Question 70: How frequently do you have fires on reformer reactor flanges? What bolting techniques and gasket types do you use to prevent leaks? What other fixes, such as flange resurfacing, have you employed? Do you use steam ri
GRUBB (Chevron USA, Inc.) Chevron has had some experience with flange fires in the past, so I’ve consulted with Dave Reeves, our corporate expert and also our Best Practice that we’ve developed for this. I know that I said temporary fixes up on the slide, but it’s not really a temporary fix. It’s more like you discover you have a leak and decide to temporarily put this on. It’s more like temporary while you’re figuring out the solution for the right gaskets to use. So we’ve employed some steam rings around some of these that were prone to leaks. Some of the leaks, since they’re hydrogen fires, are not visible during the day, so we’ve employed wrapping chicken wire around some of the rings to show the burn when it happens. The Best Practice that we developed and came up with was Kamm profile gaskets for anything over 24 inches. Some of the details are that the flange surface should be finished to 125 rms to 250 rms; you should use a high quality graphite material for the gasket covering; and, the stud loads should be set to between 20,000 psi and 25,000 psi gasket stress. We use a modified star pattern for bolting where we do the first four nuts in the star pattern, and then we go clockwise around twice, torquing to 100%. One keynote where we may have had problems since we’ve come up with these, our gasket selection has been fairly successful. Where we’ve had problems in the past is where we discovered a flange was accidentally insulated over, and then the bolt stud doesn’t hold under higher temperatures. We now try to go make sure that our flanges are not insulated after we’ve done maintenance.
NEWTON (Roddey Engineering Services, Inc.) Most of the refineries we work at use a two-step torquing procedure. They either get a hydraulic torque wrench or, as our Mechanical Engineer says, they take the end of the bolt and stretch it to 65% to 70% of yield strength and then hand-tighten the nuts. Then, you start heating up. After you reach a specified temperature, just go ahead and tighten it up all the way. One issue that he discussed with me about when we do the hydraulic torquing is to make sure that the service area is clean. You don’t want to have anything that would give you false readings. Most of the places we’ve worked in have had outside contractors come in and do this and that could be recommended.
Another solution we’ve seen is to use the Bellville type washers. I did not get permission from them to use any kind of diagram, but you can go to their website and see what they look like. But basically, it’s a spring-type washer to help the metal contacts or expands. It adjusts for that. Every client we’ve had use that has had great success with these washers.
HAZLE (NPRA) Relative to the two-step bolting procedure, Shell Deer Park recently had a flange fire on one of their reformers. They have a two-step procedure like that. They missed one of the flanges when they were going around and re-torquing and had a small fire, which then interrupted their startup. So to me, that’s an endorsement of that particular feature.
BRIAN HARRIS (Holly Refining & Marketing Company - Woods Cross) I am wondering if most people find that we have more failures. And if you cycle more, do you have to go back and retorque? Let’s say, you had a crash-down or a shutdown and you cooled off, do you go back and retorque at that point or are you good once you hot-torque the first time?
GRUBB (Chevron USA, Inc.) I don’t believe you go back and retorque.
NEWTON (Roddey Engineering Services, Inc.) We don’t retorque either.
MIKE FACKER (Western Refining Company) I just want to mention that as far as finding the leaks, we use a clear camera where you can see a lot of your vapors. It looks like a steam leak coming out of there, and that’s been handy detecting some of the leaks when you’re starting out.
Question 71 Is your company planning to install modified HF acid capability (usage of the volatility suppressing additive)? What are the incentives for doing this? What alternatives have you considered?
METKA (Sunoco, Inc.) In March 2006, in our continuing effort to support safe, reliable, and environmentally sound operation, we announced our plans to apply for a permit to independently initiate an alkylation process improvement project in our Philadelphia HF alkylation unit. The unit employs ConocoPhillips, now UOP, Split Olefin Feed Technology (SOFTTM), and the project includes voluntary incorporation of a modified acid capability. ConocoPhillips ReVAP® technology was selected for the project. As most of you are probably aware, this technology was later acquired by UOP. We had been evaluating the incorporation of modified acid technology for several years in order to determine if the technology could be applied without contributing to reliability or other operational concerns. Other options were considered and ReVAP® was selected based on demonstrated commercial application. The additive used in the modified acid technology reduces acid volatility, which provides several benefits. It provides a passive mitigation system that further enhances existing safety measures. Transportation risks are also reduced since the additive can be blended prior to shipment. Modified acid technology is one ingredient of an extensive safety program and it compliments other acid management systems, which include extensive inspection, maintenance, and equipment monitoring programs, existing active mitigation systems, feed quality control through selective hydrogenation, an online HF analyzer for continuous acid monitoring and control, and a rapid acid de-inventory system. The technology also compliments the planned implementation of compartment technology, which is another passive system, including a baffle in the settler that reduces the amount of material available in the unlikely event of a release. Other potential benefits include decreased acid usage and also slightly higher alkylate octane.
QUINTANA (Valero Energy Corporation) This response focuses more on the latter part of the question related to alternatives, which John has already touched on with a good start. We see vapor suppression additives as only one option of several available for consideration as part of a comprehensive Process Safety Management (PSM) program. The industry recommendations to consider are summarized in API Recommended Practice 751 for Safe Operation of HF Acid Alkylation Units. We believe an effective program will comprise of recommendations emphasizing leak prevention and monitoring, as well as the mitigation systems to be used in case of a leak event.
There are various elements recommended under RP 751 that are included in The Answer Book and the next three slides, so I will not go over them in detail here. The key elements include procedural aspects such as HAZOP assessments, MOC (Management of Change) programs, emergency response and control plans, and regular unit audits.
API RP 751 Elements:
•HAZOP assessment of existing unit equipment & controls
–per API RP 750 - Management of Process Hazards
•Management of Change program to address controls, instrumentation, metallurgy, procedures, relief system
•Thorough emergency response and control plan
Regular and thorough unit audits to address:
- Unit specific & industry incidents and risk exposure in the unit
- Inspection, maintenance & training records
- Mechanical & procedural changes since previous audit
- Testing & maintenance of detection, monitoring, control systems
- Testing & maintenance of mitigation systems in case of a leak
- Procedure compliance, understanding via observation, interviews
- Technology developments that further reduce accident risk
There are also equipment aspects, including regular equipment inspections, confirmation of correct metallurgy viamositive material inspection (PMI) programs, use of reliable instrumentation and minimum acid inventory, and then the mitigation systems.
API RP 751 Elements:
•A comprehensive program should include (continued):
–Regular and rigorous equipment inspections to confirm integrity of unit equipment, especially acid containing equipment
–Use of correct metallurgy
- per NACE 5A171
•Confirmation with Positive Material Identification program, especially in case of repairs or changes to equipment, piping
–Tracking mechanism to ensure resolution, close‐out of identified issues
–design tracking system to facilitate next audit
–Reliable level instrumentation systems less prone to fouling, such as nuclear, radar, ultrasonic or magnetic
–Minimum acid inventory
–Mitigation systems
These mitigation systems can include a variety of active and/or passive elements along with tell-tale components. The main active mitigation system components include water deluge or curtain systems, remote monitoring and activation systems, and rapid dump systems to limit the quantity of any leak and contain the leak to the unit area. Vapor suppression additives fall under the passive mitigation category and can be considered along with all of the other possible elements available as part of a PSM program.
API RP 751 Elements:
Mitigation systems can include active and/or passive elements as well as tell‐tale components:
- HF detectors can be point, open path or imaging systems
- Install as needed in unit risk envelope
- Acid sensitive paint on flanges, pump seals, etc.
Active mitigation systems can include:
- Water deluge and/or water curtain systems
- Remote video monitoring and remote activation, isolation systems
- Rapid dump system to contain acid, limit the extent of the leak
Passive systems can include:
- Barriers & catch pans to contain acid release
- Minimum acid inventory control & staging in equipment
- Vapor suppression additives
Each facility should assess its own location-specific risk profile and develop a mitigation strategy that includes the elements that together effectively minimize those risks while conforming to the applicable regulations for that facility.
API RP 751
Conclusion:
- Each facility should determine their location
- specific risk factors, and assess the appropriate combination of active and/or passive mitigation systems needed to minimize risks involved in operating the unit
- Local, state and/or federal laws and regulations should also be reviewed
Question 72 What feed contaminants can lead to metal corrosion in both sulfuric acid and HF alkylation units? What operating conditions promote corrosion? What do you do to reduce corrosion and/or remove contaminants?
GRUBB (Chevron USA, Inc.) I’ve consulted Gary Ash, the Pascagoula local expert, and Steve Mather, who is the corporate expert. They relayed to me that acid is still the biggest problem and not really necessarily the contaminants; but where the feed contaminants come in, they can make the acid more corrosive. They pointed out that water is the worst and that it could get less than a 92% acid strength, it’s dramatically more corrosive. Also, alcohols can also increase the corrosive nature of the acid. Some of the things that we do to minimize acid corrosion is we always control the temperature to less than 100°F maximum. We control the velocity by using long radius elbows in the design and then we do careful consideration of throttling valves and flow orifices. We avoid dead legs in the pipes and we use the correct metallurgy wherever determined.
KAISER (Delek Refining Ltd.) The important point that Rick brought up is that it’s the things that spend your acid that are going to make the unit suffer more corrosion. There are a number of different contaminants that I believe you all are aware of, and there are references out there on rough guidelines for what they ought to be. The follow-up to that is you need to pay attention to what your acid strength is doing. You need to monitor your acid strength. In the case of an HF unit, monitor the water content of the acid. Sampling your acid circulation for strength three to seven times a week is not uncommon as is using online acid analyzers that can tell you continuously where you are. For HF operations, monitor your acid regeneration; look at how much polymer you’re making. You have to realize that a lot of the feed contaminants that come in and can spend your acid will change the boiling point of that ASO. So you need to adjust your regeneration operations accordingly and make sure you maintain good acid strength and good soluble oil rejection. One of the other things that can help out in an HF unit is that the color of the polymer itself can give you an indication of what the contaminant type is. For sulfuric units, maintaining a good effluent wash section and maintaining it hot enough—120°F or hotter—are recommended, as well as keeping up the caustic strength. If you have a caustic effluent treating or are using good high strength sulfuric acid in the effluent treating, this is also important for minimizing corrosion on the downstream deisobutanizers. The other thing that you ought to do is develop a very good inspection program for your unit. Make sure you’re watching the critical areas of piping, your critical pieces of equipment that you know are going to be prone to corrosion. Also include in that dead legs and small bore piping and bleeders that hang off the bottom of pipes. Those are all very common areas to have corrosion in your units. Even if you do maintain good acid quality, those are the places that low- strength acid or water will settle out and generate problems for you. There are a couple of NACE papers in the open literature that you can have access to. NACE paper 04645, “The Effect of Operating Conditions on Corrosion in HF Alkylation Units,” and NACE 07570, “The Top Ten Corrosion Issues Affecting HF Alkylation Units” contain good references for metal corrosion in HF alkylation units (with some applicable items for sulfuric units).
Question 73: Does alkylate volume yield decrease if T90 increases? Have you quantified the costs and benefits of reducing T90 by changing reaction conditions?
KAISER (Delek Refining Ltd.) With respect to alkylate yield and T90, the short answer to the question is, yes. When T90 increases, your alkylate yield is going to go down. And if that’s all you care about alkylation, you can go to sleep for the next five minutes and Jeff will wake you up when we get done. The two are tied together at the hip by the polymer make. The things that tend to give you heavier alkylate are doing so because the polymer make and the amount of tar in the unit is going up, and it’s influencing the T90. It’s also taking away from the good quality alkylate that you want. The table below is also in The Answer Book. You see some directional influences for the things that refiners tend to have direct control over inside their unit: iso-to-olefin ratio, acid/hydrocarbon ratio, acid strength, and so on. The first column is in terms of increasing parameter. If you increase your iso-to-olefin ratio, the T90 will tend to come down; the yield will go up; and also, the alkylate octane will go up.
Increasing Parameter | T90 | Yield | RON |
---|---|---|---|
Iso/Olefin | ↓ | ↑ | ↑ |
Acid/Hydrocarbon | ↓ | ↑ | ↑ |
Acid Strength | ↓ | ↑ | ↓ |
Iso Recycle Purity | ↓ | ↑ | ↑ |
C5= and/or C4== Feed Composition | ↑ | ↓ | ↓ |
Feed Contaminants | ↑ | ↓ | ↓ |
Reaction Temperature | ↑ | ↓ | ↓ |
Reaction Time |
↑ | ↓ | ↓ |
We won’t spend a lot of time on that slide because it’s in the book. You can look at it and reference it in relation to this next slide where we talk about everything that you have a handle on that you can adjust is a range; there’s a spectrum. There’s an area that you want to try and operate your unit in to give you the best balance between not only yield and T90, but also within equipment constraints and also within safe operating parameters for the different things inside the unit. The table below shows you rough—and I do want to emphasize rough—guidelines that are highly situational dependent. The parameter is in the center; there’s a spectrum to the left; and, there’s a spectrum to the right, in terms of increase and decrease in parameters. The four items on the top—the iso/olefin ratio, acid/hydrocarbon, the acid strengths, and the isobutane recycle purity: those are the kinds of things that you’re going to want to tend to maximize as much as you’re able in order to minimize the alkylate T90 or decrease the alkylate T90 and increase your alkylate yield. The things on the bottom are the kinds of things that you’re going to want to minimize. You’re going to want to have lower feed contaminants. Lower reaction temperatures will tend to decrease the polymer make, decrease your T90, and increase your alkylate yield.
Red | Yellow | Green | Green | Yellow | Red | |
---|---|---|---|---|---|---|
4 |
6 | 8 | Iso/Olefin | 14 | 16 | 18 |
0.9 | 1 | 1.5 | Acid/Hydrocarbon | 2 | 2.5 | 3 |
80 | 83 | 86 | HF Acid Strength | 90 | 93 | 96 |
84 | 86 | 88 | Sulfuric Acid Strength | 92 | 94 | 98 |
75 | 80 | 85 | Iso Recycle Purity | 95 | 98 | 100 |
0 | C5= Feed Composition | 5 | 7 | 10 | ||
0 | C4== Feed Composition | 0.5 | 2 | 4 | ||
60 | 70 | 80 | HF Reaction Temperature | 90 | 100 | 110 |
35 | 40 | 50 | Sulfuric Reaction Temperature | 60 | 70 | 80 |
Deviations from “center” range lead to increasing problems / constraints
Straying away from the center is not always a bad thing. I think there are certain things, certainly acid strength, that if you go too low on acid strength, you tend to put your unit in danger of corrosion and eating the thing from the inside out. Lower iso/olefin ratios are not favorable. You can actually get it where you have incomplete reactions and continue to have reactions inside the tower in places you don’t want it. There are also practical limits. For instance, on the iso/olefin ratio, if you go higher than 18, it’s not that the unit is going to encounter operational problems. It’s just that you’re probably spending too much in terms of utilities, reboiler duties, condenser duties, electricity in pumping the stuff, and it’s not really buying you anything. You’ve reached an upper practical limit for what you’re trying to do and you’re not really getting any benefit in terms of your alkylate yield. So what your refiner needs to do is to try and understand where he is in this spectrum. I would suspect that a lot of you are probably already in that green zone. Depending on which parameter you have the most control over, you can do small test runs in your unit or small paper studies to see what happens if I increase this parameter because I have some room there, then how much of a response do I get in T90 and alkylate yield and what does it cost me? You can then make your own judgments from there.
ZMICH (UOP LLC) For the alkylation response here, I’ve drawn from our Technical Service Department expertise. UOP experience suggests that olefin feed composition probably has the greatest effect on T90, especially the amylene content of the feed. Our experience, “our” being UOP, suggests that fixing the feed olefin content and changing the process variables within normal range of operation would not have a strong effect on T90. In the middle of the slide, in general, for a given olefin feed composition, if the T90 increases, the alkylate specific gravity is also going to increase. For an equal weight yield, there is going to be a volumetric yield loss, as Allen was suggesting. If the T90 is increased by decreasing the isobutene/olefin ratio, then the alkylate octane would be expected to decrease and this effect could be significant. Finally, UOP has not quantified the cost and benefits of reducing T90 by changing the reaction condition.
Alkylation‐T90
•Olefin(C5=)hasgreatesteffectonT90
•FixingC5=,changing process variables has small influence
↑T90↑AlkylateSG
Equal Wt. yield ↓volume yield
•UOP has not quantified cost‐benefits of reducing T90 by changing reaction conditions
RICHARD DOSS (CITGO Petroleum Corporation) I have a question on some of the ranges from this table that’s listed here. It’s listing 50°F as outside the expected or optimum operating range for a sulfuric acid reaction. I’m used to seeing that number lower. Is there some more recent test data that’s saying 50°F is the bottom of that range?
KAISER (Delek Refining Ltd.) I had to make the table, so I had to put down some sort of a number. What I was trying to imply by having that in a green box is that 50°F is likely to be a good temperature for alkylation reaction. That doesn’t mean that if you hit 49°F and you’re in the yellow zone, all of a sudden you’re going to have subpar yield and you have to do everything you can to get it back to 50°F. This is a very broad spectrum; but in terms of trying to present something concise and understandable in a short timeframe, I put these numbers down. They’re a range, and it depends on particular pieces of equipment. But specifically, I would say, no. The 50°F is a good alkylation temperature. We tend to run our reactor in the mid-40°Fs to about 50°F. So for us, we’re a little bit cooler than that.
J. RANDALL PETERSON (STRATCO-DuPont) We design new units for 45°F and sometimes down to 42°F. Typically, I think Allen is correct: Most units run between 50°F and 60°F, the ones that are running out there, but you do get a little bit better octane at the colder temperatures.
CAMERON McCORD (Chevron Corporation) We have a sulfuric acid plant. One of the two has what we call a rerun column where we split the alkylate into a light avgas alkylate to the, probably, 75°F to 80°F yield. And then, a heavy alkylate comes off the bottom and goes back to the whole alkylate tank. Has anyone gotten experience, either on the panel or in the audience, with trying to find a better disposition with the heavy alkylate from a rerun column other than gasoline, jet, or diesel given the economic times we’re in these days? And, what product quality concerns might you expect?
KAISER (Delek Refining Ltd.) We also have a rerun column and what we’re not able to split off as light does go to gasoline. We have sufficient jet-treating capacity that we don’t find the need to try and push it into jet. My suspicion would be that it might be suitable. And again, it depends a lot on what you’re blending it into. It may not serve as a stream by itself, but you might be able to blend it in there, depending on where you are in terms of some of the cold-flow properties and if you’re trying to make a Jet-A versus a JP8. And then, I want to clarify briefly, again, on this table, that some of the things on here are not meant to be as strict limits in how they relate directly to the T90 and the alkylate yield. As Randy pointed out, cooler temperatures do tend to favor alkylate octane and yield, but you’re also paying for something. That might mean that you’re running your refrigeration compressor a lot harder, so there might be some economic penalties towards running closer to that 40°F. And so, this spectrum is not meant to serve as hard-and-fast limits for how you run the unit, but to serve as kind of directionally economic indicators that there are benefits to going lower than the 50°F, lower than the 40°F. But, they come at a cost and you’re going to have to understand the difference between that cost and benefit.
HAZLE (NRPA) Are there other panelists that have comments about disposition of heavy alkylate?
J. RANDALL PETERSON (STRATCO-DuPont) Yes, I have a follow-up comment. I didn’t load that question with all that I knew on the subject. [laughter] We have indeed tested the jet for the heavy alkylate for suitable of the jet. It’s bad on WISM in the jet. I suspect some of the polar molecules following through from the alkylation process. I was hoping someone might have a comment on how to get rid of those bad properties or if there is another disposition for that stream, perhaps a higher value.
HAZLE (NRPA) Did you want to follow up on the WISM?
KAISER (Delek Refining Ltd.) I will try. I don’t know how much room you have on your deisobutanizers (DIB) reboiler; but if you’re suspecting polar molecules, you might try to run your DIB a lot harder and try to break down a lot of those esters in the reboiler itself.
RICHARD DOSS (CITGO Petroleum Corporation) Another comment on the table that we have up here: For the units that I am aware of personally there, you find that a lot of people are running more to the right side of that table; its economics. Basically, you’re pushing capacity; you’re trying to get more through the units. You just can’t get over to the left side, but it’s the right place to be running because it makes the most money.
Question 74: Have you experienced a shortage of KOH supply for your HF alkylation unit? Are you concerned about KOH availability? What are your alternatives if KOH is unavailable?
METKA (Sunoco, Inc.) Sunoco has experienced significant shortages of KOH in both our northeast and mid-continent refinery complexes. This appears to be a universal issue. In addition, a primary supplier to the northeast claimed force majeure earlier this year. We do have some concern over this issue since both the HF alky and some LPG treating units are impacted. We’re working to identify and pursue alternatives, which include alternate suppliers, as well as application of liquid sodium hydroxide and mole sieves in the treatment applications. We did consider sodium hydroxide for use at the HF alky, but the solubility of the sodium fluoride limits starting strength that results in equipment and logistics limitations, so that was deemed as not feasible for us.
Reclaiming or regeneration of spent KOH is also being evaluated. If you do pursue this type of option, you should take a look at your storage and handling facilities and make sure that you don’t have any industrial hygiene concerns pertaining to the handling of the spent and return KOH.
Question 75: The butane stream from a catalytic polymerization (cat poly) unit, which contains 69% isobutene, 14% butylenes, and 17% normal butane, would appear to be an excellent alkylation unit feedstock, especially if isobutene is i
METKA (Sunoco, Inc.) We operate a cat poly and sulfuric alkylation unit within the same refinery. The configuration offers flexibility and synergies that allow various operating and business demands to be met. In our configuration, the cat poly debutanizer overhead feeds the alkylation unit to recover the isobutane and any remaining butylenes.
Similar to our other SPA experience, acid carryover from the effluent filtration system typically drops to the bottom of the downstream fractionators resulting in fouling and corrosion of the reboilers. Historically, we have not experienced any significant impact on the alkylation unit or sulfuric acid quality due to carryover from the cat poly unit. If carryover were to occur, we do expect that the phosphoric acid would be more of a corrosion and fouling concern than an acid consumption issue.
Below is a plot that basically shows the way in which the plants are configured. The BB is treated and split to the cat poly and alky units in parallel. Once we recover the C4s off the backend of the cat poly plant, the stream is fed back into the alkylation unit.
Gasoline ProcessesGasolineProcessesFCCDebutDepropBtmsCat GasolineC4,C4=PolyTreaterAlkyContactorsDepropDebutDepropBtmsLPGPolymer GasolinenC4,iC4ContactorEffluentDIBDebutnC4/AlkylatenC4AlkylateMake-up C4iC4PolyAlkyFCCGasolineMixed ButaneiC4nC4Rxr EffluentTreated C4, C4=EffluentTreatingPolyRxrs (FUNKY GRAPHIC)
ZMICH (UOP LLC) I have three points that I would like to make.
1) UOP does not have experience with traces of phosphorus in the alkylation unit feed.
2) UOP strongly recommends avoiding the possibility of phosphorus in the feed. The reason for this is that a combination of mineral acids will lead to a more aggressive corrosion than either of the two acids by themselves.
3) From a commercial perspective, UOP is aware of at least one refinery that feeds cat poly stream with feed from an FCC to an alkylation unit, and the process flow is shown in words as such: “Process flow is a stream goes through a water wash to remove phosphoric acid, the sand tower acting like a coalescer, and a UOP MeroxTM unit to remove sulfur before going to the alkylation unit.