The term “bitcoin mining” has become a colloquial expression, but the actual activity involved in mining a crypto currency isn’t intuitively obvious to the casual observer. Marcus Lu, reporting for Visual Capitalist, can help us out here. He explained:
“When people mine bitcoins, what they’re really doing is updating the ledger of Bitcoin transactions, also known as the blockchain. This requires them to solve numerical puzzles which have a 64-digit hexadecimal solution known as a hash. Miners may be rewarded with bitcoins, but only if they arrive at the solution before others. It is for this reason that Bitcoin mining facilities—warehouses filled with computers—have been popping up around the world. These facilities enable miners to scale up their hashrate, also known as the number of hashes produced each second. A higher hashrate requires greater amounts of electricity, and in some cases can even overload local infrastructure.”
So your basic crypto currency miner need a lot of computer processing power, electric power and an internet service provider. To get started, all of that requires some hard currency, unless you can find a work-around. Now, a few recent headlines make a bit more sense:
“1,069 Bitcoin Miners Steamrolled In Malaysia for Stealing Energy,” 17 July 2021
“Illegal Crypto Mining Farm With Almost 5,000 Computers Busted in Ukraine – The illegal operation cost between $186,000 and $259,300 in electricity to the state each month.” 12 July 2021
“Police find bitcoin mine using stolen electricity in West Midlands (UK),” 28 May 2021
“U.S. small towns take on energy-guzzling bitcoin miners,” 13 May 2021
These headlines suggest that crypto currency mining can generate significant wealth, and, for some, this prospect is worth the risk of being caught stealing a lot of electricity.
Sam Ling, writing for Miner Daily in May 2021, describes his methodology for estimating the cost to mine a bitcoin, which depends on many factors, including the cost of electricity and the cost, processing power and lifetime of the computers. Ling estimates: “It currently costs between $7,000-$11,000 USD to mine a bitcoin. …… As the price of BTC is $56,000, it remains very profitable to mine bitcoin.” You’ll find more details here: https://minerdaily.com/2021/how-much-does-it-cost-to-mine-a-bitcoin-update-may-2021/
At the industrial-size end of the crypto mining facility spectrum, US power company Talen Energy announced in July 2021 that it is planning to develop a nuclear-powered crypto mining facility and data center adjacent to its two unit, 2,494 MWe Susquehanna Steam Electric Station in Pennsylvania. The first phase of the crypto mining facility will require 164 MW of power and is due to come online in Q2 2022. When complete, the crypto mining facility will require 300 MW of on-site power supplied from the nuclear power plants via two independent substations. The potential exists to expand the crypto mining facility to 1,000 MW capacity in the future.
In May 2021, Nic Carter reported in the Harvard Business Review, “According to the Cambridge Center for Alternative Finance (CCAF), Bitcoin currently consumes around 110 Terawatt-Hours per year — 0.55% of global electricity production, or roughly equivalent to the annual energy draw of small countries like Malaysia or Sweden.” That would put current global crypto currency mining energy consumption at about 30th place among all nations in the world. In the future, energy consumption for crypto currency mining is certain to increase, perhaps dramatically. Is there an upper limit?
While the Susquehanna Steam Electric Station is fortunate to have a gained a new customer for their electric power, Exelon Generation reported in June 2021 that three of its Illinois nuclear power plants, Byron, Dresden, and Quad Cities, did not clear the PJM Interconnection capacity auction. This means that these Exelon nuclear plants have lost a customer for their future electric power generation. The issue is complex, but appears to be rooted in power auction rules that are, at least in part, inconsistent with the nation’s goal of reducing the overall carbon footprint of electric power generation. Exelon explained:
“Byron and Dresden, despite being efficient and reliable units, face revenue shortfalls in the hundreds of millions of dollars because of declining energy prices and market rules that allow fossil fuel plants to underbid clean resources in the PJM Interconnection capacity auction.”
Exelon is not the only US nuclear power utility with this type of issue. Several more US nuclear power plants are at risk of retiring prematurely instead of seeking a license extension to operate for another 20 years generating zero-carbon electricity. S&P Global Platts provides a good overview of the seriousness of the current situation in the following infographic:
Congress and the state governments need to act now to protect the nuclear power plants at high risk of premature closure, and ensure their continued operation as generators of zero-carbon electricity.
Perhaps the planned Talen Energy crypto currency mining venture points to an odd synergism between miners and nuclear power plant operators. Instead of retiring nuclear power plants that are struggling financially, it may make sense to the owners to build crypto mining facility and reap the profits from crypto currency sales. Taken to its extreme, you can imagine a nuclear power plant diverting all of its zero-carbon electric power output to its own very profitable crypto mining facility. Just imagine how many Bitcoins could be generated by diverting all US nuclear power plant electricity generation (about 20% of total US electricity generation) to power crypto currency miners.
Going back to my question “Is there an upper limit?,” I’m afraid only time will tell.
That’s the title of my favorite Moody Blues album. It’s also the current status of commercial civilian access to space.
The leading contenders are Richard Branson, with his firm Virgin Galactic Holdings, Inc., and Jeff Bezos, with his firm Blue Origin. 2021 is the year both firms plan to make their first commercial civilian sub-orbital flights with paying customers.
On 25 June 2021, the Federal Aviation Administration (FAA) granted approval of Virgin Galactic’s full commercial space-launch license. The FAA also is reviewing Blue Origin’s commercial space-launch license application, and final approval is expected soon. For commercial spaceflight, the FAA’s primary regulatory role is to ensure that the spaceflight activity is not a hazard to the general public or other aviation activities. The FAA does not regulate the design and operating characteristics of the spacecraft, as it does for commercial aircraft. Passengers flying on commercial spacecraft must acknowledge the risk by signing a waiver….and people are lining up and will be paying hefty sums to become civilian astronauts.
Virgin Galactic successfully completed its third manned test flight of the Spaceship II on 22 May 2021, with VSS Unity flying for the first time from New Mexico’s Spaceport America, which is located in the high desert near the small town of Truth-or-Consequences. I visited Spaceport America in 2015 when it was a complete but very quiet place, with only a Spaceship II mockup. That has all changed in 2021 as Virgin Galactic completed its testing program and is now preparing for its first commercial flights.
Virgin Galactic will be flying its two Spaceship II vehicles, VSS Unity and VSS Enterprise, from its base at Spaceport America. Virgin announced that the next sub-orbital flight is scheduled to occur on 11 July 2021 and Richard Branson is expected to be among the six people on board, all Virgin employees.
Virgin Galactic’s long-range plan is to operate 400 flights per year, per spaceport. To achieve this goal, Virgin recently completed the first of its next generation Spaceship III vehicles, VSS Imagine, and has started manufacturing the next Spaceship III, VSS Inspire.
Blue Origin’s New Shepard spacecraft is named for US astronaut Alan Shepard, who made the first US sub-orbital flight on 5 May 1961 on the Mercury-Redstone 3 mission and became the second man in space (after Russian astronaut Yuri Gagarin). To date, Blue Origin has made 15 consecutive unmanned launches with successful crew capsule landings, plus a successful pad escape test in 2012.
Contingent on receiving FAA license approval, Blue Origin announced that it has scheduled its first manned flight on 20 July 2021 from its west Texas launch facility near the town of Van Horn. This is the 52nd anniversary of the Apollo 11 moon landing. The four passengers for the first New Shepard manned sub-orbital flight will be Jeff Bezos, his brother Mark, Wally Funk (who is the last surviving member of NASA’s 13 female astronaut candidates for Project Mercury in the 1960s), and a fourth (as yet unnamed) passenger who won an auction by bidding $28 million for the last passenger seat. That amount will be donated to Blue Origin’s foundation, Club for the Future, to inspire future generations to pursue careers in STEM and help invent the future of life in space.
Blue Origin advertises, “This Seat Will Change How You See the World.” I have no doubt that it will. Find out more by visiting the Blue Origin website at the following link: http://www.blueorigin.com
Las Vegas relies on Lake Mead for 90% of its water needs. Currently, water from Lake Mead can be supplied to Las Vegas by three intakes at different levels in the lake. The newest, and deepest, is known as the “third straw” intake (IPS-3), which taps into the lake at 860 feet above sea level. That’s 190 feet below the highest existing intake, IPS-1, at 1,050 feet.
The operation of this three-intake system is explained in Southern Nevada Water Authority’s (SNWA) short video, “How does the SNWA’s Low Lake Level Pumping Station protect our drinking water supply?” at the following link: https://www.youtube.com/watch?v=bDDuid6XJnw&t=39s
On 18 June 2021, the lake level was 1,070.43 feet MSL at 5:00 PM. This is 158.57 feet below the “full pool” level of 1,229.00 feet and is only 20.43 feet above the highest (IPS-1) intake.
On 10 June 2021, Lake Mead water level was 1,071.51 at 7:00 AM and was about 36% full. The lake had not been this low since July 2016. Using just the 10 June and 18 June data points, lake water level currently is decreasing at about 1.5 inches per day.
Runoff from the Rocky Mountain snowpack is essentially over this year, so water level is expected to continue declining until the start of the next rainy season in November.
The first-ever official federal water shortage declaration is expected in August 2021, when the Bureau of Reclamation issues its regularly scheduled long-term water level projection. A Level 1 declaration would be implemented in January 2022 under agreements negotiated with seven states that rely on Colorado River water: Arizona, California, Colorado, Nevada, New Mexico, Utah and Wyoming. Water from the Colorado River serves 40 million people in these states and Mexico.
Let’s pray for a lot of wet weather in the US southwest.
Orbital Marine Power (https://orbitalmarine.com) is developing a large, moored tidal turbine, the O2, which they claim is the most powerful tidal turbine in the world. The O2 soon will be deployed at sea off the Orkney Islands, northeast of Scotland.
Key features of the O2 tidal turbine are:
74 meter (243 ft) tubular steel hull with fore and aft mooring connections.
Hydraulically-actuated steel legs extending from the hull support the generator nacelles and rotors that are deployed underwater after the hull has been moored using a four-point mooring system.
Two 20 meter (65.6 ft) diameter, 2-bladed rotors give the O2 more than 600 m2 (6,458 ft2) of swept area to capture flowing tidal energy.
Blade pitch control enables bi-directional operation of the turbines with the hull in a fixed moored position (the hull doesn’t swing with the tide).
Each rotor drives a 1 MWe generator housed in the nacelle.
Power is delivered to shore by a submarine cable.
Here are three short videos that will give you a quick introduction to this remarkable machine:
If the O2 demonstration proves to be successful, Orbital Marine Power plans to develop and deploy larger tidal turbines in the future.
So, what does the O2 tidal turbine have in common with an airship? The Aeromodeller II airship design developed by Belgian engineer Lieven Standaert implements an airborne mooring as a means to generate power using two wind turbines while remaining aloft.
Both the O2 tidal turbine and the Aeromodeller II airship are buoyant vehicles in their respective media (water and air, respectively) and both are designed to extract power from that medium while moored (or tethered). Important differences are that the O2 tidal turbine is permanently moored and supplies power to users on land. The Aeromodeller II drops its anchor periodically to recharge its own power system while tethered and then raises its anchor to continue its journey. You’ll find more information on the Aeromodeller II airship in my separate article here: https://lynceans.org/wp-content/uploads/2019/08/Aeromodeller-II-converted.pdf
I’ve reported previously on the Bloodhound LSR (land speed record) car in 2015, 2017, and lastly in 2019 when driver Andy Green made a series of high-speed test runs on the Hakskeen Pan in the Kalahari Desert in South Africa. On 17 November 2019, he achieved a top speed run at 628 mph (1,010 kph). The primary goal of the 2019 test campaign was to validate vehicle design and operation during high-speed runs up to 621 mph (1,000 kph). To that, the team responded, “Mission accomplished.” You can read my post on the Bloodhound LSR’s 2019 campaign here: https://lynceans.org/all-posts/land-speed-record-lows-and-highs-in-2019/
The 2019 test runs also were intended to provide an opportunity to fine-tune Bloodhound LSR before attempting a world land speed record run in 2020. However, lack of funds in 2020 deferred installing the Nammo rocket engine needed for the land speed record attempt. The worldwide COVID pandemic further intervened, cancelling a record attempt in 2020 and 2021.
The owner, Ian Warhurst, who had previously rescued the Bloodhound LSR from insolvency and then funded the 2019 high-speed tests, put the vehicle up for sale in January 2021. On 17 May 2021, the Bloodhound LSR team and the Coventry Transport Museum in Coventry, UK, announced the Bloodhound LSR jet car had moved into a new home in the museum where it is now on public display as part of the Biffa Award Land Speed Record Exhibition.
The Bloodhound LSR team reported, “….the sponsorship team are busy raising the funding required to attempt a new world land speed record, with a speed above 800mph. Once the required funding and investment has been raised, Bloodhound will leave the museum and be prepared for the record-breaking campaign.”
In the Biffa Award Land Speed Record Exhibition at the Coventry Transport Museum, Bloodhound LSR joins two UK world land speed record holders: Thrust2 and ThrustSSC.
On 4 October 1983, Richard Noble drove the Thrust2 to a world land speed record two-way average speed of 633.468 mph (1,019.468 kph) in the Black Rock Desert in Nevada, USA.
On 15 October 1997, Andy Green drove the ThrustSSC to a new land speed record and broke the sound barrier with a speed of 763mph (Mach 1.020, 1,228 kph) in the Black Rock Desert. This occurred 50 years after Captain “Chuck” Yeager, flying the Bell X-1 rocket-powered aircraft, made the first supersonic flight on 14 October 1947.
An FNPP is a transportable barge housing one or more nuclear power reactors that can deliver electric power and other services, such as low temperature process heat and/or desalinated water, to users at a wide variety of coastal or offshore sites. FNPPs are a zero-carbon energy solution that has particular value in remote locations where the lack of adequate electrical power and other basic services are factors limiting development and/or the quality of life.
After being manufactured in a shipyard, the completed FNPP is fueled, tested and then towed to the selected site, where a safe mooring provides the interfaces to connect to the local / regional electrical grid and other user facilities.
The US operated the first FNPP, Sturgis, in the Panama Canal from 1968 to 1975. Sturgiswas equipped with a 45 MWt / 10 MWe Martin Marietta MH-1A pressurized water reactor (PWR) that was developed under the Army Nuclear Power Program.
Sturgis supplied electric power to the Panama Canal Zone grid, replacing the output of Gatun Hydroelectric Plant. This allowed more water from Gatun Lake to be available to fill canal locks, enabling 2,500 more ships per year to pass through the canal. After decommissioning, dismantling was finally completed in 2019.
2. Akademik Lomonosov – The first modern FNPP
It wasn’t until 2019 that another FNPP, Russia’s Akademik Lomonosov, supplied power to a terrestrial electricity grid, 44 years after Sturgis. The Lomonosov is a one-of-a-kind, modern FNPP designed for operation in the Arctic. With two KLT-40S PWRs, Lomonosov supplies up to 70 MWe of electric power to the isolated Chukotka regional power grid or up to 50 Gcal/h of low temperature process heat at reduced electrical output to users in the industrial city of Pevek, near the eastern end of Russia’s Northern Sea Route.
Lomonosov started providing electricity to the grid on 19 December 2019 and regular commercial operation began on 22 May 2020.
3. FNPPs under development by several nations
Several nations are developing new FNPP designs along with plans for their serial production for domestic and/or export sale. The leading contenders are presented in the following chart.
Floating Nuclear Power Plants in Operation & Under Development
Akademik Lomonosov and the first four new FNPP designs in the above chart use small PWRs in various compact configurations. PWRs have been the dominant type of power reactor worldwide since their introduction in naval reactors and commercial power reactors in the 1950s. The Seaborg power barges will use compact molten salt reactors (CMSRs) that have functional similarities to the Molten Salt Reactor Experiment (MSRE) that was tested in the US in the early 1960s.
Russia is developing their 2nd-generation “optimized floating power unit” (OPEB) to deliver 100 MWe electric power, low temperature process heat and water desalination to support their domestic economic development in the Arctic. In November 2020, Rosatom director for development and international business, Kirill Komarov, reported that there was demand for FNPPs along the entire length of Russia’s Northern Sea Route, where a large number of projects are being planned. This was reinforced in May 2021, when Russia’s President Vladimir Putin endorsed a plan to deploy OPEBs to supply a new power line at Cape Nagloynyn, Chaunskaya Bay, to support the development of the Baimskaya copper project in Chukotka. The development plan calls for 350 MWe of new generation from nuclear or liquid natural gas (LNG) generators. Baimskaya currently is supplied from Pevek, where the Lomonosov is based.
A version of the OPEB also is intended for international export and has been designed with the flexibility to operate in hot regions of the world. Bellona reported that “Rosatom has long claimed that unspecified governments in North Africa, the Middle East and Southeast Asia are interested in acquiring floating nuclear plants.”
In the 1960s, China Shipbuilding Industry Corporation (CSIC) set up the 719 Research Institute, also known as the Wuhan Second Ship Design Institute or CSIC 719, to develop applications for nuclear power technology in marine platforms. CSIC has become China’s biggest constructor of naval vessels, including nuclear submarines.
About a decade ago, China considered importing FNPP technology from Russia. In 2015, China’s National Development and Reform Commission (NDRC) agreed with a CSIC 719 design plan to develop an indigenous offshore marine nuclear power platform. This plan included both floating nuclear power plants and seabed-sited nuclear power plants. Today, part of this plan is being realized in the FNPP programs at China National Nuclear Corporation (CNNC) and China General Nuclear Power (CGN), two staunch competitors in China’s nuclear power business sector.
China included the development of CNNC’s 125 MWe ACP100S and CGN’s 65 MWe ACPR50S marine PWR plants in its 13th five-year plan for 2016 to 2020. The NDRC subsequently approved both marine reactor designs.
As an example of the magnitude of China’s domestic offshore market for FNPPs, the total installed fossil fuel-powered generation in China’s offshore Bohai oilfield was estimated to be about 1,000 MWe in 2020 and growing. Replacing just these generators and providing heating and desalination services for offshore facilities represents a near-term market for a dozen or more FNPPs. Other domestic application include providing these same services at remote coastal sites and offshore islands. China has announced its intention to construct a batch 20 FNPPs for domestic use. The Nuclear Power Institute of China (NPIC) has recommended installing the country’s first FNPP at a coastal site on the Yellow Sea near Yantai, Shandong Province. South Korea raised its objection to this siting plan in 2019.
Other possible FNPP deployment sites may include contested islands that China has begun developing the South China Sea. This is a very sensitive political issue that may partially account for why there has been very little recent news on the CNNC and CGN FNPP programs. Based on their development plans discussed about five years ago, it seemed that China’s first FNPP would be completed in the early 2020s.
In addition to their domestic applications, China has repeatedly expressed interest in selling their FNPPs to international customers.
South Korea & Denmark
In the absence of clear domestic FNPP markets in South Korea and Denmark, KEPCO E&C and Seaborg Technologies are focusing on the export market, primarily with developing nations.
Details on modern FNPP designs
You’ll find more details on these new FNPPs in my separate articles at the following links:
All of the new FNPPs require regular reactor refueling and periodic maintenance overhauls during their long service lives. The periodic overhauls ensure that the marine vessel, the reactor systems and ship’s systems remain in good condition for their planned service life, which could be 60 or more years.
The FNPPs with PWRs have refueling intervals ranging from about 2 years (ACP100S) to as long as 10 years (RITM-200). Some of the PWR refuelings will be conducted dockside, while others will be conducted in a shipyard during a periodic maintenance overhaul. For Russian FNPPs, such overhauls (referred to as “factory repairs”) are scheduled to occur at 12-year intervals for the Lomonosov and 20-year intervals for the OPEB.
The fundamentally different Seaborg CMSR, with molten salt fuel, is refueled regularly while the reactor is operating. Periodic maintenance overhauls would still be expected to ensure the condition of the marine vessel, the reactor systems and ship’s systems.
With a fleet of FNPPs in service, most will be operating, while some are in the shipyard for their periodic maintenance overhauls. In addition, new FNPPs would be entering service periodically. When it is time to service an FNPP in a shipyard, it will be replaced by a different (existing or new) FNPP that is brought in to take its place.
At the end of its service life, an FNPP will be returned to a shipyard to be decommissioned, decontaminated and then dismantled, like Sturgis. Russia already has established special long-term spent fuel and radioactive waste storage facilities in mainland Russia. China, South Korea and Denmark will need to make similar provisions for the end-of-life processing and safe disposition of their retired FNPPs.
5. Economic issues
In March 2019, Jim Green wrote on what he called “the questionable economics of SMRs” in his article, “An obituary for small modular reactors.” One of his conclusions was that, “…in truth there is no market for SMRs.” Another conclusion was that “No-one wants to pay for SMRs. No company, utility, consortium or national government is seriously considering building the massive supply chain that is at the very essence of the concept of SMRs ‒ mass, modular factory construction. Yet without that supply chain, SMRs will be expensive curiosities.”
I might agree that this could be the case for land-based SMRs, but marine FNPPs are a different matter. In remote areas being considered for FNPP deployment, there probably are fewer energy options, energy price competition is a lesser concern, and an extended fuel supply chain is undesirable or impractical. Examples include FNPP applications supporting resource development along Russia’s Northern Sea Route and in China’s offshore waters. The domestic markets in both nations probably can support production runs of 10s of FNPPs. While this isn’t “mass production” in the sense of many heavy industries, it would certainly be a big enough production run to change the manufacturing paradigm in the marine nuclear industry and provide a real validation of the economics of SMRs.
6. International nuclear regulatory / legal / political issues
Deployment of the first modern FNPP, the Akademik Lomonosov, in the Arctic was accomplished under Russian domestic nuclear laws and regulations and, after the reactors were fueled, the transit to its destination was accomplished within Russian territorial waters. The final destination, Pevek, is about 980 km (609 miles) from the Bering Strait and the nearest international boundary. Not without controversy, particularly among Scandinavian nations, Lomonosov’s deployment was straightforward after the vessel completed all stages of licensing and regulatory reviews required in Russia. Now Lomonosov has been commissioned and is setting an example for the rest of the world by operating successfully in a remote Arctic port.
Except for Russia’s nuclear-powered icebreaking vessels, there have been no other civilian nuclear vessels in service since Japan’s Mutsu retired in 1992. For almost 30 years, there has been no need to establish and maintain a comprehensive international civilian nuclear vessel regulatory and legal framework.
In her August 2020 article, “Legal framework for nuclear ships,” Iris Bjelica Vlajić reports that the main international documents regulating the use of civil nuclear ships are:
UN Convention on the Law of the Sea (UNCLOS)
IMO Convention for the Safety of Life at Sea (SOLAS)
IMO Convention on The Liability of Operators of Nuclear Ships and the Code of Safety for Nuclear Merchant Ships
Further FNPP deployment along Russia’s arctic coast and initial FNPP deployment in China’s territorial coastal waters can be accomplished under the respective nation’s domestic nuclear laws and regulations. It’s easy to imagine that a range of international issues will arise as FNPP deployment becomes more widespread, in situations like the following
An FNPP is deployed to a site close to an international border.
An FNPP is deployed in a sensitive international ecosystem.
A fueled FNPP from any nation needs to transit an international strait or an exclusive economic zone (EEZ) of another nation enroute to its destination.
An FNPP is deployed to an island that is contested by one or more other nations (i.e., several islands and island groups in the South China Sea).
There has been speculation recently that the sensitivity of the last issue, above, may be contributing to increased secrecy in the last couple of years related to China’s FNPP programs.
As FNPP deployment expands, the international community will be playing catch-up as the UN, IMO, IAEA and others contribute to developing a modern nuclear regulatory and legal framework for FNPPs.
In the next decade, I think it’s very likely that two or more of the new FNPP designs will enter service. The leading contenders seem to be Russia’s OPEB and China’s ACP100S FNPP. It remains to be seen if economic issues and/or international nuclear regulatory / legal / political issues will stand in the way of eventual FNPP deployments to sites around the world.
Goodbye Indian Point 2 and 3. Your contributions of zero-carbon energy to New York’s “clean energy grid of the future” will be greatly missed.
In an average year, the 1,028-MWe Indian Point Unit 2 nuclear power plant and the 1,041-MWe Unit 3 operated at capacity factors of greater than 90% and delivered more than 18,000 GWh (thousand MWh) per year of zero-carbon electricity to the New York state electrical grid. Unit 2 was shutdown on 30 April 2020 and Unit 3 followed on 30 April 2021. Prior to its final shutdown, Unit 3 had run continuously for 753 day, which set a new nuclear industry world record. The ANS Newswire reported, “The plant’s closure is the result of a settlement agreement reached in 2017 by Entergy and the State of New York and environmental groups opposed to Indian Point’s operation. According to an April 28 (2021) news release from Entergy, its decision to accede to the shutdown was driven by a number of factors, including ‘sustained low current and projected wholesale energy prices that reduced revenues.’”
Now, Indian Point Units 2 and 3 are delivering exactly zero zero-carbon energy. I imagine the environmental groups involved in the settlement agreement are hailing the shutdowns as great achievements. I think the shutdowns represent remarkable shortsightedness (I’m using the kindest words I can think of) on the parts of Entergy and the State of New York.
New York Independent System Operator, Inc. (NYISO) operates the New York state electrical grid, which is divided into two main parts, “downstate”, which includes New York City and the Indian Point Units 2 and 3 nuclear power plants, and “upstate,” which includes the Nine Mile Point and Ginna nuclear power plants. I credit NYISO with providing the public with excellent reports that summarize their annual grid and electrical market performance. In their Power Trends 2021 report, NYISO states: “The NYISO is committed to offering the tools, skills, independent perspectives, and experience necessary to transition to a zero-emission power system by 2040.”
I’ll refer to two of those NYISO Power Trend reports to illustrate the impact of closing the Indian Point 2 and 3 nuclear power plants on progress toward New York’s “clean energy grid of the future.” Using their own graphics, let’s take a look at how NYISO was doing in 2019 (with both Indian Point Unit 2 & 3 operating), 2020 (Unit 2 shutdown in April), and their projected performance in summer 2021 (after Unit 3 shutdown).
2019: New York statewide: 58% zero-emission; Upstate: 88% zero-emission; Downstate: 29% zero-emission
2020: New York statewide: 55% zero-emission; Upstate: 90% zero-emission; Downstate: 21% zero-emission
2021: New York statewide (projected, summer): 25% zero-emission; Upstate: 67% zero-emission; Downstate: 2% zero-emission
Anyone who can draw a tend chart from 2019 to 2021 using the above three years of data and then extrapolate to the State’s goal of a zero-emission power system by 2040 can see that New York’s plans for its “clean energy grid of the future” have come off the rails. The slope of the curve to get from where NYISO is today to the State’s 2040 goal has gotten a lot steeper, and that translates directly into the cost of achieving that goal. Surely the New York ratepayers served by NYISO will pay the price in the years ahead as the State works to improve its zero-emission performance. Even getting back to where they were in 2019 would be a big improvement.
So, I reiterate that the Indian Point Unit 2 and 3 shutdowns represent remarkable shortsightedness on the parts of Entergy and the State of New York, both of which have undervalued two reliable sources of bulk zero-emission electric power generation, and have failed to appreciate Indian Point’s potential long-term contribution to achieving the State’s 2040 zero-emission power system goal (at a rate of more than 18,000 GWh per year). New York State has failed to step up and provide economic incentives to enable Entergy to compete effectively against fossil fuel generators that have been benefiting for more than a decade from the low cost of natural gas fuel. In the wholesale market, the fossil generators can undercut nuclear generators and drive the cost of electricity down to levels that no longer support the continued operation of zero-emission nuclear power plants. These trends can be seen in the following NYISO chart.
As the world generates an increasing fraction of its electricity from intermittent renewable energy sources, there currently are growing problems with grid stability and there will be problems delivering electric power on demand 24/7 unless the huge swings in intermittent renewable generating capacity are brought under control.
The nature of the intermittent photovoltaic (PV) energy generation problem is described in a 2020 paper by Alberto Boretti, et al., in which the authors note, “Because of increasing uptake (of electricity) and the phasing out of back-up conventional power plants producing energy on demand, there is the necessity to study the current variability of the (PV) capacity factors based on the actual energy production.” The authors concluded, “While the best-performing (PV) facilities achieve annual capacity factors of about 32-33%, the average annual capacity factor is less than 30%, at about 26-27%.”
During the course of an average day, PV generation can go from 0% at night to 100% at mid-day, with “tails” as generation capacity grows in the morning and falls off in the evening, and variability during the day due to weather. Using Australian high-frequency capacity factor data (because similar data were unavailable in the US), Alberto Boretti, et al., developed the following chart that compiles the capacity factors from many individual PV plants and computes their average capacity factor (the dark line in the top chart), which is a measure of the average PV generating capacity actually delivered to the grid over the course of a 24 hour period.
The second chart shown below shows the actual load demand in megawatts (MW) from the California grid operator, CAISO, for 18 August 2020, a hot day with high load demand. The broad (5-hour) peak mid-day demand on the CAISO grid was about 47,000 MW. Minimum demand at about 4 AM was about 27,000 MW.
Hopefully, you see the problem. In this case for PV generation, the generation cycle is not in sync with the demand cycle. If states and nations are unwilling to address this mismatch with reliable generators that can be started on demand, then large-scale deployment of long-duration, grid-scale energy storage systems will be needed to meet electricity demand 24/7.
What do “long duration” and “grid-scale” mean? Look at the above curves and you can see the answers for yourself. How long is there no PV generation between sunset and sunrise? It’s 10 to 14 hours in Southern California, depending on the time of year. How much is 10% of peak demand on the CAISO grid? On 18 August 2020, that would have been about 4,700 MW, about the generating capacity for four nuclear power plants (but California only has two nuclear power plants, and those will be retired in 2024 and 2025). My point is that even 10% of peak demand is a big number and to store just one hour of that requires 4,700 MWh (megawatt-hours) of storage. The numbers only get bigger as you look at the amount of energy storage needed to meet demand for several hours, or over night.
To establish a point of reference regarding grid-scale energy storage capacity, here are a few important points.
California has a goal of having an energy generation portfolio with 60% renewable generation sources by 2030. That equates to a renewable generating capacity of up to 28,000 MW during the broad mid-day peak demand period on a hot day.
California has a goal of having 10,000 MW of “energy storage” by 2030, but they haven’t defined the needed storage capacity in terms of MWh. Most of the battery energy storage systems (BESS) delivered to date in California can operate at rated power for only 1 – 2 hours. That can help reduce short-term power peaking problems during the day, but is not useful for long-term power delivery at night.
The Gateway Energy Storage project in San Diego County, CA, currently the largest BESS in the world. It is rated a 250 MW with an energy storage capacity of about 250 MWh. That will supply about 0.5% of CAISO’s peak grid demand for less than one hour because the battery can’t be fully discharged. In terms of grid-scale energy storage requirements, this “world’s largest energy storage project” is still pretty small. It represents less than 10% of the output of the Diablo Canyon nuclear power plant for one hour, after which the BESS would be exhausted while Diablo Canyon would continue delivering electricity for the remaining 23 hours of the day, generating about 54,000 MWh per day with zero carbon emissions, day after day.
An approach for using energy storage systems to help meet daily peak load demand is shown in the following graphs, with energy storage from online power generators early in the day (blue) and stored energy dispatch (orange) later in the day to supplement online power generators and reduce the peak generation demand. In the top curve, the online power generators need to follow the load profile curve between the lower and upper limits set by the “energy storage” and “energy usage” horizontal lines. With more energy storage capacity, the second graph illustrates the case of constant online generation capacity (the single horizontal line), with all demand variability being absorbed by charging and discharging energy storage systems.
As electric vehicles proliferate, the peak of the demand curve will likely continue longer into the evening and night as commercial and private vehicles are recharged. The mismatch between the generation cycle of intermittent PV energy sources and the demand curve will be getting larger.
In this post, we’ll take a look two technologies for long-duration, grid-scale energy storage systems:
Advanced compressed air energy storage (A-CAES)
Solid medium gravity energy storage
Both of these energy storage systems convert electrical energy into potential energy that can be released on demand, for example, as high-pressure air or a large suspended weight. As you might expect, these are not “perpetual motion” systems and energy is consumed with each energy storage and discharge cycle. That means that less electricity can be dispatched than was originally input for storage. High cycle efficiency becomes a very important performance parameter for energy storage systems. Manchester University, UK, reported on a BESS that had round-trip energy losses between 9.6% and 12.5% for a variety of full charge / discharge cycles, placing BESS cycle efficiency at between 87.5% and 90.4%.
The A-CAES and solid medium gravity energy storage technologies appear to have long operating lifetimes, which could give them an advantage over battery energy storage systems. The National Renewable Energy Laboratory (NREL) has determined that current technology lithium-ion battery life in BESS applications is limited to about 10 years with active thermal management and restricted cycling, and about 7 years without thermal management. Over the operating life of a grid-scale BESS, the batteries will have to be replaced periodically, adding to BESS life-cycle cost.
Keep in mind why these energy storage systems are needed. Going “green” is not simple, and relying on power generation from intermittent renewable energy sources comes with the obligation to deploy long-duration, grid-scale energy storage systems to ensure that electricity demand can be met 24/7. Rest assured, this will all show up on your future electricity bills.
2. Advanced compressed air energy storage (A-CAES)
Toronto-based Hydrostor (https://www.hydrostor.ca/company/) is a leading developer of Advanced Compressed Air Energy Storage (A-CAES) systems. Their first system entered service in 2019. Several other A-CAES systems are being developed.
The basic A-CAES process is shown in the following diagram.
Surplus electric generating capacity is used to compress ambient air to produce heated compressed air. A thermal management system captures and stores the heat produced during compression as sensible heat. The cooled, compressed air is stored in a purpose-built underground storage cavern that is maintained at constant pressure by the hydrostatic head of water in a standpipe connected to a compensation reservoir on the surface. As the storage cavern is charged, water in the cavern is displaced and flows up the standpipe, into the compensation reservoir.
When there is a demand for energy from the storage system, compressed air is released from the underground air storage cavern, reheated by the thermal management system and discharged through an air turbine to generate electricity. Water flows back from the compensation reservoir on the surface into the storage cavern to maintain the pressure of the air remaining in storage.
This A-CAES process is entirely fuel-free and produces zero greenhouse gas emissions. The operation of the Hydorstor system is explained in the 2021 video, “How Hydrostor Is Enabling The Energy Transition” (3:54 minutes) at the following link: https://www.youtube.com/watch?v=cOWjwwKSR78
Hydrostor’s Goderich A-CAES Facility
The Goderich A-CAES Facility, which went into service in 2019 in Goderich, Ontario, Canada, is the world’s first commercially contracted A-CAES facility. It is in regular service on Ontario’s Independent Electricity System Operator (IESO) grid.
This utility-scale system can deliver a peak power output of 1.75 MW, has a maximum charge rate of 2.2 MW, and has more than 10 MWh of energy storage capacity. The system can deliver rated power for 5 to 6 hours.
Hydrostor notes that this use of A-CAES technology “is a significant achievement, conforming to all interconnection, uptime, performance and dispatch standards as set out by the IESO. Hydrostor’s Goderich energy storage facility proves out the ability of Hydrostor’s A-CAES technology to fully participate in and deliver a range of valuable grid services to electricity markets.”
Hydrostor, with partners Pattern Development and Meridiam, is developing the much larger Rosamond Energy Storage Project in Kern County, CA. This A-CAES project will have a rated power of 500 MW and an energy storage capacity of 4,000 MWh, which will provide for 8 hours of operation at rated power. This project was announced on 29 April 2021 and is expected to enter service in 2026. Customers would include the Los Angeles Department of Water and Power and the operator of the state power grid, CAISO.
Pumped storage hydroelectric (PSH) is a type of gravity energy storage system that has been in existence for many decades. Such systems are dependent on regional topography with a suitable water source in proximity to a suitable elevated water storage basin. Surplus electric power is used to pump a large volume of water up to the elevated storage basin. Later, water is released through a penstock to a hydroelectric turbine to generate electricity on demand. Among current energy storage technologies, the Electric Power Research Institute (EPRI) rates PSH highest as a long-duration, grid-scale energy storage system. General Electric reports that the round-trip energy efficiency of PSH typically is about 80%.
The solid medium energy storage systems work on a similar principle of using surplus power to raise a solid mass to a relatively high elevation and later release the suspended mass and use it to mechanically drive a generator during its controlled descent. Two firms working on this type of gravity energy storage system are Energy Vault and Gravitricity. Unlike PSH, their gravity energy storage systems are not dependent on the local topography. Here’s a brief look at their systems.
California-based startup incubator Idealab (https://www.idealab.com), developed an energy storage concept that uses a tall tower topped with tower cranes as a platform for systematically building and deconstructing stacks of regularly shaped heavy masses (bricks). Potential energy is stored as bricks are raised and emplaced at a higher elevation. Energy is recovered when a brick at a higher elevation is picked up and lowered while using the suspended mass to drive a generator, a bit like the regenerative braking system on a Toyota Prius. With multiple cranes in use to move the bricks, energy storage and discharge rates can be adjusted to match operational needs until the stack of bricks is completely constructed (fully charged) or deconstructed (discharged). The Swiss firm Energy Vault (https://energyvault.com) is commercializing this gravity energy storage technology.
In partnership with Italian energy company ENEL, Energy Vault built a sub-scale demonstration system in Ticino, Switzerland and has operated the system connected to the regional grid since July 2020.
The 110 meter (361 ft) tall unit can store 35 MWh of energy.Energy Vault reported that, from proposition to working prototype, the demonstration system took about nine months to complete and cost less than US $2 million.
Lessons learned from the demonstration unit include:
A tower can be erected quickly; the cranes can be delivered within months and erected within weeks.
The heavy masses (35 ton composite bricks) can be made from a variety of materials, including concrete construction debris that would otherwise go to a landfill. At a coal plant site, the bricks could be made with coal ash aggregate.
The mechanical systems do not degrade, providing a long operating life of the project.
Specially engineered control software ensures the bricks are placed in exactly the right location each time.
Round-trip cycle efficiency is between 80% and 90%.
Energy Vault claims that they have created the world’s only cost-effective, utility-scale gravity-based energy storage system that is not dependent on land topography or specific geology underground.
With its modular, scalable system design, Energy Vault expects to offer energy storage systems with a range of power ratings, from 4 to 8 MW, and energy storage capacities, from 20 to 80 MWh. These systems can serve as long-duration power sources, delivering rated power for hours.
Scottish firm Gravitricity Ltd. (https://gravitricity.com) is developing a novel mechanical energy storage technology in which excess electric power is used to power winches that raise a heavy mass inside a deep shaft. At its new, higher elevation, potential energy has been stored in the heavy mass. Electricity is generated when needed by releasing the heavy mass and allowing it to drop under the influence of gravity, but restrained by a braking system that extracts kinetic energy as electricity until the heavy mass makes a controlled stop at the bottom of the shaft, or at some intermediate height.
To demonstrate this technology, Gravitricity constructed a 15-meter (49-foot) tall test rig at a cost of £1 million (US $1.4 million) at the Port of Leith in Edinburgh, Scotland.
This 250 kW concept demonstrator uses two 25-metric ton (27.5-ton) weights suspended by steel cables connected to two winches. With a 7-meter (23-ft) lift, this demonstration system should be able to store almost 1.0 kWh of energy. After being released at the top of the tower, the two weights discharge their stored energy via a regenerative braking system for little more than 10 seconds. While the test duration is short, it is sufficient to demonstrate that the concept works. Moreover, the demonstrator is being used to validate engineering simulations that will be used in the design of a full-scale system.
Gravitricity plans to offer systems in the 1 MW to 20 MW power range with output durations from 15 minutes to 8 hours. Key operating parameters are:
Flexible, controllable power output and total energy delivered.
Response time: zero to full power in less than one second.
Cycle efficiency: between 80% and 90%
Design life: 50-years, with no cycle limit or degradation
A single mass system is well suited for applications that require high power quickly and for a short duration.
Multiple-weight systems are better suited to storing more energy and releasing power over a longer period.
A full-scale system will be designed to operate in retired (end-of-life) mine shafts or purpose-built deep shafts rather than in tall towers. In the UK, some potentially suitable mines have end-of-life shafts that go to depths of 750 m (2,461 ft). Deep shafts specifically built for the job could have a depth in excess of 2 km (1.2 miles). Masses up to 12,000 metric tons / 13,200 tons may be used.
The energy storage capacity of a Gravitricity system can be quite significant. For example:
A 12,000 metric ton mass suspended at the top of a 750 m deep mineshaft has a potential energy of about 24.5 MWh.
The same 12,000 metric ton mass suspended at the top of a 2 km purpose-built deep shaft has a potential energy of about 65.3 MWh.
Gravitricity reports that they currently are developing a number of project opportunities at existing mines with end-of-life shafts that are suitable for full-scale prototype energy storage systems. Candidate end-of-life shafts have been identified in the UK, the Moravian Silesian Region of Czech Republic and adjacent areas in Poland, and in South Africa. Gravitricity estimates that over 10,000 MWh of energy storage capacity can be deployed globally in existing end-of-life mine shafts.
In the longer term, Gravitricity plans to sink purpose-built shafts, allowing their energy storage technology to be deployed wherever it is required. Multiple, purpose-built shafts can be built in the same area to scale the total energy storage capacity to meet user requirements.
Gravitricity expects that their system will have a levelized cost of storage (cost/MWh) that is significantly less than for lithium-ion battery energy storage systems
Kandler Smith, et al., “Life Prediction Model for Grid- Connected Li-ion Battery Energy Storage System,” National Renewable Energy Laboratory & SunPower Corp., presented at the American Control Conference, Seattle, WA, 24-26 May 2017: https://www.nrel.gov/docs/fy17osti/67102.pdf
The accident at Chernobyl Unit 4 occurred on 26 April 1986. A post-accident view of the Unit 4 reactor building is shown below.
A temporary “sarcophagus” was hastily erected around Unit 4 to provide some protection for the recovery workers and the public, to stabilize the damaged building and protect its interior from the effects of weather. Since November 2016, Unit 4 has been fully enclosed within the more substantial New Safe Confinement (NSC) building. You’ll find a good overview of the NSC at the Chernobyl Gallery website here: http://www.chernobylgallery.com/chernobyl-disaster/new-safe-confinement/
On 5 May 2021, Richard Stone, writing for Science magazine, reported online that, “Sensors are tracking a rising number of neutrons, a signal of fission, streaming from one inaccessible room, Anatolii Doroshenko of the Institute for Safety Problems of Nuclear Power Plants (ISPNPP) in Kyiv, Ukraine, reported last week during discussions about dismantling the reactor..….ever since its (the NSC) emplacement, neutron counts in most areas in the Shelter have been stable or are declining. But they began to edge up in a few spots, nearly doubling over 4 years in room 305/2, which contains tons of FCMs (fuel containing material) buried under debris.” Modeling by the ISPNPP suggests that the increasing neutron count rates may be related to the gradual drying of the FCMs. Other phenomena may be contributing, such as the observed long-term disintegration and change of consistency of some FCM formations in the rubble.
The ceiling of room 305/2 was directly under the Unit 4 reactor core. From the force of the accident, that ceiling was driven down by almost four meters.
The original inventory of uranium in the Unit 4 core was about 180 metric tons enriched to 3%. In a French-German study of the condition of the Chernobyl sarcophagus, authors G.G. Pretzsch, et al. reported that about 96% of the original nuclear fuel inventory remained inside the sarcophagus. The distribution was estimated as summarized in the following table. The authors estimated that about one-half of the total fuel mass was in Room 305/2.
The condition of room 305/2 is described in considerable detail (in Russian) in the 1998 IAEA Report INIS-UA—062, “Room 305/2 Block 4 of the Chernobyl NPP: Its Condition, Assessment of the Amount of Fuel.” The room is a jumble of damaged building structural elements, reactor parts, and FCM in various forms, including “lava” flows.
The authors reported on estimates developed using a variety of methods, as summarized in the following table, and concluded that the best estimate for room 305/2 was ≥ 60 metric tons of uranium.
After Paul Allen’s death on 15 October 2018, the Stratolaunch Systems company he founded lost the broad air launch business vision it had under his leadership. A year later, on October 2019, the private equity firm Cerberus Capital Management became the new owner of the firm renamed Stratolaunch, LLC. Another year later, in November 2021, Stratolaunch LLC announced its new air launch business vision with an initial focus on missions involving a prototype reusable hypersonic rocket plane called the Talon-A. Stratolaunch has engaged the aerospace firm Calspan (https://www.calspan.com/stratolaunch-testing/) to build and test models of the Talon-A. As described on the Stratolaunch LLC website (https://www.stratolaunch.com), Talon-A is only the first of a family of air-launched vehicles that will be developed to establish “a complete air-launch vehicle ecosystem.” It looks like Paul Allen’s broad air launch business vision still may be alive and well under new leadership.
In an important milestone for Stratolaunch LLC, their giant carrier aircraft, Roc, returned to the air for the second time from the Mojave Air and Space Port in southern California on 29 April 2021, more than two years after its first flight on 13 April 2019.
During its second flight on 29 April 2021, the Roc reached a maximum altitude of 14,000 feet (4,267 m) and a top speed of 199 mph (320 kph). The 28-wheel undercarriage remained extended for the whole flight.
At some point in the future, the Roc carrier aircraft test flight program will transition to captive carry flights with a Talon-A vehicle, followed by drop tests and finally actual flight tests of the hypersonic vehicle.
Stratolaunch explains that its Mach 6-class Talon-A vehicle is designed to make hypersonic testing more routine. They describe the Talon-A as follows:
“The Talon-A features a length of 28 feet (8.5 m), a wingspan of 11.3 feet (3.4 m), and a launch weight of approximately 6,000 pounds (2,722 Kg). It will conduct long duration flight at high Mach, and glide back for an autonomous, horizontal landing on a conventional runway. It will also be capable of autonomous takeoff, under its own power, via a conventional runway.”
Beyond Talon-A, Stratolaunch is developing a larger hypersonic vehicle named Talon-Z. A longer-term objective is to develop the Black Ice fully reusable space plane that will be able to fly payloads and crew to orbit and return them to Earth for a landing at a conventional airport. The initial design will be optimized for unmanned cargo launch and return missions. A follow-on manned version will be optimized for transporting crews and cargo to and from orbit.
Stratolaunch’s planned family of aerospace vehicles is shown in the following graphic.
If you’re interested, you can subscribe to the Stratolaunch newsletter on their website.