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Introduction

Combustion turbines have become the overwhelming option of choice for utilities looking to add additional capacity. Simple-cycle combustion turbines are being employed to meet peaking needs with combined-cycle units accommodating base load. Many utilities are currently in the process of installing new combustion turbines and are faced with conducting performance tests and certifying monitoring systems for these new units.

While the monitoring requirements for oil- and gas-fired combustion turbines in Appendices D and E of Part 75 are less burdensome than the analyzer-based monitoring counterparts, there are flow meter calibration and other quality assurance issues that must be addressed. Units using Appendix E must establish NO_X-to-heat input correlations through stack testing and monitor various parameters on a continual basis to determine whether the unit is operating within manufacturer suggested ranges.

In addition to the monitoring requirements of Part 75, combustion turbines must also meet NSPS standards under 40 CFR Part 60. Through careful planning much of the testing and monitoring requirements of Part 75 and Part 60 can be combined, but there are peculiarities to each that should be appreciated.

This paper discusses CP&L’s experience in procuring and certifying monitoring systems and conducting performance tests for its gas- and oil-fired combustion turbines. The regulatory requirements will be reviewed and various insights regarding the process will be presented.

Summary of Regulatory Requirements

New combustion turbines are affected under the Acid Rain Program and are subject to the continuous emission monitoring requirements of 40 CFR Part 75. The units are also subject to New Source Performance Standards (NSPS) under 40 CFR Part 60, Subpart GG for stationary gas turbines. Combined-cycle units with supplemental duct capability greater than 250 mmBtu/hour will also be subject to the requirements of 40 CFR Part 60, Subpart Da for new fossil-fuel fired steam generating units. The majority of this paper deals with Part 75 and Part 60 Subpart GG issues for simple cycle combustion turbines or combined cycle turbines without supplemental firing. Issues particular to combined-cycle with supplemental duct firing and Part 60 Subpart Da are discussed in a separate section.

Many of the requirements of Subpart GG and Part 75 are redundant while others are unique to only one rule. Subpart GG establishes emission limitations, along with performance testing and monitoring requirements. Part 75 details continuous emission monitoring requirements for Acid Rain Program affected units.

Subpart GG limits NO_X and SO₂ emissions from stationary combustion turbines. Under Subpart GG compliance with the applicable NO_x limitation is demonstrated with an initial Method 20 performance test with subsequent water-to-fuel ratio monitoring. The SO₂ limitation defined under Subpart GG is met by limiting the sulfur content of the fuels fired in the gas turbine, with periodic fuel sampling and analysis.

Part 75 establishes continuous emissions monitoring requirements for NO_X, SO₂, CO₂ and heat input. For combustion turbines, the SO₂ monitoring option of choice is Appendix D. While SO₂ emissions can also be monitored using CEMS with a stack SO₂ and flow meter, using Appendix D avoids the cost and hassle of the periodic maintenance and testing associated with stack analyzers. Appendix D also tends to be far more accurate than CEMS and permits utilities to avoid the biases associated with EPA’s stack flow Reference Methods. Under Appendix D, SO₂ emissions are calculated based upon fuel flow and the sulfur content of the fuel, where a default value is typically used for natural gas and fuel analysis is used for oil. For NO_X monitoring, NO_X and diluent concentration analyzers are used to report emissions on a lb/mmBtu basis. For peaking units, Appendix E, which correlates emissions to heat input based on a series of initial tests, may be used in lieu of installing analyzers. CO₂ and heat input are monitored via Appendix G, which like Appendix D, is based upon fuel characteristics and consumption.

Regulatory Deadlines

Figure 1 is a timeline summarizing the regulatory deadlines for a combustion turbine under 40 CFR Parts 60 and 75. The notification requirements start shortly after the beginning of construction with the Part 60 construction notification due 30 days after construction is begun. The next notification requirement comes prior to startup. A utility must provide notification of the "anticipated initial startup" date at least 30 days prior, but not more than 60 days prior to the anticipated startup date. Notification must also be provided for the actual initial startup date, which may or may not be different from the anticipated date. The actual startup notification must be provided within 15 days after startup.

Deadlines regarding performance/correlation testing are set in terms of the start of commercial operation, which may be different than the initial startup date. All Part 75 testing and certification requirements are must be compled by 90 after comercial operation. Under Part 60, performance testing will be completed within 60 days after the unit achieves "the maximum rate at which the affected utility will be operated," i.e., when the unit achieves maximum normal load, and no more than 180 days after initial startup. Notice of the testing should be provided at least 45 days prior to the beginning of testing. The monitoring plan and test protocol are also due 45 days prior to the beginning of testing. Fuel flow meters should be certified/calibrated prior to the beginning of test series. The test results are due 45 days after the tests are complete.

In addition to the monitoring plan, test protocol and test results, which must be submitted to EPA, Part 75 also requires that utilities develop quality assurance plans for each monitoring system. While there is no submission requirement for the quality assurance plan, this document must be maintained on-site for potential inspection. There is no specific deadline for developing the quality assurance plan in Part 75 but we recommend that this document be in place prior to the test report deadline. Ideally, it would be available at about the same time as the monitoring plan and test protocol. It, like the monitoring plan, is intended to be a "living document," changing as the monitoring system and quality assurance procedures change.

Appendix D Certification Issues

Appendix D is a pre-approved alternative that may be used by oil- and gas-fired units. While no testing is required to demonstrate the relative accuracy of the protocols and there are no daily calibration procedures analogous to those for analyzer based systems, certification is required. Certification of Appendix D monitoring consists primarily of demonstrating that the fuel flow meters meet the 2% accuracy requirements of the rule. If the fuel flow meters used for commercial billing purposes are employed for Appendix D monitoring, the certification and subsequent quality assurance requirements are waived.

One of the more recent problems associated with preparing the initial monitoring plan data for combustion turbine certification packages is demonstrating conformance with the recently revised natural gas definitions. In the May 1999 revisions, EPA introduced a new definition for pipeline natural gas and natural gas in §72.2. For "pipeline natural gas" H₂S was limited to 0.3 gr/100 scf and it was stipulated that H₂S must constitute at least 50% of the total sulfur content. The definition was changed because of Agency concerns that use of default SO₂ emission factors might result in under reporting for some sources. The new definition, however, has been problematic because EPA is requiring significant testing for sources with gas supplier contracts (tariffs) that include higher sulfur "limits" to demonstrate that the definition is met in order to use the 0.0006 lb SO₂/mmBtu default value for pipeline natural gas. The new definition has resulted in considerable confusion and unnecessary fuel sampling and analysis since many contracts specify a maximum total sulfur contents of 20 gr/100 scf and this upper limit is generally many, many times greater than the actual sulfur content. This situation is further complicated since the "H₂S > 50% total sulfur" portion of the definition is poorly written and there is no guidance for demonstrating compliance with the total sulfur requirement.

Fortunately, EPA is reconsidering the pipeline natural gas definition or, at least, the extent of testing required for demonstration purposes. The Agency seems to be coming to the realization that, although the gas contracts may have higher limits, that these values may not be indicative of the actual contents. During the recent EPA Acid Rain/OTC NO_x Budget Program Conference, Agency staff stated that the "number (the contract total sulfur value) is generally not representative of the actual total sulfur content of the gas--it is usually many times higher." When this paper was written, the natural gas definition issue was still involved in settlement discussions. Presently, indications are that the rule will likely be revised to require a simple initial demonstration of compliance with the definition rather than the current 720 hour test or on-going monitoring. We are hopeful that the Agency can come to a reasonable resolution of this issue.

Certifying Part 75 Analyzers for Combustion Turbines

The NO_X system analyzers installed on combustion turbines must meet the same certification requirements as CEMS installed on any other unit. The CEMS must meet the calibration, Relative Accuracy Test Assessment (RATA), linearity, and 7-day calibration drift requirements specified in Appendices A and B of 40 CFR Part 75. While the requirements are not unique, the nature of the combustion turbine operation and emissions can make complying with these requirements more difficult. For ultra-low NO_X applications, if the alternative performance specifications are disallowed, then the RATA, calibration, and linearity requirements become problematic. For combustion turbines serving in a peaking capacity, the 7-day drift test is particularly onerous.

The difficulty associated with ultra-low NO_X monitoring is generally related to the practice of using the data for determining compliance without an appreciation of the significant, inherent random error and uncertainties in the measurements. Satisfactorily meeting the QA/QC requirements of Part 75 for ultra-low NO_X applications is not especially difficult since Part 75 includes alternative performance specifications for low emitting units. The alternative performance specifications are included in Part 75 to address the problems associated with trying to pass a percentage based criteria at low levels, given the higher proportional uncertainties in both the Reference Method and CEMS measurements at low levels. If the Part 75 alternative performance specifications are disallowed as some states are doing, then passing the tests becomes very problematic.

The 7-day drift test is antiquated, certainly unnecessary and, perhaps, unrepresentative for units that operate only periodically. Under the current rule, all units must perform a 7-day calibration error test on seven consecutive operating days and the test must be performed while the unit is "on-line." This provision is particularly difficult for infrequently operated units. Vast periods of time may transpire during the seven operating days and drift, particularly in the presence of unit instability, may be practically unavoidable. To help resolve this problem, EPA has stated that it is considering changing the "on-line" testing requirement for peaking units to three of the seven days. This "concession" on the part of the Agency may not be very helpful for simple-cycle turbines. The stack exhaust temperature for simple-cycle turbines, which represent a large portion of peaking units, is about 1000ºF, and some CEM systems would not be able to pass one calibration under such operating temperatures and then pass the next under ambient conditions. We feel the Agency should abandon the 7-day drift test requirement, if not for all units, then certainly for combustion turbines that operate infrequently. After all, a drift test in the form of a daily calibration error test is done every day and these tests are more than adequate to bring potential drift problems to the attention of CEMS technicians.

Part 75 Analyzer-based Monitoring and Subpart GG

For water or steam injected turbines, it is important to remember that, in the absence of a waiver, the requirements of Subpart GG will still apply even after CEMS are installed on turbines. Compliance is based on the water-to-fuel ratio curve established during the performance test, unless a petition for an alternative monitoring approach is granted, although the CEMS values certainly can provide information to contest "excess emissions" for hours where the water-to-fuel ratio falls, perchance, below the test ratio.

Subpart GG does not specify excess emissions monitoring for units that do not use water injection. In certain cases EPA has requested proposal of an alternative method for recording additional information at units with alternative NO_x controls. Where NO_x and diluent gas with CEMs are available, EPA has readily accepted it as an alternative.

Subpart GG NO_X Emissions Limits

The NO_X emissions limitations for utility combustion turbines are defined under Subpart GG in accordance with the following equation:

where:

NOx_STD = allowable NO_X emissions, percent dry volume at 15% O₂;

Y = turbine heat rate at rated load, kJ/W (14.4 kJ/W max);

F = NO_X emission allowance for fuel-bound nitrogen.

Because of the high efficiency of modern combustion turbines, the calculated Subpart GG NO_X limitations calculated are typically about 100 ppm. While the equation includes an allowance for fuel bound nitrogen, the low NO_X emissions from most modern utility turbine makes this adjustment unnecessary. Also, while it is not stated in Subpart GG, fuel bound nitrogen is not a consideration for natural gas, so an allowance does not apply.

Subpart GG Performance Testing and Monitoring

The Subpart GG NO_x performance test was designed for relatively high NO_x emitting gas turbines, when all gas turbine NO_x emissions were controlled using steam or water injection. During the test, specified in Method 20, compliance with the NO_X limitation is demonstrated at four different load levels, with a separate test for each fuel. The water-to-fuel ratio is measured at each load level during the compliance test to establish a critical injection rate curve for subsequent operation. During normal operation, if the hourly water-to-fuel ratio is greater than or equal to the ratio measured during the compliance test, then the unit is considered to be in compliance. All hours where the water-to-fuel ratio falls below the ratio measured during the test must be documented in an excess emissions report.

To determine compliance during the performance test, the concentrations are corrected not only to 15% O₂ on a dry basis but also to ISO standard conditions. The ISO correction, based on input from several turbine manufacturers during the original Subpart GG rulemaking, is intended to adjust the test results to represent what the emissions from the units would be at standard atmospheric conditions.

where,

NO_{X Corrected} = NOx concentration at ISO standard conditions, ppm;

NO_{X Measured} = measured NOx concentration, ppm;

P = combustor inlet pressure, mmHg;

Pr = reference combustor inlet pressure, mmHg;

H = humidity ratio of ambient air, g H2O/g air;

T = ambient temperature, °K.

Subpart GG in §60.335(f)(1) allows the use of alternative ISO correction equations developed by the turbine manufacturer. Although not explicitly stated, the Subpart GG ISO correction was developed based upon information from various turbine manufactures for a class of combustion turbines that use diffusion-type burners. The ISO correction factor in §60.335(c)(1) does not apply to new dry-low NO_X burners.

Although not explicitly stated in the rule, the design of the Subpart GG testing and monitoring regime makes it crucial that modifications be made to the water-to-fuel injection control curve both before and after the performance tests. Subpart GG does not make any concessions for variability in the water injection control or measurement systems. The unit emissions are considered suspect whenever the water-to-fuel ratio drops below the test level regardless of however slight that drop may be. The Subpart GG approach also does not take any degree of over compliance into consideration. Under Subpart GG, the data are treated equally suspect due to a slight drop in the water-to-fuel regardless of whether the unit was tested with NO_X emissions at the limit or several times below the limit.

Therefore, to facilitate successful on-going Subpart GG compliance demonstrations, it is important that the water-to-fuel ratio used during the test be lower than the ratio used on a typical basis. The water-to-fuel ratio control curve should be adjusted to lower the rate during the test and then should be readjusted after the test to raise the level. If Subpart GG is the only consideration, the greatest operational flexibility is gained by reducing the water-to-fuel ratio (tuning the control variables) as low as possible, with a reasonable NO_X margin, during the test. Even if a higher water-to-fuel will be used on a regular basis, significantly lowering the ratio can help to exclude many of the small upsets in water or steam injection from the excess emissions reports, offering the greatest potential for reducing possible notices of violations.

If the unit has a NO_X mass emissions limitation in its permit and uses Appendix E for NO_X emission monitoring, such as a unit CP&L recently installed in Georgia, significantly reducing the water-to-fuel ratio may not be advisable. Another approach may be prudent since the performance test results will also be used for NO_X reporting under Appendix E, and the high NO_X emissions associated with using a lower water-to-fuel ratio during the test could force a reduction in the potential operation of the unit. In this case, a smaller reduction in the test water-to-fuel ratio, to cover the degree of variability in the injection control and measurement systems, is recommended. CP&L has found that a 4-5% reduction is generally adequate at its sites. In some cases, it may be wise to decouple the Subpart GG and Appendix E tests by running two completely different sets of tests: 1) a low water-to-fuel ratio test to demonstrate the wide margin of compliance available for excess emissions reporting and 2) a high water-to-fuel ratio test, corresponding more closely to actual injection rate, for Part 75 reporting purposes.

It appears that EPA is open to alternatives to its water-to-fuel monitoring approach. The Agency has accepted an alternative protocol proposed by General Electric (GE) to base excess emission reporting on a GE control algorithm in lieu of the static water-to-fuel ratio curve generated during the performance tests. GE offered this alternative approach since its water injection rate is varied in accordance with atmospheric conditions. CP&L, however, has not implemented the alternative approach since it appears that GE may not have fully followed the protocol during the initial setup of the water-to-fuel ratio controls. Also, it should be remembered that the GE protocol is only applicable to the Subpart GG requirements and that EPA has not approved its use under Part 75.

From a practical standpoint, turbine suppliers often wish utilities to schedule Subpart GG performance tests as soon as possible to get their environmental performance guarantees out of the way. While it behooves no one to wait until the deadline to perform the tests should problems arise, it is CP&L’s experience that rushing the performance test is not useful either. There always seem to be trouble shooting issues involved with starting up a unit and having testing crews sitting around waiting to test while problems are sorted out serves nobody’s interest.

Appendix E Heat Input-NO_X Correlation Testing and Monitoring

Appendix E is an alternative monitoring protocol that may be used only by oil- and gas-fired peaking units in lieu of installing a CEMS to measure NO_X emissions. NO_X emissions are correlated to the results of a series of stack tests based on the hourly heat input to the unit. With the appropriate load selection, the Subpart GG performance testing can also satisfy the NO_X-to-heat input correlation testing requirements of Appendix E. Retesting of Appendix E NO_X-to-heat input correlation is required every 3000 unit operating hours or at the 5-year anniversary of the operating permit.

In order to use Appendix E, the unit must qualify as a peaking unit under the definition in Part 72, which limits the unit’s capacity factor to 20% during any given year and 10% over three years. Units that lose Appendix E peaking unit status must currently install CEMS by the end of the next calendar year. During the recent EPA Acid Rain/OTC NO_x Budget Program Conference, Agency staff said that they believe this period is too long and that they are considering changing the requirement to specify that CEMS be installed and certified within two quarters after the quarter in which the status is lost. We are strongly concerned by this. The proposed two quarter time period is simply too short a time frame to purchase, install and certify a CEMS.

One problem with Appendix E has been its requirement for operators to solicit a list from their turbine manufacturer of at least four operating parameters (indicative of NO_X formation) with acceptable ranges to serve as QA/QC parameters. The manufacturer supplied ranges for the parameters, which must include water-to-fuel injection ratio for water or steam injection controlled units, are used on an hourly basis to establish that the unit is being operated in a normal fashion and, therefore, that the NO_X-to-heat input correlation can be used with a degree of validity. Obtaining reasonable ranges for the Appendix E QA/QC parameters from turbine manufacturers has, however, been a difficult prospect for two reasons: 1) Turbine manufacturers have no direct incentive to provide the ranges and ensure that the ranges are reasonable. 2) In fact, turbine manufacturers often feel that providing these ranges somehow conveys a guarantee of turbine performance or emission characteristics over that range. Manufacturers, therefore, hedge themselves by supplying ranges that are not indicative of the entire normal range of operation but represent a more restricted range which does not reflect the broader typical operation. Turbine manufacturers feel a disadvantage in providing these ranges; in fact, some manufacturers have refused to provide ranges stating the operator must rely on testing results, which since conditions during the test will be limited, are sure not to include the entire normal range of operation.

With the exception of water-to-fuel ratio, which is already regulated under Subpart GG, the tight, automated controls on modern combustion turbines make the process of evaluating QA/QC parameters unnecessary. Because the automated control system will ensure representative operation, the parameter ranges have limited utility. Since the value of ranges is limited and the process of obtaining ranges is difficult and provides very questionable results, we believe that hourly evaluation of QA/QC parameters should be dropped from Appendix E for combustion turbines. The parameter ranges are simply unnecessary.

Opacity Monitoring Exemption

Part 75 exempts combustion turbines from opacity monitoring. This exemption reflects the truly negligible amount of particulate produced by turbines resulting from the nature of the fuels fired and the particulars of the combustion process. However, many, if not most, states are incorporating opacity or particulate limits with periodic monitoring requirements, generally Method 9, into permits for new combustion turbines. These permit conditions are misguided and should be avoided when possible.

Issues Related to Combined Cycle Units

Substantial energy remains in the exhaust gas from a combustion turbine. In combined-cycle units, heat in the combustion turbine exhaust stream is recovered in the Heat Recovery Steam Generator (HRSG) to produce high pressure superheated steam for expansion through a steam turbine to make additional electric power. The output of the combined-cycle can be increased by supplementally heating the combustion turbine exhaust gases using duct burners within the HRSG. All emissions from the combined-cycle combustion turbine are exhausted into a single stack. As a result of BACT analysis, most modern combined-cycle turbines include dry-low NO_X technology and NO_x control devices such as Selective Catalytic Reduction (SCR).

Where duct burners are used, new combined-cycle units will be subject to two separate New Source Performance Standards (NSPS). The combustion turbine portion of the units will be subject to 40 CFR Part 60, Subpart GG for stationary gas turbines just like a simple-cycle turbine. The duct burners, which provide supplemental heat input to the HRSG, however, will be subject to the requirements of 40 CFR Part 60, Subpart Da, which applies to new electric utility units capable of combusting more than 250 mmBtu/hour heat input of fossil fuel in the steam generator. Both Subparts Da and GG establish emission limitations, along with performance testing and monitoring requirements.

Under Subpart Da, each boiler used to produce steam, including the HRSG in a combined-cycle combustion turbine, is treated as a separate unit. However, only those emissions "resulting from combustion of fuels in the steam generating unit" are subject to Subpart Da. The emissions from the combustion turbine that are exhausted into the HRSG are not subject to Subpart Da, but only to Subpart GG.

The Subpart Da NO_x limitation for new sources constructed after July 9, 1997 is 1.6 lbs/MW-hour gross energy output, based on a 30-day rolling average. Sources are required to install a NO_x CEM and a volumetric flow monitor in the stack to calculate NO_x mass emissions for determining compliance. The NO_x emissions from the HRSG duct burners are calculated using the appropriate equations in Method 19 to subtract the combustion turbine’s NO_x emissions from the total NO_x emissions measured in the stack during the Subpart GG combustion turbine performance tests.

Problems with Subpart Da

There are significant problems in trying to apply Subpart Da to combined-cycle combustion turbines. EPA’s stated intent is to regulate only the HRSG duct burners under Subpart Da but it is difficult, if not impossible, to do that on a discrete basis much less to calculate the 30-day rolling averages required by the rule. Another problem with Subpart Da is the required use of stack flow monitors for combined-cycle applications. Fortunately, EPA is currently considering changes to Subpart Da to address its deficiencies with respect to combined cycle units. The Agency has mentioned revisions are forthcoming and may be proposed as early as June.

Combined-Cycle Subpart GG Problems

For combined-cycle combustion turbine units with supplemental firing in the HRSG, initial performance testing under Subpart GG could be conducted at the gas turbine outlet.

Performing a Method 20 can, however, be very dangerous when the method is used on a combined cycle unit, particularly one that is equipped with SCR, because of the high temperature and pressure of the turbine exhaust at that location. The combination of high temperature and pressure makes Method 20 a very hazardous operation for testing personnel who could suffer serious injury. Although testing could be performed at the stack with the duct burners shutoff, that measurement will not provide a meaningful measurement of the combustion turbine emissions when SCR is installed.

Conclusions

It is important to understand that the purposes of Parts 60 and 75 are different. Part 60 establishes emissions limitations and a monitoring structure that is geared toward indicating periods when such limits might be breached, whereas Part 75 is intended to establish continuous emissions monitoring requirements for determining cumulative emissions under the Acid Rain Program. While the performance testing and monitoring requirement of Parts 60 and 75 can generally be met without much difficulty, careful planning can help avoid potential pitfalls and assist in minimizing the effort required to comply with the two somewhat duplicative rules. Attention should also be given to the peculiarities of each rule, including the differing regulatory deadlines and reporting mechanisms, with the understanding that the requirements can sometimes be combined through petitions to the Agency for custom fuel monitoring plans, performance test waivers and alternative monitoring protocols.