Selecting a boiler for heating, process loads
Boilers for heating and domestic hot water systems are used in many nonresidential buildings and across educational, hospital, and industrial campuses. This article reviews the codes and standards that regulate boiler system specification and design, plus energy efficiency and efficacy of these boiler systems.
- Learn about the different types of boilers available, system design, and available system options.
- Understand the codes, standards, and permitting considerations that boiler systems installation and design need to consider.
Packaged boilers for heating and domestic hot water systems are used in many nonresidential buildings and across many university, hospital, and industrial campuses. Packaged boilers normally fall into the category of factory assembled boilers, which are then shipped via, truck, rail,or barge to the end user’s site. In recent years some boiler manufacturers have begun selling packaged boilers as modules that are assembled in the field-which are still considered packaged boilers.
When designing a boiler system many options are available, but not all options are appropriate for every system. In some cases a modular boiler with high- and low-fire (two-stage burner) may be an acceptable solution where in another case a fully modulating boiler with 10:1 turndown ratio may be more appropriate. Cost; operator capabilities; available space; international, national, state, and local codes as adopted; and steam or hot water requirements will set the system parameters used in selecting each boiler system.
In boiler systems, steam, high-temperature hot water, and hot water are used for comfort heating, humidification, and process heating media across a wide range of building environments. Boilers can be installed in individual buildings or, as in the case of many campus environments, as part of a central plant boiler system that provides heating and process media to the campus through direct buried or tunnel distribution systems. Care needs to be taken in evaluating central boiler plants versus building-specific boiler plants. Each system type carries pros and cons with redundant capacity, operator availability, capital cost, lifecycle costs, and existing system configuration weighing the new design.
In either scenario, the boilers specified to generate steam, high-temperature hot water, and hot water vary in construction and size depending on the amount and temperature of media required. Packaged boiler steam systems vary in pressure from 15 to 1000 psig. Piping for high-, medium-,and low-pressure steam systems in industrial settings is governed by ASME B31.3: Process Piping Design. In addition, ASME B31.9: Building Services Piping may be followed depending on system pressure and temperature.
Boilers are designed to ASME Boiler and Pressure Vessel Code requirements. Piping and boiler system materials are dictated by the design pressures and temperatures desired for the system. High-temperature and pressure systems may require the use of alloy steel piping to distribute steam between the boiler and processes. Piping systems of boilers that will be used to generate power will be designed to ASME B31.1: Power Piping. Each of the respective codes will identify the allowable operating and design stresses for materials based on temperature. Steam and hot water distribution at lower temperatures for industrial and process systems can use both carbon and stainless steel piping depending on final service requirements.
Boilers come in two primary designs: fire tube and water tube. In a fire tube boiler, the boiler gases and heat are within the tubes in the boiler; while in water tube boilers, boiler feed water is within the tubes and drums of the boiler. Water tube boilers primarily are used to generate steam, while fire tube boilers are used for both steam and hot water (see Table 1). Fire tube boilers are most commonly found in single building applications where steam is used for small process systems and building heat.
These boilers are typically about 50% to 60% of the cost of a water tube boiler due to the smaller size and less steel content for a given boiler capacity. Steam generating fire tube boilers have less water in the boiler than a water tube boiler, which limits the amount of load swing that the boiler is able to handle. Yearly cleaning and inspection on the fire tube boiler is easier than on a water tube boiler, and tube repair can be performed from the boiler exterior with adequate tube pull space rather than from within the boiler (see Figure 1).
Fire tube boilers come in 2-, 3-, and 4-pass flue gas designs. Increasing the number of passes in the boiler increases boiler efficiency while also increasing cost. Steam capacity for fire tube boilers generally ranges between 5,000 and 75,000 lb/h. Hot water boilers are sized in million Btus and range from 2 to 3 MMBtu up to 100 MMBtu.
Water tube boilers come in four basic designs: D-style, A-style, O-style, and Modular layouts. D-, A-, and O-style boilers each contain upper and lower drums with steam generation tubes between the drums and on the outside walls. There are two areas in a water tube boiler, the convection pass and the furnace. The furnace section of the boiler contains the burner flame with boiler tubes on the outer wall (cooling the outer skin of the boiler) and separating walls of the boiler. In the convection (or generation) section of the boiler, tubes run between the upper and lower drums transferring heat from the flue gas into the feed water. Modular boilers are typically smaller in capacity with inlet and outlet manifolds connected by generating tubes. The small water capacity of a modular boiler allows it to heat up and produce steam much quicker than a water tube boiler. Packaged water tube boilers range in capacity from modular boilers at 3,000 to 300,000 lb/h in D-style boilers (see Figure 2).
Water tube boilers generate steam at 15 to 1000 psig and can be fitted with radiant or convective superheat systems to produce superheated steam. Superheated steam is steam that is heated above saturation temperature to create dry steam. Superheated steam is most often used in steam turbines for generating electricity, but can be used in distribution systems to reduce steamtrap load. Convective superheat sections are more desirable than radiant sections because the convective section is not subject to direct flame impingement that the radiant section may see with an out-of-adjustment burner.
Water tube boilers hold more water in the upper and lower drums and in the tubes connecting them. This allows the boilers to take larger swings in steam output without creating steam quality issues. Water tube boilers are most often the selection of choice as prime boilers in steam district energy and campus environments because of their capacity and operability range. Their ability to run at higher pressures and temperatures with superheat makes them ideal as backup boilers to electrical generating systems and as primary steam movers for generating steam in cogeneration systems.
Boilers with superheat sections may require steam temperature control between superheat sections in the boiler or at the superheater outlet. Temperature control of this type is called attemperation. Steam attemperators or de-superheaters reduce the steam temperature by spraying water into the steam line. The spray water evaporates in the steam line, cooling the steam to the desired temperature (see Figure 3).
The best water to use for attemperation (regulation) is pure condensate. This does not include boiler feed water as feedwater normally contains makeup water that may contain impurities. If clean condensate is not available, another source of attemperation water is a "sweet water"condenser. A sweet water condenser condenses saturated steam out of the boiler, while heating boiler feedwater, to create condensate, which is then metered into the superheated steam outlet of the boiler through a control valve.
Steam boiler efficiencies in the 80% to 84% level are common with the higher-efficiency boilers including feedwater economizers. Condensing boilers use integral feedwater economizers (discussed further below) that take advantage of condensing the latent heat out of the flue gas stream to bring boiler efficiencies above 90%. These condensing boilers do require higher alloy materials of construction to combat the acidic condensate generated as the flue gas is condensed, capturing the latent heat in the flue gas. Return water temperature and total system design play a large role in the selection of the boiler and final system efficiency goal.
In stand-alone building systems, unless steam is required for some process within the building, hot water boilers often are used. Hot water generated at 130 F and returned to the boiler at 90 F provides ideal conditions for a condensing boiler where efficiencies are above 90%. Added advantages to this system type are safety and reduced energy loss in distribution. The 130 F outlet temperature reduces burn potential and heat loss in the supply side piping. The system still maintains the common 40 F delta T used in most HVAC systems, but will require that the airhandling unit heating, dehumidification coils, and terminal equipment be sized appropriately.
One measure used to rate boilers is the heat release rate of the boiler, which is measured in Btu/ft3/hr. The volume of the convective and radiant furnace area of the boiler is used in this standard calculation. The radiant area of a boiler is the area in which the burner flame is in direct proximity to the boiler tubes or plenum. As the flue gas turns the corner in a water tube boiler or begins the second pass in a fire tube boiler, the convective section of the boiler begins. Improper flame adjustment can allow the flame to enter into the convective section of the boiler, but this is not normal operation and is not advised. The more metal or heat transfer surfaces within the convection and radiant sections of the boiler, the higher the heat release rate will be in the boiler.
Adding a feedwater economizer will increase boiler efficiency by using boiler exhaust gases to heat boiler feed water above the de-aerator temperature, reducing the amount of fuel needed to turn feedwater into steam. A feedwater economizer is a flue gas to feedwater heat exchanger that transfers flue gas heat into boiler feedwater before it enters the boiler steam drum. This capture of waste heat from the flue gas increases boiler efficiency by reducing the amount of energy (Btu’s) required to bring the feedwater to steam temperature and pressures. The economizer can be integral to the boiler, a box- or round-style exchanger assembly installed into the boiler stack, or it can be a cartridge-type insert into the exhaust ductwork of the boiler. The economizer can be designed as parallel or counter flow, the same as most heat exchangers. The counter flow design will have feed water flowing in the opposite direction of the flue gas. The economizer manufacturer will provide a design based on the end user’s flue gas input temperature, desired output temperature, and packaged boiler design.
Economizers can be fitted to both water tube and fire tube boilers and can be integral to the boiler design. Economizer design typically reduces the exhaust gas temperature to near 270 F; however, decreasing the temperature too far can result in condensation of the flue gas, which may create acidic condensate depending on fuel gas properties. Low flue gas temperatures also can create localized spots of condensation and potential corrosion if not controlled.
One way flue gas temperature can be controlled is by throttling the flow of feedwater through the economizer. One method of controlling feedwater flow through the economizer is through a three-way temperature control valve that is modulated based on economizer flue gas outlet temperature. Modulating the flow of feedwater through the economizer reduces the heat removed from the flue gas, raising the temperature to above condensation levels. If the boiler system will be operated normally at less than full load, consideration should be given to flue gas temperature control as discussed above.
Burner design for packaged boilers varies with boiler output. Packaged boilers can be fueled by a range of fuels, including natural gas, #2 fuel oil, propane, syngas, biogas, and #6 fuel oil. Burners can be designed to be dual-fuel units with a primary fuel and secondary or backup fuel. Fuel trains and control systems, regardless of fuel, need to be designed to meet applicable insurance company requirements (Hartford Steam Boiler Inspection and Insurance Co., FM Global, etc.) as well as NFPA 85: Boiler and Combustion Systems Hazards Code or ASME CSD-1 to ensure safe operation of the fuel train and boiler burner. Smaller burners for boilers up to approximately 65,000 lb/h will have the burner forced draft blower mounted directly to the windbox of the boiler, while larger boilers will have the forced draft blower as a separate unit. The forced draft fan motor can range from 10 to 1000 hp, depending on boiler capacity. The larger fan motor voltage normally will be medium-voltage design to reduce wiring size resulting in first-cost savings. The forced draft fan is an integral part of the boiler control strategy, and consideration of variable frequency drive versus damper jackshaft control is needed. Boiler size, operator capability, and system compatibility will help determine the boiler control strategy.
The common control strategy implemented on many new central boiler (20,000 to 300,000 lb/h of steam) installations is fully metered cross-limited operation with oxygen trim where boiler combustion is controlled by metered steam header pressure, fuel flow, and airflow. The fully metered cross-limited control scheme improves control of air-to-fuel mixture through metering of these parameters. The oxygen trim schemes allow for continuous control of excess oxygen in the flue gas, which is accomplished by optimizing combustion air into the boiler. Alternative to fully metered cross-limited boiler control is parallel position control where preset firing curves are developed during boiler startup and commissioning, and used to control fuel and air. These optimized setpoints are then programmed into the combustion control system to provide effective boiler operation across the boiler’s operating range.
Smaller building-specific boilers that only require high- and low-fire capability are normally installed with manual damper controls that are set up during startup and commissioning. The damper positions are set and locked manually to the gas valve position, restricting airflow during low fire to maintain combustion air and minimize NOx formation. At high fire, combustion is optimized to 3% to 6% excess air with fixed damper positions to optimize performance.
NOx emissions for normal burners range from 70 to 100 ppm in the flue gas. Low NOx burners are most often designed to 30 ppm, with ultra-low NOx burners targeting 9 ppm. Low NOx and ultra-low NOx burners are most often fit with flue gas recirculation systems, which bring flue gas from after the boiler or economizer back to the inlet of the forced draft fan. The decision to specify a low NOx versus ultra-low NOx burner should be made while determining the environmental permitting for the boiler. Ultra-low NOx boilers may be needed to meet federal regulations on emissions netting. Permit applications with the U.S. Environmental Protection Agency require emissions netting, which is the process of determining the net increase or decrease of hazardous air pollutants (HAP) possibly emitted from the new boiler compared to the actual emissions measured from the boiler being replaced. Data from the previous 10 years of operation is used to determine the actual HAP levels emitted by the boiler or source being removed. If the boiler being replaced has not operated or has been operated sparingly in the past 10 years, HAP netting may indicate the need for added environmental permit actions, including prevention of significant deterioration (PSD) review, public comment, and public review periods.
Low NOx burners include the mixing of flue gas with the inlet combustion air to reduce the flame temperature at combustion, which helps to lower NOx formation. In some cases additional NOx removal is required. This can be accomplished by selective catalytic reduction (SCR), which uses a reagent and catalysts to convert NOx to nitrogen and water vapor. Note that decreasing the NOx level without an SCR will often increase the level of CO emitted. The boiler burner manufacturer should take this into account in its burner design, as increasing the NOx emission level will also decrease the CO level generated.
Environmental (air) permitting of new boilers falls under EPA and state New Source Review permitting program requirements. Federal New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP)/ Maximum Achievable Control Technology (MACT), including major source and area source considerations, should be reviewed for emission performance regulations that may pertain to the new boiler. Permitting of a new boiler or replacement boilers requires the owner to review existing on-site sources and determine the overall impact of adding the new boiler source. For industrial boilers, NSPS Subpart Db is applicable to units with a heat input greater than or equal to 100 MMBtu/h. Smaller industrial/commercial/institutional units less than 100 but greater than or equal to 10 MMBtu/h are subject to Subpart Dc. Selection of the boiler fuel will play a critical role in determining final boiler allowable emissions levels for regulated air pollutants. As part of the construction permit application, the boiler operator is required to indicate what form of emissions monitoring will be used on the boiler. Emissions monitoring can be done by continuous emissions monitoring (CEMS) or predictive emissions monitoring (PEMS). With a CEMS, flue gas monitoring equipment is used to measure residual O2 or CO2, NOx, and CO. Each of these monitors reads a continuous level of each component in the flue gas for recording and reporting purposes. ThePEMS relies on calculation of expected NOx and CO levels based on fuel gas input, residual O2, or CO2, and boiler operating conditions calculated monthly.
In either case, reporting the CEM or PEM data is required as part of the final construction permit. Suggested levels of emissions for a low NOx natural gas-fired boiler are:
CO (lb/MMBtu) 0.04
SOx (lb/MMBtu) 0.05
Particulate (lb/MMBtu) 0.2
VOC (lb/MMBtu) 0.005
These values will change with selection of fuel type and may need to be altered based on existing equipment being replaced or, in the case of some permits, campus-wide requirements.
Boiler efficiency is a calculation of heat output of the boiler divided by heat input to the boiler. Where the box is drawn around the boiler helps to determine whether you are calculating boiler efficiency or boiler system efficiency. ASME PTC-4 is the standard used when testing the efficiency of boiler systems. This standard includes heat inputs and outputs that are found in large power plant energy generation systems. These inputs and outputs are not normally found on industrial packaged boilers. A simpler means to calculate packaged boiler efficiency that captures the main heat input and outputs that can be easily measured is as follows:
Boiler efficiency = Steam produced (MMBtu) + Boiler blowdown (MMBtu) – Feedwater in (MMBtu)
Fuel in (MMBtu)
This calculation provides credit for the feedwater added to the boiler by reducing the heat required to generate the steam output. The fuel MMBtu value used should be the higher heating value of the fuel, as this is the value that you will pay for when purchasing the fuel. Boiler blow-down is heat out of the boiler and is a necessary part of the boiler process to ensure good boiler operation. This simplified calculation of efficiency is normally a good value to use when calculating the operating efficiency of a packaged boiler.
The selection of a boiler for your business or institutional need is not as simple as picking a boiler manufacturer or boiler type. The proper selection of a boiler should take into account the full system requirements including process needs, heating needs, operator qualifications, distribution needs, environmental permitting, existing systems, and overall system lifecycle costs. A fire tube boiler system may be the short-term lowest capital cost system, but in the long run may be more expensive over the lifecycle due to shorter expected life and increased maintenance requirements. Likewise, the selection of a water tube boiler for a short duration heating season or hot water generation system may increase upfront capital costs that cannot be recovered over the lifecycle of the boiler.
The latest U.S. EPA regulations for industrial boilers require that boiler operators understand the regulations and are able to prove that the systems being added contain the MACT when installed. Selecting the wrong boiler can create long-term operational costs and problems that undermine the overall boiler system operator’s credibility while reducing company or institution operating profits. Selecting the correct boiler will help to increase operating profits and provide for maximum asset value to your client.
Bradley A. Pankow is a principal mechanical engineer and project manager for Stanley Consultants, focusing on educational and institutional steam, hot water, and chilled water generation and distribution systems. Prior to joining Stanley Consultants, he was factory manager and operations manager with H.J. Heinz; a lead mechanical engineer for Raytheon Engineers and Constructors; and engineering manager for Rovanco Piping Systems Inc.
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