Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Congressional research reportMar 27, 2012
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Energy Storage for Power Grids and Electric
Transportation: A Technology Assessment
/name redacted/
Specialist in Energy and Infrastructure Policy
March 27, 2012
Congressional Research Service
7-....
www.crs.gov
R42455
CRS Report for Congress
Prepared for Members and Committees of Congress
Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Summary
Energy storage technology has great potential to improve electric power grids, to enable growth
in renewable electricity generation, and to provide alternatives to oil-derived fuels in the nation’s
transportation sector. In the electric power system, the promise of this technology lies in its
potential to increase grid efficiency and reliability—optimizing power flows and supporting
variable power supplies from wind and solar generation. In transportation, vehicles powered by
batteries or other electric technologies have the potential to displace vehicles burning gasoline
and diesel fuel, reducing associated emissions and demand for oil.
Federal policy makers have become increasingly interested in promoting energy storage
technology as a key enabler of broad electric power and transportation sector objectives. The
Storage Technology for Renewable and Green Energy Act of 2011 (S. 1845), introduced on
November 10, 2011, and the Federal Energy Regulatory Commission’s Order 755, Frequency
Regulation Compensation in the Organized Wholesale Power Markets, are just two recent
initiatives intended to promote energy storage deployment in the United States. Numerous private
companies and national laboratories, many with federal support, are engaged in storage research
and development efforts across a very wide range of technologies and applications.
This report attempts to summarize the current state of knowledge regarding energy storage
technologies for both electric power grid and electric vehicle applications. It is intended to serve
as a reference for policymakers interested in understanding the range of technologies and
applications associated with energy storage, comparing them, when possible, in a structured way
to highlight key characteristics relevant to widespread use. While the emphasis is on technology
(including key performance metrics such as cost and efficiency), this report also addresses the
significant policy, market, and other non-technical factors that may impede storage adoption. It
considers eight major categories of storage technology: pumped hydro, compressed air, batteries,
capacitors, superconducting magnetic energy storage, flywheels, thermal storage, and hydrogen.
Energy storage technologies for electric applications have achieved various levels of technical
and economic maturity in the marketplace. For grid storage, challenges include roundtrip
efficiencies that range from under 30% to over 90%. Efficiency losses represent a tradeoff
between the increased cost of electricity cycled through storage, and the increased value of
greater dispatchability and other services to the grid. The capital cost of many grid storage
technologies is also very high relative to conventional alternatives, such as gas-fired power
plants, which can be constructed quickly and are perceived as a low risk investment by both
regulated utilities and independent power producers. The existing market structures in the electric
sector also may undervalue the many services that electricity storage can provide. For
transportation storage, the current primary challenges are the limited availability and high costs of
both battery-electric and hydrogen-fueled vehicles. Additional challenges are new infrastructure
requirements, particularly for hydrogen, which requires new distribution and fueling
infrastructure, while battery electric vehicles are limited by range and charging times, especially
when compared to conventional gasoline vehicles.
Substantial research and development activities are underway in the United States and elsewhere
to improve the economic and technical performance of electricity storage options. Changes to
market structures and policies may also be critical components of achieving competitiveness for
electricity storage devices. Removing non-technical barriers may be as important as technology
improvements in increasing adoption of energy storage to improve grid and vehicle performance.
Congressional Research Service
Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Contents
Introduction...................................................................................................................................... 1
Structure of the Report .............................................................................................................. 2
Other CRS Reports on Electricity Storage ................................................................................ 3
Technology Assessment Authorship .......................................................................................... 3
Acknowledgement ..................................................................................................................... 3
Chapter 1: Executive Summary ....................................................................................................... 4
Background................................................................................................................................ 4
Energy Storage for Electric Grid Applications .......................................................................... 5
High Power/Rapid Discharge Applications ......................................................................... 5
Energy Management Applications ...................................................................................... 5
Energy Storage for Transportation Applications ....................................................................... 7
Chapter 2: Background and Scope................................................................................................... 9
Organization of This Report ...................................................................................................... 9
Chapter 3: Overview of Storage Technology Applications and Benefits....................................... 11
Energy Storage for Electric Power Grids ................................................................................ 11
Current Storage Deployment for the Grid ......................................................................... 11
Applications of Energy Storage in the Grid ...................................................................... 12
Valuation of Storage for the Grid ...................................................................................... 14
Energy Storage and Renewable Energy ............................................................................ 17
Ongoing Barriers to Storage Deployment for the Grid ..................................................... 21
Current Grid Storage Policies............................................................................................ 23
Storage for Electric Transportation Applications .................................................................... 27
Transportation Storage Technologies and Pathways ......................................................... 27
Impacts and Benefits of Vehicle Electrification ................................................................ 28
Barriers to Deployment and Policies to Increase Vehicle Electrification .......................... 30
Chapter 4: Batteries for Grid Applications .................................................................................... 32
Overview ................................................................................................................................. 32
Technology .............................................................................................................................. 34
Description and Performance ............................................................................................ 34
Cost ................................................................................................................................... 37
Research and Development ............................................................................................... 40
Deployment Challenges .................................................................................................... 43
Conclusions ............................................................................................................................. 44
Chapter 5: Batteries for Electric Transportation ............................................................................ 46
Overview ................................................................................................................................. 46
Technology .............................................................................................................................. 48
Description and Performance ............................................................................................ 48
Cost ................................................................................................................................... 52
Research and Development ............................................................................................... 54
Deployment Challenges .................................................................................................... 59
Conclusions ............................................................................................................................. 60
Chapter 6: Hydrogen...................................................................................................................... 61
Overview ................................................................................................................................. 61
Technology .............................................................................................................................. 63
Description ........................................................................................................................ 63
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Performance ...................................................................................................................... 67
Cost ................................................................................................................................... 69
Research and Development ............................................................................................... 71
Deployment Challenges .................................................................................................... 72
Conclusions ............................................................................................................................. 74
Chapter 7: Compressed Air Energy Storage .................................................................................. 75
Overview ................................................................................................................................. 75
Technology .............................................................................................................................. 76
Description ........................................................................................................................ 76
Performance ...................................................................................................................... 78
Cost ................................................................................................................................... 80
Research and Development ............................................................................................... 82
Deployment Challenges .................................................................................................... 84
Conclusions ............................................................................................................................. 86
Chapter 8: Electrochemical Capacitors.......................................................................................... 87
Overview ................................................................................................................................. 87
Technology .............................................................................................................................. 87
Description ........................................................................................................................ 87
Performance ...................................................................................................................... 88
Cost ................................................................................................................................... 90
Research and Development ............................................................................................... 91
Deployment Challenges .................................................................................................... 93
Conclusions ............................................................................................................................. 94
Chapter 9: Pumped Hydro Storage ................................................................................................ 95
Overview ................................................................................................................................. 95
Technology .............................................................................................................................. 97
Description ........................................................................................................................ 97
Performance ...................................................................................................................... 98
Cost ................................................................................................................................... 99
Research and Development ............................................................................................. 101
Deployment Challenges .................................................................................................. 103
Conclusions ........................................................................................................................... 105
Chapter 10: Flywheel Storage ...................................................................................................... 106
Overview ............................................................................................................................... 106
Technology ............................................................................................................................ 107
Description ...................................................................................................................... 107
Performance .................................................................................................................... 108
Cost ................................................................................................................................. 110
Research and Development ............................................................................................. 111
Deployment Challenges .................................................................................................. 114
Conclusions ........................................................................................................................... 114
Chapter 11: Thermal Energy Storage in Buildings ...................................................................... 116
Overview ............................................................................................................................... 116
Technology ............................................................................................................................ 117
Description ...................................................................................................................... 117
Performance .................................................................................................................... 118
Cost ................................................................................................................................. 120
Research and Development ............................................................................................. 121
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Deployment Challenges .................................................................................................. 121
Conclusions ........................................................................................................................... 122
Chapter 12: Thermal Energy Storage for Concentrating Solar Power ......................................... 123
Overview ............................................................................................................................... 123
Technology ............................................................................................................................ 124
Description ...................................................................................................................... 124
Performance .................................................................................................................... 125
Cost ................................................................................................................................. 127
Research and Development ............................................................................................. 128
Deployment Challenges .................................................................................................. 130
Conclusions ........................................................................................................................... 130
Chapter 13: Superconducting Magnetic Energy Storage ............................................................. 131
Overview ............................................................................................................................... 131
Technology ............................................................................................................................ 132
Description ...................................................................................................................... 132
Performance .................................................................................................................... 133
Cost ................................................................................................................................. 134
Research and Development ............................................................................................. 135
Deployment Challenges .................................................................................................. 135
Conclusions ........................................................................................................................... 135
Figures
Figure 1. Estimated Life-Cycle Value of Several Electricity Grid Storage Applications .............. 15
Figure 2. Impact on Net Load from Using Wind Generation ........................................................ 18
Figure 3. Generation Dispatch in the WWSIS Study at 30% Wind Penetration............................ 21
Figure 4. Pathways to Vehicle Electrification ................................................................................ 27
Figure 5. Cost Components for an Installed NaS System .............................................................. 38
Figure 6. Extraction Costs of Elements in Grid Battery Couples .................................................. 39
Figure 7. Energy Storage Potential (ESP) of Battery Material Reserves ....................................... 44
Figure 8. United States Hybrid Electric Vehicle Sales................................................................... 47
Figure 9. Comparison of the Various Lithium-Ion Battery Chemistries ........................................ 49
Figure 10. Battery Cost Requirements for a Five-Year Payback from Fuel Savings..................... 53
Figure 11. Extraction Costs of Elements in Vehicle Battery Couples............................................ 54
Figure 12. FreedomCAR PHEV Energy Storage Goals ................................................................ 56
Figure 13. Practical vs. Theoretical Specific Energy for 27 Battery Chemistries ......................... 59
Figure 14. Energy Storage Potential (ESP) of Battery Material Reserves ..................................... 60
Figure 15. Electrolytic and Other Major Hydrogen Energy Pathways .......................................... 64
Figure 16. Schematic Representation of PEM Electrolysis ........................................................... 65
Figure 17. Location of Salt Deposits Across the United States ..................................................... 69
Figure 18. 110 MW CAES Plant in McIntosh, AL ........................................................................ 75
Figure 19. CAES System Diagram ................................................................................................ 77
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Figure 20. Comparison of CAES Dispatch Cost to Conventional Storage .................................... 80
Figure 21. Capital Cost Estimates for Conventional Diabatic CAES ............................................ 81
Figure 22. Comparison of Various Capacitor and Battery Topologies .......................................... 88
Figure 23. Comparison of Energy Storage Technologies .............................................................. 90
Figure 24. Comparison of Cost per Energy Throughput for Li-Ion Batteries and ECs ................. 91
Figure 25. Capacity of PHS in United States, 1956–2003 ............................................................. 96
Figure 26. Existing and Proposed PHS Facilities in the United States .......................................... 97
Figure 27. Pumped-Storage Hydropower Plant Configuration ...................................................... 97
Figure 28. Historical Efficiencies of PHS Plants in United States ................................................ 99
Figure 29. Installed Cost of PHS Plants in United States ............................................................ 100
Figure 30. Part of a 1 MW Flywheel System in the ISO-New England Grid .............................. 107
Figure 31. Electric Flywheel Components................................................................................... 108
Figure 32. Flywheel Cost Projections for a 20MW/5MWh Frequency Regulation Plant .......... 111
Figure 33. Illustration of a Chilled Water-Based TES System .................................................... 118
Figure 34. Electric Demand for Building Cooling With and Without TES ................................. 119
Figure 35. Two-Tank TES System at a 50 MW Solar Power Plant in Spain ............................... 124
Figure 36. Schematic of an Indirect Two-Tank TES System ....................................................... 125
Figure 37. Potential SMES Cost Ranges Based on Component Costs ........................................ 134
Tables
Table 1. Energy Storage Applications and Technologies ................................................................. 4
Table 2. Major Power Grid Applications of Electricity Storage .................................................... 13
Table 3. Example NaS Battery Installations in the United States .................................................. 33
Table 4. ARPA-E Supported Activities on Grid Battery Storage in FY2010-2011........................ 40
Table 5. ARRA Supported Grid Battery Demonstrations .............................................................. 41
Table 6. ARRA Supported Vehicular Battery Demonstrations ...................................................... 55
Table 7. Proposed CAES Plants in the United States .................................................................... 76
Table 8. Component Costs of a Conventional CAES System Deployed in a Salt Cavern............ 81
Table 9. Performance and Costs of Electrochemical Capacitors ................................................... 90
Table 10. Recently Completed or Proposed PHS Plants.............................................................. 101
Table 11. Flywheel Performance Characteristics ......................................................................... 110
Table 12. Flywheel Materials Characteristics .............................................................................. 112
Table 13. Technical Characteristics of a CSP System.................................................................. 126
Table 14. U.S. Department of Energy FOA Projects ................................................................... 129
Table 15. Potential Cost Reductions for CSP/TES Systems ........................................................ 129
Table 16. SMES Operating Parameters ....................................................................................... 133
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Appendixes
Appendix. Table of Acronyms ..................................................................................................... 137
Contacts
Author Contact Information......................................................................................................... 139
Congressional Research Service
Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Introduction
Energy storage technology has great potential to improve electric power grids, to enable growth
in renewable electricity generation, and to provide alternatives to oil-derived fuels in the nation’s
transportation sector. In the electric power system, the promise of this technology lies in its
potential to increase grid efficiency and reliability—optimizing power flows and supporting
variable power supplies from wind and solar generation. In transportation, vehicles powered by
batteries or other electric technologies have the potential to displace vehicles burning gasoline
and diesel fuel, reducing associated emissions and demand for oil.
In recent years, federal policy makers have become increasingly interested in promoting energy
storage technology as a key enabler of broad electric power and transportation sector objectives.
In remarks about the STORAGE Act of 2011 (S. 1845),1 which would provide investment tax
credits for storage systems connected to the electric grid, businesses and homes, Senate Energy
and Natural Resources Committee Chairman Jeff Bingaman remarked,
Deployment of storage technologies will make our nation’s electricity grid more reliable
while also enabling more efficient use of existing energy sources as well as new ones, such
as wind and solar.... These technologies have the potential to cut electricity bills, reduce peak
power demand and lower greenhouse gas emissions.2
Likewise, in a statement regarding new energy storage-related rules for wholesale electricity
markets, Federal Energy Regulatory Commissioner John Norris stated,
I believe today’s final rule is a positive first step by the Commission in recognizing the
unique characteristics and the value that storage resources offer.... As we move forward, I
strongly believe that storage will become ever more critical as we look to integrate
increasing amounts of variable energy resources.3
Referring to advanced batteries for electric transportation applications, Secretary of Energy
Steven Chu reportedly stated,
It’s now within grasp, that you can get a battery where the business plans are one-third of the
cost of today’s batteries, where you can get ranges now that would allow cars instead of 100
miles on a single charge, go 300 or more miles on the same charge…. It’s not a pipe dream
30 years from today or 20 years from today. It’s in the next decade.4
Statements such as those above highlight not only the technical opportunities for energy storage
in the grid and in electric transportation, but also the attention being paid to energy storage
technologies at the highest levels in the federal government. Nonetheless, many new energy
storage technologies continue to face significant technological and economic challenges to their
1
Storage Technology for Renewable and Green Energy Act of 2011 (S. 1845) introduced on November 10, 2011, by
Senator Ron Wyden and co-sponsored by Senators Jeff Bingaman, Susan Collins, and Robert Menendez.
2
Office of Senator Ron Wyden, “Wyden, Collins, Bingaman Legislation Will Increase Investments in the Storage of
Renewable Energy,” press release, November 10, 2011.
3
Commissioner John R. Norris, “Frequency Regulation Compensation in the Organized Wholesale Power Markets,”
Docket Nos. RM11-7-000 & AD10-11-000, Item No. E-28, Federal Energy Regulatory Commission, October 20, 2011.
4
Michael Warren, “Energy Secretary Steven Chu on Electric Cars,” The Weekly Standard Blog, April 3, 2011,
http://www.weeklystandard.com/blogs/chu-electric-cars_556135.html.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
commercialization and widespread deployment. The recent bankruptcy of Beacon Power, one of
the leading developers of flywheel energy storage technologies for the grid, is a prominent
illustration of commercial barriers to grid storage technology. Public concerns about elevated fire
risks from Chevrolet Volt electric car batteries, although shown to be exaggerated, are another.5
By contrast, increasing investments by AES Corporation in utility-scale battery storage for power
grids show continuing successful efforts to overcome technical challenges and market barriers to
bring new storage technologies into the market.6
Understanding the potential of energy storage in electric applications is complicated by a number
of factors. The first is the wide range of storage technologies either commercially available, in
development, or being researched. Because they are technologically diverse, it is difficult to gain
a balanced understanding of the fundamental capabilities, costs, and comparative advantages of
these different energy storage options. Second, there are multiple applications of energy storage,
each with distinct operational requirements. Certain storage technologies may suit certain
applications better than others. Finally, there are many aspects of market structure and economic
regulation that affect energy storage deployment. Taken together, these factors make the
development of an energy storage research and development portfolio challenging. While there is
general consensus that storage technology improvements are needed, there are multiple potential
pathways to such improvements that cut across different disciplines.
This report attempts to summarize the current state of knowledge regarding energy storage
technologies for both electric power grid and electric vehicle applications. It is intended to serve
as a reference for policymakers interested in understanding the range of technologies and
applications associated with energy storage, comparing them, when possible, in a structured way
to highlight key characteristics relevant to widespread use. The report also discusses how aspects
of policy and market structure affect competition among both mature and emerging technologies.
Structure of the Report
The report contains 13 chapters, starting with an Executive Summary, which provides an
overview of the report’s main findings. Context and background are provided in “Chapter 2:
Background and Scope” and “Chapter 3: Overview of Storage Technology Applications and
Benefits.” In particular, Chapter 3 provides an overview of electricity storage applications and
value, including their use to enable renewable electricity; current barriers to deployment; and
current initiatives to address technical, economic and market barriers. Chapters 4-13 discuss the
individual storage technologies. Each chapter can be read independently, but Chapters 2 and 3
offer the reader a more complete understanding of some of the more technologically focused
discussions in the subsequent chapters.
5
Jim Henry, “Chevy Volt Battery Fires Threaten All Electric Vehicle Makers, Not Just GM,” Forbes, December 12,
2011; National Highway Traffic Safety Administration, “NHTSA Statement on Conclusion of Chevy Volt
Investigation,” press release, January 20, 2012.
6
“AES Peaker-Sized Battery Proposals Show Company’s Vision of Storage Potential for the Grid,” Electric Utility
Week, Platts, January 2, 2012.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Other CRS Reports on Electricity Storage
CRS has written two previous reports on electricity storage: CRS Report R40797, Electric Power
Storage, by (name redacted), and CRS Report R41709, Battery Manufacturing for Hybrid and
Electric Vehicles: Policy Issues, by (name redacted).
Technology Assessment Authorship
This technology assessment and report was prepared by the National Renewable Energy
Laboratory (NREL), Strategic Energy Analysis Center, with contributions from Paul Denholm,
Anne Dillon, Easan Drury, Greg Glatzmaier, (name redacted), Marc Melaina, Jeremy Neubauer,
Doug Reindl (University of Wisconsin-Madison), Shriram Santhanagopalan, Kandler Smith,
Darlene Steward, and Samir Succar (Natural Resources Defense Council). The work was
performed under contract to CRS as part of a multiyear CRS project to examine different aspects
of U.S. energy policy. (name redacted), Assistant Director, Resources, Science, and Industry
Division, served as the CRS project coordinator. (name redacted), Specialist in Energy and
Infrastructure Policy, served as the CRS reviewer and editor of the final report.
Acknowledgement
This report was funded, in part, by a grant from the Joyce Foundation.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Chapter 1: Executive Summary
Background
Energy storage in electric applications can provide two significant benefits to the nation’s energy
system. First, it can improve the technical and economic performance of the electric power grid,
increasing reliability and potentially decreasing costs while allowing greater penetration of
intermittent sources like solar and wind generation. Second, it enables a potential transition from
an oil-based transportation system to one based on an array of domestically sourced electricity
options, greatly reducing dependence on petroleum. In both cases, a reduction in the burning of
fossil fuels could result in lower overall U.S. carbon emissions and conventional pollutants.
For purposes of assessment and comparison, it is helpful to organize the various energy storage
technologies under two industry sectors (electric grid and transportation) and two general
categories of application based on the amount of time the storage device is required to provide
service (high power/rapid discharge and energy management), further explained below. Table 1
lists the storage technologies considered in this report according to these categories. The report
provides an overview of the current capabilities and costs of each storage technology, including
the potential for technical and cost improvement. It also discusses non-technical barriers
including environmental, material, market, and policy challenges to widespread deployment.
Table 1. Energy Storage Applications and Technologies
Electric Grid (Stationary)
Transportation (Vehicular)
High Power /
Rapid Discharge
Batteries
• Lead-Acid
• Nickel
• Lithium-Ion
Capacitors
Flywheels
Superconducting Magnetic Energy
Storage (SMES)
Batteries
• Nickel
Capacitors
Flywheels
Energy
Management
Batteries
• Advanced Lead-Acid
• Flow
• High Temperature
Hydrogen
Compressed Air
Pumped Hydro
Thermal
• Concentrating Solar Power
• End Use
Batteries
• Lithium-Ion
• Lithium-Metal
• Metal Air
Hydrogen
Source: P. Denholm, National Renewable Energy Laboratory, 2011.
Note: Electric power and transportation applications may elsewhere be referred to as “stationary” and
“vehicular,” respectively.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Energy Storage for Electric Grid Applications
It is possible to divide grid storage applications into two broad categories based on the length of
time a storage device needs to provide service: (1) high power applications where the device must
respond rapidly and be able to discharge for only short-term periods (up to about one hour), and
(2) energy management related applications where the device may respond more slowly but must
be able to discharge for several hours or more. Ideally, all storage devices would be able to
provide all services, but some technologies are technically restricted to provide only short-term
services. However, many of these services have very high value in the grid, so short-term storage
can still provide considerable benefits.
High Power/Rapid Discharge Applications
The rapid response category can be further divided into short-term discharge—less than one
minute—used to provide grid stability and power quality, and longer-term discharge—up to about
an hour. Though important, short-term discharge services can often be provided by non-storage
options such as power electronics. Furthermore, this class of grid services does not address the
primary challenge of renewables integration, which requires minutes to hours of discharge time.
Currently, capacitors and superconducting magnetic energy storage (SMES) are rapid response
technologies capable only of providing short-term discharge. Research efforts for both
technologies are focused on increasing energy density and decreasing cost, with capacitor efforts
being directed in part towards vehicle applications. While SMES research has been active
historically, current efforts are modest and there is no clearly defined pathway for SMES to be
competitive for applications requiring extended discharge.
Other grid applications require devices with up to about one hour of discharge to provide services
such as frequency regulation service (responding to random, rapid variations in demand) and
contingency reserves (rapidly responding to a generator or transmission failure). Longer-term
storage can also support renewables integration by providing the subhourly ramping requirements
which will increase as greater amounts of variable generation sources are added to the grid.
Flywheels have been deployed in significant demonstration projects providing frequency
regulation. Several battery types have been demonstrated for both frequency regulation and
operating reserves, including lithium-ion and various aqueous batteries (such as lead-acid, nickelcadmium, and nickel-metal hydride). Most aqueous chemistries are considered mature
technologies, but additional improvements are possible, even for 100+ year-old lead acid
batteries. Research and development efforts on lithium-ion batteries are focused on reducing cost
and weight for transportation applications, but these efforts should have spillover benefits to grid
applications. In addition, there are certain lithium-ion configurations that are probably unsuitable
for transportation applications but potentially suitable for the grid. A major effort by commercial
vendors of rapid response technologies such as flywheels and lithium-ion batteries has been
gaining access to markets for frequency regulation and full valuation of the response capabilities
of the technology.
Energy Management Applications
Grid storage devices for energy management applications can provide continuous discharge for
several hours or more. These devices would be potentially useful for shifting energy during
periods of low demand (or high renewable supply) to periods of high demand (or low renewable
supply). Many of them can also provide the same services as high power/rapid discharge devices.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Pumped hydro storage (PHS) is the dominant technology in this category with about 22
Gigawatts (GW), equivalent to about 22 large power plants, operating in the United States for
decades. PHS has high reliability, high efficiency, and long lifetime, but is dependent on the
availability of suitable geologic conditions and requires long development times (~10 years
including permitting). Based on siting challenges and environmental opposition, PHS suffers
from the perception that these issues will prevent large-scale deployment in the future. However,
the actual technical potential is large and the number of proposed plants exceeds the current
installed capacity, with many of these proposed plants using “closed-cycle” designs that will not
interact with existing water bodies and have the potential to reduce both opposition and licensing
times. They may also use variable speed equipment improving their ability to provide rapid
discharge services.
Compressed air energy storage (CAES) is technically mature, and often considered the lowestcost option for “bulk” electricity storage, although only one such facility is deployed in the
United States. CAES is a hybrid technology which uses natural gas, and typically requires a large
underground formation. Major development efforts for CAES currently underway include
demonstrating the technology in bedded salt and porous rock. Use of such geologic formations
would open up much more of the country to CAES development. Other research and
development activities include work on CAES cycles that do not require natural gas fuel.
Hydrogen and other electricity-derived fuels are possible storage options with the advantage of
long-term (even seasonal) storage. They currently are among the least efficient (well under 50%)
and more expensive storage technologies available and have yet to be deployed beyond small
demonstration projects. Fundamental research efforts are required to decrease the cost and
increase the durability of electrolyzers and fuel cells. Most of the historic research on hydrogen
has been as an alternative fuel for transportation.
Two classes of batteries are currently the primary candidates for electric grid applications—liquid
electrolyte flow batteries and high-temperature batteries. High-temperature sodium-sulfur
batteries are the most mature and commercially available, with over 270MW deployed
worldwide, including installations in the United States. They also have the advantage of relying
on low-cost and abundant materials, although manufacturing costs have limited larger-scale use.
Sodium sulfur is the only high-temperature battery deployed at large scale, currently
manufactured by a single company in Japan. There are several alternative high-temperature
chemistries under various stages of research, development, and commercialization. Flow batteries
are in the early stages of development and commercialization, with a few U.S. demonstration
projects of vanadium and zinc-bromine technologies, with several other technologies under
development.
Thermal energy storage (TES) is often overlooked as an electricity storage technology option
because it does not store and discharge electricity directly. However, in some applications,
thermal storage can be functionally equivalent to electricity storage with efficiencies exceeding
90%, which is higher than most other storage technologies. There are two primary applications of
TES for electricity. The first is storing thermal energy from the sun which is later converted into
electricity. The currently deployed storage medium is a relatively low-cost molten salt. The
primary limitation is that TES is tied to a specific application, in this case concentrating solar
power (CSP), which has the challenges of high cost and limited deployment locations, mostly in
the desert southwest in the United States. The key research efforts include developing storage
materials with higher working temperature, which, when combined with higher temperature CSP
plants, will increase efficiency and decrease costs. CSP with thermal energy storage has been
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
deployed in Spain. Construction of a 250 MW CSP/TES facility in the United States is expected
to begin in 2012. The second application of TES is cold and hot storage in buildings. Cold
storage, used to reduce peak demand from air-conditioning, has been deployed on a relatively
large scale. This is a commercially mature technology that provides firm system capacity at very
high round-trip efficiency, with the capability of providing multiple grid services. The primary
barrier to deployment is capturing the benefits of this distributed technology in the current
regulatory and market environment.
Energy Storage for Transportation Applications
As with grid storage, energy storage for transportation applications can be loosely divided into
two primary categories: high power/rapid discharge and high energy/extended discharge. High
power devices provide short, rapid discharges for vehicle starting and acceleration. While they
cannot provide continuous discharge for electrified transport, they can dramatically improve fuel
efficiency, as demonstrated by the current generation of hybrid electric vehicles. Currently
deployed technologies for these applications include lithium-ion and nickel-based aqueous
batteries. Technologies being explored including capacitors, flywheels, and other battery types.
Some of these technologies, such as capacitors, may also be used as a fast-responding “buffer”
between the electric drive system and the battery or fuel cell in an electric vehicle (EV).
For high energy applications, where stored electricity is actually used to provide a significant
fraction of the driving energy, research and development efforts are currently focused on two
technologies—hydrogen and batteries. Conceptually, hydrogen is a simple storage technology,
produced by splitting water using electricity (among other options), storing hydrogen on board
the vehicle, and then converting it to electricity to drive an electric motor via a fuel cell. (Internal
combustion engines could also be used, but the low efficiency of that process is less attractive.)
The challenges of a hydrogen-based transportation system include the development of an entirely
new fueling infrastructure including hydrogen delivery systems and filling stations, with needed
safety standards and protocols. The low volumetric energy density of hydrogen makes storage
challenging without extremely high-pressure tanks, or advanced chemical storage still in the early
research phase. Finally, fuel cells for vehicles remain expensive, with limited lifetimes. There
have been demonstration fuel cell vehicle programs by several major auto manufacturers, with
announced plans for commercial deployment as soon as 2015. However, substantial research
efforts will be needed to reduce costs and improve performance for many of the technologies
needed for large-scale hydrogen based transportation. There are other electricity-to-fuel pathways
under consideration, but with limited research and development efforts in the United States. They
face similar challenges of requiring new fuel infrastructure and currently face much higher costs
than fossil fuel alternatives.
The primary alternative to electricity-based fuel production is battery electric storage in plug-in
hybrid electric vehicles (PHEVs) and EVs. Most commercially available and proposed EVs and
PHEVs (such as the Chevrolet Volt and Nissan Leaf) use lithium-ion batteries. Research and
development efforts are focused primarily on reducing cost and increasing energy density as well
as safety of lithium-ion technology. Earlier deployed technologies, such as lead-acid used in older
EVs and nickel metal hydride used in current HEVs, are not considered likely candidates in future
EVs due to fundamental limits of energy density. Concerns have been expressed about the largescale availability of several metals used in lithium-ion batteries, as well as its concentration in a
few geographic regions. In the longer term, lithium-metal and metal-air batteries are in the
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research and development phase, with the potential of much higher energy density than currently
available battery types.
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Chapter 2: Background and Scope
In the United States, there are two major motivations for deploying energy storage technologies.
The first is to improve the technical and economic performance of the electric power grid (“the
grid”).7 This includes enabling more efficient utilization of conventional power plants (e.g., coaland gas-fired) supplying the grid through load-leveling and providing fast response grid support
functions (“ancillary services”), among other services. It also includes enabling greater use of
renewable energy sources such as wind and solar generation, which have variable output due to
changing weather conditions. Electricity storage is a potential source of grid flexibility to ease
integration challenges and decrease integration costs for these renewables.
The second motivation for energy storage is to enable greater use of electrified transportation.
The United States is largely self-sufficient for its electricity needs, and has substantial potential to
increase production of low-carbon, domestically sourced electricity from renewable and nuclear
sources (or from coal using carbon capture). Yet many of these sources cannot directly produce
the liquid fuels generally used in conventional vehicles. Electricity storage in batteries or some
other technology (including electricity-derived fuels such as hydrogen) could provide a pathway
to more electrically powered vehicles, and thereby to reducing U.S. dependence on petroleum.
This report provides information and analysis about the current status and future opportunities for
energy storage technologies in electric grid and electric vehicle applications. It attempts to
identify technologies which may have a key role in achieving the objectives stated above. It
discusses key technical and market barriers, along with research and development (R&D) and
policy efforts to reduce those barriers. The report:
•
Describes and discusses briefly how existing storage technologies work, their
most likely applications, and their advantages for particular applications.
•
Describes current limitations of each technology and whether those limitations
might be addressed through R&D efforts.
•
Describes economic or materials barriers that might impede development or
deployment (e.g., requirements for imported precious metals).
•
Assesses the costs (fixed and operational), safety, and effectiveness of each
technology.
•
Assesses the time horizon for market readiness of each technology.
•
Provides a technical overview and status of R&D activities for new and emerging
storage technologies.
Organization of This Report
This report contains 12 chapters, starting with Chapter 1, “Executive Summary,” which provides
an overview of the report’s main findings. Context and background are provided in Chapter 2,
“Background and Scope.” Chapter 3, “Overview of Storage Technology Applications and
7
In this report, the electric power grid, or “the grid,” refers to the electric power transmission and distribution (T&D)
network operated by electric utilities to deliver electricity from generation facilities (including storage) to end users.
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Benefits,” provides an overview of electricity storage applications and value, including their use
to enable renewable electricity; current barriers to deployment; and current initiatives to address
technical, economic, and market barriers. Chapters 4-13 discuss each individual storage
technology, including a general overview, status in the marketplace (including proposed projects),
estimates of current performance, service lifetime, and costs. They also discuss the status of
R&D, including key research needs to enable improvements in cost and performance, as well as
non-technical barriers including environmental challenges, availability of raw materials, and
safety. Each of Chapters 4-13 can be read independently, but Chapters 2 and 3 offer a more
complete understanding of some of the more technologically focused discussions that follow.
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Chapter 3: Overview of Storage Technology
Applications and Benefits
Energy Storage for Electric Power Grids
Electric utilities have long been interested in energy storage technology because of its potential to
support the operation of electric power grids. Historically, one of the most important grid storage
functions has been “load-leveling,” or storing off-peak electricity during periods of low demand
and releasing it during periods of high demand, enabling the decreased use of high-cost peaking
generation. This function has been extended to include support for renewable electricity
generation, given the variable production output of wind and solar plants. More recently, utilities
have also been considering how energy storage can provide a partial alternative to the
development of the power grid itself by helping utilities optimize the use of grid infrastructure
already in place and thereby avoid or defer building new power lines. Other key storage functions
include technical services called “ancillary services” needed to provide electric power
transmission service to a customer. They include actions taken to effect a power transaction (e.g.,
scheduling), services needed to maintain the integrity of the power grid, and services needed to
correct the effects associated with undertaking a power transaction (e.g., supply-demand
balancing).8 As the electric power grid has evolved into a wholesale marketplace for competitive
bulk power purchases while at the same time becoming strained by growth in electricity demand,
the potential for energy storage has grown in importance, driving continued interest in storage
technology development and deployment.
Current Storage Deployment for the Grid
There are approximately 22 GW of utility-scale electric storage capacity in the United States
today, which equates to approximately 2% of the nation’s total existing generation capacity.9
Nearly all of this storage capacity is in the form of pumped hydro storage (PHS), which works by
pumping water from a lower reservoir to an upper reservoir, releasing that stored water through a
hydroelectric generator when electricity is needed (further discussed in Chapter 9). While there
was some development of PHS starting as early as the 1920s, much of the nation’s PHS capacity
was initiated in the mid- to late 1970s.10 This development was the result of a combination of
factors including dramatic price increases in oil and natural gas used for meeting peak electricity
demand, along with concerns about security of supply. These factors culminated in congressional
passage of the Powerplant and Industrial Fuel Use Act of 1978 (P.L. 95-620) restricting use of oil
and gas in new power plants.11 During this period utilities expected to bring online many new
8
Federal Energy Regulatory Commission, Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities, Order No. 888, April 24, 1996, p. 198.
9
U.S. Energy Information Administration, Electric Power Annual, Table 1.2, April 11, 2011, http://www.eia.gov/
cneaf/electricity/epa/epat1p2.html.
10
American Society of Civil Engineers (ASCE),Task Committee on Pumped Storage of the Hydropower Committee of
the Energy Division of the American Society of Civil Engineers, “Compendium of Pumped Storage Plants in the
United States,” American Society of Civil Engineers, New York., 1993.
11
U.S. Energy Information Administration, “Repeal of the Powerplant and Industrial Fuel Use Act (1987),” web page,
October 18, 2011, http://www.eia.doe.gov/oil_gas/natural_gas/analysis_publications/ngmajorleg/repeal.html.
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coal-fired and nuclear power plants to meet relatively steady baseload demand, but were left with
limited options to provide generation capacity to meet daily and hourly load variations (“loadfollowing”) and peak demand.12 This limitation led utilities to actively develop PHS as an
alternative to fossil-fueled intermediate load and peaking generation.
During the 1970s, there was also significant research and development of other storage
technologies including several battery types, capacitors, flywheels, compressed-air, underground
pumped hydro, and superconducting magnetic storage.13 It was expected that deployment of
storage of all types would grow significantly during this period.14 However, most PHS
development, along with interest in and deployment of other emerging storage technologies,
ended in the 1980s after steep natural gas price reductions, improvements in natural gas turbines,
and repeal of the Industrial Fuel Use Act made deployment of flexible natural gas-fired
generation more economically attractive.
Other technical, market, and regulatory factors have also served to limit the deployment of
electricity storage historically. Many of these factors continue today. They are discussed in more
detail later in this chapter and in the individual technology chapters. Briefly, however, a primary
historical challenge of storage deployment has been the limited ability of utilities to estimate and
capture the full economic value of electricity storage, especially the many dynamic benefits to the
grid of fast responding storage technologies.15 Taken together, these factors have restricted
deployment of utility-scale electricity storage in the United States over recent decades. Besides 22
GW of PHS, deployment has been limited to a single 110 MW compressed-air energy storage
(CAES) facility, and a variety of smaller projects. Between 1990 and 2010, only 2 MW of new
PHS was constructed in the United States compared to over 300 GW of new generating
capacity.16
Applications of Energy Storage in the Grid
As noted above, energy storage can be used in many valuable applications for electric power
grids. A 2010 assessment by Sandia National Laboratories, for example, lists 17 distinct
applications and 26 associated benefits of electricity storage.17 Table 2 lists some of the most
commonly cited applications for electricity storage with a basic description of each. It does not
include other possible applications of electricity storage such as “black start” (providing power to
restart the grid after a blackout), power quality, voltage and transmission support, substation on-
12
Concern about the availability of oil and other peaking fuels in this period was so great that a 1979 international
conference on the subject, which included the U.S. National Academy of Sciences, described energy storage as “a vital
element in mankind’s quest for survival and progress.” J. Silverman,(ed). “Energy Storage: A Vital Element in
Mankind’s Quest for Survival and Progress,” Transactions of the First International Assembly held at Dubrovnik,
Yugoslavia, 27 May-1 June, 1979, Pergamon Press, 1980.
13
U.S. Department of Energy, “DOE Interagency Coordination Meeting on Energy Storage,” CONF 7709116, 1977.
14
D.W. Boyd, O.E. Buckley, and C.E. Clark, “Assessment of Market Potential of Compressed-Air Energy-Storage
Systems,” Journal of Energy, 1983, No. 7, pp. 549-556.
15
P. Denholm, E. Ela, B. Kirby, and M. Milligan, The Role of Energy Storage with Renewable Electricity Generation,
NREL/TP-6A2-47187, National Renewable Energy Laboratory, Golden, CO, 2010.
16
U.S. Energy Information Administration, Annual Energy Review, October 19, 2011, Table 8.11a,
http://www.eia.gov/totalenergy/data/annual/showtext.cfm?t=ptb0811a.
17
J. Eyer and G. Corey, Energy Storage for the Electricity Grid: Benefits and Market Potential Assessment Guide: A
Study for the DOE Energy Storage Systems Program, SAND2010-0815, Sandia National Laboratories, February 2010.
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site power, and supplemental reserves. Nor does it include the role of storage in supporting
variable generation, like wind and solar generation, which is discussed in the next section.
Table 2. Major Power Grid Applications of Electricity Storage
Application
Description
Timescale of Operation
Load Leveling/
Arbitrage/
Time-Shifta
Purchasing low-cost off-peak energy and
selling it during peak periods with high
prices.
Response in minutes to hours. Discharge time
of hours.
Firm Capacity
Provide reliable generation capacity to meet
peak system demand.
Must be able to discharge continuously for
several hours or more.
• Regulation
Service
Fast responding increase or decrease in
generation (or load) to respond to random,
unpredictable variations in demand.
Unit must be able to respond in seconds to
minutes. Discharge time is typically minutes.
• Contingency
Spinning
Reserveb
Fast responding increase in generation (or
decrease load) to respond to a contingency
such as a generator failure.
Unit must begin responding immediately and
be fully responsive within 10 minutes. Must be
able to hold output for 30 minutes to 2 hours
depending on the market.
Ramping/
Load Following
Follow longer-term (hourly) changes in
electricity demand.
Response time in minutes to hours. Discharge
time may be minutes to hours.
Transmission and
Distribution
Replacement and
Deferral
Reduce loading on electric power grid during
peak times. Provides an alternative to
expensive and often difficult to site power
lines and substations.
Response in minutes to hours. Discharge time
of hours.
• Time of Use
(TOU) Rates
Functionally the same as arbitrage, just at the
customer site.
Same as arbitrage.
• Demand Charge
Reduction
Functionally the same as firm capacity, just at
the customer site.
Same as firm capacity.
• Backup Power/
Power Quality/
Uninterruptible
Power Supply
Functionally similar to contingency reserve,
just at the customer site.
Instantaneous response. Discharge time
depends on level of reliability needed by
customer.
Operating
Reserves
End-Use
Applications
Source: P. Denholm, et al., The Role of Energy Storage with Renewable Electricity Generation, NREL/TP-6A2-47187,
National Renewable Energy Laboratory, 2010.
a.
Arbitrage, strictly defined, is the simultaneous purchase and sale of the same commodity to take advantage
of price differences in two different markets. Eyer and Corey (2010) consider the term arbitrage a
misnomer as applied to energy storage, however, its use is very common and it is used in this report as
well.
b.
Contingency reserves may be provided by both spinning and non-spinning units, depending on the market.
The requirements for non-spinning reserves are the same except the resource does not need to begin
responding immediately, but still requires full response within 10 minutes. These requirements depend upon
market and market reliability rules. For an example see PJM, PJM Manual 11: Scheduling Operations, Revision
43, September 24, 2009, http://www.pjm.com/markets-and-operations/ancillary-services/~/media/
documents/manuals/m11.ashx.
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The applications in Table 2 can be divided any number of ways into a number of different groups.
However, for purposes of assessment in this report, it is helpful to classify these applications into
two general categories based on the amount of time the storage device is required to provide
service because discharge time is a fundamental characteristic distinguishing most energy storage
technologies. The first category is storage for high power or rapid discharge applications where
the device must be able to discharge for periods of up to about one hour. The second category is
energy management applications where the device must be able to discharge for several hours or
more. Some applications may overlap both categories, depending upon the type of installation in
question, but these categories offer a valid basis for comparison of storage technologies
performing, at least to the first degree, similar functions.
Valuation of Storage for the Grid
Each application of electricity storage for the power grid offers distinct benefits. One of the
challenges facing electricity storage technologies is appropriate valuation of these benefits,
especially in providing multiple services in combination. For example, some storage technologies
can provide load-leveling (and associated benefits such as lower cycling-induced maintenance),
regulation service, contingency reserves, and firm capacity. Historically, it has been difficult to
quantify these various value streams without sophisticated modeling and simulation methods. The
emergence of wholesale electricity markets now provides more transparent data for both utilities
and independent power producers to consider the opportunities for electricity storage.18
Depending on the market, these data allow evaluation of both the economic yield and optimum
location of electricity storage devices for arbitrage, capacity, operating reserves, and other
ancillary services.19
18
As of 2009, wholesale energy markets exist in parts of more than 30 states and cover about two-thirds of the U.S.
population. Independent System Operators and Regional Transmission Organizations Council, 2009 State of the
Markets Report, prepared by the ISO/RTO Council, 2009, http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A08DC3-003829518EBD%7D/2009%20IRC%20State%20of%20Markets%20Report.pdf.
19
R. Sioshansi, P. Denholm, T. Jenkin, and J. Weiss, “Estimating the Value of Electricity Storage in PJM: Arbitrage
and Some Welfare Effects,” Energy Economics, No. 31, 2009, pp. 269-277.
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Figure 1. Estimated Life-Cycle Value of Several Electricity Grid Storage Applications
Source: Compiled from Eyer and Corey, 2010 and Denholm et al., 2010.20
While there is significant variation and uncertainty in costs, most electricity storage assessments
indicate that few commercially available bulk electricity storage technologies are deployable for
less than $1,000/kW. For comparison, Figure 1 summarizes the life-cycle value of several storage
applications estimated in several previous studies in a number of locations. (The life-cycle value
can serve as a proxy for the capital cost needed for storage to be economically viable for each of
these applications.) As Figure 2 shows, $1,000/kW falls within the range of estimated life-cycle
value for all but one of the applications shown, indicating that the storage value could exceed
storage costs in specific applications. For example, energy arbitrage revenues, independent of
other storage benefits, would require a capital cost of less than $1,000/kW over most of the
locations studied. The value of electricity storage increases, however, when taking advantage of
other individual sources of revenue or even combined services. A device with sufficient energy
capacity for energy arbitrage would likely be able to provide system capacity as well. The
combination of these two services could, therefore, likely support a device costing somewhat
more than $1,000/kW.
Figure 1 shows that regulation service and contingency reserves, which are shorter-duration
applications requiring less energy capacity, have potentially higher value than energy arbitrage.
The challenge for these applications is that a device providing contingency reserves must be able
to respond rapidly, which is technically harder to do. Frequency regulation is particularly
demanding, requiring continuous changes in output, frequent cycling, and fast response. It is also
the highest-value opportunity for an electricity storage device, however, and has been the focus of
20
Both studies provide detailed explanation of sources and methods. Regulation value may exceed $4000/kW.
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many potential electricity storage applications, especially given its fairly small energy
requirements.21
Defining the Cost of Electricity Storage
When discussing the costs of storage technologies, a critical issue is that storage devices in electric applications have
both a power component (kW of discharge capacity) and an energy component (kWh of discharge capacity, which may
also be expressed as hours of discharge at rated output). The total cost of a storage application must account for the
ratings of both components, and may be expressed differently depending on the application or audience. Utilities, for
example, universally define the cost of power plants only in terms of rated power ($/kW), so they would expect to
see costs in these terms, with the hours of storage (kWh capacity) expressed separately. A grid storage plant might,
therefore, be expressed as costing $2000/kW for a device with eight hours of discharge capacity. On the other hand,
the battery community typically expresses costs in terms of rated energy ($/kWh), and may or may not include the
power component in the cost. So the cost of a battery might be stated as $500/kWh with the power capacity of the
battery established separately. When evaluating the economics of storage technologies, care must, therefore, be taken
to ensure that the costs for meeting both kW and kWh specifications are included and that both components are
“sized” properly for any specific application.
It is difficult to estimate the total market size for electricity storage in the U.S. grid. The most
comprehensive assessment of market size identifies hundreds of gigawatts of total applications.22
However, some of these applications overlap. For example, end use time-of-use (TOU) rate
management effectively duplicates load-leveling on the wholesale side. Furthermore, several of
the highest-value services, such as regulation service, have the smallest market opportunities.23
Even with these considerations, the potential market for electricity storage is large, and that
market is expected to grow in value and size with the increasing deployment of renewable energy
sources.
21
Frequency regulation theoretically is a net zero energy service over relatively short time scales, meaning the energy
capacity of the device can be much smaller than that of devices providing operating reserves and energy arbitrage.
Several power markets in the United States have changed or have proposed to change their treatment of regulation to
accommodate energy-limited storage technologies. Furthermore, it has been suggested that fast-responding storage
devices could receive a greater value per unit of capacity actually bid, because they could actually reduce the amount of
reserves needed. For example, “faster responsive resources can help to reduce California ISO’s regulation procurement
by up to 40% (on average)” and “California ISO may consider creating better market opportunities and incentives for
fast responsive resources.” Y.V. Makarov, J. Ma, S. Lu, and T.B. Nguyen, “Assessing the Value of Regulation
Resources Based on Their Time Response Characteristics,” Pacific Northwest National Laboratory, PNNL – 17632,
June 2008.
22
Eyer and Corey, 2010.
23
Requirements for frequency regulation resources are typically set for each Independent Service Operator (ISO) or
utility. Regulation requirements frequently change by the month, day, and hour. However, regulation requirements are
about 1% of peak capacity, based on NYISO and ISO-NE regulation requirements for 2009. 1% of peak capacity in the
entire United States corresponds to about 10 GW.
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Energy Storage and Renewable Energy
Renewable energy sources, such as wind and solar generation, create additional opportunities for
energy storage deployment due to the variability and uncertainty of the electricity they produce.
As variable renewable generation (VG)24 from these sources is added to the grid, it can have a
number of operational impacts on the grid, many of which can be mitigated with electricity
storage (or other enabling technologies):
•
Frequency Regulation Requirements—VG adds to the short-term (seconds to
minutes) variability in electric power frequency, which must be maintained very
close to the 60 cycles per second (hertz) for proper and reliable grid operation.25
•
Load Following Requirements—VG adds to the hourly requirements for
generation supply (ramping) on the grid, increasing the cycling and associated
maintenance of conventional generators.
•
Uncertainty in Net Load—Wind availability is less predictable than either the
variation in electric load or the availability of conventional generators. This
uncertainty can increase the cost of power system operation because it can result
in too many or too few generators being available to respond to variation in “net
load,” which is the electric load remaining on the grid after wind power supplies
are added.26
•
Ramping Range and Curtailment—VG increases the difference between the
daily minimum and maximum electricity demand (including an effective
reduction in minimum load) which can force conventional generators to reduce
output. In some cases this difference may force generation units that ought to be
running continuously to cycle off during periods of high wind output, or it can
force wind generators to curtail output, “wasting” renewable generation potential.
•
Transmission Requirements—Some renewable resources, like wind and
concentrating solar power, are remotely located, requiring new transmission to
supply the grid. New transmission is difficult to construct for economic and
24
The variable generation (VG) nomenclature is used by the North American Electric Reliability Corporation (NERC).
See NERC, Accommodating High Levels of Variable Generation, April 2009, http://www.nerc.com/docs/pc/ivgtf/
IVGTF_Outline_Report_040708.pdf.
25
The amount of additional regulation reserves required as a function of VG penetration has yet to be established
definitively, especially since the impact on minute-to-minute regulation requirements is mitigated by aggregating large
amounts of wind power with variability largely uncorrelated in the regulation time frame. However, a recent analysis
by the California Independent System Operator (CAISO) of a 33% renewable portfolio standard suggested that the use
of VG could increase regulation requirements by a factor of two to four. See CAISO, Integration of Renewable
Resources: Transmission and Operating Issues and Recommendations for Integrating Renewable Resources on the
California ISO Controlled Grid, November 2007.
26
This is actually the combination of the uncertainty in load and wind. As VG penetration increases, it begins to
dominate the net load uncertainty. This can also result in a shortage of available generation capacity. An example is the
ERCOT event of Feb. 26, 2008, where a combination of factors—including greater than predicted electricity demand,
forced outage of a conventional generation unit, wind forecast not being given to system operators, and lower than
expected wind production—resulted in too little generation capacity online to meet load. As a result, the ERCOT
system needed to deploy high-cost quick-start generation units and pay customers to curtail load. This issue has
important implications for the use of storage to mitigate uncertainty. Energy storage, like any other generation, must be
scheduled; a storage device used for load leveling may not be able to simultaneously provide hedging against underforecasted wind, because it may already be discharging. See E. Ela, and B. Kirby, ERCOT Event on February 26, 2008:
Lessons Learned, NREL/TP-500-43373. National Renewable Energy Laboratory, July 2008.
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policy reasons, however, and use of dedicated long-distance transmission for
wind or solar will be limited by the relatively low capacity factor of the resource.
Storage could increase line-loading and help reduce wind generation curtailment
due to transmission constraints.27
Figure 2 illustrates several of the above impacts on net load and corresponding operation of the
grid. In this figure, wind generation is subtracted from the load, showing the “residual” or net
load that the utility would need to meet with conventional sources. As the figure shows, the
change in generation the grid would need to provide for load-following purposes (ramp range)
can be much higher than overall load due to the variable contributions of wind power.
Figure 2. Impact on Net Load from Using Wind Generation
Source: P. Denholm, E. Ela, B. Kirby, and M. Milligan, The Role of Energy Storage with Renewable Electricity
Generation, NREL/TP-6A2-47187, National Renewable Energy Laboratory, 2010.
Note: This figure uses load data from the Electric Reliability Council of Texas (ERCOT) in 2005 along with 15
GW of spatially diverse simulated wind data from the same year.
Notwithstanding the potential contribution of storage technologies to grid operation, there is
considerable debate over the “need” for electricity storage with moderate penetration of
renewables. Many of the grid impacts listed above have been evaluated in various wind
integration studies attempting to evaluate the operational feasibility and associated costs of wind
integration. To date, most studies have found a relatively low cost of accommodating wind
27
Co-locating wind and storage has long been proposed to reduce the amount of transmission needed for new
development, coming at the tradeoff of less efficient use of energy storage. See P. Denholm, and R. Sioshansi, “The
Value of Compressed Air Energy Storage with Wind in Transmission-Constrained Electric Power Systems,” Energy
Policy, Vol. 37, pp. 3149-3158. This has been proposed to relieve congestion in the Texas grid, for example, where the
state’s best wind resources are located largely in the sparsely populated western part of the state, and transmission
capacity is limited. See N. Desai, et al., Study of Electric Transmission in Conjunction with Energy Storage
Technology, Lower Colorado River Authority, Texas State Energy Conservation Office, August 21, 2003.
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variability on the grid—typically less than $5/MWh (0.5 cents/kWh), adding less than 10% to the
cost of wind energy—when wind is providing up to 20% of a particular grid system’s demand.28
This low cost, mostly resulting from the large amount of flexible generation already available to
meet the variability in demand, has been used to argue that deployment of storage is not justified
based on variability impacts.29 However, many potentially significant costs, such as the
operations and maintenance costs of increased generator cycling, have yet to be quantified and
are not included in these studies.30 Furthermore, the studies do not consider the economic and
societal challenges associated with transmission expansion, or the option of storage as a method
to supplement new transmission.31 Consideration of these factors would almost certainly increase
the value of storage. A strong argument also can be made that VG will increase the value
proposition for storage, adding to the values that already exist in today’s grid. In general,
renewables are likely to increase the potential market size for electricity storage (for example, by
increasing the amount of certain types of generation reserves needed).
The operational value of combining a dedicated electricity storage device with a specific wind or
solar generation plant is also the subject of debate. Many storage applications dedicated to
individual renewable generators, such as renewables “firming,” which seeks to reduce variability
in renewable power output, are actually specific examples of the more general applications in
Table 2. For example, shifting wind power supply from periods of low demand to periods of high
demand is fundamentally the same as energy arbitrage. The economic benefits of this application
are greatest when the electricity storage operator can choose from all of the generators in a
system, storing electricity from any source instead of storing only wind generation, when demand
is lowest.32
28
J. DeCesaro, K. Porter, and M. Milligan., “Wind Energy and Power System Operations: A Review of Wind
Integration Studies to Date,” The Electricity Journal, Vol. 22, No. 10, December 2009, pp. 34-43.
29
Note that these studies have not necessarily focused on storage and generally do not attempt to determine the optimal
system (including the amount of storage if any) that provides the lowest cost of energy.
30
Wind integration studies typically use proprietary software and data sets, and do not always state which costs are
included or excluded. However, the Western Wind and Solar Integration Study (the highest penetration U.S. integration
study as of 2009) states: “‘Wear and tear’ costs due to increased or harder cycling of units were not taken into account
because these have not been adequately quantified.” See D. Lew et al., “How do Wind and Solar Power Affect Grid
Operations: The Western Wind and Solar Integration Study,” NREL/CP-550-46517, National Renewable Energy
Laboratory, September 2009.
31
The more recent U.S. studies of very high penetration (the Western Wind and Solar Integration Study and the Eastern
Wind Integration Study) require power and energy exchanges over larger areas than typically occur in the existing
system. See. M. Milligan, et al., Large-Scale Wind Integration Studies in the United States: Preliminary Results,
NREL/CP-550-46527, September 2009.
32
There are some exceptions when there are benefits of operationally combining VG and energy storage, typically
through co-location and sharing of certain high-cost components. The best example is integrating thermal storage into a
concentrating solar power (CSP) plant; another example is sharing power electronics in a distributed PV/battery
system. There are several other applications where co-location of VG and storage may make sense. Wind plants placed
in areas of weak transmission can potentially introduce power quality and stability issues, and storage can be a
mitigating technology; however, improved power electronics in modern wind turbines may be a lower-cost alternative.
Finally, combining wind and energy storage has been proposed as an alternative (or supplement) to developing new
transmission capacity. Despite these potential applications, the majority of storage deployed in the grid will likely be a
shared resource, which will benefit the entire system and not just a single generator or load. J.C. Smith et al., “Utility
Wind Integration and Operating Impact State of the Art,” IEEE Transactions On Power Systems, Vol. 22, No. 3,
August 2007. Just as loads are balanced in aggregate, the net load in the future grid—after all VG sources are
included—will be balanced by a mix of conventional generation, plus flexibility options that may include energy
storage.
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Grid Storage with High Renewables Penetration
Perhaps the strongest argument for energy storage in the grid occurs at relatively high penetration
of VG. The oft-cited limits of VG penetration in the range of 10%-20% and the associated “need”
for electricity storage appear to be moving targets as new grid integration techniques develop.
Recent studies have found that 30% penetration (on an energy basis) of renewables on the grid
appears to be feasible without an inherent need for storage to maintain system reliability.33
However, there appear to be some economic limits of VG at high penetration based on the limited
coincidence of VG supply and electricity demand patterns.34 At sufficiently high penetration of
wind or solar generation, VG supply can exceed demand for electricity, which results in curtailed
generation and decreased economic viability of VG. This problem is exacerbated by the cycling or
operational limits on conventional generators, many of which must remain on-line to provide
operating reserves or be available when wind and solar generation is insufficient to meet demand.
Such VG limits can be observed in the Western Wind and Solar Integration Study (WWSIS) with
30% wind penetration, at which wind power supply almost completely removes conventional
generation during high wind periods.35 Figure 3 shows the net load with wind in the study area,
along with the modeled operation (dispatch) of generation plants, which requires significant
ramping of coal generators. In one evening the net load (electricity demand minus wind supply)
drops to about 6 GW, meaning that wind is providing about 32 GW, even after much of the wind
generation is exported to surrounding areas. Doubling the amount of wind generation capacity
would produce a large amount of wind generation curtailment on this day, since the remaining 6
GW of load cannot absorb an additional 32 GW of wind generation, and the conventional
generation units are probably near or at their ability to ramp down or cycle off. Similarly, an
analysis of the Irish grid found limited wind generation curtailment at a wind penetration of 40%
on an energy basis.36 However, beyond this point, wind curtailment rates sharply increase and the
study found economic benefits of storage at the point where about 50% of the system’s energy is
provided by wind.
At higher penetration of renewable generation, the ability of conventional generators to reduce
output becomes an increasing concern. VG begins to displace units that are traditionally not
cycled, and the ability of conventional thermal generators to reduce output may become
constrained.37 Utilities in the United States have expressed concern about their systems
“bottoming out” due to the minimum generation requirements during overnight hours, and being
unable to accommodate more VG during these periods. Cycling operations, including
startup/shutdown, on-load cycling, and high frequency MW changes, can damage generation
equipment. However, the costs of such cycling can be very difficult to quantify.38 Minimum load
points would be less of a constraint if conventional power plants could be quickly shut down and
33
M. Milligan et al., Large-Scale Wind Integration Studies in the United States: Preliminary Results, NREL/CP-55046527, National Renewable Energy Laboratory, September 2009.
34
P. Denholm and M. Hand, “Grid Flexibility and Storage Required to Achieve Very High Penetration of Variable
Renewable Electricity,” Energy Policy, No. 39, 2011, pp. 1817-1830.
35
GE Energy, Western Wind and Solar Integration Study, prepared for National Renewable Energy Laboratory, NREL
Report No. SR-550-47434, May 2010.
36
A. Tuohy and M. O’Malley, “Impact of Pumped Storage on Power Systems with Increasing Wind Penetration,”
Energy Policy, Vol. 39, No. 4, 2011, pp.1965-1974.
37
For example, see M. Milligan, et al., The Impact of Electric Industry Structure on High Wind Penetration Potential,
NREL/TP-550-46273, National Renewable Energy Laboratory, July 2009.
38
S.A Lefton, and P. Besuner, “The Cost of Cycling Coal Fired Power Plants,” Coal Power, Winter 2006.
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started up at low cost. However, with the exception of certain peaking power plants such as
aeroderivative turbines and fast-starting reciprocating engines, most conventional plants have
minimum up-and-down times, and require several hours to restart—at considerable cost.
Figure 3. Generation Dispatch in the WWSIS Study at 30% Wind Penetration
Source: GE Energy (for NREL), 2010.
In some markets, electricity prices have dropped below the actual variable (fuel) cost of
producing electricity on a number of occasions. This indicates that power plant operators are
willing to sell energy at a loss to avoid further reducing output. At this point an increasing
fraction of wind generation will simply be unusable by the system and electricity storage becomes
an increasingly attractive method of shifting otherwise curtailed wind generation to times of
lower wind generation (and/or higher loads). Overall, the increase in energy storage value or
market size associated as a function of increasing VG penetration is not well quantified. In
addition, financial mechanisms for energy storage installations to recover their costs as VGenabling technologies are incomplete.
Ongoing Barriers to Storage Deployment for the Grid
Historically, the primary barriers to energy storage deployment for the grid have been establishing
a positive benefit/cost ratio for storage and actually capturing the economic value that storage
provides. While the emergence of restructured wholesale electricity markets has provided new
storage opportunities, electricity storage still faces significant non-technical barriers to
widespread market acceptance and adoption, further discussed below.
Unquantified and Uncaptured Benefits
Before wholesale electricity markets began to be restructured in the 1990s, the value of ancillary
services and other grid support functions was largely hidden in electric utilities’ cost of service.
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For example, the value of providing operating generation reserves, which affect the ability of a
power plant to respond to the electric grid’s dynamic operating needs, was rarely calculated.39 The
Federal Energy Regulatory Commission (FERC), which regulates wholesale transmission grid
tariffs, and grid operators are increasingly recognizing the value of these services, and the
advantages of electricity storage in providing them, especially because they generally require fast
response and limited energy delivery for which storage devices are well-suited. However, much
of the nation remains in a traditional regulated utility framework, where the benefits of storage in
providing grid support services remain undervalued. Furthermore, wholesale electricity markets
do not capture all the costs of generation plant operation, especially those related to cycling and
ramping. Quantifying the full value of energy storage remains challenging due in part to the
limited ability of utility models to simulate realistic power plant and storage system operation
over multiple time scales.
Wholesale electricity markets also do not capture all the potential benefits of storage to the
electric distribution system (which connects the high voltage grid to electricity end users),
including deferral of new equipment and reduced power line losses.40 Deploying storage in the
distribution system will likely be particularly challenging since distribution will almost certainly
remain a regulated monopoly utility service, with limited exposure to market conditions that
provide incentives for new technologies.
Finally, there are currently few mechanisms in place for potential energy storage operators to
capture economic benefits associated with enabling renewable energy sources. Some value may
be captured indirectly. For example, if VG increases regulation service requirements, then it also
increases market opportunities for storage. However, there are few comprehensive mechanisms to
capture any potential synergies between VG and storage.
Regulatory and Market Uncertainty and Risk
Utilities tend to be risk averse. To meet electricity supply requirements, they tend to rely on
mature generation technologies with which they have long-term experience rather than new
technologies. Conventional generation options, including flexible natural gas-fired turbines,
continue to be the primary option for load following, peak power generation, and ancillary
services. Market uncertainty, combined with a lack of incentives for risk taking in regulated
utilities, discourages the deployment of technologies that are new or have long lead times. Long
development times and risk are a particular challenge for the two leading options for bulk energy
storage—compressed air and pumped hydro. PHS, in particular, faces unique environmental and
other siting challenges (including new transmission requirements), and also faces long permitting
and construction times. The regulatory treatment of energy storage for the grid is often unclear,
and has complicated the financing of large storage projects.41 These issues are discussed in more
detail in the technology sections.
39
S.J. Jabbour, and W.M. Wells, “Optimal Dispatching of Storage Plants with Dynamics,” Proceedings of the Second
International Conference on Compressed Air Energy Storage, EPRI TR-101770, Electric Power Research Institute,
December 1992.
40
A. Nourai, V. I. Kogan, and C.M. Schafer, “Load Leveling Reduces T&D Line Losses,” IEEE Transactions on
Power Delivery, Vol. 23, No. 4, October 2008, pp. 2168-2173.
41
A recent example is the Lake Elsinore Advanced Pumped Storage Project, which applied to be considered a
transmission facility for purposes of utility rate recovery. FERC denied this request, forcing it to recover costs through
an alternative mechanism, such as the more risky (at least for the developer) generation market. Federal Energy
(continued...)
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Lack of Incentives for Customer-Sited Storage
As with deployment by utilities or independent power producers, customer-sited storage faces
challenges of valuation and capturing that value. The benefits of customer-sited storage can
exceed that of centrally deployed storage. In addition to providing load-leveling and ancillary
services, customer-sited storage can provide additional advantages of reduced distribution losses
and increased grid capacity. Some customers, particularly large commercial and industrial
consumers, can capture some of the benefits of load-leveling and peak capacity via time-of-use or
demand-based electricity rates. But many storage benefits, particularly the value of ancillary
services, cannot be captured through their rates. This makes electricity storage uncompetitive for
many electricity end users.
In summary, energy storage for the grid faces significant barriers to being evaluated on the same
economic terms as conventional grid options perceived to be less risky for utilities both in
restructured markets and in traditional integrated utilities. Storage also faces increasing
competition from a variety of technical and market options for providing grid flexibility. New
market mechanisms are being deployed to share generation, reserves, and net loads—all of which
can increase overall power system flexibility.42 Demand response also may compete against new
storage options as a significant source of operating reserves. In many locations in the United
States, demand is increasingly used as a source of grid services. In Texas demand response
typically provides half of the contingency reserve requirements. Other regions also use (or are
evaluating) load to provide regulation. Greater participation of load providing reserves and load
shifting will require regulatory and policy changes in addition to new technologies.
Current Grid Storage Policies
Recognition of the potential value of energy storage for grid applications has led to efforts by
federal and state agencies to engage in storage R&D efforts ranging from analysis of benefits to
providing direct incentives.
Analysis of Storage Benefits
Federal and state agencies have supported a number of studies to evaluate the potential role and
value of energy storage. These studies have demonstrated the potential benefits of traditional
storage applications discussed above.43 Other analyses have identified the unique benefits of fast
response electricity storage technologies (e.g., flywheels) in providing frequency regulation more
efficiently and with fewer emissions than conventional generation.44 Due in part to such analysis,
(...continued)
Regulatory Commission, “FERC Encourages Transmission Grid Investment,” Docket No. ER06-278-000, March 20,
2008.
42
Greater aggregation of loads and reserves has historically been one of the least-cost methods of dealing with demand
variability, especially because it often requires operational changes and relatively little new physical infrastructure.
This includes introducing sub-hourly markets that allow systems faster response to variability. See M. Milligan, et al.,
“The Impact of Electric Industry Structure on High Wind Penetration Potential,” NREL/TP-550-46273, National
Renewable Energy Laboratory, July 2009.
43
Many of these studies have been performed by the Department of Energy’s Energy Storage Systems Research
Program, managed by Sandia National Laboratories.
44
Makarov et al. 2008. As noted earlier the ramp requirement of 1 MW/min could easily be provided by a 1 MW
(continued...)
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there is a growing consensus, for example, that fast-response resources should be paid a premium
for regulation services in wholesale power markets to accurately reflect the value they add to the
electric system.45 As the Chairman of the Federal Energy Regulatory Commission has stated,
Regarding compensation, some storage technologies appear able to provide a nearly
instantaneous response to regulation signals, in a manner that is also more accurate than
conventional resources. These two characteristics can reduce the size, and hence overall
expense, of the regulation market. Most existing tariffs or markets do not compensate
resources for superior speed or accuracy of regulation response, but such payment may be
appropriate in the future....46
Other studies have demonstrated the potential benefit of electricity storage in supporting the
deployment of variable generation47 and reducing distribution losses.48 Analytic efforts like these
help guide policy and market reforms to appropriately capture the value of grid storage services.
Research, Development, and Demonstration Projects
Federal and local agencies have supported basic research, engineering, technology development,
and demonstration programs for many energy storage technologies in grid applications. Until
recently, Department of Energy (DOE) R&D efforts in grid electricity storage were relatively
modest. From 1992 through 2008 the annual budget for the Energy Storage Systems Program
within the DOE’s Office of Electricity Deliverability and Energy Reliability was typically less
than $10 million per year.49 (Programs supporting storage primarily for transportation
applications are discussed in the next section.) In 2010 the DOE budget was increased to $14
million. The American Recovery and Reinvestment Act of 2009 (ARRA) also greatly increased
funding for storage R&D through several programs. Applied research has been supported through
the Advanced Research Projects Agency–Energy (ARPA-E) program, with $30.6M awarded for
FY2010 and $37.7 awarded for FY2011.50
(...continued)
flywheel, but would require about 2 MW of hydroelectric capacity, 3 MW of gas-fired combustion turbine capacity, or
30 MW of gas-fired combined cycle or coal capacity. As a result, using fast responding energy storage to provide
regulation can reduce the amount of regulation required, potentially reducing system costs.
45
Federal Energy Regulatory Commission, Order Accepting Tariff Revisions, Docket ER09-836-000, May 15, 2009.
http://www.nyiso.com/public/webdocs/documents/regulatory/orders/2009/05/
FERC_Ordr_NYISO_Intgrtd_LESRs_NYISO_DAM_RTM_05_15_09.pdf
46
Jon Wellinghoff, Chairman, Federal Energy Regulatory Commission, Testimony before the Senate Committee on
Energy and Natural Resources Hearing on Energy Storage, Dec. 10, 2009.
47
KEMA, Inc., Research Evaluation of Wind Generation, Solar Generation, and Storage Impact on the California
Grid, prepared for the California Energy Commission, Public Interest Energy Research Program, CEC-500-2-1-010,
June 2010.
48
A. Nourai, V.I Kogan, and C.M. Schafer, “Load Leveling Reduces T&D Line Losses,” IEEE Transactions on Power
Delivery, Vol. 23, No. 4, October 2008, pp.2168-2173.
49
J. Boyes, “FY07 DOE Energy Storage Program Peer Review,” Sandia National Laboratories, slide presentation,
2007. http://www.sandia.gov/ess/docs/pr_conferences/2007/boyes_snl.pdf
50
M. Johnson , “Gridscale Rampable Intermittent Dispatchable Storage (GRIDS) Program,” presentation to the DOE
Annual Storage R&D Review Meeting, November 2010. http://www.sandia.gov/ess/docs/pr_conferences/2010/
johnson_doe.pdf
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Electricity storage demonstrations have been funded directly through the ARRA with a total
funding of $185 million.51 Demonstration programs are particularly important in the electric
utility sector, since regulated utilities are typically not rewarded for risk taking, and have few
incentives to be the first to deploy new technologies. These funding activities are discussed in
more detail in the technology chapters. State agencies have also supported electricity storage
demonstrations, often with co-funding from federal agencies. Examples include New York State
Energy Research and Development Authority (NYSERDA) support of demonstration programs
for flywheels and several battery technologies.52 The California Energy Commission (CEC) also
has supported at least 20 storage research and demonstration projects since 1990.53
Market Rules
Securing the ability of energy storage to compete on common terms against traditional generation
assets is a critical challenge for grid storage developers. The creation of wholesale markets allows
increased participation of electricity storage devices, but the level of participation varies by
market. In 2007 FERC issued Order 890 requiring wholesale markets to consider non-generation
resources for grid services. The order required that non-generation resources (including energy
storage and demand response) be evaluated on a comparable basis to services provided by
generation resources in meeting mandatory reliability standards, providing ancillary services, and
planning the expansion of the transmission grid.54
Since that time Independent System Operators (ISOs) and Regional Transmission Organizations
(RTOs), the entities that operate regional power grids, have increased market access, including
creating new tariffs for electricity storage.55 56 In October 2011, FERC issued Order 755 requiring
a new compensation method for grid regulation service “to remedy undue discrimination” against
faster-ramping resources such as energy storage.57
Several large-scale grid storage projects have been proposed or constructed to take advantage of
high-value ancillary service markets. Examples of operating projects include a 20 MW flywheel
facility in New York and a 12 MW battery facility in Chile.58 However, market rules are still
51
E. Christy, “Energy Storage Systems Program: 2010 Update Conference” National Energy Technology Laboratory.
November 2, 2010. http://www.sandia.gov/ess/docs/pr_conferences/2010/christy_doe.pdf
52
G. Huff, “NYSERDA/DOE Joint Energy Storage Initiative,” Sandia National Laboratories, November 2, 2010.
http://www.sandia.gov/ess/docs/pr_conferences/2010/huff_snl.pdf
53
P. Kulkarni, “California Energy Commission Support for Electricity Energy Storage,” California Energy
Commission, May 6, 2009. http://bscleantech.org/bscc3/presentations/Technology%20-%20CEC%20%20Pramod%20Kulkarni.pdf
54
Federal Energy Regulatory Commission, Preventing Undue Discrimination and Preference in Transmission Service,
Order No. 890, February 16, 2007.
55
For example, the New York ISO created a “limited energy storage resource”(LESR) tariff. In its approval of the
tariff, FERC stated “We find that the proposed tariff revisions to incorporate LESRs will benefit NYISO’s markets by
providing them with a new source of regulation service with unique operational characteristics that enable very fast
responses to needs for regulation.” Federal Energy Regulatory Commission, Order Accepting Tariff Revisions, Docket
ER09-836-000, May 15, 2009. http://www.ferc.gov/EventCalendar/Files/20090515142559-ER09-836-000.pdf
56
Federal Energy Regulatory Commission, Order Conditionally Accepting Stored Resources Compliance Filing,
Docket No. ER09-1126-001, May 10, 2009.
57
Federal Energy Regulatory Commission, Frequency Regulation Compensation in the Organized Wholesale Power
Markets, Order No. 755, October 20, 2011.
58
Sonal Patel, “Milestones for Flywheel, Lithium Battery Grid-Scale Projects,” Power, August 1, 2011.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
evolving in some regions and much of the United States has no access to restructured energy
markets to begin with.59 Uncertainty remains as to how storage assets should be able to capture
multiple value streams. Challenges remain in gaining access to distribution and customer-sited
storage. One storage company has developed a business model in which customer-sited storage is
owned by the utility as a peak generation and load shifting asset.60
Incentives for Deployment
There have been a number of financial incentive programs for grid storage technologies offered
by the federal government. In addition to the direct funding of demonstration programs, the
ARRA amended the DOE’s Loan Guarantee Program making certain electricity storage
technologies eligible.61 This program has been applied to a large solar plant in Arizona, discussed
in Chapter 12. The ARRA also established a manufacturing tax credit that could potentially be
applied to electricity storage manufacturing facilities. Several states have incentives supporting
deployment of renewable energy and energy efficiency devices which could be applicable to
storage-related equipment including fuel cells and cold thermal storage, but the impact of these
programs on actual adoption has been modest. Finally, certain renewable generators are eligible
for a 30% federal investment tax credit (ITC), currently scheduled to expire in 2016. This means
that thermal energy storage for concentrating solar power is eligible, since it is integrated into a
renewable generator. However, stand-alone storage technologies are not covered, since they are
typically not integrated into individual renewable generation installations.
A federal direct incentive program was proposed in 2010, which included a 20%-30% ITC for
new storage investments depending on size and application.62 Various other federal energy and
climate-change proposals have included language either providing financial incentives for or
otherwise encouraging energy storage deployment for the grid, but these proposals have yet to be
enacted.
Storage Portfolio Standards
Recently there have been proposals for government-mandated energy storage portfolio standards,
similar to renewable portfolio standards (which require utilities to purchase a certain portion of
their energy supplies from renewable generators).63 One example that has been enacted in state
law is California’s AB 2514, which as originally proposed required certain utilities to install
59
See, for example: “Revised Draft Final Proposal for Participation of Non-Generator Resources in California ISO
Ancillary Services Markets.” California Independent System Operator, March2010.
60
Ice Energy, “SCPPA to Undertake Industry’s Largest Utility-Scale Distributed Energy Storage Project,” press
release, January 27, 2010. http://www.ice-energy.com/content10197
61
The loan guarantee program was created to support the deployment of innovative clean energy technologies pursuant
to Section 1703 of Title XVII of the Energy Policy Act of 2005. Title XVII was amended by the American Recovery
and Reinvestment Act of 2009 to create Section 1705, a new program for deploying renewable energy and electric
power transmission projects.
62
“Storage Technology for Renewable and Green Energy Act of 2010,” S. 3617, 111th Cong., 2nd Sess, 2010.
63
Brian Nese, “Energy Storage Developers Call for National Storage Portfolio Standard,” Renewable + Law, Internet
blog, July 21, 2009. http://www.lawofrenewableenergy.com/2009/07/articles/power-storage/energy-storagedevelopers-call-for-national-storage-portfolio-standard/
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storage devices to meet 2.25% of peak demand. As passed, the bill requires the California Public
Utilities Commission to determine targets by March 1, 2012.64
Storage for Electric Transportation Applications
Transportation Storage Technologies and Pathways
The primary purposes of electrifying transportation are to reduce dependence on oil, which
currently provides most of the nation’s transportation fuel, and to reduce vehicle emissions. There
are two pathways to store electricity for use in electric vehicle (EV) fleets (Figure 4).65 The first
is switching from oil-derived fuels to one of several electricity-derived fuels, either gaseous or
liquid, with hydrogen receiving the most attention in recent years. These alternative fuels can be
produced using electricity (for example, by splitting hydrogen from oxygen atoms in water) either
centrally or near the point of use. They can then be burned in a vehicle using a modified internal
combustion (IC) engine and a conventional drive train. Such fuels can also be burned in an IC
engine-electric drive train (hybrid-electric) vehicle configuration (HEV), or in a similar fuel cell
electric vehicle (FCEV) configuration. The second pathway for electrified transport is to store
electricity on board the vehicle, primarily using batteries, and to use that stored electricity to
power an electric motor. The vehicle can be either a “pure” battery electric vehicle (BEV) or a
vehicle that uses both stored grid electricity and an IC or fuel cell engine, typically referred to as
a plug-in hybrid electric vehicle (PHEV).
Figure 4. Pathways to Vehicle Electrification
Source: P. Denholm, National Renewable Energy Laboratory.
Key: B = battery, EV = electric vehicle, FC = fuel cell, H = hybrid, IC = internal combustion, P = plug-in.
64
California Legislature, A.B. 2514 (introduced), February 19, 2010. http://leginfo.ca.gov/pub/09-10/bill/asm/ab_25012550/ab_2514_bill_20100219_introduced.pdf ); and A.B. 2514 (approved), September 29, 2010.
http://www.leginfo.ca.gov/pub/09-10/bill/asm/ab_2501-2550/ab_2514_bill_20100929_chaptered.pdf
65
This report does not consider alternative fuels, such as ethanol, that are not primarily derived from electricity.
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Impacts and Benefits of Vehicle Electrification
The most obvious benefit of vehicle electrification is reduced dependence on petroleum-derived
fuels. The amount of displaced petroleum depends on the degree of electrification of individual
vehicles and of the fleet as a whole. An FCEV running on hydrogen or a pure electric vehicle uses
no gasoline, while a PHEV could reduce a large fraction of gasoline use, depending on battery
size and driving patterns.
Shifting from gasoline to electricity may have a number of impacts on the electric power grid.
One possible outcome is a need for new generation capacity for battery charging. However, the
availability of off-peak generation is estimated to be sufficient for a large number of vehicles
assuming some level of “smart” charging. A 2007 study estimated that spare generating capacity
could have electrified 73% of light-duty gasoline vehicles in 2002.66 This level of vehicle
electrification would displace petroleum equivalent to more than 50% of the nation’s oil imports.
Another study used a somewhat more conservative methodology to estimate that the bulk power
system in 2002 could have supported electrification of approximately 37% of vehicle miles
traveled (VMTs).67 The Electric Power Research Institute (EPRI) analyzed a scenario with 20%
of VMTs in the United States powered by electricity in 2030; the modeled electric generating
capacity was just 1.7% higher in this scenario compared to the base case scenario that assumed no
EVs or PHEVs.68 Other, regional studies similar have concluded that, essentially, if vehicles
charge off-peak, a large number of vehicles can be accommodated, but if on-peak charging is
allowed, there could be increased generation requirements during peak periods of electricity
demand.69 On the electric distribution side, the impacts of vehicle electrification are more
complex. In some locations, a concentration of vehicle charging could exceed the capacity of
distribution systems, and increased loads could shorten the lifetimes of distribution transformers.
Distribution system impacts and the need for upgrades, as well as the ability to reduce the impacts
via smart charging schemes, will need to be further evaluated, typically on a local level.70
EVs and PHEVs generally produce lower greenhouse gas emissions per mile than conventional
vehicles. The amount of reduction depends on numerous assumptions about vehicle performance
and the mix of electricity supplies used for charging. One estimate is that a PHEV powered by an
average proportion of coal-generated electricity produces carbon emissions per mile similar to
those of an HEV.71 If the PHEV is charged using the current grid average emissions, carbon
66
M. Kintner-Meyer et al., Impacts Assessment of Plug-In Hybrid Vehicles on Electric Utilities and Regional U.S.
Power Grids. Part 1: Technical Analysis, Pacific Northwest National Laboratory, 2007.
67
The biggest difference between the methods is estimating which generating capacity is available and economical to
use to charge vehicles during the peak months. C.H. Stephan and J. Sullivan, “Environmental and energy implications
of plug-in hybrid-electric vehicles,” Environmental Science & Technology, Vol. 42 No. 4, 2008, pp. 1185-1190.
68
M. Duvall and E. Knipping, Environmental Assessment of Plug-In Hybrid Electric Vehicles. Volume 1: Nationwide
Greenhouse Gas Emissions, Electric Power Research Institute, 2007.
69
Examples include: P. Denholm and W. Short, An Evaluation of Utility System Impacts and Benefits of Optimally
Dispatched Plug-In Hybrid Electric Vehicles, NREL/TP-620-40293, National Renewable Energy Laboratory, 2006;
and K. Parks, P. Denholm, and T. Markel., Costs and Emissions Associated with Plug-In Hybrid Electric Vehicle
Charging in the Xcel Energy Colorado Service Territory, NREL/TP-640-41410, National Renewable Energy
Laboratory, 2007.
70
C. Farmer et al., “Modeling the Impact of Increasing PHEV Loads on the Distribution Infrastructure,” 43rd Hawaii
International Conference on System Sciences (HICSS), January 5-8, 2010. http://www.cems.uvm.edu/~phines/
publications/2010/farmer_2010_phev_distribution.pdf.
71
In the worst case scenario for a PHEV, net CO2 emissions are about the same as those of a conventional vehicle. Any
electricity supply mix less than 100% coal-generated will be cleaner. See C.H. Stephan, and J. Sullivan,
(continued...)
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emissions per mile are reduced by almost 60% compared to a conventional vehicle.72 Air
pollutant emission changes due to EV and PHEV penetration are complicated because they
depend on the type of generators used for electricity production, the pollution control equipment,
and policies that limit emissions. A California study projects that PHEVs would reduce nitrogen
oxide (NOx) and volatile organic compound (VOC) emissions per mile by 87% and 97%,
respectively, due to limits on the emissions of these pollutants.73 Estimates from other regions
project changes over a large range, including some locations where net emissions could increase
if current power plants do not install new pollution control devices.74 For example, one study
found that life cycle NOx emissions changes could range from -70% (assuming charging with
renewable generation) to +38% (charging with uncontrolled coal-fired plants) assuming no
pollution control policies.75 The actual impact on air quality is even more complex because
PHEVs displace emissions from urban areas to rural areas where power plants are typically
located and fewer people live. Estimates using air quality models generally indicate improved air
quality in urban areas as a result of vehicle electrification.76
When parked, vehicles could potentially provide various grid services. Charging of EVs can
potentially be controlled and can provide a source of dispatchable demand and demand response.
Controlled charging can be timed to periods of greatest VG output, while charging rates can be
controlled to provide contingency reserves or frequency regulation reserves. Vehicle-to-grid
(V2G) (where EVs can partially discharge stored energy to the grid) may provide additional value
by acting as a distributed source of energy storage. Most proposals for V2G focus on short-term
response services such as frequency regulation and contingency. Their ability to provide energy
services is more limited by both the storage capacity of the battery and the high cost of battery
cycling. This could restrict their ability to provide time shifting (energy arbitrage) beyond their
ability to perform controlled charging.77 The role of V2G is an active area of research. Because
(...continued)
“Environmental and Energy Implications of Plug-in Hybrid-Electric Vehicles,” Environmental Science & Technology,
Vol. 42 No. 4, 2008, pp.1185-1190.
72
One study shows slightly less relative reductions in life cycle carbon emissions because the carbon emissions due to
vehicle production (excluding the batteries) are similar, and battery production represents 2-5% of life cycle carbon
emissions from a PHEV. See C. Samaras and K. Meisterling,“Life Cycle Assessment of Greenhouse Gas Emissions
from Plug-in Hybrid Vehicles: Implications for Policy,” Environmental Science & Technology, Vol. 42 No. 9, 2008,
pp. 3170-3176.
73
J. Pont, Full Fuel Cycle Assessment: Well-to-Wheels Energy Inputs, Emissions, and Water Impacts, California
Energy Commission, 2007.
74
The Electric Power Research Institute (EPRI) has projected that, although coal-fired power plants would provide
much of the charging for PHEVs in 2030, most charging would nonetheless be from sources with pollution control
equipment (new, existing, and retrofitted). Emissions of NOx, SO2, and VOCs were therefore projected to go down with
PHEV penetration. See M. Duvall and E. Knipping, Environmental Assessment of Plug-In Hybrid Electric Vehicles.
Volume 2: United States Air Quality Analysis Based on AEO-2006 Assumptions for 2030, Electric Power Research
Institute, 2007.
75
L. Gaines et al. (2007), “Sorting through the Many Total-Energy-Cycle Pathways Possible with Early Plug-In
Hybrids,” Electric Vehicle Symposium (EVS23), Anaheim, CA, December 2-5, 2007.
76
EPRI used an air quality model to project that the PHEVs would reduce population exposure to ozone and particulate
matter. Another study used a utility simulation model to project that PHEV charging in Colorado would come primarily
from natural gas-fired power plants if there were no change in the electric generating fleet. This would lead to
significant reductions in NOx and VOC emissions in the Denver metro area, leading to modest improvements in ozone
concentrations. See G.L. Brinkman et al. “Effects of Plug-In Hybrid Electric Vehicles on Ozone Concentrations in
Colorado,” Environmental Science & Technology, Vol. 44 No.16, 2010, pp. 6256-6262.
77
This conclusion depends on the anticipated cycle life and cost of EV batteries. However, controlled charging
(without V2G) is still a potentially significant source of flexibility, with the ability to raise the minimum load and avoid
(continued...)
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electric vehicles in any form have yet to achieve significant market penetration, assessing their
potential as a source of grid flexibility is difficult. However, analysis has demonstrated potential
system benefits of both controlled charging and V2G.78
Barriers to Deployment and Policies to Increase Vehicle Electrification
A primary barrier to deployment of electric vehicles is their cost and availability. After the
discontinuation of commercially produced electric passenger vehicles in the early 1990s, and
before the introduction of the Nissan Leaf and Chevrolet Volt in late 2010, there were no massproduced electric passenger vehicles available in the United States.79 The costs of the current
generation of EVs and PHEVs are high—with recent prices for the Leaf and Volt about $35,000
and $39,000, respectively.80 The earliest projected deployment of fuel cell vehicles is 2015. While
the performance of battery technologies continues to improve, it is unclear when costs will reach
the point needed for large scale adoption.81
There are a number of federal and state policies targeted towards increasing the use of battery
electric and fuel cell vehicles. These include R&D efforts through the American Recovery and
Reinvestment Act of 2009 (ARRA, discussed in detail in the corresponding technology chapter).
ARRA also provides $2 billion toward grants for the manufacturing of advanced battery systems
and electric vehicle components. These funds are intended to support domestic manufacturing of
advanced lithium-ion batteries and hybrid electric systems and components. To incentivize
adoption, ARRA supports tax credits for the purchase of PHEVs. A comprehensive summary of
current federal and state incentives is provided at the Alternative Fuels & Advanced Vehicles Data
Center.82
Other critical barriers include a lack of existing infrastructure for vehicle fueling and charging.
For hydrogen fueled FCEVs or HEVs, entirely new infrastructure is needed for fuel production,
transport and refueling. (These issues are discussed in more detail in the hydrogen chapter.) For
EVs, lack of charging infrastructure, combined with limited range of pure electric vehicles
(...continued)
curtailment. For additional discussion of the impact of battery life and cycling on the value of V2G, see S.B. Peterson,
J.F. Whitacre, and J. Apt, “The Economics of Using PHEV Battery Packs for Grid Storage,” Journal of Power Sources,
No. 195, 2010, pp. 2377-2384; and R. Sioshansi, R. and P. Denholm, “The Value of Plug-In Hybrid Electric Vehicles
as Grid Resources,” The Energy Journal, Vol. 31 No. 3, 2010, pp. 1-23.
78
Short, W., and P. Denholm. (2006) “A Preliminary Assessment of Plug-In Hybrid Electric Vehicles on Wind Energy
Markets” NREL/TP-620-39729.
79
Some non-highway, low speed vehicles (neighborhood electric vehicles, or NEVs) were available over this time.
80
Prices are manufacturer’s suggested retail price (MSRP) before federal tax incentives. Nissan USA, “Nissan LEAF,”
Web page, 2011. http://www.nissanusa.com/leaf-electric-car/index#/leaf-electric-car/index; General Motors, “2011
Volt,” 2011. http://www.chevrolet.com/volt-electric-car/.
81
General Motors, in its recent IPO stated “In some cases, the technologies that we plan to employ, such as hydrogen
fuel cells and advanced battery technology, are not yet commercially practical and depend on significant future
technological advances by us and by suppliers. For example, we have announced that we intend to produce by
November 2010 the Chevrolet Volt, an electric car, which requires battery technology that has not yet proven to be
commercially viable. There can be no assurance that these advances will occur in a timely or feasible way.” Securities
and Exchange Commission (2010) Amendment to No. 9 to Form S-1 Registration Statement under the Securities Act of
1933 General Motors Company http://www.sec.gov/Archives/edgar/data/1467858/000119312510262471/
ds1a.htm#rom45833_2
82
U.S. Department of Energy, Alternative Fuels and Advanced Data Center, “Federal & State Incentives and Laws,”
website, 2011. http://www.afdc.energy.gov/afdc/laws/state.
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presents a barrier to large-scale adoption, especially for those who do not have access to secure
charging at home.83 Current electric rate structures also create a barrier, preventing both
maximum benefit of controlled charging to the grid, and lowest-cost charging for the consumer.
83
For more discussion of charging infrastructure issues see T. Markel, Plug-in Electric Vehicle Infrastructure: A
Foundation for Electrified Transportation, Report No. CP-540-47951, National Renewable Energy Laboratory, 2010.
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Chapter 4: Batteries for Grid Applications
Overview
Batteries are devices that store energy chemically. This report focuses on “secondary” batteries,
which must be charged before use and which can be discharged and recharged (cycled) many
times before the end of their useful life. For electric power grid applications, there are four main
battery types of interest:
•
Lead-acid
•
High temperature “sodium-beta”
•
Liquid electrolyte “flow” batteries
•
Other emerging chemistries84
Lead-acid batteries have been used for more than a century in grid applications and in
conventional vehicles for starting, lighting, and ignition (SLI). They continue to be the
technology of choice for vehicle SLI applications due to their low cost. Consequently, they are
manufactured on a mass scale. In 2010, approximately 120 million lead-acid batteries were
shipped in North America alone.85 Lead-acid batteries are commonly used by utilities to serve as
uninterruptible power supplies in substations, and have been used at utility scale in several
demonstration projects to provide grid support.86 Use of lead acid batteries for grid applications is
limited by relatively short cycle life. R&D efforts are focused on improved cycle-life, which
could result in greater use in utility-scale applications.
Sodium-beta batteries include sodium-sulfur (NaS) units, first developed in the 1960s,87 and
commercially available from a single vendor (NGK Insulators, Ltd.) in Japan with over 270 MW
deployed worldwide.88 A NaS battery was first deployed in the United States in 2002.89 There are
now a number of U.S. demonstration projects, including several listed in Table 3. The focus of
NaS deployments in the United States has been in electric distribution deferral projects, acting to
reduce peak demand on distribution systems, but they also can serve multiple grid support
84
Several of the battery types discussed in this chapter have been demonstrated or proposed for transportation
applications as well. However, they also have challenges in achieving the energy density or other characteristics needed
for storing large amounts of energy in mobile applications. Batteries for electric vehicles are discussed in Chapter 5.
85
Battery Council International, “Breakdown of North American Battery Shipments (2001-2010),” Chicago, November
4, 2011. http://www.batterycouncil.org/LeadAcidBatteries/BreakdownofShipments/tabid/173/Default.aspx
86
Electric Power Research Institute and U.S. Department of Energy (EPRI/DOE), EPRI-DOE Handbook of Energy
Storage for Transmission and Distribution Applications, Palo Alto, CA, No. 1001834, December, 2003. A 10 MW, 40
MWh lead-acid battery was built in Southern California in 1988. It operated for about nine years. A 21 MW, 14 MWh
lead-acid plant was built in Puerto Rico in 1994 to provide spinning reserves. It operated for about five years.
87
X. Lu et. al., “Advanced materials for sodium-beta alumina batteries: status, challenges, and perspectives,” Journal
of Power Sources, No. 195, 2010, pp. 2431-2442.
88
D. Rastler, “New Demand for Energy Storage,” Electric Perspectives, Edison Electric Institute, September 2008.
89
Nourai, A., “Installation of the First Distributed Energy Storage System (DESS) at American Electric Power (AEP):
A Study for the DOE Energy Storage Systems Program.” SAND2007-3580. Albuquerque, NM: Sandia National
Laboratories, June 2007. http://www.electricitystorage.org/images/uploads/docs/Sandia_First_Storage_AEP.pdf
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services. An alternative high-temperature battery, sodium-nickel-chloride, is in the early stages of
commercialization.90
Table 3. Example NaS Battery Installations in the United States
Installation
Date
Sizea
(MW/MWh)
Developer
Location
0.1/0.72
AEPb
Gahanna, OH (First U.S. demonstration)
2002
1.0/7.2
AEPb
North Charleston, WV
2006
2.0/14.4
AEPc
Bluffton, OH; Balls Gap, WV; East Busco, IN
2008
1.0
New York Power Authorityd
Long Island, NY
2008
4.0
AEPc
Presidio, TX
2009
1.0/7.2
Xcel Energye
Luverne, MN
2009
Source: National Renewable Energy Laboratory compilation.
a.
Continuous rating.
b.
A. Nourai, Installation of the First Distributed Energy Storage System (DESS) at American Electric Power (AEP): A
Study for the DOE Energy Storage Systems Program, SAND2007-3580, Sandia National Laboratories,
Albuquerque, NM, June, 2007.
c.
AEP, Energy Storage in T&D Applications, slide presentation, May 2009. http://www.aeptechcentral.com/docs/
NAS-Presentation.pdf
d.
G. Sliker, “Long Island Bus: NaS Battery Energy Storage Project,” slide presentation, New York Power
Authority, September 29, 2009. http://www.sandia.gov/ess/docs/pr_conferences/2008/sliker_nypa.pdf
e.
Xcel Energy, “Wind-To-Battery Project,” fact sheet, November 2008. http://www.xcelenergy.com/staticfiles/
xe/Corporate/Environment/wind-to-battery%20fact%20sheet.pdf
“Flow” batteries, in which a liquid electrolyte flows through a chemical cell to produce
electricity, are in the early stages of commercialization. In grid applications there has been some
deployment of two types of flow battery: vanadium redox and zinc-bromide. There are a number
of international installations of vanadium redox units, including a 250 kW installation in the
United States to relieve a congested transmission line.91 There are also a number of zinc-bromine
demonstration projects.92 Several other flow battery chemistries have been pursued or are under
development, but are less mature.
In addition to the three battery types discussed above, there are several emerging technologies
based on new battery chemistries which may also have potential in grid applications. Several of
these emerging technologies are being supported by DOE efforts such as ARPA-E and are
discussed briefly in the R&D section of this chapter.
90
J. Baker, “New Technology and Possible Advances in Energy Storage,” Energy Policy, Vol. 36, 2008, pp. 4368–
4373.
91
EPRI/DOE, 2003. The U.S. unit was installed by Pacificorp in 2004 in Moab, UT.
92
EPRI/DOE, 2003.
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Technology
Description and Performance
Lead-Acid
The lead-acid battery consists of a lead dioxide positive electrode (cathode), a lead negative
electrode (anode), and an aqueous sulfuric acid electrolyte which carries the charge between the
two. During discharge, each electrode is converted to lead sulfate, consuming sulfuric acid from
the electrolyte. When recharging, the lead sulfate is converted back to sulfuric acid, leaving a
layer of lead dioxide on the cathode and pure lead on the anode. In such conventional “wet”
(flooded) cells, water in the electrolyte is broken down to hydrogen and oxygen during the
charging process. In a vented wet cell design, these gases escape into the atmosphere, requiring
the occasional addition of water to the system. In sealed wet cell designs, the loss of these gases is
prevented and their conversion back to water is possible, reducing maintenance requirements.
However, if the battery is overcharged or charged too quickly, the rate of gas generation can
surpass that of water recombination, which can cause an explosion.
In “valve regulated gel” designs, silica is added to the electrolyte to cause it to gel. In “absorbed
glass mat” designs, the electrolyte is suspended in a fiberglass mat. The latter are sometimes
referred to as “dry” because the fiberglass mat is not completely saturated with acid and there is
no excess liquid. Both designs operate under slight constant pressure. Both also eliminate the risk
of electrolyte leakage and offer improved safety by using valves to regulate internal pressure due
to gas build up, but at significantly higher cost than wet cells described above.93
Lead-acid is currently the lowest-cost battery chemistry on a dollar-per-kWh basis. However, it
also has relatively low specific energy (energy per unit mass) on the order of 35 Wh/kg and
relatively poor “cycle life,” which is the number of charge-discharge cycles it can provide before
its capacity falls too far below a certain percentage (e.g., 80%) of its initial capacity. While the
low energy density of lead-acid will likely limit its use in transportation applications, increase in
cycle life could make lead-acid cost-effective in grid applications.
The cycle life of lead-acid batteries is highly dependent on both the rate and depth of discharge
due to corrosion and material shedding off of electrode plates inside the battery. High depth of
discharge (DoD) operation intensifies both issues. At 100% DoD (discharging the battery
completely) cycle life can be less than 100 full cycles for some lead-acid technologies. During
high rate, partial state-of-charge operation, lead sulfate accumulation on the anode can be the
primary cause of degradation. These processes are also sensitive to high temperature, where the
rule of thumb is to reduce battery life by half for every 8°C (14°F) increase in temperature above
ambient.94 Manufacturers’ warrantees provide some indication of minimum performance
expectations, with service life of three to five years for deep cycle batteries, designed to be mostly
discharged time after time. SLI batteries in cars have expected service lives of five to seven years,
with up to 30 discharges per year depending on the rate of discharge. Temperature also affects
93
94
D. Linden and T. Reddy, Handbook of Batteries, 3rd ed., McGraw Hill, New York, 2002.
Ibid.
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capacity, with a battery at -4°C (25°F) having between roughly 70% and 80% of the capacity of a
battery at 24°C (75°F).95
For many applications of lead-acid batteries, including SLI and uninterruptible power supply
(UPS), efficiency of the batteries is relatively unimportant. One estimate for the DC-DC (direct
current) efficiency of utility-scale lead acid battery is 81%, and AC-AC (alternating current)
efficiency of 70%-72%.96
High Temperature Sodium-Beta
Sodium-beta batteries use molten (liquid) sodium for the anode, with sodium ions transporting the
electric charge. The two main types of sodium-beta batteries are distinguished by the type of
cathode they use. The sodium-sulfur (Na-S) type employs a liquid sulfur cathode, while the
sodium-nickel chloride (Na-NiCl2) type employs a solid metal chloride cathode. Both types
include a beta-alumina solid electrolyte material separating the cathode and anode. This ceramic
material offers ionic conductivity similar to that of typical aqueous electrolytes, but only at high
temperature. Consequently, sodium-beta batteries ordinarily must operate at temperatures around
300°C (572°F).97 The impermeability of the solid electrolyte to liquid electrodes and its minimal
electrical conductivity eliminates self discharge and allows high efficiency.98
Technical challenges associated with sodium-beta battery chemistry generally stem from the high
temperature requirements. To maintain a 300°C operating point the battery must have insulation
and active heating. If it is not maintained at such a temperature, the resulting freeze-thaw cycles
and thermal expansion can lead to mechanical stresses, damaging seals and other cell
components, including the electrolyte.99 The fragile nature of the electrolyte is also a concern,
particularly for Na-S cells. In the event of damage to the solid electrolyte, a breach could allow
the two liquid electrodes to mix, possibly causing an explosion and fire.100
Na-S batteries are manufactured commercially for a variety of grid services ranging from shortterm rapid discharge services to long-term energy management services.101 The DC-DC efficiency
is about 85%. Calculation of the AC-AC efficiency is complicated by the need for additional
heating. The standby heat loss for each 50 kW module is between 2.2 and 3.4 kW. As a result of
this heat loss, plus losses in the power conversion equipment, the AC-AC efficiency for loadleveling services is estimated in the range of 75%-80%.102 Expected service life is 15 years at
90% DoD and 4500 cycles.103
95
EPRI/DOE, 2003.
This estimate is of the Chino 10 MW battery with 96% inverter efficiency. EPRI/DOE, 2003.
97
X. Lu et al., “Advanced Materials for Sodium-Beta Alumina Batteries: Status, Challenges, and Perspectives,”
Journal of Power Sources, No. 195, 2010, pp. 2431-2442.
98
D. Linden and T. Reddy, 2002.
99
Ibid.
100
X. Lu et. al, 2010.
101
B. Norris, J. Newmiller, and G. Peek, NAS Battery Demonstration at American Electric Power, SAND2006-6740,
Sandia National Laboratories, 2007. NGK sells a “PS” module rated for continuous discharge for load-leveling
applications and a “PQ” module rated for short discharge applications such as frequency and contingency reserves.
102
75% from Nourai, 2007 and 80% from A. Nourai, V.I. Kogan, and C.M. Schafer,“Load Leveling Reduces T&D
Line Losses,” IEEE Transactions on Power Delivery, Vol. 23, No. 4, 2008, pp. 2168–2173.
103
EPRI/DOE, 2003.
96
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The primary sodium-beta alternative to the Na-S chemistry, the Na-NiCl2 cell (typically called
the ZEBRA cell).104 Although ZEBRA batteries have been under development for over 20 years,
they are only in the early stages of commercialization.105 Nickel chloride cathodes offer several
potential advantages including higher operating voltage, increased operational temperature range
(due in part to the lower melting point of the secondary electrolyte), a slightly less corrosive
cathode, and somewhat safer cell construction, since handling of metallic sodium—which is
potentially explosive—can be avoided.106 They are likely to offer a slightly reduced energy
density.107
Liquid Electrolyte Flow Batteries
Flow batteries use liquid electrolytes that are pumped through a “stack” which contains either an
ion-exchange membrane or an electrode array. Energy is stored primarily in active materials
dissolved into electrolytes, which are stored externally and passed through the electrodes during
charge and discharge. The electrodes are separated by an ion exchange membrane to keep the
cathode-side and anode-side electrolytes separate. The advantage of flow battery technology is
that the power component (MW) and the energy component (MWh) can be sized independently,
with the electrolyte materials held in large external storage tanks for multi-MW applications. The
power rating of a flow battery is determined by the size of the battery stack, and the energy rating
by the size of the electrolyte storage tanks.
As stated earlier in this section, the two main types of flow battery in early commercialization are
vanadium redox and zinc-bromine. Vanadium redox batteries are part of a large class of flow
batteries using an ion-exchange membrane similar to that used in fuel cells. (Hence, they are
sometimes called regenerative fuel cells.) In a redox flow battery, the active materials are always
dissolved in the electrolyte. While a number of electrolyte materials have been proposed or are
under development, vanadium has the greatest degree of commercialization, with a number of
installations and active vendors. Other redox flow battery chemistries have yet to be
commercialized but have the potential to provide cost-effective alternatives and are discussed in
the R&D section of this chapter.
The redox flow battery offers several benefits over conventional batteries. First, the amount of
energy storage available is limited only by the size of the tanks and the amount of electrolyte
available. An additional benefit is avoiding the need to correct for differences among individual
battery cells (cell balancing) typical in multi-cell storage configurations using other battery
technologies, which allows for relatively simple construction of higher voltage redox batteries.
Redox flow batteries can also be recharged mechanically by replacing the electrolyte. The
disadvantages generally stem from the complexity of electrolyte pumping and storage; control
system complexity; and relatively low specific energy and energy density (typically less than that
of lead acid cells). The use of an ion-exchange membrane introduces other challenges and
benefits. Leakage across the membrane is possible, causing mixing of the cathode-side and
anode-side electrolytes. In a vanadium redox battery, the impact of leakage is mitigated by the
104
The name derives from the Zeolite Battery Research Africa Project which invented the technology in 1985.
See, for example, Daimler AG, “The New Mercedes-Benz A-Class E-CELL,” web page, September 15, 2010,
http://media.daimler.com/dcmedia/0-921-941776-1-1331063-1-0-0-0-0-0-11702-614316-0-1-0-0-0-0-0.html; J.L.
Sudworth, “The Sodium/Nickel Chloride (ZEBRA) Battery,” Journal of Power Sources, Vol. 100, 2001, pp. 149-163.
106
C. Dustmann, “Advances in ZEBRA Batteries,” Journal of Power Sources, Vol. 127, 2004, pp. 85-92.
107
D. Linden and T. Reddy, 2002.
105
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fact that both electrolyte materials are identical. However, using alternative chemistries, mixing
can seriously degrade performance. The challenge of cost-effectively manufacturing reliable ionexchange membranes is cited as a primary reason for the limited development of some of the
earliest flow battery chemistries. The claimed calendar lifetime for a vanadium battery stack is at
least 10 years with more than 10,000 cycles.108
The primary alternative to redox flow batteries is a flow battery where at least one of the active
materials is plated onto an electrode. Several chemistries have been investigated, with zinc
bromine being the most well developed. During charging, zinc is plated onto the negative
electrode. When discharging zinc is dissolved into the electrolyte. This configuration benefits
from a low-cost electrolyte and a slightly improved energy density, but problems can arise with
formation of sharp particulates during zinc plating. A 2003 estimate of cycle life is about 2000
cycles or 6000 hours of continuous operations.109 Commercial units have cycle life ratings from
1500 to over 2000 cycles.110
The DC-DC round-trip efficiency for flow batteries is in the range of 70%-80%.111 However, as
with all batteries, DC-AC losses reduce this efficiency further, and flow batteries have additional
parasitic loads of electrolyte pumps. As a result, estimates of AC-AC roundtrip efficiency is in the
range of 65%-72%.
Cost
The ability to estimate the capital cost of batteries varies by commercial maturity and application.
Lead acid batteries are the most mature and lowest-cost technology with one 2008 estimate in the
range of $150-$200/kWh.112 To this must be added the costs of a storage installation equipment in
addition to the battery cell itself (balance of plant), which were estimated at $265/kW in 2003;
however, more recent estimates are considerably higher.113 On a cost basis alone, this makes leadacid batteries appear competitive for a wide variety of applications. However, this total cost must
be placed in context of the relatively short cycle life of current lead-acid technology, restricting its
use to applications which require few actual cycles per year.
One 2009 estimate for the cost of NaS battery is about $350-$400/kWh and about $450-$550/kW
for the balance of plant.114 This corresponds to about $2970-$3450/kW for a 7.2 hour device. It is
108
EPRI/DOE, 2003.
EPRI/DOE, 2003. Data from current vendors indicate longer lives are possible with periodic maintenance. Since
zinc-bromine, like all flow battery technologies are in the early stages of commercialization, additional field trials will
be necessary to establish calendar and cycle life estimates.
110
P. de Boer, and J. Raadschelders, “Flow Batteries,” white paper prepared for Leanardo ENERGY, June 2007,
http://www.leonardo-energy.org/webfm_send/164; G. P. Corey, “An Assessment of the State of the Zinc-Bromine
Battery Development Effort,” RedFlow Limited, Brisbane, Australia, October 2010, http://www.redflow.com.au/docs/
assessment__zinc_bromine_battery.pdf.
111
EPRI/DOE, 2003; D. Rastler,“New Demand for Energy Storage,” Electric Perspectives, September/October 2008
http://www.eei.org/magazine/EEI Electric Perspectives Article Listing/2008-09-01-EnergyStorage.pdf.
112
D. Ton, et al. “Solar Energy Grid Integration Systems – Energy Storage (SEGIS-ES),” U.S. Department of Energy
and Sandia National Laboratories, May 2008, http://www1.eere.energy.gov/solar/pdfs/segis-es_concept_paper.pdf.
113
EPRI/DOE, 2003.
114
D. Rastler, “Overview of Electric Energy Storage Options for the Electric Enterprise,” slide presentation, Electric
Power Research Institute, Palo Alto, CA, 2009, http://www.greentechmedia.com/images/wysiwyg/News/
EPRIEnergyStorageOverview%20DanRastler.pdf
109
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unclear whether or not this estimate considers potential deployment at scale. Another estimate
from the first large NaS project in the United States claims that when initial project costs are
removed, NaS would cost about $2500/kW for a 7.2 hour device (Figure 5).115
Figure 5. Cost Components for an Installed NaS System
Source: A. Nourai, 2007.
Notes: PCS=Power Control Station. The factory-to-site shipping costs are considerable: “The total
transportation costs from factory to site, including customs and handling charges plus a few other items shipped
by air, translated to approximately $140/kW.”
Limited cost estimates are available for both vanadium and zinc-bromine batteries. Lack of recent
large-scale installations also makes cost estimates highly uncertain. A 2004 estimate for the cost
of a vanadium flow battery is $236/kWh and $566 for the balance of plant, or about $2450/kW
for an 8-hour device.116 While total costs are not provided, a 2010 estimate for a proposed
vanadium plant provides a cost breakdown of 35% electrolyte, 9% membrane, 17% other stack,
and 5% power control station, with the remaining 34% for engineering, management, and balance
of plant.117
A 2003 estimate118 for Zinc-Bromine is $353/kWh and $576 for the balance of plant, or about
$3400/kW for an eight hour device, while a 2011 manufacturer’s estimate is about $780/kWh for
the entire system, with projected costs of about $400/kWh for a next generation system at “full
production levels.”119 More recent, unpublished estimates place flow battery costs in excess of
$4000/kW for multi-hour devices, while a 2009 EPRI estimate places the projected costs of a
generic flow battery at $1545-$3100/kW for a 4 hour device.120 Manufacturing and deployment at
115
A. Nourai, 2007.
Electric Power Research Institute and U.S. Department of Energy (EPRI/DOE), EPRI-DOE Handbook Supplement
of Energy Storage for Grid Connected Wind Generation Applications, No. 1008703, December 2004.
117
. J.F Startari, “Painesville Municipal Power Vanadium Redox Battery Demonstration Project,” slide presentation,
Ashlawn Energy, Painesville, OH, 2010. http://www.sandia.gov/ess/docs/pr_conferences/2010/startari_ashlawn.pdf
118
EPRI/DOE, 2003.
119
The manufacturer also projects future costs at “grid scale production” of close to $100/kWh. ZBB 2011 “Investor
Presentation,” http://www.zbbenergy.com/investor-relations/presentations/.
120
D. Rastler, 2009.
116
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scale will be necessary to establish better estimates of flow battery costs. Deployment at scale
will also be needed to determine longevity as well as operation and maintenance requirements.
Some perspective on the overall cost reduction potential for certain battery types is provided in
one recent analysis of different battery chemistries.121 Figure 7 shows the cost of various
chemical pairs (couple elements) for battery types considered in this chapter. For many types,
such as the NaS battery the cost of raw materials is, theoretically, a trivial component. Most
others have couple element costs of about $10/kWh or less (assuming costs in the study year).
One chemistry that stands out as a potential cost challenge is vanadium, with the couple element
costs close to $100/kWh, primarily due to the high cost of vanadium. Figure 6 also shows goals
for the Department of Energy’s ARPA-E grid storage and electric vehicle (EV) programs. The
ARPA-E goal of $100/kWh appears to include both the power and energy component, including
power conditioning equipment, installation, and other balance of system components. This would
correspond to $800/kW for a device with eight hours of storage capacity, which would require
battery costs of well below $100/kWh considering balance of system is currently a considerable
fraction of $800/kW. The goal for the EV battery pack is discussed in the next chapter.122
Figure 6. Extraction Costs of Elements in Grid Battery Couples
Source: C. Wadia, P. Albertus, and V. Srinivasan, 2011.
Notes: Calculated from U.S. Geological Survey element prices. The EV battery pack goal of $100/kWh includes
only the cost of the battery itself.
121
C. Wadia, P. Albertus, and V. Srinivasan, “Resource Constraints on the Battery Energy Storage Potential for Grid
and Transportation Applications,” Journal of Power Sources, Vol. 196, 2011, pp. 1593-1598.
122
U.S. Department of Energy, Grid-Scale Rampable Intermittent Dispatchable Storage (GRIDS), DE-FOA-0000290,
CFDA Number 81.135, poncept paper, April 23, 2010.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Research and Development
The federal government, industry consortiums, and other groups support R&D efforts across a
range of battery technologies, including a number of emerging battery chemistries that do not fall
under the categories summarized above. The latter include alkaline, sodium ion, and liquid metal
batteries. To illustrate these efforts, Tables 4 and 5 list federal battery R&D activities supported
by ARPA-E and ARRA, according to general battery type and chemistry. Activities associated
with specific battery types are discussed below. Note that these tables include several lithium-ion
and metal-air batteries, both of which are thought of as prime candidates for transportation
applications. (These two battery types are discussed in greater detail in the following chapter.)
However, some forms may be more suitable for grid applications and supported through gridoriented R&D efforts.
In addition to federally supported efforts, there are grid battery technology R&D activities funded
by other groups and among private companies (whose details may be proprietary). For example,
the Stanford University’s Global Climate and Energy Project has awarded grants to outside
researchers for new grid-oriented battery technologies including enhanced electrolyte and solid
oxide flow battery systems.123
Table 4. ARPA-E Supported Activities on Grid Battery Storage in FY2010-2011
Lead Research Organization
Battery Type /Chemistry
Funding ($Millions)
CUNY Energy Institute
Other (Zinc-Manganese Oxide)
3.00
Fluidic Energy, Inc.
Metal Air (Zinc Air)
3.00
General Atomics
Lead-Acid/Flow
1.99
Lawrence Berkeley National Lab
Flow (Hydrogen-Bromine)
1.59
Primus Power
Flow (Zinc Chloride-Zinc Chloride)
2.00
United Technologies Research Center
Flow (To Be Determined)
3.00
Univ. of Southern California
Metal Air (Iron-Air)
1.46
Arizona State University
Metal Air (Zinc-Air)
5.13
EaglePicher Technologies
Sodium-Beta (Sodium Sulfur)
7.20
Envia Systems
Lithium-Ion
4.00
Inorganic Specialists, Inc.
Lithium-Ion
2.00
Massachusetts Institute of Technology
Other (Liquid Metal)
6.95
Source: Sandia National Laboratories, “ARPA-E Awarded Projects in Energy Storage,” web page, 2010,
http://www.sandia.gov/ess/docs/ARPA-E_FY10-11_combined.pdf.
123
Mark Shwartz, “GCEP Awards $3.5 million for Energy Storage Research,” Stanford Report, Stanford University,
September 23, 2011.
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
Table 5. ARRA Supported Grid Battery Demonstrations
Awardee
Battery Type /Chemistry
Size (Power/Energy)
Funding ($Millions)
Duke Energy Business Services
TBD
24 MW
$21.81
Primus Power
Flow (Zinc-Chloride)
25 MW (75 MWh)
$14.00
Southern California Edison Co.
Lithium-Ion
8 MW (4 hrs)
$24.98
City of Painesville
Flow (Vanadium Redox)
1 MW (6-8 MWh)
$4.24
Detroit Edison
Lithium-Ion
25 kW (20 units, 50 kWh
each)
$5.00
East Penn Manufacturing Co.
Lead-Acid (with ultracapacitor)
3 MW (1-4 MWh)
$2.54
Premium Power Corp.
Flow (Zinc-Bromine)
5-500 kW (6 hrs)
$6.06
Public Service Company of NM
Lead-Acid
500kW (2.5MWhr)
$2.51
Aquion Energy, Inc.
Other (Sodium-Ion)
10-100 kWh
$5.18
Ktech Corp.
Flow (Iron-Chromium)
250kW (1MWhr)
$4.76
Seeo, Inc.
Lithium-Ion
25 kWh
$6.20
Source: Sandia National Laboratories, “ARRA Energy Storage Demonstrations,” October 13, 2010,
http://www.sandia.gov/ess/docs/ARRA_StorDemos_10-13-10.pdf.
Lead-Acid
The primary disadvantages of lead-acid batteries are their poor energy density and short cycle
life. Marginal gains to specific energy can be achieved by improving the active material and
design of the electrodes, but will always be limited by the chemistry’s relatively low theoretical
boundaries. Cycle life potentially can be increased by adding carbon in various forms to either the
anode or cathode,124 or by replacing the traditional lead acid anode with a carbon anode similar to
that of an asymmetrical electrochemical capacitor.125 Another approach to improve cycle life is
the so called lead acid flow battery, in which lead is dissolved in an aqueous methanesulfonic acid
electrolyte. This system differs from traditional flow batteries by using of just one electrolyte and
the subsequent lack of troublesome electrolyte separators.126 If long deep discharge cycle life is
proven and costs can be kept low, these technologies may be promising for grid-based bulk
electricity storage applications.
Sodium-Beta
There are several R&D efforts associated with sodium-beta batteries. One is to develop a stacked
planar cell design that could cut cell costs in half.127 This departure from the traditional tubular
124
P.T. Moseley et al., “The Role of Carbon in Valve-Regulated Lead-Acid Battery Technology,” Journal of Power
Sources, Vol. 157, 2006, pp. 3-10; Enos, D., Hund, T., Shane, R. (2010) “Carbon-Enhanced VRLA Batteries.” DOE
Energy Storage Systems Research Program Annual Peer Review. http://www.sandia.gov/ess/docs/pr_conferences/
2010/enos_snl.pdf
125
L.T. Lam and R. Louey, “Development of ultra-battery for hybrid-electric vehicle applications,” J. Power Sources
158: 1140-1148 (2006); P.T. Moseley et al (2006).
126
Hazza, et. al., “A Novel Flow Battery: A Lead Acid Battery Based on an Electrolyte with Soluble Lead(II). Part I:
Preliminary Studies,” Phys. Chem. Chem. Phys., 2004 (6) 1773-1778.
127
Pacific Northwest National Laboratory, “EaglePicher Teams with PNNL to Transform Large-Scale Energy
(continued...)
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Energy Storage for Power Grids and Electric Transportation: A Technology Assessment
design has the ability to increase specific energy and power (the latter a limiting factor for the use
of these batteries in many applications), improve packing efficiency, and improve modularity. It
also presents the opportunity to address long term corrosion problems. However, planar designs
face sealing and material selection challenges.128 Other R&D efforts focus on low temperature
sodium based chemistries using new cathodes and/or sodium ion conductors.129 While cost is a
major R&D focus, longevity and reliability still have room for some marginal improvement using
improved cell configurations and designs.
Liquid Electrolyte
Flow battery R&D efforts include improving the performance of commercially available products
and developing new chemistries. For vanadium redox cells, research seeks to decrease the
vanadium required a
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