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  • 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.  

  • Steam Tip 25: Installing Turbulators on Firetube Boilers

    Consider Installing Turbulators on Two- and Three-Pass Firetube Boilers 

    Firetube Boilers 

    The packaged firetube boiler is the most common boiler design used to provide heating or process steam in industrial and heavy commercial applications. The American Boiler Manufacturers Association (ABMA) surveyed sales of high-pressure [15- to 350-pounds-per-square-inch-gauge (psig)] firetube and small watertube boilers between 1978 and 1994. ABMA found that firetube boilers comprised more than 85% of the sales of these boilers to industry. 

    Although firetube boilers are available in ratings up to 85,000 pounds of steam per hour (lb/hr), they are generally specified when the required steam pressure is under 150 psig and the boiler capacity is less than 25,000 lb/hr. Watertube boilers are designed for larger, high-pressure, and superheated steam applications. 

    In a firetube boiler, hot combustion gases pass through long, small-diameter tubes, where heat is transferred to water through the tube walls. Firetube boilers are categorized by their number of “passes,” or the number of times that the hot combustion gases travel across the boiler heat-exchange surfaces. For example, a two-pass boiler provides two opportunities for hot gases to transfer heat to the boiler water. Hot combustion gases enter the tubes in a turbulent flow regime, but within a few feet, laminar flow begins and a boundary layer of cooler gas forms along the tube walls. This layer serves as a barrier, retarding heat transfer. 

    Turbulators, which consist of small baffles, angular metal strips, spiral blades, or coiled wire, are inserted into the boiler tubes to break up the laminar boundary layer. This increases the turbulence of the hot combustion gases and the convective heat transfer to the tube surface. The result is improved boiler efficiency. Turbulators are usually installed on the last boiler pass. 

    Turbulator installers can also balance gas flow through the tubes by placing longer turbulators in the uppermost tubes. This practice increases the effectiveness of the available heat-transfer surface by eliminating thermal stratification and balancing the gas flow through the firetubes. 


    Turbulators can be a cost-effective way to reduce the stack temperature and increase the fuel-to-steam efficiency of single-pass horizontal return tubular (HRT) brick-set boilers and older two- and three-pass oil- and natural-gas-fueled firetube boilers. Turbulators are not recommended for four-pass boilers or coal-fired units. A four-pass unit provides four opportunities for heat transfer. It has more heat exchange surface area, a lower stack temperature, higher fuel-to-steam efficiency, and lower annual fuel costs than a two- or three-pass boiler operating under identical conditions. New firetube boilers perform better than older two- and three-pass designs. 

    Turbulators can also be installed to compensate for efficiency losses when a four-pass boiler is being converted to a two-pass boiler because of door warpage and loose and leaking tubes. 

    Turbulators are substitutes for more costly economizers or air-preheaters. They are simple, easy to install, and low cost. Their installed cost is about $10 to $15 per boiler tube. Current turbulator designs do not cause a significant increase in pressure drop or contribute to soot formation in natural-gas-fired boilers. Turbulators are held in place with a spring lock and are easily removed to allow for tube brushing. 

    Turbulators come in various lengths and widths and should be installed by a qualified installer. To avoid combustion problems, the boiler burner should be retuned after the turbulators have been installed. The installer must also verify that the stack temperature does not fall below the flue gas dew point. 

    Price and Performance Example 

    A manufacturing facility installed 150 turbulators into its firetube boiler. Tests conducted both before and after turbulator installation indicated a reduction in the stack gas temperature of 130°F. More combustion heat was being transferred into the boiler water. Because each 40°F reduction in the boiler flue gas temperature results in a 1% boiler-efficiency improvement, overall boiler efficiency has improved by about 3.25%. Fuel costs have decreased by approximately 4%. 


    Consider a two-pass firetube boiler that consumes 60,000 million Btu (MMBtu) of natural gas annually while producing 15,000 lb/hr of 100-psig saturated steam. What are the annual energy and cost savings, given that the installation of turbulators improves the boiler efficiency from 79% (E1) to 82% (E2)? Natural gas is priced at $8.00/MMBtu. 

    • Annual Energy Savings = Annual Fuel Consumption (MMBtu) x (1 – E1/E2) or 60,000 MMBtu x (1 – 79/82) = 2,195 MMBtu 
    • Annual Cost Savings = $8.00/MMBtu x 2,195 MMBtu/yr = $17,560 

    If the boiler has 250 tubes and the installed cost for the turbulator is $15 per tube, the simple payback on the investment in the energy efficiency measure is: 

    • Simple Payback = (250 tubes x $15/tube)/$17,560/year = 0.21 year 

    This tip is provided by the U.S. Department of Energy - Energy Efficiency and Renewable Energy and is adapted from material provided by Brock Turbulators and Fuel Efficiency, LLC, and reviewed by the AMO Steam Technical Subcommittee. For suggested actions and resources, click to download the complete US Department of Energy Tip Sheet.

  • Steam Tip 24: Upgrade Boilers with Energy Efficient Burners

    The purpose of the burner is to mix molecules of fuel with molecules of air. A boiler will run only as well as the burner performs. A poorly designed boiler with an efficient burner may perform better than a well-designed boiler with a poor burner. Burners are designed to maximize combustion efficiency while minimizing the release of emissions. 

    A power burner mechanically mixes fuel and combustion air and injects the mixture into the combustion chamber. All power burners essentially provide complete combustion while maintaining flame stabilization over a range of firing rates. Different burners, however, require different amounts of excess air and have different turndown ratios. The turndown ratio is the maximum inlet fuel or firing rate divided by the minimum firing rate. 

    An efficient natural gas burner requires only 2% to 3% excess oxygen, or 10% to 15% excess air in the flue gas, to burn fuel without forming excessive carbon monoxide. Most gas burners exhibit turndown ratios of 10:1 or 12:1 with little or no loss in combustion efficiency. Some burners offer turndowns of 20:1 on oil and up to 35:1 on gas. A higher turndown ratio reduces burner starts, provides better load control, saves wear and tear on the burner, reduces refractory wear, reduces purge-air requirements, and provides fuel savings. 

    Efficient Burner Technologies 

    An efficient burner provides the proper air-to-fuel mixture throughout the full range of firing rates, without constant adjustment. Many burners with complex linkage designs do not hold their air-to-fuel settings over time. Often, they are adjusted to provide high levels of excess air to compensate for inconsistencies in the burner performance. 

    An alternative to complex linkage designs, modern burners are increasingly using servomotors with parallel positioning to independently control the quantities of fuel and air delivered to the burner head. Controls without linkage allow for easy tune-ups and minor adjustments, while eliminating hysteresis, or lack of retraceability, and provide accurate point-to-point control. These controls provide consistent performance and repeatability as the burner adjusts to different firing rates. 

    Alternatives to electronic controls are burners with a single drive or jackshaft. Avoid purchasing standard burners that make use of linkages to provide single-point or proportional control. Linkage joints wear and rod-set screws can loosen, allowing slippage, the provision of suboptimal air-to-fuel ratios, and efficiency declines. 


    Consider purchasing a new energy-efficient burner if your existing burner is cycling on and off rapidly. Rotary-cup oil burners that have been converted to use natural gas are often inefficient. Determining the potential energy saved by replacing your existing burner with an energy-efficient burner requires several steps. First, complete recommended burner-maintenance requirements and tune your boiler. Conduct combustion-efficiency tests at full- and part-load firing rates. Then, compare the measured efficiency values with the performance of the new burner. Most manufacturers will provide guaranteed excess levels of oxygen, carbon monoxide, and nitrous oxide. 


    Even a small improvement in burner efficiency can provide significant savings. Consider a 50,000 pound-per-hour process boiler with a combustion efficiency of 79% (E1). The boiler annually consumes 500,000 million Btu (MMBtu) of natural gas. At a price of $8.00/MMBtu, the annual fuel cost is $4 million. What are the savings from an energy-efficient burner that improves combustion efficiency by 1%, 2%, or 3%? 

    Cost Savings = Fuel Consumption x Fuel Price x (1 - E1/E2) 

    If the installed cost is $75,000 for a new burner that provides an efficiency improvement of 2%, the simple payback on investment is: 

    Simple Payback = $75,000/$98,760/year = 0.76 year 

    Maintenance Requirements 

    Conduct burner maintenance at regular intervals. Wear on the firing head, diffuser, or igniter can result in air leakage or failure of the boiler to start. One burner distributor recommends maintenance four times per year, with the change of seasons. A change in weather results in a change in combustion. 

    Fan Selection 

    Fan selection is also important. Backward-curved fans provide more reliable air control than forward-curved fans. Radial-damper designs tend to provide more repeatable air control at lower firing rates than blade-type damper assemblies. 

    Steam Tip Information is adapted from material supplied by PBBS Equipment Corp. and Blesi-Evans Company and reviewed by the AMO Steam Technical Subcommittee. For additional information, 

    This tip is provided by the U.S. Department of Energy - Energy Efficiency and Renewable Energy and is adapted from material supplied by PBBS Equipment Corp. and Blesi-Evans Company and reviewed by the AMO Steam Technical Subcommittee. For suggested actions and resources, click to download the complete US Department of Energy Tip Sheet.  


  • Steam Tip 23: Automatic Blowdown-Control System

    To reduce the levels of suspended and total dissolved solids in a boiler, water is periodically discharged or blown down. High dissolved solids concentrations can lead to foaming and carryover of boiler water into the steam. This could lead to water hammer, which may damage piping, steam traps, or process equipment. Surface blowdown removes dissolved solids that accumulate near the boiler liquid surface and is often a continuous process. 

    Suspended and dissolved solids can also form sludge. Sludge must be removed because it reduces the heat-transfer capabilities of the boiler, resulting in poor fuel-to-steam efficiency and possible pressure vessel damage. Sludge is removed by mud or bottom blowdown. 

    During the surface blowdown process, a controlled amount of boiler water containing high dissolved solids concentrations is discharged into the sewer. In addition to wasting water and chemicals, the blowdown process wastes heat energy, because the blowdown liquid is at the same temperature as the steam produced—approximately 366°F for 150-pounds-per-square-inch-gauge (psig) saturated steam—and blowdown heat recovery systems, if available, are not 100% efficient. (Waste heat may be recovered through the use of a blowdown heat exchanger or a flash tank in conjunction with a heat recovery system. For more information, see Steam Tip 10, Recover Heat from Boiler Blowdown.) 

    Advantages of Automatic Control Systems 

    With manual control of surface blowdown, there is no way to determine the concentration of dissolved solids in the boiler water, nor the optimal blowdown rate. Operators do not know when to blow down the boiler, or for how long. Likewise, using a fixed rate of blowdown does not take into account changes in makeup and feedwater conditions, or variations in steam demand or condensate return. 

    An automatic blowdown-control system optimizes surface-blowdown rates by regulating the volume of water discharged from the boiler in relation to the concentration of dissolved solids present. Automatic surface-blowdown control systems maintain water chemistry within acceptable limits, while minimizing blowdown and reducing energy losses. Cost savings come from the significant reduction in the consumption, disposal, treatment, and heating of water. 

    How it Works 

    With an automatic blowdown-control system, high- or low-pressure probes are used to measure conductivity. The conductivity probes provide feedback to a blowdown controller that compares the measured conductivity with a set-point value, and then transmits an output signal that drives a modulating blowdown release valve. 

    Conductivity is a measure of the electrical current carried by positive and negative ions when a voltage is applied across electrodes in a water sample. Conductivity increases when the dissolved ion concentrations increase. 

    The measured current is directly proportional to the specific conductivity of the fluid. Total dissolved solids, silica, chloride concentrations, and/ or alkalinity contribute to conductivity measurements. These chemical species are reliable indicators of salts and other contaminants in the boiler water. 


    Boilers without a blowdown heat-recovery system and with high blowdown rates offer the greatest energy-savings potential. The optimum blowdown rate is determined by a number of factors, including boiler type, operating pressure, water treatment, and makeup-water quality. Savings also depend upon the quantity of condensate returned to the boiler. With a low percentage of condensate return, more makeup water is required and additional blowdown must occur. Boiler blowdown rates often range from 1% to 8% of the feedwater flow rate, but they can be as high as 20% to maintain silica and alkalinity limits when the makeup water has a high solids content. 

    Price and Performance Example 

    For a 100,000 pound-per-hour (lb/ hr) steam boiler, decreasing the required blowdown rate from 8% to 6% of the feedwater flow rate will reduce makeup water requirements by approximately 2,300 lb/hr. (See Steam Tip Sheet #9, Minimize Boiler Blowdown.) Annual energy, water, and chemicals savings due to blowdown rate reductions for a sample system are summarized in the table below. In many cases, these savings can provide a 1- to 3-year simple payback on the investment in an automatic blowdown-control system. 

    Purchasing and installing an automatic blowdown-control system can cost from $2,500 to $6,000. The complete system consists of a low- or high-pressure conductivity probe, temperature compensation and signal conditioning equipment, and a blowdown-modulating valve. Some systems are designed to monitor both feedwater and blowdown conductivity from multiple boilers. A continuous conductivity recording capability might also be desired. The total cost of the automatic blowdown system is dependent upon the system operating pressure and the design and performance options specified. 

    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.  


  • 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.

  • Steam Tip 21: Consider Steam Turbine Drives for Rotating Equipment

    Steam turbines are well suited as prime movers for driving boiler feedwater pumps, forced or induced-draft fans, blowers, air compressors, and other rotating equipment. This service generally calls for a backpressure noncondensing steam turbine. The low-pressure steam turbine exhaust is available for feedwater heating, preheating of deaerator makeup water, and/or process requirements. 

    Steam turbine drives are equipped with throttling valves or nozzle governors to modulate steam flow and achieve variable speed operation. The steam turbine drive is thus capable of serving the same function as an induction motor coupled to an inverter or adjustable speed drive. Steam turbine drives can operate over a broad speed range and do not fail when overloaded. They also exhibit the high starting torque required for constant torque loads such as positive displacement pumps. 

    Steam turbines are inherently rugged and reliable low-maintenance devices. They are easy to control and offer enclosed, nonsparking operation suitable for use in explosive atmospheres or highly corrosive environments. Steam turbines provide fast, reliable starting capability and are particularly adaptable for direct connection to equipment that rotates at high speeds. Steam turbine drives may be installed for continuous duty under severe operating conditions, or used for load shaping (e.g., demand limiting), standby, or emergency service. 

    Steam turbine performance is expressed in terms of isentropic efficiency or steam rate (the steam requirement of the turbine per unit of shaft power produced). Steam rates are given in terms of pounds per horsepower-hour (lb/hp-hr) or pounds per kilowatt-hour (lb/kWh). 


    A 300-hp steam turbine has an isentropic efficiency of 43% and a steam rate of 26 lb/hp-hr given the introduction of 600-pounds-per-square-inch-gauge (psig)/750°F steam with a 40-psig/486°F exhaust. What steam flow is necessary to replace a fully-loaded 300-hp feedwater pump drive motor? 

    Steam Flow = 26 lb/hp-hr x 300 hp = 7,800 lb/hr 

    An examination of the ASME steam tables reveals that this steam turbine would utilize 103 Btu/lb of steam or 0.80 million Btu (MMBtu) of thermal energy per hour. Given a natural gas cost of $8.00/MMBtu and a boiler efficiency of 80%, the fuel-related cost of steam turbine operation is (0.80 MMBtu/hr/0.80 x $8.00/ MMBtu) = $8.00/hr. 

    In comparison, a 300-hp motor with a full-load efficiency of 95% would require: 

    300 hp x (0.746 kW/hp) x 100/95 = 235.6 kWh/hr 

    In this example, the steam turbine drive would provide energy cost savings when the price of electricity exceeds: 

    235.6 kWh/hr x $/100 cents 

    = 3.4 cents/kWh ($0.034/kWh) 

    The total annual energy savings are strongly dependent upon the facility energy cost and the hours per year of feedwater pump operation. Annual energy savings are given in the table below for various electrical rates and pump operating schedules. In addition to operating cost savings, steam turbine maintenance costs should be compared with electric motor maintenance expenses 

    Steam Turbine Flexibility 

    Equipment redundancy and improved reliability can be obtained by mounting a steam turbine drive and an electric motor on opposite ends of the driven-equipment shaft. You can then select either the motor or turbine as the prime mover by increasing or decreasing the turbine speed relative to the synchronous speed of the motor. 

    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 and reviewed by the AMO Steam Technical Subcommittee. For suggested actions and resources, click to download the complete US Department of Energy Tip Sheet.


  • Steam Tip 20: Replace Pressure-Reducing Valves with Backpressure Turbogenerators

    Many industrial facilities produce steam at a pressure higher than that demanded by process requirements. Steam passes through pressure-reducing valves (PRVs, also known as letdown valves) at various locations in the steam distribution system to let down or reduce its pressure. A noncondensing or backpressure steam turbine can perform the same pressure-reducing function as a PRV while converting steam energy into electrical energy. 

    In a backpressure steam turbogenerator, 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 steam turbine does not consume steam. It simply reduces the pressure of the steam that is subsequently exhausted into the process header. 

    Cost-Effective Power Generation 

    In a conventional, power-only steam turbine installation, designers increase efficiency by maximizing the pressure drop across the turbine. Modern Rankine-cycle power plants with 1,800-pounds-per-square-inch-gauge (psig) superheated steam boilers and condensing turbines exhausting at near-vacuum pressures can generate electricity with efficiencies of approximately 40%. 

    Most steam users do not have the benefit of ultra-high-pressure boilers and cannot achieve such high levels of generation efficiency. However, by replacing a PRV with a backpressure steam turbine, where the exhaust steam is provided to a plant process, energy in the inlet steam can be effectively removed and converted into electricity. This means the exhaust steam has a lower temperature than it would have had if its pressure had been reduced through a PRV. In order to make up for this heat loss, steam plants with backpressure turbine installations increase their boiler steam throughput. 

    Thermodynamically, the steam turbine still behaves the same way that it would in a conventional Rankine-cycle power plant, achieving isentropic efficiencies of 20% to 70%. Economically, however, the turbine generates power at the efficiency of your particular steam boiler (modern steam boilers operate at approximately 80% efficiency), which then must be replaced with equivalent kilowatt-hours (kWh) of heat for downstream purposes. The resulting power generation efficiencies are well in excess of the average U.S. electricity grid generating efficiency of 33%. Greater efficiency means less fuel consumption; backpressure turbines can produce power at costs that are often less than $0.04/kWh. 


    Packaged or “off-the-shelf” backpressure turbogenerators are now available in ratings as low as 50 kW. Backpressure turbogenerators should be considered when a PRV has constant steam flows of at least 3,000 pounds per hour (lb/hr), and when the steam pressure drop is at least 100 psi. The backpressure turbine is generally installed in parallel with the PRV. 

    Estimating Your Savings 

    To make a preliminary estimate of the cost of producing electrical energy from a backpressure steam turbine, divide your boiler fuel cost in dollars per million Btu ($8.00/MMBtu) by the product of your boiler efficiency (Eb, 80%) and electrical generator efficiency (Eg, 95%). Then convert the resulting number into cost per kWh, as shown in the sample calculation below: 

    Electricity Cost = Fuel Cost ($/MMBtu) x 0.003412 MMBtu/kWh/(Eb x Eg) 

    Example: ($8.00/MMBtu x 0.003412 MMBtu/kWh)/(0.80 x 0.95) = $0.036/kWh 

    To estimate the potential power output at a PRV, refer to the figure below, which shows lines of constant power output, expressed in kW of electrical output per 1,000 pounds per hour (Mlb-hr) of steam throughput, as a function of turbine inlet and exhaust pressures. Look up your input and output pressure on the horizontal and vertical axes, and then use the reference lines to estimate the backpressure turbogenerator power output per Mlb-hr of steam flow. Then estimate the total installed generating capacity (kW) by multiplying this number by your known steam flow rate. The annual cost savings from the backpressure turbine can then be estimated as: 

    Power Output (kW) x Steam Duty (hr/yr) x (Cost of Grid Power – Cost of Generated Power, $/kWh) 

    Life and Cost of Backpressure Turbogenerators 

    Turbogenerators with electrical switchgear cost about $900/kW for a 150 kW system to less than $200/kW for a 2,000 kW system. Installation costs vary, but typically average 75% of equipment costs. 

    Backpressure steam turbines are designed for a 20-year minimum service life and are known for having low maintenance requirements. 

    This tip is provided by the U.S. Department of Energy - Energy Efficiency and Renewable Energy and originally published by the Industrial Energy Extension Service of Georgia Tech. For suggested actions and resources, click to download the complete US Department of Energy Tip Sheet.


  • Measuring Condensate with Vortex Meters

    Traditionally in steam heating systems, metering is performed on the steam side. However, because steam can be difficult to measure with extreme temperatures, many customers measure steam loads from the condensate side also. Measuring steam from the condensate side can also be less costly than measuring from the steam side because it’s a volumetric measurement. 

    For these applications we recommend Armstrong Vortex meters. They are typically installed on the pumped side of the condensate system right after the pumps on a vertical rise, ensuring the pipe is always full. Because one pound of condensate is equal to one pound of steam, this is a very easy and cost-effective way to measure the steam usage with the ability to control flow output. 

    Armstrong offers vortex technology for measurement of steam, liquid, and gas flows. All flow meter AVF in-line models and AVI insertion models provide multi-variable measurement and mass flow output for applications in industrial and institutional environments. With turn down up to 100:1, the Vortex meter offers 1.5% of rate accuracy or better. 

    For more information about the using Vortex meters in your application, contact the team at Campbell-Sevey.

  • Steam Tip 19: Cover Heated Open Vessels

    Open vessels that contain heated liquids often have high heat loss due to surface evaporation. Both energy and liquid losses are reduced by covering open vessels with insulated lids. The table below provides an estimate of the evaporative heat loss per square foot (ft2) of uncovered vessel surface area for various water and dry ambient air temperatures. It is assumed that the ambient air is dry with no wind currents. A fan pulling air over the uncovered tank could more than double the heat losses. 


    A rinse tank is 4 feet (ft) wide and 10 feet (ft) long. It is maintained at a constant temperature of 170°F. Determine the evaporative heat loss from the tank if the ambient temperature is 75°F. 

    • Area of Evaporating Surface = 4 ft x 10 ft = 40 ft(2)
    • Total Heat Loss for Uncovered Liquid Surface = 1,566 Btu/hr-ft(2) x 40 ft(2) = 62,640 Btu/hr 

    Cover the Tank with an Insulated Top 

    Assume that the rinse tank is heated during two shifts per day, five days per week, and 50 weeks per year. What are the annual energy savings that may be obtained by covering the tank? What is the heating cost reduction in a plant where the cost of steam is $8.00 per million Btu ($8.00/MMBtu)? Assume that covering the rinse tank with an insulated lid effectively reduces the heat losses from the liquid surface to a negligible value. 

    • Annual Energy Savings = 62,640 Btu/hr x 2 shifts/day x 8 hr/shift x 250 days/yr = 250 MMBtu 
    • Annual Heating Cost Reduction = 250 MMBtu/yr x $8.00/MMBtu = $2,000

    Heat Loss Detail 

    Eliminating internal heat gains will also result in electrical energy savings if the open tanks are located within a conditioned space. 

    Heat losses are a strong function of both wind velocity and ambient air humidity. A wind velocity of 3 miles per hour will more than double the rate of heat loss from a tank. 

    Radiation heat transfer is a secondary source of tank surface heat losses. Radiation losses increase from 90 Btu/hr-ft2 at a liquid temperature of 110°F to 290 Btu/hr-ft2 at 190°F. 

    This tip is provided by the U.S. Department of Energy - Energy Efficiency and Renewable Energy and originally published by the Industrial Energy Extension Service of Georgia Tech. For suggested actions and resources, click to download the complete US Department of Energy Tip Sheet. 

  • Steam Tip 18: Deaerators in Industrial Steam Systems

    Deaerators are mechanical devices that remove dissolved gases from boiler feedwater. Deaeration protects the steam system from the effects of corrosive gases. It accomplishes this by reducing the concentration of dissolved oxygen and carbon dioxide to a level where corrosion is minimized. A dissolved oxygen level of 5 parts per billion (ppb) or lower is needed to prevent corrosion in most high-pressure (>200 pounds per square inch) boilers. 

    While oxygen concentrations of up to 43 ppb may be tolerated in low-pressure boilers, equipment life is extended at little or no cost by limiting the oxygen concentration to 5 ppb. Dissolved carbon dioxide is essentially completely removed by the deaerator. 

    How They Work 

    The design of an effective deaeration system depends upon the amount of gases to be removed and the final oxygen gas concentration desired. This in turn depends upon the ratio of boiler feedwater makeup to returned condensate and the operating pressure of the deaerator. 

    Deaerators use steam to heat the water to the full saturation temperature corresponding to the steam pressure in the deaerator and to scrub out and carry away dissolved gases. Steam flow may be parallel, cross, or counter to the water flow. The deaerator consists of a deaeration section, a storage tank, and a vent. In the deaeration section, steam bubbles through the water, both heating and agitating it. Steam is cooled by incoming water and condensed at the vent condenser. Noncondensable gases and some steam are released through the vent. 

    Steam provided to the deaerator provides physical stripping action and heats the mixture of returned condensate and boiler feedwater makeup to saturation temperature. Most of the steam will condense, but a small fraction (usually 5% to 14%) must be vented to accommodate the stripping requirements. Normal design practice is to calculate the steam required for heating and then make sure that the flow is sufficient for stripping as well. If the condensate return rate is high (>80%) and the condensate pressure is high in comparison to the deaerator pressure, then very little steam is needed for heating and provisions may be made for condensing the surplus flash steam. 

    Deaerator Steam Consumption 

    The deaerator steam consumption is equal to the steam required to heat incoming water to its saturation temperature, plus the amount vented with the noncondensable gases, less any flashed steam from hot condensate or steam losses through failed traps. The heat balance calculation is made with the incoming water at its lowest expected temperature. The vent rate is a function of deaerator type, size (rated feedwater capacity), and the amount of makeup water. The operating vent rate is at its maximum with the introduction of cold, oxygen-rich makeup water. 

    Additional Benefits 

    Deaerators provide the water storage capacity and the net positive suction head necessary at the boiler feed pump inlet. Returned condensate is mixed with makeup water within the deaerator. Operating temperatures range from 215° to more than 350°F, which reduces the thermal shock on downstream preheating equipment and the boiler. 


    The deaerator section and storage tank and all piping conveying hot water or steam should be adequately insulated to prevent the condensation of steam and loss of heat. 

    Function Clarification 

    The deaerator is designed to remove oxygen that is dissolved in the entering water, not entrained air. Sources of “free air” include loose piping connections on the suction side of pumps and improper pump packing. 

    Pressure Fluctuations 

    Sudden increases in free or “flash” steam can cause a spike in deaerator vessel pressure, resulting in re-oxygenation of the feedwater. A dedicated pressure-regulating valve should be provided to maintain the deaerator at a constant pressure. 

    This tip is provided by the U.S. Department of Energy - Energy Efficiency and Renewable Energy and originally published by the Industrial Energy Extension Service of Georgia Tech. For suggested actions and resources, click to download the complete US Department of Energy Tip Sheet. 

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