NPRA Q&A-2
This article is the second in a three-part series of excerpts from the 1996 NPRA Q&A transcript. It includes information on a variety of catalysts, including hydrotreating, hydrocracking, reforming, and light-ends processing types.
The first article in this series featured discussions of fluid catalytic cracking unit operations (OGJ, Oct. 13, 1997, p. 50). The third will include portions of the transcript dealing with an important support operation-crude desalting.
For more information on the panelists and the format of this meeting, see Part 1 of this series.
Hydroprocessing catalyst quality
How do refiners monitor purchased hydroprocessing catalyst quality?Hunkus: We look at fresh specifications and the regeneration actuals, or, in one case, projected values. In every case, we have seen better-than-projected performance from our purchased catalyst and have come to rely on Criterion Catalyst Co. LP and CRI International Inc. as our partners. We have spot-checked their analysis on occasion and always found them conservative.
We, of course, independently verify platinum content and have spot-checked active metals and, most importantly, called around to people we know in the business. People know if they have received bad catalysts, and good catalyst companies are the ones who stay in business.
There have been no problems with start-of-run temperatures, delta P, or stability. We have found the vendor data to be quite reliable, including the data on presulfided hydrotreating catalysts.
For clarity, I wanted to add that fluid catalytic cracking (FCC) equilibrium catalyst is a separate issue, and much more quality in-house effort is required to properly optimize an FCC fresh/equilibrium additive program. I also wanted to state that my point of view is as an independent refiner who does not have a lot of in-house technical effort to spend in this area.
Kimbrell: We have retained the ability to do catalyst testing in our own pilot plants. Catalysts from commercial production runs are tested in our pilot plants prior to having a catalyst installed in a unit.
When we load it into our operating facilities, we monitor catalyst loading procedures very carefully. We test any regenerated catalyst that is being considered for reuse prior to it being used. Even after we tested the regenerated materials, we would inspect each individual container as it came in.
Lemmon: We believe that only reputable, high-quality catalyst companies have the ability to survive in the competitive catalyst marketplace. We trust in the manufacturer's reputation and do not perform "as received" quality tests.
Smith: Post-delivery quality control that we do is typically visual and quantity checks.
Barker: I concur with Mr. Hunkus and Mr. Lemmon's comments. In the area of regenerated catalysts, we have specifications that have been developed based on experience. We also insist on knowing the previous service of the catalyst, the run length, the type of feed, etc. Only second-cycle material is considered; we do not buy third-cycle material.
DiCamillo: I would like to thank you for saving the best for last on this question. Criterion, and I am sure other major catalyst vendors, have strict internal quality control programs. Our program includes statistical process control monitoring, regular physical and chemical analyses, and activity testing of the catalysts we make. We reject material that falls outside of our manufacturing specifications. We also supply certificates of analyses, upon request, to our customers.
I polled our customers and most of them do not follow up with their own analyses. Some of the things they do are to observe the loading, which would include looking into the drums and making sure it is the catalyst they actually purchased, and they look for excessive dust or something that might give them problems.
Several customers keep retainer samples of the material in case something develops at a future date. We also maintain retainers of the material we ship to customers.
If all else fails, the customer is familiar with how his unit operates. If he starts up a fresh catalyst and the performance seems different than what he is used to, he is usually on the phone quickly.
Ronald E. Marrelli (Phillips Petroleum Co.): I have a question for those on the panel who said they did not test the purchased catalyst. Can you tell me how you evaluate the performance of one catalyst vs. another or different companies?
Lemmon: We have used Pittsburgh Applied Research Laboratory to do our catalyst evaluation pilot-plant work. We also use references from refiners who are using the same catalyst in similar service.
Regulation of spent hydroprocessing catalyst
There are some recent regulatory changes in the U.S. regarding the classification of spent hydroprocessing catalysts. Will refiners still be allowed to utilize landfills, on-site bulk catalyst storage pads, and bulk transportation systems under the new legislation? Will wet dumping techniques continue to be used?DiCamillo: At this time, the proposed changes have been issued but they are not finalized, and that is not expected until some time next year. I will briefly summarize items for each part of this question.
Basically, the regulations say, with some exceptions, all hydrotreating and hydrorefining catalysts would be classified as a hazardous waste. Regarding landfill, catalysts would need to be incinerated and stabilized before landfilling.
Resource Conservation and Recovery Act (RCRA) approved, on-site bulk pads and Department of Transportation (DOT) approved hazardous waste containers would be acceptable. Suitable containers come in a variety of sizes. Spills would also be classified as hazardous, but the size of a spill has not yet been determined. Bulk transportation would be in approved containers only.
There is a question about wet dumping techniques. An exemption for waste water from wet dumping was discussed, but no final proposals have been made at this time.
Barker: The proposed regulation, as we understand it, does not involve any changes to our current procedure. We dump our catalysts under both wet and dry conditions and ship them as an excluded recyclable material to either a metals reclaimer or a primary smelter facility. We do this both in bulk shipments and in drum shipments.
Kooiman: Well, I think Mr. DiCamillo covered most of what I was going to say.
The U.S. Environmental Protection Agency (EPA) has issued a proposed rule that would classify all spent hydrotreating (HT) and hydrorefining (HR) catalysts as RCRA-listed hazardous wastes, regardless of their ignitability, corrosivity, or reactivity test results or Toxicity Characteristic Leaching Procedure characterization.
As such, disposal to landfills would be allowed only after stabilization of the spent catalyst (e.g., pre-reclaim burn of the spent catalyst) to meet Uniform Treatment Standards (UTS), with the most relevant standards to be met being leachable Ni (less than 5.0 mg/l.) and leachable V (less than 0.23 mg/l.). This rule would also require that spent HT or HR catalysts be stored in appropriate and approved containers or on RCRA pads (i.e., RCRA permitted).
Transportation of the spent HT and HR catalysts would be in accordance with DOT regulations for hazardous materials, requiring manifesting and transport by licensed carriers of hazardous waste. It is unlikely that the wet dumping technique could still be utilized unless the dumping pad was RCRA-permitted.
Under the currently proposed rule, spent catalysts released to the ground in an amount exceeding the reportable quantity (currently proposed at 1 lb or 100 lb) would be handled as a spill of hazardous waste and reportable under the Comprehensive Emergency Response and Liability Act.
ROY S. GODWIN (Sadaci (Gulf Chemical & Metallurgical Corp.)): I would like to draw attention to a very informative article on the EPA rulemaking and possible further delays, which appears in the current edition of Catails of Gulf Chemical & Metallurgical Corp.
Mild hydrocracking catalyst
Mild hydrocracking (MHC) has typically been applied to units originally designed for hydrodesulfurization (HDS) service. Conversion levels have been around 20% with very short cycles. Are there any new developments in catalyst and process technology to extend the conversion capabilities of MHC?Gentry: There are new developments in both catalysts and process technologies for extending the conversion level in mild hydrocracking. One approach is incremental improvement through such avenues as improving hydrogen partial pressure or substituting newer, more effective catalysts.
Kellogg's hydrocracking partner, Akzo Nobel, is continuously improving catalysts for both pretreatment and conversion. Even so, the liquid hourly space velocity encountered in a vacuum gas oil HDS unit is normally too high to achieve significantly greater than the 20% conversion mentioned in the question, with run lengths of something on the order of 6-12 months.
In many cases, however, the design pressure hydrogen-compression capabilities in a vacuum gas oil HDS unit are adequate for operation at significantly increased conversion level if incremental catalyst volume is added to the system. When adding reactor volume, it is essential to ensure that there are adequate catalyst beds and excellent flow distribution to optimize catalyst and hydrogen utilization.
In order to maximize reuse of existing compressors and other equipment, additional reactor volume must be added while also minimizing reactor pressure drop. Reactor design technology is therefore an important key to the successful revamp of HDS units to hydrocracking.
The Spider-Vortex quench-zone technology developed and commercialized by Mobil Technology Co. is an example of new technology now available for this application. The Spider-Vortex allows for the design of large-diameter, multibed reactors that can maximize catalyst effectiveness while operating at low pressure drop.
When revamping for significant improvements in conversion, we recommend using a two-catalyst system, optimized independently for pretreating and cracking functions. The best overall activity is obtained by zeolite-based catalysts, particularly if these catalysts have been designed to be nitrogen tolerant. Trimetallic catalyst formulations with nickel, cobalt, and molybdenum as active metals can also provide benefits, in terms of meeting both conversion and very deep desulfurization requirements.
Akzo Nobel has developed a family of catalysts which is optimized to achieve excellent desulfurization and denitrogenation together with high conversion. These catalysts, combined with Mobil's Spider-Vortex reactor design, were used to achieve 45% conversion with 2-year cycles in a Mobil-affiliated vacuum gas oil HDS unit converted to partial-conversion hydrocracking.
The same technology has been used at OMV AG in Austria in a design to convert a vacuum gas oil HDS unit to moderate pressure hydrocracking. Conversion will be increased over 60%, while at the same time run lengths will be doubled.
Arndt: Mild hydrocracking has its merits, but it also has its drawbacks. The synthetic diesel you produce when you are running at these low pressures and high end-of-run temperatures is really crummy. The product diesel will be high in aromatics (probably about a 35 motor cetane when you are running a Middle East VGO).
The total diesel from unit probably will look better than that because, most likely, you have 10-15% diesel material in your feed. If I was looking for more diesel in my refinery, the first thing I would look for is improved distillation in the crude unit.
Baldassari: We agree with the comment that, through the use of zeolitic MHC catalyst, both the run length and the conversion can be extended when converting vacuum gas oil HDS units for mild hydrocracking operations. Conversion levels of around 40% at least 12-month cycle lengths should be possible.
DiCamillo: Mr. Baldassari took the words right off my sheet here. I will add that, based on the success of our SynSat countercurrent-bed technology for distillate hydrotreating, we are also looking at its use in mild hydrocracking.
Regeneration of reforming catalyst
Does any vendor regenerate and rejuvenate semiregenerative reforming catalysts? This would eliminate the in situ regeneration/rejuvenation of these catalysts and thus save unit start-up time and possibly improve catalyst activity by having lower catalyst particle temperatures during regeneration. Also, the critical in situ oxidation/reduction steps could be eliminated, which could remove extensive time and operating errors during this critical catalyst activation step and also reduce corrosion on equipment in the semiregenerative unit.Smith: Commercial regeneration facilities in North America and Europe claim the ability to regenerate and rejuvenate reforming catalyst. Our evaluation of these facilities to determine the actual ability did not proceed due to the poor economics of the venture for our facility.Each of our two fixed-bed reformers undergoes normal regeneration every 9 months and a dump-and-screen regeneration every 2 years. The time-saving benefits of the ex situ regeneration could have only been realized during a dump-and-screen regeneration. The use of ex situ regenerated catalyst would have extended the 6 to 7-day duration of normal regenerations.
Additionally, to be feasible, a complete spare catalyst batch (approximately 150,000 lb for us), including precious metals, would have been required. So the cost of spare catalyst, the shipping costs to and from the regeneration facilities, and the limited-use spare catalyst could not offset the time-saving benefits for the dump-and-screen regenerations. So, in summary, it was not economical for our case.
Hunkus: For many years, vendors have offered ex situ regeneration services for catalytic reforming catalysts, including continuous catalyst regeneration (CCR), semiregenerative catalytic reforming, and other noble-metal-based catalysts.
One vendor also utilizes their density grading technology to remove high-carbon CCR Platformer heel catalyst from the lower-carbon, reusable Platformer catalyst. These services are available on a turnaround or an "at leisure" basis. An Oil & Gas Journal article, published on Sept. 18, 1995, describes the techniques and costs associated with this.
I agree with a lot of Mr. Smith's comments. You may be able to save some time if you just happen to have a spare catalyst load for relatively small incremental cost, which is not very likely. More importantly, you also get to compare your in situ regeneration to a controlled third-party regeneration. This option also allows complete sampling of your catalyst charge for operational adjustment, performance monitoring, and replacement evaluation.
You probably want to dump and screen your catalyst every third regeneration anyway, and a major turnaround is a good time to consider this. You certainly should dump and screen if you see any signs of maldistribution, hot spots, tails, lingering CO2 generations, or other symptoms.
Johnson: UOP is aware of several companies that provide ex situ regeneration of reforming catalyst. We basically agree with the previous comments, but I would like to add that, to our knowledge, the ex situ regeneration only does the carbon burn and screening of the catalyst. The catalyst still requires that the carbon burn be followed by an oxidation/chlorination step and reduction step to properly recondition the catalyst, which would then have to be done in situ.
Kimbrell: I agree with those comments as well. We have considered doing this, and the only time it seems like it might make sense is if we were going to dump in the screened catalyst anyway. But we have not done ex situ regeneration.
Edwin A. Carlisle (Eurecat U.S. Inc.): All of the Eurecat facilities can currently provide carbon removal and screening of the reforming catalyst. The Eurecat S.A. facility in La Voulte, France, can also perform the oxychlorination treatment.
This step is performed in controlled conditions of temperature and partial pressure of oxygen, water, and chlorinating agents to redisperse the platinum phase, just as it is done in continuous catalytic reformers. Eurecat S.A. can also provide the subsequent step of hydrogen reduction.
A batch of spent reforming catalyst has recently been successfully regenerated. The carbon was burned and the oxychlorination step was performed. This catalyst performed well when utilized by the refinery.
Separately, other batches of fresh reforming catalyst have been pre-reduced in the Eurecat equipment. The quality control features monitored include surface area, chloride content, and platinum dispersion (by H2/O2 titration), in addition to the typical physical characteristics.
This off-site treatment offers the benefit of reduced reforming unit down-time, as well as reducing inherent corrosion problems. This processing can be done either on a turnaround basis or in conjunction with a spare-charge replacement. In this last case, one batch can be regenerated to serve as a spare batch for several comparable units to minimize the expense of the catalyst.
Ronald E. Marrelli (Phil lips Petroleum Co.): We have used ex situ regeneration for about the last 15 years, sending the reforming catalyst out to various vendors (Engelhard and Tricat) to have the carbon burned. This has been very successful at our facility. It allows us time to work on our compressors, do work on the reactors, and repair scallops and screens. Our unit is relatively small, with about 40,000 lb of catalyst. We can get it in and out in a week.
Gary A. Stephens (Tricat Inc.): Tricat routinely regenerates semiregenerative reforming catalysts in North America and occasionally regenerates CCR catalyst on both a turnaround and non-time-critical basis. Our regeneration technology ensures a complete carbon burn on each particle.
The configuration of our plant also allows us to regenerate the catalyst fines as well as the catalyst, which provides our customers with additional saving on precious metals recovery costs and ensures very low catalyst losses.
Our plant is not equipped to perform oxychlorination or reduction steps. These steps are performed in situ following catalyst loading.
Lee E. Turpin (Honeywell Hi-Spec Solutions): If the oxidation/chlorination step was to be done externally, it probably would be done at lower pressures, than you would use in an actual operating plant. Could the panel comment on the effect of doing those steps at lower pressure?
Hunkus: Just off the cuff, the only comment I would make is that I think you would have to be more careful that you did not get excessive particle temperatures because you do not have as much mass to carry away the heat generated, and the burn and redistribution would both take longer.
J.B. Roddey (Roddey Engineering Services Inc.): The oxychlorination step is the platinum redistribution step. Like any other chemical reactions, it has a rate and the rate is proportional to the concentration of oxygen. So, as the concentration of oxygen increases, and the pressure would increase that concentration, then the required time to redistribute the platinum decreases. So, yes, the pressure would affect the redistribution of the platinum, though only from a time function.
Angelo P. Furfaro (UOP): Mr. Roddey is correct that the platinum redispersion step is rate-dependent upon oxygen concentration, meaning that the moles per hour are important. This is the case whether oxygen is delivered via higher pressure or higher concentration.
Good dispersion at low pressure but high oxygen concentration is apparent from the fact that UOP has more than 120 CCR Platforming process units in operation utilizing atmospheric regeneration. The technology provides for proper oxychlorination conditions, and thus good platinum redispersion at low-pressure conditions.
In fixed-bed operations, increasing the rate of platinum dispersion is usually accomplished via higher regeneration pressures and/or higher oxygen concentration during the oxychlorination step. Longer time at the refiners standard oxidation conditions can also improve platinum dispersion.
Prior to increasing the oxygen concentration during the oxidation step of the catalyst regeneration, refiners should review the capacity and capability of the recycle gas machines and attendant seal gas systems with their compressor vendor. In addition, refiners with cold-wall reactors should remain conservative with regard to increasing oxygen concentration due to concerns over possible internals damage via combustion of pockets of coke which could exist behind the reactor liner.
Disposal of polymerization catalyst
We have recently lost the only vendor who treated our spent Dimersol catalyst. Does anyone have any suggestions for disposal. If in-house neutralization is done, what is done with the alumina sol, and how is it handled once formed? Any advice from the catalyst companies on handling?Kooiman: We have a polymerization plant at Pine Bend and another one in Corpus Christi. Any sludge that is left in the vessel we will take out during turnaround as hazardous waste. We found there is not a lot of information in the industry on polymerization plants. I would appreciate any contacts in the industry.
Patrick Hoh (HRI Inc.): There is a company in Louisiana that has routinely taken the Dimersol spent catalyst for disposal. If the Dimersol licensee has a wet gas scrubber in the FCC unit, HRI suggests that this spent catalyst can be routed there for disposal.
If Dimersol catalyst is treated by neutralization and filtration steps, the filtrate can be put to the refinery waste effluent stream. The filter cake can either be sent to the landfill or to the hazardous disposal site, depending on local government restrictions.
Penex/Butamer catalyst poisoning
Has anyone experienced catalyst poisoning of Butamer or Penex Units due to CO or CO2? What was the feed source? How was the problem solved?Barker: Our Penex Plus unit experienced carbon monoxide and carbon dioxide poisoning in the feed on initial start-up. The suspected sources are the fuel gas connection to the towers that feed the unit and the unit feed tank itself, which was built with a fuel gas blanket. We replaced the feed gas blanketing with nitrogen and then constructed direct feed lines to the unit and have had no other contamination issues since then.
Davis: Cenex has not experienced CO or CO2 poisoning to the best of its knowledge, but has considered the following: If steam methane reforming hydrogen were used for the Butamer unit, the possibility exists that minute quantities of CO2 could get to the catalyst. We typically use catalytic reformer hydrogen, so this was not a real concern. But, on occasion, we have switched to steam methane reforming hydrogen for a short, say about a 1-week, period of time with no noticeable adverse effect.
Arndt: We have a different experience. We see CO in our CCR hydrogen anywhere from 4 ppm to 10 ppm, and that obviously distresses our isomerization plant. Our current fix is to dilute the CCR hydrogen with manufactured hydrogen, knowing that our methanator in our hydrogen plant is in good condition.
I am not sure how we are going to get out of this box as our methanator ages. I assume UOP is going to help us here.
Johnson: There have been several incidents of CO/ CO2 poisoning. The source of the contaminant can be from cyclic reformers and, as Mr. Arndt mentioned, also CCR Platformers.
We have observed that high water levels in the catalytic reformer will generate a high CO content in the hydrogen. One of the things that we found on a particular unit was that the air dryers for the CCR regenerator were not working properly. When new dryers were installed with proper sieve and proper operating procedures, the moisture in the recycle gas went down, as did the CO content.
As Ms. Barker mentioned, there have also been various contamination scenarios from upstream tankage and fractionation trains, again traced to contaminated gas blanketing systems. One of the things that we have found is the use of natural gas blanketing for upstream units and tanks. The natural gas contains CO2, which will dissolve into the liquid feeds, providing the route for CO2 into the unit.
Kimbrell: I agree. We actually delayed the start-up of our Penex Plus unit this year for that very reason. We found CO2 in the liquid hydrocarbon that we believe got in there from natural-gas-blanketing both the feed surge drum and the feed tank. We found up to 3% CO2 in the natural gas.
We also found CO2 in the wash water for the naphtha hydrotreater that is upstream of that unit, and we found CO and CO2 in our makeup hydrogen. We did change to nitrogen to blanket the surge drum and the feed surge tank, and that eliminated that problem. We changed to a different source of water to get rid of the CO2 problem from the water wash.
One of our hydrogen plants is a pressure swing adsorption (PSA) unit, and we were able to get that tuned to get the CO and CO2 down to recommended levels. The other hydrogen plant had a leak in the methanator feed-effluent exchanger, allowing carbon oxides to sneak by the methanator. So we fixed that, and the problem went away.
We developed and patented a novel solution to this problem that allows some CO and CO2 in the feed without damaging the catalysts.
Richard M. Nash (Shell Oil Products Co.): I agree with Mr. Johnson's comments. In fact, he may have been referring to one of our Butamer units.
We have a cyclic reformer and complete a regeneration about every 24 hr. What we have noted is that the hydrogen produced from the reformer has 40-80 ppm of CO immediately after reactor switch, and that decays over the next 24 hr rapidly, but down to a minimum of 5-10 ppm.
We think the CO is being formed from using the combination of make hydrogen for reduction and having no dryer on the regeneration system. Therefore, we have fairly high moisture.
Right now we do not have a solution. We are living with the problem and the rate at which we are poisoning the Butamer catalyst.
Keith Buercklin (Mara thon Oil Co.): Has anyone experienced oxygenates in their Penex feed, and if so, what kind of problems are you seeing as a result of that and how have you addressed them? What have you done to get rid of the oxygenates?
Arndt: We have seen oxygenates in our Penex feed when we ran off some off test gasoline back to the crude unit. We got out of that box by hydrotreating the Penex feed.
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