CO
United States
Environmental Protection Air and Radiation EPA/400/1-91/008.C
Agency (ANR-445) April 1991
ve/EPA Acid Rain Advisory
Committee Meeting:
March 20-22, 1991
Emissions Monitoring
Issue Papers
HEADQUARTERS LIBRARY
ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, D.C. 20460
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Emissions Monitoring Subcommittee Papers
March 20 - 22, 1991
Document Title Page
number
£•14 Minutes from February 20*21, 1991 Subcommittee 1
Meeting
£-15 Roberson Paper on Relative Accuracy Test Audits 14
£-16 Shigehara Slides (hardcopy) on Wet Chemistry 24
£-17 Wrona ARAC Briefing Slides (Hardcopy) 27
£-18 Poirot Paper "Time Resolution for Reporting 44
CEM Data"
£-19 Central and South West Services, Inc Issue 53
Paper "Continuous Emission Monitoring
Exemption for Gas-Fired Utilities"
E-20 Houston Lighting & Power Co., and Texas' 60
Utilities Electric Co. Issue Paper
"Alternative Emission Monitoring Approaches"
£-21 Alternate Methods by EPA Reporting and 81
Recordkeeping Requirements by EPA
(Distributed prior to or at meeting)
£-22 Reporting and Recordkeeping Requirements by EPA 92
£-23 State Agency Experience in Data Recordkeeping 104
and Reporting
£-24 Baseline Tons of S02 (1985) for Selected 108
Categories of Affected Units Under Title IV
£-25 Coal Sampling and Analysis as an Alternative 109
to Continuous Emission Monitoring in
Pennsylvania (Presented at 1983 Engineering
Foundation Conference Pocono Hershey Resort, PA)
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ACID RAIN ADVISORY COMMITTEE
Subcommittee on Emissions Monitoring
MINUTES
February 20-22, 1991
Washington, DC
ATTENDANCE
The following Subcommittee members and U.S. EPA staff attended the February 20-22,
1991 meeting:
Ms. Nancy Wrona
Director, Office of Air Quality
Arizona Department of Environmental Quality
Phoenix, AZ
Acting Subcommittee Chair
Mr. Henry Beal
Vice President for Strategic Planning
Research-Cot trell Companies
ranch burg, NJ
Mr. Robert Bergstrom, Jr.
Chief Counsel
Iowa Southern
Centerville, IA
Mr. Jerry Golden
Manager, Clean Air Program
Tennessee Valley Authority
Chattanooga, TN
Mr. David Hawkins
Senior Attorney
Natural Resources Defense Council
Washington, DC
Mr. Larry Kertcher
Source Control Branch Chief
Acid Rain Division (ARD)
Office of Atmospheric and Indoor Air Programs (OAIAP)
U.S. Environmental Protection Agency
Washington, DC .
EPA Lead
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Mr. Robert McWhorter
Senior Vice President
Ohio Edison
Akron, OH
Mr. Daniel Plum ley
Director of Park Protection
The Adirondack Council
Elizabethtown, NY
Mr. Richard Poirot
Air Quality Planner
Vermont Department of Environmental Conservation
Waterbury, VT
Also attending the meeting were:
Ms. Doris Price, Emissions Monitoring Section Chief
Ms. Margaret Shepherd, Environmental Scientist
U.S. Environmental Protection Agency
Washington, DC
Mr. Joe Nazzaro
Chief, Continuous Emissions Monitoring Unit
Department of Environmental Resources
Harrisburg, PA
The meeting was facilitated by Dr. William Warren-Hicks of KUkelly Environmental
Associates and Dr. Joan Baker of Western Aquatics, Inc.
GENERAL
The Acid Rain Advisory Committee (ARAC) Continuous Emissions Monitoring (CEM)
Subcommittee met at the Ramada Renaissance Hotel, Herndon, VA on February 20,
1991, for a full day of discussions and February 21 for a half day of discussions. During
the afternoon of February 21 and for the entire day of February 22, 1991, the
Subcommittee members attended the meeting of the full ARAC, which was also
convened at the Ramada Renaissance Hotel. The following minutes summarize the
Subcommittee meeting and the presentations made by the Emissions Monitoring
Subcommittee to the full ARAC. These minutes are organized principally by topic area
under the following major categories: (1) the Pennsylvania experience, (2) missing data
periods, (3) utility of Subpart Da regulations for Title IV of the Clean Air Act
Amendments (CAAA), (4) COz monitoring, and (5) assignments for the March meeting.
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1. THE PENNSYLVANIA EXPERIENCE
The following is a summary of a presentation by Mr. Joe Nazzaro, Pennsylvania
Department of Environmental Resources (PaDER), concerning the experience of the
State of Pennsylvania with the use of continuous emission monitors (CEMs) for meeting
state air quality regulatory requirements.
• PaDER has encouraged CEMs for measuring SOz since the early 1970s, with formal
regulations beginning in 1979. Currently over 200 CEMs are operating in
Pennsylvania with another ZOO CEMs expected to be operating in the near future.
• All CEMs undergo a 3-step approval process that includes (1) submission by the
source of a proposed monitoring plan, (2) performance testing of the CEM with a
written report submitted to PaDER, and (3) PaDER review and approval of the
report.
The source is required to establish accuracy of CEM measurements and meet the
quality assurance audit criteria as established by PaDER.
PaDER generally requires more performance testing than EPA does, and some
audit procedures and criteria are different from those established by EPA in
Subpart Da requirements.
• As part of the quality assurance/quality control (QA/QC) requirements, PaDER
. requires the source to submit a quarterly emissions report including quarterly
calibration error testing. All hourly SOz averages are reported to the state. The
PaDER experience shows that this type and amount of data is manageable using
personal computer data bases. The burden of proof is on the source to
demonstrate compliance with air quality operating permits. In addition to
penalties for violations of the emissions standards, sources are penalized for the
amount of missing data above prespecif led limits. The amount of the penalty is a
function of the total amount of missing data.
• Out of control (OOC) periods are determined retrospectively for daily zero and
calibration/drift checks. Generally, 90%-95% availability of SOz CEMs is
observed. Some sources have backup CEMs to avoid penalties.
• Pulverized coal sampling, in accordance with Pennsylvania design and performance
specifications, and wet chemical methods have been approved as alternatives to
primary CEMs.
• Some sources have attempted to use parameter monitoring as an alternative
compliance demonstration during periods of invalid CEM data. However, PaDER
does not believe that sufficient documentation is available to justify parametric
monitoring as a viable alternative.
* PaDER does not require 100% SOz data availability on an hourly basis. The
Pennsylvania requirements (75% data collected during the hour) allow for a certain
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amount of missing data to be. present during the hour because the short-term
variability is not considered to be large enough to affect the monitoring results:
2. MISSING DATA PERIODS
The majority of the Subcommittee discussions on February ZO, 1991, concerned issues
associated with the presence of missing data periods in the continuous emissions
monitoring record. Most of the discussions concerned monitoring of SO? emissions.
Title IV of the CAAA requires that in the absence of CEM data a unit is assumed to be
operating in an uncontrolled manner unless information "satisfactory to the
Administrator* is presented. The Subcommittee discussed various issues associated with
missing data periods including the following: (1) appropriate time period for accounting
for missing data, (2) definition of a valid hour, (3) development of a threshold, and
{4} methods for filling in missing data. As the discussion of issues progressed, two
general perspectives on the role of continuous emissions monitoring evolved. In many
cases, views on specific CEM issues were related td Subcommittee members' general
perspectives on the role of emissions monitoring. These perspectives can be summarized
as follows:
Perspective I: The calculation of the annual tons of SOj emitted by a unit is
emphasized. Those data necessary for the calculation of an annual average should be
collected, with less emphasis on the measurement of emissions for smaller units of time
(e.g., aa hour).
Perspective XL The maintenance of a continuous record of emissions on a small time
scale (e.g., an hour) is emphasized. Incentives which would minimize the amount of " -
missing data and provide rigorous estimates of hourly emissions are encouraged.
Appropriate Time Period for Accounting
The Subcommittee discussed the time units of concern for filling in missing data. For
CEMs, the Subcommittee agreed that an hour is the appropriate unit of time. However,
the Subcommittee agreed that other time periods may be appropriate for evaluating
alternatives to CEMs. The Subcommittee did not explicitly address which time periods
would be appropriate for various CEM alternatives.
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Definition of a Valid Hour
A key issue when establishing the number of missing data periods for CEMs is the
definition of a valid hour. As the QA/QC and other requirements that define a valid hour
become more stringent, the number of missing data periods in the emissions record may
increase. A summary, of the Subcommittee discussions follows:
• Subpart Da design specification is 4 data points per hour (15 minute cycle).
Capturing Z data points per hour is considered an exception.
• Under Title IV, allowing Z data points per hour may be advantageous, especially for
calibration periods. For many systems, daily calibration of the CEM can be
accomplished in less than 30 minutes. Therefore, allowing Z data points for the
calibration period would result in fewer missing data periods across the year. In
contrast, requiring 4 data points for a valid hour may result in better estimates of
the hourly emissions.
i .
The Subcommittee split on whether Z or 4 data points should be required for a valid
hour.
* The Subcommittee agreed that variation of measurements within an hour is an
important consideration. However, Subcommittee members were not aware of any
studies on this issue.
Development of a Threshold
Several members of the Subcommittee thought that the use of an incentive- based
approach would be appropriate to encourage a smaller amount of missing data (more
complete record of emissions monitoring). As the discussions evolved, the concept of a
threshold for the number of missing data periods in a year was developed as a means to
simplify the selection of methods for filling in missing data periods as well as to provide
an incentive-based approach. A summary of the Subcommittee discussions follows:
Most Subcommittee members agreed that some threshold is required. Examples
included a minimum requirement of 90% or 95% data capture based on the total
number of plant operating hours per year. The Subcommittee did not reach an
* agreement on the exact threshold value.
• Most Subcommittee members agreed that more stringent methods for filling in
missing data periods may be required when data capture rates fall below the
minimum threshold.
* Most Subcommittee members agreed that the source would be given more
flexibility in the approaches used to fill in missing data above the minimum
threshold value.
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• A few Subcommittee members do not think a threshold is needed.
Methods for Filling in Missing Data
The Subcommittee discussed which techniques for filling in missing data are appropriate
and under what conditions they would be used. The Subcommittee members considered
statistical, parametric, and hardware methods for filling in missing data. A summary of
the Subcommittee discussions follows:
• The Subcommittee members agreed that statistical methods look promising for
filling in short-term data gaps.
• A suggestion was made to encourage the use of backup CEMs instead of statistical
or parametric methods.
• The Subcommittee agreed that maximum uncontrolled emission rates (MUERs)
must be addressed in the rule making, but should rarely be used in practice because
of the large number of available methods for filling in missing data.
* The Subcommittee generally agreed that a number of methods could be appropriate
depending upon the length of the data gap and plant operating conditions.
• The Subcommittee agreed to further evaluate which methods could be appropriate
tinder various operating conditions and data gap lengths.
3. UTILITY OF SUBPART Da REGULATIONS FOR TITLE IV
The topics discussed regarding the utility of Subpart Da regulations for Title IV emissions
monitoring included (1) procedures for the Relative Accuracy Test Audit (RATA) and
Relative Accuracy Audit (RAA), in particular the use of instrumental versus- wet -•
chemistry measurement techniques for comparison with CEM data; (2) quality of the test
gases used in the Cylinder Gas Audit (CGA) and daily Calibration Drift Check (CDC);
(3) a linearity test as part of the CGA; (4) criteria defining "out-of-control" for the daily
CDC; and (5) Relative Accuracy (RA) criteria for the RATA and RAA.
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TA Instrumental versus Wet Chemistry
Under Subpart Da, for the RATA and RAA, CEM measurements of emission
concentrations are compared to values measured using either instrumental or wet
chemistry techniques. It was suggested that the U.S. EPA consider limiting these test
methods to instrumental techniques only for Title IV.
Mr. Ralph Roberson (Science Applications International) presented a summary of findings
from the Utility Air Regulatory Group (UARG) on RATA results using both techniques
(wet chemistry and instrumental) versus only instrumental techniques (Document E1S).
Mr. Roberson stated that no distinct improvement (i.e., smaller values for RA) was
evident for tests using only instrumental techniques. Mr. Roger Shigehera (Entropy
Environmentalists, Inc.) also presented data on the consistency of CEM and instrumental
measurements in RATAs (Document E16); similar comparisons for wet chemistry
analyses were not available.
Several potential benefits of limiting the RATA and RAA tests to instrumental
techniques were identified:
greater consistency among emissions units, simplifying data reporting requirements
and inter-unit comparisons;
• faster turnaround time, allowing for more rapid corrective action — results from
instrumental analyses are immediately available, while results from wet chemistry
analyses are typically delayed several days;
• QA on both sampling and analysis, while wet chemistry methods provide QA on only
the analytical process; and
• lower costs — costs for wet chemistry analyses are approximately three times
those for instrumental methods, although it was observed that cost, by itself, would
not be sufficient justification for restricting the RATA or RAA to only
instrumental techniques.
Reasons cited for maintaining the current Subpart Da specifications, which allow either
instrumental or wet chemistry techniques, included the following:
* greater flexibility, and
possibility that instrumental techniques and CEMs have similar inherent biases,
although no data were presented to support or refute this hypothesis.
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In general, it was decided that more analyses were needed to (1) compare CEM,
instrumental, and wet chemistry results over a range of conditions (e.g., high and low
concentrations), (2) distinguish between measurement accuracy and precision, and (3)
examine the available round-robin test data collected in earlier studies on the accuracy
and precision of wet chemistry and instrumental analyses.
Quality of CCA and CDC Test Ca
General agreement was reached on the following:
• The specifications for commercial gases under Protocol 1 should be tightened to
provide reliable reference gases for the CGA.
• The U.S. EPA should implement auditing of gas manufacturers. Results from these
audits should be reported regularly but not used for formal vendor certification.
* Protocol 1 gases should be used for both the CGA and the daily CDCs. By
upgrading the test gases used for the CDC, CEM data will be certified on a daily
basis.
Prior to implementing the requirement for Protocol 1 gases for the daily CDC, the U.S.
EPA should confirm that the required daily use of Protocol 1 gases will not result in
excessive added costs relative to the benefits gained. Abo, it was suggested that the
U.S. EPA consider allowing triplicate measurements of cylinder gas with certified
methods on a regular basis, to confirm gas concentrations, rather than an absolute
requirement to use Protocol 1 gases for both the CGA and CDC.
Linearity Test in the CGA _ - -
Emission measurements must be accurate over the full concentration range to achieve
the objectives of Title IV. In addition, some units may experience relatively large
variations in emission concentrations (e.g., units with scrubbers). At present, the CGA
within Subpart Da requires testing with only two reference gas concentrations. It was
suggested that the U.S. EPA consider increasing this requirement to three or four gas
concentrations in order to confirm the linearity of the CEM response over the full
concentration range of interest.
The Subcommittee agreed that the concept of a linearity check within the CGA was
sound and appropriate, although further work was needed to define the exact
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specifications and protocols for such a test. The major conclusions from these
discussions were as follows:
• The reference gas concentrations used for the CGA must cover the full
concentration range of interest.
* A 3- or 4-point test would be appropriate for units that may experience large
variations in emission concentrations (e.g.* many units with scrubbers).
A 2-point test may be adequate, however, for units with smaller emission
concentration ranges.
» The Subcommittee should further investigate the utility of the 3-point
calibration/error test proposed by the U.S. EPA during earlier regulatory actions
for Subpart Da.
Out-of-Control Criteria for Daily CDC
It was noted that the term 'out of control" (OOC) used in Subpart Da was potentially
misleading, and perhaps should be changed to "outside the allowable range.*
Under Subpart Da, a CEM is considered OOC if the drift detected during the daily CDC
exceeds
• 4 times the system specification (2.5% of span for SO2 and NOX) on any given day,
or
• Z times the system specification over 4 consecutive days.
In the first instance, the CEM data are considered invalid (i.e., treated as missing data)
retrospectively from the time of the previous valid CDC (generally 24 hours earlier), and
prospectively, up until the problem is corrected and the CEM is demonstrated to be back
in compliance. In the second instance, where the CEM exceeds 2 times the
specifications over 4 consecutive days, the CEM data are considered only prospectively
invalid, from the time that the OOC is detected until it is demonstrated that the
problem has been corrected.
It was proposed that the U.S. EPA consider tightening the criteria for OOC to make
them similar to the current OOC specifications used by the State of Pennsylvania. In
Pennsylvania, a CEM is considered OOC if the daily drift exceeds 2 times the system
specifications on any given day. Data are considered invalid retrospectively (since the
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JO
preceding test) and prospectively (until the problem is corrected). No separate OOC
criterion is defined for drift over several consecutive days.
Data on CEM availability in Pennsylvania, presented by Mr. Joe Nazzaro (PaDER), are
similar to those for the United States as a whole, as presented at the January
Subcommittee meeting by the Utility Air Regulatory Group (UARG) and the U.S. EPA.
It was suggested, therefore, that the tighter OOC specifications in Pennsylvania result
primarily in greater attention to CEM maintenance and QC, rather than a measurable
increase in the quantity of invalid (missing) data. Specific analyses in support of this
conclusion were not available, however.
The Subcommittee was divided on the need for tighter regulations and the degree to
which the OOC criteria should be tightened for the daily CDC. Additional information
was requested on the following items:
• the frequency with which OOC conditions result from (a) lack of adequate CEM
maintenance or QC versus (b) fundamental equipment limitations and variability;
* how many additional missing data periods would result if the criteria for OOC
were tightened;
* how often and under what circumstances basic equipment or facility
characteristics would limit the achievable criteria for valid data; and
• the ultimate influence of tighter OOC regulations on the accuracy of emission
estimates for Title IV.
The Subcommittee agreed, in principle, that the OOC criteria and regulations should be
written to reflect the achievable system accuracy and precision in most units. Units or
systems which routinely cannot achieve these tighter limits, because of their basic
equipment or facility characteristics, should be treated as exemptions or separate
classes of units. The burden of proof for such exemptions would be on the facility
operator, although the U.S. EPA would identify general conditions under which these
exemptions apply. Examples of possible exemptions proposed include (1) units with low
emissions, (2) units that must be retrofit with CEMs, and (3) units with wet scrubbers. In
addition, the regulations should recognize natural constraints, such as inclement
weather, that may on occasion hinder the completion of the daily CDC.
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RA Criteria for RATA and RAA
Given the proposed requirements to use Protocol 1 gases for the daily CDC for Title TV,
failure of the quarterly audits and RATA was considered unlikely, occurring rarely if at
all. Most Subcommittee members proposed that CEM data be considered invalid
prospectively only, following the failure of a quarterly audit (i.e., exceedance of the
specified RA criteria for the RATA and RAA or accuracy criteria for the CGA). Some
members, however, also proposed retrospective data invalidation, deleting that portion
of the previous quarter's data for which data errors are suspected based on an analysis of
the daily CDC results (using protocols for defining missing data similar to those
currently used in Pennsylvania).
Further discussions on specific RA pass/fail criteria were postponed until the March
meeting. Additional data are needed on (1) the frequency with which CEMs would fail if
the RA criteria were tightened (see Document E15), (2) the potential effects of
tightening the OOC criteria for the daily CDCs regarding the frequency of failure during
quarterly audits, and (3) the degree to which RATA or RAA failures have resulted from
^•^
"" roblems with data accuracy versus precision.
4. COz MONITORING
The Subcommittee agreed that the basic monitoring requirements for CO£ should be
based on combustion equations. Further work may be warranted, however, to modify the
equations to account for the effects of some combustion technologies and control
devices on CO? emissions. It is expected that these modifications would be relatively
minor. It was suggested that the U.S. EPA conduct additional analyses comparing CO?
estimates from combustion equations and available CEM data.
In addition, it was generally agreed that the regulations should be written to encourage
the use of CO? CEMs, where possible, both for diluent monitoring and to provide CO?
emission estimates as required by Title vm. Concerns were expressed by some
Subcommittee members that (1) some CEMs use only O; as the diluent, (2) O? monitoring
may be more accurate and/or reliable than CO<> monitoring in at least some types of
systems, and (c) COz levels can be directly computed from CEM data on O?. The
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Subcommittee requested that members compile additional information on the relative
merits of Oz versus C0£ for diluent monitoring.
5. SUBCOMMITTEE ASSIGNMENTS FOR THE MARCH MEETING
Requests were made for the following papers/information:
U.S. EPA
• Strawman paper on recordkeeping and reporting of CEM data
* Overview of the available demonstrated alternative(s) to CEMs
• Specific proposal on procedures for 3- or 4-point linearity test for CGA
UARG
• Paper on alternative methods, concentrating on alternatives to CEM measurements
of emission concentrations for the March meeting, with a follow-up paper on
alternatives to CEM flow measurements planned for the April meeting.
Summary of results from continuing work on statistical methods for estimating
missing data
Pennsylvania OER
• Summary paper on Pennsylvania's approach to alternative methods
Ohio Edison
* Proposal for exemptions to the OOC criteria for the CDC for low-emitting units,
including background data and analyses in support of the proposed special
exemption criteria
Research-Cot trell Companies
* Background information on CEMs: (a) Oz versus COj diluent monitoring and
(b) monitor accuracy and precision capabilities for SOj and NOX
The next meeting is scheduled for March 20-22, 1991. Thus, the above papers must be
distributed no later than March 13. Richard Poirot has already distributed his written
summary of proposed uses for short-term CEM data, as requested at the prior
Subcommittee meeting (Document El 8).
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e Subcommittee meeting adjourned at 12:15 on February Zl, 1991. Nancy Wrona,
acting Subcommittee Chair, presented a summary of Subcommittee discussions to ,the
full ARAC Committee on February 22 (Document El7).
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M«mo—ARAC Continuous
Monitoring Subcommittee
February 26* 1991
f age 2
all tests) and omit those 11 results (6 — SO, and 5 — NO,) for which
relative accuracies cannot be r•computed. However, we do not believe that
th* distribution of relative accuracy results would change significantly
if this were don*.
Sine* intermediate value* are net reported for eix SO, and five NO, testa,
we could not compute percent mean difference for these 11 tests. This
explains why we plot 98 SO, relative accuracies (based on all tests) and
only 92 SO, percent differences (based on all tests). Likewise, we have
54 NO, relative accuracies (based en all tests) and only 49 HO, percent
differences (based on all tests).
If you have any questions concerning this aemorandua, please do not
hesitate to call.
RLR/ehw
Enclosures
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Systems Applications
International
4600 Marriott Dr.. Suita 42a Raleigh. NC 27112
919-782-1033 Facsimile 919-782-1716 ____
A Division of Qamem International Cocpoiaiion
Health
HgMORAMPPK
FROM i
DAZE:
SUBJECI:
ARAC Continuous Monitoring Subcommittee
Ralph L. Roberson, P. I.
February 26, 1991
Tra»smittal at Presentation Materials
At your request, we are submitting copies of the graphs presented at the
February 20, 1991 ABAC Subcommittee meeting. The graph* are based on data
presented in Appendix B of the Entropy Report.1
The first four graphs examine relative accuracy for SOj and NO, monitors.
Two graphs represent all relative accuracy tests, and two represent those
based on instrumental test methods (i.e., EPA Methods 6C and 7E).
Relative accuracy Lm computed by adding the absolute value of the reported
mean difference (|d|) to the confidence coefficient (CC) and dividing the
sum by the average reference method (RM) value.
The second four graphs examine only the mean difference (i.e., confidence
coefficient is not included) for SO, and NO. monitors. Again, two graphs
are for all tests, and two are for instrumental tests. Mean difference is
computed by dividing the absolute value of the reported mean difference
(I "31) by the average reference method (RM) value.
We provide one additional note regarding our handling of the data
presented in Appendix B of the Entropy Report. Wherever possible, we plot
relative accuracies based on "recalculated results" instead of "reported
results". That is, we recalculate relative accuracies by adding each
reported mean difference to its respective confidence coefficient and
dividing the sum by the reported reference method value. However,
Appendix B lists six SO? and five NO, relative accuracy test results for
which neither the test method nor intermediate values (e.g., RM, CC, etc.)
are provided. Since intermediate values are not available, we could not
recalculate relative accuracy result* for 11 of the tests. Thus, for
these 11 results (6 — SO, and 5 — NO,) we plot reported results instead
of recalculated results. If the Subcommittee believes it would be
helpful, we can regraph the SO, and NO, relative accuracy results (based on
1 Entropy Environmentalists, Inc., Accuracy and Reliability of CEMS at
Subtaart Da tEleetrie Otilitvj Facilities, prepared for EPA under
Contract No. 68-02-4550, Work Assignment 106A, March 1990.
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-------
CONTINUOUS EMISSIONS MONITORING
SUBCOMMITTEE
UTILITY OF SUBPART Da REGULATIONS
FOR TITLE IV
MAJOR TOPICS:
1. Subpart Da QA/QC Methods
2. Definition of Invalid Data —*• Missing Data
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GENERAL CONSENSUS TO MAINTAIN
4 BASIC QA/QC COMPONENTS
IN SUBPART Da
1. Calibration Drift Tests
2. Cylinder Gas Audit
3. Relative Accuracy Audit
4. Relative Accuracy Test Audit
-------
CALIBRATION DRIFT (CD) TEST
Frequency:
Purpose:
Approach:
Daily
Are CEM readings "wavering" over time?
Challenge CEM with low and high
concentration test gases
-------
CYLINDER GAS AUDIT (CGA)
Frequency:
Purpose:
Approach:
1 / quarter, 3 quarters per year
Are CEM measurements accurate?
Challenge CEM with known
concentrations of reference gases
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RELATIVE ACCURACY AUDIT (RAA)
Frequency:
Purpose:
Approach:
1 / quarter, 3 quarters per year
Alternative to CGA
Are CEM measurements accurate
relative to other alternative measurement
methods?
Compare CEM emissions measurements
to values obtained using alternative
measurement techniques (3 replicates)
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RELATIVE ACCURACY TEST AUDIT (RATA)
Frequency:
Purpose:
Approach:
1 / year
Same as RAA, but more extensive
Same as RAA
9 replicates, rather than 3
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REASONS FOR MODIFYING SUBPART Da
o Do the objectives of Subpart Da match those
for Title IV?
No flow specifications
Interested in wider range of emissions
o Is Subpart Da contemporary given today's
CEM technology?
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REFERENCE GAS QUALITY
ISSUE: Is test gas quality sufficient to ensure accurate
CEM data?
o Quality of test gas critical for accurate data
o Many test gases on the market not sufficiently reliable
o Consensus to tighten specifications for Protocol 1
gases, including EPA manufacturer audits
o Recommendation to use Protocol 1 gases for daily
CD test as well as quarterly CGA
o Accuracy of CEM data will be certified daily.
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REFERENCE GAS CONCENTRATIONS
ISSUE: Because OEMs-must accurately measure
emissions over a wide range under Title IV,
should the number of points checked in the CGA
be increased from 2 (Subpart Da) to 3 or 4?
General agreement that this is a legitimate issue
for Title IV regulation
Of particular concern for units with scrubbers which
could experience large variations in emissions
Further work needed by EPA to define specific
protocols for test and pass/fail criteria.
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TEST CRITERIA
ISSUE: Should the test criteria be tightened to encourage
better maintenance and higner data accuracy?
o Discussion of possible tightening of relative accuracy
(RA) specifications postponed until next month
o Discussion focused on daily CD test and definition of
out-of-control (OOC) periods (i.e., data invalid).
. Under Da, CEM is OOC if drift exceeds:
4 X spec for a given day
2 X spec over 4 consecutive days
o Proposal to tighten regulations similar to
Pennsylvania standard
Pennsylvania data availability similar to nationwide
p Subcommittee split on degree to which regulations
need to be tightened.
o EPA regulations should consider special categories
of sources, such as
Units with low emissions
CEM-retrofit units
Units with wet scrubbers
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C02 MONITORING
ISSUE: Should continuous emissions monitoring for
COa be required?
o Minimum requirement for C02 monitoring:
combustion equations
o Rulemaking could encourage use of COa CEMs.
o Questions remain regarding
Market availability of COa CEMs
Need for some modification of combustion
equations
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CONTINUOUS EMISSIONS MONITORING
SUBCOMMITTEE
MISSING DATA PERIODS
MAJOR TOPICS:
1. Appropriate Time Period for Accounting
2. Definition of a Valid Hour
3. Development of a Threshold
4. Methods for Filling In Missing Data
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PERSPECTIVES ON ROLE OF MONITORING
Perspective 1: Emphasis on calculation of annual tons
of S02 emitted
Perspective II: Emphasis on maintaining continuous
record of emissions
Implications:
o Selection of methods for filling in missing data
o Quality assurance/quality control (QA/QC)
procedures
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APPROPRIATE TIME PERIOD
FOR ACCOUNTING
o For CEMs an hour is appropriate.
o Other time periods may be appropriate for
evaluating alternatives to CtMs.
Subcommittee did not explicitly address
this issue.
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DEFINITION OF A VALID HOUR
ISSUE: What constitutes a valid hour?
More stringent requirements may result in
more missing data periods.
0 Subpart Da design specification is 4 data points
per hour. Capturing 2 data points per hour is
considered an exception.
o Subcommittee split on whether 2 or 4 data points
should be required for a valid hour.
o Allowing 2 data points per hour may be
advantageous, especially for calibration periods.
o Variation of measurements within an hour is an
important consideration. However, Subcommittee
members not aware of any studies on this issue.
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THRESHOLDS
ISSUE: Shquid thresholds be established for
distinguishing the types of methods used
to estimate missing data?
o Several members thought that the use of an
incentive-based approach would be appropriate to
encourage a smaller amount of missing data (more
complete record of emissions monitoring).
o Most Subcommittee members agreed that some
threshold is required. Examples included minimum
of 90% or 95% capture (total number of plant
operating hours per year). Agreement was not
reached on the exact threshold value.
o More stringent methods may be required to fill in
missing data when capture rates fail below the
minimum threshold.
o Unit would be given more flexibility in approaches
used to fill in missing data above minimum value.
o A few Subcommittee members did not think a
threshold is needed.
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METHODS FOR FILLING IN MISSING DATA
ISSUE: Which techniques for filling in missing data
are appropriate, and under what conditions
would they be used.
Subcommittee considered statistical, parametric,
and hardware methods for filling in missing data.
A suggestion was made to enc9urage the use of
backup OEMs instead of statistical or parametric
methods.
Subcommittee agreed that MUER must be addressed
in rulemaking, but should rarely be used in practice.
Subcommittee Generally agreed that a number of
methods could Be appropriate depending upon length
of data gap and plant operating conditions.
Statistical methods look promising for short-term
data gaps.
Subcommittee agreed to further evaluate which
methods could be appropriate.
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State of Vermont
AGENCY OF NATURAL RESOURCES
103 South Main Street
Waterbury, Vermont 05676
Department of Environmental Conservation
MEMORANDUM
TO: Members ARAC CEM Subcommittee
FROM: Richard L. Poirot
SUBJECT: Time Resolution for Reporting CEM Data
DATE: • February 19, 1991
CEM reporting and recordkeeping are scheduled for discussion at our March
meeting. The appropriate time resolution for data reporting is an important aspect of
this issue, which could potentially affect other ongoing discussions regarding missing
data and alternative methods.
The range between possible CEM output frequency, and the annual basis on
which SO? totals (and NOX rates) are assessed, spans some 5 to 6 orders of
magnitude*. A reporting requirement at the shortest end of this time continuum
(seconds or minutes) would pose an unreasonable burden on affected sources and EPA
record keepers, would quickly result in an unwieldy data base, and would be difficult
to justify in terms of any potential use of the data.
On the other hand, comparison with annual SO? allowances or NOX rates does
not constitute the exclusive purpose of the CEM requirement. If this were the case.
there are more cost-efficient means of determining annual emissions totals and rates.
The CO2 monitoring requirement illustrates this point, as only an annual emissions
total is required, and the Conference Committee Explanatory Statement makes it quite
clear that CEMs are not required for the purpose of deriving an annual total. Also,
the CEM opacity monitoring requirement has no direct relevance to any annual
allowance consumption; though it does not seem logical that opacity should be
monitored, but not reported.
Regional Offices • Barre/Essex Jct./Ptttsford/N. Spnngfield/St. Johnsbury
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My personal preference would be for reporting of CEM (or alternative) data as
hourly averages, submitted on a quarterly or monthly basis. In the long run, I
believe this will minimize the overall effort of affected sources and EPA record
keepers, and maximize the usefulness of the resulting database. It would also
EPA to conduct an effective and timely external quality assurance program,
though not specified in detail in the statute . would nonetheless be highly desirable to
assure the integrity of the emissions reductions and allowance trading program.
I believe that hourly emissions reporting is thoroughly justified by the
statutory language in Title IV alone , and is further supported by the additional needs
for such data in implementing the (state-run) Title V permitting program, and
particularly in fulfilling the many tracking or assessment responsibilities scattered
elsewhere throughout the Act .
Title IV Justification
The intended purpose of CEM equipment is unambiguously defined in section
402(7) as "to sample, analyze, measure, and provide on a continuous basis a
permanent record of emissions and flow. . . " Given the well-known capabilities of CEM
technology, it is not reasonable to assume that a continuous . permanent record be
composed of a series of annual or seasonal averages. Nor is it reasonable to assume
that this continuous, permanent record was intended to reside in a piecemeal and
inaccessible form in the private books of individual, affected sources.
The Title IV definition goes on to specify several exemplary units, including
"pounds per hour", leaving no question that Congress expected EPA to maintain an
emissions record of relatively short-term time resolution. In any event, this
definition leaves no doubt that if hourly emissions reporting was not precisely what*
Congress had in mind, it is certainly well within the range of EPA's discretionary
authority.
EPA Assessment Responsibilities (External to the Title IV Allowance Program)
If we accept that comparison with annual SO 3 allowances does not constitute the
exclusive purpose of the CEM requirement, and /"or that EPA at least maintains the
justifiable option of requiring short -term (hourly) emissions data, then it becomes
important to view Title IV in the context of other Clean Air Act requirements which
require consideration of emission quantities. If EPA fails to exercise its option of
requiring short-term data, will it be able to adequately fulfill these other important
assessment responsibilities?
It is instructive to consider here that the stated purpose of Title IV is not
simply to achieve a 10 million ton SO2 reduction, but rather "to reduce the adverse
effects of acid deposition. . . " The 10 million ton goal is not a scientifically determined
figure, designed to precisely eliminate all effects of sulfur and nitrogen emissions.
In truth, we don't know exactly what the benefits (or costs) of Title IV will be.
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Conceivably, we may get part way through the control program, and find a scientific
and political consensus that the last few million tons are not worth the cost.
Conversely, it may become apparent that 10 million tons are not quite enough, or that
the benefits could be substantially improved by slight alterations in the seasonal
timing or locations of emissions reductions.
By comparison to previous Clean Air Act amendments, the 1990 Act includes a
proportionally large number of tracking and assessment responsibilities (research.
monitoring, inventorying, modeling, source attribution, strategy development,
evaluation, reporting, etc.), many intended specifically to determine the changes in
air quality and effects which result from required emissions reductions. The number
and specificity of these required assessment activities is particularly overwhelming
in contrast to EPA's projected budget resources, and will require careful coordination
and efficient utilization of all available data resources.
Attachment A contains a listing of various required Clean Air Act assessment
responsibilities which would benefit from access to hourly emissions data. Many of
these require a direct assessment of the effects of emissions reductions achieved
under Title IV and other Clean Air Act control programs. Others may not refer back
to Title IV directly, but would nonetheless require (or benefit from) estimates (highly
uncertain) or measurements of hourly emissions of 862. NOX and/or opacity.
As a general rule, virtually every evaluation involving oxidant photochemistry
requires consideration of short-term emission rates. This would include any
assessment of ozone non-attainment (itself a 1 hour standard), and also evaluations
of sulfur transformation. transport and deposition (which are strongly influenced by
oxidant chemistry and other short-term variables). Short-term emissions data are
also obviously relevant to any effects which tend to occur on a short-term basis, like
episodic acidification of surface waters, visibility impairment and acute health or
ecological effects.
The list in Attachment A was developed using the "EPA Shoe" Test. That is.
I tried to put myself in EPA's shoes, assumed that it would be my responsibility to
conduct the required assessment, and asked if I would wish to have access to hourly
emissions data. This list includes those assessments for which the answer was yes.
Title V Permit Requirements
As a practical matter, it appears likely that the (state-run) Title V permit
program will also inevitably require emissions data expressed for short averaging
times, and that the necessary coordination between the Title IV and Title V permit
processes would provide additional justification for hourly data reporting under Title
IV. Many currently operative state permit programs require hourly CEM emissions
reporting and are likely to continue or expand upon these requirements in the future.
The affected sources under Title IV and Title V are the same, and Title IV permits will
need to be consistent with Title V requirements.
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I would recommend, however; that the necessary and important Title IV/Title
V coordination be treated'as a separate issue in our discussions, for several reasons.
First, this is a large, complex issue for which the data reporting requirements
represent a relatively small part. Second, I believe that an hourly reporting
requirement is fully justified without consideration of additional Title V information
needs. Finally, such discussion is likely to lead quickly to the more controversial
questions of whether emissions data collected pursuant to Title IV should or could be
used for determining compliance under Title V. This is an important question, but not
one for which the ARAC Committee is likely to reach a consensus of any use to EPA.
In any event, the possibility that short term data, if available, might be used
"inappropriately" for compliance determination, would not provide a defensible
justification for disguising the data by reporting only long-term averages.
RLP:ljl
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ATTACHMENT A
8PA ASSESSMENT RESPONSIBILITIES WHICH WOULD REQUIRE OR
BENEFIT FROM ACCESS TO SHORT-TERM (HOURLY) EMISSIONS DATA
Attainment and Maintenance
o 182(c}(l) Enhanced monitoring in "Serious" (.160-.ISC ppm) or worse ozone
nor.- attainment areas; requires states (following EPA rules) to "improve
monitoring of emissions of oxides of nitrogen."
o 182(1}(1)(B) Each state in a "multi-State ozone non-attainment area" shall
"use photochemical grid modeling" or other equally effective analytical
method.
c 184(d) For interstate "Ozone Transport Regions", EPA must promulgate
criteria for determining interstate source/receptor contributions, including
• "best availacle air quality monitoring and modeling."
c 18S(B) E?A/N'AS study on "role of ozone precursors in tropospr.eric ozor.e
formation ar.d control." Study shall examine roles of nox and voc emissions
redaction, extent to which NOX reductions rr.ay ' contribute to achievement of attainment in different non-attainment
areas . . . role of biogenic VOC emissions, and basic information required
for AQ models. .Report shall use "all available information."
c 190 EPA to issue guidance on RAC.M and 3ACM en various categories of sources
contributing to PM-1C ' non-attainment "taking into account emissions
reductions achieved or expected to be achieved under Title IV . . . ••
Hazardous Air Pollutants
o 301(k) EPA Research/Monitoring (in representative numcer of urban areas) en
Hazardous air pollutant effects from area sources, including acute and
chronic effects, consideration of atmospheric transformations which can
elevate public health risk, and role of such emissions as precursors to
ozone and acid aerosols. Report in three years; National Strategy in five
years (strategy shall provide for ambient monitoring and emissions
modeling).
o 301(a) EPA/NOAA assessment of atmospheric deposition of hazardous air
pollutants to Great Lakes, Lake Champlain, Chesapeake Bay and Coastal
Waters, including assessment of "sources and deposition rates of air
pollutants (and their atmospheric transformation precursors)." EPA report
in three years, then biennially, on above including sources of atmospheric
deposition to above waters, and description of any revisions of the
requirements, standards and limitations pursuant to this Act
necessary to assure protection of human health and environment."
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o 301(n)
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o 812 (Amending 312(a)) Formation of Council on Clean Air Compliance
Analysis. EPA/Council shall conduce "comprehensive analysis of the impact
of this Act on the public health, economy and environment of the Unites
States"; including limitations on SOX and NOX; considering costs and all
economic, public health and environmental benefits. EPA "to assure that
damage to human health and environment is more accurately measured".
EPA/Comnterce/Labor/Council report in 2 years and every 2 years including
future projections. Council to review data for use in such analysis and
make recommendations for use and methods to analyze such data.
o 812 (Amending 312(b)) GAO Report (in 2 years, then annually) on
"incremental human health and environmental benefits and incremental costs
beyond current clean air requirements of the new control strategies and
technologies required by this Act" including effects en jobs, energy
security, competitiveness in international markets, etc.
o 81S(a) EPA and affected states negotiate with Mexico to develop program to
monitor and improve air. quality in U.S./Mexico border regions. Monitoring
to include met data, air quality, emissions, "sufficient, to the extent
necessary to support use of state-of-the-art mathematical air modeling
analysis". Project emissions reductions to attain primary and secondary
NAAQS and other air quality goals. "Include to the extent possible, data
from monitoring programs undertaken by other parties."
c 81S(b) Negotiate to develop joint remediation measures ir. border region.
o 815(c) EPA annual reports on progress toward riAAQS in border region.
c 816 Amending Subpart 2. part C, title :. 169 3 (aj through
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Title IX Research . •
o 901(b) Amending 103(O through (f)
o (c) EPA program of research, testing and methods development for sampling,
measurement, monitoring, analysis and modeling including:
1} Considerations of individual pollutants, complex mixtures, and
transformations.
2) National monitoring network to collect data -(with—quar.tif.ication of..
certainty) in status and trends of emissions, deposition, air quality,
water quality, forest condition and visibility.
3) Develop improved methods of monitoring, analysis and modeling to
increase understanding of sources of ozone precursors, formation,
transport, regional influences, trends and interactions with other
pollutants
Improve ability to inventory emissions cf VOC and NOX
Improve understanding of reaction mechanisms through which natural
and anthropogenic emissions react to form ozone and other oxidants
4) Submit periodic reports (5 years) to assess effectiveness cf pollution
control regulations and programs.
c (e) E?A/HOAA/FWS/Ag research to understand short and Icr.g-terrn caus
effects and trends in ecosystem damage from air pollution includi
characterization of causes and effects sf chrsnis and episodic exposures at:
determination cf reversibility; development cf improved atmospheric
dispersion modeling and monitoring; assessments of short-term and long-c.erni
ecological effects cf acid deposition and other air pollutants on surface
waters...
o 901(c) Amending lCj(g) through (k) ' -
c (g) Improvements in non-regulatory strategies and technologies for
preventing or reducing multiple air pollutants including, SOX, NOX, metals,
PM-10, CO and CO2 from stationary sources including fossil fuel power plants
(shall be considered for new and existing facilities).
o (i) EPA report on coordination of 901 research with other programs (in 2
years, then every 4 years)
o (j) Continuation of NAPAP to review research status, identify information
needs, assure coordination among federal agencies to "ensure availability
and quality of data and methodologies needed to evaluate the status and
effectiveness of the acid deposition control program." Including research
and monitoring of
(i) Continuous emissions monitoring of acid deposition precursors.
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(ii) Maintain, upgrade and apply models, such as RADM, describing
interactions of emissions/ atmosphere and dose/response.
/
(iii) Costs, benefits and effectiveness of acid deposition control
program
Report every 2 years to include:
(1) Actual and projected emissions and acid deposition trends
(ii) Ambient concentrations of acid deposition precursors and
transformation products
(iii) status of effected ecosystems, including visibility
(iv) Causes and effects of such deposition
(v) Occurrence and effects of episodic acidification
i) Confidence level associated wish each conclusion
o 901 (g) EPA research, monitoring and annual reports on occurrence and
effects of acid deposition west of Mississippi River, including occurrence
and effects on high elevations, and utilizing predictive modeling techniques.
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JO
E 19
Central and South West Services, Inc.
OlM*: Ttiu 7S26W16*
February 13, 1991
Fax *
To: Larry Kertcher (202) 252-0892
David Hawkins (202) 783-5917
Henry Seal (201) 685-4120
Jerry Golden (615) 751-3561
Robert J. McWhorter (216) 384-5791
Daniel R. Plunley (518) 873-6675
Richard L. Poirot (802) 244-5141
Nancy Wrona (602) 257-6874
Robert Bergstroa (515) 432-7096
As agreed to at the last ARAC Eaissions Monitoring sub-committee
meeting in Washington, January 28, 1991, I am presenting for your
review and discussion an issue paper that merits consideration in
the CEMS rule making process. The paper represents the needs of
a large population of phase II affected gas units.
I would be happy to speak to any guest ion? next week at the
February ARAC meetings,
Yours truly,
N.N. Dharmarajan
(214) 754-1373
(214) 754-1380 (fax)
NND/»h
A Mamtoaf of tfta1 CMWV! Mid SouOt WMI Syvtwn
Cfrml Pom* and Ugnt Compwy • Pu»c S«vc* Compwiy * Owanoma • Sou0M*mm Etaetne Powir Company
• Tranio*. Inc. • VWwi Tnii UWittM Company
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ISSUE PAPER
CONTINUOUS EMISSION MONITORING EXEMPTION
FOR GAS-FIRED UTELTTIES
Presented to:
Hie Acid Rain Advisory Committee
Prepared by:
Radian Corporation
8501 Mo-Pac Blvd.
P. O. Box 201088
Austin, Texas 78720-1088
for
Central and South West Services, Inc.
1616 Woodall Rodgers Freeway
Dallas, Texas 75266
12 February 1991
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ISSUE PAPER
CONTINUOUS EMISSION MONITORING EXEMPTIONS
FOR GAS-FIRED UTILITIES
ISSUE
Gas-fired utility stations that fire fuel oil less than 10 percent of the time
should be exempted from the requirements of Section 412 of Title IV of the Clean Air
Act Amendments of 1990 (CAAA) to install continuous emission monitors (CEMs) for
the measurement of sulfur dioxide (SO}), volumetric flow rate, and opacity. Further-
more, the requirement of Section 821 of Title Vm of the CAAA to monitor carbon
dioxide (CCK) emissions should not be interpreted to mean that a GEM for CO2 is
required. Acceptable alternate methods for the measurement of these emissions are
*az available and should be allowed.
BACKGROUND
Section 412 of Tide IV of the CAAA requires that all sources subject to
the title install and operate CEMs on each affected unit for the measurement of SO^
volumetric flow rate, and opacity. Also, Section 821 of Title Vm of the CAAA requires
that each affected source shall monitor CO2 emissions, although no specifications are
made as •Ifct method of monitoring. Regulations for the CEMs must be issued not
later th^Hfcl+en months after enactment of the CAAA (by 15 May 1992). Phase I
affected m*,** defined by Section 404 of Title IV of the CAAA, must install and
operate CEMs not later than 36 months after enactment of the CAAA (by 15 November
1993). Phase H affected units, as defined by Section 405 of Title IV of the CAAA, must
install and operate CEMs by 1 January 1995. CEMs are defined as the equipment used
to sample, analyze, measure, and provide (on a continuous basis) a permanent record of
emissions and flow, expressed in pounds per million British thermal units (MM Btu),
1
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pounds per hour, or such other form as the EPA Administrator may prescribe by
regulations. Section 412(a) allows for the provision of "any alternative monitoring system
that is demonstrated as providing information with the same precision, reliability,
accessibility, and timeliness as that provided by CEMs...".
DISCUSSION
Phase I affected units are primarily coal-fired units, some of which will
benefit from the use of SO2 and volumetric flow rate monitors through the establishment
of the SO2 Allowance Transfer Program as provided by Section 403 of Tide IV of the
CAAA. Exchange of emission credits is expected to take place upon enactment of the
Phase I regulations, 1 January 1995.
All gas-fired units are included in the Phase n list These units, for the
.>
provide a reliable electrical supply, a majority of these units have expensive oil as a
backup fuel. Oil firing is typically less than one percent in any one year and occurs only
when gas supply is curtailed due to weather conditions. The contribution of such gas-
fired units to SO2 emission rates and opacity is an insignificant factor compared to units
which are primarily coal- or oil-fired (1).
SOT CQT tmd Volumetric Flow Rate
Gas-fired units should be excluded from the requirement of installing
CEMs for continuous monitoring of SO» and the requirement to monitor CO2 emissions
should not be interpreted to mean that a CEM is required for this purpose. Analyses
providing the sulfur and carbon content of the fuel, whether the fuel is fuel gas or fuel
oil, will provide data of equal or better quality than that provided by CEMs. NSPS
Subpan D already allows use of fuel analysis to monitor SO2 emissions for gas- and
fired units. Volumetric flow rate will be needed to quantify SO: and CO2 emissions.
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Fuel firtaf rate or unit load measurements can be substituted for a GEM for determining
volumetric^** rate. These analyses and measurements are generally already practiced
at most gas-fired utility stations and would seem to satisfy the requirements of precision,
reliability, accessibility, and timeliness for alternative monitoring systems.
The estimated cost for installing CEMs for SO» COj, and volumetric flow
rate, measurement is $ 173,000 per unit This cost includes the CEMs, sample delivery
and conditioning system, instrument housing, data logging or recording system, access
ladders and platforms, and certification. It does not include continuing costs for
calibration, maintenance, and reporting. EPA's National Utility Reference File lists 622
gas-fired units as of 1985 (2). An additional 161 units are planned according to the
Utility Data Institute (3). Therefore, installation of CEMs represent a capital expendi-
ture of approximately $135,000,000 for these units. These figures dearly demonstrate
that any benefits associated with the requirement to install CEMs to monitor SO* CO*
and volumetric flow rate on gas-fired units as opposed to using alternative monitoring
systems are far exceeded by the costs.
Opacity
Gas-fired units should be excluded from the requirement of installing
CEMs for continuous monitoring of opacity. There are no discernible visible emissions
from units fixing 100 percent natural gas. When a unit is firing fuel oil, several factors
have aa jlhfMB opacity, including sulfur and vanadium content of the fuel, upset
coadit&olHMifc at sun-up), and nozzle plugging. Nozzle plugging can be addressed by
a infiiliTiiaairi linn ( schedule and operator training. Many gas-fired utilities use the
practice of test fixing fuel oil for several minutes on a monthly or bimonthly basis to
ensure that the fuel ofl delivery, control, and firing system is operating property. This
practice keeps operators trained in oil firing procedures and oil fixing equipment
maintenance. Visible emissions during start-up with fuel oil represent, at this time, an
unsolvable problem. However, this is classified as an "upset* situation which occurs very
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infrequently and typically lasts less than 30 minutes. Opacity studies have indicated
opacity diptds directly on the sulfur and vanadium content of the fuel oil (4). Gen-
erally, units that fire low sulfur (less than 0.7 percent), low vanadium (less than 50 ppm
by weight) oil have opacities less than 15 percent Furthermore, the highest fraction of
the visible emissions from firing fuel oil results from the condensation of sulfuric add
(HjSO4), which generally occurs after the stack exit as the flue gas is mixed with ambient
air. A CEM measuring opacity in the stack will not detect this event
An alternative monitoring system for the measurement of opacity could
involve the services of a certified opacity reader during periods when fuel oil is being
fired, thereby providing the same level of precision, reliability, and accessibility as a
CEM. Frequency of measurement can be established by regulation to satisfy the level of
timeliness.
The estimated cost for installing CEMs for opacity measurement is
5105,000 per unit if installed independently of other CEMs. This cost includes the
CEMs, data logging or recording system, access ladders and platforms, and certification.
The total cost for instillation of* opacity monitors on 622 existing and 161 planned gas-
fired units is approximately $85,000,000. These figures dearly demonstrate that any
%.
benefits associated with the requirement to install CEMs to monitor opacity on gas-fired
units as opposed.to using an alternative monitoring system are far exceeded by the costs.
Therefore, gas-fired units should not be required to use CEMs to monitor opacity, since
data eta tginitably obtained by an alternative monitoring systems.
**
REFERENCES
1. AP-42, Section 1.4, Table 1.4-1. Uncontrolled Emission Factors for Natural
Gas Combustion.
2. National Utility Reference File, EPA, November 1989.
3. Utility Data Institute, Capital Expenditure File, July 1990.
-------
Sulfate Formation in Oil-Fired Power Plant Plumes, Volume 1, Final
Report, 1983.
T. -
-------
-------
E 20
February 12, 1991
TO: Members of Emission* Monitoring Subcommittee, ABAC
Re: Continuous Emission Monitors for Gas/Oil Units <10% Oil
Attached is a paper prepared to address the rationale and alternatives to
requiring continuous emission monitors on Sec. 403(h) units, i.e. that class of
gas/oil units which fire less than 10 percent oil.
As was discussed in the last meeting of the Emissions Monitoring Subcommittee,
there are a number of reasons to consider alternatives to continuous emissions
monitors for this specific class of units. While the time constraints in the
preparation of this document have kept us from providing all the details which
might be necessary in rulemaklng, ve feel that the framework and concepts upon
which the Subcommittee can make a decision are included.
If there are any questions which require further information or clarification,
we will be pleased to respond and provide that information to the Subcommittee.
Thank you for your consideration of this issue.
J.BL. Smith
Houston Lighting & Power Co.
P. 0. Box 1700
Houston, Texas 77001
(713) 922-2190
Wade Stansell
Texas Utilities Electric Co.
2001 Bryan Tower, Room 2070
Dallas, Texas 7S201
(214) 812-4814
cc:
Lertcher • EPA
tz - EPA
Clauasen - EPA
-------
-------
EMISSION MONITORING APPROACHES
Oil and Gas-fired Units Less Than 10 Percent Oil Consumed
i.
1.0 INTRODUCTION
The requirement for Continuous Emissions Monitoring Systems
(GEMS) on all affected units is designed to allow determination.
of the actual tonnage of SO2 and average NOx emission rate
emitted during any given year. On some affected units the CEMS
are also used for compliance with emission limitations*
Section 412 of the Clean Air Act Amendments of 1990 provides
for monitoring of opacity, SO* and NOx emissions and volumetric
flow from the stack to make the tonnage determination for SOg.
Section 412 also makes provisions for alternative methods of
monitoring the emissions from these units. The purpose of this
paper is to delineate alternative methods that, under certain
conditions, will provide the same tonnage information for SO2
and NOX emission rate and opacity as that provided by CEMS for
Gas/oil-fired units firing less than 10 percent oil. These
alternatives are appropriate since the Section 405 (h) units are
a class of unit which has relatively small contributions of S02
and NOx due to the fuel use, basic design and operating
capacity. The purpose of this paper is not to provide all of
the details of the methods but only a rudimentary understanding
of principles behind these methods.
alternate monitoring methods for SO2 are proposed
which depend upon the measurement of the fuel sulfur content
and the fuel flow to individual units or groups of units. The
three alternative methods are:
1) INPUT .METHOD
Periodic measurement of the fuel and sulfur input to
the plant or unit,
-------
2) THROUGHPUT METHOD
Continuous measurement of the fuel flow to each unit
and gross measurement of plant fuel sulfur content,
3} CONTINUOUS METHOD
Continuous measurement of fuel flow to each unit and
batch or continuous measurement of the sulfur con-
tent of the fuel to each unit.
Each of these methods has its usefulness depending upon the
particular configuration of the oil supply and delivery system
and the method of fuel oil circulation within the system.
Two alternate NOx monitoring methods are proposed which
depend upon 1) accurate characterization of the NOx emissions
over the load range and 2) characterization of the influence of
excess oxygen on NOx emissions. One alternate method of
monitoring the opacity during periods when oil is fired is
proposed that relies on the currently accepted EPA standard
visual observation method.
The following Sections provide insight into the rationale
for the potential use of these alternative monitoring methods.
Section 2.0 provides a discussion of the potential relative
accuracy requirements of the alternate SO2 monitoring systems
in terms of quantifying the national SOg emission tonnage on a
yearly basis. The rudiments of the three alternate SO2
monitor^sjg methods are described and some of the configurations
36f
for vbirfflfctfeftse may be used are listed. Section 3.0 provides
similar^tiscussions for alternate NOx monitoring methods.
Section 4.0 provides a brief discussion on the alternate
opacity monitoring method. Section 5.0 provides conclusions
related to the utilization of alternate monitoring methods for
gas/oil units firing less than 10 percent oil.
-------
2.0 SULFUB OZZDS EMISSIONS
2.1 Accuracy Requirements
Current CEMS requirements for Subpart Da units require that
each monitor be certified according to specific criteria for
relative accuracy and calibration drift. These requirements
have been in effect for more than a decade. The accuracy
criteria is based upon comparison of the CEMS output for a
specific emission specie (NOX or S02) compared to a reference
method. The allowable relative accuracy for certification of
a CEMS is permitted to be as high as ± 20 percent. Consequent-
ly, a CEMS which was certified at a relative accuracy of + 20
percent could conceivably report S02 emissions which were at
least 20 percent above the actual emission level.
It would be reasonable to assume that the CEMS certifica-
tion criteria for the 1990 Clean Air Act Amendments would be
nearly identical to those for units required to meet the
Subpart Da New Source Performance Standards provisions.
Consequently, due to the relative accuracy specifications on
CEMS the potential will exist for inaccuracies (as high as ± 20
%) in the estimation of the total SO2 tonnage for the US boiler
population if all boilers utilized CEMS. It is not certain
what the exact inaccuracies would be since not all CEMS would
consistently have inaccuracies on the high or low side of the
reference method. It is certain, however, that the average of
all reiafcjfcve accuracies for the US boiler population would not
*tr*
result VF^swro inaccuracies compared to the reference method.
For the sake of the following discussion, it is assumed that
the mean relative inaccuracy for the US boiler population is 10
percent.
Based upon the EPRI boiler database, it is estimated that
one third of the potential utility fossil fuel capacity in the
3
-------
US* is comprised of gas-, oil- or gas/oil-fired units. Of this
one third potential generation, only a fraction of these burn
both gas and oil. Furthermore, only a fraction of those that
burn both gas and oil regularly burn less than 10 percent.
Consequently, only a very small percentage of the potential
total US generation is represented by those units that burn
both gas and oil and burn less than 10 percent oil.
Due to the price differential between coal-fired generation
and gas and/or oil fired generation, coal-fired unit capacity
factors are generally higher than for gas/oil fired units.
Most large coal-fired units are base loaded whereas gas/oil-
fired units are cycled and are generally used to carry, the load
swings. The net result of this is that gas/oil-fired units
would represent only a small fraction (much less than 1/3) of
the actual total US electric generation due to their lower
capacity factor.
Most gas/oil units are located in metropolitan areas where
coal firing is less desirable. In the large metropolitan areas
the sulfur content of fuel oil is generally limited. In the
Los Angeles area and some northeastern metropolitan areas the
allowable sulfur content is much less than one percent (approx.
0.5%). In general, the sulfur content of fuel oils used by
utilities is less than the sulfur content for coals. If one
assumes that the average sulfur content for all units burning
oil is approximately 0.9 percent, then the emission rate would
be 1.0 J|»JIOCBtu (18,000 Btu/lb oil). Using this assumed rate,
one can estimate the relative contribution of the gas/oil-fired
units firing less than 10 percent oil to the total US SO2
tonnage under the most conservative conditions.
The conservative estimate can be made by assuming capacity
factors, and average emission rates for all coal and gas/oil-
fired units. In addition, by assuming that all US gas/oil-
-------
fired unit* fir* oil at a rate less than 10 percent, the SO2
contribution by these Section 405 (h) units is maximized. The
following Table provides assumptions for an extremely conserva-
tive estimate of the SOg emissions from gas/oil-fired units
firing less than 10 percent oil.
TABLE 2-1
ESTIMATE O7 SOj CONTRIBUTION
ASSUMPTIONS
FUEL TYPE COAL GAS/OIL
PERCENTAGE OF FUEL 100 90/10
CAPACITY, % of US Total 67 33
AVERAGE ANNUAL CAPACITY. FACTOR, % 60 30
SOj EMISSION RATE, Ib/MMBtU . 0.6. 1.0
802 CONTRIBUTION ESTIMATE
PERCENTAGE CONTRIBUTION 96.0 4.0
The results presented in Table 2-1 are only for the purpose of
providing an upper bound for the estimated SOg contribution.
The 4.0 percent contribution by units burning less than 10
percent oil is extremely conservative for the following
reasons:
1) Hot all of the non-coal fired units burn both gas
and oil, therefore, much less than 33 percent actu-
ally fire both gas and oil.
2) OjUy a nail percentage of the unite that do fire
gas and oil fire less than 10 percent oil,
•fore, the flection 405(h) units represent only a
small fraction of the actual US generation
IB less than the 33 percent assumed above)*
3) The emission rate is low for coal and high for oil,
therefore, the contribution for coal-fired units is
actually much greater than indicated.
Neglecting the fact that the emission rates are conservative.
-------
if it is assumed that 70 percent (high estimate), of the non-
coal fired units fire gas and oil and 50 percent of these fire
less than 10 percent oil, then the SQg contribution would be
less than 2 percent of the US total. It is believed that these
assumptions regarding the number of units burning less than 10
percent oil are very conservative as well and a more realistic
SO- contribution vould be more in the order of 1 percent rather
than 2 percent.
It is very unlikely that the accounting of all US SO2 emis-
sions for a particular yearly period vould have an accuracy of
± 2 percent much less ± 1 percent. This is particularly true
since the allowed inaccuracies for certified CEMs is ± 20
percent. In the end, even completely neglecting the S02
contribution from the gas/oil fired boilers that burn less than
10 percent oil would not detract significantly from the
accounting of the total US SOg tonnage. As a consequence,
relatively simple SO. accounting methods (other than CEMs) for
these boilers would be sufficient to estimate this 1 percent
SO2 contribution.
2.2 SOX Formation
Alternate methods for monitoring SOg emissions are depen-
dent upon the fate of the fuel sulfur. If the fuel sulfur
eventually leaves the boiler by paths other than through
gaseous emissions or if gaseous sulfur species (SO^) other than
SO, ar^present in large quantities, then the alternate
monitoMML methods described in Section 1 would not be appro-
^^»^ff^^
priate. Since the fuel sulfur content of natural gas is
essentially zero, there is no discussion of alternative methods
of monitoring sulfur dioxide emissions from the combustion of
natural gas. The following paragraphs illustrate the fate of
the fuel sulfur for oil combustion and demonstrate that for oil
firing, the alternate methods would be appropriate.
-------
Oil BO Teraation
The oil burned in utility plants today is a refined
product. In addition, the tolerance on certain constituents in
the oil can be held to reasonably close to specifications. As
mentioned previously, most oil fired utility boilers in
metropolitan areas fire relatively low sulfur oil. The sulfur
content is restricted by contract with the supplier and due to
the cost of desulfurization, the delivered oil is usually close
to the specified sulfur content (not significantly lower). As
a consequence, in most cases (but not necessarily all) the oil
delivered from one supplier has a relatively constant sulfur
content. Even in the case where the oil is delivered from
different suppliers to the same specification, the variation
between suppliers would not necessarily be significant.
The sulfur in a batch of oil is, for all practical purpos-
es, homogeneous. Furthermore, in most cases oil from different
batches is circulated within tanks and therefore becomes rela-
tively well mixed at some point in time. As a result of the
relatively constant oil sulfur content and the ability of the
oils to mix, the sulfur content of fuel oil does not change
significantly over short periods of time.
The ash content in fuel oils is generally much less than 1
percent (appro*. 0.1%), consequently, there is little opportu-
nity fcor sulfur capture as sulfates in the ash as is the case
with aj^ftV Fuel oil combustion, therefore, results entirely in
the
.tion of
and SOj. Generally, SOj formation from
oil combustion in utility boilers is in the order of 5 to 10
ppm or less than 0.00001 percent. Since there are insignifi-
cant amounts of sulfates and SOj formed during fuel oil
combustion, essentially all of the sulfur in the oil converts
directly to SO.. Tha sulfur content of fuel oil la. therefore.
a direct measure of the SO* emissions.
-------
1} Measure the fuel consumed over the monitoring period
by accounting for quantities on hand plus deliveries
minus quantities remaining.
2) Calculate the average sulfur content by a weighted
average of the sulfur content of quantities at the
beginning and end of the period vita those for the
contents of the deliveries.
3) Calculate the average fuel oil higher heating value
(HHV) by a weighted average of the HHV of quantities
at the beginning and end of the period with those
for the contents of the deliveries.
4) Calculate the SO- emission rate (lb/HX8tu) and the
total SO. tonnage during the period using the fuel
oil quantity consumed during the period and the
weighted average sulfur
heating value of the oil.
content and the higher
Throughput 8O« Monitoring Method
T Z
•v
Under certain circumstances, the measurement of .the total
quantity of fuel oil flow by the INPUT METHOD may not be as
accurate as necessary. This may be due to large tank capaci-
ties or the method of fuel oil supply to the unit. In these
cases it may be necessary to measure the fuel flow to the unit
rather than the net amount of oil in the tanJc(s). The major
difference between the IVPOT and THROUGHPUT methods is that
the actual fuel flow to the unit is measured by use of a
continuous fuel oil flow meter. The calculational procedure is
identical between the two methods.
The assumption is made that the potential inaccuracies
iBk'^y the measurement of the total fuel oil quantities
do not ntreduce significant inaccuracies in the weighted
average sulfur content of the fuels burned. It is assumed that
widely varying fuel sulfur content fuels are not delivered to
the plant for the reasons stated in 2.2.
10
-------
The proposed alternate THROUGHPUT METHOD so. monitoring
approach im as follows:
1) Measure the fuel flov consumed over the monitoring
period by utiliration of an in-line continuous flov
meter.
2) calculate the average sulfur content by a weighted
average of the sulfur content of quantities at the
beginning and end of the period with those for the
contents of the deliveries.
3} calculate the average fuel oil higher heating value
(HHV) by a weighted average of the HHV of quantities
at the beginning and end of the period with those
for the contents of the deliveries.
4) Calculate the SO. emission rate (Ib/KKBtu) and the
total' BO. tonnage during the period using the fuel
oil quantity consumed during the period and the
weighted average sulfur content and the higher
heating value of the oil.
Continuous 802 Monitoring Method
Under some situations, neither the measurement of the total
quantity of fuel oil flov from storage tanks nor the assurance
that the sulfur contents of various sources of fuel can be made
with certainty. In these instances, these measurements must be
made at the boiler inlet. As with the THROUGHPUT METHOD, the
fuel flov can be measured vita a continuous totalizing flov
meter. The measurement of sulfur content in the fuel can be
par f oraeil- -in a standard grab sample/ analysis method.
lie grab samples in the fuel line leading to the
boiler can be made as required. The frequency of sampling may
be dictated by the variability of the fuel sulfur supplied to
the storage tanks, the degree to which the storage tank is
mixed and the flovrate of the fuel oil. Not all of the samples
need be analyzed individually since all that is necessary is to
know the average sulfur content over a specified period of
11
-------
time. The individual samples can be accumulated and thoroughly
mixed prior to analysis at the reporting times.
The proposed alternate CONTINUOUS METHOD so2 monitoring
approach is as follows:
1) Measure the fuel flow consumed over the monitoring
period by utilization of an in-line continuous
totalizing flow meter.
2) Accumulate discrete in-line fuel oil samples at
specified times during the reporting period and mix
representative portions for all samples taken during
the period for analysis of the average sulfur con-
tent and the higher heating value.
3) calculate the SO- emission rate (Ib/HMBtu) and the
total 80. tonnage during the period using the fuel
oil quantity consumed during the period and the
weighted average sulfur content and the higher
heating value of the oil.
3.0 NITROGEN OXIDE EMISSIONS
Section 407 of the 1990 Clean Air Act Amendments addresses
the requirements for the Nitrogen Oxides Emission Reduction
Program. This section states that the applicability of this
section is for coal-fired units only. Emission limitations, are
specified in this section for tangential- and dry bottom wall-
fired units that burn coal. No nitrogen oxide limitations are
specified for gas- or gas/oil-fired units. Section 412
indicate^ that sources subject to the Title must install and
operatsjjj^MB for sulfur oxides, nitrogen oxides, opacity and
volumetric flow on each affected unit and that alternative
monitoring approaches may be approved by the Administrator.
By virtue of the fact that gas/oil fired units firing less
than 10 percent oil (Section 405 (h)) are affected units for
S02 emissions, Section 412 is applicable for these units for
12
-------
SO- emission, however, since HOx emissions are not regulated
for gas/oil-fired units under this Title, it is questionable
whether HOx monitoring should be required. The following
paragraphs briefly describe alternate NOx monitoring approaches
which could provide emissions information at least at the
accuracy level as that provided by CEMs.
3.1 Qas/OiT NOX Formation
HOx formation in utility boilers is a function of many
parameters. Some of the parameters are peculiar to the
particular boiler and cause the NOx emissions characteristics
to be unique to that particular boiler. These parameters are
related to the design of the boiler (tangential, wall-fired,
etc.) and cannot be changed without major changes in the
design, consequently, for a given unit, the NOx characteristics
are relatively constant. Other NOx influencing parameters are
related the type of fuel combusted and still others are related
to the mode of operation which generally is dictated by the
type of fuel burned.
In the end, the parameters that can change NOx characteris-
tics from a particular boiler are related to the type of fuel
burned. There are two basic types of NOx formation mechanisms
- Thermal NOx and Fuel NOx. Thermal NOx formation results from
the thermal fixation of atmospheric nitrogen. Fuel NOx results
from oxidation of the fuel-bound nitrogen. The contribution of
each ofTJfreie formation mechanisms is shown in Table 3-1.
13
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TABLE 3-1
CONTRIBUTION OF FORMATION MECHANISMS
70R UTILITY BOILER FUELS
FUEL FORMATION MECHANT8M
THERMAL NOX FUEL NOX
Natural Gas 100% 0
Fuel Oil " 70-80 20-30
Coal 20 - 50 50 - 80
For coal combustion, the influence of fuel-bound nitrogen is
the predominate source of NOx. For most fuel oils it is a
secondary source and for gas fuels it is not a factor.
The fuel properties for natural gas are, for all practical
purposes, invariant and contain virtually no sulfur or nitrogen
bearing compounds. Fuel oils, which are supplied with a
purchase specification for maximum sulfur content, usually
result in a relatively narrow nitrogen content variation. As
a consequence of the relatively constant fuel properties for
gas/oil-fired boilers, the NOX characteristics are relatively
easy to characterize for a given condition. In addition, these
KOx characteristics are very repeatable.
On gas/oil-fired boilers, the units are generally operated
in, more or less, fixed configurations at each load point.
This is primarily due to the operational factors that influence
heat r*£» and boiler efficiency. In these fixed configura-
tions, SpH major parameters that influence NOx formation are
the load point and the operating excess oxygen. Most gas/oil-
fired boilers are generally operated over the load range with
a excess oxygen curve set by the automatic boiler fuel/air
ratio controls. This results in near constant excess oxygen
levels at steady load conditions. Some variation exists in the
operating excess oxygen level dependent upon the steam tempera-
14
-------
ture control method and during times when the unit is operating
in a transient load condition. In most cases the excess oxygen
variation about the normal level varies no more that ± 0.5
percentage points in 02 and at the most by ± 1 percentage
point.
With the repeatable nature of NOx emissions from gas/oil-
fired boilers, it is possible to establish the NOx emission
rate characteristics by a periodic measurement of the NOx
versus load. The frequency of this NOx characterization
depends upon the alternate monitoring accuracy requirements.
Depending upon the degree to which 02 influences NOX emissions,
a characterization of this parameter may also be required for
a thorough emission rate characterization. The assessment of
whether 02 characterization is necessary is dependent upon the
slope of the NOx versus 02 curve. If the change in NOx over
the normal 0. excursion at a particular load causes the NOx
estimation to fall outside acceptable accuracy limits, then
this factor may need to be included. If, on the other hand,
the excursion results in a variation about the normal 02 point
of no more that i 10 percent, then inclusion of this factor may
not be necessary.
3.2 Alternate NOX Monitoring Approaches
Two alternate approaches are proposed which depend upon
adequate^ characterizations of the NOx emissions for both gas-
and oi^b^ing conditions. The frequency of these character-
izationsFVould likely be once per year or at a maximum twice
per year. The two approaches require differing amounts of
characterization depending upon the sensitivity of NOx to 02
excursions. They differ only in the necessity for character-
izing excess oxygen.
15
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Load CB«^e.qterizatien NOx Monitoring Method
The proposed alternate LOAD CHARACTERIZATION METHOD NOX
monitoring approach is as follows:
1) Perfora a thorough NOx versus load characterisation
using EPA approved methods at a ainiaua once per
. year.
2) Measure the gas fuel flov consumed over the morii-
toring period by utilization of an in-line continu-
ous totalizing flow aeter.
3) Measure the oil fuel flow by one of the three aeth-
ods described in the Alternate SO. Monitoring Ap-
proaches (section 2.3).
4) Continuously measure and record the unit load.
5) Calculate the. annual NOx emission rate by integrat-
ing the NOx versus load over the operating tiae for
gas and oil firing by weighting the emissions by
operating tiae on each fuel over the monitoring
period.
Load/O» Character!eation NOx Monitoring Method
If it is determined during the initial testing of the unit
that excess oxygen significantly influences NOx emissions at a
particular load/ this factor will need to be included in the
NOx characterization.
alternate LOAD/O, CHARACTERIZATION METHOD NOx
^B. ~ *
aonltozjng approach is as follows:
1) Perform a thorough NOx versus load characterization
using SPA approved methods at a minimum once per
• year. At each load point establish the o. character-
istics for an excursion at least 1 percent above and
.below the normal 0- set point.
-------
-77
2) Measure the gas fuel flow consumed over the moni-
toring period by utilization of an in-line continu-
totalieiog flow meter.
3} Measure the oil fuel flov by one of the three meth-
ods described ia the Alternate SO. Monitoring Ap-
proaches (section 2.3).
4) Continuously measure and record the unit load and O2*
S) calculate the annual NO* emission rate by integrat-
ing the NOX versus load and 0- characteristics over
the operating time for gas ana oil firing by weigh-
ting the emissions by operating time on each fuel
over the monitoring period.
4.0 ALTERNATE OPACITY MONITORING METHOD
Prior to the use of CEMs for monitoring opacity, EPA Method
9 was used to assess the opacity of oil-fired units. Due to
the relative small amount of time that oil is burned on these
Section 405(h) units, it would seem appropriate to again
utilize this as an alternate primary opacity monitoring method
during periods of oil firing. The method requires a trained
qualified observer to periodically visually determine the
opacity from the utility boiler stack. The Method 9 procedures
are delineated in 40 CFR Part 60, Appendix A.
Units that fire less than 10 percent oil are not likely to
constitute a serious opacity problem. This is particularly
true of units that fire gas and oil simultaneously. During
period *t time when these units are firing less than 50 percent
oil, ivfr extremely unlikely that opacity problems would occur
due to •olfur oxide plumes for any of the commonly used sulfur
content oils. In addition, since most units that burn oil in
metropolitan areas fire relatively low eulfur oil. Even under
conditions where 100 percent oil was fired it is not likely
that sulfur oxide plume opacity difficulties would occur. As
a consequence of these factors and the fact that opacity
17
-------
limitations are not specified for units under Section 405 (h),
installation of a costly CE« for monitoring opacity would
appear to be inappropriate. Method 9 could be used as an
assurance that opacity levels were maintained within local
required levels. As an alternative to the installation of a
GEM for opacity monitoring on units that fire less than 10
percent oil, Method 9 is proposed as the primary monitoring
method.
The frequency and appropriate periods of time to apply the
visual monitoring approach would be dependent upon the oil
firing scenario. Certainly under conditions where oil and gas
were fired simultaneously at an oil level less than 50 percent
monitoring would be inappropriate. In most instances where the
sulfur content was less than 1 percent it may also be inappro-
priate. The following is a proposed method to ascertain the
need and frequency of visual opacity monitoring.
1) Through controlled tests over the load range estab-
lish the opacity levels under typical gas/oil firing
coaditioas.
2) Determine the conditions under which opacity levels
exceed federal or local standards or other appropri-
ate criteria. ...
3) Bstablish the conditions under which opacity moni-
toring is appropriate.
4) Bstablish the frequency of monitoring for the ap-
ipopriate operating conditions.
Under the title, there are no limitations for opacity. In the
absence of this limitation, some criteria would have to be
developed to determine when monitoring was appropriate. If it
was determined that regular opacity monitoring was not warrant-
ed based upon the above procedure, an annual re-certification
of the opacity characteristics would likely be sufficient.
18
-------
Under other conditions visual monitoring might be required only
during periods which could result in exceedences of the opacity
criteria.
5.0 CONCLUSION
As the Clean Air Act Amendments (CAAA) of 1990 are pres-
ently written, installation of expensive CZMs is required for
all affected units. Ostensibly the Amendments are designed to
reduce SO* and NOx emissions from coal-fired boilers. The
Amendments recognize that units firing oil can contribute
emissions as well and therefore under Sections 405 (e) , (f) , (g)
and (h) allowances for S02 are specified. Under Section 407 no
limitations on NOx emissions are specified for the aforemen-
tioned units under Section 405. The amendments recognize that
the emissions of SO£ and NOx from coal fired units is the major
concern. As indicated in Section 2.1 of this report, units
under CAAA Section 405 (h) represent much less than 1 percent of
the S0g emissions from the total US boiler population.
Furthermore, there is no NOx emission limitation on these
units. Nevertheless, the requirements of CAAA Section 412
presently require expensive CEMs to monitor both S02 and NOx on
these units even though NOx has no limitation and SO* emissions
from these units are less than 1 percent of the total US
emissions (much less than the measurement accuracy of CEMs) .
Installation of a complete CEM on a gas fired unit could be
as higJJ^a $300,000 (1990 $) . In addition, maintenance,
supplieir and administrative reporting associated with the
monitor would amount to $30,000 or more per year. For a 15
year monitor life, this would amount to a typical utility
annualized cost of approximately $87,000. on a dollars per ton
monitored basis for a 250 MWe gas/oil fired boiler firing less
than 10 percent oil, this is in the order of $275/ton. This is
approximately 15 times the cost for a similar coal-fired unit.
19
-------
Baaed upon this significant disparity and the small SO,
contribution from units under Section 405(h) to the total us
S02 emissions, it is appropriate that other less expensive
monitoring approaches be used on these units.
Based upon the small S02 contribution and the fact that NOx
emission and opacity limitations are not addressed for units
that fall under Section 405(h), the following alternate
monitoring requirements would seem appropriate for these units:
1) Monitor SO. emissions based upon the sulfur content
of the fuel oil and measurement of the fuel usage
for the monitoring period.
2) Wave the monitoring requirement for NOx emissions
for this class of boiler.
3) Establish opacity monitoring requirements based upon
EPA Method 9.
Adoption of these alternate monitoring methods would supply (H|
information as accurate as that supplied by OEMs at a much
smaller dollar/ton monitored cost. In addition, it would
eliminate the need for the use.of volumetric flow measurements
which may introduce more inaccuracies than the alternate
monitoring methods.
Use of the alternate monitoring methods proposed does not
detract from the intent of the Clean Air Act Amendments of
1990. ftAe* the coal-fired units are the major contributors to
^f»
both t^KMu and NOx and since units under Section 405(h)
jfy *
contribute 802 l€Vttls *ar lesfl than the accuracy of the present
monitoring methods, these proposed alternate monitoring methods
will not result in estimates of the emission rate or annual
tonnage that are measurably either over or under the true total
US levels.
20
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ISSUE PAPER — E21
PROVISIONS FOR ALTERNATIVES TO
CONTINUOUS EMISSION MONITORS (CEMS)
March 13, 1991
I S SOB PRESENTED
This paper discusses criteria and procedures that could be
applied to alternative monitoring systems seeking approval under
Section 412. The paper is being presented for discussion; none of
the options herein are being endorsed by EPA at this time. ARAC
members are encouraged to • present other options they think
appropriate.
INTRODUCTION
Section 412 (a) requires each affected unit to have a full
complement of emission monitoring equipment. A unit is an affected
unit if it is subject to any emission reduction requirement or
limitation under Title IV. Table 1 lists the affected categories
of units.
Each category listed in Table 1 would be required to install
a full complement of monitors as described in Section 412 (a) (S02,
NOX, opacity, and volumetric flow) . Depending upon the NOx
>nitoring requirements of Title IV, a diluent (O2 or C02) monitor
also be required.
Section 412 (a) directs the Administrator to establish
demonstration criteria for alternative systems that meet the
criteria specified with the same precision, reliability,
accessibility, and timeliness. An alternative monitoring system
is a CEMS in which any or all of the named monitors have been
replaced with equivalent emission measurement and data reduction
techniques .
ALTERNATIVE DEMONSTRATIONS
The objective of the alternative regulations is to provide
guidance concerning permissible alternatives and to minimize the
need for large scale case-by-case evaluations.
Who Makes the Demonstration?
Section 412 (a) directs the Administrator to specify the
requirements for CEMS and alternative systems demonstrated to be
the same as CEMS in the four attributes discussed in the
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Equivalency Considerations below. It is assumed that the
demonstration is made to the Administrator. Though the wording of
the Act may be interpreted to mean demonstrated by an affected
source, there is no preclusion as to the Administrator's own
demonstrations. Who may make a demonstration runs from a single
affected source, industrial group, or the Agency (including
States). Because the "who" is not defined, the legislation would
allow the Administrator to specify avenues for demonstrations.
Specifying how demonstrations could be made will reduce the number
of demonstrations and maintain order in the allocation process
while achieving the national reduction goals. The regulation may
specify acceptable alternative demonstration programs afforded
affected units. Alternative demonstration programs may be made on
a:
• case-by-case unit specific basis. This has been the
historical procedure of the Agency, e.g., NSPS Subpart Db
for NOX monitoring;
• representative testing applied to a class or category
of affected units. A demonstration may be made for an
alternative monitoring system with applicability to a
defined category of like units. This successful
demonstration, by industry or EPA, would be limited to
the specified category. The EPA would have the latitude
to define the class or category based on Table 1 or sub-
sets of Table 1 by criteria such as pollutant, size, fuel,
control equipment, etc. The validation protocol mentioned
in a later section addresses this demonstration. Any
source not included in the category would be afforded the
case-by-case option;
• administrative determination. The Administrator could
specify acceptable alternatives based upon historical
information on alternative demonstrations.
The regulations would specify who may make a demonstration and
how the demonstrations can be made.
Approval by Whom"?
Section 412(d) implies that the alternative monitoring systems
must be approved by the Administrator. Historically this authority
has been delegated to afford orderly functioning of Agency actions.
The demonstrations must be conducted prior to the date a GEMS
system is required to be installed and certified. For purposes of
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e Act this date is November 15, 1993 for Phase 1 sources and
nuary 1, 1995 for Phase 2. Approximately 2,000 potential
alternatives could be applied for within the next four years.
The approval process may consist of three phases: the initial
application, performance testing, and final approval. The initial
application must be submitted to the Agency. The latter two steps
would need to be coordinated with the Agency depending upon the
Agency's desire for process efficiency and to have certification
observers present.
The regulations should clearly identify the organization in
EPA responsible for administering and receiving demonstrations,
approval authority over the demonstrations, and certification
authority for all CEMS and alternative methods. The regions and
States, as proposed in the original overall program framework
paper, would act as the field observers and preliminary reviewers
of the demonstrations and certifications. They would make findings
and recommendations to the specified authority . on acceptance or
rejection. The Region and State activity is predicated on intra-
and interagency agreements; but operated in this manner a
nationally consistent deliberation and approval process would be
maintained.
EQPIVALENCY CONSIDERATIONS
Section 412(b) and (c) of the Clean Air Act (the Act) require
generators subject to the Phase l and Phase 2 limitations of Title
4 to install and operate CEMS, quality assure data, and keep
records and reports in accordance with regulations issued under
(a). Section (a) requires the Administrator to specify the
requirements of CEMS by regulation within eighteen months of
enactment. The Administrator must also specify requirements for
any alternative monitoring system that is demonstrated as providing
information with the same precision, reliability, accessibility,
and timeliness as that provided by the CEMS. The requirements for
alternatives may also specify limitations on the use of
alternatives as are necessary to preserve the orderly functioning
of the allowance trading system and assure the reductions called
for in th« Act.
The Act's definition of a CEMS system includes the pollutant
monitor, effluent flow monitor, and the data system to create on
a continuous basis, a permanent record of the emissions. For
alternative requirements developed by the Administrator, the system
includes pollutant and flow such that the reported units are on a
mass per unit of time basis.
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It*
The Act specif les that an alternative monitoring system is only
approvable if it is demonstrated to meet the four criteria of
equivalency established by CEMS. Those criteria in terms of the
GEMS must be established in order to judge an acceptable
alternative. Those criteria and "Webster's Ninth New College
Dictionary" definitions are:
Precision - The degree of refinement with which an
application is performed or a
measurement stated;
Reliability -The extent to which an experiment, test, or
measuring procedure yields the same results
on repeated trials;
Accessibility - Capable of being used or seen or ability
to obtain or make use of;
Timeliness - Appropriate or adapted to the times or
the occasion, coming early or at the
right time.
These definitions must be augmented to conform to the
conventions of CEMS as practiced over the last two decades.
Specifically, reliability has also come to include the availability
of the monitoring system. This should be retained in our
definition of reliability. In addition, timeliness and
accessibility may not be mutually exclusive.
The Act states, "with the same," preceding these criteria.
This should mean that the alternative system is capable of being
placed in a one-to-one correspondence (equivalent) to the CEMS.
; The Act does not prevent the Administrator from imposing other
requirements for possible alternatives. Substitute data systems,
quality assuring data, and recordkeeping and reporting data are
applicable at all times and equally apply to CEMS and their
alternatives.
In th« context of paragraph (a) , successful demonstrations of
alternatives should be required to meet the capability of the CEMS
in fulfilling these requirements under the general criteria above.
The alternative requirements to be proposed should also
incorporate the Agency policy that BO exemptions to the monitoring
requirements of Title 4 will be allowed. A successful
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(J -J
. . a
•;
onstration should not be interpreted as an exemption to the CEMS
equirements, e.g., fuel monitoring'of natural gas for SO2 emission
monitoring.
Precision. Reliability* Accessibility*and Timalineaa as Defined
bv the GEMS and Plov Monitoring
Pollutant Monitors
The proposed requirements for Acid Rain contemplate that the
pollutant monitors should first be capable of meeting the accuracy
requirement as detailed in the regulations. In addition, the
monitors must be linear across the range of potential measurements.
The pollutant system should probably have an hourly continuous
measurement capability. The reporting requirements contemplated
require quarterly submissions of daily accumulations based on the
1-hour records. The data, and reliability of the monitor, would
be required to be demonstrated over a 16 8-hour test where no
adjustments to the system are allowed. In addition, QA is required
to assure continued monitor reliability, quarterly and annually.
The results of pollutant monitor certifications, relative
accuracy audits, relative accuracy test audits, cylinder gas
audits, and retrievals from AIRS/AFS on monitor availability have
shown that-the current pollutant compliance monitoring systems for
^ SPS Subpart Da, over long periods of time and repeated tests, are
eliable. The pollutant monitors routinely pass the short-term
relative accuracy requirements and have availabilities greater than
95 percent. The contemplated requirements would also require that
the pollutant monitors not exceed the design drift limitations on
a 24-hour basis.
Flow ..Monitors
The probable availability is expected to be similar to that
achieved by the pollutant monitors above. The accuracy of flow
monitoring systems appears to be approximately 5 percent.
Preliminary information indicates that some monitors currently meet
this requirement. Additional data is being obtained.
The -requirements contemplate initial certifications for
accurate measurements over the range of flows and reliability
assurances on a periodic basis.
Accessibility and timeliness appear to be the same as for
pollutant CEMS.
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Opacity^ ftpnitors
Opacity monitors are used widely for NSPS (proper operation
and maintenance) and SIPs for compliance with opacity limitations.
These systems provide 1-minute averages based on six or more data
points equally spaced over the minute. Their availability has been
documented to be greater than 98 percent. Design requirements
specify that they be accurate to within 3 percent over the range
of emission measurements (calibration error). The resolution of
the measurements are to be to the nearest 0.5 percent opacity.
The opacity monitoring systems are limited in application.
They are not applicable in effluent streams that contain water
droplets and do not measure opacity forming downstream of the stack
exit.
The contemplated requirements for Acid Rain will require the
installation of opacity monitors where no current requirement
applies. The . systems must meet the current performance
specifications required of NSPS or the SIP, which ever is more
stringent. Opacity limitations currently required of the unit will
continue. Recordkeeping and reporting will be consistent with the
current NSPS or SIP requirements for existing and new
installations.
Data Acquisition^Systems
The data management system requirements of the regulations
discussed in another paper would:
• require the maintenance of all emission-related measurements
on site;
• require quarterly reports of summarize quality assured data;
• require reporting of the data in some type of electronic
media.
The paper further states that, the state of the art process
control and accompanying computer equipment allow operators of
combustion and other process equipment to sample, record, and
analyze a large number of process parameters. This greatly
enhances the timeliness and accessibility attributes of the GEMS.
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An alternative is something that can be approved in place of
the GEMS. The alternative must provide information with the same
attributes as described for the combined pollutant CEMS and flow
monitoring system required of the unit. This must be demonstrated.
precision
A current-emission.measurement validation protocol provides
two statistical tests which must be satisfied in order to show
equivalency on a system basis. The document is entitled, "Protocol
for the Field Validation of Emission Concentrations from Stationary
Sources" (protocol). . Briefly the proposed alternative must
demonstrate a precision equivalent to the validated method (F-
test) and an accuracy (t-test) test showing there is no bias at the
80-percent confidence level. If the bias is shown to be
statistically significant a correction factor is evaluated, but
cannot be outside the range of 0.90 to 1.10.
This field demonstration program would address the equivalent
accuracy and precision of the alternative monitoring system under
field conditions to the CEMS. In the protocol, 18 samples (9
pairs) are obtained and compared. The F-test and t-test analyses
are independent of the time between sampling and the emission
1 eveIs at which the sampling is conducted. The field test could
e conducted over the range of emissions that occur in some time
frame, e.g., 48 hours.
Other protocols may also be referenced by the rules for certain
applications. Test Method 19, Determination of Sulfur Reduction
Removal Efficiency and Particulate Matter, Sulfur Dioxide, and
Nitrogen Oxides Emission Rates, could be referenced appropriately
for alternative systems that would be incorporating fuel sampling
and analysis. These requirements would be in addition to the
precision and accuracy test mentioned above.
This fuel sampling and analysis protocol only covers coal and
oil, and has the limitation of not being an as fired system.
Sampling and analysis results do not necessarily reflect what coal
is actually being burned. This is due to the practice of bunkering
fuel for combustion. The regulations should specify "as fired"
sampling. An additional protocol for natural and fuel (refinery
process) gas fired generators would need to be provided.
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8
Reliability
The CEMS and flow monitor system requirements specify a
continuous demonstration of reliability, at a minimum, on a 24-
hour basis (accuracy within 2.5 percent of a known reference
value). Zn addition, the reliability must be initially
demonstrated over a 168-hour test in which no adjustments are made
to the system. A similar test could be conducted on the
alternative system. A time period could be established over which
no adjustments to the alternative system could be made. The output
of the system would be checked against the CEMS/flow system output.
Continual reliability of alternative systems (QA) must provide
the. same assurances as established by the CEMS. In general the
rules should specify that alternative systems must provide data
validation procedures, data reduction procedures and recalibration
procedures. The rules would specify the data validation criteria,
the . minimum data reduction procedures and recalibra.tion
requirements.
There are no specific Federal criteria that could be cited.
In general the regulation may be framed around the following:
• For alternative systems employing parameter monitoring;
Data Validation. Data must be considered invalid if
any of the following conditions occur:
a. The equipment being used to monitor the parameter
is not operated in accordance with the manufactures
requirements,
b. The equipment being used to monitor the parameter
is not being maintained in accordance with the
manufacturers specifications,
c. The parameter monitoring equipment is inoperative,
d. The monitored process is not operating.
- Data Reduction Criteria:
a. All averages must be calculated using valid data
only,
b. A one-hour average will be considered valid only
if it contains 100 percent of the readings of all
parameters used in the calculation,
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- Maintenance Requirements:
a. Minor maintenance. Any maintenance done that
does not effect the integrity of the parameter
monitor. Requirement for a calibration check prior
to and after maintenance,
b. Major maintenance. Any maintenance that would
effect the integrity of the parameter monitor.
Recalibration of the equipment upon completion of the
maintenance or repair.
Periodic Recalibration. The recalibration of the
parameter monitor shall be conducted on a quarterly basis.
• For systems using fuel sampling and analysis the QA may
. include the analytical QA published by ASTM in addition to the
following;
Data Validation Criteria
a. Criteria for daily composite unit samples.
j|t b. Criteria for daily composite system samples.
c. Criteria for laboratory sample analysis
- Data Reduction Procedures. These would be the same a
for CEMS and parameter monitoring.
Maintenance Requirements. Besides manufacturer
requirements the rules may have:
a. Requirements for the sulfur analyzer.
b. Requirements for the calorimeter.
c. Requirements for the sample acquisition system.
d. Requirements for the sample preparation system.
Periodic Recalibration. Quarterly recalibration
through performance specification testing.
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10
Accessibility
In the case of the GEMS and flow system, the generator is
expected to obtain and use quality assured data on a 24-hour basis.
The information is available on site. Systems that would require
longer periods are not equivalent.
Timeliness
The GEMS system includes the data acquisition system. Every
hour on the hour an emission rate is permanently recorded for Acid
Rain. On a 24-hour period the data is quality assured. The data
then becomes available. Adjustments are automatically injected to
the permanent record, e.g., substitute data, as flagged by the
system as it monitors the performance of the GEMS. At the end of
each 24-hour period and quarter, the data is summarized and
available within the CPU time of the data acquisition system.
These timeliness criteria must be matched, with the alternative
systems established to monitor the data inputs to the system and
quality assurance checks of the system.
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11
Tabl* 1. Affected Source Categories
category
All units named in Phase I
All units with a nameplate capacity equal to or
above 75 Mve and annual baseline emission rates
greater than 1.20 Ibs/mmbtu
All coal or oil fired units with nameplate
capacity less than 75 Mwe and annual baseline
emission rates greater than 1.20 Ibs/mmbtu
All coal fired units with annual baseline
emission rates .less than 1.20 Ibs/mmbtu .
All oil and gas fired units with annual baseline
emission rates equal to or greater than 0.60
Ibs/mmbtu
All oil and gas fired units with annual baseline
emission rates less than 0.60 Ibs/mmbtu
All oil and gas fired units consuming less than
10 percent oil per annum
All new units commencing commercial operation
between 1986 and December 31, 1995
Any process source or combustion unit that elects
into Phase I or II
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Issue Paper - Reporting and Recordfceeping of £22
Continuous Emissions Monitoring (GEM) Data
SSUE
What are the appropriate content, frequency, and form for the
reporting and recordkeeping of continuous emissions monitoring
(CEM) data as required by the acid deposition control program
provisions of the 1990 Clean Air Act Amendments (CAAA)?
INTRODUCTION
Section 412 of the 1990 CAAA mandates EPA to specify
requirements for the reporting and recordkeeping by affected
sources of various types of CEM (or equivalent alternative
monitoring system) data for each of their affected units.
These CEM data include:
• Sulfur dioxide (SO2) emissions,
• Nitrogen oxides (NOJ emissions,
• Opacity, and
• Volumetric exhaust gas flow.
For ease of discussion, the term "CEM data" will be used
roughout this paper, although it is intended to include data from
Iternative monitoring systems judged to have the "same precision,
reliability, accessibility, and timeliness as CEMs.")
EPA needs accurate and timely CEM data to fulfill its
Congressionally mandated responsibilities to:
. • Determine whether an affected unit's emissions during a
given year exceed its SO2 allowances and/or NOX emissions
limitation.
• Implement the Act's excess emissions penalty and offset
(Sec. 411) and enforcement provisions (Sec. 414).
• Ensure achievement of the annual 10 million ton SO,
reduction and the mandated reduction of NO (Sec. 401 and
Sec. 404-407).
• Develop numerous reports to Congress on assessments and
program evaluations of the changes in air quality,
visibility, and acidic deposition effects resulting from the
S02 and NOX emissions reductions (Titles IV, VIII, and IX).
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While the statute delineates the applicability and scope of
the CEM data reporting and recordkeeping requirements quite
clearly, it' appears to leave much of the specific content
(including the appropriate time resolution for data reports and
records) as well as the frequency and form of reporting to EPA's
discretion. Our objective in this issue paper, therefore, is to
set forth options for each of these parameters for consideration by
the Subcommittee for Emissions Monitoring (Subcommittee) of the
Acid Rain Advisory Committee (ARAC). To facilitate focused and
fruitful discussion, we will attempt to relate these reporting and
recordkeeping parameters both to the Act's purposes and to EPA's
mandated responsibilities.
DISCUSSION OF REPORTING AND RECORDKEEPING OPTIONS
Preliminary discussion during the ARAC meetings indicates some
confusion may exist about the relationship between recordkeeping
and reporting in EPA's traditional CEM data collection require-
ments. To the extent possible, this paper attempts to clearly
delineate one from the other. Under Subpart Da New Source
Performance Standards (NSPS) and subsequent federal and state CEM
regulations, EPA has required affected sources to maintain records
of pollutant concentration and opacity measurements (or approved
surrogates for these) necessary to assure compliance with
applicable emissions standards. EPA has required these sources to
report only a small subset of the actual data generated and
recorded by CEMs—only those data necessary to make a compliance
determination, assist in regulatory development, or otherwise
needed for implementation of the air pollution control program.
EPA can require the sources to submit additional information from
their CEM data records, however, when reports indicate potential
noncompliance or when supplemental information is needed.
The same philosophy will apply to reporting and recordkeeping
under the acid deposition control program provisions of the 1990
CAAA: EPA will require only those data elements needed to ensure
compliance with the CEM regulation and to perform its
Congressionally mandated responsibilities listed previously.
Emissions-related data not reported to EPA should be retained by
the sources for a limited period of time (e.g., three years) for
on-site review by federal and state inspectors and for assessment
and program evaluation purposes. Records will be available for
collection and review through Section 114 authority under the Act,
as well as to the public through the Freedom of Information Act
(FOIA) process.
Our discussion of considerations for CEM data report and
record contents (i.e., data elements and the appropriate time
resolution) is organized into three sections around the monitored
pollutant emissions and conditions: (1) S02 emissions, (2) flow,
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and (3) NO emissions. Opacity has been omitted simply to
streamline the articulation of the key acid deposition precursor
emission reporting and recordkeeping issues. Opacity will be
onitored and probably reported to EPA, although no compliance
etermination will be made under the acid rain rule. (Title IV's
requirement to monitor opacity might possibly be related to
visibility for sources located near national parks or in Clean
States.)
In addition to discussing the rationale for various proposed
reporting and recordkeeping requirements, each section presents our
initial thoughts on "strawman" templates for the reporting of CEM
data. Our goal is to develop standardized templates that will
interface with many (or at least the most advanced) CEM automated
data acquisition and handling systems (DAHSs) and will accommodate
all the allowed combinations of primary/approved alternative
system/substitute data methods that may be employed to account for
a unit's SO2 and NO, emissions throughout the year. Admittedly,
this is an ambitious undertaking as there are numerous DAHSs and
many combinations of potentially acceptable methods for emissions
data capture and estimation. . .
Our strawman templates focus on the allowed data combinations
for SO, and NOX emissions, as defined by the following
possibilities:
• CEM/equivalent alternative monitoring systems for measuring
S02 and NOX pollutant concentrations.
• Flow monitor/alternatives to flow monitor for converting
pollutant concentration measures into measures of mass
emissions per unit time.
• Substitute data methods for filling in missing CEM-and/or
flow data
- Statistical estimation
- Parametric methods
- Other backup monitoring methods/systems
- Application of minimum data availability threshold (s).
EPA is in the process of analyzing whether CEM DAHS report
generation software in use today can be characterized into a
manageable set of generic classes. If it can, perhaps tailored
versions of the standard templates could be created for automatic
interfacing with CEM DAHSs. (EPA is considering the possibility of
offering user-friendly, ready-to-install, PC-based software to
facilitate the preparation of accurate CEM data reports by sources
who elect to use electronic transfer.)
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A related issue, involves the computation and reporting of
pollutant emission rates by sources operating continuous emissions
rate monitoring systems (CERMSs). A CERMS is defined to consist of
pollutant concentration (SO, and/or NO ) monitors (PCMs), a flow
rate monitor (FRM) , and a data recorder to measure and provide
permanent records of SO2 and/or NOX emissions. (We have identified
at least seven coal-fired and four other utilities that have been
operating CERMSs for a year or longer.) The primary question is
whether and how the DAHS combines FRM data (in scfh) with PCM data
(in ppm) to calculate hourly pollutant emissions rates (in Ib/hr).
Do the FRM and the PCM(s) have separate DAHSs or does integrated
system software calculate pollutant emissions rates directly? The
answers to these questions could have important ramifications for
the CEM data templates.
The last two sections address the frequency and form for
reporting under the acid rain rule which, most likely, would be
consistent across the various types of CEM data.
SO, Emissions
The reporting and recordkeeping of S02 emissions are pivotal
to the stated purpose of Title IV, "to reduce the adverse effects
of acid deposition through the reductions in annual emissions of
sulfur dioxide of ten million tons ... and, in combination with
other provisions of this Act, of nitrogen oxides emissions of
approximately two million tons .... It is the intent of this title
to effectuate such reductions by requiring compliance by affected
sources with prescribed emissions limitations by specified
deadlines, which limitations may be met ... by an emission
allocation and transfer system."
Implicit in this goal and crucial to the success of a market-
based allowance trading program for S02 emissions are two
principles that have been deliberated in previous Subcommittee
discussions and papers: ....
• Need for 100% Accounting of SO2 Emissions
(
• Need for Quality Assured CEM Data.
In addition, EPA needs accurate and timely reports on CEM data, as
well as ready access to supporting emissions-related records, to
measure progress towards achievement of the mandated annual 10
million ton SO2 reduction and to assure compliance with the Title's
innovative and flexible SO, emissions source control program. These
requirements underscore the importance of another principle that
has been alluded to, but not discussed, within the Subcommittee:
• Minimization of Errors in CEM Reports.
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In the paragraphs which follow, we discuss the implications of
these principles for the reporting and recordkeeping of S02
issions.
Need for 100% Accounting of S0: Emissions. EPA needs a complete
(100%) accounting of a unit's S02 mass emissions in tons to develop
a cumulative annual total for comparison with the allowances it
holds. If the tons of SO2 emitted exceeds the allowances and the
unit is not using an alternate compliance method such as a Phase Z
extension technology or repowering, the Act's excess emissions
penalty and offset would be applied. Further, as discussed
previously in the Missing Data Periods Issue Paper, we expect the
accounting of a unit's annual S02 emissions to include estimates
and/or other substitute data during periods when CEM measures are
not available—at least for units that do not maintain redundant
CEMs.
Several of the concepts discussed (and, in some instances,
agreed upon) by the Subcommittee within the context of missing
data appear pertinent to the consideration of reporting and
recordkeeping for SO2 emissions. These concepts include:*
• An hour is the appropriate time period for the accounting of
CEM data.
• Use of an incentive-based approach with data capture
thresholds would encourage a smaller amount of missing CEM
data and, thus, provide a more complete record of actual
measured emissions. Examples of threshold values included
90* and 95% of total unit operating hours per year.
• An estimate of "probable actual emissions" based on a
statistical evaluation of available CEM measurements would
be used for filling in missing data above the threshold.
e Alternative approaches being considered for filling in
missing data would depend on the length of the data gap.
Statistical methods , for estimating emissions appear
satisfactory for short data gaps of a few hours1 duration.
• The frequency of data gaps could also influence the
determination of acceptable methods for filling in missing
data.
These principles for S02 emissions accounting suggest the
following: an hour would be an appropriate time increment for CEM
data recording; and reports should contain sufficient information
on CEM data gaps and the methods used to fill them for EPA to check
the validity of substitute data when appropriate.
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Need, for Quality, Assured CEMData. The Subcommittee reached
general consensus on the importance of accurate CEM; data for SO2
emissions accounting and agreed to maintain the basic quality
assurance (QA)/quality control (QC) procedures of NSPS subpart Da
for the acid rain rule. Two of the concepts discussed within the
context of quality assuring CEM data appear germane to reporting
and recordkeeping:
• Accuracy of CEM data should be certified daily. Using
certified or Protocol 1 gases for daily calibration drift
(CD) tests would accomplish this.
• CEM data recorded during periods when the monitor is deemed
. out-of-control (OOC) by daily CD tests are not valid for
emissions accounting. Thus, CEM OOC periods become missing
data periods.
These QA/QC principles suggest the following: a day would be the
appropriate time resolution for CEM data reporting; reports should
contain sufficient information on daily CD tests and OOC periods
for EPA to confirm the validity of CEM data; and reports should be
filed periodically, say, on a monthly or quarterly basis, so that
any apparent discrepancies noted in EPA's checks can be reviewed
with the source and resolved in a timely manner. Periodic reports
would also facilitate the orderly administration of the Acid Rain
Allowances and Emissions Data Systems and the sharing of timely
information with the regulated community and other potential
stakeholders in allowance trading market.
Minimization of Errors in CEM Reports. Another pertinent
observation for reporting and recordkeeping that has surfaced
during previous Subcommittee discussions is the surprisingly high
incidence and severity of computational errors plaguing calculated
data in source-generated CEM reports. This is one of the major
conclusions of a study by Entropy Environmentalists, Inc., of
quarterly relative accuracy test audit (RATA) reports submitted by
Subpart Da sources during 1988 and 1989. This study, which was
reviewed by both EPA and the Utility Air Regulatory Group (UARG),
indicates that EPA should require the reporting of actual measures
(e.g., ppm SO,, ppm KOx, scfh exhaust flow rate, etc.) comprising
the calculated units of the emissions standards (i.e., tons/yr SO2/
and Ib/MMBtu NOJ—at least initially until the accuracy of the
sources1 computational procedures can be confirmed. The Entropy
analysis shows that 24% of the reported CEM relative accuracy (RA)
values contain significant computational error and 8% deviate from
the correct value by one-third to over 300%.
Moreover, the risk of computational error is substantially
higher in the algorithms for combining CEM pollutant concentration
measures with volumetric exhaust gas flow measures (or equivalent
PRELIMINARY DRAFT FOR ARAC
DISCUSSION DOES NOT REPRESENT THE POSITION OF
U.S. ENVIRONMENTAL PROTECTION AGENCY
-------
70
alternative measures) to yield estimates of SO2 mass emissions per
unit time. The computation of CEM RA involves the addition of two
eras, divided by a third term; whereas the computation of tons of
O2 emitted per year involves the use of two different equations
(depending on whether the pollutant concentration and flow measures
are taken on the same or different moisture bases) with as many as
five multiplicative terms.
A related objective is to reduce, and hopefully eliminate,
computational and other software-generated errors in reports and
records from DAHS1 computers integral to CEM systems (GEMS).
Experience shows that CEM data produced by the most accurate and
reliable pollutant monitors are meaningless if the emissions
information is processed incorrectly. Typical computational
blunders and software misspecifications which EPA and state
agencies have observed include: use of "dry-basis" algorithms to
calculate emissions in terms of the standard (i.e., Ib/MMBtu) from
in-situ or "wet-basis" monitors; and substitution of the average of
30 discrete 24-hour averages for a true 30-day rolling average
(i.e., the average of all valid hourly data over the last 30
operating days). '
Developing report template software that interfaces
automatically with common CEM DAHSs should reduce the incidence of
such errors. Another approach, which EPA is evaluating, is to
develop DAHS certification test and audit procedures designed
specifically to uncover incorrect algorithms and other programming
rrors. Some states have reported finding major software errors
uring audits (See Document E23).
Strawman Template for SO^ETnisslons-.JtepQrting. Table 1 presents
our initial thoughts on how the principles for SO, emissions
reporting discussed above might be combined into a standardized
template. One of the notes to this table refers to a sample Header
Report, which is displayed as Figure 1. Insofar as possible, EPA
hopes
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(3) Daily calibration checks, daily zero and span drift
checks, adjustments, and maintenance performed on
CEMS \
(4) Periods when CEMS is inoperative
(5) Hourly: pollutant concentration (ppm), diluent
.concentration (t 02 or C02), exhaust flow rate
(dscf/hr), calculated Ib/hr (SO2).
(6) Daily: fuel characteristics (average sulfur and
heat content) and usage (tons or gallons per day);
to provide periodic independent check against CEMS.
It has been suggested by some that EPA consider developing
standardized templates for CEM data records (as well as CEM data
reports) so as to ensure the availability of consistent and useable
short-term emissions data for the Congressionally mandated acid
deposition control program evaluations and assessments which may
require or benefit from such data. (Attachment A of.a Memorandum
to the Subcommittee by Richard Poirot, Vermont Department of
Environmental Conservation, on Time Resolution for Reporting CEM
Data, dated February 19, 1991, lists these studies.)
Flow
Traditionally, CEM data has been reported in pounds of
ollutant per unit of heat input (Ib/MMBtu), ppm, or micrograms per
ic meter. Under Title IV, however, volumetric flow data are
required to compute each unit's S02 emissions in tons/year for
comparison with the allowances it holds. Such data are also needed
for levying the Title's excess emissions fee and offset against
units who do not have "balanced books" at the end of the year.
Flow data would also be required to convert a unit's annual NOX
emissions rate into tons, should the Act's penalty provision
(expressed as $2000/excess ton) apply. In addition, units
participating in the annual NO, emissions averaging pools allowed
under Sec. 407 (e) may also need to develop estimates of NOX mass
emissions in tons.
As in the accounting of a unit's annual SO2 emissions, we
expect the accounting of a unit's annual volumetric exhaust gas
flow to include estimates and/or other substitute data during
periods when flow measures are not available. The Subcommittee,
however, has not yet addressed the issue of missing flow data.
The principles enunciated under SO, emissions for 100%
accounting, accurate and quality assured data,.and minimization of
errors would also appear to apply to the reporting and
recordkeeping of flow (or alternative methods to convert pollutant
PRELIMINARY DRAFT FOR ARAC
DISCUSSION DOES NOT REPRESENT THE POSITION OF
U.S. ENVIRONMENTAL PROTECTION AGENCY
10
-------
concentration measures Into mass emissions measures). The
alternative methods to flow monitors that have been mentioned
informally within the Subcommittee (e.g., heat input, feedwater
flow rates, steam flow rates, etc.) would add greater complexity,
however, to standardized reporting templates. These alternatives,
although not shown as yet to be equivalent to flow monitors,
generally employ different 'units of measure than flow monitors and
involve different computational procedures for the determination of
SO2 mass emissions per unit time. Heat input, for example, "which
is typically measured in MMBtu/hr, would be combined with SO2
pollutant concentration measures on a Ib/MMBtu, not ppm, basis to
yield S02 mass emissions per hour. ; ';'
Table 2 is a strawman template for the reporting of flow (or
equivalent) data. This template and the strawman template for SO2
emissions, shown previously as Table 1, illustrate one approach
that would accommodate the reporting of the heat input alternative
method, although it has not^ been demonstrated to be equivalent to
CEM and flow monitor systems for estimating SO, mass emissions per
unit time.
Supporting records to be maintained by the sources for flow
reports might include:
(1) Stack inside diameter (ft)
(2) Calibration checks, adjustments, and maintenance
performed on flow monitor
(3) Periods when flow monitor is inoperative
(4) Hourly: average stack temperature (°F), average
gas exit velocity (ft/sec), and stack gas
volumetric flow (scfh).
(5) Daily: average stack gas moisture content (%}.
Some of these data elements (i.e., Items 2, 3, and parts of 4)
would not be germane for certain alternative methods that have been
mentioned.
NO Emissions
The reporting and recordkeeping of NOX emissions are obviously
important to the Act's stated purpose, quoted previously. The
accounting of KOX emissions may not need to be as stringent,
however, as that described for S02 emissions for the following
reasons:
PRELIMINARY DRAFT FOR ARAC
DISCUSSION DOES NOT REPRESENT THE POSITION OF
U.S. ENVIRONMENTAL PROTECTION AGENCY
11
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• There is no explicit requirement for a cumulative annual
total of NOX emissions from each affected unit. ,
• The emissions allowances and transfer system does not
presently extend to NOX.
• The NOX emissions source control program adheres generally
to EPA's traditional method of specifying applicable
emissions standards.
The treatment of missing data for NOX emissions may also
differ from that prescribed for S02 emissions. (The Subcommittee
has not formally discussed the issue of missing NOX CEM data.)
Since the statutory limitation is expressed as an annual average,
it appears that some consideration may be given to the impact of
discrete (small) data "pieces" on the overall average. It may be
argued that a small amount of missing data, say, 5% or less could
be tolerated for NOX emissions for units not participating in the
annual emissions averaging pools allowed under Sec. 407(e). On the
other hand, some estimating rules will be needed for all NO
emissions and to gauge progress towards achievement of the annual
NOX reduction.
Table 3 is a strawman template for the reporting of NO,
emissions. While it closely resembles the strawman template for
SO2 emissions, shown previously as Table 1, there are two notable
exceptions:
• Average daily NOX emissions must be calculated on a
Ib/MMBtu basis, corresponding to the units of the
standard, as well as reported on a ppm basis.
• No requirement exists for the calculation of total daily
NOX emissions in Ibs or tons. (This exception will
probably not apply to units averaging their emissions
with others.)
Table 3 contains a column for measures from an equivalent
alternative monitoring system (EAMS) although no candidate
alternative systems or methods have been identified for NOX
emissions.
Supporting records to be maintained by the sources for NOX
emissions reports would probably be similar to those listed for S02
emissions.
Frequency of Reporting
As discussed under SO2 emissions, periodic reports—probably
on a monthly or quarterly .basis—are essential to the orderly
PRELIMINARY DRAFT FOR ARAC
DISCUSSION DOES NOT REPRESENT THE POSITION OF
U.S. ENVIRONMENTAL PROTECTION AGENCY
13
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administration of the Acid Rain Allowances and Emissions Data
Systems and to the timely resolution of apparent discrepancies
(noted in EPA's data quality checks) with the sources. Monthly
reporting would lead to more efficient and cost/effective
administrative processing at EPA, primarily by avoiding periodic
(albeit predictable) "crunches" of processing relatively large
batches of CEM data. Also, monthly reporting would enable the
sources' CEM operators to keep current with the reporting
requirements and minimize time spent "re-learning" the process. On
the other hand, quarterly reporting is used in most state CEM
programs and, as such, represents the de facto standard. A few
programs (i.e., Connecticut, Washington, and California - Bay
Area), however, already have monthly reports and others have
indicated that monthly reporting would be preferable to the current
practice (See Document E23).
Form of Reporting
EPA wants to encourage and facilitate the use of electronic
reporting, via either a PC-floppy diskette or a modem with a toll-
free "1-800" telephone number, since this form has proven to be a
feasible and efficient method for ensuring timely and accurate CEM
data in several state programs. EPA is considering offering user-
friendly, ready-to-install, PC-based software containing the
standardized report templates (with built-in data edit checks and
HELP screens) to assist the sources in preparing accurate automated
CEM data reports. States could use this software as the "core" for
their CEM reporting requirements, adding and/or modifying data
elements as needed. User Manuals, Easy Reference Cards, and
program documentation would be included with the software, possibly
to be packaged as "self-installation" CEM data report kits.
We have discussed this approach with several states, and they
enthusiastically endorse the concept. Further, we intend to
solicit recommendations from different kinds of sources (with
varying levels of CEM experience) on the types of user interfaces,
data edit checks, software interfacing protocols, etc., that would
be most helpful. Any suggestions made by members of the
, Subcommittee or other ARAC participants would be most welcome-
particularly if they come within the next few months as we develop
functional specifications for the EPA Acid Rain Allowances and
Emissions Data Systems.
Figure 2, Acid Rain Bulletin Board, depicts one method for the
electronic transfer of automated CEM data reports from the sources
to EPA. Although EPA's Acid Rain Emissions Data System, like the
Aerometric Information and Retrieval System (AIRS), will probably
reside in a mainframe computer, PCs would be used to "buffer"
emissions data submitted via modem and to process data on floppy
diskettes. The PCs could employ an electronic bulletin board
PRELIMINARY DRAFT FOR ARAC
DISCUSSION DOES NOT REPRESENT THE POSITION OF
U.S. ENVIRONMENTAL PROTECTION AGENCY
15
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system to log receipt* of data and perform minimum QA checks before
uploading to the,mainframe system database.
Under this scenario, the mainframe software could produce an
"echo" report of the emissions data and header information as
received from each source, QA'd, and tabulated for entry into the
EPA Acid Rain Emissions and Allowances Data Systems. The reports
would then be sent back to the sources, either electronically
through the bulletin board or transmitted in hard copy form through
the mail, for review and verification. Such an "echoing" procedure
would not only eliminate electronic transcription errors, but also
assure the sources' concurrence with data in EPA's databases.
PRELIMINARY DRAFT FOR ARAC
DISCUSSION DOES NOT REPRESENT THE POSITION OF
U.S. ENVIRONMENTAL PROTECTION AGENCY
17
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£23
State Agency Experience in Data Recordkeeping and Reporting
The following draft chart summarizes information from state agencies on various CEM
reporting and recordkeeping issues. These issues include the time resolution of data in
reports, the frequency of reports, the use of hard copy or computerized data, the use of
automated data handling systems, the degree of errors in reporting, and the use of flow
monitor data. The chart will be updated as further information becomes available.
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Baseline Tons of SO, (1985) for Selected Categories of Affected Unit* Under Tttte IV
Category of Units
Alt units with nameplate capacity
<7SMW • . .
Units with nameptate capacity
<75MW and baseline emission rate
>l.2lb/MMBtu
All oil- and gas-fired units
(<50% coal-fired)
Oil- and gas-fired units consuming
< 10% oil per year
Number of Units
639
194
859
525
Number of Tons SO,
665.569.72
575.943.94
592.258.00
7626.36
Source: National Mlowane* OaubaM
Preliminary Draft for ABAC Discussion
Does Not Represent the Position of the U.S. Environmental Protection Agency
-------
Presented at 1983 Engineering Foundation Conference
Pocono Hershey Resort, PA
COAL SAMPLING AND ANALYSIS
AS AN ALTERNATIVE TO CONTINUOUS EMISSION MONITORING
IN PENNSYLVANIA
Joseph C. Nazzaro
Department of Environmental Resources
Harrisburg, PA
On August 1, 1979, the Pennsylvania Department of Environmental Resources
promulgated regulations which implemented the EPA requirements of 10/6/75 (40 FR
46240} concerning the preparation, adoption and submittal of implementation
plans for emission monitoring of stationary sources. The regulations included
requirements for installation of SO. continuous emission monitoring systems
(CEMS's) on solid-fossil-fuel-fired combustion units having greater than 250.mm
Btu/hr heat input (83 sources, representing approximately 75% of all SO.
emissions in the State). Also included was a provision allowing the Department
to use the data from the CEMS's to determine compliance with SO.
emission-averaging standards for daily and running 30-day time periods.
•to
In addition to general regulatory requirements, three references were cited
Oich provided the specific requirements. Two of the references (40 CFR 51 and
CFR 60) existed as parts of the Code of Federal Regulations. The third
reference, the Continuous Source Monitoring Manual (Manual) was developed by the
Department and contained the administrative procedures for obtaining approval of
monitoring installations, additional performance testing requirements,
recordkeeping and reporting requirements and quality assurance requirements.
In response to "industry requests, the Department developed general requirements,
design and performance specifications, performance test procedures, submittal
requirements, recordkeeping and reporting requirements and quality assurance
requirements for coal sampling and analysis systems (CSAS's) to be used as
alternatives to SO- CEMS's. On April 21. 1981, these items were added to the
Manual and the Department's regulations were amended to allow use of CSAS's to
meet regulatory requirements for SO. emission monitoring.
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-------
110
COAL SAMPLING AND ANALYSIS AS AN ALTERNATIVE
TO CONTINUOUS EMISSION MONITORING SYSTEMS
IN PENNSYLVANIA
INTRODUCTION
The request to allow use of CSAS's. in place of CEMS's raised three
main concerns in DER--
l. The data would not be real-time and, thus, of little use in managing
emissions to avoid violations of SO2 standards.
2. Such systems would be difficult to audit for continued accuracy and
repeatability.
3. EPA, while indicating that CSAS's could be used, "reserved" the section
of the Code which would provide the requirements for CSAS's. Although
ASTM procedures for obtaining gross samples of coal existed, they
were not directly applicable to a CSAS required to produce data for ,
direct comparison with a stationary combustion source SO2 emission
standard for enforcement purposes.
Upon consideration of the first two concerns, it was decided that the
increased response time and difficulty in auditing would be acceptable only if
CSAS's could provide data that could be applied to the emission standards in a
.manner identical to CEMS's.
With respect to the third concern, it soon became evident that some
design and performance specifications would have to be developed and other,
existing specifications modified in order to serve the Department's purpose.
DESIGN SPECIFICATIONS
The decision to develop design specifications in addition to performance
specifications was made in order to avoid a "black box" approach to CSAS's. Adherence
to general design criteria, it was hoped, would increase confidence in the CSAS
repeatability and would allow inspectors to detect system changes that could
affect performance. The design specifications cover the general areas of (1)
sample acquisition point location, (2) sample collection technique, and (3) sample
preparation and analysis.
The sample acquisition point location criteria are directed at obtaining
a sample representative of the coal actually burned in the combustion unit, rather
than an estimate of coal quality as received at the plant. This requires that the
sample acquisition points be located as close as possible to the point at which the
coal is burned. Alternative locations are allowed only upon demonstration that
the system results are still representative of the coal "as-fired."
The sample collection technique criteria are designed to provide
that can be related to specific time periods of SO2 emissions in order to
a comparison of all CSAS results with reference method SO2 sampling. ASTM
-------
sample type, condition and spacing criteria, as well as general ASTM equipment
criteria, are specified. Additionally, in order to make possible combining of
samples from individual units to represent combined emissions (as when several
units discharge to a common stack), proportional sampling is required. While it is
assumed that most users will prefer automatic sampling techniques, a proportional
sampling strategy for manual sampling is also specified.
Sample preparation and analysis criteria are specified in accordance
with ASTM procedures with alternatives allowed upon demonstration of equivalent
results.
design specification details, see the "Initial Application (Phase I)"
section of the Manual which is reproduced in the Appendix.
PERFORMANCE SPECIFICATIONS
In addition to the design specifications, the following performance
specifications were developed in order to define the acceptable level cf CSAS
accuracy, repeatability and reliability.
Sampling;
1. Number of subincrement point samples per hour per point of sample
acquisition. (See Appendix for terminology specific to "as-fired"
CSAS's)
The number of sample increments was arrived at by application of the
criteria in Table 2 of ASTM D223A
iABlC, 2 ^•H
Top Sid
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' 10. 1)0 mmi
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MovnuioilT Cleaned Corf
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to weft caaev the nwmocr of tncremcnu »ho»ild be aa iFectficd for ra» lunckanodl vo»l.
-------
2. Weight of hourly increment point sample.
The criteria of the above-referenced Table 2 was applied, resulting in
the specification of 2 pounds per increment.,
3. Variation of actual factor of proportionality for daily composite unit
samples (seven days, individual unit).
In order to define acceptable CSAS repeatability and prevent significant
bias in the 30-day average calculated SO2 emission rate, the ratio of
coal sampled to coal burned for each daily time period must be within
20% of the average ratio as determined during a 7 .day test period.
The 20% specification allows for a 10% actual variation with a 10%
weighing error.
ft. Variation of actual factor of proportionality for daily composite unit
samples (daily, all units within system).
In order that the daily composite system samples are not significantly
biased by improper weighting of,certain daily composite unit samples*
the ratio of coal sampled to coal burned for each unit in a system
(more than one unit discharging through a single stack) must be shown
to be within 20% of the average ratio for all units in the system.
Analysis;
Specifications listed in the appropriate ASTM. standard methods ~
5. Precision of sample preparation.
6. Calibration error for percent sulfur analysis, dry basis.
7. Precision of analysis for percent sulfur, dry basis.
8. Standardization of calorimeter water equivalent.
9. Precision of analysis for Btu/lb., dry basis.
System Operation:
10. Response time of system.
In order to allow identification of problems with coal quality and
possible corrective action, the CSAS must yield final results within
168 hours of completing the collection of the daily sample.
11. Operational period of system.
In order to encourage a high reliability of system components, the
CSAS must operate for at least 16S hours without any corrective
maintenance.
12. Relative accuracy of system Ibs. SO2/106 Btu results.
-------
In order to qualify as an acceptable alternative to CEMS's for direct
i comparison of data to SO2 emission standards, the CSAS must meet
the same relative accuracy specification as is required for CEMS's.
TEST PROCEDURES
While existing ASTM procedures were available for demonstration of
compliance with the performance specifications for the analysis portion of the
CSAS, procedures appropriate for demonstration of compliance with the performance
specifications for the sampling and system operation portions had to be developed.
For details of these procedures, see the "Performance Testing (Phase II)" section
of "the Manual reproduced in tne~A"ppendix.
The relative accuracy performance specification test for CSAS's is
identical to that used for CEMS's. A minimum of nine 1-hour reference method
source tests must be conducted for comparison with CSAS data which must be
collected for corresponding hourly time periods.
While the performance specification tests are designed to verify the
operational parameters of the CSAS initially, periodic testing was deemed necessary
in order to evaluate the operation of the CSAS and validity of the resultant data
over time. Appropriate performance testing is required whenever corrective
maintenance is performed on the sulfur analysis, heating value analysis, sample
acquisition or sample preparation portions of the CSAS. In addition, the Phase II
performance specification testing, with the exception of relative accuracy testing,
is required to be conducted once during every calendar quarter.
ACTUAL APPLICATIONS
While several different approaches were proposed by companies in
attempts to satisfy the Department's CSAS requirements, only one type of CSAS
has been demonstrated to conform to all design and performance criteria or
equivalents, where permitted. Several unsuccessful proposals were denied mainly
due to inability to represent SOj emissions for known, discreet, hourly time
periods. To date, no company has proposed a manual sampling program as outlined
in the Department's Manual.
The Pennsylvania Electric Company (Penelec) Automatic "As-Burned"
Coal Sampler System (PACSS), patented by Mr. Al Slowik of Penelec, has undergone
successful demonstration of compliance with design and performance criteria at
six different utility stations on a total of 16 generating units which have a total of
nine emission points (due to instances of several units discharging through a single
stack).
The sample acquisition portion of the PACSS consists of a stainless
steel probe located so as to convey pulverized coal from a coal pulverizing mill
exhauster to a cyclone collector which discharges to a coal sample can, as shown
in Figure 1 of the Appendix. The coal is collected periodically, at least two
samples per hour, by automatic, timed operation of a pneumatic pinch valve which
allows or prevents coal flow in the probe. When coal is not being sampled, high
pressure instrument air is supplied to back-purge the probe, thus reducing plugging
problems.
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D.
E.
P.
G.
18.
19.
20.
21.
Analysis of each laboratory sample for BTU/lb. must be conducted in
duplicate using ASTM 02015-77(78) or methods which produce equivalent
results. Results must be recorded on a dry basis.
Analysis of each laboratory sample for percent sulfur must be conducted
!n duplicate using ASTM 03177-75, Method B- Bomb Washing Method or
methods which produce equivalent results. Results must be recorded on
a dry basis.
Analysis of each laboratory sample for percent moisture must be
conducted in accordance with ASTM 03173-73(79).
Results for each laboratory sample must be converted to tb. SO2/106
BTU using the average values of percent sulfur and BTU/lb. from the
duplicate analysts as follows:
S = (Sa * S2)/2
H « (Hj * H->)/2
Where
Sj s first measured value of percent sulfur
§2 = second measured value of percent sulfur
S = average of Sj and 5*
HI « first measured value of BTU/lb.
Hj ~ second measured value of BTU/lb.
H « average of HI and Hi
. SO2/106 BTU . • •
22. The calibration error with respect to percent sulfur analysis must be
checked at minimum every seven days using .either NBS SRM I632a or
NBS SRM I631a-midrange.
23. The value of the calorimeter water equivalent must be, checked at
minimum every seven days using ASTM D2Q15-77-{78), Section 7.
The claimed performance specifications as listed in Table V (will be verified as
part of Phase II).
Process and pollution control equipment operating parameters which affect
the SO? emission level, along with an explanation of the method to be used to
record these parameters.
Calibration, operational,
recommended schedules.
and maintenance procedures, along with
An explanation of procedures to be used .to satisfy the Department's
requirements as listed in the "Record keeping'and Reporting" section of this
manual.
a
-------
= rated coal burning capacity of base unit (Ibs. coal burned/hr.)
Nm s maximum number of sample acquisition points for any unit
within the system.
NOTE: Record Fo retaining two significant digits.
d. Calculate the subincrement point sample weight for each
combustion unit within the system by the equation
Where Wjs subincrement point sample weight for unit i (Ibs.)
F0 - ideal factor of proportionality (Ibs. sampie/lb. coal burned).
Cj0 = rated coal burning capacity of unit i (lbs./hr.).
Nj s number of sample acquisition points for unit i.
NOTE: Record Wj retaining two significant digits.
e.
At the beginning of each discrete hourly time period* determine
the number and spacing of subincrement point samples to be
collected at each point of sample acquisition for each combustion
unit within the system according to the following table.
Number of Subincrements Spacing
0.00 toO. SO 2 30 minutes
0.51 toO.75 3 20 minutes
0.76 lol.OO 4 15 minutes
Where Cja = actual coal burning rate for unit i anticipated for me
hour (Ibs. coal burned/hr.)
Cj0 s rated coal burning capacity for unit i (Ibs. coal burned/hr.)
f. Collect the samples according to the specified weight, numbers,
and spacing*.
16. Each daily composite unit sample must be weighed prior to combining, in
accordance with all quality assurance criteria, to form the daily
composite system sample. All data necessary to calculate the actual
factors of proportionality (Fja) for daily composite unit samples from
each individual combustion unit within the system (i.e.t the weight of
each daily composite unit sample and the weight of coal burned in the
unit during the same daily time period) must be recorded.
17. Preparation of a 50-gram laboratory sample from each daily composite
system sample must be conducted in accordance with ASTM 02013-72
(78) as for Group B samples.
-------
9, An hourly increment system sample, which consists of hourly increment
unit samples for all combustion units which discharge to a common flue
during a particular discrete hourly time period, must accurately
represent the actual SO2 emissions from the flue for that time period.
10. A daily composite unit sample must consist of all subincrement point
samples collected for a particular combustion unit during a discrete daily
time period.
11. A daily composite system sample, which consists of daily composite unit
samples for all combustion units which discharge to a common flue
during a particular daily time period, must accurately represent the
actual SO2 emissions from the flue for that time period. Combination of
daily composite unit samples to form daily .composite system samples
must be conducted in accordance with all applicable quality assurance
criteria.
12. For sampling of coal streams other than fSuidized. pulverized coal, each
subir.crement point sample must consist of a Type 1, Condition A or 8,
Spacing 1 sample as specified in ASTM 02234-76.
13. For sampling of fluidized. pulverized coal, each subincrement point
sample must consist of a Type I, Condition A, B, or C, Spacing 1 sample
as specified in ASTM 02234-76.
14. Subincrement point samples must be collected in proportion to the
weight of coal passing the point of sample acquisition during the time
period represented by the samples. The factor of proportionality tlbs.
sample/ID, coal burned) must be as nearly identical as possible for all
sample acquisition points within a particular system.
15. For sampling systems that do not inherently sample on a proportional
basis, :ne following method shall be used to determine the sampling
strategy.
a. Determine the maximum rated coal burning capacity in ib. per hour
for each combustion unit within 'a system (ail units discharging to a
common flue).
b. Select the unit with the lowest rated coal burring capacity as the
base unit.
c. Calculate the ideal factor of proportionality for the system by the
equation:
Where Fo = ideal factor of proportionality (Ibs. sample/lb. coal burned}
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*
II. Coal Sampling/Analysts Systems
A. A general description of the process(es). and pollution control equipment. All
factors that may affect the operation or maintenance of the sampling/analysis
system must be included.
B. The location of the sample acquisition point(s) in relation to:
1. The point at which the coal is burned
2. Any coal processing devices
3. Pollution control equipment
4. Emission point of pollutant gases to the atmosphere
Provide a flow diagram which clearly shows the location ^>f "The sample
acquisition point(s). Include any test data and an explanation as to the basis
for the choice of the location.
C. A description of the equipment, methods, and procedures to be used to comply
with each of the following system design specifications or their equivalent,
where applicable (for explanation of terms, see Table IV). Equivalency must
be demonstrated to the Department's satisfaction.
1. Points of sample acquistion must be located as close as possible to the
point at which the coal is burned.
2. Points of sample acquisition must be located downstream of any coal
processing devices, including but not limited to pulverizers, unless an
alternate location will yield representative results.
3. A separate point of sample acquisition must be located in each
coal feed stream to a particular combustion unit unless it can
demonstrated that sampling conducted at fewer points will y
representative results.
4. Sample collection must be by means which do not allow for operator
discretion with respect to portions of sample retained or rejected.
5. Sampling devices must comply with ASTM D'2234-76, Sections 6.4
through 6.10, unless alternate devices yield representative results.
6. A minimum of two subincrement point samples must be collected from
each point of sample acquisition for each discrete hourly time period.
7. An hourly increment point sample must consist of all subincrement point
samples collected at a particular sample acquisition point during a
discrete hourly time period. Each hourly increment point sample must
weigh at least two pounds* except for flutdized. pulverized coal where
lower sample weights yield representative results.
8. An hourly increment unit sample must consist of all hourly increment
point samples for a particular combustion unit during a particular
discrete hourly time period.
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INITIAL APPLICATION (PHASE D
Upon promulgation of a > monitoring requirement, the following information must be
submitted within six months to the appropriate Regional Office. This information must
indicate the probable capability of a system to meet all of the regulatory requirements.
Only information concerning one specific proposed system should be submitted. Multiple
proposals will not be evaluated. The information must be clearly identified in the
submittal.
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APPENDIX
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systems appear to be sufficient to result in data that can be directly compared
with existing combustion source SO2 emission standards. Coal sampling and analysis
systems designed to meet these requirements appear to be reliable and cost effective
alternatives to continuous emission monitoring systems.
-------
During performance testing, Penelec demonstrated that the results-
obtained by sampling from a single exhauster from a particular coal pulverizing
mill was equivalent to results obtained by sampling all exhausters from that mill.
Penelec also demonstrated that results obtained by sampling quantities of coal
weighing less than two Ibs. per hour were equivalent to results obtained by sampling
at a rate of at least two Ibs. per hour. In accordance with Department criteria,
these equivalent procedures were approved.
RELIABILITY COMPARISON
Although the Department does not yet have sufficient data to conduct
a rigorous evaluation of data availability of CSAS's versus CEMS's , such information
is available on a limited scale. The table below indicates percent "valid days" (a
valid day is one containing no more than six continuous hours of invalid data) for
CSAS's and CEMS's reporting during the first quarter of 1983.
CEMS's CSAS's
Percent Valid Davs Number oi Units Number of Units
100.0 ' 10 * .
98.9 u
97.8 1
94.ft 4
93.3 <*
92.2 3
90.0 2
88-9 1
84.4 7 1
80.0 1
78.9 1
72.2 I
66.7 3
57.8 I
The average percent valid days for CSAS's during the first quarter of
1983 was 97.4% versus 89.9% for CEMS's.
ECONOMIC COMPARISON
According to Penelec, the cost of installing a PACSS (labor plus materials)
is approximately $1,500 per sampler. At one sampler per pulverizing mill, the
largest PACSS installed to date has eight samplers for a total installation cost of
approximately $12,000.
Although CEMS equipment costs of $10,000 to $20,000 are often cited
by manufacturers, total installed costs of $50,000 to $100,000 are not unusual.
Annual operation and maintenance costs for either CSAS or CEMS may
be estimated to be approximately equal to the installed equipment cost.
CONCLUSIONS
The requirements established by the Department for coal sampling and
analysis systems to be used as alternatives to continuous emission monitoring
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TABLE IV
DEFINITION OF SAMPLE TERMINOLOGY FOR COAL SAMPLING/ANALYSIS SYSTEMS
Time Period
(less than one hour)
hourly
Term
subincrement
increment _
daily
composite
Can Represent
point (1)
point
unit
system
unit
system
Definition
individual sample collected
at a single point
accumulation of (1) lor a
single point for one hour
accumulation of (I) for all
points in unit for one hour
accumulation of (1) for aJJ
units in system for one hour
accumulation of (1) for all
points in unit for 2
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TABLZ V
COAL SAMPLING PERFORMANCE SPECIFICATIONS
1.
2.
3.
4'.
5.
6.
Parameter
Number of subincrement point samples per hour
per point of sample acquisition
Weight of hourly increment point sample
Variation of actual factor of proportionality for
daily composite unit samples (7 days, individual •
unit)
Variation of actual, factor of proportionality for
daily composite unit samples (daily, all units
within system)
Precision of sample preparation
Calibration error for percent sulfur analysis.
dry basis
7. Precision of analysis for percent sulfur, dry basis
8. Standardization of calorimeter water equivalent
9. Precision of analysis for BTU/lb., dry basis
10. Response time of system
11. Operational period of system
12. Relative accuracy of system ib. SCH/IO6 BTU
results
Secification
>2 IbS.
Each daily value must be within
+20% of the average
Each unit value must be within
+20% of the average value
The ratio of variance must be £3.29
£10 percent of each NBS SRM
value (high, mid, and low ranges)
£0.05 percent sulfur if sample
contains <2.Q percent sulfur. £0.1
percent sulfur if sample contains
>2.0 percent sulfur
Must comply with ASTM D2015-77(7e
Section 6
£50 BTU/lb.
£168 hours
M68 hours
£20 percent of mean value of
reference method tests plus
95 percent confidence interval
13
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PERFORMANCE TESTING (PHASE H)
f
After approval of Phase I, the applicant should proceed with purchasing, installation, and
performance testing. The Source Testing and Monitoring Section must be advised in
writing at least 10 days prior to Performance Specification Testing and provided the
opportunity to observe and participate in all testing. The Section must also be advised in
writing within 10 days after the completion of testing. The Section reserves the right to
conduct testing during the Performance Specification Testing or at any time thereafter.
Phase II must be completed within 10 months after Phase I approval. AH performance
specification testing must be conducted in accordance with the appropriate performance
specification test procedures in 40 CFR, Part 60, Appendix B, of the Code of Federal
Regulations and in this manual. Additional requirements are as follows:
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in. Coal Sampling/Analysis
A. Conditioning Period
1. Determine the calorimeter water equivalent in accordance with ASTM
02105-77(78), Section 6. Record all data and results for submission with
performance test report.
2. Operate the system for an initial 168-hour conditioning period in a
normal operating manner.
B. Operational test period. Operate the system for an additional 168-hour period
in a normal operating manner during which time all performance testing must
be completed (with the exception of Sections B.5. through B.9. below, which
must be completed within 168 hours after the completion of the operational
test period).
I. Test for number of subincrement point samples per hour. Conduct this
test in triplicate for each point of sample acquisition.
a. Collect and weigh a single subincrement point sample.
b. Collect and weigh the next subsequent hourly increment point
sample.
2. Test for weight of hourly increment point samples. Conduct this test in
triplicate for each point of sample acquisition.
a. Use the weights determined in B.l.b. above for this test.
3. Test for variation of actual factor of proportionality for daily composite
jnc samples (7 days, individual unit).
a. For each unit monitored, collect all data necessary to determine
the actual factor of proportionality (Fja) for each of the seven
daily time periods during the operational test period (i.e., the
weight of each daily composite unit sample and the weight of coal
burned in the unit during the same daily time period).
fc. Test for variation of actual factor of proportionality for daily composite
unit samples (daily, all units within system).
a. Use the data collected as in B.3.a. above for this test.
5. Test for precision of sample preparation. Conduct this test for each
system monitored using any five of the seven daily composite system
samples normally collected during the 168-hour operational test period.
a* Divide the daily composite system sample Into two equal
subsamples.
17
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b. Prepare and analyze one of the subsamples according to normal
procedures (in duplicate).
c. Prepare and analyze the remaining subsample for'dry ash content*
using ASTM 02013-72(78), Appendix A2, Section A2.2.
6. Test for calibration error of percent sulfur analysis, dry basis.
a. For each analyzer to be used* conduct five non-consecutive
analyses on each of MBS SRM 163la low, middle, and high ranges
for percent sulfur, dry basis at any time during the 163-hour
operational test period (NOTE: If NBS SRM 163 la is not available.
conduct this test using NBS SRM 1635 and NBS SRM 1632a).
7. Test for precision of analysis for percent sulfur, dry basis.
a. Conduct the normal duplicate analyses of the daily composite
system samples for the 168-hour operational test period.
8. Test for precision of analysis for BTU/lb., dry basis.
a. Conduct the normal duplicate analyses of the daily composite
system samples for the 168-hour operational test period.
9. Test for response time of monitoring system.
a. Record the date and time that each calculation of Ibs. SO2/106
BTU is completed for each daily composite system sample during
- the 168-hour operational test period.
10. Test for standardization of calorimeter water equivalent.
a. Use data and results as obtained in A.I. above.
11. Test for operational period of monitoring system.
a. Keep records indicating compliance with all performance
specifications for the i68-nour operational test period.
12. Test for relative accuracy of monitoring system Ibs. SO2/106 BTU
results. This test must be conducted for each system monitored.
a. Conduct a series of nine source tests for SOj emissions in
accordance with the requirements of Chapter 139 of the
Pennsylvania Department of Environmental Resources' Rules and
Regulations. Each test must consist of the following determin-"
ations:
i. Effluent SO2 concentration in accordance with the
procedures specified in Chapter 139, Section 139.4(10).
18
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ii. Effluent volumetric flow rate according to Methods I, 2, 3
and » of 40 CFR, Part 60, Appendix A of the Code of Federal
Regulations.
Hi. Heat input to the source(s) being monitored, using heat
balance or actual fuel feed data.
i
iv. If it can be demonstrated that u and iii above are relatively
constant, the Department may allow a single measurement of
each to represent conditions for up to three measurements
of i.
b. Results of each source test must be expressed as Ibs. SO2/106 BTU
for a known, discrete hourly time period, using the data collected
in i, ii and iii above.
c. Collect and analyze, in the normal manner, hourly increment
system samples for the system monitored for time periods
corresponding to each source test.
d. Results of the monitoring system must be expressed as Jbs.
SO2/I06 BTU for the time periods corresponding to each source
test.
C. Calculations
1. Number of subincrement point samples per hour.
. a.. Using the data collected as in B.l.a and B.l.b. calculate the
average number of subincrement point samples as follows:
_
xsi
Where N - average number of subincrement point sarrpies per hour
Xi s average of the three weights determined as .n ?.l.b.
Xsi * average of the three weights determined as ;n B.l.a.
2. Weight of hourly increment point samples
a. Using the data collected as in B.l.b., calculate the average weight
of hourly increment point samples as follows:
3
EXi
•«* i»l
Xi « -
where X~i a average weight of hourly increment point samples
Xi * individual weights determined as in B.I. b.
19
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3. Variation of actual factor of proportionality for daily composite unit
samples (seven day, individual unit).
a. Calculate the actual factor of proportionality for. each.daily
composite unit sample for each daily time period as follows:
F- *£
Fia s c'ia
where F|a Actual factor of proportionality for daily composite unit
sample
X! s weight of daily composite unit sample
Cla = weight of coal burned in unit during the corresponding daily
time period
b. Calculate the average of the actual factors of proportionality for
the 168-hour operational test period as follows:
where F;a average of the actual factors of proportionality for the 163-
hour operational test period
* • •
Fja s individual actual factors of proportional!iy for each daily
composite unit sample
c. Calculate the variation as follows for each of the 7 actual factors
of proportionality:
Vi-
ia
where Vj ~ variation of an individual actual factor of
proportionality
Fjm s individual actual factor of proportionality
Fja - average of the actual factors of proportionality as
calculated in C.3.b.
Variation of actual factors of proportionality for daily composite unit
samples (daily, all units within system)
20
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Calculate the average of the actual factors of proportionality for
all units within a system, for each daily time period during the 168-
hour operational test period as follows:
n
I Fs
b.
where Fsa = average of the actual factors of proportionality for all
units within a system for a particular daily time period
during the 168-hour operational test period.
Fja = individual actual factor of proportionality
n = number of units within system
Calculate the variation as follows for each of the units for each of
the seven daily time periods during the operational test period:
sa
where V; a variation of an
proportionality
individual actual factor of
Fia = individual actual factor of proportionality
Fsa s average of the actual factors of proportionality for all
units within a system for a particular daily time period
as calculated in C.4.a.
5. Precision of sample preparation
a. Using the data collected in B.5.C., calculate the ratio of the largest
variance of any set of four subsarr.pies to trie average variance cf
the five sets of four suosampies according to ASTM 02013-72(73),
Appendix A2.
b. The ratio calculated in C.S.a. must be <3.29 in order to comply
with Performance Specification S.
6. Calibration error of percent sulfur analysis, dry basis
a. Using the data collected in B.S.a., calculate each error as follows? "
|%Smi
%Sci
x 100% I- 100%
21
-------
7.
where E; = error of an individual analysis
% Srai » measured percent sulfur, dry basis
% Sci = certified percent sulfur, dry basts
Precision of analysis for percent sulfur, dry basis
a. Using the data collected as in B.7.a., calculate the precision of
analysis for percent sulfur, dry basis for each pair of duplicate .
analyses as follows:
where P; s precision of analysis for an individual pair of duplicate
analyses
% SI; s percent sulfur results for first analysis
% S2j = percent sulfur results for second (duplicate) analysis
8. Precision of analysis for BTU/lb., dry basis
a. : Using the data collected in B.S.a.. calculate the precision of
analysis for BTU/lb., dry basis for each pair of duplicate analyses
as follows:
Pi* IHlj-H2il
where P; s precision of analysis for an individual pair of duplicate
analyses
HI-, - BTU/lb. results for first analysis
H2-, s BTU/lb. results for second (duplicate) analysts
9. Response time of monitoring system.
a. Using the data collected as in 8.9.a., calculate the time between
recording of Ibs. SOs/lO6 BTU results and the end of the daily time
period represented by the results.
10. Standardization of calorimeter water equivalent
a. Using the data collected in A.I., calculate the standard deviation
of the test series in accordance with ASTM 02015*77(78), Appendix
Al. This value must be <3.6 BTU/degree F in order to comply with
Performance Specification 8
11. Operational period of monitoring system.
22
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a. If the monitoring system fails to comply with any performance
specification during the 168-hour operational test period, the test
period must be repeated. During the repetition, compliance need
be demonstrated only with the failed specifications).
12. Relative accuracy of monitoring system Ibs. SOg/lQ6 BTU results. Using
the data collected as in 8.12.&. through B.12.d., calculate the relative
accuracy plus 95 percent confidence interval as follows:
9
'£ r
5=1
EX$i
x 100%
CIo.95 * O.Q<
9 9
9U
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I •"
•a'
FINAL APPROVAL (PHASE HQ
A report must be submitted to the Bureau verifying the monitoring system's compliance
with all regulatory requirements. The report must be submitted within two months after
completion of Phase II and must include the data as specified in Phase II and in the
following:
I. Continuous Source Emission Monitoring
A. For opacity monitoring, W CFK, Part 60, Appendix B, Performance
Specification 1, Sections S and 9.
B. For sulfur dioxide or nitrogen oxides monitoring, 40 CFR, Part 60, Appendix B,
Performance Specification 2, Sections 6 and 7.
C. For oxygen and carbon dioxide monitoring, 40 CFR, Part 60, Appendix B,
Performance Specification 3, Sections 6 and 7.
II. Coal Sampling/Analysis Systems
A. No additional information.
The method used to convert the monitoring data to the required reporting format must be
verified in the report using actual test data. The report must also include a description of
any changes, additions, or deletions made to the information submitted in the initial
application (Phase I).
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II. Coal Sampling/Analysis Systems
A. Record Keeping
1. The company shall reduce all of the system results to daily averages in
LB SOW106 BTU in accordance with the data validation and reduction
criteria in the Quality Assurance section of this manual.
2. A chronological file shall be maintained by the company which includes:
a
a. All laboratory samples identified by system and date represented.
b. The results of each analysis for percent sulfur and BTU/lb.
c. All valid averages as calculated in I. above, along with the date
and time the result was recorded.
d. The cause, time periods, and magnitude of all calculated emissions
which exceed the applicable emission standard(s).
e. Data and results for all performance tests and recalibrations.
• f. The data, necessary to show compliance with all data validation and
reduction criteria in the Quality Assurance section of this manual.
g. The cause and time periods for any invalid data averages.
h. A record of any repairs, adjustments, or maintenance to the
system.
i. The process and pollution control equipment operating data for all
parameters wnicr. affect the emission level of 5O->.
3. All data must 5e maintained 5v t.K.e company for a ?er:oci of two years
and ae provided :o :re Department upon request u any time.
Laboratory samples .rust 3e maintained antil tre =rtd of the next
subsequent reporting period.
8. Reporting Requirements
I. The following information shall be reported to the Department on a
calendar quarter oasis:
a. For each day, the daily average emission rate and causes for any
daily averages which exceed the 30-day standard.
b. For each day, the number of valid hours and causes for any invalid
daily averages.
e. The results from all performance tests and recalibrations
conducted during the quarter.
27
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The report shall be submitted in two copies to the central office by the
30th day following the close of the reporting period.
The report shall" be submitted in a format specified by the Department
and must be signed by the person exercising managerial responsibility
over the operation of the sources) for which monitoring is required.
23
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II.
Coal Sampling/Analysis Systems
A. Data Validation Criteria
1.
2.
Daily composite unit samples. A daily composite unit sample shall be
considered invalid if any of the following conditions OCCUR
a. The sampling/analysis system is not operated in accordance with
the performance specifications set forth in this manual.
b. The sampling/analysis system is not operated in accordance with
the quality assurance criteria of this manual.
c. Any combination of sampling/analysis system downtime and
monitored unit downtime exceeds six consecutive hours.
d. The actual weignt of the daily composite unit sample is less than
0.75 Fja Cia Ibs.
where Fja = average of the actual factors of proportionality for
unit i determined during the most recent performance
specification test (Ibs. sampie/lb. fired).
C1m =
weight of coal burned in unit i that day Obs. fired)
e.
The actual factor of proportionality for the daily composite unit
sample is not witnin » 20% of the average of the actual factors of
proportionality for all valid composite unit samples within tne
system* unless all valid daily composite unit samples are analyzed
individually and results weigr.ted according to tne actual amount of
coal fired in eacn unit.
Daily Composite System Samples
a. A daily composite system sample snai! 3e considered ir.valid if *.h
total actual vaiid sample weignt is less than
O.T5
M
I
|DS-
Where M
number of units within the system
3. Laboratory sample analysis. The results of analysis of a laboratory
sample shall be considered invalid if any of the following conditions
occur:
a« The next subsequent calibration check indicates non-compliance
with Performance Specification 6 or Performance Specification 3.
31
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(U) Instrument Air, 5C psig
( >) Electronic
Timers (2)
,»
V
puiveritad coal
frmn miTla to boi-Tor' *
(1) Stainless
0 1 0 C 1 — — » -^
probe (1/2" 1.3.)
i»* 'X£rr£
•^1 1
•
^2> — '
Purge ^
••
C<
,4
MM
H> tf
•• ^
^- (3) Solenoid
- (2) Air Opera
/ r-r
3 1
A
•
*
( ) Cyclone
Sa pie Can
"Cycle of ...'.Operation*1
Let t - Start of Cycle
(1) (t) to (t * 5 »«c.) — purge
(2) (t * 5 »«c.) to (t * 13 tee.) — sample
(3) (t •»• 13 sec.) to (t * 60 minutes) —-off
Repeat Cycle
Samples collected from noon to noon each day.
••Actual timing is site dependent (depends on coal flow, pros BUT-
in coal pipe, etc.)
Figure 1
Pennsylvania ElaetTlc C
Automatic "As Burned" Coal Sampler
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b. The precision of analysis for percent sulfur, dry basis, is not in
compliance with Performance Specification 7.
c. The precision of analysis for BTU/lb., dry basis, is not in
compliance with Performance Specification 9.
B. Data Reduction Procedure
I. All data averages must be calculated using valid data only.
2. A daily average shall be considered valid if all of the data validation
criteria above are complied with.
3. A running 30-day average shall be considered valid if it contains at least
23 valid daily averages.
C* Maintenance Requirements
1. Sulfur analyzer maintenance
a. Conduct the test for calibration error, as specified in item UI.B.6
of the "Performance Testing" section of this manual, immediately
following any corrective maintenance to the sulfur analyzer. •
2. Calorimeter Maintenance
a. Conduct standardization of the calorimeter water equivalent, in
accordance with ASTM 02015-77(78), Section 6, immediately
following any corrective maintenance to the calorimeter.
3. Sample Acquisition Maintenance
a. Conduct tests, as specified in items III.B.l, III.B.2, III.B.3, and
III.B.!* of the "Performance Testing" section of this manual,
immediately following any corrective maintenance to the point of
sample acquisition.
ft. Sample Preparation Maintenance
a. Conduct tests, as specified in item I1I.B.3 of the "Performance
Testing" section of this manual, immediately following any
corrective maintenance on equipment used in sample preparation*
O. Periodic Recalibration
* .-
**
I. Quarterly Recalibration
a. Performance specification tests, as specified in items 01.5.1
through ULB.11 of the "Performance Testing" section of this
manual, must be conducted quarterly.
32
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