Water Use for Electric Power Generation

Transcription

1 Water Use for Electric Power Generation

2

3 Water Use for Electric Power Generation Final Report, February 2008 EPRI Project Manager R. Goldstein ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California PO Box 10412, Palo Alto, California USA

4 DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM: (A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY'S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER'S CIRCUMSTANCE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT. ORGANIZATION(S) THAT PREPARED THIS DOCUMENT Maulbetsch Consulting NOTE For further information about EPRI, call the EPRI Customer Assistance Center at or askepri@epri.com. Electric Power Research Institute, EPRI, and TOGETHER SHAPING THE FUTURE OF ELECTRICITY are registered service marks of the Electric Power Research Institute, Inc. Copyright 2008 Electric Power Research Institute, Inc. All rights reserved.

5 CITATIONS This report was prepared by Maulbetsch Consulting 770 Menlo Avenue, Suite 211 Menlo Park, CA Principal Investigators J. Maulbetsch B. Barker This report describes research sponsored by the Electric Power Research Institute (EPRI). The report is a corporate document that should be cited in the literature in the following manner: Water Use for Electric Power Generation. EPRI, Palo Alto, CA: iii

6

7 REPORT SUMMARY This report analyzes how thermoelectric plants use water and the strengths, limitations, and costs of available technologies for increasing water use efficiency (gal/mwh). The report will be of value to power company strategic planners, environmental managers, and generation managers as well as regulators, water resource managers, and environmentalists. Background Population and economic growth increase use of fresh water resources. Demand for electricity also is increasing. Thermoelectric generation already accounts for approximately 40% of national freshwater withdrawals at a time when ecological concerns limit freshwater availability for population, power generation, industrial, and agricultural uses and considerable uncertainty exists about how future climate variability and change may alter water supplies. A consequence of all these factors is increasing pressure on the electric power industry to consume less water and use it more efficiently. Objective To provide an overview of the major uses of water for power plant operations and a basic introduction to water conservation options generally available today. Approach The project team began with a quantitative overview of water use by application and by type of plant fossil and nuclear steam-electric plants, gas-fired turbine plants, and renewable plants. The body of their research analyzes alternative water conservation management options available today. These include in-plant recycling and reuse of water to minimize water intake and discharge; various dry technologies for cooling, scrubbing, and ash handling, as well as wet/dry hybrid technologies and the comparative costs; alternative sources of water for the future, including municipal wastewater, brackish ground water, and water produced during oil and gas operations; and basic economics of water including cost of acquisition, delivery, treatment, and discharge. In an effort to synthesize key elements in the report for readers, the team provided six hypothetical case studies of different types of power plants operating under different conditions in the United States. v

8 Results Plant type is the dominant factor in determining water requirements. In plants with water-cooled condensers, cooling will dominate the plants water needs. Approaches to increasing water use efficiency or decreasing water use in power generation include dry/hybrid cooling; nontraditional water sources; recycle and reuse of water within plants; combined cycle, photovoltaic, wind, and gas turbine generation; dry scrubbing; and dry ash handling. Relative advantages, limitations, and costs of different water conserving technologies are highly site dependent. EPRI Perspective Growing societal demands on U.S. water resources will result in pressure on the electric power industry to increase its water use efficiency and reduce its total water use. The power industry is already engaged in conserving water on many fronts developing dry cooling, dry scrubbing, and dry ash handling technologies; creating new and innovative recycling systems for treating and reusing water for various plant functions; and pioneering ways to make use of abundant and untapped supplies of municipal waste water and other nontraditional sources. Through scientific/technical research, there exist opportunities for the power industry to develop improved and less costly technologies and procedures for conserving water. Keywords Cooling Water Sustainability Generation Conservation Water use efficiency vi

9 CONTENTS 1 INTRODUCTION SCOPE AND OBJECTIVES OVERVIEW OF WATER REQUIREMENTS Variations by Plant Types Other Effects on Water Requirements Site Climate Regulations Source Water Quality CONVENTIONAL WET COOLING WATER RECOVERY, RECYCLING AND REUSE San Juan Generating Station Zero-Liquid Discharge (ZLD) Water Recycle Treatment Arizona Public Service Redhawk Power Station: At the Leading Edge of ZLD (Yarbrough 2007) New Options for Further Water Recovery DRY COOLING TECHNOLOGY Dry Cooling Technology Hybrid Wet/Dry Systems Comparative Costs Dry Scrubbing Dry Ash Handling Dry Technologies and ZLD ALTERNATIVES TO FRESH WATER SUPPLY Municipal Waste Water vii

10 Brackish Ground Water Seawater Produced Water THE ECONOMICS OF WATER Cost of Water Acquisition Costs Delivery Costs Treatment Costs Total Water Costs CASE STUDIES OF DIFFERENT PLANTS OPERATING IN VARIOUS REGIONS OF THE U.S CONCLUSIONS REFERENCES viii

11 LIST OF FIGURES Figure 3-1a Water Requirements by Use and Type of Plant (using closed cycle wet cooling where a steam turbine is present) Figure 3-1b Water Requirements by Use and Type of Plant (excluding cooling and gas turbine steam/water injection) Figure 3-2 Dry and Wet Bulb Temperatures Exceeded 1% of the Year (~90 hours) Figure 3-3 Makeup Water As a Function of Cycles of Concentration Figure 4-1 Once Through Cooling Figure 4-2 Wet Cooling Tower Figure 5-1 San Juan Generating Station Water Treatment Figure 5-2 Reverse Osmosis System Schematic (from FEMP [Federal Energy Management Program] 2004) Figure 5-3 Vapor Compression Falling Film Evaporator Schematic (from Heins 2005) Figure 5-4 Crystallizer Schematic (from Heins 2005) Figure 5-5 Redhawk ZLD Facility 9 (From Yarbrough 2007) Figure 5-6 Redhawk Water Balance (courtesy Power Magazine [Yarbrough 2006]) Figure 5-7 ZLD Cake Ready for Disposal (from Yarbrough 2007) Figure 5-8 ZLD Cake Disposal Containers (from Yarbrough 2007) Figure 5-9 Water Recovery From the Plume (courtesy: SPX Marley) Figure 6-1 Air Cooled Condenser Figure 6-2 Dry-cooled Plant on Mystic River North of Boston, MA Figure 6-3 Hybrid Cooling System Figure 6-4 Comparative Costs of Wet and Dry Cooling Systems Figure 6-5 Effect of Water Cost on Cooling System Cost Comparisons Figure 7-1 Projected U.S. Non-agricultural Water Consumption (Source: DOE) ix

12

13 LIST OF TABLES Table 3-1 Estimated Plant Cooling Water Withdrawals Table 3-2a Plant Process Water Requirements Table 3-2b Plant Process Water Requirements Table 5-1 Water Quality by Use Table 5-2 Water Flow at San Juan Table 8-1 Water Acquisition Costs Table 8-2 Total Water Costs xi

14

15 1 INTRODUCTION An abundant supply of good quality water is of great benefit to the operations and economics of power production. Historically, proximity to such a water source, as well as to fuel, transmission access and load center, has been a primary requirement for siting power plants. However, in recent times water has become a more contentious siting issue as population and economic growth have put increasing pressure on water resources. Power plants must compete with the demands of municipalities, agriculture, and industry for surface and groundwater supplies, and they face the lingering perception by officials that water is simply too precious to evaporate in a power plant. Water costs are rising, and the long-term trend is for increasing environmental restrictions on the use and discharge of water by all users. Far and away the largest use of water by power plants is for cooling; that is, for condensing the steam flowing out of the turbine generator, and using the water to carry the rejected heat into the atmosphere. Other major uses of water in the power plant include flue-gas scrubbing, ash sluicing, boiler make up, gas turbine inlet cooling, dust control, and hotel/housekeeping activities. Power plants currently account for about 3% of the freshwater consumed in the U.S., in contrast with agriculture, which consumes about 40%. (USGS 1998) However, because about half of the power plants in the U.S. still use once-through cooling technology, power plants account for about 40% of U.S. freshwater withdrawals, most of which is returned back to its original source - - a river, lake, or impoundment -- about 20 degrees (F) warmer. Concerns over thermal pollution and the entrainment of fish and other marine life curtailed this approach many years ago. Virtually all new plants use closed-cycle cooling, which reduces water withdrawal requirements to just a fraction (2-5%) of the once-through approach. In the future, the competition for water will require electricity generators to go further to conserve fresh water supplies. There are a number of avenues. One is to find innovative ways to recycle water within the power plant. Another is to use water-saving or dry technologies wherever possible as for cooling, scrubbing and ash handling. A third is to use waste water supplies from municipalities, agricultural runoff, brackish ground water, or seawater. All of these approaches alter the economics of power generation. Recycling often requires capital equipment and the cost of chemicals to treat and upgrade the water quality. Dry technologies require little or no water, but are usually more capital intensive, and typically exact a penalty in terms of plant performance. Finally wastewater must be acquired, delivered and treated before it can be used in the power plant. All of these water-conserving options raise the cost of power generation. 1-1

16

17 2 SCOPE AND OBJECTIVES This document provides an overview of the major uses of water for power plant operations, and a basic introduction to the different water conservation options generally available today. It also outlines the distinctions between different types of plants, and summarizes the economic implications of different designs. It is intended for educational purposes, and assumes the reader to be broadly knowledgeable about power generation, but not an expert in power plant water requirements or water management systems. The report draws critical distinctions between the terms withdrawal and consumption of water. Withdrawal is the water has been brought inside the plant perimeter for use, but does not indicate what happens to it after that; it could be consumed or returned to its source. Consumption is the term used for the water that has been dissipated or used up, leaving the plant boundary through evaporation into the atmosphere or as moisture in disposed solid wastes. The report begins with a quantitative overview of water use by application and by type of plant fossil and nuclear steam-electric plants, gas-fired turbine plants, and renewable plants to show the dominant role that cooling plays in water usage. The body of the report describes the basics of conventional wet cooling, and the alternative water management options available today. These include In-plant recycling and reuse of water to minimize the water intake and discharge. Various dry technologies for cooling, scrubbing, and ash handling, as well as wet/dry hybrid technologies and the comparative costs. Alternative sources of water for the future, including municipal wastewater, brackish ground water, and water produced during oil and gas operations. The basic economics of water including the cost of acquisition, delivery, treatment, and discharge. In an effort to synthesize the key elements in the report for the reader, the document ends with six hypothetical case studies of different types of power plants operating under different conditions in the U.S. These variable conditions include local climate, water availability and regulation related to intake and discharge. 2-1

18 Scope and Objectives A simple-cycle, gas-fired unit operating in a peaking mode A large combined cycle plant operating at 75% capacity A large base-load, coal-fired power plant A large nuclear PWR operating at 95% capacity A large IGCC base-load plant operating at 85% capacity A small solar-thermal power plant operating at 25% capacity. 2-2

19 3 OVERVIEW OF WATER REQUIREMENTS Water requirements for electric power generation are highly variable. They are influenced by a number of factors, but most significantly by the type of plant, fuel, and choice of the power plant cooling system. Secondary influences are the local climate, the source of water, the environmental regulations to which the plant is subject, and the choice of water management system to be employed. Table 3-1 gives the estimated water requirements for cooling (in gallons/mwh) for different types of plants, using different fuels and condenser cooling systems. Closed cycle wet cooling for any of the steam-based, Rankine-cycle plants whether coal, gas, oil or nuclear -- withdraws just a fraction (e.g. 2%) of the water required for once-through cooling, even though it might consume more water. (EPRI 2004) Tables 3-2a and 3-2b show the water requirements for other critical functions in the plant, including environmental control, ash handling, turbine performance enhancement, fuel processing, boiler/reactor make up and hotel load. (Water General Corporation 1987; EPRI 1983: DePaepe 2001) Hotel water use includes cleaning, drinking and sanitation needs. In sum, these requirements are small compared with cooling. Table 3-1 Estimated Plant Cooling Water Withdrawals 3-1

20 Overview of Water Requirements Table 3-2a Plant Process Water Requirements Table 3-2b Plant Process Water Requirements 3-2

21 Overview of Water Requirements Variations by Plant Types As illustrated in Figure 3-1a, plant type is a important factor in the amount of water required. By far the dominant water requirement is for cooling. Rankine-cycle steam plants, whether fossilfired or nuclear, require condenser cooling to condense the steam coming from the steam turbine prior to pumping the condensed water back to the boiler or reactor. Of the fossil-fueled plants, coal units have the highest heat rates (or lowest efficiencies), as well as the highest requirements for water over and above that for condenser cooling, due to the in-plant power and water requirements for coal pulverization, flue gas scrubbing, and ash handling. Because the cooling water requirement is so large compared to other uses at most plants, the requirements for all other uses are obscured in Figure 3-1a. Figure 3-1b displays the non-cooling requirements on a scale that makes some comparison among plant types and water uses possible. Nuclear plants typically have somewhat lower efficiencies than fossil plants due to lower turbine steam pressures and temperatures, and have higher condenser heat rejection loads to deal with, since there is no heat escaping up the stack as there is in fossil plants. For simple-cycle gas turbine plants, the condenser cooling load is zero. In the case of combinedcycle plants, only about 1/3 to 1/2 of the plant output is generated with the steam portion of the power cycle; and the unit s condenser cooling requirements correspond directly to the output of the steam cycle. However, all combustion turbine plants have some amount of additional water requirements, including gas turbine inlet air cooling, steam or water injection in the gas turbine compressor inlet, and, in the case of Integrated-Gasification, Combined-Cycle (IGCC) plants, water for the gasification process. 3-3

22 Overview of Water Requirements Figure 3-1a Water Requirements by Use and Type of Plant (using closed cycle wet cooling where a steam turbine is present) Figure 3-1b Water Requirements by Use and Type of Plant (excluding cooling and gas turbine steam/water injection) 3-4

23 Overview of Water Requirements Similar to gas turbines, some renewable plant types such as solar-photovoltaic and wind, have no steam condenser cooling requirements. However, solar-thermal and biofuels plants typically utilize Rankine steam cycles similar to fossil-plants, likely with somewhat higher heat rates due to lower turbine inlet conditions. All solar plants require some water for collector surface cleaning and all plants have need for hotel water for cleaning, drinking and sanitary use. Hotel use varies somewhat with the size of the plant staff, which can vary a great deal with plant type. In the case of biofuels, the amount of water required to grow the crop can be considerable but is highly variable. It has been ignored in these comparisons, in part because the amount is highly uncertain, and in part, because this affords a consistent treatment with the other plants for which some water is required for fuels, notably resource extraction (mining, drilling, etc.). Fuel-related water requirements have not been included in the totals. Other Effects on Water Requirements Other important, but secondary, influences on plant water requirements are: Site climate Regulations Source water In-plant water management systems Site Climate Local climate affects the amount of water evaporated for a given cooling load. In warm humid environments, cooling towers must be larger and will use more fan power than would be the case at drier sites in order to reject the same heat load while achieving the same cold water temperature. Under humid conditions, the fraction of heat transferred to the atmosphere by evaporation is less than it would be in a hot, dry climate perhaps as low as 70-75%, as opposed to 85-90% for drier climates. (Hensley 2006) This can result in a difference in the water consumption rate of gallons/mwh between the two sites. Cooling towers reject heat to the environment both by evaporation (latent heat transfer) and by convection (sensible heat transfer) from the hot water to the cooler air. The portion of the heat load transferred by evaporation and, hence, the water consumption rate of a cooling tower for a fixed heat load is greater (~85 to 90%) in dry conditions than in humid conditions (~70 to 75%). Therefore, cooling water requirements for similar power plants can differ substantially from site to site. This is illustrated by reference to Figure 3-2, which displays both the 1% ambient temperatures and the 1% wet bulb temperatures for ten cities. As an example, the 1% ambient temperatures in New York and Denver are fairly close together (~ 88ºF for Denver; ~91 ºF for New York) while the 1% wet bulb temperatures are quite different (~ 63ºF for Denver; ~77 ºF for New York). (EWD 2000) The higher latent-to-sensible heat transfer ratio in the dry Denver area compared to the humid New York area could result in a higher evaporation rate of 60 to 120 gpm/mwh. 3-5

24 Overview of Water Requirements C ity-to-city Variation in 1% Ambient Temperature Tempeature, F Atlan ta Boston Ch icago Denve r Las Vegas Miami New York San Francisco Seattle St.Louis City-to-city Variation in 1% Wet Bulb Temperature 1% Wet Bulb. F Atlanta Boston Chicago Denver Las Vegas Miami New York San Francisco Seattle St.Louis Figure 3-2 Dry and Wet Bulb Temperatures Exceeded 1% of the Year (~90 hours) For combined cycle plants, the effect of climate can be even greater. On very hot days, the output of the combustion turbines is reduced since the lower density of the inlet ambient air results in a lower mass flow through the gas turbines and a correspondingly lower power output. This can be compensated for in a variety of ways. The two most common ways are cooling of the turbine inlet air by cooling the inlet air either by injecting some water in the inlet stream or by using mechanical chillers, which in turn may have wet cooled condensers. During hot periods when the combustion turbine output falls off, many combined cycle plants are also equipped with duct burners to augment the turbine exhaust flow going to the steam turbine through the heat-recovery steam generator (HRSG). This shifts the plant s output proportionately from the combustion turbine side to the steam side with a correspondingly higher steam condenser heat rejection requirement. While these conditions may exist for only a small period of the year when ambient temperatures are high, the water use during those periods is increased. 3-6

25 Overview of Water Requirements If the steam side output increases from 1/3 to 1/2 of the total plant output, the cooling tower water requirements will increase by 50%, or by gpm/mwh. The water consumption for gas turbine inlet cooling can vary from zero, in the case of air cooled chillers, to 7.5 gallons per MWh for inlet sprays, depending on the amount of cooling desired. Regulations Water use and conservation at power plants are becoming increasingly important and contentious siting issues. Particularly in the West and Southwest, where drought or population growth leads to present or projected shortages of water for agricultural, residential, commercial and industrial use or for in-stream flow maintenance, opposition to power plant siting frequently focuses on the issue of water use and can lead to lengthy hearings and delays in or denial of project approval. Moreover, the issue is not confined to water-short regions. There are many instances of the proposed or actual use of dry cooling in regions where water is plentiful or in the vicinity of large water bodies. These have been driven by regulatory concerns other than water conservation such as the desire to reduce impacts to aquatic organisms, eliminate any discharge steams or avoid problems with visible plumes or drift from wet cooling towers. In some instances, where time-to-market has been an important economic consideration, project developers have chosen to use dry cooling or other water conservation technologies as a way to reduce the length of the licensing process and to bring the plant on-line more rapidly. An obvious example has been the regulations governing intake and discharge of cooling water under Sections 316(a) (discharge) and 316(b) (intake) of the Clean Water Act. These have in nearly all cases led to the use of closed-cycle cooling (usually wet cooling towers) rather than once-through cooling at new plants. The situation for existing plants is in flux at the time of this writing (July, 2007) with the recent remand of EPA s 316 (b) Phase II rules for existing plants. While retrofit of closed-cycle cooling has not been mandated as yet, there has been increasing pressure by several state agencies in that direction. As can be seen in Table 3-1, the effect of using closed cycle cooling rather than once-through cooling is a huge reduction in water withdrawn by the plant. There may, however, be some increase in water consumed by the plant in the cooling process since, as discussed above, the bulk of the cooling achieved with wet cooling towers derives from the evaporation of a portion of the circulating water. In a few instances, the intake regulations have been interpreted as requiring dry cooling in place of wet cooling for new plants, to gain further reduction in the plant s water requirements. To date this has been rare. The other category of regulations affecting water use in plants is the imposition of zero liquid discharge (ZLD) limitations, which are common in the Colorado River areas. Under ZLD limitations, the only water leaving the plant can be water vapor through the cooling tower plume, or up the stack, or from an evaporation pond, or moisture in disposed solids such as scrubber sludge or ash. In areas where evaporation ponds are not possible (as in net rainfall regions) or uneconomic, the alternative is the use of power consuming mechanical/thermal equipment such as evaporator-crystallizers. In either case, economics dictates that the flow of non-recyclable liquid to the ultimate disposal process should be minimized. ZLD encourages maximum in-plant recycle/reuse or the choice of dry processes for cooling, ash handling or stack gas cleaning wherever possible. 3-7

26 Overview of Water Requirements Finally, air quality regulations can sometimes govern the choice of water using systems. For example, drift emissions from cooling towers are classified by EPA as PM 10. (USEPA 1995) PM 10 often sets the maximum cycles of concentration in the cooling tower. In some nonattainment areas, the purchase of PM 10 offsets may be required. If this is not possible, the use of dry cooling may be the only option. On the other hand, it is usually the case that dry cooling imposes heat rate and capacity penalties on the plant, at least during the hotter periods of the year. To the extent that the required generation must be made up by burning additional fuel or supplied from other, perhaps less efficient plants, the total emissions of air pollutants, including carbon dioxide may increase, resulting in pressures to stay with wet cooling rather than dry. Source Water Quality The use of lower quality source water inevitably increases the total amount of water that must be taken into the plant. This results from the need to treat the water prior to use, either before it reaches the plant or inside the plant boundaries. All treatment processes must generate a reject brine stream in addition to the product water; this typically increases the make-up requirements by 25-35%. For most uses, this is not a major issue. However, for cooling towers, the use of high salinity make-up, such as seawater or saline groundwater, can dramatically increase the make-up requirements. Cooling tower blowdown is required for all towers to maintain circulating water quality within acceptable limits. For good quality make-up, towers are typically run between 5-10 cycles of concentration (cycle of concentration is the ratio of the concentration of the blowdown to that of the make up water). Higher cycles might be possible, but water savings reach a point of diminishing returns at cycles above 10. Seawater make-up, however, limits the cycles of concentration to 1.4 to 1.6. (Maulbetsch in press) As shown in Figure 3-3, the make-up requirements increase dramatically at these low cycles of concentration. Cooling Tower Make-up (for evaporation rate of 600 gallons/mwh) 2,000 1,800 h Make-up requirement, gal/mw 1,600 1,400 1,200 1, Cycles of concentration 10 Figure 3-3 Makeup Water As a Function of Cycles of Concentration 3-8

27 4 CONVENTIONAL WET COOLING Conventional wet cooling by means of a cooling tower began to supplant once-through cooling in the 1970s following the strictures of the Clean Water Act. Once-through cooling, as shown in Figure 4-1 below, takes water directly from a source river, lake, ocean and uses it to condense the steam, and then returns the water to the original source roughly 20 degrees F warmer. Roughly one-third of U.S. thermoelectric capacity in the U.S. still uses once-through cooling. Conventional wet cooling reduces the environmental problems of entrainment and impingement during intake, and the problems of thermal pollution during discharge. The principal components of a conventional wet cooling system are the surface condenser, the wet tower, and the circulating water system that moves water from the condenser to the wet tower. The turbine exhaust steam flows over the outside of the surface condenser tubes, where it gives up its heat to the water inside the closed circulating water system, and in the process, condenses to water that is returned to the boiler. Figure 4-1 Once Through Cooling 4-1

28 Conventional Wet Cooling The warm water leaving the condenser is then pumped to the top of the cooling tower, shown schematically in Figure 4-2, where it flows downward through the packing or fill, which is designed to break the water up into small droplets or spread it out into a thin film to maximize the surface area exposed to the cooling air. (Hensley 2006) Air is drawn through the tower by large fans. The circulating water is cooled by a combination of evaporation and convective heat exchange. The warm moist plume rises from the tower, and the cooled water is collected at the bottom of the tower and pumped back to the condenser to pick up more heat in a continuous cycle. Evaporation typically carries off 85-90% of the heat, and convection the remaining 10-15%. Roughly 2% of the cooling water is lost through evaporation, requiring continuous additions of makeup water. Since evaporation results in the buildup of dissolved solids in the circulating water, a portion of the water is discharged as blowdown to limit the concentration of these solids and to prevent scaling and corrosion that can interfere with the transfer of heat from the condenser to the cooling water. Figure 4-2 Wet Cooling Tower 4-2

29 Conventional Wet Cooling There are several ways to design the wet cooling tower. With mechanical draft towers the air is drawn through the tower by large fans. Alternatively, natural draft towers draw air through the tower by a chimney affect. Natural draft towers are large hyperbolic structures that are costly to construct, but have the advantage of lower operating and maintenance costs. Their use in the U.S. has been limited to the very large coal and nuclear units. Mechanical draft cooling towers come in two basic types depending on how the airflow is designed. If the air is brought in from the side, running perpendicular to the falling water, it is called a crossflow design, as shown in Figure 4-2. If the air is brought in from the bottom and drawn upward in opposition to the falling water, the design is called counterflow. The advantage of crossflow is that it minimizes operating and maintenance costs. The advantage of counterflow is that it minimizes space requirements (footprint) and works better where icing is a critical issue. With proper application, both configurations are cost effective. Mechanical draft towers are typically arranged as cells in a larger configuration. Most often these cells are arrayed in-line to form a rectangular unit. Although drift is not a major problem from the standpoint of water loss, it can be a critical factor affecting local residents or business, and equipment in the immediate vicinity. Drift can lead to wet or icy roads in some regions, corrosion of metal structures that are downwind, and switchyard insulator flashover. Drift eliminator systems have been able to reduce drift as a percent of water flow from 0.008% to %, so that only the smallest droplets pass through. EPA regulates the matter contained in the droplets as particulates under PM 10 rules. Visible plumes of condensed water vapor can occur particularly in humid cold weather. If the plumes stay at ground level, they can create visibility problems, and, if they affect highways or airport runways, they can create safety hazards. In such situations, plume abatement technology may be required. 4-3

30

31 5 WATER RECOVERY, RECYCLING AND REUSE The ongoing drive to conserve water has been extended to a wide variety of innovative processes to recover, recycle and reuse the water already in use in the power plant. This calls for treating the water to isolate and remove the contaminants that invariably build up as the plant systems and subsystems perform their functions, and to send the treated water back into use. The goal is to reduce the amount of fresh water required for makeup at the front end, and to reach a point of minimized water use or even zero discharge at the back end. Different uses in the plant have different requirements for the purity of the water. The requirements for boiler make-up are higher, for example, than those for cooling, and those for cooling have higher requirements than those for the limestone slurry used for scrubbing SO x out of the flue gas. In some situations, blowdown from one system can be used directly as make-up to another system. In other cases, blowdown can be treated and then recycled to the original process, or sent to another process. In general, if water is to be treated for reuse, it is preferable to treat it completely for the highest possible level use, and then let the water cascade down to lower uses, rather than clean it up just a little bit for an intended intermediate use. This is a rule of thumb, but not absolute; reuse strategy is quite plant specific. Table 5-1 below shows the uses of water in terms of descending water quality requirements. Table 5-1 Water Quality by Use Water Use Boiler/reactor feedwater Gas turbine inlet cooling Hotel, housekeeping and potable water Cooling tower Ash sluicing Limestone slurry for FGD Water Quality Requirements Highest quality High quality Medium quality Medium quality Low quality Low quality 5-1

32 Water Recovery, Recycling and Reuse Blowdown from the boiler and cooling tower, along with waste slurry from the FGD operation and the sluicing of ash, are typically sent to the disposal ponds, although blowdown from the boiler is sometimes sent to the gas turbine. The solids settle to the bottom, while the clear water at the top (the supernatant) is treated and recycled back into the plant. In many plants, the ash or sludge is actively dewatered through a filtering process (e.g. drum filter), rather than waiting for the solids to settle out by gravity alone. Eventually, what is left is a concentrated residual of wastewater. This waste can be sent to an evaporation pond on site for further concentration/drying into a solid, or actively treated to a solid state in an evaporator/crystallizer. The residue is then disposed of as solid waste. Evaporation ponds are discouraged in some states, including California. San Juan Generating Station A highly integrated recycling operation is underway at the San Juan Generating Station, a plant operated by Public Service of New Mexico, located in the Four Corners area of New Mexico. The water flow is shown in table 5-2, and the full extent of the recycling is shown in figure 5-1. Notice in particular the six input streams of waste process water entering the Process Wastewater Ponds and the multi-pronged treatment of the water exiting the ponds. The highest level goes through both distillation and demineralization before heading off to the boiler. The intermediate quality distilled water is sent off to the cooling tower. And the lowest quality water is sent directly from the wastewater pond to the limestone preparation operation. 97.5% of the water consumed is evaporated in the tower or goes up the stack; less than 1% ends up in the evaporation pond. Table 5-2 Water Flow at San Juan Water Stream Flow (1) gpm % Water into plant 13, % Make-up allocation Cooling tower 12, % Scrubber % Ash handling % Plant service water % Water out of plant Cooling tower (evap/drift) 11, % FGD cake % Scrubber evap 1, % Ash system % Steam loss % Evaporation Pond % capacity factor = 76.2 % for 22,000 acre-feet/year 5-2

33 Water Recovery, Recycling and Reuse Evap & Drift Plant Service Water Boiler Blowdown San Juan River Cooling Towers (4 units) Blowdown Plant Drains Steam Losses Water Lost to Disposal Ash System (4 units) Recycle to Limestone Prep Overflow (occasional) Spent Regen Process Wastewater Ponds (3) Coal Pile Runoff (occasional) Boiler Make-up Demins (2) Distillate Limestone Prep FGDs (4 units) Water Loss to Flue Gas Brine Brine Concentrators (2) Make-up Re-cycle To atmosphere To disposal Simplified Water Balance San Juan Generating Station Water Lost to Disposal Slurry Dewatering Boiler Cleaning (occasional) FGD Purge Water Evaporation Ponds (75 acres) Figure 5-1 San Juan Generating Station Water Treatment Zero-Liquid Discharge (ZLD) Water Recycle Treatment Power plants have been using water treatment processes to recycle waste streams for many years. Generally, there are two commonly used treatment technologies for recycling plant wastewater reverse osmosis (RO), evaporator and evaporator-crystallizer systems. RO is a process, shown schematically in Figure 5-2 that utilizes pressure to force water through a membrane leaving most of the dissolved salts behind. RO can remove up to 99.5% of the salts in water when used in this manner. Reverse osmosis systems are typically comprised of a softening/silica removal step, followed by filtration, final softening and then RO. Softening removes salts from water that can form mineral deposits (e.g. calcium, magnesium and silica). Mineral deposits must be removed because they interfere with the performance of the RO process by covering up the membrane surface where salts are rejected. Filtration removes particulate matter that also inhibits water passage through the RO membrane. Waste streams generated by the RO process consist of solid waste from the softening system, waste brine from the final softening system and a waste brine stream from the RO. The system can be designed to recover 75% to 85% of the waste streams. 5-3

34 Water Recovery, Recycling and Reuse Evaporation processes essentially distill purified water from contaminated wastewater. The water to be treated is heated, evaporating a portion of the flow. The evaporated steam is compressed and condensed producing the high-quality water and leaving a further concentrated brine behind. A schematic of a vertical, falling film evaporator, typical of current design, is shown in Figure 5-3. Evaporator/crystallizers take the concentrated brine stream from the evaporator and evaporate the remainder of the free water leaving only moist solids behind for ultimate disposal, resulting in a zero-liquid discharge system. A schematic of a ZLD crystallizer is shown in Figure 5-4. Figure 5-2 Reverse Osmosis System Schematic (from FEMP [Federal Energy Management Program] 2004) Figure 5-3 Vapor Compression Falling Film Evaporator Schematic (from Heins 2005) 5-4

35 Water Recovery, Recycling and Reuse Figure 5-4 Crystallizer Schematic (from Heins 2005) 5-5

36 Water Recovery, Recycling and Reuse Arizona Public Service Redhawk Power Station: At the Leading Edge of ZLD (Yarbrough 2007) Redhawk is a 1060 MW combined cycle power plant brought online in mid-2002 by APS. It has a state-of-the art ZLD system, shown in Figures 5-5 and 5-6, using reclaimed effluent for power plant cooling, as a means of saving the high quality groundwater in the area west of Phoenix for local domestic use. It recycles more than 95% of the plant s wastewater, employing a 1050 gpm RO system, and a 700 gpm demineralizer. The two cooling towers operate at 20 cycles of concentration, sending 442 gpm (combined flow) to the ZLD facility. Redhawk has eliminated the need for an evaporation pond, and ships 60 tons/day of solid ZLD cake offsite, as pictured in Figures 5-7 and 5-8. Figure 5-5 Redhawk ZLD Facility 9 (From Yarbrough 2007) 5-6

37 Water Recovery, Recycling and Reuse Figure 5-6 Redhawk Water Balance (courtesy Power Magazine [Yarbrough 2006]) ZLD Cake Figure 5-7 ZLD Cake Ready for Disposal (from Yarbrough 2007) 5-7

38 Water Recovery, Recycling and Reuse 20 Ton Bins Figure 5-8 ZLD Cake Disposal Containers (from Yarbrough 2007) 5-8

39 Water Recovery, Recycling and Reuse New Options for Further Water Recovery A number of new options are being explored that could further reduce the total makeup water requirement. One would recover water from the plume leaving the wet cooling tower. (Feeley III 2006) A second would recover water escaping up the stack from boiler and scrubber operations. In the first case, the Air-to-air system shown in Figure 5-9 draws the wet plume through a heat exchanger cooled by air. The liquid condenses on the heat exchanger plates and runs back onto the hot water distribution deck of the cooling tower. This process, which is estimated to save 15-30% of the water exiting the cooling tower, is being prepared for full-scale field testing on San Juan Unit 4. In the second, the University of North Dakota Energy and Environment Research Center (UNDEERC), in conjunction with Siemens Westinghouse Power Corporation, is about to start a two-year test of a new process to extract water from the stack gas. (UNDEERC 2004) They will use a drying agent in a desiccant-based dehumidification system that promises to recover a large fraction (25-30%) of the water escaping the plant up the stack. If successfully applied to a plant comparable to the 1800 MW San Juan Generating Station, for example, the savings could amount to more than 3600 gallons per minute, roughly 20% of that evaporated in the cooling tower. As the scarcity and cost of water rise, power plant managers will be continuously challenged to find new and innovative ways to recover, recycle and reuse the water in the plant. Figure 5-9 Water Recovery From the Plume (courtesy: SPX Marley) 5-9

40

41 6 DRY COOLING TECHNOLOGY Dry Cooling Technology Where water is at a premium or its use restricted, the major technological opportunities for saving water are in the cooling system by using dry or hybrid cooling. In a dry system, the steam from the turbine is carried in large ducts to an air-cooled condenser (ACC) where the heat is transferred directly to the air passing over the surface. The ACC uses a large number of finned tubes to increase the surface area exposed to the cooling air, similar to the way cars, refrigerators and electronics are cooled. (Wyndrum 2007) The ACC is normally designed in the shape of an A-frame with steam entering along the apex and condensing as it passes downward through finned tubes, as shown in Figure 6-1. There is a key engineering advantage in keeping the steam duct as short as possible to minimize steam pressure losses. As a result, the ACC is normally located close to the turbine building. Figure 6-1 Air Cooled Condenser 6-1

42 Dry Cooling Technology Dry cooling offers distinct advantages by dramatically reducing water consumption, and increasing the flexibility of power plant siting. However, the capital cost of dry cooling is considerably higher than wet cooling, and the dry cooling process typically exacts a penalty on power plant performance. The penalty is aggravated during the hottest days of the year when power plant efficiency falls off substantially. (Maulbetsch 2002; EPRI 2004) Figure 6-2 Dry-cooled Plant on Mystic River North of Boston, MA The capital and operating cost disadvantage of dry cooling can be offset by the elimination of most water related costs in arid or water-constrained regions. The major water costs include the cost of acquisition, water delivery, treatment and discharge. There is an additional environmental cost to protect fish and marine life from entrainment and impingement during intake. Sometimes, it is not the cost or availability of water that is driving the decision to go to dry cooling as can be seen in Figure 6-2. It can be the licensing process; in some areas dry cooling can cut a year or more off the licensing process. The use of dry cooling on nuclear plants requires special consideration. First, the preferred, more efficient type of dry cooling is the direct system in which steam from the turbine is ducted directly to the air-cooled condenser (ACC). This system is likely not applicable to boiling water reactors (BWR s) because a leak or rupture in the steam duct or ACC would create an open steam flow path from the reactor core to the environment. The application to pressurized water reactors (PWR s) should be allowed since the secondary steam generation loop provides a physical barrier between the reactor flow circuit and turbine/condenser steam circuit. 6-2

43 Dry Cooling Technology Second, indirect dry cooling, in which steam from the turbine is condensed in a conventional shell-and-tube steam condenser and the hot water is then cooled, prior to recirculation, in an aircooled heat exchanger (ACHE), should be acceptable. However, indirect imposes a higher efficiency penalty on the turbine than a direct system. This results from the higher condensing temperature (and hence higher turbine exhaust pressure) at the same ambient air temperature. In a direct system, condensing temperature exceeds ambient air temperature by only the amount required to transfer the cooling heat load across the ACC. For an indirect system, the additional thermal resistance of the shell-and-tube steam condenser, the temperature rise of the cooling water as it passes through the condenser and the somewhat lower heat transfer coefficients of an ACHE as compared to an ACC result in a significantly higher condensing temperature for the same ambient air temperature. Finally, the current approach to nuclear plant design and licensing is to use a standard plant design, which, once approved by the NRC, is acceptable without extensive review. The turbines in these designs have not been selected or optimized for use with dry cooling as have those currently used on dry cooled fossil plants. Hybrid Wet/Dry Systems Wet and dry cooling systems can be combined to gain the advantages of both and to offset the disadvantages of each. Hybrid systems, illustrated schematically in Figure 6-3, designed for maximum water conservation are essentially dry systems with just enough wet cooling added to prevent significant deterioration in power plant efficiency during the hottest days of the year. Sometimes these are referred to as dry/wet-peaking cooling tower systems. When temperatures rise and the turbine backpressure gets too high, the wet cooling system is turned on, improving heat rates and generation capacity. The ambient temperature at which the wet cooling portion is turned on depends on the site meteorology, the cooling system design and the amount of water available on an annual basis. Depending on the site-specific circumstances it might be used for as few as the hottest few hundred hours to as much as half the year. These systems typically limit annual water use to 20-80% of that required for all wet cooling. 6-3

44 Dry Cooling Technology Figure 6-3 Hybrid Cooling System The wet and dry systems are typically designed to operate in parallel. The majority of the time the steam is flowing only to the dry system, but as the ambient air temperature and turbine backpressure rise above specified design limits, the wet system can be turned on. The steam then begins to flow to the surface condenser, transferring the heat to the cooling water, which is taken to the wet tower for cooling through evaporation, thus reducing the heat load on the ACC. The application of hybrid systems to nuclear plants is subject to the same considerations as were discussed above under dry cooling systems; that is, it may not be allowable to use an air-cooled condenser for the dry portion of the hybrid system, particularly on a BWR. The hybrid system would more likely be designed with an indirect system for the dry portion. Comparative Costs As a general rule, closed cycle cooling system are more costly and less efficient than are oncethrough cooling. Additionally, closed-cycle wet systems are less expensive and more efficient than dry or hybrid systems. Extensive analyses comparing costs and performance of closedcycle cooling systems are available from several sources. (EPRI 2005 #350) (EPRI 2004 #480) Maulbetsch 2002 #60) Maulbetsch 2006 #510) Figure 6-4 illustrates the comparative costs of wet and dry cooling both on the basis of initial capital costs and annual costs which include, in addition to the annualized capital cost, the differential costs of operating power, cooling system maintenance and the plant performance penalty costs imposed by cooling system limitations on turbine efficiency. As indicated, the absolute and relative costs are a function of site meteorology. Figure 6-5 illustrates the effect of water costs on the comparative costs of wet and dry cooling and demonstrates that at a water cost of between $2 and $4 per 1000 gallons, wet cooling can cost more than dry cooling on an annual cost basis. 6-4

45 Dry Cooling Technology Dry/Wet System Cost Ratios Gas-fired Combined-cycle Plant Capital Cost Annual Cost Ratio of Costs Hot, Site arid 1 Hot, Site humid 2 Extreme, Site 3arid Moderate, Site 4cool Moderate, Site 5warm Figure 6-4 Comparative Costs of Wet and Dry Cooling Systems Annual Cost Ratios vs. Water Cost Base--$1.00/kgal $2.00/kgal $4.00/kgal Cost Ratios El Paso, Site TX1 Jacksonville, Site 2 FL Bismarck, Site 3ND Portland, Site OR 4 Pittsburgh, Site 5PA Figure 6-5 Effect of Water Cost on Cooling System Cost Comparisons 6-5

46 Dry Cooling Technology Hybrid cooling costs are typically significantly greater than wet system costs but are usually lower than all-dry systems costs if they are sized to consume at least 20% of the water used by an all-wet system. (EPRI 2004 #480) Dry Scrubbing In traditional operation, scrubbing removes SO 2 from the flue gas by spraying a limestone slurry into the gas stream. The SO 2 reacts with the calcium in the slurry to form calcium sulfate or sulfite, which falls to the bottom as a wet sludge. Some of the water is separated out in recycle tank and sent back to do more scrubbing; some is lost through evaporation, up the stack, or in settling ponds. Some is sent to landfills as moisture in the solid waste. (EPRI 1983) There are two options for reducing the amount of water lost through traditional scrubbing. The first involves cooling the flue gas before scrubbing. Reducing the stack gas temperature by 25 degrees F can reduce evaporative losses by 15-20%. The second is a form of dry scrubbing. It consists of atomizing an alkaline reagent and spraying it into the hot flue gas to absorb the SO 2. The water used is about 20% less than wet scrubbing, and the residue comes out as a dry product that is airborne, rather than a wet sludge that falls to the bottom. The dry residue is captured in a particulate control device, such as a baghouse or ESP. (EPRI 1992) Dry Ash Handling Fly ash is routinely captured in dry form through precipitators and baghouses, but bottom ash is another matter. Ash falling from the bottom of coal-fired power boiler is close to combustion temperature and extraordinary difficult to handle. Traditionally, bottom ash has been sluiced with water to quench it and to provide a means of fluidly conveying the ash to a settling pond or to a dewatering bin where some of the water can be recovered and reused. Dry mechanical systems are now available for capturing and conveying bottom ash. Typically, the bottom ash falls into a hopper, and is then conveyed on a belt that can absorb the thermal and mechanical shocks of falling ash. While being conveyed, the ash is cooled with air. The ash moves to a crusher that pulverizes the large clinkers, yielding a product that is fine enough to be mixed with fly ash. Such systems can be fully automatic, can be maintained without shutting down the boiler, and can eliminate ash dewatering bins, ponds, and wastewater treatment. (Allen-Sherman-Hoff 2005; Allen-Sherman-Hoff 2006) Dry Technologies and ZLD As noted in a previous section on ZLD Water Recycle Treatment, tightly integrated plant water systems cascade water of lower and lower quality down through various uses until a residual amount of no-longer-recyclable brine is sent to a final treatment stage for evaporation and disposal of the solids residue. These final evaporator/crystallizer components are costly and energy intensive. Significant cost savings can be realized by reducing the flow to the ZLD system as much as possible. 6-6

47 Dry Cooling Technology This can introduce a conflict in objectives. For example, the use of dry cooling in place of a wet cooling tower eliminates the opportunity of recycling wastewater streams from other parts of the plant such as the boiler make-up treatment plant to the cooling tower where a large portion of it would be evaporated. Therefore, water system designs and equipment choices must be thoroughly evaluated against the whole array of criteria from water conservation to cost reduction. 6-7

48

49 7 ALTERNATIVES TO FRESH WATER SUPPLY Alternative water supplies offer significant opportunities for power plants to limit their use of freshwater. Potential sources included seawater and brackish groundwater, as well as wastewater from municipal effluent, industrial operations, oil and gas production, and agricultural runoff. Most freshwater supplies are now fully subscribed in the U.S. With wastewater reclamation and desalinization growing at rates of 15% and 10% per year, respectively, non-traditional water consumption could well equal freshwater consumption in the U.S. within 30 years, as shown in Figure 7-1. Figure 7-1 Projected U.S. Non-agricultural Water Consumption (Source: DOE) 7-1

50 Alternatives to Fresh Water Supply Municipal Waste Water Municipal wastewater typically undergoes extensive treatment in the 25,000 municipal effluent facilities in the U.S. And typically the treated water is then discharged into waterways or allowed to percolate in disposal ponds. Only about 8% of the 32 billion gallons per day (BGD) of treated gray water is reclaimed or recycled. As such, gray water represents one of the largest untapped resources of relatively clean water for the future. According to DOE, its use is projected to grow from 2.6 BGD in 2006 to 12 BGD by Municipal wastewater was first used for power plant cooling over 40 years ago. Initially, a few plants in California, Texas and Florida used municipal effluent for cooling. In the past ten years the use of this resource has increased dramatically. A recently published survey by Argonne National Laboratory (Veil 2007) has identified 70 plants using municipal effluent today. These include Burbank Power in California, Southwestern Public Service in Texas, Lakeland Electric in Florida, the Delta Energy Center in Pittsburg, California, PSE&G in New Jersey, AES Granite Ridge in New Hampshire, and the Palo Verde Nuclear Generating Station in Arizona. At Palo Verde, gray water has been used for cooling its three-unit, 3,875 MW plant for over 20 years. The gray water is pumped 35 miles from Phoenix, put through an additional (tertiary) stage of treatment, and then stored in large (760 million gallon) lined reservoir. There are several zerodischarge or near zero-discharge plants using municipal effluent in the Southwest. Using municipal wastewater poses both technical and economic problems. Depending on the plant and the final disposition of the plant s wastewater stream, the use of municipal effluent can be relatively simple. At plants where municipal effluent is used in lieu of freshwater and where cooling tower blowdown can be discharged directly into an adjacent surface waterbody, municipal effluent is often incorporated easily into plant operations. In these scenarios, the plant metallurgy must be compatible with the treated effluent. At zero discharge plants, municipal effluent is generally more costly to use, but this depends on the quality of the freshwater source (overall salinity, mineral salt concentrations, etc). Treatment can be quite specific depending upon the source and state of the gray water. At Palo Verde, for example, the effluent is put through trickling filters to reduce ammonia content and adjust alkalinity. (Yarbrough 2007) Clarifiers are used to remove phosphates and magnesium through the addition of chemicals to remove sediment, suspended solids and other contaminants. Coagulant is added to the tank and the ph is adjusted. After mixing, flocculant is added resulting in rapid clarification of the water and the precipitation of solids. Further chemical addition is used to reduce the level of calcium carbonate, which tends to otherwise cause a build up of scale, and finally, gravity filters are used to remove any remaining suspended solids. Transportation costs are dependent on the distance of the power plant from the municipal wastewater plant and existing water-reuse pipeline infrastructure. Added to the cost of transportation is the additional cost of disinfection and specialty chemicals to control mineral scale. 7-2

51 Alternatives to Fresh Water Supply A contractual agreement with the municipality on the flow and quality of gray water is one of the most critical factors in success. A major concern is a variation in source water quality, since variable inlet water quality makes it difficult to keep the treatment systems and chemical feeds in proper balance and to ensure consistent quality of the treated water being supplied to the plant. Southwestern Public Service in the Texas panhandle, which has worked with the city of Amarillo for many years, says that the utility should hold the city accountable for poor water quality and gear the price paid for the city s gray water accordingly. (Wjeck 2007) Mountain View power plant in Southern California has a similar arrangement with the City of Redlands. Sometimes a second supply line is needed in case the first one goes down, and a large number of holding ponds on both ends of the line to ensure an even steady flow of water to the power plant. In some municipalities there is increasing demand for treated municipal effluent of a variety of uses including irrigation of parks and other recreational properties, other industrial users or even aquifer recharge to hold back salt water intrusion. As a result, reclaimed water may not be available for long-term purchase by a power plant, even if it is physically available at the municipal water treatment plant. Brackish Ground Water There are large brackish groundwater aquifers throughout much of the interior U.S. Texas alone, for example, has an estimated 2.5 billion acre-feet of such water, equal to a thousand year withdrawal at a level equal to 10% of current U.S. fresh water consumption. Treatment costs can range from $0.75/kgal to $3.00/kgal, depending largely upon salinity, which varies greatly from region to region, from 1,000ppm to 20,000pm. Brackish groundwater can also contain high levels of scale-causing compounds, such as carbonates, sulfates and silicates. Seawater Seawater has been used for power plant cooling for decades along the coasts. Its use today is estimated at around 60 billions of gallons per day (BGD). Salinity levels are quite high but offset by the low levels of carbonate, sulfate and silica levels that cause scaling. The real impediment for future use are the ecological impacts, including entrainment and impingement of various organisms that get captured in the intake structure, thermal effluent streams, and growing desire for industry-free coast lines. Desalinization is largely being used to create potable water for rapidly growing coastal areas. In 2000, there were 220 plants in the country, generating 400 million gallons of freshwater. The growth rate is about 10% per year, indicating an output of about 2 BGD of drinking water by Its use for power generation is at an early stage; the Huntington Beach and Encina power plants in Southern California have integrated desalinization plants on the drawing boards. 7-3

52 Alternatives to Fresh Water Supply Produced Water Produced water is a byproduct of oil, gas and mining operations. On average, a barrel of oil brings up about six barrels of produced water, representing a significant source for the future. The quality varies greatly by region and local geology. Salinity levels range from 500 ppm to over 400,000 ppm. Produced water can also have high levels of organics and soluble hydrocarbons. Water from mining operations also may contain heavy metals and naturally occurring radioactive materials. There are currently two projects in California (one operational and one in design) that will treat produced water to drinking water quality for discharge. The quality of this water will be such that it could be used for power plant cooling. The economics of using produced water for power generation largely hinge on the proximity of the oil and gas operation to the power plant. 7-4

53 8 THE ECONOMICS OF WATER Cost of Water Engineers evaluating the design of a power plant cooling system will typically try to estimate the so-called breakeven cost of water, the point where the total lifetime cost of a dry cooling system equals the total cost of a wet cooling system. The capital cost of a dry system will typically run four times the cost of a comparable wet system, but can be offset by decades of reduced water consumption and its associated costs of pumping, treating, etc. Water cost consists of four parts: the cost of acquisition or purchase, the cost of delivery, the cost of treatment if necessary, and the costs of discharge or disposal. Each of these components can vary by an order of magnitude depending upon location, source, and local requirements. Acquisition Costs The cost of acquiring water depends upon geographic region, and whether water use is oversubscribed or undersubscribed in the local area. And it also depends on whether the water is purchased outright on an annual basis (at so called leased prices), or whether the user is able to buy the water rights, which entitles the owner to an agreed number of acre-feet of water per year in perpetuity. The range is quite large, as shown in Table 8-1 below, and future water costs could be significantly higher. Also, water rights law is very complex and varies dramatically from state to state. Therefore, generalizations cannot adequately bracket the subject matter. Table 8-1 Water Acquisition Costs Purchase Option Minimum Low Medium High Water Rights, $/acre-foot Nil Water Supply, $/kgal Nil Delivery Costs The cost of transporting water from the source to the power plant site include the capital cost of pipeline and the operating costs for pumping the water. Installation costs are affected by the length of the pipeline and the route. Routes through urban areas can be double or triple the cost of pipelines through rural areas. In aggregate, delivery costs range from a low of $0.15/kgal to $1.20/kgal. 8-1

54 The Economics of Water Treatment Costs Treatment costs include the initial clean up costs for in-plant use, and the final costs as the water exits the plant for discharge or disposal, as described in Chapter 7. The major treatment expense is for operating expenses, chemicals, power, maintenance and labor. The range of costs for treatment is quite large anywhere from $0.25 to $4.00 per 1000 gallons. It is totally dependent on the degree of treatment required to use the water source in power plant operations, and the level of treatment to dispose of the water and/or treatment solids. If the plant must operate in a ZLD mode, costs will at the higher end of the range. Total Water Costs The complete cost picture for water acquisition, delivery and treatment is shown in Table 8-2. The range represents an order of magnitude difference between low total cost and high cost. At the extreme, the high cost represents an unlikely combination of negative factors -- poor quality water requiring lengthy uphill pipeline transport to a zero-discharge site. Table 8-2 Total Water Costs Costs in $/kgal Minimum Low Medium High Acquisition Nil Delivery Nil Treatment/Disposal TOTAL

55 9 CASE STUDIES OF DIFFERENT PLANTS OPERATING IN VARIOUS REGIONS OF THE U.S. This final section describes a series of hypothetical case studies that are illustrative of the many factors that must be considered when determining the water management system for power generation. The case studies explore different types of power plants, with different duty cycles, climates, and constraints on water supply. Given the array of variables, there are many possible combinations; the six power plants chosen here, under three different scenarios each, should help convey the full range of options. On the following pages, the power plants chosen are: 150 MW peaking plant. Specifically, a gas-fired combustion turbine operating at a 20% capacity factor. 550 MW combined-cycle plant. Specifically, a gas-fired unit typically designed with two combustion turbines sending hot gas to two heat recovery steam generators (HRSG s) feeding a single steam turbine (known as a 2 x 1 configuration), with summer peaking duty, and operating with a 75% capacity factor. 750 MW coal-fired plant. Specifically, a base-load, sub-critical unit located in a summer peaking region MW nuclear plant. Specifically, a base-load pressurized water reactor, with winter peaking duty, and operating with a 95% capacity factor. 500 MW IGCC power plant. Specifically, a base-load, summer peaking unit, gasifying Powder River Basin coal, and operating with an 85% capacity factor. 40 MW solar-thermal power plant. Specifically, a non-dispatchable unit, with a 25% availability factor. 9-1

56 Case Studies of Different Plants Operating in Various Regions of the U.S. 150 MW Peaking Plant Gas-fired Combustion Turbines 20% Capacity Factor Case Climate Water Availability Intake/Discharge Regulations 1 Hot, arid None for power None/ZLD 2 Moderate, dry Limited None/ZLD 3 Hot, humid Plentiful Normal/NPDES Gas turbine peaking plants generally have no steam-cycle and therefore no steam condenser cooling requirement. The water requirements on a per MWh basis are quite low. In addition to a modest amount of water needed for lube oil cooling, generator cooling and the hotel needs of a small staff, water would be used for turbine performance enhancement. This is normally used only on hot days; however, since the peak loads coincide with the hottest days in most locations, the turbine enhancement capability is desirable.) Case 1: In a hot arid climate with no water allocable for power applications, as in the Las Vegas area, the performance enhancement would be limited to inlet air cooling using a mechanical refrigerated chiller with an air cooled condenser. The auxiliary heat load could be dissipated with air-cooled fin-fan coolers. Hotel water could be city water if available, or groundwater, if suitably treated. Case 2: In a dry area with some water availability, inlet air cooling could be more economically provided with either a spray system or an evaporative system where the air passes through a wetted matrix material. The water consumption rates would be approximately 25 gallons per MWh. For 150 MW at a 20% capacity factor this would be a modest water requirement of 8-15 acre-feet per year. 9-2

57 Case Studies of Different Plants Operating in Various Regions of the U.S. Case 3: In an area with plentiful water, significantly more power augmentation could be achieved with steam injection. Water can be evaporated with hot tail gas from the turbines and compressed and injected into the compressor. Estimates for a 50 MW turbine indicate that as much as 300 gallons/mwh could be profitably injected, resulting in potential efficiency gains of 10 points and power augmentation of 50-70%. For the conditions of this example, water use would amount to over 300 acre-feet. 550 MW Combined-Cycle Plant Gas-fired 2 x 1 Configuration Summer Peaking 75% Capacity Factor Case Climate Water Availability Intake/Discharge Regulations 1 Hot/arid None ZLD 2 Variable/dry Limited ZLD 3 Moderate/rainy Plentiful Variable/NPDES Gas-fired combined-cycle plants have been at the forefront of water-conservation efforts not only because of their inherent water savings from generating two-thirds of their power from combustion turbines, but also because they have chosen dry cooling on many of the newer plants throughout the country. The major water needs are for steam-side condenser cooling and for combustion turbine performance augmentation, both strongly determined by ambient temperature levels. Case 1: In the hot, arid Southwest where many of these plants exist, dry cooling is virtually mandatory in locations where no fresh water can be allocated to power generation. Turbine performance augmentation could be provided by mechanical refrigeration chillers with aircooled condensers. If available, treated reclaimed water might be used for more economical turbine air inlet cooling with sprays or evaporative systems. However, the primary means of offsetting the hot-day performance fall-off of the gas turbine is the use of duct burning to 9-3

58 Case Studies of Different Plants Operating in Various Regions of the U.S. augment the flow to the steam side. Very low water consumption can be achieved, but at the price of higher capital costs and limited output on the hot, peak demand days. Case 2: In other areas such as the mountain states, hybrid cooling, using perhaps only 25-50% of the water needed for wet cooling, may be possible. This would be preferred at sites with high summertime temperatures since the wet cooling would provide low backpressures at those times. At sites with more moderate summertime temperatures, or hot periods of shorter duration, dry cooling may be used with only modest penalties. Limited amounts of water might be used for turbine inlet air cooling. Case 3: In areas with plentiful water, wet cooling towers for the steam condenser and evaporative inlet air cooling on the combustion turbines could be the systems of choice. 750 MW Fossil Plant Coal-fired, Sub-critical Base-load, Summer Peaking Case Climate Water Availability Intake/Discharge Regulations 1 Variable/arid None ZLD 2 Moderate/dry Limited ZLD 3 Hot/humid Plentiful NPDES Coal-fired steam plants have the highest water consumption per MWh of any of the fossil power plants. This results from the full power generation coming from the steam cycle and the need for stack gas scrubbing, ash handling and greater dust control. In addition, coal plants require greater staffing than gas-fired or renewable plants and higher hotel loads. Case 1: In arid areas where fresh water supplies cannot be allocated to power generation, the alternatives are dry cooling or the use of reclaimed municipal water as make-up for an all-wet or hybrid system. Dry-ash handling could be used along with dry scrubbing with spray dryers to minimize all water uses. Intensive internal recycle and reuse could be employed to minimize water intake and to reduce the residual wastewater sent to the ultimate disposal of the 9-4

59 Case Studies of Different Plants Operating in Various Regions of the U.S. evaporator/crystallizer or the evaporation pond. At sites with high summertime temperatures, the use of reclaimed water would be highly advantageous; at sites in dry but colder locations, dry cooling is less penalizing. Case 2: In areas with some, but limited water availability, hybrid cooling is expected to become the system of choice, as it was recently at Comanche III in Pueblo, Colorado. Water consumption can be limited to 25-50% of that required for all-wet cooling. Cooling tower blowdown may be stored and used to offset the need for fresh scrubber makeup, and hot day penalties can be minimized or eliminated. Such locations are likely to have ZLD requirements, so a high degree of internal recycle and reuse would be economical. Recent developments seeking to recover evaporated water from cooling tower plumes may prove effective and economical for further reducing water requirements. Case 3: In regions such as the Southeast or Northeast, with plentiful water available, conventional wet cooling, wet scrubbing and perhaps wet ash sluicing could be systems of choice. The exception might be sites where particularly stringent regulations were enforced regarding the environmental effects of cooling water intake losses under 316(b) Phase I rules. While unusual, there have been instances where even the limited amount of water required for closed-cycle cooling make-up was deemed to be less than the best approach for preventing intake loses; in those cases, dry cooling has been imposed. 9-5

60 Case Studies of Different Plants Operating in Various Regions of the U.S MW Nuclear Plant Pressurized Water Reactor Base-load, Winter Peaking 95% Capacity Factor Case Climate Water Availability Intake/Discharge Regulations 1 Hot/arid to dry None to limited ZLD 2 Wet/rainy Plentiful NPDES Nuclear plants have the highest water requirements for condenser cooling because of their generally higher heat rates compared to fossil-steam plants, as well as the absence of any heat rejection up a stack. On the other hand, the cooling system make-up is the only consumptive water use of any consequence at a nuclear plant. Case 1: The water conservation options for nuclear plants at arid or dry sites are limited in that it is not clear that dry cooling, at least direct dry cooling using an air-cooled condenser, would be allowed to operate on a nuclear plant. It seems likely, although not certain, that indirect dry cooling, in which hot cooling water from a surface condenser is re-circulated through an aircooled heat exchanger -- exactly as it is to a wet cooling tower -- would be permitted. But this would impose even more severe heat rate and capacity penalties than those imposed with direct dry systems. The alternative is the use of reclaimed water, such as is done at the Palo Verde Nuclear Generating Station. The use of hybrid systems should be considered but presumably it would be a design where the dry portion was of the indirect type rather than an air-cooled condenser. Case 2: In areas where water is plentiful, wet cooling, which is commonly used on nuclear plants worldwide could be the system of choice. Water conservation is possible either through operation at the highest possible cycles of concentration or through the use of non-fresh water. 9-6

61 Case Studies of Different Plants Operating in Various Regions of the U.S. 500 MW IGCC Plant Powder River Basin Coal Base-load, Summer Peaking 85% Capacity Factor Case Climate Water Availability Intake/Discharge Regulations 1 Hot/arid None ZLD 2 Variable/dry Limited ZLD 3 Moderate/rainy Plentiful Variable/NPDES IGCC plants, in which coal is gasified to provide fuel for a combined-cycle plant, have thermal operating characteristics and cooling requirements on the generation side of the plant, which are essentially identical to the gas-fired combined-cycle plant discussed previously. Additional water requirements exist for the coal gasification process part of the plant, any associated materials handling functions, the likely requirement for additional dust control measures, and a larger plant staff. A discussion of water conservation opportunities in the gasification area is beyond the scope of this review. Case 1: With severe limitations on available water, dry cooling could be used and turbine performance augmentation could be provided by mechanical refrigeration chillers with aircooled condensers. If available, treated reclaimed water might be used for more economical turbine air inlet cooling with sprays or evaporative systems. However, as was the case with gasfired plants, the primary means of offsetting the hot day performance fall off of the gas turbines is the use of duct burning, to increase the flow and temperature of the gas flow to the steam generator. This imposes additional heat load on the air-cooled condenser on the hottest days, exacerbating the dry cooling limitations at times of peak demand. Very low water consumption can be achieved, but at the price of higher capital costs and limited output on the hot, peak demand days. 9-7

62 Case Studies of Different Plants Operating in Various Regions of the U.S. Case 2: At locations with somewhat more water available, hybrid cooling, using perhaps only 25-50% of the water needed for wet cooling, may be possible. This would be preferred at sites with high summertime temperatures since the wet cooling would provide low backpressures at those times. At sites, with more moderate summertime temperatures, or hot periods of shorter duration, dry cooling may be used with only modest penalties. Limited amounts of water might be used for turbine inlet air cooling. Case 3: In areas with plentiful water, wet cooling towers for the steam condenser and evaporative inlet air cooling on the combustion turbines could be the systems of choice 9-8

63 Case Studies of Different Plants Operating in Various Regions of the U.S. 40 MW Solar-thermal Plant Non-dispatchable 25% Availability Case Climate Water Availability Intake/Discharge Regulations 1 Hot, arid No water allocable for power None/ZLD 2 Moderate, dry Limited seasonally None/ZLD 3 Warm, humid Plentiful 316(b) limits/npdes Water requirements at solar-thermal plants are also dominated by the water used for steam condensation. It is higher on a per MWh basis because of the higher heat rates of solar turbines operating at lower turbine inlet temperatures and pressures than turbines used at fossil-fired or nuclear plants. The only other water needs in addition to auxiliary cooling for bearing oil and generator cooling, would be for dust control. Dust control may be particularly critical on sites with large solar collector panels. Hotel water would be needed for periodic cleaning of the collector surfaces in addition to the usual cleaning, sanitary and drinking requirements. Estimates of this requirement vary considerably from site to site but are nonetheless minor in comparison to the condenser cooling water use. 9-9