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Everything listed under: Steam Efficiency

  • Steam Tip 26: Consider Installing a Condensing Economizer

    The key to a successful waste heat recovery project is optimizing the use of the recovered energy. By installing a condensing economizer, companies can improve overall heat recovery and steam system efficiency by up to 10%. Many boiler applications can benefit from this additional heat recovery, such as:

    • district heating systems
    • wallboard production facilities
    • greenhouses
    • food processing plants
    • pulp and paper mills
    • textile plants
    • hospitals

    Condensing economizers require site-specific engineering and design, and a thorough understanding of the effect they will have on the existing steam system and water chemistry.

    Use this tip sheet and its companion, Considerations When Selecting a Condensing Economizer, to learn about these efficiency improvements or contact the team at Campbell-Sevey for help.

    A conventional feedwater economizer reduces steam boiler fuel requirements by transferring heat from the flue gas to the boiler feedwater. For natural gas-fired boilers, the lowest temperature to which flue gas can be cooled is about 250°F to prevent condensation and possible stack or stack liner corrosion.

    The condensing economizer improves waste heat recovery by cooling the flue gas below its dew point, which is about 135°F for products of combustion of natural gas. The economizer reclaims both sensible heat from the flue gas and latent heat by condensing flue gas water vapor (see Table 1). All hydrocarbon fuels release significant quantities of water vapor as a combustion byproduct. The equation below shows the reactants and combustion products for the stoichiometric combustion in air of methane (CH4), the primary constituent of natural gas. When one molecule of methane is burned, it produces two molecules of water vapor. When moles are converted to pound/mole, we find that every pound of methane fuel combusted produces 2.25 lb. of water vapor, which is about 12%of the total exhaust by weight.

    Since the higher heating value of methane is 23,861 Btu per pound (Btu/lb), 41.9 lb of methane is required to provide one million Btu (MMBtu) of energy, resulting in 94.3 lb of high temperature water vapor. The latent heat of vaporization of water under atmospheric pressure is 970.3 Btu/lb. When one MMBtu of methane is combusted, 91,495 Btu of water vapor heat of evaporation (94.3 lb x 970.3 Btu/lb )is released up the boiler stack. This latent heat represents approximately 9% of the initial fuel energy content. The bulk of this latent heat can be recovered by cooling the exhaust gas below its dew point using a direct contact or indirect condensing economizer. It is possible to heat water to about 200°F with an indirect economizer or 140°F with a direct contact economizer.

    Energy Savings Potential

    The available heat in a boiler’s exhaust gases is dependent upon the hydrogen content of the fuel, the fuel firing rate, the percent of excess oxygen in the flue gases, and the stack gas temperature.

    Consider a natural gas-fired boiler that produces 100,000 lb/hr of 100-psig saturated steam. At 83% efficiency, the boiler firing rate is about 116 MMBtu/hr. At its full firing rate, the boiler consumes over 4,860 lb of natural gas each hour while exhausting 10,938 lb of high temperature water vapor each hour. The water vapor in the flue gas contains over 10.6 MMBtu/hr of latent heat. As shown in Table 2, the total heat actually available for recovery is strongly dependent upon the stack gas temperature at the condensing economizer outlet.

    Assume that an indirect contact condensing economizer is retrofitted onto this 100,000 lb/hr steam boiler to heat 50% of the makeup water from 55°F to 200°F and flue gases are cooled to 100°F. At these conditions, 12.75MMBtu/hr of total energy is available in the exhaust, of which 7.55 MMBtu/hr will be recovered to heat makeup water in the condensing economizer. More energy could be recovered if additional heat sinks are available. 

    Given 8,000 hours per year of boiler operation, and a fuel cost of $8.00/MMBtu, the annual energy recovered is valued at:

    Annual Savings = 7.55MMBtu/hr x 8,000 hrs/yr x $8.00/MMBtu/0.83 = $582,170


    District Heating System

    A boiler plant that provides up to 500,000 lb/hr of steam for a district heating system installed a direct contact condensing economizer. This economizer saves up to 20 MMBtu/hr, depending on the boiler load. Since condensate is not returned from the district heating system, the recovered energy is used to preheat plant makeup water from 45°- 60°F up to 132°F, resulting in a steam system energy efficiency improvement of 6.3%.

    Food Processing Plant

    A food processing plant installed an indirect contact condensing economizer on a 20,000-lb/hr boiler. The condensing economizer reduced the flue gas temperature from 300°F to 120°F, while capturing 2.0 MMBtu/hr of sensible and latent heat. Energy recovered by the condensing economizer heated makeup water, reducing deaerator steam requirements from 5,000 lb/hr to 1,500 lb/hr.

    For additional information on economizers, refer to Steam Tip Sheet #3 Use Feedwater Economizers for Waste Heat Recovery. This tip is provided by the U.S. Department of Energy - Energy Efficiency and Renewable Energy. For suggested actions and resources, click to download the complete US Department of Energy Tip Sheet.  

  • Wondering Why Your Steam Piping Is Making That Funny Noise?

    Want to know why your condensate pump sounds like someone dropped a bag of marbles in it? 

    You know you need a vacuum breaker, but you don't really understand why?

    Need some training so you understand what’s really going on in your steam system? 

    C’mon over to Campbell-Sevey!  

    We talk all about all of these things in our engaging full day seminar. Campbell-Sevey's live steam training room, with glass bodied steam traps and glass piping, provides a rare inside look at how steam systems and traps really operate. 

    Plus, your boss is buying lunch since it’s included in the cost of the class. What could be better than a free lunch at Famous Dave’s? Click to learn more and register for our next session. 


  • The Impact of Tariffs on the Steam Industry

    With recent government announcements of tariff hikes on steel and aluminum imports, the impact on the steam, air, and water industry is expected to be significant. 

    Raw materials like steel and aluminum typically account for over 50% of costs associated with process equipment. With tariffs on imports increasing by 25%, we encourage our customers to budget an extra 10% - 25% for equipment to cover the added costs. 

    Already prices of raw materials have increased sharply since January 2018 as shown in the charts below:

    This will impact many of our vendors: Armstrong steel products, Johnston boilers, condensate pump packages, BFS deaerators, boiler stacks, flash tanks, and separators to name some of them.

    We encourage customers to order equipment early if possible, to minimize the impact the tariffs will have on their budgets. If you have questions regarding how this may impact your company, contact the team at Campbell-Sevey


  • Top 3 Reasons to Use Custom Coils

    Steam heating coils are used in nearly every industry for various industrial ventilation and process drying applications. Because it can be challenging to find a standard coil that fits your exact needs, many companies have custom coils created for them. This provides several distinct advantages:

    1. Nearly any type and size of coil can be created

    Every steam system is unique, requiring solutions that are also unique. With custom coils there is flexibility to produce nearly any type of coil you need, regardless of size or capacity. If all you need is a hot water booster coil for low pressure steam, don't invest in a standard coil that is far more than what is required. 

    2. Improved efficiency by lowering operation steam pressure

    With steam coils, the lower the operating steam pressure in the coil, the more energy efficient the design. Process coils are sometimes designed to use high pressure steam when lower pressure steam will do. It's a matter of redesigning the heat transfer surface area. In HVAC coil design, fins are responsible for 70% or more of heat transfer while tubes are only responsible for the remaining. By adjusting the number of fins or tubes within the passes the desired heat transfer is achieved as efficiently as possible.

    3. Coils can be created for any industry application

    Every industry has different coils needs based on the application. For instance, steam or hot water face velocities are not the same as chilled water or direct expansion. For steam or hot water, 800 feet/minute is ideal. For chilled water or refrigerant, 500 feet/minute is ideal. A custom coil takes those requirements into account. Custom steam coils can be manufactured for a variety of industries including:

    • Grain/seed processing facilities 
    • Pulp/paper processing facilities 
    • Dairy processing facilities 
    • Food processing facilities 
    • Power plants
    • Heat recovery systems
    • Petroleum/chemical plants
    • Textile factories

    For more information on creating a custom coil to meet your specific needs, contact the team at Campbell-Sevey


  • Test Your Knowledge: Energy Assessments

    According to the U.S. Department of Energy’s Industrial Technologies Program, plants that do energy assessments of their steam systems typically uncover opportunities for reducing energy and cost savings range from _____________ per year?

    1. 3%-7%
    2. 5%-10%
    3. 10%-15%
    4. 12%-18%
    5. 15%-20%

    And the answer is...

    3. 10%-15%

    Steam systems account for about 30% of the total energy used in industrial applications for product output. These systems can be indispensable in delivering the energy needed for process heating, pressure control, mechanical drives, separation of components, and production of hot water for process reactions.

    As energy costs continue to rise, industrial plants need effective ways to reduce the amount of energy consumed by their steam systems. Industrial steam systems can include generation, distribution, end use, and recovery components, as shown in the diagram. End-use equipment includes heat exchangers, turbines, fractionating towers, strippers, and chemical reaction vessels. Steam systems can also feature superheaters, combustion air preheaters, feedwater economizers, and blowdown heat exchangers to boost system efficiency. 

    According to the U.S. Department of Energy’s Industrial Technologies Program, making steam systems more efficient throughout industry could reduce annual plant energy costs by several billion dollars and environmental emissions by millions of metric tons. Typically, plants that assess their steam systems uncover potential steam system energy use and cost savings that range from 10% to 15% per year.

    Facts & Figures

    • About one-third of the nation’s total energy use is consumed in U.S. industrial facilities; nearly one-ninth is used by steam systems.
    • Industry consumes more than 40% of the nation’s total use of natural gas.
    • Even plants with energy management programs can often save 10% to 15% more using best practices to increase their energy efficiency.
    • System improvements can often reduce the energy costs of a typical industrial steam system by 10% to15%.


    • Energy efficiency improvements can reduce utility bills and improve your plant’s bottom line.
    • Many improvements require little or no extra investment, are easy to implement, and have payback times of less than a year.
    • Strategies that increase energy efficiency often reduce operating and maintenance costs, minimize waste, and enhance production.
    • Energy efficiency helps to reduce negative impacts on the environment and can enhance corporate community relations programs.

    Click to download the entire report from the U.S. Department of Energy and see a list of typical ways to increase steam system efficiency. For more information on doing a Utility Systems Study within your plant, contact the team at Campbell-Sevey


  • Expand Wireless Technology In Your Steam System to Improve Efficiency

    In recent years, wireless technology has made a significant impact to improve industrial steam system operations, cut energy waste and enhance safety. As the technology has continued to advance, expanding the use of wireless networks and sensors has become dramatically more cost-effective as compared to wired alternatives, with faster installation time and minimal disruption. Here are a few of the technologies we highly recommend:

    SteamEye Steam Trap Monitoring

    Let’s face it, at any given time a percentage of your steam traps have failed, and you just don’t have the staff to test them frequently. Besides, the trap you check on Tuesday may fail Wednesday — and not be scheduled for a recheck until next year—leaving the median time of discovery at 6 months. With an average steam trap failure rate of 5% - 20% that can add up to significant energy losses. SteamEye is a steam trap monitoring system that uses a wireless transmitter to detect temperature and ultrasonic fluctuations in steam flow. It uses a radio frequency (RF) wireless transmitter mounted at the inlet of any type of steam trap to detect temperature and ultrasonic fluctuations in steam flow. A central receiver then alerts system operators of trap failure. Here are two scenarios where Steam Eye has made an impact:

    • Scenario 1: Reducing Failure Rate
      • A large university had over 4,300 steam traps located over 13.9 miles of underground steam and condensate lines and 2.3 miles of utility tunnels. Their steam trap failure rate was nearly 25% so they chose to install SteamEye monitors which measures and manages their steam trap data to improve the steam system and maintenance of the steam traps. As a result, the university has reduced steam consumption while increasing their campus footprint, lowering lowered their steam trap failure rate from 25% to 1.4%.
    • Scenario 2: Hospital cuts steam consumption
      • A large hospital, built in the 1950s, faced the high cost of getting steam from the city's steam loop and desired to cut energy costs. To identify where steam loss was occurring they installed a SteamEye monitoring system. A full steam trap survey was conducted and they retrofitted 76 high and medium pressure steam traps. The hospital was able to cut steam consumption by an average of 4,000 pounds per hour with a substantial savings. The customer also recognized a simple payback within two years of installing SteamEye.

    AIM - Armstrong Intelligent Monitoring (Acoustic and Temperature)

    Three constant challenges that plant managers and maintenance personnel face in the operation of any system include:

    1. Identifying a failure: ability to immediately pinpoint what has failed, when it failed and where it failed.
    2. Evaluating the scope: comprehending the magnitude of the failure related to process and utility systems.
    3. Measuring the impact: accurately calculate the costs including process disruptions, wasted energy andplant shut downs, safety hazards and fines levied.

    AIM enables your team to tackle all three challenges with one wireless system solution that combines a mix of methods including acoustic and temperature monitoring. Here are three scenarios where AIM has provided pinpoint detection and notification of failures:

    • Scenario 1: Condensate Back Up Caused by Steam Trap Malfunctions
      • The customer was experiencing problems with multiple steam traps that caused condensate to back up into their steam turbine. This issue caused severe downtime and decreased performance, directly affecting their bottom line. After installing AIM on the affected steam traps, the customer was made aware of the problem and were able to react immediatly before condensate back up became an issue. 
    • Scenario 2: Leaking Isolation Shut Off Valves
      • The customer experienced problems identifying the location of a leaking isolation shut off valve. When leaking shut off valves bypass materials for critical process, production efficiency decreases significantly. AIM was installed to acoustically monitor and identify when and where leaks occurred along the line. If a potential leak was identified, the customer would be immediately notified to avoid even more leakage.
    • Scenario 3: Pump Trap Failure
      • Pump trap failure caused condensate backup, flooding coils and process equipment, causing harm to the customer’s steam system and equipment. An AIM system was installed to wirelessly monitor the skin temperature of any pipe, vessel or piece of equipment. As a result, early detection of reduced inlet condensate temperature to the pump trap allowed the customer to prevent potential failure.

    AIM helps you work smarter by anticipating your needs and taking the guess work out of system troubleshooting enabling you to address problems before they spiral out of control.

    Wireless HART

    More HART products are installed in more plants around the world than any other. AIM works through a centrally located wireless gateway that enables real time, 24/7 monitoring. It easily connects and organizes WirelessHART devices to your host system while providing security, scalability, and data reliability. HART's wireless technology allows users to access the vast amount of unused information stranded in these installed smart devices. It also provides a cost-effective, simple and reliable way to deploy new points of measurement and control without the wiring costs.

    Work Smarter - Not Harder

    According to research*, wireless technology can provide: 

    • 60% less cost per device - less cabling and conduit, calibration-free, no training and low power
    • 65% less time per device - less engineering, non-intrusive, faster commissioning, quick deployment, easy integration
    • 95% less rack room footprint - no junction boxes, marshalling cabinets or input/output cards

    Campbell-Sevey offers an extensive line of wireless solutions to fit your industrial applications. Contact us to learn more about wireless options and how you can take advantage of the benefits going wireless provides.  *Emerson


  • Steam Tip 22: Consider Installing High-Pressure Boilers with Backpressure Turbine-Generator

    When specifying a new boiler, consider a high-pressure boiler with a backpressure steam turbine-generator placed between the boiler and the steam distribution network. A turbine-generator can often produce enough electricity to justify the capital cost of purchasing the higher-pressure boiler and the turbine-generator. 

    Since boiler fuel usage per unit of steam production increases with boiler pressure, facilities often install boilers that produce steam at the lowest pressure consistent with end use and distribution requirements. 

    In the backpressure turbine configuration, the turbine does not consume steam. Instead, it simply reduces the pressure and energy content of steam that is subsequently exhausted into the process header. In essence, the turbogenerator serves the same steam function as a pressure-reducing valve (PRV)—it reduces steam pressure—but uses the pressure drop to produce highly valued electricity in addition to the low-pressure steam. Shaft power is produced when a nozzle directs jets of high-pressure steam against the blades of the turbine’s rotor. The rotor is attached to a shaft that is coupled to an electrical generator. 


    The capital cost of a back-pressure turbogenerator complete with electrical switchgear varies from about $900 per kilowatt (kW) for a small system (150 kW) to less than $200/kW for a larger system (>2,000 kW). Installation costs vary, depending upon piping and wiring runs, but they typically average 75% of equipment costs. 

    Packaged or “off-the-shelf” backpressure turbogenerators are now available in ratings as low as 50 kW. Backpressure turbogenerators should be considered when a boiler has steam flows of at least 3,000 pounds per hour (lb/hr), and when the steam pressure drop between the boiler and the distribution network is at least 100 pounds per square inch gauge (psig). The backpressure turbine is generally installed in parallel with a PRV, to ensure that periodic turbine-generator maintenance does not interfere with plant thermal deliveries. 

    Cost-Effective Power Generation 

    In a backpressure steam turbine, energy from high-pressure inlet steam is efficiently converted into electricity, and low-pressure exhaust steam is provided to a plant process. The turbine exhaust steam has a lower temperature than the superheated steam created when pressure is reduced through a PRV. In order to make up for this heat or enthalpy loss and meet process energy requirements, steam plants with backpressure turbine installations must increase their boiler steam throughput (typically by 5% to 7%). Every Btu that is recovered as high-value electricity is replaced with an equivalent Btu of heat for downstream processes. 

    Thermodynamically, steam turbines achieve an isentropic efficiency of 20% to 70%. Economically, however, the turbine generates power at the efficiency of the steam boiler. The resulting power generation efficiency (modern steam boilers operate at approximately 80% efficiency) is well in excess of the efficiency for state-of-the-art single- or combined-cycle gas turbines. High efficiency means low electricity generating costs. Backpressure turbines can produce electrical energy at costs that are often less than $0.04/kWh. The electricity savings alone—not to mention ancillary benefits from enhanced on-site electricity reliability and reduced emissions of carbon dioxide and criteria pollutants — are often sufficient to completely recover the cost of the initial capital outlay. 

    Estimating Your Savings 

    Since you have already determined that you need a boiler to satisfy your process thermal loads, the marginal cost of power produced from the backpressure turbine-generator is: 

    Cost of Power Production = (Annual Boiler Fuel Cost after Pressure Increase – Annual Boiler Fuel Cost before Pressure Increase)/Annual kWh Produced by Turbine-Generator 

    The cost of boiler fuel before and after a proposed pressure increase can be calculated directly from the boiler fuel cost, boiler efficiency, and inlet and outlet steam conditions. The annual kWh produced by the turbine generator can be calculated from the inlet and exhaust pressures at the turbine, along with the steam flow rate through the turbine, in thousand pounds per hour (Mlb-hr). 

    To estimate the potential power output of your system, refer to the figure below, which shows lines of constant power output, expressed in kW of electricity output per Mlb-hr of steam throughput as a function of the inlet and exhaust pressure through the turbine. Look up your input and output pressure on the axes shown, and then use the lines provided to estimate the power output, per Mlb/hr of steam flow rate for a backpressure turbogenerator. You can then estimate the turbine power output by multiplying this number by your known steam flow rate. 


    A chemical company currently uses a 100-psig boiler with 78% boiler efficiency (E1) to produce 50,000 lb/hr of saturated steam for process loads. The boiler operates at rated capacity for 6,000 hours per year (hr/yr). The boiler has reached the end of its service life, and the company is considering replacing the boiler with a new 100-psig boiler or with a high-pressure 600-psig boiler and a backpressure steam turbine-generator. Both new boiler alternatives have rated efficiencies (E2) of 80%. The company currently pays $0.06/ kWh for electricity, and purchases boiler fuel for $8.00 per million Btu (MMBtu). Condensate return mixed with makeup water has an enthalpy of 150 Btu/lb. What are the relative financial merits of the two systems? 

    Step 1: Calculate the current annual boiler fuel cost: $3,200,000 per year 

    Current Boiler Fuel Cost 

    = Fuel Price x Steam Rate x Annual Operation x Steam Enthalpy Gain / E1 

    = $8.00/MMBtu x 50,000 lb/hr x 6,000 hr/yr x (1,190 Btu/lb – 150 Btu/lb) / (0.78 x 106 Btu/MMBtu) 

    = $3,200,000 per year 

    Step 2: Calculate the boiler fuel cost of a new 100-psig, low-pressure (LP) boiler: $3,120,000 per year 

    Resulting reductions in fuel costs are due solely to the higher efficiency of the new boiler. 

    New LP Boiler Fuel Cost 

    = Fuel Price x Steam Rate x Annual Operation x Steam Enthalpy Gain/E2 

    = $8.00/MMBtu x 50,000 lb/hr x 6,000 hr/yr x (1,190 Btu/lb – 150 Btu/lb)/ (0.80 x 106 Btu/MMBtu) 

    = $3,120,000 per year 

    Step 3: Calculate the boiler fuel cost of a new high-pressure (HP) boiler capable of producing 600 psig, 750ºF superheated steam: $3,318,300 per year 

    We must now take into account the additional enthalpy necessary to raise the pressure of the boiler steam to 600 psig. With a 50% isentropic turbine efficiency, the exhaust steam from the backpressure turbine is at 100 psig and 527ºF and must be desuperheated by adding 5,000 lb/hr of water. In order to provide an equivalent amount of thermal energy to the process loads, the boiler steam output is reduced to 45,000 lb/hr. 

    New HP Boiler Fuel Cost 

    = Fuel Price x Steam Rate x Annual Operation x Steam Enthalpy Gain / E2 

    = $8.00/MMBtu x 45,000 lb/hr x 6,000 hr/yr x (1,379 Btu/lb – 150 Btu/lb) / (0.80 x 106 Btu/MMBtu) 

    = $3,318,300 per year 

    Step 4: Estimate the electricity output of the steam turbine-generator: 6,750,000 kWh per year 

    At 600-psig inlet pressure with 750ºF superheated steam and 100-psig exhaust pressure, the system will satisfy existing steam loads but will also produce approximately 25 kW of electric power per Mlb-hr of steam production (you can use the figure on page 2 to estimate your power output for steam at saturated conditions). Thus, 

    Turbine-Generator Power Output 

    = 45 Mlb-hr x 25 kW/Mlb-hr 

    = 1,125 kW 

    Assuming a 6,000-hr operating year, the electricity output of this turbine will be: 

    Turbine-Generator Electricity Output 

    = 1,125 kW x 6,000 hr/yr 

    = 6,750,000 kWh/yr 

    Step 5: Determine the cost of electricity produced by the turbine: $0.029/kWh 

    The value is derived from the difference in fuel costs between the two boiler alternatives, divided by the power produced by the turbine: 

    Fuel Cost of Produced Electricity 

    = ($3,318,300/yr – $3,120,000/yr)/ 6,750,000 kWh/yr 

    = $0.029/kWh 

    Step 6: Calculate energy savings benefits: $209,250 per year 

    Cost Savings = 6,750,000 kWh x ($0.06/kWh – $0.029/kWh) = $209,250/yr 

    This level of savings is often more than adequate to justify the capital and maintenance expenditures for the backpressure turbine-generator set and the incremental cost of purchasing and installing the higher-pressure boiler. 

    This tip is provided by the U.S. Department of Energy - Energy Efficiency and Renewable Energy and originally adapted from material provided by the TurboSteam Corporation. For suggested actions and resources, click to download the complete US Department of Energy Tip Sheet.

  • Flash High-Pressure Condensate to Regenerate Low-Pressure Steam

    Every pound of steam saved is a pound that does not have to be produced by the boiler. That's why recovering flash steam is a great way to reduce energy costs. 

    Flash steam is steam that is created when condensate at a higher pressure and temperature is released to a lower pressure and the condensate cannot exist as a liquid in the new condition. 

    Flash steam can be used for the same purposes as live steam because it has exactly the same latent heat content as boiler steam. If this latent heat is not put to some service, the heat energy that was used to produce it is partially wasted. 

    So how much of a financial impact can saving flash steam make? Here is an example:

    In a plant where the cost of steam is $8.00 per million Btu ($8.00/MMBtu), saturated steam at 150 pounds per-square-inch-gauge (psig) is generated, and a portion of it throttled to supply 30-psig steam. Assuming continuous operation, the annual energy savings of producing low-pressure steam by flashing 5,000 pounds per hour (lb/hr) of 150-psig condensate is $40,924. Over 10 years that's over $400,000 in savings! 

    Determine if Flash Steam Recovery is right for your plant

    Campbell-Sevey can help you determine the potential for high pressure condensate flashing by completing a plant survey that:

    • Identifies all sources of high pressure condensate
    • Determines condensate flow and duration, as well as the heat recovery potential due to flashed steam production
    • Identifies compatible uses for low-pressure steam
    • Estimates the cost effectiveness of installing appropriate heat recovery devices and interconnecting piping

    Click here to download and review Armstrong's complete Flash High-Pressure Condensate to Regenerate Low-Pressure Steam best practices tip, along with suggested actions. 

  • Understanding Installation of Steam Tracing for Long-Term Application Success

    QMax recently released a detailed whitepaper on how HTC thickness and installation quality affect tracing performance. Here is a short segment along with a link to download the complete whitepaper.

    Qmax steam tracing by Campbell-SeveyOne of the most misunderstood and misused components of conductive steam tracing systems is heat transfer compound, or HTC. HTC is a viscous mastic designed to fill small air gaps between the tracing element and the object to be heated. Heat transfer compound is considerably more effective at transferring heat than static air, but has relatively poor thermal conductivity compared to the other components in a steam tracing system. If used in very thin layers, however, HTC helps maximize the performance of heating systems. This paper discusses and demonstrates why the performance and success of conductive steam tracing systems is highly dependent upon proper installation and use of HTC.

    Around the world, sulfur operations rely heavily on high performance steam tracing and jacketing to heat piping, equipment, and vessels. Failure to properly heat these systems can cause sulfur to freeze and ultimately shut down a processing plant or even an entire refinery. To ensure that a steam tracing system will operate as designed, especially for critical processes like liquid sulfur and vapors with sulfur compounds, proper system installation is critical for long-term success.

    To help understand how HTC thickness and installation quality affect tracing performance in critical operations like those involving sulfur, QMax Industries Inc. focused on testing two high performance steam tracing technologies: FTS (Fluid Tracing System) and CST (Carbon Steel Tracing). The systems were tested extensively with controlled HTC thicknesses for their effectiveness in melting elemental sulfur by tracing a sulfur-filled vessel in a QMax Industries Inc. facility. The outcome of improperly installing HTC, regardless of the reason or steam tracing technology used was consistent: as the HTC layer thickness between the tracing and pipe or vessel increases, the overall heat transfer rate from steam to process decreases. Increasing HTC thickness by only 1/16-inch from an optimal thickness of 1/32-inch increased the time required to melt elemental sulfur by as much as 70%.

    Click to download the complete whitepaper on "Understanding Installation of Steam Tracing for Long-Term Application Success". If you have questions about using steam tracing in your facility, contact the team at Campbell-Sevey


  • 6 Factors to Consider When Designing a Humidification System

    Humidity affects many properties of air and of materials in contact with air. A huge variety of manufacturing, storage and testing processes are humidity-critical that's why humidity controls are used to prevent condensation, corrosion, mold, warping or other spoilage. However the cost of controlling humidity, through air-conditioning systems or other means, can take a significant amount of energy. To minimize these costs, there are six key factors to consider:

    1. Survey the building construction
    2. Calculate humidification load
    3. Determine the best energy source
    4. Select proper water type
    5. Humidification system location
    6. Appropriate controls selection

    1. Survey the building construction/design of the building envelope

    A humidity controlled building must not leak large amounts of air. To minimize air leaks install a continuous vapor barrier, examine all areas of conditioned air loss (exhaust fans, windows, doors, etc), locate vapor retarders on warm side of wall (inside from insulation) and avoid thermal bridge (single glazing, metal casing of doors/windows).

    2. Calculate humidification load

    Humidification load is dominated by outdoor air entering and leaving the building or space. Dry outdoor air enters via two paths – ventilation or infiltration. Load is based on the amount of outside air entering the building or space. If the calculation isn't done properly under sizing can occur leading to the inability to maintain desired relative humidity. If over sizing occurs the result is irregular humidity levels or wet ducts. 

    3. Determine the best energy source

    Adiabatic humidifiers use heat from surrounding air to change water into vapor. Examples include: pressurized water atomizers, ultrasonic, wetted media and compressed air foggers. Isothermal Systems use heat added to the water. These types of systems include: steam boilers, unfired steam generators, electrode type (plastic cylinders), electric resistive heater type, steam heat exchangers and gas-fired humidifiers.

    4. Select proper water type

    Types of water vary for humidification systems, but make a difference in performance and maintenance. Common types include: potable (tap) water from city or well source, softened water, reverse osmosis (RO) water – filtered to remove most of minerals/contaminants, and de-ionized (DI) water – high quality and free of minerals/contaminants.

    5. Humidification system location

    Several factors go into determining the best location: access to energy (electric, gas or steam), water source, drain availability, and access for maintenance. Also important is the available absorption distance which will affect system choice. Dispersed steam must be absorbed before it comes in contact with downstream objects such as fans, vanes and filters. Adiabatic units need to be positioned where sufficient heat is available to vaporize water being added.

    6. Appropriate controls selection

    When selecting humidity controls it's important to determine: desired relative humidity set point, acceptable relative humidity variances, space temperature (stable temperatures must be maintained for accurate humidity control), and component quality – select controls that match the application.

    For help in designing a humidification system for your exact application, contact the team at Campbell-Sevey


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Products We Carry

  • Hot Water Boilers
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  • Deaerators
  • Heat Recovery Steam Generators (HRSG’s)
  • Automatic Recirculation Valves
  • Economizers
  • Gas-Fired Water Heaters
  • Gas-Fired Humidifiers
  • Boiler/Generator Flue Stacks
  • Continuous Emissions Monitors (CEMS)
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  • Flash Tanks
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  • Piston Valves
  • Heating/Cooling Coils
  • Plate and Frame Heat Exchangers
  • Shell and Tube Exchangers
  • Water Heaters
  • Steam Humidifiers
  • Vacuum Systems
  • Condensers
  • Steam Traps
  • Wireless Steam Trap Monitors
  • Tube Bundles
  • Direct Gas-Fired Space Heaters
  • Direct Gas-Fired Make-Up Air Units
  • Unit Heaters
  • Strainers
  • Air Vents
  • Liquid Drainers
  • Heat Transfer Packages
  • Digital Water Mixing Valves
  • Air Cooled Condensers/Dry Coolers
  • Steam Filters
  • Electric Condensate Pumps
  • Steam/Air-Powered Condensate Pumps
  • Packaged Condensate Pump Skids