Assessing Feasibility of Direct Drive Technology for Energy Recovery from Digester Biogas

Transcription

1 Assessing Feasibility of Direct Drive Technology for Energy Recovery from Digester Biogas Hugh Monteith (1), Kaoru Yajima (2), David Andrews (2), and Paula Steel (3) (1) Hydromantis, Inc., 1685 Main Street West, Suite 302, Hamilton, ON, Canada, L8S 1G5 (2) Regional Municipality of Waterloo, Waterloo, ON; (3) Associated Engineering, Toronto, ON ABSTRACT The Regional Municipality of Waterloo completed a study, with support from Environment Canada, to evaluate the feasibility of using direct drive technology to recover energy from digester biogas. The study identified that a 150 HP engine, operating at 54 % load, could be supported by the estimated gas production of 1560 m 3 /d with 63 % methane by volume. Potential applications of the direct drive technology included an existing raw sewage pump, or a new air blower. Low levels of hydrogen sulfide (4-10 ppm v ) and siloxanes (40-50 µg/l) reduced the require gas pretreatment to a chiller to reduce the moisture content. Total project costs for application of the direct drive engines were similar in magnitude, estimated at $1.02 Million (Cdn) and $1.04 Million for the proposed new blower and for the existing raw wastewater pump, respectively. The blower application was favored over the wastewater pump application due to ease of installation and greater flexibility for future biogas production rates. Annual operating and maintenance costs were estimated at $16,850 for both applications. Based on a cost of $0.061/kWh, the net annual savings in electricity by the direct drive engine application was estimated at $56,640, while the value of recovered thermal energy (30% efficiency) was estimated at $25,150, resulting in net annual savings of $64,900. These savings result in a payback period of 15.9 years, which although long is not unreasonable for the investment required, at the current price of electricity. The payback period for the direct drive application would decrease significantly if the price of electricity were to increase. For example, if the price of electricity increased from its current value of $0.061/kWh to $0.10/kWh, assuming 30 % thermal energy recovery, the payback period would decline from 15.9 to 10.1 years. KEY WORDS: Anaerobic, Digester Gas, Energy, Direct Drive INTRODUCTION Biogas is a renewable resource available at most wastewater treatment plants. However, a recent study has indicated that this valuable resource is not being fully utilized. Excess digester gas is normally flared during warmer months because heat recovery cannot fully utilize the digester gas produced. A recent survey of wastewater treatment plants determined that almost 20% of the total digester gas produced was flared to the atmosphere with no energy recovery (CH2M Hill, 2000). Direct drive technology bypasses the mechanical-electrical-mechanical energy conversion inefficiencies and the power grid quality problems associated with combined heat and power 3517

2 (CHP) technologies. The direct drive technology is a good fit for a municipal wastewater treatment plant where there is a high demand for mechanical power. In spite of the apparent advantages, the technology has not been widely adopted. Direct drive technology has a demonstrated advantage in that it can use biogas effectively throughout the year and has a shorter payback period when compared to boilers, micro-turbines, cogeneration units and fuel cells (Enviromega, 2004) (Figure 1). Preliminary cost estimates indicate that direct drive engines are the most economical means of recovering biogas energy, with payback periods as short as three years. Region of Waterloo s Strategic Focus on Green Initiatives The Regional Municipality of Waterloo (RMOW) has developed a Strategic Focus which includes a general goal to improve air quality and protect the environment. Included in this goal is a specific action to investigate green initiatives that will reduce emissions and energy consumption. In keeping with this initiative, the RMOW prepared a conceptual study on the application of biogas cogeneration facilities at the Waterloo wastewater treatment plant (WWTP). The analysis concluded that cogeneration was potentially feasible, but there would be a long payback period. This result confirmed information presented in a recent study which identified significant payback periods for cogeneration units, micro-turbines and fuel cells (Enviromega 2004). While the conceptual analysis examined biogas cogeneration alternatives, it did not consider biogas-powered direct drive technologies. Based on the information available, application of direct drive technology at Waterloo has the potential to provide additional value, both in terms of the green initiatives contained in the Strategic Focus and the payback period for the investment. Payback Period (years) Engine/Gen Boiler Microturbine Fuel Cell Direct Drive Minimum Maximum Median Figure 1. Estimated Payback Periods for Biogas Energy Recovery in Canada (Environment Canada, 2004) 3518

3 STUDY OBJECTIVE Environment Canada is currently supporting a two phase study evaluating the economic feasibility of applying direct drive engine technology to recover the energy from digester gas at Canadian wastewater treatment plants. Funding for feasibility assessments by up to five municipalities was anticipated by Environment Canada, but ultimately only three municipalities, including the RMOW, submitted proposals. In the planned second phase of the study, a full-scale demonstration of the technology will be implemented at least one of the facilities. The specific objectives of the feasibility study undertaken by the Region of Waterloo were to: Evaluate the existing biogas situation, including assessment of current biogas quality, biogas production rate, excess biogas availability, and existing biogas conditioning equipment. Evaluate the process feasibility of direct drive applications, including suitability (e.g. use of pumps or blowers, sizing, speed and torque requirements); potential use of up to three different direct drive technologies (e.g. conventional engines, modified commercial engines, specialty engines); requirements for additional gas conditioning for short-listed engine types; evaluation of requirements for natural gas supplementation, when necessary; and development of a major equipment list and process flow diagram for the most likely direct drive solution. Refine the process and costing estimate by creation of a conceptual design, estimation of capital costs (+/- 30%) of proposed equipment, estimation of operating costs and potential value of energy savings; estimation of payback period for the proposed design; and modify the proposed design to reduce costs as required. DESCRIPTION OF WATERLOO WWTP The Waterloo WWTP was initially constructed in 1962, but there have been extensive additions and renovations since that time. The treatment involves a conventional activated sludge process that provides chemical phosphorus removal, chlorine disinfection and anaerobic digestion of wastewater solids. The waste biological solids are co-thickened with primary sludge in the primary clarifiers. The raw combined sludge is then pumped to a two-stage anaerobic digestion process consisting of a primary and secondary digester. The anaerobic digestion process stabilizes the biosolids generated from the liquid treatment process. One of the by-products of anaerobic digestion is biogas, which is a mixture of primarily methane and carbon dioxide plus small amounts of various other gases. The digester gas is passed through sediment and condensate traps, but there is no other preconditioning of the gas to remove impurities (i.e., H 2 S or siloxane). Presently, the gas is used in a boiler system that provides thermal heating for the anaerobic digestion process and some of the buildings. Any excess biogas is currently flared, which the Region recognizes as a waste of a valuable resource. The RMOW has initiated a preliminary design for upgrading the Waterloo WWTP to achieve the ultimate design capacity. The proposed upgrade will include upgrades to the aeration system, 3519

4 the future addition of a biological aerated filter (BAF) system for nitrification, a new ultraviolet disinfection system, and a biosolids thickening and dewatering facility. These upgrades are expected to improve the digester gas production which improves the prospect of implementing technology to fully utilize the biogas generated. STUDY PROCEDURES This section documents the procedures used to acquire data or to estimate process or economic parameters required to complete the feasibility study. Documentation of Historical Digester Performance Volatile Solids Reduction. Since no direct metering was available, it was necessary to estimate a daily biogas production rate, to establish the energy available for a direct drive engine application. The daily biogas production rate was estimated using the digester volatile solids reductions. At the start of this study, there was no documentation of volatile solids reduction (VSR) in the primary digester as a process control measurement or to estimate biogas production. There are several ways to calculate the volatile solids reduction in a digester (Schafer et al., 2003), but a commonly used procedure uses an assumption that the fixed or non-volatile fraction measured in feed and digested sludge is conserved (referred to as the VanKleek method). In this procedure, the volatile solids reduction in a digester is calculated by the formula ( v1 v2) VSR = *100 v1 v1* v2 (1) ( ) where: VSR = volatile solids reduction, % v1 = volatile solids fraction of feed sludge as decimal fraction v2 = volatile solids fraction of digested sludge as decimal fraction Raw and digested sludge were sampled on a weekly basis from November through February to permit calculation of the VSR in the digester. Raw sludge samples were collected from the discharge side of one of the digester feed sludge pumps, while samples of primary digested sludge were collected from the overflow to the secondary digester on the roof of the digester building. The volatile fraction of the sludge samples was determined by pre-weighing a sample in a tared measuring dish, and then measuring the ash residue (fixed solids) after oxidizing the volatile fraction overnight in a muffle furnace at 550 o C. Biogas Production Rate. As no gas metering was available for this study, the VSR data were used to estimate digester total gas production (including methane, carbon dioxide and other minor gas components) using conversion factors ranging from 0.75 to 1.12 m 3 /kg VS destroyed (Metcalf and Eddy, 2001). The total daily biogas production rate was estimated by combining 3520

5 the digester daily feed pumping rate (approximately 250 m 3 /d) with the VSR value and a gas production factor (e.g., 0.9 m 3 /kg VS destroyed). Biogas Quality. The methane content of the digester gas is the key component for energy production when the gas is combusted. Impurities in the digester gas can contribute to higher maintenance costs because they cause can lead to corrosion (hydrogen sulphide) or abrasion (volatile siloxanes). To establish typical biogas quality, samples were submitted to the analytical laboratory in clean Tedlar gas sampling bags for analysis. Collection of the gas samples is depicted in Figure 2. Figure 2. Collection of Digester Gas Sample for Analysis of Components Biogas quality was assessed using gas chromatography (GC) instrumentation, either alone or in tandem with a mass spectrometer (MS). In this study, the major components of digester gas were analyzed by gas chromatography alone because the retention time in the GC column and display of peaks representing the compounds of interest (methane, carbon dioxide, hydrogen sulphide, etc.) are well documented. For other trace compounds, such as volatile siloxanes and other trace organic compounds, coupled GC-MS was used for analysis. Identification of Candidate Engines for Direct Drive Application Potential applications of direct drive engines were determined in consultation with one of several suppliers (Toromont Industries, Concord, ON). A representative from Toromont toured the Waterloo WWTP site with representatives from RMOW and Hydromantis, Inc. to review the 3521

6 existing digester gas installation, biogas production and quality data, and potential application sites. Potential applications were based on the gas production and quality data. Components such as gas cleaning, booster compressors and other appurtenances were discussed and reviewed. The potential for dual fuel applications and fuel blending was also reviewed. A factor that influenced the assessment was the Region s commitment to its Strategic Focus on green initiatives. In general terms, RMOW s Strategic Focus favored selection of an engine that might be slightly over-sized (and therefore more costly), but was more environmentally friendly when compared to a smaller, less expensive engine that would need more frequent replacement. Conceptual Design for Selected Direct Drive Application The conceptual designs were created based mostly on the daily volume of biogas produced. Considerations included location of gas conditioning equipment, need for a booster based on the application location in the plant, transport of the gas to the application site, structural conditions needed to accommodate the drive engine, and thermal recovery systems. Conceptual drawings were prepared for both the plan and elevation views for the potential applications. Costing and Economic Assessment of Application The costing assessment for the potential applications was completed using a spreadsheet estimator from the Hydromantis-AE joint venture. Costing elements for the direct drive application were received from the engine supplier and used in the design. The economic assessment was completed by determining the net annual savings (in reality savings represent the avoided purchase of off-site energy) based on estimates of the direct drive engine operating costs. A spreadsheet was developed to allow for an estimation of the sensitivity of the simple payback period to the price of energy. RESULTS Historical Digester Performance Volatile Solids Reduction. Solids concentration data and volatile solids reduction (VSR) calculations for the primary digester, based on the procedure described in Section 2.1.1, are provided in Table 1. VSR decreased through the end of December and early January due to problems with a mechanical mixer in the digester. Once corrected in mid-february, the VSR values began to increase. No data are presented for February 9, the week during which the digester mixer was repaired. It was noted that the calculated values are lower than the 45 to 60 % 3522

7 reduction that might be expected in a well-operating digester. Optimization of the digestion process is recommended to improve the reduction and create more biogas for potential utilization. Table 1. Raw Sludge and Digested Sludge Solids Concentration Data Sample Date Total Solids (g/l) Raw Sludge % Volatile Solids Digested Sludge Total Solids (g/l) % Volatile Solids Volatile Solids Reduction (%) November 17, % % 33.6% November 17, % % 55.9% November 24, % % 43.8% December 1, % % 36.7% December 8, % % 35.9% December 15, % % 37.1% December 22, % % 30.2% December 29, % % 33.8% January 5, % % 28.4% January 12, % % 28.6% January 20, % % 33.8% January 26, % % 30.2% February 2, % % 30.4% February 16, % % 33.1% February 23, % % 39.1% March 2, % % 39.1% March 9, % % 29.6% The VSR data are plotted in Figure 3 indicating the 3-week moving average, representing the nominal retention time in the digester. The approach smoothes out weekly variations and provides a clearer depiction of the overall trend in VSR values. Biogas Production Rate. Biogas production was estimated from the VSR values based on the conversion factor described in the Methods section above. The estimated production, based on the minimum and maximum factors of 0.75 and 1.12 m 3 /kg VS destroyed, and a representative value of 0.9 m 3 /kg VS destroyed, are presented in Figure 4. The estimated spike in gas production results from the repairs to the digester mixer in mid- February. No feed sludge was sent to the digester in the days preceding the mixer repair. Once the repair was completed, the sludge that had accumulated in the clarifier was sent to the digester as a large load. The increased sludge loading resulted in a higher than normal gas production rate. Without the apparent spike in gas production for February 23, the daily gas production was estimated to range between 1150 and 2500 m 3 /d, assuming a production factor of 0.9 m 3 /kg VS 3523

8 destroyed. The median value over this period was 1,540 m 3 /d. Insufficient data were available from other times of the year to estimate seasonal variations in digester gas production. The range in values observed in the period of November through March suggests that operational factors (mechanical mixing problems) have an effect on the gas production rate. Volatile Solids Reduction, % 50.0% 45.0% 40.0% 35.0% 30.0% 25.0% 20.0% 15.0% 10.0% 5.0% 0.0% 17/11/ /11/2005 1/12/2005 8/12/ /12/ /12/ /12/2005 5/1/ /1/ /1/ /1/2006 2/2/2006 9/2/ /2/ /2/2006 2/3/2006 9/3/2006 Figure 3. Record of Volatile Solids Reduction in Waterloo Primary Digester, November 2005 March Data from a flow meter installed by RMOW subsequent to this study indicate that the actual biogas production rate are substantially higher than the rates estimated by the standard conversion factors based on volatile solids reduction by a factor of 2 to 3 times. Total Biogas Production, m3/d m3/kg VS destr 0.9 m3/kg VS destr 1.12 m3/kg VS destr 17/11/2005 1/12/ /12/ /12/ /1/ /1/2006 9/2/ /2/2006 9/3/2006 Figure 4. Predicted Biogas Production Rate, Waterloo Primary Digester, November 2005 March

9 Biogas Quality Methane Content and Hydrogen Sulphide. Samples of biogas from the primary digester were submitted for analysis of the major components, between August 2005 and February The results are presented in Table 2. Table 2. Biogas Quality Sampling Date 2005 Methane Biogas analysis, % v/v Carbon Dioxide Oxygen Other Balance H 2 S, ppm v 4-Aug Nov Nov Nov 59 (1) Nov 58 (1) Nov Nov Dec Dec Dec Feb Feb Average (1) Value not included in determination of average due to high contribution of other gases; ( ) not tested The average biogas methane content was estimated from the data with the exception of two samples from November 10, The appearance of a significant component in the category of other gases balance was sufficiently high to suggest possible contamination of the sample. Otherwise, with this exception, the methane content of the digester gas was remarkably consistent (approximately 63 % by volume), yielding a gross heating value of between 635 and 640 BTU/ft 3 ( MJ/m 3 ). The hydrogen sulphide (H 2 S) content of the digester gas was measured, and for the most part, the concentrations were relatively low (approximately 4 ppm v ) for digester gas (WERF, 2006). The samples from February 2006 were higher at 9-10 ppm v. The low H 2 S concentrations likely result from the use of iron salts for phosphorus removal from the Waterloo plant wastewater. The iron ends up in the sludge fed to the digester, where it ties up the sulphide as insoluble ferrous sulphide. 3525

10 Only one previous sampling event (August 2005) was available for comparison with the biogas quality obtained during this evaluation. The limited data suggest that the methane content and H 2 S concentrations are consistent over the course of a year, but additional analyses are recommended to verify this conclusion. Siloxanes. Siloxanes are organo-silicon compounds that are used in cosmetic and hygiene products such as shampoos. Siloxanes pose a problem for internal combustion engines because at the high temperatures they are oxidized to silica, a highly abrasive compound that deposits on the wall and pistons of the combustion chamber. The deposits cause excessive wear and early failure of the engines, resulting in high maintenance costs. Siloxanes can be removed by activated carbon, but treatment for siloxane removal can be a significant operating expense. Concentrations of siloxanes in the digester gas samples collected in the study are presented in Table 3. The predominant siloxane compound present is octamethyl cyclotetrasiloxane, also known as D4, comprising approximately 90 % of the total siloxane concentrations. Decamethyl cyclopentasiloxane (D5) comprises another 5-8 % of the total concentrations. Over the sampling period between August and December of 2005, the total siloxane concentrations have been consistently between 40 to 50 µg/l, which is low compared to observations elsewhere (WERF, 2006). As a result, siloxane removal from the Waterloo digester gas is likely not required, which avoids significant potential operating expense. Table 3. Concentrations of Siloxane Compounds in Waterloo WWTP Digester Gas (µg/l) CAS # COMPOUND Aug 4/05 Nov 10/05 Bag 15 Nov 10/05 Nov 10/05 Bag 13 Bag 25 Dec 8/05 Bag Hexamethyl Disiloxane -L Hexamethyl Cyclotrisiloxane D Octamethyl Trisiloxane - L Octamethyl Cyclotetrasiloxane - D Decamethyl Tetrasiloxane - L <0.010 <0.010 <0.011 < Decamethyl Cyclopentasiloxane - D Dodecamethyl Pentasiloxane - L5 <0.187 <0.136 <0.136 <0.138 < Dodecamethyl Cyclohexasiloxane - D <0.073 Total

11 Identified Direct Drive Applications Existing Plant Application. A major challenge in developing a plan for applying direct drive technology is matching the useable mechanical energy in the biogas with motors in the treatment plant operations. Based on the quantity of biogas produced daily (approximately 1,540 m 3 /d), with a methane content of 63 % by volume, the raw energy value of the digester gas was estimated to range from 26 to 34 MBTU/d (27.4 to 35.9 GJ/d), depending on whether the most conservative factor for biogas production (0.75 m 3 /kg VS destroyed) or a more typical value of 0.91 m 3 /kg VS destroyed was used. Assuming a typical energy conversion factor of 7000 BTU/bHP-hr (Toromont Industries), the available shaft power available from the current biogas production rate and quality ranged from150 HP (112.5 kw) as a conservative estimate, to 200 HP (150 kw) as a typical value. The main opportunities typically considered for direct drive applications are for pumping of raw wastewater or return activated sludge, or for blowers for diffused aeration activated sludge systems. In the Waterloo treatment plant as it currently exists, potential applications are limited; the facility uses Archimedes screw pumps for return activated sludge, and the activated sludge process uses mechanical surface aerators. The surface aerators are mounted on concrete pads over the aeration basins and do not lend themselves to the installation of a direct drive engine. Consequently, the only realistic alternative for applying direct drive technology in the existing plant was for raw wastewater pumping. The motors on each of the four raw wastewater pumps are 150 HP (112.5 kw). Replacement of one of the electric motors on a raw wastewater pump was therefore considered a viable alternative. Proposed Upgraded Plant Application. As noted earlier, the Waterloo treatment plant is in the preliminary design stage for an upgrade that includes conversion of the surface mechanical aerators to fine bubble diffusion and future addition of a biological aerated filter (BAF) process, replacement of chlorine disinfection with ultraviolet (UV) light, and addition of a high-speed centrifuge for residual solids dewatering. Several blowers are required for the diffused aeration system and future BAF process. The blowers for the proposed aeration upgrade are rated at 250 HP (187.5 kw). This slightly exceeds the estimated energy in daily biogas production, based on calculations reported earlier in the paper. The blower sizing in the pre-design stage could be adjusted to accommodate a blower associated with a direct drive engine and compensating with the two other blowers (one inservice and one stand-by). This direct drive application would be more suitable than a centrifuge motor because the multiple blowers for aeration would provide some redundancy if the digester gas supply becomes unavailable for whatever reason. The centrifuge application would offer no such redundancy or flexibility. For the direct drive application at either the existing raw wastewater pumping station or the proposed new blower building, the process design is virtually identical. A generic process schematic for the direct drive engine application is provided in Figure 5. The figure shows that thermal energy is recovered by connecting to the existing plant central hot water loop at the main 3527

12 control/admin building. An outdoor radiator/cooling system is provided to eliminate potential excess waste heat in summer months. Without a detailed evaluation, it is generally the case that a newer installation, such as the blower application is easier to implement and less costly than a retrofit installation, as the raw wastewater pump would be. Selected Direct Drive Applications for Economic Analysis Type of Engine. There are a number of suppliers capable of supplying the direct drive engine technology. For this study only, engines available from Toromont Industries were considered. Based on discussions with the equipment representative, three types of engines were considered appropriate as a direct drive application at the Waterloo WWTP. The two mainframe engines were the 3300 Series Model 3306, and 3400 Series Model 3406, while the third engine was the Olympian Series, which is based on an automotive engine supplied by General Motors. Pertinent information regarding the engines is provided in Table 4. Table 4. Selected Technical Data for Potential Engines Parameter Model 3306 Model 3406 Olympian G125G1 Engine Speed, rpm 1800 based on load 1800 Compression ratio 10.5:1 9.4:1 to 10.3:1 9.1:1 Engine Power rating 100 % load rpm 189 (prime) 210 (standby) Engine Power rating rpm No data 75 % load Engine Power rating 54 % load rpm No data Nominal energy recovery efficiencies reported for the model 3306 engine are provided in Table 5. for different operating loads (Caterpillar, 2005). The thermal efficiency reported is that recovered directly from the engine, but may not be used by the treatment plant. The data indicate that the mechanical energy recovered decreases as the operating load declines. The loss efficiency is shown as being recovered as thermal energy in Table 5. Table 5. Energy Recovery Efficiency for Model 3306 Engine (Caterpillar, 2005) Load (%) Energy Recovery Efficiency (%) Mechanical Thermal Total

13 Figure 5. Schematic Depiction of Direct Drive Application for Waterloo Treatment Plant 3529

14 Emission Factors are provided in Table 6 for the 3306 model engine at different operating loads (Caterpillar, 2005). The emission factors do not vary substantially even when the engine operates at less than 100 % load. The literature received did not have emission factors for the other engines, but it is anticipated that they would be similar. Table 6. Air Pollutant Emission Factors from Model 3306 Engine (Caterpillar, 2005). Load (%) Emission Factor (g/bhp-hr) NO x CO Total Hydrocarbons Non-methane Hydrocarbons The model 3406 engine was selected for consideration in these evaluations. This engine is oversized for the pump application of 150 HP (112.5 kw), operating at about 54 % load and 1200 rpm. For the potential blower application (250 HP or kw), the engine is more closely matched for at 75% loading, but operating at a higher rpm level, with associated higher maintenance costs. One important advantage of selecting the larger engine size was that it could be ramped up to meet higher levels of gas production due to digester optimization and a growing population. Type of Fuel(s). The engines considered for this application were a dual-fueled systems, capable of operating on either digester gas, or natural gas, but not a blend of the two gases. Controls would be supplied with the engine for automatic switchover to natural gas should the digester gas pressure or flow rate fall below a critical set value. A blending system was ruled out for this assessment due to the cost of the computer control required to maintain the correct flow proportions. It was considered that the cost of the computerized automated blending control would run into the tens of thousands of dollars, without adding substantial benefit over the two fuel system. Process Considerations. The quality of the Waterloo plant s digester gas was discussed above. Concentrations of the impurities that are of greatest concern, namely H 2 S and siloxanes, are low. As a result, the need for gas pretreatment equipment to specifically remove these two impurities is not required at this time (Ronson, 2006). Insufficient biogas quality data have been collected to permit a complete evaluation of the potential variation of the gas quality over an extended time period. Additional characterization of the biogas to permit an assessment of seasonal variability is recommended. The digester gas is saturated with moisture as it leaves the digester at a temperature of approximately 35 o C. In passing through the gas collection system piping, heat is lost and moisture in the gas condenses. The conditioning equipment deemed necessary for this application would be a gas chiller that would reduce the temperature of the gas prior to delivery 3530

15 to the engine. By removing the moisture, the heat value of the digester gas would increase. It would also reduce the chance of blockages in the gas delivery piping due to moisture condensation. Another benefit of the chiller is that during the condensation of the moisture, additional H 2 S and siloxanes would be removed. Site Location. The gas chiller would be located in the digester building, close to where the gas is produced. Close proximity to the digester gas source prevents a long run of pipe in which moisture could condense prior to reaching the chiller, reducing its effectiveness. Consideration of the available space in the digester building suggests that installation in the basement of the digester building is the preferred option. Depending on the decision to use the direct drive engine coupled to an existing raw wastewater pump, or to a proposed blower in the plant upgrade, different installations would be required. For the raw wastewater pump, the engine specifications suggested that an engine skid could be installed in the pump building based on the layout of the proposed expanded structure. This assumption was adopted in the economic analysis that follows below. The existing electric motor will be removed for the installation of the direct drive engine, but strengthening or reinforcement of the main floor concrete slab was not deemed necessary. Alternatively, the direct drive engine may be applied to operation of one the proposed blowers to be installed as part of the plant upgrade. The building is in the pre-design stage and can accommodate the inclusion of the direct drive engine with one of the three proposed blowers. In either application, the digester gas would be piped from the chiller in the digester building, by a booster compressor to the application site. The gas piping would follow existing underground service piping, and would be buried sufficiently deep to prevent freezing and frost heave. Hot water from the engine jacket would be used for thermal energy recovery in either application by piping it to a junction with the plant s central hot water loop at the admin/main control building. A thermal control unit would be installed in the admin/control building to accommodate use of the hot water from the direct drive engine. A site plan of the Waterloo WWTP is provided as Figure 6 to show the relative locations of the digester building, where the gas chiller will be located, and the two potential locations where the direct drive engine could be installed. The hot water piping connection from either of the two potential direct drive engine application sites is also indicated in the figure. Economic Analysis Installed Cost of Direct Drive Application Existing Raw Wastewater Pump. Application of a direct drive engine for operation of a raw wastewater pump was costed assuming use of a model 3406 gas engine. The Olympian engine was not considered, as it involves use of a smaller engine that, while less expensive to purchase, needs earlier replacement. The costing details for this application are provided in Table 7. The total construction costs for this scenario were $1.04 Million (Cdn) as of March, The direct drive unit and pump, with 3531

16 associated controls, contribute approximately 21 % of the total project cost, while the mechanical, electrical and instrumentation components contribute another 48 % to the total project costs. Proposed New Blower. If a direct drive blower application in the upgraded plant were to be considered, the estimated total project costs for this scenario were $1.02 Million (Cdn) as of March, 2006 (Table 8). This cost estimate assumed use of a model 3406 engine for the application. Of this total, the direct drive unit and associated controls contributed 21 % of the total project cost for the scenario, while the mechanical, electrical and instrumentation components contributed another 46 % of the total project costs. Although the total project costs were similar, within the individual line costs there were substantial differences. Piping costs to carry the digester gas to an engine in the proposed blower room, and to transport hot water from the engine to the hot water control loop in the admin building, were estimated at $257,000, compared to $144,000 for the raw wastewater pump application. The distances from the anaerobic digesters to the proposed blower room and the water return to the admin building, were much greater than to the existing wastewater pumping building. Conversely, there were no costs for heating ventilation and air conditioning (HVAC) and supporting appurtenances such as louvres, grills and diffusers factored into the proposed blower application because they were already part of the design, whereas they were estimated to cost $117,500 as a retrofit in the wastewater pump application. In the project costs, provision was made for returning hot water from the engine jacket to the central heating loop of the treatment plant for recovery of thermal energy for space heating (included in the piping costs and for the thermal control system). A credit for this heating (thermal energy) in the form of avoided hydrocarbon fuel purchase, could thus be claimed. Economic Assessment of Direct Drive Applications Estimation of Operating and Maintenance Costs. Operating and maintenance costs of the direct drive units are required to estimate the economic return (e.g. simple payback period) for the applications. The assumptions used in Table9 have been included in the estimation of the O&M costs, based on the advice of the direct drive equipment supplier (Ronson, 2006). The engine size selected for this estimation is 150 HP (112.5 kw), based on use of the engine operating at a lower loading that allows the engine to operate at 1200 rpm, thus reducing maintenance costs. The Unit O&M cost provided is for a new greenfield application; the cost is for the labor and replacement or refurbishment cost of the engine and appurtenances. At the Waterloo facility, however, the direct drive would substitute for an existing electric motor, which also has maintenance costs. Accordingly, the greenfield annual O&M costs were adjusted downward by 50 % to reflect a substitution of the electric motor O&M costs for the direct drive engine O&M costs. 3532

17 Table 7. Estimated Total Construction Costs for Direct Drive Pump Application, Waterloo WWTP Div. Description Amount 1 General Requirements $ 8,000 2 Site Work $ 54,500 3 Concrete $ 5,000 5 Metals $ 5,000 9 Finishes $ 1, Equipment Direct Drive Unit $ 117,975 Gas Pretreatment Equipment (Inc. Blower) $ 72,600 Heat exchanger (to boiler line) $ 12,100 Heat Exchanger Recirculation Pump $ 14,520 TOTAL $ 217, Special Construction/Controls & Instrumentation Control System/Control Panels $ 85,000 Gas Alarm System $ 17,000 TOTAL $ 102, Mechanical Piping, Valves and Actuators $ 144,342 Plumbing Specialties & Accessories $ 16,500 Heating and Ventilation and AC $ 44,880 Louvres, Grills and Diffusers $ 72,600 Thermal Control System $ 48,180 Engine Exhaust System $ 38,775 Testing, adjusting and balancing $ 10,725 TOTAL $ 376, Electrical Misc. Wiring $ 4,250 Motor Control Centers: $ 17,000 TOTAL $ 21,250 Sub- total excluding General Contractor's O/H & Profit $ 789,947 Engineering and Construction Admin (10% of Sub-total) 10% $ 78,995 General Contractor's Overhead & Profit 10% 10% $ 78,995 Sub-Total Construction Cost $ 947,936 Contingency (10%) 10% $ 94,794 TOTAL CONSTRUCTION COST(Excluding GST) $ 1,042,730 GST 7% (less 7% rebate) 0% - TOTAL CONSTRUCTION COST(Including GST) $ 1,042,

18 Table 8. Estimated Total Construction Costs for Direct Drive Blower Application, Waterloo WWTP Div. Description Amount 1 General Requirements $ 8,000 2 Site Work $ 54,500 9 Finishes $ 1, Equipment Direct Drive Unit $ 117,975 Gas Pretreatment Equipment (Inc. Blower) $ 72,600 Heat exchanger (to boiler line) $ 12,100 Heat Exchanger Recirculation Pump $ 14,520 TOTAL $ 217, Special Construction/Controls & Instrumentation Control System/Control Panels $ 85,000 Gas Alarm System $ 17,000 TOTAL $ 102, Mechanical Piping, Valves and Actuators $ 256,905 Plumbing Specialties & Accessories $ 25,328 Thermal Control System $ 48,180 Engine Exhaust System $ 4,125 Testing, adjusting and balancing $ 10,725 TOTAL $ 345, Electrical Misc. Wiring $ 4,250 Motor Control Centers: $ 17,000 TOTAL $ 21,250 Sub- total excluding General Contractor's O/H & Profit $ 749,208 Engineering and Construction Admin (10% of Sub-total) 10% $ 74,921 General Contractor's Overhead & Profit 10% 10% $ 74,921 Sub-Total Construction Cost $ 899,049 Contingency (10%) 10% $ 89,905 TOTAL CONSTRUCTION COST(Excluding GST) $ 988,54 GST 7% (less 4% rebate) 3% $ 29, TOTAL CONSTRUCTION COST(Including GST) $ 1,018,

19 Table 9. Assumed Factors for Estimation of Direct Drive Annual O&M Costs Factor Assumed Value Units Operating Load 150 bhp Unit O&M cost $/bhp Operating hours 8760 hours/year Availability 95% Annual O&M cost (greenfield) 33,700 $/yr Annual O&M cost (substitution) 16,850 $/yr Note: costs are expressed in 2006 Canadian dollars The annual O&M costs used in the economic evaluation for direct drive units were therefore estimated at $16,850/yr. Estimation of Avoided Energy Costs. The value of using the energy from digester gas is to avoid the purchase of energy from off-site, whether it is as electricity or a hydrocarbon fuel such as natural gas. For the direct drive applications, the energy in the digester gas is converted to mechanical energy to drive the motors on either a pump or blower. The application therefore avoids the electricity charges from operating motors on the pump or blower selected. The value of the avoided electricity cost was determined based on the price of electricity paid by the Waterloo WWTP. Based on a 2004 value of $0.055/kWh, with an estimated 10 % increase in the price since then, the purchased cost of electricity at the Waterloo plant was estimated as $0.061/kWh. Calculation of the savings due to reduction of purchased electricity is shown in Table10. Table 10. Calculation of Avoided Electricity Costs by Application of Direct Drive Technology Factor Assumed Value Units Operating Load (150) kw (HP) Unit electricity cost $/kwh Operating hours 8760 hours/year Availability 95% Annual Avoided Electricity Costs 56,642 $/yr The cost savings due to avoidance of electricity purchased for either the pump or blower is estimated at $56,600 per year. Recovery of thermal energy also avoids use of hydrocarbon fuel at the boiler, and potentially replaces energy used for space heating. The maximum thermal efficiency of the engine water jacket is approximately 60 % from Table 5. At an assumed energy potential of MBTU/d in the digester gas, the maximum recovered thermal energy would be MBTU/d. Because it is not realistic to expect complete recovery of the thermal energy, a thermal recovery efficiency of 30 % was assumed as a reasonable approximation, resulting in an estimated recovered energy value of MBTU/d from the engine water jacket. This quantity of energy is equivalent to 290 m 3 /d of natural gas. At a price for natural gas of $0.25/m 3, the estimated annual savings from avoided fuel costs were $25,130. The total estimated annual energy savings from avoided 3535

20 use were thus $81,770. Actual annual savings include the annual O&M costs, resulting in an estimated net annual savings of $64,920. Determination of Payback Period. A simple payback period calculation was used for this analysis. The simple payback can be defined as the project capital cost divided by the net annual savings. For the project capital costs, both applications were very similar in magnitude ($1.019 Million for the blower application and $1.043 Million for the pump application), and so the payback periods would be almost identical. As a result, the payback period determined was based on a total capital cost of $1.03 Million. Based on the above discussion, which includes recover of 30% thermal energy, the calculated payback for a direct drive application at the Waterloo WWTP was 15.9 years, which is a long, but not unreasonable time, for the investment required at the current price of electricity. The direct drive scenarios were developed using a larger engine (model 3406) than needed. Use of the larger engine was accepted rather than the more appropriately sized Olympian gas engine due to the accelerated replacement rate of the smaller engine. The decision is consistent with RMOW s Strategic Focus, as discussed earlier.. Sensitivity Analysis of Payback period to Energy Prices. The cost of electricity is currently low at approximately $0.061/kWh. An increase in the price of purchased electricity could have a significant effect of the economic return determined for the direct drive application. To determine the effect of the price of purchased electricity on the payback period, a range of electricity prices from $0.06/kWh to 0.20/kWh was tested against the payback period. The results are shown in Figure 7 for payback periods based on both annual savings and net annual savings. Figure 7 shows that the payback period would decrease rapidly if the price of electricity were to increase. For example, if the direct drive application was to be implemented because the price of electricity was $0.10/kWh (many treatment plants in the U.S. pay this much and more for their electricity), the payback period would decline to 10.1 years based on the net annual savings. The maximum potential thermal energy recovered from a direct drive application is approximately 55 %, per the specifications of the model 3406 gas engine. In real operation, this maximum recovery efficiency is probably not achievable, and a value of 30 % efficiency was assumed for primary costing purposes. A range of thermal recovery efficiencies was evaluated for different prices of electricity. The results are presented in Figure 8 as a family of curves representing different thermal recovery efficiencies. The figure indicates that improved recovery and use of thermal energy from the engine jacket would result in a further decrease in the payback period. The payback period is relatively insensitive to the value of the thermal energy recovered. For example, if less recovered heat is needed in the summer months, the equivalent annual thermal recovery efficiency would be 20 %, leading to an estimated payback period of 18.2 years, rather than the 15.9 years calculated using 30 % thermal recovery efficiency. 3536

21 Payback Period (years) Price of Electricity ($/kwh) Figure 7. Effect of Electricity Price on the Payback Period for a Direct Drive Application at the Waterloo WWTP 30.0 Payback Period (years) Price of Electricity ($/kwh) Thermal recovery 0% Thermal recovery 10% Thermal recovery 20% Thermal recovery 30% Thermal recovery 40% Thermal recovery 50% Figure 8. Effect of Thermal Energy Recovery and Electricity Price on the Payback Period Effect of Biogas Production on Estimation of Payback Period. A study completed for Environment Canada in 2004 (Enviromega Inc., 2004) investigated the economic feasibility of using digester gas at the largest Canadian wastewater treatment plants, including the Waterloo, ON facility. In the Environment Canada report, the estimated payback for a direct drive engine application at the Waterloo plant was 9.0 years, which is a significant discrepancy compared to the value of 15.9 years determined at a current electricity price of $0.061/kWh with 30 % thermal energy recovery. The capital costs for the direct drive installation in both assessments were similar, at $1.13 Million and $1.03 Million for the Environment Canada (Enviromega, Inc., 2004) and the current study, respectively. The main cause of the difference in payback periods had therefore to lie with 3537

22 determination of the net annual savings. In the older Environment Canada (EC) report, the annual O&M costs were higher than those estimated in the current evaluation because the older study assumed that gas pretreatment for removal of hydrogen sulphide and siloxanes was required. Subsequent analysis of the Waterloo digester gas has shown that pretreatment, other than a gas chiller, is not required. Operating and maintenance costs exclusive of gas pretreatment in the EC study were estimated at $33,000/yr, higher than the $16,900/yr estimated in this assessment. Inclusion of gas pretreatment costs for H 2 S and siloxane removal inflated the O&M costs in the EC study to $152,800 (Hydromantis Inc., 2006). The unit prices for purchased energy in the two studies were slightly different, but not excessively. The EC (2004) study used electricity and natural gas unit prices of $0.07/kWh and $0.30/m 3, respectively. In the current study, the corresponding unit prices for electricity and natural gas were $0.061/kWh and $0.25/m 3, respectively. The values used in the current assessment are therefore slightly more conservative than the EC study, which would help to contribute to a longer estimated payback period. The estimated savings resulting from avoidance of purchased electricity and natural charges is one of the principal differences in the two assessments. The EC (2004) assessment reported avoided energy costs (as savings) of $255,000/year (Hydromantis, Inc., 2006), a great deviation from the $81,800/year estimated in this study. Clearly, more credit for energy savings was provided in the Enviromega study. The reason for the high energy savings can be traced to the digester gas production rate calculated in the EC (2004) study. The biogas production rate was a calculation based on the volatile solids reduction, which itself was estimated from the detention time in the digester. The estimated volatile solids reduction (VSR) of 48% contributed to an estimated gas production rate of 2,813 m 3 /d (65 % methane), almost double the rate of 1,540 m 3 /d (63 % methane) used in the current assessment. The current estimated VSR was typically %, well below the value of 48 % used in the EC study. The main difference in the payback period between the two reports was thus the estimate of the daily biogas production. Efforts to improve the reduction of volatile solids should result in more digester gas for energy recovery. The economic return of the direct drive engine application is clearly dependent on the correct estimation of the daily biogas production. With the recent installation of a digester gas flow meter at the Waterloo WWTP to provide an accurate reading of the production rate, estimation of the payback period should be improved significantly. Other Environmental Considerations. Adoption of the direct drive engine technology offers another environmental benefit to Canada. Greater use of digester gas produced on-site will reduce overall greenhouse gas emissions (GHGs). Biogas use will reduce the purchase and consumption of natural gas (a fossil fuel) and electricity (which is partly produced from thermal electricity generating stations) at the Waterloo plant. Such reductions are in support of Canada s efforts to reduce GHGs as required by the Kyoto Protocol. 3538