Update on ici boiler mact
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Update on ici boiler mact Update on ici boiler mact Presentation Transcript

  • icfi.com | Bruce Hedman March 5, 2013 Update on ICI Boiler MACT
  • 2icfi.com | Clean Air Acts Standards for Boilers and Incinerators  On December 20, 2012, EPA finalized a specific set of adjustments to March 2011 Clean Air Act standards for boilers and certain solid waste incinerators − Area Source Boiler Rule − Major Source Boiler Rule (ICI Boiler MACT) − Commercial and Industrial Solid Waste Incinerators MACT  Adjustments based on new data and additional information on real- world performance − Maintain public health benefits by reducing toxic air pollution, including mercury and particulates − Increase flexibility of compliance − Maintain cuts in the cost of implementation represented by March 2011 rule − Provide clarity in identifying which non-hazardous secondary materials are, or are not, solid wastes
  • 3icfi.com | Compliance Timelines  Adjustments to numerical emissions limits and to technology subcategories significant enough to warrant allowing a full three years for compliance  Major Source Boiler Rule (ICI Boiler MACT) − Three years after publication in Federal Register (January 31, 2016) − Sources may request an additional year if required for the installation of controls or repowering (installation of CHP included)  Area Source Boiler Rule − Timeline for initial notification for existing area source boilers no later than January 2014 − Compliance date for emissions limits, tune-up requirements and energy assessments March 21, 2014  CISW Incinerator Rule − Five years after publication in Federal Register (January 31, 2016)
  • 4icfi.com | Affected Major and Area Source Boilers Major Source Boilers About 14,000 Covered Units 88% follow work practice rules 12% have numerical limits About 183,000 Covered Units (no natural gas boilers) Less than 1% have limits 99% follow work practice rules 12,300 need to follow work practice standards such annual tune ups 1,700 need to meet numerical emissions limits 182,400 need to follow work practice standards such tune ups 600 need to meet numerical emissions limits Area Source Boilers
  • 5icfi.com | ICI Boiler MACT (Major Source Rule)  Standards for hazardous air pollutants from major sources: industrial, commercial and institutional boilers and process heaters (excludes any unit combusting solid waste)  Major source is a facility that emits: − 10 tpy or more of any single Hazardous Air Pollutant, or 25 tpy or more of total Hazardous Air Pollutants (HAPs)  Emissions limits applicable to new and existing units > 10 MMBtu/hr − Mercury (Hg) − Filterable Particulate Matter (PM) or Total Selective Metals (TSM) as a surrogate for non-mercury HAP metals − Hydrogen Chloride (HCl) as a surrogate for acid gas HAP − Carbon Monoxide (CO) as a surrogate for non-dioxin/furan organics 5
  • 6icfi.com | ICI Boiler MACT (cont’d)  For new and existing units < 10 MMBtu/hr – the rule establishes a work practice standard instead of numeric emission limits (periodic tune-ups)  Rule significantly impacts oil, coal, biomass, and process gas boilers − Emission limits must be met at all times except for start-up and shutdown periods − Controls are potentially required for Hg, PM, HCI, and CO − Also includes monitoring and reporting requirements − Limits are difficult (technically and economically) for oil and coal boilers (especially older units)
  • 7icfi.com | Compliance Strategies  Standard Control Technologies for Affected Boilers − Mercury (Hg): Fabric filters and activated carbon injection are the primary control devices − Particulate Matter (PM): Electrostatic precipitators may be required for units to meet emission levels − Hydrogen Chloride (HCl): Wet scrubbers or fabric filters with dry injection are the primary control technologies − Carbon Monoxide (CO): Tune-ups, replacement burners, combustion controls and oxidation catalysts are the preferred control technologies Required compliance measures for any unit depend on current emissions levels from the units and the control equipment already in place
  • 8icfi.com |  Convert boilers to natural gas − Replace burners in existing boilers with natural gas burners (lose efficiency) − Replace boiler with natural gas boiler − Compliance becomes straight forward (tune-ups in lieu of more rigorous control options) Compliance Strategies
  • 9icfi.com |  Install a natural gas fueled CHP system − Gas turbine/generator produces electricity − Turbine waste heat generates steam through a HRSG  Represents a tradeoff of benefits versus additional costs – Represents a productive investment – Potential for lower steam costs due to generating own power – Higher overall efficiency and reduced emissions – Higher capital costs, but partially offset by required compliance costs or new gas boiler costs Compliance Strategy
  • 10icfi.com | ICI Boiler MACT - Potential CHP Capacity Fuel Type Number of Facilities Number of Affected Units Boiler Capacity (MMBtu/hr) CHP Potential (MW) CO2 Emissions Savings (MMT) Coal 332 751 180,525 18,055 114.2 Heavy Liquid 170 367 48,296 4,830 22.9 Light Liquid 109 241 22,133 2,214 10.5 Total 611* 1,359 250,954 25,099 147.6 *Some facilities are listed in multiple categories due to multiple fuel types; there are 567 ICI affected facilities •CHP potential based on average efficiency of affected boilers of 75%; Average annual load factor of 65%, and simple cycle gas turbine CHP performance (power to heat ratio = 0.7) • GHG emissions savings based on 8000 operating hours for coal and 6000 hours for oil, with a CHP electric efficiency of 32%, and displacing average fossil fuel central station generation
  • 11icfi.com |  Compares cost of compliance options for coal and/or oil fired boilers: − Installing control technologies on existing boilers − Replacing existing boilers with new natural gas boilers − Converting existing boilers for operation on natural gas − Replacing existing boiler with a natural gas fueled combustion turbine CHP system CHP Analysis
  • 12icfi.com | CHP Analysis XYZ Papers Boiler Unit Data: Unit Type Total Capacity (MMBtu/hr) Primary Fuel Hours of Operation Year Installed Emissions Control Technology Stoker/Sloped Grate Boiler 156 Coal 8400 1960 ESP Stoker/Sloped Grate Boiler 245 Coal 8539 1968 ESP Total Coal Capacity: 401 Max Hours 8539 Compliance Control Requirements: Fabric Filter TCI = $0 Electrostatics Precipitator TCI = $0 Scrubber TCI = $0 Dry Sorbent Injection followed by a Fabric Filter (DIFF) TCI = $17,895,905 CO Oxidation Catalyst TCI = $12,954 Boiler Tune-up TCI = $12,954 Total Capital Cost of Controls = $17,921,813 Total Annual Operating Costs of Controls = $3,111,550 Fuel Switching Alternative Compliance Option: Boiler Conversion to Natural Gas Costs $6,621,935 Coal Boiler Replacement Cost $14,560,413 Natural Gas Access Cost (if gas is not available at the site) $390,720 Coal Boiler Decommissioning Cost $8,767,111 Total Fuel Switching TCI = $14,560,413
  • 13icfi.com | CHP Analysis Comparative Cost of Compliance Options Upgrade Coal Boilers Boiler Replacement: New Natural Gas Boilers Boiler Conversion: Natural Gas Burners and Controls Natural Gas CHP Boiler Capacity, MMBtu/hr input 401.0 401.0 401.0 NA Avg Steam Demand, MMBtu/hr 248.6 248.6 248.6 248.6 Boiler Efficiency 78% 80% 70% NA CHP Capacity, MW 0 0 0 17 CHP Electric Efficiency NA NA NA 34% Fuel Use, MMBtu/year 2,721,964 2,653,915 3,033,046 3,463,714 Annual Fuel Cost $6,532,714 $13,269,575 $15,165,228 $17,318,568 Annual O&MCost $4,082,946 $1,778,123 $2,032,141 $2,794,264 Annual Compliance O&M $3,111,550 NA NA NA Annual Electric Savings ($8,492,036) Annual Steam Operating Costs $13,727,210 $15,047,697 $17,197,369 $11,620,796 Annual Operating Savings (coal compliance) $2,106,413 Annual Operating Savings (gas boiler) $3,426,901 Based on: Coal Price: 2.40 $/MMBtu Natural Gas Price: 5.00 $/MMBtu Electricity Price: 0.065 $/kWh
  • 14icfi.com | CHP Analysis Annual Steam Operating Costs $13,727,210 $15,047,697 $17,197,369 $11,620,796 Annual Operating Savings (coal compliance) $2,106,413 Annual Operating Savings (gas boiler) $3,426,901 Capital Costs $17,921,813 $14,560,413 $6,621,935 $26,747,867 CHP Incremental costs (coal compliance) CHP Payback (coal compliance) 4.2 CHP Incremental costs (gas boiler) CHP Payback (gas boiler) 3.6 Cash Flow Projections Upgrade Coal Boilers New Natural Gas Boilers Boiler Conversion to Natural Gas Natural Gas CHP Capital Costs $17,921,813 $14,560,413 $6,621,935 $26,747,867 5 YR Annual Fuel Cost $34,683,064 $70,449,973 $80,514,255 $91,946,629 5 YR Annual O&MCost $21,676,915 $9,440,296 $10,788,910 $14,835,127 5 YR Annual Compliance O&M $16,519,642 $0 $0 $0 5 YR Annual Electric Savings $0 $0 $0 ($45,085,370) 5 YR Net Cash Flow (Output) $90,801,433 $94,450,682 $97,925,100 $88,444,253 Capital Costs $17,921,813 $14,560,413 $6,621,935 $26,747,867 10 YR Annual Fuel Cost $74,890,240 $152,120,801 $173,852,344 $198,537,972 10 YR Annual O&MCost $46,806,400 $20,384,187 $23,296,214 $32,033,105 10 YR Annual Compliance O&M $35,670,434 $0 $0 $0 10 YR Annual Electric Savings $0 $0 $0 ($97,351,670) 10 YR Net Cash Flow (Output) $175,288,887 $187,065,401 $203,770,493 $159,967,273 10 YR IRR - Natural Gas CHP vs Coal Compliance Baseline Case 23% $5,158,141 $8,826,054 $12,187,454 10 Yr NPV - Natural Gas CHP vs Coal Compliance Baseline Case
  • 15icfi.com |  DOE Boiler MACT Technical Assistance Program (Decision Tree Analysis): http://www.1.eere.energy.gov/manufacturing/distributedenergy/boilermact.html DOE Technical Assistance Contact us at: Decision Tree Analysis
  • 16icfi.com | Boiler MACT Sites in Alabama Fuel Type # Boilers Capacity (MMBTu/hr) Coal 16 6,347 Heavy Oil 10 1,483 Light Oil 3 704 Process Gas 4 480 Biomass 49 13,823 Total 82 22,836 Total Affected Sites 41 Paper Chemicals Nonmetallic Minerals
  • 17icfi.com | Boiler MACT Sites in Arkansas Fuel Type # Boilers Capacity (MMBTu/hr) Coal 3 471 Heavy Oil 2 1,079 Light Oil 0 0 Process Gas 0 0 Biomass 52 7,014 Total 57 8,564 Total Affected Sites 30 Paper Nonmetallic Minerals
  • 18icfi.com | Boiler MACT Sites in Iowa Fuel Type # Boilers Capacity (MMBTu/hr) Coal 39 14,641 Heavy Oil 3 145 Light Oil 5 432 Process Gas 0 0 Biomass 7 709 Total 54 15,927 Total Affected Sites 22 Food Processing Universities Fabricated Metals
  • 19icfi.com | Boiler MACT Sites in Illinois Fuel Type # Boilers Capacity (MMBTu/hr) Coal 36 9,478 Heavy Oil 2 178 Light Oil 7 584 Process Gas 13 1,199 Biomass 1 18 Total 59 11,458 Total Affected Sites 25 Food Processing Chemicals Machinery
  • 20icfi.com | Boiler MACT Sites in Tennessee Fuel Type # Boilers Capacity (MMBTu/hr) Coal 39 11,811 Heavy Oil 7 693 Light Oil 12 270 Process Gas 0 0 Biomass 15 2,273 Total 73 15,046 Total Affected Sites 26 Paper Government Facilities Universities
  • 21icfi.com | Texas Permitting Options Texas has three permitting routes for CHP –  Standard Permit – applies to most EGUs  Permit by Rule (PBR) – only applies to natural gas CHP systems  Case-by-Case – applies to systems not eligible under the 1st two options
  • 22icfi.com | Texas Standard Permit  Issued in 2001, revised in 2007  Defined permitting procedure for CHP and other EGUs  Includes output-based NOx limits o No size constraints o Separate limits for East and West Texas  Must use either: o Natural gas o Landfill gas, digester gas, stranded oilfield gas o Liquid fuels
  • 23icfi.com | Texas Standard Permit  Allows for CHP thermal credit: o Provides a compliance credit based on a rate of 1 MWh for each 3.4 MMBtu of heat recovered(added to denominator of lbs/MWh emissions rate). o To receive compliance credit, the heat recovered must be > 20% of the total energy output of the CHP unit o The SP can be accessed at: http://www.tceq.texas.gov/assets/public/permitting/air/NewSourceR eview/Combustion/egu_techsum_sp.pdf
  • 24icfi.com | Texas Permit by Rule (PBR)  Issued in July 2012  Expedited permit option for CHP systems fueled by “pipeline-quality”  natural  gas o Emergency fuels (propane, LPG, diesel, etc.) may be used for no more than 720 hours in any 365 day period  CHP systems < 20 kW are exempt from permitting requirements  Individual CHP system or any group of units may not exceed 15 MW in capacity  CHP systems from 8 to 15 MW must install an oxidation catalyst  No supplemental firing (gas turbines)
  • 25icfi.com | Texas Permit by Rule (PBR)  PBR output-based NOx limits are generally less stringent than those in the standard permit; CO limits also apply  Recovered heat must be > 20% of the total heat energy output to qualify o Total  heat  energy  output  is  “fuel  in”  minus  “power  out”  CHP thermal credit same as under the standard permit o 1 MWh for each 3.4 MMBtu of heat recovered  The PBR can be accessed at: http://info.sos.state.tx.us/pls/pub/readtac$ext.TacPage?sl=R&app=9&p_dir=&p _rloc=&p_tloc=&p_ploc=&pg=1&p_tac=&ti=30&pt=1&ch=106&rl=513
  • 26icfi.com | PBR M&V Requirements  Reciprocating engine (ICE) > 20kW – analyze emissions within 180 days with portable analyzer; ongoing monitoring every 6 months  If CHP unit not certified by manufacturer, tested within 90 days of startup; Gas turbines and ICE > 375kW retest every 16,000 hours  If oxidation catalyst required, tested within 90 days and retest every 16,000 hours  Records need to be kept for 2 years – non compliance events, maintenance, and emergency fuel hours.
  • 27icfi.com | Texas NOx Limits Operating > 300 hrs/yr 0.47 Operating < 300 hrs/yr 1.65 Operating > 300 hrs/yr with a capacity > 250 kW 0.14 Operating < 300 hrs/yr 0.47 Any unit with a capacity < 250 kW 0.47 Operating > 300 hrs/yr 3.11 Operating < 300 hrs/yr 21 Operating > 300 hrs/yr 0.14 Operating < 300 hrs/yr 0.38 EGUs firing any gaseous or liquid fuel with at least 75% landfill gas, digester gas, stranded oilfield gas, or gaseous or liquid renewable fuel by volume (*Except in West Texas) On or after 5/16/2007 N.A. 1.9 CHP units powered by pipeline quality natural gas-fired engines and turbines. Applies to an individual unit or group of units up to 15 MW. 20 kW to 8 MW 1.0 Installed prior to 1/1/2005 Installed on or after 1/1/2005 East Texas < 10 MW West Texas < 10 MW On or after 5/16/2007 On or after 5/16/2007 Units > 10 MW > 8 MW to < 15 MW (Must have an oxidation catalyst) 0.7 EGU NOx limits - applies to units installed on or after 5/16/2007. Units are limited to the use of the following fuels: 1) natural gas, 2) landfill gas, digester gas, stranded oilfield gas, or gaseous renewable fuel, or 3) liquid fuels not containing waste oils or solvents Standard Permit NOx limits Permit by Rule (PBR) NOx limits