Boilers that exceed these restrictions are termed power boilers and are widely used in industry and institutional applications such as hospitals, laboratories, college campuses, and prisons. These applications may involve long distance distribution that makes steam a practical heating medium or they may involve processes such as sterilization, laundry, or kitchen facilities that utilize steam. High temperature hot water is also used as an efficient means of transferring energy over long distances and can be used to drive the processes in equipment such as absorption chillers.
For whatever reason power boilers are employed, there are certain features that must be considered and incorporated into the design of these systems. These unique features of power boiler system design are a direct result of their higher operating temperatures and pressures. For instance, the pressure relief vent on a large, high-pressure steam boiler would not be terminated indoors as might be done on a smaller hot water heating boiler as the uncontrolled release of steam is a danger to operating personnel. Because of this danger, when two power boilers are connected to the same steam main, the steam connection from each boiler must be fitted with two stop valves with a free-blowing drain between them.
If one of the two boilers is down for its annual inspection, you cannot have the stop valve fail and bleed steam back into the open boiler. The first valve at the boiler would be a non-return valve installed at the outlet and the second valve would be an outside screw-and-yoke type. High temperature hot water boilers would also require two valves on the return connection to the boiler.
The duty seen by many power boilers is such that they are large enough to catch the attention of government regulators. For instance, Ohio law requires that steam boilers larger than 30 hp cannot be operated unless they are directly in the charge of a licensed engineer. The law goes on to define one hp as 12 sq ft of boiler heating surface. Additionally, this engineer may not leave the boiler plant unattended any longer than the length of the evaporation test of the boiler. Rules such as this have been the source of ambiguity and debate, however environmental regulations tend to be a more likely cause of confusion.
The Clean Air ActThe Clean Air Act was enacted by the federal government in 1963 and has been amended numerous times. The 1970 amendments set national air quality standards as well as standards for new pollution sources. The 1977 amendments imposed stricter standards on new emissions sources, established a more comprehensive permitting process, and extended compliance deadlines. The 1990 Clean Air Act Amendments, however, have proven to be the most complex and far-reaching environmental law that Congress has enacted. The 1990 CAAA with its 11 titles has definitely impacted the HVAC industry. Title VI, for instance which covers ozone protection, has changed the air-conditioning and refrigeration industry by phasing out CFCs.
When it comes to boilers and the EPA, size matters. As long as boiler input is less than 10 MMBtu, it will not be affected by the 1990 CAAA. Interestingly, it does not matter how a large the boiler plant actually becomes. Therefore a plant comprised of many boilers just under this threshold would not have to deal with these environmental regulations.
The 1990 CAAA required the 50 states to each submit an implementation plan detailing how they would meet the federal pollution reduction goals. The states can delegate authority to regional entities, but are ultimately charged with implementing and enforcing the amendment. For instance, the Ohio EPA operates one of the nation’s most extensive air monitoring networks. The system is comprised of nearly 400 monitors with the task of determining if air pollution controls are effective.
The federal EPA has instituted the National Ambient Air Quality Standards (NAAQS) that address six pollutants: nitrogen dioxide, sulfur dioxide, ozone, lead, carbon monoxide, and particulate matter. Lead is not an issue in the emissions of power boilers unless they operate on fuels such as waste oil. Ozone is a secondary pollutant formed by the reaction of hydrocarbons with nitrogen oxides (NOx). Hydrocarbons, sometimes referred to as volatile organic compounds (VOCs), can be controlled by maintaining proper combustion conditions. Carbon monoxide is formed by incomplete combustion and, like VOCs, can be controlled by maintaining the burner so that it maintains a proper air-to-fuel ratio.
Sulfur dioxide is classified as a pollutant because it reacts with water vapor in the air to form sulfuric acid, contributing to acid rain. This pollutant is best reduced by switching to low-sulfur fuels. As with sulfur, the key to reducing particulate emissions is in selecting clean fuels. Nitrogen compounds, unlike these other pollutants can be reduced by the design of the burner.
Low NOx TechnologiesOf the six regulated pollutants, reduction of nitrogen compound emissions can be influenced by the design professional through equipment specifications. As a result, this pollutant has been targeted by many regulatory jurisdictions for reduction when it comes to the installation of new power boilers. Like sulfur compounds, NOx can lead to acid rain and can also contribute to the production of ozone.
Power boilers can form NOx in two ways. Fuel NOx is formed by the reaction of nitrogen contained in the fuel with oxygen in the air and is not a problem when natural gas is the fuel. However, fuel oils can contain significant amounts of nitrogen and can account for up to 50% of total NOx emissions of power boilers. Thermal NOx is produced when nitrogen and oxygen in the combustion air combine due to the high temperatures present in the flame. Thermal NOx will make up the majority of NOx formed during the combustion of natural gas and light fuel oils.
As thermal NOx is produced by high temperatures in the burner flame, reduction in the flame temperature can impact emissions. Strategies used to control flame temperature fall within the category of combustion control techniques and include flue gas recirculation and steam injection. Although post combustion methods exist to address NOx control, they are expensive and are normally not used on boilers less than 100 MMBtuh input.
While it is possible to reduce thermal NOx by modifying the burner to produce a larger flame, this technique has its limitations and is usually coupled with other methods. One of these methods is flue gas recirculation. This involves diverting a portion of the relatively cool flue gases back into combustion zone in order to reduce the flame temperature. There are two types of flue gas recirculation. The first is external flue gas recirculation where a separate fan and ductwork force a portion of the flue gases back through the burner. The second type is known as induced flue gas recirculation, where the burner blower is used to draw flue gases back to be mixed with new combustion air and fuel.
Another method of low NOx combustion control technology involves the injection of steam into the flame, thereby reducing its temperature and subsequently reducing NOx production. This approach can reduce NOx emissions by up to 80% when firing natural gas; however, efficiency can be degraded by 3% to 10%. Figure 1 shows a 30,000-pph steam boiler fitted with a steam-injection, low-NOx burner.
Permitting ProcessAs mentioned previously, any new boiler over 10 MMBtu input will be affected by the 1990 CAAA. Each state is required to manage its state implementation plan (SIP). In Ohio, a new source of emissions over this threshold requires a permit to install (PTI) to be approved by the Ohio EPA. There are similar, if not identical, procedures in other regional jurisdictions of the United States.
It is important to submit the application for the PTI to the regional air authority early in the design stages of the project so that any changes can be made before the bidding process. The PTI includes information such as the proposed boiler location; equipment description, construction and testing schedule, plus a listing of the air pollutant emissions for any pollutant that will exceed one ton per year. Supporting calculations are also required as well as a process schematic. The process schematic can be very simple showing the features of the proposed installation that are of importance to the air authority such as fuel, firing rate, flue gas volume, and stack configuration.
Although the project may be in an attainment area for all pollutants, there could be special requirements if the facility is considered a major air pollution source under Title V of the 1990 CAAA. Under Title V, major sources are those that have a potential to emit:
- 100 tons per year or more of any one regulated pollutant (particulate matter; nitrogen oxides; sulfur dioxide; carbon monoxide; VOCs; lead);
- 10 tons per year or more of any one hazardous air pollutant; or
- 25 tons per year or more of any two or more hazardous air pollutants (there are nearly 200 listed in Section 112 of the 1990 CAAA).
Once the PTI is obtained, the construction of the new boiler installation can start. Testing will then be required to verify that the emissions conditions of the PTI will be met. The local air authority may be able to provide a list of qualified testing agencies. After receipt of the emissions compliance report, the air authority will then issue the permit to operate.
Best Available Control TechnologyFor larger boiler installations and for institutions identified as major sources, the regional air authority may require that the new installation incorporate the best available control technology or BACT. This can be a vague goal where economics are taken into account.
On a recent boiler replacement project at an Ohio prison, BACT was required to be implemented to control the emission of NOx. This was a 30,000-pph steam boiler that would have emitted slightly less than 8 tons of NOx per year if fitted with a standard 80-ppm burner. Going with a 40-ppm, low-NOx burner would reduce the annual emissions by nearly 4 tons at a cost of about $60,000 for the equipment. This equates to about $15,000 per ton, which is considered fairly expensive.
Alternates were taken for 30-ppm and 25-ppm NOx burner configurations with pricing at about $8,000 each. This equates to about $8,000 and $16,000 per ton respectively for the incremental reductions.
Although the regional air authority accepted a 40-ppm burner design in the Permit To Install application, the client chose to go with the 25-ppm low-NOx burner. This strategy allowed the client some breathing room when it came to the emissions testing.
Control SystemsMost power boilers installed at large institutions are dual fuel and are typically set up to operate on natural gas and #2 fuel oil (Figure 2). Large consumers of gas can get a rate break from the utility if they have the ability to be curtailed and switch to oil. More importantly, however, is the nature of many institutions where they cannot tolerate an interruption of fuel. Some institutions still burn coal, and more than likely receive political and legal pressure from the regional air authority to convert to cleaner fuels.
An important issue for many facilities is the turndown ratio of the burner, as the peak steam demand will often vary significantly from winter to summer. Although a turn-down of 10 to 1 or greater may be achievable on a standard natural gas burner, the addition of low NOx requirements may make this unattainable. An 8-to-1 or even 6-to-1 turndown ratio may be more reasonable. The resulting turndown when firing fuel oil may be even lower.
When firing on fuel oil, a means of atomizing the fuel is required. Smaller, packaged boilers often use pressure atomization where an oil pump pressurizes the oil to the 200 to 300 psig range. This pump can be driven from a belt coupled to the blower motor. Larger boilers with specialized burners require either steam or compressed air for atomization. Steam atomization is less energy intensive and less expensive to install.
However, because this method requires steam pressure for operation, the system cannot be restarted on oil once steam pressure is lost. To compensate for this, a connection can be installed to allow restarting with a propane tank. Air atomization requires a compressed air source that could possibly have a larger motor horsepower requirement than the blower used for combustion air. Not only does this consume a lot of power, it also can be very noisy.
Control of feedwater is of paramount importance. If the drum level is too high, water droplets can be entrained into the steam leaving the boiler, which can cause damage to system components downstream. The consequences of low water level include a reduction in furnace circulation, which can cause tube overheating and failure. Feedwater control systems are classified as single-, dual-, or three-element feedwater control systems. Single element systems operate solely on the level of the water in the drum. As the level drops below setpoint, the feedwater valve is opened to admit more water to the drum. This works well in many institutional applications with slow changes in the load as a proportional plus integral signal is applied to the difference between the drum level and setpoint.
If large load swings are anticipated, dual-element feedwater control may be considered. In addition to water level, the instantaneous steam-flow measurement is used to calculate the appropriate feedwater makeup rate. Three-element feedwater control adds the measurement of flow in the feed line as well as steam flow and drum level to provide an even greater degree of control. Three-element control is generally seen in the utility industry. Figure 3 shows a freestanding combustion control panel.
The firing rate for steam boilers will be in response to a deviation from setpoint as indicated from a pressure sensor typically located in the header. Most institutional boilers can use a control strategy known as single-point positioning to respond to load demand and to adjust for optimum fuel-to-air ratio. The firing-rate control signal is used to drive a common actuator that adjusts both the fuel delivery rate by modulating a valve, and the combustion airflow by actuation of dampers. The cams on the specialized actuator can be custom shaped in the field to provide for specific positioning control characterization of the relationship between the input signal and the output shaft position.
A more sophisticated approach known as parallel positioning utilizes separate actuators for the fuel valve and the combustion air dampers allowing for more precise control across the entire range of firing.