Friday, November 11, 2011

Flue Gas Treatment

Treating flue gas minimizes or eliminates both the environmentally unacceptable nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions as well as the collecting of unburned solid particles before they escape into the atmosphere. Both techniques involve a number of steps

NOx Reduction Techniques

Fuel Selection
Control of NOx pollutants begins with the proper fuel selection. A coal with a sufficiently low fuel nitrogen (less than 1.5%) as shown in a routine fuel analysis may eliminate the need for any NOx reduction techniques. Natural gas has no nitrogen in the fuel; fuel oil typically has a lower nitrogen content than coal. Coal reactivity may also be decreased to slow down combustion and decrease temperatures to minimize NOx production. Lower flame temperatures will result in a lower level of NOx production in oil and gas-fired systems. Boiler systems that have highly turbulent flames and high temperature furnaces usually need lower fuel nitrogen than is normally available in the required quantities. Reduction techniques would then be needed.

Furnace Sizing
This step is only practical if a new facility is planned. By increasing the furnace cooling surface, the high temperature and time aspects of NOx production can be reduced. Another benefit is the increased flexibility in coal purchasing especially in specifications and price.

Burner Selection
Selecting a burner relative to furnace size limits the oxygen availability to form NOx while simultaneously shaping the flame to minimize the 2800 degree residency time. This permits the use of moderate and low-nitrogen coal and meeting NOx emission regulations. This method generally produces good results.

Low Excess Air Combustion
This technique also limits the availability of oxygen and increases the efficiency of a high-turbulence burner. There is little change in the 2800-degree residency time and only fair results can be expected. Also, when this technique is used, a fairly complex series of controls must be installed to maintain the best combustion. Coal ash problems may also arise due to the reduced oxygen levels.

Two-Stage Firing
This technique also limits oxygen availability by adding excess oxygen, needed for complete combustion, through overfire air ports. The rate of combustion is lessened and the 2800 degree residency time is decreased. It produces good results with moderate-to-high fuel nitrogen coals. There is the possibility of decreased carbon burnout and furnace heat absorption and an increase in fireside deposits and potential corrosion.

Off-Stoichiometric Firing
This method also limits oxygen availability and flame temperature but for different levels of burners on large units. It is fairly successful and easily applied to existing units. As in the two-stage firing technique, there can be carbon loss and increased slagging.

Flue Gas Recirculation
This method takes advantage of the reaction that tends to drive fuel nitrogen towards N2 in the presence of NO. With NO present, there is a tendency to minimize the formation of thermal NOx by driving the reaction toward the more stable N2. This is a “last resort” technique when regulations must be met with high-nitrogen coal. It is the most effective method but it is the most expensive and difficult to install. Combustion control equipment and operating requirements with fans, ductwork and air balancing increase the complexity and can create problems.

Selective Non-Catalytic Reduction (SNCR) and Selective Catalytic Reduction (SCR)
There are two types of SNCR control technologies for retrofit to industrial boilers; one uses ammonia as the reducing agent; the other urea.
They reduce NOx in the flue gas to molecular hydrogen at high temperatures between 1600 and 2000 degrees Fahrenheit without a catalyst. With a catalyst the conversion takes place at a much lower temperature range, roughly 575-800 degrees Fahrenheit. This is called SCR. Typically these agents are injected in the post-combustion region.
Because of the significant load variations in industrial boilers which cause the optimum temperature zone to shift location in the boiler, the application and effectiveness of this type of flue gas treatment is limited.

Solid Particle Removal
The removal of solid particles from the flue gas (also called particulate emissions) is an important part of the combustion process, as proper system selection and the maintenance of that system can significantly affect plant operating costs, as well as legislative compliance. These solid particles are basically the nonburnable elements in coal that leave the furnace and boiler after combustion.
There are a number of control techniques that can be applied, varying with the type of coal and combustion equipment installed (stoker, fluidized-bed or pulverized-coal firing):

Mechanical Collection
This is the oldest form of particulate collection. It extracts ash particles from the flue gas circular air current, which forces the particles to the outer portion of the current and downward into a storage hopper. It is typically found in stoker-fired boilers. Some spreader stoker fired boilers use mechanical collectors ahead of precipitators or baghouses for reinjection of the flycarbon and for an increase in overall collection efficiency.

Sidestream Separation
This is an additional technique applied to mechanical collection to improve collection efficiency. In operation, some 10-20% of the flue gas is removed from the bottom hopper of the collector and cleaned in a small baghouse. This can in-crease ash collection efficiency by up to 35-50%.

Electrostatic Precipitators
These devises operate on the principle that the ash particles can accept an electrical charge. Particles pass through an electrical field and are attracted to a vertical metal plate, where, periodically, they are shaken loose and collected in the collection hopper.

Baghouse Collectors
These systems, quite simply, work on the same principle as a household or industrial bag-type vacuum cleaner. The ash is removed in one of two ways; a reverse stream of air is blown through the bag during collection shutdown, which re-moves the ash coating and channels it into a collection hopper. The other method involves collection of the ash on the outside of the bag. A high-pressure pulse of air is periodically forced down through the bag, shaking the ash from the bag and into the ash hopper.

Wet Scrubbers
These devises cause the ash to be mixed with water droplets in a high-velocity air stream. The ash-laden droplets are then collected in a down-stream scrubber demister section. Care must be taken in the disposal of the contaminated water, which will contain sulfuric and hydrochloric acid from the chemical combination of water and fly-ash. Also, additional care must be taken to assure the water is properly and completely removed from the flue gas. A wet scrubber has an advantage since additional heat is removed from the flue gas and can be recovered by exchangers for heating makeup water For comparison purposes, here are the cost differentiation factors between the various solid particulate collection systems, starting with the assumption that the mechanical collector is a factor of one:

Sulfur Dioxide Removal and Control
All coal and oil contain some sulfur. As a result, there is bound to be some amount of sulfur dioxide generated in the combustion process. Just how its emission is minimized depends on a number of available techniques.

Coal Benefication
Using washed coal is considered the best alternative for meeting sulfur regulations. Factors such as transportation, availability and price need to be considered. This practice is not as common as it used to be, given the availability of lower-sulfur coal.

Wet Nonregenerative Scrubbers
These systems can operate in a “throwaway” mode, where the sulfur dioxide gas reacts with a chemical, such as limestone, and the combined compound is disposed of or sold for gypsum. With additional processing, the elemental sulfur can be separated and made available for sale. Solids and pH levels are continuously monitored from a slipstream takeoff.

Wet Regenerative System
These scrubbers substantially speed up the collection process. However, their effectiveness requires the use of expensive sodium hydroxide or sodium carbonate, which require recovery systems. A major benefit, however, is the lack of sol-ids buildup, scaling, or critical pH control.

Dry Scrubbers
Here the flue gas is combined with chemicals in a water-based spray. The heat in the flue gas dries up the moisture, leaving a solid product, collectable in the baghouse. Critical elements in these systems include residence time in the chamber, flue gas temperature, which must be high enough to assure 100% moisture evaporation and adequate mixing of the chemical with the flue gas.

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Sunday, November 6, 2011

Bernoulli’s Theorem

The Bernoulli Theorem1 is a mathematical derivation based on the law of conservation of energy. This theorem states that the total energy of a fluid at any particular point above a datum plane is the sum of the elevation head, the pressure head, and the velocity head. Stated mathematically:
    Eq. (1)
If there are no friction losses and no energy is added to or taken from the system, H is constant for any point in the fluid. In reality, whenever fluid is moving there is friction loss (hL). This loss describes the difference in total energy at two points in the system. Expressing the energy levels at Point 1 versus Point 2 then becomes:
 Eq. (2)
All practical formulas for fluid flow are derived from the above. Modifications to Eq (2) have been proposed by many investigators to account for the friction losses.

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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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