SCAQMD RULE 2011-2 - MAJOR SOURCES - CEMS
LAST REVISED 02/14/97

(Amended February 14, 1997)

TABLE OF CONTENTS

CHAPTER 2 - MAJOR SOURCES - CONTINUOUS EMISSION MONITORING SYSTEM (CEMS)

A. Measurement Requirements .............................................................. 2011A-2-1

B. Monitoring Systems .......................................................................... 2011A-2-4

C. Reporting Procedures ....................................................................... 2011A-2-21

D. Alternative Procedures for Emission Stack Flow Rate Determination .. 2011A-2-23

E. Missing Data Procedures ................................................................... 2011A-2-25

F. Time -Sharing ..................................................................................... 2011A-2-33

The criteria for determining the applicable SOx RECLAIM category for a specific piece of equipment is presented in Table 1-A for a major source. If a major source category is applicable to this equipment, then the Facility Permit holder shall be required to comply with the performance standards associated with a CEMS (Continuous Emission Monitoring System) or an approved Alternative Monitoring System (AMS).

The Facility Permit holder of a source that is required to install CEMS may request the Executive Officer to approve an alternative monitoring device (or system components) to quantify emissions of SOx. The applicant shall demonstrate to the Executive Officer that the proposed alternative monitoring device is at a minimum equivalent in relative accuracy, precision, reliability, and timeliness to a CEMS for that source, according to the criteria specified in 40 CFR Part 75 Subpart E. In lieu of the criteria specified in 40 CFR Part 75 Subpart E, substitute criteria is acceptable if the applicant demonstrates to the Executive Officer that the proposed alternative monitoring device is at minimum equivalent in relative accuracy, precision, reliability, and timeliness to a CEMS for that source. Upon approval by the Executive Officer, the substitute criteria shall be submitted to the federal Environmental Protection Agency as an amendment to the State Implementation Plan (SIP).

Chapter 2 describes the methodologies for measuring, monitoring, and reporting emissions from major sources. All major sources shall be monitored by a continuous emissions monitoring system (CEMS) or an alternative monitoring system (AMS). The required equipment-specific variables, both measured and reported, to be monitored are found in Tables 2-A and 2-B, respectively.

Another important requirement of major SOx sources is the way in which they transmit data to the District's Central Station and the reporting frequency. Major sources shall electronically transmit the data via an RTU on a daily basis. In addition, the aggregated SOx emissions from all major sources must be submitted in a Monthly Emissions Report.

During the interim period, January 1, 1994 through December 31, 1994 for Cycle 1 facilities and July 1, 1994 through June 30, 1995 for Cycle 2 facilities mass emissions for major sources shall be determined using emission factors referenced in Table 2 of Rule 2002.

Other important aspects covered in this chapter include missing data procedures and CEMS timesharing requirements.

A. MEASUREMENT REQUIREMENTS

  1. Between January 1, 1994 and December 31, 1994 (Cycle 1 facilities) and between July 1, 1994 and June 30, 1995 (Cycle 2 facilities), major sources shall be allowed to use an interim reporting procedure to measure and record SOx emissions on a monthly basis and may be extracted from SOx emission data gathered by existing District certified continuous emissions monitoring system (CEMS). Chapter 2, Subdivision C, Paragraph 1 specifies the requirements for this interim period. On and after January 1, 1995 (Cycle 1 facilities) and July 1, 1995 (Cycle 2 facilities), the Facility Permit holder of each major source shall report a daily average of SOx emission by 5:00 p.m. of the following day and comply with all other applicable requirements (except Chapter 2, Subdivision C, Subparagraph 1) specified in this chapter.

  2. The Facility Permit holder shall by March 31, 1994 for Cycle 1 facilities and September 30, 1994 for Cycle 2 facilities, submit a CEMS plan to the Executive Officer for approval. The plan shall contain at a minimum the following items:

    a. A list of all major sources which will have CEMS installed.

    b. Details of all proposed Continuous Emission Monitors as well as the proposed flow monitors for each affected source.

    c. Details of the Quality Control/Quality Assurance Plan for the CEMS.

    d. Proposed range of each CEMS and the expected concentrations of pollutants for each source.

    e. Date by which purchase order for each system will be issued.

    f. Construction schedule for each system, and date of completion of the installation.

    g. Date by which CEMS certification test protocol will be submitted to the District for approval for each system.

    h. Date by which certification tests will be completed for each system.

    i. Date by which certification test results will be submitted for review by the District, for each system.

    j. Any other pertinent information regarding the installation and certification for each system.

    If a CEMS Plan is disapproved in whole or in part, the District staff will notify the Facility Permit holder in writing and the Facility Permit holder shall have 30 days from the date it receives the notice from the District to resubmit its plan.

  3. The Facility Permit holder of each major SOx equipment shall install, calibrate, maintain, and operate an approved CEMS to measure and record the following:

    a. Sulfur oxide concentrations in the gases discharged to the atmosphere from affected equipment.

    b. Oxygen concentrations, at each location where sulfur oxide concentration are monitored, if required for calculation of the stack gas flow rate.

    c. Stack gas volumetric flow rate. An in-stack flow meter may be used to determine mass emissions to the atmosphere from affected equipment, except:

    i. when more than one affected piece of equipment vents to the atmosphere through a single stack and there is no approvable means of determining emissions from each piece of equipment, or

    ii. during periods of low flow rates when the flow rate is no longer within the applicable range of the in-stack flow meter.

    d. In lieu of complying with Chapter 2, Subdivision A, Paragraph 1, Subparagraph c if heat input rate is needed to determine the stack gas volumetric flow rate, the Facility Permit holder shall include in the CEMS calculations the F factors listed in 40 CFR Part 60, Appendix A, Method 19, Table 19-1. The Facility Permit holder shall submit data to develop F factors when alternative fuels are fired and obtain the approval of the Executive Officer for use of the Fd factors before firing any alternative fuels.

    e. Fuel gas flow rate if the CEMS uses the fuel gas flow rate and the sulfur content of the fuel gas to determine the sulfur oxide emissions.

    f. Sulfur content of the fuel if the CEMS uses the fuel input rate and the sulfur content of the fuel gas to determine the sulfur oxides emission rate.

    g. All applicable variables listed in Table 2-A.

    h. The Facility Permit holder shall also provide any other data necessary for calculating air contaminant emissions as determined by the Executive Officer.

    i. The data shall be recorded both by strip chart recorders and computer print out. The strip chart shall have a minimum chart width of 10 inches, a readability of 0.5% of the span, and a minimum of 100 chart divisions.

  4. The Facility Permit holder must submit to the District his certification test results and supporting document for each CEMS by December 31, 1994. It must certify that the results show that the CEMS has met all the requirements of the rule if its submission is after August 31, 1994. Upon receipt of the test results and the certification that the CEMS is in compliance, the District will issue a Provisional Approval.

    After the Provisional Approval, all the data measured and recorded by the CEMS will be considered valid quality assured data, (retroactive to January 1, 1995) provided that the Executive Officer does not issue a notice of disapproval of final certification. Final certification of the CEMS will be granted if the certification test results show that the CEMS has met all the requirements of the rule.

    In the case where the test results show that the CEMS does not meet all the requirements of the rule, the Executive Officer will disapprove the final certification. If this occurs, the previously considered valid data from January 1, 1995 will have to be replaced by data as specified in the "Missing Data" section of the rule. This procedure shall be used until the time that new certification test results are submitted, and the CEMS has received final approval by the District.

  5. The variables listed in Table 2-A shall be measured and recorded to track the operation of basic and control equipment independent of measurements made by the monitoring equipment. The variables found in Table 2-B shall be reported to the District's SOx Central Station Computer. Alternatives in Table 2-A and 2-B indicated choices which must be specified in the Facility Permit for that equipment.

  6. As part of the Facility Permit Application review, the Executive Officer may modify the list of Facility Permit holder-selected variables.

  7. Data on Facility Permit holder - selected variables shall be made available to the District staff upon request.

  8. Source tests shall be performed by testing firms/laboratories who have received approval from the District by going through the District's laboratory approval program.

  9. All Relative Accuracy Test Audits (RATA) shall be performed by testing firms/laboratories who have received approval from the District by going through the District's laboratory approval program.

  10. Whenever EPA Protocol 1 gases are not available because National Institute for Standards and Testing (NIST) does not produce Standard Reference Materials (SRMs) for these gases at the appropriate concentration, EPA Protocol 2 (use of gas dilution systems) may be used to certify calibration gas standards. In the case where no SRMs are available, the facility can submit a gas calibration protocol for approval, which specifies the steps to be taken for analyzing the concentration and stability of calibration gases.

B. MONITORING SYSTEMS

  1. Information Required for Each 15-Minute Interval

    All CEMS for affected equipment shall, at a minimum, generate and record the following data points once for each successive 15-minute period on the hour and at equally spaced intervals thereafter:

    a. Sulfur oxide concentration in the stack in units of ppmv.

    b. Oxygen concentration or carbon dioxide in the stack in units of percent.

    c. Volumetric flow rate of stack gases in units of dry or wet standard cubic feet per hour (dscfh or wscfh). For affected equipment standard gas conditions are defined as a temperature at 68°F and one atmosphere of pressure.

    d.

    (i) Fuel flow rates in units of standard cubic feet per hour(scfh) for gaseous fuels or pounds per hour (lb/hr) for liquid fuels if EPA Method 19 is used to calculate the stack gas volumetric flow rate, and

    (ii) Fuel type.

    e. Sulfur oxide mass emissions in units of lb/hour. The sulfur oxide emissions are calculated according to the following:

    ei

    =

    ai x c i x 1.662 x 10-7

    (Eq. 1)

    where:


    ei

    =

    The mass emissions of sulfur oxides (lb/hr),

    ai

    =

    The stack gas concentration of sulfur oxide (ppmv),

    ci

    =

    The stack gas volumetric flow rate (scfh).

    Example Calculation:


    ai

    =

    2.7 ppm


    ci

    =

    90,000 scfh


    ei

    =

    ai x ci x 1.662 x 10-7


    ei

    =

    (2.7)(90,000)(1.662 x 10-7) = 0.04 lb/hr SOx

    When the CEMS uses the heat input rate and oxygen concentration to determine the sulfur oxide emissions, the following equation would be used to calculate the emission of sulfur oxide:




    r



    ei

    =

    ai x [20.9/(20.9 - bi)] x 1.662 x 10-7 x Undisplayed Graphic (Fij x dij x Vij)

    (Eq. 2)




    j=1


    where:




    ei

    =

    The mass emissions of sulfur oxide (lb/hr),


    ai

    =

    The stack gas concentration of sulfur oxide (ppmv),


    bi

    =

    The stack gas concentrations of oxygen (%),


    r

    =

    The number of different types of fuel,


    Fij

    =

    The F factor for each type of fuel, the ratio of the gas volume of the products of combustion to the heat content of the fuel (scf/106 Btu),


    dij

    =

    The metered fuel flow rate for each type of fuel measured every 15-minute period,


    Vij

    =

    The higher heating value of the fuel for each type of fuel.

    The product (dij x Vij) must have units of millions of Btu per hour (106Btu/hr). Equation 2 may not be used in cases where enriched oxygen is used, non-fuel sources of carbon dioxide are present (e.g., lime kilns and calciners), and the oxygen content of the stack gas is 19 percent or greater.

    Example Calculation:





    r



    ei

    =

    ai x [20.9/(20.9 - bi)] x 1.662 x 10-7 x

    Undisplayed Graphic

    (Fdij x dij x Vij)





    j=1



    where:


    ai

    =

    38.9 ppm


    bi

    =

    5.6%


    Fdij

    =

    8710 dscf/106 Btu


    dij

    =

    10,000 dscfh


    Vij

    =

    1394 Btu/dscf


    ei

    =

    38.9 x [20.9/(20.9 - 5.6)] x 1.662 x 10-7 x [8710/106 x 10000 x 1394]


    ei

    =

    1.1 lb/hr of SOx

    When the CEMS uses the heat input rate and carbon dioxide concentration to determine the sulfur oxide emissions, the following equation shall be used to calculate the emission of sulfur oxide:



    r


    ei

    =

    (ai/ti) x 100 x 1.662 x 10-7 x

    Undisplayed Graphic

    (Fcij x dij x Vij)

    (Eq. 3)



    j=1


    where:




    ei

    =

    The mass emissions of sulfur oxide (lb/hr).


    ai

    =

    The stack gas concentration of carbon dioxide (ppmv).


    ti

    =

    The stack gas concentrations of carbon dioxide (%).


    r

    =

    The number of different types of fuel.


    Fcij

    =

    The carbon-based, F factor for each type of fuel, the ratio of the dry gas volume of carbon dioxide to the heat content of the fuel (scf/106 Btu).


    dij

    =

    The metered fuel flow rate for each type of fuel measured every 15-minute period.


    Vij

    =

    The higher heating value of the fuel for each type of fuel.

    The product (dij x Vij) must have units of millions of Btu per hour (106Btu/hr).

    Example Calculation:





    r



    ei

    =

    (ai/ti) x 100 x 1.662 x 10-7 x

    Undisplayed Graphic

    (Fcij x dij x Vij)




    j=1




    where:






    ai

    =

    38.9 ppm


    ti

    =

    11.0%


    dFcij

    =

    1040 scf/106 Btu


    dij

    =

    10,000 dscfh


    Vij

    =

    1394 Btu/dscf


    ei

    =

    (38.9/11.0) x 100 x 1.662 x 10-7 x [1040/106 x 10000 x 1394]


    ei

    =

    0.85 lb/hr of SOx

    When the CEMS uses the fuel gas flow rate and the sulfur content to determine the sulfur oxides emission rate, the CEMS shall use the following equation to calculate the emissions of sulfur oxide:

    ei = si x di x 1.662 x 10-7 (Eq. 4)

    where:



    ei

    =

    The emissions of sulfur oxide (lb/hr),

    si

    =

    The sulfur content of fuel gas (ppmv),

    di

    =

    The fuel gas flow rate (scfh).

    Example Calculation:


    si

    =

    38 ppmv


    di

    =

    1,576,980 scfh = 1.577 x 106 scfh


    ei

    =

    (38)(1.577 x 106 scfh)(1.662 x 10-7) = 9.96 lb/hr.

    f. All measurements for concentrations and stack gas flow rates, and selection of F factor shall be made on a consistent wet or dry basis.

    g. CEMS status. The following codes shall be used to report the CEMS status:

    1-1

    -

    VALID DATA

    2-2

    -

    CALIBRATION

    3-3

    -

    OFF LINE

    4-4

    -

    ALTERNATE DATA ACQUISITION (e.g., manual sampling)

    5-5

    -

    OUT OF CONTROL

    6-6

    -

    FUEL SWITCH (e.g., gas to oil, coke to coal)

    7-7

    -

    10% RANGE (may be used to report at default 10% valid range whenever actual concentration value is below 10%)

    8-8

    -

    LOWER THAN 10% RANGE (may be used to report at actual concentration value if less than 10% valid range

    9-9

    -

    NON-OPERATIONAL

    h. For processes in which less than 50% of emissions are caused by fuel combustion, record the Source Classification Code (SCC) for the process conducted. SCCs are listed in the State of California Air Resources Board Document "Instructions for the Emission Data System Review and Update Report, Appendix III, Source Clasification Codes and EPA Emission Factors".

    i. The count of valid data points collected.

    j. The count of data points in excess of 95% of span range of the monitor collected.

  2. Hourly Calculations

    The hourly average stack gas concentrations of sulfur oxides and oxygen, the stack gas volumetric flow rate, the fuel flow rate, the fuel sulfur content of the fuel gas, and the emission rate of sulfur oxides shall be calculated for each piece of affected equipment as follows:



    n





    Undisplayed Graphic ai





    i=1



    A

    =

    _______

    (for SOx concentration)

    (Eq. 5)



    n





    n





    Undisplayed Graphic bi





    i=1



    B

    =

    ______

    (for O2 concentration)

    (Eq. 6)



    n





    n





    Undisplayed Graphic ci





    i=1




    =

    ______

    (for stack gas volumetric flow rate)

    (Eq. 7)

    C


    n





    n





    Undisplayed Graphic di





    i=1



    D

    =

    ______

    (for fuel flow rates)

    (Eq. 8)



    n



    Calculate D for each type of fuel firing separately.



    n





    Undisplayed Graphic si





    i=1



    S

    =

    ______

    (for sulfur content of fuel gas)

    (Eq. 9)



    n





    n





    Undisplayed Graphic ei





    i=1



    Ek

    =

    _____

    (for SOx emissions)

    (Eq. 10)



    n



    All concentrations and stack gas flow rates shall be made on a consistent wet or dry basis


    where:



    A

    =

    The hourly average stack gas concentration of sulfur oxides (ppmv),


    ai

    =

    The measured stack gas concentrations of sulfur oxides (ppmv),


    B

    =

    The hourly average oxygen stack concentration (%),


    bi

    =

    The measured stack gas concentrations of oxygen (%),


    C

    =

    The hourly average stack gas flow rate (scfh),


    ci

    =

    The measured stack gas volumetric flow rates (scfh),


    D

    =

    The hourly average metered fuel flow rates, for each type of fuel (appropriate units of volumetric flow rate for each type of fuel, e.g., scfh, gal./hr, lb/hr, bbl/hr, liters/hr, etc.),


    di

    =

    The metered fuel flow rates for each type of fuel (appropriate units of volumetric flow rate for each type of fuel, e.g., scfh, gal./hr, lb/hr, bbl/hr, etc.),


    S

    =

    the hourly average sulfur content of the fuel (ppmv),


    Ek

    =

    The hourly average emissions of sulfur oxide (lb/hr),


    ei

    =

    The measured emissions of sulfur oxide (lb/hr),


    n

    =

    Number of valid data points during the hour.

    The values of A through Ek shall be recorded for each affected piece of equipment.

    Example Calculation:


    For SOx concentration:

    a1

    =

    3.0 ppm, a2 = 4.6 ppm, a3 = 12.2 ppm, a4 = 7.0 ppm.



    n






    Undisplayed Graphic ai






    i=1




    A

    =

    ____

    =

    3.0 + 4.6 + 12.2 + 7.0

    =

    6.7 ppm



    n


    4


    For O2 concentration:

    b1,

    =

    3.5% O2, b2 = 5.2%, b3 = 4.4%, b4

    =

    3.0%



    n







    Undisplayed Graphicbi







    i=1





    B

    =

    ____

    =

    3.5 + 5.2 + 4.4 + 3.0

    =

    4.0 %



    n


    4



    For stack gas volumetric flow rate:


    c1 = 89,160 scfh

    c3 = 91,980 scfh



    c2 = 90,120 scfh

    c4 = 89,520 scfh




    n







    Undisplayed Graphic ci







    i=1





    C

    =

    _______

    =

    89,160+90,120+91,980+89,520

    =

    90,195 scfh



    n


    4



    For Sulfur:




    n




    Undisplayed Graphic Si


    S

    =

    i =1

    (for sulfur content of fuel gas)



    n



    S1

    =

    558 ppmv H2S

    S3

    =

    722 ppmv H2S


    S2

    =

    630 ppmv H2S

    S4

    =

    785 ppmv H2S


    S

    =

    588 + 630 + 722 + 785
    4

    =

    681 ppmv H2S

    For fuel flow rate:


    d1

    =

    106,392 scfh

    d3

    =

    101,426 scfh


    d2

    =

    96,504 scfh

    d4

    =

    92,065 scfh



    n







    Undisplayed Graphic di







    i=1





    D

    =

    _____

    =

    106,392+96,504+101,406+92,065

    =

    99,097 scfh



    n


    4



    For SOx emission rate:


    e1

    =

    .032 lb/hr, e2 = .037 lb/hr, e3 = .039 lb/hr, e4 = .041 lb/hr



    n







    Undisplayed Graphicei







    i=1





    Ek

    =

    _____

    =

    .032+.037+.039+.041

    =

    .037 lb/hr.



    n


    4



  3. Daily Calculations

    a. Daily mass emissions calculation

    The daily emissions of sulfur oxides shall be calculated and recorded for each affected SOx source using the following procedure:



    N


    P


    G

    =

    Undisplayed Graphic Ek

    +

    Undisplayed Graphic Em

    (Eq. 11)



    k=1


    m=1


    where:


    G

    =

    The daily emissions of sulfur oxide (lb/day),

    Ek

    =

    The hourly average emission rate using CEMS (lb/hr)

    Em

    =

    The hourly average emission rate of sulfur oxides using substitute data (see Chapter 2, Subdivision B, Paragraph 5, Subparagraph b and Chapter 2, Subdivision F)(lb/hr),

    N

    =

    Number of hours of valid data (see Chapter 2, Subdivision B, Paragraph 5) from the CEMS coinciding with the source operating hours,

    P

    =

    Number of hours using substitute data when the source is operating; and

    M

    =

    Number of operating hours of the source during the day,

    Note that M = N + P

    Example Calculation:


    Em

    =

    1.7 lb/hr


    N

    =

    23 hrs


    P

    =

    1 hr


    M

    =

    24 hr


    Ek

    =

    0.037 lb/hr


    G

    =

    (0.037 lb/hr)(23 hr) + (1.7 lb/hr)(1hr)


    G

    =

    2.55 lb/day SOx

  4. Operational Requirements

    The CEMS shall be operated and data recorded during all periods of operation of the affected SOx source including periods of start-up, shutdown, malfunction or emergency conditions, except for CEMS breakdowns and repairs. Calibration data shall be recorded during zero and span calibration checks, and zero and span adjustments. For periods of hot standby the Facility Permit holder may enter a default value for SOx emissions. Before using any default values the Facility Permit holder must obtain the approval of the Executive Officer and must include in the CEMS applications or CEMS plans the estimates of SOx emissions, the SOx concentrations, the oxygen concentrations, the sulfur content of fuel gas, and the fuel input rates or the stack gas volumetric flow rates during hot standby conditions. The Executive Officer will approve only those emission values which are found to correspond to hot standby conditions.

  5. Requirements for Valid Data Points

    Valid data points are data points from a CEMS which meets the requirements of Chapter 2, Subdivision B, Paragraph 12 and which is not out-of-control as defined in Attachment C - Quality Assurance and Quality Control Procedures. In addition, whenever specifically allowed by these RECLAIM rules, data points obtained by the methods specified in Chapter 2, Subdivision B, Paragraph 6 or Chapter 2, Subdivision B, Paragraph 7, are considered valid. Furthermore, a data point gathered pursuant to Chapter 2, Subdivision B, Paragraph 6 or 12, except a zero value data point, shall not be valid unless it meets the requirements of Chapter 2, Subdivision B, Subparagraph (8)(a). A zero value data point is a data point gathered while the source is not operating and is within 5% of the span range from zero value.

    a. Each CEMS and component thereof shall be capable of completing a minimum of one cycle of operation (sampling, analyzing and data recording) for each successive 15-minute interval.

    b. Raw data shall be gathered from the monitors at equally spaced intervals. The Facility Permit holder shall specify, within the test report for a Relative Accuracy Test Audit of a CEMS, the frequency of data gathering in a 15-minute interval. This data gathering frequency shall remain the same throughout the period following the Relative Accuracy Test Audit until a subsequent Relative Accuracy Test Audit is conducted with a different specified frequency. The specified frequency shall be the frequency for data gathering to constitute continuous measurement.

    c. All valid raw data points gathered from the monitors within a 15-minute interval shall be used to compute a 15-minute average emissions data point. If only one valid data point is gathered within a 15-minute interval, that data point shall be used as the 15-minute average emission data point. No invalid data points may be used to compute the 15-minute average emission data point. A valid 15-minute average emission data point must further be based on a minimum of one valid raw data point.

    d. Except for facilities which are required to comply with 40 CFR Part 75, the following data for each 15-minute period shall be computed for each CEMS:

    i. the average emissions values,

    ii. the count of valid data points, and

    iii. the count of data points in excess of 95% of span range of the monitor.

    e. All SOx concentration, volumetric flow, and SOx emission rate data shall be reduced to 1 hour averages. Valid hour averages shall be equally computed based on four valid 15-minute average emission data points equally spaced over each 1 hour period, comencing at 12:00 a.m., except for a maximum of four 1-hour maintenance periods in each day during which CEMS maintenance activities such as calibration, quality assurance, maintenance, or CEMS repair is conducted. During these 1-hour maintenance periods a valid hour average shall consist of at least two valid 15-minute average emission data points.. A 1-hour maintenance period is defined when the operation of the CEMS is interrupted for CEMS maintenance activities at any time during any 1-hour period, and that period shall count towards the four 1-hour maintenance periods allowed regardless of the number of valid data points gathered. The CEMS shall be kept properly operational at all times unless such CEMS must be turned off for CEMS maintenance activities.

    f. Failure of the CEMS to acquire the required number of valid 15-minute average emission data points within any 1-hour period shall result in the loss of such data for the entire 1-hour period and the Facility Permit holder shall record and report data by means of the data acquisition and handling system for the missing hour in accordance with the applicable procedures for substituting missing data in the Missing Data Procedures in Chapter 2 Subdivision E of this document.

  6. Alternative Data Acquisition Using Reference Methods

    a. When valid sulfur oxides emission data is not collected by the permanently installed CEMS, emission rate data may be obtained using District Methods 6.1 or 100.1 (for SOx concentration in the stack gas) in conjunction with District Methods 1.1, 2.1, 3.1, and 4.1 or by using District Methods 6.1 or 100.1 in conjunction with District Method 3.1 and EPA Method 19. Emission rate data may also be obtained using District Methods 307-91 or ASTM Method D1072-90, Standard Test for Total Sulfur in Fuel Gases (for sulfur content in the fuel gas) in conjunction with the fuel gas flow rate.

    b. If the Facility Permit holder chooses to use a standby CEMS (such as in a mobile van or other configuration), to obtain alternative monitoring data at such times when the permanently installed CEMS for the affected source(s) cannot produce valid data, then the standby CEMS is subject to the following requirements:

    i. Standby CEMS shall be equivalent in relative accuracy, reliability, reproducibility and timeliness to the corresponding permanently installed CEMS.

    ii. The Facility Permit holder shall submit a standby CEMS plan to the District for review prior to using the standby CEMS.

    iii. District acceptance of standby CEMS data shall be contingent on District approval of the plan.

    iv. The use of standby CEMS shall be limited to a total of 6 months for any source(s) within a calendar year.

    v. The Facility Permit holder shall notify the District within 24 hours if the standby CEMS is to be used in place of the permanently installed CEMS.

    vi. During the first 30 days of standby CEMS use, the Facility Permit holder shall conduct a Certified Gas Audit (CGA) of the standby CEMS.

    vii. The Facility Permit holder shall notify the District within the 30-day period if the standby CEMS shall be used longer than 30 days.

    viii. After the first 30 days of using the standby CEMS, the Facility Permit holder shall conduct at least one RATA of the standby CEMS and the RATA shall be conducted within 90 days of the initial use of the standby CEMS.

    ix. All RATA and CGA shall be performed by testing firms/laboratories who have received approval from the District by going through the District's laboratory approval program.

    x. Immediately prior to obtaining data from the source(s) to be monitored, the standby CEMS shall be quality assured in accordance with District Method 100.1

  7. Alternative Data Acquisition Using Process Curves or Other Means

    Process curves of SOx emissions or other alternative means of SOx emission data generation shall be used to obtain sulfur oxides emission data, provided the Facility Permit holder has obtained the approval of the Executive Officer prior to using alternate means of SOx emission data generation. The process curves and the alternate means of SOx emission data generation mentioned in this paragraph shall not be used more than 72 hours per calendar month and shall only be used if no CEMS data or reference method data gathered under Chapter 2, Subdivision B, Paragraph 6 is available. Process curves may be used on units which have air pollution control devices for the control of sulfur oxides emissions provided the Facility Permit holder submits a complete list of operating conditions that characterize the permitted operation. The conditions must be specified in the Facility Permit for that equipment. The process variables specified in the Facility Permit conditions must be monitored by the source.

  8. Span Range Requirements for SOx Analyzers or Fuel Gas Sulfur Analyzers and O2 Analyzers

    a. Full scale span ranges for the SOx analyzers and O2 analyzers used as part of a stack gas volumetric flow system at each source shall be set on an individual basis. The full scale span range of the SOx analyzers and O2 analyzers shall be set so that all data points gathered by the CEMS lie within 10 - 95 percent of the full scale span range. However, any data points that fall below 10 percent of the full scale span range may be reported in accordance with 8(b), 8(c), or 8(d) as applicable. Missing Data Procedures as prescribed in Chapter 2, Subdivision E shall be substituted for any data points falling above 95 percent range of the full scale span range.

    b. For CEMS with RECLAIM certified multiple span ranges, the Facility Permit holder shall report data that falls below 10 percent of the higher full scale span range and above 95 percent of the lower full scale span range, at the 10 percent value of the higher full scale span range.

    c. In the event that any data points gathered by the CEMS fall below 10 percent of the full scale span range, the Facility Permit holder may elect to report SOx concentrations at the 10 percent full scale span range value.

    d. In the event that any data points gathered by the CEMS fall below 10 percent of the lowest vendor guaranteed full scale span range for that CEMS (defined as the lowest full scale span range that the vendor guarantees to be capable of meeting all current certification requirements of RECLAIM in Rule 2011 Protocols, Appendix A), the Facility Permit holder may elect to use the following procedures to measure and report SOx concentrations.

    i. Report all monitored concentrations that fall below 10 percent of the lowest vendor guaranteed full scale span range for that CEMS at the 10 percent lowest vendor guaranteed full scale span range value, or

    ii. Report all monitored concentrations that fall below 10 percent of the lowest vendor guaranteed full scale span range for that CEMS at the actual measured value, provided that the CEMS meets the Alternative Performance Requirements prescribed in Attachment F.

    The Alternative Performance Requirements prescribed in Attachment F shall be imposed in place of the semiannual assessments as required pursuant to Attachment C (B)(2).

    e. The Facility Permit holder electing to use (B)(8)(c) and (B)(8)(d)(i) to report SOx concentrations that fall below 10 percent of full scale span range or 10 percent of the lowest vendor guaranteed full scale span range for that CEMS, shall meet the following:

    i. In the event any of the specified testing requirements as prescribed in Attachment C (B)(2) are not met, the Facility Permit holder shall no longer use (B)(8)(c) or (B)(8)(d)(i) to report SOx concentrations below 10 percent of the full scale span range until compliance is demonstrated. Missing Data Procedures specified in Chapter 2, Subdivision E shall apply retroactively from the date in which the Facility Permit holder last demonstrated compliance with Attachment C (B)(2).

    ii. From September 8, 1995 to the beginning of the compliance year (January 1, 1995 for Cycle 1 and July 1, 1995 for Cycle 2), the Facility Permit holder may retroactively report concentrations that fell below 10 percent of the full scale span range at the 10 percent span range value, in lieu of using the Missing Data Procedures specified in Chapter 2, Subdivision E.

    f. The Facility Permit holder electing to use (B)(8)(d)(ii) to measure and report SOx concentrations that fall below 10 percent of the lowest vendor guaranteed full scale span range for that CEMS, shall meet the following:

    i. Submit an application, with the appropriate fees, supporting documentation, and if necessary test protocols to the Executive Officer or designee in order to amend their CEMS Certification Plan to include the selected criteria. The application shall be approved by the Executive Officer or designee prior to using (B)(8)(d)(ii).

    ii. (B)(8)(d)(ii) may only be chosen after initial tests as prescribed in Attachment F are completed and demonstrate that the CEMS is capable of measuring SOx concentrations at below 10 percent of the full scale span range.

    iii. In the event any of the specified reporting and testing requirements for (B)(8)(d)(ii) as prescribed in Attachment F are not met, the Facility Permit holder shall no longer use (B)(8)(d)(ii) to measure SOx concentrations below 10 percent of the lowest vendor guaranteed full scale span range for that CEMS until compliance with (B)(8)(d)(ii) is demonstrated. Missing Data Procedures described in Chapter 2, Subdivision E shall apply retroactively from the date in which the Facility Permit holder last demonstrated compliance with (B)(8)(d)(ii), unless the Facility Permit holder can demonstrate compliance with Attachment C (B)(2), then the Facility Permit holder may report concentrations retroactively at the 10 percent lowest vendor guaranteed span range value and may continue to report at the 10 percent lowest vendor guaranteed span range value until compliance is demonstrated with (B)(8)(d)(ii).

    iv. In the event that the SOx concentrations are at levels such that the Facility Permit holder cannot complete the low level spike recovery test or alternative reference method test for low level concentrations pursuant to Attachment F, then the Facility Permit holder may elect to report all monitored concentrations that fall below 10 percent of the lowest vendor guaranteed full scale span range at the 10 percent lowest vendor guaranteed full scale span range value, in lieu of using Missing Data Procedures.

    v. Upon approval of the CEMS application to use (B)(8)(d)(ii), the Facility Permit holder may retroactively report concentrations at the 10 percent lowest vendor guaranteed span range value in lieu of using the Missing Data Procedures specified Chapter 2, Subdivision E, from the beginning of the compliance year for which the application was submitted up until the application approval date.

    g. Up until July 1, 1996, Facility Permit holders whose CEMS have been provisionally or finally certified prior to September 8, 1995, and have used Missing Data Procedures as prescribed in Chapter 2, Subdivision E to report mass emissions that have been measured by the CEMS in the 10 percent to less than 20 percent of full scale span range, may report the actual concentrations measured in this range as valid data retroactively from the beginning of the current compliance year.

  9. Calibration Drift Requirements

    The CEMS design shall allow determination of calibration drift (both negative and positive) at zero level (0 to 10 percent of full scale and high-level (80 to 100 percent of full scale) values. Alternative low-level and high-level span values shall be allowed with the prior written approval of the Executive Officer.

  10. Relative Accuracy Requirements for Stack Gas Volumetric Flow Measurement Systems

    The stack gas volumetric flow measurement system shall meet a relative accuracy requirement of being less than or equal to 15 percent of the mean value of the reference method test data in units of standard cubic feet per hour (scfh). Relative accuracy is calculated by the equations in Section 8 of 40 CFR Part 60, Appendix B, Performance Specification 2. The volumetric flow measurement system shall also meet the specifications in Attachment B (BIAS TEST) of this protocol. The District recommends (but does not require) performing a flow profile study following the procedures in 40 CFR, Part 60, Appendix A, Test Method 1, Section 2.5 to determine the acceptability of the potential flow monitor location and to determine the number and location of flow sampling points required to obtain a representative flow value.

    In situations where the stack gas velocity is low (less than 10 ft./sec.) and the above relative accuracy procedure provides results that have a low level of accuracy and precision, the relative accuracy of the fuel flow meter may be determined according to one of the following alternatives:

    a. Calibrate the facility CEMS fuel flow meter in accordance with the procedures outlined in 40 CFR Part 75, Appendix D, either in-line or off-line.

    b. Calibrate a test fuel flow meter in accordance with the procedures outlined in 40 CFR Part 75, Appendix D. Use the calibrated test fuel meter to calibrate the facility CEMS fuel flow meter to the same level of accuracy and precision as in 40 CFR Part 75, Appendix D.

    c. Calibrate a test fuel flow meter according to the procedure outlined in (B)(10)(b) and install this meter in line with the facility CEMS fuel flow meter and use 40 CFR Part 60, Method 19 (F-factor approach) to determine relative accuracy to the same level of accuracy as in (B)(10).

    Other alternative techniques (e.g., tracer gas approach, electronic micro-manometer) may be used to determine relative accuracy of fuel flow meters where low stack volumetric flow rates exist, if these techniques are approved in writing by the District.

  11. Quality Assurance for Fuel Flow Meters

    Fuel flow measuring devices used for obtaining stack flow in conjunction with F-factors shall be tested as installed for relative accuracy using reference methods to determine stack flow.

    If the flow device manufacturer has a method or device that permits the fuel flow measuring device to be tested as installed for relative accuracy, the Facility Permit holder shall request approval from the Executive Officer. Approval will be granted in cases where the Facility Permit holder can demonstrate to the satisfaction of the Executive Officer that no suitable testing location exists in the exhaust stacks or ducts and that it would be an inordinate cost burden to modify the exhaust stack configuration to provide a suitable testing location. The method or device used for relative accuracy testing shall be traceable to NIST standards. This method shall be used only if natural gas, fuel oil, or other fuels can be shown, by the Facility Permit holder to have stable F-factors and gross heating values, or if the Facility Permit holder measures the F-factor and gross heating value of the fuel. A stable F-Factor is defined as not varying by more than +/-2.5 % from the constant value used for F-Factor. For the fuels listed in 40 CFR 60, Appendix A, Method 19, Table 19-1, the F-Factors are assumed to be stable at the value cited in Table 19-1. Any F-Factor cited in Regulation XX shall supersede the F-Factor in Table 19-1. For fuels not listed in the citations above, but which the Facility Permit holder can demonstrate that the source-specific F-Factor meets the same stability criteria, periodic reporting of F-Factor may be accepted and the adequacy to the frequency of analysis shall be demonstrated by the facility such that the probability that any given analysis will differ from the previous analysis by more than 5% (relative to the previous analysis) is less than 5%. Analysis records shall be maintained, including all charts and laboratory notes.

  12. Relative Accuracy Requirements for Emission Rate Measurement

    The emission rate measurement shall meet a relative accuracy requirement of being less than or equal to 20 percent of the mean value of the reference method test data in units of lb/hr. Relative accuracy is calculated by the equations in Section 8 of 40 CFR Part 60, Appendix B, Performance Specification 2. The emission rate measurement shall also meet the specifications in Attachment B (BIAS TEST) of this Appendix A.

  13. Certification Requirements for Analyzers

    The portion of the CEMS which samples, conditions, analyzes, and records the sulfur oxides and oxygen concentrations in the stack gas or the sulfur in the fuel gas shall be certified according to the specifications in 40 CFR, Part 60, Appendix B, Performance Specifications 2 and 3. The portion of the CEMS which samples, conditions, analyzes, and records the sulfur in the fuel gas shall be certified using the specifications in 40 CFR, Part 60, Appendix B, Performance Specification 2 with the exception that District Method 307-91 shall be used for reference method to determine the sulfur content in the fuel gas. Units using monitors with more than one span range must perform the calibration error test on all span ranges. This portion of the CEMS shall also meet the specifications in Attachment B of this Appendix A.

  14. Provisional Approval

    The Facility Permit holder of a major source shall submit certification test results and supporting documents to the District for each CEMS by December 31, 1994 for Cycle 1 facilities and June 30, 1995 for Cycle 2 facilities. The Facility Permit holder shall certify that the results show that the CEMS has met all the requirements of the protocol if its submission is after August 31, 1994. Upon receipt of the test results and the certification that the CEMS is in compliance, the District will issue a Provisional Approval.

    After the Provisional Approval, all the data measured and recorded by the CEMS will be considered valid quality assured data, (retroactive to January 1, 1995) provided that the Executive Officer does not issue a notice of disapproval of final certification. Final certification of the CEMS will be granted if the certification test results show that the CEMS has met all the requirements of the protocol.

    In the case where the test results show that the CEMS does not meet all the requirements of the rule, the Executive Officer will disapprove the final certification. If this occurs, the previously considered valid data from January 1, 1995 will be replaced by data as specified in the "Missing Data" section of the protocol. This procedure shall be used until the time that new certification test results are submitted, and the CEMS has received final approval by the District.

  15. Sampling Location Requirements

    Each affected piece of equipment shall have sampling locations which meet the "Guidelines for Construction of Sampling and Testing Facilities" in the District Source Test Manual. If an alternate location (not conforming to the criteria of eight duct diameters downstream and two diameters upstream from a flow disturbance) is used, the absence of flow disturbance shall be demonstrated by using the District method in the Source Test Manual, Chapter X, Section 1.4 or 40 CFR, Part 60, Appendix A, Method 1. Section 2.5 and the absence of stratification shall be demonstrated using District method in the Source Test Manual, Chapter X, Section 13.

  16. Sampling Line Requirement

    The CEMS sample line from the CEMS probe to the sample conditioning system shall be heated to maintain the sample temperature above the dew point of the sample. This requirement does not apply to dilution probe systems where no sample condensation occurs.

  17. Recertification Requirements

    The District will reevaluate the monitoring systems at any affected piece of equipment where changes to the basic process equipment or air pollution control equipment occur, to determine the proper full span range of the monitors. Any monitor system requiring change to its full span range in order to meet the criteria in Chapter 2,. Subdivision B, Paragraph 8 shall be recertified according to all the specifications in Chapter 2, Subdivision B, Paragraph 10, Chapter 2, Subdivision B, Paragraph 11, and Chapter 2, Subdivision B, Paragraph 12 as applicable, including the relative accuracy tests, the calibration drift tests, and the calibration error tests. A new CEMS plan shall be submitted for each CEMS which is reevaluated.

    The recertification for any existing CEMS shall be completed within 90 days of the start-up of newly changed or modified equipment monitored by such CEMS. The Facility Permit holder shall calculate and report SOx emission data for the period prior to the CEMS recertification by means of the automated data acquisition and handling system according to the following procedures:

    a. For any CEMS which is recertified within 90 days of start-up of the newly modified equipment, the emission data recorded by the CEMS prior to the recertification would be considered valid and shall be used for calculating and reporting SOx emissions for the equipment it serves.

    b. For any CEMS which is not recertified within 90 days of start-up of the newly modified equipment, the 90th percentile emission data (lb/day) for the previous 90 unit operating days recorded by the CEMS prior to the recertification shall be used for calculating and reporting SOx emissions for the equipment it serves.

  18. Quality Assurance Procedures for Analyzers

    The quality assurance and quality control requirements for analyzers, flow monitors, and SO2 emission rate systems are given in Attachment C (QUALITY ASSURANCE AND QUALITY CONTROL PROCEDURES) of these guidelines. The quality assurance plans required by Attachment C of these protocols shall be submitted along with the CEMS certification application to the District for the approval of the Executive Officer. Source test and monitoring equipment inspection reports required by the Protocols shall be kept on-site for at least three years. The reference method tests are those methods specified in Chapter 6 (Reference Methods). Any CEMS which is deemed out-of-control by Attachment C shall be corrected, retested by the appropriate audit procedure, and restored to in-control status within 24 hours after being deemed out-of-control. If the CEMS is not in-control at the end of the 24-hour period, the CEMS data shall be gathered using the methods in Chapter 2, Subdivision B, Paragraph 6 and Chapter 2, Subdivision B, Paragraph 7. All data which is gathered in order to comply with Attachment C shall be maintained for three years and be made available to the Executive Officer upon request. Any such data which is invalidated shall be identified and reasons provided for any data invalidation. The sulfur oxides, oxygen, and fuel gas sulfur monitors shall also meet the specifications in Attachment B (BIAS TEST).

  19. Calibration Gas Traceability

    All calibration gases used during certification tests and quality assurance and quality control activities shall be certified according to 40 CFR, Part 75, Appendix H - Revised Traceability Protocol No. 1.

  20. Relative Accuracy Test Audits Report Submittal

    A test report shall be submitted to the District for each semi-annual or annual assessment test of a CEMS as required under Paragraph (B)(2) of Attachment C - Quality Assurance and Quality Control Procedures. Such report shall be submitted on or before the end of the quarter following the date of a required test.

C. REPORTING PROCEDURES

  1. Interim Reporting Procedures

    a. From January 1, 1994 until December 31, 1994 (Cycle 1 facilities) and July 1, 1994 until June 30, 1995 (Cycle 2 facilities), the Facility Permit holder shall be allowed to use an interim procedure for data reporting and storage. The Facility Permit holder shall submit as part of the Facility Permit application, the methodology for interim data reporting and storage. The Facility Permit application shall be subject to the approval of the Executive Officer and shall, at a minimum, meet the requirements of Chapter 2, Subdivision C, Paragraph 1, Subparagraphs b, c and d.

    b. All the data required in Chapter 2, Subdivision C, Paragraph 1, Subparagraphs c and d shall be made available to the Executive Officer.

    c. For each affected piece of equipment the following information shall be stored on site in a format approved by the Executive Officer.

    i. Calendar dates covered in the reporting period.

    ii. Each daily emissions (lb/day) and each hourly emissions (lb/hour).

    iii. Identification of the operating hours for which a sufficient number of valid data points has not been taken; reasons for not taking sufficient data; and a description of corrective action taken.

    d. The following information for the entire facility shall be reported on a monthly basis in a format approved by the Executive officer:

    i. Calendar dates covered in the reporting period.

    ii. The sum of the daily emissions (lb/day) from each affected SOx RECLAIM sources.

    e. All data required by Chapter 2, Subdivision B, Paragraphs 1,2,3,4,5 and Chapter 2, Subdivision C, Paragraph 1, Subparagraphs c and d shall be recorded and/or transmitted to the District in a format approved by the Executive Officer.

  2. Final Reporting Procedures

    a. On and after January 1, 1995 (Cycle 1 facilities) and July 1, 1995 (Cycle 2 facilities), the RTU installed at each location shall be used to electronically report total daily mass emissions of SOx and daily status codes to the District Central SOx Station.

    b. On and after January 1, 1995 (Cycle 1 Facilities) and July 1, 1995 (Cycle 2 Facilities), the Facility Permit holder shall submit to the Executive Officer a Monthly Emissions Report in the manner and form specified by the Executive Officer within ten calendar days of the close of each calendar month.

    c. On and after January 1, 1995, (Cycle 1 facilities) and July 1, 1995 (Cycle 2 facilities), all or part of the interim data storage systems shall remain as continuous backup systems.

    d. An alternate backup data storage system shall be implemented, upon request.

D. ALTERNATIVE PROCEDURES FOR EMISSION STACK FLOW RATE DETERMINATION

  1. Multiple Sources Venting to a Common Stack

    In the event that more than one source vents to a common stack, the alternative reference method for determining individual source flow rates shall use the F-factors in EPA Method 19 and the following equation:

    r

    ci = [20.9/(20.9 - bi)] x Undisplayed Graphic (Fdij x dij x Vij) (Eq. 12)

    j=1

    where:




    ci

    =

    The stack gas volumetric flow rate (scfh),


    bi

    =

    The stack gas concentrations of oxygen (%),


    r

    =

    The number of different types of fuel,


    Fdij

    =

    The F factor for each type of fuel, the ratio of the gas volume of the products of combustion to the 0heat content of the fuel (scf/106 Btu),


    dij

    =

    The metered fuel flow rate for each type of fuel measured every 15-minute period,


    Vij

    =

    The higher heating value of the fuel for each type of fuel

    The product (dij x Vij) must have units of millions of Btu per hour (106 Btu/hr). All concentrations and stack gas flow rates shall be calculated on a consistent wet or dry basis. The measurement of wet concentration and wet F factor shall be allowed provided that wet concentration of SOx is measured.

    Example Calculation:


    Gaseous Fuel


    bi

    =

    4.2% O2


    Fdji

    =

    8710 dscf/106 Btu


    dji

    =

    50,000 scfh


    Vji

    =

    1050 Btu/dscf


    cig

    =

    [20.9/(20.9 - 4.2)] x [(8710/106)(50,000)(1050)


    cig

    =

    570,938 dscfh


    Liquid Fuel:


    bi

    =

    4.2% O2


    Fdji

    =

    9,190 dscf/106 Btu


    dji

    =

    500 gal/hr.


    Vji

    =

    136,000 Btu/gal.


    cil

    =

    (20.9/20.9 - 4.2)(9,190/106)(136,000)(500) = 781,150 dscfh


    Total Stack Flow Rate = cig + cil = 570,938 + 781,150 = 1,352,088 dscfh

    This method shall be used for applicable sources before and after the interim period mentioned in Chapter 2, Subdivision C, Paragraph 1. The orifice plates used in each affected piece of equipment vented to a common stack shall meet the requirements in Chapter 2, Subdivision D, Paragraph 2.

  2. Quality Assurance for Orifice Plate Measurements (Applies Only to Multiple Sources Venting to a Common Stack)

    Each orifice plate used to measure the fuel gas flow rate shall be checked once every 12 months using Reference Methods. If the orifice plate cannot be checked using Reference Methods, it may be checked using other methods that can show traceability to NIST Standards. If the orifice plate cannot be checked by Reference Methods or other methods that can show traceability to NIST standards, the orifice plate shall be removed from the gas supply line for an inspection once every 12 months, and the following inspection procedure shall be followed:

    a. Each orifice plate shall be visually inspected for any nicks, dents, corrosion, erosion, or any other signs of damage according to the orifice plate manufacturer's specifications.

    b. The diameter of each orifice shall be measured using the method recommended by the orifice plate manufacturer.

    c. The flatness of the orifice plate shall be checked according to the orifice plate manufacturer's instructions. The departure from flatness of an orifice plate shall not exceed 0.010 inches per inch of dam height (D-d/2) along any diameter. Here D is the inside pipe diameter and d is the orifice diameter at its narrowest constriction.

    d. The pressure gauge or other device measuring pressure drop across the orifice shall be calibrated against a manometer, and shall be replaced if it deviates more than ±2 percent across the range.

    e. The surface roughness shall be measured using the method recommended by the orifice plate manufacturer. The surface roughness of an orifice plate shall not exceed 50 microinches.

    f. The upstream edge of the measuring orifice shall be square and sharp so that it shall not show a beam of light when checked with an orifice gauge.

    g. In centering orifice plates, the orifice shall be concentric with the inside of the meter tube or fitting. The concentricity shall be maintained within 3 percent of the inside diameter of the tube or fitting along all diameters.

    h. Any other calibration tests specified by the orifice plate manufacturer shall be conducted at this time.

    If an orifice plate fails to meet any of the manufacturer's specifications, it shall be replaced within two weeks.

  3. Fuel flow measuring devices used for obtaining stack flow in conjunction with F-factors shall be tested as installed for relative accuracy using reference methods to determine stack flow

    If the flow device manufacturer has a method or device that permits the fuel flow measuring device to be tested as installed for relative accuracy, the Facility Permit holder shall request approval from the Executive Officer. Approval will be granted in cases where the Facility Permit holder can demonstrate to the satisfaction of the Executive Officer that no suitable testing location exists in the exhaust stacks or ducts and that it would be an inordinate cost burden to modify the exhaust stack configuration to provide a suitable testing location. The method or device used for relative accuracy testing shall be traceable to NIST standards. This method shall be used only if natural gas, fuel oil, or other fuels can be shown, by the Facility Permit holder to have stable F-factors and gross heating values, or if the Facility Permit holder measures the F-factor and gross heating value of the fuel. A stable F-Factor is defined as not varying by more than +/-2.5 % from the constant value used for F-Factor. For the fuels listed in 40 CFR 60, Appendix A, Method 19, Table 19-1, the F-Factors are assumed to be stable at the value cited in Table 19-1. Any F-Factor cited in Regulation XX shall supersede the F-Factor in Table 19-1. For fuels not listed in the citations above, but which the Facility Permit holder can demonstrate that the source-specific F-Factor meets the same stability criteria, periodic reporting of F-Factor may be accepted and the adequacy to the frequency of analysis shall be demonstrated by the facility such that the probability that any given analysis will differ from the previous analysis by more than 5% (relative to the previous analysis) is less than 5%. Analysis records shall be maintained, including all charts and laboratory notes.

E. MISSING DATA PROCEDURES

No later than January 1, 1998, the following Missing Data Procedures shall be used to determine substitute data whenever a valid hour of SOx emission data or fuel gas total sulfur content data has not been obtained or recorded. Prior to January 1, 1998, the following procedures or the Missing Data Procedures in effect as of July 12, 1996 may be used.

  1. Procedures for Missing SOx Concentration Data or Fuel Gas Sulfur Content Data

    For each equipment, whenever a valid hour of SOx pollution concentration or fuel gas total sulfur content data has not been obtained or recorded, the Facility Permit holder shall provide substitute data using the procedures below. Alternatively, a facility may provide SOx pollution concentration missing data using the procedure in 40 CFR Part 75 Subpart D if the relative accuracy of the pollutant analyzer and flow measurement system during the last CEMS certification test and/or RATA are both less than 10%.

    a. The Facility Permit holder shall calculate on a daily basis the percent data availability from the SOx pollutant concentration monitoring analyzer or the fuel gas sulfur content monitoring analyzer according to the following procedures.

    i. Calculate on a daily basis a rolling percentage of the operating hours of each equipment that each concentration monitoring system was available for the period from the date the SOx pollutant concentration monitoring analyzer was provisionally certified or 365 days prior to the current date (not counting the current day), whichever date is later, to the day previous to the current date.

    ii. Record on a daily basis the percent annual concentration monitor availability using the following equation:

    W = Y/Z x 100% (Eq.13)

    where:

    W

    =

    the percent annual monitor availability

    Y

    =

    the total operating hours for which the monitor provided quality-assured data during the period from the date the SOx pollutant concentration monitoring analyzer was provisionally certified or 365 days prior to the current date (not counting the current day), whichever date is later, to the day previous to the current date.

    Z

    =

    the total operating hours of the affected piece of equipment during the period from the date the SOx pollutant concentration monitoring analyzer was provisionally certified or 365 days prior to the current date (not counting the current day), whichever date is later, to the day previous to the current date.

    Example Calculation:


    Y

    =

    1,680 hrs


    Z

    =

    2,160 hrs


    W

    =

    Y/Z x 100%


    W

    =

    (1,680/2,160) x 100%


    W

    =

    78%

    b. Whenever the percent annual monitor availability is 95 percent or more, the Facility Permit holder shall calculate substitute data for each hour according to the following procedures.

    i. For a missing data period less than or equal to 24 hours, substitute data shall be calculated using the 1N Procedure in Attachment A. If insufficient data is available to perform this calculation, substitute data shall be calculated pursuant to clause E(1)(b)(ii).

    ii. For a missing data period greater than 24 hours, substitute data shall be calculated using the maximum hourly concentration recorded by the concentration monitor for the previous 30 days. If no emissions occurred during the previous 30 days, substitute data shall be calculated pursuant to clause E(1)(c)(iii).

    c.

    i. Whenever the percent annual monitor availability is 90-percent or more but less than 95-percent, the Facility Permit holder shall calculate substitute data for each hour according to the following procedures.
    I. For a missing data period of less than or equal to 3 hours, substitute data shall be calculated using the average of the recorded concentration for the hour immediately before the missing data period and the hour immediately after the missing data period. If no emissions occurred during the hour immediately before the missing data period or the hour immediately after the missing data period, substitute data shall be calculated pursuant to clause E(1)(c)(ii).

    II. For a missing data period of more than 3 hours but less than or equal to 24 hours, substitute data shall be calculated using the maximum hourly concentration recorded by the concentration monitor for the previous 30 days. If no emissions occurred during the previous 30 days, substitute data shall be calculated pursuant to clause E(1)(c)(iii).

    III. For a missing data period of greater than 24 hours, substitute data shall be calculated using the maximum hourly concentration recorded by the concentration monitor for the previous 365 days. If no emissions occurred during the previous 365 days, substitute data shall be calculated pursuant to subparagraph E(1)(d).

    ii. Whenever the percent annual monitor availability is less than 90 percent, substitute data shall be calculated using the highest hourly concentration recorded during the service of the monitoring system. For the purpose of this subparagraph, service of the monitoring system shall start from the initial certification date of the analyzer or the date when a decrease in the valid range of the monitoring system is approved by the Executive Officer.

    d. For missing data periods where there is no prior CEMS data available or the highest CEMS data is zero:

    i. for less than or equal to 24 hours, the mass emissions shall be calculated using totalized fuel usage and the starting emission factor specified in Table 2 of Rule 2002 or any alternative emission factor used in the determination of initial allocations; or

    ii. For less than or equal to 24 hours and where fuel usage is not available, the mass emissions shall be calculated using the equipment maximum rated capacity, 100 percent equipment uptime, and the starting emission factor specified in Table 2 of Rule 2002; or

    iii for greater than 24 hours, the mass emissions shall be calculated using the equipment maximum rated capacity, 100 percent uptime, and uncontrolled emission factors. An uncontrolled emission factor is an emission factor representative of the emissions prior to any emission control equipment from the source. An uncontrolled emission factor can be determined based on the starting emission factor used in the determination of initial allocations discounted by any control efficiency, or based on source test data. In determining a control efficiency, the facility permit holder may use source test data.

    iv. Retroactively from January 1, 1995 and ending June 30, 1995, for Cycle 1 Facility Permit holders with major SOx sources that do not have an approved RECLAIM certified CEMS, may calculate SOx daily mass emissions in lieu of the procedures specified in the above clauses E(1)(d)(i), E(1)(d)(ii), and E(1)(d)(iii), using (1) the emission factor specified in Table 2 of Rule 2002 or any alternative factor used in the determination of initial allocations or specified in the facility permit and (2) the totalized fuel usage or process throughput.

    v. Facility Permit holders with SOx major sources which demonstrate to the satisfaction of the Executive Officer or designee that standard equipment is not available for measuring exhaust emissions for the purpose of RECLAIM CEMS certification may submit an application by December 31, 1995 to use an alternative exhaust gas and/or pollutant concentration measuring equipment. Such equipment must employ commercially available technology, and must be demonstrated to meet all the requirements of CEMS certification. Upon approval of the application, the Facility Permit holder may calculate SOx daily mass emissions in lieu of the procedures specified in clauses E(1)(d)(i), E(1)(d)(ii), and E(1)(d)(iii), using the alternate method of (1) the emission factor specified in the facility permit and (2) the totalized fuel usage or process throughput. Such calculation of SOx mass emissions may be done retroactively from July 1, 1995 and ending December 31, 1997 or until the CEMS is finally certified, whichever is earlier. The alternate method of calculating mass emissions shall be applied after the proposed equipment has been approved by the Executive Officer. If the CEMS is not certified by December 31, 1997, then SOx daily mass emissions shall be calculated by the procedures specified in clauses E(1)(d)(i), E(1)(d)(ii), and E(1)(d)(iii) retroactive to July 1, 1995.

    vi. If the Facility Permit holder demonstrates that standard equipment is not available but alternative equipment is commercially available as set forth in (E)(1)(d)(v) and also demonstrates to the satisfaction of the Executive Officer or designee that their CEMS cannot be certified because (1) there is an inordinate cost burden for flow monitoring as specified under (B)(11) and (2) that the Reference Methods, as specified in Rule 2011(h)(1) and Appendix A, cannot be applied because no suitable testing location exists in the exhaust stacks or ducts, then the Facility Permit holder may submit an alternative CEMS plan for certification by December 31, 1995. This plan must demonstrate that the proposed monitoring system complies with all other requirements of CEMS certification and is the most technically feasible in measurement accuracy. Until the alternative CEMS is certified or up until December 31, 1997, whichever is earlier, and retroactive to July 1, 1995, the Facility Permit holder may calculate SOx daily mass emissions in lieu of the procedures specified in clauses E(1)(d)(i), E(1)(d)(ii), and E(1)(d)(iii), using the alternate method of (1) the emission factor specified in the facility permit and (2) the totalized fuel usage or process throughput. If the CEMS is not certified by December 31, 1997, then SOx daily mass emissions shall be calculated by the procedures specified in clauses E(1)(d)(i), E(1)(d)(ii), and E(1)(d)(iii).

  2. Procedures for Missing Stack Exhaust Gas Flow Rate Data

    For each equipment, whenever a valid hour of stack exhaust gas flow rate data has not been obtained or recorded, the Facility Permit holder shall provide substitute data using the procedures below. Alternatively, a facility may provide stack exhaust gas flow rate missing data using the procedure in 40 CFR Part 75 Subpart D if the relative accuracy of the pollutant analyzer, flow measurement system, and emission rate measurement during the last CEMS certification test and/or RATA are all less than 10%.

    a. The Facility Permit holder shall calculate on a daily basis the percent data availability from the flow monitoring system according to the following procedures.

    i. Calculate on a daily basis a rolling percentage of the operating hours of each equipment that each flow monitoring system was available for the period from the date the SOx pollutant concentration monitoring analyzer was provisionally certified or 365 days prior to the current date (not counting the current day), whichever date is later, to the day previous to the current date.

    ii. Record on a daily basis the percent annual flow monitor availability using the following equation:

    W = Y/Z x 100% (Eq. 14)

    where:

    W

    =

    the percent annual flow monitor availability

    Y

    =

    the total operating hours for which the monitor provided quality-assured data during the period from the date the SOx pollutant concentration monitoring analyzer was provisionally certified or 365 days prior to the current date (not counting the current day), whichever date is later, to the day previous to the current date.

    Z

    =

    the total operating hours of the affected piece of equipment during the period from the date the SOx pollutant concentration monitoring analyzer was provisionally certified or 365 days prior to the current date (not counting the current day), whichever date is later, to the day previous to the current date.

    Example Calculation:





    Y

    =

    1,680 hrs


    Z

    =

    2,160 hrs


    W

    =

    Y/Z x 100%


    W

    =

    (1,680/2,160) x 100%


    W

    =

    78%

    b. Whenever the percent annual flow monitor availability is 95 percent or more, the Facility Permit holder shall calculate substitute data for each hour according to the following procedures.

    i. For a missing data period less than or equal to 24 hours, substitute data shall be calculated using the 1N Procedure in Attachment-A. If insufficient data is available to perform this calculation, substitute data shall be calculated pursuant to clause E(2)(b)(ii).

    ii. For a missing data period greater than 24 hours, substitute data shall be calculated using the maximum hourly flow recorded by the flow monitor for the previous 30 days. If no emissions occurred during the previous 30 days, substitute data shall be calculated pursuant to clause E(2)(c)(iii).

    c. Whenever the percent annual flow monitor availability is 90-percent or more but less than 95-percent, the Facility Permit holder shall calculate substitute data for each hour according to the following procedures.

    i. For a missing data period of less than or equal to 3 hours, substitute data shall be calculated using the average of the recorded flow rate for the hour immediately before the missing data period and the hour immediately after the missing data period. If no emissions occurred during the hour immediately before the missing data period or the hour immediately after the missing data period, substitute data shall be calculated pursuant to clause E(2)(c)(ii).

    ii. For a missing data period of more than 3 hours but less than or equal to 24 hours, substitute data shall be calculated using the maximum hourly flow rate recorded by the flow monitor for the previous 30 days. If no emissions occurred during the previous 30 days, substitute data shall be calculated pursuant to clause E(2)(c)(iii).

    iii. For a missing data period of greater than 24 hours, substitute data shall be calculated using the maximum hourly flow rate recorded by the flow monitor for the previous 365 days. If no emissions occurred during the previous 365 days, substitute data shall be calculated pursuant to subparagraph E(2)(d).

    d. Whenever the percent annual flow monitor availability is less than 90 percent, substitute data shall be calculated using the highest hourly flow rate recorded during the service of the monitoring system. For the purpose of this subparagraph, service of the monitoring system shall start from the initial certification date of the analyzer or the date when a decrease in the valid range of the monitoring system is approved by the Executive Officer.

  3. Procedures for Missing Stack Exhaust Gas Flow Rate Data and Missing SOx Concentration Data

    For each equipment, whenever a valid hour of both stack exhaust gas flow rate data and SOx pollution concentration data have not been obtained or recorded, the Facility Permit holder shall provide substitute data using emissions data and the procedures below.

    a. The Facility Permit holder shall calculate and record on a daily basis the percent annual emission availability. The percent annual emission availability shall be equal to the lesser of the percent annual concentration monitor availability as determined in subparagraph E(1)(a) or the percent annual flow monitor availability as determined in subparagraph E(2)(a).

    b. Whenever the percent annual emission availability is 95 percent or more, the Facility Permit holder shall calculate substitute data for each hour according to the following procedures.

    i. For a missing data period less than or equal to 24 hours, substitute data shall be calculated using the 1N Procedure in Attachment-A. If insufficient data is available to perform this calculation, substitute data shall be calculated pursuant to clause E(3)(b)(ii).

    ii. For a missing data period greater than 24 hours, substitute data shall be calculated using the maximum hourly emissions for the previous 30 days. If no emissions occurred during the previous 30 days, substitute data shall be calculated pursuant to clause E(3)(c)(iii).

    c. Whenever the percent annual emission availability is 90-percent or more but less than 95-percent, the Facility Permit holder shall calculate substitute data for each hour according to the following procedures.

    i. For a missing data period of less than or equal to 3 hours, substitute data shall be calculated using the average of the recorded emissions for the hour immediately before the missing data period and the hour immediately after the missing data period. If no emissions occurred during the hour immediately before the missing data period or the hour immediately after the missing data period, substitute data shall be calculated pursuant to clause E(3)(c)(ii).

    ii. For a missing data period of more than 3 hours but less than or equal to 24 hours, substitute data shall be calculated using the maximum hourly emissions recorded for the previous 30 days. If no emissions occurred during the previous 30 days, substitute data shall be calculated pursuant to clause E(3)(c)(iii).

    iii. For a missing data period of greater than 24 hours, substitute data shall be calculated using the maximum hourly emissions for the previous 365 days. If no emissions occurred during the previous 365 days, substitute data shall be calculated pursuant to subparagraph E(3)(d).

    d. Whenever the percent annual emission availability is less than 90 percent, substitute data shall be calculated using the highest hourly emissions recorded during the service of the monitoring system. For the purpose of this subparagraph, service of the monitoring system shall start from the initial certification date of the analyzer or the date when a decrease in the valid range of the monitoring system is approved by the Executive Officer.

Measurement

F. TIME-SHARING

  1. Time-sharing is where an analyzer and possibly the associated sample conditioning system is used on more than one source. Timesharing is allowed for SOx RECLAIM sources provided the CEMS can meet the following requirements in addition to the other requirements in this document for each source that is timeshared.

  2. All sources shall have mutually compatible span range(s). The span range(s) must be able to meet the criteria in Chapter 2, Subdivision B. Paragraph 8.

  3. Each source must have a data reading period greater than or equal to 3 times the longest response time of the system. For shared systems the response time is measured at the input or probe at each source. A demonstration of response time for each source must be made during certification testing. Data is not to be collected following a switch of sampled sources until an amount of time equal to the response time has passed.

  4. The CEMS must be able to perform and record zero and span calibrations at each source.

TABLE 2-A

MEASURED VARIABLES FOR MAJOR SOx SOURCES

EQUIPMENT TYPE : FLUID CATALYTIC CRACKING UNITS

EQUIPMENT

MEASURED VARIABLES

FCCUs

1. Stack SOx concentration and exhaust flow rate;

2. Status code;

3. Feed rate.

FCCUs with feed hydrodesulfurization

All variables identified for FCCUs.

FCCUs with SOx reducing catalyst

All variables identified for FCCUs; AND
4. Type and amount of catalyst used.

FCCUs with wet flue gas desulfurization (e.g., slurry of Ca(OH)2/CaCO3 or NaOH/Na2CO3)

All variables identified for FCCUs; AND
4. Scrubber solution injection rate.

FCCUs with dry flue gas desulfurization (e.g., dried slurry of Ca(OH)2/CaCO3 or NaOH/Na2CO3)

All variables identified for FCCUs; AND
4. Scrubber solution injection rate.

TABLE 2-A (CONTINUED)

MEASURED VARIABLES FOR MAJOR SOx SOURCES

EQUIPMENT TYPE : TAIL GAS UNITS

EQUIPMENT

MEASURED VARIABLES

Tail gas units

1. Stack SOx concentration and exhaust flow rate;

2. Status code;

3. Production rate;

Tail gas units with amine treatment
(e.g. MEA, DEA, SCOT)

All variables identified for tail gas units; AND
4. Amine solution injection rate

Tail gas units with caustic wash
(e.g., MEROX w NaOH, catalyst)

All variables identified for tail gas units; AND
4. Caustic solution injection rate

Tail gas units with metal based wash

(e.g., CHEMSWEET with ZnO and Zn Acetate, IRON SPONGE with wood chips w iron oxide)

All variables identified for tail gas units; AND
4. Metal based solution injection rate

Tail gas units with carbonate wash

(e.g., CATACARB with K2CO3, catalyst, and inhibitor)

All variables identified for tail gas units; AND
4. Carbonate solution injection rate

Tail gas units with REDOX processes

(e.g., STRETFORD with Vanadium based solution, WELLMAN-LORD SULFEROX with iron w/chelating agent)

All variables identified for tail gas units; AND
4. REDOX solution injection rate

Tail gas units with other catalytic conversion processes to H2S (e.g., Hydrotreating)

All variables identified for tail gas units

TABLE 2-A (CONTINUED)

MEASURED VARIABLES FOR MAJOR SOx SOURCES

EQUIPMENT TYPE : SULFURIC ACID PRODUCTION PLANTS

EQUIPMENT

MEASURED VARIABLES

Sulfuric acid production plants with dual absorption processes

1. Stack SOx concentration and exhaust flow rate;

2. Status code;

3. Sulfuric acid production rate;

4. Strength of acid produced;

5. Inlet SO2, O2 concentrations to 1st and 2nd stage converters;

6. Inlet SO3 to absorption tower;

7. Conversion efficiency of 1st and 2nd stage converters;

8. Conversion efficiency of absorption tower;

9. Efficiency of acid mist control devices;

10. Type and amount of fuel usage for furnace.

Sulfuric acid production plantswith sodium sulfite/bisulfite/ammonia scrubbing processes

1. Stack SOx concentration and exhaust flow rate;

2. Status code;

3. Sulfuric acid production rate;

4. Strength of acid produced

5. Sodium sulfite/bisulfite/ammonia injection rate;

6. Scrubber solution pH

7. Conversion efficiency of absorption tower

8. Efficiency of acid mist control devices;

9. Type and amount of fuel usage for furnace.

TABLE 2-A (CONTINUED)

MEASURED VARIABLES FOR MAJOR SOx SOURCES

EQUIPMENT TYPE : EQUIPMENT BURNING REFINERY, LANDFILL OR DIGESTER GASEOUS FUELS

EQUIPMENT

MEASURED VARIABLES

Combustion equipment

1 Stack SOx, O2 concentrations, and fuel flow rate; OR
Fuel sulfur content and fuel flow rate;

2. Status code;

Combustion equipment with wet scrubber (e.g., Lime CaO, Limestone CaCO3, Sodium Sulfite Na2SO3, Double alkali Na2SO3/CaO/CaCO3, Magnesium oxide Mg(OH)2)

All variables identified for combustion equipment;

AND

3. Scrubber solution injection rate.

Combustion equipment with spray dryer or dry scrubber (e.g., absorption with Na2CO3 or slaked lime solution)

All variables identified for combustion equipment;

AND

3. Scrubber solution injection rate;

Combustion equipment with carbon adsorption

All variables identified for combustion equipment.

TABLE 2-B

REPORTED VARIABLES FOR ALL MAJOR SOx SOURCES

EQUIPMENT

REPORTED VARIABLES

Fluid Catalytic Cracking Units
Tail Gas Units
Sulfuric Acid Production
Equipment that burns refinery, landfill or sewage digester gaseous fuel except gas flares. Any existing equipment using SOx CEMS or equivalent monitoring device, or that is required to install such monitoring device under District rules to be implemented as of [date of adoption]. Any SOx source or process unit elected by the Facility Permit holder or required by the Executive Officer to be monitored with CEMS or equivalent monitoring device. Any Sox source or process unit whose reported SOx emissions was equal to or greater than 10 tpy for any calendar year from 1987 to 1991, inclusive, excluding any SOx source or process unit which has reduced SOx emissions below 10 tons per year prior to January 1, 1994.

1. Total Daily SOx mass emissions from each source;

2. Daily status codes