WATER IS A CRITICAL INPUT for energy. Overall, about 15 percent of the water the world currently uses goes to making energy in one form or another.1 While most people are aware that water is used directly for generating power in hydroelectric turbines at dams, it is often overlooked how important water is for other parts of the energy sector. For example, water is used in the extractive industries for producing fuels such as coal, uranium, oil, and gas. In addition, water is an input for energy crops such as corn for ethanol or biomass for fuel pellets. Water is also a critical ingredient for the power sector as a coolant that increases the efficiency of power plants. Generally speaking, water improves the energy sector, which is great news. It also sets the energy sector up for vulnerability in the event that water is not available the way planners expect.
Globally, hydroelectric power is the largest source of nonthermal generation in use (the other common options being solar panels and wind turbines), accounting for over 16 percent of generation.2 Thermal generation (also known as thermoelectric generation), which uses heat to boil water into steam or to pressurize other gases to spin a turbine, makes up almost all of the rest. Hydroelectric is a powerful, efficient, and reliable source of energy—as long as it has water. The water use implications of hydroelectric power differ significantly from thermal generation because it does not withdraw or consume water for cooling. Instead, hydroelectric facilities use the force of gravity to pass water through turbines to generate electricity.
The typical design is pretty straightforward: a dam is built to create a large reservoir of water with a significant elevation differential. The elevation difference between the water behind the dam and the river downstream of the dam creates potential energy that can be converted to mechanical energy (m) from rotating turbines that can be converted to electrical energy (e) from the spinning magnets within a generator.
Water can be used to generate electricity. In a hydroelectric facility, falling water spins turbines that are connected to generators. Usually a dam is built to create a reservoir of water at a higher elevation than the river below.
The power output of the system is a product of the height difference through which the water falls and the volumetric flow rate of the water. Large volumes of water falling long distances at a high rate of speed generate a lot of power. The hydroelectric turbines rotate on a vertical axis, like a merry-go-round. And they are large devices. Water falls through the curved blades, forcing them to rotate a shaft that is attached to a generator.
Hydroelectric turbines are very efficient, especially compared with conventional power generation options. [U.S. Army Corps of Engineers: Institute for Water Resources, Hydropower: Value to the Nation, Fall 2001]
The process is very simple, and consequently dams are highly efficient: they can usually achieve nearly 90 percent or higher conversion efficiency from the potential energy of the elevated water to electrical energy at the powerhouse.3 This performance is much better than the 30–40 percent efficiency that is typical for conventional thermal power plants, and still one and a half times better than the most efficient, state-of-the-art natural gas power plants that combine steam turbines and gas turbines in a sophisticated fashion to achieve 60 percent efficiency. One of the key advantages noted before is that solar energy does the heavy lifting for us, raising water to high elevations from evaporation, after which we can harness the free force of gravity on the way back down.
Hydroelectric power plants can be absolutely massive, both in area and power generation. The largest power plant in the world, the Three Gorges Dam in China, has a capacity of 22 gigawatts, about the size of twenty or more nuclear power plants. It is so large, the mass of the water in the reservoir slowed the earth’s rotation. By putting nearly 40 billion tons of water elevated to hundreds of meters above sea level, the dam has essentially made the earth a little fatter in the middle and flatter at the top, extending the day by six-hundredths of a microsecond.4 The gargantuan Hoover Dam, which is famous as one of the world’s first major dams and for its proximity to Las Vegas, is only 2 gigawatts by comparison. If the water supply is reliable, large dams can be used for baseload power. But hydroelectric power plants also have the ability to be quickly turned on and off, which gives them great operational flexibility. That means they can also be used to meet peak load or to firm up the power grid.
Because the construction of large dams has such a large impact on ecosystems, building new ones is contentious in most developed countries. While efforts to build major dams are still under way in Asia and South America, increasing hydropower generation in the United States and Europe faces a lot more resistance. Getting public approval for new sites can be quite difficult.
Consequently, for the United States, smaller-scale opportunities, known as “small hydro” or “microhydropower,” or addition of hydropower at existing facilities that otherwise do not generate electricity have a better likelihood to be built.5 The U.S. Department of Energy’s Oak Ridge National Laboratory in 2012 determined that 12 gigawatts of new power generating capacity can be installed by adding powerhouses to some of the eighty thousand dams in the United States that are used for storing water, controlling floods, and managing navigable waterways, but do not make electricity. The existing fleet of twenty-five hundred hydroelectric dams has a total capacity of 78 gigawatts, so simply adding turbines to these nonpowered dams could expand hydropower capacity by 15 percent or more. Just one hundred dams of those eighty thousand could be used to add 8 gigawatts of capacity, which is similar to eight nuclear power plants. Because these nonpowered dams have already incurred many of the construction costs and ecosystem impacts, adding power to the existing dam site is often a faster, less expensive, and less controversial way to expand hydropower than creating new reservoirs that displace people and flood ecosystems.
Because smaller dams can be just a few feet tall, reminiscent of beaver dams, they are less disruptive. They can be built deep in the woods without flooding valleys or blocking fish migration, and generally keep their impact to a minimum. Smaller dams face less opposition and permits are easier to obtain. There are also run-of-river designs with the turbines laid along the riverbed without a dam at all, instead just harnessing the currents. Experiments with these designs have been conducted in the East River in New York City. Enclosed versions can be inserted into downhill pipes like those in the California aqueduct. As water flows downhill inside the pipes, turbines spin, generating electricity. These versions are termed hydrokinetic, as they take the kinetic energy out of the flowing water to make electricity.
Then there are the ocean-based systems. The headline-grabbing ones include wave power and tidal power. Waves are continuous, driven by the wind with a force that beachgoers would easily recognize as powerful and unstoppable. Designs have emerged over the years to capture this energy. They include space-age-looking devices such as buoys with pistons inside that float up and down, gates that rock back and forth underwater on the ocean floor, snakelike contraptions that twist back and forth with the waves, and turbines-in-tubes at the ocean’s edge that spin back and forth as water rushes in and out. The ultimate resource is large, globally, but expensive to harness as the waves themselves beat up the equipment and the saltwater is corrosive. Ultimately, turning wave power into a massive power source will include lining our coasts with hundreds of miles of these power plants, which is likely to be implausible given concerns about the possible effects on the marine environment.
Tidal energy is also appealing. Driven by the moon’s gravitational pull, which conveniently raises the oceans several feet twice daily, this renewable resource does not deplete. And the technology is the same as for conventional hydropower, so this resource is reliable and simple. But the falling water is available only at certain times of the day and it requires good elevation gain between low tide and high tide. Those conditions happen in just a few places around the world—Nova Scotia and off the northern coast of France are two famous sites. That means the potential for tidal energy is not quite as universal as one might anticipate.
Other ocean-borne designs include Ocean Thermal Energy Conversion (OTEC) and salinity gradients. OTEC devices have a design a century old, exploiting the temperature difference between the relatively warm ocean surface and the cold ocean depths to drive a power plant. Differences in salinity at the mouth of rivers where freshwater mixes with the ocean can be used with osmotic membranes to create a flow of water to generate electricity. While that sounds promising, early Norwegian experiments were only able to generate enough power for a lightbulb. Undeterred, in late 2014 the Dutch announced a trial of similar technology with the hope of making it financially viable by 2020.6
Although hydropower does not require water for cooling like thermal generation, it is often considered a highly water consumptive technology due to the large volumes of water evaporated from the surface of reservoirs behind dams that house turbines.7 The increased surface area of man-made reservoirs beyond the nominal run-of-river accelerates the evaporation rates from river basins. Notably, the estimates for this increased evaporation depend significantly on regional location. Major dams in the desert Southwest of the United States are especially prone to water loss from evaporation. Dams in cooler, wetter climates do not lose water as quickly (or at all). Furthermore, whether all the evaporation should be attributed to power generation is not clear, as reservoirs serve multiple purposes, including water storage, flood control, and recreation.
In addition to direct power generation through hydroelectric turbines, water indirectly enables power generation through the cooling it provides for power plants that use heat to make steam that drives a steam turbine. Overall, about 75 percent of the world’s power plants use heat to make power. And those hot power plants need cooling to protect equipment and to make them more efficient. That amounts to a lot of cooling water. In exchange, the thermal power plants heat the water up before it is returned to the source.
Overall, the power sector is the single largest user of water in the United States, responsible for nearly half of all water withdrawals (a little more than 160 billion gallons per day, when including seawater), withdrawing even more than agriculture.8 When considering only freshwater withdrawals, the power plants and agriculture withdraw about the same amount, roughly 115 billion gallons per day. Although agriculture uses significant volumes of groundwater and surface water for irrigation, the power sector primarily uses surface water. The mining sector, which includes the extractive industries for fuels production, requires another 5 billion gallons per day, and the industrial sector, which includes refineries and other facilities for upgrading fuels, is responsible for another 16 billion gallons per day of withdrawals.
Despite the power sector withdrawing the most water, the agricultural sector consumes the most. A vast preponderance of the water that is withdrawn for power plants is returned to the source, though at a different temperature and quality. The amount of water that is withdrawn and consumed by thermal power plants is driven primarily by a mix of factors including the fuel (coal, gas, nuclear, etc.), turbine design, cooling technology, and local weather. Nuclear power plants are particularly water intensive because, unlike power plants fueled by coal or natural gas, they cannot shed any waste heat to the atmosphere through smokestacks. Nuclear power plants don’t have any emissions, so all of their waste heat has to be dumped into waterways.
The three most common cooling methods are open-loop, closed-loop, and air-cooling. On average across the thermal power sector in the United States, about fifteen gallons of water are withdrawn and just under one gallon consumed for every kilowatt-hour of electricity that is generated. Because typical homes in the United States use about twenty to forty kilowatt-hours of electricity each day, approximately three to six hundred gallons of cooling water are required to make electricity for those homes. That same home might use 150 gallons per day for washing, cooking, drinking, and watering lawns. That means we use two to four times more water at home for our lights and outlets than our faucets and showerheads.
Open-loop or once-through cooling withdraws large volumes of fresh and saline surface water, passes it through the power plant for one-time use, and returns nearly all the water to the source with little of the water being consumed due to evaporation. While open-loop cooling is energy efficient and low in infrastructure and operational costs, it has water impacts. The water intake systems at power plants can entrain and impinge aquatic life, also doing damage. Entrainment is the withdrawal of fish and aquatic organisms from the environment into the power plant facility. Impingement is the pinning of fish and aquatic organisms against water intake screens.
In addition, the discharged water is warmer than ambient water, causing thermal pollution, which can kill fish and harm aquatic ecosystems. As a result, environmental agencies regulate discharge temperatures, taking into account a water body’s heat dissipation capacity. If power plant operators return the water above their approved temperature, they could be fined.
Closed-loop cooling towers are familiar as large, concrete inverse parabolas with white clouds of water vapor escaping out the top. People often associate them with nuclear power plants, but they work with other plants, too. Cooling towers withdraw water then recirculate the water until it evaporates, which has a cooling effect. Because the cooling is essentially achieved through evaporation, closed-loop cooling causes higher water consumption.
The need for such large amounts of water at the right temperature for cooling introduces vulnerabilities for the power plants. If a severe drought or heat wave reduces the availability of water or restricts its effectiveness for cooling due to thermal pollution limits, the fact that the power plant consumes so little water becomes less important than the fact that it needs the water in the first place.
Power plants constructed before the 1970s almost exclusively used open-loop cooling designs, which have very high water withdrawals. When these power plants were built, water was perceived as abundant, and environmental regulations were practically nonexistent. During the 1960s and 1970s, environmental concerns about water increased, kicking off an era of regulatory pressure to reduce water use at power plants. One of the key pieces of legislation was the Clean Water Act (1972), which established the framework for regulating discharges of chemical and thermal pollution into the waters of the United States.9
The Clean Water Act outlawed the unpermitted discharge of any pollutant from a point source into navigable waters. Point sources—discrete locations such as pipes or man-made ditches—are regulated by the Clean Water Act, but broader sources of pollution such as runoff over a wide area including farms and other agricultural operations are not. While homes do not generally need a permit for their wastewater flows into the sewers or septic systems, industrial, municipal, and other facilities must obtain permits for their discharges that go to surface waterways. In this way, the Clean Water Act regulates discharges from power plants. It also regulates intake requirements. Power plants built since then have almost exclusively used closed-loop designs with cooling towers as a way to serve many environmental interests by greatly reducing the entrainment and impingement of aquatic wildlife and reducing thermal pollution by limiting hot water returns.
Open-loop cooling withdraws more water, but consumes less. Closed-loop cooling towers withdraw less, but consume more. Which of these two options is “better” can depend on local prevailing circumstances. However, the conventional wisdom implies that cooling towers have less of an impact than open-loop cooling systems.
Today, 43 percent of U.S. thermal power plants are large power facilities with generation capacity of over 100 megawatts. Of these large power plants, 42 percent use closed-loop cooling towers and just over 14 percent use cooling reservoirs. Just under 1 percent use dry cooling, which is also known as air cooling, and the remaining 43 percent of these large power plants use once-through cooling.10 Most of those plants with once-through cooling systems were built before the Clean Water Act was enacted or were grandfathered in once the legislation was passed. Many of these plants, built before strict emissions controls, are decades old and are simultaneously dirty and thirsty. Whether they should be shut down in exchange for newer, cleaner, leaner plants remains a hotly contested public policy debate.
Moving forward, new hybrid and dry systems might see greater implementation because of looming regulatory requirements and competition for water. For example, the California State Lands Commission proposed a moratorium on construction of new power plants with open-loop cooling systems on the coast. That clashes with a separate effort to push power plants to coastal regions where open-loop cooling can use seawater to spare inland freshwater.11 In other words, environmental concerns about oceanic wildlife are in direct conflict with environmental concerns about inland freshwater supply. Conservation, efficiency, and the use of alternative, water-efficient options can meet those competing environmental objectives simultaneously.
More water-efficient cooling technologies exist; however, these systems have drawbacks. Dry-cooled systems operate like radiators in automobiles: a coolant is circulated within a series of closed pipes and air blows over it to cool the pipes. Air-cooled systems withdraw and consume less than 10 percent of the water of wet-cooled systems.12 However, dry-cooling systems have higher capital costs and reduce overall efficiency of the plant, which increases costs and emissions per unit of electricity generated. Because the heat capacity of air is so much lower than water, much more air has to be moved to achieve the same cooling as with water. That means much larger facilities are needed to create the larger cooling surfaces in dry-cooling systems, which dramatically increases capital costs. Furthermore, a power plant with dry cooling can experience a 1 percent loss in efficiency for each degree increase of temperature, limiting power generation when it is hot outside.
Because they include both closed-loop wet systems and dry-cooling equipment, hybrid wet-dry cooling systems provide a compromise between wet- and dry-cooling systems.13 Hybrid wet-dry cooling systems can have low water consumption for much of the year by operating primarily in dry mode, but have the flexibility to operate more efficiently in wet mode during the hottest times of the year when the extra cooling gives a boost in the power output from the plant. Unfortunately, water resources are typically less available during these peak demand times. Although dry- and hybrid cooling systems are proven technologies and useful solutions in water-strained areas, they usually are not economically competitive designs if water is cheap and available. And, in severely water-constrained regions, dry cooling is often the only alternative. In such cases, the up-front capital costs and reduction in the power plant’s efficiency are more readily justifiable.
In addition to the water needs for hydroelectric power and for cooling conventional thermoelectric power plants fueled by coal, natural gas, and nuclear, the other forms of renewable power—solar, wind, geothermal, and biomass—also need water for their operation. The range of water they need varies dramatically.
Renewable electricity technologies such as wind turbines and solar photovoltaic (PV) panels do not use heat to make electricity, so they do not need cooling water. They need small volumes of water for manufacturing components at the steel mill where the turbine parts are fabricated or the semiconductor factory where the solar panels are printed, and they also use water for cleaning equipment in the field. Other than that the water needs are minimal.
The heat-based forms of renewable power—such as concentrating solar power (CSP) that uses mirrors to focus solar beams onto a central location to boil water, enhanced geothermal systems that use the heat of the earth, and biomass-powered plants that burn wood chips—all need water for cooling. The challenge with solar thermal plant systems is that areas that provide the best sunshine for CSP are typically dry and hot—think southern Spain and the American desert Southwest. As Roger Duncan, the former general manager of Austin Energy, is fond of saying, “What a solar thermal power plant needs to be effective is a desert with a lot of water.” The conundrum of this situation is challenging. Although dry-cooling technology can be coupled, doing so introduces efficiency losses, particularly on hot days. Nonetheless, some solar companies have committed to dry cooling to avoid the political, availability, and environmental barriers posed by citizen concerns over water issues. These new systems demonstrate the feasibility of dry-cooling technology for large-scale systems and might be indicators of a new trend in electricity.
Geothermal power plants utilize naturally occurring heat belowground to create steam and generate electricity. They work best in locations near volcanic activity, such as Iceland and the mountain West of the United States. However, much of the global geothermal resource is deep dry hot rock that does not hold enough water to drive steam-powered turbines. That means water has to be added. Enhanced geothermal systems exploit the dry hot rock by injecting large volumes of water down into fractured rock from an external water supply at the surface. The injected water absorbs the geothermal heat and is pumped to the surface to power the steam cycle. The same water volume is then injected back into the rock to form a closed-loop system. However, because of lower operating temperatures and losses during the round trip from the surface, geothermal systems need more water than nuclear or solar thermal power plants.
Electricity generation from burning biomass like wood pellets or trash requires the use of similar amounts of cooling water as coal- and nuclearfueled thermoelectric facilities, as the power generation process is very similar. Beyond the water needed to cool the power plant, water is also needed to develop the fuel.
The power sector is not the only part of the energy supply chain that needs water: water is also needed to produce fuels, including the growth, mining, extraction, and refining of fuels. There are several ways to think about the water intensity of fuels. We can think about the water needed per gallon of fuel. Or the water needed per unit of energy. But both notions are problematic. Failing to establish our metrics clearly can confuse public policymaking, which can lead to bad outcomes.
Speaking in rough orders of magnitude, it takes roughly one gallon of water per gallon of gasoline from conventional petroleum, one thousand gallons of water per gallon of ethanol from irrigated corn, and one hundred thousand gallons of water per gallon of biodiesel from algae.14 While these ratios are easy to contemplate, they skip some key aspects. In particular, they do not consider the differences in energy density or the type of water. A gallon of ethanol has roughly two-thirds the energy of a gallon of gasoline, so treating both gallons the same is misleading. And algae can grow in saltwater, which is abundant, so maybe it does not matter how much water it requires.
And what about natural gas and hydrogen, two gases whose energy density per gallon varies for different pressures and temperatures? Pipelinequality natural gas in the United States at standard conditions (standard temperature and pressure, which is zero degrees Celsius and normal pressure at sea level) has a density of about one million Btu per thousand cubic feet. Compressed natural gas is typically stored at a pressure 200 to 250 times higher than at sea level, which means compressed natural gas requires less than 1 percent of the volume it would require at standard conditions. Liquefied natural gas is cooled to —162 degrees Celsius, after which it occupies a volume that is less than one six-hundredth of gas at standard conditions. Comparing the volume of water per volume of natural gas can lead to ambiguities, as the volumetric energy density of natural gas varies so much, depending on its storage conditions. Hydrogen has a similar problem. Hydrogen has the same energy content as gasoline when compressed to seven hundred times the pressure at sea level. However, uncompressed, the same volume has a much lower energy content.
Finding comparable measurements complicates matters further: a “gallon” is a clumsy or irrelevant metric for electricity. Water matters for electric vehicles since they are becoming more popular and power generation requires so much water. But what is a gallon of electricity?
We could instead express water intensity in terms of gallons of water per unit of energy. Doing so is more precise than the volume-to-volume approach since the energy density variations from gasoline to ethanol, natural gas, and hydrogen can more easily be accommodated. The energy content of electricity can also be incorporated, despite having a nonobvious volume.
While this approach is indeed an improvement, it still falls short because it fails to include the variations in conversion efficiency for the different fuels in the engines and motors that drive our cars. An internal combustion engine has a typical efficiency range of 15–30 percent. Motors that propel electric cars have a typical efficiency of 80–90 percent. That means, even the water-per-unit-of-energy metric is not perfect, as it fails to capture the fact that electrical energy takes a car three times further than a gasoline car per unit of energy. It is better to think about the water needed per unit of energy service that is provided: per mile traveled in a car, or per unit of heating or lighting, for example.15 Switching our thinking from miles per gallon (of gasoline) to gallons (of water) per mile would be a clearer indicator of the water intensity of transportation fuels.
Beyond these simple ratios, it is also important to distinguish the water needs at various stages of the life cycle of fuel production and use. These stages include production, upgrading, transport, and end-use. Production is the point of extraction for oil and gas; mining for coal and uranium; or photosynthesis for biofuels. Upgrading includes refining to turn crude oil into gasoline, jet fuel, or diesel; biorefining to turn corn or sugar into ethanol; and enrichment to turn ore or yellowcake into enriched uranium. For oil and gas, water is used to release the fuels out of the ground by waterflooding of conventional reservoirs, steam-assisted gravity drainage for the Canadian oil sands, or hydraulic fracturing of shale formations. Water is used again both as an input chemical and to make steam at the refinery. For biocrops, water is used for irrigation and to make steam for fermentation. For coal mining, dewatering often has to occur before the coal can be removed. Water is also used to control dust at coal mines. For uranium, water is used in mining to leach out the desired minerals and then to cool the power plants that provide the electricity for centrifugal enrichment.
In addition, water is used as a process input and a feedstock for process steam at refineries to upgrade the crudes into higher-value products. Typical volumes of water that are needed end-to-end for petroleumbased fuels from extraction through refining are approximately three to four gallons of water per gallon of fuel.16 For natural gas, the volumes of water are approximately six to twelve gallons of water per gallon equivalent of oil.17
Generally speaking, unconventional oil and gas production sites are more water intensive than conventional oil and gas production. For oil sands production in Canada or heavy oil production in Venezuela, water is used to make steam to make the sticky, heavy oils flow out of the wells more easily. Water is also a critical input for hydraulic fracturing, during which jets of high-pressure water are injected into shale formations to cause fractures that increase the permeability of the reservoir.18 Typical injection volumes are 2–9 million gallons per well of injected water.
Along with the millions of gallons of water, approximately one half million pounds of sand are included as “proppants” that hold the cracks open to increase gas flow.19 In addition, chemical additives such as acids, surfactants, biocides, and scaling inhibitors are used to increase productivity. The typical composition of frac fluids is 98 percent sand and water, and 2 percent chemical additives. As producers become more water-efficient, using less water per well, the relative fraction of chemicals increases. That actually invites an environmental conundrum: using less water is an environmental objective, but the use of more chemicals makes many environmentalists uneasy. And higher fractions of chemicals, in particular gels and acids, are used for shale formations that produce a lot of liquids along with the gases.
One story about a boomtown in Texas recounted the following anecdote about what might be witnessed at a local bar: “Many’s the time you’d see a man come in, order a quart of whisky poured in a bowl and go to washing his face and hands. Damned good reason for that: water had to be hauled miles and it cost like blue blazing hell. . . . It took many hundred barrels of water to drill a well those days . . . but water cost three dollars a barrel.”20 That story is not from the shale boom in the 2010s—it was about the oil boom in Burkburnett, Texas, written for a story in Cosmopolitan in 1939. Water has always been expensive for oil and gas booms, so the modern shale frenzy might not be that different after all.
A significant fraction of the injected fluids comes back out of the wells as wastewater, including drilling muds, flowback water (which is the portion of the injected frac fluids that are returned), and produced water (which is the naturally occurring water in the reservoir that gets brought up through the well). The volumes can range from 15 percent to 300 percent of the injected water, depending on the geological characteristics of the formation. That means some wells return more water than was injected, whereas other wells keep most of the water downhole. Overall in the United States, about seven or more barrels of water are handled, produced, or injected for every barrel of oil that is produced. That means oil and gas companies are really water companies who happen to have high-value byproducts, namely, the oil and gas.
Unfortunately, produced water usually has very high salinity and is difficult to treat. Underground injection into saline aquifers is one disposal method, though the water can also be treated and reused. In Texas, there are abundant injection sites, which makes disposal relatively easy. By contrast, in the Marcellus Shale region of the northeastern United States, the wastewater must be treated or trucked elsewhere as pipelines, treatment plants, and injection sites are limited in availability. The wastewater could also be shipped to more distant disposal sites, which requires energy for transport and introduces risks of accidental spills along the way.
In many cases, the produced water volumes far exceed the volumes of fuels that are produced, making wastewater disposal a potential constraint on production. Wastewater injection is common in areas like Texas and Oklahoma that have a lot oil and gas production. The waste fluids are injected at high pressures deep underground to keep them sequestered out of the hydrologic cycle.
However, doing so can induce seismicity, which is a scientific way to say “cause earthquakes.” They happen when the wastewater, pumped at very high pressures and high flow rates, is injected at a fault, pressurizing and lubricating the fault, then triggering an earthquake. In 2014, because of significant oil and gas activity and wastewater disposal that goes along with it, the state of Oklahoma was the most seismically active of the fifty states, exceeding even California.21 Unfortunately, those earthquakes take place in the middle of the country, where seismic codes for buildings are weak or nonexistent. It didn’t take long for residents in Oklahoma and northern Texas to notice that the rise in earthquakes and nearby hydraulic fracturing were related, though regulators, under significant pressure from industry, seemed reluctant to connect the dots. In 2015, the U.S. Geological Survey linked those earthquakes to the underground injection of wastewater from oil and gas production.22
The earthquakes became so frequent, along with other concerns about the rise of shale production, that the citizens of Denton, Texas, a conservative city that is supportive of the oil and gas industry, overwhelmingly passed a referendum to ban fracking in the city in fall 2014. In response, in 2015 the Texas legislature, backed with a lot of campaign donations from the oil and gas industry, changed the laws to prohibit cities from passing such bans.
Buying, trucking, injecting, and disposing of the water costs a lot of money for oil and gas operators. A large drilling pad with multiple wells might cost $10 million to complete; up to 10 percent of the cost can be for water management. In an arid climate enduring an oil and gas boom, water is precious, so water prices can escalate. During the shale boom in the 2010s in Texas, water prices for hydraulic fracturing increased a hundredfold.23
The mining for uranium and coal can have significant impacts on water quality. Underground abandoned mines affect groundwater because water flows through the mines, picking up contaminants before traveling onward to aquifers. Surface mines, in particular mountaintop removal mines, also affect water quality because of the topographic disturbances that push soil and other mining residue into waterways. In addition, ponds and other impoundments are often used to store waste from coal-mining operation and ash from combustion at the power plants. When those impoundments fail, the pollutants move into waterways.
It is not just the fossil fuels that require water and impact water quality: biofuels have the same issues. Because biofuels are grown domestically and take carbon dioxide out of the atmosphere during growth, they have received a lot of policy support and interest. The most common forms of bioenergy include liquid fuels like ethanol for transportation and solid fuels like wood pellets for the power sector, though biogas (a renewable form of natural gas) can also be produced and used for those same applications. The water needs for growing biofuels vary widely depending on what is grown, where it is harvested, and whether or not it requires irrigation. Some biomass sources, such as forest trimmings and pulp and paper industry waste, use only natural precipitation for biomass growth. In contrast, dedicated energy crops and crop residues often come from irrigated lands with large volumes of human-applied water in addition to natural precipitation.
Although refineries need just a few gallons of water to produce a gallon of fuel from crude oil, biorefineries turning corn starch into ethanol consume three to ten gallons of water per gallon of ethanol, mostly as a source of steam for fermentation. Producing ethanol from Brazilian sugarcane consumes twelve to twenty-four gallons of water per gallon of ethanol.24 While those numbers are greater than for petroleum-based fuels, this water consumption is just one part of the life cycle for biofuels. Notably, in the United States, fossil fuels are often used to create the steam at the biorefineries, which means biofuels are more carbon intensive and fossil-fuel dependent than many people might expect. Because biorefineries produce tens to hundreds of millions of gallons of fuel each year, they consume hundreds of millions of gallons of water per year, creating a localized impact and competition with other water users.
In addition to the water used for fermentation at the biorefinery, both irrigated and nonirrigated biofuel feedstocks need significant amounts of water to grow, on the order of several hundreds to low thousands of gallons of water per gallon of fuel. Whether the water is “counted” depends on whether the water was from irrigation. By convention, if the water was provided by rainfall, then governmental inventories do not include the water in their accounting. In actuality, the nonirrigated biofuels also need water for the growth phase, but we simply do not count it. However, that water is taken out of the system from other purposes and might also be worthy of tracking.
Unlike the oil and gas industry, which can use saline water for injection into wells, photosynthesis of traditional energy crops uses freshwater. For irrigated U.S. corn in 2003, the average irrigation withdrawal was nearly eight hundred gallons of water per gallon of ethanol. Soybeans are a little less water intensive than corn. For irrigated U.S. soybeans, the average irrigation withdrawal was approximately five hundred gallons of water per gallon of fuel. It is worth noting that trade associations and other advocates for the renewable fuels industry conveniently leave out the water intensity of crop growth and fossil-fuel dependence of biorefineries in their promotional materials, instead focusing on how biorefining is not that much more water intensive than traditional fuels.
Generally, the impact of growing biofuels is lower in water-rich regions, where irrigation is not necessary. For example, the vast majority of biofuels produced in Brazil are from rain-fed sugarcane, decreasing the irrigation water requirements for ethanol production. Brazilian ethanol production also uses the waste biomatter—bagasse from the sugarcane, rather than coal or natural gas as the fuel in the biorefinery—to ferment the sugar into alcohol. In addition, sugarcane cultivation in Brazil does not cause topsoil erosion the way corn does in the United States. In fact, sugarcane has been grown in the same location without loss of topsoil since the early 1500s, when it was introduced to Brazil by Martim Afonso de Sousa. Sugarcane also produces more feedstock per acre, which means it needs less water per unit of energy produced. Overall, these factors suggest that sugarcane might be a sustainable option for Brazil.
Second- and third-generation biofuels, like lignocellulosic crops (switchgrass, wood chips) and harvesting of forest residues, are appealing because they presumably do not require irrigation, might be compatible for growth on degraded lands, and are not expected to trigger soil erosion. However, they might need much higher energy inputs at the biorefinery to convert from cellulose to starches than sugars. Algae has also been identified as a high-potential advanced biofuel. It needs even more water than corn, soy, or sugar, but that water can be saltwater or wastewater effluent, which means we might not care how water intensive it is.25
Getting energy to market also requires water, with barges along inland waterways and ships on the oceans moving crude and finished energy products from source to market. In particular, barges are used extensively for shipping coal and refined petroleum products, especially in the United States along the Mississippi River. China moves even more tonnage by its inland rivers. That means extended drought that lowers the water levels of the Mississippi or Yangtze Rivers puts supplies at risk for power plants that receive their coal by barge.
The oceans are also used for moving the world’s fuels. Of the world’s approximately 90 million barrels of daily oil consumption, 55 million are traded across country boundaries.26 A significant fraction of that is shipped by supertankers over oceans, with the rest of it moving by pipeline. Each supertanker can hold up to 2 million barrels of oil. Of the 55 million barrels per day of petroleum trade across boundaries, about 38 million barrels of it is crude and the remainder is refined products. Moving oil by ship exposes the oceans to water quality risks from spills that can occur when ships run aground or are attacked. Because the petroleum is also liquid, it disperses quickly, spreading across large areas. Unfortunately, there have been many famous oil spill incidents over the years.
In addition, trillions of cubic feet of liquefied natural gas (LNG) moves each year across the oceans in specialized ships that have spherical containers designed to keep the liquefied gas cold so it stays in liquid form. Before operators load the fuel onto the ship, multibillion-dollar liquefaction facilities that use a lot of energy cool down the natural gas to make it a liquid so that it can be exported more easily, as liquids are denser than gases. The ships arrive at multibillion-dollar gasification facilities designed for import. Along the way to its destination, some of the liquefied cargo boils off, and that gas powers the ships.
Once the LNG arrives at its destination, it might need even more water. Unlike power plants that use water as a coolant, large LNG facilities can use water as a source of heat. For example, there is a facility in the Adriatic Sea that takes very cold LNG from Qatar and turns it into gas. To do so, it uses the heat of the ocean. To make LNG, liquefaction facilities cool the gas to a temperature lower than —162 degrees Celsius, at which point the methane liquefies. Even though the ocean is cold, the LNG is even colder, and that means the water in the Adriatic Sea can be used as a source of heat for boiling the LNG from liquid to the gas phase. In this case the water gets colder as the methane gets warmer, and so instead of the risk that power plants have where the water can be too hot, the risk instead is that water is returned too cold. While regulators in the United States are concerned that power plants will return water to the environment at a temperature that is too hot, for these LNG facilities, regulators are concerned that water will be returned at a temperature that is too low to be safe for the aquatic environment.
Increasingly, coal is also moved by ships. Coal is historically produced and consumed within the same region. Compared with natural gas and petroleum, a smaller fraction of coal use is traded intercontinentally. However, coal export markets are growing. Because of the cheap gas from the shale revolution in the United States, the power sector’s consumption of coal has dropped, displaced partly by natural gas. That has led to lower prices for coal, which make it attractive to European and Asian power plants, a new destination for coal mined in the United States. That means coal is mined, moved by train to ports, moved over the ocean on massive coal transport ships, before being unloaded at receiving terminals to be sent by train to the power plants. Surprisingly, coal can also be moved by pipeline.27 While it is hard to imagine shipping solid materials by pipeline, by adding water, coal slurries can be produced that are fluid enough to transport by pipe. This approach requires mixing finely ground coal with significant volumes of water, up to hundreds of gallons of water per kilowatt-hour of electricity that is ultimately produced.
All of these transport modes use water, which means water is at risk from contamination or quality degradation from spills and accidents. And those transport mechanisms are vulnerable to drought and flood-related interruptions.
While the quantity of water needed for energy is extensive, water quality issues are also relevant. Energy can be used to improve water quality through water and wastewater treatment. But, energy can also degrade water quality, usually because of mistakes, accidents, or systemwide effects.
Oil spills are a particularly high-profile example of the risks to water quality. The oil spill discussed earlier from a blowout at a drilling platform in the Santa Barbara Channel was responsible for the release of 80,000 to 100,000 barrels (3–4 million gallons) of crude oil into the waters off the coast of California early in 1969. At the time, that was the largest spill in U.S. history. The Santa Barbara incident was surpassed in volume by the 1989 Exxon Valdez accident twenty years later, which spilled 11 million gallons of oil along Prince William Sound, Alaska. The explosion and subsequent oil spill from the Deepwater Horizon disaster at BP’s Macondo well in the Gulf of Mexico on April 20, 2010, was even larger, unfortunately demonstrating that as oil production becomes more difficult, the scale of accidents can increase too. That accident is also a stark reminder that low-probability, high-impact risks of petroleum exploration in aquatic environments can lead to disaster.
All spills are bad news, but the spill from the failed blowout preventer at the Macondo well in 2010 was particularly gripping because it was aired on live television. It got so bad that commentators, including me, wondered out loud if detonating a nuclear weapon inside the well would help seal it off. That became a front-page headline on the New York Times, reminding me to never muse out loud or by email around a reporter.28 Shortly after this idea got picked up by the news and became a punch line on the Daily Show with Jon Stewart, I was vindicated by a distinguished veteran of the U.S. nuclear weapons testing program, who confided to me that he was upset I beat him to the punch as he was going to make the same recommendation publicly. He cited his experience from the weapons tests in the 1960s, where they would conduct underground and undersea explosions and so they knew exactly how tightly it would seal off a well. It turns out that President Nixon had supported the use of nuclear weapons for oil and gas production as a way to fracture wells decades before hydraulic fracturing in shales became popular, so we had more experience with that crazy idea than I anticipated.29
And while those three spills in the United States captured media attention here, many other spills happen worldwide. Other famous spills include the Amoco Cadiz, which broke in two off the coast of Brittany, France, in 1978, spilling 67 million gallons of oil.
While a large tanker carrying crude oil as a high-dollar freight makes big news when it loses its valuable cargo in such an environmentally risky way, in fact, over one hundred smaller spills happen each year that are hardly as newsworthy and are not from oil tankers. Though small, they can still have an impact on a local scale.30 One of those events was in the San Francisco Bay when a cargo ship collided with the Bay Bridge in early November 2007, spilling 58,000 gallons of its bunker oil into the bay. And a pipeline that broke on land but along the coast of Santa Barbara sent thousands of barrels of oil into the water in 2015, reminding observers of the 1969 oil spill in the same region.
These water-related spills can also happen in urban settings. For example, in January 2008, an oil spill in my hometown of Austin flowed into Waller Creek, which is located downtown. As recounted by the local paper, it turns out that 8,000 gallons of fuel oil, used for on-site power generators, had been sitting idle in an underground storage tank for more than a hundred years in an alley next to the storied Driskill Hotel, where President Lyndon B. Johnson took Lady Bird Johnson on their first date (he asked her to marry him at the end of that day). Subsequent building owners on the neighboring lots forgot about the tank and paved over and built beside it for decades, not realizing it was there. Ultimately a large water leak caused water to spill into the tank, pushing out 4,200 gallons of fuel oil. So in this case it was water that caused the spill, and water that was impacted by the spill. Even this small spill had cleanup costs of approximately $200,000.
Hurricanes can also cause spills. Newspaper coverage of Hurricane Ike in 2008 reported that its “winds and massive waves destroyed oil platforms, tossed storage tanks and punctured pipelines. . . . At least a half million gallons of crude oil spilled into the Gulf of Mexico and the marshes, bayous and bays of Louisiana and Texas.”31 Industrial centers near Houston and Port Arthur and oil production facilities off Louisiana’s coast were hardest hit by the storm. Over the span of a few days just before, during, and after the hurricane, 52 oil platforms out of roughly 3,800 in the Gulf of Mexico were destroyed, and at least 448 releases of oil, gasoline, and dozens of other substances were reported, impacting the ground, air, and water in Texas and Louisiana. Of those, “by far, the most common contaminant left in Ike’s wake was crude oil.” And that is just one storm. Hurricanes like that cause the kind of disruption to the oil and gas sector that terrorists could only dream of.
Spills can also occur from leaking pipelines. Unfortunately, spills have been part of the history of pipelines since the very beginning. The U.S. Department of Transportation keeps a record of what are termed “significant pipeline incidents”—those that cause fatality or injury, have costs in excess of $50,000, liquid releases of fifty barrels or more, or releases that cause fire or explosions.32 On average, there are over 125 significant spills of hazardous liquids yearly in the United States, releasing an average of more than 120,000 barrels of hazardous liquids annually. Despite that record, pipes are generally considered a safer, cheaper, and cleaner way to transport liquids than trucks and trains.
However, with a growing industry to develop the carbon intensive and more corrosive Canadian oil sands, long-haul pipelines that bring that form of crude, known as dilbit (shorthand for “diluted bitumen”), across the United States to refineries are controversial. The Keystone XL pipeline, which can transport more than a million barrels per day, was opposed strongly in 2012–2015 by environmental groups and the Nebraska legislature, partly because of fears that a leak above the Ogallala Aquifer would cause irreparable harm.
Two prominent examples of serious leaks from pipelines carrying dilbit occurred in 2010 and 2011. One was the rupture of a thirty-inch pipeline operated by Enbridge in July 2010 near Marshall, Michigan.33 That rupture released nearly a million gallons of crude into the Talmadge Creek, which then flowed into the Kalamazoo River. The spill was followed by heavy rains, which carried the oil even farther. InsideClimateNews won the 2013 Pulitzer Prize for national reporting for its coverage of the disaster. What is particularly vexing about that spill is that the heavy dilbit sank to the bottom of waterways, where it became submerged under the riverbeds and for which common cleanup techniques used for spills of lighter, conventional oil weren’t as effective. The total costs for cleanup, which started in 2010 and required at least three years, were estimated to exceed one billion dollars, making it the costliest oil spill cleanup in U.S. history. By contrast, cleanup for the high-profile spill in the Yellowstone River in 2011, which released 63,000 gallons of crude oil, was easier, even though it contaminated seventy miles of river, because the oil was lighter and did not sink into the riverbed. That difference in the crude reduced the cost, lessened the impact, and simplified the cleanup.
Oil spills have the most visible and headline-grabbing effects on water quality, but natural gas also poses its own risks. It is difficult to differentiate natural and anthropogenic contamination, but there are concerns that ramped-up production will exacerbate the risks of the latter. While these risks are very real, there are aquifers that have naturally occurring natural gas. One notable example is the town of Burning Springs, West Virginia, which is named for the phenomenon that owing to the natural gas in the aquifer, the water can be lit on fire.
These water quality concerns are particularly prominent for unconventional gas production from shale formations using hydraulic fracturing because of the large volumes of water that are used for well completion and the large volumes of wastewater that are generated, and because drilling penetrates the water table. Notably, conventional drilling also punctures the water table and produces wastewater, so those risks aren’t specific to unconventional production. At the same time, the volumes of water are different, the types of chemicals injected into and produced out of the wells are different, and the higher pressures used for hydraulic fracturing mean the risks for well failures might be higher.
These risks are very real. Yet even with all the attention to water quality that accompanied the shale boom, several questions remain. Which activity introduces greater risk: belowground well work (drilling and completion) or aboveground functions (trucking and storage in ponds)? Which belowground activity introduces greatest risk: drilling, hydraulic fracturing, or wastewater injection? Which water sources are at greater risk: surface water or groundwater? Which water type is the greater risk: frac fluids that are injected into the ground or the wastewater that comes out of the ground?
The concerns about the impact of shale production on water quality occur at several steps and locations in the shale production life cycle: at the water table, from migration underground, from seepages from the storage ponds, from the outputs of the wastewater treatment plants, from the wastewater injection, and from truck accidents that cause spills. Anytime the water table is penetrated by a well—something that has happened over a million times in the United States during more than a century of oil and gas production—there is risk of contamination. This risk is akin to the medical profession, where every time the skin is punctured to take a blood sample, there is a risk of infection. Done with the right precautions, the risk of infection is quite small, and the same is true with oil and gas operations: if companies case their wells in cement the right way—to the right depth, with the right quality of cement, letting it cure fully, and testing its integrity—then the risk of water contamination is quite small. But, mistakes have happened and do happen. They are rare, but impactful. And, if it’s your water that is ruined, it’s not very comforting to know that such a phenomenon seldom occurs.
There are also the concerns of chemical seepage from the point where the fracturing occurs to the groundwater. However, it is hard to imagine the chemicals flowing thousands of feet upward through the shale and other geological layers to the water table, when it would be so much easier to just flow through the well instead. Having said that, there are natural fissures and seeps, so it’s possible the fracturing process activates those existing pathways through the rock.
While research to quantify the risks and impacts is still under way, anecdotally, the aboveground risks from spills, leaks from storage ponds, and truck accidents that cause a release of water from the tanks seem to be a much bigger overall factor.34 And studies have clarified that the water quality risks are primarily from the drilling and cement work of the well, not the fracturing.35
The idea of water quality risks for our transportation fuels isn’t a new one. For many years, MTBE (methyl tert-butyl ether) was a common additive to gasoline to improve automobile performance. However, it was prone to leaking out of underground storage tanks and trickling into the groundwater. After some litigation, the additive was eliminated from fuels in the first decade of the 2000s because of the risks to water quality. The loss of MTBE helped pave the way for a new, all-natural organic additive that promised to help boost the octane in cars without posing a risk to water quality: ethanol from corn. In fact, ethanol’s potential as an additive is one of the reasons it received so much support in the form of tax credits, subsidies, and mandates in the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007. But corn ethanol poses its own risk to water quality.
Quantifying the water quality impacts of the agricultural portion of the biofuel life cycle presents new challenges because most of the impacts spread out over a large area, like the pollution from car exhaust all over a city. Pollutants are transferred into water by means of excess irrigation, rainfall, or snowmelt that flows over and through the ground as runoff, collecting manmade pollutants from farms—the chemicals used to fertilize the crops—as it moves. Since pollutants transferred to water bodies from contaminated runoff or percolation through the ground cannot be attributed to discrete sources, this type of water pollution is much more difficult to measure and regulate. Even though the connection between agricultural activity and nutrient runoff to downstream water bodies is widely accepted, pollution from agricultural sources is largely unregulated. The same story is generally true when it comes to the air quality impacts of farms, too.
Because of biofuels mandates, domestic production of biofuels—and the water pollution caused by farm runoff—has gone up.36 Although all fertilized crop production loses nutrients, corn is particularly inefficient: it uses only 40–60 percent of the nutrients delivered to its roots. That means the rest of the nutrients run off into the neighboring ecosystem. In particular, there have been increases in nitrogen and phosphorus agricultural chemical concentrations and hypoxia (a “dead zone”) in surface waters draining from farmland in the Mississippi River basin, and groundwater near farmland, into the Gulf of Mexico. This increase in nutrient loading from crop production has contributed to the growth of a large hypoxic area in the Gulf of Mexico, which is currently the second largest hypoxic zone in the world after the Baltic Sea.
It is hoped that other forms of bioenergy such as switchgrass and woody materials would not only lower irrigation needs but also require fewer agricultural chemical inputs and therefore have lower water quality impacts. Those prospective benefits are part of the motivations for the use of plants other than corn as a source of fuels.
As countries shift from conventional fossil fuel production toward unconventional fossil fuels and biofuels, the nature, extent, and location of water use and water pollution will be different. Consequently, the existing regulatory frameworks for protecting water quality may need to be updated and revised.
