|The Milford Wind farm near Milford, Utah will generate power that can be stored in the planned Intermountain CAES project. Photo courtesy: SunEdison|
Tim Miser, Associate Editor
How CAES Technology May Give an Old Coal-Fired Site a New Lease on Life
Out in the middle of nowhere, in the high desert of rural Utah, the coal-fired Intermountain Power Project flexes its 1,900-MW muscles to provide electricity to Los Angeles and Southern California. It’s a job the plant has performed since 1986, when plant owner Intermountain Power Agency completed a five-year construction project and began operation of the 950-MW Unit 1, to be followed about a year later by the commissioning of an identically-sized Unit 2. Today the plant is operated by the Los Angeles Department of Water and Power.
It was a proud facility at its inauguration, the largest coal-fired power plant in the United States, with a construction cost of $4.5 billion. It utilized tandem compound steam turbines built by GE, and subcritical boilers supplied by Babcock & Wilcox.
Both the capacity and reliability of wind power from Milford Wind farm in Utah will be increased upon the completion of the Intermountain Energy Storage Project.
Photo courtesy: SunEdison
In 2004, GE and Alstom successfully uprated both units, and the outlook for the plant looked promising-so promising, in fact, that the additional two generating units for which the plant was originally designed were in the pipeline. A 900-MW Unit 3 was scheduled to go online in 2012, with Unit 4 presumably to materialize sometime thereafter.
That’s when things hit a snag.
The City of Los Angeles, a major purchaser of the power plant’s electricity output, decided to go “coal-free” by 2020. That end date was batted around for a time, with some suggesting a date of 2025 was more realistic. In the end, after the dust had settled, one thing was certain: by some time in the middle of the coming decade, LA will no longer need coal-fired power. Not only does this mean the city will no longer purchase coal-fired power generated within the state of California, neither will it purchase coal-fired power sourced beyond the state’s borders. Indeed, legislation in California now makes it very complicated for the state’s power plants to continue to purchase coal-fired power after current contracts expire.
The energy landscape is changing. To the average consumer, this change is subtle, perhaps even imperceptible. When utility customers flip on their switches at home the lights still turn on, and that’s about as deeply as anyone thinks about it. To those in the industry, though, the change feels more profound. Everyone is working overtime to keep pace with the coming energy revolution. When coal plants die, something else will take their place. While natural gas is an obvious successor, a great many are hoping the changing times will mean increased demand for renewable resources. But with all their promise, solar and wind power also carry attendant liabilities, namely intermittency. The sun doesn’t always shine; the wind doesn’t always blow. This makes it critical for an evolving industry to develop next-generation technologies to store renewable energy when Mother Nature looks down kindly on us.
So, what do you do with a once-proud power plant that has been forced-perhaps prematurely-into obsolescence? Fortunately, the situation isn’t as bad as it might first seem. No determination has yet been made to shutter the plant entirely, so the facility may well go on producing power for other localities into the future. A natural gas-fired plant is scheduled for construction next door to the coal-fired plant. It is expected to be operational by the mid-2020s, hopefully in time to capitalize on commercially-advantageous natural gas prices, while lowering the site’s overall environmental footprint.
At most sites around the country, this plan would be deemed sufficient, but the folks at Intermountain have grander ambitions.
The “Big Idea”
Turns out the Intermountain site has a peculiar geologic advantage; it’s situated atop a vast salt deposit, formed eons ago when an inland sea slowly evaporated, concentrating the brine into still smaller proportions. When at last the sea was no more, it “breathed its last” directly under the Intermountain site in Delta, Utah, bequeathing to future inhabitants a geologic windfall. The petroleum geologists who initially discovered this deposit were less than thrilled. Salt doesn’t sell as well as oil. But those in the power generation industry had a decidedly different take on the matter.
“It’s been known for decades-though few have paid attention to it-that there is an incredible salt deposit below the power plant,” says Lincoln Bleveans, power resources manager for Burbank Water & Power, the company behind a new energy storage project at the site. “There’s a few thousand feet of rock, and then below that about 10,000 feet of pure, white, perfect salt.”
Bleveans is excited because a salt reserve of this quality makes it possible to install a state-of-the-art compressed air energy storage (CAES) installation. He explains: “The salt deposits at the site can be hydro-mined. First the cap rock is drilled. Then clean water is pumped into the deposit, which dissolves the salt, itself becoming saline in the process. That water is then pumped back out, and this process is repeated to excavate the salt and create room for CAES storage. These types of deposits are perfect for creating caverns using very well-established technology, and in fact there are already four caverns at the Intermountain site which are used to store gaseous and liquid petroleum products.”
About CAES Technology
CAES is not unlike pumped hydro energy storage, which uses surplus energy to pump water to an uphill reservoir, from which it can later be released to turn turbines that re-generate a portion of the electricity, recouping that power which was expended during the initial pumping stage. Similarly, CAES uses surplus energy to compress air into large underground holding areas. When power is needed at a later date, this air can be released and expanded to turn turbines that re-generate the electricity.
Robert Schulte is a principal at Schulte Associates LLC, and a consultant to Burbank Water & Power. He explains that, like pumped hydro, CAES pumps air up a “metaphorical energy hill”. Above ground, he says, CAES equipment looks very conventional, and “any utility person that runs natural gas-fired equipment would recognize it instantly.” Essentially, CAES facilities utilize a simple-cycle natural gas-fired combustion turbine, which is notable for its omission of compressor blades. These compressor blades are not required, because the compression of air into the underground storage areas is accomplished at an earlier time, using large electric motors which are discrete from the turbine itself. A CAES system, then, effectively interrupts in time the process of compression and expansion that would otherwise occur in quick succession at a conventional simple-cycle gas-fired facility, where air is compressed and then immediately input into the turbine. Once air is compressed into underground caverns, it can be stored at length until it is released to turn a turbine that generates power.
The compression of air, so part and parcel of the CAES process, generates heat. Current iterations of CAES technology dissipate much of this heat as waste. When the stored air is later expanded, temperatures drop dramatically, and secondary heat must be applied using natural gas to warm the air, thus accounting for the heat lost in the initial compression stage. “Imagine the cans of compressed air you can buy at the store to clean your computer keyboard,” Schulte says. “When used long enough, those cans become very cold. The same thing happens when compressed air is expanded out of the salt caverns. Because of this, a small amount of natural gas is used to reheat the air as part of the CAES process.” Though they are not commercially viable now, future iterations of CAES technology hope to store heat generated during compression for later use during expansion. This adiabatic process would increase the efficiency of the CAES process, rendering it still more cost-effective.
This highly mechanical form of energy storage is markedly different from chemical battery storage in capacity, duration, and cost.
Schulte explains that chemical batteries cannot compare to CAES for large installations. “Whenever energy storage comes up these days, everyone talks about chemical batteries,” he says. “This is because of their compact residential size. In certain cases, chemical batteries can supply as much as 20 MW, but the project at Intermountain targets 1,200 MW of storage or more, so we need much larger capacities”
A 1-MW chemical battery is about the size of a semi-trailer. Because 1,200 of these units would be required to equal the capacity of the CAES project planned for the Intermountain site, the resulting above-ground footprint at the site would become very large.
CAES systems also outperform chemical batteries in duration. “At full-output,” Schulte explains, “current chemical battery technology might last as long as 10 hours, but the Intermountain CAES project is targeting output of 48 hours in duration. The project is meant to enable greater integration of renewable resources, specifically wind power. If you’re trying to back up wind energy, where lulls might exist for 24 hours or more, it’s important to have a world-class energy storage system to bridge intermittency gaps.”
While chemical batteries may have better round-trip efficiency ratings than CAES installations, they also cost more than CAES for comparable capacities of energy storage.
Out at the Site
At its root, the Intermountain CAES project is designed to enable integration of greater amounts of renewable resources. “Our larger context is renewables in the West,” says Bleveans. “As a California utility, Burbank Water & Power has a mandate to reach 33 percent renewable penetration by 2020, and 50 percent by 2030. For us, then, this is ultimately a reaction to the new renewable world we live in. From the standpoint of reliability, the only way to make this work is to have a significant amount of energy storage, and the world is coming around to that.”
Bleveans further explains that pumped hydro might have theoretically worked for the project, but that technology is “highly geographically dependent, and we’re in the middle of a desert.” CAES too has geographic constraints, but the Intermountain site is uniquely positioned to leverage its salt deposits for underground storage. “If you have a great site-and we think we do-CAES becomes a very cost-effective and operationally-effective technology,” Bleveans says.
Owing to the existing coal-fired plant, the Intermountain site has a highly-developed energy ecosystem. “There are already rail spurs for transportation and equipment associated with power generation,” Bleveans says. “The site is eerily good. It’s strange that so many fundamental pieces of the puzzle have come together here.”
Access to the Southern Transmission System is also available at the south end of the site. This very large DC transmission line runs from the Intermountain installation in Utah to Southern California and was initially installed at the Intermountain site to serve the baseload coal plant located there.
“That line can carry 2,400 MW of power,” Schulte says. “We’re proposing to place the CAES installation at the same site, which will allow us to supersize the future of the coming wind power.” The intermountain site already has 300 MW of wind capacity nearby, and another 3,000 MW are planned by 2025 for installations in Wyoming. “That means we will need to push 3,300 MW of wind energy down a 2,400-MW transmission line. The only way you can do this is to store energy generated above the capacity of the transmission line for later distribution when the wind isn’t blowing.”
This strategy will not only enable renewable resources above and beyond the capacity of current transmission infrastructure, it will also render notoriously intermittent renewables far more reliable. “We do not have to store much wind energy to enable a very large amount of renewables to fit down the constrained transmission line,” explains Schulte. “In this sense our capacity to store energy is more important than the round-trip efficiency ratings of a given technology.”
Southern California also has a growing portfolio of photovoltaic (PV) solar power. This PV power can also be routed in the reverse direction, to run up the transmission line from California to Utah. Once at the Intermountain site, it too can be stored alongside wind energy in the CAES system.
“In fact,” says Schulte, “we anticipate the first 300 MW of the CAES project will be online before the Wyoming wind machines are installed, so the first phase of the CAES project will serve as storage for this PV solar power. By 2025, when the wind turbines are installed and the remaining 900 MW of CAES storage are operational, the storage project will be timed to service those new wind resources as well.”