Upgrading the Bottom of the Barrel

Transcription

1 104 SPECIAL EDITION Fall 2008 Upgrading the Bottom of the Barrel INSIDE... Feed Contaminants in Hydroprocessing Units Maximizing ULSD Unit Performance New 420DX Catalyst New 585DX Catalyst Inlet Diffuser and Random Packing SmART Catalyst System Series Hydroprocessing Catalysts from The Chevron and Grace Joint Venture

2 Dear Hydroprocessor: This special issue of the Catalagram is devoted solely to you and your operations. Hydroprocessing engineers are continually faced with challenges, such as the rapidly increasing demand for ultra low sulfur diesel worldwide, as well as the requirement for low sulfur FCC feed to meet increasingly stringent government regulations. Advanced Refining Technologies was formed by Chevron USA and Grace Davison to bring the best possible products and technologies to hydroprocessors. Since our inception in 2001, we have continuously developed and manufactured catalysts that upgrade the heaviest feeds, deliver exceptional run length and activity, and produce the cleanest fuels. Why should you make ART part of your bid process? ART is the only catalyst company experienced at minimizing sulfur and heavy metals in the full boiling range of products; More refiners use ART s high performance catalyst systems while processing difficult feed in high pressure residuum fixed-bed and ebullating bed hydroprocessing units than any other catalysts; ART s research and development experience focuses on customizing catalyst solutions to fit feed characteristics, reactor operating parameters, and desired product slate. This includes running pilot plant tests with prospective customers' desired feed to optimize the catalyst system and to gain confidence in commercial performance expectations; ART s distillate catalyst R&D lab and production facility are in the same location, ensuring you that production quality assurance aligns with R&D design parameters. Contact your ART sales representative or me to discuss how ART can optimize your hydroprocessing operation. We stand ready to deliver the performance you demand. Sincerely, Robert H. Bullard Vice President and Managing Director Avanced Refining Technologies

3 In this Special Issue of the CATALAGRAM 104 SPECIAL EDITION Fall 2008 Upgrading the Bottom of the Barrel INSIDE... Hydroprocessing Catalysts from The Chevron and Grace Joint Venture Feed Contaminants in Hydroprocessing Units Maximizing ULSD Unit Performance New 420DX Catalyst New 585DX Catalyst Inlet Diffuser and Random Packing SmART Catalyst System Series CATALAGRAM 104 SPECIAL EDITION Managing Editors: Charles Olsen and Lauren Blanchard Contributors: Gerianne D Angelo Garry E. Jacobs Dave Krenzke Charles Olsen Greg Rosinski Josh Siegel Brian Watkins Please address your comments to betsy.mettee@grace.com Advanced Refining Technologies 7500 Grace Drive Columbia, MD Feed Contaminants in Hydroprocessing Units By Josh Siegel and Charles Olsen, ART Opportunity feeds can help improve profitability, but there can be some consequences. Many of these new feeds may contain unknown levels of common catalyst poisons such as silicon or arsenic. It is important to be aware of the various contaminants to avoid unfortunate surprises like pressure drop build up or unexpected catalyst deactivation which can both result in shortened cycle length on the hydrotreater and unexpected turnarounds. In this article, guidelines are suggested to help minimize the potential impact. Maximizing ULSD Unit Performance when Processing LCO and other Previously Processed Feeds By Brian Watkins, ART ULSD has evolved from simply meeting the diesel sulfur specification to a constant awareness of unit performance in order to process difficult streams such as FCC light cycle oil (LCO) and other thermally cracked stocks; synthetic crudes; and various other pre-processed feed sources. It is important to understand the impact of processing new feed streams, and this paper highlights a few examples demonstrating significant differences in feed reactivity, which are not necessarily anticipated from the usual bulk feed analyses. 420DX: A New High Activity CoMo Catalyst for ULSD by ART By Brian Watkins and Charles Olsen, ART ART recently announced the commercialization of its newest DX TM Platform Catalyst, 420DX. 420DX catalyst will enable refiners to enhance their ULSD operation with either increased cycle length or additional use of opportunity feedstocks in order to maximize margin. Commercial samples of 420DX have been sent to several major oil companies with positive feedback that 420DX is a top tier pro capable of exceeding refiners needs in demanding ULSD applications. Improving FCC Feed Quality with ART s Newest FCC Pretreat Catalyst, 585DX By Brian Watkins, ART ART s newest generation of ultra high activity NiMo catalyst, 585DX offers refiners a significant boost in its ability to generate low sulfur FCC products as well as deliver benefits of nitrogen removal and poly aromatic saturation. Combining New and Old Technologies Inlet Diffuser and Random Packing Dramatically Improve Reactor Performance By Garry E. Jacobs, Fluor Enterprises, Inc. and Gerianne D Angelo, ART This paper, delivered at the 2008 NPRA Annual Meeting, presents the case history of a kerosene hydrotreater that failed to meet product sulfur targets, subsequent to a catalyst changeout. ART Excels In ULSD Service: Update on Sulfur minimization By ART By Greg Rosinski, Dave Krenzke, and Charles Olsen, ART ULSD production with the first SmART Catalyst System Series began early in 2004 at a North American refinery processing a feed containing 40% of a high endpoint LCO. Since that time DX Platform Catalysts have been selected for over 35 ULSD applications as either stand-alone catalysts or as components in SmART System. The technology has been a great success since its introduction with millions of pounds installed in commercial units around the world W. R. Grace & Co.-Conn. The information presented herein is derived from our testing and experience. It is offered, free of charge, for your consideration, investigation and verification. Since operating conditions vary significantly, and since they are not under our control, we disclaim any and all warranties on the results which might be obtained from the use of our products. You should make no assumption that all safety or environmental protection measures are indicated or that other measures may not be required.

4 Feed Contaminants in Hydroprocessing Units Josh Siegel Technical Services Engineer Charles Olsen Worldwide Technical Services Manager ADVANCED REFINING TECHNOLOGIES Chicago, IL USA Introduction R efiners are facing many challenges from new regulations on sulfur levels in gasoline and diesel fuel, the rising cost of crude and other raw materials, and directives to decrease the cost of production. In an effort to lower these costs, refineries often find opportunities to purchase lower cost crudes or purchase other feedstocks such as LCO. While these opportunity feeds can help improve profitability, there can be some consequences. Many of these new feeds coming into the refinery may contain unknown levels of common catalyst poisons such as silicon or arsenic. It is important to be aware of the various contaminants to avoid unfortunate surprises like pressure drop build up or unexpected catalyst deactivation which can both result in shortened cycle length on the hydrotreater and unexpected turnarounds. In this article, several of the more common feed contaminants that may be present in hydrotreater feeds are reviewed. In some cases guard catalysts can be employed to help mitigate some of the problems caused by catalyst poisons and in other cases, guidelines are suggested to help minimize the potential impact. 2

5 Silicon Silicon (Si) is probably the most widespread catalyst poison encountered in distillate hydrotreater feeds. The common source of silicon is from a delayed coker operation which uses an anti-foam agent based on polydimethylsiloxane to suppress foaming in the coker drums. The siloxane complex breaks down in the coking process to lighter molecular weight fragments consisting of modified silica gels. These remnants end up primarily in the naphtha range, although small quantities have also been found in the kerosene and diesel fractions. As a result, silicon contamination is a major concern in units treating coker naphtha. In these units, the rate of silicon deposition on the catalyst is usually what determines run length rather than coke deactivation. In extreme cases of contamination, cycle lengths can be as short as three to six months. Under hydrotreating conditions, the silica fragments present in the feed undergo a condensation reaction with the alumina forming a strong chemical bond as depicted in Figure 1. Thus, once the silicon is bound to the surface it cannot be removed and is considered a permanent poison. The modified gels are associated with the alumina support as opposed to the active metal sulfides, and are dispersed throughout the alumina surface of the catalyst. As the silicon builds up on the catalyst it begins to restrict the catalyst pores and eventually blocks access to the active sites. This phenomenon is referred to as pore mouth plugging. Silicon is one of the contaminants which can be trapped by using specially designed catalysts. ART introduced the StART Catalyst System for just this purpose. This technology combines a state of the art silica guard material, AT724G catalyst along with the active HDS and HDN CH 3 [ O Si] n O Pounds of silicon / ft3 of catalyst Cycle Length, months O H H Figure 1 O H H CH 3 [ O Si] n O CH3 [ O Si] n O Al 2 O 3 Al 2 O 3 Al 2 O Figure 2 Same Canister Silicon Capacities Competitor or A Competitor or C AT724G AT535 Figure 3 StART TM Catalyst System Offers Longer Cycles Cycle 1 Cycle 2 StART TM Catalyst System O H 2 ART Catalagram 104 Special Edition Fall

6 catalyst AT535. The AT724G is a high surface area guard catalyst designed for maximum silicon capacity. Figure 2 compares the Si capacity of AT724G and AT535 with some competitor catalysts. AT535 by itself has essentially the same Si capacity as these materials, while AT724G has over 30% higher Si capacity. Figure 3 shows a commercial example of the how the StART TM Catalyst System can increase the cycle length over competitive silicon trapping materials. In this case, ART s custom designed system more than doubled the cycle length over the previous cycles with catalyst from competitor A. Another important aspect to be aware of with silicon poisoning is that the deposition of the modified silica gels on the alumina surface is a catalytic reaction and the ultimate quantity of silicon pick up depends on reactor temperature. The temperature dependence of silicon pick up for AT724G is shown in Figure 4. A catalyst in a guard reactor which is limited to low temperatures will pick up much less silicon than the same catalyst in a main reactor operating at higher temperature. 4 Silicon capacity, lbs Si/ft 3 catalyst Temperature, F Arsenic Figure 4 Temperature Dependence of Silicon Capacity Arsenic (As) is found in many crudes including some from West Africa and Russia as well as many synthetic crudes. It is frequently becoming a common contaminant as use of these crudes, especially synthetic crudes from Canada, has increased in recent years. The Arsenic is believed to bind with the metal sulfide sites, and in particular the active nickel on the catalyst forming nickel arsenide. This has a dramatic impact on catalyst activity. To demonstrate the impact of arsenic on catalyst activity, ART obtained a series of catalysts containing different levels of arsenic. These samples were carefully regenerated in the laboratory, and were then activity tested using a diesel feed containing 50% cracked stocks under conditions producing <500 ppm sulfur. Figure 5 summarizes the results of that work. At 1000 ppm arsenic the catalyst shows 5 F HDS activity loss and nearly 15 F loss in HDN activity. The activity loss quickly increases to over 50 F at 1 wt.% arsenic on the catalyst. Degrees Activity Loss, F Canister data for a variety of ART catalysts indicates that catalysts containing nickel are more effective for trapping arsenic. Figure 6 summarizes the arsenic pick up values for several ART NiMo catalysts. As this data shows, both AT535 and AT575 are quite effective for trapping arsenic. Note that the difference between canisters 1 and 2 are the level of arsenic in the feed (canister 2 was in a unit processing >80% coker naphtha) and the temperature of the reactor containing the canister. The difference between canisters indicates that like silicon pick up, the ultimate arsenic pick up is strongly dependent on temperature. Figure 7 shows the As pick up as a function of temperature for an ART NiMo catalyst. These results were obtained by analyzing spent samples of the catalyst from a three reactor unit processing 100% cracked naphtha from a synthetic crude source. The first reactor was operated at very low temperature (~275 F) in order to saturate diolefins. The second reactor was designed to saturate mono-olefins and operated at about 430 F. The last reactor had an inlet of 570 F and an outlet temperature of approximately 650 F. The arsenic content on the catalyst correlated with the temperature of the reactor as depicted in the figure. The data demonstrate that a high nickel cata- Figure 5 Effect of Arsenic on Catalyst Activity HDS 10 HDN wt.% Arsenic on Catalyst (Carbon free basis)

7 Pounds of arsenic / ft 3 of catalyst lbs As/ft 3 of Catalyst Figure 6 Arsenic Pick-Up in Basket Testing Canister 1 Gulf Coast Unit processing 30% coker naphtha from another crude source. Canister 2 Unit processing >80% coker naphtha from Canadian synthetic crude. GSK-6A AT724G AT535 AT575 AT724G AT535 Figure 7 Temperature Dependence of Arsenic Capacity Temperature, F lyst can pick up very high arsenic levels if the operating temperature and feed concentration are high enough. Sodium and Calcium Sodium (Na) is a severe catalyst poison that can cause significant activity loss even at low levels. It works by promoting the sintering of catalytic metals and neutralizing acid sites. Typical sources of sodium include a malfunctioning desalter, sea water contamination or caustic contamination. Depending on the source of sodium, the signs of poisoning include rapid activity loss and an increase in pressure drop. Figure 8 shows the effects of sodium poisoning on catalyst activity. The figure indicates that for a sodium content of 0.5 wt.% the activity is at most 60% of fresh catalyst activity. This translates to roughly 30 F loss in activity for 1 wt.% sodium on the catalyst. Calcium (Ca) is a similar poison to sodium and is found in some West African crudes. There is some evidence that it is an even stronger poison with roughly 1 wt.% calcium resulting in 50 F or more activity loss. It is therefore critical to keep these out of the hydrotreater feed with a suggested maximum of 0.5 ppm of either sodium and calcium. Phosphorous Relative Activity, % Figure 8 Impact of Sodium Contamination on Activity wt.% Sodium on Catalyst Phosphorous (P) contamination in oil has been traced to fractionation fluids that are often used in crudes from the Western Canadian Sedimentary Basin. The source is diphosphate esters which are soluble in the crude oil. Refineries that run large percentages of light Western Canadian crude have reported crude column and crude furnace fouling for many years. Improvements made to crude columns to minimize fouling have transitioned the depositing of phosphorous to the downstream hydrotreaters. ART Catalagram 104 Special Edition Fall

8 6 Other sources of phosphorous include gasoline slop tanks, imported feeds and lube oil wastes. If phosphorous does manage to make its way into the hydrotreater, it will poison the active sites of the catalyst causing a loss in activity. A level of 1 wt.% of phosphorous on the catalyst results in roughly 10 F loss in activity. ART recommends that a feed content of < 0.5 wppm be maintained whenever possible, as well as the use of feed filters to assist in trapping of phosphorous sediment. A case study of the detrimental impacts of feed poisons on hydrotreater performance involved a ULSD unit which had recently started up with ART catalysts. Shortly after start up the unit began to experience extremely rapid catalyst deactivation. It was so severe that within a few months the unit required an unplanned turnaround and fresh catalyst was installed. Samples of spent catalyst were collected representing catalyst throughout the bed, and these were analyzed in the laboratory. The results are summarized in Table I. It is apparent from these results that the catalysts were exposed to high levels of several poisons including arsenic, sodium, phosphorous and iron. The contaminants penetrated well into the catalyst bed. Catalyst at the bottom of the reactor was not yet poisoned, but the coke content was extremely high for catalyst which had been onstream such a short time. The level of contaminants indicates the catalyst in the top half of the bed had lost over 60 F of activity, while the bottom was providing most of the HDS conversion. This required very high temperatures, which is reflected in the high carbon content for the catalyst at the bottom of the bed. Iron Iron (Fe) works its way into hydrotreater feed as rust and iron scale from corrosion of upstream equipment and piping, as well as from unfiltered particulates present in the feed. Iron naphthenates can form from corrosion due to naphthenic acid in the feed, and the iron readily precipitates out in the presence of heat and H 2 S. These iron particulates fill the interstitial spaces in the catalyst bed which will result in a higher than expected pressure drop. To help mitigate the pressure drop associated with iron, ART uses a series of grading materials (GSK-19, GSK-9, GSK- 6A and GSK-3A) which have high void space to accumulate and store these particulates. GSK-9 is also an iron trapping material which has high internal void space for trapping soluble iron inside its large pore network. These measures are helpful for delaying pressure drop buildup, but they do not prevent or eliminate it. Effective feed filtration to remove particulates (at least 25 microns) in combination with high void grading provides a longer lasting way in helping mitigate pressure drop buildup from these sources. Nickel and Vanadium Nickel (Ni) and Vanadium (V) contamination have been found in resids and the heavier fractions of vacuum gas oils. They are a more significant problem in FCC pretreat units and other applications processing heavier feeds, and not often encountered in diesel or other light feeds. The deactivation mechanism of these poisons is pore mouth plugging. Nickel and Table I Spent Catalyst Analysis vanadium are usually contained in large porphoryin molecules which are too big to penetrate into the pores of typical hydrotreating catalysts. Therefore, the nickel and vanadium end up depositing on the outside of the catalyst ultimately blocking access to the active sites within the pores. Pilot plant testing with heavy feeds by ART on a widely used FCC pretreat catalyst, AT575, indicates that a 1 wt.% Ni+V on the catalyst results in 5-9 F loss in activity. AT575 is a catalyst designed for treating heavy feeds, so the activity loss will be greater for a smaller pore (relative to AT575) catalyst. Nickel and vanadium are treated by using specially designed catalysts for removing metals. These catalysts have pore size distributions which are tailored to provide very high capacities for nickel and vanadium. ART has vast experience with treating resid and resid containing feeds, and offers a wide array of ICR and HOP series catalysts with differing metals capacities and HDS activities. Using these in conjunction with ART AT or DX TM Catalyst Platform are an effective way of dealing with nickel and vanadium in cases where they are known to be present. As, wt.% Fe, wt.% Na, wt.% P, wt.% C, wt.% GSK GSK GSK- 6A Top Middle Bottom

9 Maximizing ULSD Unit Performance when Processing LCO and Other Previously Processed Feeds Brian Watkins Supervisor, Hydrotreating Laboratory Services ADVANCED REFINING TECHNOLOGIES Chicago, IL USA W ith demands for increased production of ultra-low sulfur diesel (ULSD) and the rise in crude prices, unit operation and performance have become significantly more challenging. This has prompted refiners to look for ways to maximize their diesel pool by using opportunity feedstocks. However, use of these feedstocks may lead to other problems which impact unit performance. ULSD has evolved from simply meeting the diesel sulfur specification to a constant awareness of unit performance in order to process difficult streams such as FCC light cycle oil (LCO) and other thermally cracked stocks; synthetic crudes; and various other pre-processed feed sources. It is important to understand the impact of processing new feed streams, and this paper highlights a few examples demonstrating significant differences in feed reactivity, which are not necessarily anticipated from the usual bulk feed analyses. Background It has been documented for some time that desulfurization of dibenzothiophene and substituted dibenzothiophenes occurs through two reaction pathways: the direct sulfur abstraction route and the hydrogenation abstraction route. The former involves adsorption of the molecule on the catalyst surface via the sulfur atom followed by C-S bond scission. This path is favored when using cobalt-molybdenum (CoMo) based hydrotreating catalysts. The second pathway involves saturation of one aromatic ring of the diben- ART Catalagram 104 Special Edition Fall

10 Type API Sulfur, wt.% Nitrogen, ppm Aromatics, lv.% Mono-, lv.% Poly-, lv.% Dist., D86, F IBP 10% 50% 70% 90% FBP zothiophene species followed by the extraction of the sulfur atom. Nickel-molybdenum (NiMo) catalysts have a higher selectivity for desulfurization via this route. It is efficient to model ULSD kinetic schemes by grouping the various sulfur species into easy sulfur and hard sulfur categories. The socalled easy sulfur is made up of compounds which are readily desulfurized via direct abstraction and boil below about 680 F, while hard sulfur is made up of compounds which are more readily removed via hydrogenation followed by abstraction. These compounds include 4,6 dimethyl-dibenzothiophene and other di- and tri- substituted dibenzothiophenes. The relative amounts of easy and hard sulfur in a feed are critical properties to consider since the concentration of each can vary significantly from feed to feed depending on crude source, boiling range and the prior thermal or catalytic treatment of the feedstock. Further details can be found in the 2007 ERTC paper by ART entitled SmART Strategies for Maximizing ULSD Unit Performance: Tuning Hydrogen Utilization for Flexibility with Cracked Stocks. The use of thermal or catalytic treatment of feedstocks that will be sent Table I Base Feed Properties SR LCO Ebullating Bed Diesel Fixed Bed Diesel to a ULSD unit can have varying effects depending on the severity of the pre-treatment. LCO and coker diesels have long been common elements combined with a straight run (SR) feed source to produce ULSD products. LCO generated from an FCC can vary depending on the severity of the pre-treatment of the FCC feed. However, the common element is the increase in polynuclear aromatic compounds relative to other Bezothiophene SR Fixed Bed LCO Ebullating Bed feeds. The amount of LCO blended into the diesel hydrotreater has a much greater effect on catalyst performance when producing ULSD than when operating under prior, less restrictive, low-sulfur regulations. Use of diesel range products from ebullating bed resid or fixed bed resid desulfurizers can also have a significant impact on catalyst activity if not clearly identified as to their origin. The general properties of diesel streams from these units often indicate that they may be fairly easy to hydrotreat due to their unusually low sulfur content. Table I lists the general properties for examples of each of the base feeds used in pilot testing at ART. Note that Ebullating Bed Diesel represents a diesel fraction from the product of an LC-FINER or H-Oil Unit, and Fixed Bed Diesel is the diesel fraction coming from a Fixed Bed Resid Unit. The diesel product from an Ebullating Bed Resid (EB) Unit and the Fixed Bed Resid (FB) Unit provide very different sulfur distribution patterns compared to the other feeds in Figure 1. It is clear that although the total sulfur is much Figure 1 Sulfur Distribution in the Four Feedstocks C1-BT C2-BT C3-BT C4+ BT Dibenzothiophene C1-DBT C2-DMDBT 4,6-DMDBT C3+DBT

11 lower for the two resid diesel materials, a majority of the sulfur species that are present are all the so-called hard sulfur species. To help explain how the HDS activity changes with product sulfur for these feeds, pilot work was completed using 100% SR diesel as the base feed. The individual components were blended into the base feed to show the individual, as well as some cumulative effects on catalyst performance. Two different concentrations (15% and 30% by volume) of LCO were used. The blends containing LCO produced a five to seven number decrease in API, as well as decreases in total sulfur of 2500 to 2700 ppm, respectively. Feed nitrogen content, however, increases by 150 to 250 ppm, and the total aromatic content in each of the blends increases 10 to 18 volume percent. The resid diesel streams were blended into the SR at a 25% by volume concentration. This gave a similar 1.5 to 2 number decrease in API for each of the FB and EB diesel streams, with a significant increase in total nitrogen of 120 to 220 ppm, respectively. Feed aromatic content showed a three to four number increase in mono-aromatics. Required Temperature Increase, F Required Temperature increase, F Figure 2 Comparison of EB and FB Diesel Blends in ULSD Application Product Sulfur, ppm At low severity hydrotreating (higher product sulfur), there is little difference between the straight run and the blended resid diesel streams. Figure 2 is a plot of the EB and FB diesel blends at different levels of sulfur removal. The impact of adding EB diesel is little more than 4 F higher temperature relative to the SR, while the FB diesel required just over 10 F for low sulfur products. As the product sulfur is decreased the required temperatures start to diverge: 17 F higher temperature is required for the Figure 3 Addition of LCO on ULSD Performance Product Sulfur, ppm SR 15% LCO 30% LCO SR 25% EB Diesel 25% FB Diesel EB diesel blend feed at 200 ppm sulfur and 22 F for the FB diesel. Clearly, there is a different temperature response for each feed which is most likely an indication that although the total sulfur is lower, the additional nitrogen from the EB unit is hindering the catalytic ability to saturate the more difficult sulfur compounds required to produce ULSD. The FB diesel feed also has an impact, due to the fact that it contains additional refractory sulfur which is harder to remove. As product sulfur continues to trend toward ULSD, the difference increases to over 35 F. A comparison of the feedstock inspections shown in Table I shows that the two feeds are similar with no obvious explanation for a 30 F increase in required temperature relative to the base feed to achieve ULSD sulfur levels. This underscores the importance of the source (or history) of a feedstock, and how significant this can be on unit performance. Figure 3 summarizes data using the 15% and 30% LCO feeds. The impact of even a small amount of LCO is again readily apparent. Initially about 20 F higher temperature is required compared to the SR feed for 15% LCO, and 40 F higher ART Catalagram 104 Special Edition Fall

12 Figure 4 Cumulative Addition of LCO for HDS LCO by itself. This impact can be seen through the entire range of operation as shown in Figure 4. temperature is required at the 30% LCO level as compared to the base feed at 500 ppm product sulfur. Although not obvious from the chart, there are also small differences in the temperature response between the SR and LCO containing feeds. Using 15% LCO there is a 20 F loss in HDS activity at 500 ppm sulfur which increases to 50 F at 200 ppm sulfur and to over 90 F for ULSD. With a 30% LCO blend, the activity differences are much greater: 37 F at 500 ppm sulfur increasing to 70 F at 200 ppm sulfur and over 115 F for ULSD. As mentioned above, this is an indication that as LCO is added to the feed, the concentration of refractory, sterically hindered sulfur compounds increases making it more difficult to desulfurize. The presence of more refractory compounds decreases the temperature response relative to the base SR feed. That means that a much larger temperature increase is required for the LCO feed to achieve the same sulfur removal as the base feed. 10 Required Temperature increase, F The effects of combining the various diesel sources are not necessarily a cumulative effect on catalyst performance. The effect of adding 15% LCO into a feedstock that Product Sulfur, ppm already contains 25% FB diesel has only an additional 10 F impact compared to the 20 F increase in required temperature discussed above. The use of 30% LCO blended into the 25% FB feed has an impact of 28 F increase in required temperature which is almost 10 F lower than 30% Type SR 25% FB Diesel 15% LCO & 25% FB 30% LCO & 25% FB API Sulfur, wt.% Nitrogen, ppm Aromatics, lv.% Mono-, lv.% Poly-, lv.% Dist., D86, F IBP 10% 50% 70% 90% FBP LCO (Low FBP) One possible option to gain back some of the lost activity is to change the end point of the feed to be used. ART was able to conduct duplicate pilot plant testing on this same LCO, but with a 30 F end point reduction to simulate affect on catalyst performance. Table II lists the major component analysis between the two LCO feed sources. The decrease in endpoint lowers the total sulfur by almost 1000 ppm, where total nitrogen decreases by 129 ppm. The impact this reduction has on ULSD performance is over 30 F in restored catalyst activity which corresponds to additional life in the hydrotreater. A comparison of the two LCO feeds blended at 30% into the SR base feed is shown in Figure 5. The addition of LCO has a major impact on activity for both the low and high endpoint materials. The required temperature increase for ULSD in going from 0 to 30% LCO Table II Comparison of Boiling Point Reduction on LCO LCO (High FBP)

13 Figure 5 Impact on FBP Reduction on Hydrotreating Performance Required Temperature increase, F Degrees F / % LCO Product Sulfur, ppm SR 30% Hi FBP LCO 30% Lo FBP LCO Figure 6 Activity Comparisons at Different LCO FBP and Concentration Low FBP LCO High FBP LCO for the lower endpoint material is about 1.2 F per percent LCO. Processing the higher endpoint LCO increases the required temperature to about 1.4 F per percent LCO. Notice from the chart that the activity effects are not linear with increasing LCO content. The first 15% LCO has a larger impact on activity than the next 15%. Figure 6 demonstrates this more clearly in the form of a plot of activity lost as a function of LCO content. It clearly shows much higher activity losses for the first few percent LCO as compared to the last few percent added to the feed. ADVANCED REFINING TECH- NOLOGIES can work closely with refining technical staff to help plan for processing opportunity feeds such as those discussed above. One of the keys is being aware of the potential impact processing certain feeds will have on unit performance. Feeds which have been previously processed present unique challenges and ART is well positioned to provide assistance on how best to maximize unit performance and take advantage of these opportunity feedstocks Percent LCO ART Catalagram 104 Special Edition Fall

14 420DX: A New High Activity CoMo Catalyst for ULSD by ART Brian Watkins Supervisor, Hydrotreating Laboratory Services Charles Olsen Worldwide Technical Services Manager ADVANCED REFINING TECHNOLOGIES Chicago, IL USA A RT introduced its line of ultra high activity DX TM Catalyst Platform in response to refiner s demands for superior technology that delivers premium performance. This family of catalysts has exceeded expectations with its performance in demanding ULSD applications processing difficult feed blends. One of the keys to the ultra high activity observed with these catalysts is maximizing the utilization of active metals on the catalyst through ART s chelate chemistry. This impregnation technology significantly improves metals utilization by allowing ART to manipulate the active metal components on the catalyst. It has been shown that when applied correctly chelates promote and enhance the formation of Type II metal sulfide sites (see Catalagram 96, 2004). ART CDXi and NDXi catalysts have demonstrated the benefits of this technology in ULSD units around the world both as stand alone catalysts and as part of a SmART Catalyst System Series. Building on this great success, ART s dedicated research and development staff has recently announced the commercialization of its newest DX TM Catalyst Platform, 420DX. Figure 1 compares the activity of several generations of ART cobaltmolybdenum (CoMo) catalysts. The figure shows that 420DX offers 30% improvement in both HDS and HDN activity over CDXi catalyst. 12

15 Normalized Intensity RVA, % Figure 1 ART s High Performance Catalysts AT405 CDXi 420DX HDS HDN Figure 2 IR Spectra of the 420DX Support Lewis Acid sites Wave numbers (cm-1) Figure 3 Molybdenum XPS Spectra for Non-Chelated Catalyst Mo Spectra Researchers at ART have identified surface acidity as a key property for improved catalytic performance. It is generally accepted that there is a strong relationship between the role of increased surface acidity and improved reaction rate for reactions controlled through ring saturation such as nitrogen and hard sulfur removal. Changes in surface acidity have also been shown to affect the interaction of active metals with the alumina surface during impregnation. ART is able to exploit this phenomenon in the design of 420DX. This catalyst utilizes similar impregnation technology as CDXi where a chelate is used to bind to the cobalt ions in the impregnation solution and reduce interactions with the alumina support. The chelate/ion complex stays intact on the catalyst which allows the molybdenum to sulfide at lower temperature promoting the formation of Type II active sites. With 420DX, this technology is enhanced through the use of a modified alumina carrier with improved surface acidity. This is demonstrated in Figure 2, which shows a pyridine infrared (IR) spectrum of the new support. The spectrum has a doublet at 1624 and 1616 wave numbers, as well as an absorption peak at 1452, which are thought to indicate the presence of Lewis acid sites. This confirms the incorporation of surface acidity in the new support. While the acid sites give 420DX better performance for both HDS and HDN activity, they are not strong enough to initiate any cracking reactions under typical hydrotreating conditions. Normalized intensity Sulfided at 755 F Sulfided at 575 F Sulfided at 260 F Fresh X-Ray Photoelectron Spectroscopy (XPS) was also used to help better understand the surface chemistry of 420DX. Figures 3 and 4 summarize some of these results. Figure 3 shows XPS spectra taken on a conventional (non-chelated) catalyst which has been sulfided at various temperatures. The spectra cover the binding energies for the expected Mo states with the MoS 2 state highlighted by the dotted red line at about 229 ev. The fresh catalyst ART Catalagram 104 Special Edition Fall

16 shows the presence of MoO 3 as expected. It is not until sulfiding 575 F that the MoS 2 peak becomes apparent. Figure 4 summarizes similar XPS spectra for a chelated catalysts like CDXi or 420DX. Notice in this case that the MoS 2 peak begins to appear at a sulfiding temperature of 260 F. This indicates that the presence of the chelate promotes sulfidation of the Mo at lower temperature compared to the non-chelated catalyst. Sulfiding the Mo at lower temperature results in a more fully sulfided Mo structure which promotes the stacking of the MoS 2 into Type II active sites. This explains much of the improved activity demonstrated by the DX TM Catalyst Platform. To understand the improved activity of 420DX, one has to look at the Co species as a function of sulfiding temperature with XPS. Figure 5 summarizes these data for CDXi. The XPS spectra now show the binding energies characteristic of cobalt oxide ( ev) and cobalt sulfide ( ev). The binding energy for cobalt sulfide is highlighted in blue in the figure. The fresh catalyst shows the characteristic peak for cobalt oxide as expected. The cobalt sulfide peak becomes prominent for sulfiding at 575 F, but notice how broad the peak is for high temperature sulfiding. The wide peak indicates there are several states of cobalt present. Figure 6 shows similar spectra for 420DX. Notice the much sharper peak for high temperature sulfiding for the cobalt sulfide species compared to the spectra for CDXi. This indicates that 420DX has a greater concentration of the active cobalt sulfide species which translates to higher activity. ART has completed pilot plant testing over a variety of conditions to demonstrate the performance advantage of 420DX. Figure 7 shows the results of side-by-side testing of CDXi and 420DX at 980 psi hydrogen partial pressure and 2500 SCFB H 2 /Oil ratio. At these Normalized Intensity Normalized Intensity Normalized intensity Figure 4 Molybdenum XPS Spectra for Chelated Catalyst Sulfided at 755 F Sulfided at 575 F Sulfided at 260 F Fresh Co Spectra Sulfided at 755 F Sulfided at 575 F Sulfided at 396 F Sulfided at 260 F Fresh Mo Spectra Binding energy (ev) Figure 5 Cobalt XPS Spectra of CDXi Mo sulfide appears at 260 F for chelated catalyst Co Spectra Sulfided at 755 F Sulfided at 575 F Sulfided at 396 F Sulfided at 260 F Fresh Binding energy (ev) Figure 6 Cobalt XPS Spectra of 420DX Binding energy (ev) 14

17 conditions, 420DX clearly outperforms CDXi by over 20 F at 10 ppm sulfur on a difficult feed containing 30% cracked stocks. One of the additional benefits of 420DX is that the improved HDS and HDN activity has a minimal impact on increased aromatic saturation overall, and consequently does not increase hydrogen consumption to a measurable extent. This offers refiners greater flexibility in meeting their HDS activity requirements while minimizing hydrogen consumption using 420DX as a stand-alone catalyst or in combination with ART s premium NDXi catalyst in a SmART System for producing ULSD from difficult feeds. Additional pilot plant work was completed to look at the advantages of 420DX for moderate and high pressure applications using a SR feedstock. Figure 8 shows the expected SOR activity for seven ppm sulfur of 420DX and CDX. Note that again at higher pressure, 420DX shows a greater than 20 F improvement over CDXi. At moderate pressure the activity difference is still greater than 10 F. 420DX will enable refiners to enhance their ULSD operation with either increased cycle length or additional use of opportunity feedstocks in order to maximize margin. Commercial samples of 420DX have been sent to several major oil companies with positive feedback that 420DX catalyst is a top tier product capable of exceeding refiners needs in demanding ULSD applications. WABT, F (10ppm sulfur, 1ppm nitrogen) Figure 7 Comparison of CDXi and 420DX at High Pressure psia 1026 psia HDS CDXi 420DX Catalyst HDN Figure 8 ULSD Comparison of CDXi and 420DX CDXi 420DX Catalyst ART Catalagram 104 Special Edition Fall

18 Improving FCC Feed Quality with ART s Newest FCC Pretreat Catalyst, 585DX Brian Watkins Supervisor, Hydrotreating Laboratory Services ADVANCED REFINING TECHNOLOGIES Chicago, IL USA A s clean fuels regulations become more challenging, ART s line of ultra high activity FCC pretreat catalysts continues to evolve. Providing refiners with superior technology and first-class performance, ART s AT575 catalyst has long proven its performance advantage with outstanding stability and exceptional ability to provide refiners with consistent, high quality feed for their FCC units. In keeping with this tradition, ART is introducing its newest generation of ultra high activity NiMo catalyst, 585DX. Figure 1 compares the activity of several FCC pretreat catalysts supplied by ART. This newest member to the FCC pretreat family is capable of significantly reducing required Start of Run (SOR) temperatures for both hydrodesulfurization (HDS) and hydrodenitro (HDN) response. 585DX offers refiners a significant boost in its ability to generate low sulfur FCC products, as well as deliver the benefits of nitrogen removal and poly aromatic saturation. The enhanced ability for HDS and HDN allow for use of this product in a wide range of operation. The results from side-by-side testing of 16

19 Relative Volume Activity, % Relative Volume Activity, % WABT, F (500ppm sulfur & nitrogen) Figure 1 ART s Line of FCC Pretreat Catalysts AT575 AT775 AT DX HDS HDS AT575 HDN Figure 2 Comparison of AT575 and 585DX in Low Pressure FCC Pretreat HDS AT575/AT DX 585DX/AT792 HDN Figure 3 Comparison of AT575 and 585DX in Two ApART TM Catalyst Systems for FCC Pretreat HDN AT575 and 585DX show 585DX clearly outperforming AT575 by over 130% at 1400 psi H 2 pressure for both HDS and HDN. In refining applications that have lower unit pressures, 585DX pilot plant work has shown that the advantage is still in excess of 115% as compared to AT575 for HDN while maintaining a 110% RVA improvement for HDS as shown in Figure 2. Additional performance gains are also available to refiners by utilizing ART s ApART TM Catalyst System. Coupling the improved HDS activity of AT792, a trimetallic (NiCoMo) FCC pretreat catalyst, with the improved HDN activity of 585DX, allows refiners to produce low sulfur and nitrogen FCC feeds at significantly lower SOR temperatures. Figure 3 shows the advantage of using this system over a previous system of AT575 and AT775. This pilot work used a feedstock containing cracked material and 3000 ppm nitrogen. This work was done for a refiner at 1600 psia hydrogen pressure. From this testing, the 585DX and AT792 ApART system provided over a 15 F lower start of run temperature. An additional benefit of 585DX is the improved aromatic saturation activity. 585DX shows an increased saturation of multi ring compounds with a 7% increase in conversion of 4+ ring compounds. This increased saturation allows for improved feed quality and increased yields from the FCC operation. The pilot plant work shown in Figure 4 used a feedstock with 2.3 wt.% sulfur and 1900 ppm nitrogen. Using ART 585DX as a stand alone catalyst or in combination with ART AT792 provides many alternatives for producing quality FCC feedstock. 585DX is a nickel-molybdenum (NiMo) catalyst that has outstanding HDS activity coupled with extremely high HDN and HDA activities. This catalyst provides superior HDN and HDA to augment refiners need for better FCC feed conversion as well as reduced sulfur providing support in producing lower sulfur gasoline. ART Catalagram 104 Special Edition Fall

20 Figure 4 Comparison of AT575 and 585DX for PNA Saturation % Conversion rings+ 3 rings+ 4 rings+ AT DX Meet the ART Group Introducing a few of ART s world-class team members: Scott Purnell, is General Manager, with daily responsibilities for the ART business unit. Scott joined Grace in 1993 and held various technical, marketing, sales and management positions in Grace s FCC business. Scott has a B.S.Ch.E. from Penn State and a Ph. D. in Chemical Engineering from the University of Delaware. Chuck Olsen, Worldwide Technical Services Manager, has been selected to 2008 National Petrochemical and Refiners Association Question and Answer panel. Chuck, who has over 15 years of experience in hydroprocessing, has held a variety of technical service, research and technical management positions in Chevron and Grace Davison before joining ART. Olsen holds a B.S.ChE degree from the University of Minnesota, and M.S. and Ph.D. degrees in chemical engineering from the University of Illinois in Champaign-Urbana. Gerianne D Angelo is Senior Technical Service Engineer with responsibility for estimates, troubleshooting, training engineers and operators, attending meetings to explain proposals, sending out data reports, loading/startups and helping in anyway possible our clients who have questions or issues on their units. Geri, who has a B.S.Ch.E. from the University of Illinois, joined ART in 2001 after twelve years at Citgo s, Lemont, IL refinery. Woody Shiflett, Director of Global Marketing, is based at the Chevron Technical Center in Richmond. Prior to joining ART in 2001, Woody was employed Criterion Catalysts from 1983 to 2001, holding increasingly responsible positions in the hydrotreating business. The author of numerous technical papers, he holds a B.S.Ch.E. from the University of Akron, a Ph.D. in Chemical Engineering from the University of Wisconsin- Madison and an MBA from Texas A&M University. Lauren Blanchard serves as Strategic Business Marketing Manager. She received a B.S. Ch.E. from the University of Massachusetts and an MBA from Loyola University, Maryland. Since joining Grace in 1993, she has held operations, technical, quality assurance and marketing positions in both ART and Grace s Refining Technologies business. Mark Peterson, Director Marketing Segment, joined Grace in Prior to that, Mark was National Sales Manager, Hydrotreating Catalysts for Akzo and General Manager, Process Technology and Licensing for Unocal. Mark received a B. A. in chemistry from the University of California-Irvine an Ph.D. in Physical Chemistry from the University of California-Davis. Bob Fletcher is ART s Regional Sales Manager based in Houston, TX. Bob, who holds a B.S. and M.S. in Mechanical Engineering from the University of Cincinnati, joined Grace Davison s Refining Technologies in 1993 after holding various technical specialty chemicals sales positions at Betz and Chemlink. 18

21 Combining New and Old Technologies - Inlet Diffuser and Random Packing Dramatically Improve Reactor Performance Garry E. Jacobs Technical Director, Process Engineering Fluor Enterprises, Inc. Aliso Viejo, CA, USA Gerianne D Angelo Senior Technical Service Engineer ADVANCED REFINING TECHNOLOGIES Chicago, IL USA T he performance of hydroprocessing reactor internals has improved significantly over the past decade, driven in part by ultra low sulfur product specifications. Yet, some reactors continue to operate with internals that are inadequate for the operating conditions. This inadequacy may be caused by the introduction of heavier feedstocks or by constraints that preclude installation of the appropriate hardware. This paper presents the case history of a kerosene hydrotreater that failed to meet product sulfur targets, subsequent to a catalyst changeout. The reactor operates with a mixed-phase feed, but is lacking a liquid distribution tray. Troubleshooting work included pilot plant testing of the catalyst retains, leak testing of the feed/effluent exchangers, and radioactive tracer tests and gamma scans of the reactor. A charge rate test was also performed which suggested significant underutilization of the catalyst. Evidence of liquid maldistribution was also obtained by visual inspection of the catalyst bed surface and analysis of spent catalyst samples. Using computational fluid dynamic (CFD) modeling, a new inlet diffuser was designed to improve liquid dis- ART Catalagram 104 Special Edition Fall

22 Figure 1 Existing Inlet Diffuser Troubleshooting Activities A simplified comparison of the operating conditions and performance for the two catalyst cycles is presented in Table I. Of particular note was the approximately 1½-PSI reactor pressure drop through the post 2007 T/A catalyst load. With uniform vapor/liquid distribution, the pressure drop should be at least two times higher. This was the first evidence of significant liquid maldistribution. The ensuing troubleshooting activities further explored this and other possible causes of the higher-than-expected product sulfur levels. tribution to the top of the catalyst bed and was installed during a catalyst changeout. In addition, high void fraction random packing was loaded at the top of the bed to promote radial liquid dispersion. After restart of the unit, the reactor was able to meet the refiner s 10 ppmw sulfur target for ultra low sulfur kerosene (ULSK) product. Background Figure 1. The inlet diffuser is inserted in the reactor inlet nozzle and helps dissipate the momentum of the incoming feed. The addition of a tray was considered by refinery personnel, but could not be justified based on acceptable performance during the catalyst cycle leading up to the 2007 turnaround. Feed/Effluent Exchangers When producing ultra low sulfur distillates, extremely small and previously unnoticeable leaks in feed/effluent exchangers can result in off-spec product. Several techniques were used by the refiner to check for such leakage, including feed and product sulfur speciations and tracer tests. If raw feed is leaking into the reactor effluent, then easily hydrotreated sulfur compounds (e.g., mercaptans and alkylthiophenes) will be present in the product. The speciation results Subsequent to a catalyst changeout in the spring of 2007, a kerosene hydrotreater failed to meet ULSK specifications. The unit feed consists of a mixture of straight-run kerosene and coker naphthas. During the previous catalyst cycle, the reactor initially treated only fully vaporized naphtha. A couple of years into that eight-year cycle, the straight-run kerosene was introduced, creating a mixed phase feed. During the final year of that cycle, the reactor was able to produce ULSK. The catalyst changeout was dictated by concerns of silicon breakthrough into the reformer feed. Table I Comparison of Operating Conditions and Performance Catalyst Cycle Post T/A Feedstock Loading Method Severity Axial Temp Profile Naphtha Only (~2 Yrs) Naphtha + Kerosene (~6Yrs) Sock ULSK (Final Year) Typical Naphtha + Kerosene Dense Inadequate HDS Typical The reactor did not have a liquid distribution tray. The distribution hardware consisted solely of a basic inlet diffuser, shown in Pressure Drop T/A Observations 7-9 PSI (Final Year) No Agglomeration ~1 1/2 PSI 20

23 confirmed the presence of mercaptans, but not propyl- and lighter thiophenes that were abundantly present in the feed. The absence of these thiophenic compounds, which can not be produced by recombination reactions, provided strong evidence that feed/effluent exchanger leakage was not the cause of high sulfur levels in the kerosene product. This result also indicates that the mercaptans were formed by recombination reactions, as discussed subsequently. Two tracer tests were also performed on the feed/effluent exchangers. In separate tests, a high volatility sulfiding agent and a radioactive noble gas tracer were injected on the feed side of the exchangers. The effluent side of the exchangers was then monitored for presence of tracer. Both tests indicated no leakage across the exchangers, within detection limits. Implicitly, the absence of sulfiding agent in the reactor effluent was also an indication of liquid phase maldistribution, as the fully vaporized sulfiding agent was completely converted to hydrogen sulfide in the reactor. Catalyst Activity Since the reactor does not have a distribution tray, liquid phase sulfiding could not ensure proper activation of the entire catalyst load. For this reason, vapor phase sulfiding was performed using dimethyl disulfide (DMDS). The sulfiding step was uneventful, with the lowand high-temperature hydrogen sulfide breakthroughs occurring as expected. The catalyst Certificate of Analysis (COA) was reviewed and found in compliance with the Process and Quality Assurance Specifications. Catalyst retains from the commercial reactor were loaded in a pilot plant reactor and tested using a representative blend of the refiner s feedstocks. For comparison, a standard sample of the same catalyst type was also tested in the pilot plant. The results confirmed that Distance from Top Tangent Line (ft.) Figure 2 Radioactive Tracer Test Results the activity of the retained sample was essentially equal to that of the standard sample, within pilot plant testing tolerances. Furthermore, the temperature required to meet the ULSK sulfur target in the pilot plant was actually 10 F lower than the SOR projection for the commercial reactor. The pilot plant results indicated an activity disparity of approximately 60 F, compared with commercial unit performance. This is roughly equivalent to a 16-fold difference in space velocity. At first glance, this disparity may seem too dramatic to be explained by liquid maldistribution. This point will be addressed subsequently, with the benefit of further observations. Vapor/Liquid Distribution Within the Reactor To explore the possibility of liquid maldistribution within the reactor, the refiner utilized a process diagnostics Radiaton Intensity (Counts per Time Interval) services company to perform two separate tests. Radioactive Tracer Test The radioactive tracer test was intended to quantify the liquid distribution within the catalyst bed. A radioactive halogenated hydrocarbon was injected into the reactor feed. As the feed mixture passed through the bed, the radioactive halogen adsorbed onto the catalyst. Eight uniformly spaced detectors were then lowered about the periphery of the reactor, and radiation measurements were obtained at multiple elevations. The results of this radioactive tracer test are shown in Figure 2. The relative uniformity of the eight scan lines was interpreted as an indication of good liquid distribution within the bed, with the caveat that the test could not identify axisymmetric maldistribution. ART Catalagram 104 Special Edition Fall

24 Figure 3 Normalized Radar Plots of Radioactive Tracer Test Results A B C W NW N NE E W NW N NE E W NW N NE E SW S SE SW S SE SW S SE 4.0 ft. 5.0 ft. 6.0 ft. 7.0 ft. 7.0 ft. 8.0 ft. 9.0 ft ft ft ft ft. Unfortunately, this tracer test was significantly flawed. A simple flash calculation at the reactor inlet operating conditions revealed that the halogenated hydrocarbon tracer was approximately 50% vaporized. Therefore, the results did not provide an accurate indication of the liquid distribution, as tracer from the vapor phase also adsorbed onto the catalyst. A closer examination of the data suggests the results are actually indicative of the vapor phase distribution. At each elevation, the raw data was normalized and graphed on radar plots (see Figure 3), to facilitate visualization and interpretation. Figure 3A indicates that the peak tracer deposition shifted from the E/SE region to the S/SW region. This shift occurred between the 5-0 and 6-0 elevations, which is consistent with the transition from ¼ grading to 1/10 silicon guard catalyst. Figure 3B indicates that another shift in the peak tracer deposition occurred (from the S/SW region to the West region) between the 8-0 and 9-0 elevations. This shift is consistent with the transition from 1/10 silicon guard catalyst to 1/20 HDS catalyst. Figure 3C indicates that the peak tracer deposition stabilized in the West region through the 12 0 elevation. Minimum tracer deposition stabilized in the SE region. These shifts in peak tracer deposition occurred rapidly, within elevation changes of one foot or less. In this reactor, vapor is the continuous phase. Liquid trickles over the grading and catalyst, and as such, can not make rapid radial transitions. Therefore, the rapid shifts shown in Figure 3 are likely attributable to changes in the vapor flow path, caused by porosity variations. If this interpretation is correct, the tracer data indicates locally high and low vapor-phase space velocities, respectively, in the West and SE regions. These deviations from uniform flow, however, are not of the magnitude necessary to explain the poor reactor performance. Most notably, the tracer results provided no meaningful information on the liquid-phase distribution. Gamma Scan The gamma scan was intended to quantify the vapor and liquid distribution prior to entering the catalyst bed. A 9 x 9 horizontal fan-patterned scan was performed, utilizing 9 source placements and 9 detector placements. The 81 data points were used to produce the results shown graphically in Figure 4. This figure indicates very high densities near the reactor wall and very low densities in the center of the reactor. The results were interpreted as evidence of an annular flow pattern with virtually no (liquid) flow in the center of the bed. An alternate, more probable interpretation of Figure 4 is that the reactor wall was too thick (~3 ) to provide any meaningful information about the phase distribution above the bed. As presented below, evidence gathered during the subsequent turnaround confirmed liquid flow primarily in the central region of the bed. The limitations of gamma scan technology are discussed elsewhere. Charge Rate Test A charge rate test was performed to provide an indication of catalyst utilization. The test is performed at two different reactor feed rates (i.e., space velocities), holding feed quality, reactor temperature, and gas-to-oil ratio constant. Catalyst activity is dictated primarily by the latter two variables. Therefore, the rate constants for both space velocities can be equated, as shown in Equation 1. The feed and product sulfur concentrations, along with the two space velocities, are inserted into this equation to determine the apparent HDS reaction order, n. 22

25 Figure 4 Gamma Scan Above Catalyst Bed Intrinsic kinetics for individual sulfurbearing species (e.g., thiophene) are generally first order with respect to the species concentration. However, petroleum-derived oils contain a broad spectrum of sulfur species, with widely varying reactivities. This wide variation increases the apparent (i.e., observed) HDS reaction order to for bulk desulfurization. The processing objective of the kerosene hydrotreater is ~99.5% HDS. This level of treating is beyond bulk desulfurization, with only alkylbenzothiophenes remaining in the reactor effluent. Therefore, the apparent reaction order is likely in the range of In contrast, the charge rate test indicated an apparent reaction order of 4.3, which corresponds to 25 30% of the catalyst not being utilized, depending upon the assumed reaction order (see Figure 5). Equation 1 Analyzing Charge Rate Test by Equating Rate Constants Figure 5 Estimate of Unused Catalyst (Based on Charge Rate Test) The charge rate test has shortcomings, though. It does not consider whether the reacting sulfur species are present in the vapor phase, liquid phase, or both phases. In this regard, it seems more applicable for troubleshooting reactors in which the reacting species remain predominantly in the liquid phase at the reactor operating conditions (e.g., gas oil hydrotreaters). This was not the case for the kerosene hydrotreater, as approximately 35% of the feed was in the vapor phase during the charge rate test. Observed HDS Reaction Order Subsequent to these troubleshooting activities, the refiner requested that Fluor design a new inlet diffuser to improve liquid distribution to the catalyst bed. Inlet Diffuser and Random Packing Improve Liquid Distribution The vapor and liquid phases entering a reactor can be highly maldistributed due to the impact of the elbows in the reactor feed line, just upstream of the inlet nozzle. The flow paths taken by both phases are % of Catalyst Not Utilized dependent upon their relative ART Catalagram 104 Special Edition Fall

26 momentums and the piping geometry, and are not easily predicted without a tool such as CFD. The potential extent of maldistribution is illustrated in Figure 6. This picture is the result of CFD modeling of the refiner s reactor inlet line. The model extends from near the heater outlet, through the combining tee, and along the common line to the reactor inlet. In the picture, the interface between the vapor phase and the liquid phase is green. At the inlet to the vertical run, the liquid collects on the far side of the elbow. In the horizontal run above the reactor, the flow begins transitioning into a stratified regime, with the majority of the liquid flowing along the bottom of the line. At the final elbow, the liquid s momentum carries it to the far side (i.e., east side) of the reactor inlet nozzle. Figure 6 Vapor/Liquid Maldistribution at Reactor Inlet Figure 7 Fluor Inlet Diffuser The inset circular image is a crosssectional view, just as the flow passes through the reducing flange and enters the top of the reactor. In this image, the liquid is red and the vapor is blue. The two phases are quite segregated, with liquid heavily biased toward the east side of the reactor. The function of the Fluor inlet diffuser is to correct this maldistribution. New Technology: U.S. Patent No. 7,281,702 Fluor s patented inlet diffuser is illustrated in Figure 7. It has been designed to accommodate the wide variations in vapor and liquid maldistribution that may occur due to different operating conditions and reactor inlet line routings. This diffuser utilizes three stages, contained in a cylindrical cartridge, followed by a deflector plate. Each stage consists of two sets of vanes. Flow is outward through the upper set of vanes and inward through the lower set of vanes. Figure 8 Inlet Diffuser Liquid Spray Pattern The upper vanes induce swirling, which forces the liquid toward the cartridge wall, creating hold up (i.e., allowing the vapor to slip past the 24

27 liquid). The lower vanes act as vortex breakers, reducing the swirl of the inflowing fluid. The fluid flows downward in the center of the cartridge to pass from one stage to the next. The swirling action redistributes the liquid circumferentially. Exiting the third stage, the liquid and vapor discharge onto a deflector plate, creating a hollow cone spray pattern (see Figure 8). Figure 9 50mm Ceramic Raschig Rings With this spray pattern, liquid wetting at the top of the catalyst bed is in the form of an annular ring. The benefits of an annular ring wetting pattern have been revealed and utilized, previously. Prior to reaching the active catalyst, liquid distribution within the bed can be further improved using old technology. Old Technology Raschig Rings (Courtesy of Saint-Gobain NorPro) Raschig rings (see Figure 9) were invented at the end of the 19th century by Fritz Raschig to improve the fractionation of carbolic acid. Since then, higher efficiency random packings have been developed for distillation applications. Interestingly, though, raschig rings can still play an important role in process engineering. These high void fraction rings promote rapid liquid dispersion in trickle flow applications. This characteristic is quantified by a radial dispersion coefficient, which allows various random Radial Dispersion Coefficient (mm) packings to be objectively compared. The radial dispersion coefficient is dependent upon the packing diameter. Figure 10 illustrates that 50-mm raschig rings are approximately three times more effective than the 15-mm spheres commonly used as grading in hydroprocessing reactors. Combining Technologies To improve liquid distribution in the reactor, Fluor recommended that the Figure 10 Radial Dispersion Coefficients 5 Raschig Rings Spheres Nominal Diameter (mm) Pall Rings refiner install a custom designed inlet diffuser, along with 3 feet of 50- mm raschig rings, loaded on top of the existing catalyst. This combination is illustrated in Figure 11. The reactor feed liquid is treated in an annular portion of the catalyst bed, while the vaporized feed is treated primarily in the unwetted portion. Unit Shutdown Activities In the fall of 2007, the kerosene hydrotreater was taken off-line. The refiner felt that a catalyst changeout was warranted, to maximize the probability of achieving ULSK sulfur levels upon restart. Prior to unloading, the top of the bed was visually inspected. The inspection revealed an ~3-foot diameter, ~8-inch deep crater below the inlet diffuser. This crater was unambiguous evidence that liquid had channeled down the center of the reactor and caused localized settling. Due to the settling, the grading materials had become intermixed. The inspection confirmed the inaccuracy of the gamma scan results. Approximately 4½ feet of grading and catalyst were then vacuumed from the top of the catalyst bed. ART Catalagram 104 Special Edition Fall

28 Figure 11 Improved Liquid Distribution tested side-by-side with a standard sample of the same catalyst type. The tests were performed using a much heavier (API = 11 ) distillate feedstock, as the refiner s feed blend was no longer available. The results indicated that the east core sample was 5 7 F less active than the standard sample, at ULSD product sulfur levels. Therefore, within the reproducibility of the pilot plant testing, this core sample was only marginally less active than the fresh retains (tested during the performance troubleshooting). As such, it is very inappropriate to refer to this sample as spent catalyst. Observed Kinetics Revisited HDS catalyst samples were obtained by coring several feet further into the bed. The remaining catalyst was dumped and the reactor was sock loaded with new catalyst. Because the catalyst did not pack as densely as planned, only 2 feet of 50-mm raschig rings were loaded on top of the bed. The Fluor inlet diffuser was installed prior to closing the reactor. Post-Shutdown Performance Activities Subsequent to sulfiding activities, the unit processed only the straightrun kerosene for several days, after which the coker naphtha was introduced and operating severity was slowly increased. The reactor was able to produce ULSK at a temperature level below the SOR projection. The refiner was extremely pleased with the reactor performance. a good marker of the liquid distribution. As shown in Figure 12, the center and east samples contained significantly more silicon than the other samples. This silicon distribution is consistent with the observed crater and with the CFD modeling (which indicated an easterly bias to the incoming liquid). Cored Catalyst Sample Activity Testing Catalyst from the east core sample (with 0.68 wt.% silicon loading) was loaded in a pilot plant reactor and With visual confirmation that liquid had indeed channeled down through the central region of the reactor, the kinetic performance during one of the troubleshooting days was revisited. The basis for this analysis is presented in Table II. At the reactor operating conditions, approximately 70% of the feed was vaporized. The catalyst volume was divided into two portions, with one portion treating the vaporized feed and the other portion treating the unvaporized feed. Gas distribution between the two portions was estimated based on the requirement of equal pressure drop across both portions. The significantly reduced gas flow in the liquid wetted portion most likely Figure 12 Silicon Loadings on Cored Catalyst Samples Cored Catalyst Samples Silicon Loading The cored catalyst samples were analyzed for trace contaminants. Of particular note were the silicon loadings, as silicon can be used as 26

29 caused localized hydrogen starvation and hot spots, an environment which promotes mercaptan formation. Interestingly, mercaptan concentrations decreased at higher operating temperatures, which is inconsistent with conventional wisdom regarding recombination. Typically, recombination is attributed to very high operating temperatures, rather than localized hydrogen starvation. In this instance, higher reactor inlet temperatures increased feed vaporization, which increased the gas-to-oil ratio (i.e., hydrogen partial pressure) in the wetted portion of the catalyst bed. With an LHSV 3hr -1, the sulfur content of the vaporized portion is reduced to less than 1 ppmw. Based on an overall product sulfur content (excluding mercaptans) of ~150 ppmw, the unvaporized portion had to contain ~500 ppmw. This concentration requires an LHSV of approximately 35hr -1. The quantity of catalyst involved is equivalent to the volume of a cone with a 3-ft. diameter base (i.e., the diameter of the observed crater) and a height equal to that of the HDS catalyst bed. Repeat Charge Rate Test The refiner is interested in repeating the charge rate test. This test requires that the coker naphtha be removed from the unit feed. With no other convenient destination available, the test will not be conducted until the coker is shut down for maintenance. Concluding Remarks When troubleshooting reactor performance problems, it is very important to understand the fundamentals behind the diagnostic tests being performed. Nothing hampers an investigation more than misconceptions and misinformation. In the case history presented here, the liquid phase radioactive tracer test results and the gamma scan results both produced misinformation regarding the vapor and liquid distribution within the reactor. Table II Kinetic Analysis of Kerosene Reactor (Accounting for Feed Vaporization and Liquid Maldistribution) Unit Feed Rate (BPD) Phase Split (BPD) API Gravity Total Sulfur (ppmw) TBP Distillation ( F) 10% 50% 90% LHSV (hr 1 ) Overall Each Phase (Note 1) Gas-to-Oil Ratio (SCFB) Overall Each Phase (Note 3) Catalyst WABT ( F) Product Sulfur (ppmw) Total Each Phase It is also important to follow the trail that the evidence provides. With catalyst activity confirmed by testing of the commercial retains and the possibility of exchanger leakage eliminated by two independent tests, maldistribution became the prime suspect. Very low pressure drop about 1½ PSI across the reactor was the first direct evidence of severe liquid maldistribution. The mercaptan-containing product and the high apparent HDS reaction order provided further indications of liquid maldistribution. Vaporized Feed 9, ~3 (Note 2) > , ~1100 Same for Both Phases Unvaporized Feed 3, ~35 < 300 ~150 (excluding mercaptans) nil ~500 Notes: 1. Determined by kinetic analysis, using catalyst activity derived from pilot plant testing of commercial retains. 2. LHSV 3hr -1 required to treat vaporized feed to <1 ppmw sulfur. Actual LHSV is less than 3hr Estimates - based on requirement of equal pressure drop for both the unwetted portion (vaporized feed) and wetted portion (unvaporized feed) of the catalyst bed. For reactors operating with mixed phase feed, an appropriately designed distribution tray maximizes catalyst utilization and resulting reactor performance. When installation of a distribution tray is not possible in a revamp application, liquid distribution can be improved through the use of a new technology, a unique inlet diffuser, and an old technology, raschig rings. Together these two elements, at very low relative cost, improve liquid distribution and catalyst utilization when producing ultra-low sulfur products in a trayless reactor. The ART Catalagram 104 Special Edition Fall

30 alternative, neglecting liquid distribution and hoping for adequate performance, should be considered too great an engineering and economic risk to accept. References Maiti, R. N., and Nigam, K. D. P., Gas-Liquid Distributors for Trickle- Bed Reactors : A Review, Ind. Eng. Chem. Res. 2007, 46, Alvarez, A., Ramirez, S., Ancheyta, J., Rodriguez, L. M., Key Role of Reactor Internals in Hydroprocessing of Oil Fractions, Energy & Fuels 2007, 21, Vidrine, S., Hewitt, P., Radioisotope Technology Benefits & Limitations in Packed Bed Tower Diagnostics, Ethylene Producers Conference at 2004 Spring AIChE Meeting, New Orleans, LA, April Unpublished. Carberry, J. J., Chemical and Catalytic Reaction Engineering, McGraw-Hill, New York, 1976; pp Hoftyzer, P. J., Liquid Distribution in a Column with Dumped Packing, Trans. Instn Chem. Engrs 1964, 42, T109-T117. Jacobs, G. E., Milliken, A. S., Evaluating Liquid Distributors in Hydroprocessing Reactors, Hydrocarbon Processing, November 2000, Jacobs, G. E., Krenzke, L. D., Insights on Reactor Internals for ULSD Performance of Existing and New Hardware, NPRA 2003 Annual Meeting, AM node=208&/~=cb89f5851d60aae8 b6c72ce d5 McCulloch, D. C., Catalytic Hydrotreating in Petroleum Refining. In Applied Industrial Catalysis, Volume 1; Leach, B. E., Ed.; Academic Press: New York, 1983; pp

31 ART Excels In ULSD Service: Update on Sulfur minimization by ART Greg Rosinski Technical Service Engineer Dave Krenzke Regional Technical Services Manager Charles Olsen Worldwide Technical Services Manager ADVANCED REFINING TECHNOLOGIES Chicago, IL USA A RT first introduced the SmART Catalyst System Series for ultra-low sulfur diesel (ULSD) in Since that time the technology has been widely accepted by the refining industry as top tier for ULSD. As detailed previously (Catalagram 99, 2006), the SmART System is a staged catalyst system customized to meet individual refiners objectives with the performance of the system driven by ART s DX TM Catalyst Platform. ULSD production with the first SmART System began early in 2004 at a North American refinery processing a feed containing 40% of a high endpoint Light Cycle Oil (LCO). Since that time DX Catalyst Platform has been selected for over 35 ULSD applications as either stand-alone catalysts or as components in SmART System. The technology has been a great success since its introduction with millions of pounds installed in commercial units around the world. Several of the first refiners to utilize a SmART System are still enjoying benefits today, or have reloaded another SmART System based on the exceptional first cycle they received from the technology. This article contains several case studies highlighting the performance of ART catalysts in a variety of ULSD units around the world. These are summarized in Table I. Refiner A is an initial user of a SmART System in Asia Pacific. This refiner conducted in-house testing for their ULSD catalyst selection. ART Catalagram 104 Special Edition Fall

32 Region A AP B AP C AP D AP E NA F NA G NA H NA WABT, F Table I Summary of ULSD Case Studies Feed 40% cracked stock Straight Run Straight Run Straight Run 40% coker/lco 50% LCO 70% LCO 45% LCO/LCGO Inlet Pressure psig N/A Figure 1 Asia Pacific Refiner A LHSV % CoMo/ % NiMo 70/30 90/10 55/45 30/70 35/65 70/30 + Dewax 35/65 25/75 5 ppm product sulfur They requested catalyst samples from ART and a market leading domestic supplier. The DX TM Catalyst Platform tested as a substantially more active catalyst than the others in the program. As a result, ART was selected as the catalyst supplier for their unit, which started up in the last half of This refiner was completing a revamp, which involved the addition of a new reactor in front of an existing reactor. They decided to use fresh catalyst in the new lead reactor while keeping used ART catalyst in the lag reactor. The unit conditions are characterized by an inlet pressure of 930 psig and a LHSV of 0.7 hr -1. The feed contains up to 40% cracked stocks, and the product sulfur has averaged 5 ppm. The unit ran for three years before the refiner decided to change out the used catalyst in the lag reactor with fresh catalyst from ART. The performance of the unit is summarized in Figure 1 and, as the figure depicts, stability has been exceptional. WABT, F 560 Actual Normalized Days on Stream Low severity mode Product Sulfur: 15% <8ppm Figure 2 Asia Pacific Refiner B High severity mode Product Sulfur: 85% <8ppm Return to low severity mode: WABT dropped about 14 F Days on Stream Actual Normalized to 10 ppm Figure 2 shows data for Refiner B. This was another major Asia Pacific refiner using a SmART System. This refiner needed to produce 10 ppm sulfur diesel for two years in a newly revamped unit. The operating conditions for this unit are 770 psig inlet pressure with an LHSV around 0.7 hr -1. The feed was a high end point, straight run diesel with typical sulfur content of 1.25 wt.%. This refiner was concerned with minimizing hydrogen consumption as hydrogen availability was limited at the refinery. This was a situation well suited for the flexibility of the SmART System to tune the hydrogen consumption/activity relationship. The optimum loading for this unit was 90% cobalt-molybdenum (CoMo) and 10% nickel-molybdenum (NiMo) catalyst. This design was expected to be significantly more active than an all CoMo loading and would consume the same amount of hydrogen as an all CoMo loading. The final selection of the SmART System was based on competitive pilot plant testing by the refiner. 30

33 About eight months into the ULSD portion of the cycle, the refiner significantly increased the operating severity and began producing very low sulfur diesel. Typically, 8 ppm is the recommended product sulfur target when producing <10 ppm ULSD. In the higher severity mode, the product sulfur was well below 8 ppm 85% of the time, whereas in the lower severity mode the product sulfur was below 8 ppm only 15% of the time. The higher severity led to a much higher deactivation rate and potentially jeopardized the two year cycle length. After discussions with the refiner, the severity was reduced and the two year cycle length was achieved. ART was chosen for the second cycle which again was based on competitive testing and the outstanding performance demonstrated in the first cycle. The current system is performing very well. WABT, F Days on Stream Actual Refiner C, another Asia Pacific refiner, selected ART catalysts for their ULSD unit based on the strong reference from the refiners mentioned above. This refiner needed to produce 8 ppm sulfur diesel for two years and hydrogen availability was not a constraint. The operating conditions included an inlet pressure of 850 psig and LHSV of 1.2 hr -1. The feed was also a high endpoint, straight run diesel with a sulfur content of 1.8 wt.%. This was a more demanding operation than those discussed previously, and a required system designed for maximum activity. The catalyst loading in this case was 55% CoMo and 45% NiMo. The performance is summarized in Figure 3. This unit met all performance targets during the two year cycle and has just been reloaded with a new SmART System. Figure 3 Asia Pacific Refiner C Operating data for Refiner D is shown in Figure 4. This is a grass roots ULSD unit in Asia Pacific. ART was chosen to participate in this project because of the excellent performance of the SmART System from previous references in the region. ART worked Normalized to 8 ppm 300 closely with the refiner and engineering construction firm on the design basis for this project. A 30% CoMo and 70% NiMo SmART System was designed for this unit in order to deliver maximum activity. The operating conditions for this unit included an inlet pressure of 1130 psig and LHSV of 1.1 hr -1. This unit also processes a straight run feed which has a relatively high level of nitrogen and an endpoint of 730 F (by D86). The unit is running well and meeting all performance expectations with a somewhat lower than estimated deactivation rate, and is well on track to meet the targeted threeyear cycle length. WABT, F Figure 4 Asia Pacific Refiner D Days on Stream Actual Normalized to 8 ppm Refiner E is another grassroots ULSD unit, which started up in the second quarter of 2006 in North America. ART worked with the licensor on the unit design and proposed a SmART System loading consisting of about 65% NiMo. This loading was designed for maximum activity as the design feed contained a high percentage of cracked stocks. The conditions of the unit included an inlet pressure of 1070 psig with an LHSV of 1.25 hr -1. This refinery processes mostly sweet crudes, and the feed to the unit typically contains about 40% FCC LCO and coker LGO. The activity of the system has been extremely high, allowing this refiner ART Catalagram 104 Special Edition Fall

34 to operate at 20% over design charge rate. Figure 5 shows the performance for the cycle thus far, and it is evident from the figure that the catalyst stability has been excellent. In fact, the unit was designed for a 24-month cycle, but 48 months appears possible even at higher than design feed rates. This unit also typically processes 10% kerosene with occasional increases to as much as 30%. As can be seen in Figure 5, the addition of kerosene to the feed has no negative impact on the activity of the system, and may even improve the performance. Notice how the WABT decreases when processing higher amounts of kerosene. This suggests that the increase in feed vaporization (decrease in H 2 pressure) is offset by the decrease in hard to treat, substituted dibenzothiophene sulfur species. Figure 6 summarizes data from Refiner F in North America. This refiner had completed a project to revamp an existing hydrocracker to ULSD service. The objectives were to increase feed capacity from 30,000 to 45,000 BPSD, while ensuring the capability to process 50% or more LCO, as well as provide for cold flow improvement during the winter months. This refiner also wanted to minimize the hydrogen consumption so that feed rate could be maximized within make-up hydrogen constraints. Along with Süd Chemie, ART designed a dewaxing/ulsd catalyst system meeting the unit objectives. The unit started up successfully in the 2nd quarter of 2006 and processes both sweet and sour crude derived feeds in block operation. The feed is also comprised of vol.% of a high endpoint LCO. The performance of the unit is summarized in Figure 6. The unit came on stream with higher than expected activity, and is well on its way to exceeding the target three year cycle length. Additional details on this unit can be found in Catalagram 103, Spring WABT, F Normalized WABT, F Normalized WABT, F Figure 5 North American Refiner E Days on Stream WABT Kerosene Figure 6 North American Refiner F Days on Stream Figure 7 North American Refiner G 5 ppm average product sulfur Days on Stream Kerosene, vol.% 32

35 Inlet Pressure, Psig Figure 8 North American Refiner G Hydrogen Activity Refiner G is another grassroots unit which started up in the fourth quarter of The performance of this unit is summarized in Figure 7. ART again worked closely with the licensor on the new unit design and proposed a SmART System loading using 65% NiMo catalyst for maximum activity. The unit typically processes >70% LCO, including both LCO produced within the refinery and purchased externally. The initial deactivation rate of the unit was significantly higher than expected, and it was determined that this was due to lower H 2 partial pressure than design combined with lower H 2 /Oil ratio. This can be seen in Figure 8 which shows the trend of reactor inlet pressure and the recycle hydrogen purity. Early in the cycle there were control issues and the inlet pressure showed a steady decline. The recycle hydrogen purity also decreased steadily and had periods where it fell dramatically. Once the H 2 partial pressure concerns were addressed, combined with better bed temperature management, the deactivation rate decreased significantly. The operation became much more consistent, and since that time the deactivation rate indicates that the unit will easily meet the expected 24-month cycle length. Finally for Refiner H, Figure 9 summarizes the performance of a Days on Stream Pressure Recycle H 2 WABT, F Recycle H 2 Purity, vol.% SmART System at a U.S. Gulf Coast refinery. This was another grassroots unit that started up in the Fall of SOR activity met expectations, and since that time the unit operating severity has steadily increased. The current feedrate is 22% over design and the feedstock endpoint has increased by F. Typical unit conditions include 0.8 hr -1 LHSV and 1300 psig inlet pressure, and, on average, the unit processes a feed containing 15% FCC LCO, 30% LCGO and 5% coker naphtha. At times the unit has processed as much as 80% cracked stocks in the feed, and still the product sulfur has averaged less than 6 ppm for the cycle. The target cycle length was 24 months, and the unit is currently on track for a Figure 9 North American Refiner H Days on Stream 36-month cycle. Also shown in Figure 9 is the API uplift from the unit. From the chart, the API typically increases 6-10 numbers depending on the feedstock. As this sampling of case studies demonstrates, the SmART System has been employed in a wide variety of ULSD applications around the world. The technology has been successfully operating over a broad range of operating conditions from low to high pressure with feeds ranging from straight run to 80% cracked stocks. In each application, all expectations have been met or exceeded, and in a number of cases ART catalyst has been selected for the second cycle based on the excellent performance. ADVANCED REFINING TECHNOLOGIES continues to develop higher performance products for ULSD as evidenced by the recent introduction of the newest DX TM Catalyst Platform, 420DX. The addition of this catalyst to the ULSD portfolio is an example of the commitment that ART will continue to deliver state-of-the-art technology for ULSD API Gravity Increase WABT API Uplift ART Catalagram 104 Special Edition Fall

36 Columbia, Maryland USA Fax Houston, Texas USA Fax Singapore Fax Richmond, California USA Fax Worms, Germany Fax Toda, Japan Fax The information presented herein is derived from our testing and experience. It is offered, free of charge, for your consideration, investigation and verification. Since operating conditions vary significantly, and since they are not under our control, we disclaim any and all warranties on the results which might be obtained from the use of our products. You should make no assumption that all safety or environmental protection measures are indicated or that other measures may not be required. Catalagram, D-PrISM, Grace, Grace Davison, GSR, SmART Catalyst System, and SuRCA are trademarks, registered in the United States and/or other countries, of W. R. Grace & Co.-Conn. NEPTUNE is a trademark of W. R. Grace & Co.-Conn. ApART, AT, DX and StART are trademarks of Advanced Refining Technologies, LLC. ART and ADVANCED REFINING TECHNOLOGIES are trademarks, registered in the United States and/or other countries, of Advanced Refining Technologies, LLC. Chevron and ICR are trademarks, registered in the United States and/or other countries, of Chevron Intellectual Property LLC. LC-FINING TM is a trademark of Chevron Intellectual Property LLC. HOP is a trademark, registered in the United States and/or other countries, of Japan Energy Corporation licensed to Advanced Refining Technologies, LLC and W. R. Grace & Co.-Conn. H-OIL is a trademark, registered in the United States and/or other countries of Axens North America, Inc. This trademark list has been compiled using available published information as of the publication date of this brochure and may not accurately reflect current trademark ownership. This brochure is an independent publication and is not affiliated with, nor has it been authorized, sponsored, or otherwise approved by any of the aforesaid companies W. R. Grace & Co.-Conn.