Encina Wastewater Authority Energy & Emissions Strategic Plan Final Report

Transcription

1 trim line Encina Wastewater Authority Energy & Emissions Strategic Plan Final Report April 2011

2

3

4 Table of Contents List of Tables... viii List of Figures... x List of Appendices... xii List of Abbreviations... xii Executive Summary... 1 ES- 1: Introduction... 1 ES- 2: Baseline Energy Profiles and Projections... 4 ES- 3: Energy Efficiency and Process Improvements... 8 ES- 4: Technology Evaluations Electrical Power Production ES- 5: Technology Evaluations Biogas Production ES- 6: Technology Evaluations Waste Heat ES- 7: Air Emissions ES- 8: Alternative Scenarios Development, Evaluation and Selection ES- 9: Grant and Incentive Programs Summary Section 1: Introduction Business Plan Key Issue Study Objectives and Approach Current Energy Management Strategic Plan Current Facilities and Operations Current Air Emissions Permits Strategic Planning Horizon Section 2: Baseline Energy Profiles and Projections Introduction and Purpose EWPCF Baseline Period Wastewater Flows Current Operations Baseline Energy Purchase, Production and Use Energy Units Purchased and Produced Electrical Energy Natural Gas Purchases and Digester Gas Production Heat Production and Use Cost of Baseline Energy Purchases Power Natural Gas Current Operations Energy Summary Energy Demand and Production Projections EWPCF Wastewater and Solids Flow Projections Energy and Emissions Strategic Plan, Encina Wastewater Authority i

5 Table of Contents (cont d) Electrical Energy Production and Use Natural Gas Biogas Production Heat Production Power Demand, Gas Production and Waste Heat Forecast Summary and Findings Section 3: Energy Efficiency and Process Improvements Introduction and Purpose Energy Audit Baseline Energy Consumption Energy Efficiency Measures Efficiency Measures Summary Process Audit Energy Use During On Peak Periods Individual Process Unit Review and Observations Headworks Primary Treatment Aeration System Secondary Clarifiers Diffused Air Flotation System Internal Combustion Engine Cooling Water Pumping Odor Tower Water Pump (3WL) Digester Re-circulation Pumps EWA Operations Staff Interview Information Flow Equalization Basin Headworks Chemical Use Review Process Changes Analysis Screenings Hopper Primary Clarifier Covers Stamford Baffles Operations Manual Potential Improvements Summary Section 4: Technology Evaluations Alternative Power Production Introduction and Purpose, Technology Evaluations Introduction and Purpose, Alternative Power Production Internal Combustion Engines Introduction History Energy and Emissions Strategic Plan, Encina Wastewater Authority ii

6 Table of Contents (cont d) Technical Description Vendors Size and kw Production Gas Blending System Waste to Energy Implications Emissions Reduction Catalyst Biogas Treatment Description Reason for Limited Information Development Cost Examples of Internal Combustion Engine Projects Community Impacts Environmental Impacts Greenhouse Gas Impacts Operational Impacts Summary of Advantages and Disadvantages Fuel Cell Introduction History Technical Description Vendors Size and kwh Production Examples of Fuel Cell Projects Potential Funding Sources Cost Community Impacts Environmental Impacts Greenhouse Gas Impacts Operational Impacts Summary of Advantages and Disadvantages Solar Photovoltaic (PV) Introduction History Technical Description Vendors Size and kwh Production Examples of Solar PV Projects Potential Funding Sources Cost Community Impacts Environmental Impacts Greenhouse Gas Impacts Operational Impacts Summary of Advantages and Disadvantages Small Wind Energy and Emissions Strategic Plan, Encina Wastewater Authority iii

7 Table of Contents (cont d) Description Vendors Reason for limited Information Development Southern California Annual Average Wind Power Microturbines Introduction History Technical Description Vendors Size and kwh Production Examples of Microturbine Projects Potential Funding Sources Cost Community Impacts Environmental Impacts Greenhouse Gas Impacts Operational Impacts Summary of Advantages and Disadvantages Section 5: Technology Evaluations Biogas Production Biogas Production Enhancements Introduction and Purpose Waste to Energy Introduction History Technical Description Vendors Size and kwh Production Examples of Grease Trap Waste and Food Waste Projects Potential Funding Sources Cost Community Impacts Environmental Impacts Greenhouse Gas Impacts Operational Impacts Summary of Advantages and Disadvantages Cell Lysis Introduction History Technical Description Vendors Size and kwh Production Energy and Emissions Strategic Plan, Encina Wastewater Authority iv

8 Table of Contents (cont d) Examples of Cell Lysis Projects Potential Funding Sources Cost Community Impacts Environmental Impacts Greenhouse Gas Impacts Operational Impacts Summary of Advantages and Disadvantages Digester Train Modifications Description Reason for Limited Information Development References Other Support Facilities Sludge Heating as a Dewatering Aid Description History Technical Description Vendors Reason for Limited Information Development Biogas Storage Description Reason for Limited Information Development Section 6: Technology Evaluations Waste Heat Introduction and Purpose Chillers Technical Description Absorption chillers Adsorption chillers Vendors Size and kw Production Cost Summary of Advantages and Disadvantages Waste Heat Power Generation Technical Description Organic Rankine Cycle Engine Heat Recovery Hydraulic Engine Size and kwh Production Cost Summary of Advantages and Disadvantages Steam Turbines Description Reason for Limited Information Development Gasification of Biosolids Energy and Emissions Strategic Plan, Encina Wastewater Authority v

9 Table of Contents (cont d) MaxWest Environmental Systems Introduction History Technical Description Examples of Gasification Projects Vendor s Commercial Arrangement Cost Nexterra Systems Introduction History Technical Description Examples of Gasification Projects Vendor s Commercial Arrangement Cost Section 7: Air Emissions Introduction and Purpose Current SDAPCD Permit Estimated Emissions for each Technology Permit Strategy Options Maintain Synthetic Minor Permit, Emissions Near Maximum Threshold Limits Seek a Major Source Permit (Title V) Continuing with Synthetic Minor Permit with Significantly Lower Pollutant Emissions Greenhouse Gas Considerations Section 8: Alternative Scenarios Development, Evaluation and Selection Introduction and Purpose Evaluation Criteria and Weighting Factors Technologies Retained for Projects Development Energy Self Generation Goals Approach to Identifying Alternative Scenarios Preliminary Project Scenarios Preliminary Alternative Scenarios Scoring Top Ranked Scenarios Considerations Screened Scenarios Surviving Scenarios Selected Project and Implementation Plan Selected Scenario B Description Implementation Plan Summary and Findings Energy and Emissions Strategic Plan, Encina Wastewater Authority vi

10 Table of Contents (cont d) Relative Cost of Energy from Various Sources Recommended Scenario Energy Independence Additional Recommendations Future Work Section 9: Grant and Incentive Programs Summary Technology Based Funding Support Programs Fuel Cells Funding Sources Solar PV Funding Sources California s Net Energy Metering (NEM) The California Solar Initiative (CSI) Microturbines Funding Sources Waste to Energy (WTE) Funding Sources Energy and Emissions Strategic Plan, Encina Wastewater Authority vii

11 Table of Contents (cont'd) List of Tables ES-1 Summary of Existing EWPCF Energy Management Facilities ES-2 Recommended Project Summary ES-3 Baseline 12-Month Natural Gas and Biogas Usage (Therms) ES-4 Baseline Heat Projection and Utilization (MM Btu/hr) ES-5 Baseline Energy Summary ES-6 Projected Energy Demand and Production1) ES-7 Projected Heat Balance (MMBtu/hr)) 1) ES-8 Energy Demand Reduction Opportunities ES-9 CO Emissions from Key Technologies ES-10 Highest Ranked Scenarios ES-11 Scenarios A and B Comparison ES-12 Priorities for implementing Scenario B Table 1 SDAPCD Synthetic Minor Emissions Thresholds Table 2 Baseline 12 Month Natural and Biogas Usage (Therms) Table 3 Baseline Heat Production and Utilization (MMBtu/hr) Table 4 Baseline Energy Profile Summary Table 5 Flow Projections Table 6 Projected Energy Demand and Production (Natural Units) Table 7 Projected Energy Demand and Production (Therms) Table 8 Baseline Electrical Energy Consumption By Area Table 9 Estimated SDG&E Incentives, Energy Savings, and Simple Payback Table 10 Clarifiers Online High SVI and Flow Table 11 Major Improvements Greater than $10,000 investment Table 12 Minor Recommendations Less than $10,000 investment Table 13 Current and Projected Digester Gas Production Table 14 Current and Projected Electricity Production Table 15 Heat Production, Use and Wasting Table 16 Gas Blending System On-Site Electricity Production (Three Engines) Table 17 Estimated Emissions Reduction from Clean Air Catalyst Table 18 Estimated Cost Emissions Reduction System Table 19 Catalyst Replacement Parts, Replacement Frequency and Estimated Costs Table 20 Potential Funding Sources Fuel Cell Energy and Emissions Strategic Plan, Encina Wastewater Authority viii

12 Table of Contents (cont'd) Table 21 Table 22 Table 23 Table 24 Table 25 Table 26 Table 27 Table 28 Table 29 Table 30 Table 31 Table 32 Table 33 Table 34 Table 35 Table 36 Table 37 Table 38 Table 39 Table 40 Table 41 Table 42 Table 43 Table 44 Table 45 Table 46 Table 47 Table 48 Table 49 Table 50 Table 51 Table 52 Table 53 Table 54 Table 55 Table 56 Estimated Costs for 300 kw and 1.4 MW Fuel Cell Systems Operational Impacts of Fuel Cell PV Solar Operations Impacts Potential Funding Microturbines Estimated Costs of One 65 kw Microturbine Operational Impacts of Microturbines Grease Hauler Market Assessment Estimate of Digester Gas and Energy Production Estimated Revenue Waste Receiving Station Estimated O&M Cost Operational Impacts of using Grease Trap Waste/Food Waste Crown System Equipment Components Estimate of Digester Gas and Energy Production OpenCEL System Equipment Components Estimate of Digester Gas and Energy Production Cell Lysis Systems O&M Costs Operational Impacts of using Cell Lysis Biogas Storage Cost Estimates Estimated Cost of Trane Absorption Chiller Estimated Cost of Eco-Max Adsorption Chiller Cost Comparison of Existing Chiller to Absorption & Adsorption Chillers Estimated PureCycle Power System Cost Estimated Infinity Turbine Power System Cost Estimated Costs - Nexterra s Gasification System - Sludge to Heat Solution IC Engine CO Emissions Fuel Cell CO Emissions Sludge Drying Operation CO Emissions 2009 Greenhouse Gas Combustion Emission Summary Evaluation Criteria Technologies Included in Scenarios Development Technologies Excluded in Scenario Development Initially Identified Alternative Scenarios Scenario Scoring Values Preliminary Scenarios Scoring Results Highest Ranked Scenarios Scenarios A and B Comparison Energy and Emissions Strategic Plan, Encina Wastewater Authority ix

13 Table of Contents (cont'd) Table 57 Table 58 Table 59 Table 60 Table 61 Table 62 Table 63 Table 64 Investment Cost Breakdown Energy Comparison Factors Scenario B Energy Sources (million therms/year) Recommended Scenario B Technologies Priorities Prioritized Investments Potential Funding Sources Fuel Cell Potential Funding Microturbines Estimated Revenue List of Figures ES-1 Baseline 12-Month Electrical Power Purchases ES-2 Evaluation Criteria with Weighting ES-3 Energy Cost for Various Sources ES-4 Scenarios A and B Energy Sources Comparison ES-5 Scenario B Energy Elements Figure 1 Baseline EWPCF Wastewater Flows Figure 2 Baseline Electrical Power Purchases and Production Figure 3 Baseline Unit Electricity Use per Millon Gallons Treated Figure 4 Baseline Natural Gas Purchases Figure 5 Baseline Digester Gas Production Figure 6 Baseline Heat Production & Utilization Figure 7 Baseline Electricity Purchases Figure 8 Baseline Natural Gas Purchases Figure 9 Projected Wastewater Flows Figure 10 Projected Solids Loading Figure 11 Projected Electrical Energy Production and Purchases Figure 12 Projected Natural Gas Demands Figure 13 Biogas Production and Uses Figure 14 Dryer Gas Demands Figure 15 Projected Heat Production, Usage and Wasting Figure 16 Business As Usual Energy Purchases and Self Generation Figure 17 Current and Projected Energy Demand Figure 18 Aeration Basin Selector Layout Figure 19 Secondary Clarifier Photo Energy and Emissions Strategic Plan, Encina Wastewater Authority x

14 Table of Contents (cont'd) Figure 20 Figure 21 Figure 22 Figure 23 Figure 24 Figure 25 Figure 26 Figure 27 Figure 28 Figure 29 Figure 30 Figure 31 Figure 32 Figure 33 Figure 34 Figure 35 Figure 36 Figure 37 Figure 38 Figure 39 Figure 40 Figure 41 Figure 42 Figure 43 Figure 44 Figure 45 Figure 46 Figure 47 Figure 48 Headworks Photo Screenings Hopper Primary Basin Covers Stamford Baffle Photo Four Stroke Cycle Biogas Scrubber Unit Schematic MCFC Fuel Cell Diagram Typical Solar PV System Small Wind Turbine Wind Energy Map Southern California Cutaway of Microturbine (Source: Capstone) Installed Microturbine Grease Trap Waste Receiving Schematic Food Waste Receiving and Processing Schematic OpenCEL s Focused Pulsed (FP) Technology Crown Solids Disintegration System Crown Solids Disintegration System Basic Process Flow Diagram OpenCEL Focused Pulsed (FP) Model 20 System Basic Process Flow Diagram Alfa Laval Spiral Heat Exchanger Biogas Storage Vessels Absorption Chiller Schematic Adsorption Chiller Photo Organic Rankine Cycle Unit Schematic Steam Turbine Unit Schematic Maxwest s Gasification System Flow Diagram Nexterra s Gasifier Scenarios A and B Energy Sources Comparison Highest Ranked Scenario Achieving Strategic Objective Energy Cost from Various Sources Energy and Emissions Strategic Plan, Encina Wastewater Authority xi

15 Table of Contents (cont'd) List of Appendices A Business As Usual Energy Data B ECOS Energy Audit Report C Technology Cost Templates D Scenario Summary Sheets E Scenario Ranking Sheets List of Abbreviations kw mw kwh mwh Btu MM Btu/hr MG MM CF/yr CF Hp mg/l Ft 2 mgd FTE gpd Kilowatts Megawatts Kilowatt hours Megawatt hours British thermal units Million British thermal units per hour Million gallons Million cubic feet per year Cubic Feet Horse Power Milligrams per liter Feet squared Million gallons per day Full time equivalent Gallons per day Energy and Emissions Strategic Plan, Encina Wastewater Authority xii

16 Executive Summary ES- 1: Introduction ES- 1.1 Background The Encina Wastewater Authority (EWA) is a Joint Powers Authority (JPA) owned by the cities of Carlsbad, Vista, and Encinitas, and, the Buena Sanitation, Vallecitos Water, and Leucadia Wastewater special districts. EWA operates, maintains, and administers the Encina Water Pollution Control Facility (EWPCF) located in Carlsbad, California. The EWPCF is a conventional activated sludge wastewater treatment plant with liquid capacity of 40.5 million gallons per day (MGD) and solids capacity of 43.3 MGD. The EWPCF employs chemically enhanced primary treatment to increase the volume of gas produced in its anaerobic digesters by reducing the quantity of organic solids oxidized in secondary treatment. The EWPCF routinely achieves over 95% removal rates for influent suspended solids and carbonaceous biochemical oxygen demand. The highly treated effluent is either returned to the member agencies for recycling or is discharged to the Pacific Ocean through the Encina Ocean Outfall. Solid by-products are pelletized and sold as an alternative fuel or fertilizer. Wastewater treatment is and an energy intensive enterprise and energy costs in southern California have skyrocketed. Since the original Energy Management Strategic Plan was adopted in 2003, EWPCF energy management expenses have increased over 208% to nearly $2.1 million per year despite marginally lower influent flows and solids loadings. Recent tariff challenges initiated by San Diego Gas & Electric threaten to push these costs even higher. This Energy and Emission Strategic Plan (E 2 SP) establishes EWA s strategy for the production and use of three (3) distinct and operationally interrelated forms of energy utilized at the EWPCF: electricity; gas; and, heat. ES- 1.2 Existing EWPCF Energy Management Facilities The existing EWPCF energy management facilities were founded on recommendations made in the 2003 Energy Management Strategic Plan and implemented as a part of the Phase V Expansion Project completed in These facilities meet a significant portion of the EWPCF s demand for power, provide emergency backup power for the EWPCF, meet EWPCF heat demands, and use most of the biogas produced in the anaerobic digesters. Specifically: The EWPCF currently produces electricity using four (4) Caterpillar Model G3516, water cooled internal combustion (IC) engines. Due to air permit restrictions, engine run time is limited and thus EWPCF must also purchase electricity from SDG&E. Each of these IC engines can be fueled by biogas produced in EWPCF s anaerobic digesters or by natural gas purchased from a statewide natural gas JPA. Excess biogas is also used in the Phase V Heat Dryer or post-phase V waste gas flare. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-1

17 Using various heat exchange technologies, IC engine cooling water is used to heat the EWPCF s anaerobic digesters. IC engines that produce energy in the form of both electricity and heat are commonly referred to as cogeneration engines. EWPCF s IC engine and heat exchange array is known as the EWPCF Cogeneration System. Table ES-1: Summary of Existing EWPCF Energy Management Facilities Power Source Delivery Concept Delivery System Percentage Electricity Produced On-Site Cogeneration 69% Purchased SDG&E 31% Gas Produced On-Site Biogas from Anaerobic 64% Digesters Purchased Statewide Natural Gas JPA 36% Heat Produced On-Site Cogeneration 100% ES- 1.3 Purpose of the Energy and Emissions Strategic Plan As in all current enterprise activities, EWA is guided by its 2013 Business Plan which includes a number of principles underlying development of the E2SP. First, EWA s Mission Statement states: As an environmental leader, EWA provides sustainable and fiscally responsible wastewater services to the communities it serves while maximizing the use of alternative and renewable resources. In addition, the 2013 Business Plan sets forth nine Key Issues identified by the EWA Board of Directors as critical to accomplishing EWA s Mission. Key Issue No. 5 states in part: Additional resource recovery and investment creates the opportunity for energy independence to mitigate fiscal impacts arising from unstable energy markets. Therefore, the purpose of the E 2 SP is to maximize return on investment and the use of alternative/renewable resources while moving the EWPCF towards energy independence. To accomplish this purpose, staff established four (4) goals for the Project: 1. Energy Efficiency Goal: Review existing energy consumption and evaluate alternative methods to reduce energy consumption. 2. Energy Production Goal: Identify and evaluate alternative technologies for increasing on-site energy production powered by alternative or renewable fuels. 3. Emissions Permitting Goal: Evaluate alternative emissions and permitting models considering EWPCF energy demands and probable energy production strategies. 4. Planning Goal: Recommend specific actions that maximize return on investment and the use of alternative/renewable resources while moving towards energy independence Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-2

18 ES- 1.4 which is defined initially as the capability to consistently produce 95% of the EWPCF s total electricity demand on-site, independent of SDG&E before Planning Process Elements On October 28, 2009 the Board of Directors approved a staff recommendation to commission Kennedy/Jenks Consultants (KJ) to develop this E 2 SP in cooperation with staff. KJ developed and led staff through a process comprised of the following planning process elements to achieve the Project s Goals: Develop baseline (current and projected) EWPCF energy needs based on current operations and permit limitations Identify efficiency measures that could reduce energy consumption as initial action items Provide a comprehensive analysis of technologies available that offer the opportunity to reduce electrical power and natural gas purchases Rank available technologies using evaluation criteria Evaluate air emissions regulations and identify required permit modifications associated with alternative technologies Compare alternatives, rank and identify the preferred alternative and develop an implementation plan The recommended E2SP Alternative Project (Scenario B) includes the following technologies and features: Implement energy efficiency measures (EEM s). Increase biogas production (beyond production available from wastewater solids) by implementing a Waste to Energy (WTE) project. Install biogas treatment and exhaust catalysts on all engines to substantially reduce carbon monoxide emissions thereby increasing permit allowable engines run time. Supplement the existing Administration Building chiller with a new adsorption chiller and hot water loop utilizing available waste heat from IC engines hot water recovery system. Increase total IC engine capacity to maintain current level of redundancy and meet electrical energy demands by installing 5 th and 6 th engines. See Table ES-2 for a summary of the recommended project. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-3

19 Table ES-2: Recommended Project Summary Plan Element Investment ($ Million) Payback (Years) Priority Energy Efficiency Measures $ to 25 1 IC Engine Gas Treatment & Catalysts $ Waste to Energy $ th IC engine $ Administration Building Chiller $ th IC engine $ ES- 2: Baseline Energy Profiles and Projections EWPCF s demand for energy and the ability to produce energy in the form of electricity, gas and heat under baseline conditions is profiled. Baseline conditions are defined as operation of current processes and equipment within current permit limitations. A 12 month operating period is used to define current conditions, including seasonal variations. The impact of wastewater flow increases on existing EWPCF energy management capabilities is considered. A baseline energy profile through year 2030 is projected and defined as Business as Usual ES- 2.1 Baseline Energy Profiles. Electricity. Electrical power is required to operate all wastewater treatment unit process at the EWPCF. Total annual electrical power consumption was 17,500,000 kwh, with a monthly average of 1,456,700 kwh. Total annual electrical power production was 12,000,000 kwh, with a monthly average of 985,300 kwh. EWA purchased 5,500,000 kwh of electricity over the 12 month baseline period. Approximately 69% of the EWPCF electricity demand was produced onsite. Monthly self produced and purchased electrical energy is shown graphically in the following paragraph, Figure ES-1. To partially mitigate the self generation constraints imposed by SDAPCD permits, staff applied for permit modifications which were granted during the report preparation period. The modified permits allow a greater use of IC engines increasing the baseline electricity self generation to 12,500,000 kwh. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-4

20 Figure ES-1: Baseline 12-Month Electrical Power Production and Purchases Gas. Biogas produced in EWPCF s digesters is used in combination with purchased natural gas to fuel the dryer and IC engines. Total annual gas consumption included 1,250,000 therms of produced biogas and 695,700 therms of purchased natural gas as summarized on Table ES- 3. Biogas has about 60% of the fuel content of natural gas and thus a larger volume of biogas is required for a given use. Small quantities of biogas (35,000 therms) were flared to protect EWPCF systems and comply with air permits. Larger quantities of biogas could be used in the dryer if more was available from the digesters. The baseline use of biogas in the IC engines was at the maximum allowed by the current air emissions permits. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-5

21 Table ES-3: Baseline 12-Month Natural Gas and Biogas Usage (Therms) Process/Facility Natural Gas Biogas Total IC Engines 1) 87,000 1,200,000 1,287,000 Solids Dryer 541,800 15, ,800 Dryer RTO 41, ,300 Administration Building 24, ,300 Maintenance Building 1, ,300 Flared 0 35,000 35,000 Totals 695,700 1,250,000 1,945,700 1) Including indirect use and blending Heat. Heat is produced at EWPCF from the operation of the IC engines and solids dryer process units. A portion of the produced heat from the IC engines (in the form of hot water) is utilized in the anaerobic digesters and an absorption chiller serving the Power Building. Excess hot water heat is wasted to EWPCF effluent. All of the dryer system heat (in the form of hot air) is wasted to the atmosphere. A summary of the baseline heat balance, recorded as MMBtu/hr (million Btu s per hour), is show in Table ES-4: Table ES-4: Baseline Heat Projection and Utilization (MM Btu/hr) Heat Source Produced Utilized Wasted IC Engines a) Dryer/RTO b) Digesters Chiller Total a) Heat produced in hot water circulation system b) Exhausted hot air Total Energy. Energy purchased and produced at EWPCF during the baseline period is summarized in the following Table ES-5. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-6

22 Table ES-5: Baseline Energy Summary Electricity Gas 1) Heat 2) kwh/yr % Total therms % Total MMBtu/hr % Total Self 12,000,000 3) 69% 1,250,000 64% Generation Purchased 5,500,000 31% 695,700 36% - - Total 17,500,000 1,945, ) Nearly all of the self generated gas is utilized to fuel IC engines. Purchased gas is used to fuel buildings equipment and the dryer 2) 47% of the IC engine produced hot water heat was utilized by the EWPCF digesters and power building absorption chiller 3) IC engine use during the baseline period under a SDAPCD permit modified in May Under the new permit, annual self generation would increase to approximately 12,500,000 kwh/yr. ES- 2.2 Baseline Energy Projections An energy profile was developed assuming no process changes, no permit condition changes, and the projected increase in wastewater flows from 22.6 mgd in 2010 to 33.7 mgd by the year EWA operators would have the option of using increasing biogas production in the IC engines, up to the maximum operations limits associated with the current SDAPCD air emissions permit or as fuel for the dryer. The electricity and gas self generation levels shown here are based on using increasing biogas production in the IC engines as the first priority. Electricity- Annual electricity demand is projected to increase from 17.5 million kwh in 2010 to 24.0 million kwh in Self generation would not exceed 12.5 million kwh due to the modified air emissions permits restrictions. Self generation would decrease from 69% to 52% by Gas- The total gas demand is projected to increase from 1.9 million therms in 2010 to 2.2 million therms in Annual biogas production would increase from 1.25 million therms in 2010 to 1.8 million therms in This provides an opportunity to reduce natural gas demand in the dryer from 0.54 million therms to 0.36 million therms by Total natural gas purchases would be reduced from 0.70 million therms in 2010 to 0.38 million therms in Self generation of all gas usage (including IC Engine fueling) would increase from 64% to 83% by Flaring of excess biogas would be required beginning in approximately 2025 when the maximum dryer biogas fuel demand and allowable IC engine use is reached. Heat- Heat utilization would increase to meet higher digester heat demands although wasted hot water heat would remain relatively high at 3.2 MMBtu/hr. Projected business as usual energy demands and self generation capabilities are summarized in the following tables ES-6 and ES-7. The self generation levels are based on an estimated allocation of increasing biogas use between IC engines and the dryer as noted above. The total equivalent energy self generation values shown in Table ES-6 were determined by converting all energy units to a common unit of measure (therms). Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-7

23 Table ES-6: Projected Energy Demand and Production 1 Total Electricity Demand Electricity Self Generation Total Gas Use Total Equivalent Energy Self Generation 3) Average Flow Gas Self Generation 2) Year MGD kwh Therms ,500,000 69% 1,945,700 64% 56% ,659,000 61% 1,980,000 79% 57% ,951,000 52% 2,270,000 83% 57% ,916,000 45% 2,570,000 88% 57% 1) Business as Usual 2) Gas self generation percentages also include a large portion of the electricity self generation benefit derived by the IC engine operation 3) Total equivalent self generation is determined by combining electricity, gas and waste heat usage into a single calculation. The percentages are lower compared to individual electricity and gas self generation values due to overlap between electricity and gas energy types. Table ES-7: Projected Heat Balance (MMBtu/hr) 1 Year Utilized Waste ) Hot air heat produced in the dryer/rto unit is excluded Assuming wastewater flows increase as presented, EWPCF electricity and gas usage is projected to increase between years 2010 and A baseline energy profile was developed to quantify projected increases based on the business as usual condition (i.e., no major changes to processes and no changes to air emissions permits). Because air emissions rates for the IC engines are fixed by permit, the additional biogas produced by increased wastewater flows would be used in the heat dryer(s). Additional electrical energy demand would be met through purchased electricity. ES- 3: Energy Efficiency and Process Improvements There are opportunities for investment in improvements that would reduce electric power demand and purchased energy cost. Some opportunities are process changes and some are efficiency measures. Some of these investments may be eligible for local energy projection incentives. Potential improvements, Energy Efficiency Measures (EEM), which could reduce electrical energy demand, were identified. Also, a process audit was also completed that concluded with a list of potential energy savings process changes. This energy and process audit achieved the Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-8

24 Goal No. 1: Review existing energy consumption and evaluate alternative methods to reduce energy consumption. The analysis and results include the following: As stated in Section 2 above, the baseline annual electricity energy demand was 17,500,000 kwh. Blowers operating to provide air for the flow equalization, aeration basins and agitation air resulted in the greatest demand (6,110,000 kwh, 35% of total demand) Dewatering, secondary treatment support facilities, the heat dryer, and effluent pumping facilities incurred similar significant electrical demands each over the 12 month baseline period: Dewatering (2,015,000 kwh 11%) Dryer (1,846,000 kwh 10 %) Effluent Pumping (1,581,000 9%) Secondary support Facilities (1,435,000 kwh 8 %) Nine (9) potential EEM s where identified ranging in electrical demands savings from 76,000 kwh to 2,000,000 kwh. The recommended EEM target of electrical demand savings is 2,000,000 kwh, which is 11% of the baseline demand and 35% of total purchased electricity. The EEM s and process changes with the greatest potential for energy cost savings and their status are presented in Table ES-8. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-9

25 Table ES-8: Energy Demand Reduction Opportunities Category Name Potential Annual Savings Schedule & Status EEM Turbo Blowers Technology $380, Study Planned Process Change Reduce Sludge Return Rate $250, ; Implemented Process Change Anaerobic Selectors $200, ; Design in Progress EEM Variable Speed Ventilation Fans $150, ; Study Planned EEM Variable Speed Digester Mix $140, ; Study Planned Pumps EEM Repair Aeration Air Main $120, ; Construction in Progress ES-4: Technology Evaluations Electrical Power Production Candidate technologies were divided into three groups: biogas production, electrical power and waste heat. Several conventional and alternative technologies within each group were evaluated by considering environmental, operational, technology maturity and cost factors. The technology evaluations were intended to provide an objective basis for selecting appropriate technologies for inclusion in alternative project scenarios. This evaluation process achieved the Project s Energy Production Goal: Identify and evaluate alternative technologies for increasing on-site energy production powered by alternative or renewable fuels. Alternative power technologies would provide EWA the ability to increase self generated electricity. Continued use of internal combustion (IC) engines, fuel cells, solar photovoltaic (PV), small wind turbines and microturbines were evaluated. Technologies retained for development of alternative project scenarios Include: IC engines, with and without emissions reduction equipment Fuel cells fueled by biogas or natural gas Solar PV Retained technologies offer cost savings, leveraging of existing investment (IC engines), increased self generation due to higher fuel efficiency (fuel cells) and reduction of greenhouse gas emissions (IC engines fueled by biogas, fuel cells and solar PV). Technologies dropped from consideration and the reason for that finding include: Small wind turbines There is limited wind source at the EWPCF site as documented by nationally published wind data. Microturbines Benefits are limited due to availability of existing IC engines, comparatively higher costs due to smaller units, increased operating complexity. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-10

26 ES- 5: Technology Evaluations Biogas Production Biogas production enhancement technology evaluations included opportunities to increase biogas production through the following processes: Waste to Energy Cell Lysis Digester Enhancements. Waste to Energy (WTE) and Cell Lysis were selected as technologies suitable for consideration in the development of project scenarios as each would increase biogas production contributing to increased self generation with acceptable environmental, operational, and cost impacts. WTE would include the introduction of grease to the anaerobic digesters by third parties serving businesses in North San Diego County. Increased biogas production from grease organic solids reduction would be directly proportional to the volume of grease received and likely would require development of a grease receiving market over time. Food waste is an alternate organics source as well. The analysis estimated biogas production could be enhanced by 533,000 therms a year a 39% increase. Cell Lysis is an emerging technology that would increase biogas production by conditioning waste activated sludge prior to feeding into digesters. The technology is utilized in Europe now and is recently being installed in the United States. Experience indicates biogas production could be increased by approximately 10%. Digester train modifications were not retained due to their high capital cost, operating difficulty and marginal capability to increase gas production. Other evaluated support facilities technologies include biogas treatment, sludge heating preconditioning and biogas storage. Biogas treatment was retained as a selected technology to be included with several other technologies to provide required biogas pre-treatment. ES- 6: Technology Evaluations Waste Heat Waste heat technologies evaluated in the analysis include those capable of converting currently produced waste heat into chilled water for space cooling (absorption and adsorption systems) and processes able to produce electricity (organic rankine cycle [ORC] power and steam turbine systems). Gasification of biosolids that could increase produced heat supply was evaluated. Produced heat could be used either directly to offset gas fuel needs currently met by purchase of natural gas, or used to produce mechanical energy or electricity thereby offsetting power purchases. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-11

27 The absorption/adsorption and organic rankine cycle (ORC) technologies are selected for consideration in the alternative scenario development process. Either would reduce power purchases and allow EWA to improve use of currently wasted produced heat. Steam turbines were not selected due to high costs and limited available systems that could effectively use waste EWPCF produced heat. Gasification of biosolids was determined to be an emerging technology with limited operating experience and high cost and space requirements. ES- 7: Air Emissions This section reviewed constraints on cogeneration operation due to air emissions. Opportunities to relieve those constraints and optimize the use of existing and future cogeneration equipment were evaluated. Air emissions from other technologies were also evaluated. This review achieved the Project s Emissions Permitting Goal: Evaluate alternative emissions and permitting models considering EWPCF energy demands and probable energy production strategies. One IC engine serves as a standby unit and the remaining 3 are available for production of electricity. Based on carbon monoxide (CO) emissions limits contained in current San Diego Air Pollution Control District (APCD) air emission permits, the use of the IC engines is limited to an equivalent of approximately 1.8 IC engines full-time use at this time. The current air emissions permit results in an unused IC engine capacity equal to 1.2 IC engines preventing EWA from increasing self generated electricity (beyond current operation) unless an alternative air emissions strategy is adopted. CO emissions from IC engines, fuel cells and the existing dryer technologies are presented in Table ES-9. Table ES-9: CO Emissions from Key Technologies Capacity and Annual CO Emissions (kw) Emissions Technology Fuel (tons/yr) IC Engine without Catalyst Biogas IC Engine with Catalyst Biogas Fuel Cell Biogas 1, Dryer 40% Biogas 1) Dryer 82% Biogas 1) RTO Emissions Natural Gas ) The remaining fuel demand would be met by natural gas Greenhouse gas baseline emissions were reviewed in this section. For reporting year 2009, emissions expressed in metric tons per year of CO2 equivalents were 22,000 tons of which 17,000 were classified as biogenic and 5,000 as non-biogenic. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-12

28 Alternative project scenarios were evaluated in Section 8 using a model developed for that purpose. That model considered CO and CO2 emissions for each technology and each scenario. ES- 8: Alternative Scenarios Development, Evaluation and Selection ES- 8.1 Purpose The purpose of this section is to develop practical alternative scenarios that would achieve energy independence in accordance with the Business Plan. Energy independence is defined initially as the capability to consistently produce 95% of the EWPCF s total electricity demand on-site, independent of SDG&E. This section includes the development of preliminary scenarios, ranking scenarios by completing the scoring process, preliminary screening of scenarios and ultimately recommending the most favorable scenario. The scoring and preliminary screening resulted in a short list of scenarios from which the recommended scenario was selected. The recommended scenario was then further developed into a prioritized plan for implementing the technologies comprising the scenario. This section achieves the Project s Planning Goal: Recommend specific actions that maximize return on investment and the use of alternative/renewable resources while moving towards energy independence which is defined initially as the capability to consistently produce 95% of the EWPCF s total electricity demand on-site, independent of SDG&E before ES- 8.2 Evaluation Criteria and Weighting Factors KJ and EWA staff developed evaluation criteria for use in comparing alternative technologies. Five criteria were developed that include various factors considered important in the ranking process. Weighting was developed using the pair wise technique by EWA staff. The selected evaluation criteria include: Operational Impact Cost and Savings Technology Maturity and Reliability Air Permitting Environmental Considerations. The criteria weighting developed by the pair wise comparison is shown in Figure ES-2. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-13

29 ES- 8.3 Figure ES-2: Evaluation Criteria with Weighting Technologies Retained for Projects Development Sixteen (16) candidate technologies divided into three (3) general categories were considered in the analysis. From this list, eight (8) were selected for inclusion in the development of alternative scenarios. The technologies surviving the screening process were as follows: Electricity Production Internal combustion engines with emissions reduction Internal combustion engines without emissions reduction Fuel cells Solar photovoltaic (PV) Biogas Production Waste to energy (WTE) Cell lysis Waste Heat Utilization Organic rankine cycle engine (ORC) Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-14

30 Adsorption/absorption chiller Technologies considered and dropped in the technology screening process were as follows: Electricity Production Microturbines Small wind turbines Biogas Production Digester train modification Other support facilities o o Sludge heating Biogas storage Waste Heat Utilization ES- 8.4 Biosolids gasification Energy Self Generation Goals A primary objective of the E 2 SP is to provide EWA with a plan for achieving targeted energy self generation goals. The development of alternative scenarios provides the opportunity to identify combinations of the selected technologies that could achieve such goals. The alternative scenarios developed in the study were configured to enable EWA to self generate 95% of the total EWPCF electrical needs in the year The 95% self generation goal included an allowance for implementation of EEM s (estimated to reduce electrical energy use by 2.0 MM kw/hr per year). Natural gas purchases are also considered in the development and opportunities to reduce such purchases to the maximum extend possible is identified. However, the 95% 2020 self generation target is the metric used to select the mix of technologies included in each of the alternative scenarios. ES- 8.5 Approach to Identifying and Evaluating Alternative Scenarios The selected technologies offer EWA the opportunity to reduce dependence on purchased electricity and natural gas. The value of incorporating each within the EWPCF operation can be initially viewed by considering unit costs expressed on a common basis. The following figure provides a comparison of energy cost from various sources expressed in a common unit of energy (therms). See figure ES-3. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-15

31 Figure ES-3: Energy Cost for Various Sources The comparison demonstrates the economic value of waste to energy, the use of existing IC engines fueled by biogas and the organic rankine cycle generator (ORC) units. Solar PV and fuel cells operating on natural gas are shown to have the highest cost. Fuel cells fueled by biogas and a new adsorption chiller have unit costs between the off-peak and on-peak purchased power costs. Combining multiple technologies into scenarios was identified as the next step for subsequent comparison. An Excel-based model was utilized to facilitate the development of alternative scenarios. Based on a building blocks concept, the model allows the selection of technologies tracking the following key factors. Capital Cost Annual Operation and Maintenance Cost Net Present Value Annual Carbon Monoxide (CO) Emissions Annual Power and Production/Purchase Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-16

32 Annual Biogas Utilization Annual Natural Gas Purchases Waste Heat Balance (production and utilization) Greenhouse Gas Emissions (carbon dioxide - CO 2 ) Total energy requirements and onsite energy production are tabulated in 5-year increments to allow selection of combinations of technologies meeting selected goals. The annual CO emissions are tabulated and notification is provided by the model when the total exceeds the current synthetic minor limitation of 100 tons per year. Electricity generation is tracked and compared to demand. Using this model feature, various combinations of technologies were identified that could achieve the Planning Goal of 95% self generated electricity by By tracking biogas production and utilization as technologies are selected, the availability of sufficient biogas is verified. Technologies that would increase biogas production (waste to energy and cell lysis) were incorporated into some of the identified scenarios. ES- 8.6 Preliminary Project Scenarios Using the scenario model, seventeen (17) scenarios (alternative projects) were initially developed. Each scenario was configured with alternative combinations of technologies for comparison purposes. The combinations were designed to evaluate all practical combinations of variables (technologies). As noted previously, all of the scenarios (with one exception) would allow EWA to achieve 95% electrical energy self generation in the year One scenario would be limited to 90% self generation in Each scenario included combinations of technologies from the following list: IC Engines: Identified scenarios including continuing with four (4) existing engines, adding a 5 th engine or installing engines with greater capacity than current 750 kw units IC Engines gas treatment and catalysts: Several scenarios include the addition of air emissions reduction equipment (biogas treatment and catalysts) allowing increased IC engine use within the current SDAPCD permit emissions limits. Dryer Facilities: Fueled with one of two possible combinations of biogas and natural gas (40% biogas/60% natural gas or 82% biogas/18% natural gas) Fuel cell: 0.3 mw or 1.4 mw units (compared to 0.75 kw for each current IC engine) Solar: 1.0m mw, 3.0 mw or 4.0 mw (larger capacity installations would utilize net metering) Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-17

33 Organic Rankine Cycle Generator (ORC): utilizing waste heat from IC engines or fuel cell producing 0.23 mw electricity Second Absorption Chiller: 110 ton unit installed in Administration Building (without this technology, existing administration equipment utilizes electricity) Cell Lysis: Increasing biogas production Waste to Energy: Increasing biogas production A detailed table listing technologies included in each of the 17 scenarios is provided in Section 8.6 of the full report. A summary of the variations between the scenarios is as follows: Three scenarios would exceed the current APCD air emissions permit creating the need to obtain a Title V major emissions permit Nine scenarios would maintain current four IC engines operation Seven scenarios include air emissions reduction equipment for all IC engines Eight scenarios include a fuel cell Five scenarios include solar PV equipment Thirteen scenarios include an adsorption chiller serving the Administration Building Five scenarios include an Organic Rankine Cycle (ORC) unit Twelve scenarios include waste to energy (WTE) ES- 8.7 Preliminary Project Scenarios Scoring The seventeen scenarios were ranked by completing a scoring process utilizing the evaluation criteria and the weightings developed in the study. A matrix analysis approach was used assigning scores derived from the weighted criteria applied to each technology included within each scenario. The scoring was completed by assigning the highest possible score to each technology included within a scenario. Scores were then adjusted downward based on technology limitations for each of the technologies included in the scenario. With 12 technologies and 100 possible points for the 5 evaluation criteria, the maximum possible score was Those technologies that were not included in a scenario received the maximum score. A review of the scoring resulted in the following findings: Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-18

34 The business as usual scenario received a score of 919 and was tied for 4 th highest. The highest ranked scenario (receiving a score of 975) would not enable EWA to achieve the % electricity self production goal The 2 nd highest ranked scenario (receiving a score of 958) includes additional IC engines and emissions reduction on all engines The highest ranked scenario including fuel cells technology was tied for 4 th with a score of 919 The highest ranked scenario including solar PV technology was ranked 6 th with a score of 915 The highest scenario requiring a Title V emissions permit (major emissions designation) received a score of 901 (ranked 9 th ) ES- 8.8 Top Ranked Scenarios Considerations The top ranked scenarios were compared by completing a detailed review of each to verify the scoring for each and identification of features that might influence a final selection. For screening purposes, low scoring scenarios, scenarios that impaired operational efficiency or operational redundancy, scenarios unlikely to meet the 95% on-site production of electricity goal, and scenarios adding to EWPCF s current GHG emissions were eliminated from further consideration. The remaining top 6 ranked scenarios were assigned E 2 SP Scenario designations to simplify the final comparison and selection of a recommended scenario, see Table ES-10. Table ES-10 provides a comparison of the remaining 6 highest scored E2SP Scenarios A through F. Features of each E 2 SP Scenario are listed including electricity producing technologies contributing to self generation capacity. The six top ranked E 2 SP Scenarios have several common features: Each would maximize use of biogas in the dryer up to the maximum design blend of 82% biogas and 18% natural gas. Waste to energy, (WTE) increasing biogas production, is included to achieve self generation goals and dryer gas demand in five of the six scenarios (WTE is not included in Scenario A, Business as Usual). Each includes the installation of an adsorption chiller utilizing available waste heat reducing existing Administration Building equipment electricity demand. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-19

35 Table ES-10: Highest Ranked Scenarios Comparison Features Score Annual Capital Net Present 2020 Electricity No. of Biogas No. Engines Fuel Cell ORC Generation Solar PV 2030 Electricity Final Designation Scenario Cost ($ mil) Cost ($ mil) Value ($ mil) Self Generation Engines Treatment with Catalyst (mw) (mw) (mw) Self Generation B 4f 958 $2.5 $11.7 $ % 6 Full % C 4e 933 $2.2 $10.0 $ % 5 Full % D $2.4 $13.0 $ % 4 For % A 1 (Business as 919 $3.2 $ - $ % % Usual) E $2.4 $17.5 $ % 5 Full % F 4b 902 $2.3 $13.5 $ % 4 For % Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES-20

36 Excepting Scenario A, Business as Usual, each achieves the Planning Goal of consistently producing 95% of the EWPCF s total electricity demand on-site, independent of SDG&E, before 2020 Of particular note was the final scoring with respect to the capital and net present value cost estimates. Scenario A (Business as Usual) was estimated to have the lowest of both. It would not, however, allow EWA to achieve its goals. Also, the estimated net present value is dependent on a state-wide published energy inflation rate of 1.75% per year. The rate of energy price increase is controlled by others and higher purchased energy prices would increase Scenario A costs. ES- 8.9 Selected Project and Implementation Plan The highest scoring scenario, Scenario B has the third lowest net present value and the second lowest capital cost. It maximizes the use of the recently installed IC engines and continues with the same mix of existing technologies (technologies EWA staff are familiar with and have available staff to support) with the exception of gas treatment and catalysts. Scenario B utilizes the remaining Power Building space by including the addition of a 5 th engine. Gas treatment and catalysts allow greater use of the IC engines and reduce CO emissions well below SDAPCD threshold for a synthetic minor emissions permit. With the addition of a 5 th engine, up to 4 engines would be operated maintaining one engine as a standby unit as required to meet EWPCF reliability requirements. Scenario B also includes a 6 th engine that would allow EWA to achieve 95% self generation in With these factors in mind, the final recommendation is to rely on the evaluation criteria, weighting and scoring developed during the study and select the highest scoring scenario, E 2 SP Scenario B. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES- 21

37 ES Description of Recommended Project The recommended E 2 SP Scenario B includes the following technologies and features: Implement Energy Efficiency Measures. Increase biogas production (beyond production available from wastewater solids) by implementing a waste to energy project. Install biogas treatment and catalysts on all engines to substantially reduce carbon monoxide and other pollutant emissions thereby complying with current emissions limitations. Supplement existing Administration Building chiller with new absorption chiller and hot water loop utilizing available waste heat from IC engines hot water recovery system. Increase total IC Engine capacity to maintain current level of redundancy and meet electrical energy demands by installing 5 th and 6 th engines. Increasing the size of one or more of the existing 750 kw engines and installing a larger 6 th engine would likely be more cost effective than expanding the existing energy building to accommodate a 6 th engine. Utilize biogas as a fuel source for the dryer up to a maximum blend of 82% biogas and 18% natural gas as biogas production increases and exceeds IC engine biogas demand for self generation of electricity. A comparison of business as usual and the recommended scenario is provided in the following Table ES-11. Electricity and total energy self generation would be significantly increased with implementation of Scenario B. Total energy accounts for electrical energy production and use of biogas offsetting purchases of natural gas. The comparison of energy self production includes implementation of the recommended Energy Efficiency Measures (EEMs) identified in the study. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES- 22

38 Table ES-11: Scenarios A and B Comparison Factors (2020) Scenario A (Business as Usual) Scenario B (Recommended) Electricity Self Generated 52% 95% Gas Self Generated 83% 79% Total Energy Equivalent Self 57% 81% Generated Capital Cost $0 $11,700,000 O&M Cost $3,210,000 $2,510,000 Self Generation (kwh/yr) 12,500,000 19,800,000 Purchased Energy 1) $3,000,000 $940,000 CO Emissions (t/yr) GHG Emissions (t/yr) 6,500 6,100 Net Present Value $26,800,000 $29,200,000 1) Estimated 2020 cost of electricity and gas purchases inflated to 2020 dollars (1.75% inflation rate) Scenario B would require a capital investment of $11,700,000 to achieve the 2020 onsite electricity production goal. A portion of that investment would be recovered by reduced operating costs. Energy purchases and self generation for Scenarios A (Business as Usual) and B (Recommended) are compared graphically in the Figure ES-4. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES- 23

39 Figure ES-4: Scenarios A and B Energy Sources Comparison Implementing Scenario B would allow EWA to move forward with increased levels of self generation. Figure ES-5 provides a breakdown of energy elements of Scenario B in 2010, 2020 and 2030 in common units (millions of therms per year) and grouped into categories as follows: Purchased Electricity: Electricity and natural gas purchases Existing Heat Recovery: Heat utilization for digesters and the existing chiller Existing Produced Gas: Electrical energy production from IC engines limited by current SDAPCD permit (prior to installation of gas treatment and catalysts EEM Energy Reduction: Energy savings associated with Energy Efficiency Measures Emissions Reduction on Existing Engines: Increased electricity production with installation of gas treatment and catalysts Waste to Energy and 5 th Engine: Increased electricity production with installation of waste to energy technology and 5 th IC engine Expanded Chiller Use: Increased recovery of waste heat with installation of new chiller serving the Administration Building 6 th Engine: Increased electricity production with installation of 6 th IC engine Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES- 24

40 ES Implementation Plan Figure ES-5: Scenario B Energy Elements Scenario B includes several technology components that could be implemented in a phased manner. A recommended phasing plan is developed by setting priorities for each technology. The opportunity to increase self generation is directly related to increased biogas production that is dependent on two factors, increased wastewater (and solids) flows and implementation of the recommended waste to energy project. Increased wastewater flows are dependent on the local economy and associated new development. The WTE project provides an opportunity to increase biogas production immediately and potentially has a higher degree of certainty for increasing biogas production. Considering these factors, the recommended priority for implementing Scenario B elements is provided in Table ES-12. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES- 25

41 Table ES-12: Priorities for implementing Scenario B Payback Plan Element Investment - $ Million Period - Years Priority Basis for Setting Priority Energy Efficiency to 25 1 Demand reduction Measures IC Engine Gas Treatment & Ability to increase self generation and reduce emissions Catalysts Waste to Energy Near term biogas increased production with high level of EWA control 5 th IC engine Scheduling dependent on increased wastewater flows Administration Building Chiller Reduces natural gas and electricity purchases; utilizes waste heat 6 th IC engine Scheduling dependent on increased wastewater increased flows The E-CAMP process should be used to schedule, fund and implement the recommended plan elements. ES Summary and Findings Benefits of Recommended Scenario: The recommended plan, E 2 SP, has the following benefits: 1. Reduce the requirements for purchased energy. Under Scenario B the cost of purchased energy is projected to fall between years 2010 and Reduce air CO emissions and remove operating constraints imposed by air emissions permits. 3. Reduce reliance on outside energy providers. 4. Leverages the previous investments made in internal combustion engine generators. 5. Insulate EWA energy budgets from the uncertainty of energy markets. Energy Independence: The E 2 SP has shown that energy independence is indeed achievable for EWPCF. The Plan, compared to Business as Usual, is projected to: Increase self generated electricity from 69% currently to 95% in Increase self generated gas from 64% to 79% in Increase self generated total (equivalent) energy from 56% currently to 81% in Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES- 26

42 Additional Recommendations: Beyond implementing the recommended Scenario, other actions should be taken to support the objectives of this plan: 1. Energy asset management: Update and improve programs for energy assets condition assessment and maintenance. Improve operability and control of existing cogeneration system. 2. Energy funding strategies: As part of the Comprehensive Asset Management Program (CAMP) and the budget process, support energy strategic initiatives that focus on continuous improvement related to energy efficiency and energy annual cost. While current budget pressures may slow the implementation of energy related initiatives, they should be evaluated in the context of facility wide need through the established CAMP process. 3. Energy initiatives awareness: Utilize EWA s website and other communications to make the public aware of the energy cost of accomplishing our work and of initiatives underway to reduce the amount of energy and cost devoted to providing our services. 4. Waste to energy implementation: Explore cooperative ventures between EWA and Member Agencies related to grease and food waste derived fuel production. Future Work. EWPCF s culture of energy efficiency and optimization should be maintained. Additional effort will contribute to this. These efforts should consider and include the following future studies, analysis and improvements. 1. Energy procurement management: The effort includes conducting tariff analysis, consideration of long term energy purchase contracts and new strategies for energy procurement. 2. Energy sub-metering: Expand and automate the system of monitoring and reporting electrical power use by plant area and equipment. This type of data supports energy use projections, management and conservation. 3. Purchased energy quality and reliability: Evaluate the quality and reliability of electrical power being delivered to us. Determine if purchased power quality and reliability could be improved, and if so, how. Consider actions to reduce our risk of not being able to provide services due to electrical power delivery shortcomings. 4. Energy asset security and internal reliability: Evaluate the security and reliability of assets related to distribution of self produced energy. Identify strategies for maintaining service in the event of natural disasters, component failure and human error. 5. Energy use model: Explore expanding our energy use predictive model to include feedback from our metering and real time status of energy use and generation. Design the model to best support the staff resources of EWA. 6. Energy use and efficiency metrics: Establish metrics to measure improvements in the efficient generation and use of energy. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES- 27

43 7. Energy conservation: Expand initial work related to demand reduction and search for additional energy conservation measures. ES- 9: Grant and Incentive Programs Summary The available funding is in the form of incentives managed by the local supplier of energy (SDG&E) and state and federal grants and are primarily technology based. ES- 9.1 Fuel Cells In California, the Self Generation Incentive Program (SGIP) governed by the California Public Utility Commission offers an incentive for fuel cells using a renewable fuel, such as digester gas, of $4500 per kw up to 1 MW. For projects greater than 1MW, incentives of $2250 per kw are available for the energy generated between 1 MW and 2 MW. Projects larger than 2 MW receive $1125 per KW above 2 MW and up to 3 MW. Systems must be new, UL listed, and in compliance with all applicable performance and safety standards. Wind systems, fuel cells and advanced energy storage systems must be covered by a minimum five year warranty. The warranty must protect against the breakdown or degradation in electrical output of more than ten percent from the originally rated electrical output. The warranty should cover all replacement and labor costs. The incentive can go to the project if owned or leased. The SGIP might not receive additional funding beyond December 31, ES- 9.2 Solar PV California s Net Energy Metering (NEM): Net energy metering applies to solar PV projects as long as the project is behind the meter. Eligible renewable resources are photovoltaic, wind, fuel cells and dairy biogas. System capacities are limited to a maximum of 1 MW in size. SDG&E is obligated by state law to provide a net metering agreement to all their customers. Net metering is a method of metering the energy consumed and produced by a customer that has a renewable resource generator, and credits the customer with the retail value of the generated electricity. The California Solar Initiative (CSI): This is part of the Go Solar California campaign which builds on 10 years of state solar rebates offered to customers in California's investor-owned utility territories. CSI rebates vary according to system size, customer class, and performance and installation factors. The subsidies automatically decline in "steps" based on the volume of solar megawatts confirmed within each utility service territory. Federal rebates and incentives are available in the form of tax credits and rebates. Unfortunately, tax-exempt entities such as EWA are not eligible unless developed through a third party agreement. ES- 9.3 Microturbines Federal rebates and incentives are available in the form of tax credits and rebates. Unfortunately, tax-exempt entities such as EWA are not eligible. However, a tax exempt entity could take advantage of these incentives through a third-party lease arrangement. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES- 28

44 ES- 9.4 Waste to Energy (WTE) The funding incentives for installing a waste receiving facility are geared to the ultimate use of the digester gas that is produced. Energy production incentives could be used to help fund a combined heat and power system. The improvements directly associated with waste receiving (i.e. pumps, tanks, and site improvements) are not eligible for incentives. However, energy efficiency incentives could be used to lower the cost of project components such as premium efficiency pumps and motors. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page ES- 29

45

46 Section 1: Introduction The Encina Wastewater Authority (EWA) is a Joint Powers Authority (JPA) owned by the City of Carlsbad, City of Vista, City of Encinitas, Leucadia Wastewater District, Vallecitos Water District and Buena Sanitation District. EWA operates the Encina Water Pollution Control Facility (EWPCF) located in Carlsbad, California. EWPCF is currently treating 23 million gallons per day (mgd) discharging secondary effluent to the Pacific Ocean through an ocean outfall and anticipates flows will increase to as much as 43 mgd in the future. A portion of the secondary effluent (up to 3.0 mgd) is discharged to an advanced water treatment facility owned by the City of Carlsbad. Like other similar facilities, one of the highest operating costs is the purchase of power and natural gas to accommodate operating requirements. EWA recently completed improvements to onsite power generation utilizing internal combustion engines and a sludge drying system that requires gas as a means of providing heat for the drying process. As the operations of the new facilities were being optimized, EWA proceeded to update their Energy Strategic Plan, first developed in The updated plan includes the management of emissions associated with the use of biogas and natural gas as fuel sources Business Plan Key Issue EWA s 2013 Business Plan (adopted in 2008) addresses nine (9) key issues. Key Issue No. 5 (Additional resource recovery and investment creates the opportunity for energy independence) recognizes the economic value of increased self generation of energy. This study pursues the concepts of increased self generation by evaluating alternative technologies and the development of a recommended energy strategic plan focused on optimizing self generation of energy. 1.2 Study Objectives and Approach The objective of this study is to update and expand the Energy Strategic Plan adopted in 2003 and to further expand the scope by including air emissions in the plan development. The goal is to achieve a defined level of energy independence within a predictable period of time. The objectives of the study are to: Project energy usage Identify opportunities for energy demand reduction Identify technologies for increasing energy production Evaluate air emissions compliance in conjunction with production technologies Recommend improvements that will work toward achieving energy independence Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 1-1

47 To accomplish these objectives, an approach was developed summarized as follows: Develop baseline (current and projected) EWPCF energy needs based on current operations and permit limitations Identify efficiency measures that could reduce energy consumption as initial action items Provide a comprehensive analysis of technologies available that offer the opportunity to reduce electrical power and natural gas purchases Rank available technologies using evaluation criteria Evaluate air emissions regulations and identify required permit modifications associated with alternative technologies Proceed with the comparison of alternatives, ranking and identification of the preferred alternative and develop an implementation plan 1.3 Current Energy Management Strategic Plan The Energy Management Strategic Plan (Kennedy/Jenks Consultants, 2003) adopted by EWA included the following objectives: EWA s stated objectives of this Plan are developing an energy management strategic plan that provides operational flexibility to maximize efficiency, uses available biogas, and maintains plant reliability while minimizing the need for new or significantly altered air permits. The process and conclusion of the Plan is to meet these objectives and achieve the goal of developing a plan for improving the existing energy management system to meet EWA s needs for the next 20 years. Defining success and knowing when the objectives of the project have been achieved involves meeting well-defined criteria that includes: Power Generation Heat Generation Gas Production Meeting the plant s power demand. Providing backup power. Meeting the plant s heat demand without boilers. Using all biogas produced by the plant. The plan provided the framework for planning and construction of improvements, most of which were completed in The plan included the replacement of all existing engines with new generators offering the following benefits: 1. The EWPCF retained its classification as a minor source with the San Diego APCD. 2. The energy system is simple with respect to permitting, design, construction, start-up, training, operation, and maintenance. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 1-2

48 3. The energy system uses proven technology. 4. EWA is prepared for fluctuating energy rates and realized substantially lower energy costs. 5. The plant s heat demand is supplied by heat recovered from internal combustion engines. 6. Multiple units provide system reliability. 7. Most of the plant s electrical power demand is generated onsite. 8. Emergency backup power capacity increased from 1,375 kw to 2,250 kw. 9. The system has the flexibility to respond to varying operating conditions and has adequate capacity to beneficially use the biogas when the dryer isn t operating. 10. The system increased beneficial use of biogas. 11. Operation and maintenance of the energy system was reduced, and procedures are similar to the earlier system thus minimizing training requirements for new equipment. 12. The energy system is adaptable to phasing, expanding, and upgrading because it is based on packaged generator sets. 13. The system uses the existing cogeneration building system footprint. 1.4 Current Facilities and Operations EWPCF is a secondary activated sludge type treatment facility with an existing design capacity of 43.3 million gallons per day (mgd) liquid and 30.3 mgd solids. The additional solids capacity is needed to accommodate the solids generated from upstream water reclamation facilities. The overall purpose of EWPCF is to treat wastewater to meet the standards of the NPDES permit. EWPCF unit processes include preliminary treatment (screening and grit removal), primary treatment, secondary treatment, and solids treatment. The last major expansion to the existing design capacity was completed in 2009 during what is known as the Phase V Expansion. The preliminary and primary treatment processes are not energy intensive. The implementation of chemically enhanced primary treatment has had a significant beneficial impact on the energy demand for secondary treatment. Secondary treatment is energy intensive because of its demand for compressed aeration air. The energy required to supply aeration air is the largest single energy demand at the facility. Six electric motor-driven aeration blowers exist to provide aeration and agitation air. The aeration and agitation air supplies are cross connected through a pipe and valve. Aeration air is conveyed to the aeration basins through an underground aeration header. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 1-3

49 Solids treatment includes sludge thickening, anaerobic digestion, dewatering, and heat drying facilities. Sludge thickening is accomplished with three dissolved air flotation thickeners. Sludge stabilization occurs in three 95-foot diameter anaerobic digesters with 2.23 million gallons of capacity each. The biogas produced in the anaerobic digestion process provides some of the fuel for the cogeneration system and will provide fuel for the future biosolids heat drying facility. Two 50-foot diameter digesters are currently decommissioned, but could be used for sludge or gas holding to provide a wide-spot in the line for sludge and gas management. During the mid to late 1990 s EWPCF experienced an increase in wastewater strengths, which were substantially higher than the facilities design parameters. Increased influent wastewater strength was measured in the form of higher concentrations of biochemical oxygen demand (BOD) and total suspended solids (TSS). As a result of the increased wastewater strengths, the plant s secondary treatment capacity was effectively reduced. To restore the secondary treatment capacity to the design standards, EWPCF moved forward in 2001 to construct a Chemically Enhanced Primary Treatment (CEPT) system. EWPCF flows have decreased recently due to the affects of water conservation and increased treatment occurring in a satellite reclamation plant (Meadowlark Water Reclamation Facility). 1.5 Current Air Emissions Permits EWA operates several facilities regulated by the San Diego County Air Pollution Control District (SDAPCD). The regulated process equipment impacting EWPCF s energy independence capabilities are: Four internal combustion (IC) engines fueled by biogas and natural gas One Andritz DDS40 sludge dryer (fueled by biogas and natural gas) and CECO Systems natural gas fired regenerative thermal oxidizer (RTO) Two Rosemont, Inc. Varec 239A series 6-inch diameter exposed flares equipped with natural gas pilot systems providing EWPCF the ability to flare excess biogas Process equipment operations must comply with SDAPCD permits that establish operating limits based on emissions levels confirmed by source testing during the equipment startup period for regulated pollutants. The operating limits are developed by SDAPCD based on air basin conditions within their jurisdiction. EWA s permits include operating limitations in compliance with synthetic minor emissions threshold criteria established by SDAPCD listed in the following table. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 1-4

50 Table 1: SDAPCD Synthetic Minor Emissions Thresholds Maximum Synthetic Minor Criteria Pollutant Threshold (tons/year) 1) Carbon Monoxide 100 Nitrogen Oxides 50 Volatile Organic Compounds (VOC) 50 Particulate Matter 100 Sulfur Oxides 100 1) Potential to emit Carbon monoxide, a product of fuel combustion in an engine or dryer, is the controlling pollutant at EWPCF. When the 100 ton per year threshold is reached, the emission levels for the remaining four regulated pollutants are well below their respective threshold levels. Using biogas as a fuel source for the IC engines and sludge dryer, EWA reduces dependence on purchases of commercial electrical power and natural gas. Currently, 96% of the produced biogas is utilized within the current SDAPCD permits limitations and with the equipment now in place. An incidental portion of current biogas production (4%) is being flared. These uses emit carbon monoxide. As biogas production increases with higher wastewater flows, biogas usage would eventually be constrained by the current emissions permit structure and equipment. Biogas flaring would be forced to increase substantially without SDAPCD permit revisions or investment in new emissions control technology. EWA has the option of obtaining less restrictive emissions permits that would essentially eliminate the carbon monoxide constraint thereby allowing increased electrical energy production with existing IC engines. This option would require a reclassification to a Title V major emissions source which is possible within SDAPCD and Untied States environmental Protection Agency (USEPA) regulations. Such a designation requires a significant public review process and air quality modeling to identify impacts to the environment. This study evaluates alternative technologies that would provide EWPCF with the ability to increase self generation of energy (electrical and gas) either within the current synthetic minor permit threshold criteria or under a major emissions source permit designation. 1.6 Strategic Planning Horizon This planning effort addressed the planning period through year All projections and calculations were carried through The full strategic plan should be subject to a detailed update in year However, facilities planned in response to the plan s objectives and findings were planned through the year This is because it is believed that purchased energy prices and developing technologies could not be effectively predicted beyond 10 years. For this reason it is recommended that projections and recommendations from this report be reviewed to confirm findings presented in this report in Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 1-5

51

52 Section 2: Baseline Energy Profiles and Projections 2.1 Introduction and Purpose Baseline data has been developed using recorded operating data that began when the plant resumed normal operations after completion and startup of the Phase V expansion and all process units were functioning normally. The 12 months beginning in April 2009 through March 2010 have been used to develop the baseline profile. Wastewater and solids loading projections are utilized in the development of projected increases in energy demand and self generation without process or emissions permit modifications. EWPCF s demand for energy and the ability to self generate energy (in the form of electricity, gas and waste heat) under baseline conditions is addressed in this section. Baseline conditions are defined as operation of current processes and equipment within current permit limitations. This is completed by presenting the following information; Current and projected wastewater flows and solids loading Baseline energy profile for total energy demand and self generation by evaluating operating data for a 12-month period Energy projections through 2030 for baseline conditions The data developed in this section is compared (in subsequent sections) to alternative energy profiles focused on increased levels of energy self generation that could be realized with investments in alternative technologies. 2.2 EWPCF Baseline Period Wastewater Flows Average daily wastewater flows have been dropping over the last several years due to the affects of water conservation and the diversion of higher flows to the Vallecitos Water District Meadowlark Water Reclamation Facility (MRF). Wastewater flows during the 12 month baseline period are shown graphically in Figure 1. EWPCF influent flows ranged from mgd (October 2009) to mgd (January 2010) with a 12 month average flow rate of 22.6 mgd. The higher flow rates occurring in April 2009 and January through March 2010 are likely due to seasonal changes in Meadowlark Water Reclamation Facility (MRF) diversions. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-1

53 Figure 1: Baseline EWPCF Wastewater Flows 2.3 Current Operations EWA operating staff maintains detailed records of all operating energy parameters including electrical energy purchase and production, natural gas purchase and use, biogas production and use, and hot water production and use. Each of the energy types is summarized in the following subsections; a detailed breakdown of energy data is provided in Appendix A Baseline Energy Purchase, Production and Use Baseline energy use and production for electricity, natural gas, biogas and hot water are presented in the following subsections Energy Units Electrical energy purchases and production are reported in kilowatt hours (kwh). Gas purchases and production are reported in therms. Hot water is reported in million Btus per hour (MMBtu/hr). A summary of all energy types is provided in a common energy unit (therms) in Table 7 (page 2-19) in this section Purchased and Produced Electrical Energy During the period between April 2009 and March 2010, EWA s monthly power purchased from SDG&E ranged from 313,100 kwh (December 2009) to 680,500 kwh (September 2009), as shown in the Figure 2. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-2

54 The amount of power produced monthly by cogeneration ranged from 881,500 kwh (February 2010) to 1,076,000 (October 2009), also shown in the figure below. Total power purchased from SDG&E for this period was 5,500,000 kwh, with a monthly average of 458,300 kwh. Total annual electrical power production was 12,000,000 kwh, with a monthly average of 985,300 kwh. Total annual power consumption was 17,500,000 kwh, with a monthly average of 1,456,700 kwh. The self generated electrical power was about 69% of the total electrical demand during the baseline period. The unit power use ranged from 1,760 kwh/mg in April 2010 to 2,600 kwh/mg in September 2009 averaging 2,130 kwh/mg. Average monthly unit power use is shown graphically in Figure 3. Variations in unit energy use is primary due to seasonal changes in wastewater temperature. Figure 2: Baseline Electrical Power Purchases and Production Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-3

55 Figure 3: Baseline Unit Electricity Use per Millon Gallons Treated Natural Gas Purchases and Digester Gas Production Natural gas is purchased from the state sponsored Department of General Services Natural Gas Program (DGS) and has a variety of uses at the EWPCF, including: Power production in internal combustion engines (directly and through the eclipse blending unit) Sludge dryer RTO Space and water heating in the Administration Building and Maintenance Building. Total natural gas purchases are recorded with a EWPCF master meter and reported in therms in monthly utility invoices. EWPCF utilizes the natural gas in a number of processes and equipment recording use with several EWA maintained individual meters. The internal uses are recorded in detailed spreadsheets that were utilized to develop baseline natural gas use throughout EWPCF. Appendix A includes monthly summaries of recorded natural gas use by equipment and process during the baseline period. During the 12 month baseline period, the natural gas purchased for EWPCF use was 730,000 therms (the energy unit utilized to quantify and invoice EWA for natural gas purchases). The recorded in-plant use was approximately 5% lower (695,700 therms) during the same period. The difference in recorded values is within accepted tolerances for totalizing and comparing multiple meters. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-4

56 Table 2 provides a summary of natural gas utilization by process or equipment (as measured by internal plant gas meters) during the 12 month baseline period. Biogas utilization is also provided in Table 2 for the same period. Each fuel quantity is reported in therms. A therm is 100,000 Btu of heat Natural gas fuel (heat) content is higher at approximately 1,000 Btu/CF; biogas fuel content is lower at 600 Btu/CF. Therefore, about 1.7 CF of biogas is required to produce the same heat as 1.0 CF of natural gas. Fuel content differences are reflected in the volume of each fuel utilized to provide the fuel quantities shown in Table 2. Table 2: Baseline 12 Month Natural and Biogas Usage (Therms) Process/Facility Natural Gas Biogas Total Internal Combustion 87,000 1,200,000 1,287,500 Engines 1) Solids Dryer 541,800 15, ,800 Dryer RTO 41, ,300 Administration Building 24, ,300 Maintenance Building 1, ,300 Flared 0 35,000 35,000 Totals 695,700 1,250,000 1,945,700 1) Including direct use and blending. The baseline monthly natural gas purchases from DGS ranged from 55,000 therms (February 2010) to 84,500 therms (October 2009) and averaged 60,800 therms as shown in the Figure 4. Total internally measured use during the baseline period was 695,700 therms, with a monthly average of 58,000 therms and a range of 45,800 therms (February 2010) to 72,700 therms (September 2009). EWPCF utilizes biogas produced in anaerobic digesters to fuel IC engines and supplement gas demands in the sludge dryer. IC engine use is limited by daily and annual quantities of biogas and natural gas specified in operating permits issued by SDAPCD. The permit constraints allow EWA to operate the equivalent of approximately 2.0 IC engines over a 12 month (as modified in May 2010) period. During the baseline period, approximately 5% of produced biogas was flared. This occurred due to SDAPCD permit limitations and ongoing dryer startup activities. In the future, the need to flare biogas is expected to be reduced and would occur when biogas cannot be used in the IC engines or the dryer during brief periods. Monthly biogas production ranged from 97,200 therms (August 2009) to 152,500 (October 2009) as shown in Figure 5. The 12 month baseline period digester gas production was 1,250,000 therms, with an average of 104,200 therms per month. The recorded monthly volume of biogas production appeared to increase dramatically in October EWA staff indicated there were meter operating issues during that period and the recorded data for that month may not be accurate. Corrective action has been taken. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-5

57 Figure 4: Baseline Natural Gas Purchases Figure 5: Baseline Digester Gas Production Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-6

58 Heat Production and Use Heat is produced at EWPCF with the operation of the IC engines and solids dryer process units. Produced heat is utilized in the anaerobic digesters and an absorption chiller. Heat production and use is measured as in units of million Btu/hrs (MMBtu/hr). EWA estimates and records the quantity of waste heat generated by the four existing IC engines and RTO exhaust and heat utilization by an absorption chiller (serving the switchgear room) and digesters. Because heat quantities are not measured, billed, and quantified in the same manner as electrical power, natural gas, and digester gas, the recorded heat production is estimated based on manufacturer specifications. The IC engines excess heat is transferred to a water cooling system. During the baseline period, the average heat transfer was 6.8 MMBtu/hr, ranging from 6.0 MMBtu/hr (August 2009) to 8.6 MMBtu/hr (October 2009). Hot water is provided to the anaerobic digester and an absorption chiller. There is a substantial quantity of excess heat that is wasted. The anaerobic digesters was estimated to have an average baseline heat demand of 1.2 MMBtu/hr. This estimate is reasonable by comparison to other plant designs with similar size digesters, flows, and ambient temperatures. EWA operates an absorption chiller that cools the main switchgear room. The primary heat source is operating switchgear shedding heat. The absorption chiller is estimated to have an average baseline heat demand of 2.0 MMBtu/hr. This estimate was established by consulting specifications for the installed unit (Trane model ABSC 112) and assumes the chiller operates continuously at full capacity. The remainder of the produced heat is wasted to EWPCF effluent. The average baseline rate of waste heat was 3.6 MMBtu/hr. Currently, there is no method of capturing and utilizing the heat exhausted from the RTO and all of the heat produced in the RTO is wasted as hot air. Based on the manufacturer specifications, the estimated average baseline rate of exhaust heat is 1.39 MMBtu/hr. The combined total of wasted heat (RTO plus hot water) during the baseline period was 5.0 MMBtu/hr. Table 3 provides a summary of the average rate of heat production, utilization and wasting during the baseline period. Figure 6 provides a graphical representation of baseline heat production, utilization and wasting. The chiller and digester demands (met by hot water provided from the IC engines) are shown on the lower portion of the graph. Excess IC engine waste heat ( in the form of hot water) and the RTO waste heat (in the form of hot air) are identified separately and labeled as a wasted heat source. Total heat production is delineated by the combined demand and waste portions on the graphs. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-7

59 Table 3: Baseline Heat Production and Usage (MMBtu/hr) Heat Source Produced Usage Wasted IC Engines a) 6.8 Dryer/RTO b) 1.4 Digesters 1.2 Chiller 2.0 Total (a) Heat produced in water circulation system (b) Exhausted hot air Figure 6: Baseline Heat Production & Utilization Cost of Baseline Energy Purchases EWA purchases for electricity from SDG&E and natural Gas from DSG during the baseline 12 month period totaled $1,720,000. Details for each energy source purchase are provided in the following subsections Power EWA s monthly costs for power purchases from SDG&E during the baseline period are presented in Figure 7. The total cost during the baseline period was $1,063,000. The monthly charge for electricity averaged $88,600, ranging from $58,500 (January 2010) to $126,000 (June 2009). The average rate for purchased electricity ranged from $0.23 per kwh (April 2009 and February 2010) to $0.15 per kwh (September 2009), averaging $0.19 per kwh. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-8

60 The range in monthly costs is due to variations in flow rates and seasonal variations in aeration requirements. The variation in monthly rate is due to the time of day purchases. Unplanned purchases at peak time of day rates can occur due to equipment outages. Figure 7: Baseline Electricity Purchases Natural Gas EWA s monthly costs for natural gas purchases from DGS during the baseline period are presented in Figure 8. The average monthly natural gas charge was $54,700, ranging from $51,300 (May 2009) to $63,500 (January 2010). The 12 month total cost during the baseline period was $657,000. The average cost for natural gas was $0.77 per therm, ranging from $0.71 per therm (September 2009) to $0.84 per therm (January 2010). The variation in gas demand is largely due to solids dewatering performance and variations in price are due to market forces. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-9

61 Figure 8: Baseline Natural Gas Purchases Current Operations Energy Summary A summary of the energy profile at EWPCF during the 12 month baseline period (April 2009 through March 2010) is presented in Table 4. Table 4: Baseline Energy Profile Summary Electricity Gas Heat 1) kwhr/yr % Total therms % Total MMBtu/hr % Total Self 12,000,000 69% 1,250,000 64% Generation Purchased 5,500,000 31% 695,700 36% 0 0 Total 17,500,000 1,945, Usage Total Purchases $1,063,000 $657,000 $0 1) Listed heat values are limited to hot water produced by the IC engines. Utilization heat was 3.19 MMBtu/hr (47% of produced hot water) Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-10

62 2.4 Energy Demand and Production Projections This subsection develops a projection of energy utilization referred to as Business as usual for comparison with alternatives developed in this report. A business as usual production and demand model was developed utilizing the baseline usage parameters for flow, electrical power, natural gas, digester gas, and heat. The model divides the production and demand into flow dependent and non-flow dependent processes. The model was developed in this manner to properly account for energy usage projections recognizing certain processes within the parameters will increase as plant flows and loading increase (flow dependent), and energy usage for other EWPCF facilities will remain constant (non-flow dependent). The projections are modeled on a linear basis utilizing projected flow and solids loading increases through the year The projection in this section is based on current plant operation within the limits of the current SDAPCD synthetic minor permit and assumes no significant changes within the EWPCF process units, equipment, and operations EWPCF Wastewater and Solids Flow Projections Projected increases in flow and solids loading provided by EWA (see Table 5) are used to forecast electrical power and gas energy demands. Self generation capabilities and estimated commercial power purchases are also projected. The projected increase in wastewater flows and solids loading used in the analysis are presented graphically in Figures 9 and 10. Table 5: Flow Projections Year EWPCF Flow (MGD) Service Area Flow a) (MGD) Total Solids (dt/d) (1) Service area flow includes flow diverted at satellite plants with being returned to EWPCF through the regional sewer system. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-11

63 Figure 9: Projected Wastewater Flows Figure 10: Projected Solids Loading Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-12

64 2.4.2 Electrical Energy Production and Use Based on the analysis of existing energy usage, 75% of the power consumed at the plant is flow dependent increasing with flows and solids loading, while 25% is non-flow dependent remaining constant. Projected electrical energy self generation is based maximum IC engine operation allowed under the current SDAPCD permit and will remain constant through the year All increased power demand associated with the increased flows will be purchased from SDG&E. The total electrical power annual use is projected to increase from 17,500,000 kwh in 2010 to 27,915,000 kwh in The self generated portion will remain a constant 12,500,000 kwh; purchased electrical energy will therefore increase from 5,500,000 kwh in 2010 to 15,042,000 kwh in the year Figure 11 presents the projected self generation and SDG&E purchase graphically from 2010 to Figure 11: Projected Electrical Energy Production and Purchases Natural Gas Using the baseline natural gas demands discussed in Section 2.3, future demands were projected by determining which processes using natural gas are flow and non-flow dependent. The administration and maintenance buildings demand are not flow dependent and are assumed to remain constant. Under normal operating conditions, the IC engines are primarily fueled with biogas and a relatively small amount of natural gas is added. Biogas and natural gas are blended in the existing eclipse unit. The IC engine use will not increase beyond the current operating levels Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-13

65 due to the SDAPCD permit limitation; the use of natural gas in the IC engines is therefore held constant in the projections. The fuel requirements for the dryer and RTO is flow dependent and will increase as flow and solids loading increases. It is understood that as flows increase, new, larger equipment may be required to replace the existing equipment sized for certain flows, which could lead to more of a step-wise increase in fuel demand. However, for the purpose of the projection in this analysis, it is assumed that the natural gas demand of the equipment and processes increases at a linear rate. The dryer fuel demand will be met by providing a blend of natural gas and biogas. Natural gas is required to accommodate the RTO fuel demand. Over the baseline period, EWA staff was able to implement the proposed long term plan to maximize use of biogas in the dryer; the proposed plan is to eventually fuel the dryer with an 80%/20% blend of biogas and natural gas as a fuel source. The current volume of biogas does not allow the operators to achieve that goal. The business as usual model develops projected natural gas purchases through 2030 by assuming the IC engines will be fueled with biogas up to the SDAPCD permit limit and natural gas use in the dryer will be reduced as biogas production increases in response to flows and solids loadings increases. The RTO demand for natural gas (the only acceptable fuel source for this process unit) will increase as flows and solids loadings increase due to increased run time. Figure 12 provides a graphical presentation of projected natural gas requirements through the year The total natural gas demand will decrease as biogas production increases with increased flows and solids loading. In the year 2023, the 82%/18% maximum dryer fuel supply blend of biogas and natural gas will be reached and natural gas demands will be approximately 61% of current demands. Natural gas demand will increase gradually after 2023 as flows continue to increase. In the year 2030, the demand will be approximately 54% of current natural gas demand. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-14

66 Figure 12: Projected Natural Gas Demands Biogas Production Biogas gas production is forecast to increase at a proportional rate established from the projected increase in wastewater flows and solids loadings. Biogas will be used in the IC engines and dryer as noted in the previous subsection. The baseline business as usual condition assumes biogas will provide the entire IC engine demand with a relatively small blend of natural gas (less than 10% of the IC engine fuel supply will be provided by natural gas). Biogas production exceeding the IC engine demand will be blended with natural gas and serve as the dryer fuel supply. In the year 2023, the maximum blend of biogas and natural gas (82%/18%) fuel mixture for the dryer will be reached. Excess biogas not utilized will be flared. Incidental flaring of biogas is expected to occur prior to the year After approximately 2025, biogas flaring will be routinely required as gas production will exceed the IC engines and dryer demands. Figure 13 presents the business as usual projected biogas production and use. In the early years (2010 through 2011), the IC engine fuel demand could utilize of all biogas production. As flows increase, biogas production will enable EWA to accommodate the dryer fuel demand with a blend of biogas and natural gas. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-15

67 Figure 13: Biogas Production and Uses Figure 14 shows the quantities of biogas and natural gas required to meet the dryer demand. If the IC engines fuel demand is primarily met with biogas, the dryer would require 100% natural gas initially. Dryer biogas use would increase as flows increase and would reach the estimated maximum 82%/18% blend of biogas and natural gas in the approximate year Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-16

68 Figure 14: Dryer Gas Demands Heat Production Projected baseline heat production and usage through 2030 is as follows: IC engine heat production would remain constant due to SDAPCD emissions limitations Digester heat usage would increase due to increased solids loading The switchgear absorption equipment heat usage would remain constant and is not forecasted to increase Total wasted hot water heat would decrease RTO heat (in the form of hot air) would increase due to increased solids loading With a fixed quantity of usable heat (in the form of hot water) and an increasing demand, waste heat quantities will decrease. However, a relatively large quantity of heat wasting will continue to occur through 2030 Figure 15 shows the projected balance of produced and waste heat through The total quantity of produced heat is shown as a combination of digester and absorption chiller use and wasted heat from IC engines and RTO operations. The total quantity of heat production will increase from 6.8 MMBtu/hr in 2010 to 9.3 MMBtu/hr in All of the increase will occur in Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-17

69 the RTO unit (from 1.4 MMBtu/hr to 2.5 MMBtu/hr). Heat usage will increase from 3.2 MMBtu/hr to 3.9 MMBtu/hr with all of the increase occurring in the digesters. Figure 15: Projected Heat Production, Usage and Wasting 2.5 Power Demand, Gas Production and Waste Heat Forecast Table 6 provides a summary of projected energy demand and self generation for the Business as Usual baseline condition. The projections are provided graphically in Figure 16. Figure 16 presents energy data in a uniform energy unit (therms). The conversion of IC engine energy assumes 32.7% efficiency (gas fuel content to produced electricity). The conversion of heat energy use is based on a direct conversion from MMBtu/hr to therms. An explanation of the energy information presented in Figure 16 is provided below: Purchased Electricity: electrical energy purchased from SDG&E Biogas Generated Electricity: Self generated electrical power produced from biogas Dryer/RTO NG: Dryer and RTO fuel demand provided by purchased natural gas Buildings NG: Administration and maintenance buildings by purchased natural gas Dryer Biogas: Dryer fuel demand provided by biogas produced in digesters Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-18

70 Digesters & Existing Chiller: Digester and chiller heat demand provided by hot water produced by IC engines fueled by digester produced biogas Table 6: Projected Energy Demand and Production (Natural Units) Electricity Use/Self Generation Average Flow Total Plant Power Demand (Purchased + Gas Use/Self Generation Heat Use/Self Generation 1) Total Plant Gas Hot Water Use Hot Water Demand Wasting (Purchased + Produced) Produced) Year MGD kwh Therms MMbtu/hr MMBtu/hr ,500,000 1,945, ,659,000 1,980, ,951,000 2,270, ,916,000 2,570, ) RTO hot-air heat produced and wasted is not included Table 7: Projected Energy Demand and Production (Therms) Electricity Use/Self Generation Average Flow Total Plant Power Demand (Purchased + Gas Use/Self Generation Heat Use/Self Generation 1) Total Plant Gas Hot Water Use Hot Water Demand Wasting (Purchased + Produced) Produced) Year MGD therms therms Therms therms ,813,000 1,945, , , ,157,000 1,980, , , ,501,000 2,270, , , ,915,000 2,570, , ,000 1) RTO hot-air heat produced and wasted is not included Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-19

71 Figure 16: Business As Usual Energy Purchases and Self Generation 2.6 Summary and Findings This section analyzes existing EWPCF energy production and use and presents projected use through the years 2020 and The summary of this analysis is as follows: Electricity: Annual electrical power is currently 17,500,000 kwh and is projected to increase to 24,000,000 kwh in 2020 and 27,900,000 kwh in Gas: Total annual biogas and natural gas usage is currently 1,950,000 therms and is projected to increase to 2,300,000 therms in 2020 and 2,600,000 therms in Heat: Heat production is currently 6.8 MMBtu and is projected to remain relatively constant into 2020 and However, the amount of heat actually reused increases from 28,000 MM Btu to 32,400 in 2020 and 34,200 in Current and projected demand by energy type is presented in Figure 17. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-20

72 Figure 17: Current and Projected Energy Demand Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 2-21

73

74 Section 3: Energy Efficiency and Process Improvements 3.1 Introduction and Purpose The purpose of this section is to identify opportunities for energy demand reduction through equipment, process or procedural changes. These changes do not require major investment and could be characterized as low hanging fruit. Section 3 presents the approach and findings for the following tasks completed as a part of this study: Energy Audit: Audit existing electrical energy consuming equipment and lighting facilities. Identify potential energy efficiency measures and estimate potential energy savings Process Audit; Complete an audit of EWPCF process units, list potential process changes and develop estimated potential energy savings 3.2 Energy Audit A technical team provided by ECOS (a subconsultant retained by K/J) performed a 2-day walkthrough energy audit of the Encina Wastewater facility in December The audit consisted of a site visit by Mike Bailey, P.E. and Patti Boyd who evaluated major energy consuming equipment, their condition, and current operation. The audit focused on the major energy using equipment at EWPCF, as measured by peak power demand and frequency of operation. The details of the audit are presented in ECOS report provided in Appendix B. A summary of the major findings is presented in this section. EWPCF staff was interviewed and an inventory of energy usage was prepared. Kennedy/Jenks used the audit information to identify energy efficiency measures (EEM) that could be implemented to reduce energy usage and demand for power and natural gas. Incentives to help fund the EEMs were also identified. The findings of the Energy Audit are summarized below; a complete copy of the ECOS report is included in Appendix B. The audit included a review of EWA maintained electrical energy use spreadsheets and operator interviews. The audit considered electrical consuming equipment as follows: Motors Pumps VFD HVAC / cooling systems Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-1

75 Lighting Control Systems Cogeneration/process combustion The major facility systems reviewed during the site visit included: Activated Sludge Cogeneration Disinfection Effluent Pumping Headworks HVAC Lighting Plant Water Primary Clarifiers Return Activated Sludge Pumps Secondary Clarifiers Solids Dewatering Solids Digestion Sludge Thickener Waste Activated Sludge Pumps Baseline Energy Consumption A summary of power consumption by processes and areas within EWPCF is provided in Table 7. The data was obtained from monthly plant power consumption spreadsheets that are used to record individual equipment motor operating hours generally divided into control center (MCC) units. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-2

76 The data provided in Table 8 was developed from EWA data recorded over the January through December 2010 operating period. During this period, all of the modified process units and newly installed Phase V improvements were operating in a stable mode, including the new dryer system. The total energy consumption during this period is nearly indentical to the baseline period utilized in the previous section (the April 2009 through March 2010 operating period) and use of this data is judged to be an accurate method of identifying energy utilized within each plant area during baseline conditions. Flow rates during the two periods are nearly identical further supporting the use of the data to establish specific area baseline conditions. Table 8: Baseline Electrical Energy Consumption By Area MCC Annual kwh Percentage - CEPT System 9, % G & F Screenings 875, % K, L, N, P & R Power Building (Blowers) 8,395, % 3 Centrifuge Feed Pit 479, % H Dewatering 2,015, % 2 Centrifuge pumps, screw conveyor, 1,025, % ventilation - Andritz Dryer Facilities 1,846, % B & C Secondary Building 1,435, % D & E Effluent Pump Station 1,581, % CPS Combine Pump Station 14, % N/A Operations 0 0.0% Total 17,674, % Energy recorded within the power building and listed in Table 7 includes numerous equipment and process units including the six (6) blowers used to provide air for aeration basins and agitation air. During the baseline period, the energy use recorded for the 6 blowers was 6,110,000 kwh, 35% of the total annual EWPCF electrical energy demand. ECOS estimated the total lighting demand to be 445,000 kwh (see table 9, ECOS report, Appendix B), 3% of the total annual electrical demand Energy Efficiency Measures The results of the audit provided a baseline energy usage that was compared to potential electrical energy efficiency measures (EEM) identified by the audit team. Several EEM s were identified and preliminary cost estimates and estimated energy savings developed for each. For each measure, the audit team identified potential incentives provided by the local utility (SDG&E) to help offset some of the installation costs. The utility incentives were included in the estimated financial payback period calculations. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-3

77 The audit team identified the following efficiency measures as having financial merit for implementation. Aeration and Agitation Blower System EEM 1: Eliminate leaks in supply pipe or move blowers adjacent to the basins. EEM 2: Cease operation of the aeration/agitation blowers for demand response. EEM 3: Retrofit existing blower throttle control with VFD control (see Table 3, ECOS report) EEM 4: As an alternative to EEM 3, replace multi-stage centrifugal compressors with new, turbo blower technology (see table 4, ECOS report) Variable Frequency Drives (VFD) EEM 5: Retrofit Plant Water 3WHP pumps with VFD control (see Table 5, ECOS report) EEM 6: Retrofit other Plant Water pumps with VFD control (see Table 6, ECOS report) EEM 7: Retrofit HVAC Fans with VSD control (see Table 7, ECOS report) EEM 8: Retrofit Solids Digestion mixing pumps with VFD control (see Table 8, ECOS report) Lighting and Sensors EEM 9: Install occupancy sensors for the lighting in rooms housing the motor control centers and continue upgrading existing lighting with more efficient fixtures (see page 19, ECOS report) An explanation of EEM details is as follows: EEM 1 energy savings would occur by eliminating air leaking in the underground portion of the secondary aeration basins air supply pipeline. The aeration system blowers are operating at a rate greater than required to meet the secondary process aeration demand. EEM 2 energy savings would occur if aeration could be reduced during high energy rate periods. This measure assumes sufficient oxygen can be transferred to the activated sludge process immediately prior to the reduced aeration period. EEM 3 and EEM 4 are alternative blower improvement upgrades and both have the potential to reduce energy consumption. Only one of these two EEM s would be implemented. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-4

78 VFD refers to variable frequency drives for selected electrical motors. The use of VFD units is intended to take advantage of lower power consumption made possible when the frequency can be varied to change motor speeds compared to other types of variable speed units or operating motors at constant speeds greater than required to meet the process needs. The audit team identified an additional potential energy saving opportunity recommended to be considered at a future data. The team noted there are two (2) 40 hp Kaeser air compressors running about 40% of the time and, after a more detailed study is competed, replacing the units with smaller horsepower motors outfitted with VFD drives may result in reduced energy demand. The potential savings are much smaller than the identified EEMs and further analysis is not recommended now at a part of this study. The audit team also noted SDG&E may be available to provide an audit of the compressor system at no cost to EWA. The recommendation is referenced as REC 1 listed as follows: Service Air System REC 1: Perform a compressed air system audit to determine if a smaller air compressor with VFD control can provide adequate flow for the existing system while using less power. Table 9 provides a summary of the estimated energy savings and the possible incentives available for the proposed EEMs 1 through 9. A summary of potential EEM benefits are as follows: Energy savings range from a low of 76,000 kwh per year for occupancy sensors to control lighting (EEM 9) to a high of 2,000,000 kwh per year with the replacement of existing multistage blowers with centrifugal compressors (EEM 4). These potential savings would reduce current electrical annual energy use of 17,500,000 kw. Estimated simple pay back periods range from less than one year (EEM s 3, 5, 6 7 and 8) to over 20 years (EEM 1 repair of leaking aeration piping). Installation of VFD drive units on current constant speed motors is the primary means of reducing energy in 5 EEM s (3, 5, 6, 7 and 8); if the estimated savings are correct and each are implemented, the annual reduction in energy use could be over 2,000,000 kwh year). Estimated incentives from SDG&E available for each EEM are as shown in Table 9. The annual power usage is approximately 17.4 million kwh as presented in Section 2. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-5

79 3.2.3 Efficiency Measures Summary The nine (9) EEM s offer EWA the opportunity to reduce energy demand within existing EWPCF processes and equipment. Each measure will require refinement of the estimated savings, a decision on which to implement, budgeting and implementation. For the purpose of identifying a conservative estimate of the identified energy efficiency measures, this study uses an estimated savings potential of 2,000,000 kwh annual savings. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-6

80 Table 8: Estimated SDG&E Incentives, Energy Savings, and Simple Payback Incentives per SDG&E s Standard Performance $0.09 per kwh Motors/other $100 per peak kwh Utility Incentive SDG&E Industrial Rate Contract Program $0.05 per kwh Lighting kw (Demand) Savings Simple EEM No. Description Measure Cost kwh Savings Payback Annual Avoided Current New Annual Annual Estimated Peak Estimated Net Cost ($) After Current New Cost Usage kwh kwh Incentive savings Incentive Incentives peak kw Peak kw kwh Consumption savings ($) kw ($) (years) Cease operation of the 2 aeration/agitation blowers $0 6,110,000 6,110,000 0 $ $82,000 $0 $0 demand response 5 Retrofit Plant Water 3 WHP pumps with VFD control $ 34, , , ,000 $35, $4,500 - $1,600 $75, Retrofit HVAC Fans with VFD control $ 100,000 1,650, , ,000 $75, $10,000 $24,800 $158, Reftrofit Solids Digestion pump with VFD control $115,000 1,500, , ,000 $67, $8,500 $47,500 $142, Retrofit other Plant Water pumps with VFD control $ 73, , , ,000 $33, $4,500 $39,200 $71, Retrofit existing aeration air blower throttle control with $ 395,000 6,110,000 4,570,000 1,540,000 $138, $24,000 $256,400 $292, VFD control 4 Replace multi-stage centrifugal compressors with $1,235,000 6,110,000 4,110,000 2,000,000 $180, $29,000 $1,055,000 $380, new, turbo blower technology 9 Install occupancy sensors for the lighting in the motor control center rooms and continue upgreading existing $52, , ,000 76,000 $3, $300 $48,200 $14, lighting with more efficient fixtures 1 Repair leaks in air supply pipe or move blowers adjacent to the basins (assume 10% savings, assume piping fix is $3 M) $3,000,000 6,110,000 5,499, ,000 $55, $8,000 $2,945,000 $116, ) Incentives available from SDG&E are as noted for each energy use type Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-7

81 3.3 Process Audit A process audit was completed with the purpose of identifying opportunities to improve energy efficiency at the EWPCF by modifying one or more of the process facilities. EWA operating staff members were interviewed and the operation of various treatment processes was observed. In addition, process and energy usage data files were reviewed. The staff does a commendable job of optimizing energy use by operating high energy consuming equipment outside the peak electrical demand time. Based on the energy optimization strategies employed by EWA staff, the focus of the energy process audit was directed to finding additional opportunities to reduce energy consumption and associated costs. Several process improvements were identified and specific improvements that could be completed without further study have been identified along with other possible improvements that require further study prior to adoption. Five major and five minor improvements were identified. Simple cost benefit analyses of these improvements are presented in Section Energy Use During On Peak Periods The staff does an excellent job of mitigating energy use during on peak times. The flow equalization basin also reduces the impact of hydraulic and organic peak loading on the plant. There was no observed energy saving related to the operations of equipment/processes during peak periods Individual Process Unit Review and Observations Headworks Consideration should be given to removing one grit unit from service. One unit has the capacity of 30 mgd which about matches the daily peak hour. Staff can run total volatile solids on grit system effluent before and after removing a unit to see if one grit unit can handle the flow. An indication that one unit is insufficient would be a noticeable reduction in grit hauled to the landfill. Taking a grit unit offline would save EWA approximately $6,000 per year in electricity charges. One of the largest potential energy saving recommendations in the head works area involves modification of the headworks exhaust fan. This 100 HP motor/fan runs 24 hours per day. Reducing run-time by 50% or re-gearing to reduce fan speed and air changes could result in electrical savings of approximately $55,000 per year. Prior to implementing this concept, an analysis of airflow change rates for compliance with code requirements and potential impacts to corrosion should be completed Primary Treatment The primary sludge ph is consistently around 5.5. The ferric addition is probably partly responsible for the lower ph. However, it is believed that the primary sludge withdrawal rate Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-8

82 may be too slow. If the sludge removal rate is too low, the sludge can ferment and create organic acids. This would account for the lower ph. The fermentation process can result in the liquefying of solids and slightly higher loading on the aeration basin. The organic acids are also a food source for filamentous bacteria which contribute to settling problems as well as foaming in the aeration tanks and digesters. It is suggested that the pumping rate be increased and staff monitor sludge ph, primary effluent Biochemical Oxygen Demand (BOD) and Total Suspended Solids (TSS) to see if increased primary sludge pumping beneficially impacts performance Aeration System At times the conditions at the facility promote the growth of filamentous bacteria. The addition of a selector to the activated sludge system would enable staff to improve control of filaments without the use of chlorine. Since the plant routinely partially nitrifies (10-15 mg/l nitrate is not uncommon in the effluent), an anoxic or anaerobic selector would allow the oxygen combined with the nitrate (NO3) to be used for BOD removal reducing the overall oxygen demand. In addition, reducing the nitrate would decrease the risk of denitrification in the secondary clarifier. A little denitrification shining was observed in the secondary clarifier during the plant visit. Denitrification would also restore some of the alkalinity used up during nitrification. The configuration of the aeration basin allows for a propeller pump between the walls separating the influent and discharge zones of the aeration basins to bring the nitrate created back into a selector zone that would be established at the influent end of the aeration basin. Turning this propeller pump on and off would allow the selector to be operated as an anoxic or anaerobic selector depending on filament and nitrate considerations. It is suggested that implementation of a selector be investigated in more detail. Note that the basins are currently operating in a pseudo anaerobic selector mode by starving the upstream aeration zone of air. Some benefits are already being achieved from this operating procedure. Figure 18 provides a conceptual aeration basin selector layout. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-9

83 Add propeller pumps through AB walls Add selector walls Add static mixers Selector- can be either anaerobic or anoxic Figure 18: Aeration Basin Selector Layout Savings may also result from reducing the facility s sludge yield. Reducing the sludge yield from its current average of around 0.8 by just 10-20% could result in considerably less secondary sludge to process. Less secondary sludge would ultimately result in lower solids loading to the anaerobic digester reducing solids handling costs through subsequent process units. The savings would also come from reduced polymer use and the potential to take one of the Dissolved Air Flotation Thickeners (DAFT) units off-line. The best way to estimate the savings is to lower the sludge yield and measure the reduction in energy across affected systems. The most convenient way to reduce the sludge yield or reduce the variability is to increase the Mixed Liquor Suspended Solids (MLSS). It is recommended that the MLSS be slowly increased to see if the sludge yield performance is improved without adding blower energy or creating nitrate problems. Computer modeling of the secondary system can illuminate potential savings. Models such as Biowin or GPS-X allow manipulation of Solids Retention Time (SRT) and Dissolved Oxygen (DO) to determine lowest DO set points and sludge yield. It also helps optimize Return Activated Aludge (RAS) rates to keep rate as low as possible and maximize Waste Activated Sludge (WAS) concentration. A calibrated model may be beneficial and something for EWA to consider Secondary Clarifiers Clarifier modeling indicates that the plant could operate with fewer secondary clarifiers and associated RAS pumps. The modeling suggests the plant could reduce the number of clarifiers from the current 4 down to 2 without impacting performance. It is recommended that the staff take one clarifier off-line and evaluate the impact on performance. If effluent quality does not suffer then take another clarifier off line and re-evaluate. The energy cost savings associated with each clarifier and RAS pump is about $27,000 per year. Table 10 below shows the design information for just two clarifiers in service with high sludge volume index (SVI) and influent flow. A photo of one existing clarifier is provided in Figure 19. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-10

84 Table 9: Clarifiers Online High SVI and Flow SVISN 200 ml/g Total Clarifier Surface Area 17,310 ft 2 MLSS Concentration 1,000 mg/l Influent Flow 35 mgd Surface Overflow Rate 2,022 gal/ft 2 d RAS Flow 6 mgd Applied Solids Loading* lbft 2 d RAS SS Concentration* 6,833 mg/l Reducing the RAS rate from the current 45% to 30% would also result in reduced secondary WAS volume. In fact, the modeling shows that the RAS rate could be reduced enough to double the concentration of RAS/WAS sludge. This means that the plant would produce half the volume of waste sludge. Couple this with the potential reduction from improved sludge yield and the savings associated with solids handling could be significant. The specific savings cannot be determined at this time. Figure 19: Secondary Clarifier Photo Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-11

85 It would be beneficial for staff to have a nitrate probe installed on the secondary clarifier effluent to provide them with information useful in estimating the oxidative state of the mixed liquor suspended solids (MLSS) as well as the denitrification risk. When the nitrate reads high it could be used as a trigger to turn down the aeration system air possibly saving energy Diffused Air Flotation System Plant staff is credited for the idea of shedding energy associated with the diffused air flotation (DAFT) units during peak energy cost periods (that 4-6 hour period each day). Manually shutting down the DAFT units and support equipment during this period could save EWA an estimated $15,000 per year and not impact DAFT performance Internal Combustion Engine Cooling Water Pumping EWA currently pumps around 1,000 gpm to the four existing internal combustion engines (IC Engines) for cooling. This pumping energy equates to about $30,500 per year. It was mentioned by EWA operating staff that this flow may need to be increased to 2,000 gpm. The existing IC engine system is included in the alternatives analysis provided in this report. The analysis considers ways in which to increase utilization of the hot water system. The opportunity to optimize the hot water system (including reduced hot water pumping costs) will be included in the recommended energy optimization plan Odor Tower Water Pump (3WL) The odor tower water pump discharges 800 gpm while the SDAPCD operating permit requires only 450 gpm. It may be possible to change the pump impeller size (at a lower capital cost than installing a variable frequency drive) to reduce the energy required to operate this motor. Replacing the pump and motor with may provide an even greater energy savings considering the higher efficiency associated with a smaller pump sized for the lower flow rate. A simplified approach to estimating energy savings based on a direct relationship between flow and energy consumption indicates a potential 38% energy demand reduction, a potential savings of approximately $15,000 per year Digester Re-circulation Pumps There are two 40 HP pumps pumping sludge through the heat exchangers. Shutting off these pumps during the peak electrical charge period (4 hours/day) could save approximately $14,500 per year. The staff would most likely have to coordinate this with thickened waste activated sludge (TWAS) and primary sludge pumping. There appears to be sufficient opportunity to save energy thereby justifying the additional analysis EWA Operations Staff Interview Information Flow Equalization Basin The flow equalization basin (EQ basin) could be acting as a fermentation chamber. If the wastewater is held long enough in a low DO environment, the water could ferment creating Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-12

86 organic acids that could contribute to filament growth. It is recommended that a DO meter be installed in the EQ basin to enable staff to monitor environmental conditions in the basin Headworks The facility currently operates two bar screens (photo provided in Figure 20). Taking one bar screen offline will save approximately $400 per year in power cost as well as reduce labor and maintenance costs. With reduced run-time there is potential for increased equipment life. The second bar screen is not needed with current flows. It may be possible to adjust the timers on the bar screen remaining in service to reduce unnecessary runs. With differential level control as a backup to the timer there is little risk of plugging the screen. Reduced run-time will slightly reduce power and maintenance expenses. Figure 20: Headworks Photo Chemical Use Review The chemical dose to some odor control units was slightly above permit requirement. A lower dose may still provide sufficient odor control. However, the chemical and energy savings associated with lower dosing would be minimal. Addition of a biological selector and/or EQ basin optimization could reduce filament predominance and eliminate the need for RAS chlorination. Ferric dosage to the primary clarifiers may be higher than needed for odor control (based on low primary sludge ph). Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-13

87 3.3.5 Process Changes Analysis Screenings Hopper Staff currently has to handle the screening material many times per day. They pull the small interior screenings hopper out of the building and dump it into a larger exterior dumpster. This handling increases injury risk to staff and is labor intensive. It is estimated that about $5,000 per year in labor is used for this task. EWA should investigate modifying the screenings area to accommodate the larger dumpster. A photo of the hopper facilities is provided in Figure 21. Figure 21: Screenings Hopper Primary Clarifier Covers Some of the primary clarifiers have well maintained and functional aluminum covers. Others are semi-covered by fiberglass hut-type covers that are ineffective in odor containment and controlling vector attraction. Occasionally, these older covers sometimes end up in the primary clarifier. There is an increased safety risk to staff while engaged in fishing these out and repositioning. Improved primary covers may allow the ferric feed to be reduced saving both energy and chemical. Figure 22 includes a photo of the existing primary clarifier covers. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-14

88 Figure 22: Primary Basin Covers Stamford Baffles Stamford baffles have been shown to reduce secondary clarifier effluent TSS up to 35%. These relatively inexpensive fasten to the side wall of the clarifiers and reduce the up flow energy (density current) found near the weir. Consideration should be given to adding Stamford baffles to all the secondary clarifiers. Figure 23 provides a photo of Stamford baffles in a circular clarifier similar to the EWA clarifiers. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-15

89 Figure 23: Stamford Baffle Photo Operations Manual The current plant operations manual is out of date. Updating the manual would ensure staff are following the recommended guidelines for equipment start-up, operation, and control Potential Improvements Tables 11 and 12 provide summaries of potential process revisions that could reduce energy consumption. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-16

90 Table 11: Major Improvements Greater than $10,000 investment Recommended No. Action 1 Selector engineering study 2 Slow RAS rate down from 45% to 35% 3 Decrease Sludge Yield Increase MLSS from 1000 to 1200mg/L 4 Update Operations Manual 5 Modify screen room to allow hopper to be inside and cover all primary clarifiers with aluminum covers Expected Benefit Improved filament control. Reduce risk of denitrification Some possible reduction in overall oxygen requirements. Less sludge being produced. Less loading /poly to thickeners. Less RAS Pump Energy; less polymer Lower energy cost and sludge volume to handle Update to provide current operation procedures and training for new operators to replace those that will retire soon Improve safety and labor effectiveness Estimated Cost to implement ($1,000) $50 study, $1,200 construction Estimated Annual Cost Benefit ($1,000) Estimated time to Implement $200 6 months $60 study $250 6 months $60 study months $250 n/a 12 months $200 $200 will save at least this if no injury occurs Total $ months Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-17

91 Table 12: Minor Improvements Less than $10,000 investment Estimated Annual Cost Benefit No. Recommended Action Expected Benefit Estimated Cost to implement ($1,000) ($1,000) Estimated time to Implement (months) 1 Reduce exhaust flow rates in Lower energy cost $5 $55 <1.0 headworks building 2 Remove secondary clarifier Lower energy costs, N/A - labor $53 <1.0 from service; run on three vs. O&M costs cost built in four; then take another offline 3 Take DAFT offline during Lower energy costs, N/A - labor $15 <1.0 peak energy time O&M costs cost built in $15 <1.0 4 Take Digester mixing pumps offline during peak energy time 5 Remove one grit system from service and operate on one 3.4 Summary Lower energy costs, O&M costs Lower energy costs, O&M costs N/A - labor cost built in N/A - labor $6 <1.0 cost built in Total $144 <5.0 An EWPCF energy demand profile (by major process area) was developed along with potential energy efficiency measures (EEM) that could reduce electrical energy demand. A process audit was also completed that concluded with a list of potential energy savings process concepts. The analysis and results presented in Section 3 include the following: The baseline annual energy demand was 17,700,000 kwh. Blowers operating to provide air for aeration basins and agitation air require the most electrical energy (6,110,000 kwh, 35% of total demand) Dewatering, secondary treatment support facilities, the new dryer and effluent pumping facilities require similar quantities of electrical energy as follows: Dewatering (2,015,000 kwh 11%) New Dryer (1,846,000 kwh 10.4%) Secondary support Facilities (1,435,000 kwh 8.1%) Effluent Pumping (1,581, %) Nine (9) EEM s where identified ranging in annual electrical demands savings from 76,000 kwh to 2,000,000 kwh. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-18

92 The recommended EEM target of electrical demand savings is 2,000,000 kwh, 12% of the baseline demand. Potential process changes were grouped into two projects groups; major projects (greater than $10,000 cost) and minor projects (les than $10,000). Potential savings from these process changes is significant but each requires further evaluation. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 3-19

93 Section 4: Technology Evaluations Alternative Power Production 4.1 Introduction and Purpose, Technology Evaluations Technologies considered in the development of a recommended Energy and Emissions Strategic Plan update are presented and evaluated in report Sections 4, 5 and 6. This introductory section identifies the scope of evaluation of all technologies in Sections 4, 5 and 6, grouped into the following categories: Section 4 Alternative Power Internal Combustion Engines Fuel Cell Solar photovoltaic Small wind Microturbines Section 5 Biogas Production Biogas Enhancements o Waste to energy (WTE) o o Cell Lysis Digester Train Enhancements Other Support Facilities o Biogas treatment o o Sludge heating Biogas storage Section 6 Waste Heat Absorption and adsorption chillers Power generation Steam turbines Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-1

94 Gasification of biosolids The purpose of the technical evaluations is to provide technical, performance, cost and environmental information used to identify selected technologies and develop alternative project scenarios consisting of one or more of the technologies that would enable EWA to meet business plan energy goals. 4.2 Introduction and Purpose, Alternative Power Production In this section, alternative power technologies are indentified and evaluated for consideration in the development of the Updated Energy and Emissions Strategic Plan. Each technology would enable EWA to produce electrical energy offsetting SDG&E purchased electricity. Information presented for each alternative power technology serves as a basis for development of project scenarios in a subsequent section that considers the combination of one or more technologies that would enable EWA to achieve self generation goals included in the adopted Business Plan. 4.3 Internal Combustion Engines Introduction Wastewater treatment plants (WWTP) have a source of renewable energy from anaerobic digestion - digester gas. Traditionally, digester gas has been used in boilers to provide heat back to the digester and for heating of buildings. Often, excess digester gas is flared. However, digester gas may also be used to produce electricity in addition to heat. The most efficient way to utilize the energy in the digester gas is through a cogeneration system. Cogeneration is the simultaneous production of electricity and heat, both of which are used in the WWTP. This assessment provides an overview of the use of internal combustion (IC) engines at EWPCF. Cogeneration has been used at EWPCF since For EWPCF, this source of electrical power allows EWA to avoid purchasing electricity at peak daily electricity rates. The engine generators also provide emergency standby power as required by the EWA National Pollution Discharge Elimination System (NPDES) permit History Internal combustion (IC) engines were first experimented with as far back as the late 1600 s. However, it wasn t until the late 1800 s that effective internal combustion engines were built, and their use became much more common. Different engine designs have different applications. IC engines are used for automobiles, trucks, construction and mining equipment, marine propulsion, lawn care, and power generation. Typically, for cogeneration applications, four cycle turbocharged and intercooled reciprocating engines have been used. Digester gas has been used as fuel for internal combustion engines for over 50 years. IC engines are normally used for sizes from 20 to 5,000 kw. Electricity conversion efficiency ranges from 25 to 35 percent. The overall efficiency ranges from 70 to 90 percent. Reciprocating engines are Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-2

95 popular for cogeneration because there are many successful installations of this type, the equipment is well understood, and they perform well and are reliable when properly maintained Technical Description In an internal combustion engine, fuel and air is combusted in a combustion chamber. This reaction creates gases at high temperature and pressure, which expand. The expanding gases move parts of the engine, such as a piston, to perform work. The IC engines typically used for cogeneration use a four-stroke spark ignition system. A single cycle of operation (intake, compression, power, and exhaust) is completed over four strokes of a piston. During the intake stroke, the intake valve opens and the descending piston draws the air-fuel mixture into the cylinder. During the compression stroke, the intake valve closes and the piston moves up, compressing the air-fuel mixture at the top of the cylinder. The ratio of the volume of the cylinder when the piston is at the bottom to the volume when the piston is at the top is called the compression ratio. Higher compression ratios result it more powerful and efficient engines. However, higher compression ratios typically are not compatible with air pollution devices often required for this type of equipment. The next stroke of the cycle is the power stroke, where the spark plug fires and ignites the air-fuel mixture. Combustion of this mixture creates hot gases that expand, forcing the piston down. This is what gives the engine its power. The final stroke in the cycle is the exhaust stroke. During the exhaust stroke, the exhaust valve opens, the combustion products -- mainly carbon dioxide, carbon monoxide, nitrogen oxides, and unburned fuel -- are forced out of the cylinder, the piston moves back up again, and the four stroke cycle is repeated. A diagram of the four stroke cycle is shown below in Figure 24. Figure 24: Four Stroke Cycle IC engines are sensitive to some of the impurities typically contained in digester gas. These impurities include hydrogen sulfide, siloxanes, particulate matter, moisture, and other compounds, and engine manufacturers typically recommend these be removed or reduced before use in the engine. These constituents can cause, or form products that cause, accelerated wear on the engine. Gas clean-up usually includes dehydration and filtration, and can require sulfur removal if gas sulfur levels are high. If siloxanes are not removed, more Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-3

96 frequent maintenance may be necessary; however, the cost of equipment to remove siloxane from the gas can be high. In an IC engine cogeneration system, heat can be recovered from the exhaust, the jacket water, and to a lesser extent the engine oil. This allows for fairly high overall efficiencies for these systems Vendors There are several companies that manufacture IC engines in the size range suitable for EWPCF. The primary manufacturers of IC engines for cogeneration are Waukesha, Caterpillar, Jenbacher and Deutz Size and kw Production Current and projected electricity and heat production is presented in Section 2. The following discussion provides additional details related to IC engine operations. Biogas produced in two operating digesters is utilized as a fuel in the cogeneration system producing electrical power and heat in the form of hot water. Biogas is blended with a small quantity of natural gas to operate IC engines producing electricity. Heat produced by the IC engines is utilized in the digesters and an absorption chiller serving the energy building. Current and projected digester gas production is shown in Table 13. Table 13: Current and Projected Digester Gas Production Year Flow Rate (mgd) Digester Gas Production (therms/yr) ,250, ,566, ,883, ,265,000 EWA currently operates four Caterpillar G kw IC engines. This type of engine is also available from Caterpillar in a 1,400 kw model. The operation of the IC engines is limited by the SDAPCD permit as noted previously. This limitation (in accordance with the May, 2010 amended permit) allows EWA to utilize up to 224 million cubic feet per year (MMCF/Yr) of biogas and natural gas in the four existing IC engines; natural gas use is allowed up to 10% of the total gas volume. This restriction results in two engines operating at full load for a total of 39 hours of the available 48 hours per day under this limitation (approximately 2.0 engine equivalents over a 12 month period). Current and projected electricity produced by IC engines is shown in Table 14 and compared to EWPCF total electricity demand through IC engine electricity production is limited to a Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-4

97 maximum of 12.5 million kwh/yr through 2030 due to current SDAPCD permit limitations. Required purchases of electricity from SDG&E would increase from 5.4 million kwh/yr to over 15.0 million kwh/yr. The projected self generation would increase as noted in Table 14 from current levels as biogas production increases up to the maximum limitation. The electricity produced by IC engines cannot exceed 12.5 million kwh/yr due to the current SDAPCD limitation. As developed in a subsequent subsection, the restrictions could be removed by installing gas treatment and exhaust catalysts. Significantly higher electricity could then be produced onsite. Table 14: Current and Projected Electricity Production Year Total Electricity Demand (kwh/yr) Existing IC Engine Production (kwh/yr) Required SDG&E Purchase (kwh/yr) ,500,000 12,000,000 5,500, ,659,000 12,500,000 7,786, ,950,000 12,500,000 11,077, ,915,000 12,500,000 15,042,000 The current and projected combined heat demand is provided in Section 2 and repeated in Table 15 below for the period 2010 through The chiller heat demand is not projected to change in Table 15. The digester heat demand would change as wastewater flows increase. The heat demand increases from the baseline condition of 3.25 MMBtu/hr (million British thermal units per hour) to 3.91 MMBtu/hr a 20 percent increase solely as the result of increasing digester demand. As shown in Table 15, excess heat would be produced through the year 2030 even if IC engine operation continues to be restricted by SDAPCD permit limits. Table 15: Heat Production, Use and Wasting Year Plant Flow Chiller Heat Demand Digester Heat Demand Hot Water Waste Heat MGD MMBtu/hr MMBtu/hr MMBtu/hr Gas Blending System Blending provides EWA with the ability to utilize biogas and natural gas simultaneously as a fuel source for the IC engines. Using natural gas as a supplemental fuel, self generation of electricity could be increased beyond the amount possible with biogas alone. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-5

98 If SDAPCD permit limitations are addressed either by obtaining a new permit that increases current limits or installation of gas treatment and catalysts enabling compliance with current emissions limits, biogas and natural gas could be used to increase onsite electricity production. EWA retains one of the four existing IC engines as a standby unit; the maximum electricity production capacity is that which could be provided by operating three engines up to their maximum operating condition. The maximum annual production of electricity for each engine is estimated to be 5,979,000 kwh/yr with an operating efficiency of 91% (9% non-operating period allowing for maintenance). Operating three engines full-time would provide 17,937,000 kwh/yr. Table 16 provides a summary of total EWPCF electricity demand, on-site electricity generation, required purchases and percentage of self generation through 2030 with maximum operation of three IC engines. As noted above, this is based on modified SDAPCD permit conditions or with the installation of emissions reducing catalyst on each engine. Table 16: Gas Blending System On-Site Electricity Production (Three Engines) Year Plant Electrical Demand On-Site Electricity Production Purchased Electricity Percent of On- Site Electricity Produced kwh kwh kwh % ,500,000 17,500, % ,659,000 17,937,000 2,722,000 87% ,950,000 17,937,000 6,014,000 75% ,916,000 17,937,000 9,978,000 64% Presently, the cost of producing electrical power with natural gas ($1.40 per therm) exceeds the cost of purchasing off-peak electricity ($1.15 per therm). This reduces the advantage of utilizing fuel blending. For that reason, fuel blending is not considered a viable technology to EWPCF at this time Waste to Energy Implications Waste to Energy (WTE) systems involve adding food waste and grease to the digesters to increase the production of digester gas as developed in Section 4. Implementing WTE would increase biogas production that could be utilized in the IC engines (assuming a revised SDAPCD permit is obtained or emissions reducing catalysts are installed) thereby increasing self generation of electricity Emissions Reduction Catalyst The operations of IC engines at EWA are currently limited by the amount of carbon monoxide (CO) emitted during operation as note previously. Engine CO emissions would be reduced by installing exhaust catalysts. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-6

99 Lean burn IC engines, such as the installed CAT G3516 can be equipped with either an oxidation catalyst which reduces CO emissions, or a selective catalytic reduction (SCR) catalyst which reduces NOx emissions or a combination of the two technologies. A catalyst is a substance which promotes certain reactions but is not one of the original reactants or final products. An oxidation catalyst utilizes platinum group metals (platinum, palladium, and rhodium are commonly used) in a monolithic honeycomb made from ceramics or stainless steel. Exhaust passes through the catalyst and contacts the platinum where CO is converted to CO 2. SCR uses a reductant, such as urea, and a catalyst to produce N 2 and H 2 O from nitrogen oxides (NO x ). One manufacturer, Clean Air Systems, offers a system which incorporates an SCR catalyst, an oxidation converter, and a critical or super-critical sound attenuation. This system, available through Hawthorne Power Systems claims to reduce CO and NOx by up to 88% and 75% respectively. Adding this system to the IC engines may reduce CO and NOx levels enough to allow three engines to operate all of the time within the current permit levels. The catalyst may be added to the existing oxidation catalyst/silence housing. The exhaust system may need to be modified to accommodate an increase in backpressure to prevent damage to the IC engines. The primary concern with adding any sort of emission control is that digester gas normally contains siloxanes and other contaminants which can poison a catalyst, sometimes in a matter of days or hours. In order to use digester gas with a catalyst, moisture, siloxanes, H 2 S, and any other contaminants in the gas stream would need to be removed, through a clean-up skid, so that they do not harm the catalyst. For this reason, gas treatment will be considered with catalysts as a package. No conditioning is required for pipeline natural gas as it does not contain contaminants. Adding the catalyst system would allow three engines to operate all of the time under the current permit as presented in the previous subsection. Table 17 gives the estimated emissions reduction from the Clean Air catalyst. Table 17: Estimated Emissions Reduction from Clean Air Catalyst Current Emissions After Treatment Percent Reduction Pollutant g/bhp-hr g/bhp-hr % NOx % CO % The estimated cost for catalyst equipment is $340,000 for all four engines not including installation, a urea tank, and air system. Periodically adding urea is the only on-going maintenance item, but the catalyst components require replacement approximately every 3 years Biogas Treatment Biogas treatment is a relatively new addition to wastewater treatment plant cogeneration systems. Gas from anaerobic digesters has been used to power equipment for many years Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-7

100 without provisions for gas treatment. Biogas normally contains mainly CH 4 and CO 2. It also normally contains traces of H 2 S, water vapor, siloxanes, and other volatile organic compounds. A majority of the cases requiring gas conditioning have involved siloxanes Description Siloxanes are a family of man-made organic compounds that contain silicon, oxygen, and methyl groups. These chemicals are used in the production of personal hygiene, cosmetics, health care, and industrial products. Use of these chemicals has increased over time. These chemicals are found in wastewater and volatilize in the digesters, entering the digester gas stream. When these gases are combusted to generate power, siloxanes are converted to silicon dioxide (SiO 2 ), which can deposit in the combustion and exhaust stages of the equipment as well as foul any emission reduction catalyst. Most generation equipment manufacturers have a maximum limit for siloxanes in the digester gas, above which treatment is required. Treatment is always recommended for engines with exhaust catalysts. Figure 25 provides a schematic for a typical scrubber system. H2S Scrubbers Gas Blower Reheater Siloxane Filters Dryer Siloxane Filters To Engine Generators Figure 25: Biogas Scrubber Unit Schematic Gas treatment systems typically consist of H 2 S, siloxane, and moisture removal. H 2 S is removed using an iron sponge which absorbs the H 2 S. The moisture is removed using a refrigerated dryer which chills the gas using refrigerant. The resulting moisture is drained to a plant drain. The gas then passes through activated carbon siloxane filters, which adsorb the siloxane molecules. Gas treatment systems require periodic maintenance, which can be performed by the equipment supplier. Care must be taken when removing the iron sponge media. The iron sponge media can become pyrophoric and must be allowed to stabilize (oxidize) prior to disposal. The media is removed from the vessels and spread 2-3 inches deep and allowed to absorb oxygen for several days. After oxidation the material may be disposed of as nonhazardous material. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-8

101 A detailed gas analysis conducted at two separate times and covering all siloxanes species, is required to accurately determine the extent of gas conditioning required. This analysis would also test for H 2 S, CH 4, and all other gas constituents. The gas testing costs approximately $3,400 for a full analysis Biogas treatment, or clean-up, would be required with the installation of microturbines, fuel cells, or exhaust catalysts installed on IC engines Reason for Limited Information Development Additional gas treatment information is provided in the discussion of alternative power technologies in Section Cost The estimated cost to install emissions reduction equipment to the four existing IC engines is provided in Table 18. The required equipment includes gas treatment, urea tank and catalysts. The estimated first year operation and maintenance (O&M) cost is $0.03 per kwh. Total operating costs allowing for capitalized costs is $0.83 per kwh for the first year of operation. A detailed cost template is provided in Appendix C. Table 18: Estimated Cost Emissions Reduction System Item Project Cost Exhaust Catalyst Equipment $340,000 Installation (30% of Equipment Cost) $102,000 Urea Tank $5,000 Gas Treatment System $1,530,000 Gas Treatment System Installation $460,000 Subtotal: $2,437,000 Engineering costs (20%) $490,000 Total installed cost: $2,927,000 Starting year O&M costs ($/kwh) $ First year cost power ($/kwh) $ Year average cost ($/kwh) $0.090 Equivalent Value cost ($/kwh) $0.078 The estimated catalyst replacement part costs are listed in Table 19 for sensors and two alternative catalysts. The total catalyst replacement part costs are included along with gas treatment system operating costs in the estimated O&M costs in $/kwh shown in Table 18 above. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-9

102 Table 19: Catalyst Replacement Parts, Replacement Frequency and Estimated Costs Part Hours Cost NO X Sensors (2 per unit) 8,000 $7,700 for both CO Catalyst 20,000 $8,000 per unit SCR Catalyst 20,000 $10,500 per unit Examples of Internal Combustion Engine Projects IC engines are widely used at wastewater treatment plants. Uses include cogeneration, standby power and fulfilling other mechanical power needs. The technology is considered mature and there is a relatively low risk associated with IC engine use. The use of gas treatment and catalysts enables agencies and private enterprise to meet increasing stringent air emissions standards. In some California air basins, the use of IC engines is becoming increasingly difficult due to significant emissions requirements. EWPCF, located in the SDAPCD air basin, will be faced with more stringent standards. However, there is readily available gas treatment technology resulting in economically feasible IC engines use in the SDAPCD air basin Community Impacts Use of a cogeneration system beneficially produces both electric power and useable waste heat. The use of IC engines for cogeneration is typically more strictly regulated because they generally have higher emissions of NO x and CO than other cogeneration options, and because they also create more noise. At EWPCF, engines would be housed to contain noise and catalysts, if used, greatly reduce NO x and CO emissions. The increased cost of fuel and concern with greenhouse gas emissions has renewed interest in pursuing renewable energy alternatives. As well, state and federal policies encourage the use of renewable energy sources, and there is an increased expectation by the public for public agencies to be green. While there are fewer incentives for using IC engines, the state renewable portfolio standard (RPS) policy has required electricity suppliers to purchase an increasing percentage of renewable energy over time. The use of digester gas with cogeneration can contribute to these renewable energy goals Environmental Impacts Air: Generally, internal combustion engines, particularly reciprocating engines, have moderately high emissions of air pollutants, due to incomplete combustion of fuel. Under the current SDAPCD permit, emissions are below acceptable levels for a synthetic minor emissions designation. With the addition of emissions reduction equipment, discharge of regulated pollutants would be significantly reduced. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-10

103 Land: Adding blending, waste-to-energy, or a catalyst will require additional space inside the current boundaries of the plant. Care needs to be taken as to not impact current plant operations. Water: The currently installed IC engines are connected to a heat recovery loop which periodically needs a modest amount of make-up water. The gas conditioning system would require additional water, and will have drain water which will need to be routed to the plant drainage system. Noise: IC engines are fairly noisy. Noise emissions from the Caterpillar G3516 engine are expected to be approximately 80 to 90 dba at approximately 50 feet, which is roughly equivalent to the sound of a gas lawnmower at 100 feet, or very loud speech at the distance of three feet. Installing equipment further from receptors also will reduce perceived noise, as there is approximately a 6dB reduction in noise level for each doubling of distance from the noise source to the receptor. Mechanical noise from the engine is generally reduced by locating the equipment within an insulated building. As well, the engines are equipped with silencers, and the proposed catalysts also include silencers. Aesthetic/Visual: It is not expected there would be significant visual impacts from installation of the IC engine. Equipment would be contained within the existing footprint of the facility, and although there would be a smoke stack, the equipment should have minimal visible emissions. Waste by-products: The lube oil will periodically require replacement. It is assumed that used oil will be recycled. The catalyst also creates a waste by-product that can be disposed of in the landfill Greenhouse Gas Impacts IC engines operation at EWPCF, primarily fueled by biogas, emit carbon dioxide and carbon monoxide that converts to carbon dioxide, a greenhouse gas (GHG). However, such combustion reduces the flaring of such gas and, more significantly, offsets the purchase of commercially supplied power that is produced by the combustion of fuels emitting a greater quantity of greenhouse gas using the engines at EWPCF thereby result in a net reduction of GHG emissons Operational Impacts EWA is currently operating four IC engines in the production of self generated electricity. The addition of emissions reduction equipment and gas treatment (in order to accommodate increased use of the IC engines within the current SDAPCD permit emissions limitations) would increase operations complexity although at a lower level compared with the introduction of complete new power producing technologies. Adding an additional engine to the current four (4) engine system would increase the operational effort, but not significantly Summary of Advantages and Disadvantages The advantages and disadvantages for the continued use of IC engines follows: Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-11

104 Advantages o Allows EWA to continue production of electricity utilizing recently installed engines o o o Emissions can be controlled to acceptable levels by continuing to limit operations in accordance with the current SDAPCD permit, or Increase self generation by installing emissions reduction equipment on the existing IC engines Increased self generated electricity can be achieved by implementing a waste to energy (WTE) project. Disadvantages o Requires the purchase of a gas conditioning system to use with digester gas (to increase power production) o Additional maintenance requirements associated with the gas conditioning and catalyst systems 4.4 Fuel Cell Introduction Biogas used as a fuel to operate fuel cells is addresses in this subsection. Fuel cells are similar to IC engines to the extent they use fuel (including biogas) and produce waste heat that can be captured and beneficially used. Natural gas is often used as a fuel source and is briefly addressed. This assessment presents technical, environmental and cost information of the use of fuel cells at EWPCF for the production of self generated electricity History Fuel cells were invented over 100 years ago, but it was the space program in the 1960s that impelled their commercial development. Fuel cells are commercially available, and while they seem to have overcome their past history of poor performance they are still a relatively new technology. Vendors are overcoming these issues by only leasing their fuel cells and providing all maintenance and operations support through contract operations agreements. Fuel cells provided the power on Gemini and Apollo spacecraft, and provide power on the space shuttle as well. Fuel cells generate electricity by a chemical reaction. Each fuel cell has one positive and one negative electrode, called, respectively, the cathode and anode. The reactions that produce electricity occur at the electrodes. Each fuel cell also has an electrolyte, which carries charged particles from one electrode to the other. There are several different types of fuel cells. Each type uses different electrolytes and operating temperatures. The type of fuel cell used in the space program requires pure fuels, limiting its terrestrial applications. The four Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-12

105 primary fuel cell technologies in development include phosphoric acid fuel cells (PAFC), molten carbonate fuel cells (MCFC), solid oxide fuel cells (SOFC), and proton exchange membrane fuel cells (PEMFC). PAFCs use liquid phosphoric acid as the electrolyte. The PAFC is the oldest technology used today. Generally, PAFCs have higher capital costs and lower efficiencies than other types of fuel cells such as MCFC and SOFC. Power plants utilizing PAFCs are generally large and heavy and require warm-up time, making them most appropriate for stationary applications. Efficiencies of approximately 35 to 45 percent are achievable with PAFCs. MCFCs use an electrolyte composed of a molten carbonate salt mixture. These fuel cells operate at high temperatures and have efficiencies as high as 45 to 60 percent. However, the high operating temperatures accelerate component breakdown and corrosion, decreasing the life of the cell. SOFCs use a hard ceramic compound as the electrolyte. SOFCs also operate at high temperatures, with efficiencies approximately 45 to 60 percent. This technology is still at a relatively early stage of development compared with other fuel cell technologies. Development of PEMFCs has generally been driven by the automotive sector, because of their low temperature operation, which allows them to start quickly, and their light weight. PEMFCs use a thin solid membrane for, an electrolyte. They are generally good candidates for smaller applications, and have efficiencies of approximately 35 to 50 percent. Fuel cells run on hydrogen, and can use a variety of hydrogen sources. If the fuel source is not pure hydrogen, a fuel reformer is generally required to extract the hydrogen. Natural gas (methane) is considered to be the cleanest fuel next to hydrogen. Fuel reformers break the methane molecule and separate the hydrogen for use by the fuel cell. When digester gas is used as the source of methane, it must first be cleaned to remove impurities such as siloxanes and hydrogen sulfide. The first fuel cell operated on digester gas was a PAFC placed into service in 1997 at a wastewater treatment plant in New York. Since that time an increasing number of fuel cells have been installed using digester gas, most using either PAFC or MCFC technologies. Many have been in operation for more than 50,000 hours (almost 6 years). The following discussion focuses on digester gas-fed fuel cells. A single fuel cell generates a small amount of electricity, so in practice many fuel cells are typically assembled into a stack to generate the desired power output Technical Description Fuel cells work like batteries, making electrical energy from chemical energy without combustion. Unlike batteries, fuel cells require refueling. Fuel cells use hydrogen as their fuel source. Methane in digester gas or natural gas can be used as the source of hydrogen. However, impurities in the gas must first be removed through a gas clean-up system, as they can poison the fuel cell catalyst, which limits its ability to ionize hydrogen, thereby reducing the fuel cell s efficiency. FuelCell Energy delivers complete packaged modules to a site that includes all the necessary equipment to run the generation plant. Recently, FuelCell Energy Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-13

106 implemented a requirement for additional sulfur clean-up equipment for their fuel cells with an up-front cost of about $40,000. After cleaning the gas, a fuel reformer or fuel processor is used to extract the hydrogen from the methane. The fuel cell has one positive electrode (the cathode) and one negative electrode (the anode) with an electrolyte between them. The hydrogen is fed to the anode and air (oxygen) is fed to the cathode. A catalyst on the surface of the anode splits the hydrogen into protons (hydrogen ions) and electrons. As the hydrogen ions move from the anode to the cathode through the electrolyte, electricity is created. Electrons cannot flow through the electrolyte and, as a result, flow through an external circuit as an electric current. At the cathode, a catalyst on the surface recombines the hydrogen ions and electrons with oxygen to produce water and heat. A diagram of an MCFC fuel cell is shown in Figure 26 (picture source: USDOE, Office of Energy Efficiency and Renewable Energy). Figure 26: MCFC Fuel Cell Diagram This process is different than the traditional two-step process of combustion where fuel is first burned, and the subsequent heat is used to produce power. Avoiding the two-step process makes the fuel cells more efficient than combustion technologies. Individual fuel cells generate a relatively small voltage. The current produced by an individual cell is related to the cell surface area. To develop the desired voltage, individual cells are stacked and connected in series. The number of fuel cells in the stack determines the total voltage, and the surface area of each cell determines the total current. The total electrical power generated is equal to the voltage multiplied by the current. Fuel cells produce direct current (DC) electricity. The electrical standard for most uses, such as building power, is alternating current (AC), so the fuel cell uses a power inverter to convert the electricity from DC to AC. This however decreases its efficiency. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-14

107 4.4.4 Vendors More than 60 companies worldwide are involved in the development of fuel cells. Generally, most companies focus on one of the primary types of fuel cell technologies. Developers of PAFCs include UTC Power, Fuji Electric Company, and Mitsubishi Electric Corporation. Fuel Cell Energy and Hitachi are developing MCFC technology. More than 40 companies are developing PEMFCs, and include ReliOn, Ballard Generation Systems, UTC Power, Bloom Energy and Nuvera Fuel Cells. There are more than 20 developers of SOFC technology, including Siemens Westinghouse Power Corporation, SOFCo, and ZTEK Corporation. FuelCell Energy provided information about sizing and cost estimates for this resource assessment Size and kwh Production The Encina facility produces an average of 584,000 cubic feet per day of digester gas with a methane content of approximately 58 percent (molar percent). The amount of digester gas available varies somewhat throughout the year. This analysis considers the amount of digester gas that could be utilized by either a 300 kw or 1.4 mw fuel cell system. Vendors do not typically manufacture many different sizes of fuel cells; they typically focus on one or two sizes. FuelCell Energy (FCE) manufactures three sizes; in addition to the two discussed in this analysis they make a 2.8 MW fuel cell system. One FCE DFC300MA (an MCFC), with a total output of 300 kw at full load, would utilize approximately 86,000 cubic feet of digester gas per day. One FCE DFC1500, with a total output of 1.4 MW at full load, would utilize approximately 400,000 cubic feet of digester gas per day. Operating the 300 kw and 1.4 mw fuel cells at full load 24 hours per day, 365 days per year, would generate approximately 2.6 million kwh or 12.3 million kwh, respectively. The fuel cell systems are provided with integrated heat recovery modules, and the recovered heat could be used for process and building heating requirements. The recoverable heat from a 1.4 mw fuel cell is 4.3 mm Btu/hr as hot water. The fuel cell is typically equipped for dual fuel use, and can automatically blend in natural gas if the supply of digester gas drops, to maintain full load. The natural gas is also used as a back-up fuel if the digesters need to be taken down. The total energy used by the plant during the baseline period) was approximately 17.3 million kwh. At full load, the 300 kw fuel cell system would provide approximately 2.6 million kwh, or approximately 14 percent of current energy use by the plant. The 1.4 MW fuel cell facilities could provide approximately 12.3 million kwh at full load, which is more energy than was purchased by the plant. The 1.4 mw fuel cell system at full load produces approximately 67 percent of the current total plant electricity use. If the plant continued to utilize two IC engines at full capacity (up to the permit limit), the excess digester gas available is estimated to be approximately 43,000 cubic feet per day currently, 189,500 cubic feet per day by 2015, and 456,000 cubic feet per day by By 2015, the amount of excess digester gas available would be sufficient to operate two 300 kw fuel cells, and by 2030 the available excess digester gas could operate five 300-kW fuel cells. Because of the extremely low emissions from the fuel cells, air permit modifications may not be necessary. In addition to the natural gas back-up and gas clean-up equipment, FCE requires electric load levelers. This requirement comes from the lessons learned from the Dublin-San Ramon plant. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-15

108 Electrical disruptions in the treatment plant can cause the fuel cell to shut-down and it can take 8-12 hours to bring back on-line. The load levelers, acting as a big capacitor bank, allow the fuel cell to ride-out the electrical disruption and put the generated electricity back out onto the grid; thus preventing the shut-downs and lengthy start-ups Examples of Fuel Cell Projects Fuel cells generating electricity have been in operation for over 20 years. Today there are about 50 fuel cell installations in California alone totaling over 25 mw; 10 mw of which is at wastewater treatment plants. Approximately 90 percent of fuel cell projects installed by one supplier (FCE) utilize digester gas. The largest fuel cell plant in the world is a 5.6 MW FCE plant in Korea. Currently FCE is the only supplier of fuel cells suitable for biogas as a fuel source. UTC Power is planning on providing biogas fuel cells equipment in Bloom Energy offers commercial fuel cells but has not yet installed a unit operating on biogas. The Eastern Municipal Water District installed three 250 kw fuel cells that operate on digester gas at their Moreno Valley Regional Water Reclamation Facility. The fuel cells provide the District with enough energy to operate 40 percent of the plant at peak hours. The City of Riverside installed a 1 mw FCE fuel cell in August 2008 at their MGD wastewater treatment plant. Because of air quality permit issues, and problems with siloxane and H 2 S, Riverside shut down their 3.9 MW IC engine plant. They now primarily operate the 1 mw fuel cell, and operate the IC engines only when they have excess digester gas. The Regional Wastewater Treatment Facility for the City of Tulare has three FCE 300 kw fuel cells operating on digester gas. Installation of the fuel cell systems allowed Tulare to address emissions non-attainment restrictions in place in the San Joaquin Valley Potential Funding Sources In California, the Self Generation Incentive Program (SGIP) governed by the California Public Utility Commission offers an incentive for fuel cells using a renewable fuel, such as digester gas, of $4500 per kw up to 1 MW. For projects greater than 1mW, incentives of $2250 per kw are available for the energy generated between 1 mw and 2 mw. Projects larger than 2 mw receive $1125 per kw above 2 MW and up to 3 MW. Systems must be new, UL listed, and in compliance with all applicable performance and safety standards. Wind systems, fuel cells and advanced energy storage systems must be covered by a minimum five year warranty. The warranty must protect against the breakdown or degradation in electrical output of more than ten percent from the originally rated electrical output. The warranty should cover all replacement and labor costs. The incentive can go to the project if owned or leased. The SGIP might not receive additional funding beyond December 31, A federal tax incentive is also available for installation of fuel cells, after first applying the state tax incentive. The federal incentive is the smaller of $3,000/kW or 30 percent of the cost. The federal incentive is available through Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-16

109 However, a tax exempt entity could take advantage of these incentives through a third-party lease arrangement. For instance, EWA could enter into an agreement with one of a FCE s distributors. Leasing the equipment through a distributor would allow Encina to gain some of the advantage of the tax incentives passed through in the form of a lower energy price. The lessor would charge a fee for this service. The potential funding from the two funding sources (assuming a lease arrangement to take advantage of the federal tax credit) for an EWA fuel cell project is provided in the Table 20. Without a lease arrangement only the SGIP is available to EWA. Table 20: Potential Funding Sources Fuel Cell Source Incentive (300 kw) Incentive (1.4 MW) California Self Generation Incentive Program $1,350,000 $5,400,000 Federal Business Energy Investment Tax Credit $756,000 $756,000 Total $2,106,000 $6,156, Cost Fuel cells are typically an expensive cogeneration technology and need financial incentives to compete with other better established generation technologies. That is why tax incentives are higher for fuel cells than for microturbines or reciprocating engines. The incentives are intended to stimulate a competitive environment for power generation technologies. The estimated costs for the 300 kw and 1.4 mw FCE systems are presented in Table 21. Detailed cost templates are provided in Appendix C. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-17

110 Table 21: Estimated Costs for 300 kw and 1.4 MW Fuel Cell Systems Item Cost Cost (300 kw system) (1.4 MW system) Fuel Cell $1,860,000 $6,020,000 Gas Treatment $400,000 $1,000,000 Water Treatment $125,000 $250,000 Heat Recovery $200,000 $400,000 Electrical $144,000 $332,000 Shipping, installation, commissioning $450,000 $1,200,000 Subtotal: $3,291,000 $9,362,000 Cont./Eng costs (40%) $872,000 $3,745,000 Total installed $4,407,000 $13,107,000 cost: Incentives $1,350,000 $5,400,000 Total Net Capital Cost $3,257,000 $7,707,000 O&M through long term service agreement 1) $0.15/kWh $0.07/kWh First year cost power (cents/kwh) 10-Year average cost (cents/kwh) Present Value cost (cents/kwh) 1) Includes operation of fuel cell, gas and water treatment systems $0.31 $0.14 $0.33 $0.15 $0.28 $0.13 Design life for the FCE s fuel cell systems is estimated to be 20 years. Operation and maintenance of the system must be provided by FCE through a Long Term Service Agreement (LTSA) in order to qualify for state incentives. These agreements are typically at least 5 years long and cost 7-15 cents/kwh for O&M (depending on the unit capacity) which includes the cost of replacement stacks every 3-5 years. The contract operator would also monitor the system remotely in order to provide full time operating support. With the aforementioned incentives the net capital cost of one 300 kw fuel cell system would be $3,257,000 or $10,900 per kw, and the net capital cost of one 1.4 MW fuel cell system would be $7,707,000 or $5,500 per kw Community Impacts The use of fuel cells for cogeneration is readily accepted by regulatory agencies because there are virtually no emissions, mostly water vapor and carbon monoxide (CO), and because they are substantially quieter than IC engines. In fact, fuel cells are currently exempt from having to obtain an air emissions permit. The increased cost of fuel and concern with greenhouse gas emissions has resulted in a renewed interest in pursuing renewable energy alternatives. As well, state and federal policies Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-18

111 encourage the use of renewable energy sources, and there is an increased expectation by the public for public agencies to be green. State policies have required electricity suppliers to purchase an increasing percentage of renewable energy over time. One growing trend since the late 1990s is for municipal governments to purchase green power for use in government buildings and infrastructure, or to set a goal requiring utilities to generate or purchase a given percentage of renewable energy. The use of a renewable energy such as digester gas with cogeneration can contribute to attainment of these local policy goals. Fuels cells therefore enjoy excellent community acceptance Environmental Impacts Air: Air emissions from fuel cells are very low, and are currently exempt from many Clean Air Act permitting requirements. A 1.4 mw fuel cell is estimated to have emissions of nitrogen oxides (NOx) of <0.01 lb/mwh, and CO emissions of <0.10 lb/mwh. Emissions from both the 300 mk and 1.4 mk fuel cell units have emissions which meet or exceed 2007 California Air Resources Board standards and thus are exempt from permit air quality requirements. NOx emissions are negligible. Land: The standard configuration for the 1.4 mw fuel cell requires an area of approximately 42 feet by 58 feet plus additional space for maintenance access. Water: A 1.4 mw requires a water pressure of psig at the inlet to the power plant at all times. During full power operation, the overall water consumption of the power plant is approximately 5,800 gallons per day, and water discharge is approximately 2,900 gallons per day. This varies depending on the quality of the supply water. The power plant only consumes water while it is filling the water storage tank. When the tank is full, the power plant only draws water when the system is back flushing. Pretreatment of water is required and typically includes a small mineral reduction system (such as reverse osmosis). The discharge water is under pressure and will contain the impurities that were in the feed water that are not removed by carbon filtration as well as some quantities of anti-scalant. Noise: Fuel cells are relatively quiet equipment. Environmental noise is typically measured as A-weighted sound levels in decibels, abbreviated as dba. The A-weighted scale represents the noise scale that corresponds closest to the range heard by the human ear. Noise emissions from a 1.4 mw fuel cell is expected to be approximately 72 dba at 10 feet. A low noise option can reduce the noise to 65 dba at 10 feet, which is roughly equivalent to the sound of normal conversation at the distance of three feet. Installing equipment further from receptors also will reduce perceived noise, as there is approximately a 6 dba reduction in noise level for each doubling of distance from the noise source to the receptor. Aesthetic/Visual: It is not expected there would be visual impacts from installation of a fuel cell. Equipment would be contained within the existing footprint of the facility, and there would be no tall emissions stacks or visible emissions. Waste By-Products: The waste products produced by fuel cells are discharge water, stack units and gas treatment components. The fuel cell stacks need to be replaced every 3-5 years and would be 100 percent recycled. However, the gas clean-up equipment will generate some solid waste. The carbon media used to remove siloxanes will periodically require replacement (about Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-19

112 every 6 months). Used media can be disposed as solid waste into a landfill. Particulate filters will also require periodic replacement, and can be disposed as solid waste Greenhouse Gas Impacts Fuel cells operation at EWPCF utilizing biogas would result in reduced greenhouse gas emissions. This would occur as biogas combustion in the current IC engines and commercial power purchases is replaced by fuel cell operations. The total net reduction in greenhouse gas emissions would increase in direct proportion to the installed and operating fuel cell capacity Operational Impacts The operational impacts of the utilization of digester gas through fuel cells should be minimal. Although the gas cleaning system and fuel cells is complex, the service agreement required by FCE provides all operation and maintenance requirements for these systems. Very little plant personnel time would be required under this arrangement. When compared to other digester gas utilization options, the fuel cell is the leader with regard to impacts on air quality and air permit discharge compliance. Since the fuel cell does not burn the gas, it has little or no negative impact on air quality. Operational impacts from a fuel cell are summarized in Table 22. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-20

113 Table 22: Operational Impacts of Fuel Cell Parameter FTE / Labor Maintenance Requirements Boilers Air Permit Compliance Discharge Permit Compliance Need for Heat Summary of Advantages and Disadvantages The advantages of fuel cells are: Very low air pollutant emissions, requiring no air permit Operational Impact 0 to 0.1 FTE increase Provided by FCE Not needed with fuel cell option No air permit required Not applicable Can be used to heat the digesters with excess used for buildings. Large financial incentives available for implementing this technology Power production efficiency of approximately 47%, or approximately 42% more efficient than conventional IC engines. Operation and maintenance can be provided by manufacturer The disadvantages of fuel cells are: High capital and operating costs Single supplier currently providing equipment suitable for biogas fuel systems Require effective digester gas cleaning Increased plant operation and maintenance complexity due to gas clean-up and new fuel cell equipment not presently in place at EWPCF Lack of consistent operating history with biogas as a fuel source Cannot be brought on line instantly to supply emergency power 4.5 Solar Photovoltaic (PV) Introduction The term solar energy refers to a number of technologies that derive their energy from the sun. This resource assessment focuses on photovoltaic (PV) solar electric systems, in which sunlight is converted directly into electricity using solar panels. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-21

114 4.5.2 History The first PV cells were developed in the early 1950 s, and by end of the decade, they were being used in space technology. Improved technology has allowed for the expansion of solar PV applications since that time, and today there are multiple utility-scale and small-scale uses for the technology. Federal and state incentives have drastically increased the use of solar PV systems as a renewable energy resource for electricity Technical Description As described by the Solar Energy Industries Association (SEIA, 2010): PV technologies directly convert energy from sunlight into electricity. Sunlight strikes the semiconductor material and releases electrons from their atomic bonds, producing an electric current. PV panels contain no moving parts and generally last twenty years or more with minimal maintenance. Most modern solar cells are made from either crystalline silicon or thin-film semiconductor material. Silicon cells are more efficient at converting sunlight to electricity, but generally have higher manufacturing costs. Thin-film materials typically have lower efficiencies, but are simpler and less costly to manufacture. Figure 27 below shows how a solar PV array converts the sun s energy to electricity, and how it may be connected to the utility grid. (Source: Retrieved online 01/04/10 from the State of Rhode Island Office of Energy Resources: Figure 27: Typical Solar PV System By themselves, PV units do not represent a complete PV system. The system includes support structures that point them toward the sun, and components that take the direct-current electricity produced by modules and convert it to alternate-current electricity. Some PV systems also use a storage device such as batteries to allow nighttime use of the power (from USDOE, accessed online May 2008) although providing batteries for larger systems is not typically cost effective. Due to the popularity of solar energy as a potential tool for greenhouse gas reduction, a significant amount of funding and research has been dedicated to the development of PV technology and its use has grown dramatically in recent years. Although research continues to Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-22

115 improve the efficiency of solar arrays, this is considered a mature technology, having been used in utility-scale applications for nearly 30 years, and in smaller-scale applications for even longer. The reliability of PV technology as a source of electricity is contingent upon the solar energy available at a particular location. In addition, because the sun s energy reaching the Earth fluctuates both daily and annually, the electricity generated from this technology also fluctuates Vendors Below is a limited list of companies close to EWA that are involved in the sale and installation of solar PV equipment. This list was obtained from the California Public Utility Commission and California Energy Commission Go Solar website ( Solar Watt Solutions, Inc Cynthia Land Carlsbad, CA Siliken Renewable Energy 5901 Priestly Drive, Ste 170 Carlsbad, CA Siliken.usa@siliken.com A&M Energy Solutions 2118 Wilshire Blvd #718 Santa Monica, CA Size and kwh Production On average, solar panels can be installed to achieve approximately 1 kilowatt (kw) of power per 100 square feet of useable space. In order to determine kwh production for EWA, the electricity production for a 100 kw PV installation in Carlsbad, California was calculated using the PVWatts tool developed by the researchers at the National Renewable Energy Laboratory (NREL) ( The PVWatts calculator works by creating performance simulations that provide estimated monthly and annual energy production in kilowatts and energy value. It considers weather data for the selected location and provides an estimate of available the solar radiation. Solar radiation is then converted and annual AC energy production is calculated (in kilowatt-hours per year per kilowatt installed). Based on PVWatts calculations for Carlsbad, CA, the annual energy production from a 100 kw PV installation is estimated to be approximately 150,000 kwh/year. This estimate is based in Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-23

116 the assumptions that the panels are installed on south-facing, fixed-tilt arrays at 33.2-degrees. Additionally, a DC to AC conversion factor of 0.77 was used Examples of Solar PV Projects In addition to hundreds of residential and commercial roof-top solar PV installations throughout southern California, the following are a few examples of other government/non-profit agencies with solar PV installations in California: Cal Polytechnic University, San Luis Obispo (175 kw). Installer was SunEdison LLC, who is the owner of the project under a power purchase agreement with the University. Vallecitos Water District (341 kw). Installer was SPG Solar, Inc. Sonoma County Water Agency (596 kw). Installer was SPG Solar, Inc. City of San Marcos Fire Department (58 kw). Installer was Akeena Solar City of Thousand Oaks, Hill Canyon Treatment Plant (450 kw) Potential Funding Sources A number of different local, state, and federal incentives are available for solar energy projects. The rebates vary based on size of system and ownership (public entity or private). The following is a summary of rebates EWA may be eligible for. California s Net Energy Metering (NEM). Net energy metering applies to solar PV projects as long as the project is behind the meter. Eligible renewable resources are photovoltaic systems, wind driven technologies, fuel cells and dairy biogas use systems. System capacities are limited to a maximum of 1 MW in size. SDG&E is obligated by state law to provide a net metering agreement to all their customers. Net metering is a method of metering the energy consumed and produced by a customer that has a renewable resource generator, and credits the customer with the retail value of the generated electricity. Effectively, the meter runs backwards, causing a credit with the utility. Net metering s benefit is the deferred cost of the electricity that EWA does not have to purchase, providing the full retail value of the electricity produced ($0.19 cents per kwh). The renewable system must be intended primarily to offset part or all of the electric requirements for electricity at that meter. EWA does not have to own the eligible renewable resource; however the output must be dedicated to offset the electricity used at that meter. Net excess electricity (NEG), beyond that month s actual usage, is carried over as a credit for a 12- month cycle, but at the end of the 12-month period, any NEG is zeroed out and EWA will not be paid for that generation. It therefore becomes important to correctly size the project so that over the course of a year the project does not create any NEG. With net metering EWA will own all of the RECs (Renewable Energy Credits) and carbon credits from the renewable resource. Net metering does not preclude EWA s eligibility for other incentives. The California Solar Initiative (CSI). This is part of the Go Solar California campaign which builds on 10 years of state solar rebates offered to customers in California's investor-owned Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-24

117 utility territories. CSI rebates vary according to system size, customer class, and performance and installation factors. The subsidies automatically decline in "steps" based on the volume of solar megawatts confirmed within each utility service territory. The CSI rebate applicable to a 100 kw array in the year 2010 is the Performance Based Incentive (PBI). The PBI pays out an incentive, based on actual kwh production, over a period of five years. PBI payments are provided on a dollar per kilowatt-hour basis, based on a step system of statewide MW receiving rebates from the program. The step basis payments vary from $0.10 to $0.50 per kwh for government agencies. In late 2010, the program was at step 8 which would provide new systems $0.15 per kwh payments over a 5 year period. Federal rebates and incentives are available in the form of tax credits and rebates. Unfortunately, tax-exempt entities such as EWA are not eligible. However, a tax exempt entity could take advantage of these incentives through a third-party lease arrangement. For instance, EW could enter into an agreement with a solar PV provider and enter into a long-term Purchase Power Agreement (PPA). This would not require EWA to commit any up-front capital but would require EWA to purchase the electric output of the solar PV system. Entering into such an arrangement would allow Encina to gain some of the financial advantage of the tax incentives passed through in the form of a lower energy price Cost Based on consultations with local solar panel installers and Kennedy/Jenks experience, the current materials and installation price ranges from $5.00 to $9.00 per watt installed. Average PV module prices are currently about $4.40 per watt, which is down approximately $0.50 per watt from where they were 12 months ago (per Installation costs, however, can range from $2.00 to $4.50 per watt. The variation in this price range is dependent upon the size of the system (economies of scale), physical location, new versus existing structure, and siting challenges (i.e. equipment, penetrations, slope). The costs analyzed here include the photovoltaic panels, fixed-tilt solar arrays, inverters, wiring, engineering, installation, utility grid interconnect, warranty, 5-years of maintenance, and 5-years of performance monitoring and reporting service (an eligibility requirement by some of the financial incentive programs). Maintenance requirements depend upon the system size. Regular maintenance is minimal over the life of the system and includes periodically washing and cleaning the panels, as well as testing and cycling the inverters. The lifetime of most PV arrays is between 20 and 30 years and failures that require replacements are rare. PV arrays degrade at an approximate rate of % capacity per year. The degradation is due to energetic particles from the sun that produces physical damage to silicon-based solar cells. The degradation of the system capacity begins at year 1 and continues throughout the system lifetime, which is estimated to be 30 years. Manufacturer warranties and PPA s usually take this degradation into account. However, the inverter needs to be replaced every 10 years for approximately $0.70 per watt installed (source: and this cost is usually included in the vendor maintenance agreement. The present value cost for the resource, assuming a 100 kw system lasting 30 years, a 20 year 6 percent bond, receiving the California s Solar Initiative Go Solar incentive from CCSE Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-25

118 ($0.15/KWh for 5 years) and Net Energy Metering incentive (retail rate of $0.19/KWh for the life of the project), would be about $0.18/kWh. This is slightly lower than the present value cost of utility power from SDG&E ($0.19 per kwh). An alternative cost structure for this energy source would be through a power purchase agreement (PPA). Under this structure, a third party installs, owns and operatives the solar PV system, and EWA would purchase the power generated from the third party. This could be an advantage for EWA because there is no up front capital required, and tax credits, of which EWA cannot take advantage, may be available to the third party and written into the pricing for EWA, lowering the overall cost of the power. Since such agreements are negotiated with third party providers, an estimated cost can not be determined without further analysis and contact with third party providers Community Impacts Community acceptance of solar electric systems is generally high. PV systems can provide dependable energy independence at a very low impact to the environment, with a positive impact for both the local and regional community. Continued technological advances, a long life span for the equipment ( years) and tax and cash incentives have made PV more costeffective Environmental Impacts Air: Solar PV systems produce no air pollution. Land: Solar PV systems generally require 100 square feet of unobstructed and unshaded area per kw, and weigh 4-6 pounds per square foot. A 100 kw system would therefore require 10,000 square feet, or about one quarter acre. Large solar PV project require a great deal of open land or roof tops. Water: Solar PV systems do not use water in the generation process, and use very little water when the panels are periodically cleaned. Noise: Solar PV systems produce no noise pollution. Aesthetic/Visual: Installation of a PV system on an existing roof would have minimal aesthetic effects. Siting at other locations may have some limited visual effect, depending on the location. Waste by-products: Power production with Solar PV systems generates no waste by-products, but the production of PV cells results in some hazardous waste (cadmium and arsenic) Greenhouse Gas Impacts PV systems emit no greenhouse gases during operation, and would avoid the impacts from greenhouse gases that would otherwise be emitted by the electricity it replaces. In the case of EWA, the electric utility provider is San Diego Gas and Electric (SDG&E). The GHG emissions factor for SDG&E is 603 pounds of CO 2 per mwh of energy produced. A single 100 kw array of Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-26

119 PV panels producing 149,000 kwh/year at EWA would avoid emitting approximately 41 metric tons of CO 2, which would otherwise be emitted from consumption of the same volume of electricity distributed by SDG&E Operational Impacts The impacts on the treatment plant operations and maintenance associated with a solar PV system would be minimal. Solar PV systems do not require on-going staffing during generation, except for the limited time required to periodically clean the panels. Any replacements or maintenance is usually performed by the vendor. Table 23 provides a summary of estimated PV system operations impacts. Table 23: PV Solar Operations Impacts 1) Full time equivalent Parameter FTE 1) / Labor Maintenance Requirements Boilers Air Permit Compliance Discharge Permit Compliance Need for Heat Summary of Advantages and Disadvantages Advantages Low operations & maintenance requirements Operational Impact FTE increase Minor PM. Other maintenance done by vendor if 3rd party agreement is implemented Not applicable Not applicable Not applicable Does not generate auxiliary heat nor offset any of the facility s heat requirements No fuel costs Very low environmental impacts and no greenhouse gas emissions or other waste produced from operation Financial incentives available to make PVs more cost-effective Peak PV production coincides with peak summer demand and energy pricing in California. Disadvantages Relatively large space requirements for significant electricity production (although rooftop installation would mitigate this disadvantage) High purchase/installation costs per kw relative to other forms of electricity, but partially mitigated by federal, state and utility incentives. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-27

120 A power purchase agreement is required to take advantages of tax incentives. 4.6 Small Wind The term small wind includes wind turbines with a capacity of up to 100 kilowatts (kw). Small wind is commonly used in residential applications, as well as for telecommunications dishes or pumping water. It is also common to combine wind turbines with other power sources such as diesel generators, batteries, or photovoltaic systems (DOE, 2010). The wind has been harnessed for energy for hundreds of years through the use of wind mills. Modern day wind turbines have been in use since World War II, and wind farms have been in existence on a commercial scale since the 1980 s, with constantly improving technology and efficiency (DOE, 2010) Description Wind turbines work by converting the kinetic energy of wind into mechanical power. The wind turns the blades on a rotor, which spin a shaft, which connects to a generator that makes electricity. The power in the wind is proportional to its speed (velocity) cubed. A picture of a basic wind turbine is provided below in Figure 28. Source: Retrieved online 01/04/10 from the American Wind Energy Association (AWEA): Figure 28: Small Wind Turbine Wind energy is a mature technology that continues to improve through ongoing research and development efforts. Small scale wind is not as mature of a technology as large utility-scale wind turbines, but they are reliable. However, one of the major challenges of wind power is the intermittent nature of the wind itself. Wind energy is not always available when or where electricity is needed. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-28

121 4.6.2 Vendors Below is a limited list of vendors and contact information for small wind turbines (100 kw): Prevailing Wind Power 324 N Gertruda Redondo Beach, CA US bhayes@prevailingwindpower.com (310) Northern Power Systems 29 Pitman Road Barre, Vermont (877) 90-NORTH or (802) Southwest Windpower 1801 W. Route 66 Flagstaff, AZ USA info@windenergy.com Fax: (928) Reason for limited Information Development The feasibility of wind power was deemed to be low for the EWA, and a full evaluation of the resource was not performed, for the following two reasons: 1. Estimates of a wind resource are expressed in wind power classes ranging from Class 1 to Class 7. Each class representing a range of mean wind power density or equivalent mean wind speed at specified heights above the ground. Class 1 and 2 areas are marginal for wind power production, and Class 1 areas are generally unsuitable for utility-scale wind energy development. The land along the entire coastline from Los Angeles to San Diego is classified as having Class 1 wind power potential, based on regional wind power maps produced by the National Renewable Energy Laboratory (see figure 29 below). The EWA property is clearly a Class 1 site and would therefore not be a suitable site for wind. 2. Wind turbines have a visual/aesthetic impact on surrounding property owners. This impact can be difficult if not impossible to mitigate, which would likely result in a difficult permitting for the EWA site. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-29

122 Southern California Annual Average Wind Power Source: Wind Energy Resource Atlas of the United States. U.S. Department of Energy, National Renewable Energy Laboratory. Golden, Colorado. Retrieved online 01/10/10 at Figure 29: Wind Energy Map Southern California References U.S. Department of Energy (DOE). Energy Efficiency and Renewable Energy. Accessed online 1/04/10 at Microturbines Introduction Wastewater treatment plants equipped with anaerobic digesters can produce renewable energy in the form of digester gas. Traditionally, digester gas has been used in boilers to provide heat back to the anaerobic digestion process and for heating of buildings. Often, excess digester gas is flared. However, digester gas may also be used to produce electric power in addition to heat. The most efficient way to utilize the energy in the digester gas is through a cogeneration system. Cogeneration is the simultaneous production of electricity and heat, both of which are used in the WWTP. This assessment provides an overview of the use of microturbines for cogeneration at the Encina facility. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-30

123 4.7.2 History Microturbines are small combustion turbines that generally produce less than 500 kw of power. Historically, microturbines have been used since the mid-to-late 1960s as turbochargers in cars and trucks, to provide auxiliary power in aircraft and missiles, and to provide power in remote locations, particularly by the telephone industry. Microturbines used for the production of power have typically utilized natural gas for fuel. However, over the last several years microturbines have increasingly used feed stocks of landfill gas or other waste fuels, including digester gas to generate electricity Technical Description Microturbines are similar to larger traditional combustion turbines, or small jet engines, but spin at much faster speeds. Pressurized fuel is supplied to the combustor, mixed with fuel, and then burned. The heated combusted gases expand, powering the turbine that operates the generator and produces electricity. A recuperator can be added to the process to recover waste heat. A cutaway of a microturbine is shown in Figure 30. Figure 30: Cutaway of Microturbine (Source: Capstone) Microturbines are available in modular units from 30 kw to 200 kw. Their small size (about the size of a household refrigerator) allows easy siting, typically near the point where the energy will be used, minimizing transmission losses. A typical microturbine unit is shown in Figure 31 (below). Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-31

124 Figure 31: Installed Microturbine Using multiple smaller units allows maintenance to be performed while minimizing interruption to power generation. The efficiency of microturbines is typically between 25 and 30 percent. Greater overall efficiency (up to 70 or 80 percent) is possible when the waste heat is recovered and utilized beneficially. Microturbines are more tolerant of variable gas quality, and thus perform better than reciprocating engines on digester gas. However, microturbines require fuels that are nearly free of impurities, such as hydrogen sulfides and siloxanes typically found in digester gas. The combustion of siloxanes leaves sand-like deposits on engine parts that can result in loss of performance or cause the turbine wheel to seize. Therefore, manufacturers usually require that the digester gas be cleaned before use in the microturbines. A typical gas treatment system, or clean-up skid, may include a chiller, compressor, activated carbon filter, and coalescing filter. The production of digester gas from an anaerobic digester typically varies with time. Microturbine systems can be set up so that natural gas is blended with digester gas when the supply of digester gas drops temporarily. Blending in natural gas allows the microturbine to operate constantly at maximum load rather than shutting down or operating at a lower efficiency. During those periods when the supply of digester gas is insufficient to operate the microturbine at maximum load, natural gas can be automatically blended in to supply sufficient fuel for maximum operation. This prevents digester gas from being wasted by diverting it to a flare. Blending of natural gas with digester gas requires additional equipment, and would likely make sense only if power costs were much higher than the cost of natural gas. Installation of microturbines using digester gas began in the early 2000s. Because there are few moving parts, microturbines have demonstrated high reliability, with plant availability exceeding 90 percent, when satisfactory gas treatment is provided. Problems with initial installations Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-32

125 generally revolved around the cleanliness of the fuel, and better fuel cleaning has resulted in improved reliability. The clean-up technology developed by American Filtration Technologies (AFT) appears to have solved this problem. Kennedy/Jenks installed the AFT equipment on Capstone microturbines in West Lafayette, Indiana and have not had any problems in the 8 months of operation. As well, they have not had to clean or recharge the filters since start-up. Microturbines are designed to last between 40,000 to 80,000 hours (5 to10 years) before a major overhaul. However, since most units have not been in service that long it is not yet known exactly how long they will last Vendors There are more than 20 companies worldwide involved in the development of microturbines. The leading manufacturers include Capstone Turbine, Elliott Microturbines, Turbec, and Ingersoll-Rand Engine Systems. Unison Solutions provides the AFT gas conditioning systems packaged with Capstone microturbines, and they provided this package to the West Lafayette, Indiana project. Information in this analysis was provided by Unison Solutions Size and kwh Production Encina produces an average of 584,000 cubic feet per day of digester gas with a methane content of approximately 58 percent. The amount of digester gas available varies somewhat throughout the year. This analysis looks at the amount of digester gas that could be utilized by either one 65 kw or one 200 kw microturbine. (Capstone also produces a 30 kw microturbine; this was not included in the analysis.) We assume that some natural gas would be used to provide consistent gas quality to the microturbines when dips in digester gas quality occurred. Each 65 kw microturbine could utilize 33,000 cubic feet per day of digester gas. Capstone s C65 microturbine system is provided with an integrated heat recovery module, and the recovered heat could be used for process and building heating requirements. One 65 kw unit operating constantly would generate approximately 0.57 million kwh of electricity over the course of a year, and produce 0.25 MMBtu/hr of heat. Each 200 kw microturbine could utilize approximately 99,000 cubic feet per day of digester gas, and operating continuously at full load would generate approximately 1.75 million kwh of electricity over the course of a year, and produce 835,000 But/hr of heat. During the baseline period, EWA s total energy consumption was approximately 17.3 million kwh. Thus, the one 65 kw microturbine could supply approximately 3 percent of the facility s annual demand, and one 200 kw microturbine could supply approximately 10 percent of the facility s annual demand. If the plant continued to utilize two IC engines at full capacity (up to the SDAPCD permit limit), the excess digester gas available is estimated to be approximately 43,000 cubic feet per day currently, 189,500 cubic feet per day by 2015, and 456,000 cubic feet per day by Without modification of the existing permit, use of the microturbines may be limited. The current excess digester gas is sufficient to operate one 65 kw microturbine, but permit limits may prohibit operation at full capacity. If the permit were modified so that all digester gas could be utilized, the available digester gas currently is sufficient to operate one 65 kw microturbine. By 2030, the available excess digester gas would be sufficient to operate ten 65 kw microturbines or two 200 kw microturbines; although it may make more sense to utilize a combination of 65 kw and 200 kw microturbines to limit the footprint necessary for this installation. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-33

126 4.7.6 Examples of Microturbine Projects With its digester improvements, the City of West Lafayette took a proactive approach to going green. The project incorporated a cogeneration system with a receiving facility for Fats, Oils, and Grease (FOG) and food waste from Purdue University cafeterias. Utilizing two (2) 65kW digester gas fueled Capstone microturbines with the AFT clean-up skid, renewable electricity now supplies approximately 25% of the treatment plant s power needs, including electric car charging stations. The City of Millbrae installed one Ingersoll-Rand 250 kw microturbine at their Water Pollution Control Plant in The microturbine is the primary power source for the plant. The cogeneration system is dual-fuel, operating on natural gas and biogas, and includes a gas clean-up skid and gas blending facility. However, the old Ingersoll-Rand gas clean-up skid does not work well, and is so problematic that Millbrae is investigating switching to the AFT clean-up skid. Unison Solutions has ten installations nationwide at wastewater treatment plants utilizing digester gas, and anticipates installation of six or seven more this year. They estimate that there are approximately thirty Capstone installations at wastewater treatment plants nationwide Potential Funding Sources A federal tax incentive is available for installation of microturbines through the Federal Business Energy Investment Tax Credit. The federal incentive is the smaller of $200/kW or 10 percent of the cost. As a tax exempt entity, Encina would not be eligible for these incentives. However, a tax exempt entity could take advantage of these incentives through a third-party lease arrangement. For instance, EWA could enter into an agreement with a third-party. Leasing the equipment through a distributor or buying output from a third-party owner could allow Encina to gain some of the advantage of the tax incentives passed through in the form of a lower energy price. The potential funding from the federal tax credit for a project at Encina is provided in Table 24. Table 24: Potential Funding Microturbines Cost Incentive Incentive Source (65 kw) (200 kw) Federal Business Energy $13,000 Investment Tax Credit $40,000 Total $13,000 $40,000 The rising cost of energy has made cogeneration increasingly attractive for wastewater treatment facilities. Wastewater treatment facilities, such at those at EWA, produce renewable fuel (digester gas), use substantial amounts of on-site electricity, have a need for stand-by power (during utility power outages) for reliability, and can utilize the waste heat in the digesters. State and federal governments offer incentives to encourage green energy from renewable Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-34

127 resources. These factors can make cogeneration more cost effective for smaller wastewater facilities than it has been in the past. Microturbines cost more than reciprocating engines, but are not as expensive as fuel cells. The estimated costs for one Capstone C65 or one Capstone 200 kw microturbine are presented in Table 25. Detailed cost templates are provided in Appendix C. Table 25: Estimated Costs of One 65 kw Microturbine Item Unit Cost Unit Cost (65 kw) (200 kw) Capstone microturbine $100,000 $320,000 Clean up skid $210,000 $250,000 Shipping, installation, commissioning $250,000 $250,000 Subtotal: $560,000 $820,000 Engineering costs (20%) $112,000 $164,000 Total installed cost: $672,000 $984,000 Starting O&M costs ($/kwh) $0.03 $0.03 First year cost power ($/kwh) $0.15 $ Year average cost ($/kwh) $0.17 $0.12 Equivalent Value cost ($/kwh) $0.15 $0.10 Design life for microturbines is estimated to be between 40,000 and 80,000 hours. Leases for equipment are typically extend over a 10-year period. With the previously noted incentives the net capital cost of the 65 kw microturbine would be $659,000 or $10,100 per kw, and the net capital cost of the 200 kw microturbine would be $944,540 or $4,700 per kw. The present value cost for the 200 kw microturbine is lower than the 65 kw because the installation costs for the units are the same and the clean up skid required for the larger unit only costs approximately 20 percent more than that needed for the smaller unit. Therefore, the increased cost of the 200 kw averaged over the greater amount of kwh produced results in the lower present value cost Community Impacts The increased cost of fuel and concern with greenhouse gas emissions has renewed interest in pursuing renewable energy alternatives. As well, state and federal policies encourage the use of renewable energy sources, and there is an increased expectation by the public for public agencies to be green. One growing trend since the late 1990s is for municipal governments to purchase green power for use in government buildings and infrastructure, or to set a goal requiring utilities to generate or purchase a given percentage of renewable energy. The use of a renewable fuel such as digester gas with microturbines can contribute to attainment of these local policy goals, and help ensure community acceptance Environmental Impacts Air: Air emissions from microturbines are lower than those from reciprocating engines, and are generally relatively easy to permit. Microturbines with a combined 1,000 kw capacity would emit Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-35

128 2.5 tons of carbon monoxide per year compared to a 750 kw IC engine (without gas treatment) emission of 52 tons per year. Land: One of the advantages of microturbines is their relatively small size. One C65 occupies an area of approximately 30 by 77 inches, and requires a horizontal clearance of 30 inches on the left, right, and front of the unit. A horizontal clearance of 36 inches is required at the rear of the unit. Additional space is required for the equipment used to clean the digester gas. The clean-up skid occupies more area than the microturbine. The footprint of the skid is approximately 8 by 12 feet, the chiller occupies 4 by 4 feet, and the control panel occupies approximately 1 by 3 feet, for a total area of approximately 100 square feet. Water: Microturbines use a minimal amount of water. Noise: Microturbines are relatively quiet. Noise emissions from the C65 microturbine system is 65 dba at 33 feet, which is roughly equivalent to the sound of an automobile traveling by at 30 mph at a distance of 50 feet, or normal conversation at the distance of three feet. An optional acoustic inlet hood kit is available to reduce noise from the microturbine by up to 5 dba. Installing the microturbines further from receptors also will reduce perceived noise, as there is approximately a 6 dba reduction in noise level for each doubling of distance from the noise source to the receptor. Aesthetic/Visual: It is not expected there would be visual impacts from installation of the microturbines. Equipment would be contained within the existing footprint of the facility, and there would be no smoke stacks, visible emissions, or a water vapor plume. Waste By-Products: The microturbines have no waste by-products. However, the gas cleanup equipment will generate some solid waste. The media used to remove siloxanes will periodically require replacement (about every 6 months), and the used media can be disposed of as solid waste in a landfill. Particulate filters will also require periodic replacement, and can be disposed as solid waste in a landfill Greenhouse Gas Impacts Microturbines require the combustion of methane, which emits greenhouse gases such as carbon dioxide. The emissions by microturbines would be lower than current IC engines thereby reducing greenhouse gas. Replacing the electricity purchased from SDG&E with electricity produced by this technology would also reduce greenhouse gas emissions. Assuming this technology could replace 570,000 kwh/year of EWA s current electricity needs (using one 65 kw microturbine), carbon dioxide emissions would be reduced by an estimated 200 metric tons per year. Using one 200 kw microturbine to produce 1.75 million kwh/year would reduce carbon dioxide emissions by an estimated 600 metric tons per year Operational Impacts Biogas used as a fuel for microturbines must be cleaned to a high level prior to use. As with the fuel cell, this high level of cleaning requires increased operational and maintenance time. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-36

129 Most maintenance on the microturbine itself would require additional training or use of an outside vendor. Several companies provide operation and maintenance services for microturbine systems. A summary of the operational impacts of microturbines is provided in Table 26. Detailed cost templates are provided in Appendix C. Table 26: Operational Impacts of Microturbines Parameter FTE 1) / Labor Maintenance Requirements Air Permit Compliance Discharge Permit Compliance Available Excess Heat 1) Full time equivalent Operational Impact 0.20 FTE increase High level of maintenance skills required. Gas treatment equipment maintenance requires staff time. Discharges relatively clean compared to IC engines improving SDAPCD permit issues Not applicable Can be used to heat the digesters with excess used for buildings Summary of Advantages and Disadvantages The advantages of microturbines are: Lower emissions compared to current IC engines operations Small footprint of equipment Quieter operation than IC engines Effective response to variable fuel supply The disadvantages of microturbines are: Requires digester gas cleaning Limited incentives available for this technology Small unit capacity, high capital cost Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 4-37

130

131 Section 5: Technology Evaluations Biogas Production 5.1 Biogas Production Enhancements Introduction and Purpose Enhancing EWPFC biogas production would provide a greater opportunity for production of electrical energy onsite and self generation of fuel for the sludge dryer. This section identifies and presents an evaluation of biogas enhancement that could be achieved by introducing a new source of organic material delivered to the site or by producing additional gas from wastewater organics. The additional organics would be combined with current wastewater generated organic materials for gas production. Section 5 does not consider producing pipeline quality gas for introduction into the commercial gas delivery pipeline system. This is because at this time and in the near future gas demand at EWPCF exceeds biogas production quantities Waste to Energy Introduction Over the past 25 years resource recovery and recycling rather than landfill disposal has been given increased support by government policy and the general public. The issues of sustainability, fossil fuel shortages, energy costs, greenhouse gas reduction, and landfill space constraints has made the analysis of energy recovery from wastes such as grease trap waste and food solid wastes a focus of activity nationwide. Grease trap waste, is a significant and problematic component of domestic wastewater due to their potential to plug sewers. There are some fats, oils, and grease in residential wastewater; however, the main sources are commercial and industrial wastewaters. In a typical community, restaurants are generally the largest source of grease. Grease trap waste and food waste can create additional quantities of digester gas that can be used to create electricity. Food solid wastes have been identified as having potential for energy recovery, but only recently has there been activity to utilize this resource by landfill gas capture and energy conversion, composting, or use in wastewater treatment plant digesters. Wastewater treatment plants digesters are used for waste solids stabilization, reduction and methane biogas energy recovery to engine generators or fuel cells. The digesters can then provide a portion of electricity needs for pumps, aeration and other uses at the treatment plant History Historically, grease trap waste has been problematic in sewer systems and it is estimated that nearly 40 percent of all sanitary sewer overflows are related to grease trap waste that enters the sewer system. In June 2001, Barry Newman of the Wall Street Journal, wrote "America's sewers are in a bad way. Three-quarters are so bunged up that they work at half capacity, Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-1

132 causing 40,000 illegal spews a year into open water. Local governments already spend US$ 25 billion a year to keep the sewers running." Most communities have adopted requirements for the installation of grease traps on laterals for restaurants and other commercial and industrial establishments that have greasy waste. The traps hold much of the waste grease and prevent it from entering the collection system. However, grease traps must be periodically emptied to remove the accumulated grease or the traps will start to pass grease into the collection system. In 1998 the National Renewable Energy Laboratory sponsored a study titled Urban Waste Grease Resource Assessment which investigated the sources and quantities of grease in 30 metropolitan areas across the United States. The communities included in the study ranged in size from a population of 83,000 to nearly 4 million. Based on the results of this study, the average grease production of trap grease is pounds per person per year. The same study found that food scrap waste accounts for 12.4 percent of the total municipal solid waste that is generated in the United States. This represents over 31 million tons of food scrap waste generated in Currently, only about 2.5 percent of food waste is diverted from landfills nationwide. The majority of food waste that is diverted is used for composting, which requires large amounts of land and releases volatile organic compounds (greenhouse gases) into the atmosphere Technical Description As an alternative to landfill disposal, both grease trap waste and food scrap waste are ideal for anaerobic digestion at wastewater treatment plants, assuming there is excess digester capacity. Anaerobic digestion has been successfully used for many years to stabilize a range of organic solid wastes and provide benefits of reduced demand on landfill space and a renewable energy source in the form of methane gas. Technically, the challenging aspects to using grease trap waste and food scrap waste are related to receiving, conditioning, and feeding the waste into the anaerobic digester. Most grease receiving systems will have means for transferring loads from trucks used to haul the waste and an associated containment area for spillage and odor control. This is typically followed by a heavy debris separator (rock trap), grinder or chopper pump, holding tank, and metering pump system. The level of processing required can vary significantly depending on the characterization of the waste stream. Food wastes in particular can have significant quantities of material that would not be suitable for anaerobic digestion such as plastic, metals, and other material that could harm mechanical equipment. In general, source separated food wastes are most desirable as this type of waste requires minimal processing at the wastewater treatment plant. This simplified processing system may consist of a hopper outfitted with a gravity fed grinder and progressive cavity pump for waste transfer. It is important that the waste stream be metered into the digester to prevent upset of the biological treatment process due to over feeding. Figures 32 and 33 illustrate systems that are being used successfully to receive and digest grease trap wastes and food scrap wastes. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-2

133 This schematic below illustrates a proposed grease receiving station for Encina and the associated process diagram. Figure 32: Grease Trap Waste Receiving Schematic This schematic illustrates the proposed food waste receiving/processing diagram and equipment. Figure 33: Food Waste Receiving and Processing Schematic Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-3

134 Vendors In general, grease trap waste and food scrap waste receiving facility designs are site specific. Land availability, waste characterization, waste hauler preferences, aesthetic concerns (visual, audible, odor related), and treatment plant configuration are some factors that are used to determine the ultimate configuration of the receiving facility. Kennedy/Jenks has experience designing these types of facilities Size and kwh Production Based on operational experience at wastewater treatment plants, it is estimated that an anaerobic digester will produce roughly 13 cubic feet of digester gas for every gallon of grease trap waste received (3,100 CF per wet ton of grease). This production estimate is made based on a grease content of 18 percent in the trap waste, 95 percent volatile content in the grease, 60 percent volatile solids destruction in the digester, and 15 cubic feet per pound of volatile solids destroyed in the digester. Methane content in digester gas can vary, but is typically around 600 BTU per cubic foot. It is important to consider the adequacy of digester mixing before grease digestion is started since this waste stream will have a tendency to form a mat on the top of the digester if sufficient mixing energy is not available. Based on data from a study performed by East Bay Municipal Utility District (EBMUD) titled "Anaerobic Digestion of Food Waste" dated March 2008 (EPA Funding Opportunity No. EPA- R9-WST ), digester gas production from food waste can vary from 2,500 to 4,300 cubic feet of methane per wet ton of food waste. The food waste that was received at EBMUD had a total solids content of 28 percent. It is suggested in the report that anaerobic digestion of food waste will yield more gas than municipal wastewater sludge because of higher volatile content in the food waste and higher volatile solids destruction rate associated with more biodegradable food waste. The reported volatile fraction of the food waste used in the study was 86.3 percent and the volatile destruction rate in the bench-scale digester was 73.8 percent. A preliminary market assessment for grease trap waste and food scrap waste was performed to determine the availability and willingness of haulers to use a facility at Encina. The market assessment consisted of a telephone survey of waste haulers in the area. In general, haulers are eager to use a facility at Encina because of its close location to urban areas where the waste is generated. The proximity of the plant to the waste sources results in less hauling time and fuel costs for the hauling companies. In addition, the waste haulers were very interested in a disposal site within San Diego County, because there currently is no site within the County, and all of the haulers transport north to San Bernardino, Orange County, Riverside, and Los Angeles. Data obtained during the preliminary market assessment is summarized in Table 27. The listed tipping fees are based on the quantity of grease delivered to the site measured in gallons. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-4

135 Table 27: Grease Hauler Market Assessment Hauler Contact Contact Info Quantity (gpd) Atlas Pumping Service Baker Commodities Liquid Environmental Wright Septic Tank Service Bill Anderson Charlie Hernandez ce.com ext 3016 mmodities.com Current Tipping Fee ($/gal) 25,000 $0.08 5,000 ~ 7,000 $0.07 (if not taken to their own facility) Truck Type Vacuum truck 5500 gals, rear dump 6" gravity hoses gal trucks, rear dump 6" gravity hoses Level of Interest Dana King ext 14 9,000 $0.02~$0.05 High Scott Wright ,400 ~ 2,800 $0.071 Vacuum truck 5500 gals, rear dump 4"~6" gravity hoses As an example, based on the market assessment, Encina could receive 5 loads of grease trap waste and one load of food scrap waste per day. The amount of kwh produced could be estimated in Table 28. At the current average price for electrical energy purchases of $0.19 per kwh, the estimated increased annual production of 3,059,000 kwh would reduce energy purchases by $581,000 per year. High High High Table 28: Estimate of Digester Gas and Energy Production 5 Grease Trap Waste Loads = 15,000 gallons 15,000 gallons grease trap waste x 13 CF digester gas / gallon of waste = 195,000 CF 1 Food Scrap Waste Load = 10 tons 10 tons food scrap waste x 5,300 CF / wet ton of food waste = 53,000 CF Total Gas from Waste Streams = 248,000 CF 248,000 CF Digester Gas x 600 BTU/CF = 1488 therms 1488 therms x kwh/therm = 43,568 kwh Electrical Generation Efficiency 30% = x 43,568 kwh (reciprocating engines) 13,070 kwh Generator Availability 90% x 13,070 kwh = 11,765 kwh Daily Electrical Generation Potential = 11,765 kwh Annual Electrical Generation Potential* = 3,059,000 kwh * assuming 260 working days per year Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-5

136 Examples of Grease Trap Waste and Food Waste Projects The City of Millbrae has been successfully receiving and co-digesting hauled grease waste since January of The City uses the additional digester gas to fuel a 250 kw microturbine, which can serve 80 percent of the wastewater treatment plant electrical demand. The City currently receives 3000 gallons of grease trap waste per day at their wastewater treatment plant, which has an average dry weather treatment capacity of 2 MGD. The City of West Lafayette, Indiana began receiving food scrap waste at their wastewater treatment facility from Purdue University in June 2009 and will begin receiving regular loads of grease trap waste in The waste receiving station was originally designed for grease trap waste receiving but was retrofitted to accept food waste from Purdue food service areas. The City currently receives approximately 1 ton per day of food scrap waste and is looking to expand beyond Purdue University to other food waste producers in the City. The City is also expected to receive roughly 10,000 gallons per day of grease trap waste. The City uses the biogas produced in their anaerobic digesters to run microturbines that supply some of the electricity and heat used by the treatment plant. East Bay Municipal Utility District s (EBMUD) main wastewater treatment plant in Emeryville, California has been successfully co-digesting food scrap waste for several years. The average annual wastewater flow to EBMUD s wastewater treatment facility is currently 80 MGD. EBMUD uses the additional digester gas to run three dual-fuel engines rated at 2.15 MW each. The cogeneration plant is capable of generating 6.45 MW. During peak power production, the system can put 10 percent of the power generated back onto the utility grid. Powering the plant with biogas-generated electricity and using recovered digester heating saves EBMUD about $2,000,000 annually Potential Funding Sources The funding incentives for installing a waste receiving facility are geared to the ultimate use of the digester gas that is produced. Energy production incentives could be used to help fund a combined heat and power system. The improvements directly associated with waste receiving (i.e. pumps, tanks, and site improvements) are not eligible for incentives. However, energy efficiency incentives could be used to lower the cost of project components such as premium efficiency pumps and motors. Waste receiving can generate funds through tipping fees, which are charged to the haulers who use the waste receiving station. Tipping fees for grease trap waste can vary widely from $0.02 per gallon to $0.25 per gallon. Typical tipping fees for landfills that would normally take food waste range between $30 and $50 per ton. Based on the preliminary market assessment, tipping fees for grease trap waste at EWA could range from $0.02 to $0.08. Tipping fees for food waste could range from $30 to $50 per ton. Table 29 provides an example of the potential revenue from tipping fees. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-6

137 Table 29: Estimated Revenue 5 Grease Trap Waste Load / day = 15,000 gallons 15,000 gallons grease trap waste / day x $0.05 / gallon = $750/day $750 / day x 260 days / year = $195,000/year 1 Food Scrap Waste Load / day = 10 tons 10 tons food scrap waste / day x $30 / ton = $300/day $300 / day x 260 days / year = $78,000/year Total Tipping Fees = $273,000/year Cost Probable capital cost for a waste receiving station that could receive and process grease trap waste and food waste can range from $1 million to $1.5 million based on experiences at othjer facilities. In general, this would include a storage tank, metering and mixing pumps, rock-trap, food waste grinder, glass-lined ductile iron pipe, odor scrubber, waste measuring equipment, and concrete receiving area for truck unloading. The range in cost is primarily driven by above or below ground storage. Probable cost has an accuracy of plus 50 percent to minus 30 percent. If larger digesters that already have pump mixing systems are utilized, they will likely not require mixing upgrades. However, if smaller digesters (currently not in service) are utilized, they will require improvements to their pump-mixing systems. The typical cost for an external pump-mixing system for digesters of this size is $1.5 million. The estimated capital, operations and maintenance costs for a waste receiving station is summarized in Table 30. The estimated unit cost based on electrical energy from produced gas is also provided. Table 30: Waste Receiving Station Estimated O&M Cost Item Project Cost Installed cost of waste receiving station $1,000,000 Contingencies + Engineering costs $400,000 (40%) Total installed cost: $1,400,000 Starting O&M costs (3% escalation) $0.04 (cents/kwh) First year cost power (cents/kwh) $ Year average cost (cents/kwh) $0.06 Equivalent Value cost (cents/kwh) $0.05 Assumptions: 5 grease load (3000 gallons) and 1 food load (10 wet tons) received everyday. Co-generator availability of 90%. Estimated O&M costs include labor power and equipment repair. Co-generator operational costs not included here. Only costs associated with grease waste and food waste receiving are included. Project costs are based on assumption that the waste receiving tank is above ground. 20-year equipment life is assumed. Estimated tipping fees have been excluded from the estimated electrical energy unit costs shown above. The value of implementing a waste to energy program can be further evaluated by comparing the cost of producing biogas with the cost of purchasing natural gas. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-7

138 The increased estimated increase in production of biogas is 1,488 therms per day or 533,000 therms per year. As shown in the cost template in Appendix C, the first year total cost (including debt serve and operating costs) is estimated to be $260,000, a unit cost of $0.48 per therm without allowance for potential tipping fees. A lower unit cost would be achieved if tipping fees are implemented. The cost of natural gas is considerably higher ($0.90 per therm) Community Impacts In general, grease trap waste and food waste digestion are viewed as positive solutions to two problematic waste disposal issues and enjoy good community acceptance. More and more communities are enacting ordinances that require restaurants and business owners to install pre-treatment devices (traps and/or interceptors) to reduce the amount of grease trap waste that is discharged to sewers. This will result in growing demand for suitable places to dispose of the grease trap waste collected by these pre-treatment devices and wastewater treatment plants are a logical receiving point for this waste. Food waste diversion from landfills is generally viewed as a positive way to reduce volume to landfills thereby extending their lives, and recovery energy from this constant fuel supply. Collecting food waste at wastewater treatment plants also has the advantage of reducing the land that would otherwise be needed if the food waste were used for composting. As well, using the digester gas to generate electricity is considered a renewable resource which also enjoys wide community support Environmental Impacts Air: Impacts to air quality related to receiving and processing grease trap waste and food waste should be minimal. The most notable impact would be potential odor emissions from the receiving area. Both grease trap waste and food waste can be odorous. Odor emissions can be mitigated by containing the receiving area and using equipment that minimizes the possibility of odor emissions. Based upon conversations with grease hauling companies during the initial screening, there currently are no grease receiving stations in San Diego County. Therefore, the haulers must truck the grease collected within San Diego County to Riverside, Orange, and Los Angeles Counties for disposal. On average, a one-way trip from Carlsbad to these areas is approximately 60 miles. Implementation of grease receiving at Encina would result in significant reduction in air emissions due to hauling and transportation. Land: As compared to alternative disposal methods, receiving grease trap waste and food waste at a wastewater treatment plant will require less land than landfill disposal or composting. Land requirement for the receiving facilities at wastewater treatment plants is relatively small (roughly 0.5 to 1.0 acre, including paved receiving area). Water: Water usage for a waste receiving facility is typically for wash down and dilution liquid for food waste (approximately 200 gpd). This water can be treated effluent from the wastewater treatment plant or potable water. Impacts to surrounding surface water features should be minimal since runoff from the receiving facilities and wastewater treatment plant are typically routed back to the plant for treatment. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-8

139 Noise: Noise can be a concern for the receiving station if the plant is located near to a residential community. Noise from the receiving area can be mitigated by enclosing the area or providing a sound wall. Noise on surrounding surface streets could be substantial from increased truck traffic. If noise on surrounding surface streets is a concern, restricted hauling times can mitigate the impact. Aesthetic/Visual: Visually the receiving area will not stand out from other industrial systems at a wastewater treatment plant. If aesthetics is an issue, equipment can be screened or enclosed. Waste By-Products: The waste product that is generated from digestion of grease trap waste and food waste is typically dewatered for further processing or disposal. Dewatered solids can be disposed of in landfills, processed further into soil amendment, or converted into fuel (i.e. cement kiln fuel) Greenhouse Gas Impacts Adding grease trap waste and food waste to digesters increases methane production, this in turn can be used to increase electrical generation. The methane is burned, which releases carbon monoxide thereby increasing greenhouse gas (GHG) emissions. However, replacing the electricity purchased from a WWTP s utility provider (non-biogenic GHG) with biogas produced electricity (biogenic GHG) would result in an overall reduction of greenhouse gas emissions. Using this process could replace 3.05 mwh of current annual electricity needs. Using SDG&E s current emissions factor of lbs of CO 2 /MWh, non-biogenic carbon dioxide emissions would be reduced by an estimated 1,083 metric tons of CO 2 per year Operational Impacts A waste-to-energy program will have substantial operational and staff impacts. Impacts come from the construction, operations and maintenance of the receiving station, administration of the grease trap and food waste program, as well as the generation equipment. The impacts of the generation equipment are discussed in the IC Engine, Fuel Cell and Microturbine assessments. The receiving station requires a substantial footprint for the process equipment, the hauler interconnection equipment, and the drive-up pad. Careful consideration must be given to the design to minimize impacts on existing plant operations. The receiving and odor control equipment will require frequent cleaning and periodic maintenance. However, the hauler interface can be automated with a card-swipe system that will not require staffing, and can therefore be operated 24/7/365. Operating a grease trap and food waste receiving program will require additional staff for program administration. The program must be promoted, the haulers will need to be permitted and monitored, and the invoices will need to be prepared with assistance from the IT and accounting departments. There is also a risk that haulers could bring in toxic or other undesirable materials to the facility that could harm the digestion process. This risk can be mitigated either by clear rules, strict manifest requirements for waste haulers, and/or sampling of the waste received. Testing of the sampled waste usually is not done unless a hauler created a problem with the digester. This sampling technique has been used by other agencies as an effective risk management tool. To Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-9

140 ensure accountability samples could be held for approximately 20 days or the equivalent digester detention time, whichever is greater. Operational impacts associated with use of a grease trap and food waste program are provided in Table 31. Table 31: Operational Impacts of using Grease Trap Waste/Food Waste Parameter FTE 1) / Labor Maintenance Requirements Boilers Air Permit Compliance Effluent Discharge Permit Compliance Need for Heat 1) Full time equivalent Operational Impact 0.40 fulltime staff equivalents (FTE) increase (when coupled with a gas to energy system). This assumes an automated card entry system for hauler access and monitoring. Additional support is required from management, IT and accounting to administer the program. Equipment cleaning and minor maintenance associated with screening and odor equipment. Not applicable with grease trap and food waste receiving. May be required depending on the size of the gas-toelectricity technology selected. Minor odor issues possible. Not applicable Hot water is needed to help wash down the grease from receiving tank walls and to flush line to digester Summary of Advantages and Disadvantages Advantages and disadvantages of a waste to energy program at EWA are summarized as follows: Advantages: Renewable power production Waste diversion Reduction in carbon footprint Fuel Self generation at a cost lower than purchase of natural gas ($0.48 per therm vs $0.90 per therm) Disadvantages: Increased loading on digesters Increased maintenance costs Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-10

141 Potential odor concerns Cell Lysis Introduction Cell lysis is a method of cellular disruption causing the release of the biological material contained within the cell walls. This relates to the field of wastewater treatment as a pretreatment process for combined or waste activated sludge prior to anaerobic digestion; subjecting the sludge to a process which causes cell lysis, or cellular destruction, prior to digestion, is believed to increase volatile solids reduction and biogas production. These advantages can translate to reduced residual solids after digestion, which results in reduced dewatering, dryer, and biosolids disposal operations. Increased volatile solids destruction in the digester will also increase biogas production. The cell lysis equipment is typically a packaged skid mounted factory manufactured system History Cell lysis for pre-treatment of wastewater sludge is considered a fairly new process that has been more commercially marketed in recent years. There are several forms of cell lysis technologies, some of which include using ultrasonic sound waves, high pressure differential, and pulsed electric field. Historically, the primary driver to install these types of systems was to increase digester capacity by improving digester performance. Another typical driver is to reduce volume of residual solids produced by the wastewater treatment process. In more recent years, focus has shifted to biogas enhancement and the creation of more renewable energy from wastewater sludge. Another recent development is the advantage of using the pre-treated sludge to replace the need for supplemental carbon addition. Supplemental carbon addition is typically required in biological nutrient removal systems to provide appropriate nutrients to drive the denitrification process Technical Description Cell lysis, or cellular disruption, is accomplished by piercing, shearing, or rupturing the cell membrane and causing the cell to release its contents. Cell lysis is accomplished via mechanical or physical methods, including: Mechanical Agitation Pressure Sonication Ultrasound Nitrogen Burst Lysis Method Example cell lysis systems are shown in the following figures. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-11

142 Figure 34: OpenCEL s Focused Pulsed (FP) Technology OpenCEL s Focused Pulsed (FP) technology sends pulses of high voltage electricity to bombard waste as it flows between two electrodes. Typically, the bombardment lasts 20 to 100 microseconds. The bombardment breaks down the cell membrane, which then becomes permeable to small molecules. As these molecules penetrate cells, they swell, and the membranes rupture. The process is known as electroporation or lysis. The Crown Solids Disintegration System (Figure 35) passes sludge through a high pressure disintegration nozzle assembly where microbial cells are ruptured, releasing enzymes and destroying filamentous microorganisms. A recirculation tank is used to mix treated and untreated solids on a continuous basis optimizing the enhanced production of biogas. Figure 35: Crown Solids Disintegration System Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-12

143 Vendors Two cell lysis vendors were contacted for this study: OpenCEL and Siemens Water Technologies (Crown Process). OpenCEL is an Environmental Biotechnology Company with a proprietary cell lysis technology for improved processing of wastewater biosolids. OpenCEL processes uses Pulsed Electric Field (PEF) technology directly attacks the basic building blocks of all cell membranes and walls. OpenCEL s proprietary technology, Focused Pulsed (FP), applies high frequency electrical pulses to break open biosolids cell membranes, releasing soluble material that can more readily be reduced and converted to energy. OpenCEL has been investigating the commercial application of PEF sludge pre-treatment since OpenCEL first pilot-tested their technology from1998 to 2000, at the Lancaster, Ohio wastewater treatment facility. In 2007, OpenCEL started full-scale operations demonstrating their technology at City of Mesa s Northwest Water Reclamation Plant (NWWRP) in Arizona. Siemens Water Technology is the North American supplier and service provider of the Crown sludge disintegrator system, manufactured by Biogest AG of Germany. The sludge processing system uses a patented cell lysis process, which includes a progressive cavity pump, homogenizer, disintegrator nozzle assembly, recirculation tank, discharge pump, and control panel. Generally, the system is sized to pretreat 33% of the average daily sludge fed to the digester Size and kwh Production The size of the cell lysis system depends on the technology and the sludge flow volume for which the system is sized. Siemens Crown Solids Disintegrator In their proposal dated September 16, 2009, Siemens proposed a Crown system sized to treat roughly 33% of the average combined thickened waste activated sludge (WAS) and primary solids (PS) sent to the digesters daily, (197,594 gpd x 33% = 65,206 gpd or 46 gpm). The remaining 67% of combined sludge would continue to go directly to the digesters. The Crown system would be installed on the feed line to the digesters, after the sludge thickeners. See Figure 27 for a schematic of the proposed installation. As shown in Figure 36, the treatment system draws WAS and PS from a recirculation tank that is placed in the digester delivery piping system. The treatment system is sized to treat 33% of the total rate. The recommended flow rate is based on experience developed at operating facilities and provides what has been found to be a good balance between capital and operating costs and increased gas production. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-13

144 Figure 36: Crown Solids Disintegration System Basic Process Flow Diagram The proposed skid mounted Crown system has approximate dimensions of 16 feet x 8 feet x 8.5 feet tall. See Table 32 below for the list of equipment supplied on the skid. Table 32: Crown System Equipment Components Parameter Value Units Recirculation Tank 1,000 Gallons Recirculation Tank Mixer 10 Horsepower Macerator/Homogenizer 3 Horsepower Pressurization Pump 30 Horsepower High Speed Mixer ( 2 units) 5 Horsepower (ea.) Number of Crown Disintegrators 1 -- Digester Feed pump for Conditioned Sludge 5 Horsepower The kwh production is directly related to the increase in digester gas production as a result of the cell lysis treatment. The Crown process reports an increase in biogas production of 10% and an increase in volatile solids reduction of 15%. Table 33 provides an estimate of digester gas and energy production that could be achieved with the reported enhancements provided by this technology. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-14

145 Table 33: Estimate of Digester Gas and Energy Production EWPCF Current Average Digester Gas Production = 600,000 CF/day Increased Digester Gas Production (10%) x 600,000 CF/day = 60,000 CF/day 60,000 CF Digester Gas x 600 BTU/CF = 360 therms 360 therms x kwh/therm = 10,540 kwh Electrical Generation Efficiency 30% (reciprocating x 10,540 kwh = 3,162 kwh engines) Generator Availability (90%) x 3,162 kwh = 2,846 kwh Added Daily Electrical = 2,846 kwh Generation Potential Added Annual Electrical Generation Potential 1) = 740,000 kwh 2) 1) Assumes cell lysis equipment availability is 70% 2) Process parasitic loads have not been deducted According to their proposal, Siemens expects the Crown to increase the destruction of volatile solids remaining 15%. Based on the data provided, the digester currently runs at around 67.7% volatile solids. With the expected results of the Crown process, the volatile solids would decrease to approximately 57.5% remaining. According to their proposal, this will result in a reduction in solids production by roughly 3,700 lbs/day. The benefit in this reduction to Encina is reduced solids handling (i.e. dewatering and drying) and disposal costs. In addition, Siemens expects the dewaterability of the solids from the digester to improve from 23% (current dryness being fed to the dryer) to 27% dry solids. This projected benefit has not been verified for EWPCF solids. The benefit in increased dewaterability to Encina is improved dryer operations and the associated energy savings. Based on Siemens analysis of dryer operations, they anticipate an energy savings of approximately $100,000 per year for reduced dryer runtime. These assumptions would have to be verified by piloting the Crown process system. It should also be noted that loading a dryer with solids dryer than 25% may cause the dried product to be more prone to becoming airborne and impact dryer operation in other ways. OpenCEL In their proposal, OpenCEL proposed their Focused Pulse (FP) Model 20 system sized to treat the entire flow of waste activated sludge (WAS) being fed to the digesters (76,000 gpd or 53 gpm). Their system is designed to treat WAS; primary solids do not receive treatment. Therefore, the system would treat approximately 38% of total 197,597 gpd of sludge fed to the digesters. The primary sludge would continue to go directly to the digesters as presently operating. Figure 37 provides a schematic of the proposed installation. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-15

146 Figure 37: OpenCEL Focused Pulsed (FP) Model 20 System Basic Process Flow Diagram The proposed skid mounted OpenCEL system has approximate dimensions of 15.4 feet x feet x 6 feet tall. Table 34 includes a list of skid mounted equipment. Table 34: OpenCEL System Equipment Components Parameter Value Units High-Voltage Power Supply (2 units) 150 kw (ea.) Modulator (converts high voltage 1 -- energy into pulsed format OpenCEL Treatment Chamber 1 -- Closed Loop Chiller 10 Ton Rotary Lobe Pump 4 inch dia. Multi-grinder 4 inch dia. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-16

147 The kwh production is directly related to the increase in digester gas production as a result of the cell lysis treatment. The OpenCEL system reports a biogas production increase of 40% and a volatile solids reduction increase of 24%. Table 35 provides a summary of possible digester gas and energy increased production claimed by suppliers of this technology. These improvements seem high; we suggest that a pilot system be installed to confirm predicted benefits. Table 35: Estimate of Digester Gas and Energy Production EWPCF Current Average Digester Gas Production = 600,000 CF/day Increased Digester Gas Production x 600,000 CF/day = 240,000 CF/day (40%) 240,000 CF Digester Gas x 600 BTU/CF = 1,440 therms 1,440 therms x kwh/therm = 42,163 kwh Electrical Generation Efficiency 30% x 42,163 kwh = 12,650 kwh (reciprocating engines) Generator Availability (90%) x 12,650 kwh = 13,385 kwh Added Daily Electrical = 13,385 kwh Generation Potential Added Annual Electrical Generation Potential 1) = 3,480,000 kwh 2) 1) Assumes cell lysis equipment availability is 70% 2) Process parasitic loads have not been deducted According to information provided by the manufacturer, the treatment process has been shown to increase the destruction of volatile solids by 24%. This will result in a reduction in solids production. The benefit in this reduction is reduced solids handling (i.e. drying and dewatering). In addition, OpenCEL expects a savings in heat required for digester heating. As part of the OpenCEL treatment process, the WAS is heated and the WAS delivered to the digester would increase compared to the current operating temperature reducing required heating. This would have limited benefit to EWA due to the current excess heat produced by IC engines Examples of Cell Lysis Projects The following are examples of installations for cell lysis treatment. OpenCEL City of Mesa, AZ Northwest Water Reclamation Plant (NWWRP) Siemens Crown Solids Disintegrator The vendor reports several existing installations in Europe. A list of such installations was not provided. Currently no installations within the United States Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-17

148 Potential Funding Sources The cell lysis equipment is not eligible for current incentive programs Cost Cell lysis technology vendors provided cost estimates for their proposed systems summarized in the following paragraphs. Siemens Crown Solids Disintegrator In a proposal prepared for EWA on September 16, 2009, Siemens provided a budgetary price for the Crown disintegration system, skid mounted equipment, and services for $1,040,000. Siemens anticipates an average power draw for the Crown system to be approximately 35 kw. Assuming an electricity rate of $0.19 / kw-hr, this equates to an operating cost of roughly $58,000 per year. Annual O&M costs for the system are estimated to be approximately $15,000. OpenCEL In a proposal prepared for EWA dated January 2010, OpenCEL provided a budgetary price for a complete OpenCEL Focused Pulsed (FP) Model 20 system for $2,100,000. A complete OpenCEL Focused Pulsed (FP) Model 20 system consists of the following major subsystems: Two 150 kw high-voltage power supply (HVPS) to convert incoming line voltage (typically 480 volts) into the required high voltage for the FP process. One modulator to switch the high-voltage energy into a pulsed format. Treatment chamber enclosures where a flowing liquid is treated by pulsed, high-voltage fields. A control system to operate the FP unit and provide an interface between the OpenCEL and plant SCADA systems. Pumping and grinding equipment required to control the delivery of material to the FP system. A 10-ton closed loop chiller to provide cooling for the electrical equipment. Startup services including control system integration, calibration and operator training. The estimated operations and maintenance cost for cell lysis equipment is summarized in Table 36. Detailed cost templates are provided in Appendix C. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-18

149 Table 36: Cell Lysis Systems O&M Costs Item Crown Process OpenCEL Crown System costs $1,000,000 $2,100,000 Installation, Contingencies + Engr (40%) 400,000 $840,000 Total installed cost: $1,400,000 $2,940,000 Annual O&M costs 1) $70,000 $340,000 First year cost power 1) $0.15 $0.18 (cents/kwh) 10-Year average cost 1) $0.15 $0.19 (cents/kwh) Equivalent Value cost 1) (cents/kwh) $0.13 $0.16 1) Cost of additional power produced from cell lysis; cost includes cell lysis process only Community Impacts The addition of cell lysis treatment does not impact the community Environmental Impacts Air: Impacts to air quality related to the increase in digester gas production. A technology for converting the increased digester gas into energy would have to do so in accordance with the APCD permit. Therefore, the cell lysis processes do not have direct impacts to air quality. Land: The cell lysis processes do not directly impact land. Water: The cell lysis processes do not impact water quality. Noise: The cell lysis equipment can be housed within existing or new buildings to minimize any noise impacts to the plant and surrounding areas. Aesthetic/Visual: The cell lysis equipment would be located on-site at the treatment plant. The skid mounted equipment can be housed within an enclosed building or outdoors. The Crown process has skid mounted equipment size of approximately 16 feet x 8 feet x 8.5 feet tall. The OpenCEL process has skid mounted equipment size of approximately 15 feet x 22 feet x 6 feet tall. Equipment can be housed within existing or new buildings to minimize aesthetic and visual impacts to the plant. Waste By-Products: The cell lysis processes do not create additional waste by-products Greenhouse Gas Impacts Implementation of cell lysis treatment will have a net positive reduction in greenhouse gas emissions. While additional biogas will be created, this biogas will be captured and used on-site in the form of electricity or biogas to fuel equipment. The new process and equipment will require electricity to operate, but the utilization of biogas will offset the electricity demand. In addition, the benefit of reduced solids results in less run time for the dryer. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-19

150 Operational Impacts Operational impacts are summarized in Table 37. Table 37: Operational Impacts of using Cell Lysis Parameter FTE 1) / Labor Maintenance Requirements Boilers Air Permit Compliance Discharge Permit Compliance 1) Full time equivalent Operational Impact 0.1 FTE increase (when coupled with a gas to energy system). Equipment cleaning and minor maintenance associated with piping and equipment. Not applicable Not applicable Not applicable Summary of Advantages and Disadvantages Advantages: Increased digester gas production yielding increased self generation of energy Increased destruction of volatile solids yielding decrease in solids handling and disposal costs Increase dewaterability increasing operational efficiency of dryer and costs For OpenCEL process, reduced demand for digester heating Disadvantages: Capital cost Additional equipment and process leads to increased operational needs Potential for operational complexity and fine tuning of digester operations Uncertain performance based on limited experience; a pilot plant would be required Digester Train Modifications Currently, EWA uses anaerobic digesters to stabilize primary and waste activated sludge from the wastewater treatment process. For this study, multi-stage mesophilic anaerobic digestion was identified as a method that should be evaluated for increasing digester gas production. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-20

151 Description Phased anaerobic digestion methods have been used and investigated in several forms over the years to improve on digester performance mainly in the areas of volatile solids reduction and pathogen control. For the purpose of this study staged mesophilic digestion and acid/gas phased digestion were considered as possible ways to improve biogas production at EWA Staged Mesophilic Digestion: The staged mesophilic digestion process uses two mesophilic digesters that are operated in series. The first digester is typically designed with a solids retention time (SRT) of 7 to 10 days (Metcalf & Eddy, 2003). The solids retention time in the second reactor can vary and can be relatively short since most of the process considerations are satisfied in the first reactor. Both stages are heated and mixed (WEF, 2010). Research on staged mesophilic digestion does not provide clear evidence that biogas production will increase significantly (Metcalf & Eddy, 2003). It has been found that two-stage mesophilic digestion does provide benefits in improved biosolids stability, reduced potential of short-circuiting, and reduced pathogens. It was also noticed that this type of process has less capacity to accommodate large variations in loadings than a single stage system (WEF, 2010) Acid/Gas Phased Digestion: In the acid/gas digestion process there are two anaerobic reactors. The first reactor is used to maintain conditions suitable for acidogenesis and the second reactor is used for methanogenesis. The first phase is operated at a ph of 6 or less and a SRT of 1 to 3 days. The second phase is operated at a neutral ph with an SRT of 10 days or greater (Metcalf & Eddy, 2003). Both stages are heated and mixed. Where the acid/gas digestion process has been studied, significant increases in volatile solids reduction has been reported in some cases but not others. The consistent improvement noted in the research as a result of implementing this process was a reduction in digester foaming (WEF, 2010) Reason for Limited Information Development Based on the limited research that was conducted for this evaluation, it is not recommended that phased digestion be considered further as a means to increase digester gas production. It appears from literature review that increases in volatile destruction cannot be reliability achieved by implementing phased digestion. It is possible that the existing smaller anaerobic digesters (not currently in use) could be retrofitted with a new mixing system and used as a first stage for an acid/gas digestion process. However, the cost for the capital improvements and operating costs associated with an additional digester (mixing system operation, digester equipment maintenance, and periodic digester cleaning) do not seem justified given the uncertain potential of increasing digester gas production. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-21

152 If there were other reasons to go to phased digestion such as reduced digester foaming, then the benefits of this process could be investigated further References Metcalf and Eddy, Inc., Wastewater Engineering Treatment and Reuse, Fourth Edition (2003), McGraw Hill, Boston, MA. WEF Design of Municipal Wastewater Treatment Plants, WEF Manual of Practice No. 8, Fifth Edition (2010), Water Environment Federation, Alexandria, VA. 5.2 Other Support Facilities Sludge Heating as a Dewatering Aid Description Preheating biosolids to 60 C / 140 F or higher before dewatering alters the characteristics and makes it easier to dewater. Studies have shown this type of thermal conditioning of biosolids prior to dewatering via centrifuge has contributed to the increase in solids concentration by nearly six percent History The San Diego Metro Biosolids Center (MBC) implemented the concept of biosolids pre-heating prior to dewatering via centrifuge. The MBC receives solids from Point Loma Wastewater Treatment Plant (PLWTP) and North City Water Reclamation Plant (NCWRP). MBC provides thickening and digestion of the raw sludge generated at NCWRP; and dewatering of the anaerobically digested biosolids from both PLWTP and NCWRP. The biosolids preheating concept was implemented at MBC over a decade ago. MBC planned dewatered solids in the 28-30% solids range and it was uncertain if existing centrifuges would be able to achieve such solids concentration levels in the dewatered cake. The preheating concept was implemented using waste heat from the onsite co-generation facility utilizing a spiral heat exchanger to heat the anaerobically digested biosolids from 94 o F to 120 o F. Viscosity of the biosolids occurred making improving solids removal in the centrifuges. Initially, this conditioning process helped improve the biosolids from 28-29% to 31-32%. However, this process was discontinued at MBC due to maintenance issues with the thermal conditioning equipment. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-22

153 Figure 38: Alfa Laval Spiral Heat Exchanger Technical Description Pre-heating of digested biosolids to improve solids concentration has been implemented in several facilities throughout the US. Literature states the pre-heating processes helped improve dewatered solids concentration by 6%, where as the processes implemented in Europe helped improve solids concentration by only 2 3% which is consistent with the improvement in dewatered solids concentration achieved in San Diego s MBC. However, there are several disadvantages to this process. In addition, to the frequent plugging of the spiral heat exchangers, transportation of the biosolids cake was more difficult. Odors issues have also been experienced. Another downside to pre-heating sludge to over 140 o F is that it may cause an increase in soluble BOD in the centrate. This secondary effect was not analyzed at San Diego s MBC as the biosolids pre-heating process was discontinued after a short period of implementation. The literature states that if the waste heat is obtained from a source that would otherwise be wasted, biosolids preheating may be an economical method of thermal conditioning to improve the dewatering process. It should, however, be noted that San Diego s MBC discontinued the process due to maintenance issues as noted above and that these issues outweighed the benefits of a 2-3% improvement in the solids content of the dewatered biosolids Vendors Alfa Laval (Sweden), Premium Process Equipment (offered by HESECO (US)), and GOOCH THERMAL SYSTEMS (US), are some of the vendors that manufacture spiral heat exchanges Reason for Limited Information Development Literature and data from treatment plants indicates biosolids preheating to 140 o F or higher has a beneficial the solids dewatering process, improving solids concentration by 2 3 %. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-23

154 Disadvantages such as heating costs, maintenance issues, possible increases in soluble BOD in the centrate, and odor considerations outweigh the benefits realized by the pre-heating process Biogas Storage Description Biogas storage is used to dampen gas flow fluctuations due to the variability of the biological processes in digesters. Biogas gas storage can be accomplished in several ways. In a cylindrical digester the gas can be stored under the cover. There are two types of covers used to store gas, floating and membrane. Floating covers can be added to existing digesters and allow the volume of the digester to change without allowing air to enter the digester. Membrane covers consist of a support structure for a small center gas dome and flexible air and gas membranes. An air blower is generally used to pressurize the air space between the two membranes to vary the air volume. In addition to the digester covers, biogas storage can be accomplished using a separate storage device. As with the membrane covers, the separate storage device contains an outer and inner membrane. The dual membrane system uses fans to pressurize the air space between the membranes, providing a consistent pressure to the gas contained in the inner membrane. The inner membrane is free to inflate and deflate depending on the amount of gas to be stored. Gas is normally stored at low pressure, to minimize the cost of the storage system and avoid the cost and maintenance of a gas compressor. Gas storage to hold approximately 15 minutes of production would provide a buffer to minimize the effects of variable gas production on cogeneration equipment. 15 minutes of storage would be about 11,000 cubic feet by Gas holding technology is mature and is available from at least two companies. Siemens offers digester gas holding covers (shown below at the left) and WesTech offers storage covers and a stand- alone membrane storage sphere called the DuoSphere (shown at the right). Figure 39: Biogas Storage Vessels Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-24

155 Estimated raw costs for the biogas storage options (based on providing 11,000 cubic feet of storage) are provided in Table 38. Piping, electrical, instrumentation, site improvements and foundations for the listed storage units are not included. Table 38: Biogas Storage Cost Estimates Item Cost ($) Floating Cover $170,000 Siemens Tank Mounted Membrane Gas Holder $285,000 WesTech DuoSphere Gas Holder $120, Reason for Limited Information Development This option was not developed further due to cost and space constraints at the plant. A similar effect (dampening out the effect of gas production fluctuations) can be accomplished with natural gas blending, at a smaller cost and with a smaller footprint. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 5-25

156

157 Section 6: Technology Evaluations Waste Heat 6.1 Introduction and Purpose In this section, waste heat recovery technologies are indentified and evaluated for consideration in the development of the Updated Energy and Emissions Strategic Plan. Each technology would enable EWA to utilize heat captured from IC engines (or other selected technologies that would produce heat) to reduce dependence on outside energy sources. Information presented for each waste heat technology serves as a basis for development of project scenarios in a subsequent section that considers the combination of one or more technologies that would enable EWA to achieve self generation goals included in the adopted Business Plan. 6.2 Chillers Technical Description Two types of chiller designs are available for producing chilled water from waste heat Absorption chillers Absorption chillers use heat, instead of mechanical energy, to provide cooling. The mechanical compressor in a conventional chiller is replaced by a thermal compressor that consists of an absorber, a generator, a pump, and a throttling device. The refrigerant vapor from the evaporator is absorbed by a solution mixture in the absorber. This solution is then pumped to the generator where the refrigerant is re-vaporized using a waste heat source. The refrigerant depleted solution is then returned to the absorber via a throttling device. The most common refrigerant/absorber combinations are water/lithium bromide and ammonia/ water. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-1

158 High Pressure Waste Heat From Plant Heat Recovery Loop Refrigerant Vapor To Condenser Generator Pump Thermal Vapor Compression Cycle Throttle Valve Low Pressure Absorber Rejected Heat to Cooling Tower Refrigerant Vapor From Evaporator Figure 40: Absorption Chiller Schematic Adsorption chillers Adsorption chillers use a silica gel to adsorb the refrigerant vapor (water) instead of a lithium bromide solution. (Adsorption refers to a process where the molecules adhere only to the surface of a medium while absorption is a process where the molecule is taken internally and not on the surface). The benefit of silica gel is that the gel is not corrosive. Lithium bromide is corrosive. Absorption chillers are a mature technology, adsorption chillers are a relatively new technology. Both chillers have similar coefficients of performance (COP = chiller load/heat input) of approximately For reference a mechanical chiller has a COP of 1.5 to Vendors Trane and Carrier are providers of absorption chillers. Eco-Max is a provider of adsorption chillers. The Eco-Max adsorption chiller is shown in the photo on the below Figure 41. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-2

159 Figure 41: Adsorption Chiller Photo Size and kw Production Absorption chillers are well understood at EWA, because they already have a 100 ton Trane lithium-bromide unit installed in the Power Building. Adding a second chiller of the same capacity as the existing mechanical chiller in the Administration Building would require 2.3 MMBtu/hr. This amount of heat may be available from the IC engines depending on how many IC engines EWA is able to run and the waste heat demands from other operations. The unit use about 5 kw of power. An adsorption chiller would require a similar amount of heat for the same cooling performance. The benefit of the adsorption technology is the silica gel, which requires less maintenance than the lithium bromide solution. The adsorption chiller uses approximately 1 kw of power Cost The expected costs for the Trane Absorption Lithium Bromide Chiller are outlined in Table 39. The costs for a 100 ton adsorption chiller are outlined in Table 40. Each unit would require the installation of hot water piping extending from the energy building to the administration building at an estimated cost of $730,000. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-3

160 Table 39: Estimated Cost of Trane Absorption Chiller Item Project Cost Trane Absorption Chiller $160,000 Installation (35% of Equipment Cost) $56,000 Piping, Valves, and other equip $32,000 Cooling Tower $25,000 Subtotal: $273,000 Engineering costs (20%) $55,000 Total installed cost: $328,000 Table 40: Estimated Cost of Eco-Max Adsorption Chiller Item Eco-Max Adsorption Chiller Installation (35% of Equipment Cost) Piping, Valves, and other equip Cooling Tower Engineering costs (20%) Subtotal: Total installed cost: Project Cost $180,000 $63,000 $36,000 $25,000 $304,000 $61,000 $365,000 Table 41 shows the comparison of the existing mechanical chiller with the Trane absorption chiller and the Eco-Max adsorption chiller. The assumption is that the chiller runs 24/7/365 at a 95 percent capacity factor, and that the O&M costs are relatively equal and thus not included in this analysis. The cost savings is due to a reduced power cost by replacing the current 136 ton electrical chiller in the Administrative building with a nameplate capacity of approximately 137 kw, (electrical power). The Trane absorption chiller would utilize waste heat and about 5 kw; the Eco-Max adsorption chiller would utilize waste heat and about 1 kw of power. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-4

161 Table 41: Cost Comparison of Existing Chiller to Absorption & Adsorption Chillers Option Capital Cost Electrical Energy (kw/yr) Electricity Cost (per yr) Natural gas (therms /yr) Natural gas purchase (cost per yr) Total Annual Energy & Operating Costs 1) Simple Payback in Years Existing $0 1,173,000 $223,000 24,320 $22,000 $245,000 0 Trane $1,400,000 44,000 $8,300 0 $0 $8,300 6 Eco-Max $1,440,000 8,700 $1,650 0 $0 $1, ) Estimated annual operation costs of $27,000 for optional chiller technologies is excluded in simple payback calculation The lower energy use by the absorption and adsorption chillers translates into reasonable financial savings with a 6 year simple payback period Summary of Advantages and Disadvantages Advantages: Reduced operating costs, including electrical and gas energy purchases Increased use of unused waste heat resource Disadvantages: Increased operations complexity Uncertain costs to install and maintain relatively long hot water piping within the existing plant site with existing underground piping that could require unidentified costs to mitigate conflicts. 6.3 Waste Heat Power Generation Technical Description Two technologies are available to generate power with waste heat, organic Rankine cycles and heat recovery hydraulic engines Organic Rankine Cycle Engine An organic Rankine cycle (ORC) power generation system works in a similar way to a water Rankine cycle (traditional steam power plant). The Rankine cycle is a thermodynamic cycle which converts heat into work. The heat cycle is external and the working fluid, usually water but in this case refrigerant, is in a closed loop. The work is extracted and converted to electricity using a turbine generator. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-5

162 The main difference between the two cycles is the operating fluid. The operating fluid in an ORC is a refrigerant, organic chemicals such as R-410 and R-245fa. A refrigerant is used instead of water due to the lower boiling point, which allows a lower temperature heat source to be utilized. The refrigerant is vaporized by the heat from the waste heat source, which is fed to a turbine. The vaporized refrigerant drives the turbine which is connected to a generator which produces electrical power. The refrigerant is condensed, by giving up heat to a cooling loop, and returned to the waste heat exchanger by a pump. A diagram of a typical ORC system is shown below in Figure 42. Return to Plant Heat Recovery Loop Waste Heat Exchanger From Plant Heat Recovery Loop Feed Pump Steam Power Turbine To Cooling Tower or 3JWC Loop Heat Rejection Liquid From Cooling Tower or 3JWC Loop Figure 42: Organic Rankine Cycle Unit Schematic ORC systems are relatively new, only two companies offer systems commercially. UTC Power offers a 280 kw unit and Infinity Turbine LLC offers units at 30, 250, and 500 kw Heat Recovery Hydraulic Engine Heat recovery hydraulic engines also operate using refrigerants with low boiling points. Refrigerants are generally matched to the available heat source by using refrigerants with lower boiling points with lower temperature heat sources. The refrigerant heats up converting the waste heat source to pressure. A separate hydraulic circuit converts this pressure to shaft output power, capable of turning a generator and generating electricity. The Otello Heat Recovery Engine is the only system currently in development. This system uses off the shelf technology from Honeywell (controls and hydraulic valves) and Olaer (bladder and piston accumulators) Size and kwh Production ORC systems require a significant amount of heat to generate electricity. The PureCycle Power System, 280 kw unit from UTC Power, requires 11.6 MMBtu/hr to operate, above the likely amount of waste heat available at EWA. The heat required is significantly more than the amount of heat available with normal operation of the IC engines. For the cost analysis presented in Table 42 it is assumed that the appropriate amount of waste heat is available, Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-6

163 requiring four engines to operate continuously. Infinity turbine offers a 250 kw unit which can operate on a hot water input of F F. This system would require at least 530 gpm of hot water to operate, or approximately 6 MMBtu/hr. This amount of waste heat should be available if three engines are continuously operated. Output power will vary with the hot, heat water (temperature) input Cost The expected equipment and installation costs as well as O&M costs, 10 year average power cost, and levelized cost for the PureCycle Power System are shown in Table 42. The system efficiency is 8% and the system costs $480,000. Efficiency is defined as the net electrical energy derived from the heat source (hot water) expressed as a percent of the total available energy. The expected equipment, installation, and O & M costs, as well as the 10 year average power costs and equivalent cost for the Infinity system are listed in Table 43. System costs are $380,000. If three engines were available and provided sufficient waste heat, this option could be cost-effective with a cumulative 10 year savings of over $2.3 million. Table 42: Estimated PureCycle Power System Costs Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-7

164 Table 43: Estimated Infinity Turbine Power System Costs Item Project Cost Infinity Turbine Power System $380,000 Installation (35% of Equipment Cost) $133,000 Piping, Valves, and other equip $462,000 Cooling Tower & Heat Loop Pipeline $25,000 Subtotal: $1,000,000 Cont./Eng. costs (20%) $400,000 Total installed cost: $1,400,000 Starting O&M costs ($/kwh) $0.03 First year cost power ($/kwh) $ Year average cost ($/kwh) $0.14 Equivalent cost ($/kwh) $ Summary of Advantages and Disadvantages The Otello Heat Recovery Engine is custom built to harness the available heat source. The system is still in the development stage, only one system has been built -- a 50 kw proof of concept. No maintenance data or operational data is available. A 20 kw prototype to be tested at Imperial College in London, England will cost an estimated 120,000 (GBP) or $190,000 for materials. The company who owns the technology, Australia based International Innovations Limited, is looking for a pilot site to demonstrate the technology in the U.S.A. In summary format: Advantages Opportunity to use waste heat to produce electricity, reducing waste heat quantities Increased self generation electricity would complement and ad to IC engine self generation Disadvantages Increased operating complexity Requires significant IC engine operation to provide sufficient waste heat Electricity production would be reduced or eliminated during periods of IC reduced operation Limited operating experience in similar wastewater plant applications Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-8

165 6.4 Steam Turbines Steam turbines have been used for power generation for over 100 years. Most electricity in the United States is produced using steam turbines. Steam turbines can range in size from 50 kw to several hundred mw. Steam turbines are used to turn electric generators or provide mechanical energy for pumps or other process equipment Description Steam turbines vary from other generation technologies in that the fuel does not directly drive the turbine. The fuel is burned in order to create heat which is used to produce steam which is then used to drive the turbine. The steam can also be generated using a nuclear reactor, or by recovering waste heat from an IC engine or microturbine. A schematic is provided in Figure 43 below. Heat Recovery Steam Generator Steam Steam Turbine Engine Exhaust Engine Generator Condenser Water Feed Pump Figure 43: Steam Turbine Unit Schematic Steam turbines operate on the Rankine cycle. This thermodynamic cycle is the basis for conventional power generating stations and requires both a heat source and a heat sink. This basic diagram shows how the technology would be applied at EWA. The heat source in this cycle is the IC engine jacket water and exhaust. Steam is generated in the heat recovery steam generator and exits at high pressure to drive the steam turbine. The condenser provides the necessary heat sink which would be cooled by a new cooling tower or the Plant waste heat loop. Steam exiting the turbine is condensed. The water from the condenser is returned to the heat recovery steam generator through the feed pump. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-9

166 6.4.2 Reason for Limited Information Development The main reason for limited development of this resource is the large amount of heat required. The smallest commercial steam turbine generator requires approximately 26 MMBtu/hr which is about double the amount of heat available with all four IC engines running. The steam turbine would produce about 500 kw. Smaller turbines may be available but these turbines are typically used in steam plants to power pumps or other in-plant equipment. Also, the waste heat available at EWPCF would require supplemental heating at additional cost in order to be converted to steam. 6.5 Gasification of Biosolids MaxWest Environmental Systems Introduction MaxWest Environmental Systems is a private company based in Houston, TX. MaxWest designs, builds, owns, and operates waste to energy gasification facilities History Key members of MaxEn Capital LLC and Westwood Energy Systems, Inc. (WESI) joined forces in 2007 to establish MaxWest Environmental Systems. MaxEn Capital LLC is an investment banking firm based in Houston, TX. Westwood Energy Systems is a former subsidiary of Westwood Fibre Ltd., a forestry company based in Kamloops, British Columbia, Canada. Westwood Energy designs and manufactures bio-energy gasification systems. MaxWest Environmental Systems has acquired Westwood Energy Systems Technical Description Dried solids enter a gasifier to under the processes of pyrolysis and partial combustion to produce char and synthesis gas (syngas). A thermal oxidizer receives the gases produced by the gasifier and converts the syngas to usable heat for energy recovery. Shown in the figure below, an Energy Recovery and Power Generation System uses hot gas from the thermal oxidizer in a Heat Recovery Steam Generator (HRSG) producing steam. The steam can be used directly to supplement the biosolids drying process or could be used for generating power through a steam turbine electric generator. In the case of EWPCF, steam can either be used to generate electric power, provide energy for the rotary drum dryer, thereby, reducing natural gas/digester gas usage, or provide heat to the digester tanks. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-10

167 Source: MaxWest Environmental Systems Figure 44: Maxwest s Gasification System Flow Diagram Examples of Gasification Projects There are approximately 8 WESI designed gasification processes in the US and Canada, out of which only one plant in Sanford, FL processes municipal sewage sludge. The Sanford plant s capacity is 45 wet tons per day with an existing Fenton dryer. The facility is currently being expanded to receive 85 wet tons per day with a Therma-Flite dryer replacing the Fenton Dryer. MaxWest operates the system under contract with the City of Sanford (City) with fees paid by the City for processing biosolids and also some fees rebated for biosolids which are imported from other communities. Installations of MaxWest s full-scale gasification facilities processing biosolids are fairly recent. However, it must be noted the concept of gasification of biosolids is also relatively new to the US market Vendor s Commercial Arrangement MaxWest prefers to Design-Build-Own-Operate (DBOO) a gasification system on a turnkey basis and assumes all risks of construction, financing, and permitting. The other business options available with MaxWest include Build-Own-Operate-Transfer (BOOT) and Build- Transfer (BAT). If EWA is interested in owning and operating the facility, MaxWest will consider building and transferring the system on a license/royalty basis. The customer is required to provide a site that will be leased for the duration of the contract (15 25 years, typically). MaxWest will be paid a disposal fee per ton of waste and for renewable energy delivered. Although, MaxWest prefers long term DBOO procurement, they recently presented to Encina an option of a 5-year term with turnover at the end of five years. This five year term would provide Encina with the benefit of an extended period of process optimization at no additional expense. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-11

168 Cost MaxWest provides a gasification system that has both options of processing the biosolids to produce heat and electricity. The waste heat generated in the process could be used to meet the drying process requirements; and any surplus waste heat could be used to generate steam. An estimated cost was not available from MaxWest during the preparation of this study Nexterra Systems Introduction Nexterra Systems Corporation (Nexterra) is a private company based in Vancouver, BC, Canada and it develops, manufactures and delivers gasification systems History Nexterra is majority-owned by Calgary, Canada based ARC Financial Corporation. ARC manages private equity funds representing $2.7 Billion in committed capital that are focused on high growth, early stage companies in the energy industry. In March 2004, Nexterra completed a $5.4 million private equity financing, led by ARC. Over the years, ARC has continued to invest in Nexterra with a total investment of over $20 million. Nexterra has also received funding commitments from federal, state, and industrial sectors Technical Description Nexterra s gasification process is similar to the technology described previously. Figure 45 illustrates the four primary stages of Nexterra s system. Dried solids enter a gasifier through the in-feed system where it goes through progressive stages of drying, pyrolysis, and partial combustion to produce char and synthesis gas. The char is removed from the base of the gasifier. Syngas exits the gasifier at F which is combusted in a close coupled oxidizer with the resulting flue gas directed to heat recovery equipment such as boilers, thermal oil heaters, air-to-air heat exchangers or turbines. There is also potential to directly fire syngas into industrial boilers, kilns, dryers, and other equipment. In the case of the EWPCF, the flue gas can either be used to generate electric power, provide energy for the rotary drum dryer, thereby, reducing natural gas/digester gas usage, or provide heat to the digester tanks. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-12

169 Source: Nexterra Systems Corp Figure 45: Nexterra s Gasifier Examples of Gasification Projects Nexterra has two installations utilizing biosolids in the US, one of which is under construction at the Department of Energy s Oakridge Labs in TN. There is also another installation currently in the design phase in Stamford, CT. Nexterra also has approximately 5 installations in Canada that use woody biomass as the feedstock for gasification, one of which is under construction. Nexterra offers two types of gasification systems. The first produces heat from the gasification of biosolids. This system will be available during the third quarter of The second system is the gasification of biosolids to produce electrical power from an Internal Combustion (IC) engine. This technology is at a pilot stage and is being demonstrated at their Product Development Center in Vancouver, BC Vendor s Commercial Arrangement In addition to supplying gasification equipment, Nexterra also has the option of Design-Build- Own-Operate (DBOO) Cost Table 44 provides the estimated capital and Operation and Maintenance (O&M) costs for Nexterra s Sludge to Heat / Sludge to Electricity Gasification Systems. Capital costs include the addition of a new gasification system and all associated equipment. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-13

170 Table 44: Estimated Costs - Nexterra s Gasification System: Sludge to Heat Solution Item Capital Cost Annual O&M Cost (Dollars) (Dollars) Sludge to Heat Solution $18,230,000 1) $200,000 2) Sludge to Electricity Solution $37,670,000 1) 2) 3) $350,000 1) Includes a new gasification system (feed system, gasifiers, scrubber, gas holding and cleaning, and engine generator), building to house equipment, and includes mark ups for 17% Electrical and Instrumentation, 7% Contractor Indirects, 15% Contractor OH&P, 25% Estimate Contingency 2) As estimated by Nexterra 3) Annual O&M costs do not include the potential revenue from the sale of Syngas. Nexterra recommends a 14 ft diameter gasifier and an approximately 50 ft x 100 ft footprint for the Gasification-to-Heat process. They recommend a 16 ft diameter gasifier and approximately a 75 ft x 100 ft footprint for a Gasification-to-Electricity process. Nexterra s Gasification-to-Electricity process produces electricity through a General Electric Jenbacher IC engine generation available in modules of 2 Mega Watts. In order to have enough fuel for this system, approximately 12,000 dry tons per year of biosolids are required. The projected year 2030 biosolids production for Encina is approximately 9,400 dry tons. The 2,600 dry tons per year short fall could be addressed by obtaining feedstock from biosolids from other wastewater treatment facilities, waste wood from construction/demolition sites, or commercial and residential yard debris. If no additional biomass or biosolids are available then power could be produced from producing steam. However, Nexterra suggests this is a less efficient solution. It should also be noted that biosolids gasification technology that produces electricity is still at a pre-commercial stage with Nexterra. Nexterra s biosolids gasification to produce heat could be used to produce up to 13 Million British Thermal Units per hour (MMBtu/hr) based on the projected biosolids quantity of 9,400 dry tons per year and 6,240 operating hours per year. This waste heat could be used in the rotary drum drying process, thereby reducing the natural gas/digester gas usage. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 6-14

171 Section 7: Air Emissions 7.1 Introduction and Purpose The purpose of this section is to review constraints on cogeneration operation due to air emissions. The objective would be to look for opportunities to relieve those constraints and optimize the use of existing and future cogeneration equipment. Further, the section should address air emissions and related constraints associated with other technologies. This would ultimately result in a strategy that addresses both technology selection and air emissions permit impacts on EWPCF. 7.2 Current SDAPCD Permit The IC engine limits were recently modified (May 4, 2010) and are as follows: Total biogas and natural gas (NG) annual consumption shall not exceed 224 million cubic feet per year (MMCF/year) Total annual NG consumption shall not exceed 10 percent of the total annual limit Biogas daily consumption shall not exceed 1.0 MMCF/day NG daily consumption shall not exceed 0.55 MMCF/day 7.3 Estimated Emissions for each Technology Alternative technologies that utilize combustion to product energy or heat would contribute to the total annual emissions loading considered by SDCAPCD in the development of permits to construct and operate. As noted in the sections above, technologies would contribute different levels of loadings and, in some cases, be significantly reduced with the addition of gas treatment and post combustion treatment. During the series of workshops completed as a part of this study, the idea of using a building blocks approach was presented. With this approach, technologies would be combined into alternatives that could achieve the target energy independence goals and, at the same time, track air emissions quantities to determine compliance with air emissions goals. Section 1.5 provides a summary of the current emissions restrictions noting carbon monoxide (CO) is the controlling pollutant at EWPCF. The current permit (with synthetic minor limitations compliance) allows annual CO emissions up to 100 tons per year. Daily limits are also specified for biogas and NG combustion. CO emissions for IC Engines for biogas and NG with and without exhaust catalysts and gas treatment are summarized in table 45. The estimated annual emissions are adjusted for the anticipated maximum available annual 8,000 operating hours. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 7-1

172 Table 45: IC Engine CO Emissions Technology Gas Treatment and/or Catalyst Capacity (kw) Fuel source Annual CO Emissions (t/yr) IC Engine No 750 Biogas 51 IC Engine Yes 750 Biogas 5.0 IC Engine No 750 NG 31 IC Engine Yes 750 NG 3.1 Fuel cells would emit a much lower level of CO as summarized table 46; Table 46: Fuel Cell CO Emissions Fuel Cell Capacity (kw) Biogas Fuel CO Emissions NG Fuel CO Emissions (t/yr) (t/yr) 300 kw kw The sludge dryer and RTO equipment are fueled by biogas/ng and NG respectively. The RTO is fueled entirely by NG and the dryer can be fueled with a maximum blend of 82% biogas and 18% NG. The current maximum ratio achieved recently in the dryer has been 40% biogas and 60% NG. Their combined CO emissions for each fuel combination at 2010 solids treatment volumes are listed in the following table 47. Table 47: Sludge Drying Operation CO Emissions 6.3 Dryer Biogas/NG Combination Annual CO emissions (t/yr) 40%/60% %/18% RTO emissions 1) 0.4 1) Emissions from required natural gas use in RTO unit The CO emissions listed above indicate the continued use of IC engines without gas treatment or catalyst has the greatest impact complying with synthetic permit limitations. 7.4 Permit Strategy Options EWA has three basic strategies available when considering the adoption of this Energy and Emissions Strategic Plan. Each is described in the following subsections. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 7-2

173 7.4.1 Maintain Synthetic Minor Permit, Emissions Near Maximum Threshold Limits With this option, CO emissions would be allowed to remain near the 100 t/yr emissions similar to the current operation and the addition of gas treatment and or catalysts on the existing IC engines would be avoided. The mix of technologies would require care to ensure permit limitations are not exceeded. Technologies that could be used to increase self generation at the EWPCF facility include: Fuel cells Solar PV Organic rankine engine New chiller Seek a Major Source Permit (Title V) This strategy would allow CO emissions to exceed the current permit limitations. It includes full utilization of the existing four IC engines (and more engines if needed) to maximize self generation of electricity, without installation of gas treatment and exhaust catalysts. This option would likely result in the lowest capital investment to achieve a greater level of self generation capabilities Continuing with Synthetic Minor Permit with Significantly Lower Pollutant Emissions The third option would result in a significant reduction in CO emissions well below the current 100 tons per year CO emissions level. This has the added value of resulting in a much less restrictive permit and providing an improved operating flexibility due to the large safety margin below the synthetic minor permit CO threshold. Technologies that could be used with this strategy include: Provide gas treatment and exhaust catalysts on all IC Engines Fuel cells Solar PV Organic rankine engine New chiller Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 7-3

174 7.5 Greenhouse Gas Considerations Assembly Bill 32, the California Global Warming Solutions Act of 2006 (AB 32; Statutes of 2006, chapter 488), creates a comprehensive, multi-year program to reduce GHG emissions to 1990 levels by the year 2020 and to 80 percent below 1990 levels by Governor Schwarzenegger directed the California Air Resource Control Board (ARB) (Executive Order S ) to adopt a regulation by July 31, 2010, requiring the state's load serving entities to meet a 33 percent renewable energy target by ARB may consider different approaches that would achieve the objectives of the Executive Order. This could include increasing the target and accelerating and expanding the time frame based on a thorough assessment of technical feasibility, system reliability, cost, greenhouse gas emissions, environmental protection, and other relevant factors. Proposition 23 (November 2010) ballot initiative proposed to relax the implementation of AB 32 which would have been tied to a State Employment threshold. With the failure of this initiative, all requirements contained in AB 32 are in full affect. SDAPCD recently based on EPA GHG Permitting Rule regulations (adopted June 3, 2010), decided to include a Title V threshold based on GHG emissions. The Title V de minimis threshold is being evaluated and an initial potential to emit threshold of 75,000 metric tons of CO2eq is being considered. Discussions with SDAPCD staff indicated Information Request letters will be sent out to facilities with cogeneration that are currently non-title V permitted facilities. EWPCF was mentioned as one of the facilities on the Information Requested list. EWA recently completed the calendar year (CY) 2009 California Emission Inventory for greenhouse gases. Encina, based on a cogeneration rated capacity in excess of 1.0 MW, has participated in the State of California program since Table 48 provides an overall summary of 2009 GHG Inventory for combustion emissions. Table 48: 2009 Greenhouse Gas Combustion Emission Summary Fuel Type (Preliminary Facility Emission Detailed Report 3/25/2010 un-verified) Sources Associated with Fuel Total Gas Utilization (million cubic ft/year) Associated CO 2eq (metric tonnes) Biogas Cogeneration Engines ,925 Natural Gas Cogeneration Engines Biogas Flare 20 1,258 Natural Gas Eclipse Blower 1 69 Natural Gas RTO/Dryer 55 4,419 Natural Gas Administration Building Total (Biogenic- Biogas) 17,183 Total (Natural Gas) 5,219 Total - Combustion Processes 22,402 Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 7-4

175 It should be noted that GHG emissions associated with biogenic (biogas) sources are classified as a renewable type activity and are recorded independently in the State of California database. SDAPCD will consider the entire inventory including biogenic fuels on whether facility inclusion into the Title V permitting program is warranted. Wastewater processes and non-combustion sources were not required for inclusion in the CY 2009 inventory. The wastewater industry has been aggressively pursing the emission estimation methodology, potential impact of emissions of nitrogen oxide (N 2 O) and potential impact to the overall facility greenhouse gas inventory. Although carbon dioxide is the focus of most greenhouse gas discussions, nitrogen oxide has a potency equivalency factor of one pound of N 2 O equals 296 pounds of CO 2, therefore a relatively small amount of N 2 O can significantly impact the overall facility inventory. Monitoring of the N 2 O issue, as well as any use of natural gas, may increase the GHG facility inventory. GHG reduction strategies, reduction in purchased natural and energy reduction measures should be considered as part of the energy independence strategy. EWA does not currently have a carbon footprint reduction program but will continue to comply with AB 32 and developing federal regulations. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 7-5

176

177 Section 8: Alternative Scenarios Development, Evaluation and Selection 8.1 Introduction and Purpose The purpose of this section is to develop practical alternative scenarios that would achieve energy independence in accordance with the Business Plan. Energy independence is defined initially as self generating 95% of EWPCF s required electrical power. This section includes the development of preliminary scenarios, ranking scenarios by completing a scoring process, preliminary screening of scenarios and ultimately recommending the most favorable scenario. The scoring and preliminary screening resulted in a short list of scenarios from which the recommending scenario was selected. The recommended scenario was then further developed into a prioritized plan for implementing technologies comprising the scenario. 8.2 Evaluation Criteria and Weighting Factors Kennedy/Jenks and EWA staff developed the evaluation criteria presented in Table 49 below for use in comparing alternative technologies. The five selected criteria include various factors as described in the ranking process. Weighting was developed using the paired wise technique by EWA staff. 8.3 Technologies Retained for Projects Development In Section 4, alternative technologies were identified and developed by completing detailed descriptions, capabilities, operating experience and cost information. In Section 8, selected technologies are combined into scenarios that have the potential to achieve targeted energy independence goals. Sixteen (16) candidate technologies divided into four (4) general categories are considered in the previous sections 4, 5, and 6. From this list, eight (8) were selected for inclusion in the development of alternative scenarios. Table 50 on the following page lists the selected technologies and the basis for their inclusion. Technologies considered in Section 4, 5, and 6 that were excluded from the development of scenarios and the reasons for their exclusion are listed in Table 51. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-1

178 Table 49: Evaluation Criteria Criteria Description Weighting Adverse or beneficial impacts on the operations of the plant General operations and Operations maintenance complexity 32% Recycle stream, quality, quantity and impacts Additional support utilities requirements Unit cost per energy measurement Operations and Cost and Savings maintenance costs 21% Present worth value Expected life of resource Incentives Number of available suppliers Experienced vendors Maturity and Reliability 20% available Existing operating systems Permit type Air Permitting Operational impacts 19% from regulatory scrutiny Green House Gas Land Water Environmental 8% Noise Aesthetic/visual Waste by-product Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-2

179 Table 50: Technologies Included in Scenarios Development Category Technology Basis for Inclusion Biogas Production Enhancements Waste to gas (WTE) Offers significant increase in biogas production Cell lysis Offers important increases biogas production Alternative Power Generation IC Engines without gas treatment or catalysts Low level of operator complexity; allows consideration of non- Synthetic Minor permit Waste Heat Recovery and Utilization IC Engines with gas treatment & catalyst Fuel cell Solar PV Absorption/adsorption chiller Organic rankine cycle power generation scenario Provides higher level of engine operation within Synthetic Minor permit restrictions Low air emissions, produces usable waste heat; high level of gas use efficiency; high subsidies available Reduced air emissions; high level of subsidies; relatively low level of operation complexity Utilizes available waste heat; reduces electrical energy demand Utilizes available waste heat; produces electrical energy offsetting air emissions Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-3

180 Table 51: Technologies Excluded in Scenario Development Category Technology Basis for Exclusion Biogas Production Enhancements Digester Train Modifications Increased biogas production uncertain; cost/ benefits uncertain Alternative Power Generation Small Wind Limited wind resources available at EWPCF per published data Microturbines High biogas treatment requirements increases operator complexity; recent EWA investment in new IC engines that can achieve similar high quality air emissions with installation of gas treatment and catalysts Waste Heat Utilization Steam Turbines Large demand for heat exceeding available supply Recovery and Utilization MaxWest Environmental Systems Nexterra Systems Sludge Heating Limited projects experience; requires special 3 rd party lease agreement Limited projects experience; uncertain technology costs Limited technology experience; high maintenance requirements Other Support Facilities Biogas Storage Site constraints; concern about safety of on-site biogas storage 8.4 Energy Self Generation Goals A primary objective of the Energy and Emissions Strategic Plan is to provide EWA with a plan for achieving targeted energy self generation goals. The development of alternative scenarios provides the opportunity to identify combinations of the selected technologies that could achieve such goals. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-4

181 In Section 2, projected energy needs are developed for electrical energy and gas utilization. The projections are based on a Business as Usual scenario that assumes no changes to the current operations scheme (including retaining existing APCD permits and operating without process changes or new process units). In Section 3, the results of an energy audit are presented and list of potential process changes that could reduce energy demands are identified. These are identified as Energy Efficiency Measures (EEM) that collectively could reduce EWPCF electrical energy demand by over 2.0 million kwh per year. In Section 5, it is assumed implementation of EEM s will reduce EWPCF energy demands by 2.0 million kwh/yr (compared to baseline energy demands developed in Section 2). The alternative scenarios developed in this section are configured to enable EWA to self generate 95% of the total EWPCF electrical needs in the year 2020; a total that has been adjusted downward based on implementation of EEM s. Natural gas purchases are also considered in the development and opportunities to reduce such purchases to the maximum extend possible is identified. However, the 95% 2020 electrical self generation target is the metric used to select the mix of technologies included in each of the alternative scenarios. 8.5 Approach to Identifying Alternative Scenarios To facilitate the development of alternative scenarios, an Excel-based model is utilized. Based on a building blocks concept, the model allows the user to create a list of technologies keeping track of several key factors. Capital Cost Annual Operation and Maintenance Cost Net Present Value Annual Carbon Monoxide (CO) Emissions Annual Power and Production/Purchase Annual Biogas Utilization Annual Natural Gas Purchases Waste Heat Balance (production and utilization) Greenhouse Gas Emissions (carbon dioxide - CO 2 ) Total energy requirements and onsite energy production are tabulated in 5-year increments to allow the user to select combinations of technologies meeting selected goals. The annual CO emissions are tabulated and the user is notified when the total exceeds the current synthetic minor limitation of 100 tons per year. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-5

182 Carbon monoxide emissions levels are the total emissions for all processes using biogas and/or natural gas as a fuel sources expression as tons per year (t/yr). Greenhouse gas emissions include emissions of carbon dioxide (CO 2 ) also expressed as metric tons per year (t/yr) of non-biogenic CO 2. The tabulated value is limited to on-site emissions for use of natural gas a fuel source and CO 2 emissions by SDG&E for the electrical energy purchased by EWA in accordance with greenhouse gas tabulation protocols. The model allows the user to select one or more of the eight (8) selected technologies that survived screening. There are a number of variables affecting several of the technologies resulting in a total of 24 individual technology choices available to the user. The following provides a summary of the technologies and their possible configurations included in the model: 1. IC engines (biogas fueled) without gas treatment or catalysts 2. IC engines (biogas fueled) with gas treatment and catalysts 3. IC engines (natural fueled) without catalysts 4. IC engines (natural gas fueled) with catalysts 5. IC engines with and without gas treatment and catalysts (50% biogas and 50%) NG fueled 6. Dryer fueled with 82% biogas and 18% natural 7. Dryer fueled with 40% biogas and 60% natural 8. Fuel Cell (0.3 mw and 1.4 mw) 9. Waste to Energy (WTE) for enhanced biogas production 10. Organic Rankine Cycle Engine (0.23 mw and 50 kw) 11. Cell Lysis for enhanced biogas production 12. Solar PV (1.0 mw, 3.0 mw and 4.0 mw) 13. Chiller (135 ton and 250 ton) Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-6

183 8.6 Preliminary Project Scenarios Using the scenario model, seventeen scenarios were initially identified by Kennedy/Jenks and EWA staff. Each scenario was configured with alternative combinations of technologies for comparison purposes. As noted previously, all of the scenarios (with one exception) would allow EWA to achieve 95% electrical energy self generation in the year Scenario 4d would be limited to 90% electrical self generation in A summary of the 17 scenarios is provided in the following table. Technologies included in each scenario are noted along with relevant information as follows: IC Engines: Number of engines included (either 4 existing or a new 5 th engine); a scenario requiring 6 engines would be achieved by providing engines greater than 750 kw. IC Engines gas treatment and catalysts: For some scenarios, gas treatment is provided for 3 or fewer engines as noted; full treatment provided where noted; number of catalysts as noted; where catalyst is provided without gas treatment operation with natural gas only is allowed reducing CO emissions (for SDAPCD permit compliance) Fuel cell: 0.3 mw or 1.4 mw as noted Solar: 1.0m mw, 3.0 mw or 4.0 mw as noted (larger installations utilize net metering) Organic Rankine Cycle Generator (ORC): All 0.23 mw included as noted Second Absorption Chiller: 110 ton unit as noted (installed in administration building) Cell Lysis: Included as noted Waste to Energy (WTE): included as noted With the exception of one scenario (Scenario 8) the biogas and natural gas blend provided to the dryer is 82%/18% respectively by Scenario 8 is based on a biogas to natural gas blend of 40%/60% due to biogas use by other technologies included with that scenario. Scenarios that would emit carbon monoxide greater than the 100 ton synthetic permit limitation are noted in red font. Annual GHG emissions in metric tons is also provided. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-7

184 Table 52: Initially Identified Alternative Scenarios Scenario IC Engines IC Engines Biogas Treatment IC Engines Catalyst Fuel Cell Solar ORC Second Chiller Cell Lysis WTE CO Emissions (t/yr) GHG Emissions (t/yr) 1 (Business as Usual) 4 None , None yes --- yes 190 4, Full mw 1 mw --- yes --- yes for mw yes --- yes 38 4,564 4e 5 Full mw yes ,780 4b 4 For mw mw yes 27 3,436 4d 5 Full yes --- yes 27 5, none 1 (NG) mw yes 127 4, Full mw yes --- yes 49 5, None 1 (NG) 1.4 MW yes --- yes 87 3, None mw 3.0 mw --- yes , None 1 (NG) mw yes , For mw yes yes , For mw mw yes --- yes 34 3, Full mw --- yes --- yes 26 5, Full mw mw yes --- yes 23 3,171 4f 6 Full yes --- yes 27 6,083 Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-8

185 8.7 Preliminary Alternative Scenarios Scoring The seventeen scenarios were ranked by completing a scoring process utilizing the evaluation criteria and the weightings for each presented in Subsection 8.1. A matrix analysis approach was used assigning scores derived from the weighted criteria applied to each technology included within each scenario. The scoring was completed by assigning the highest possible score to each technology included within a scenario. Scores were then adjusted downward based on technology limitations for each of the technologies included in the scenario. With 12 technologies and 100 possible points for the 5 evaluation criteria, the maximum possible score is Those technologies that were not included in a scenario received the maximum score. Scores for each of the technologies were assigned based on the score ranges listed in the following Table 53: Table 53: Scenario Scoring Values Criteria Maximum Scores 1) Scoring Method 1) Operations 32 32, 24, 16, 8, 0 Cost & Savings 21 Calculated based on Present Value; lowest cost receives highest points, 21 Maturity & Reliability 20 20, 15, 10, 5, 0 Air Permitting t/yr (19); t/yr (15); t/yr (10); t/yr (5); >100 t/yr (0) Environmental 8 8, 6, 4, 2, 0 Total 100 1) The team reached consensus on the maximum scores and scoring method for each criteria The scoring was completed in a workshop attended by EWA staff. Scoring was considered and developed for each technology and applied with an Excel spreadsheet. Detailed scoring sheets are provided in Appendix E. The results of the scoring are summarized in the following Table 54. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-9

186 Table 54: Preliminary Scenarios Scoring Results Rank Scenario Score 2020 Electrical Self Generation 1 4d % 2 4f % 3 4e % % (Business as % Usual) % % 7-8 4b % % % % % % % % % % 8.8 Top Ranked Scenarios Considerations Screened Scenarios The top ranked scenarios were compared by completing a detailed review of each to verify the scoring for each and identifying features that might influence a final selection. For screening purposes, projects scoring less than 900 were screened out. In additional, Scenario 2 was dropped because the CO emissions would require operating under a Title V permit. This was deemed inconsistent with EWA s Mission of being an environmental leader. Scenario 4b was also dropped because it did not equip all engines with exhaust catalysts. This would dictate assigning an engine to natural gas fuel only and would reduce equipment redundancy and hamper efficient operations. Scenario 4d was the highest scoring scenario but was not carried forward because it does not achieve energy independence goals. Scenario 4f (the second highest scoring scenario) takes advantage of the recent EWA investment in new IC engines and utilizes the remaining energy building space by including additional engines. Gas treatment and catalysts are included thereby allowing greater use of the IC engines and reducing CO emissions well below the SDAPCD threshold for a synthetic minor emissions permit. This scenario does not include alternative electricity producing technologies (such as solar PV) relying entirely on the IC Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-10

187 engines. With the addition of a 5 th engine, up to 4 engines could be operated with the adoption of this scenario (thereby maintaining one engine as a standby unit as required to meet EWPCF reliability requirements). Operating 4 engines under Scenario 4d would limit self generation to 90% of the projected 2020 demand. Each of the remaining 16 scenarios would allow EWA to provide 95% self generation capacity. Because of the 2020 self generation limitation, Scenario 4d was dropped from consideration and is not included in the final top ranked scenarios list. Scenario 4f is very similar to 4d and was carried forward. Scenario 4f has all the features of 4d but in addition adds a 6 th engine (or a larger 5 th engine) sometime before 2020 to operate on natural gas and bring self generation capacity up to 95% Surviving Scenarios The remaining top 6 ranked scenarios were assigned Strategic Plan Scenario designations (A through F) as shown in Table 55 to simplify the final comparison and selection of a recommended scenario. The features of the short listed scenarios are shown in the table. Strategic Plan Scenario B (preliminary Scenario 4) was created to provide a scenario similar to Scenario 4d by including a 6 th engine (that would allow EWA to achieve 95% self generation in 2020) and was scored highest among the remaining scenarios. This scenario has a high score even when considering the added cost of adding a 6 th engine. The estimated capital cost includes an expansion of the building at a much greater incremental expense (compared to the installation of a 5 th engine). As in the case of Scenario 4d, this scenario is taking advantage of the current investment in four new IC engines and that feature results in a competitive capital and operating cost when compared to other scenarios. Scenario 4f is identical to 4b up until the time when the 6 th engine (or installation of a larger IC engine) is implemented. Strategic Plan Scenario A (preliminary Scenario 1 - Business as Usual) would maintain the current operational scheme (with no required capital investment) and was scored as a tie for 4 th and 5 th highest. Electricity self generation would be considerably lower in 2020 (52%), much lower in 2030 (45%) and would not allow EWA to achieve self generation goals. Table 55 provides a comparison of the remaining 6 highest scored Strategic Plan Scenarios A through F. Features of each Strategic Plan Scenario are listed in the table including electricity producing technologies contributing to self generation capacity. The following electricity producing technologies are included in one or more of the 6 highest ranked Strategic Plan Scenarios: IC Engines fueled by biogas and natural gas with various levels of gas treatment and catalysts Organic Rankine Cycle Generator Fuel Cells Solar PV Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-11

188 Table 55: Highest Ranked Scenarios Final Designation Scenario Score Annual Cost ($ mil) Comparison Capital Cost ($ mil) Net Present Value ($ mil) 2020 Self Generation No. of Engines Biogas Treatment No. Engines with Catalyst Features Fuel Cell (mw) ORC Generation (mw) Solar PV (mw) 2030 Electricity Self Generation B 4f 958 $2.2 $11.7 $ % 6 Full % C 4e 933 $2.2 $10.0 $ % 5 Full % D $2.4 $13.0 $ % 4 For % A 1 (Business as Usual) 919 $3.2 $ - $ % % E $2.4 $17.5 $ % 5 Full % F 4b 902 $2.3 $13.5 $ % 4 For % Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-12

189 Each of the top ranked Strategic Plan Scenarios has several common features as listed below: Maximize use of biogas in the dryer up to a maximum blend of 82% biogas and 18% natural gas. A waste to energy (WTE) scenario feature that would increase biogas production required to achieve self generation goals and dryer gas demand. The installation of an adsorption chiller utilizing available waste heat thereby reducing existing administration building equipment natural gas demand. 8.9 Selected Project and Implementation Plan During the review of the highest ranked Strategic Plan Scenarios listed in Table 62, the following important considerations were identified: The ranking process was developed with careful consideration of the five weighted criteria listed in Section 4. The resulting scores were judged to be appropriate based on the weighting and scoring process developed by Kennedy/Jenks Consultants and EWA staff. Each of the remaining 6 top highest ranked scenarios would allow EWA to achieve the energy independence goals included in the adopted business plan with one exception, Strategic Plan Scenario A (Business as Usual). Of particular note was the final scoring with respect to the capital and net present value cost estimates. Scenario A (Business as Usual) was estimated to have the lowest cost. It would not, however, allow EWA to achieve the Business Plan goals and the estimated present value is dependent on a state-wide published energy inflation rate of 1.75% per year. The cost differential could quickly narrow if actual energy inflation rates are higher. Scenario B (the highest ranked scenario) has the third lowest net present value and shared the lower capital cost with Scenario C. It maximizes the use of the recently installed IC engines and continues with the same mix of existing technologies (technologies EWA staff are familiar with and have available staff to support) with the exception of gas treatment and catalysts. With these factors in mind, the final recommendation is to rely on the evaluation criteria, weighting and scoring developed during the study and select the highest ranked short listed scenario, Strategic Plan Scenario B Selected Scenario B Description The recommended Strategic Plan Scenario B includes the following technologies and features: Utilize IC Engines fueled with biogas to produce electricity thereby reducing commercial power purchases to 5% of electricity demands in Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-13

190 Increase total IC Engine capacity to maintain current level of reliability and meet electrical energy demands by installing 5 th and 6 th engines. The option of increasing the size of the 5th engine would likely be less costly than expanding the existing energy building to accommodate a 6 th engine. Install biogas treatment and catalysts on all engines to substantially reduce carbon monoxide and other pollutant emissions thereby complying with current emissions limitations. Increasing biogas production (beyond production available from wastewater solids) is required and would be achieved by implementing a waste to energy (WTE) project. Utilize biogas, as a fuel source for the dryer up to a maximum blend of 82% biogas and 18% natural gas as biogas production increases. Replace existing administration building electric driven chiller with a new adsorption chiller utilizing available waste heat from the IC engines hot water recovery system. A comparison of Scenario A, Business as Usual, and the recommended scenario are provided in the following Table 56. Electricity and total energy self generation would be significantly increased with implementation of Scenario B. Total energy accounts for electrical energy production and use of biogas offsetting purchases of natural gas. The comparison of energy self production includes implementation of the recommended Energy Efficiency Measures identified in Section 3. Scenario B would require a capital investment of $11,700,000 to achieve the self generation levels indicated. The breakdown of this investment is shown in Table 57. A portion of that investment would be recovered by reduced operating costs. The recovery rate could be greater over time if the state published inflation rate for commercial energy (1.75% per year) proves to be too low. Table 56: Scenarios A and B Comparison Factors (2020) Scenario A (Business as Usual) Scenario B (Recommended) Electricity Self Generated 52% 95% Total Energy Self Generated 57% 81% Capital Cost $0 $11,700,000 O&M Cost $3,206,000 $2,508,000 Self Generation (kwh/yr) 14,133,000 23,623,000 Power Purchase $2,700,000 $239,000 CO Emissions (t/yr) GHG Emissions (t/yr) 6,400 6,100 Net Present Value $26,830,000 $29,078,000 Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-14

191 Table 57: Investment Cost Breakdown Technology Cost ($) Biogas treatment and exhaust catalysts $3,000,000 Waste to energy $3,200,000 5 th engine with catalyst $1,000,000 Administration Building Chiller $1,400,000 6 th engine with catalyst and building expansion $3,100,000 Total $11,700,000 Carbon monoxide air emissions would be significantly reduced while green house gas emissions (using the carbon dioxide portion for comparison) would be marginally reduced. Figure 46 provides a graphical side by side comparison for purchased and self generated energy for the current situation (Business as Usual) in 2010 and both Scenarios A and B in 2020 and The energy values are presented in therms to provide a common energy unit for comparison. The factors used to calculate the common energy units are summarized in the following Table 58. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-15

192 Figure 46: Scenarios A and B Energy Sources Comparison Table 58: Energy Comparison Factors Energy Elements Energy Factors Biogas fuel content 600 btu/cf Natural Gas fuel content 1,000 btu/cf IC engine electrical energy production efficiency (not including waste heat 32.7% recovery efficiency) Adsorption Chiller hot water utilization 2.3 MM Btu/hr Existing EWPCF equipment gas As documented by EWPCF utilization records Existing EWPCF IC engine hot water 3.7 MM Btu/hr production Implementing Scenario B would allow EWA to move forward with increased levels of self generation as summarized in Table 58 and shown graphically in Figure 46. Energy values are presented in common units (millions of therms per year) and grouped into categories explained as follows: Purchased Electricity: Electricity and natural gas purchases Existing Heat Recovery: Heat utilization for digesters and the Power Building existing chiller Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-16

193 Existing Produced Gas Generated Power: Electrical energy production from IC engines limited by current APCD permit (prior to installation of gas treatment and catalysts) EEM Energy Reduction: Energy savings associated with Energy Efficiency Measures Emissions Reduction on Existing Engines: Increased electricity production with installation of gas treatment and catalysts Waste to Energy and 5 th Engine: Increased electricity production with installation of waste to energy technology and 5 th IC engine Expanded Chiller Use: Increased recovery of waste heat with installation of new chiller serving administration building Add 6 th Engine: Increased electricity with installation of 6 th IC engine (or increased size Table 59: Scenario B Energy Sources (million therms/year) of 5th engine) Table 59: Scenario B Energy Sources (million therms/year) Year Flow (MGD) Purchased Energy Existing Heat Recovery Existing Produced Gas 1) EEM/Chiller Energy Reduction Emissions Reduction on Existing Engines 2) Waste to Energy & 5 th Engine Expanded Chiller use Add 6 th Engine ) Modified SDAPCD permits (May 2010) increased IC engine operation. 2) This feature lifts the engine run-hour imposed by air emissions permits. Totals Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-17

194 Figure 47: Highest Ranked Scenario Achieving Strategic Objective Implementation Plan Scenario B includes several technology components that could be implemented in a phased manner. A recommended phasing plan is developed by setting priorities for each technology. The opportunity to increase self generation is directly related to increased biogas production that is dependent on two factors, increased wastewater (and solids) flows and implementation of the recommended waste to energy (WTE) project. Increased wastewater flows are dependent on the local economy and associated new development. The WTE project provides an opportunity to increase biogas production immediately and potentially has a higher degree of certainty for increasing biogas production. Considering these factors, the recommended priority for implementing Scenario B technologies is provided in the following Table 60. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-18

195 Table 60: Recommended Scenario B Technologies Priorities Technology Priority Basis for Setting Priority Energy efficiency measures 1 Demand reduction IC Engine Gas treatment & Ability to increase self generation and reduce 2 Catalysts emissions Waste to Energy 3 Near term biogas increased production with high level of EWA control 5th engine 4 Scheduling dependent on increased wastewater flows Administration Building Chiller 6 th IC engine Summary and Findings 5 Reduces natural gas and electricity purchases Scheduling dependent on increased wastewater flows Relative Cost of Energy from Various Sources As part of alternative technology development and evaluation the relative cost of energy from different sources was developed. The data is presented as the cost to EWA of providing needed energy in the form required for use from the various sources. Sources include from purchased energy, self generated energy through modification of existing facilities and from new technologies. For this comparison energy is measured in therms. Cost of energy varies significantly from about $0.30 per therm to about $2.70 per therm. See Figure 48 for a relative cost comparison. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-19

196 Figure 48: Energy Cost from Various Sources The various sources are discussed and defined as follows: Purchased energy: Prices are for On-Peak Electricity, Off-Peak Electricity (semi-peal and off peak) and natural gas. Waste to energy: This represents the cost of gas from produced imported grease and food waste and used on site. Solar electricity: This is the cost of electricity from a photovoltaic system owned by EWA. Fuel cell electricity: Costs are for natural gas fueled and biogas fueled fuel cells. Chiller: This is the cost of capturing waste heat and using it in a chiller in lieu of an electric powered chiller. Existing engine produced electricity: The costs represent the cost of equipping existing engines with biogas treatment and exhaust catalysts in order to maximize the use of existing assets and biofuel. Also, the cost of using existing engines equipped with catalysts and fueled by purchased natural gas is presented. New engine produced electricity: The costs represent the cost of purchasing new engines and equipping them exhaust catalysts in order to maximize the use of existing assets and biofuel. Also, the cost of purchasing new engines with catalysts fueled by purchased natural gas is presented. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-20

197 Organic Rankine generator: The cost represents the cost of purchasing and maintaining new generators to produce electricity from waste heat. All site generation technologies, accept fuel cell and solar systems can produce electricity at a lower cost than electricity purchased on peak. In addition, existing and new engines with catalysts fueled by biogas and organic Rankine generators can produce electricity at a lower price the purchased off-peak electricity Recommended Scenario The recommended plan, Strategic Scenario B, has the following benefits: 1. Reduce the requirements for purchased energy. The cost of purchased energy is projected to fall between years 2010 and 2020 and the rise between 2020 and Reduce air CO emissions and remove operating constraints imposed by air emissions permits. 3. Reduce reliance on outside energy providers. 4. Leverages the previous investments made in internal combustion engine generators. 5. Insulate EWA energy budgets from the uncertainty of energy markets. The investment plan includes six (6) elements to implement between now and These investments range in size from $1.0 to $3.2. The prioritized elements and their respective simple pay back periods are shown in Table 61. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-21

198 Table 61: Prioritized Investments Technology Priority Investment $ Payback - yr EEM s 1 Varies by process 0.2 to 25 IC Engine Gas Treatment & Catalysts 2 $3,000, Waste to Energy 3 $3,200, th Engine 4 $1,000, Administration Building Chiller 5 $1,400, th Engine 6 $3,100, This Energy Strategic Plan should be revisited in 2015 and 2020 to schedule energy independence related investments, confirm cost effectiveness as purchased energy prices change and plan for providing energy after year The E-CAMP process should be used schedule, fund and implement the 5 major components of the scenario Energy Independence The Energy & Emissions Strategic Plan Update has shown that energy independence is indeed achievable for EWPCF. The Plan, compared to Business as Usual, is projected to: Increase self generated electricity from 52% to 95% in Increase self generated total energy from 56% currently to 81% in Additional Recommendations Beyond implementing the recommended Scenario, other actions should be taken to support the objectives of this plan: 1. Energy asset management: Update and improve programs for energy assets condition assessment and maintenance. Improve operability and control of existing cogeneration system. 2. Energy funding strategies: As part of the Comprehensive Asset Management Program (CAMP) and the budget process, support energy strategic initiatives that focus on continuous improvement related to energy efficiency and energy annual cost. While current budget pressures may slow the implementation of energy related initiatives, they should be evaluated in the context of facility wide need through the established CAMP process. 3. Energy initiatives awareness: Utilize EWA s website and other communications to make the public aware of the energy cost of accomplishing our work and of initiatives underway to reduce the amount of energy and cost devoted to providing our services. 4. Waste to energy implementation: Explore cooperative ventures between EWA and Member Agencies related to grease and food waste derive fuel production. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-22

199 Future Work EWPCF s culture of energy efficiency should be maintained. Additional efforts will contribute to this. These efforts should consider and include the following future studies, analysis and improvements. 1. Energy procurement management: The effort includes conducting tariff analysis, consideration of long term energy purchase contracts and new strategies for energy procurement. 2. Energy sub-metering: Expand and automate the system of monitoring and reporting electrical power use by plant area and equipment. This type of data supports energy use projections, management, and conservation. 3. Purchased energy quality and reliability: Evaluate the quality and reliability of electrical power being delivered to us. Determine if purchased power quality and reliability could be improved, if so, how. Consider actions to reduce our risk of not being able to provide services due to electrical power delivery shortcomings. 4. Energy asset security and internal reliability: Evaluate the security and reliability of assets related to distribution of self produced energy. Identify strategies for maintaining service in the event of natural disasters, component failure and human error. 5. Energy and use model: Explore expanding our energy use predictive model to include feedback from our metering and real time status of energy use and generation. Design the model to best support the staff resources of EWA. 6. Energy use and efficiency metrics: Establish metrics to measure improvement in the efficient generation and use of energy. 7. Energy conservation: Expand initial work related to demand reduction and search for additional energy conservation measures. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 8-23

200

201 Section 9: Grant and Incentive Programs Summary This section provides an overview of available funding opportunities to offset capital costs associated with improvements that would either reduce energy demand or enhance production of electricity. The available funding is in the form of incentives managed by the local supplier of energy (SDG&E) and state and federal grants. 9.1 Technology Based Funding Support Programs The technology evaluations presented in previous sections included a discussion of potential funding sources. Those technologies with specific funding opportunities are repeated in the following subsections Fuel Cells Funding Sources In California, the Self Generation Incentive Program (SGIP) governed by the California Public Utility Commission offers an incentive for fuel cells using a renewable fuel, such as digester gas, of $4,500 per kw up to 1 mw. For projects greater than 1mW, incentives of $2,250 per kw are available for the energy generated between 1 mw and 2 mw. Projects larger than 2 mw receive $1,125 per kw above 2 mw and up to 3 mw. Systems must be new, UL listed, and in compliance with all applicable performance and safety standards. Wind systems, fuel cells and advanced energy storage systems must be covered by a minimum five year warranty. The warranty must protect against the breakdown or degradation in electrical output of more than ten percent from the originally rated electrical output. The warranty should cover all replacement and labor costs. The incentive can go to the project if owned or leased. The SGIP might not receive additional funding beyond December 31, A federal tax incentive (ITC) is also available for installation of fuel cells, after first applying the state tax incentive. The federal incentive is the smaller of $3,000 per/kw or 30 percent of the cost. The federal incentive is available through The new law also allows taxpayers eligible for the business ITC to receive a grant from the U.S. Treasury Department instead of taking the business ITC for new installations. Unfortunately, as a tax exempt entity, Encina would not be eligible for these incentives. However, a tax exempt entity could take advantage of these incentives through a third-party lease arrangement. For instance, EWA could enter into an agreement with one of a Fuel Cell Energy (FCE s) distributors. Leasing the equipment through a distributor would allow EWA to gain some of the advantage of the tax incentives passed through in the form of a lower energy price. However, the lessor would charge a fee for this service. The potential funding from the two funding sources (assuming a lease arrangement to take advantage of the federal tax credit) for the Encina project is provided in the Table 62. Without a lease arrangement only the SGIP is available to EWA. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 9-1

202 Table 62: Potential Funding Sources Fuel Cell Source Incentive (300 kw) Incentive (1.4 MW) California Self Generation Incentive Program $1,350,000 $5,400,000 Federal Business Energy Investment Tax Credit $756,000 $756,000 Total $2,106,000 $6,156, Solar PV Funding Sources A number of different local, state, and federal incentives are available for solar energy projects. The rebates vary based on size of system and ownership (public entity or private). The following is a summary of rebates EWA may be eligible for California s Net Energy Metering (NEM) Net energy metering (NEM) applies to solar PV projects as long as the project is behind the meter. Eligible renewable resources are photovoltaics, wind, fuel cells and dairy biogas. System capacities are limited to a maximum of 1 mw in size. SDG&E is obligated by state law to provide a net metering agreement to all their customers. Net metering is a method of metering the energy consumed and produced by a customer that has a renewable resource generator, and credits the customer with the retail value of the generated electricity. Effectively, the meter runs backwards, causing a credit with the utility. RNet metering s benefit is the deferred cost of the electricity that EWA does not have to purchase, providing the full retail value of the electricity produced ($0.19 per/kwh). The renewable system must be intended primarily to offset part or all of the electric requirements for electricity at that meter. EWA does not have to own the eligible renewable resource; however the output must be dedicated to offset the electricity used at that meter. Net excess electricity (NEG), beyond that month s actual usage, is carried over as a credit for a 12-month cycle, but at the end of the 12-month period, any NEG is zeroed out and EWA would not be paid for that generation. It therefore becomes important to correctly size the project so that over the course of a year the project does not create any NEG. With net metering EWA would own all of the Renewable Energy Credits (RECs) and carbon credits from the renewable resource. Net metering does not preclude EWA s eligibility for other incentives The California Solar Initiative (CSI) This is part of the Go Solar California campaign which builds on 10 years of state solar rebates offered to customers in California's investor-owned utility territories. CSI rebates vary according to system size, customer class, and performance and installation factors. The subsidies automatically decline in "steps" based on the volume of solar megawatts confirmed within each utility service territory. The CSI rebate applicable to a 100 kw array in the year 2010 is the Performance Based Incentive (PBI). The PBI pays out an incentive, based on actual kwh production, over a period of five years. PBI payments are provided on a dollar per kilowatt-hour basis, based on a step system of statewide mw receiving rebates from the program. Currently, the payback for PBI rebates for a government owned solar system would likely be $0.26 per kwh produced. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 9-2

203 Federal rebates and incentives are available in the form of tax credits and rebates. Unfortunately, tax-exempt entities such as EWA are not eligible. However, a tax exempt entity could take advantage of these incentives through a third-party lease arrangement. For instance, EWA could enter into an agreement with a solar photovoltaic provider and enter into a long-term Purchase Power Agreement (PPA). This would not require EWA to commit any upfront capital but would require EWA to purchase the electric output of the solar photovoltaic system. Entering into such an arrangement would allow Encina to gain some of the financial advantage of the tax incentives passed through in the form of a lower energy price Microturbines Funding Sources A federal tax incentive is available for installation of microturbines through the Federal Business Energy Investment Tax Credit. The federal incentive is the smaller of $200/kW or 10 percent of the cost. As a tax exempt entity, Encina would not be eligible for these incentives. However, a tax exempt entity could take advantage of these incentives through a third-party lease arrangement. For instance, EWA could enter into an agreement with a third-party. Leasing the equipment through a distributor or buying output from a third-party owner could allow Encina to gain some of the advantage of the tax incentives passed through in the form of a lower energy price. The potential funding from the federal tax credit for a project at Encina is provided in Table 63. Table 63: Potential Funding Microturbines Source Incentive (65 kw) $13,000 Incentive (200 kw) Federal Business Energy Investment Tax Credit $40,000 Total $13,000 $40, Waste to Energy (WTE) Funding Sources The funding incentives for installing a waste receiving facility are geared to the ultimate use of the digester gas that is produced. Energy production incentives could be used to help fund a combined heat and power system (cogeneration). The improvements directly associated with waste receiving (i.e. pumps, tanks, and site improvements) are not eligible for incentives. However, energy efficiency incentives could be used to lower the cost of project components such as premium efficiency pumps and motors. Waste receiving can generate funds through tipping fees, which are charged to the haulers who use the waste receiving station. Tipping fees for grease trap waste can vary widely from $0.02 per gallon to $0.25 per gallon. Typical tipping fees for landfills that would normally take food waste range between $30 and $50 per ton. Based on the preliminary market assessment, tipping fees for grease trap waste at EWA could range from $0.02 to $0.08. Tipping fees for food waste could range from $30 to $50 per ton. Table 64 provides an example of the potential revenue from tipping fees. Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 9-3

204 Table 64: Estimated Revenue 5 Grease Trap Waste Load / day = 15,000 gallons 15,000 gallons grease trap waste / day x $0.05 / gallon = $750/day $750 / day x 260 days / year = $195,000/year 1 Food Scrap Waste Load / day = 10 tons 10 tons food scrap waste / day x $30 / ton = $300/day $300 / day x 260 days / year = $78,000/year Total Tipping Fees = $273,000/year Source: Savings by Design Funding Energy and Emissions Strategic Plan, Encina Wastewater Authority Page 9-4

205 Appendix A: Business as Usual Energy Data Appendix A presents current and projected baseline energy data through the year 2030.

206

207 Table A-1 EWA Baseline Electrical Energy Purchases and Production Billing Month Billing Days in Average Daily Flow Monthly Total Electricity Purchased Monthly On Peak Demand Monthly Non- Coincident Demand Non- Coincident Demand Monthly Total Electricity Generated Monthly Total Plant Demand Month MG kwh kw kw kw kwh kwh Average Use (kwh/mg) Apr , ,075 3, ,467 1,338,497 1,937 May , ,117 3, ,304 1,520,267 2,216 Jun , ,994 3, ,208 1,589,370 2,439 Jul , ,229 2, ,987 1,617,707 2,371 Aug , ,592 1, ,403 1,556,886 2,247 Sep , ,229 2,229 1,012,584 1,693,074 2,596 Oct , ,767 2,767 1,076,093 1,442,084 2,164 Nov , ,229 2,229 1,076,041 1,414,712 2,168 Dec , ,229 2,229 1,058,723 1,371,812 1,992 Jan , ,229 2,229 1,070,101 1,392,801 1,834 Feb , ,984 1, ,438 1,186,159 1,758 Mar , ,952 1, ,327 1,356,917 1,816 Baseline Annual Usage ,540,000 13,797 25,627 29,051 11,823,676 17,480,286 P:\2009\ EWA - Energy Management Strategic Plan\09-Reports\9.09-Reports\Final Report\Appendix A\App-A-tables.xls A-1

208 Table A-2 EWA Baseline Natural Gas and Biogas Purchase, Production and Use Billing Month Billing Days in Month Average Daily Flow MG Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Baseline Annual Usage 22.6 Total Natural Gas Purchased 1) Natural Gas used in Cogen Natural Gas used in Cogen Natural Gas used in Eclipse Natural Gas used in Eclipse Natural Gas used in Dryer Natural Gas used in Dryer Natural Gas used in RTO Natural Gas used in RTO Natural Gas used in Admin. Bldg. Natural Gas used in Admin. Bldg. Natural Gas used in Maintenance Bldg. Natural Gas used in Maintenance Bldg. therms scf therms scf therms scf therms scf therms scf therms scf therms scf therms scf therms scf therms scf therms 61, ,746 7, ,120 2,241 3,837,007 38, ,486 3, ,000 1, ,944, ,669 15,319,700 91, ,600 4,840 63,697 1,021,565 10, ,146,966 41, ,343 3, ,425 1,884 19, ,126, ,760 18,758, , ,700 2,212 75,793 1,263,387 12, ,887,521 48, ,135 3, ,851 2,589 7, ,444, ,664 17,671, , ,200 1,363 70,925 1,104,539 11, ,610,292 46, ,672 2, ,208 1,642 2, ,513, ,080 17,244, , ,300 1,616 76,925 1,178,571 11, ,994,200 49, ,908 3, ,818 1, ,205,300 97,232 15,222,000 91, ,300 5,900 79,051 1,907,280 19, ,920 2,519 4,859,000 48, ,938 3, ,744 1,247 4, ,487, ,926 18,457, , ,500 1,155 84, ,762 3, ,470 3,615 4,844,000 48, ,869 3, ,028 1,620 19, ,416, ,496 25,373, , ,500 2,427 71,344 42, ,450 2,765 4,644,800 46, ,792 3, ,117 1,981 16, ,425, ,555 20,200, , ,300 3,014 72, ,530 1,695 4,836,900 48, ,684 3, ,946 2,309 6, ,061, ,366 22,061, , ,300 3,836 75, ,450 1,635 5,314,916 53, ,041 3, ,090 1,801 21, ,266, ,601 22,031, , ,640 3,820 59, ,523 1, ,820 1,378 3,796,924 37, ,760 3, ,659 3,097 12, ,677, ,062 17,126, , ,227,700 13,366 60, ,235 8,002 96, ,406,864 34, , , ,117 2,831 14, ,678, ,068 15,568, ,408 2,769,427 15,000 1,990, , ,828 13,822,839 87,000 2,522,475 25,225 40,882, ,794 4,127,611 41,276 2,432,003 24, ,364 2, ,115,311 1,250, ,048,850 1,218,293 2,769,427 15,000 6,036,408 35,000 1) 695,700 therms natural gas recorded by EWPCF process unit meters Digester Gas Produced Digester Gas Produced Digester Gas used in Cogen Digester Gas used in Cogen Digester Gas used in Dryer Digester Gas used in Dryer Digester Gas Flared Digester Gas Flared P:\2009\ EWA - Energy Management Strategic Plan\09-Reports\9.09-Reports\Final Report\Appendix A\App-A-tables.xls A-1

209 Table A-3 EWA Baseline Heat Production Use Heat Production and Use Billing Month Billing Days in Average Daily Flow Heat from Cogen Absorption Chiller Heat Demand Digester Heat Demand Heat Wasted From Cogen. Exhaust Heat from RTO Total Heat Used Total Heat Wasted Month MG Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Baseline Annual Usage 22.6 MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr MMBtu/hr P:\2009\ EWA - Energy Management Strategic Plan\09-Reports\9.09-Reports\Final Report\Appendix A\App-A-tables.xls A-1

210 Table A-4 EWA Baseline Detailed Electricity and Gas Production and Use Projections for Business as Usual Percent of electricity used for NON-flow-dependent processes: Baseline Electricity Required to Treat Water (kwhr/mgd): Baseline Electricity Produced by Treating Water (kwhr/mgd): 25% 580, ,284 Baseline Ratio of Digester Gas to Natural Gas in Dryer: 92% Maximum Ratio of Digester Gas to Natural Gas in Dryer: Baseline Natural Gas Required for RTO to Treated Water (Therms/MGD): 82% 1,827 Gas & Energy Production data per May 2010 SDAPCD Permit Modifications Baseline Digester Gas Produced by Treating Water (Therms/MGD): 55,795 Max Elect - biogas Max biogas + Naural Gas Baseline Digester Gas Flared (Percent of Total Produced): 64.6% Volume Max kwh/yr therms/yr kwh/yr MMCF/Yr Max Allowable Digester Gas in Cogen per May 2010 SDAPCD permits (Therms/year): 1,344, MMCF/Yr 12,868,209 1,209,600 11,581, Max Allowable Natural Gas in Cogen per May 2010 SDAPCD permits (Therms/year): 224,000 * MMCF/Yr 224,000 2,144, Engine Heat Recovery/Fuel Input: 33% * Maximum = 10% Biogas 1,433,600 13,726,089 Baseline Heat Required for Digesters to Treat Water (MMBtu/Hr/MGD): % Percent of Digesters Static Heat Loss: 30% Electricity Use/Production Gas Use/Production Year Average Flow Total Plant Total Non-Flow- Digester Total Plant Total Electricity Flow- Natural Gas Natural Gas 18% Dryer Maximum Natural Gas Natural Gas Total Natural Flow- Digester Digester Gas Digester Digester Electricity Dependent Total Dryer Natural Gas Natural Gas Digester Gas Gas Demand Electricity Demand Dependent Used in Used in Gas DryerDG Used in Used in Gas Dependent Gas Used in Gas Used in Gas Used Purchased Generated Energy Gas Demand Used in Dryer Used in RTO Gas Flared Avaialble for (Purchased + (Purchased + Energy Used Cogen. Eclipse Demand Demand Admin. Bldg. Maint. Bldg. Purchased Nat. Gas Used Produced d Cogeneration Dryer in Dryer (Cogen.) Used Dryer Produced) Produced) MGD kwh kwh kwh kwh kwh Therms Therms Therms Therms Therms Therms Therms Therms Therms Therms Therms Therms Therms Therms Therms Therms Percent Therms ,498,858 12,868,209 17,367,067 12,996,995 4,370, ,588 99, , ,588 40,920 24,320 2, , ,508 1,249, ,344, % 1,870, ,157,218 12,868,209 18,025,426 13,655,355 4,370, , , , ,630 42,992 24,320 2, , ,622 1,313, ,344, % 1,964, ,815,577 12,868,209 18,683,786 14,313,715 4,370, , , , ,250 45,065 24,320 2, , ,315 1,376, ,344,000 32,422 32,422 5% 2,025, ,473,937 12,868,209 19,342,146 14,972,074 4,370, , , , ,983 47,138 24,320 2, , ,121 1,439, ,344,000 95,730 95,730 15% 2,055, ,132,297 12,868,209 20,000,506 15,630,434 4,370, , , , ,717 49,211 24,320 2, , ,927 1,503, ,344, , ,039 24% 2,085, ,790,657 12,868,209 20,658,865 16,288,794 4,370, , , , ,450 51,284 24,320 2, , ,734 1,566, ,344, , ,347 32% 2,115, ,449,016 12,868,209 21,317,225 16,947,153 4,370, , , , ,183 53,356 24,320 2, , ,540 1,629, ,344, , ,656 40% 2,145, ,107,376 12,868,209 21,975,585 17,605,513 4,370, , , , ,917 55,429 24,320 2, , ,346 1,692, ,344, , ,964 47% 2,175, ,765,736 12,868,209 22,633,944 18,263,873 4,370, , , , ,650 57,502 24,320 2, , ,152 1,756, ,344, , ,273 53% 2,205, ,424,095 12,868,209 23,292,304 18,922,232 4,370, , , , ,383 59,575 24,320 2, , ,958 1,819, ,344, , ,582 59% 2,235, ,082,455 12,868,209 23,950,664 19,580,592 4,370, , , , ,117 61,647 24,320 2, , ,764 1,882, ,344, , ,890 65% 2,266, ,740,815 12,868,209 24,609,023 20,238,952 4,370, , , , ,850 63,720 24,320 2, , ,570 1,946, ,344, , ,199 70% 2,296, ,399,174 12,868,209 25,267,383 20,897,312 4,370, , , , ,583 65,793 24,320 2, , ,376 2,009, ,344, , ,507 75% 2,326, ,057,534 12,868,209 25,925,743 21,555,671 4,370, , , , ,317 67,866 24,320 2, , ,182 2,072, ,344, , ,816 79% 2,356, ,715,894 12,868,209 26,584,102 22,214,031 4,370, , , , ,311 69,939 24,320 2, , ,250 2,136,124 16,261 1,344, , ,863 82% 2,402, ,374,254 12,868,209 27,242,462 22,872,391 4,370, , , , ,359 72,011 24,320 2, , ,370 2,199,433 56,576 1,344, , ,857 82% 2,473, ,508,865 12,868,209 27,377,074 23,007,002 4,370, , , , ,391 72,435 24,320 2, , ,826 2,212,377 64,819 1,344, , ,559 82% 2,487, ,643,477 12,868,209 27,511,686 23,141,614 4,370, , , , ,423 72,859 24,320 2, , ,282 2,225,322 73,061 1,344, , ,260 82% 2,502, ,778,089 12,868,209 27,646,297 23,276,226 4,370, , , , ,455 73,283 24,320 2, , ,738 2,238,266 81,304 1,344, , ,962 82% 2,516, ,912,700 12,868,209 27,780,909 23,410,838 4,370, , , , ,487 73,707 24,320 2, , ,194 2,251,211 89,547 1,344, , ,663 82% 2,530, ,047,312 12,868, ,915, ,545, ,370, ,002, , , ,519 74,130 24,320 2, , ,649 2,264, , ,344, , ,365 82% 2,545, Abbreviations: Footnotes 1) May 2010 SDAPCD permit modifications increased total allowable Biogas use in IC engines kw = Kilowatts 2) Unit energy values noted above based on observed baseline operating conditions (April 2009 through May 2010) kwh = Kilowatt-hours 3) Flow projections provided by EWA MGD = million gallons per day 4) Energy demand independent of flow estimated from recorded uses within EWPCF SCFM = Standard Cubic Feet per Minute 5) EWA could maximize self generation by fueling IC engines with 90% Biogas and 10% natural gas; table values assume no natural gas used as IC engine fuel 6) Table valuse based on Biogas first priority is IC Engine fuel source, dryer fuel source is secondary priority Conversions: 1 Btu = kwh 1 therm = 100,000 Btu 1 cf digester gas = 600 Btu 1 cf nat. gas = 1000 Btu 1 therm = kwh 1 kwh = 3414 Btu 1 kwh = therms Other Factors IC engine gas eff 32.70% P:\2009\ EWA - Energy Management Strategic Plan\09-Reports\9.09-Reports\Final Report\Appendix A\App-A-tables.xls A-1

211

212 Table A-5 EWA Energy Production and Use Projections 5 Year Increment Projections for Business As Usual Year Average Flow Total Electricity Purchased Electricity Use/Production Total Electricity Generated (Cogen.) Total Plant Electricity Demand (Purchased + Produced) Natural Gas Used in Cogen. Natural Gas Used in Dryer Natural Gas Used in RTO Natural Gas Used in Admin. Bldg. Natural Gas Used in Maint. Bldg. Gas Use and Production Total Digester Gas Natural Gas Produced Purchased Digester Gas Used in Cogeneration Digester Gas Used in Dryer Digester Gas Flared Total Plant Gas Demand (Purchased + Produced) MGD kwh kwh kwh Therms Therms Therms Therms Therms Therms Therms Therms Therms Therms Therms MMBtu/hr MMBtu/hr MMBtu/hr MMBTu/hr MMBtu/hr MMBTu/hr Heat Produced in Cogen Absorption Chiller Heat Demand Heat Use and Production Digester Heat Demand Waste Heat From Cogen. Heat Wasted From RTO Total Waste Heat ,367,067 12,000,000 17,367, ,588 40,920 24,320 2, ,136 1,249,805 1,249, ,895, ,158,865 12,500,000 20,658, ,450 51,284 24,320 2, ,362 1,566,347 1,344, , ,140, ,450,664 12,500,000 23,950, ,117 61,647 24,320 2, ,392 1,882,890 1,344, , ,291, ,415,521 12,500,000 27,915, ,577 74,130 24,320 2, ,336 2,264,155 1,344, , ,848 2,590, P:\2009\ EWA - Energy Management Strategic Plan\09-Reports\9.09-Reports\Final Report\Appendix A\App-A-tables.xls A-1

213 Appendix B: ECOS Energy Audit Report A full copy of the energy audit prepared by ECOS is provided in this appendix.

214

215 TM Making a World of Difference Portland, OR San Francisco, CA Seattle, WA Durango, CO Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis Submitted by: Ecos 309 SW 6th Avenue #1000 Portland OR April 6, 2010

216

217 DISCLAIMER In no event will Ecos Consulting be liable for (i) the failure of the customer to achieve the estimated energy savings or any other estimated benefits included herein, or (ii) for any damages to customer's site, including but not limited to any incidental or consequential damages of any kind, in connection with this report or the installation of any identified energy efficiency measures. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

218 CONTACTS & PREPARATION KENNEDY/JENKS CONTACTS The following Kennedy/Jenks personnel assisted with this report: Ted Schilling, PE Energy Services Client Manager Kennedy/Jenks Consultants 200 Southwest Market Street, Suite 500 Portland, OR P: F: C: Direct: ECOS CONTACTS Mike Bailey, P.E. Patti Boyd Ecos IQ 309 SW Sixth Ave., Suite 1000 Portland, OR x146 (M. Bailey) Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6, 2010 i

219 TABLE OF CONTENTS 1.0 EXECUTIVE SUMMARY Introduction About Ecos Energy Efficiency Measure (EEM) Summary... 3 Aeration and Agitation Blower System... 3 Variable Frequency Drives (VFD)... 3 Lighting and Sensors... 3 Compressed Air System (Service Air) Economic Summary DETAILED DESCRIPTION OF ENERGY EFFICIENCY OPPORTUNITIES Aeration and Agitation Blower System EEM 1: Fix leaks in supply pipe or move blowers adjacent to the basins EEM 2: Reduce operation of the aeration/agitation blowers for demand response EEM 3: Retrofit existing blower throttle control with VFD control EEM 4: Replace multi-stage centrifugal compressors with turbo blower technology Variable Frequency Drives EEM 5: Retrofit Plant Water 3WHP pumps with VFD control EEM 6: Retrofit other Plant Water pumps with VFD control EEM 7: Retrofit HVAC Fans with VFD control EEM 8: Retrofit Solids Digestion pumps with VFD control Lighting and Sensors Description of Lighting EEM 9: Lighting Improvements Compressed Air System (Service Air) REC 1: Compressed Air System Recommendation Motor Efficiency ANALYSIS OVERVIEW Energy Use Breakdown Annual kwh and Cost per Usage Category SAN DIEGO GAS AND ELECTRIC REBATES AND INCENTIVES Caveats Sources and Information Review of Sources Standard Performance Contract Program Energy Savings Bid Program (ESB) Interim Application Express Efficiency Program APPENDICES Appendix A: Aeration Blower Upgrade/Replacement Estimates and Brochure Appendix B: SDG&E AL-TOU Rate Schedule Appendix C: Premium Efficiency Motors Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6, 2010 ii

220 1.0 EXECUTIVE SUMMARY 1.1. Introduction The Ecos technical team performed a 1.5-day walk-though energy audit of the Encina Wastewater Authority facility located at 6200 Avenida Encinas, Carlsbad CA This audit consisted of a site visit by Mike Bailey, P.E. and Patti Boyd who evaluated major energy using equipment, their condition, and current operation. The audit and this resulting report focus on the top four largest energy using systems at the facility as measured by both their peak power draw and the frequency of operation (annual energy use = average kw x hours of operation per year. The annual kwh and cost in dollars for each of the plant s systems are tabulated in Table 10. The equipment reviewed included: Motors Pumps VFD HVAC / cooling systems Lighting Control Systems Cogeneration/process combustion Other equipment The major systems reviewed during the site visit included: Activated Sludge* HVAC* Solids Digestion* Plant Water* Return Activated Sludge Pumps Lighting Thickener Cogeneration Secondary Clarifiers Headworks Disinfection Miscellaneous, usage not labeled (primary/secondary equalization pumps) Waste Activated Sludge Pumps Primary Effluent Pumping Solids Dewatering *Top four energy users at EWA Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

221 Prior to visiting the site, Ecos engineers reviewed available technical and operations information for the facility to prepare our team to identify priority systems and equipment to review during the site visit. Of critical importance for an analysis is accurate information on the annual operating hours of each major piece of equipment evaluated since operating conditions during our actual site visit might not be representative of the facilities operations throughout the entire year. After the site visit we reviewed all provided information including prior audits, recommended process optimization improvements, and developed our own observations from the collected data. Our analysis developed estimates of energy use (kwh/year) of current equipment and Energy Efficiency Measures (EEM) that represent opportunities for reducing current energy consumption. Where possible, we estimated the cost of implementing these EEM, the estimated annual energy savings, and the resulting simple payback on the investment. For each measure we will identify potential incentives provided by the local utility (SDG&E) to help offset some of the measure installation cost. The utility incentives will be included on the estimated financial payback for each EEM. This report for the Encina Water Authority (EWA) plant documents the audit areas as well as the energy efficiency measures with energy saving potential. Costs and return on investment timeframes are included for all efficiency measures described. Section 1.2 below summarizes the most favorable measures. ECOS was provided an annualized cost electricity of $0.1923/kWh. This was used to perform calculations in this report. The Kennedy/Jenks Consultants project team determined the annualized cost to be $0.1873/kWh later in the project. It was decided to not rework the calculations in this report. The difference of 2.6% would not significantly change the results and recommendations About Ecos Ecos has been performing audits since 1997 has focused specifically on services for commercial and industrial (C&I) customers since Led by Mike Bailey, P.E. (Mechanical CA M31192), the team has the experience and expertise to translate audit findings into actionable recommendations for facility operators to implement energy-saving practices and measures. Our experience includes recent work with the wastewater treatment facility in Benicia, California to identify energy-efficiency opportunities. Through this audit and evaluation service and resulting changes to the plant s compressed air systems, we were able to nearly halve the amount of energy use in their aeration processes. Ecos has been a certified Allied Technical Assistance Contractor (ATAC) provider for the Energy Trust of Oregon since 2008, providing audit and implementation plan development services for a variety of C&I customers throughout Oregon. These services include performing visual inspections, collecting data logs from power meters and developing recommendations for capital and operational improvements based on the audit findings. We also have substantial experience with auditing through several programs we operate for utilities throughout the country, such as a compressed air program for Pacific Gas and Electric (PG&E), multifamily complex audits and commercial audits for LED lighting applications in parking garages for Oncor in Texas. Further, Ecos has also been working with the Northwest Energy Efficiency Alliance (NEEA) for the past five years to promote Continuous Energy Improvement (CEI), a term used initially by NEEA to describe its implementation of strategic energy management processes and concepts with industrial customers in the Northwest. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

222 1.3. Energy Efficiency Measure (EEM) Summary Ecos audit and subsequent analysis identified the following efficiency measures and a recommendation with financial merit. Aeration and Agitation Blower System EEM 1: Fix leaks in supply pipe or move blowers adjacent to the basins. EEM 2: Reduce operation of the aeration/agitation blowers for demand response. EEM 3: Retrofit existing blower throttle control with VFD control. EEM 4: Replace multi-stage centrifugal compressors with new, turbo blower technology. Variable Frequency Drives (VFD) Retrofit fans and circulation pumps with VFD control EEM 5: Retrofit Plant Water 3WHP pumps with VFD control. EEM 6: Retrofit other Plant Water pumps with VFD control. EEM 7: Retrofit HVAC Fans with VFD control. EEM 8: Retrofit Solids Digestion pumps with VFD control. Lighting and Sensors EEM 9: Install occupancy sensors for the lighting in the motor control centers and continue upgrading existing lighting with more efficient fixtures. Compressed Air System (Service Air) REC 1: Perform a compressed air system audit to determine if a smaller air compressor with VFD control can provide adequate flow for the existing system while using less power. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

223 1.3. Economic Summary Table 1 summarizes the energy savings and the subsequent incentives available for the proposed EEMs in order from smallest to largest payback. Table 1: Estimated SDG&E Incentives, Energy Savings, and Simple Payback Utility Incentive EEM No SDG&E Industrial Rate Description Measure Cost Current kwh Consumption $0.09 per kwh $0.05 per kwh kwh Savings New kwh Consumption kwh savings motors/other lighting Estimated Incentive ($) Current kw Peak $100 per peak kw kw (Demand) Savings New kw Peak Peak kw savings Estimated Incentive ($) Incentives per SDG&E's Standard Performance Contract Program Yearly Savings ($) Measure Budgetary Cost After Incentives Simple Payback After Incentives (years) 2 Cease operation of the aeration/agitation blowers for demand response $ - 6,663,463 6,663,463 - $ $82,060 $ 28,171 Immediate n/a 5 Retrofit Plant Water 3WHP pumps with VFD control $ 34, , , ,954 $ 17, $4,543 $ 76,527 $ 17, Retrofit HVAC Fans with VFD control $ 99,500 1,630, , ,130 $ 49, $9,305 $ 156,749 $ 49, Retrofit Solids Digestion pumps with VFD control $ 115,250 1,489, , ,863 $ 57, $8,503 $ 143,237 $ 57, Retrofit other Plant Water pumps with VFD control $ 72, , , ,585 $ 33, $4,242 $ 71,456 $ 39, Retrofit existing blower throttle control with VFD control $ 394,820 6,663,463 5,118,960 1,544,503 $ 139, $23,900 $ 297,008 $ 231, Replace multi-stage centrifugal compressors with new, turbo blower technology Install occupancy sensors for the lighting in the motor control centers and continue upgrading existing lighting with more efficient fixtures Fix leaks in supply pipe or move blowers adjacent to the basins (assume 10% savings, assume piping fix is $3M) $ 1,243,000 6,663,463 4,653,084 2,010,379 $ 180, $29,223 $ 386,596 $ 1,032, $ 51, , ,955 74,504 $ 3, $350 $ 14,327 $ 47, $ 3,000,000 6,663,463 5,997, ,346 $ 59, $8,206 $ 128,138 $ 2,931, Assumptions: Incentives are based on Standard Performance Contract Program in Section (Table 12) (EEM1) 10% decrease in consumption (kwh and kw) for fixing leaks (EEM1) Replacement of blower supply pipe = $3M (EEM 2) No change in kwh consumption for demand response (EEM 3) capped at 50% of $200k cost with kwh incentive alone Demand charges were taken from AL-TOU (Appendix B) = $34.33/kW (EEM 9)Section EEM 9 contains lighting assumptions Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

224 2.0 DETAILED DESCRIPTION OF ENERGY EFFICIENCY OPPORTUNITIES After analyzing the systems and equipment at EWA, Ecos identified four areas to focus on. Each of these system areas have energy efficiency measures that EWA should consider for implementation. These are outlined in detail in the following section. Two of these focus areas have identified large energy and cost savings: Blower System and VFD installation on numerous fans and pumps. While these areas have large potential savings, these savings will require close coordination with operations and may require some process adjustments. VFDs have been recommended on systems that may have little or no process change. This recommendation provides flexibility to the operations group to make adjustments without having to use additional labor and materials expense to change out sheaves, for example. It is understood that operations and process benefits versus risks must be evaluated before implementing the recommended EEMs. The other two focus areas, Lighting and Compressed Air, have relatively small opportunities for savings, but are relatively easy to implement with little to no impact on plant operations Aeration and Agitation Blower System EWA has multiple multi-stage centrifugal blowers of different sizes and ages used to provide aeration and agitation air to the Primary Equalization basins (Figure 1). Typical operation of this system is for two 500 hp blowers to operate (throttled) to provide the required supply of air for both the aeration and agitation systems. When higher flow is required, the third 500 hp blower is initiated and, if more air is required, agitation air can be supplied by a single 250 hp blower. This may happen in summer months, when the weather is warmer and there is higher flow which also may require an additional basin. EWA currently averages 23 MGD in two basins. The third basin is triggered at 36 MGD, and the fourth at 45 MGD. Table 2 provides a high level description of the blower equipment. As expected, this equipment comprises the largest energy use at the facility and following logically, the largest savings opportunities lie here. Figure 1: Aeration Blower Table 2: Blower Equipment High Level Information Size Model # Manufacturer 500 hp Catalog #: AD Lamson 500 hp Assume AD Lamson 500 hp Type: MVI-54 Roots 350 hp AD00 Gardner Denver 250 hp Type: MVG-64 Roots 250 hp Assume MVG-64 Roots Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

225 As detailed in Section 3.2, the blowers in the Activated Sludge usage category use approximately 6,663,463 kwh of energy for an estimated annual cost of almost $1.3 Million (assuming all power is purchased at EWA s assumed levelized rate of $ per kwh). As described by multiple facility personnel, one of the main issues the plant has with this system are the multiple leak locations where a significant portion of the compressed blower air is basically used to aerate the dirt. The air can be felt physically blowing out of the ground in multiple locations along the approximately 180 yards from the blower building to the basins. Ecos believes that this is a major issue for EWA that must be addressed in their quest to be as efficient a facility as possible and to manage process risk. It is also thought that once the leakage issue is under control, there will be a drastic reduction in the quantity of air required by the system, resulting in a large reduction in energy required to produce that air. The following sections detail Ecos recommendations for EWA and their aeration/agitation system EEM 1: Fix leaks in supply pipe or move blowers adjacent to the basins The piping used for this system (Figure 2) is comprised of the aeration piping (4 diameter) and the agitation piping (2 diameter) which runs for approximately 180 yards from the aeration building to the basins (Figure 3). Approximately 75% of the length is under ground. Figure 2: Aeration/Agitation Piping Figure 3: View from basins to blower station There are two ways to address the significant leak issue, but both are costly. First, the current pipeline could be repaired or completely reconstructed while continuing to provide air from the blowers existing location. Alternatively, a new blower station could be created near the basins which could bypass the leaking pipe and supply air directly to the basins. Figure 4 shows a possible location for this new station which is approximately 20 yards from the basins. Figure 4: Possible Location for New Blower Station In order to estimate the amount of loss EWA is experiencing by leakage, Ecos used rough flow values that were witnessed during the site audit. At that time, two 500 hp blowers were in operation producing 17,838 CFM (Figure 5). Per the SCADA display, 9,600 CFM was going to the aeration system and the agitation system (comprised of three flows 1,594 CFM, 412 CFM, and 1,256 CFM) was receiving a total of 3,262 CFM. Simply subtracting the flow to the aeration/agitation systems Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

226 shows that it is possible that 17,838 CFM 9,600 CFM 3,262 CFM = 4,976 CFM (28%) of total flow is being wasted. This appears to be an incredibly large value and may be due to errors in the flow meters or time differences in the readings (the total flow in the blower room was taken at a different time than the SCADA readings of flow to the aeration and agitation basins). The three aeration blowers combined for a total 12 month energy use (based on actual data for the first 11 months of 2009) of 6.3 million kwh. Ten percent of this would be 630,000 kwh worth $128,000 per year. If the actual loss rate was twenty percent, the annual cost for the loss would be about $242,000. Figure 5: Screenshot of Blower Control System during Audit EEM 2: Reduce operation of the aeration/agitation blowers for demand response Demand charges can make up the largest portion of an industrial customer s energy cost, if not managed properly. EWA manages the peak demand as standard operating procedure. In addition to all other blower recommended measures, reducing operation of the blowers during peak hours should be evaluated for further energy reduction opportunities.. Pre-charging the basins with oxygen during nonpeak hours to help minimize the effect of the absence of aeration air should be evaluated for its benefit versus process risk. It is understood that varying operational conditions may not allow this EEM to be implemented. For the purposes of this report, the peak demand schedule was taken from SDG&E s SCHEDULE AL- TOU and is shown in Figure 6. Figure 6: SDG&E s Schedule AL-TOU for Peak Demand Charges 1 1 Appendix B, total demand charge is assumed to be = $34.33/kW Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

227 2.1.3 EEM 3: Retrofit existing blower throttle control with VFD control As previously stated, normal operation consists of two (2) qty. Lamson 500 hp blowers running 24 hours 7days per week to provide the necessary aeration and agitation air. These blowers are multi-stage centrifugal blowers with inlet choke valves for flow and pressure control. This is an excellent application for VFD 2 to control input power to achieve desired output rather than the current process of restricting input air which actually false loads the blower motor into working even harder. This false load situation is due to the fact that when air flow into the blower is restricted, the inlet pressure becomes negative and drops below atmospheric pressure. The blower then must work harder to achieve the desired output (system) pressure as it moves "up" the blower s fan curve, resulting in a higher delta P and causing output flow to be reduced. At the time of our visit, two blowers were operating with part of the output choked through a control valve that was 20% open in order to reduce discharge pressure from 8.2 psi to 2.2 psi (agitation). This scenario results in a loss of approximately 60% of the energy content before the air has even left the machine room. For the purposes of this study, Ecos consulted with a reputable vendor of centrifugal blowers and VFD upgrades to existing blowers who helped develop cost and savings estimates for replacing EWA s existing multi-stage centrifugal blowers with turbo blowers. Cost comparisons were done at 9000 SCFM (standard conditions at sea level for temperature and pressure). This is due to the fact that an existing multistage blower while throttled uses more than 500 hp in some of the conditions at ICFM 3. The resulting energy usage and annual cost is detailed in Table 3 for illustration purposes. Actual results may vary: Table 3: Estimated Energy Usage and Annual Cost for VFD Retrofit of Existing Lamson Blowers EEM No Description Inlet Temp Total Input kw 3 Upgrade existing throttle controlled blowers with VFD control Total after Implementation Cost per Day Days per Estimated Annual Annual kwh ($0.1923/kWh) Year Cost $ 2, ,152 $ 173, $ 2, ,065,728 $ 397, $ 2, ,761,552 $ 338, $ 2, ,528 $ 75, $ 10, ,118,960 $ 984,376 Existing Electricity Usage and Cost (Section 3.2) Estimated Annual Electricity Savings 6,663,463 $ 1,281,384 1,544,503 $ 297,008 Measure Cost Before Incentive Simple Payback in years (Estimated Annual Savings / $ 394, Measure Cost Before Incentive) 2 See Section 2.2 for a detailed discussion of how installing a VFD on a blower can produce a substantial amount of energy savings. 3 Inlet cubic feet per minute - ICFM - is used by compressor vendors to establish conditions when the inlet to the compressor is throttled to account for the resulting pressure drop. The conversion from ICFM to ACFM (actual cubic feet per minute) can be expressed as ACFM = ICFM (P act / P f ) (T f / T act ), and the conversion between ACFM and SCFM (standard cubic feet per minute) can be expressed as ACFM = SCFM [P std / (P act - P sat Φ)](T act / T std ). Where P act = absolute pressure at the actual level (psia), P f and T f = pressure/temperature after filter or inlet equipment (psia, R), T act = actual ambient air temperature ( R), P std = standard absolute air pressure (psia), P sat = saturation pressure at the actual temperature (psi),ø = actual relative humidity, and T std = standard temperature ( R). Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

228 2.1.4 EEM 4: Replace multi-stage centrifugal compressors with turbo blower technology Figure 7: Cut Away of Turbo Blower Wastewater treatment facilities commonly use low-pressure multi-stage centrifugal blowers to supply air to aeration tanks for mixing and biological oxidation. These throttle controlled multistage blowers are notoriously inefficient, may require independent cooling, and a great deal of maintenance while offering poor control, loud noise, and a large physical footprint. Evidence of poor performance includes the large amount of heat produced. Alternatively, there is a technology of a completely different design from these existing blowers. This centrifugal High-Volume, Low-Pressure (HVLP) 4 turbo blower (Figure 7) is based on micro-turbine compressor technologies with RPM of 20,000-30,000 (compared with typical blowers at 1800 rpm and much looser tolerances), uses precision machined components and built-in/ integrated variable frequency drive (VFD) controls, and have air bearings to reduce friction. This allows the turbo blower to produce the same discharge flow volume and system pressure requirement while using much less electricity. Although cost for this technology is higher than a multistage compressor (or upgrading the existing compressor with a variable frequency drive), kwh usage is reduced. Ecos has experience with this new blower technology in a wastewater aeration application where actually monitored energy consumption was decreased by approximately 50% while the same discharge flow volume and pressure were maintained. At this plant, two blowers were installed in September 2008 and as of February 2010, the blowers are still working well. For the purposes of this study, Ecos consulted with a reputable vendor for this type of equipment who helped develop cost and savings estimates for replacing EWA s existing multi-stage centrifugal blowers with turbo blowers. Each of the two (2) qty. Lamson 500 hp blowers that are in normal operation would be replaced by two (2) qty. 300 hp turbo blowers, for a total of four (4) turbo blowers. The results of the comparison are presented in Table 4. Table 4: Estimated Energy Usage and Annual Cost for Replacement of Existing Blowers with Turbo Blowers EEM No Description Inlet Temp Total Input kw Cost per Day Days per Estimated Annual Annual kwh ($0.1923/kWh) Year Cost $ 2, ,680 $ 158,394 Replace each 500 hp Lamson $ 2, ,878,156 $ 361,169 Blower with 2 qty. Turbo $ 2, ,597,440 $ 307,188 Blowers $ 2, ,808 $ 68,037 Total 2115 $ 9, ,653,084 $ 894,788 Existing Electricity Usage and Cost (Section 3.2) 6,663,463 $ 1,281,384 Estimated Annual Electricity Savings 2,010,379 $ 386,596 Measure Cost Before Incentive Simple Payback in years (Estimated Annual Savings / $ 1,243, Measure Cost Before Incentive) 4 Appendix A has cost and energy usage estimates as well as a brochure for a Turbo Blower. References from HSI of both installed and in progress projects are also included. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

229 2.2. Variable Frequency Drives Variable Frequency Drives (VFD), also commonly referred to as Adjustable Speed Drives (ASD) or Variable Speed Drives (VSD) are an excellent opportunity for energy savings in centrifugal equipment such as blowers, fans (Figure 8) or pumps. For the purposes of this report we will discuss savings achieved after installing a VFD where frequency is adjusted to vary the speed of equipment. VFDs use solid state electronics to modify the AC power that is sent to the motor, allowing the motor speed and power consumption to vary from the motor s full load or design condition. VFDs have been greatly improved over the last years and have become much more affordable even for motors as small as 2-3 Horse Power (hp). One of the most common applications for VFD are in locations that require variable flow or pressure such as the aeration system, but constant loads on fans and pumps are an often overlooked opportunity. Centrifugal fans and pumps are designed to turn the rotational energy of the motor into increased flow and pressure of a fluid either gas or liquid. These types of rotating equipment follow a set of relationships called the Fan / Pump Affinity Laws. These laws of physics dictate how this type of equipment operates. The laws state that for a fixed physical system (no change in impeller or fan) flow is directly proportional to rotational speed (often measured in rotations per minute or RPM), while the power required (electricity in kw) is proportional to the cube of the rotational speed: Figure 8: Belt Driven Fan When equipment is designed, typically the engineer builds in a sizing safety factor to ensure it is large enough to do the job required (so larger than what is expected to be required). This sets the MINIMUM size of the equipment that the project team must purchase but usually the standard equipment size that is actually installed is slightly larger than the design size. For these reasons it is often possible to reduce Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

230 the flow of fans and pumps by 20 percent (saving 50 percent of the power!) with little or no impact to the processes or intended purpose of the equipment. A word of caution however, there may be a few (although surprisingly rare) situations where reduced flow CAN have an undesired affect on the process or proper equipment operation. It is much more common to discover that flow can be decreased more than 20 percent resulting in even greater savings (a 30 percent reduction in flow results in a 66 percent reduction in power). The only true way to determine which situation exists is to consider the process and the role the equipment plays carefully. If the initial review does not uncover any adverse affects, then the VFD should be installed and the flow gradually reduced as much as possible to a minimum level where process performance is not affected. Exhaust fans and circulation pumps are excellent opportunities for this kind of application of VFD. It is rare that a 20-30% reduction in flow of an exhaust or circulation pump will be noticed. Care should be taken to consider the entire system for example if the exhaust fan flow is reduced, but the fresh supply air is not reduced as well, the space could become over-pressured. This does not mean that a VFD should not be installed. It does mean that VFD should be installed on both the exhaust and supply fans so they can be reduced together. Another interesting consequence of the Affinity laws is that for these types of systems it is better to operate multiple parallel pieces of equipment at partial load rather than a single unit at full load. For example two pumps (or fans) operating in parallel at half design flow (both the same size) would use only a quarter (25 percent) of the power required if one of them were operating at full flow. While both operating conditions produce the same total flow, operating two in parallel results in a potential power REDUCTION of as much as 75 percent! Ecos was able to identify many potential opportunities for this kind of VFD application. To estimate energy savings we assumed a 20 percent flow reduction was possible resulting in a 50 percent reduction in current energy use (based on actual operating hours). Many of these systems could be reduced more or could operate in parallel which would result in additional savings. Although adding VFDs to motors is a more expensive first cost alternative to a traditional sheave or impeller changes to lower flow/power, the VFDs allow for a full range of control (larger operating range) where changing sheaves removes the option of ramping back up to full flow if it is ever required. In addition, changing sheaves may result in the same energy savings as a VFD if the actual load on the motor is reduced, but it is difficult to adjust and once sheaves are changed. The sheave/belt/pulley may not result in the same load savings if motor load is not reduced by the same amount as what would be achieved with a VFD. Finally, this is fundamentally an interactive optimization opportunity reducing flow as much as possible to meet process requirement but minimizing over-pumping that wastes energy with no process benefit. This optimum energy / process flow point is very difficult to predict in advance and may change overtime this lends the VFD as a much more flexible solution than sheave or impeller changes. The opportunities are detailed in the following tables. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

231 2.2.1 EEM 5: Retrofit Plant Water 3WHP pumps with VFD control (Table 5). Plant operators indicated that one of these three pumps currently has a VFD installed but it is run in manual (constant speed, on/off control) because the other two pumps are operated by on/off control driven by pressure. VFD drives should be installed on the remaining two pumps. A predictive Iterative-Derivative-Proportional (IDP) control loop should be installed to operate the pumps as a system in order to minimize energy use. An operations review should be conducted to determine the true minimum performance requirements for these pumps as typical operations set points are often significantly higher than what is actually required. Table 5: Estimated Energy Savings and Payback for 3WHP pumps Number UsageCategory Name Motor Size(HP) Annual kwh Annual Cost$ AnnualEnergy SavingskWh AnnualCost Savings$ VFD Installation Cost SDG&E Incentive Installation CostAfter Incentive Estimated Payback (Years) 3031 PlantWater 3WHPPUMP ,536 $55, ,268 $27,550 NAExisting NA NA NA 3033 PlantWater 3WHPPUMP ,846 $53, ,923 $26,523 $17,000 $8,500 $8, PlantWater 3WHPPUMP ,527 $44, ,764 $22,454 $17,000 $8,500 $8, Total: 397,954 $76,527 $34,000 $17,000 $17, EEM 6: Retrofit other Plant Water pumps with VFD control (Table 6). There are a number of other Plant Water pumps that appear to be likely candidates for VFD installation. Table 6: Estimated Energy Savings and Payback for Plant Water pumps Number UsageCategory Name Motor Size(HP) Annual kwh Annual Cost$ AnnualEnergy SavingskWh AnnualCost Savings$ VFD Installation Cost SDG&E Incentive Installation CostAfter Incentive Estimated Payback (Years) 3051 PlantWater 3WLPUMP ,816 $42, ,908 $21,328 $15,000 $7,500 $7, PlantWater 3WLPUMP ,432 $36,620 95,216 $18,310 $18,750 $9,375 $9, PlantWater 3WPUMP ,390 $14,305 37,195 $7,153 $7,500 $3,750 $3, PlantWater 3WPUMP ,680 $12,438 32,340 $6,219 $7,500 $3,750 $3, PlantWater 2WPUMP ,019 $11,542 30,009 $5,771 $7,500 $2,709 $4, PlantWater 3WLCPUMP ,328 $11,217 29,164 $5,608 $4,500 $2,250 $2, PlantWater 3WPUMP ,910 $8,252 21,455 $4,126 $7,500 $1,939 $5, PlantWater 3WLCPUMP ,596 $ 5,884 15,298 $2,942 $4,500 $1,382 $3, Total: 371,585 $71,456 $72,750 $33,443 $39, Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

232

233 2.2.3 EEM 7: Retrofit HVAC Fans with VFD control (Table 7). There are a number of fans and air handlers that are operating at constant flow that are likely able to be reduced with little or no impact to process performance or operator comfort. Table 7: Estimated Energy Savings and Payback for HVAC Fans Number UsageCategory Name Motor Size(HP) Annual kwh Annual Cost$ AnnualEnergy SavingskWh AnnualCost Savings$ VFD Installation Cost SDG&E Incentive Installation CostAfter Incentive Estimated Payback (Years) 1602 HVAC EXHAUSTFAN ,124 $ 113, ,562 $56,837 $25,000 $12,500 $12, HVAC OCFFAN ,032 $60, ,516 $30,483 $15,000 $7,500 $7, HVAC BLOWERROOMFAN ,692 $34,170 88,846 $17,085 $9,000 $4,500 $4, HVAC FOULAIRFAN ,685 $21,477 55,842 $10,738 $15,000 $5,046 $9, HVAC BFPROOMAHU ,095 $20,979 54,548 $10,490 $6,000 $3,000 $3, HVAC ENGINEROOMFAN 15 88,846 $17,085 44,423 $8,543 $5,000 $2,500 $2, SolidsDigestion ENGINEROOMFAN 15 85,850 $16,509 42,925 $8,254 $5,000 $2,500 $2, HVAC SUPPLYFAN ,429 $8,544 22,214 $4,272 $4,000 $2,000 $2, HVAC BLOWERROOMFAN 10 29,460 $5,665 14,730 $2,833 $4,500 $1,329 $3, HVAC SUPPLYFAN 5 25,476 $4,899 12,738 $2,450 $3,000 $1,148 $1, HVAC GALLERYFAN 5 23,582 $4,535 11,791 $2,267 $3,000 $1,063 $1, HVAC AIRHANDLER 3 14,862 $2,858 7,431 $1,429 $2,500 $670 $1, HVAC AIRHANDLER 3 11,126 $2,140 5,563 $1,070 $2,500 $502 $1, Total: 815,130 $156,749 $99,500 $49,750 $49, Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

234

235 2.2.4 EEM 8: Retrofit Solids Digestion pumps with VFD control (Table 8). There are a number of Solids Digestion circulation pumps that appear to be likely candidates for VFD installation. Table 8: Estimated Energy Savings and Payback for Solids Digestion Pumps Number UsageCategory Name Motor Size(HP) Annual kwh Annual Cost$ AnnualEnergy SavingskWh AnnualCost Savings$ VFD Installation Cost SDG&E Incentive Installation CostAfter Incentive Estimated Payback (Years) 5501 SolidsDigestion SLUDGECIRCPUMP ,746 $45, ,373 $22,763 $12,000 $6,000 $6, SolidsDigestion DIGMIXPUMP5A ,509 $42, ,254 $21,010 $15,000 $7,500 $7, SolidsDigestion SLUDGECIRCPUMP ,965 $41, ,482 $20,669 $12,000 $6,000 $6, SolidsDigestion DIGMIXPUMP6A ,229 $33,696 87,614 $16,848 $15,000 $7,500 $7, SolidsDigestion DIGMIXPUMP6B ,139 $30,410 79,069 $15,205 $15,000 $7,500 $7, SolidsDigestion DIGMIXPUMP5B ,195 $27,344 71,098 $13,672 $15,000 $7,500 $7, SolidsDigestion HEATLOOPPUMP ,142 $11,373 29,571 $5,687 $4,500 $2,250 $2, SolidsDigestion HEATLOOPPUMP ,142 $11,373 29,571 $5,687 $4,500 $2,250 $2, SolidsDigestion HEATLOOPPUMP ,142 $11,373 29,571 $5,687 $4,500 $2,250 $2, SolidsDigestion HOTWATERPUMP ,240 $8,507 22,120 $4,254 $4,000 $2,000 $2, SolidsDigestion HOTWATERPUMP ,807 $8,424 21,904 $4,212 $4,000 $2,000 $2, SolidsDigestion SLUDGECIRCPUMP ,967 $8,070 20,983 $4,035 $7,500 $1,897 $5, SolidsDigestion HOTWATERCIRCPUMP# ,505 $34,170 18,253 $3,510 $2,250 $1,125 $1, Total: 744,863 $143,237 $115,250 $57,625 $57, Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

236

237 2.3. Lighting and Sensors Description of Lighting During the site audit, Ecos observed six lighting Types that contribute to the majority of lighting use at the EWA Facility (Figure 9). Estimated lighting usage and annual costs by type are presented below in Table 9. Since Ecos started this study, EWA has been working to replace inefficient lighting. Figure 9: Major Lighting Types at EWA Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

238 Type 1 3 Lamp/T8 recessed troffers/2 magnetic ballasts/94w This lighting type was found in all Motor Control Centers (MCCs) and several storage areas. Operators indicated that the lights were typically left on constantly and that they were controlled primarily by on/off switches. Table 9 details the quantity of troffers per MCC with a total of 165 used for 24 hours each day for calculation purposes. Ecos conservatively assumed that all troffers had T8 lamps, but several, older T12 lamps were observed to be in existence. For the six types of lighting investigated, this type has the greatest potential for energy savings at EWA EEM 9a: Install occupancy sensors for the lighting in the motor control centers In order to accomplish this, EWA should ensure that all fixtures with magnetic ballasts are replaced with electronic ballasts and that all T12s have been retrofitted to T8 or replaced with T5 lamps. Occupancy sensors should be installed whenever possible in areas with low usage. See Figure 10 for typical locations of occupancy sensors (automatic on/off) in an MCC. Vacancy (manual on/ auto off, so the occupant has a choice) or photo sensors should be installed in non-critical areas where sufficient ambient light may exist. Ecos believes that half of the energy currently used for this type of lighting can be removed with the addition of occupancy sensors as the hours of operation will be reduced by the appropriate use of sensors to turn off lights when a space in not occupied or when adequate natural light is present. Figure 10: Typical Motor Control Center with Occupancy Sensor Locations For calculation purposes, Ecos used 30 quantity fixtures at $250 per fixture for the installation of occupancy sensors in MCCs. Type 2-250w mercury vapor A total of 20 of these fixtures were found dispersed around the perimeter of plant, and along plant access roads. Hours of operation were assumed to be 12 per day. Ecos was informed that EWA is in the process of replacing these aged lamps and has already begun this process having purchased 5 of these fixtures for $11,000 earlier this year. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

239 2.3.3 EEM 9b: Continue upgrading existing lighting with more efficient fixtures It is recommended that the replacement wattage be at least 75w less than the existing wattage (the calculations in this report assume the difference to be 250w (old) - 175w (new) = 75w (savings). LED lamps, which are an even more efficient option, should be investigated for this purpose. LED lamps are a commercially available option that produce high quality light while using less than half the energy, but are still relatively expensive (even after incentives and energy savings). Ecos witnessed at least one of these lamps on in the daytime and recommends that the control system for these lights should be added to the plant's maintenance schedule to ensure that the lights are only in operation in when necessary. Type 3 Mixed Use in Administration and Maintenance Buildings Due to time constraints and the fact that the Administration and Maintenance Buildings were recently constructed and Title 24 compliant, a detailed lighting inventory was not performed. It was noticed during the visit that occupancy sensors and high efficiency lighting were in place. In order to estimate energy usage for lighting in these buildings, Ecos referred to Title 24 s 2008 Building Energy Efficiency Standards, Section 146 Prescriptive Requirements for Indoor Lighting. A General Commercial and Industrial work building has an allowable Lighting Power Density of 1 W/ft 2. For the purposes of this report, Ecos has estimated the size of the Administration and Maintenance Buildings to be approximately 32,000 ft 2, and 12,500 ft 2 respectively for a total of 44,500 ft 2. Type 4-250w high pressure sodium This lighting type was found surrounding many large areas of the plant. Table 9 details the quantity of lamps found in each area with a total 124 used for 10 hours each day for calculation purposes. Ecos does not recommend a change to this equipment at this time. When replacement or upgrade is considered, EWA should work a lighting specialist for possible reconfiguration options that will provide the same pattern of coverage with less lighting. This would be most effective in the Effluent Pumping area which has approximately the same quantity of lamps as the Secondary Equalization area but is approximately 25% of the size. Additionally, Ecos witnessed several of these lamps on in daylight and recommends adding these photo sensors to the site s maintenance schedule. Type 5-175w MH wall pack These wall packs were found to be installed externally approximately every 30 ft of all original buildings as well as several inside (gallery) applications. Table 9 details the quantity of lamps found in each area with a total 70 used for 12 hours each day for calculation purposes. As these lights were updated within the last two years, Ecos does not recommend a change to this equipment at this time. However, they are all on manual switch control and several of the lights were on in outside locations during the daytime. If the upgrade did not include a lamp that uses less than 50w, a 42w replacement CFL wall pack is available with photo sensors that should be considered as the lights are replaced. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

240 Type 6-100w lanyard mount, explosion proof These lights were found around the digester tanks and the tanks in the northeast corner of the plant. Table 9 details the quantity of lamps found with a total of 22 used for 12 hours each day for calculation purposes. No equipment changes are recommended at this time. When replacement or upgrade is considered, EWA should work with a lighting specialist to reconfigure to provide the same pattern of coverage with less lighting. At end of life, it is recommended that these lamps are replaced completely with a more efficient lighting option. Table 9: Lighting Usage and Annual Cost Estimates 1 Type 3L/T8 recessed troffers/ 2mag ballast/94w Location All Motor Control Centers: Screening (5), Primary Gallery (28), Orf (2), Gen Room (21), Blower Room (16), Compressor Room (6), Power Building (32), Dewatering (18), Maintenance storage corner (9), Chlorine Bldg. (7), Secondary Bldg (10), Secondary Gallery (11) Est Watts Apx. Qty. Est. hrs Est. kwh Est. Annual Cost Change Recommended? ,868 $ 26,127 Yes 2 250w mercury vapor Perimeter of plant, access roads ,900 $ 4,211 Yes 3 Mixed Administration Building (est. 32k ft2) and Maintenance Building (est. 12,500 ft2), total is 44,500 ft2. New buildings, Title 24. Assume 1 W/ft ,250 $ 21,393 No 4 250w high pressure sodium Multiple: Sed Tanks (14), DAF (17), Eff. Pumps (21), Sec. Equalization (24), Aeration (48), average 10 hours per day with photo sensors ,150 $ 21,759 No 5 175w MH wall pack Every apx. 30 ft of all buildings external, multiple buildings indoor: Maintenance/Power Bldg (30), Screening Building Area (10), Secondary Gallery (14), Chlorine (5), Dewatering (9) ,655 $ 10,318 No 6 100w lanyard mount, explosion proof Digester Tanks (10), tanks northeast corner (12) ,636 $ 1,853 No Estimated Total Per Plant 445,459 $ 85,662 Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

241 2.3.2 EEM 9: Lighting Improvements An estimate of possible energy savings follows and is summarized in Table 1.The change to newer technology and the addition of controls has the potential to decrease energy use by as much as 74,504 kwh per year saving approximately $14,327. Type 1 EEM 9a: Installing occupancy/vacancy/photo sensors will reduce operation hours by ½ 94w x 165 fixtures x 4,380 hours = 67,934 kwh savings Costs are estimated based on 30 fixtures and $250 per fixture ($7,500) Type 2 EEM 9b: Reducing the existing wattage by 75w will reduce energy usage by 30% 75w savings x 20 fixtures x 4,380 hours = 6,570 kwh savings Per operations staff, costs are based on 5 fixtures for $11,000 and 20 remaining fixtures ($44,000) Total Savings = 67,934 kwh + 6,570 kwh = 74,504 kwh Total Costs = $7,500 + $44,000 = $51,500 Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

242 2.4. Compressed Air System (Service Air) There are 2 qty. 40 hp Kaeser air compressors used for service air throughout the plant (Figure 11). According to the run time hours received, the compressors operate together for 3590 hours (40%) of the year for an annual energy cost of $20,430. The new 15 hp Start Air Compressors in the engine room are not addressed in this study. It is assumed that efficient equipment was installed for this application as they appear to be in operation 80-90% of the time. Ecos observed that the compressors were not running constantly but would run (cycle), then stop and stay off before cycling again after several minutes (typical of Load/Unload operation). Based on this, it is our opinion that the system is in good condition and operating well but we are not able to quantify operation or a potential for improvement without a baseline study over a 1-2 week period. It has been Ecos experience that most compressed air systems are designed to supply the maximum quantity of air that would ever be required at one time and to ensure that this quantity is available constantly. This results in a system that is oversized for the plant s actual reality during normal operation. A solution to this can be determined by monitoring the system s power and pressure over a certain time period which will illustrate the actual demand on the system during normal operation. Once this test is complete, and a system profile is developed from the data, evidence is then available (actual system flow in CFM) that will justify if using a smaller air compressor for normal operation is an option. The existing larger hp compressors can run in standby for high demand occurrences. Figure 11: Existing Kaeser Compressor REC 1: Compressed Air System Recommendation To better understand current compressor operations and potential for energy savings, Ecos recommends that the existing compressed air systems be monitored for two weeks by a qualified auditor. Ecos is capable of performing this task, but SDG&E may offer this audit service for free. Power (kw) to each of the compressors and system pressure(s) (psig) should be measured and a system profile developed from this data. From this data, actual system flow (CFM) can be determined. If the actual CFM can be supplied by a smaller compressor using less power, this alternative should be investigated. It must also be noted that even if the baseline study recommends upgrading the existing compressor system with a smaller, VFD controlled compressor, it is a relatively small savings compared to the other opportunities identified in this report. The typical achievable savings of 20% ($4,000), would take 4-5 years to payback the cost of the replacement which could be $20,000 for a 30 hp VFD compressor. EWA should take this tradeoff into consideration and focus on other energy savings opportunities first. Although it did not appear (based on the delayed cycling of the compressors) that the system was feeding large air leaks, any known leaks should be fixed as soon as possible. Once the largest leaks have been identified and remedied, an ultrasonic leak detector is the best means for finding smaller leaks. It is recommended to check all compressed air lines and applications monthly with an ultrasonic leak detector after larger leaks have been fixed. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

243 2.5. Motor Efficiency Premium efficiency motors can save 2-5% over standard efficiency motors. While this is often not enough to justify replacement of a functioning existing motor, all new motors purchased by EWA as replacements or for new construction should be specified as the highest-efficiency available. Please note that the bar for what is a premium is constantly rising. For more information, see Appendix C includes a greater explanation of this idea as well as developed by Washington State University. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

244 3.0 ANALYSIS OVERVIEW 3.1. Energy Use Breakdown Energy use at EWA was derived from several sources. Process or Usage category for each piece of equipment was obtained in the ANN 08 Run Hours.xls file which was provided by the EWA site. This information was correlated with the data in NEW 09 HOURS-updated xls which provided 11 months of 2009 operations data. This was adjusted to a 12 month period and subtotaled below (14,097,848 kwh). Annual cost was determined using an assumed average power cost of $ (which includes use, demand and fees, but does not account for co-generation costs assumes all power is purchased). All motors are assumed to have 91% effective efficiency and 82.5% load factor 5. Lighting estimates are detailed in Section 2.3. Run hours and usage information was not available at the time of this report for most New Equipment (Dryer Building, etc.) that started in This was estimated to be the difference between Total Electrical Consumption from Kennedy Jenks Energy Efficiency Technical Memorandum (18,353,000 kwh, and based on utility data) and the Subtotal (14,097,848 kwh). Cogen includes only power using equipment and does not factor any generation or heat recovery. The results are detailed in Table Annual kwh and Cost per Usage Category Table 10: EWA 2009 Estimated Energy Use by Usage Category and for all New Equipment Usage Category 2009 Annual kwh Annual Cost $ Activated Sludge 6,663,463 $ 1,281,384 HVAC 1,587,462 $ 305,269 Solids Digestion 1,582,313 $ 304,279 Plant Water 1,563,214 $ 300,606 Return Activated Sludge Pumps 908,511 $ 174,707 Lighting 445,459 $ 85,662 Thickener 317,589 $ 61,072 Cogen 288,667 $ 55,511 Secondary Clarifiers 241,346 $ 46,411 Headworks 187,858 $ 36,125 Miscellaneous (from NEW 09 HOURS-updated ) 122,996 $ 23,652 Disinfection 65,025 $ 12,504 Waste Activated Sludge Pumps 62,950 $ 12,105 Primary 51,022 $ 9,811 Effluent Pumping 9,174 $ 1,764 Solids Dewatering 800 $ 154 Sub Total 14,097,848 $ 2,711, New Equipment/Other (18.53 MW MW) 4,255,152 $ 818,266 Total 18,353,000 $ 3,529,282 5 Note that these values are based on previous EWA s assumptions we are using them for consistency and it was beyond or scope to evaluate if these assumptions are correct for EWA or not. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

245 4.0 SAN DIEGO GAS AND ELECTRIC REBATES AND INCENTIVES 4.1. Caveats This report was developed and first submitted at the end of At that time, both the San Diego Gas & Electric (SDG&E) website, and a representative from SDG&E ( ) stated that new incentive rates and rebates would be posted on the SDG&E website on January 2, All incentives need to be rechecked when each of the options is evaluated. Additionally, all projects must be approved for funding and SDG&E must certify that the project meets the program requirements and terms and conditions before they are implemented. Note also that Ecos did not take into consideration programs such as Capacity Bidding, Critical Peak Pricing, or Peak Generation found here: Additionally, the quantity of EWA s purchased power may affect the amount of incentive that SDG&E agrees to provide. As projects are approved for action, EWA or a Project Sponsor can work with SDG&E to determine actual incentive values Sources and Information The following current relevant information and applications were used for the purposes of this report: Standard Performance Contract Program: Energy Savings Bid Program 2009 Interim Policy Manual: Interim Application San Diego Gas & Electric Express Efficiency Program: Review of Sources Standard Performance Contract Program Per SDG&E, The Standard Performance Contract (SPC) program offers incentive payments for energyefficiency projects involving the installation of new, high-efficiency equipment or systems. A project may consist of the retrofit of existing equipment/systems or the installation of equipment associated with new/added load. Applicants are eligible to receive up to 50% of the cost for each project for Calculated (SPC) Measures, not to exceed $350,000 per project site. The definition of Peak Demand, per the California Public Utilities Commission (CPUC) developed by the Database for Energy Efficient Resources (DEER) is, the average grid level impact (in kw) for a measure between 2:00 p.m. and 5:00 p.m. during three consecutive weekday periods containing the weekday temperature with the hottest temperature of the year. The hours defined for peak demand for SDG&E vary over the year and are as follows (Table 11): Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

246 Summer May 1 - Sept 30 Winter / All Other On Peak - Weekdays 11 a.m.- 6 p.m. Weekdays 5 p.m.- 8 p.m. Ecos has used the method and incentive values detailed in this program to calculate the incentive savings estimates in this report. They are detailed in Table 12. Table 12: Program Incentive Rate Table Energy Savings Bid Program (ESB) SDG&E has multiple energy incentive programs; another that may be appropriate for EWA is the energy savings bid program. This program differs from the standard program in that energy savings and incentives are based on actual performance as determined by Measurement and Verification (M&V) rather than calculations done beforehand. It is more time consuming and possibly more difficult than the calculation based savings program but can provide up to 100% of the project measure s cost. This approach is recommended for any of the above blower measures where savings will be substantial Interim Application Express Efficiency Program The third program that might work for EWA is the express efficiency program which basically allocates deemed savings (a set dollar amount) for standard efficiency measures. Examples of these types of projects include retrofitting a T12 with a T8/T5 fixture, or installing occupancy or photo sensors. 6 Appendix B Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6,

247 APPENDICES Appendix A: Aeration Blower Upgrade/Replacement Estimates and Brochure The following pages contain information from HSI Blowers, a reputable Blower manufacturer that Ecos has a relationship with. Calculations were based on information provided by Ecos as discovered during the site audit and are provided for illustration and comparison purposes. Actual results and final installation costs will vary. Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6, 2010

248 Quote # : Date : F.O.B.: Rev: 12/21/2009 Freight to Jobsite Patricia Boyd Ecos 433 California Street Suite 630 San Francisco CA Tel: BUDGET Qty Part # Description Price Extend VFD Upgrade vs. Turbo Blower Comparison Delivery: Terms: To Be Determined T.B.D. HSI Representative Coombs Hopkins HT-300 Turbo Blower 4 HSI HT-300 HSI HT-300 High Speed Turbo Blower Package: Standard package contains the following: Model: HT-300 Motor: 200 HP, 460/3/60 Motor IP 45 / 54 Electrical Enclosure: UL/ULC - NEMA 12 Rated Motor Starter: VFD Starter w/ Disconnect Controller: Programmable Logic Controller with touch screen HMI interface. Airend: Two (2) impellers mounted on a single shaft, supported by Air Foil bearings in an integral casing. Pressure Relief Valve w/ silencer. Sound Enclosure: Heavy Duty steel I-beam construction with fork lift access. Paint: Powder Coated w/ 2 coat epoxy paint. Noise: Less than 85 dba per OSHA standards $155, $621, Includes - 14" Check Valve - 14" Expansion Joint - 14" Butterfly Valve For Isolation - Full Submittal Documentation - One Trip for Startup and Training - Freight to Jobsite 1 PHF-300 HT-300 Passive Harmonic Filter $11, $11, VFD Upgrade 2 VFD HP Variable Frequency Drive, 480V - HSI 3100 local surge/overload control panel for vfd mass flow control with instrumentation - Full Submittal Documentation - Freight to Jobsite - One Trip for Startup and Training $83, $166, PHF HP, Passive Harmonic Filter $15, $30, Page 1

249 Patricia Boyd Ecos 433 California Street Suite 630 San Francisco CA Tel: BUDGET Quote # : Rev: Date : 12/21/2009 F.O.B.: Freight to Jobsite Delivery: Terms: To Be Determined T.B.D. HSI Representative Coombs Hopkins Qty Part # Description Price Extend Page 2 Notes: Any work or equipment beyond the scope of this quotation will be performed or provided only after customer approval and acceptance by HSI. Freight, Taxes or Export Crating are not included in quote unless otherwise stated. Quote is valid for 45 days. Estimated Pricing is Not Guaranteed. Prices quoted are in US dollars. Delivery is verified at time of order. All standard HSI terms and conditions apply. By: Brandon Quinton Accepted: Date: Patricia Boyd 7901 Hansen, Houston, TX Phone: or Fax: Web:

250 Datasheet No. : Design Date : 12/21/2009 Quote/Job No.: Prepared By : bquinton Customer Coombs Hopkins Project Northern California Site Data Elevation: 0 ft a.s.l. Gas Data MW : RH: 0.0% k : Cp: Gas Pct Air (dry) BLOWER INPUT POWER (BHP) DISCHARGE PRESSURE (PSIG) BLOWER CONDITIONS PERFORMANCE SURGE Curve Data Model [ (r)=remanufactured ] LAMSON 1806 Configuration Impeller 1 (6) 1003 Impeller 2 Impeller 3 Driver Control Method Op. Speed [ RPM ] Inlet Throttling [ valve/%closed ] Bar. Pressure [ PSIA ] Inlet Pressure [ PSIA ] Inlet Temp. [ F ] Inlet Humidity [ % RH ] MW / k / Cp Volume (Std.) [ SCFM@68F ] Volume (Inlet) [ CFM ] Disch. Pressure [ PSIG ] Diff. Pressure [ PSI ] Power [ BHP ] Efficiency [ % ] Disch. Temp. [ F ] Pressure Rise [ PSI ] Turndown [ % ] Surge Pressure [ PSIG ] Surge Volume [ CFM ] 1. Primary Curve (r) 3,560 none /1.396/ Auto Throttle (r) LAMSON 1806 (6) , in./54.1% /1.396/ INLET VOLUME (CFM) 3. Auto Speed (r) LAMSON 1806 (6) ,302 none /1.396/ HSI, Inc 7901 Hansen Rd Houston, Texas Office Fax Toll Free sales@hsiblowers.com Print Date: 12/21/2009 ISO 9001:2000 CERTIFIED 1.6.8

251 Datasheet No. : Design Date : 12/21/2009 Quote/Job No.: Prepared By : bquinton Customer Coombs Hopkins Project Northern California Site Data Elevation: 0 ft a.s.l. Gas Data MW : RH: 0.0% k : Cp: Gas Pct Air (dry) BLOWER INPUT POWER (BHP) DISCHARGE PRESSURE (PSIG) BLOWER CONDITIONS PERFORMANCE SURGE Curve Data Model Configuration Impeller 1 Impeller 2 Impeller 3 Driver Control Method Op. Speed [ RPM ] Inlet Throttling [ valve/%closed ] Bar. Pressure [ PSIA ] Inlet Pressure [ PSIA ] Inlet Temp. [ F ] Inlet Humidity [ % RH ] MW / k / Cp Volume (Std.) [ SCFM@68F ] Volume (Inlet) [ CFM ] Disch. Pressure [ PSIG ] Diff. Pressure [ PSI ] Power [ BHP ] Efficiency [ % ] Disch. Temp. [ F ] Pressure Rise [ PSI ] Turndown [ % ] Surge Pressure [ PSIG ] Surge Volume [ CFM ] 1. Curve 1 HSI HT-300 H(VLD) 20,795 none /1.396/ INLET VOLUME (CFM) HSI, Inc 7901 Hansen Rd Houston, Texas Office Fax Toll Free sales@hsiblowers.com Print Date: 12/21/2009 ISO 9001:2000 CERTIFIED 1.6.8

252 HT-300 Vs. Lamson 1806 Performance Comparison HSI HT-300 High Speed Turbo Blowers Total Flow Inlet Relative Discharge Drive Total Total Cost Days Per Shaft BHP Quantity Total Shaft Temp. Humidity Pressure Loss Input KW.085 Per Day Year Annual Cost 9000 SCFM % 8.0 PSIG % $70, SCFM 75 40% 8.0 PSIG % $159, SCFM 50 45% 8.0 PSIG % $135, SCFM 30 50% 8.0 PSIG % $30, $395, Lamson 1806 Multistage with VFD Total Flow Inlet Relative Discharge Drive Total Total Cost Days Per Shaft BHP Quantity Total Shaft Temp. Humidity Pressure Loss Input KW.085 Per Day Year Annual Cost 9000 SCFM % 8.0 PSIG % $76, SCFM 75 40% 8.0 PSIG % $175, SCFM 50 45% 8.0 PSIG % $149, SCFM 30 50% 8.0 PSIG % $33, $435, Lamson 1806 Multistage with Throttled Inlet Total Flow Inlet Relative Discharge Drive Total Total Cost Days Per Shaft BHP Quantity Total Shaft Temp. Humidity Pressure Loss Input KW.085 Per Day Year Annual Cost 9000 SCFM % 8.0 PSIG % $91, SCFM 75 40% 8.0 PSIG % $222, SCFM 50 45% 8.0 PSIG % $201, SCFM 30 50% 8.0 PSIG % $46, $562,338.43

253 H I G H S P E E D T U R B O B L O W E R S Innovation Service Experience

254 INNOVATION IN ACTION Introducing HSI High Speed Turbo Blowers and Exhausters What if a blower could... What if you found this blower with the local service and support that you know and trust?

255 DESCRIPTION AND SPECIFICATIONS POWER SAVING LOW MAINTENANCE NOISE What is Your TRUE Cost of Ownership? Cost Let us offer a 20 year life cycle analysis on your next project. INSTALLATION CONTROL INTEGRATION COMPLETE PACKAGE SERVICE

256 DESCRIPTION AND SPECIFICATION Impeller - Motor Inlet air is channeled over the motor to provide cooling prior to compression and discharge. Double suction symmetric Bearings Air Bearings Superior durability

257 Enclosure and Control Variable Frequency Drive Enclosure Relief Valve Constant Pressure Mode Quantitative Mode Proportional Mode RPM 1 100% 2 90% 3 80% 4 70% 5 60% % Programmable Logic Controller (PLC) 2 1

258 Performance Envelope VOLUME (nm 3 /hr) PRESSURE (PSIG) PRESSURE (kpa) VOLUME (SCFM) Blower Impeller Outlet Cabinet Enclosure Dimensions Weight Model Configuration Flange (in) Size L x W x H (mm) Size L x W x H (in) Kg Lbs HT-5 single x 600 x x 23.6 x HT-5 twin x 600 x x 23.6 x HT-10 single x 600 x x 23.6 x HT-10 twin x 600 x x 23.6 x HT-20 single x 700 x x 27.6 x HT-20 twin x 700 x x 27.6 x HT-30 single x 700 x x 27.6 x HT-30 twin x 700 x x 27.6 x HT-50 single x 700 x x 27.6 x HT-50 twin x 700x x x 27.6 x HT-75 single x 850 x x 33.5 x HT-75 twin x 850 x x 33.5 x HT-100 single x 850 x x 33.5 x HT-100 twin x 850 x x 33.5 x HT-150 single x 950 x x 37.4 x HT-150 twin x 950 x x 37.4 x HT-200 single x 1050 x x 41.3 x HT-200 twin x 1050 x x 41.3 x HT-300 single x 1050 x x 41.3 x HT-300 twin x 1050 x x 41.3 x

259 APPLICATIONS AND SPECIFICATIONS Common Applications Water and Waste Water General Industrial Power Industry Petroleum & Chemical Specifications TECHNICAL DATA Configuration Number of impellers Pressure range Flow range Outlet connection Inlet filter Pressure relief valve Operating speed Casing pressure Seals (air) Bearings Lubrication Drive type Vibration tolerence Rotor balance Enclosure/electrical Electrical cabinet Motor voltage 1 or 2 impellers (single, in series or in parallel) 2 To 25 PSIG (.13 to 1.7 bar) 10 to 10,000 SCFM (1 to 300 m2m). Flanged ASA 125# / ANSI 150# drilling 10 micron felted synthetic material, powder coated steel frame, washable with compressed air or soap Pneumatic actuated pressure relief valve and integral silencers included in standard package. No external compressed air utility required 8000 RPM to 45,000RPM (sub critical operation) 50 PSIG maximum Self contained Air foil non contact, non wearing, dynamic fluid film utilizing air None required Self contained motor and shaft with integrally attached overhung impeller(s) Maximum allowable.07 in/sec (2mm/sec) Military standard Individual impellers and rotating assembly dynamically balanced NEMA 12 (standard), upgrades available UL, ULC Listed 240, 380, 440, 480, 575 volt, 50 or 60Hz, 3 phase input power. Internal control voltage transformer. Motor HP/KW rating Motor Motor starter VFD type Noise level Control UV protective cover Network connections Cooling system 5 to 300 hp (1 to 250kW) IP 45, 54 protection, highly efficient permanent magnet or induction type motor. Inverter type variable frequency drive Highly efficient 6 pulse drive standard with operating range to 1000 hz operation (optional harmonic filters available) Under 85 dba per OSHA standards Programmable logic controller with touch screen human machine interface (standard) Included to protect touch screen interface Ethernet, RS232, or DH485 as standard. Optional connections to communicate with any protocol available. Internally self cooled by inlet air or external cooling options available to capture heat to supplement HVAC or water heating. MATERIALS OF CONSTRUCTION Blower housing Cast aluminum Impellers Cast aluminum Air bearings Teflon coated Inconel Blower enclosure 16 gauge sheet metal with synthetic wool sound dampening material Blower enclosure skid Heavy duty steel I-beam construction with fork lift access ports Enclosure finish Powder coated with 2 coat epoxy paint standard

260 HIGH SPEED TURBO BLOWERS Additional Products Multistage Centrifugal Blowers Blower Control Systems Aftermarket Services

261 US/Canada Partial Project List No. Customer Location Consultant Model Q'ty Capacity [SCFM] Pressure [PSI] Application Status Date of Start Up Contact Name Phone Number 1 City of Laporte Laporte, Tx N/A HT Grit Aeration Installed February-09 Robert Banks (281) FL Smidth Salt Lake City, UT HT Flotation Cell Installed February-09 Ian Gordon (801) City Tryon Tryon, NC HT WW Aeration Installed December-09 4 City of Eureka Eureka, MO HT WW Aeration Installed May-09 Mr. Dave Ricks (636) City of Festus Festus Crystal City, MO HT WW Aeration Installed July-09 Mr. David Smith (636) Sweetwater Spring Valley, CA HT WW Aeration Installed January-10 Thaddeus Gardner (760) Kimberly Clark Neena, WI HT Paper Process Production May-09 8 Tri City Tri City, OR MWH HT WW Aeration Production April-10 Dale Richwine (503) Little Maumelle Little Maumelle, AR CDM HT WW Aeration Submittal July GE Zenon Tri City, OR MWH HT BackWash Production February-10 Darren Oneill (905) x NBC Narraganset Bay, RI CH2MHILL HT WW Aeration Submittal April-10 Terry Cote (401) x Power Supply St. Louis, MO HT Demo Installed February Gravenhurst Gravenhurst, ON CH2MHILL HT WW Aeration Production March ERC Greenbay, WI HT Food Process Installed November Sanitaire Triton, GA HT WW Aeration Delivered January Essex Junction, VT Essex Junction, VT Forcie Aldridge HT WW Aeration Delivered January-10 Wayne Elliott (802) West Sound Utlitity Port Orchard, WA HT WW Aeration Production February-10 Randy Screws (360) Kachina Village, AZ Kachina, AZ HT WW Aeration Installed July Thunder Valley Lincoln, CA HT WW Aeration Delivered February City of Chandler Chandler, AZ B&C HT WW Aeration Submittal May Laughlin-Sutton Elkin, NC HT WW Aeration Production March-10 Tony Combs (704) St. Bernard Parish Munster, LA HT WW Aeration Submittal April Tiki Island Tiki Island, TX HT WW Aeration Production March Decatur Utilities Decatur, AL HT WW Aeration Submittal April Mt. Holly Mt. Holly, NJ HT WW Aeration Submittal May City of Georgetown Georgetown, CO Frachetti Eng HT WW Aeration Submittal February City of Lompoc Lompoc, WWTP B&C HT WW Aeration Production February Township of Mapleton Mapleton, ON R.J. Burnside HT WW Aeration Submittal March City of Festus Festus Crystal City, MO HT WW Aeration Delivered January-10 Mr. David Smith (636) South Central WWTP Harnett County, NC HT WW Aeration Submittal April City of Hanover Hanover, NH Underwood Eng HT Sludge Aeration Submittal May Leprino Foods HT Approved March Galway Bay Corp Altoona, PA HT WW Aeration Submittal May Galway Bay Corp Altoona, PA HT WW Aeration Submittal May Farmers Korner Breckenridge, CO Carollo HT WW Aeration Submittal February Clear Creek Redding, CA CH2MHILL HT WW Aeration Submittal September Pittsfield Pittsfield, Ma HT WW Aeration Submittal September-10 Total 126

262 Appendix B: SDG&E AL-TOU Rate Schedule Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6, 2010

263 Revised Cal. P.U.C. Sheet No E San Diego Gas & Electric Company San Diego, California Canceling Revised Cal. P.U.C. Sheet No E SCHEDULE AL-TOU Sheet 1 GENERAL SERVICE - TIME METERED APPLICABILITY Applicable to all metered non-residential customers whose monthly maximum demand equals, exceeds, or is expected to equal or exceed 20 kw. This schedule is not applicable to residential customers, except for those three-phase residential customers taking service on this schedule as of April 12, 2007 who may remain on this schedule while service continues in their name at the same service address. Those three-phase residential customers remaining on this schedule who choose to switch to a residential rate schedule may not return to this schedule. This schedule is optionally available to common use and metered non-residential customers whose Monthly Maximum Demand is less than 20 kw. Any customer whose Maximum Monthly Demand has fallen below 20 kw for three consecutive months may, at their option, elect to continue service under this schedule or be served under any other applicable schedule. This schedule is the utility's standard tariff for commercial and industrial customers with a Monthly Maximum Demand equaling or exceeding 20 kw. Non-profit group living facilities taking service under this schedule may be eligible for a 20% California Alternate Rates for Energy (CARE) discount on their bill, if such facilities qualify to receive service under the terms and conditions of Schedule E-CARE. Agricultural Employee Housing Facilities, as defined in Schedule E-CARE, may qualify for a 20% CARE discount on the bill if all eligibility criteria set forth in Form or Form is met. TERRITORY Within the entire territory served by the Utility. RATES Description AL-TOU Transm Distr PPP ND CTC RS TRAC UDC Total Basic Service Fees ($/month) kw Secondary $58.22 I $58.22 I Primary I I Secondary Substation 16, I 16, I Primary Substation 16, I 16, I Transmission I I > 500 kw Secondary I I Primary I I Secondary Substation 16, I 16, I Primary Substation 16, I 16, I Transmission I I > 12 MW Secondary Substation 26, I 26, I Primary Substation 26, I 26, I T Trans. Multiple Bus 3, , Distance Adjust. Fee Secondary - OH Secondary - UG Primary - OH Primary - UG (Continued) 1C20 Issued by Date Filed Mar 28, 2008 Advice Ltr. No E Lee Schavrien Effective May 1, 2008 Senior Vice President Decision No Regulatory Affairs Resolution No.

264 Revised Cal. P.U.C. Sheet No E San Diego Gas & Electric Company San Diego, California Canceling Revised Cal. P.U.C. Sheet No E SCHEDULE AL-TOU Sheet 2 GENERAL SERVICE - TIME METERED RATES (Continued) Description AL-TOU Transm Distr PPP ND CTC RS TRAC UDC Total Demand Charges ($/kw) Non-Coincident Secondary 3.93 R R Primary 3.80 R R Secondary Substation 3.93 R R Primary Substation 3.80 R R Transmission 3.76 R R Maximum On-Peak Summer Secondary 0.84 I I Primary 0.81 I I Secondary Substation 0.84 I I Primary Substation 0.81 I I Transmission 0.81 I I Winter Secondary 0.19 I I Primary 0.18 I I Secondary Substation 0.19 I I Primary Substation 0.18 I I Transmission 0.18 I I Power Factor ($/kvar) Secondary Primary Secondary Substation Primary Substation Transmission. (Continued) 2C6 Issued by Date Filed Aug 21, 2009 Advice Ltr. No E Lee Schavrien Effective Sep 1, 2009 Senior Vice President Decision No Regulatory Affairs Resolution No. E-3930

265 Revised Cal. P.U.C. Sheet No E San Diego Gas & Electric Company San Diego, California Canceling Revised Cal. P.U.C. Sheet No E SCHEDULE AL-TOU Sheet 3 GENERAL SERVICE - TIME METERED RATES (Continued) Description AL-TOU Transm Distr PPP ND CTC RS TRAC Energy Charges ($/kwh) On-Peak - Summer Secondary ( ) R R Primary ( ) R R Secondary Substation ( ) R R Primary Substation ( ) R R Transmission ( ) R R Semi-Peak Summer Secondary ( ) R R Primary ( ) R R Secondary Substation ( ) R R Primary Substation ( ) R R Transmission ( ) R R Off-Peak Summer Secondary ( ) R R Primary ( ) R R Secondary Substation ( ) R R Primary Substation ( ) R R Transmission ( ) R R On-Peak Winter Secondary ( ) R R Primary ( ) R R Secondary Substation ( ) R R Primary Substation ( ) R R Transmission ( ) R R Semi-Peak Winter Secondary ( ) R R Primary ( ) R R Secondary Substation ( ) R R Primary Substation ( ) R R Transmission ( ) R R Off-Peak - Winter Secondary ( ) R R Primary ( ) R R Secondary Substation ( ) R R Primary Substation ( ) R R Transmission ( ) R R Notes: Transmission Energy charges include the Transmission Revenue Balancing Account Adjustment (TRBAA) of ($.00070) per kwh and the Transmission Access Charge Balancing Account Adjustment (TACBAA) of ($.00149) per kwh. PPP rate is composed of: Low Income PPP rate (LI-PPP) $.00302/kWh, Non-low Income PPP rate (Non-LI-PPP) $(.00156)/kWh (pursuant to PU Code Section 399.8, the Non-LI-PPP rate may not exceed January 1, 2000 levels), and Procurement Energy Efficiency Surcharge Rate of $.00237/kWh. UDC Total (Continued) 3C8 Issued by Date Filed Apr 27, 2009 Advice Ltr. No E Lee Schavrien Effective May 1, 2009 Senior Vice President Decision No. D Regulatory Affairs Resolution No.

266 Revised Cal. P.U.C. Sheet No E San Diego Gas & Electric Company San Diego, California Canceling Revised Cal. P.U.C. Sheet No E SCHEDULE AL-TOU Sheet 4 GENERAL SERVICE - TIME METERED RATES (Continued) Rate Components The Utility Distribution Company Total Rates (UDC Total) shown above are comprised of the following components (if applicable): (1) Transmission (Trans) Charges, (2) Distribution (Distr) Charges, (3) Public Purpose Program (PPP) Charges, (4) Nuclear Decommissioning (ND) Charge, (5) Ongoing Competition Transition Charges (CTC), (6) Reliability Services (RS), and (7) Total Rate Adjustment Component (TRAC). T Utility Distribution Company (UDC) Total Rate shown above excludes any applicable commodity charges associated with Schedule EECC (Electric Energy Commodity Cost) and Schedule DWR-BC (Department of Water Resources Bond Charge). Certain Direct Access customers are exempt from the TRAC, as defined in Rule 1 Definitions. T Time Periods All time periods listed are applicable to local time. The definition of time will be based upon the date service is rendered. Summer May 1 - Sept 30 Winter All Other On-Peak 11 a.m. - 6 p.m. Weekdays 5 p.m. - 8 p.m. Weekdays Semi-Peak 6 a.m a.m. Weekdays 6 a.m. - 5 p.m. Weekdays 6 p.m p.m. Weekdays 8 p.m p.m. Weekdays Off-Peak 10 p.m. - 6 a.m. Weekdays 10 p.m. - 6 a.m. Weekdays Plus Weekends & Holidays Plus Weekends & Holidays The time periods shown above will begin and end one hour later for the period between the second Sunday in March and the first Sunday in April, and for the period between the last Sunday in October and the first Sunday in November. Non-Standard Seasonal Changeover Customers may select on an optional basis to start the summer billing period on the first Monday of May and to start the winter billing period on the first Monday of October. Customers electing this option will be charged an additional $100 per year for metering equipment and programming. Franchise Fee Differential A Franchise Fee Differential of 5.78% will be applied to the monthly billings calculated under this schedule for all customers within the corporate limits of the City of San Diego. Such Franchise Fee Differential shall be so indicated and added as a separate item to bills rendered to such customers. (Continued) 4C13 Issued by Date Filed Mar 28, 2008 Advice Ltr. No E Lee Schavrien Effective May 1, 2008 Senior Vice President Decision No Regulatory Affairs Resolution No.

267 Revised Cal. P.U.C. Sheet No E San Diego Gas & Electric Company San Diego, California Canceling Revised Cal. P.U.C. Sheet No E SCHEDULE AL-TOU Sheet 5 GENERAL SERVICE - TIME METERED SPECIAL CONDITIONS 1. Definitions: The Definitions of terms used in this schedule are found either herein or in Rule Voltage: Service under this schedule normally will be supplied at a standard available Voltage in accordance with Rule Voltage Regulators: Voltage Regulators, if required by the customer, shall be furnished, installed, owned, and maintained by the customer. 4. Reconnection Charge: Any customer resuming service within twelve months after such service was discontinued will be required to pay all charges which would have been billed if service had not been discontinued. T T T 5. Non-Coincident Demand Charge: The Non-Coincident Demand Charge shall be based on the higher of the Maximum Monthly Demand or 50% of the Maximum Annual Demand. 6. On-Peak Period Demand Charge: The On-Peak Period Demand Charge shall be based on the Maximum On-Peak Period Demand. 7. Power Factor: The Power Factor rate shall apply to those customers that have a Power Factor Test Failure and will be based on the Maximum Kilovar billing demand. Those customers that have a Power Factor Test Failure will be required to pay for the Power Factor Metering that the utility will install. 8. Parallel Generation Limitation. This schedule is not applicable to standby, auxiliary service or service operated in parallel with a customer's generating plant, except as specified in Rule 1 under the definition of Parallel Generation Limitation. 9. Seasonal Changeover Switching Limitation. Customers who elect the nonstandard Seasonal Changeover option of this schedule will be prohibited from switching service to the regular seasonal changeover for a 12-month period. 10. Limitation on Non-Standard Seasonal Changeover Availability. At the utility's sole option, the optional non-standard seasonal changeover provision is available to no more than ten additional Schedule AL-TOU and Schedule A6-TOU customers annually and; service will be provided in the order in which requests are received. (Continued) 5C11 Issued by Date Filed Mar 28, 2008 Advice Ltr. No E Lee Schavrien Effective May 1, 2008 Senior Vice President Decision No Regulatory Affairs Resolution No.

268 Revised Cal. P.U.C. Sheet No E San Diego Gas & Electric Company San Diego, California Canceling Revised Cal. P.U.C. Sheet No E SCHEDULE AL-TOU Sheet 6 GENERAL SERVICE - TIME METERED SPECIAL CONDITIONS (Continued) 11. Terms of Optional Service. A customer receiving service under this schedule may elect to change to another applicable rate schedule, but only after receiving service on this schedule for at least 12 consecutive months. If a customer elects to discontinue service on this schedule, the customer will not be permitted to return to this schedule for a period of one year. 12. Basic Service Fee Determination. The basic service fee will be determined each month based on the customer s Maximum Annual Demand. 13. Transmission Multiple Bus Basic Service Fee. This fee shall apply where a customer has at their option elected to be billed at this rate and is limited to where the customer is delivering power and taking service at one or more than one transmission service level bus even if at two or more different voltage levels, for service to a generation facility that is located on a single premise owned or operated by the customer. In such a case, the Utility shall, for the purposes of applying retail rates, combine by subtracting any generation delivered from any loads served provided, however, that for purposes of applying retail rates the difference resulting from this combining may not be less than zero. All other charges on this tariff shall also apply to the resulting combined loads. Any customer selecting this optional billing no later than six (6) months from the first effective date of this new rate shall, for billing purposes, have any previously incurred demand ratchet treated as a zero from the effective date of the change in billing forward. In addition, any standby charges shall be adjusted to the customer s contract level from the effective date of the change in billing forward until the customer s demand triggers a future change. 14. Billing. A customer s bill is first calculated according to the total rates and conditions listed above. The following adjustments are made depending on the option applicable to the customer: a. UDC Bundled Service Customers receive supply and delivery services solely from the Utility. The customer s bill is based on the Total Rates set forth above. The EECC component is determined by multiplying the EECC price for this schedule during the last month by the customer s total usage. b. Direct Access (DA) and Community Choice Aggregation (CCA) Customers purchase energy from a non-utility provider and continue to receive delivery services from the Utility. The bills for a DA and CCA Customer will be calculated as if they were a UDC Bundled Service Customer, then crediting the bill by the amount of the EECC component, as determined for a UDC Bundled Customer, and including the appropriate Cost Responsibility Surcharge (CRS) if applicable. c. Virtual Direct Access Customers receive supply and delivery services solely from the Utility. A customer taking Virtual Direct Access service must have a real-time meter installed at its premises to record hourly usage, since EECC change hourly. The bill for a Virtual Direct Access Customer will be calculated as if it were a UDC Bundled Service Customer, then crediting the bill by the amount of the EECC component, as determined for a UDC Bundled Customer, then adding the hourly EECC component, which is determined by multiplying the hourly energy used in the billing period by the hourly cost of energy. T T T T T Nothing in this service schedule prohibits a marketer or broker from negotiating with customers the method by which their customer will pay the CTC charge. 15. Temporary Service. When service is turned on for cleaning and/or showing of an unoccupied premise above 20 kw facility, the minimal usage shall be billed under Schedule A, until a new tenant begins service. Should usage exceed 20kW at any time for cleaning and/or showing, the customer shall be billed the rates on this schedule. (Continued) 6C14 Issued by Date Filed Nov 29, 2006 Advice Ltr. No E-A Lee Schavrien Effective Dec 29, 2006 Vice President Decision No. Regulatory Affairs Resolution No. E-4013

269 Revised Cal. P.U.C. Sheet No E San Diego Gas & Electric Company San Diego, California Canceling Revised Cal. P.U.C. Sheet No E SCHEDULE AL-TOU Sheet 7 GENERAL SERVICE - TIME METERED SPECIAL CONDITIONS (Continued) 16. Multiple Meters on Single Premise. When a single corporate entity owns a contiguous property, not divided by any public right of way or property owned by another entity, all within the same governmental agency s jurisdiction, and the Utility has more than one meter serving that property, then, at the customer s request the Utility will for the additional fees and conditions set forth in this Special Condition bill all of the usage at some, or all, of the meters as though the whole premise were served through a single meter. As of September 21, 2004, for new customers to be eligible for combined billing, all meters must have the same billing components. These components include but are not limited to Large Customer CTC Adjustment, Large Customer Commodity Credit, Direct Access (DA) Cost Responsibility Surcharge, DA Utility Service Credit, DA Energy Charge and DA Franchise Fee Surcharge. Meter data will be combined for the purpose of billing UDC charges, as listed in the Rates Section of this tariff, but meter data is not allowed to be combined for the purpose of off setting any charges on SDG&E s commodity rate schedules.. The customer must pay for the utility to install and maintain meters to record consumption in 15 minute intervals for all involved meters. The customer must also pay a distance adjustment fee determined by the utility that is based on the distance between each of the meters involved using normal utility position to determine that distance. The rate applied will be the Distance Adjustment Fee from the Rate Section of this tariff multiplied by T T T T T T 17. Electric Emergency Load Curtailment Plan: As set forth in CPUC Decision , all transmission level customers except essential use customers, OBMC participants, net suppliers to the electrical grid, or others exempt by the Commission, are to be included in rotating outages in the event of an emergency. A transmission level customer who refuses or fails to drop load shall be added to the next curtailment block so that the customer does not escape curtailment. If the transmission level customer fails to cooperate and drop load at SDG&E s request, automatic equipment controlled by SDG&E will be installed at the customer s expense per Electric Rule 2. A transmission level customer who refuses to drop load before installation of the equipment shall be subject to a penalty of $6/kWh for all load requested to be curtailed that is not curtailed. The $6/kWh penalty shall not apply if the customer s generation suffers a verified, forced outage and during times of scheduled maintenance. The scheduled maintenance must be approved by both the ISO and SDG&E, but approval may not be unreasonably withheld. 18. Other Applicable Tariffs: Rules 21, 23 and Schedule E-Depart apply to customers with generators. 19. Generator Operation: The operation of a generator unless expressly authorized by tariff is prohibited. 7C7 Issued by Date Filed Mar 28, 2008 Advice Ltr. No E Lee Schavrien Effective May 1, 2008 Senior Vice President Decision No Regulatory Affairs Resolution No.

270 Appendix C: Premium Efficiency Motors Prepared for Kennedy/Jenks Encina Water Authority Energy Analysis April 6, 2010

271 Energy Efficiency Premium Efficiency Motors Description: A large fraction of electrical energy consumed in many facilities is used to run electric motors. Nationally, motordriven systems account for about 57% of all electrical energy use. Energy-efficient motors now available are typically 2%-8% more efficient than standard motors. This efficiency improvement can translate into substantial energy and dollar savings. Over a typical ten-year operating life, a motor operating most of the time can easily consume electricity valued at more than 50 times the motor s initial purchase price. This means that when you spend $1,600 to purchase a motor that operates continually, you may be obligating yourself to spend more than $80,000 on electricity. Therefore, it may be wise to invest in motors with higher efficiencies than what is required, even if they are a bit more expensive. Premium efficiency motors reduce the amount of lost energy going into heat rather than power by using steel with better magnetic qualities, bigger diameter wire, and better bearings. Since less heat is generated, less energy is needed to cool the motor with a fan further improving energy efficiency. The term premium efficiency has been used by many people to mean anything better than what the government defines as high efficiency. Recently, the Consortium for Energy Efficiency (CEE) developed minimum efficiencies that motors have to exceed in order to be considered premium efficiency. This isn t law yet, but is getting to be fairly widely accepted among motor manufacturers. As is clarified in the table below, premium-efficiency motors are more efficient than energy-efficient motors. Applications: The CEE Premium Efficiency standards apply to NEMA Design A and B, three-phase induction motors rated from 1- to 200-horsepower, with synchronous speeds of 1200, 1800, and 3600 RPM, and with either Open Drip Proof (ODP) or Totally Enclosed Fan-Cooled (TEFC) enclosures. These motors are used extensively to drive pumps, fans, compressors, and machine tools. CEE Premium Efficiency motors should be considered in all new motor procurements and when specifying motor-driven equipment. Premium Efficiency motors should also be considered as an alternative to repairing or rewinding a failed motor. Premium Efficiency motors may also be cost-effective replacements for older, operable motors particularly when the operable motor has been rewound, or is oversized and underloaded.

272 Premium Efficiency Factsheet Premium Efficiency motors are particularly cost-effective when annual operating hours exceed 2,000, where utility rates exceed $0.06/kWh, when motor repair costs exceed 60% of the price of a replacement Premium Efficiency motor, or where electrical utility motor rebates or other conservation incentives are available. Performance/Costs: Premium Efficiency motors typically cost 10% to 15% more than their energy efficient counterparts. Annual energy savings are dependent upon operating profile, duty-cycle, and efficiency gain. Depending on power costs, it is sometimes cost-effective to retrofit existing working motors. For example, at $0.07/kWh, replacing the average 10 hp motor with the best premium efficiency motor will pay back in about three years, assuming continuous operation at _ load. Efficiency standards and annual savings for using Premium Efficiency motors rather than energyefficient motors are summarized in the following table. Availability: For each motor size, speed, and enclosure combination, at least three major motor manufacturers offer products that meet CEE Premium Efficiency standards. Since vendors typically stock or have access to multiple motor brands, most distributors have little difficulty providing Premium Efficiency motors. For Additional Information: MotorMaster+ software The U.S. Department of Energy sponsors MotorMaster+ 3.0 software. MotorMaster+ features a manufacturers database containing price and performance information for over 27,000 motors. You can download the software from the website, or call the OIT Clearinghouse at (800) for your free copy. Motors U.S. Department of Energy Industries of the Future BestPractices This website contains tip sheets, case studies, and technical reports on motors and drives efficiency practices. 2