Bonus Report. Consider new technologies to increase diesel yield from bottom-of-the-barrel products. Refining Developments

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1 Originally appeared in: November 212, pgs Used with permission. Bonus Report Refining Developments L. Wisdom, J. Duddy and F. Morel, Axens, Princeton, New Jersey Consider new technologies to increase diesel yield from bottom-of-the-barrel products As crude oil and product prices continue to climb, there are economic incentives for refineries to increase the total distillate yield with increased selectivity toward diesel fuel. The debate continues over the pros and cons of simply adding a new delayed coker vs. a hydrocracker upstream of an existing delayed coker to improve overall liquid yield. The following commercial examples will explore both sides on how to find more distillates from every barrel of oil processed. BACKGROUND The US has the greatest concentration of delayed cokers in the world. Of the 13 refineries processing 17.8 million bpd (MMbpd) of crude oil, 6 of these refineries use delayed coking (DC) to destroy vacuum (VR) and to increase the yield of distillates for further processing into transportation fuels. The first delayed coker came online in 1929 at the Standard Oil of Indiana refinery located in Whiting, Indiana. At that time, crude oil was selling for $1.27/bbl in current dollars. Since then, the refining industry has gone through various economic cycles. The most recent cycle started in 2 with a consistent rise in the price of crude oil, which is about $1/bbl for WTI. In addition, two major shifts have occurred in the energy market; natural gas prices started declining in 28 due to new discoveries, and the gasoline-to-diesel margin reversed in 25 with diesel priced higher than gasoline. As a result of these changes, a study was conducted to explore how these shifts would influence a refiner s decision on adding more crude capacity via a refinery expansion. US MARKET FOR DELAYED COKING In 21, the US had 6 delayed cokers as compared to 11 in Europe, 4 in the Middle East and 27 in Asia-Pacific. In the US market, delayed coking was the preferred choice for destroying the VR from medium and heavy crude oil. Of the 6 delayed coking units in the US, 55% in terms of capacity are located in PADD 3 (US Gulf Coast) and 13% are located in the PADD 2 market (US Midwest). The vast majority of these delayed coking units (DCUs) were installed when crude oil was below $2/bbl. In the last 1 years, Brent and WTI prices have risen at an unprecedented rate. Historically, refineries have added incremental DC capacity as part of refinery expansions because it was considered to be low-investment, well-known and economically attractive option. But, with the new changes in market prices and the increase in hydrocracking worldwide, is DC still the best option for a US-based refinery? Case history 1. The following case history investigates an existing 1,-bpsd refinery processing 1% Arabian Heavy crude. Expansion studies were conducted using both Arabian Heavy crude and Athabasca bitumen, with properties as listed in Table 1. Fig. 2 is the front-end section of a typical refinery configuration; it uses a delayed coker to process the entire VR. Straightrun (SR) and delayed coker distillates are processed into naphtha, diesel and fluid catalytic cracking (FCC) feed pretreat hydrotreaters. Steam-methane reforming (SMR) is used to generate hydrogen. Fig. 1. Delayed coker at Husky Energy s upgrader at Lloydmininster, Saskatchewan, Canada. HYDROCARBON PROCESSING November 212

2 Two expansion configurations were investigated for this case study. The first case (Case 1) adds an additional 1, bpsd of Arabian Heavy crude and duplicates the existing 27,2-bpsd delayed coker. The expansion brings the total crude throughput to 2, bpsd. The battery limits are shown in Fig. 2; it includes the associated offsite and utilities. It does not include the FCC unit or the post-fcc hydrotreater. Case 2. The second case (Case 2) adds a 54,4-bpsd hydrocracker upstream of the existing delayed coker, which remains unchanged, as shown in Fig. 3. In this configuration, the residual hydrocracking unit is a single-train plant with a single reactor operating at 6% conversion of 975 F+ to distillates. A second variation of Case 2 (Case 2A) was also investigated with a variation in which the conversion level is increased to 7% and the crude throughput is increased to 3, bpsd to fill the existing DCU. To handle the increased feedrate and reactor severity for Case 2A, two reactors, in series with inter-stage separation was required for this single-train plant. With the higher conversion level in the hydrocracker, the total Arabian Heavy crude capacity was increased to 3, bpsd, and the existing Table 1. Options for refinery expansions Property Arabian Heavy Athabasca bitumen API Sulfur, wt% Nitrogen, wt ppm 1,68 3,9 Ni + V, wt ppm CCR, wt% C 7 asphaltenes, wt% Distillation, wt% IBP 35 F F F F Crude Atmospheric Crude still SR naphtha SR AGO Vacuum still Vacuum SR VGO Delayed coking unit Naphtha Diesel Fig. 2. Base case of 1,-bpsd existing refinery. Natural gas Light gases to gas plant Naphtha to gasoline plant VGO Diesel product plant VGO to FCC Coke product DCU is still capable of processing the entire unconverted VR. Case 3. The final case (Case 3) examines the effect of switching from Arabian Heavy Crude to Athabasca bitumen (DilBit). This is a variation of Case 2 (see Fig. 3) with the addition of a hydrocracker ahead of the existing DCU. Due to the high VR content in the crude, the crude rate to the refinery is only increased from 1, bpsd to 15, bpsd. In all cases, the product streams naphtha, diesel and vacuum gasoil (VGO) are treated to the same level of product quality. ECONOMIC BASIS For this updated study, pricing data from the US Energy Information Agency (EIA) for the US as a whole and also for the PADD 2 (Midwest) and PADD 3 (Gulf Coast) were examined. The US prices for Brent, WTI and industrial natural gas for the last 1 years are shown in Fig. 4. Brent and WTI have tracked fairly close to each other, except for the last couple of years. The prices for DilBit (Athabasca bitumen) can be calculated from Western Canadian Select (WCS) synthetic crude, which is traded in Chicago, Illinois. There is a weak correlation between Brent and WCS prices except when the natural gas condensate (diluent) is removed from the WCS. To calculate the actual price of the bitumen, the cost of natural gas condensate is removed from the DilBit resulting in an average net price for the Athabasca bitumen at $68/bbl when Brent crude is valued at $1/bbl. This bitumen price is the same price as Hardisty heavy bitumen (12 API) at $68.35/bbl, quoted in January 212. Brent crude is used as benchmark crude for this study to determine gasoline and diesel margins based on historical trends. Natural gas prices increased from 22 to 25 due to a large demand and supply shortage, as shown in Fig. 4. However, in 26, the production of additional natural gas entered the market with tight shale gas formations; this started a downward trend in natural gas prices. At present, the average Crude Atmospheric Crude still SR naphtha Vacuum SR AGO Vacuum still Residue hydrocracking unit Unconverted vacuum SR VGO Delayed coking unit Naphtha Diesel Natural gas Light gases to gas plant Naphtha to gasoline plant VGO Diesel product plant VGO to FCC Coke product Fig. 3. Case 2 of the 1,-bpsd refinery with hydrocracker and expanded DCU. HYDROCARBON PROCESSING November 212

3 US industrial natural gas price is in the range of $4 to $5 per thousand standard cubic feet (scf), or roughly $3/bbl of oil equivalent (boe) basis. The gasoline-to-brent price spread (gasoline price minus Brent crude price) is shown in Fig. 5. It reflects a general increase in gasoline margins from 2 to 27 and then a steady decrease thereafter. Importation of gasoline from Europe and the increase in ethanol blending into the US gasoline pool are decreasing domestic demand for this fuel. For the last three years, PADD 2 prices have been higher than the average US prices while PADD 3 prices have been lower than the national average. The diesel-to-gasoline margin over the same period is shown in Fig. 6. For this study, a price spread of $9/ bbl is assumed for gasoline to Brent crude, which equates to $19/bbl for gasoline when Brent crude is valued at $1/ bbl for the average US market. Slightly higher prices could be used for projects in PADD 2, based on these historical trends. The price of diesel fuel overcame the price of gasoline in 25, and it has remained higher than gasoline for the last six years. Consequently, there is more interest from refiners to increase diesel production. This would imply an increase in mildand full-conversion hydrocracking in the future. Based on the mentioned trends, an economic basis, as shown in Table 2, was determined. STUDY CASES A summary of the four expansion cases investigated is described here: Case 1: Add 1, bpsd of Arabian Heavy crude to the existing refinery using DC as the conversion unit Natural gas WTI Brent Case 2: Add 1, bpsd of Arabian Heavy crude and install a hydrocracker, operating at 6% VR conversion ahead of the existing delayed coker. Case 2A: Same as Case 2, with the hydrocracker operating at 7% VR conversion and crude throughput increasing to 2, bpsd. Case 3: Add 5, bpsd to the existing refinery and switch from Arabian Heavy crude to Athabasca bitumen. In this case, a hydrocracker was installed upstream of the existing DCU. In all of the cases evaluated, the SR and cracked products Gasoline-Brent spread, $/bbl Whole US PADD 2 PADD Fig. 5. Gasoline-to-Brent price for US, PADDs 2 and 3: 1992 to Whole US PADD 2 PADD Cost, $/boe 8 6 Diesel-gasoline spread, $/bbl Jun- Jun-2 Jun-4 Jun-6 Jun-8 Jun-1 Jun-12 Fig. 4. Crude oil and natural gas prices: June 2 to June Fig. 6. Diesel-to-gasoline prices: 1992 to 212. HYDROCARBON PROCESSING November 212

4 were hydrotreated to meet the product specifications, as shown in Table 3. Expansion Case 1. The existing refinery crude capacity was doubled to 2, bpsd with Arabian Heavy crude. The total VR feedrate to the delayed coker is 54,4 bpsd. The new coker is a duplicate of the existing unit. The C 5 + product Table 2. Economic basis Item Value Operating, days per year 345 Offsites and utilities cost, % of process units 5 Investment contingency, % 2 Natural gas cost, $/thousand scf 5. Sulfur product credit, $/metric ton 2 Coke product credit, $/metric ton 1 Arabian Heavy crude price, $/bbl Net bitumen cost, $/bbl Brent crude (Ref. Price), $/bbl 1 LPG price, $/bbl 61 Gasoline price, $/bbl 19 Diesel price, $/bbl 114 VGO (FCC feed) price, $/bbl 15 Note: Reflects prices represents typical values in the marketplace during the period of 29 to 211 as reported by the US Energy Information Agency and by Natural Resources Canada. Table 3. Product Specifications Item Naphtha Diesel VGO Sulfur, wt ppm.5 max. 1 max. 2, max. Nitrogen, wt ppm.5 max. Cetane number 4 min. yield from the delayed coker is 66 vol%. This product is then blended with the SR distillates and hydrotreated to meet the product specifications, as listed in Table 3. The overall liquid yield was 18,5 bpsd or 9.3 vol% on crude throughput, which includes liquefued petroleum gas (LPG), naphtha, diesel and VGO. The VGO is assumed to be routed to an FCC unit, which has a post-hydrotreater and can meet Tier 3 gasoline specifications. Table 4 summarizes the breakdown of the product yields. Expansion Case 2. As in Case 1, the overall refinery throughput is doubled to 2, bpsd and all of the VR (54,4 bpsd) is routed to a single-train, single-reactor hydrocracking unit operating at 6% VR conversion. The unconverted (21,922 bpsd) is sent to the existing DCU with a nameplate capacity of 27,2 bpsd. The overall yields from the hydrocracker, the downstream delayed coker and hydrotreaters are listed in Table 4. All of the SR, hydrocracker and coker distillates are hydrotreated to meet the product quality specifications, as shown in Table 3. The overall liquid yield was 192,6 bpsd or 96.3 vol % on crude throughput including LPG, naphtha, diesel and VGO, which is routed to an FCC unit. This case is very similar to the commercial hydrocracker/dcu at Husky Energy s Lloydminster Upgrader in Saskatchewan, Canada (Fig. 7). The feed to this hydrocracker is about 34, bpsd of a blend Cold Lake/Lloydminster heavy, and it operates around 6% conversion. The entire unconverted from the hydrocracking unit is routed to a DCU to produce fuel-grade coke for export. Expansion Case 2A. In this case, the hydrocracking unit conversion level is increased from 6% to 7%. The number of reactors is increased to two in series with inter-stage separation, but they still operate in a single train. The larger reactor volume is required due to the greater feedrate and reactor severity. With the higher conversion level, the refinery throughput can be increased to 3, bpsd, which results in Table 4. Product Yields Case 1 Case 2 Case 2A Case 3 Feed type Arabian Heavy Athabasca bitumen Configuration DC Resid HC Resid HC/DC Resid HC/DC Resid HC conversion, % Yields, vol% on crude LPG Naphtha Diesel VGO Total Coke yield, metric tpy 3,114 1,431 1,76 1,647, scf/bbl of crude* ,84 Note: DC = Delayed coking Resid HC= Residue hydrocracker *Includes HC and/or DCU plus all three distillate hydrotreaters HYDROCARBON PROCESSING November 212

5 a feedrate of 81,655 bpsd to the hydrocracking unit; the unconverted bottoms (24,53 bpsd) are routed to the existing DCU. The yields for this case are shown in Table 4 for the hydrocracker and DCU. As before, all of the distillate SR and hydrocracked/delayed coker products are hydrotreated. The overall liquid yield is 292,3 bpsd or 97.4 vol% on crude throughput. Expansion Case 3. In this case, the crude type is switched from Arabian Heavy to a Canadian DilBit based on Athabasca bitumen. The feedrate to the refinery is expanded to only 15, bpsd of Athabasca bitumen (excluding the diluent, which is recovered and returned to Canada). The total feedrate to the diluent recovery unit is 216,9 bpsd, and it contains about 31 vol% of diluent. The relatively small increase in throughput is due to the high content of VR in the feed (58.6 vol% vs vol% for Arabian Heavy). The feedrate to the hydrocracking unit is 83,754 bpsd, and the feedrate to the delayed coker is 27,221 bpsd. In this case, the hydrocracking unit is a single train with two reactors in series with interstage separation and operates at 68% conversion. STUDY RESULTS A summary of the cases processing Arabian Heavy crude is shown in Table 4. The most severe design conditions were associated with the cases processing the greatest percentage of cracked stocks and the highly aromatic bitumen feedstock. Catalyst cycle lengths were set at 3 months. The product naphtha is routed to a catalytic reforming or isomerization unit, diesel to the ultra-low-sulfur diesel (ULSD) pool and VGO to the FCC/post treater for meeting Tier 3 gasoline specifications. Liquid yield. In hydrocracking, many of the coke precursors are hydrogenated, which results in higher liquid yield and reduced coke production. In addition, hydrogen consumption in the liquid product increases the API gravity, which, in turn, leads to greater volume swell and increased yield of transportation fuels. As expected, the total liquid yield is a function of the conversion level and the amount of hydrogen consumed in the liquid product, as shown in Table 4. Case 2 shows a 6 vol% increase in liquid yield from Case 1, which is about 4.2 MM bbl/yr of additional product (LPG, naphtha, diesel and VGO). By increasing the hydrocracker conversion from 6 vol% to 7 vol%, the total yield increases by 6.6 vol% over Case 1, which adds an additional production of 4.6 million bbl/yr of liquid product. The additional production translates into additional net revenue (product revenue less feedstock cost and operating cost), as shown in Fig. 8. The Case 1 expansion adds an additional $77 million/yr, while Cases 2 and 2A add more than $5 million net revenue/yr. In contrast with the higher liquid yield, the coke production is reduced by more than 5%. Coke produced in Cases 1 and Product yield, vol% Product yield of conv. unit, vol% Incremental net revenue, $MM/yr Existing refinery Case 1 Case 2 Case 2A Incremental net revenue, $MM/yr Fig. 8. Product yield of conversion unit vs. incremental revenue Diesel/gasoline ratio Fig. 7. Husky Energy s hydrocracking unit in Lloydmininster, Saskatchewan, Canada.. Case 1 Case 2 Case 2A Fig. 9. Diesel/gasoline selectivity for Cases 1, 2 and 2A. HYDROCARBON PROCESSING November 212

6 2 are 3,114 metric tpd and 1,431 metric tpd, respectively, indicating that 54 wt% of the coke precursors were converted in the hydrocracker. When the hydrocracker conversion is raised to 7%, the conversion of coke precursors is increased to 63 wt%, reducing the amount of coke even further. Accordingly, Case 2A can process more feed without major modifications to the existing DCU. Expansion investment cost, $/bbl 3, 25, 2, 15, 1, 5, Crude dist. Conversion unit Hydrotreaters Case 1 Other Offsites Contingency Case 2 Case 2A Case 3 Fig. 1. Investment costs for various expansion plans: Cases 1, 2, 2A and 3. Selectivity to diesel fuel. Ebullated-bed hydrocrackers are more selective to middle-distillate production than other conversion technologies. With the margin between diesel and gasoline expecting to increase, the selectivity becomes more important to the refiner desiring to maximize the economic returns on projects. One measure of this selectivity is the ratio of diesel-to-gasoline production. As shown in Fig. 9, the selectivity of the conversion unit increases from the DC scheme (Case 1) of 1.5 bbl of diesel to 1 bbl of gasoline production to the hydrocracker/dcu (Case 2 at 6% conversion) and reaches the highest value 2.2 bbl of diesel to 1 bbl of gasoline for the hydrocracker/dcu (Case 2A at 7% conversion). For a 2,-bpsd refinery, the diesel production would increase from 64,4 bpsd (Case 1) to 7,5 bpsd (Case 2A). The incremental increase of 6, bpsd translates into an annual revenue increase of $234 million for the refinery. Hydrogen consumption and volume swell. As shown in Table 4, the total hydrogen consumption for the expansion increases by 78% from Case 1 to Case 2A. This results in a total volume swell increase of 6.6 vol% on crude, which equates to an additional product of 13,2 bpsd for a 2,-bpsd refinery. As mentioned previously, the base price of industrial natural gas used for this study is $5/thousand scf, which is about $3/bbl (boe basis). With gasoline and diesel selling for $19/bbl and $114/bbl, hydrogen consumption provides the refinery with an Case 1 Case 2 Case 2A 6 Case IRR, % Average US value Case 2A IRR, % 3 15 Case Case Brent price, $/bbl Fig. 11. IRR vs. Brent price Diesel/gasoline spread, $/bbl Fig. 12. IRR vs. diesel-to-gasoline spread. HYDROCARBON PROCESSING November 212

7 Unit availability, % A B C D E F Commercial plants Fig. 13. Onstream times for commercial advanced ebullated-bed hydrocrackers in operation. 1 impressive uplift of $79/bbl to gasoline (i.e., $3/bbl boe to $19/bbl for gasoline) and $84/bbl uplift for diesel production. Alternate case when processing Athabasca bitumen. The major results of this case are shown in Table 4. Processing Athabasca bitumen or other heavy Canadian crudes will provide economic advantages that include upgrading a cheaper feedstock with low-cost hydrogen to high API transportation fuels. Relative to Case 2A, Case 3 provides the highest total liquid yield on crude of 11.5% of total liquid product vs. 96.9% for Case 2A. This is due to the lower API gravity of the crude and upgrading to about the same API gravity of the products. This case also represents the highest production of diesel and VGO per barrel of crude for any of the cases examined. For all of the cases, diesel production could increase further by adding a VGO hydrocracker during the expansion as compared to adding additional cat feed hydrotreating (CFHT) capacity upstream of the FCC unit. This would also improve the overall refinery diesel/gasoline ratio. ECONOMIC ANALYSIS For the economic analysis, the same basis from Table 2 will be used. The investment cost for the expansion cases was only for new units and associated offsites and utilities whereas, the revenues and operating expenses were for the entire refinery. Investment cost. Offsites and utilities were taken as a percentage of the total installed cost for the process units. Fig. 1 shows the investment cost breakdown for each of the investigated cases. The investment cost per barrel of crude for the new units varied from $14,8/bpsd to $22,4/bpsd with the delayed coker expansion at the lowest overall investment. For the expansion cases, the investment cost included new crude and vacuum units; conversion unit (delayed coker or hydrocracking unit); naphtha, diesel and VGO hydrotreaters, SMR hydrogen plant, sulfur plant, gas recovery section, amine regeneration; sour-water stripping; and corresponding offsites plus utilities. Operating cost for ISBL. The total operating cost, including fixed and variable operating costs, varied from $3.15/bbl of crude in Case 1 to $4.42/bbl for Case 2. Case 3, processing Athabasca bitumen, was the highest with a cost of $7.98/ bbl. The top two operating costs for the hydrocracking unit/dcu cases (Cases 2, 2A and 3) were natural gas plus catalyst and chemicals vs. natural gas and electricity for the delayed coker case (Case 1). Rate of return. The total net annual revenues (product revenue less crude cost and total operating cost) varied from $169 million for the delayed coker expansion (Case 1) to $932 million for the hydrocracking/dcu expansion (Case 2A) based on an Arabian Heavy crude price of $92.48/bbl. The product prices were $19/bbl for gasoline and $114/bbl for diesel. As shown in Fig. 11, the addition of a hydrocracker upstream of a delayed coker is more profitable when Brent crude price exceeds $55/bbl. As light oil prices continue to climb, the IRR for the delayed coker expansion case falls to zero when Brent crude reaches $115/bbl. This is due to the low conversion (i.e., low product liquid yield) and high crude costs. This analysis assumes a constant $/bbl discount to Arabian Heavy crude and a constant $/bbl differential between the price of gasoline and diesel to the price of Brent crude. History tells us that variations will occur in both lightand heavy-crude price differentials as well as price fluctuations in the finished product prices of gasoline and diesel. For this reason, several sensitivity studies were conducted. Sensitivity studies. During a sensitivity study, a number of questions were asked including, What happens if the dieselto-gasoline spread continues to widen? In all cases, the IRR climbs sharply by 6 to 7 percentage points for every $5/bbl the margin of diesel/gasoline increases. In the US Energy Information website forecast, the margins are expected to keep climbing for the short term. What s the impact in processing Athabasca bitumen from Canada relative to Arabian Heavy? The IRR doubles from 24% in Case 2 to over 5% in Case 3. This is mainly due to the attractive price of Canadian bitumen ($68.85/bbl) vs. the price for Arabian Heavy ($92.48/bbl). The differential of $23.63/ bbl for feedstock cost provides a significant incentive for all cases processing Athabasca bitumen. During a review of product prices in the US market, it was noted that higher margins for diesel fuel in PADD 2 (Midwest market) were $2/bbl to $3/bbl. The price variations in the diesel/gasoline spread varied between $5/bbl to +$17/bbl with a general increase occurring over the past five years. As shown in Fig. 12, an increase in the price of ULSD fuel vs. gasoline provides a tremendous uplift in the IRR for the project. A project located in the Midwest would see the IRR increased by 4 to 6 percentage points, depending upon which expansion case is selected. The same general trend is evident when the gasoline-to-brent crude price is increased. Residue hydrocracking reliability. Residue hydrocracking based on ebullated-bed technology is a mature technology, with HYDROCARBON PROCESSING November 212

8 17 operating plants processing more than 65, bpsd of VR in North America, Europe, Middle East and Asia-Pacific. The reliability of the advanced ebullated-bed technology has improved over the last 44 years since the startup of the first plant for KNPC s Shuaiba Refinery in Kuwait. 1 Over the past 1 years of operation, the average availability of six commercial advanced ebullated-bed units was 96% (Fig. 13). 1 This high level of reliability is the direct result of nearly 2-unit years of operating experience, automation of operations, pro-active reliability teams, improvements in the understanding of the chemistry of asphaltene conversion and stability through R&D, and ongoing improvements in critical equipment, components and process instrumentation. The plot shown in Fig. 13 reflects unit availability for six operating commercial advanced ebullated-bed units. 1 Availability is defined as the actual onstream time less planned turnarounds (typically occur once every three to six years) and outages due to external factors (i.e., hurricanes on the Gulf Coast). Acknowledgment Jim Colyar, a senior technology consultant, performed the revised internal study for which this article is based. The authors wish to acknowledge his work and contribution to heavy-oil upgrading. Editor s Note 1 The process is Axens ebullated-bed technology. BIBliogrAPHY Duddy, J., L. Wisdom, S. Kressmann, and T. Gauthier, Understanding and Optimization of Residue Conversion in H-Oil, Oct. 2, 24. Ellis, P. J. and C. A. Paul, Delayed coking, AIChE 1998 Spring National Meeting, New Orleans, March 8 12, Largeteau, D., J. Ross, M. Laborde and L. Wisdom, The Challenges & Opportunities of 1 wppm Sulfur Gasoline, 211 NPRA Annual Meeting, San Antonio, March 211. McQuitty, B., Status of the Bi-Provincial Upgrader: H-Oil Operation and Performance, IFP Seminar in Lyon, France September US Energy Information Agency, 212 Annual U.S. Crude Oil First Purchase Price. Wisdom, L., E. Peer. and P. Bonnifay, Cleaner fuels shift refineries to increased resid hydroprocessing, Parts 1 and 2, Oil and Gas Journal, Feb. 9, Larry Wisdom is a senior executive at Axens in charge of marketing the heavy-ends technologies in North America. The current portfolio of technologies includes the hydrotreating and hydrocracking of gasoil and s, slurry-phase hydrocracking, solvent deasphalting and visbreaking. During his 3 year career, he has co-authored more than 3 papers on heavy-oil upgrading and holds two patents. Prior to joining Axens, he worked for Hydrocarbon Research Inc. (HRI) and FMC Corp. Mr. Wisdom graduated from the University of Kansas with a BS degree in chemical engineering and a MBA in marketing and finance. John Duddy is the director of heavy oil and coal technology for Axens North America Inc. in Princeton, New Jersey. He is responsible for Axens ebullated-bed technologies for upgrading of heavy oil and coal. These technologies include H-Oil, H-Coal and Coal/oil co-processing. Mr. Duddy has been with Axens for 32 years and holds a BS degree in chemical engineering from Drexel University. Frédéric Morel is an expert director adviser for Axens marketing, technology and tech services department. He was formerly the manager of Axens hydroprocessing and conversion technical services group and the product line manager of VGO, resid and coal conversion. Mr. Morel has over 3 years of experience in oil refining, having worked previously with IFP s Lyon Development Center as a research engineer, a project leader of distillates and s hydroprocessing, and the manager of the development department. Mr. Morel holds a degree in chemical engineering from Ecole Supérieure de Chimie Industrielle de Lyon and a graduate degree from Institut d Administration des Entreprises. Article copyright 212 by Gulf Publishing Company. All rights reserved. Printed in U.S.A. Not to be distributed in electronic or printed form, or posted on a website, without express written permission of copyright holder.