions andcomparing the actual travel to the design travel. If it’s traveling way beyond its limits, find outwhy, make the adjustments. There just really isn’t a good way to inspect an expansion joint.

MARLOWE:If you do have a problem with your expansion joints, it’s good to inspect them before the

turnaround. So if you can get the shrouds off, you can get some scaffolding up there and get alook at them. At least you can find out if you’ve got a problem before you come down. So Irecommend that you try to get an inspection and bring in one of the expansion joint inspectors.And that’s what we did, and we were happy to get that all done ahead of time so we had a knownindication if we had a problem within the shroud.

LEWIS FREDERICKSON (Chevron Products Company):I’ve got some more specimens of my failures. First of all, for those of you that haven’t

been inside an expansion joint, this is a sample of the braided metal hose that seals the gapbetween the moving parts of a packed expansion joint (PHOTO 2x).

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These braided metal hoses come in different form and with different attachment methods fromthe different vendors. My recommendation when you’re buying a new expansion joint is to getthe closest thing to bullet proof you can find.

If this braided metal hose is intact in your expansion joint when you’re inspecting it, it’svery difficult to see anything that’s going on inside the expansion joint. You can just check theexternal refractory and the condition of the internal sleeve. If the braided hose is damaged or outof place, it can be the forerunner of bigger problems. We shut down one of our FCC units lastsummer. We inspected a two-element cold wall expansion joint in the regenerated catalyststandpipe. Many cold wall expansion joints depend on a kaowool pillow (Figure 3x) forinsulation to keep the bellows elements cool. As has been discussed previously, the two majorfailure mechanisms for expansion joints are corrosion because they get too cold or embrittlementbecause they get too hot. These kaowool pillows also come in several different forms fromdifferent vendors. The expansion joint we looked at last summer had this kind of insulation. Ourinspectors found the braided hose displaced in the upper quadrant in both elements. Weinspected behind the braided hoses with a boroscope, and found the wire mesh part of thiskaowool pillow. We did not find the kaowool. It looked like the kaowool had been sucked out ofthe wire mesh covering. Of course, this meant that we had lost the insulation in this location. Westuffed new sections of kaowool pillow into the void to prevent the bellows from overheating foranother year of operation.

PHOTO 3X

BAZIL BURGESS (Premcor, retired):How you test your expansion joint really depends on what kind you’ve got. Basically on

the market now, you have a single ply bellows and a two-ply bellows that is either testable or hasan online indicator on it. If you’ve got a single ply bellows, about the only thing you can do is avisual test on it, unless you want to go to the expense of putting blinds inside the line and doingan air test on it. That’s usually not allowable, due to time and several other considerations.

About ten years ago, several manufacturers started coming out with what we called atwo-ply testable bellows. Both plies on the bellows are designed for the full pressure andtemperature of the system. There is normally a little wire mesh inside of the two plies, and thatgap had a vacuum pulled on it to as near absolute as they can get it, and then the bellows is

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sealed before it’s welded onto the shell. Some of them, you have to test those or put a pressuregauge on them or something of that nature. At least one manufacturer has a device that willindicate whether that vacuum has been broken or not.

My recommendation is to put two-ply testables and at least one manufacturer I know ofcan put these bellows on your existing expansion joints for you, if you want them to. But thatwould be my recommendation, simply because even when you’re online, if one bellows goes,you’ve got the other bellows that is in there, in place, that will carry you to the next turnaroundand you can either test it before the turnaround and during the turnaround, and that will tell youwhether you need to replace it. But you’re operating safely at all times, and that’s the mainconsideration. I’ve worked in too many of the single plies that have cracked and had to berepaired.

LEWIS FREDERICKSON (Chevron Products Company):I just want to add to my earlier comments. I fully agree with Bazil’s recommendation for

two-ply testable expansion joints, monitored onstream and also vacuum tested during shutdownsto make sure you’ve got no leaks on the plies.

Now when we install new expansion joints, we are also working with the vendors toinclude a temperature monitoring system so we can tell what temperature the convolutions areactually operating at. We have those on a couple of expansion joints so far, and we have foundsome very surprising results. Expansion joints that we expected to be running hot are runningcolder than we want them to be. We have actually added more external insulation.

ROBERT BROYLES (Senior Flexonics Pathway):Bob Broyles, Senior Flexonics Pathway. I just wanted to reinforce the issue regarding

bellows temperature and monitoring the bellows temperature, because we have been followingthis issue of dewpoint corrosion now for several years. I believe it is a significant problem. I dohave with me a sample of bellows, 625 bellows, that have failed due to dewpoint corrosion, forthose who might be interested. But bellows temperature measurement should definitely be part ofmonitoring of bellows operation online.

Question 19. How do you determine when it is time to retire an expansion joint?

CARPER:Retiring bellows is a risk management question and this up to the individual refineries.

Some of the refineries prefer to run two to three campaigns between bellows replacement. Thereis a limited amount of data on the number of runs between replacement. Currently we areextending the run lengths on some units and are very much concerned about when to you retirethe bellows. Previously we saw three to four year run lengths and now we are attempting five tosix year run lengths between turnarounds. You figure 3 six year run lengths between bellowsreplacement - eighteen years between bellow’s replacement. Is that the time to retire bellows?

Basically, your historical data, is probably the best guide. Last year we replaced threeexpansion (rotation) joints, excuse me, two expansion joints. These joints were in service over 25years and had not experienced any problems with the bellows. They were initially purged jointsbut the purge was disconnected several years ago allowing the bellows to fill with catalyst. Thesejoints were on a spent catalyst riser, side-by-side unit. The reason for replacement was concernfor bellows age and the hinge hardware was failing.

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We have another expansion joint at one of our refineries that was placed in service in1956. Still in service, never replaced. The bellows metallurgy is 347 stainless steel. We do notknow when we are going to replace the bellows. I can assure you, when the time comes we willhave a nightmare due to accessibility. We know we will have to face replacement one of thesedays!

So, the smart answer is, retire them right before they fail. But you’ve got to find thatperiod in time. The next best answer is not to use expansion joints, period. This is the strategy weattempt to achieve. Earlier this year I had the opportunity to visit one of our refineries in Europe.This unit has a PRT also. You think you have nightmares, this unit has 38 expansion joints fromthe top of the regenerator to the precipitator inlet.

FARLEY:This question was covered some in the 1998 session. I think it was question number 13.

And I believe that question talked a little bit about dual-ply bellows. This is a question that weget asked quite a bit. And from what KBR can tell, we generally see people in the industry goingbetween 10 and 20 years for replacement of expansion joints. This is based upon the inspectionreports from previous turnarounds. And really, the impression I have is that it’s based more onheightened concern at each location where people have the concern about making it through thenext run. We see that driving a lot of replacements for expansion joints. Really, you’d say thecriteria are pretty shaky, but 10 to 20 years is what we typically see.

BAZIL BURGESS (Premcor, retired):I had a lot of trouble in the ’80s with single-ply bellows, and I’ve never managed to get

enough courage up to extend a run on a single-ply bellows over 15 years. So, you know, if that’sany help anywhere between 10 and 15 years on a single-ply bellows is the best I couldrecommend.

Again, the recommendation is replacing any single-ply you’ve got with two-ply, and thenrun until that indicator tells you you’ve lost one of those plies. And then you can run until thenext shutdown on the one that’s remaining.

Question 20. Is there a better way to remove thick wall refractories than by chipping?Hydrodemolition? Explosive demolition? Robotics? Please describe yourexperience with any of these new methods.

DEMARTINO:Let me run down what I found out in talking to some of the refineries.Robotics is used on a very limited basis. If you have maybe a single line where you can

put a single person in it, robotics may be a good method of repair or removal. Explosives, Ifound out, are rarely used, due to the fact that if you don’t have the proper explosives, there’sbulging of the units that can occur. I’m not saying it doesn’t work, but you have to have arelatively scientific methodology to it.

We’ve seen a lot of the hydrodemolition come of age. The problem you’re going to havethere is taking care of the water, because there’s a tremendous amount of water that runs out thebottom of the unit. Sometimes they’ll take a 30 cu. yd. dumpster, run the water into thedumpster, and then let the solid settle out and let the water come out over the top, so there’s someless sensitive issues with the back end of the plant where they would treat the water.

Still, everything we’re seeing, it’s mostly chipping guns. And there are machines outthere that are relatively slow hitting, but they’re very hard hitting, and they can shear through

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bolts, and they can shear through the shell. And they even have the capabilities to remove thevibration cast lines.

There’s also a rivet buster. Anyway, that’s the most widely used thing. We had one ofour customers last year on an RCC turnaround that had never heard of them, and they flew up toour office to witness ARC spray metalizing and the demolition with the rivet buster. Typically,in one coked up area in the refinery, they put seven shifts in for the coke removal. They werefinished in one. So it just gives you an idea of some of the ways that materials can be moved.

BAZIL BURGESS (Premcor, retired):I’ve had a lot of experience in trying to do that. A couple of points that need to be brought

out. Fresh refractory that even if it’s cured, will be easier to take out, but the longer that’s in yourunit, the more coke that is embedded in the refractory on your risers, which is mainly where thestuff is, the harder that will be to get out. Now after two years, I managed to do somehydrodemolition on a riser with the same company, with the same equipment, with the samepeople, two years later, they couldn’t cut the stuff. I’ve done it with chipping. It takes a lot of timeand it’s almost not worth it. The best recommendation I could come up with is let your refractorygo as long as you possibly can, (I’ve taken it down to three inches) and then plan on doingcomplete replacement the next shutdown. And by complete replacement, I mean just cut the riserout and put a new riser in. That’s actually going to be the cheapest way for you to do that job andthe quickest.

Question 21. How do you remove coke from cyclones and other areas in the reactor?How do you know when you are done? What safety and operationalconcerns have to be addressed?

DROSJACK:We’re talking about removal of coke and I think the answers are pretty similar in that the

chipping guns are the most common application in our facilities. We did do some workattempting to use explosives. When we did that, it got some of the coke off, but the cyclonesdidn’t like it too much, and we rattled them pretty badly and damaged them.

The same comment on the high pressure water. One of the issues with the coke is just theability to get the guns access to the coke as well as the fact that you’ve got to dispose of a lot ofdirty water.

CARPER:We saw one unit which filled solid with coke from the top of the cyclones to the top

head. The reactor dome steam was cut off as an energy conservation measure. This was a realnightmare for removal. There were pockets of pyrophoric iron sulphide which ignited uponexposure to air. We ended up breaking up the coke using blasting technology. One detonationwas too close to the vessel and resulted in a hole in the top head.

The bulk of the removal was completed with chipping guns and rivet busters. Onceremoved, we inspected the cyclone hangers and found deformation due to the excess load. Thehangers were strained from the weight of the coke and the restraints imposed by theincompressibility of the coke. The coke formed while the cyclone hangers were thermallyexpanded. During shutdown or cool down, the hangers thermally contracted and the cokerestrained the contraction. We found the hangers had severe deformation.

The word of warning is, if you get into a similar situation that bad, take a look at yourhangers system for distortion. Typically cyclone hanger systems are not designed for the excess

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weight of coke. They are designed for the weight of the cyclone plus the weight of the catalyst.So you might want to review your designs.

FARLEY:Not so much related to removal of coke, but instead to minimize coke formation,

especially in units that run resid (a portion of the feed that boils at very, very high temperatures),dome steam can be very useful to minimize coke formation in the top head of the vessel.Important warning, though, is that the steam has to be bone dry. You don’t want to have anyliquid in that steam that goes into the top of the vessel. That’s been known to cause moreproblems than the dome steam ring not being there.

Other steps to minimize coke formation have been addressed earlier. Riser operation cangreatly help minimize coke formation.

Question 22. What innovative techniques improve turnaround effectiveness?Inspection (thermal imaging, digital imaging, etc.)• scaffolding• blinding• refractory removal• chemical cleaning

COUSAR:One task that is always in the critical path of turnarounds is scaffolding. Once you are

down and obtain vessel entry, scaffolding is the next step. We have successfully used the Excelbrand of scaffolding. This scaffolding, in our opinion, is the most easily erected scaffolding thatwe have seen to date. This scaffolding helped shave a tremendous amount of time off our recentturnaround. Two identical scaffolding jobs performed within our Regenerator are compared(Figure 24) “Regenerator Scaffolding Comparisons”). They were built to perform exactly thesame function to get to specific places in the upper regenerator.

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The scaffolding’s unique design allows construction of most angles required. Thisallowed our inspectors to have the best footing available when crawling up in and around thecyclones. Other benefits of Excel scaffolding are that no tools are needed for assembly, it hasbuilt in ladder components; personnel can climb through hatched decks, node point rings allow360 degree placing of up to 8 bars, vertical leg heights are in 11” increments up to 9’ 7”, anddiagonal braces are not needed with gusset designed bars. (Figure 25 “Excel Scaffolding”).

This jig-stand that we built during our October '99 turnaround is an example of theversatility of Excel scaffolding (Figure 26 “Jig Stand”). It was a fully engineered structure withPE certification designed to hold 300,000 lbs. It was designed and erected in 12 hours by 5 men.

FARLEY:There's been a big push the last several years. Once oil is out of the unit, the issue is to

minimize time until maintenance can get into the unit. And a lot of people think chemicalcleaning is the way to speed up that time, and therefore shorten the overall turnaround duration.This was a question that came up in the 1998 session here. Basically, several people have

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proprietary processes to do this and some of the ones that have been mentioned are U.L. ZymeFlow and Phillips Lifeguard Process.

These processes will actually remove benzene and all hydrocarbon (zero LEL), so by thetime the vessel is opened up, generally you have pretty good working conditions formaintenance. The issue is that these services are not free. There is a cost that goes with thesechemical cleaning methods. You have to look at the time savings versus the price you pay to dochemical cleaning.

My personal experience has been pretty good with the processes. I’ve had pretty goodluck with cleaning the fractionation systems and I have seen them pay for themselves. I urgepeople doing this for the first time to devote serious effort to working with the contractor youchoose to make sure this goes smoothly. It does not take that much of a schedule delay to giveup a significant portion of your cost savings.

MARLOWE:On our last turnaround, we used thermal imaging ahead of time to try to determine where

we had problems. And as I talked about before on the regenerator wall, that gave us an idea howmany square feet we had in our major problem area, but it also helped us find out throughthermal imaging any other spots that we would need to repair. So it helped us with our planning.

Our inspectors all had digital picture cameras. We had six or eight of those during theoutage, and we recommend that highly. We could take those pictures the same day and take themto an extra work request meeting and talk to our managers about this repair. It helpedtremendously in getting the word across and getting the explanation as to why we need to dorepairs. And also that was available for a turnaround report almost immediately after theturnaround. And we brought in inspectors who could help us write the reports right off the bat, sothose are all good things to have for these outages.

CARPER:One of our refineries has a standard 30" gate valve in the reactor overhead line. During

each turnaround, the refinery pulls the bonnet to remove the coke. The valve is used only duringstartup. During shutdown, a blind is installed. Prior to startup, the blind is pulled and the valveclosed. The valve is opened during startup and the disk locked open with a pin. Theoretically,this procedure saves time during startup.

Scaffolding was mentioned previously and I just wanted to share a recent experience.Last weekend we hired a contractor who used rope access technology for an inspection effortinside a regenerator. Let us call the experience a learning experience with limited success. Weunexpectedly shutdown a unit and needed to look inside the regenerator for the cause of acatalyst loss. Term the experience as a limited success, we learned a lot, learned limitations andapplications. This technology is something you might want to consider.

DEMARTINO:Oh, here are the demolition hammers (see Figure 2, page 7). All it is is a very slow

hitting, 40 lb. hammer that’s made to shear through vibration casting and coke. And just to touchon the coke, I’ve gotten a couple of samples and I had them sent up to Rutgers in Livingston,New Jersey. I had them soaked in liquid carbon dioxide, and the teacher pulled them out, andyou’d think he would smash it with a hammer. Nothing happened. So the next thing we weregoing to try was CO2 blasting, hoping we could thermal cycle it back and forth to ease removal.But based on putting it in a frozen environment, tapping it, not a damn thing happened. That’s

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our method of removal for refractory, even a vibration casting; we get some results, but it’s notgreat. It’s not a place you want to be chipping.

BAZIL BURGESS (Premcor, retired):I’d like to add to what Larry Carper commented on. In the Lima refinery, we had a 36"

valve in the position between the regenerator reactor and the fractionator. And we had the sameproblem that he’s discussing where it would coke up during the run, nothing we could do to stopit. And in our ’94 shutdown, we replaced that valve with a through conduit valve, which has anormal block and bleed system on it. It’s built into part of the valve mechanism. And we havehad several instances, now, of being able to use that valve. In fact, one time we had to use it wasright after a fire, which was right underneath the valve. In every instance, the valve opened andclosed when we needed it to, and we were able to document a 24-hr savings over blinding onstartup and shutdown to justify the cost of the valve.

DARRYL BERTRAM (BP Amoco p.l.c.):Darryl Bertram, BP Australia. Just following on Larry’s comments about rope access, at

our Kwinana refinery, we have made pretty extensive use of rope access techniques. Typically,for these unplanned, unscheduled shutdowns where process engineering might just like to have alook in cyclones and what-not. It’s very important, though, from a safety perspective, to get theright sort of people involved, to have the people who, if you’re going to use your own people forit, to make sure they’re trained, and most importantly, quite confident in the techniques. But it’s aworthwhile thing for inspecting areas where it’s unlikely you’ll find a large amount of work to do,but you do need to have a look.

KEITH E. BLAIR (Valero Refining Co.):Keith Blair, Valero, Paulsboro, NJ. I am hoping to poll the audience on the question.

We’ve had a running controversy among refineries as to the effectiveness and the viability ofwashing down a regenerator as you immediately shut down a unit, open it up and want to get asmuch catalyst out as possible. There are varying philosophies saying that the washing down is agreat thing, it gets rid of a lot of catalyst. But then, there’s also the drawback of where it goesafter you’ve washed it down. And I would like to see if through a show of hands, if each refinercan possibly have one person raise their hands, to see if they do wash them down?

HAZLE:If I understand correctly, you’re washing down the regenerator with water. How many do

that? Washing down a regenerator with water to remove catalyst? Four.

CARPER:We typically wash down the regenerator in order to improve the dust situation and

enhance the inspection effort. Our metallurgists recommend using a 2% soda ash solution for theregenerator internals. Like chicken soup, you are not sure of the benefit but, there is no harm.

KENNETH BLAIR (Valero Refining):I understand that. I guess the question I really was placing was where does it go? How do

you get it out? What do you do with it when it comes out? And does anybody find that to be of amajor drawback to doing it in the first place?

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CARPER:The water is collected and properly disposed.

KEN GOTTSELIG (Koch Petroleum Group):I’m giving a talk tomorrow on our incident in the regenerator where we were soda ash

washing and ended up with through-wall cracks of the regenerator wall, the carbon steel portion.So if anybody wants to know more about it, you can talk to me or come over to the presentationtomorrow.

DONALD F. SHAW (Carmagen Engineering, Inc.):I just wanted to add or reinforce, I think somebody on the panel mentioned earlier to

reduce downtime, I think a lot of our refineries have started integrating the dryout process with astartup procedure and not where you’re drying out refractories, not treat it as a separate operation.And that may be something people want to look at.

FRED COLLIER (Williams Energy Services):Washing a regenerator with water is pretty dangerous, especially if you’ve got stainless

steel inside it. 304 Stainless is really susceptible to polythionic acids. And it’s a triangle, you’vegot moisture, air and sulfur, and when you’re putting water in there, you’ve got a very importantpart of that triangle. So I’d be very careful about putting water inside regenerators. There’s a lotof ways of getting that dust down besides putting water in there. So you ought to think aboutthat. It would be very disastrous.

LEWIS FREDERICKSON (Chevron Products Company):In response to the question about washing down the regenerator, Chevron tries to avoid

doing that due to all of the stainless steel components. When we have done it we built a damunderneath the regenerator collect the catalyst and then suck it up with a vacuum truck and haulit away. We don’t think our refinery sewers can handle the amount of catalyst that we generatefrom washing the regenerator.

Question 23. What innovative contracting strategies reduce turnaround duration andcost and/or improve effectiveness.

COUSAR:We have implemented three innovative contracting strategies at Williams. The first is

what we call the “dream team” approach. This approach allows for one contractor for eachrequired discipline. The dream team is a collection of specific contractors that provide specificservices (Figure 27 “Dream Team). If a company is very good at pipe welding, let them weldpipe. The same follows with scaffolding, insulating, refractory lining and so on. By keeping thescope of work for each contractor down, we keep that contractor’s best people focused on theirparticular scopes of work. By selecting companies to provide personnel for one particular craft,you get their best people. If you expect them to provide all crafts, they will end up sub-contracting the work. This tends to cause your top-notch crews to sink into mediocrity. Mostorganizations will need to add a contractor to help administrate all the contracts and track thetime. This method also allows the flexibility to contract with the individual contractors a varietyof contracts to suit their work (i.e. time and material, lump sum, etc..).

The second strategy is the use of what we call a “SWAT Team”. We plan for and budgeta select group of crackerjack boilermakers, pipefitters, and fire/hole watch personnel on both the

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day and night shifts. This group of 12 to 16 people per shift makes up the “SWAT Team”. Thisteam is used to perform work at the sole discretion of the project/turnaround manager. Whenevera problem arises or an area needs speeding up, simply point and shoot. This group helps keepthings on or ahead of schedule as well as takes care of larger items that come up unexpectedly.This was a very effective tool for us during our recent turnaround.

The third strategy is the use of the target price contract. The target price contract issimilar to a lump-sum contract, with both parties sharing in overruns and underruns. Thiscontract simply allows the two parties to identify and agree upon the suppliers and contractorsthat will work together. It is all about setting a common goal with incentives that drive each partythrough a high degree of teamwork. This unique concept allows the comfort of lump-sumcontracting, yet it also provides the flexibility to purchase goods and to contract services that arepreferred without the dreaded “change order”. Significant changes in scopes are agreed upon andtaken into account in the total target price.

DEMARTINO:I would just have a question. It appears you're hand-picking a few guys from each

company. There's got to be a what-if scenario, and it happened to me last November. I was fullyinvolved in two Cat Cracker turnarounds, and I had another 100 people doing other jobs acrossthe country. And we failed pretty well on one of our turnarounds. We couldn't send one of ourbest customers some of our best people. And do you ever get faced with that kind of scenario?

COUSAR:We maintain excellent relationships with our key contractors, and we get them involved

early in the turnaround planning process. We let them know in advance what we expect as wellas encourage them to help develop the turnaround plan. We do insist on getting the contractor’sbest people, and if they cannot be provided to us, we will seek alternate contractors.

DEMARTINO:Okay. The problem I see with that scenario is, you have the Exxons and Mobils of the

United States, now. And some of the other big mergers happen, and I had conversation withExxon and Mobil about this. They have the biggest hammer in the country, now, and they

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demand that they get the right people all the time. And somehow, someday soon, that’s not goingto be fair to the other refiners. We demand. And it’s not going to happen on every job. It can’thappen on every job.

COUSAR:I agree, but the combination of the relationships we maintain with our contractors and the

involvement in planning we give to our contractors has been successful for us thus far.

DEMARTINO:One of the things we’ve done is come up with a strategy which I guess some of the other

people have used out here. For a lot of the T&M (time and materials) work that we do for therefinery industry, my rates include all of my company’s own equipment. There's no way tonickel and dime the owner companies, much to my dislike. So our day shift and night shift ratesinclude all the equipment, include all the per diems, and even go so far as to include themobilization and demobilzation fleets. So they see one set of rates, and there are no hidden costsfor an extra 10 or 15 chipping guns per shift. So that's kind of a unique way. Since we starteddoing that, we haven't lost a contract that we bid.

BAZIL BURGESS (Premcor, retired):One thing that we did at the Lima Refinery is set up an engineering team with both

maintenance engineers and technical experts on metallurgies, piping and what have you as atrouble-shooting team. Your inspectors are always finding problems. And these people, theirsole purpose on the refinery during the shutdown is to come up with solutions for thoseproblems, and it takes it out of your supervisor's hands, it gets it right up to the managers, and ithelps speed changes through your system when they're needed.

The other thing that I've seen done in the past is most of the time you're alwayswondering where you're going to get air, where you're going to put welding machines. I've seensix and eight packs stacked up on the deck where you know you're going to be doing a lot ofwelding. This normally saves a lot of time with the welder trying to find where his machine hasto be adjusted and that type of thing. And then if you need air, on your structure in particular,what I've seen done is an extra pipe run up the structure with hose stations on it so you can hookup portable machines down at the bottom to provide air all the way up the structure. You don'thave to worry about running hoses. You don't have to worry about large hoses, anyway. Youdon't have to worry about pressure drops in your piping up there to where you need the air. Soyou've got enough air for your jack hammers or anything else you need. This can all be doneprior to the shutdown, and all you've got to do is hook a short welding lead and run it into theunit when you get it open. That's all.

IV: PROCESS/PERFORMANCE-RELATED ISSUES

Question 24. What are the driving forces for selecting catalyst blends?• selectivity/yield• hardware changes• erosion/attrition

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COUSAR:Refineries select from a variety of catalysts to meet specific yield slates based on

economic factors. Because we operate a resid FCC, we utilize both fresh catalyst andequilibrium catalysts to provide our conversion as well as bottoms upgrading. We rely on thefresh catalyst to provide the foundation of our catalytic conversion and selectivity. It isformulated to achieve a desired yield pattern as well as be resistant to attrition, thermaldeactivation, and metals deactivation. The purchased equilibrium catalyst (Ecat) provides aneconomic alternative to fresh catalyst that allows us to maintain unit activity by controllingmetals levels and at times has supplemented for catalyst losses. We have evolved over the lastseveral years from using primarily Ecat and supplementing with fresh catalyst to using primarilyfresh catalyst and supplementing with Ecat. This approach has become a necessity in order toachieve our selected yields as our cat feed has continuously gotten heavier and the metals andcon carbon levels have increased.

We also add various catalyst additives to make more subtle changes in the yield structure.Additives such as ZSM-5 influence the yield of LPG olefins. These types of additives are usedas an adjustment knob to tweak a yield pattern to achieve a certain yield structure, but theprimary catalyst used to drive our cat is the fresh catalyst.

FARLEY: I stress working with your refinery economic planning group when you look at catalyst

formulations; these guys are pretty valuable in giving you direction as to where you want to shiftoperation. Do you need more LPG, more gasoline, is octane important? It’s really important forthe process people in the operation to have an understanding of this. And you get thatunderstanding by working with the economic group.

In terms of things like hardware changes that drive catalyst shifts, there’s really not thatmany. You look at recent revamps and consider the recent technology pieces that are used, andfrom our experience, the number one thing we see that shifts a catalyst blend would besomething like a riser termination device. There are a lot of different names for these types ofdevices, but basically they all fall under the category of something that reduces residence time inthe reactor vessel. Generally, people start looking at a lot higher activity catalyst in the FCCafter this type of revamp to recover some conversion. There have been some cases where it’s justnot possible to get the activity on existing catalyst that refiners want. So there’s been a catalystchange associated with that.

Other revamps that may have, in select cases, a catalyst change, would be feed nozzles.Generally, you can lose a little bit of octane with a feed nozzle revamp. And in some locations,that’s pretty important. Octane barrels may have very high value. You want to do something torecover that octane. That may not be catalyst, it may be temperature. But catalyst is one optionfor that. Changing reaction system residence times (changing volume in the riser) maynecessitate a change in catalyst.

I’d also stress that in today’s environment, it’s pretty interesting where you have a lot ofproduct specifications that are very important today that weren’t important, or not as importantten years ago. Things like gasoline olefin content. And you see some pretty severe catalystchanges being made to make these specifications. I think people need to start looking atsomething like an olefin barrel value. You don’t see that commonly in the U.S. today, but it’s areal problem. You look at units in Japan and places in the U.S., gasoline olefin content is veryimportant in selecting catalyst.

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MARLOWE:We have high velocities in our system at Toledo, and that’s related to the cyclones so we

do have a higher attrition, probably, than we need. It’s not a selection criteria at our location.And it’s really not a selection criteria anywhere in our refineries in the Sun system. But you canselect catalyst blends with hardness considerations. And with less ability to break down or attriteand create much finer particles than you want. So that is something that you can work out, butyou do have to do that in your own location with the requirements that you have there.

ROBERT A. LUDOLPH (Sunoco, Inc.):Just to add to some of the comments that Jim made, in the area of hardware changes. In

almost every location that we made hardware changes, especially when we upgraded our feednozzles, and in a couple of cases where we changed the riser residence time, meant that therewas a major change in the catalyst formulations that we used in the unit. In some cases, we wentto an activity change, but we found pretty quickly that we needed a selectivity change along withit. And in particular, we found that there were some technologies that some of the suppliersoffered that we couldn’t take advantage of because they offered active ingredients that forwhatever reason, we couldn’t employ. When we put in those technologies, we found we openedup the portfolio more, and we had more options, especially seasonally.

When it comes to erosion and attrition, I’ll also add to that fluidization. We’ve found insome of our units that fluidization is more of a concern than erosion or attrition resistance. Thereare differences in what we have seen with different suppliers’ products. Harder does notnecessarily mean good things. It’s been pretty good when it comes to regenerator losses, but itactually has done us some harm in ash increase in our slurries. So I’d be careful with gettingsomething that’s harder than you’re more accustomed to running.

Use your unit to tell you what’s a good operating area based on your expander vibrationsthat may result or your slurry ashes that may result. And work with that as your baseline, and usethat with the information that the supplier has in their portfolio to specify a proper product foryou.

BAZIL BURGESS (Premcor, retired):For those of you who have hot gas expanders that have had a problem with buildup of

catalyst on the shroud, you might want to look at changing catalyst if you can’t solve the problemany other way. Back in the late ’80s, we made several changes, one of them being catalyst. Andall of a sudden, we started having that problem, where we did not have it before. So we had notgotten around to identifying that particularly, but that’s something you might look at.

JOSEPH W. WILSON (Barnes and Click, Inc.):Just a couple of other things you might look at when you start thinking about catalyst.

There are catalyst properties, mostly physical properties, but some reactive properties you canchange to deal with other problems in the unit. For example, if you have an increase to a catalystwith a higher particle density, it can have an affect on the amount of losses from your regeneratorin your opacity. If you change to a catalyst with a lower total void fraction at minimumfluidization conditions, it can sometimes help overcome problems with an overloaded or aninefficient stripper, and reduce your regenerator temperatures and product loss that way, inhydrogen on coke.

The activity change that C. J. mentioned in response to an improved riser terminationdevice, this can also be used on units that are pushing their catalyst circulation limits in the slide

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valves and the stand pipes to get away from those limits by reducing the cat/oil ratio required toget the desired conversion that you need.

Question 25. What are the sources of FCC catalyst metal contaminants such aspotassium, iron, sodium, calcium, and zinc? What are the remedies formetal contamination? Are FCC feed desalters the answer?

FARLEY:These are not necessarily your typical contaminants. For contaminants like potassium,

iron, sodium, calcium, and zinc, sources can vary. Most of the time, it’s feed related. In ourexperience we’ve seen zinc associated mainly with lube oil or motor oil; several locations arerunning used motor oil through their process units.

I think everybody pretty well knows sodium is a bad actor as far as it actually physicallydestroys portions of the catalyst by attacking the acid sites. Potassium is very similar. It’s not assevere as sodium, but it’s bad. Calcium acts in a similar fashion. Zinc also has a similar type ofattack. The industry has done a lot of work in the last few years about iron. We've seen a lot ofpapers about the effects of iron contamination.

The main problem is that it is hard to account for variations in feed contaminant loadingson a day to day basis. Generally, people only make changes upon seeing moves in the FCCequilibrium catalyst properties. This introduces a lot of lag time in the control of the unit.So the issue is how do you look at the FCC feed to make sure you don't get the contaminants inthe unit to begin with. My personal experience has been that the bad problems I've had arerelated to specific sources of feed. For example, one crude well is undergoing some sort ofcleaning operation and suddenly you have 20 ppm iron in your FCC feed sample. By the timeyou get the sample results, it’s been in your unit for quite a while.

Having said that FCC feed is the usual source of metals, it may not be the problem inevery instance. If you start to see metal spikes on your E-cat analysis, you start seeing highsodium or, high iron, you owe it to yourself to look at more than just the feed. You can't justassume that it's coming from the feedstock. There have been cases where sodium has comefrom the air system. I know of one case in particular where caustic was being unloaded with airpressure. And literally, caustic got in the air system, which got in the FCC through the airsystem, and that's a horrible, horrible thing to happen. But it happens, and you're never going tofind that in the feedstock.

In terms of rank order, we would think sodium, potassium, calcium, then zinc and iron issort of the order of severity of these contaminants.

COUSAR:Close monitoring of the desalter effluent water pH and management of refinery recycle

streams are two means by which we control metals in our topped crude/cat feed. One theoryabout calcium and iron contamination is the use of the chelant Na4EDTA in the acid stimulationof oil well production. EDTA has a tendency to pick up iron and calcium while releasing sodium.Severe pH changes inside the desalters can cause the calcium and iron to be discharged back intothe crude while the sodium is picked up again.

Does anyone in the audience have any experience with FCC feed desalters as a means ofmetals removal from cat feed?

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KENNETH A. PECCATIELLO (Chevron Products Company):In addition to potassium from feedstocks, refiners that are using potassium hydroxide for

HF alkylation neutralization and are feeding the acid soluble oil (ASO) back to the FCC unit canintroduce additional potassium on the catalyst.

FRANK ELVIN (Coastal Catalyst Technology, Inc.):If you’re going to run resids, you should have a double desalter ahead of your resid to

take out any sodium that may be coming in with the resid. There’s usually a lot of sodium in theresid coming from your crude unit where you have a desalter, and usually you add sodium for pHcontrol. And double desalting is very effective at improving the FCC performance.

The other things you can do to handle these metals and the main problem with metals isthe nickel and vanadium, but all these other metals also are bad for the FCC yields. You can addextra fresh catalyst, you can purchase flash catalyst, you can purchase good equilibrium catalystto flush out the metals, you can use the Kellogg magnetic separator to minimize the amount offresh catalyst you need, and you can also use Coastal’s ACT process, which actually demetalizesthe catalyst so that less fresh catalyst is required.

Question 26. What is the panel’s experience with cyclone velocities greater than75ft/sec? Does it correlate with cyclone life? What about catalystcarryover? What are the advantages of higher velocities?

FARLEY: We see a very large number of units actually operating above 75 fps velocity. Normally,

from a design standpoint, we don’t plan on this. But in operation, 30% to 50% of the units that Iknow of are routinely doing this. And, does it correlate with cyclone life? Yes, it does. Ouropinion is that it shortens cyclone life and if it shortens cyclone life, it’s a failure that takes placebetween turnarounds. You’re going to have some sort of failure faster operating with highervelocities than you do running lower velocities.

In terms of catalyst carryover, increasing cyclone inlet velocity also increases thepressure drop across the cyclone, which means dipleg backup increases. At some point in timewith continued increases in velocities, you can run out of dipleg. The second you’re out of dipleg,the catalyst that’s in the cyclone goes out the top, and you have carryover due to dipleg backup.

In terms of advantages of higher velocities, directionally, there’s some marginalimprovement in cyclone efficiency. But the problem is, your cyclone loading goes up so quicklythat you never really see that. The real advantage of higher velocities is you can do it on line.You’ve got your unit, it’s been running two years, you come up with some new onlineoptimization routine, and you can push more capacity to the unit with the same cyclones youhave, and you choose to do that until your next turnaround. That’s the real advantage of highervelocities. I don’t think that anybody really designs to run higher velocities, just as a matter ofcourse.

There have been cases where people choose to accept higher velocities due to spacelimitations, but these are not common cases.

MARLOWE:Just to add to that, we talked about the high velocities before. We do have problems with

higher velocities at our location. The Toledo Refinery does run 83 to 85 feet per second, and thisis in the inlet to the second stage. This is where you want to try to maintain your 85 feet persecond.

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Now, the 75 feet per second is really a design point that the manufacturers try to maintainso that you can have a normal life of your cyclone. If you’re planning on replacing the cyclone orrepairing it, yes you could take advantage of some higher velocities, but you have to be verycareful. What we were worried about was we were not monitoring it, and the operationscapacities were pushing it to well above 85 feet per second. We ran 86, 87, 88, 89 feet persecond.

It doesn’t sound like a lot, but the velocities are a factor of 3 or a factor of 4 related toerosion. So if you have a 13% increase in your velocity, then you probably have close to a 45%increase in your erosion. So you would wear out much, much, much, faster. So you can almosttake that calculation factor of 3 and you can kind of take the days or whatever from an initialdesign of 15 or 20 years, and you’ll find out how many days you actually knock off of your life.So, a major cause of erosion is your velocity, so you really want to monitor your velocity.

BILL HEUMANN (Fisher-Klosterman):We’ve done a lot of work with velocities and cyclones. A lot of it is mirroring what the

panel said. We find that a increased inlet velocity kind of correlates about to the cube of theincrease in velocity. So 15% increase in inlet velocity might get you about 50% increase inerosion rate or a 33% decrease in equipment life. Of course, you’ve got two real times you’reconsidering whether you’re going in as an increasing flow to an existing unit that’s just sittingthere and it’s a throughput issue.

The other is for a rebuild or repurchase or refitting a vessel with cyclones. And one majoradvantage that at least everybody needs to understand that drives part of the selection is higherinlet velocity ends up with cheaper cyclones. So, when you’re making your capital costscomparisons and you’re looking at a new system, if you’re comparing a system that is 75 feet persecond inlet velocity and another one at 65 feet per second inlet velocities, there is a costdisadvantage in the initial capital equipment, you know, with bigger equipment at higher inletvelocities.

The other thing - when you’ve got existing cyclones, your increase in flow will increaseinlet and outlet velocities, but the two are not necessarily coupled when you’re working with anew design and the effects on erosion and decreased equipment life are a lot more clearly linkedto inlet velocity. So if you have pressure drop, but you don’t want to be using inlet velocity,outlet velocity is less detrimental, in our experience, to life.

FARLEY:That’s a good comment from the floor. We’ve seen something similar to that where one

advantage of higher cyclone velocities was basically eliminating the need for vessel replacement.In this case, to the velocity range you would like, the head would have to come off, and you don’thave enough diameter for the cyclone layout you need. You eventually reach some sort ofultimate capacity where you’ve got high superficial velocity. The next cyclone size is notavailable for you, because you can’t get the cyclones in, there’s just not enough physical space inthe top head of that vessel. So what you end up looking at is vessel shell replacement and I havenot seen too many people get excited about that, yet.

WILLIAM D. HENNING (Conoco Inc.):We’ve had one Cat Cracker where after about a year of operation, we wore down the

refractory on the back end of the primary cyclone. And the inlet velocity there was about 85 feetper second, so it was moving along pretty good. And so we fixed it up pretty quickly. Then wedeveloped a strategy for operating based on velocities, and we used erosion as proportional to

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velocity to the 5th power, and that seemed to fit some previous data in the unit, and also it seemedto work pretty well until we got to the next turnaround and we could actually replace thecyclones.

Question 27. What are the consequences of using oxygen enrichment?additional maintenance expenses?safety considerations?

FARLEY:The background of O2 enrichment is that, you have a lot of FCCs out there that are out of

air blower capacity. And there’s still a lot of incremental margin to burn more coke. O2

enrichment offers one way to combust incremental coke when you’re out of air blower.The issue is, it’s not free. You have to buy the oxygen to combust the coke. There is

usually an economic debit where the regenerator temperature ends up going up some, so theremay be a loss in cat to oil, depending on what the unit configuration is. Most people report somesort of incremental catalyst deactivation. These numbers go all over the map. I’ve heard numbersat 10%, I’ve heard numbers at 40%, so, it’s very site specific.

Overall, if the regenerator temperature goes up, there’s usually some sort of decline in theoverall yield structure of the unit. So, what this gets down to is usually, there’s a pretty robusteconomic evaluation, and hurdle pricing is set where the feed margin has to be over a certainvalue before you make the decision to use O2 enrichment.

Once you make the decision to use O2 enrichment, it’s pretty important to have a veryrobust safety interlock system in place and it is very important to control the percentage ofoxygen that’s actually entering the regenerator. My direct experience is that most people limit O2

to about 25 mol % being charged to the regenerator. There are reports in industry of people goinghigher than that. And as mentioned, the safety interlock system is absolutely critical.

CARPER:There’s another reason for using oxygen enrichment, you can decrease your superficial

velocity if you run into cyclone loading challenges. Individual plant economics drive thisdecision.

One of our refineries uses a dedicated crew to handle the equipment and connections.They are specifically trained and dedicated to the tasks. The keys are quite simple: keep it clean,keep it dry, and keep it oil free. The refinery’s source of information for handling and addressingsafety issues was from the Compressed Gas Association and Linde.

Lastly one major key our refinery wanted to share: by all means, do not hot tap into anoxygen line.

ROBERT BEST (Air Products and Chemicals, Inc.):In addition to the comments from the podium, I wanted to mention that oxygen

enrichment will slightly increase the regenerator bed temperature. As a general rule of thumb forpredicting the temperature rise, and of course, this is due to the loss of some of the nitrogen asheat sinks, is that you consider that for each 1% of oxygen enrichment, the bed temperature canincrease by about 3o to 5o F, given no other changes in process variables.

In addition to that, oxygen enrichment levels in our experience have ranged from 21% to28%. And I would agree that on an average basis, we see about 24%, on average.

Some brief comments related to safety. To our knowledge, the FCC oxygen enrichmenthas been safely practiced by our customers for well over two decades. We believe that around

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the world, FCC O2 enrichment is used in between 40 to 50 FCC units. And a brief listing ofsafety considerations would include a properly designed O2 diffuser, proper placement of thatdiffuser, keeping in mind placing it at least ten pipe diameters from any impingement point,observing O2 material construction compatibility issues in piping guidelines. We, as a company,closely follow CGA pamphlet 4.0 and 4.1 guidelines for O2 material selection, pipelineconstruction, and cleaning practices.

And just briefly, on the O2 flow skid and controls, this should include several key safetyinterlocks such as high oxygen flow, high oxygen pressure, high calculated O2 enrichment levels,high measured O2 enrichment, high temperature conditions in the air main downstream of the O2

injection, low air flow, regenerator temperature, and a general catch-all master FCC interlock, toname most of the common interlocks. Each of our applications, of course, would follow a formalhaz-op review prior to commissioning.

And in closing, I’d just like to mention for more detailed information on FCC O2

enrichment safety and other FCC topics, I would recommend an interesting and new website putout by Refinery Process Services, and in part sponsored by Air Products. The address iswww.thefccnetwork.com.

JOSEPH W. WILSON (Barnes and Click, Inc.):I’ve got a question this time. Just out of curiosity, if anybody’s willing to name numbers,

I’m curious as to what levels of oxygen enrichment people are actually running on a regularbasis.

J. ROBERT RILEY III (Grace Davison):One of the side benefits that we’ve seen as a consequence of oxygen enrichment is that as

the EPA and the other regulatory agencies are starting to crack down on SOx emissions, thecatalyst additives for SOx control are generally much more efficient when used in a regeneratorusing oxygen enrichment. So, that’s a little side benefit you can get.

ROBERT BEST (Air Products and Chemicals, Inc.):I just want to mention that on average, about - the answer to the question about what level

of enrichment? We see about 24% as a rough average, the range being from very little toprobably a maximum of 28%. Self-imposed guidelines dictated by CGA and other companies,mainly for safety purposes, you have - above 28%, you try to treat the line as if it’s going to haveto carry pure oxygen, and therefore needs the required cleanliness to do so.

JASON PAGEL (Lyondell-Citgo Refining): Our typical O2 level is around 24.5%.

UNKNOWN:At the one refinery where we use oxygen enrichment, we run 25% to 27%.

T. DAVID PAY (Lyondell-Citgo Refining):David Pay, Lyondell-Citgo Refining. To add on to Jason’s remarks, we’ve been doing

oxygen enrichment since 1983. And initially, we started with a vaporizing system where theoxygen was brought in as a liquid, and then fed into the unit. Now, we have a pipelineconnection and so it comes in as a vapor. The original system we had stainless steel pipingthroughout, but when we installed some new equipment back in 1992, we had to re-route the

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line, so we went with carbon steel lines for the additional piping that we had to put in. We did gothrough a very elaborate cleaning of the system before we commissioned it.

Question 28. What kinds of filters or separators have satisfactorily removed catalystfrom slurry?

FARLEY:The table (Figure 28 – see next page) compares some slurry filters or separators that have

satisfactorily removed catalyst from slurry. The first column is Gulftronics, the second column isthe Mott cartridge filter system, the third column is the Pall cartridge filter, and the last column isthe hydrocyclone.

Basically, just a quick survey of what's out there in industry, from what I can see,Gulftronics, first installed 1979, has a lot of installations, more than 50. Estimated slurry solidconcentration is around 50 ppm. The Mott system, first installed 1990, currently has 9installations, and generally estimated to be around 20 ppm slurry solids. Pall cartridge systems,first installation was 1989, 16 of those installations now, generally estimated to have anywherefrom 20 to 50 ppm solids in the slurry product to storage, with 50 ppm on the high side. And theDorr-Oliver hydrocyclone, 1960 for first installation, around 50 of those, generally more like 300ppm solids in the final slurry product.

The Gulftronics preferred backwash material is HCO, with Mott also generally listingHCO first, while Pall tends to name slurry as their first choice. The three systems do call out thatany of the streams below can be satisfactory.

Basically, Gulftronics directionally has the highest backwash rate. The Mott and Pallsystems are fairly similar in terms of backwash rates. The filter systems have a wider operatingtemperature range than the Gulftronics.

It is important to look at things like plot space and operating costs when making yourdecision as far as which type of system to invest in. There can be some pretty surprisingdifferences in plot space. The final decision should be based more on life cycle cost analysis asopposed to investment cost only.

COUSAR:Prior to our '99 FCC turnaround , we were losing quite a bit of catalyst from our reactor.

We went through the process of evaluating both the Pall and the Mott filtration systems. The costestimate for the filtration skid (including the filtration vessels, filter elements, piping, pumps,valves, etc.) that was sized for approximately 3,000 bpd of slurry was about $1.1 million. Thetotal installed cost was estimated to be $2.2 million. We were justifying this expenditure basedon approximately $0.9 million of savings. The savings were in the form of a reduction in thefrequency of cleaning the slurry tanks, a reduction in the disposal costs of the catalyst sludge inthe tanks, and the elimination of the slurry settling aid. The decision was made to revamp ourFCC reactor and in doing so, we reduced our catalyst losses to the point to where the filterproject was economically infeasible.

MONIQUE STREFF (Fisher Rosemount Systems):I'm just wondering if that $.9 million in savings was just for a year or considered overall?

COUSAR:That was our annualized savings. That was $900,000 per year.

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HAZLE:Any other questions or comments? I’ve held you long enough. I appreciate you staying

for the end of the session. Let’s say thank you to our panelists. [applause].

Device GulftronicsSeparator

Mott CartridgeFilter System

Pall Cartridge FilterSystem

Dorr-OliverHydrocyclone

FirstInstallation

1979 1990 1989 1960

Number ofInstallations

>50 9 16 >50

EstimatedSlurry EffluentSolidsConcentration,ppm

50 <20 <50 ~ 300

Percent ofslurry feed thatis recycled toriser fromseparator

0 0 0 ~9

Backwashrequirement asa percent ofseparatorfeedrate

20 As low as0.2 %, up

to 2 %

Up to 2 % 0

Choices forbackwash fluid

FCC Feed,LCO, HCO,

Slurry

FCC Feed,LCO, HCO,

Slurry

FCC Feed,LCO, HCO,

Slurry

NA

Operatingtemperaturerange (°F)

302 -392° F(356° Fnormal)

401 - 600° F(480° F normal)

480° F normaloperation, 550° Fmaximum design

temperature

482 - 670° F

Figure 28

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2000 EXHIBITORS

ABB Fan Group North America19065 Highway 174Pell City, AL 35125205-814-1722Mr. Bruce J. Gallagher

ABB Fan Group engineers and manufactures FDand ID fans for fired heaters, CCR blowers, high-pressure fans for fluidization and sulfur recovery,and will engineer upgrades for allexisting fans.

Aggreko Inc.12000 Aerospace Ave., Suite 300Houston, TX 77034713-852-4500Mr. Bob James

World Wide provider of specialty utility services.Services include temporary electricity, oil-free air,cooling water, process cooling and more. Backedby a professional support team and engineeringstaff.

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Plant inspection services API 510, 570, 653.

AltairStrickland, Inc.5110 Railroad AvenueDeer Park, TX 77536281-478-6200Mr. Sherwood McDonald

FCCU T/A Specialist; Field Erected Vessels, Tower& Tray Work, Field Piping.

Atlantic Scaffolding Company2817 West End Avenue, Suite 126 - Box 169Nashville, TN 37203615-851-5727Mr. Wes Horton

TURNKEY scaffolding contractor featuring ExcelModulor System, the "no tools -positive locking"system; Engineeral Scaffold, FCC "JIG Stands"reduces costs; Regional offices: Baltimore, BatonRouge, Houston, Nashville, New Orleans, Mobile,Tampa.

Bently Nevada Corporation7651 Airport Blvd.Houston, TX 77061713-640-1111 x4203Mr. Glenn Poche

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Boardman, Inc.1135 S. McKinleyOklahoma City, OK 73108405-634-5434 x222Mr. Roger Grommet

FCCU Components, ASME Section VIII Div. 1vessels trayed towers.

Causeway Steel Products, Inc.6923 MayfairHouston, TX 77078713-649-6923Mr. Darrell McAnelly

Causeway manufactures refractory anchoring,hexmetal, flexmetal, hexcels, s-anchors andpunchtabs. Causeway also offers completehexmetal and flexmetal, fabrication with insulationdrawings, which will greatly reduce your insulationtime.

Champion Elevators, Inc.8400 Villa DriveHouston, TX 77061713-640-8500Lee Brantley

American manufacturer of rack-and-pinion elevatorsystems specifically engineered for thepetrochemical and refinery environments.Temporary and permanent elevators available fornew construction, retrofits and turn-arounds.Custom engineered for your specific project withexplosion proof, corrosion resistant and variablefrequency drives available.

Compressor Controls Corporation11359 Aurora Ave.Des Moines, IA 50322281-583-7799Mr. Jeff McWhirter

Compressor Controls Corp. (CCC) is the worldleader in design and manufacture of electroniccontrol systems for all turbomachinery applications,including cat cracker air blowers and PowerRecovery Trains.

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Construction & Turnaround Services12343 East Skelly DriveTulsa, OK 74128918-437-4400Mr. Gerald Schivally

Mechanical and refractory field contractor forturnarounds and capitol projects.

Continental Fabricators, Inc.5601 West Park AvenueSt. Louis, MO 63110314-781-6300Mr. Charles W. Vogler

All FCCU Components including Reactor andRegenerator Heads, Internals, Risers, Wyes, AirGrids, Stripper Sections, Overhead Lines.

Corhart Refractories1600 West Lee StreetLouisville, KY 40210502-775-7388C.W. Miller

Corguard-Abrasion, impact, and corrosion resistantceramic. Airgrid nozzles, cyclones (inlets, dustbowls, diplegs), 3rd stage separater tubes, transferlines, coker elbows, riser linings, and critical flownozzles.

Deloro Stellite471 Dundas Street EastBelleville K8N 1A2, ONCanada613-968-3481 x245Ms. Elaine Foster

Deloro Stellite is a provider of solutions for wear,corrosive and heat resistant problems. Deloromanufactures cobalt and nickel based alloys.Components are produced in eight processes,supported by a full machineshop.

Delta Catalytic Industrial Services2000 Argentia Road, Plaza 1, Suite 400Mississauga, L5N 1P7, ONCanada403-258-6700Mr. Ken Beevers

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Diamond Refractory Services, Inc.8431 MosleyHouston, TX 77075713-378-9200Mr. Chris Lanclos

FCCU T/A Specialists, Vibration Casting, WetGunning, D-Bar Anchor, Project Management andCorporate Alliances.

Dynamic-Ceramic LimitedCrewe Hall, Weston Road, CreweCheshire, CN1 6UAEngland011441270501000Mr. Richard Binks

Advanced ceramic materials and components forwear, erosion, and corrossion resistance.

ENPRO SYSTEMS, INC.16315 Market StreetChannelview, TX 77530281-452-5865Mr. Rick Crago

FCCU Slide & High Performance Butterfly Valves,Diverter Valves, Reactor/Regenerator Vessels,Overhead Transfer Lines, Risers/Standpipes, AirDistributors, Injection Nozzles, and ASME CodePressure Vessels.

Everlasting Valve Company108 Somogyi CourtSouth Plainfield, NJ 07080908-769-0700Mr. Frank Hawley

The Rotating Disc Valves renew their sealingsurfaces with each cycle. FCCU licensors includethese valves in their specifications. Dry abrasivemedia or slurries; vacuum to class 2500°temperatures to 1500° F.

Expansion Joint Systems, Inc.10035 Prospect Ave., Suite 202Santee, CA 92071619-562-6083Ms. Kathy Tyson

Manufacturer of metal and fabric expansion jointsand piping solutions for various applicationsincluding FCCU, Spent Catalyst, RegeneratorStandpipe Joints, Fluegas, Clam Shell Joints andon-site services. EJMA Member.

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Fibercon International, Inc.100 South Third StreetEvans City, PA 16033724-538-5006Mr. Keith Foley

Steel reinforcing fibers (slit sheet, melt extract,drawn wire), anchors, studs and stud weldingequipment for the refractory industry.

Fisher-Klosterman, Inc.822 S. 15th St.Louisville, KY 40210502-572-4000Mr. Gary Kissel

Cyclones, Diplegs, and Trickle Valves for fluid bedsystems. Air pollution control equipment, servicesand replacement parts.

Grace Davison7500 Grace Drive, Bldg. 25, 2nd FloorColumbia, MD 21044410-531-8226Ms. Elizabeth W. Mettee

World’s leading supplier of Fluid CrackingCatalysts & FCC Additives.

Hi-Tech Refractory/Geo. P. Reintjes3800 SummitKansas City, MO 64111-2999816-756-2150Mr. Tim Coppinger

Hi-Tech and the Geo. P. Reintjes Co. are full servicerefractory installation contractors specializing inFCCU turnarounds. Offices are located throughoutthe USA and Canada.

InduMar Products, Inc.2500 Tanglewilde, Suite 260Houston, TX 77063713-977-4100Mr. Bart Davis

InduMar Products, Inc. will be demonstrating theSTOP IT PIPE REPAIR system.

Industrial Gunite, Inc.2000 Magnolia StreetPasadena, TX 77503713-477-0331Mr. Robert M. Ferguson

Contractor specializing in refractory, fireproof, andacid proof construction and turnarounds.

J.T. Thorpe & Son, Inc.14540 Alondra Blvd.La Mirada, CA 90638714-670-9500Mr. Craig Jackson

Refractory Engineering & Contracting.

Kellogg Brown & Root, Inc.601 Jefferson AvenueHouston, TX 77002-7990281-492-5880Mr. Terry L. Goolsby

Provide refiner’s with information about FCCproducts offered by Kellogg Brown & Root and howit will help them.

Koch Specialty Plant Services, Inc.12221 E. Sam Houston Pkwy. NHouston, TX 77044713-427-7715Ms. Veronica Brown

KSPS specializes in tower internal installation,revamp, maintenance and repair services, which include modification and repair of firedequipment, reactor catalyst changeouts, on-sitehydraulic bolting, field machining and bundleextraction.

Lamons Gasket Company7300 Airport Blvd.Houston, TX 77061713-222-0284Ms. Debbie D. Warren

Manufacturer of spiralwound gaskets, heatexchanger gaskets, ring joint gaskets, all non-metallic fluid sealing products and bolts, andspecialty fasteners.

Lubrication Systems Company1740 Stebbins DriveHouston, TX 77043713-464-6266Mr. Bob Harrington

Manufacturer of: Most advanced oil mist generatoravailable, oil purification systems, API 614 lube oilsystems, and pre-engineered lube oil systems.

Marsulex Environmental Technologies200 N. 7th StreetLebanon, PA 17046717-272-7212Mr. Ed Tenney

FCC cylcones and electrostatic precipitators, wetflue gas desulfurization scrubbers.

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Mogas Industries, Inc.14330 E. Hardy StreetHouston, TX 77039281-449-0291Ms. Lori Evans

Since 1973, Mogas has engineered metal seatedball valve solutions that overcome high temperatureand high pressure, media build-up, cycling withsolids in the line and erosive attack of materials andcoatings.

Murphy Industrial Constructors626 East Pine PlaceGriffith, IN 46319219-923-0425Terry Swanson

FCCU Turnaround Services.

Nooter Construction Company1400 South Third StreetSt. Louis, MO 63104800-325-7369 x565Mr. Raymond J. Montrey

FCCU T/A Maintenance and Repair.

Philip Services Corp.5200 Cedar Crest Blvd.Houston, TX 77087713-495-3521Mr. Mike Prevost

Project management, refractory, catalyst handling,piping and specialty welding. Tower, vessel andexchanger specialist.

REMOSA S.p.A.17 South Briar Hollow, Suite 207Houston, TX 77027713-355-4900Mr. William W. Cathriner

Slide, Butterfly, Diverter Valves.

Resco Products, Inc.705 Sarah AnnNacogdoches, TX 75961936-560-3335Mr. Robert M. Huegele

Resco Products Inc. manufacturers a complete lineof high quality refractories for the refining industry.

RHI Refractories America600 Grant St.Pittsburgh, PA 15219573-473-3517Mr. Mark Schnake

Manufacturer of refractory products previouslyproduced by N. American, Harbison-Walker, andA.P. Green Refractory companies.

Ribbon Technology Corp.825 Taylor Station RoadGahanna, OH 43230614-864-5444Mr. John Norder

Ribbon Technology manufactures stainless steel forcastable refractory reinforcement.

Senior Flexonics - Pathway Division2400 Longhorn Industrial Dr.New Braunfels, TX 78130830-629-8080Mr. Dave McGrath

Senior Flexonics Pathway is recognized as theindustry leader in the innovation, design andmanufacture of high-quality metal and fabricexpansion joints.

Sermatech Technical Services12505 Reed Rd.Sugar Land, TX 77478713-948-1534Mr. John J Saphier

Engineered coatings for steam turbines and axialflow compressors.

Shared Systems Technology, Inc.127 Salem AvenueThorofare, NJ 08086856-853-5700Mr. Frank DeMartino

Refractory Installer.

Stress Engineering Services Inc.13800 Westfair East DriveHouston, TX 77041281-955-2900Mr. Terry Lechinger

SES is a consulting engineering company withdisciplines in civil, mechanical, electrical, mechanicaland chemical disciplines. Offices in 5 US cities withexpertise in fitness for service, remaining life andhigh temperature applications.

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TAPCO International5915 BrittmooreHouston, TX 77041713-466-0300Mr. Mark S. Taylor

FCC Slide Valves, Butterfly Valves, Diverter Valvesand FCC Equipment.

Team Industrial Services, Inc.200 Hermann DriveAlvin, TX 77511281-388-5545Mr. W. R. McAfee

Team provides high temperature, high pressureleak repairs and hot tap services on cat crackerwalls and flue gas ducts (1350° F), plus thermowelland sparger installations (1300° F).

The TIMEC Group of Companies155 Corporate PlaceVallejo, CA 94590-6968707-642-2222 x239Mr. Rich Milland

Industrial turnaround, maintenance, repair andmodification services, including projectmanagement, planning and safety. Subsidiariesspecialize in tower, vessel, heater repairs; welding;electrical/instrumentation; exchanger, bolting andcatalyst services.

VALVTRON6830 N. Eldridge #502Houston, TX 77488713-466-7200 x4Ms. Ronda Kalinec-Espinoza

VALVTRON’S metal seated ball valves are aproven solution for tough FCCU applications suchas slurry pump isolation. Many of our valves havebeen in service over 10 years without repairs. Wecan provide customer contacts who will testify to ourlongevity in this and other service FCCUapplications.

Vesuvius Premier9135 Wallisville Road, Suite AHouston, TX 77029713-675-4167Mr. Steve Kirklin

Vesuvius offers a full like of refractory products andservices for the construction and maintenance ofhydrocarbon processing facilities. Vesuvius offers afull line of monolithics, brick and ceramic fiber.

Zimmermann & Jansen, Inc.620 N. Houston Ave.Humble, TX 77338281-446-8000Mr. Bredo Christensen

Manufacturer of High Temperature Slide, Butterfly,Double Disc, Gate, Wedge-within-wedge Valves.

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