Power plant operators have long understood the vital role water plays in power generation. Now, as the rest of the world begins recognizing that as well, a conflict is brewing between the growing demand for electricity and increasingly strained water resources.
Unless you’ve been living in a cave, you’ve likely heard the term “water-energy nexus” recently. Around the globe, experts and policy makers are waking up to the reality that the world’s energy needs and its water needs are on a collision course.
A recent report from the Congressional Research Service lays out the challenge in the U.S. National water consumption is projected to increase 7% by 2030, and 85% of that increase is attributable to the energy sector. Globally, the figures are dire: According to the International Energy Agency (IEA), consumption is projected to increase 2.5% per year through 2035 even with policy changes designed to increase water use efficiency, with energy-related consumption doubling over the same period.
The potential for a staggering conflict can be drawn from just two statistics: Worldwide, according to the United Nations, 2 billion people lack access to safe water supplies, and 1.3 billion lack access to electricity. In most cases, these numbers represent the same people.
One problem in tackling these challenges is a paucity of good data. The U.S. Geological Survey (USGS), which publishes comprehensive reports on water usage in the U.S. every five years, has not reported water consumed in power generation since 1995—only total withdrawals. The USGS plans to return to reporting this data with the study for 2010, but this report will not be available until late 2014.
Thus, though it is known that withdrawals for once-through cooling (OTC) have been more or less level since 1980, it is not clear how recent moves toward generation resources with very different water use profiles may have affected consumption. The Electric Power Research Institute (EPRI) has attempted to fill this gap, most recently with a report updated in April 2014, though it covered only thermoelectric plants using freshwater.
The EPRI results, based on data from 2009 for all thermal plants except nuclear (for which data through 2011 was available) are consistent with previous studies suggesting that while power generation withdrawals are a significant portion (about 40%) of total withdrawals, consumption constitutes a much smaller share. Total withdrawals were estimated at 139,800 million gallons per day (mgd), with OTC accounting for almost all of this. Consumption was estimated at 3,930 mgd, with most of this (2,760 mgd) accounted for by wet recirculating cooling.
This appears to represent a largely unchanged load on the nation’s water resources compared to 2005 USGS data. The USGS estimated that total (fresh and saltwater) withdrawals for power generation that year were 201,000 mgd, of which 142,710 mgd were freshwater.
While the U.S. is far less water-stressed than countries such as China and India, many states face challenges in meeting water demand. A May 2014 report from the U.S. General Accounting Office (GAO) found that 24 of 50 states were likely to experience regional water shortages over the next decade and 40 out of 50 state water managers expected some portion of their states to experience shortages under average conditions.
These responses are not surprising given that large portions of the western U.S. are currently experiencing severe to exceptional long-term drought. This includes nearly all of California, Arizona, and New Mexico, and large portions of Texas, Oklahoma, and Kansas.
Significantly for the generation industry, California and Texas represent the two largest markets for future capacity, according to the Energy Information Administration (EIA). Further, the Southwestern U.S. as a whole is projected to see greater than 30% electricity demand growth by 2040.
Ongoing droughts have threatened disruptions to generation in Texas and the Midwest (see “Water Issues Challenge Power Generators” in the July 2013 issue) and have caused curtailments in hydropower generation in California and the Pacific Northwest. The California Independent System Operator said in May that the state was likely to have as much as 1,669 MW of its hydroelectric capacity unavailable this summer, while as much as 1,150 MW of thermal capacity would be unavailable due to limitations on cooling water withdrawals.
Kate Zerrenner, project manager for the Environmental Defense Fund’s U.S. Climate and Energy Program and a former climate policy analyst with the GAO, isn’t convinced generators fully appreciate what they’re facing. “Many electric utilities and power grid operators have drought contingency plans, but drought planning is not the same thing as water planning,” she told POWER. “If we anticipate a growing demand of this limited resource (and we do), we need to talk about climate change. It is no longer an option to conduct long-range planning without using all the available data. We need a thorough analysis of climate impacts on water, so both electric and water utilities know what they’re working with.”
Globally, water stresses are concentrated in the Asia-Pacific region, with the greatest future stresses projected to come in the countries expected to see the greatest electricity demand growth: China and India (Figure 1).
Many of China’s problems stem from a geographic mismatch between its resources and population. While water is relatively abundant in the south, its population and water-intensive industry—and thus its greatest power demands—are concentrated in the water-poor northeast. About 60% of the nation’s planned capacity growth is sited in this region, even though it has but 5% of the country’s water resources. According to a report from the World Resources Institute released in April, almost 60% of China’s generating capacity is expected to face steep competition for water in the future, which has forced the central government to enact caps on withdrawals and set goals for increased efficiency. (For more on China’s water challenges, see “Power Sector Link to Water Is Deep, Complex” in the June issue.)
According to the IEA, withdrawals for power generation in India are expected to grow by almost 50% between 2010 and 2035, with consumption more than doubling. Most of the stresses will come in the southern and eastern coastal regions, as well as heavily populated Gujarat state. The country has already experienced water-related disruptions to generation: Shortages forced the 2.3-GW Chandrapur coal plant in Maharashtra offline in the summer of 2010, leading to power outages across the state, a situation that nearly recurred during a second drought in 2012. A similar shutdown occurred at a plant in Chhattisgarh in 2008, and the 2012 drought was blamed in part for a massive blackout in August that knocked out power for almost half the nation.
Though Europe is not generally considered water-stressed, it has still experienced water-related challenges to generation, notably during droughts in 2003 and 2005, which caused a series of curtailments at thermoelectric plants. France in particular lost a quarter of its nuclear capacity during the 2003 drought as a result of constraints on cooling water. Climate change is expected to aggravate future water stresses in Europe, according to the IEA, with reduced summer river flows and higher water temperatures.
Other regions of the world are facing potential water-energy collisions. The Middle East, one of the most arid regions on earth, is a study in contrasts. The wealthy countries around the Persian Gulf have managed their water stresses through energy-intensive desalination. Though this has given them sufficient water supplies, a substantial portion of their total generation capacity is devoted to producing water. Meanwhile, the poorer countries struggle to meet both water and power needs of their population. (For more on this region’s energy profile, see “Shifting Sands: The Middle East’s Thrust for Sustainability” in this issue.)
Latin America’s heavy reliance on hydropower has meant fewer challenges with respect to cooling but greater exposure to drought-induced curtailments. Conflicts have also arisen between hydroelectric plants and agricultural interests. Though the region as a whole is less water-stressed than others, there are still arid countries, such as Chile, where generators have had to plan carefully to meet their water needs (see “Chile’s Power Challenge: Reliable Energy Supplies” in the September 2012 issue). Climate change is also expected to reduce the reliability of existing hydro resources in the future, according to the IEA.
Finally, Africa—the least electrified region in the world—is also looking toward hydropower as a way forward. Hydro currently supplies 32% of Africa’s generation, though only 8% of its economically feasible hydro potential has been developed (see “The Power Potential of Southern Africa” in the February 2014 issue).
Given its numerous inherent challenges, it’s hardly surprising that the water-energy nexus has drawn increasing regulatory attention.
At the federal level, the Environmental Protection Agency (EPA) on May 19 issued its final rule governing power plant cooling water intake systems under Section 316(b) of the Clean Water Act. The rule is focused on reducing impingement and mortality of aquatic life and is expected to have little immediate effect on total withdrawals. Closed-cycle cooling is favored—though not required—for new capacity. (For more on the new rule, see the June 2014 issue cover story, “Site-Specific Factors Are Critical for Compliance with Final 316(b) Existing Facilities Rule.”)
The EPA is also in the process of revising its rules on power plant effluent. The proposed rule, published in April 2013, establishes new or additional requirements for wastewater streams. Several compliance options are proposed for existing plants, but zero-liquid discharge could potentially be the standard for new plants. The final rule was supposed to be published on May 22 but has been delayed until September 2015 while the EPA completes its rulemaking for coal ash.
At the state level, California in 2010 moved to phase out OTC at plants that draw cooling water from the ocean or marine estuaries (Figure 2). The rule requires retrofitting with closed-cycle cooling or reducing impact on marine life through other means. Most plants will need to be in compliance by 2020, though a few have until 2029.
|2. Shifting gears. Dynegy’s 2.5-GW Moss Landing plant near Monterey, Calif., must cease using ocean water for cooling before 2018. Dynegy is considering retrofitting wet cooling towers for the four-unit facility. Courtesy: David Monniaux|
While regulatory attention is growing, Zerrenner believes more than that is necessary. “In most instances, power and water are not managed by the same regulatory entities,” she noted. “To the same effect, at the legislative level, often the committee charged with water policy is not the same as the one charged with energy policy.” Tackling the water-energy nexus will require breaking down policy and regulatory silos.
At the federal level at least, that may be happening. In May, Senators Lisa Murkowski (R-Alaska) and Ron Wyden (D-Ore.), both members of the Senate Committee on Energy and Natural Resources, introduced a bill to establish an interagency coordination committee focused on the water-energy nexus. The bill also proposes a budget mechanism to allow policymakers to see where funding is needed across energy-water initiatives.
The Challenge of Changing Technologies
While a shift away from OTC may reduce withdrawals, Kent Zammit, senior program manager with EPRI, warned that it could also increase consumption. “Wet cooling towers typically evaporate over twice as much water as OTC,” he said. According to the EPRI study, coal plants using OTC from adjacent rivers consumed 212 gal/MWh on average, while those using cooling towers consumed 365 gal/MWh. The differences were even greater for nuclear plants, with those using cooling towers consuming 545 gal/MWh versus 155 gal/MWh for OTC.
This suggests that while shifting to closed-cycle cooling will require much lower volumes of available water, it is likely to increase the power sector’s overall consumption, perhaps significantly, unless dry cooling methods constitute the bulk of the new systems. Dry cooling, however, is the most expensive and carries the largest efficiency penalties. It is also not appropriate for every plant or every location. Large nuclear plants in particular are unable to use dry cooling, in part for safety reasons. Dry cooling for coal plants, while currently rare, is seeing increasing use, particularly overseas: China, South Africa, and Australia have all built large coal plants using dry cooling methods in water-challenged areas.
While wind and solar photovoltaic generation require negligible amounts of water, the same cannot be said of all new generation technologies. Concentrating solar power (CSP), in particular, when coupled with wet cooling methods, can consume substantial amounts of water, in some cases exceeding that of fossil generation methods. This is a problem since these systems are typically sited in hot, arid, water-poor areas because these regions typically experience the highest insolation.
When coupled with dry cooling, CSP requires very little water (Figure 3). However, in addition to the increased costs, dry cooling is much less effective in hot environments, and CSP plants can experience reduced outputs of 10% to 15%, or more, on hot days.
Integrated gasification combined cycle (IGCC) generation, should it gain a foothold—which is uncertain (see “Does IGCC Have a Future?” in this issue)—could reduce overall water consumption from coal generation. However, the savings are not as great as might be suspected because the water saved from the steam cycle and emissions control systems is offset by consumption from the gasifier.
According to research by the National Energy Technology Laboratory (NETL), current IGCC designs consume around 102 gal/MWh to 139 gal/MWh for process and emissions control, compared to 107 gal/MWh to 116 gal/MWh for steam plants. The main savings are in cooling, if wet evaporative methods are used: Largely because of their greater efficiency, IGCC plants consume around 20% to 30% less water for cooling than do steam plants.
When carbon capture and storage (CCS) is included, however, the water savings are significant. Though CCS itself consumes substantial additional water, it requires far less when coupled with IGCC than with steam. Adding CCS could nearly double a steam plant’s water consumption, according to the NETL report, but it would increase an IGCC plant’s consumption by only about 37%. Still, said Zammit, the “penetration and impact [of CCS] will be unit- and site-specific.”
Another impact on water resources could come from biomass generation. While in-plant water consumption is comparable to coal plants, growing biomass fuel may require significant amounts of water, particularly if it is grown specifically for use in a power plant. This is a concern in areas where agricultural water supplies are already under stress, such as China, India, and the U.S. central plains.
Biomass is not the only fuel with an effect on water resources. Natural gas from shale is projected to constitute 53% of the U.S. gas supply by 2040, according to the EIA. While the water consumed by hydraulic fracturing is small compared to agricultural use, much shale gas development is taking place in areas under water stress, such as Texas. Shale gas, as a new industry, must compete with existing demands on water resources, something that has caused controversy in many areas. It is worth noting as well that, unlike water used in agriculture, most of the water used in hydraulic fracturing is permanently lost from the hydrological cycle. Waterless methods, though currently limited, are likely to grow in importance.
The Way Forward
There is clearly pressure—political, social, and environmental—to reduce the power sector’s load on water resources. Most of these pressures will be experienced in areas such as India and China, where both electricity and water supplies are constrained.
Zerrenner believes one key is better coordination between power and water suppliers. “The power sector and the water sector need a better understanding of how they impact each other,” she said. “A crucial
For existing plants, a focus on improving efficiency—of both water and plants—will be key. A 2010 NETL study reviewed various methods that have been employed globally, among them:
■ Replacing/retrofitting with modern, more efficient plant systems.
■ Switching to higher-quality coal.
■ Use of waste heat to dry high-moisture coals.
■ Retrofitting dry cooling.
■ Retrofitting cogeneration.
■ Purification/desalination of brackish water and saltwater.
■ Dry bottom ash handling.
■ Dry emissions scrubbing.
■ Recycling and reusing wastewater.
■ Improved monitoring of water consumption.
The use of alternative sources of water deserves special attention, since it can have the most direct impact on a plant’s consumption of local water resources. One facet of this can include capturing wastewater streams, such as cooling tower blowdown, and using these for processes that do not require high water quality. Cascading wastewater from higher- to lower-quality needs enables extensive reuse. Many plants in water-stressed areas have already implemented such recycling measures. Making degraded water sources more cost-effective for cooling is another area with future possibilities, according to Jessica Shi, a senior technical leader at EPRI.
Where large quantities of water are needed for wet cooling, municipal wastewater has proven useful as a replacement for freshwater. A number of new plants in the U.S., such as the Sand Hill Energy Center in Austin (Figure 4) and the Empire Generating Plant in Rensselaer, N.Y., have leveraged such supplies. Doing so, however, requires special measures because of the potential for generating airborne pathogens.
For high-quality water needs, purification and desalination of water resources that are not suitable for agriculture or other competing uses—whether seawater or low-quality groundwater—is an option. While expensive and energy intensive, it can be made cost-effective if a desalination plant is co-located with the power plant in an area where freshwater is at a premium (that is, where it can be sold to recapture some costs) and waste heat can be captured for use in the desalination process (see “Adding Desalination to Solar Hybrid and Fossil Plants” in the May 2010 issue). Advanced membrane distillation technology could also greatly reduce the costs of desalination.
Going forward, new technologies will be necessary to further improve efficiency and reduce costs for closed-cycle cooling, as well as improving overall plant water efficiency. “We have technologies today that can reduce water consumption for new plants,” said Zammit. However, “research is still needed to address the cost and O&M impacts of such technologies. In addition, research into technologies such as the thermo-syphon cooler and more cost-effective water treatment options could help conserve water at existing plants.”
EPRI and several partners inaugurated the Water Research Center at Georgia Power’s Plant Bowen in Cartersville, Ga., in 2012 with the goal of generating industry-wide insights that will help generators minimize their impact on water resources. (See “Research Center Dedicated to Power Plant Water Use Opens” in the November 2012 issue, and “Advanced Cooling and Water Treatment Technology Concepts for Power Plants” in the April 2014 issue.) Specialized research such as this is certain to be key. ■
— Thomas W. Overton, JD is a POWER associate editor (@thomas_overton, @POWERmagazine).
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