The approximately 400,000 industrial and commercial boilers in the United States consume about 33 quadrillion Btu — about 25 percent of the world's energy — per year. The United States imports about 40 percent of that energy from unpredictable sources, such as the Middle East. More than 60 percent of those boilers are more than 20 years old and have operating efficiencies of 70 to 75 percent. That means the United States is wasting large amounts of fuel from precarious sources (400 million barrels of oil per year based on 10 percent waste) and fouling the environment with noxious pollutants that adversely impact health, warm the globe, and alter the climate and ecosystem.
Environmental issues and the need to reduce costs while remaining competitively viable impact process industries, manufacturers, hospitals, schools, commercial buildings, and government institutions. Energy conservation is key for building owners to remain successful in today's economic environment.
About 160,000 boilers are in the U.S. industrial sector. Approximately 90,000 to 100,000 of those boilers are more than 20 years old, average 350 to 400 hp, and produce steam at pressures exceeding 15 psig.
A 400-hp high-pressure steam boiler operating at 100 psig consumes 17,851,733 Btuh when operating at 75-percent fuel-to-steam efficiency. This equals 179 therms of natural gas per hour. If this boiler operates for 5,000 hr annually at $1 per therm, it will cost $895,000 to operate per year. This boiler-operating cost can be associated with the manufacturing of a product, which then must be sold. If the costs to create the product are reduced and the price maintained, the margin of cash flow increases.
Energy should be tracked as closely as any other operating expense. Unfortunately, many businesses consider boiler energy as a cost of doing business, raising prices to cover energy escalation without any price/value offset. Although some operational expenses can be reduced, boilers have certain inefficiencies that cannot be eliminated because of physics and boiler-system thermodynamics. For example, convection and radiation losses in the previously mentioned boiler can account for efficiency reductions of 1 to 2 percent. Some combustion inefficiencies that ensure safety cannot be eliminated, amounting to non-recoverable energy losses of 3 percent. That leaves up to 10 to 11 percent of efficiency that can be recovered (approximately $98,450 per year).
Thus far, this article has focused on a process-steam boiler's potential savings, while omitting total steam-boiler systems and process equipment. However, 20 to 30 percent of savings in the form of trapped condensate return, flash-steam recovery, blowdown heat recovery, vent condensing, etc., is potentially available in these areas. This article's examination of hot-water heating systems will provide a short discussion on the importance of evaluating an entire system when considering possible system inefficiencies and potential energy-cost savings.
About 240,000 commercially sized hot-water boilers are in the United States. Approximately 154,000 of them are more than 20 years old. Many are operating at efficiencies of 60 to 70 percent because of poor design, inadequate control, piping/pumping and radiation deficiencies, excessive cycling, etc.
Often, condensing boilers with efficiencies of 90 to 95 percent can help solve such issues. However, in many cases, non-condensing boilers are replaced at a significant expense, when the cost of the condensing unit and the old boiler's removal are considered. Unless a condensing boiler and its system are understood and configured properly, outcomes can be far less than expected, with high capital expenditures and protracted to nonexistent returns on investment (ROI).
Retrofit or Replacement
Boiler retrofits and replacements involve specific criteria that must be evaluated before a decision is made. These criteria impact several areas of a steam or hot-water-heating facility, such as operations (present and long-term needs, operating hours, downtime impact, load criticality, etc.), the physical plant (mechanical floor area, access, power, piping systems, processes, operating personnel, etc.), and budget constraints (available capital expenditures).
Retrofit and replacement evaluation criteria generally include:
Age and condition of the boiler to be retrofitted or replaced.
Capacity in pounds of steam per hour or hydronic heating load in British thermal units.
Operating pressure or temperature.
Hydronic heating with condensing/non-condensing boilers.
Fuel-to-steam efficiency and overall hydronic-heating efficiency.
Burner characteristics (fuel flexibility, turndown, fuel/air control, etc.).
Control and/or sequencing schemes for steam and hot water.
Duty (heating and/or process).
Removal and installation costs.
When deciding whether to retrofit or replace a process-steam boiler, age is a distant second to condition in the review process. The condition of a boiler's pressure vessel — shell, furnace, and tubes — is most important. The shell, furnace, and tubes make up a boiler's body and venous system, delivering heat energy from the burner.
If an annual inspection of water-side and fire-side surfaces shows minimal signs of heavy scaling, pitting, cracking, or stress, a pressure vessel probably is in good shape and could deliver many more years of dependable life. This indicates that proper operating procedures have been followed, including an effective water-treatment program. A boiler with a pressure vessel in poor condition and that performs poorly has reached the end of its useful life.
The next step is to check the efficiency of a boiler using a flue-gas analyzer, which indicates the percent of oxygen (O2), carbon monoxide (CO), carbon dioxide (CO2), and nitrogen oxide (NOx) in exit gas. Efficiency inspections are performed after a boiler has stabilized and achieved its normal operating pressure. While the boiler is in manual mode, efficiency is checked by modulating fire from low to high throughout the burner's entire range. Readings then entered into a formula corrected for normal operating conditions, and an overall efficiency is attained. This overall efficiency is the basis for determining payback.
If overall efficiency is in the 70-to-80-percent range, and the pressure vessel is in good shape, burner modifications should be considered. If combustion analysis shows high excess air (8 to 10 percent O2) in mid- to high-fire ranges and CO in excess of 50 ppm, a burner requires a major tuneup, upgrade, or replacement.
An upgrade involving controls and air/fuel drives may be the least expensive option. However, upgrade costs should be evaluated based on a boiler's expected life cycle. A life-cycle evaluation may reveal additional savings when a properly sized burner is fitted to a boiler's furnace for optimum radiant-heat transfer. At this time, controls should be updated with advanced technology to govern burner safety and communicate and historically trend burner operation, proactively managing boiler energy choices.
Even if a boiler performs well throughout an efficiency analysis, incremental savings may be available because of the boiler's original sizing to its load. Inefficiency often occurs during summer, when an oversized boiler remains mostly in low fire, cycling several times an hour. This drives up radiation and convection losses as a percent of input while increasing excess-air levels and reducing combustion efficiency. Excessive cycling and poor combustion efficiency can reduce a boiler's efficiency from a normal full-capacity rating of 83 percent to a percentage in the low 70s. As mentioned previously, a 400-hp boiler costs $895,000 annually to operate at 75 percent. A 5-percent improvement in those areas would equate to almost $45,000 per year.
The best solution may be to purchase a small “summer boiler” properly sized for reduced-load conditions. A boiler that provides adequate backup for a larger boiler during peak load time during winter should be considered. Taking into account the hourly cost of plant downtime per unit, annual savings can be substantial with this strategy, especially during times of fuel-price volatility. This solution can be applied to any efficient boiler with “shoulder” operating months. Even on new projects, this can be an effective energy solution.
Considering a boiler consumes, on average, four times its cost in fuel every year, all of the issues pertaining to boiler-replacement selection, including operational, physical, and financial concerns, need to be well thought out. A boiler purchase needs to be evaluated on a true price/value basis using the previously mentioned financial criteria, especially life-cycle costing. Duty load needs to be considered as well as all of the energy and operational needs a boiler may have to handle, such as swing conditions, steam quality, burner turndown, boiler-control schemes, emission limitations and credits, domestic and clean-in-place water needs, guaranteed efficiencies, local service/parts, training, and removal and replacement costs.
Overall efficiency is the primary concern for hydronic heating systems with non-condensing boilers operating at system temperatures of approximately 180°F to 200°F and return-water temperatures between 160°F and 180°F. Overall system efficiency, or annual seasonal efficiency (ASE), includes piping pickup/loss factors, boiler thermal efficiency, outdoor-air adjustments, radiation/convection losses, and cycling losses.
Some engineers quickly decide to replace older boilers with higher-efficiency condensing boilers, giving little thought to a system's operating conditions and what will be required for these new units to realize their full savings potential. New condensing boilers that are allowed to operate at higher design temperatures, such as 180°F supply and 160°F return, most of the time will not condense or realize their associated savings. Because the capital investment of a condensing boiler is 15 to 20 percent higher than that of a non-condensing unit, the loss of efficiency will negate any expected ROI.
For boilers to condense, the system would have to operate at a lower temperature of around 140°F with a return temperature of 120°F. Adequate air-handler-coil surface must be ensured to achieve comfort at these lower temperatures, and any domestic water supplied indirectly through the boiler must be handled properly to fulfill design requirements. In this case, retrofit or replacement may not be necessary. Instead, a boiler may be supplemented.
Hybrid Hydronic Heating Plants
A hybrid boiler plant is defined as a hydronic heating plant that combines condensing and non-condensing boilers. This type of system is designed to take advantage of the best properties of both boiler types. Through proper design and selection, it may be possible to save the same amount of energy associated with a properly designed fully condensing plant by designing a hybrid system at one-third to half of the cost.
Hybrid boiler plants also may include alternative-fuel boilers, such as electric/electrode units. The use of one alternative fuel over another can be driven by the instantaneous cost of the fuel. Cost monitoring of fuel can drive a switchover between operating boilers and should be part of operating procedures.
Where to Use Hybrid Systems
Higher return-water-temperature requirements are one of the main stumbling blocks to using non-condensing boilers for higher-efficiency designs. As mentioned previously, in most applications, water has to be returned to a boiler at or above 130°F to 140°F to prevent flue-gas condensation. Normally, the dew point of exhaust gases is approximately 135°F.
Hybrid systems can be utilized in legacy/existing plants or new designs. Older non-condensing boilers could reduce overall project cost significantly, provided their pressure vessels and burners are in acceptable shape.
An energy solution that combines the ideal number of condensing and non-condensing units can reduce fuel consumption by more than 40 percent relative to existing systems or new non-condensing systems. Even though this savings is caused by the reduction of boiler cycling, all of the design requirements for comfort, domestic water, snow melting, etc. are satisfied.
Figure 1 shows a heating profile typical of many commercial buildings. Within this profile, maximum heating load occurs during winter months. However, when fuel consumption is normalized against a unit of consumption, such as heating degree days, more heat is consumed in off-peak months, such as October and April (Figure 1). This occurs when a proportional-integral-derivative (PID) loop cannot be maintained within acceptable parameters, resulting in what often is referred to as “short cycling.”
Two control concepts lead to a boiler system's ultimate savings, represented by the theoretical curve in Figure 2. The first concept to consider is intelligent flow. Current control schemes are based on PID temperature controls. Although these controls are an improvement over older systems they have not caught up with advances in processing software. British-thermal-unit heating-load consumption now can be calculated to match a heat profile exactly. In other words, British thermal units that are lost in a system can be recovered immediately through mass-flow balancing.
By utilizing this applied control, needless boiler cycling is reduced greatly, if not eliminated. Under current control scenarios — on-off boiler cycling at low-load conditions and the pursuit of PID-loop temperatures — boiler efficiency can be reduced by 20 to 30 percent. Even when utilizing a condensing boiler at low return temperatures, theoretical efficiencies of 95 percent can drop to as low as 65 percent under high cycling conditions. Through the use of system delta-T and flow rate, actual consumed heating load can be calculated. Therefore, theoretical energy savings is the difference between the curves in figures 1 and 2.
The second concept to consider is intelligent load sharing. With a properly sized boiler, run cycles can be limited to two or fewer per hour under no-load conditions. To accomplish this, a small boiler is sized to allow 30 min of run time under no-load conditions (delta-T multiplied by 500 [8.3 lb per gallon of water multiplied by 60 min]). Given system volume and the delta-T of a boiler's operating set point, minimum firing rate can be calculated. With this minimum firing rate, a boiler with an appropriate turndown can be selected to track heating load, picking up minimum losses as they occur. During most evaluations, this outcome usually is achieved by a boiler smaller than the rest of the units attached to the heating plant. The use of a smaller boiler is similar to the “summer-boiler” concept used in steam plants. In these cases, a small steam boiler is used to carry light loads, leaving only a small process load. The steam used for sterilization and/or humidification in a hospital is one example.
To accomplish intelligent load sharing, a heating-plant control must be able to calculate the load consumed and recognize the minimum and maximum capacity of each boiler. The controller also must be able to turn modulating boilers on and off to match the load exactly. Sizing and control schemes using only temperature variation (without mass-flow calculation/selection) usually employ multiple equally sized boilers, resulting in considerable on-off cycling as the load drops below minimum turndown. This is extremely inefficient because of frequent pre- and post-purge losses and stresses mechanical equipment, leading to higher incidences of costly repairs and downtime.
How Hybrid Systems Work
Condensing boilers are used in hybrid systems when heating loads drop to an outside-air temperature of about 32°F to 35°F. In northern climates, this accounts for approximately 75 to 80 percent of the heating season and about one-third of the heating load. Actual loads will need to be verified using load-calculation software or existing load profiles.
As heating load increases with a drop in outside-air temperature, switching to non-condensing boilers provides heat for the incremental increase in demand. Built-in algorithms enable the transition from condensing to non-condensing units. When utilizing the piping configuration shown in Figure 3, condensing-boiler outputs are driven up to or above 140°F. This configuration ensures that the inlet to non-condensing boilers can prevent condensation.
As load increases (increasing heat loss), the non-condensing boilers take charge. If the non-condensing units are sized for two-thirds of the load, condensing boilers can supplement when a smaller load is needed or during the most severe conditions. If more than one non-condensing unit is used, the control can change or sequence the operating units in a lead/lag setting to equalize run time. The use of non-condensing boilers allows for higher temperatures (more British thermal units) on colder design days. This concept supports higher supply temperatures, keeping the heating coil surface in reheat boxes to a minimum, and accommodates the use of indirect domestic-hot-water heating.
A burner-management system, sometimes referred to as a flame safeguard, can help determine good hybrid-system candidates. Many burner-management systems keep track of the number of cycles and run hours. If boilers are cycling excessively, the boiler system is a good hybrid-design candidate. Many boiler rooms experience 10 to 40 cycles per hour, which can indicate a heating plant that is oversized for small loads. Other indicators include excessive maintenance requirements, frequent downtime, and general customer frustration with fuel bills and/or system performance.
As previously mentioned, Figure 2 shows potential energy savings as the difference between the trend lines. The captured savings will be greater during off-peak months, such as October and April. Systems in moderate or mid-range climates generally will produce greater overall savings because they experience additional operating hours during off-peak months. Warmer climates still can achieve potential savings if a summer reheat schedule is used.
A traditional non-condensing boiler plant has an ASE of 65 to 70 percent because of on-off cycling during off-peak design seasons. A boiler plant using condensing boilers exclusively could reach an ASE of up to 93 percent. However, a properly designed hybrid system could reach these levels at a lower installation cost than that of an all-condensing-boiler plant.
Finally, a minimum savings of 20 percent can be expected with hybrid systems, though savings as high as 40 to 50 percent can be realized. Additionally, hybrid systems can reach these savings levels without changing high supply temperatures during design-day conditions. The final result is retrofit applications that are more affordable with shorter payback periods. Combining condensing boilers with new (or existing) non-condensing units can help achieve the best of both worlds.
Steve Connor is the director of marketing/communications for Cleaver-Brooks Inc. A frequent speaker and author on boiler design, efficiency, and safe operation, his background includes more than 40 years of experience in steam generation, including engineering, service training, and field-application sales.