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Refinery hydrogen management – the big picture

02.01.2003  |  Huycke, R.,  UOP N.V., Antwerp, BelgiumZagoria, A.,  UOP LLC, Des Plaines, Illinois

Hydrogen network operating decisions affect the bottom line every day, but most refineries do not apply the tools that could dramatically increase profitability


Hydrogen has always played an important role in oil refining, but refiners today are finding that it is one of the most critical challenges facing them as they plan production of clean fuels. In addition, hydrogen management practices significantly impact operating costs, refinery margin and CO2 emissions.

Therefore, an effective hydrogen management program must address refinery-wide issues in a systematic, comprehensive way. Managing hydrogen more effectively has been found to improve refinery profitability by millions of dollars a year, and often enables the refiner to avoid the capital cost of new hydrogen production.

The hydrogen system consists of hydrogen producers, hydrogen purification, hydrogen consumtand the distribution network itself (Fig. 1). Tools and techniques are available to manage each of these individual hydrogen network components.

Fig 1
 Fig. 1  

The hydrogen network.

However, if you consider the refinery as a whole, instead of individual process units, much greater opportunity exists to impact the refinery profit. The key to unlocking significant profit improvement opportunities is to focus on hydrogen's effect on the performance of hydroprocessing units - and therefore gross margin.

Presented here are various components of the hydrogen network and effective strategies for improving the network, from simple operating adjustments to capital improvements. A methodology for analyzing the hydrogen network as a whole is described, and guidelines are provided to manage the network effectively. Also discussed are hydrogen's role in refinery LP models and some approaches for determining refinery hydrogen's proper value.


The primary sources of hydrogen in a refinery are catalytic reformers, hydrogen plants and purchased hydrogen.

Catalytic reformers - operations. Operating conditions of the catalytic reformers (rates and severities) are typically set by overall refinery economics (the gasoline pool) rather than the need for hydrogen. Hydrogen yields are primarily a function of the properties of the feed naphtha, severity, catalyst and operating pressure.1,2,3 If the operating conditions are set by the Planning Department based on refinery-wide economics, there is little opportunity to improve hydrogen production through operating adjustments.

Hydrogen plants - operations. Hydrogen plants produce hydrogen primarily through the steam reforming and water gas shift reactions:

   CH4 + H2O 1 3H2 + CO (methane feed)

   CO + H2O 1 H2 + CO2

The reforming reaction is endothermic and equilibrium limited. Lower pressure and higher temperature favor higher conversion to hydrogen. Operating pressure is typically set by a practical hydrogen delivery pressure. Maximum temperature is constrained primarily by tube life and coking concerns. The steam-to-carbon ratio is a critical operating variable that affects conversion and coking.

Optimum operation is unique to each hydrogen plant because the constraints in each unit will be unique. If the refiner's goal is to minimize the per-unit cost of hydrogen rather than maximizing production, there will be a different optimum temperature and steam-to-carbon ratio. Since these optimum setpoints can change daily, as a function of rates and feed compositions, the operator should have the tools to optimize the reformer accordingly.4,5 All the skills required to operate a furnace efficiently and safely are critically important for hydrogen plant operations.

Increasing hydrogen production. In a catalytic reformer, a number of methods are available to increase hydrogen production. Obviously, hydrogen production may be increased by modifying equipment to enable increased charge rate. Also, hydrogen yields can be improved by: changing the naphtha feed to one more favorable for hydrogen production; decreasing pressure; or replacing the catalyst charge with one that provides a higher hydrogen yield.6,7 Large increases in hydrogen production can be achieved through pressure reduction by converting from fixed bed to continuous catalytic regeneration mode.

A low-cost (capital and operating) catalyst regeneration process has been developed for the majority of fixed bed reforming and stacked reactor reforming units to maximize hydrogen yields. This type of project can be quite attractive if the alternative is building a new hydrogen plant.

For hydrogen plants, a number of approaches exist to revamp for higher capacity. Increases of up to 25% are common. Debottlenecking may be achieved by mechanical modifications to remove equipment constraints, adding pre-reforming or adding post-reforming.8,9

Over-the-fence hydrogen supply. The make-or-buy decision is a relatively straightforward economic calculation. Non-economic issues such as reliability, long-term commitments and operating coordination need to be considered. The option to cogenerate electricity will also affect the economics.

An additional consideration is the availability of any hydrogen-containing streams currently going to fuel. These may be valuable to the hydrogen supplier either for hydrogen recovery (purification) or as feed to a hydrogen plant. If the refiner chooses not to recover this hydrogen himself, these streams can potentially be sold to the hydrogen supplier.


Hydrogen recovery. Look for hydrogen-containing streams, such as hydrotreater offgases or "excess" hydrogen streams that are currently being sent to fuel gas or hydrogen plant feed. The cost of hydrogen recovery can be as low as 50% of the production cost. Whereas the cost of generation is usually fixed for a certain location (primarily a function of energy cost), the cost of hydrogen recovery depends on many factors, such as fuel gas pressure and composition of the hydrogen-containing stream. In general, hydrogen recovery should be pursued for all streams with favorable economics. In some rare situations, additional constraints such as minimum/maximum hydrogen content of the fuel system must be considered.

Potential for debottlenecking purification units. If the additional purification needed is less than approximately 30% of the capacity of an existing hydrogen purification unit, a revamp is often the most cost-effective way to obtain the extra capacity. In many cases, it will be required to sacrifice either hydrogen purity or recovery against the increased capacity. Pressure drop over the unit may increase significantly and must be considered. Pre- and post-treatment equipment may also have to be revamped to cope with increased flowrates. Often more plot space will be needed.

Selecting purification technology. The three most commonly used processes for hydrogen purification are pressure swing adsorption (PSA), semipermeable membranes and cryogenic separation (cold box). These processes have been described in detail elsewhere.10 Important parameters to consider when selecting the hydrogen purification technology are:

  • Minimum purity of the hydrogen product. If a hydrogen product with a purity of 99 vol% or higher is required, PSA is the obvious choice. PSA is the only process capable of producing a hydrogen stream containing less than 10-ppmv carbon oxides, a typical requirement for catalytic processes. Membranes and cold boxes can produce hydrogen in excess of 95-vol% hydrogen content.
  • Pressure drop between feed gas and hydrogen. Effective membrane separation requires that the feed stream is available at a pressure two to five times the pressure of the permeate product (this is the driving force needed to let hydrogen permeate preferentially over other components). If this pressure ratio is not available, additional compression equipment is required. PSA and cold boxes have only minimal pressure losses between feed and hydrogen product.
  • Possibility of byproduct recovery. A cryogenic unit has the ability to deliver separate hydrocarbon byproduct streams. The offgas from membranes contains all the nonhydrogen components in a single stream close to feed pressure, so further separation is possible. Offgas from a PSA unit is at low pressure, making by-product recovery not cost-effective.
  • Delta cost between hydrogen product and feed gas. The larger the difference in value between hydrogen and fuel, the more capital can be expended on purification equipment. Each unit will have its own trade-off curve between cost (capital and operating) and recovery (ratio of hydrogen contained in the product stream over hydrogen contained in the feed stream). See section, "How much is hydrogen worth?," p. 46.
  • Capacity. Membranes are usually the lowest cost option for low product rates, but are rarely cost-effective for larger capacities, because the number of membrane elements is proportional to the hydrogen product rate. PSA units are built to produce from 5 to 100 MMscfd of hydrogen and more. The cost of a PSA unit for a small capacity is higher than that of a membrane unit, but PSAs have better economies of scale. Cryogenic separation is also expensive for small capacities, but has excellent economies of scale.

Purification design decisions. Once the technology has been selected based on the criteria mentioned above, there are further considerations. If a PSA unit is the technology of choice, the main question is: what tail gas pressure will the PSA operate at? The tail gas pressure is the pressure at which the adsorbent is regenerated. Lower tail gas pressure means higher recovery and capacity, but tail gas compression may be needed to operate at very low pressures. In most cases, the tail gas is discharged to the refinery fuel gas header, unless a dedicated low-pressure burner is available. The impact of high tail gas pressure on hydrogen recovery may be as much as 20% (Fig. 2).

Fig 2
 Fig. 2  

Effect of PSA tail gas pressure at a typical feed gas pressure.

The PSA unit produces high-purity hydrogen. Operating the PSA at lower purity will have a minimal effect on recovery. If lower purities are acceptable during certain periods, it is better to install a feed-to-product bypass around the PSA unit. Blend a fraction of the feed gas in the hydrogen product, if you can tolerate feed components in the hydrogen product. In this way, overall hydrogen recovery can be maximized at the lowest acceptable purity.

Although H2S does not present a problem for the PSA adsorbent, it is recommended that H2S be removed upstream of the PSA unit. The PSA unit will concentrate all H2S in the tail gas stream, which is compressed and sent to a fuel gas system. Besides environmental considerations, safety and metallurgy must be considered.

Membrane fibers are polymeric and can be damaged by aromatics condensation. During the separation process, hydrogen is preferentially drawn from the feed gas so the residue gas enriches in hydrocarbons. Heat the membrane feed gas above its dewpoint to avoid condensation during operation.

The fuel gas pressure of a cryogenic system determines the maximum achievable purity of the hydrogen product, and also fixes the purity/recovery relation. Again, a trade-off is to be made between additional compression of the tail gas stream going to fuel and increased hydrogen recovery. At typical operating pressures, a 10-psi increase in tail gas pressure can reduce recovery by 1%. Separate hydrocarbon streams with different boiling point ranges can be obtained by adding separators. A methane wash column is required if low boiling components such as CO or nitrogen are to be removed.10

Designing for compressor flexibility provides greater flexibility in utilizing purified streams. Modifications requiring compressor flexibility include changing the makeup composition (such as purifying recycle gas with a membrane purifier and dropping the permeate to makeup compressor suction) and the recycle purity (handling the change in recycle gas molecular weight through the recycle compressor).

Revamping existing purification units. After construction and startup, refinery objectives and hydrogen balances often change. If the capacity expansion is limited to 30% or less of installed capacity, relatively minor modifications to the existing unit can achieve the required capacity increase. There are several options.11 By modifying the process cycle, hydrogen recovery can be traded for hydrogen capacity. A 3% reduction in recovery can lead to a capacity increase of up to 20%, the net result being an increase in hydrogen production.

Improved hydrogen recovery of 1% to 2% can be achieved by high-performance adsorbents (depending on the installed charge of adsorbents). If the PSA unit operates at high tail gas pressure, lowering the tail gas pressure through the addition of a tail gas compressor can increase both capacity and recovery.

Membrane units can be expanded by simply adding membrane area. Recovery and purity can be maintained if the pressure levels around the membrane unit are kept constant. If permeate (membrane product) compression is added to enable reducing permeate pressure, hydrogen recovery and purity can be improved with the original membrane area. Increasing the outlet temperature of the feed superheater increases hydrogen recovery at the expense of lower purity. Expansion of membrane purifiers is facilitated if the pre- and post-treatment equipment are designed to accommodate future capacity expansion.

For cryogenic units, capacity increases can often be obtained by adding a fuel gas compressor without modifications to the cold box itself. The cost impact of initially designing the cold box for this type of expansion is low.10


Hydrotreaters and hydrocrackers consume hydrogen in a series of reactions converting organic sulfur and nitrogen compounds to hydrogen sulfide and ammonia. The hydrogen also reacts with the hydrocarbons in the oil, increasing the hydrogen-to-carbon ratio.

Hydrocracking reactions convert heavier oils to diesel and naphtha range materials. All of these reactions increase the products' value and contribute to the refinery's gross margin.

Hydrogen partial pressure both drives these reactions and suppresses unwanted coke formation. A minimum hydrogen partial pressure (usually measured as reactor inlet purity or recycle gas purity) is required to operate with a reasonable catalyst life and reactor temperature. The minimum hydrogen partial pressure is not a fixed value. It is a function of current operating conditions - charge rate, feed properties, desired product properties. Operating below minimum hydrogen partial pressure reduces catalyst life. Operating above the minimum hydrogen partial pressure typically requires an increase in total hydrogen supplied to the hydrogen network.

Makeup purity is often confused with hydrogen partial pressure. For a given set of operating conditions, hydrogen partial pressure is determined by the combination of makeup purity and purge flow. It is possible to adjust hydrogen partial pressure without modifying makeup purity. Conversely, it is possible to utilize a different makeup stream, with a different purity, and maintain the same hydrogen partial pressure. From the operator's point of view, hydrogen partial pressure can be adjusted by modifying the purge flow or modifying the streams used as makeup to adjust the makeup purity.

Thinking beyond the issue of minimum hydrogen partial pressure is critical. Operators should:

  • Regularly monitor the hydrogen partial pressure in key hydrotreaters and hydrocrackers
  • Have available hydrogen partial pressure targets that reflect current operating conditions and optimization of refinery gross margin
  • Adjust hydrogen partial pressures accordingly

For any set of operating conditions, there is an optimum hydrogen partial pressure. Since hydrogen partial pressure drives the reactions, increasing hydrogen partial pressure can enable increased charge rate, improved product properties or longer catalyst life. In hydrocrackers, it can enable improved yields, or greater conversion per pass. Therefore, increasing hydrogen partial pressure beyond the minimum can increase the refinery gross margin well above the additional hydrogen cost associated with increasing the hydrogen partial pressure. To maximize the profitability of these units, one must have a good understanding of the process characteristics and refinery economics. Detailed process models that reflect the performance of the units as a function of hydrogen partial pressure are required.

Methods to significantly improve hydrogen partial pressure include debottlenecking compression and adding H2S scrubbing of the recycle gas.


Hydrogen network analysis. One view of the hydrogen network is as a collection of nodes (producers and consumers) and the connections between them. Hydrogen pinch analysis is a mathematical technique to analyze the hydrogen network on this level.12 The analysis combines hydrogen requirements (quantity and purity) of each consuming unit, specified hydrogen production (quantity and purity) of each hydrogen producing unit and designation of one hydrogen producer as the swing unit, which will turn up or down to match the needs of the consumers.

The approach is similar to energy pinch, but is different in some key aspects. Hydrogen network pinch involves generating source and sink composite curves based on network definition, and a hydrogen surplus curve derived from the composite curves (Figs. 3 - 5). Analysis of the surplus curve provides the theoretical minimum hydrogen required from the swing producer (such as a hydrogen plant) to meet the needs of the network, assuming no constraints on how the units are connected.

Fig 3
 Fig. 3  

Composite curves.

Fig 4
 Fig. 4  

Surplus curve - current operation.

Fig 5
 Fig. 5  

Surplus curve-pinched.

This is a theoretical minimum hydrogen requirement. Modifications to the real network necessary to achieve this minimum might be as easy as opening and closing some valves, or as daunting as adding a new multistage compressor to connect low-pressure sources to high-pressure consumers. Intermediate modifications could be adding cascades between the purge of one unit and the makeup of another.

Additional tools beyond hydrogen pinch are required to design practical, efficient hydrogen networks.13 A hydrogen network model can be used. This model must represent the actual connectivity of the network, existing compressors, and hydrogen consumption, light ends generation and solution losses of each hydrogen consumer. With this tool, network modifications can be tested and new hydrogen balances generated.

This same model allows modifying operations to represent different cases and operating modes - including summer/winter and future operations - and adding new hydroprocessing units and hydrogen purifiers.

Hydrogen purification analysis. Hydrogen purification plays two roles in the hydrogen network. First, it can be used to upgrade streams that are currently going to fuel because they are too low in purity. Second, streams such as catalytic reformer hydrogen - which are currently used directly - can be purified to increase the partial pressure in reactors, debottleneck makeup compressors and/or reduce purge to fuel from hydroprocessing units.

Hydrogen pinch analysis requires all hydrogen purification to be completely defined as part of the network definition. Therefore it cannot directly define the optimum purification scheme. However, the pinch purity does provide clear direction as to which streams to consider for purification.

The most challenging aspect of purification analysis is selecting the optimal purification scheme and operating conditions. First, the purification technology (membrane, PSA, or on rare occasion, cryogenic) must be selected. Beyond technology selection, technical decisions - such as operating pressures, membrane area, membrane polymer, PSA cycle and PSA adsorbent mix -  all have key impacts on performance and cost. In the end, these factors must be considered in light of the conflicting criteria of capital cost, product purity, hydrogen recovery, compression requirements and operating flexibility. Good purification process models, a thorough understanding of purifier design and operations, and access to the hydrogen network model are essential to effectively optimize the purification scheme.

Consider modifications to both new and existing purifiers. Revamping existing equipment for increased throughput, different feed or improved recovery is often cost-effective.

Results of hydrogen network analysis. Where improvements in the hydrogen management system can be made is different for every refinery, but profitability improvements through better hydrogen management were identified in every one of the 25 refineries we have worked with. Improvements included:

  • Switching which streams are routed to the existing purifier
  • Routing low-purity hydrogen streams to the hydrogen plant
  • Better control of partial pressure (purge rates)
  • Improving pressure control to fuel
  • Revamping PSA for higher capacity
  • Increasing severity in a cat feed hydrotreater to increase FCC gasoline yield
  • Increasing throughput in the hydrocracker.14

One refinery identified over $6 million/year in hydrogen savings with no capital projects. Another avoided the capital cost of 20 MMscfd of new hydrogen plant capacity through much smaller investment in hydrogen recovery capacity. Table 1 provides an overview of hydrogen network improvement options.


Hydrogen networks should be operated so that:

  • Amount of hydrogen sent to fuel is minimized
  • Profitability of each process unit is maximized
  • Hydroprocessing catalysts are not exposed to hydrogen partial pressures below safe operating levels
  • Adjustments are made in response to day-to-day changes in the refinery.

Of course, every hydrogen network is different, but it is possible to offer some general guidelines that would serve every refinery well.

If it's important, measure it. If you don't know how much hydrogen is going to fuel, you can't minimize it. If you don't know the recycle purity in your hydrocracker, you can't optimize it. So, if you want to take control of your hydrogen network:

  • Make sure you have reliable meters on important flows.
  • Where practical or critical, put online analyzers on recycle streams and around purifiers.
  • Do whatever it takes to get lab samples in a timely and reliable manner when the life of your catalyst is at stake, or when you are reducing charge rates because you are wasting hydrogen due to running the hydroprocessing unit vents too conservatively.

If controllers are putting hydrogen to fuel, do something. Some refineries continually dump high-purity hydrogen to fuel through pressure control valves in order to maintain the refinery hydrogen balance. There must be a better way!

Look for other streams to control with. Look for other places to put the control flow besides fuel. Look for ways to reduce the amount of control flow. Improvement may be found in better control schemes, improved regulatory control or some advanced control. Don't accept at face value that "We have to waste this much hydrogen."

Get everybody thinking in dollar terms. Operators, technical staff and management should think and see dollars when they see the Hydrogen Network Daily Report. The hydrogen in the fuel system should be reported in units of dollars/day. So should the: hydrogen plant production; opportunity cost of turning down the hydrocracker because of a hydrogen supply constraint; and increased cetane number in the diesel hydrotreater product due to higher partial pressure.

Convert setpoints to dollars in the operator's mind, and he or she will control dollars. Represent hydrogen network problems to management in dollar terms, and they will find the resources to fix them.

Use meaningful hydrogen partial pressure targets. Too-low hydrogen partial pressure can reduce hydroprocessor performance (profitability) and, at worst, damage the catalyst. Higher than optimum hydrogen partial pressure often results in higher network hydrogen requirements (costs). Not all hydroprocessing units are the same. Some are relatively insensitive to recycle purity, have robust catalyst, involve a relatively easy reaction and don't directly generate a lot of profit. Critical hydroprocessing units are just the opposite.

If hydrogen partial pressure matters, then:

  • Measure it.
  • Establish a manual or automated control scheme to adjust the makeup and/or purge to control it.
  • Establish a target recycle purity.
  • Modify the recycle purity target as feed properties, feed rates or desired product specifications change.
  • Let operators know how well they are controlling hydrogen partial pressure, in terms of dollars/day.

Always consider the big picture. In most refineries, the hydrogen network covers most operating areas. Changes in one operating unit will affect the hydrogen availability or purity in the other end of the plant. Operating changes that affect the network should be made based on what is most profitable for the refinery as a whole. Optimum use of hydrogen cannot be achieved if each unit is operated independently. Operators must communicate about actions that affect the network. Tools and policies must be in place to help optimize the network as a whole, rather than as individual units.

Putting it all together. Combine the hydrogen network and process models with online data, an understanding of refinery economics, objective function and a nonlinear solver. The result is an online optimizer that will recommend operator actions to protect catalyst, use hydrogen efficiently and maximize refinery profitability.


Managing your hydrogen network requires understanding the value of hydrogen to your refinery. You need this number to evaluate hydrogen network improvement projects and to make day-to-day hydrogen network decisions. Hydrogen's value is a function of the refinery's current and future hydrogen situation. Generally, the hydrogen situation falls into one of the following categories:

  • Catalytic reformers produce enough hydrogen to satisfy all the users; there is no hydrogen plant or purchased hydrogen. In this case, hydrogen should be valued at fuel value.
  • Refinery is not constrained by hydrogen availability; hydrogen production and/or purchase is required to meet the hydrogen balance. In this case, the hydrogen's value is the production/purchase cost of incremental hydrogen.
  • Refinery modifications are being planned that will require more hydrogen than is currently available. In this case, hydrogen is valued not at its marginal production cost, but at its fully loaded cost, including capital charges for a new hydrogen plant. Hydrogen recovery projects are extremely attractive in this situation.
  • Refinery is constrained by hydrogen availability; at least some of the time, charge rates and severities are adjusted in hydroprocessing units due to limited hydrogen supply. In this case, hydrogen's value is determined by the opportunity cost of constraining the hydroprocessing units. This can be calculated by adjusting the hydrogen constraint in the refinery LP model and determining the hydrogen marginal value. In this situation, hydrogen usually has much greater value than in the other cases.

The opportunities to make process improvements through optimized hydrogen partial pressure can impact hydrogen valuation, so valuation may not be quite this simple.


If the refinery is hydrogen-limited, planning tools (LP) must accurately reflect the impact of crude properties and unit operating conditions on hydrogen consumption, vent flows and purities. Inaccurate modeling of hydrogen production, consumption and vents can lead to incorrect valuation of crudes or refinery operating modes. For example, different crudes and cutpoints will affect the chemical hydrogen consumption in a diesel hydrotreater or the hydrogen yield in a catalytic reformer.

Equally important, the purge flow on this hydrotreater may have to be increased to maintain the desired hydrogen partial pressure. The increased purge results in increased makeup flow, which also needs to be represented in the LP hydrogen balance. If the real-life hydrogen constraints are different than those modeled in the LP, then actual process unit throughputs and product qualities will also be different from planned. HP


1 Dachos, N., A. Kelly, D. Felch and E. Reis, "UOP Platforming Process," Handbook of Petroleum Processes, Robert A. Meyers, ed. 2nd edition, McGraw-Hill, New York, 1997.

2 Wier, M.J., J. Utley, J. Elstein and D. Schwake, "Strategies for Maximizing Profits from Catalytic Reforming Units," NPRA Annual Meeting, March 1998.

3 Rachford, R. H. and N. j. Gilsdorf, "The Platforming Process in the Reformulated Gasoline Era," NPRA Annual Meeting, March 1992.

4 Broadhurst, P. V. and P. E. J. Abbott, "Improving Hydrogen Plant Performance, Part I," Petroleum Technology Quarterly, Summer 2002, p. 130.

5 Broadhurst, P. V. and P. E. J. Abbott, "Improving Hydrogen Plant Performance, Part II," Petroleum Technology Quarterly, Autumn 2002, p. 137.

6 Fecteau, D. J., "Revamp Engineering Update," 1998.

7 Beshears, D. R., "CCR Platforming Catalyst Selection Improves Unit Flexibility and Profitability," NPRA Annual Meeting, March 2000.

8 Cromarty, B., C. W. Hooper and K. Chlapik, "Cost-Effective Uprating of Existing Hydrogen Production Units," NPRA Annual Meeting, March 1994.

9 Fleshman, J.D., "Cost Efficient Revamps in Hydrogen Plants," Petroleum Technology Quarterly, Summer 2001, p. 83.

10 Miller, G.Q. and J. Stoecker, "Selection of a Hydrogen Separation Process," NPRA Annual Meeting, March 1989.

11 Picioccio, K. and E. Reyes, "Breaking the Barrier with PSA Revamps," Petroleum Technology Quarterly, Spring 2000.

12 Alves, J.J., "Analysis and Design of Refinery Hydrogen Distribution Systems," PhD thesis, UMIST, Manchester, UK, 1999.

13 Zagoria, A., G. P. Towler, B. M. Wood and F. M. Hibbs, "If You Are Burning H2, You Are Burning Money," NPRA Annual Meeting, March 1999.

14 Ciolek, W.H., "Hydrogen Management - It's For Every Refiner," AIChE Spring National Meeting, April 2001.


Alan Zagoria is a senior engineering consultant with the Solutions and Services Department of UOP LLC in Des Plaines, Illinois. For the past five years, he has led UOP's Hydrogen Management Group, assisting refiners around the world in tackling the challenges of meeting clean fuels requirements. Mr. Zagoria has worked for UOP/Union Carbide for more than 25 years. Most of his work has been in the area of hydrogen purification. Within that specialty he has lead UOP's efforts in process development, process design, control system design and field services. He earned a BS in chemical engineering from Northwestern University. He can be reached at Alan.Zagoria@uop.com.


Rudolf Huycke joined UOP in 1991 and is manager of the Process Engineering Department of UOP N.V. in Antwerp, Belgium. He is accountable for optimizing hydrogen purification schemes, process design and development, control systems programming and startup activities of hydrogen purification equipment for the refining and petrochemical industry. Mr. Huycke holds an MS in chemical engineering from the University of Ghent, Belgium, and can be reached at Rudolf.Huycke@uop.com.

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