boiler efficiency calcucations

Process Heating: Combustion Efficiency

Fundamentals of CombustionDuring 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

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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)] / HHVEff = [{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 DataEA = excess air (0=stoch, 0.1 = optimum) 0.50Tca = temperature combustion air before burner (F) 70Tex = temperature exhaust gasses (F) 350

Constants for Natural GasLHV = lower heating value (Btu/lb) 21,500HHV = higher heating value (Btu/lb) 23,900cpp = specific heat of products of exhaust (Btu/lb-F) 0.260Tdpp = dew point temp of H20 in exhaust (F) 140Afs = air/fuel mass ratio at stochiometric conditions 17.20

Combustion Efficiency Calculationshr = heat of reaction = (if Tex<140 then hr=HHV else hr = LHV) 21,500Tc = temp combustion (F) = Tca+hr/[(1+(1+EA)(Afs))cpp] 3,156Efficiency = [1 + (1+EA)(AFs)]*cpp*(Tc-Tex)/HHV 81.8%

The percent fuel savings from improving combustion efficiency is:

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Percent fuel savings = (Effdesired – Effactual) / Effdesired x 100

In engineering practice, the combustion efficiency is sometimes called “available heat”. A chart showing natural gas combustion efficiency (available heat) as a function of exhaust gas temperature and excess air is shown below.

Source: Process Heat Tip Sheet #2, U.S. Department of Energy, DOE/GO-102002-1552.

Fuels

HHV LHV StoichiometricFuel Air Ratio

Methane CH4 17.2Natural gas .65CH4 +.08H2

+ .18 N2 + .03O2+.6CO2

Acetylene C2H2Ethylene C2H4Ethane C2H6Propylene C3H6Propane C3H8Butane C4H10Octane (Gasoline)

C8H18

Diesel C12H26Coal .82C + .05H20

+ .02H2+.01O212.25

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Combustion Efficiency At Part LoadAs demonstrated in the preceding discussion, combustion efficiency is a function of the temperature of the exhaust gas and the quantity of excess combustion air. When combustion burners are modulated to less than full load, these variables often change from their full-load values and the combustion efficiency can increase or decrease accordingly.

In many cases, the temperature of exhaust gasses decreases when the burners are at low-fire because the residency time of exhaust gasses in the heat exchanger increases. If a proper air/fuel ratio is maintained at low fire, combustion efficiency can increase as demonstrated in the following case study.

The boiler has an oxygen sensor on the flue stack, which regulates the air/fuel ratio to maximize boiler efficiency. Despite this control feature, the temperature of flue gas was about 600 F. This is unusually high; normal stack temperatures are about 400 F. After discussions with management, we concluded that the reason for the elevated stack temperatures must be insufficient heat transfer area inside the boiler. Management agreed with this assessment. During our visit we measured the temperature of the exhaust in the flue stack, Ts, and the boiler efficiency, E, at different pressures and loading levels. The readings are shown in the following Table 6.1.

Table 6.1. Measured stack temperatures, Ts, and efficiency, E, of the fire-tube boiler.Boiler Pressure High Fire Medium Fire Low Fire100 psig Ts=620 F; E = 75.6% Ts=550 F; E=76.0% Ts = 400 F; E=78.8 %70 psig Ts = 380 F; E=84.0 %

Similarly, for boilers with step or modulation control, combustion efficiency generally improves when the boiler is operated at part load because the ratio of heat exchanger surface area to heat input increases. A typical curve showing combustion efficiency as a function of part-load ratio is shown below (ASHRAE 2000, HVAC Systems and Equipment Handbook, Pg 27.6). A curve fit gives the following relation:

Effpl = Efffl + .055/.75 (1-PLR)

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(Source: ASHRAE 2000, HVAC Systems and Equipment Handbook, Pg 27.6)

However, combustion efficiency can also decline at part load if the quantity of combustion air is not decreased proportionately with the quantity of fuel. Check the burner to determine the type of part-load combustion air control. In some older burners, the quantity of combustion air is not decreased at part-load conditions. These burners are excellent candidates for updated combustion air controls. Other burners have a mechanical arm that varies the position of a damper on the combustion air supply duct according to the position of the inlet fuel valve. Although mechanical controls can do an acceptable job of varying the supply of combustion air, the best controls use flue gas sensors and direct digital controls to precisely modulate the quantity of combustion air to maintain optimum efficiency.

Linkage and O2 Trim Combustion ControlsThe fuel-to-air ratio in most boilers is controlled by a mechanical linkage which attempts to maintain a constant fuel-to-air ratio across the entire firing range. Unfortunately, mechanical linkages are seldom able to do this. We regularly measure different fuel-to-air ratios at low, medium and high fire. In these cases, we recommend that the linkage be adjusted to generate 10% excess air at one firing rate, and greater than 10% excess air at the other firing rates.

10% excess air can be maintained across all firing rates by installing independent digital controls on the combustion air and gas supply lines, which are controlled to maintain 10% excess air. This type of control is sometimes called “oxygen trim” or “O2 trim”. The following costs were supplied by Jim Turton at Ballanger Company (513) 271-3915, which is a local supplier of Cleaver Brooks boilers. O2 trim controls cost between $12,000 and $15,000. To retrofit an existing boiler with O2 trim controls, about 2 days

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labor would be required at about $750 per day; for a total of about $1,500 in labor costs. In addition, the controls need to be checked and calibrated every few months and each calibration takes a couple of hours. Thus, if an O2 trim package is calibrated 3-4 times per year, and each calibration takes about 2-3 hours, the maintenance and calibration costs about $1,000 per year.

Oxygen Enhancement When atmospheric air is used in combustion, the nitrogen in the air is largely inert. However, this does not mean that it has no effect on combustion. The energy released during the combustion reaction is absorbed by the products of combustion. The nitrogen in the products of combustion absorbs a portion of the heat of combustion and lowers the adiabatic combustion temperature. The reduced combustion temperature reduces the efficiency of combustion.

Burning pure oxygen instead of atmospheric air eliminates the dilutive effects of nitrogen. This increases the combustion temperature and the efficiency of combustion. Using the method developed earlier, the air to fuel ratio for stochiometric combustion of methane with oxygen combustion is:

CH4 + 2 O2 > 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 ControlPrimary 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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mailto:[email protected]

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: 2.1233.1Annual Savings Project Cost Simple

PaybackResource CO2 (lb) Dollars Capital Other TotalNatural Gas 3,387 mmBtu 433,600 $32,384 $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 Medium Fire Performance Low Fire PerformanceExhst. Temp

Excess Air

Comb. Eff.

Exhst. Temp

Excess Air

Comb. Eff.

Exhst. Temp

Excess Air

Comb. Eff.

457 F 45% 79.3% 412 F 54% 80.0% 394 F 88% 78.6%

Boiler #2

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

1 2 3Firing Rate

Exc

ess

Air

150

200

250

300

350

400

450

500

Exh

aust

Gas

Tem

per

atu

re (

F)

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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Low Medium High

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 real-time 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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http://www.udayton.edu/udiac

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/year3,837 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


PaybackResource CO2 (lb) Dollars Capital Other TotalNatural Gas 841 mmBtu 95,000 $7,098 None None None 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 Medium Fire Performance Low Fire PerformanceExhst. Temp

Excess Air

Comb. Eff.

Exhst. Temp

Excess Air

Comb. Eff.

Exhst. Temp

Excess Air

Comb. Eff.

531 F 32% 78.3% 463 F 56% 78.4% 352 F 115% 78.7%

250-hp Boiler

0%

20%

40%

60%

80%

100%

120%

140%

1 2 3Firing Rate

Exc

ess

Air

150

200

250

300

350

400

450

500

550

600

Exh

aust

Gas

Tem

per

atu

re (

F)

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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Low Medium High

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.

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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/year841 mmBtu/year x $8.44 /mmBtu = $7,098 /year


841 mmBtu/year x 113 lb CO2/mmBtu ≈ 95,000 lb CO2 /year


Requesting the plant’s boiler service technician adjust settings on the boiler would require no significant cost.


Immediate

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AR X: Recalibrate Boiler Air/Fuel Ratio to 10% Excess Air at Medium Fire



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 DataTa = temperature combustion air before burner (F) 66Tex = temperature exhaust gasses (F) 506EA = excess air (0=stoch, 0.1 = optimum) 0.54Qng (mmBtu/h) = heat input to burner 8.700Percent rated input 0.36Tw1 (F) 180Tw2 (F) (for either "Steam" or "HotWater") 341EAn = excess air (0=stoch, 0.1 = optimum) 0.10"Steam" or "HotWater" SteamIf "Steam" then enter enthalpy of sat steam leaving boiler, hw2 (Btu/lb) 1191

Constants (for Natural Gas)LHV = lower heating value (Btu/lb) 21,500HHV = higher heating value (Btu/lb) 23,900Cpex = specific heat of products of exhaust (Btu/lb-F) 0.260Tdpp = dew point temp of H20 in exhaust (F) 140AFs = air/fuel mass ratio at stochiometric conditions 17.20

Calculated ValuesTc (F) = temp combustion = Ta+LHV/[(1+(1+EA)(Afs))cpp] 3,074Qlat (Btu/lb) (Qlat = HHV - LHV if Tex < 140 F, else Qlat = 0) 0eb = [{1 + (1+EA)(AFs)}*Cpex*(Tc-Tex) + Qlat] /HHV 76.8%Q (Btu/h) = Useful heat transferred to water = Qng x 10^6 x Effc 2,405,399 T1 (F) = Tc - Tw1 2,894 T2 (F) = Tex - Tw2 165 Tlm (F) = ( T2- T1) / ln( T2 / T1) 953UA (Btu/h-F) = Qu / ( Tlm (F)) 2,525Tcn (F) = new temp combustion = Ta+LHV/[(1+(1+EAn)(Afs))Cpex] 4,217UAn (Btu/h-F) = UA [{1 + (1 + EA,n) AFs} / {1 + (1 + EA) AFs}]4/5 1,951ebn (with EAn but Tex const) = [1 + (1+EAn)(AFs)]*Cpex*(Tcn-Tex)/HHV 80.4% T1n (F) = Tcn - Tw1 4,037Guess current T2n (F) (lower than T2….) 176.1334This should equal zero if T2n is correct 0Tex,n (F) = T2n + Tw2 517ebn = [1 + (1+EAn)(AFs)]*Cpex*(Tcn-Texn)/HHV 80.2%Qng,n (mmBtu/h) = Qu / (ebn x 10^6) 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/year799 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 /yearEstimated Implementation Cost

Negligible. Estimated Simple Payback

Immediate

20

AR X: Reduce Excess Combustion Air in Boilers


PaybackResource CO2 (lb) Dollars Capital Other TotalNatural Gas 1,064 mmBtu 120,200 $9,225 None None None 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 DataTca = temperature combustion air before burner (F) 70Tex = temperature exhaust gasses (F) 367EA = excess air (0=stoch, 0.1 = optimum) 1.02Qng (mmBtu/h) = heat input to burner 7.300Tw1 (F) 200Tw2 (F) (for either "Steam" or "HotWater") 233EAn = excess air (0=stoch, 0.1 = optimum) 0.10"Steam" or "HotWater" SteamIf "Steam" then enter enthalpy of sat steam leaving boiler, hw2 (Btu/lb) 1158

Constants (for Natural Gas)LHV = lower heating value (Btu/lb) 21,500HHV = higher heating value (Btu/lb) 23,900cpp = specific heat of products of exhaust (Btu/lb-F) 0.260Tdpp = dew point temp of H20 in exhaust (F) 140Afs = air/fuel mass ratio at stochiometric conditions 17.20

Calculated Valueshr (Btu/lb) = heat of reaction = LHV if Tex > 140 else HHV 21,500Tc (F) = temp combustion = Tca+hr/[(1+(1+EA)(Afs))cpp] 2,383Effc = [1 + (1+EA)(AFs)]*cpp*(Tc-Tex)/HHV 78.4%Qu (Btu/h) = Useful heat transferred to water = Qng x 10^6 x Effc 5,723,887dt1 (F) = Tc - Tw1 2,183dt2 (F) = Tex - Tw2 134dtlm (F) = (dt2-dt1) / ln(dt2/dt1) 734UA (Btu/h-F) = Qu / (dtlm) 7,794Tcn (F) = new temp combustion = Tca+hr/[(1+(1+EAn)(Afs))cpp] 4,221Effcn (with EAn but Tex const) = [1 + (1+EAn)(AFs)]*cpp*(Tc-Tex)/HHV 83.5%dt1n (F) = Tcn - Tw1 4,021Guess current dt2n (F) (lower than dt2….) 17This should equal zero if dt2 is correct 0Texn (F) = dt2n + Tw2 250Effcn = [1 + (1+EAn)(AFs)]*cpp*(Tcn-Texn)/HHV 86.1%Qngn (mmBtu/h) = Qu / (Effcn x 10^6) 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/year1,064 mmBtu/year x $8.67 /mmBtu = $9,225 /year


1,064 mmBtu/year x 113 lb CO2/mmBtu ≈ 120,200 lb CO2 /year


Requesting the boiler service contractor adjust intake air controls involves no implementation cost.


Immediate

23

AR X: Reduce Excess Combustion Air in Boiler

ARC: ?Annual Savings Project Cost Simple

PaybackResource CO2 (lb) Dollars Capital Other TotalNatural Gas 93 mmBtu 10,500 $729 None None None Immediate

AnalysisDuring 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 SavingsOur 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 DataEA = excess air (0=stoch, 0.1 = optimum) 0.29Tca = temperature combustion air before burner (F) 69Tex = temperature exhaust gasses (F) 433


Calculated Valueshr = heat of reaction = (if Tex<140 then hr=HHV else hr = LHV) 21,500Tc = temp combustion (F) = Tca+hr/[(1+(1+EA)(Afs))cpp] 3,635Efficiency = [1 + (1+EA)(AFs)]*cpp*(Tc-Tex)/HHV 80.8%

If the quantity of excess air was reduced to 10%, the efficiency of the boiler would increase to about 82.1% as shown below.

Input Data

EA = excess air (0=stoch, 0.1 = optimum) 0.10Tca = temperature combustion air before burner (F) 69

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Tex = temperature exhaust gasses (F) 433



According to billing data, the energy content of the diesel fuel input to the boiler during the last year was 5,885 mmBtu.

(5,885 mmBtu/hr) x (1 – 80.8% / 82.1%) = 93 mmBtu/yr93 mmBtu/yr x $7.84 /mmBtu = $729 /year

The CO2 emission savings would be about:

93 mmBtu/year x 113 lbs CO2/mmBtu ≈ 10,500 lbs CO2 /year

Estimated Implementation CostAccording to management, the boiler is maintained by a contractor. The cost of asking to the contractor adjust the quantity of combustion air during a regularly scheduled maintenance call would be negligible.

Estimated Simple PaybackImmediate

25

AR X: Adjust Air/Fuel Ratio to Improve Boiler EfficiencyAnnual Savings Project

CostSimple

PaybackResource CO2 (lb) DollarsNatural Gas 736 MBtu 84,640 $4,247 $500 1 month

AnalysisA natural-gas fired boiler rated at 2.1 MBtu per hour supplies 100 psig steam for process heating. The boiler has two modes of firing, high fire and low fire. During our visit, the boiler ran on low fire most of the time. We measured the exhaust stack temperature of the boiler to be about 670 F.

In addition, data from measurements performed by a boiler maintenance contractor on 11/01/2001 are shown in the table below. These measurements are consistent with the measurements we took using our combustion analyzer, and are very troubling.

11/01/2001 12:38 pm 11/01/2001 12:41 pmStack Temp 598 F 551 FAmbient Temperature 96.5 F 96.5 FO2 9.0 % 9.2 %CO2 6.7 % 6.6 %CO 0 % 0 %Excess air 67.3% 70.0 %Efficiency 75.7% 74.4 %

Most boilers are designed to operate at stack temperatures less than 100 F above the temperature of the steam and with about 10% excess air. The elevated stack temperature and percent O2 in the flue gas of your boiler most likely indicates insufficient heat transfer across the heat exchanger due to fouling of the heat exchanger surfaces, and/or the air/fuel ratio is too high, resulting in excess pressure drop (draft) and exhaust flow rate across the heat exchanger. RecommendationFirst, we strongly recommend that you contact a competent boiler service company and reduce the air/fuel ratio. The optimum amount of O2 in the flue gas for a natural gas boiler is about 2.2%, which corresponds to 10% excess air. In contrast, the oxygen content of your flue gas is 9%, which corresponds to 67% excess air! Reducing the amount of excess air will decrease the draft across the heat exchanger, lower the exhaust temperature and significantly increase the efficiency of the boiler.

Once the air/fuel ratio is properly adjusted, the stack temperature should decrease to less than 100 F above the temperature of the steam. The temperature of saturated steam at 100 psig is about 337 F. Thus, the stack temperature should be less than about 440 F. If it isn’t, it is probably indicative of fouling and/or deposits on the heat exchanger surfaces. In this case, we recommend cleaning and descaling the heat exchange surfaces. In addition, water treatment practices should be reexamined.

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Estimated SavingsCurrently, the combustion efficiency of the boiler is about 75%. If the boiler were operating properly with 2.2% O2, 10% excess air, and an exhaust temperature of about 440 F (net stack temperature of 360 F assuming 80 F ambient air temperature) the efficiency would be about 82.2%.

According to management the boiler operates for about 8,000 hours per year. Assuming that, on average, the boiler is 50% loaded, the savings from adjusting the boiler would be about:

2.1 MBtu/hr x 50% x 8,000 hr/yr = 8,400 MBtu/yr

8,400 MBtu/yr x = 736 MBtu/yr

736 MBtu/yr x $5.77 /MBtu = $4,247 /yr

Estimated Implementation CostWe estimate hiring a boiler service company to optimize the combustion efficiency would cost less than $500.

Estimated Simple Payback$500 / $4,247 /year x 12 months/year = 1 months

27

AR X: Reduce Boiler Pressure to Improve the Efficiency of the Fire Tube Boiler

Annual Savings ProjectCost

SimplePaybackResource CO2 (lb) Dollars

Natural Gas 1,004 MBtu 11,245 $3,333 None Immediate

Analysis and RecommendationSteam is supplied to the plant from two boilers for process and space heating. One boiler is a water tube boiler generating steam at 135 psig. It is rated at 40,000 pounds per hour. The other is a fire tube boiler generating steam at 95 psig. It is rated at 8,800 pounds per hour. The fire-tube boiler supplies steam to the plant during the second shift and during the weekend for space heating purposes. Management estimates that the fire-tube boiler is about 75% loaded during these times.

The boiler has an oxygen sensor on the flue stack, which regulates the air/fuel ratio to maximize boiler efficiency. Despite this control feature, the temperature of flue gases were about 600 F. This is unusually high; normal stack temperatures are about 400 F. After discussions with management, we concluded that the reason for the elevated stack temperatures must be insufficient heat transfer area inside the boiler. Management agreed with this assessment.

During our visit we measured the temperature of the exhaust in the flue stack, Ts, and the boiler efficiency, E, at different pressures and loading levels. The readings are shown in the following Table 6.1.

Table 6.1. Measured stack temperatures, Ts, and efficiency, E, of the fire-tube boiler.Boiler Pressure High Fire Medium Fire Low Fire100 psig Ts=620 F; E = 75.6% Ts=550 F; E=76.0% Ts = 400 F; E=78.8 %70 psig Ts = 380 F; E=84.0 %

Management suggested that in the past, this boiler was successfully operated at 70 psig during second shift. We recommend doing this again to increase the efficiency of the boiler and reduce the amount of natural gas consumed by the boiler. Management also expressed concern that the boiler could not generate enough steam at a set-point pressure of 70 psig. This would not be the case. In fact, the boiler would be able to generate more steam at 70 psig than it can at 100 psig. In addition, we asked a boiler expert if running the boiler at a lower set-point pressure would harm the boiler. The boiler expert assured us that this is not the case.

Estimated SavingsManagement estimates that, on average, the fire-tube boiler is about 75% loaded. If so, this would mean that the fire-tube boiler uses about half of all natural gas to both boilers. Thus, we estimate that the fire tube boiler is closer to 50% loaded.

From Table 6.1, the boiler is about 76% efficient when 50% loaded and operating at 100

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psig. We were unable to record the efficiency of the boiler at medium fire when operated at 70 psig. However, using the efficiency trend from operating the boiler at 100 psig, we estimate that the boiler would be 81% efficient if operated at 70 psig. The fire-tube boiler runs from about 2 pm to 11 pm for five days per week. The enthalpy of water at 50 F is about 18 Btu/lb and the enthalpy of saturated steam at 100 psig is about 1190 Btu/lb. Thus, the energy consumption of the boiler operating at 100 psig during second shift is about:

8,800 lb/hr x 50% x (1,190 – 18) Btu/lb x 9 hr/dy x 5 dy/wk x 50 wk/yr / 76 % = 15,267 MBtu/yr

The enthalpy of saturated steam at 70 psig is about 1,185 Btu/lb. The energy consumption of the boiler operating at 70 psig during second shift would be about:

8,800 lb/hr x 50% x (1,185 – 18) Btu/lb x 9 hr/dy x 5 dy/wk x 50 wk/yr / 81 % = 14,263 MBtu/yr

The savings would be about:

15,267 MBtu/yr - 14,263 MBtu/yr = 1,004 MBtu/yr1,004 MBtu/yr x $3.32 /MBtu = $3,333 /yr These savings are conservative since we did not include weekend operation of boiler for space heating. To verify our assumptions, we cross check with utility data. Based on these estimates, the fire-tube boiler would consume about

15,267 MBtu/yr / 50,442 MBtu/yr = 30%

of all natural gas. The percent savings from operating at a lower pressure would be about:

1,004 MBtu/yr / 15,267 MBtu/yr = 6 %

Estimated Implementation CostsNone.

Estimated Simple PaybackImmediate.

29

AR X: Reduce Air Flow Through Dispatch and Jenson Ovens

ARC: ?Annual Savings Project Cost Simple

PaybackResource CO2 (lb) Dollars Capital Other TotalNatural gas 327 mmBtu 37,000 $2,564 None None None Immediate

Analysis

The Dispatch oven is equipped with an exhaust air fan which forces air out of the oven and draws an equal amount of air in through an open grate. The exhaust duct is equipped with a damper, which is currently set to 100% open. If the damper were partially closed, the quantity of air heated by the oven would be reduced, which would improve the efficiency of the oven and decrease gas use. However, it is important to maintain enough air flow through the furnace so that fumes emitted by the products do not accumulate inside the furnace and cause an explosive situation.

The Jenson oven has a similar configuration, but is about twice as big and has a burner with about twice the capacity of the Dispatch oven.

Recommendation

We recommend slightly closing the exhaust dampers to reduce airflow through the Jenson and Dispatch ovens. We recommend that the dampers be closed no more than 25% in order to maintain sufficient airflow though the ovens.

Estimated Savings

The indoor air temperature in the plant is about 70 F. We measured the temperature of the walls and top of the oven during operation, and found that they were at about 75 F. Thus, we assume that energy loss through the shell of the oven is negligible. According to management, the Dispatch oven operated at about 250 F for about 70 hours per week during the past year. The product of the density and specific heat of air is about 0.018 Btu/ft3-F. In the Major Gas Using Equipment section of the report, we estimated that the Dispatch oven used about 875 mmBtu/yr of natural gas. If so, the average flow air flow rate through the oven is about:

875 mmBtu/yr / (60 min/hr x 70 hr/wk x 50 wk/yr x 0.018 Btu/ft3-F x (250 – 70) F) = 1,286 ft3/min

We estimate that the motor on the exhaust fan is about 1-hp. According to the 2000-2001 Grainger Catalog pg. 3666, 1-hp double-inlet blowers similar to the blower on the oven generate about 1,300 cfm at 1.125 in wg static pressure. Thus, this flow rate appears to be reasonable.

According to management, the Dispatch oven will operate for about 35 hours per week during the coming year. If the flow were reduced by 25%, the savings would be about:

(1,286 ft3/min x 60 min/hr x 35 hr/wk x 50 wk/yr x 25%) x 0.018 Btu/ft3-F x (250 – 70) F = 109 mmBtu/yr

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The Jenson oven has a similar configuration, but is about twice as big and has a burner with about twice the capacity of the Dispatch oven. Thus, we estimate that the savings from reducing the flow of air through the Jenson oven by 25%, would be twice as much as the savings from reducing the flow of air through the Dispatch oven by 25%. If so, the total savings would be:

109 mmBtu/yr + (2 x 109 mmBtu/yr) = 327 mmBtu/yr327 mmBtu/yr x $7.84 /mmBtu = $2,564 /yr

This would reduce CO2 emissions by the electric utility by about:

327 mmBtu/year x 113 lbCO2/mmBtu ≈ 37,000 lb CO2 /yr


According to the facilities manager, the cost of adjusting the exhaust damper would be negligible.


Immediate

31

AR X: Recalibrate Boiler Air/Fuel Ratio to 10% Excess Air at Low Fire



Analysis

A service contractor maintains the plant’s boilers. The service contractor measured exhaust gas temperature, percent oxygen and percent excess air for the Hurst boiler at high, medium, and low fire. We calculated the combustion efficiency based on these data. The results are shown in the table below. The Hurst boiler is only used as a backup. Combustion data from the Johnston boiler, which operates most of the time, were not available. We assume that these data are also representative of the Johnston boiler.

Firing Rate

Exhaust Gas Temperature

Percent O2 In

Exhaust

Percent Excess

Air

Combustion Efficiency

High 433 F 6.1% 38.0% 80.5%Medium 374 F 6.5% 42.0% 81.8%

Low 335 F 8.6% 65.0% 81.8%

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). Higher levels of excess air dilute the combustion stream and decrease the quantity of useful heat available to the process.

The data in the table indicate that the quantity of excess air increases as firing rate decreases. Thus, it appears this boiler was calibrated to operate most efficiently at high fire. However, as explained in the Steam System Analysis section of the report, the average natural gas demand of the Johnston boiler is less than its minimum natural gas input. Thus, the burner cycles off and on at minimum fire to maintain a set steam pressure. Calibrating the boiler to use minimum excess air at low fire, rather than high fire, would increase the efficiency of the boiler.

Recommendation

We recommend requesting the contractor to recalibrate the boiler to use 10% excess air at low fire where the boiler operates most often.

Estimated Savings

To calculate savings from reducing excess air to 10%, we used the Department of Energy process heating simulation software PHAST, which can be downloaded from DOE’s website www.oit.doe.gov. The figure below shows that current combustion efficiency is 82.9%, and that reducing excess air to 10% would increase combustion efficiency to 85.7%.

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http://www.oit.doe.gov/

PHAST Results from Reducing Excess Air

According to the Steam System Analysis, the Johnston boiler operates at 6.27 mmBtu/hr input for about 40% of plant operating time. Using the results from PHAST, the average hourly heat transferred to water/steam is about:

6.27 mmBtu/hour x 40% x 82.9% = 2.08 mmBtu/hour

If excess air was reduced, causing combustion efficiency to increase to 85.7%, the percentage of time the boiler would need to fire in order to transfer 2.08 mmBtu/hr to water/steam would be about:

2.08 mmBtu/hour / (6.27 mmBtu/hour x 85.7%) = 38.7%

According to management, the plant operates about 7,200 hours/year. Thus, annual natural gas savings would be about:

6.27 mmBtu/hour x 7,200 hours/year x (40% - 38.7%) = 587 mmBtu/year587 mmBtu/year x $7.34 /mmBtu = $4,309 /year


587 mmBtu/year x 113 lb CO2/mmBtu ≈ 66,300 lb CO2 /year

Reducing excess air would also cause the boiler to fire for less frequently. Doing so would cause draft loss to increase if AR X was not implemented. Hence, we encourage AR X to be implemented in order to realize the full savings potential.


Requesting a boiler contractor to adjust controls on a regularly scheduled visit requires no significant cost.

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Immediate

34

AR X: Recalibrate Furnace Air/Fuel Ratio to 10% Excess Air


PaybackResource CO2 (lb) Dollars Capital Other TotalNatural Gas 26,143 mmBtu 2,954,000 $222,216 $2,500 $1,230 $3,730 1 month

Analysis

We measured excess air in the exhaust gasses of one of the plant’s aluminum pot furnaces to be 95%. 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). Higher levels of excess air dilute the combustion stream and decrease the quantity of useful heat available to the process.

The pot furnace burners are North American brand burners. According to manufacturer literature, the burners are capable of varying combustion air intake over their firing range. Therefore, excess air should stay relatively constant when the burner is controlled properly. Maintenance showed us the intake air adjustment controls on the furnaces, which can be manually tuned by plant maintenance.

The following table shows the rated input of each furnace type, estimated average natural gas consumption, and the percentage of average consumption to the rated input, based off of values as derived in the Process Heating Analysis section of the report.

Furnace TypeRated Input

(mmBtu/hr)

Estimated Average

Consumption (mmBtu/hr)

Percentage (Avg. Cons. / Rated Input)

Reverb (Prod. Time) 8.7 2.18 25%Reverb (Non-Prod. Time) 8.7 0.44 5%Aluminum Melting 1.5 0.54 36%Aluminum Pot 1.5 0.54 36%Zinc 0.75 0.27 36%

To achieve maximum energy efficiency, furnaces should be calibrated at their average firing rate where they operate most often. Based on the percentages in the table shown above, the furnaces seem to operate mostly in the low-to-medium firing range.

Recommendation

We recommend recalibrating the air/fuel ratio on each of the plant’s furnaces to 10% excess air at their average firing rates, which are low-to-medium. Calibrating would involve one technician taking a real-time combustion gas analysis while another technician adjust intake air controls until 10% excess air is reached. A combustion gas analysis can be done with a combustion analyzer probe. Online literature from the burner manufacturer, North American (namfg.com), recommends burners operate at around 20% excess air, which is close to our recommendation.

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Estimated Savings

Definition & DerivationCombustion efficiency is defined as the ratio of heat transferred to metal to the total fuel energy supplied. To calculate combustion efficiency, adiabatic combustion temperature, Tc, must first be calculated, which is a function of combustion air inlet temperature, Ta, and excess combustion air, EA. Constants in the calculation are natural gas lower heating value (LHV = 21,500 Btu/lb), stoichiometric air/fuel ratio for natural gas combustion (AFs = 17.2 lb-air/lb-ng), and natural gas specific heat (Cp = 0.26 Btu/lb-F). The following equation calculates adiabatic combustion temperature, Tc.

Tc = Ta + LHV / [{1 + (1 + EA) • AFs} • Cp]

The heat transferred to metal, Qtrans, is a function of natural gas mass flow rate, mng, air mass flow rate, mair, combustion temperature, Tc, and exhaust gas outlet temperature, Tex. The following equation calculates heat transferred to metal, Qtrans.

Qtrans = (mng + mair) • Cp • (Tc – Tex)

The total fuel energy supplied, Qsupp, is equal to natural gas mass flow rate, mng, and higher heating value of natural gas (HHV = 23,900 Btu/lb).

Qsupp = mng • HHV

Thus, combustion efficiency, ε, is calculated as:

ε = Qtrans / Qsupp = [(mng + mair) • Cp • (Tc – Tex)] / [mng • HHV]

The mass terms cancel, and combustion efficiency, ε, becomes a function of excess air.

ε = [{1 + (1 + EA) • AFs} • Cp • (Tc – Tex)] / HHV

From this equation and the equation for combustion temperature, Tc; combustion efficiency, ε, is purely a function of excess air, EA, inlet combustion air temperature, Ta, and exhaust gas outlet temperature, Tex. This method for calculating combustion efficiency has been incorporated into the process heat simulation program HeatSim (Kissock and Carpenter, 2001) which can be downloaded free of charge off of the UD-IAC website at www.udayton.edu/udiac.

Aluminum Pot FurnacesEach aluminum pot furnace is equipped with a recuperator that transfers energy from exhaust outlet gasses to the inlet combustion air. We measured plant air temperature near the combustion air inlet to be 100 F and measured inlet combustion air temperature of one pot furnace to be 615 F after being preheated. We measured exhaust gas temperature to be 950 F at the outlet of the recuperator after transferring heat to combustion air. In addition, we measured 95% excess air in the exhaust. We could not measure the

36


temperature of exhaust gasses immediately after leaving the furnace and before entering the recuperator. However, the temperature gain of combustion air in a recuperator is about equal to temperature lost from exhaust gasses since the two streams have nearly the same mass flow rate and specific heat. The temperature gain of combustion air is about:

615 F – 100 F = 515 F

If the exhaust gasses lose 515 F through the recuperator, their temperature immediately after leaving the furnace is about:

950 F + 515 F = 1,465 F

The following HeatSim output screens show the current furnace combustion efficiency with recuperator, and the combustion efficiency if no heat were reclaimed and inlet combustion air temperature was 100 F.

Pot Furnace Efficiency with Recuperator Pot Furnace Efficiency without Recuperator

These calculations indicate that the aluminum pot furnace is 58.0% efficient, and would be 38.7% efficient without a recuperator. Thus, the recuperator increases the efficiency by about 19%.

Reverb FurnaceManagement monitored natural gas consumption of the reverb furnace to be 2.18 mmBtu/hr on average during production time. To calculate reverb furnace efficiency, we consider the two major heat sinks associated with the furnace: the aluminum inside of the furnace and the plant atmosphere to which the furnace emits heat. The remaining furnace heat is lost through the stack, and is not considered useful.

According to last year’s production records, the company purchased about 10,825,000 pounds of raw material. According to management, about 65% - 70% of total raw material is melted in the reverb furnace. Assuming 65%, the average hourly mass of aluminum loaded into the reverb furnace during the plant’s 5,400 annual production hours is about:

(10,825,000 lbs/year x 65%) / 5,400 hours/year = 1,303 lbs/hour

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Aluminum has a specific heat of 0.215 Btu/lb-F and a latent heat of melting of 138 Btu/lb. We measured the average plant temperature to be 95 F. Thus, the heat required to melt 1,253 lbs/hour of aluminum to 1,350 F is about:

1,303 lbs/hour x [0.215 Btu/lb-F x (1,350 F – 95 F) + 138 Btu/lb] = 531,396 Btu/hour

To calculate shell heat loss from the reverb furnace, we entered reverb furnace dimensions and temperatures into HeatSim. (Shell loss is discussed in greater detail in AR X.) According to HeatSim, 256,131 Btu/hour is attributed to reverb furnace shell loss.

Reverb Furnace Shell Loss

Dividing useful heat output by total heat input, the efficiency of the reverb furnace is about:

(531,396 Btu/hr + 256,131 Btu/hr) / [2.18 mmBtu/hr x (106 Btu /mmBtu)] = 36.1%

According to the digital monitor on the reverb furnace, aluminum temperature inside the furnace was 1,350 F and exhaust gas temperature was about 1,900 F during our visit. The HeatSim output screen below shows that about 54% excess air would result in 36.1% combustion efficiency. Thus, we assume the reverb furnace operates with 54% excess air.

Reverb Furnace Efficiency During Production Time

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Management indicated the set-point temperature of the aluminum inside the furnace is turned down to 1,200 F during non-production time. Thus, we estimate exhaust temperature is about 150 F lower than during production time. If so, exhaust gas temperature is about 1,750 F. Assuming excess air is also 54% during non-production time, combustion efficiency is about 40.6%.

Reverb Furnace Efficiency During Non-Production Time

On average, reverb furnace efficiency is about:

[36.1% x (4.5 dys/wk / 7 dys/wk)] + [40.6% x (2.5 dys/wk / 7 dys/wk)] = 37.7%

Aluminum Melting FurnacesAlthough we could not analyze the exhaust gasses of any melting furnace, we know the exhaust gas temperature is close to the pot furnace exhaust gas before entering the recuperator. We assume the melting furnaces are calibrated similarly to the pot furnace we analyzed. If so, excess air content would also be about 95%, and the combustion efficiency would be about 38.7%, which is the efficiency of a pot furnace without a recuperator.

Zinc FurnacesThe digital controls on the zinc furnaces indicate the zinc temperature inside the furnace is about 830. The temperature of aluminum in the pot furnaces is 1,250 F and stack temperature is about 1,465 F, which is a difference of 215 F. Assuming the exhaust gas temperature of the zinc furnaces is also 215 F greater than the zinc, the exhaust gas temperature is about:

830 F + 215 F = 1,045 F

We could not measure excess air in the exhaust gasses; however, we assume the melting furnaces are calibrated similarly to the pot furnace. If so, excess air content is about 95%. The HeatSim output screen below shows the combustion efficiency of the zinc furnaces is about 54.4%.

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Zinc Furnace Combustion Efficiency

In the proceeding analysis, we assumed the pot furnaces, melting furnaces, and zinc furnaces were all calibrated similarly, thus operate at about 95% excess air. We assumed the reverb furnace operates at 50% excess air. With these excess air values, we calculated combustion efficiency of each furnace using HeatSim (Kissock and Carpenter, 2005), which can be downloaded free of charge off of the UDIAC website www.udayton.edu/udiac.

To determine savings, we calculated the combustion efficiency of each furnace operating at 10% excess air, as shown in the following HeatSim output screens.

Pot Furnace Combustion Efficiency Melting Furnace Combustion Efficiency

With 10% Excess Air With 10% Excess Air

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Reverb Furnace Combustion Efficiency Reverb Furnace Combustion Efficiency During Production Time With 10% EA During Non-Production Time With 10% EA

Zinc Furnace Combustion EfficiencyWith 10% Excess Air

The following table summarizes the annual natural gas used by each group of furnaces, their current combustion efficiency, their combustion efficiency at 10% excess air, and annual natural gas savings. Values associated with current furnace operation were taken from the Process Heat Analysis. Annual natural gas savings was calculated using the following equation.

NG Savings = Current Gas Use x (1 – Current Efficiency /New Efficiency)

Furnace Type

Annual Natural Gas

Use (mmBtu/year)

Current Combustion Efficiency

Combustion Efficiency at

10% Excess Air

Annual Natural Gas

Savings (mmBtu/year)

Aluminum Pot 37,908 58.0% 71.5% 7,157Reverb (Prod. Time) 12,243 36.1% 51.0% 3,577Reverb (Non-Prod. Time) 1,373 40.6% 54.2% 345Aluminum Melting 33,113 38.7% 60.4% 11,897Zinc 14,580 54.4% 69.5% 3,168Total 99,217 26,143

According to the table, about 26,143 mmBtu per year could be saved from reducing excess air. Cost savings would be about:

26,143 mmBtu/year x $8.50 /mmBtu = $222,216 /year


26,143 mmBtu/year x 113 lb CO2/mmBtu ≈ 2,954,000 lb CO2 /year


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A combustion flue gas analyzer capable of analyzing exhaust streams up to about 1,800 F costs about $2,500. We estimate it would take two maintenance workers about ½ hour to calibrate a furnace. The plant has approximately 41 furnaces. At a labor rate of $30 per hour, the maintenance cost of calibrating the furnaces would be about:

2 workers x ½ hour/furnace x 41 furnaces x $30 /worker-hour = $1,230

Total implementation cost would be about:

$2,500 + $1,230 = $3,730


($3,730 / $222,216 /year) x 12 months/year = 1 month

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AR X: Convert Forehearth to Oxy-fuel BurnersAnnual Savings Project

Fuel (mmBtu) Elec (kWh) CO2 (lbs) Dollars ($) Cost ($) PaybackEnergy 114,730 -2,266,397 7,751,000 $714,721 $2,000,000 34 months

Analysis

The forehearth currently uses atmospheric air to mix with natural gas for combustion. The plant’s melting furnaces were recently retrofitted with oxy-fuel burners, which use pure oxygen to mix with natural gas for combustion. Oxy-fuel is more energy-efficient and provides a higher flame temperature than burners that use atmospheric air because atmospheric air contains nitrogen which does not contribute to the combustion chemical reaction but only acts as a heat sink. Oxygen is produced in an oxygen plant and sent to the melting furnaces.

Within the next year, the forehearth will be rebuilt. According to management, it is possible to retrofit the forehearth with oxy-fuel burners during rebuild.

Recommendation

We recommend converting the forehearth to use oxy-fuel burners during rebuild and expanding the oxygen plant to provide for oxy-gas for the forehearth.

Estimated Savings

The temperature of exhaust from the forehearth is about 2,700 F. The spreadsheet below is an output screen from CombEff.xls for the combustion of atmospheric air with natural gas. CombEff.xls incorporates combustion chemical equations and heat energy balances to calculate combustion efficiency. According to the spreadsheet, the combustion efficiency in the forehearth is currently about 28.0%.

Input DataEA = excess air (0=stoch, 0.1 = optimum) 0.20Tca = temperature combustion air before burner (F) 70Tex = temperature exhaust gasses (F) 2,700

Constants (for Natural Gas)LHV = lower heating value (Btu/lb) 21,500HHV = higher heating value (Btu/lb) 23,900Cpp = specific heat of products of exhaust (Btu/lb-F) 0.260Afs = air/fuel mass ratio at stochiometric conditions 17.20

Calculated ValuesTc = temp combustion (F) = Tca+LHV/[(1+(1+EA)(Afs))Cpp] 3,891Efficiency = [1 + (1+EA)(AFs)]*Cpp*(Tc-Tex)/HHV 28.0%

The graph below demonstrates the combustion efficiency improvement from using pure O2 as the oxidizer in natural gas combustion. According to the graph, the forehearth combustion efficiency would increase to about 67%.

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Source: North American Combustion Handbook 3 rd ed . North American Manufacturing Company. 1995

According to management’s records, the forehearth uses about 197,100 mmBtu per year. Thus, the annual natural gas savings would be about:

197,100 mmBtu/year x [1 – (28% / 67%)] = 114,730 mmBtu/year114,730 mmBtu/year x $7.00 /mmBtu = $803,110 /year

This would reduce CO2 emissions by about:

114,730 mmBtu/year x 113 lb CO2/mmBtu ≈ 12,964,000 lb CO2 /year

To generate oxygen for oxy-fuel, additional electrical energy would be needed. The annual natural gas used in the forehearth would be about:

197,100 mmBtu/year – 114,730 mmBtu/year = 82,370 mmBtu/year

The higher heating value of natural gas is about 23,900 mmBtu/lb. For stoichiometric combustion, four lb of oxygen is needed for one lb of natural gas. If the forehearth operated at 20% excess oxygen, the annual mass of oxygen used would be about:

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82,370 mmBtu/year x 106 Btu/mmBtu x (lb-NG /23,900 Btu) x 4 lb-O2 /lb-NG x 120% = 16,542,929 lb/year

At standard conditions, the density of oxygen is 0.0827 lb/ft3. Thus, the annual volume of oxygen used by the forehearth would be about:

16,542,929 lb/year / 0.0827 lb/ ft3 x (mcf /1,000 ft3) = 200,035 mcf/year

According to the Melter Efficiency Analysis section of the report, about 11.33 kWh of electricity is needed to produce 1 mcf of oxygen. Thus, the annual increase in electrical energy consumption would be about:

200,035 mcf/year x 11.33 kWh/mcf = 2,266,397 kWh/year2,266,397 kWh/year x $0.039 /kWh = $88,389 /year

This would increase CO2 emissions by about:

2,266,397 kWh/year x 2.3 lb CO2/kWh ≈ 5,213,000 lb CO2 /year

The net annual savings would be about:

$803,110 /year – $88,389 /year = $714,721 /year

The net reduction in CO2 emissions would be about:

12,964,000 lb CO2 /year – 5,213,000 lb CO2 /year ≈ 7,751,000 lb CO2 /year


According to management, it would cost about $2,000,000 to convert the forehearth to use oxy-fuel and expand the oxygen plant to provide enough oxy-gas.


($2,000,000 / $714,721 /year) x 12 months/year = 34 months

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AR 6: Convert Two Smelters’ Gas Burners from Atmospheric Combustion to Oxy-fuel Combustion

ARC: 2.1126.1Annual Savings Project Cost

SimplePaybackResource

CO2

(tonnes)Dollars Capital Other Total

Natural Gas 7,771 mmBtu 391 $75,942 $100,000 $50,000 $150,000Oxygen -$66,052Total 7,771 mmBtu 391 $9,890 $100,000 $50,000 $150,000 182 month

Analysis

Smelters No. 3 and 600 currently use atmospheric air for combustion. Smelters No. 1 and No. 2 have been retrofitted with oxy-fuel burners, which mix pure oxygen with natural gas for combustion. Oxy-fuel is more energy-efficient and provides a higher flame temperature than burners that use atmospheric air because atmospheric air contains about 79% nitrogen. The nitrogen does not contribute to the combustion chemical reaction, but it does act as a heat sink and lowers the temperature of combustion.

Management is considering retrofitting the No. 3 and 600 smelters to oxyfire and asked us to estimate savings.

Smelter No. 3Recommendation

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Based on the analysis below, retrofitting smelters’ No.3 and 600 atmospheric burners to use oxy-fuel burners, would reduce operating costs. However, the investment is substantial and the pay back is long.

Estimated Savings

The temperature of exhaust from smelters No. 3 and 600 is about 2,550 F. We assume the excess air for smelters No. 3 and 600 is about 5 percent. The combustion equation for the combustion of natural gas is:

CH4 + 2(O2 + 3.76 N2) CO2 + 2 H20 + 7.52 N2

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 combustion equation above, the air fuel ratio for stochiometric (complete) combustion, AFs, are about:

AFs = (mca/mng)stoch = 17.2 lb-air/lb-ng

Excess air is defined as:

EA = mca,actual / mca,stoch - 1

Thus, 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 + (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. In this case, the heat of reaction equals the lower heating value (LHV) of the fuel because the exhaust gas streams are above 140 F. The heating values of natural gas are shown below:

LHVng = 21,500 Btu/lbng HHVng = 23,900 Btu/lbng

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 + (1+EA) x (AFs)} x cpp x (Tc-Tex)] / HHV

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Where Tca is the temperature of the combustion air before it enters the burner, and Tex is the temperature of the exhaust gasses.

The spreadsheet below is an output screen from CombEff.xls for the combustion of atmospheric air with natural gas. CombEff.xls incorporates combustion chemical equations and heat energy balances to calculate combustion efficiency. The current efficiencies of smelters No. 3 and 600 are calculated to be about 39 % as shown in the table below.




The use of oxy-fuel would reduce the air fuel ratio for stochiometric (complete) combustion to 4 lb-oxygen/lb-ng by eliminating nitrogen in the combustion equation above. The spreadsheet below shows the efficiency of the smelters with oxy-fire burners would increase to about 76%, assuming an oxygen fuel ratio of 4 lb-oxygen/lb-ng and that the excess air for combustion remains the same at 5%.




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The graph below demonstrates the combustion efficiency improvement from using pure O2 as the oxidizer in natural gas combustion. According to the graph, the efficiency is about 69% for a flue gas exist temperature of 2,550 F. This number is comparable to our calculated efficiency of 76%. For this analysis, the calculated efficiency of 76 % will be used.

Source: North American Combustion Handbook 3 rd ed . North American Manufacturing Company. 1995

According to management’s records, smelters No.3 and 600 use about 15,144 mmBtu per year. Thus, the annual natural gas savings would be about:

15,144 mmBtu/year x [1 – (39% / 76%)] = 7,373 mmBtu/year7,373 mmBtu/year x $10.30 /mmBtu = $75,942 /year

The annual natural gas used in smelters No.3 and 600 would be about:

15,144 mmBtu/year – 7,373 mmBtu/year = 7,771 mmBtu/year

For stoichiometric combustion, four lb of oxygen is needed for one lb of natural gas. If smelters No.3 and 600 operated at 5% excess oxygen, the annual mass of oxygen used would be about:

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7,771 mmBtu/year / 23,900 Btu/lb-NG x 4 lb-O2 /lb-NG x 105% = 1,365,615 lb/year

At standard conditions, the density of oxygen is 0.0827 lb/ft3. Thus, the annual volume of oxygen used by smelters No.3 and 600 would be about:

1,365,615 lb/year / 0.0827 lb/ ft3 / 100 ft3/ccf = 165,129 ccf/year

According to the billing statements provided by management listed in the table below, the total cost of oxygen is $0.40 /ccf.

Date Volume O2 Total Cost O2SCF ($)

12/20/2007 91600 $459.1712/10/2007 313300 $1,209.6111/21/2007 140300 $624.0210/22/2007 255400 $1,016.00

10/3/2007 374800 $1,417.789/23/2007 404500 $1,518.32

Total 1579900 $6,244.90Avg. Cost per CCF $0.40

Thus, the annual cost of oxygen would be about:

165,129 ccf/year x $0.40 /ccf = $66,052 /year

The net annual savings would be about:

$75,942 /year – $66,052 /year = $9,890 /year

This would reduce plant CO2 emissions by about:

7,373 mmBtu/year x 117 lb CO2/mmBtu / (2,205 lb/tonne) ≈ 391 tonnes-CO2 /year

These results shown above are based on our understanding of the processes. However, we note that from September to December, total expenditures for oxygen for the two current oxy-fire burners were about $6,245, which suggests an annual cost for oxygen of about $25,000. We estimate that the annual cost of oxygen for two additional burners would be about $66,052 per year. We don’t understand the nature of this discrepancy. Thus, we suggest that you review our analysis carefully before using it to make investment decisions.


According to management, it would cost about $150,000 to convert smelters No.3 and 600 to use oxy-fuel. We assume that $100,000 would be material and $50,000 would be labor.

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($150,000 / $9,890 /year) x 12 months/year = 182 months

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