AIR EMISSION PERMIT NO. 10900008- 001 IS ISSUED TO Mayo ... · PDF fileAIR EMISSION PERMIT NO. 10900008- 001 IS ISSUED TO Mayo Foundation for Saint Marys 1216 Southwest 2nd Street

TDD (for hearing and speech impaired only): (651) 282-5332 Printed on recycled paper containing at least 10% fibers from paper recycled by consumers

AIR EMISSION PERMIT NO. 10900008- 001

IS ISSUED TO

Mayo Foundation for

Saint Marys 1216 Southwest 2nd Street

Rochester, Olmsted County, MN 55902 The emission units, control equipment and emission stacks at the stationary source authorized in this permit are as described in the following permit applications: Permit Type Application Date Total Facility Operating Permit December 15, 1995,

updated December 9, 2002 This permit authorizes the Permittee to operate the stationary source at the address listed above unless otherwise noted in Table A. The Permittee must comply with all the conditions of the permit. Any changes or modifications to the stationary source must be performed in compliance with Minn. R. 7007.1150 to 7007.1500. Terms used in the permit are as defined in the state air pollution control rules unless the term is explicitly defined in the permit. Permit Type: Federal; Pt 70/Major for NSR Issue Date: July 23, 2003 Expiration: July 23, 2008 All Title I Conditions do not expire. Ann M. Foss Major Facilities Section Manager Majors and Remediation Division for Sheryl A. Corrigan Commissioner Minnesota Pollution Control Agency

TABLE OF CONTENTS

Notice to the Permittee Permit Shield Facility Description Table A: Limits and Other Requirements Table B: Submittals Table C: not used in this permit Appendix A: not used in this permit Appendix B: Modeled Parameters (SO2) Appendix C: Insignificant Activities Required to be Listed

NOTICE TO THE PERMITTEE:

Your stationary source may be subject to the requirements of the Minnesota Pollution Control Agency’s (MPCA) solid waste, hazardous waste, and water quality programs. If you wish to obtain information on these programs, including information on obtaining any required permits, please contact the MPCA general information number at:

Metro Area (651) 296-6300

Outside Metro Area 1-800-657-3864

TTY (651) 282-5332

The rules governing these programs are contained in Minn. R. chs. 7000-7105. Written questions may be sent to: Minnesota Pollution Control Agency, 520 Lafayette Road North, St. Paul, Minnesota 55155-4194.

Questions about this air emission permit or about air quality requirements can also be directed to the telephone numbers and address listed above. PERMIT SHIELD:

Subject to the limitations in Minn. R. 7007.1800, compliance with the conditions of this permit shall be deemed compliance with the specific provision of the applicable requirement identified in the permit as the basis of each condition. Subject to the limitations of Minn. R. 7007.1800 and 7017.0100, subp. 2, notwithstanding the conditions of this permit specifying compliance practices for applicable requirements, any person (including the Permittee) may also use other credible evidence to establish compliance or noncompliance with applicable requirements. FACILITY DESCRIPTION:

St. Marys is a tertiary care hospital which includes several buildings located on a 49 acre campus. The primary emission units at the facility are three identical boilers which exhaust through a common stack, one cogeneration turbine, and two emergency generators. Each boiler combusts natural gas with distillate fuel as backup. The cogeneration turbine burns only natural gas. One generator burns only distillate oil; the other can burn distillate oil or a mixture of natural gas and distillate oil (dual fuel).

While St. Marys is owned and operated by the Mayo Foundation, it is not contiguous with the majority of the Mayo facilities in Rochester, and thus is a separate source under the New Source Review and Part 70 regulations. This permit is a Part 70 operating permit. The facility is an existing major source under New Source Review. No modifications are approved through this permit. The facility is not a major source of HAP emissions.

The facility is located in an area that was previously designated as non-attainment for SO2. However, the area currently meets the ambient air quality standards, and was officially redesignated as “attainment” on May 8, 2001. The facility has been subject to a federally enforceable permit (part of Minnesota’s state implementation plan, or SIP, for attaining ambient air quality standards) containing requirements contributing to the correction of the non-attainment problem and the ultimate redesignation. The requirements of that permit have been incorporated into this permit as non-expiring Title I conditions. This permit will ultimately replace the existing permit and be incorporated into the SIP (separately from the permit issuance process).

TABLE A: LIMITS AND OTHER REQUIREMENTS 07/23/03

St Marys

10900008 - 001

Facility Name:

Permit Number:

Table A contains limits and other requirements with which your facility must comply. The limits are located in the first column ofthe table (What To do). The limits can be emission limits or operational limits. This column also contains the actions that you musttake and the records you must keep to show that you are complying with the limits. The second column of Table A (Why to do it)lists the regulatory basis for these limits. Appendices included as conditions of your permit are listed in Table A under total facilityrequirements.

Subject Item: Total Facility

What to do Why to do itSITE-SPECIFIC REQUIREMENTS hdr

Parameters Used in Modeling: The stack parameters used in the most recentlyapproved modeling are listed in Appendix B of this permit. Before making anyphysical changes or changes in the method of operation which may affectparameters listed in Appendix B, the Permittee shall demonstrate to the MPCA thatthe SO2 plume dispersion characteristics following the physical change or changein method of operation will be equivalent to or better than the SO2 dispersioncharacteristics modeled using the parameters in Appendix B. The informationsubmitted must include, at a minimum, the locations, heights, and diameters of thestacks, locations and dimensions of nearby buildings, the velocity and temperatureof the gasses emitted, and the SO2 emission rates.

Title I Condition: SIP for SO2 NAAQS, 40 CFR pt. 50,and MN State Implementation Plan

If the information does not demonstrate equivalent or better dispersioncharacteristics, or if a conclusion cannot readily be made about the dispersion, thePermittee must remodeled.

For changes that do not involve an increase in SO2 emission rates and that do notrequire a permit amendment, this proposal must be submitted as soon aspracticable, but no less than 60 days before beginning actual construction of thestack or associated emission unit.

For changes involving an increase in SO2 emission rates and that require a minorpermit amendment, the proposal must be submitted as soon as practicable, but noless than 60 days before beginning actual construction of the stack or associatedemission unit.

For changes involving an increase in SO2 emission rates and that require a permitamendment other than a minor amendment, the proposal must be submitted withthe permit application.

Title I Condition: SIP for SO2 NAAQS, 40 CFR pt. 50,and MN State Implementation Plan (continued fromabove)

Deviations from requirements cited as "Title I Condition: State Implementation Planfor SO2" shall be reported semiannually with the Semiannual Deviations Reportrequired by this permit (See Table B). Reporting for these conditions shall occureven if there were no deviations for the reporting period.


The facility currently uses ozone-depleting substances as defined in 40 CFR pt. 82.Sections 601-618 of the 1990 Clean Air Act Amendments and 40 CFR pt. 82 mayapply to your facility. Read Sections 601-618 and 40 CFR pt. 82 to determine allthe requirements that apply to your facility.

40 CFR pt. 82

OPERATIONAL REQUIREMENTS hdr

Circumvention: Do not install or use a device or means that conceals or dilutesemissions, which would otherwise violate a federal or state air pollution control rule,without reducing the total amount of pollutant emitted.

Minn. R. 7011.0020

Operation Changes: In any shutdown, breakdown, or deviation the Permittee shallimmediately take all practical steps to modify operations to reduce the emission ofany regulated air pollutant. The Commissioner may require feasible and practicalmodifications in the operation to reduce emissions of air pollutants. No emissionsunits that have an unreasonable shutdown or breakdown frequency of process orcontrol equipment shall be permitted to operate.

Minn. R. 7019.1000, subp. 4

Fugitive Emissions: Do not cause or permit the handling, use, transporting, orstorage of any material in a manner which may allow avoidable amounts ofparticulate matter to become airborne. Comply with all other requirements listed inMinn. R. 7011.0150.

Minn. R. 7011.0150

Noise: The Permittee shall comply with the noise standards set forth in Minn. R.7030.0010 to 7030.0080 at all times during the operation of any emission units.This is a state only requirement and is not enforceable by the EPA Administrator orcitizens under the Clean Air Act.

Minn. R. 7030.0010 - 7030.0080

Inspections: The Permittee shall comply with the inspection procedures andrequirements as found in Minn. R. 7007.0800, subp. 9(A).

Minn. R. 7007.0800, subp. 9(A)

The Permittee shall comply with the General Conditions listed in Minn. R.7007.0800, subp. 16.

Minn. R. 7007.0800, subp. 16

RECORDKEEPING hdr

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Facility Name:

Permit Number:

Record keeping: Retain all records at the stationary source for a period of five (5)years from the date of monitoring, sample, measurement, or report. Records whichmust be retained at this location include all calibration and maintenance records, alloriginal recordings for continuous monitoring instrumentation, and copies of allreports required by the permit. Records must conform to the requirements listed inMinn. R. 7007.0800, subp. 5(A).

Minn. R. 7007.0800, subp. 5(C)

Recordkeeping: Maintain records describing any insignificant modifications (asrequired by Minn. R. 7007. 1250, subp. 3) or changes contravening permit terms(as required by Minn. R. 7007.1350 subp. 2), including records of the emissionsresulting from those changes.

Minn. R. 7007. 0800, subp. 5(B)

REPORTING/SUBMITTALS hdr

Shutdown Notifications: Notify the Commissioner at least 24 hours in advance of aplanned shutdown of any control equipment or process equipment if the shutdownwould cause any increase in the emissions of any regulated air pollutant. If theowner or operator does not have advance knowledge of the shutdown, notificationshall be made to the Commissioner as soon as possible after the shutdown.However, notification is not required in the circumstances outlined in Items A, Band C of Minn. R. 7019.1000, subp. 3.

At the time of notification, the owner or operator shall inform the Commissioner ofthe cause of the shutdown and the estimated duration. The owner or operator shallnotify the Commissioner when the shutdown is over.

Minn. R. 7019.1000, subp. 3

Breakdown Notifications: Notify the Commissioner within 24 hours of a breakdownof more than one hour duration of any control equipment or process equipment ifthe breakdown causes any increase in the emissions of any regulated air pollutant.The 24-hour time period starts when the breakdown was discovered or reasonablyshould have been discovered by the owner or operator. However, notification is notrequired in the circumstances outlined in Items A, B and C of Minn. R. 7019.1000,subp. 2.

At the time of notification or as soon as possible thereafter, the owner or operatorshall inform the Commissioner of the cause of the breakdown and the estimatedduration. The owner or operator shall notify the Commissioner when thebreakdown is over.

Minn. R. 7019.1000, subp. 2

Notification of Deviations Endangering Human Health or the Environment: As soonas possible after discovery, notify the Commissioner or the state duty officer, eitherorally or by facsimile, of any deviation from permit conditions which could endangerhuman health or the environment.

Minn. R. 7019.1000, subp. 1

Notification of Deviations Endangering Human Health or the Environment Report:Within 2 working days of discovery, notify the Commissioner in writing of anydeviation from permit conditions which could endanger human health or theenvironment. Include the following information in this written description:1. the cause of the deviation;2. the exact dates of the period of the deviation, if the deviation has been corrected;3. whether or not the deviation has been corrected;4. the anticipated time by which the deviation is expected to be corrected, if not yetcorrected; and5. steps taken or planned to reduce, eliminate, and prevent reoccurrence of thedeviation.

Minn. R. 7019.1000, subp. 1

Application for Permit Amendment: If a permit amendment is needed, submit anapplication in accordance with the requirements of Minn. R. 7007.1150 throughMinn. R. 7007.1500. Submittal dates vary, depending on the type of amendmentneeded.

Minn. R. 7007.1150 through Minn. R. 7007.1500

Extension Requests: The Permittee may apply for an Administrative Amendmentto extend a deadline in a permit by no more than 120 days, provided the proposeddeadline extension meets the requirements of Minn. R. 7007.1400, subp. 1(H).

Minn. R. 7007.1400, subp. 1(H)

Emission Inventory Report: due 91 days after end of each calendar year followingpermit issuance (April 1). To be submitted on a form approved by theCommissioner.

Minn. R. 7019.3000 through Minn. R. 7019.3100

Emission Fees: due 60 days after receipt of an MPCA bill. Minn. R. 7002.0005 through Minn. R. 7002.0095

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Facility Name:

Permit Number:

Subject Item: GP 001 Boilers

Associated Items: EU 001 Boiler 1

EU 002 Boiler 2

EU 003 Boiler 3

What to do Why to do itEmission and Operating Limits hdr

Fuel Used: The Permittee shall burn only natural gas or very low sulfur oil, asdefined in 40 CFR Section 60.41b.


Sulfur Content of Fuel: less than or equal to 0.5 percent by weight (very low sulfuroil, as defined in 40 CFR Section 60.41b)

Title I Condition: SIP for SO2 NAAQS, 40 CFR pt. 50,and MN State Implementation Plan; 40 CFR Section60.42b(j); Minn. R. 7011.0565

Nitrogen Oxides: less than or equal to 0.10 lbs/million Btu heat input using 30-dayRolling Average . This standard applies at all times.

40 CFR Section 60.44b(a); 40 CFR Section 60.46b(a);Minn. R. 7011.0565

Opacity: less than or equal to 20 percent opacity using 6-minute Average , exceptfor one 6-minute period per hour of not more than 27 percent opacity. Thisstandard applies at all times except during periods of startup, shutdown, ormalfunction.

40 CFR Section 60.43b(f) and (g); 40 CFR Section60.46b(a); Minn. R. 7011.0565

Monitoring Requirements hdr

Sulfur Content of Fuel Oil: The Permittee shall obtain and maintain a fuel supplierreceipt from the fuel oil supplier for each shipment of oil received, certifying that theoil meets the definition of very low sulfur oil as defined in 40 CFR Section 60.41b.

The Permittee shall ensure that the fuel supplier uses an approved AmericanSociety of Testing and Materials (ASTM) method to determine the sulfur content ofliquid fuels.

Title I Condition: SIP for SO2 NAAQS, 40 CFR pt. 50,and MN State Implementation Plan; 40 CFR Section60.42b(j)(2); Minn. R. 7011.0565

NOx Emissions: The Permittee shall calibrate, maintain, and operate a continuousemission monitoring system (CEMS), and record the output of the system, formeasuring NOx emissions discharged to the atmosphere. As allowed by 40 CFR60.13(g), the Permittee operates one CEMS in the common duct for the threeboilers.

The CEMS shall be operated and data recorded during all periods of operation ofthe boilers, except for CEMS breakdowns and repairs. Data is recorded duringcalibration checks, and zero and span adjustments.

The 1-hour average NOx emission rates measured by the CEMS shall beexpressed in lb/million Btu heat input, and shall be used to calculate the averageemission rates. At least 2 data points must be used to calculate each 1-houraverage.

[For additional monitoring requirements, see Subject Item MR001.]

40 CFR Section 60.48b(b)(1), (c), and (d); 40 CFRSection 60.13(g); Minn. R. 7011.0565

When NOx emissions data are not obtained because of CEMs breakdowns orrepairs, data will be obtained by using standby monitoring systems, Method 7 or7A, or other approved reference methods to provide data for a minimum of 75% ofthe operating hours in each steam generating unit operating day, in at least 22 outof 30 successive steam generating unit operating days.

40 CFR Section 60.48b(f); Minn. R. 7011.0565

Opacity: The Permittee shall calibrate, maintain, and operate a continuousmonitoring system for measuring the opacity of emissions discharged to theatmosphere, and record the output of the system.

As allowed by 40 CFR 60.13(g), the Permittee operates one COMS in the commonduct for the three boilers.

[For additional monitoring requirements, see Subject Item MR003.]

40 CFR Section 60.48b(a); 40 CFR Section 60.13(g);Minn. R. 7011.0565

Testing Requirements hdr

Upon request, the Permittee shall use a 30-day performance test to determinecompliance with the NOx standard. During periods when performance tests are notrequested, NOx emission data collected via the CEM shall be used to calculate a30-day rolling average emission rate on a daily basis and used to prepare excessemission reports, but will not be used to determine compliance with the NOxemission standard. A new 30-day rolling average emission rate is calculated eachsteam generating unit operating day as the average of all of the hourly NOxemission data for the preceding 30 steam generating unit operating days.

40 CFR Section 60.46b(e)(4); Minn. R. 7011.0565

Recordkeeping and Reporting Requirements hdr

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Facility Name:

Permit Number:

The Permittee shall record and maintain records of the amounts of each fuelcombusted each day and calculate the annual capacity factor individually fordistillate oil and natural gas. The annual capacity factor is determined on a12-month rolling average basis with a new annual capacity factor calculated at theend of each calendar month.

40 CFR Section 60.49b(d); Minn. R. 7011.0565

The Permittee shall maintain records of opacity. 40 CFR Section 60.49b(f); Minn. R. 7011.0565

The Permittee shall maintain records of the following information for each steamgenerating unit operating day:(1) Calendar date.(2) The average hourly NOx emission rates (expressed as NO2), in lb/million Btuheat input.(3) The 30-day average NOx emission rates calculated at the end of each steamgenerating unit operating day.(4) Identification of the steam generating unit operating days when the calculated30-day average NOx emission rates are in excess of the NOx emission standard,including the reasons for the excess emissions and a description of correctiveactions taken.(5) Identification of the steam generating unit operation days for which data havenot been obtained including reasons for not obtaining sufficient data and adescription of corrective actions taken.(6) Identification of the times when emission data have been excluded from thecalculation of average emission rates and the reasons for excluding data.

40 CFR Section 60.49b(g); Minn. R. 7011.0565

(7) Identification of "F" factor used for calculations, method of determination, andtype of fuel combusted.(8) Identification of the times when the pollutant concentration exceeded full spanof the CEMS.(9) Description of any modifications to the CEMS that could affect the ability of theCEMS to comply with Performance Specification 2 or 3.

continued from above

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Facility Name:

Permit Number:

Subject Item: GP 002 Boilers and Generators

Associated Items: EU 001 Boiler 1

EU 002 Boiler 2

EU 003 Boiler 3

EU 004 Generator 5

EU 005 Generator 6

What to do Why to do itEmission Limits hdr

Sulfur Dioxide: less than or equal to 65.56 tons/year using 12-month Rolling Sumcalculated monthly, as described below.

Title I Condition: To avoid major source classificationunder 40 CFR Section 52.21 and Minn. R. 7007.3000(limit originally set 3/27/91)

Monitoring and Recordkeeping Requirements hdr

Daily recordkeeping: Each day, record the total quantity of each type of fuel burned,and the sulfur content by weight of fuel oil in the tank from which oil is drawn onthat day.

Title I Condition: To avoid major source classificationunder 40 CFR Section 52.21 and Minn. R. 7007.3000

Monthly Recordkeeping: SO2 Emissions

By the 15th day of each month, calculate and record the following:

a. The total quantity of natural gas used in the GP002 units during the previousmonth (G), in million cubic feet

b. The total quantity of sulfur contained in distillate oil used in the GP002 unitsduring the month (S), in pounds, calculated by multiplying the gallons of oil withsulfur content "x" by "x" and the density of the oil (pounds/gallon), plus the gallonsof oil with sulfur content "y" by "y" and the density of the oil, etc.

c. The SO2 emissions for the previous months (E), in tons, using the followingequation: E = 0.001 S + 0.0003 G, where: 0.001 = [(2 pounds of SO2/pound ofsulfur) x (1 ton/2000 pounds)] and 0.0003 = [(0.6 pounds of SO2/million cubic feetof natural gas) x (1 ton/2000 pounds)]

The 12-month rolling sum is calculated by summing the values of "E" calculated forthe previous 12 months.

Minn. R. 7007.0800, subp. 4 and 5

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Facility Name:

Permit Number:

Subject Item: EU 004 Generator 5

Associated Items: GP 002 Boilers and Generators

SV 002 No. 5 Generator Stack


Fuel: The Permittee shall burn only distillate oil in the generator. Title I Condition: SIP for SO2 NAAQS, 40 CFR pt. 50,and MN State Implementation Plan

Sulfur Content of Fuel: less than or equal to 0.41 percent by weight Title I Condition: SIP for SO2 NAAQS, 40 CFR pt. 50,and MN State Implementation Plan

Opacity: less than or equal to 20 percent opacity once operating temperatures havebeen attained

Minn. R. 7011.2300, subp. 1


Fuel Oil Sulfur Content: The Permittee shall determine the sulfur content usingeither Method 1 or Method 2:

Method 1: The Permittee shall obtain and maintain a fuel supplier receipt for eachshipment of distillate fuel oil delivered, certifying that the shipment complies withthe ASTM specifications for distillate fuel oil, and that the sulfur content is less thanor equal to 0.41% by weight as determined by ASTM method D 1552 or inaccordance with the current ASTM method.

Method 2: The Permittee shall calculate and record the sulfur content of the fuel oilin each tank which supplies fuel to the emergency generators after each delivery offuel oil to the tank. The following steps shall be taken:


a) The Permitee shall sample fuel oil from the tank(s) prior to the initial delivery offuel oil when using this method. Sampling of each tank shall be conducted at leastonce per calendar year for any calendar year in which this method is used. ThePermitee shall analyze the oil sample to determine the sulfur content of the fuel oilin percent by weight in accordance with ASTM method D1552 or with the currentASTM method. The percent sulfur of the sample shall be used as "A(P)" whendetermining the average percent sulfur using the equation below.

b) Before the end of the following business day after each fuel delivery to a tankwhich supplies fuel oil to the emergency generator, the Permittee shall calculate themaximum percent sulfur of the fuel oil using the following equation:


A(N) = [{A(P) x V(P)} + {(S(D) x V(D)}] / V(N)

Where:A(N) = the new average sulfur content of the tankA(P) = the previously calculated average sulfur content of the tankV(P) = the previously calculated volume of oil in the tankS(D) = the sulfur content of the oil deliveryV(D) = the volume of oil deliveredV(N) = the new volume of oil in the tank = V(P) + V(D) - total quantity of oil burnedsince V(P) was calculated


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Facility Name:

Permit Number:

Subject Item: EU 005 Generator 6

Associated Items: GP 002 Boilers and Generators

SV 003 No. 6 Generator Stack


Fuel: The Permittee shall burn only natural gas or distillate oil in the generator. Title I Condition: SIP for SO2 NAAQS, 40 CFR pt. 50,and MN State Implementation Plan

Sulfur Content of Fuel: less than or equal to 0.41 percent by weight (applies todistillate oil only)


Opacity: less than or equal to 20 percent opacity once operating temperatures havebeen attained

Minn. R. 7011.2300, subp. 1

Operating Hours: less than or equal to 1040 hours/year using 12-month RollingSum

Title I Condition: To avoid classification as a majormodification under 40 CFR Section 52.21 and Minn. R.7007.3000.


Fuel Oil Sulfur Content: The Permittee shall determine the sulfur content usingeither Method 1 or Method 2:

Method 1: The Permittee shall obtain and maintain a fuel supplier receipt for eachshipment of distillate fuel oil delivered, certifying that the shipment complies withthe ASTM specifications for distillate fuel oil, and that the sulfur content is less thanor equal to 0.41% by weight as determined by ASTM method D 1552 or inaccordance with the current ASTM method.

Method 2: The Permittee shall calculate and record the sulfur content of the fuel oilin each tank which supplies fuel to the emergency generators after each delivery offuel oil to the tank. The following steps shall be taken:


a) The Permitee shall sample fuel oil from the tank(s) prior to the initial delivery offuel oil when using this method. Sampling of each tank shall be conducted at leastonce per calendar year for any calendar year in which this method is used. ThePermitee shall analyze the oil sample to determine the sulfur content of the fuel oilin percent by weight in accordance with ASTM method D1552 or with the currentASTM method. The percent sulfur of the sample shall be used as "A(P)" whendetermining the average percent sulfur using the equation below.

b) Before the end of the following business day after each fuel delivery to a tankwhich supplies fuel oil to the emergency generator, the Permittee shall calculate themaximum percent sulfur of the fuel oil using the following equation:


A(N) = [{A(P) x V(P)} + {(S(D) x V(D)}] / V(N)

Where:A(N) = the new average sulfur content of the tankA(P) = the previously calculated average sulfur content of the tankV(P) = the previously calculated volume of oil in the tankS(D) = the sulfur content of the oil deliveryV(D) = the volume of oil deliveredV(N) = the new volume of oil in the tank = V(P) + V(D) - total quantity of oil burnedsince V(P) was calculated


Recordkeeping - Hours of Operation: By the 15th day of each month, calculate andrecord the hours the generator was operated during the previous month, and thetotal hours operated during the previous 12 months.

Title I Condition: To avoid classification as a majormodification under 40 CFR Section 52.21 and Minn. R.7007.3000.

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Facility Name:

Permit Number:

Subject Item: EU 006 Turbine Engine

Associated Items: SV 004 Cogeneration Turbine Stack

What to do Why to do itEmission Limits and Operating Requirements hdr

Nitrogen Oxides: less than or equal to 190 parts per million at 15% O2, on a drybasis

40 CFR Section 60.332(a)(2); Minn. R. 7011.2350

Sulfur Content of Fuel: less than or equal to 0.8 percent by weight 40 CFR Section 60.333(b); Minn. R. 7011.2350

Monitoring Requirements hdr

Custom Sulfur Monitoring Schedule: (A) Sulfur monitoring shall be conducted twicemonthly (bi-weekly) for six (6) months. If the monitoring shows little variability in thefuel sulfur content, and indicates consistent compliance with 40 CFR Section60.333(b), then sulfur monitoring shall be conducted once per calendar quarter.

(B) Conduct fuel sulfur content monitoring once per quarer for six (6) quarters. Ifquarterly monitoring shows little variability in the fuel sulfur content, and indicatesconsistent compliance with the 40 CFR Section 60.333(b), the fuel sulfur contentmonitoring frequency may be reduced to a semi-annual basis (first and thirdquarters of the calendar year).

40 CFR Section 60.334(b)(2); Minn. R. 7011.2350;EPA guidance memo dated August 14, 1987; EPAapproval memo dated May 2, 2003

Determination of Sulfur Content: ASTM D 1072-80 or 90 (Reapproved 1994), D3031-81, D 4084-82 or 94, or D 3246-81, 92, or 96 shall be used to determine thesulfur content of gaseous fuels.

Upon written approval of U.S. EPA, the following alternative method may be usedto determine the sulfur content of pipeline natural gas: Gas Processors Association(GPA) Standard Method 2377-86, "Test for Hydrogen Sulfide and Carbon Dioxidein Natural Gas Using Length of Stain Tubes." The Permittee will use two length ofstain tubes for each sample: one to detect hydrogen sulfide and one to detectmercaptans.

40 CFR Section 60.335(d); Minn. R. 7011.2350

Custom Nitrogen Monitoring Schedule: The requirement to monitor the nitrogencontent of the fuel is waived, provided only pipeline quality natural gas iscombusted in the turbine.

40 CFR Section 60.334(b)(2); Minn. R. 7011.2350;EPA guidance memo dated August 14, 1987; EPAapproval letter dated May 2, 2003

The Permittee shall comply with the above monitoring requirements until such timeas EPA promulgates revisions to the monitoring requirements in 40 CFR Part 60Subpart GG. At that time, the Permittee may choose to comply with the monitoringrequirements of the revised rule, provided the revised rule allows that choice.

40 CFR Sectio 60, Subpart GG; Minn. R. 7011.2350;Minn. R. 7007.0800, subp. 4

Reporting Requirements hdr

Notification of Noncompliance: Should any sulfur analysis indicate noncompliancewith 40 CFR Section 60.333(b), as described in 40 CFR Section 60.334(c)(2), thePermittee shall notify the MPCA of such excess emissions and the custom fuelmonitoring schedule shall be re-examined by the Administrator. Sulfur monitoringshall be conducted weekly during the interim period when the custom fuelmonitoring schedule is being re-examined.


Reporting: If there is a change in fuel supply, the Permittee shall notify the MPCAof such change for re-examination of the custom fuel monitoring schedule. Asubstantial change in fuel quality shall be considered as a change in fuel supply.Sulfur monitoring shall be conducted weekly during the interim period when thecustom fuel monitoring schedule is being re-examined.


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Facility Name:

Permit Number:

Subject Item: MR 001 NOx Monitor

Associated Items: CM 001

EU 001 Boiler 1

EU 002 Boiler 2

EU 003 Boiler 3

What to do Why to do itContinuous Operation: CEMS must be operated and data recorded during allperiods of emission unit operation including periods of emission unit start-up,shutdown, or malfunction except for periods of acceptable monitor downtime. Thisrequirement applies whether or not a numerical emission limit applies during theseperiods. A CEMS must not be bypassed except in emergencies where failure tobypass would endanger human health, safety, or plant equipment.

Acceptable monitor downtime includes reasonable periods as listed in Items A, B,C and D of Minn. R. 7017.1090, subp. 2.

40 CFR Section 60.13(e), Minn. R. 7017.1090, subp.1; Minn. R. 7007.0800, subp. 4

All CEMS shall complete a minimum of one cycle of operation (sampling, analyzing,and data recording) for each successive 15-minute period.

The Permittee shall reduce all CEMS data to 1-hour averages. One hour averagesshall be computed from four or more data points equally spaced over each 1-hourperiod.

Data recorded during periods of CEMS breakdown, repair, calibration checks, andzero and span adjustments shall not be included in the data average.

40 CFR Section 60.13(e)(2); 40 CFR Section 60.13(h);Minn. R. 7017.1140; Minn. R. 7017.1160; Minn. R.7007.0800, subp. 4

QA Plan: Develop and implement a written quality assurance plan that covers eachCEMS. The plan shall be on site and available for inspection within 30 days aftermonitor certification. The plan shall contain all of the information required by40CFR 60, App. F, section 3.

Minn. R. 7017.1170, subp. 2; Minn. R. 7007.0800,subp. 4

CEMS Relative Accuracy Test Audit (RATA): due before end of each calendar yearfollowing CEM Certification Test, except as noted in Minn. R. 7017.1170, subp. 5.Follow the procedures in 40 CFR Section 60, Appendix F.


Relative Accuracy Test Audit (RATA) Notification: due 30 days before CEMSRelative Accuracy Test Audit (RATA)) . Notification may be made by fax, mail,electronic mail, or hand delivered. This is state-only requirement and is notenforceable by EPA or citizens under the Clean Air Act.

Minn. R. 7017.1180, subp. 2

Relative Accuracy Test Audit (RATA) Results Summary: due 30 days after end ofeach calender quarter in which the annual CEMS RATA was conducted. This isstate-only requirement and is not enforceable by EPA or citizens under the CleanAir Act.

Minn. R. 7017.1180, subp. 3

CEMS Daily Calibration Drift (CD) Test: The Permittee shall automatically checkthe zero (or low level value between 0 and 20 percent of span value) and span (50to 100 percent of span value) calibration drifts at least once daily in accordancewith a written procedure. The zero and span must, as a minimum, be adjustedwhenever either the 24-hour zero drift or the 24-hour span drift exceeds two timesthe limit from Appendix B of 40 CFR 60.

40 CFR Section 60.13(d)(1); Minn. R. 7017.1170,subp. 3; Minn. R. 7007.0800, subp. 4

CEMS Cylinder Gas Audit (CGA): due before end of each calendar half-yearfollowing CEM Certification Test, using a form approved by the commissioner,except that a CGA is not required during any half-year in which a RATA isperformed.


Cylinder Gas Audit (CGA) Results Summary: due 30 days after end of eachcalendar quarter following Cylinder Gas Audit (CGA). This is state-onlyrequirement and is not enforceable by EPA or citizens under the Clean Air Act.

Minn. R. 7017.1180, subp.1

Recordkeeping: The owner or operator must retain records of all CEMS monitoringdata and support information for a period of five years from the date of themonitoring sample, measurement or report. Records shall be kept at the source.

40 CFR Section 60.7(f); Minn. R. 7017.1130; Minn. R.7007.0800, subp. 4

Records of Startup, Shutdown, or Malfunction: Any owner or operator subject tothe provisions of this part shall maintain records of the occurrence and duration ofany startup, shutdown, or malfunction in the operation of an affected facility; anymalfunction of the air pollution control equipment; or any periods during which acontinuous monitoring system or monitoring device is inoperative.

40 CFR Section 60.7(b)

A-9


St Marys

10900008 - 001

Facility Name:

Permit Number:

CEMS Recertification Test: Recertification of a previously certified CEMS isrequired if the monitor undergoes a change invalidating its certification. Any of thefollowing changes to a certified CEMS invalidates the certification status of themonitoring system:A. replacement of the analyzer;B. change in location or orientation of the sampling probe or site;C. modification to the flue gas handling system which changes its flowcharacteristics; orD. a change that in the commissioner's judgement siginficantly affects the ability ofthe stem to measure or record the pollutant concentration, or volumetric gas flow.

40 CFR Section 60.13(b); Minn. R. 7017.1050, subp.1; Minn. R. 7007.0800, subp. 4

CEMS Recertification Test Pretest Meeting: due 7 days before CEMSRecertification Test. This is a state-only requirement and is not enforceable byEPA or citizens under the Clean Air Act.

Minn. R. 7017.1060, subp. 3

CEMS Recertification Test Plan: due 30 days before CEMS Recertification Test. 40 CFR Section 60.7(a)(5); Minn. R. 7017.1060, subp.1 & 2

CEMS Recertification Test Report: due 45 days after CEMS Recertification Test Minn. R. 7017.1080, subp. 1, 2, & 4; 40CFR60.13(c)(2)

CEMS Recertification Test Report - Microfiche Copy: due 105 days after CEMSRecertification Test. This is a state-only requirement and is not enforceable by EPAor citizens under the Clean Air Act.

Minn. R. 7017.1080, subp. 3

A-10


St Marys

10900008 - 001

Facility Name:

Permit Number:

Subject Item: MR 002 O2 Monitor


EU 001 Boiler 1

EU 002 Boiler 2

EU 003 Boiler 3

What to do Why to do itRecords of Startup, Shutdown, or Malfunction: Any owner or operator subject tothe provisions of this part shall maintain records of the occurrence and duration ofany startup, shutdown, or malfunction in the operation of an affected facility; anymalfunction of the air pollution control equipment; or any periods during which acontinuous monitoring system or monitoring device is inoperative.


A-11


St Marys

10900008 - 001

Facility Name:

Permit Number:

Subject Item: MR 003 Opacity Monitor


EU 001 Boiler 1

EU 002 Boiler 2

EU 003 Boiler 3

What to do Why to do itContinuous Operation: COMS must be operated and data recorded during allperiods of emission unit operation including periods of emission unit start-up,shutdown, or malfunction except for periods of acceptable monitor downtime. Thisrequirement applies whether or not a numerical emission limit applies during theseperiods. A COMS must not be bypassed except in emergencies where failure tobypass would endanger human health, safety, or plant equipment.

Acceptable monitor downtime includes reasonable periods as listed in Items A, B,C and D of Minn. R. 7017.1090, subp. 2.

40 CFR Section 60.13(e); Minn. R. 7017.1090, subp. 1

The Permittee must at a minimum follow the following procedures for a COMS.Minimum procedures must include an automated method for producing a simulatedzero opacity condition and an upscale opacity condition using a certified neutraldensity filter or other related technique to produce a known obstruction of the lightbeam. Such procedures must provide a system check of all active analyzer internaloptics with power or curvature, all active electronic circuitry including the lightsource and photo-detector assembly, and electronic or elecro-mechanical systemsand hardware and/or software used during normal measurement operation.

40 CFR Section 60.13(d)(2)

QA Plan Required: Develop and implement a written quality assurance plan whichcovers each COMS. The plan shall be on site and available for inspection within30 days after monitor certification. The plan shall contain the written procedureslisted in Minn. R. 7017.1210, subp. 1.

Minn. R. 7017.1210; Minn. R. 7007.0800, subp. 4

COMS Daily Calibration Drift (CD) Check: The Permittee must automatically,intrinsic to the opacity monitor, check the zero (low-level) and upscale (high-level)calibration drifts at least once daily. The optical surfaces exposed to effluent gasesmust be cleaned before performing the drift adjustments, except for systems usingautomatic zero adjustments. The optical surfaces must be cleaned when thecumulative automatic zero compensation exceeds 4 percent opacity.

40 CFR Section 60.13(d)(2); Minn. R. 7017.1210,subp. 2; Minn. R. 7007.0800, subp. 4

COMS Calibration Error Audit: due before end of each calendar half-year followingCOMS Certification Test or Permit Issuance. Conduct three point calibration erroraudits at least 3 months apart but no greater than 8 months apart. Filter valuesused shall correspond to approximately 10%, 25%, and 50% opacity. Refer toMinn. R. 7017.1210 for full instructions.


All COMS shall complete a minimum of one cycle of sampling and analyzing foreach successive 10-second period and one cycle of data for each successive6-minute period.

The Permittee shall reduce all COMS data to 6-minute averages. Six minuteaverages shall be calculated from 36 or more data points equally spaced over each6-minute period. Data reduction shall be done in accodance with the proceduresoutlined in Minn. R. 7011.7017.1200, subp. 3

Data recorded during periods of COMS breakdown, repair, calibration checks, andzero and span adjustments shall not be included in the data average.

40 CFR Section 60.13(e)(1); 40 CFR Section 60.13(h);Minn. R. 7017.1200, subp. 1, 2 & 3; Minn. R.7007.0800, subp. 4

Recordkeeping: The owner or operator must retain records of all COMS monitoringdata and support information for a period of five years from the date of themonitoring sample, measurement or report. Records shall be kept at the source.

Minn. R. 7017.1130; Minn. R. 7007.0800, subp. 4

Records of Startup, Shutdown, or Malfunction: Any owner or operator subject tothe provisions of this part shall maintain records of the occurrence and duration ofany startup, shutdown, or malfunction in the operation of an affected facility; anymalfunction of the air pollution control equipment; or any periods during which acontinuous monitoring system or monitoring device is inoperative.


COMS Recertification Test: Recertification of a previously certified COMS isrequired if the monitor undergoes a change invalidating its certification. Any of thefollowing changes to a certified COMS invalidates the certification status of themonitoring system:A. replacement of the analyzer;B. change in location or orientation of the sampling probe or site;C. modification to the flue gas handling system which changes its flowcharacteristics; orD. a change that in the commissioner's judgement siginficantly affects the ability ofthe stem to measure or record the pollutant concentration, volumetric gas flow, oropacity.

40 CFR Section 60.13(b); Minn. R. 7017.1050, subp.1; Minn. R. 7007.0800, subp. 4

A-12


St Marys

10900008 - 001

Facility Name:

Permit Number:

COMS Recertification Test Plan: due 30 days before COMS Recertification Test.This is a state-only requirement and is not enforceable by the EPA or citizens underthe Clean Air Act.

Minn. R. 7017.1060, subp. 1 & 2

COMS Recertification Test Pretest Meeting: due 7 days before COMSRecertification Test. This is state-only requirement and is not enforceable by EPAor citizens under the Clean Air Act.

Minn. R. 7017.1060, subp. 3

COMS Recertification Test Report: due 45 days after COMS Recertification Test.This is a state-only requirement and is not enforceable by EPA or citizens under theClean Air Act.

Minn. R. 7017.1080, subp. 1, 2 & 4

COMS Recertification Test Report - Microfiche Copy: due 105 days after COMSRecertification Test. This is a state-only requirement and is not enforceable byEPA or Citizens under the Clean Air Act.

Minn. R. 7017.1080, subp. 3

A-13

TABLE B: SUBMITTALSFacility Name: St Marys

Permit Number: 10900008 - 001

07/23/03

Table B lists most of the submittals required by this permit. Please note that some submittal requirements may appear in Table Aor, if applicable, within a compliance schedule located in Table C. Table B is divided into two sections in order to separately listone-time only and recurrent submittal requirements.

Each submittal must be postmarked or received by the date specified in the applicable Table. Those submittals required by parts7007.0100 to 7007.1850 must be certified by a responsible official, defined in Minn. R. 7007.0100, subp. 21. Other submittals shallbe certified as appropriate if certification is required by an applicable rule or permit condition.

Send any application for a permit or permit amendment to:

Permit Technical AdvisorPermit SectionAir Quality DivisionMinnesota Pollution Control Agency520 Lafayette Road NorthSt. Paul, Minnesota 55155-4194

Also, where required by an applicable rule or permit condition, send to the Permit Technical Advisor notices of:- accumulated insignificant activities,- installation of control equipment,- replacement of an emissions unit, and- changes that contravene a permit term.

Unless another person is identified in the applicable Table, send all other submittals to:

SupervisorCompliance Determination UnitAir Quality DivisionMinnesota Pollution Control Agency520 Lafayette Road NorthSt. Paul, Minnesota 55155-4194

Send submittals that are required to be submitted to the U.S. EPA regional office to:

Mr. George CzerniakAir and Radiation BranchEPA Region V77 West Jackson BoulevardChicago, Illinois 60604

Send submittals that are required by the Acid Rain Program to:

U.S. Environmental Protection AgencyClean Air Markets Division1200 Pennsylvania Avenue NW (6204N)Washington, D.C. 20460

B-1

TABLE B: ONE TIME SUBMITTALS OR NOTIFICATIONSFacility Name: St Marys


07/23/03

What to send When to send Portion of Facility AffectedApplication for Permit Reissuance due 180 days before expiration of Existing

PermitTotal Facility

B-2

TABLE B: RECURRENT SUBMITTALSFacility Name: St Marys


07/23/03

What to send When to send Portion of Facility AffectedCOMS Calibration Error Audit ResultsSummary

due 30 days after end of each calendarquarter following COMS Calibration ErrorAudit. Must be submitted on a form approvedby the commissioner.

MR003

Excess Emissions/Downtime Reports (EER's) due 30 days after end of each calendarquarter following Initial Startup of the MonitorThe report must be submitted even if therewere no excess emissions, monitordowntimes, or monitor bypasses during thequarter. The report shall be submitted on aform approved by the commissioner. Thecontent of the report shall include those itemslisted in Minn. R. 7017.1110, subp. 2(A) - (C).

Excess emissions are defined as all 6-minuteperiods during which the average opacityexceeds the opacity standard, or as anycalculated 30-day rolling average NOxemisson rate which exceeds the emissionlimit.

GP001

Report due 30 days after end of each calendarhalf-year following Initial Startup of the boilers.Report is to include certification that only verylow sulfur oil was combusted in the boiler, andthe information recorded under 60.49b(g).

GP001

Semiannual Deviations Report due 30 days after end of each calendarhalf-year following Permit Issuance. The firstsemiannual report submitted by the Permitteeshall cover the calendar half-year in which thepermit is issued. The first report of eachcalendar year covers January 1 - June 30.The second report of each calendar yearcovers July 1 - December 31. If no deviationshave occured, the Permittee shall submit thereport stating no deviations.

Total Facility

Compliance Certification due 31 days after end of each calendar yearfollowing Permit Issuance (for the previouscalendar year). To be submitted on a formapproved by the Commissioner, both to theCommissioner and to the US EPA regionaloffice in Chicago. This report covers alldeviations experienced during the calendaryear.

Total Facility

B-3

APPENDIX B – Modeled Parameters (SO2) Facility Name: St Marys Permit Number: 10900008-001 Any physical change or change in a method of operation must result in plume dispersion characteristics equivalent to or better than the plume dispersion characteristics modeled using the parameters below. Revision of any of these parameters may require a permit amendment. SV ID Number Stack Height

(feet)

Stack Diameter

(feet)

Exhaust Temperature

(°F)

Air Flow

(acfm) SV001 223 3.35 350 107535 SV002 37 2.33 900 30500 SV003 37 2.33 900 35600

APPENDIX C – Insignificant Activities Facility Name: St Marys Permit Number: 10900008-001

Insignificant Activities and Applicable Requirements

Minn. R. 7007.1300,

subpart Rule Description of the Activity Applicable Requirement

3(D) Processing operations:

2. Equipment venting particulate matter (PM) or particulate matter less than 10 microns (PM-10) inside a building, provided that emissions from the equipment are:

a). filtered through an air cleaning system; and

b). vented inside of the building 100% of the time.

• Carpenter shop

Minn. R. 7011.0710/0715

3(G) Emissions from a laboratory, as defined in the subpart.

• Experimental study and teaching laboratories

Minn. R. 7011.0510/0515 +Minn. R. 7011.0610 + Minn. R. 7011.0710/0715

3(H) Miscellaneous:

4. brazing, soldering or welding equipment;

• Various welding and soldering equipment

Minn. R. 7011.0510/.0515 + Minn. R. 7011.0610 + Minn. R. 7011.0710/0715

3(I) Individual emissions units at a stationary source, each of which have a potential to emit the following pollutants in amounts less than:

1. 4,000 lbs/year of carbon monoxide; and

2. 2,000 lbs/year each of nitrogen oxide, sulfur dioxide, particulate matter, particulate matter less than ten microns, volatile organic compounds (including hazardous air pollutant-containing VOC), and ozone.

• Three 50,000 gallon Distillate Oil storage tanks, potential VOC emissions 0.013 tpy each

• Two ethylene oxide sterilizers, potential VOC (including ethylene oxide) emissions of 0.61 tpy each

40 CFR 60.116b(a) and (b)

Minn. R. 7011.0710/0715

Minn. R. 7007.1300,

subpart Rule Description of the Activity Applicable Requirement

4 Emissions units with emissions less than all the following limits but not included in subpart 2:

A. potential emissions of 5.7 pounds per hour or actual emissions of two tons per year of carbon monoxide;

B. potential emissions of 2.28 pounds per hour or actual emissions of one ton per year for particulate matter, particulate matter less than ten microns, nitrogen oxide, sulfur dioxide, and VOCs; and

C. for hazardous air pollutants, emissions units with: (1) potential emissions of 25 percent or less of the hazardous air pollutant thresholds listed in subpart 5; or (2) combined HAP actual emissions of one ton per year unless the emissions unit emits one or more of the following HAPs: carbon tetrachloride; 1,2-dibromo-3-chloropropane; ethylene dibromide; hexachlorobenzene; polycyclic organic matter; antimony compounds; arsenic compounds, including inorganic arsine; cadmium compounds; chromium compounds; lead compounds; manganese compounds; mercury compounds; nickel compounds; selenium compounds; 2,3,7,8-tetrachlorodibenzo-p-dioxin; or dibenzofuran.

• Power plant sandblaster – actual PM/PM10 0.274 tpy

• Hospital maintenance sandblaster – actual PM/PM10 0.274 tpy

• Power plant parts washer – potential VOC 0.612 lb/hr

• Hospital maintenance parts washer – potential VOC 0.397 lb/hr

• Portable pumps – actual emissions for last several years is 0 tpy

• Non-contact cooling tower – potential PM/PM10 0.76 lb/hr; actual total HAP (ethylene glycol) 0.063 tpy

• Gluing – actual VOC 0.028 tpy; actual total HAP (toluene, methanol, methylene chloride, xylene) 0.025 tpy

• Parts lubrication – actual VOC 0.01 tpy

• Printing activities – actual VOC 0.215 tpy

• Degreasing – actual VOC 0.148 tpy; actual total HAP (methyl chloroform) 0.084 tpy

• Flux cleaning – actual VOC 0.002 tpy

Minn. R. 7007.0710/0715 (for all)

Technical Support Document Permit Number 10900008-001 Date Printed: 3/5/2004 Page 1 of 12

TECHNICAL SUPPORT DOCUMENT For

AIR EMISSION PERMIT NO. 10900008-001 This technical support document is intended for all parties interested in the permit. The purpose of this document is to set forth the legal and factual basis for the permit conditions, including references to the applicable statutory or regulatory provisions. 1. General Information 1.1. Applicant and Stationary Source Location:

Owner and Operator Address and Phone Number (list both if different)

Facility Address (SIC Code: 8062)

Mayo Foundation 200 First Street Southwest Rochester, MN 55905

St. Marys 1216 Southwest 2nd Street Rochester, Olmsted County, MN

Contact: David Senjem, Environmental Affairs Officer

1.2. Description of the facility

St. Marys is a tertiary care hospital which includes several buildings located on a 49 acre campus. The primary emission units at the facility are three identical boilers which exhaust through a common stack, one cogeneration turbine, and two emergency generators. Each boiler combusts natural gas with distillate fuel as backup. The cogeneration turbine burns only natural gas. One generator burns only distillate oil; the other can burn distillate oil or a mixture of natural gas and distillate oil (dual fuel).

While St. Marys is owned and operated by the Mayo Foundation, it is not contiguous with the majority of the Mayo facilities in Rochester, and thus is a separate source under the New Source Review and Part 70 regulations. This permit is a Part 70 operating permit. The facility is an existing major source under New Source Review. No modifications are approved through this permit. The facility is not a major source of HAP emissions.

The facility is located in an area that was previously designated as non-attainment for SO2. However, the area currently meets the ambient air quality standards, and was officially redesignated as “attainment” on May 8, 2001. The facility has been subject to a federally enforceable permit (part of Minnesota’s state implementation plan, or SIP, for attaining ambient air quality standards) containing requirements contributing to the correction of the non-attainment problem and the ultimate redesignation. The requirements of that permit have been incorporated into this permit as non-expiring Title I conditions. This permit will ultimately replace the existing permit and be incorporated into the SIP (separately from the permit issuance process).


1.3 Description of any changes allowed with this permit issuance

None. 1.4 Description of all amendments issued since the issuance of the last total facility permit and to be included in the Part 70 Permit.

Permit Number and Issuance Date

Action Authorized

989-91-OT-2, 3/27/91 Previous Total Facility Permit. Authorized replacement of 4 existing natural gas/residual oil boilers with 3 new natural gas/distillate oil boilers.

Amendment 1 to 989-91-OT-2, 9/4/91

Revised language for operation and placement of NOX CEMS.

Amendment 2 to 989-91-OT-2, 2/15/96

Authorized installation of cogeneration turbine.

Amendment 3 to 989-91-OT-2, 5/31/96

Authorized installation of one COMS in common duct of the 3 boilers, as allowed by NSPS. Also revised compliance demonstration for distillate oil – went from monthly restriction to 12-month rolling sum.

Amendment 4 to 989-91-OT-2, 2/28/97

Incorporated Title I conditions and compliance demonstration requirements to show compliance with national and state ambient air quality standards. The permit was incorporated into the SO2 SIP.

1.5. Changes Made to Permit Since Beginning of Public Notice

Attachment 5 to this document includes a copy of the comment letter submitted by Mayo Foundation, a copy of an emailed request made by St. Marys after the public notice period, and copies of the MPCA’s responses to those comments. Attachment 4 to this document includes a copy of EPA’s letter outlining partial approval of the requested alternatives to the monitoring schedule prescribed in 40 CFR part 60, subpart GG. A summary of the changes made to the permit follows. All changes made are either correction of errors or result in the permit being more restrictive than the draft version placed on public notice, therefore the public notice need not be repeated.

• On page A-12 of the permit, under the requirements for COMS Daily Calibration Drift (CD) Check, the last sentence requiring adjustment when the CD exceeds twice the specification of PS-1 of 40 CFR 60, Appendix D, was removed. This requirement applies specifically to CEMS (continuous emission monitoring systems), not COMS. The citation was also corrected to 40 CFR Section 60.13(d)(2), which applies specifically


to COMS; the original citation, 40 CFR Section 60.13(d)(1), applies specifically to CEMS.

• On page A-8 of the permit, the two sections labeled Custom Sulfur Monitoring Schedule (a) and (b) were combined into one section. The requirement was corrected to require quarterly monitoring for six quarters, as prescribed in the EPA guidance memo and approval letter, both included in Attachment 4 to this document.

• On page A-8 of the permit, the paragraph appearing in the original draft stating that “in the absence of EPA approval of the associated custom monitoring schedule proposed below, sulfur and/or nitrogen content of the fuel shall be determined and recorded each operating day, in accordance with the methods described in 40 CFR 60, Subpart GG” was deleted. Since EPA approval was received during the public notice period, the approved items were included in the proposed permit, and the unapproved items were removed from the proposed permit.

• On page A-8 of the permit, the section Determination of Sulfur Content was revised. The paragraph stating that upon approval of EPA, St. Marys could use sulfur content data obtained from Rochester Public Utilities was removed, since EPA explicitly denied that request. The paragraph stating that upon approval of EPA, the alternative Gas Processors Association method could be used, was revised to specify that the alternative method could be used upon written EPA approval.

• All of the citations pertaining to custom monitoring were revised to include the August 14, 1987 EPA guidance memo, and the May 2, 2003, EPA approval letter.

• On page A-8 of the permit, language was added to allow St. Marys to follow the monitoring requirements of the revised Subpart GG rule. The rule as proposed on April 14, 2003, allows a facility burning pipeline natural gas to not monitor sulfur content of the fuel. If that revision is promulgated, St. Marys does not want to be held to the custom schedule outlined in the permit, provided the revised rule allows the choice.

1.6. Facility Emissions:

Table 1. Total Facility Potential to Emit Summary:

PM tpy

PM10 tpy

SO2 tpy

NOx tpy

CO tpy

VOC tpy

Pb tpy

SingleHAP tpy

All HAPs

tpy Total Facility Limited Potential Emissions

19.5 18.2 65.7 507.9 214.6 18.56 0.001 2.7 3.1

Total Facility Actual Emissions 1

4.77 4.58 2.41 107.1 44.16 4.0 0.0 NR 2 NR 2

1 From 2001 Emission Inventory 2 Not reported (HAPs are not reported on the annual emissions inventory)


Table 2. Facility and Permit Classification

Classification Major/Affected Source *Synthetic Minor *Minor PSD NOX, CO SO2 PM, PM10, VOC NAAR - NA Part 70 Permit Program NOX, CO SO2 PM10, VOC, HAPs * Refers to potential emissions that are less than those specified as major by 40 CFR 52.21, 40 CFR pt. 51 Appendix S, and 40 CFR pt. 70. 2. Regulatory Overview of Facility New Source Review

The operations covered under this permit are considered a major source under New Source Review. No changes requiring PSD review have been made, and no physical changes are authorized through this permit.

This permit eliminates a previously set limit on the quantity of fuel oil that may be burned. On March 27, 1991, a limit was set restricting fuel oil usage in the boilers to 1806833 gallons, to be burned only during the months of November, December, January, and February. At the same time, the existing SO2 limit of 65.56 tons per year for the three boilers and two generators combined was set. The fuel oil usage limit was changed to a 12 month rolling sum on May 31, 1996. In the updated permit application submitted in December 2002, the Permittee requested to have the fuel oil usage limit removed. Analysis of the potential emissions revealed that the SO2 limit of 65.56 tons per year is more restrictive than the fuel oil usage limit. Under the scenario that the entire 65.56 tons of SO2 (which is the combined limit for the 3 boilers plus the two generators) is generated by combustion of fuel oil in the boilers, this requires 1775491 gallons of fuel oil per year:

1775491 gal/year x 0.1477 S lb SO2/gallons x 0.5 x 1 ton/ 2000 lb = 65.56 tons SO2/yr

(0.1477S is the AP-42 emission factor for combustion of distillate fuel oil in a boiler larger than 100 MMBtu/hour, and 0.5% is the fuel oil sulfur content limit in the SO2 SIP for Rochester.)

Thus, the Permittee cannot combust 1806833 gallons of fuel oil and still meet the SO2 emission limit of 65.56 tons per year. The only other pollutants exceeding potential emission of 100 tons per year are NOX and CO, for which worst case emissions occur when natural gas is fired (i.e., limiting the quantity of fuel oil does not reduce the NOX and CO PTE). Therefore, the fuel oil usage restriction was removed from the permit as unnecessary.

The permit also includes a restriction on hours of operation of the dual fuel generator (EU005) to 1040 hours per year, to keep emissions below the significant increase thresholds for PSD. National Ambient Air Quality Standards (NAAQS)

Because the facility was identified as a potentially-culpable source in the SO2 nonattainment area in Rochester, the facility is subject to limitations on fuel usage that restricts the SO2 emissions from the facility. These restrictions have been submitted as part of Minnesota’s State


Implementation Plan for SO2 through Amendment No. 4 to Air Emission Permit No. 989-91-OT-2, which was issued on February 28, 1997. These restrictions are non-expiring Title I conditions, and have been carried forward into this permit. The Rochester area is no longer considered a nonattainment area. The existing permit (to be replaced by this permit) that currently is part of the SIP and which contains the Title I SIP conditions, is included as Attachment 3 to this technical support document. National Emission Standards for Hazardous Air Pollutants (NESHAPs)

The facility is not a major source of HAP emissions. Part 70 Permit Program

The facility is a major source under the Part 70 permit program, since permitted emissions of CO and NOX exceed 100 tons per year. New Source Performance Standards

Portions of the facility are subject to the following New Source Performance Standards contained in 40 CFR Section 60:

• Subpart Db -- Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units (60.40b--60.49b)

• Subpart Kb -- Standards of Performance for Volatile Organic Liquid Storage Vessels (Including Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced After July 23, 1984 (60.110b--60.117b)

• Subpart GG -- Standards of Performance for Stationary Gas Turbines (60.330--60.335) Minnesota Standards of Performance

Portions of the facility are subject to the following:

• Minn. R. 7011.0710/0715 - Standards of Performance for Industrial Process Equipment

• Minn. R. 7011.2300 - Standards of Performance for Stationary Internal Combustion Engines

Table 3. Regulatory Summary

EU, GP, or SV

Applicable Regulations Comments:

EU001, EU002, EU003

40 CFR 60, Subpart Db

The 3 boilers are each subject to the Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units


EU, GP, or SV

Applicable Regulations Comments:

EU001, EU002, EU003, EU004, EU005

Title I – SIP conditions Each of these units is subject to conditions contained in the State Implementation Plan for SO2

GP002 Title I – conditions to avoid NSR

These conditions were set in a previous permit, to avoid major source classification for a modification (installation of boilers)

EU006 40 CFR 60, Subpart GG

The combustion turbine is subject to the Standards of Performance for Stationary Gas Turbines

Per the EPA letter dated May 2, 2003, the Permittee is subject to an alternate sulfur and nitrogen monitoring schedule; because only pipeline quality natural gas is burned, a waiver is sought for the nitrogen content, and a limited sulfur monitoring, in accordance with the August 14, 1987 EPA memo (see memo and letter in Attachment 4 to this document)

Pending EPA (OAQPS) approval, the Permittee will be allowed to use the Gas Processors Association Standard Method 2377-86 for determining sulfur content of natural gas.

TK001, TK002, TK003

40 CFR 60, Subpart Kb The fuel oil storage tanks are subject to the Standards of Performance for Volatile Organic Liquid Storage Vessels

EU004, EU005

Minn. R. 7011.2300 The 2 generators are each subject to Minnesota’s Standards of Performance for Stationary Internal Combustion Engines

3. Technical Information 3.1 Calculations

Calculations for all combustion sources were done using AP-42 emission factors (including HAPs), except where another limit is specified in the NSPS standards or SO2 SIP.

Each of the three boilers can be fueled by distillate oil or natural gas. If distillate oil is burned, both the NSPS and the SO2 SIP limit the sulfur content to 0.5% by weight. The NSPS limits the NOX emissions to 0.1 lb/MMBtu. Worst-case emissions for all pollutants except NOX and CO occur when distillate oil is combusted. Natural gas causes the worst case emissions for NOX and CO.


Generator 5 (EU004) is fueled by distillate oil only. The SO2 SIP limits the sulfur content of the fuel used in the generator to 0.41% by weight; Minn. R. 7011.2300 limits the SO2 emissions to 0.5 lb/MMBtu heat input. A sulfur limit of 0.41% by weight results in maximum SO2 emissions of 0.41 lb/MMBtu (assuming all sulfur is converted to SO2).

Generator 6 (EU005) can be fueled by distillate oil, or can be run in dual fuel mode, which is defined in AP-42 as 95% natural gas/5% distillate oil. The SO2 SIP limits the sulfur content of the fuel used in the generator to 0.41% by weight; Minn. R. 7011.2300 limits the SO2 emissions to 0.5 lb/MMBtu heat input. A sulfur limit of 0.41% by weight results in maximum SO2 emissions of 0.41 lb/MMBtu (assuming all sulfur is converted to SO2). The Permittee proposed in the Title V permit application that the 0.41% sulfur restriction does not apply when operating in the dual fuel mode. However, the SO2 SIP does not make that distinction, therefore that requirement will not be dropped through this permit. The permit does clarify that the 0.41% sulfur content restriction applies to distillate oil burned in the generator (as opposed to natural gas, which typically has a sulfur content of roughly 0.0006% by weight). Worst case PM, PM10, SO2, and NOX emissions occur when distillate oil is combusted; worst case VOC and CO emissions occur in the dual fuel mode.

The limited emissions from these five units (three boilers and two generators) are restricted by the SO2 limit of 65.56 tons per year (discussed previously). The following scenarios were examined to determine which resulted in the worst case emissions for each pollutant:

• The entire 65.56 tons generated by via burning distillate oil with a sulfur content of 0.5% by weight in the boilers. By burning 1775491 gallons of distillate oil, they would generate 65.56 tpy of SO2, 3 tpy PM, 2 tpy PM10, 9 tpy NOX, 2 tpy VOC, and 4 tpy CO (Pb emissions are negligible). Under this scenario, no additional fuel can be combusted in the boilers or in the generators, because the 65.56 tpy of SO2 is already generated.

• The 3 boilers run at capacity on natural gas. This results in less than 1 tpy SO2, 10 tpy PM/PM10, 135 tpy NOX, 7 tpy VOC, and 113 tpy CO. Under this scenario, there is still over 64 tpy SO2 that can be generated, so added to this scenario was both generators operating at maximum capacity on their respective worst case fuels for each pollutant. This results in an additional 8 tpy PM, 6 tpy PM10, 45 tpy SO2, 348 tpy NOX, 11 tpy VOC, and 98 tpy CO, for total potential emissions under this scenario of roughly 18 tpy PM, 16 tpy PM10, 46 tpy SO2, 482 tpy NOX, 18 tpy VOC, and 211 tpy CO.

• Both generators running at capacity on their respective worst case SO2 fuel. This results in 45 tpy SO2. The remaining SO2 was assumed generated by operating the boilers on fuel oil. Total potential emissions under this scenario were 8.5 tpy PM, 7 tpy PM10, 65.56 tpy SO2, 351 tpy NOX, 11 tpy VOC, and 99 tpy CO.

• The entire 65.56 tpy generated by operation of the three boilers at maximum capacity, using the combination of natural gas and distillate oil that limits SO2 to 65.56 tons. This turned out to be operating the boilers for approximately 7991 hours per year on natural gas, and 769 hours on distillate oil (for a total of 8760 hours). This results in potential emissions of 12 tpy PM, 11 tpy PM10, 65.56 tpy SO2, 131 tpy NOX, 8.5 tpy VOC, and 107 tpy CO.


Thus, the worst case emissions that could occur while still meeting the 65.56 tpy SO2 limit, occur under the 2nd bulleted item, running all three boilers on natural gas at full capacity, and both generators on their worst-case fuel at full capacity. While potential SO2 emissions under that scenario are less than the allowed 65.56 tons, the scenario results in the worst case emissions for each of the other pollutants.

The combustion turbine is fueled by natural gas. NSPS Subpart GG limits NOX emissions to 193 ppmv. Potential emissions based on AP-42 factors are 5.81 lb/hour for NOX, which is less than 25 ppmv (per permit application). 3.2 Modeling Requirements

SO2 modeling has been done, as part of the development of the SIP requirements. The physical parameters for point sources of SO2 re included as Appendix B to the permit. Any change to any of those parameters must result in better dispersion characteristics, or modeling must be repeated before the change can be made.

Actual PM10 and NOX emissions do not fit within the guidelines of when full modeling for those pollutants would be required. Under the guidance, we would then require that the facility submit “modeling information” for our use in the future. However, since the facility has been included in full modeling for NOX and PM10, which was done for all major Rochester sources in 2003, we have the physical characteristics of the sources of PM10 and NOX. Therefore, the information submittal is not being required. 3.3 Periodic Monitoring

In accordance with the Clean Air Act, it is the responsibility of the owner or operator of a facility to have sufficient knowledge of the facility to certify that the facility is in compliance with all applicable requirements.

When evaluating the monitoring included in the permit, the MPCA considered the following:

• The likelihood of violating the applicable requirement;

• Whether add-on controls are necessary to meet the emission limit;

• The variability of emissions over time;

• The type of monitoring, process, maintenance, or control equipment data already available for the emission unit;

• The technical and economic feasibility of possible periodic monitoring methods; and

• The kind of monitoring found on similar units.

Table 4 summarizes the periodic monitoring requirements for those emission units for which the monitoring required by the applicable requirements is nonexistent or inadequate.


Table 4. Emission Units Subject to Periodic Monitoring

EU/GP/CE Emission limit (basis)

Additional Monitoring

Discussion

EU001 EU002 EU003

Sulfur content of fuel (0.5% by weight) (NSPS Subpart Db; SO2 SIP)

Recordkeeping of vendor receipts showing sulfur content of fuel oil

As required by NSPS; ASTM specifications do not allow the sulfur content of distillate oil to exceed 0.5%, so noncompliance is unlikely.

NOX limit (0.1 lb/MMBtu) (NSPS Subpart Db)

None. Calculation of hourly and 30-day average emission rates using CEMS data are required by the NSPS.

40 CFR 60.46b(e)(4) states that “During periods when performance tests are not required, nitrogen oxides emissions data … are used to calculate a 30-day rolling average on a daily basis and used to prepare excess emissions reports, but will not be used to determine compliance with the nitrogen oxides emission standards.” So, because the data is not used to determine compliance, Appendix F regarding operation of CEMS does not apply. However, since the CEMS data exists, it can be used as an indicator of compliance. In addition, potential NOX emissions based on published AP-42 emission factors are less than the emission limit.

Opacity limit (20% with excursions) (NSPS Subpart Db)

None COMS operated in accordance with NSPS requirements

EU001 EU002 EU003 EU004 EU005

SO2 annual limit (65.56 tons) (Title I, to avoid major modification status)

Daily recordkeeping, monthly calculations

Use the fuel sulfur content data collected as required by NSPS and SO2 SIP.




Discussion

EU004 Sulfur content of fuel oil (0.41% by weight) (SO2 SIP)

Option 1 – maintain fuel supplier receipts showing sulfur content equal to or less than 0.41%

Option 2 -- calculate sulfur content of entire volume of fuel in the tank following each delivery of oil

These requirements are spelled out in the SO2 SIP

Opacity (20%) (Minn. R)

None Opacity is typically not an issue if the equipment is operated properly on clean fuel. Testing is not required, because it is counterproductive to operate a generator for the sole purpose of testing opacity.

SO2 emissions (0.5 lb/MMBtu) (Minn. R.)

None If the sulfur content is maintained at 0.41% or less, assuming all sulfur is converted to SO2, then maximum emissions would be 0.41 lb/mmBtu

EU005 Sulfur content of fuel oil (0.41% by weight) (SO2 SIP)

Option 1 – maintain fuel supplier receipts showing sulfur content equal to or less than 0.41%

Option 2 -- calculate sulfur content of entire volume of fuel in the tank following each delivery of oil

These requirements are spelled out in the SO2 SIP

Opacity (20%) (Minn. R)

None Opacity is typically not an issue if the equipment is operated properly on clean fuel. Testing is not required, because it is counterproductive to operate a generator for the sole purpose of testing opacity.




Discussion

EU005, continued

SO2 emissions (0.5 lb/MMBtu) (Minn. R.)

None If the sulfur content is maintained at 0.41% or less, assuming all sulfur is converted to SO2, then maximum emissions would be 0.41 lb/mmBtu

Hours of operation (1040/year) (Title I, to avoid major modification status)

Recordkeeping

EU006 NOX limit (193 ppmv) (NSPS Subpart GG)

None NSPS-required initial performance test has been completed and passed (maximum 23.3 ppmv). Waiver of requirement to monitor nitrogen content of pipeline quality natural gas was requested under the terms of the 8/14/87 EPA memo on custom fuel monitoring schedules under Subpart GG (John Rasnic memo). EPA letter to the MPCA, dated May 2, 2003, approved a custom monitoring schedule as outlined in the John Rasnic memo. The John Rasnic memo and the May 2, 2003 approval letter are included in Attachment 4.

Sulfur content (0.8% by weight) (NSPS Subpart GG)

Custom monitoring schedule outlined in permit

A reduced-frequency custom sulfur monitoring schedule was requested under the terms of the 8/14/87 EPA memo on custom fuel monitoring schedules under Subpart GG (John Rasnic memo). EPA letter to the MPCA, dated May 2, 2003, approved a custom monitoring schedule as outlined in the John Rasnic memo. The John Rasnic memo and the May 2, 2003 approval letter are included in Attachment 4.

3.4 Insignificant Activities


Appendix C of the permit includes those insignificant activities that are required to be listed in the permit application. Emissions from these operations/activities do not affect applicability of any regulations or programs. 4. Conclusion Based on the information provided by the Mayo Foundation, the MPCA has reasonable assurance that the proposed operation of the emission facility, as described in the Air Emission Permit No. 10900008-001 and this technical support document, will not cause or contribute to a violation of applicable federal regulations and Minnesota Rules. Staff Members on Permit Team: Toni Volkmeier, Greg Berger, Dan Brady, Mike Mondloch (peer reviewer) Attachments: 1. Calculations and PTE Summary

2. Facility Description and CD-01 Forms 3. Previous SIP Document (amendment 4 to 989-91-OT-2) 4. EPA Memo on Custom Monitoring; Letter to EPA Seeking Approval; EPA

Approval Letter 5. Comments Received During Public Notice Period; Response to Public

Comments

Documents

AIR EMISSION PERMIT NO. 10900008- 001 IS ISSUED TO Mayo ... · PDF fileAIR EMISSION PERMIT NO. 10900008- 001 IS ISSUED TO Mayo Foundation for Saint Marys 1216 Southwest 2nd Street