Air Quality Permitting of New DC Water Biosolids ... - IngentaConnect

Residuals and Biosolids 2011

Air Quality Permitting of New DC Water Biosolids Projects Ersin Kasirga, Parsons (Principal Author) Walter Bailey, DC Water Chris Peot, DC Water Blue Plains AWTP Biosolids Program Management 5000 Overlook Avenue SW Washington, DC 20032 ABSTRACT The Blue Plains Advanced Wastewater Treatment Plant (AWTP) located in Southwest Washington, D.C. is a 370 million gallon per day average flow municipal treatment plant that processes wastewater from Washington, D.C. and parts of the suburban Maryland and Northern Virginia. The plant is owned and operated by the District of Columbia Water and Sewer Authority (DC Water). As part of the new Biosolids Management Program (BMP), DC Water has embarked on a $407 million design, construction, and commissioning of new biosolids handling facilities comprised of Main Process Train (MPT), Combined Heat & Power (CHP) and Final Dewatering Facility (FDF). The MPT project will be comprised of the Thermal Hydrolysis Process (THP) which will reduce the quantity of solids hauled offsite, produce Class A pathogen-free biosolids and generate a renewable fuel in the form of digester gas. The CHP component of the BMP will use digester gas and/or natural gas in some combination to fire combustion gas turbines to generate about 13 MW of electric power. Heat from the gas turbine exhaust gases will be recovered in Heat Recovery Steam Generators (HRSGs) that will supply steam for the THP. The FDF include a new belt filter press system to mechanically dewater the Class A, thermally hydrolyzed-digested biosolids. The Washington, DC metropolitan area was reclassified from a serious to a severe ozone nonattainment area in 2003. Under the District of Columbia Municipal Regulations (DCMR), the District Department of the Environment Air Quality Division (DDOE) is the responsible agency for undertaking the State Implementation Plans (SIPs) in Washington DC area. Both federal regulations and the DCMR apply to the MPT, CHP and FDF projects for air quality permitting. Since the DC Water had already submitted Title V application, it is anticipated that the Title V will be amended after the approval of the air quality permit application. The DC Water estimated that the new biosolids projects will constitute a major source for nitrogen oxides (NOx) emissions and Non attainment New Source Review (NNSR) threshold will be triggered. Since the RFPs for the MPT and FDF projects are already issued and the RFP for the CHP project is already underway, securing the Permit to Construct (PTC) in a timely fashion is crucial to meet the schedule and budget requirements of the projects under the BMP. DC Water is requesting a permit to construct from the DDOE not later than June 2011 to avoid delays in construction of the Biosolids Projects. This is in concert with DC Water’s goal to improve the air quality and environment while complying with the Federal Regulations and the DCMR. Since DC Water is concerned about handling potential project changes during permitting, the permitting team developed conceptual permitting pathways to handle potential

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project changes during permitting process. It is anticipated that as designs are refined later during preliminary and final design stages of the MPT and the CHP projects, the Potential to Emit (PTE) estimates that will be included in the Permit to Operate (PTO) application are likely to come down. This will be in concert with DC Water’s goal to improve the air quality and environment while complying with the Federal regulations and the DCMR. KEYWORDS Air quality permitting, DC Water. INTRODUCTION The Blue Plains Advanced Wastewater Treatment Plant (AWTP) located in Southwest Washington, D.C. is a 370 million gallon per day average flow municipal treatment plant that processes wastewater from Washington, D.C. and parts of the suburban Maryland and Northern Virginia. The plant is owned and operated by the District of Columbia Water and Sewer Authority (DC Water). Wastewater flows to the plant receive primary treatment, secondary treatment using the activated sludge process and secondary sedimentation. Flow then receives “advanced” treatment through the nitrification / denitrification process followed by filtration and disinfection prior to discharge to the Potomac River. The average effluent total phosphorus concentration is about 0.01 mg/L which is well below the 0.18 mg/L annual average NPDES permit limit. The solids treatment processes are comprised of thickening and dewatering processes for primary sludge, secondary waste activated sludge (WAS), and nitrification/denitrification waste activated sludge. These facilities include screening and degritting processes, gravity thickeners, dissolved air flotation thickeners, sludge blending and centrifuge dewatering. Currently, lime stabilization of dewatered sludge is practiced to produce and Class B biosolids for land application. As part of the new Biosolids Management Program (BMP), DC Water has embarked on a $407 million design, construction, and commissioning of new biosolids handling facilities comprised of Main Process Train (MPT), Combined Heat & Power (CHP) and Final Dewatering Facility (FDF) projects. Each project has a different project delivery method. MPT, CHP and FDF project’s delivery methods are Design-Build (DB), Design-Build-Operate (DBO) and traditional Design-Bid-Build (DBB) respectively. DC Water issued a Request for Proposal (RFP) for procuring a Design-Build (DB) contractor for the MPT project in October 2010 and an RFP will be issued soon for the CHP project. Project Design Engineer (PDE) is selected in October 2010 for the FDF project and design of the facility is already underway. DC Water is committed to air quality and environment. By utilizing the alternative project delivery methods contract, DC Water expects to gain significant benefits through more cost effective and expedited contractual process as plans and specifications become a deliverable of the contract. This approach is part of the DC Water’s permitting strategy to ensure that the permitting new biosolids projects are issued cost effectively in a timely fashion with minimal risks. Therefore, DC Water decided to bundle the three biosolids projects in a single permit application and submit to the District Department of the Environment Air Quality Division


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(DDOE) which is the responsible agency for undertaking the State Implementation Plans (SIPs) in Washington DC area for a Chapter 2 Permit to Construct. NEW BIOSOLIDS PROJECTS AND EMISSION SOURCES MPT Project The MPT project will be comprised of the Thermal Hydrolysis Process (THP), preceded by raw sludge blending and screening plus pre-dewatering and followed by conventional anaerobic digestion. The MPT facilities will reduce the quantity of solids hauled offsite, upgrade the solids for reuse to Class A pathogen-free designation, and produce a renewable fuel in the form of digester gas. The objective of the THP is to condition the sludge through heat and pressure to make the resulting slurry more amenable to digestion. Also, meeting the time and temperature relationship, pathogens are killed yielding a Class A biosolids product following digestion. The THP is a proprietary process by CAMBI. The THP consists of 4 parallel trains. Each train consists of a pulper, six reactor tanks, a flash tank, circulation pumps, outflow pumps from the flash tank (digester feed pumps), and other support systems. The THP relies on receiving pressurized steam to operate. Permanent steam supply will be provided from the CHP project which will be implemented in parallel with the MPT. Thermally hydrolyzed sludge will be pumped to four 3.8 million gallon digesters which will be operated in parallel. Digesters will be of the cylindrical design constructed of reinforced or posttensioned concrete or a combination of reinforced concrete and steel. The digesters will be provided with a fixed, non-submerged cover, and a cone bottom. Digester contents will be mixed using mechanical draft tube mixers. Digester gas produced from anaerobic digestion will be utilized at the CHP plant to produce steam for the THP and electric power. During start-up, emergency situations and other rare system upsets, the CHP may not be able to utilize the digester gas that is produced. Under these conditions, waste gas flares that are provided as part of the MPT will operate to burn digester gas as a pollution control measure. The flares will be utilized to prevent the venting of digester gas until the system returns to a state of normal operation and combustion of the digester gas in the CHP resumes. Two low-NOx (nitrogen oxides) emergency flares will be provided to combust the digester gas that is not combusted in the CHP facility or in the auxiliary boiler. The emergency flares will be operated under normal operating scenarios for up to 400 hours per year to accommodate maintenance and testing that will ensure proper operation in the event of an emergency situation that shuts all of the combustion gas turbine (CT) and Heat Recovery Steam Generator (HRSG) trains down. Two flares are provided to accept up to the maximum instantaneous gas production in an emergency situation. There are several points within the MPT where the process will generate objectionable odors. The objective of the odor control portion of the MPT is to control these odors such that they are not a nuisance to the plant staff and do not contribute to odors at the plant property line. Odors will be contained by maintaining a negative pressure on vessels (e.g., blending tanks, dewatered


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cake bins) and rooms (sludge screen debris collection room) where odorous compounds will likely be generated. Negative pressure will be maintained through powered fans selected specifically for foul air application. Foul air will be conveyed to central odor control equipment via ductwork. A biological scrubbing odor control system will be provided to reduce odors. Discharge of the treated air will be through a stack. CHP Project The CHP project will use digester gas (DG) and/or natural gas (NG) in some combination to fire combustion gas turbines to generate about 13 MW of electric power. Heat from the gas turbine exhaust gases will be recovered in the HRSGs that will supply steam for the THP. The CHP facility is expected to include digester gas siloxane cleaning, digester gas compression, natural gas compression, natural gas/digester gas turbines including a diverter system and duct burners, heat recovery steam generators, and support systems. DC Water will utilize three combustion gas turbines (CT) and HRSG trains to produce process steam and electricity for use within the Blue Plains AWTP. These units will primarily operate by combusting digester gas produced through anaerobic digestion. Natural gas will be used exclusively during initial equipment operation, currently projected at a six to nine month period. In addition, natural gas will also be used in instances of insufficient digester gas production to meet steam demands and/or maximize electricity production and when the combustion turbines are producing standby power. During periods of supplemental natural gas firing, either a mixture of 70% DG and 30% NG or only NG will be fired in the CTs. Duct burners will be used to increase the steam generated by the CHP. The duct burners will fire digester gas only to increase the thermal energy of the turbine exhaust gases before the heat is recovered to produce additional steam for the CAMBI process. The duct burners will not be utilized during the initial six to nine month period when the system is limited to firing natural gas when the CAMBI process has not commenced operation. The CT/HRSG trains will provide process steam for use in the CAMBI Process. This system will be able to produce process steam to meet peak needs currently estimated at 42,000 lb/hr. Although the production of digester gas is somewhat variable, the CHP has been designed to ensure that all the digester gas can be utilized in the combustion equipment during periods of maximum digester gas production. Potential modes of CT/HRSG train operations are: ¾ CT firing NG in simple-cycle and truncated combined cycle mode (exhaust through unfired HRSGs); ¾ CT firing DG with exhaust through fired duct burners or unfired HRSGs; and ¾ CT using NG/DG mixture (30% NG/70% DG) through fired or unfired HRSGs. The scenario that produces the highest annual emissions (CTs firing DG and HRSGs with duct burners firing DG) was used to estimate the Potential to Emit (PTE) for the CHP.


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The auxiliary boiler will only operate during periods of maintenance, periodic testing, or malfunctions of the CT/ HRSG trains when additional steam is needed in the CAMBI process. This boiler will be capable of producing up to 50,000 lb/hr of process steam. It will commence operation during the six to nine month start-up period and will also operate as needed on natural gas during this period to meet steam demands. This boiler will be able to fire digester gas and natural gas. Siloxanes are a common contaminant in digester gas. This class of chemicals readily volatilize into the gas phase during the anaerobic digestion process. Combustion of these compounds leads to fouling of equipment, as glass like particles are formed and deposited. DC Water will use a proprietary adsorption bed system to remove the siloxanes from the digester gas produced in this process. The system will utilize four reactor vessels, with three in service and one being regenerated at any given time. Regeneration will be performed by blowing hot air through the saturated bed to volatilize the adsorbed siloxanes and purge any digester gas. This air will then be sent to a flare to combust the removed siloxanes to silica (sand) which will later be removed from the base of the flare. A black-start generator will be used to provide the initial power needed for start-up of a turbine in the case of a utility power failure. A diesel generator set will be installed for this purpose. The use of this generator will be limited to periodic testing, utility power failure start-up of the CTs and possible operation for limited periods in the case of a utility power failure. Once the turbines are operational, the generator will be shut down. Maintenance and testing of the diesel generator will be performed for up to 100 hours per year to ensure proper performance and availability. Operation in the event of utility failure is considered an emergency (non-routine) operating mode. FDF Project The Final Dewatering Facility project consists of constructing a new dewatering system for the Class A digested biosolids and the modification of the existing dewatering and lime stabilization system for Class B biosolids. Belt filter presses (BFPs) are proposed for the final dewatering of the Class A biosolids prior to truck loading. The BFPs will be used on the biosolids after the CAMBI and anaerobic digestion processes. This dewatering process will be located in the new final dewatering building. Twelve new BFPs will be installed with the potential to install four more in the future. The BFPs will utilize polymer supplied from the existing emulsion polymer system to increase the effectiveness of the dewatering process. Digested biosolids have a high ammonia concentration and low total suspended solids (TSS) concentration. Wash water used to clean the belt filter presses will conversely have a low ammonia concentration and high TSS concentration. BFPs with the capability of collecting the wash water and filtrate streams separately will be necessary to treat these individually. Spent wash water will drain to a new concrete collection tank for further collection of solids. The belt filter press building will be vented to an odor scrubber to reduce VOC and odorant emissions. After the final dewatering, the Class A biosolids will be conveyed by four belt conveyors to storage bunkers or to hoppers for direct truck loading. The existing northwest and southwest


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biosolids storage bunkers will be cleaned, disinfected and repaired in preparation for handing Class A biosolids. Trucks will be loaded from these bunkers using existing overhead cranes and clam shell buckets. For direct truck loading, the conveyors will discharge to one of four hoppers located above the truck loading bay. The hoppers will load trucks by gravity utilizing a motorized knife gate shut off valve when the truck being loaded is full. The odor control facilities for the FDF will take the existing facilities into account, while providing for the most efficient means to contain, capture, convey, treat, and discharge scrubbed air to the atmosphere. The existing Direct Sludge Loading Facility (DSLF) odor control unit will be moved to a suitable location to make room for the new Final Dewatering Building. In its new location, the existing dual-stage chemical scrubber emissions will be same as in the current location and there will be no new odor scrubber installed. New odor control units will be provided for the new Final Dewatering (Belt Filter Press or BFP) Building which will be an extension of the west side of the existing Dewatered Solids Loadout Facility Building. A dual-stage chemical scrubber is selected for the FDF. All the odor control systems will be in compliance with air permit limitations and OSHA rules and guidelines for occupational safety and health. APPLICABLE REGULATIONS Under the Clean Air Act (CAA) the Environmental Protection Agency (EPA) is responsible for establishing and maintaining federal programs to control air quality. It is a statutory goal of the EPA that non-attainment areas for any of the criteria pollutants develop State Implementation Plans (SIPs) to identify a strategy, consisting of rules limiting emissions of nonattainment pollutants and their precursors and a time frame for reaching attainment. The Washington, D.C. metropolitan area was reclassified from a serious to a severe ozone non-attainment area in 2003. The definition of “major source” is 25 tons per year of potential emissions for nitrogen oxides (NOx) and volatile organic compounds (VOCs). The Washington, D.C. area is an attainment area for other criteria pollutants, and the major source threshold for those pollutants is 250 tons per year for a major combustion source. The major source/modification threshold for Hazardous Air Pollutants (HAPs) is 10 tons/year for a single HAP and 25 tons/year for combined HAPs. Under the District of Columbia Municipal Regulations (DCMR), the District Department of the Environment Air Quality Division (DDOE) is the responsible agency for undertaking the SIPs in Washington DC area. The air quality permit application is a two step process per DDOE requirements. The regulating agency first requires the DC Water to apply for a construction permit (PTC) and then later during the actual design of the facilities, apply for an operating permit (PTO) for all the combustion and odor emission sources. Both federal regulations and the District of Columbia Municipal Regulations (DCMR) apply to the MPT, CHP and Final Dewatering projects for air quality permitting. Since DC Water had already submitted Title V application in March 2008, it is anticipated that the Title V will be amended after the approval of the air quality permit application.


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DC Water estimated that the new biosolids projects will constitute a major source for (NOx) emissions and Non Attainment New Source Review (NNSR) threshold will be triggered. Requirements for New Source Review (NSR) in nonattainment areas intended to ensure that requirements in permitting new sources will result in reasonable further progress toward the goal of reaching attainment. To ensure this goal, NSR requires that emissions from new sources are at the Lowest Achievable Emission Rates (LAER) and that there is no net increase in emissions. Lowest Achievable Emission Rate (LAER) LAER is the control technology that is required for nonattainment pollutant sources. If an area is nonattainment for ozone, LAER will be required for new or modified sources that emit ozone precursors, nitrogen oxides (NOx), and volatile organic compounds (VOC). LAER is defined as follows: For any source, that rate of emissions which reflects – ¾ The most stringent emission limitation which is contained in the implementation plan of any state for such class or category of source, unless the owner or operator of the proposed source demonstrates that such limitations are not achievable, or ¾ The most stringent emission limitation which is achieved in practice by such class or category of source, whichever is more stringent. LAER determination in the greater Los Angeles which is an extreme ozone nonattainment area is presented in the South Coast Air Quality Management District (SCAQMD) guidance in California. The SCAQMD guidance states that “the federal Clean Air Act requirement for Lowest Achievable Emission Rate (LAER) is implemented through BACT in the AQMD”. The SCAQMD’s Best Available Control Technology Guidelines (Part D, page 61) lists Best Available Control Technology (BACT) for digester gas (and landfill gas) as 25 ppmvd (parts per million – volume dry) NOx @15% O2. The SCAQMD BACT Guideline document is a credible reference when determining LAER for a new gas turbine source on low Btu (landfill gas or digester gas) fuel. The CHP will consist of three Solar Mercury 50 combustion turbines (CTs) with heat recovery steam generators (HRSGs). The Mercury 50 CTs are unique in that the design of these turbines incorporates improvements such that lower NOx emissions, when compared to other CTs using digester gas or similar fuel, can be achieved. Projects using the Mercury 50 CT running on landfill gas have operational track records of achieving 25 ppmvd NOx, and this level of NOx emissions has been considered LAER for numerous projects using this fuel. Based on this evaluation, the 25 ppmvd NOx emission rate is the lowest emission rate commonly found by agencies in LAER demonstrations. When digester gas is burned as a fuel, siloxanes cause silica deposits in the form of a white powder in gas turbine hot sections. Siloxanes are chemically stable manufactured additives used in many consumer and industrial products, ranging from cosmetics, shampoos, paper coating, textiles and adhesives to microchip manufacturing. Siloxanes comprise carbon (C), Hydrogen (H), Oxygen (O) and silicon (Si). Most siloxanes volatilize rapidly in anaerobic digestion


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process. Such siloxane compounds are known as volatile methyl siloxanes (VMS) and can be linear molecule or rings (cyclomethicones), and include alternating Si and O atoms. In case of employing Selective Catalytic Reduction technology (SCR) for emission reductions, siloxanes can form a silica on the catalyst surface, rapidly reducing the catalyst’s activity and causing irreversible damage to the catalysts which must be replaced. Presence of siloxanes in the digester gas would severely contaminate an SCR catalyst, vendors will not guarantee SCR for this application, and therefore, the addition of an SCR is not to be considered in a LAER determination. Emission Offsets In accordance with Section 204, District Regulations which specifies permit requirements addressing NNSR, emission offsets for NOx will be obtained at a 1.3 to 1.0 ratio. The potential sources of these will be identified prior to the issuance of the permit to construct. Prevention of Significant Deterioration (PSD) The federal prevention of significant deterioration (PSD) program was established in 1978 as a result of a law suit that argued that the Clean air Act Amendments of 1977 required that a program be established to prevent degradation of air quality in regions of country that were currently in attainment. PSD review is pollutant specific and it applies only to those pollutants for which a project is considered major by comparison to major source thresholds or major modification thresholds (PSD significant emission rates) and the project area is designated as attainment or unclassified. For a new facility to be subject to PSD review, the project’s PTE must exceed the PSD major source thresholds which are: ¾ 100 tpy if the source type is one of 28 named source categories, or ¾ 250 tpy for all other sources. Since Blue Plains AWTP is not an existing major source for PSD purposes, nor does the MPT/CHP Projects belong to any of the 28 named source categories and more specifically, the total heat input for the CHP is less than the threshold of 250 million British thermal units per hour (MMBtu/hr) for source category “fossil fuel fired steam electric plant” (applicable PSD major source threshold is 250 tpy) the Facility is not currently an existing major source for PSD permitting. In addition, the MPT/CHP Project will not be classified as a named category for PSD permitting through the addition of equipment to the Facility Title V permit as part of this project. As a result, all pollutants have a 250-tpy threshold for PSD permitting. Based on calculations of the Project’s PTE, all pollutants have a PTE that is less than 250 tpy; therefore, this application is not subject to PSD provisions. National Standards for Hazardous Air Pollutants (NESHAPs) Byproducts from the combustion of natural and digester gas result in emissions of Hazardous Air Pollutants (HAPs). The CHP project is estimated to generate less than 10 tpy of any individual HAP and less than 25 tpy of the aggregate of all HAPs. Furthermore, when combined with facility wide HAP emissions, this total plus the existing HAP emissions are below the 10 tpy major source threshold for an individual HAP, and below 25 tpy for the aggregate of HAPs;


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therefore, the Blue Plains AWTP is minor for HAPs and is not subject to NESHAPs for major sources. Greenhouse Gas (GHG) Monitoring and Reporting Recently promulgated federal GHG monitoring and reporting regulations (40 CFR 98) require specific facilities to monitor and report GHG such as carbon dioxide and nitrous oxide if certain thresholds are exceeded. Furthermore, the rule requires facilities that emit 25,000 metric tons or more actual GHG from combustion sources such as boilers or process heaters to report GHG emissions from these sources. The CHP includes combustion sources which are subject to 40 CFR 98 Subpart C reporting requirements if 25,000 metric tons or more are emitted from all sources at the facility. Combustion units associated with this process include gas turbines, duct burners, auxiliary boilers, flares and an emergency generator. 40 CFR 98.30(b) states that emergency generators are not subject to reporting as fuel combustion sources. The combustion of digester gas in flares is also not subject to reporting under this subpart with the exception pilot fuel and standard testing and maintenance. Considering the three CT/HRSG trains fueled by DG with partial (30%) NG in all of the turbines, a total of 18,960 metric tons of CO2e per year is estimated. When combined with potential emissions from all of the facility’s current natural gas boilers at maximum annual operation, emissions of 66,766 metric tons of CO2e per year are estimated indicating that the CHP facility may be subject to the reporting requirement of 40 CFR 98 if space heating emits more than 6,040 metric tons of CO2e. However, in a recent development, on January 12, 2011, the U.S. Environmental Protection Agency (EPA) announced its plan to defer greenhouse gas (GHG) permitting requirements for carbon dioxide (CO2) emissions from biomass fired and other biogenic sources for three years. During the three year period, the agency will seek input on critical scientific issues from its partners within the federal government and from outside scientists who have relevant expertise. EPA will also further consider the comments it received from its July 2010 Call for Information, including comments noting that burning certain types of biomass may emit the same amount of CO2 emissions that would be emitted if they were not burned as fuel, while others may result in a net increase in CO2 emissions. Before the end of the three year period, the agency intends to issue a second rulemaking that determines how these emissions should be treated or counted under GHG permitting requirements. Aggregation Rule Aggregation is an important consideration for the determination of applicability of major NSR. The aggregation rule specifies that if a source or reviewing authority determined that proposed projects are “sufficiently interrelated”, then the source or reviewing authority must consider the proposed projects to be a single project aggregating all of the emissions increases for the individual projects for the major NSR applicability analysis. This would mean that emissions increases from the interrelated projects must be summed for the first step of the two step NSR


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applicability analysis to determine if the overall project will result in significant emissions increase. The aggregation rule clarified that in order to be aggregated, activities must have more in common than the timing of construction and the fact that the activities support the overall basic function of the plant. The rule also added a presumption that modifications separated by three or more years are not substantially related. Activities separate by less than three years have no such presumption of independence. EPA clarified that timing has a role in the aggregation decision making process but is not a determinant. The EPA identified some potential indicators of a substantial relationship such as the following: ¾ Joint planning (same capital improvement project or engineering study); ¾ Occur close in time (indicator but not determinant); ¾ Functionally interconnected components. Challenges to the final rule by interveners prompted EPA actions to extend the effective date of the January 2009 final rule pending additional rule making by the EPA. As a result, EPA has reverted back to their case-by-case method of NSR aggregation interpretations instituted prior to the aggregation rule. This stay did not affect the considerations of substantial relationships that were described in EPA memos and guidance. APPROACH AND CHALLENGES TO PERMITTING PROCESS Since the selection of a DB Contractor for the MPT project and RFP issuance of the CHP project are already underway along with design of the FDF project, securing the PTC in a timely fashion is crucial to meet the schedule and budget requirements of these projects. Therefore, DC Water developed a permitting strategy which considers risk minimization, project schedule, and management of project changes during permitting. A step-by-step orderly approach to permitting is developed. The following steps constitute the preparation of the air quality permit application for the three proposed projects. ¾ Meet with the conceptual engineering teams and develop a list of emission sources and emission factors. Identify the regulatory triggers and the implications for permitting the three projects; ¾ Meet with the DC Water Staff/legal team to review the approach and permitting implications and prepare a presentation to the DDOE and EPA Region 3 for the introductory meeting; ¾ Participate in an introductory meeting with DDOE and EPA Region 3 staff to notify them of the upcoming submittals and establish the regulatory framework for agency review; ¾ Prepare a roadmap for permitting; ¾ Prepare the application and technical support document; ¾ Identify sources of offsets if NNSR is triggered; ¾ Submit air permit application after internal review by DC Water staff, DC Water general counsel, and others;


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¾ Communicate with DDOE regarding project changes. Complying with the permitting schedule is very important for completion of the projects because the PTC must be obtained prior to the start of the construction. During the development of permitting strategy, permitting team considered the following for permit schedule. ¾ ¾ ¾ ¾

Information needed to complete permit application; Time required to prepare the needed information; Time required for review and application of the permits; Any permits or approvals that must be completed prior to the Biosolids Projects permit.

DC Water submitted the PTC application for the referenced projects in August 2010. The level of design details for some air emission sources varies due to the nature of different project delivery methods. One critical aspect of the DB or DBO contract is that the project scope is described by definitive, project based performance criteria rather than comprehensive construction plans and specifications. The DB or DBO process places the burden of developing the final details of the equipment design on the selected design-builder firm. DC Water provided air emission estimates in the PTC application that will be greater than the emissions specified in the DB contract solicitation. The DB contractor will have latitude to specify and supply the actual equipment within the solicitation constraints. DC Water will not contractually accept any emission rates or annual PTE values from the DB contractor that are higher than the limits submitted to DDOE in the air permit application to construct the projects. It is anticipated that as designs are refined later during preliminary and final design stages, the PTE estimates are likely to come down. During the introductory meeting with DDOE, separating certain aspects of the projects from the main application was discussed in order to expedite the permitting process. Based on the EPA’s aggregation rule, the project components meet the three indicators of a substantial relationship and therefore would likely be considered a single project by the EPA. Separating the project components into discrete construction approvals could risk a NSR violation since construction of a project subject to NNSR can not commence until the project has been approved. There is no provision within NNSR regulations for construction of individual components of a project while awaiting approval of other components, especially when the application of LAER and the acquisition of emission offsets are a consideration. The only sources that do not produce NOx emissions are the proposed odor scrubbers for the MPT and FDF projects. The bioscrubber associated with the MPT has the potential to introduce new air pollutants even though it is a control device. The odor scrubber associated with the FDF project, however, does not increase emissions or introduce new pollutants. Therefore, it may be separately permitted from the rest of the project and issued an expedited permit without potential regulatory implications. DC Water is requesting a permit to construct from DC Department of Environment, Air Quality Division not later than June 2011 to avoid delays in construction of the Biosolids Projects. This is in concert with DC Water’s goal to improve the air quality and environment while complying with the federal and the DC Government regulations. However, DC Water is concerned about


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handling potential project changes during permitting as it appears that permitting the Biosolids Projects would pose unique challenges to DC Water as well as the regulating agency. In order to navigate through the unchartered territories in the permitting process, DC Water’ permitting team developed conceptual permitting pathways to handle potential project changes during permitting process. Figure 1 shows the permitting pathways which consider that the projects are subject to NNSR and ask about the applicability of LAER, aggregation rule and nature of the project delivery before requesting to submit an addendum to the permit application for the potential project changes. For example, in case of the FDF scrubber, LAER and aggregation rule do not apply and the project delivery method is DBB. Therefore, DC Water would ask the PDE to provide supplementary information regarding project changes and then submits an addendum to the permit application independently from the main application. In case of gas turbines or auxiliary boiler in the CHP project, however, a different pathway applies as LAER and aggregation rule are both valid and the project delivery method is DBO. This pathway leads to the DBO contractor who is ultimately responsible for completing the design, construction and operation of the facilities, requesting for detailed information regarding all the specified equipment so that an addendum can be issued to the permit application. This project can not be permitted independently from the main application. Another example is emergency flares in the MPT project where another pathway can be pursued as LAER may not applicable but the aggregation rule is valid while the project delivery method is DB. This pathway leads to the DB contractor who is responsible for completing the design and construction of the facilities, requesting for detailed information regarding all the specified equipment so that an addendum can be issued to the permit application. This project can also not be permitted independently from the main application. Actual permit conditions that will be issued by the regulating agency could also bring about additional challenges. DC Water expects that all the estimates of emissions and control efficiencies presented in the application will appear as permit conditions. It is likely that there will be other conditions that could include constraints on start-ups and shutdowns, and requirements for emissions monitoring. DC Water would make all the effort to negotiate these conditions as early in the application review process as they are being developed so that wording that will make compliance difficult can be avoided. ACKNOWLEDGMENTS The authors wish to thank the DC Water personnel, Biosolids Program Manager Brown and Caldwell, Parsons and AECOM who have contributed to the preparation of the air quality permit application at the Blue Plains AWTP. REFERENCES Brown and Caldwell, Biosolids Program Manager (2010) TM 11 Odor Control Considerations.


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Brown and Caldwell, Biosolids Program Manager (2010 TM 4 Process Control Strategy. Brown and Caldwell, Biosolids Program Manager (2010) TM 19 Main Process Train, Permitting Requirements. Brown and Caldwell, Biosolids Program Manager, (2010) TM 10 Gas Management System. DC Water, AECOM (2010) Air Permit Application for Main Process Train, Combined Heat and Power Plant, and Final Dewatering Facility. AECOM, Memorandum (2010) Analysis of Potentially Applicable Prevention of Significant Deterioration Rules and Monitoring and Reporting of Greenhouse Gases. AECOM Memorandum (2011) Analysis of EPA’s Aggregation Policy and Potential Permitting Ramifications. South Coast Air Quality Management District (2006) Best Available Control Technology Guidelines. Witherspoon, Leslie (2009) Mercury 50 Product Information Letter, Solar Turbines. Trzupek, Richard (2002) Air Quality Compliance and Permitting Manual, Mc Graw Hill. U.S. Environmental Protection Agency, Air and Radiation Division; Web Site, Washington D.C.


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Figure 1: Pathway for project changes during the permitting process.


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