Project Background - Projects & Planning€¦ · projections = 32 mgd. Maximum design biogas production rate in model year: 439,085 cubic feet/day (160 million cubic feet/year). (3)

Technical Memorandum 4.4

To: Mary Strawn, Arlington County Water Pollution Control Bureau From: K. Richard Tsang, CDM Smith Date: March 29, 2018 Subject: Arlington County WPCP Solids Master Plan TM No. 4.4 – Air Emissions Modeling Report

1.0 Project Background The Arlington Water Pollution Control Plant (WPCP), located at 3402 South Glebe Road in Arlington, Virginia, is permitted to discharge an average daily flow of 40 million gallons per day of treated wastewater into Four Mile Run. The plant provides wastewater treatment for residential and commercial customers located in Arlington County, as well as portions of neighboring jurisdictions. A layout of the WPCP site is shown in Figure 1-1.

The County is completing a Solids Master Plan for the WPCP to develop a long-term management strategy for residuals produced as part of the treatment process. A detailed evaluation of various biosolids management alternatives was completed as part of the master planning process. The preferred alternative identified by the County includes thermal hydrolysis pretreatment (THP) with anaerobic digestion. THP combined with anaerobic digestion will produce a Class A biosolids product as well as a biogas that can be captured and utilized as a fuel.

Multiple options are currently under consideration for utilization of the biogas, including:

Installation of combined heat and power (CHP) system on-site, including engine generators to produce electricity and heat recovery systems to generate hot water/steam for use at the WPCP.

Treatment of the biogas to meet compressed natural gas (CNG) on-road motor vehicle fuel standards and delivery of the treated fuel to offsite fueling stations. The expected gas quality for CNG fuel is a product having a typical heating value of 975 BTU/scf; concentration of greater than 90% methane; concentration of less than 8% nitrogen; and concentration of less than 0.5% oxygen, CNG may be produced from technologies such as scrubbers, membranes, and pressure swing adsorption.

Mary Strawn, Arlington County March 29, 2018 Page 2

Treatment of biogas to meet natural gas pipeline standards and injection of bio-methane into a distribution pipeline. Natural gas pipeline standards can vary but typically have a higher minimum heating value and lower allowable oxygen and nitrogen concentration than CNG. Biomethane may be produced using technologies such as water scrubbers, membranes, and pressure swing adsorption.

Figure 1-1. Arlington County WPCP Existing Site Layout All of the utilization options require a waste gas burner (WGB) to control excess biogas produced in the digestion process. To assist in comparing the potential air quality impacts from these options, three groups of scenarios for emission calculations and dispersion modeling were developed. These scenarios are summarized in Table 1-1.


Table 1-1. Future Scenario Descriptions

Scenario Biogas to CHP

Engines Biogas to Waste Gas Burner(1)

Biogas to Offsite

Utilization

New Natural Gas Boiler for

Steam

Biosolids Haul

Trucks

Scenario 1: CHP Engines Located North of Glebe Road, at Old DAF Building

1A 100% of available biogas (2) 0% of available biogas (2) Not applicable Yes Yes

1B 90% of available biogas (2)

10% of available biogas (2), unit west of new THP facilities Not applicable Yes Yes

1C 90% of available biogas (2)

10% of available biogas (2), unit east of new THP facilities Not applicable Yes Yes

Scenario 2: CHP Engines Located South of Glebe Road, West of Operations Control Building

2A 100% of available biogas (2) 0% of available biogas (2) Not applicable Yes Yes

2B 90% of available biogas 10% of available biogas (2), unit west of new THP facilities Not applicable Yes Yes

Scenario 3: Offsite Utilization of Biomethane or CNG

3A Not applicable 15% of available biogas (2) 85% of

available biogas (2)

Yes Yes

3B Not applicable 100% of available biogas (2,3), unit west of new THP facilities

0% of available biogas Yes Yes

Scenario 4: CHP Engines Located North of Glebe Road with Additional Emissions Controls

4A Scenario 1A w/SCR, OxiCat, and DPF 0% of available biogas (2) Not applicable Yes Yes

4B Scenario 1B w/SCR, OxiCat, and DPF


4C Scenario 1C w/SCR, OxiCat, and DPF

10% of available biogas (2), unit east of new THP facilities Not applicable Yes Yes

Scenario 4: CHP Engines Located South of Glebe Road with Additional Emissions Controls

5A Scenario 2A w/SCR, OxiCat, and DPF 0% of available biogas (2) Not applicable Yes Yes

5B Scenario 2B w/SCR, OxiCat, and DPF


Notes: (1) Percentage of biogas to waste gas burner may depend on availability of CHP engines or offsite utilization demand. The anticipated worst-

case scenario, specific to ambient air quality, is 100% utilization of biogas in CHP engines. (2) Available biogas is based on biogas production projections in Year 2030 (midpoint of planning period). Annual average wastewater flow

projections = 32 mgd. Maximum design biogas production rate in model year: 439,085 cubic feet/day (160 million cubic feet/year). (3) This scenario was developed assuming no off-site gas utilization. This could be potentially due to downtime on the gas cleaning system or

due to no demand by the off-site customer.


1.1 Objective of Dispersion Modeling Study The primary objectives of the air dispersion modeling study are as follows:

1. To assess the overall facility’s compliance with National Ambient Air Quality Standards (NAAQS) and Virginia Ambient Air Quality Standards (VAAAQS) with the implementation of biosolids management project.

2. To understand the air quality impacts and the nearest sensitive receptors due to additional planned combustion equipment related to digester gas combustion.

3. To address questions raised by project stakeholders regarding the air quality impact of digester gas combustion

4. To identify potential air quality permitting issues that would need to be addressed once a biogas utilization option is chosen.

Dispersion modeling was conducted for all criteria pollutants including Nitrogen Dioxide (NO2), Carbon Monoxide (CO), Sulfur Dioxide (SO2), Particulate Matter (PM10) with aerodynamic diameter less than 10 microns, PM2.5 with aerodynamic diameter less than 2.5 microns and results were compared with the applicable NAAQS and VAAAQS. In addition, Volatile Organic Compounds (VOC) were modeled as a surrogate for organic hazardous air pollutants. The air dispersion analysis was conducted in accordance with the Guideline on Air Quality Models pursuant to Title 40 Code of Federal Regulations (CFR) Part 51 (40 CFR 51) Appendix W.

1.2 Air Quality Permitting Thresholds WPCP is subject to the air quality regulations of the U.S. Environmental Protection Agency (U.S. EPA) and Virginia Department of Environmental Quality (VDEQ). WPCP is currently a non-major source and holds stationary source permit to operate three diesel fuel emergency generators, multiple hot water boilers for building heating, two methanol storage tanks, and one diesel storage tank.

In accordance with the definition of “Major Stationary Source” in the Title 9 State Air Pollution Control Board Commonwealth of Virginia’s Administrative Code 5, Chapter 80 (9VAC5 Chapter 80), any physical change that would occur at a stationary source not previously qualifying as a major stationary source will be considered a major stationary source if the physical change would result in the following increases either in actual emissions, or in the federal potential to emit, greater than or equal to:

100 tons per year of volatile organic compounds (VOC);

100 tons per year of nitrogen oxides (NOx); or

100 tons per year of any other pollutants such as carbon monoxide (CO), sulfur dioxide (SO2), particulate matter (PM10 or PM2.5).


Table 1-2 presents the Major Source threshold and the Facility’s potential to emit (PTE) after the addition of the proposed project under each scenario. The PTE assumes that all proposed new equipment operates continuously at the design capacity for a given scenario, and that the existing equipment emits at the currently permitted maximum annual rate, except for the existing emergency generator engines A, B, and C, discussed below. Once an option is selected to carry forward into construction, permitting the new units at the PTE will allow the greatest flexibility in equipment operations under the permit. Therefore, the following source assumptions are used to obtain the PTE for each scenario:

Scenarios 1A, 1B, 1C, 2A, and 2B: Existing units emit at the currently permitted annual emission rate, and the new units (two CHP engines, one waste gas burner, and two natural gas boilers) would operate continuously at 100 percent of design capacity.

Scenarios 3A and 3B: Existing units emit at the currently permitted annual emission rate, and the new units (one waste gas burner, and two natural gas boilers) would operate continuously at 100 percent of design capacity.

Emergency Standby Generator Engines A, B, and C: The Arlington WPCP is not currently participating in any on-call power generation programs; therefore, the existing emergency standby generator engines A, B, and C are each assumed to operate once per week for maintenance testing, 52 weeks per year.

Note that these assumptions are only used to obtain the PTE for comparison to the Major Source emission thresholds. The air dispersion modeling included in this study is based on the operating assumptions noted in Table 1-1 above.

1.3 National and State Ambient Air Quality Standards The Environmental Protection Agency (EPA) has established NAAQS for six criteria pollutants: SO2, PM10, PM2.5, NO2, CO, Ozone (O3), and lead (Pb). The NAAQS specify maximum concentrations for various averaging times below which the air quality is considered acceptable with an adequate margin of safety and they include both primary and secondary standards. Table 1-3 presents the summary of the current NAAQS pursuant to 40 CFR 50 and VAAAQS pursuant to 9VAC5 Chapter 30 for criteria pollutants. Arlington County, Virginia is currently in NAAQS attainment for all criteria pollutants, except for the 2008 8-hour O3 standard.

Table 1-2. Summary of Estimated Potential Emissions in Tons per Year

Pollutant

Existing Facility PTE,

tpy

Proposed CHP Units PTE, tpy

Scenarios 1A/B/C and 2A/2B

Proposed Biomethane

Utilization Units PTE, tpy

Scenarios 3A/3B

Total Facility with CHP project

addition PTE, tpy

Total Facility with Biomethane Utilization

project addition PTE, tpy

Title V/Major Stationary Source Threshold, tpy2,3

Carbon Monoxide (CO) 33.3 94.9 26.8 128.2 (1) 62.3 100

Nitrogen Oxides (NOx) 25.2 19.1 5.4 44.2 32.5 100

Sulfur Dioxide (SO2) 6.1 3.8 3.6 9.9 9.8 100

Inhalable Particulate Matter (PM10)

8.0 5.1 1.7 13.1 10.0 100

Fine Particulate Matter (PM2.5) 8.0 5.1 1.7 13.1 10.0 100

Volatile Organic Compounds (VOC)

4.3 11.5 7.0 15.8 11.5 100

Source: CDM Smith, 2017 Key: PTE= potential to emit; tpy = tons per year; CHP = combined heat and power; WGB = waste gas burner Notes: 1) Exceeds major source threshold for combined existing and new units. Although this is a conservative scenario in that assumes full year operation of two CHP engines and the WGB, removing the

WGB would result in CO emissions that still exceed the threshold. 2) Title V/Major source thresholds obtained from: http://www.deq.virginia.gov/Portals/0/DEQ/Air/Regulations/801.pdf page 8:1-9 Definition of “Major Source” (c) that states “For ozone

nonattainment areas, any stationary source with the potential to emit 100 tons per year or more of VOC or NOx in areas classified as “marginal” or “moderate,” 50 tons per year or more in areas classified as "serious," 25 tons per year or more in areas classified as "severe," and 10 tons per year or more in areas classified as "extreme"

3) Arlington County Attainment Status, Marginal for 8-Hr Ozone (2008), as of 12/7/17: https://www3.epa.gov/airquality/greenbook/hbca.html#Ozone_8-hr.2008.Washington

http://www.deq.virginia.gov/Portals/0/DEQ/Air/Regulations/801.pdf

https://www3.epa.gov/airquality/greenbook/hbca.html#Ozone_8-hr


Table 1-3. National and Virginia Ambient Air Quality Standards

Pollutant Averaging Time VAAAQS NAAQS Primary

NAAQS Secondary

Ozone (O3) 8-hr 0.070 ppm 0.070 ppm Same as primary

Inhalable Particulate Matter (PM10)

24-hr 150 µg/m3 150 µg/m3 Same as primary

Fine Particulate Matter (PM2.5)

24-hr 35 µg/m3 35 µg/m3 Same as primary

Annual 12 µg/m3 12 µg/m3 15 µg/m3

Carbon Monoxide (CO)

1-hr 35 ppm (40 mg/m3)

35 ppm (40 mg/m3)

NS

8-hr 9 ppm (10 mg/m3)

9 ppm (10 mg/m3)

NS

Nitrogen Dioxide (NO2)

1-hr 100 ppb (189 µg/m3)

100 ppb (189 µg/m3)

NS

Annual 0.053 ppm (100 µg/m3)

0.053 ppm (100 µg/m3)

Same as primary

Sulfur Dioxide (SO2) (1)

1-hr 0.075 ppm (196 µg/m3)

0.075 ppm (196 µg/m3)

-

3-hr (secondary VAAAQS and NAAQS) (2)

0.5 ppm (1,300 µg/m3)

NS 0.5 ppm (1,300 µg/m3)

24-hr 0.14 ppm (365 µg/m3)

0.14 ppm (365 µg/m3)

NS

Annual 0.030 ppm (80 µg/m3)

0.030 ppm (80 µg/m3)

NS

Lead (Pb) Rolling 3-month average 1.5 µg/m3 0.15 µg/m3 Same as primary Source: NAAQS: 40 CFR 50; VAAAQS: 9VAC5 Chapter 30 Key: µg/m3 = micrograms per cubic meter; VAAAQS = Commonwealth of Virginia Ambient Air Quality Standard; mg/m3 = milligrams per cubic

meter; NAAQS = National Ambient Air Quality Standard; NS = no standard; ppb = parts per billion; ppm = parts per million Notes: 1) The January 9, 2018, Federal Register notes that Arlington County, along with much of the country, was designated as

attainment/unclassifiable (which is treated as attainment) for the 2010 SO2 1-hour NAAQS (83 FR 1098). This designation has an effective date of April 9, 2018; indicating that the previous SO2 primary standards (0.14 ppm 24-hour and 0.03 ppm annual) will remain in effect until April 9, 2019, one year after the effective date of designation under the current (2010) standard.

2) Note that the secondary 3-hour standard is much higher than the 2010 primary 1-hour standard. Demonstrating compliance with the 1-hour standard effectively demonstrates compliance with the secondary 3-hour standard.


1.4 Air Pollutants Modeled in this Study Ozone (O3) is a secondary pollutant, meaning that it is formed in the atmosphere from reactions of other precursor compounds under certain conditions, and O3 concentrations are highly dependent on regional concentrations of the precursor compounds (with major contributions coming from motor vehicle emissions). Therefore, O3 was not modeled in this study. Primary precursor compounds that lead to formation of O3 include VOC and NOx, which are addressed on a facility basis through the emissions permitting thresholds noted in Section 1.2.

As an air pollutant, Pb was a concern when leaded-gasoline was commonly used in automobiles. However, since the removal of Pb from motor vehicle fuels, Pb concentrations have declined substantially. In addition, the WPCP does not emit Pb from the existing or proposed operations. Therefore, Pb is not modeled in this study.

PM2.5 can be emitted directly from sources or can form in the atmosphere from other precursor compounds. The AERMOD dispersion model used for this analysis does not include effects of atmospheric chemistry and physics on the formation of PM2.5. Therefore; only directly-emitted PM2.5 is modeled in this study,

Because VOC does not have a primary or secondary NAAQS, it was modeled only for annual averaging period.

In summary, the following pollutants were included in the air dispersion modeling analysis:

CO (1-hour and 8-hour averages) PM2.5 (24-hour and annual averages)

NO2 (1-hour and annual averages) PM10 (24-hour average)

SO2 (1-hour, 24-hour, and annual averages)1 VOC (annual average)

2.0 Source Description The existing and proposed emission units that were included in the dispersion modeling analyses are summarized in the Table 2-1.

1 On June 2, 2010, the 1-hour SO2 standard was established and the existing 24-hour and annual primary standards were revoked. The 24-hour

and annual standards remain in effect until one year after an area is designated for the 2010 standard. At this time, Arlington County has not received a designation (either attainment or non-attainment) for the 2010 1-hour standard, therefore, all three primary standards were modeled. A secondary 3-hour standard also exists for SO2, however, demonstration of attainment with the 1-hour and 24-hour standard indicates attainment of the 3-hour standard.


Table 2-1. Facility Sources

Equipment Manufacturer Existing/ Proposed

Primary Fuel

Maximum Rated Capacity

Emergency Generator A Caterpillar 3516C Existing Diesel 2,500 kWe

Emergency Generator B Caterpillar 3516C Existing Diesel 2,500 kWe

Emergency Generator C Caterpillar 3516C Existing Diesel 2,500 kWe

Dewatering Building NG water heater/boiler Kewanee L3w-150G-LE Existing Natural

Gas 5.021 MMBtu/hr

Operations Control Building (OCB) Boiler1

Lochinvar Corp. Commercial Heating Boiler Model "Knight" KBN-501 NG

Existing Natural Gas 5 MMBtu/hr

New Maintenance Building (NMB) Boiler1 Aerco Low NOx boiler Existing Natural

Gas 2 MMBtu/hr

Methanol Storage Tank 1 - Existing -- 12,000 gallons

Methanol Storage Tank 2 - Existing -- 12,000 gallons

Diesel Storage Tank - Existing -- 12,000 gallons

Biosolids Trucks for Sludge Hauling - Existing/Modified Diesel

1600 truck trips in 2016/ 1,030 truck trips in 2030

Enclosed Waste Gas Burner Varec Proposed Bio Gas 19.5 MMBtu/hr

CHP Stack 1 GE Jenbacher Proposed Bio Gas 846 kW (1,175 BHP)

CHP Stack 2 GE Jenbacher Proposed Bio Gas 846 kW (1,175 BHP)

Natural Gas Boiler 1 Cleaver Brooks Model CBLE Proposed Natural

Gas 200 HP (6.695 MMBtu/hr)

Natural Gas Boiler 2 Cleaver Brooks Model CBLE Proposed Natural

Gas 200 HP (6.695 MMBtu/hr)

Notes:

1) Only one duty OCB boiler and one NMB boiler is included in the dispersion model. A second boiler is assumed to be in standby for the dispersion modeling.

2.1 Source Emission Rates The air quality analysis requires that the maximum hourly and annual emissions from each source be fully and accurately characterized. The maximum hourly emissions are used to estimate concentrations for the short-term averaging periods (1-hour, 8-hour, and 24-hour), whereas the annual emissions are used to estimate concentrations for the long-term averaging period (annual).


The maximum hourly emissions from the existing sources are based on maximum permitted emission limits or maximum emitting potential of the source. Table 2-2 summarizes the short-term emission rates for the existing sources and proposed sources.

The maximum annual emissions from existing sources are based on 2016 actual emission inventory, whereas the maximum annual emissions from proposed sources are based on the maximum potential to emit from the source, adjusted to duration that the given source is expected to be available under each scenario. For example, the CHP engines are expected to be operating 90 percent of the time under Scenarios 1B, 1C, and 2B; therefore, the annual potential to emit emission rate is multiplied by 0.9 to obtain the 90 percent emission rate for the year. Table 2-3 summarizes the long-term emission rates for the existing sources and the proposed sources.

The detailed emission calculations and the back-up tables for each emission source are provided in Appendix A.

The following sections provide a brief discussion for the existing and proposed emission units and the basis of their maximum potential emission rates.

2.1.1 Existing Emission Units 2.1.1.1 Caterpillar Generators A, B and C The Facility has three identical Caterpillar (Model 3516 C) diesel generator sets A, B and C with a rated capacity of 2500 kWe each. All three generators have Selective Catalytic Reduction (SCR) and Oxidation Catalyst as add-on control technology.

The existing emissions of NOx from these units required some additional analysis. The hourly emission limits contained in the facility air quality permit depends on whether the selective catalytic reduction (SCR) system is, or is not, operating. SCR system NOx control efficiencies are highly dependent on the exhaust gas temperature entering the catalyst bed. According to the facility Stationary Source Permit to Construct and Operate dated July 2, 2012, the SCR system should be operating when the catalyst bed temperature reaches 572 OF. The instrument controls for these systems are often designed to avoid injecting ammonia (ammonia is used to reduce NOx to elemental nitrogen, N2) into the bed until temperatures reach the minimum required for NOx reduction. Therefore, some percentage of time that the engine is operating would likely occur without the SCR operating.

The permitted emissions limits indicate that the SCR system provides at least 90 percent reduction in the NOx emissions compared to the uncontrolled condition: NOx emission limit with SCR operating = 4.7 pounds/hour (lb/hr); NOx emission limit without SCR operating = 48.2 lb/hr. The actual NOx emissions for the 12-month period from December 2015 through November 2016 were

Table 2-2. Short-Term Emission Rates for Existing and Proposed Sources

Emission Source

Short-term Emission Rates (g/s) Emission Rate Basis

NOx CO SO2 PM10 PM2.5 VOC

Emergency Generator A 0.75 0.81 0.16 0.20 0.20 0.10 Permit Limits1

Emergency Generator B 0.75 0.81 0.16 0.20 0.20 0.10 Permit Limits1

Emergency Generator C 0.75 0.81 0.16 0.20 0.20 0.10 Permit Limits1

Dewatering Building NG water heater/boiler 6.30E-02 5.29E-02 3.72E-04 4.71E-03 4.71E-03 3.41E-03 NOx and CO emission limits from Permit; SOx, PM and VOC from AP-42 emission factors;(1) based on maximum rated heat input capacity

Operations Control Building (OCB) Boiler1 1.89E-02 1.51E-02 3.71E-04 4.69E-03 4.69E-03 3.40E-03 CO, SOx, PM and VOC from AP-42 emission factors;(1) based on maximum rated heat input capacity; 20 ppm low NOx burner, emission rate calculated for NOx

New Maintenance Building (NMB) Boiler1 6.12E-03 2.08E-02 1.48E-04 1.88E-03 1.88E-03 1.36E-03 CO, SOx, PM and VOC from AP-42 emission factors;(1) based on maximum rated heat input capacity; 20 ppm low NOx burner, emission rate calculated for NOx

Methanol Storage Tank 1 - - - - - 3.21E-03 EPA Tanks v4.09d, based on annual throughput limit


Diesel Storage Tank - - - - - 4.77E-04 EPA Tanks v4.09d

Biosolids Trucks for Sludge Hauling (Baseline/Existing) 1.59E-03 5.06E-04 6.37E-06 9.77E-05 8.99E-05 7.75E-05 EPA MOVES for year 2016

Enclosed Waste Gas Flare 0.15 0.74 0.10 0.04 0.04 0.20 Typical gas quality/Vendor info

CHP Stack 1 0.20 0.98 0.00 0.05 0.05 0.07 Typical gas quality/Vendor info

CHP Stack 2 0.20 0.98 0.00 0.05 0.05 0.07 Typical gas quality/Vendor info

Natural Gas Boiler 1 9.28E-03 3.37E-02 8.44E-04 8.44E-03 8.44E-03 3.37E-03 Typical gas quality/Vendor info


Biosolids Trucks for Sludge Hauling (Future) 3.87E-04 1.20E-04 5.98E-06 1.06E-05 9.71E-06 1.57E-05 EPA MOVES for year 2030 Source: CDM Smith, 2017 Notes: 1) Emission factors from U.S. EPA Compilation of Air Pollutant Emission Factors (AP-42). Available at https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emission-factors (last accessed January 30, 2018).

https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emission-factors

2

Table 2-3. Long-Term Emission Rates for Existing and Proposed Sources

Emission Source Long-term Emission Rates (g/s)

Emission Rate Basis NOx CO SO2 PM10 PM2.5 VOC

Emergency Generator A 0.75 0.32 0.06 0.08 0.08 0.04 2016 Emissions Inventory

Emergency Generator B 0.75 0.36 0.08 0.10 0.10 0.05 2016 Emissions Inventory

Emergency Generator C 0.75 0.29 0.08 0.10 0.10 0.05 2016 Emissions Inventory

Dewatering Building NG water heater/boiler 6.30E-02 5.29E-02 3.72E-04 4.71E-03 4.71E-03 3.41E-03 2016 Emission Inventory actual throughput and AP-42 emission factors(1)

Operations Control Building (OCB) Boiler1 1.89E-02 1.51E-02 3.71E-04 4.69E-03 4.69E-03 3.40E-03 2016 Emission Inventory actual throughput and AP-42 emission factors;(1) 20 ppm low NOx boiler

New Maintenance Building (NMB) Boiler1 6.12E-03 2.08E-02 1.48E-04 1.88E-03 1.88E-03 1.36E-03 2016 Emission Inventory actual throughput and AP-42 emission factors;(1) 20 ppm low NOx boiler



Diesel Storage Tank - - - - - 4.77E-04 EPA Tanks v4.09d

Biosolids Trucks for Sludge Hauling (Baseline/Existing) 1.11E-03 3.54E-04 4.45E-06 6.83E-05 6.29E-05 5.42E-05 EPA MOVES for year 2016

Enclosed Waste Gas Flare @ 100% 0.15 0.74 0.10 0.04 0.04 0.20 Typical gas quality/Vendor info; at full operating load based on design capacity

Enclosed Waste Gas Flare @ 10% 0.01 0.07 0.01 0.004 0.004 0.02 Typical gas quality/Vendor info; at 10% operating load based on design capacity

Enclosed Waste Gas Flare @ 15% 0.02 0.11 0.02 0.01 0.01 0.03 Typical gas quality/Vendor info; at 15% operating load based on design capacity

CHP Stack 1 and Stack 2 @ 100 % 0.20 0.98 0.00 0.05 0.05 0.07 Typical gas quality/Vendor info; at full operating load based on design capacity

CHP Stack 1 and Stack 2 @ 90% 0.18 0.88 0.001 0.04 0.04 0.06 Typical gas quality/Vendor info; at 90% operating load based on design capacity



Biosolids Trucks for Sludge Hauling (Future) 1.74E-04 5.42E-05 2.69E-06 4.75E-06 4.37E-06 7.07E-06 EPA MOVES for year 2030 Source: CDM Smith, 2017 Notes: 1) Emission factors from U.S. EPA Compilation of Air Pollutant Emission Factors (AP-42). Available at https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emission-factors (last accessed January 30, 2018).

https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emission-factors


provided by Arlington County. Assuming that each engine is readiness tested one (1) hour per week for 52 weeks per year, the hourly emission for each engine would be approximately 5.91 lb/hr, based on the actual emissions data. These assumptions imply that the SCR system operates for more the 58 minutes per hour during the 60-minute test. Therefore, a maximum hourly emission rate of 5.91 lb/hr is assumed for both the short-term (1-hour average) and long-term (annual average) NO2 concentration modeling analysis.

The other pollutant emission rates are based on the permit limits for the short-term analyses, and on the actual 12-month emissions for the long-term analysis. Finally, to obtain reasonable estimates of the peak hourly concentrations from these units, all three units were assumed to operate during the same hour (10 am to 11 am local time) every weekday. The long-term (annual) concentration was estimate by assuming all three units operated from 10 am to 11 am on every Wednesday.

Alternative operating scenarios such as emergency operation, Independent System Operator’s (ISO) Demand Response operation or critical power generation have not been included in the model at this time. Currently, the County is not enrolled in any on-call power generation programs.

Appendix B includes a copy of the current facility permit and Appendix C includes a copy of the 2016 emissions inventory report.

2.1.1.2 Storage Tanks The facility has two 12,000-gallon methanol storage tanks, and one 12,000-gallon diesel storage tank. Environmental Protection Agency’s (EPA) Windows-based computer software program TANKS v4.09d was used to estimate VOC emissions from fixed roof storage tanks. TANKS is based on the emission estimation procedures from Chapter 7 of EPA's Compilation Of Air Pollutant Emission Factors (AP-42).2 A fixed roof tank model was used to estimate the emissions for a typical tank configuration and dimensions, with the maximum permitted annual throughput capacity of 1,000,000 gallons. It was assumed that the tank emits at all the time, and therefore, long-term emission rates are same as the short-term emission rates for each of the three tanks.

The methanol tanks were modeled as outdoor vertical tanks, whereas the diesel tank was modeled as outdoor horizontal tank. The tank condition was assumed to be good, and used Washington DC’s meteorological conditions as available in TANKS default database.

Appendix A, Table 3 presents a summary of total VOC emissions from each tank. The TANKS output report for methanol storage tank and diesel storage tank is included in Appendix D. The output report contains information on the tank data inputs and emission information.

2 Available at: https://www3.epa.gov/ttn/chief/ap42/ch07/index.html (last accessed January 30, 2018).

https://www3.epa.gov/ttn/chief/ap42/ch07/index.html


2.1.1.3 Boilers The Facility currently has five existing boilers, but only three were modeled. Out of the five existing boilers, it was assumed that one Operations Control Building (OCB) boiler and one New Maintenance Building (NMB) boiler was for duty and one is for standby. A second OCB boiler and a second NMB boiler were not included in the model at this time.

For the three boilers included in the model, the short-term emission rates were based on a combination of the permitted emission limits where available, and the design heat input rating of the boiler. Whereas the long-term emission rates for existing boilers were based on the emissions reported in the 2016 emissions inventory (See Appendix A, Table 4).

2.1.1.4 Biosolids Trucks for Sludge Hauling Biosolids from the facility are currently hauled off-site for disposal. It is anticipated that the amount of biosolids being disposed would reduce due to implementation of the solids management project. Therefore, as part of this air emission study, emissions from biosolids trucks were also incorporated. The methodology for this assessment is explained in detail, below.

Trip estimates The trip estimates for the baseline condition are 1,600 trucks per year. With the proposed condition for the model year 2030, the trips are estimated to be reduced 570 per year, to 1,030 trucks per year.

Emissions The short-term emissions for the biosolids sludge hauling trucks for both scenarios was determined based on the following assumptions:

The 1,600 truck trips (existing) and 1,030 truck trips (future with project) could occur anytime during the 8-hour workday period on Mondays through Fridays, and during the 4-hour workday period on Saturdays. The available working period is 2,288 hours per year. Since the available hours for delivery exceeds the number of deliveries, it was assumed that one truck trip would occur per hour for the maximum short-term emission rate calculation. The assumptions for short-term truck trip emissions are summarized below:

Maximum of one (1) truck with engine ON during a given hour.

Truck engine is ON for 15 minutes per delivery turnaround, and engine is off during loading.

Truck engine is ON for 15 minutes per hour, max.

Maximum truck speed onsite is 5 miles per hour (mph), used to obtain emission factors in grams per mile (g/mi) from the EPA Motor Vehicle Emissions Simulator (MOVES) model.


The short-term emissions were estimated as follows:

Speed (mi/hr) x Emission Factor (g/mi) = Emission Rate (g/hr)

Emission Rate (g/hr) x 0.25 (engine on hr/trip, = 15 min/trip) = Trip Emissions (g/trip, onsite only)

Trip Emissions (g/trip) x 1 trip/hr / (3600 s/hr) = Model input (g/s)

The long-term emissions for the biosolids hauling trucks for both scenarios was determined based on the following assumptions:

Truck deliveries occur 8 hours per day on Monday to Friday, and four hours per day on Saturday. This equates to 2,288 hours with potential truck delivery hours per year)

Maximum of one (1) truck with engine ON during a given hour.

The long-term emissions were estimated as follows:

Truck trips per year x Trip emissions (g/trip) = Annual Emissions (g/yr)

Annual emissions (g/yr) / 2288 delivery hours per year / (3600 s/hr) = Model input (g/s)

The dispersion model was set-up to only allow emissions to occur during 8 hours per day on Monday through Friday, and during 4 hours per day on Saturday each week.

MOVES Input The most recent version of MOVES 2014a (released on November 17, 2016) was used for this analysis. The MOVES model was run using a national scale domain with default data available in for the year 2016 and a future condition year 2030. A run specification (RunSpec XML model file) was created for Arlington County with “Emission Rates” as calculation type. All months, days, and times were selected for the modeled time span, and hourly time aggregation was used. Three types of sources (vehicles) were modeled: Refuse truck, Single unit long haul truck and Single unit short haul Truck. All vehicles were modeled with diesel fuel to accurately represent the current sludge hauling operations. All five road types were selected in the MOVES Road Type panel.

Both output files were stored in a specified output database after executing the MOVES run. Upon completion of successful execution of MOVES run, the results were post-processed using mySQL script to obtain an average running exhaust emission factor in grams per mile for each pollutant, for each source type traveling at an average speed of 2.5 mph - 7.5 mph.


Emissions from “refuse truck” source type were the most conservative (highest) of the truck types analyzed; therefore, it was used in the air quality model. Table 2-4 below shows the criteria pollutant emissions for the baseline condition and the future proposed condition – a significant decrease from the baseline. The reduction in truck emission rates between existing conditions (2016) and future proposed conditions (2030) is due to both a reduction in truck emission rates that will occur as new trucks meeting the newer emission standards replace existing trucks, and the reduction in truck trips associated with the proposed condition. Appendix A, Table 5 provides the detailed backup calculations.

Table 2-4. Biosolids Sludge Hauling Truck Emissions

Scenario NOx CO SO2 PM10 PM2.5 VOC

Baseline condition (2016)

Short-term emissions (g/s) 1.6 E-03 5.1 E-04 6.4 E-06 9.8 E-05 9.0 E-05 7.8 E-05

Long-term emissions (g/s) 1.1 E-03 3.5 E-04 4.5 E-06 6.8 E-05 6.3 E-05 5.2 E-05

Proposed condition (2030)

Short-term emissions (g/s) 3.9 E-04 1. 2E-04 6.0 E-06 1.1 E-05 9.7 E-06 1.6 E-05

Long-term emissions (g/s) 1.7 E-04 5.4 E-05 2.7 E-06 4.8 E-06 4.4 E-06 7.1 E-06

2.1.2 Proposed Emission Units The scenarios analyzed were summarized in Table 1-1. The following subsections provide the details of the individual proposed units included in the modeling.

2.1.2.1 Combined Heat and Power Engines Generators The Facility is proposing to install two CHP engine generators, firing digester gas. Final equipment manufacturer and model are not known at this time, however, a Jenbacher (JMC 316 GS-B.L) engine generator with an electrical output of 846 kilowatts (kW) (1,175 horsepower), or equivalent, was selected as a representative engine generator. Appendix E presents the CHP engine cut-sheet, and emission limits.

The maximum potential emission rates from a proposed CHP engine are presented in Appendix A, Table 6. The emission factors for NOx, CO, VOC and PM10 were based on the emission limits for GE Jenbacher JMC316 engine. Emission rate for PM2.5 is assumed to be equal to that of PM10. The SO2 emission factor is based on treated digester gas hydrogen sulfide (H2S) concentration of 5 parts per million by volume (ppmv).

The partial operating load scenarios for CHP engines (90%) were simulated based on emission rates appropriate for the 90% of the design CHP engine BHP rating. See Appendix A, Table 7 for CHP engine emission rates for 90% load condition.

Mary Strawn, Arlington County

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Page 17

2.1.2.2 Enclosed Waste Gas Burner

The Facility is also proposing to install an enclosed burner with a heat input rate of 19.8 million

British Thermal Units per hour (MMBtu/hr) to control digester gas when the CHP engines or the

off-site biomethane utilization system are not available or when digester gas is produced at a rate

greater than the energy demand of the CHP engines. The maximum potential emission rates for the

proposed new enclosed waste gas burner is presented in Appendix A, Table 8.

Emission factors for NOx, CO and VOC were obtained from the vendor specifications for the Varec

Biogas Model 244E Enclosed Flare. The PM emission factor was calculated based on EPA’s AP-42

Chapter 2.4, Table 2.4-5 for Municipal Solid Waste Landfills. It has been assumed that PM10 is equal

to PM2.5. The SO2 emission factor is based on a digester gas methane content of 55% and an H2S

concentration of 140 ppm in digester gas. Appendix F presents the Varec Enclosed Flare cut-sheet,

and emission limits.

For the partial operating load scenario for Waste Gas Burner 10% and 15% were simulated using

emission rates appropriate for the 10% and 15% of design heat input capacity of the enclosed

waste gas burner. See Appendix A, Table 9 and 10 respectively for waste gas burner emission rates

at 10% and 15% operating condition.

2.1.2.3 Natural Gas Boilers for Steam

The Facility is also proposing to install two natural gas boilers (duty) and one standby for steam

with 200HP capacity (heat input rate of 6.6 MMBtu/hr) for steam production. The maximum

potential emission rates for the proposed boilers are included in Appendix A, Table 11.

The heat input rating and emissions in lb/MMBtu were obtained from Cleaver-Brooks Model CBLE

Boiler Book updated 5/2017 for 200HP boiler, included in Appendix G. The dispersion model only

included two in-duty boilers. The third stand-by natural gas boiler is not included in the model at

this time.

3.0 Modeling Methodology 3.1 Model Selection and Options

Atmospheric dispersion modeling was conducted for NO2, CO, SO2, PM10, PM2.5 and VOC using the

most recent available version of the U.S. EPA AERMOD modeling system version 16216r. AERMOD

is currently listed as the preferred model for refined dispersion modeling in the U.S. EPA’s

Guideline on Air Quality Models. The graphical user interface, AERMOD View version 9.5.0, created

by Lakes Environmental Software, was used to facilitate model setup and post-processing. A

summary of model inputs is provided in Table 3-1. Details are provided in subsequent sections.


Table 3-1. Model Input

Option Description AERMOD Setting

Non-default options for NO2

Modeling conversion of NOx to NO2

Tier 2 Ambient Ratio Method (ARM2) 1-hr NO2/NOx ratio of 0.5 Annual NO2/NOx ratio of 0.5

Dispersion Coefficient Urban

Terrain Height Options Elevated

Elevation Data NED/SRTM 1/3 Arc Second Data GeoTIFF (USGS National Map Seamless Server)

Receptors Cartesian Multi-tier receptor grid – Two tiers Tier 1 – Every 50 m from center of the grid to 500 m Tier 2 – Every 100 m up to 2500 m

Cartesian Plant Boundary along the fence line Every 25 m along the fence line

Meteorological Data 2012, 2013, 2014, 2015, and 2016

Surface Station Ronald Reagan Washington International Airport (Station No: 13473)

Upper Air Station Sterling, VA (Station No. 93734)

Variable Emission Rate Caterpillar generators – Used hour of day by day of week (All values set to zero except for value of 1 set for 10:00 hour on Wednesday. Existing Boilers – Seasonal emissions. Adjusted peak hourly emissions rates to match total natural gas consumed by season (winter, spring, summer, and fall) and total annual consumption for 2016. biosolids trucks – Used hour of day by day of week.

Key: NED = national elevation dataset; SRTM = shuttle radar topography mission; USGS = U.S. Geological Survey

3.2 NOx to NO2 Conversion The model was set to the regulatory defaults for all pollutants except NO2. The Tier 2 Ambient Ratio Method (ARM2) for conversion of NOx to NO2 was selected in AERMOD. In this option, the minimum ambient NO2/NOx ratio of 0.5 and maximum ambient NO2/NOx ratio of 0.9 was applied to all scenarios.

3.3 Land Use Analysis The population density method (40 CFR 51 Appendix W 7.2.3 (d)) was used to determine the land use of the surrounding areas, which states that if population density is greater than 750 people/km2, the site shall be classified as urban, and that urban dispersion parameters shall be used.


A population of 230,050 for Arlington county was obtained from census database and divided by the total land area of the Arlington county of 67 square kilometer (km2). The population density for Arlington County was determined to be 3,434/km2. Therefore, for the modeling purposes, urban dispersion coefficients are used for all sources.

3.4 Terrain National Elevation Dataset (NED) files were used to determine the terrain elevations in the area surrounding the Facility. 1/3 arc second data was downloaded from the USGS National Map Seamless Server. AERMAP, a preprocessor to the AERMOD modeling system, was used to interpolate the elevations for each source, building and receptor location.

3.5 Receptors A uniform cartesian receptor grid was used every 100m from center of the grid to 3000m. The grid origin, or the center of the grid, was centered on the modeled sources at the Facility.

Fence line grid receptors were placed every 25 meters along the fence line for the Facility. The general public does not have access to the Facility; therefore, results for receptors inside the Facility fence line are not reported.

Discrete receptors were placed at 89 residential home locations nearest the Facility. In addition, one discrete receptor was placed at the Arlington Monitoring Station at 18th Street South, and South Hayes Street.

Figure 3-1 shows the modeled receptors.

3.6 Meteorological Data Two data sets, a surface observation file and an upper air measurement file, are required to create the AERMOD meteorological data set. The most recent five years of consecutive upper air and surface data (2012 through 2016) as provided by the National Climatic Data Center (NCDC) meteorological resource center was used. The following meteorological stations were used:

Surface Air Data: Ronald Reagan Washington International Airport (Station No. 13473)

Upper Air Station: Sterling, VA (Station No. 93734)


Figure 3-1. Location of Grid, Fenceline and Discrete Receptors Modeled


The AERMINUTE utility was used to process the 1-minute Automated Surface Observing System (ASOS) wind data and Integrated Surface Hourly Data (ISHD) from the surface station to generate the hourly averages of wind speed and wind direction. U.S. EPA AERMET version 16216 was used to process the meteorological data before using in the AERMOD model. The resulting 5-year wind rose is presented in Figure 3-2. The prevailing wind direction is from the south, with secondary winds from the northwest and northeast.

Figure 3-2. Wind Rose for Ronald Reagan Washington National Airport, 2012-2016 (Meteorological Station No. 13743) 3.7 Model Output The averaging times and design value output used in the model are described in Table 3-2. AERMOD has post-processors that estimate NAAQS and VAAAQS design values for 1-hr NO2, 1-hr SO2, and 24-hr PM2.5. A pre-1997 PM10 NAAQS option was used for the 24-hr PM10.


Table 3-2. Modeled Value Selection

Pollutant Averaging Period Design Value

Carbon Monoxide (CO) 1-hr Highest second high (1)

8-hr Highest second high (1)

Nitrogen Dioxide (NO2) 1-hr 5-year average of 98th percentile of daily max 1-hour concentration (2)

Annual 5-year maximum (3)

Sulfur Dioxide (SO2) 1-hr 5-year average of 99th percentile of daily max 1-hour concentrations (2)



Annual 5-year maximum (3)

Inhalable Particulate Matter (PM10) 24-hr Highest fourth high over five years (4)

Fine Particulate Matter (PM2.5) 24-hr 5-year average of the 98th percentile of 24-hour concentrations (2)

Annual 5-year maximum (3) Source: 40 CFR 50 Notes: 1) The NAAQS is not to be exceeded more than once a year; therefore, the highest second high value from the modeled data was selected for

the given averaging period. 2) The design value for monitored concentrations is the 3-year average of the 98th (NO2 or PM2.5) or 99th (SO2) percentile (40 CFR 50).

However, USEPA guidance generally required five years of meteorological data to be modeled, when modeling is used to predict future conditions (40 CFR 51, Appendix W). Subsequent guidance clarified that the five-year average of the modeled values would be recognized as equivalent to the three-year average for comparison to the NAAQS (USEPA, Applicability of Appendix W Modeling Guidance for the 1-hour NO2 National Ambient Air Quality Standard, June 28, 2010).

3) The maximum value from the five years of data was selected. 4) Highest sixth high value of 24-hr PM10 concentrations was selected within a single five-year meteorological data file to comply with the

PM10 NAAQS modeling demonstration based on the High (N+1) High value for N years. 3.8 Background Concentrations Three years of background concentrations (2014 through 2016) from the Arlington Monitoring Station (at 18th Street South and South Hayes Street) were used on this Project as background concentrations. The background concentration values and monitoring station locations for each pollutant are presented in Table 3-3. The pollutant model runs were processed with these background concentrations included in the model runs for the all source group. Thus, the single-value background concentrations of each pollutant, except for 1-hour NO2, have been included in the modeled results for comparison to the NAAQS.


For 1-hour NO2 models, background concentrations were developed for each hour of the day. The hourly NO2 concentrations were obtained from the USEPA AIRS Database for the most recent complete 3-year period (2014 through 2016). For each year, the 98th percentile value was determined for each hour of the day. These 98th percentile hour-of-day values were then averaged over the three years, producing the three-year average of 98th percentile hour-of-day background concentrations. The 1-hour NO2 model runs were processed with these background concentrations included in the model runs for the all source group. The hourly background concentration for 1-hour NO2 runs is shown in Table 3-4.

Table 3-3. Background Air Quality Data

Pollutant Averaging Period

Selected Background Concentration for dispersion

modeling (ug/m3) Notes Monitoring Station Address

(2014-2016)

CO 1-hr 4578 Max H2H over 3 years

Washington-Arlington-Alexandria, DC-VA-MD-WV S 18th And Hayes St

8-hr 2289 Max H2H over 3 years

NO2 1-hr* See Table 3-4

Annual 21 Max annual arithmetic mean over 3 years

PM2.5

24-hr 9.2 98th Percentile (3rd High) averaged over 3 years; “First tier”

Annual 20 Average of annual arithmetic means over 3 years

PM10 24-hr 29 Max H2H averaged over 3 years

Washington-Arlington-Alexandria, DC-VA-MD-WV 435 Ferdinand Day Drive, Alexandria, Va

SO2

1-hr 21 99th Percentile (4th High) averaged over 3 years; “first tier”

Washington-Arlington-Alexandria, DC-VA-MD-WV Sta. 46-B9, Lee Park, Telegraph Road

24-hr 13 Max H2H averaged over 2010, 2011 and 2012

Annual 3 Max annual arithmetic mean over 3 years

Source: USEPA Outdoor Air Quality Data – Monitor Values Report. https://www.epa.gov/outdoor-air-quality-data/monitor-values-report. Accessed December 12, 2017.

https://www.epa.gov/outdoor-air-quality-data/monitor-values-report


Table 3-4. Hourly NO2 Background Air Quality Data

Hour Beginning Hour Ending Background Concentration

ppb ug/m3

00:00 01:00 38 71

01:00 02:00 37 69

02:00 03:00 37 70

03:00 04:00 36 68

04:00 05:00 38 72

05:00 06:00 39 73

06:00 07:00 40 76

07:00 08:00 40 76

08:00 09:00 38 72

09:00 10:00 37 69

10:00 11:00 31 59

11:00 12:00 28 52

12:00 13:00 25 48

13:00 14:00 23 44

14:00 15:00 24 45

15:00 16:00 22 42

16:00 17:00 27 51

17:00 18:00 31 59

18:00 19:00 36 68

19:00 20:00 39 73

20:00 21:00 39 74

21:00 22:00 39 73

22:00 23:00 40 74

23:00 24:00 38 72

Source: USEPA. Pre-Generated Data Files (Tables of Hourly Data). https://aqs.epa.gov/aqsweb/airdata/download_files.html#Raw (https://aqs.epa.gov/aqsweb/airdata/hourly_42602_2016.zip; https://aqs.epa.gov/aqsweb/airdata/hourly_42602_2015.zip; https://aqs.epa.gov/aqsweb/airdata/hourly_42602_2014.zip). Accessed December 12, 2017.

Key: ppb = parts per billion; ug/m3 = micrograms per cubic meter

https://aqs.epa.gov/aqsweb/airdata/download_files.html#Raw

https://aqs.epa.gov/aqsweb/airdata/hourly_42602_2016.zip




3.9 AERMOD Source Types Table 3-5 provides a summary of all existing and proposed sources included in the different scenarios. All combustion equipment stacks are included as “point” source type in AERMOD. The storage tanks are represented as “elevated area” source type and the biosolids trucks are represented as “line volume” source type. Figures 3-3 through 3-7 presents a source and building layout for each scenario.

Table 3-5. AERMOD Source Type

Source Type Description Existing/Proposed Scenario ID

Point Caterpillar 3516C Genset A stack Existing Baseline and Scenario 1A, 1B, 1C, 2A, 2B, 3A and 3B

Point Caterpillar 3516C Genset B stack Existing

Point Caterpillar 3516C Genset C stack Existing

Point Dewatering Building Boiler stack Existing

Point OCB Boiler stack Existing

Point NMB Boiler stack Existing

Elevated Area Methanol Storage Tank vent 1 Existing

Elevated Area Methanol Storage Tank vent 2 Existing

Elevated Area Diesel Storage Tank vent Existing

Line Volume Biosolids Trucks for Sludge Hauling Existing/Modified Baseline and Future Scenarios with 2030 emission

rates

Point Proposed Enclosed Waste Gas Flare Proposed Scenario 1B, 1C, 2B, 2C, 3A, 3B

Point Proposed CHP Stack 1 Proposed Scenario 1A, 1B, 1C, 2A, 2B

Point Proposed CHP Stack 2 Proposed

Point Proposed Natural Gas Boiler 1 Proposed Scenario 1A, 1B, 1C, 2A, 2B, 3A and 3B

Point Proposed Natural Gas Boiler 2 Proposed


Figure 3-3. Location of Emissions Sources for Existing Scenario

Figure 3-4. Location of Emissions Sources for Scenarios 1A and 1B


Figure 3-5. Location of Emissions Sources for Scenario 1C, Alternate Waste Gas Burner Location

Figure 3-6. Location of Emissions Sources for Scenarios 2A and 2B, Alternate CHP Building Location


Figure 3-7. Location of Emissions Sources for Scenarios 3A and 3B 3.10 Exhaust Stack Parameters Table 3-6 presents a summary of source parameters used in the model for all sources.

3.11 Building Parameters Stack sources are subject to building downwash. Building Profile Input Program (BPIP-PRIME) was used to calculate each building’s potential zone of influence. The building base elevations were calculated using AERMAP pre-processor using terrain elevation as described earlier in Section 3.1.4. The building heights that were used in the model are presented in Table 3-7. The building parameters shown in the table are not comprehensive for the site. Only multi-story structures were included in the model. Buildings with more than one roof height, such as the Dewatering Building, were modeled as separate structures for each roof height.


Table 3-6. Stack Parameters for Existing Sources

Key: cfm = cubic feet per minute; fps = Feet per second

Notes:

1) The calculated exhaust stack velocity based on available exhaust air flow data from Caterpillar cut sheet. A stack diameter of 18 inches was assumed, based on the WPCP Operator Manual, Volume 14, Section 4, Standby Generation Facility (Exhibit 4.4), dated June 2012. This data is to be confirmed.

Emission Source

Exhaust Stack Parameters

Stack Parameter Basis Height Diameter Temperature Air

Flow Velocity

Feet Inches degrees F cfm fps

Emergency Generator A 30 18 572 19,582 184 Caterpillar cut-sheet1

Emergency Generator B 30 18 572 19,582 184 Caterpillar cut-sheet1

Emergency Generator C 30 18 572 19,582 184 Caterpillar cut-sheet1

Dewatering Building NG water heater/boiler 30 16 200 1100.76 13.13 Estimated

Operations Control Building (OCB) Boiler 30 12 200 1096.15 23.26 Estimated

New Maintenance Building (NMB) Boiler 30 16 200 438.46 5.23 Estimated

Methanol Storage Tank 1 5 5 70 - - Estimated

Methanol Storage Tank 2 5 5 70 - - Estimated

Diesel Storage Tank 5 5 70 - - Estimated

Enclosed Waste Gas Flare 25 36 800 6779.05 15.98 Vendor cut-sheet

CHP Stack 1 25 10 300 3265.80 99.79 Vendor cut-sheet

CHP Stack 2 25 10 300 3265.80 99.79 Vendor cut-sheet

Natural Gas Boiler 1 25 16 300 1600 19.09 Vendor cut-sheet


Table 3-7. Building Parameters

Building ID Building Name Building

Tier Base Elevation

(meter) Building Height

(meter)

NMB_BLDG1 New Maintenance Bldg1 1 13.66 6.1

NMB_BLDG2 NMB Bldg2 1 10.72 15.24

DWB_BLDG1 Dewatering Building 1 1 8.45 26.37

DWB_BLDG2 Dewatering Bldg 2 1 9.09 23.16

DWB_BLDG3 Dewatering Bldg 3 1 11.51 18.75

SPB_1 Solids Processing Bldg1 1 10.65 22.25



EQTANK1 Flow Equalization Tank 1 1 5.2 12.19

EQTANK1 Flow Equalization Tank 1 2 5.2 13



EQTANK3 Flow Equalization Tank3 1 3.64 12.19




DAFBLDG Dissolved Air Floatation Bldg 1 7.86 5.18

OCB_BLDG1 OCB Building 1 1 3.26 9.14

GEN_BLDG Generator Building 1 3.5 7.62



PT_BLDG Preliminary Treatment Building 1 5.17 12.19

PROPAD1_1A Proposed Anaerobic Digester1_1A 1 8.61 18.29

PROPAD2_1A Proposed Anaerobic Digester2_1A 1 7.91 18.29

PROPDSH_1A Proposed Digested Sludge Holding_1A 1 7.31 8.53

PROPDSH2_1A Proposed Digested Sludge Bldg_1A 1 5.84 8.53

PROPSPB_1A Proposed SPB building_1A 1 6.26 9.14


Building ID Building Name Building

Tier Base Elevation

(meter) Building Height

(meter)

PROPDB_1A Proposed Digester Bldg_1A 1 6.53 6.1

PROPSGB_1A Proposed Steam Generator Building_1A 1 11.06 6.1

PROPCHPBLDG_2A Proposed CHP Engine Building_Scenario2A 1 3.37 6.1

PUMPSTATION Pump Station 1 9.79 3.66

BLOWER BLDG Blower Bldg 1 3.7 6.1

OPS CTRL BLDG Operations Control Bldg 1 3.75 3.66

METHANOLFEED Methanol Feed Facility 1 4.69 4.57

POSTAERFCLTY Post Aeration Facility 1 4.75 6.1

SODIUM HYPO Sodium Hypochlorite Facility 1 4.35 7.62

ODORCNTRLNORTH Odor Control North 1 3.81 6.1

PROPCHPBLDG_1A Proposed CHP Building_Scenario1A 1 9.09 6.1


EQTANK2 Flow Equalization Tank 2 2 3.7 13



BLD_34 National Gateway 1 - Existing 1 5.55 42.67

BLD_35 National Gateway 2 - Existing 1 4.67 42.67

BLD_36 National Gateway 3 - Future 1 5.48 42.67

BLD_37 National Gateway 4 - Future 1 5.56 42.67 Notes: 1) The existing scenario includes only existing buildings. Only 2 existing National Gateway buildings are included in the existing model

scenario. The National Gateway buildings are outside the facility and not part of the WPCP. 2) All proposed scenarios include existing buildings except for Solids Processing Building and DAF building, and proposed buildings applicable

for the scenario. The proposed scenario also includes 2 future (plus the 2 existing) National Gateway buildings outside the facility.


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4.0 Results AERMOD predicted the concentration of each pollutant at each ground-level receptor according to

the model input parameters described above. The maximum predicted concentrations were based

on the NAAQS design values as described in Table 3-2. The maximum predicted facility-wide

concentrations were added to background concentrations and then compared with NAAQS. The

results for each pollutant and averaging period are summarized in Figure 4-1 through Figure 4-8,

and are tabulated in Table 4-1.

AERMOD output concentrations are summarized in Appendix H by pollutant and by scenario.

Isopleths generated from AERMOD model output are included in Appendix I. Modeling input and

output files will be provided to Arlington County separately.

The use of five years of hourly meteorological data (over 43,000 hours), and key building

dimensions in the dispersion analysis ensures that the likely worst-case concentrations are being

modeled. Although the most likely wind directions are from the south, northwest, and northeast,

Figure 3-2 indicates that winds blow from all directions, thus the maximum hourly and daily

concentrations in every direction around the facility have been analyzed.

4.1 Observations

Following are the key observations and conclusions:

� No NAAQS exceedances are modeled at the sensitive receptor locations off-site (i.e., the

nearest residential receptors around the site) in the projected scenarios.

� The modeled stack emissions sources under scenarios with a new CHP facility (Scenarios 1A,

1B, 1C, 2A, and 2B) generate criteria air pollutant concentrations higher than the existing

sources at the WPCP boundary and at the discrete receptors

� The model predicts NO2 concentrations above the hourly air quality standard at the WPCP

boundary in scenarios with a CHP facility, without additional emission controls installed.

� The model predicts PM2.5 concentrations above the 24-hour and annual air quality standards

at the WPCP boundary in scenarios with a CHP facility, without additional emission controls

installed.

� The modelled stack emissions sources under the scenario with 100 percent of the biogas

being sent to the waste gas burner (Scenario 3B) shows a higher SO2 concentrations. This is

primarily due to oxidation of the reduced sulfur (as hydrogen sulfide, H2S) in the biogas. The

model output is sensitive to the concentration of H2S in the biogas.

� Application of emissions control technologies would likely reduce emissions from the

proposed CHP facility below any emission or concentration thresholds of concern (see

Section 4.2).


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Figure 4-1. Existing Facility & Background Contributions to Pollutant Concentrations at Pead Fence & Peak Residential Locations

Figure 4-2. Scenario 1A Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations


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Figure 4-3. Scenario 1B Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations

Figure 4-4. Scenario 1C Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations


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Figure 4-5. Scenario 2A Facility & Background Contributions to Pollutant Concentrations at Peak Fence

& Peak Residential Locations

Figure 4-6. Scenario 2B Facility & Background Contributions to Pollutant Concentrations at Peak Fence

& Peak Residential Locations


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Figure 4-7. Scenario 3A Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations

Figure 4-8. Scenario 3B Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations


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Table 4-1. AERMOD Predicted Concentrations and Comparison to NAAQS

Pollutant Averaging

Period Scenario

Modeled Concentration

(ug/m3)

Background (µg/m3)

Total Concentration (ug/m3)

NAAQS

(µg/m3) Max at Fence

Max at Resident

Max at Fence

Max at Resident


1-hr Existing 204 114 4,578 4,782 4,692 40,000

Scenario 1A 836 839 4,578 5,414 5,417 40,000

Scenario 1B 1030 840 4,578 5,608 5,418 40,000

Scenario 1C 836 839 4,578 5,414 5,417 40,000

Scenario 2A 934 581 4,578 5,512 5,159 40,000

Scenario 2B 934 581 4,578 5,512 5,159 40,000

Scenario 3A 458 245 4,578 5,036 4,823 40,000

Scenario 3B 396 245 4,578 4,974 4,823 40,000


8-hr Existing 28 16 2,289 2,317 2,305 10,000

Scenario 1A 720 394 2,289 3,009 2,683 10,000

Scenario 1B 1030 870 2,289 3,319 3,159 10,000

Scenario 1C 720 393 2,289 3,009 2,682 10,000

Scenario 2A 699 338 2,289 2,988 2,627 10,000

Scenario 2B 522 338 2,289 2,811 2,627 10,000

Scenario 3A 309 149 2,289 2,598 2,438 10,000

Scenario 3B 309 148 2,289 2,598 2,437 10,000


1-hr Existing 164 110 59 / 591 164 110 188

Scenario 1A 198 183 74 / 721 198 183 188

Scenario 1B 205 184 74 / 731 205 184 188

Scenario 1C 198 184 73 / 701 198 184 188

Scenario 2A 195 164 71 / 741 195 164 188

Scenario 2B 195 164 71/ 741 195 164 188

Scenario 3A 164 110 59 / 731 164 110 188

Scenario 3B 164 110 59 / 731 164 110 188


Annual

Existing 0.34 0.08 21 21 21 100

Scenario 1A 30 8 21 51 29 100

Scenario 1B 28 7 21 49 28 100

Scenario 1C 27 7 21 48 28 100

Scenario 2A 9 6 21 30 27 100

Scenario 2B 9 5 21 30 26 100

Scenario 3A 2 1 21 23 22 100

Scenario 3B 3 3 21 24 24 100


March 29, 2018

Page 38

Pollutant Averaging

Period Scenario


(ug/m3)

Background (µg/m3)


NAAQS


Max at Resident

Max at Fence

Max at Resident

Sulfur Dioxide (SO2)

1-hr Existing 32 14 21 53 35 196

Scenario 1A 32 14 21 53 35 196

Scenario 1B 55 32 21 76 53 196

Scenario 1C 56 19 21 77 40 196

Scenario 2A 32 14 21 53 35 196

Scenario 2B 55 31 21 76 52 196

Scenario 3A 55 31 21 76 52 196

Scenario 3B 55 31 21 76 52 196


24-hr Existing 2 1 13 15 14 366

Scenario 1A 2 1 13 15 14 366

Scenario 1B 36 12 13 49 25 366

Scenario 1C 28 4 13 41 17 366

Scenario 2A 2 1 13 15 14 366

Scenario 2B 30 11 13 43 24 366

Scenario 3A 30 11 13 43 24 366

Scenario 3B 30 11 13 43 24 366


Annual Existing 0.01 0.01 3 3.01 3.01 78

Scenario 1A 0.27 0.08 3 3.27 3.08 78

Scenario 1B 0.42 0.25 3 3.42 3.25 78

Scenario 1C 0.35 0.10 3 3.35 3.10 78

Scenario 2A 0.10 0.05 3 3.10 3.05 78

Scenario 2B 0.20 0.20 3 3.20 3.20 78

Scenario 3A 0.28 0.28 3 3.28 3.28 78

Scenario 3B 1.76 1.78 3 4.76 4.78 78

Inhalable Particulate Matter

(PM10)

24-hr Existing 2.22 1.46 29 31 30 150

Scenario 1A 31 10 29 60 39 150

Scenario 1B 38 13 29 67 42 150

Scenario 1C 31 10 29 60 39 150

Scenario 2A 32 14 29 61 43 150

Scenario 2B 27 12 29 56 41 150

Scenario 3A 12 5 29 41 34 150

Scenario 3B 12 5 29 41 34 150


March 29, 2018

Page 39

Pollutant Averaging

Period Scenario


(ug/m3)

Background (µg/m3)


NAAQS


Max at Resident

Max at Fence

Max at Resident

Fine Particulate Matter

(PM2.5)

24-hr Existing 1.64 0.89 20 21.6 20.9 35

Scenario 1A 27 7 20 47 27 35

Scenario 1B 30 10 20 50 30 35

Scenario 1C 27 8 20 47 28 35

Scenario 2A 15 8 20 35 28 35

Scenario 2B 15 8 20 35 28 35

Scenario 3A 6 3 20 26 23 35

Scenario 3B 6 3 20 26 23 35

Fine Particulate Matter

(PM2.5)

Annual Existing 0.04 0.01 9 9.2 9.2 12

Scenario 1A 9 2 9 18 11 12

Scenario 1B 8 2 9 17 11 12

Scenario 1C 8 2 9 17 11 12

Scenario 2A 3 2 9 12 11 12

Scenario 2B 2 2 9 12 11 12

Scenario 3A 1 0.3 9 10 10 12

Scenario 3B 1 1 9 10 10 12

Volatile Organic Compounds (VOC)

Annual Existing 6 4

Not measured

6 4 N/A

Scenario 1A 12 4 Not

measured 12 4 N/A

Scenario 1B 11 4 Not

measured 11 4 N/A

Scenario 1C 12 4 Not

measured 12 4 N/A

Scenario 2A 8 5 Not

measured 8 5 N/A

Scenario 2B 8 5 Not

measured 8 5 N/A

Scenario 3A 6 4 Not

measured 6 4 N/A

Scenario 3B 6 4 Not

measured 6 4 N/A

Notes:

1) The background concentration for 1-hour NO2 varies by the hour of the day, as shown in Table 3-4. Therefore, the background concentration for a given scenario and receptor location would depend on the hour that the maximum concentration occurred. The

background value for the peak fence location is given first, followed by the background for the peak residential location.

Key: N/A = Not applicable.


March 29, 2018

Page 40

4.2 Potential Control Equipment and Effect on Air Quality

As noted in Section 1.2, the WPCP Potential to Emit for CO under the CHP option scenarios would be

above the major source threshold if no additional CO controls were applied to the CHP engines. In

addition, concentrations of NO2 and PM2.5 at the Facility fence would potentially exceed the ambient

air quality standards under the CHP option scenarios if no additional NO2 or PM2.5 controls were

applied. Scenarios 4A, 4B, and 4C were developed using the same conditions as Scenarios 1A, 1B,

and 1C respectively with the addition of emissions control equipment. Scenarios 5A and 5B were

developed using the same conditions as Scenarios 2A and 2B with the addition of emissions control

equipment.

A brief review of potential emission control technologies for CHP engines was conducted, and the

following technologies are several that were considered to be currently available for biogas CHP

engines:

� Catalytic Oxidation (CatOx): CatOx units have been applied on engines and combustion

equipment for decades. CatOx units can often achieve 90 percent or more reduction of CO and

VOC. For this study, it was assumed that CO emissions from the CHP engines could be reduced

by 85 percent. The existing standby emergency generators at the facility include CatOx units

in the engine discharge stacks.

� Selective Catalytic Reduction (SCR): SCR units have been used on large engines for control of

NOx emissions. The existing standby emergency generator engines are equipped with SCR

units, so the Facility already has some storage for the SCR ammonia source (usually urea

pellets). Several sources, including the current permit for the existing facility, indicate that

over 90 percent reduction of NOx emissions can be achieved using SCR. For the controlled

analysis conducted here, the control efficiency is assumed to be 70 percent to provide a

conservative result.

� Particulate Filters: Particulate filters have been installed on mobile diesel engines for a

number of years. Applying particulate filter technology to the CHP may achieve an emission

rate of 0.05 grams per horsepower hour, approximately a 67 percent reduction below the

uncontrolled conditions.

Looking at the CO emissions first, reducing the CHP engine CO emissions by 85 percent would result

in a total reduction of over 57 tons per year (from 68 to 11 tons per year). The Facility-wide PTE

would then be 71 tons per year, well below the 100 ton-per-year major source emissions threshold.

The impact of SCR and Particulate Filters on CHP engine emission controls on Facility -wide NO2

and PM2.5 concentrations are presented in Figure 4-9 through Figure 4-13, and controlled

concentration isopleths are presented in Appendix J. The results indicate that with emission

controls, the facility impacts would be less than the ambient air quality standards at the property

line, and concentrations in the community would be better than the standards.


March 29, 2018

Page 41

Figure 4-9. Scenario 4A Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations with Installation of SCR and DPF Control Devices

Figure 4-10. Scenario 4B Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations with Installation of SCR and DPF Control Devices


March 29, 2018

Page 42

Figure 4-11. Scenario 4C Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations with Installation of SCR and DPF Control Devices

Figure 4-12. Scenario 5A Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations with Installation of SCR and DPF Control Devices


March 29, 2018

Page 43

Figure 4-13. Scenario 5B Facility & Background Contributions to Pollutant Concentrations at Peak Fence & Peak Residential Locations with Installation of SCR and DPF Control Devices

Appendix A

Emission Rate Calculation

Page A-1

Anaerobic Digestion Alternatives Air Emissions StudyCity of Arlington, Arlington County Water Pollution Control Plant, VATable A-1A - Long term emission rates

Existing/Proposed EU # Source Type Stack ID Source description Capacity Unit Emission Rate Source Hours of Operation

Existing SourcesExisting A Point GenAstack Caterpillar 3516-C Diesel Engine Generator Set 2500 kWe 2016 Emission Inventory 52Existing B Point GenBstack Caterpillar 3516-C Diesel Engine Generator Set 2500 kWe 2016 Emission Inventory 52Existing C Point GenCstack Caterpillar 3516-C Diesel Engine Generator Set 2500 kWe 2016 Emission Inventory 52Existing Tank 1 Elevated Area source Methanoltankvent1 Fixed roof methanol storage tank 12000 gallons EPA Tanks, based on annual throughput limit 8760Existing Tank 2 Elevated Area source Methanoltankvent2 Fixed roof methanol storage tank 12000 gallons EPA Tanks, based on annual throughput limit 8760Existing Tank 3 Elevated Area source Dieseltankstack1 Fixed roof diesel storage tank 12000 gallons EPA Tanks 8760Existing DWB-BOIL Point DWB-BOILstack1 Kewanee L3w-150G-LE NG water heater for dewatering bldg 5.021 MMBtu/hr 2016 Emission Inventory actual throughput and AP-42 emission factors 8760

Existing NMB-BOIL 1 Point NMB-BOILstack2 Aerco Low NOx Boiler 2 MMBtu/hr2016 Emission Inventory actual throughput and AP-42 emission factors;

20 ppm low NOx boiler 8760Existing NMB-BOIL 2 Point NMB-BOILstack3 Aerco Low NOx Boiler 2 MMBtu/hr

Existing OCB-BOIL 1 Point OCB-BOILstack4 Lochinvar Boiler Model "Knight" KBN-501 NG 5 MMBtu/hr2016 Emission Inventory actual throughput and AP-42 emission factors;

20 ppm low NOx boiler 8760Existing OCB-BOIL 2 Point OCB-BOILstack5 Lochinvar Model "Knight" KBN-501 NG 5 MMBtu/hrExisting Sludge Hauling Line Sludge Hauling Sludge Truck Hauling Emissions - Diesel 1600 trips/year EPA MOVES 15 min engine running timeScenario 1: CHP Engines on North Side of Glebe Road; Scenario 2: CHP Engines on South Side of Glebe RoadScenario 1A, 2A: 0% to waste gas burner, and 100% going to CHP EnginesProposed CHP Engine 1 Point CHPengine1stck Jenbacher or equal JMS-316 846 kW Typical gas quality/Vendor info 8760.00Proposed CHP Engine 2 Point CHPEngine2stck Jenbacher or equal JMS-316 846 kW Typical gas quality/Vendor info 8760.00Proposed Waste Gas Burner Point Flarestack Varec 244E enclosed waste gas burner Vendor Info 0.00Proposed NG Boiler 1 Point NGBoilerStck1 Natural Gas Steam boiler for on-site bio-gas utilization 6.70 MMBtu/hr AP-42/Vendor Info 8760.00Proposed NG Boiler 2 standby Point NGBoilerStck3 Natural Gas Steam boiler for on-site bio-gas utilization 6.70 MMBtu/hr AP-42/Vendor InfoModified Modified Line Sludge Hauling Sludge Truck Hauling Emissions - Diesel 1030 trips/year EPA MOVES 15 min engine running timeScenario 1B and 1Ca and 2B: 10% to waste gas burner and 90% going to CHP engines (Location of waste gas burner is different between 1B and 1C) (Location of CHP engines is different between Scenario 1 and 2)Proposed CHP Engine 1 Point CHPengine1stck Jenbacher or equal JMS-316 789 kW Typical gas quality/Vendor info 8760.00Proposed CHP Engine 2 Point CHPEngine2stck Jenbacher or equal JMS-316 789 kW Typical gas quality/Vendor info 8760.00Proposed Waste Gas Burner Point Flarestack Varec 244E enclosed waste gas burner 1.95 MMBtu/hr Vendor Info 8760.00Proposed NG Boiler 1 Point NGBoilerStck 1 Natural Gas Steam boiler for on-site bio-gas utilization 6.70 MMBtu/hr AP-42/Vendor Info 8760.00Proposed NG Boiler 2 Point NGBoilerStck2 Natural Gas Steam boiler for on-site bio-gas utilization 6.70 MMBtu/hr AP-42/Vendor Info 8760.00Proposed NG Boiler 3 standby Point NGBoilerStck3 Natural Gas Steam boiler for on-site bio-gas utilization 6.70 MMBtu/hr AP-42/Vendor InfoModified Modified Line Sludge Hauling Sludge Truck Hauling Emissions - Diesel 1030 trips/year EPA MOVES 15 min engine running timeScenario 3: Off-site Utilization of Biomethane or CNGScenario 3A; 15% of available bigoas to waste gas burner; 85% biogas to offsite utilizationProposed Waste Gas Burner Point Flarestack Varec 244E enclosed waste gas burner 2.93 MMBtu/hr Vendor Info 8760Proposed NG Boiler 1 Point NGBoilerStck 1 Natural Gas Steam boiler for on-site bio-gas utilization 6.695 MMBtu/hr AP-42/Vendor Info 8760Proposed NG Boiler 2 Point NGBoilerStck2 Natural Gas Steam boiler for on-site bio-gas utilization 6.695 MMBtu/hr AP-42/Vendor Info 8760Proposed NG Boiler 3 standby Point NGBoilerStck3 Natural Gas Steam boiler for on-site bio-gas utilization 6.695 MMBtu/hr AP-42/Vendor InfoProposed Air Stripper Point Air stripper stack Biogas to fuel treatment system Off gasModified Modified Line Sludge Hauling Sludge Truck Hauling Emissions - Diesel 1030 trips/year EPA MOVES 15 min engine running timeScenario 3B; 100% biogas going to waste gas burner; 0% biogas going to off-site utilizationProposed Waste Gas Burner Point Flarestack Varec 244E enclosed waste gas burner 19.50 MMBtu/hr Based on max digester gas flow rate; vendor info 8760Proposed NG Boiler 1 Point NGBoilerStck 1 Natural Gas Steam boiler for on-site bio-gas utilization 6.695 MMBtu/hr AP-42/Vendor Info 8760Proposed NG Boiler 2 Point NGBoilerStck2 Natural Gas Steam boiler for on-site bio-gas utilization 6.695 MMBtu/hr AP-42/Vendor Info 8760Proposed NG Boiler 3 standby Point NGBoilerStck3 Natural Gas Steam boiler for on-site bio-gas utilization 6.695 MMBtu/hr AP-42/Vendor InfoProposed Air Stripper Point Air stripper stack Biogas to fuel treatment system Off gasModified Modified Line Sludge Hauling Sludge Truck Hauling Emissions - Diesel 1030 trips/year EPA MOVES 15 min engine running time

Page A-2


Existing/Proposed EU # Source Type Stack ID

Existing SourcesExisting A Point GenAstackExisting B Point GenBstackExisting C Point GenCstackExisting Tank 1 Elevated Area source Methanoltankvent1Existing Tank 2 Elevated Area source Methanoltankvent2Existing Tank 3 Elevated Area source Dieseltankstack1Existing DWB-BOIL Point DWB-BOILstack1

Existing NMB-BOIL 1 Point NMB-BOILstack2Existing NMB-BOIL 2 Point NMB-BOILstack3

Existing OCB-BOIL 1 Point OCB-BOILstack4Existing OCB-BOIL 2 Point OCB-BOILstack5Existing Sludge Hauling Line Sludge HaulingScenario 1: CHP Engines on North Side of Glebe Road; Scenario 2: CHP Engines on South Side of Glebe RoadScenario 1A, 2A: 0% to waste gas burner, and 100% going to CHP EnginesProposed CHP Engine 1 Point CHPengine1stckProposed CHP Engine 2 Point CHPEngine2stckProposed Waste Gas Burner Point FlarestackProposed NG Boiler 1 Point NGBoilerStck1Proposed NG Boiler 2 standby Point NGBoilerStck3Modified Modified Line Sludge HaulingScenario 1B and 1Ca and 2B: 10% to waste gas burner and 90% going to CHP engines (Location of waste gas burner is different between 1B and 1C) (Location of CHP engines is different between Scenario 1 and 2)Proposed CHP Engine 1 Point CHPengine1stckProposed CHP Engine 2 Point CHPEngine2stckProposed Waste Gas Burner Point FlarestackProposed NG Boiler 1 Point NGBoilerStck 1Proposed NG Boiler 2 Point NGBoilerStck2Proposed NG Boiler 3 standby Point NGBoilerStck3Modified Modified Line Sludge HaulingScenario 3: Off-site Utilization of Biomethane or CNGScenario 3A; 15% of available bigoas to waste gas burner; 85% biogas to offsite utilizationProposed Waste Gas Burner Point FlarestackProposed NG Boiler 1 Point NGBoilerStck 1Proposed NG Boiler 2 Point NGBoilerStck2Proposed NG Boiler 3 standby Point NGBoilerStck3Proposed Air Stripper Point Air stripper stackModified Modified Line Sludge HaulingScenario 3B; 100% biogas going to waste gas burner; 0% biogas going to off-site utilizationProposed Waste Gas Burner Point FlarestackProposed NG Boiler 1 Point NGBoilerStck 1Proposed NG Boiler 2 Point NGBoilerStck2Proposed NG Boiler 3 standby Point NGBoilerStck3Proposed Air Stripper Point Air stripper stackModified Modified Line Sludge Hauling

Annual Annual Annual Annual Annual Annual

NO2 CO SO2 PM10 PM2.5 VOC NO2 CO SO2 PM10 PM2.5 VOC NO2 CO SO2 PM10 PM2.5 VOC Commenttpy tpy tpy tpy tpy tpy lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr g/s g/s g/s g/s g/s g/s

0.154 0.066 0.012 0.016 0.016 0.008 5.914 2.549 0.470 0.616 0.616 0.308 7.45E-01 3.21E-01 5.92E-02 7.76E-02 7.76E-02 3.88E-02 a, b, c0.154 0.074 0.016 0.021 0.021 0.010 5.914 2.862 0.627 0.803 0.803 0.394 7.45E-01 3.61E-01 7.90E-02 1.01E-01 1.01E-01 4.96E-02 a, b, c0.154 0.060 0.016 0.020 0.020 0.010 5.914 2.298 0.612 0.783 0.783 0.392 7.45E-01 2.90E-01 7.71E-02 9.87E-02 9.87E-02 4.93E-02 a, b, c

- - - - - 0.112 - - - - - 0.025 - - - - - 3.21E-03 d - - - - - 0.112 - - - - - 0.025 - - - - - 3.21E-03 d - - - - - 0.017 - - - - - 0.004 - - - - - 4.77E-04 d

6.30E-02 5.29E-02 3.72E-04 4.71E-03 4.71E-03 3.41E-03 e,f

6.12E-03 2.08E-02 1.48E-04 1.88E-03 1.88E-03 1.36E-03 e,fg

1.89E-02 1.51E-02 3.71E-04 4.69E-03 4.69E-03 3.40E-03 e,fg

See MOVES output tab 1.11E-03 3.54E-04 4.45E-06 6.83E-05 6.29E-05 5.42E-05 h

6.81 34.04 0.05 1.70 1.70 2.27 1.55 7.77 0.01 0.39 0.39 0.52 1.96E-01 9.79E-01 1.49E-03 4.89E-02 4.89E-02 6.52E-02 I,j,k6.81 34.04 0.05 1.70 1.70 2.27 1.55 7.77 0.01 0.39 0.39 0.52 1.96E-01 9.79E-01 1.49E-03 4.89E-02 4.89E-02 6.52E-02 I,j,k

Inactive in AERMOD0.32 1.17 0.03 0.29 0.29 0.12 0.07 0.27 0.01 0.07 0.07 0.03 9.27E-03 3.37E-02 8.43E-04 8.43E-03 8.43E-03 3.37E-03 n

nSee MOVES output tab 1.74E-04 5.42E-05 2.69E-06 4.75E-06 4.37E-06 7.07E-06

6.13 30.63 0.05 1.53 1.53 2.04 1.40 6.99 0.01 0.35 0.35 0.47 1.76E-01 8.81E-01 1.34E-03 4.40E-02 4.40E-02 5.87E-02 I,j,k6.13 30.63 0.05 1.53 1.53 2.04 1.40 6.99 0.01 0.35 0.35 0.47 1.76E-01 8.81E-01 1.34E-03 4.40E-02 4.40E-02 5.87E-02 I,j,k0.51 2.56 0.36 0.15 0.15 0.68 0.12 0.59 0.08 0.03 0.03 0.16 1.47E-02 7.37E-02 1.04E-02 4.17E-03 4.17E-03 1.96E-02 I,j,k0.32 1.17 0.03 0.29 0.29 0.12 0.07 0.27 0.01 0.07 0.07 0.03 9.27E-03 3.37E-02 8.43E-04 8.43E-03 8.43E-03 3.37E-03 n0.32 1.17 0.03 0.29 0.29 0.12 0.07 0.27 0.01 0.07 0.07 0.03 9.27E-03 3.37E-02 8.43E-04 8.43E-03 8.43E-03 3.37E-03 n

nSee MOVES output tab 1.74E-04 5.42E-05 2.69E-06 4.75E-06 4.37E-06 7.07E-06 p

0.77 3.84 0.54 0.22 0.22 1.02 0.18 0.88 0.12 0.05 0.05 0.23 2.21E-02 1.11E-01 1.56E-02 6.26E-03 6.26E-03 2.95E-02 l.m0.32 1.17 0.03 0.29 0.29 0.12 0.07 0.27 0.01 0.07 0.07 0.03 9.27E-03 3.37E-02 8.43E-04 8.43E-03 8.43E-03 3.37E-03 n0.32 1.17 0.03 0.29 0.29 0.12 0.07 0.27 0.01 0.07 0.07 0.03 9.27E-03 3.37E-02 8.43E-04 8.43E-03 8.43E-03 3.37E-03 n

nDo not include o

See MOVES output tab 1.74E-04 5.42E-05 2.69E-06 4.75E-06 4.37E-06 7.07E-06 p

5.12 25.62 3.61 1.45 1.45 6.83 1.170 5.850 0.825 0.332 0.332 1.560 1.47E-01 7.37E-01 1.04E-01 4.17E-02 4.17E-02 1.96E-01 l.m0.32 1.17 0.03 0.29 0.29 0.12 0.074 0.268 0.007 0.067 0.067 0.027 9.27E-03 3.37E-02 8.43E-04 8.43E-03 8.43E-03 3.37E-03 n0.32 1.17 0.03 0.29 0.29 0.12 0.074 0.268 0.007 0.067 0.067 0.027 9.27E-03 3.37E-02 8.43E-04 8.43E-03 8.43E-03 3.37E-03 n

nDo not include o

See MOVES output tab 1.74E-04 5.42E-05 2.69E-06 4.75E-06 4.37E-06 7.07E-06 p

Assumed Standby

Assumed Standby

Assumed Standby

s different between Scenario 1 and 2)

Assumed Standby

Assumed Standby

Assumed Standby

Page A-3


* In all scenarios, the waste gas burner will be located on the north side of Glebe Road, near the existing DAF Building and closer to S. Fern St. For Scenario 1C, the waste gas burner will be located on north side of Glebe Road, but closer to South Eads Street.

a) Long-term emission rates for existing caterpillar generators are based on 2016 Emissions Inventory. See Table 2 of this Appendix.b) The lb/hr emission rates emission rates were adjusted to reflect intermittent operation. c) The dispersion model is set up only for the maintenance and readiness testing of the generator operating scenario. No other operating scenarios have been included at this time.d) Based on typical tank configurations and annual throughput permit limit. It is assumed that tank emits all the time. Therefore, long term emission rates are the same as short term emission rates. See Table 3 for TANKS VOC emissionse) The long-term emission rates for existing 5 natural gas boilers were calculated based on actual natural gas usage in 2016 and AP-42 emission factors, except for (f) below. See Table 4 of this Appendix for detailed boiler calculations.f) The NOx and CO emission factors for dewatering building boiler and OCB boiler were obtained from permit limit. The NOx emission factor for NMB-boiler based on 20 ppm Low NOx burner emission limit (obtained from NMB boiler O&M manual)

g) One NMB boiler and One OCB boiler is assumed to be in standby operation.h) Sludge hauling emission rates obtained from the EPA MOVES for the year 2016. Emission rates for average Speed Bin ID (2.5 mph to 7.5 mph) was selected to best represent lower speed of the sludge hauling trucks on site. See Table 5 of this Appendix forMOVES results.i) Proposed CHP engine emission rates based on vendor spec sheet and standard emissions obtained from Jenbacher JMS 316 data sheet. See Table 6 for CHP Engine calculationsj) The emission rates for proposed CHP engines for 100% available biogas scenario was based on maximum design capacity of the engine The long-term emission rates are assumed to be the same as short-term emission rates.See Table 6 for CHP Engine calculationsk) The short term emission rates for proposed CHP engines for 90% available biogas scenario was based on 100% of maximum design capacity of the CHP engine. The long-term lb/hr emission rates are based on the lower design capacity (90% of maximumdesign BHP capacity of the CHP engine). See Table 7 for CHP engine calculations at 90% loadingl) Waste gas burner emission rates based on Vendor spec sheet, emissions data from Varec Enclosed Flare 244E model. Burner's maximum heat input design capacity is based on 500 scfm volumetric capacity (19.5 MMBtu/hr)m) The long term emission rates lb/hr for the 10% and 15% waste biogas to burner scenarios are calcualted with a lower (10% and 15% respectively) heat input rate of waste gas burner. The short-term lb/hr emission rates are based on the maximum (or100%) design capacity. See Table 8, 9 and 10 respectively for emission calculations for 100 %, 10% and 15% waste gas burner loading scenarios.n) The emission rates for the proposed cleaver brooks natural gas boiler were based on Cleaver Brooks CBLE boiler book for 200HP capacity. The long term and short term emission rates are assumed to be the same. See Table 11 for natural gas boileremission calculations.o) Only H2S emissions will be emitted from the off gas released due to bio-gas treatment process to upgrade the fuel to renewable natural gas. H2S and Methane emissions are not calculated for the modeling study. p) Sludge hauling emission rates obtained from the EPA MOVES for the year 2030. Emission rates for average speed Bin ID 2 (2.5 Mph - 7.5 mph)was selected to best represent lower speed of the sludge hauling trucks on site. The long term and short termemission rates are assumed to be the same. See Table 5 for MOVES output and detailed calculations.

Anaerobic Digestion Alternatives Air Emissions Study

City of Arlington, Arlington County Water Pollution Control Plant, VA

Table A-1B - Short term emission rates

1-hr

1-hr and 8-

hr

1-hr, 3-

hr,8-hr

and 24-hr 24-hr 24-hr N/A

Existing/

Proposed EU # Source Type Stack ID Source description Capacity Unit Emission Rate Source Hours of Operation NO2 CO SO2 PM10 PM2.5 VOC NO2 CO SO2 PM10 PM2.5 VOC

lb/hr lb/hr lb/hr lb/hr lb/hr lb/hr g/s g/s g/s g/s g/s g/s

Existing Sources

Existing A Point GenAstack

Caterpillar 3516-C Diesel Engine

Generator Set 2500 kWe Permit limits 52 5.914 6.400 1.300 1.600 1.600 0.800 7.45E-01 8.06E-01 1.64E-01 2.02E-01 2.02E-01 1.01E-01

Existing B Point GenBstack



Existing C Point GenCstack



Existing Tank 1 Point Methanoltankvent1

Fixed roof methanol storage

tank 12000 gallons

EPA Tanks, based on annual

throughput limit 8760 - - - - - 0.0255 - - - - - 3.21E-03

Existing Tank 2 Point Methanoltankvent2

Fixed roof methanol storage

tank 12000 gallons

EPA Tanks, based on annual

throughput limit 8760 - - - - - 0.0255 - - - - - 3.21E-03

Existing Tank 3 Elevated Area source Dieseltankstack1 Fixed roof diesel storage tank 12000 gallons EPA Tanks 8760 - - - - - 0.0038 - - - - - 4.77E-04

Existing DWB-BOIL Point DWB-BOILstack1

Kewanee L3w-150G-LE natural

gas water heater for dewatering

building 5.021 MMBtu/hr

NOx and CO emission limits from

Permit; SOx, PM and VOC from AP-

42 emission factors; based on

maximum rated heat input capacity 8760 0.500 0.420 0.003 0.037 0.037 0.027 6.30E-02 5.29E-02 3.72E-04 4.71E-03 4.71E-03 3.41E-03

Existing NMB-BOIL 1 Point NMB-BOILstack2 Aerco Low NOx Boiler 2 MMBtu/hr

CO, SOx, PM and VOC from AP-42

emission factors; based on maximum

rated heat input capacity; 20 ppm low

NOx burner, emission rate calculated

for NOx 8760 0.049 0.165 0.001 0.015 0.015 0.011 6.12E-03 2.08E-02 1.48E-04 1.88E-03 1.88E-03 1.36E-03

Existing NMB-BOIL 2 Point NMB-BOILstack3 Aerco Low NOx Boiler 2 MMBtu/hr

Existing OCB-BOIL 1 Point OCB-BOILstack4

Lochinvar Corporation

Commercial Heating Boiler

Model "Knight" KBN-501 NG 5 MMBtu/hr

NOx and CO emission limits from

Permit; SOx, PM and VOC from AP-

42 emission factors; based on

maximum rated heat input capacity 8760 0.150 0.120 0.003 0.037 0.037 0.027 1.89E-02 1.51E-02 3.71E-04 4.69E-03 4.69E-03 3.40E-03

Existing OCB-BOIL 2 Point OCB-BOILstack5

Lochinvar Corporation

Commercial Heating Boiler

Model "Knight" KBN-501 NG 5 MMBtu/hr

Existing Sludge Hauling Line Sludge Hauling

Sludge Truck Hauling Emissions

- Diesel 1600 trips/year EPA MOVES

15 min engine

running time See MOVES output tab 1.59E-03 5.06E-04 6.37E-06 9.77E-05 8.99E-05 7.75E-05

Proposed CHP Engine 1 Point CHPengine1stck Jenbacher or equal JMS-316 846 kW Typical gas quality/Vendor info 8760 1.55 7.77 0.01 0.39 0.39 0.52 1.96E-01 9.79E-01 1.49E-03 4.90E-02 4.90E-02 6.53E-02

Proposed CHP Engine 2 Point CHPEngine2stck Jenbacher or equal JMS-316 846 kW Typical gas quality/Vendor info 8760 1.55 7.77 0.01 0.39 0.39 0.52 1.96E-01 9.79E-01 1.49E-03 4.90E-02 4.90E-02 6.53E-02

Proposed

Waste Gas

Burner Point Flarestack

Varec 244E enclosed waste gas

burner 19.5 MMBtu/hr Vendor Info 8760

Proposed NG Boiler 1 Point NGBoilerStck1

Natural Gas Steam boiler for on-

site bio-gas utilization 6.695 MMBtu/hr AP-42/Vendor Info 8760 0.074 0.268 0.007 0.067 0.067 0.027 9.28E-03 3.37E-02 8.44E-04 8.44E-03 8.44E-03 3.37E-03



site bio-gas utilization 6.695 MMBtu/hr AP-42/Vendor Info 8760

Modified Modified Line Sludge Hauling



15 min engine

running time 3.87E-04 1.20E-04 5.98E-06 1.06E-05 9.71E-06 1.57E-05

Proposed CHP Engine 1 Point CHPengine1stck Jenbacher or equal JMS-316 846 kW Typical gas quality/Vendor info - 1.55 7.77 0.01 0.39 0.39 0.52 1.96E-01 9.79E-01 1.49E-03 4.90E-02 4.90E-02 6.53E-02

Proposed CHP Engine 2 Point CHPEngine2stck Jenbacher or equal JMS-316 846 kW Typical gas quality/Vendor info - 1.55 7.77 0.01 0.39 0.39 0.52 1.96E-01 9.79E-01 1.49E-03 4.90E-02 4.90E-02 6.53E-02

Proposed

Waste Gas



burner 19.5 MMBtu/hr Vendor Info - 1.17 5.85 0.83 0.33 0.33 1.56 1.47E-01 7.37E-01 1.04E-01 4.17E-02 4.17E-02 1.96E-01

Proposed NG Boiler 1 Point NGBoilerStck 1









15 min engine


Proposed

Waste Gas



burner 19.5 MMBtu/hr Vendor Info - 1.17 5.85 0.83 0.33 0.33 1.56 1.47E-01 7.37E-01 1.04E-01 4.17E-02 4.17E-02 1.96E-01







Proposed Air Stripper Point Air stripper stack

Biogas to fuel treatment system

Off gas 8760




15 min engine


Proposed

Waste Gas



burner 19.5 MMBtu/hr Vendor Info 8760 1.17 5.85 0.83 0.33 0.33 1.56 1.47E-01 7.37E-01 1.04E-01 4.17E-02 4.17E-02 1.96E-01







Proposed Air Stripper Point Air stripper stack

Biogas to fuel treatment system

Off gas 8760




15 min engine


Assumed Standby

Assumed Standby

Assumed Standby

Assumed Standby

See MOVES output tab

No criteria air pollutant emissions

No criteria air pollutant emissions

Scenario 1B and 1Ca and 2B: 10% to waste gas burner and 90% going to CHP engines (Location of burner is different between 1B and 1C) (Location of CHP engines is different between Scenario 1 and 2)

Scenario 3: Off-site Utilization of Biomethane or CNG

Scenario 3A; 15% of available bigoas to waste gas burner; 85% biogas to offsite utilization

Scenario 3B; 100% biogas going to waste gas burner; 0% biogas going to off-site utilization

Inactive in AERMOD

Scenario 1: CHP Engines on North Side of Glebe Road; Scenario 2: CHP Engines on South Side of Glebe Road

Scenario 1A, 2A: 0% to waste gas burner, and 100% going to CHP Engines

Assumed Standby

Assumed Standby

Page A-1



Table A-1B - Short term emission rates

* In all scenarios, the waste gas burner will be located on the north side of Glebe Road, near the existing DAF Building and closer to S. Fern St. For Scenario 1C, the waste gas burner will be located on north side of Glebe Road, but closer to South Eads Street.

a)Short-term emission rates for all pollutants for existing caterpillar generators was obtained from Air Permit Registration No. 70026 dated October 30 2009 (amended July 2, 2012) for Arlington WPCP.

b) The lb/hr emission rates were adjusted to obtain peak short term averages due to intermittent operation.

c) The dispersion model is set up only for the maintenance and readiness testing of the generator operating scenario. No other operating scenarios have been included at this time.

d) Based on typical tank configurations and annual throughput permit limit. It is assumed that tank emits all the time. Therefore, long term emission rates are the same as short term emission rates. See Table 3 for TANKS emission calculations

e) The short-term emission rates for existing 5 natural gas boilers are calculated based on maximum natural gas usage capacity and AP-42 emission factors, except for (f) below. See Table 4.

f) The NOx and CO emission factors for dewatering building boiler and OCB boiler were obtained from permit limit. The NOx emission factor for NMB-boiler based on 20 ppm Low NOx burner emission limit (obtained from NMB boiler O&M manual)

g) One NMB boiler and One OCB boiler is assumed to be in standby operation.

h) Sludge hauling emission rates obtained from the EPA MOVES for the year 2016. Emission rates for average Speed Bin ID 2 (2.5 mph to 7.5 mph) was selected to best represent lower speed of the sludge hauling trucks on site. See Table 5.

i) Proposed CHP engine emission rates based on vendor spec sheet and standard emissions obtained from Jenbacher JMS 316 data sheet.

j) The emission rates for proposed CHP engines for 100% available biogas scenario was based on maximum daily digester gas production rate. The short-term emission rates are calculated from proposed design capacity. See Table 6

l) Waste gas burner emission rates based on Vendor spec sheet, emissions data from Varec Enclosed Flare 244E model. Burner's maximum heat input design capacity is based on 300 scfm volumetric capacity

n) The emission rates for the proposed cleaver brooks natural gas boiler were based on Cleaver Brooks CBLE boiler book for 200HP capacity. The long term and short term emission rates are assumed to be the same. See Table 11.

o) Only H2S emissions will be emitted from the off gas released due to bio-gas treatment process to upgrade the fuel to renewable natural gas. H2S and Methane emissions are not calculated for the modeling study.

p) Sludge hauling emission rates obtained from the EPA MOVES for the year 2030. Emission rates for average Speed Bin ID 2 (2.5 mph to 7.5 mph) was selected to best represent lower speed of the sludge hauling trucks on site. The long term and short term emission rates are assumed to be the same

k) The emission rates for proposed CHP engines for 90% available biogas scenario was based on 90% of available digester gas going to CHP engines. The BHP of CHP engine was based on heat input rate available from the lower volumetric capacity of digester gas available to CHP engines, and specific fuel consumption factor from Jenbacher JMS316

data sheet. The short-term emission rates are assumed to be the same as proposed 100% design capacity of CHP engines. See Table 7.

m) The emission rates for the 10% and 15% biogas flared scenarios are calcualted with a lower heat input rate of flare. The short-term emission rates are assumed to be the same as 100% proposed design capacity. See Table 8, 9 and 10 respectively for emission calculations for 100%, 10%

and 15% flare loading scenarios.

Page A-2



Table A-2 - Existing Caterpillar Generators A, B, C emissions inventory

Notes:

Generators A, B, C emissions snap shot below obtained from emissions inventory reported in 2016.

Tons/year emissions calculated from the monthly actual emission rates

Assume PM10=PM2.5

Generator A (Tons/month)

NOx CO SO2 VOC PM10

Dec-15 0.014088272 0.002754 0.001671 0.00107 0.002139

Jan-16 0.012097739 0.00193 0.001171 0.00075 0.001499

Feb-16 0.018799001 0.007426 0.001617 0.001035 0.002069

Mar-16 0.012152614 0.005902 0.000761 0.000487 0.000974

Apr-16 0.009673444 0.004982 0.00064 0.000409 0.000819

May-16 0.010579996 0.005274 0.000687 0.00044 0.00088

Jun-16 0.016347132 0.009829 0.001368 0.000875 0.001751

Jul-16 0.010619576 0.005149 0.000948 0.000607 0.001214

Aug-16 0.014735202 0.007335 0.001259 0.000806 0.001611

Sep-16 0.01068068 0.004125 0.000793 0.000508 0.001015

Oct-16 0.011553497 0.005229 0.000798 0.00051 0.001021

Nov-16 0.012426314 0.006332 0.000513 0.000513 0.001027

Total Tons/year 0.15 0.07 0.01 0.01 0.02

Generator B (Tons/month)

NOx CO SO2 VOC PM10

Dec-15 0.013312143 0.00292239 0.001635642 0.001047 0.002094

Jan-16 0.011167448 0.00593526 0.001154017 0.000739 0.001477

Feb-16 0.017488530 0.01015705 0.002116826 0.001355 0.00271

Mar-16 0.012537215 0.00614216 0.001353216 0.000866 0.001732

Apr-16 0.009433245 0.00508676 0.00101198 0.000548 0.001295

May-16 0.010287634 0.00535697 0.001068821 0.000584 0.001368

Jun-16 0.016516200 0.00847835 0.001870099 0.001197 0.002394

Jul-16 0.011606970 0.00569657 0.001128713 0.000722 0.001445

Aug-16 0.013272771 0.0078933 0.001566762 0.001003 0.002005

Sep-16 0.009631194 0.00473403 0.000990212 0.000634 0.001267

Oct-16 0.010783852 0.00558258 0.001134797 0.000726 0.001453

Nov-16 0.011936511 0.00643113 0.001279382 0.000819 0.001638

Total Tons/year 0.15 0.07 0.02 0.01 0.02

Generator C (Tons/month)

NOx CO SO2 VOC PM10

Dec-15 0.014052 0.002708 0.001631 0.001044 0.002088

Jan-16 0.011276 0.001865 0.001124 0.000719 0.001438

Feb-16 0.019579 0.007781 0.002153 0.001378 0.002755

Mar-16 0.012678 0.005866 0.0012 0.000768 0.001536

Apr-16 0.009401 0.004668 0.000932 0.000597 0.001193

May-16 0.010358 0.005021 0.001011 0.000647 0.001294

Jun-16 0.01525 0.008987 0.001837 0.001176 0.002352

Jul-16 0.010209 0.004741 0.001141 0.00073 0.00146

Aug-16 0.015215 0.004959 0.001623 0.001039 0.002077

Sep-16 0.010876 0.00295 0.000996 0.000638 0.001275

Oct-16 0.011535 0.004386 0.001086 0.000695 0.00139

Nov-16 0.012195 0.005821 0.001175 0.000752 0.001504

Total Tons/year 0.15 0.06 0.02 0.01 0.02

Page A-1



Table A-3 - Tanks Output

pda

Type of Tank Location Working Loss Breathing Loss Total (lb/yr) Total(Tons/yr) Emission rate(lb/hr)

Fixed roof methanol storage tank Outdoor 126.28 96.74 223.02 0.112 0.0255

Fixed roof methanol storage tank Outdoor 126.28 96.74 223.02 0.112 0.0255

Fixed roof diesel storage tank Outdoor 27.40 5.78 33.18 0.017 0.0038

Notes:

1) A typical tanks configuration were used to obtain storage tanks dimensions

2) The long term and short term emission rates are the same, assuming tanks emits all the time

Page A-1



Table A-4 Existing Boiler PTE

Existing Boilers (potential to emit emission rates)

Boiler ID Description

Max Heat input

capacity

(MMBtu/hr)

Max Allowable

Throughput

(MMScf/yr)(1)

NG input

(MMscf/hr)

Exhaust Gas

flow (ROM)

(MMscf/hr) NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 PM10 PM2.5 VOC

DWB-BOIL Kewanee L3w-150G-LE NG Water Heater 5.021 29.15 0.00492 0.0492 1.4802 1.2434 0.0087 0.1108 0.1108 0.0802 0.500 0.420 0.0030 0.0374 0.0374 0.0271

NMB-BOIL 1 Aerco Low NOx boiler 2 11.61 0.00196 0.0196 0.1438 0.4876 0.0035 0.0441 0.0441 0.0319 0.049 0.165 0.0012 0.0149 0.0149 0.0108

NMB-BOIL 2 Aerco Low NOx boiler - standby

OCB-BOIL 1 Lochinvar Model "Knight" KBN-501 NG boiler 5 29.02 0.00490 0.0490 0.4441 0.3553 0.0087 0.1103 0.1103 0.0798 0.150 0.120 0.0029 0.0373 0.0373 0.0270

OCB-BOIL 2 Lochinvar Model "Knight" KBN-501 NG boiler - standby

Total 12.021 69.78 0.0118 2.068 2.086 0.021 0.265 0.265 0.192

1. Permitted natural gas thoughput to DWB, NMB1, NMB2, OCB1, and OCB2 combined is limited to 69.78 cubic ft per year.

Air Permit Emission Limits NOx (lb/hr) CO (lb/hr)

DWB-BOIL 0.5 0.420

OCB-BOIL1 0.15 0.120

OCB-BOIL2 0.15 0.120

Max unconstrained natural gas usage - based on burner capacity 103.24 MMscf/yr

Max permitted natural gas usage (total for all five boilers) 69.78 MMscf/yr

2016 total natural gas usage in existing boilers (MMcf/yr) 7.01 MMscf/yr

% Capacity used from total allowable 6.79

Heat content of natural gas 1020.0 MMBtu/MMscf

Annual throughput by season MMcf/season

Total Seasonal

Hours

Dec-Feb 65% 67.11 2184 260.71%

Mar-May 31% 32.00 2208 122.99%

Jun-Aug 1% 1.03 2208 3.97%

Sep-Nov 3% 3.10 2184 12.03%

Total 100% 103.24 8784.00

AP-42 Emission Factors

Pollutant lb/MMScf lb/MMBtu lb/MMScf

NOx (20 ppm for NMB units) - 0.0243 24.7685

CO 84 0.0824

SO2 0.6 0.0006

PM -10 7.6 0.0075

PM 2.5 7.6 0.0075

VOC 5.5 0.0054

NMB Boiler

NOx Emissions

lb/MMBtu = ppm x 1/molar volume x MW x Fd x 20.9/(20.9 - %O2)

3 Excess O2, %

Molecular weight of NO2 (MW) = 46.00 lb/lb-mol

molar volume = 385.3 dscf/lbmol @ 14.696 psia, 68 deg. F

ppm = 20 ppm @3%O2 limit

Fd = 8710 dscf/MMBtu for natural gas (note that this is dscf of Exhaust Gas per MMBTU of natural gas input to the burner)

8.9 dscf/scf fuel for natural gas

NOx lb/MMBtu= 0.0243 lb/MMBtu

NOx lb/MMScf 24.77 lb/MMscf

8760.0

Existing Boiler PTE for Permitted NG Throughput

tpy

Unconstrained Operating

Hours (calculated) for all

boilers

5694.0

2715.6

87.6

262.8

lb/hr

Page A-1



Table A-4 Existing Boiler PTE

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 PM10 PM2.5 VOC

0.063 0.053 0.00037 0.0047 0.0047 0.0034 0.043 0.036 0.00025 0.0032 0.0032 0.0023

0.006 0.021 0.00015 0.0019 0.0019 0.0014 0.004 0.014 0.00010 0.0013 0.0013 0.0009

0.019 0.015 0.00037 0.0047 0.0047 0.0034 0.013 0.010 0.00025 0.0032 0.0032 0.0023

Use variable emissions by season in AERMOD to correct to season emission rates.

g/s (Short term) g/s (Long term)

Page A-2



Table A-5 - Biosolids Sludge Truck Hauling Emission Calculations

Existing Scenario (For model year 2016) Emission Factor (g/mi), for 5 mph speed

Source Type ID Source Type NOx CO SO2 PM10 PM2.5 VOC

51 Refuse Truck 4.566724386 1.457211646 0.01833162 0.28137617 0.25886529 0.22328496

52 Single Unit short haul truck 3.448804671 1.386445507 0.01663849 0.24162187 0.22229148 0.28292427

53 Single unit long haul truck 3.047487052 1.216391634 0.01634468 0.20270829 0.18649113 0.25227398

Future Scenarios (For model year 2030) Emission Factor (g/mi)

Source Type ID Source Type NOx CO SO2 PM10 PM2.5 VOC

51 Refuse Truck 1.114543354 0.346641767 0.01722624 0.03039359 0.02796202 0.04525805

52 Single Unit short haul truck 0.797201284 0.358844584 0.01537062 0.02135462 0.01964618 0.04664074

53 Single unit long haul truck 0.810479411 0.354950064 0.01521643 0.02163912 0.01990792 0.04686466

Modeled Annual Vehicle Miles Traveled Estimates

2016 2030

Trucks per year 1,600 1,030

Average Running Time (min) 15 15

Page A-1



Table A-5 - Biosolids Sludge Truck Hauling Emission CalculationsShort-term: Short-term Model inputs:

Trip Emissions, g/truck trip Emissions g/sec


5.71 1.82 0.02 0.35 0.32 0.28 1.59E-03 5.06E-04 6.37E-06 9.77E-05 8.99E-05 7.75E-05

4.31 1.73 0.02 0.30 0.28 0.35 1.20E-03 4.81E-04 5.78E-06 8.39E-05 7.72E-05 9.82E-05

3.81 1.52 0.02 0.25 0.23 0.32 1.06E-03 4.22E-04 5.68E-06 7.04E-05 6.48E-05 8.76E-05

Short-term Model inputs:

Trip Emissions, g/truck trip Emissions g/sec


1.39 0.43 0.02 0.04 0.03 0.06 3.87E-04 1.20E-04 5.98E-06 1.06E-05 9.71E-06 1.57E-05

1.00 0.45 0.02 0.03 0.02 0.06 2.77E-04 1.25E-04 5.34E-06 7.41E-06 6.82E-06 1.62E-05

1.01 0.44 0.02 0.03 0.02 0.06 2.81E-04 1.23E-04 5.28E-06 7.51E-06 6.91E-06 1.63E-05

Assumptions for short-term truck emissions:

- Maximum of one (1) truck with engine on during a given hour.

- Truck engine is on for 15 minutes per delivery turnaround, engine is off during loading.

- Truck engine is on for 15 minutes per hour, max.

- Maximum truck speed onsite is 5 mph, used to obtain emission factors (in g/mi) from MOVES2014a.

- Speed (mi/hr) x Emission Factor (g/mi) = Emission Rate (g/hr).

- Emission Rate (g/hr) x 0.25 (engine on hr/trip = 15 min/trip) = Trip Emissions (g/trip, onsite only)

- Trip Emissions (g/trip) x 1 trip/hr / (3600 s/hr) = Model input (g/s)

Page A-2



Table A-5 - Biosolids Sludge Truck Hauling Emission Calculations Use Hour_of_Day by Day_of_Week in AERMOD

Long term Long-term Model inputs:

Emissions g/yr g/s


9,133.45 2,914.42 36.66 562.75 517.73 446.57 1.11E-03 3.54E-04 4.45E-06 6.83E-05 6.29E-05 5.42E-05

6,897.61 2,772.89 33.28 483.24 444.58 565.85 8.37E-04 3.37E-04 4.04E-06 5.87E-05 5.40E-05 6.87E-05

6,094.97 2,432.78 32.69 405.42 372.98 504.55 7.40E-04 2.95E-04 3.97E-06 4.92E-05 4.53E-05 6.13E-05

Long term Long-term Model inputs:

Emissions g/yr g/s


1,434.97 446.30 22.18 39.13 36.00 58.27 1.74E-04 5.42E-05 2.69E-06 4.75E-06 4.37E-06 7.07E-06

1,026.40 462.01 19.79 27.49 25.29 60.05 1.25E-04 5.61E-05 2.40E-06 3.34E-06 3.07E-06 7.29E-06

1,043.49 457.00 19.59 27.86 25.63 60.34 1.27E-04 5.55E-05 2.38E-06 3.38E-06 3.11E-06 7.33E-06

Assumptions for long-term truck emissions:

- Truck deliveries occur 8 hours/day on Mon-Fri; and 4 hours/day on Sat.

= 260 full days & 26 half days = 2288 hours with potential truck deliveries

- Maximum of one (1) truck with engine on during a given hour.

- Truck trips per year (e.g., 1600 in 2016) x Trip emissions (g/trip) = Annual Emissions (g/yr)

- Annual emissions (gr/yr) / (2288 delivery hrs/yr) / (3600 s/hr) = Model input (g/s)

Page A-3



Table A-6 - CHP Engine Generator 100% loading

USE THIS TAB FOR CHP SHORT TERM EMISSION RATES IN SCENARIOS 1A, 2A, 1B, 1C, 2B

USE THIS TAB FOR CHP LONG TERM EMISSION RATES FOR SCENARIO 1A, 2A FOR 100% GAS GOING TO CHP

Fuel

Heat Input Vendor Vendor Usage

Rate a

Estimate b

Estimate b

per Engine One Engine One Engine

Pollutant (bhp) (kW) MMBtu/hr (lb/MMBtu) (g/bhp-hr) lb/MMBtu (g/hr) g/s (lb/hr) (hours/year) (g/s) (tpy)

NOx 1175 846 7.84 --- 0.6 --- 705 0.1958 1.554 8760 0.1958 6.81

CO 1175 846 7.84 --- 3.0 --- 3525 0.9792 7.771 8760 0.9792 34.04

SO2 1175 846 7.84 --- 0.0015 5.37 0.00149 0.012 8760 0.0015 0.052

PM 10 1175 846 7.84 --- 0.15 --- 176 0.0490 0.389 8760 0.0490 1.7019

PM 2.5 1175 846 7.84 --- 0.15 --- 176 0.0490 0.389 8760 0.0490 1.7019

VOC 1175 846 7.84 --- 0.2 --- 235 0.0653 0.518 8760 0.0653 2.27

1 kw 1.341022089 bhp

Notes:a

Rated engine power output and fuel heat input rate obtained from Jenbacher JMS 316 or equalb

NOx, CO, VOC and PM10 Emission Factors obtained from JMS 316 or equal standard emissions. PM10 assumed to be equal to PM2.5c

SO2 calculated based on 5 ppm in the treated digester gas.

SO2 emission rate calculations

lb/scf = ppm x MW/(385.4 x 10^6) (Simplification of Ideal Gas Law for Standard Conditions)

lb/MMBtu = lb/scf x scf/Btu x (1 x 10^6 Btu)/MMBtu

MW H2S = 34.08

MW SO2 = 64.07

Heating Value Bio-gas = 550 Btu/scf

lb SO2 / MMBtu = lb H2S/MMBtu x (MW SO2 / MW H2S) for assumed 100% conversion

Standard temperature 20 C

293.15 K

Treated H2S Concentration in Gasc

5 ppm

SO2 Emission Factor 0.0015 lb/MMBtu

H2S Emission Factor 0.0008 lb/MMBtu

Long-term emission rates

Emission RatesRated Engine

Power Output a

Emission Factors and Limits Short-Term

Based on H2S

conc c

Page A-1



Table A-7 - CHP Engine Generator 90% Loading

USE THIS TAB FOR CHP LONG TERM EMISSION RATES FOR SCENARIO 1B, 1C, 2B FOR 90% GAS GOING TO CHP

Fuel

Heat Input Vendor Vendor Usage

Rate a

Estimate b

Estimate b

per Engine One Engine One Engine

Pollutant (bhp) (kW) MMBtu/hr (lb/MMBtu) (g/bhp-hr) lb/MMBtu (g/hr) (g/s) (lb/hr) (hours/year) (tons/year) (grams/sec)

NOx 1058 789 7.06 --- 0.6 --- 635 0.1763 1.40 8760 6.127 0.1763

CO 1058 789 7.06 --- 3.0 --- 3173 0.8813 6.99 8760 30.634 0.8813

SO2 1058 789 7.06 --- 0.0015 4.84 0.00134 0.0107 8760 0.047 0.00134

PM 10 1058 789 7.06 --- 0.15 --- 159 0.0441 0.35 8760 1.532 0.0441

PM 2.5 1058 789 7.06 --- 0.15 --- 159 0.0441 0.35 8760 1.532 0.0441

VOC 1058 789 7.06 --- 0.2 --- 212 0.0588 0.47 8760 2.042 0.0588

1 kw 1.341022089 bhp

Notes:a

Rated engine power output and fuel heat input rate calculated from available digester gas and specific fuel consumption obtained from Jenbacher JMS 316 or equalb

NOx, CO, VOC and PM10 Emission Factors obtained from JMS 316 or equal. PM10 assumed to be equal to PM2.5c

SO2 calculated based on 5 ppm in the treated digester gas.

Specific fuel consumption of engine 6672 btu/hp-hr (JMS Jenbacher spec sheet 316)

SO2 emission rate calculations

lb/scf = ppm x MW/(385.4 x 10^6) (Simplification of Ideal Gas Law for Standard Conditions)

lb/MMBtu = lb/scf x scf/Btu x (1 x 10^6 Btu)/MMBtu

MW H2S = 34.08

MW SO2 = 64.07

Heating Value Bio-gas = 550 Btu/scf

lb SO2 / MMBtu = lb H2S/MMBtu x (MW SO2 / MW H2S) for assumed 100% conversion

Standard temperature 20 C

293.15 K

Treated H2S Concentration in Gasc

5 ppm



Short-term Emission Factors and Limits Short-Term Long-term emission rates (100%)

Rated Engine Based on H2S

conc c

Emission Rates

Power Output a

Page A-1



Table A-8 - Flare Emission Rates Calculations at 100% loading

Waste Gas Burner Emissions

For lb/hr emission calculations based on gas burner design capacity

Volumetric Flow based on Burner Design 500 cfm 30000 scfh

Heat Rate 19.50 MMBtu/hr (Varec 244E enclosed waste gas burner design spec sheet)

Methane heat of combustion 1000 Btu/scf methane

Methane content of digester gas 55%

For lb/hr and Tons/year Calculations

H2S Concentration in Gas 140 ppm Provided by CDM Smith design team

Maximum Waste Gas Burner Operation 8,760 hr/year

PM Emission Factor 0.017 lb/MMBtu (AP-42 Chapter 2.4, Table 2.4-5)

NOx Emission Factor 0.060 lb/MMBtu Varec Enclosed Flare 224E emission limits spreadsheet

CO Emission Factor 0.300 lb/MMBtu Varec Enclosed Flare 224E emission limits spreadsheet


VOC Emission Factor 0.080 lb/MMBtu Varec Enclosed Flare 224E emission limits spreadsheet

Assume 100% conversion of H2S to SO2 for the SO2 emission rate

MW H2S = 34.08

MW SO2 = 64.07

Nitrogen Oxide Emissions

Calculated NO2 emission rate during waste gas burner operation (based on burner design):

0.060 lb 19.5 MMBtu 1.17 lb

1 MMBtu 1 hr hr

Calculated NO2 annual emission rate

lb 8,760 hour 1 ton = 5.12 ton

hr 1 year 2000 lb year

Carbon Monoxide Emissions

Calculated CO emission rate during waste gas burner operation (based on burner design):

0.300 lb 19.5 MMBtu 5.85 lb

1 MMBtu 1 hr hr

Calculated CO annual emission rate

lb 8,760 hour 1 ton = 25.62 ton


Sulfur Dioxide Emissions

Calculated maximum SO2 emission rate assuming 100 percent of sulfur is emitted as SO2 (based on burner design):

0.042 lb 19.5 MMBtu 100% conversion 0.83 lb

1 MMBtu 1 hr hr

Calculated SO2 annual emission rate assuming 100 percent of sulfur is emitted as SO2

lb 8,760 hour 1 ton 3.61 ton


PM Emissions

Calculated PM emission rate during waste gas burner operation (based on burner design):

0.017 lb 19.5 MMBtu 0.33 lb

1 MMBtu 1 hr hr

Calculated PM annual emission rate



Volatile Organic Compounds Emissions

Calculated maximum VOC emission rate (based on burner design):

0.080 lb 19.5 MMBtu 1.56 lb

1 MMBtu 1 hr hr

Calculated VOC annual emission rate



)*

)*

* )*

*

* =

USE THIS TAB FOR WASTE GAS BURNER SHORT TERM EMISSION RATES FOR SCENARIO 1B, 1C, 2B, 3A, 3B

* =

(

=

0.8 * * =

)*

=

*

=

(

USE THIS TAB FOR WASTE GAS BURNER LONG TERM EMISSION RATES FOR SCENARIO 3B

*

*

1.2

1.6

*

5.9 *

( 0.3 *

Page A-1




USE THIS TAB FOR WASTE GAS BURNER LONG TERM EMISSION RATES FOR SCENARIO 1B, 2B

Waste Gas Burner Emissions

For lb/hr emission calculations based on gas burner design capacity

Volumetric Flow based on Waste Gas Burner Design 500 cfm 30000 scfh

Design Gas Burner Heat input rate 19.5 MMBtu/hr (Varec 244E enclosed flare design spec sheet)

Burner Heat Rate 1.95 MMBtu/hr (at 10% design capacity)



H2S Concentration in Gas 140 ppm Provided by CDM Smith design team Provided by CDM Smith design team

Maximum Burner Operation 8,760 hr/year

PM Emission Factor 0.017 lb/MMBtu (AP-42 Chapter 2.4, Table 2.4-5) (AP-42 Chapter 2.4, Table 2.4-5)

NOx Emission Factor 0.060 lb/MMBtu Varec Enclosed Flare 224E emission limits spreadsheetVarec Enclosed Flare 224E emission limits spreadsheet

CO Emission Factor 0.300 lb/MMBtu Varec Enclosed Flare 224E emission limits spreadsheetVarec Enclosed Flare 224E emission limits spreadsheet


VOC Emission Factor 0.080 lb/MMBtu Varec Enclosed Flare 224E emission limits spreadsheetVarec Enclosed Flare 224E emission limits spreadsheet


MW H2S = 34.08

MW SO2 = 64.07

PM Emissions

Calculated PM emission rate during waste gas burner operation (based on 10% burner design):

0.017 lb 2.0 MMBtu 0.03 lb

1 MMBtu 1 hr hr

Calculated PM annual emission rate




Calculated NO2 emission rate during waste gas burner operation (based on 10% burner design):

0.060 lb 2.0 MMBtu 0.12 lb

1 MMBtu 1 hr hr

Calculated NO2 annual emission rate




Calculated CO emission rate during gas burner operation:

0.300 lb 2.0 MMBtu 0.59 lb

1 MMBtu 1 hr hr

Calculated CO annual emission rate:




Calculated maximum VOC emission rate (based on 10% burner design):

0.080 lb 2.0 MMBtu 0.16 lb

1 MMBtu 1 hr hr





Calculated maximum SO2 emission rate assuming 100 percent of sulfur is emitted as SO2 (based on 10% burner design):


1 MMBtu 1 hr hr

Calculated SO2 annual emission rate assuming 100 percent of sulfur is emitted as SO2:


hr 1 year 2000 lb year0.1 * * =

=

( 0.6 * )*

* =

0.2 * )*

* *

( 0.1 * )*

* =

* =

( 0.0 * )*

* =

Page A-1




Waste Gas Flare Emissions

For lb/hr emission calculations based on flare design capacity

Volumetric Flow based on Waste Gas Burner Design 500 cfm 30000 scfh

Design Gas Burner Heat input rate 19.50 MMBtu/hr (Varec 244E enclosed flare design spec sheet)

Burner Heat Rate 2.93 MMBtu/hr (at 15% design capacity)



For lb/hr and Tons/year Calculations

H2S Concentration in Gas 140 ppm Provided by CDM Smith design team

Maximum Burner Operation 8,760 hr/year

PM Emission Factor 0.017 lb/MMBtu (AP-42 Chapter 2.4, Table 2.4-5)

NOx Emission Factor 0.060 lb/MMBtu Varec Enclosed Flare 224E emission limits spreadsheet

CO Emission Factor 0.300 lb/MMBtu Varec Enclosed Flare 224E emission limits spreadsheet



VOC Emission Factor 0.080 lb/MMBtu Varec Enclosed Flare 224E emission limits spreadsheet


MW H2S = 34.08

MW SO2 = 64.07

PM Emissions

Calculated PM emission rate during waste gas burner operation (based on 15% burner design):

0.017 lb 2.9 MMBtu 0.05 lb

1 MMBtu 1 hr hr

Calculated PM annual emission rate:




Calculated NO2 emission rate during waste gas burner operation (based on 15% burner design):

0.060 lb 2.9 MMBtu 0.18 lb

1 MMBtu 1 hr hr

Calculated NO2 annual emission rate:




Calculated CO emission rate during gas burner operation (based on 15% burner design):

0.300 lb 2.9 MMBtu 0.88 lb

1 MMBtu 1 hr hr

Calculated CO annual emission rate:




Calculated maximum VOC emission rate (based on 15% burner design):

0.080 lb 2.9 MMBtu 0.23 lb

1 MMBtu 1 hr hr





Calculated maximum SO2 emission rate assuming 100 percent of sulfur is emitted as SO2 (based on 15% burner design):


1 MMBtu 1 hr hr

Calculated SO2 annual emission rate assuming 100 percent of sulfur is emitted as SO2:


hr 1 year 2000 lb year0.1 * * =

=

( 0.9 * )*

* =

0.2 * )*

* *

( 0.18 * )*

USE THIS TAB FOR WASTE GAS BURNER LONG TERM EMISSION RATES FOR SCENARIO 3A

* =

* =

( 0.05 * )*

* =

Page A-1



Table A-11 - Proposed NG Boilers Emission Rates Calculations

Source

Design Heat

Input Rating

(MMBTU/hr)1

Operating

Hrs.

NOx1

CO1

SO21

PM101

PM2.51

VOC1

NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 PM10 PM2.5 VOC NOx CO SO2 PM10 PM2.5 VOC

Proposed NG Boiler 1 6.695 8760 0.011 0.04 1.00E-03 0.01 0.01 0.004 0.074 0.268 0.007 0.067 0.067 0.027 0.32 1.17 0.03 0.29 0.29 0.12 0.0093 0.0337 0.0008 0.0084 0.0084 0.0034

Proposed NG Boiler 2 standby 6.695 8760 0.011 0.04 1.00E-03 0.01 0.01 0.004 0.074 0.268 0.007 0.067 0.067 0.027 0.32 1.17 0.03 0.29 0.29 0.12 0.0093 0.0337 0.0008 0.0084 0.0084 0.0034

Notes:

1Cleaver-Brooks Model CBLE Boiler Boiler Book updated 5/2017 for 200HP boiler

2Emissions obtained from estimated emission levels avialable in Table 12 from CBLE boiler book (5/17) natural gas boilers for 9 ppm NOx emissions

Maximum Annual Emission (tons/year) Maximum Emission Rates (g/s)Emission Factors (lb/MMBtu) Maximum Hourly Emissions (lb/hr)

Page A-1



Potential To Emit

Table A-12 Total Estimated Emission Rates

Total Maximum Potential to Emit (tons/year) Scenarios1/2 Scenario 3

Pollutant CHP Engines

Waste Gas

Burner

One natural

gas boilers

Total Scenario 1/2

Emissions

Total Scenario 3

Emissions Gen A, B, C Boilers

Methanol

Storage

Tanks

Existing

Facility

Emissions

NOx 13.62 5.12 0.32 19.1 5.4 23.1 2.1 - 25.2 44.2 30.6 100

CO 68.1 25.62 1.17 94.9 26.8 31.2 2.1 - 33.3 128.2 58.9 100

SO2 0.104 3.6 0.0 3.7 3.6 6.1 0.02 - 6.1 9.9 9.7 100

PM 10 3.404 1.45 0.29 5.1 1.7 7.7 0.3 - 8.0 13.1 9.4 100

PM 2.5 3.40 1.45 0.29 5.1 1.7 7.7 0.3 - 8.0 13.1 9.4 100

VOC 4.54 6.83 0.12 11.5 7.0 3.9 0.2 0.2 4.3 15.8 11.2 100

Notes:1

Facility Air Permit Registration No. 70026 amended July 2, 2012 (issued October 30, 2009) 2

Arlington County Attainment Status, Marginal for 8-Hr Ozone (2008), as of 12/7/17: https://www3.epa.gov/airquality/greenbook/hbca.html#Ozone_8-hr.2008.Washington3

Major Source thresholds: https://www.epa.gov/title-v-operating-permits/who-has-obtain-title-v-permit4

9VAC5-80-60 Definitions - "Major Source" ('c)

http://www.deq.virginia.gov/Portals/0/DEQ/Air/Regulations/801.pdf

Total Facility After

Biomethane

Utilization Project

Addition

Existing UnitsProposed New Units Total Facility

After CHP

Project

Addition

Major Source

Thresholds

(tons/year) 2,3,4

Page A-1

Appendix B

Facility Air Permit

Appendix C

2016 Emissions Inventory

Appendix D

EPA TANKS Output for Storage Tanks

TANKS 4.0.9dEmissions Report - Summary Format

Tank Indentification and Physical Characteristics

IdentificationUser Identification: Arlington Methanol_VFRTCity: alexandriaState: VirginiaCompany: Arlington WPCPType of Tank: Vertical Fixed Roof TankDescription: Arlington VA

Tank DimensionsShell Height (ft): 19.00Diameter (ft): 10.50Liquid Height (ft) : 17.00Avg. Liquid Height (ft): 16.00Volume (gallons): 12,000.00Turnovers: 8.58Net Throughput(gal/yr): 100,000.00Is Tank Heated (y/n): N

Paint CharacteristicsShell Color/Shade: Gray/LightShell Condition GoodRoof Color/Shade: Gray/LightRoof Condition: Good

Roof CharacteristicsType: DomeHeight (ft) 0.00Radius (ft) (Dome Roof) 10.50

Breather Vent SettingsVacuum Settings (psig): -0.03Pressure Settings (psig) 0.03

Meterological Data used in Emissions Calculations: Washington National AP, District of Columbia (Avg Atmospheric Pressure = 14.67 psia)

Page 1 of 5TANKS 4.0 Report

1/30/2018file:///C:/Program%20Files%20(x86)/Tanks409d/summarydisplay.htm


Liquid Contents of Storage Tank

Arlington Methanol_VFRT - Vertical Fixed Roof Tankalexandria, Virginia

Daily Liquid Surf.Temperature (deg F)

LiquidBulk

Temp Vapor Pressure (psia)Vapor

Mol.LiquidMass

VaporMass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Methyl alcohol All 64.42 56.67 72.17 60.25 1.6553 1.2976 2.0941 32.0400 32.04 Option 2: A=7.897, B=1474.08, C=229.13






Individual Tank Emission Totals

Emissions Report for: Annual

Arlington Methanol_VFRT - Vertical Fixed Roof Tankalexandria, Virginia

Losses(lbs)Components Working Loss Breathing Loss Total EmissionsMethyl alcohol 126.28 96.74 223.02






Tank Indentification and Physical Characteristics

IdentificationUser Identification: Arlington_diesel storage tankCity: AlexandriaState: VirginiaCompany: Arlington WPCPType of Tank: Horizontal TankDescription: 12000 gal diesel storage tank

Tank DimensionsShell Length (ft): 20.50Diameter (ft): 10.00Volume (gallons): 12,000.00Turnovers: 0.00Net Throughput(gal/yr): 1,000,000.00Is Tank Heated (y/n): NIs Tank Underground (y/n): N

Paint CharacteristicsShell Color/Shade: Red/PrimerShell Condition Good

Breather Vent SettingsVacuum Settings (psig): -0.03Pressure Settings (psig) 0.03

Meterological Data used in Emissions Calculations: Washington National AP, District of Columbia (Avg Atmospheric Pressure = 14.67 psia)




Liquid Contents of Storage Tank

Arlington_diesel storage tank - Horizontal TankAlexandria, Virginia

Daily Liquid Surf.Temperature (deg F)

LiquidBulk

Temp Vapor Pressure (psia)Vapor

Mol.LiquidMass

VaporMass Mol. Basis for Vapor Pressure

Mixture/Component Month Avg. Min. Max. (deg F) Avg. Min. Max. Weight. Fract. Fract. Weight Calculations

Distillate fuel oil no. 2 All 68.94 58.23 79.65 62.35 0.0087 0.0061 0.0119 130.0000 188.00 Option 1: VP60 = .0065 VP70 = .009






Individual Tank Emission Totals

Emissions Report for: Annual

Arlington_diesel storage tank - Horizontal TankAlexandria, Virginia

Losses(lbs)Components Working Loss Breathing Loss Total EmissionsDistillate fuel oil no. 2 27.04 5.78 32.82





Appendix E

GE Jenbacher CHP Engine Cut-Sheet

10.11.2016/RS (7F53) Kuwahee Creek WWTP_JMC316_S.docx Copyright ©(rg) established by authorized sales provider from GE Jenbacher GmbH & Co OG 1/31

Technical Description

Cogeneration Unit-Container

JMC 316 GS-B.L

Kuwahee Creek WWTP

Electrical output 846 kW el.

Thermal output 1989 MBTU/hr

Emission values NOx < 0.6 g/bhp.hr (NO2)


0.01 Technical Data (on container) _______________________________________ 4 Main dimensions and weights (on container) 5 Connections 5 Output / fuel consumption 5

0.02 Technical data of engine ____________________________________________ 6 Thermal energy balance 6 Exhaust gas data 6 Combustion air data 6 Sound pressure level 7 Sound power level 7

0.03 Technical data of generator _________________________________________ 8 Reactance and time constants (saturated) 8

0.04 Technical data of heat recovery ______________________________________ 9 General data - Hot water circuit 9 General data - Cooling water circuit 9

connection variant F __________________________________________________ 10

0.10 Technical parameters _____________________________________________ 11

1.00 Scope of supply - Module __________________________________________ 14

1.01 Spark ignited gas engine __________________________________________ 14

1.01.01 Engine design _________________________________________________ 14

1.01.04 Standard tools (per installation) __________________________________ 16

1.03 Module Accessories ______________________________________________ 16

1.03.01 Engine jacket water system ______________________________________ 17

1.03.02 Automatic lube oil replenishing system incl. extension tank __________ 18

1.07 Painting _________________________________________________________ 18

1.11 Engine generator control panel per module- Dia.ne XT4 incl. Single synchronization of the generator breaker _________________________________ 18 Touch Display Screen: 19 Central engine and module control: 22 Malfunction Notice list: 23

1.11 Motor control panel – Container design ______________________________ 26

1.20.03 Starting system ________________________________________________ 26

1.20.05 Electric jacket water preheating __________________________________ 27

1.20.08 Flexible connections ___________________________________________ 27

2.00 Electrical equipment ______________________________________________ 28


4.00 Delivery, installation and commissioning _____________________________ 28 4.01 Carriage 28 4.02 Unloading 28 4.03 Assembly and installation 28 4.04 Storage 28 4.05 Start-up and commissioning 28 4.06 Trial run 29 4.07 Emission measurement (exhaust gas analyser) 29

5.01 Limits of delivery - Container _______________________________________ 29

5.02 Factory tests and inspections ______________________________________ 30 5.02.01 Engine tests 30 5.02.02 Generator tests 30 5.02.03 Module tests 30

5.03 Documentation ___________________________________________________ 31


0.01 Technical Data (on container)

Data at: Full

load

Part Load

Fuel gas LHV BTU/scft 579

100% 75% 50%

Energy input MBTU/hr [2] 7,838 6,087 4,337

Gas volume scfhr *) 13,537 10,513 7,490

Mechanical output bhp [1] 1,175 881 587

Electrical output kW el. [4] 846 631 416

Recoverable thermal output

~ Intercooler 1st stage MBTU/hr 655

~ Lube oil MBTU/hr 392

~ Jacket water MBTU/hr 942

~ Exhaust gas cooled to 995 °F MBTU/hr ~

Total recoverable thermal output MBTU/hr [5] 1,989

Heat to be dissipated

~ Intercooler 2nd stage MBTU/hr [9] ~

~ Lube oil MBTU/hr ~

~ Surface heat ca. MBTU/hr [7] 296

Spec. fuel consumption of engine electric BTU/kWel.hr [2] 9,263

Spec. fuel consumption of engine BTU/bhp.hr [2] 6,672

Lube oil consumption ca. gal/hr [3] 0.08

Electrical efficiency % 36.8%

Thermal efficiency % 25.4%

Total efficiency % [6] 62.2%

Hot water circuit:

Forward temperature °F 185.0

Return temperature °F 140.0

Hot water flow rate GPM 99.1

*) approximate value for pipework dimensioning [_] Explanations: see 0.10 - Technical parameters All heat data is based on standard conditions according to attachment 0.10. Deviations from the standard conditions can result in a change of values within the heat balance, and must be taken into consideration in the layout of the cooling circuit/equipment (intercooler; emergency cooling; ...). In the specifications in addition to the general tolerance of ±8 % on the thermal output a further reserve of +5 % is recommended for the dimensioning of the cooling requirements.

CH4 > 50 Vol.% required for specified NOx-emissions


Main dimensions and weights (on container)

Length in ~ 490

Width in 99-118

Height in ~ 110

Weight empty lbs ~ 53,390

Weight filled lbs ~ 56,270

Connections

Hot water inlet and outlet [A/B] in/lbs 3''/145

Exhaust gas outlet [D] in/lbs 10''/145

Fuel gas connection (on container) in 4''/232

Fresh oil connection G 28x2''

Waste oil connection G 28x2''

Cable outlet in 31.5x15.7

Condensate drain in 0.7

Output / fuel consumption

ISO standard fuel stop power ICFN bhp 1,175

Mean effe. press. at stand. power and nom. speed psi 218

Fuel gas type Sewage gas

Based on methane number | Min. methane number MN d) 135 | 100

Compression ratio Epsilon 12.5

Min./Max. fuel gas pressure at inlet to gas train psi 1.16 - 2.9 c)

Allowed Fluctuation of fuel gas pressure % ± 10

Max. rate of gas pressure fluctuation psi/sec 0.145

Maximum Intercooler 2nd stage inlet water temperature °F 140

Spec. fuel consumption of engine BTU/bhp.hr 6,672

Specific lube oil consumption g/bhp.hr 0.22

Max. Oil temperature °F 189

Jacket-water temperature max. °F 203

Filling capacity lube oil (refill) gal ~ 73

c) Lower gas pressures upon inquiry d) based on methane number calculation software AVL 3.2


0.02 Technical data of engine

Manufacturer GE Jenbacher

Engine type J 316 GS-C82

Working principle 4-Stroke

Configuration V 70°

No. of cylinders 16

Bore in 5.31

Stroke in 6.69

Piston displacement cu.in 2,376

Nominal speed rpm 1,800

Mean piston speed in/s 402

Length in 112

Width in 57

Height in 71

Weight dry lbs 9,259

Weight filled lbs 10,340

Moment of inertia lbs-ft² 212.89

Direction of rotation (from flywheel view) left

Radio interference level to VDE 0875 N

Starter motor output kW 7

Starter motor voltage V 24

Thermal energy balance

Energy input MBTU/hr 7,838

Intercooler MBTU/hr 655

Lube oil MBTU/hr 392

Jacket water MBTU/hr 942

Exhaust gas cooled to 356 °F MBTU/hr 1,924

Exhaust gas cooled to 212 °F MBTU/hr 2,334

Surface heat MBTU/hr 171

Exhaust gas data

Exhaust gas temperature at full load °F [8] 995

Exhaust gas temperature at bmep= 163.2 [psi] °F ~ 1018

Exhaust gas temperature at bmep= 108.8 [psi] °F ~ 1038

Exhaust gas mass flow rate, wet lbs/hr 11,056

Exhaust gas mass flow rate, dry lbs/hr 10,267

Exhaust gas volume, wet scfhr 138,358

Exhaust gas volume, dry scfhr 122,608

Max.admissible exhaust back pressure after engine psi 0.870

Combustion air data

Combustion air mass flow rate lbs/hr 10,185

Combustion air volume SCFM 2,104

Max. admissible pressure drop at air-intake filter psi 0.145


Sound pressure level

Aggregate a) dB(A) re 20µPa 100

31,5 Hz dB 88

63 Hz dB 90

125 Hz dB 98

250 Hz dB 93

500 Hz dB 94

1000 Hz dB 92

2000 Hz dB 93

4000 Hz dB 90

8000 Hz dB 94

Exhaust gas b) dB(A) re 20µPa 117

31,5 Hz dB 104

63 Hz dB 116

125 Hz dB 131

250 Hz dB 110

500 Hz dB 109

1000 Hz dB 107

2000 Hz dB 107

4000 Hz dB 104

8000 Hz dB 103

Sound power level

Aggregate dB(A) re 1pW 120

Measurement surface ft² 1,066

Exhaust gas dB(A) re 1pW 125

Measurement surface ft² 67.60

a) average sound pressure level on measurement surface in a distance of 3.28ft (converted to free field) according to DIN 45635, precision class 3.

b) average sound pressure level on measurement surface in a distance of 3.28ft according to DIN 45635, precision class 2. The spectra are valid for aggregates up to bmep=217.55661 psi. (for higher bmep add safety margin of 1dB to all values per increase of 15 PSI pressure).

Engine tolerance ± 3 dB


0.03 Technical data of generator

Manufacturer STAMFORD e)

Type PE 734 B e)

Type rating kVA 1,347

Driving power bhp 1,175

Ratings at p.f.= 1.0 kW 846

Ratings at p.f. = 0.8 kW 839

Rated output at p.f. = 0.8 kVA 1,049

Rated reactive power at p.f. = 0.8 kVAr 629

Rated current at p.f. = 0.8 A 1,262

Frequency Hz 60

Voltage V 480

Speed rpm 1,800

Permissible overspeed rpm 2,250

Power factor (lagging - leading) 0,8 - 1,0

Efficiency at p.f.= 1.0 % 96.6%

Efficiency at p.f. = 0.8 % 95.8%

Moment of inertia lbs-ft² 753.55

Mass lbs 5,975

Radio interference level to EN 55011 Class A (EN 61000-6-4) N

Ik'' Initial symmetrical short-circuit current kA 12.53

Is Peak current kA 31.91

Insulation class H

Temperature rise (at driving power) F

Maximum ambient temperature °F 104

Reactance and time constants (saturated)

xd direct axis synchronous reactance p.u. 2.19

xd' direct axis transient reactance p.u. 0.13

xd'' direct axis sub transient reactance p.u. 0.10

x2 negative sequence reactance p.u. 0.14

Td'' sub transient reactance time constant ms 10

Ta Time constant direct-current ms 20

Tdo' open circuit field time constant s 2.14

e) GE Jenbacher reserves the right to change the generator supplier and the generator type. The contractual data of the generator may thereby change slightly. The contractual produced electrical power will not change.


0.04 Technical data of heat recovery

General data - Hot water circuit

Total recoverable thermal output MBTU/hr 1,989

Return temperature °F 140.0

Forward temperature °F 185.0

Hot water flow rate GPM 99.1

Design pressure of hot water lbs 145

min. operating pressure psi 51.0

max. operating pressure psi 131.0

Pressure drop hot water circuit psi 8.70

Maximum Variation in return temperature °F +0/-21

Max. rate of return temperature fluctuation °F/min 18

General data - Cooling water circuit

Heat to be dissipated MBTU/hr 0

Return temperature °F 140

Cooling water flow rate GPM 66

Design pressure of cooling water lbs 145

min. operating pressure psi 7.0

max. operating pressure psi 73.0

Loss of nominal pressure of cooling water psi ~

Maximum Variation in return temperature °F +0/-21

Max. rate of return temperature fluctuation °F/min 18

The final pressure drop will be given after final order clarification and must be taken from the P&ID order documentation.

established by authorized sales provider from GE Jenbacher GmbH & Co OG

connection variant F


0.10 Technical parameters

All data in the technical specification are based on engine full load (unless stated otherwise) at specified

temperatures as well as the methane number and subject to technical development and modifications. For

isolated operation an output reduction may apply according to the block load diagram. Before being able to

provide exact output numbers, a detailed site load profile needs to be provided (motor starting curves, etc.).

All pressure indications are to be measured and read with pressure gauges (psi.g.).

(1) At nominal speed and standard reference conditions ICFN according to DIN-ISO 3046 and DIN 6271,

respectively

(2) According to DIN-ISO 3046 and DIN 6271, respectively, with a tolerance of +5 %.

Efficiency performance is based on a new unit (immediately upon commissioning).Effects of degradation

during normal operation can be mitigated through regular service and maintenance work;

reference value --> 55%CH4 /

(3) Average value between oil change intervals according to maintenance schedule, without oil change

amount

(4) At p. f. = 1.0 according to VDE 0530 REM / IEC 34.1 with relative tolerances

(5) Total output with a tolerance of ±8 %

(6) According to above parameters (1) through (5)

(7) Only valid for engine and generator; module and peripheral equipment not considered (at p. f. = 0,8)

(guiding value)

(8) Exhaust temperature with a tolerance of ±8 %

(9) Intercooler heat on:

* standard conditions (Vxx) - If the turbocharger design is done for air intake temperature > 86°F w/o de-

rating, the intercooler heat of the 1st stage need to be increased by 2%/K starting from 77°F. Deviations

between 77 – 86°F will be covered with the standard tolerance.

* Hot Country application (Vxxx) - If the turbocharger design is done for air intake temperature > 104°F

w/o de-rating, the intercooler heat of the 1st stage need to be increased by 2%/K starting from 95°F.

Deviations between 95 – 104°F will be covered with the standard tolerance.

Radio interference level

The ignition system of the gas engines complies the radio interference levels of CISPR 12 and EN 55011

class B, (30-75 MHz, 75-400 MHz, 400-1000 MHz) and (30-230 MHz, 230-1000 MHz), respectively.

Definition of output

ISO-ICFN continuous rated power:

Net break power that the engine manufacturer declares an engine is capable of delivering continuously, at

stated speed, between the normal maintenance intervals and overhauls as required by the manufacturer.

Power determined under the operating conditions of the manufacturer’s test bench and adjusted to the

standard reference conditions.

Standard reference conditions:

Barometric pressure: 14.5 psi (1000 mbar) or 328 ft (100 m) above sea level


Air temperature: 77°F (25°C) or 298 K

Relative humidity: 30 %

Volume values at standard conditions (fuel gas, combustion air, exhaust gas)

Pressure: 1 atmosphere (1013.25 mbar)

Temperature: 32°F (0°C)


Output adjustment for turbo charged engines

Standard rating of the engines is for an installation at an altitude ≤ 1640 ft and an air intake temperature ≤ 86

°F (T1) Maximum room temperature: 122°F (T2) -> engine stop

If the actual methane number is lower than the specified, the knock control responds. First the ignition timing

is changed at full rated power. Secondly the rated power is reduced. These functions are done by the engine

management.

Exceedance of the voltage and frequency limits for generators according to IEC 60034-1 Zone A will lead to a

derate in output.

Parameters for the operation of GE Jenbacher gas engines

The genset fulfills the limits for mechanical vibrations according to ISO 8528-9.

The following "Technical Instruction of GE JENBACHER" forms an integral part of a contract and must be

strictly observed: TA 1000-0004, TA 1100 0110, TA 1100-0111, and TA 1100-0112.

Transport by rail should be avoided. See TA 1000-0046 for further details

Failure to adhere to the requirements of the above mentioned TA documents can lead to engine damage and

may result in loss of warranty coverage.

Parameters for the operation of control unit and the electrical equipment

Relative humidity 50% by maximum temperature of 104°F.

Altitude up to 2000m above the sea level.

Parameters for using a gas compressor Parameters for using a gas compressor

The gas quantity indicated under the technical data refers to standard conditions with the given calorific

value. The actual volume flow (under operating conditions) has to be considered for dimensioning the gas

compressor and each gas feeding component – it will be affected by:

Actual gas temperature (limiting temperature according to TA 1000-0300)

Gas humidity (limiting value according to TA 1000-0300)

Gas Pressure

Calorific value variations (can be equated with methane (CH4) variations in the case of biogas)


The gas compressor is designed for a max. relative under pressure of 0.22 psi(g) (15 mbar(g)) and a inlet

temperature of 104°F (40°C) , if within scope of supply GE Jenbacher.

1.00 Scope of supply - Module

Design:

The module is built as a compact package. The engine and generator are mounted on a common base when

a low voltage generator is specified (<1000 V). In case of a medium voltage generator the engine base is

bolted to the generator base.

The Engine output shafting is connected through a coupling to the generator. To provide the best possible

isolation from the transmission of vibrations, the engine rests on the engine base-frame by means of

anti-vibration mounts. The remaining vibrations are eliminated by mounting the complete module on isolating

pads (e.g. Sylomer). This, in principle, allows for placing of the module to be directly on any floor capable of

carrying the static load. No special foundation is required. Prevention of sound conducted through solids has

to be provided locally.

1.01 Spark ignited gas engine

Four-stroke, air/gas mixture turbocharged, aftercooled, with high performance ignition system and

electronically controlled air/gas mixture system.

The engine is equipped with the most advanced

LEANOX® LEAN-BURN COMBUSTION SYSTEM

developed by GE JENBACHER.

1.01.01 Engine design

Engine block

Single-piece crankcase and cylinder block made of special casting, crank case covers for engine inspection,

welded steel oil pan.

Crankshaft and main bearings

Drop-forged, precision ground, surface hardened, statically and dynamically balanced; main bearings (upper

bearing shell: 3-material bearing / lower bearing shell: sputter bearing) arranged between crank pins, drilled

oil passages for forced-feed lubrication of connecting rods.

Vibration damper

Maintenance free viscous damper

Flywheel

With ring gear for starter motor


Pistons

Single-piece, made of light metal alloy, with piston ring carrier and oil passages for cooling; piston rings made

of high quality material, main combustion chamber specially designed for lean burn operation.

Connecting rods

Drop-forged, heat-treated, big end diagonally split and toothed. Big end bearings (upper bearing shell: sputter

bearing / lower bearing shell: grooved bearing) and connecting rod bushing for piston pin.

Cylinder liner

Chromium alloy gray cast iron, wet, individually replaceable.

Cylinder head

Specially designed and developed for GE JENBACHER-lean burn engines with optimized fuel consumption

and emissions; water cooled, made of special casting, individually replaceable; Valve seats and valve guides

and spark plug sleeves individually replaceable; exhaust and inlet valve made of high quality material.

Crankcase breather

Connected to combustion air intake system

Valve train

Camshaft, with replaceable bushings, driven by crankshaft through intermediate gears, valve lubrication by

splash oil through rocker arms.

Combustion air/fuel gas system

Motorized carburetor for automatic adjustment according fuel gas characteristic. Exhaust driven turbocharger,

mixture manifold with bellows, water-cooled intercooler, throttle valve and distribution manifolds to cylinders.

Ignition system

Most advanced, fully electronic high performance ignition system, external ignition control.

Lubricating system

Gear-type lube oil pump to supply all moving parts with filtered lube oil, pressure control valve, pressure relief

valve and full-flow filter cartridges. Cooling of the lube oil is arranged by a heat exchanger.

Engine cooling system

Jacket water pump complete with distribution pipework and manifolds.

Exhaust system

Turbocharger and exhaust manifold

Exhaust gas temperature measuring

Thermocouple for each cylinder

Electric actuator

For electronic speed and output control


Electronic speed monitoring for speed and output control

By magnetic inductive pick up over ring gear on flywheel

Starter motor

Engine mounted electric starter motor

1.01.04 Standard tools (per installation)

The tools required for carrying out the most important maintenance work are included in the scope of supply

and delivered in a toolbox.

1.03 Module Accessories

Base frame

Common Base Frame fabricated with welded structural steel. Frame to mount the engine, jacket water heat

exchangers, pumps and engine auxiliaries, as well as generator.

Coupling

Engine to Generator coupling is provided. The coupling isolates the major sub-harmonics of engine

alternating torque from generator.

Coupling housing

Provided for Coupling

Anti-vibration mounts

2 sets of isolation, one is arranged between engine block assembly and base frame. The second is via

insulating pads (SYLOMER) for placement between base frame and foundation, delivered loose.

Exhaust gas connection

A flanged connection is provided that collects the exhaust gas turbocharger output flows, includes flexible

pipe connections (compensators) to compensate for heat expansions and vibrations.

Combustion air filter

A Dry type air filter with replaceable filter cartridges is fitted. The assembly includes flexible connections to

the fuel mixer/carburetor and service indicator.

Interface panel (M1 cabinet)

Totally enclosed sheet steel cubicle with hinged doors, pre-wired to terminals, ready to operate. All Cable

entry will be via bottom mounted cable gland plates.

Painting: RAL 7035

Protection: External NEMA 3 (IP 54), Internal IP 20 (protection against direct contact with live parts)


Cabinet design is according to IEC 439-1 (EN 60 439-1/1990) and DIN VDE 0660 part 500, respectively.

Ambient temperature 41 - 104 °F (5 - 40 °C), Relative humidity 70%

Dimensions:

Height: 51 in (1300 mm)

Width: 47 in (1200 mm)

Depth: 16 in (400 mm)

Control Power Source: The starter batteries and the cabinet mounted battery chargers will provide the power

source for this enclosure.

Interface Panel contents and control functions:

The cabinet houses the unit Battery Charger and primary 24VDC Control Power Distribution (breakers,

fuses, and terminals) from the unit Batteries

Distributed PLC Input and Output cards, located in the cabinet, gather all Engine and Generator Control

I/O. These cards transmit data via data bus interface to the central engine control of the module control

panel located in the A1 cabinet. Data bus is via CAN and B&R Proprietary Data Highway (Data Cables

provided by GE)

Speed monitoring relays for protection are provided.

Gas Train I/O Collection, including interface relays and terminals for gas train shutoff valves.

Transducer for generator functions, such as excitation voltage.

Door Mounted Emergency Stop Switch with associated Emergency Stop Loop interface relays.

Miscellaneous control relays, contacts, fuses, etc. for additional control valves, and auxiliaries.

Interface Terminal Strips

Skid Mounted 3 Phase Devices are Powered by 3 x 480/277 V, 60 Hz, 50 A

AC Power for engine mounted auxiliaries (heater, pumps, etc.) are routed through a separate J-box mounted

on the side M1 cabinet (Box E1). This is done to maintain signal segregation (AC from control)

NOTE: Generator Current Transformer wiring is connected directly to the Generator and does NOT

pass through the M1 cabinet.

1.03.01 Engine jacket water system

Engine cooling jacket system

Closed cooling circuit, consisting of:

Expansion tank

Filling device (check and pressure reducing valves, pressure gauge)

Safety valve(s)

Thermostatic valve

Required pipework on module

Vents and drains

Jacket water pump, including check valve

Jacket water preheat device


1.03.02 Automatic lube oil replenishing system incl. extension tank

Automatic lube oil replenishing system:

Includes float valve in lube oil feed line, including inspection glass. Electric monitoring system will be provided

for engine shut-down at lube oil levels "MINIMUM" and "MAXIMUM". Solenoid valve in oil feed line is only

activated during engine operation. Manual override of the solenoid valve, for filling procedure during oil

changes is included.

Oil drain

By set mounted cock

Oil sump extension tank 79.3 gal

To increase the time between oil changes

Aftercooling oil pump:

Mounted on the module base frame; it is used for the aftercooling of the turbocharger; period of operation of

the pump is 15 minutes from engine stop.

Consisting of:

Oil pump 250 W, 480/277 V

Oil filter

Necessary pipework

1.07 Painting

Quality: Oil resistant prime layer

Synthetic resin varnish finishing coat

Color: Engine: RAL 6018 (green)

Base frame: RAL 6018 (green)

Generator: RAL 6018 (green)

Module interface

panel: RAL 7035 (light grey)

Control panel: RAL 7035 (light grey)

1.11 Engine generator control panel per module- Dia.ne XT4 incl. Single synchronization of the generator breaker

Dimensions:

Height: 87 in (including 8 in pedestal *)

Width: 32 -48 in*)

Depth: 24 in *)


Protection class:

external IP42

Internal IP 20 (protection again direct contact with live parts)

*) Control panels will be dimensioned on a project specific basis. Actual dimensions will be provided in the

preliminary documentation for the project.

Control supply voltage from starter and control panel batteries: 24V DC

Auxiliaries power supply: (from provider of the auxiliary supply)

3 x 480/277 V, 60 Hz

Consisting of:

Motor - Management - System DIA.NE

Setup:

a) Touch display visualization

b) Central engine and unit control

Touch Display Screen:

15“ Industrial color graphic display with resistive touch.

Interfaces:

24V voltage supply

VGA display connection

USB interface for resistive touch


Protection class of DIA.NE XT panel front: IP 65

Dimensions: W x H x D = approx. 16x12x3in

The screen shows a clear and functional summary of the measurement values and simultaneously shows a

graphical summary.

Operation is via the screen buttons on the touch screen

Numeric entries (set point values, parameters…) are entered on the touch numeric pad or via a scroll bar.

Determination of the operation mode and the method of synchronization via a permanently displayed button

panel on the touch screen.

Main screens (examples):

Main: Display of the overview, auxiliaries status, engine start and operating data.

ELE: Display of the generator connection with electrical measurement values and synchronization status


OPTION: Generator winding and bearing temperature Trending

Trend with 100ms resolution

Measurement values:

510 data points are stored

Measurement interval = 100ms

Raw data availability with 100ms resolution: 24 hours + max. 5.000.000 changes in value at shut down

(60 mins per shut down)


Compression level 1: min, max, and average values with 1000ms resolution: 3 days

Compression level 2: min, max, and average values with 30s resolution: 32 days

Compression level 3: min, max, and average values with 10min resolution: 10 years

Messages:

10.000.000 message events

Actions (operator control actions):

1.000.000 Actions

System messages:

100.000 system messages

Central engine and module control:

An industrial PC- based modular industrial control system for module and engine sequencing control (start

preparation, start, stop, aftercooling and control of auxiliaries) as well as all control functions.

Interfaces:

Ethernet (twisted pair) for remote monitoring access

Ethernet (twisted pair) for connection between engines

Ethernet (twisted pair) for the Powerlink connection to the control input and output modules.

USB interface for software updates

Connection to the local building management system according to the GE Jenbacher option list

(OPTION)

MODBUS-RTU Slave

MODBUS-TCP Slave,

PROFIBUS-DP Slave (160 words),

PROFIBUS-DP Slave (190 words),

ProfiNet

OPC

Control functions:

Speed control in idle and in island mode

Power output control in grid parallel operation, or according to an internal or external set point value on a

case by case basis

LEANOX control system which controls boost pressure according to the power at the generator terminals,

and controls the mixture temperature according to the engine driven air-gas mixer

Knocking control: in the event of knocking detection, ignition timing adjustment, power reduction and

mixture temperature reduction (if this feature is installed)

Load sharing between engines in island mode operation (option)

Linear power reduction in the event of excessive mixture temperature and misfiring


Linear power reduction according to CH4 signal (if available)

Linear power reduction according to gas pressure (option)

Linear power reduction according to air intake temperature (option)

Multi-transducer to record the following alternator electrical values:

Phase current (with slave pointer))

Neutral conductor current

Voltages Ph/Ph and Ph/N

Active power (with slave pointer)

Reactive power

Apparent power

Power factor

Frequency

Active and reactive energy counter

Additional 0 (4) - 20 mA interface for active power as well as a pulse signal for active energy

The following alternator monitoring functions are integrated in the multi-measuring device:

Overload/short-circuit [51], [50]

Over voltage [59]

Under voltage [27]

Asymmetric voltage [64], [59N]

Unbalance current [46]

Excitation failure [40]

Over frequency [81>]

Under frequency [81<]

Lockable operation modes selectable via touch screen:

"OFF" operation is not possible, running units will shut down immediately;

"MANUAL" manual operation (start, stop) possible, unit is not available for fully automatic

operation.

"AUTOMATIC" fully automatic operation according to external demand signal:

Demand modes selectable via touch screen:

external demand off („OFF“)

external demand on („REMOTE“)

overide external demand („ON“)

Malfunction Notice list:

Shut down functions e.g.:

Low lube oil pressure

Low lube oil level


High lube oil level

High lube oil temperature

Low jacket water pressure

High jacket water pressure

High jacket water temperature

Overspeed

Emergency stop/safety loop

Gas train failure

Start failure

Stop failure

Engine start blocked

Engine operation blocked

Misfiring

High mixture temperature

Measuring signal failure

Overload/output signal failure

Generator overload/short circuit

Generator over/undervoltage

Generator over/underfrequency

Generator asymmetric voltage

Generator unbalanced load

Generator reverse power

High generator winding temperature

Synchronizing failure

Knocking failure

Warning functions e.g.:

Cooling water temperature min.

Cooling water pressure min.

Generator winding temperature max.

Remote signals:

(volt free contacts)

1NO = 1 normally open

1NC = 1 normally closed

1COC = 1 change over contact

Ready for automatic start (to Master control) 1NO

Operation (engine running) 1NO

Demand auxiliaries 1NO

Collective signal "shut down" 1NC

Collective signal "warning" 1NC

External (by others) provided command/status signals:


Engine demand (from Master control) 1S

Auxiliaries demanded and released 1S

Single synchronizing Automatic

For automatic synchronizing of the module with the generator circuit breaker to the grid by PLC- technology,

integrated within the module control panel.

Consisting of:

Hardware extension of the programmable control for fully automatic synchronization selection and

synchronization of the module and for monitoring of the generator circuit breaker closed signal.

Lockable synchronization selection via touch screen with the following selection modes:

"MANUAL" Manual initiation of synchronization via touch screen button followed by fully

automatic synchronization of the module

"AUTOMATIC" Automatic module synchronization, after synchronizing release from the module

control

"OFF" Selection and synchronization disabled

Control of the generator circuit breaker according to the synchronization mode selected via touch

screen.

"Generator circuit breaker CLOSED/ Select" Touch-button on DIA.NE XT

"Generator circuit breaker OPEN" Touch-button on DIA.NE XT

Status signals:

Generator circuit breaker closed

Generator circuit breaker open

Remote signals:

(volt free contacts)

Generator circuit breaker closed 1 NO

The following reference and status signals must be provided by the switchgear supplier:

Generator circuit breaker CLOSED 1 NO

Generator circuit breaker OPEN 1 NO

Generator circuit breaker READY TO CLOSE 1 NO

Mains circuit breaker CLOSED 1 NO

Mains circuit breaker OPEN 1 NO

Mains voltage 3 x 480/277V or 3x 110V/v3 other measurement voltages available on request

Bus bar voltage 3 x 480/277 V or 3x 110V/v3 – other measurement voltages available on request

Generator voltage 3 x 480 V or 3x 110V/v3 – other measurement voltages available on request

Voltage transformer in the star point with minimum 50VA and Class 0,5


The following volt free interface-signals will be provided by GE Jenbacher to be incorporated in

switchgear:

CLOSING/OPENING command for generator circuit breaker

(permanent contact) 1 NO + 1 NC

Signal for circuit breaker undervoltage trip 1 NO

Maximum distance between module control panel and engine/interface panel: 99ft

Maximum distance between module control panel and power panel: 164ft

Maximum distance between module control panel and master control panel: 164ft

Maximum distance between alternator and generator circuit breaker: 99ft

1.11 Motor control panel – Container design

Sheet metal IEC enclosure, components and assembly UL listed.

For distribution and protection of the module and container auxiliaries.

With cubicle lighting.

Dimensions:

Height: 71 inch (1800 mm)

Width: 39 inch (990 mm)

Depth: 16 inch (405 mm)

Equipment:

Equipped with IEC type starters for each motor

With safety disconnect switches for every load

With step down transformer 480/120V, 10kVA for container consumers

2 motorstarter 7.2kW 10hp

4 motorstarter 4.7kW 6.5hp



1 circuit breaker 8.67kW 12hp

1 motorstarter 3kW 4hp

1.20.03 Starting system

Starter battery:

2 piece 12 V Pb battery, 200 Ah (according to DIN 72311), complete with cover plate, terminals and acid

tester.


Battery voltage monitoring:

Monitoring by an under voltage relay.

Battery charging equipment:

Capable for charging the starter battery with I/U characteristic and for the supply of all connected D.C.

consumers.

Charging device is mounted inside of the module interface panel or module control panel.

General data:

Power supply 3 x 320 - 550 V, 47 - 63 Hz

max. power consumption 1060 W

Nominal D.C. voltage 24 V(+/-1%)

Voltage setting range 24V to 28,8V ( adjustable)

Nominal current (max.) 40 A

Dimensions ca. 10 x 5 x 5 inch (240 x 125 x 125 mm)

Degree of protection IP20 to IEC 529

Operating temperature 32 °F – 140 °F (0 °C - 60 °C)

Protection class 1

Humidity class 3K3, no condensation.

Natural air convection

Standards EN60950,EN50178

UL/cUL (UL508/CSA 22.2)

Signalling:

Green Led: Output voltage > 20,5V

Yellow Led: Overload, Output Voltage < 20,5V

Red Led: shutdown

Control accumulator:

Pb battery 24 VDC/18 Ah

1.20.05 Electric jacket water preheating

Installed in the jacket water cooling circuit, consisting of:

Heating elements

Water circulating pump

The jacket water temperature of a stopped engine is maintained between 133 °F (56°C) and 140°F (60°C), to

allow for immediate loading after engine start.

1.20.08 Flexible connections

Following flexible connections per module are included in the GE Jenbacher -scope of supply:


No.Connection Unit Dimension Material

2 Warm water in-/outlet in/lbs 3''/145 Stainless steel

1 Exhaust gas outlet in/lbs 10''/145 Stainless steel

1 Fuel gas inlet in/lbs 3''/145 Stainless steel

2 Intercooler in-/outlet in/lbs 3''/145 Stainless steel

2 Lube oil connection Error! Reference source not found. Hose

Sealings and flanges for all flexible connections are included.

2.00 Electrical equipment

Totally enclosed floor mounted sheet steel cubicle with front door wired to terminals. Ready to operate, with

cable entry at bottom. Naturally ventilated.

Protection: IP 42 external, NEMA 12

IP 20 internal (protection against direct contact with live parts)

Design according to EN 61439-2 / IEC 61439-2 and ISO 8528-4.

Ambient temperature 41 - 104 °F (5 - 40 °C), 70 % Relative humidity

Standard painting: Panel: RAL 7035

Pedestal: RAL 7020

4.00 Delivery, installation and commissioning

4.01 Carriage According to contract.

4.02 Unloading Unloading, moving of equipment to point of installation, mounting and adjustment of delivered equipment on

intended foundations is not included in GE Jenbacher scope of supply.

4.03 Assembly and installation Assembly and installation of all GE Jenbacher -components is not included in GE Jenbacher scope of supply.

4.04 Storage The customer is responsible for secure and appropriate storage of all delivered equipment.

4.05 Start-up and commissioning Start-up and commissioning with the GE Jenbacher start-up and commissioning checklist is not included.

Plants with island operation require internet connection.


4.06 Trial run After start-up and commissioning, the plant will be tested in an 8-hour trial run. The operating personnel will

be introduced simultaneously to basic operating procedures.

Is not included in GE Jenbacher scope of supply.

4.07 Emission measurement (exhaust gas analyser) Emission measurement by GE Jenbacher personnel, to verify that the guaranteed toxic agent emissions have

been achieved (costs for measurement by an independent agency will be an extra charge).

5.01 Limits of delivery - Container

Electrical

Module:

At terminals of generator circuit breaker

Warm water

At inlet and outlet flanges on container

Exhaust gas

At exhaust gas outlet flange on top of the container; special stack provided locally

Combustion air

The air filters are set mounted, no external ductwork is necessary

Fuel gas

At inlet flange of the container

Lube oil

At lube oil connections on container

Condensate

At the condensate drains on container.

Insulation

Insulation of heat exchangers, pipework and exhaust gas silencer is not included in our scope of supply and

must be provided locally.

First filling

The first filling of module, (lube oil, engine jacket water, anti freeze-, anti corrosive agent, battery acid) is not

included in our scope of supply.

The composition and quality of the used consumables are to be strictly monitored in accordance with the

"Technical Instructions" of GE JENBACHER.

Suitable bellows and flexible connections must be provided locally for all connections.


Cables from the module must be flexible.

5.02 Factory tests and inspections

The individual module components shall undergo the following tests and inspections:

5.02.01 Engine tests Carried out as combined Engine- and Module test according to DIN ISO 3046 at GE Jenbacher test bench.

The following tests are made at 100%, 75% and 50% load, and the results are reported in a test certificate:

Engine output

Fuel consumption

Jacket water temperatures

Lube oil pressure

Lube oil temperatures

Boost pressure

Exhaust gas temperatures, for each cylinder

5.02.02 Generator tests Carried out on test bench of the generator supplier.

5.02.03 Module tests The engine will be tested with natural gas (methane number 94). The performance data achieved at the test

bench may therefore vary from the data as defined in the technical specification due to differences in fuel gas

quality.

Carried out as combined Engine- and Module test commonly with module control panel at GE Jenbacher test

bench, according to ISO 8528, DIN 6280. The following tests are made and the results are reported in a test

certificate:

Visual inspection of scope of supply per specifications.

Functional tests per technical specification of control system.

Starting in manual and automatic mode of operation

Power control in manual and automatic mode of operation

Function of all safety systems on module

Measurements at 100%, 75% and 50% load:

Frequency

Voltage

Current

Generator output

Power factor

Fuel consumption

Lube oil pressure

Jacket water temperature

Boost pressure

Mixture temperature

Exhaust emission (NOx)


The module test will be carried out with the original generator, except it is not possible because of the

delivery date. Then a test generator will be used for the module test.

To prove characteristics of the above components, which are not tested on the test bench by GE

JENBACHER, the manufacturers’ certificate will be provided.

In the case of a container unit the above mentioned test procedure for the module is performed in Jenbach.

GE Jenbacher reserves the right to perform the functional test of the container in a GE facility elsewhere.

5.03 Documentation

Preliminary documentation 60 days after receipt of a technically and commercially clarified order:

Module drawing 1)

Technical diagram 1)

Drawing of control panel 3)

List of electrical interfaces 2)

Technical specification of control system 2)

Technical drawing auxiliaries (if included in GE Jenbacher-limit of delivery) 1)

At delivery:

Wiring diagrams 3)

Cable list 3)

At start-up and commissioning (or on clients request):

Operating and maintenance manual 4)

Spare parts manual 4)

Operation report log 4)

Available Languages

1) DEU, GBR

2) DEU, GBR, FRA, ITA, ESP

3) DEU, GBR, FRA, ITA, ESP, NLD, HUN, RUS, POL, TUR, CZE

4) DEU, GBR, FRA, ITA, ESP, NLD, HUN, RUS, POL, TUR, CZE, SLOWEN, SLOWAK, SERB, SCHWED,

ROM, PRT, NORWEG, LITAU, LETT, BULGAR, CHINA, DNK, ESTN, FIN, GRC, KROAT

Appendix F

Varec Enclosed Flare 244E Cut-Sheet

Design Criteria

Q 500 scfm Flow Rate- Maximum gas production

T 95 Deg. F Gas Temperature

D 10 Inches Flare Diameter

H 650 Btu/cu. Ft. Heat Content - Must be based on 60.18 F (3)

L 19.67 Ft Burner Tip above Ground Level

14.66667 Ft Burner Standard height

5.00 FT Additional height from ground to base of flare. (NOT INCLUDED IN VAREC'S SCOPE OF SUPPLY)

Gas Exit Velocity

V 15.984 ft/s Part 60.18 C.3.ii and C.4.iii Vmax 47.0708 m/s 154.43165 fps

BTU 24.2262 MJ/scm

Flame Length (metric)

Lf 20.77452 Feet 0.01288*(H+(Q*60))^0.44

Per API 521: LOG(Vmax) = (Ht + 28.8)/31.7 equation

Flame height center under wind conditions

Yc 1.038726 Yc = C*Lf/2

Radiation Level @ 6 feet above Ground (assuming average height of an operator is 6 foot)

K 1086.424 btu/ft2/hr

Maximum recommended = 1500 BTU/h-ft2

60.18 C,3,ii

60.18 F (3)

(3) The net heating value of the gas being combusted in a flare shal be calculated using the following equation:

where:

60.18 C.4.iii

F.5

MUST NOT EXCEED THIS

VALUE TO MEET PART 60.18,

PARA. F(5)

SAFE OPERATING HEIGHT CALCULATIONS

Net heating value of the sample, MJ/scm; where the net enthalpy per mole of offgas is based on combustion

at 25°C and 760 mm Hg, but the standard temperature for determining the volume corresponding to one mole

is 20°C;

(ii) Flares shall be used only with the net heating value of the gas being combusted being 11.2 MJ/scm

(300 Btu/scf) or greater if the flare is steam-assisted or air-assisted; or with the net heating value of the gas

being 7.45 MJ/scm (200Btu/scf) or greater if the flare is nonassisted. The net heating value of the gas being

combusted shall be determined by the methods specified in paragraph (f) (3) of this section.

Steam-assisted and nonassisted flares designed for and operated with an exit velocity, as determined by the

methods specified in paragraph (f)(4), less than the velocity, Vmax1 as determined by the method specified in

paragraph (f)(5), and less than 122m/sec (400ft/sec) are allowed.

Constant,

1.740 X 10-7

where the standard temperature for is 20°C;

C = constant variable for wind. Worst case is 0.1

(with flame laying horizontal).

Lf = flame length (FT)

K = 0.3 x H x Q x 60 /(4 x pi x (L+Yc)^2) where:

H = heat content of the gas (BTU/ft3)

Q = Flow rate (cfm)

L = Flare tip height above grade in feet

Yc = Center of flame value*

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Appendix G

Cleaver Brooks Natural Gas Boiler Cut-Sheet

CBLE125-800 HP

Boiler Book05/2017

BOILER BOOK CBLE

2

CONTENTSFEATURES AND BENEFITS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3PRODUCT OFFERING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3DIMENSIONS AND RATINGS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4PERFORMANCE DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .24ENGINEERING DATA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27

ILLUSTRATIONSDimensions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5-15Open rear head on CBLE boilers with davits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21Mounting Piers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21-22Front Davit Support . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22Lifting Lug Location, Model CBLE Boilers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23Predicted stack temperature increase for pressure > 125 psig . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .26Standard Gas Train Connection Size and Location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31Typical Gas Piping Layout . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .33Model CBLE Gas Train Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34No.2 Oil Connection Size, Location, and Recommended Line Sizes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34No. 2 Oil Piping, Single Boiler Installation, Remote Oil Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .35No. 2 Oil Piping, Multiple Boiler Installation, Remote Oil Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .35No. 2 Oil Piping, Multiple Boiler Installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36No. 2 Oil Piping Typical Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37Boiler Room Length (Typical Layouts) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .40Boiler Room Width (Typical Layout) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .40Breeching Arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .41

TABLESModel CBLE Steam Boiler Ratings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Model CBLE Hot Water Boiler Ratings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4CBLE Blower Motor Selection - operating pressures 150 psig and less, and all hot water boilers . . . . . . . . . . . . . . . . .17CBLE Blower Motor Selection - operating pressures greater than 150 psig (steam boilers) . . . . . . . . . . . . . . . . . . . . .17Blower Motor Selection CB-LE NTI Boilers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Turndown Guarantee for CB-LE NTI Boilers - Natural Gas & #2 Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Model CB-LE Boiler Weights . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19Steam Boiler Safety Valve Openings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20Hot Water Boiler Relief Valve Openings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20Predicted Fuel-to-Steam Efficiencies - Natural Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25Predicted Fuel-to-Steam Efficiencies - No. 2 Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .26CBLE Boilers - Natural Gas, Emission Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27CBLE Boilers - No. 2 Oil, Emission Levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27CBLE Predicted Sound Levels 30 ppm NOx Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .28Standard, Undersize, and Oversize Gas Trains . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .28Minimum required regulated gas pressure altitude conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30Maximum Gas Consumption (CFH) for Natural Gas and Propane Vapor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30Blowdown Tank Sizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37Heating Surface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .38Steam Volume and Disengaging Area . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .38Recommended Steam Nozzle Size (for 4000 to 5000 fpm nozzle velocity) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .39Recommended Non-Return Valve Size . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .39

BOILER BOOK CBLE FEATURES AND BENEFITS

3

The Low Emission feature combines the packaging of induced flue gas recirculation with the Cleaver-Brooks integral front head. The front head routes the flue gases from the fourth pass to the fan and burner assembly for reliable low NOx perfor-mance. The enhanced burner design assures maximum NOx reduction at all firing rates while maintaining top of the line boiler performance.

Standard Low Emission Options include 60, 30, or 20 ppm packages (all NOx emission levels are given on a dry volume basis and corrected to 3% O2):

• NOx performance for 60 ppm (natural gas corrected to 3% O2) uses a standard size combustion air fan for induced flue gas recirculation.

• NOx performance for 30 or 20 ppm (natural gas corrected to 3% O2) includes a larger combustion air fan/motor assembly and a larger internal NOx reduction system.

Cleaver-Brooks' commitment to lowering emissions is based on more than 400 low NOx installations - all passing guaran-teed emission performance levels.

FEATURES AND BENEFITSThe Cleaver-Brooks Model CB Boiler - the premium firetube on the market today - includes the four-pass dryback design, five square feet of heating surface per boiler horsepower, and maximum boilerefficiency. In addition to the features of the Model CB Boiler, the Low Emission Option provides thefollowing

Integral Front Head Design• Single-piece front door. • Fan cassette assembly for easy access to fan and motor.• Guaranteed low nitrogen oxide (NOx) performance.• Enhanced burner performance. • Improved flame stability and combustion control.• Intimate mixing of air and fuel assures minimum CO levels at low NOx levels.

True Boiler/Burner/Low NOx Package• UL/ULC approved package.• Assures highest fuel-to-steam efficiency.• Eliminates the need for field installation of burner, controls, or NOx equipment.• Single point positioning of fuel and air ensures ease of startup and provides reliable operation.

PRODUCT OFFERINGThe Low Emission Option currently is available on:• 125 - 800 hp Model CB Firetube Dryback Boilers.• High-pressure and low-pressure steam and hot water designs.• Natural Gas, No. 2 oil, or combination fired.• Retrofit capability.

Standard Equipment• Model CB Firetube Boiler.• New integral front head with internal low NOx system.• Enhanced burner design.

Available OptionsFor option details, contact your local Cleaver-Brooks authorized representative.• Full line of Model CB Firetube options.• Additional NOx reduction packages.

BOILER BOOK CBLE DIMENSIONS AND RATINGS

4

DIMENSIONS AND RATINGSThe Model CBLE dimensions and ratings are provided in the tables and figures below.

These dimensions are for reference only; certified drawings from CB are required if clearances arecritical.

Table 1. Model CBLE Steam Boiler Ratings

BOILER HP 125 150 200 250 300 350 400 500 600 700 800

RATINGS SEA LEVEL TO 700 FTRated Steam Cap. (lbs /hr from and @ 212 °F)

4313 5175 6900 8625 10350 12075 13800 17250 20700 24150 27600

Btu Output (1000 Btu/hr) 4184 5021 6695 8369 10043 11716 13390 16738 20085 23433 26780APPROXIMATE FUEL CONSUMPTION AT RATED CAPACITY

Light Oil (gph)A 36.4 43.7 58.3 72.9 87.5 102.1 116.6 145.8 175.0 204.1 233.3Natura l Gas (cfh) MBtu 5103 6123 8165 10206 12247 14288 16329 20412 24494 28576 32659Gas (Therm/hr) 51.0 61.2 81.6 102.1 122.5 142.9 163.3 204.1 244.9 285.8 326.6

POWER REQUIREMENTS - SEA LEVEL TO 700 FT, 60 HZBlower Motor hp Refer to Tables 3 and 4Oil Pump Motor, hp No. 2 Oil

1/2 1/2 1/2 1/2 3/4 3/4 3/4 3/4 3/4 1 1

Air Compressor Motor hp (Oil firing Only)

3 3 3 5 5 5 7-1/2 7-1/2 7-1/2 7-1/2 7-1/2

NOTES: A. Based on 140,000 Btu/ga l.

Table 2. Model CBLE Hot Water Boiler RatingsBOILER HP 125 150 200 250 300 350 400 500 600 700 800

POWER REQUIREMENTS - SEA LEVEL TO 700 FT, 60 HZRated Cap. Btu Output (1000 Btu/hr)

4184 5021 6695 8369 10043 11716 13390 16738 20085 23433 26780

APPROXIMATE FUEL CONSUMPTON AT RATED CAPACITY

Light Oil (gph)A 36.4 43.7 58.3 72.9 87.5 102.1 116.6 145.8 175.0 204.1 233.3

Natura l Gas (cfh) MBtu 5103 6123 8165 10206 12247 14288 16329 20412 24494 28576 32659

Gas (Therm/hr) 51.0 61.2 81.6 102.1 122.5 142.9 163.3 204.1 244.9 285.8 326.6

POWER REQUIREMENTS - SEA LEVEL TO 700 FT, 60 HZ

Blower Motor hp Refer to Tables 3 and 4

Oil Pump Motor, hp No. 2 Oil

1/2 1/2 1/2 1/2 3/4 3/4 3/4 3/4 3/4 1 1

Air Compressor Motor hp (Oil firing Only)

3 3 3 5 5 5 7-1/2 7-1/2 7-1/2 7-1/2 7-1/2

NOTES:A. Based on 140,000 Btu/ga l.


5

(measurements shown in inches)

Dimensions Steam 125-200 HP

Description DIMBoiler HP

125 150 200

LENGTHS

Length Overall A 173 196.5 228.5

Shell B 125 149 180

Front Head Extension C 28 28 29

Front Ring Flange to Nozzle - 15# D 88 90 96


Rear Head Extension E 19.5 19.5 19.5

Front Ring Flange to Panel G 17 17 17

Ring Flange to Base H 0.5 0.5 0.5

Base Frame I 112 136 167

Rear Flange Ring to Base J 12.5 12.5 12.5

HEIGHTS

Ht Overall K 87 87 87

Base to Vent Outlet L 87 87 87

Base to Boiler Centerline M 46 46 46

Base to Gas Train N 6 8.5 8.5

HEIGHTS (continued)

Base to Panel Top T 75 75 77

Base to Panel Bottom U 15 15 17

Height of Base V 12 12 12

Base to Steam Nozzle Y 82.38 82.38 82.38

WIDTHS

Width Overall O 89.88 89.875 90.5

Center to ALWCO P 38.75 38.75 38.75

A

B

C D

E

F

G

H I J

KLM Y

N

O

P QR S

T

UV

WX

YAA

BB CC DD EE

GG

HHHH

JJ

GGGG

JJ

KK

FF FARSIDE

Figure 1. Dimensions CBLE Steam - 125-200 HP


6

Center to Outside Control Panel Q 48.5 48.5 48.5

Center to Lagging R 33 33 33

Center to WC S 44.5 45 45

Base Inside W 44.5 44.5 44.5

Base Outside X 52.5 52.5 52.5

Boiler I.D. F 60 60 60

CONNECTIONS

Electric - Main Power Supply AA 460 / 3 / 60 460 / 3 / 60 460 / 3 / 60

Surface Blowoff (with collector pipe) BB 1 1 1

Steam Outlet 15# (150# Flange) CC 8 8 10


Chemical Feed FF 1 1 1

Feed Water (2) GG 1.5 1.5 2

Blowdown (2) 150# HH 1.5 1.5 1.5

Drain (2) 15# HH 1.5 1.5 2

Water Column Blowdown JJ 0.75 0.75 0.75

Gauge Glass Blowdown KK .025 0.25 0.25

VENT STACK

Diameter (OD) (flgd. connection) 16 16 16

CLEARANCES

Rear Door Swing (Davited) 32 32 32

Front Door Swing 67 67 67

Tube Removal, Rear 115 139 170

Tube Removal, Front 103 127 158

MINIMUM BOILER ROOM LENGTH ALLOWING FOR DOOR SWING AND TUBE REMOVAL:

From Rear of Boiler 307 355 417

From Front of Boiler 260 308 370

Through Window or Doorway 224 248 279

WEIGHT IN LBS

Normal Water Capacity 5750 7250 8625

Approx. Ship Wt. 15 psig 11300 12600 14600



Dimensions Steam 125-200 HP (Continued)


125 150 200


7




250 300 350

LENGTHS

Length Overall A 191.5 220 250

Shell B 144 171 201

Front Head Extension C 23.5 25 25



Rear Head Extension E 24 24 24

Front Ring Flange to Panel G 17 23 23

Ring Flange to Base H 0.5 0.5 0.5

Base Frame I 131 158 188

Rear Flange Ring to Base J 12.5 12.5 12.5

HEIGHTS

Ht Overall K 115 115 115

Base to Vent Outlet L 106 106 106

Base to Boiler Centerline M 56 56 56

Base to Gas Train N 10 10 10

Base to Panel Top T 77 77 77

Base to Panel Bottom U 17 17 17

Height of Base V 12 12 12

Base to Steam Nozzle Y 101.50 101.50 101.50

WIDTHS

Width Overall O 106.5 106.5 108.75

Center to ALWCO P 48.5 48.5 48.5

Center to Outside Control Panel Q 58 58 58

Center to Lagging R 42 42 42

A

BC

D

E

F

G

H I J

K

L

M

N

OP Q

R S

T

UV

WX

Y

AA

BBCC

DDEE

FF

GG

HH

HH

JJ

JJ

KK

GGGG

Y

FARSIDE



8

Center to WC S 53.75 53.75 53.75

Base Inside W 56 56 56

Base Outside X 64 64 64

Boiler I.D. F 78 78 78

CONNECTIONS

Electric - Main Power Supply AA 460 / 3 / 60 460 / 3 / 60 460 / 3 / 60

Surface Blowoff (with collector pipe) BB 1 1 1



Chemical Feed FF 1 1 1

Feed Water (2) GG 2 2 2.5

Blowdown (2) 150# HH 1.5 1.5 1.5

Drain (2) 15# HH 2 2 2

Water Column Blowdown JJ 0.75 0.75 0.75

Gauge Glass Blowdown KK 0.25 0.25 0.25

VENT STACK

Diameter (OD) (flgd. connection) 20 20 20

CLEARANCES

Rear Door Swing 43 43 43

Front Door Swing 89 89 89

Tube Removal, Rear 131 157 187

Tube Removal, Front 116 142 172

MINIMUM BOILER ROOM LENGTH ALLOWING FOR DOOR SWING AND TUBE REMOVAL RMOVAREMOVAL:

From Rear of Boiler 364 417 477

From Front of Boiler 303 356 416

Through Window or Doorway 275 302 332

WEIGHT IN LBS

Normal Water Capacity 10670 13000 15465






250 300 350


9




400 500 600 700 800

LENGTHS

Length Overall A 205.75 227.75 259.75 298.75 298.75

Shell B 146.75 167.5 199.75 232.75 232.75

Front Head Extension C 27 28 28 34 34

Front Ring Flange to Nozzle - 15# D 98 101 96 112 112

Front Ring Flange to Nozzle - 150# D 96 100 96 112 112

Rear Head Extension E 32 32 32 32 32

Front Ring Flange to Panel G 26 26 26 26 26

Ring Flange to Base H 0.5 0.5 0.5 0.5 0.5

Base Frame I 133.75 154.75 186.75 219.75 219.75

Rear Flange Ring to Base J 12.5 12.5 12.5 12.5 12.5

HEIGHTS

Ht Overall K 134 134 134 134 134

Base to Vent Outlet L 126 126 126 126 126

Base to Boiler Centerline M 67 67 67 67 67

Base to Gas Train N 12 12 12 12 12

Base to Panel Top T 75 75 75 75 75

Base to Panel Bottom U 15 15 15 15 15

Height of Base V 12 12 12 12 12

Base to Steam Nozzle Y 121.5 123.5 121.5 121 121

WIDTHS

Width Overall O 124 124.25 124 124 124

Center to ALWCO P 57.5 57.5 57.5 57.5 57.5

Center to Outside Control Panel Q 66.5 66.5 66.5 66.5 66.5

A

BC

D

E

F

G

HI J

K

AA

BB CC

DD

EE

FFJJ

GG

HH HH

L

M

N

O

P QR S

T

UV

W

X

Y

JJJJ

KK

GGGG

Y

FARSIDE



10

Center to Lagging R 51 51 51 51 51

Center to WC S 63 63 63 63 63

Base Inside W 58.88 58.88 58.88 58.88 58.88

Base Outside X 71.88 71.88 71.88 71.88 71.88

Boiler I.D. F 96 96 96 96 96

CONNECTIONS

Electric - Main Power Supply AA 460 / 3 / 60 460 / 3 / 60 460 / 3 / 60 460 / 3 / 60 460 / 3 / 60

Surface Blowoff (with collector pipe) BB 1 1 1 1 1

Steam Outlet 15# (150# Flange) CC 12 12 12 12 12

Steam Outlet 150# (300# Flange) CC 6 8 8 8 8

Chemical Feed FF 1 1 1 1 1

Feed Water (2) GG 2.5 2.5 2.5 2.5 2.5

Blowdown/Drain (2) HH 2 2 2 2 2

Water Column Blowdown JJ 0.75 0.75 0.75 0.75 0.75

Gauge Glass Blowdown KK 0.25 0.25 0.25 0.25 0.25

VENT STACK

Diameter (OD) (flgd. connection) 24 24 24 24 24

CLEARANCES

Rear Door Swing 53 53 53 53 53

Front Door Swing 108 108 108 108 108Tube Removal, Rear 131 152 184 217 217

Tube Removal, Front 114 135 167 200 200

MINIMUM BOILER ROOM LENGTH ALLOWING FOR DOOR SWING AND TUBE REMOVAL

From Rear of Boiler 386 428 492 558 558

From Front of Boiler 314 356 420 486 486

Through Window or Doorway 308 329 361 394 394

WEIGHT IN LBS

Normal Water Capacity 14810 15950 19270 23000 23000

Approx. Ship Wt. 15 psig 33500 37110 42300 49500 49600





400 500 600 700 800


11


Dimensions HW 125-200 HP

Des cription DIMBoiler HP

125 150 200

LENGTHS

Overa ll (60 ppm Sys tem) A 171-1/2 196-1/2 228-1/2

Shell B 125 149 180

Base Frame C 112 136 167

Front Head Extens ion (60 ppm Sys tem) D 27 28 29

Rear Head Extens ion E 19-1/2 19-1/2 19-1/2

Front Ring Flange to Outle t HH 114 136 167

Front Ring Flange to Re turn H 89 102 131

Ring Flange to Base F 1/2 1/2 1/2

Over Tubeshee ts V 113 137 168

Shell Extens ion P 12 12 12

Rear Flange Ring to Base G 12-1/2 12-1/2 12-1/2

WIDTHS

Overa ll I 75-1/2 75-1/2 75-1/2

I.D. Boile r J 60 60 60

Cente r to Entrance Box K 42-1/2 42-1/2 42-1/2

Cente r to Outs ide Hinge KK 35 35 35

Center to Lagging L 33 33 33

Base , Outs ide M 52-1/2 52-1/2 52-1/2

Figure 4. Dimensions CBLE Hot Water - 125-200 HP

R

F G

WW

P

BB

D E

GG

Q

Z

Y T U

RR - RF - RD

X

HH

AB

HIL K

OO O

KK

M

N

EE

FF

DD

V

J

C


12

Base , Ins ide N 44-1/2 44-1/2 44-1/2

HEIGHTS

Overa ll OO 87 87 87

Base to Vent Outle t O 87 87 87

Base to Return and Outle t X 82-3/8 82-3/8 82-3/8

Height of Base Q 12 12 12

Base to Bottom of Boile r R 16 16 16

BOILER CONNECTION

Auxilia ry Connection Z 1 1 1

Water Re turn Flange T 6A 6A 6A

Water Outle t Flange (2" Dip Tube Included) U 6A 6A 6A

Dra in, Front and Rear W 1-1/2 1-1/2 2

Air Vent Y 1-1/2 1-1/2 1-1/2

VENT STACK

Diameter (flgd. connection) BB 16 16 16

MINIMUM CLEARANCES

Rear Door Swing DD 32 32 32

Front Door Swing EE 67 67 67

Tube Removal, Rear FF 115 139 170

Tube , Removal, Front GG 103 127 158

MINIMUM BOILER ROOM LENGTH ALLOWING FOR DOOR SWING AND TUBE REMOVAL FROM:

Rear of Boile r RR 307 355 417

Front of Boile r RF 260 308 370

Thru Window or Doorway RD 224 248 279

WEIGHT IN LBS

Water Capacity Flooded 7670 9295 11130

Approx. Ship. Wgt. – 30 ps igApprox. Ship. Wgt. – 125 ps ig

1140011800

1250012900

1450014900

NOTES: All connections a re threaded unless indica ted.A. ANSI 150 ps ig flange .

Dimensions HW 125-200 HP (Continued)


125 150 200


13




250 300 350

LENGTHS

Overa ll (60 ppm Sys tem) A 191-1/2 220 252

Shell B 144 171 201

Base Frame C 131 158 188

Front Head Extens ion (60 ppm Sys tem) D 23-1/2 25 27

Rear Head Extens ion E 24 24 24

Front Ring Flange to Re turn H 103-1/2 130 160

Front Ring Flange to Outle t HH 131 158 188

Ring Flange to Base F 1/2 1/2 1/2

Over Tubeshee ts V 129 156 186

Shell Extens ion P 15 15 15

Rear Flange Ring to Base G 12-1/2 12-1/2 12-1/2

WIDTHS

Overa ll I 93 93 93

I.D. Boile r J 78 78 78

Cente r to Entrance Box K 51 51 51

Cente r to Outs ide Hinge KK 51 51 51

Center to Lagging L 42 42 42

Base , Outs ide M 64 64 64

Base , Ins ide N 52 52 52

Figure 5. Dimensions CBLE Hot Water 250-350 HP

skoorBrevaelC

R

F G

WW

P

BB

D E

GG

Q

Z

Y T U

RR - RF - RD

X

HH

AB

HI

L K

OO O

KK

M

N

EE

FF

DD

V

J

C


14

HEIGHTS

Overa ll OO 115 115 115

Base to Vent Outle t O 106 106 106

Base to Return and Outle t X 101-1/2 101-1/2 101-1/2

Height of Base Q 10 10 10

Base to Bottom of Boile r R 17 17 17

BOILER CONNECTION

Auxilia ry Connection Z 1-1/4 1-1/4 1-1/4

Water Re turn Flange (2" Dip Tube included) T 8A 8A 8A

Water Outle t Flange (2" Dip Tube Included) U 8A 8A 8A

Air Vent Y 1-1/2 1-1/2 1-1/2

Dra in, Front and Rear W 2 2 2

VENT STACK

Diameter (flgd. connection) BB 20 20 20

MINIMUM CLEARANCES

Rear Door Swing DD 43 43 43

Front Door Swing EE 89 89 89

Tube Removal, Rear FF 131 157 187

Tube , Removal, Front GG 116 142 172


Rear of Boile r RR 364 417 477

Front of Boile r RF 303 356 416

Thru Window or Doorway RD 275 302 332

WEIGHT IN LBS

Water Capacity Flooded 13880 16840 20090


2140022200

2350024300

2670027500

NOTES: All connections a re threaded unless indicted.A. ANSI 150 ps ig flange .



250 300 350


15




400 500 600 700 800

LENGTHS

Overa ll (60 ppm Sys tem) A 206 228 262 299 300

Shell B 147 168 200 233 233

Base Frame C 134 155 187 220 220

Front Head Extens ion (60 ppm Sys tem) D 27 28 30 34 35

Rear Head Extens ion E 32 32 32 32 32

Shell Ring Flange to Base F 1/2 1/2 1/2 1/2 1/2

Rear Ring Flange to Base G 12-1/2 12-1/2 12-1/2 12-1/2 12-1/2

Shell Flange to Outle t HH 139-1/2 156-1/2 182-1/2 216-1/2 216-1/2

Shell Flange to Return H 107 125 151-1/2 185 185

Over Tubeshee ts V 130 151 183 216 216

Shell Extens ion P 17 17 17 17 17

WIDTHS

Overa ll I 113 113 113 113 115

I.D. Boile r J 96 96 96 96 96

Cente r to Entrance Box K 62 62 62 62 64

Cente r to Outs ide Hinge KK 62 62 62 62 62

Cente r to Lagging L 51 51 51 51 51

Base , Outs ide M 72 72 72 72 72

Figure 6. Dimensions CBLE Hot Water 400-800 HP

skoorBrevaelC

R

F G

WW

P

BB

D E

GG

Q

Z

Y T U

RR - RF - RD

X

HH

AB

HI

L K

OO O

KK

M

N

EE

FF

DD

V

J

C


16

Base , Ins ide N 56 56 56 56 56

HEIGHTS

Overa ll OO 134 134 134 134 134

Base to Vent Outle t O 126 126 126 126 126

Height of Base Q 12 12 12 12 12

Base to Bottom of Boile r R 19 19 19 19 19

Base to Return and Outle t X 121-9/16 121-9/16 121-9/16 121-9/16 121-9/16

BOILER CONNECTIONS

Auxilia ry Connection Z 1-1/4 1-1/4 1-1/4 1-1/4 1-1/4

Dra in, Front and Rear W 2 2 2 2 2

Water Re turn T 10A 10A 12A 12A 12A

Water Outle t (2” Dip Tube Included) U 10A 10A 12A 12A 12A

Air Vent Y 2 2 2 2 2

VENT STACK

Diameter (Flanged Connection) BB 24 24 24 24 24

MINIMUM CLEARANCES

Rear Door Swing DD 53 53 53 53 53

Front Door Swing EE 108 108 108 108 108

Tube Removal, Rear FF 131 152 184 217 217

Tube Removal, Front GG 114 135 167 200 200


Rear of Boile r RR 386 428 492 558 558

Front of Boile r RF 314 356 420 486 486

Thru Window or Doorway RD 308 329 361 394 394

WEIGHT IN LBS

Normal Water Capacity 20015 23300 28260 33360 33360


3330037270

3690040780

4215046005

4965053300

4975053400

NOTES: All connections a re threaded unless indica ted:A. ANSI 150 ps ig flange .



400 500 600 700 800


17

Table 3. CBLE Blower Motor Selection - operating pressures 150 psig and less, and all hot water boilers

BOILER HPMOTOR HP

60 PPM 30 PPM 20 PPM125 5 10 10150 7.5 10 10200 15 15 NA250 7.5 10 15300 10 15 30350 15 25 40400 10 15 20500 15 20 30600 25 30 60700 30 50 75800 50 75 NA

NOTES: For e leva tions above 700’ - contact your loca l Cleaver-Brooks autho-rized representa tive .

Table 4. CBLE Blower Motor Selection - operating pressures greater than 150 psig (steam boilers)

BOILER HPMOTOR HP

60 PPM 30 PPM 20 PPM125 5 10 10150 10 10 15200 15 20 NA250 7.5 10 20300 10 20 40350 20 30 50400 10 15 25500 20 25 40600 25 40 60700 40 60 75C

800 60 75A NANOTES: For e leva tion above 700’ - contact your loca l Cleaver-Brooks autho-rized representa tive .A. Downra te to 770 hp.B. Downra te to 675 hp.C. Downra te to 660 hp.


18

Table 5. Blower Motor Selection CB-LE NTI Boilers

Table 6. Turndown Guarantee for CB-LE NTI Boilers - Natural Gas & #2 Oil

Boiler SizeTurndown

9 ppm 15 ppm

125 4:1 4:1

150 4:1 5:1

200 4:1 5:1

250 5:1 5:1

300 5:1 5:1

350 5:1 5:1

400 5:1 6:1

500 5:1 6:1

600 6:1 6:1

700 7:1 7:1

800* 7:1 7:1*800 HP to be derated to 720 HP for 9 ppm and 750 HP for 15 ppm

Altitude: 700 ft and less - Design Pressure: 150 psi and less

* 800 HP - to be de-rated to 720 HP for 9 ppm and to 750 HP for 15 ppm.

mpp 9mpp 51NominalBoiler Size Blower Motor HP Blower Motor HP


19

Table 7. Model CB-LE Boiler Weights

BOILER HP FUELSERIES

HOT WATER STEAM

30 PSIG 125 PSIG 15 PSIG 150 PSIG 200 PSIG

125

100 11200 11600 11300 12000 12600

200 11400 11800 11500 12400 13000

700 11300 11700 11400 12300 12900

150

100 12300 12700 12400 13200 13900

200 12500 12900 12600 13500 14200

700 12300 12700 12400 13300 14000

200

100 14400 14800 14500 15500 16300

200 14500 14900 14600 15600 16400

700 14500 14900 14600 15600 16400

250

100 20700 21500 20800 22000 23800

200 21400 22200 21500 22800 24600

700 20900 21700 21000 22500 24300

300

100 23100 23900 23200 24800 26800

200 23500 24300 23600 25200 27200

700 23400 24200 23500 25000 27000

350

100 26200 27000 26300 27600 29100

200 26700 27500 26800 27800 29300

700 26400 27200 26500 27700 29200

400

100 33000 36970 33200 36270 39380

200 33300 37270 33500 36570 39680

700 33200 37170 33400 36470 39580

500

100 36600 40470 36810 39670 43480

200 36900 40780 37110 39970 43580

700 36800 40680 37010 39870 43280

600

100 41850 45905 42000 44725 49100

200 42150 46005 42300 45025 49400

700 42050 45915 42200 44925 49300

700800

100 49450 53000 49300 51850 57015

200 49750 53300 49600 52150 57315

700 49650 53200 49500 52050 57215

NOTES: 1. Weights shown are based on s tandard product offe ring for current lis ted boile rs . If units a re of specia l des ign and cons truction, actua l weightwill be de te rmined a t time of shipment. Shipment will then be made on shippers weight and count. All weights a re in US pounds .


20

Table 8. Steam Boiler Safety Valve OpeningsVALVE

SETTING 15 PSIG STEAM 100 PSIG STEAM 125 PSIG STEAM 150 PSIG STEAM 200 PSIG STEAM 250 PSIG STEAM 300 PSIG STEAM

BOILER HP

NO. OF VALVESREQ'D

OUTLET SIZE(IN.)

NO. OF VALVESREQ'D

OUTLET SIZE(IN.)

NO. OF VALVES REQ'D

OUTLET SIZE(IN.)

NO. OF VALVESREQ'D

OUTLET SIZE(IN.)

NO. OF VALVESREQ'D

OUTLET SIZE(IN.)

NO. OF VALVES REQ'D

OUTLET SIZE(IN.)

NO. OF VALVES REQ'D

OUTLET SIZE(IN.)

125 1 3 2 1-1/2 2 (1) 1-1/2(1) 1-1/4 2 (1) 1-1/2

(1) 1-1/4 2 (1) 1-1/4(1) 1 2 1 2 1

150 1 3 2 (1) 2(1) 1-1/2 2 1-1/4 2 (1) 1-1/2

(1) 1-1/4 2 (1) 1(1) 1-1/4 2 1 2 1

200 2 2-1/2 2 2 2 1-1/2 2 1-1/2 2 (1) 1-1/2(1) 1-1/4 2 1-1/4 2 (1) 1

(1) 1-1/4

250 2 (1) 2-1/2(1) 3 2 (1) 2-1/2

(1) 2 2 (1)2(1)1-1/2 2 (1) 2

(1) 1-1/2 2 (1)1-1/2(1)1-1/4 2 (1) 1-1/2

(1) 1-1/4 2 1-1/4

300 2 3 2 (1) 2-1/2(1) 2 2 2 2 (1) 2

(1) 1-1/2 2 1-1/2 2 (1)1-1/2(1)1-1/4 2 (1) 1-1/2

(1) 1-1/4

350 3 (1) 2(2) 3 3 (1) 2-1/2

(2) 2 2 (1)2(1)1-1/2 2 2 2 (1) 1-1/2

(1) 2 2 1-1/2 2 (1) 1-1/2(1) 1-1/4

400 3 (2) 3(1) 2-1/2 3 (1) 2

(2) 2-1/2 2 (1)2(1)2-1/2 2 (1) 2-1/2

(1) 2 2 (1) 1-1/2(1) 2 2 (1) 2

(1) 1-1/2 2 1-1/2

500 3 (3) 3 3 2-1/2 2 2-1/2 2 (1) 2-1/2(1) 2 2 (1) 2

(1) 2-1/2 2 (1) 2(1)1-1/2 2 (1) 1-1/2

(1) 2

600 4 3 4 (3) 2-1/2(1) 2 3 2-1/2 2 2-1/2 2 (1) 2

(1) 2-1/2 2 2 2 2

700 5 (3) 3(2) 2-1/2 5 (3) 2-1/2

(2) 2 3 2-1/2 3 (2) 2-1/2(1) 2 2 2-1/2 2 (1) 2

(1) 2-1/2 2 2

800 5 (3) 3(2) 2-1/2 5 (3) 2-1/2

(2) 2 4 (3) 2-1/2(1) 2 3 (2) 2-1/2

(1) 2 2 2-1/2 2 (1) 2(1) 2-1/2 2 (1) 2

(1) 2-1/2

NOTES: Valve manufacture rs a re Kunkle , Consolida ted or Conbraco, depending on ava ilability. This table revised 04/2012.

Table 9. Hot Water Boiler Relief Valve OpeningsVALVE

SETTING 30 PSIG HW 60 PSIG HW 100 PSIG HW 125 PSIG HW

BOILER HP NO. OF VALVES REQ'D

OUTLET SIZE (IN.)

NO. OF VALVES REQ'D

OUTLET SIZE (IN.)

NO. OF VALVES REQ'D

OUTLET SIZE (IN.)

NO. OF VALVES REQ'D

OUTLET SIZE (IN.)

125 1 2-1/2 1 2 1 2 1 1-1/4

150 1 2-1/2 1 2-1/2 1 2 1 2

200 2 (1) 2-1/2(1) 1-1/4 1 2-1/2 1 2 1 2

250 2 (1) 2(1) 2-1/2 1 2-1/2 1 2-1/2 1 2

300 2 2-1/2 2 (1) 1(1) 2-1/2 1 2-1/2 1 2-1/2

350 3 (2) 2-1/2(1) 1 2 (1) 2-1/2

(1) 2 1 2-1/2 1 2-1/2

400 3 (1) 2(2) 2-1/2 2 (1) 2

(2) 2-1/2 2 (1) 1(1) 2-1/2 1 2-1/2

500 4 (1) 1(3) 2-1/2 2 2-1/2 2 (1) 2-1/2

(1) 1-1/4 2 (1) 1(1) 2-1/2

600 4 (3) 2-1/2(1) 2 3 (1) 1-1

(2) 2-1/2 2 (1) 2(1) 2-1/2 2 (1) 2-1/2

(1) 1-1/4

700 & 800 5 (1) 1(4) 2-1/2 3 (1) 2

(2) 2-1/2 2 2-1/2 2 (1) 2-1/2(1) 2

NOTES: Hot wate r re lie f va lves a re Kunkle #537.


21

Figure 7. Space required to open rear head on CBLE boilers equipped with davits

Figure 8. Model CBLE Boiler Mounting Piers (60” and 78”)

BOILER HPDIMENSIONS (INCHES)

A B C D E

CB-125 THRU CB-200 33 55 45 68 32

CB-250 THRU CB-350 42 69 58 86 43

CB-400 THRU CB-800 51 88 71 109 53

BOILER HP A B C D E F G X1 X2 X3

125 6 9 112 39-1/2 57-1/2 4 44-1/2 10 9-3/4 22-1/2

150 6 9 136 39-1/2 57-1/2 4 44-1/2 10 9-3/4 22-1/2

200 6 9 167 39-1/2 57-1/2 4 44-1/2 10 9-3/4 22-1/2

250 6 12 131 46 70 4 56 10 22 22-1/2

300 6 12 158 46 70 4 56 10 22 22-1/2

350 6 12 188 46 70 4 56 10 22 22-1/2

NOTE:

All numbers in table are in inches.6-inch high mounting piers recommended for use beneath the boiler base frame. The use of these piers provides increased inspection accessibility to the piping beneath the boiler and added height for washing down the area beneath the boiler.


22

Figure 9. Model CBLE Boiler Mounting Piers (96”)

Figure 10. Front Davit Support

BOILER HP A B C D E F G

400 6 14 134 50 78 6-1/2 58-7/8

500 6 14 155 50 78 6-1/2 58-7/8

600 6 14 187 50 78 6-1/2 58-7/8

700-800 6 14 220 50 78 6-1/2 58-7/8

NOTE: 1. All numbers in table a re in inches .2. 6-inch high mounting pie rs recommended for use benea th the boile r base frame. The use of these pie rs provides in-

creased inspection access ibility to the piping benea th the boile r and added he ight for washing down the a rea benea ththe boile r.

CBLE 250-350HP

CBLE 400-800HP

Motor HP Hole Number7.5 115 125 240 3

Motor HP Hole Number10 120 130 250 275 3


23

Figure 11. Lifting Lug Location, Model CBLE Boilers

BOILER HP VIEWALL DIMENSIONS IN INCHES

A B C D E

125 All B 80-1/4 29-3/4 70-1/2 10 3

150 All B 80-1/4 29-3/4 83-1/2 10 3

200 All B 80-1/4 29-3/4 114-1/2 10 3

250Steam B 99 36 72 10 3

Hot Water B 99 36 81 10 3

300Steam B 99 36 99 10 3

Hot Water B 99 36 108 10 3

350Steam B 99 36 129 10 3

Hot Water B 99 36 138 10 3

400Steam B 119 35-3/4 78 11 3

Hot Water B 119 35-3/4 78 11 3

500Steam B 119 35-3/4 99 11 3

Hot Water B 119 35-3/4 99 11 3

600Steam B 119 35-3/4 131 11 3

Hot Water B 119 35-3/4 131 11 3

700 & 800Steam B 119 35-3/4 164 11 3

Hot Water B 119 35-3/4 164 11 3

NOTE: A, B and C dimens ions may vary by 1/2 inch.

BOILER BOOK CBLE PERFORMANCE DATA

24

PERFORMANCE DATAThe Low Emission Option provides NOx reduction at current published and predicted fuel-to-steamefficiencies.

Specifying Boiler Efficiency

Cleaver-Brooks offers an industry leading fuel-to-steam boiler efficiency guarantee for Model CB-LEFiretube Boilers. The guarantee is based on the fuel-to-steam efficiencies shown in the efficiencytables and the following conditions. The efficiency percent number is only meaningful if the specificconditions of the efficiency calculations are clearly stated in the specification (see Cleaver-Brookspublication CB-7768 for a detailed description of efficiency calculations).

When specifying the efficiencies in the tables, be sure to include the specific guarantee conditions tomaximize the effectiveness of your efficiency specification. If you have any questions regarding theefficiency specifications, please contact your local Cleaver-Brooks authorized representative.

Efficiency Specification

The boiler manufacturer shall guarantee that, at the time of startup, the boiler will achieve fuel-to-steam efficiency (see Tables 10 and 11) at 100% firing rate (add efficiency guarantees at 25%,50%, and 75% of rating, if required). If the boiler(s) fail to achieve the corresponding guaranteedefficiency as published, the boiler manufacturer will rebate, to the ultimate boiler owner, tenthousand dollars ($10,000) for every full efficiency point (1.0%) that the actual efficiency is belowthe guaranteed level.

The specified boiler efficiency is based on the following conditions.

1. Fuel specification used to determine boiler efficiency:

• Natural Gas

Carbon,% (wt) = 69.98Hydrogen,% (wt) = 22.31Sulfur,% (wt) = 0.0Heating value, Btu/lb. = 21,830

• No. 2 Oil


No. 6 Oil


2. Efficiencies are based on ambient air temperature of 80 °F, relative humidity of 30%, and 15% excess air in the exhaust flue gas.

3. Efficiencies are based on manufacturer’s published radiation and convection losses. (For Cleaver-Brooks radiation and convection losses, see Boiler Efficiency Facts Guide, publication number CB-7767).

4. Any efficiency verification testing will be based on the stack loss method.

For efficiencies and stack temperatures at operating pressures not listed, follow these procedures:


25

When the operating steam pressure is between 10 psig and 125 psig, interpolate the values from theefficiency tables.

When the operating steam pressure is above 125 psig, estimated efficiency can be calculated asfollows:

Example:

Boiler: 350 hp.

Fuel: natural gas.

Operating steam pressure: 200 psig.

Find the fuel-to-steam efficiency at 100% firing rate. From Table 10 for a 350 hp boiler operating at100% firing rate and an operating steam pressure of 125 psig, the efficiency is 82.5%.

Using Figure 12, note that the stack temperature increases 36 °F at the higher operating pressure. Toestimate boiler efficiency, use this rule of thumb: For every 40 °F increase in stack temperature,efficiency decreases by 1%. Since the stack temperature rise is 36 °F, the decrease in the boilerefficiency at 200 psig operating pressure is calculated as follows: 36/40 =.9%. Therefore, the boilerefficiency at 200 psig operating pressure is 82.5 -.9 = 81.6%

Emissions

The emission data included in this section consists of typical emission levels for Model CB boilersequipped with 60, 30, 25, and 20 ppm LE Options when firing natural gas and No. 2 oil.

The data in Table 12 and Table 13 represent typical emission levels only. Guaranteed emission levelsare available from your local Cleaver-Brooks authorized representative.

Table 10. Predicted Fuel-to-Steam Efficiencies - Natural Gas

BOILERHP

OPERATING PRESSURE = 10 ps ig OPERATING PRESSURE = 125 ps ig

% OF LOAD % OF LOAD

25% 50% 75% 100% 25% 50% 75% 100%

125 83.3 83.6 83.4 83.2 80.4 80.9 81.0 81.0

150 84.4 84.6 84.5 84.3 81.5 82.0 82.0 82.1

200 85.0 85.3 85.1 84.9 82.2 82.7 82.7 82.7

250 85.0 84.7 84.0 83.3 82.0 82.0 81.6 81.3

300 85.3 85.3 84.6 83.9 82.6 82.7 82.2 81.9

350 85.3 85.7 85.2 84.5 82.6 83.2 82.8 82.5

400 84.5 84.7 84.6 84.4 81.8 82.2 82.4 82.2

500 85.5 85.7 85.5 85.2 82.8 83.2 83.3 83.1

600 85.7 86.0 85.8 85.6 82.9 83.5 83.6 83.5

700 85.7 86.2 86.0 85.7 83.0 83.6 83.6 83.6

800 85.8 86.1 85.9 85.6 83.1 83.6 83.7 83.5


26

Table 11. Predicted Fuel-to-Steam Efficiencies - No. 2 Oil

BOILERHP

OPERATING PRESSURE = 10 ps ig OPERATING PRESSURE = 125 ps ig

% OF LOAD % OF LOAD

25% 50% 75% 100% 25% 50% 75% 100%

125 86.7 86.9 86.7 86.6 83.7 84.2 84.3 84.3

150 87.8 88.0 87.8 87.6 84.8 85.3 85.3 85.4

200 88.4 88.7 88.4 88.2 85.6 86.0 86.0 86.0

250 88.3 88.1 87.4 86.7 85.3 85.3 84.9 84.7

300 88.6 88.7 88.0 87.3 85.9 86.0 85.5 85.2

350 88.6 89.0 88.5 87.8 85.9 86.6 86.1 85.8

400 87.9 88.1 87.9 87.6 85.1 85.5 85.6 85.5

500 88.9 89.0 88.9 88.6 86.1 86.5 86.6 86.4

600 89.0 89.4 89.2 89.0 86.2 86.8 86.9 86.8

700 89.1 89.5 89.3 89.1 86.3 86.9 87.0 86.9

800 89.2 89.5 89.3 89.0 86.4 86.9 87.0 86.8

Figure 12. Predicted stack temperature increase for pressure > 125 psig

BOILER BOOK CBLE ENGINEERING DATA

27

ENGINEERING DATA Sound Level

Table 14 gives a summary of predicted sound pressure levels for Model CB boilers with 30 ppm LEOptions. Contact your local Cleaver-Brooks authorized representative for sound levels or other LEOptions.

Units - The units for the sound level tables are dbA (decibels, measured on the A-weighted scale) inreference to 0.0002 microbars (20 micro-Newtons per square meter). Their reference are standardlyused in specifying and reporting sound pressure levels on industrial equipment.

Test Method - The sound pressure levels in the above tables were obtained from tests in accordancewith the “ABMA Test Code for the Measurement of Sound from Packaged Boilers”. In accordancewith this code the sound pressure levels reported were measured on the boiler centerline 4-1/2 feetvertically above the bottom of the base rails and 3 feet horizontally in front of the end of the blower

Table 12. CBLE Boilers - Natural Gas, Emission Levels

POLLUTANTESTIMATED LEVEL

60 ppm 30 ppm 20 ppm 15 ppm 9 ppm

CO ppmA

lb./MMBtu50/150B

0.04/0.1150/150B

0.04/0.1150/150B

0.04/0.1150

0.0450

0.04

NOx ppmA

lb/MMBtu60

0.0730

0.03520

0.02415

0.0189

0.011

SOx ppmA

lb/MMBtu1

0.0011

0.0011

0.0011

0.0011

0.001

HC/VOC5ppmA

lb/MMBtu10

0.00410

0.00410

0.00410

0.00410

0.004

PM ppmA

lb/MMBtu-

0.01-

0.01-

0.01-

0.01-

0.01

A. ppm leve ls a re given on a dry volume bas is and corrected to 3% oxygen (15% excess a ir).B. CO emiss ion for 60, 30, 25 & 20 ppm sys tem is 50 ppm (0.04 lb/MMBtu) when boile r is opera ting above 50% of ra ted capacity. CO emiss ion is 150 ppm (0.11 lb/MMBtu) when boile r is opera ting be low 50% of ra ted capacity.

Table 13. CBLE Boilers - No. 2 Oil, Emission Levels

POLLUTANTESTIMATED LEVEL

60 ppm LE Option 30, 20 ppm LE Option 15 ppm 9 ppm

CO ppmA

lb/MMBtu50

0.03950

0.03950

0.03950

0.039

NOx ppmA

lb/MMBtu140

0.18690

0.12085

0.11370

0.093

SOx ppmA

lb/MMBtu2780.52

2780.52

2780.52

2780.52

HC/VOCs ppmA

lb/MMBtu4

0.0024

0.0024

0.0024

0.002

PM ppmA

lb/MMBtu-

0.025-

0.025-

0.025-

0.025

A. ppm leve ls a re given on a dry volume bas is and corrected to 3% oxygen (15% excess a ir).BASED ON THE FOLLOWING CONSTITUENT LEVELS:

Fuel-bound Nitrogen content = 0.015% by weight.Sulfur content = 0.5% by weight.Ash content = 0.01% by weight.


28

motor or front surface of the electrical cabinet.

Sound Level Meter - The sound level meter used complies with ANSI S1.4, Type 1 (Precision). Thereadings are taken with the meter set for slow response and corrected for background levels.

Sound Pressure - The large size boilers, the need for auxiliary equipment, and the necessaryinterconnecting piping make it impractical (and sometimes impossible) to provide a boiler testingenvironment which is suitable for taking the data needed to develop Sound Pressure Power levels.

Typical Values - Sound pressure levels (dbA) for the same boiler will vary between boiler rooms. Soundlevels will vary with motor type, NOx levels, and altitudes. In addition, variations will occur betweendifferent people using different sound meters on the same boiler. And finally, no two boilers can beexpected to give precisely the same sound levels. For these reasons, we can only predict, but notguarantee, sound levels (dbA).

Table 14. CBLE Predicted Sound Levels 30 ppm NOx Systems

BOILER HP 125 150 200 250 300 350 400 500 600 700 800

HFO, dbA 84 84 84 83 84 85 84 85 85 88 90

LFO, dbA 82 82 83 81 82 83 82 83 83 84 89

HFG, dbA 82 82 83 82 83 84 83 83 85 87 90

LFG, dbA 81 81 82 81 82 83 81 81 82 84 88

NOTES1. Sound pressure levels measured on boilers operating in various locations and expressed in dbA are asshown:2. Based on standard altitude fans and fan motors, 60 Hz.3. Contact your local Cleaver-Brooks authorized representative for sound levels of 60 or 20 ppm LE Op-tions.

ABBREVIATIONS: HF = High Fire LF = Low Fire O = Oil G = Gas

Table 15. Standard, Undersize, and Oversize Gas Trains

CBLE

BOILER HP GAS TRAIN SIZE

UPSTREAM VALVE*

DOWNSTREAM VALVE*

EMISSIONS LEVEL 09 ppm 15 ppm 20 ppm 30 ppm 60 ppm UC

125 HP 1.5 in BB BB 3.3 - 4.9 psi 3.3 - 4.9 psi 0.8 - 5.0 psi 0.7 - 5.0 psi 0.7 - 5.0 psi 0.7 - 5.0 psi125 HP 1.5 in PC PC 3.4 - 5.0 psi 3.4 - 5.0 psi 0.9 - 5.0 psi 0.8 - 5.0 psi 0.8 - 5.0 psi 0.8 - 5.0 psi125 HP 2.0 in BB BB 3.1 - 3.3 psi 3.1 - 3.3 psi 0.6 - 0.8 psi 0.6 - 0.7 psi 0.5 - 0.7 psi 0.5 - 0.7 psi125 HP 2.0 in PC PC 3.1 - 3.4 psi 3.1 - 3.4 psi 0.6 - 0.9 psi 0.6 - 0.8 psi 0.6 - 0.8 psi 0.5 - 0.8 psi125 HP 2.5 in PC PC 3.0 - 3.1 psi 3.0 - 3.1 psi 0.4 - 0.6 psi 0.4 - 0.6 psi 0.4 - 0.5 psi 0.4 - 0.5 psi125 HP 3.0 in PC PC 2.9 - 3.0 psi 2.9 - 3.0 psi 0.4 - 0.4 psi 0.4 - 0.4 psi 0.4 - 0.4 psi 0.3 - 0.4 psi125 HP 4.0 in PC PC 2.9 - 2.9 psi 2.9 - 2.9 psi 0.4 - 0.4 psi 0.3 - 0.4 psi 0.3 - 0.4 psi 0.3 - 0.3 psi


200 HP 1.5 in BB BB 4.6 - 6.9 psi 5.0 - 7.5 psi 1.6 - 5.0 psi 1.5 - 5.0 psi 1.5 - 5.0 psi200 HP 1.5 in PC PC 4.8 - 7.2 psi 5.2 - 7.8 psi 1.8 - 5.0 psi 1.7 - 5.0 psi 1.7 - 5.0 psi


29

200 HP 2.0 in BB BB 4.1 - 4.6 psi 4.5 - 5.0 psi 1.0 - 1.6 psi 1.0 - 1.5 psi 1.0 - 1.5 psi200 HP 2.0 in PC PC 4.1 - 4.8 psi 4.5 - 5.2 psi 1.1 - 1.8 psi 1.1 - 1.7 psi 1.0 - 1.7 psi200 HP 2.5 in PC PC 3.8 - 4.1 psi 4.2 - 4.5 psi 0.7 - 1.0 psi 0.7 - 1.0 psi 0.6 - 1.0 psi200 HP 3.0 in PC PC 3.6 - 3.8 psi 4.0 - 4.2 psi 0.6 - 0.7 psi 0.5 - 0.7 psi 0.5 - 0.6 psi200 HP 4.0 in PC PC 3.6 - 3.6 psi 4.0 - 4.0 psi 0.5 - 0.6 psi 0.5 - 0.5 psi 0.4 - 0.5 psi


300 HP 1.5 in - 2.0 in BB BB 5.5 - 8.3 psi 5.7 - 8.5 psi 3.0 - 5.0 psi 3.0 - 3.6 psi 3.0 - 3.5 psi 3.0 - 3.5 psi300 HP 1.5 in - 2.0 in PC PC 5.8 - 8.7 psi 6.0 - 9.0 psi 3.3 - 5.0 psi 3.3 - 3.7 psi 3.3 - 3.6 psi 3.3 - 3.6 psi300 HP 2.0 in BB BB 4.6 - 5.5 psi 4.7 - 5.7 psi 2.1 - 3.0 psi 2.1 - 3.0 psi 2.0 - 3.0 psi 2.0 - 3.0 psi300 HP 2.0 in PC PC 4.7 - 5.8 psi 4.8 - 6.0 psi 2.2 - 3.3 psi 2.2 - 3.3 psi 2.1 - 3.3 psi 2.1 - 3.3 psi300 HP 3.0 in PC PC 3.9 - 4.6 psi 4.0 - 4.7 psi 1.3 - 2.1 psi 1.3 - 2.1 psi 1.2 - 2.0 psi 1.2 - 2.0 psi300 HP 4.0 in PC PC 3.7 - 3.9 psi 3.9 - 4.0 psi 1.1 - 1.3 psi 1.1 - 1.3 psi 1.0 - 1.2 psi 1.0 - 1.2 psi

350 HP 1.5 in - 2.0 in BB BB 6.4 - 9.0 psi 6.2 - 9.0 psi 4.2 - 5.0 psi 4.2 - 5.0 psi 4.1 - 5.0 psi 4.1 - 5.0 psi350 HP 1.5 in - 2.0 in PC PC 6.8 - 9.0 psi 6.6 - 9.0 psi 4.6 - 5.0 psi 4.6 - 5.0 psi 4.5 - 5.0 psi 4.5 - 5.0 psi350 HP 2.0 in BB BB 5.4 - 6.4 psi 5.3 - 6.2 psi 3.2 - 4.2 psi 3.2 - 4.2 psi 3.2 - 4.1 psi 3.1 - 4.1 psi350 HP 2.0 in PC PC 5.6 - 6.8 psi 5.4 - 6.6 psi 3.4 - 4.6 psi 3.4 - 4.6 psi 3.3 - 4.5 psi 3.3 - 4.5 psi350 HP 2.5 in PC PC 4.3 - 5.4 psi 4.2 - 5.3 psi 2.1 - 3.2 psi 2.1 - 3.2 psi 2.0 - 3.2 psi 2.0 - 3.1 psi350 HP 3.0 in PC PC 4.0 - 4.3 psi 3.8 - 4.2 psi 1.7 - 2.1 psi 1.7 - 2.1 psi 1.7 - 2.0 psi 1.6 - 2.0 psi350 HP 4.0 in PC PC 3.7 - 4.0 psi 3.6 - 3.8 psi 1.5 - 1.7 psi 1.5 - 1.7 psi 1.4 - 1.7 psi 1.4 - 1.6 psi

400 HP 1.5 in - 2.0 in BB BB 6.9 - 9.0 psi 6.9 - 9.0 psi 4.6 - 5.0 psi 4.6 - 5.0 psi 4.5 - 5.0 psi 4.5 - 5.0 psi400 HP 1.5 in - 2.0 in PC PC 7.4 - 9.0 psi 7.5 - 9.0 psi 5.1 - 8.7 psi 5.1 - 7.7 psi 5.1 - 7.7 psi 5.1 - 7.7 psi400 HP 2.0 in BB BB 5.5 - 6.9 psi 5.6 - 6.9 psi 3.2 - 4.6 psi 3.2 - 4.6 psi 3.2 - 4.5 psi 3.2 - 4.5 psi400 HP 2.0 in PC PC 5.7 - 7.4 psi 5.8 - 7.5 psi 3.4 - 5.0 psi 3.4 - 5.0 psi 3.4 - 5.0 psi 3.4 - 5.0 psi400 HP 2.5 in PC PC 4.1 - 5.5 psi 4.2 - 5.6 psi 1.8 - 3.2 psi 1.8 - 3.2 psi 1.8 - 3.2 psi 1.8 - 3.2 psi400 HP 3.0 in PC PC 3.7 - 4.1 psi 3.8 - 4.2 psi 1.3 - 1.8 psi 1.3 - 1.8 psi 1.3 - 1.8 psi 1.3 - 1.8 psi400 HP 4.0 in PC PC 3.4 - 3.7 psi 3.5 - 3.8 psi 1.1 - 1.3 psi 1.0 - 1.3 psi 1.0 - 1.3 psi 1.0 - 1.3 psi

500 HP 2.0 in - 2.5 in BB PC 5.8 - 7.6 psi 5.8 - 7.6 psi 4.6 - 5.0 psi 4.6 - 5.0 psi 4.5 - 5.0 psi 4.5 - 5.0 psi500 HP 2.0 in - 2.5 in PC PC 6.0 - 8.3 psi 6.0 - 8.3 psi 4.8 - 5.0 psi 4.7 - 5.0 psi 4.7 - 5.0 psi 4.7 - 5.0 psi500 HP 2.5 in PC PC 3.9 - 5.8 psi 3.9 - 5.8 psi 2.7 - 4.6 psi 2.7 - 4.6 psi 2.7 - 4.5 psi 2.6 - 4.5 psi500 HP 3.0 in PC PC 3.3 - 3.9 psi 3.3 - 3.9 psi 2.0 - 2.7 psi 2.0 - 2.7 psi 2.0 - 2.7 psi 2.0 - 2.6 psi500 HP 4.0 in PC PC 2.8 - 3.3 psi 2.8 - 3.3 psi 1.6 - 2.0 psi 1.6 - 2.0 psi 1.5 - 2.0 psi 1.5 - 2.0 psi

600 HP 2.0 in - 2.5 in BB PC 8.0 - 9.0 psi 8.0 - 9.0 psi 6.5 - 9.0 psi 6.5 - 9.0 psi 6.4 - 8.9 psi 6.3 - 8.8 psi600 HP 2.0 in - 2.5 in PC PC 8.2 - 9.0 psi 8.2 - 9.0 psi 6.7 - 10.0 psi 6.7 - 10.0 psi 6.6 - 9.9 psi 6.6 - 9.9 psi600 HP 2.5 in PC PC 5.4 - 8.0 psi 5.4 - 8.0 psi 3.9 - 5.0 psi 3.8 - 5.0 psi 3.8 - 5.0 psi 3.7 - 5.0 psi600 HP 2.5 in - 3.0 in PC PC 5.2 - 5.4 psi 5.2 - 5.4 psi 3.7 - 3.9 psi 3.6 - 3.8 psi 3.5 - 3.8 psi 3.5 - 3.7 psi600 HP 3.0 in PC PC 4.3 - 5.2 psi 4.3 - 5.2 psi 2.8 - 3.7 psi 2.7 - 3.6 psi 2.7 - 3.5 psi 2.6 - 3.5 psi600 HP 4.0 in PC PC 3.7 - 4.3 psi 3.7 - 4.3 psi 2.2 - 2.8 psi 2.1 - 2.7 psi 2.0 - 2.7 psi 2.0 - 2.6 psi

700 HP 2.0 in - 3.0 in BB PC 11.0 - 15.0 psi 10.7 - 15.0 psi 8.7 - 13.1 psi 8.6 - 13.0 psi 8.6 - 12.9 psi 8.6 - 12.8 psi700 HP 2.0 in - 3.0 in PC PC 11.3 - 15.0 psi 11.0 - 15.0 psi 9.0 - 13.5 psi 8.9 - 13.4 psi 8.9 - 13.4 psi 8.9 - 13.3 psi700 HP 2.5 in - 3.0 in PC PC 7.1 - 9.0 psi 6.8 - 9.0 psi 4.8 - 5.0 psi 4.7 - 5.0 psi 4.7 - 5.0 psi 4.6 - 5.0 psi700 HP 3.0 in PC PC 6.0 - 7.1 psi 5.7 - 6.8 psi 3.6 - 4.8 psi 3.6 - 4.7 psi 3.5 - 4.7 psi 3.5 - 4.6 psi700 HP 4.0 in PC PC 5.1 - 6.0 psi 4.8 - 5.7 psi 2.8 - 3.6 psi 2.7 - 3.6 psi 2.7 - 3.5 psi 2.6 - 3.5 psi

800 HP 2.0 in - 3.0 in BB PC 10.8 - 15.0 psi 10.7 - 15.0 psi 10.6 - 15.0 psi800 HP 2.0 in - 3.0 in PC PC 11.2 - 15.0 psi 11.1 - 15.0 psi 11.0 - 15.0 psi

Table 15. Standard, Undersize, and Oversize Gas Trains (Continued)

CBLE


UPSTREAM VALVE*

DOWNSTREAM VALVE*



30

* BB = Butter Ball; PC = Plug Cock

NOTE: In cases where the gas train increases in size after the regulating valve, two diameters are listed. The first number is the customer connection size.

800 HP 2.5 in - 3.0 in PC PC 6.1 - 9.0 psi 6.0 - 10.0 psi 5.9 - 10.0 psi800 HP 3.0 in PC PC 4.8 - 6.1 psi 4.7 - 5.0 psi 4.6 - 5.0 psi800 HP 4.0 in PC PC 3.5 - 4.8 psi 3.4 - 4.7 psi 3.4 - 4.6 psi

Standard Gas Train size is highlighted

Table 16. Minimum required regulated gas pressure altitude conversionALTITUDE

(FT)CORRECTION

FACTORALTITUDE

(FT)CORRECTION

FACTOR

1000 1.04 6000 1.25

2000 1.07 7000 1.30

3000 1.11 8000 1.35

4000 1.16 9000 1.40

5000 1.21 - -

To obta in minimum required gas pressure a t a ltitudes above 700 fee t, multiply the pressure by the lis ted factors : Inches WC x 0.577 = oz/sq-in. Oz/sq-in x 1.732 = Inches WCInches WC x 0.0361= ps ig. Oz/sq-in x 0.0625 = ps ig.Ps ig x 27.71 = Inches WC Ps ig x 16.0 = Oz/sq-in.

Table 17. Maximum Gas Consumption (CFH) for Natural Gas and Propane Vapor

BOILER HP

TYPE OF GAS AND HEAT CONTENT

NATURAL GAS1000 (Btu/cu-ft)

PROPANE GAS2550 (Btu/cu-ft)

125 5103 2000

150 6124 2402

200 8165 3202

250 10206 4002

300 12247 4802

350 14280 5600

400 16329 6404

500 20415 8006

600 24494 9605

700 28576 11206

800 32659 12807

Table 15. Standard, Undersize, and Oversize Gas Trains (Continued)

CBLE


UPSTREAM VALVE*

DOWNSTREAM VALVE*



31

Figure 13. Standard Gas Train Connection Size and Location

Stack Support Capabilities

All standard Cleaver-Brooks Firetube Boilers with an LE option can support up to 2,000 lbs withoutadditional support.

LE Boilers 250 hp through 800 hp can be reinforced to support 3,000 lbs.

Stack/Breeching Size Criteria

The design of the stack and breeching must provide the required draft at each boiler flue gas outlet.Proper draft is critical to burner performance.

Although constant pressure at the flue gas outlet of the Model CB-LE is not required, it is necessaryto size the stack/breeching to limit flue gas pressure variation. The allowable pressure range is –0.25"W.C. to +0.25" W.C.

For additional information, please review Section I4, General Engineering Data (Stacks) and SectionF, Stacks. Stack and breeching sizes should always be provided by a reputable stack supplier whowill design the stack and breeching system based on the above criteria. Your local Cleaver-Brooksauthorized representative is capable of assisting in your evaluation of the stack/breeching design.

Boiler Room Combustion Air

When determining boiler room air requirements, the size of the room, air flow, and velocity of airmust be reviewed as follows:

1. Size (area) and location of air supply openings in boiler room. A. Two (2) permanent air supply openings in the outer walls of the boiler room are

recommended. Locate (1) at each end of the boiler room, preferably below a height of 7 feet.This allows air to sweep the length of the boiler.

B. Air supply openings can be louvered for weather protection, but they should not be coveredwith fine mesh wire, as this type of covering has poor air flow qualities and is subject toclogging by dust or dirt.

C. A vent fan in the boiler room is not recommended, as it could create a slight vacuum undercertain conditions and cause variations in the quantity of combustion air. This can result inunsatisfactory burner performance.

D. Under no condition should the total area of the air supply openings be less than (1) squarefoot.

E. Size the openings by using the formula: Area (sq-ft) = CFM/FPM

BOILERHP

MODEL CB

CONNECTION SIZE

(IN. NPT)

LOCATION DIMENSION

“A” (IN.)

125-200 1-1/2 52

250-350 2 56

400 2 58

500 2-1/2 60

600 2-1/2 - 3 71

700-800 3 65


32

2. Amount of air required (cfm). A. Combustion Air = Rated bhp x 8 cfm/bhp. B. Ventilation Air = Maximum bhp x 2 cfm/bhpC. Total recommended air = 10 cfm/bhp - up to 1000 feet elevation. Add 3 percent more per

1000 feet of added elevation. 3. Acceptable air velocity in Boiler Room (fpm).

A. From floor to (7) foot height - 250 fpm B. Above (7) foot height - 500 fpm

Example: Determine the area of the boiler room air supply openings for (1) 300 hp boiler at 800 feetaltitude. The air openings are to be 5 feet above floor level.

• Air required: 300 x 10 = 3000 cfm (from 2B above). • Air velocity: Up to 7 feet = 250 fpm (from 3 above). • Area Required: Area = cfm = 3000/250 = 12 sq-ft total. • Area/Opening: 12/2 = 6 sq-ft/opening (2 required).

Consult local codes, which may supersede these requirements.


33

Figure 14. Typical Gas Piping Layout

This figure illustrates the basic gas valve arrangement on Cleaver-Brooks Model CB boiler and shows thecontractor's connection point. The valves and controls between the contractor connection point and the gasmain in the street are representative of a typical installation. Actual requirements may vary depending on localcodes or local gas company requirements which should be investigated prior to preparation of specificationsand prior to construction.

A. Utilities service valve.B. Utilities service regulator.C. Gas meter.D. Piping from meter to boiler.

The size of the gas line from the meter to the gas pressure regulator at the boiler can be very important if gas pressures are marginal. The gas line sizing is dependent on:

1. Gas pressure at outlet of gas meter (C)2. Rate of gas flow required, CFH3. Length of pipe run (D)4. Pressure required at contractor connection point.

The local gas utility will advise the pressure that is available at the outlet of their meter.


34

Figure 15. Model CBLE Gas Train Components

Figure 16. No.2 Oil Connection Size, Location, and Recommended Line Sizes

56

S

13

42

PILOT GAS LINE

S

S

MAIN GAS LINE

M MTo

BurnerGasSupply

11

10

97

12 13814 15

FLOWFLOW

BOILER HP

SUPPLY AND RETURN

CONN SIZES (IN. NPT)

A(IN.)

RECOMMENDED OIL LINEA

SIZES (STANDARD PIPE)

(IN. - IPS)

STORAGE TANK TO BOILER

OR PUMP CONNECT

PUMP TO

BOILER

RETURN LINE TO

TANK

125 150 200

3/4 12-1/2 1 1 1

250 300350

3/4 34 1 1 1

400 500600

3/4 11-3/4 1 1 1

700800 1 11-3/4 1 1 1

NOTE: See No. 2 Oil Line S izing Ins truction for sys tems with other condi-tions .A. For suction line condition with a maximum of 10 ft of lift and a tota l of 100 ft of suction line .


35

Figure 17. No. 2 Oil Piping, Single Boiler Installation, Remote Oil Pump

Figure 18. No. 2 Oil Piping, Multiple Boiler Installation, Remote Oil Pumps


36

Figure 19. No. 2 Oil Piping, Multiple Boiler Installation


37

Figure 20. No. 2 Oil Piping Typical Arrangement

Table 18. Blowdown Tank Sizing

BOILER HP WATER (GAL)

125 97

150 118

200 145

250 146

300 176

350 210

400 177

500 209

600 250

700, 800 296

NOTE: Quantity of wate r removed from boile r by lowering normal wate r line 4".


38

Table 19. Heating Surface

BOILER HP

HEATING SURFACE (SQ-FT)

FIRESIDE WATERSIDE

125 625 679

150 750 820

200 1000 1092

250 1250 1346

300 1500 1623

350 1750 1932

400 2000 2151

500 2500 2691

600 3000 3262

700, 800 3500 3810

Table 20. Steam Volume and Disengaging Area

BOILER HPSTEAM VOLUME CU-FT STEAM DISENGAGING AREA

SQ-IN

HIGH PRESSUREA LOW PRESSUREB HIGH PRESSUREA LOW PRESSUREB

125 25.4 36.6 5371 5887

150 30.7 44.3 6511 7138

200 37.7 54.4 7985 8752

250 49.2 70.6 7980 8695

300 59.5 85.3 9651 10516

350 70.9 101.7 11507 12538

400 72.1 97.9 9793 10593

500 83.7 113.7 11376 12303

600 101.5 137.8 13787 14911

700-800 119.8 162.7 16273 17600

NOTE: Based on normal wate r leve l.A. Based on 150 ps ig des ign pressure .B. Based on 15 ps ig des ign pressure .


39

Table 21. Recommended Steam Nozzle Size (for 4000 to 5000 fpm nozzle velocity)

Boiler HP

OPERATING PRES-SURE PSIG 125 150 200 250 300 350 400 500 600 700 800

15 8 8 10 10 12 12 12 12 12 12 12

30 6 6 8 8 8 10 10 10 12 12 12

40 6 6 6 8 8 8 10 10 10 12 12

50 6 6 6 6 8 8 8 10 10 10 12

75 4 4 6 6 6 8 8 8 8 10 10

100 4 4 6 6 6 6 6 8 8 8 10

125 4 4 4 6 6 6 6 8 8 8 8

150 3 3 4 4 6 6 6 6 6 8 8

200 2.5 3 4 4 4 4 6 6 6 6 6

250 2.5 3 3 4 4 4 4 6 6 6 6

NOTES: 1. Steam nozzle sizes given in inches.2. Recommended steam nozzle sizes based on 4000 to 5000 fpm steam velocity. 3. All standard steam nozzle sizes for 150 psig design pressure or greater are the same as 125 psig operating pressure on the above table.To increase or decrease the standard size, request the change with your local Cleaver-Brooks authorized representative.4. Shaded area denotes special surge load baffles must be installed to avoid possible water carry-over.5. For incremental operating pressures contact your local Cleaver-Brooks authorized representative.

Table 22. Recommended Non-Return Valve Size

BOILER HP BOILER CAPACITY (LBS/HR)

OPERATING PRESSURE (PSIG)

50 75 100 125 150 175 200 250

100 3450 2-1/2 2-1/2 NA NA NA NA NA NA

125 4313 3 2-1/2 2-1/2 2-1/2 NA NA NA NA

150 5175 3 3 2-1/2 2-1/2 2-1/2 2-1/2 NA NA

200 6900 3* 3 3 3 3 2-1/2 2-1/2 2-1/2

250 8625 4 3* 3 3 3 3 3 3

300 10350 4 4 4 3* 3 3 3 3

350 12025 4 4 4 4 4 3* 3 3

400 13800 5 4 4 4 4 4 4 3*

500 17210 6 5 5 4 4 4 4 4

600 20700 6 6 5 5 5 4 4 4

700 24150 6 6 6 5 5 5 5 4

800 27600 6 6 6 6 6 5 5 5

NOTE: Valve sizes (300 # Flanges) given in inches.Standard Non-Return valve selections limited to a maximum 2 to 1 turndown (50% of full load); selections based on typical non-returnvalve sizing recommendations. For final valve selection contact your C-B authorized representative.* Indicates pressure drop of less than 7.5 psig. All other selections are less than 6 psig pressure drop.


40

1. Shortest boiler room length (Dwg A) is obtained by allowing for possible future tube replacement (from front or rear ofboiler) through a window or doorway. Allowance is only made for minimum door swing at each end of the boiler. Thisarrangement provides sufficient aisle space at the front of the boiler but a “tight” space condition at the rear.If space permits, approximately 1.5 additional feet should be allowed at the rear for additional aisle and working space.2. Next shortest boiler room length (Dwg B) is obtained by allowing for possible future tube replacement from the front ofthe boiler. Allowance is only made for minimum door swing at the rear.If space permits, approximately 1.5 additional feet should be allowed at the rear for additional aisle and working space.3. A slightly longer boiler room (Dwg C) is obtained by allowing for possible future tube replacement from the rear of theboiler. Allowance for door swing at the front provides sufficient aisle and working space at the front.

Figure 22. Boiler Room Width (Typical Layout)

Figure 21. Boiler Room Length (Typical Layouts)

BOILER HP 125-200 250-350 400-800

Dimens ion A 82" 93" 102"

Dimens ion B 115" 141" 171"

NOTES: 1. Recommended Minimum Dis tance Between Boile r and Wall. Dimen-

s ion “A” a llows for a “clear” 42" a is le be tween the wate r col-umn on the boile r and the wall. If space permits , this a is le should be widened.

2. Recommended Minimum Dis tance Between Boile rs .Dimens ion “B” be tween boile rs a llows for a “clear” a is le of:42" - 125 -200 hp48" - 250-350 hp60" - 400-800 hpIf space permits , this a is le should be widened.


41

Figure 23. Breeching Arrangement

BOILER BOOK CBLE

e-mail: [email protected] Address: http://www.cleaverbrooks.com

Appendix H

AERMOD Output Results – Predicted Concentrations

by Pollutant and Scenarios

Appendix H - AERMOD Output Results

Table H-1 Summary by Pollutant

Pollutant

Averaging

Period Scenario Max @ Fence

Max @

Resident

Background

(µg/m3) Max @ Fence

Max @

Resident NAAQS (µg/m3)

Existing 164 110 Included 164 110 188

1A 198 183 Included 198 183 188

1B 205 184 Included 205 184 188

1C 198 184 Included 198 184 188

2A 195 164 Included 195 164 188

2B 195 164 Included 195 164 188

3A 164 110 Included 164 110 188

3B 164 110 Included 164 110 188

Existing 0.34 0.08 21 21 21 100

1A 30 8 21 51 29 100

1B 28 7 21 49 28 100

1C 27 7 21 48 28 100

2A 9 6 21 30 27 100

2B 9 5 21 30 26 100

3A 2 1.00 21 23 22 100

3B 3 3 21 24 24 100

Existing 1.64 0.89 20 22 21 35

1A 27 7 20 47 27 35

1B 30 10 20 50 30 35

1C 27 8 20 47 28 35

2A 15 8 20 35 28 35

2B 15 8 20 35 28 35

3A 6 3 20 26 23 35

3B 6 3 20 26 23 35

Existing 0.04 0.01 9 9 9 12

1A 9 2 9 18 11 12

1B 8 2 9 17 11 12

1C 8 2 9 17 11 12

2A 3 2 9 12 11 12

2B 2 2 9 12 11 12

3A 1 0.3 9 10 10 12

3B 1 1 9 10 10 12

Existing 2.2 1.46 29 31 30 150

1A 31 10 29 60 39 150

1B 38 13 29 67 42 150

1C 31 10 29 60 39 150

2A 32 14 29 61 43 150

2B 27 12 29 56 41 150

3A 12 5 29 41 34 150

3B 12 5 29 41 34 150

Existing 32 14 21 53 35 196

1A 32 14 21 53 35 196

1B 55 32 21 76 53 196

1C 56 19 21 77 40 196

2A 32 14 21 53 35 196

2B 55 31 21 76 52 196

3A 55 31 21 76 52 196

3B 55 31 21 76 52 196

PM10 24-Hr

SO2 1-Hr

Total Conc. (µg/m3)

1-HrNO2

NO2 Annual

PM2.5 24-Hr

PM2.5 Annual

Modeled Conc. (µg/m3)

Page H-1


Table H-1 Summary by Pollutant

Pollutant

Averaging

Period Scenario Max @ Fence

Max @

Resident

Background


Max @


Total Conc. (µg/m3)Modeled Conc. (µg/m

3)

Existing 2 1.00 13 15 14 366

1A 2 1.00 13 15 14 366

1B 36 12 13 49 25 366

1C 28 4 13 41 17 366

2A 2 1.00 13 15 14 366

2B 30 11 13 43 24 366

3A 30 11 13 43 24 366

3B 30 11 13 43 24 366

Existing 0.01 0.010 3 3 3 78

1A 0.27 0.08 3 3 3 78

1B 0.42 0.25 3 3 3 78

1C 0.35 0.10 3 3 3 78

2A 0.10 0.05 3 3 3 78

2B 0.20 0.20 3 3 3 78

3A 0.28 0.28 3 3 3 78

3B 2 2 3 5 5 78

Existing 204 114 4,578 4,782 4,692 40,000

1A 836 839 4,578 5,414 5,417 40,000

1B 1,030 840 4,578 5,608 5,418 40,000

1C 836 839 4,578 5,414 5,417 40,000

2A 934 581 4,578 5,512 5,159 40,000

2B 934 581 4,578 5,512 5,159 40,000

3A 458 245 4,578 5,036 4,823 40,000

3B 396 245 4,578 4,974 4,823 40,000

Existing 28 16 2,289 2,317 2,305 10,000

1A 720 394 2,289 3,009 2,683 10,000

1B 1,030 870 2,289 3,319 3,159 10,000

1C 720 393 2,289 3,009 2,682 10,000

2A 699 338 2,289 2,988 2,627 10,000

2B 522 338 2,289 2,811 2,627 10,000

3A 309 149 2,289 2,598 2,438 10,000

3B 309 148 2,289 2,598 2,437 10,000

Existing 6 4 Not measured 6 4 Not applicable

1A 12 4 Not measured 12 4 Not applicable

1B 11 4 Not measured 11 4 Not applicable

1C 12 4 Not measured 12 4 Not applicable





VOC Annual

SO2 Annual

CO 1-Hr

CO 8-Hr

SO2 24-Hr

Page H-2


Table H-2 Summary by Scenario

Scenario Pollutant

Averaging

Period Max @ Fence

Max @

Resident

Background


Max @


1-Hr 204 114 4,578 4,782 4,692 40,000

8-Hr 28 16 2,289 2,317 2,305 10,000

1-Hr 164 110 Included 164 110 188

Annual 0.34 0.08 21 21 21 100

PM10 24-Hr 2.2 1.5 29 31 30 150

24-Hr 1.64 0.89 20 22 21 35

Annual 0.04 0.01 9 9 9 12

1-Hr 32 14 21 53 35 196

24-Hr 2.0 1.0 13 15 14 366

Annual 0.01 0.01 3 3 3 78

VOC Annual 6 4 Not measured 6 4 Not Applicable

1-Hr 836 839 4,578 5,414 5,417 40,000

8-Hr 720 394 2,289 3,009 2,683 10,000

1-Hr 198 183 Included 198 183 188

Annual 30 8 21 51 29 100

PM10 24-Hr 31 10 29 60 39 150

24-Hr 27 7 20 47 27 35

Annual 8.6 2.2 9 18 11 12

1-Hr 32 14 21 53 35 196

24-Hr 2.0 1.0 13 15 14 366

Annual 0.27 0.08 3 3 3 78


1-Hr 1,030 840 4,578 5,608 5,418 40,000

8-Hr 1,030 870 2,289 3,319 3,159 10,000

1-Hr 205 184 Included 205 184 188

Annual 28 7 21 49 28 100

PM10 24-Hr 38 13 29 67 42 150

24-Hr 30 10 20 50 30 35

Annual 7.8 2.1 9 17 11 12

1-Hr 55 32 21 76 53 196

24-Hr 36 12 13 49 25 366

Annual 0.42 0.25 3 3 3 78


1-Hr 836 839 4,578 5,414 5,417 40,000

8-Hr 720 393 2,289 3,009 2,682 10,000

1-Hr 198 184 Included 198 184 188

Annual 27 7 21 48 28 100

PM10 24-Hr 31 10 29 60 39 150

24-Hr 27 8 20 47 28 35

Annual 7.7 2.0 9 17 11 12

1-Hr 56 19 21 77 40 196

24-Hr 28 4 13 41 17 366

Annual 0.35 0.10 3 3 3 78


SO2

1C

CO

NO2

PM2.5

SO2

Modeled Conc. (µg/m3) Total Conc. (µg/m

3)

CO

NO2

PM2.5

SO2

Existing

1A

CO

NO2

PM2.5

SO2

1B

CO

NO2

PM2.5

Page H-3


Table H-2 Summary by Scenario

Scenario Pollutant

Averaging

Period Max @ Fence

Max @

Resident

Background


Max @


Modeled Conc. (µg/m3) Total Conc. (µg/m

3)

1-Hr 934 581 4,578 5,512 5,159 40,000

8-Hr 699 338 2,289 2,988 2,627 10,000

1-Hr 195 164 Included 195 164 188

Annual 9 6 21 30 27 100

PM10 24-Hr 32 14 29 61 43 150

24-Hr 15 8 20 35 28 35

Annual 2.7 1.7 9 12 11 12

1-Hr 32 14 21 53 35 196

24-Hr 2 1 13 15 14 366

Annual 0.10 0.05 3 3 3 78


1-Hr 934 581 4,578 5,512 5,159 40,000

8-Hr 522 338 2,289 2,811 2,627 10,000

1-Hr 195 164 Included 195 164 188

Annual 9 5 21 30 26 100

PM10 24-Hr 27 12 29 56 41 150

24-Hr 15 8 20 35 28 35

Annual 2.4 1.6 9 12 11 12

1-Hr 55 31 21 76 52 196

24-Hr 30 11 13 43 24 366

Annual 0.20 0.20 3 3 3 78


1-Hr 458 245 4,578 5,036 4,823 40,000

8-Hr 309 149 2,289 2,598 2,438 10,000

1-Hr 164 110 Included 164 110 188

Annual 2 1 21 23 22 100

PM10 24-Hr 12 5 29 41 34 150

24-Hr 6 3 20 26 23 35

Annual 1.0 0.3 9 10 10 12

1-Hr 55 31 21 76 52 196

24-Hr 30 11 13 43 24 366

Annual 0.28 0.28 3 3 3 78


1-Hr 396 245 4,578 4,974 4,823 40,000

8-Hr 309 148 2,289 2,598 2,437 10,000

1-Hr 164 110 Included 164 110 188

Annual 3 3 21 24 24 100

PM10 24-Hr 12 5 29 41 34 150

24-Hr 6 3 20 26 23 35

Annual 1.1 0.8 9 10 10 12

1-Hr 55 31 21 76 52 196

24-Hr 30 11 13 43 24 366

Annual 1.76 1.78 3 5 5 78


3B

CO

NO2

PM2.5

SO2

3A

CO

NO2

PM2.5

SO2

2B

CO

NO2

PM2.5

SO2

2A

CO

NO2

PM2.5

SO2

Page H-4

Ap

pe

nd

ix H

- A

ER

MO

D O

utp

ut

Re

sult

s

Su

mm

ary

by

Po

llu

tan

t

w/

Em

issi

on

Co

ntr

ols

Po

llu

tan

t

Av

era

gin

g

Pe

rio

dS

cen

ari

oM

ax

@ F

en

ce

Ma

x @

Re

sid

en

t

Ba

ckg

rou

nd

( µg

/m3)

Ma

x @

Fe

nce

Ma

x @

Re

sid

en

tN

AA

QS

(µg

/m3)

Existing

164

110

Included

164

110

188

1A

164

112

Included

164

112

188

1B

171

118

Included

171

118

188

1C

164

112

Included

164

112

188

2A

164

115

Included

164

115

188

2B

164

115

Included

164

115

188

Existing

1.64

0.89

20

21.6

20.9

35

1A

93

20

29

23

35

1B

13

520

33

25

35

1C

93

20

29

23

35

2A

53

20

25

23

35

2B

64

20

26

24

35

Existing

0.04

0.01

9.2

9.2

9.2

12

1A

31

9.2

12

10

12

1B

31

9.2

12

10

12

1C

31

9.2

12

10

12

2A

11

9.2

10

10

12

2B

11

9.2

10

10

12

PM2.5

Annual

Mo

de

led

Co

nc.

(µg

/m3)

To

tal

Co

nc.

(µg

/m3)

NO2

1-Hr

PM2.5

24-Hr

Appendix J Isopleths With Additional Controls on NOx and PM2.5

Emissions

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario1A_NO2_1hr_wBckgnd\Scenario1A_NO2_1hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - NO2 1-hr w/ARM2 - Scenario 1A (2030) 100% CHPNorth CHP Location. Includes Bckgnd NO2. 70% Control on CHP.

COMMENTS:

1 Hr NO2 NAAQS = 188 micrograms/cubic meter (ug/m3).Background ~ 74 ug/m3.

Contour color legend represents 10% increments relative to the NAAQS.

Peak concentration occurs at North Fence along 31st Street near New Maint. Bldg.

COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

13

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

164 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario1B_NO2_1hr_wBckgnd\Scenario1B_NO2_1hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - NO2 1-hr w/ARM2 - Scenario 1B (2030) 90% CHPNorth CHP Location; West WGB Location. Incl Bckgnd; 70% Control CHP

COMMENTS:

NAAQS for 1-Hour NO2=188 micrograms/cubic meter (ug/m3).Background ~ 74 ug/m3.


Peak concentration occurs on North Fence along 31st Street near New Maint. Bldg.

COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

14

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

171.19 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario1C_NO2_1Hr_wBckgnd\Scenario1C_NO2_1hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - NO2 1-Hr w/ARM2 - Scenario 1C (2030) 90% CHPNorth CHP Location. East WGB Location. Incl Bckgnd. 70% Control CHP.

COMMENTS:

NAAQS for 1-Hour NO2=188 micrograms/cubic meter(ug/m3).Background ~ 74 ug/m3.

Contour color legend represents10% increments relative to theNAAQS.

Peak concentration occurs atNorth Fence along 31st Streetnear New Maint. Bldg.

COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

14

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

163.97 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario2A_NO2_1Hr_wBckgnd\Scenario2A_NO2_1hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - NO2 1-Hr w/ARM2 - Scenario 2A (2030) 100% CHPSouth CHP Location; Incl Bckgnd. 70% Control CHP.

COMMENTS:



Peak concentration occurs on South Plant Fence next to Glebe Road.

COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

13

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

164.37 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario2B_NO2_1Hr_wBckgnd\Scenario2B_NO2_1hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - NO2 1-Hr w/ARM2 - Scenario 2B (2030) 90% CHPSouth CHP Location. West WGB Location. 70% Control CHP.

COMMENTS:



Peak concentration occurs on South Plant Fence next to Glebe Road.

COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

14

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

164.38 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario1A_PM25_24Hr_wBckgnd\Scenario1A_PM25_24Hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 24Hr - Scenario 1A (2030) 100% CHPNorth CHP Location. Incl Bckgnd. 66% Control on CHP.

COMMENTS:

NAAQS for 24-Hr PM2.5= 35 micrograms/cubic meter (ug/m3).Background = 20 ug/m3.


Peak concentration occurs on North Plant Fence along 31st St near NMB.

COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

13

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

29.1 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario1B_PM25_24Hr_wBckgnd\Scenario1B_PM25_24Hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 24Hr - Scenario 1B (2030) 90% CHPNorth CHP Location. West WGB Location. Incl Bckgnd. 66% Control CHP.

COMMENTS:




COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

14

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

33.4 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario1C_PM25_24Hr_wBckgnd\Scenario1C_PM25_24Hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 24Hr - Scenario 1C (2030) 90% CHPNorth CHP Location. East WGB Location. Incl Bckgnd. 66% Control CHP.

COMMENTS:



Peak concentration occurs on Northeast Plant Fence along South Eads St.

COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

14

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

29.3 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario2A_PM25_24Hr_wBckgnd\Scenario2A_PM25_24Hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 24Hr - Scenario 2A (2030) 100% CHPSouth CHP Location. Incl Bckgnd. 66% Control CHP.

COMMENTS:



Peak concentration occurs on North Plant Fence along 31st St near NMB..

COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

13

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

25.5 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario2B_PM25_24Hr_wBckgnd\Scenario2B_PM25_24Hr.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 24Hr - Scenario 2B (2030) 90% CHPSouth CHP Location. West WGB Location. 66% Control CHP.

COMMENTS:




COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

14

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

26.4 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario1A_PM25_Ann_wBckgnd\Scenario1A_PM25_Ann.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 Annual - Scenario 1A (2030) 100% CHPNorth CHP Location. Incl Bckgnd. 66% Control on CHP.

COMMENTS:

NAAQS for Annual PM2.5= 12 micrograms/cubic meter(ug/m3).Background = 9.2 ug/m3.


Peak concentration occurs onNorth Plant Fence along 31st Stnear NMB.

COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

13

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

12.1 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario1B_PM25_Ann_wBckgnd\Scenario1B_PM25_Ann.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 Annual - Scenario 1B (2030) 90% CHPNorth CHP Location. West WGB Location. Incl Bckgnd. 66% Control CHP.

COMMENTS:




COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

14

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

11.9 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario1C_PM25_Ann_wBckgnd\Scenario1C_PM25_Ann.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 Annual - Scenario 1C (2030) 90% CHPNorth CHP Location. East WGB Location. Incl Bckgnd. 66% Control CHP.

COMMENTS:




COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

14

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

11.8 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario2A_PM25_Ann_wBckgnd\Scenario2A_PM25_Ann.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 Annual - Scenario 2A (2030) 100% CHPSouth CHP Location. Incl Bckgnd. 66% Control CHP.

COMMENTS:




COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

13

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

10.1 ug/m^3

AERMOD View - Lakes Environmental Software C:\Lakes\Projects\Arlington\AERMOD-Runs\Mitigated Models\Scenario2B_PM25_Ann_wBckgnd\Scenario2B_PM25_Ann.isc

SCALE:

0 0.3 km

1:8,000

PROJECT TITLE:

Arlington WWTP - PM2.5 Annual - Scenario 2B (2030) 90% CHPSouth CHP Location. West WGB Location. Incl Bckgnd. 66% Control CHP.

COMMENTS:




COMPANY NAME:

CDM Smith Inc.

MODELER:

Pehrson, John

DATE:

2/8/2018

PROJECT NO.:

110722

SOURCES:

14

RECEPTORS:

1192

OUTPUT TYPE:

Concentration

MAX:

9.9 ug/m^3

Documents

Project Background - Projects & Planning€¦ · projections = 32 mgd. Maximum design biogas production rate in model year: 439,085 cubic feet/day (160 million cubic feet/year). (3)