Hearings Fact Sheet - Department of Environmental Quality

STATE OF MICHIGAN Rick Snyder, Governor

DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

CONSTITUTION HALL ● 525 WEST ALLEGAN STREET ● P.O. BOX 30260 ● LANSING, MICHIGAN 48909-7760 www.michigan.gov/air

PUBLIC PARTICIPATION DOCUMENTS For Renaissance Power LLC Carson City, Michigan

PERMIT APPLICATION NUMBER 51-13 September 17, 2013

Renaissance Power LLC Permit No. 51-13

Page 1 September 17, 2013

FACT SHEET September 17, 2013 Purpose and Summary The Michigan Department of Environmental Quality (MDEQ), Air Quality Division (AQD), is proposing to act on Permit to Install (PTI) application No. 51-13 from Renaissance Power LLC. The permit application is for a proposed modification to convert the existing four (4) simple cycle natural gas-fired turbine electric generation units to combined cycle turbines. The proposed project is subject to permitting requirements of the MDEQ’s Rules for Air Pollution Control and state and federal Prevention of Significant Deterioration (PSD) regulations. Prior to acting on this application, the AQD is holding a public comment period and a public hearing, if requested in writing, to allow all interested parties the opportunity to comment on the proposed PTI. All relevant information received during the comment period and hearing if held, will be considered by the decision maker prior to taking final action on the application.

Background Information and Proposed Project The Renaissance Power LLC (Renaissance) facility is an existing power plant located in Carson City, Montcalm County. Renaissance currently operates four (4) simple cycle natural gas-fired Siemens 501 FD2 combustion turbine generators (CTG), a diesel-fired emergency generator, a diesel-fired firewater pump engine, and a natural gas-fired fuel heater, at this facility. The proposed modification and conversion includes the addition of four (4) heat recovery steam generators (HRSG) equipped with duct burners (DB) for supplemental firing and two (2) steam turbine generators (STG), resulting in two (2) power blocks, each in a “two-by-one” (2x1) configuration consisting of two CTG/HRSG and one STG. The CTG and duct burners will be permitted to operate on natural gas only. The project will require additional ancillary equipment to facilitate with startups and safe shutdowns of the facility including two (2) 40 million Btu per hour (MMBtu/hr) natural gas-fired auxiliary boilers, two (2) engine-driven 1000 kilowatt (kW) emergency diesel-fired generators each with a 2,000 gallon diesel storage tank. The existing ancillary equipment including the emergency generator, fuel heater, and firewater pump engine will remain and will not be physically modified. A mechanical draft cooling tower and water cooled condenser will be installed for the eastern power block. An Air Cooled Condenser will be installed for the western power block.

Present Air Quality The Renaissance facility is located in Montcalm County, which is currently in attainment with the National Ambient Air Quality Standards (NAAQS) for carbon monoxide (CO), nitrogen dioxide (NO 2 ), sulfur dioxide (SO 2 ), particulate matter that has an aerodynamic diameter less than or equal to a nominal 10 microns (PM10), particulate matter that has an aerodynamic diameter less than or equal to a nominal 2.5 microns (PM2.5), ozone, and lead.



Pollutant Emissions The existing facility is a major stationary source. The proposed project results in a significant emissions increase of CO, nitrogen oxide (NOx), particulate matter (PM), PM10, PM2.5, volatile organic compounds (VOC), and greenhouse gases (GHG) as carbon dioxide equivalent (CO 2 e). The proposed project is, therefore, subject to the PSD Regulations in Part 18 of the Michigan Air Pollution Control Rules and Title 40 Code of Federal Regulations Part 52.21 (40 CFR 52.21). The following table provides the estimated emissions for each criteria pollutant: TABLE 1 PROJECT EMISSION SUMMARY Total Emission PSD Significant Pollutant Increase Emission Rate (tpy) (tpy) 100 660.1 CO 40 508.3 NOx 40 36.5 SO 2 25 210.1 PM 15 210.5 PM10 10 204.6 PM2.5 296.4 VOC 40 0.00270 Lead 0.6 5,397,056 CO 2 e 75,000* 7 5.7 Sulfuric Acid Mist *Subject to Regulation (STR) Threshold

Subject to PSD? Yes Yes No Yes Yes Yes Yes No Yes No

Key Permit Review Issues Staff evaluated the proposed project to identify all state rules and federal regulations which are, or may be, applicable. The tables in Appendix 1 summarize these rules and regulations. •

Prevention of Significant Deterioration (PSD) Regulations – The project was reviewed under the PSD rules which require Best Available Control Technology (BACT), as summarized in Appendix 2, and an air quality impact analysis for each regulated air pollutant for which the project will result in significant emissions. The pollutants subject to PSD review were CO, NOx, PM, PM10, PM2.5, VOC, and GHG as CO 2 e.

•

Minor/Major Modification Determination for Attainment Pollutants – The facility is an existing PSD major stationary source and the proposed project is a major modification for CO, NOx, PM, PM10, PM2.5, VOC, and GHG as CO 2 e; and a minor modification for SO 2 , lead, and sulfuric acid mist. Renaissance is located in Montcalm County which is currently in attainment for all pollutants.

Renaissance Power LLC Permit No. 51-13 •


Federal NESHAP Regulations – National Emission Standards for Hazardous Air Pollutants (NESHAP) were established under 40 CFR Part 63. A major source under the NESHAP is defined as potential emissions of 10 tpy for a single hazardous air pollutant (HAP) or 25 tpy for all HAPs combined. An area source has potential HAP emissions below the major source values. The total potential HAP emissions from the proposed modified facility will be less than 10 tpy for any single HAP and 25 tpy for all HAP combined (4.9 tpy and 14.84 tpy respectively), and therefore the source is considered an area source of HAP emissions. The two emergency diesel-fired generators are subject to the NESHAP for Stationary Reciprocating Internal Combustion Engines, 40 CFR Part 63, Subpart ZZZZ. As the NESHAP for Stationary Combustion Turbines, 40 CFR Part 63, Subpart YYYY only applies to major HAP sources, it will not apply to the proposed four combined-cycle CTG. While there is an area source NESHAP for Industrial, Commercial, and Institutional Boilers, 40 CFR Part 63, Subpart JJJJJJ, it does not apply to the proposed auxiliary boilers as they will be exclusively natural gas-fired.

•

Federal NSPS Regulations – New Source Performance Standards (NSPS) were established under Title 40 of the Code of Federal Regulations (40 CFR) Part 60. The four reconstructed natural gas-fired CTG are subject to the NSPS for Stationary Combustion Turbines, 40 CFR Part 60 Subpart KKKK. The two emergency diesel-fired generators are subject to the NSPS for Stationary Compression Ignition Internal Combustion Engines, 40 CFR 60, Subpart IIII. The two auxiliary boilers are subject to the NSPS for Small Industrial-CommercialInstitutional Steam Generating Units, 40 CFR 60, Subpart DC. The fuel heater is not subject to this NSPS, since the installation date predates the applicability determination.

•

Rule 224 T-BACT Analysis – The MDEQ Rules for Air Pollution Control require that new or modified equipment that emits toxic air contaminants (TAC) must utilize the Best Available Control Technology for Toxics (T-BACT), unless the emission unit emits toxic air contaminants that are particulates or VOC and are in compliance with BACT or Lowest Achievable Emission Rate requirements. The emission units at Renaissance are subject to PSD BACT for both particulates and VOC, therefore per Rule 336.1224(2)(c), the T-BACT requirements of Rule 224 do not apply to this project.

•

Rule 225 Toxics Analysis – The MDEQ Rules for Air Pollution Control require the ambient air concentration of TAC be compared against health-based screening levels. The analysis used air dispersion modeling to evaluate the sum of the impacts of the TAC emissions from the reconstructed CTG/HRSG and new ancillary equipment based on the health-based screening levels. The TAC with the highest predicted ambient impact from this project was sulfuric acid. The modeled impact was approximately 7 percent of the initial threshold screening level (ITSL). The remaining TACs were significantly less than their respective ITSL. Therefore, the project will comply with the requirements of Rule 336.1225.



•

Rule 702 BACT Analysis for VOC – The MDEQ Rules for Air Pollution Control requires that new or modified equipment which emits VOC must meet BACT. The project is subject to Rule 702 BACT for VOC. A demonstration of compliance with PSD BACT (summarized in Appendix 2) will satisfy the Rule 702 BACT requirement.

•

Criteria Pollutants Modeling Analysis - An air quality impact analysis, as required by Rules 336.2811 through 336.2813, using computer dispersion modeling to predict the ambient air impacts was performed for CO, NOx, PM10, PM2.5, and SO 2 emissions. NOx refers specifically to nitrogen monoxide (NO) and NO 2 with the larger portion being that of NO 2 , a highly reactive gas, which is what United States Environmental Protection Agency (USEPA) established air quality standards for under the Clean Air Act. Additionally, Renaissance was granted a waiver for preconstruction ambient monitoring. A total of five different operating scenarios were utilized in the dispersion modeling for the project and the worst case impact for each criteria pollutant was used in comparison to the maximum levels allowed. Short term startup and shutdown emissions for NOx and CO were evaluated using an average hourly emission rate. This is the most appropriate data for the compliance demonstration as discussed in the USEPA memorandum “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NOx National Ambient Air Quality Standard” dated March 1, 2011. Specifically, the section titled Treatment of Intermittent Emissions. The Significant Impact Level (SIL) analysis considers the potential emission increases from the proposed project for CO, NO 2 , PM10, PM2.5, and SO 2 and compares them to the SIL, as shown in Table 2, below. The impacts of SO 2 and CO for all averaging periods, and PM10 on an annual average were determined to all be below their respective SIL. There is no SIL for either PM or GHG. TABLE 2 SIGNIFICANT IMPACT LEVELS (SIL) Pollutant

SO 2

PM10 PM2.5 NO 2 CO

Averaging Period

SIL 3 (ug/m )

1-hour 3-hour 24-hour Annual 24-hour Annual 24-hour Annual Annual 1-hour 8-hour

7.8 25 5 1 5 1 1.2 0.3 1 2,000 500

Project Maximum Impact 0.89 0.83 0.38 0.02 5.96 0.94 3.39 0.56 4.55 678 309

Below SIL? Yes Yes Yes Yes No Yes No No No Yes Yes

If the results determine that the modeled ambient air impacts, for each pollutant, are less than their respective SIL than no further modeling is required. If the results determine the modeled impacts exceed the SIL, then a facility-wide NAAQS and PSD Increment modeling analysis is required.



The NAAQS are intended to protect public health. The analysis compares the total facility impact, including any additional nearby facilities (background), to the NAAQS. There are no NAAQS for PM or GHG. Renaissance was required to do this analysis for NO 2 , PM2.5, and 24-hour PM10, since these pollutants were above their respective SIL. This analysis also included secondary PM2.5 from precursors of NOx and SO 2 , therefore the cumulative PM2.5 primary and secondary impacts were examined for comparison with the NAAQS. The results of the NAAQS analysis are below in Table 3. TABLE 3 NAAQS ANALYSIS Facility Background Maximum Pollutant Concentration Concentration 3 (ug/m ) 3 (ug/m ) 1-hour 188 88.51 67.9 NO 2 Annual 100 4.58 13.8 PM10 24-hour 150 4.83 29.0 24-hour 35 2.31 23.8 3 PM2.5 Annual 12 0.59 8.9 3 Includes secondary PM2.5 formation. 4 This is the total impact from the facility plus background. Averaging Period

NAAQS 3 (ug/m )

Total 4 Concentration 3 (ug/m )

Below NAAQS?

156.41 18.38 33.83 26.11 9.49

Yes Yes Yes Yes Yes

The PSD increments are intended to allow industrial growth in an area, while ensuring that the area will continue to meet the NAAQS. The analysis compares the total facility impact plus other increment consuming facilities nearby. There are no PSD Increments for PM, GHG, or CO. Renaissance was required to do PSD Increment modeling for PM2.5 and NO 2 for all averaging periods, and PM10 on a 24-hour averaging period, since these pollutants were above their respective SIL. This analysis also included secondary PM2.5 from precursors of NOx and SO 2 , therefore the cumulative PM2.5 primary and secondary impacts were examined for comparison with the increment. Additionally, there were no increment consuming sources relative to this source. The results of the PSD increment analysis are below in Table 4. TABLE 4 PSD INCREMENT ANALYSIS Facility Maximum Pollutant Concentration 3 (ug/m ) NO 2 Annual 25 4.58 PM10 24-hour 30 4.87 24-hour 1.2 3.39 3 PM2.5 Annual 0.3 0.56 3 Includes secondary PM2.5 formation. Averaging Period

PSD Increment 3 (ug/m )

Below PSD Increment? Yes Yes Yes Yes

While the facility will not directly emit ozone, the facility will emit both NOx and VOC at levels greater than 100 tpy, thus triggering the ozone ambient impact analysis requirements of 40 CFR 51.166. Ground-level ozone concentrations are the result of photochemical reactions among various chemical species. The chemical species that contribute to ozone formation, referred to as ozone precursors, include NOx and VOC emissions from both anthropogenic (e.g., mobile and stationary sources) and natural sources (e.g., vegetation).



The USEPA has not approved an ozone model for single source applications nor have they provided specific guidance for completing an ambient impact analysis for ozone as it relates to PSD. Therefore, Renaissance quantified the regional ozone formation impacts from the proposed project using a similar approach to quantifying secondary PM2.5 formation impacts and determined that the highest source impact for ozone would not be significant. •

Additional Impact Analysis – An additional impact analysis is required for major sources or major modifications pursuant to 40 CFR Part 52.21(o) and Rule 336.2815. This analysis is necessary to evaluate the impacts from the proposed project for soils, vegetation, visibility and growth. The proposed project is not anticipated to have a negative impact on soils, vegetation, visibility, and to have no impact on growth once construction is completed.

Key Aspects of Draft Permit Conditions The draft permit conditions contain emission limits, material limits, process/operational restrictions, monitoring, recordkeeping, and reporting requirements necessary for an enforceable permit that meets all applicable state and federal requirements. The following is a brief discussion of the key aspects of the draft permit conditions: •

Emission Limits – The draft permit includes emission limits for NOx, CO, VOC, PM, PM10, PM2.5, and CO 2 e to make the permit enforceable per the rules, and to protect the air quality standards.

•

Material Limits - The draft permit only allows the combustion of pipeline quality natural gas in the CTG, HRSG duct burners, auxiliary boilers, and fuel heater to assure fuel quality and consistency. Pipeline quality natural gas is required to have a minimum heat input (Btu) content and maximum sulfur content which affects combustion and air emissions. For the same reasons, the draft permit limits the emergency generators and existing engine-driven firewater pump fuel to only ultra-low sulfur diesel fuel with the maximum sulfur content of 15 ppm (0.0015 percent) by weight.

•

Process/Operational Restrictions – The draft permit requires a Malfunction Abatement Plan for the CTG/HRSG trains. Renaissance is required to develop the plan to include a preventative maintenance program and corrective procedures in the event of an equipment malfunction or failure. Also, the draft permit requires a plan that describes how emissions will be minimized during start-up and shutdown (SU/SD) for both the auxiliary boilers and the CTG/HRSG trains. The plan shall incorporate procedures recommended by the equipment manufacturer as well as incorporating standard industry practices. For the CTG/HRSG trains, start-up is defined as the period of time from initiation of combustion turbine firing until each combustion turbine reaches steady state synchronization to the grid (i.e. minimum of 50% of the maximum design capacity). Shutdown is defined as that period of time from the initial lowering of the CTG output (i.e. 50% of the maximum design capacity), with the intent to shutdown, until the point at which the combustion process has stopped.



The draft permit includes two standard operating restrictions on the emergency generators. The permittee shall not operate the diesel fueled emergency generators for more than 500 hours each per year on a 12-month rolling time period basis as determined at the end of each calendar month. Additionally, the permittee shall install, maintain, and operate the emergency generators according to the manufacturer’s written instructions, or procedures developed by the owner/operator and approved by the engine manufacturer, over the entire life of the engines. Also, the draft permit includes an operating restriction for the auxiliary boilers to use not more than 360.8 MMscf (million standard cubic feet) of natural gas per 12-month rolling time period combined the two auxiliary boilers. This is equivalent to 4,600 hours of operation for each on an annual basis and restricts the emissions from the boilers to less than their maximum potential to emit. •

•

Emission Control Device Requirements – The draft permit includes emission control device requirements for certain emission units. Emissions are controlled using both low emitting process equipment and add-on emission controls. −

Auxiliary Boilers - These units will be equipped with low-NOx burners to control NOx emissions.

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CTG/HRSG Trains - Each emission unit will have dry low-NOx combustors (CTG and HRSG with duct burners) and selective catalytic reduction (SCR) for NO X control and oxidation catalyst for CO and VOC control inside the HRSG.

Testing and Monitoring Requirements – The draft permit includes emissions testing, monitoring, and recordkeeping requirements for all emission units. Also, the sizes or capacities of the emission units are specified in the permit conditions. −

Two Emergency Generators - nameplate capacity shall not exceed 1000 kW; required non-resettable hours meters to track the operating hours; emissions testing or manufacturer certification documentation is required for non-methane hydrocarbon + NO x , CO, and PM emission rates; monthly calculations of emissions; a record of testing required or manufacturer certification documentation indicating that each emergency generator meets the applicable emission limitations; monitor and record the hours of operation of emergencies and non-emergencies, on a monthly and12-month rolling time period basis; fuel supplier certification records or fuel sample test data, for each delivery of diesel fuel oil used in the fire pump engine, demonstrating that the fuel sulfur content meets the material limit in the permit; and12-month rolling total CO 2 e mass emission records.

−

Two Auxiliary Boilers - maximum design heat input capacity for each auxiliary boiler shall not exceed 40.0 MMBtu (million British thermal units) per hour on a fuel heat input basis (based on standard operating conditions such as air temperature, humidity, and pressure); emissions testing required for NOx, CO, PM, PM10, PM2.5, and VOC emission rates from each boiler at maximum routine operating conditions, once every five years and initial operation; required device to monitor and record the fuel usage rate; records on a 12-month rolling total basis for CO 2 e mass emissions for each boiler; records of all information necessary for all notifications and reports as specified in the special conditions as well as that information necessary to demonstrate compliance with the emission limits of the permit.


•


−

Fuel Heater - maximum design heat input capacity for the fuel heater shall not exceed 20 MMBtu per hour on a fuel heat input basis; required device to monitor and record the fuel usage rate; records on a 12-month rolling total basis for CO 2 e mass emission for the fuel heater; records of all information necessary for all notifications and reports as specified in the special conditions as well as that information necessary to demonstrate compliance with the emission limits of the permit.

−

CTG/HRSG Trains - maximum design heat input capacity for each CTG/HRSG shall not exceed 2,807 MMBtu per hour on a fuel heat input basis (based on standard operating conditions such as air temperature, humidity, and pressure), including the combined fuel heat input for both the CTG and HRSG with duct burner; required testing for NO X and CO emission rates and mass emissions from each CTG/HRSG once every five years; required testing for PM, PM10, PM2.5 and VOC emission rates from each CTG/HRSG at maximum routine operating conditions once every five years; required continuous emission monitoring system (CEMS) to monitor and record the NOx emissions and oxygen or carbon dioxide (O 2 or CO 2 ) content of the exhaust gas from each CTG/HRSG; required CEMS to monitor and record the CO emissions and oxygen or carbon dioxide (O 2 or CO 2 ) content of the exhaust gas from each CTG/HRSG; required device to monitor and record the fuel flow rate on a continuous basis for each CTG/HRSG; records on a 24-hour rolling average basis of the NOx and CO concentration and mass emissions for each CTG/HRSG; records of start-up and shutdown events and the mass emissions for each CTG/HRSG; records on a 12-month rolling total basis for CO2e mass emissions for each CTG/HRSG; records of all information necessary for all notifications and reports as specified in the special conditions as well as that information necessary to demonstrate compliance with the emission limits of the permit.

Federal Regulations – Each of the four proposed CTG/HRSG trains will be subject to the NSPS for Stationary Combustion Turbines, 40 CFR Part 60 Subpart KKKK. Also, the fuel gas heater and each auxiliary boiler will be subject to the NSPS for Small IndustrialCommercial-Institutional Steam Generating Units, 40 CFR Part 60 Subpart Dc. The emergency generators will be subject to the NSPS for Stationary Compression Ignition Internal Combustion Engines, 40 CFR Part 60 Subpart IIII. The draft permit specifies that compliance with certain permit conditions will constitute compliance with the respective NSPS for each emission unit through required emission limits, process/operational restrictions, monitoring/recordkeeping, and reporting. The proposed emergency generators will also be subject to the NESHAP for Stationary Reciprocating Internal Combustion Engines, 40 CFR Part 63 Subpart ZZZZ. Compliance with the requirements of NSPS IIII constitutes compliance with the NESHAP as the emergency generators subject to the NSPS Subpart IIII have no additional emission limit requirements under the NESHAP.

Conclusion Based on the analyses conducted to date, the AQD staff concludes that the proposed project would comply with all applicable state and federal air quality requirements. The AQD Staff also concludes that this project, as proposed, would not violate the federal NAAQS or the state and federal PSD increments.



Based on these conclusions, the AQD staff has developed draft permit terms and conditions which would ensure that the proposed facility design and operation are enforceable and that sufficient monitoring, recordkeeping, and reporting would be performed by the applicant to determine compliance with these terms and conditions. If the permit application is deemed approvable, the delegated decision maker may determine a need for additional or revised conditions to address issues raised during the public participation process. If you would like additional information about this proposal, please contact Ms. Melissa Byrnes AQD, at 517-373-7065.


Page 10 September 17, 2013 Appendix 1 STATE AIR REGULATIONS

State Rule

R 336.1201

R 336.1205

R 336.1224

R 336.1225 to R 336.1232

R 336.1279 to R 336.1290 R 336.1299(2)(b) R 336.1301 R 336.1331 R 336.1370 R 336.1401 and R 336.1402 R 336.1601 to R 336.1651

R 336.1702

R 336.1801

R 336.1901

Description of State Air Regulations Requires an Air Use Permit for new or modified equipment that emits, or could emit, an air pollutant or contaminant. However, there are other rules that allow smaller emission sources to be installed without a permit (see Rules 336.1279 through 336.1290 below). Rule 336.1201 also states that the Department can add conditions to a permit to assure the air laws are met. Outlines the permit conditions that are required by the federal Prevention of Significant Deterioration (PSD) Regulations and/or Section 112 of the Clean Air Act. Also, the same types of conditions are added to their permit when a plant is limiting their air emissions to legally avoid these federal requirements. (See the Federal Regulations table for more details on PSD.) New or modified equipment that emits toxic air contaminants must use the Best Available Control Technology for Toxics (T-BACT). The T-BACT review determines what control technology must be applied to the equipment. A T-BACT review considers energy needs, environmental and economic impacts, and other costs. T-BACT may include a change in the raw materials used, the design of the process, or add-on air pollution control equipment. This rule also includes a list of instances where other regulations apply and T-BACT is not required. The ambient air concentration of each toxic air contaminant emitted from the project must not exceed health-based screening levels. Initial Risk Screening Levels (IRSL) apply to cancer-causing effects of air contaminants and Initial Threshold Screening Levels (ITSL) apply to non-cancer effects of air contaminants. These screening levels, designed to protect public health and the environment, are developed by Air Quality Division toxicologists following methods in the rules and U.S. EPA risk assessment guidance. These rules list equipment to processes that have very low emissions and do not need to get an Air Use permit. However, these sources must meet all requirements identified in the specific rule and other rules that apply. Adopts by reference the provisions of 40 CFR 63.40 to 63.44 (2002) and 40 CFR 63.50 to 63.56 (2002), the federal hazardous air pollutant regulations governing constructed or reconstructed major sources. Limits how air emissions are allowed to look at the end of a stack. The color and intensity of the color of the emissions is called opacity. The particulate emission limits for certain sources are listed. These limits apply to both new and existing equipment. Material collected by air pollution control equipment, such as dust, must be disposed of in a manner, which does not cause more air emissions. Limit the sulfur dioxide emissions from power plants and other fuel burning equipment. Volatile organic compounds (VOCs) are a group of chemicals found in such things as paint solvents, degreasing materials, and gasoline. VOCs contribute to the formation of smog. The rules set VOC limits or work practice standards for existing equipment. The limits are based upon Reasonably Available Control Technology (RACT). RACT is required for all equipment listed in Rules 336.1601 through 336.1651. New equipment that emits VOCs is required to install the Best Available Control Technology (BACT). The technology is reviewed on a case-by-case basis. The VOC limits and/or work practice standards set for a particular piece of new equipment cannot be less restrictive than the Reasonably Available Control Technology limits for existing equipment outlined in Rules 336.1601 through 336.1651. Nitrogen oxide emission limits for larger boilers and stationary internal combustion engines are listed. Prohibits the emission of an air contaminant in quantities that cause injurious effects to human health and welfare, or prevent the comfortable enjoyment of life and property. As an example, a violation may be cited if excessive amounts of odor emissions were found to be preventing residents from enjoying outdoor activities.


Page 11 September 17, 2013 STATE AIR REGULATIONS

State Rule R 336.1910 R 336.1911 R 336.1912 R 336.2001 to R 336.2060 R 336.2801 to R 336.2804 Prevention of Significant Deterioration (PSD) Regulations Best Available Control Technology (BACT)

R 336.2901 to R 336.2903 and R 336.2908

Description of State Air Regulations Air pollution control equipment must be installed, maintained, and operated properly. When requested by the Department, a facility must develop and submit a malfunction abatement plan (MAP). This plan is to prevent, detect, and correct malfunctions and equipment failures. A facility is required to notify the Department if a condition arises which causes emissions that exceed the allowable emission rate in a rule and/or permit. Allow the Department to request that a facility test its emissions and to approve the protocol used for these tests. The PSD rules allow the installation and operation of large, new sources and the modification of existing large sources in areas that are meeting the National Ambient Air Quality Standards (NAAQS). The regulations define what is considered a large or significant source, or modification. In order to assure that the area will continue to meet the NAAQS, the permit applicant must demonstrate that it is installing the BACT. By law, BACT must consider the economic, environmental, and energy impacts of each installation on a case-by-case basis. As a result, BACT can be different for similar facilities. In its permit application, the applicant identifies all air pollution control options available, the feasibility of these options, the effectiveness of each option, and why the option proposed represents BACT. As part of its evaluation, the Air Quality Division verifies the applicant’s determination and reviews BACT determinations made for similar facilities in Michigan and throughout the nation. Applies to new “major stationary sources” and “major modifications” as defined in R 336.2901. These rules contain the permitting requirements for sources located in nonattainment areas that have the potential to emit large amounts of air pollutants. To help the area meet the NAAQS, the applicant must install equipment that achieves the Lowest Achievable Emission Rate (LAER). LAER is the lowest emission rate required by a federal rule, state rule, or by a previously issued construction permit. The applicant must also provide emission offsets, which means the applicant must remove more pollutants from the air than the proposed equipment will emit. This can be done by reducing emissions at other existing facilities. As part of its evaluation, the AQD verifies that no other similar equipment throughout the nation is required to meet a lower emission rate and verifies that proposed emission offsets are permanent and enforceable. FEDERAL AIR REGULATIONS

Citation Section 109 of the Clean Air Act – National Ambient Air Quality Standards (NAAQS)

Description of Federal Air Regulations or Requirements The United States Environmental Protection Agency has set maximum permissible levels for seven pollutants. These NAAQS are designed to protect the public health of everyone, including the most susceptible individuals, children, the elderly, and those with chronic respiratory ailments. The seven pollutants, called the criteria pollutants, are carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter less than 10 microns (PM10), particulate matter less than 2.5 microns (PM2.5), and sulfur dioxide. Portions of Michigan are currently non-attainment for either ozone or PM2.5. Further, in Michigan, State Rules 336.1225 to 336.1232 are used to ensure the public health is protected from other compounds.


Page 12 September 17, 2013 FEDERAL AIR REGULATIONS

Citation 40 CFR 52.21 – Prevention of Significant Deterioration (PSD) Regulations Best Available Control Technology (BACT) 40 CFR 60 – New Source Performance Standards (NSPS) 40 CFR 63— National Emissions Standards for Hazardous Air Pollutants (NESHAP)

Description of Federal Air Regulations or Requirements The PSD regulations allow the installation and operation of large, new sources and the modification of existing large sources in areas that are meeting the NAAQS. The regulations define what is considered a large or significant source, or modification. In order to assure that the area will continue to meet the NAAQS, the permit applicant must demonstrate that it is installing BACT. By law, BACT must consider the economic, environmental, and energy impacts of each installation on a case-by-case basis. As a result, BACT can be different for similar facilities. In its permit application, the applicant identifies all air pollution control options available, the feasibility of these options, the effectiveness of each option, and why the option proposed represents BACT. As part of its evaluation, the Air Quality Division verifies the applicant’s determination and reviews BACT determinations made for similar facilities in Michigan and throughout the nation. The United States Environmental Protection Agency has set national standards for specific sources of pollutants. These New Source Performance Standards (NSPS) apply to new or modified equipment in a particular industrial category. These NSPS set emission limits or work practice standards for over 60 categories of sources. The United States Environmental Protection Agency has set national standards for specific sources of pollutants. The National Emissions Standards for Hazardous Air Pollutants (NESHAP) (a.k.a. Maximum Achievable Control Technology (MACT) standards) apply to new or modified equipment in a particular industrial category. These NESHAPs set emission limits or work practice standards for over 100 categories of sources.

Section 112 of the Clean Air Act

In the Clean Air Act, Congress listed 189 compounds as Hazardous Air Pollutants (HAPS). For facilities which emit, or could emit, HAPS above a certain level, one of the following two requirements must be met:

Maximum Achievable Control Technology (MACT)

1) The United States Environmental Protection Agency has established standards for specific types of sources. These Maximum Achievable Control Technology (MACT) standards are based upon the best-demonstrated control technology or practices found in similar sources.

Section 112g

2) For sources where a MACT standard has not been established, the level of control technology required is determined on a case-by-case basis.

Notes: An “Air Use Permit,” sometimes called a “Permit to Install,” provides permission to emit air contaminants up to certain specified levels. These levels are set by state and federal law, and are set to protect health and welfare. By staying within the levels set by the permit, a facility is operating lawfully, and public health and air quality are protected. The Air Quality Division does not have the authority to regulate noise, local zoning, property values, offsite truck traffic, or lighting. These tables list the most frequently applied state and federal regulations. Not all regulations listed may be applicable in each case. Please refer to the draft permit conditions provided to determine which regulations apply.



Appendix 2 – Best Available Control Technology Analysis (Michigan Rule 336.2810) Four (4) Combined Cycle Natural Gas-fired Combustion Turbine Generators (CTG) with Duct Burners (DB) for supplemental firing of the Heat Recovery Steam Generators (HRSG)

A requirement of PSD New Source Review is a Best Available Control Technology (BACT) analysis. The topdown BACT approach per the EPA DRAFT New Source Review Workshop Manual (October 1990) was utilized. The top-down approach considers all available emission reduction options and proceeds in a five-step process as follows: 1. Identify all control technologies; 2. Eliminate technically infeasible options; 3. Rank the remaining control technologies by control effectiveness; 4. Evaluate the most effective controls and document the results; 5. Select BACT (e.g., the most effective option not rejected is BACT). Combined Cycle Combustion Turbine Generators The four (4) CTG/HRSG are subject to a BACT analysis for the following regulated pollutants: CO, NOx, PM, PM10, PM2.5, VOC, and GHG (as CO 2 e). The following is a summary of the BACT analysis. BACT for NOx NOx is generated thermally when nitrogen reacts with oxygen in the combustion air in a high temperature environment, and from oxidation of organic nitrogen compounds in the fuel (fuel NOx). Fuel properties have a significant impact on NOx formation. Pipeline quality natural gas contains free nitrogen, but no fuel bound nitrogen. Renaissance Power identified several combustion and post combustion control technologies for the control of NOx emissions from each CTG/HRSG with DB. The following technologies were identified and evaluated: Combustion and Post Combustion Controls

•

Dry Low-NOx Burners (LNB)

•

Water or steam injection

•

Selective Non-Catalytic Reduction (SNCR)

•

Selective Catalytic Reduction (SCR)

•

Xonon Cool Combustion™

•

EMx

TM

TM

(Formerly SCONOx )

The review of each of these technologies is summarized below. •

Dry low-NOx burners (LNB) are commonly combined with post combustion controls to achieve the lowest NOx emission rates. LNB control fuel and air mixing ratios in the burner of the turbine in order to reduce flame temperature and reduce thermal NOx formation. This technology is considered a technically feasible control alternative and will be the baseline scenario since the proposed turbines will be designed with LNB.

•

Water or steam is injected into the combustion air of the turbine in order to reduce thermal NOx. Water or steam injection is not compatible with dry low-NOx burners which are considered for this project and therefore, this technology is not considered a technically feasible control alternative, for this project.

•

Selective non-catalytic reduction (SNCR) involves injecting urea or ammonia into the exhaust gases where temperatures exceed 1,500°F, which reacts with NOx, forming elemental nitrogen and water without the need for a catalyst. Instead of a catalyzed reaction, the NOx reduction reactions are driven by the thermal



decomposition of urea or ammonia and the subsequent chemical reaction reduction of NOx. SNCR systems can control NOx with efficiencies up to about 75 percent. The ideal temperature window for SNCR is 1,600°F to 2,100°F. The temperature entering the HRSG after the combustion turbine will be approximately 1,100°F. Therefore, SNCR is not considered a technically feasible control alternative for a combined-cycle combustion turbine because there is not an appropriate temperature window for ammonia injection and adequate reduction of NOx in the exhaust gases. •

Selective catalytic reduction (SCR) is a post combustion system that can reduce NOx emissions at 80 to 95 percent efficiency. SCR systems consist of an ammonia injection system and a catalytic reactor. Ammonia is injected into the flue gas where it reacts with NOx in the presence of the catalyst to form molecular nitrogen (N 2 ) and water. This reaction occurs at flue gas temperatures of 600 to 800°F. The efficiency of the SCR system operation depends on catalyst reactivity, routine replacement of the catalyst, and maintaining a proper ammonia injection rate. This technology is considered a technically feasible control alternative.

•

Xonon Cool Combustion™ uses a catalyst instead of a flame in the combustion process, enabling combustion at temperatures below the threshold at which thermal NOx forms. This technology has not been demonstrated in practice on a larger utility CTG. Therefore, Xonon Cool Combustion™ is not considered a technically feasible control alternative, for this project.

•

EMx is similar to SCR, except that NOx in the exhaust stream reacts with potassium carbonate (K 2 CO 3 ) to form potassium nitrate (KNO 3 ). This compound is reacted with hydrogen to form gaseous nitrogen (N 2 ), TM and regenerate the K 2 CO 3 . The lower exhaust temperature required for the reactions in the EMx to take TM place is less than that of SCR (300°F verses 600 to 800°F). The EMx system also provides reductions in CO emissions and to a lesser degree, reductions in VOC emissions by oxidation. This technology has not TM been demonstrated in practice on a larger utility CTG. Therefore, EMx is not considered a technically feasible control alternative, for this project.

TM

TM

Water/steam injection, SNCR, Xonon Cool Combustion™, and EMx were considered not technically feasible for this application. The technically feasible control technologies were ranked by control effectiveness as follows: Expected Effectiveness Control System

Based on outlet concentrations in parts per million by volume (ppmv)

LNB + SCR

2–4

SCR

2–9

LNB

8 – 25

It is proposed that BACT for NOx is the use of LNB and SCR technology together with emission limits at different operating scenarios. It is necessary to include a BACT limit during steady state (normal) operation as well as during startup and shutdown, where combustion is inefficient and emission rates per unit of fuel combusted are significantly elevated compared to normal operation. At low loads, the combustors are not yet operating in lean pre-mix mode which contributes to higher NOx emission rates. During normal operation (loads greater than 50 percent of capacity), BACT is represented by an emission limit of 2 ppmv dry at 15% oxygen based on a 3-hour rolling average and 18.6 pounds per hour based on a 24-hour rolling average for each CTG; and 2 ppmv dry at 15% oxygen based on a 3-hour rolling average and 23.7 pounds per hour based on a 24-hour rolling average for each CTG/HRSG operating with a DB. During SU/SD operations (loads less than 50 percent of capacity), each CTG is limited to 500 hours per 12-month rolling time period. BACT is represented by an emission limit of 176.9 pounds per hour during startup and 147.3 pounds per hour during shutdown, both limits are based on an operating hour.



For dispersion modeling, an average hourly emission rate was used as the most appropriate data for the compliance demonstration as discussed in the EPA memorandum “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NOx National Ambient Air Quality Standard” dated March 1, 2011, specifically the section titled Treatment of Intermittent Emissions. All mass emission limits are protective of NAAQS and PSD increment. Compliance with these limits will be monitored using a NOx CEMS.

BACT for CO CO and VOC emissions result from the incomplete combustion of carbonaceous fuels, such as natural gas. The primary influencing factors for CO and VOC formation are the combustion temperature, turbulence (mixing of fuel and oxygen) and the residence time in the combustion zone. Renaissance Power identified combustion and post combustion control technologies for the control of CO and VOC emissions from each CTG. The following technologies were identified and evaluated:

Combustion and Post Combustion Controls

•

EMx

•

Catalytic Oxidation System (COS)

•

Good Combustion Control Practices

TM

TM

(Formerly SCOCO )


EMx (Formerly SCOCO ) is similar to SCR, except that NOx in the exhaust stream reacts with potassium carbonate (K 2 CO 3 ) to form potassium nitrate (KNO 3 ). This compound is reacted with hydrogen to form gaseous nitrogen (N 2 ), and regenerate the K 2 CO 3 . The lower exhaust temperature required for the TM TM reactions in the EMx to take place is less than that of SCR (300°F verses 450°F). The EMx system provides reductions in CO emissions and to a lesser degree, reductions in VOC emissions by oxidation. TM This technology has not been demonstrated in practice on a larger utility CTG. Therefore, EMx is not considered a technically feasible control alternative, for this project.

•

Catalytic Oxidation Systems (COS) have been applied to combustion turbines and have demonstrated their ability to effectively reduce CO and VOC emissions. They are also commercially available from numerous vendors. COS is considered a feasible control alternative, for this project.

TM

TM

TM

EMx was considered not technically feasible for this application. The technically feasible control technologies were ranked by control effectiveness as follows: Expected Effectiveness Control System

Based on outlet concentrations in parts per million by volume (ppmv)

COS

2-5

Good Combustion Practices – CTG

4 – 10

Good Combustion Practices – CTG and LNB

8 - 25

It is necessary to include a BACT limit during steady state (normal) operation and an alternative BACT limit during startup and shutdown, where combustion is inefficient and emission rates per unit of fuel combusted are elevated compared to normal operation. At the very early stages of the startup cycle, the COS is technology limited and it is difficult to accurately measure CO because of specific stack O2 conditions. However, the startup cycle for combustion equipment of this nature requires far less time than other types of combustion processes used to generate electricity.



It is proposed that BACT for CO and VOC emissions is the use of good combustion control practices and a COS together with emission limits. During normal operation (loads greater than 50 percent of capacity), BACT for CO is represented by an emission limit of 2.0 ppmv dry at 15% oxygen based on a 3-hour rolling average and 11.4 pph based on a 24-hour rolling average for each CTG; and 2.0 ppmv dry at 15% oxygen based on a 3-hour rolling average and 14.5 pph based on a 24-hour rolling average for each CTG/HRSG operating with a DB. During SU/SD events, the add-on COS control technology is not fully functional due to the exhaust gas temperature through the HRSG being less than the temperature necessary for optimal catalyst operation. BACT for CO during SU/SD operations (loads less than 50 percent of capacity), each CTG is limited to 500 hours per 12-month rolling time period. BACT is represented by an emission limit of 456.3 pph during startup and 360.0 pph during shutdown, for each CTG. Compliance with the CO limits will be monitored using a CO and diluent CEMS. For purposes of facilitating emissions measurements during periods of startup and shutdown, the diluent capping procedures of Section 3.3.4 of 40 CFR Part 75, Appendix F, may be utilized. The mass emission limit is protective of the NAAQS. During normal operation, BACT for VOC is represented by an emission limit of 2.0 ppmv dry at 15% oxygen for each CTG/HRSG operating with or without a DB. Compliance with the VOC limits will be determined through stack testing. Averaging times for the emission limit will be based on testing protocols. Michigan Air Pollution Control Rule 336.2003(5) requires that “Minimum sample time shall be 60 minutes, which may be continuous or a combination of shorter sampling periods for sources that operate in a cyclic manner.” Compliance with the VOC emission limit will be based on a short-term average.

BACT for PM, PM10, and PM2.5 Particulate matter emissions from the combustion of natural gas depends on suspended particles in the combustion air, sulfates formed due to sulfur in the fuel, the products of incomplete combustion such as unburned carbon, and metallic oxides from degradation of internal turbine components. Particulate matter less than 10 microns in diameter is called PM10 and particulate matter less than 2.5 microns in diameter is called PM2.5 and each type includes both the “filterable” and “condensable” fraction of particulate matter and both were evaluated simultaneously. PM exists as a solid or liquid at temperatures of approximately 250°F and are considered the “filterable” or “front half” of particulate matter. The “condensable” portion of PM10 and PM2.5 is particulate matter that exists as a solid or liquid at temperatures less than 32°F. It includes substances such as nitrogen compounds and sulfur compounds, which are in a vapor state at high temperatures, acid gases, VOCs, etc., but does not include condensed water vapor. Renaissance identified several combustion and post combustion control technologies for the control of PM, PM10, and PM2.5 emissions. The following technologies were identified and evaluated: Combustion and Post Combustion Controls

•

Combustion Controls

•

Pipeline Quality Natural Gas

•

Fabric Filter Baghouses

•

Dry Electrostatic Precipitators (ESPs)

•

Wet ESPs

•

Wet Scrubbers




PM, PM10, and PM2.5 emissions from natural gas combustion are inherently low, and combustion controls can further minimize the amount of particulate generated due to incomplete combustion in the combinedcycle units. Optimization of the combustion chamber designs and operation practices that improve the oxidation process and minimize incomplete combustion is the primary mechanism available for lowering emissions, and often referred to as combustion controls.

•

The formation of particulate can result from the oxidation of sulfur compounds, which can precipitate as particulate matter in the exhaust stream. Pipeline quality natural gas contains very low levels of sulfur; thus, emissions of sulfur and the resulting PM, PM10, and PM2.5 are minimized through the use of this cleanburning fuel.

•

A fabric filter baghouse removes particulate from the flue gas using fabric filter bags. As the particulate laden gas passes through the bags, a layer of particulate called “filter cake” builds up on the bags which also act as a filteration device. Fabric filters can achieve high levels of PM, PM10, and PM2.5 control at greater than 99% (as high as 99.9+%) on a mass basis. Fabric filter baghouses have several advantages when used for particulate control including high control efficiencies, relatively constant outlet grain loading over the load ranges, and simple operation and maintenance. Fabric filters are also considered to be the best technology for capturing fine filterable particulate.

•

A dry ESP is a large enclosure filled with a series of fields which consist of negatively charged discharge electrodes and positively charged collection plates. The discharge electrodes negatively charge the particles in the gas stream which migrate to the positively charged plates. Particulate collected on the plates is periodically removed by rapping the plates. Factors affecting particulate collection efficiency of an ESP include gas flow rate through the ESP, total plate area, particulate resistivity, voltage, and the sectionalization of the ESP. The smaller the collection area of the ESP, the narrower the acceptable resistivity range becomes. To optimize particulate resistivity and maximize collection efficiency, sulfur trioxide is injected to condition the ash and reduce particulate resistivity. ESPs have lower pressure drops across the control device than fabric filters which saves energy by reducing fan horsepower requirements, and therefore, the parasitic load on the generating unit. ESPs can achieve control efficiencies of greater than 99%.

•

Wet ESPs are similar to dry ESPs with negative and positive charged fields that attract particles. However, in a wet ESP, the flue gas is cooled below the dew point and particulate matter may be present as either solid or liquid particles. Water droplets, other condensable materials (e.g., sulfuric acid), and fine particulate matter can be collected by the charged fields. The electrodes are flushed with water to remove collected materials.

•

Wet scrubbers remove particulate using several mechanisms, including condensation, inertial impaction of particulate with water droplets, and reactions of PM and PM precursors with the scrubber reagents. Particulate control efficiency in a wet scrubber is variable depending on the scrubber design, particulate size, and particulate loading but control efficiency can be greater than 90%.

Renaissance evaluated the technical feasibility of the potential control options. It was determined that the use of combustion controls and pipeline quality natural gas fuel were the only available and technically feasible options, based on information in EPA’s RBLC database, no other natural gas-fired combined-cycle unit has been equipped with an add-on particulate control device. Renaissance proposes to use combustion controls and pipeline quality gas fuel together with emission limits, as BACT for PM, PM10, and PM2.5 emissions. PM Renaissance proposes an emission limit of 0.0042 pounds per MMBtu for each CTG and 0.0073 pounds per MMBtu for each CTG/HRSG operating with a DB.



PM10 Renaissance proposes emission limits of 0.0042 pounds per MMBtu and 9.0 pounds per hour, which includes startup and shutdown for each CTG; and 0.0073 pounds per MMBtu and 15.6 pounds per hour for each CTG/HRSG operating with a DB. The mass emission limits are protective of the NAAQS and PSD increment. PM2.5 Renaissance proposes emission limits of 0.0042 pounds per MMBtu and 9.0 pounds per hour, which includes startup and shutdown for each CTG; and 0.0073 pounds per MMBtu and 15.6 pounds per hour for each CTG/HRSG operating with a DB. The mass emission limits are protective of the NAAQS and PSD increment. Compliance with the PM, PM10, and PM2.5 limits will be determined through stack testing. Averaging times for the emission limit will be based on testing protocols. Michigan Air Pollution Control Rule 336.2003(5) requires that “Minimum sample time shall be 60 minutes, which may be continuous or a combination of shorter sampling periods for sources that operate in a cyclic manner.” Compliance with the PM10 and PM2.5 emission limit will be based on a short-term average.

BACT for Greenhouse Gases (GHG) GHGs are generated when fuel is combusted. GHGs are regulated as a single air pollutant defined as the aggregate mix of six well-mixed GHGs. The six GHGs are carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF 6 ). Some of these GHGs have a higher global warming potential than others. To address this, GHGs are converted to carbon dioxide equivalents (CO 2 e). Emissions of gases other than CO 2 are translated into CO 2 e by using the gases’ global warming potential. Total GHG emissions are calculated by summing the CO 2 e emissions of all six constituent GHGs. Efficient combustion of natural gas results in conversion of almost all the fuel to CO 2 , with only trace amounts of CH 4 and N 2 O. No HFCs, PFCs, and SF 6 are produced with the combustion of natural gas. Since CH 4 and N 2 O have higher global warming potential, less efficient combustion results in higher CO 2 e emissions. Renaissance identified several combustion and post combustion control technologies for the control of GHGs. The following technologies were identified and evaluated: Combustion and Post Combustion Controls

•

Carbon Capture and Sequestration (CCS)

•

Lower Emitting Alternative Technologies

•

Thermal Efficiency


Carbon capture and sequestration (CCS) is a multiple-step process. The first step in CCS is capture of the CO 2 from the flue gas, the transportation of CO 2 emissions, and then long-term storage of the captured CO 2 , or sequestration. Depending on which sequestration method is selected, capture may or may not be necessary. For example, geological sequestration requires that the CO 2 be captured prior to the sequestration step, whereas terrestrial sequestration does not. (Both of these sequestration methods are described in more detail below.) Capture and sequestration are evaluated separately to determine feasible solutions for each step of the CCS process. Each step of the process is described in detail below.

–

Carbon Capture Carbon capture is the separation of CO 2 from the flue gas before it is emitted through the exhaust stack from the facility. Capture systems being developed are expected to collect up to 90 percent of flue gas CO 2 . There are a number of CO 2 capture technologies and capture enhancement methods including: o

Absorption processes, such as a hybrid solution (mixed physical and chemical solvent);

Renaissance Power LLC Permit No. 51-13 o o o


Physical separation (membrane, cryogenic separation); Adsorption processes; and Biological uptake of CO 2 by algae.

Absorption (chemical, physical, and hybrid technologies) – In chemical absorption, CO 2 is scrubbed from flue gases through a chemical reaction with the scrubbing medium. The most commonly used scrubbing mediums for CO 2 are amine solutions. These solutions are commercially available today, but none have been used on the scale encountered in electrical generation. Physical absorption uses a scrubbing solution where CO 2 is more soluble in the solution than other gases components in the exhaust gas. Physical separation technologies include membrane and cryogenic separation. In physical absorption, no reaction takes place between CO 2 and the scrubbing solution. The targeted gas, in this case CO 2 , is selectively absorbed into the solution. Physical absorbents currently being developed include propylene carbonate and several proprietary materials. These materials are used to separate CO 2 from the exhaust stream. They are later regenerated and the CO 2 is captured for further processing or sequestration. Although physical absorbents are easier to regenerate than chemical absorbents, they are less effective than chemical absorbents at removing CO 2 from dilute gas streams. Polymer-based membrane technology is currently under development and is not commercially available. In cryogenic separation, the gas is cooled and compressed to condense CO 2 . This technology is only effective on flue gas with very high CO 2 concentrations. In hybrid absorption both chemical and physical absorbents are used. Hybrid absorption allows the user to tailor the absorbents to a specific application. One technology currently being developed is based on the combination of a hollow fiber membrane contactor with absorption technologies. This process utilizes solvent absorption, which performs as the selective layer, within a hollow fiber configured membrane contactor made of the chemically and thermally resistant polymer. Adsorption Processes - Solid sorbents include zeolite, activated carbon, lime and other proprietary materials that use chemical adsorption, physical adsorption, or a combination of the two. Contacting the flue gas with the solid sorbent includes fixed, moving and fluidized beds. Biological Uptake – There is ongoing research into algae strains that can uptake CO 2 from a concentrated stream via photosynthesis and produce bio-fuel. This process is not commercially available at this time. Currently, absorption technology is the most feasible technology for carbon capture and is considered an available technology. Of the technologies presented, the most developed is the amine- and ammonia-based absorption technologies. However, the process of separating CO 2 from the flue gas has high energy demand and is cost intensive. Therefore, the addition of a carbon capture system would reduce the net generating capacity of the proposed combined-cycle operation, and any gains in process efficiency. –

Transportation of CO 2 emissions Captured CO 2 emissions would have to be transported to a storage site. Depending on the type of project, transportation may involve pipelines, truck transport, ocean-going vessels, etc.

–

Carbon Sequestration Sequestration is the long term isolation of CO 2 from the atmosphere through physical, chemical, biological, or engineered processes. Geological sequestration is a sequestration technique involving the storage of captured CO 2 in a location where it will not readily escape into the atmosphere. Current technology involves the use of deep underground rock formations where the extreme pressure and temperatures cause the CO 2 to enter the liquid phase, and can be used for enhanced oil recovery (EOR). Injected CO 2 occupies pore spaces in the surrounding rock. Saline water residing in the pore space will be displaced by the CO 2 . The CO 2 also dissolves in water and chemical reactions between the dissolved CO 2 and rock create solid carbonate minerals which trap CO 2 . Another sequestration technique is ocean storage. This is done by injecting CO 2 into the ocean at depths typically below 1,000 meters. The CO 2 is expected to dissolve or form into a lake which would delay the dissolution of CO 2 back into the environment.



•

Terrestrial sequestration involves using plant mass to absorb CO 2 from the atmosphere during photosynthesis and ultimately metabolize and store carbon as vegetative tissue mass, or transfer the carbon to the soil. Terrestrial sequestration has a lower ultimate storage capacity and requires that any changes to land use management be maintained for long periods of time to prevent inadvertent CO 2 releases (e.g., forest fires). Large quantities of land would be required for terrestrial sequestration, and the long-term impact and practicality of this approach would need to be further evaluated for this alternative.

•

Lower emitting alternative technologies to generate power include wind, solar, geothermal, hydroelectric, nuclear, and biomass-fueled plants. These technologies are not capable of providing power on-demand. The proposed project would provide flexible, dispatchable, and fast ramping power that would not obstruct development and use of renewable resources. Also, application of these lower emitting technologies would fundamentally alter the business purpose of the emission source, and are therefore eliminated from further consideration for this project.

•

Energy (thermal) efficiency in a combustion process minimizes the use of fuel through maximizing energy output. The more complete the combustion, the higher the energy output.

Terrestrial sequestration was considered not a feasible control technology for this retrofit project because of the lack of land. The technically feasible control technology combinations were ranked by control effectiveness as follows: Control System

Expected Effectiveness Based on percent of pollutant removed

CCS

Up to 90%

Energy Efficiency

50 – 60%

Carbon capture and sequestration were reviewed for economic, energy, and environmental impact. CCS is assumed to be about 90 percent effective. However, the use of CCS technology for natural gas-fired combined cycle units entails significant economic, energy, and environmental impacts as a control method would also result in significant energy and environmental impacts due to the increased fuel usage required to operate the CCS systems. Renaissance referred to a detailed cost analysis conducted by Carnegie Mellon 1 University which specifically analyzed costs for plants using amine-based post-combustion CCS systems with 90% CO2 capture. The analysis found that CCS increases capital costs (in 2007 basis) by approximately $600/kW, which would result in an incremental capital cost of approximately $840 million for this project. The analysis also found the cost (in 2007 basis) of CO2 avoided, ranged from $74 to $114 per ton CO2 which equates to annual costs of $400 to $600 million. The information referred to above in the Carnegie Mellon study is consistent with other available data such as a white paper by CH2M Hill for Southern Cal Edison 2 which estimated the incremental cost of retrofitting an existing plant with an amine-based CCS system to be $785/kW. CCS is not considered available for this project due to the lack of nearby, demonstrated, large-scale sequestration sites, and the uncertainty and time delay associated with designing, obtaining permits and easements and constructing a pipeline to transport captured CO2 to a sequestration site. Furthermore, as shown above, significant costs associated with installation and operation and maintenance of a CCS system makes the technology economically infeasible. 1

The cost of Carbon Capture and Storage for Natural Gas Combined Cycle Power Plants, Rubin and Zhai, Department of Engineering and Public Policy, Carnegie Mellon University, http://www.wecc.biz/committees/BOD/TEPPC/SPSG/MDTF/120914/Lists/Minutes/1/CCS_Costs_for_Combined_Cycle.pdf

2

Technical and Regulatory Analysis of Adding CCS to NGCC Power Plants in California, CH2M hill, http://web.mit.edu/sequestration/costing/pdfs/2010_CH2M-HILL.pdf



Therefore, Renaissance selected energy efficiency as BACT for this project. A natural gas-fired combined-cycle operation is expected to have a thermal efficiency of approximately 50 to 60 percent on a higher heating value (HHV) basis at ISO conditions. BACT is represented by an emission limit or work practice standard. As BACT for GHG has been determined to be energy efficiency, Renaissance is proposing heat input capacity of 2,147 MMBtu per hour and a gross energy output rate of 1,000 lbs CO2e/MW-hr, based on a 12-month rolling time period for each CTG/HRSG and DB. Heat rates are a measure of the energy input required to produce a given level of electrical output. A margin for compliance of 5% was used in calculating the expected maximum CO2 emissions rate. While this emission rate is slightly higher than other recent BACT determinations it is a result of taking into account that the combustion turbines are older units installed in 2001 and have already experienced some level of degradation. Compliance with the proposed limit will be calculated from the continuously monitored CO2 emissions.



Auxiliary Boilers, Fuel Heater, and Emergency Generators A top-down PSD BACT analysis was performed for all of the other proposed ancillary equipment, which includes the two auxiliary boilers, fuel heater, and two emergency generators. The complete PSD BACT analyses for these units are contained in the application file and are available for public review. High efficiency designs and limited use of the equipment resulted in determinations that no add-on controls were required. Below is a summary of the proposed PSD BACT limits for these units:

Auxiliary Boilers PSD BACT Limits Annual Equivalent Limit 1 Pollutant lb/MMBtu heat input, tpy each unit Total for both units CO 0.036 6.6 NO X 0.035 6.4 PM 0.005 0.9 PM10 0.005 0.9 PM2.5 0.005 0.9 VOC 0.005 0.9 GHG as CO 2 e ---11,503.7 (BACT limit) 1 Based on an annual maximum natural gas usage rate of 180.4 MMscf/unit per 12-month rolling time period.

Fuel Heater PSD BACT Limits Annual Equivalent Limit 1 Pollutant lb/MMBtu heat input, tpy each unit Total for both units CO 0.09 6.6 NO X 0.15 13.4 PM 0.009 0.8 PM10 0.009 0.8 PM2.5 0.009 0.8 VOC 0.05 4.2 GHG as CO 2 e ---10,943.0 (BACT limit) 1 Based on an annual maximum natural gas usage rate of 171.8 MMscf/unit per 12-month rolling time period.

Emergency Generators PSD BACT Limits Annual Equivalent Limit 2 Pollutant g/bhp-hr, tpy each unit Total for both units CO 2.6 4.3 NO X 4.8 7.9 PM 0.15 0.25 PM10 0.15 0.25 PM2.5 0.15 0.25 VOC --0.19 GHG as CO 2 e ---1,731.4 (BACT Limit) 2 Based on an annual maximum of 500 hours/unit per 12-month rolling time period.

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