An integrated assessment of global and regional water demands for electricity generation to 2095

Advances in Water Resources 52 (2013) 296–313

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An integrated assessment of global and regional water demands for electricity generation to 2095 Evan G.R. Davies a,⇑, Page Kyle b, James A. Edmonds b a b

Department of Civil and Environmental Engineering, 3-133 Markin/CNRL Natural Resources Engineering Facility, University of Alberta, Edmonton, Alberta, Canada T6G 2W2 Joint Global Change Research Institute, Pacific Northwest National Laboratory, 5825 University Research Court, Suite 3500, College Park, MD 20740, USA

a r t i c l e

i n f o

Article history: Received 2 July 2012 Received in revised form 26 November 2012 Accepted 29 November 2012 Available online 8 December 2012 Keywords: Electric power Integrated assessment Water use Water withdrawal Water consumption

a b s t r a c t Electric power plants account for approximately half the global industrial water withdrawal. Although continued electric-sector expansion is probable, significant variations in water intensity by electricity technology and cooling system type make its effects on water demands uncertain. Using GCAM, an integrated assessment model of energy, agriculture, and climate change, we establish lower-, median-, and upper-bound estimates for current electric-sector water withdrawals and consumption in 14 geopolitical regions, and compare them with available estimates. We then explore water use for electricity to 2095, focusing on uncertainties in water withdrawal and consumption intensities, power plant cooling system changes, and adoption rates of water-saving technologies. Results reveal a probable decrease in the water withdrawal intensity with capital stock turnover, but a corresponding increase in consumptive use, for which technologies under development may compensate. At a regional scale, water use varies significantly based on the existing capital stock and its evolution over the century. Ó 2012 Elsevier Ltd. All rights reserved.

1. Introduction Over the last century, population growth, economic development, and increasing irrigation have driven a significant increase in water demand [1,2], while land use change and hydraulic engineering have altered water supply [3,4]. Both will be affected over the long term by continuing socio-economic development and climate change [5–8]. Scientists, policy makers, and the public are therefore increasingly concerned about water scarcity [9,10] – a concern that has driven a rise in global assessments of water resources. Many assessments have concentrated on water supply, and have produced figures [11,12,1,2] that are increasingly reliable [13], as well as models [14–18] that simulate water supply in a large number of the world’s river basins as a function of, for example, current and historical weather and runoff data, land use, reservoir operations, and climate change. In contrast, sectoral water use data are significantly less certain [19,20] but are of great interest at river-basin to national scales. Both water supply and demand are increasingly incorporated into global-scale assessments and water resources databases, such as the FAO’s AQUASTAT [21], as well as water resources models, including TARGETS [22], WBM [15], WaterGAP [9], WATERSIM [23], H08 [24], H08-MATSIRO [25], and ANEMI [26], many of which ⇑ Corresponding author. Tel.: +1 780 492 5134; fax: +1 780 492 0249. E-mail addresses: [email protected] (E.G.R. Davies), [email protected] (P. Kyle), [email protected] (J.A. Edmonds). 0309-1708/$ - see front matter Ó 2012 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.advwatres.2012.11.020

can project water use far into the future. The understanding such models can bring to water demand is critical, because (1) water use is more amenable than supply to adjustment through economic and social policies, and alternative technologies, and (2) the growth in water use in the last century is likely to continue throughout this century. From 1900 to 2000, global freshwater withdrawals – domestic, industrial, and agricultural – grew from an estimated annual 580 km3 to 3715 km3, with a more than five-fold increase in agricultural water withdrawal, and much larger, nearly 18-fold increases in industrial and domestic withdrawals [1,2,27]. Similarly, global freshwater consumption grew from 330 km3 to 2075 km3 from 1900 to 1995, also with a five-fold increase in agricultural consumption, and 18- and 10-fold increases in industrial and municipal consumption [1], respectively. Continuing growth in sectoral water use through the current century is likely to be similarly uneven. Thus, while irrigated agriculture (A), industrial (I), and domestic (D) withdrawals in 2000 amounted to approximately 2548 km3, 672 km3, and 494 km3 [27], or 69%, 18%, and 13% of the total, respectively, several global water models and assessments project converging shares over the next decades, with the agricultural water use share – although not necessarily volume – dropping significantly in most cases. Thus, by 2075, WaterGAP [9] projects sectoral withdrawal percentages for the SRES A2 and B2 scenarios of 41% (A; 2246 km3), 28% (I; 1490 km3), and 31% (D; 1679 km3), and 44% (A; 2211 km3), 21% (I; 1031 km3), and 35% (D; 1726 km3), respectively. Shen et al. [28] project values

E.G.R. Davies et al. / Advances in Water Resources 52 (2013) 296–313

for four SRES scenarios, with values for A2 and B2 reproduced here, of 52% (A; 5227 km3), 37% (I; 3772 km3), and 11% (D; 1147 km3), and 59% (A; 3996 km3), 26% (I; 1754 km3), and 15% (D; 1002 km3), respectively; and ANEMI [26] projects values of 60% (A; 2948 km3), 20% (I; 957 km3), and 20% (D; 952 km3). This convergence of sectoral shares results from differing trends in key determinants of sectoral water use. Specifically, agricultural water use may grow relatively slowly, albeit from a large initial volume, because the global area of irrigated land is not expected to expand dramatically in the next few decades [29,30], and irrigation projects tend to be fairly inefficient with much improvement possible [31]. (Such assumptions are uncertain, of course, with recent studies by Bruinsma [29] and Fischer et al. [32] projecting 11% and 26% increases, respectively, in irrigated land to 2050, and Döll [33] showing that climate change may increase crop-water requirements in the 2070s by almost 8% for the irrigated land area in 1995.) In contrast, industrial and domestic water uses are more closely linked to rising GDP and population [34,35,15,36,16], and may therefore grow rapidly even as water resources become increasingly scarce. The projections of industrial water use from existing water resources models are not built from detailed representations of the demand drivers and technological choices for the various components of industrial water demands. Therefore, although industrial withdrawal and consumption calculations have been conducted at high resolution with complex models in several cases [9,28,37,38], the models have represented the drivers of industrial water use in a simplified manner – as functions of GDP and a technological change parameter [16,26], or of electricity consumption and technological change [28] – or have used projections from global-change scenarios [37,38]. In contrast, several other groups have used complex energy-economy models to project a large portion of the industrial water use for individual nations: specifically, the volume of water used for electricity generation. For the United States, EPRI [39], NETL [40–42], Feeley et al. [43], and Chandel et al. [44] investigated electric sector water use in the relatively near term to 2020 (EPRI) or 2030, while Cooley et al. [45] focused on electric sector water use to 2035 in the intermountain West. Outside the United States, Koch and Vögele [46] simulated electric sector water use to 2030 in the Elbe River Basin with two models, a water demand and a water supply model, and Rio Carillo and Frei [47] projected water use for total energy production in Spain to 2030. Yu et al. [48] estimated coal and water uses, as well as emissions of CO2 and SO2, in China with a technologically-detailed energy model to 2030. Like the latter set of models, we use a process-based approach to establish current and future water withdrawal and consumption volumes for electricity production. Electric-sector water use is currently significant, and constituted approximately half the industrial water withdrawal (400 km3 of 725 km3 total) and 20% of the industrial consumption (11.4 km3 of 55.2 km3) on a global basis in 1995 [19]. We use GCAM, an integrated assessment model of energy, agriculture, and climate change [49–51], to simulate explicitly the key drivers of water withdrawal and consumption for electricity in fourteen world regions from 2005 to 2095: (1) shifts in electricity technology shares, (2) changes in cooling system types, and (3) adoption of water conservation technologies. The study is intended to serve as a base year and business-asusual assessment of future water demands for electricity generation, allowing improvement of existing representations of future industrial water demands that are used in water scarcity analyses, and providing data and methods that will be useful for incorporation of water into integrated assessment models that have historically focused on the energy, agriculture, and climate systems. Due to the system boundaries of this study, there are several limitations to note. First, although water shortages have recently af-

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fected electricity generation in the United States, France, and Australia [52], and climate change may worsen the problem [53], we do not address changes in water supply. As such, we also do not consider feedbacks between water scarcity and technology choice in the electricity sector. Inclusion of both water availability and scarcity–technology feedbacks in our estimates would require the incorporation of a river-basin scale hydrological model and a water pricing mechanism, both of which are under development for integration into GCAM. Further, we do not assess the impact of greenhouse gas emissions mitigation policies on the future electric generation mix and the consequent effects of these policies on water demands; such climate–energy–water connections are the subject of a companion paper (Kyle et al., accepted for publication). Finally, water used to produce and transform the fuels used by the electric sector is omitted, along with all other indirect water demands of the power sector. Despite these limitations, our work represents the first incorporation of water demands into a prominent, technologically-detailed integrated assessment model, and – to the best of our knowledge – the first global assessments, at regional scales, of electric-sector water use into the relatively distant future. The values generated are grounded in a process-based representation of the global energy system, with water withdrawal and consumption values based on the literature. Combination of our water withdrawal and consumption intensities with cooling system shares for all major electricity generation technologies yields reasonable estimates of regional electricity sector water use values for 2005. Our sensitivity analysis then reveals the relative importance of electricity technology- and cooling system-choices on water use into the future, and produces results that may help to inform regional and national water policy, as well as electric sector decisions. Finally, contributions of electricity production to regional water scarcity, and water stress changes over time, are estimated. Section 2 of this paper presents key drivers of electric sector water use and describes integrated assessment modeling and GCAM. Section 3 explains the methodology. Section 4 presents and analyzes a set of ten comparative simulations, or ‘‘scenarios’’, whose results are then discussed in Section 5. Section 6 provides conclusions from the work. 2. Simulating electric sector water use Electric sector water use depends on total electricity production, the electricity generation technology mix (coal, natural gas, oil, nuclear, solar, and so on), the water use intensity (measured as m3 of water per MWh of energy) of each electricity technology, and the characteristics of cooling systems associated with individual power plants. These determinants of water use are discussed in Section 2.1. Section 2.2 then describes integrated assessment modeling and the GCAM model. 2.1. Water use for electricity Global electricity demand has grown by a factor of four since 1970, and international agencies and integrated assessment models anticipate continued growth into the future (see Fig. 1), driven in large part by increasing population and per-capita income. Thus, in the longer term, reference scenarios from integrated assessment models participating in the recent development of new Representative Concentration Pathways [54] generally produced a power sector expansion from 73 EJ yr 1 in 2008 to between 360 EJ yr 1 and 420 EJ yr 1 in 2100 (Fig. 1). With such a large expansion in electricity demand, it can be expected that, absent supply constraints or technology shifts, the water demands of the electric power sector will also continue to increase through the end of the century.

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Fig. 1. Global total electricity demand, 1971–2100, from several recent assessments. Historical time series from IEA [55]; near-term projections from IEA [56] and Sims et al. [57]; long-term scenarios from the following integrated assessment models: GCAM [51], IMAGE [54], and MESSAGE [58].

In addition to the variability of electricity demand projections, estimation of water demands into the future is further complicated by the significant range – several orders of magnitude – of the water requirements for electricity production across available power generation technologies [40,59,60,45]. These water demand intensities depend on a number of factors, including the plant cooling system, which plays the key role; generation technology; plant capacity; treatment of power generation byproducts; and local environmental and climatic conditions [43,44]. Both wet and dry cooling systems are currently used in power plants: wet systems use water, either in once-through flow or recirculating configurations, and dry systems use air for cooling. Once-through systems withdraw large volumes of surface water but evaporate, or consume, a small fraction, while recirculating systems withdraw much smaller volumes, but consume the majority of the withdrawal. Data scarcity complicates assessment of future water use for electricity – even present-day electric sector water use is unknown [19,61]. For example, although gross water withdrawal figures for electric power are available for several nations and regions, including the United States [62,63], Australia [64], Canada [65], and Europe [66], consumption values are generally not reported in a consistent fashion. For all other regions of the world, withdrawal estimates – available primarily from Gleick [20] and AQUASTAT [21] – do not disaggregate electric sector withdrawals from total industrial withdrawals [21]. Moreover, these total industrial water withdrawal estimates are often of poor quality due to sparse metering and reporting, and a blurred distinction between public-supplied and self-supplied water, which are classified as ‘‘municipal’’ and ‘‘industrial’’ water use, respectively. Given both significant differences in water use from one power plant to another, and data scarcity, several research groups [39,40,67] have developed simplified water withdrawal and consumption intensities (e.g. m3 of water per MWh of energy) to analyze and project water use by the power sector. Derived from United States data, these intensity values are available for combinations of electricity generation technologies and cooling system types that together create a set of ‘‘model plants’’ [40]. Tables 1 and 2 present literature estimates of water withdrawal and consumption intensities, respectively, for an array of model plants, including pulverized coal (Coal), conventional oil- and natural gas-fired (Oil/NG), nuclear (Nuclear), natural gas combined cycle

(NGCC), biomass and generic fossil fuel (Oth. Steam), integrated gasification combined cycle (IGCC; a new coal-fired technology), geothermal (Geotherm.), concentrating solar power (CSP), photovoltaic (PV), wind turbine (Wind), and hydroelectric (Hydro) plants. The tables include several geothermal and CSP technologies, which are differentiated in terms of their steam-reservoir and sunlight-concentrating lens characteristics, respectively. The wide range of estimated intensities for each model plant type is based on differences in plant age, operational and thermal efficiency, cooling system age and water source, plant location, diurnal and seasonal temperature variations, wind speeds, and humidity levels [67,60]. However, several patterns are apparent. First, plants with evaporative cooling systems have far lower withdrawal rates, and generally higher consumption rates, than those with once-through flow systems. Second, non-thermal power plants (PV, Wind, Hydro) use very little water, with the notable exception of consumptive use from hydropower, discussed below. Third, for a given cooling system type, nuclear plants tend to use more water than fossil-electric plants. Fourth, advanced fossil-fuel technologies such as natural gas combined cycle (NGCC) or integrated gasification combined cycle (IGCC) use less water per unit of power produced than related conventional technologies (natural gas steam power plants, and pulverized coal power plants, respectively). However, IGCC is a new technology and its water use factors (Tables 1 and 2) are uncertain, as they are based on a sample of only six pilot designs studied by NETL [71]. Similar uncertainty applies for concentrating solar power (CSP) technologies. Finally, water use by hydropower is singularly problematic. Studies that report hydropower water consumption typically estimate the total evaporative losses at reservoirs in comparison with losses absent a dam – all losses are assigned to electric power production [74,60]. This approach yields estimates as low as 5.4 m3 MW h 1 [in a total range of 5.4–26 m3 MW h 1; 68] and as high as 68 m3 MW h 1 [74], a range many times broader than that of any other generation technology. Furthermore, assigning all evaporative losses to electricity generation ignores the fact that dams are often constructed for multiple uses, such as water supply for municipal or agricultural purposes, flood control, and recreation. In addition to ‘‘model plant’’ water use intensities, determination of current and future electric sector water use requires information on the shares of (1) electricity generation technologies, and

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E.G.R. Davies et al. / Advances in Water Resources 52 (2013) 296–313 Table 1 Summary of water withdrawal values by electricity generation technology and cooling system type (m3 MW h Tech.

Gleick [68]

Coal Once-thru’ Wet Tower Pond Wet w CCS

76–190 1.9–2.3 1.1–2.3

DOE [70]

NETL [71]

180 4.5

76–189 1.1–2.3 1.9–2.3

2.3–2.6

NETL [41]b

NETL [72]

). Jacobson [73]

2.2–2.5 +7%

NETL [42]

F&K [59]a

Macknick et al. [60] Low

Med.

High

86–103 2.0–2.5 57–68

98 2.5 65

76 1.9 1.1 4.6

138 3.8 46 4.8

189 4.54 91 5.0

4.3–5.0

76–190 1.9–2.3 1.1–2.3

180 4.5

76–189 1.1–2.3 1.9–2.3

86 1 30

86 2.3 30

38 3.6 3.6

132 4.6 4.6

227 5.5 5.5

Nuclear Once-thru’ Wet Tower Pond

95–227 3.0–4.2 1.9–4.2

180 4.5

95–227 1.9–4.2 3.0–4.2

119 4.2

120 5.0 3.9

95 3.0 2.3c

168 4.2 27

227 9.8 49

28–76 0.9 0.9

180 4.5

28–76 0.9

34 0.6 23

28 0.6 23 1.8

43 1.0 23 1.9

75 1.3c 23 1.9

86 1 30

76 1.9 1.1

132 3.3 1.7

189 5.5 2.3

1.4 2.2c

1.5 2.2

2.3 2.6

Geotherm. Dry steam Flash Binary EGS Hybrid Bin. Hybrid EGS CSP (Solar) Tower Trough Dish Fresnel Hy_trough Hy_tower

1.0 2.1

76–190 1.9–2.3 1.1–2.3

IGCC Wet Tower Wet w CCS

c

V&D [19]a

4.9–5.6

Oth. Steam Once-thru’ Wet Tower Pond

a

NETL [69]

Oil/NG Once-thru’ Wet Tower Pond

NGCC Once-thru’ Wet Tower Pond Wet w CCS

b

EPRI [39]

1

180 4.5

1.0 +7%

1.8

76–190 1.1–2.3 1.9–2.3 1.0

1.4–1.8 2.2–2.5

+7%

1.4–1.5 2.2

7–13 0 15

7.6

0 0 0

6.8 0.0 6.4 11 0.3 3.1

6.8 0.0 14 18 0.8 5.3

6.8 0.1 15 20 1.4 7.6

4

2.8 2.9–3.5

2.8 2.9 0.1

2.8 2.7

3.0 3.3

3.3 4.0

3.8 0.4 0.3

3.8 1.3 0.6

3.8 1.3 0.9

PV

0

0

0.8–1.9

0.0

0.1

0.1

Wind

0

0

0.2

0.0

0.0

0.0

Hydro

0

0

0.08

Abbreviated sources are V&D [19], Vassolo and Döll [19]; and F&K [59], Fthenakis and Kim [59]. Values from NETL [41] are indicated as percentage difference from the corresponding technology without CCS. Where denoted, withdrawal values from Macknick et al. [60] are adjusted so that model plant consumption does not exceed withdrawals.

(2) cooling systems in each region. The generation mix in all regions of the world is reasonably well understood [55,75]; however, there is little information on the deployment rates of different cooling system types in most regions [19]. Any global bottom-up estimate of present-day water demands by the power sector must therefore include assumptions about the shares of the different types of cooling systems presently in use; it follows that any such projection must also consider the evolution of these shares over time. To summarize, estimation of current electric sector-water use and simulation of its evolution to 2095 relies on uncertain water use data, highly variable water use intensities by electricity generation technology, uncertain current cooling system shares, and assumptions about water conservation technology development and changes in cooling system shares over the next 80 years. After an introduction to integrated assessment below, the Methodology (Section 3) explains how we assign water use characteristics to

each of these factors for each GCAM electricity technology and world region, both now and into the future. 2.2. Integrated assessment and GCAM Broadly, integrated assessment models combine sub-models from a range of disciplines into a single framework, allowing analysis of interactions between the different systems that are not addressed by single-discipline models [76–78]. GCAM is an integrated assessment model developed by the Pacific Northwest National Laboratory, designed for long-term analysis of energy supply and demand, agriculture and land use, greenhouse gas emissions, and climate. For the purposes of the present study, only the components of the model relevant for the assessment of water use by the power sector are described; readers interested in the other components of the model are here referred to several publications [50,79–81]. Future electricity demand in

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Table 2 Summary of water consumption values by electricity generation technology and cooling system type (m3 MW h Tech.

Coal Once-thru’ Wet Tower Pond Wet w CCS Oil/NG Once-thru’ Wet Tower Pond Nuclear Once-thru’ Wet Tower Pond

Gleick [68]

1.2 2.6

1.1 2.6

2.2–3.2

a

c

0.65 1.33 1.33

DOE [70]

1.1 1.1–1.8 1.8

NETL [71]

NETL [41]b

2.2–2.6

NETL [72]

Jacobson [73]

1.7–2.0 +103%

NETL [42]

F&K [59]a

Macknick et al. [60] Low

Med

High

0.5 1.8–2.0 0.2–3.0

0.4 1.8 1.1 3.6

1.0 2.6 2.1 3.6

1.2 4.2 2.7 3.6

3.2–3.7

0.65 1.33 1.33

1.1 1.1–1.8 1.8

0.3 0.6 0.4

0.4 2.5 2.5

0.9 3.1 3.1

1.1 4.4 4.4

1.5 2.7 2.7

0.65 1.33 1.33

1.5 1.5–2.7 2.7

0.5 2.4

0.4 2.2 2.1

1.0 2.5 2.3

1.5 3.2 2.7

0.65 1.33 1.33

0.4 0.7

0.08 0.5 0.9

0.1 0.5 0.9 1.4

0.4 0.8 0.9 1.4

0.4 1.1 0.9 1.4

0.3 0.6 0.4

1.1 1.8 1.1

1.1 2.1 1.5

1.1 3.7 1.8

1.2 2.0

1.4 2.0

1.7 2.1

1.9

1.0 1.9

1.1 1.8 1.8

IGCC Wet Tower Wet w CCS

b

3.9–4.4

V&D [19]a

).

1.1 1.8 1.8

0.4 0.7 0.7

Oth. Steam Once-thru’ Wet Tower Pond

CSP (Solar) Tower Trough Dish Fresnel Hy_trough Hy_tower

1.1 1.8 1.8

NETL [69]

4.4–5.0

NGCC Once-thru’ Wet Tower Pond Wet w CCS

Geotherm. Dry steam Flash Binary EGS Hybrid Bin. Hybrid EGS

EPRI [39]

1

0.65 1.33 1.33

0.7 +103%

1.3

1.1 1.1–1.8 1.8 0.8

1.4 1.8–2.0

+103%

1.1–1.2 1.7–1.8

7–13 0 15

5.3

0 0 0

6.8 0.0 6.4 11 0.3 3.1

6.8 0.0 14 18 0.8 5.3

6.8 0.1 15 20 1.4 7.6

4

2.8 2.9–3.5

2.8 2.9 0.1

2.8 2.7

3.0 3.3

3.3 4.0

3.8 0.4 0.3

3.8 1.3 0.6

3.8 1.3 0.9 0.1

PV

0

0

0.0

0.1

Wind

0

0

0.0

0.0

0.0

Hydro

2.7c

17–29

5.4

17

68

17

Abbreviated sources are V&D [19], Vassolo and Döll [19]; and F&K [59], Fthenakis and Kim [59]. Values from NETL [41] are indicated as percentage difference from the corresponding technology without CCS. From Gleick (1994: 292), reservoir evaporation from all U.S. reservoirs are approximately half the median estimate for California.

each region is driven by growth in demand for energy services by the buildings, industrial, and transportation sectors, which in turn are driven by exogenous assumptions about population and income in each region, modified by technological aspects of energy service provision. At 5-year intervals from 2005 to 2095, GCAM solves the electricity generation mix in each of fourteen geopolitical regions – the United States, Canada, Western Europe, Japan, Australia and New Zealand, the Former Soviet Union, China, the Middle East, Africa, Latin America, Southeast Asia, Eastern Europe, Korea, and India. Capital stocks are modeled explicitly. Thus, while the generation mix of new builds in any time period depends largely on the characteristics of available technologies and on energy prices in that time period, the total generation mix also depends on the decisions made in prior time periods. GCAM has been used extensively in international analysis of climate policy [81,82], technological strategies for greenhouse gas

mitigation [83,84], and future emissions scenarios [85,51]. This study constitutes a first step towards integrating the water system into the model.

3. Methodology The following steps were used to calculate electric sector water withdrawal and consumption values in GCAM in 14 world regions from 2005 to 2095. First, a literature-based dataset was assembled of model plant water withdrawals and consumption for the simulation base year of 2005 (Tables 1 and 2), and base intensity values were assigned for each model plant. Second, cooling system shares for each electricity generation technology in each region were established for 2005. Third, changes in regional cooling system shares were estimated from 2005 to 2095. Fourth, reductions in

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water withdrawal and consumption through adoption of waterefficient technologies were estimated for 2020 onward. Fifth, water use intensity and cooling system estimates were incorporated into GCAM (v1.0, Rev. 4246) and adjusted to match assessments for 2005. Finally, these adjusted values were then used to form the basis of a set of scenarios used to explore the evolution of water demands by the electric power sector to 2095. The following sections explain steps one through six in greater detail. 3.1. ‘‘Model plant’’ water use intensities Throughout the analysis, we used three different sets of model plant water-use intensities to investigate the sensitivity of electricsector water use to variability in technology-specific assumptions for water intensity values, which was intended to reflect both the high variability in published values (Tables 1 and 2), and regional and annual variations in actual water use for each model plant type. The ‘‘minimum,’’ ‘‘median,’’ and ‘‘maximum’’ intensity values presented in the recent, comprehensive literature review conducted by Macknick et al. [60] were used for all fourteen GCAM regions to ensure consistency through, (1) use of mid-range literature values for each combination of power plant and cooling system, and (2) use of a single source for the intensity values. One set of adjustments was required. Because the electric-sector water withdrawal initially calculated for the United States, with the combination of electricity production from GCAM and the ‘‘median’’ water intensities from Macknick et al. [60], was lower than those of two recent assessments [43,63], the ‘‘median’’ water withdrawal intensities of all once-through flow cooling systems were adjusted upwards by 15%. With this adjustment, the match between our values and those of previous assessments was quite close, as shown in Section 3.5, and the intensities for individual technologies nonetheless remained well within the ranges reported in the literature (Table 1) for all technologies. 3.2. Cooling system shares in 2005 After establishing model plant water-use intensities, cooling system shares were required for each GCAM electricity technology in each region for the base year of 2005. However, the necessary data were scarce; for example, the World Electric Power Plants Database [86] used by Vassolo and Döll [19] to estimate global water use by the electric sector provided cooling system data for only 11% of its listed thermal power stations. Further, inventories of electricity generation by technology do not include cooling system details (e.g. [75,87]). Thus, while cooling system shares in the United States, Australia, and China were available in the literature, shares in all other regions were estimated. For the United States, cooling system shares were available from Energy Information Administration surveys, as aggregated by NETL [40,42] into 16 thermal ‘‘model plants’’ through combination of four generation technologies with four cooling system types. We used their shares, but reduced the reported dry cooling share of natural gas combined cycle plants from 59% to 10% [88], because the reported figure was based on a small sample size and was likely too high [42]. For Australia, cooling system shares for the same set of power generation technologies were available from a detailed dataset of generation and cooling system types presented by Smart and Aspinall [89], while cooling shares for coalpowered electric plants in China – which provide approximately 80% of the annual electricity generation [90] – were provided by Yu et al. [48]. For all other regions, cooling system shares were estimated, as explained below. First, regional dry cooling shares were set. Second, regional percentages of seawater-based once-through flow systems were assigned. Third, regional electric-sector water with-

301

drawal and consumption estimates were collected from the literature. Finally, region-specific shares of once-through flow and wet tower cooling systems were calculated so that the sum of each region’s electric sector water withdrawal was consistent with the literature-based estimates, when the base year (2005) electricity generation by each technology and cooling system was multiplied by its corresponding ‘‘median’’ water withdrawal intensity. Note that in this calculation, cooling ponds were not considered as their water demand profile generally falls between the other system types; in practice, cooling systems with cooling ponds may function in similar fashion to evaporative [39,41] or once-through flow systems [40,42]. Regional dry cooling shares were calculated from Nagel and Wurtz’s [91] breakdown of the approximately 64 GW of air-cooled capacity installed globally between 2000 and 2005. This sample likely includes more than 80% of dry cooling systems operational in 2005, due to the rapid growth in the dry cooling market during this time interval [91,92]. Shares in each region were calculated as total dry-cooled capacity divided by total thermoelectric generating capacity in 2006 [87] – nuclear power plants were omitted since they do not use dry cooling. Next, regional percentages of seawater-based once-through flow systems were estimated; this study focuses on freshwater use, so withdrawals and consumption of seawater were excluded. Seawater withdrawal percentages at once-through flow cooling systems were derived from data available for the United States [30%; 63,42], China [13%; 48], and Australia [66%; 89]. In most other regions, between 10% and 30% of once-through flow systems were assumed to use seawater, with higher shares in regions with abundant coastline, coastal population centers, and limited freshwater resources. In Japan, Korea, and the Middle East, however, nearly all power plants with once-through flow systems were assumed to use seawater, since all nuclear plants in Japan and Korea are located on the coasts [93] as are most fossil-electric plants in Japan [94]; we assumed the same factors of freshwater scarcity and a lack of large freshwater lakes drive seawater use for cooling in the Middle East. Water use estimates from the literature were then used to assign regional wet tower and once-through flow system shares. As explained above, several nations and regions provide cooling water withdrawal values, while Gleick [20] and FAO [21] provide estimates of total industrial water withdrawals for all GCAM regions. Where specific cooling water withdrawal values were unavailable – Latin America, the Former Soviet Union, the Middle East, Korea, Southeast Asia, and Africa – estimates were based on Gleick [20] and FAO [21] values, adjusted according to ratios of cooling water withdrawals to total industrial water withdrawals from Vassolo and Döll [19, Table 3]. Finally, for Japan, manufacturing-only water withdrawals available from Japan MLIT [95] were deducted from Gleick’s [20] estimate of total industrial water to calculate cooling water withdrawals. Cooling water and total industrial water use values from the literature are provided in Table 3. To approximate the literature estimates, regional cooling system shares outside the United States and Australia and New Zealand were assigned uniform values across electricity technologies, except for nuclear power in Japan and Korea, as explained above. Note that because withdrawal intensities for once-through flow systems are significantly higher than for wet towers (Table 1), the water withdrawal calculations were quite sensitive to the assumed once-through share. Further, we did not adjust our regional cooling system shares to match regional cooling water consumption from the literature. In the few cases where such data are available, they were likely calculated using assumptions that vary across studies, and so are not necessarily compatible with our approach. For example, even for the United States, the literature estimates of cooling water consumption for 2000–2005

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Table 3 Literature estimates of cooling water- and total industrial water withdrawal and consumption, by continent or subcontinent and GCAM region (km3 yr 1). Water consumption figures exclude evaporation from hydroelectric reservoirs. GCAM region

North America United States

Canada

Latin America

Europe Western Europe

Eastern Europe

Former Soviet Union

Middle Easta

Year

1995 1995 1995 2000 2000 2005 2005 2005 1996 2005 2005 1995 1995 2000 2005 1995 1995 2000 2005 1995 2000 2005 1995 2000 2005 1995 1995 2000 2005

Australia, N.Z.

1995 2000 2000 2005

Asia

1995 1995 2000 2005 1995 2000 2005 2005 1990 2000 2000 2000 1995 2000 2005 2005 2000 2002 1995 2000 2005

Chinab

India

Japan

Korea South-East Asia

Africa

1995 1995 2000 2005

Cooling water

Industrial water

Withdr.

Cons.

Withdr.

224

3.7

267 210

182

4.6

Source

Cons. 9.5

[19] [21] [62] [20] [39] [41] [43] [63] [20] [96,65] [21]

220 202 206 197

4.2 5.1 8.6 30.7

27.8

0.7 31.6

7.3

0.3

122 87.9

3.8

90.9 27.7 23.0

1.4

0.16

1.1

0.17

0.43

0.27

41.0

2.8

26.4 28.7 27.5 32.3 218 108 110 111 29.8 30.5 26.1 79.1 73.2 69.9 8.0 4.2 4.7 12.6 7.1 2.6 2.7 143.7 190 230 208 97.1 161

[21] [19] [20] [21]

3.2

16.9

[19] [21,66] [20] [21,66] [21,66] [20] [21,66] [21,66] [20] [21,66] [21] [19] [20] [21]

0.32

0.97

[19] [21] [20] [64] [21] [19] [20] [21] [21] [20] [48]c [21] [21] [21] [97] [20] [95]d [95]d [21] [95]d [20] [21] [21] [20] [21]

23

67 133 15 10 40 35.2 12.4 11.9 15.8 11.0 3.1 3.1 10.2 12.0 45.7e

35

3.6

0.3

9.9 9.6 9.1 10.7

1.2

[19] [21] [20] [21]

a Vassolo and Döll’s ‘‘West Asia’’ is assumed to be the same geographical region as GCAM’s ‘‘Middle East’’. b In GCAM, ‘‘China’’ also includes Vietnam, Cambodia, North Korea, Mongolia. c Figure cited is for coal-fired electricity generation only. d Figure cited is for manufacturing use only. e In Indonesia, AQUASTAT lists industrial water use as 0.38 km3 in 1992 and 24.7 km3 in 2005 – a key driver of the rapid rise in South-east Asian industrial water withdrawal.

bracketed quite a wide range, from about 4.2 km3 yr 8.6 km3 yr 1 [43], as shown in Table 3.

1

[39] to

Our derived percentages of cooling system types for all GCAM regions and thermoelectric generation technologies in 2005 are provided in Table 4. These technologies are grouped according to the approach in NETL [42]; thus, as in the categories of Tables 1 and 2, ‘‘Coal’’ corresponds to Coal, ‘‘Other fossil/bio’’ to Oil/NG and Oth. Steam, ‘‘Combined cycle’’ to NGCC and IGCC, and ‘‘Nuclear’’ to nuclear. 3.3. Future cooling system shares Projections in cooling system shares to 2095 are inherently uncertain. In assigning future shares, we therefore made a variety of assumptions based on current trends in the United States, Europe, and China, and applied them to all fourteen GCAM regions. The assumptions and their justifications follow. Concerns over water availability and environmental protection have already motivated a shift away from new construction of once-through flow systems, towards evaporative- and dry-cooling. In the United States, Clean Water Act provisions and public pressure discourage the use of once-through flow systems [42], and so the vast majority of plants built since 1970 have used either evaporative cooling towers or cooling ponds [72]. Similarly in Europe, environmental legislation limits cooling water use under certain conditions [53]. Thus, a steady decrease in electric-sector withdrawal intensity has occurred in the United States since the 1970s [63], and in Europe since at least 1995 [66]; cooling system scenarios developed by Yu et al. [48] suggest a comparable trend in China. Further, like freshwater once-through systems, future expansion of seawater cooling is probably limited in the United States because (1) seawater is generally unsuitable for use in evaporative cooling systems [63], and (2) the current regulatory environment discourages the construction of power plants on coasts [42]. Note, however, that we have assumed a small fraction of plants continue to use once-through flow systems (Table 5) to account primarily for new construction of freshwater cooling ponds with characteristics similar to once-through flow systems. Finally, dry cooling shares have grown substantially in the last two decades [91]. Future deployment will likely depend on a wide variety of factors such as the severity of regional water supply constraints, and consequent changes in water allocations or increases in water prices; the spatial distribution of growth in electricity demand; changes in environmental regulation in different regions; and the degree to which dry cooling technologies advance. Because low shares of dry cooling result at least partially from its high relative costs, lower costs from technological progress could cause dry cooling to become more widespread. Based on the above observations, assigned cooling system percentages for new power plants built in all model time periods after 2020 are shown in Table 5. Conversion from base-year values to 2020 values was assumed to progress linearly, after which cooling system shares for all new plants remain constant. The long-term percentage of new builds with once-through flow systems is intended to include systems with cooling ponds that function in similar fashion to once-through flow systems. Because of their relatively higher water use, nuclear plants in the four relatively water-scarce regions with abundant coastline (Japan, Korea, the Middle East, and Australia and New Zealand) were assumed to use once-through flow systems exclusively, with greater than 95% of cooling water needs supplied by seawater. Seawater cooling percentages in all regions were kept equal to their values in the base year, with the exception of the United States, where the percentage is decreased from 30% to 5%, based on NETL [42]. Like NETL [42], we assumed that new natural gas combined-cycle plants do not use once-through flow cooling, and that 60% use dry cooling systems. For all other technologies and regions, dry cooling shares in the base year are passed forward to future periods, with the

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E.G.R. Davies et al. / Advances in Water Resources 52 (2013) 296–313 Table 4 Assumed cooling system shares for thermoelectric generation technologies in 2005 (%), by GCAM region. Region

Seaa

USAb Canada Western Europe Japan Australia & NZ Former Soviet Union Chinab Middle East Africa Latin America Southeast Asia Eastern Europe Korea India

30 10 20 97 66 10 13 96 30 30 87 10 97 30

Coal

Other fossil/bio

Combined cycle

Nuclear

1-thru

WT

Dry

1-thru

WT

Dry

1-thru

WT

Dry

1-thru

WT

Dry

39.1 71 27.7 90 36.8 37.4 20 60 12 18 75 34.5 20 47

48 29 69.6 6.5 56.3 62.6 64.9 38.2 76 77.9 21.5 65.5 76.5 49.5

0.2 0 3 3.5 6.9 0 8.1 1.8 12 4.1 3.5 0 3.5 3.5

59.2 71 27.7 90 100 37.4 20 60 12 18 50 34.5 20 47

23.8 29 69.6 6.5 0 62.6 64.9 38.2 76 77.9 46.5 65.5 76.5 49.5

0 0 2.7 3.5 0 0 8.1 1.8 12 4.1 3.5 0 3.5 3.5

11.6 71 27.7 90 49.9 37.4 20 60 12 18 50 34.5 20 47

76.7 29 69.6 6.5 50.1 62.6 64.9 38.2 76 77.9 46.5 65.5 76.5 49.5

10 0 2.7 3.5 0 0 8.1 1.8 12 4.1 3.5 0 3.5 3.5

38.1 71 27.7 100 0 37.4 20 60 24 18 95 34.5 100 47

43.6 29 72.3 0 100 62.6 73 40 76 82 5 65.5 0 53

0 0 0 0 0 0 0 0 0 0 0 0 0 0

a

Indicates the percentage of once-through flow power plants using seawater cooling. For the United States and China only, cooling pond percentages are non-zero can be derived from the difference between the values provided and 100% cooling. For example, 12.7% of coal-fired plants in the US use cooling ponds. b

Table 5 Assumed reference cooling system shares for thermoelectric generation technologies in power plants built between 2020 and 2095 (%), by GCAM region. Region

Seaa

USAb Canada Western Europe Japan Australia & NZ Former Soviet Union Chinab Middle East Africa Latin America Southeast Asia Eastern Europe Korea India

5 10 20 97 66 10 13 96 30 30 30 10 97 30

Coal

Other fossil/bio

Combined cycle

Nuclear

1-thru

WT

Dry

1-thru

WT

Dry

1-thru

WT

Dry

1-thru

WT

Dry

0 10 10 10 10 10 10 10 10 10 10 10 10 10

85 90 87.3 86.5 60 90 81.9 60 90 85.9 86.5 90 86.5 86.5

5 0 2.7 3.5 30 0 8.1 30 0 4.1 3.5 0 3.5 3.5

0 10 10 10 10 10 10 10 10 10 10 10 10 10

85 90 87.3 86.5 60 90 81.9 60 90 85.9 86.5 90 86.5 86.5

5 0 2.7 3.5 30 0 8.1 30 0 4.1 3.5 0 3.5 3.5

0 0 0 0 0 0 0 0 0 0 0 0 0 0

38.3 40 40 40 30 40 40 30 40 40 40 40 40 40

60.0 60 60 60 30 0 8.1 30 12 4.1 3.5 0 3.5 3.5

0 10 10 100 100 10 10 100 10 10 10 10 100 10

90 90 90 0 0 90 90 0 90 90 90 90 0 90

0 0 0 0 0 0 0 0 0 0 0 0 0 0

a

Indicates the percentage of once-through flow power plants using seawater cooling. For the United States and China only, cooling pond percentages are non-zero can be derived from the difference between the values provided and 100% cooling. For example, 10% of coal-fired plants in the US use cooling ponds. b

exception of the Middle East and Australia and New Zealand, where 30% of new builds of conventional fossil electric plants are assumed to use dry cooling. The balance of cooling system shares are assigned to wet towers, for all regions and generation technologies. 3.4. Technological changes for model plants As part of the US Department of Energy’s Innovations for Existing Plants (IEP) program, new technologies are under development for recirculating cooling systems, which may reduce freshwater demands of thermoelectric generation from the next decade onwards by up to 70% [40,43]. Sorted into five categories, the technologies include alternative cooling water make-up sources, increased cycles of concentration to reduce blowdown frequency, steam recovery, water reclamation from combustion flue gases, and reduction in evaporation losses from coal plants through coal drying. In theory, the combination of all five technologies could reduce model plant water withdrawal and consumption by 64–69%, and 59–65%, respectively [43]; however, because alternative cooling water make-up sources are unlikely to be available in all locations – we assumed their use in 33% of cases – maximum reductions are assumed to average 50% and 39%, respectively.

To clarify the relative importance of technological change in water use reduction, as compared with water use intensity values and cooling system changes, we explored several alternative rates of water-savings technology adoption. These ‘‘adoption rates’’ are in the range of those investigated for the United States by Feeley et al. [43; 0%, 10%, 30%, and 50% market penetration in 2030] and are assigned as follows: (1) Low technology case: No adoption of advanced water-saving technologies. (2) Moderate adoption rate: Starting in 2020, 50% of all new builds globally apply the new IEP technology categories. (3) High adoption rate: Starting in 2020, 100% of all new builds globally apply the new technologies. In the ‘‘high adoption rate’’ case, we also increased dry cooling shares by 10% for all non-nuclear technologies, with wet tower shares correspondingly decreased by 10% from 2020 onwards, to represent (1) technological improvements that lower costs and improve performance, or (2) a regulatory or investment environment that encourages the deployment of dry cooling systems. The increase is significant, given that dry cooling is currently used for less than 3% of the global thermoelectric capacity [91,87].

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3.5. Incorporation of technology-specific water demands into GCAM The final step was the assignment of region-, time-, and scenario-specific water withdrawal and consumption intensities to each electricity generation technology – pulverized coal, natural gas combined cycle, hydroelectric, and so on – in GCAM. Water demands have not historically been of interest for energy models, and as such, cooling systems are not explicitly considered in GCAM’s suite of electricity generation technologies. Conversely, for example, where literature estimates of water use intensities typically do not differentiate between oil and gas steam turbines because of their similar water demands, GCAM represents them as separate technologies because they consume different fuels. The assignment of water use intensities therefore merged the electricity technologies represented in GCAM with the cooling system details required to characterize water use, and yielded one water withdrawal and one consumption intensity for each electricity technology in each region, time period, and scenario. For 2005, combination of the ‘‘minimum’’, ‘‘median’’, and ‘‘maximum’’ water use intensities with the cooling system percentages of Table 4 and electricity production output from GCAM yielded three estimates in Table 6 of each region’s total cooling water withdrawals and consumption (excluding hydropower). These values can be compared with the literature estimates of Table 3. Note that aggregation to regional totals with either the ‘‘low’’ or the ‘‘high’’ intensities yielded estimates in Table 6 that are often inconsistent with regional inventories, where available; however, to span the uncertainty in the possible regional water use by power plants, we provide withdrawal and consumption values for both sets of intensities in addition to the median values. Next, the addition of changes in cooling system shares and technological progress to the initial water use intensities produced a set of region-, time-, and scenario-explicit water intensities for each five-year interval from 2005 to 2095 that, combined with electricity generation, yielded estimates of electric-sector water use to 2095 – the topic of the results and analysis section below. 3.6. Scenario descriptions In this section we introduce the set of scenarios used to investigate the possible evolution of future water demands by electricity generation, addressing the importance of uncertainties in baseyear water use, future changes in cooling system types, and application of water-saving technologies. All water demand scenarios

use socio-economic and power sector technology attributes (e.g. costs, efficiencies, lifetimes) adapted from the reference scenario described by Clarke et al. [80], and thus share the same future population growth, economic growth, electricity generation, and technological changes in the power sector. We focus on a single electricity generation scenario to demonstrate how water demand diverges according to changes in water use intensities, cooling systems, and technologies. Thus, the scenarios are differentiated by alternative present and future water demand characteristics of power generation technologies. A companion paper (Kyle et al., accepted for publication) applies electric sector water use characteristics derived here to investigate connections between climate policy, electricity generation technologies, and water. The characteristics of the reference scenario are as follows. The global population peaks in 2065 and stabilizes towards the end of the century at about 9 billion people. Consistent with a broad body of integrated assessment literature, improvements in standards of living continue through the end of the century, particularly in present-day developing economies. The energy system undergoes moderate levels of technological change which tend to increase energy efficiency over time, but no greenhouse gas emissions constraints or emissions prices are adopted to mitigate climate change. The core of this analysis is then built on nine ‘‘scenarios’’ of present and future water demands by the electric power sector, defined as unique combinations of three sets of starting water use intensities by electric technologies (min, median, and max), and three rates of future technology change relevant for water demands (lotech, midtech, and hitech). A tenth scenario with median starting intensities, no change in cooling system percentages by electric technology, and frozen future technology (frztech) is also presented to demonstrate the importance of the cooling systems and technology changes assumed in all other scenarios. These ten scenarios are summarized in Table 7. The minimum, median, and maximum intensities correspond to the respective sets of water use intensities from Macknick et al. [60], presented in Tables 1 and 2 and modified as explained in Section 2.2. For CSP and geothermal technologies, wherein Macknick et al. [60] presented water use intensities for an array of technologies more specific than the CSP and geothermal technologies in GCAM, we use a simple average of the intensity values for the available technologies. The lotech, midtech, and hitech scenarios correspond to the ‘‘no adoption’’, ‘‘Middle adoption’’, and ‘‘Full adoption’’ cases described

Table 6 Electric sector cooling water withdrawals and consumption by gcam region in 2005 (km3), using minimum, median, and maximum intensitiesa. Water consumption figures exclude evaporation from hydroelectric reservoirs. GCAM region

Withdrawals Minimum

USA Canada Western Europe Japan Australia & NZ Former Soviet Union China Middle East Africa Latin America Southeast Asia Eastern Europe Korea India Global total a

84.6 12.7 45.3 2.1 2.6 25.1 30.8 1.4 3.4 4.0 4.3 10.7 0.9 14.3 242

Consumption Median

Maximum

207.4 28.1 96.5 4.9 5.8 65.8 72.2 3.3 7.6 10.3 9.9 23.0 1.7 31.3

271.1 35.1 124.2 6.2 7.2 88.6 91.1 4.6 9.8 14.3 13.0 28.4 2.0 38.6

568

734

Minimum, median, and maximum intensities are from Macknick et al. [60] – see Tables 1 and 2.

Minimum 4.67 0.22 3.94 0.10 0.25 1.78 2.92 0.59 0.76 0.87 0.54 0.60 0.34 0.63 18.2

Median 6.67 0.36 5.11 0.14 0.36 2.42 4.33 0.75 1.02 1.10 0.70 0.87 0.46 0.95 25.2

Maximum 9.38 0.50 7.02 0.21 0.55 3.41 6.64 1.06 1.51 1.54 1.00 1.29 0.68 1.42 36.2

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E.G.R. Davies et al. / Advances in Water Resources 52 (2013) 296–313 Table 7 Configuration details for the 10 scenarios. Intensities

Technology

Cooling

Scenario name

Minimum Minimum Minimum Median Median Median Maximum Maximum Maximum Median

No adoption Middle adoption Full adoption No adoption Middle adoption Full adoption No adoption Middle adoption Full adoption No adoption

Reference Reference +10% Dry Reference Reference +10% Dry Reference Reference +10% Dry No change

min_lotech min_midtech min_hitech median_lotech median_midtech median_hitech max_lotech max_midtech max_hitech median_frztech

in Section 3.5 and based on Feeley et al. [43]. Cooling system changes assumed in the lotech and midtech (‘‘reference’’ cooling) scenarios are provided above in Table 5. Note however that dry cooling shares are increased by 10% for all non-nuclear technologies in the hitech scenarios, balanced by a corresponding deduction in the share of power plants with wet towers. Finally, the ‘‘frozen technology’’ scenario (median_frztech) clarifies the role of the assumed changes in cooling systems in all other scenarios. This scenario uses median values for water use intensities, but then assumes that the base-year cooling system share of each electricity generation technology in each region is carried forward to all future periods. In this scenario, the water intensity of electricity generation may still change in response to technology change in the electric power sector, whether from shifts between fuels, or switches between more or less advanced technologies within a fuel type. This scenario is distinguished from the others in having relatively high shares of once-through flow systems used through 2095.

4. Results and analysis In this section, we first show the global growth in electricity from 2005 to 2095 along with the generation mix, which is common to all scenarios in the study. We then present and analyze water withdrawals and consumption in these scenarios, first at a global level and then for specific regions, focusing on the United States, China, and India.

Notes

Lower bound scenario Reference scenario

Upper bound scenario

Frozen technology scenario

4.1. Electricity generation The electricity generation scenario used in this study shows global electric sector growth from approximately 60 EJ yr 1 in 2005 to over 300 EJ yr 1 in 2095 (Fig. 2) – a value approximately in the middle of the range of the RCP scenarios of Fig. 1 and intended to represent a business-as-usual case. Note that the scenario used is not tuned to a specific RCP scenario, but is nevertheless consistent with many integrated assessment studies, both in the quantity and the generation mix over time (e.g. [98]). The average generation mix is characterized by a continued reliance on fossil fuels through the end of the century, but with important contributions from nuclear energy, biomass, and a suite of non-biomass renewable energy sources including hydro, wind, solar, and geothermal energy. Growth in electricity production is especially strong in currently developing economies (Africa, China, India, Latin America, the Middle East, and Southeast Asia); while these economies account for about 35% of global electricity generation in 2005, they grow 10-fold over the course of the century to account for 75% of all electricity generation in 2095. The remainder of the analysis focuses on the potential water requirements for the electricity generation profile shown in Fig. 2.

4.2. Global water withdrawal and consumption for electricity generation Total global water withdrawal and the average withdrawal intensity of the electric power sector are shown by scenario in

Fig. 2. Global electricity generation by technology in GCAM, 2005–2095.

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Fig. 3. Global electric sector water withdrawals (left; km3 yr

1

) and withdrawal intensities (right; m3 MW h

Fig. 3. On the left side of the figure, nine of the ten scenarios have relatively constant withdrawals over time, while the withdrawal volume in the ‘‘frozen technology’’ (median_frztech) scenario increases by 150%, or 800 km3 yr 1, from 2005 to 2095. Key factors that explain the relatively constant global withdrawals in all of the scenarios (except median_frztech) are (1) the shift from once-through flow cooling systems to wet tower systems, and (2) changes in the technology mix used to generate electricity. Shifts in cooling system types are driven by the differences between the base-year stock averages (Table 4) and those assumed for new installations after 2020 (Table 5), combined with the effects of retirement of existing power plants and the growth of the electric sector as a whole. Both shifts in cooling systems and in electricity generation technologies have considerable impact on electric sector water use, since at least 85% of electricity in 2050 is generated at facilities that did not exist in 2005. However, in the latter half of the century as the turnover of existing capital stocks nears completion, electric sector water withdrawals begin to track the growth of the electric sector (Fig. 3). The relative importance of cooling system- and electricity generation technology shifts is apparent in both the global total withdrawal volumes (left side) and global average withdrawal intensities (right side) of Fig. 3. Specifically, comparison between the ‘‘frozen technology’’ scenario – without cooling system changes or the implementation of water-saving technologies – and the other nine scenarios reveals that cooling system changes are critical: the withdrawal volume in the median_frztech scenario rises significantly from 2005 to 2095, while withdrawals in all other scenarios remain essentially constant. However, shifts in electricity generation technologies are also important, and are solely responsible for the 50% reduction in withdrawal intensity in the median_frztech scenario – other scenarios have reductions of approximately 80%. Examples of such shifts in the electricity generation mix include increased use of wind power, and deployment of natural gas combined cycle and IGCC power plants (Fig. 2). Thus, while high water-use technologies like conventional coal and nuclear produce 55% of the electricity in 2005, their share falls to 32% by 2095, at which point low water-use technologies such as IGCC, NGCC, Wind, and PV produce 46% of the electricity, up from 21% in 2005 (the majority of which is from a mixture of conventional and combined-cycle natural gas plants). Finally, water-saving technologies further decrease withdrawal intensities, by up

1

) for ten scenarios, from 2005–2095.

to 20% from lotech scenarios to hitech scenarios in 2095. The withdrawal reductions linked to these water-saving technologies are greatest in the long term; although their deployment starts in 2020, electric sector capital tends to be long-lived, and as such, reductions are largest by the later time periods in the analysis. The specific regional and technological trends underlying this relative stability in global withdrawals will be investigated in the following section. The trends observed for global water withdrawals do not apply to global water consumption volumes, which increase substantially in all scenarios in this study (Fig. 4). However, the cause again is the shift from once-through flow to wet tower systems, which increases the average water consumption intensity of electricity generation (Fig. 4(C)) – see the water use intensity differences in Table 2. The effect of this shift is particularly apparent in the higher consumption for the median_lotech scenario as compared with the median_frztech scenario in Fig. 4(A). Without deployment of water-saving technologies (lotech scenarios in Fig. 4(A)), switching from the base-year cooling system shares towards primarily wet tower systems leads to a fivefold increase in water consumption from 2005 to 2095, similar to the growth in electric generation. Deployment of advanced, water-saving technologies substantially reduces water consumption intensity over time, by 20% (midtech scenarios) to 40% (hitech scenarios). These reductions are therefore not sufficient to stabilize global water consumption, but may nevertheless compensate for the additional consumption that occurs with a shift away from once-through flow cooling. Finally, baseyear intensity uncertainties also strongly affect water consumption volumes over time, as well as the relative value of water-conservation technologies. For example, the growth in water consumption from 2005 to 2095 in the lotech scenarios is about five-fold irrespective of the base year intensities; however, in volumetric terms this increase may be as low as 80 km3 yr 1 (min_lotech scenario) and as high as 150 km3 yr 1 (max_lotech scenario). Moreover, although full deployment of advanced water conservation technologies reduces water consumption by 40% irrespective of the base year intensities, savings range from 40 km3 yr 1 (min_hitech compared with min_lotech) to 80 km3 yr 1 (max_hitech compared with max_lotech). Fig. 4(B) shows significant and growing evaporation from hydroelectric reservoirs at the global scale, with values that are, of course, highly uncertain. For 2005, the estimate based on the

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A

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B

C

Fig. 4. Global electric sector water consumption excluding hydropower (A), hydropower-related water consumption (B), and global average water consumption intensity excluding hydropower (C) by scenario, from 2005 to 2095.

median intensity is about 50 km3 yr 1, greater than the total consumption by all other electric technologies (see Fig. 5, below), while the ‘‘minimum’’ water consumption intensity [68] yields only 16 km3 yr 1 and the ‘‘maximum’’ intensity [74] yields about 200 km3 yr 1; for comparison, Shiklomanov [1] estimated evaporation from all reservoirs (including those not involved in hydropower production) as 188 km3 yr 1 in 1995. The hydroelectric water consumption intensities used in this study are all based on analysis of water evaporation from reservoirs in the United States, and as such may not accurately bound the range for hydroelectricity-related water evaporation in all regions. Effects of climate change are also neglected, although anticipated increased landsurface temperatures will drive higher evaporation rates [6], particularly by the end of the simulation period. More reliable estimates of the water consumption intensity of hydropower would greatly improve any attempts to quantify and attribute water consumption in current and future periods. 4.3. Technological and regional trends in water use This section examines the technological and regional trends underlying the global results of the previous section through the following scenarios, all of which use median base-year intensities: median_lotech, median_frztech, and median_hitech. We focus on these ‘‘median’’ scenarios because they best match available base-year regional water use inventories, and because an examina-

tion of differences between them helps to clarify potential results of cooling system changes and water conservation technology adoption on future water demands. From a global, technological perspective, coal-fired electricity in the base year accounts for about 50% of global water withdrawals and consumption, not including evaporation from hydroelectric reservoirs (Fig. 5). Over the course of the century, the growth in market share of IGCC coal power plants (Fig. 2) decreases water withdrawals substantially, such that nuclear power plants account for the majority of the withdrawal volume towards the end of the century. Natural gas power plants shift mostly to combined cycle plants, which have especially low water use; therefore, although natural gas provides about 20% of electricity in 2095, it accounts for less than 5% of electric sector water withdrawals and consumption in the median_lotech scenario. Electricity generation with biomass accounts for a growing portion of global withdrawal and consumption after 2020. Note that these figures relate only to cooling water requirements for biomass-fired plants; the agricultural (irrigation) water volumes required to grow the biomass, which can be very large [99,100], are omitted. Finally, when evaporation from hydroelectric reservoirs at the global scale is included, it amounts to 50% or more of the global total consumption; however, such figures are very uncertain as explained above. At the regional scale, we focus on the United States, China, and India, three large economies that account for approximately half of total global water withdrawals and consumption (excluding

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Fig. 5. Global water withdrawal and consumption (km3 yr associated with hydropower.

1

) by electric generation technology for median_lotech scenario, 2005–2095, including water consumption

hydropower) in all periods in this analysis. In the United States, with cooling system shares fixed at 2005 levels (median_frztech scenario), the water withdrawal increases only slightly over the course of the century, whereas water consumption increases by 22% from 2005 to 2030, and by 67% from 2005 to 2095 (excluding hydropower; Fig. 6). The relative stability in withdrawals and the moderate increase in consumption volumes in the next few decades with ‘‘frozen technology’’ are similar to the baseline scenarios of NETL [41] and Feeley et al. [43], wherein withdrawals increased by 5% and decreased by 0.5% from 2005 to 2030, respectively, and consumption increased by 27% in both studies. With a shift in the United States away from once-through flow systems (median_lotech scenario), and the construction of lower water-intensity combined-cycle plants (Fig. 2), retirement of existing capital stock leads to a substantial reduction in water withdrawals from 2005 levels – by 13% in 2030, and by 84% at the end of the century. However, consumption rises by 30% from 2005 to 2030, and by 108% from 2005 to 2095, as wet towers replace once-through flow systems. A possible technological remedy – the full deployment of available water-saving technologies (median_hitech) – does not noticeably reduce water consumption from 2005 to 2030, because of the relatively large existing capital stock in this region combined with long lifetimes for power generation capital. In 2030 in these scenarios, about 65% of the power in the U.S. is produced at power plants that existed in 2005. In the long term, however, this water conservation technology strategy does stabilize water consumption, post-2035. Again, our near-term figures are consistent with reasonably similar scenarios in several studies. For example, EPRI [39] reported increases in water consumption of 14% and 24% between 2000 and 2020, depending on the degree of shift towards evaporative cooling systems. In a set of four scenarios characterized by different cooling system shares, NETL [41] found withdrawals decreased by 5–23% from 2005 to 2030, and consumption increased by 30–50%. Feeley et al. [43] reported a 9% reduction in withdrawal and a 30% increase in consumption between 2005 and 2030 for a scenario similar to our median_lotech. In China, the growth of the electric sector, and nuclear power in particular, drives greater increases in water withdrawal and consumption than in the United States (Fig. 6). With cooling system shares fixed at 2005 levels (median_frztech), the water withdrawal increases by 106% from 2005 to 2035, and by 250% from 2005 to 2095. These ‘‘frozen technology’’ results are similar to the business-as-usual scenario developed by Yu et al. [48], who reported a 101% increase in withdrawals from 2005 to 2035. Changes in

cooling system shares restrain the increase, but withdrawal volumes still rise by 51–52% from 2005 to 2035, and by 60–81% from 2005 to 2095 (median_hitech and median_lotech, respectively). This increase is generally consistent with the ‘‘planning policy’’ scenario from Yu et al. [48], who reported a 58% increase in water withdrawals from 2005 to 2035. In all of the scenarios, water consumption increases substantially over the full time period, by between 224% (median_hitech scenario, excluding hydropower) and 450% (median_lotech scenario, excluding hydropower). The role of advanced technologies is significant here – full deployment of water conservation technologies (median_hitech) decreases water consumption in 2095 by about 10 km3 yr 1 compared with the median_lotech scenario, and 7 km3 yr 1 compared with the median_frztech scenario. Finally, evaporation from hydroelectric reservoirs is very high in China (Fig. 6), rising from 7 km3 to 20 km3 from 2005 to 2095 with the median consumption intensity. Uncertainty in the hydroelectric consumption intensity value was therefore particularly significant for China, as the evaporative loss decreased to 6.3 km3 yr 1 in 2095 with the minimum intensity and increased to approximately 80 km3 yr 1 with the maximum. The electricity sector in India produced only about 25% as much power as China’s in 2005; however, the GCAM reference electricity scenario includes a 20-fold expansion from 2005 to 2095. Indian water withdrawal consequently rises by a factor of thirteen from 2005 to 2095 in the ‘‘frozen technology’’ scenario, with the total exceeding 400 km3 yr 1 in 2095. In contrast, because of the large share of once-through flow cooling systems in existing power plants [97], scenarios with cooling system change undergo relatively modest growth in withdrawal volumes (Fig. 6): approximately 65% from 2005 to 2035, and between 200% and 250% from 2005 to 2095, depending on the technology level (median_hitech and median_lotech, respectively). Growth in water consumption is substantial in all scenarios, reaching values near the end of the century that are similar to China’s (between 14 km3 and 24 km3, excluding hydropower), with a similarly prominent role for water-saving technologies. Shifts similar to those of the United States, China, and India, are apparent in other GCAM regions as well, as shown for the median_lotech scenario in Fig. 7. Specifically, both the increase in water use for electricity in developing regions and the shift away from oncethrough flow cooling systems in developed and reforming economies lead to a long-term redistribution, both volumetrically (Fig. 7A) and relatively (Fig. 7B), of the global distribution of electric sector water withdrawals and consumption. Water withdrawal volumes from 2005 to 2095 decrease in all developed and

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reforming economies in this scenario (Australia and New Zealand, Canada, Eastern Europe, the Former Soviet Union, Japan, Korea, the United States, and Western Europe); taken together, withdrawals in these regions decrease from 421 km3 yr 1 in 2005 to 120 km3 yr 1 in 2095. In contrast, the electric sector water withdrawals in the developing regions – Africa, China, India, Latin America, the Middle East and Southeast Asia – increase from 133 km3 yr 1 in 2005 to 424 km3 yr 1 in 2095. As compared with developed regions, developing regions have relatively low capacity for the retirement of existing power plants with high shares of oncethrough flow cooling systems to reduce regional power sector water demands.

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Fig. 7 also shows the corresponding consumption values by region, including hydropower; for comparison, the median estimate of global cooling water consumption (i.e. excluding hydropower) is overlaid on the chart. Unlike withdrawal volumes, consumption increases in all 14 regions, but most in developing regions – specifically, between 2005 and 2095 water consumption increases by 360% in developing regions, and by 60% in developed regions. Thus, while present-day developing economies accounted for 43% of global electricity-related water consumption in 2005, they account for 70% of global electric sector water consumption – whether hydropower is included or excluded – by the end of the century.

Fig. 6. Water withdrawal and consumption by electric generation technology for the United States (top), China (middle) and India (bottom), in the median_lotech scenario, including hydropower. Also shown are electricity generation, and total water withdrawals and consumption in median_frztech and median_hitech scenarios.

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(A)

(B)

(C)

(D)

Fig. 7. Global electric sector water withdrawal volume (A), relative withdrawal percentage (B), consumption volume (C), and relative consumption percentage (D) by 14 geopolitical regions, 2005–2095, in median_lotech scenario. Evaporation from reservoirs used to produce hydropower is included in regional consumption totals and global cooling water consumption excluding hydropower (Cooling Water Only) is also overlayed (C).

5. Summary The vast majority of present-day water withdrawals for cooling at thermoelectric power plants occur in once-through flow cooling systems, many of which were built decades ago. In the future, as these legacy systems are retired and replaced, freshwater-based once-through flow cooling systems are likely to become less common, because of increasing water scarcity and environmental protection concerns. These dynamics are assumed to apply to both developed and developing regions in most scenarios in this study, consistent with other assumed socioeconomic and technological aspects of development. Since once-through flow systems have about 40 times the water withdrawal intensity of evaporative cooling systems, this switch could substantially reduce the future water demands for electric power production. The cooling system changes assumed in this study reduce end-of-century global electric sector water withdrawals by about 60%, as compared with a scenario in which cooling system types do not change from their estimated shares in 2005. Still, even without changing cooling system types, our study finds that the withdrawal intensity of electric power production can nevertheless be expected to decrease, as a

secondary effect of ongoing technological progress in the electric power sector. Natural gas combined cycle plants and integrated gasification combined cycle plants have lower water demands than their conventional counterparts, and the expansion of renewable energy sources, particularly wind and photovoltaic energy, likewise puts downward pressure on the average water withdrawal intensity of the electric sector. One of the implications of the ongoing shift away from oncethrough flow cooling systems and towards evaporative cooling systems is that it causes an increase in total cooling water consumption (i.e., evaporation). Without additional water conservation technologies deployed, this study finds an approximate 10% increase in cooling water consumption (not including hydro) at the end of the century that is due to our assumed future shifts in cooling system types. This increased water consumption may be quite important, particularly in systems that are already water-stressed. In this context, development and deployment of water conservation technologies may be key; the suite of technologies applied in this study reduced end-of-century cooling water consumption by about 40%. While these technologies do not stabilize future global water consumption for electric power production – the scenar-

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ios in this analysis are characterized by a five-fold expansion in the electric sector from 2005 to 2095 – they more than compensate for the additional water consumption that occurs due to switching cooling system types. Moreover, we note that even the ‘‘hitech’’ scenarios in this study only assume adoption of water conservation technologies expected to become available in the next decade; as such, the scenarios may under-estimate what is actually achievable if water conservation is prioritized in future technology research and development. An important caveat on these results is that evaporation from hydroelectric reservoirs consumes large volumes of water; indeed, our median estimate for global water consumption by hydropower alone is nearly twice that of all other electric technologies. This implies a potentially prominent role for technologies that may reduce evaporative losses at reservoirs [101,102]. Still, the uncertainty around this estimate is far greater than that of any other electric generation technologies; as such, future efforts to quantify and characterize electric sector water consumption would greatly benefit from enhanced understanding of water consumption from hydropower. Specifically, further research is needed to quantify better the base year estimates of reservoir evaporation, to attribute the losses appropriately among the multiple reservoir uses, and to incorporate the effects of climate change in future estimates of consumptive losses. Ultimately, technology-related reductions in the water use intensity of electricity production may serve to mitigate a constraint on electric sector growth, which plays an important role in economic development [103,104], and is likely to aid in addressing climate change (e.g. [98]). Reducing the water demands of the electric power sector may also benefit other water users, including natural ecosystems, particularly where water use for power production receives higher priority than other potential uses of water. Omitting future water supplies and other water demands, it is difficult to assess the significance of either the growth in water consumption observed in these scenarios, or the reductions in this growth achievable with the advanced technologies in the hitech scenarios. Still, we close by noting that water scarcity is already a significant issue affecting the power sector in many regions, and may become more important in the future, particularly if electricity generation is to expand by five times globally, and by up to twenty times in individual regions. If climate change mitigation leads to even greater electric sector growth [98], water demands may rise higher with the greater water use intensities of nuclear power and CCS (Table 2; addressed in our companion study, Kyle et al., accepted for publication, 2012). Shifts toward wet tower and dry cooling systems will reduce water withdrawals significantly, while development and deployment of water-saving technologies in power generation will reduce both freshwater withdrawal and consumption.

6. Conclusions This study analyzes global demands of water for electric power production over this century, by incorporating water demands into the reference scenario of GCAM, an integrated assessment model of energy, agriculture, and climate. The study starts by developing estimates of water demands in 2005 for electric generation technologies in each of 14 GCAM geopolitical regions. Estimates are designed to be consistent with available data on water demands of specific electric generation technologies, characteristics of existing stocks of power plants, and regional inventories of electric sector water demands. The study then focuses on the importance of three variables – base year uncertainty in the water demands of specific power plant types, the rate of change in cooling system types in the future, and

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the potential adoption of water conservation technologies – in determining the future water demands of the electric sector. This work represents the first global assessment of decade- to century water demand by the electric power sector. This study yielded three key insights. First, the water withdrawal intensity of electric power production can be expected to decrease in the near future due to capital stock turnover in the power sector. This decrease is due to both the ongoing switch from once-through flow cooling systems to evaporative cooling systems, and also to the deployment of advanced electricity generation technologies, that also tend to have relatively low cooling water requirements. It is also consistent with observed trends in developed regions in the last few decades. Second, the decrease in water withdrawal rates is accompanied by an increase in the consumptive use of water for cooling, as evaporative cooling systems typically have greater rates of water consumption than once-through flow systems. Third, a suite of water conservation technologies, currently under development, may offset the increase in water consumption that occurs with a switch to evaporative cooling systems.

Acknowledgments The authors would like to acknowledge funding support from the Integrated Assessment Research Program of the US Department of Energy’s Office of Science, and the sponsors of the Pacific Northwest National Laboratory’s Global Energy Technology Strategy Program.

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