HOMECAT 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 1 2 NPRA CAT CRACKER SEMINAR AUGUST 8-9, 2000 HOUSTON, TEXAS TABLE OF CONTENTS Panelists..................................................................................... ii Refractory, Materials, Internals, Expansion Joints, and Slide Valves .........................................................................................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 a warranty or representation for which the participants assume legal responsibility. Users should undertake sufficient verification and testing to determine the suitability for their own particular purpose of any information or products referred to herein. NO WARRANTY OF FITNESS FOR A PARTICULAR PURPOSE IS MADE. Nothing herein is to be taken as permission, inducement, or recommendation to practice any patented invention without a license. i TX FCC Technical Services Manager Kellogg Brown & Root Houston. Toledo. TN Frank DeMartino Mike Drosjack C.PANELISTS Larry Carper FCCU Mechanical Equipment Consultant BP Amoco Naperville. Inc. OH Process Engineer Williams Refining LLC Memphis. TX Reliability Engineer Sunoco. NJ Engineering Advisor Reliability & Process Safety Westhollow Technology Center Equilon Enterprises LLC Houston. J. Farley Jim Marlowe Spence Cousar ii . IL President Shared Systems Technology Thorofare. I want to welcome everybody. For those of you that attended the meeting two years ago. The tabletop will also be open tomorrow at lunch for you to see all of the fine things they have out there. and after looking at the agenda I am sure it will be. Fred Collier of Williams Energy.the ones that have worked very hard to put on this seminar. you can pick them up at the NPRA registration desk. HAZLE: Thank you. [applause] I'd also like to thank the NPRA staff that has worked very hard to make all of these arrangements for the meeting facilities and the tabletop area. TX August 8-9. I'm looking forward to the agenda. I think their participation is one of the things that will really make this conference one that's worthwhile to everyone. Pat Lysaght of Marathon Ashland. The tabletop exhibit will be open this evening after the Q&A Session. and I want to thank them for putting on. and tomorrow morning we will have coffee. First. and I hope you all appreciate it. from what I can see. If you're here.2000 Cat Cracker Seminar Adams-Mark Hotel Houston. To start with.there will not be any continental breakfast. and put their answers together. and Charlie Pauls of Cooperative Refining. If you're around. I hope everyone finds this seminar as fruitful as it has been in the past. This is the first year of having a larger exhibit hall. often consulting other people in the places where they work. who then edit those questions submitted to NPRA and select the ones that they will use in the session. which is great. and we have the panelists here. With that. you should have received your copy by mail within the last week. It will also be open tomorrow morning. Jerry. the transcripts of the last two Cat Cracker Q & A Sessions are available. we will have the workshops and there will be a series of them with six starting in the morning. and six more in the afternoon. They are Jeff Hazle. could you stand up? I'd like to thank them again for their fine work. a fantastic tabletop show. The Program Committee puts together a panel of experts. Also. The Panelists then prepare their responses. They are Jon Carlson of Koch Petroleum. I also want to thank the exhibitors. I'd like to go ahead and start the conference and turn it over to Jeff Hazle for the Q&A. This 1 . could you stand up? [applause] Thank you. Yvette Brooks. I’d like to welcome you to the 2000 Cat Cracker Seminar. for introducing the Q&A Session. My name is Jerry Crail of Equilon LLC and I am the chairman of this year’s seminar. I'd like to introduce some of the committee members . If you have not received the 1996 or 1998. some of them are repeated. 2000 CRAIL: Good afternoon. Stacy Lane and Kelly Healy. We'll talk to them in a minute. Shailendra Gupta of BP. As you will notice. We're employing the usual Q&A format where we solicit questions from past attendees of these conferences. I think we have a record turnout this year. which will enable people to go to different workshops. and that will only be coffee . Tomorrow. We're going to start off today with a Q&A Session. I want to thank you all for coming. or make changes . The units I typically interface with are Kellogg/KBR 2 . so if you have a question to ask of the panel. My job is to perform FCC technical service work for KBR. will talk about how the solution to the problem has evolved as technology has advanced. J. it’s more informal. which is up the road here. FARLEY: I joined KBR in 1997. we have tried to organize the answers as much as possible in the following way: The first responder will give some background on the question. and the panel. As usual. prior to that. which was formed by Shell and Texaco’s refining arms a couple of years ago. we ask that you use the microphone when you address questions to the panel. As usual. It is intended to represent a dialogue with you. I’m with Equilon Enterprises. Hopefully. because when we finish the transcript. if necessary. the session will be recorded and a transcript will be made. and somebody will bring the microphone to you. if you would. I worked for a major refining company for just over 7 years. Farley of Kellogg Brown & Root. For that reason. there is a disclaimer for this.000 bbd FCC that processes 100% atmospheric tower resid. Mike? DROSJACK: Hi. The panel is representing their experiences. and Jeff couldn’t make it. in Houston. we will mail it out to everybody who speaks. HAZLE: The next panelist is Spence Cousar. you need to test to see whether or not it’s appropriate for your own facility.make sure we understood what your question was. Anything that you hear here. the attendees. raise your hand. please state your name and affiliation. I’m in the Westhollow Technology Center. We replaced both our reactor and regenerator and installed UOP’s VSS catalyst separation technology in both vessels. When they do that. and have a little bit of everything in that package. Next to me is Mike Drosjack with Equilon. They had some problem at the refinery. Spence. We have a 75. We have microphones in both aisles and one in the back. We have a different stage setting this year. so Spence is filling in at the last moment. and more conversational. We completed an FCC revamp in November 1999. There is no legal responsibility or liability that goes along with their answers. The second responder will describe how the problem was addressed initially.year. of course. My particular function is providing support in the rotating machinery area. if there is one. and you will have a chance to edit your comments. The next panelist is C. TN. We also have people who will be carrying the microphones to you. With that. we have eight Cat Crackers scattered around the country from Delaware City to Louisiana to Houston. and hand a business card to the microphone handler. I will ask each of them to describe the kind of FCC units that they work with. He’s a late fill-in for Jeff Warmann at Williams Energy. and we provide support to the various refining locations we have. which means I travel around the world to visit different locations where we have projects as well as heading to places where we have extended service agreements. and then the third responder. we will introduce the panelists. And in our company right now. HAZLE: Thanks. what do you have at Williams? COUSAR: I’m a process engineer at the Williams refinery in Memphis. and then we’ll go to the questions. I don't work just for one company. HAZLE: The next panelist is Jim Marlowe of Sunoco’s Toledo refinery..000 bpd fuel facility refinery. J. So that's why I am glad to come here and try to share some information with you.000 bpd. For the first question and the first response. I also work with a good number of UOP geometries. but I've been working with FCCU’s for 25 years. I've been involved in at least 50 Cat Cracker installations and I've probably seen the full spectrum of FCCU technology. I work for many companies. CARPER: BP Amoco currently has 22 Fluid Units utilizing various designs and technologies throughout the world. and we have a 150. EXPANSION JOINTS. stacked and high-efficiency designs. and our Cat Cracker is around a 60. last is Frank DeMartino. HAZLE: Next is Larry Carper. DEMARTINO: I don't have a Cat Cracker. AND SLIDE VALVES Question 1.designs that are anywhere from five years to thirty years old. Some of the units are gas oil units and some are resid units. and shortly will become a free agent. I have over 23 years experience within the company. I will ask for questions from the audience. HAZLE: Alright. MARLOWE: I’ve been with the Sun Toledo Refinery for about ten or fifteen years. could you lead on this. please? I. Following each question. C. Let’s go to the first question. My exchange today will focus on experience with the heritage Amoco units as my exposure to the heritage BP units is limited. REFRACTORY. Before that I had service with Amoco and with ARCO. after the panelists’ responses. INTERNALS. I'm the president of Shared Systems Technology. such as side-by-side. who works in BP Amoco’s Refining Technology Group in Naperville. Illinois. MATERIALS. Has anyone experienced a packed expansion joint failure due to polythionic 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? 3 . HAZLE: Thank you panelists. We've put this material in some pretty 4 . For high temperature designs.FARLEY: Polythionic acid (PTA) stress corrosion is caused by acid formation on "sensitized" stainless steel when air and water contact a sulfur contaminated hydrocarbon. Recently we learned that a refinery experienced a bellows failure due to overheating which 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. Our successes with either material is mixed. DROSJACK: We've had these problems in our facilities more than once. we usually require an H grade to maintain high temperature strength. Generally. for Advanced Polymer Sciences. It has good resistance to sensitization and PTA attack. Too cool and you risk dewpoint corrosion or polythionic acid stress corrosion cracking. the dewpoints change. Stainless steel expansion joints have surfaces that exceed the limits of the onset of stress corrosion. The number is 1-800-334-7193. if you apply this post-cure coating above the dewpoint where the material may be at 500°. We would generally say Inconel 625 is a respectable choice. We have looked at things like 800H and 800HT. The current thinking within our metallurgy community is Inconel 625-LCF. In terms of exotic metallurgies to avoid polythionic attack. If you're above the dewpoint where the acid maybe wouldn't be so much of an issue. Previously we specified Incoloy 825 and Inconel 625 as an alternate. Internal packing/insulation minimizes catalyst entering the convolutions maintaining the functionality of the bellows or expansion joint. or other forms of stress corrosion. We recently experienced a failure with Inconel 625 bellows. The solution is to insulate externally. there's a chance that the coating will resist the acid attack for a long time. we tend to stay away from these things. because they are not immune to sensitization. you have to look at the costs and benefits when reviewing all of the alternatives. but too much external insulation can overheat the bellows. Bellows temperature design is critical. And really. there are two general areas to look at to keep this from occurring. The "sensitization" of stainless steel occurs when the carbon content is "unstabilized" and allows microstructural intergranular paths to form by carbide precipitation during heating (such as welding) when temperatures exceed about 800 °F. CARPER: We have struggled with bellows metallurgy for years. then adjusting as necessary. as well as low temperature chloride attack. but this still allows carbide precipitation or sensitization to take place. We suggest monitoring the bellows temperature during and after startup. But now you risk cooling the bellows below dewpoint. But if you're below the dewpoint. There are natural cavities where water can be trapped in these surfaces. it's not an issue. and so materials like 304. It's choosing the appropriate materials of heat treatment that can handle the manufacturing processes unsensitized and also keeping the process stress heat moisture away from these bellows and keep the polythionic attack (PTA) from occurring. I can give you an 800 number. Too hot can embrittle the bellows material. 316 or chemically stabilized 321 are not immune in the expansion joint design. The internal shroud failed exposing the bellows to the high temperature flue gas. and it gets pretty thick over the run length. and the gas flow is moving towards the left. Question 2. this makes a very hard coke. We say that there are basically two root causes for this problem. You can have two or three inches of material build up. Has anyone experienced coke formation on the outside diameter of reactor 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. but primarily. This is a pretty well-known problem. To improve your perspective. FIGURE 1 Coke forms for several reasons. You can have literally heavy components that form liquid droplets that coalesce in this area. This has been effective for inhibiting this kind of coke formation. where feed can be very difficult to vaporize. this area is pretty inactive in the cyclone body. we point to the riser. inside the cyclone. including some high sulfur. 5 . so it is not scoured by solids. we tend to start looking at the riser operation and start asking whether or not we are getting good atomization in the riser. the cyclone inlet horn is located over here (right side of photo). What we see is coke formation that has occurred over two to three years of operation. and that’s what you can see here in this photograph (Figure 1). and it happens quite often on the back side of the gas outlet tube. which then thermally crack. We have also seen that one way to help mitigate this is to use a little bit of sweep steam in the reactor vessel disengager. What kind of temperatures do we have in the riser? Do we have enough catalyst/oil mixing? Is there enough steam in the riser to easily vaporize the hydrocarbon? This has been of particular importance in resid units. when we start seeing this type of coke formation. high temperature applications and had some real good success. So that may be one thing you want to consider to stop some of your acid attack. But generally.adverse conditions. Generally when we see this. DEMARTINO: We happen to work for one customer that has a resid unit that put many. many anchors in place. Coke on the OD of a gas outlet tube is unstable and can plug diplegs. The second issue is that this material will spall off and end up in a dipleg. plugging a dipleg which resulted in an unplanned outage. there is a very real chance that all they are doing is buying about two or three weeks of time. low chrome steel cyclones and refractory. We are continuing efforts for understanding and prevention. part C. We recently experienced a situation where thermal cycling the reactor was sufficient to dislodge the coke from the outlet tube. So. and robotic demolition. see this coke present in the cyclone system. because there are two main issues with that. Indiana. Later in the session. this coke can be a fuel source. was how important is removal of this coke? And the easy answer is that it’s absolutely critical to remove this coke. QUINCY SUMMERS (Countrymark Co-op): Quincy Summers with Countrymark. FARLEY: One part of the question. Mt. at least one of my customers is. Vernon. That’s the first issue.CARPER: Until recently. So they are using some refractory anchors. just to hold the immense amount of coke so they could go inside and get some inspections and then chip away the coke so there was no accidents. I am not gutsy enough to try and sell this concept! I would like to offer one point of observation. if it was a stainless steel vessel and the coke wouldn’t attach itself to the vessel. there are ways of arc spray metallizing 304 or 300 grade stainless to carbon steel. You may have to do an air dryout when you restart and as you get up to temperature with air. we have found coke to form on both carbon steel. The bond strengths are up around 10. And when this happens. The coke was both hard and soft. we have not experienced coke forming on austenitic stainless steel cyclones in a reactor vessels. Most recently we found coke in one of our gas oil units. It’s very important for the coke to be removed if you see it on the gas outlet tube. because they are going to go back in the vessel to get the material out of the dipleg. hydrodemolition. Regarding the question of anchoring coke. we have seen coke form on the OD (outside diameter) of gas outlet tubes in resid operations. but it’s something that somebody may want to try if they’re having a lot of coke buildup. Removal? . The first one is. my response to question #20 will also cover explosive demolition. Of everything we’ve seen 6 .000 psi. However. once again. and decide not to spend the time to get it out. It is an interesting observation. So. And then the discussion was made. how do you keep away from having hot spots? There is not an easy way. 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. you really have to take it out. we are very adamant about coke removal. And it’s very.Adamantly recommend removal. If you go into the unit and you see this present. which is the answer to your specific question. dryout time. It’s a relatively inexpensive method of application. and there’s a chance that the coke would not attach itself to the stainless steel. you know. very common around the world to have units that come down for turnaround. I have evidence now that if you stick around FCC units long enough. the darn things will make you a liar about everything you say. PHOTO 1X This is a sample (Photo 1x) of the kind of coke we found on the backside of the cyclone outlet tubes in one of our FCC reactors. It’s not a great thing. a rivet buster is the most effective. Everybody ends up covered in coke dust at the end of the shift and you get bigger muscles. There are some sketches coming up of that. but they’re one entity demolition pieces whereas you can have six. It’s beautiful. 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. ten rivet busters working in the same unit. FIGURE 2 There are some robotic systems out there. eight. That still seems to be the best way for the demolition. basically.in all of these refineries I talk to across the United States. it gets you off the critical path pretty quickly. It’s got about a 30-inch arc on the backside and it’s got imprints of hex mesh on that backside. And we brought some pictures to show you on the screen of this. LEWIS FREDERICKSON (Chevron Products Company): I’m Lew Frederickson from Chevron. It’s got very nice horizontal erosion marks on 7 . and then it came off. we’ll certainly talk to you.if you find coke in the cyclones. Unless you’re really looking for it. we tried inspecting the reactor cyclones with a video camera due to really tough accessibility. We also had a large pile of coke in the bottom of the spent catalyst stand pipe. but it plugged the spent catalyst slide valve. a lot of this coke spalled off. and the reports that we got were good. and sometimes the deposits are a lot smoother than this one is. The scary part was that experienced inspectors were in those cyclones. apparently. TENNEY (Marsulex Inc. Inc. which was in March 2000. We’ve elected 8 . WILSON (Barnes and Click. EDWIN D. Back in the mid-80s. What is the experience with different refractory systems for regenerator cyclones? MARLOWE: The picture (Figure 3) shows what happened to our unit on our last inspection. We took several more bucketfuls of coke out of the two cyclones in this FCC unit. Question 3. of course. And you’ve really got to be alert in looking for it. We did not identify coke with the video camera. This is primarily important in the sense that as it forms during operation. Another option that works sometimes. I fully support the recommendation the panel made . or much rougher than the stainless steel which. it’s less likely to break off from a small upset. So just another option to at least alleviate some of the downside of this coke buildup. We missed it during the shutdown. We put it into two units. and when we tried to startup. I’m Bill Wilson. This is a picture of our secondary hopper on our secondary cyclone. and they didn’t see it. In another FCC shutdown following the coke incident mentioned above. What is your experience with erosion in regenerator secondary cyclone dust bowls? Explain the effect of cyclone size and catalyst loading on expected cyclone life. you need to take it out. and Lou Frederickson kind of demonstrated. It will cause a problem somewhere sooner or later. As you all know.): Not so much a question as a comment. but when we did get someone into the cyclones to look specifically for coke. we’ve also seen that with regards to coke buildup on things like counter-weighted valves. if you have refractory lining on the outside of that outlet tube. I agree it needs to come off. is pickled and does not particularly corrode. It was really easy to figure out where it came from. we did some experimental work with filling up the back area with some special refractory and a special design. once you find it. We attribute it to the fact that the low chrome and the carbon steels will have an oxide surface on them. is that it tends to stay on refractory lined surfaces better than it does on a steel surface. and a rough surface. JOSEPH W. or had reported in a number of our cyclones that people have had coking in the reactors for all the reasons that were mentioned.): We’ve also seen. If anybody’s interested. The other thing Larry Carper mentioned about the difference between stainless steel and the low chrome and the carbon steels. it was black in there. or you might have the same problem we did. an FCC consultant with Barnes and Click. This Sun Refinery has regen cyclones that are too small for the throughput that we desire. One of the questions they had here was about using anchors to hold the coke in place. we found deposits in the same location. you might not find coke deposits like this. everything was shiny. Lou’s stayed on until they started back up again. But we actually have had one case where just lining that tube prevented unexpected shutdowns from plugged diplegs after spalling off the outlet tube.the other side. It went through the diplegs okay. We had known since ’93 that our cyclones are too small. We did add some more wear plates and we improved the secondary hoppers by adding some length to them and putting in 1" refractory in lieu of the ¾". We added wear plates to the secondary hoppers to try to avoid some of this wear through on the secondary cyclones. and Kellogg specialists. we talked to Tony Schultz. we increased our design conditions to 55. and we were wearing into the metal. We had a five year and three month run. In preparing for the 2000 turnaround. We talked to Ed Tenney. In '95. We had to do some research with cyclone experts. About six months before our last outage in March. we had new cyclones. we were anticipating to have as many as 104 wear areas that we would be prepared to patch. 9 . hoping that we would be able to run a little longer without having a hole through. We had excessive wear also in the secondary hoppers. we did run longer. even with our improvements.to live with that limit as long as possible. The history in ’89 with our cyclone wear was that we had excessive wear to our secondary hoppers and diplegs. we decided that we were running velocities that were too high in our cyclones. But still. FIGURE 3 So we presented much of what I’m telling you today to our upper management. In ’89. You can see that we lost the refractory. In ’95. and we added more wear plates. So we added wear plates. And what you're seeing there is circular wear at the very top of the dipleg and that is what's worn the most. And we told them that in ’85. we lost the hex. This is the kind of wear we've seen.000 bbd. We were about a month away from hole through. we were one month away from a hole through in both these situations. This is a picture (Figure 4) looking down into the bottom of the secondary hopper. They were put in for the high temperature regeneration. Seven out of our eight hoppers had those kinds of holes in them when we opened them up in the year 2000 after a five year run. we put new secondary hoppers in on that outage. We also put some wear plates on the diplegs where we found some more wear out areas. That was on the same hopper that you saw a picture of just a minute ago. we had an average velocity of about 81 feet per second at the inlet of this second stage hopper. so we had a pretty good history on this unit. So we found a way to limit our velocities and we did make it to the turnaround. We had run different run lengths at different velocities. we couldn’t have run much longer. in relation to the velocities. Each one of those is an actual hole through the hopper area and the dipleg. We could tell that in a four-year run. From this photograph (Figure 5) I’ve got some more comments. But as you can see. we had an 10 . We’d have only made it maybe one or two more months. That’s another picture (Figure 5) of the holes where you can see the white dusting there coming down. before we had done some of the improvements. Then for the five year and three month run we had in our ’95 outage. I guess.FIGURE 4 FIGURE 5 But we’ve slowed our velocities down from the 86 or 87 feet per second at the inlet of the secondary hoppers. We had given our management a choice of shutting down earlier or limiting our velocities. and I’ve just taken a package from the Premcor refinery in Lima. refilled them with refractory. But in '93. we had good inspection. and so you have less erosion potential. So it's very easy to have erosion. KBR strongly believes you want to limit the secondary cyclone inlet velocity to about 75 feet per second. FARLEY: Regarding the cyclones. Inlet and outlet velocities in the secondary cyclones are higher than the primary cyclones. This is a critical parameter for maximum efficiency. of course. think this is a large factor in erosion in the secondary cyclone. so you have a reduced swirling velocity. and we didn’t change to anything that was a larger size or different. which I believe they're planning on solving by replacing the cyclones next time. In the regenerator cyclone. The reason is that companies want to take advantage of capacity in the unit. we had a cyclone holed just below the dipleg in the secondary cyclones. and took the boxes off. in terms of erosion. they have a continual problem. BAZIL BURGESS (Premcor. in terms of minimizing secondary cyclone erosion. And on the next major shutdown in '94. we think there is more flexibility in outlet velocity. we’re going to give them these same limits. we think it’s pretty common to see wear on the secondary cyclones’ dust bowls. 11 . so we knew what to expect. and brought it back up. which gives you lower swirling velocities. We do not. That gives you a really high swirling velocity found in the dust bowl area. Increasing the cyclone size gives you a lower velocity. It is important to note that most people believe erosion is a factor of velocity to at least the third power (cubed). And just as the picture shows. For our next run. installed boxes. In the primary cyclone you have high catalyst loading and that loading provides a kind of cushion for the particles to ride along each other. They have an existing cyclone there and they can make money today by running over 75 feet a second. but we believe you should stay below 175 fps. Some people believe it is even higher than this. So we knew that was the range that we could live with in our situation. we went in. And that’s basically what we’re doing now. however. 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. vapor comes up the dipleg. which makes for very poor conditions in that dust bowl. which leads to a much more erosive condition. The high loading exerts some drag on that gas. But in the secondary cyclones.average of about 82 feet per second. So we had good history. The upper cyclone in the secondary cyclones has low solids loading so it has higher swirling velocities. We also believe that high L/D (length to diameter) ratios will improve cyclone efficiencies. increased the length of the cyclone dust pots. It's fairly common to do that. We knew with a maximum velocity of 85 and an average of 83 we would be able to hold out. We went in. And then. However. Primary cyclones’ high solids loading and fairly low pressure drop means gas usually flows down the dipleg. which used to be the BP Refinery there before it was sold. we think it is a marginal improvement. There is a substantial change in erosion potential with a small increase in velocity. high L/D in the first stage is more useful. This is not to say we do not believe in high L/D. retired): My name is Bazil Burgess. We know we’re not going to be able to wear the cyclones out at the secondary hoppers if we control these velocities. generally. it's not uncommon to see holes this size in the dust bowls. is a primary cyclone that’s not the best cyclone in the world and may not be as efficient as it should be.We had an opportunity to go back in about two and a half or three years later. we didn’t have any idea what had caused it. I think people have already mentioned inlet velocities as a key item. which I don’t think has been mentioned. Obviously. with about 37 years experience in the Cat Cracking business. can be problems in that area. DONALD F. But on the other hand. I just wanted to reinforce and maybe offer a few new comments to what were made. sometimes the wear plates. temperature coming out of the regenerator and also pressure. if you’re trying to fix something during a turnaround. and discovered that the entire bottom half of the cone of the cyclone on the secondary cyclones had eroded to bare metal. but I think we’ve seen in some cases. 12 . put a wear plate on. you might try to accommodate some of these issues. And sometimes the fix is to try to improve the primary cyclone. The other one. you generate a deeper vortex. and he had informed us that our cyclones were borderline on length the first time around when they were built. then there’s more time for the vortex kinetic energy to be dissipated before it gets into the dust bowls. unless they're filled with refractory and really tight to the surface. everybody has done the wear plate scheme. and you have to be able to work that out. I sort of call it a dysfunctional primary cyclone. We got a recommendation from them on velocities for that particular cyclone. You might be putting higher loadings and more catalyst and larger particle sizes into the secondary cyclone. The last item. I think it’s pretty well known if you talk to the cyclone vendors. formerly with Exxon. but we went ahead and made appropriate repairs. we’d eroded to bare metal there also. I believe their plans at this point are to replace those cyclones. At that time. and he made us up a set of charts based on airflow of the air going into the regenerator. is the L over D ratio of the cyclone bodies. which I think cyclone vendors will talk about. Realizing again. and the assumption is you might have a clean sheet of paper and you’re designing new cyclones. The numbers that I like to see are probably between 75 and 85 feet per second in inlet. We had the same circumstances. if indeed you can. but it wasn’t as bad. And we operated by that. I’m currently with Carmagen Engineering. because of a failure elsewhere in the unit. because an existing unit that might shorten the dipleg. So. because they’re also planning on going up in capacity. And right at the junction of the dust pot and the dipleg. and actually there was enough kinetic energy in the gap between wear plate and the old metallic body pieces. If the cyclone bodies are longer. you can’t always lengthen your cyclones. And we were probably increasing our velocity. The other item that was alluded to is the gas outlet velocities. We still had a little problem when we went back in in ’99. At least in some circles. and it’s driven down into the dust bowl. One thing that I guess I was surprised to see several years ago — we've seen where people have boxed in. SHAW (Carmagen Engineering. that if you have a higher outlet velocity. and talked to our process engineer. I’ve heard people talk about slightly lower limits. But I think that also depends on the overall system that you have.): My name is Don Shaw. I listed what I think might be root causes for this problem. that is considered to be a critical aspect. Inc. and people hole through in that area. And people with cyclones that have put in smaller outlet tubes have seen this erosion occur. talked to our vendor. that the erosion occurred in that little gap. One other comment. you can do a thermal imaging. after the cone comes into the secondary hopper. As the unit comes online. but it makes much more difference on the primary cyclone. and we could lengthen the secondary hopper. but this probably wouldn’t help you because elevated temperatures are certainly going to tell you that you have refractory loss. I would like to poll the audience to determine who is using and who is interested. TENNEY (Marsulex Inc. But. 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. we would be above our lower transition cone into the dipleg. so we’re still waiting to get the final results. Maybe Ed can address it. We could cut back the cone a little bit. What we do is embed a detectable material that is encapsulated in the material of choice for the thin wall of various linings . and this refractory that’s in the face of this 13 . We didn’t really concern ourselves too much with that. could be Atchem. DEMARTINO: Bill Dawes of United Refining is in the audience this afternoon. like aa-22. on the secondary cyclone. We assumed that this would be more for the thin wall abrasion linings. But this system is for a typical hot wall installation with a thin abrasion-resistant lining.EDWIN D. And we had a couple of options there. If you’re on a stand pipe or a regenerator wall. We trimmed the cone back a little bit so it was a little wider. it didn’t stop the wear. We were worried about the wear point in the secondary hopper. resulting in no development. It doesn’t make a whole lot of difference. He and I came up with an idea and we had some patent searches done on it. We had the secondary hopper made longer so that where our vortex ended. We elected to do both. But we have seen the same designs in some online petrochemical cyclones and there we have seen a night and day change from the erosion to no erosion. which is basically is to embed a material at a specific thickness in the refractory lining. 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. So that seemed to make a little difference. JOSEPH L. as you can see. And we have been putting some of those in here for the last several years. But could you share with us the L over D and the outlet velocities associated with that? MARLOWE: Yes. Is anybody currently using cyclone wear indicators and what type? Is there any interest in it? Please raise your hands. from what I understand. could be A22. Question 4.): We did some work on this some years ago. I’m not sure. 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. The location of our wear was right at the bottom of the vortex from the cone. and we found that the shape of the hopper makes a significant difference. It still was the highest velocity right there at the bottom of the cone. I guess we didn’t really change the L over D.could be plastic. Funding did not follow the requests. (Response: One). abrades away, this detectable material would release itself in the operational environment of the Cat Cracker, or a petroleum coke gasifier. We’ve already had some discussion with the catalyst companies that do the testing of the catalyst 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 pick up a certain ppm, you know that you have a problem somewhere where you had determined to install these devices. And if you know that you ran 20 months and you have a release, it’s time to start 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 market something like this. And I really don’t want to be bothered. So we’ve been talking to Vesuvius and RHI and Resco and a couple of the others to see if they could purchase it and market it. It’s much more than a company my size can handle, but we think that it’s going to help a lot of companies 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 a thermocouple-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 unit you’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 encapsulate the lines with A22 and then Bob Jenkins is inspecting more of our stuff, so who would want to pay for that? But on a weekly basis or twice a week, typically the catalyst companies will check the catalyst. And for a nominal fee, they can look for this type of material. Once you say “Hey, we have a release”, you have a potential problem down the line. And then so you don't throw 100 tons of catalyst out after your first run, you have a benchmark of say 1 ppm of the material. So the next time you have a release in there of say 2 ppm, you have another potential problem down the 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 suggested there is also a possibility of using this type of cyclone or a thermocouple insulation for a refractory cyclone wear indicator. I don't think anybody has done anything with it, but it was a possibility at that time, so it's probably still suitable, because I do know the thermocouples 14 they’ve got inside the reactor now are still functional, and they are the type of thermocouples that you 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 the advantages and disadvantages of upward and downward pointed nozzles? 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 much discussion with different people. Kellogg Engineering agreed that these would be about the best four different methods we could try. FIGURE 6 So we tried ceramic nozzles on the air grid on a small scale basis. We had some direct replacement and we had some oversized sleeves that we had tried in the past. We took a look at those and we saw that neither one of those actually solved our problem. We were getting a lot of erosion and backflow into the nozzles. As you can see from this picture (Figure 6), we have a couple different types of nozzles. But the wear is pretty typical for anything that projects outside the refractory. We could see that you get outside wear and you get wear from the catalyst recirculating inside the nozzle. What was interesting to us is, in ’95, once we cut back the nozzle to the refractory lines the eroding lessened or stopped. At least it seemed that way. So we did cut a number of them 15 back flush to the refractory line and we left those that had cut themselves back alone. We had an order in for a couple hundred of the ceramic nozzle inserts, and installed around 40. That’s what you see with the white circles here. Actually, the picture (Figure 6) is from the year 2000 this last spring. They start out pretty square and flat at the surface, and then wear pretty uniformly in more of a dome shape. The other thing we did was replace a number of in-kind nozzles and we did try some oversized sleeves that fit over the worn nozzle tips. But by far, the best thing we could see after we opened up on the year 2000 spring turnaround, was that just cutting back the nozzles to the refractory line worked well. Unless you have a nozzle that actually has recirculation and goes back inside the nozzle past the refractory line, you really don’t have to worry about adverse effects. Kellogg will tell you, that you want to make sure your nozzle length still has critical dimensions or you will still have wear problems. You have to keep a minimum dimension from the orifice of your nozzle out to the end, whether it’s at the refractory line or whether it’s at the end 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 air discharges into the bed. The orifice takes pressure drop to make sure there is even air distribution. That helps eliminate catalyst backflow in one section of the grid and which then gets discharged through another section of the grid. When catalyst backs into a grid on a routine basis, 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 the static head of the bed at turnaround conditions. And, you have to be careful about catalyst attrition, which can be caused by high velocity jets 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 a nozzle where the orifice is located too close to the nozzle discharge; this gives you a high velocity jet discharging into the catalyst bed because the flow is not fully developed in the nozzle. That can cause catalyst attrition. KBR also fully refractory lines the external portion of the air grid to improve mechanical reliability. This reduces the temperature the grid operates at as well as cuts down on the temperature differences between the top and bottom surfaces of the grid. There is a portion of the question about upward and downward pointing nozzles. I think the industry experience has been that both types of nozzles will work. KBR prefers the downward 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 some mechanical 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 two designs 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 a tapered configuration that would match the flow distribution as it came out and the inside was 16 So we changed to a design similar to that which Kellogg mentioned where we’re looking at a section of pipe with an orifice at the bottom. So I would anticipate again. Dynamic-Ceramics has got around that by patenting a design. It was a ceramic insert inside and it had two pieces of steel outside the ceramic. That worked fairly well. This worked exceptionally well. because the thermal expansion differential is about half of that of the stainless steel. and the metal was barely worn after several years. What would happen is you’d get a polishing of the refractory on . we allow enough play on both sides of the collar to take care of that expansion 17 . JOHN PRICE (Corhart Refractories): John Price with Corhart Refractories. since it’s been a while since I’ve done this work. But what we did is we used a thin wall piece of pipe. This was reported to this meeting probably in the mid-’80s. because the designs we were given were based on a square edged orifice. MARLOWE: This was a Corhart design. but what we do. either tubing or something like Schedule 5 or Schedule 10 stainless. there has been a problem in joining ceramics to metals due to the difference in thermal expansion. that design also would work for several years.): Good afternoon. and when we came back down and looked at it.): Did the gap cause you any problems for vibration? MARLOWE: On vibration? No. both the ceramic was hard enough for resistance similar to the refractory. we had actually maybe just a few signs of some erosion in the nozzles. RICHARD BINKS (Dynamic-Ceramics Ltd. And those two pieces were welded together and that locked in the ceramic insert. But you should consult someone else on that. We had about a 6" diameter polishing of the top of the refractory. Historically. Of course. We're the ones that manufactured the Corguard. and we put in a rounded edge orifice. there’s a little gap there so you have this difference for thermal growth. And then there’s an outer pipe sleeve on top of that. What experience does the panel have in joining ceramics to metals and getting around the problem of the differential in thermal expansion? MARLOWE: You mean as far as attaching the two? RICHARD BINKS (Dynamic-Ceramics Ltd.we were looking at 1" thin wall pipe. and we put the top of the pipe right at the surface of our refractory.): Yes. They probably would have gone for several more runs without any trouble. and the one that has come up with that design. I believe that’s about a 4 to 1 ratio on the pipe and the length. RICHARD BINKS (Dynamic-Ceramics Ltd. There was one piece of steel that was shaped for the header similar to a sockolet. but very little if any at all.rounded so we had an exact diameter for the orifice. We did have a flow problem. We've used it in other areas other than the air grid nozzle. We didn't see any cracking or anything like that if that's what you’re referring to. The waste factor is down around 5%. Has anyone used a “no cure” refractory and has the experience been satisfactory? DEMARTINO: The “No cure” refractory that we dealt with made by the John Zink Company is called Thermbond. We have gunited the material in large quantities and have hand applied it to many areas of Cat Crackers. Some applications may not be justified for the use of such materials due to the fact 18 . you can dry gun by that time. Are the shell temperature (k) values or test results affected? Is coke impregnation affected? DEMARTINO: We have the opportunity to do either wet or dry. waste the first ton up in the unit to get it nice and gelled and the proper water/cement ratios. maybe a little bit higher on the overhead applications. And we haven’t had any leakage that I’m aware of since we’ve gone to that two-piece design. Question 6. There are retardants that can be put into it so it gives you a little bit more working time. If you’re doing a few hundred square feet or a thousand square feet in your regenerator or even your reactor. if you have continuous feed mixers and a ten ton per hour rockvalve swing tube refractory pump. Those are the obvious advantages to wet gunning. and we had a few installations where there were a couple that leaked. Compare wet gunning of refractory materials in a coke impregnation service v. Gunite applications require a large amount of personal protective equipment. just you’ll be welding the steel to steel whether you’re on a pipe grid or a dome or whatever. Question 7. get your mixes just right. It uses an acid as the liquid to reduce the heat cure schedules sometimes down to zero. there are some wonderful pluses to doing the wet gunning of refractories. There are no laminations. There’s no dusting. But when we went to the twopiece design and we controlled the sealing of the ceramic to the steel in our shop. The material will gel. regular gunning. If you're hand packing. there was a onepiece collar design that relied too much on the installer to make sure that the seal was good. And the set times of the refractories that are being applied can be adjusted. Initially. stick welding all at the same time. and I’m sure the other competitors will agree with this. There are pros and cons to these types of materials. Plus you can have multiple crafts doing simultaneous workscopes like stud welding.and have the surface sealed with the gaskets on both sides so that you can allow for that differential to take place within the nozzle or within the joint and still then. This is due to the dust and the acid used for wetting the material at the nozzle. it really has a chance to reduce some of the critical path that you may have on your turnaround. but it won’t have an exothermic reaction right away. Applications can exceed ten tons an hour. then those problems went away. by the time you set up all your equipment and slick the hose. based on the application of any specific turnaround. ramming or casting them they are a pleasure to work with. So. The big thing you have to remember is if you have enough volume. The application is extremely precise versus the dry gunning. scaffolding modifications. They weren’t heat cured and were ramped up to operating temperature quickly with no spalling at all. have been there since the ’70s. we’ve got a lot of different refractories. DEMARTINO: I would agree with you in the reactor and the regenerator. In the meantime. not mixed right. and we were getting hot spots. We went back in with about two-thirds of our regenerator with this pump casting material. These units are tremendous in size and you cannot heat them fast enough. light the air heater pilot. and we were monitoring.that the cost and time of application may outweigh the cost and time associated with the heat cure. and we’re very hopeful that this is going to hold up just like it has in the couple of 19 . The vessels and catalyst are large heat sinks and the start up process is sufficiently slow enough to avoid adding time for refractory dryout. purge the reactor. we actually had to cool our regenerator walls with some steam spray nozzles. that you’re not going to get that refractory to hold up too much longer than 15 or 20 years without having some problems with it spalling. And we were planning on replacing this with conventional refractory. load catalyst. Use the total installed cost approach with repairs which includes refractory dryout. Some of our corporate people got together. heat the catalyst. What is the experience with form and pump casting technique v. we have a multi-disciplinary team review the refractory repairs. including locations. we heard about some people that were trying some of this pump casting material. The units are pretty old.this is a slow process. i. seriously challenge the argument. The question you should ask yourself is why do you need to use them? If the argument is you want to save time on the startup due to refractory dryout. went and saw. light the torch oil . cracking.e. Question 8. We try to take a certain square footage of the regenerator and try to get it replaced. So. but we’ve had the opportunity to apply these materials in the air heaters of the Cat Cracker. And we try to replace part of the walls. Our approach to refractory dryout is quite simple. in talking with our refractory specialist and others in the business. CARPER: I am not aware of any low or no cement castable used in our units. Well. We know. perform an air test. In the regenerator. By the time you start the air blower. Between 1995 and the year 2000 for our turnaround. we had some material here that we’d already replaced and it was less than 15 years old. so this is a picture (Figure 7) of what it looks like when they forming up one of the sections. every four or five years. So we were concerned. or it wasn’t exactly the right material. deteriorating to the point where you’ll have hot spots. It doesn’t take it a real long time. we had some refractory that was not cured right. at our refinery. Before startup. refractory types and quantity of material installed and the startup procedure. and got some information from people who had seen this material first-hand after it had been in service for a while. wet gunning refractory? MARLOWE: In talking about refractories. But it turned out to be only in the upper third of the shell on the regenerator. we try to get about a third of it done at every major turnaround. getting thermal pictures to make sure that we weren’t getting larger or different spots. They stack on top of each other and keep moving the forms up. So this is one of the options we have over a light gunned refractory material. With the lightweight and the medium weight refractory. put a pair of vise grips on above the snap configuration. and then a little bitty dent or “snap configuration”. it's a non-issue. it works well. torque it. so that it can be removed once the pumping is done. You're going to get a myriad of cracks from this stud to the next stud to the next stud. Screwed to that would be a piece of 3/8" stainless steel rod that has a thread for a few inches. and then what you would do is simply fill in this cavity with other refractory that you want to use. and then a flared nut to retain the base of the footed anchor. On Jim Marlowe's photograph. you would start by welding a 3/8" carbon steel stud on specific centers. A rod would come through the 3/8" spacers. But there are some other.locations we’ve seen. there is an issue with cracking. you 20 . and would certainly fill that little void up with the refractory that you were pumping. After that it would have another nut. by the time you set all this up. maybe slightly better ways to approach the installation. and then there's a fender washer. You would attach a naturally a footed anchor around the stud. and you may have multiple crafts involved. you simply strip everything out to this point. Including myself. I guess it's like pouring a concrete driveway and you're putting a column every six feet. because just in the pouring application. you're going to set up some tremendous stresses with the higher density refractories. have another fender washer and a nut. But for the medium and the lightweight refractories. But please bear in mind. When you start to get up into the higher density refractories. Once that's complete. This would support the Masonite or plywood. we cannot install this. By the time you set up this form system. you could see this plywood and 2 X 4 whaler that's two 2 X 4's with a 3/8" spacer between them. and it would snap off. We’re hoping to get 15 or 20 years without any spalling or cracking. because the carpenters want to do it and the iron workers want to do it. For form and pump casting. There are some other systems out there to circumvent the patent system whereby they'll build a set of wooden welders or rent steel forming systems and have supports back to the cyclone system. and everybody gets involved in some of this stuff. FIGURE 7 DEMARTINO: The system that Jim’s talking about is a patented system. maybe a pair of glasses. DEMARTINO: Right. ours was a large area. Our experience with bolted slide valves is that the bolts coming loose tend to cause the valve to ultimately fail (Figure 8 “Bolting Failure”). Boltless Design”). We'd end up cutting the bolts out and tacking the nuts back to the orifice plate anyway. (Figure 9 “Boltless” Weld-in Design”) (Figure 10 “Traditional vs. The boltless design seems to cure these problems. You do have some issues with making a cavity and filling it with refractory. Jim? You need more than 100 square feet. Right.could shotcrete it. Again. Question 9. you need quite a bit of volume just to warrant the application. The other thing I see. we would have to repair and/or replace these bolts. however. but that’s still within spec. During every turnaround in the past. if you know what I mean ( laughs ). if you drop a coffee cup in there or something like that. Say 20 feet tall and the circumference of the 35 feet diameter regenerator. we haven’t had a full run with them yet. we installed boltless slide valves in place of our existing Regenerated catalyst and new Recirculating catalyst slide valves. 21 . What is your operating experience with a slide valve that has “boltless” internals? COUSAR: During our October 1999 revamp. MARLOWE: Yes. The Recirculation valve is very close to our combustor due to our structure limitations. Due to the thermal difference and the tight tolerances in the slide valve tongue and guides. However. we have had no problems operating the valve with up to a 150ºF differential across it. I am also aware of two miserable failures. the slide valve tongue would hang up at 60% open.One problem that we had was due to a design anomaly. The radiant heat affects the recirculation slide valve body in such a way that there is up to a 250ºF differential across the valve. What do you use to purge the slide valve stem? Are there any advantages for a “purgeless” system? CARPER: I am aware of success stories within the heritage BP units using “purgeless” slide valves. Question 10. Since then. The valve was designed to have less than 100ºF across it. 22 . We solved this problem by installing a 1" thick thermal blanket on the bottom of the valve. We have since installed the proper springs to remedy the problem. We did experience a packing failure. We do purge the stems of our slide valves . but it was due to an engineering bust related to the spring can hangers on the slide valves. The preferred medium is nitrogen. and keep it there as consistently as you possibly can and hope it doesn't stop to the point where you plug things up. For each of those Enpro valves. You need to try to establish the right flow just like Larry was talking about. but it's what we have available. For purge control we currently recommend restriction orifice plates. and keeping the flow consistent is always critical to any of our purge systems. you're going to plug things up with catalyst and you might not be able to clear it back out. We size our restriction orifices using an exit velocity criteria. ensure the steam is properly trapped and dry. As soon as you get a stop of the flow or you get too much flow or too little flow you are headed for problems with the purge. ROV’s. Not necessarily as dry as we'd like to have it. stuffing boxes and actuator seals due to the catalyst laden gas. It seems like you can't go four or five years without having some kind of upset or interruption to the purge medium. We have used restriction orifice unions which leak and restriction orifice valves. We've had one packing that gave us a little trouble and will continue monitoring. the manufacturer recommends we either leave it purgeless or that we can purge it partially. But the flow. We found manufacturing variances in ROV’s which eventually lead us to restriction orifice plates. Damaged items included stems.our spent catalyst slide valves and our regenerator slide valves. and the purge medium that we use right now is steam. 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 Little Purge”). and the other one seems to be holding up very well. we've just installed three new Enpro butterfly valves out of about six or seven butterfly valves we have on our Cat Cracker. We currently have all purgless systems on slide valves (Figure 13 “Purge-less Stuffing Box”). If you elect to use steam. 23 . We do recommend that a detection system be placed on the “purge” port. Once this happens the risk is not getting the purge back or becoming less and less effective. and some of them are on our butterfly valves. If a failure of the primary packing occurs. We were not able to determine the root cause for the failures. We do restrict the flow to these purge connections. If you don't have enough flow. air. and nitrogen. The options that we have for purge in our refinery are steam. We've tried all these purge mediums in other locations. MARLOWE: As Larry talked about there are many mediums you can use for purge. usually dry orificed air. Too high a flow gives you a lot of circulation and gets catalyst flowing in there and you're going to wear some things down. whether it's in your purge system or in other systems.Both failures were on flue gas valves. so good. We design for a limit at 90 feet per second at the annular area between the stem outside diameter and backseat bushing inside diameter using downstream conditions. Right now. the amount of flow. the detector will sense it and more packing material can be added into the packing area thereby sealing off the leak. We've elected to see if we can go purgeless. We recommend using steam or nitrogen for regenerated or catalyst control valves and air or nitrogen for flue gas valves. Purge medium is dependent service. and so far. Our solution was to revert to purged valve stems. 24 . sledge hammer and making the anchor look like a tortilla until it falls to the bottom of the unit.1. you can stud weld with up to three guns nearly simultaneously. You’re going to get a more consistent weld application. It's not like taking a 20 lb. We have installed about three million stud welded anchors in seven years with minimal failure. especially if you're going up in cyclones hex steel. FIGURE 14 25 . We put premier Atchem in there. 30º to the other side. The job turned out very well. they’re three times faster than stick welded hex steel linings. This is a cyclone conical shape. There’s also reduced labor. which is an AWSD1. The welding flash hazard is near zero. you don’t need a welding shield. and it’s a very. I think I have photos (Figures 14 and 15) of a cyclone that we were doing. so just safety glasses are acceptable. And all that means is you’re going to put a an apparatus over the weld and bend it 30º to one side. they will not actuate. because the flash is contained in the ceramic ferrule. it appears in the northeastern United States. and have performed extremely well. With the single power source. And there have also been some of the refiners (I won't mention names) who have been through at least two runs on their Cats with the hex anchors and the v-anchors and things like that. because we’re using bricklayers versus boilermakers. It's a wonderful way to save money. they will actuate. very easy weld test. So there’s some reduced costs in equipment use. A little bit tougher to stud weld a specific pattern in a conical shape rather than in a barrel. If you pull the trigger on two of them at the same time. and that was for Foster Wheeler cyclones for China. When we talk to the customer about the hex anchor productivity rates. but it seems to be less accepted out West. How have stud welded refractory anchors held up in service? How long a run did they have? DEMARTINO: Stud welded refractory anchors have caught on. The savings are about 40% over the hex steel applications.Question 11. and the inspector says he thinks it's no good. But if they’re seconds apart. That's a stud welded hex anchor that happens to be made by Causeway. We put in stud anchors. and as you can see. This picture here (Figure 16) shows the surface of our regenerator. It's much faster and easier to use with no adverse problems related to the many installations that Sun has. We've been using it in '85 '89. I don't know whether that's just because we make sure we put them in right or we make sure we get the surface preparation you need. We did some testing on the stud anchors and came to the conclusion that they were just as apt to bend and break at the anchor as they were to snap at the weld out. and the year 2000 turnarounds. very good with them.’95.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. FIGURE 16 26 . But we have had good experience with them. We do prefer to use the stud welding applications. we have had the stud welding and we've had the stick welds and anchors on the surface. But there are still some areas where we have the stick welds. and most recently we stud lined the Kbars for the air grid. you really have a big problem. if they’re not solution annealed. but they’re not in the same temperature cycle. But if you stud weld the carbon steel stud. Working with Bob Jenkins and doing some vibration casting of refractory applications.DEMARTINO: There’s one more application. They estimated that they would be back within 40 days. some samples had up to 9 % sigma phase. there’s no heat affected zone from re-welding a solution-annealed anchor to a carbon steel. Larry’s going to have some comments in that direction. Between the ’95 and the year 2000 turnarounds. we ended up developing some very serious cracks on stream. Then they put additional material on top with valves to vent off away from themselves. It seems to help out some of the other applications that we have. 304H specifically. and we were getting these cracks. We have experienced extensive cracking on a 304H stainless steel line and its welds due to sigma phase change after 25 years of service. have a tendency to fatigue and snap during the refractory installation. and we wanted to know 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. Question 12. and were able to grind down and repair most of the cracks. We had to do another one before our next planned turnaround. and 40 days it was. But the majority of it was right around the heat affected area and the welds for the 308 rod material. We developed an 18" crack along this area (Figure 17). which you see in the flared nut and put the solution-annealed anchor onto it. We were able to get this 304H line out of service and change it during the turnaround. We’ve been concerned about that for quite a few years and in ’95 we did find quite a few cracks in our overhead line between the third stage separator and our power recovery turbine. I know we’ve had discussions about this before at the NPRA meetings. Most of the cracks were related to cracks in the weld area or the heat affected area in the parent metal. It probably decimates the solution annealing of it anyhow. So once it starts. We found some cracks and we sampled those for sigma phase. and it ties into a 54" line. Our ducting is over 20 years old. they recommend that anchors be solution annealed before they’re installed. because the heavy vibration. We brought in some specialists with aluminum suits and cooling devices and were only able to work twenty to thirty minutes at a time. We still have a few other pieces of 304H that are over 20 years old. 27 . over three weeks. so we were glad to get this behind us. We had welders in there almost the entire turnaround time. where the two lines come together (Figure 18). We had to bring in specialty people since this was 1350oF material with catalyst fines coming out. It was a rather expensive repair and this didn’t stop our problem. What is the life of 304H stainless steel and can its remaining life be predicted? MARLOWE: This relates to 304 stainless steel material. and about Cat Crackers and concerns about what is the predicted age for how long can you live with 304 stainless steel material. They had to put stiffeners across this crack area (Figure 19) and boxed it up on each end. This was along our 30" bypass line that goes around the PRT (Power Recovery Turbine). FIGURE 17 FIGURE 18 28 . I had an opportunity to visit one of our refineries in Europe earlier this year.FIGURE 19 CARPER: Well. The PRT was the same vintage. a weld metal study concluded E308 filler metal was not optimum. Currently we specify E347-16 as the filler metal when the operating temperature is above 1000ºF and use E308 when the operating temperature is below 1000ºF. and developing a long term repair/replacement strategy. In looking at the system. We've had problems. We had a line that was in service for close to 26 years. We eventually replaced several sections of duct in key areas and replaced the filler metal in many of the longitudinal seams. ROBERT GOSSELIN (ExxonMobil Refining & Supply): Robert Gosselin. Less than 4 years. ExxonMobil. you had cracking when 29 . the duct wall thickness was substantial when compared to the previous unit resulting in substantially lower hoop stresses. We had problems all throughout the 26 years. Repairs consisted of replacing a section of the duct. What we found . but it wasn't as old as your line.what you mentioned about the ferrite content . We installed a PRT at one of our refineries in the early ’80s. Beaumont. decreasing the operating temperature and pressure. The design for this duct was to use minimal or no corrosion allowance. This forced us to look at weld metals. If it was too high. Use as thin of sections as practical and 100 percent radiograph the welds. The crack is through the center of the weld. After several years.if it was too low. We found the stress rupture properties of E308 filler metal were about 80 percent of the parent metal at elevated temperatures. you had cracking when you welded. I’ve seen similar and it looks too familiar. We also recommend controlling the ferrite number below 6. just like what you're talking about. We put a new line in. Shortly afterwards we began experiencing weld failures due to stress rupture. just looking at the picture there. we had the same problem again. In the mid ‘90s we experienced a failure through the middle of a weldment. This resulted in changing our specifications from E308 to E347 filler type weld metals when welding 304 stainless steels. A result was they were not experiencing weld failures. 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. one of the options that somebody proposed was use a different material. Bazil. What kind of temperatures are you looking at? BAZIL BURGESS (Premcor. But I don’t know what else. We have seen very little sigma phase cracking in our cyclones and we have one unit where the cyclones are 36-37 years old and another with cyclones 33 years old. 5" of abrasion 30 . The cost was prohibitive when compared to E347. I know the numbers are wrong. So we put acoustic emissions monitors in the locations where we had problems and kind of listened for cracks. basically. something like that. We felt like the problem was during the startup going from low ambient temperatures to operating temperature. retired): Also on the ductwork. E1682. that's what most of the refineries were going to. I think that anything else would be way too expensive. we've seen cracking in cyclones. Like I said earlier. because back in the late '80s. We might look into that later. But EPRI talked about a different rod. one solution is to use thicker metal. BAZIL BURGESS (Premcor. Has anybody had any experience with cyclones? I've had sigma phase cracking after about ten to twelve years in cyclone welds. We did replace that piping with carbon steel. MARLOWE: No. BAZIL BURGESS (Premcor. But I guess the only thing that I’ve heard as far as a solution from the panel was basically thicker metals to give you lower stress to extend the life. I guess I’m asking if anybody had experience. but we’re hoping maybe that will help. retired): I've actually run overhead lines made out of stainless steel with AA22 in it at 1450oF design temperature at about 50 psig. E16-8-2 has about 95 to 105 percent of the stress rupture properties of the parent metal. even looking at a different metal. A solution is to design the cyclones and especially the hanger system for lower stress. It was.you started up. Is this common also? CARPER: Bazil. we had looked at just what other stainless steels would be acceptable for material. that was affordable to use? CARPER: We looked at other filler metals during the study discussed earlier. as we didn't have the time. retired): All we're talking about right now seems to be ductwork. I don’t remember now. DEMARTINO: What would be the temperature of this. Is that pretty much the only solution? I guess one of the concerns. An alternate welding electrode was E16-8-2. We found this welding electrode was not readily available during a late 1980’s project. it was an E1864. We haven’t tried it yet. Since we weren't considering this line to be redesigned we stayed with the 304H. has anybody considered using refractory lined carbon steel. DEMARTINO: Okay. and then when it tried to shrink. During a run between 1995 and the year 2000. you’ve increased the weight of it so you’ve got to go to new hanger designs and a whole lot of other things. JOSEPH W. you wouldn’t want refractory on that line at all. that looked like the best solution for us. we were getting thermal fatigue cracking. we decided it was safer for us to go with the cold wall. because not only were we getting sigma phase cracking. but it also has a SS clad liner inside of it. with what I just described. Between those two phenomena. because you’re riding the carbon? BAZIL BURGESS (Premcor. It turned out to be about a 40" long crack along that area. probably in the late ’80s.): Bill Wilson with Barnes and Click. So that was the solution for us at the time for regenerator overhead line.resistant refractory at a later date. But it had propagated itself all the way out from the liner dissimilar metal welder out to the surface. the point is. we were suspicious that we’ve had a defect that has started and propagated at that location. Inc. the dissimilar metal welds for the attachment of the liner. you’re running about 400 o F .500 o F shell temperature on that line. So we started getting cracking there. because the shell wall of the line was so thick that we were actually getting cracking on the outside due to expansion of the outside wall from pressure from the inside of the shell. with the problems we were running into with stainless. And as a result of that. Do you need some kind of a membrane system. It’s all lined with a 410 strip material or a clad 405 material. Again. early ’90s. because if it comes loose and goes through the expander. Is anyone experiencing problems with E309 stainless steel weld cracking in high temperature service and extended age (>10 years)? MARLOWE: This question pertains to a problem that hit home with us. Question 13. I believe the gentleman from Sun mentioned this was a line that was tied into a flue gas expander. And where they make the welds. it will take out the rotor pretty thoroughly. We have a reactor head that is a low chrome material. we did get a crack to the atmosphere in the dollar plate at the top of this head. This was in the flue area of the plenum. In that particular circumstance. they used a 309 rod. and you’ve increased the size of it. when we had to change it. retired): Well. Just as a point of clarification. but there’s not an issue since you put such a massive amount of refractory that you’ve reduced the cold wall temperature. also. WILSON (Barnes and Click. But. 31 . it couldn’t. you’ve got to get the catalyst out of the air blower. We found E309-16 welds to have poor stress rupture properties. Here it is where we had to grind out the area where the old welds were. Whenever that occurs. and then welded it back up with new 309 rod. CARPER: As part of the study discussed earlier. Our metallurgists are recommending using Incoweld A and Inconel 182 filler metals for 300 series stainless steel to carbon steel bimetallic welds. too.FIGURE 20 So it took some time to get to this condition and it was complicated by some flexing of the platform at the top. we’ll replace that head at our next outage. You turn your air blower into a catalyst hopper. If you’re really lucky. Currently we restrain ourselves to using E309-16 for bimetallic structural welds and where the structure is not critical. To make the repair. There was also difficulty in controlling the ferrite number. 32 . ground that out. That’s a picture (Figure 20). And that’s not what they were designed for. Hopefully. And in terms of why is this a bad thing. It was a combination of the defect being generated and then propagated by the flexing of this platform at the top. we’ve had the occasion where you can open the case screens and actually just pour it out. So we ended up at the turnaround. we ground out all the crack and went back in and got rid of the 309 rod connections. went in and repaired all of the defect areas that we could find in the top of the head. the problem is you get the catalyst back there. 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. we also looked at E309-16 weld rods. II: ROTATING EQUIPMENT Question 14. The ferrite numbers ranged from 7 to 15 with an average around 11. the question is what happens? In the best of cases. And we’ve seen them do that once in a while. but more often than not. your time can go on up from there. and they have some sort of assist to help this valve close. Units in the industry have been down 30 days because a check valve in this service failed. So if you look at the whole scenario. it's the valve we tend to come across. It's absolutely critical that this valve works. We have them in Toledo.That’s kind of lucky. But the issue here is it is not a good thing to have your check valves fail and let the catalyst get back into the machines. maybe up to ten days if you're lucky. Generally. 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. If you have an axial air blower. like Mike mentioned. FARLEY: At KBR. two days. in a lot of cases. we generally look at the Atwood-Morrell swingcheck or isocheck valve. I think several locations have had problems where the proper PM was not done. The next thing that occurs. you've got a good chance of blowing all the blades off of it. you can end up with a more catastrophic failure. They'll also have some kind of actuator that's going to have automatic flows on it. can cause them to distort. Make sure these valves aren't hung up or frozen in place. These are not theoretical failures. We've never really had an incident where it backflowed for us through the blowers. a few days. If you really get yourself in bad shape. Okay. but what might be more likely is you don't know you've got catalyst in the bottom in the case and you restart the machine again. OK? These things have happened. But we have had that situation at our Philadelphia Refinery. putting hot catalyst into the air blower cases. Insurance companies have estimated losses of upwards of $55 million from one incident of a check valve in this service failing. and they've had some serious backflows turning their blower into a catalyst hopper. We always urge you to follow these PM 33 . even if you get the catalyst out. they're counterweighted. But they are changing their specification and they're looking at some improvements so they wanted me to pass along that they have a new design specification and Adams is a brand that is able to meet those new improvements. with some catalyst in there. you might be able to drop catalyst in the machine while it's still rotating. and have all the parts available. Some of the other guys here are going to talk about what kind of check valves we have and how they work. which really aren't high temperature machines. three days. And in that case. also. if you do severe damage to the case. They're going to try the Adams in their unit this fall when they have their shutdown. and you can end up with flange leaks and sometimes warping the things bad enough to cause the machines to rust. And I'd like to reiterate what Mike talked about initially on some of these types of failures. We're always reconditioning this and repairing it at each outage. Every time we've looked at units. so it will be a little quicker response time. Having said that. It's important to periodically exercise these things. It seems to be the world leader. these valves have an actuator. you have to open the machine up and clean it out physically. you're going to lose a day. that stuff is going to take you a day. If you don't have spare rotors. These PM procedures were generally listed either in the technical bulletins from the valve manufacturers or in the original documentation with the valve. a good way to make sure the valve works is to always do proper preventative maintenance (PM) checks on this valve. We have plugged it up where we had to take it apart several times. if you love your Cat Cracker. if you’ll just shake those weighted arms . So that might be an option for the gentleman as something different to look at. and that needs to be done at least once every three months. So you might want to take a look at piping configuration to help you prevent major damage in your blowers. And most of them have these big weighted arms on them and when you walk by those valves. And if you love your blower. 34 . Except we have radial blowers. PM is so important. and I certainly didn’t at the time. That’s generally the most significant problem we’ve seen with these types of valves.you can’t move them far. where the air line went down and then up into the Peabody heater.): Darryl Bertram. and the piping actually had a trap. DARRYL BERTRAM (BP Amoco p. retired): I can certainly testify to the problems they cause.c. UNKNOWN: Yes sir. similar to what you have underneath a sink. from what I’ve been able to see from the records. BP Australia. BAZIL BURGESS (Premcor. you’d better shake that handle every once in a while. so we haven’t wrecked a blower. FRED COLLIER (Williams Energy Services): I’d just like to reiterate the fact that when you’ve got this check valve. We’ve had all the bad experiences that the panel and other people have named. a Peabody heater was right under the regenerator. The problem we had is that we were not testing our trip mechanism and as a result. and then that was actually above the level of the catalyst in the unit. but it offers quite light pressure drops compared with the normal lever operated swing check type valve. BAZIL BURGESS (Premcor. The first unit I worked on was a direct line up and down from the blower to the regenerator. I think this question was originally mine.procedures.l. And to date have had pretty good service from that. On the unit I worked on recently. but you can move them just enough to make sure that flapper stays loose. What we’re looking for is an alternative to the flapper type check valve. you need to make sure that you’ve got a way of testing it without shutting your unit down while you’re online. they’ve never had a problem with catalyst getting back in their blowers. although it’s a 50 year old Cat Cracker. and it was a straight drop to the axial blower. retired): The first unit I worked on with the axial blower actually had a trip check valve on it. But I would like to make one other point that some people might not think of. So if you do get some kind of trip valve or trip check valve. We recently installed a Mannesman axial movement check valve on our resid unit at Kwinana. that the PM procedures were not followed. It’s a fairly expensive option compared with the traditional check valve. And in that unit. but a trip valve like on a turbine or any other non-swing type check valve. What I’m wondering is has anybody had any luck with something like a trip valve? Not a trip throttle valve. it didn’t work. because I had the opportunity to repair an axial blower that got hot catalyst in to it. the blowers were slightly farther away. when the check valve was caught un-operated. And there’s a couple of things you’ve got to look at that are pretty important. though. We have not had serious incidents in my experience. It’s going to cost you a fair amount of money to put one of these in. What factors should be considered in changing the main air blower driver 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. But we did have a number of years ago a catastrophe at one of our refineries in which we had three associated ethylene plants with nine compressors. And it only gives you a very short period of time to run down to get most of the load off the machine and then it’s going to coast. we have rundown tanks in the Cat Crackers and other units. whatever is attached to. And then another 20 or 30 feet of horizontal run from the inlet pipe if you want to have any hope of being successful. The two that didn’t had to change out the rotors and it scored them pretty badly. Some of them are just a head tank. don’t think about an expander power recovery turbine in there. you shut stuff off. How many refineries have a emergency lube oil supply tank that supplies lube oil in the case of a pump failure? DROSJACK: In a number of our refineries. there has to be room. because it’s quite likely that that power recovery train will be the limiting factor on the run length between turnarounds. because you’re not going to be very happy. is they’re only rundown tanks. And if you look at the life . The one that had the rundown tanks did not damage any of the rotors. The second one is turnaround intervals. Another part of this is what your separation system does. If you don’t have a good one. And you have to be tied into the trip so that you quit producing any head out of the blower. And part of the issue you have to look at is how long you’re planning to run this unit between turnarounds. One is your pressure ratio. And the question is whether that power recovery is really worth the cost of putting that machine in. 35 . 20. power outage. You can’t have a big enough tank to run the machine until it stops. And one of the big things is economics. How much power you can actually generate from the expander itself.there’s some discussion of that later most everybody can get two years. in our Cat Crackers. The separators are one of the big drivers in terms of how long an expander can run. So one of the things you do have to have is a fairly long open space at the end of your air blower to get this thing in. and you’re going to be somewhere in the middle. Those are some of the principle issues in terms of just deciding. Others have nitrogen pressure on top in case the lube oil pumps give out for whatever reason. You’re going to need maybe 15.Question 15. And then maybe one last factor. and see if it’s worth the cost. If you put one of these in. 30 feet of physical space to drop the machine in. The expander power recovery trains are going to be one of the shortest lived machinery components in the Cat Cracker. In a minute I will show some pictures about the ugly things that can happen if your separation system isn’t up to snuff. Question 16. One of the things to understand about these. a few people have gotten six years. what have you. So you need to make sure that you’ve got some kind of mechanism to control the speed of the unit so that you can dump the flue gas going into your expander before it gets above some kind of critical speed. and if you look closely. The unit I worked on used a steam turbine up to about 3200 RPM. 7. 2. 4. Many of the expanders will have tip cracking. To have some perspective on that. 6. 3. And then some of them will progress to have the blade tips fall off. Between the blade tips and the shroud. An awful lot is seen from the catalyst deposition. the machine may have 60 to 100 or so thousandths clearance. Normally. to slow down the overspeed so that the control systems could catch it. we were easily expecting four to five years out of it. Before we brought this down. between the blade tips and the shroud. If that fills up with catalyst and the blade tips rub. And the issue here is if you lose these pieces. Other than that. retired): A couple of other things you probably need to consider is that normally. That’s one thing you need to look at. And this is what can happen (Figure 21). and you get to the point where you simply can’t stand the vibration. And the only reason we ran to this point in time was simply to get to a particular time when we could shut this down. And that motor was an induction motor and acted as a brake also. If you look at this. And in terms of this machine. One is simply that passing too much catalyst will cause fouling. Those are the pieces that fell off during the course of about six months or a year on this particular machine. your expander will provide 100% of your power during operation or maybe some percentage lower. that accounts for about 1 or 2 mils extra vibration. with a little bit of care and thought in installing it. dictated by your vendor.000 HP motor to come up to speed. And by the time we learned how to operate it and how to maintain it. So that’s the deposition issue. the remainder of the time. depending on how you design it. if you lose or have to dump your air or something like that.I have a blade up here if anybody wants to look at it later . 36 . I don’t see any reason why you shouldn’t be able to get four to five years out of an expander. this isn’t supposed to have a piece missing. it was putting out about ten mils vibration. This thing is about as big . The crack can progress and have a piece fall out. you can see the numbers 1. you unbalance the rotor. And the other thing you need to look at is these are going to start up differently from a standard blower.BAZIL BURGESS (Premcor. you can generate thermal cracks and then you’ll cause a piece of blade to fall off. and then kicked in a 4.it’s about half as big as a half dollar. 5. But you have to have either a steam turbine and/or an electric motor to start up and get up to operating speed. This type of failure is not that unusual. you risk over-speeding the entire train. We started off not quite knowing how to operate it. This is a rotor that just came off (Figure 22). Question 17. What is the affect of the third stage separator on the power recovery turbine’s performance? DROSJACK: There are two effects of malperformance or lack of performance on a separation system. you could feel this thing moving the ground about 300 yards away from the machine. It will cause deposition of catalyst either on the blades or in the worst case. and again you get into unbalance. This has gone through the D-Gun into the waspalloy. This kind of phenomenon occurs in all expanders. And a lot of that is tied to how your separator performs. When this occurs.FIGURE 21 Next slide shows another problem that can occur (Figure 23). At the end of four years. passing too many of them. this erosion will progress to the point where pieces start to flake off the end of the blade. or somewhere between three and four years. there would have been a hole through here. This is erosion. And that’s pretty hard stuff. They’re coated with D-Gun. And these particular blades are made of waspalloy. whether indeed the erosion is sufficient to shorten your run length and whether it can run as long as you want. The other thing that can happen. they’ll blast the metal away on the machine. and you see what happens here. If the separators are not separating out the large particles. 37 . You’re going to lose horsepower. whether or not you’re going to make it. one of the things that happens is you’re going to lose performance. because you’ve screwed up the aerodynamic flowpath. The question is how much you see in yours. This is after two years of operation. We have a Shell third 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.FIGURE 22 FIGURE 23 MARLOWE: We were concerned about these issues before our spring turnaround. but as far as the ceramic sleeves that are in there and the swirl tube arrangement. we’ve never really done anything with it just inspected it. But the concern was when does it 38 . patched the ceramics a little bit with some mud and let it go. So he agreed to that. Again. we suspected a E308 filler metal issue. and some of the things that I can share with you. And it does work.become a problem? What kind of clearances do you need to look for? What kind of wear should you really see on a third stage separator? So getting involved with that investigation and finding out what to look for. looked at some of the different criterion that he gave us.1" for the fit up between the ceramic can and the stainless steel swirl tube. after another two years. we had had some wear. The ceramic liners were in relatively good shape. I can’t remember precisely how many we replaced. CARPER: Last fall. On this same unit. DROSJACK: One more comment following onto that. I did contact Jason Horwege at Shell Technology. This was after a two-year run. and he had some different scenarios for us to look at. He gave us something else to look at. When we looked at it. So we looked at our history. It was an insignificant number. but we assumed that over time. applying some of those fixes. He had one scenario if you saw some wear quite often. This would probably guarantee a safe run for another four years. the clearance had probably doubled in size over that 20 or 30 years. one of the larger separators. Over 85% of bottom tube sheet welds were also cracked. we had blades which didn’t have any erosion. There are 144 tubes in this separator. but it still was not that noticeable. Thirty-eight percent of the top outlet tubes to tubesheet welds were cracked. He said that the performance loss is proportional to Pi. we’d take out 40 in loss. 39 . So we took Jason’s numbers and figured that we would be somewhere between 30% and 50% range for a replacement of the ceramics and the stainless steel swirl tubes. And so we decided that of the 120 that we had. we had the opportunity to go inside a third-stage separator. That was our game plan for the turnaround. was really the challenge. The separator was in service since 1981 and ignored throughout the years. and had problems with your unit periodically. I just marked the ones that had the worst clearances. He related that a 5% increased opening would be like a 5% efficiency loss in your third stage separator. and when we went in there. and determined that we’d been running well for quite a long time and we really didn’t know what our clearances were. This was one of the first opportunities to take a good thorough look. as the Pi number times that clearance. One of the other things that’s done with that is you can use isokinetic testing on the stack dust samples to determine how much catalyst is coming out and what the size distribution is and use that as one of the triggers as to when to work on the separator. or another if you had a long run. So we did have a good running unit and we didn’t have a problem up to this point. He said the design clearance was originally for a thermal growth plus approximately 0. Replacing the number of ceramics and swirl tubes that we did will only help avoid a future problem and make our next run on the separator as uneventful as in the past. The cracks were in the welds. Tomorrow during the workshop session a discussion on PRTs and separators is planned. First of all. We also recommend inspecting the joints for travel from the cold to hot positions and comparing the actual travel to the design travel.III: TURNAROUND/MAINTENANCE/INSPECTION Question 18. You do not have a good method of inspecting internally unless you remove the internal shroud. make the adjustments. it’s good to inspect them before the turnaround. find out why. for those of you that haven’t been inside an expansion joint. LEWIS FREDERICKSON (Chevron Products Company): I’ve got some more specimens of my failures. Today. Sorry. 40 . and we were happy to get that all done ahead of time so we had a known indication if we had a problem within the shroud. There just really isn’t a good way to inspect an expansion joint. about what you can and can’t do. We are hearing stories of people using fiberoptics to inspect bellows. We recommend removal of the external shroud and penetrant testing the bellows including the attachment welds. If it’s traveling way beyond its limits. we recommend ensuring the packing is intact and repairing any damage due to erosion. Similarly for an outside inspection. You risk damaging the bellows. How do you inspect an expansion joint when the unit is in operation or during turnaround? CARPER: This is a question we have struggled with for many years. So I recommend that you try to get an inspection and bring in one of the expansion joint inspectors. So if you can get the shrouds off. bellows are usually packed. The items of interest are the bellows and hardware. Shroud removal is risky. MARLOWE: If you do have a problem with your expansion joints. There really isn’t a good answer. this is a sample of the braided metal hose that seals the gap between the moving parts of a packed expansion joint (PHOTO 2x). but your options are pretty much limited. please share with the audience. Internally. you can get some scaffolding up there and get a look at them. I am not aware of any of our plants attempting this and if anybody has any stories. And that’s what we did. At least you can find out if you’ve got a problem before you come down. unless you want to go to the expense of putting blinds inside the line and doing an air test on it. My recommendation when you’re buying a new expansion joint is to get the closest thing to bullet proof you can find. We inspected behind the braided hoses with a boroscope. We stuffed new sections of kaowool pillow into the void to prevent the bellows from overheating for another year of operation. it can be the forerunner of bigger problems. several manufacturers started coming out with what we called a two-ply testable bellows. We shut down one of our FCC units last summer.These braided metal hoses come in different form and with different attachment methods from the different vendors. You can just check the external refractory and the condition of the internal sleeve. We inspected a two-element cold wall expansion joint in the regenerated catalyst standpipe. about the only thing you can do is a visual test on it. you have a single ply bellows and a two-ply bellows that is either testable or has an online indicator on it. due to time and several other considerations. the two major failure mechanisms for expansion joints are corrosion because they get too cold or embrittlement because they get too hot. Our inspectors found the braided hose displaced in the upper quadrant in both elements. About ten years ago. Basically on the market now. Of course. If you’ve got a single ply bellows. If the braided hose is damaged or out of place. this meant that we had lost the insulation in this location. It looked like the kaowool had been sucked out of the wire mesh covering. We did not find the kaowool. and found the wire mesh part of this kaowool pillow. The expansion joint we looked at last summer had this kind of insulation. Many cold wall expansion joints depend on a kaowool pillow (Figure 3x) for insulation to keep the bellows elements cool. and that gap had a vacuum pulled on it to as near absolute as they can get it. PHOTO 3X BAZIL BURGESS (Premcor. If this braided metal hose is intact in your expansion joint when you’re inspecting it. As has been discussed previously. retired): How you test your expansion joint really depends on what kind you’ve got. and then the bellows is 41 . it’s very difficult to see anything that’s going on inside the expansion joint. There is normally a little wire mesh inside of the two plies. That’s usually not allowable. These kaowool pillows also come in several different forms from different vendors. Both plies on the bellows are designed for the full pressure and temperature of the system. Question 19. My recommendation is to put two-ply testables and at least one manufacturer I know of can put these bellows on your existing expansion joints for you. Some of the refineries prefer to run two to three campaigns between bellows replacement. simply because even when you’re online. and that’s the main consideration. I believe it is a significant problem. Last year we replaced three expansion (rotation) joints. Currently we are extending the run lengths on some units and are very much concerned about when to you retire the bellows. 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. 42 . At least one manufacturer has a device that will indicate whether that vacuum has been broken or not. The reason for replacement was concern for bellows age and the hinge hardware was failing. Previously we saw three to four year run lengths and now we are attempting five to six year run lengths between turnarounds. we are also working with the vendors to include a temperature monitoring system so we can tell what temperature the convolutions are actually operating at.eighteen years between bellow’s replacement. that will carry you to the next turnaround and you can either test it before the turnaround and during the turnaround. ROBERT BROYLES (Senior Flexonics Pathway): Bob Broyles. But bellows temperature measurement should definitely be part of monitoring of bellows operation online. two expansion joints. Expansion joints that we expected to be running hot are running colder than we want them to be. excuse me. Some of them. if one bellows goes. But that would be my recommendation. I just wanted to reinforce the issue regarding bellows temperature and monitoring the bellows temperature. Is that the time to retire bellows? Basically. Now when we install new expansion joints. you have to test those or put a pressure gauge on them or something of that nature. your historical data. in place. and we have found some very surprising results. because we have been following this issue of dewpoint corrosion now for several years. LEWIS FREDERICKSON (Chevron Products Company): I just want to add to my earlier comments. and that will tell you whether you need to replace it. They were initially purged joints but the purge was disconnected several years ago allowing the bellows to fill with catalyst. I do have with me a sample of bellows. that have failed due to dewpoint corrosion. There is a limited amount of data on the number of runs between replacement. I’ve worked in too many of the single plies that have cracked and had to be repaired. 625 bellows. We have actually added more external insulation. But you’re operating safely at all times. These joints were on a spent catalyst riser. for those who might be interested. monitored onstream and also vacuum tested during shutdowns to make sure you’ve got no leaks on the plies. if you want them to. Senior Flexonics Pathway. We have those on a couple of expansion joints so far. you’ve got the other bellows that is in there. is probably the best guide. side-by-side unit. I fully agree with Bazil’s recommendation for two-ply testable expansion joints. You figure 3 six year run lengths between bellows replacement .sealed before it’s welded onto the shell. These joints were in service over 25 years and had not experienced any problems with the bellows. the recommendation is replacing any single-ply you’ve got with two-ply. retire them right before they fail. This unit has a PRT also. never replaced. and then run until that indicator tells you you’ve lost one of those plies. due to the fact that if you don’t have the proper explosives. we generally see people in the industry going between 10 and 20 years for replacement of expansion joints. I found out. I think it was question number 13. are rarely used. Question 20. but they’re very hard hitting. We’ve seen a lot of the hydrodemolition come of age. and I’ve never managed to get enough courage up to extend a run on a single-ply bellows over 15 years. This is the strategy we attempt to achieve. Sometimes they’ll take a 30 cu. BAZIL BURGESS (Premcor. This is a question that we get asked quite a bit. So. The bellows metallurgy is 347 stainless steel. you’d say the criteria are pretty shaky. We do not know when we are going to replace the bellows. so there’s some less sensitive issues with the back end of the plant where they would treat the water. FARLEY: This question was covered some in the 1998 session. there’s bulging of the units that can occur. Robotics is used on a very limited basis. And from what KBR can tell. But you’ve got to find that period in time. yd. everything we’re seeing. Explosives. retired): I had a lot of trouble in the ’80s with single-ply bellows. it’s mostly chipping guns. We know we will have to face replacement one of these days! So. DEMARTINO: Let me run down what I found out in talking to some of the refineries. If you have maybe a single line where you can put a single person in it. This is based upon the inspection reports from previous turnarounds. Still. We see that driving a lot of replacements for expansion joints. I’m not saying it doesn’t work. You think you have nightmares. and then let the solid settle out and let the water come out over the top. Is there a better way to remove thick wall refractories than by chipping? Hydrodemolition? Explosive demolition? Robotics? Please describe your experience with any of these new methods. I can assure you. the smart answer is. And I believe that question talked a little bit about dual-ply bellows. and they can shear through 43 . this unit has 38 expansion joints from the top of the regenerator to the precipitator inlet. the impression I have is that it’s based more on heightened concern at each location where people have the concern about making it through the next run.We have another expansion joint at one of our refineries that was placed in service in 1956. And really. robotics may be a good method of repair or removal. you know. The problem you’re going to have there is taking care of the water. if that’s any help anywhere between 10 and 15 years on a single-ply bellows is the best I could recommend. Still in service. because there’s a tremendous amount of water that runs out the bottom of the unit. but you have to have a relatively scientific methodology to it. Really. Again. period. when the time comes we will have a nightmare due to accessibility. Earlier this year I had the opportunity to visit one of our refineries in Europe. but 10 to 20 years is what we typically see. dumpster. run the water into the dumpster. The next best answer is not to use expansion joints. And there are machines out there that are relatively slow hitting. And then you can run until the next shutdown on the one that’s remaining. We found the hangers had severe deformation. So it just gives you an idea of some of the ways that materials can be moved. the more coke that is embedded in the refractory on your risers. if you get into a similar situation that bad. in one coked up area in the refinery. And by complete replacement. Fresh refractory that even if it’s cured. During shutdown or cool down. Typically cyclone hanger systems are not designed for the excess 44 . The coke formed while the cyclone hangers were thermally expanded. When we did that. I managed to do some hydrodemolition on a riser with the same company. will be easier to take out. the harder that will be to get out. I’ve done it with chipping. We ended up breaking up the coke using blasting technology. I mean just cut the riser out and put a new riser in. we inspected the cyclone hangers and found deformation due to the excess load. We had one of our customers last year on an RCC turnaround that had never heard of them. Now after two years. The bulk of the removal was completed with chipping guns and rivet busters. That’s actually going to be the cheapest way for you to do that job and the quickest. BAZIL BURGESS (Premcor. with the same people. and we rattled them pretty badly and damaged them. There’s also a rivet buster. that’s the most widely used thing. which is mainly where the stuff is. We did do some work attempting to use explosives. but the cyclones didn’t like it too much. There were pockets of pyrophoric iron sulphide which ignited upon exposure to air. (I’ve taken it down to three inches) and then plan on doing complete replacement the next shutdown. Question 21. and they flew up to our office to witness ARC spray metalizing and the demolition with the rivet buster. The hangers were strained from the weight of the coke and the restraints imposed by the incompressibility of the coke. with the same equipment. The word of warning is.bolts. they couldn’t cut the stuff. take a look at your hangers system for distortion. How do you remove coke from cyclones and other areas in the reactor? How do you know when you are done? What safety and operational concerns 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. Anyway. two years later. they put seven shifts in for the coke removal. CARPER: We saw one unit which filled solid with coke from the top of the cyclones to the top head. A couple of points that need to be brought out. Typically. The same comment on the high pressure water. One of the issues with the coke is just the ability to get the guns access to the coke as well as the fact that you’ve got to dispose of a lot of dirty water. This was a real nightmare for removal. retired): I’ve had a lot of experience in trying to do that. They were finished in one. it got some of the coke off. but the longer that’s in your unit. the hangers thermally contracted and the coke restrained the contraction. The best recommendation I could come up with is let your refractory go as long as you possibly can. One detonation was too close to the vessel and resulted in a hole in the top head. It takes a lot of time and it’s almost not worth it. The reactor dome steam was cut off as an energy conservation measure. and they can shear through the shell. Once removed. And they even have the capabilities to remove the vibration cast lines. They were built to perform exactly the same function to get to specific places in the upper regenerator. FARLEY: Not so much related to removal of coke. in our opinion. but instead to minimize coke formation. is that the steam has to be bone dry. Question 22. This scaffolding helped shave a tremendous amount of time off our recent turnaround. very high temperatures). digital imaging. Riser operation can greatly help minimize coke formation. What innovative techniques improve turnaround effectiveness? Inspection (thermal imaging. That’s been known to cause more problems than the dome steam ring not being there. though. Important warning. So you might want to review your designs. is the most easily erected scaffolding that we have seen to date. etc. Other steps to minimize coke formation have been addressed earlier. Once you are down and obtain vessel entry. We have successfully used the Excel brand of scaffolding. You don’t want to have any liquid in that steam that goes into the top of the vessel.) • scaffolding • blinding • refractory removal • chemical cleaning COUSAR: One task that is always in the critical path of turnarounds is scaffolding. This scaffolding. scaffolding is the next step. dome steam can be very useful to minimize coke formation in the top head of the vessel. 45 . especially in units that run resid (a portion of the feed that boils at very. Two identical scaffolding jobs performed within our Regenerator are compared (Figure 24) “Regenerator Scaffolding Comparisons”).weight of coke. They are designed for the weight of the cyclone plus the weight of the catalyst. and diagonal braces are not needed with gusset designed bars. node point rings allow 360 degree placing of up to 8 bars. It was designed and erected in 12 hours by 5 men. several people have 46 . (Figure 25 “Excel Scaffolding”). This allowed our inspectors to have the best footing available when crawling up in and around the cyclones. This was a question that came up in the 1998 session here.The scaffolding’s unique design allows construction of most angles required. the issue is to minimize time until maintenance can get into the unit. personnel can climb through hatched decks. Other benefits of Excel scaffolding are that no tools are needed for assembly. Once oil is out of the unit. FARLEY: There's been a big push the last several years. Basically.000 lbs. This jig-stand that we built during our October '99 turnaround is an example of the versatility of Excel scaffolding (Figure 26 “Jig Stand”). vertical leg heights are in 11” increments up to 9’ 7”. it has built in ladder components. And a lot of people think chemical cleaning is the way to speed up that time. and therefore shorten the overall turnaround duration. It was a fully engineered structure with PE certification designed to hold 300. proprietary processes to do this and some of the ones that have been mentioned are U. Prior to startup. I had them soaked in liquid carbon dioxide. We unexpectedly shutdown a unit and needed to look inside the regenerator for the cause of a catalyst loss. These processes will actually remove benzene and all hydrocarbon (zero LEL). CARPER: One of our refineries has a standard 30" gate valve in the reactor overhead line. Last weekend we hired a contractor who used rope access technology for an inspection effort inside a regenerator. 40 lb. page 7). the refinery pulls the bonnet to remove the coke. and you’d think he would smash it with a hammer. New Jersey. During shutdown. Nothing happened. So it helped us with our planning. All it is is a very slow hitting. tapping it. So the next thing we were going to try was CO2 blasting. And as I talked about before on the regenerator wall. this procedure saves time during startup. Scaffolding was mentioned previously and I just wanted to share a recent experience. I urge people doing this for the first time to devote serious effort to working with the contractor you choose to make sure this goes smoothly. Term the experience as a limited success. we learned a lot. The valve is used only during startup. the blind is pulled and the valve closed. But based on putting it in a frozen environment. You have to look at the time savings versus the price you pay to do chemical cleaning. The issue is that these services are not free. and the teacher pulled them out. Our inspectors all had digital picture cameras. I’ve had pretty good luck with cleaning the fractionation systems and I have seen them pay for themselves. I’ve gotten a couple of samples and I had them sent up to Rutgers in Livingston. learned limitations and applications. It does not take that much of a schedule delay to give up a significant portion of your cost savings. My personal experience has been pretty good with the processes.L. so by the time the vessel is opened up. hammer that’s made to shear through vibration casting and coke. a blind is installed. It helped tremendously in getting the word across and getting the explanation as to why we need to do repairs. not a damn thing happened. that gave us an idea how many square feet we had in our major problem area. And just to touch on the coke. but it also helped us find out through thermal imaging any other spots that we would need to repair. so those are all good things to have for these outages. This technology is something you might want to consider. we used thermal imaging ahead of time to try to determine where we had problems. There is a cost that goes with these chemical cleaning methods. Zyme Flow and Phillips Lifeguard Process. and we recommend that highly. That’s 47 . hoping we could thermal cycle it back and forth to ease removal. here are the demolition hammers (see Figure 2. And also that was available for a turnaround report almost immediately after the turnaround. DEMARTINO: Oh. Let us call the experience a learning experience with limited success. The valve is opened during startup and the disk locked open with a pin. And we brought in inspectors who could help us write the reports right off the bat. Theoretically. We had six or eight of those during the outage. We could take those pictures the same day and take them to an extra work request meeting and talk to our managers about this repair. During each turnaround. generally you have pretty good working conditions for maintenance. MARLOWE: On our last turnaround. nothing we could do to stop it. And we had the same problem that he’s discussing where it would coke up during the run. to get the right sort of people involved. we had a 36" valve in the position between the regenerator reactor and the fractionator. from a safety perspective. It’s built into part of the valve mechanism. even a vibration casting. In the Lima refinery. which was right underneath the valve.): Keith Blair. BAZIL BURGESS (Premcor. we get some results. BLAIR (Valero Refining Co. there’s also the drawback of where it goes after you’ve washed it down. and we were able to document a 24-hr savings over blinding on startup and shutdown to justify the cost of the valve. you are not sure of the benefit but. 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 a major drawback to doing it in the first place? 48 . if each refiner can possibly have one person raise their hands. you’re washing down the regenerator with water. for these unplanned. one time we had to use it was right after a fire. And I would like to see if through a show of hands.): Darryl Bertram. the valve opened and closed when we needed it to. It’s not a place you want to be chipping. Our metallurgists recommend using a 2% soda ash solution for the regenerator internals. Just following on Larry’s comments about rope access. BP Australia. And in our ’94 shutdown. Paulsboro. we have made pretty extensive use of rope access techniques. I am hoping to poll the audience on the question. which has a normal block and bleed system on it. retired): I’d like to add to what Larry Carper commented on. of being able to use that valve. In fact. Like chicken soup. to make sure they’re trained. open it up and want to get as much catalyst out as possible. we replaced that valve with a through conduit valve. quite confident in the techniques. There are varying philosophies saying that the washing down is a great thing. at our Kwinana refinery. it gets rid of a lot of catalyst. CARPER: We typically wash down the regenerator in order to improve the dust situation and enhance the inspection effort. Valero. But it’s a worthwhile thing for inspecting areas where it’s unlikely you’ll find a large amount of work to do.l. though. KEITH E. Typically.c. KENNETH BLAIR (Valero Refining): I understand that. now. How many do that? Washing down a regenerator with water to remove catalyst? Four. But then. there is no harm. but you do need to have a look.our method of removal for refractory. and most importantly. unscheduled shutdowns where process engineering might just like to have a look in cyclones and what-not. to have the people who. DARRYL BERTRAM (BP Amoco p. We’ve had a running controversy among refineries as to the effectiveness and the viability of washing down a regenerator as you immediately shut down a unit. but it’s not great. And we have had several instances. It’s very important. NJ. In every instance. to see if they do wash them down? HAZLE: If I understand correctly. if you’re going to use your own people for it. The dream team is a collection of specific contractors that provide specific services (Figure 27 “Dream Team). So I’d be very careful about putting water inside regenerators. air and sulfur.). SHAW (Carmagen Engineering.): I just wanted to add or reinforce. you’ve got moisture. not treat it as a separate operation. It would be very disastrous. especially if you’ve got stainless steel inside it. So if anybody wants to know more about it. refractory lining and so on. The second strategy is the use of what we call a “SWAT Team”. The first is what we call the “dream team” approach. DONALD F. There’s a lot of ways of getting that dust down besides putting water in there. The same follows with scaffolding. We plan for and budget a select group of crackerjack boilermakers. What innovative contracting strategies reduce turnaround duration and cost and/or improve effectiveness. This approach allows for one contractor for each required discipline. we keep that contractor’s best people focused on their particular scopes of work. you get their best people. By selecting companies to provide personnel for one particular craft. I think somebody on the panel mentioned earlier to reduce downtime. you can talk to me or come over to the presentation tomorrow. Chevron tries to avoid doing that due to all of the stainless steel components. So you ought to think about that. you’ve got a very important part of that triangle. 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. We don’t think our refinery sewers can handle the amount of catalyst that we generate from washing the regenerator. etc. pipefitters. Inc. FRED COLLIER (Williams Energy Services): Washing a regenerator with water is pretty dangerous. COUSAR: We have implemented three innovative contracting strategies at Williams. LEWIS FREDERICKSON (Chevron Products Company): In response to the question about washing down the regenerator. 304 Stainless is really susceptible to polythionic acids. I think a lot of our refineries have started integrating the dryout process with a startup procedure and not where you’re drying out refractories. This method also allows the flexibility to contract with the individual contractors a variety of contracts to suit their work (i. let them weld pipe. and when you’re putting water in there. And that may be something people want to look at. lump sum..e. This tends to cause your top-notch crews to sink into mediocrity. the carbon steel portion. Question 23. When we have done it we built a dam underneath the regenerator collect the catalyst and then suck it up with a vacuum truck and haul it away. they will end up subcontracting the work.CARPER: The water is collected and properly disposed. By keeping the scope of work for each contractor down. And it’s a triangle. If you expect them to provide all crafts. insulating. If a company is very good at pipe welding. and fire/hole watch personnel on both the 49 . time and material. Most organizations will need to add a contractor to help administrate all the contracts and track the time. with both parties sharing in overruns and underruns. There's got to be a what-if scenario. This team is used to perform work at the sole discretion of the project/turnaround manager. and I had another 100 people doing other jobs across the country. and it happened to me last November. And some of the other big mergers happen. They have the biggest hammer in the country. This group of 12 to 16 people per shift makes up the “SWAT Team”. now. This contract simply allows the two parties to identify and agree upon the suppliers and contractors that will work together. and we get them involved early in the turnaround planning process. This group helps keep things 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. and they 50 . We let them know in advance what we expect as well as encourage them to help develop the turnaround plan. I was fully involved in two Cat Cracker turnarounds. and I had conversation with Exxon and Mobil about this. Whenever a problem arises or an area needs speeding up. The target price contract is similar to a lump-sum contract. We do insist on getting the contractor’s best people. We couldn't send one of our best 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. DEMARTINO: I would just have a question. simply point and shoot. you have the Exxons and Mobils of the United States. now. And we failed pretty well on one of our turnarounds. Significant changes in scopes are agreed upon and taken into account in the total target price. DEMARTINO: Okay. and if they cannot be provided to us. yet it also provides the flexibility to purchase goods and to contract services that are preferred without the dreaded “change order”.day and night shifts. It appears you're hand-picking a few guys from each company. It is all about setting a common goal with incentives that drive each party through a high degree of teamwork. This unique concept allows the comfort of lump-sum contracting. we will seek alternate contractors. The problem I see with that scenario is. The third strategy is the use of the target price contract. where you're going to put welding machines. I've seen six and eight packs stacked up on the deck where you know you're going to be doing a lot of welding. What are the driving forces for selecting catalyst blends? • selectivity/yield • hardware changes • erosion/attrition 51 . and it takes it out of your supervisor's hands. that’s not going to be fair to the other refiners. anyway. You don't have to worry about pressure drops in your piping up there to where you need the air.demand that they get the right people all the time. So that's kind of a unique way. piping and what have you as a trouble-shooting team. There's no way to nickel and dime the owner companies. And then if you need air. what I've seen done is an extra pipe run up the structure with hose stations on it so you can hook up portable machines down at the bottom to provide air all the way up the structure. much to my dislike. 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. and all you've got to do is hook a short welding lead and run it into the unit when you get it open. and there are no hidden costs for an extra 10 or 15 chipping guns per shift. and it helps speed changes through your system when they're needed. someday soon. You don't have to worry about running hoses. We demand. The other thing that I've seen done in the past is most of the time you're always wondering where you're going to get air. This can all be done prior to the shutdown. 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. include all the per diems. For a lot of the T&M (time and materials) work that we do for the refinery industry. 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. and even go so far as to include the mobilization and demobilzation fleets. BAZIL BURGESS (Premcor. my rates include all of my company’s own equipment. COUSAR: I agree. Your inspectors are always finding problems. Since we started doing that. And these people. we haven't lost a contract that we bid. it gets it right up to the managers. You don't have to worry about large hoses. on your structure in particular. So they see one set of rates. This normally saves a lot of time with the welder trying to find where his machine has to be adjusted and that type of thing. their sole purpose on the refinery during the shutdown is to come up with solutions for those problems. So you've got enough air for your jack hammers or anything else you need. And somehow. And it’s not going to happen on every job. That's all. It can’t happen on every job. IV: PROCESS/PERFORMANCE-RELATED ISSUES Question 24. So our day shift and night shift rates include all the equipment. but the primary catalyst used to drive our cat is the fresh catalyst. Because we operate a resid FCC. Changing reaction system residence times (changing volume in the riser) may necessitate a change in catalyst. more gasoline. it may be temperature. In terms of things like hardware changes that drive catalyst shifts. that’s pretty important. There are a lot of different names for these types of devices. and from our experience. You don’t see that commonly in the U. gasoline olefin content is very important in selecting catalyst.S. thermal deactivation. And you see some pretty severe catalyst changes being made to make these specifications. So there’s been a catalyst change associated with that. there’s really not that many. but basically they all fall under the category of something that reduces residence time in the reactor vessel. You want to do something to recover that octane. these guys are pretty valuable in giving you direction as to where you want to shift operation. would be feed nozzles. 52 . we utilize both fresh catalyst and equilibrium catalysts to provide our conversion as well as bottoms upgrading. That may not be catalyst. We rely on the fresh catalyst to provide the foundation of our catalytic conversion and selectivity. But catalyst is one option for that. Other revamps that may have. Generally. I think people need to start looking at something like an olefin barrel value.S. it’s pretty interesting where you have a lot of product specifications that are very important today that weren’t important. The purchased equilibrium catalyst (Ecat) provides an economic alternative to fresh catalyst that allows us to maintain unit activity by controlling metals levels and at times has supplemented for catalyst losses. You look at units in Japan and places in the U. Octane barrels may have very high value. is octane important? It’s really important for the process people in the operation to have an understanding of this. in select cases. a catalyst change. you can lose a little bit of octane with a feed nozzle revamp. There have been some cases where it’s just not possible to get the activity on existing catalyst that refiners want. the number one thing we see that shifts a catalyst blend would be something like a riser termination device. This approach has become a necessity in order to achieve our selected yields as our cat feed has continuously gotten heavier and the metals and con carbon levels have increased. It is formulated to achieve a desired yield pattern as well as be resistant to attrition. today. We also add various catalyst additives to make more subtle changes in the yield structure. people start looking at a lot higher activity catalyst in the FCC after this type of revamp to recover some conversion. Generally. and metals deactivation. And in some locations. And you get that understanding by working with the economic group. FARLEY: I stress working with your refinery economic planning group when you look at catalyst formulations. but it’s a real problem.COUSAR: Refineries select from a variety of catalysts to meet specific yield slates based on economic factors. These types of additives are used as an adjustment knob to tweak a yield pattern to achieve a certain yield structure.. We have evolved over the last several years from using primarily Ecat and supplementing with fresh catalyst to using primarily fresh catalyst and supplementing with Ecat. or not as important ten years ago. I’d also stress that in today’s environment. You look at recent revamps and consider the recent technology pieces that are used. Things like gasoline olefin content. Additives such as ZSM-5 influence the yield of LPG olefins. Do you need more LPG. if you have an increase to a catalyst with a higher particle density. Inc. In some cases. JOSEPH W. So that is something that you can work out. J. we found we opened up the portfolio more. in the area of hardware changes.MARLOWE: We have high velocities in our system at Toledo. we went to an activity change. but some reactive properties you can change to deal with other problems in the unit. one of them being catalyst. The activity change that C. you might want to look at changing catalyst if you can’t solve the problem any other way. but it actually has done us some harm in ash increase in our slurries. Harder does not necessarily mean good things. we made several changes. And all of a sudden. retired): For those of you who have hot gas expanders that have had a problem with buildup of catalyst on the shroud. ROBERT A. Inc. but that’s something you might look at. we started having that problem. I’ll also add to that fluidization. mostly physical properties. When we put in those technologies. meant that there was a major change in the catalyst formulations that we used in the unit. There are catalyst properties. BAZIL BURGESS (Premcor. but you do have to do that in your own location with the requirements that you have there. WILSON (Barnes and Click. We’ve found in some of our units that fluidization is more of a concern than erosion or attrition resistance.): Just to add to some of the comments that Jim made. So we had not gotten around to identifying that particularly. When it comes to erosion and attrition. So I’d be careful with getting something that’s harder than you’re more accustomed to running. where we did not have it before. and use that with the information that the supplier has in their portfolio to specify a proper product for you.): Just a couple of other things you might look at when you start thinking about catalyst. but we found pretty quickly that we needed a selectivity change along with it. Back in the late ’80s. probably. this can also be used on units that are pushing their catalyst circulation limits in the slide 53 . we couldn’t employ. In almost every location that we made hardware changes. Use your unit to tell you what’s a good operating area based on your expander vibrations that may result or your slurry ashes that may result. than we need. and in a couple of cases where we changed the riser residence time. in hydrogen on coke. especially when we upgraded our feed nozzles. and we had more options. But you can select catalyst blends with hardness considerations. it can sometimes help overcome problems with an overloaded or an inefficient stripper. It’s been pretty good when it comes to regenerator losses. It’s not a selection criteria at our location. If you change to a catalyst with a lower total void fraction at minimum fluidization conditions. There are differences in what we have seen with different suppliers’ products. LUDOLPH (Sunoco. For example. And in particular. mentioned in response to an improved riser termination device. and that’s related to the cyclones so we do have a higher attrition. And with less ability to break down or attrite and create much finer particles than you want. and reduce your regenerator temperatures and product loss that way. And it’s really not a selection criteria anywhere in our refineries in the Sun system. especially seasonally. And work with that as your baseline. we found that there were some technologies that some of the suppliers offered that we couldn’t take advantage of because they offered active ingredients that for whatever reason. it can have an affect on the amount of losses from your regenerator in your opacity. and zinc. but it’s bad. potassium. Question 25. I think everybody pretty well knows sodium is a bad actor as far as it actually physically destroys portions of the catalyst by attacking the acid sites. Calcium acts in a similar fashion. Severe pH changes inside the desalters can cause the calcium and iron to be discharged back into the crude while the sodium is picked up again. It’s not as severe as sodium. If you start to see metal spikes on your E-cat analysis. We've seen a lot of papers about the effects of iron contamination. You can't just assume that it's coming from the feedstock. people only make changes upon seeing moves in the FCC equilibrium catalyst properties. Generally. sources can vary. then zinc and iron is sort of the order of severity of these contaminants. you start seeing high sodium or. One theory about calcium and iron contamination is the use of the chelant Na4EDTA in the acid stimulation of oil well production. which got in the FCC through the air system. sodium. So the issue is how do you look at the FCC feed to make sure you don't get the contaminants in the unit to begin with. Does anyone in the audience have any experience with FCC feed desalters as a means of metals removal from cat feed? 54 . The main problem is that it is hard to account for variations in feed contaminant loadings on a day to day basis. I know of one case in particular where caustic was being unloaded with air pressure. you owe it to yourself to look at more than just the feed. What are the sources of FCC catalyst metal contaminants such as potassium. This introduces a lot of lag time in the control of the unit. calcium. 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. calcium. several locations are running used motor oil through their process units. For example. The industry has done a lot of work in the last few years about iron. sodium. My personal experience has been that the bad problems I've had are related to specific sources of feed. In terms of rank order. iron. Having said that FCC feed is the usual source of metals. and that's a horrible. it may not be the problem in every instance. Zinc also has a similar type of attack. it’s feed related. calcium. and zinc? What are the remedies for metal contamination? Are FCC feed desalters the answer? FARLEY: These are not necessarily your typical contaminants. EDTA has a tendency to pick up iron and calcium while releasing sodium. For contaminants like potassium.valves and the stand pipes to get away from those limits by reducing the cat/oil ratio required to get the desired conversion that you need. it’s been in your unit for quite a while. horrible thing to happen. one crude well is undergoing some sort of cleaning operation and suddenly you have 20 ppm iron in your FCC feed sample. And literally. Most of the time. and you're never going to find that in the feedstock. Potassium is very similar. high iron. we would think sodium. In our experience we’ve seen zinc associated mainly with lube oil or motor oil. caustic got in the air system. There have been cases where sodium has come from the air system. iron. But it happens. By the time you get the sample results. This is where you want to try to maintain your 85 feet per second. I don’t think that anybody really designs to run higher velocities. we talked about the high velocities before. increasing cyclone inlet velocity also increases the pressure drop across the cyclone. and usually you add sodium for pH control.): If you’re going to run resids. we don’t plan on this. But in operation. In terms of catalyst carryover. and you can also use Coastal’s ACT process. but these are not common cases. FRANK ELVIN (Coastal Catalyst Technology. The other things you can do to handle these metals and the main problem with metals is the nickel and vanadium. there’s some marginal improvement in cyclone efficiency. But the problem is. and you choose to do that until your next turnaround. PECCATIELLO (Chevron Products Company): In addition to potassium from feedstocks. The Toledo Refinery does run 83 to 85 feet per second. it’s a failure that takes place between turnarounds. Normally. There have been cases where people choose to accept higher velocities due to space limitations. Inc. In terms of advantages of higher velocities. Question 26. You’re going to have some sort of failure faster operating with higher velocities than you do running lower velocities. And. We do have problems with higher velocities at our location. you can run out of dipleg. it does. you come up with some new online optimization routine. you can purchase good equilibrium catalyst to flush out the metals. and this is in the inlet to the second stage. You’ve got your unit. just as a matter of course. The second you’re out of dipleg. and you can push more capacity to the unit with the same cyclones you have. you can purchase flash catalyst. which actually demetalizes the catalyst so that less fresh catalyst is required. you can use the Kellogg magnetic separator to minimize the amount of fresh catalyst you need. your cyclone loading goes up so quickly that you never really see that. The real advantage of higher velocities is you can do it on line. At some point in time with continued increases in velocities. directionally. from a design standpoint. and you have carryover due to dipleg backup. Our opinion is that it shortens cyclone life and if it shortens cyclone life. You can add extra fresh catalyst. it’s been running two years. but all these other metals also are bad for the FCC yields. does it correlate with cyclone life? Yes. the catalyst that’s in the cyclone goes out the top. you should have a double desalter ahead of your resid to take out any sodium that may be coming in with the resid. That’s the real advantage of higher velocities. 55 . And double desalting is very effective at improving the FCC performance. There’s usually a lot of sodium in the resid coming from your crude unit where you have a desalter. MARLOWE: Just to add to that. which means dipleg backup increases. What is the panel’s experience with cyclone velocities greater than 75ft/sec? Does it correlate with cyclone life? What about catalyst carryover? What are the advantages of higher velocities? FARLEY: We see a very large number of units actually operating above 75 fps velocity. 30% to 50% of the units that I know of are routinely doing this. refiners that are using potassium hydroxide for HF alkylation neutralization and are feeding the acid soluble oil (ASO) back to the FCC unit can introduce additional potassium on the catalyst.KENNETH A. the 75 feet per second is really a design point that the manufacturers try to maintain so that you can have a normal life of your cyclone. your increase in flow will increase inlet and outlet velocities. because you can’t get the cyclones in. there’s just not enough physical space in the top head of that vessel. you know. Then we developed a strategy for operating based on velocities. and you don’t have enough diameter for the cyclone layout you need. And so we fixed it up pretty quickly. with bigger equipment at higher inlet velocities. but the velocities are a factor of 3 or a factor of 4 related to erosion. there is a cost disadvantage in the initial capital equipment. to the velocity range you would like. and you’ll find out how many days you actually knock off of your life. and we used erosion as proportional to 56 . so you really want to monitor your velocity. A lot of it is mirroring what the panel said. WILLIAM D. Of course. So if you have a 13% increase in your velocity. So you would wear out much. you’ve got two real times you’re considering whether you’re going in as an increasing flow to an existing unit that’s just sitting there and it’s a throughput issue. In this case. much. What we were worried about was we were not monitoring it. if you’re comparing a system that is 75 feet per second inlet velocity and another one at 65 feet per second inlet velocities. The next cyclone size is not available for you. to life. So if you have pressure drop. So 15% increase in inlet velocity might get you about 50% increase in erosion rate or a 33% decrease in equipment life. And the inlet velocity there was about 85 feet per second. It doesn’t sound like a lot.Now. We ran 86.when you’ve got existing cyclones. 87. yet. when you’re making your capital costs comparisons and you’re looking at a new system. outlet velocity is less detrimental. 88. but you have to be very careful. If you’re planning on replacing the cyclone or repairing it. We find that a increased inlet velocity kind of correlates about to the cube of the increase in velocity. so it was moving along pretty good.): We’ve had one Cat Cracker where after about a year of operation. the head would have to come off. So. but the two are not necessarily coupled when you’re working with a new design and the effects on erosion and decreased equipment life are a lot more clearly linked to inlet velocity. The other is for a rebuild or repurchase or refitting a vessel with cyclones. a major cause of erosion is your velocity. We’ve seen something similar to that where one advantage of higher cyclone velocities was basically eliminating the need for vessel replacement. then you probably have close to a 45% increase in your erosion. we wore down the refractory on the back end of the primary cyclone. much. in our experience. The other thing . and the operations capacities were pushing it to well above 85 feet per second. So. HENNING (Conoco Inc. And one major advantage that at least everybody needs to understand that drives part of the selection is higher inlet velocity ends up with cheaper cyclones. FARLEY: That’s a good comment from the floor. So you can almost take that calculation factor of 3 and you can kind of take the days or whatever from an initial design of 15 or 20 years. yes you could take advantage of some higher velocities. So what you end up looking at is vessel shell replacement and I have not seen too many people get excited about that. but you don’t want to be using inlet velocity. BILL HEUMANN (Fisher-Klosterman): We’ve done a lot of work with velocities and cyclones. faster. 89 feet per second. You eventually reach some sort of ultimate capacity where you’ve got high superficial velocity. There are reports in industry of people going higher than that. the bed temperature can increase by about 3o to 5o F. Overall. To our knowledge. the safety interlock system is absolutely critical. Individual plant economics drive this decision. O2 enrichment offers one way to combust incremental coke when you’re out of air blower. One of our refineries uses a dedicated crew to handle the equipment and connections. do not hot tap into an oxygen line. As a general rule of thumb for predicting the temperature rise. and also it seemed to work pretty well until we got to the next turnaround and we could actually replace the cyclones. it’s very site specific. you have a lot of FCCs out there that are out of air blower capacity. So. The refinery’s source of information for handling and addressing safety issues was from the Compressed Gas Association and Linde. you can decrease your superficial velocity if you run into cyclone loading challenges. we see about 24%. so there may be a loss in cat to oil. And there’s still a lot of incremental margin to burn more coke. The keys are quite simple: keep it clean. I’ve heard numbers at 40%. and of course. I wanted to mention that oxygen enrichment will slightly increase the regenerator bed temperature. on average. there’s usually some sort of decline in the overall yield structure of the unit. if the regenerator temperature goes up. You have to buy the oxygen to combust the coke. the FCC oxygen enrichment has been safely practiced by our customers for well over two decades. And as mentioned. Question 27. ROBERT BEST (Air Products and Chemicals. and hurdle pricing is set where the feed margin has to be over a certain value before you make the decision to use O2 enrichment. These numbers go all over the map. it’s not free. Lastly one major key our refinery wanted to share: by all means. We believe that around 57 . CARPER: There’s another reason for using oxygen enrichment. this is due to the loss of some of the nitrogen as heat sinks. and keep it oil free. I’ve heard numbers at 10%. They are specifically trained and dedicated to the tasks. what this gets down to is usually. My direct experience is that most people limit O2 to about 25 mol % being charged to the regenerator. there’s a pretty robust economic evaluation. it’s pretty important to have a very robust safety interlock system in place and it is very important to control the percentage of oxygen that’s actually entering the regenerator. Some brief comments related to safety. And I would agree that on an average basis. depending on what the unit configuration is. In addition to that. keep it dry. What are the consequences of using oxygen enrichment? additional maintenance expenses? safety considerations? FARLEY: The background of O2 enrichment is that. given no other changes in process variables. The issue is. Once you make the decision to use O2 enrichment. Inc. is that you consider that for each 1% of oxygen enrichment. and that seemed to fit some previous data in the unit. Most people report some sort of incremental catalyst deactivation. There is usually an economic debit where the regenerator temperature ends up going up some. oxygen enrichment levels in our experience have ranged from 21% to 28%.velocity to the 5th power. so.): In addition to the comments from the podium. FCC O2 enrichment is used in between 40 to 50 FCC units. on the O2 flow skid and controls. we run 25% to 27%.above 28%. high calculated O2 enrichment levels.): I’ve got a question this time. Each of our applications.1 guidelines for O2 material selection. to name most of the common interlocks. To add on to Jason’s remarks.0 and 4. 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. Now. we had to re-route the 58 . of course. Inc. I’d just like to mention for more detailed information on FCC O2 enrichment safety and other FCC topics. DAVID PAY (Lyondell-Citgo Refining): David Pay. low air flow. The address is www. We. high measured O2 enrichment. J. we started with a vaporizing system where the oxygen was brought in as a liquid. that’s a little side benefit you can get. but when we installed some new equipment back in 1992. ROBERT BEST (Air Products and Chemicals. you try to treat the line as if it’s going to have to carry pure oxygen. And just briefly. we’ve been doing oxygen enrichment since 1983. high temperature conditions in the air main downstream of the O2 injection. regenerator temperature.the answer to the question about what level of enrichment? We see about 24% as a rough average. keeping in mind placing it at least ten pipe diameters from any impingement point. Inc. mainly for safety purposes. this should include several key safety interlocks such as high oxygen flow. The original system we had stainless steel piping throughout. I would recommend an interesting and new website put out by Refinery Process Services.the world. JOSEPH W.): I just want to mention that on average. T. observing O2 material construction compatibility issues in piping guidelines. Just out of curiosity. about . pipeline construction. and a general catch-all master FCC interlock. JASON PAGEL (Lyondell-Citgo Refining): Our typical O2 level is around 24. Lyondell-Citgo Refining. we have a pipeline connection and so it comes in as a vapor. And in closing. I’m curious as to what levels of oxygen enrichment people are actually running on a regular basis. and in part sponsored by Air Products. and therefore needs the required cleanliness to do so. Self-imposed guidelines dictated by CGA and other companies. So. and then fed into the unit. UNKNOWN: At the one refinery where we use oxygen enrichment. closely follow CGA pamphlet 4. And initially. And a brief listing of safety considerations would include a properly designed O2 diffuser. if anybody’s willing to name numbers. as a company. the range being from very little to probably a maximum of 28%.thefccnetwork. you have . and cleaning practices. high oxygen pressure. proper placement of that diffuser. would follow a formal haz-op review prior to commissioning. the catalyst additives for SOx control are generally much more efficient when used in a regenerator using oxygen enrichment.com.5%. WILSON (Barnes and Click. We went through the process of evaluating both the Pall and the Mott filtration systems. first installed 1990. Gulftronics directionally has the highest backwash rate. valves.1 million. Question 28. The savings were in the form of a reduction in the frequency of cleaning the slurry tanks. so we went with carbon steel lines for the additional piping that we had to put in. And the Dorr-Oliver hydrocyclone. Basically. while Pall tends to name slurry as their first choice. first installed 1979. the second column is the Mott cartridge filter system.9 million in savings was just for a year or considered overall? COUSAR: That was our annualized savings. we were losing quite a bit of catalyst from our reactor. 1960 for first installation. we reduced our catalyst losses to the point to where the filter project was economically infeasible. the third column is the Pall cartridge filter. That was $900. currently has 9 installations.9 million of savings. The Mott and Pall systems are fairly similar in terms of backwash rates. first installation was 1989. It is important to look at things like plot space and operating costs when making your decision as far as which type of system to invest in.000 bpd of slurry was about $1. generally more like 300 ppm solids in the final slurry product. around 50 of those. MONIQUE STREFF (Fisher Rosemount Systems): I'm just wondering if that $. We did go through a very elaborate cleaning of the system before we commissioned it. with Mott also generally listing HCO first.line. The decision was made to revamp our FCC reactor and in doing so. The filter systems have a wider operating temperature range than the Gulftronics. etc. just a quick survey of what's out there in industry. with 50 ppm on the high side. and the last column is the hydrocyclone. a reduction in the disposal costs of the catalyst sludge in the tanks. piping. has a lot of installations. filter elements.) that was sized for approximately 3. Gulftronics. The first column is Gulftronics. more than 50. What kinds of filters or separators have satisfactorily removed catalyst from slurry? FARLEY: The table (Figure 28 – see next page) compares some slurry filters or separators that have satisfactorily removed catalyst from slurry. 16 of those installations now. The final decision should be based more on life cycle cost analysis as opposed to investment cost only. The three systems do call out that any of the streams below can be satisfactory. from what I can see. 59 . There can be some pretty surprising differences in plot space. The Gulftronics preferred backwash material is HCO. and the elimination of the slurry settling aid. COUSAR: Prior to our '99 FCC turnaround .2 million. The Mott system.000 per year. The cost estimate for the filtration skid (including the filtration vessels. pumps. The total installed cost was estimated to be $2. Estimated slurry solid concentration is around 50 ppm. and generally estimated to be around 20 ppm slurry solids. generally estimated to have anywhere from 20 to 50 ppm solids in the slurry product to storage. Basically. We were justifying this expenditure based on approximately $0. Pall cartridge systems. [applause]. Slurry 401 . Device First Installation Number of Installations Estimated Slurry Effluent Solids Concentration. LCO. HCO. 550° F maximum design temperature NA 482 . LCO.2 %. LCO.670° F Figure 28 60 . HCO. Slurry 302 -392° F (356° F normal) FCC Feed. HCO.600° F (480° F normal) Up to 2 % 0 FCC Feed. Let’s say thank you to our panelists. Slurry 480° F normal operation. up to 2 % FCC Feed. ppm Percent of slurry feed that is recycled to riser from separator Backwash requirement as a percent of separator feedrate Choices for backwash fluid Operating temperature range (°F) Gulftronics Separator 1979 >50 50 Mott Cartridge Filter System 1990 9 <20 Pall Cartridge Filter System 1989 16 <50 Dorr-Oliver Hydrocyclone 1960 >50 ~ 300 0 0 0 ~9 20 As low as 0.HAZLE: Any other questions or comments? I’ve held you long enough. I appreciate you staying for the end of the session. cooling water. Gallagher ABB Fan Group engineers and manufactures FD and ID fans for fired heaters. TX 77061 713-640-1111 x4203 Mr. hexmetal. 1135 S. s-anchors and punchtabs. Inc. AL 35125 205-814-1722 Mr. Darrell McAnelly Causeway manufactures refractory anchoring. Jeff McWhirter Compressor Controls Corp. Houston. Bob James World Wide provider of specialty utility services.. Des Moines. Tampa. 1 vessels trayed towers. Baton Rouge. Services include temporary electricity. AltairStrickland. TX 77536 281-478-6200 Mr. CCR blowers. Glenn Poche Rotating machinery protection and management hardware/software and engineering services providing full solutions. highpressure fans for fluidization and sulfur recovery. flexmetal. 5110 Railroad Avenue Deer Park. Leo Poirier Plant inspection services API 510. Field Erected Vessels. 6923 Mayfair Houston. Nashville. OK 73108 405-634-5434 x222 Mr. Roger Grommet FCCU Components. Wes Horton TURNKEY scaffolding contractor featuring Excel Modulor System. Houston. TX 77029 713-673-2385 Mr. Boardman. TN 37203 615-851-5727 Mr. Causeway also offers complete hexmetal and flexmetal. Engineeral Scaffold. McKinley Oklahoma City. 61 . hexcels. oil-free air. retrofits and turn-arounds. Custom engineered for your specific project with explosion proof. Causeway Steel Products. All Tech Inspection 9009 North Loop East #155 Houston. Bruce J. Bently Nevada Corporation 7651 Airport Blvd. Backed by a professional support team and engineering staff. Regional offices: Baltimore. Aggreko Inc. Mobile. Suite 300 Houston. FCC "JIG Stands" reduces costs. Suite 126 . Sherwood McDonald FCCU T/A Specialist. TX 77034 713-852-4500 Mr. 12000 Aerospace Ave. 653. TX 77061 713-640-8500 Lee Brantley American manufacturer of rack-and-pinion elevator systems specifically engineered for the petrochemical and refinery environments. the "no tools -positive locking" system. 570. process cooling and more.2000 EXHIBITORS ABB Fan Group North America 19065 Highway 174 Pell City. Inc. Tower & Tray Work. and will engineer upgrades for allexisting fans. fabrication with insulation drawings. Champion Elevators. Temporary and permanent elevators available for new construction. ASME Section VIII Div. TX 77078 713-649-6923 Mr. which will greatly reduce your insulation time. corrosion resistant and variable frequency drives available. Atlantic Scaffolding Company 2817 West End Avenue. Field Piping. New Orleans. 8400 Villa Drive Houston. including cat cracker air blowers and Power Recovery Trains.Box 169 Nashville. Compressor Controls Corporation 11359 Aurora Ave. IA 50322 281-583-7799 Mr. Inc. Inc. (CCC) is the world leader in design and manufacture of electronic control systems for all turbomachinery applications. Components are produced in eight processes. Louis. Diverter Valves. erosion. Inc. CA 92071 619-562-6083 Ms. Crewe Cheshire. Corhart Refractories 1600 West Lee Street Louisville. Elaine Foster Deloro Stellite is a provider of solutions for wear. Overhead Transfer Lines. NJ 07080 908-769-0700 Mr. Fluegas. INC. Deloro manufactures cobalt and nickel based alloys. and critical flow nozzles. transfer lines. 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MO 63110 314-781-6300 Mr. Vogler All FCCU Components including Reactor and Regenerator Heads. plant commissioning and start-up. Suite 400 Mississauga. CN1 6UA England 011441270501000 Mr. Risers/Standpipes. Vibration Casting. Air Distributors. maintenance management technology/CASP (Computer Assisted Scheduling & Planning System). Risers. ON Canada 613-968-3481 x245 Ms. Internals. Dry abrasive media or slurries. construction and construction management. Air Grids. Everlasting Valve Company 108 Somogyi Court South Plainfield. Overhead Lines. corrosive and heat resistant problems. Regenerator Standpipe Joints. Wyes. 10035 Prospect Ave. impact. Project Management and Corporate Alliances. Dynamic-Ceramic Limited Crewe Hall. Charles W. Continental Fabricators. Injection Nozzles. ON Canada 403-258-6700 Mr. 5601 West Park Avenue St. EJMA Member. ENPRO SYSTEMS. L5N 1P7. turnarounds & shutdowns management and execution. Suite 202 Santee. Inc. OK 74128 918-437-4400 Mr. and corrossion resistance. 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NJ 08086 856-853-5700 Mr. manufacturers a complete line of high quality refractories for the refining industry. Houston. vessel and exchanger specialist.p. John Norder Ribbon Technology manufactures stainless steel for castable refractory reinforcement. Mark Schnake Manufacturer of refractory products previously produced by N.P. Pittsburgh. Tower. 705 Sarah Ann Nacogdoches. media build-up. William W. Green Refractory companies.A. piping and specialty welding. Raymond J. TX 77027 713-355-4900 Mr. MO 63104 800-325-7369 x565 Mr. PA 15219 573-473-3517 Mr. 14330 E. IN 46319 219-923-0425 Terry Swanson FCCU Turnaround Services. Stress Engineering Services Inc. Butterfly. TX 78130 830-629-8080 Mr. Mike Prevost Project management. design and manufacture of high-quality metal and fabric expansion joints. Nooter Construction Company 1400 South Third Street St. TX 77039 281-449-0291 Ms. mechanical and chemical disciplines. Offices in 5 US cities with expertise in fitness for service. Frank DeMartino Refractory Installer. Dave McGrath Senior Flexonics Pathway is recognized as the industry leader in the innovation. catalyst handling. Montrey FCCU T/A Maintenance and Repair. 825 Taylor Station Road Gahanna. Louis. John J Saphier Engineered coatings for steam turbines and axial flow compressors. Inc. 17 South Briar Hollow. remaining life and high temperature applications. TX 77087 713-495-3521 Mr. TX 77041 281-955-2900 Mr. TX 75961 936-560-3335 Mr. Diverter Valves. Robert M. Inc. New Braunfels.Mogas Industries. Harbison-Walker. Ribbon Technology Corp. Inc. refractory. Lori Evans Since 1973. TX 77478 713-948-1534 Mr. Resco Products. American. and A. vessel. Inc. TX 77041 713-466-0300 Mr. maintenance. plus thermowell and sparger installations (1300° F). TX 77029 713-675-4167 Mr. TX 77488 713-466-7200 x4 Ms. Vesuvius offers a full line of monolithics. Double Disc. Many of our valves have been in service over 10 years without repairs. bolting and catalyst services. Butterfly. McAfee Team provides high temperature. Diverter Valves and FCC Equipment. Vesuvius Premier 9135 Wallisville Road. planning and safety. Houston Ave. high pressure leak repairs and hot tap services on cat cracker walls and flue gas ducts (1350° F). We can provide customer contacts who will testify to our longevity in this and other service FCCU applications. brick and ceramic fiber. Suite A Houston. Rich Milland Industrial turnaround. Team Industrial Services. including project management. heater repairs. TX 77338 281-446-8000 Mr. Inc. 200 Hermann Drive Alvin. Humble. 65 . VALVTRON 6830 N. CA 94590-6968 707-642-2222 x239 Mr. Zimmermann & Jansen. Steve Kirklin Vesuvius offers a full like of refractory products and services for the construction and maintenance of hydrocarbon processing facilities. Gate. TX 77511 281-388-5545 Mr. Wedge-within-wedge Valves. W. 620 N. Ronda Kalinec-Espinoza VALVTRON’S metal seated ball valves are a proven solution for tough FCCU applications such as slurry pump isolation. Butterfly Valves. welding. repair and modification services. Eldridge #502 Houston. exchanger. Mark S.TAPCO International 5915 Brittmoore Houston. R. The TIMEC Group of Companies 155 Corporate Place Vallejo. Subsidiaries specialize in tower. Bredo Christensen Manufacturer of High Temperature Slide. electrical/instrumentation. Taylor FCC Slide Valves. 1 .