comments of legal & safety employer research, inc. (laser ... · for summit ethanol, llc,...

Comments of Legal & Safety Employer Research, Inc. (LASER)& Concerned Citizens of Putnam County

Regarding a Proposed Air Quality Permit forSummit Ethanol LLC, Leipsic, OH

Presented to

Ohio Environmental Protection AgencyDivision of Air Pollution Control,

&

U.S. Environmental Protection Agency, Region V,Air & Radiation Division, Permits & Grants Section

& Air Enforcement Section

Legal & Safety Employer Research, Inc. (LASER)Concerned Citizens of Putnam County (CCPC)Richard C. Sahli, Counsel to LASER & CCPC

981 Pinewood Lane, Gahanna, Ohio 43230(614) 428-6068; [email protected]

Prepared byAlexander J. Sagady, Environmental Consultant

657 Spartan Avenue, East Lansing, MI 48823(517)332-6971; http://www.sagady.com [email protected]

This document available on the web at:http://www.sagady.com/workproduct/LASERCommentSummitEthanol.pdf

Table of Contents

1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2 Comments Applicable to Multiple Emission Units . . . . . . . . . . . . . . . . . . . . . . . . 1

2.1 The Draft Permit Does Not Contain Sufficient Federally EnforceablePhysical Production Rate and/or Throughput Limitations on the Potential toEmit to Ensure the Facility Does Not Exceed Major Stationary SourceLimitations and Individual Emission Unit Limitations . . . . . . . . . . . . . . . . 1

2.1.1 Broin and Associate Admission of Facility Operations Above TheirEthanol Plant Nameplate Capacities at Their Turn-key and “PremierPartner” Sites . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2.1.2 The Present Draft Permit Contains Poorly Stated, Ineffective Site-Wide Physical Limitations on the Potential to Emit . . . . . . . . . . . . . 2

2.1.3 Ohio EPA Must Amend the Draft Permit to Include Hourly andAnnual Federally Enforceable Physical Process LimitationsApplicable to Each Emission Unit to Limit the Potential to Emit;Mass Rate Emission Limitations and Grain Loading Rates Are“Blanket Restrictions” Which Cannot Be Considered as Limiting thePotential to Emit of Individual Emission Units Under WellEstablished Precedent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

2.1.4 Nothing in the Permit Application Submittal, the Draft Permit andthe Ohio EPA Air Rules Ensures that the Maximum ProductionRates Shown in the Application Actually Reflect the Actual“Maximum Design Capacity” of the Equipment Intended for SiteInstallation; In the Absence of Such Assurances and Without MakingSuch Limitations Enforceable, Ohio EPA’s Acceptance of thePotential to Emit Portrayed by Applicant Constitutes Error . . . . . . 6

2.2 Applicant Has Not Provided a Best Available Technology Demonstrationfor All Emission Units in Violation of the Present Federally Approved OhioState Implementation Plan for New Source Review . . . . . . . . . . . . . . . . . . 8

2.3 Applicant Has Not Described All of the Facility Emission Sources in theApplication and Such Application is Not Complete; All VOC-RelatedProcess Emission Units Must be Described in the Application and TheirPotential to Emit Must be Characterized . . . . . . . . . . . . . . . . . . . . . . . . . . 10

2.3.1 Summit Ethanol’s Application Failed to Fully Describe EmissionUnits and Associated VOC Emissions from, and Controls on,Process Wastewater Treatment Units, Such as Biomethanators,Commonly Installed at Other Broin-Constructed Facilities . . . . . 10

2.3.2 The Applicant Has Not Identified a Number of Other Likely ProcessEmission Points, the Nature of Any VOC Controls Provided and theQuantification of Expected Emissions from Such Emission Points 11

2.4 The Draft Permit Contains No Requirement for Compliance with NSPS 40C.F.R. Part 60, Subpart A Provisions . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

2.5 Modeling issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

2.6 Compliance Monitoring and Evaluation for Volatile Organic CompoundEmissions from the RTO, the RTO Bypass and the DDGS Fluidized BedCooler Should Embrace EPA’s Midwest Scaling Protocol for EthanolPlants; the Draft Permit Should Not Confer Sole Discretion on theApplicant to Chose Between EPA Methods 25, 25A and 18 for Evaluationof Compliance with VOC Emission Limitations and the Major StationarySource Threshold for VOCs With No Adjustment for Variability of TheseDiffering Methods to Detect the Mass Rate Emissions of OxygenatedVolatile Organic Compounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

2.7 The Draft Permit Fails to Incorporate Hourly PM-10 Mass Rate Emissionand Potential to Emit Limitations on All Emission Units and Thus Fails toEnsure that Short Term Prevention of Significant Deterioration Limits areMet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

2.8 Section II - Table 7-A Stack Egress Point Information Conflicts withEmission Calculations as to Volumetric Discharge Characterization . . . . 15

2.9 The Draft Permit Contains Rote “Applicable Compliance Method[s]”Which Fail to Properly Evaluate Whether the Source Meets Emission Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

2.9.1 Repeated Citation to an Erroneous Limitation of 0.04 gr/dscf and“cfm” Rather Than “dscfm” . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

2.9.2 Compliance with a Grain Loading Emission Limitation Stated with aSingle Significant Figure Accuracy Cannot Be Used in EngineeringCalculations to Properly Assess Compliance with a Mass RateEmission Number Stated with More than One Significant Figure . 16

2.10 The Applicant Has Not Considered NOX and Carbon Monoxide Emissionsfrom Space Heating Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

2.11 Compliance Monitoring of Fabric Filter Controlled Emission Units . . . . 18

2.12 The Summit Ethanol Facility Is Actually a Major Stationary Source . . . . 18

3 Discussion of Permit Regulatory Sections and Emission Calculations by IndividualEmission Unit and Process Groupings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

3.1 B001 and B002 – Natural Gas-Fired Boilers #1 and #2 . . . . . . . . . . . . . . 19

3.1.1 Ohio EPA has Erroneously Depicted the PM/PM10 Potential to Emitfor Boilers #1 and #2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

3.1.1.1 By Failing to Incorporate Condensible PM Emissionsand Failing to Include Enforceable PhysicalLimitations on Natural Gas Fired to the Boilers, OhioEPA’s Draft Permit Fails to Limit the Potential to Emitof the Two Boiler Units . . . . . . . . . . . . . . . . . . . . . . 19

3.1.1.2 The Gas Fired Boiler Units at the Subject FacilityCannot Meet the Emission Limits Stated in the DraftPermit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

3.1.1.3 Ohio EPA’s Finding that the Potential to Emit forPM10 is 3.5 tons/year Per Boiler is in Error . . . . . . 20

3.1.1.4 Proper Treatment of Condensible Particulate Matter asa Contribution to Total PM10 and PM Emissions is aMatter of Considerable Federal Regulatory Interest inNew Source Review Programs . . . . . . . . . . . . . . . . . 21

3.1.2 Boiler #1 and #2 NOX and CO Emissions . . . . . . . . . . . . . . . . . . . 21

3.1.2.1 Applicant Has Submitted No Information ShowingThey Will Be Able to Comply with the 0.035 lbs NOXPer Million BTU Heat Input Emission Limitation . . 21

3.1.3 The Draft Permit Contains No Enforceable Physical Limitations onthe Potential to Emit for Carbon Monoxide, Particulate Matter andNitrogen Oxides . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

3.2 F001 – Fugitive Emissions from Site Roads . . . . . . . . . . . . . . . . . . . . . . . 22

3.2.1 Applicant Has Understated Fugitive Emissions by UnderstatingVMT from Transport of Dried Distiller Grains . . . . . . . . . . . . . . . 22

3.2.2 Applicant Has Underestimated Particulate Emissions from SiteRoadways by Using an Unrealistic Silt Loading Factor NotSupported by AP-42 Factors and Not Typical of AgriculturalCommodity-Related Industrial Facility Roads as Demonstrated bythe Experience of Other States . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

3.2.2.1 Applicant’s should at least use a 0.6 g/M2 or HigherSilt Loading Factor for Ubiquitous Low Traffic PublicPaved Roads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

3.2.2.2 Applicant’s 0.4 g/M2 Silt Loading Factor is NotSupported by Actual Industry Experience, AcceptedPermitting Practices and the Common Practices ofOther Nearby State Jurisdictions . . . . . . . . . . . . . . . 23

3.2.2.3 Nothing in the Draft Permit Requires a DeterminantAmount of Fugitive Road Dust Control That Can BeAssured of Achieving the Claimed Low ParticulateEmissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

3.3 J001 – Ethanol and Gasoline Loading Operations . . . . . . . . . . . . . . . . . . 25

3.3.1 Ohio EPA’s Synthetic Minor Determination Doesn’t Contain theCorrect Total VOC Emissions from this Emissions Unit; Ohio EPADid Not Use the Applicant’s Emission Characterization in Either theSynthetic Minor Determination, Nor The Draft Permit . . . . . . . . . 25

3.3.2 Applicant and Ohio EPA Have Failed to Properly CharacterizeFugitive Volatile Organic Compound and Hazardous Air PollutantEmissions From Emission Unit J001 Loading Operations . . . . . . . 26

3.3.3 Ohio EPA’s Volatile Organic Compound Potential to EmitDetermination of Point Source J001 Loading Emissions Is Subject toSignificant Question . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

3.3.4 Applicant Has Failed to Properly Characterize Particulate Emissionsfrom the Flare to Control Loading Operations . . . . . . . . . . . . . . . . 28

3.3.5 Ohio EPA’s “Synthetic Minor Determination” Contains the WrongVOC Emission Number for J001 Loading Operations . . . . . . . . . . 28

3.4 P007-P009 – Ethanol Production, Dryer Operation and Scrubber/ThermalOxidizer Controls . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

3.4.1 The Applicant Has Not Incorporated a Ohio Best AvailableTechnology (BAT) Determination and a BAT Level of Control forthe Dryer Burner NOX Emissions . . . . . . . . . . . . . . . . . . . . . . . . . 28

3.4.2 VOC Emission Characterization of Uncontrolled Dryer EmissionsFails to Consider Thermal Decomposition of Spent Distiller’s Grainand Multiple Volatile Chemical Compounds Found in Wet GrainResiduals and Thus Understates Potential VOC Emissions from theRegenerative Thermal Oxidizer Stack . . . . . . . . . . . . . . . . . . . . . . 29

3.4.3 Applicant Has Failed to Justify or Document the Uncontrolled DryerPM Emission Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

3.4.4 Dryer Sulfur Dioxide Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

3.4.5 Issues Arising From Conditional Applicability of EmissionLimitations to “Normal Operation” of the Regenerative ThermalOxidizer (RTO), the Matter of Scheduled and UnscheduledMaintenance and Other Outages of the RTO, and Consequences ofSuch Conditional Applicability and Outages for Site Emission Units,Summit Ethanol’s Potential to Emit and Clean Air Act Compliance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

3.4.5.1 The Draft Permit is Not Clearly Written to RequireThat Hours of Regenerative Thermal Oxidizer OutagesFrom Scheduled Maintenance Accumulate to and areLimited by the 500 Hour Provision; the 500 HourProvision Should Be Amended to Embrace Rolling 12Month Average Compliance Measurement,Recordkeeping and Reporting . . . . . . . . . . . . . . . . . 30

3.4.5.2 Given the Failure to Account for ScheduleRegenerative Thermal Oxidizer (RTO) Downtime inPermit Provision Limitations, Applicant Has Failed toProperly Quantify Potential to Emit Emissions ofVOC, CO and PM During Times of Scheduled RTOMaintenance Outages . . . . . . . . . . . . . . . . . . . . . . . . 31

3.4.5.3 As Presently Stated, the Draft Permit EmissionLimitations for Emission Units P007, P008 and P009Destroy the Effectiveness of the Stated EmissionLimitations in Violation of EPA’s ContinuousCompliance Policy and the Federal Clean Air Act . 32

3.4.6 The Draft Permit Fails to Limit the NOX, VOC, Carbon Monoxideand Particulate Matter Potential to Emit for Emission Units P007,P008 and P009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

3.4.7 The Draft Permit Fails to Require Assurances of ContinuousCompliance with NOX and Carbon Monoxide Emission Limitations;the Draft Permit Should Be Amended to Incorporate Both NOX andCarbon Monoxide Continuous Emission Monitoring . . . . . . . . . . 33

3.4.7.1 Issues of NOX Compliance Assurance . . . . . . . . . . 34

3.4.7.2 Issues of Carbon Monoxide Compliance . . . . . . . . . 34

3.5 P801 – Fugitive VOC Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.5.1 Applicant’s Fugitive VOC Leak Emission Characterization for OpenEnded Lines is Erroneous . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.6 P901 and P902 – Stack and Fugitive Emissions from Grain Receiving,Transferring, Conveying and Storage; DDGS Loadout . . . . . . . . . . . . . . 35

3.6.1 Hourly Mass Rate Emission Limitations Should Be Applied on P901and P902 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.6.2 Annual Limitations on the Amount of Grain Received by the FacilityShould Be Written in the Form of Twelve Month Rolling Averages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.6.3 Applicant’s VOC Emission Characterization for the DGS Dryer isSubject to Question . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.6.4 Applicant’s Rejection of Wet Scrubber Controls on the DDGSCooler in the Best Available Technology Determination Should beDisallowed . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

3.7 P011 - Cooling Tower Emission Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36

Comments of LASER & CCPC on a Proposed Air Permit Page 1for Summit Ethanol, LLC, Leipsic, OH

1 Introduction

Legal & Safety Employer Research, Inc. (LASER) and Concerned Citizens ofPutnam County have produced these comments as an independent review of the air permitapplication and draft permit for the proposed Summit Ethanol, LLC facility at Leipsic,OH. We submit these comments for filing with the Ohio Environmental ProtectionAgency, Division of Air Pollution Control and the U.S. Environmental ProtectionAgency, Region 5, Air & Radiation Division.

2 Comments Applicable to Multiple Emission Units

2.1 The Draft Permit Does Not Contain Sufficient Federally Enforceable PhysicalProduction Rate and/or Throughput Limitations on the Potential to Emit toEnsure the Facility Does Not Exceed Major Stationary Source Limitationsand Individual Emission Unit Limitations

2.1.1 Broin and Associate Admission of Facility Operations Above Their EthanolPlant Nameplate Capacities at Their Turn-key and “Premier Partner” Sites

Attachment #5 contains information from the Broin and Associates website and othersources showing admissions that ethanol production facilities designed and/or constructedby Broin are operated at production rates which exceed the stated “nameplate designcapacities” of the facilities.

A summary of these Broin admissions are in the table below:

Plant Nameplate CapacityAccording to Broin WebSite (MMgal/Year)

Stated as Actually Operating atPercentage of NameplateCapacity

James Valley Ethanol 45 110%

Great Plains Ethanol 40 110%

Michigan Ethanol 40 120%

Tall Corn Ethanol 40 120%

Northern Lights Ethanol 40 110% (Broin Website)125% (Biofuels Journal, 2005)

Broin Enterprises, Inc 140%

It thus appears as a practice of Broin to design and construct ethanol production facility equipment that is subsequently operated at process rates greater than the stated nameplatedesign capacity. Time, resources and available information does not permit a complete


examination of all aspects of these practices. However, we submit this information to illustrate that emission calculations submitted by the Applicant that rely on statedmaximum process capacities that are less than what is physically possible will not reflectthe actual potential to emit of the subject facility if the Applicant later chooses to operatethe particular equipment process rates beyond what was an applicant-stated maximumprocess capacity in the permit application.

When an ethanol production facility operates in a usual and ordinary manner at a processrate exceeding the maximum stated process capacity and where no physical processmodification has been made, it is not likely that the original applicant-stated maximumprocess information articulated the actual maximum design process rate that is physicallyachievable.

2.1.2 The Present Draft Permit Contains Poorly Stated, Ineffective Site-WidePhysical Limitations on the Potential to Emit

An examination of the permit finds the following provisions:

“1. The maximum annual ethanol throughput rate for this emissions unit shall notexceed 69 million gallons. The maximum annual gasoline throughput rate for thisemissions unit shall not exceed 40 million gallons.” (Condition J001:II.B.1)

“2.b The annual allowable emission rate is based on the annual production of69,000,000 gallons denatured ethanol. Since the facility annual production rate isequivalent to the maximum facility capacity, no operational restrictions,monitoring, record keeping or reporting requirements are necessary to ensure thatthis emissions unit does not exceed its annual allowable emission rates. Therequirement to record the amount of ethanol produced is in the terms andconditions of emissions unit J001.” (Condition J001:II.A.2.2a)

While the first condition limits the maximum annual rate on a calendar year basis ofproduct loading, it does not limit the actual site production rate and the potential to emitof the other site emission units. .

The product loading compliance provisions at Condition J001:II.C.2 and J001:II.D.4require only calendar annual compliance justification and not production limit complianceon the basis of rolling 12 month averages. Failure to require rolling 12 month averagesmeans that periods of production beyond nameplate capacity and the shipping of suchproduct can be straddled over calendar year boundaries and still be larger than the designbasis production rate for a portion of a year.

Permit provisions which articulate a calculation basis of annual emissions for compliancetest purposes and which do not affirmatively prohibit the process rate from exceeding a


1 http://www.epa.gov/ttn/atw/pte/june13_89.pdf

stated amount fail to physically limit the potential to emit. See, for example, the secondparagraph of Condition J001:II.A.2.2a which mentions “69 million gallons” but doesn’tactually require that the production rate be limited to this annual rate.

Condition P901:II.B.1 does provide an operational restriction on the annual materialthroughput rate of 8683,280 tons of grain received per year, but this physical limitation onthe potential to emit is defective because it is written on a calendar year basis rather thana rolling 12 month average basis.

2.1.3 Ohio EPA Must Amend the Draft Permit to Include Hourly and AnnualFederally Enforceable Physical Process Limitations Applicable to EachEmission Unit to Limit the Potential to Emit; Mass Rate Emission Limitationsand Grain Loading Rates Are “Blanket Restrictions” Which Cannot BeConsidered as Limiting the Potential to Emit of Individual Emission UnitsUnder Well Established Precedent

Ohio EPA must incorporate both plant-wide and emission unit specific physicallimitations on the production rate and/or process throughput rate in order to properly limitthe potential to emit to reflect and validate potential to emit emission calculations in theapplication. Such limits must be stated on an hourly and an annual basis. Annualaveraging should feature rolling 12 month averages rather than calendar year compliancedetermination. Ohio EPA must also require enforceable requirements for monitoring,recordkeeping and reporting on such physical limitations on the potential to emit in orderto assure compliance.

Without federally enforceable physical limitations on the potential to emit, there can beno assurances that Applicant’s facility will maintain short term emissions at mass ratesless than what were used in air quality modeling studies. Such physical limitations arenecessary to ensure that Summit Ethanol remains below the 100 ton potential to emitthreshold for major stationary source status.

Ohio EPA is required to run its minor source permitting activity pursuant to Clean AirAct requirements. Under the Court’s holding in the case of U.S. v. Lousiana-PacificCorporation, D. Colo., blanket emission limitations and grain loading limits cannot beconsidered as provisions which limit the potential to emit of a process unit. This courtdecision is described by EPA in its June 13, 1989 Guidance on Limiting the Potential toEmit:1

“In United States v. Louisiana-Pacific Corporation, 682 F. Supp. 1122 (D. Colo.Oct. 30, 1987) and 682 F. Supp. 1141 (D. Colo. March 22, 1988), Judge Alfred


Arraj discussed the type of permit restrictions which can be used to limit a source'spotential to emit. The Judge concluded that:

... not all federally enforceable restrictions are properly considered in thecalculation of a source's potential to emit. While restrictions on hours ofoperation and on the amount of materials combusted or produced areproperly included, blanket restrictions on actual emissions are not. (682 F.Supp. at 1133)

The Court held that Louisiana-Pacific's permit conditions which limited carbonmonoxide emissions to 78 tons per year and volatile organic compounds to 101.5tons per year should not be considered in determining "potential to emit" becausethese blanket emission limits did not reflect the type of permit conditions whichrestricted operations or production such as limits on hours of operation, fuelconsumption, or final product.

The Louisiana-Pacific court was guided in its reasoning by the D.C. Circuit'sholding in Alabama Power v. Costle, 636 F. 2d 323 (D.C. Circuit 1979). BeforeAlabama Power, EPA regulations required potential to emit to be calculatedaccording to a source's maximum uncontrolled emissions. In Alabama Power, theD. C. Circuit remanded those regulations to EPA with instructions that the Agencyinclude the effect of in-place control equipment in defining potential to emit. EPAwent beyond the minimum dictates of the D.C. Circuit in promulgating revisedregulations in 1980 to include, in addition to control equipment, any federallyenforceable physical or operational limitation. The Louisiana-Pacific court foundthat blanket limits on emissions did not fit within the concept of proper restrictionson potential to emit as set forth by Alabama Power.

Moreover, Judge Arraj found that:

...a fundamental distinction can be drawn between the federally enforceablelimitations which are expressly included in the definition of potential toemit and (emission) limitations.... Restrictions on hours of operation or onthe amount of material which may be combusted or produced ... are,relatively speaking, much easier to "federally enforce." Compliance withsuch conditions could be easily verified through the testimony of officers,all manner of internal correspondence and accounting, purchasing andproduction records. In contrast, compliance with blanket restrictions onactual emissions would be virtually impossible to verify or enforce.

Thus, Judge Arraj found that blanket emission limits were not enforceable as apractical matter.


The Louisiana-Pacific court was guided in its reasoning by the D.C. Circuit'sholding in Alabama Power v. Costle, 636 F. 2d 323 (D.C. Circuit 1979). BeforeAlabama Power, EPA regulations required potential to emit to be calculatedaccording to a source's maximum uncontrolled emissions. In Alabama Power, theD. C. Circuit remanded those regulations to EPA with instructions that the Agencyinclude the effect of in-place control equipment in defining potential to emit. EPAwent beyond the minimum dictates of the D.C. Circuit in promulgating revisedregulations in 1980 to include, in addition to control equipment, any federallyenforceable physical or operational limitation. The Louisiana-Pacific court foundthat blanket limits on emissions did not fit within the concept of proper restrictionson potential to emit as set forth by Alabama Power.

Moreover, Judge Arraj found that:

...a fundamental distinction can be drawn between the federally enforceablelimitations which are expressly included in the definition of potential toemit and (emission) limitations.... Restrictions on hours of operation or onthe amount of material which may be combusted or produced ... are,relatively speaking, much easier to "federally enforce." Compliance withsuch conditions could be easily verified through the testimony of officers,all manner of internal correspondence and accounting, purchasing andproduction records. In contrast, compliance with blanket restrictions onactual emissions would be virtually impossible to verify or enforce.

Thus, Judge Arraj found that blanket emission limits were not enforceable as apractical matter.” (EPA memo at p 8-10)

A site wide physical limit on ethanol loading or grain received is not necessarily capableof limiting the potential to emit on all of the individual emission units on site. In thepresent case, limiting the amount of ethanol loaded cannot realistically limit the annualpotential to emit of the site natural gas boilers. Such boilers must have physicallimitations that directly address the process equipment in question, such as limitations onthe total amount of natural gas burned in the boiler annually on a rolling 12 monthaverage basis. Most of the emission unit provisions in the draft permit provisions fail toinclude effective physical limitations on the potential to emit of this nature and sufficientto ensure that the facility remains a minor emission source in the aggregate.


2.1.4 Nothing in the Permit Application Submittal, the Draft Permit and the OhioEPA Air Rules Ensures that the Maximum Production Rates Shown in theApplication Actually Reflect the Actual “Maximum Design Capacity” of theEquipment Intended for Site Installation; In the Absence of Such Assurancesand Without Making Such Limitations Enforceable, Ohio EPA’s Acceptanceof the Potential to Emit Portrayed by Applicant Constitutes Error

A programmatic and structural omission in Ohio EPA’s Permit to Install programapplicable to facilities permitted as minor sources and associated defects in the structureof the PTI permit application forms enable PTI Applicants, like Summit Ethanol, toarticulate statements of maximum process production/throughput rates for emission unitsat less than the maximum physical design capacity of the equipment. Ohio EPA relianceon maximum stated process operating rates rather than affirmed maximum physicaldesign rates in emission calculations leads to underestimation of emission unit potential toemit.

Ohio EPA should not rely on a stated process rate as being the maximum rate unless therate is limited by federally enforceable limitations or it is affirmatively declared as aphysical design limitation.

In order to determine whether a new source is a major or minor permit, Ohio EPA Rulesspecify a definition of “Potential to Emit” that tracks the federal definition:

“ "Potential to emit" means the maximum capacity of an emissions unit orstationary source to emit an air pollutant under its physical and operationaldesign. Any physical or operational limitation on the capacity of the emissionsunit or stationary source to emit an air pollutant, including air pollution controlequipment and restrictions on hours of operation or on the type or amount ofmaterial combusted, stored or processed, shall be treated as part of its design if thelimitation or the effect it would have on emissions is federally enforceable orlegally and practicably enforceable by the state. Secondary emissions do not countin determining the potential to emit of a stationary source.” (emphasis added)(OAC 3745-31-01 (UUUU))

Ohio EPA may not rely solely on an “operational design” as a stated maximum rate underthe potential to emit definition.

While a Permit to Install application for a major stationary source in an attainment areamust submit information on maximum design capacity of emission units pursuant to OAC3745-31-12 (A), (B) and (C)(1), this rule requirement does not apply to new minor sourcepermit applications. No other Ohio EPA air rule ensures that maximum productionspecifications for emission units at minor sources are actually the maximum physical design capacity instead of a stated maximum operational design rate (set by the applicantat less than the physical design rate).


Ohio EPA’s “Emissions Activity Category Form(s)” do not ensure that maximum designcapacity of process equipment is provided. The forms generally contain a titleddisclosure for “maximum production” under hourly and annual averaging times. “Maximum production” does not mean “maximum physical design capacity” within themeaning of a physical design limitation on the maximum production rate in the Potentialto Emit definition. A source is free to specify the setting of a maximum operationaldesign process operating rate on such forms.

Nothing in the “Specific Instructions” that Ohio EPA provides for the “EmissionsActivity Category Form(s)” requires in a controlling manner that “maximum production”is to be defined and stated as the maximum physical design capacity. Instructions #4 and#5 for filling out the General Process Operation Emissions Activity Category Form, forexample, say:

“State the average and maximum hourly production rates of the processoperation.....’Maximum’ is defined as the operation’s highest attainable productionrate. This often is identified by the manufacturer as the “maximum designcapacity” for equipment.” (instruction #4)

“State the projected annual production and indicate the appropriateunits.....’Maximum’ is defined as the operations (sic) highest attainable productionrate. This often is identified by the manufacturer as the “maximum designcapacity” for equipment.” (instruction #5)

“Attainable” does not necessarily mean physically attainable. These instructions do notrequire, in a clear and unequivocal manner, that “maximum production” be considered asa rate which is the maximum possible under the physical design of the equipment.

In several places in the Summit Ethanol application and draft permit, Ohio EPA relies onthe maximum production rate specification in the Emission Activity Category Forms ormaximum “stack flow rates at maximum capacity” submitted by Applicant to concludethat maximum unit emissions have been considered. For example, for several of thefabric filter controlled material processing units Ohio EPA concludes on the basis ofmaximum flow rates indicated that, if the grain loading rate is maintained, the facility willbe in compliance with its annual emission limitations. Here is one example out of manyin the draft permit:

“Applicable Compliance Method: Compliance with the annual allowable PM10emission limitation shall be demonstrated using the following calculation based onthe bag house design and a maximum operating schedule of 8760 hrs/yr: = 0.004gr/dscf x 1 lb/7000 gr x 2,500 cfm x 60 min/hour x 8760 hours/yr x 0.0005 ton/lb= 0.38 tons/year


Therefore, as long as compliance with the 0.04 (sic) gr/dscf is maintained,compliance with the annual PM10 limitation shall be ensured.” (ConditionP001:II.E.2.b)

In the absence of federally enforceable physical process limitations on the potential toemit, the Ohio EPA reliance on the stated maximum process rates is misplaced becausethere are no assurances that these rates actually reflect maximum physical design capacityor an federally enforceable limitation that ensures the operational physical process ratewill be less than the maximum physical design capacity. Such misguided Ohio EPAreliance is an artifact of the failure of Ohio EPA to ensure by rule, application forms andby application instruction that information contained in an application for a minor sourcePermit to Install reflects design rather than Applicant-set process operational limitations.

Because mass rate emission limitations and grain loading stack gas concentrations do notlimit the potential to emit under the Clean Air Act, and because of the failure of OhioEPA to incorporate the enforceable physical limitations on the potential to emit notedabove, there can be no clear assurances the draft permit will assure compliance with bothemission unit specific limitations and with the overall major stationary source thresholds.

Given the Applicant’s admissions that other plants it has designed or managed are nowoperating at production rates above their overall nameplate capacities, such failures toassure compliance at this facility can lead to undetected violations of federal and stateClean Air Act requirements.

2.2 Applicant Has Not Provided a Best Available Technology Demonstration forAll Emission Units in Violation of the Present Federally Approved Ohio StateImplementation Plan for New Source Review

The draft permit contains several provisions stating that a particular emission unit is notsubject to a requirement for Best Available Technology (BAT) under the Ohio airregulations; see, for example, the following examples in the draft permit which areillustrative but not exhaustive of such provisions excusing emission units from the BATrequirement:

“Permit to Install 03-17156 for this air contaminant source takes into account thevoluntary restrictions of 1.20 lbs PM10/hr and 5.26 tons PM10/yr as proposed bythe permittee for the purpose of avoiding Best Available Technology (BAT)requirements under OAC rule 3745-31-05(A)(3).” (Condition P011:II.A.2.a)

“Pursuant to ORC 3704.03(T)(4), the Best Available Technology (BAT)requirements under OAC rule 3745-31-05(A)(3) do not apply to the uncontrolledparticulate matter less than 10 microns in diameter (PM10), VOC and SO2emissions from this air contaminant source since the potentials to emit (PTE) for


2 Approved as part of the Ohio State Implementation Plan, 68 FR 2909

PM10, VOC and SO2 is each less than ten tons per year.” (ConditionB001:II.A.2.h)

“This emissions unit potential to emit for SO2* is less than 10 tons per year. Therefore, pursuant to ORC 3704.03(T)(4), OAC rule 3745-31-05(A)(3) is notapplicable.” (Condition P007:II.A.2.e)

“The Best Available Technology (BAT) requirements under OAC rule 3745-31-05(A)(3) do not apply to the PE, PE equal to or less than 10 microns in size(PM10) and sulfur dioxide (SO2) emissions from this air contaminant source sincethe calculated annual emission rate for PE, PM10 and SO2 emissions is less than ten tons per year taking into account the federally enforceable restriction on thehours of operation under OAC rule 3745-31-05(C). (Condition P012:II.A.2.a)

The current, federally-approved Ohio State Implementation Plan provides:

(A) The director shall issue a permit to install or plan approval, on the basis of theinformation appearing in the application, or information gathered by or furnishedto the Ohio environmental protection agency, or both, if he determines that theinstallation or modification and operation of the air contaminant source, solidwaste disposal facility, infectious waste treatment facility, water pollution source,disposal system, land application of sludge, or public water system will......

(2) Not result in a violation of any applicable laws......

(3) Employ the best available technology, except when the onlyrequirement to obtain a permit to install is due to a modification asdescribed in rule 3745-31-01 and paragraph (A)(2) of rule 3745-31-02 ofthe Administrative Code. (OAC 3745-31-05(A)(2) & (3), as previouslyEPA approved)2

The currently approved Ohio SIP defines Best Available Technology in the followingmanner:

(N) "Best available technology" means any combination of work practices, rawmaterial specifications, throughput limitations, source design characteristics, anevaluation of the annualized cost per ton of air pollutant removed, and air pollutioncontrol devices that have been previously demonstrated to the director ofenvironmental protection to operate satisfactorily in this state or other states with


3 ibid

similar air quality on substantially similar air pollution sources. (OAC 3745-31-01(N))3

Although the Ohio Legislature enacted amendments to the BAT requirements at ORC3704.03(T)(4) providing for a ten ton cutoff for the requirement, this change has not beenincorporated into the federally enforceable Ohio State Implementation Plan under theClean Air Act. Changes to the Ohio SIP are only effective after approval by the EPAAdministrator pursuant to 40 C.F.R. §51.105. The present Ohio SIP, which is federallyenforceable, remains in effect without a ten ton/year threshold and with a requirement forBest Available Technology implementation by permit requirement for all of the emissionunits at the proposed Summit Ethanol plant. In issuing a new source review permit, OhioEPA must comply with this current federally approved Ohio SIP requirement pursuant to42 U.S.C. §7410(a)(2)(C). Issuance of a permit that impermissibly violated thisrequirement of the of the Ohio SIP and the Act constitutes backsliding prohibited under42 U.S.C. §7410(l). In addition, through adoption of OAC 3745-31–1(ZZZZZ)(2)(jj), theOhio Administrative Code explicitly embraces the Federal Clean Air Act as amended,including the authorities cited in this paragraph.

2.3 Applicant Has Not Described All of the Facility Emission Sources in theApplication and Such Application is Not Complete; All VOC-Related ProcessEmission Units Must be Described in the Application and Their Potential toEmit Must be Characterized

2.3.1 Summit Ethanol’s Application Failed to Fully Describe Emission Units andAssociated VOC Emissions from, and Controls on, Process WastewaterTreatment Units, Such as Biomethanators, Commonly Installed at OtherBroin-Constructed Facilities

The Applicant is claiming that most of the contact process wastewater from the plant willbe recycled back into the fermentation process. Although the Applicant has describedhow molecular sieve vacuum regeneration system condensate will be handled, theApplicant has not fully described how thin stillage will be handled and treated and thesubsequent consequences for volatile organic compound emissions and control.

The Applicant admits that process wastewater from fermentation is separated viacentrifuge and then concentrated to syrup through an evaporation process. While thesyrup is mixed with the spent distiller’s grain solids from the centrifuge and subsequentlydried in the DDGS dryers, the application is completely silent on the fate of the gaseousevaporation stream which will contain considerable volatile organic compounds.


No information is provided on the fate of any noncondensible gases and evaporatorcondensate. It is common that such evaporator condensate is heavily contaminated withchemical oxygen demand and that such wastewater requires further treatment before itcan be either discharged or re-used in the fermentation process. Applicant’s submittalmust not be approved unless and until the process fate of both evaporator condensateaqueous organic compounds and non-condensible evaporator gases is identified andquantified in the process. If a biomethanor is to be used for process evaporatorcondensate cleanup, this unit must be listed as a process emission unit and all controldevices for this stream must be identified.

Attachment #6 shows several plants designed by Broin which employ biomethanatortechnology for process wastewater treatment. If this technology is to be employed at theSummit Ethanol plant, such equipment must be properly identified as an emission unit and controlled in any new source review permit issued to the subject facility.

2.3.2 The Applicant Has Not Identified a Number of Other Likely Process EmissionPoints, the Nature of Any VOC Controls Provided and the Quantification ofExpected Emissions from Such Emission Points

The Applicant has identified the batch fermenters, beer well and distillation condensers asprocess emission sources controlled by the wet scrubber/RTO emission control train. However, other likely VOC emission sources are not identified or shown for emissioncontrol and quantification. These would include flash tanks, cook water tanks, pre-fermenter mix tanks, yeast storage vents, hammermill output flow area, whole stillagetank, thin stillage tank, centrate tank, syrup tank, evaporator condensate tank, wet DGSstorage and/or loadout area and interprocess point conveyors for wet and/or hot DGS

Absolute clarity on such miscellaneous emission points is required as to potential VOCsources given the small margin claimed by Applicant and Ohio EPA between the claimedpotential to emit and the 100 ton/year VOC major stationary source threshold.

2.4 The Draft Permit Contains No Requirement for Compliance with NSPS 40C.F.R. Part 60, Subpart A Provisions

Various emission units of Applicant’s proposed facility are subject to federal New SourcePerformance Standards at 40 C.F.R. Part 60. However, a search of the draft permitindicates no references to compliance with the NSPS preamble section, 40 C.F.R. Part 60,Subpart A.

Each emission unit which is subject to a federal New Source Performance Standard mustincorporate a provision which also requires conformance to the NSPS preamble


provision, Subpart A of 40 C.F.R. Part 60 as a federally enforceable applicablerequirement to which the facility is subject..

2.5 Modeling issues

Ohio EPA has a policy concerning a 50% PSD increment consumption level and apparentexemptions from it. In the present case, Ohio EPA has apparently granted an extensionby consideration of Applicant’s submittal, but Ohio EPA has failed to place any basis orfinding in the record as to the reasons and criteria for making such an exemption decision. The draft permit should not be granted unless and until Ohio EPA makes a clear findingon the record why the 50% PSD increment consumption policy should be waived as partof an exemption.

Ohio EPA has also failed to require the Applicant to model non-point source fugitiveemission sources (such as the cooling tower, site roads and process equipment fugitivePM10 emissions). Since such fugitive emission sources do consume increment and EPAhas a policy of limiting such increments, Ohio EPA should have articulate a finding andbasis on the record as to why these fugitive sources should not have been modeled indetermining the ambient increment consumption from the project. This is particularlyimportant since the predicted 24 hour PM10 ambient increment consumption from pointsources alone is close to the 83% criterion that Ohio EPA has established in theirincrement consumption policy.

2.6 Compliance Monitoring and Evaluation for Volatile Organic CompoundEmissions from the RTO, the RTO Bypass and the DDGS Fluidized BedCooler Should Embrace EPA’s Midwest Scaling Protocol for Ethanol Plants;the Draft Permit Should Not Confer Sole Discretion on the Applicant toChose Between EPA Methods 25, 25A and 18 for Evaluation of Compliancewith VOC Emission Limitations and the Major Stationary Source Thresholdfor VOCs With No Adjustment for Variability of These Differing Methods toDetect the Mass Rate Emissions of Oxygenated Volatile Organic Compounds

Draft Permit Conditions P007.II.E.1.c.iv, P007.II.E.1.d, P007.II.E.2.a.iv, P007.II.E.2.c,P008.II.E.1.c.iv, P008.II.E.1.d, P008.II.E.2.a.iv, P009.II.E.1.c.iv, P009.II.E.1.d,P009.II.E.2.a.iv, P010.II.E.1.c.ii and P010.II.E.2.b all contain provisions stating thatApplicant may use EPA stack testing methods...

“.....18, 25 or 25A of 40 CFR Part 60, Appendix A...”(emphasis added)

As a result, these provisions confer upon the Applicant the sole and unfettered discretionto choose between any of these three methods to determine compliance with volatileorganic compound emission limitations. Under these provisions Applicant is free to


directly compare the actual test result from any of the three EPA methods with the VOCemission limitations stated in the permit for compliance determination purposes.

EPA VOC test Method 25 and Method 25A are not alone capable of accuratelydetermining the actual mass rate of the total speciated volatile organic compoundemissions from emission units P007-9 (fermentation and dryer process units) and fromP010 (fluidized bed DDGS cooler). Emissions from these process unit feature a majorityof chemical species which are alcohols, acids, aldehydes, ketones and other oxygenatedorganic chemical compounds.

Emission characterizations and compliance determinations for new source review andPSD threshold applicability purposes must reflect speciated volatile organic compoundemission calculation analysis that takes the full mass of oxygenated VOCs into account inemissions assessment and compliance determination. EPA directives on this matter areclear that use of “as carbon” measurements for purposes of new source review and TitleV applicability and compliance are not permissible:

“For the other regulated pollutants that you listed, with the exception of VOC,calculation of the actual or potential emissions for purposes of NSR and title Vapplicability should follow the EPA principles for developing emission factors,inventories and test methods for the subject pollutant. For VOC emissions,however, it is recognized that the EPA’s test methods do not measure the pollutantmass exactly or only measure a subset of the pollutant mass. Nevertheless, for thepurposes of both NSR and title V applicability, our policy has been that VOCemissions should be calculated as the total mass of VOCs. That is, a value for eachvolatile organic compound known to be emitted should be calculated separatelyand the sum of the individual values should be reported as total VOCs (e.g., 20 tpyof toluene and 26 tpy of methyl ethyl ketone should be calculated separately andthen reported as 46 tpy of VOC). This follows our guidance in the document titled“Procedures for Preparing Emission Factor Documents,” where we indicate thatemission factors for VOCs should be reported “in terms of actual weight of theemitted substance.” Those organic substances which are specifically excludedfrom EPA’s definition of VOC at 40 CFR § 51.100(s), because they have“negligible photochemical reactivity,” should not be included in the total VOCemission calculation for NSR and title V applicability. The document also providesan exception in the case of unknown species by stating that such emissions shouldbe calculated using an “educated guess” or a molecular weight of 44 (for reportingas propane). Where necessary, this procedure should be used to calculateemissions of those volatile organic compounds that cannot otherwise bequantified.”

“It is the EPA’s intent that a consistent approach be taken, wherever possible, toquantify and report pollutant emissions for its various air programs. Thus, themethods described above for quantifying pollutant emissions would also apply to


4 June 5, 2001 letter from John Seitz, Director, EPA Office of Air Quality Planning andStandards, to D. Edward Settle, Manager, Air Quality, ThermoRetec Corporation, Golden, COavailable on EPA’s Region 7 NSR website or from Commentors.

our procedures for such things as NSR netting, emission trading and offsets, aswell as for other SIP-related programs for criteria pollutants.”4

This is clear articulation of EPA policy for new source review air permitting proceedings. As a result, reliance on emission estimation methods reflecting VOCs measured only ascarbon or propane that understate the total mass of VOC species emitted cannot be usedto compare to emission limitations and to evaluate the source status as to the 100tons/year major stationary source threshold. Ohio EPA’s acceptance in the draft permit ofunscaled EPA Method 25/25A compliance determinations on the emission unitsmentioned in this subsection absolutely breaches the required conduct for new sourcereview air quality permitting pursuant to the Clean Air Act.

The draft permit should be amended to specifically cite EPA’s guidance documentconcerning the measurement of volatile organic compounds from ethanol plants entitled“Midwest Scaling Protocol for the Measurement of ‘VOC Mass Emissions’ VOCSampling at Wet and Dry Grain Mills and Ethanol Production Facilities,” August, 2004(See Attachment #7). Permit language should be added to clarify that all Method 25/25Adeterminations should be subject to EPA’s current generic scalar of 2.2, or to beotherwise in compliance with the protocols contained in the Midwest Scaling Protocol. The draft permit should be amended to ensure that the result measured for volatile organiccompound emissions be appropriately scaled if EPA Methods 25/25A are used before theVOC results are compared with the legally enforceable volatile organic compoundemission limitations for the two emission units mentioned in the prior paragraph. Thedraft permit should provide that an EPA Method 18 determination of total VOCsmeasured as specific compounds or a Method 25/25A determination as modified by thescalar factor of 2.2, whichever is larger, can be used to enforce the permit’s volatileorganic compound emission limitations.

In addition, the list of specific compounds for which an EPA Method 18 determinationshould provide analysis should be extended to include all of the following (going beyondthe list presently mentioned in the EPA protocol):

acetaldehyde, acetic acid, ethanol, formaldehyde, formic acid, 2-furaldehyde, methanol, butyric acid, glycerol, pyruvic acid, lactic acid, propionic acid, butanolacrylamide, acrolein, isoamyl alcohol, ethyl acetate, succinic acid, butanediol, isoamyl acetate

Glycerol, in particular, has previously been identified in dryer exhaust emissions as asignificant constituent. Glycerol emissions are a particular product of dryer treatment ofsyrup incorporation with spent, wet distiller’s grains in the elevated temperature


environment of DGS dryers. Other compounds on the list of additional chemical speciesto be considered in Method 18 determinations are known fermentation byproducts and/orproducts of thermal degradation of corn/grain that will likely occur in DGS dryers.

2.7 The Draft Permit Fails to Incorporate Hourly PM-10 Mass Rate Emissionand Potential to Emit Limitations on All Emission Units and Thus Fails toEnsure that Short Term Prevention of Significant Deterioration Limits areMet

The following relevant emission units in the draft permit contain no hourly mass rateemission limitations and short term limitation on physical production rate or processfeedstock rates: P001, P002, P003, P004, P005, P006, P010, P012, P901 and P902.

In the absence of both hourly mass rate PM10 emission limitations and hourly short termphysical limitations on production and/or process rates, there can be no assurance thatthese emission units are limited in their potential to emit. While the dispersion modelingstudy assumed most of these emission units had gram/sec emission rates calculated on thebasis of the annual permissible emissions in tons per year, such a procedure alone cannotensure that the gram/second rate will not exceed the assumptions made in the modelingstudy. The gram/second rate used for modeling must conform to the maximum shortterm potential to emit under 40 C.F.R. Part 51, Appendix W, Guideline on Air QualityModels.

Because there are no enforceable hourly emission rates and no enforceable physicallimitations on the potential to emit for the listed emission units, there can be no assurancethat the facility will meet the assumed gram/second rates in the modeling study. Sincethe assumed gram/second rates for PM10 emissions from the listed emission units cannotbe assured, there are no clear assurances that the subject facility will meet Ohio SIPlimitations and/or Ohio EPA policies limiting Prevention of Significant Deteriorationincrement consumption from Summit Ethanol as a single source (i.e. the 83% maximumincrement consumption policy).

2.8 Section II - Table 7-A Stack Egress Point Information Conflicts with EmissionCalculations as to Volumetric Discharge Characterization

Section II - Table 7-A of the permit application lists the maximum stack flow rate atmaximum capacity as “ACFM” or actual cubic feet per minute. The absolute numericmagnitude of the same volumetric discharge flow rate numbers that appear in Table 7-Aalso appear in the Appendix B emission calculation section, but in this location thevolumetric flows are shown as “dscfm” or dry standard cubic feet per minute. Actualcubic feet per minute will not be the same as dry standard cubic feet per minute unless theactual conditions are dry and under standard conditions.


The application must be clarified before it is approved to ensure that the proper flow ratesare described and used appropriately in emission calculations.

2.9 The Draft Permit Contains Rote “Applicable Compliance Method[s]” WhichFail to Properly Evaluate Whether the Source Meets Emission Limitations

Several permit sections contain “Applicable Compliance Method[s]” which are rotecitation to permit and PTI application assumptions and which do not actually measurecurrent emissions for comparison to emission limitations. The problems are identifiedbelow:

2.9.1 Repeated Citation to an Erroneous Limitation of 0.04 gr/dscf and “cfm”Rather Than “dscfm”

Several of the emission unit sections contain a PM10 “Applicable Compliance Method”determination with the following sentence, identical across several emission units:

“Therefore, as long as compliance with the 0.04 gr/dscf [sic] is maintained,compliance with the annual PM10 limitation shall be ensured.”

The figure of 0.04 gr/dscf repeatedly cited in the sentences in several emission unitsections is erroneous. All such citations in all of the emission unit sections should bechanged to 0.004 gr/dscf.

Each of these sentences also contain a citation to exhaust flow measured as ‘cfm’ ratherthan ‘dscfm’ and each such occurrence must be corrected. Ohio EPA should make aclear finding on whether the subject discharge volumetric rate information are, in fact, dry standard cubic feet per minute or, alternatively, actual cubic feet per minute.

Note, the application itself contains conflicting information on whether design flows aredry standard cubic feet per minute (dscfm) or actual cubic feet per minute (acfm); seeprior subsections for discussion.

2.9.2 Compliance with a Grain Loading Emission Limitation Stated with a SingleSignificant Figure Accuracy Cannot Be Used in Engineering Calculations toProperly Assess Compliance with a Mass Rate Emission Number Stated withMore than One Significant Figure

The draft permit repeatedly applies “Applicable Compliance Method” emissioncalculations such as the one below for emission unit P010:


“= 0.004 gr/dscf x 1 lb/7000 gr x 31,800 cfm* x 60 min/hour x 8760 hours/yr x0.0005 ton/lb = 4.77 tons/year”

This formula purports to determine annual emissions of 4.77 tons per year, accurate tothree significant figures, based on a calculation that must ultimately rely on a grainloading determined with only a single significant figure accuracy basis. As such, theformula violates well known and standard engineering calculation management ofaccuracy in calculated determinations. In a formula to determine emissions, the finalresult of the calculation must not have more significant figures than the least number ofsignificant figures represented as any one operand in the calculation. If a source issubject to an emission limitation stated as “0.004 gr/dscf,” then any resulting mass rateemission calculation must be limited to a single significant figure. Alternatively, thegrain loading emission limitation could be amended to 0.00400 (provided the stack testmethod error would allow such a determination) or the compliance method could bedetermined from hourly mass rate emissions determined during a test and fromcompliance with a new hourly mass rate emissions limitation.

Ohio EPA must amend the permit to either increase the accuracy of determination of allgrain loading limits to a specified accuracy or number of significant figures in the stacktest report, or subject any compliance method emission calculation result to theappropriate rules on the maximum number of significant figures in engineeringcalculations in the final result. This problem occurs for several of the “ApplicableCompliance Method” determinations for several emission units.

In the present example under emission unit P010, the final result would be 5 tons/yearrather than 4.77 tons/year if the only requirement for testing of the grain loading is toconform to only a single digit significance calculation in viewing both the complianceformula and the engineering stack test reporting.

2.10 The Applicant Has Not Considered NOX and Carbon Monoxide Emissionsfrom Space Heating Units

The Applicant can be expected to operate natural gas fired space heating units in thefermentation building and other parts of the facility. Although space heating units mightbe exempted from permit requirements, they must nevertheless be counted towards thetotal of emissions for comparisons with and to the 100 ton/year major stationary sourcethreshold. Applicant must disclose the total emissions associated with such spaceheating units as part of a complete application.


2.11 Compliance Monitoring of Fabric Filter Controlled Emission Units

As presently written, there are no requirements to assure compliance that test ongoingfabric filter performance after a single, initial stack test. Fabric filter controls candeteriorate from wear and aging effects on equipment. There is no way that the singlestack test conducted shortly after the commencement of operations is capable of detectingthe future current performance of the fabric filter emission control units potentially manyyears later. The draft permit should be amended to provide for fabric filter leak detectionmonitoring on all fabric filter controlled emission units.

2.12 The Summit Ethanol Facility Is Actually a Major Stationary Source

Applicant’s facility is subject to a 100 ton/year major stationary source potential to emitthreshold for criteria pollutants. However, the actual potential to emit for the subjectfacility does not comply with this threshold given Applicant’s admitted potential to emitindications as modified by the PTE characterizations contained in this comment. BecauseSummit Ethanol potential to emit exceeds 100 tons for volatile organic compounds at thevery least, the Ohio EPA should not issue the draft permit as proposed as the facility issubject to the Prevention of Significant Deterioration (PSD) Best Available ControlTechnology (BACT) and air quality impact review requirements which have not beensatisfied in the current minor source permit proceeding.

For volatile organic compounds, the failure to recognize fugitive emissions from loadingoperations and the failure to consider other miscellaneous emission units push theproposed facility over the 100 ton VOC limit. Other criteria pollutants may also have potential to emit totals which exceed the 100 ton limit, subject to additional informationdisclosure needs and clarifications.

For particulate matter emissions, the failure to use an appropriate silt loading factor forfugitive road emissions, the failure to properly calculate site VMT for fugitive roademission calculations, the understatement of particulate emissions from the site gas firedboiler operations and the failure to consider that the product loading flare will releasecondensible particulate matter may, in concert, push the subject facility over the 100 tonthreshold for particulate emissions.

3 Discussion of Permit Regulatory Sections and Emission Calculations byIndividual Emission Unit and Process Groupings

Emission unit descriptors as set forth in subsequent sections of this comment refer to thedisposition and meaning of these numbers as they appear in the draft permit as assignedby Ohio EPA and not as depicted in the permit application.


3.1 B001 and B002 – Natural Gas-Fired Boilers #1 and #2

3.1.1 Ohio EPA has Erroneously Depicted the PM/PM10 Potential to Emit forBoilers #1 and #2

Applicant’s Appendix B emission calculations properly determined that PM/PM10emissions from the two 143 MMBTU/hr natural gas fired boilers would be 9.3 tons peryear. This determination was based on the use of an AP-42 emission factor 7.6 lbs oftotal particulate (as both filterable and condensible PM) per million standard cubic feet ofnatural gas burned.

Notwithstanding this correct depiction of the potential to emit for PM/PM10 in theApplicant’s submittal, all aspects of NSR permitting for emission units B001 and B002after this point are in error and must be remedied before the permit can be granted. Thesuccession of errors include the following:

3.1.1.1 By Failing to Incorporate Condensible PM Emissions and Failing toInclude Enforceable Physical Limitations on Natural Gas Fired to theBoilers, Ohio EPA’s Draft Permit Fails to Limit the Potential to Emitof the Two Boiler Units

Conditions B001/B002:II.A.2b of the draft permit indicate:

“The permittee has requested voluntary allowable emission limitations (sic) for PEof 0.27 lbs/hr and 1.18 TPY. The short term (lb/hour) and long-term (tons/year)emission limitations for PE are being established as practically and legallyenforceable requirements representing the potential to emit based on the physicalcapacity of the missions unit and the use of natural gas.”

An emission rate of 0.27 lbs/hr and 1.18 ton/year for particulate emissions from a 143MMBTU/hr boiler is apparently derived from the AP-42 emission factor of 1.9 lbs of PMper million standard cubic feet of natural gas combusted apparently for filterable PMonly. This conclusion is buttressed by the draft Ohio EPA permit when it goes on tospecify in its “applicable compliance method” provision at Condition B001/B002:II.E.3cthat such emission factor be used.

Condition B001/B002:II.E.3c also states that EPA Method 5 for “total filterableparticulate” will be used, if required, to determine compliance with the hourly allowablePE limitation. Nothing in EPA Method 5 requires that condensibles be reflected in thefinal determination and Ohio EPA has not specified EPA Method 201 and 202 forcompliance with the PE emission limitation. In fact, the “total filterable particulate”designation would mitigate against any use of condensible particles in the back half of theMethod 5 sampling train from being reported in the final compliance test.


Merely saying that the emission source will only be accountable for filterable particulateemissions from these two emission units when AP-42 factors indicate that the majority ofPM emissions from natural gas combustion are in condensible form means the draftpermit language inaccurately characterizes potential particulate emissions from thefacility.

3.1.1.2 The Gas Fired Boiler Units at the Subject Facility Cannot Meet theEmission Limits Stated in the Draft Permit

The statement of the particulate emission limitations in Conditions B001/B002:II.A.1 isthat they are stated as “particulate emissions” and are unqualified as being solelyconsidered as filterable emissions. The only way the facility can comply with the draftpermit is to rely on a compliance testing methodology which does not determine the totalparticulate emissions. As such, the emission limitations are not fully enforceable inpractice. Given the AP-42 factor of 7.6 lb of total PM per million scf of natural gascombusted, the source will be unable to actually comply with the emission limitation.

3.1.1.3 Ohio EPA’s Finding that the Potential to Emit for PM10 is 3.5tons/year Per Boiler is in Error

Ohio EPA then goes on to say at Conditions B001/B002:II.A.2h that the potential to emitfor PM-10 is 3.5 tons per year using the AP-42 factor of 5.7 lbs PM10/million scf ofnatural gas. This AP-42 factor is only for the AP-42 factor for condensible PM only. Applicant has admitted that 100% of filterable and condensible emissions from the boilersare PM10 by setting the emission factors for total particulate and PM 10 as equal factors.

Accordingly, Ohio EPA’s finding in the stated conditions as relying on only the AP-42 condensible fraction for boiler natural gas combustion emissions is against the greatweight of evidence. The total potential to emit for Boilers #1 and #2 is properly set at9.3 tons per year for PM10, and not at 7 tons per year as published by Ohio EPA in thedraft permit.

In Ohio EPA’s “Synthetic Minor Determination,” Ohio EPA repeats this same error bydetermining that the TSP emissions for both boilers is 1.13 tons/year and the PM10emissions is 3.5 tons/year for each of the boilers. First, by definition, TSP cannot be lessthan PM10 since PM10 is a subset of total suspended particulate emissions. The“Synthetic Minor Determination” is thus in error on the combined emissions from Boilers#1 and #2 by understating TSP by 7 tons per year and PM10 by 2.3 tons per year.


5 55 Fed. Reg. 12426 (March 17, 1990). See also 55 Fed. Reg. 14246 (April 17, 1990)(“emissions that contribute to ambient PM10 concentrations are the sum of in-stack [non-Condensible] PM10 . . . and Condensible emissions.”); 55 Fed. Reg. 41546 (October 12, 1990)(“Condensible particulate matter (CPM) emissions form very fine particles in the PM10 sizerange and are considered PM10 emissions”); 56 Fed. Reg. 65433 (December 17, 1991) (same).

6 March 31, 1994 letter from Thompson Pace, SO2/Particulate Matter Program Branch,EPA Office of Air Quality Planning and Standards to Sean Fitzsimmons, Iowa Department ofNatural Resources

3.1.1.4 Proper Treatment of Condensible Particulate Matter as a Contributionto Total PM10 and PM Emissions is a Matter of Considerable Federal Regulatory Interest in New Source Review Programs

Commenters remind Ohio EPA that compliance determinations for ensuring that modeledPM10 air quality demonstrations are representative of actual emissions require thatfilterable and condensible PM stack test results must be added together to evaluatecompliance with PM10 emission limitations and this is a matter of considerable federalinterest. In fact, EPA does not approve the approach of setting PM 10 compliance onlyto filterable “front half” PM stack test determinations. EPA has recognized that....

“...condensible emissions are also PM10, and that emissions that contribute toambient PM10 concentrations are the sum of in-stack PM10 and condensibleemissions.”5

Similarly, EPA’s Office of Air Quality Planning and Standards has statedunequivocally that....

“[s]ince CPM is considered PM-10 and, when emitted, can contribute to ambientPM-10 levels, applicants for PSD permits must address CPM if the proposedemission unit is a potential CPM emitter.”6

EPA has repeatedly required permitting authorities to include condensible PM10 limitsand testing methods in permits.

3.1.2 Boiler #1 and #2 NOX and CO Emissions

3.1.2.1 Applicant Has Submitted No Information Showing They Will Be Ableto Comply with the 0.035 lbs NOX Per Million BTU Heat InputEmission Limitation

Applicant’s emission calculations for Boiler #1 and #2 show reliance on a 0.04 lbsNOX/MMBtu “Manufacturer’s Guarantee.” All of Applicant’s emission calculations


relied on this emission factor with a predicted annual emission of 25.1 tons per yearNOW for each natural gas fired boiler. On July 28, 2006, Applicant submitted a newmass emission rate table showing each boiler at 21.9 tons NOX/year, but with nothing toaddress the NOX emission factor.

The Applicant mentioned performance at another facility, but the Applicant neversubmitted any stack test results showing the facility will, in fact, be able to comply withthe 0.035 lb NOX per million BTU limit contained in the draft permit for both boilers atConditions B001/B002:II.A.1. This must be considered a crucial issue since a failure tomeet the 0.035 lb/NOX/MMBtu limit could put the entire facility over the 100 ton NOXPTE threshold for a major stationary source.

3.1.3 The Draft Permit Contains No Enforceable Physical Limitations on thePotential to Emit for Carbon Monoxide, Particulate Matter and NitrogenOxides

The draft permit fails to provide effective physical limitations on the potential to emit forthese natural gas fired boilers. Limitations on the amount of grain received and theamount of ethanol loaded at the facility do not limit the potential to emit for the gas firedboiler emission units. Deterioration of boiler heat transfer surfaces could easily lead toan increase in the amount of natural gas combusted in the unit in order to achieve thesame steam production output. There are no provisions which limit the amount of naturalgas that can be combusted in these boiler units, either on an emission unit-specific or onan overall plant basis. Since there are no ongoing periodic monitoring measures that aresufficient to ensure that the emission units maintain compliance with the numericalannual emission limitations on an ongoing basis, there are no measures to assurecompliance on a continuing basis that carbon monoxide, particulate matter and nitrogenoxides will conform to the stated annual emission limitations.

The draft permit should be amended to provide for annual limitations on a rolling 12month average basis for the amount of natural gas combusted in the B001 and B002natural gas fired emission units.

3.2 F001 – Fugitive Emissions from Site Roads

3.2.1 Applicant Has Understated Fugitive Emissions by Understating VMT fromTransport of Dried Distiller Grains

In its July 2, 2006 letter from ENSR, Applicant stated that the annual load out of DDGSwas 201,480 tons per year. However, Applicant’s potential to emit vehicle milestraveled calculation in support of the site road fugitive dust emission characterizationshows DDGS haul out at 25 tons/truck and 7,008 trucks per year. That would only


account for 175,200 tons per year of DDGS. At 25 tons DDGS per truck, 201480 tons ofDDGS would require 8059 trucks per year or 7092 VMT per year for DDGS loads ratherthan the 6,167 VMT/year indicated. As such, the total site VMT increases from 41,566to 42,491 VMT/year.

As such, the Applicant will not be able to comply with the calculated 14.96 tons PM/yearemission limitation in the draft permit as expected annual emissions calculated on a PTEbasis would be at least 15.3 tons of PM/year.

3.2.2 Applicant Has Underestimated Particulate Emissions from Site Roadways byUsing an Unrealistic Silt Loading Factor Not Supported by AP-42 Factorsand Not Typical of Agricultural Commodity-Related Industrial FacilityRoads as Demonstrated by the Experience of Other States

3.2.2.1 Applicant’s should at least use a 0.6 g/M2 or Higher Silt Loading Factorfor Ubiquitous Low Traffic Public Paved Roads

Applicant has proposed and Ohio EPA has apparently accepted use of a silt loading factorof 0.4 g/M2 in arriving at an emissions estimate of 14.96 tons of total suspendedparticulate (TSP) per year. Applicant’s claim of a silt loading factor of 0.4 g/M2 forApplicant’s industrial road is significantly less than all of the means for AP-42 siltloading on industrial roads in other industry sectors. Applicant’s claim of 0.4 g/M2siltloading on a non-public industrial road is unconvincingly less than the “ubiquitousbaseline” of 0.6 g/M2 cited by AP-42 for public roads with less than 500 ADT (this factoris also subject to multipliers based on antiskid treatments in the winter).

Calculation of Applicant’s fugitive road dust emissions using 0.6 g/M2 with all otherfactors being the same would yield expected particulate emissions of 20.0 tons per year,or an additional 5 tons per year of total suspended solids. As a result, the “syntheticminor determination” and the draft permit emission limitations must be revised toincorporate this minimum level of a more realistic silt loading rate of 0.6 g/M2.

3.2.2.2 Applicant’s 0.4 g/M2 Silt Loading Factor is Not Supported by ActualIndustry Experience, Accepted Permitting Practices and the CommonPractices of Other Nearby State Jurisdictions

A review of actual industry data of silt loading factors and permitting practices of othernearby states involving silt loading factors is reviewed in the table below:


Case Description of Cited Information Silt LoadingFactor Cited(g/M2)

Seeattach-ment forfurtherinfo

MN-1 Measured silt factor at a cereal production facility – Malt-O-Meal cited at air modeling training

0.5 1

MN-2 Measured silt factor in summer at ethanol plant – ChippewaValley- Benson

0.6 1

MN-3 Measured silt factor in summer at ethanol plant – ADMMarshall, Year 2001 (no cleaning)

0.76 to 2.93 1

MN-4 Measured silt factor in summer at ethanol plant – ADMMarshall, Year 2003 (with cleaning)

0.7 to 0.72 1

MN-5 MPCA Policy - do extensive on-site testing/cleaning, or useAP-42 industrial road values

7.4+ forindustrial roads

1

NE-6 Nebraska PSD permit for Archer Daniels Midland Company- Columbus, NE

3.0 - uncontrolled1.26 -controlledpermit limit

2

NE-7 Nebraska PSD permit for Cargill, with actual silt loadingvalues tested by Cargill-MCP

0.92 3

IN-8 Indiana minor source permitting practice for AndersonClymer and ASA Linden, LLC, with factor taken from AP-42 public road “ubiquitous baseline”

0.6 4

Actual test values at shown in the table indicate that a 0.4 g/M2 silt loading factor used foremission characterization of the subject facility is too low to reflect loadings actuallyachieved in practice by the selection of ethanol or agricultural commodity facilities.

In particular, when prevention of significant deterioration reviews of fugitive emissionsfrom roads assume higher silt loading assumptions at other facilities, the Applicant andOhio EPA cannot maintain that the failure in the present case to require any kind ofverification or numerical certainty for road fugitive emission controls can achieve lowersilt loading assumptions.


3.2.2.3 Nothing in the Draft Permit Requires a Determinant Amount ofFugitive Road Dust Control That Can Be Assured of Achieving theClaimed Low Particulate Emissions

The draft permit contains no measures which will actually assure compliance with the 0.4g/M2 silt loading parameter and with the specified annual emission limitation forparticulate emissions from site roads. There are no firm requirements for periodicsweeping and cleaning that would allow such a level of silt loading performance to beachieved. Mere reliance on a future plan and Applicant-discretionary levels of stringencyin road dust control which are not enforceable limitations in practice and the draft permitprovisions cannot ensure compliance with the claimed annual emission limitation.

At a minimum, any permit based on such a low level of silt loading, if it is ultimatelyallowed, should contain a permit provision actually requiring this silt loading level to beactually achieved in practice and to be continually maintained through quarterly testingrequirements, recordkeeping and reporting. No such measures are presently in the draftpermit. Because such measures would constitute BAT, the Application’s failure torequire accountability for such measures means that BAT has not been incorporated forthe road dust emission unit, notwithstanding the stringent assumed level of silt loadingcontrol to 0.4 grams/square meter.

Under the present circumstances with the content of the submitted application, the permitshould not issue because of failure to properly characterize the fugitive road dustemissions from the facility.

3.3 J001 – Ethanol and Gasoline Loading Operations

3.3.1 Ohio EPA’s Synthetic Minor Determination Doesn’t Contain the CorrectTotal VOC Emissions from this Emissions Unit; Ohio EPA Did Not Use theApplicant’s Emission Characterization in Either the Synthetic MinorDetermination, Nor The Draft Permit

Volatile organic compound emissions listed for emission unit J001 are shown as 0.45 tonper year in the Ohio EPA “Synthetic Minor Determination.” The records does notindicate any derivation of the 0.45 ton/year emission number listed.

The draft permit itself contains an emission specification of 2.07 tons of VOC per yearfrom emission unit J001. However, this emission listed in the permit is less thanApplicant’s emission characterization submitted on July 28, 2006 as 3.87 tons per year. Applicant previously submitted a worst case emissions characterization from 100% truckloadout of product denatured ethanol of 2.48 tons per year. Since Applicant hassubmitted two emission characterizations that exceed the emission limitations in the draftpermit, Applicant will be unable to comply with the Ohio EPA permit if it is issued


7 EPA AP-42 Emission Factors for Transportation and Marketing of Petroleum Liquids,Section 5.2.2.1.1. Loading Losses, Page 5.2-6

without revision. In addition, both of the most recent Applicant J001 emission unit characterizations exceed the 0.45 ton VOC/year emission number in the “Synthetic MinorDetermination.”

3.3.2 Applicant and Ohio EPA Have Failed to Properly Characterize FugitiveVolatile Organic Compound and Hazardous Air Pollutant Emissions FromEmission Unit J001 Loading Operations

Neither the Applicant nor Ohio EPA have properly characterized all volatile organiccompound and hazardous air pollutant emissions from product loading operations atemission unit J001. Specifically, the emission characterization fails to consider fugitiveemissions that will occur under the emission estimation procedure indicated at AP-42 -Section 5.2 for “Transportation and Marketing of Petroleum Liquids.” The relevant AP-42 section states:

“The overall reduction efficiency should account for the capture efficiency of thecollection system as well as both the control efficiency and any downtime of thecontrol device. Measures to reduce loading emissions include selection ofalternate loading methods and application of vapor recovery equipment. .........However, only 70-90 percent of the displaced vapors reach the control device,because of leakage from both the tank truck and collection system. The collectionefficiency should be assumed to be 90 percent for tanker trucks required to passan annual leak test. Otherwise, 70 percent should be assumed.”7 (emphasisadded)

All of Applicant’s and Ohio EPA’s attempts to characterize emissions from the J001emission unit loading operations have effectively assumed 100% capture efficiency whenthere is no basis in the draft permit and the application to make such an assumption or toassume that such a 100% capture efficiency will be achieved in practice. There isn’teven a requirement to ensure that tank trucks have passed an annual leak test, as per theAP-42 emission factor characterization discussion.

Applicant admits that the uncontrolled potential to emit with 100% truck loadout ofdenatured ethanol in trucks which have previously hauled gasoline is 124.1 tons per year. Since there are no restrictions in the permit to limit the number and type of such vehiclesfor loading operation, this is a valid uncontrolled potential to emit. Because nothing inthe permit holds the Applicant responsible for not loading any tank truck unless it haspassed an annual leakage test, the AP-42 - Section 5.2 emission determination shouldincorporate an assumption of a 70% capture rate. This means that fugitive VOCemissions calculated on the basis of potential to emit would be 37.2 tons per year. If a


8 See Condition J001:II..A.2.a

9 See Condition J001:II.B.1

90% capture efficiency is assumed, the fugitive VOC emissions from loading operationswould be 12.4 tons per year. Both of these additional fugitive VOC emission numberswould put Applicant’s proposed facility over the 100 ton VOC major stationary sourcethreshold. Applicant/Ohio EPA similarly underestimated HAP emissions by failing toaccount for fugitive emissions from loading operations.

3.3.3 Ohio EPA’s Volatile Organic Compound Potential to Emit Determination ofPoint Source J001 Loading Emissions Is Subject to Significant Question

According to Ohio EPA, the draft permit states:

“The PTE for VOC of 2.07 TPY (for this emissions unit) was calculated bymultiplying the emission factors of 0.463 lb VOC/1000 gallon of ethanol and4.375 lbs VOC/thousand gallon of gasoline [as determined through themethodology in AP-42, section 5.2.2 (1/95) in conjunction with the informationsubmitted by the permittee in PTI application #03-17156] by the maximum annualthroughout of 69 million gallons and 40 million gallons, respectively, and by acontrol factor of (1-0.98*), and then dividing by 2000 pounds/ton.

* the control efficiency for the flare is assumed to be a minimum of 98%.”8

“The maximum annual ethanol throughput rate for this emissions unit shall notexceed 69 million gallons. The maximum annual gasoline throughput rate for thisemissions unit shall not exceed 40 million gallons.”9

There is no physical basis for the subject process equipment and inherent process forconsidering that gasoline throughput would be as much as anything approaching 40million gallons. Applicant’s T003 and T004 denatured ethanol tank emissioncharacterization is modeled on the basis of 95% ethanol on a liquid mass fraction basis. For a 69 million gallon denatured ethanol production facility, gasoline throughput shouldnot exceed 3.45 million gallons per year. Ohio EPA’s 40 million gallon processthroughput limit is an unacceptable provision for federal enforceability to limit thepotential to emit from the product loading operation. The 40 million gallon gasolineprocess parameter is also not an appropriate basis on which to make an emissiondetermination.


3.3.4 Applicant Has Failed to Properly Characterize Particulate Emissions fromthe Flare to Control Loading Operations

While saying that the flare should be of “smokeless” design, such a design should notexcuse Applicant from characterizing the particulate emissions from such a flare. Applicant has assumed zero flare particle emissions. Most of the emissions would beexpected to be condensible particulate emissions. At a minimum, Applicant should haveattempted to quantify flare particulate emissions using emission factors for condensibleparticles from natural gas combustion. There is no reason to believe that combustion ofgasoline vapors and ethanol would produce less particulate matter than consumption ofnatural gas, which is primarily methane, on lb PM per MMBTU basis.

3.3.5 Ohio EPA’s “Synthetic Minor Determination” Contains the Wrong VOCEmission Number for J001 Loading Operations

Ohio EPA’s Synthetic Minor Determination shows 0.45 tons per year for flare-relatedcontrolled emissions (not considering the fugitive emissions which were neglected byOhio EPA as well as Applicant). However, Applicant submitted an emission table late inthe process showing 3.87 tons per year of VOC. A prior determination assumed 2.48 tonsper year. Nothing in the file demonstrates the basis of the 0.45 ton per year figure usedby Ohio EPA.

3.4 P007-P009 – Ethanol Production, Dryer Operation and Scrubber/ThermalOxidizer Controls

3.4.1 The Applicant Has Not Incorporated a Ohio Best Available Technology(BAT) Determination and a BAT Level of Control for the Dryer Burner NOXEmissions

The Applicant failed to include an Ohio Best Available Technology determination forNOX emissions from the dryer burner units. Nothing in the application submittals orsubsequently submitted documents provides such a OH BAT determination.

Applicant used a stack test to set a 0.0817 lbs NOX/MMBTU emission level for the dryerunits for purposes of emission calculation. However, off-the-shelf low NOX and/or ultralow NOX burner technology should be capable of achieving NOX emissions at and below0.04 lbs NOX/MMBTU. Nothing submitted by Applicant addresses this discrepancy. Because the level of emissions for the dryer burners exceeds an emission factor whichwould reflect a BAT level of NOX emission control, the subject facility has failed toincorporate BAT for the two dryer emission units.


3.4.2 VOC Emission Characterization of Uncontrolled Dryer Emissions Fails toConsider Thermal Decomposition of Spent Distiller’s Grain and MultipleVolatile Chemical Compounds Found in Wet Grain Residuals and ThusUnderstates Potential VOC Emissions from the Regenerative ThermalOxidizer Stack

Applicant’s emission calculations for uncontrolled dryer volatile organic compoundemissions cannot be considered realistic for two reasons. First, Applicant attempts tosolely ascribe the uncontrolled VOC emissions of the dryers to ethanol and acetaldehydefound in the aqueous liquor contained in wet spent distiller’s grain. Applicant’s VOCemission characterization for these two compounds occupies the entire field ofApplicant’s claim of the uncontrolled dryer VOC emission rate. This means thatApplicant is essentially claiming that there will be no uncontrolled VOCs associated withthermal decomposition of spent distiller’s grains in the latter stages of the drying processand evaporation of volatile compounds found in process waste “syrup” that is mixed withspent distiller’s grain..

Second, stack tests on dryer emissions in the industry show that ethanol is not thepredominate volatile organic species in dryer emissions. Rather, glycerol and acetic acid frequently constitute the primary VOC chemical species that are emitted from bothcontrolled and uncontrolled dryer emissions. Glycerol (CH2OHCHOHCH2OH ), inparticular, is a compound that is left over from the fermentation process and is not a likelycombustion product of incomplete combustion. Applicant’s method of determination ofuncontrolled VOC emissions from dryers by examining the products of aqueouscompounds cannot be considered complete if all such compounds are not examined fortheir potential release in heated dryer systems from liquids and “syrup” associated withwet spent distiller’s grains introduced into dryer systems. Applicant’s methods ofuncontrolled dryer VOC emissions characterization cannot pass muster on this basis.

3.4.3 Applicant Has Failed to Justify or Document the Uncontrolled Dryer PMEmission Rate

The Applicant asserted a 0.135 grain per dry standard cubic foot uncontrolled PMemission rate for the dryer exhaust but failed to provide any basis, such as a stack testresult for this rate.

Moreover, there is no information on whether this is for filterable PM or filterable pluscondensible PM.

Without such information, there is no certainty that the subject facility will be able tocomply with the emission limitation stated in the proposed permit and with the majorstationary source threshold of 100 tons per year for particulate matter.


3.4.4 Dryer Sulfur Dioxide Emissions

The projection of uncontrolled sulfur dioxide emissions from the dryer are very low andreflect on natural gas combustion factors. However, it is common in ethanol plants to usesulfuric acid for pH control and balance. Sulfates entering the dryer create additionalpotential for sulfur dioxide emissions and this was not properly considered by theApplicant’s emission characterization.

3.4.5 Issues Arising From Conditional Applicability of Emission Limitations to“Normal Operation” of the Regenerative Thermal Oxidizer (RTO), theMatter of Scheduled and Unscheduled Maintenance and Other Outages of theRTO, and Consequences of Such Conditional Applicability and Outages forSite Emission Units, Summit Ethanol’s Potential to Emit and Clean Air ActCompliance

3.4.5.1 The Draft Permit is Not Clearly Written to Require That Hours ofRegenerative Thermal Oxidizer Outages From Scheduled MaintenanceAccumulate to and are Limited by the 500 Hour Provision; the 500Hour Provision Should Be Amended to Embrace Rolling 12 MonthAverage Compliance Measurement, Recordkeeping and Reporting

The Applicant’s emission characterization accounts for bypass emissions from thefermentations and distillation operations during up to 500 hours of regenerative thermaloxidizer outages from “unscheduled maintenance or other operational reasons.” Theseemission calculations assume that there are zero emissions from the dryers during theRTO outages because the dryers will be shut down. No information is provided on howquickly the dryers can be shut down consistent with safe operating procedures and whatemissions will occur during such dryer shutdowns following commencement of a RTOoutage. Applicant has failed to provide any VOC emission estimate associated with wetDGS handling, storage and loadout that would necessarily occur during continuedfermentation and distillation operation while the RTO was down.

All of the limitation language relating to “Emission limits during unscheduled downtimeof the RTO” is written to only address “unscheduled” RTO outages. This raises the verysubstantial question of emissions associated with “scheduled” RTO outages which can bedistinguished from “unscheduled maintenance or other operational reasons” which is notdefined by the permit. As presently written, the permit does not provide that scheduledmaintenance RTO outage downtime accumulates to the total 500 hour limitation and is, infact, limited by the 500 hour per year provision.


The 500 hour per year provision itself and its reporting and recordkeeping provisions arenot written to require compliance review on a rolling 12 month average basis and thedraft permit should be re-written to embrace such a rolling 12 month average basis.

3.4.5.2 Given the Failure to Account for Schedule Regenerative ThermalOxidizer (RTO) Downtime in Permit Provision Limitations, ApplicantHas Failed to Properly Quantify Potential to Emit Emissions of VOC,CO and PM During Times of Scheduled RTO Maintenance Outages

While Applicant and Ohio EPA have accounted for bypass emissions during RTOoutages from “unscheduled maintenance or other operational reasons,” both Applicantand Ohio EPA have failed to show potential to emit emissions from the dryer processexhaust during times of schedule maintenance outages of the RTO. The draft permitprovisions dealing with RTO outages are not clearly written to prohibit such uncontrolleddryer emissions. As a result, such emissions should have been accounted for in permit toinstall calculations, unless Ohio EPA is willing to amend its permit to address this issueby specifically prohibiting dryer operation during scheduled RTO outages.

Aspects of the current draft permit are highly misleading on the matter of sourceconfiguration during RTO outages and subsequent emissions.

Although Condition P007:II.A.1 provides...

“During unscheduled downtime of the RTO, emissions unit P007 shall be the onlyemissions unit exhausted to the fermentation scrubber.”

....this provision can hardly be considered protective during RTO outages since dryerprocess units P008 and P009 never exhaust to the fermentation scrubber inlet anywayduring normal operations. Process gas from the dryers is fed to the thermal oxidizerdownstream from the fermentation scrubber exit and not at its inlet.

Nothing in Condition P007:II.A.2.c requires shutdown of the two dryers during scheduledmaintenance RTO outages. Nothing in the permit defines what “unscheduledmaintenance or other operational reasons” and “unscheduled down time of the RTO”actually mean and their relationship to scheduled maintenance of the RTO. Since nothingin the permit defined the meaning of these phrases, Commenters can only conclude thatsuch treatment is wholly vested in the unfettered discretion of the permittee. If the RTOwas subject to a catastrophic failure and could not be operated for several months as amatter of expectation, it appears nothing in the permit prevents Applicant from self-defining facility operation during a months-long RTO outage as being scheduledmaintenance in light of changed circumstances with subsequent uncontrolled dryeroperation being in compliance with the permit and unaffected by the emission limitationsthat only apply during RTO operation.


Conditions P008:II.B.2 and P009:II.B.2 are identical and provide for the following:

“The permittee shall shutdown this emissions unit and emissions unit P009 whenthe RTO experiences an unscheduled shutdown.”

The condition in the P009 section should have referred to P008 and is erroneous aspublished. More importantly, however, is the fact that this provision does nothing toprohibit continued dryer operation during scheduled maintenance RTO outages. Monitoring Conditions P007:II.C.3, P008:II.C.3 and P009:II.C.3 all explicitlycontemplate the possibility of site operation of the dryer units at times when the RTO isshutdown, giving credence to a de facto, but unrecognized third process operationalscenario of continued dryer operation during RTO outages during scheduled maintenanceor other operations without such conditions being subject to any time constraint andwithout the permittee being responsible for compliance with the need to stay under the major stationary source threshold for the facility.

Nothing at all in the permit application addresses the expected number of scheduledmaintenance outages of the RTO. With no information in the application about expectedannual scheduled maintenance outage intervals, there is no basis for rendering a potentialto emit estimate during such uncontrolled dryer emissions and the application must berejected as incomplete.

At 265 lbs per hour of uncontrolled volatile organic compounds, emissions from thedryers will be very substantial during RTO scheduled maintenance outages as a mode ofoperation. Just 15 hours of uncontrolled dryer VOC emissions during RTO outages fromscheduled maintenance will put the entire facility over the 100 ton potential to emitlimitation. Because no information has been provided on expected RTO scheduledmaintenance times and the potential to emit from allowable dryer emissions during thesetimes, the PTI application must be considered incomplete and unapprovable.

3.4.5.3 As Presently Stated, the Draft Permit Emission Limitations forEmission Units P007, P008 and P009 Destroy the Effectiveness of theStated Emission Limitations in Violation of EPA’s ContinuousCompliance Policy and the Federal Clean Air Act

The following language in the table of “Applicable Emissions Limitations/ControlMeasures” at Conditions P007.II.A.1, P008:II.A.1 and P009:II.A.1 is noted:

“Emission limits during normal operation:

Normal operation is defined as periods when the regenerative thermal oxidizer(RTO) is in operation and providing air pollution control to emissions uni P007,P008 and P009.”


Because non-operation of the regenerative thermal oxidizer is not “normal operation” asdefined by Conditions P007.II.1.A, P008.II.1.A and P009:II.1 table emission limitations, the draft permit as presently written allows virtually unrestrained operations andemissions during RTO outages.

The effect of the conditional language placed on the emission limitations for “normaloperation” only is to completely remove the enforceability and effectiveness of the P007,P008 and P009 emission limitations in the table during all RTO outages, both“unscheduled,” scheduled and from “other operational reasons” with no distinctions madebetween any such conditions. Such a permit provision violates 42 U.S.C. §7410(j)calling for assurances that the technological system of continuous emission reduction willenable the source to comply with permit limitations and other provisions of the Act. Emission limitations which disappear under a condition when emission control equipmentis not operational are a form of “automatic exemption” of emission limitations whichviolate long-standing EPA policies and requirements in the administration of the CleanAir Act and development of State Implementation Plans. The permit under presentdiscussion is a prospective part of the Ohio State Implementation Plan and must besubject to federal enforceability requirements. Under the present conditional languagefor emission limitations under “normal operation,” all of the practical enforceability of theRTO emission limitations is removed during all RTO non-operation, from whatevercause.

3.4.6 The Draft Permit Fails to Limit the NOX, VOC, Carbon Monoxide andParticulate Matter Potential to Emit for Emission Units P007, P008 and P009

There are no effective physical limitations on the potential to emit at the emission unitlevel for NOX, volatile organic compounds, carbon monoxide and particulate matteremissions from Emission Units P007, P008 and P009. There is no limitation on theamount of wet DGS charged to dryers or the DGS production rate from the dryers. Thereis no annual rolling average limitation on the amount of natural gas combusted in thedryers and the thermal oxidizer that would limit the potential to emit. ConditionP007:II.A.2.b cannot be construed as a legally enforceable condition limiting the annualproduction of denatured ethanol to 69,000,000 gallons.

3.4.7 The Draft Permit Fails to Require Assurances of Continuous Compliancewith NOX and Carbon Monoxide Emission Limitations; the Draft PermitShould Be Amended to Incorporate Both NOX and Carbon MonoxideContinuous Emission Monitoring

As written, the draft permit does not contain adequate provisions to assure compliancewith emission limitations for P007, P008 and P009 during times when a stack test is notbeing conducted. The “Applicable Compliance Methods” shown are ineffective at


determining emissions and assuring compliance on a continuous basis since they whollyrely on results from a single compliance test conducted within 180 days of the originalcommencement of source operation. Reliance on distant past measures of performancecannot reflect the current state of emission control efficiency and process operations. Ata very minimum, the draft permit should be amended to include an annual requirement todemonstrate compliance with emission limitations using the EPA stack testing methodsspecified. But even adding an annual stack test requirement does not provide adequatemeasures to assure compliance since none of the calculations depend on present/recentperformance indicators.

3.4.7.1 Issues of NOX Compliance Assurance

NOX emissions under the draft permit and with the configuration of equipment for P007,P008 and P009 come from 3 different combustion units discharging to a common stackand subject to two different design standards for the amount of emissions per millionBTU heat input. None of the monitoring measures of the draft permit provide parameterand process monitoring which could ensure that NOX emissions remain within certainvariability from parameter limits that were demonstrated during a compliance stack test. There isn’t even a requirement to limit, monitor or record the natural gas combustion rate.

Because of the three different combustion units and the single mass rate emissionlimitation, the draft permit should be amended to require a continuous emission monitorfor NOX as well as a stack flow meter and oxygen sensor, all of which can determinemass emission rates. Continuous monitoring to assure compliance with the NOXemission limitation is an economic means to assure compliance on a continuing basis. Inaddition to the NOX continuous monitoring requirement that should be incorporated tothe draft permit, a full suite of CEM quality assurance, quality control measures, quarterlyreporting on both excess emissions and CEM downtime and compliance with EPAperformance specifications should be provided.

3.4.7.2 Issues of Carbon Monoxide Compliance

The draft permit should also be amended to incorporate carbon monoxide continuousemission monitoring. Both carbon monoxide and NOX emission rates tend to have aninverse relationship to each other. Because dryer and oxidizer operational setpoints willhave an important relationship to both CO and NOX emissions and how such emissionvary, both CO and NOX monitoring should be conducted at the combined stack dischargefor Emission Units P007, P008 and P009.


3.5 P801 – Fugitive VOC Emissions

3.5.1 Applicant’s Fugitive VOC Leak Emission Characterization for Open EndedLines is Erroneous

Applicant’s submittal indicates uncontrolled emissions from 50 open ended lines of 0.8ton VOC/year and controlled emissions of 0.0 ton/year. However, Applicant’s controlmeasures show only 25 of the open ended lines with 100% control, rather than 50. Therefore, Applicant’s VOC emissions from leaks associated with the 25 open endedlines (as per the presentation in Applicant’s emission calculation spreadsheets) has beenunderstated by the amount of 0.4 tons VOC per year.

3.6 P901 and P902 – Stack and Fugitive Emissions from Grain Receiving,Transferring, Conveying and Storage; DDGS Loadout

3.6.1 Hourly Mass Rate Emission Limitations Should Be Applied on P901 and P902

The draft permit should be amended to include hourly mass rate emission limitations forall criteria pollutants for these emission units. In particular, there can be no assurancethat the ambient modeling exercise that was completed properly reflects short termemission rate PSD increment characterizations without an hourly PM10 limit.

3.6.2 Annual Limitations on the Amount of Grain Received by the Facility ShouldBe Written in the Form of Twelve Month Rolling Averages

Condition P901:II.B.1 should be amended to incorporate rolling 12 month averages onthe annual throughput limit on grain received. Condition P901:II.C.3 should be amendedto conform to the 12 month rolling average compliance requirement.

3.6.3 Applicant’s VOC Emission Characterization for the DGS Dryer is Subject toQuestion

Applicant first calculated the VOC emission rate from the DDGS cooler as though 100%of the VOC emissions consisted of ethanol. Applicant then estimated that methanol,acetaldehyde and formaldehyde were also present at a total of 1.36 ton/year, but theApplicant never added the 1.36 tons of HAP to the VOC emission total. The Applicanterroneously failed to consider that non-HAP, non-ethanol VOC compounds, such asacetic acid and glycerol, would also likely be present in the DDGS cooler exhaust. Suchmultiple oxygenated compounds would have a significantly higher different VOC tocarbon ratio than ethanol.


3.6.4 Applicant’s Rejection of Wet Scrubber Controls on the DDGS Cooler in theBest Available Technology Determination Should be Disallowed

The Applicant’s Best Available Technology demonstration for VOC emissions stated thatwet scrubbers were not technically feasible for control of VOC emissions from the DDGScooler on the basis that “compounds not easily absorbed by water.” Applicant thencharacterized the majority of emissions from the DDGS cooler as ethanol. Ethanol ishighly soluble in water and a wet scrubber is used for control of VOC as ethanol in otherparts of the process. In addition, certain types of scrubbers could also have eliminated theneed for a fabric filter for PM control from the cooler. If ethanol control is easilyachieved at the fermentation scrubber, it is completely invalid to claim that control ofVOCs as ethanol at the DDGS is not technically feasible because ethanol is “....not easilyabsorbed by water.”

The BAT demonstration is also defective because it failed to consider use of all or aportion of the DDGS cooler flue gas stream as combustion air for another related sitecombustion process unit.

3.7 P011 - Cooling Tower Emission Unit

The draft permit language for the cooling tower emission unit should be amended toinclude a physical limit to set a maximum hourly water circulation rate commensuratewith the rate considered in the emission calculation and measures to assure compliancewith such a rate.

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Broin & Associates http://www.broinandassociates.com/projects.asp

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Completed Projects - Premier PartnersNorthstar EthanolVoyager EthanolSioux River EthanolOtter Creek EthanolIowa EthanolJames Valley EthanolGreat Plains EthanolMichigan EthanolTall Corn EthanolNorthern Lights EthanolNortheast Missouri GrainEXOLPro-CornEthanol2000Broin Enterprises, Inc.

Completed ProjectsHeartland Grain FuelsHeartland Corn ProductsAl-Corn Clean Fuels


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Northern Lights Ethanol, LLC, Near Big Stone City, SD, Plans Expansion & New Technology http://www.biofuelsjournal.com/articles/Northern_Lights_Ethanol__LLC__Near_Big_Stone_C...

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Print / Email this article Date Posted: Oct. 27 2005

Northern Lights Ethanol, LLC, Near Big Stone City, SD, Plans Expansion & New Technology Sioux Falls, SD--Northern Lights Ethanol, LLC, located near Big Stone City, SD and designed, constructed, managed, and marketed by Sioux Falls-based Broin Companies, Oct 27 announced intentions to expand the ethanol production facility.

Plans include increasing plant capacity by 50% from 50 to 75 million gallonsannually as well as implementing Broin Companies’ patent-pending BPX™ethanol production technology.

Northern Lights Ethanol, LLC, a partnership of Northern Growers, LLC and Broin Companies, began operations in July 2002 with a nameplate production rate of 40 million gallons per year.

Currently, the plant is operating at 125% above design capacity producing 50 million gallons of ethanol annually.

In addition to creating a new market for additional corn, the expansion willincrease Northern Lights’ annual production of Dakota Gold Enhanced NutritionDistillers Products™ to 225,000 tons.

“This expansion will increase Northern Lights’ annual corn consumption by 9million bushels, bringing our total usage to 26.5 million bushels,” said Blaine Gomer, General Manager of Northern Lights.

Northern Lights Ethanol, LLC, Near Big Stone City, SD, Plans Expansion & New Technology http://www.biofuelsjournal.com/articles/Northern_Lights_Ethanol__LLC__Near_Big_Stone_C...

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“This offers yet another market for our local corn producers and will have manyadditional positive economic impacts on the area.”

Northern Lights Ethanol has also signed a new long-term contract formanagement and marketing services provided by Broin Companies.

“We are pleased with the continued partnership with Northern Lights Ethanol,”said Jeff Broin, CEO of the Broin Companies.

“Northern Lights has performed very well and we are looking forward to evengreater success in the future with the addition of state-of-the-art BPX technologyand increased production capacity.”

Engineering activities and due diligence items for the technology implementationand expansion are moving forward at a brisk pace.

For more information, contact Rebecca Sevening at 605-965-2200.

See Related Websites/Articles:

Broin Companies

Email: [email protected] • 3065 Pershing Ct. • Decatur, IL 62526 • 800-728-7511 • Fax: 217-877-6647

©2001-2006 Country Journal Publishing Co. — No portion of this site may be copied or reproduced without prior express written permission. Privacy Policy


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Attachment #6

Phoenix BioSystems--General Project Experience http://www.pbiosystems.com/experience.htm

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General Project ExperiencePHOENIX BIO-SYSTEMS, INC.

at ICM, Inc. 310 North First Street, P.O. Box 116

Colwich, Kansas 67030

· Anaerobic · Wastewater Treatment · Groundwater · Odor ·

· Distillery · Microbial Control ·

ANAEROBIC

· Supplied skid-mounted 2-module Bio-Methanator unit to a fuel ethanol plant in Oakley, KS. Unit was skid-mounted in ICM/Phoenix shopand designed to remove up to 8,000 ppd COD from evaporator condensate. Unit was delivered in October 2003 and started up in January2004 for Western Plains Energy, LLC, Oakley, Kansas.

· Supplied skid-mounted 4-module Bio-Methanator unit to a fuel ethanol plant in Aurora, SD. Unit was skid-mounted in ICM/Phoenix shopand designed to remove up to 16,000 ppd COD from evaporator condensate. Unit was delivered in August 2003 and started up inNovember 2003 for VeraSun Energy, LLC, Aurora, South Dakota.

· Supplied skid-mounted 2-module Bio-Methanator unit to a fuel ethanol plant in Minden, NE. Unit was skid-mounted in ICM/Phoenix shop and designed to remove up to 8,000 ppd COD from evaporator condensate. Unit was delivered in June 2003 and started up inNovember 2003 for KAAPA Ethanol, LLC, Minden, Nebraska.

· Supplied skid-mounted Bio-Methanator unit to a fuel ethanol plant in Marcus, IA. Unit was skid-mounted in ICM/Phoenix shop anddesigned to remove up to 8,000 ppd COD from evaporator condensate. Unit was delivered in December 2002 and started up in April 2003for Little Sioux Corn Processors, LLC, Marcus, Iowa .

· Supplied skid-mounted Bio-Methanator unit to a fuel ethanol plant in Plainview, NE. Unit was skid-mounted in ICM/Phoenix shop and


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designed to remove up to 4,000 ppd COD from evaporator condensate. Unit was delivered in October 2002 and started up in March 2003for Husker Ag Processing, LLC, Plainview, Nebraska .

· Supplied skid-mounted Bio-Methanator unit to a small fuel ethanol plant in Aberdeen, SD. Unit was skid-mounted in ICM/Phoenix shopand designed to remove up to 2,000 ppd COD from evaporator condensate. Unit was delivered and started up November 2002 forHeartland Grain Fuels, Inc., Aberdeen, South Dakota.

· Supplied skid-mounted dual Bio-Methanator unit to Michigan Ethanol, LLC, a new 40 million GPY fuel ethanol plant in Vassar, MI. Unit was skid-mounted in ICM/Phoenix shop and designed to remove up to 8,000 ppd COD from evaporator condensate, concentrated byR.O. Unit was installed in one week in July 2002 and subsequently started up in 10 days in November 2002 for Broin and Associates, theengineer for Michigan Ethanol, LLC, Caro, Michigan.

· Supplied skid-mounted, dual Bio-Methanator unit to MidWest Grain Processors, LLC, a 40 million GPY fuel ethanol plant in Lakota, IA. Unit was skid-mounted in ICM/Phoenix shop and designed to remove up to 8,000 ppd COD from evaporator condensate and waste CIPwater. Unit was installed in one week in April 2002 and subsequently started up in 10 days in November 2002 for MidWest GrainProcessors, LLC, Lakota, Iowa.

· Supplied skid-mounted, dual Bio-Methanator unit to Badger State Ethanol, LLC, a 40 million GPY fuel ethanol plant in Monroe, WI. Unitwas skid-mounted in ICM/Phoenix shop and designed to remove up to 8,000 ppd COD from evaporator condensate and waste CIP water. Unit was installed in one week in June 2002 and subsequently started up in 10 days in October 2002 for Badger State Ethanol, LLC, Monroe, Wisconsin.

· Supplied skid-mounted dual Bio-Methanator unit to Tall Corn Ethanol, LLC, a new 40 million GPY fuel ethanol plant in Coon Rapids, IA. Unit was skid-mounted in ICM/Phoenix shop and designed to remove up to 8,000 ppd COD from evaporator condensate, concentratedby R.O. Unit was installed in one week in March 2002 and subsequently started up in 10 days in August 2002 for Broin and Associates,the engineer for Tall Corn Ethanol, LLC, Coon Rapids, Iowa.

· Supplied skid-mounted dual Bio-Methanator unit to Northern Lights Ethanol, LLC, a new 40 million GPY fuel ethanol plant in Big Stone City, SD. Unit was skid-mounted in ICM/Phoenix shop and designed to remove 8,000 ppd COD from evaporator condensate, concentratedby R.O. Unit was installed in one week in January 2002 and subsequently started up in 10 days in June 2002 for Broin and Associates, theengineer for Northern Lights Ethanol, LLC, Big Stone City, South Dakota.

· Supplied skid-mounted Bio-Methanator unit to a 30 million GPY fuel ethanol plant in Claremont, Minnesota. Unit was skid-mounted inICM/Phoenix shop and designed to remove 4.000 ppd COD from evaporator condensate. Unit was installed in one week in February 2002and subsequently started up in 10 days in May 2002 for Al-Corn Ethanol, Claremont, Minnesota.

· Supplied skid-mounted, dual Bio-Methanator unit to Adkins Energy, LLC, a 36 million GPY fuel ethanol plant in Lena, IL. Unit wasskid-mounted in ICM/Phoenix shop and designed to remove 8,000 ppd COD from evaporator condensate and dryer stack scrubber water. Unit was installed in one week in March 2002 and subsequently started up in 10 days in July 2002 for Lurgi PSI, the engineer for AdkinsEnergy, LLC, Lena, Illinois .


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· Supplied skid-mounted, dual Bio-Methanator unit to Glacial Lakes Ethanol, LLC, a 40 million GPY fuel ethanol plant in Watertown, SD. Unit was skid-mounted in ICM/Phoenix shop and designed to remove 8,000 ppd COD from evaporator condensate and waste CIP water. Unit was installed in one week in Spring 2002 and subsequently started up in 10 days in September 2002 for Glacial Lakes Ethanol, LLC, Watertown, South Dakota .

· Supplied skid-mounted Bio-Methanator unit to a fuel ethanol plant in Bartow, FL. Unit was skid-mounted in ICM/Phoenix shop anddesigned to remove 4,000 ppd COD from evaporator condensate. Unit was installed and started up in less than two weeks in December2001 for Parallel Products of Florida, Inc., Bartow, Florida.

· Supplied skid-mounted, dual Bio-Methanator unit to Exol, LLC, a 36 million GPY fuel ethanol plant in Albert Lea, MN. Unit wasskid-mounted in ICM/Phoenix shop and designed to remove 8,000 ppd COD from evaporator condensate and dryer stack scrubber water. Unit was installed in one week in May 2001 and subsequently started up in 10 days in October 2001 for Broin and Associates, theengineer for Exol, LLC, Albert Lea, Minnesota.

· Supplied skid-mounted dual Bio-Methanator unit to a new 40 million GPY fuel ethanol plant in Wentworth, SD. Unit was skid-mountedin ICM/Phoenix shop and designed to remove 8,000 ppd COD from evaporator condensate and dryer stack scrubber water. Unit wasinstalled in one week in May 2001 and subsequently started up in 10 days in Sept 2001 for Broin and Associates, the engineer for Dakota Ethanol, LLC, Wentworth, South Dakota.

· Supplied skid-mounted Bio-Methanator unit to a 30 million GPY fuel ethanol plant in Winthrop, Minnesota. Unit was skid-mounted in ICM/Phoenixshop and designed to remove 4,000 ppd COD from evaporator condensate. Unit was installed in one week in March 2001 and subsequently started upin 10 days in June 2001 for Heartland Corn Products (HCP), Winthrop, Minnesota.

· Supplied skid-mounted Bio-Methanator unit to a small fuel ethanol plant in Scotland, South Dakota. Unit was skid-mounted in ICM/Phoenix shop anddesigned to remove 1,000 ppd COD from evaporator condensate. Unit was delivered and started up October, 2000 for Broin Enterprises, Inc. (BEI),Scotland, South Dakota.

· Design Team Leader, Operations Start-up and Training Supervisor for turnkey provision of ICM/Phoenix Bio-Methanator treating 150 gpm evaporatorcondensate at Golden Triangle Energy, GTE, LLC, Craig, Missouri.

· Design Team Leader, Operations Start-up and Training Supervisor for turnkey provision of ICM/Phoenix Bio-Methanator treating 150 gpm evaporatorcondensate at Northeast Missouri Grain Processing, NEMO, LLC, Macon, Missouri.

· Design Team Leader, Operations Start-up and Training Supervisor for turnkey provision of ICM/Phoenix Bio-Methanator treating 400 gpm evaporatorcondensate. High Plains Corporation Fuel Ethanol Facility, York Nebraska. Provided permit modification services (NDEQ)

· Design Team Leader, Operations Start-up and Training Supervisor for turnkey provision of ICM/Phoenix Bio-Methanator treating 150 gpm evaporatorcondensate at Pro-Corn LLC, Preston, Minnesota.

· Design Team Leader, Operations Start-up and Training Supervisor for turnkey provision of ICM/Phoenix Bio-Methanator treating 150 gpm evaporatorcondensate at Agri-Energy, LLC, Luverne, Minnesota.

· Design Team Leader, Operations Start-up and Training Supervisor for turnkey provision of ICM/Phoenix Bio-Methanator treating 150 gpm evaporatorcondensate at Denco, LLC, Morris, Minnesota.


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· Design Team Leader and Operations Supervisor for 10,000 gallon High Rate Anaerobic Bio-Methanator at High Plains Corporation Fuel Ethanol Facility in Colwich, Kansas.

· Develop high rate Bio-film Anaerobic Bio-System for the treatment of ethylene, diethylene, and propylene glycol wastewaters from airport stormwaterrun-off for A3 Environmental, Sarasota, Florida.

· Provide complete design, operator training and start-up services of Bio-film Anaerobic Bio-System for the treatment of distillation wastewaters and reduction of sewer surcharge for ethanol distilling plant in Colorado. Ag Power of Colorado.

· Design, fabricate, and start-up of ICM/Phoenix Anaerobic Bio-Methanation system for the treatment of soft drink syrup production wastewaters atA.L.I. for Enviro-Care, Inc., San Juan, Puerto Rico.

· Provide design for two-stage Wastewater Treatment system for Downflow Bio-Film Anaerobic Filtration and land application of yeast-drying operation process wastewaters for yeast processing plant in Georgia.

· Develop, design, construction oversight and start-up of solvent Hazardous Waste Upflow Bio-Film Anaerobic system capable of 15 grams/liter/dayCOD destruction of overspray solvents from can making internal coating operation. Coors Container, Golden, Colorado.

· Developed pilot scale Downflow Bio-Film Anaerobic system capable of destruction of 30 gram/liter/day chemical oxygen demand (COD) for brewerywastewater.

· Provide design of Fixed-Bed Upflow Anaerobic (Bio-Methanation) waste treatment facility for alcohol distillery thin stillage treatment in Louisiana.

· Nutrient balance, process optimization, process design evaluation for operating cheese whey permeate Bio-Methanation Suspended Growth Phase reactor in Wisconsin. Provide operations management, systems optimization and redesign for Bio-Methanation andAerobic Sequencing Batch Reactor plants for the treatment of cheese plant wastewaters and cheese whey permeate.

· Provide equipment, engineering, and turn-key installation of Process Control Upgrade to existing waste water anaerobic lagoon. Ag Processing, Inc., Hastings, Nebraska.

WASTEWATER TREATMENT PLANT

· Provide design basis for three-stage Wastewater Treatment facilities including Bio-Film Anaerobic, Aerobic Lagoon and Land Applicationsystem. Assist client in obtaining wastewater (NPDES) and air quality permits from Nebraska Department of Environmental Control.

· Optimization of six (6) MGD Brewery process waste treatment plant. Develop and evaluate Selector Operation for process upgrade and reduction of polymer use.

· Direct bench scale Treatability studies for the application of Sequencing Batch Reactors to brewery process waste.

· Provide design of Aerobic Bio-filtration Modular system for treatment of landfill leachate in New York State.

· Provide design for modular domestic wastewater treatment system for use in salt water at Bahamas Resort. Zeta Tech, Inc.


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GROUNDWATER

· Provide treatability report and complete dual Aerobic Submerged Bio-Tower Design for treatment of groundwater contaminated with chlorinatedhydrocarbons and solvents at the Lowry Superfund Site in Colorado. Provided Modular Dual Bio-Reactor system.

· Treatability study for the use of Downflow Bio-Film Bio-reactors for the treatment of solvent contaminated groundwaters at RCRA site in Michigan. Upjohn/RTG, Inc., Denver/Lakewood, Colorado.

· Develop design for in-situ Bio-Remediation of contaminated groundwater at can manufacturing facility. Provide microorganisms capable ofdestruction of chlorinated hydrocarbons. Design pilot system for in-situ injection/remediation in order to model systems for full-scale design. Coors Container Can End Manufacturing, 44th & McIntyre, Golden, Colorado.

· Develop data and report to Colorado Department of Health on Natural Bio-degradation in-situ of ethyl acetate and toluene in contaminated groundwater for paper packaging producer. Graphics Packaging, Boulder, Colorado

· Design of soil washing and Land Farming system for the remediation of Chlorinated Hydrocarbons and Oils in contaminated soils. Coors Container,Golden, Colorado.

· Advise engineering project teams for contaminated Groundwater Site Assessments and remediation of hydrocarbon spills. Prepare site assessment and remediation plans for submission to regulatory authorities. Technical advisor to Coors Project Manager in the development of remediation plansfor Lowry Superfund Site.

· Provide groundwater treatment Aerobic Upflow Biologically Activated Carbon Bio-Reactor system for treatment of BTEX contamination at USTRemediation site in Panama City, Florida. Spectrum Environmental, Pelham, Alabama.

· Provide design parameters and treatability for the Bio-Remediation of Petroleum Contaminated Soils and Waste Oil pit under contract to LT Environmental for a petroleum processing site near Greeley, Colorado.

· Provide treatability for the Bio-Remediation of Waste Oil pits in Wyoming. Treatability testing included the assessment of ex-situ Bio-reactors and theapplication of on-site land farming of petroleum waste pit liquor and contaminated site soil. LT Environmental, Denver, Colorado.

ODOR/VOC

· Develop plan and equipment design for the treatment of hydrogen sulfide Odor and Corrosion Control in municipal wastewater systems in Florida. Equipment design included a simple air-lift aerator for lift station application and Odor Bio-Scrubbers for hydrogen sulfide removal at master liftstation.

· Design, direct pilot operations, and provide engineering scale-up parameters for full-scale Bio-Filter for the destruction of Volatile Organic AirEmissions from aluminum can production plan.

· Provided microbiological process and design parameters for the development of full-scale Bio-Filter designed to eliminate organic and sulfide Odorscreated by waste activated sludge management system in Colorado.

· Provide design of Odor Bio-Scrubbers for fermentation plant odor emissions in Colorado.


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· Provide Odor Bio-Scrubber for stack off-gas at Agri-Energy, LLC, Luverne, Minnesota.

DISTILLERY

· Manage Qualification Production Trials for a 15-million gallon per year Fuel Ethanol Plant in western Nebraska in order to preserve Nebraska State Alcohol Tax Credits. Assemble and direct complete start-up and operating team on year-end short notice. Start-up plant and produce qualifying amount of 200° Proof fuel alcohol. Credits were preserved. Provided technical feasibility, economic evaluation, and recommendations to owners fordisposition, sale, and/or liquidation options for the plant.

· Provide Technical and Economic Evaluation and liquidation value study for Fuel Alcohol Plant in South Dakota under contract to professional liquidation firm. Asset Management Inc., Miami, Florida.

· Direct Pilot Operation (5,000 gallons per week) for the technical and economic feasibility of the recovery of USP Grade Glycerol from fuel alcohol plant thin stillage. Investigate the application of pressure filtration, DE pre-coat vacuum filtration, ceramic micro-filtration, ultra-filtration,nano-filtration, ion exchange, and evaporator unit operations in 5,000 gpw pilot plant. Provide operations management, process analysis, unitoperations assessments, economic feasibility, and recommendations for future development and scale-up to fuel alcohol client.

· Provide design basis for Corn Processing, Continuous Ethanol and Torula Yeast production facilities for fuel alcohol plant in Sutherland, Nebraska. Provide mass balance, process flow, and equipment recommendations to client for application to experimental concept corn wet milling plant.

· Contract for engineering, reconstruction, start-up and operation of 400,000 gpy Alcohol Distillation and Dehydration facility for the disposal of waste beer in Barnesville, Colorado.

· Design, start-up of Alcohol Production and Waste Treatment Systems for potato waste-to-alcohol plant in Colorado. Provided optimization and operation training for grain conversion, Fermentation and Waste Treatment facilities. Developed process control lab and trained personnel.

· Technical assessment, economic evaluation, and asset valuation of two (2) Alcohol Production Plants in Virginia. Provided redesign specifications, equipment recommendations, and investment required to make plants operational for insurance carrier in Virginia.

MICROBIAL CONTROL

· Provide assessment and control measures for microbial hydrogen sulfide production and Bio-Fouling corrosion problem in oil/water emulsion, metalworking system at can production facility. Coors Container Company, Golden, Colorado.

· Microbial corrosion Bio-Fouling assessment and control in water cooling systems for aircraft maintenance operations. Provided control measures tostabilize cooling system for major carrier in Denver. Frontier Airlines, Denver, Colorado.

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Attachment #7

Midwest Scaling Protocol for the Measurement of “VOC Mass Emissions”

VOC Sampling at Wet and Dry Grain Mills and Ethanol Production Facilities

U.S. Environmental Protection AgencyOffice of Air Quality Planing and Standards

Office of Regulatory Enforcement

August 2004

Version 1.6August 2004

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VOC Sampling from Wet and Dry Grain Mills and Ethanol Production Facilities

Introduction

This protocol is designed to determine the actual volatile organic compound (VOC) massemission rates from sources where significant amounts of oxygen-containing organic compoundsare emitted. Either U.S. EPA Method 25 or Method 25A is used to determine the total organiccompound concentration of the emission samples. The concentration data are then converted tocarbon mass (or propane mass) emission rates. Simultaneously, the concentrations of the mostsignificant individual organic compounds in the emission sample are measured with Method 18.

This protocol is designed to be used in conjunction with Methods 25 or 25A to provideaccurate VOC mass emission measurements from most air emission units at grain mills andethanol production facilities. VOC mass emissions based on concentration measurements withMethods 25 or 25A reported “as carbon” or “as propane” results in reported VOC emission ratesless than the actual emissions of the VOC pollutants. The Midwest Scaling Protocol (MSP)provides a way to convert the VOC results from “as carbon,” when Method 25 is used, or from“as propane,” when Method 25A is used, to “as VOC ” emission rates.

Sources in this industry may opt to use a standard scaling factor (SF) of 2.2 pounds ofVOC per pound of VOC as carbon instead of performing quantitative measurements ofindividual volatile organic compounds in order to derive individual scaling factors for eachsource. Alternatively, the MSP provides an acceptable means for the quantitative measurementsof air emissions of individual volatile organic compounds from sources at grain mills and ethanolproduction facilities. The MSP also serves as a reference for equations used to convert VOCconcentration measurements reported “as carbon” or “as propane” to actual VOC massemissions.

The decision to use Method 25 or Method 25A to measure total VOC concentrations issource dependent. In general, Method 25 is applicable to all sources with total VOCconcentrations >50 ppmC (parts per million carbon). Methane and carbon monoxideconcentrations are also measured with Method 25. However, referring to Method 25A, section1.1 of Method 25 states:

“Direct measurement of an effluent with a flame ionization detector (FID) analyzer maybe appropriate with prior characterization of the gas stream and knowledge that thedetector responds predictably to the organic compounds in the stream. If present,methane (CH4) will, of course, also be measured. The FID can be applied to thedetermination of the mass concentration of the total molecular structure of the organicemissions under any of the following limited conditions: (1) Where only one compound is known to exist; (2) when the organic compounds consist only of hydrogen and carbon;


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(3) where the relative percentages of the compounds are known or can be determined,and the FID response to the compounds are known;

(4) where a consistent mixture of the compounds exist before and after emission controland only the relative concentrations are to be assessed; or

(5) where the FID can be calibrated against mass standards of the compounds emitted(solvent emissions, for example).”

The FID used in Method 25A has a depressed response to organic compounds thatcontain oxygen. The tester must determine, for the specific FID unit used for each test, theresponse factor for each organic compound that constitutes 5% or more of the total mass of theindividual VOC species analyzed. A weighted average of these response factors shall be used toadjust the FID’s response to the actual emission samples. The tester shall adjust the analyzer’sresponse prior to converting the response to a mass emission rate.

If the tester uses Method 25A to measure VOC from a source where the moisture contentis greater than 10%, then the tester must normally dilute the sample using the procedures inMethod 205 to reduce the water content of the sample to less than 10%. The tester shall use aheated sample line to transport the sample from the stack to the analyzer to prevent condensationof water and organic compounds. At the time of this writing, at least one FID analyzer has atolerance for moisture content up to 40%. The moisture content for which Method 205 dilutionis required is analyzer-dependent.

One specific application of Method 18 for measuring the kinds of oxygen containingcompounds that are most common in the emissions from grain mills is the impinger methoddeveloped by the National Council for Air and Stream Improvement, Inc. (NCASI). NCASI hasdesignated this method as NCASI CI/SG/PULP-94.02, Chilled Impinger/Silica Gel Tube TestMethod at Pulp Mill Sources for Methanol, Acetone, Acetaldehyde, Methyl Ethyl Ketone andFormaldehyde (NCASI 94.02). Water soluble organic compounds are collected in impingersfilled with chilled laboratory grade water. Any target compounds that break through the chilledwater are collected on organic grade silica gel. Method 18 analytical procedures, gaschromatography with flame ionization detection or mass spectrometric detection, are used tomeasure the target organic compounds listed in Table 1.1 that are collected in the sampling train,except for formaldehyde which is measured by a colorimetric procedure. The sample collection,recovery and preservation procedures for this specific application of Method 18 are described inAppendix B along with recommended GC/FID procedures for most target compounds. Theanalytical procedures to measure formaldehyde are described in Appendix C. Additional GCoperating conditions may be necessary to quantify all of the water-soluble volatile organiccompounds on the target list.

These data are used to calculate the weighted average ratio of the VOC molecular weightdivided by the VOC carbon mass (or VOC propane mass). This SF is then used to convert thetotal organic carbon mass emission rate to the total VOC mass emission rate (i.e., the results areconverted from “as carbon” or “as propane” to “as VOC”).


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It should be noted that the VOC mass emission calculation based on a conversion ofMethod 25 or Method 25A data using Method 18 measurements of a specific list of oxygenatedorganic compounds may slightly bias the true total mass VOC emission rate compared to the useof a complete set of organic compound concentrations, including all non-oxygenatedhydrocarbons. The source is allowed, at its discretion and with the EPA’s approval, to performadditional sampling and analysis to quantify the concentrations of other hydrocarbon compounds,including non-oxygenated compounds, and use the overall average molecular weight for allquantified organic compounds in the calculations discussed below. Failure to conduct additionaltesting indicates that the source accepts the oxygenated organics weighted average molecularweight to carbon weight ratio as representative of the actual average molecular weight to carbonweight ratio of all organic compounds present in the emissions from the specific unit beingtested.

1.0 Scope and Applicability.

1.1 Analytes. The analytes in Table 1.1 must be measured from each source being tested. These compounds have been found to comprise the bulk of the identified VOC emitted fromsources at grain mills and ethanol production facilities.

Analyte CAS Number Interference-Free AnalyticalSensitivity

Total Organic Compounds NA M25A ~3 ppmC, M25 ~50 ppmC

Acetaldehyde 75070 ~ 1 ug/ml

Acetic Acid 64197 ~ 1 ug/ml

Ethanol 64175 ~ 1 ug/ml

Formaldehyde 50000 ~ 1 ug/ml

Formic Acid 64186 ~ 1 ug/ml

2-Furaldehyde 98011 ~ 1 ug/ml

Methanol 67561 ~ 1 ug/ml

1.2 Applicability. This protocol is applicable to determining the actual VOC massemission rates from sources at grain mills and ethanol production facilities.

1.3 Data Quality Objectives. The quality of the data needed is determined by the needs ofthe data user. If the test using this protocol is required as part of a regulatory process and if the


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tester follows and meets the performance criteria in the protocol, including all Method 18 spikerequirements, it is presumed that the MSP produces data of suitable quality to determinecompliance with that regulation. The performance criteria in the protocol are set at levels that anoperator properly using well designed equipment will consistently attain or exceed. However,because the protocol allows different options to comply with some of the performance criteria, itis the responsibility of the owner or operator of the emission unit, as the data provider, to identifythe specific requirements in the protocol that were followed and document that the protocol’sperformance criteria were met, or to identify deviations as an exception to the protocol. Theregulatory agency is considered the data user and, therefore, is entitled to make the finalassessment of data quality.

For the purpose of determining only the SF to be used in calculating VOC massemissions, the spike requirements of Method 18 may be replaced with an analytical spike setconsisting of one low concentration and one high concentration spike sample. These alternatespike samples shall be prepared in the field by spiking the first impinger of the sample collectiontrain and drawing a measured amount of hydrocarbon-free air through the impinger trainequivalent to the nominal sample volume. The spike samples shall be recovered and analyzedusing the same procedures as those used to recover and analyze the source samples.

2.0 Summary of Protocol. Total organic emissions are measured based on the carbon contentof the sample. The list of individual organic compounds that are present in significant quantitiesare measured individually by Method 18 (using the specific application described in Appendix B)and used to convert the total carbon based measurements to a true VOC mass.

3.0 Definitions. Use the definitions as specified in the following methods.

3.1 EPA Methods. These are methods found in 40 CFR Part 60, Appendix A, and 40CFR Part 51, Appendix M.

3.1.1 Method 25 — Determination Of Total Gaseous Non-methane Organic EmissionsAs Carbon

3.1.2 Method 25A — Determination Of Total Gaseous Organic Concentration Using aFlame Ionization Analyzer

3.1.3 Method 18 — Measurement Of Gaseous Organic Compound Emissions By Gas

Chromatography

3.1.4 Method 205 —Verification of Gas Dilution Systems for Field InstrumentCalibrations

3.1.5 Method 5 —Determination Of Particulate Emissions From Stationary Sources


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3.1.6 Method 1 — Sample And Velocity Traverses for Stationary Sources

3.1.7 Method 2 — Determination Of Stack Gas Velocity And Volumetric Flow Rate

3.1.8 Method 3A—Determination of Oxygen and Carbon Dioxide Concentrations inEmissions from Stationary Sources (Instrumental Analyzer Procedure).

3.1.9 Method 4—Determination of Moisture Content in Stack Gases.

3.1.10 Method 10 —Determination Of Carbon Monoxide Emissions From StationarySources

3.1.11 Method 10B —Determination Of Carbon Monoxide Emissions From StationarySources

4.0 Interference. Interference as specified in the methods in Section 3 and Appendix B.

5.0 Safety. Follow the safety precautions as specified in the methods in Section 3 andAppendix B. Note that some sources and some areas of grain processing and ethanol production facilitiesmay be fire or explosion hazards. Use appropriate caution and selection of sample collectionprocedures.

6.0 Equipment and Supplies. Equipment and supplies as specified in the methods in Section 3and Appendix B.

7.0 Reagents and Standards. Reagents and standards as specified in the methods in Section 3and Appendix B, with the following exception:

7.1 For Method 25A, obtain a calibration standard of all individual target analytes inSection 1.1 and/or other target analytes found in screening tests at significant levels (>5% of thetotal VOC). The standards shall be within the range of 25 % to 200 % of the expectedconcentration of the individual compound. These calibration standards will be used to developresponse factors for each individual compound. These gases shall meet the specifications ofSection 7.1 of Method 25A.

8.0 Sample Collection, Preservation, Storage and Transport.

8.1 Test Protocol (TP). The procedures in Appendix A, entitled “A Guide for StackTest Protocol Development and Submittal For VOC Emission Tests at Grain Processing andEthanol Production Facilities,” shall be used to assure consistency and adequacy. Failure tosubmit a complete TP could add cost and time due to postponements or additional submittals ofthe TP.


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8.2 Operating Conditions. For the entire period of its performance test, each affectedsource shall operate at 90% to 100% of its maximum achievable capacity or itsallowable/permitted capacity under representative conditions while maintaining safe and stableload conditions using the highest emitting fuel (normal power sources) and processing typicalmaterial resulting in normal product. Operational parameters shall be recorded at 15-minuteintervals during the test to substantiate the load. The inlet and outlet gas temperatures of thedryers, syrup addition feed rate and solids content, wet cake feed rate (e.g. tons/hour) shall berecorded during the test.

8.3 The samples shall be collected using the following parameters:

8.3.1 Sources Without Entrained Water Droplets or Aerosols. If the tester intends to useprocedures for sources that do not have entrained water droplets, the tester shall conduct a visualinspection and a saturation test of the exhaust gases immediately prior to testing to demonstratethe stack gas is not saturated. A saturation test consists of measuring the moisture content of theexhaust gases using Method 4 and comparing the measured moisture results to tabulated valuesfor moisture content at 100 % relative humidity at the average temperature of the stack gas. Ifthe measured moisture content exceeds the moisture content from the tabulated values, then thestack gas shall be considered to be saturated and to contain water droplets. If the stack gas doesnot contain water droplets or visible aerosols, collect the samples directly from the stack gasusing the procedures in Method 25 or Method 25A and Method 18 as described in Appendix B. Use appropriate caution and unheated sample trains when collecting samples from explosion orfire hazard rated sources regardless of aerosol or water droplet content.

The need for unheated sample trains may dictate the requirement for using Method 25 ifthe Method 25A sample train would be subject to sample condensation.

8.3.2 Sources That Contain Entrained Water Droplets. If the stack gas contains entrainedwater droplets, the sample shall be extracted directly from it using the isokinetic samplingprocedures described in Method 5 with the exception that the sample shall be drawn from asingle representative point, preferably near the center of the stack or duct. Use Method 1 todetermine the appropriate sampling location. The tester shall maintain the probe and filter of theMethod 5 sampling train at 250° F + 25° F. Between 20 and 30 dry standard cubic feet (dscf)shall be drawn through the Method 5 sampling train over a one-hour period for each of the threeruns.

Use two stainless steel compression fittings behind the filter in the heated filter box of theMethod 5 sampling train to withdraw the sample for the total organic compound quantificationtest (Method 25 or 25A) and for the individual organic compound analysis (Method 18 asdescribed in Appendix B). Place a valve between the Method 5 and the Method 25 or 25Asampling system, and between the Method 5 and the Method 18 sampling systems to isolate eachof the sampling systems for leak checks. The tester shall account for the amount of samplediverted to the total organic quantification test and to the Method 18 sampling trains when


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calculating the isokinetic sampling rates. Method 25 samples require ~5 dry standard liters (~0.2dscf) per sample, and the Method 18 train requires ~30 dry standard liters (~1.1 dscf) per sample. Method 25A analyzers have different flow requirements and must be determined individually.

8.4.3 All Sources. Measure stack gas velocity according to the procedures in Methods 2and 3 at the beginning and the end of each test. Measure the moisture content of the stack duringeach test according to the procedures in Method 4. If the moisture content of the sample streamis greater than 10% (or as otherwise specified for the specific FID used) and if the tester ismeasuring total organic compounds by Method 25A, the tester shall use the procedures inMethod 205 to dilute the sample to reduce the moisture content to within the linear and unbiasedoperating range of the FID. The tester shall conduct cyclonic flow tests prior to thecommencement of testing at all sampling locations. If cyclonic flow is determined, appropriatecorrections must be conducted.

8.4.4 Dryers and Combustion Sources. Measure the carbon monoxide content ofemissions from dryers and combustion sources using the procedures in Method 10 orMethod10B.

8.5 Sample Recovery.

8.5.1 If using Method 25 for the total organic compound quantification test, follow theprocedures in that method to recover the sample, store it and transport it to the laboratory.

8.5.2 Follow the recovery procedures in Method 18 as described in Appendix B with thefollowing exception: If the tester uses an empty impinger as the final impinger in the sampletrain to collect any carryover impinger solution due to high moisture content in the stack, thetester shall recover any liquid in the final impinger and treat it as part of the sample. The testermay combine this recovered liquid with the sample from the impinger immediately in front of thefinal impinger or may recover it in a separate container.

9.0 Quality Control. Follow the quality control procedures as specified in the methods inSection 3 and Appendix B.

10.0 Calibration and Standardization. Follow the procedures for calibration andstandardization as specified in the methods in Section 3 and Appendix B with the followingexceptions:

10.1 For Method 25A, the tester shall determine the response factor of the actualinstrument used for measuring the total organic compound concentration to each of theindividual compounds in Section 1.1 that comprise >5% of the identifiable VOC in the sample. The response factor shall be determined by the instrument’s response to the calibration gas usedduring the emissions test. The tester may determine the response factor in the laboratory, at thetest site prior to the testing, or in the laboratory within 45 days after the first day of the testing


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provided that the instrument has not been modified or repaired in the interim. The responsefactor shall not be acceptable if the instrument is modified, repaired or adjusted between the testdate and the date that the response factors are determined. After the tester has determined theresponse factor for an individual instrument, the tester may use this response factor for othertests on the same emission unit using the same instrument until the instrument is modified orrepaired.

Immediately prior to determining the response factors, the tester must introduce zero gasand high-level calibration gas at the calibration valve assembly. The analyzer output shall beadjusted to the appropriate levels, if necessary. The predicted response as carbon shall becalculated for the compound for which a response factor is being determined by multiplying theconcentration of the compound by the number of carbon atoms in each molecule of thecompound. Then, the tester shall introduce the calibration gas to the measurement system, recordthe analyzer response, and calculate the response factor using the equation in Section 12.7.

11.0 Analytical Procedure. Follow the analytical procedures as specified in the methods inSection 3 and Appendix B.

12.0 Calculations and Data Analysis. Follow the calculation and data analysis procedures asspecified in the methods in Section 3 and Appendix B with the following additions:

12.1 Scaling Factor, SF. Calculate the scaling factor using the following equation.

Equation 1

Where SF = Factor used to correct mass as carbon to “as VOC” or actual mass (expectedto be 1.9-2.6)N = Total number of compoundsMWi = Molecular weight of compound iMWCi = Molecular weight of carbon per mole of compound i MFCi = Mole fraction of carbon contributed by compound i

12.2 Mole Fraction of Carbon.


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Equation 2

Where mCi = Milligrams of carbon contributed by compound i in the Method 18 sample.

12.3 Mass of Carbon Contributed by Each Compound.

Equation 3

Where mi = Milligrams of compound i in the Method 18 sample

12.4 Actual Mass Concentration VOC in the Sample Gas. Calculate the actual massconcentration of VOC in the sample gas from the measured VOC concentration as carbon usingthe following equation.

Equation 4

Where ma = Actual mass concentration of VOC in the samplemc = Measured carbon mass concentration of VOC in the sample, mg/dscm.

12.5 Carbon Mass in the Sample Based on Method 25A Measurement. For Method 25A,calculate the carbon mass in the Method 25A measured sample using the following equation.

Equation 5

Wheremc = Organic concentration as carbon, ppmv from Method 25A.RFave = Weighted average response factor from Equation 6.

12.6 Average Response Factor for Method 25A. Calculate the weighted averageresponse factor, RFave, for Method 25A using the following equation.


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Equation 6

Where Ci = Concentration in ppm carbon of organic compound iRFi = Response Factor of organic compound i

12.7 Response Factor for Individual Compounds. Calculate the response factor forindividual organic, RFi, compounds using the following equation.

Equation 7

Where Cci = Concentration in ppmv carbon of organic compound i as certified by themanufacturer of the standardCmi = Measured concentration in ppm carbon of organic compound i fromSection 10.1


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Appendix A

A Guide forStack Test Protocol Development and Submittal

For VOC Emission Tests at Grain Processing and Ethanol Production Facilities

PROTOCOL DEVELOPMENT

A detailed protocol, describing all test equipment, procedures, and quality assurance (QA)measures to be utilized, will help ensure that a complete and representative stack test isperformed. The protocol must be specific for the test, facility, operating conditions, andparameters to be measured. Adherence to the protocol should eliminate unnecessarydelays and costs in the performance of the test, whether the work is done in-house or by aconsultant.

The term "tester" will be used to refer to the individual(s) performing the emission test,whether in-house or a consultant. The tester should make at least one on-site inspectionof the emission point(s), testing ports, stack access and other parameters in order toprepare the protocol.

The following provides specific guidance pertinent to the major elements of the stack testprotocol.

1. Project Description

Provides a general description of the project. This should include sufficient detail toallow those individuals responsible for review and approval to perform their tasks. Where appropriate, the following shall be included:

a. Intended end use of the acquired data.

b. Dates anticipated for the beginning and the completion of testing.

c. Description of plant processes and control equipment, including flow diagramsand permitted, or maximum achievable, process rates.

d. Description of plant operating conditions, including but not limited to productionrate, fuel rate, process data (including relevant temperatures and/or flow rates),and pollution control operational data.


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e. Proposed operation during the stack test . Unless approved or specified by U.S.EPA or the applicable state agency, the test will be deemed unacceptable if therelevant process(es) are operated at less than 90% of maximum capacity.

f. List of operating and emission parameters to be measured during the test, typicaloperating ranges for these parameters, and the maximum ranges for theseparameters.

2. Project Organization and Responsibility

Include a table or chart showing the project organization and line of authority. List thekey individuals, including the Quality Assurance Officer (QAO), who are responsible forensuring the collection of valid measurement data and the routine assessment ofmeasurement systems for precision and accuracy.

3. QA Objectives for Measuring Data

All measurements must be made to ensure that results are representative of the normal, orpermitted, maximum operating conditions of the facility. Data quality objectives will bedetermined for each measurement and compared with the requirements for the specificproject. This will ensure that the data collected will be appropriate for their intended use.

4. Sampling Procedure

For each major measurement parameter, provide a description of the sampling proceduresto be used. Officially approved EPA procedures and Reference Methods should be usedwhere applicable. The protocol should include the following:

a. A stack diagram showing test ports, their distances from upstream anddownstream disturbances, the stack diameter, planned sampling equipment andmonitoring locations.

b. The proposed method for the determination of the presence and quantification ofcyclonic flow.

c. The proposed number of sample flow measurement points and the total samplevolume.

d. A detailed description of all sampling, sample recovery, and analytical procedures. In the case of non-standard procedures or modifications to standard procedures,the entire procedure should be described with justifications and necessary data forbackup. Options offered by the Reference Method should be selected andjustified.


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e. Any special conditions for the preparation of the sampling equipment andcontainers to avoid sample contamination.

f. Samples of forms to be used to record sample history, sampling conditions, andplant operating conditions.

g. The methodology for measurement of plant and pollution control device operatingconditions.

h. If more than one sampling train is to be used, a detailed description of the relevantsequencing and logistics.

i. If Continuous Emission Monitors (CEMs) are to be used, a detailed description ofthe operating and data logging procedures.

5. Sampling Procedures for Ethanol Production Facility Dryers

The protocol for the emission test should include the following test methods to accuratelycharacterize the VOC emissions from dryers:

Test Methods -

USEPA Method 1: Sampling Location and Cyclonic Flow DeterminationUSEPA Method 2: Stack Gas Velocity and Volumetric Flow RateUSEPA Method 3: Stack Gas Molecular WeightUSEPA Method 4: Stack Gas Moisture ContentUSEPA Method 18: Gas Chromatography

The preferred application of Method 18 based on similar sources is the NCASIMethod CI/SG/PULP-94.02: Chilled Impinger/Silica Gel Tube Test Method atPulp Mill Sources for Methanol, Acetone, Acetaldehyde, Methyl Ethyl Ketoneand Formaldehyde

USEPA Method 25: Determination of Total Gaseous Non-Methane Emissions asCarbon

USEPA Method 25A: Determination Of Total Gaseous Organic Concentration UsingA Flame Ionization Analyzer

Location - Sampling shall be performed at the exit of each stack. If the stack has acontrol device for VOC emissions, sampling shall occur before and after the controldevice where applicable and consistent with the Project Description listed above.

Isokinetics - Sample shall be drawn isokinetically from a single representative point forall methods in any stack that contains uncombined water or organic aerosols.


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Detection Limits - The limits of detection for each targeted compound and for total VOCshall be calculated in Kg/hr and/or lbs/hr.

6. Sample Custody

Sample custody is a part of any good laboratory or field operation. At a minimum, thefollowing sample custody procedures shall be addressed in the protocol:

a. Documentation of procedures for preparation of reagents or supplies that becomean integral part of the sample (e.g., filters and absorbing reagents).

b. Procedures and forms for recording the exact location and specific considerationsassociated with sample acquisitions. As samples are transferred betweenindividuals, the individuals should sign and date their relinquishing of, or receiptof, the samples on the Chain of Custody form.

c. Prepared sample labels containing all information necessary for effective sampletracking. Labels or custody seals should cover the sample container cap such thatit would be evident if the sample was opened by a person other than the laboratoryanalyst.

7. Calibration Procedures and Frequency

Include calibration procedures and information for each major measurement device,including coefficients, by reference to a standard method or by providing writtendescription. Provide the frequency planned for recalibration during the test and a list ofall calibration standards, including their source and traceability. Equipment to becalibrated would include, for example, dry gas meters, orifice meters, pitot tubes,thermometers/thermocouples, nozzles, flow meters as well as all process parametermonitors. Also include a detailed description of spike preparation procedures.

8. Documentation

Include sample copies of all data log sheets and examples of any calculations that will beperformed on the raw data. Note: copies of all raw data sheets, including manually andautomatically recorded data (strip charts and data logger or computer printouts) will besubmitted with the test report and copies must be available at the end of the day's testing.


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Appendix BMethod 18 for Oxygenated Organics Other Than Formaldehyde

Introduction.This appendix describes a specific application of the general Method 18 procedures to measurethe individual oxygenated organic compounds other than formaldehyde that are required by theMidwest Scaling Protocol. Formaldehyde is collected in the same Method 18 sample, but isanalyzed by a separate procedure found in Appendix C. Both this specific application ofMethod 18 and the formaldehyde procedure in Appendix C were developed by the NCASI andvalidated for their use at pulp mills. The NCASI identifies the procedure as NCASI MethodCI/SG/PULP-94.02, Chilled Impinger/Silica Gel Tube Test Method at Pulp Mill Sources forMethanol, Acetone, Acetaldehyde, Methyl Ethyl Ketone and Formaldehyde.

AcknowledgmentThis method was prepared by Dr. MaryAnn Gunshefski, Senior Research Scientist, andWard Dickens, Research Associate, at the NCASI Southern Regional Center. Otherassistance was provided by Terry Bousquet, Senior Research Scientist, with the NCASIWest Coast Regional Center.

This specific application follows the general Method 18 procedure with the following additionsto Method 18 taken directly from the NCASI Method CI/SG/PULP-94.02.

1.0 Scope and Application. Same as Method 18 with the following addition: Stability - The stability of acetaldehyde in the impinger catch was found to be 10 days, withrefrigeration at approximately 4°C. The stability of acetone, methyl ethyl ketone, and methanolwas found to be 21 days, with refrigeration at approximately 4°C. The stability of acetaldehyde,acetone, methyl ethyl ketone, and methanol on the silica gel sorbent tubes was found to beapproximately 10 days, with refrigeration at approximately 4°C. Once desorbed in 3% n-propanol, these same compounds are stable for up to 21 days, with refrigeration at approximately 4°C.

2.0 Summary of Method. Same as Method 18 with the following addition:This method involves collection of an air sample by drawing it through a midget impinger, whichis filled with water, and then through two 2-section silica gel sorbent tubes. The impinger is keptin an ice water bath during sampling to enhance collection efficiency. The impinger catch isanalyzed for methanol, acetaldehyde, ethanol, formic acid, acetic acid, 2-furaldehyde, by directinjection into a gas chromatograph equipped with a flame ionization detector (GC/FID). Thesilica gel sorbent is desorbed with a 3% (v/v) solution of n-propanol. The desorbate is injecteddirectly into the GC/FID for analysis of methanol, acetaldehyde, ethanol, formic acid, acetic acid,and 2-furaldehyde. Alternative GC procedures may be used with prior approval.

3.0 Definitions. Same as Method 18.


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4.0 Interferences. Same as Method 18 with the following addition: method interferences maybe caused by contaminants in solvents, reagents, glassware and other sample processinghardware. Clean all glassware by detergent washing with hot water and rinsing with tap water. The glassware should then be drained dry and baked at greater than 100°C for over 2 hours.

5.0 Safety. Same as Method 18.

6.0 Equipment and Supplies. Same as Method 18 with the following additions:

6.1.1 Sampling apparatus. A diagram of the sampling train is shown in Figure 1 (see below).

6.1.1.1 Probe/sampling line. The probe is made from Teflon tubing or stainless steel, which isthen attached to the first impinger.

6.1.1.2 Impinger train. Three 30 mL capacity midget impingers are connected in series to thesampling probe. The impingers should have regular tapered stems. All impinger trainconnectors should be glass and/or Teflon.

6.1.1.3 Sorbent tubes Two 2-section silica gel sorbent tubes (SKC #226-15 GWS) are placed inline after the impingers.

6.1.1.4 Rotameter. A 1000 mL/min capacity rotameter should be placed in line after the silicagel sorbent tubes for a visual flow check during sampling and leak checking. The rotameter isnot used to determine the actual flow rate through the impingers.

6.1.1.5 Critical orifice. A 400 ± 50 mL/min critical orifice should be used for flow control.

6.1.1.6 Vacuum pump - The critical orifice is followed by a pump capable of providing avacuum of about 18 inches of Hg. Pump capacity should be sufficient to obtain and maintaincritical conditions at the orifice.

6.1.1.7 Pressure gauges. One pressure gauge is placed before the critical orifice, and onepressure gauge is placed before the pump, and both are used when leak checking the sampletrain. The pressure gauge downstream of the critical orifice provides a check for critical flowconditions at the orifice.

6.1.1.8 On/off valve. An on/off valve is placed between the critical orifice and the secondpressure gauge, and is used when leak checking the sample train.

6.1.1.9 Flowmeter. A bubble tube flowmeter is used to measure flow at the sampling line tipprior to and after sampling. Alternatively, a dry gas meter may be used.


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Alternative Sampling Apparatus. An equivalent sample gas collection system may be proposedby the tester (e.g., use of a volumetrically calibrated evacuated vessel and controller consisting ofa needle valve and rotameter along with pre- and post-tank temperature and absolute pressuremeasurements, or use of a Volatile Organic Sampling Train [VOST] console with its low-flowcalibrated dry gas meter.)

6.1.1.10 Thermometer - An accurate thermometer is used to measure ambient temperature.

6.1.1.11 Barometer - A barometer is used to measure barometric pressure.

6.1.1.12 Sample storage bottles. Glass (i.e., 40 mL VOA vials) or polyethylene bottles can beused to store the impinger catch sample after stack sampling is complete.

6.1.2 GC/FID analysis apparatus

6.1.2.1 Laboratory glassware. Volumetric pipets, volumetric flasks, autosampler vials, syringes,and cuvettes necessary for standards preparation and analysis.

6.1.2.2 NCASI-recommended gas chromatography system. Gas chromatography/flameionization detector system, complete with a temperature-programmable gas chromatographsuitable for splitless injection and all required accessories including syringes, analytical columnsand gases. Note that we suspect systems with EPC are not designed to handle aqueousinjections, and as a result the FID flame may begin to go out during the runs. This could be dueto the water which builds up in the GC system after several injections on any type of GC. Bakeouts are necessary for any type of GC system, but more frequent bakeouts of a system withEPC may need to be performed.

6.1.2.3 Column - 30 m x 0.53 mm x 1 :m bonded phase DB-WAX fused silica capillary column(J&W Scientific or equivalent); 30 m x 0.32 mm x 0.25 :m bonded phase DB-WAX fused silicacapillary column (J&W Scientific or equivalent); 30 m x 0.53 mm x 3 :m bonded phase DB-624fused silica capillary column (J&W Scientific or equivalent); or other column shown to becapable of separating methanol, acetone, acetaldehyde, methyl ethyl ketone and n-propanol.

6.1.2.4 GC detector - Flame ionization detector with appropriate data system.

7.0 Reagents and Standards

7.1 Water - Deionized water is to be used as the impinger collection liquid, and in thepreparation of all standard and spike solutions.

7.2 Pure compounds - Reagent grade methanol, acetaldehyde, ethanol, formic acid, acetic acid,2-furaldehyde, formaldehyde solution in water (stabilized with methanol) for preparation of


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standard and spike solutions. Be sure to account for the methanol in the formaldehyde solutionwhen calculating spike concentrations.

7.3 GC/FID calibration primary stock solution - Prepare stock solution by diluting 0.126 mL ofpure methanol, 0.128 mL of pure acetaldehyde, 0.073 mL of glacial acetic acid, 0.127 mL of pureethanol, 0.082 mL of pure formic acid, 0.086 mL of pure 2-furaldehyde, and 0.270 ml of 37%formaldehyde solution in 100 ml volumetric flask with DI water (1000 mg/L plus the methanol inthe formaldehyde solution).

7.4 GC/FID calibration and matrix spike solutions - Prepare standard solutions by serialdilutions of the stock solution. The recommended calibration range is 0.5 to 1000 mg/L. It hasbeen found that the linear range can be extended up to 10,000 mg/L. Prepare matrix spikesolutions by calculating the concentration of analytes desired and diluting the primary stocksolution.

7.5 GC/FID internal standard primary spiking solution (if used) - Prepare primary stock solutionby adding 0.312 mL cyclohexanol and diluting to 100 mL with DI water in a 100 mL volumetricflask (3 mg/mL cyclohexanol). Another internal standard material could be used if it isdemonstrated that it does not interfere with the analyte peaks in the chromatogram.

7.6 n-propanol - Prepare a 3% (v/v) n-propanol/water solution for desorption of the analytesfrom the silica gel sorbent tubes.

8.0 Sample Collection, Preservation, Storage, and Transport. Same as Method 18, Sections8.2.4, 8.3, and 8.4.3 with the following additions:

8.1.1 Sample bottle preparation - Determine the number of sample bottles required for thesampling trip. Weigh each bottle and record the pre-sampling weight on the bottle.

8.1.2 Sampling.

8.1.2.1 Measure and record ambient temperature and barometric pressure.

8.1.2.2 Preparation of collection train. Measure 20 mL of DI water into each of the first andsecond impingers and assemble the sampling train.

8.1.2.3 Leak and flow check procedure. Make sure that the on/off valve is in the on position,close the valve to the M-5 train and turn on pump to draw a vacuum. When the vacuum readingis approximately 25 inches of Hg, turn the pump on/off valve to the off position, then record timeand pressure reading on first pressure gauge. A leak is indicated by a flow of bubbles in theimpinger, liquid being drawn into the stem of the impinger or a loss of vacuum. If a leak ispresent, tighten fittings, connections and impingers, and restart the leak check procedure. After 2minutes, record the pressure reading on the first pressure gauge again. The leakage rate should


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not be in excess of 1 inch Hg (vacuum) in 2 minutes. Slowly and carefully open the valve to theM-5 train, and turn the on/off valve back to the on position. If using the critical orificeprocedure, check the flow rate at the probe inlet with a bubble flowmeter. The flow rate shouldbe comparable to the flow rate of the critical orifice with the impingers off-line. Record fivemeasurements of the flow rate and turn off the pump.

8.1.2.4 Sample collection - Insert the probe into the stack and secure it. Start the pump,recording the time and the flow reading on the rotameter. End the sampling after 60 minutes.Record the time and remove the tubing from the vent. Recheck the sample flow rate at the probeinlet and turn off the pump. If the flow rate has changed significantly, redo sampling with freshcapture water. A slight variation (< 5%) in flow can be averaged. With the probe inlet end of theline elevated above the impinges, add about 5 mL of water into the inlet tip to rinse the line intothe first impinger.

8.1.3 Sample recovery - Transfer the contents of the impingers into an appropriately labeled andpre-weighed sample storage bottle. The contents of both impingers can be combined into onebottle. If a large amount of water was collected in the dropout impinger, two bottles can be used. Remove the silica gel tubes from the sampling train, cap ends (tape caps on if necessary), andlabel. Store both impinger and sorbent tube samples in a cooler with ice until they can be storedin a laboratory refrigerator at approximately 4°C.

9.0 Quality Control. Same as Method 18 with the following exception: for the purpose ofdetermining only the Scaling Factor to be used in calculating VOC mass emissions, the spikerequirements of Method 18 may be replaced with an analytical spike set consisting of one lowconcentration and one high concentration spike sample. These alternate spike samples shall beprepared in the field by spiking the first impinger of the sample collection train and drawing ameasured amount of filtered air through the impinger train equivalent to the nominal samplevolume. The spike samples shall be recovered and analyzed using the same procedures as thoseused to recover and analyze the source samples.

10.0 Calibration and Standardization. Obtain calibration standards for each target compoundto be analyzed. Prepare or obtain enough calibration standards so that there are three differentconcentrations of each organic compound expected to be measured in the source sample. Foreach organic compound, select those concentrations that bracket the concentrations expected inthe source samples. A calibration standard may contain more than one organic compound. Prepare or obtain standards in the same solvent used for the sample extraction procedure. Verifythe stability of all standards for the time periods they are used. Analyze each standard intriplicate.

10.1 GC/FID analysis of calibration standards.

10.1.1 Internal standard calibration.


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10.1.1.1 Inject 1 :L of a methanol, acetaldehyde, ethanol, formic acid, acetic acid, and 2-furaldehyde calibration solution containing the internal standard and determine the retention timeof the analytes relative to the internal standard. Each analyst should optimize the temperatureprogram or instrument conditions, as necessary, to establish distinct separate peaks.

10.1.1.2 Calculate the relative response factor for the analytes (RRFM) using Equation 1 (section12.1, below). If the average of the relative response factor for the analytes is constant, i.e.,exhibits a coefficient of variation less than 20%, the calibration is acceptable and the averageRRFM can be used in all subsequent calculations; otherwise, the calibration curve solutions mustbe reanalyzed and reevaluated. It may be necessary to perform instrument maintenance prior toreanalysis. If reanalysis also fails to produce a linear curve, new calibration standards must beprepared and analyzed.

10.1.1.3 Analyze and calculate the relative response factor of a midrange calibration standarddaily, prior to each sample set, using Equation 2 (section 12.2, below) to verify the calibration. The relative response factors must be within an acceptable range. If they are not, either prepare anew standard or perform instrument maintenance. If necessary, re-calibrate the instrument.

10.2.2 External standard calibration

10.2.2.1 Inject 1 :L of a methanol, acetaldehyde, ethanol, formic acid, acetic acid, and 2-furaldehyde calibration solution and determine the retention time of each analyte. Each analystshould optimize the temperature program or instrument conditions, as necessary, to establishdistinct separate peaks.

10.2.2.2 Measure and plot the response of each analyte vs. concentration. If the correlationcoefficient of the graph is greater than 0.99, the calibration is acceptable and the equation of thecurve can be used in all subsequent calculations; otherwise, the calibration curve solutions mustbe reanalyzed and reevaluated. It may be necessary to perform instrument maintenance prior toreanalysis. If reanalysis also fails to produce a correlated curve, new calibration standards mustbe prepared and analyzed.

10.2.2.3 Analyze and calculate the concentration of a mid-range calibration standard daily, priorto each sample set, to verify the calibration. The recovery should be between 70 and 130%. If itis not, either prepare a new standard or perform instrument maintenance. If necessary, re-calibrate the instrument.

10.3 Analytical range and minimum calibration level

10.3.1 Demonstrate that the calibration curve is acceptable (relative response factors exhibit acoefficient of variation less than 20%, or correlation coefficient greater than 0.99) throughout therange of the calibration curve.


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10.3.2 Demonstrate that the analytes are detectable at the minimum levels using the lowest levelcalibration curve solution.

11.0 Analytical Procedures.

11.1 Preparation of impinger samples. Remove bottles from refrigerator. Weigh the samplebottles and record weights on the bottle. Transcribe initial and final bottle weight to sample fielddata sheet. Bottles do not need to be at room temperature before weighing. Remove an aliquotof sample and place in the sampler vial, add 10 :L of internal standard solution (if using internalstandard calibration curve), and cap vial.

11.2 Preparation of sorbent tube samples. Remove sorbent tubes from refrigerator. Remove endcaps and score glass to remove the silica gel from one section. All sections of the silica gel tubescan be combined and analyzed together. This is considered the “back half” of the samplecollection train. Pour into a 4.0 mL screw-capped vial and add 3.0 mL of a 3% (v/v) n-propanol/water desorption solution. Allow to sit for 30 minutes, with occasional light shaking. Vigorous shaking causes the silica gel particles to adhere to the cap and walls of the vial. Remove an aliquot of the desorption solution and place in an autosampler vial. Add 10 :L ofinternal standard solution (if using internal standard calibration curve) and cap vial.

11.3 GC/FID analysis. Analysis is performed by direct aqueous injection into the GC/FID.Representative conditions for the GC/FID analysis are given in Tables 1, 2 and 3 (section 18,below). Other chromatographic columns and conditions may be used if it has been establishedthat the compounds are separated and quality control parameters are met. Once the GC/FIDsystem is optimized for analytical separation and sensitivity, the sample operating conditionsmust be used to analyze all samples, blanks, calibration standards and quality assurance samples. Note that constant injections of aqueous samples can cause water to build up in the system. Thiswill cause the retention times to shift, and the peaks to broaden. It is recommended that afterapproximately 50 injections a bakeout of the system be performed. This should consist ofheating the injector to 250°C, the oven to over 200°C and the detector to 275°C for at leastseveral hours.

12.0 Data Analysis and Calculations. Same as Method 18 Sections 12.7 -12.9 with thefollowing additions:

12.1 Relative Response Factor. Calculate the relative response factor (RRFM using the followingequation.

Equation 1

Where:AM = area of analyte peak


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AIS = area of internal standard peakCM = concentration of analyte injected CIS = concentration of internal standard injected

12.2 Calibration Verification. Calculate the concentration of the midrange standard using thefollowing equation.

Equation 2

Where:AM = Area of the analyte peakCIS = Concentration of the internal standard (mg/L)AIS = Area of the internal standard peakRRFM = Relative response factor of analyte

13.0 Method Performance. Same as Method 18.

14.0 Pollution Prevention. [Reserved]

15.0 Waste Management. [Reserved]

16.0 Alternative Procedures. [Reserved]

17.0 References. Same as Method 18 with the following addition:17.1 National Council for Air and Stream Improvement, Inc. (NCASI). Methods Manual -NCASI Method CI/SG/PULP-94.02 Chilled Impinger/silica Gel Tube Test Method at PulpMill Sources for Methanol, Acetone, Acetaldehyde, Methyl Ethyl Ketone and Formaldehyde. National Council for Air and Stream Improvement, Inc.. Research Triangle Park, N.C. 1998.

18.0 Tables, Diagrams, Flowcharts, and Validation Data.

Table 1: GC/FID Operating Conditions for Methanol, Acetaldehyde, Acetone and MethylEthyl Ketone Analysis-DB-WAX ColumnInjection: DirectInjector Temperature: 150°CInjection Volume: 1 :LFID Detector Temperature: 250°CCarrier Gas: HeliumColumn: DB-WAX, 30 m x 0.53 mm id x 1 micronfused silica capillary columnTemperature Program °C:


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Initial: 18vC for 8 minRamp 1: 3°C/min to 20°C for 2 minutesRamp 2: 50°C/min to 220°CRamp 3: [deliberately blank]Final Hold Time: 5 minutesRetention Time Order: acetaldehyde, acetone, methyl ethyl ketone,methanol, n-propanol, cyclohexanol

Table 2: GC/FID Operating Conditions for Methanol, Acetaldehyde, Acetone and MethylEthyl Ketone Analysis-DB-WAX ColumnInjection: DirectInjector Temperature: 170°CInjection Volume: 1 :LFID Detector Temperature: 275°CCarrier Gas: HeliumColumn: DB-WAX, 30 m x 0.32 mm id x 0.25 micronfused silica capillary columnTemperature Program °C:Initial: 0°C for 3 minRamp 1: 5°C/min to 50°C for 4 minutesRamp 2: 70°C/min to 100°C for 10 minRamp 3: 70°C/min to 200°CFinal Hold Time: 4 minutesRetention Time Order: acetaldehyde, acetone, methyl ethyl ketone,methanol, n-propanol, cyclohexanol

Table 3: GC/FID Operating Conditions for Methanol, Acetaldehyde, Acetone and MethylEthyl Ketone Analysis-DB-624 ColumnInjection: DirectInjector Temperature: 170°CInjection Volume: 1 :LFID Detector Temperature: 275°CCarrier Gas: HeliumColumn: DB-624, 30 m x 0.53 mm id x 3 micronfused silica capillary columnTemperature Program °C:Initial: 0°C for 3 minRamp 1: 5°C/min to 50°C for 0 minutesRamp 2: 70°C/min to 105°C for 17 minRamp 3: 70°C/min to 220°CFinal Hold Time: 3 minutesRetention Time Order: acetaldehyde, methanol, acetone, n-propanol,methyl ethyl ketone, cyclohexanol


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Appendix CAnalysis of Method 18 Samples for Formaldehyde

1.0 Scope and Application. Same as Appendix B with the following addition: The stability of formaldehyde was found to be 21 days, with refrigeration at approximately 4°C.

2.0 Summary of Method. This method contains procedures for analyzing the samples collected by the Method 18procedure described in Appendix B for formaldehyde. To analyze for formaldehyde, theacetylacetone derivatization/spectrophotometric analysis method is used on an aliquot of theimpinger solution collected according to Appendix B.

3.0 Definitions. Same as Appendix B.

4. Interferences. Same as Appendix B with the following addition:

Interferences with the formaldehyde analysis can be caused by the presence of sulfur compounds(i.e. SO2) in the source gas.

5.0 Safety. Same as Appendix B.

6.0 Equipment and Supplies. Same as Appendix B with the following addition:

6.1. Formaldehyde analysis apparatus

6.1.1 Spectrophotometer - A spectrophotometer capable ofmeasuring absorbance at 412 nm.

7.0 Reagents and Standards.

7.1 Water. Deionized water is to be used as the impinger collection liquid, and in thepreparation of all standard and spike solutions.

7.2 Pure compound. Reagent grade 37% formaldehyde solution (formalin) for preparation ofstandard and spike solutions.

7.3 Acetylacetone reagent. Prepare by dissolving 15.4 g of ammonium acetate in about 50 mLof DI water in a 100 mL volumetric flask. Add 0.20 mL of acetylacetone to this solution, alongwith 0.30 mL of glacial acetic acid. Mix thoroughly and dilute to 100 mL with DI water. Storereagent in a brown glass bottle in the refrigerator. Reagent is stable for at least two weeks.

7.4 Formaldehyde analysis primary stock solution. Prepare stock solution by diluting 2.7 mL offormalin in a 1000 mL volumetric flask with DI water (1000 mg/L formaldehyde).


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7.4.1 Formaldehyde analysis calibration standard solution. Prepare standard solution by diluting1.0 mL of primary stock solution in a 100 mL volumetric flask with DI water (10 mg/Lformaldehyde).

8.0 Sample Collection, Preservation, Storage, and Transport. The sample is collectedaccording to the procedures in Appendix B.

9.0 Quality Control. Each field sampling program or laboratory that uses this method isrequired to operate a formal quality assurance program. Laboratory or field performance iscompared to established criteria to determine if the results of analyses meet the performancecriteria of the method.

9.1 Field blank samples. A field blank sample of water must be prepared to assure that the waterbeing used in the impingers is not contaminated. It is made in the field by filling a 40 mLVOA vial or polyethylene bottle with the same water being used to fill the impingers.

9.2 Field spike sample. A field spike sample should be prepared by spiking the impinger with aknown amount of analyte before sampling. The spike solution described in Appendix A shouldbe used for this purpose. After the impinger is spiked, a sample bottlecontaining DI water should also be spiked. This provides a check of the spiking solution andspiking procedure. The impinger spiking may be done on a duplicate sampling train ifthe equipment is available or may be done during a normal sampling run. This type of spiking isperformed when a check of the complete sampling procedure, sample storage and sampleanalysis is desired.

9.3 Laboratory blank sample. A laboratory blank sample should be analyzed with each batch ofsamples. A batch is considered no more than 10 samples of similar matrix type.

9.4 Laboratory duplicates. A replicate injection of one sample in the analytical batch should beperformed. The results of the duplicate analysis should be within 10% of the mean of theoriginal and duplicate sample analysis.

9.5 Laboratory matrix spike samples. A laboratory matrix spike sample may be prepared witheach group of similar matrix type. Using the mean concentration determined by the replicateanalyses or the background level determined from a single measurement, determine the spikinglevel which will give one to four times the background. If the background sample doesnot have detectable levels of analytes, spike the sample at approximately five times the lowestcalibration level of the instrument. Spike the sample with the determined amount ofthe calibration standard/matrix spike solution and proceed to analyze the sample in the normalmanner. The results can be considered acceptable if the calculated spike recovery is 70 to130%. In cases where multiple analytes are present, the analyte with the highest concentrationshould govern the acceptance criteria.


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10.0 Calibration and Standardization.

10.1 Formaldehyde analysis calibration solutions. A series of calibration standards are madefrom the standard solution (Section 7.1.4.1) by adding 0, 0.1, 0.2, 0.4, 1.0 and 1.5 mL of thestandard solution to individual screw-capped vials. The volume in each vial is adjusted to 2.0mL with DI water. This corresponds to 0, 0.5, 1, 2, 5 and 7.5 mg/L calibration solutions. Toeach vial, 2.0 mL of the acetylacetone reagent is added, and the procedure described in Section11.1 is then followed.

11.0 Analytical Procedures.

11.1 Formaldehyde sample analysis. Remove a 2.0 mL aliquot of the impinger sample andtransfer to a screw-capped vial. Add 2.0 mL of the acetylacetone reagent and mix thoroughly.Place vial in a water bath at 60/C for 10 minutes. Allow vials to cool to room temperature. Transfer the solution to a cuvette and measure the absorbance at 412 nm. If the sample solutionconcentration is above the calibration curve, dilute original sample and repeat entire procedure. Do not dilute colored (derivitized) samples.12.0 Data Analysis and Calculations.

13.0 Method Performance. [Reserved]

14.0 Pollution Prevention. [Reserved]

15.0 Waste Management. [Reserved]

16.0 Alternative Procedures. [Reserved]

17.0 References. Same as Appendix B.

18.0 Tables, Diagrams, Flowcharts, and Validation Data. [Reserved]