Friday, June 10, 2011

Benefits of Biodiesel

Environmental Benefits

In 2000, biodiesel became the only alternative fuel in the country to have successfully completed the EPA-required Tier I and Tier II health effects testing under the Clean Air Act.  These independent tests conclusively demonstrated biodiesel’s significant reduction of virtually all regulated emissions, and showed biodiesel does not pose a threat to human health. 

Biodiesel contains virtually no sulfur or aromatics, and use of biodiesel in a conventional diesel engine results in substantial reduction of unburned hydrocarbons, carbon monoxide and particulate matter.  A U.S. Department of Energy study showed that the production and use of biodiesel, compared to petroleum diesel, resulted in a 78.5% reduction in carbon dioxide emissions.  Moreover, biodiesel has a positive energy balance.  For every unit of energy needed to produce a gallon of biodiesel, at least 4.5 units of energy are gained.

Energy Security Benefits 

With agricultural commodity prices approaching record lows, and petroleum prices approaching record highs, it is clear that more can be done to utilize domestic surpluses of vegetable oils while enhancing our energy security.  Because biodiesel can be manufactured using existing industrial production capacity, and used with conventional equipment, it provides substantial opportunity for immediately addressing our energy security issues.

If the true cost of using foreign oil were imposed on the price of imported fuel, renewable fuels, such as biodiesel, probably would be the most viable option.  For instance, in 1996, it was estimated that the military costs of securing foreign oil was $57 billion annually.  Foreign tax credits accounted for another estimated $4 billion annually and environmental costs were estimated at $45 per barrel.  For every billion dollars spent on foreign oil, America lost 10,000 – 25,000 jobs.
Economic Benefits  
The biodiesel industry has contributed significantly to the domestic economy.  The 51,893 jobs that are currently supported by the US biodiesel industry reflect the beginning of the industry’s potential to create jobs and economic growth in the US economy.  Biodiesel has added $4.287 billion to the Gross Domestic Product (GDP). 
Biodiesel has the potential to support more than 78,000 jobs by 2012.  A stable, thriving biodiesel industry is necessary if the U.S. is to eventually benefit from the commercial scale production of algal-based biofuels.  The NBB estimates that for every 100 million gallons of biodiesel that is produced from algae, 16.455 jobs will be created and $1.461 billion will be added to the GDP.   Quality Benefits

Biodiesel is registered as a fuel and fuel additive with the EPA and meets clean diesel standards established by the California Air Resources Board (CARB).  B100 (100 percent biodiesel) has been designated as an alternative fuel by the U.S. Department of Energy and the U.S. Department of Transportation.  Moreover, in December 2001, the American Society of Testing and Materials (ASTM) approved a specification (D675) for biodiesel fuel.  This development was crucial in standardizing fuel quality for biodiesel in the U.S. market.  As of 2008, there is a specification for B6-B20, and up to B5 is included in the diesel fuel specification (D 975).  

The biodiesel industry also utilizes a voluntary quality management certification program for biodiesel producers, marketers, and laboratories called the BQ-9000 Program.  The BQ-9000 Program combines internationally accepted quality management principles with the ASTM biodiesel fuel specification to help ensure that customers and end users get the highest quality fuel possible.  The National Biodiesel Accreditation Commissions issues ‘BQ-9000 Marketer,’‘BQ-9000 Producer’ and 'BQ-9000 lab' certifications for biodiesel marketers and/or producers and biodiesel testing laboratories that have met all requirements of quality management system certification program.  BQ-9000 companies are subject to annual third-party audits to verify their continued compliance with the program requirements.  The BQ-9000 program provides added assurance to customers, as well as engine manufacturers, that the biodiesel marketed by these companies meets the ASTM standards for biodiesel and that the fuel supplier will stand behind its products.  

EPAct Benefits

Effective November 1998, Congress approved the use of biodiesel as an Energy Policy Act (EPAct) compliance strategy.  The legislation allows EPAct-covered fleets (federal, state and public utility fleets) to meet their alternative fuel vehicle purchase requirements simply by buying 450 gallons of pure biodiesel and burning it in new or existing diesel vehicles in at least a 20% blend with diesel fuel.  The Congressional Budget Office and the U.S. Department of Agriculture have confirmed that the biodiesel option is the least-cost alternative fuel option for meeting the Federal government’s EPAct compliance requirements.  Because it works with existing diesel engines, biodiesel offers an immediate and seamless way to transition existing diesel vehicles into a cleaner burning fleet.

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Thursday, June 9, 2011

Steam Systems

Generating steam is the primary function of most boiler systems. In some industries, where 40-60 percent of all energy is consumed in the generation of steam in fired or wasteheat boilers, efficient operation and regular maintenance can represent a great potential in energy savings.
Industrial Steam Trapping Handbook
For instance, in the absence of an effective maintenance program, it’s common to find 15 to 20 percent of steam traps not working properly. Another energy-waster is to allow steam leaks to persist, reducing steam production by as much as three to five percent. Insulation deterioration can cause another 5 to 10 percent steam loss during rain storms, as the insulation gets wet and loses its effectiveness. Fouled turbines and exchangers can cause as high as a 25 percent efficiency loss.
In a discussion on steam systems, many over-laps may occur when addressing maintenance and operation procedures. For example, Chapter 2, Water Treatment, discusses the addition of amines to keep the pH of the condensate high, avoiding acid attack. In this chapter, that subject is related to corrosion in steam traps, a specific problem area in steam systems.
Besides its use and subsequent availability in numerous industrial processes and also in generating electricity, steam is also employed to drive pumps and compressors as well as providing freeze protection for winter operations. Steam system operation is complex because of its generation, distribution, recovery and use at several different pressure levels.
There are five general “rules” that should be followed for maximum efficiency in steam generation. They are:
1.     Always produce steam at the highest possible temperature and pressure. This is a basic thermodynamic and economic principle.
2.     Always apply steam to process use at the lowest possible pressure and temperature levels.
3.     In fired boilers, only produce steam for valid end uses, such as process steam and reboilers.
4.     Always expand steam from a higher pressure level to a lower pressure level through the most efficient means possible.
5.     Always produce maximum steam from process wasteheat recovery systems.

Proper steam system design will greatly increase operational efficiency. Poorly designed steam traps are the ones mot likely to function improperly or fail completely. Steam Tracing systems (a system designed to monitor steam temperature on a process pipe, for example), frequently evolve in a hap-hazard manner, often to solve a short-term problem, such as a steam trap that doesn’t work. Leaks, freezing, steam system dead-ends and equipment damage can all be consequences of improper design. Heat loss can be avoided by proper insulation design and maintenance.
Because there are so many different potential problem areas to address, it is helpful segregate as many of them as possible in common groups.
General Operational Procedures
1.     Process analyzers and advanced control techniques should be employed to minimize energy consumption of plants. Many plants use feed preheaters to supply heat for operation. Significant energy savings can be associated with system optimization. Specific operating control targets should be employed with energy conservation in mind.
2.     Improperly operated vacuum systems can significantly increase steam usage. Any leaks that develop should be repaired.
3.     Every operating area should have checklists and Standard Operating Instructions (SOIs) to ensure that unneeded steam traps and tracing systems are turned off as they can be a significant source of steam usage. Tracing systems are routinely left on year-round but are only needed during the colder months.
4.     Steam consumption targets and guidelines should be established at all facilities and for all major pieces of equipment. Targets should be routinely adjusted for process feed-rate changes. Target consumption should be plotted relative to load (load curves). The goals should be to operate the plant on these load curves.
5.     Each steam generator should be rated according to its performance characteristics or efficiency. That way, during a period of in-creasing steam demand, the most efficient generators can be loaded first, keeping energy consumption to a minimum while getting the most steam out of the most efficient systems. Also, where options exist and there is flexibility, the most efficient systems should be used first.
6.     Steam systems should be surveyed routinely to identify seldom-used steam lines which could be removed from service. Adjustments to systems should be made as dictated by plant steam requirements. If not automated, these adjustments should be described in a set of clearly stated, written instructions to the operator.
6.     Steam tracing systems should be held to an absolute minimum, as their use can down-grade overall steam distribution efficiency. Alternatives to steam tracing should be investigated, such as electrical heating tapes for remote locations where the monitoring of a steam tracing system would be impractical.
7.     Steam distribution and condensate systems should be designed so that effective corrosion treatment systems can be employed. See Chapter 2, Water Treatment, for information on these treatment systems.
8.     Steam systems should also be designed with adequate metering to be able to keep track of where the steam is going and to routinely get facility-wide and individual process-unit steam balances.

Steam Traps
1.     Every operating area should have a program to routinely check steam traps for proper operation. Testing frequency depends on local experiences but should at least occur yearly.
2.     All traps should be numbered and locations mapped for easier testing and record-keeping. Trap supply and return lines should be noted to simplify isolation and repair.
3.     Maintenance and operational personnel should be adequately trained in trap testing techniques. Where ultrasonic testing is needed, specially trained personnel should be used.
4.     High maintenance priority should be given to the repair or maintenance of failed traps. Attention to such a timely maintenance procedure can reduce failures to three to five percent or less. A failed open trap can mean steam losses of 50-100 lb/hr.
5.     All traps in closed systems should have atmospheric vents so that trap operation can be visually checked. If trap headers are not equipped with these, they should be modified.
6.     Proper trap design should be selected for each specific application. Inverted bucket traps may be preferred over thermostatic and thermodynamic-type traps for certain applications.
7.     It is important to be able to observe the discharge from traps through the header. Although several different techniques can be used, the most foolproof method for testing traps is observation. Ultrasonic, acoustical and pyrometric test methods often suggest erroneous conclusions.
8.     Traps should be properly sized for the expected condensate load. Improper sizing can cause steam losses, freezing and mechanical failures.
9.     Condensate collection systems should be properly designed to minimize frozen and/or premature trap failures. Condensate piping should be sized to accommodate 10 percent of the traps failing to open.

1.     Systems should be regularly surveyed to re-place or repair missing and deteriorated insulation. This is especially important after insulation has been removed to repair steam leaks.
2.     An overall survey of steam lines should be conducted every five years (or one fifth of the facility per year) to identify areas where insulation or weatherproofing has deteriorated. Typical culprits include prolonged exposure to moisture, chemicals or hydrocarbons. Instruments to measure the effectiveness of insulation include thermographic (heat image) devices. This instrument gives an indication of surface temperatures by displaying various colors. It is ideal for large areas. Others include portable infrared pyrometers, or heat guns, that measure surface heat by infrared wave emitted from the surface and contact-type pyrometers and surface crayons, which must be in contact with the surface to measure heat.
3.     Following any maintenance work, areas where work has been performed should be inspected to see where insulation should be repaired or replaced. Removable insulation blankets should have been reinstalled on all equip- ment. The last step in any maintenance work should be the repair, replacement or reinstallation of insulation. System components often overlooked and left uninsulated include valves, turbines, pumps and flanges.
4.     Optimal insulation thickness should be applied to any new piping systems.
5.     During steam line surveys, insulation should be visually inspected for the following defects:
·         Physical damage
·         Cracks in vapor barriers
·         Broken bands or wires
·         Broken or damaged
·         weather-tight jointseals
·         Damaged covers and
·         weatherproofing

1.     All steam leaks should be repaired as quickly as possible. Leaks are one of the most visible forms of energy waste. The table in Figure 27 shows steam loss at pounds per hour, for a given sized hole, at a given pressure. Steam leaks can also suggest management indifference to efficient operation and pose significant safety hazards. Steam leaks don’t get smaller, neither does the cost of fixing them.
2.     Standard procedures should dictate that proper gaskets and packing are used in steam system flanges and valves.
3.     An on-stream, leak-repair specialist should be employed to repair leaks when the steam system cannot be taken down.
4.     All steam systems should be designed for minimum leakage. For example, flanges and threaded piping should be minimized.

1.     There are large incentives to use steam at its lowest possible pressure for heating, primarily to reduce energy consumption. Process or equipment changes will often allow the use of lower steam pressure. These considerations are part of the plant initial design phase and any changes recommended should undergo an economic analysis to justify process or equipment changes.
2.     The utilization of steam at all pressure levels should be maximized. High pressure steam should not be reduced in pressure through control valves and low pressure steam should not be vented. Typically, there are large in centives to eliminate steam venting and pressure letdown. A significant reduction in fuel cost is perhaps the largest incentive. Instrumentation should be designed to continuously monitor steam pressure letdown and venting. In short, all steam systems should be balanced.
3.     Reboilers and steam preheaters should use only the lowest steam pressure possible. This can often be done by using extended tube surfaces, nucleate boiling tubes and lower tower pressures.
Tabel : Estimate of steam losses
Special Notes on Turbines
1.     Steam turbines should always be operated at the lowest back pressure possible. In topping turbines, high back pressure can be caused by inadequate piping or high steam consumption from declining turbine efficiency. A high pressure drop between the turbine exhaust and the steam header could mean the piping is restrictive. In condensing turbines, high back pressure can be caused by vacuum system problems.
2.     Condensing turbines are not very efficient as they tend to lose energy and utilize only 15 to 20 percent of the available steam thermal energy. At some point, consideration should be given to replacing these turbines with top-ping turbines, electric motors or direct-drive gas turbines.
3.     Low turbine efficiency is often the result of blade fouling. Fouling is usually a result of water that has not been treated properly. See Chapter 2, Water Treatment, for further recommendations. Water-washing turbines on-stream will often restore their efficiency. Improperly treated feedwater can also cause permanent long-term damage to boiler waterwall surfaces and superheater tubes.

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Wednesday, June 8, 2011

Don't Send Money Down the Drain

Driving energy savings through key solutions to condensate management.

Energy consciousness and environmental awareness have transformed condensate from an inexpensive byproduct of steam distribution to a valuable resource that can substantially reduce operating costs. For process systems that use steam as the heat transfer media, improved condensate management can enhance the overall system performance and longevity.

Condensate is a ready-made supply of recoverable energy. Typical chemical-process plants should be able to recover over 60% of the condensate produced in their steam systems. Unfortunately, traditional system design and installation practices are in many cases inadequate for insuring positive condensate drainage. As a result, the condensate is either drained to waste, or the performance of the heat exchanger is diminished.

Making simple changes in system design, along with following practical management steps, can offer significant financial returns while also increasing heat exchanger performance and integrity.

Condensate-recovery challenges
In any steam distribution system in a process plant, such as the one represented by Figure 1, the condensate requires some means of motive pressure to be returned to the boiler plant. The motive pressure either is a result of the supply-steam pressure, or is generated by a mechanical pump. In either case, the motive pressure must always be greater than the condensate return backpressure to guarantee continuous drainage.
The two most common piping designs for heat-exchanger condensate drainage consist of incorporating a level-actuated collection pot or utilizing a steam trap. In both cases, the equipment is directly piped to the condensate return system and, accordingly, is affected by the return line backpressure.

The level-actuated collection pot is a common choice for large, high-capacity, heat-exchange vessels such as reboilers (both positive pressure and vacuum) and shell-and-tube designs. The condensate level in the collection pot, controlled by an actuated drain valve, can be constant or variable. The constant-level version incorporates a modulating steam valve for process-side temperature control, whereas the variable-level system uses a constant-pressure steam valve and varies the exposed heat exchanger surface area by flooding the vessel with condensate. While both options provide process temperature control, neither is without potential performance and equipment integrity problems.

Constant-level pot: The constant-level design relies on varying the steam pressure and volume to maintain the desired process temperature requirements. The problems occur as the supply steam control valve throttles closed with the thermal requirements decrease from startup conditions This, in turn, decreases the steam pressure and volume, which leads to an even lower available condensate motive pressure. To make matters worse, if the steam valve throttles closed to the point that the pressure in the heat exchanger is less than the condensate backpressure, the heat exchanger will unintentionally flood. This decreases thermal performance and can lead to corrosion (carbonic acid from cooled condensate), surface pitting (accelerated by trapped non-condensable gases), and potentially compromising the structural integrity of the tubes and tube sheet through stress cracking and water-hammer.

Variable-level pot: To avoid low-pressure problems that can occur with a constant-level, modulated supply-steam control system, many heat exchanger systems are designed to flood for process temperature control. Instead of the process temperature actuating the supply steam control valve, a condensate drain valve is modulated to expose or flood the heat exchanger surface area while maintaining a constant supply-steam pressure to the vessel. As the thermal requirements decrease, the condensate drain valve throttles closed to back up condensate into the vessel, effectively decreasing the surface area for heat transfer. This is similar to the unintentional flooded condition occurring with a constant-level design, except that the constant steam pressure creates a positive motive pressure for condensate return. Nevertheless, the detriment to the system, corrosion, vessel life and structural integrity, still exist, just as in the constant-level installations.

Conventional steam traps: Steam traps are widely employed to drain condensate and vent noncondensable gases from heat exchangers. Because the internal mechanism performs as a discharge control valve, the steam trap inherently operates in a manner comparable to that of a condensate system with a constant-level collection pot.
Thus, a system employing a conventional steam trap is subject to operating conditions similar to those described for exchangers that employ collection pots. With adequate steam pressure to overcome the condensate return backpressure, the heat exchanger will perform with optimal efficiency. But if the supply-steam control valve throttles closed due to a decrease in thermal requirements, the available condensate motive pressure decreases, and the condensate backs up and floods the vessel. As with the collection pot, the heat exchanger loses performance and is subject to corrosion and structural damage.

The recurring theme of the aforementioned operating scenarios is that adequate pressure is required for to overcome the condensate-return-line backpressure, ensuring complete drainage and noncondensable-gas venting from the heat exchanger. Admittedly, a quick remedy for a flooded vessel is to drain the condensate (and vent the gases) by opening valves to the atmosphere (Figure 2). Obviously, though, this remedy wastes thermal energy and creates a potential safety hazard.
Solving the problem
The preferable solution consists of incorporating a mechanically actuated pumping device driven by air, other gas, or steam, called a pump trap, into the system (Figure 3), to isolate the heat exchanger from flooding and to insure sufficient condensate pressure to overcome the return-line backpressure. This approach will keep the heat exchanger operating at optimal efficiency while assuring its structural integrity.
The installation of such a device in a closed-loop arrangement allows process unit to maintain a dry heat exchanger regardless of the chest pressure, condensate rate, or efficiency of the tube bundle. The main benefits of this system solution are the elimination of tube bundle corrosion and potential tube failure, both of which could cause an upset condition and production interruption. But furthermore, because complete condensate removal from the heat exchanger is assured, the plant can take advantage of all of the surface area in the bundle; this capability may allow the heater to run at its lowest possible pressure, which minimizes energy consumption due to the latent heat content of lower-pressure steam.

In new process plants, the installation of a pump trap, rather than a conventional centrifugal or positive-displacement pump, on process heat exchangers can lead to savings on installation costs. For one thing, net positive suction head (NPSH) is critical for those heat exchanger systems that operate under vacuum and employ conventional pumps, because such pump are subject to cavitation. For that reason, heat exchangers that are to be outfitted with conventional pumps are often elevated to extreme heights to allow for proper drainage. Some systems may require a 40-foot elevation to drain a conventional condensate pot. But with pump traps employed instead, such heights are not necessary, because those traps are immune to the cavitation. Use of pumps traps thus can often lead to significant capital-cost savings, by reducing the skirt height required for exchangers or reboilers — sometimes to as little as 4 ft. (Figure 4).
Pump traps offer other benefits that collection pots or conventional steam traps do not. Complete, effective removal of condensate under all operating conditions allows a heat exchanger to operate at peak efficiency by reducing corrosion on the tube bundle, while also lessening the potential for destructive water hammer. Likewise, as noted above, allowing a heat exchanger to operate at its lowest possible chest pressure while maintaining a consistent outlet process temperature profile minimizes energy consumption.

Other aspects of condensate management
Condensate management requires a holistic, turnkey approach to realize significant energy savings. In addition to the recommendations discussed up to now, here are a few practical pointers:
Return-line sizing: The size of condensate return lines is a critical design factor. Because steam is a vapor, it requires more volume per unit of mass than does a liquid (such as condensate). Return lines must be adequately sized to account not only for the movement of liquid condensate, but also for the presence of live and flash steam. The receiver vent lines also need to be sized accordingly, to reduce the condensate return temperature to acceptable levels and avoid damage to condensate return pumps.

Steam traps: Aside from the condensate return issues discussed earlier in this article, every system also needs to have the right type of steam trap for the application, as well as a sufficient number of traps installed at proper intervals to remove condensate as quickly as possible. The general rule of thumb is that traps should be located at 100- to 300- foot intervals. Determining the right trap depends on a number of variables; but in general, the mechanical, inverted-bucket steam traps usually prove to be the best solution as they allow continuous drainage of condensate.

Condensate collection assemblies: These assemblies, which bring together multiple valves into one central location, may be advantageous; they help reduce the number of individual condensate collection points along the line. Additional benefits include reductions in installation costs and space requirements, as well as an increased accessibility to equipment for routine maintenance and repairs.

Thermal insulation: Insulating distribution and condensate return lines can pay big dividends; in fact, it can reduce energy losses by 90%. Any surface over 120°F should be insulated.

Smart management: Simple but intelligent management practices, such as establishing a routine steam trap inspection and maintenance program are also an essential part of maximizing condensate recovery and return. Fuel savings exceeding 10% can be achieved through an effective trap management program alone.

by: Brian Kimbrough and Steve Ashby

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Wednesday, June 1, 2011

Refinery Hydrogen Management - The Big Picture

by Alan Zagoria, Solutions & Services

Refiners today are finding that hydrogen 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, often enabling the refiner to avoid the capital cost of new hydrogen  production.
The hydrogen system consists of producers, purification processes, consumers, and the distribution network itself. Daily operating decisions impact the performance of the hydrogen network and therefore profitability.
There are tools and techniques available to manage each of these individual hydrogen network components. However, when you consider the refinery as a whole, instead of individual process units, there is much greater opportunity to impact the refinery profit. The key is to focus on the effect of hydrogen on the performance of hydroprocessing units, and therefore gross margin, to unlock significant profit improvement opportunities.
Hydrogen Producers
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. Since 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. The optimum operation (temperature, steam to carbon ratio) 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 is 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.
Increasing Hydrogen Production
In a catalytic reformer, there are a number of methods 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. Large increases in hydrogen production can be achieved through pressure reduction by converting from fixed bed to continuous catalytic regeneration mode. This type of project can be quite attractive if the alternative is building a new hydrogen plant.
For hydrogen plants, there are a number of approaches 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.
Hydrogen Recovery
Hydrogen recovery is typically much less expensive than hydrogen production. Look for hydrogen-containing streams, such as hydrotreater off-gases or “excess” hydrogen streams that are currently being sent to fuel gas or hydrogen plant feed.
Hydrogen recovery is typically accomplished using either membrane or PSA technology. The optimum purification scheme takes into consideration feed stream compositions and pressures, required product purity and pressure, and the economic trade off of product purity vs. hydrogen recovery.
Debottlenecking existing purification units is often a very attractive way to increase hydrogen recovery. Debottlenecking of PSAs can be achieved through inexpensive cycle modification, adsorbent change, reduction of tail gas pressure, or additional beds. Membrane purifiers are typically debottlenecked by adding more membrane cartridges or pressure changes.
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.
It is critical to think beyond the issue of minimum hydrogen partial pressure. 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.
Best Practices for Hydroprocessing Operations
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
Hydrogen Network Improvements
Hydrogen Network Analysis
The minimum hydrogen requirements for any given set of hydrogen consumers and producers can be determined using a new technique called Hydrogen Pinch Analysis. The analysis combines the hydrogen requirements (quantity and purity) of each consuming unit, the 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. The analysis 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. This is a theoretical minimum hydrogen requirement.
Additional tools beyond hydrogen pinch are required to design practical, efficient hydrogen networks. A hydrogen network model can be used for this purpose. This model must represent the actual connectivity of the network, existing compressors, and the hydrogen consumption, light ends generation, and solution losses of each hydro gen consumer. With this tool, network modifications can be tested and new hydrogen balances generated. This same model allows modification to operations to represent different cases and operating modes, including summer/winter and future operations, and the addition of new hydroprocessing units and hydrogen purifiers.
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 twenty five refineries we have worked with to date. 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 the PSA for higher capacity
·         Increasing severity in a cat feed hydrotreater to increase FCC gasoline yield
·         Increasing throughput in the hydrocracker
One refinery has identified over $6MM/year in hydrogen savings with no capital projects. Another was able to avoid the capital cost of 20 MMSCFD of new hydrogen plant capacity through much smaller investment in hydrogen recovery capacity.
As a leading supplier of refining technology, and a supplier of over 700 Polybed™ PSA systems and Polysep™ membrane systems in hydrogen purification service, UOP has in-depth knowledge of hydrogen producing, consuming, and recovery processes, and is uniquely qualified to support every refiner’s hydrogen management program. _

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