Process Heating: Combustion Efficiency Fundamentals of Combustion During the combustion of fossil fuels, hydrocarbon molecules such as methane, CH4, are combined with oxygen to produce carbon dioxide and water in an exothermic reaction. The simplified combustion equation for the combustion of natural gas is: CH4 + 2O2 → CO2 + 2H20 The ratio of the mass of combustion air, mca, to the mass of natural gas, mng, is called the air fuel ratio, AF. Using the simplified combustion equation above, the air fuel ratio for stochiometric (complete) combustion, AFs, can calculated to be about: AFs = (mca/mng)stoch = 17.2 In practice, incomplete mixing of air and natural gas requires that “excess air”, EA, be supplied. Excess air is defined as: EA = mca,actual / mca,stoch - 1 If the supply of combustion air is insufficient to combust all of the fuel, then uncombusted fuel will go up the stack reducing the combustion efficiency and increasing hydrocarbon emissions that cause smog. Too much air reduces the combustion temperature and the combustion efficiency. For most applications, exhaust gas oxygen levels of about 2% and corresponding excess air levels of about 10% are optimum. North American burner recommends about 20% excess air (“Low Emissions Gas Burner”, Bulletin 4452, North American Manufacturing Company, March, 2005). However, some drying or solvent evaporation applications may require higher levels of excess air. The actual air/fuel ratio, AF, can be written as: AF = (1+EA) x AFs From an energy balance on the combustion process, the combustion temperature, Tc, can be calculated as: Tc = Tca + hr / [cpp x {1 + (mca/mng)] Tc = Tca + hr / [cpp x {1 + (1+EA) x AFs] where cpp is the specific heat of products of combustion, Tca is the temperature of the combustion air before entering the burner and hr is the heat of reaction of the fuel. The heat of reaction, hr, is the useful heat transferred from the combustion chamber during the combustion reaction. The heat of reaction depends on the phase of the water in the exhaust gasses. If water leaves as a vapor, it carries away the heat required to vaporize the water and less useful heat is available for the process. In this case, the heat 1
of reaction equals the lower heating value (LHV) of the fuel. If water leaves as a liquid, more useful heat is available to the process and the heat of reaction equals the higher heating value (HHV) of the fuel. The heating values of natural gas are shown below: LHVng = 21,500 Btu/lbng
HHVng = 23,900 Btu/lbng
The dew point temperature of water in exhaust gas is about 140 F. Because most exhaust gas streams are above this temperature, the heat of reaction is generally the lower heating value of the fuel. The steady-state efficiency of combustion is the ratio of the useful heat delivered to the process to the heat content of the fuel. Using the preceding equations, the combustion efficiency is: Eff = [{1 + (AF)} x cpp x (Tc-Tex)] / HHV Eff = [{1 + (1+EA) x (AFs)} x cpp x (Tc-Tex)] / HHV Thus, the combustion efficiency can be determined as a function of only three variables that must be measured: excess air, EA, the temperature of the combustion air before it enters the burner, Tca, and the temperature of the exhaust gasses, Tex. These variables are measured by combustion analyzers. Excess air, EA, is determined by the ratio of O2 and CO2 (or CO) in the exhaust gas. The equations to determine combustion efficiency can be entered into a spreadsheet. The spreadsheet, CombEff.XLS, is shown below. CombEff.XLS Input Data EA = excess air (0=stoch, 0.1 = optimum) Tca = temperature combustion air before burner (F) Tex = temperature exhaust gasses (F)
0.50 70 350
Constants for Natural Gas LHV = lower heating value (Btu/lb) HHV = higher heating value (Btu/lb) cpp = specific heat of products of exhaust (Btu/lb-F) Tdpp = dew point temp of H20 in exhaust (F) Afs = air/fuel mass ratio at stochiometric conditions
21,500 23,900 0.260 140 17.20
Combustion Efficiency Calculations hr = heat of reaction = (if Tex CO2 + 2 H2O Mair / Mfuel = (2 x 2 x 16) / (12 + 4) = 4.0 This value can be used in conjunction with the previous simplified equations for combustion temperature and efficiency of combustion with oxygen. Combustion efficiencies calculated using the simplified method compare well with values from the graph below. The primary reason for the small discrepancies between the simplified method and the graph shown below is that the simplified method is based on combustion of pure methane while the graph below is for natural gas, which includes a small percentage of other hydrocarbons in addition to methane.
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Pollution Control Primary air pollutants include VOCs, NOx and SOx. When fuel is burned with insufficient oxygen, unburned hydrocarbons are carried out in the exhaust. Visually, unburned hydrocarbons appear as smoke or sooty exhaust. When unburned hydrocarbons collect in an exhaust stack, they become a serious fire hazard. Primary indicators of unburned hydrocarbons are CO and H2, which increase exponentially with insufficient oxygen. Volatile organic compounds (VOCs) are another class of carbon compounds released during incomplete combustion. VOCs and O3 (Ozone) react with sunlight to cause visual smog which is also a health hazard.
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Nitrous oxides (NOx) are created when the nitrogen in air reacts with oxygen at high temperatures. The quantity of NOx produced increases with temperature (see figure below). Thus, a drawback to preheating combustion air is increased NOx formation.
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Source: Combustion Fundamentals, Klassen, 2003 Gas Machinery Research Council. Low NOx burners can reduce NOx formation. In addition, flue gas recirculation, in which flue gas is injected into the combustion process to preheat the air and fuel can also substantially reduce NOx formation (A Novel Method of Waste Heat Recovery from High Temperature Furnaces, Arvind Atreya, Department of Mechanical Engineering, University of Michigan, ACEEE Industrial Energy Efficiency, 2007) Sulfur oxides (SOx) are created when the sulfur in fuel reacts with oxygen. SOx reacts in the atmosphere with water to form sulfuric acid and is a principle component of “acid rain”. The quantity of SOx created is largely a function of the sulfur content of the fuel. Coal has relatively high levels sulfur, while natural gas has virtually none.
How To Look At A Flame And Know If It’s Right (Source: CEC Combustion Services
[email protected]) Looking at a flame and understanding what’s going on is more an art than a science. There are however a few basic rules of thumb that can help you to know what’s going on. When you look at a flame you generally need to be looking at a flame moving towards you. It’s not a guarantee that you will even have a site port that will allow you to do this. If you find such a port, first wave your hand around it to make sure there’s no flue gas leakage. Then with a gloved hand you push on the glass a little to make sure it does not break easily. Then with safety glasses on and a long sleeved shirt, go ahead and look. You’ll be looking for a few basic things like color.
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For stoichiometric (Perfect) combustion, you’ll want to see a nice rich blue with little orange or yellow tips. If you see a very pale blue, and if it’s noisy and appears to have a lot of energy and sharp edges, it’s probably too lean of a mixture. If the flame is fat, lazy and bright yellow or orange you’re way too rich.
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Example Recommendations
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AR X: Specify O2 Trim Controls on New Boilers ARC: 2.1233.1 Natural Gas
Annual Savings Resource CO2 (lb) Dollars 3,387 mmBtu 433,600 $32,384
Project Cost Simple Payback Capital Other Total $28,000 None $28,000 10 months
Analysis The plant’s existing boilers use linkages that connect natural gas supply valves with combustion air inlet dampers. In such a configuration, combustion air intake is controlled based on natural gas input to the boilers. The following table and graph shows the exhaust gas temperature, excess air, and combustion efficiency of Boiler #2, which is a 100-hp boiler, at different firing rates. Air/fuel ratio is not constant over the firing range, but rather increases as firing rate decreases.
High Fire Performance Exhst. Temp 457 F
Excess Air 45%
Comb. Eff. 79.3%
Medium Fire Performance Exhst. Temp 412 F
Excess Air 54%
Low Fire Performance
Comb. Eff. 80.0%
Exhst. Temp 394 F
Excess Air 88%
Comb. Eff. 78.6%
Boiler #2 500 450
Excess Air
400 350 300 250 200
Exhaust Gas Temperature (F)
100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0%
150 Low 1
Medium 2
3High
Firing Rate Excess Air
Exhaust Temp
The optimal excess combustion air in a gas heating system for energy efficiency and pollution prevention is about 10% (“Guide to Industrial Assessments for Pollution Prevention and Energy Efficiency”, EPA/625/R-99/003), which yields an O2 content of 1.7% in the exhaust gasses. Higher levels of excess air dilute the combustion stream and decrease the quantity of useful heat available to the process.
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An emerging technology in fuel-fired energy systems is O2 trim combustion controls, which controls combustion intake air based on air/fuel ratio of combustion. Such a system consists of a gas monitoring probe inserted in the exhaust stack, measuring realtime oxygen content of exhaust gasses. The probe is linked to a control that automatically opens or closes the combustion air inlet damper to maintain a desired excess air level at all times. The desired excess air level, or O2 content, can be digitally programmed into the control system. Management is considering replacing the existing six 100-hp boilers with two 300-hp boilers. If done, specifying an O2 trim on the boilers would be very economical. Although an O2 trim specification would increase the cost of the new system, the energy cost savings over the life of the system would be magnitudes higher than the additional upfront cost. Efficiency measures such as an O2 trim are most economical when implemented at the construction stage of a project. Recommendation We recommend specifying an O2 trim on the two new 300-hp boilers, if installed. We recommend programming the O2 trim to maintain 10% excess air, which yields an O2 content of 1.7% in the exhaust gasses. Estimated Savings In the Steam System Analysis section of the report, we calculated that the plant’s boilers operate at about 53% of full-fire on average. According to the plant’s boiler technician, Boiler #2 performs very similarly to the other five 100-hp boilers. Thus, we assume that each 100-hp boiler, on average, operates at about 54% excess air with a stack temperature of about 412 F, which is how Boiler #2 operates at medium fire. This yields a combustion efficiency of 80.0%. To find the efficiency improvement from reducing excess air from 54% to 10%, we used the simulation software program HeatSim (Kissock and Carpenter, 2005), which can be downloaded free of charge off of the UDIAC website www.udayton.edu/udiac. HeatSim models a boiler as a heat exchanger and uses fundamental combustion equations and heat exchanger equations to find the change in heat transfer and efficiency from reducing boiler excess air. The combined rated heat input to the plant’s six 100-hp (4.2 mmBtu/hour) boilers is: 4.2 mmBtu/hour-boiler x 6 boilers = 25.2 mmBtu/hour The HeatSim output screen below shows the efficiency improvement and energy savings from operating the same steam heat load at 10% excess air instead of 54% excess air. The input values are either defined earlier in this AR or in the Steam System Analysis section of the report.
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According to HeatSim, the efficiency of the boilers would rise from 80.0% to 82.7%, and fuel savings would be about 0.438 mmBtu per hour. Annual natural gas savings would be about: 0.438 mmBtu/hour x 8,760 hours/year = 3,837 mmBtu/year 3,837 mmBtu/year x $8.44 /mmBtu = $32,384 /year The total reduction in CO2 emissions would be about: 3,837 mmBtu/year x 113 lb CO2/mmBtu ≈ 433,600 lb CO2 /year Estimated Implementation Cost According to the plant’s boiler provider, the additional cost of including an O2 trim on a new boiler is about $14,000 per boiler. The additional cost for two boilers would be about: $14,000 /boiler x 2 boilers = $28,000 Estimated Simple Payback ($28,000 / $32,384 /year) x 12 months/year = 10 months
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AR X: Adjust 250-hp Boiler’s Burner to 10% Excess Air at High Fire ARC: 2.1233.1 Natural Gas
Annual Savings Resource CO2 (lb) 841 mmBtu 95,000
Dollars $7,098
Project Cost Capital Other Total None None None
Simple Payback Immediate
Analysis The plant’s existing boilers use linkages that connect natural gas supply valves with combustion air inlet dampers. In such a configuration, combustion air intake is controlled based on natural gas input to the boilers. The following table and graph shows the exhaust gas temperature, excess air, and combustion efficiency of the plant’s 250-hp boiler at different firing rates. Air/fuel ratio is not constant over the firing range, but rather increases as firing rate decreases.
High Fire Performance Exhst. Temp 531 F
Excess Air 32%
Comb. Eff. 78.3%
Medium Fire Performance Exhst. Temp 463 F
Excess Air 56%
Low Fire Performance
Comb. Eff. 78.4%
Exhst. Temp 352 F
Excess Air 115%
Comb. Eff. 78.7%
140%
600
120%
550 500
Excess Air
100%
450
80%
400
60%
350 300
40%
250
20% 0%
200 Low 1
Medium 2
High 3
Exhaust Gas Temperature (F)
250-hp Boiler
150
Firing Rate Excess Air
Exhaust Temp
The optimal excess combustion air in a gas heating system for energy efficiency and pollution prevention is about 10% (“Guide to Industrial Assessments for Pollution Prevention and Energy Efficiency”, EPA/625/R-99/003), which yields an O2 content of 1.7% in the exhaust gasses. Higher levels of excess air dilute the combustion stream and
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decrease the quantity of useful heat available to the process. Boiler service technicians generally calibrate excess air with burners at high fire. If the 250-hp boiler were calibrated to 10% excess air at high fire, excess air would decrease at all firing rates without the possibility of falling below 10%. Recommendation We recommend requesting the plant’s boiler service technician adjust the 250-hp boiler’s burner to 10% excess air at high fire. Thus, excess air should decrease over the boiler’s entire firing range. We also recommend doing the same for the 100-hp boilers if they do not plan to be replaced with new boilers. Estimated Savings In the Steam System Analysis section of the report, we calculated that the plant’s boilers operate at about 53% of full-fire on average. Thus, we assume that the 250-hp boiler, on average, operates at about 56% excess air with a stack temperature of about 463 F, which is how it operates at medium fire. This yields a combustion efficiency of 78.4%. From the above chart, excess air seems to vary rather linearly with excess air. Thus, if the excess air at high fire decreased 22 percentage points to 10%, we assume that excess air at medium fire would also decrease 22 percentage points to 34%. To find the efficiency improvement from reducing excess air from 56% to 34%, we used the simulation software program HeatSim (Kissock and Carpenter, 2005), which can be downloaded free of charge off of the UDIAC website www.udayton.edu/udiac. HeatSim models a boiler as a heat exchanger and uses fundamental combustion equations and heat exchanger equations to find the change in heat transfer and efficiency from reducing boiler excess air. The HeatSim output screen below shows the efficiency improvement and energy savings from operating the 250-hp boiler at 10% excess air instead of 54% excess air. The input values are either defined earlier in this AR or in the Steam System Analysis section of the report.
16
According to HeatSim, the boiler efficiency would rise from 78.4% to 79.9%, and fuel savings would be about 0.096 mmBtu per hour. Annual natural gas savings would be about: 0.096 mmBtu/hour x 8,760 hours/year = 841 mmBtu/year 841 mmBtu/year x $8.44 /mmBtu = $7,098 /year The total reduction in CO2 emissions would be about: 841 mmBtu/year x 113 lb CO2/mmBtu ≈ 95,000 lb CO2 /year Estimated Implementation Cost Requesting the plant’s boiler service technician adjust settings on the boiler would require no significant cost. Estimated Simple Payback Immediate
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AR X: Recalibrate Boiler Air/Fuel Ratio to 10% Excess Air at Medium Fire ARC: 2.1233.2 Natural Gas
Annual Savings Resource CO2 (lb) Dollars 799 mmBtu 90,300 $5,769
Project Cost Capital Other Total None None None
Simple Payback Immediate
Analysis The optimal excess air in a gas heating system for energy efficiency and pollution prevention is about 10% (“Guide to Industrial Assessments for Pollution Prevention and Energy Efficiency”, EPA/625/R-99/003). Higher levels of excess air dilute the combustion stream and decrease the quantity of useful heat available to the process. In addition, higher excess air levels cause the combustion stream to flow at higher velocities, thereby reducing the heat transfer rate within the boiler. Two boilers provide process heat to the plant. The large boiler, rated at 8.7 mmBtu/hour, is the plant’s primary boiler. The small boiler, rated at 6.5 mmBtu/hour, is the backup boiler and only provides process steam about one day per month, according to maintenance. Otherwise, it is kept warm on standby. During our visit, the small boiler provided process steam and the large boiler was on standby. Controls on the boilers modulate natural gas and air intake to maintain the pressure at about 105 psig. When the small boiler was operating at medium fire, we measured its stack temperature and excess air content to be 526 F and 38%, respectively. The boiler was then turned down to low fire, and its stack temperature and excess air content became 486 F and 77%, respectively. This indicates that the boiler’s controls do not maintain constant excess air at varying firing rates. The control arrangement may be such that excess air is optimized at high fire, but control effectiveness decreases at lower firing rates. Recommendation According to maintenance, a boiler service contractor periodically performs a check-up on the plant’s boilers. We recommend asking the contractor to measure the excess air on both boilers at varying firing rates. We then recommend requesting the contractor to adjust the linkages so that excess air is at 10% at medium fire, which is the boilers’ most common firing rate. Estimated Savings According to the Utility Analysis section of the report, 25,121 mmBtu of natural gas was consumed by the plant in 2004. In addition, 13% of total usage is attributed to facility use and 62% is production dependent. We assume all facility and production dependent gas use is attributed to the boilers. If so, the annual natural gas consumption by the boilers is about: 25,121 mmBtu/year x (13% + 62%) = 18,841 mmBtu/year
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According to management, the plant operates 24 hours per day, 5 days per week, 50 weeks per year, for a total of 6,000 hours per year. Thus, the average hourly natural gas consumption is about: 18,841 mmBtu/year / 6,000 hours/year = 3.14 mmBtu/hour Since the large 8.7 mmBtu/hour boiler is the primary boiler, we estimate the average fraction of full load at which the boiler operates is about: 3.14 mmBtu/hour / 8.7 mmBtu/hour = 0.36 According to maintenance the boiler feedwater temperature is about 180 F. The temperature of 105 psig steam is 341 F and the enthalpy is 1,191 Btu/lb. We measured the room air temperature used for combustion to be 66 F. Our spreadsheet program, CombEff.XLS, calculates the change in efficiency by adjusting the amount of excess combustion air. The method accounts for the increased temperature of combustion and the increased heat transfer within the boiler. It does so by modeling the boiler as a parallel-flow heat exchanger, and calculates efficiency improvement using the LMTD heat exchanger method. We assume the stack temperature and excess air in the large boiler is the same as in the small boiler. For the simulation, we took the average of the measured values between high and low fire, which were 506 F and 54%. The calculations below, from CombEff.XLS, show the boiler’s current efficiency and the efficiency if excess combustion air were lowered to 10%.
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Input Data Ta = temperature combustion air before burner (F) Tex = temperature exhaust gasses (F) EA = excess air (0=stoch, 0.1 = optimum) Qng (mmBtu/h) = heat input to burner Percent rated input Tw1 (F) Tw2 (F) (for either "Steam" or "HotWater") EAn = excess air (0=stoch, 0.1 = optimum) "Steam" or "HotWater" If "Steam" then enter enthalpy of sat steam leaving boiler, hw2 (Btu/lb) Constants (for Natural Gas) LHV = lower heating value (Btu/lb) HHV = higher heating value (Btu/lb) Cpex = specific heat of products of exhaust (Btu/lb-F) Tdpp = dew point temp of H20 in exhaust (F) AFs = air/fuel mass ratio at stochiometric conditions Calculated Values Tc (F) = temp combustion = Ta+LHV/[(1+(1+EA)(Afs))cpp] Qlat (Btu/lb) (Qlat = HHV - LHV if Tex < 140 F, else Qlat = 0) eb = [{1 + (1+EA)(AFs)}*Cpex*(Tc-Tex) + Qlat] /HHV Q (Btu/h) = Useful heat transferred to water = Qng x 10^6 x Effc ∆ T1 (F) = Tc - Tw1 ∆ T2 (F) = Tex - Tw2 ∆ Tlm (F) = ( ∆T2- ∆T1) / ln( ∆T2 / ∆T1) UA (Btu/h-F) = Qu / ( ∆Tlm (F)) Tcn (F) = new temp combustion = Ta+LHV/[(1+(1+EAn)(Afs))Cpex] 4/5 UAn (Btu/h-F) = UA [{1 + (1 + EA,n) AFs} / {1 + (1 + EA) AFs}] ebn (with EAn but Tex const) = [1 + (1+EAn)(AFs)]*Cpex*(Tcn-Tex)/HHV ∆ T1n (F) = Tcn - Tw1 Guess current ∆T2n (F) (lower than ∆T2….) This should equal zero if ∆T2n is correct Tex,n (F) = ∆T2n + Tw2 ebn = [1 + (1+EAn)(AFs)]*Cpex*(Tcn-Texn)/HHV Qng,n (mmBtu/h) = Qu / (ebn x 10^6)
66 506 0.54 8.700 0.36 180 341 0.10 Steam 1191
21,500 23,900 0.260 140 17.20
3,074 0 76.8% 2,405,399 2,894 165 953 2,525 4,217 1,951 80.4% 4,037 176.1334 0 517 80.2% 3.000
Based on these results, we estimate that the boiler’s efficiency would increase from 76.8% to 80.2%. If the boiler operates at an average efficiency of 76.8% throughout the year, its useful energy output is about: 18,841 mmBtu/year x 76.8% = 14,470 mmBtu/year To meet this energy requirement with an 80.2% efficiency boiler, the required input would be about: 14,470 mmBtu/year / 80.2% = 18,042 mmBtu/year The annual natural gas savings would be about: 18,841 mmBtu/year – 18,042 mmBtu/year = 799 mmBtu/year 799 mmBtu/year x $7.22 /mmBtu = $5,769 /year The total reduction in CO2 emissions would be about: 799 mmBtu/year x 113 lb CO2/mmBtu ≈ 90,300 lb CO2 /year Estimated Implementation Cost Negligible. Estimated Simple Payback Immediate 20
AR X: Reduce Excess Combustion Air in Boilers ARC: 2.1233.2 Natural Gas
Annual Savings Resource CO2 (lb) Dollars 1,064 mmBtu 120,200 $9,225
Project Cost Capital Other Total None None None
Simple Payback Immediate
Analysis According to the EPA document “Guide to Industrial Assessments for Pollution Prevention and Energy Efficiency” (EPA/625/R-99/003) the optimal excess air in a gas heating system for energy efficiency and pollution prevention is about 10%. Higher levels of excess air dilute the combustion stream and decrease the quantity of useful heat available to the process. In addition, higher excess air levels cause the combustion stream to flow at higher velocities, thereby reducing the heat transfer rate within the boiler. Two boilers, each rated at 7.3 mmBtu/hour input, provide steam for plant space heating. Controls on each boiler modulate natural gas and air intake to maintain the pressure at about 8 psig. According to maintenance, only one boiler runs at a time, and the operation schedule alternates between the two. We measured the boiler stack temperature and excess air content to be 367 F and 102%, respectively, at high fire. If excess air were decreased, the boilers would operate more efficiently and less gas would be needed. Recommendation According to maintenance, a boiler service contractor performs a check-up on the plant’s boilers before each heating season. We recommend asking the service contractor to adjust the controls on the boilers so that the excess combustion air is reduced to 10% for all firing rates. Estimated Savings According to maintenance, the boiler was operating at high fire during our visit, thus we assume its input was 7.3 mmBtu/hour. According to maintenance, nearly 100% of the condensate is returned in the steam system, thus we assume the feedwater temperature is about 200 F. During our visit, the boiler generated steam at 8 psig (enthalpy = 1,158 Btu/lbm, temperature = 233 F). Our spreadsheet program, CombEff.XLS, calculates the change in efficiency by adjusting the amount of excess combustion air. The method accounts for the increased temperature of combustion and the increased heat transfer within the boiler. It does so by modeling the boiler as a parallel-flow heat exchanger and calculates efficiency improvement using the LMTD heat exchanger method and assuming that the heat transfer coefficient, UA, is constant. The calculations below, from CombEff.XLS, show the boiler’s current efficiency and the efficiency if excess combustion air were lowered to 10%.
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Calcs Efficiency Gain From Decreasing Excess Air in Boilers (PF) Input Data Tca = temperature combustion air before burner (F) Tex = temperature exhaust gasses (F) EA = excess air (0=stoch, 0.1 = optimum) Qng (mmBtu/h) = heat input to burner Tw1 (F) Tw2 (F) (for either "Steam" or "HotWater") EAn = excess air (0=stoch, 0.1 = optimum) "Steam" or "HotWater" If "Steam" then enter enthalpy of sat steam leaving boiler, hw2 (Btu/lb) Constants (for Natural Gas) LHV = lower heating value (Btu/lb) HHV = higher heating value (Btu/lb) cpp = specific heat of products of exhaust (Btu/lb-F) Tdpp = dew point temp of H20 in exhaust (F) Afs = air/fuel mass ratio at stochiometric conditions Calculated Values hr (Btu/lb) = heat of reaction = LHV if Tex > 140 else HHV Tc (F) = temp combustion = Tca+hr/[(1+(1+EA)(Afs))cpp] Effc = [1 + (1+EA)(AFs)]*cpp*(Tc-Tex)/HHV Qu (Btu/h) = Useful heat transferred to water = Qng x 10^6 x Effc dt1 (F) = Tc - Tw1 dt2 (F) = Tex - Tw2 dtlm (F) = (dt2-dt1) / ln(dt2/dt1) UA (Btu/h-F) = Qu / (dtlm) Tcn (F) = new temp combustion = Tca+hr/[(1+(1+EAn)(Afs))cpp] Effcn (with EAn but Tex const) = [1 + (1+EAn)(AFs)]*cpp*(Tc-Tex)/HHV dt1n (F) = Tcn - Tw1 Guess current dt2n (F) (lower than dt2….) This should equal zero if dt2 is correct Texn (F) = dt2n + Tw2 Effcn = [1 + (1+EAn)(AFs)]*cpp*(Tcn-Texn)/HHV Qngn (mmBtu/h) = Qu / (Effcn x 10^6)
70 367 1.02 7.300 200 233 0.10 Steam 1158
21,500 23,900 0.260 140 17.20
21,500 2,383 78.4% 5,723,887 2,183 134 734 7,794 4,221 83.5% 4,021 17 0 250 86.1% 6.652
According to these calculations, the boiler’s efficiency would increase from 78.4% to 86.1%. We assume this would be true throughout the entire heating season for both boilers. According to the Utility Analysis section of the report, about 77% of the plant’s annual natural gas use, or 11,883 mmBtu is used for space heating. Assuming the boiler operates at 78.4% efficiency throughout the year, its useful energy output is about: 11,883 mmBtu/year x 78.4% = 9,316 mmBtu/year To meet this energy requirement with an 86.1% efficiency boiler, the required input would be about:
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9,316 mmBtu/year / 86.1% = 10,819 mmBtu/year The annual natural gas savings would be about: 11,883 mmBtu/year – 10,819 mmBtu/year = 1,064 mmBtu/year 1,064 mmBtu/year x $8.67 /mmBtu = $9,225 /year The total reduction in CO2 emissions would be about: 1,064 mmBtu/year x 113 lb CO2/mmBtu ≈ 120,200 lb CO2 /year Estimated Implementation Cost Requesting the boiler service contractor adjust intake air controls involves no implementation cost. Estimated Simple Payback Immediate
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AR X: Reduce Excess Combustion Air in Boiler ARC: ? Natural Gas
Annual Savings Resource CO2 (lb) Dollars 93 mmBtu 10,500 $729
Project Cost Capital Other Total None None None
Simple Payback Immediate
Analysis During our visit, we measured the temperature and quantity of excess air in the exhaust gasses of the primary boiler. The temperature was about 433 F. The exhaust gasses contained about 29% more air than is required for stoichiometric combustion. The ideal amount of excess air is 10%. Recommendation We recommend asking your boiler maintenance contractor to slightly reduce the quantity of combustion air supplied to the boiler so that the boiler operates at 10% excess air at high fire. Estimated Savings Our spreadsheet program, CombEff.XLS, predicts combustion efficiency as a function of excess air, exhaust temperature and intake air temperature. The program shows that the efficiency of combustion with 30% excess air is about 80.0%. This compares well with the 81% combustion efficiency calculated by our efficiency instrument. The input data, constants, equations and output are shown below. Input Data EA = excess air (0=stoch, 0.1 = optimum) Tca = temperature combustion air before burner (F) Tex = temperature exhaust gasses (F)
0.29 69 433
Constants (for Natural Gas) LHV = lower heating value (Btu/lb) HHV = higher heating value (Btu/lb) cpp = specific heat of products of exhaust (Btu/lb-F) Tdpp = dew point temp of H20 in exhaust (F) Afs = air/fuel mass ratio at stochiometric conditions
21,500 23,900 0.260 140 17.20
Calculated Values hr = heat of reaction = (if Tex
