Safety and oxygenate operations made HF alkylation a hot topic of discussion at the most recent National Petroleum Refiners Association annual question and answer session on refining and petrochemical technology.
The panel of experts responded to a variety of questions regarding the mechanical, process, and safety aspects of the HF alkylation process. Among the issues discussed were mitigation techniques, removal of oxygenates from alkylation unit feed, and amylene alkylation.
The NPRA Q&A Session was held Oct. 16-18, 1991, in Denver. For further details on this important meeting and its format, see OGJ, Mar. 16, p. 3 7.
AMYLENE ALKYLATION
Are people alkylating C5 olefins in HF units? What levels are being alkylated? What are the results regarding octane, Rvp, end point, and acid soluble oil (ASO) yield?
Grant: Our operating experience indicates that C5 olefins at levels above 5% of total unit charge, treated with C3 and C4 olefins in conventional amine/caustic systems, will cause excessive acid soluble oil production and acid consumption. The increased diolefin content of the amylene feed increases acid losses through increased ASO make.
I would like to mention a few references on this topic: the 1987 NPRA Q&A Session transcript on pages 109 and 110; and also two papers presented at the 1991 NPRA Annual Meeting; AM-91-16, "Integrated Olefin Processing," by Lawrence Lew, Donald Makovec, and Martyn Pfile of Phillips Petroleum Co.; and AM-91-50, "Ultimate C4/C5 Olefin Processing Scheme for Maximizing Reformulated Gasoline Production," by Pam Keefer and Ken Masters of Stratco Inc. and Jean-Luc Nocca and Jean Cosyns of Institut Francais du Petrole.
Golden: Two of our U.S. refineries alkylate C5s. Normally about half or less of the available C5s are alkylated. Driving additional material off of the fluid catalytic cracked (FCC) gasoline results in a marked increase in ASO production so that handling of it becomes difficult. The increased ASO and polymer production are due to the increased levels of diolefins and C6 + material. By alkylating C5S, the Rvp of FCC gasoline is reduced, bringing about an overall reduction in pool Rvp. However, I would second Mr. Scott's earlier comment that the reduction may not be as dramatic as you would suspect.
If one third to one half of the available C5s are alkylated, the end point of the product alkylate will remain within specification limits. Future regulation of gasoline 90% distillation point, however, could change this. Since the octane of C5 alkylate is not radically different from mixed C5S in our experience, the octane impact on the overall pool is relatively small.
With regard to increasing amylene alkylation, some loss of flexibility in blending premium gasoline may be suffered since the total alkylate octane will drop as more C5s are added to alkylation feed. Fischer: Our experience confirms the previous comments. We are alkylating Some C5 olefins in one of our HF alkylation units in the order of about 5% of feed. We have not quantified the results fully yet, but we have seen a drop in octane and an increase in ASO yield.
McClung: To my knowledge, no one is actually processing pentylenes alone in an alkylation unit. I know of one other refiner besides the ones I have already mentioned who processes C5 olefins in conjunction with C4S, but I have no results for that.
Pazmanyi: We do not process C5 olefins in our HF alkylation plant, but I have some background information from UOP.
They told me there have been several applications over the years, and there has certainly been a lot of study and preparation under way for the future C3 amylene alkylation.
Regarding the performance, around 90 to 92 road octane can be expected from C3 amylene alkylate with 2 to 5 psi Rvp, depending on conditions, and whether it is all or only part-for example, tertiary amyl methyl ether (TAME) raffinate-of C5 amylene.
Regarding how much polymer would be made, they expect that the regeneration requirement would be about 1.5 to 2 times more than for C4 olefins.
Of course, the impact will be lessened by being only a portion of the total unit feed.
Robert E. Davis (R.E. Davis Chemical Corp.): I would like to inject one thing for the people who are alkylating C5 olefins in HF units. Please monitor the fluoride content of your finished product.
I think you are in for a big surprise.
OXYGENATE REMOVAL
Has anyone replaced all or part of their feed drying beds with materials to remove oxygenates from MTBE operational If so, is regeneration by any stream other than butane being considered?
Knepper: We do not have an MTBE operation; however, we have oxygenates in our Butamer fees. The oxygenates originate with the saturate feed coming into the alkylation unit. We are using Alcoa Selexsorb CD alumina in a single Butamer guard dryer that is in series with the feed dryers to keep oxygenates out of the Butamer reactors. The regeneration is with butane.
We have not quantified the performance of this material in removing oxygenates, however, we lose Butamer activity every time this guard dryer is regenerated. We will be considering additional Selexsorb in the saturate feed dryers. However, when we do that, the regenerate will have to go to storage instead of back to the olefin feed.
Williams: Southwestern Refining Co. Inc.'s alkylation feed dryers are charged with a molecular sieve. Our MTBE unit, which is scheduled for completion during the third quarter of 1992, will include a set of adsorbers for removal of oxygenates from alkylation feed. The adsorbent system that we have chosen is licensed and marketed by UOP.
STAGED FEED INJECTION
What results are being achieved with staged feed injection, especially first-stage butylene and second-stage propylene, regarding expected vs. actual alkylate yields, octane, acid consumption, ASO production, and utility savings? Is there an advantage of splitting butylenes and amylene?
Pritzel: I am not aware of anyone operating with segregated stage feed. Plants have been operating for a number of years with two stages feeding mixed C3-C4 olefins. The advantage of two stages is to increase the efficiency of the system by optimizing the isobutane-to-olefin contact in the reactor. If the C3-C4 olefins are split, a higher-octane alkylate and slightly higher alkylate yield would be obtained.
When propylene is charged separately, additional propylenes would react with the excess isobutane via the hydrogen transfer step, resulting in the production of 2,2,4-trimethylpentane and propane. The 2,2,4-trimethylpentane has an (R+M)/2 octane several numbers higher than the typical 92 to 94 octane of alkylate. However, this requires additional isobutane. You would also have a higher acid consumption and additional propane yield.
As far as the splitting of butylenes and amylene in staged feed injection, again I am not aware of anyone doing that. However, if that were done, you could expect an increase in the hydrogen transfer reaction, which would produce isopentane from the amylene. The result would be a higher-octane alkylate, but also a higher-Rvp alkylate which, as has been mentioned before, is not really desirable.
Knepper: I concur with Mr. Pritzel. We have a two-stage unit where we feed a mixed feed to both. In terms of the utilities, we have saved quite a little on iso-to-olefin ratio. We run an 8 iso-to-olefin ratio (molar) right now, but we have been as low as 5.
CORROSION CONTROL
Is anyone using unique materials such as Teflon trays or carbon packing in an HF acid regenerator? What other corrosion control methods are employed?
Pazmanyi: To the first part, our answer is no. We do not use such materials. To the second part, my comment is that after four years of operation, the 3-mm internal Monel-400 lining of our acid regenerator was corroded and just now we are chancing it for new solid Monel equipment.
We tried also to change the regeneration process, and we would like to improve the oxygenate removal from our FCC C4 fraction alkylation feed.
Pritzel: The main problem is to keep the water content of the acid down. This means frequent monitoring of the acid purity and water level to prevent acid attack.
Moyse: I have to add a negative comment. We were not able to locate anyone who was using special materials in this regard. We are told that the corrosion control is quite simply a matter of the choice of the correct metallurgy.
Knepper: Our tower uses a monel pipe insert filled with monel Raschig rings. We have tried carbon rings, but then, disappeared after a short time. The Teflon rings melted. However, part of the insert uses a Teflon seal. The seal holds up marginally well, but is 1/4-in. thick. The monel rings also corroded away after a period of time, but do provide a reasonable run length before they are gone. However, the monel rings cost approximately $600/cu ft.
Hamilton: I have nothing further to add except that we are not aware of anyone using the Teflon trays or the carbon packing,
NEUTRALIZATION PITS
What methods are being used to agitate covered neutralization pits in HF alkylation units, and has there been any problem with vapor evolution from these covered pits?
Williams: Our neutralization pit is agitated using a Lightning mixer. In 1972 we installed a pit blower to move the vapors to the iso-stripper reboiler for destruction. Since installing this blower, we have not had very many problems with vapor emissions from this pit.
Pazmanyi: My answer is also negative. We have never experienced vapor or gas evolution from the two neutralization pits in our HF alkylation unit. The agitation can be done using the built-in mixing pumps.
Fischer: One of our refineries initially used air agitation, but subsequently switched to a propeller-type mechanical mixer. This particular pit has a PVC vent pipe on top of the pit for dispersion of vapors. We also use a small continuous nitrogen puree across the vapor space in the pit.
SOLID CATALYST
What progress is being made on developing a solid catalyst for the alkylation of light olefins and isobutane?
McClung: Unless there is some public announcement at this particular Q&A Session, I cannot be terribly encouraging on this subject. What progress is being made is published in patents, which I review just about monthly. The most prolific in publishing U.S. patents is Mobil. If such a process had been invented by now, I think that Jim Maiden would have told you.
Mobil's approaches in the patents are based on boron tri-fluoride, called BF3, and their other approach is zeolitic. However, to my knowledge there is no commercial application of either of these. I know that it is the "Holy Grail" of the petroleum industry to find this kind of process, and there is a lot of work being done. I think Mobil is your most reliable source for progress.
Pazmanyi: I have only some literature data. I think there are three types: (1) zeolites, (2) acidic ion-exchange resins, and (3) the oxide-based super acids. I have not heard of any commercial applications.
Michael Humbach (UOP): We concur with what has been said. We have a fairly intense R&D effort going on right now in this area. What we are finding is that indeed it is going to take a breakthrough, not only in catalyst technology, but also in process technology. So at this time, we do not have a technology to announce, but we are working on it.
FLUORIDE ANALYSIS
What kind of instruments are being used successfully to monitor fluoride ions in cooling water and condensate water both on-line and off-line? What is the testing and calibration frequency?
Pazmanyi: In our HF alkylation unit, we use Foxboro E99S type fluoride ion analyzers on-line in the cooling water system, in the condensate return system, and in the neutralization pit effluent water. The calibration frequency with Orion 9409 electrodes is once a month; the checking-out and testing are done weekly. Last year, the same serial number resulted in modified electrodes where the calibration and testing work had to be done more frequently.
We use an off-line Radiometric pH my measuring instrument with fluoride selective electrode, which gives a linear millivolt logarithmic concentration characteristic curve in the full measuring range (from 0.1 to 1000 ppm). Calibration is required every 3 months, We use a Radiometer Copenhagen pHM 84 pH meter with an F-1052 F electrode.
Pritzel: Fluoride ion specific analyzers have been used with success in some locations on-line on the cooling water. These analyzers have good sensitivity. On the other hand, they are subject to interference from the chloride ion, so they will not work in salt water service. They also require preventive maintenance since they are very dependent on the quality and representivity of the sample.
Typically they are located on the cooling water outlet of the reactor and in the main cooling water return header. Calibration at least once per month is recommended.
Some pH analyzers have also been used, but since there are many variables affecting the pH, a fluoride leak would not be detected quickly unless it was a major leak. Hydrocarbon leak detectors have been used on condensate systems.
Williams: We have elected to monitor the pH of the cooling water exiting the HF alkylation unit rather than attempting the specific ion route. At the outset, we worked with Rosemount in attempting to analyze for the fluoride ion but, as Mr. Pritzel has already observed, we encountered significant interference.
Additionally, there appeared to be problems with the durability of the specific ion probe. We therefore decided, just on a cost and reliability basis, to select pH measurement. Our standard for this service is the Rosemount Model 103. The pH readings are continuously monitored, recorded, and alarmed via the distributed control system (DCS).
Dennis Finch (Eppendorf North America Inc.): The Eppendorf EPAS high-speed, on-line analyzer hardware will run methods for the analysis of fluoride in cooling water, boiler feedwater, condensate, and similar streams, The analytical method is determined by the required level of detection and the stream's chemical matrix.
This analyzer will provide immediate information as to breakthrough of condensate polishers or resin beds, allowing fast remedial action. The EPAS can be used to control blowdown, as well.
The EPAS series analyzers employ an autocalibration feature that is operator programmable as to frequency and sequence. Calibration frequency is dependent on the method of analysis. Once weekly is typical. Alarms are operator programmable, as well.
PH ADJUSTMENT
How are pH adjustments made for HF alkylation unit spent lime before disposal? What reagent is used?
Knepper: We now have a KOH system, but previously we used lime. Our past experience was to trickle a predetermined amount of concentrated sulfuric acid into the sludge while turning the sludge over with air spargers. The exact amount of acid required was determined in the laboratory by titrating a sludge sample to a pH of 11. We then leave the air spargers on overnight and verify the sludge pH prior to disposal.
We want to stress that the acid must be added at a controlled rate as the reaction can be violent if added too quickly, and this would result in a vapor release.
Williams: We adjust the pH of our spent lime by controlling the blend of constant boiling mixture (CBM) and a neutralization solution containing 4% calcium hydroxide and 2% potassium hydroxide. The CBM flows first into a mixing pit where it is thoroughly mixed with the neutralization solution; we typically correct the pH to between 7 and 9. If we need further corrections, we have the flexibility of adding sack lime as needed.
Once the pH has been corrected, we move the mixture to a transfer pit for removal and additional processing via centrifuge. The lime cake produced from the centrifuge process is considered a Class I nonhazardous waste, and is disposed in a landfill. The water recovered from the lime is processed in our wastewater treatment plant.
At one point we did experience poor control in the neutralization process, which resulted in high-pH material in the neutralization and transfer pits. During that period, our neutralization solution was composed of 6% potassium hydroxide and 6% calcium hydroxide. Reducing the concentrations of these compounds to the level mentioned earlier appears to have corrected our pH-control problems.
David Kennard (Tetra Technologies Inc.): I would like to reiterate a response given yesterday under the topic of recycling solid wastes. Tetra has modified some of its existing waste acid treatment technology to produce a high-purity densified calcium fluoride product from ASO and acid relief neutralizer (ARN) streams capable of being recycled. Tetra's waste treatment division is marketing this process to refiners using HF alkylation.
HF MITIGATION
What HF mitigation measures are being installed by refiners? What level of acceptance by regulatory and community concerns has resulted?
Williams: In conjunction with an expansion of our HF alkylation unit in 1988, Southwestern put in place a number of measures for reducing HF exposure risk, A water deluge system using 13 stationary standard Nfpaul-certified monitors was added. The monitors are capable of flowing 500 gpm at 100 psig.
Deluge monitors were placed at various elevations around the acid storage drums, reactors, and settlers. Five of the 13 deluge nozzles are located outside of the acid area. Depending on wind direction, these may or may not be utilized during a leak. These monitors are adjustable, and the master can be activated from the control panel in our central control room or from one of four locations within the unit.
A 40:1 ratio of water to HF was used as a basis for design. This was developed from the field test conducted by the HF mitigation task force led by Lawrence Livermore National Laboratories. In addition to this, our acid circulating pumps are each equipped with two 25 gpm sprinklers that are designed to produce 300 ii droplets at 100 psig.
These sprinklers are located approximately 3 ft from the pump seals. These acid pumps are also equipped with double seals, so an inboard seal failure would result in a flow of buffer fluid into the process.
For containment of HF spills, we have added a retaining wall around the perimeter of our new first-stage reactor, acid settler, and HF storage vessels. The wall is constructed of concrete, and is 4 ft high by approximately 6 in. thick with water stops installed at all joints. The volume of the containment area is designed to retain a full volume of the largest process vessel, which in our case is the acid storage drum.
Pazmanyi: Our UOP HF alkylation unit was built in 1987 and started up in 1988. The unit design included an automatic isolation system for acid circulating pumps, HF and hydrocarbon detectors, an up/down two-way water curtain system around the acid area, HF sensitive paints, a meteorological station, a change house, emergency booths, etc.
After some strong complaints from the outside, the following was done:
- Emergency telecommunication and a warning system were established for the two neighboring cities.
- The refinery provided thousands of gas masks for personal use.
- A foundation was established consisting of a special technical committee, responsible for the safety and technical level developments in the HF alkylation unit. These developments included reduction of acid inventory down to about 25 tons in the system, an emergency acid dump system, overpressurization of the control room in case of emergency, isolation of the acid regenerator from the iso-stripper using remote operated valve, remote operation of the water curtain, acid unloading automatic shutoff valves, a maintenance and operational survey, Hazop, etc.
These modifications are already in progress (about 90% complete). The acceptance level, after introduction of a new policy of "open gates," is improving.
Knepper: We have installed remote motor-operating valves at the strategic locations within the concentrated acid section of the unit. These include the suction and discharge valves on the circulating acid pumps, as well as the valves to isolate either one of our dual reactor settler systems. We also have a remote-operated valve on our acid unloading line at the loading spot, which can be shut to isolate any rail car, truck, or hose problems.
Hydrocarbon alarms are located throughout the unit which we feel will indicate a leak of acid in the unit since even our most concentrated acid streams contain adequate hydrocarbon to activate these hydrocarbon alarms. We have tested these sensors. We feel that the fluoride alarms that are currently available will not be reliable in our climate.
We recently replaced our old vertical mixer settler with a modified settler design which eliminated the old trayed mixer section. This reduced the required operating acid inventory by nearly one half on that particular reactor system,
The combined acid inventory of both systems was 65 lb of HF per b/d of alkylate.
It is now being operated at 40 lb of HF per b/d. We think we can approach 25 lb per b/d. The new modified settler has a boot on the bottom which will provide an operable acid level range without the full acid volume.
The same project replaced our acid storage drum. Both of these new vessels were made from low-sulfur, vacuum degassed, normalized steels that are available today. This reduces the possibility of any hydrogen blistering.
The project also installed double seals on all of our concentrated acid pumps, with alarms on the outer seal alkylate flush to indicate any inner seal problems.
In terms of regulatory and community acceptance, we are participating in the local emergency planning committee. This group is planning for any major problem, not just HF. They are installing sirens, and are providing public education on how to react in an emergency.
Grant: At one of our locations we have already implemented: hydrocarbon detectors; remote-control tv monitors; remote unit shutdown systems; remote shutdown systems to isolate smaller sections of the plant in an emergency; automatic shutdown systems on the propane and butane KOH treaters to protect the equipment from overheating; and HF and hydrocarbon detectors in breathing air intake, which automatically trip the breathing air compressor on high level.
Critical isolation valves in HF service are solid monel plug valves. Critical thermowells have been upgraded to the latest Phillips specifications. All nonessential nozzles have been removed from the HF acid reaction circuit. We have installed a bypass around the acid relief neutralizer with a rupture disk to route to the flare in case the neutralizer becomes blocked.
Work in progress includes pump seal fire detection system, water spray deluge systems on all HF inventory vessels and pump seals, and remote-controlled elevated fire monitors. Planned measures include a rapid acid dump system and reduction in HF acid inventory.
Golden: We are progressing well on a plan that addresses leak prevention, equipment isolation, leak detection and warning, and leak mitigation. Much of the new installation is automated so as not to require intimate operator interface.
Key components of the overall plan are: eliminating piping and equipment where the risk of a leak may be high; installing an automatic vessel isolation and acid dump system; installing HF detectors, water sprays, and other mitigation and detection equipment; and increasing the inventory of personal protective gear and dispersing the same over more varied locations.
In addition, we train the noncompany local emergency responders through the local emergency planning commission (LEPC) in specific techniques to deal with HF. We further believe that community awareness coupled with community involvement are key issues that must be addressed, and are not limited to HF.
Frederickson: We are using water spray from fixed monitors. We have also established detailed inspection practices and material specifications for our plants. Leak detecting monitors are scheduled to be installed. So far, we have had no regulatory or community problems or concerns about what we are doing.
Fischer: We conducted a fairly extensive risk analysis about 4 years ago using an outside consultant. We also subscribe to the HF mitigation task force work done in recent years. We are now in the process of installing a three-level water spray system made up of dose-up fire deluge nozzles, a perimeter spray curtain, and several elevated remotely operated water cannons. A separate sewer and holding pond will collect the runoff water.
In addition we will have a remotely located dump tank and piping designed to deinventory the unit of HF in less than 10 min. These systems will be activated separately by the control room operator. We also have HF detectors at the unit perimeter and have had good experience with them. In addition to this we have remotely controlled tv monitors at strategic locations throughout the unit.
Steven Fischer (Champlin Refining & Chemicals Co.): For those who are using water mitigation techniques with these high water ratios (40 to 1), what scenarios are you using to determine the amount of HF that is released to which 40 to 1 ratio will apply? What size rupture is being considered?
Williams: A wide variety of release scenarios was examined in the course of the hydrofluoric acid spill experiments conducted in Nevada. Acid release rates varied from about 470 gpm for the vapor cloud dispersion tests, to about 33 gpm for one of the water spray mitigation tests. Some of the graphical data I have seen based on these field tests indicate that at a volumetric water-to-acid ratio of about 40, HF scrubbing efficiency approaches 90%.
A more complete discussion of the testing program may be found in the Oct. 17, 1988, edition of Oil & Gas journal. Additionally, you may wish to refer to a paper by D.N. Blewitt, et al., entitled "Conduct of Anhydrous Hydrofluoric Acid Spill Experiments," International Conference on Vapor Cloud Modeling, Cambridge, Mass., Nov. 2-4, 1987.
Golden: I know that various orifice sizes have been looked at through the auspices of the HF mitigation task force. I think 1/2 and 3/4 in. were two sizes that were looked at, and obviously they set different design criteria. I think that different companies may standardize differently depending on what types of small fittings they have. I believe the thrust has been towards a leak-at-a-bleeder scenario for a design basis.
Bruce Scott (Bruce Scott Inc.): I have a couple of comments. Responding to the question on the size of the hole, in my experience most people have been looking at anywhere from a 1 in. or 3/4 in. I think South Coast Air Quality Management District in Los Angeles set up a 2-in. hole as their standard leak.
The other comment I wanted to make was that the API committee on HF alkylation has prepared a recommended practice, RP751, dealing with HF safety issues. That practice is out for ballot now. Balloting ought to be over by the end of this month or early November. It will cover most of the things you have heard said by the panel.
MAGNETIC DRIVE PUMPS
James J. Spears (Spears & Associates Inc.): I have a general question. Is anyone using magnetic drive sealless pumps for HF service?
Knepper: I am aware that Sundyne is currently selling a pump. It is not a magnetic drive pump, but it is a completely enclosed pump that is sealless. They were just in not long ago trying to sell me one. I know that they are being used in California in some refinery out there.
Golden: I have a comment on magnetic drive. Maybe some of the vendors can amplify on this. I think the problem with the magnetic drives so far has been horsepower limitation. You have to have a rather small alkylation unit for the magnetic drive to have a good application. If the pumping rates are fairly high, I do not think the magnetic drives currently can provide the horsepower required.
James J. Spears (Spears & Associates Inc.): Mr. Golden, what horsepower are you talking about? When you mentioned the limits on horsepower, what is the typical limit? Magnetic drives go up to about 75 hp. So I am wondering what would be the normal requirement. (A later inquiry to Dickow, one of the largest manufacturers of magnetic drive pumps, revealed that they have pumps up to 200 hp and-depending on the specific application-potentially higher.)
Golden: Obviously it is going to vary from plant to plant. At our plant, the add circulation pumps are 400 hp, which currently exceeds the magnetic drive capability. The fresh acid pump is at the upper end of mag-drive horsepower range, and therefore is questionable. So far, we have elected to stay with enhanced seals.
Molla K. Anam (Unoven Co.): I have two questions about the rapid acid dump system: (1) When the acid is dumped rapidly, how is the pressure maintained in the dump drum? (2) Is anyone using any remote acid transfer tank? If so, what type of precautions are taken for that remote tank?
Golden: Perhaps I did not understand the question, but in our design, the objective is to get rid of the pressure at the point of the leak as quickly as possible, not to maintain it. As far as where the acid goes, that is the big risk, I think, in all of this. I do not know of any design anyone has that is absolutely failsafe in all scenarios.
In your design, it is important to consider the impact that activating the dump system will have on the acid relief/storage vessel. Sizing and pressure rating of the vessel are two critical parameters in that design. The vessel should be designed to handle a pressure increase during filling so as to minimize venting and relief requirements.
Michael Laux (Diamond Shamrock Refining & Marketing Inc.): What model HF detectors are you using, Mr. Fischer?
Fischer: The instrument we are using is the TG Series F type HF monitor, manufactured by Bionics Instrument Co. of Japan. The Canadian agent is Aquatronix Inc., 70 Gibson Dr., Unit 8, Markham, Ont.
BUTANE CONTAMINATION
Are there any contamination problems in processing the alkylation unit butanes in an C4 isomerization unit or selling them on the open market as butane product (i.e., pipeline specifications on fluoride concentrations and the status of effective fluoride removal technology to avoid catalyst poisoning)?
Frederickson: Alkylation unit butanes are indeed a problem for isomerization plants.
In the one refinery where Chevron currently has both an isomerization plant and an HF alkylation plant, we send the alkylation plant butanes to a KOH treater and then to gasoline blending. We do not recycle them to the isomerization plant.
At two other locations we defluorinate the alkylate butanes with activated alumina to meet sales specifications. We are building an isomerization plant at one of these locations and are considering recycling the alkylation plant butanes after defluorination down to 1-2 ppm fluoride.
As for sales, our Warren Petroleum subsidiary recently set a specification of 1 ppm fluorides in normal butane that they purchase.
Knepper: We do not sell butane, but we do use as a source of Butamer feed, the side cut butane from the iso-stripper. Feeding iso-stripper butane to a Butamer unit can be a problem if adequate feed treatment is not in place. The butane is first treated with two alumina treaters in series and then dried. We sample weekly the outlet of the first treater and change the alumina when fluoride breakthrough occurs.
One lesson we have learned is that if the fluorides do break all the way through both treaters they will chew up your dryer sieves quite effectively. If we keep a close eve on samples, then everything works alright as far as the fluorides are concerned. There is usually something else that shuts us down, like oxygenates.
UOP says that 1 lb of fluoride poisons 100 lb of catalyst. For selling the butane, a KOH treater after the alumina treaters is recommended to drop fluoride levels even lower.
Pritzel: I do have two other comments. There are contamination problems, but, as mentioned, if the proper treating equipment is used you should not have any problems.
Also, you must do routine testing to make sure that you do not have a high fluoride content or that you are not getting a fluoride breakthrough.
David Smith (Alcoa): With proper design and operation of the butane defluorinators on your alkylation unit, you can obtain as low as 1 ppm by weight HF in the effluent.
Then, as far as the feed stream to a Butamer unit, you can, through selective adsorbents, molecular sieves, or activated aluminas, remove all those other contaminants. These contaminants include HF that has come through, oxygenates, or mercaptans, or any of the other contaminants of concern.
Thus, you can protect that Butamer catalyst.
VESSEL CRACKING
What has been the experience with cracking of HF unit vessels? What were the locations of cracks on the vessels? What percentage of welds are checked? What is the acceptable upper limit of weld hardness?
Fischer: Our HF alkylation unit has been operating since 1966. To date, we have not encountered cracking in any unit vessels. If we were to encounter weld cracks, the area inspected would range from a representative sample to 100% of the vessel.
The maximum acceptable weld hardness for carbon steel is 200 Brinell.
Knepper: I do not have an answer on the cracking question. Our biggest problem has been hydrogen blistering.
We have addressed this by using Lukins fineline steel. For weld hardness, we specify a maximum of 200 Brinnell hardness on HF acid service per UOP's piping specifications.
On our recent construction projects, we have stress-relieved all new piping and checked the Brinnell hardness of 5% of the welds before and after heat treatment to achieve the Brinnell hardness specification.
Pazmanyi: After 4 years of operating our equipment we did not find cracks. There are radial-type cracks at the inlet and outlet flange surfaces of our acid circulating pumps, which were repaired by deposit welding. The frequency of welds checking ties between 50 and 100%. We feel that 200 Brinell is acceptable as the upper limit of weld hardness.
Bruce Scott (Bruce Scott Inc.): There are two other things as well as the metallurgy that will have a strong influence on cracking. A little bit of oxygen with HF promotes cracking and corrosion ferociously. There is some evidence that suggests arsenic in the acid will also promote cracking.
Fred Collier (Mapco Petroleum Inc.): During a turnaround of our HF alkylation unit last May, we found some severe cracking in our acid settler. The cracks were found using ultrasonic inspection with 45 and 65 shear waves.
One of the cracks located at a 6-in. nozzle in the vessel head, was 3-in. long and 1 in. deep. Other cracks were found at attachment welds for baffles and trays. All of the cracks were repaired and the entire vessel was stress relieved.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
