Energy Storage Technology
Grid stability is often cited as a potential problem if “too much” renewable power becomes available for distribution through the grid. A rough rule of thumb has surfaced in the industry suggesting that if the percentage of renewable power exceeds 20% of the grid’s power, the grid’s stability will be endangered. The concern is that is if a generator has unpredictable output volatility, as is the case for wind and solar power generators, other generators will not be able to replace a rapid reduction in power or avoid overloading the system at certain times of peak output. The real keys are predictability and the speed with which other generators can adjust their output.
New England power regulators see hydro power as a renewable power source but not as an unpredictably volatile source. Consequently, when you ask NEPOOL what percentage of renewable power might create a problem for the grid, they will reframe the question to ask what percentage of renewable power, excluding hydro power, might create a problem. In 2014, they see the non-hydro renewable contribution to the New England grid as very small and therefore of no immediate concern in terms of grid stability. The concern they do have is that the existing natural gas fired plants are not receiving enough natural gas to operate at full capacity. This is relevant to grid stability because natural gas plants are seen as generators with output levels that are relatively easily adjusted. So, if a wind farm suddenly stops generating because the wind stops blowing, a natural gas fired power plant can quickly replace the lost supply, as long as the plant has enough natural gas.
New England regulators are not unaware of the grid stability issues increased wind and solar might bring; they simply do not believe they pose an immediate concern. NEPOOL’s equivalent for the states of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia, called the PJM Interconnection System, has been more concerned about the percentage of wind and solar coming into their system. In PJM’s announcement, below, the “headline” is that their grid can absorb 30% wind & solar, but the details include important assumptions, including the construction of 14 billion (with a “b”) dollars’ worth of new transmission line capacity and what they refer to as “regulation reserves” of up to 1.5 gigawatts. These are significant assumptions that make storage – the ability to preserve wind and solar generated power for later use - a much more important part of our future grid system than NEPOOL regulators seem to believe.
PJM's Report Summary follows:
Experts believe that the PJM Interconnection system, can handle up to 30 percent of its energy from wind and solar without "any significant reliability issues," assuming transmission upgrades and additional regulation reserves — and at the same time reducing costs and reliance on its costlier conventional generation fleet.
Twelve PJM member states have renewable portfolio standards ranging from 18-25 percent, most with solar carve-outs. PJM projects its own wind and solar requirements will continue to steadily build from roughly 4 GW combined wind and solar in 2010 to 33 GW of wind and over 9 GW of solar by 2029. [Update: PJM's latest Regional Transmission Expansion Plan suggests it'll need to accommodate roughly 38 GW of renewables to meet all those states' RPS targets by 2028.] To get their arms around this rapidly increasing amount of wind and solar energy in its infrastructure back in the spring of 2011 PJM stakeholders requested a study, led by GE Energy, to assess the operational, planning, and market impacts of adding large-scale integration of wind and solar power over the next 15 years. The study covered how it would take shape and be operated, what transmission upgrades would be required, capacity values, and general overall impact on PJM operations. Ten scenarios were explored, from simply maintaining 2011 levels of 2 percent renewable integration, to meeting a 14 percent RPS mandate by 2026, up to a maximum of 30 percent energy annually from solar and wind.
Preliminary results were disclosed in the fall of 2013, and final results were presented on February 28, 2014.
The bottom line: PJM says its system "would not have any significant reliability issues operating with up to 30 percent of its energy [from renewables]" (note: that's energy, not capacity) though it will require significant additional transmission (nearly $14 billion) and regulation reserves (up to 1.5 GW).
Here's a shortlist of the findings, which are summarized here and discussed in more detail here and here:
1. While suggesting that independent system operators (ISOs) and regional transmission organizations (RTOs) are better suited to handle integration, PJM acknowledges its big footprint would "greatly reduce" variability-related challenges, such as weather diversity and power forecasting/scheduling.
2. Every scenario they explored would reduce PJM's fuel costs and variable operation/maintenance costs, and lowered average locational marginal prices.
3. Top-end 30 percent renewables integration would mean more cycling on PJM's existing generation fleet and would lower coal and combined-cycle generation under all scenarios. Renewables' lower capacity factors would result in lower revenues for conventional generation resources, but "these increased costs were small relative to the value of the fuel displacement."
4. They also looked at energy storage and demand response, finding that 1 GW of storage or demand response used in place of generator resources for spinning reserves (in the 30 percent renewables scenario) reduced total system production costs by more than $17 million annually, or $1.99/MWh ($17.41/kW-year).
The study takes into account the technology likely incorporated into future wind farms, e.g. larger, taller, and more powerful turbines, that will have higher capacity factors and effective load carrying capabilities than what PJM already uses. It also touches on some impact to (ISOs) and RTOs such as larger balancing areas, shorter scheduling intervals, and centralized wind power forecasting. However, the study pointedly does not analyze the economics of it all or compare the capital investments required. Nor does it get into transmission costs, e.g. generator interconnections and upgrades to mitigate voltage problems, and it didn't run simulations to evaluate frequency and voltage control issues. To the energy storage angle, the study didn't assess the economics of the regulation market, suggesting market price of regulation and capital costs will ultimately decide viability.
As a follow-up, the study suggests further examination of reserve requirements and improving resource flexibility, including adding active power controls to wind and solar plants. Recommendations will be explored in more detail at future stakeholder meetings, likely for the PJM's Intermittent Resources Task Force, which meets roughly every two months.
Posted by Kay Mann for Rick Smith, President of the Hydrogen Energy Center.
On March 27, 2014 from 1-2:00 pm, The Clean Energy States Alliance (CESA) and the Northeast Electrochemical Energy Storage Cluster (NEESC) are hosting a webinar on distributed wind technology for hydrogen production.
This webinar will introduce attendees to renewable hydrogen production from wind. Learn about the efficiencies to be gained from renewable production, the market vectors for renewable hydrogen, and the National Renewable Energy Laboratory's goals for improving overall system efficiencies and cost reductions.
Proton OnSite will be introducing the technology, followed by an overview of a wind to hydrogen installation at the Town of Hempstead, NY, and lastly, NREL's efforts to bring the technology to scale in the next 5-10 years. Learn how the electrolysis of water generates hydrogen, and the technology’s applicability to, and suitability for, energy use whether as localized power generation, renewable energy storage, combined heat and power, or as vehicle fuel.
The Town of Hempstead shall share details about project implementation, financing, and goals. Learn about the tax credits and incentives used to finance these projects, and identify the major project costs. A question and answer session will follow the presentations.
Tara Schneider Moran, Town of Hempstead, NY
Kevin Harrison, National Renewable Energy Laboratory
Steve Szymanski, Proton OnSite
In order to store wind energy in the form of hydrogen, current generated by wind turbines (or solar PV arrays) is run through water (H2O) to create hydrogen (H2) and oxygen (O2) in a process known as electrolysis, using a device called an electrolyser (or electrolyzer).
Ideally, hydrogen is made only when there is no other immediate direct use for the wind generator’s electricity. When that is the case, hydrogen is storing power that would otherwise simply be discarded without any source of payment for the wind generator’s owners. While it is not technically correct to say that this excess power is free when used to make hydrogen, it is accurate to say that the cost is very low.
Technologies differ, but a useful rule of thumb is to say that it takes about 60 kilowatt hours of electricity to make 1 kilogram kg) of hydrogen. Using the kilogram as a unit of H2 measure is helpful because a kilogram of hydrogen contains roughly the same amount of energy as a gallon of gasoline.
Thinking in these terms also focuses our attention on the fact that wind power stored as hydrogen can be used in place of gasoline as a vehicle fuel. A single 6MW offshore wind machine with a 50% utilization factor could make hydrogen equal to 1200 gallons of gasoline every day.
Taking a moment to reflect on electrolysis as a power storage method and hydrogen as a gasoline substitute reveals that the technology of storing wind energy as hydrogen necessarily involves several technologies, once the need to make money, or at least not lose money, is added to our thought process.
The ultimate cost of using electrolysis to store wind energy is affected not just by the design of the electrolyser and size and pressure of the storage tanks, but also by:
a. The technologies used to capture, store and use or sell, the oxygen generated by the electrolysis;
b. The technologies required for the storage, possible transport or possible on-site dispensing of hydrogen for use as a vehicle fuel (see the Transportation section);
c. The technology used to convert the stored hydrogen back to electricity if the facility operator’s goal is to help the grid’s ability to use more renewable power or to create a 24/7 power supply for a use that is directly connected to the wind generator or solar array. Possible choices include:
(i) A typical internal combustion generator running on H2 stored in high-pressure tanks near the wind or PV generator, instead of diesel, gasoline or other fossil fuel
(ii) Using a Fuel Cell to convert the locally tank-stored hydrogen back to electricity. See also this page:
Wind Energy Storage Today's Products
(iii) Using a remote combined cycle natural gas power plant by pumping hydrogen from the electrolyser into a natural gas pipeline that is feeding the power plant. Mixing hydrogen and natural gas in the same pipeline involves well-known technologies that require little if any modification to existing pipelines unless and until the amount of hydrogen in the line exceeds 15% of the total volume.
Similarly, natural gas/hydrogen mixtures at this level can be used with modifying the power plant. The mixture will burn cleaner than natural gas alone and reduce the amount of that fossil fuel that must be burned. This technology is referred to as “Power to Gas” and is discussed in greater detail in the next several paragraphs.
(iv)Converting stored hydrogen back to electricity using an internal combustion engine generator or fuel cell may or may not result in acceptable electricity costs. Inefficient (15% to 30%) internal combustion engines have a far lower purchase price than more efficient fuel cells (40% to 60%).
The critical difference for a particular installation may lie in how well the generator or fuel cell captures and uses excess heat. With total efficiencies, including heat capture, exceeding 90% for many fuel cell installations, the more expensive fuel cell may nevertheless be the better choice.
When trying to picture a wind-to-electricity-to-hydrogen-to-electricity system, several different possibilities arise.
a. An electrolyser that makes the hydrogen, the tanks that store it, and the generators or fuel cells that generate new electricity from the “stored wind power,” are all located in close proximity to the wind generators. Electricity is delivered to end-users through the same wires that the wind machines use for direct delivery of electricity to end users.
b. The installation made up of an electrolyser, storage tanks and a generator or fuel cells receives electricity from wind machines that are many miles away on land or many miles offshore. In this scenario, the eletrolyser/storage/generator or fuel cell facility is just another “end user” when seen from the perspective of the wind machines. The transmission lines from the generator or fuel cells to the consumer-end-user may or may not be the same lines that run between the wind machines and other end users.
c. An electrolyser is located near the wind machines but the hydrogen gas is transported by pipeline, ship, rail or truck to the generator/fuel cell site. If the internal combustion engine generator in this scenario is actually the turbine in a combined cycle natural gas power plant, we have the “Power to Gas” method mentioned in c(iii) above.
Power-to-Gas has several significant aspects:
a. No hydrogen storage tanks are required. The natural gas pipeline system acts as a storage “tank” with a capacity that, for practical purposes in the near and medium term, is unlimited, given the amount of hydrogen that is likely to be produced using this method.
b. There is no need to connect the wind machines to end users using transmission lines. All of the output from the wind machines can go to the electrolysers producing hydrogen that becomes “green fuel” for the natural gas power plant. The efficiency losses from elecrolysis (+/- 50%) are more than offset by saving the cost of new transmission lines – existing lines from existing power plants will continue to carry the combined cycle plant’s output.
c. Although the electroyser must be near a natural gas pipeline, the wind machine can be miles away, even offshore. Recall sub-paragraph (b) in the previous section. A single line from the wind machines to the electrolyser is all that is required.
d. Another attribute of the natural gas system is seasonal storage. In many areas around the world, there is a seasonal pattern to the wind generation profile. Unfortunately, periods of high wind output may come during the shoulder periods of lower electricity demand. Power-to-Gas provides not only TWh of storage, but seasonal storage capability as well. This effectively enables the renewable gas produced from surplus renewable generation as part of the fuel stream of existing gas-fired generators at the most suitable time. It is the best of both worlds.
e. The Achilles Heel of Power to Gas, and utility scale renewable hydrogen systems generally, is right-sizing the electrolyzers. Luckily the technology scales up when smaller units are connected together, making “modularity” the industry’s hoped-for answer to the size question. The largest onshore wind farm (Alta Wind Energy Center in California) has a capacity of 1,000 MW.
Currently, a number of companies are developing megawatt-scale PEM and alkaline electrolysers and the belief is this will facilitate the first steps toward proving electrolyser technology in this relatively new application.
Currently, the world’s largest single stack PEM electrolyser is Hydrogenics’ 1 MW system it recently announced will be installed at an E.ON power-to-gas facility in Hamburg, Germany. Obviously in the future much larger systems will be made, but they are likely to contain multiple stacks, or be connected to form a multi-megawatt system.
This information was posted by Kay Mann for Rick Smith, President of the Hydrogen Energy Center.
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