COLUMBUS, GEORGIA S HIGH-EFFICIENCY, LOW COST, DIGESTER-GAS-FIRED POWER PLANT

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1 COLUMBUS, GEORGIA S HIGH-EFFICIENCY, LOW COST, DIGESTER-GAS-FIRED POWER PLANT Karen Durden,* John Willis, Randy Shaw, Dilip Shah, Anup Shah, Jim Schettler, Brown and Caldwell Cliff Arnett, Steve Davis, Columbus Water Works *Brown and Caldwell 990 Hammond Drive, Suite 400 Atlanta, Georgia ABSTRACT Growing concern over the cost of power and long-term availability of limited fossil fuel resources for the production of electricity have caused electrical utilities and governments to promote green or renewable power. Solar, wind, geothermal, biomass, biogas, and low-impact hydroelectricity are current acceptable green-power sources. Digester gas is a renewable, green energy resource that has been used in wastewater treatment plant (WWTP) engines since the 1930s. In the 1980s, many WWTPs added cogeneration with rich-burn engines. In the 1980s and 1990s, utilities either converted their rich-burn engines to lean-burn engines or installed new lean-burn engines to meet air quality requirements. Because digester gas is of finite supply and is dependent on operating parameters such as sludge feed and volatile solids destruction, it is desirable for WWTPs to maximize the efficiency of electricity generation and beneficial reuse of otherwise wasted heat. Recently, a number of projects have used innovative cogeneration technologies, such as fuel cells, gas turbines, microturbines, and Stirling Cycle engines, to harness the energy of digester gas. In addition, advanced reciprocating engine systems (ARES) are currently being developed as another cogeneration technology under an initiative sponsored by the United States Department of Energy (USDOE) and U.S. National Laboratories with three reciprocating engine manufacturers. Columbus Water Works (CWW) is currently evaluating the use of ARES engines for combined heat and power (CHP) generation for its Class A biosolids process named Columbus Biosolids Flow-Through Thermophilic Treatment (CBFT 3 ) at the South Columbus Water Reclamation Facility (SCWRF) that currently treats an average flow between 30 and 35 million gallons per day (mgd). The use of ARES engines as part of the CBFT 3 project would represent one of the lowest capital cost, highest net efficiency CHP technologies. The project is expected to provide a payback between 4 to 7 years, with an even shorter payback period depending on the degree of federal funding secured and avoided capital offsets assumed. Other innovative features of the project include the addition of grease trap waste to the digestion process to increase gas and power production, digester gas pretreatment using multiple unit processes, and heat recovery systems. 3570

2 KEYWORDS Cogeneration, Green Power, ARES, Combined Heat and Power, Digester Gas Treatment, Class A, Anaerobic Digestion INTRODUCTION CWW has led the development of a Class A digestion process named CBFT 3. The CBFT 3 process will allow CWW to improve the quality and minimize the amount of biosolids generated from the SCWRF and, consequently, reduce land application, landfill, and disposal costs. The CBFT 3 process is a two-stage, thermophilic process consisting of anaerobic continuousfeed, mix digestion followed by anaerobic plug-flow reactors. The CBFT 3 process is used to meet the pathogen reduction requirements of 40 Code of Federal Regulations (CFR), Part 503 under Alternative 6: Qualification as an Equivalent to a Process to Further Reduce Pathogens (PFRP). Mesophilic anaerobic digestion is provided downstream of the CBFT 3 process to ensure vector attraction reduction (VAR) requirements. Extensive bench- and pilot-scale testing has shown the ability of the CBFT 3 process to meet the Class A requirements for pathogen reduction. CWW received a patent in June of 2005 for the process and use of a plug-flow reactor in conjunction with a thermophilic digester to produce Class A biosolids. That patent was subsequently presented by CWW to the Water Environment Research Foundation (WERF) in October 2005 to hold in the public domain for the use of all wastewater utilities. The next step in the development of the CBFT 3 process is the advanced demonstration project, which will be used to validate the performance of the full-scale system to meet Class A biosolids standards. Furthermore, the advanced demonstration project will include the green power component that uses digester gas to produce electricity and recover waste heat. AVAILABLE COGENERATION TECHNOLOGIES Several cogeneration technologies were considered for the SCWRF. The evaluated technologies include: Fuel cells Combustion gas turbines Microturbines Internal combustion engines Stirling Cycle engines ARES engines Brief descriptions of these technologies are presented below. 3571

3 Fuel Cells Fuel cells utilize digester gas as a reactive fuel and source of hydrogen to generate electricity in modular arrangements that are somewhat similar to batteries. Because fuel cells operate without combustion, they are capable of producing energy with low emissions. Because fuel cells are sensitive to contaminants in digester gas, extensive digester gas pretreatment must be utilized to remove hydrogen sulfide, siloxanes, particulates, and trace heavy metals. Fuel cells have electrical efficiencies and heat recovery performance of approximately 37 and 40 percent, respectively. Fuel cells have been used on digester gas applications throughout the country, including King County, Washington; Los Angeles Terminal Island facility of the Los Angeles Department of Water and Power; Columbia Boulevard WWTP in Portland, Oregon; Rancho Las Virgenes Composting Facility in Calabasas, California; and several installations in New York. 1 An example fuel cell installation is shown on Figure 1. Figure 1 Fuel Cells Combustion Gas Turbines Gas turbines are large rotary prime movers in sizes of 1 megawatt (MW) and larger. Gas turbines or combustion gas turbines utilize pressurized and combusted digester gas to rotate a high-speed turbo expander that is coupled to an electric generator to produce electricity. Gas turbines typically operate in a range of 22 to 30 percent electrical efficiency. Gas turbines produce a very large quantity of hot exhaust gases and have a very high ratio of usable heat to electrical output. Gas turbines require very high pressure fuel, often 200 to 300 pounds per square inch gauge (psig), and can have 35 to 40 percent heat recovery performance. The requirement to pressurize the flow upstream of the turbine represents a fairly significant parasitic load that reduces overall efficiency. 2 Microturbines Microturbines are a form of small combustion gas turbines with exhaust recuperators for better performance. Microturbines, which combust pressurized digester gas to rotate a very high-speed turbo-expander that is coupled to an electric generator, have an output of less than 1 MW. Early microturbine installations on digester gas include facilities in Pennsylvania, Colorado, California, New York, and Vermont. 1 Microturbines also operate at electrical efficiencies and heat recovery performance that are in the 22 to 26 percent, and 20 to 24 percent ranges, respectively. Microturbines are particularly advantageous in ozone non-attainment zones because of low nitrous oxide (NO x ) emissions. Microturbines require, at a minimum, removal of water vapor and siloxanes from digester gas. 3572

4 Internal Combustion Engines Internal combustion engines, as shown on Figure 2, are the common cogeneration technology at wastewater facilities and are used for generation of electricity or mechanical energy to drive process equipment, such as pumps and blowers. Over two-thirds of WWTP cogeneration units in the United States are internal combustion engines. Many recent projects have used lean-burn technology, which means the engine operates with excess combustion air or leaner than the stoichiometric air fuel ratios. As a result, lean-burn engines emit far lower air emissions, such as NO x or unburned engine fuel. Engines have energy efficiencies and heat recovery performance in the 30 to 38 and 40 to 50 percent ranges, respectively. Digester gas pretreatment requirements include removal of water vapor, hydrogen sulfide, and siloxanes. Figure 2 Internal Combustion Engines Stirling Cycle Engines Stirling Cycle engines are a new cogeneration technology that uses an external combustion process to convert heat to mechanical power. Stirling Cycle engines reportedly have reduced emissions compared to reciprocal engines. Biogas pretreatment requirements for Stirling Cycle engines are not known at this time because it is a new technology. A 25-kilowatt (kw) Stirling Cycle engine was recently installed for demonstration testing in Corvallis, Oregon, but was taken out of service when hydrogen leaks developed. 1 ARES Engines Major engine manufacturers are currently developing advanced engines that offer either increased efficiency or cleaner burning operations than conventional internal combustion engines. The higher efficiency of the ARES engines is significant. For example, at 40 percent efficiency, only 14.7 cubic feet (cf) of digester gas is required per kw. This results in higher kw output for a given amount of digester gas compared to technologies like microturbines and combustion gas turbines. The ARES program is sponsored by the USDOE and U.S. National Laboratories in concert with three reciprocating engine manufacturers (Caterpillar, Cummins, and Waukesha). The program is designed to advance reciprocating engine efficiency and reduce engine emissions over a 10-year planning horizon that began in While the timetable has slipped slightly, all three manufacturers are making progress toward the program objectives and have a 2004-criteria-compliant engine either installed or planned. As of 2005, two engine manufacturers had ARES in service operating on natural gas while the third has units in testing that should be deployed in the near future. There are not currently any applications of ARES engines on digester or landfill gas. Biogas pretreatment for ARES engines includes removal of water vapor, hydrogen sulfide, and siloxanes. 3573

5 Technology Summary Table 1 compares the advantages and disadvantages of the cogeneration technologies evaluated for the SCWRF. Table 1 Summary of Evaluated Cogeneration Technologies Technology Advantages Disadvantages Fuel Cells Combustion Gas Turbines Microturbines Internal Combustion Engines Low or no exhaust emissions High electrical efficiency Modular arrangement More cost-effective than internal combustion engines for sizes greater than 40 MW Provide substantial usable heat and can produce high pressure steam Low exhaust emissions Available in small sizes High electrical efficiencies Widely used on digester gas Operate on low-pressure fuel High thermal and electrical efficiency Very high capital and operating cost Low recoverable heat High-level digester gas and natural gas pretreatment required Limited capacity Lower electrical efficiency Too large for the SCWRF; better suited to 80-mgd WWTPs and larger Require high-pressure fuel Produce very little usable heat Higher capital and operating cost Numerous units required for SCWRF Require high-pressure fuel Lower efficiency compared to ARES engines Require sound attenuation More mechanically complex Stirling Cycle Engines ARES Engines Require limited digester gas pretreatment High thermal and electrical efficiency Low exhaust emissions Present units are in developmental stages Single supplier with limited resources Numerous units required for SCWRF Require high-pressure fuel High capital cost Low recoverable heat Present units have been used solely for landfill gas applications Uncertain capital and operation and maintenance (O&M) costs More mechanically complex 3574

6 ARES Technology Selection During the evaluation, ARES units were identified as the most suitable green power technology for implementation in combination with the CBFT 3 thermophilic digestion process. ARES engines were selected based on their low capital cost, high electrical efficiency, availability of high-grade heat for heating the digestion process to thermophilic temperatures, and comfort level with an upgraded conventional engine technology. The presence of three available vendors and oversight by the USDOE further enhanced CWW s comfort level with this new technology. DIGESTER GAS PRODUCTION Several factors were considered when calculating the design digester gas production for the demonstration project. Currently, the SCWRF operates its anaerobic digesters under mesophilic conditions. In order to appropriately size the engines such that they operate at maximum efficiency, 2 years worth of sludge production data were analyzed. Figure 3 shows the historical total volatile solids loading, volatile solids destruction, and digester gas production. Figure 3 Historical Digester Gas Production and Volatile Solids Destruction 900, , ,000 Gas Production cfd Feed Volatile Solids ppd Destroyed Volatile Solids ppd 120, , , , , , , ,000 0 Jan-02 Apr-02 Jul-02 Oct-02 Jan-03 Apr-03 Jul-03 Oct-03 Jan-04 Gas Production (CFD) 80,000 60,000 40,000 Volatile Solids (ppd) 20,000 0 Date The average gas production in the mesophilic anaerobic digestion process at the end of the evaluated period is roughly 325,000 cubic feet per day (cfd), which represents an average volatile solids destruction of 58 percent. 3575

7 In addition to analyzing historical data, other factors that influenced engine sizing included: Conversion from mesophilic to thermophilic digestion Growth in the service area, especially from Fort Benning Beneficial reuse of grease trap waste to produce additional power By converting to temperature-phased digestion as part of the CBFT 3 process, it is estimated that gas production will increase by an additional 10 to 20 percent due to enhanced volatile solids destruction at the higher operating temperature. In addition, digester gas production and subsequently engine sizing was influenced by growth in the SCWRF service area. Columbus, which is home to Fort Benning, is projected to see relocation of approximately 10,000 soldiers and 30,000 military and civilian support personnel as a result of the Base Realignment and Closure (BRAC) initiative. It is estimated that digester gas production will increase by approximately 17 percent with the delivery of raw wastewater (and associated solids/organic loads) from Fort Benning to the SCWRF for treatment. Finally, grease trap waste will be beneficially reused during anaerobic digestion to increase gas production. Currently, the SCWRF uses engineered bacteria and magnetic flow conditioning to degrade and destabilize grease. Clarified water from this process is then returned to the plant headworks. An average of 30,000 gallons per week of grease trap waste is currently treated. It is expected that the volume will reach 38,000 gallons per week once Fort Benning grease trap waste is received. In the CBFT 3 process, grease will be preheated and added to the thermophilic digesters. During periods when grease is fed to the thermophilic digestion process, it is estimated that digester gas production will increase approximately 5 to 10 percent. This type of grease-to-gas approach has been used successfully at the South Bayside System Authority in Redwood City, California. 3 The East Bay Municipal Utility District also conducted a study that showed increased digester gas production with the addition of fats, oils, and grease to anaerobic digestion. 4 At start-up, the cogeneration facility at the SCWRF is projected to handle an average digester gas production of between 420,000 and 455,000 cfd. The associated minimum day, maximum week, and maximum day gas production rates are estimated to be 200,000, 750,000, and 1,000,000 cfd, respectively. To handle variations in digester gas production, a membrane gas holder cover will be provided for the mesophilic digester for digester gas storage. Based on the above average gas production, 38.5 percent net electrical efficiency, and a 580 British thermal units (Btu)/cf heating value, normal gas production could produce between 1.1 and 1.3 MW of electrical power. SYSTEM FEATURES The CBFT 3 process at the SCWRF will employ robust gas treatment prior to energy recovery using ARES engines. In addition, innovative heat recovery systems will be used as part of the CBFT 3 process. These are further explained in more detail below. 3576

8 Gas Treatment Gas produced during anaerobic digestion will be collected and treated prior to energy recovery. Digester gas contains a variety of contaminants that can lead to malfunctioning or destruction of cogeneration equipment. The contaminants of primary concern include water, hydrogen sulfide, siloxanes, and particulate matter. Water is always present at saturation due to the evolution of gas from the digesting sludge; the mass of water per unit volume increases because of the higher temperature of the thermophilic digestion process. Hydrogen sulfide, which is present at higher concentrations at thermophilic temperatures, causes corrosion by forming sulfuric acid when interacting with water. Hydrogen sulfide levels in digester gas typically range from 300 to 2,500 Figure 4 Siloxane Buildup parts per million (ppm). Siloxanes, which are becoming more prevalent as they replace many hydrocarbon-based compounds in consumer products, may be present in volatile forms in digester gas. These gaseous-phase compounds precipitate silicon oxide compounds when burned resulting in serious deposits, as shown on Figure 4, and accelerated wear on moving parts of cogeneration equipment. Particulate material can contribute to wear and failure of end-use equipment but these contaminants are fairly easy to remove using conventional filtration equipment. Many cogeneration technologies require a higher level of digester gas pretreatment. In addition, the need for gas treatment in older installations is also becoming apparent on a more and more frequent basis due largely to the increased presence of siloxanes in the fuel stream. Systems that used to require engine rebuilds every 4 to 6 years are now facing major maintenance efforts on an annual or even more frequent basis. Because the ARES engines will require a higher level of gas treatment than currently provided at the SCWRF, a multi-stage treatment system is planned to clean the digester gas. Specifically, the gas treatment system will consist of: Iron sponges to remove hydrogen sulfide Refrigerated drying to remove water, siloxanes, and volatile organic compounds (VOCs) Booster blowers combined with gas reheating to eliminate potential for condensation downstream of drying; blowers will be sized to deliver gas to the engines at the required pressure Activated carbon for removal of siloxanes Fine-media filtration for final particulate removal 3577

9 Figure 5 shows a schematic depiction of the planned gas treatment system. Figure 5 Schematic of the Proposed Gas Treatment Train Iron Sponge Digester Refrigerative Dryer Activated Carbon Booster Blower & Gas Reheating Particulate Filter Clean Gas To ARES Multi-stage systems similar to that proposed herein have been used by Brown and Caldwell at the Annacis Island WWTP in Vancouver, British Columbia; the Alverado WWTP in Union City, California; the Santa Cruz WWTP in Santa Cruz, California; the Salt Lake City Water Reclamation Plant in Salt Lake City, Utah; and the West Boise WWTP in Boise, Idaho. Heat Recovery As previously discussed, all of the produced digester gas will be burned in the ARES engines as part of the cogeneration solution for the energy recovery system. The electric power generated from the ARES engines will largely offload the plant electrical demand up to one-third of the current SCWRF electrical demand. Heat will be recovered from various locations and sources within the ARES engine system. Heat will also be recovered from the thermophilic sludge prior to mesophilic digestion. The various sources of heat recovery are listed in Table 2 below. Table 2 Summary of Heat Recovery Sources Heat Source Heat Quality Recovery Method Engine exhaust High-grade 2 Steam generation Engine jacket cooling High-grade 1,2 Hot water Thermophilic sludge Mid-grade 3 Sludge-to-water heat exchanger Engine intercooler Low-grade 4 Hot water recirculation Engine lube oil cooling Low-grade 4 Hot water recirculation 1 Subject to engine specifications. Alternatively, could be mid-grade heat and recovered in hot water recirculation loop. 2 High-grade heat quality ranges from 180 to 250 degrees Fahrenheit (F). 3 Mid-grade heat ranges from 140 to 180 degrees F. 4 Low-grade heat is less than 140 degrees F. 3578

10 The overall sludge process heating requirements are shown on Figure 6. Figure 6 Summary Schematic of the Sludge Heating and Cooling System Raw Sludge In o F o F 95 o F 95 o F Class- A Biosolids Out Mid - Grade Heat In Low - Grade Heat In Mid/High - Grade Heat In High-Grade Heat In Mid-Grade Heat Out The elements of the sludge heating and cooling system include the following features: First Stage Pre-Heating. The raw sludge will be heated to roughly mesophilic temperatures (93 to 97 degrees F) within this first process using heat recovered from cooling the thermophilic sludge downstream of the plug flow reactors. A sludge-to-water heat exchanger will be utilized to recover heat from the 140 degree F sludge exiting the plug flow reactors. The heated water will then be pumped (in a continuous loop) to a second sludge-to-water heat exchanger for raw sludge preheating. On system start-up, first stage pre-heating will be provided by an ARES engine, boiler, or direct steam injection. Second Stage Pre-Heating. Grease trap waste will be introduced into the first stage preheated raw sludge stream prior to second stage preheating. The combined sludge will pass through a sludge-to-water heat exchanger. The hot water source for this heat exchanger will be from the low-grade heat recovered from the engine intercooler and lube oil systems. Third Stage Pre-Heating. The combined, preheated raw sludge and grease trap waste will flow through third-stage preheating and the contents will be heated to the desired thermophilic temperature set point (127 to 131 degrees F). Steam injection using low pressure steam will be utilized for third stage preheating. Steam will be generated from heat recovered from the engine exhaust. Thermophilic Digestion. The first process tank in the CBFT 3 process will be operated at thermophilic temperatures in excess of 127 degrees F. Digester heating will be accomplished by the existing draft tube heat exchangers to offset any ambient heat loss and any additional heating required if the preheating systems cannot achieve the desired operating temperatures. The existing hot water heating and recirculation loop will continue to be used for this purpose. The supply of hot water to the existing water-towater heat exchanger in this loop will either be from boiler water or engine jacket cooling water. 3579

11 Pre-Plug-Flow Heating. The temperature will be boosted upstream of the plug-flow reactors using direct injection of low pressure steam. Temperature will be boosted to 142 to 144 degrees F and controlled upstream of the insulated, yet unheated plug-flow vessels. Post-Plug-Flow Heat Recovery. The thermophilic sludge will be cooled to approximately 98 degrees F in this heat recovery system upstream of mesophilic digestion. The heat recovered will be used to heat the raw incoming sludge in the first stage preheating described above. The hot water recirculation loops and steam injection systems described above are summarized herein. Low-Grade Heat (less than 140 degrees F) Recovery Hot Water Recirculation Loop. Figure 7 presents a summary schematic of the low-grade heat hot water recirculation loop. Heat recovered from engine intercooler and lube oil sources will be continuously circulated in a low grade hot water loop. The hot water will be used for the second stage sludge preheating system described above. A heat sink will also be included in this loop in order to adequately dissipate the required heat for proper engine operation. The sink will either consist of a fan radiator or a water-to-water heat exchanger. Figure 7 Summary Schematic of Low-Grade Hot Water Recirculation Loop HEAT RECOVERY SOURCE ARES ENGINES intercooler lube oil Low-Grade Heat Hot Water Recirculation Loop HEAT APPLICATION SECOND STAGE SLUDGE PRE-HEATING (water-to-sludge heat exchanger) Mid-Grade Heat (140 to 180 degrees F) Recovery Hot Water Recirculation Loop. Figure 8 presents a summary schematic of the mid-grade heat hot water recirculation loop. Heat will be recovered from the thermophilic sludge discharging the plug flow reactors (i.e., sludge cooling) in a sludge-to-water heat exchanger. The water will be continuously circulated to the first-stage sludge preheating water-to-sludge heat exchanger to preheat the raw sludge as described above. This water circulation loop will comprise the mid-grade heat recovery hot water recirculation loop. 3580

12 HEAT RECOVERY SOURCE PLUG FLOW REACTOR DISCHARGE SLUDGE (sludge-to-water heat exchanger) Mid-Grade Heat Hot Water Recirculation Loop HEAT APPLICATION FIRST STAGE SLUDGE PRE-HEATING (water-to-sludge heat exchanger) Figure 8 Summary Schematic of Mid-Grade Heat Recovery Hot Water Recirculation Loop High-Grade Heat (180 to 250 degrees F) Recovery Hot Water Recirculation Loop. Figure 9 presents a summary schematic of the high-grade heat recovery hot water recirculation loop. Heat will be recovered from the engine jacket cooling water through a water-to-water heat exchanger. Hot water will be circulated through the existing hot water system associated with the boilers and the digester draft tube mixers. Figure 9 Summary Schematic of High-Grade Heat Recovery Hot Water Recirculation Loop HEAT RECOVERY SOURCE Primary - ARES ENGINES (jacket cooling water) Back-Up - BOILERS (existing) Hi-Grade Heat EXISTING Hot Water Recirculation Loop HEAT APPLICATION ALL DIGESTER DRAFT TUBE MIXERS (existing jackets) High-Grade Heat Recovery Low Pressure Steam System. Figure 10 presents a summary schematic of the high-grade heat recovery low pressure steam system. Heat will be recovered from the engine exhaust (and possibly from the engine jacket cooling water) through a gas-to-water heat exchanger. Using potable water, low pressure steam up to 14 psig will be generated and injected directly into the sludge just prior to the thermophilic 3581

13 digester to achieve temperatures exceeding 127 degrees F and just after the thermophilic digester to achieve temperature exceeding 140 degrees F prior to the plug flow reactors. Figure 10 Summary Schematic of High-Grade Heat Recovery Low Pressure HEAT RECOVERY SOURCE HEAT APPLICATION ARES ENGINES (exhaust) Potable Water Hi-Grade Heat Low Pressure Steam Injection THERMOPHILIC DIGESTERS (injection into feedstock) PLUG FLOW REACTORS (injection into feedstock) Steam System It is critical that the controls on the heating systems meet the requirements of the Class A sludge heating, the cooling needs of the engines, and the thermophilic-to-mesophilic process change. Thus, the existing boilers and hot water loop will be retained in service to supplement the other sources when necessary (projected to be less than 1 percent of the time when combination of extreme sludge flow rates and winter raw sewage temperatures dramatically increase the required heating load). The ARES engines, in addition to low-pressure steam, will provide system redundancy for the high-grade heat recovery system. ECONOMIC EVALUATION The economics of the ARES engines were evaluated to assist CWW in the planning and financing of the CBFT 3 advanced demonstration project. The analysis computed annual operating costs and savings based on inputs such as: Monthly raw sludge and ambient air temperatures Digester operating temperatures Feed sludge flow rate and solids concentrations Volatile solids destruction and digester gas production Monthly operating days and hours Electricity and natural gas costs Engine O&M service agreement cost Engine efficiency With the above inputs, the heat balance in the CBFT 3 process and its impact on engine costs were calculated. As shown in Table 3, the total heat recovered in the CBFT 3 process, including 3582

14 heat recovered from cooling thermophilic sludge and from the ARES engine jacket water, lube oil, intercooler, and exhaust, exceeds the heat demand in every month except March. Consequently, minimal natural gas is required at the SCWRF to operate the existing boilers as a supplemental heat source. 3583

15 Table 3 Engine Economic Analysis 3584 Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total Average raw sludge temperature, 1 degrees F Heated sludge temperature for thermophilic digester, degrees F Average ambient temperature, 1 degrees F Digester gas production, 1 cfd 485, , , , , , , , , , , ,000 - Average digester gas fuel energy (LHV), million Btuh Total average heat required for thermophilic digester, million Btuh Total average heat required for plug flow reactor, million Btuh Total average sludge heat required, million Btuh Possible heat recovery from cooling sludge from plug flow reactor, million Btuh Possible heat recovery from engine (excludes exhaust heat), million Btuh WEFTEC.06

16 Table 3 Engine Economic Analysis 3585 Month Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Total Possible heat recovery from engine exhaust heat, million Btuh Total possible heat recovery, million Btuh Average supplemental natural gas fuel to back up boiler, million Btuh Natural gas cost 1, per therm $0.77 $0.77 $0.77 $0.77 $0.77 $0.77 $0.77 $0.77 $0.77 $0.77 $0.77 $ Monthly cost of the supplemental natural $0 $0 -$1,500 $0 $0 $0 $0 $0 $0 $0 $0 $0 -$1,500 gas to standby boiler Net average electrical output, kw 1,350 1, ,160 1,480 1,260 1,230 1,320 1,280 1,520 1,490 1,290 - Value of generated electricity 3, per kwh $0.061 $0.068 $0.064 $0.066 $0.064 $0.065 $0.071 $0.077 $0.074 $0.068 $0.070 $ Value of the net generated electric $62,000 $51,000 $41,000 $55,000 $70,000 $59,000 $65,000 $75,000 $68,000 $76,000 $75,000 $71,000 $768,000 power per month Monthly O&M cost per engine equipment -$14,000 -$13,000 -$14,000 -$14,000 -$14,000 -$14,000 -$14,000 -$14,000 -$14,000 -$14,000 -$14,000 -$14,000 -$167,000 service agreement 4 Monthly net cost savings $48,000 $38,000 $26,000 $41,000 $56,000 $45,000 $51,000 $61,000 $54,000 $62,000 $61,000 $57,000 $600,000 WEFTEC.06 1 Based on historical data. 2 Assumes digester gas fuel value of 580 Btu/cf. 3 Costs based on data from June 2005 to May 2006 with 5-percent annual escalation. 4 Assumes $0.015/kWh for engine O&M service agreement. Cost includes routine maintenance, minor engine overhaul maintenance, major engine overhaul maintenance, and labor costs.

17 It was assumed in the analysis that all routine maintenance, minor and major engine overhauls, and associated labor would be performed by an independent engine service provider. Because there are currently no ARES engine installations on digester gas, the engine O&M cost was based on experience with conventional internal combustion engines operating on digester gas. To determine the simple payback period for the green power component of the project, capital cost estimates for several engine configurations were developed in addition to the annual net cost savings. By using the above costs, the payback period for the green power component was calculated. These results are shown in Table 4 below. Table 4 Payback Period for Green Power Component of Advanced Demonstration Project Parameter Two 990-kW Engines Three 990-kW Engines One 1,600-kW Engine Two 1,600-kW Engines Capital $2,690,000 $3,720,000 $2,298,000 $3,670,000 Cost 1 Net Annual $600,000 $600,000 $600,000 $600,000 Savings 2 Simple Payback Period 4.5 years 6.2 years 3.8 years 6.1 years 1 Capital cost includes costs for ARES engines, gas pretreatment system, piping, electrical, instrumentation and controls, 20 percent unitemized construction elements, bonds, insurance, contractor overhead and profit, and engineering. 2 From Table 3. As shown above, the payback period for the green power component of the project ranges from approximately 4 to 7 years. CONCLUSIONS The combination of ARES technology with thermophilic anaerobic digestion creates an interesting synergy between the production of renewable power and the treatment of biosolids to Class-A levels. While digester gas is a renewable resource, it is available in finite quantities and its efficient use is important to leveraging its value. The CBFT 3 project will demonstrate how this synergy can be optimized to achieve overall fuel efficiencies in excess of 80 percent. The project will also demonstrate current state-of-the-art gas treatment technologies at full scale; the design of which will minimize the required operation and maintenance attention over the life of the installation. 3586

18 REFERENCES 1 Monteith, et al. (2005) Cost-Effective Energy Recovery from Anaerobically Digested Wastewater Solids Draft Final Report, Water Environment Research Foundation; Washington, D.C. 2 Chambers, A; Potter, I. (2002) Gas Utilization from Sewage Waste. Carbon and Energy Management, Alberta Research Council; Edmonton, Alberta, Canada. 3 Joyce, M; Donaldson, B. (2005) Fattening Up the Bottom Line: Changing Sewer Grease from a Liability to an Asset. Water Environment and Technology, 17 (8), Suto, et al. (2006) Innovative Anaerobic Digestion Investigation of Fats, Oils, and Grease. Water Environment Federation Residuals and Biosolids Management Conference, Cincinnati, Ohio. 3587