McCain Foods Othello - Washington · 2019. 8. 8. · McCain proposes to expand the production capacity of the Othello facility by adding a production line and a wastewater treatment

PROJECT REPORT McCain Foods USA, Inc. > Othello Facility

Notice of Construction Application for Line 4 Project

Prepared By:

Aaron Day – Principal Consultant

Hui Cheng – Senior Consultant

TRINITY CONSULTANTS 20819 72nd Ave. South

Suite 610 Kent, WA 98032 (253) 867-5600

July 2019

Project 194801.0005

Environmental solutions delivered uncommonly well

McCain | Line 4 Project NOC Application Trinity Consultants i

TABLE OF CONTENTS

1. EXECUTIVE SUMMARY 1-1

2. PROJECT DESCRIPTION 2-1

3. EMISSION CALCULATIONS 3-1 3.1. Project Emissions .................................................................................................................................................. 3-1

Boiler 3 .......................................................................................................................................................................................... 3-1 Line 4 .............................................................................................................................................................................................. 3-2 Flare ................................................................................................................................................................................................ 3-2

3.2. Facility-Wide Emissions ...................................................................................................................................... 3-3 Existing Production Lines ...................................................................................................................................................... 3-3 Existing Boilers .......................................................................................................................................................................... 3-4 HVAC Units ................................................................................................................................................................................... 3-4

4. REGULATORY REVIEW 4-1 4.1. NOC Applicability ................................................................................................................................................... 4-1 4.2. PSD Applicability ................................................................................................................................................... 4-1 4.3. Title V Operating Permits ................................................................................................................................... 4-1 4.4. New Source Performance Standards (NSPS) ................................................................................................. 4-1

NSPS Subpart A .......................................................................................................................................................................... 4-1 NSPS Subpart Dc ....................................................................................................................................................................... 4-2

4.5. National Emission Standards for Hazardous Air Pollutants .................................................................... 4-3 NESHAP Subpart A ................................................................................................................................................................... 4-3 NESHAP Subpart JJJJJJ ............................................................................................................................................................. 4-4

4.6. State and Local Regulatory Applicability ....................................................................................................... 4-4 Washington Toxic Air Pollutant Regulations ............................................................................................................... 4-4 State Regulatory Applicability ............................................................................................................................................ 4-5

5. BEST AVAILABLE CONTROL TECHNOLOGY 5-1 5.1. New Boiler 3 ............................................................................................................................................................ 5-1

BACT Analysis for NOX Emissions ....................................................................................................................................... 5-1 5.1.1.1. Burner Options .................................................................................................................................................................... 5-1 5.1.1.2. Add-On Controls .................................................................................................................................................................. 5-2

BACT Analysis for CO Emissions ......................................................................................................................................... 5-3 BACT Analysis for PM10, PM2.5, and VOC Emissions .................................................................................................... 5-3

5.2. New Line 4 ................................................................................................................................................................ 5-4 BACT Analysis for PM10 and PM2.5 Emissions ................................................................................................................ 5-4 BACT Analysis for VOC Emissions ...................................................................................................................................... 5-4

5.3. Biogas Generation ................................................................................................................................................. 5-5 5.4. tBACT ......................................................................................................................................................................... 5-5

6. DISPERSION MODELING ANALYSIS 6-1 6.1. Model Selection ...................................................................................................................................................... 6-1 6.2. Meteorological Data .............................................................................................................................................. 6-1 6.3. Coordinate System ................................................................................................................................................ 6-1 6.4. Terrain Elevations ................................................................................................................................................. 6-1 6.5. Receptor Grids ........................................................................................................................................................ 6-2 6.6. Building Downwash .............................................................................................................................................. 6-4

McCain | Line 4 Project NOC Application Trinity Consultants ii

6.7. Point Source ............................................................................................................................................................ 6-4 6.8. NOX to NO2 Conversion ......................................................................................................................................... 6-5 6.9. Significant Impact Analysis ................................................................................................................................ 6-5

Modeled Emission Rates ......................................................................................................................................................... 6-6 SIL Model Results ...................................................................................................................................................................... 6-6

6.10. TAP Analysis ......................................................................................................................................................... 6-7 Modeled Emission Rates ...................................................................................................................................................... 6-7 TAP Model Results .................................................................................................................................................................. 6-8

APPENDIX A: APPLICATION FORMS AND ASSOCIATED DOCUMENTS A-1

APPENDIX B: CALCULATIONS AND SUPPORTING DOCUMENTATION B-1

APPENDIX C: MODELING FILES AND SUPPORTING DOCUMENTATION C-1

McCain | Line 4 Project NOC Application Trinity Consultants iii

LIST OF FIGURES

Figure 6-1. Modeled Objects 6-3

McCain | Line 4 Project NOC Application Trinity Consultants iv

LIST OF TABLES

Table 3-1. Project Emissions Summary 3-3

Table 3-2. Post-Project Facility Wide Potential-to-Emit Summary 3-5

Table 4-1. Project TAP Emission Summary 4-5

Table 6-1. Modeled Buildings 6-4

Table 6-2. Point Source Location 6-5

Table 6-3. Point Source Parameters 6-5

Table 6-4. SIL Modeled Emission Rates 6-6

Table 6-5. SIL Model Results 6-7

Table 6-6. TAP Modeled Emission Rates 6-8

Table 6-7. TAP Model Results 6-8

McCain | Line 4 Project NOC Application Trinity Consultants 1-1

1. EXECUTIVE SUMMARY

McCain Foods USA Inc. (McCain) owns and operates a potato processing facility located in Othello, Washington (the Othello facility). The Othello facility is operated under Approval Orders DE95-AQ-E125 (first amendment) and DE98AQ-E121, issued by the Washington Department of Ecology (Ecology).

McCain proposes to expand the production capacity of the Othello facility by adding a production line and a wastewater treatment plant (the Line 4 Project). This report and the included appendices serve as the Notice of Construction (NOC) application for the proposed Line 4 Project. The application was developed pursuant to the requirements found in Washington Administrative Code (WAC) 173-400-110. A State Environmental Protection Act (SEPA) Checklist is also required for the proposed project, and will be submitted separately by McCain.

Section 2. Project Description Section 3. Emission Calculations Section 4. Regulatory Review Section 5. Best Available Control Technology (BACT) Review Section 6. Dispersion Modeling Analysis Appendices • Appendix A: NOC Application Forms and Associated Documents • Appendix B: Calculations and Supporting Documentation • Appendix C: Modeling Files and Supporting Documentation


2. PROJECT DESCRIPTION

McCain operates the Othello facility under Approval Orders DE95-AQ-E125 (first amendment) and DE98AQ-E121. These two orders have established limits on production rates for Line 1 and Line 3, as well as synthetic minor limits for PM and NOX by limiting the use of natural gas at the Othello facility. Current operations at the Othello facility include:

Line 1 for processing battered or conventional french fry products. Line 1 includes a steam-heated dryer and a two- stage fryer. Line 2 for processing conventional french fry products. Line 2 includes a steam-heated dryer and a single-stage fryer. Line 3 for processing co-product potato products. Line 3 includes a direct-fired dryer and a single-stage fryer. An air washer (Line 1 scrubber) controlling PM emissions from Line 1 Stage B of the two-stage fryer. An air washer (Line 2 scrubber) controlling PM emissions from Line 2 single-stage fryer. A wet electrostatic precipitator (ESP) controlling PM emissions from Line 3 single-stage fryer and Line 1 Stage A of the two-stage fryer. Two natural gas-fired boilers, Boiler 1 and Boiler 2, providing process steam.

The proposed expansion project includes installation of a new boiler, a new production line capable of processing conventional and battered french fry products, and a wastewater treatment plant. McCain proposes to expand the facility by adding the following list of equipment:

A production line (Line 4) including a potato dryer and a two-stage fryer, with approximately 59,720 lbs finished product per hour; A wastewater treatment plant with a covered anaerobic digester; A new boiler (referred to as Boiler 3), rated at 97.6 million Btu per hour (MMBtu/hr), firing natural gas and biogas; A flare as a backup to Boiler 3 for burning off remaining biogas; A wet ESP controlling PM emissions from Line 4 dryer and fryer; and A scrubber for removing hydrogen sulfide from the biogas.

A process flow diagram for the Othello facility is provided in Appendix A. McCain expects to start construction in October 2019 and complete construction in January 2021. The project and equipment is in final stages of design: the general building arrangement is being finalized, and vendor selection and evaluation are underway for process equipment.


3. EMISSION CALCULATIONS

This report provides project emissions calculations for the installation of Line 4 and associated emission units. The report also includes facility-wide potential to emit (PTE) calculations in order compare the post-project PTE against the Title V Air Operating Permit and Preventions of Significant Deterioration (PSD) major source thresholds.

This section describes the methodologies and assumptions used to calculate emissions from each source at the facility. Detailed emission calculations are provided in Appendix B.

3.1. PROJECT EMISSIONS The emission units that will increase emissions from the project include Boiler 3, Line 4, and the flare.

Boiler 3

Boiler 3 will fire both natural gas and biogas. When biogas generation rate is low or biogas is unable to be routed to the boiler, Boiler 3 will fire natural gas only. Therefore, emissions are calculated for two scenarios: natural gas only, and dual fuel.

Emissions of PM10, PM2.5, SO2, and VOC from firing natural gas are calculated using emission factors from AP-42 Chapter 1.4, for small boilers less than 100 MMBtu/hr. NOX and CO emissions are estimated based on burner vendor guarantees of 30 and 50 parts per million (ppm), respectively, at 3% oxygen. Emissions from natural gas combustion are based on the maximum heat input of 97.6 MMBtu/hr. PTE for natural gas combustion scenario assumes continuous operation.

When firing dual fuel, biogas will provide a portion of the heat input. On hourly basis, the emission calculations are based on the maximum hourly biogas generation rate at 850 standard cubic feet per minute (scfm). On annual basis, the maximum biogas generation rate is expected to be 325 million scf based on McCain’s projection. Emissions of PM10, PM2.5, and VOC are not expected to be different for biogas and natural gas combustion; therefore, emissions of these pollutants from dual fuel firing use same emission factors from AP-42 Chapter 1.4. Emissions of NOX and CO are dependent on the burner design; therefore, NOX and CO emissions during dual fuel firing are based on the vendor guarantees of 30 and 50 ppm.

Emissions of SO2 when firing dual fuel are determined by the hydrogen sulfide (H2S) content of the biogas. The H2S content in the biogas stream is expected to be as high as 5000 ppm. McCain will install a sulfur scrubber to remove H2S from the biogas, and expects an outlet concentration of 200 ppm H2S.1 Emissions of SO2 and H2S from biogas combustion assume 98% destruction efficiency of H2S in the waste stream after scrubber treatment. Hourly and annual SO2 total emissions for the dual fuel scenario also includes natural gas combustion emissions, in supplement to the heat input provided by biogas.

Speciated pollutants, including hazardous air pollutants (HAPs) and toxic air pollutants (TAPs), are based on emission factors from Ventura County Air Pollution Control District AB2588 Combustion Emission Factors. This source provides emission factors for natural gas external combustion sources in the size range of 10-100

1 McCain is currently working with various vendors for the scrubber, and at least one vendor is able to guarantee an outlet

concentration at 200 ppm or less.


MMBtu/hr in units of lb/MMscf, but does not specify the heating value to convert the factors from lb/MMscf to lb/MMBtu. For biogas, our emission calculations assume that the natural gas external combustion factors are representative, even though the heating value of biogas is much lower than that of natural gas. To adjust for the difference in heating value between natural gas and biogas, the lb/MMscf natural gas factors are applied to the biogas combustion rate in scfm directly, which is conservative for estimating speciated HAP/TAP emissions from biogas combustion.

Line 4

Line 4 will be able to manufacture conventional products and battered french fry products. Line 4 consists of a potato dryer and a two-stage fryer, both of which will be steam heated. PM10 and PM2.5 emissions are expected from the dryer, and PM10, PM2.5 and VOC emissions are expected from the fryer.

PM10 and PM2.5 emissions from Line 4 will be controlled by a wet ESP. Emissions from the wet ESP are estimated based on McCain’s recent source test performed at the Burley, ID plant.2 The lb/ton finished product emission factor is derived from emission testing results at the Burley, ID plant. A 20% safety factor is applied to those results to conservatively estimate emissions.

VOC emissions from Line 4 are also estimated based on source testing at the Burley, ID plant. Similar to PM emissions, the lb/ton emission factor derived from the Burley test result is applied with a 20% safety factor. Note that only total hydrocarbons (THC) were tested at Burley, and it is conservatively assumed that THC emissions are the same as VOC. There are no HAP or TAP emissions expected from Line 4, based on McCain’s process knowledge.

Flare

A flare will be used to burn off any generated biogas that could not be routed to Boiler 3 for use. The flare will use propane as the pilot gas. To conservatively estimate the emissions from the flare, the emissions presented in this section assume a scenario in which all biogas generated is routed to the flare (i.e., 850 scfm and 325 million scf per year).

Emissions of PM10, PM2.5, NOX, and CO from biogas combustion are estimated based on flare factors from AP-42 Chapter 2.4, Municipal Solid Waste Landfills (October 2008 draft version). The factors for landfill flares are representative of biogas combustion, because the heating value of biogas is similar to that of landfill gas (both are about half the heating value of natural gas). Additionally, these factors are listed on the basis of standard cubic foot methane burned, which should provide a representative estimate for biogas combustion when adjusted to the heating value of biogas. The lb/million dscf methane factor is converted to lb/MMBtu using methane’s high heating value (HHV) of 1011 Btu/scf.3

VOC emissions from the flare are conservatively estimated using the AP-42 Chapter 1.4 factor for boiler natural gas combustion. The factor in lb/MMscf is converted to lb/MMBtu using the default natural gas heating value of 1020 Btu/scf.

2 The Burley, ID plant has a similar production line as the Line 4 proposed here, including the capacity and the type of

products. Burley’s production line is also controlled by a wet ESP, and the emissions from the wet ESP were tested in early 2019.

3 https://www.engineeringtoolbox.com/heating-values-fuel-gases-d_823.html

https://www.engineeringtoolbox.com/heating-values-fuel-gases-d_823.html


SO2 and H2S emissions are estimated using the mass balance approach, assuming the sulfur scrubber reduces the H2S content of the biogas to 200 ppm, and the flare achieves a 98% destruction efficiency of H2S.

Propane combustion emissions from the flare pilot are estimated based on the AP-42 Chapter 1.5 factors. The propane usage is estimated based on a McCain’s projection, which is approximately 1,315 gallons per year.

Similar to Boiler 3 emissions, speciated HAPs and TAPs emissions are based on emission factors from Ventura County Air Pollution Control District AB2588 Combustion Emission Factors. The heating values of propane and biogas are used to convert the factors provided in lb/MMscf to lb/MMBtu.

Table 3-1 summarizes the project emissions and compares emissions to the exemption thresholds from WAC 173-400-110(5).

Table 3-1. Project Emissions Summary

Pollutant New Boiler 3

(tpy) New Line 4

(tpy) New Flare

(tpy) Project Total a

(tpy)

Exemption Thresholds b

(tpy) PM10 3.19 5.35 1.53 10.07 0.75 PM2.5 3.19 5.35 1.53 10.07 0.5 SO2 5.87 -- 5.68 5.93 2.0 NOX 15.57 -- 3.99 19.57 2.0 CO 15.78 -- 4.71 20.48 5.0

VOC 2.31 53.59 0.56 56.45 2.0 a The project total emissions for SO2 are the maximum of New Boiler 3 and New Flare. In this case, the maximum annual

SO2 emission rate is based on all generated biogas being combusted at the New Flare, and New Boiler 3 firing 100% natural gas.

b The exemption thresholds are obtained from WAC 173-400-110(5).

3.2. FACILITY-WIDE EMISSIONS Facility-wide emission calculations are performed to compare against the Prevention of Significant Deterioration (PSD) and Title V major source thresholds. Emission calculations are performed for the following equipment and operations:

Existing production lines 1, 2 and 3; Existing boilers; and The heating, ventilation, and air-conditioning (HVAC) units.

Facility wide criteria pollutant and HAP emissions are summarized in Table 3-1. The calculation of Washington Toxic Air Pollutants (TAPs) is discussed in Section 4.6.1.

Existing Production Lines

Line 1 consists of a steam-heated dryer and a two-stage fryer, and is capable of manufacturing conventional or batter french fry products. Line 2 consists of a steam-heated dryer and a single stage fryer, and only manufactures conventional french fry products. Line 3 consists of a direct-fired dryer and a co-product fryer, manufacturing potato co-products only.


PM10 and PM2.5 emissions from the dryers at Lines 1, 2, and 3 are determined using Othello’s dryer emission factor of 0.25 lb/finished ton product.4 PM10 and PM2.5 emissions from the fryers at Lines 1, 2, and 3 are connected to various control devices:

Line 1 Stage A fryer exhaust and Line 3 fryer exhaust are routed to the existing wet ESP. PM emissions are estimated based on the wet ESP emission limit of 0.0262 grain per dry standard cubic feet (gr/dscf), scaled to a lb/finished ton emission factor.

Line 1 Stage B fryer exhaust is routed to the Line 1 Air Washer. The Stage B fryer is used for both conventional and batter products. PM emissions are estimated based on the Line 1 Air Washer test result depending on the product type, with a 20% safety factor.

Line 2 is only used to manufacture conventional products, and the Line 2 fryer exhaust is routed to the Line 2 Air Washer. Therefore, the same emission factor from the Line 1 Air Washer for conventional products is used (including the 20% safety factor).

VOC emissions are only expected from the fryers. Since the air washers and wet ESP are not used to control VOC emissions, VOC emissions from all fryers are estimated based on Othello’s fryer emission factor of 0.092 lb/finished ton.5

Since the Line 3 dryer is direct fired, SO2, and VOC emissions from natural gas combustion are also included using AP-42 Chapter 1.4 emission factors. NOX and CO emissions are based on a 1994 source test from McCain’s Ontario, OR facility, which are the best available data for a direct-fired dryer. Speciated TAP and HAP emissions are based on emission factors from Ventura County Air Pollution Control District AB2588 Combustion Emission Factors for natural gas. The Line 3 dryer has a capacity of 10 MMBtu/hr, based on the size of the burner.

Existing Boilers

The maximum heat inputs for Boiler 1 and Boiler 2 are 65.98 MMBtu/hr and 95.55 MMBtu/hr, respectively. Both boilers are natural gas-fired. The existing Boiler 1 and Boiler 2 were installed before 2000, and no source test data is available. Therefore, PM10, PM2.5, SO2, NOX, CO, and VOC emissions from the existing boilers are based on AP-42 Chapter 1.4 emission factors for a boiler without any control. Speciated TAPs and HAPs emissions are also based on emission factors from Ventura County Air Pollution Control District AB2588 Combustion Emission Factors for natural gas.

HVAC Units

HVAC Units are used exclusively for comfort air conditioning purposes. Since they are not considered fugitive sources, the emissions are included for determining major source applicability. All HVAC units at the Othello facility are natural gas-fired. Emissions of PM10, PM2.5, SO2, NOX, CO, and VOC are conservatively calculated based on AP-42 Chapter 1.4 emission factors for small boilers without any control.

Table 3-2 summarizes the post-project facility-wide PTE, and compares to the applicable major source thresholds.

4 This emission factor is estimated based source tests performed in 1990s at the Burley, ID plant and the Ontario, OR plant. 5 This emission factor was based on information reported to Ecology in Source Emissions Evaluation Reports dated

1/12/1999 and 5/18/1998, applying a 20% safety factor.


Table 3-2. Post-Project Facility Wide Potential-to-Emit Summary

Emission Unit PM10 PM2.5 SO2 NOX VOC CO

Combined HAPs

(tpy) (tpy) (tpy) (tpy) (tpy) (tpy) (tpy) Line 1 35.29 35.29 -- -- 15.76 -- -- Line 2 30.64 30.64 -- -- 7.88 -- -- Line 3 7.81 7.81 0.03 6.57 2.26 16.02 3.52E-03 Boiler 1 2.15 2.15 0.17 28.33 1.56 23.80 0.02 Boiler 2 3.12 3.12 0.25 41.03 2.26 34.47 0.03 New Boiler 3 3.19 3.19 5.87 15.57 2.31 15.78 0.04 New Line 4 5.35 5.35 -- -- 53.59 -- -- New Flare 1.53 1.53 5.68 3.99 0.56 4.71 0.48 HVAC Systems 3.73 3.73 0.29 49.05 2.70 41.20 0.04 Facility-Wide TOTAL a 92.81 92.81 6.66 144.55 88.86 135.96 0.62 Title V Major Source Threshold

100 100 100 100 100 100 25

Below Title V Major Source Threshold?

Yes Yes Yes No Yes No Yes

PSD Major Source Threshold 250 250 250 250 250 250 N/A

PSD Major Source? No No No No No No N/A a Facility-wide SO2 emissions considers the worst-case of burning biogas at the New Boiler 3 or the New Flare.

Emissions from HVAC systems are included here only for the purpose of determining major source applicability, since they are not “fugitive sources”.


4. REGULATORY REVIEW

This section identifies the regulatory requirements applicable to the proposed Line 4 Project.

4.1. NOC APPLICABILITY An NOC permit application must be filed and an approval order issued by Ecology prior to the construction or modification of an affected facility per WAC 173-400-110(2)(a). The Line 4 Project includes installation of new emission units that will have emission increase higher than the exemption thresholds under WAC 173-400-110(5), as shown in Table 3-1. Therefore, an NOC application is required and an approval order must be issued prior to construction of the new emission units. This permit application provides the required elements of an NOC application, including the TAP review required by WAC 173-460.

Additionally, this project includes the installation of multiple air-make units and air-handling units, with a collective heat input capacity totaling 65.35 MMBtu/hr. However, these units are installed for the purposes of comfort air conditioning only, and thus exempt from NOC requirements per WAC 173-400-110(4)(h)(iv).

4.2. PSD APPLICABILITY PSD is the major New Source Review permitting program for attainment pollutants. The Othello facility is located in Adams County, which is an attainment area for all criteria pollutants. Currently, the Othello facility is not a major source under the PSD program. Upon completion of the Line 4 Project, the post-project facility-wide PTE for the Othello facility will remain below the PSD major source thresholds, as shown in Table 3-2. Therefore, PSD review is not required for the Line 4 Project.

4.3. TITLE V OPERATING PERMITS The Othello facility is currently operated under Approval Orders DE95-AQ-E125 (first amendment) and DE98AQ-E121, which established the synthetic minor limits of 92 tons per year for PM and NOX. As shown in Table 3-2, the NOX and CO emissions will be greater than 100 tpy upon completion of this project; therefore, a Title V operating permit will be required for operating the Othello facility. McCain requests rescinding the synthetic minor limits for PM and NOX under Approval Order DE95AQ-E121 (first amendment) upon issuance of the new approval order for this project. McCain will submit a timely and complete application for the Title V operating permit per WAC 173-401-500(3)(c).

4.4. NEW SOURCE PERFORMANCE STANDARDS (NSPS) WAC 173-400-115 adopts federal NSPS by reference. NSPS apply to certain types of equipment that are newly constructed, modified, or reconstructed after a given applicability date. A discussion of NSPS subparts potentially relevant to this project is provided below.

NSPS Subpart A

All affected sources subject to an NSPS are also subject to the applicable general provisions of NSPS Subpart A unless specifically excluded by the source-specific NSPS. NSPS Subpart A addresses the following for facilities subject to a source-specific NSPS:

Initial construction/reconstruction notification


Initial startup notification Performance tests Performance test date initial notification General monitoring requirements General recordkeeping requirements Semi-annual monitoring system and/or excess emission reports

NSPS requirements apply to sources that undergo construction, reconstruction, or modification, after the proposal date of the standard. The following definitions in 40 CFR 60.2 are pertinent to this classification:

Existing facility means, with reference to a stationary source, any apparatus of the type for which a standard is promulgated in this part, and the construction or modification of which was commenced before the date of proposal of that standard; or any apparatus which could be altered in such a way as to be of that type.

Modification means any physical change in, or change in the method of operation of, an existing facility which increases the amount of any air pollutant (to which a standard applies) emitted into the atmosphere by that facility or which results in the emission of any air pollutant (to which a standard applies) into the atmosphere not previously emitted.

The proposed Line 4 Project involves construction of new emission units, which are reviewed individually against the potentially applicable NSPS subparts. There is no source category under NSPS specific to potato processing facilities; however, NSPS subparts for general types of equipment (e.g., steam generating units) are potentially applicable and are discussed below.

Additionally, 40 CFR 60.18 sets forth general control device and work practice requirements, including flares. Since the flare is not used to comply with applicable subparts in Part 60 or 61, the flare is not subject to the general requirements per 40 CFR 60.18(a)(1).

NSPS Subpart Dc

Pursuant to 40 CFR 60.40c(a), Subpart Dc applies to each:

“…steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/h)) or less, but greater than or equal to 2.9 MW (10 MMBtu/h).”

Steam generating unit is defined in 40 CFR 60.41c as “a device that combusts any fuel and produces steam or heats water or heats any heat transfer medium,” where heat transfer medium is defined as “any material that is used to transfer heat from one point to another point.” The new Boiler 3 has a heat input capacity greater than 10 MMBtu/hr and meets the definition of a steam-generating unit. Therefore, Subpart Dc applies to the boiler.

40 CFR 60.42c contains the SO2 standard and 40 CFR 60.43c contains the PM standard in Subpart Dc. The applicability of these standards is focused on coal-, oil-, and wood-fired units. Neither standard is applicable to the proposed Boiler 3, because it will fire only natural gas and biogas. Nevertheless, the requirements of Part 60 Subpart A and the following notification and recordkeeping requirements still apply to the boiler:


Notification of construction per 40 CFR 60.7(a) is required within 30 days of commencement of construction;

Notification of actual startup per 40 CFR 60.48c(a) is required within 15 days of the initial startup of the boiler;

Records of each fuel combusted during each calendar month should be maintained per 40 CFR 60.48c(g)(2); All records should be maintained for a period of two years following of the date of such record, per 40 CFR

60.48c(i).

No reporting requirements under Subpart Dc apply to Boiler 3.

4.5. NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS National Emission Standards for Hazardous Air Pollutants (NESHAPs) have been established in 40 CFR Part 61 and Part 63 to control emissions of HAPs from stationary sources. The applicability of NESHAP rules often depends on a facility’s major source status with respect to HAP emissions. Under 40 CFR Part 63, a major source is defined as “any stationary source or group of stationary sources located within a contiguous area and under common control that emits or has the potential to emit considering controls, in the aggregate, 10 tons per year or more of any HAP or 25 tons per year or more of any combination of HAP.” The Othello facility is an area source of HAP.

NESHAP Subpart A

All affected sources subject to a Part 63 NESHAP are also subject to the general provisions of Part 63 Subpart A unless specifically excluded by the source-specific NESHAP. Per NESHAP Subpart A, the following definitions are important when characterizing whether the affected source is new, reconstructed, or existing:

Affected source means the collection of equipment, activities, or both within a single contiguous area and under common control that is included in a section 112(c) source category or subcategory for which a section 112(d) standard or other relevant standard is established pursuant to section 112 of the Act. Each relevant standard will define the “affected source,” as defined in this paragraph.

New Source means any affected source the construction or reconstruction of which is commenced after the Administrator first proposes a relevant emission standard under this part establishing an emission standard applicable to such source.

Reconstruction, unless otherwise defined in a relevant standard, means the replacement of components of an affected or a previously non-affected source to such an extent that the fixed capital cost of the new components exceeds 50 percent of the fixed capital cost that would be required to construct a comparable new source.

Existing Source means any affected source that is not a new source.

The proposed Line 4 Project involves installation of new emission units, which are reviewed against the potentially applicable subpart for the source category. There is no specific source category under NESHAP for potato processing facilities; however, NESHAP subparts for general equipment types may still be applicable, and are discussed below.


NESHAP Subpart JJJJJJ

NESHAP Subpart JJJJJJ applies to boilers at area sources of HAPs. Boilers are defined in 40 CFR §63.11237 as:

“…an enclosed device using controlled flame combustion in which water is heated to recover thermal energy in the form of steam or hot water. Controlled flame combustion refers to a steady-state, or near steady-state, process wherein fuel and/or oxidizer feed rates are controlled. Waste heat boilers are excluded from this definition.”

The proposed Boiler 3 will only fire natural gas and biogas, and meets the definition of a gas-fired boiler under Subpart JJJJJJ:

“…any boiler that burns gaseous fuels not combined with any solid fuels, burns liquid fuel only during periods of gas curtailment, gas supply emergencies, or periodic testing on liquid fuel. Periodic testing of liquid fuel shall not exceed a combined total of 48 hours during any calendar year.”

Gas-fired boilers are exempted from NESHAP subpart JJJJJJ, as stated in 40 CFR 63.11195(e). Therefore, NESHAP Subpart JJJJJJ does not apply to Boiler 3.

4.6. STATE AND LOCAL REGULATORY APPLICABILITY

Washington Toxic Air Pollutant Regulations

In Washington, all new sources emitting TAPs are required to demonstrate compliance with the Washington TAP program pursuant to WAC 173-460. Ecology has established a de minimis emission rate, a small quantity emission rate (SQER), and an acceptable source impact level (ASIL) for each listed TAP. If the total project-related TAP emissions increase exceeds the de minimis level for a pollutant, then permitting and a control technology review is triggered. If the emissions increases exceed its respective SQER, further determination of compliance with the ASIL using air dispersion modeling is required.

Per WAC 173-460-040(2), the TAP review is performed for the new emission units with TAP emissions (Boiler 3, the new wet ESP, and the flare). The project emission increase is determined following the calculation methodologies discussed in Section 3.1. The project TAP emissions are summarized in Table 4-1, and the detailed calculations are included in Appendix B.

There are six TAPs with project emissions greater than the SQER. Therefore, dispersion modeling is performed to demonstrate compliance against the ASILs for these TAPs, as discussed in Section 6.


Table 4-1. Project TAP Emission Summary

Pollutant Averaging

Period

Project Emission

Rate a De Minimis SQER Modeling Required? (lb/averaging period)

Benzene Year 57.25 0.331 6.62 Yes

Formaldehyde Year 391.75 1.6 32 Yes

Naphthalene Year 3.86 0.282 5.64 No

Acetaldehyde Year 16.95 3.55 71 No

Acrolein 24-hr 0.02 0.000394 0.00789 Yes

Propylene 24-hr 4.45 19.7 394 De Minimis

Toluene 24-hr 0.14 32.9 657 De Minimis

Xylenes 24-hr 0.09 1.45 29 De Minimis

Ethyl Benzene Year 475.94 3.84 76.8 Yes

Hexane 24-hr 0.05 4.6 92 De Minimis

H2S 24-hr 0.93 0.0131 0.263 Yes

SO2 1-hr 3.60 0.457 1.45 Yes

NO2 1-hr 0.48 0.457 1.03 No

CO 1-hr 5.08 1.14 50.4 No a Project emissions are conservatively determined to be the sum of the dual fuel scenario for the new boiler and the

projected biogas emissions for the flare for all TAPs.

State Regulatory Applicability

The following requirements apply to the Line 4 Project:

WAC 173-400-040(2): No person shall cause or allow the emission for more than three minutes, in any one hour, of an air contaminant from any emissions unit which at the emission point, or within a reasonable distance of the emission point, exceeds twenty percent opacity as determined by Ecology Method 9A.

WAC 173-400-040(7): No person shall cause or allow the emission of a gas containing sulfur dioxide from any emissions unit in excess of one thousand ppm of sulfur dioxide on a dry basis, corrected to seven percent oxygen for combustion sources, and based on the average of any period of sixty consecutive minutes.

WAC 173-400-050(1): No person shall cause or allow emissions of particulate matter from combustion units in excess of 0.23 gram per dry cubic meter at standard conditions (0.1 gr/dscf).

WAC 173-400-060: No person shall cause or allow emissions of particulate matter from any general process operation in excess of 0.23 gram per dry cubic meter at standard conditions (0.1 gr/dscf) of exhaust gas.


5. BEST AVAILABLE CONTROL TECHNOLOGY

Under WAC 173-400-113, Ecology requires all new sources or modifications to existing sources to use BACT for all pollutants not previously emitted or pollutants for which emissions would increase as a result of the new source or modification. A BACT analysis is included in this section for all emission units subject to NOC permitting.

5.1. NEW BOILER 3

BACT Analysis for NOX Emissions

5.1.1.1. Burner Options

The typical control technology for controlling NOX emissions from boilers is by installing a low-NOX burner (LNB) or an ultra-low NOX burner (ULNB). Both LNB and ULNB are feasible technologies for the proposed natural gas-fired Boiler 3. For natural gas firing, an ULNB can achieve a NOX outlet concentration as low as 9 ppm (at 3% oxygen) and a LNB can achieve a NOX concentration at 30 ppm (at 3% oxygen).

Most of the NOX emissions from combustion are generated due to the high temperature at the combustion zone, where nitrogen in the air is converted to NOX. The NOX generated in this way by combustion is usually referred to as “thermal NOX”. Increasing the mass flow in the combustion zone in order to decrease the flame temperature can lower the amount of thermal NOX. When firing natural gas, NOX emissions of 20 ppm can be achieved using “flue gas recirculation” (FGR) in order to reduce the flame temperature. LNB uses this approach to reduce NOX emissions.

However, it is more difficult to reduce NOX concentration to levels below 20 ppm. Increasing the amount of FGR will not further reduce the NOX concentration in the exhaust gas. The other type of NOX generated during combustion is called prompt NOX. An intermediate nitrogen-containing compound (hydrogen cyanide) is generated at fuel rich flame zone, and hydrogen cyanide can later form nitrogen monoxide (NO). ULNB designs are able to prevent prompt NOX generation by carefully controlling the air and fuel injection, mixing, and ignition point.

The fuel properties have a great influence on burner design and performance. The heating value of natural gas is approximately 1000 Btu/scf, but the heating value of biogas is lower, at approximately 600 Btu/scf. The methane content in biogas is much lower than in natural gas, and biogas contains more inert gas than natural gas, both of which result in the lower heating value of biogas. Based on McCain’s discussions with burner vendors, achieving the lower NOX emission rates typically reached by UNLB designs is problematic for burners firing biogas. One boiler vendor is able to guarantee a 9-ppm NOX outlet concentration with an ULNB when firing natural gas only.6 However, when introducing biogas as the fuel, the varying fuel composition and lower heating value of biogas will cause the following issues for an ULNB:

Dual fuel combustion should at least be at 50 percent load for the boiler, to ensure ignition of biogas. NOX emissions higher than 9 ppm are expected when firing dual fuels.

6 Document from Normand Bujoid (Cleaver Brooks) to Peter Cormier (McCain), June 12, 2019.


Biogas overall heat input must be less than 30 percent, and a specific design must be used in order to accommodate dual fuel use.

Upon loss of biogas fuel supply, boiler operation may be interrupted due to the fuel composition change.

McCain proposes to install a LNB instead of an ULNB, for the following reasons:

In order to lower operation cost and environmental footprint at the facility, McCain would like to use biogas as a renewable fuel source for the boiler.

McCain’s manufacturing process typically requires 50 percent of the boiler capacity on average, but the firing rate will vary depending on the actual steam demand. With the LNB, biogas combustion can accommodate boiler loads as low as 15 percent and the proportion of biogas to the overall heat input can be as high as 75 percent, both of which give McCain maximum flexibility in biogas combustion when needed.

The boiler needs to ramp up and down quickly to respond to the steam demand of the process (referred to as “load swing”). Due to design reasons, an ULNB is already slow compared to a LNB, a problem that would become even worse when firing biogas. In order to ensure minimum interruption at the facility’s processes, the LNB is preferred while not comprising NOX emission performance. Additionally, McCain has utilized LNBs at other facilities, and is familiar with dealing with load swings with LNBs.

The LNB design can also be configured to isolate the natural gas feed and the biogas feed so that boiler shutdown could be avoided upon sudden loss of biogas supply.

This proposed NOX performance level at 30 ppm matches the BACT determinations for two similar facilities: • Approval Order No. 10AQ-E344, First Amendment was issued by Ecology, for J.R. Simplot Company’s

potato processing facility located in Moses Lake, WA. This permit sets forth BACT limit for the biogas/natural gas combination at 30 ppm NOX (corrected to 3% oxygen). NOX limits are higher when hydrogen gas is introduced to co-fire with the other two gaseous fuels.

• Order of Approval No. 2016-0016, Revision 3, was issued by Benton Clean Air Agency, for Lamb Weston, Inc.’s facility located in Richland, WA. The 96 MMBtu/hr natural gas-fired boiler has a NOX limit at 37.2 lb/MMscf, which is equivalent to 30 ppm NOX corrected to 3% oxygen.

5.1.1.2. Add-On Controls

McCain also evaluates the feasibility for installing add-on control devices. Add-on devices such as selective catalytic reduction (SCR), selective non-catalytic reduction (SNCR), and non-selective catalytic reduction (NSCR) are available options. Of all these three types of add-on controls, SCR appears to have the highest control effectiveness for the following reasons:

SNCR does not use a catalyst for the reaction between ammonia or urea with NOX to reduce NOX emissions, unlike SCR. Lack of a catalyst requires a higher temperature to achieve the chemical reaction, which makes SCR applicable to more combustion sources.

NSCR requires zero excess air and a catalyst without a reagent. However, boiler exhaust oxygen levels vary widely, which does not meet the requirement of zero excess air. Therefore, NSCR is not considered technologically applicable to boilers.

A cost analysis was performed for SCR in accordance to EPA’s Control Cost Manual methodologies7 as well as information available for the Othello facility, such as utility rates. The following assumptions are used for the cost analysis:

7 EPA Air Pollution Control Cost Manual, 7th Edition. Section 4, Chapter 2 – Selective Catalytic Reduction (updated

6/12/2019).


Total capital investment is calculated following the equation for industrial gas-fired units. Even though the equation is designed for units between 205 and 4100 MMBtu/hr, this cost analysis assumes that it is also appropriate for a gas-fired boiler less than 100 MMBtu/hr.

Ammonia is assumed to be the reagent and the cost for anhydrous ammonia is used to estimate reagent cost. Typically, aqueous ammonia solution is the actual reagent applied in SCR systems. The cost for installation and operation of the associated ammonia solution storage tanks and ammonia injection systems are not included for conservatism.

SCR control efficiency ranges from 70% to 90%. Lower inlet NOX concentration may result in lower control efficiency overall. Since the inlet NOX concentration is low, the cost analysis assumes the outlet NOX concentration is at 4 ppm (corrected to 3% oxygen) for conservatism.

This cost analysis assumes a SCR control equipment life of 25 years with an interest rate of 5.5%.

The detailed cost calculations are provided in Appendix B. The cost effectiveness calculated is $21,406 per ton of NOX removed, and is cost prohibitive for the project.

Due to the process reasons, BACT limits issued for similar facilities, and the cost effectiveness assessed for add-on controls, McCain proposes a LNB with NOX emissions at 30 ppm (at 3% oxygen) without add-on controls as BACT for NOX emissions for Boiler 3. McCain is currently working on finalizing the design and working with multiple vendors. The proposed BACT will be implemented in the final equipment choice.

BACT Analysis for CO Emissions

Similar to NOX, emissions of CO are driven by the combustion technology instead of fuel types. Due to the low heating value of biogas and the resulting lower flame temperature, the boiler vendor only guarantees 50 ppm CO (at 3% oxygen) when firing both biogas and natural gas.

This level of CO emissions is lower than the BACT limits for the two similar facilities:

Approval Order No. 10AQ-E344, First Amendment, for J.R. Simplot Company sets forth BACT limit at 125 ppm CO (corrected to 3% oxygen) for any gas fuel mixture.

Order of Approval No. 2016-0016, Revision 3, for Lamb Weston, Inc. sets a CO limit at 75.4 lb/MMscf, which is equivalent to 100 ppm CO corrected to 3% oxygen for the natural gas-fired boiler.

Therefore, McCain proposes the LNB with 50 ppm CO (corrected to 3% oxygen) as the BACT for CO emissions from Boiler 3. McCain is currently working on finalizing the design and working with multiple vendors. The proposed BACT will be implemented in the final equipment choice.

BACT Analysis for PM10, PM2.5, and VOC Emissions

VOC emissions depend on combustion efficiency, and PM10/PM2.5 emissions primarily consists of uncombusted hydrocarbons. The typical control technologies applied include good combustion practices and use of natural gas for PM10, PM2.5, and VOC emissions. Since a LNB is flexible in accommodating various fuel mixes, the combustion efficiency for biogas is not expected to be any lower than that for natural gas. Therefore, use of the gaseous fuels and good combustion practices are proposed as BACT for PM10, PM2.5, and VOC emissions from Boiler 3.


5.2. NEW LINE 4

BACT Analysis for PM10 and PM2.5 Emissions

Both the steam-heated dryer and the two-stage fryer from Line 4 emit PM10 and PM2.5, emissions due to the high moisture content in potatoes. Mist eliminators, impingement devices, wet scrubbers, and wet ESPs are available technologies to control particulate matter emissions.

McCain has been operating wet scrubbers (air washers) and a wet ESP at Othello facility. A wet ESP can achieve a removal efficiency of 90 percent, as is known to McCain as the best available technology for removing particulate matter emissions from dryers and fryers. Therefore, McCain proposes a wet ESP as the BACT for PM10 and PM2.5 emissions from Line 4.

BACT Analysis for VOC Emissions

VOC emissions are produced in the deep frying process. Carbon adsorbers, condensers, and oxidizers are the available add-on control technologies for VOC emissions control. Carbon adsorbers and condensers are not technologically feasible in this case, because:

Carbon adsorbers can work with low to medium concentration gas streams, but are more intended for recovery of VOC. Additionally, activated carbon is less effective where the waste gas has high relative humidity.8

Condensers are also typically used to recover the VOCs captured, and are used for treating emission streams with high VOC concentrations (typically greater than 5,000 ppm).9 The VOC in the exhaust stream is approximately 25 ppm (based on Burley, ID test results), too low for effective recovery.

Thermal oxidizers are considered technological feasible in this case. A cost analysis is performed for a regenerative thermal oxidizer (RTO) in accordance to the EPA Control Cost Manual methodologies.10 The cost analysis is based on the following assumptions:

A vendor quote is used to determine the capital investment. Due to the size of the flow rate from the wet ESP, two RTOs would be required.

Annual operating costs are based on local labor rates and utility rates. This cost analysis assumes an equipment life of 20 years with an interest rate of 5.5%.

Detailed cost calculations are provided in Appendix B. The cost effectiveness calculated is $17,334 per ton of VOC removed, which is cost prohibitive.

Therefore, McCain proposes best management practices without add-on controls as the BACT for VOC emissions from Line 4.

8 EPA Air Pollution Control Cost Manual, 7th Edition. Section 3.1 – VOC Recapture Controls, Chapter 1 – Carbon Adsorbers. 9 EPA Air Pollution Control Cost Manual, 7th Edition. Section 3.1 – VOC Recapture Controls, Chapter 2 – Refrigerated

Condensers. 10 EPA Air Pollution Control Cost Manual, 7th Edition. Section 3.2 – VOC Destruction Controls, Chapter 2 – Incinerators and

Oxidizers.


5.3. BIOGAS GENERATION The covered anaerobic digester will generate biogas. Typical biogas composition includes methane, carbon dioxide, nitrogen, H2S, and water. Due to the methane content and for safety reasons, combustion of biogas is the best treatment method. McCain proposes to use the biogas as a fuel source in Boiler 3, and use a flare as a backup when biogas cannot be routed to Boiler 3.

McCain estimates a maximum H2S content of 5000 ppm. Since sulfur is not removed from combustion processes, H2S will be oxidized to SO2 at either Boiler 3 or the new flare. Without any control, this could result in more than 100 tons per year of SO2 emissions. Therefore, McCain proposes to use a scrubber as BACT to remove sulfur emissions from biogas. The scrubber will utilize a media (e.g., bacteria beds) to remove the H2S in the biogas stream and the H2S will be converted to stable compounds (e.g., elemental sulfur), depending on the type of technology implemented. McCain proposes a system with an outlet H2S concentration of 200 ppm, achieving a removal efficiency of 96 percent. A copy of an example vendor quote is provided in Appendix B.

5.4. TBACT Pursuant to WAC 173-460-040, BACT for TAPs (tBACT) should be employed for new or modified emission units for all TAPs for which the increase in emissions will exceed de minimis emission value. As shown in Table 4-1, benzene, formaldehyde, naphthalene, acetaldehyde, acrolein, ethylbenzene, H2S, SO2, CO and NO2 emissions are above the de minimis levels.

McCain proposes the following technologies as tBACT for these TAPs:

A LNB burner with NOX emissions at 30 ppm and CO emissions at 50 ppm (corrected to 3% oxygen) for CO and NO2 emissions;

Use of gaseous fuels and good combustion practices for benzene, formaldehyde, naphthalene, acetaldehyde, acrolein and ethylbenzene emissions; and

A scrubber removing H2S in the biogas for H2S and SO2 emissions.


6. DISPERSION MODELING ANALYSIS

As discussed in Section 4.6.1, air dispersion modeling is performed for each TAP with emissions greater than its respective SQER. Additionally, a modeling analysis is performed to compare the impact from the proposed Line 4 Project to the significant impact levels (SILs) for criteria pollutants. If the project impact exceeds the SIL for a pollutant, further assessment is necessary to demonstrate that the National Ambient Air Quality Standard (NAAQS) will not be exceeded.11

This section discusses the methodologies applied for the air dispersion modeling analysis and presents the results for the SIL and TAP analyses.

6.1. MODEL SELECTION The American Meteorological Society/Environmental Protection Agency Regulatory Model Improvement Committee (AERMIC) modeling system, the most recent AERMOD dispersion model version 18081 with Plume Rise Model Enhancements (PRIME) advanced downwash algorithms, is used as the dispersion model in the air quality analysis.

6.2. METEOROLOGICAL DATA Five years of surface meteorological data are taken from the nearest airport, Grant County International Airport (Station ID: KMWH; WBAN ID: 24110). The data from the five most recent years (2014 through 2018) is used. The upper air data is taken from the nearest upper air station in Spokane, Washington (OTX) for the corresponding period. All data is processed using regulatory default options.

6.3. COORDINATE SYSTEM The locations of the emission sources, structures, and receptors for this modeling analysis are represented in the Universal Transverse Mercator (UTM) coordinate system using the North American 1983, CONUS (NAD83) projection. The UTM grid divides the world into coordinates that are measured in north meters (measured from the equator) and east meters (measured from the central meridian of a particular zone, which is set at 500 km). UTM coordinates for this analysis are based on UTM Zone 11. The location of the Othello plant is approximately 5,189,495 meters Northing and 334,338 meters Easting in UTM Zone 11.

6.4. TERRAIN ELEVATIONS Terrain elevations for receptors, buildings, and sources are determined using National Elevation Dataset (NED) supplied by the United States Geological Survey (USGS). The NED is a seamless dataset with the best available raster elevation data of the contiguous United States. NED data retrieved for this model have a grid spacing of 1/3 arc-second or 10 m. The AERMOD preprocessor, AERMAP version 11103, is used to compute model object elevations from the NED grid spacing. AERMAP also calculates hill height data for all receptors. All data obtained from the NED files are checked for completeness and spot-checked for accuracy.

11 Section 4.2, Appendix W to 40 CFR Part 51, January 17, 2017.


6.5. RECEPTOR GRIDS Per Ecology’s guidance on TAP review, six (6) square Cartesian receptor grids are used in the air dispersion modeling analyses. The new wastewater plant will be built on McCain’s property, which is located on the northwest of the Othello facility. Therefore, the receptor grids extend from the center of the two pieces of property instead of from the sources, in order to cover the possible locations with maximum impact from all emission sources. The modeled receptor grid extends approximately 8,400 meters from the center of the two pieces of properties (approximately located at 333,949 m E and 5,189,638 m N).

A grid containing 12.5-meter spaced receptors and extending roughly 150 meters from all sources and approximately 700 meters from the center;

A grid containing 25-meter spaced receptors extending from 150 meters to 400 meters from all sources and approximately 850 meters from the center;

A grid containing 50-meter spaced receptors extending from 400 meters to 900 meters from all sources and approximately 1,250 meters from the center;

A grid containing 100-meter spaced receptors extending from 900 meters to 2,000 meters from all sources and approximately 2,150 meters from the center;

A grid containing 300-meter spaced receptors extending from 2,000 meters to 4,500 meters from all sources and approximately 4,150 meters from the center;

A grid containing 600-meter spaced receptors extending from 4,500 meters to 6,000+ meters from all sources and approximately 8,400 meters from the center.

In addition, 12.5-meter spaced receptors are included along the Othello facility’s fenceline and new wastewater plant fenceline. Figure 6-1 shows the modeled ambient air boundaries in purple.


Figure 6-1. Modeled Objects

Wastewater Treatment Plant

Othello Facility

New Line 4 Building

New Flare

New wet ESP Boiler 3


6.6. BUILDING DOWNWASH Emissions from each source are evaluated in terms of their proximity to nearby structures. The purpose of this evaluation is to determine if stack discharges might become caught in the turbulent wakes of these structures. Wind blowing around a building creates zones of turbulence that are greater than if the buildings were absent. The concepts and procedures expressed in the GEP Technical Support document, the Building Downwash Guidance document, and other related documents are applied.

The new Line 4 building will be built along with the existing cold storage buildings on the south side of the Othello facility. Based on the building elevation drawings (see Appendix C), the four building structures are included for building downwash purposes. The existing buildings at the Othello facility are too far from these modeled sources to affect results; therefore, they are not included.

Table 6-1. Modeled Buildings

Building ID UTM Easting

(m) UTM Northing

(m) Elevation

(m) Height

(m) Shape

CSTG1 334146.6 5189449.3 329.37 10.01 Rectangle CSTG2 334145 5189380.4 329.28 10.41 Rectangle

NEWSIDE 334235.8 5189379.9 330.86 11.79 Rectangle NEW4 334237.9 5189446.4 330.79 12.55 Polygon

Note: UTMs are provided for one corner of the building.

6.7. POINT SOURCE Emission sources modeled for the Line 4 Project include the three new sources: Boiler 3, the wet ESP, and the flare. All three sources are modeled as point sources. The locations of the sources are determined based on the site layout, which is provided in Appendix C.

The source parameters for Boiler 3, including exhaust flow rate and temperature, are determined based on the vendor provided performance data. The lower value of the boiler firing dual fuels or natural gas for each parameter is used for conservatism. Stack height and diameter for Boiler 3 are based on design information. The flow rate, diameter and stack height for the wet ESP are based on McCain’s design for Line 4, and the exhaust temperature is based on source testing of similar equipment at McCain’s Burley, ID plant.

The flare is also modeled as a point source following EPA’s dispersion modeling guidance12:

Default values for temperature, velocity, and radiation loss are used, since source-specific parameters are not available.

The effective stack height and stack diameter are calculated based on the actual flare tip height, heat release and radiation loss.

The heat release is calculated using the biogas heat content and the hourly maximum flow rate of 850 scfm.

Table 6-2 summarizes the locations of these modeled sources and Table 6-3 summarizes the modeled parameters. The locations of the modeled sources are also shown in Figure 6-1.

12 AERSCREEN User’s Guide, Section 2.1.2.


Table 6-2. Point Source Location

Model Unit ID Description UTM Easting UTM Northing Elevation

(m) (m) (m) B3S3 Alpha Boiler 3 334280.0 5189359.1 331.30

WESP2 Alpha Wet ESP 334327.6 5189357.7 331.67 FLR Flare 333434.0 5189827.0 284.58

Table 6-3. Point Source Parameters

Source ID Height a Temperature b Flow Rate Velocity b Diameter c

(ft) (m) (F) (K) (acfm) (m/s) (in) (m) B3S3 150 45.72 290 416.48 28,603 11.56 48 1.22

WESP2 140 42.67 112.7 317.98 130,161 23.39 72 1.83 FLR -- 8.64 -- 1273 -- 20.00 -- 1.00

a Flare physical tip height is 12 ft. The modeled stack height is calculated using EPA guidance with the radiation loss (55%; EPA default).

b Flare temperature and velocity use EPA default. c Flare modeled diameter is calculated using heat release (2,270,482 cal/s) and the radiation loss.

6.8. NOX TO NO2 CONVERSION The modeling analysis for NO2 is performed using Ambient Ratio Method 2 (ARM2), which is a regulatory default according to the latest guidance.13 The model inputs for ARM2 apply the national regulatory default for ARM2 of the minimum ambient NO2/NOX ratio of 0.5 and a maximum ambient ratio of 0.9. This minimum ambient ratio of 0.5 is conservative, because for a natural gas-fired boiler the in-stack ratio is less than 0.1.

Using this approach will provide a conservative estimate in NO2 concentration increase resulting from this project, because the NO2/NOX ratio drops along with the increase in NOX concentrations. At the NO2 SILs, the NO2/NOX ratio is approximately at 0.9, while the actual NOX concentrations at the boiler stack are likely much higher and thus a much lower NO2/NOX ratio is expected.

6.9. SIGNIFICANT IMPACT ANALYSIS The significant impact analysis is performed to assess the ambient air impact from the proposed Line 4 Project. A source must have a “significant impact” on ambient air quality in order to cause or contribute to a NAAQS violation. If the modeled impact is below the SIL for a pollutant, it indicates that the modeled source does not have a significant impact; thus, further modeling analysis against the NAAQS is not necessary.14

The significant impact analysis is performed for the following pollutants and averaging periods:

PM10, 24-hr and annual averaging periods; PM2.5, 24-hr and annual averaging periods;

13 Section 4.2.3.4, Appendix W to 40 CFR Part 51, January 17, 2017. 14 EPA memo, Guidance on Significant Impact Levels for Ozone and Fine Particles in the Prevention of Significant Deterioration

Permitting Program (April 17, 2018).


NO2, 1-hr and annual averaging periods; and SO2, 1-hr, 3-hr, 24-hr, and annual averaging periods.

Modeled Emission Rates

The new wet ESP emits PM10 and PM2.5 only. The modeled emission rates are based on McCain’s expected level of particulate matter emissions, as discussed in Section 3.1.2.

Boiler 3 emits NOX, SO2, PM10, and PM2.5. The modeled NOX emission rate is the same for the 1-hr and annual averaging periods, which are both based on the NOX emission guarantee from the vendor. Both short-term and annual SO2 emission rates are based on firing dual fuels, as discussed in Section 3.1.1. The modeled emission rate for PM10 is also the same for 24-hr and annual averaging periods, because they are based on the AP-42 emission factor. The modeling analysis assumes that PM2.5 emission rate is the same as PM10.

Flare 3 emits NOX, SO2, PM10, and PM2.5. Short-term emission rates for all pollutants are based on the hourly maximum amount of biogas generated, and the annual emission rates are based on the annual amount of biogas generated. It is conservatively assumed that all biogas generated is routed to the flare. Additionally, the emissions from combusting the pilot gas (propane) are included for modeling purposes.

The modeled emission rates are summarized in Table 6-4.

Table 6-4. SIL Modeled Emission Rates

Source ID

Short-Term SO2 Emission Rate

Annual SO2 Emission Rate

Short-term NOX Emission Rate

Annual NOX Emission Rate

Short-Term PM10/PM2.5

Emission Rate

Annual PM10/PM2.5

Emission Rate (lb/hr) (g/s) (tpy) (g/s) (lb/hr) (g/s) (tpy) (g/s) (lb/hr) (g/s) (tpy) (g/s)

B3S3 1.82 2.293E-01 5.87 1.688E-01 3.56 4.480E-01 15.57 4.480E-01 0.73 9.163E-02 3.19 9.163E-02 WESP2 -- -- -- -- -- -- -- -- 1.22 1.539E-01 5.35 1.539E-01

FLR 1.78 2.245E-01 5.68 1.633E-01 1.25 1.579E-01 3.99 1.149E-01 0.48 6.065E-02 1.53 4.412E-02

SIL Model Results

The model results for the significant impact analysis are summarized in Table 6-5. As shown in Table 6-5, all modeled pollutants are below their corresponding SILs. Therefore, no further modeling analysis against the NAAQS is necessary.


Table 6-5. SIL Model Results

Pollutant Averaging

Period

Maximum Modeled Concentration

(µg/m3) SIL

(µg/m3) % of SIL

PM10 24-hr 1.39 5 28%

Annual 0.08 1 8%

PM2.5 24-hr 0.79 1.2 b 66%

Annual 0.07 0.2 b 37%

NO2 1-hr 5.96 7.5 80%

Annual 0.16 1 16%

SO2 a

1-hr 6.35 7.8 81% 3-hr 6.93 25 28%

24-hr 2.74 5 55% Annual 0.11 1 11%

a SO2 results include the Boiler 3 firing dual fuel and the flare operations. When the Boiler 3 is firing dual fuel, the flare would not be operated in order to destruct the remaining biogas generated. Therefore, the model results shown here are conservative compared to the actual operations.

b EPA allows states to use alternative SILs if properly justified, but does not allow a value higher than 0.3 µg/m3 (annual) or 1.2 µg/m3 (24-hr). The recommended SIL values from the EPA memo, Guidance on Significant Impact Levels for Ozone and Fine Particles in the Prevention of Significant Deterioration Permitting Program (April 17, 2018), are listed here.

6.10. TAP ANALYSIS TAPs emissions are only expected from natural gas and biogas combustion at Boiler 3 and the flare. Therefore, only these two emission sources are modeled for TAPs.

Modeled Emission Rates

The modeled TAPs emission rates are summarized in Table 6-6, and are based on the following:

For TAPs that have 1-hr and 24-hr averaging periods, the maximum hourly emission rate for Boiler 3 (firing dual fuel) and the hourly emission rate for flare (including pilot gas combustion) are used. • The emission rate for firing dual fuel is higher than that for firing natural gas only for Boiler 3. • The hourly emission rate for flare is based on the maximum hourly biogas generation rate at 850 scfm.

For TAPs that have an annual averaging period, the annual emission rate for Boiler 3 (firing dual fuel) and the annual emission rate for flare (including pilot gas combustion) are used. • The emission rate for firing dual fuel is higher than that for firing natural gas only for Boiler 3. • The annual emission rate for flare is based on the annual biogas generation rate at 325 million scf per

year.


Table 6-6. TAP Modeled Emission Rates

Source ID

Modeled Emission Rates a Benzene Formaldehyde Acrolein Ethyl Benzene H2S SO2

B3S3 2.79E-03 tpy 5.91E-03 tpy 3.10E-04 lb/hr 3.31E-03 tpy 1.94E-02 lb/hr 1.82 lb/hr

8.013E-05 g/s 1.699E-04 g/s 3.908E-05 g/s 9.533E-05 g/s 2.441E-03 g/s 2.293E-01 g/s

FLR 2.58E-02 tpy 0.19 tpy 5.10E-04 lb/hr 0.23 tpy 1.94E-02 lb/hr 1.78 lb/hr

7.433E-04 g/s 5.465E-03 g/s 6.427E-05 g/s 6.750E-03 g/s 2.441E-03 g/s 2.245E-01 g/s a Modeled emission rates are in g/s. They are converted from either lb/hr or tpy rates shown here, depending on the modeled averaging

period for the TAP. For pollutants with annual averaging period, the tpy value is used. All other pollutants are based on the lb/hr values.

TAP Model Results

The TAP modeling results are summarized in Table 6-7. As shown in Table 6-7, the modeled concentrations are well below the ASIL for all TAPs, demonstrating compliance with Chapter WAC 173-460.

Table 6-7. TAP Model Results

Pollutant Averaging

Period

Modeled Concentration a ASIL % of

ASIL (µg/m3) (µg/m3) Benzene Year 0.0005 0.0345 1%

Formaldehyde Year 0.003 0.167 2% Acrolein 24-hr 0.001 0.06 1%

Ethyl Benzene Year 0.004 0.4 1% H2S 24-hr 0.03 2 1% SO2 1-hr 8 660 1%

a Maximum value out of the five-year modeled period. The modeled concentration represents the total impact from the Boiler 3 (firing dual fuel) and the flare (including pilot gas). The results are conservative, because the flare would not be operated if all biogas generated is fired at Boiler 3.

McCain | Line 4 Project NOC Application A-1 Trinity Consultants

APPENDIX A: APPLICATION FORMS AND ASSOCIATED DOCUMENTS

1. NOC Application Form

2. Process Flow Diagrams

Notice of Construction Application A notice of construction permit is required before installing a new source of air pollution or modifying an existing source of air pollution. This application applies to facilities in Ecology’s jurisdiction. Submit this application for review of your project. For general information about completing the application, refer to Ecology Forms ECY 070-410a-g, “Instructions for Ecology’s Notice of Construction Application.”

Ecology offers up to 2 hours of free pre-application help. We encourage you to schedule a pre-application meeting with the contact person specified for the location of your proposal (see below). For more help than the initial 2 free hours, submit Part 1 of the application and the application fee. You may schedule a meeting with us at any point in the process.

Completing the application, enclose it with a check for the initial fee and mail to:

To request ADA accommodation, call (360) 407-6800, 711 (relay service), or 877-833-6341(TTY). ECY

070-410 (Rev. 03/2018) Page 1 of 6

Check the box for the location of your proposal. For help, call the contact listed below. Ecology Permitting Office Contact

CRO Chelan, Douglas, Kittitas, Klickitat, or Okanogan County

Ecology Central Regional Office – Air Quality Program

Lynnette Haller (509) 457-7126

[email protected]

ERO

Adams, Asotin, Columbia, Ferry, Franklin, Garfield, Grant, Lincoln, Pend Oreille, Stevens,

Walla Walla, or Whitman County Ecology Eastern Regional Office – Air Quality Program

Karin Baldwin (509) 329-3452

[email protected]

NWRO San Juan County

Ecology Northwest Regional Office – Air Quality Program

Dave Adler (425) 649-7267

[email protected]

IND

Kraft and Sulfite Paper Mills and Aluminum Smelters Ecology Industrial Section – Waste 2 Resources Program

Permit manager: ____________________________________

James DeMay (360) 407-6868

[email protected]

NWP U.S. Department of Energy Hanford Reservation

Ecology Nuclear Waste Program

Lilyann Murphy(509) 372-7951

[email protected]

WA Department of Ecology Cashiering Unit P.O. Box 47611 Olympia, WA 98504-7611

For Fiscal Office Use Only: 001-NSR-216-0299-000404

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mailto:[email protected]





[email protected]

Notice of Construction Application

ECY 070-410 (Rev. 03/2018) Page 2 of 6

Check the box for the fee that applies to your application.

New project or equipment

$1,500: Basic project initial fee covers up to 16 hours of review

$10,000: Complex project initial fee covers up to 106 hours of review

Change to an existing permit or equipment $200: Administrative or simple change initial fee covers up to 3 hours of review Ecology may determine your change is complex during completeness review of your application. If your project is complex, you must pay the additional $675 before we will continue working on your application.

$875: Complex change initial fee covers up to 10 hours of review

$350 flat fee: Replace or alter control technology equipment (WAC 173-400-114) Ecology will contact you if we determine your change belongs in another fee category. You must pay the fee associated with that category before we will continue working on your application.

Read each statement, then check the box next to it to acknowledge that you agree.

The initial fee you submitted may not cover the cost of processing your application. Ecology will track the number of hours spent on your project. If the number of hours Ecology spends exceeds the hours included in your initial fee, Ecology will charge you $95 per hour for the extra time.

You must include all information in this application. Ecology may not process your application if it does not include all the information requested.

Submittal of this application allows Ecology staff to inspect your facility.

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ECY 070-410 (Rev. 03/2018) Page 4 of 6

Part 2: Technical Information The Technical Information may be sent with this application to the Ecology Cashiering Unit, or may be sent directly to the appropriate Ecology office along with a copy of this application.

For all sections, check the box next to each item as you complete it.

III. Project DescriptionAttach the following to your application:

Description of your proposed project Projected construction start and completion dates Operating schedule and production rates List of all major process equipment with manufacturer and maximum rated capacity Process flow diagram with all emission points identified Plan view site map Manufacturer specification sheets for major process equipment components Manufacturer specification sheets for pollution control equipment Fuel specifications, including type, consumption (per hour and per year), and percent sulfur

IV. State Environmental Policy Act (SEPA) ComplianceCheck the appropriate box below.

SEPA review is complete. Include a copy of the final SEPA checklist and SEPA determination (e.g., DNS, MDNS, EIS) with your application.

SEPA review has not been conducted.

If SEPA review will be conducted by another agency, list the agency. You must provide a copy of the final SEPA checklist and SEPA determination before Ecology will issue your permit.

Agency Reviewing SEPA:

_________________________________________________________________

If SEPA review will be conducted by Ecology, fill out a SEPA checklist and submit it with your application. You can find a SEPA checklist online at www.ecology.wa.gov/Regulations-Permits/SEPA/Environmental-review/SEPA-document-templates

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City of Othello

http://www.ecy.wa.gov/programs/sea/sepa/forms.htm

https://ecology.wa.gov/Regulations-Permits/SEPA/Environmental-review/SEPA-document-templates


ECY 070-410 (Rev. 03/2018) Page 5 of 6

V. Emissions Estimations of Criteria PollutantsDoes your project generate air pollutant emissions? Yes No

If yes, provide the following information about your air pollutant emissions:

Air pollutants emitted, such as carbon monoxide (CO2), lead (Pb), nitrogen dioxide (NO2), ozone (O3), and volatile organic compounds (VOC), particulate matter (PM2.5, PM10, TSP), sulfur dioxide (SO2)

Potential emissions of criteria air pollutants in tons per hour, tons per day, and tons per year (include calculations)

Fugitive air pollutant emissions – pollutant and quantity

VI. Emissions Estimations of Toxic Air PollutantsDoes your project generate toxic air pollutant emissions? Yes No

If yes, provide the following information about your toxic air pollutant emissions:

Toxic air pollutants emitted (specified in WAC 173-460-1501)

Potential emissions of toxic air pollutants in pounds per hour, pounds per day, and pounds per year (include calculations)

Fugitive toxic air pollutant emissions - pollutant and quantity

VII. Emission Standard ComplianceDoes your project comply with all applicable standards identified? Yes No

Provide a list of all applicable new source performance standards, national emission standards for hazardous air pollutants, national emission standards for hazardous air pollutants for source categories, and emission standards adopted under the Washington Clean Air Act, Chapter 70.94 RCW.

VIII. Best Available Control Technology Provide a complete evaluation of Best Available Control Technology (BACT) for your proposal.

1 http://apps.leg.wa.gov/WAC/default.aspx?cite=173-460-150

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http://apps.leg.wa.gov/WAC/default.aspx?cite=173-460-150

http://apps.leg.wa.gov/WAC/default.aspx?cite=173-460-150


ECY 070-410 (Rev. 03/2018) Page 6 of 6

IX. Ambient Air Impacts AnalysesDoes your project cause or contribute to a violation of any ambient air quality standard or acceptable source impact level? Yes No

Provide the following:

Ambient air impacts analyses for criteria air pollutants (including fugitive emissions)

Ambient air impacts analyses for toxic air pollutants (including fugitive emissions)

Discharge point data for each point included in ambient air impacts analyses (include only if modeling is required)

Exhaust height Exhaust inside dimensions (diameter or length and width) Exhaust gas velocity or volumetric flow rate Exhaust gas exit temperature Volumetric flow rate Discharge description (i.e., vertically or horizontally) and if there are any obstructions (e.g., raincap)

Emission unit(s) discharging from the point Distance from the stack to the nearest property line Emission unit building height, width, and length Height of tallest building on-site or in the vicinity, and the nearest distance of that building to the exhaust

Facility location (urban or rural)

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Natural gas

Natural gas

Biogas + Natural gas

Dryer 1

Dryer 2

Dryer 3

Line 1 Batter Fryer

Line 1 Conventional Fryer


Co-product Fryers

Line 1 Scrubber (Air Washer)

Line 2 Scrubber (Air Washer)

Wet ESP 1

Air Emissions

Product Flow

(Batter products only)

Boiler 1

Boiler 2

Boiler 3 Dryer 4

Line 4 Batter Fryer


(Batter products only)

Wet ESP 2

McCain Othello Facility Process Flow Diagram

McCain | Line 4 Project NOC Application B-1 Trinity Consultants

APPENDIX B: CALCULATIONS AND SUPPORTING DOCUMENTATION

1. Emission Calculation Tables

2. BACT Cost Calculation Tables

3. Vendor Provided Information

1. Emission Calculation Tables

TableB‐1a.PotentialEmissionSummary

PM10 PM2.5 SO2 NOX VOC CO HAPs CO2e

Line 1 35.29 35.29 -- -- 15.76 -- -- --Line 2 30.64 30.64 -- -- 7.88 -- -- --Line 3 7.81 7.81 0.03 6.57 2.26 16.02 3.52E-03 5,129Boiler 1 2.15 2.15 0.17 28.33 1.56 23.80 0.02 33,840Boiler 2 3.12 3.12 0.25 41.03 2.26 34.47 0.03 49,007New Boiler 3 3.19 3.19 5.87 15.57 2.31 15.78 0.04 50,058New Line 4 5.35 5.35 -- -- 53.59 -- -- --New Flare 1.53 1.53 5.68 3.99 0.56 4.71 0.48 11,932HVAC Systems 3.73 3.73 0.29 49.05 2.70 41.20 0.04 58,582ProjectEmissionsa 10.07 10.07 5.93 19.57 56.45 20.48 0.52 61,990WACExemptionLevels 0.75 0.50 2.00 2.00 2.00 5.00 NA NANSRRequired? Yes Yes Yes Yes Yes Yes NA NAFacility‐WidePotentialEmissionsb

92.81 92.81 6.66 144.55 88.86 135.96 0.62 208,547

TitleVThresholdc 100 100 100 100 100 100 25 --TitleVRequired? No No No Yes No Yes No --PSDMajorSourceThresholdd

250 250 250 250 250 250 N/A --

PSDMajorSource? No No No No No No No --a

b

c

d

EmissionPoint

AnnualEmissionRate(tpy)

Per 40 CFR 70.2 and 70.3, a Title V Permit is required for any major source which is defined as the potential to emit emissions greater or equal to 100 tpy for any air pollutant subject to regulation, 10 tpy of an individual HAP, or 25 tpy of combined HAPs. Fugitives sources do not need to be considered in determining the potential to emit for the facility since the source is not one of the listed 28 source categories. As the Othello facility is not categorized as a listed source category, fugitive emissions are not required to be included. The EPA definition of "fugitive emissions" is "those emissions which could not reasonable pass through a stack, chimney, vent, or other functionally-equivalent opening" per the February 10, 1999 memorandum InterpretationoftheDefinitionofFugitiveEmissionsinParts70and71 , from Thomas C. Current, Director Information Transfer and Program Integration Division. All fugitive emissions of HAP must be included when determining major source status. Fugitive emissions in this case would include truck traffic for products/raw materials transportation, which does not emit any HAP.

The Othello facility is currently considered a minor source under the Prevention of Significant Deterioration (PSD) air permitting program. PSD permitting is triggered for a minor source when a modification to an existing minor source would be major considered on its own. Major as defined in 40 CFR 52.21(b)(1)(i)(a) has the potential to emit 250 tpy of any regulated NSR pollutant for facilities that are not in one of the listed categories. Since the Othello facility is not classified as one of the listed categories, fugitive emissions do not need to be included in the PSD applicability determinations.

Project and facility-wide SO2 emissions take the maximum of biogas firing at the boiler or the flare. Project emissions only include the new Boiler 3, New Line 4, and New Flare. There will be HVAC systems to be installed along with this new project, but they are for comfort air conditioning purposes only. Therefore, emissions from the HVAC systems associated with the project are not included, per WAC 173-400-110(4)(h)(iv).HVAC systems emissions are included in PTE for applicability determination, as they are not considered "fugitive sources".

TableB‐1b.ProjectTAPEmissionsProjectEmissionRatea DeMinimis SQER

Benzene Year 57.25 0.331 6.62 YesFormaldehyde Year 391.75 1.6 32 YesNaphthalene Year 3.86 0.282 5.64 NoAcetaldehyde Year 16.95 3.55 71 No

Acrolein 24-hr 0.02 0.000394 0.00789 YesPropylene 24-hr 4.45 19.7 394 De Minimis

Toluene 24-hr 0.14 32.9 657 De MinimisXylenes 24-hr 0.09 1.45 29 De Minimis

Ethyl Benzene Year 475.94 3.84 76.8 YesHexane 24-hr 0.05 4.6 92 De Minimis

H2S 24-hr 0.93 0.0131 0.263 YesSO2 1-hr 3.60 0.457 1.45 YesNO2 1-hr 0.48 0.457 1.03 NoCO 1-hr 5.08 1.14 50.4 No

a Project emissions are conservatively determined to be the sum of the dual fuel scenario for the new boiler and the projected biogas emissions for the flare for all TAPs.

(lb/averagingperiod)PollutantAveragingPeriod

ModelingRequired?

TableB‐2a.PotentialEmissionsfromtheNewBoiler3‐NaturalGasCombustion

Maximum Operating Hours 8,760 hr/yearMaximum Heat Input Capacity b 97.6 MMBtu/hrEstimated Heat Input by Natural Gas a 854,976 MMBtu/yr

NaturalGasEmissionFactor

ExhaustGasEmissionFactor

EmissionFactora

(lb/MMscf) (lb/dry106scf) (lb/MMBtu) (lb/hr) (tpy)

PM10c 7.6 -- 7.45E-03 0.73 3.19

PM2.5c 7.6 -- 7.45E-03 0.73 3.19

SO2c 0.6 -- 5.88E-04 0.06 0.25

NOXd -- 4.18 3.64E-02 3.56 15.57

VOC c 5.5 -- 5.39E-03 0.53 2.31CO c -- 4.24 3.69E-02 3.60 15.78CO2e e -- -- 11,428.76 50,057.97

CO2e -- -- 116.98 11,416.97 50,006.32

N2O e -- -- 2.20E-04 0.02 0.09CH4

e -- -- 2.20E-03 0.22 0.94a

Natural gas heating value 1,020 Btu/scfb

c

d

e

CO2 1

N2O 298

CH4 25

CO EF (lb/MMscf) = CO concentration (ppm) × 1.660×10-7 (lb/scf)/(ppm-SO2) × 28.0101 (g/mol SO2) / 64.066 (g/mol CO) × 20.9%/(20.9%-3%) × 106

The emission factors for each GHG are obtained from 40 CFR 98 Subpart C, Tables C-1 and C-2 for natural gas combustion, and converted to values in lb/MMBtu. The GHGs emissions are calculated based on the Global Warming Potentials (GWP) provided in Table A-1 of 40 CFR 98.

NOX EF (lb/MMscf) = NOX concentration (ppm) × 1.194×10-7 (lb/scf)/(ppm-NOX) × 20.9%/(20.9%-3%) × 106

PollutantEmissionRate

The maximum heat input is based on vendor provided burner heat input.

Emission factors for small boilers (<100 MMBtu/hr) are obtained from Table 1.4.1 and Table 1.4.2, AP-42 Chapter 1.4, Natural Gas Combustion. Here it assumes that these emissions are not affected by the type of gas fired (natural gas or biogas). Note that the annual SO2 emissions listed in this table only represents natural gas combustion at the estimated annual natural gas usage listed here.Emission factors for NOX and CO are obtained from vendor guarantee of 30 ppm and 50 ppm corrected to 3% oxygen, respectively. The emission factors are converted from ppm to lb/MMscf using EPA Method 19 using the equations below. A conversion fuel factor of 8,710 dscf/MMBtu is used to determine the emission factor in lb/MMBtu.

The natural gas heating value below is used to convert the AP-42 emission factors in lb/MMscf to lb/MMBtu, in accordance with footnotes in Chapter 1.4. The boiler can fire all of the biogas generated and supplement the remaining heat input by natural gas, or fire 100% natural gas.

TableB‐2b.PotentialEmissionsfromtheNewBoiler3‐BiogasandNaturalGasCombustion97.6 MMBtu/hr

854,976 MMBtu/yr0.051 MMscf/hr325 MMscf/yr

32.44 MMBtu/hr206,674 MMBtu/yr

H2SContent(molarfraction) (lb/hr) (tpy)

SO2 from Biogas b 0.02% 98% 1.78 5.68H2S b 0.02% 98% 0.02 0.06

BiogasEmissionFactor


(lb/MMBtu) (lb/MMBtu) (lb/hr) (tpy)

PM10c 7.45E-03 7.45E-03 0.73 3.19

PM2.5c 7.45E-03 7.45E-03 0.73 3.19

SO2 from Natural Gas 5.88E-04 0.04 0.19NOX

c 0.04 0.04 3.56 15.57VOC c 5.39E-03 5.39E-03 0.53 2.31CO c 0.04 0.04 3.60 15.78CO2e d 11373.20 49880.95

CO2d 114.79 116.98 11346.18 49780.80

N2O d 1.39E-03 2.20E-04 0.06 0.21CH4

d 7.05E-03 2.20E-03 0.37 1.44a

Biogas heating value: 636 Btu/scfb

gas constant, J/K-mol: 8.314

Standard air temperature, K: 273.15

Standard pressure, Pa: 101325MW of SO2, g/mol: 64

MW of H2S, g/mol: 34.1c The same emission factors for natural gas combustion are used here for biogas combustion. d

H2S content is based on McCain's design information, consistently with other sites operating a wastewater treatment plant. Based on the sulfothane scrubber quote, the outlet H2S concentration will be less than 200 ppm. It assumes that 98% of the H2S will be combusted to SO2. The following parameters are used to convert the sulfur content from H2S to SO2:

DestructionEfficiency

Biogas consumption a

The emission factors for each GHG are obtained from 40 CFR 98 Subpart C, Tables C-1 and C-2 for other biomass gaseous fuels, and converted to values in lb/MMBtu. The GHGs emissions are calculated based on the Global Warming Potentials (GWP) provided in Table A-1 of 40 CFR 98.


Biogas consumption rate is based on McCain's estimates on annual basis. Here assumes that the new Boiler 3 can fire up to 100% of biogas generated. Hourly biogas consumption is based on McCain's estimate, which is 850 scfm. Biogas heating value is based on McCain's design information.

EmissionRate

Pollutant

Estimated Heat Input by Biogas a

Maximum Heat Input Capacity

TableB‐2c.PotentialEmissionsfromtheNewBoiler3

Pollutant

HourlyEmissionRate(lb/hr)

AnnualEmissionRate

(tpy)

PM10 0.73 3.19PM2.5 0.73 3.19SO2

a 1.82 5.87NOX 3.56 15.57VOC 0.53 2.31CO 3.60 15.78H2S b 0.02 0.06

HAPs 9.42E-03 0.04CO2e 11,429 50,058

a

b H2S emissions are from uncombusted biogas.

Emissions are the worst of combustion of natural gas only or dual fuel.

TableB‐2d.TAPandHAPEmissionsfromtheNewBoiler3Maximum Operating Hours 8760 hr/yrEstimated Heat Input by Natural Gas a 854,976 MMBtu/yrEstimated Annual Heat Input by Biogas b 206,674 MMBtu/yrEstimated Hourly Heat Input by Biogas b 32 MMBtu/hr

EmissionFactor NaturalGas Biogas

(lb/MMscf) (lb/MMBtu) (lb/hr) (tpy) (lb/MMBtu) (lb/hr) (tpy)

Benzene c Yes Yes 0.0058 5.69E-06 5.55E-04 2.43E-03 9.12E-06 6.66E-04 2.79E-03Formaldehyde c Yes Yes 0.0123 1.21E-05 1.18E-03 5.16E-03 1.93E-05 1.41E-03 5.91E-03PAH's (including Naphthalene)

c No Yes 0.0004 3.92E-07 3.83E-05 1.68E-04 6.29E-07 4.60E-05 1.92E-04

Naphthalene c Yes Yes - included above 0.0003 2.94E-07 2.87E-05 1.26E-04 4.72E-07 3.45E-05 1.44E-04

Acetaldehyde c Yes Yes 0.0031 3.04E-06 2.97E-04 1.30E-03 4.87E-06 3.56E-04 1.49E-03Acrolein c Yes Yes 0.0027 2.65E-06 2.58E-04 1.13E-03 4.25E-06 3.10E-04 1.30E-03Propylene c Yes No 0.5300 5.20E-04 0.05 0.22 8.33E-04 0.06 0.25Toluene c Yes Yes 0.0265 2.60E-05 2.54E-03 1.11E-02 4.17E-05 3.04E-03 1.27E-02Xylenes c Yes Yes 0.0197 1.93E-05 1.89E-03 8.26E-03 3.10E-05 2.26E-03 9.46E-03Ethyl Benzene c Yes Yes 0.0069 6.76E-06 6.60E-04 2.89E-03 1.08E-05 7.93E-04 3.31E-03Hexane c Yes Yes 0.0046 4.51E-06 4.40E-04 1.93E-03 7.23E-06 5.28E-04 2.21E-03

a


Biogas heating value: 636 Btu/scfc

TAP? HAP?


Biogas consumption rate is based on McCain's estimates on annual basis. Here assumes that the new alpha boiler can fire up to 100% of biogas generated. Hourly biogas consumption assumes the 30% combustion is contributed by biogas based on vendor info. Biogas heating value is based on McCain's design information.

Emissions factors for HAPs are taken from the Ventura County Air Pollution Control District AB 2588 Combustion Emission Factors. http://www.aqmd.gov/docs/default-source/permitting/toxics-emission-factors-from-combustion-process-.pdf. The emission factors provided are in the unit of lb/MMscf for natural gas external combustion sources in the size of 10-100 MMBtu/hr. The emission factor document does not specify the heating value to convert the factors from lb/MMscf to lb/MMBtu. For biogas it is assumed that the natural gas external combustion factors are representative, even though the heating value of biogas is much lower than that of natural gas. In this case, the lb/MMscf natural gas factors were applied to biogas combustion rate in scfm directly, which is conservative in estimating speciated HAP/TAP emissions from biogas combustion.

DualFuelEmissionRate

Pollutant

EmissionRate

TableB‐3a.PotentialEmissionsfromtheFlare‐PilotGas

Maximum Operating Hours 8,760 hr/yearPropane Usage a 1315 gal/yrEstimated Heat Inputa 120.31 MMBtu/yr

PropaneEmissionFactorb

PropaneEmissionFactorc

(lb/1000gal) (lb/MMBtu) (lb/hr) (tpy)

PM10 0.7 -- 1.05E-04 4.60E-04PM2.5 0.7 -- 1.05E-04 4.60E-04SO2 0.054 -- 8.11E-06 3.55E-05NOX 13 -- 1.95E-03 8.55E-03VOC 1 -- 1.50E-04 6.57E-04CO 7.5 -- 1.13E-03 4.93E-03CO2e c -- 1.91 8.37

CO2c -- 138.60 1.90 8.34

N2O c -- 1.32E-03 1.82E-05 7.96E-05CH4

c -- 6.61E-03 9.08E-05 3.98E-04a

Propane heating value 91.5 MMBtu/1000 galb

c

CO2 1

N2O 298

CH4 25


Emission factors for propane combustion are obtained from Table 1.5-1, AP-42 Chapter 1.5. According to an EPA study (https://www3.epa.gov/ttnchie1/conference/ei12/area/haneke.pdf), a national average sulfur content in LPG is 0.54 gr/1000 gal, which is used to determine the SO2 emission factor.

Propane usage is estimated based on a similar plant's actual usage, and scaled to the maximum amount usage for PTE purposes. Propane heating value from AP-42 Chapter 1.5 is used to determine the heat input.

The emission factors for each GHG are obtained from 40 CFR 98 Subpart C, Tables C-1 and C-2 for propane combustion, and converted to values in lb/MMBtu. The GHGs emissions are calculated based on the Global Warming Potentials (GWP) provided in Table A-1 of 40 CFR 98.

TableB‐3b.PotentialEmissionsfromtheFlare‐BiogasCombustion5.10E-02 MMscf/hr

325 MMscf/yrEstimated Heat Input by Biogas a 206,674 MMBtu/yr

H2SContent(molarfraction) (lb/hr) (tpy)

SO2b 0.02% 98% 1.78 5.68

H2S b 0.02% 98% 0.02 0.06

(lb/hr) (tpy)

PM10c 1.48E-02 lb/MMBtu 0.48 1.53

PM2.5c 1.48E-02 lb/MMBtu 0.48 1.53

NOXc 0.039 lb/MMBtu 1.25 3.99

CO c 0.045 lb/MMBtu 1.48 4.70VOC d 5.39E-03 lb/MMBtu 0.17 0.56CO2e e 3742.63 11923.51

CO2e 114.79 lb/MMBtu 3723.48 11862.51

N2O e 1.39E-03 lb/MMBtu 0.05 0.14CH4

e 7.05E-03 lb/MMBtu 0.23 0.73a

Biogas heating value: 636 Btu/scfb

gas constant, J/K-mol: 8.314

Standard air temperature, K: 273.15Standard pressure, Pa: 101325

MW of SO2, g/mol: 64

MW of H2S, g/mol: 34.1c

d

e

TableB‐3c.PotentialEmissionsfromtheFlare

Pollutant

HourlyEmissionRate(lb/hr)

AnnualEmissionRate(tpy)

PM10 0.48 1.53PM2.5 0.48 1.53SO2

a 1.78 5.68NOX 1.25 3.99VOC 0.18 0.56CO 1.48 4.71H2S b 0.02 0.06

HAPs 0.15 0.48CO2e 3,745 11,932

a

b H2S emissions are from uncombusted biogas.

Emissions are the sum from pilot gas combustion and biogas combustion.


Biogas consumption rate is based on McCain's estimates on annual and hourly basis. The maximum hourly biogas generation rate is expected to be 850 scfm. Biogas heating value is based on McCain's design information.

H2S content is based on McCain's design information, consistently with other sites operating a wastewater treatment plant. Based on the sulfothane scrubber quote, the outlet H2S concentration will be less than 200 ppm. It assumes that 98% of the H2S will be combusted to SO2. The following parameters are used to convert the sulfur content from H2S to SO2:

The emission factors for each GHG are obtained from 40 CFR 98 Subpart C, Tables C-1 and C-2 for other biomass gaseous fuels, and converted to values in lb/MMBtu. The GHGs emissions are calculated based on the Global Warming Potentials (GWP) provided in Table A-1 of 40 CFR 98.

EmissionRate

Biogas consumption a

PollutantDestructionEfficiency

The PM10, PM2.5, NOX and CO emission factors are obtained from AP-42 Chapter 2.4 (Draft version, October 2008). The factors for landfill flares are assumed to be representative of biogas combustion, because the landfill gas' heating value is close to biogas' heating value (about half of natural gas' heating value). Additionally, these factors are on the per scf CH4 burned, which should provide a representative estimate for biogas combustion using biogas' heating value. The lb/million dscf CH4 factor is converted to lb/MMBtu using CH4's HHV of 1011 Btu/scf.

The biogas stream contains mainly methane and other inert gases, which does contain small amount of VOC. The VOCs are usually destroyed during combustion. The same VOC emission factor for natural gas combustion is conservatively used here for biogas combustion (AP-42 Chapter 1.4 factors in lb/MMscf converted to lb/MMBtu using the default natural gas heating value of 1,020 Btu/scf).

EmissionFactor

TableB‐3d.TAPandHAPEmissions‐FlareMaximum Operating Hours 8760 hr/yrEstimated Heat Input by Propanea 120.31 MMBtu/yrEstimated Heat Input by Biogas b 206,674 MMBtu/yrEstimated Hourly Heat Input by Biogas b 32 MMBtu/hr

EmissionFactor Propane Biogas(lb/MMscf) (lb/MMBtu) (lb/MMBtu) (lb/hr) (tpy)

Benzene c Yes Yes 0.159 6.33E-05 2.50E-04 8.11E-03 0.03Formaldehyde c Yes Yes 1.169 4.65E-04 1.84E-03 0.06 0.19PAH's (including Naphthalene)

c No Yes 0.014 5.57E-06 2.20E-05 7.14E-04 2.28E-03

Naphthalene c Yes Yes - included above 0.011 4.38E-06 1.73E-05 5.61E-04 1.79E-03

Acetaldehyde c Yes Yes 0.043 1.71E-05 6.76E-05 2.19E-03 6.99E-03Acrolein c Yes Yes 0.010 3.98E-06 1.57E-05 5.10E-04 1.63E-03Propylene c Yes No 2.440 9.71E-04 3.84E-03 0.12 0.40Toluene c Yes Yes 0.058 2.31E-05 9.12E-05 2.96E-03 9.43E-03Xylenes c Yes Yes 0.029 1.15E-05 4.56E-05 1.48E-03 4.71E-03Ethyl Benzene c Yes Yes 1.444 5.74E-04 2.27E-03 0.07 0.23Hexane c Yes Yes 0.029 1.15E-05 4.56E-05 1.48E-03 4.71E-03

a

Propane heating value 91.5 MMBtu/1000 galPropane liquid to gas 36.4 cf/gal

b

Biogas heating value: 636 Btu/scfc Emissions factors for HAPs are taken from the Ventura County Air Pollution Control District AB 2588 Combustion Emission Factors.

http://www.aqmd.gov/docs/default-source/permitting/toxics-emission-factors-from-combustion-process-.pdf. The emission factors provided are in the unit of lb/MMscf for natural gas external combustion sources in the size of 10-100 MMBtu/hr. The emission factor document does not specify the heating value to convert the factors from lb/MMscf to lb/MMBtu. For biogas it is assumed that the natural gas external combustion factors are representative, even though the heating value of biogas is much lower than that of natural gas. In this case, the lb/MMscf natural gas factors were applied to biogas combustion rate in scfm directly, which is conservative in estimating speciated HAP/TAP emissions from biogas combustion.

TotalEmissionRate

Propane usage is estimated based on a similar plant's actual usage, and scaled to the maximum amount usage for PTE purposes. Propane heating value from AP-42 Chapter 1.5 is used to determine the heat input.

Biogas consumption rate is based on McCain's estimates on annual basis. Here assumes that the new alpha boiler can fire up to 100% of biogas generated. Hourly biogas consumption assumes the heat input capacity is reached by biogas combustion. Biogas heating value is based on McCain's design information.

Pollutant TAP? HAP?

TableB‐4a.PotentialEmissionsfromLine4

Operating Hours 8,760 hr/yearLine 4 Capacity 59,270 lb finished product/hr

PM10/PM2.5 VOC PM10/PM2.5 VOC PM10/PM2.5 VOCLine 4 Dryer and Two-Stage Fryer - Wet ESP

a0.041 0.413 1.22 12.23 5.35 53.59

1.22 12.23 5.35 53.59a

TOTALLine4

Line 4 dryer/fryer will be steam heated. Emissions from Line 4 dryer/fryer will be controlled by a new wet ESP. The wet ESP performance is based on recent McCain's Burley, ID plant source test results for a production line with a dryer and a two-stage fryer, accouting for a safety factor of 20%. The emission factor from the test report in lb/hr is converted to a lb/finished ton value using the production rate during the test. It is conservatively assumed all THC is VOC.

Stage

EmissionFactors(lb/finishedton)

EmissionRate(lb/hr)

EmissionRate(tpy)

TableB‐5a.PotentialEmissionsfromtheExistingBoiler1‐NaturalGas

Operating Hours 8,760 hr/yearNatural Gas Heating Value a 1,020 Btu/scfMaximum Heat Input Capacity b 65.98 MMBtu/hr

NaturalGasEmissionFactor EmissionFactor(lb/MMscf) (lb/MMBtu) (lb/hr) (tpy)

PM10c 7.6 7.45E-03 0.49 2.15

PM2.5c 7.6 7.45E-03 0.49 2.15

SO2c 0.6 5.88E-04 0.04 0.17

NOXc 100 0.10 6.47 28.33

VOC c 5.5 5.39E-03 0.36 1.56CO c 84 8.24E-02 5.43 23.80CO2e d -- 7,726.12 33,840.42

CO2e -- 116.98 7,718.15 33,805.50

N2O e -- 2.20E-04 1.45E-02 0.06CH4

e -- 2.20E-03 0.15 0.64a The natural gas heating value uses a typical heating value from AP-42. b

c

d

CO2 1

N2O 298

CH4 25e

The GHGs emissions are calculated based on the Global Warming Potentials (GWP) provided in Table A-1 of 40 CFR 98.

The emission factors are obtained from 40 CFR 98 Subpart C, Tables C-1 and C-2, and converted to values in lb/MMBtu.


The maximum heat input is based on vendor provided emission data at 100% firing rate.

Emission factors for small boilers (<100 MMBtu/hr) are obtained from Table 1.4.1 and Table 1.4.2, AP-42 Chapter 1.4, Natural Gas Combustion.

TableB‐5b.TAPandHAPEmissions‐Boiler1Maximum Operating Hours 8760 hr/yrEstimated Heat Input by Natural Gas a 577,985 MMBtu/yr

EmissionFactorb NaturalGas(lb/MMscf) (lb/MMBtu) (lb/hr) (tpy)

Benzene Yes Yes 0.0058 5.69E-06 3.75E-04 1.64E-03Formaldehyde Yes Yes 0.0123 1.21E-05 7.96E-04 3.48E-03PAH's (including Naphthalene) No Yes 0.0004 3.92E-07 2.59E-05 1.13E-04

Naphthalene Yes Yes - included above 0.0003 2.94E-07 1.94E-05 8.50E-05

Acetaldehyde Yes Yes 0.0031 3.04E-06 2.01E-04 8.78E-04Acrolein Yes Yes 0.0027 2.65E-06 1.75E-04 7.65E-04Propylene Yes No 0.5300 5.20E-04 0.03 0.15Toluene Yes Yes 0.0265 2.60E-05 1.71E-03 7.51E-03Xylenes Yes Yes 0.0197 1.93E-05 1.27E-03 5.58E-03Ethyl Benzene Yes Yes 0.0069 6.76E-06 4.46E-04 1.95E-03Hexane Yes Yes 0.0046 4.51E-06 2.98E-04 1.30E-03

5.30E-03 0.02a



Emissions factors for HAPs are taken from the Ventura County Air Pollution Control District AB 2588 Combustion Emission Factors. http://www.aqmd.gov/docs/default-source/permitting/toxics-emission-factors-from-combustion-process-.pdf. The emission factors provided are in the unit of lb/MMscf for natural gas external combustion sources in the size of 10-100 MMBtu/hr. The emission factor document does not specify the heating value to convert the factors from lb/MMscf to lb/MMBtu. For biogas it is assumed that the natural gas external combustion factors are representative, even though the heating value of biogas is much lower than that of natural gas. In this case, the lb/MMscf natural gas factors were applied to biogas combustion rate in scfm directly, which is conservative in estimating speciated HAP/TAP emissions from biogas combustion.

Pollutant TAP? HAP?EmissionRate

TOTALHAPs

TableB‐6a.PotentialEmissionsfromtheExistingBoiler2‐NaturalGas

Operating Hours 8,760 hr/yearNatural Gas Heating Value a 1,020 Btu/scfMaximum Heat Input Capacity b 95.55 MMBtu/hr


PM10c 7.6 7.45E-03 0.71 3.12

PM2.5c 7.6 7.45E-03 0.71 3.12

SO2c 0.6 5.88E-04 0.06 0.25

NOXc 100 0.10 9.37 41.03

VOC c 5.5 5.39E-03 0.52 2.26CO c 84 8.24E-02 7.87 34.47CO2e d -- 11,188.71 49,006.55

CO2e -- 116.98 11,177.17 48,955.98

N2O e -- 2.20E-04 0.02 0.09CH4


c

d

CO2 1

N2O 298

CH4 25e The emission factors are obtained from 40 CFR 98 Subpart C, Tables C-1 and C-2, and converted to values in lb/MMBtu.


The maximum heat input is based on vendor provided emission data at 100% firing rate.Emission factors for small boilers (<100 MMBtu/hr) are obtained from Table 1.4.1 and Table 1.4.2, AP-42 Chapter 1.4, Natural Gas Combustion. The GHGs emissions are calculated based on the Global Warming Potentials (GWP) provided in Table A-1 of 40 CFR 98.

TableB‐6b.TAPandHAPEmissions‐Boiler2Maximum Operating Hours 8760 hr/yrEstimated Heat Input by Natural Gas a 837,018 MMBtu/yr





7.68E-03 0.03a

Natural gas heating value 1,020 Btu/scfb Emissions factors for HAPs are taken from the Ventura County Air Pollution Control District AB 2588 Combustion Emission Factors.

http://www.aqmd.gov/docs/default-source/permitting/toxics-emission-factors-from-combustion-process-.pdf. The emission factors provided are in the unit of lb/MMscf for natural gas external combustion sources in the size of 10-100 MMBtu/hr. The emission factor document does not specify the heating value to convert the factors from lb/MMscf to lb/MMBtu. For biogas it is assumed that the natural gas external combustion factors are representative, even though the heating value of biogas is much lower than that of natural gas. In this case, the lb/MMscf natural gas factors were applied to biogas combustion rate in scfm directly, which is conservative in estimating speciated HAP/TAP emissions from biogas combustion.



TOTALHAPs

TableB‐7a.PotentialEmissionsfromLine1


PM10/PM2.5 VOC PM10/PM2.5 VOC PM10/PM2.5 VOC

Line 1 Dryer a 0.25 -- 4.88 -- 21.35 --Line 1 Fryer Stage A - Batter b 0.107 0.092 2.08 1.80 9.12 7.88Line 1 Fryer Stage B - Batter c 0.0564 0.092 1.10 1.80 4.82 7.88Line 1 Fryer Stage B - Conventional

c0.1087 0.092 2.12 1.80 9.29 7.88

8.06 3.60 35.29 15.76a Line 1 dryer is steam heated. The PM emissions are based on Othello's dryer emission factor.b

c

d

TableB‐7b.PotentialEmissionsfromLine2


PM10/PM2.5 VOC PM10/PM2.5 VOC PM10/PM2.5 VOC

Line 2 Dryer a 0.25 -- 4.88 -- 21.35 --Line 2 Fryer - Conventional b 0.1087 0.092 2.12 1.80 9.29 7.88

7.00 1.80 30.64 7.88a Line 2 dryer is steam heated. The PM emissions are based on Othello's dryer emission factor.b

EmissionRate(tpy)

TOTALLine2

Line 2 fryer is only for conventional products, and is controlled by the existing air washer. PM emission factor is based on source test based on air washer outlet for the corresponding product. VOC emissions are based on Othello's emission factor for fryers.

Line 1 fryer stage B is for battered products and conventional products, and is controlled by the existing air washer. PM emission factor is based on source test based on air washer outlet for the corresponding product type (batter or conventional), accounting for 20% safety factor. VOC emissions are based on Othello's emission factor for fryers.

Stage


EmissionRate(lb/hr)


EmissionRate(tpy)

Line 1 fryer stage A is for battered products only, and is controlled by the existing Wet ESP. PM emission factor is based on Wet ESP permit limit of 0.0262 gr/dscf per NOC No. DE 98AQ-E121, but scaled to a lb/finished ton factor using 2011 test result. VOC emissions are based on Othello's emission factor for fryers (test data applying 20% safety factor).

TOTALLine1d

Line 1 total emissions include dryer and fryer emissions. Fryer emissions are based on the batter products emissions for conservatism, because emissions are higher for manufacturing batter products than conventional products.

Stage

EmissionRate(lb/hr)

TableB‐8a.PotentialEmissionsfromtheLine3Dryer

Operating Hours 8,760 hr/yearLine 3 Capacity 10,000 lb finished product/hrNatural Gas Heating Value a 1,020 Btu/scfMaximum Heat Input Capacity b 10.00 MMBtu/hr


ExhaustGasEmissionFactor

(lb/MMscf) (lb/MMBtu) (lb/hr) (tpy)SO2

c 0.6 0.00 5.88E-03 0.03NOX

c 153 0.15 1.50 6.57VOC c 5.5 0.01 0.05 0.24CO c 373 0.37 3.66 16.02CO2e d 1,170.98 5,128.89

CO2d -- 116.98 1,169.77 5,123.60

N2O d -- 2.20E-04 2.20E-03 9.66E-03CH4

d -- 2.20E-03 2.20E-02 0.10

PM10/ PM2.5e

0.25 lb/ton finished product 1.25 5.48

a

b

c

d

CO2 1N2O 298CH4 25

e PM emissions are determined based on Othello's dryer emission factor.

TableB‐8b.PotentialEmissionsfromLine3Fryer


PM10/PM2.5 VOC PM10/PM2.5 VOC PM10/PM2.5 VOCLine 3 Fryer - Co-product

a0.107 0.092 0.53 0.46 2.34 2.02

a

TableB‐8c.PotentialEmissionsfromLine3

Pollutant

HourlyEmissionRate

(lb/hr)

AnnualEmissionRate

(tpy)

PM10 1.78 7.81PM2.5 1.78 7.81SO2 5.88E-03 0.03NOX 1.50 6.57VOC 0.52 2.26CO 3.66 16.02

HAPs 8.04E-04 3.52E-03CO2e 1,171 5,129


Line 3 dryer is a direct-fired dryer. Heat input capacity is based on the burner capacity. Emission factors from natural gas combustion are obtained from Table 1.4.1 and Table 1.4.2, AP-42 Chapter 1.4, Natural Gas Combustion. NOX and CO emission factors are based on April 1994 Ore-Ida source test for Ontario, OR facility, which are the best available source of factors from a direct-fired dryer using natural gas.

EmissionRate(tpy)

Line 3 fryer is only for co-product only, and is controlled by the existing wet ESP. PM emission factor is based on Wet ESP permit limit of 0.0262 gr/dscf per NOC No. DE 98AQ-E121, but scaled to a lb/finished ton factor using 2011 test result. VOC emissions are based on Othello's emission factor for fryers.

The emission factors for each GHG are obtained from 40 CFR 98 Subpart C, Tables C-1 and C-2 for natural gas combustion, and converted to values in lb/MMBtu. The GHGs emissions are calculated based on the Global Warming Potentials (GWP) provided in Table A-1 of 40 CFR 98.

The natural gas heating value below is used to convert the AP-42 emission factors in lb/MMscf to lb/MMBtu, in accordance with footnotes in Chapter 1.4.

Stage


EmissionRate(lb/hr)

TableB‐8d.TAPandHAPEmissions‐Line3Maximum Operating Hours 8760 hr/yrEstimated Heat Input by Natural Gas a 87,600 MMBtu/yr

b NaturalGas(lb/MMscf) (lb/MMBtu) (lb/hr) (tpy)



Acetaldehyde Yes Yes 0.0031 3.04E-06 3.04E-05 1.33E-04Acrolein Yes Yes 0.0027 2.65E-06 2.65E-05 1.16E-04Propylene Yes No 0.5300 5.20E-04 5.20E-03 0.02Toluene Yes Yes 0.0265 2.60E-05 2.60E-04 1.14E-03Xylenes Yes Yes 0.0197 1.93E-05 1.93E-04 8.46E-04Ethyl Benzene Yes Yes 0.0069 6.76E-06 6.76E-05 2.96E-04Hexane Yes Yes 0.0046 4.51E-06 4.51E-05 1.98E-04

a


http://www.aqmd.gov/docs/default-source/permitting/toxics-emission-factors-from-combustion-process-.pdf



TableB‐9a.PotentialEmissionsfromHVACSystems

Operating Hours 8,760 hr/yearNatural Gas Heating Value a 1,020 Btu/scfExisting HVAC Units Heat Input Capacity b 48.87 MMBtu/hrNew HVAC Units Heat Input Capacity b 65.35 MMBtu/hr


PM10c 7.6 7.45E-03 0.85 3.73

PM2.5c 7.6 7.45E-03 0.85 3.73

SO2c 0.6 5.88E-04 0.07 0.29

NOXc 100 0.10 11.20 49.05

VOC c 5.5 5.39E-03 0.62 2.70CO c 84 8.24E-02 9.41 41.20CO2e d -- 13,374.83 58,581.74

CO2e -- 116.98 13,361.03 58,521.30

N2O e -- 2.20E-04 0.03 0.11CH4


c

d

CO2 1

N2O 298

CH4 25e The emission factors are obtained from 40 CFR 98 Subpart C, Tables C-1 and C-2, and converted to values in lb/MMBtu.


The maximum heat input is the sum of all HVAC systems at Othello facility (existing and new).Emission factors for small boilers (<100 MMBtu/hr) are obtained from Table 1.4.1 and Table 1.4.2, AP-42 Chapter 1.4, Natural Gas Combustion. The GHGs emissions are calculated based on the Global Warming Potentials (GWP) provided in Table A-1 of 40 CFR 98.

TableB‐9b.TAPandHAPEmissions‐HVACSystemsMaximum Operating Hours 8760 hr/yrEstimated Heat Input by Natural Gas a 1,000,560 MMBtu/yr





9.18E-03 0.04a


http://www.aqmd.gov/docs/default-source/permitting/toxics-emission-factors-from-combustion-process-.pdf



TOTALHAPs

2. BACT Cost Calculations

CostCalculationsforVOCControl

TableB‐10a.CapitalCosts

CapitalCost ValueforTwoRTOs($) OAQPSNotationTRITON-65.95 Equipment Cost (x2) 2,554,000 Vendor QuoteStart-Up and Commissioning 40,000 Vendor QuoteTotalCapitalInvestment 2,594,000$ Vendor Quote

TableB‐10b.OperatingCostsOperatingCost Value OAQPSNotationGas Required (MMBtu/hr) 1 23 Vendor QuoteDirectAnnualCosts 3

Operating Labor (0.5 hr, per 8-hr shift) 2 18,221$ ESupervisory Labor 2 2,733$ F = 0.15 × EMaintenance Labor (0.5 hr, per 8-hr shift) 2 18,221$ GMaintenance Materials 2 18,221$ H = GNatural Gas Cost 4 1,021,544$ IElectricity 2,5 395,601$ J

TotalDirectAnnualCosts 1,474,541$ DAC=E+F+G+H+I+JIndirectAnnualCosts

Overhead 2 34,437$ M = 0.60 × (E + F + G + H)Administrative Charges 2 51,880$ N = 0.02 × TCIProperty Tax 2 25,940$ O = 0.01 × TCIInsurance 2 25,940$ P = 0.01 × TCICapital Recovery 6 217,064$ CRCS = TCI x CRF

TotalIndirectAnnualCosts 355,261$ IDAC=M+N+O+P+CRCTotalAnnualCost 1,829,802$ TAC=DAC+IDAC

1 Natural gas heat requirement calculated using burner size from vendor quote, which is 11.5 MMBtu/hr for each RTO.2

3 Values based on operating schedules and percentages specified in OAQPS Manual, Section 3.2, Chapter 2, Table 2.104 Natural gas cost is from Cascade Natural Gas Corp. rate for large volume general services. The lowest tier rate is conservatively used here to estimate the cost.5

6

TableB‐10c.ControlCostEffectivenessAnnual Control Cost per Oxidizer ($/oxidizer, in 2019 $) 914,901$

152.78

Control Cost Effectiveness (2019 $/ton) 17,334$ 1

The VOC can be collected and controlled would be the new production line, downstream of the proposed wet ESP. Therefore, only VOC emissions from the new production line is considered in this case. Vendor guarantees a removal efficiency of 98.5%.

Cost factors taken from OAQPS Cost Control Manual (CCM) - U.S. EPA, Office of Air Quality Planning and Standards (OAQPS), EPA Air Pollution Control Cost Manual, 7th Ed Section 3.2 VOC Destruction Controls, Chapter 2.5

Electricity costs include fan operation. Based on vendor quote, there is a 15 hp combustion blower, a 350 hp induced draft booster fan, and a 350 hp AB PowerFlex Series VFD for RTO volume control, for each of the RTO. The cost is based on the utility rate in Othello, WA.The capital recovery factor is calculated according to OAQPS CCM Section 1, Chapter 2, Equation 2.8a. The interest rate recommend by EPA can vary by firm or industry, but the bank prime rate is a default rate that can be used for annualization of capital costs (OAQPS CCM 7th Edition, Section 1, Chapter 2). This rate is 5.5% as of February 2019 (https://www.federalreserve.gov/releases/h15/). The annual recovery assumes the equipment life of 20 years, which is the default life span from OAQPS CCM, Section 3.2.

Pollutant to be removed at 100% capture and 98.5% control efficiency (tpy)

CostCalculationsforNOXControl

TableB‐11a.CapitalCosts

CapitalCost ValueforOneSCR($) OAQPSNotation

TotalCapitalInvestment

1

2,207,273$ TCI = $10,530 x ((1,640 MMBtu/hr) / (QB (mmBtu/hr))0.35 x QB x ElevF x RF

TableB‐11b.OperatingCostsOperatingCost Value OAQPSNotation

DirectAnnualCosts

Operating Labor (4 hr, per day) 2 48,589$ EMaintenance Cost and Labor 3 11,036$ F = 0.005 × TCIReagent Cost 4 3,234$ GCatalyst Replacement Cost 5 39,623$ HElectricity 6,7 20,277$ I

TotalDirectAnnualCosts 122,758$ DAC=E+F+G+H+I

IndirectAnnualCosts

Overhead 8 -$ Administrative Charges 9 1,590$ J = 0.03 × (E + 0.4 × F)Capital Recovery 10 164,551$ CRCS = TCI x CRF

TotalIndirectAnnualCosts 166,141$ IDAC=J+CRCTotalAnnualCost 288,899$ TAC=DAC+IDAC

1

2

3

4

5

6

7

8

9

10

TableB‐11c.ControlCostEffectiveness288,899$

15.57Estimated NOX Emissions Removed w/ SCR (tpy) 2.08

21,406$

Overhead, property tax, and insurance costs are considered to be zero as the SCR system requires minimal operating or supervisory labor, in many cases property taxes do not apply to capital improvements such as air pollution control equipment, and an SCR system is not viewed as risk-increasing hardware according to OAQPS CCM, Section 4, Chapter 2.

Equation 2.53 from OAQPS Cost Control Manual (CCM) - U.S. EPA, Office of Air Quality Planning and Standards (OAQPS), EPA Air Pollution Control Cost Manual, 7th Ed Section 4 NOx Controls, Chapter 2 (updated 6/12/2019). Assume an elevation factor of 1, and a retrofit factor of 1 for new construction.Operation of an SCR system requires minimal, operating or supervisory labor; therefore, it is estimated that operating labor time will be 4 hours per day per OAQPS CCM, Section 4, Chapter 2.Equation 2.57 from OAQPS CCM - Section 4, Chapter 2.

Equation 2.63 from OAQPS CCM - Section 4, Chapter 2. Assumed 1 reactor chamber, cost of catalyst is $8,000/m3, and there are 3 catalyst layers, which are default values from the associated CCM SCR Cost Calculation Spreadsheet (dated June 2019). Catalyst volume is calculated following Equations 2.22 through 2.27: the efficiency of NOX

control is determined based on the inlet and outlet NOX concentrations (30 ppm and 4 ppm, respectively); ammonia slip assumes to be 5 ppm to be conservative; sulfur adjustment is based on post-treated biogas sulfur content of 200 ppm; and temperature adjustment is based on the exhaust temperature of 290 F based on vendor infomration for the boiler. The annualized catalyst replacement cost assumes replacement every 3 years at the bank prime rate.

Equation 2.61 and 2.62 from OAQPS CCM - Section 4, Chapter 2.

The cost is based on the utility rate in Othello, WA.

Pre-SCR NOX Emissions (tpy)Annual Control Cost per SCR ($/SCR, in 2019 $)

Control Cost Effectiveness (2019 $/ton)

Equation 2.69 from OAQPS CCM - Section 4, Chapter 2.

Equation 2.70 and 2.71 from OAQPS CCM - Section 4, Chapter 2. Assumes the SCR life of 25 years.

Eq. (2.58) and Eq.(2.35) from OAQPS CCM - Section 4, Chapter 2 assuming ammonia is used as the reagent. Cost based on anhydrous ammonia price of $616.47/ton in 2019 per Illinois Production Cost Report https://www.ams.usda.gov/mnreports/gx_gr210.txt (accessed Jun 20, 2019).

TableB‐12.SupportingCostDataOperatorCost

2019 33.28 $/hr

Labor rate is based on median hourly wage for Plant and System Operators, Other, based on May 2019 Washington State Occupational Employment and Wage Estimate, Bureau of Labor Statistics. https://www.bls.gov/oes/current/oes_wa.htm#49-0000

MaintenanceCost

2019 33.28 $/hr

Labor rate is based on median hourly wage for Plant and System Operators, Other, based on May 2019 Washington State Occupational Employment and Wage Estimate, Bureau of Labor Statistics. https://www.bls.gov/oes/current/oes_wa.htm#49-0000

ElectricityCost

2019 0.0424 $/kW-hrAvista Utilities rate for extra large general service rate in Washington. The lowest tier rate is conservatively used here to estimate the cost.

NaturalGasCost

2019 5.07 $/MMBtuCascade Natural Gas Corp. rate for large volume general services. The lowest tier rate is conservatively used here to estimate the cost.

BankprimerateFeb-19 5.5% https://www.federalreserve.gov/releases/h15/

3. Vendor Quote - RTO

CONFIDENTIALITY NOTICE: This document and its contents are confidential and are intended solely for the

use of the addressee. Any use, dissemination, distribution, or copying of this document and its contents is

strictly prohibited without the express written permission of Catalytic Products International.

980 Ensell Road | Lake Zurich, Illinois 60047 | office: 847.438.0334 | fax: 847.438.0944

e-mail: [email protected] | website: www.cpilink.com

Proposal for Two (2) TRITON 65.95

Regenerative Thermal Oxidizer

Proposal Number B19-8295

Presented To:

Trinity Consultants Trinity Consultants

20819 72nd Ave. South, Suite 610

Kent, WA 98032

Attention: Hui Cheng

For:

Trinity Consultants Potato Chip Manufacturing Plant

302 Western Street

Auburn, WA 98001

Prepared By:

Catalytic Products International, Inc.

980 Ensell Road

Lake Zurich, Illinois 60047

Dennis L. Salbilla

Regional Sales Manager

847-550-4118

June 4th, 2019


http://www.cpilink.com/

Quote B19-8295 Rev. 0 P a g e | 2

Table of Contents

Section 1a: Basis of Design ................................................................................................................... 3

Project Background ..................................................................................................................... 3

Basis of Recommendation .......................................................................................................... 3

Unique Features of the TRITON Series ..................................................................................... 7

Section 1b: Equipment Specifications ...............................................................................................11

TRITON 65.95 RTO..................................................................................................................... 11

Section 2: Equipment Description ......................................................................................................12

General Description ................................................................................................................... 12

Fresh Air Purge and Idle Damper ............................................................................................ 13

Even-Flo Manifolds .................................................................................................................... 13

Vertical Posi-Seal Valves ........................................................................................................... 14

Cold Face Supporting Grid ....................................................................................................... 17

Regenerator Heat Exchange Media ........................................................................................ 17

Regenerators and Combustion Chamber .............................................................................. 18

Burner System ............................................................................................................................ 19

Burner Gas Train ........................................................................................................................ 20

ID Booster Fan............................................................................................................................ 21

System Control .......................................................................................................................... 22

ID Booster Fan Motor Control ................................................................................................. 25

Startup Services ......................................................................................................................... 26

Section 3: Equipment Budgetary Cost Summary ............................................................................27

Project Investment .................................................................................................................... 27

Payment Terms .......................................................................................................................... 27

Equipment Delivery ................................................................................................................... 27

Equipment Shipment ................................................................................................................ 27

SECTION 4: BUYER’S RESPONSIBILITIES .........................................................................................28

SECTION 6: EQUIPMENT WARRANTY .............................................................................................29

SECTION 7: TERMS and CONDITIONS .............................................................................................30

Quote B19-8295 Rev. 0 P a g e | 3

Section 1a: Basis of Design

Project Background

Trinity Consultants is exploring abatement options for odor control for a potato chip manufacturing

plant in Washington state. The sources that will be abated are from a wet Electrostatic Precipitator

(ESP) containing VOCs created by potato fryers.

Basis of Design

This proposal covers the design and supply of Two (2) Regenerative Thermal Oxidizer (RTO) unit. CPI

understands the exhaust characteristics are:

Plant A

Exhaust Flow Rate ACFM 130,000

Exhaust Temperature °F less than 100

VOC Composition TBD

VOC Load #/h 13

The final design engineering as noted in this proposal will incorporate all the necessary components

to exceed the air compliance goals and operational requirements while using our proven and

innovative design features to provide a highly reliable system.

Basis of Recommendation

Catalytic Products International (CPI) has worked with a variety of industries to develop a proven and

innovative technique to eliminate VOC emissions from multiple process exhaust operations.

Regenerative Thermal Oxidization in this application is being presented based on its ability to meet

the compliance goals of 98.5% VOC DRE or to a lower limit of 30 ppm VOC and reduce the

operating cost for air pollution control. The final design engineering as noted in this proposal will

incorporate all the necessary components to successfully destroy the Odor and VOC’s from Trinity

Consultants sources, while using our proven and innovative design features to provide a highly

reliable system.

Quote B19-8295 Rev. 0 P a g e | 4

Regenerative Thermal Oxidizer – How Does It Work?

The (2) TRITON 65.95 Regenerative Thermal Oxidizer system recommended in this proposal will

allow:

https://www.youtube.com/watch?time_continue=15&v=WdS4ijpByho

https://www.youtube.com/watch?time_continue=15&v=WdS4ijpByho

Quote B19-8295 Rev. 0 P a g e | 5

• Continuous VOC destruction and odor abatement across operational range

• Low cost of operation

• Fully automatic operation - with no operating interface required

• Easy installation

• Highest reliability with minimal maintenance

The TRITON system designed will include our innovative design features allowing for continuous

VOC destruction. The basis of the design will not place limitations on the client for solvent

concentrations; it will provide the specified VOC destruction independent of solvent concentration.

This continuous destruction ability is key to air pollution control design. The TRITON system is not

hindered by any operational characteristics.

The systems low cost of operation will center on the use of a nominal 95% primary heat exchanger.

The heat exchanger is made up of a thermally stable structured ceramic. This special heat exchange

system will provide very low burner heating demands and provides very low static pressures for

reduced electrical consumption. Sophisticated control logic constantly analyzes the regenerator

temperature profiles from several thermocouple inputs and constantly adjusts valve timing to

maximize the thermal rate efficiency of the system.

TRITON Regenerative Thermal Oxidizer

The system will incorporate our TSS controls to provide fully automatic operation. The system will

incorporate our TSS control package to supervise the operation of the RTO and integrate with the

process.

Each TRITON system is designed to allow the highest uptime reliability with minimal maintenance.

The maintenance requirements will be fully described in the supplied operator manuals, and only

Quote B19-8295 Rev. 0 P a g e | 6

includes normal fan maintenance, linkage tightening, and bearing lubrication. The system uses a

few moving parts, and these parts are accessible from outside of the system. There is no need to

enter the oxidizer for normal maintenance. The TRITON System also employs a “bake-out” feature

that will allow periodic high temperature cleaning of condensate residue from the lower levels of the

media beds and cold face support, along with the ability of being washed down with water. The

media selected for this application is designed for use in rendering applications.

Quote B19-8295 Rev. 0 P a g e | 7

TRITON II RTO with Polishing Chamber

Unique Features of the TRITON Series

Regenerative Thermal Oxidizer

The TRITON Series is designed to be very easy to assemble, and is comprised of four modular units:

• The Regenerator, which holds the media, loaded on-site

• The Even-Flo manifolds, which contain the Posi-Seal Valves

• The Combustion Chamber, which is installed on top of the regenerator

• Auxiliary items such as exhaust stack and booster fan are shipped separately for field

installation

The modular system is structurally sound and designed to be placed on a foundation or support

structure. All four modular components are fit together in our shop prior to shipment to insure

proper field assembly.

Quote B19-8295 Rev. 0 P a g e | 8

The regenerator arrives on a flatbed truck to be mounted on the foundation

Items to Note:

1) The flanged assembly simplifies connection to the Even-Flo Manifolds

2) Structurally superior cold face support

3) Multiple thermocouple connections for better temperature control

4) Structural reinforcements ensure a long useful equipment life

Item 1

Item 2

Item 3

Item 4

Quote B19-8295 Rev. 0 P a g e | 9

The Even-Flo Manifolds are mounted directly next to the regenerator

Items to Note:

1) The minimized size (volume) of our Even-Flo manifolds is extremely important at insuring

high VOC destruction

2) No field installation of the valves is required insuring proper operation at time of installation.

3) Compact and efficient design of both the regenerator and the Even-Flo Manifold.

The TRITON Series RTO will be shipped in four main sections.

This photo shows setting the Regenerator Tower Section.

Item 1 Item 2

Quote B19-8295 Rev. 0 P a g e | 1 0

The Even-Flo Plenum Module will be field assembled to the regenerators.

The combustion chamber will be set atop the regenerators.

Quote B19-8295 Rev. 0 P a g e | 1 1

Section 1b: Equipment Specifications

Plant Information

Plant Location Washington State

Plant Elevation ‘ASL – assumed < 500 FASL

Process Potato Chip

Manufacturing

Ambient Temperature - Average °F 30 – 80

Relative Humidity - Average % –20 - 50

Seismic Zone 1

Wind Velocity - assumed mph 30

Electrical Area Classification Unclassified

Equipment Location Outdoors at grade

Fuel Natural Gas

Fuel Pressure psig 5-10

Electrical Requirements 480 VAC, 3-phase, 60 Hz

Compressed Air @ -40 °F dewpoint, clean and dry psig 85-95

TRITON 65.95 RTO

Quantity of Units 2

Operating Temperature – normal °F 1,500

Operating Temperature – maximum °F 1,800

Residence Time sec 1

Heat Exchanger Effectiveness % 95

Insulation – Type

Ceramic Fiber

Insulation – Thickness Inch 6

Insulation – Density lb/ft3 10

Burner Capacity – Installed MMBtu/h 11.5 Each RTO

Combustion Blower Hp 15 Each RTO

Induced Draft Booster Fan hp 350 Each RTO

AB PowerFlex Series VFD for RTO Volume Control hp 350 Each RTO

Quantity of PLC

1 Each RTO

Natural Gas Requirements CFH 23,000 Total

Compressed Air Requirements CFM 20 Total

Electrical Requirements Amps 1100

Quote B19-8295 Rev. 0 P a g e | 1 2

Section 2: Equipment Description

General Description

TRITON Regenerative Thermal Oxidizers are specially designed systems that provide industry leading

VOC destruction, the lowest operating cost, and the highest uptime reliability.

The Regenerative process starts by using a

system booster fan to draw in process

emissions gasses into the Even-Flo manifolds

and the RTO. The process emissions are

directed into one set of Posi-Seal Valves, for

distribution into one of two regenerator

columns. Posi-Seal Valves in conjunction with

the Even-Flo manifolds are the basis for all

TRITON systems ability to provide continuous

VOC destruction. The design of these two

revolutionary components takes advantage of

leak-free construction and minimal flushing

volumes. The results provide the user with

only high performance and minimized costs.

From the exit of the Posi-Seal Valves, the un-

treated exhaust enters one of the ceramic

media filled regenerator columns. Here the

exhaust stream is heated from approximately

95° F to over 1,425° F. The structured ceramic

media used in the TRITON Series Regenerative

Thermal Oxidizer provides low (flange to

flange) static pressures and the highest thermal rate efficiency. TRITON systems pack more thermal

heat transfer in a smaller package.

Upon exiting the regenerator column, the exhaust will be oxidized in the combustion chamber,

where the temperature will be raised to 1,500° F. At this temperature the majority of the entering

VOC's will be converted to CO2 and water vapor. When solvent loads are sufficient (usually + 3%

LEL) the natural gas burner system can be shut off and self-sustaining operation is achieved.

These combusted VOC are then drawn into the second regenerator column to give up the heat to

the incoming un-treated air, and then finally exhausted out of the booster fan into the exhaust stack

to atmosphere. The whole process is controlled via the TSS control system. Posi-Seal Valve

positioning is monitored for precise destruction and thermal exchange effectiveness. No input is

required by operators.

Quote B19-8295 Rev. 0 P a g e | 1 3

Fresh Air Purge and Idle Damper

CPI will provide one (1) 44” diameter fresh air purge and idle damper for each oxidizer

• 316L stainless steel

• 4-20 mA modulating RCS direct drive motor

• Personnel protection on weather-hood inlet,

• Loose matching stainless steel flange.

Even-Flo Manifolds

The start of the TRITON regenerative oxidation process begins with the introduction of process

exhaust through the Even-Flo inlet manifolds. The basis of the Even-Flo design takes advantage of

duct-under construction to minimize flushing air volume while maximizing flushing efficiency. The

Even-Flo manifolds are specially designed for even air distribution to the regenerator beds. Each

manifold is constructed and designed for maximum performance, durability, and easy access. The

Even-Flo manifolds are shop fitted to the Posi-Seal Valves. The Even-Flo inlet manifolds are supplied

shop insulated to minimize heat losses during operation.

• 3/16” thick 316L stainless steel shell with external carbon steel structural reinforcing.

o Externally insulated and clad in aluminum cladding. A structural deck will be

provided to allow personnel access to poppet valve deck

o (2) 22” x 48” poppet valve access doors located at grade

• (2) dual element thermocouples for RTO inlet and outlet temperature monitoring.

• (1) Siemens SITRANS differential pressure transmitter

o Pre-mounted and piped

• Inlet manifold will be insulated and clad. Reminder of oxidizer housing is insulated internally.

Quote B19-8295 Rev. 0 P a g e | 1 4

Vertical Posi-Seal Valves

This perhaps is the most important feature about any TRITON system is the highly reliable

regenerator valves use the concepts that we made famous in our FLOATING TUBE recuperative heat

exchangers, stress free designs with zero leakage. When compared to less reliable butterfly or other

poppet valve assemblies, Posi-Seal valves provide a level of sophistication that is un-matched.

Posi-Seal valves are designed to take advantage of a vertical axis that allows for soft seating action

with self-centering guidance. The innovative feature about all Posi-Seal valves is the air tight

machined seal that eliminates valve bypass and maintenance intensive gaskets. The Posi-Seal valve

will be pneumatically operated and will cycle open or closed based on the program logic called for

in this application. Each Posi-Seal valve will include the following:

• Cylinder exhaust to be piped to Even-Flo exhaust manifold with ¾” dia synthetic rubber

hose with push lock fitting. A ¾” NPT locking ball valve will also be provided in the line.

• 1/4-inch thick platter reinforced with 7/8” thick coupling plates are bolted together with

aircraft style wire tie of all fasteners

• Hanna heavy duty air cylinders with Parker directional control solenoids

• Heavy Duty Construction including:

o 2-inch diameter damper shafts

o High temperature linear bearings

o Cylinder alignment couplings

• Proximity switches to prove position

• (2) 20-gallon ASME rated compressed air holding tanks (one for each poppet valve)

o Interconnecting air supply from accumulation tanks to air cylinders and between

tank connection to be ¾” synthetic rubber hose with push lock fittings rated for 250

PSIG

o (1) Ashcroft low compressed air pressure switch will be mounted to the far

accumulation tank with pressure gauge

Posi-Seal Valving Technology

Superior design and high-quality

construction allow TRITON Systems to

effectively treat very large exhaust

streams with the same performance as

smaller Regenerative Thermal

Oxidizers.

Quote B19-8295 Rev. 0 P a g e | 1 5

• Compressed sch 40 threaded air train including the following:

o ½” #150 raised face flange inlet connection

o ½” sch 40 threaded piping

o ½” npt locking ball valve shutoff

o ½” npt check valve

o ½” npt regulator

• Each valve is factory adjusted for: stroke, proximity switch position, and soft seating

guidance.

Posi-Seal Valves provide industry leading technology and are the corner stone of

the TRITONs ability to provide high destruction rates.

• Zero leakage across operating range

• Heavy duty platters and shafts

• Minimized entrained volumes for the highest destruction rates

• Pneumatic operators with fully piped and wired systems

• All TRITON Systems utilize air actuators pre-set at the factory.

• Actuators are pre-piped and wired and include compressed air dryers to

insure moisture free air to all actuators.

Pneumatic POSI-SEAL Valve Operator and

Compressed Air Holding Tank

Quote B19-8295 Rev. 0 P a g e | 1 6

Posi-Seal Valves incorporate several features that

work to provide long service life, minimal attention,

and high performance.

The most important feature of the Posi-Seal Valve

is that is constructed as a complete structural

assembly. The assembly is mounted into the Even-

Flo Manifold and will not relay on shared loads of

the manifold.

The operation of the Posi-Seal Valve is vertical,

thereby eliminating wear and tear routinely

encountered in horizontal designs.

Show below is a high temperature linear bearing

that is used in two locations across the valve shaft.

The linear bearing eliminates wear and provides

long service life.

High temperature linear bearing package insures smooth linear action

Bearings used at two points to provide extraordinary support of the valve

Quote B19-8295 Rev. 0 P a g e | 1 7

Cold Face Supporting Grid

The cold face support grid is another innovative technique developed to allow high support strength

and low pressure drop. While conventional systems use, a low cost expanded metal support, the

TRITON’s cold face support grid is a fabricated structure made of 3" x 3/8” 316L bar stock on top of

a unique system of 316L I-beam support. The advantages offered in our cold face support grid are;

high strength, lowest pressure drop, and eliminated plugging.

Regenerator Heat Exchange Media

Due to plugging concerns caused by the rendering process, CPI is proposing a more particulate-

tolerant and maintenance-friendly media bed design style block.

This TRITON Series Regenerative Thermal Oxidizer utilizes a special media design a special structured

block for flow distribution, relatively open cells for all the media and a special thermally resistant ½

block for the top layer.

• The top layer is a ½ block to increase thermal shock resistance by reducing the thermal

gradient of one block.

• S-type technology utilized for plug resistance and redistribution effects for the top layer

• MK20 25 cell material installed in the top of the bed protects the layers below from

particulate and extends the lower layers life

• MK20 ½ blocks can be easily removed, cleaned outside the unit, and reinstalled

• The intermediate layers are comprised of LA10 with 37 cells which is a novel honeycomb cell

structure characterized by a coarse cell geometry (3.4 x 3.4 mm²) and relatively thin cell wall

thickness (0.6 mm) resulting in the highest open frontal area (>72%) ratio of heat media

honeycombs for Regenerative Thermal Oxidizer applications. This cell design is optimized

for high particulate laden and non-corrosive gas streams. The relatively high surface area

for a large cell type block geometry of about 847 m²/m³ renders high efficiencies in RTO

applications by applying significantly less heat media volume compared to 25 or 32 cell

designs and similar volumes to 40x40 cell bed designs. Combining the advantages of the

highest open frontal area and increased surface area provide this structure with advantages

in pressure drop and thermal performance than larger sized cell types (25 and 32 cell)

• HD block provide for distribution for the bottom layer

CPI has developed a

revolutionary Cold Face Support

System. The support minimizes

pressure losses while

strengthening the regenerator.

316L stainless steel construction.

Quote B19-8295 Rev. 0 P a g e | 1 8

Catalytic Products has experience with RTO’s plugging with organic particulate and extending the

run time between media change outs. It has been our experience that the structured block bed

proposed offers the ability of being washed down following a bake-out more completely than with

a saddle bed.

Regenerators and Combustion Chamber

The main housing consists of two (2) internally insulated regenerators connected by a common

insulated combustion chamber. The combustion chamber is designed in conjunction with the nozzle

mix burner system for even temperature uniformity, leading to high performance and lower

operating cost. The unit is shop assembled to simplify field erection. The construction of the

regenerators and combustion chamber is made up of the following materials:

• The regenerator towers and combustion chamber are fabricated from at least 3/16” thick

316L stainless steel shell reinforced with carbon steel external structural framing.

o The combustion chamber will be supplied with a 24” x 24” hinged access door to

the combustion chamber.

• Painted carbon steel I-beam skid frame shared with Even-Flo inlet manifold.

• Special ceramic media sized for nominal 95% heat recovery and rendering applications.

• Three (3) dual element thermocouples are provided in each media bed for precise

temperature profiling of the ceramic media.

• Three (3) dual element thermocouples are provided in the combustion chamber. (two for

temperature control and one for high temp limit)

• Two (2) 1/4 NPT pressure ports will be provided above and below each media bed for

manual pressure monitoring.

• Burner site glass will be provided.

Quote B19-8295 Rev. 0 P a g e | 1 9

Modular Regenerator Technology

Burner System

The burner will be a Maxon Kinemax, or equal, Nozzle Mix gas burner system. A nozzle mix burner

uses external combustion air to provide sufficient oxygen even in an oxygen-deficient air stream and

to provide a stable flame pattern throughout the operating range of the system while providing low

NOx emissions. The burner is designed to promote mixing when fired horizontally into the

combustion chamber and provides even heating during regenerator switching. This design provides

the high velocity which creates a tremendous amount of turbulence and leads to the excellent

temperature uniformity for which TRITON RTO’s are known.

The Maxon Kinemax allows a 40:1 turndown, requires low gas pressure (5 psi), and emits low levels

of NOx and CO.

The Maxon burner will include the following:

• Two (2) Maxon 6” Kinemax burner with ceramic discharge sleeve pre-mounted into the

combustion chamber per oxidizer

• Honeywell self-checking UV scanner with air purge for flame supervision

• Maxon CV gas control valve will be piped after the gas train and before the burner.

o Honeywell Modutrol-4 electric operator and mechanical linkage and low fire start

switch

• External combustion air blower with the following supply details:

o The combustion air blower will be a New York Blower, pressure blower complete

with the following equipment:

▪ 460 VAC, 3-phase, 60 Hz, direct drive TEFC motor

▪ Standard carbon steel punched flanges at inlet & outlet

▪ Inlet filter with silencer

• The combustion air blower will be mounted on top of the Even-Flo Manifold – allowing

convenient connection to the gas burner. The auxiliary equipment includes:

o Carbon steel wafer type manual control damper with locking lever arm

o Punched, flanged outlet fitting with flex connection

Quote B19-8295 Rev. 0 P a g e | 2 0

o Painted carbon steel combustion air blower ducting from discharge of blower to

inlet of burner.

o Includes flanged connection and pre-mounting of the following air control valve:

▪ Maxon M3 carbon steel combustion air control valve with Honeywell

Modutrol-4 electric operator

▪ Welded pressure ports as necessary

o Inlet filter/silencer

o A Karl Dungs proof of air flow pressure switch will be provided in a NEMA 4

enclosure, shipped loose for field mounting and piping by others

Burner Gas Train

This natural gas train is designed pursuant to NFPA-86 and will include the following components:

• The gas train will be a 2.5” diameter schedule 40 BI, threaded construction, rated for outdoor

installation:

o Pre-piped and mounted inside a gas train cabinet with bottom venting

▪ The cabinet will be mounted on the combustion chamber and prepiped to

the preheat burner

▪ Gas pipe from the gas train outlet to the burner inlet is factory installed.

▪ Stainless steel flex connection mounted at burner elevation for both main

gas and pilot

▪ Pre-wired to a NEMA 4 junction box. The junction box will be mounted to

the gas train cabinet.

o 6000V ignition transformer in a NEMA 4 enclosure with ignition wire to burner

o Shop leak tested prior to shipment.

• Inlet main shut-off valve

• Inlet Strainer

• Main Gas Train

o Main natural gas regulator with piping and shut-off valves

o Low gas pressure switch

o Two Honeywell Series automatic shut-off valves

o High gas pressure switch

o Main gas shut-off valve

• Pilot Gas Train

o Two (2) Pilot gas shut-off valves

o Pilot gas regulator

o Two (2) ASCO pilot solenoids

o Three (3) pressure indicator gauges with manual shut-off

Quote B19-8295 Rev. 0 P a g e | 2 1

ID Booster Fan

The induced draft booster fan will be a New York Blower or equivalent, meeting with the following

supply details: Arrangement 8, 1770 rpm, fan, complete with the following features and accessories:

• Externally insulated and clad

• Heavy-duty, all-welded, 316L stainless steel construction

• Punched, flanged inlet and outlet

• Shaft / bearing and coupling guards

• Bolted access door

• Housing drain

• Ceramic felt shaft seal

• Constant speed, direct drive coupling package

• 1800 rpm, 3/60/460v, TEFC, PE, VFD rated motor

• Booster fan construction is good to for use with the bakeout system.

Quote B19-8295 Rev. 0 P a g e | 2 2

• Karl Dungs proof of air flow pressure switch pre-mounted inside a NEMA 4 enclosure and

mounted to oxidizer Even-Flo plenum

• Siemens SITRANS inlet duct pressure transmitter for inlet duct pressure control (shipped

loose for field mounting on customer supplied ductwork)

o Note: The booster fan is sized to provide a maximum of -2.0” W.C. negative pressure to

evacuate the process ducting.

System Control

Each TRITON Series Regenerative Thermal Oxidizer comes equipped, as standard, with a special

control and monitoring package called Temperature Safety System (TSS). It has been developed for

the use of protecting the oxidizer and providing self-diagnostics.

The TSS-PLC panel allows the entire oxidizer system to be a one-button start/stop operation. This

provides user-friendly operation and avoids costly operator errors. TSS controls temperature

programming during all phases of the oxidizer's warm up, operating, and cool down cycles. This

minimizes thermal stress on components and provides long equipment life. TSS will also integrate

the process with the operation of the oxidizer for safe, economical operation.

The TRITON Series Regenerative Thermal Oxidizer process begins with the touch of a button, which

activates the system’s PLC-based Temperature Safety System (TSS). The TSS control system

automatically retrieves media temperatures, opens the fresh air purge/idle damper, controls the

booster fan, purges the system with fresh air, ignites the burner, cycles the valves, and gradually

brings the system up to the correct operating temperature. The TSS also monitors the temperature

in the regenerators, combustion chamber in three places, and in the valve assembly’s inlet and outlet.

This helps safeguard the system from extreme temperature fluctuations that cause thermal stress

and overall system fatigue.

Quote B19-8295 Rev. 0 P a g e | 2 3

As soon as the required operating temperature is reached, the TSS enables the process lines to feed

into the oxidizer or holds the system in idle mode until production is ready. When production is

ready the fresh air purge damper closes and one or more of the diverting dampers open to draw the

volatile organic compounds (VOC’s) from the process lines.

A booster fan draws one or more VOC-laden exhaust from your process lines into the system at a

fixed duct static pressure. From there, VOC’s are directed into one of the systems regenerators (an

internally insulated vessel containing ceramic media). The contaminated gases are passed through

the first regenerator where energy is transferred from the ceramic media to the gas to elevate the

temperature.

This elevated temperature approaches the ignition level for most solvents and then is directed from

the ceramic bed into the combustion chamber. As the stream exits the ceramic bed and travels

through the internally lined combustion chamber minimal heat is added to ensure a proper oxidation

temperature and a designed dwell time is maintained for the ultimate destruction of the streams

VOC’s. The resultant clean, oxidized gases are redirected into a second regenerator bed to continue

the energy transfer and oxidation cycle before being released to the atmosphere.

The TSS – PLC control panel will include the following components:

• NEMA-12 painted carbon steel single door enclosure designed to be mounted indoors.

o Color – CPI standard gray epoxy

o Codes – TSS control panels are designed to NEC standards. Unless specifically

mentioned below, no other standards apply

o 480 VAC, 3-phase, 60 Hz main disconnect

• Allen-Bradley CompactLogix 1769 L33 Ethernet Processor with the following:

o Inputs and outputs as required for managing the oxidizer system and interlocks for

source isolation dampers.

Quote B19-8295 Rev. 0 P a g e | 2 4

o Remote Service Access via VPN internet broadband web port with integral Ethernet

switch

• Allen-Bradley PanelView Plus 7 with a 12” color touch screen. MMI will including the

following:

o 12” color touch screen with Ethernet IP

o Door mounted in the main control panel

o Start/Stop functions

o PID Loop Control of:

▪ Burner Temperature Control

▪ VF Drive Speed Control

▪ Valve Switching

▪ Bake-out Feature

o Text and graphic indication of system status & individual graphic screens

▪ System overview screen with First Fault Annunciation and Trouble Alarm

History

▪ Combustion system detail screen

▪ Booster fan detail screen

▪ Maintenance screen

▪ Secure PID access screen

▪ Animated system flow diagram

• Eurotherm high temperature limit shut off

• Honeywell paperless advanced TVEZ Series single pen graphical chart recorder:

o Combustion Chamber Temperature

• Honeywell RM7800M1011 flame safety system Burner Management System (BMS)

o Motor starter for the combustion air blower

• Door mounted alarm horn

• Sample screens:

Quote B19-8295 Rev. 0 P a g e | 2 5

ID Booster Fan Motor Control

The volume control will be provided by a variable frequency drive controlled by the PLC receiving a

signal from the inlet pressure transmitter. The system will include the following:

• Powerflex 400 series VFD mounted inside the TSS control panel

Quote B19-8295 Rev. 0 P a g e | 2 6

Exhaust Stack

CPI will provide two (2) 66” diameter 316L stainless steel exhaust stack discharging 40’-0” above

grade, to accommodate a maximum of 50,000 SCFM air flow. Stack to include the following:

• Two 3" diameter test ports, with caps located 90 degrees apart

• Carbon steel base rings with grounding lugs

• Flexcom, or equal, fabric exhaust stack inlet expansion joint

• Insulated and clad within 8’ of ground.

• Access ladder and platform

Startup Services

Complete start-up and operator training is supplied. The startup normally begins after the customer

has confirmed readiness by filling out our supplied startup checklist. The startup normally begins

after the customer has confirmed readiness by filling out our supplied startup checklist. This list is a

simple sheet that asks you to confirm such things as: the gas supply is ready, electrical components

have all been wired correctly, ductwork is ready, and production conditions are ready. Our men will

perform the following steps:

• Confirm operation of all safeties

• Establish oxidizer readiness and startup on fresh air

• Balance the air volumes and flows from the source to the equipment

• Set all system field components

• Set all oxidizer adjustments on production conditions

• Record pressures and volumes for insertion into the operation manual

• Verify operation via mutual acceptance of performance by both parties

• Train all necessary personnel. Training normally requires a few hours (per shift). If multiple

shifts are required, we can make extra arrangements to be on site during that particular

shifts.

Quote B19-8295 Rev. 0 P a g e | 2 7

Section 3: Equipment Budgetary Cost Summary

Project Investment

TRITON RTO Units with

Structured Heat

Recovery Media as

described in this

proposal

Two (2) TRITON 65.95 RTO $ 2,554,000.00

Start-up both RTO’s $ 40,000.00

Adder to increase Thermal Efficiency to 97% $ 84,000.00

Payment Terms

Net 10 Days upon receipt of invoice

30% down payment to initiate the order, due immediately (net cash)

30% upon submission of general arrangement drawing and PID

30% upon equipment ready to ship

10% upon installation or 30 days after shipment, whichever comes first

Equipment Delivery

26 weeks after receipt of purchase order and down payment

Equipment Shipment

EXW, CPI Factory. Buyer is responsible for all shipping costs. CPI can offer other options

such as FOB Destination where CPI includes the cost of freight, if requested.

The quoted prices and deliveries are subject to the attached

TERMS AND CONDITIONS and are valid for a period of 30 days

Quote B19-8295 Rev. 0 P a g e | 2 8

SECTION 4: BUYER’S RESPONSIBILITIES

The following list will detail items that are not included as part of the proposal and identifies the

responsibility of the customer. NOTE: This list of responsibilities can change based on the final

agreed to scope of supply for various installation services.

• Provide a concrete pad based upon CPI provided concrete pad drawing. Note customer to

supply soil boring/core sample compaction report for CPI to provide pad design.

• Provide for mechanical, electrical and piping installation of the RTO unit.

• Natural gas piping at 11,500 CFH at 5 PSIG to each RTO gas train inlet.

• Clean, dry (-40 oF dew point) compressed air supply to each RTO connection point at 8-10

CFM at 90 PSIG. (CPI offers air dryer as option).

• Provide 600-amp 480 VAS, 3-Phase, 60 Hz electrical service to each CPI supplied TSS Control

VFD Cabinet

• Customer is responsible for all interconnecting wiring to each RTO.

• Required construction and/or building permits. CPI will provide design calculations and/or

documentation drawings.

• All work is quoted as non-holiday, M-F during normal work hours. If weekend, holiday, or

overtime work is required, it will be quoted separately. The rigging of the TRITON II unit is

quoted as using non-union labor (the same as the last three RTO’s DS Container has

purchased), the interior electrical installation is quoted as using union electrical contractors

(the same as the last three RTO’s DS Container has purchased).

• Provide plant personnel and production ready conditions for startup and operator training

at time of startup.

• Any fire suppression equipment if required.

• Security fencing and lighting if required.

• Insulation of ductwork, fan, valves, and exhaust stack if required.

• All controls and instruments other than specified i.e.; flow measurement, LEL devices,

detonation and flame arrestors, or others. Instruments make and model are clearly

identified as to intended supply

• Compliance testing if required.

• Ethernet line to each TSS control panel.

• Freight from shipping point to site

• Startup service for any delays caused by the customer or representatives of the customer

will be billed at $135.00/hr for normal weekdays, $202.00/hr for weekends, $270.00 for all

holidays, and all expenses plus 10%.

Quote B19-8295 Rev. 0 P a g e | 2 9

SECTION 6: EQUIPMENT WARRANTY

The Seller warranty to Buyer that the equipment and machinery mentioned in this proposal shall be

free from defects of materials or workmanship under normal use and maintenance for a period of

one (1) year from date of shipment. The liability of Seller under this warranty shall be limited to the

repair or replacement, at Seller's option, or any part or component which may prove to be defective

under normal use, service, and maintenance after Seller, in its sole discretion, determines same to

be defective. This warranty is conditioned upon Buyer giving Seller immediate written notice of an

alleged defect and refraining from the attempted repair of alleged defects without prior written

consent of Seller. The Seller makes no warranty whatsoever with respect to accessories or

components not supplied by Seller. For any components purchased by Seller for use on or in

conjunction with the equipment which is the subject of this contract, the Seller extends to the Buyer

only the same warranty granted to Seller by the component vendor or manufacturer.

The performance and safety of the equipment mentioned herein is contingent upon proper

installation, the use of suitable process materials, and operation and maintenance by properly

trained personnel. Seller makes no warranty whatsoever as to the inclusion of the equipment

supplied by Seller into Buyer's manufacturing process, Seller's warranty being limited solely to the

operation of its equipment sold hereunder in accordance with the specifications therefore.

THIS WARRANTY IS IN LIEU OF ALL OTHER WARRANTIES, EXPRESSED OR IMPLIED,

INCLUDING THE WARRANTIES OF MERCHANTABILITY AND FITNESS FOR USE. IT IS

EXPRESSLY AGREED THAT UNDER NO CIRCUMSTANCES SHALL THE SELLER BE HELD LIABLE

FOR ANY SPECIAL OR CONSEQUENTIAL DAMAGES OR LOSS OF PROFIT ARISING FROM ANY

CAUSE, AND SELLER'S LIABILITY SHALL BE STRICTLY LIMITED AS STATED HEREIN.

Quote B19-8295 Rev. 0 P a g e | 3 0

SECTION 7: TERMS and CONDITIONS

I. ACCEPTANCE

All sales of material or equipment by Catalytic Products International are expressly conditioned upon the terms and conditions set forth in the written order

acknowledgment of Seller. Any additional or different terms of conditions set forth in the purchase order of the Buyer or any similar such communication, are

hereby objected to by Catalytic Products International and shall not be binding nor effective unless assented to in writing by Catalytic Products International.

II. CANCELLATION

Buyer acknowledges this is custom engineered and fabricated equipment to the buyers exacting specifications. Buyer may cancel any order only by mutual

agreement, and only upon written notice to Catalytic Products International, and with payment to Catalytic Products International of reasonable cancellation

charges, including but not limited to (1) the proportionate contract price for all material completed, whether shipped or not, prior to notice of cancellation is

received; (2) an inventory restocking fee equal to 30% of the original order including any change orders; and (3) all expenses incurred by Catalytic Products

International by reason of such cancellation, including reimbursement for any charges arising from termination of sub-contract claims.

III. DAMAGE OR LOSS

The Company shall not be liable for damage to or loss of equipment after delivery of such equipment to the point of shipment. In the case of equipment to be

installed by or under supervision of the Company, the Company shall not be liable for damage or loss after delivery by the carrier to the site of installation. If,

thereafter, pending installation or completion of installation or full performance by the Company, any such equipment is damaged or destroyed by any cause

whatsoever, other than by the fault of the Company, the Buyer agrees promptly to pay or reimburse to the Company, in addition to or apart from any and all

other sums due or to become due hereunder, an amount equal to the damage or loss so occasioned.

IV. DELAYED SHIPMENTS

Quoted shipping dates are approximate. Catalytic Products International will use its best efforts to fill all orders within the time quoted. However, final shipping

schedules shall be subject to any conditions that may prevent compliance with acknowledged delivery schedules. Catalytic Products International shall not be

liable for failure to give notice any delay, and such delay shall not constitute grounds for cancellation.

Catalytic Products International reserves the right to store such products in a warehouse for the accounts and at the risk of the Buyer after the products or any

substantial portion thereof are ready for shipment cannot be made for either of the following reasons:

(a) If CPI is prevented from making shipment or delivery in accordance with instructions of the Buyer, or

(b) By strike, boycott, natural disaster, governmental law, regulation, or circumstances beyond the control of CPI.

V. FIELD SERVICE

Unless otherwise noted herein, the cost of this equipment does not include service and/or installation. Field service, as stated in proper written quotation, for

repair or start-up will be charged at a per diem rate plus all living and traveling expenses incurred from the time of leaving base of operations until return.

Premium rate will be charged for work in excess of eight hours per day and for Saturday, Sunday, and holiday work. On start-up projects Catalytic Products

International should be notified approximately thirty days prior to the start-up date, and name and title of a single authority responsible for securing and

releasing personnel should be included. Catalytic Products International service representative will require time verification sheets to be approved by the Buyer's

authorized representative at the completion of each day's work.

Upon request, Catalytic Products International in its discretion will furnish as an accommodation to Buyer such technical advice or assistance as is available in

reference to the use of the product by Buyer. Catalytic Products International assumes no obligation or liability for the advice or assistance given or results

obtained, all such advice or assistance being given and accepted at Buyer's risk.

VI. GUARANTEE

Material and equipment distributed by Catalytic Products International are the products of reputable manufacturers sold under their respective brand or trade

names. Catalytic Products International shall use its best efforts to obtain from each manufacturer, in accordance with the manufacturer's warranty (copies of

which will be furnished upon request) or customary practice, the repair or replacement of products that may prove defective in material or workmanship. The

foregoing shall constitute the exclusive remedy of the Buyer and the sole obligation of Catalytic Products International. Except as to title, THERE ARE NO

WARRANTIES, WRITTEN, ORAL, IMPLIED, OR STATUTORY, relating to the described material or equipment, which extends beyond that described in this

paragraph. NO WARRANTY OF MERCHANTABILITY OR OF FITNESS FOR PURPOSE SHALL APPLY. Any and all such warranties are subject to purchaser's

application of purchased equipment and materials strictly and exclusively within the technical specification as defined in Catalytic Products International's order

acknowledgment and general technical description.

With acknowledgment of Buyer's order, Seller assumes that Buyer has verified technical specifications as set forth in this contract and Buyer has the responsibility

for correctness of said technical specifications. Unless specially noted, this proposal is not intended to exactly meet the Buyers specification and if conflict arises,

this proposal takes precedence.

Performance guarantees for catalyst and systems shall be strictly and exclusively limited to those expressly stated in Seller's written order acknowledgment, and

such guarantees shall only apply if catalysts were found in original and sealed factory package. Performance guarantees for heat exchangers shall be strictly

and exclusively limited to those expressly stated in Seller's written order acknowledgment based on nominal (+/- 5%) efficiencies. All replacements arising from

claims on guarantees as herein stated are made FOB Shipping Point (American Uniform Commercial Code) Seller’s Plant.

The foregoing warranty is in lieu of and excludes all other expressed or implied warranties of merchantability or fitness for any particular use. Seller guarantees

that catalysts have been given to carrier in unbroken original factory sealed package.

VII. LIABILITY

The Company will not be liable for any damage caused by the operation of the machinery or devices purchased whether or not operated in accordance with

instructions or because of any failure to meet conditions of our guarantee. Liability under any contract shall in no case exceed the price paid for goods furnished

by Catalytic Products International. In no event will Catalytic Products International be liable for consequential damages, or the failure of the Buyer to provide

proper safety features for the protection of personnel in the use of operation of equipment.

Quote B19-8295 Rev. 0 P a g e | 3 1

Catalytic Products International's liability on any claim for loss or damage arising out of this contract or from the performance or breach thereof or connected

with the supplying of material or equipment hereunder, or its sale, resale, operation or use, whether based on warranty, contract, negligence or other grounds,

shall not exceed the price allowable to such material or equipment or part thereof involved in the claim. Catalytic Products International shall not, under any

circumstances, be liable for any labor charges unless agreed upon in advance in writing by Catalytic Products International.

Buyer assumes full responsibility for proper handling and storage of catalysts and equipment, after receipt from carrier, in accordance with Seller's instructions.

Warranties and guarantees become void unless handling and storage was made in accordance with Seller's instructions.

VIII PATENTS

The Company shall hold Buyer harmless for any expense or loss resulting from infringement of patents or trademarks arising from compliance with the Buyer's

designs or specifications.

IX. PRICING

Seller reserves the right (a) to revise any price quoted without notice to Buyer, at any time prior to acceptance of Buyer's purchase order by Seller, (b) unless

otherwise noted, all prices by Catalytic Products International are subject to change without notice. Prices do not include sales, use, excise, value added, or

similar taxes, and where applicable, such taxes shall be billed as a separate item and paid by the Buyer. Unless otherwise noted, all sales are made FOB Shipping

Point (American Uniform Commercial Code) with no allowance for special crating, duties or fees and in all cases, title shall pass upon delivery at point of shipment

and thereafter all risk of loss or damage shall be upon the Buyer.

All items shown as freight allowed pertains to particular items and quantities. Any deviation after placement of order such as changes in quality or partial release

will be subject to the manufacturer's terms and conditions where applicable.

X. RETURNED MATERIAL

No credit will be given for returns except by specific written approval of Seller. No special designed catalyst materials or equipment may be returned. No

catalyst, burner nozzle, burner block, or other parts directly exposed to flame, condensate or poisonous substances may be returned after use.

XI. SHIPMENT

All shipments will be made FOB Shipping Point s (American Uniform Commercial Code) Catalytic Products International factory unless otherwise specified. In

the absence of specific instructions, Catalytic Products International will select the carrier. Title to the material shall pass to the Buyer upon delivery thereof by

Catalytic Products International to the carrier, delivery or pick-up service. Thereupon the Buyer shall be responsible thereof. Products held for Buyer, or stored

for Buyer, shall be at the risk and expense of Buyer. Claims against Catalytic Products International for shortages must be made within 48 hours after arrival of

shipment at Buyer's destination.

Shipping dates are approximate and only as shows on the order acknowledgment. Shipping dates are not guaranteed. Catalytic Products International shall

not be liable for delays in delivery or failure to manufacture or deliver due to causes beyond its reasonable control, including but not limited to acts of God, acts

of Buyer, acts of military or civil authorities, fires, strikes, flood, epidemic, war, riot, delays in transportation or car shortages, or inability to obtain necessary labor

materials, components or manufacturing facilities. In the event of any such delay, the date of delivery shall be extended for a period equal to the time lost by

reason of such delay. In the event of impossibility of performance resulting from any of the above causes, Catalytic Products International shall have the right

to cancel this contract without further liability to Buyer. Cancellation of any part of this order shall not affect Catalytic Products International's right to payment

for any product delivered hereunder. Orders with indefinite delivery dates are accepted upon the understanding that Catalytic Products International shall have

the right to fill said order as it sees fit in the course of its manufacturing schedules and to hold the goods for the Buyer's account at Buyer's expense and risk,

pending receipt of definite delivery instructions.

XII. SUPPLEMENTAL CLAUSES FOR EXPORT ORDERS

(a)...Currency: The prices quoted herein are payable in U.S. Dollars, unless otherwise stated in written order acknowledgment.

(b)...Proof of Export: Those products which are to be purchased only for export: The Buyer agrees to furnish Catalytic Products International with proof of

exportation of all or any part of such products within five months from the date of the Catalytic Products International invoices therefore, or if exportation of

any part shall not have occurred within that period. Buyer agrees to pay Catalytic Products International upon demand, the amount of any manufacturer's excise

tax or other tax which now or hereafter may be imposed on the sale of such products for consumption within the United States.

(c)...License and Permit Requirements:

(1)...Catalytic Products International will secure all export licenses and permits required by the United States Government and Buyer will furnish reasonable

cooperation in acquiring such licenses and permits. If such licenses and permits are paid for by Buyer such payments will be added to the contract price.

(2)...Buyer will secure all licenses and permits required by the foreign government and Catalytic Products International will furnish reasonable cooperation in

acquiring such licenses and permits. The delivery schedule is contingent upon securing all necessary licenses and permits.

(3)...Failure to obtain a required license or permit in sufficient time to permit delivery within the time set forth in the contract, and without the fault or

negligence of the contracting parties, shall occasion an equitable adjustment in the delivery schedule.

XIII. TAXES

The prices shown do not include any taxes (sales, excise, use, etc...) or any government charges. Such taxes or charges applicable to the order will be paid by

the Buyer except where specifically exempt by a certificate. Only when Catalytic Products International is registered to collect applicable taxes will such taxes be

added to the invoice and collected by Catalytic Products International.

XIV. NON-SOLICITATION

Each party agrees that beginning on the contract acceptance date and for a period of twelve (12) months after final acceptance or earlier termination of this

Agreement, it shall not (I) solicit, encourage, advise, induce or cause any employee of the other party [who worked directly or indirectly on the Services after the

contract acceptance date] to terminate his or her employment with such party or any of its subsidiaries or Affiliates, nor provide any assistance, encouragement,

information, or suggestion to any person or entity regarding the solicitation or hiring of any employee of the other party or any of its subsidiaries or Affiliates;

or (ii) induce or attempt to induce any person, business or entity which is a supplier or customer of a party, or which otherwise is a contracting party with a party,

to terminate any agreement with a party.

3. Vendor Quote - Scrubber

PROJECT

Edmonton

PREPARED FOR

Mathew Kress Dillon Consulting Limited

1430 - 91st Street SW Suite 101 Edmonton, Alberta, T6X 1H1

T - 403.215.8880 ext. 4602 F - 403.215.8889 [email protected]

www.dillon.ca

PREPARED BY Raechel Jones, E.I.

Business Development Associate C: 970-371-5024

E: [email protected]

PROPOSAL DATE

June 5, 2019

370 Interlocken Boulevard • Suite 680 • Broomfield, CO • 800021 • MVseer.com • 303.277.1625 • [email protected] Proposal No.: P RRJ 19 018 R1

370 Interlocken Boulevard • Suite 680 • Broomfield CO • 800021 • MVseer com • 303 277 1625 •

PREPARERaechel Jon

Business Development AssC: 970-37

E: raechel.jones@mvsee

PROPOSAL DJune 5

Info@MVsee

ABOUT MV TECHNOLOGIES

For more than a decade, MV Technologies has been solving emission and odor control challenges for a variety of process industries that include: oil and gas production, petroleum refining, food and beverage production, and biogas to power conversion from landfill and agricultural sources. MV’s solutions are founded on the principles of applying best available technology to the client’s site-specific conditions in order to deliver the true lowest cost of ownership.

PROJECT OVERVIEW

Mr. Mathew Kress from Dillon Consulting Limited has requested a proposal from MV Technologies to provide an H2S scrubber system to remove H2S from biogas generated from a food waste anaerobic digester

The preliminary project parameters as provided by Mr. Kress include:

Process Parameter Value Average Flow Rate: Peak Flow Rate: Inlet H2S Concentration: Max. Allowable Outlet H2S Conc.: Operating Temperature:

25,000 m3/d (615 scfm) 32,000 m3/d (785 scfm) 5,000 ppm 200 ppm 90-95°F

PROPOSED H2SPLUS SYSTEM DESCRIPTION

Design Parameter Value Configuration: Media Vessel Dimension: Anticipated Pressure Drop: BioActive Media (BAM) Volume: Bed Life:

Two-Vessel H2SPlus System Operated in Parallel 12’ diameter; 11’-6” tall 8” W.C. @ Maximum Flow Rate 2,184 FT3

67 days @ Average Flow Rate

SYSTEM EQUIPMENT DETAILS

The H2SPlus System proposed for the project will include:

Media Vessels

Two (2) insulated FRP vessel – 12’ dia. X 11’-6” tall 1,092 cubic feet of iron sponge design capacity per vessel Fully removable flanged and domed lid with neoprene dovetail gasket. Bolts provided are 18-2 SS MV Technologies designed media support system and gas distribution system 12” Flanged inlet with neoprene spherical expansion joint 10” Flanged outlet with neoprene spherical expansion joint Inlet and outlet will have a block and bleed safety valve set up Butterfly inlet/outlet valves with lug style, cast iron body, Viton Seat, SS Disc, and SS Stem. Gear-operated with hand

wheel for the outlet valves and chain operated for the inlet valves. Neoprene vessel pad 30” diameter flanged side manway Operating pressure range of +1 psi/-1 psi

BioActive Media

2,184 total cubic feet of BAM Proprietary Bacteria and Nutrients Capable of removing up to 13-pounds* of H2S per cubic foot of BioActive Media

(*in the presence of O2 at a ratio of 5:1) Spent media is non-hazardous may be landfilled, composted, or land applied Range of acceptable operating temperatures from 80F to 130F Biogas must be fully saturated for optimum efficiency

BioActive Media Removal System

The system will come with two (2) sets of MV nets.

Recirculation System

Sized to provide adequate recirculation of MV Technologies bacteria, nutrients and water required to maintain correct moisture content of BioActive Media in each vessel. The system typically requires 100-200 gallons per week of makeup water.

In Ground Sump, Qty. 2: FRP Sump Pump, Qty. 3 submersible, explosion-proof 480 VAC 3 Phase

One for the vessel One overflow

Float switches (class 1 div 2) for automatic makeup water addition. 1” SS ball valve with NEMA 4X/7 electronic actuator Level Transmitter

Online BioActive Media Bed Monitoring System

Temperature transmitter (class 1 div 2) to monitor bed temperature, Qty. One inside the media bed

304 SS Thermowell (for RTD)

Continuous Online Regeneration System Regenerative Air Addition Blower for 5-10% air addition to system to achieve target O2levels for optimized removal

capacity of media. O2 is consumed in media bed, leaving less than 0.5% in the downstream biogas. Schedule 80 PVC air lines to the gas inlet header Biogas flow switch, NEMA 7 Enclosure. To be installed in client header piping, with 20 pipe diameter upstream and 10

pipe diameter downstream.

Control Panel

Analog monitoring and control of temperature alarm points, sump pumps, sump makeup water ball valve, air regeneration blower, and flow switch.

NEMA 4X Enclosure mounted outside the classified hazardous area

Documentation

Pre-Startup Checklist Commissioning Startup Plan and Checklist General Arrangement, PFD, P&ID, Control Panel GA and Layout Drawing Installation guidance document Operation and Maintenance Manual

Startup and Commissioning

Equipment Testing Services - Control panel checkout will be performed prior to shipment. All other rotating equipment, instruments, and valves shall be tested prior to, or during, system startup. System will be pressure tested after installation.

Training - MV Technologies Engineers will provide on-site operations training to Owner designated staff at time of startup. Upon startup, an MV Technologies Engineer will work with a designated Owner Representative to finalize IOM documentation specifically for the client’s system.

INVESTMENT SUMMARY

The total cost for the H2SPlus™ System proposed for the project includes the initial charge of media, one trip for on-site startup and training, and one on-site visit for assistance for the first media replacement.

PRICING SUMMARY H2SPlus™ System Equipment – Two-Vessel System Initial Media Charge – 2,184-ft3

TOTAL SYSTEM INVESTMENT NOTES

1. Quote is good for sixty (60) days from proposal date.2. Standard lead time of equipment shipment is 12-14 weeks upon approval of engineering submittal.3. All pricing and operating estimates exclude freight of equipment and/or media. Owner may elect MV

to coordinate freight with preferred vendors with a pass-through of the costs to the owner.

PAYMENT TERMS H2SPlus™ System Equipment

40% Invoiced (Net 5) upon execution of Purchase Agreement. Engineering commences upon receipt of payment.

35% Invoiced (Net 30) 60 days after Purchase Agreement, or upon Engineering Submittal approval, whichever is earlier

20% Invoiced (Net 30) upon H2SPlus™ System equipment readiness for shipment 5% Invoiced (Net 30) 30 days after shipment or completed acceptance test, whichever is earlier 100% H2SPlus™ System Equipment

Initial Media Charge 100% Invoiced (Net 30) upon H2SPlus™ System equipment readiness for shipment

EXCLUSIONS 1. Site preparation shall be provided by others, including, but not limited to concrete pad and site utility

requirements, such as electrical and water. 2. System installation and assembly shall be provided by others, unless otherwise negotiated.3. All system and interconnecting piping, HDPE or equivalent recommended, provided by others.4. Pricing does not include taxes, sales or otherwise. It is the sole responsibility of owner to account for and

report any applicable taxes, as required.

OWNER RESPONSIBILITY Labor Requirements; Power Cost; Waste Generation; Cost/Procurement of Additional Materials.

GENERAL H2SPLUS SYSTEM DESIGN AND OPERATION

A typical H2SPlus™ System includes the components shown in the General Arrangement below. The dimensions of the media vessel are primarily based on the flow rate, with some additional consideration given to inlet H2S concentration. The media temperature is controlled by the recirculation system, which also allows for media pH management to a target range of 9-10 through the sump.

Two vessel installation in Caldwell, Idaho

At time of media replacement, MV Technologies top-entry tanks, in combination with our MVNets™ make the process simple and efficient, as photographed below. MV’s leadership position in dry scrubber technology is based not only on the engineering of cost-effective H2S conversion reactions, but also importantly, designing the whole process to be simple and safe for our clients.

MVNETS™ PROVIDE EASE IN REMOVAL OF SPENT MEDIA

TECHNOLOGY OVERVIEW

Our H2SPlus™ System as proposed and addressed in this document will:

Be designed to meet all operating conditions as determined by end-user requirements. MV will engineer and procure equipment necessary to deliver the H2S outlet concentrations as required. Should site conditions change or experience increases, or spikes, above the stated expected maximum conditions of concentration, the system would continue to deliver required outlet conditions. The only effect will be the increased rate of media consumption.

Provide for easy and rapid media change out – with MVNets™ a media change in a single vessel can typically be accomplished in less than 24 hours.

Provide the lowest cost per pound of H2S removal of any technology on the market.

Operate at 100% effectiveness immediately upon startup and does not require any offline run-in or maturation period, as is standard in biological scrubbers.

Tolerate upset conditions such as large swings in H2S concentrations or changes in temperature

Feature a “set and forget” design –

STATEMENT OF EXPERIENCE

The first MV Technologies H2SPlus™ System, installed in 2001, was placed in service to remove the hydrogen sulfide gas from a biogas stream collected from a covered lagoon at a Cargill Meat Packing facility in Fort Morgan, Colorado.

Since 2001, MV Technologies has installed numerous H2SPlus Systems, providing H2S solutions for facilities such as landfills, waste water treatment plants, covered lagoons, anaerobic digesters at food and beverage plants, and farm-based anaerobic digesters.

Following is an abbreviated list of just some of the various projects completed by MV Technologies:

Landfill Gas Ada County Landfill, Idaho (SCS Engineers) Cape May Municipal Landfill, New Jersey (three expansions) Chesterfield, Virginia (INGENCO) Emerald Park Landfill, Wisconsin (Advanced Disposal)

o Including a 2 Vessel Expansion ACUA Landfill, New Jersey (DCO Energy) New Bern Landfill, North Carolina (INGENCO) Pecan Road Landfill, Georgia (Advanced Disposal) Warren County Landfill, New Jersey (Atlantic Lining) JED Landfill, St. Cloud, Florida (Waste Connections)

Anaerobic Digester Biogas Double A Dairy, Idaho (Andgar) Dry Fermentation Anaerobic Digestion, California (Zero Waste Energy) MillerCoors Brewery, Colorado MillerCoors Brewery, Texas Potawatomi Digester, Wisconsin (Biothane, LLC) Spoetzel Brewery, Texas

Covered Lagoon Digester Biogas Dodge City, Kansas (Cargill Meat) Fort Morgan, Colorado (Cargill Meat) Fresno, California (Cargill Meat) Grand Island, Nebraska (JBSS)

SYSTEM PERFORMANCE GUARANTEE

System Performance Warranty MV Technologies warrants, for a period of ten years, that the proposed H2SPlus™ or systems will meet or exceed the requirements as stated in this Proposal. This warranty is contingent upon: the user’s demonstration that system application has been, at all times, within the gas flow rates and H2S loading provided in the Equipment Purchase Specification; the user’s demonstration that MV’s Operations and Maintenance procedures have been followed; the user’s demonstration that media use has not exceeded the designed loading capacity of H2S per cubic foot of BioActive Media before change out; that on-site annual system performance inspections are conducted by MV Technologies authorized personnel and that recommended necessary adjustments to operating conditions are made in a timely fashion. This warranty may be extended at the end of the ten-year period by mutual agreement of the parties.

H2SPlus Media Performance Guarantee MV Technologies warrants, for an agreed period of time from date of system startup, the H2SPlus System™ designed for the System Owner will, when operated according to MV Technologies Specifications at or below design conditions as established in the approved MV Technologies H2SPlus Proposal, will remove up to 6-pounds of H2S per one (1) cubic foot of our reactive media, BAM™, until breakthrough condition.

In the event the H2SPlus system does not perform as described above, MV Technologies will provide, at its expense, the pro-rata amount of BAM™ at each media replacement cycle so as to provide the equivalent media consumption performance. By way of example, if the actual H2S removal rate was determined to be 5-pounds per one cubic foot of BAM, MV would provide 16% discount off the next vessel media charge of BAM.

Standard H2SPlus Media Performance Guarantee may not apply to all installations and is evaluated on a site by site basis upon final review of site conditions and parameters.

Conditions of the Warranty 1. “Breakthrough” condition is defined as measured H2S concentration levels in the H2SPlus System outlet

gas, exceeding the system design levels established in the approved MV Technologies Proposal. 2. Client must demonstrate, to the reasonable satisfaction of MV Technologies, that the H2SPlus System

is installed and operated according to its design specifications, and at or below the design conditions. 3. H2S concentrations and total flow rate of incoming gas must be accurately monitored and recorded at

least every third day so that incoming pounds of H2S until breakthrough condition may be determined.

Limitations of Remedy and Liability In no event shall MV Technologies be liable for any special, incidental or consequential damages based upon breach of warranty, breach of contract, negligence, strict tort or any other legal theory. Such damages include, but are not limited to, loss of profits, loss of savings or revenue, and/or the system to which it is attached or has been made a part of, costs of any substitute equipment, downtime, the claims of third parties, including customers, and injury to property.

GENERAL PRODUCT AND SYSTEM WARRANTY STATEMENT MV Technologies, LLC (“MV Technologies” or “MV”) is committed to providing quality products and services to its customers. As a demonstration of this commitment, MV Technologies offers the following warranty on its products and systems.

GRANT OF WARRANTY MV Technologies provides this warranty for its products and systems under the terms and conditions detailed below to the person, corporation, organization, or legal entity, which owns the product or system on date of start-up (Owner). This warranty is not transferrable without express written consent of MV Technologies.

WARRANTY COVERAGE Products or systems provided by MV Technologies that are determined by MV to have malfunctioned during the warranty period, under normal use, solely as a result of defects in manufacturing workmanship or material, shall be repaired or replaced at MV Technologies discretion. MV Technologies liability under this warranty to the Owner shall be limited to MV’s decision to repair or replace, at its shop or in the field, items deemed defective after inspection by MV.

WARRANTY EXCLUSIONS 1. Any equipment, parts and work not manufactured or performed by MV Technologies carry their own manufacturer’s warranty. 2. MV Technologies’ only obligation regarding equipment, parts, and work manufactured, or performed by others, shall be to assign to

the Owner whatever warranty MV Technologies receives from the original manufacturer. 3. MV Technologies does not warrant its products or systems from malfunction or failure due to shipping or storage damage,

deterioration due to exposure to the elements, vandalism, accidents, power disturbances, or “Acts of God” as commonly applied in commercial transactions.

4. This warranty does not cover damage due to misapplication, misuse, improper installation, or lack of proper service and/or maintenance, nor does it cover normal wear and tear, and does not apply to modifications or the effect of modifications not specifically authorized in writing by MV Technologies, or to parts and labor for repairs not made by MV Technologies or its authorized warranty service provider.

5. This warranty does not cover incidental or consequential damages or expenses incurred by the Owner, or any other party, resulting from the order and/or use of its products or systems, whether arising from breach of warranty, non-conformity to order specifications, delay in delivery, or any loss sustained by the Owner. No agent or employee of MV Technologies has any authority to make verbal representations or warranties for any goods manufactured and sold by MV Technologies, without the written authorization signed by an authorized officer of MV Technologies. Any alterations or repair of MV Technologies' product or systems by personnel other than those directly employed by, or authorized by MV, shall void the warranty, unless otherwise stated under specific written guidelines issued by MV Technologies to the Owner.

6. MV Technologies warrants the products and systems designed and fabricated to perform in accordance with the specifications as stated in the proposal for the equipment and while the equipment is properly operated within the site specific design limits for that equipment as stated in the proposal.

7. MV Technologies warrants only that its products and systems will meet the site specific design limits as stated in its proposal, and makes no representation that those site specific design limits satisfy any operating condition, regulatory, safety, or other limits or standards whatsoever.

8. Operation of the product or systems outside the site specific design limits shall void the warranty. All media must be purchased through MV Technologies or approved in writing by MV Technologies during the warranty period. Media purchased through alternate sources and not approved in writing by MV Technologies shall void the warranty.

9. Owner shall be responsible for all maintenance service, including, but not limited to, lubricating and cleaning the equipment, replacing expendable parts and/or media, making minor adjustments, and performing operating checks, all in accordance with the procedures outlined in MV Technologies Operations and Maintenance Manual.

WARRANTY PERIOD Unless otherwise specifically agreed in writing, MV Technologies warranty is valid for 18 months from the time the equipment is shipped from MV Technologies factory or 12 months from the date of startup, whichever occurs first.

WARRANTY PERIOD REPAIRS All warranty claim requests must be initiated with a Return Material Authorization (RMA) number for processing and tracking purposes. When field service is deemed necessary in order to determine a warranty claim, the costs associated with travel, lodging, etc. shall be the responsibility of the Owner, except under prior agreement. This warranty covers only those repairs that have been conducted by MV Technologies, or by an MV authorized warranty service provider, or by someone specifically authorized by MV Technologies to perform a particular repair or service activity. All component parts replaced under the terms of this warranty shall become the property of MV Technologies.

MV TECHNOLOGIES ASSUMES NO OTHER WARRANTY FOR ITS EQUIPMENT, EITHER EXPRESS OR IMPLIED,

INCLUDING ANY IMPLIED WARRANTY OR MERCHANTABILITY, FITNESS FOR PARTICULAR PURPOSE, OR NON-INFRINGEMENT, OR LIABILITY FOR ANY INCIDENTAL OR CONSEQUENTIAL DAMAGE.

MV Technologies, LLC •370 Interlocken Boulevard • Suite 680 • Broomfield, CO • 800021 Phone: 303-277-1625 • Fax: 303-277-9624 • www.MVseer.com

McCain | Line 4 Project NOC Application C-1 Trinity Consultants

APPENDIX C: MODELING FILES AND SUPPORTING DOCUMENTATION

1. Modeling Directory

2. Site Layout and Elevation Drawings

3. Boiler and Flare Vendor Information


Table C-1. Modeling Files Directory

Folder File Name Description BPIP Bpip input file

Bpip output file Bpip summary file

Files for BPIP inputs and outputs.

Met Data MWHxx.SFC MWHxx.PFL

Meteorological files as inputs to AERMOD, including the surface file and upper air file. “xx” indicates the year among 2014-2018.

SIL NSD_1hr.ami NSD_1hr.aml NO2_all_1-hr_1st_high.plt

NO2 1-hr model input and output files. The plot file for all modeled sources.

NSD_Axx.ami NSD_Axx.aml No2_all_annual14.plt

NO2 annual model input and output files. “xx” indicates the year among 2014-2018. The plot file for the worst modeled year, which is 2014.

P10SD_24-hr.ami P10SD_24-hr.aml Pm10_all_24-hr_1st_high.plt

PM10 24-hr model input and output files. The plot file for all modeled sources.

P10SD_Axx.ami P10SD_Axx.aml Pm10_all_annual14.plt

Annual PM10 model input and output files. “xx” indicates the year among 2014-2018. The plot file for the worst modeled year, which is 2014.

P25SD_24-hr.ami P25SD_24-hr.aml Pm25_all_24-hr_1st_high.plt

PM2.5 24-hr model input and output files. The plot file for all modeled sources.

P25SD_A.ami P25SD_A.aml Pm25_all_annual.plt

PM2.5 annual model input and output files. The plot file for all modeled sources.

SSD_1hr.ami SSD_1hr.aml So2_all_1-hr_1st_high.plt

SO2 1-hr model input and output files. The plot file for all modeled sources.

SSD_Axx.ami SNSD_Axx.aml So2_all_annual14.plt

SO2 annual model input and output files. “xx” indicates the year among 2014-2018. The plot file for the worst modeled year, which is 2014.

SSD_ST.ami SSD_ST.aml So2_all_3-hr_1st_high.plt So2_all_24-hr_1st_high.plt

SO2 3-hr and 24-hr model input and output files. The plot file for all modeled sources.

TAP ATDxx.ami ATDxx.aml Acrolein_all_24-hr_1st_high15.plt

Acrolein 24-hr model input and output files. “xx” indicates the year among 2014-2018. The plot file for the worst modeled year, which is 2015.

BTDxx.ami BTDxx.aml Benzene_all_annual14.plt

Benzene annual model input and output files. “xx” indicates the year among 2014-2018. The plot file for the worst modeled year, which is 2014.

ETDxx.ami ETDxx.aml EB_all_annual14.plt

Ethylbenzene annual model input and output files. “xx” indicates the year among 2014-2018. The plot file for the worst modeled year, which is 2014.

FTDxx.ami FTDxx.aml Formaldehyde_all_annual14.plt

Formaldehyde annual model input and output files. “xx” indicates the year among 2014-2018. The plot file for the worst modeled year, which is 2014.

HTDxx.ami HTDxx.aml H2S_all_24-hr_1st_high15.plt

H2S 24-hr model input and output files. “xx” indicates the year among 2014-2018. The plot file for the worst modeled year, which is 2015.


Folder File Name Description STDxx.ami STDxx.aml SO2_all_1-hr_1st_high15.plt

SO2 1-hr model input and output files. “xx” indicates the year among 2014-2018. The plot file for the worst modeled year, which is 2015.

2. Site Layout and Elevation Drawings

DNDN

DN DN DN

pp

p

pp

p

p p

p p

p

p p

p

WB-67 - Interstate Semi-Trailer

WB

-6

7 - In

te

rsta

te

S

em

i-T

ra

ile

r

p

SU-40 - Single Unit Truck

D

N SCALE: 1" = 60'OVERALL SITE PLAN

KEYED NOTES - EXISTING

RIGHT-OF-WAY LINE

--

--

PROCESSING BUILDING

CENTRAL RECEIVING BUILDING

EAST RECEIVING BUILDING

FORKLIFT CHARGING BUILDING

COLD STORAGE #1

COLD STORAGE #2

CENTRAL SHIPPING DOCK

1

2

3

4

5

6

7

8

RIGHT-OF-WAY LINE

EASEMENT LINE

PROPOSED HOT MIX ASPHALT

PROPOSED CONCRETE

PROPOSED CRUSHED SURFACING

PROPOSED GRASS OR LANDSCAPING

9

10

OF

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NO.

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BY

SHT.

SIZE

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PROJ.

DWG. TITLE

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NO.

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V

E

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AS NOTED30X42

?

PACIFICENGINEERING

200 S. COLUMBIA STREET, SUITE 300 I WENATCHEE, WA 98801P(509) 662-1161 I F(509) 663-8227 I www.pacificengineering.net

T U R A LS T R U C

VIC LI

2019-05-03

McCain Foods USA, Inc.

100 Lee Road

Othello, WA. 99344

Phone: (509) 488-9611 Fax (509) 488-3982

PT2112-ALPHA

-

PROJECT ALPHA

MAR

1

4

5

6

8

9

2

3

7

KEYED NOTES

25T PROCESSING BUILDING

25T RAW RECEIVING DOCK

BATTER RECEIVING DOCK

ATL SHIPPING DOCK

OFFICE & EMPLOYEE BREAK ROOM

SCREENING & PROCESS WASTE BUILDING

FIRE PUMP HOUSE

INCOMING TRUCK SCALE

OUTGOING TRUCK SCALE

MUD SETTLING BASIN

SOLIDS LOADING APRON, APPROX ### SF

LOADING DOCK CONCRETE HARDSTAND, APPROX #### SF TOTAL

SUPPORT CORRIDOR CONCRETE HARDSTAND, APPROX #### SF

HEAVY-DUTY ASPHALT (TRUCK ROUTES), APPROX ###### SF

REGULAR-DUTY ASPHALT (VEHICLE PARKING), APPROX ##### SF250± PARKING STALLS, INCL. 7 ADA (5 STANDARD ADA, 2 VAN)

CEMENT CONCRETE SIDEWALK, APPROX #### SF

CEMENT CONCRETE TRAFFIC CURB (TYP), APPROX #### LF

CRUSHED SURFACING, APPROX ###### SF

LANDSCAPE ROCK, APPROX ##### SF

SITE RETAINING WALL

DEDICATED TRUCK ENTRANCE

TRUCK GUARD/SCALE HOUSE

10

11

12

13

14

4

1016

9

13

15

5

6

SOUTH SHIPPING DOCK

CONCRETE HARDSTAND (TYP)

ASPHALT PAVEMENT (TYP)

EDGE OF PAVEMENT (TYP)

POWER TRANSFORMER (TYP)

FENCE (TYP)

RAILROAD SPUR (McCAIN)

RAILROAD SPUR (WILBUR-ELLIS)

MUD SETTLING BASIN

WELL PUMP HOUSE

11

12

13

14

15

16

17

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15

16

11

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2060-C401

19

14

7

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7

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12

12

13

14

14

14

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18

19

19

19

19

20

1920

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20

20

21

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21

22

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REC 3

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(COLD STORAGE 02)

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(COLD STORAGE 01)

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BATTER / INGREDIENT STORAGE AREA

AutoCAD SHX Text

FRYER

AutoCAD SHX Text

DRYER

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DRY BATTER HANDLING

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SAPP MIXING

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BATTER

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ERS

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PEELING

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WET ESP 25T

AutoCAD SHX Text

CUTTING

AutoCAD SHX Text

PACKAGING

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WASTE OIL/STARCH UNLOADING AREA

AutoCAD SHX Text

NEW 25T OIL TANKS

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STARCH TANK

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SORTING

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BLANCHER

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SAPP FLUME

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FREEZER

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PEF

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AIR COMPRESSORS

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OIL ROOM

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OIL RECOVERY TANKS

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OIL DAY TANKS

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TRANSFORMERS

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TRANSFORMERS

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MUD SETTLING

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EXISTING FIRE RESERVOIR

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TRANSFORMERS

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ER-04-004

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RAMP

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ER-04-005

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TRANSFORMERS

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COMPRESSOR ROOM

AutoCAD SHX Text

RECIRCULATOR PIT

AutoCAD SHX Text

ER-04-006

AutoCAD SHX Text

PACKAGING MATERIALS (BELOW ACCUMULATION)

AutoCAD SHX Text

PEF GENERATOR ROOM BELOW/ CONTROL ROOM ABOVE

AutoCAD SHX Text

PACKAGING MAINTENANCE SHOP

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FINISHED LAB

AutoCAD SHX Text

(WOC LEVEL)

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PENTHOUSE (ABOVE)

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PENTHOUSE(ABOVE)

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ATL

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PALLETIZING

AutoCAD SHX Text

CASE ACCUMULATION

AutoCAD SHX Text

SANITATION CORRIDOR

AutoCAD SHX Text

LOADING DOCK

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HI-PSI PUMPS

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PARKING LOT

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WTR HTR

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PACKAGING MATERIALS

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FUTURE CHOPPED AND FORMED LINE AREA

AutoCAD SHX Text

ER-04-003

AutoCAD SHX Text

TRUCK TRAFFIC

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CAR TRAFFIC

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CHEMICAL ROOM

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SUMP PIT

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RAMP

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PARTS STORAGE

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PROCESSING MAINTENANCE SHOP

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STORVEYORS

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RECEIVING

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OVERHANG

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DECK

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FIRE LANE

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PARKING LOT

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REC 1

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SCALE HOUSE

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TRANSFORMERS

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TRANSFORMERS

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CUTTER LAB

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RISER

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NEW WATER TANK

AutoCAD SHX Text

TOTE ROOM

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FROZEN GRADING

AutoCAD SHX Text

SUMP PIT

AutoCAD SHX Text

EXIST FIRE PUMPHOUSE

AutoCAD SHX Text

NEW FIRE PUMPHOUSE

AutoCAD SHX Text

PUMPS

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OILY WATER PIT

AutoCAD SHX Text

WASTE PIT

AutoCAD SHX Text

E

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E

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E

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E

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B

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B

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B

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B

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B

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B

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B

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B

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B

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B

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B

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E

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P

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7' CHAIN LINK

AutoCAD SHX Text

LPG

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DIESEL

AutoCAD SHX Text

DIESEL

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LPG

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DIESEL

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SUPERSEDES ALL PREVIOUS ISSUES

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APPROVED FOR CONSTRUCTION

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PRELIMINARY - NOT FOR CONSTRUCTION

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DWG. NO.

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DWG. TITLE

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BY

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REFERENCE DWGS.

AutoCAD SHX Text

PRIVATE AND CONFIDENTIAL This Drawing is not to be reproduced in any manner whatsoever, without written authorization of McCAIN FOODS LIMITED Florenceville, Canada

AutoCAD SHX Text

BY

AutoCAD SHX Text

NO.

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DATE

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REVISION

AutoCAD SHX Text

REVISIONS

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NOTES

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MAR

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D

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2019-02-08

AutoCAD SHX Text

REV-D

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MAR

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F

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2019-02-22

AutoCAD SHX Text

REV-F

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MAR

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G

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2019-03-01

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REV-G

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MAR

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H

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2019-03-08

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REV-H

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MAR

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K

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2019-03-29

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REV-K

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MAR

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2019-05-03

AutoCAD SHX Text

M

AutoCAD SHX Text

REV-M

FF-PROCESS100' - 0"

TOW-OFFICE122' - 8"

TOW RIDGE-PROCESS143' - 2"

FF-RECEIVING104' - 0" FF-EXISTING

98' - 0"

ABCDEFGJKLMNPQRSTUVW H

1

3000-A311

2

3000-A311

3

3000-A311

4

3000-A311

5

3000-A311

6

3000-A311

7

3000-A311

8

3000-A311

9

3000-A311

10

3000-A311 FR-1

FF-PROCESS100' - 0"

TOW EAVE-PROCESS138' - 8"

BOD EAVE-PROCESS137' - 0" TOW-OFFICE

122' - 8"


FF-RECEIVING104' - 0"FF-EXISTING

98' - 0"

2345678 1

BOD RIDGE-PROCESS141' - 6"

1

3000-A321

2

3000-A321

3

3000-A321

4

3000-A321

5

3000-A321

TOW-WASTE PIT116' - 8"

FR-A

FF-PROCESS100' - 0"


TOW-SUPPORT130' - 8"


98' - 0"

A B C D E F G J K L M N P Q R S T U V WH

1

3000-A311

2

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3

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4

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5

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6

3000-A311

7

3000-A311

8

3000-A311

9

3000-A311

10

3000-A311

PRIVATE AND

CONFIDENTIALThis Drawing is not to be reproduced in any

manner whatsoever, without written authorization of

McCAIN FOODS LIMITED

Florenceville, Canada

SHT. NO.

DRN. BY

SHEET SIZE

NO.PROJ.

SHEET TITLE

DATE

DWG NO.

SCALE

V

E

R




DWG. NO. DWG. TITLE BY

REFERENCE DWGS.

BYNO. DATE REVISION

REVISIONS

NOTES

AS NOTED

PT2112-ALPHA

30X42

M

ZJM 2019-05-03

PROJECT ALPHA

McCain Foods USA, Inc.100 Lee Road

Othello, WA. 99344

Phone: (509) 488-9611 Fax (509) 488-3982

B 2019-01-25

C 2019-01-28

D 2019-02-01

ZJM

ZJM

ZJM

1 OF 1

E 2019-02-13 ZJM

F 2019-02-22 ZJM

G 2019-03-01 ZJMPRICING SET

H 2019-03-08 ZJM

J 2019-03-15 ZJM

K 2019-03-29 ZJM

L 2019-04-25 ZJM

M 2019-05-03 ZJM

5/3

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19

1:5

5:2

3 P

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BIM

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0:/

/McC

ain

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a-A

_v1

8.r

vt

3000-A211

OVERALL - ELEVATIONS

1" = 30'-0"

1ELEVATION - NORTH

1" = 30'-0" 3030-A111

2ELEVATION - EAST

1" = 30'-0" 3150-A111

3ELEVATION - SOUTH

FF-EXISTING98' - 0"

2 3 4 5 6 7 8

CEILING-EXISTING120' - 0"

1

3000-A321

2

3000-A321

3

3000-A321

4

3000-A321

5

3000-A321

37000 SFPACKAGING

947 SFPACKAGING MAINTENANCE SHOP

31922 SFPALLETIZING

FF-EXISTING98' - 0"

2 3 4 5 6 7 8


1

3000-A321

2

3000-A321

3

3000-A321

4

3000-A321

5

3000-A321

31922 SFPALLETIZING

2777 SFSTORVEYORS (0°)

5422 SFTOTE RM (0°)

37000 SFPACKAGING

12904 SFFROZEN GRADING (40°)

FF-PROCESS100' - 0"

FF-EXISTING98' - 0"

2 3 4 5 6 7 8


1

3000-A321

2

3000-A321

3

3000-A321

4

3000-A321

5

3000-A321

7615 SFATL

993 SFMCC

12904 SFFROZEN GRADING (40°)

1388 SFCORRIDOR

3738 SFPARTS STORAGE/MAINTENANCE

FR-A

FF-PROCESS100' - 0"

TOW-SUPPORT130' - 8"

INTERSTITIAL125' - 0"

FF-LPR85' - 0"

BOD-SUPPORT129' - 0"


3 4 5 6 7


2

3000-A321

3

3000-A321

4

3000-A321

1608 SFRECIRCULATOR PIT

72928 SFPROCESSING

75066 SFWALK ON CEILING

FF-PROCESS100' - 0"



HPR PIT82' - 6"

BOD EAVE-PROCESS137' - 0"


3 4 5 6 7


2

3000-A321

3

3000-A321

4

3000-A321

BOD-WASTE PIT115' - 0"

TOW-WASTE PIT116' - 8"


72928 SFPROCESSING

6986 SFOIL RM

1774 SFWASTE RM

FF-PROCESS100' - 0"



MEZZ-PROCESS112' - 0"



3 4 5 6 7


2

3000-A321

3

3000-A321

4

3000-A321

629 SFCONTROL/OBSERVATION

665 SFPEF RM

72928 SFPROCESSING


6986 SFOIL RM

FF-PROCESS100' - 0"





3 4 5 6 7


2

3000-A321

3

3000-A321

4

3000-A321

72928 SFPROCESSING


1014 SFMCC

1022 SFEQUIPMENT DECK

FF-PROCESS100' - 0"





FF-RECEIVING104' - 0"

3 4 5 6 7


2

3000-A321

3

3000-A321

4

3000-A321

2798 SFDRY BATTER

8820 SFBATTER/INGREDIENT STORAGE

72928 SFPROCESSING




TOW-OFFICE122' - 8"




3 4 5 6 71


BOD-OFFCE121' - 0"

2

3000-A321

3

3000-A321

4

3000-A321

5

3000-A321

20868 SFRECEIVING

1866 SFLOADING DOCK

1082 SFMCC



TOW-OFFICE122' - 8"



3 4 5 6 7

MEZZ-RECEIVING124' - 0"

1


BOD-OFFCE121' - 0"

2

3000-A321

3

3000-A321

4

3000-A321

5

3000-A321

20868 SFRECEIVING

3661 SFSIZING DECK

1578 SFOPEN OFFICE

PRIVATE AND





SHT. NO.

DRN. BY

SHEET SIZE

NO.PROJ.

SHEET TITLE

DATE

DWG NO.

SCALE

V

E

R





REFERENCE DWGS.

BYNO. DATE REVISION

REVISIONS

NOTES

AS NOTED

PT2112-ALPHA

30X42

M

ZJM 2019-05-03

PROJECT ALPHA


Othello, WA. 99344

Phone: (509) 488-9611 Fax (509) 488-3982

B 2019-01-25

C 2019-01-28

D 2019-02-01

ZJM

ZJM

ZJM

1 OF 1

E 2019-02-13 ZJM

F 2019-02-22 ZJM


H 2019-03-08 ZJM

J 2019-03-15 ZJM

K 2019-03-29 ZJM

L 2019-04-25 ZJM

M 2019-05-03 ZJM

5/3

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19

1:5

5:4

8 P

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3000-A311

OVERALL - SECTIONS N/S

1" = 30'-0" 3000-A111

1SECTION - N/S 1

1" = 30'-0" 3000-A111

2SECTION - N/S 2

1" = 30'-0" 3000-A111

3SECTION - N/S 3

1" = 30'-0" 3000-A111

4SECTION - N/S 4

1" = 30'-0" 3000-A111

5SECTION - N/S 5

1" = 30'-0" 3000-A111

6SECTION - N/S 6

1" = 30'-0" 3000-A111

7SECTION - N/S 7

1" = 30'-0" 3000-A111

8SECTION - N/S 8

1" = 30'-0" 3000-A111

9SECTION - N/S 9

1" = 30'-0" 3000-A111

10SECTION - N/S 10

FF-EXISTING98' - 0"

A B C D E F G

1

3000-A311

2

3000-A311

3

3000-A311

31922 SFPALLETIZING

7615 SFATL

FF-PROCESS100' - 0"


BOD-SUPPORT129' - 0"


98' - 0"

A B C D E F G J K L M N P Q R S T U V WH.5 J.5 K.5 L.5 M.5 N.5 P.5 Q.5 R.5 T.5 U.5S.5H

1

3000-A311

2

3000-A311

3

3000-A311

4

3000-A311

5

3000-A311

6

3000-A311

7

3000-A311

8

3000-A311

9

3000-A311

10

3000-A311

8820 SFBATTER/INGREDIENT STORAGE

1866 SFLOADING DOCK

20868 SFRECEIVING

1014 SFMCC

1022 SFEQUIPMENT DECK

1544 SFAIR COMPRESSORS6986 SF

OIL RM4724 SF

BOILER RM1608 SF

RECIRCULATOR PIT4457 SF

AMMONIA COMPRESSORS

1031 SFMCC

993 SFMCC

31922 SFPALLETIZING

FF-PROCESS100' - 0"



98' - 0"

MEZZ-SCALE DECK110' - 0"

A B C D E F G J K L M N P Q R S T U V W

MEZZ-RECEIVING124' - 0"


H.5 J.5 K.5 L.5 M.5 N.5 P.5 Q.5 R.5 T.5 U.5S.5H

1

3000-A311

2

3000-A311

3

3000-A311

4

3000-A311

5

3000-A311

6

3000-A311

7

3000-A311

8

3000-A311

9

3000-A311

10

3000-A311

37000 SFPACKAGING

4065 SFSCALE DECK

5422 SFTOTE RM (0°)

12904 SFFROZEN GRADING (40°) 72928 SF

PROCESSING


394 SFCORRIDOR

20868 SFRECEIVING

3661 SFSIZING DECK

FF-PROCESS100' - 0" FF-PROCESS

100' - 0"




A B C D E F G J K L M N P Q R S T U V W


H.5 J.5 K.5 L.5 M.5 N.5 P.5 Q.5 R.5 T.5 U.5S.5H


1

3000-A311

2

3000-A311

3

3000-A3114

3000-A311

5

3000-A311

6

3000-A311

7

3000-A311

8

3000-A311

9

3000-A311

10

3000-A311

37000 SFPACKAGING

1388 SFCORRIDOR

1315 SFMCC

72928 SFPROCESSING


1315 SFMCC

20868 SFRECEIVING

241 SFCUTTER LAB

72928 SFPROCESSING

TOW-OFFICE122' - 8"


98' - 0"

A B C D E F G T U V W


T.5 U.5

BOD-OFFCE121' - 0"

1

3000-A311

2

3000-A311

3

3000-A311

9

3000-A311

10

3000-A311

3738 SFPARTS STORAGE/MAINTENANCE

37000 SFPACKAGING

595 SFFINISHED LAB947 SF

PACKAGING MAINTENANCE SHOP

PRIVATE AND





SHT. NO.

DRN. BY

SHEET SIZE

NO.PROJ.

SHEET TITLE

DATE

DWG NO.

SCALE

V

E

R





REFERENCE DWGS.

BYNO. DATE REVISION

REVISIONS

NOTES

AS NOTED

PT2112-ALPHA

30X42

M

ZJM 2019-05-03

PROJECT ALPHA


Othello, WA. 99344

Phone: (509) 488-9611 Fax (509) 488-3982

B 2019-01-25

C 2019-01-28

D 2019-02-01

ZJM

ZJM

ZJM

1 OF 1

E 2019-02-13 ZJM

F 2019-02-22 ZJM


H 2019-03-08 ZJM

J 2019-03-15 ZJM

K 2019-03-29 ZJM

L 2019-04-25 ZJM

M 2019-05-03 ZJM

5/3

/20

19

1:5

5:5

9 P

M

BIM

36

0:/

/McC

ain

- A

lph

a/M

cCa

in-A

lph

a-A

_v1

8.r

vt

3000-A321

OVERALL - SECTIONS E/W

1" = 30'-0" 3000-A111

1SECTION - E/W 1

1" = 30'-0" 3000-A111

2SECTION - E/W 2

1" = 30'-0" 3000-A111

3SECTION - E/W 3

1" = 30'-0" 3000-A111

4SECTION - E/W 4

1" = 30'-0" 3000-A111

5SECTION - E/W 5

3. Boiler and Flare Vendor Information

McCain Foods Othello, WA

6940 Cornhusker Hwy. ◊ Lincoln, NE 68507 ◊ Tel: (402)434-2000 ◊ Fax (402)434-2064 ◊ www.CleaverBrooks.com

NO. 27070034-Rev-3 Page 24 05/03/19

Guaranteed Emissions with FGR

Guaranteed Emissions; 25% to 100% MCR corrected to 3 %O2 on a dry basis.

Natural Gas Digester Gas (co-firing 40mm

DG w/ NG) NOx ppmvd 30 30CO ppmvd 50 50SOx (Not burner dependent) lb/MMBtu 0.228 0.228 PM (Particulate) lb/MMBtu 0.0074 0.0074 VOC lb/MMBtu 0.0053 0.0053Based on: Cleaver-Brooks technician is required for start-up and adjustments. EA (excess air) and FGR rates are expected only and not guaranteed. Please refer to boiler performance for guaranteed boiler efficiency. PM is exclusive of any particulates in combustion air or other sources of residual particulates from material. SOx emission emitted depends directly on the Sulfur content in the Fuel (not burner dependent).

Fuel Gas Analysis %v NG Methane CH4 93Ethane C2H6 7Propane C3H8 0N & I- Butane C4H10 0N & I-Pentane C5H12 0Hexane C6H14 0Nitrogen N2 5Carbon Dioxide CO2 0Hydrogen Sulfide H2S Traces Grains / 100

SCF

HHV Btu/SCF 1,050 Temp. 0F (Assumed)

60

Pressure psig (Assumed)

25

Fuel Gas Analysis %v Digester Gas Methane CH4 63Oxygen O2 1.43Nitrogen N2 6.12Carbon Dioxide CO2 29.03Hydrogen Sulfide H2S 0.42HHV Btu/SCF 636 Pressure psig 10

Note 1 Above information is preliminary only and will be confirmed on drawings issued for construction. Note 2 Do not use the above Burner model designation for emission permit application. Note 3 Emission and capacity guarantees are specific to the fuel analysis listed. Performance with any other Fuel

composition that will result in more than 1% Oxygen content variation in flue gas and/or a ± 5% Wobbe index variation needs to be evaluated. Fuel composition and properties shall be constant over time. Any variation in the Fuel needs to be submitted for review of emissions guarantees and burner design.

Note 4 Under normal operating conditions, the natural gas temperature range should be within 40-80 ºF.

BOILER PREDICTED PERFORMANCE*Version: CB EBS-Size-v2019.2.1Customer: McCain Foods Engineer: McCoy

Proposal: McCain foods Fuel: NG70/BG30

Model: NB-300D-65 Design Pressure: 350 PSIG

Boiler Load - % 100% 75% 50% 25%

Steam Flow - Gross Production 80,000 60,000 40,000 20,000 lb/hr

Net Steam Flow - Gross less Pegging Steam 80,000 60,000 40,000 20,000 lb/hr

Pegging Steam - - - - lb/hr

Steam Pressure - Operating 300 300 300 300 psig

Steam Temperature 421 421 421 421 °F

Fuel Input (HHV) 96.4 72.0 47.9 24.1 mmbtu/hr

Ambient Air Temperature 80 80 80 80 °F

Relative Humidity 60 60 60 60 %

Excess Air 15 15 15 25 %

Flue Gas Recirculation 13 13 13 13 %

Steam Output Duty 80.9 60.7 40.4 20.2 mmbtu/hr

Heat Release Rate - Volumetric 74,992 55,988 37,221 18,737 btu/ft3-hr

Heat Release Rate - Area 125,300 93,548 62,191 31,306 btu/ft2-hr

Heat Flux 33,051 btu/ft2-hr

Feed Water Temperature 227 227 227 227 °F

Water Temperature Leaving Economizer 327 315 303 298 ±10°F

Blow Down 2.0 2.0 2.0 2.0 %

Boiler Gas Exit Temperature 596 543 488 444 ±10°F

Economizer Gas Exit Temperature 292 272 253 240 ±10°F

Air Flow 80,755 60,290 40,081 21,931 lb/hr

Flue Gas to Stack 86,841 64,835 43,102 23,451 lb/hr

Flue Gas to Stack 29,136 21,351 13,907 7,436 acfm

Flue Gas Including FGR 98,131 73,263 48,706 26,500 lb/hr

Fuel Flow 6,086 4,544 3,021 1,520 lb/hr

Flue Gas Analysis,Losses, & Efficiency - %

Dry Gas Loss 4.1 3.7 3.3 3.4 %

Air Moisture Loss 0.1 0.1 0.1 0.1 %

Fuel Moisture Loss 10.6 10.5 10.5 10.4 %

Casing Loss 0.3 0.4 0.6 1.2 %

Margin 1.0 1.0 1.0 1.0 %

Efficiency - LHV 93.0 93.4 93.7 93.0 %

Efficiency - HHV 83.9 84.3 84.5 84.0 %

Total Pressure Drop Including Economizer 7.60 4.19 1.82 0.52 inH2O

Products of Combustion - CO2 9.31 9.31 9.31 8.63 % vol.

- H2O 17.89 17.89 17.89 16.74 % vol.

- N2 70.37 70.37 70.37 70.88 % vol.

- O2 2.42 2.42 2.42 3.74 % vol.

- SO2 0.00 0.00 0.00 0.00 % vol.

Fuel Composition - Gas Boiler Surface

methane 78.3302 % vol. Furnace Volume: 1,285 ft3

ethane 3.970357 % vol. Furnace Projected Area: 769 ft2

carbon dioxide 11.787642 % vol. Evaporator: 3,523 ft2

nitrogen 5.320997 % vol. Total Area: 4,292 ft2

hydrogen sulfide 1.015E-2 % vol. Economizer: 8,319 ft2

oxygen 0.580652 % vol. Superheater: - ft2

LHV 14,292 btu/lb

HHV 15,839 btu/lb

*Above data is predicted only, see proposal for guaranteed numbers.

June 20, 2019

Cleaver-Brooks, Inc.

Engineered Boiler Systems

27070034-Size-v2019.2.1-R3 (80kpph) Firm Bid 7-3-19

LoadsCase3 6/20/2019

BOILER PREDICTED PERFORMANCE*Version: CB EBS-Size-v2019.2.1Customer: McCain Foods Engineer: McCoy

Proposal: McCain foods Fuel: Natural Gas

Model: NB-300D-65 Design Pressure: 350 PSIG

Boiler Load - % 100% 75% 50% 25%

Steam Flow - Gross Production 80,000 60,000 40,000 20,000 lb/hr

Net Steam Flow - Gross less Pegging Steam 80,000 60,000 40,000 20,000 lb/hr

Pegging Steam - - - - lb/hr

Desuperheater Spray - - - - lb/hr

Steam Pressure - Operating 300 300 300 300 psig

Steam Temperature 421 421 421 421 °F

Fuel Input (HHV) 96.2 71.8 47.8 24.0 mmbtu/hr

Ambient Air Temperature 80 80 80 80 °F

Relative Humidity 60 60 60 60 %

Excess Air 15 15 15 25 %

Flue Gas Recirculation 13 13 13 13 %

Steam Output Duty 80.9 60.7 40.4 20.2 mmbtu/hr

Heat Release Rate - Volumetric 74,822 55,876 37,156 18,707 btu/ft3-hr

Heat Release Rate - Area 125,016 93,360 62,082 31,257 btu/ft2-hr

Heat Flux 34,473 btu/ft2-hr

Feed Water Temperature 227 227 227 227 °F

Water Temperature Leaving Economizer 324 313 301 296 ±10°F

Blow Down 2.0 2.0 2.0 2.0 %

Boiler Gas Exit Temperature 592 540 487 443 ±10°F

Economizer Gas Exit Temperature 290 270 253 240 ±10°F

Air Flow 80,842 60,372 40,146 21,970 lb/hr

Flue Gas to Stack 84,903 63,404 42,162 22,985 lb/hr

Flue Gas to Stack 28,603 20,958 13,689 7,330 acfm

Flue Gas Including FGR 95,941 71,647 47,644 25,973 lb/hr

Fuel Flow 4,060 3,032 2,016 1,015 lb/hr

Flue Gas Analysis,Losses, & Efficiency - %

Dry Gas Loss 3.9 3.6 3.2 3.3 %

Air Moisture Loss 0.1 0.1 0.1 0.1 %

Fuel Moisture Loss 10.6 10.5 10.4 10.3 %

Casing Loss 0.3 0.4 0.6 1.2 %

Margin 1.0 1.0 1.0 1.0 %

Efficiency - LHV 93.2 93.6 93.8 93.1 %

Efficiency - HHV 84.1 84.5 84.7 84.1 %

Total Pressure Drop Including Economizer 7.34 4.05 1.76 0.51 inH2O

Products of Combustion - CO2 8.35 8.35 8.35 7.73 % vol.

- H2O 18.07 18.07 18.07 16.89 % vol.

- N2 71.11 71.11 71.11 71.57 % vol.

- O2 2.47 2.47 2.47 3.81 % vol.

- SO2 0.00 0.00 0.00 0.00 % vol.

Fuel Composition - Gas Boiler Surface

methane 93.0 % vol. Furnace Volume: 1,285 ft3

ethane 7.0 % vol. Furnace Projected Area: 769 ft2

hydrogen sulfide 1.0E-4 % vol. Evaporator: 3,523 ft2

Total Area: 4,292 ft2

LHV 21,385 btu/lb Economizer: 8,319 ft2

HHV 23,686 btu/lb Superheater: - ft2

*Above data is predicted only, see proposal for guaranteed numbers.

June 20, 2019

Cleaver-Brooks, Inc.

Engineered Boiler Systems

27070034-Size-v2019.2.1-R3 (80kpph) Firm Bid 7-3-19

LoadsCase4 6/20/2019

185

5911 Butterfield Road Hillside, IL 60162 • tel: (708) 236-6000 • fax: (708) [email protected] • www.ljtechnologies.com • ISO 9001:2008 Certified

Waste Gas Burner with Touch Screen Control Panel

Rev: 97300T-3D

97300T

Designed for complete automatic operation of the entire Flare System, the S&J 97300T Waste Gas Burner and Touch Screen Control Panel is specifically designed to operate efficiently with low BTU anaerobic digester waste gases. The 97300T efficiently incinerates waste gases thus minimizing odors and VOC’s. The stoichiometric pilot ensures that a proper air to fuel mixture is maintained throughout the wide range of pressure and BTU fluctuations experienced in these processes. A continuous or intermittent burning pilot in the flame area provides stable, controlled nonsmoking combustion to minimize odors and VOC emissions. Alarm outputs and automatic controls provide safe, reliable and simple operation.

The 97300T is capable of withstanding a wind speed load of 150 mph and seismic zone 4 loads. Its stainless steel components endure the severest of process environments. The burner tip is designed with swirl inducers that create a cyclonic effect that produces an efficient air/fuel mixture and maximizes flame retention. The wind shroud induces sufficient air to the flare tip for proper mixing and combustion throughout the operating range.

Paired with a touch screen control panel, the flare controller is designed for complete automatic operation of the entire Flare System. Shand & Jurs’ Flare System gives the operator much more flexibility in controlling the system with more parameters easily configured via the touch screen control panel. The Control Panel can also be connected to a local PLC.

The flare pilot control system utilizes state of the art electronics and all necessary instrumentation to safely operate the flare system. Pilot controls are enclosed in a NEMA 4, carbon steel, electrical enclosure. The flare pilot, for automatic operation, can be ordered to operate only during initial start up or continuously. The Pilot Control Panel includes a dry contact input for Remote Start, typically from a SCADA system or pressure switch. The Pilot Control Panel also includes Contact Status outputs for Alarm and Flame Proven.

The auto-ignition sequence is started by the closing of the remote start contact or pressure switch contact indicating that the gas pressure limit has been reached and flaring of excess gas should begin. Once the sequence begins, the operation of the Burner will continue until the contact opens.

The S&J 97300T is especially designed to combust unwanted biogases generated in fermentation processes like anaerobic digesters, lagoons, and

97300T Waste Gas Burner with Touch Screen Control Panel

Features • High Performance Stoichiometric

Pilot

• No Flame Front Burn-out of Pilot Gas During Ignition

• Sizes 2” Through 12”

• Touch Screen Control Panel

• Burns High Flow, Low BTU “Wet” Methane

• No Venturi Maintenance

• State-of-the-Art Digital Control

• Fully Automated Pilot: Continuous or Intermittent While Flaring

• Provides Alarm Outputs


186


Rev: 97300T-3D

97300T

Specifications:

Functions:

Sizes:2”, 3”, 4”, 6”, 8”, 10” & 12”

StackBurnerConnection:ANSI 150 lb. Raised Face Flange

ContactOutputs:Alarm SPST, 120 VAC 1 AmpFlame Proven SPST, 120 VAC 1 AmpOther Status Outputs Available

PowerRequirements:120 VAC 4 Amp 60 Hz; 220 VAC (option)

Controller:Type: Touch ScreenTemperature Range: -20 to 150 degrees FEnclosure: Wall Mount NEMA 4 (Optional NEMA 4X or 7); Enclosure Material: Carbon Steel Optional: Stainless SteelFunctions: Manual Start Remote Start Automatic Sequencing Continuous Pilot or Intermittent Pilot

StackMaterials:Top Assembly and Pilot Nozzle: Stainless SteelBottom Stack Assembly: Carbon Steel (6”-12”) (Optional Stainless Steel) Stainless Steel (2”-4”) *Other materials available

Biogas Criteria Composition: 50%-70% CH4, 50%-30% CO2, with trace amounts ofH2S, Inert Gases and Air

Moisture Content:Saturated (100% Humidity)

PilotGas:Natural Gas LPG (Propane)Waste Gas (500 BTU/ Cubic foot Minimum)

PilotGasPressure:10” - 28” W.C. Low Pressure - Standard1-100 PSIG High Pressures - Optional

ManualStart:The operator puts selector to manual and initiates ignition by depressing start on the touch screen control panel.

RemoteStart:Remote ignition is performed by placing selector switch in the auto position and closing the remote location dry contact to initiate the operation of the waste gas burner.

AutoStart:Automatic Start is performed by the sensing of a pressure permissive in the system. The pilot control panel must be set to “Auto” position for this to be controlled by the pressure switch. When the pressure switch contacts close, the auto flaring sequence will begin. Once the pressure drops below the pressure switch set point the contacts will open, halting operation.

Accessories:A back pressure regulator / deflagration arrester should be installed in the digester line just upstream of the flare. For automatic operation, the solenoid option must be selected on the back pressure regulator.

187



Rev: 97300T-3D

97300T

Dimensions:

Flow specified for gas with 0.8 specific gravity, air at 60o F, and .5” WC pressure drop

Dimensions (Inches [mm])Size A B C

2 [50] 16 [406] 24 [610] 88 [2235]3 [75] 18 [457] 24 [610] 92 [2337]

4 [100] 20 [508] 24 [610] 92 [2337]6 [150] 24 [610] 36 [914] 128 [3251]8 [200] 24 [610] 48 [1219] 144 [3658]

10 [250] 30 [762] 48 [1219] 176 [4470]12 [300] 36 [914] 60 [1524] 188 [4775]

Size(Inches mm]) Capacity (FT3/Hr.)

2 [50] 40003 [75] 9970

4 [100] 191506 [150] 442008 [200] 76800

10 [250] 12900012 [300] 218600

Stack Dimensions Capacity

1/2" PILOT LINE(PIPING NOT PROVIDED)

PILOT GASINLET

CONTROLPANEL POWER

MOUNTING FLANGEANSI 150# RF

WIND SHROUD

THERMOCOUPLE

A

B

C

THERMOCOUPLECONDULET

FLAME CHECK(97200)

FLARETIP

FLARESTACK

THERMOCOUPLE WIRETYPE "K" (CONDUIT ANDWIRING NOT PROVIDED)

PILOT NOZZLE

PILOT GAS TRAIN(COMPONENETS ONLY)

IGNITERCONDULET

IGNITION TRANSFORMER WIRING(CONDUIT AND WIRE NOT PROVIDED)

Hui.Cheng

Rectangle


188


Rev: 97300T-3D

97300T

Option B Unit Size2 2”3 3”4 4”5 6”7 8”8 10”9 12”

Table B - Unit Size

Model Number Selection

The model number will have a base number 97300T followed by 8 digit numbers. These digits will represent 8 sets of option tables.

97300T - AB - CD - EF - GH

97300T Ordering Guide

Option H Shroud / Stack1 304(L) Stainless Steel / Carbon Steel

2 304(L) Stainless Steel / 304(L) Stainless Steel3 316(L) Stainless Steel / Carbon Steel4 316(L) Stainless Steel / 316(L) Stainless Steel

NOTE:Pilot Material 316 Stainless Steel

Table H - Materials of Construction

Option G Description

0 Standard*

Option A Pilot Gas0 Natural1 Propane2 Bio

Option E Description

1 Low Pressure Local Manual Start or Remote Dry Contact2 Low Pressure Remote Control with Pressure Switch3 High Pressure Local Manual Start or Remote Dry Contact4 High Pressure Remote Control with Pressure Switch

Option C Description1 120 VAC, 60HZ2 220/240 VAC, 50/60HZ

Option F Description1 Continuous 2 Intermittent

Table G - Gas Train

Table A - Pilot Gas Table E - Control

Table C - Power Source

Table F - Pilot

* Standard regulator pressure is 10 PSIG max

Option D Description0 NEMA 4 - Carbon Steel1 NEMA 7 - Cast Aluminum2 NEMA 4X - 304 Stainless Steel3 NEMA 4X - 316 Stainless Steel4 NEMA 4 - Carbon Steel (UL 508A)5 NEMA 7 - Cast Aluminum (UL 508A)6 NEMA 4X - 304 SS (UL 508A)7 NEMA 4X - 316 SS (UL 508A)

*Includes heater and thermostat

Table D - Enclosure Rating