WATER DEMANDS FOR 

EXPANDING ENERGY DEVELOPMENT 

i ·. .. .. _" : " .. --... t - '« ... ; ·••• 

WATER DEMANDS FOR 

EXPANDING ENERGY DEVElOPMENT 

By George H. Davis and Leonard A. Wood 

GEOLOGICAL SURVEY CIRCULAR 703 

1974 
United States Department of the Interior 

ROGERS C. B. MORTON, Secretory 

Geological Survey 

V. E. McKelvey, Director 

First printing 197 4 

Second printing 1 97 4 

Free on application to the U.S. Geological Survey, National Center, Reston, Va. 22092 
CONTENTS 

Page 

Abstract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 

Water demands for expanding energy development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 

Extraction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 

Transport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 

Refining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 

Conversion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 

Steam-electric generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 

Oil shale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 

Coal gasification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 

Coal liquefaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 

ILLUSTRATIONS 

Page 

Figure 1. Heat balance diagram of typical1,000-mw fossil-fueled thermal-electric plant. . . . . . . 4 

2. Withdrawal of water for major uses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 

3. Annual withdrawals of water for thermal-electric power generation in the 

United States, 1920-72 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 

4. Water consumption in refining and conversion processes . . . . . . . . . . . . . . . . . . . . . . . 13 

TABLES 

Page 

Table 1. Contingent water consumption forecasts for a 1-million-barrel-per-day shale-oil 

industry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 

2. Present and future water use in the Upper Colorado River Basin.. . . . . . . . . . . . . . . . . 10 

3. Water consumption in refining processes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 

III 
CONVERSION FACTORS 

Length 

1 inch=25.4 millimeters (mm) 

1 mile= 1.60934 kilometer (km) 

Area 

1 acre=0.4047 hectares (ha) 

Volume 

1 gallon=0.0037845 cubic meters (m3 ) 

1 barrel (42 gal)=0.15899 cubic meters (m3 ) 

1 acre-foot=1,233 cubic meters (m3 ) 

1 cubic foot=0.0283 cubic meters (m3 ) 

Mass 

1 ton (2,000 lbs)=0.907185 metric tons (t) 

Flow 

gallon per minute=0.0037854 cubic meters per minute 

(m3 /min) 

IV 

Temperature 

°C=5/9 tF-32) 

Pressure 

1 pound per square inch=0.0703 kilograms per square centimeter 

(kg/cm2 ) 

Energy 

1 British thermal unit (Btu)=0.252 kilogram calories 

1 British thermal unit (Btu)=0.000293 kilowatt hours (kwhr) 

Energy - Volume 

British thermal unit per cubic foot (gas)=O.O 1035 kilowatt 

hours per cubic meter (kwhr/m3 ) 

British thermal unit per cubic foot (gas)=8.9046 kilogram 

calories per cubic meter (kcal/m3 ) 

1 gallon (water) per kilowatt hour=0.0283 cubic meters per 

kilowatt hour (m3 /kwhr) 

1 gallon (water) per million British thermal units=0.01292 liters 

per kilowatt hour (1/kwhr) 
Water Demands for Expanding Energy Development 

By George H. Davis and Leonard A. Wood 

ABSTRACT 

Water is used in producing energy for mining and reclamation 

of mined lands, onsite processing, transportation, refining, and 

conversion of fuels to other forms of energy. In the East, South, 

Midwest, and along the seacoasts, most water problems are 

related to pollution rather than to water supply. West of about 

the 100th meridian, however, runoff is generally less than potential diversions, and energy industries must compete with other 

water users. Water demands for extraction of coal, oil shale, 

uranium, and oil and gas are modest, although large quantities of 

water are used in secondary recovery operations for oil. The only 

significant use of water for energy transportation, aside from 

in-stream navigation use, is for slurry lines. Substantial quantities 

of water are required in the retorting and the disposal of spent 

oil shale. The conversion of coal to synthetic gas or oil or to 

electric power and the generation of electric power with nuclear 

energy require large quantities of water, mostly for cooling. 

Withdrawals for cooling of thermal-electric plants is by far the 

largest category of water use in energy industry, totaling about 

170 billion gallons (644 million m3 ) per day in 1970. 

Water availability will dictate the location and design of 

energy-conversion facilities, especially in water deficient areas of 

the West. 

WATER DEMANDS FOR EXPANDING 

ENERGY DEVELOPMENT 

Much concern has been expressed recently as to 

whether water supplies will be sufficient to support 

accelerated energy development foreseen in Operation 

Independence. Taking the Nation as a whole, sufficient 

water is available for energy growth, but locally, as in 

arid parts of the Colorado River Basin, limited water 

supplies will dictate economies in water use and affect 

plant siting. As Young and Thompson (1973) point out 

with respect to electric-power generation, the term 

"water requirements" is misleading because demand for 

water for cooling is sensitive to price of water and thus is 

quite flexible rather than inflexible or fixed as implied 

by the word "requirement." Much the same is true of 

other energy-conversion systems. 

Water is used in many aspects of energy production 

including mining and reclamation of mined lands, onsite 

processing, transportation, refining, and conversion to 

other forms of energy. In the East, South, Midwest, and 

along the seacoasts, water supplies are generally adequate for energy industries; most water problems in 

those regions are related to pollution rather than to supply. West of about the 100th meridian, however, runoff 

is generally less than potential diversions, and energy 

industries must compete with other users for the limited 

available water supplies. Water is especially short in areas 

having less than 10 inches (254 mm) mean annual rainfall, generally not enough for establishing vegetation 

without irrigation. 

EXTRACTION 

The principal categories of extraction comprise coal 

mining, oil and gas production, uranium mining, and oilshale mining. 

Coal-mining water demands are modest, and include 

water for dust control, fire protection, and coal washing. 

These needs are nominal and quality is not a limiting 

factor in any of them. In areas where natural precipitation is less than 10 inches (254 mm), an additional water 

demand exists for establishing vegetation on disturbed 

areas following surface mining. The amount of water 

needed is related to natural precipitation and area disturbed and thus is highly variable. In most arid areas, 

application of 0.5-0.75 acre-ft/acre (152-229 mm) 

should be sufficient to establish seedlings that would 

survive without further water application (National 
Academy of Sciences-National Academy of Engineering, 

1973). This water must be of reasonably good quality to 

encourage plant growth (preferably less than 2,000 mg/1 

dissolved-solids concentration). Even now, water 

demands for revegetation pose serious problems, particularly in the Four Corners area of Arizona, New Mexico, 

Utah, and Colorado. 

Oil and gas extraction generally involves only nominal 

water demands for drilling, some 37,000 acre-ft 

(45.6 million m3 ) of freshwater annually nationwide. 

However, where water flooding is employed as a secondary recovery technique, somewhat larger quantities of 

water are needed to drive oil toward recovery wells. 

Where saltwater is available for this use (that is, formation waters produced with oil), it is generally preferable 

to freshwater, but in some fields freshwater is used for 

water flooding. Magnitude of use is highly variable and 

depends upon formation characteristics, but generally is 

modest compared to other energy-industry demands. 

Buttermore (1966, p. 6-8) calculated that the total 

demand for secondary recovery nationwide in 1962 was 

about 560,000 acre-ft (690 million m3 ) of which 

157,000 acre-ft (194 million m3 ) was freshwater. The 

remainder was saline water, most of which was produced 

with oil. 

Uranium mining involves water demands for dust control, ore beneficiation, and revegetation similar to coal 

mining, but tonnage handled is much less than for coal; 

thus, the total water requirements are lower. As in coal 

mining, quality of the water generally is not critical for 

these uses. Where surface mining is practiced, water 

requirements for revegetation are comparable to those of 

coal mining. 

The U.S. Atomic Energy Commission (1972, table 

S-3A) estimates that the area disturbed in surface mining 

of uranium, normalized for annual requirements of a 

typical 1,000 mw (megawatts, electric output) lightwater reactor generating station, would be 17 acres 

(6.9 hectares). The water requirement for revegetation at 

that rate would be trivial even for great increases in 

nuclear generation. For a rough comparison, it is estimated that mining for comparable energy production by 

a typical coal-fired electric plant would result in about 

10 times more land disturbance. 

Oil-shale mining is expected to become a major industry in several parts of Colorado, Utah, and Wyoming 

underlain by the Green River Formation. Shale will be 

extracted by surface mining, underground mining, and 

perhaps as an adjunct to in situ underground retorting. 

Retorting of shale mined by surface or underground conventional methods will be done on or near the mining 

site, and large volumes of loosely compacted waste will 

be produced in the retorting process. Water demands for 

2 

mining, processing, waste disposal, and land reclamation 

are intimately related. One of the largest demands is for 

compaction and revegetation of retort-plant waste which 

comprises some 40 percent of the total water use. The 

Department of the Interior's Final Environmental 

Impact Statement for the Prototype Oil Shale Leasing 

Program (U.S. Department of the Interior, 1973) estimates consumptive water demand of from 121,000 to 

189,000 acre-ft (149 million to 233 million m3 ) per year 

at a production rate of 1 million barrels (158,899 m3 ) 

per day of shale oil, or from 2.5 to 4 volumes of water 

consumed per volume of oil produced. 

TRANSPORT 

The only significant use of water in energy transport, 

aside from in-stream navigation use, is for slurry lines. 

Slurry lines have been used for many years in the eastern 

coal districts, but one of the more recent installations is 

the slurry line extending from the Black Mesa coal mine 

in northeastern Arizona to the Mojave Power Plant on 

the Colorado River at the southern tip of Nevada 

273 miles (440 km) away. A slurry line was adopted 

because the terrain made it economically attractive visa-vis rail transportation, the only other reasonable mode 

of conveyance. Another plant, the Navajo Power Plant 

(under construction) near Lake Powell is to be supplied 

from the same mine by a railroad built for that purpose. 

Water for the Mojave slurry lines is supplied by wells 

pumping some 3,200 acre-ft (3 .9 million m3 ) per year 

from a thick extensive sandstone aquifer that underlies 

Black Mesa. In this area, recharge from precipitation is 

negligibly small, and the pumped water is mainly withdrawn from storage. The power plant, rated at 1,500 

mw, consumes about 23,000 acre-ft (28 million m3 ) per 

year for cooling and other plant uses; thus, the water use 

for transport is only about one-sixth that of the plant 

consumption. At the plant the slurry water is separated 

from the coal and treated, and part is used in the plant 

water supply. 

REFINING 

Most energy fuels require some degree of refining 

before ultimate use. Some or parts of these processes are 

carried out at or near the site of extraction, that is, gas 

scrubbing, coal washing, oil-shale retorting, and uraniumore concentration. In other instances, the raw material 

may be transported to industrial centers for all or part of 

the refining process as is the case with crude oil, solvent 

refining of coal, and uranium enrichment and reactorfuel fabrication. 
The energy fuels that involve a refining process 

distinct from both extraction and subsequent conversion or consumption are nuclear fuels and oil 

(including shale oil and synthetic oil from coal), and 

are described in the following section. 

Water demands in the nuclear fuel cycle have been 

calculated by the Atomic Energy Commission {1972) 

on the basis of annual requirements of a typical 

I ,000-mw light-water reactor steam-electric plant 

operating 80 percent of the time. Of a total consumption of I63 million gallons ( 617 thousand m3 ), 65 

million gallons (246 thousand m3 ), or about 40 percent, is assigned to the uranium-ore milling stage, 

almost entirely as evaporation from tailings ponds. The 

remaining consumption of water occurs mainly in 

evaporative cooling in the uranium enrichment plant, 

which is normalized to 90 million gallons (341 thousand m3 ) annually for a 1 ,000-mw plant. The 

remaining 8 million gallons (30 thousand m3 ) is 

assigned in about equal proportions to the production 

of uranium hexafluoride and reprocessing of used fuel 

elements. Not included in the above water consumption calculations is water consumed at power plants 

supplying electricity for the enrichment process. This 

annual power requirement is estimated at 310,000 

mwhr (megawatt hours) that, if produced in a fossilfuel plant, would indicate an evaporative requirement 

of roughly 160 million gallons (604 thousand m3 ). To 

keep this demand in proper perspective, it should be 

remembered that the electrical power produced by the 

model 1 ,000-mw nuclear station annually (at 80 percent load factor) amounts to about 22 times the 

energy consumed to produce an annual fuel requirement for a 1 ,000-mw station (U.S. Atomic Energy 

Commission, 1972, p. D5). 

Water demand for petroleum refining is highly variable, depending upon such factors as process employed, 

refinery design, and cost and availability of water. 

A sampling of refineries producing 30 percent of the 

petroleum products in the United States in 1955 (Otts, 

1963, p. 299), indicated an average withdrawal demand 

of 468 gallons (1.76 m3 ) of water per barrel (42 

gallons or 0.159 m3 ) of crude-oil input. Some 90 

percent of this water was used in cooling processes at 

various stages of refining. A more meaningful measure 

of water demand, however, is the consumptive use, 

which averaged 39 gallons (O.I4 m3 ) of water per 

barrel of crude-oil input, or roughly 1 volume of 

water consumed per I volume of crude. Of this 

consumption, 7I percent was accounted for in 

evaporative cooling, 26 percent as boiler feed water, 

and the remaining 3 percent for sanitary and other 

in-plant uses. 

3 

CONVERSION 

Conversion embraces the concept of changing an 

energy raw material into a more usable form of energy. 

Examples include burning of coal, gas, or oil to produce 

electricity, or converting energy of nuclear fission to 

electricity. Other examples include changing coal or oil 

into gas, a cleaner, more convenient fuel for space heating, or even changing coal into a form of oil for further 

refining. Much of the present emphasis on conversion 

seeks to use fuels abundant in the United States, such as 

coal and oil shale, to meet the present energy crisis without sacrificing air quality objectives. Generally, this 

involves processing near the site of extraction to produce 

a nonpolluting fuel which can be transported to a distant 

market. Alternatively, the coal can be used near the 

mine to produce electricity for transport to market. 

The processes of particular interest in the present 

energy shortage are coal gasification, coal liquefaction, 

oil-shale retorting, use of geothermal energy for electric 

generation, and increased use of coal-burning plants and 

nuclear reactors for power generation. In each mode 

considerable flexibility is possible in plant design, process employed, and location of processing facilities with 

respect to site of extraction, source and use of water, 

and location of market. It is impractical, if not impossible, to assign rigid values of water use per unit of energy 

produced to all processes because of economic tradeoffs, but ranges of water demand are useful for planning 

purposes. Moreover, in electric-power generation the 

need for high fuel efficiency generally dictates water 

demand within close limits; accordingly, water demand 

for electric generation can be estimated reasonably well. 

STEAM-ELECTRIC GENERATION 

The most efficient method of meeting large steady 

electric demand (base load) is by use of a steam turbine 

to drive a generator (fig. 1). The steam may be produced 

from geothermal wells, by burning coal, oil, or gas, or by 

heat given off by nuclear fission. The power output of a 

steam turbine is greatly increased by reducing the pressure on the outlet side of the turbine. This is done by 

use of a condenser, which lowers the temperature of the 

exhaust steam, causing condensation and thus significantly reducing the pressure. The cooling capacity 

needed for the condensation phase accounts for the 

greatest consumption of water in the entire energyproduction process. 

Various systems are used for condenser coolingonce-through circulation, cooling ponds, sprayers, wet 

cooling towers, dry cooling towers, and combinations of 

the preceding systems. Once-through cooling commonly 
.j>. 

0.9xJ09 BTU/HR 

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n., ..... ,.,.,.,.:.;.:.:.:.:.:.;.:.: ..... : ... :.: .... -c~J 

IN PLANT LOSSES CONDENSATE 

0.4xJ09 BTU/HR RETURN 

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MAKEUP 

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Figure 1.-Heat balance diagram of typical 1,000-mw fossil-fueled thermal-electric plant. 
is used where the plant is near an abundant source of 

water, such as the sea, a large lake, or a large river. As 

the name suggests, water from an infinite (for practical 

purposes) source is circulated through the condenser and 

carries the waste heat away to a point of discharge elsewhere on the water body. The heat is dissipated through 

increased evaporation from the slightly warmer water 

body and by conduction to the atmosphere. 

Where no large water body is available, a natural or 

artificial pond may be used for storage and as a heat 

sink. In this mode, heat is dissipated mainly through 

surface evaporation from the warmed pond. Where the 

cooling capacity of the pond is inadequate, sprayers may 

be used to increase evaporation. Sprayers may also be 

used together with canals in once-through systems to 

reduce the impact of heated discharge on fish and other 

aquatic biota. 

Where water is in short supply or discharge of heated 

water is unacceptable, and ponds are not practicable, 

cooling towers generally are employed. In wet cooling 

towers some of the warm water evaporates through contact with an air draft, either naturally induced or driven 

by fans, thus cooling the remaining water. Dry cooling 

towers dissipate heat directly to an air draft in a fashion 

similar to an automobile radiator. Although dry cooling 

towers are effective in reducing water consumption, 

their capital cost greatly exceeds that of wet cooling 

processes, and their use results in a loss of thermal efficiency as well. They find their greatest use in cold climates and to date have seen little use in the United 

States in steam-electric power generation. 

Various combinations of these cooling techniques are 

applied to achieve maximum economy in combination 

with acceptable environmental effects. The cooling system is quite independent of the type of fuel; rather, it 

depends mainly on local factors such as availability of 

water, terrain features, and potential environmental 

impacts. 

The cooling demand, regardless of how the waste heat 

is dissipated, is governed by the thermal efficiency of the 

plant, which is expressed as electrical output as a percentage of energy input. Maximum thermal efficiency is 

achieved by use of very high steam temperatures and 

inlet pressures. In the newer modern fossil-fueled plants, 

for example, thermal efficiency of 40 percent is achieved 

with inlet temperatures as high as I ,000°F (538°C) and 

pressures of 3,500 psi (246 kg per em 2 ). 

The evaporative demand of a fossil-fueled steamelectric generator may be expressed as (Cootner and 

LOf, 1965, p. 74): 

Gallons evaporate4/kwhr=0.39 (ali- I), 

where H is overall thermal efficiency, and a is boilerfurnace efficiency (usually about 0.9). The boiler5 

furnace efficiency, normally about 90 percent, represents the fuel energy that is not lost in flue gases. The 

heat energy lost in flue gases is about 10 percent. An 

additional 5 percent of the input is dissipated to the 

atmosphere through in-plant losses and uses. Thus about 

85 percent of the input energy is used in driving the 

turbines or is disposed of as thermal waste in the form of 

warmed water. 

Present nuclear plants are less efficient than fossilfueled plants because of safety restrictions on maximum 

steam temperatures, and nuclear plants dissipate waste 

heat almost entirely to cooling water because no flue 

gases are emitted. A typical nuclear plant of 31-percent 

thermal efficiency releases about 50 percent more heat 

to cooling water than a fossil-fueled plant of comparable 

power output. 

With respect to consumption of water, geothermal 

plants are the least efficient form of steam-electric generation. Because of inherent low temperature and pressure 

of natural steam used, the geothermal plants at the Geysers Field, Calif., for example, have an overall thermal 

efficiency of only about 14 percent, the remaining 

energy being dissipated by evaporative cooling with comparably greater water consumption. The source of 

cooling water is the condensed geothermal steam, about 

80 percent being consumed in the cooling. process. The 

remaining 20 percent, which is of poor quality, is 

injected into the producing formation (Finney, 1972). 

The rapid growth of electric consumption in the 

United States in recent decades is reflected in increased 

water withdrawals for thermal-electric power. Surveys of 

water use compiled at 5-year intervals by the U.S. Geological Survey (fig. 2) show that by 1965 withdrawals by 

thermal-electric plants exceeded irrigation withdrawals, 

to become the leading class of withdrawal use in the 

Nation. This reflects not only the rapid growth of electric demand but also the fact that most plants employed 

once-through systems for condenser cooling. Concern 

over thermal pollution of water bodies, however, has 

resulted in a trend to greater use of closed evaporative 

systems employing cooling towers, ponds, or sprayers. 

Thus the rapid growth of thermal-electric withdrawal 

should level off considerably in coming decades. This 

effect, coupled with the influence of improvements in 

thermal efficiency, can be observed in figure 3. Nonetheless, consumptive use by thermal-electric generation will 

continue to grow and will increase relative to withdrawals. This seeming paradox is due to the fact that closed 

cooling systems have a greater evaporation loss relative 

to once-through systems as well as additional water consumption not applicable to once-through systems. The 

principal water economies of once-through systems are 

attributable to a greater proportion of conductive heat 
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Figure 2.-Withdrawal of water for major uses. 

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THERMAL-ELECTRIC ENERGY, IN BILLION KWHR 

Figure 3.-Annual withdrawals of water for thermal-electric power generation in the United States, 1920-72. 

loss vis-a-vis evaporative loss from natural water bodies 

than from high temperature ponds or cooling towers. 

Cooling towers, moreover, waste a small proportion of 

their water supply as drift (small droplets of water 

7 

escaping the tower without contributing to the evaporation process) and, in most cases, have additional consumption chargeable to "blowdown," disposal of poorquality waste water that cannot be returned to the 
natural system. A thorough examination of the question 

of unit consumption of water in power-plant cooling is 

not warranted here, but expert opinion ranges from 

Cootner and Lofs {1965, p. 58) observation that water 

loss from a receiving stream in once-through cooling is 

nearly the same as in a recycle system, to an estimate by 

the Water Resources Council (1968, p. 4-3-2) that 

cooling towers have consumptive use roughly twice that 

of once-through systems. These differences stem from a 

general lack of information on evaporation from open 

water bodies. Although makeup water for recycling systems can be measured directly with relative ease, precise 

measurements of evaporation from open water bodies is 

very difficult. Moreover, where water is in abundant supply, as where once-through cooling is employed, the 

question of consumptive use is rather academic. Furthermore, much of the consumption of water associated 

with once-through systems is of saline water, mainly seawater, or from the Great Lakes where such consumption 

is a small consideration. Indeed, in 1970 withdrawals of 

saline water (Murray and Reeves, 1972, p. 7) comprised 

28 percent of the total withdrawals for thermal-electric 

power. This figure itself probably is disproportionately 

low because many power plants drawing water from 

estuaries or downstream of competing users are classed 

in Federal Power Commission reports as freshwater withdrawals, although this water would soon waste to the sea 

if not used in this way. 

Consumptive use becomes a serious consideration 

only where it is in competition with other socially beneficial water consumption. Thus, the main focus on consumptive use by electric-power plants and other energy 

industries is in the West where freshwater has high value 

for alternative uses. 

The table below shows the average evaporative 

requirement of modern thermal-electric plants by various classes. In each instance, most efficient design is 

assumed. As noted earlier, water consumed per kwhr 

(kilowatt hour) is governed mainly by thermal efficiency, although the type of cooling system employed 

may also affect consumption to some degree. Little 

future improvement can be expected in fossil-fueled 

plants, which already are crowding theoretical thermalefficiency limits. Similarly, little improvement can be 

expected with geothermal systems, which are constrained by the relatively low temperature and pressure 

of the natural steam sources tapped. Nuclear generation, 

however, has a potential for significant improvements in 

thermal efficiency and water requirements. Hightemperature gas-cooled reactors (HTGR) now coming 

into use are expected to have an overall thermal efficiency of 40 percent, as are breeder reactors now being 

planned. 

The other principal types of energy conversion of concern with respect to water consumption are conversion 

of oil shale to oil, coal to gas (coal gasification), and coal 

to oil (coal liquefaction). 

OIL SHALE 

Oil shale may be mined either in open pit or in underground mines and then retorted on the surface. Belowground retorting experiments have been tried using 

several methods, but until recently in situ processes were 

not claimed to be competitive with mining and aboveground plants. However, late in 1973 one firm 

announced high recoveries of oil and lower cost for a 

combination of underground mining and in situ retorting 

in which 25-30 percent of the shale is mined and 

retorted on the surface. The remaining shale is fractured, 

collapsed into the mined-out void, and retorted where it 

lies. Although a commercial-sized plant of any kind 

remains to be built, technology may change rapidly during the next decade. 

The operators of the two Federal Prototype Leases in 

Colorado probably will use above-ground processing. 

Pilot plants have tested many methods of mining and 

above-ground and in situ retorting, but none of the 

processes has been done on a commercial scale. The pilot 

mines and plants have handled a few tons of shale up to 

as much as 1,000 or more tons (907 metric tons) per 

day; the Department of Interior's Prototype Lease 

Consumptive demand of water-cooled thermal-electric plants 

Heat Thermal Atmospheric Evaporative Gallons 

Type 1 rate efficiency dissipation Percent dissipation consumed 

(Btu/kwhr) (percent) (Btu/kwhr) (Btu/kwhr) per kwhr 

fossil fueled ............... 9,000 38 1,350 15 4,230 0.5 

Nuclear ................... 10,700 32 535 5 6,741 .8 

Geothermal ................ 24,000 14 1,200 5 19,440 1.8 

1 Most efficient design. At normal operating rates (80 percent load factor), the water consumption of these types of plants is 

approximately 15 acre-ftjyearfmw capacity for fossil-fueled, 22-acre-ftjyearfmw for nuclear, and 48 acre-ftjyearfmw for geothermal 

plants. 

8 
Program envisions mining more than 50,000 tons 

{45,359 metric tons) a day from an underground 

mine and more than 100,000 tons {90,718 metric 

tons) a day from an open pit mine. 

The oil shale must be heated to about 900° F 

(482° C) to convert the solid organic material in the oil 

shale to gas and oil vapors. The three most advanced 

retorts developed for heating oil shale are the Union Oil 

Retort, the Gas-Combustion Retort, and the TOSCO 

Retort. The first two maintain controlled combustion of 

shale within the retorts, but the TOSCO process uses 

heated ceramic balls with finely crushed shale in a 

rotating cylindrical drum. The shale oil produced by all 

these retorts is a low-gravity, moderate-sulfur, highnitrogen oil that has a high pour point and is rather 

viscous. The shale oil probably will be upgraded by 

hydrocracking, or some other process, to reduce its viscosity and make it suitable for pipeline transport to a 

refinery located where more abundant water supplies are 

available. 

The largest use of water in the production of shale oil 

is for disposal of the dry spent shale after it has been 

crushed and roasted to extract the hydrocarbons. The 

water is used for dust control while the spent shale is 

being transported (possibly as a slurry), but its most 

important use is in compacting and stabilizing the disposal pile. Spent shale that contains 20-30 percent 

water will set up like a weak portland cement. In fact, if 

the slope of the face of the pile is 18° or less, the limiting parameter on the height to which a box canyon can 

be filled is the load-bearing strength of the alluvial floor 

of the canyon. (U.S. Department of the Interior, 1973, 

v. I, p. I-42-I-43.) 

Estimates of the most likely amounts of water consumed by an oil-shale mine, retort, and upgrading plant 

of 100,000 barrels (15,899 m3 ) per day capacity of 

shale oil range from about 7,500 gpm (gallons per 

minute) (28m3 per minute or 12,150 acre-ft per year) 

to about 11,400 gpm (43m3 per minute or 18,420 acreft per year). Associated urban uses would increase the 

estimated range to 8,350-12,400 gpm (31.6-46.9 m3 

per minute or 13,400-20,100 acre-ft per year). The 

average of the high and low estimates for each use is (in 

gallons per minute): 

Processed shale disposal 

Shale oil upgrading ........ . 

Power requirements ....... . 

Retorting ............... . 

Mining and crushing ....... . 

Revegetation ............. . 

Sanitary use . . . . . . . . . . . .. . 

Associated urban .......... . 

4,500 

2,300 

1,100 

800 

550 

220 

30 

900 

Total ................ 10,400 

9 

A series of mines and plants will probably be required 

to produce 1 million barrels (158,899 m3 ) per day of 

shale oil. The Final Environmental Statement for the 

Prototype Oil Shale Leasing Program assumed a mix of 

17 mines and plants including 11 underground, 2 open 

pit, and 4 in situ mines would be needed for 1 million 

bpd (barrels per day). Based on the assumed technology mix, the Final Environmental Statement estimated 

that 121,000-189,000 acre-ft (149 million-233 million m3 ) per year of water would be consumed in 

producing 1 million barrels (158,899 m3 ) per day of 

shale oil (table 1). 

The source of water for oil-shale developments must 

be the Upper Colorado River Basin, although the initial 

mines on the Prototype Leases in the Piceance Basin in 

Colorado may develop enough ground water to satisfy 

all their water needs. A long-term, large-scale oil-shale 

industry in Colorado, Utah, and Wyoming will depend 

on diversion of stored surface water from the Colorado 

River Basin. Table 2 shows the status of water use in the 

Upper Basin. Water is available for an industry of more 

than 1 million bpd of shale oil if water not committed to 

other uses is made available to oil-shale developments. A 

much larger industry (several million barrels per day) 

would require purchase and transfer of water rights from 

agriculture to industry. 

COAL GASIFICATION 

As there are no modern-design coal-gasification plants 

of commercial scale in the United States, estimates of 

water demand must be based on research operations, 

foreign experience, and design data of projected plants. 

One of the chief sources of information is an engineering 

report of the El Paso Natural Gas Co. Burnham I Coal 

Gasification Complex planned for a site near 

Farmington, N.Mex. (Stearns-Roger Inc., 1973). The 

processes being considered for that complex, designed 

to produce 288 million scf (standard cubic feet) per 

day (8.15 million m3 per day) of pipeline-quality gas 

(954 Btu per ft 3 or 9.87 kwhr per m3 ), include coal 

gasification by the Lurgi process followed by shift conversion, gas cooling, gas purification, and methane synthesis. In simple terms, the Lurgi process produces a low 

Btu product (about 400 Btu per ft 3 or 4.14 kwhr per m3 ) 

which is upgraded by methane synthesis to pipeline quality. In various stages water is consumed in the chemical 

reaction; cooling requirements contribute additionally to 

the overall water demand. Because water is scarce in the 

region of the plant, recycling will be used to the 

maximum, and air cooling will be used insofar as 

practicable. The water input will consist of about 

7,000 gpm (26m3 per minute) diverted from the San 
Table I.-Contingent water consumption forecasts, in acre-ft per year, for a 1-million-barrel-per-day shale-oil industry 

(After table 111-6, vol. 1, U.S. Department of the Interior, 1973] 

Lower range 

Process requirements 

Mining and crushing .................................•. 

Retorting .•.........•..•..................•......... 

Shale oil upgrading ......•.•...............•..•........ 

Processed shale disposal ............................•... 

Power requirements ..........•.....................•.. 

Revegetation .......................•.....•.......... 

Sanitary use ......................................•.. 

6,000 

9,000 

17,000-21 ,000 

24,000 

10,000 

0 

1,000 

Most likely 

6,000- 8,000 

9,000- 12,000 

29,000- 44,000 

47,000- 70,000 

15,000- 23,000 

0- 12,000 

1,000- 1,000 

Upper range 

8,000 

12,000 

44,000 

84,000 

37,000- 45,000 

18,000 

1,000 

----------------------------------------------- Subtotal 67,000-71,000 

Associated urban 

Domestic use ......•.............•................... 

Domestic power ..............•.......•............... 

Subtotal 

TOTAL 

9,000-11,000 

0 

9,000-11,000 

76,000-82,000 

Ancillary development 

107,000-170,000 

13,000- 17,000 

1,000- 2,000 

14,000- 19,000 

121,000-189,000 

204,000-212,000 

17,000 

2,000 

19,000 

22 3,000-231 ,000 

Nahcolite/dawsonite . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 32,000- 64,000 

===================================== 

GRAND TOTAL .................................... . 76,000-82,000 121,000-189,000 255,000-295,000 

1 Estimates based on one or two plants; however, future markets may support three plants (see Chapter I, Section C-1-f). With 

three plants, the upper limit would approximate 327,000 acre-ft of water per year. Development above the 1-million-barrel-per-day 

level, including a commitment to develop the Naval Oil Shale Reserves, would require additional water. 

Table 2.-Present and future water use, in thousands of acre-ft per year, in the Upper Colorado River Basin 

[After table 11-4, vol. l, U.S. Department of the Interior, 19731 

Use Colorado Utah Wyoming 

Allocated share of 5,750,000 acre-ft 1 ••••••••••••••••••••••••••••••••••••••••• 2,976 1,322 805 

1970 use .........................................•...................... -1,788 -684 -304 

Committed future use .................................................... . -955 -397 -392 

Evaporation from storage units ............................................. . -342 -152 -92 

Credit for water salvage ................................................... . +121 +18 +31 

Not identified as to use 12 107 48 

Committed future use that could be made available for oil shale .................... . 2 155 3 19 

Total potential water that could be made available for depletion for oil-shale 

development4 •••••••••••••••••••••••••••••••••••••••••••••••••••••••••• 167 107 67 

Total 

5,103 

-2,776 

-1,744 

-586 

+170 

167 

174 

341 

1 Arizona received the right to the consumptive use of the first 

50,000 acre-ft per year. 2 From the existing Green Mountain and Ruedi Reservoirs and 

the authorized West Divide Project. 3 From the existing Fontenelle Reservoir-Seedskadee Project. 4 This includes water not presently identified for a particular 

use, plus water from authorized projects committed to oil-shale 

development and water from existing reservoirs not presently 

committed to a particular use. Additional water can be made 

available if the States permit the industry to purchase some of 

the water rights from those presently using water and if the use 

category is changed from some of the future commitments. 

10 
Juan River plus 765 gpm (2.89 m3 per minute) of moisture in the coal input, and 630 gpm (2.38 m3 per 

minute) produced by the methane-synthesis reaction. Of 

this total input, some 2,200 gpm (8.3 m3 per minute) 

will react to form gas, 1 ,300 gpm ( 4.9 m3 per minute) 

will be piped to the coal mine and other offsite users, 

900 gpm (3.4 m3 per minute) will evaporate from waste 

ponds, 190 gpm (0.72 m3 per minute) will leave as wet 

ash, 2,965 gpm (11.2 m3 per minute) will escape in the 

cooling system, and the remaining 840 gpm (3.2 m3 per 

minute) is accounted for in numerous small plant discharges. This represents an extreme case of water conservation as the plant is engineered so that only 15 percent 

of gross cooling requirements is met by evaporative cooling. In other areas and under other conditions water 

consumption might be considerably higher. In terms of 

annual consumption at an assumed load factor of 91 

percent, the above estimates indicate total water 

consumption of 14,000 acre-ft (17 million m3 ) per year 

of which about 2,500 (3 million m3 ) is supplied to the 

mine and other offsite uses, leaving a consumptive 

demand for the plant of about 11 ,500 acre-ft 

(14 million m3 ) per year. Of the total consumption of 

14,000 acre-ft (17 million m3 ) per year, 11,700 acre-ft 

(14 million m3 ) per year is supplied by imported water, 

1,300 acre-ft (1.6 million m3 ) per year is moisture contained in the input coal, and the remaining 1,000 acre-ft 

(1.2 million m3 ) per year is produced in the methanesynthesis reaction. 

The Synthetic Gas-Coal Task Force (1973, p. XII-3) 

calculated substantially higher make-up water demands 

for typical coal-gasification plants. The following table 

summarizes their estimates of the annual water requirements of a typical 250 billion Btu per day ( ~ 250 

million scf per day or 7 million m3 per day) plant as 

follows: 

It was assumed in the first instance that the above 

plants would be totally water cooled; the different rates 

of make-up reflect different requirements for blowdown 

which depends upon the quality of input water. The 

3-percent rate would apply to high-quality supply water 

while the 7-percent rate would apply to brackish or 

highly turbid supplies. The lower line of the table estimates water demand for in-plant use based on partial air 

cooling; the lower ranges of these estimates are comparable to the design estimates for the Burnham Complex. 

To summarize, water consumption in coal gasification 

plants producing pipeline gas of 250 million scf per day 

(7 million m3 per day) capacity can be expected to 

range from about 10,000 acre-ft (12 million m3 ) per 

year where water is at a premium to 45,000 acre-ft 

(55 million m3 ) per year where abundant but poorquality water is used for cooling. The principal differences are in evaporative cooling requirement and relate 

to the extent to which air cooling is employed and 

greater waste-water disposal where input water is of low 

quality. 

Production of low Btu gas for power-plant consumption onsite rather than high Btu pipeline-quality gas is 

considered feasible in many situations. This can be 

accomplished in essentially the way planned at the 

Burnham Complex except that the methane-synthesis 

process is omitted. As the methane synthesis does not 

play a major role in water consumption, it is believed 

that this alternative mode of gas production would have 

little bearing on consumptive demand for comparable 

Btu outputs. 

COAL LIQUEFACfiON 

Estimation of unit values of water consumption in 

producing oil from coal is tenuous at best because no 

Make-up rate, in percentage of cooling water circulation 

Process water, gpm ....................... . 

Boiler make-up, gpm ..................... . 

Cooling make-up, gpm .................... . 

Total, gpm ............................. . 

Total, acre-ft per year at 90 percent load factor .. 

Minimal demand assuming partial air cooling, 

acre-ft per year at 90 percent load factor ..... 

Bituminous and subbituminous 

3 

1,742 

396 

12,107 

14,245 

20,714 

10,358 

11 

5 

1,742 

396 

20,178 

22,316 

32,451 

16,225 

7 

1,742 

396 

28,249 

30,387 

44,187 

22,094 

Lignite 

3 5 7 

1,705 1,705 1,705 

359 359 359 

10,096 16,828 23,559 

12,160 18,892 25,623 

17,682 27,472 37,259 

8,845 13,682 16,630 
commercial-scale operations exist in the United States 

and none of several possible processes has been shown to 

be competitive with alternate fuels. Among processes 

under consideration are fhe following: Consol, solvent 

refining, H-Coal, and COED (Hottel and Howard, 1971, 

p. 161-182). Unit water-consumption estimates range 

from as little as 0.2 acre-ft (247m3 ) annually per bpd of 

synthetic-oil output to as much as 1.3 acre-ft (I ,600m3 ) 

per year per bpd capacity. The National Petroleum 

Council (1973) adopted a unit consumptive-use value of 

0.2 acre-ft (247m3 ) per year per bpd capacity. Until 

better data become available, this figure is probably as 

good an estimate as any other for planning purposes. 

The 0.2 acre-ft (247m3 ) per year per bpd capacity 

translates into 20,000 acre-ft (25 million m3 ) per year 

for 100,000 barrels (16,000 m3 ) per day of oil. 

SUMMARY 

Consumptive demand for water in various energy 

processes is summarized in table 3 and figure 4. Here 

consumption of water is compared on the basis of 

energy output in millions of Btu. The larger consumptive 

uses are associated with large cooling requirements, 

particularly in thermal-electric power generation, where 

under the best present design nearly two-thirds of the 

energy input is dissipated as waste heat, mostly through 

evaporation of water. It should be noted that figure 4 

includes both refining and conversion processes; hence, 

at least some of the fuel produced in oil refining 

becomes energy input in fossil-fueled electric generation, 

and the uranium fuel processed becomes energy input in 

nuclear-electric generation. To this extent these water 

requirements are additive in the total fuel cycle; however, much of the fossil-fuel product goes to other 

energy uses such as transportation, space heating, and 

industrial uses, and is not additive. Conversely, much of 

the electric power is not used to produce heat (measured 

in Btu's) but is used to make light or, in electric motors, 

to perform work. The work output of electric motors 

relative to input of electric current generally exceeds 

80 percent compared to the efficiencies of engines using 

fossil fuels which are generally less than 30 percent. The 

comparatively large consumption of energy and water in 

generating electricity is largely compensated for if the 

electricity is used to produce torque. 

Table 3.-Water consumption in refining processes 

Process and product 

Uranium ............... . 

Oil ................... . 

Pipeline ~s from coal ..... . 

a. Water cooling (90 

percent load factor). 

b. Partial air cooling (90 

percent load factor). 

Synthetic oil from coal ..... 

Oil from shale ........... . 

Consumptive use 

(gallons per 

106 Btu) 

14.34 

6.7 

72-158 

37-79 

31-200 

19-29 

Remarks 

Reactor fuel for 1,000 mw nuclear plant annualized 

for 80 percent load factor. Includes water 

consumed at power plants supplying electricity 

for processing. 

Average for U.S. refineries (Otts, 1963). 

Lurgi gasification followed by methanation stage. 

Product about 1,000 Btu per standard cubic foot. 

Consumption varies with amount of blowdown 

required; directly proportional to mineral 

content and turbidity of cooling supply. 

Assumes 85 percent of cooling demand met by 

nonevaporative air cooling. 

General estimate based on several potential 

processes using pressure hydrogenation 

technology. 

Includes water requirement for spent shale disposal. 

Average water consumption in electrical generation 

[Most efficient design assumed; at 80 percent load factor] 

Process 

Fossil-fueled .......................... . 

Nuclear .............................. . 

Geothermal ........................... . 

Water consumption, 

(gallons per kwhr) 

12 

0.5 

.8 

1.8 

Water consumption (gallons 

per 106 Btu of electrical 

output) 

146 

234 

527 
LITERS PER KILOWATT HOUR 

0 1 2 3 4 5 6 7 

Geothermal~~~~mm~~~~~~mm~~~~~~~~~~ 

electric 

Nuclear 

electric 

Fossil-fueled~~~...,.,....,,.,......,.. .......... 

electric 

Coal 

gasification 

Coal 

I iquefaction 

Oil shale 

Uranium fuel 

processing 

Oil refining 

0 100 200 300 400 

~Maximum 

.Minimum 

lmm 

~ Average 

500 600 

GALLONS PER MILLION BTU OUTPUT 

Figure 4.-Water consumption in refining and conversion processes. 

REFERENCES 

Buttermore, P.M., 1966, Water use in the petroleum and 

natural gas industries: U.S. Bur. Mines Inf. 

Circ. 8284, 36 p. 

Cootner, P. H., and Lof, G. 0. G., 1965, Water demand 

for steam electric generation: Resources for the 

Future, Inc., Washington, D.C., 144 p. 

Finney, J.P., 1972, Energy, research, and development: 

Statement before Subcommittee on Science, 

Research, and Development: U.S. House of Representatives, Washington, D.C., May 24. 

Hottel, H. C., and Howard, J. B., 1971, New energy 

technology-Some facts and assessments: 

MIT Press, Cambridge, Mass., 364 p. 

13 

Murray, C. R., and Reeves, E. B., 1972, Estimated use of 

water in the United States in 1970: U.S. Geol. Survey 

Circ. 676, 37 p. 

National Academy of Sciences-National Academy of 

Engineering, 1974, Rehabilitation potential of western coal lands: Natl. Acad. Sci., Washington, D.C. (In 

press). 

National Petroleum Council, 1974, Report of the Water 

Availability Task Force: Natl. Petroleum Council, 

Washington, D.C. (In press). 

Otts, L. E., Jr., 1963, Water requirements of the petroleum industry: U.S. Geol. Survey Water-Supply 

Paper 1330-G, p. 287-340. 

Stearns-Roger Inc., 1973, El Paso Natural Gas Company 

Burnham I coal gasification complex (Stearns-Roger 
Job No. C-10450): in Second supplement of application of El Paso Natural Gas Co. for a certificate of 

public convenience and necessity: Federal Power 

Comm. Docket No. CP 73-131. 

Synthetic Gas-Coal Task Force, 1973, Final report of 

the Supply-Technical Advisory Task ForceSynthetic gas coal: Federal Power Comm., Washington, D.C., 172 p. 

U.S. Atomic Energy Commission, 1972, Environmental 

survey of the nuclear fuel cycle: Atomic Energy 

Commission, Washington, D.C., 309 p. 

14 

U.S. Department of the Interior, 1973, Final 

environmental statement for the prototype oil shale 

leasing program: Dept. of Interior, Washington, D.C., 

6 vols. 

Water Resources Council, 1968, The Nation's water 

resources, the first national assessment: Water Res. 

Council, Washington, D.C., 419 p. 

Young, H. P., and Thompson, R. G., 1973, Forecasting 

water use for electric power generation: Water Res. 

Research, v. 9, no. 4, p. 700-807 . 

.':u.s. GOVERNMENT PRINTING OFFICE 1974-543-586/ 147