Rule 1110.2 Estimated Retrofit Costs to Achieve Proposed Biogas Limits David Rothbart, P.E. Los Angeles County Sanitation Districts Air Quality Engineering Section October 26, 2010
Presentation Outline Problem Statement Biogas Pretreatment Estimated Retrofit Costs: Los Angeles County Sanitation Districts South Orange County Wastewater Authority Inland Empire Utilities Agency Riverside County Waste Management Department City of Riverside City of San Bernardino Conclusions Recommendations
Problem Statement Current Rule 1110.2 biogas NOx limits (2/1/08 revision): 36 ppmvd x ECF (for BHP > 500) 45 ppmvd x ECF (for BHP < 500) Rule 1110.2 proposes to reduce biogas NOx limit to 11 ppmvd on July 1, 2012 Biogas is not the same as natural gas (i.e., siloxanes and other contaminants) EPA is not aware of any [catalyst] technologies that are proven (Source: EPA - August 10, 2010) SCAQMD future emission reductions: up to 90% NOx reductions and plus by 2020/2021 What NOx and CO limits can be achieved without increasing biogas flaring?
Biogas Pretreatment Adsorption required to remove siloxanes Chilling required A dry cool biogas is needed to maximize adsorption Most existing facilities do not chill biogas Other contaminants consume adsorption pore space Hydrogen sulfide VOCs
Siloxanes in Landfill and Digester Gas * - JWPCP WWTP samples were obtained after chilling to 60 o F. Siloxane Concentration (ppmv)
300 Hydrogen Sulfide in Landfill and Digester Gas 250 H 2 S Concentration (ppmv) 200 150 10 0 Biogas is not natural gas 50 0 8/8/10 8/15/10 8/22/10 8/29/10 Samples for Valencia WRP obtained prior to iron sponge. 9/5/10 Valencia WRP Puente Hills Landfill Calabasas Landfill Spadra Landfill Scholl Canyon Landfill OCSD JWPCP 9/12/10 9/19/10 9/26/10 10/3/10 10/10/10
Valencia Wastewater Treatment Plant 705 bhp Cooper-Superior digester gas cogeneration engine (AP No. 351750) Retired on February 1, 2009 due to Rule 1110.2 No cost-effective energy recovery project has been identified as a replacement 230,000 cubic feet per day of digester gas is being flared
Puente Hills Landfill IC Engine Facility Three lean burn 2.7 MW Caterpillar 3616 engines BACT at time of construction in 2006 Current permit limits: NOx 36 ppmvd x ECF CO 351 ppmvd Current income $0.016/kW-hr
Puente Hills Landfill IC Engine Facility Limited Available Retrofit Space
Puente Hills Landfill IC Engine Facility Estimated Retrofit Cost Conservative Assumptions: Adequate space is available for pretreatment Existing mufflers can be replaced by CO catalyst & SCR Structural reinforcement is not required 10-year equipment life Maximum allowable engine back pressure is not exceeded Capital - $11.2 million Estimated loss (after retrofit) $0.026/kW-hr
Rule 1110.2 Compliance South Orange County Wastewater Authority October 26, 2010
J. B. Latham Treatment Plant
J. B. Latham Treatment Plant Aeration equipment and engine-blower system installed in 1989 Existing engine-blower system uses 65-70% available digester gas More energy efficient types of air diffusers and blowers available Current facility plan looking at engine-blower system that (i) is most economic, (ii) is most energy efficient and (iii) offers best possibility of meeting long term air quality emission goals
Regional Treatment Plant
Regional Treatment Plant Three internal combustion engines used to generate power for on-site use and heat for digester operation Original units installed in 1983 were replaced with with lean burn engines in 1999 to be meet tighter air quality limits for lower NOx Engine output curtailed through reduced natural gas feed to meet initial requirements of amended Rule 1110.2
Regional Treatment Plant Compliance Alternative Evaluation Study performed by Carollo Engineers in 2008 Evaluated options for the retrofit or replacement of the engines including the following: - Retrofit of ICE s with SCR units - Retrofit of ICE s with NOxTech units - Replacement of ICE s with fuel cells Study found that retrofit with NOxTech was the most cost effective option based on current technology SOCWA has taken no further action on retrofit/replacement pending the completion of testing of ICE retrofit technologies by others
Estimated Retrofit Costs Retrofit Capital Cost ($ million) Gross Power Output (kw) Net Income ($/kw-hr) Will Proposed Limits Result in Flaring? SOCWA $4.71 800-0.021 TBD
Conclusions SOCWA s Board of Directors will review any proposed retrofit/replacement/abandonment of the Regional Treatment Plant engines based on economics, environmental value, proven technology and regulatory compliance (short term and long term) Preliminary cost for engine modification with SCR system is over $300,000 per ton NOx removed; alternative needs to be updated based on results from OCSD and others
Rule 1110.2 Retrofit Considerations Inland Empire Utilities Agency Meeting with SCAQMD Staff October 26, 2010
Service Area 240 Square Miles 850,000 People 7 Facilities Wastewater Treatment (4) Water Treatment (1) Biosolids Treatment (2) Composting Facility (1) Platinum LEED Headquarters Building Agency Overview
Rule1110.2 (2008 Amendment) Implications of 2008 amendment Parameter Unit Prior to Feb 2008 After Feb 2008 Gas Flared ft 3 /month 1,048,420 4,570,240 Energy Production kwh/month 1,321,600 714,375 Energy Purchased kwh/month 1,105,327 1,483,994 Natural Gas Purchased therms/month 50,878 2,025 Net Savings $/month $99,963 $56,416
Renewable Energy Generation Renewable Energy Resources Solar Power (3,500 kw) Digester Gas Cogeneration RP-1 Two Engines 1,400 kw capacity each RP-2 One Engine 580 kw capacity
Concerns with Engine Retrofits Site constraints Gas quality Technical feasibility Capital project funding Increased O&M costs Uncertainty of Future Regulatory Requirements
Site Constraints
Cost Estimation Scenarios Cost estimate and assumptions were evaluated by third party Black and Veatch 2010 Scenarios for RP-1 Scenario 1 Two engines would be retrofitted with gas cleaning and post combustion control systems but only one engine run at a time Scenario 2 Two engines would be retrofitted with gas cleaning and post combustion control systems with both running at the same time Scenario for RP-2 Single engine would be retrofitted with gas cleaning and post combustion control systems
Cost Estimation Assumptions Equipment Description Capital Cost O&M Cost RP-1 RP-2 RP-1 RP-2 Gas Cleaning System $1.5M $1.4M $0.007/kWh $0.021/kWh Post Combustion Control $6.0M $1.5M $0.01/kWh $0.01/kWh Equipment Description Current O&M Costs Expected O&M Costs RP-1 RP-2 RP-1 RP-2 Cogeneration Engine $0.08/kWh $0.08/kWh $0.082/kWh $0.096/kWh
Summary Facility Scenario Cost to Produce Energy Onsite ( /kwh) Savings over Imported Energy* ( /kwh) Current Configuration 8.2 1.8 RP-1 1 Engine Operation (Retrofit)** 13.7 (3.7) 2 Engine Operation (Retrofit)** 13.6 (3.6) RP-2 Current Configuration 8.3 1.7 1 Engine Operation (Retrofit)** 16.7 (6.7) *Purchased energy estimated at 10 /kwh **Based on a 20-year payback at 3% interest rate
City of Riverside Regional Water Quality Control Plant DRAFT - DO NOT CITE OR QUOTE
Currently 40 MGD Rated Plant Aeration trains with oxic/anoxic zones, secondary clarifiers, flow equalization. Solid Handling consist of Dissolved Air Flotation Thickening (DAFT) of Waste Activated Sludge (WAS), digestion of primary and secondary solids, and belt press and centrifuge dewatering of digested sludge. DRAFT - DO NOT CITE OR QUOTE
Three 1,400 kw Gross Digester Gas Lean Burn Engine Generator sets One Digester/Natural Gas Fuel Cell rated at 1 MW At least 2/3 of Plant Energy Needs is supplied by Digester Gas and on site co-generation. DRAFT - DO NOT CITE OR QUOTE
Looked at Two Control Technologies 1)SCR with Gas Clean-up and CO catalyst 2)NOx Tech DRAFT - DO NOT CITE OR QUOTE
OPERTING UNIT ASSUMPTIONS Number of Units 3 Operating Unit Output, kw 1,000 Unit Availability 80% FINANCIAL ASSUMPTIONS Present worth year 2010 First year of evaluation 2012 Project duration, years 10 & 20 Inflation (capital costs) 3.0% Inflation (O&M costs) 3.0% Gross discount rate 5.0% DRAFT - DO NOT CITE OR QUOTE
Construction Cost $7,285,000 10 Year Life O&M Costs, $/kwh $0.019 Capital Costs,$/kWh $0.045 Total Costs, $/kwh $0.064 20 Year Life O&M Costs, $/kwh $0.022 Capital Costs,$/kWh $0.028 Total Costs, $/kwh $0.050 Construction Cost $5,119,000 10 Year Life O&M Costs, $/kwh $0.018 Capital Costs,$/kWh $0.032 Total Costs, $/kwh $0.050 20 Year Life O&M Costs, $/kwh $0.021 Capital Costs,$/kWh $0.020 Total Costs, $/kwh $0.041 DRAFT - DO NOT CITE OR QUOTE
Element # Element Cost 1 SCR/CO Catalyst systems (3 units) $432,000 2 1000 gallon Urea doble contained storage Tank $3,000 3 Urea pump $6,000 4 Demolish and Removal Work $10,000 5 Foundation Work $156,450 6 2" Urea Piping (SST) and valves- 100' $6,600 7 16" Exhaust Pipe,expansion joints and supports - 150' $108,000 8 Fuel Conditioning System (1,100 scfm) $2,403,500 9 2" Air Piping and valves - 75' $2,250 10 8" Digester Gas Pipe (SST), valves and supports - 150' $45,000 11 Misc $25,000 Sub-Total $3,197,800 12 Electrical and Instrumentation $319,780 TOTAL DIRECT COST $3,517,580 SALES TAX 8.75% $246,231.00 Subtotal $3,763,811 CONTINGENCY 20% $752,762 Subtotal $4,516,573 GENERAL CONDITIONS 10% $451,657 Subtotal $4,968,231 GENERAL CONTRACTOR OH&P 15% $745,235 Subtotal $5,713,465 ESCALATION TO MID POINT 2% $114,269 Subtotal $5,827,734 Intergration Difficulty Factor due to Plant Expansion 25% $1,456,934 Total Estimated Cost $7,284,668 TOTAL ESTIMATED CONSTRUCTION COST $7,285,000 Element # Element Cost 1 NOxTech Gas Treatment System (3 Units) $1,500,000 2 1000 gallon Urea double contained storage Tank $3,000 3 Urea pump $6,000 4 Demolish and Removal Work $10,000 5 Foundation Work $156,450 6 2" Urea Piping (SST) and valves- 100' $6,600 7 16" Exhaust Pipe, expansion joints and supports - 150' $108,000 8 2" Air Piping and valves - 75' $2,250 9 8" Digester Gas Pipe (SST), valves and supports - 150' $45,000 10 Misc. $25,000 Sub-Total $1,862,300 11 Electrical and Instrumentation $186,230 12 Elevated Support Structure 30'X60' $450,000 TOTAL DIRECT COST $2,498,530 SALES TAX 8.75% $146,199 Subtotal $2,644,729 CONTINGENCY 20% $528,946 Subtotal $3,173,675 GENERAL CONDITIONS 10% $317,368 Subtotal $3,491,043 GENERAL CONTRACTOR OH&P 15% $523,656 Subtotal $4,014,699 ESCALATION TO MID POINT 2% $80,294 Subtotal $4,094,993 Integration Difficulty Factor due to Plant Expansion 25% $1,023,748 Total Estimated Cost $5,118,741 TOTAL ESTIMATED CONSTRUCTION COST $5,119,000 DRAFT - DO NOT CITE OR QUOTE
Year 2010 Ten Year Twenty Year Average Average Operation Data Electricity Generated (KW-hrs.) 21,024,000 21,024,000 O&M Costs SCR Fuel Conditioning System $260,172 $326,436 $370,833 SCR/CO System $6,000 $7,528 $8,551 Catalyst $5,000 $6,274 $7,127 Urea $35,478 $44,514 $50,569 CEMS $20,000 $25,094 $28,507 Total Annual Costs $397,273 $465,587 Present Worth of Annual Costs $326,650 Total Estimated Constriction Cost $7,285,000 Annualized Total Project Capital Cost 10 yr. $9,434,408 Annualized Total Project Capital Cost 20 yr. $11,691,345 Year 2010 Ten Year Twenty Year Average Average Operation Data Electricity Generated (KW-hrs.) 21,024,000 21,024,000 O&M Costs SCR NOxTech System $20,000 $326,436 $370,833 Urea $35,478 $44,514 $50,569 Process NOx CEMS $12,000 $25,094 $28,507 Total Annual Costs $383,894 $449,908 Present Worth of Annual Costs $67,478 Total Present Worth of O&M Cost Annualized Total Project Capital Cost 10 yr. $6,629,339 Annualized Total Project Capital Cost 20 yr. $8,215,236 Total Estimated Constriction Cost $5,119,000 Cost per kw/hr. 10 yr. life O&M Costs, $/kwh $0.019 Capital Costs,$/kWh $0.045 Total Costs, $/kwh $0.064 Cost per kw/hr. 20 yr. life O&M Costs, $/kwh $0.022 Capital Costs,$/kWh $0.028 Cost per kw/hr. 10 yr. life O&M Costs, $/kwh $0.018 Capital Costs,$/kWh $0.032 Total Costs, $/kwh $0.050 Cost per kw/hr. 20 yr. life O&M Costs, $/kwh $0.021 Capital Costs,$/kWh $0.020 Total Costs, $/kwh $0.041 Total Costs, $/kwh $0.050 DRAFT - DO NOT CITE OR QUOTE
2011 Starting Phase I Expansion and Plant Upgrade Project Increasing plant capacity to 46 MGD Adding 26 MGD of MBR support the City Recycle Water Program Increasing Digester Capacity Adding 170,000 CF of Digester Gas Storage Capacity Phase II ultimate will increase pant capacity to 52 MGD Anticipated energy demand will be 8 MW. DRAFT - DO NOT CITE OR QUOTE
Estimated Retrofit Costs to Achieve Proposed Biogas Fueled Engine Emissions Limits to Comply with Rule 1110.2 Emission Limits John Vronay, P.E. Consultant City of San Bernardino Municipal Water Reclamation Facility October 26, 2010
Outline Existing Equipment Biogas Clean-up Estimated Retrofit Costs: Pump-Drive Engines Blower-Drive Engines Cogeneration Facility Feasibility Summary
Existing Equipment Pumps: 4 x CAT G342 Pump-Drive Engine 225 HP each, Variable Speed Drive 2 dedicated to Nat gas with NSCR Catalyst (propane back-up) 2 dedicated to digester gas, operated lean & de-rated Permitted at 45 PPMv NOx 1110.2 Engines < 500 HP No electrical back-up, typically 1 unit on-line Process Aeration Facility: 2 x VHP 5108GL 750 HP at 880 RPM Meets existing compliance limits of 36 PPMv NOx with margin Operate very lean at 11% exhaust O2 Cogeneration Facility: 2 x VGF P48 GLD 999 HP each: 12.5M kw-hours or 66% of all electrical Power De-rated to meet existing limits of 36 PPMv NOx and Avoid CEMS Operate lean at 8% exhaust O2 Currently in process of commissioning
Bio Gas Treatment Currently No Gas Clean-up Gas is compressed and stored at 55 PSIG Filtered to Remove Major Particulates Water Drop Out in System Via Drip Traps Siloxane content 20-100 PPMv (last 3 years) H2S Content 50-100 PPMv Clean-up Requirements for NSCR and SCR Gas Clean up Requirements Specifications* Total Siloxanes: < 1 PPMv 99% Reduction Total Sulfur as SO2: < 25 PPMv 60% Reduction Total VOC and Phosphorus Compounds: < 10 PPMv 99% Reduction *Per Johnson Mathey for SCR and/or NSCR Systems: OCT 2010 Study
GAS PRODUCTION Bio Gas Treatment Plant produces average of 327 SCFM of digester gas Average LHV 565 BTU/SCF Capable of producing 12.5M kw-hours Annually Value of Avoided purchased Electrical Power $825k Annually Capable of Producing 66% of all power required CLEAN-UP REQUIRED FOR NSCR OR SCR Refrigeration and with Adsorption Media Canisters Redundant Systems Required if All Engines Have Catalysts Cost of Installation of Gas Clean-Up: $1.7M Annualized Cost of Gas Clean-up Equipment: $74k
Bio Gas Treatment Plan View
Bio Gas Treatment Elevation Refrigeration with Redundant Adsorption Cannisters
Existing Equipment Summary Unit Designation: CAT 1 CAT 2 CAT 3 CAT 4 BLOWER 1 BLOWER 2 COGEN 1 COGEN 2 Engine Model No.: G342 G342 G342 G342 VHP 5108 GL VHP 5108 GL VGF P48 GLD VGF P48 GLD Power Output BHP: 225 225 225 225 750 750 999 999 Allowable Back Pressure (in wc): 34 34 34 34 9 9 13.5 13.5 Proposed Reduction Technology: NSCR NSCR NSCR NSCR SCR SCR SCR SCR Proposed Combustion Mode: Stoich Stoich Stoich Stoich Lean Lean Lean Lean Manufacturer: Caterpillar Caterpillar Caterpillar Caterpillar Waukesha Waukesha Waukesha Waukesha
Pump-Drive Engines Pumps: 4 x CAT G342 Pump-Drive Engine 225 HP each, Variable Speed Drive 2 dedicated to Nat gas with NSCR Catalyst (propane back-up) 2 dedicated to digester gas, operated lean & de-rated Permitted at 45 PPMv NOx 1110.2 Engines < 500 HP No electrical back-up Option Compliance Option for 1110.2 Fit all engines with new NSCR Catalysts ( 4 total) Minor Pipe Fitting Work Required New AFRC Required Total Installation Cost = $10,700 per engine Annualized Operating Cost of $1,000 per engine Total Annual Reduction of NOx + ROG = 0.25 TPY per unit
Pump Drive Engines Each of Four Engines Would be Operated Stoichiometric And Fitted with New NSCR Catalysts and AFRC capital Cost = $10,700 per unit
Pump Drive Engines
Blower-Drive Engines Blowers: 2 x Waukesha VHP 5108GL 750 HP each, Variable Speed Drive Digester Gas Operation Only Meet Existing Permit Limits Permitted at 36 PPMv NOx 1110.2 Engines > 500 HP Electrical Blowers x 2 for 100% Back-up Compliance Option for 1110.2 Fit both engines with new SCR Catalysts Significant Design and Construction Work Required New AFRC Required Total Installation Cost = $275k per engine Annualized Operating Cost of $33.5k per engine Total Annual Reduction of NOx + ROG = 0.73 TPY per unit Extremely Limited on Back-Pressure
Blower-Drive Engines
Cogeneration Engines Electrical Generators: 2 x Waukesha VGFP48 GLD 999 HP each, Fitted with Exhaust and Jacket Water Heat Recovery Digester Gas Operation or Air Blended Natural Gas Operation Permitted at 36 PPMv NOx 1110.2 Engines > 500 HP In Process of Commissioning Compliance Option for 1110.2 Fit both engines with new SCR Catalysts Very Significant Design and Construction Work Required New AFRC Required Total Installation Cost = $510k per engine Annualized Operating Cost of $40k per engine Total Annual Reduction of NOx + ROG = 0.95 TPY per unit Extremely Limited on Back-Pressure, Already at Limit
Cogen Plant-Drive Engines
Cogen Plant-Drive Engines
Cogen Plant-Drive Engines Model of Existing Exterior Arrangement of Exhaust System
Cogen Plant-Drive Engines Model of Proposed Exterior Arrangement of Exhaust System
Cogen Plant-Drive Engines Model of Existing Interior Arrangement of Exhaust System
Cogen Plant-Drive Engines Model of Proposed Interior Arrangement of Exhaust System
Feasibility Summary for San Bernardino Overall Facility Cost Per Ton of Reduction of NOx + ROG Based on 10-Year NPV: $3.5M per Ton Reduced Total capital Cost Including Gas Clean-up $4.03M Net Income $/kw-hour (-$0.04/kW-hour) SCR Does not Appear to be Feasible for New Cogen Facility due to space and back-pressure Constraints. Likely not feasible for Blower Engines due to Limited Back Pressure Flaring Likely/TBD
Rule 1110.2 Estimated Retrofit Costs to Achieve Proposed Biogas Limits (Continued) David Rothbart, P.E. Los Angeles County Sanitation Districts Air Quality Engineering Section October 26, 2010
Summary of Estimated Retrofit Costs Retrofit Capital Cost ($ million) Power Output (kw) Net Income ($/kw-hr) Proposed Limits May Result in Flaring? LACSD $11.2 8,100-0.026 Yes OCSD ~ $21.6 21,000 - TBD SOCWA $4.7 800-0.021 Yes IEUA RP-1 $7.5 2,800-0.036 TBD RP-2 $2.9 580-0.067 Yes RCWMD $0.8 1,000-0.021 Yes City of San Bernardino $4.0 2,700-0.040 Yes City of Riverside $5.1 to $7.3 3,000-0.023 to -0.046 Yes
Conclusions Preliminary results from demonstration projects indicate not all projects can achieve the proposed biogas limits Every facility is different (pretreatment needs vary due to contaminant loading site-to-site) Retrofits are more costly than flaring for most facilities NAAQS standards will require further reductions by 2020/21
Recommendations Final CEMS results from Ox Mountain, OCSD and Noxtech demonstrations are needed The Final Technology Assessment Report for Biogas Engines should address: Costs for chilling and redundant adsorption systems Anticipated equipment life due to new NAAQS Rule 1110.2 has already caused flaring of biogas Cost Effectiveness threshold should be $19,650 per ton (VOC+NOx) and cost per kw-hr cannot exceed power importation rates GHG impacts from reduced renewable power generation Modify Rule 1110.2 to require a technology assessment every five years