POWER Proceedings of the ASME 2014 Power Conference POWER2014 July 28-31, 2014, Baltimore, Maryland, USA

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1 Proceedings of the ASME 2014 Power Conference POWER2014 July 28-31, 2014, Baltimore, Maryland, USA POWER WET, DRY, AND HYBRID HEAT REJECTION SYSTEM IMPACTS ON THE ECONOMIC PERFORMANCE OF A THERMOELECTRIC POWER PLANT SUBJECTED TO VARYING DEGREES OF WATER CONSTRAINT Thomas P. Carter, P. E. Johnson Controls, Inc. Waynesboro, PA, USA Sean P. Bushart, Ph. D. Electric Power Research Institute Palo Alto, CA, USA James W. Furlong, P. E. Johnson Controls, Inc. Waynesboro, PA, USA Jessica Shi, Ph. D. Electric Power Research Institute Palo Alto, CA, USA ABSTRACT The reduction of water consumption and use is emerging as a top priority for all types of thermoelectric power plants. In the United States, thermoelectric power production accounts for approximately 41% of freshwater withdrawals [1] and 3% of overall fresh water consumption. [2] On the basis of responses to a 2011 Electric Power Research Institute (EPRI) Request for Information [3], the feasibility study [4,5,6,7] of a Thermosyphon Cooler Hybrid System (TCHS) [8], proposed by Johnson Controls, was funded under EPRI s Technology Innovation (TI) Water-Conservation Program. The objective of this project was to further develop the TCHS design concept for larger scale power plant applications and then perform a thorough technical and economic feasibility evaluation of the TSC Hybrid System and compare it to a variety of other competitive heat rejection systems. The Thermosyphon Cooler Hybrid System reduces power plant cooling tower evaporative water loss by pre-cooling the condenser loop water through a dry cooling process employing an energy efficient, naturally recirculating refrigerant loop. This paper details the results of a detailed feasibility study that was conducted to compare the cost and performance of the TCHS to a number of other potential wet, dry, and hybrid thermoelectric power plant heat rejection systems operating under varying degrees of water constraint. Installed system cost estimates were developed for the base all wet cooling tower systems, TCHS s of varying sizes, air-cooled condenser (ACC) hybrid systems of varying sizes, and all dry ACC systems. Optimized all wet cooling tower and all dry ACC system configurations were developed for five different climatic locations. A comprehensive power plant simulation program that evaluated the fuel and water requirements of the power plants equipped with the different heat rejection systems across the weather conditions associated with all 8,760 hours of a typical meteorological year was developed and then an extensive array of simulations were run each location. The summary data were organized in a separate interactive dynamic system comparison summary program to allow users to gain further insight into the relationships between the various heat rejection systems and the sensitivity of the results to changes in key input assumptions. This paper details the data presented in the interactive dynamic system comparison summary program. This program displays the key metrics of the Annual Net Cost of Power Production, the Annual Net Power Plant Profit, the Annual Operating Profit, and the Internal Rate of Return as a function of the Percent Annual Water Savings Required for the various heat rejection systems at each of the five studied climatic locations studied. Key results and conclusions are presented. INTRODUCTION Thermoelectric power generation based on the Rankine cycle results in significant amounts of low grade thermal energy that must be rejected to the atmosphere. This heat must be rejected in order to condense the primary low pressure steam after it exits the steam turbine. Rejecting this heat directly to a river, lake, or other body of water through once through 1 Copyright 2014 by ASME

2 systems, while energy efficient, is becoming increasingly difficult to implement due to regulatory restrictions associated with the potential adverse impacts on local aquatic ecosystems. As a consequence of the environmental restrictions associated with once through cooling systems, closed loop (all wet) cooling tower systems have become the predominant system of choice for thermoelectric plant heat rejection. In geographies where water is not available in quantities sufficient for evaporative cooling, all dry ACC systems have been deployed. Cooling tower systems represent the most energy efficient and space efficient heat rejection alternative to once through systems. By employing evaporation as the primary means of heat rejection, cooling tower systems can produce much cooler water temperatures than dry heat rejection systems which translate to lower steam condensing temperatures and a more energy efficient Rankine cycle. The primary disadvantage of cooling tower systems is that they consume massive amounts of water to replenish the water consumed by evaporation (for heat rejection) and blowdown (for solids removal). For example to maintain the dissolved solids in the condenser water loop at a level no higher than five times that of the incoming make-up water (Cycles of Concentration (CoC) = 5), the flow rate of the blowdown stream needs to be equal to one fourth (1/(CoC-1)) of the water evaporated. The cooling tower make-up water requirements for a typical 500MW power plant can exceed 2.5 billion gallons per year. Air-cooled condensers directly transfer the heat from the condensing steam to the atmosphere and therefore do not evaporate water nor do they need to have a blowdown stream. However, air cooling is typically much less efficient than evaporative cooling in terms of cost, energy, and space efficiency. This leads to higher parasitic fan energy costs and higher heat rejection equipment first costs. In air cooled systems, the ambient dry bulb (DB) temperature represents the level of the ultimate heat sink. For evaporatively cooled systems, the temperature level of the ultimate heat sink is the ambient wet bulb (WB) temperature. On hot summer days, the ambient DB can be 30F to 40F higher than the ambient WB which increases the temperature and corresponding pressure at which the waste heat can be extracted from the system. As the temperature and corresponding pressure of the condensing steam is increased, both the capacity and the efficiency of the entire power producing cycle are negatively impacted. Unfortunately, these higher DB temperatures typically occur simultaneously with the higher demand for power. Hybrid wet/dry systems, employing both evaporative heat exchanger devices and air-cooled heat rejection devices have also been proposed as a way to reduce the water consumption of the all evaporative (cooling tower only) systems while simultaneously minimizing the performance and first cost penalties associated with the all air-cooled systems. In addition to hybrid systems comprising air-cooled condensers connected in parallel with a steam surface condenser connected to a cooling tower, a new system type of hybrid system, the Thermosyphon Cooler Hybrid System (TCHS) comprised of a dry cooling device, the Thermosyphon Cooler (TSC) located upstream and in series with a cooling tower was also evaluated. One of the objectives of the EPRI Feasibility Study was to develop relative first and annual operating cost data on a 500MW coal fired plant equipped with various types of heat rejection systems and then quantify the plants overall economic performance, in five different climatic locations when faced with varying degrees of water constraint. OVERVIEW OF THE THERMOSYPHON COOLER HYBRID SYSTEM Since the Thermosyphon Cooler Hybrid System (TCHS) is a new system technology, it will be briefly described here. Additional details on the system can be found in the references [ 4,5,6,7,8,9]. The TCHS employs a sensible heat rejection device, a thermosyphon cooler (TSC), upstream and in series with an evaporative heat rejection device, an open cooling tower, to satisfy the annual cooling requirements of a given power plant. By reducing the thermal load on the cooling tower, the TCHS can significantly reduce the annual water consumed for cooling while still maintaining the peak power plant output on the hottest summer days. Figure 1 shows a functional cut away view of a pilot scale thermosyphon cooler. Figure 1 Functional Cut Away View of a Pilot Scale Thermosyphon Cooler Warm cooling water from the steam surface condenser enters the evaporator water box and then travels through the tubes in the shell and tube evaporator. Refrigerant on the shell side of the evaporator boils off and removes heat from the cooling water flowing inside the tubes. The refrigerant vapor, driven by a difference in vapor pressure then travels up to the cooler tubes in the air cooled condenser. The vapor is condensed in the condenser tubes and heat is transferred from the refrigerant to the ambient airstream as air is moved over the finned tube condenser surface by the induced draft fans. The 2 Copyright 2014 by ASME

3 condensed refrigerant liquid, assisted by gravity, creates a liquid head in the supply line to the evaporator. This refrigerant liquid head provides the pressure driving force to overcome the pressure drop in the system and allows the refrigerant in the loop to circulate without the need for a refrigerant pump. A conceptual drawing of a larger, field erected TSC module, comprised of 14 factory assembled condenser modules is shown in Figure 2. The estimated cost and performance of this this module concept was used in the economic analysis. Figure 2 Field Erected Thermosyphon Cooler Module OVERVIEW OF THE HEAT REJECTION SYSTEMS ANALYZED The overall analysis was based on the design and operation of a 500MW coal fired power plant. For each power plant, the annual economic performance of the plant, under varying degrees of water constraint, was evaluated utilizing the following 11 heat rejection systems listed below. 1) The base all wet cooling tower system designed to condense steam at 2.5 in. Hg (108.7 F) at the 1% design WB temperature 2) Hybrid System comprising the full base cooling tower and 8 TSC Modules in series with the full sized cooling tower of System (1) 3) Hybrid System comprising the full base cooling tower and 16 TSC Modules in series with the full sized cooling tower of System (1) 4) Hybrid System comprising the full base cooling tower and 24 TSC Modules in series with the full sized cooling tower of System (1) 5) Hybrid System comprising the full base cooling tower and 32 TSC Modules in series with the full sized cooling tower of System (1) 6) Hybrid System comprising the full base cooling tower and 40 TSC Modules in series with the full sized cooling tower of System (1) 7) A full direct air-cooled steam condenser sized to condense the steam at the lower of 4.0 in Hg. (125.4 F) or a minimum 30 F initial temperature difference (saturated steam condensing temperature inlet DB) at the 2% summer (June - September) DB. 8) Hybrid System comprising the full base cooling tower and a parallel ACC sized at 20% of the full ACC 9) Hybrid System comprising the full base cooling tower and a parallel ACC sized at 40% of the full ACC 10) Hybrid System comprising the full base cooling tower and a parallel ACC sized at 60% of the full ACC 11) Hybrid System comprising the full base cooling tower and a parallel ACC sized at 80% of the full ACC Using a procedure outlined in previous EPRI reports [10, 11] performance and cost models for cooling towers and steam surface condensers along with cost models for water piping, pumps, fan electrical connections, cooling tower basin costs, and water intake structures were developed. A separate optimization program was then developed to select the design cooling tower flow rate, cooling tower approach, cooling tower size, and steam condenser size to yield the lowest evaluated cost of the wet cooling tower heat rejection system for the given design ambient wet bulb temperature and design steam condensing pressure at each climatic location studied. The base all cooling tower system was sized to condense the steam at 2.5 in. Hg (108.7 F) at the 1% design WB associated with each location. For all locations except Yuma, AZ, the full all dry ACC s were sized to condense the steam at 4.0 in. Hg (corresponding to a saturated steam condensing temperature of F) at the 2% summer DB. In the case of Yuma, AZ, the design saturated condensing temperature was raised to F to select the ACC with a minimum 30 F initial temperature difference between the design saturated condensing temperature and the design inlet DB temperature. Specific details of the sizing of the base all wet and all dry systems can be found in the final EPRI project report [5]. CLIMATIC LOCATIONS ANALYZED Annual system analyses were conducted using hourly WB and DB temperatures for a typical meteorological year (TMY). The TMY3 weather data were obtained from a commercially available psychrometric analysis program. [12] Five geographic locations were chosen to represent a range of climatic conditions. These locations and their corresponding wet and dry design points [13] are listed in Table 1. Location 1% Design WB ( F) 2% Summer DB ( F) Yuma, AZ San Luis Obispo, CA Jacksonville, FL Saint Louis, MO Bismarck, ND Table 1 Design WB and DB Temperatures 3 Copyright 2014 by ASME

4 OVERVIEW OF THE GENERAL SYSTEM SCHEMATIC As detailed in a previous ASME IMECE Conference paper [14], a simple flow schematic of the modeled power plant heat rejection system is shown in Figure 3. The main steam loop is shown in black, the steam condenser water loop is shown in blue, and the dry cooler glycol loop is shown in purple. The major pieces of equipment modeled and connected to the steam loop are the steam boiler (1), the steam turbine / generator set (2), the steam surface condenser (3) and the air cooled condenser (ACC) (4). Connected to the condenser water loop are the steam surface condenser (3), the TSC system [which includes a dedicated water pump (5), the water to refrigerant evaporator (6) and the refrigerant to air condenser (7)], the dry cooler system [which includes the dedicated water pump (8), the water to glycol heat exchanger (9), the glycol pump (10) and the glycol to air cooler (11)], the cooling tower (12), a cooling tower bypass valve (13), and the main condenser water pump (14). The specific equipment that s in operation, for a specific simulation run, depends on the selected system being modeled and the specific operating conditions and control strategy being employed. While the simulation program was designed to also analyze a third type of hybrid system incorporating glycol dry coolers with plate frame heat exchangers installed upstream of the cooling tower, this system was not included in the final feasibility study analysis B 3 O I L E R Figure 3 Simplified Flow Schematic for the Modeled Power Plant Heat Rejection System SYSTEM SIMULATION PROGRAM A cooling system simulation model was then developed to enable the various heat rejection systems studied to be evaluated from a performance and economic standpoint. Using the hourly temperature bin data, hourly net power dispatch schedules, hourly water availability schedules, and hourly selling price of energy schedules, performance of each piece of equipment along with production costs and profitability were determined for each of the 8,760 hours of a typical meteorological year for each geographical location studied. Figure 4 shows a screen shot from the dynamic system simulation section of the analysis program. Using the scroll bar on the left, the user can scroll through each of the temperature conditions associated with each hour of the year to look at the modeled performance of each piece of equipment and overall plant capacity and operating economics. 4 Copyright 2014 by ASME

5 Figure 4 Dynamic System Simulation Screen SYSTEM COMPARISON TOOL Within each of the 11 equipment configurations previously identified, multiple simulation runs were conducted to account for variations in allowable water constraints and control set points. This resulted in a total of 55 annual simulations runs being conducted for each of the five locations. Each simulation run resulted in the excess of 1.6 million cells of data and therefore yielded over 440 million cells of data for the entire project. To assist in gaining insight and drawing useful conclusions from this vast amount of data, a dynamic system comparison summary tool was created as shown in Figure 5. Each of the 11 system configurations can be viewed on the basis of the following key economic metrics: The Annual Net Cost of Power Production The Annual Net Profit The Annual Operating Profit The Investment Internal Rate of Return (IRR) The financial metric of interest can be selected by selecting the appropriate plot tab at the bottom of the screen. Each of the metrics is plotted against the value of the % Annual Water Savings Required. The assumptions used to produce the results can then be changed from their initial values by using the slide bar controls on the right hand side of the screen. As the slide values are changed, the data displayed on the plots dynamically changes to reflect the results with the new assumptions. 5 Copyright 2014 by ASME

6 Figure 5 Dynamic System Comparison Summary Tool SYSTEM COMPARISONS Each of the economic metrics varies slightly due to the annual weather profiles associated with each geographic location but in general follow the same trends. For this paper, only the results for the location are shown. However, as will be shown later, the metrics are also significantly impacted by the initial assumptions. In this section, each of the metrics will be described in greater detail. For Figures 6 through 9, the initial assumptions are set as indicated in Figure 5. The first metric is the Annual Net Cost of Power Production as shown in Figure 6. This metric is equal to the sum of the following: The annual cost of fuel The annual burdened cost of water The annualized cost of capital for the heat rejection system The annualized cost of capital for the balance of the plant Plus the annualized cost of lost revenue due to extended construction delays (if any) This sum is then divided by the total annual net MWH s produced to yield the Annual Net Cost of Power Production ($/MWH). Annual Net Cost of Power Production ($/MWH) $63.00 $62.00 $61.00 $60.00 $59.00 $58.00 $57.00 Annual Net Cost of Power Production (Fuel+Water+Annualized Capitization Charge) $/MWH (Water Cost at $1/1000 gal.) Figure 6 Annual Net Cost of Power Production 6 Copyright 2014 by ASME

7 The base all wet cooling tower system is shown by the steeply rising thick blue line. This system has the lowest net cost of power production with a value of $57.19 per MWH assuming there are no limits on the amount of water available. However, as can be seen by its steep upward slope, even very minor constraints on water availability cause rapid increases in the annual net cost of power production. This occurs because the output of the plant is constrained in almost exact proportion to the constraint on water. While fuel and water costs will also decrease with decreased power output, the large annualized cost of the power plant and heat rejection system remains constant and must be allocated to the fewer MWH s of energy produced. The solid color lines represent the cost performance of varying sizes of TSC Hybrid systems added to the base full wet system. TSC Hybrid systems comprised of 8, 16, 24, 32, and 40 TSC modules were modeled. Each TSC Hybrid system s cost performance is plotted against the % annual water savings required. The control strategy used to operate the TCHS changes depending on the level of annual water savings required. Typically, the lowest operating cost is achieved when the system is operated under WECER control [9]. This is followed by operating the fans at full speed. Next is operating at full speed and maximum steam condensing temperature. The final point on the curve at the 100% Annual Water Savings Required on the right hand side of the plot is where the plant is operating with just the TSC unit in operation, assuming no water is available and the cooling tower is completely off line. The plant output is typically curtailed to some degree at this point. This curtailment in plant output and the need to continue to pay the full capitalization rate on the entire plant is the cause of the rapid rise in the annual net cost of power production in this mode of operation. The dotted lines show the operation of the hybrid ACC systems. Four parallel ACC system sizes comprising ACC s sized to approximately 20%, 40%, 60%, and 80% of the full ACC design. Since these are hybrid systems capable of operating at lower condensing pressures during summer peak temperature conditions, the performance is based on using a more efficient, standard lower pressure steam turbine. The three points on each curve to the right of the 0% Savings Required correspond to operating at 100% ACC fan speed controlling to meet the optimum steam condensing pressure, 100% ACC fan controlling to the maximum steam condensing pressure (5 Hg Alarm Point), and finally at the far right of the plot, operating with the ACC only, assuming no water is available for the cooling tower. As with the TSC Hybrid System, when the ACC Hybrid system is operated without the cooling tower in operation to provide 100% water savings, the power plant output is most likely curtailed to some degree. Finally, the gold colored horizontal dashed line represents the full ACC system operating with a modified (higher pressure) turbine and designed to operate at a higher steam condensing pressure. On average, the plant heat rate, at equivalent steam condensing temperatures, when using a modified-conventional turbine instead of a conventional steam turbine is about 1% higher. Looking at the plot in total, a few general observations are worth noting: With no curtailment of water availability and the low burdened cost of water at $1.00 / 1000 gallons, the all wet base cooling tower system provides the lowest net annual cost of power production. The burdened cost of water includes the cost to acquire, deliver, and treat the cooling tower make-up water, and then the proportional cost to treat and dispose of the cooling tower blowdown water. However, even very limited water restrictions on this all wet base system cause the net cost of power production to escalate very rapidly. This is primarily due to the burden of needing to continue to pay the full capitalization costs of the plant but now having to absorb these costs over a curtailed power output. With water curtailments of only 1% to 2%, the smaller hybrid systems (either TCHS or the ACC parallel hybrid options) provide a lower cost of power production. As would be expected, the smaller the dry component of the hybrid system, the lower the net cost of power production. However, the degree of water resiliency increases with larger hybrid systems. For this reason, it s important to understand the degree of water savings that needs to be designed for as this will directly impact the cost of the hybrid system and the resulting Annual Net Cost of Power Production. Unlike the full wet system, whose cost of power production escalates rapidly when faced with even minor water curtailments, or the full ACC system, whose cost of power production is high but independent of water availability, the hybrid systems can operate across a range of water availabilities. In years where water is plentiful, the hybrid plants can operate at their most cost advantaged point and then shift to higher operating cost but still offering higher production capabilities than the all wet plants when water constraints increase. Even though there is a wide variation in water resiliency between the various heat rejection systems, the net impact on the annual net cost of power production, at the 0% water savings required point, still falls within a relatively small range of $57.19/MWH for the base cooling tower system to $58.77/MWH for the all dry system. This represents a tight band of only $0.0016/kWh. The second metric, as shown in Figure 7, is the Annual Net Profit. It is calculated by summing up the total revenue from all the net energy sales and then subtracting the sum of 7 Copyright 2014 by ASME

8 the annual costs for fuel plus water plus the annual capitalization charges for both the heat rejection systems and the balance of the power plant. The operating points initially established for the power plant system modeling in this study have the plants operating on very thin profit margins. Therefore, even relatively minor changes in the cost of power production as shown in Figure 6, lead to very dramatic changes in the annual net profit, especially as the plant is faced with water constraints and the need to operate with reduced levels of cooling tower make-up water. When faced with the possibility of water restraints, hybrid systems provide a degree of insurance of continued profitability across a wider range of water availabilities. Annual Net Profit Millions $13 $11 $9 $7 $5 Annual Net Profit (MWH Sales - (Fuel+Water+Annualized Capitization Charge) ) (Water Cost at $1/1000 gal.) Unlike the calculation for the annual net profit displayed in Figure 7, the annual operating profit shown in Figure 8 does not subtract out the annual capitalization costs. It is interesting to note that even at the low burdened cost of water of $1.00 / 1000 gallons, for this location, all the alternative systems have a lower operating cost, and therefore a higher operating profit than the all wet system. However, this was not the case in all climatic locations studied. The fourth metric, as shown if Figure 9, compares the various heat rejection system alternatives in terms of their investment internal rate of return (IRR) based on a 15 year evaluation compared to the base all wet system. For this calculation, the full capital cost difference between the base all wet cooling tower only system and the hybrid or full ACC system is considered an investment expense at year 0. Then for years 1 through 15, the operating profit cash flow difference between the hybrid systems or the full ACC system and the base all wet system is calculated at varying degrees of required water savings. Excel s IRR function is then used to calculate the IRR. 250% Internal Rate of Return (IRR) - Based on 15 Year Evaluation Relative To The All Wet Cooling Tower Only System (Water Cost at $1/1000 gal.) $3 200% $1 150% -$1 IRR % 100% Figure 7 Annual Net Profit Figure 8 shows how the choice of system and % water savings required impact the annual operating profit. 50% 0% Annual Operating Profit (MWH Sales - (Fuel+Water) ) Annual Operating Profit Millions $137 $136 $135 $134 $133 $132 $131 Figure 8 Annual Operating Profit (Water Cost at $1/1000 gal.) -50% Figure 9 Internal Rate of Return The large increase in the alternative systems increasing IRR is related primarily to their ability to maintain power production in the face of required water savings while the base cooling tower system requires the power plant to proportionally reduce its power output and net profitability with reductions in water availability. For lower amounts of anticipated required water savings, the smaller hybrid systems require much less initial capital investment which results in much higher IRR s. As an example of how changing the base initial assumptions can influence the results, Figures 10 through 13 show how changing the burdened cost of water impacts the net cost of power production. 8 Copyright 2014 by ASME

9 Annual Net Cost of Power Production (Fuel+Water+Annualized Capitization Charge) $/MWH Annual Net Cost of Power Production (Fuel+Water+Annualized Capitization Charge) $/MWH (Water Cost at $1/1000 gal.) (Water Cost at $5/1000 gal.) $63.00 $63.00 $62.00 $62.00 Annual Net Cost of Power Production ($/MWH) $61.00 $60.00 $59.00 Annual Net Cost of Power Production ($/MWH) $61.00 $60.00 $59.00 $58.00 $58.00 $57.00 $57.00 Figure 10 Annual Net Cost of Power Production with the Burdened Cost of Water = $1.00 / 1000 gallons Figure 12 Annual Net Cost of Power Production with the Burdened Cost of Water = $5.00 / 1000 gallons Annual Net Cost of Power Production (Fuel+Water+Annualized Capitization Charge) $/MWH Annual Net Cost of Power Production (Fuel+Water+Annualized Capitization Charge) $/MWH (Water Cost at $3/1000 gal.) (Water Cost at $7/1000 gal.) $63.00 $63.00 $62.00 $62.00 Annual Net Cost of Power Production ($/MWH) $61.00 $60.00 $59.00 Annual Net Cost of Power Production ($/MWH) $61.00 $60.00 $59.00 $58.00 $58.00 $57.00 $57.00 Figure 11 Annual Net Cost of Power Production with the Burdened Cost of Water = $3.00 / 1000 gallons Figure 13 Annual Net Cost of Power Production with the Burdened Cost of Water = $7.00 / 1000 gallons Two quick observations can be made from these four Figures showing the impact of increasing water rates on the annual net cost of power production. First, by looking at Figures 11 and 12, one can see that as the burdened cost of water moves somewhere between $3 to $5 per 1000 gallons, the full ACC system starts to offer the lowest annual net cost of power production. Secondly, by looking at all four of these plots, at burdened water costs again in the $3 to $5 per 1000 gallon range, the differences between the various systems tend to compress. CONCLUSIONS For a number of factors, the reduction of water consumption and use is emerging as a top priority for all types of thermal electric power plants. 9 Copyright 2014 by ASME

10 Detailed installed system costs estimates were developed for the base all wet cooling tower systems, TSC hybrid systems of varying sizes, ACC hybrid systems of varying sizes, and full ACC systems. Optimized all wet and full ACC system configurations were developed for five different climatic locations. A comprehensive power plant simulation program that evaluated the fuel and water requirements of the power plants equipped with the different heat rejection systems across the weather conditions associated with all 8,760 hours of a typical meteorological year was developed and then an extensive array of simulations were run each location. The summary data were organized in a separate interactive dynamic system comparison summary program to allow users to gain further insight into the relationships between the various heat rejection systems and the sensitivity of the results to changes in key input assumptions. Based on the analysis of the extensive volume of plant simulation data over a wide range of climatic conditions we have reached the following general conclusions: 1) The capacity and profitability of water cooled power generating stations are dramatically impacted by even minor constraints in water availability. 2) Both TSC Hybrid systems and ACC Hybrid systems offer a cost effective way to reduce water consumption and insure against even minor constraints (<5%) on water availability even at fully burdened water costs of just $1.00 / 1000 gallons. 3) At water costs between $3 to $5 per 1000 gallons, hybrid and all dry ACC systems become more cost competitive than all wet systems, even with no water constraints. 4) Controlling to higher steam condensing system pressures is a very cost effective way to increase the water savings capability of a hybrid equipped heat rejection system. REFERENCES [1] Kenny, J.F., Barber, N.L., Hutson, S.S., Linsey, K.S., Lovelace, J.K., and Maupin, M.A., 2009, Estimated use of water in the United States in 2005: U.S. Geological Survey Circular 1344, 52 p. [2] U.S. Department of Energy. National Renewable Energy Laboratory. Consumptive Water Use for U.S. Power Production. NREL/TP December Springfield, VA. [3] Development of Innovative Technologies for Cooling, Waste Heat Utilization, Water Treatment, and Water Resource Expansion to Reduce Power Sector Water Use. EPRI, Palo Alto, CA: yinnovations/rfi-waterusereduction.pdf. [4] Program on Technology Innovation: Feasibility of Using a Thermosyphon Cooler Hybrid System to Reduce Cooling Tower Water Consumption. EPRI, Palo Alto, CA; [5] Program on Technology Innovation: Feasibility of Using a Thermosyphon Cooler Hybrid System to Reduce Cooling Tower Water Consumption. (Final Report Pending Publication) EPRI, Palo Alto, CA; [6] Technology Insights: Thermosyphon Cooler Hybrid System For Water Savings in Power Plants. EPRI, Palo Alto, CA; [7] Technology Pipeline: Thermosyphon Cooler System For Lower-Cost Hybrid Plant Cooling And Drought Resiliency. EPRI, Palo Alto, CA; [8] U.S. Department of Commerce. Patent and Trademark Office. Thermosyphon Coolers For Cooling Systems With Cooling-towers, United States Patent Application Publication, Pub. No. US2011/ A1. Washington, D.C., Dec. 1, [9] Carter, T.P., Furlong, J.W., Bushart, S.P., and Shi, J., Thermosyphon Cooler Hybrid System For Water Saving Power Plant Heat Rejection. Proceedings of the ASME 2013 Power Conference. Boston, MA 2013 [10] Comparison of Alternate Cooling Technologies for U.S. Power Plants: Economic, Environmental, and Other Tradeoffs. EPRI, Palo Alto, CA: [11] Economic Evaluation of Alternative Cooling Technologies. EPRI, Palo Alto, CA: [12] Psychrometric Analysis. CD Version Hands Down Software, [13] American Society of Heating, Refrigerating and Air- Conditioning Engineers, Inc., Weather Data Viewer Version 4.0. Atlanta, GA, [14] Carter, T.P., Furlong, J.W., Bushart, S.P., and Shi, J., Power Plant Heat Rejection System Modeling And Comparison. Proceedings of the ASME 2013 International Mechanical Engineering Congress & Exposition, San Diego, CA Copyright 2014 by ASME