&EPA
United States
Environmental Protection
Agency
OTC Sources under the Federal NOX
Budget Trading Program:
Guidance on Changing Monitoring Methods and Upgrading
Monitoring Plans to EDR v2.1
Clean Air Markets Division
U.S. Environmental Protection Agency
October 12, 2001
CLEANAIR
MARKET PROGRAMS
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October 12, 2001
OTC Sources under the Federal NOX Budget Trading Program:
Guidance on Changing Monitoring Methods and Upgrading
Monitoring Plans to EDR v2.1
Table of Contents
Page
Introduction and Background 1
Section 1: How to Add, Delete and Modify Records in the Monitoring Plan 5
Section 2: Coal-fired Units 11
Case 1: NOX Emission Rate CEM with Stack Flow and Diluent Monitor for
Heat Input 12
Case 2: NOX Emission Rate CEMS with Either Alternative Heat Input or
Maximum Heat Input 15
Case 3: NOX Concentration CEMS and Stack Flow Monitor, No Heat
Input Measurement 20
Case 4: NOX Concentration CEMS and Stack Flow Monitor for NOX Mass
(Stack Flow and Diluent Monitor for Heat Input) 26
Section 3: Oil- and Gas-fired Units 27
Case 5: NOX Emission Rate CEMS with Heat Input Monitoring (Stack Flow and Diluent
Monitor or Appendix D Fuel Flow Monitoring) 29
Case 6: NOX Emission Rate CEMS with Either Alternative Heat Input or Maximum
Heat Input 30
Case 7: NOX Concentration CEMS and Stack Flow Monitor, No Heat
Input Monitoring 37
Case 8: NOX Concentration CEMS with Heat Input Monitoring (Stack Flow and Diluent
Monitor or Appendix D Fuel Flow Monitoring) 44
Case 9: Appendix E Correlation for NOX Emission Rate and Appendix D Fuel Flow
Metering for Heat Input 45
Case 10: Unit Specific or Generic NOX Default Rate and Appendix D Fuel Flow Metering
for Heat Input 51
Case 11: Unit Specific or Generic NOX Default Rate with Alternative or Maximum Heat
Input or Long Term Fuel Flow 57
Section 4: Oil- And Gas-fired Low Mass Emissions (LME) Units 65
Case 12: LME Unit Using NOX Unit Specific Default with Long Term Fuel Flow Heat
Input Monitoring 67
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October 12, 2001
OTC Sources under the Federal NOX Budget Trading Program:
Guidance on Changing Monitoring Methods and Upgrading
Monitoring Plans to EDR v2.1
Table of Contents (cont.)
Page
Section 5: Comparison of OTC and Subpart H Requirements 73
Section 6: Ozone Season Only Reporting for OTC-Subpart H Sources 87
Appendix A: Monitoring Plan EDR Changes for All Units 97
11
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October 12, 2001
OTC Sources under the Federal NOX Budget Trading Program:
Guidance on Changing Monitoring Methods and Upgrading
Monitoring Plans to EDR v2.1
List of Tables
Page
Table 2-1: Summary Comparison of NOX and Heat Input Monitoring Methodologies in the
OTC and Federal NOX Budget Programs for Coal/ Solid Fuel Fired Units 11
Table 3-1: Summary Comparison of NOX and Heat Input Monitoring Methodologies in the
OTC and Federal NOX Budget Programs for Non LME Oil and Gas
Fired Units 28
Table 4-1: Summary Comparison of LME NOX and Heat Input Monitoring Methodologies in
the OTC and Federal NOX Budget Programs for LME Oil and Gas Fuel
Fired Units 66
Table 5-1: Units Using NOX CEM System 74
Table 5-2: Missing Data Substitution 76
Table 5-3: Appendix D Fuel Flow for Gas and Oil Fired Units 78
Table 5-4: Default NOX Emission Rates/Low Mass Emissions Methodology 78
Table 5-5: CEM System Quality Assurance - RATA Standards 81
Table 5-6: CEM System Quality Assurance - RATAs Testing Requirements 82
Table 5-7: CEM System Quality Assurance - Flow to Load 83
Table 5-8: CEM System Quality Assurance - Data Validity 83
Table 5-9: CEM System Quality Assurance - Calibration Gases 84
Table 5-10: CEM System Quality Assurance - Linearity Tests 84
Table 5-11: Appendix D Quality Assurance Fuel Flow Monitoring for Gas and Oil
Fired Units 85
Table 6-1: QA Requirements for Units Reporting on an Ozone Season Basis 89
Table A-l: RT 510 Code Changes 98
Table A-2: RT 520 Code Changes 99
Table A-3: RT 531 Code Changes 100
Table A-4: RT 585 Code Changes 102
in
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October 12, 2001
OTC Sources under the Federal NOX Budget Trading Program:
Guidance on Changing Monitoring Methods and Upgrading
Monitoring Plans to EDR v2.1
List of Examples
Page
Example for Case 1: EDR Record Changes for a Coal Unit with CEMS for NOX Rate
and HI 13
Example for Case 2: EDR Changes for a Coal Unit using MHHI 18
Example for Case 3: EDR Changes for a Coal Unit using NOXC and FLOW 24
Example for Case 6: EDR Changes for an Oil Unit using MHHI 34
Example for Case 7: EDR Changes for an Oil and Gas Unit using NOXC and FLOW 41
Example for Case 9: EDR Changes for an Oil & Gas Unit using App. E and App. D 48
Example for Case 10: EDR Changes for an Oil Unit using Unit Specific Defaults with
Appendix D 54
Example for Case 11: EDR Changes for an Oil Unit using Unit Specific Default with
Long Term Fuel Flow 61
Example for Case 12: EDR Changes for a Unit that Qualifies as an LME Unit 70
IV
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Purpose of this
Document
Intended
Audience
Document
Organization
INTRODUCTION AND BACKGROUND
The U.S. Environmental Protection Agency (EPA) has prepared this
guidance to assist sources in States that are participating in the Ozone
Transport Commission (OTC) NOX Budget Program (NBP) as they
transition to a larger regional NOX trading program developed under a
NOX SIP Call and in response to section 126 petitions filed by a number
of Northeastern States. Under the OTC program, sources use monitoring
requirements developed under an OTC monitoring guidance document.
Under the new Federal NOX Budget Trading Program (Federal NBP),
sources must follow procedures set out in 40 CFR Part 75, Subpart H.
This document explains how the Part 75 requirements differ from the
OTC monitoring options and what monitoring plan changes you will
have to make.
If you currently monitor and report under the OTC NBP and use
Electronic Data Reporting (EDR) v2.0, then you should use this
document to help you determine what monitoring and monitoring plan
reporting changes you will have to make. If you own or operate an Acid
Rain Program affected unit that also is subject to the OTC NBP, this
guidance is not applicable - you already must meet the Part 75
requirements and use EDR v2.1. Also, if you will be affected by the
Federal NBP but are not affected under the OTC NBP, this guidance is
not applicable; the guidance is aimed at sources that are transitioning
from OTC to Federal NBP, not sources in non-OTC States that will be
developing NOX mass monitoring for the first time. EPA encourages
sources in both OTC and non-OTC States to review the "Small Entity
Compliance Guide: Federal NOX Budget Trading Program (40 CFR Part
97)" (see http://www.epa.gov/airmarkets/fednox/126secg.pdffor a copy
of that guidance), which provides a general overview of the monitoring
requirements you will have to meet under the Federal NBP.
This brief introduction provides some general background on the OTC
and Federal NBPs. Section 1 then describes how to report during the
"transition" quarter (i.e., the first quarter for which you report an EDR
v2.1 file) and how to determine start and end dates for various records.
Sections 2, 3 and 4 describe changes for three types of units:
! Coal-fired units;
! Oil- and gas-fired units; and
! Low mass emissions (LME) units
For coal-fired units and oil- and gas-fired units, this document treats each
possible monitoring configuration under the OTC NBP as a possible
"case" and then for each case presents the specific options and changes
that are required to convert to an acceptable Part 75 monitoring option
and EDR v2.1 monitoring plan. Also, for most cases, the document
includes a specific case example to demonstrate how the monitoring plan
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Pagel
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Introduction and Background
would change from EDR v2.0 to EDR v2.1. There are 11 cases for coal-
fired and oil- and gas-fired units.
The third type of unit a low mass emissions unit is a subset of oil-
and gas-fired units. LME units are oil- and gas-fired units that meet an
actual and calculated emission threshold (<50 tons NOX per year or <25
tons NOxper ozone season). Under the OTC NBP, there were no special
monitoring provisions for this unit type. Because the option for an LME
unit potentially applies to any oil- or gas-fired unit, this document
presents the LME monitoring option, and the monitoring and monitoring
plan changes it involves, in a separate section rather than as an option
under each oil- and gas-fired unit case.
Section 5 provides a comparison of the OTC and Subpart H monitoring
and testing requirements so that you can determine what other changes
will be needed when you start reporting using EDR v2.1.
Section 6 is for sources that plan to report only during the ozone season,
rather than reporting all four quarters each year. This section describes
what tests you must perform, when you must conduct them, and how you
must report them.
Finally, Appendix A identifies the EDR monitoring plan changes that
will apply generally to all units because, regardless of monitoring method
changes, you will need to make at least some formatting changes to
switch from EDR v2.0 to EDR v2.1 reporting. These types of changes
are found in Appendix A so that they do not have to be repeated in each
case. However, each case does list which of these general changes
applies to each Part 75 monitoring option. The formatting changes
include:
! New record types in EDR v2.1
! Record types used in EDR v2.0 that have been discontinued in EDR
v2.1
! Added/discontinued fields in record types that appear in EDR v2.0
andv2.1
! Codes that change between EDR v2.0 and v2.1 for reporting in
already existing fields
In addition to Appendix A, you should also use the EDR v2.1 Reporting
Instructions which contain detailed descriptions of each EDR v2.1
record type and field to help you make changes in your EDR.
OTC NOX On September 27, 1994, OTC adopted a Memorandum of Understanding
Budget Program f°r the development and proposal of the OTC NBP, a region-wide NOX
emission reduction program that began in 1999. Under the OTC NBP,
boilers, turbines and indirect heat exchangers above certain size
Page 2 Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
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Introduction and Background
thresholds must meet NOX emission limits during the ozone season (May
1- September 30) to achieve regional emission reductions. The affected
sources receive an allocation of emission allowances under State
regulations. Each source can use those allowances to cover their
emissions, can purchase allowances from others to cover their emissions
(or to bank the allowances for future years), or can sell any surplus
allowances. To account for their emissions, each source must follow
specific monitoring procedures. For the OTC NBP, each State has
required their sources to implement the procedures contained in the "NOX
Budget Program Monitoring Certification and Reporting Instructions,"
July 3, 1997 and "Guidance for Implementation of Emission Monitoring
Requirements for the NOX Budget Program," January 28 1997. The OTC
States that are participating in the NBP are: CT, DC, DE, MA, MD, NH,
NJ, NY, PA and RI.
Federal NOX The EPA has developed the Federal NBP based in part upon analyses
Budget Program conducted by the Ozone Transport Assessment Group (OTAG). OTAG
was a partnership between the EPA, the Environmental Council of the
States and various industry and environmental groups which assessed the
long-range transport of ozone and ozone precursors. The initial OTAG
findings were translated into rule requirements in two separate actions.
First, on September 24, 1998, EPA finalized a rule (known as the NOX
SIP Call) requiring 22 States and the District of Columbia to submit
State implementation plans that address the regional transport of ground-
level ozone. By improving air quality and reducing NOX emissions, the
actions directed by these plans will decrease the transport of ozone across
State boundaries in the eastern half of the United States. Originally, the
rule required emission reduction measures to be in place by May 1, 2003;
that date was extended to May 31, 2004, in a court decision that
generally upheld EPA's rulemaking.
Second, EPA published "Findings of Significant Contribution and
Rulemaking on Section 126 Petitions for Purposes of Reducing Interstate
Ozone Transport" on January 18, 2000 under authority of section 126 of
the Clean Air Act. Eight northeastern States had submitted petitions
under section 126 of the Act that sought ozone related reductions from
certain sources in upwind states. EPA made a technical finding for each
of the petitions. The Agency determined that large, fossil fuel fired
stationary sources in certain upwind States should be required to reduce
their ozone season emissions to mitigate the effect these sources have on
ozone non attainment in downwind states. The sources that are affected
by this rule include large electric generating units (EGUs) and large
industrial/ institutional boilers or turbines (non-EGUs) that emit NOX
from burning fossil fuels. These NOX emissions contribute to the
nonattainment of the National Ambient Air Quality Standards (NAAQS)
for ozone in the downwind states.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001 Page 3
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Introduction and Background
OTC States'
Response to
EPA's Federal
NBP Actions
Changes for
OTC NBP
Sources
In the NOX SIP Call, EPA established State NOX emission budgets. EPA
based the point source budgets on presumed levels of control applied to
large EGUs, non-EGUs, certain internal combustion engines and certain
cement kilns. For the large EGUs and non-EGUs, EPA developed a
model trading rule that States could adopt as part of their SIP
implementation strategy. The model rule was promulgated on October
27, 1998, as 40 CFR Part 96. In this model, the States would determine
allowance allocations and have certain other responsibilities, and EPA
would manage the trading system so that it could operate on an interstate
basis. All monitoring under the model rule must follow the requirements
EPA has developed under Subpart H of 40 CFR Part 75. For the section
126 rulemaking, EPA similarly developed an interstate trading program
for generally the same group of sources, and required adherence to Part
75 monitoring procedures. The Federal program was promulgated on
January 18, 2000, as 40 CFR Part 97. The main difference is that under
the section 126 rulemaking, the compliance date is still set for May 1,
2003, and EPA is responsible for allowance allocations.
Each of the OTC States subject to Federal NBP actions (all except for
NH) have submitted a SIP to EPA in response to the NOX SIP Call. Each
of the SIPs contains a trading program component consistent with the
Federal NBP, and each requires compliance by May 1, 2003. Assuming
final approval of these SIP submittals by the OTC States, the OTC NBP
States will implement a trading program under the SIP call and not the
section 126 rulemaking.
One of the main differences between the Federal NBP under the SIP Call
regulations and the OTC NBP is the monitoring requirements each
source will face. For units that are affected by the Acid Rain Program,
the changes are not relevant because those sources already are required to
follow Part 75 procedures. For other units, the changes required may be
minimal or somewhat significant; it will depend on the current
monitoring option that a unit uses under the OTC NBP. The monitoring
changes take effect on May 1, 2002, one year earlier than the effective
date of the trading program change.
This document will help you understand what monitoring changes may
be required, both in terms of the monitoring options you use and the
electronic reporting of monitoring plan data to EPA.
Page 4
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
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SECTION 1: HOW TO ADD, DELETE AND
MODIFY RECORDS IN THE MONITORING PLAN
Purpose of this
Section
What to Include
in the
Transition
Quarter
How to Report
Changes in
Each Record
Type
Additional Note
about MDC
Error Messages
RT505
Updating your monitoring plan to meet Subpart H requirements and the
EDR v2.1 format will require adding records, changing codes and
"deactivating" records that will no longer be applicable. This section
describes how to report during the "transition" quarter (i.e., the first
quarter for which you submit an EDR v2.1 file) and how to determine
start and end dates for various record types.
EPA maintains an historical database of monitoring plan information that
supports the interpretation and evaluation of QA test data and is used for
program implementation purposes. Therefore it is important that you
provide complete and accurate monitoring plan data, including records
indicating the appropriate "end" date and delete status when a
methodology, system, formula, etc. will no longer be used. Information
to "deactivate" these records should be included in the file for the quarter
during which the change takes place. So, for OTC sources, the first
quarterly report in EDR v2.1 (required by 2nd Quarter 2002) should
include both the OTC records that are being deactivated as well as the
new records for Subpart H.
Most record types have either a status field, begin and end dates, or both.
Use these fields to indicate whether and when the records are active.
Once you have reported records as status "delete" and with the
appropriate end date in a particular quarterly report file, you may remove
those records from your monitoring plan for future EDR submissions.
If you are using MDC to make or evaluate these monitoring plan
changes, you will notice that error messages about invalid codes are
generated on the updated plan when you evaluate using any quarter and
year that begins before the "end" date on the OTC records that are being
deactivated. These errors should not appear if you change the evaluation
quarter and year to a later time period when only the Subpart H records
are active.
Do not include the existing RT 505 for Program NBP in the transition
quarter. Instead, add a new RT 505 for Program OTC-SUBH and then
remove the RT 505 for NBP. For OTC-SUBH, the Program
Participation date in column 24 should be the beginning of the first
reporting period for which you are submitting in EDR v2.1. For
example, if you report on an ozone season basis and submit your first
EDR v2.1 file for 2nd Quarter 2002, the file will include emissions data
starting on May 1, 2002 so your Program Participation Date should also
be May 1, 2002 (whether or not you are actually operating on that day).
If you choose to comply with Subpart H and EDR v2.1 in an earlier
quarter, the Program Participation date should be the first day of that
earlier quarter. Contact your State agency to determine the correct State
Regulation Code (column 32) for the new RT 505.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
PageS
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Section 1; How to Add, Delete and Modify Records
RT 507 To maintain qualification as a peaking unit, be sure to report a new RT
507 for the current calendar year or ozone season.
RT 510 Defining a new system. If you are changing methodologies, define a
new system or systems with a new unique system ID. Do not change a
current monitoring system into a different type of system. For example,
if you are converting from a NOX emission rate CEM to Appendix E NOX
(or vice-versa), you must define a new NOX system with a new system ID
and deactivate the old NOX system. Similarly, if switching from a NOX
concentration system to a NOX emission rate system (or vice-versa), you
must define a new system with a new system ID and deactivate the old
system (see Deactivating below).
Adding. In the first quarter you report a new system, report the Status
(col. 16) for each component in the newly defined system as "A." For all
records in the system, report the first date that the system is used to
report any data (including initial certification test data) in the "first date
system reported data" field (col. 100). The "first date" must be the same
for all components in the system.
Deactivating. In the last quarter you report data from a system, or the
following quarter if you used that system through the end of the quarter,
report "D" as the status (col. 16) and report the "last date system reported
data" date (col. 108) for each component. The "last date" must be the
same for all components in the system. After reporting this deactivated
system for one quarter, you may remove those records entirely for your
next quarter submission. (Note: if you receive errors from ETS about
the deactivated system because it was in use for part of the quarter,
change the status field to C for each component in the system for this
quarter, and then report the system again the next quarter with the status
as D for each component (report the appropriate "last date" in both
cases).)
Changing from single scale to dual range. If you have a single-scale
NOX monitor and you must (or elect to) install a dual range monitor (or
you begin using the dual range capability of your current monitor), there
are three methods of updating the plan. If you have installed a new
monitor and will be conducting the initial certification testing of that
monitor while the old monitor is still reporting emissions data, you must
use method 3.
Method 1: Change the component type of the existing NOX
component to NOXA.
Method 2: Define a new component with component type NOXL
and add it to the existing NOX system.
Page 6 Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
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Section 1; How to Add, Delete and Modify Records
Method 3: Deactivate the current NOX system and define a new
NOX system containing one new dual range NOX component (component
type NOXA) or containing new high and low scale NOX components
(component types NOXL and NOXH).
See RT 530 below for related changes.
Changing from single scale with the OTC overscaling provisions to
use of the Part 75 default high range provisions. If you have a single-
scale NOX analyzer with a span value less than the maximum potential
concentration (i.e., you are using the default overscaling option permitted
for OTC monitoring), and you elect to continue using that monitor (and
span value) and use the default high range from Part 75, you have two
possible methods for revising your plan:
Method 1: Mark the status of the existing NOX component as D
and add a new NOXL component.
Method 2: Deactivate the existing NOX system, define a new
NOXL component and add a new NOX system with that NOXL
component.
See RT 530 below for related changes.
RT 520 Defining a new formula. If you add formulas for new calculations,
report each new formula with a new unique formula ID and report the
status in column 10 as A.
Updating the formula code. If for Subpart H you are using the same
calculation that references the same types of monitors or constants that
you used for OTC, but the formula code has changed, simply update the
formula code field in the existing record. See Appendix A of this
document for a list of code changes in RT 520.
Deactivating. For formulas that will no longer be used under Subpart H,
report the status in column 10 as D. It is not necessary to update any
formula codes for formulas that you are deactivating.
RT 530 Defining a new span. Add the appropriate span records for each new
CEMS parameter. For the Span effective date and hour in columns 68
and 74, report the date and hour that this span value was first used to test
the CEMS or measure emissions.
Deactivating. If you no longer need a span record for a particular
parameter because a CEMS methodology is no longer used, report the
last date and hour that the span record was in use for the parameter by
completing the Span Inactivation Date and Hour (col. 76, 82). After
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001 Page 7
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Section 1; How to Add, Delete and Modify Records
reporting this deactivated span value for one quarter, you may remove
this record for your next quarterly submission.
Revising span and range. If the annual review of MFC, span and range
(required by Part 75, Appendix A) necessitates changing one or more of
those values, deactivate the previous span record with the appropriate
end date and add a new span record with the adjusted values and the
appropriate begin date.
Meeting the dual range requirements If your unit has add-on controls
and you are using a single-scale NOX analyzer to measure controlled
emissions and relying on the OTC default overscaling option for
uncontrolled hours (up to 72 hours during the ozone season), you will
either have to go to dual range monitoring or use the default high range
provisions of Part 75.
Changing from single scale to dual range. If you are adding a
low scale, add a span record for that new range. If you are adding
a high scale range to monitor uncontrolled emissions, deactivate
the existing high scale record . Add two new span records one
for NOX scale H and one for NOX scale L.
Changing from OTC overscaling to using a default high
range. The existing NOX span record indicates that the scale is
high (H), so deactivate it. Add two new span records: one for
NOX scale H and one for NOX scale L. See the EDR v2.1
Instructions for details about which fields to complete for the
high scale span record and see the Acid Rain Program Policy
Manual, Question 10.29 for information about reporting hourly
values using the default high range provisions.
RT 531 Adding. Use the Value Effective Date and Hour in columns 45 and 53
to indicate the start date for the value. This date should match the start
date of the relevant methodology. See the EDR v2.1 Instructions for
detailed information about what values to define in RT 531.
Deactivating. For values that are no longer defined in RT 531, such as
NOX MER (for missing data purposes), report the Value No Longer
Effective Date and Hour in columns 55 and 63. This date should be the
last day and hour of the last quarter that you reported using EDR v2.0.
RT 540 Adding. If you have defined a new oil or gas system, add RT 540 for
that system and report the Submission Status in column 60 as A.
Updating Codes. If you have an existing RT 540 for an oil or gas
system that you will continue to use, update the Initial Accuracy Test
Method in column 38 to match the appropriate code that has been
Page 8 Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001
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Section 1; How to Add, Delete and Modify Records
established in EDR v2.1 and report the submission status in column 60
asC.
Deactivating. If you are deactivating an oil or gas system, report the
Submission Status in column 60 as D in the RT 540 for that system.
RT 585 Updating Codes. If you are keeping your current monitoring methods,
simply update the codes in the existing records. For example, in EDR
v2.1 for methodology CEM, the fuel type must be NFS and the missing
data approach should be changed to SPTS.
Adding. If you are instituting new methodologies, add the appropriate
RTs 585 and report the Methodology Start Date in column 34 as the first
date for which emissions or heat input were or will be reported using this
method. Also add a RT 585 for moisture (parameter H2O) if you need
that value for any of your calculations.
Deactivating. If you are discontinuing a methodology, report the
Methodology End Date in column 42 as the last date for which emissions
or heat input were or will be reported using this method.
RT 587 Updating Codes. If you have been reporting a fuel as secondary and it
qualifies as an Emergency or Ignition (Startup) fuel type, change the Fuel
Indicator in column 29 to the appropriate new code.
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Section 1; How to Add, Delete and Modify Records
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Page 10 Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001
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SECTION 2: COAL-FIRED UNITS
Use Table 2-1 to determine the Case number of your OTC monitoring scenario. Then go
to the detailed discussion of that Case number in this section to determine the changes
you need to make.
Monitoring
Methodology
Changes
Generally, there are only limited options for monitoring coal-fired units
under either Part 75 or the OTC Monitoring Guidance. Therefore, you
will not have significant changes or new options to convert your OTC
monitoring to Part 75 requirements unless you are not currently
monitoring heat input. Table 2-1 summarizes the monitoring
methodology changes that may be required for your coal-fired OTC unit
to comply with Part 75, Subpart H monitoring and monitoring plan
reporting requirements. This section then presents the changes in a series
of four cases so that you can review the changes based on your specific
monitoring configurations.
You should note that each case is reported at the unit level. If you
defined common stacks or multiple stacks for use with your current OTC
monitoring, those designations should most likely remain in the Subpart
H monitoring scenario. (This may not be true for unmonitored bypass
stacks see additional note on bypass stacks at the end of Appendix A.)
Also, in each case you will find a list of general EDR monitoring plan
Record Type (RT) changes that will have to occur as you convert to Part
75 monitoring. Use the list to identify the general record type changes
that apply, and consult the detailed identification of the changes in
Appendix A, Changes for All Units.
Table 2-1: Summary Comparison of NOX and Heat Input Monitoring Methodologies in the
OTC and Federal NOX Budget Programs for Coal/ Solid Fuel Fired Units
Unit
Type
Coal
Current OTC Monitoring Method
NOX
NOX Emission Rate
CEMS
NOX Concentration
CEMS and Stack
Flow Monitor
Heat Input
Stack Flow Monitor and
Diluent (02/C02) CEM
Alternative Heat Input
Method
Maximum Heat Input
None (only NJ required
heat input reporting for
OTC)
Stack Flow Monitor and
Diluent (02/C02) CEM
Change Required for
Subpart H Monitoring?
No changes needed to basic monitoring
method
These OTC methods for Heat Input are not
allowed under Subpart H. Coal-fired units
must use a stack flow monitor and diluent
CEM to determine heat input
Heat Input is required for State allocation
purposes, so coal-fired units must use a
stack flow monitor and diluent CEM to
determine heat input
No changes needed to basic monitoring
method
Case#
1
2
3
4
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 11
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Section 2: Coal-fired Units
Casel
Casel
NOX Emission Rate CEM with Stack Flow
and Diluent Monitor for Heat Input
Overview
General EDR
Changes
No basic monitoring methodology change is required for either the NOX
emission rate methodology or the heat input methodology for Case 1.
One key step is to delete the existing RT 505 for NBP and define a new
RT 505 for OTC-SUBH to identify the date when your unit begins
complying with Subpart H requirements. You should add this RT 505
first before making other changes if you are using the Monitoring Data
Checking (MDC) software program to make the changes.
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535,
536, 555, 556, 585 and 587.
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
RT 505 for NBP.
our \
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Case 1 Example
Unit
Example Unit lisa circulating fluidized bed coal-fired unit. Since this
unit is using CEMs for both NOX Emission Rate and Heat Input, no basic
monitoring methodology change is required for either the NOX emission
rate or the heat input methodologies. However, changes are required to
upgrade from EDR v2.0 to v2.1. The attached comparison shows the
changes made for each record type.
Page 12
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Example for Case 1: EDR Record Changes for a Coal Unit with CEMS for NQS Rate and HI
RT100
OTC
SUBH
RT102
OTC/SUBH
RT504
OTC
SUBH
RT505
OTC
SUBH
RT506
SUBH
RT510
OTC
SUBH
RT520
OTC
SUBH
EDR Version Changed from V2.0 to V2.1. Reporting Quarter
and Year Changed
10010000022001V2 .0
10010000022002V2.1
No Changes
102CASE 1
COGENERATION 4961NJ017
400835 744510
Fields Added in v2.1
5041 CFB 468.019961201
5041 CFB 468.019961201 178 36
87 87
New record reported for Subpart H Participation beginning on 4/1/2002
5051 NBP B Q 19990501NJAC727-31NJ
5051 OTC-SUBH B Q 20020401 NJ
New record type in EDR v2.1. Required for
all units.
5061 111 1996 100000100000
Updated DAHS version
5101 3AF3SFUFLOWP FLOWU FREEFLOWING
5101 DAH3SFUFLOWP DAHS GREAT DAHS SYSTEMS
5101 3AC3SNUNOX P CO2 DINMEASURERIGHT
5101 3AL3SNUNOX P NOXLDINMEASURERIGHT
5101 3AN3SNUNOX P NOXHDINMEASURERIGHT
5101 DAH3SNUNOX P DAHS GREAT DAHS SYSTEMS
5101 3AF3SFUFLOWP FLOWU FREEFLOWING
5101 DAH3SFCFLOWP DAHS GREAT DAHS SYSTEMS
5101 3AC3SNUNOX P CO2 DINMEASURERIGHT
5101 3AL3SNUNOX P NOXLDINMEASURERIGHT
5101 3AN3SNUNOX P NOXHDINMEASURERIGHT
5101 DAH3SNCNOX P DAHS GREAT DAHS SYSTEMS
FL-989
IX
00-4000
N-4000
N-4000
IX
FL-989
8Y
00-4000
N-4000
N-4000
8Y
B11213
9 8 ROM
5H05003
49-316
49-316
9 8 ROM
B11213
98RCM
5H05003
49-316
49-316
98RCM
19990501
19990501
19990501
19990501
19990501
19990501
19990501
19990501
19990501
19990501
19990501
19990501
Updated formula code
5201 U3FHHI F-15 S# (3AF-3SF) * (I/ 1800) * (S# (3AN-3SN) /100)
5201 U3FMNOXMF-10AF# (3FN) * F# (3FH) * T 1
5201 U3FNNOX F-6 (1.194 * 10**-7) * S#(3AN-3SN) * 1800 * (100/ (S# (3AN-3SN) )
5201 U3FHHI F-15 S# (3AF-3SF) * (1/1800) * (S# (3AN-3SN) /100 )
5201 C3FMNOXMF-24 F# (3FN) * F# (3FH) * T_l
5201 U3FNNOX F-6 (1.194 * 10**-7) * S#(3AN-3SN) * 1800 * (100/ (S# (3AN-3SN) )
n
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Example for Case 1: EDR Record Changes for a Coal Unit with CEMS for NQS Rate and HI
RT530
OTC
SUBH
RT531
OTC
SUBH
RT535
OTC
SUBH
RT536
SUBH
RT585
OTC
SUBH
RT587
OTC/SUBH
Fields Added for Flow. Method updated and MEC/ MFC value added for CO2.
5301 CO2 HNA 20.000 20.000% 99050100
5301 FLOWHF 7500000.000 156.250 156 . 250KSCFM 99050100
5301 NOX HHD 251.500 0.465 300.000 300.000PPM 99050100
5301 NOX LHD 54.000 0.150 60.000 60.000PPM 99050100
5301 C02 HHD 20.000 20.000 20.000% 99050100
5301 FLOWHF 7500000.000 156.250 156 . 250KSCFM 99050100 9375000 9375000
5301 NOX HHD 251.500 0.465 300.000 300.000PPM 99050100
5301 NOX LHD 54.000 60.000 60.000PPM 99050100
Deactivated FLOW and NOX records. Added CO2M default for diluent cap.
5311 FLOW 7500000. OOOSCFH MD NFSAMPF 1999050100
5311 NOX 0.465LBMMBTUMD NFSAMPC 1999050100
5311 C02M 5.000%C02 DC NFSADCPD2002040100
5311 FLOW 7500000 .OOOSCFH MD NFSAMPF 19990501002002033123
5311 NOX 0 .465LBMMBTUMD NFSAMPC 19990501002002033123
Designated Normal load field should be left blank in EDR v2.1.
5351 ST 300M
5351 ST 300
New record type added in EDR v2.1. Required for all units/stacks with any CEM system.
5361 300 65H,MM 20011001
Note code changes.
5851 HI CEM NFSPLOAD 19990501
5851 NOXRCEM NFSPLOAD 19990501
5851 HI CEM NFSPSPTS 19990501
5851 NOXRCEM NFSPSPTS 19990501
No Changes
5871 C 19990501 P
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-------
Case!
Section 2: Coal-fired Units
Case 2
NOX Emission Rate CEMS with Either
Alternative Heat Input or Maximum Heat Input
Methodology
Changes
EDR
Monitoring Plan
Changes
You do not have to change your basic NOX emission rate methodology.
However, you are not allowed to use the OTC Alternative Heat Input and
Maximum Heat Input options under Part 75, Subpart H. You must
install a stack flow monitor and use it in conjunction with the existing
diluent monitor to determine heat input. If moisture correction is needed,
you may either calculate hourly moisture from wet and dry O2 readings,
measure moisture directly using a moisture sensor or use the appropriate
default value provided in Part 75. (Or, if the stack gas stream is
saturated, e.g., if there is a wet scrubber associated with the unit or stack,
you may use a temperature sensor and moisture look-up table.)
You will have to add some record types and you will have to deactivate
and delete others. One key step you must take is to delete the existing
RT 505 for NBP and define a new RT 505 for OTC-SUBH to identify
the date when your unit begins complying with Subpart H requirements.
You should add this RT 505 first before making other changes if you are
using the Monitoring Data Checking (MDC) software program to make
the changes.
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
RT 505 for NBP.
our \
new I
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RT510
The following sections describe the other specific changes you will have
to make to a number of monitoring plan Record Types to reflect the
monitoring changes you are making to convert to Part 75, Subpart H
monitoring.
Add (1): The new stack flow system comprised of the stack flow
monitor and the DAHS software component.
Add (2): If you will be measuring moisture by the wet/dry O2 method,
define an H2O system comprised of wet and dry O2 components and the
DAHS software. If you use a moisture sensor, define an H2O system
consisting of the sensor component and the DAHS software. If you will
be using the look-up table for a wet scrubber stack, define an H2O system
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 15
-------
Section 2; Coal-fired Units Case 2
comprised of just the DAHS software component. (If you are using a
moisture default value, do not define a moisture system in RT 510.
Instead, add a RT 531 see below.)
Deactivate: The Alternative Heat Input system, if you had defined one
in EDR v2.0.
RT 520 Add (1): A new heat input formula which references the flow
component in the flow system and the diluent component in the NOX
system. Use Table 19: Heat Input Formula Reference Table in the EDR
v2.1 Instructions to determine the correct formula for your monitoring
situation it depends on diluent monitor type (CO2 or O2) and whether
you sample on a wet or dry basis.
Add (2): A NOX mass formula (code F-24) which references the NOX
emission rate formula and the newly defined heat input formula.
Add (3): An H2O formula if you are using wet and dry O2 monitors to
determine stack moisture.
Deactivate: The NOX mass formula that references the ALTHI or MHHI
value.
RT530 Add(l): A span record for stack flow.
Add (2): A span record for O2, if not previously defined and you are
using wet and dry O2 monitors to determine stack moisture.
RT 531 Add (1): A record for the minimum potential %O2 for missing data
purposes, if using an O2 diluent monitor for the heat input calculation.
Add (2): If you need an hourly moisture value to calculate heat input
and you elect to use the default value from Part 75, the appropriate
%H2O value (see EDR v2.1 Instructions for RT 531).
Add (3): If you have a moisture system, the minimum or maximum
%H2O for missing data purposes (see § 75.37(b)).
Add (4): A record for the appropriate diluent cap value if you intend to
use those provisions (see formulas in Part 75, Appendix F, Sections 4
and 5).
Deactivate (1): The record for parameter HI or HR.
Deactivate (2): The record for parameter NOX (which defined the MER
value for missing data purposes).
Page 16 Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case!
Section 2: Coal-fired Units
RT585
General EDR
Changes
Case 2 Example
Unit
Add (1): A methodology record for parameter Heat Input (code HI in
col. 10), Methodology Continuous Emissions Monitoring (code CEM in
col. 14), and fuel type non fuel-specific (code NFS in col. 24).
Add (2): If you need a moisture value to calculate heat input or NOX
emission rate, add RT 585 for moisture (H2O), indicating whether you
are measuring moisture or using a default value.
Deactivate: The previously defined record for parameter HI (for either
ALTHI or MHHI methodology).
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
\ RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 555,
556, 585 and 587.
Example Unit 2 is a Circulating Fluidized Bed Coal-Fired Unit. For the
OTC NBP, this unit has been using a NOX emission rate CEM combined
with the Maximum Hourly Heat Input (MHHI) rate to determine NOX
mass. Since the default methodology (MHHI) is not allowed for this unit
under Subpart H, the facility will be installing a new stack flow monitor
and a wet basis O2 monitor to use with the existing dry-basis O2 monitor
to determine heat input and stack moisture. The attached comparison
shows the changes made for each record type.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 17
-------
Example for Case 2: EDR Changes for a Coal Unit using MHHI
RT100
OTC
SUBH
RT102
OTC/SUBH
RT504
OTC
SUBH
RT505
OTC
SUBH
RT506
SUBH
RT510
OTC
SUBH
RT520
OTC
SUBH
EDR Version Changed from V2.0 to V2.1
10020000022001V2 .0
10020000022002V2 .1
No Changes
102CASE 2 COGENERATION
4911NY009 404411 740743
Fields Added in v2.1
5042 CFB 510.019901107
5042 CFB 510.019901107 110 0 400 400
New record reported for Subpart H Participation beginning on 4/1/2001
5052 NBP B Q 19990501NJAC727-31NJ
5052 OTC-SUBH B Q 20020401 NJ
New record type in EDR v2.1. Required for all units.
5062 222 1990 200000200000
Flow and Moisture Systems Added. DAHS version updated.
5102 001103UNOX P DAHS PERFECT DATA V22.2 2001-99
5102 005103UNOX P NOX EXTANALYSIT C250 005-88
5102 006103UNOX P O2D EXTANALYSIT C960 006-78
5102 001103CNOX P DAHS PERFECT DATA V400 2001-99
5102 005103UNOX P NOX EXTANALYSIT C250 005-88
5102 006103UNOX P O2D EXTANALYSIT C960 006-78
5102 001104AFLOWP DAHS PERFECT DATA V400 2001-99
5102 008104AFLOWP FLOWU FLOW RIGHT, INC. FANCY FLOW 134-8765
5102 001105AH20 P DAHS PERFECT DATA V400 2001-99
5102 006105AH20 P 02D EXTANALYSIT C960 006-78
5102 007105AH20 P 02W IS AIR UP THERE WETWON 1 9907768
Old NOX mass formula marked for deletion, new formulas added for new
5202 U107NOX 19-1 E = (1.194 * 10**-7) * S#(005-103) * 9780 * 20.9 / (20
5202 U109NOXMF-10AMNOX = F#(107) * UNIT MAXIMUM HEAT INPUT RATE * TH
5202 U107NOX 19-1 E = (1.194 * 10**-7) * S#(005-103) * 9780 * 20.9 / (20
5202 D109NOXMF-10AMNOX = F#(107) * UNIT MAXIMUM HEAT INPUT RATE * TH
5202 A110HI F-18 HI = S# (008- 110) * [ (100-P# (111) ) / 100 * 9780] * [ (20
5202 A111H20 M-l 100* (S# (006- 105) - S#(007-105)) / S#(006-105)
5202 A112NOXMF-24 NOXM=F#(107) * F#(110) * t h
19990501
19990501
19990501
19990501
19990501
19990501
20020401
20020401
20020401
20020401
20020401
heat input determination.
.9 - S#(006-103) )
.9 - S# (006-103) )
.9-S#(006-103) ) / 20.9 ]
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Example for Case 2: EDR Changes for a Coal Unit using MHHI
RT530
OTC
SUBH
RT531
OTC
SUBH
RT535
OTC
SUBH
RT536
SUBH
RT585
OTC
SUBH
RT587
OTC/SUBH
Added span record to support addition of flow system. Note new fields in RT 530 for flow.
5302 NOX HHD 380.000 0.852 400.000 500.000PPM 99050100
5302 O2 H 25.000 25.000% 99050100
5302 FLOW HD 45000000.000 940.000 940.000KSCFM 02040100 56400000 56400000
5302 NOX HHD 380.000 0.852 400.000 500.000PPM 99050100
5302 02 H 25.000 25.000% 99050100
Deactivated previous defaults. Added records for minimum %H2O, minimum %O2 and the diluent cap.
5312 HI 510.000MMBTUHRPM C ANPC 1999050100
5312 NOX 0.852LBMMBTUMD NFSAMPC 1999050100
5312 H20M 3.000%H20 MD NFSADEF 2002040100
5312 HI 510 .OOOMMBTUHRPM C ANPC 19990501002002033123
5312 NOX 0 .852LBMMBTUMD NFSAMPC 19990501002002033123
5312 02M 5.000%02 MD NFSADATA2002040100
5312 02X 14.000%02 DC NFSADCPD2002040100
Designated Normal Load field should be left blank for OTC-SUBH Units.
5352 ST 400H
5352 ST 400
New RT in v2.1. Required for all units/stacks with any CEM system.
5362 400 80H,MH 20020201
Discontinued previous method for HI. Added records for HI and Moisture. Also note code changes.
5852 HI MHHI C PNA 19990501
5852 NOXRCEM NFSPLOAD 19990501
5852 H20 MWD NFSPSPTS 20020401
5852 HI CEM NFSPSPTS 20020401
5852 HI MHHI C PNA 1999123120020331
5852 NOXRCEM NFSPSPTS 19990501
No Changes
5872 C 19990501 P
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Section 2: Coal-fired Units
Case 3
Case 3
NOX Concentration CEMS and Stack Flow Monitor,
No Heat Input Measurement
Methodology
Changes
EDR
Monitoring Plan
Changes
You do not have to change your methodology for determining NOX mass
emissions. However, since OTC States will require heat input for
allowance allocation purposes, you must install a diluent monitor and use
it in conjunction with the existing stack flow monitor to determine heat
input. If moisture correction is needed, you may either calculate hourly
moisture from wet and dry O2 readings, measure moisture directly using
a moisture sensor or use the appropriate default value provided in Part
75. (Or, if the stack gas stream is saturated, e.g., if there is a wet
scrubber associated with the unit or stack, you may use a temperature
sensor and moisture look-up table.)
You may keep your current NOX concentration system (NOXC), continue
using it in conjunction with stack flow to calculate NOX mass and add a
CO2 or O2 monitoring system to be used in conjunction with stack flow
to calculate heat input. Alternatively, you may define a new NOX
emission rate system comprised of the NOX and diluent monitors and the
DAHS software. This new system would become the primary NOX
methodology; you can either discontinue use of the NOXC system or use
it as a secondary method for determining NOX mass. (If you define a
NOX emission rate system, you do not need to define a separate diluent
system.)
You will have to add some record types and you will have to deactivate
and delete others. One key step you must take is to delete the existing
RT 505 for NBP and define a new RT 505 for OTC-SUBH to identify
the date when your unit begins complying with Subpart H requirements.
You should add this RT 505 first before making other changes if you are
using the Monitoring Data Checking (MDC) software program to make
the changes.
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
RT 505 for NBP.
our \
new I
»the I
Page 20
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case 3 Section 2; Coal-fired Units
The following sections describe the other specific changes you will have
to make to a number of monitoring plan record types to reflect the
monitoring changes you are making to convert to Part 75, Subpart H
monitoring.
RT 510 Add (1): If you elect to continue using NOX concentration times flow
rate as your primary NOX mass methodology, define a new diluent system
(comprised of the CO2 or O2 monitor and the DAHS software
component). If you elect to change your primary NOX mass methodology
from NOX concentration times stack flow rate to NOX emission rate time
heat input rate, define a new NOX emission rate system (comprised of the
NOX and diluent monitors and the DAHS software).
Add (2): If you will be measuring moisture by the wet/dry O2 method,
define an H2O system comprised of wet and dry O2 components and the
DAHS software. If you use a moisture sensor, define an H2O system
consisting of the sensor component and the DAHS software. If you will
be using the look-up table for a wet scrubber stack, define an H2O system
comprised of just the DAHS software component. (If you are using a
moisture default value, do not define a moisture system in RT 510.
Instead, add a RT 531 (see below).)
Deactivate: The NOX concentration system if you defined a newNOx
emission rate system and you do not plan to continue using NOX
concentration times stack flow rate as a secondary method for
determining NOX mass.
RT 520 Add (1): A heat input formula which references the flow component and
flow system ID numbers and the diluent component ID (associate either
with the new diluent system ID or, if defined instead, the new NOX
emission rate system ID). Use Table 19: Heat Input Formula Reference
Table in the EDR v2.1 Instructions to determine the correct formula for
your monitoring situation it depends on diluent monitor type (CO2 or
O2) and whether you sample on a wet or dry basis.
Add (2): If you defined a new NOX emission rate system, add a NOX
emission rate formula that references the NOX and diluent components of
that system. Also define a new NOX mass formula (code F-24) to
calculate NOX mass emissions from NOX emission rate and Heat Input.
Add (3): An H2O formula if you are using wet and dry O2 monitors to
determine stack moisture.
Deactivate: If you defined a new NOX emission rate system and you do
not plan to continue using the NOX concentration system, deactivate the
NOX mass formula that references the NOXC system.
Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001 Page 21
-------
Section 2; Coal-fired Units Case 3
RT 530 Add: A span record for the new O2 or CO2 monitor. Also add the flow
rate span value and full-scale range (in scfh) to columns 90 and 99 of the
span flow record.
RT 531 Add (1): The appropriate default %H2O value, if you need an hourly
moisture value to calculate heat input and you elect to use the default
value from Part 75 (see EDR v2.1 Instructions for RT 531).
Add (2): The minimum or maximum %H2O for missing data purposes
(see § 75.37(b)), if you have a moisture system.
Add (3): A record for the minimum potential %O2 for missing data
purposes, if using an O2 diluent monitor for the heat input calculation.
Add (4): A record for the appropriate diluent cap value if you intend to
use those provisions (see formulas in Part 75, Appendix F, Sections 4
and 5).
Deactivate (1): The previously defined FLOW MPF value.
Deactivate (2): The previously defined NOX MEC/MPC value(s).
RT 585 Add (1): A methodology record for parameter Heat Input (code HI in
col. 10), Methodology Continuous Emissions Monitoring (code CEM in
col. 14), and Fuel Type Non Fuel-Specific (code NFS in col. 24).
Add (2): If you need a moisture value to calculate heat input or NOX
emission rate, add RT 585 for moisture (H2O), indicating the appropriate
methodology.
Add (3): If you elect to define a NOX emission rate system, add RT 585
for parameter NOXR, methodology CEM and fuel code NFS and
indicate that this is a primary method. Deactivate the existing RT 585
for parameter NOXM. If you plan to continue using the NOX
concentration system, then add another RT 585 for parameter NOXM,
methodology CEM , and fuel code NFS, with the same start date as the
NOX emission rate method, but indicate that it is a secondary
methodology.
General EDR You will have to make general EDR changes (additional/discontinued
Changes fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 555,
556, 585 and 587.
Page 22 Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case 3 Section 2; Coal-fired Units
Case 3 Example Example Unit 3 is a dry-bottom wall-fired bituminous coal unit. For the
Unit OTC NBP, this unit has been using a NOX Concentration CEM combined
with a Stack Flow monitoring system to determine NOX mass. Assuming
heat input is required for State allowance allocations, the facility will be
installing a wet basis O2 monitor to determine heat input and will use the
appropriate Part 75 default moisture value for coal. The attached
comparison shows the changes made for each Record Type.
Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001 Page 23
-------
Example for Case 3: EDR Changes for a Coal Unit using NQXC and FLOW
RT100
OTC
SUBH
RT102
OTC/SUBH
RT504
OTC
SUBH
RT505
OTC
SUBH
RT506
SUBH
RT510
OTC
SUBH
RT520
OTC
SUBH
EDR Version Changed from V2.0 to V2.1. Reporting Quarter and Year Changed.
10030000022001V2 . 0
10030000022002V2.1
No Changes
102CASE 3 COGENERATION 4911PA095 404133 752842
Fields Added in v2.1
5043 DB 1160.019950828
5043 DB 1160.019950828 120 0 235 235
New record reported for Subpart H Participation beginning on 4/1/2001
5053 NBP B Q 19980701PA PA
5053 OTC-SUBH B Q 20020401 PA
New RT in v2.1. Required for all units.
5063 333 1995 300000300000
Diluent System added. DAHS version updated.
5103 D11F10UFLOWP DAHS PERFECT DATA, INC. CNT-220
5103 F11F10UFLOWP FLOWU VOLUMAIR DP-200 0550MKT
5103 D11N10UNOXCP DAHS PERFECT DATA, INC. CNT-220
5103 N11N10UNOXCP NOX DINMEASURERIGHT 99-77 872J-222
5103 D11F10CFLOWP DAHS PERFECT DATA, INC. CNT-221
5103 F11F10UFLOWP FLOWU VOLUMAIR DP-200 0550MKT
5103 D11N10CNOXCP DAHS PERFECT DATA, INC. CNT-221
5103 N11N10UNOXCP NOX DINMEASURERIGHT 99-77 872J-222
5103 D11010A02 P DAHS PERFECT DATA, INC. CNT-221
5103 011010A02 P 02D DINOXYGEN UNLTD MONITOR 0 555-603
19980701
19980701
19980701
19980701
19980701
19980701
19980701
19980701
20020401
20020401
New formula added to support new heat input determination
5203 UN10NOXMN-1 M NOx h = 1 . 194*10**- 7*S# (N11-N10 ) *S# (F11-F10 ) *t h
5203 UN10NOXMN-1 M NOx h = 1 . 194*10**- 7*S# (N11-N10 ) *S# (F11-F10 ) *t h
5203 A011HI F-18 HI=S# (P11-P10) * [(100- H20 default) )/ (100*9780) ] [(20.9- Stt(Oll-OlO)
)/20.9]
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Example for Case 3: EDR Changes for a Coal Unit using NQXC and FLOW
RT530
OTC
SUBH
RT531
OTC
SUBH
RT535
OTC
SUBH
RT536
SUBH
RT585
OTC
SUBH
RT586
OTC/SUBH
RT587
OTC/SUBH
RT 530 for diluent added to support addition of diluent system. Fields added in RT 530 for flow.
5303 FLOWHF 16019000.000 325.000 450 . OOOKSCFM 99010100
5303 NOX HTR 240.000 0.000 300.000 300.000PPM 99010100
5303 FLOWHF 16019000.000 325.000 450. OOOKSCFM 99010100 19500000 27000000
5303 NOX HTR 240.000 0.000 300.000 300.000PPM 99010100
5303 02 HNA 20.00 25.000% 02040100
Deactivated Flow and NOXC records. Added H2O default value for bituminous coal, minimum %O2
for missing data purposes and diluent cap value for O2.
5313 FLOW 16019000. OOOSCFH MD NFSAMPF 1998070100
5313 NOXC 240.000PPM MD NFSAMPC 1998070100
5313 FLOW 16019000. OOOSCFH MD NFSAMPF 19980701002002033123
5313 H20 6.000%H20 PM BT AMC 2002040100
5313 NOXC 240.000PPM MD NFSUMPC 19980701002002033123
5313 02M 5.000%02 MD NFSADATA2002040100
5313 02X 14.000%02 DC NFSADCPD2002040100
Designated Normal load field should be left blank in EDR v2.1. Also, unless you qualify on the basis of
being a peaking unit or a bypass stack, leave the Single Load designation field blank.
5353 MW 125HS
5353 MW 125
New RT in EDR v2.1. Required for all units/stacks with any CEM system.
5363 125 40H,MMH20020101
Added for methodologies for Heat Input and Moisture. Also note code changes.
5853 NOXMCEM NFSPLOAD 19980701
5853 H20 MDF C PNA 20020401
5853 HI CEM NFSPSPTS 20020401
5853 NOXMCEM NFSPSPTS 19980701
No Changes
5863 NOX LNB PO
No Changes
5873 C 19950828 P
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Section 2: Coal-fired Units
Case 4
Case 4
NOX Concentration CEMS and Stack Flow Monitor for NOX Mass
(Stack Flow and Diluent Monitor for Heat Input)
Overview
General EDR
Changes
No basic monitoring methodology change is required for either the NOX
emission rate methodology or the heat input methodology for Case 4.
However, if you elect to switch to the NOX emission rate times heat input
rate methodology for NOX mass, and to discontinue using NOX mas
concentration times flow rate (or to use it as a secondary NOX mass
methodology), see Case 3, above, for further guidance.
One key step is to delete the existing RT 505 for NBP and define a new
RT 505 for OTC-SUBH to identify the date when your unit begins
complying with Subpart H requirements. You should add this RT 505
first before making other changes if you are using the Monitoring Data
Checking (MDC) software program to make the changes.
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 540,
555, 556, 585 and 587.
Note! If you use MDC to change your
monitoring plan RTs, first define a new
RT 505 for OTC-SUBH and remove
the RT 505 for NBP.
Page 26
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
SECTION 3: OIL- AND GAS-FIRED UNITS
Use Table 3-1 to determine the Case number of your OTC monitoring scenario. Then go
to the detailed discussion of that Case number in this section to determine the changes
you need to make.
Monitoring
Methodology
Changes
The OTC Monitoring Guidance allowed a number of monitoring
methodologies for oil and gas units that are not permitted under Part 75.
However, similar methods are provided for oil and gas units that qualify
as Low Mass Emissions units. If you meet the requirements of Section
75.19 and intend to use the LME provisions, see Section 4 for guidance
on converting your monitoring plan to reflect LME monitoring. If you
do not qualify for the LME provisions, you may need significant changes
to convert your OTC monitoring to Part 75 requirements. Table 3-1
summarizes the monitoring methodology changes that may be required
for your oil or gas-fired OTC unit to comply with Part 75, Subpart H
monitoring and monitoring plan reporting requirements. This section
then presents the changes in a series of seven cases so that you can
review the changes based on your specific monitoring configurations.
If you currently use a stack moisture default value in any of your
emission calculations, note that Subpart H does not allow use of default
H2O values for oil and gas units. You will need to measure stack
moisture (or calculate it from wet and dry O2 readings) on an hourly
basis.
You should note that each case is reported at the unit level. If you
defined common stacks or multiple stacks for use with your current OTC
monitoring, those designations should most likely remain in the Subpart
H monitoring scenario. (This may not be true for unmonitored bypass
stacks see additional note on bypass stacks at the end of Appendix A.)
Also, in each case you will find a list of general EDR Record Type (RT)
changes that will have to occur as you convert to Part 75 monitoring.
Use the list to identify the general RT changes that apply and consult the
detailed identification of the changes in Appendix A, Changes for All
Units
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 27
-------
Section 3: Oil/Gas-fired Units
Table 3-1: Summary Comparison of NOX and Heat Input Monitoring Methodologies in the
OTC and Federal NOX Budget Programs for Non LME Oil and Gas Fired Units
Unit
Type
Gas or
Oil
Current OTC Monitoring Method
NOX
NOX Emission Rate
CEMS
NOX Concentration
CEMS with Stack
Flow Monitor
Appendix E
Correlation Curves
Unit Defaults or
Generic Defaults
Heat Input
Stack Flow Monitor and
Diluent (O2/CO2) CEM
Appendix D, Hourly Fuel
Flow
Alternative Heat Input
Maximum Heat Input
None (only NJ required
heat input reporting for
OTC)
Appendix D Hourly Fuel
Flow or Stack Flow
Monitor and Diluent
(O2/CO2) CEM
Appendix D, Hourly Fuel
Flow
Appendix D, Hourly Fuel
Flow
Alternative Heat Input
Method
Maximum Heat Input
Long Term Fuel Flow
Change Required for non-LME
Subpart H Monitoring?
No changes needed to either basic
monitoring method.
Yes. Use Appendix D fuel flow
monitoring or a stack flow monitor and
diluent CEM to determine heat input.
(Or, for an emergency fuel, see Part 75,
Appendix D, Section 2.1.4.3 and Policy
Manual Question 25.10.)
Yes. Use Appendix D fuel flow
monitoring or a stack flow monitor and
diluent CEM to determine heat input.
No changes needed to either basic
monitoring method
Possibly. If non-peaking unit, NOX
emission rate CEMS required. If
peaking unit, no changes needed to NOX
methodology. No changes required for
Heat Input methodology.
Yes for NOX. Install NOX emission rate
CEMS or, if peaking, use Appendix E
correlation.
No changes required to Heat Input
methodology.
Yes. Install NOX emission rate CEMS
or, if peaking, Appendix E correlation.
Use Appendix D fuel flow monitoring
(or a stack flow monitor and diluent
CEM) to determine heat input. (Or, for
an emergency fuel, see Part 75,
Appendix D, Section 2.1 .4.3 and Policy
Manual Question 25.10.)
Case
#
5
6
7
8
9
10
11
Page 28
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
CaseS
Section 3: Oil/Gas-fired Units
CaseS
NOX Emission Rate CEMS with Heat Input Monitoring
(Stack Flow and Diluent Monitor or Appendix D Fuel Flow Monitoring)
Overview
General EDR
Changes
No basic monitoring methodology change is required for either the NOX
emission rate methodology or the heat input methodology for Case 5.
One key step is to delete the existing RT 505 for NBP and define a new
RT 505 for OTC-SUBH to identify the date when your unit begins
complying with Subpart H requirements. You should add this RT 505
first before making other changes if you are using the Monitoring Data
Checking (MDC) software program to make the changes.
If you are using an OTC default value for stack moisture, see Case 6
below for the applicable monitoring plan changes.
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 540,
555, 556, 585 and 587.
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
the RT 505 for NBP.
our \
new I
J
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 29
-------
Section 3: Oil/Gas-fired Units
Case 6
Case 6
NOX Emission Rate CEMS with Either
Alternative Heat Input or Maximum Heat Input
Methodology
Changes
EDR
Monitoring Plan
Changes
You do not have to change your basic NOX emission rate methodology.
However, you are not allowed to use the OTC Alternative Heat Input and
Maximum Heat Input options under Part 75, Subpart H. You must use
fuel flow metering in accordance with Part 75, Appendix D or install a
stack flow monitor and use it in conjunction with the existing diluent
monitor to determine heat input. (If you are using maximum heat input
rate only for an emergency fuel, see the Acid Rain Program Policy
Manual, Question 25.10 and RT 587 changes described in Appendix A
of this document.) If moisture correction is needed, you may either
calculate hourly moisture from wet and dry O2 readings or measure
moisture directly using a moisture sensor.
You will have to add some record types and you will have to deactivate
and delete others. One key step you must take is to delete the existing
RT 505 for NBP and define a new RT 505 for OTC-SUBH to identify
the date when your Unit begins complying with Subpart H requirements.
You should add this RT 505 first before making other changes if you are
using the Monitoring Data Checking (MDC) software program to make
the changes.
Appendix D
RT510
Note! If you use MDC to change
your monitoring plan RTs, first
define a new RT 505 for OTC-
SUBH and remove the RT 505 for
NBP.
The following sections describe the other specific changes you will have
to make to a number of monitoring plan record types to reflect the
monitoring changes you are making to convert to Part 75, Subpart H
monitoring.
If you elect to use Appendix D fuel flow metering to determine heat
input, make the following changes:
Add (1): A new fuel flow system for each fuel burned (oil and/ or gas).
The fuel flow system should be comprised of (at a minimum) one fuel
flow monitor and the DAHS software component. The parameter
reported for the fuel flow system should be OILM, OILV or GAS,
Page 30
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case 6 Section 3; Oil/Gas-fired Units
depending on the fuel being measured and the basis for measurement
(OILM is mass, OILV is volume).
Add (2): If you need an hourly moisture value, an H2O system
comprised of wet and dry O2 components (or a moisture monitor) and the
DAHS software.
Deactivate: The Alternative Heat Input system, if you defined one in
EDRv2.0.
RT 520 Add (1): Formulas for heat input rate from each fuel. If you determine
net fuel flow by summing or taking the difference between multiple fuel
flow meters, add the appropriate FGAS or FOIL formula to calculate the
net or total hourly fuel flow rate. If you burn multiple fuels, also add the
code D-15A formula to calculate the total hourly heat input rate from
combined fuels. Please see the appropriate reference tables in the EDR
v2.1 Instructions to determine the correct formula for your monitoring
situation.
Add (2): A NOX mass formula (code F-24) which references the NOX
emission rate formula and the newly defined heat input rate formula.
Add (3): An H2O formula if you are using wet and dry O2 monitors to
determine stack moisture.
Deactivate: The NOX mass formula that references the ALTHI or MHHI
value.
RT 531 Add (1): A record for the appropriate diluent cap value if you intend to
use those provisions (see formulas in Part 75, Appendix F, Sections 4
and 5).
Add (2): If you have a moisture system, a record for the minimum or
maximum %H2O for missing data purposes (see § 75.37(b)).
Deactivate (1): The record for parameter ALTHI or HI.
Deactivate (2): The record(s) for NOX MER.
Deactivate (3): The record for parameter H2O that defined the default
moisture value allowed under OTC, if you defined one.
RT 540 Add: For each fuel flowmeter system, report RT 540 information. Do
not report this record to report data on individual components. Report
one RT 540 for each GAS, OILV or OILM system in RT 510, except
when a system is made up of multiple fuel flowmeters using different
methods of calibration. In this situation, report multiple RTs 540 for the
system indicating the calibration method for each flowmeter (col. 38) in
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001 Page 31
-------
Section 3; Oil/Gas-fired Units Case 6
the subsequent records (all information in other fields of the multiple
RTs 540 will be identical).
RT585 Add (1): Record(s) for parameter Heat Input (code HI in col. 10),
Methodology Gas Fuel Flow or Oil Fuel Flow (codes GFF or OFF,
respectively, in col. 14), and for the appropriate fuel type (col. 24).
Add (2): A record for parameter H2O if you use stack moisture in any of
your calculations.
Deactivate: The record for parameter HI (for either ALTHI or MHHI
methodology).
Stack Flow If you elect to use stack flow monitoring to determine heat input, make
Monitoring the following changes:
RT 510 Add (1): Define the new flow system (comprised of the flow monitor
and the DAHS software component).
Add (2): If you need to measure moisture, an H2O system comprised of
wet and dry O2 components (or a moisture monitor) and the DAHS
software.
Deactivate: The Alternative Heat Input system if you defined one in
EDRv2.0.
RT 520 Add (1): A new heat input formula which references the flow
component in the flow system and the diluent component in the NOX
system. Use Table 19: Heat Input Formula Reference Table in the EDR
v2.1 Instructions to determine the correct formula for your monitoring
situation it depends on diluent monitor type (CO2 or O2) and whether
you sample on a wet or dry basis.
Add (2): A NOxmass formula (code F-24) which references the NOX
emission rate formula and the newly defined heat input formula.
Add (3): An H2O formula if you are using wet and dry O2 monitors to
determine stack moisture.
Deactivate: The NOxmass formula that references the ALTHI or MHHI
value.
RT 530 Add: A span record for stack flow.
RT 531 Add (1): If you have a moisture system, a record for the minimum or
maximum %H2O for missing data purposes (see § 75.37(b)).
Page 32 Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case 6
Section 3: Oil/Gas-fired Units
Add (2): A record for the minimum potential %O2 for missing data
purposes, if using an O2 diluent monitor.
Add (3): A record for the appropriate diluent cap value if you intend to
use those provisions (see formulas in Part 75, Appendix F, Sections 4
and 5).
Deactivate (1): The record for ALTHI or HI values.
Deactivate (2): The record(s) for NOX MER values.
Deactivate (3): The record for parameter H2O that defined the default
moisture value allowed under OTC, if you defined one.
RT585
General EDR
Changes
Case 6 Example
Unit
Add (1): A methodology record for parameter Heat Input (code HI in
col. 10), Methodology Continuous Emissions Monitoring (code CEM in
col. 14), and fuel type non fuel-specific (code NFS in col. 24).
Add (2): A record for parameter H2O if you use stack moisture in any of
your calculations.
Deactivate: The record for parameter HI (for either ALTHI or MHHI
methodology).
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 540,
555, 556, 585 and 587.
Example Unit 6 is a Combined Cycle Oil-Fired Unit. For the OTC NBP,
this unit has been using a NOX emission rate CEM combined with the
Maximum Hourly Heat Input (MHHI) rate to determine NOX mass.
Since the default methodology (MHHI) is not allowed for this unit under
Subpart H, the facility will be installing a new oil fuel flow meter to
determine heat input. The attached comparison shows the changes made
for each record type.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 33
-------
Example for Case 6: EDR Changes for an Oil Unit using MHHI
RT100
OTC
SUBH
RT102
OTC/SUBH
RT504
OTC
SUBH
RT505
OTC
SUBH
RT506
SUBH
RT510
OTC
SUBH
EDR Version Changed from V2.0 to V2.1. Reporting Year and Quarter Changed.
10060000022001V2 .0
10060000022002V2.1
No Changes
102CASE 6 COGENERATION 4911PA009
404920 761025
Fields Added in EDR v2.1
5046 CC 1205.019930412
5046 CC 1205.019930412 150 16 258
New record reported for Subpart H Participation beginning on 5/1/2002
5056 NBP B Q 1998070125PA123108PA
5056 OTC-SUBH B OS20020501 PA
NewRTinEDRv2.1
5066 666 1993 600000600000
Oil System Added. DAHS version changed.
5106 DAS111UNOX P DAHS PERFECT DATA, INC. GOOD DAHS V33
5106 NOX111UNOX P NOXHIS MEASURERIGHT N-7000 0480095R
5106 02W111UNOX P O2W IS MEASURERIGHT O-8000 0480167
5106 DAS111CNOX P DAHS PERFECT DATA, INC. GOOD DAHS V2200
5106 NOX111UNOX P NOXHIS MEASURERIGHT N-7000 0480095R
5106 O2W111UNOX P O2W IS MEASURERIGHT O-8000 0480167
5106 DAS211AOILMP DAHS PERFECT DATA, INC. GOOD DAHS V2200
5106 OFM211AOILMP OFFMORFOIL FLOWING FL0008 FL0000812
19980701
19980701
19980701
19980701
19980701
19980701
20020501
20020501
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Example for Case 6: EDR Changes for an Oil Unit using MHHI
RT520
OTC
SUBH
RT530
OTC
SUBH
RT531
OTC
SUBH
RT535
OTC
SUBH
RT536
SUBH
Old NOX mass formula deactivated, new formulas added for NOX mass and heat input determination.
Code for FW formula updated.
5206 U001NOX 19-2 E_H= (1 - 194*10**- 7) *S# (NOX- 111) *F# ( 003 ) (20 . 9/ (20 . 9 ( 1-B_WA) -S# (O2W-111 ) ) )
5206 U002NOXMF-10AM_NOX_H=F# (001) *Max_HI*T_l
5206 U003FW F-7C F_W=1*10**6 ( (5 . 57*H) + ( 1 . 53*C) + (0 . 57*S) + ( 0 . 14*N) - (0 . 46*02 ) + (0 . 21*WAT) ) /GCV
5206 U001NOX 19-2 E H= (1 . 194*10**- 7) *S# (NOX- 111) *F# ( 003 ) (20 . 9/ (20 . 9 ( 1-B WA) -S# (O2W-111 ) ) )
5206 D002NOXMF-10AM NOX H=F# (001 ) *Max HI*T 1
5206 C003FW 19-14F W=l*10**6 ( (5 . 57*H) + ( 1 . 53*C) + (0 . 57*S) + ( 0 . 14*N) - (0 . 46*02 ) + (0 . 21*WAT) ) /GCV
5206 A011HI D-8 HI rate-oil= S#(OFM-211) * GCVoil/ 10**6
5206 A012NOXMF-24 NOXM= F#(001) * F#(011) * op time
No changes
5306 NOX HHD 100.000 0.183 125.000 150.000PPM 98070100
5306 O2 H 21.000 25.000% 98070100
5306 NOX HHD 100.000 0.183 125.000 150.000PPM 98070100
5306 02 H 21.000 25.000% 98070100
Deactivated previous defaults. Added record to define diluent cap value.
5316 HI 1205.000MMBTU PMNFSANPC 1998070100
5316 NOX 0.183LBMMBTUMD NFSAMPC 1998070100
5316 HI 1205 .OOOMMBTU PM NFSANPC 19980701002001123123
5316 NOX 0 .183LBMMBTUMD NFSAMPC 19980701002001123123
5316 02X 19.000%02 DC NFSADCPD2002050100
Designated Normal load field should be left blank for OTC-SUBH Units.
5356 MW 101H
5356 MW 101
New RT in v2.1
5366 101 23H,LHL20020101
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Example for Case 6: EDR Changes for an Oil Unit using MHHI
RT540
SUBH
RT585
OTC
SUBH
RT587
OTC/SUBH
Added for Fuel Flow System
5406 2110ILMOIL 71263. OLBHR UMXAPI A
Discontinued for MHHI methodology, Added for Appendix D Fuel Flow. Also note code changes.
5856 HI MHHI NFSPNA 19980701
5856 NOXRCEM NFSPLOAD 19980701
5856 HI MHHI NFSPNA 1998070120011231
5856 HI OFF OILPSPTS 20020501
5856 NOXRCEM NFSPSPTS 19980701
No Changes
5876 OIL19980701 P
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Case?
Section 3: Oil/Gas-fired Units
Case?
NOX Concentration CEMS and Stack Flow Monitor,
No Heat Input Monitoring
Methodology
Changes
EDR
Monitoring Plan
Changes
You do not have to change your basic NOX emission rate methodology.
However to determine heat input you must use fuel flow metering in
accordance with Part 75, Appendix D or install a diluent monitor and use
it in conjunction with the existing stack flow monitor. If moisture
correction is needed, you may either calculate hourly moisture from wet
and dry O2 readings or measure moisture directly using a moisture
sensor.
You will have to add some record types and you will have to deactivate
and delete others. One key step you must take is to delete the existing
RT 505 for NBP and define a new RT 505 for OTC-SUBH to identify
the date when your unit begins complying with Subpart H requirements.
You should add this RT 505 first before making other changes if you are
using the Monitoring Data Checking (MDC) software program to make
the changes.
Appendix D
RT510
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
the RT 505 for NBP.
our \
new I
J
The following sections describe the other specific changes you will have
to make to a number of monitoring plan record types to reflect the
monitoring changes you are making to convert to Part 75, Subpart H
monitoring.
If you elect to use Appendix D fuel flow monitoring to determine heat
input, make the following changes:
Add (1): A new fuel flow system for each fuel burned (oil and/or gas).
The fuel flow system should be comprised of (at a minimum) one fuel
flow meter and the DAHS software component. The parameter reported
for the fuel flow system should be OILM, OILV or GAS, depending on
the fuel being measured and the basis for measurement (OILM is mass,
OILV is volume).
Add (2): If you need to an hourly moisture value, an H2O system
comprised of wet and dry O2 components (or a moisture monitor) and the
DAHS software.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 37
-------
Section 3; Oil/Gas-fired Units Case 7
RT 520 Add (1): Formulas for heat input rate from each fuel. If you determine
net fuel flow by summing or taking the difference between multiple fuel
flow meters, add the appropriate FGAS or FOE. formula to calculate the
net or total hourly fuel flow rate. If you burn multiple fuels, also add the
code D-15A formula to calculate the total hourly heat input rate from
combined fuels. Please see the appropriate reference tables in the EDR
v2.1 Instructions to determine the correct formula for your monitoring
situation.
Add (2): An H2O formula if you are using wet and dry O2 monitors to
determine stack moisture.
RT531 Deactivate: Records for parameter NOXC, FLOW or H2O.
RT 535 Remove: If you previously reported an "S" (col. 19) to denote state
approval of single load flow RATA testing, you should remove this value
from RT 535. If you do not qualify for single load RATA testing based
on being either a bypass stack or a peaking unit, this field should be left
blank. Also leave this field blank if, in a particular year, you qualify for
single load RATA under Part 75 because the unit has operated at a single
load level for >85% of the time since the last annual flow RATA (use RT
695 to claim the multi load flow testing exemption for that year).
RT 540 Add: This record for each fuel flowmeter system. Do not report this
record to report data on individual components. Report one RT 540 for
each GAS, OILV or OILM system in RT 510, except when a system is
made up of multiple fuel flowmeters using different methods of
calibration. In this situation, report multiple RTs 540 for the system
indicating the calibration method for each flowmeter (col. 38) in the
subsequent records (all information in other fields of the multiple RTs
540 will be identical).
RT 585 Add (1): Methodology record(s) for parameter Heat Input (code HI in
col. 10), Methodology Gas Fuel Flow or Oil Fuel Flow (codes GFF or
OFF, respectively, in col. 14), and for the appropriate fuel type (col. 24).
Add (2): Methodology record for H2O, if needed in your NOX mass
calculation.
Diluent Gas If you elect to use diluent gas monitoring to determine heat input, make
Monitoring the following changes (if you also plan to define a NOX emission rate
system, see Case 3):
RT 510 Add (1): The new diluent system (comprised of the O2 or CO2 monitor
and the DAHS software component).
Page 38 Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001
-------
Case?
Section 3: Oil/Gas-fired Units
Add (2): If moisture correction is required, an H2O system comprised of
wet and dry O2 components (or a moisture sensor) and the DAHS
software.
RT520
RT530
RT531
RT585
General EDR
Changes
Case 7 Example
Unit
Add (1): A new heat input formula which references the diluent
component in the diluent system and the flow component in the flow
system. Use Table 19: Heat Input Formula Reference Table in the EDR
v2.1 Instructions to determine the correct formula for your monitoring
situation it depends on diluent monitor type (CO2 or O2) and whether
you sample on a wet or dry basis.
Add (2): An H2O formula if you are using wet and dry O2 monitors to
determine stack moisture.
Add: A span record for the O2 or CO2 monitor.
Add (1): A record for minimum or maximum %H2O for missing data
purposes if you have defined an H2O system.
Add (2): A record for the minimum potential %O2 for missing data
purposes, if using an O2 diluent monitor.
Add (3): A record for the appropriate diluent cap value if you intend to
use those provisions (see formulas in Part 75, Appendix F, Sections 4
and 5).
Deactivate: Records for parameter NOXC, FLOW or H2O.
Add (1): A record for parameter Heat Input (code HI in col. 10),
Methodology Continuous Emissions Monitoring (code CEM in col. 14),
and fuel type non fuel-specific (code NFS in col. 24).
Add (2): A record for parameter H2O if moisture correction is required.
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 540,
555, 556, 585 and 587.
Example Unit 7 is a Combined Cycle Gas Fired Unit. For the OTC NBP,
this unit has been using a NOX concentration and stack flow to determine
NOX mass. The example assumes the State SIP requires this Unit to
monitor heat input, so the facility will be installing gas fuel flow
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 39
-------
Section 3; Oil/Gas-fired Units Case 7
monitors to determine heat input. The attached comparison shows the
changes made for each record type.
Page 40 Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001
-------
Example for Case 7: EDR Changes for an Oil and Gas Unit using NQXC and FLOW
RT100
OTC
SUBH
RT102
OTC/SUBH
RT504
OTC
SUBH
RT505
OTC
SUBH
RT506
SUBH
RT510
OTC
SUBH
EDR Version Changed from V2.0 to V2.1.
Reporting Quarter and Year Changed.
10070000022001V2 .0
10070000022002V2.1
No Changes
102CASE 7
COGENERATION 4911PA095
404133 752842
Fields Added in v2.1
5047 CC 1160.019950828
5047 CC 1160.019950828 150 28
234 236
New record reported for Subpart H Participation beginning on 4/1/2002
5057 NBP B Q 19980701PA123108PA
5057 OTC-SUBH B Q 20020401 PA
NewRTinEDRv2.1
5067 111 1995 700000700000
Fuel Flow System Added. DAHS version changed.
5107 D01F10UFLOWP DAHS PERFECT DATA, INC
5107 F01F10UFLOWP FLOWDP MEASURERIGHT
5107 D01N10UNOXCP DAHS PERFECT DATA, INC
5107 N01N10UNOXCP NOX DINMEASURERIGHT
5107 D01F10CFLOWP DAHS PERFECT DATA, INC
5107 F01F10UFLOWP FLOWDP MEASURERIGHT
5107 D01G10AGAS P DAHS PERFECT DATA, INC
5107 GF1G10AGAS P GFFMORFGAS FLOWING FAST
5107 GF2G10AGAS P GFFMORFGAS FLOWING FAST
5107 D01N10CNOXCP DAHS PERFECT DATA, INC
5107 N01N10UNOXCP NOX DINMEASURERIGHT
GOOD DAHS
FL-789
GOOD DAHS
N-7000
GOOD DAHS
FL-789
GOOD DAHS
GFZOOM
GFZOOM
GOOD DAHS
N-7000
V33 2185
0550
V33 2185
42D49872-284
V22002185
0550
V22002185
GF0000001
GF0000002
V22002185
42D49872-284
19980701
19980701
19980701
19980701
19980701
19980701
20020401
20020401
20020401
19980701
19980701
n
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Example for Case 7: EDR Changes for an Oil and Gas Unit using NQXC and FLOW
RT520
OTC
SUBH
RT530
OTC
SUBH
RT531
OTC
SUBH
RT535
OTC
SUBH
RT536
SUBH
RT540
SUBH
RT585
OTC
SUBH
New formulas added for new heat input determination
5207 UN10NOXMN-1 M NOx h = 1 . 194*10** -7*S# (N10-N01) *S# (F10-F01) *t h
5207 AGFZFGASN-GASNet gas flow= Stt(GFl-GZl) + F#(GF2-GZ1)
5207 AH10HI D-6 HI rate-gas= F#(GFZ) * GCV gas/ 10**6
5207 UN10NOXMN-1 M NOx h = 1 . 194*10** -7*S# (N10-N01) *S# (F10-F01) *t h
New fields added in Flow RT 530.
5307 FLOWHF 16019000.000 325.000 450 . OOOKSCFM 98070100
5307 NOX HTR 105.000 0.000 140.000 150.000PPM 98070100
5307 FLOWHF 16019000.000 325.000 450. OOOKSCFM 98070100 19500000 27000000
5307 NOX HTR 105.000 0.000 140.000 150.000PPM 98070100
Deactivated previous default values.
5317 FLOW 16019000. OOOSCFH MD NFSAMPF 1998070100
5317 NOXC 67.000PPM MD NFSCMEC 1998070100
5317 NOXC 105.000PPM MD NFSUMPC 1998070100
5317 FLOW 16019000 .OOOSCFH MD NFSAMPF 19980701002002033123
5317 NOXC 67.000PPM MD NFSCMEC 19980701002002033123
5317 NOXC 105.000PPM MD NFSUMPC 19980701002002033123
Designated Normal load field should be left blank for OTC-SUBH Units. State Approved Single Load
Flow Rata qualification indicator no longer reported here.
5357 MW 125HS
5357 MW 125
New RT in v2.1
5367 125 56M,HH 20020101
Added for Fuel Flow System
5407 G10GAS PNG 15800. OHSCF UMXASME A
Added for Appendix D Fuel Flow. Also note code changes.
5857 NOXMCEM NFSPLOAD 19980701
5857 HI GFF PNGPSPTS 20020401
5857 NOXMCEM NFSPSPTS 19980701
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-------
Example for Case 7: EDR Changes for an Oil and Gas Unit using NQXC and FLOW
o
o
§
g
o
RT586
OTC/SUBH
RT587
OTC/SUBH
No Changes
5867 NOX NH3 PO
No Changes
5877 PNG19980701 P
n
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a
g-
Q
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Section 3: Oil/Gas-fired Units
CaseS
CaseS
NOX Concentration CEMS with Heat Input Monitoring
(Stack Flow and Diluent Monitor or Appendix D Fuel Flow Monitoring)
Overview
General EDR
Changes
No basic monitoring methodology change is required for either the NOX
emission rate methodology or the heat input methodology for Case 8.
One key step is to delete the existing RT 505 for NBP and define a new
RT 505 for OTC-SUBH to identify the date when your unit begins
complying with Subpart H requirements. You should add this RT 505
first before making other changes if you are using the Monitoring Data
Checking (MDC) software program to make the changes.
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 540,
555, 556, 585 and 587.
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
RT 505 for NBP.
our \
new I
»the I
Page 44
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case 9
Section 3: Oil/Gas-fired Units
Case 9
Appendix E Correlation for NOX Emission Rate and
Appendix D Fuel Flow Metering for Heat Input
Methodology
Changes
EDR
Monitoring Plan
Changes
You do not have to change your Heat Input monitoring methodology.
However, if your unit does not qualify as a peaking unit, you must install
a NOX emission rate CEM system. (Unless you qualify as an LME unit
see Part 4 of this document.) Unlike the OTC program which allows
Appendix E for any oil or gas-fired unit with a maximum heat input
capacity less than 250 mmBtu/hr or any size if peaking, Part 75 restricts
use of the Appendix E NOX methodology to peaking units.
You will have to add some record types and you will have to deactivate
and delete others. One key step you must take is to delete the existing
RT 505 for NBP and define a new RT 505 for OTC-SUBH to identify
the date when your Unit begins complying with Subpart H requirements.
You should add this RT 505 first before making other changes if you are
using the Monitoring Data Checking (MDC) software program to make
the changes.
NOX Emission
Rate CEM
(Non-Peaking
Unit)
RT510
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
the RT 505 for NBP.
our \
new I
J
If the unit qualifies as peaking, consult Appendix A, Changes for All
Units for the record type changes required for conversion to EDR v2.1.
For a non-peaking unit, the following sections describe the other specific
changes you will have to make to a number of monitoring plan record
types to reflect the monitoring changes you are making to convert to Part
75, Subpart H monitoring.
If you must use a NOX emission rate CEM system, make the following
changes.
Add (1): A new NOX emission rate system comprised of the NOX
concentration monitor, diluent monitor and the DAHS software
component. The parameter reported for the system should be NOX.
Make certain to use a dual range monitor if required. If you elect to use
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 45
-------
Section 3; Oil/Gas-fired Units Case 9
the default high range provisions of Part 75, use component type NOXL
for your single scale NOX monitor.
Add (2): If moisture correction is required, an H2O system comprised of
wet and dry O2 components (or a moisture sensor) and the DAHS
software.
Deactivate: The Appendix E NOX system.
RT 520 Add (1): An H2O formula, if you defined an H2O system with wet and
dry O2 components.
Add (2): A new NOX emission rate formula which references the new
NOX rate CEM components. Use Table 15: Heat Input Formula
Reference Table in the EDR v2.1 Instructions to determine the correct
formula for your monitoring situation - it depends on diluent monitor
type (CO2 or O2) and whether you sample on a wet or dry basis.
Add (3): A NOxmass formula (code F-24) which references the newly
defined NOX emission rate formula and the heat input formula.
Deactivate: The NOxmass formula that references the Appendix E
system.
RT 530 Add: A span record for NOX concentration and O2 or CO2. If the NOX
monitor is dual range or you are using the default high range provisions,
be certain to add both high and low scale NOX span records.
RT 531 Add (1): If you intend to use the diluent cap provisions, a record to
define the appropriate diluent cap value for this unit (see EDR v2.1
Instructions for RT 531).
Add (2): If you have a moisture system, define the minimum or
maximum %H2O for missing data purposes (see § 75.37(b)).
RT 535 Add: (If not already present) to report load information, as required for
any CEMS methodology.
RT 560 Remove: It is not necessary to include previously reported Appendix E
correlation curve segment information after the transition quarter.
However, if this curve was used for any part of a reporting quarter, this
information should remain in RT 560.
RT 585 Add (1): A record for parameter NOX emission rate (code NOXR in col.
10), Methodology Continuous Emissions Monitoring (code CEM in col.
14), and fuel type non fuel-specific (code NFS in col. 24).
Page 46 Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case 9
Section 3: Oil/Gas-fired Units
General EDR
Changes
Add (2): If moisture correction is required, a record for moisture
(parameter H2O).
Deactivate: The record for NOX rate (for the AE methodology).
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 540,
555, 556, 585 and 587.
Example Unit 9 is a Dry Bottom wall-fired Oil and Gas Fired Unit. For
the OTC NBP, this unit has been using Appendix E NOX correlation
curve with Appendix D fuel flow monitoring to determine NOX mass.
However, since this Unit no longer qualifies to use Appendix E NOX rate
monitoring, the facility will be installing a NOX rate CEM (NOX
concentration monitor and an O2 dry monitor). The attached comparison
shows the changes made for each record type.
Case 9 Example
Unit
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 47
-------
Example for Case 9: EDR Changes for an Oil & Gas Unit using App. E and App. D
RT100
OTC
SUBH
RT102
OTC/SUBH
RT504
OTC
SUBH
RT505
OTC
SUBH
RT506
SUBH
RT510
OTC
SUBH
EDR Version Changed from V2.0 to V2.1.
Reporting Quarter and Year Changed.
10090000022001V2 .0
10090000022002V2.1
No Changes
102CASE 9
ELECTRIC UTILITY 4911DE001 391039 753245
Fields Added in v2.1
5049 DB 225.019620401
5049 DB 225.019620401 130 33 45
New record reported for Subpart H Participation beginning on 5/1/2002
5059 NBP B OS199807017DEL60N037DE
5059 OTC-SUBH B OS20020501 DE
New record type in EDR v2.1
5069 911 1976 900000900000
Deactivated Appendix E Systems. Added
5109 DAS101UOILMP DAHS GREAT DATA SYSTEMS
5109 OF1101UOILMP OFFMCORMEASURERIGHT
5109 DAS102UGAS P DAHS GREAT DATA SYSTEMS
5109 GF1102UGAS P GFFMORFGAS FLOWING FAST
5109 DAS103UNOX P DAHS GREAT DATA SYSTEMS
5109 DAS104UNOX P DAHS GREAT DATA SYSTEMS
5109 DAS101COILMP DAHS GREAT DATA SYSTEMS
5109 OF1101UOILMP OFFMCORMEASURERIGHT
5109 DAS102CGAS P DAHS GREAT DATA SYSTEMS
5109 GF1102UGAS P GFFMORFGAS FLOWING FAST
5109 DAS103DNOX P DAHS GREAT DATA SYSTEMS
5109 DAS104DNOX P DAHS GREAT DATA SYSTEMS
5109 DASN13ANOX P DAHS GREAT DATA SYSTEMS
5109 N11N13ANOX P NOX DILNOXXY MON
5109 022N13ANOX P 02D DIL02 MEASURE
NOX Rate CEM System. Updated DAHS
IX
XK-4000 TGS02618
IX
GFF-100 WS6011598
IX
IX
2.61X
XK-4000 TGS02618
2.61X
GFF-100 WS6011598
IX
IX
2.61X
NOXXY 777 NOX777-3
MON-1-453 024378-567
version.
19980701
19980701
19980701
19980701
19980701
19980701
19980701
19980701
19980701
19980701
1998070120010930
1998070120010930
20020501
20020501
20020501
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Example for Case 9: EDR Changes for an Oil & Gas Unit using App. E and App. D
RT520
OTC
SUBH
RT530
SUBH
RT531
SUBH
RT535
OTC
SUBH
RT536
SUBH
RT540
OTC
SUBH
Marked previous NOXM formulas for deletion. Added new formulas for NOX emission rate and NOX
mass. Updated heat input formula code.
5209 U101HI F-19 HI_oil = S#(OF1-101) * GCV_oil / 10 ** 6
5209 U102HI F-20 HI_gas = S#(GF1-102) * GCV_gas / 10 ** 6
5209 U106NOXMF-10AM_NOx(oil) = NOx rate from oil correlation curve * F#(101) * T_oil
5209 U107NOXMF-10AM_NOx(gas) = NOx rate from gas correlation curve * F#(102) * T_gas
5209 U108NOXMN-3 M_NOx(total) = F#(106) + F#(107)
5209 U109HI F-20CHI_combined fuels = ( (F#(101) * T_oil) + (F#(102) * T_gas) ) / T_unit
5209 U101HI F-19 HI oil = S#(OF1-101) * GCV oil / 10 ** 6
5209 U102HI F-20 HI gas = S#(GF1-102) * GCV gas / 10 ** 6
5209 D106NOXMF-10AM NOx(oil) = NOx rate from oil correlation curve * F#(101) * T oil
5209 D107NOXMF-10AM NOx(gas) = NOx rate from gas correlation curve * F#(102) * T gas
5209 D108NOXMN-3 M NOx(total) = F#(106) + F#(107)
5209 C109HI D-15AHI combined fuels = ( (F#(101) * T oil) + (F#(102) * T gas) ) / T unit
5209 AHIHNOXMF-24 NOXM= F# (NNN) * F#(109) * unit op time
5209 ANNNNOX 19-1 E= 1.194*10**-? * S#(N11-N13) * 9190 * 20 . 9/20 . 9-S# (022-N13)
Added span information for NOX and O2 monitors
5309 NOX HHD 320.000 0.528 400.000 400.000PPM 02010100
5309 02 H 20.000 25.000 25.000% 02010100
Added Record to Define Diluent Cap value (for a boiler)
5319 02X 14.000%02 DC NFSADCPD2002050100
Designated Normal load field should be left blank in EDR v2.1
5359 MW 19H
5359 MW 19
New record type in EDR v2.1. Required for Units using CEM methods.
5369 19 9H,MH 20020101
Initial Calibration Method Codes added to EDR v2.1.
5409 1010ILMOIL 12300 . OLBHR UMXMFC-9M- 1988 U
5409 102GAS PNG 2400.0HSCF UMXMFC-3M- 1989 U
5409 101OILMOIL 12300. OLBHR UMXAPI C
5409 102GAS PNG 2400.0HSCF UMXAPI C
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Example for Case 9: EDR Changes for an Oil & Gas Unit using App. E and App. D
RT560
OTC
RT585
OTC
SUBH
RT586
OTC/SUBH
RT587
OTC/SUBH
Appendix E Correlation Curve Records removed in v2.1
5609
5609
5609
5609
5609
5609
5609
5609
19971203 1 OG01103 0.0 100.3 0.270 0.270PNG
19971203 2 1G02103 100.3 138.5 0.270 0.290PNG
19971203 3 2G03103 138.5 197.9 0.290 0.360PNG
19971203 4 3G04103 197.9 227.5 0.360 0.340PNG
19980202 5 OR01104 0.0 102.3 0.350 0.350OIL
19980203 6 1R02104 102.3 153.0 0.350 0.370OIL
19980203 7 2R03104 153.0 200.4 0.370 0.380OIL
19980203 8 3R04104 200.4 220.1 0.380 0.410OIL
Deactivated Appendix E methodology. Added NOXR CEM methodology. Also note code changes.
5859
5859
5859
5859
5859
5859
5859
5859
5859
HI GFF PNGPLOAD 19980701
HI OFF OILPLOAD 19980701
NOXRAE OILPNA 19980701
NOXRAE PNGPNA 19980701
HI GFF PNGPSPTS 19980701
HI OFF OILPSPTS 19980701
NOXRAE OILPNA 1998070120010930
NOXRAE PNGPNA 1998070120010930
NOXRCEM NFSPSPTS 20020501
No Changes
5869
NOX LNB P 1995030119950601
No Changes
5879
5879
OIL19980701 P
PNG19980701 S
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Case 10
Section 3: Oil/Gas-fired Units
Case 10
Unit Specific or Generic NOX Default Rate and
Appendix D Fuel Flow Metering for Heat Input
Methodology
Changes
EDR
Monitoring Plan
Changes
You do not have to change your Heat Input monitoring methodology.
However, Part 75 does not allow use of default NOX rates for non-LME
units. If your unit qualifies as peaking, you may use the Appendix E NOX
correlation method. If your unit does not qualify as a peaking unit, you
must install a NOX emission rate CEM system.
You will have to add some record types and you will have to deactivate
and delete others. One key step you must take is to delete the existing
RT 505 for NBP and define a new RT 505 for OTC-SUBH to identify
the date when your unit begins complying with Subpart H requirements.
You should add this RT 505 first before making other changes if you are
using the Monitoring Data Checking (MDC) software program to make
the changes.
Appendix E
(Peaking Unit)
RT507
RT510
RT520
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
the RT 505 for NBP.
our \
new I
J
The following sections describe the other specific changes you will have
to make to a number of monitoring plan record types to reflect the
monitoring changes you are making to convert to Part 75, Subpart H
monitoring.
If you qualify for and elect to use the Appendix E correlation method to
determine NOX emission rate, make the following changes:
Add: With the appropriate peaking qualification information.
Add: A new Appendix E NOX system for each correlation curve to be
established. If you are testing each fuel separately, define a system for
each fuel burned (oil and/or gas). Each Appendix E system should be
comprised of the DAHS software component only.
Add: A NOX mass formula (code F-24) which references the NOX
emission rate from Appendix E curve and the total heat input rate
formula.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 51
-------
Section 3: Oil/Gas-fired Units
Case 10
RT530
RT531
RT535
RT560
RT585
NOX Emission
Rate CEM
(Non-Peaking
Unit)
RT510
RT520
Deactivate: The NOxmass formula that references the unit specific or
generic default.
Add: Record to define maximum NOX emission rate for gas and/or oil
(parameter GNOX or ONOX). See EDR v2.1 Instructions.
Deactivate: Unit specific or generic default NOX rate values.
Add: (If not already present) to report load information, as required for
any CEMS methodology
Add: For each Appendix E system when testing has been completed.
Add: A methodology record for parameter NOX rate (code NOXR in col.
10), Methodology Appendix E (code AE, in col. 14), and for the
appropriate fuel type (col. 24).
Deactivate: The previously record for NOX rate (for either UDEF or
GDEF methodology).
If you must or elect to use a NOX emission rate CEM system, make the
following changes:
Add (1): The new NOX rate system (comprised of the NOX concentration
monitor, the diluent monitor and the DAHS software component). Make
certain to use a dual range analyzer if necessary. If you elect to use the
default high range provisions of Part 75, use component type NOXL for
your single scale NOX monitor
Add (2): If moisture correction is required, define an H2O system
comprised of wet and dry O2 components (or a moisture sensor) and the
DAHS software.
Add (1): A new NOX emission rate formula which references the newly
defined NOX system. Use Table 15: Heat Input Formula Reference
Table in the EDR v2.1 Instructions to determine the correct formula for
your monitoring situation it depends on diluent monitor type (CO2 or
O2) and whether you sample on a wet or dry basis.
Add (2): A NOxmass formula (code F-24) which references the NOX
emission rate formula and the total hourly heat input rate formula.
Add (3): An H2O formula, if you defined an H2O system with wet and
dry O2 components.
Page 52
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case 10
Section 3: Oil/Gas-fired Units
RT530
RT531
RT535
RT585
General EDR
Changes
Case 10
Example Unit
Deactivate: The NOX mass formula that references the unit specific or
generic NOX default.
Add: A span record for NOX concentration and the diluent. Make
certain to add both low and high scale NOX records if you have dual
ranges or are using the default high scale range provisions.
Add (1): If you intend to use the diluent cap provisions, a record to
define the appropriate diluent cap value for this unit (see EDR v2.1
Instructions for RT 531).
Add (2): If you have a moisture system, define the minimum or
maximum %H2O for missing data purposes (see § 75.37(b)).
Deactivate (1): The record(s) for unit specific or generic default values.
Deactivate (2): The record(s) for maximum fuel flow.
Add: (If not already present) to report load information, as required for
any CEMS methodology.
Add (1): A record for NOX rate (code NOXR in col. 10), Methodology
Continuous Emissions Monitoring (code CEM in col. 14), and fuel type
non fuel-specific (code NFS in col. 24).
Add (2): If moisture correction is required, a record for moisture
(parameter H2O).
Deactivate: The previously defined RT 585 for heat input (for either
UDEF or GDEF methodology).
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 540,
555, 556, 585 and 587.
Example Unit 10 is a Diesel fired Combustion Turbine. For the OTC
NBP, this unit has been using Unit Specific NOX rate with Appendix D
fuel flow monitoring to determine NOX mass. However, this Unit no
longer qualifies to use the Unit Specific NOX rate default, but is a peaking
unit, which qualifies the unit to use Appendix E. The attached
comparison shows the changes made for each record type.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 53
-------
Example for Case 10: EDR Changes for an Oil Unit using Unit Specific Defaults with Appendix D
RT100
OTC
SUBH
RT102
OTC/SUBH
RT504
OTC
SUBH
RT505
OTC
SUBH
RT506
SUBH
RT507
OTC
SUBH
RT510
OTC
SUBH
EDR Version Changed from V2.0 to V2.1. Reporting Quarter and Year Changed.
10010101022001V2 .0
10010101022002V2.1
No Changes
102CASE 10 INDUSTRIAL TURBINE 2834PA091
401246 751808
Fields Added in v2.1
50410 CT 366.019890801
50410 CT 366.019890801 456 77 97
New record reported for Subpart H Participation beginning on 5/1/2002
50510 NBP B OS19980701PA25CH121 PA
50510 OTC-SUBH B OS20020501 PA
New record type in EDR v2.1
50610 10 10 10 1989 101010101010
New Peaking Qualification Data for 2002
50710 20011998A 4.01999A 5.32000A 7.9 5.7PK
50710 20021999A 5.32000A 7.92001A 7.4 6.9PK3HD
Added Appendix E System. Updated DAHS version.
51010 101100UOILVP OFFMTUROILMEASURE OM-768 8706-12413-1-3B
51010 102100UOILVP DAHS GREAT DAHS SYSTEMS IX
51010 101100UOILVP OFFMTUROILMEASURE OM-768 8706-12413-1-3B
51010 102100COILVP DAHS GREAT DAHS SYSTEMS 222X
51010 102AE1ANOX P DAHS GREAT DAHS SYSTEMS 222X
19980701
19980701
19980701
19980701
20010401
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Example for Case 10: EDR Changes for an Oil Unit using Unit Specific Defaults with Appendix D
RT520
OTC
SUBH
RT531
OTC
SUBH
RT535
OTC
SUBH
RT540
OTC
SUBH
RT560
SUBH
RT585
OTC
SUBH
Marked Unit Specific Default NOXM formula for deletion. Added new formula to reference
Appendix E system.
52010 U102HI F-19VHIO (mmbtu/hr) = S# (101-100) * (Gross_calorif ic_value_oil / 10**6)
52010 U110NOXMF-10ANOXM= UDEF NOX * F#(102) * optima
52010 U102HI F-19VHIO (mmbtu/hr) = S# (101-100) * (Gross calorific value oil / 10**6)
52010 D110NOXMF-10ANOXM= UDEF NOX * F#(102) * optima
52010 AAE1NOXMF-24 NOXM= S#(102-AE1) * F#(102)* Unit op time
Deactivated all previous defaults
53110 NOXG 1 .200LBMMBTUMD DSLUNBP 1998070100
53110 NOXU 0 .305LBMMBTUPM DSLCTEST1998070101
53110 OILV 2424 .OOOGALHR MD DSLADES 1998070100
53110 NOXG 1.200LBMMBTUMD DSLUNBP 19980701002001093023
53110 NOXU 0.305LBMMBTUPM DSLCTEST19980701012001093023
53110 OILV 2424 .OOOGALHR MD DSLADES 19980701002001093023
Designated Normal load field should be left blank in EDR v2.1
53510 MW 29H
53510 MW 29
Initial Calibration Method Codes Added to EDR v2.1
54010 100OILVDSL 2424 . OGALHRUMXISO 8316 A
54010 100OILVDSL 2424 . OGALHRUMXILMM A
Appendix E Correlation Curve Records Added
56010 20020214 1 OSG1AE1 0.0 80.0 0.270 0.270DSL
56010 20010224 2 1SG2AE1 80.0 163.2 0.270 0.254DSL
56010 20010224 3 2SG3AE1 163.2 244.7 0.254 0.301DSL
56010 20010224 4 3SG4AE1 244.7 351.2 0.301 0.311DSL
Added Appendix E methodology. Deactivated NOXR UDEF methodology. Also note code changes.
58510 HI OFF DSLPLOAD 19980701
58510 NOXRUDEF DSLPDEF 19980701
58510 HI OFF DSLPSPTS 19980701
58510 NOXRAE DSLPNA 20020501
58510 NOXRUDEF DSLPDEF 1998070120010930
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Example for Case 10: EDR Changes for an Oil Unit using Unit Specific Defaults with Appendix D
RT586
OTC/SUBH
RT587
OTC/SUBH
No Changes
58610 NOX H2O PO
No Changes
58710 DSL19980701 P
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Case 11
Section 3: Oil/Gas-fired Units
Case 11
Unit Specific or Generic NOX Default Rate with
Alternative or Maximum Heat Input or Long Term Fuel Flow
Methodology
Changes
EDR
Monitoring Plan
Changes
None of these OTC methods are permitted by Part 75 for non-LME units.
If your unit qualifies as a peaking unit, you may use Appendix E. If your
unit does not qualify as a peaking unit, you must install a NOX emission
rate CEM system. For heat input, you could install a stack flow monitor
to use in conjunction with a diluent monitor, but this case assumes that
you will elect to install an Appendix D fuel flow monitoring system to
determine heat input. (If you are using maximum heat input rate only for
an emergency fuel, see the Acid Rain Program Policy Manual, Question
25.10 and RT 587 changes described in Appendix A of this document.)
You will have to add some record types and you will have to deactivate
and delete others. One key step you must take is to delete the existing
RT 505 for NBP and define a new RT 505 for OTC-SUBH to identify
the date when your unit begins complying with Subpart H requirements.
You should add this RT 505 first before making other changes if you are
using the Monitoring Data Checking (MDC) software program to make
the changes.
Appendix E
(Peaking Unit)
RT507
RT510
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
the RT 505 for NBP.
our \
new I
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The following sections describe the other specific changes you will have
to make to a number of monitoring plan record types to reflect the
monitoring changes you are making to convert to Part 75, Subpart H
monitoring.
If you qualify for and elect to use the Appendix E correlation method to
determine NOX emission rate, make the following changes (and the
changes listed for Appendix D below):
Add: With the appropriate peaking qualification information.
Add: A new Appendix E NOX system for each correlation curve to be
established. If you are testing each fuel separately, define a system for
each fuel burned (oil and/or gas). Each Appendix E system should be
comprised of the DAHS software component only.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 57
-------
Section 3: Oil/Gas-fired Units
Case 11
RT520
Add: A NOxmass formula (code F-24) which references the NOX
emission rate from Appendix E curve and the total heat input rate
formula.
RT530
RT531
RT535
RT560
RT585
NOX Emission
Rate CEM
(Non-Peaking
Unit)
RT510
RT520
Deactivate: The NOxmass formula that references the unit specific or
generic default.
Add: Record to define maximum NOX emission rate for gas and/or oil
(parameter GNOX or ONOX). See EDR v2.1 Instructions.
Deactivate: Unit specific or generic default NOX rate values.
Add: (If not already present) to report load information, as required for
any CEMS methodology
Add: For each Appendix E system when testing has been completed.
Add: A methodology record for parameter NOX rate (code NOXR in col.
10), Methodology Appendix E (code AE, in col. 14), and for the
appropriate fuel type (col. 24).
Deactivate: The previously record for NOX rate (for either UDEF or
GDEF methodology).
If you must or elect to use a NOX emission rate CEM system, make the
following changes (and the changes listed for Appendix D below):
Add (1): The new NOX rate system (comprised of the NOX concentration
monitor, the diluent monitor and the DAHS software component). Make
certain to use a dual range analyzer if necessary. If you elect to use the
default high range provisions of Part 75, use component type NOXL for
your single scale NOX monitor
Add (2): If moisture correction is required, define an H2O system
comprised of wet and dry O2 components (or a moisture sensor) and the
DAHS software.
Add (1): A new NOX emission rate formula which references the newly
defined NOX system. Use Table 15: Heat Input Formula Reference
Table in the EDR v2.1 Instructions to determine the correct formula for
your monitoring situation it depends on diluent monitor type (CO2 or
O2) and whether you sample on a wet or dry basis.
Add (2): An H2O formula, if you defined an H2O system with wet and
dry O2 components.
Page 58
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case 11 Section 3; Oil/Gas-fired Units
Add (3): A NOxmass formula (code F-24) which references the NOX
emission rate formula and the total hourly heat input rate formula.
Deactivate: The NOX mass formula that references the unit specific or
generic NOX default.
RT 530 Add: A span record for NOX concentration and the diluent. Make
certain to add both low and high scale NOX records if you have dual
ranges or are using the default high scale range provisions.
RT 531 Add (1): If you intend to use the diluent cap provisions, a record to
define the appropriate diluent cap value for this unit (see EDR v2.1
Instructions for RT 531).
Add (2): If you have a moisture system, define the minimum or
maximum %H2O for missing data purposes (see § 75.37(b)).
Deactivate (1): Unit specific or generic default NOX rate values.
Deactivate (2): Maximum fuel flow records.
RT 535 Add: (If not already present) to report load information, as required for
any CEMS methodology.
RT585 Add (1): A record for NOX rate (code NOXR in col. 10), Methodology
Continuous Emissions Monitoring (code CEM in col. 14), and fuel type
non fuel-specific (code NFS in col. 24).
Add (2): If moisture correction is required, a record for moisture
(parameter H2O).
Change End Date: In the previously defined RT 585 for heat input (for
either UDEF or GDEF methodology) report for one quarter with the
appropriate Methodology End Date (col. 42).
Appendix D If you elect to use Appendix D fuel flow monitoring to determine heat
input, make the following changes:
RT 510 Add: A new fuel flow system for each fuel burned (oil and/ or gas). The
fuel flow system should be comprised of (at a minimum) one fuel flow
monitor and the DAHS software component. The parameter reported for
the fuel flow system should be OILM, OILV or GAS, depending on the
fuel being measured and the basis for measurement (OILM is mass,
OILV is volume).
Deactivate: The Alternative Heat Input System that was defined for
OTC monitoring, if any.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001 Page 59
-------
Section 3: Oil/Gas-fired Units
Case 11
RT520
RT531
RT535
RT540
RT585
General EDR
Changes
Case 11
Example Unit
Add (1): Formulas for heat input rate from each fuel flowmeter system.
If you determine net fuel flow by summing or taking the difference
between multiple fuel flow meters, add the appropriate FGAS or FOIL
formula to calculate the net or total hourly fuel flow rate. If you burn
multiple fuels, also add the code D-15A formula to calculate the total
hourly heat input rate from combined fuels. Please see the appropriate
reference tables in the EDR v2.1 Instructions to determine the correct
formula for your monitoring situation.
Deactivate : The long term fuel flow apportionment formula(s), if any.
Deactivate: The records for maximum heat input or maximum fuel
flow.
Add: This record to support the load-based missing data procedures for
Appendix D fuel flow metering.
Add: This record for each fuel flowmeter system. Do not report this
record to report data on individual components. Report one RT 540 for
each GAS, OILV or OILM system in RT 510, except when a system is
made up of multiple fuel flowmeters using different methods of
calibration. In this situation, report multiple RTs 540 for the system
indicating the calibration method for each flowmeter (col. 38) in the
subsequent records (all information in other fields of the multiple RTs
540 will be identical).
Add: Methodology record(s) for parameter Heat Input (code HI in col.
10), Methodology Gas Fuel Flow or Oil Fuel Flow (codes GFF or OFF,
respectively, in col. 14), and for the appropriate fuel type (col. 24).
You will have to make general EDR changes (additional/discontinued
fields, additional/discontinued record types, changed codes) to convert
your monitoring plan to EDR v2.1 format see Appendix A, Changes
for All Units, and consult the EDR v2.1 Instructions for further
information on the following record types:
! RTs 503, 504, 505, 506, 508, 510, 520, 530, 531, 535, 536, 540,
555, 556, 585 and 587.
Example Unit 11 is a Diesel fired Combustion Turbine. For the OTC
NBP, this unit has been using Unit Specific NOX rate with long term fuel
flow monitoring to determine NOX mass. However, this Unit no longer
qualifies to use either the Unit Specific NOX rate default or the long term
fuel flow methodologies. However, since this unit is a peaking unit, the
facility is using Appendix E NOX monitoring with Appendix D fuel flow
monitoring to determine NOX mass. The attached comparison shows the
changes made for each record type.
Page 60
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Example for Case 11: EDR Changes for an Oil Unit using
Unit Specific Default with Long Term Fuel Flow
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RT100
OTC
SUBH
RT102
OTC/SUBH
RT504
OTC
SUBH
RT505
OTC
SUBH
RT506
SUBH
RT507
OTC
SUBH
RT510
OTC
SUBH
EDR Version Changed from V2.0 to V2.1. Reporting Quarter and Year Changed.
10011000022001V2 .0
10011000022002V2.1
No Changes
102CASE 11 ELECTRIC UTILITY 4911CT009 411733 724739
Fields Added in v2.1
50411 CT 378.019690722
50411 CT 378.019690722 240 12 120
New record reported for Subpart H Participation beginning on 5/1/2002
50511 NBP B OS1999050122A-174 CT
50511 OTC-SUBH B OS20020501 CT
New record type in EDR v2.1
50611 11 11 11 1976 110000110000
New Peaking Qualification Data for 2002
50711 20011998A 9.11999A 7.82000A 7.1 8.0PK
50711 20021999A 6.62000A 9.22001A 7.8 7.9SK3HD
Added Appendix D and E systems. Updated DAHS version. Deactivated LTOL system.
51011 D11101ULTOLP DAHS PERFECT DATA, INC. PDI-457 19990501
51011 D11101DLTOLP DAHS PERFECT DATA, INC. PDI-880 1999050120010930
51011 D11202ANOX P DAHS PERFECT DATA, INC. PDI-880 20020501
51011 104204AOILVP OFFMPDPMEASUREOIL MDF-540 904400001 20020501
51011 D11204AOILVP DAHS PERFECT DATA, INC. PDI-880 20020501
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Example for Case 11: EDR Changes for an Oil Unit using
Unit Specific Default with Long Term Fuel Flow
RT520
OTC
SUBH
RT530
SUBH
RT531
OTC
SUBH
RT535
SUBH
RT536
SUBH
RT540
SUBH
RT560
SUBH
All previous formulas marked for deletion. New formulas added to reference Appendix D and E
systems.
52011 U101HVOFF-15AS# (Dll-101) * (MWh/MWt)
52011 U102HI F-19VF# (101) * (GCVo/1000000)
52011 U103NOXMF-10AHourly NOx mass = (F# ( 102 ) ) *NOx unit specific default emission rate * T_10
52011 D101HVOFF-15AS# (Dll-101) * (MWh/MWt)
52011 D102HI F-19VF# (101) * (GCVo/1000000)
52011 D103NOXMF-10AHourly NOx mass = (F# ( 102 ) ) *NOx unit specific default emission rate * T 10
52011 A105HI F-19VHI= S# (104 -204) * (GCVo/1000000)
52011 A201NOXMF-24 NOXM= S#(D11-202) * F#(105) * op time
Added record to define NOX MER for Appendix E
53011 ONOX 200.000 0.392 02050100
Deactivated all records.
53111 NOXG 1 .200LBMMBTUMD DSLANBP 1999050100
53111 NOXU 0 .740LBMMBTUPM DSLATEST1999050100
53111 OILV 1800 .OOOGALHR MD DSLADES 1999050100
53111 NOXG 1.200LBMMBTUMD DSLANBP 19990501002001093023
53111 NOXU 0.740LBMMBTUPM DSLATEST19990501002001109303
53111 OILV 1800. OOOGALHR MD DSLADES 19990501002001109303
Added record to support Appendix D Fuel Flow metering
53511 MW 36
Added record to support quarterly fuel-flow-to-load analysis for Appendix D Fuel Flow metering
53611 36 11
Added record to support Appendix D Fuel Flow metering
54011 2040ILVDSL 9784 . OGALHRUMXAPI A
Added Appendix E Correlation Curve Records
56011 20020402 1 0001202 0.0 85.0 0.271 0.271DSL
56011 20020402 1 1002202 85.0 178.3 0.271 0.332DSL
56011 20020402 1 2003202 178.3 265.8 0.332 0.340DSL
56011 20020402 1 3004202 265.8 351.7 0.340 0.316DSL
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Example for Case 11: EDR Changes for an Oil Unit using
Unit Specific Default with Long Term Fuel Flow
n
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RT585
OTC
SUBH
RT587
OTC/SUBH
Added Appendix D
58511 HI LTOF
58511 NOXRUDEF
58511 HI LTOF
58511 HI OFF
58511 NOXRAE
58511 NOXRUDEF
and E methodologies. Deactivated
DSLPDEF
DSLPDEF
DSLPDEF
DSLPSPTS
DSLPSPTS
DSLPDEF
19990501
19990501
1999050120010930
20010501
20020501
1999050120010930
NOXR UDEF and LTOF methodologies.
No Changes
58711 DSL19990501
P
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Section 3: Oil/Gas-fired Units
[This page intentionally left blank.]
Page 64 Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
SECTION 4: OIL- AND GAS-FIRED LOW MASS
EMISSIONS (LME) UNITS
See Table 4-1 for a summary of issues to consider if you qualify as a Low Mass Emissions
(LME) Unit. Then go to the detailed discussion of Case 12 in this section to determine
the changes you need to make.
Monitoring
Methodology
Changes
Unit-Specific
NOX Emission
Rates
Generation of
Quarterly Data
Files using MDC
For an oil or gas fired unit not affected under the Acid Rain program, a
Low Mass Emissions (LME) unit under §75.70 is one with actual and
calculated potential annual NOX emissions < 50 tons (or if the unit is
reporting only on an ozone season basis, ozone NOX emissions < 25 tons)
(see § 75.19 and § 75.74 (c)(10)).
If your unit qualifies as an LME Unit, you are eligible to use unit or fuel
specific or generic defaults to determine NOxrate, and either maximum
rated hourly heat input (in mmBtu) or heat input calculated from a long
term fuel flow method (including data on volume, specific gravity, and
GCV of fuel(s) combusted).
The LME methodology must account for all emissions during an ozone
season. Therefore you may not switch between a different methodology
and the LME method during the ozone season.
§ 75.19(c)(l)(iv)(A) specifies that a four-load NOX emission rate test is
required to establish a unit-specific NOX emission rate value (see Part 75,
Appendix E, Section 2.1). Also a multiplier of 1.15 must be applied to
fuel-specific, unit-specific default NOX emission rates (or the minimum
rate of 0.15 Ib/mmBtu must be used, if that is higher than the tested rate
times 1.15). EPA has proposed changes to §75.19 which would remove
the 1.15 multiplier for most units and allow testing at fewer than four
loads. However, until that rule is promulgated, the four-load test and
multiplier must be used. Check with your State contact to determine the
status of those proposed revisions, especially if you are already using a
unit-specific NOX rate.
LME Monitoring Plan Submission Requirements for both electronic and
hardcopy submissions are available in §75.53(f)(5).
The Monitoring Data Checking (MDC) Software has an option which
allows you to create a report for a specific quarter and year for a
particular LME Unit.
The report is generated based on the operating periods, long term fuel
flow and load data (if necessary) and monitoring plan default values.
The file is displayed in a preview window and can be saved to a user-
defined filename and file location. The file will contain the applicable
record types from the following list:
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 65
-------
Section 4: LME Oil/Gas-fired Units
RT 100
RT305
RT307
RT360
RTs 500+
RT645
RT624
RTs 627- 630
RTs 900+
Facility Identification
Heat Input from Long Term Fuel Flow Measurements
Cumulative NOX Mass Emissions (Subpart H Only)
Hourly Emissions Data for Qualifying Low Mass
Emissions
Monitoring Plan Data Stored in MDC for the Unit
LME Qualifying Data for the same year as the EDR
year.
Miscellaneous QA Tests
Fuel Flowmeter Certifications Data
Compliance and Certification Data
Please see the MDC Helpfile for a more detailed description of the
process and the resulting file. (From Help on the main menu, go to
Contents> LME> LME EDR File Report.)
Table 4-1: Summary Comparison of LME NOX and Heat Input Monitoring Methodologies
in the OTC and Federal NOX Budget Programs for LME Oil and Gas Fuel Fired Units
Unit
Type
Oil or Gas
Low Mass
Emissions
(LME)
Unit
Current OTC Monitoring Method
NOX
A Unit can qualify as
LME, regardless of the
Current Methodology.
However, the majority
of LME Units are
expected to be Units
already using Unit
Specific or Generic
Default NOX Emission
Rates.
Heat Input
A Unit can qualify as
LME, regardless of the
Current Methodology.
However, the majority
of LME Units are
expected to be Units
already using Long
Term Fuel Flow,
Maximum Hourly Heat
Input or an Alternative
monitoring method.
Change Required for
Subpart H Monitoring?
If a Unit qualifies as LME (actual or
potential annual NOX emissions < 50 tons
annually, or < 25 tons if ozone season
reporting only), then the Unit may use unit
or fuel specific or generic defaults to
determine NOX rate, and either maximum
rated hourly heat input or long term fuel
flow to determine heat input. See § 75.19
and § 75.74 (c)(10) for qualification and
reporting requirements.
Currently, Part 75 requires that a Unit-
specific NOX rate be determined from a 4-
load Appendix E test and that a multiplier
of 1.15 be applied to the resulting emission
rate. Proposed revisions would change
both of these requirements.
Case
#
12
Page 66
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Case 12
Section 4: LME Oil/Gas-fired Units
Case 12
LME Unit Using NOX Unit Specific Default with Long Term Fuel Flow Heat
Input Monitoring
Methodology
Changes
EDR
Monitoring Plan
Changes
If a Unit qualifies as LME (actual or potential annual NOX emissions <
50 tons annually, or < 25 tons if ozone season reporting only), then the
Unit may use unit or fuel specific or generic defaults to determine NOX
rate, and either maximum rated hourly heat input or long term fuel flow
to determine heat input. See § 75.19 and § 75.74 (c)(10) for qualification
and reporting requirements.
A Unit can qualify as LME, regardless of the Current Methodology.
However, the majority of LME Units are expected to be Units already
using Unit Specific or Generic Defaults for NOX rate and Long Term
Fuel Flow, Maximum Hourly Heat Input or an Alternative monitoring
method to determine Heat Input.
You will have to add some record types and you will have to deactivate
and delete others. One key step you must take is to delete the existing
RT 505 for NBP and define a new RT 505 for OTC-SUBH to identify
the date when your unit begins complying with Subpart H requirements.
You should add this RT 505 first before making other changes if you are
using the Monitoring Data Checking (MDC) software program to make
the changes.
RT507
Note! If you use MDC to change your
monitoring plan RTs, first define a
RT 505 for OTC-SUBH and remove
the RTS05for NBP.
our \
new I
J
The following sections describe the other specific changes you will have
to make to a number of monitoring plan record types to reflect the
monitoring changes you are making to convert to Part 75, Subpart H
monitoring.
Remove: Do not report RT 507 for LME Units. If you previously
reported, do not include in the EDR once LME methodologies are being
used.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 67
-------
Section 4; LME Oil/Gas-fired Units Case 12
RT 510 Add: If applicable, add a long term gas or oil fuel flow system. Each
long term fuel flow system should include DAHS software and the
Appendix D, billing fuel flowmeter or other relevant components.
Deactivate: Any NOX rate or Heat Input system.
RT 520 Deactivate: All formulas. (It is not necessary to report formulas for
LME Units.)
RT 530 Deactivate: All span records, if any.
RT 531 Add: Record to define the appropriate LME default value, e.g.. Generic
NOX emissions rates (Ib/mmBtu), Fuel and Unit Specific NOX emission
rate, and maximum hourly rated heat input rate (mmBtu/hr). See the
EDR v2.1 Instructions for the appropriate LME codes.
Deactivate: Any previously defined values reported in RT 531 unless
they were generic default values that are still applicable. (Unit-specific
NOX rates from testing may still be valid for your unit if the proposed
revisions to Part 75 have been promulgated, but check with your State
before making this assumption.)
RT535 Remove: Do not report RT 535 for LME Units.
RT 540 Add: For each long term fuel flow system, report RT 540 information.
(This record is needed because maximum fuel flow is no longer defined
in RT 531.) Do not report this record to report data on individual
components. Report one RT 540 for each GAS, OILV or OILM system
in RT 510, except when a system is made up of multiple fuel flowmeters
using different methods of calibration. In this situation, report multiple
RTs 540 for the system indicating the calibration method for each
flowmeter (col. 38) in the subsequent records (all information in other
fields of the multiple RTs 540 will be identical).
RT 560 Remove: Do not report RT 560 for LME Units, even if an Appendix E
NOX emissions correlation curve was previously defined.
RT 585 Add: A methodology record for parameter Heat Input (code HI in col.
10) and NOX emissions rate (code NOXR in col. 10). See the EDR v2.1
Instructions for the appropriate LME codes.
Update: The codes in existing method records for defaults and/or long
term fuel flow if you are still using those methods under the LME
provisions.
Deactivate: The previously defined records for heat input and NOX
unless they were long term fuel flow and defaults and you are still using
them.
Page 68 Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001
-------
Case 12 Section 4; LME Oil/Gas-fired Units
RT 645 Add: This record to demonstrate qualification to use the LME
provisions.
General EDR You will have to make general EDR changes (additional/discontinued
Changes fields, additional/ discontinued record types, changed codes) for certain
record types. See Appendix A to this document, and consult the EDR
v2.1 Instructions for further information, on the following record types:
! RTs 504, 505, 506, 508, 510, 531, 540, and 585
Case 12 Example Unit 12 is a Diesel and gas-fired unit. For the OTC NBP, this
Example Unit unit has been using a Unit Specific NOX rate combined with long term
fuel flow heat input determination to calculate NOX mass. Since the unit
qualifies as an LME unit and is still eligible to use defaults and long term
fuel flow, the facility has decided to use generic default values and long
term heat input under Subpart H. The attached comparison shows the
changes made for each record type.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001 Page 69
-------
Example for Case 12: EDR Changes for a Unit that Qualifies as an LME Unit
RT100
OTC
SUBH
RT102
OTC/SUBH
RT504
OTC
SUBH
RT505
OTC
SUBH
RT506
SUBH
RT507
OTC
RT510
OTC
SUBH
EDR Version Changed from V2.0 to V2.1. Reporting Quarter and Year Changed
10012000022001V2 .0
10012000022002V2.1
No Changes
102LME CASE ELECTRIC UTILITY 4911NJ029
395100 741200
Fields Added in v2.1
504LME CT 500.019890101
504LME CT 500.019890101 175 12 153
New record reported for Subpart H Participation beginning on 5/1/2002
505LME NBP B OS19980701NJAC727-31NJ
505LME OTC-SUBH B OS20020501 NJ
New record type in EDR v2.1. Required for all units.
506LME LME LME LME 1989 120000120000
No New Peaking Qualification Data for 2002, Unnecessary for LME Qualification
507LME 20011998A 2.31999A 2.52000A 6.0 3.6PK
Updated DAHS version.
510LME 120FAOULTOLP DAHS PERFECT DATA, INC. PD1-1000
510LME M51FAOULTOLP BOFFPDPMEASURERIGHT
510LME 120FA1ULTGSP DAHS PERFECT DATA, INC. PD1-1000
510LME FA1FA1ULTGSP BGFFTURMETERIT
510LME 120FAOCLTOLP DAHS PERFECT DATA, INC. LME PERFECT 11
510LME M51FAOULTOLP BOFFPDPMEASURERIGHT
510LME 120FA1CLTGSP DAHS PERFECT DATA, INC. LME PERFECT 11
510LME FA1FA1ULTGSP BGFFTURMETERIT
19980701
19980701
19980701
19980701
19980701
19980701
19980701
19980701
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Example for Case 12: EDR Changes for a Unit that Qualifies as an LME Unit
RT520
OTC
SUBH
RT531
OTC
SUBH
RT540
OTC
SUBH
All previous formulas marked for deletion.
520LME
520LME
520LME
520LME
520LME
520LME
520LME
520LME
520LME
520LME
520LME
520LME
520LME
520LME
UFAOHVOFF-15AHVOF = S# (M51-FAO) * GMW DIE / LT GMW DIE
UFA1HI F-19VHI DIE = F#(FAO) * GCV DIE / 10**6
UFA2NOXMF-10ANOX MASS DIE = F#(FA1) * NOX RATE DIE
UFA5HGASF-15AHGAS = S#(FA1-FA1) * GMW GAS / LT GMW GAS
UFA6HI F-20 HI GAS = F#(FA5) * GCV GAS / 10**6
UFA7NOXMF-10ANOX MASS GAS = F#(FA6) * NOX RATE GAS
UFA8NOXMN-3 NOX MASS TOT = F#(FA2) + F#(FA7)
DFAOHVOFF-15AHVOF = S#(M51-FAO) * GMW_DIE / LT_GMW_DIE
DFA1HI F-19VHI DIE = F#(FAO) * GCV DIE / 10**6
DFA2NOXMF-10ANOX MASS DIE = F#(FA1) * NOX RATE DIE
DFA5HGASF-15AHGAS = S#(FA1-FA1) * GMW GAS / LT GMW GAS
DFA6HI F-20 HI GAS = F#(FA5) * GCV GAS / 10**6
DFA7NOXMF-10ANOX MASS GAS = F#(FA6) * NOX RATE GAS
DFA8NOXMN-3 NOX_MASS_TOT = F#(FA2) + F#(FA7)
Deactivated some previously reported records. New LME default values added.
531LME
531LME
531LME
531LME
531LME
531LME
531LME
531LME
531LME
531LME
531LME
531LME
531LME
531LME
GAS 4878.000HSCF MD PNGADES 1998070100
NOXG 1.200LBMMBTUMD DSLUNBP 1998070100
NOXG 0.700LBMMBTUMD PNGUNBP 1998070100
NOXU 0.206LBMMBTUPM DSLCTEST1998070800
NOXU 0.122LBMMBTUPM PNGCTEST1998070800
OILV 3597.100GALHR MD DSLADES 1998070100
GAS 4878.000HSCF MD PNGADES 19980701002001093023
NOXG 1 .200LBMMBTULM DSLULME 1998070100
NOXG 0 .700LBMMBTULM PNGULME 1998070100
NOXU 0.237LBMMBTULM DSLCTEST2002050100
NOXU 0.150LBMMBTULM PNGCTEST2002050100
NOXU 0 .206LBMMBTUPM DSLCTEST19980701002001093023
NOXU 0 .122LBMMBTUPM PNGCTEST19980701002001093023
OILV 3597 .100GALHR MD DSLADES 19980701002001093023
Previously defined Initial Method of Calibration Removed
540LME
540LME
540LME
540LME
FAOOILVDSL 6000 . OGALHRURVNIST #40971 U
FA1GAS PNG 36000. OHSCF URVMFC-4M- 1986 U
FAOOILVDSL 6000 . OGALHRURV C
FA1GAS PNG 3 6 000. OHSCF URV C
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Example for Case 12: EDR Changes for a Unit that Qualifies as an LME Unit
RT585
OTC
SUBH
RT586
OTC/ SUBH
RT587
OTC/SUBH
RT645
SUBH
Codes Changed
585LME HI LTGF PNGPDEF
585LME HI LTOF DSLPDEF
585LME NOXRUDEF DSLPDEF
585LME NOXRUDEF PNGPDEF
585LME HI LTFF DSLPNA
585LME HI LTFF PNGPNA
585LME NOXRNOXU DSLPNA
585LME NOXRNOXU PNGPNA
19980701
19980701
19980701
19980701
19980701
19980701
19980701
19980701
No Changes
586LME NOX H2O P 19890601
No Changes
587LME DSL19980701 P
587LME PNG19980701 S
Added for LME qualification
645LME 20020S1999 9.314.7 0.0
0.0 932000 7.313.5 0.0 0.0 88200112.518.2 0.0 0.0 121
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Purpose of This
Section
SECTION 5: COMPARISON OF OTC AND
SUBPART H REQUIREMENTS
This section provides side by side comparison summaries of OTC and
Subpart H monitoring and quality assurance requirements in instances
where the requirements are different. OTC monitoring requirements in
the Guidance for Implementation of Emission Monitoring Requirements
for the NOX Budget Program, dated January 28, 1997, referenced Part 75
requirements (November 20, 1996) for units not subject to the Acid Rain
Program. Part 75, however, has been revised since the 1997 guidelines
were issued (revisions were promulgated on October 27, 1998 (63 FR
57356) and May 26, 1999 (64 FR 28564)).
Note! Although this document provides
brief summaries of current Subpart H rule
provisions, you need to review carefully
the actual rule text to transition
successfully from OTC to Subpart H
monitoring.
Monitoring
Requirements/
Options
The following tables compare OTC and Subpart H monitoring
requirements and options. An index to the tables and monitoring
requirements/options is provided below:
! Table 5-1: Units Using NOX CEMS:
- MFC, MEC, Span and Range Requirements
- Full Scale or High Range Exceedances
- Fuel Specific Moisture Default Option
- Maximum Heat Input Option
- Bypass Stacks
- Like-Kind Replacement Analyzers
! Table 5-2: Missing Data Substitution:
-NOX
- Flow
- Diluent and Heat Input
- Moisture
- Fuel Flow
! Table 5-3: Appendix D Fuel Flow:
- Oil Sampling for Fuel GCV and Density
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 73
-------
Section 5; Comparison of OTC and Subpart H Requirements
! Table 5-4: Default NOX Rates/Low Mass Emissions:
- Default NOX Rate Options
- Maximum Heat Input Option
- Long Term Fuel Flow Option
- Alternative Heat Input Method
Table 5-1: Units Using NOX CEM System
Requirement/
Option
OTC
Subpart H
NOXMPC
Uncontrolled
Units
The OTC guidelines provided three options for
determining the MFC for an uncontrolled unit:
1. A default value from Tables 2-1 and 2-2 of
Appendix A.
2. A minimum of 30 days of historical CEM
data representing various operating
conditions.
3. Reference method test results at various
operating conditions.
Appendix A similarly provides three options,
but with a few differences for 1 and 2:
1. A default value from Tables 2-1 and 2-2 or
use 400 ppm for oil/gas units or 800 ppm for
coal units.
2. A minimum of 720 hours of historic CEM
operating hours when combusting the fuel or
blend with the highest NOX emission rate.
3. Reference method test results at various
operating conditions.
(App. A, §2.1.2.1)
NOX MFC for
Controlled Units
For a controlled unit the MFC was determined
using the values in Tables 2-1 and 2-2 of
Appendix A.
In Appendix A the MFC for a controlled unit is
determined in the same manner as for
uncontrolled units except that if reference
method testing or historic data options are used
the data collected must represent uncontrolled
operation. (App. A., § 2.1.2.1)
NOX MEC for
Controlled Units
The OTC guidelines provided three options for
determining the MEC of a controlled unit:
1. Percent Reduction Equation
2. A minimum of 30 days of historical CEM
data representing various operating
conditions.
3. Reference method test results based on tests
performed at various loads, and operate at
the highest excess O2 level expected under
normal operating conditions.
In Appendix A, a separate MEC determination
is required for each fuel.
There are three options which include using
1. Equation A-2, which is similar to the Percent
Reduction Equation,
2. Using historical CEM data. Reference
method testing is to be done at various loads
and while control equipment operations are
stable. If historic data is used, a minimum of
720 hours of historic CEM operating hours
during stable operation under various loads
is required, or
3. Reference method testing.
(App. A, §2.1.2.2)
(cont.)
Page 74
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Section 5; Comparison of OTC and Subpart H Requirements
Table 5-1: Units Using NOX CEM System (cont.)
Requirement/
Option
OTC
Subpart H
NOX Monitor
Span and Range
for Controlled
Units
Under OTC the span for a unit was set at a
value between 100% and 125% of the MEC.
The range was set such that it was equal to or
greater than 125% of the MEC, and the
majority of measured values are within 20 -
80% of the range. A dual range monitor was
required if the low range was exceeded more
than 72 hours in an ozone season.
In Appendix A, the "high" span value is set
between 100% and 125% of the MFC. The
high range is set such that the reading are kept,
to the extent practicable, between 20% and
80% of full-scale range of the instrument.
The MEC is then compared to the high range
value. If the MEC values for all fuels are
> 20.0 percent of the high range value, the high
span and range values are sufficient. If any of
the MEC values is < 20.0 percent of the high
range value, two spans (low and high) are
required, one based on the MFC and the other
based on the MEC.
(App. A, §§2.1.2.3 and 2.1.2.4)
Annual Monitor
MFC, MEC,
Span and Range
Evaluation
The OTC guidelines do not require annual
span and range evaluations.
In Appendix A, the span and range is to be
evaluated each year, at a minimum, and the
span and range are to be changed if the
majority of emissions over the year are not
within 20% - 80% of monitor range (with
certain exceptions).
(App. A, §§2.1.2.5 and 2.1)
Full Scale or
High Range
Exceedance
For an uncontrolled unit, if not due to fuel
switching, report a NOX concentration equal to
150% of the full scale range for every hour,
and adjust the instrument range.
For an uncontrolled unit, if due to fuel
switching, or a controlled unit due to control
equipment operation, report the MFC for the
hour based on Tables 2-1 and 2-2 of Appendix
A.
If the full scale range was exceeded for 72
hours or more during an ozone season, install
an additional high range analyzer.
Under Appendix A, for exceedances of the
high full scale range, report 200.0 percent of
the current full-scale range as the hourly NOX
concentration for each hour of the full-scale
exceedance and make appropriate adjustments
to the MFC, span, and range to prevent future
full-scale exceedances.
(App. A, §2.1.2.5)
Fuel Specific
Moisture
Default Option
Documented moisture default constants
allowed in place of an hourly moisture
measurement, if burning oil and/or gas.
Appendix A allows specific moisture defaults
for coal and wood (but not for oil and gas) in
place of an hourly moisture measurement.
(§§75.71(b)and75.11(b)(l))
(cont.)
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 75
-------
Section 5; Comparison of OTC and Subpart H Requirements
Table 5-1: Units Using NOX CEM System (cont.)
Requirement/
Option
OTC
Subpart H
Maximum Heat
Input Option
OTC allowed a source to petition the State
regulatory agency to use a unit-specific
maximum hourly heat input to calculate NOX
mass based on the higher of the manufacturer's
maximum rated capacity, or the highest
observed hourly heat input in the past five
years.
Under Subpart H, the use of maximum heat
input to determine NOX mass emission rate is
only allowed for Low Mass Emissions units.
(§§75.70 and 75.19)
Bypass Stacks
Under the OTC guidelines a unit may either
install a NOX CEM in each stack, or install a
NOX CEM in the main stack, and use the
maximum NOX emission rate for the bypass
stack emissions.
Subpart H provides two options for NOX
emissions from bypass stacks at units requiring
a NOX CEMS. A unit can either use a CEMS
on the bypass stack or perform reference
method monitoring. Currently there is no
provision in the rule for the use of maximum
default values for bypass stack hours, although
EPA does allow this through policy guidance
and on 6/13/01 proposed to add it to Part 75 .
(§ 75.72(c), ARP Policy Manual, Q 17.6, June
13, 2001 Federal Register).
Like-kind
Replacement
Analyzers
Like-kind replacement analyzers are not
specified in OTC monitoring guidelines.
Subpart H provides an additional back-up
monitoring alternative, for up to 720 hours per
year like-kind replacement analyzers (same
make and model as the primary analyzer and
connected to the same probe and interface as
the primary analyzer).
(§ 75.20(d)(2))
Table 5-2: Missing Data Substitution
Requirement/
Option
OTC
Subpart H
Missing Data
Procedures for
NOX Emission
Rate or
Concentration
CEM
The OTC guidance document allowed using
the Part 75 missing data substitution provisions
or substituting the maximum potential NOX
emission rate (MER) or maximum potential
NOX concentration (MFC) for every missing
data hour. In addition, the OTC questions and
answers provided additional guidance allowing
use of fuel-specific and control-status specific
MER and MFC values either as the default for
every missing data hour or as part of the Part
75 substitution algorithm when the MER or
MFC was required.
Subpart H requires use of the Part 75 missing
data procedures, which are load-based for NOX
emission rate. On 6/13/01, EPA proposed to
revise Part 75 to add fuel-specific and control-
status-specific missing data substitution.
(§ 75.33)
(June 13, 2001 Federal Register)
(cont.)
Page 76
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Section 5; Comparison of OTC and Subpart H Requirements
Table 5-2: Missing Data Substitution (cont.)
Requirement/
Option
OTC
Subpart H
Missing Data
Procedures for
Stack Flow
The OTC guidance document allowed using
the Part 75 missing data substitution provisions
or substituting the maximum Potential Flow
rate (MPF) for every missing data hour.
Subpart H requires use of the Part 75 missing
data procedures for flow.
(§ 75.33)
Missing Data
Procedures for
CO2> O2, CEMs
and Heat Input
For missing data reporting for CO2 or O2 used
for heat input calculations, the OTC guidelines
provide a choice between using the maximum
CO2% or minimum O2% defined in the
monitoring plan or basing the substitute value
on the amount of quality assured data and
whether availability is less than 90%.
The missing data provisions in Subpart H for
CO2 and O2 used for heat input are also based
on the amount of quality assured data and
availability, but also the length of the missing
data period. There are no provisions for
simply using the maximum CO2% or minimum
O2% in the unit's monitoring plan. For the first
720 hours of quality assured data the
requirements are similar. However, after the
initial 720 hours, substitute values are based on
the duration of the missing data period as well
as availability.
(§75.36 and Table 1)
Missing Data
Routine for
Moisture CEM
The OTC guidelines allow substituting 0.0%
for every hour of missing data or using an
algorithm based on availability and amount of
quality assured data available. The average of
the hour before and hour after moisture values
are used for the first 720 hours of QA'd
moisture data and after that if moisture data
availability is > 90%. A value of 0.0% is
reported if no prior quality assured data exist
or after 720 QA'd hours if the data availability
is < 90%.
Subpart H missing data procedures for
moisture are the inverse of those for CO2 and
O2 except that if certain NOX emission rate
formulas are in use (19-3, 19-4 or 19-8), they
are the same. (e..g., if there are no prior
quality assured moisture values and equation
19-6 is used, the minimum percent moisture
would be substituted, but if equation 19-3 is
used, the maximum percent moisture would be
substituted.)
(§75.37 and Table 1)
Missing Data for
Fuel Flow
The OTC guidance document allowed using
the Part 75 missing data substitution provisions
or substituting the maximum Potential Fuel
Flow rate for every missing data hour.
Subpart H requires use of the Part 75 missing
data procedures for fuel flow.
(Appendix D, §§ 2.4.2 and 2.4.3)
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 77
-------
Section 5; Comparison of OTC and Subpart H Requirements
Table 5-3: Appendix D Fuel Flow for Gas and Oil Fired Units
Requirement/
Option
OTC
Subpart H
Oil Sampling for
Fuel GCV and
Density
The OTC guidelines provided four options for
oil sampling:
1. Sample each oil delivery,
2. Sample from the fuel storage tank after each
fuel delivery,
3. Daily flow proportional sampling by
extracting a hourly sample, or
4. Daily as fired samples.
Appendix D procedures for determining oil
GCV and density are slightly different, but
similarly provide for sampling after each
delivery, from the fuel storage tank, daily flow
proportional sampling, and daily as fired
sampling. Subpart H oil sampling
requirements are in App. D, § 2.2.1.
The handling of the timing of ozone season
sampling of storage tanks and deliveries are
also different in Subpart H.
(§ 75.74(c)(5))
Table 5-4: Default NOX Emission Rates/Low Mass Emissions Methodology
Requirement/
Option
OTC
Subpart H
Default NOX
Rate Options
A unit that combusted only oil and/or gas and
is not required to use NOX CEMS, was allowed
to develop and use a unit-specific default NOX
emission rate factor, or the unit may have used
generic default emission rates based on fuel
combusted and type of unit. In some
instances, testing at fewer than four loads was
allowed to derive the default emission rates.
Under Subpart H, only units burning only gas
and/or oil, and demonstrate that NOX annual
emissions are less than 50 tons (for year-round
reporters) or that ozone season emissions are
less than 25 tons (for ozone season-only
reporters), may develop a unit specific default
NOX rate or use a generic default NOX rate.
Unit specific default rates are based on testing
at four load levels per Appendix E, instead of
the lesser number of load levels that may have
been used in some cases by OTC units. In
addition the unit specific rate is based on
multiplying the maximum tested emission rate
by a 1.15 multiplier for controlled and
uncontrolled units, or using a default rate of
0.15 Ib/mmBtu for controlled units, whichever
is higher.
On June 13, 2001, EPA proposed substantive
revisions to § 75.19, including changes to the
method of determining default NOX emission
rates.
(§§ 75.74 (c)(10) and 75.19, June 13, 2001
Federal Register)
(cont.)
Page 78
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Section 5; Comparison of OTC and Subpart H Requirements
Table 5-4: Default NOX Emission Rates/Low Mass Emissions Methodology (cont.)
Requirement/
Option
OTC
Subpart H
Maximum Heat
Input
Option
OTC allowed a source to petition the State
regulatory agency to use a unit-specific
maximum hourly heat input to calculate NOX
mass based on the higher of the manufacturer's
maximum rated capacity, or the highest
observed hourly heat input in the past five
years.
Under Subpart H, the use of maximum heat
input to determine NOX emission rate is
allowed for Low Mass Emissions units.
(§§75.70 and 75.19)
Long Term Fuel
Flow Option
Under OTC a unit that combusted only oil
and/or gas and that had elected to use a unit-
specific or generic default NOX emission rate
was allowed to determine hourly heat input
based on fuel usage measurements for a
specified period that was longer than an hour.
Under Subpart H, only units burning only
natural gas and/or oil, and demonstrate that
NOX annual emissions are less than 50 tons (for
year-round reporters) or that ozone season
emissions are less than 25 tons (for ozone
season-only reporters), may use records of
long-term fuel flow (quarterly), to calculate
hourly heat input to a low mass emissions unit.
(§§ 75.74(c)(10)and75.19)
Alternative Heat
Input Method
States approved some alternative heat input
determinations for OTC Sources.
Under Subpart H, sources may petition for
alternative monitoring methods, but they must
meet the requirements of Part 75, Subpart E.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 79
-------
Section 5; Comparison of OTC and Subpart H Requirements
Certification/
Quality
Assurance Tests
The following tables compare OTC and Subpart H monitoring
requirements and options. An index to the tables and certification and
quality assurance requirements/options is provided below:
! Table 5-5: CEMS QA - RAT A Standards:
- NOX Emission Rate System
- NOX Concentration System
- Moisture System
! Table 5-6: CEMS QA - RATA Test Requirements:
- Load Level Definitions
- Flow RATA Load Levels
- New Flow Reference Methods
- RATA Grace Period
- RATA Extension for non-QA Operating Hours
! Table 5-7: CEMS QA - Flow to Load:
- Flow to Load/Gross Heat Rate Check
! Table 5-8: CEMS QA - Data Validity:
- Conditionally Valid Data
! Table 5-9: CEMS QA - Calibrations:
- Calibration Gas Protocol
- Mid Range Daily Calibration Option
! Table 5-10: CEMS QA - Linearity:
- Low Span Monitor Exemption
- Quarterly Linearity Grace Period
- Linearity Frequency
! Table 5-11: Appendix D - Fuel Flow:
- Fuel Flow to Load Option
- Fuel Flowmeter Calibrations
- Fuel Flowmeter Inspections
Page 80
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
-------
Section 5; Comparison of OTC and Subpart H Requirements
Table 5-5: CEM System Quality Assurance - RATA Standards
System
Type
NOX Emission
Rate System
NOX
Concentration
System
Moisture
System
OTC
Relative Accuracy
Standard
20.0% (all annual
frequency)
or
If not passing on a relative
accuracy basis and mean
CEM value is < 0.20
Ib/mmBtu (low emitter),
mean CEM value within
±0.041b/mmBtuofthe
reference method mean (all
annual frequency)
20.0% (all annual
frequency)
or
If not passing on a relative
accuracy basis and mean
CEM value is < 250 ppm
(low emitter),
mean CEM value within
±30 ppm of the reference
method mean value
15.0% or mean difference
within ±1.0% H2O (all
annual)
BAF
Must use 1.100
ifRA>10.0%
(or mean
difference >
0.02 Ib/mmBtu
if passing
RATA as a
low-emitter).
Otherwise, as
calculated.
Must use 1.100
ifRA>10.0%
(or mean
difference >
±15 ppm if
passing RATA
as a low-
emitter).
Otherwise, as
calculated.
None
Subpart H
Relative Accuracy
Standard
10.0% for semi-annual frequency
7.5% for annual frequency
(App. A, § 3.3.2, App. B, § 2.3.1.2)
or
If not passing on a relative accuracy
basis and the mean CEM value is
< 0.200 Ib/mmBtu (low emitter),
mean CEM value within ± 0.020
Ib/mmBtu of reference method mean
for semi-annual frequency, or
mean CEM value within ±0.015
Ib/mmBtu of the reference method
mean for annual frequency
(App. B, §2.3.1.2)
10.0% for semi-annual frequency
7.5% for annual frequency
(App. A, § 3.3.7, App. B, § 2.3.1.2)
or
If not passing on a relative accuracy
basis and the mean CEM value is
< 250.0 ppm (low emitter),
mean CEM value within ±15.0 ppm
of the reference method mean for
semi-annual frequency, or
(App. A, § 3.3.7(b))
mean CEM value within ±12.0 ppm
of the reference method mean for
annual frequency.
(App. B, §2.3.1.2)
10.0% or mean difference within
± 1.5 % H2O for semi-annual.
(App. A, § 3.3.6), or
< 7.5%, or mean difference within
± 1.0%H2O for annual.
(App. B, §2.3.1.2)
BAF
As calculated or
may use 1.111
for low-emitter
(App. A,
§ 7.6.5(b))
As calculated or
may use 1.111
for low-emitter
(App. A,
§ 7.6.5(b))
None
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 81
-------
Section 5; Comparison of OTC and Subpart H Requirements
Table 5-6: CEM System Quality Assurance - RATAs Testing Requirements
Requirement/
Option
OTC
Subpart H
Load Level
Definitions
The OTC guidelines referenced a previous
version of Part 75, Appendix A which
identified low load as anywhere from the
minimum safe stable load to 50% of
maximum load. (There was no minimum
separation between the adjacent load levels
and no definition of normal load.)
Appendix A now more clearly defines the load levels
for RATAs. The low, mid, and high load levels are
defined in terms of the range of operation. The most
frequently used load would be designated as normal,
and there is a provision for designating a second
normal load level.
(App. A, §6.5.2.1)
Number of load
levels for Flow
RATA
A 3-load RATA is required, unless the State
approved a single-load RATA for initial
certification. This approval would be based
on the owner or operator's demonstration that
the unit has operated at a constant load
(operated within 10% of the average load for
90% of the time for the previous year).
A 3-load RATA is required for initial certification,
except for peaking unit and bypass stack monitors,
which only require single-load RATAs. For quality-
assurance, the required load levels for flow RATAs
are given in Part 75 (App. B, § 2.3.1.3(c)):
1. A 3-load RATA, at the low-, mid-, and high-load
levels shall be performed for the initial
certification, recertification, and when the
polynomial coefficients or K-factor(s) are changed.
A 3-load RATA is required at least once in every
period of five consecutive calendar years.
2. An annual 2-load flow RATA shall be done at the
two most frequently used load levels,
3. If the flow monitor is on a semiannual RATA
frequency, 2-load flow RATAs and single-load
flow RATAs at normal load may be performed
alternately.
4. A single-load annual flow RATA, at the most
frequently-used load level, may be performed in
lieu of the 2-load RATA if a historical load data
analysis shows that the unit has operated at a single
load level for > 85.0 percent of the time.
5. Only single-load flow RATAs are required for
peaking unit and bypass stack monitors.
Flow RATAs
New Part 60
Flow Test
Methods
New Part 60 reference methods for stack flow
(Method 2F, 2G, 2H) are not available for
sources that report in EDR v2.0.
Part 75 was revised to allow the use of additional
flow reference methods in Part 60, Appendix A.
RATA Grace
Period
A RATA grace period is not available under
the OTC guidelines.
Part 75 has been revised to include a 720 consecutive
unit operating hour grace period for completion of
RATA testing when a RATA has not been performed
by the end of the quarter in which the RATA is
required. (App. B, § 2.3.3(a))
RATA
Extension for
nonQA
Operating
Quarters
The OTC guidelines required that a RATA be
performed and completed at least once every
calendar year. Annual RATAs were to be
performed at least four months apart. No
extensions for non QA operating quarters.
Parts 72 and 75 have been revised to base RATA
frequency on "QA operating" quarters rather than
quarters. A QA operating quarter is a quarter in
which there are at least 168 unit or stack operating
hours. Semiannual RATAs, for example, are to be
performed every two successive QA operating
quarters. (App. B, § 2.3.1.1)
Page 82
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
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Section 5; Comparison of OTC and Subpart H Requirements
Table 5-7: CEM System Quality Assurance - Flow to Load
Requirement/
Option
OTC
Subpart H
Flow to
Load/Gross Heat
Rate Check
OTC guidelines do not require a flow to load
or gross heat rate check.
Part 75, Appendix A has been revised to add a
new quarterly quality assurance requirement for
flow monitorsthe flow-to-load ratio or gross
heat rate test. A reference value of the ratio of
flow rate to unit load or gross heat rate is
determined each time that a passing flow RATA is
performed at a normal load level. A separate
reference value is determined for each normal load
level.
(App. A, § 7.7(a), App. B, § 2.2.5 )
Table 5-8: CEM System Quality Assurance - Data Validity
Requirement/
Option
OTC
Subpart H
Conditionally
Valid Data
Conditionally valid data are not allowed by
the OTC guidelines.
Subpart H allows the use of conditionally valid
data from CEMS during certification, and
recertification test periods and during the periodic
linearity and RAT As. The purpose is to minimize
the hours of substitute data or maximum potential
values reported. Rules for the data validation are
provided in § 75.20(b)(3). For initial
certifications see App. A, §§ 6.2(a), 6.3.1(a),
6.3.2(a), 6.4(a) and 6.5(f). For linearity checks
and RATA data validation procedures see App. B,
§§2.2.3(b)and2.3.2(b).
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 83
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Section 5; Comparison of OTC and Subpart H Requirements
Table 5-9: CEM System Quality Assurance - Calibration Gases
Requirement/
Option
OTC
Subpart H
Cal Gas Protocol
Changes
During the ozone season, perform all daily
calibrations and linearity checks using
protocol calibration gases. For tests
performed during the non-ozone season
conform with applicable State requirements
for calibration gas. A protocol gas is a
calibration gas mixture prepared and analyzed
according to Section 2 of the EPA
Traceability for Assay and Certification of
Gaseous Calibration Standards (revised
September 1993), EPA 6000 R93/224 or a
revised version of this standard approved by
both EPA and the State.
Part 75 requires "calibration gas" as defined in
section 5.1 of Appendix A, to be used for daily
calibrations and reference method testing.
Parts 72 and 75 calibration gas protocols have
been revised to be consistent with a September
1997 protocol document (EPA Traceability
Protocol for Assay and Certification of Gaseous
Calibration Standards, EPA600/R-97/121):
1. App. H, which was based on an older 1987
Protocol 1, has been removed from Part 75.
2. §§ 72.2 and 72.3 calibration gas definitions and
abbreviations have been revised.
3. App. A, §§ 5.1.1 - 5.1.8 (Standard Reference
Materials) have been revised.
4. App. A, § 6.2 has been revised to reference
App. A, §5.1.
5. § 75.22 (c)(l) was revised to reference App. A,
section 5
Mid Range Cal
Gas Option
Under OTC calibration error tests are
performed at two concentrations: (1) zero-
level and (2) high level.
Part 75, Appendix A now allows the use of a zero-
level and a mid-level (50.0% to 60.0% of the span
value) or high-level calibration gas in calibration
error tests.
(App. A, § 6.3.1 and App. B, § 2.1.1)
Table 5-10: CEM System Quality Assurance - Linearity Tests
Requirement/
Option
OTC
Subpart H
Low Span
Monitor
Exemption
OTC guidelines do not provide an exemption
from the linearity test requirements for low
span value monitors. (However, for monitors
with a span < 50 ppm, only two points are
required (low and high) and for monitoring
with a span < 25 ppm a two point test with a
zero and non-zero gas is allowed.)
Appendix A provides a linearity exemption for
low span NOX monitors if the NOX span value for
a particular monitor range is < 30 ppm.
(App. A, § 6.2)
Quarterly
Linearity Grace
Period
The OTC guidelines provide a 72 unit
operating hour grace period to perform the
required linearity test for a quarter in which
the unit operates for more than 168 hours.
The linearity grace period in Appendix B is 168
consecutive unit or stack operating hours:
(App. B, § 2.2.4(a))
(cont.)
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Section 5; Comparison of OTC and Subpart H Requirements
Table 5-10: CEM System Quality Assurance - Linearity Tests (cont.)
Requirement/
Option
OTC
Subpart H
Linearity
Frequency
Perform and report a successful linearity test
for each analyzer once during each calendar
quarter in which the unit operates more than
168 hours. At a minimum, one linearity test
must be performed every calendar year that
the unit operates.
Appendix B requires that a linearity check be
performed at least once during each QA operating
quarter (>168 unit or stack operating hours). The
tests are to be conducted no less than 30 days
apart and to the extent practicable.
(App. B, § 2.2.1)
Also no more than four successive calendar
quarters shall elapse after the quarter in which a
linearity check of a monitor or monitoring system
(or range of a monitor or monitoring system) was
last performed.
(App. B, § 2.2.3(f))
Table 5-11: Appendix D Quality Assurance
Fuel Flow Monitoring for Gas and Oil Fired Units
Requirement/
Option
OTC
Subpart H
Fuel Flow to
Load Option
Fuel flowmeters must be calibrated the earlier
of every two calendar years or every four unit
operating quarters in which the fuel measured
is combusted at the unit. There are no fuel
flowmeter QA testing extensions.
In Appendix D, if the procedures of a fuel flow-
to-load test are performed during each "fuel
flowmeter QA operating quarter", subsequent to a
required flowmeter accuracy test or transmitter
accuracy test and primary element inspection, (as
applicable), those procedures may be used to meet
the requirement for periodic quality assurance
testing for a period of up to 20 calendar quarters
from the previous accuracy test or transmitter
accuracy test and primary element inspection.
(App. D, §2.1.7)
Fuel Flowmeter
Calibrations
Fuel flowmeters must be calibrated the earlier
of every two calendar years or every four unit
operating quarters in which the fuel measured
is combusted at the unit.
Appendix D extends the maximum amount of time
between fuel flowmeter accuracy tests to 20
successive calendar quarters, and bases the four
quarter test interval on "fuel flowmeter QA
operating quarters".
(App.D,§2.1.6(a))
Fuel Flowmeter
Inspections
The OTC guidelines do not require visual
inspections of orifice plate or venturi meters.
Appendix D requires a visual inspection of the
orifice, nozzle, or venturi meter at least once every
twelve calendar quarters. The fuel flow to load
option (App. D, § 2.1.7) may be used to reduce the
inspection frequency.
(App. D, §2.1.6.4(a))
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
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Section 5; Comparison of OTC and Subpart H Requirements
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SECTION 6: OZONE SEASON ONLY REPORTING FOR
OTC-SUBPART H SOURCES
Purpose of This
Section
Applicability
Reporting
Periods
Transition from
Annual OTC
Reporting
This section provides a summary of the special considerations for
monitoring and reporting on an ozone season basis as opposed to an
annual basis. The OTC NBP allowed for ozone season only reporting in
some circumstances, and the NOX Budget Trading Programs build on that
experience.
Currently under the OTC NOX Budget Program, you have to report on a
year-round basis for units that use a NOX CEMS to account for NOX
emissions. Otherwise, OTC States (other than Pennsylvania) allow non-
Acid Rain units without a CEMS to report data on an ozone season basis
for the OTC NOX Budget Program. Under the NOX SIP Call, EPA allows
both ozone season only reporting and annual reporting for non-acid rain
units. Each of the OTC States have allowed for ozone season only
reporting in their SIPs for all non-Acid Rain units, except Massachusetts
which continues to limit ozone season reporting to non-Acid rain units
that do not use CEMS.
You will report data for the second and third quarters. For the second
quarter report, the data must be submitted for May and June (sources
may also elect to submit data for April). The third quarter report will
cover the entire quarter, July-September. The second quarter report may
also include results from quality assurance activities that occur during the
non-ozone period see below for further details on what non-ozone
season quality assurance activities may be required. If you do not
operate in the second quarter, then that information would be included in
your third quarter report.
The EDR v2.1 Instructions for Record Type (RT) 508 address this
transition reporting for sources that already are using EDR v2.1. As
detailed in the Instructions, any change in reporting frequency takes
effect at the beginning of the next calendar year. If you are changing
your reporting frequency from year-round to ozone season, you are not
required to report a first quarter report in the calendar year following
when you elect to make the change. Your next required submission
would be the second quarter, at the start of the ozone season for the next
calendar year. Regardless of which method you choose, the reporting
frequency must be the same for any stack or pipe and its associated units.
The Instructions identify the following critical steps for changing from
year-round reporting to ozone season reporting:
! Report a RT 508 in your fourth quarter report.
! In column 10, enter the new reporting frequency as "OS" (ozone
season). (Do not change the reporting frequency reported in RT 505
in the fourth quarter report. The reporting frequency in RT 505
must be changed in the first report submitted under the new ozone
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 87
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Section 6; Ozone Season Reporting for OTC-Subpart H Only Sources
season reporting frequency which begins May 1st of the second
quarter).
! In column 12, enter the beginning date of the new reporting
frequency (i.e.. May 1st of the next calendar year).
! Submit your next quarterly report for the second quarter (May 1 -
June 1) of the next calendar year.
For units that currently report under EDR v2.0, these instructions will
not work because you do not have RT 508 under EDR v2.0. Instead, you
should report a changed RT 505 in your fourth quarter report (your final
report under EDR v.2.0) to indicate that you will switch to ozone season
reporting. This indication will let EPA know of your changed status, and
that no first quarter 2002 report is required for your unit.
Special QA For any unit that you report on an ozone season only basis, you must
Procedures meet the specific quality assurance procedures of 40 CFR 75.74(c). You
will have to conduct some Subpart H quality assurance testing prior to
the beginning of the ozone season (before May 1) and other testing
during the ozone season (May 1 through September 30). These separate
requirements are summarized in the following table. Because of some of
the complexities of conducting quality assurance to support ozone season
only reporting, you should evaluate these requirements carefully before
determining whether the switch to ozone season only reporting is
practical and cost effective for your individual circumstances.
When required QA tests that are done outside of the ozone season
(between October 1 of the previous year and April 30 of the current year)
affect data validation in the current ozone season, submit the results of
these QA tests in the quarterly report for the second calendar quarter of
the current year, or with the third quarter report, if the second quarter is a
non-operating quarter (see § 75.74(c)(6)(v)).
Page 88 Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001
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Section 6; Ozone Season Reporting for OTC-Subpart H Only Sources
Table 6-1:
QA Requirements for Units Reporting on an Ozone Season Basis
Perform these QA
tests-
Daily calibrations
(outside ozone
season)
Daily calibrations
(inside ozone
season)
Daily interference
checks
(inside ozone
season)
Daily interference
checks
(outside ozone
season)
Linearity check
(outside ozone
season)
Linearity check
(inside ozone
season)
For this
equipment-
Each required
CEMS
Flow monitor
Each required
gas monitor
At these times...
From the date and
hour of any RATA
or linearity check
passed in the "pre-
ozone season
period" (i.e., from
10/1 of previous
year through 4/30 of
current year)
Throughout the
ozone season (5/1 -
9/30)
Throughout the
ozone season
From the date and
hour of any flow
RATA passed in the
pre-ozone season
period
During the pre-
ozone season period
from 10/1 of
previous year
through 4/30 of
current year
In 2nd and 3rd
quarters
With these qualifications and
exceptions...
If the test is not completed by 4/30,
a 168 operating hour grace period is
allowed if a linearity check was
passed in the previous year and if
the unit operated for < 336 hours in
the last ozone season
! The linearity check is required
only in QA operating quarters
! No grace periods allowed for
these checks
(cont.)
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 89
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Section 6; Ozone Season Reporting for OTC-Subpart H Only Sources
Table 6-1:
QA Requirements for Units Reporting on an Ozone Season Basis (cont.)
Perform these QA
tests...
For this
equipment.
At these times.
With these qualifications and
exceptions...
! RATA
! Bias test
(NOX and flow
systems, only)
NOx-diluent
CEMS
NOX
concentration
CEMS
Flow monitor
Moisture
monitor
Diluent
monitor used
only for heat
input rate
Pre-ozone season
period from 10/1 of
previous year
through 4/30 of
current year
Not required if RATA from
previous ozone season is able to
validate data for part or all of
current ozone season
If the results of this RATA
qualify for an annual RATA
frequency, you may use this
RATA to validate data for entire
current ozone season
If the results of this RATA
require a semiannual frequency,
you may use this RATA to
validate data for entire current
ozone season (if test was
performed in the current year) or
only through 6/30 of current year
(if test was performed in the
previous year)
If the RATA is not completed by
4/30, a 720 operating hour grace
period is allowed if a RATA was
passed in the previous year and if
the unit operated for < 336 hours
in the last ozone season
If the RATA is not completed by
4/30 and you do not qualify for a
grace period, you may use the
conditional data validation
procedures of § 75.20 (b)(3) in
the current ozone season, subject
to certain restrictions.
(cont.)
Page 90
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
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Section 6; Ozone Season Reporting for OTC-Subpart H Only Sources
Table 6-1:
QA Requirements for Units Reporting on an Ozone Season Basis (cont.)
Perform these QA
tests...
! RATA
! Bias test
(NOX and flow
systems, only)
Flow-to-load ratio
test
Leak check
Fuel flowmeter
accuracy tests
For this
equipment...
! NOx-diluent
CEMS
! NOX
concentration
CEMS
! Flow monitor
! Moisture
monitor
! Diluent
monitor used
only for heat
input rate
Flow monitor
DP-type flow
monitor
Fuel flowmeter
At these times...
Inside the ozone
season, i.e., in 2nd or
3rd quarter
In 2nd and 3rd
quarters
In 2nd and 3rd
quarters
Every four "fuel
flowmeter QA
operating quarters"
(fuel measured by
flowmeter is
combusted >168
unit operating
hours)
With these qualifications and
exceptions...
! Required only when a pre -ozone
season RATA or a RATA
performed during the last ozone
season is not able to quality
assure data for the entire current
ozone season
! You may opt to perform all
required RATAs in the 2nd or 3rd
quarter instead of performing
RATAs outside the ozone season
! You may use an ozone season
RATA to validate data for part or
all of the next ozone season, if
the RATA results qualify for an
annual frequency, and if you
perform daily calibrations (and
interference checks if applicable)
from 10/1 of current year through
4/30 of the next year
! Required only in "QA operating
quarters"
! Complex configurations may be
exempted by petition under
§ 75.66
Required only in "QA operating
quarters" (> 168 unit operating
hours)
! Include calendar quarters outside
the ozone season when
determining the accuracy test
deadline
! For orifice, nozzle and venturi-
type flowmeters, visual
inspections are also required
every 3 years
! An optional "fuel flow-to-load"
or "gross heat rate" test (see
Appendix D, section 2.1.7) may
be performed in the 2nd and 3rd
quarters to extend the interval
between flowmeter accuracy
tests to up to 20 quarters
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
Page 91
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Section 6; Ozone Season Reporting for OTC-Subpart H Only Sources
Key EDR Record Appendix C of the EDR v2.1 Instructions includes detailed explanations
Types of how to assemble an EDR for your particular type of unit. In addition,
the main body of the Instructions contains detailed information on each
individual record type in the EDR. For applicable record types, the
Instructions contain specific guidance for ozone season-only reporters.
The following is a list of the EDR record types that provide this guidance
and a summary of the special ozone season-only reporting provisions.
To determine all of the required record types for your particular
monitoring scenario (e.g., NOX emission rate CEM system and Appendix
D Fuel Flow metering), refer to Appendix C.
You should make note of the record types on this list and refer to the
version 2.1 Instructions for further details, to determine how your ozone
season-only reporting status will affect your EDR v2.1 reporting. The
page number in the January 24, 2001 .pdf version of the v2.1
Instructions is included in the parenthetical description of each record
type, below:
! RT305 (LME long term fuel flow, p. 73). The Instructions
indicate how to report for ozone season only values (Field 16).
! RT 307 (Cumulative NOX mass data, p. 79-80). Leave blank Fields
67, 77 and 87 - cumulative annual NOX tons, heat input and
operating hours.
! RT 360 (LME hourly emissions data, p. 94). You can report
operating time (Field 18) only for ozone season.
! RT 505 (Program indicator, p. 102). After switching from OTC to
Part 75 monitoring, in the new record for program code "OTC-
SUBH" report the reporting frequency in column 22 as "OS."
! RT 507 (Peaking/gas-fired qualifying data, p. 107-108,110-111)
If you report on an ozone season basis, Part 75 allows you to qualify
as a peaking unit based on ozone season data only (see §
75.74(c)(l 1)). The EDR Instructions clarify how to report data that
you rely on to qualify as a peaking unit using ozone season data.
You will report in your second quarter report data from the previous
ozone season to update the information in this RT, or to report that
you no longer qualify as a peaking unit.
! RT 508 (Subpart H reporting schedule, p. 111-113) You will use
this RT to indicate that you report on an ozone season only basis.
Follow the instructions provided.
! RT 556 (conditionally valid data, p. 166,170). You must resolve
all conditionally valid data recorded during the ozone season no
later than the deadline for submitting the third quarter emissions
Page 92 Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001
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Section 6; Ozone Season Reporting for OTC-Subpart H Only Sources
report, either by using missing data substitution or by completing
the required QA test(s). In some cases, resubmittal of the emissions
report for the second quarter may be required to fully resolve
conditionally valid data for the ozone season (see § 75.74(c)(3)(xi)
and (xii)). You can use the conditionally valid flag in Field 51 only
in the second quarter report.
! RTs 601/602/603/605/606 (Various QA test data records, p. 185-
187,189-190,192). The Instructions provide information on when
checks are required and how to report these QA test data.
! RTs 610/611 (RATA and bias test data, p. 195). You will not use
the QA operating quarter method of determining RATA deadlines
and data validation status. Instead, a successful RATA resulting in
a semiannual (or annual) frequency validates data from a CEMS for
two (or four) calendar quarters (not QA operating quarters)
following the quarter in which the RATA is passed (see
§§ 75.74(c)(2)(ii)(F) and (G) and § 75.74(c)(3)(vii)). A grace
period is conditionally allowed within the ozone season, when the
data validation window from the previous RATA has expired prior
to the start of the current ozone season (see § 75.74(c)(2)(ii)(H)).
To claim this grace period, follow the applicable instructions under
RT 699. Report the appropriate reason code in Field 131 of RT
611.
! RT 624 (Other QA, including flowmeterprimary element
inspections, p. 211). Report out-of-season primary element
inspection in the quarterly report for the second calendar quarter of
the current year (or in the third quarter report, if the second quarter
is a non-operating quarter).
! RTs 627/628 (Fuelflowmeter accuracy tests, p. 212-214). You
must include all fuel flowmeter QA operating quarters for the entire
year when determining the deadline for the next accuracy test (see
§ 75.74(c)(4)). If you perform a required test outside the ozone
season to validate data in the current ozone season, you need to
report the results of the test in the quarterly report for the second
calendar quarter of the current year (or in the third quarter report, if
the second quarter is a non-operating quarter).
! RTs 629/630 (Fuel flow-to-load test, p. 216, 219). If you select this
test option, you only need to conduct the test during the ozone
season, and report RTs 629/630 for the second and third calendar
quarters, if those quarters are operating quarters (see
§ 75.74(c)(3)(v)). See RT 696, below, for claiming accuracy test
extension based on this test.
Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001 Page 93
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Section 6; Ozone Season Reporting for OTC-Subpart H Only Sources
! RT 695 (single-loadRATA, p. 230-231). You will not use this RT
because this option is not available for ozone season-only reporters.
You must conduct a two-load flow RATA for routine quality-
assurance, and a three-load RATA at least once every five years and
whenever the polynomial coefficients or K-factor(s) of the flow
monitor are changed (see § 75.74(c)(2)(ii)(C)).
! RT 696 (fuel flowmeter accuracy test extension, p. 232-234). You
can claim an automatic deadline extension for non-ozone season
calendar quarters. In the ozone season, if you do not use the
optional fuel flow-to-load ratio methodology in Section 2.1.7 of
Appendix D, you can claim a one-quarter extension of the fuel
flowmeter accuracy test deadline for any quarter which does not
qualify as a "fuel flowmeter QA operating quarter" (as defined in
§ 72.2), including non-operating quarters. When the optional fuel
flow-to-load ratio methodology is used, accuracy test deadline
extensions may be claimed for that same reason, or for: (1) any
quarter in which the optional fuel flow-to-load ratio test in Section
2.1.7 of Appendix D is performed and passed; or (2) any quarter in
which fewer than 168 hours of fuel flowmeter data are available for
the fuel flow-to-load ratio test, after allowable data exclusions are
taken under Section 2.1.7.3 of Appendix D; or (3) any quarter in
which the baseline data collection period for the fuel flow-to-load
ratio test is still in progress, and fewer than four calendar quarters
have elapsed since the quarter of the last successful fuel flowmeter
accuracy test.
! RT 697 (RATA deadline extension or exemption, p. 234-236).
Generally, do not use this RT the RATA deadline extensions do
not apply for ozone season reporters. Only in rare cases when the
conditional RATA exemption for non-redundant backup monitors
(code 5) is claimed, would this RT be used.
! RT 698 (Quarterly QA test exemptions, p. 237-239). In the ozone
season, the following exemptions can apply, as applicable to your
monitoring systems: (1) linearity check, leak check, and flow-to-
load ratio test exemptions may be claimed for any operating quarter
that does not qualify as a QA operating quarter (the unit or stack
operates for less than 168 hours); (2) a linearity check exemption
may be claimed for a particular monitor range (e.g., the high or low
range of a dual-span unit) if the range is not used during the quarter;
(3) for NOX span values of 30 ppm or less, an on-going linearity
check exemption may be claimed; and (4) for complex exhaust
configurations, an on-going flow-to-load ratio test exemption may
be claimed if approved by petition to the Administrator under
§ 75.66 and Section 7.8 of Appendix A to Part 75. You may not
claim an exemption from the required pre-ozone season linearity
check unless your unit qualifies for the on-going exemption for a
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Section 6; Ozone Season Reporting for OTC-Subpart H Only Sources
NOX span value < 30 ppm). A 168 unit/stack operating hour grace
period is conditionally allowed when the pre-ozone season linearity
check is not completed by April 30th (see § 75.74(c)(2)(i)(D)(7) and
the RT 699 instructions).
! RT 699 (QA test extension grace period, p. 239-241). The
minimum frequency of linearity checks and associated grace periods
set out in Appendix B, section 2.2.3(f), do not apply for ozone
season reporters. You need to perform linearity checks both outside
and inside the ozone season at the frequency specified in
§ 75.74(c)(2)(i) and § 75.74(c)(3)(ii) of Subpart H. Grace periods
are conditionally allowed for the required pre-ozone season linearity
checks, but not for the linearity checks required within the ozone
season (see § 75.74(c)(2)(i)(D)(7) and § 75.74(c)(3)(ii)). See the
EDR v2.1 Instructions for detailed conditions for qualifying for the
grace periods and special reporting provisions for RT 699 for ozone
season only reporters.
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001 Page 95
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Section 6; Ozone Season Reporting for OTC-Subpart H Only Sources
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Page 96 Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001
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APPENDIX A: MONITORING PLAN EDR
CHANGES FOR ALL UNITS
Purpose of this Even if a change in methodology is not required for your unit, changes
Section have been made in the reporting format between EDR v2.0 and EDR
v2.1. EDR format modifications include changes to already existing
record types (e.g. discontinued and added codes, discontinued and added
fields), as well as entire record types being removed and additional
record types added. These changes for monitoring plan records are
summarized in this section. Consult the EDR v2.1 Instructions for a
detailed descriptions of reporting requirements for each record type.
RT 100 Facility Identification
Report "V2.1" for all submissions in column 15 in RT 100 (instead of
"V2.0") once you switch to Subpart H reporting.
RT 101 Record Types Submitted (optional)
If you report RT 101 (this RT is optional), codes have changed in the
parameter reported field. Codes SO2RTN and SO2RTOT have been
removed, and Codes LOWMASS, MOISTUR, NOXRATE, OSNSUMM
and QTRSUMM have been added.
RT 102 Facility Location and Identification Information
The only change between EDR v2.0 and EDR v2.1 is the reservation of
column 90 to correct the county code field length. This should not
require any changes to be made in your EDR.
RT503 Stack/ Pipe Header Definition Table
Maximum Hourly Gross Load in MW (col. 37) and steam (col. 43)
should no longer be reported in RT 503. Also, new fields for Stack Exit
Height Above Ground Level (col. 62), Ground Level Elevation Above
Sea Level (col. 66), Inside Cross-sectional Area at Flue Exit (col. 71) and
Inside Cross-sectional Area at Flow Monitor Location (col. 75) have
been added.
RT504 Unit Information
Fields for Stack Exit Height Above Ground Level (col. 36), Ground
Level Elevation Above Sea Level (col. 40), Inside Cross-sectional Area
at Flue Exit (col. 45) and Inside Cross-sectional Area at Flow Monitor
Location (col. 49) have been added.
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Appendix A; EDR Changes for All Units
RT505
RT506
RT507
RT508
RT510
Program Indicator for Report
All units must add an RT 505 for OTC-SUBH and delete the existing RT
505 for NBP. Make sure all fields are accurate for participation in OTC-
SUBH and represent the appropriate conversion date. Codes added to
v2.1 are OTC-SUBH, SUBH and SIP.
EIA Cross Reference Information (NEW)
This is a new record type that is required for all units.
Fuel Usage Data to Qualify as a Peaking Unit
A code for ozone season peaking unit (SK) has been added to the Type of
Qualification field (column 49), and a new field for the Method of
Qualifying (column 51) has been added. If your unit has been qualifying
as a peaking unit but then exceeds the capacity factor limits, submit a RT
507 that indicates that the peaking status has been lost (code PSL in
column 51). See the EDR v2.1 Instructions for details.
Subpart H Reporting Frequency Change (NEW)
This is a new record that should be reported in the appropriate quarter to
indicate a planned change to the Reporting Frequency (as reported each
quarter in RT 504). See the EDR v2.1 Instructions for details.
Monitoring Systems/ Analytical Components Table
No fields have been added to or removed from RT 510. However, see
the table below for code removals and additions. (Also, see the Acid
Rain Program Policy Manual, Question 7.1 if you plan to use the "like-
kind" replacement analyzer provisions of Part 75.)
Table A-l: RT 510 Code Changes
Column
17
23
Field Name
System parameter
monitored
Component type
Codes Added
(none)
CO2A, NOXA,
O2DA and O2WA
Codes Removed
HI
(none)
RT520
Formula Table
No fields have been added to or removed from RT 520. However, some
codes have been added, removed or changed for v2.1. For parameter
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Appendix A; EDR Changes for All Units
Monitored (col. 14) codes removed from v2.1 include HGAS, HMOF,
and HVOF (previously used to apportion long term fuel flow to each
hour no longer required since only LME units may use long term fuel
flow and those units do not need to report any formulas). The changes to
Formula Code (col. 23) values are summarized below. See EDR v2.1
Instructions for detailed tables of all formulas.
Table A-2: RT 520 Code Changes
Para-
meter
NOX
HI
NOXM
HI
HI
FGAS
FOIL
FW
H2O
EDR v2.0
Formula
Code
19-3
19-5
F-17
F-10A
F-20C
F-20A
F-20B
H-l
none
none
F-7C
none
EDR v2.1
Formula
Code
19-3 and
19-3D
19-5 and
19-5D
F-17 and
F-17D
F-24
D-15A
F-21C
F-21A
F-21B
none
N-GAS
N-OIL
19-14
M-1K
Description
If you use any of these formulas and plan to use the
diluent cap provisions of Part 75, you must add the "D"
version of the formula to RT 520 and use it (and report
that formula ID) for any hour in which you apply the
diluent cap value to the calculation. See the directions
for RT 520, in the EDR v2.1 Instructions.
Code change (same calculation - NOX emission rate times
heat input and operating time)
Code change (calculates total heat input rate from
multiple fuels at the same unit)
Code Change (calculates to total unit heat input rate from
multiple stacks or ducts)
Code change (same calculation - MW apportionment of
heat input from common stack to constituent units)
Code change (same calculation - Steam load
apportionment of heat input from common stack to
constituent units)
Formula code removed
New code (previously left blank)
New code (previously left blank)
Code change (same calculation - wet F-factor)
Moisture calculation using a K-factor of other
mathematical algorithm per Part 75, App. A, Section
6.5. 7(a)
Guidance on Changing OTC Monitoring to Part 75 October 12, 2001
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Appendix A; EDR Changes for All Units
RT530
RT531
Span Table
There are two new codes for parameter Monitored (col. 10): GNOX and
ONOX (to define missing data values for Appendix E NOX monitoring).
For flow span records, two required fields have been added: Flow rate
span value in SCFH (col. 90) and Flow rate full-scale range value in
SCFH (col. 97).
There are also two new field relating to the dual range requirements -
Dual Spans Required (column 84) and Default High Range Value (col.
85). If you have been using the default overscaling option allowed under
OTC, you will need to either switch to dual ranges or use the Part 75
default high range provision (see RT 530 in Section 1 of this document
and Part 75, Appendix A, Section 2.1.2.4(e)).
Maximums, Minimums, Defaults and Constants
Many values that were previously reported in RT 531 to define missing
data values are no longer required. Similarly, values not previously
defined in EDR v2.0 may now be defined. See the EDR v2.1
Instructions for a full discussion of the new uses for RT 531. Also, the
following codes have been changed for reporting in this RT:
Table A-3: RT 531 Code Changes
Column
10
34
37
41
Field Name
Parameter
Purpose or
Intended use
Type of Fuel
Source of
Value
Codes Added
CO2G, MHHI, MNHI,
MNNX, MNOF, MNGF,
H2OM, H2OX, O2M
DC, DM, LM
ANT, BT, LIG, SUB, W
DCPD, LME, MC,
SAMP, CONT, DEF
Codes Removed
NOX, FLOW, GAS,
GCV, HI, HR, NOXC,
OILM, OILV, DENS,
GCV
SE, SM
(none)
EF, MEC, DES, NBP,
PERM
RT535
Unit and Stack Operating Load Data
The Designated Normal Load field in column 18 should be left blank for
EDR v2.1. This information will be reported in RT 536 column 25.
If you previously reported a Single Load RATA Testing Only flag of "S"
(State Approved), you should remove this value from RT 535. If you
qualify for single load RATA testing as a bypass stack or a peaking unit,
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Appendix A; EDR Changes for All Units
report a B or P in this field. If, for a particular year, you qualify for
single-load flow RATA testing under Part 75 because the unit has
operated at a single load level for > 85% of the time since the last annual
flow RATA, leave this field blank but report RT 695 to claim the multi-
load flow testing exemption for that year.
RT 536 Range of Operation, Normal Load and Load Usage (NEW)
Report this new record type for each unit, common stack or multiple
stack with installed CEMS. Also submit RT 536 (columns 1 through 21
only) for a unit, common pipe or multiple pipe if you elect to use the
optional quarterly fuel flow-to-load test in Section 2.1.7 of Part 75
Appendix D to quality assure a fuel flowmeter at that unit or pipe
location.
RT540 Fuel Flowmeter Data
In column 17, the type of fuel code NNG (Natural Gas) has been added.
Also, specific codes have been established for the Initial Calibration
Method in column 38; other values will no longer be accepted.
RT 555 Monitoring System Recertification, Maintenance or Other Events
This record type has been replaced by RT 556. Please discontinue use of
RT555.
RT 556 Monitoring System Re-certification Maintenance, or Other Events
(NEW)
This record type replaces RT 555.
RT 560 Appendix E NOX Correlation Curve Segments
In the Type of Fuel field (col. 54) codes NNG (Natural Gas) and PDG
(Producer Gas) have been added.
RT 585 Monitoring Methodology Information
If moisture correction is required in any of your emissions formulas, add
RT 585 for parameter H2O to indicate your moisture determination
method.
Also, the list of valid codes has changed:
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Appendix A; EDR Changes for All Units
Table A-4: RT 585 Code Changes
Col
14
24
28
Field Name
Monitoring
Methodology
Type of Fuel
Associated with
Methodology
Missing Data
Approach
Codes Added
NOXG, NOXU, LTFF,
MMS, MDF, MTB,
MWD, FSA
NNG
SPTS and REV75
Codes Removed
ALT, GDEF, UDEF,
LTGF, LTOF
R
DBF and LOAD
RT586
RT587
Additional Note
Regarding
Bypass Stacks
Control Equipment Information
In the Control Equipment Code field (col. 14), many additional codes are
now available. Codes added include DLNB, DA, DL, FBL, MO, SB,
WL, WLS, B, ESP, WS, and C.
Unit Fuel Type
Codes have been added for the primary/secondary indicator field (col.
29) to indicate that a fuel type qualifies as an emergency fuel (E) or is a
fuel that is only used for ignition (I). If your unit burns oil only as an
emergency fuel and you intend to use the exemption from fuel flow
metering provided for emergency fuels (see the Acid Rain Program
Policy Manual, Question 25.10), be sure to update the RT 587 for this
fuel by reporting E in this field.
Also, a field was added (col. 31) to report "Demonstration to Qualify for
monthly fuel sampling for GCV."
Currently, Subpart H only provides two option for determining NOX
emissions from bypass stacks at units using a NOX CEM methodology
either use CEMS on the bypass stack also, or use reference method
monitoring (see § 75.72(c)). EPA has proposed revisions to this section
that would add as a third option the use of the appropriate maximum
default value(s) for every bypass hour. Under the proposed revisions,
OTC units that are currently using CEM monitoring for the main stack
and default values for bypass stacks and elect to continue with that
approach will need to revise their monitoring plan because all emissions
data will be reported at the unit level rather than at the multiple stacks.
This would require deactivating the multiple stacks and all the systems,
formulas and defaults at those stacks and adding those CEM systems,
formulas and default values at the unit. Contact EPA or your State for
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Appendix A; EDR Changes for All Units
additional information if you have questions about bypass stack
monitoring requirements under Subpart H.
Guidance on Changing OTC Monitoring to Part 75 - October 12, 2001 Page 103
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