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  1. “As a long-time advocate of new nuclear plant construction, perhaps I should stop sounding the alarm and simply maneuver to be ready to help pick through the wreckage.”

    If it is a race between the current trends in the “market” and the slow-poke NRC…I’m not sure I would bet on the NRC.

    If accident tolerant fuels are allowed to be used sometime in the near future, what do you think the chances are that their use will allow for significant down-grading of the QA/safety levels for various plant equipment and programs…hence driving down costs?

    1. The ATF will not allow for any significant down-grading of the safety limits. That is flawed thinking. “Keeping the core covered” is not going to somehow become a mere suggestion because the fuel cladding doesn’t oxidize as readily. I think everybody knows that deep down. Maybe some new plant designs will figure ATF into their safety case and allow slightly worse peak conditions during an accident, but there is no chance to change the licensing basis of any of the Gen2/Gen3 plants.

      1. Asking out of ignorance: Would ATF allow for any cost reductions? If so, how? If not, then why bother (asking under the assumption that our plants are already “safe enough”, as some argue)?

      2. IIUC, technologies like SiC cladding would largely eliminate the threat of meltdowns even if fuel was partially uncovered.

        Metallic fuel allows greater water flow and heat production, which can reduce costs per kWh by allowing the plant to operate at higher power without increasing expenses.

      3. @EP: Yes, metallic fuel would have less stored energy due to higher thermal conductivity and could likely operate at a higher linear heat rate as well as decrease peak temperatures in an accident. Based on LightBridge’s online publications, I find that they do not pack more uranium atoms per linear metric of fuel rod length (same or less energy content as UO2); the fuel does not have longer legs for a given enrichment. Not sure if any PWR have the room to uprate much, even if metallic fuel significantly increases margin to dryout. Lightbridge might allow slightly smaller reloads due to increased peaking allowances due to increased margin. You also have to handle the fact that the fuel swells about 1% per percent 10GWd/T and changes the fuel/water ratio by as much – something not typically accounted for.

        The SiC cladding is a composite material where thread is wound onto a mandrel and then is impregnated by vapor deposition to form a tube. Sure, they even have ways to cap those tubes and yes, they are supposedly quite durable, but none of that sounds cheap. It sounds like manufacturing will be expensive even with a mature product line. Metal tubes are a really good trade-off. I don’t see SiC cladding becoming adopted due to costs.

        I like the ATF coatings and think that such a treatment should eventually become standard across the industry, so long as it doesn’t force an increase in enrichment requirements greater than say 0.20% on average. My assumption is that the cladding treatment significantly reduces oxidation/corrosion and allows cladding to function beyond the current 62GWd/T rod average burnup limit currently observed for modern zirc cladding. There could be a savings in fuel costs if the fuel could last beyond 62GWd/T rod average burnup.

        I like that you mention: “even if fuel was partially uncovered,” because as you know the fuel does become uncovered certain LOCA sequences. Still, I don’t see how a licensee is going to leverage a “largely eliminated threat of meltdown” afforded by SiC cladding in order to justify continued operation with ECCS components out of service (i.e. broken safety injection pump). I consider this to be flawed reasoning or at least wishful thinking. I don’t think the technical justification is sound. The ECCS components are just as important to recovery and long term outcomes as they are to injection phase prompt action. They need to be available for design basis events.

  2. Rod,
    I agree with you.

    The problem is that indeed, most power outages are due to trees shedding a few branches. But we are moving into a period of structural power outages. A period of load shedding, not tree shedding.

    But few people recognize this because so far–it’s been all about the trees.

    ISO-NE study of fuel availability should sound some alarms, but it hasn’t. 19 of 23 scenarios for New England include load shedding by 2025.
    https://www.iso-ne.com/static-assets/documents/2018/01/20180117_operational_fuel-security_analysis.pdf

  3. It was not a good week for the industry. Since power generation has become politicized like everything else I have tried to explain to the lay folks why more wind/solar does not equate to lower CO2 emissions.

    Its tough sledding even when I point to the following:

    https://www.electricitymap.org/?page=map&solar=false&remote=true&wind=false

    This is a great link which shows real time and trends for Co2 emissions. Predictably the only countries/regions that are i.e. low CO2 on a continuous basis are nuclear such as France and Ontario. This excludes places that are all hydro.

    Denmark and Germany are always various shades of yellow or brown.

    It doesn’t seem to sink in though.

    Add to your list “ignore actual data”

  4. “A multi-decade, high-risk experiment, initially envisioned by Ken Lay and his colleagues at Enron, is nearing a potentially painful precipice.”

    I think this comes close to hitting the nail on the head. In my limited opinion, there is something definitely wrong with energy economics that are short term, provide an unreliable product and are not in the interests of the common good.

    Despite the rhetoric preached by some, the “market” is not always the best decision maker. Those in charge of our country should be providing a nearly invisible hand guiding that market to what is in the best long term interests of the public at large. Instead, they seem to be making their decisions with the short term in mind.

    History proved that the Enron boys were not “the smartest guys in the room.”

    1. The “market” as any control system, is only as good as it’s signals, feedback lags, gains and control algorithms allows it to be.

      1. “The “market” as any control system, is only as good as it’s signals, feedback lags, gains and control algorithms allows it to be.”

        I think you are right. If one could model a circuit of the US economy, I think you’d find it is getting some positive feedback, has a few poles in the right half plane and has some unnecessary current drain where the bad guys who run the system are running off with the cash.

  5. As someone watching from nearby and being concerned that jugheads here in Canada will follow along, this jumped out at me:

    While it’s true that some of this situation appears to be part of a normally functioning market that uses price signals to help participants determine opportunities and capacity choices …

    My observation is that the ultimate users and purchasers of electricity, all who really need it, aren’t participants in this ‘market’. The participants are the generators and virtually powerless deliverers of electricity. They’re working in a ‘market’ that’s heavily tilted. It got that way with good intentions from puppet environmental groups. I agree that there is probably a serious lesson coming somewhere in the USA. I hope it won’t be too deadly , but I’m not optimistic that one lesson will be enough. Institutional inertia takes a long time to overcome. Some of it might have to change over several election cycles.

  6. With natural gas now making up over 50 percent of the supply of electricity in New England, and most of that gas coming from pipelines that you can count on one hand, we are in a precarious situation here in New England. The Iso-New England fuel security analysis identified the winter-long gas pipeline compressor outage as the single worst scenario leading to the greatest number of load shedding days. And compressors being rotating equipment can fail catastrophically, we know. This worst-case scenario was followed by an extended 2-unit Millstone winter outage. This past winter during the deep freeze, New England needed the dual-capability of oil-burning units like Mystic to get us through the spell along with Millstone, Seabrook, and Pilgrim. We are losing that fuel diversity capability. Meanwhile, we have the offshore Cape Wind with its mandatory 20 cents per kwh wholesale rates, ramping up to 30 cents over the coming decade. And we have various photovoltaic arrays sprinkled around the state, that would otherwise cost about 20 cents per kwh just for amortized capital costs, subsidized by us poor ratepayer suckers. The future of electric power security in New England is bleak.

  7. The system is just reacting to regulation by routing around the problem. If the regulators don’t want nuclear power, they will get rid of it.

  8. My series of articles address the root cause of this problem. Today’s article, More on the Auction Fiasco, is at http://bit.ly/2GtJdn3
    This article, and the others referenced in the article, and the ones that will be published this week and next, get to the core of the problem.

  9. The root cause has little to do with the regulators and a myriad of other issues, it has to do with a long-term failure to educate.

    The majority of Americans, and of course this includes politicians, have no idea what Rod and the rest of us are talking about. As long as the lights turn on and they can watch TV or surf the web the issues we’re concerned about are just too abstract to them. So, they don’t know how good they have it and haven’t a clue as to the problems we’ve created in our electricity generation sector.

    Back in the 1970s in Germany, the pro nuclear types had a bumper sticker that mocked the antis: “Mein Strom kommt aus der Steckdose” (iow, my electricity comes from the wall socket), this was a succinct way of hitting back at the mindless anti-nuclear movement. Unfortunately, we’ve seen how well that worked out with Germany rushing toward a complete phase-out of nuclear by 2022.

  10. Many nuclear power plants and coal power plants, that were Base-load plants were shut down and more are being shut down. These problems are going to multiply, and the economic damage is going to be significant.
    One problem I see rearing its ugly head is that the shutting down of the base-load plants are going to have unintended consequences. Presently many (if not all) of the Base-load plant exist as the hub among the nodes making up the electrical grid. Thus, the lines radiating out of that node are sized to carry their load to the next node. Few, of these lines radiating out of the hub have the capacity to carry the entire load of the generating station. Several of these stations were two GW stations. The loss of that station means that the replacement power has to be routed through several of these lines that were designed to deliver power to the hub, and then be distributed to the other transmission lines to deliver to those customers, while still supplying the loads on the line that has become the feeder line. Massive upgrading of the various transmission lines are going to be needed. Breakers will need upgraded. Grid distribution protection schemes will need to be modified. Breakers replaced and moved. These plants were built 20 -40 years ago. The distribution system has grown around these plants. The distribution system near the plants relies upon the source being the plant that is shut down.
    If you live in an area where these plants are being shut down, Ohio, Western PA, MA, etc. I recommend you check your insurance policy on power loss coverage for spoiled food, buy some candles or Battery operated LED lanterns, a generator large enough to power your freezer and furnace, and other power related problem mitigation.
    “The U.S. electric power system is designed and operated to meet a “3 nines” reliability standard. This means that electric grid power is 99.97 percent reliable. While this sounds good in theory, in practice it translates to interruptions in the electricity supply that cost American consumers an estimated $150 billion a year.” [Galvin Electricity Initiative]
    How much will the frequent outages of “Green Power” that we “learn to live with” cost us?

  11. Here in the Pacific Northwest, about 50% hydropower, we are doing fine. No more wind farms are under construction. Indeed, power from utilities is down slightly which I attribute to LED lighting installation.

    More, Portland General Electric, the major utility for northern Oregon, is stopping planning for one or two CCGTs to replace the coal burner in Boardman which is going to shut down soon. Instead they have contacted with the Bonneville Power Administration for hydropower. BPA is happy because they now wheel less than previously to California, so have the surplus to sell.

    As far as I know, Energy Northwest continues to move forward on the plan to place a Nuscale 12pak next to the Columbia Generating Station, which is growing long of tooth.

    Our neighbors to the south in California are closing 3, or is it 5, CCGTs and stopping planning on building 2 more. Of course the remaining reactor is going to shut down. I don’t fully understand how California plans to stay energized. But BPA isn’t going to wheel much power down the Pacific Intertie anymore.

  12. “As far as I know, Energy Northwest continues to move forward on the plan to place a Nuscale 12pak next to the Columbia Generating Station, which is growing long of tooth”

    Not quite correct. We have an agreement with the Utah Associated Municipal Power Systems to potentially operate the first NuScale small modular reactor, expected to be commercially operational in the mid-2020s at the Idaho National Laboratory

    1. Quite correct, in that I have seen nothing indicating that the plan has been abandoned.

      What you write about Idaho Falls is also correct and is more immediate.

      1. I’ve worked at Columbia for 10 1/2 years and have never heard of a legit plan to build a NuScale plant on site. There were early talks about possibly converting Unit 1 and using the remaining structure, but that was thrown out of the window fairly quickly I believe.

        I would LOVE it if it were true though….just like I day dream while looking out at the abandoned skeletons of Unit 1 and Unit 4 and think about how awesome it would be if they had completed them.

      2. Bonds 25 — The Washington State Legislature commissioned the study which recommended as I indicated. The recommendation did not mention the reuse of any existing infrastructure, just building a new Nuscale 12pak.

        I don’t know the planning horizon, but it would be after the Idaho Falls project proves that Nuscale can deliver.

  13. @EP – It seems that publications pertaining to LightBridge that were previously available for download on NEI are no longer available. From memory, one of the documents discussed the U-Zr alloy density being 10.2g/cc, which is similar to a “stack density” for typically dense UO2.

    I did find an ANS publication (unfortunately a PowerPoint) from 2011 that shows a comparison between “equivalent” light bridge and 17×17 UO2 fuel assemblies for a 14’ EPR core. On page 6 you will see that the comparison is between a reference UO2 assembly containing 536KgU @ 4.4w/o and a LightBridge assembly containing 274KgU @ 11.3w/o.

    http://filecache.drivetheweb.com/ir1_ltbridge/162/download/Lightbridge+ANS+June+2011+Presentation.pdf

    It seems like a non-disclosure agreement with LightBridge would be needed to obtain information for more detailed nuclear calculations, but based on what I could scrounge-up… the 24-month cycle at uprated power [marketing] promises are based on increasing fuel enrichment significantly above 5 w/o. I don’t see that as a problem, other than for economics…

    Assuming that LightBridge fuel assemblies allow a reduction in batch size due to the fact that they can achieve higher burnup and operate with increased peaking, I have compared an 80-feed reload of 4.4 w/o UO2 assemblies to a 68-feed reload of 11.3 w/o LightBridge assemblies.

    Assume: $100/SWU
    Assume: $8/Kg Conversion
    Assume: $30/Kg U3O8
    Assume: $200,000 fab cost per unit

    80-feed UO2
    SWU $25,893,425
    Conversion $3,422,054
    Uranium $33,493,349
    Fabrication $16,000,000
    Total $78,808,828

    68-feed LightBridge
    SWU $37,218,921
    Conversion $3,989,333
    Uranium $39,045,600
    Fabrication $13,600,000
    Total$$ $93,853,855

    I think the LightBridge product is great, it certainly has a good Russian pedigree with lots of use in naval applications; I want to see it used in commercial power plants. It is going to be challenging to justify “like-for-like” replacement in the current fleet.

    1. If you do the arithmetic, you’ll find that the LTBR fuel has about 31.0 kg U-235 compared to 23.6 for the conventional.  This is 1.3x as much, which is obviously going to support a longer fueling cycle.

      If it supports 23 months of operation per cycle vs. 17 months, per your numbers the cost comes to $4.08 million/mo for LTBR vs. $4.64 million/mo.  You also get about another 5 days of operation per year.  Figuring 24e6 kWh/day @ $.05/kWh ($1.2 million/d) that’s another $6 million/yr in revenue on top of the lower cost.  It sure looks attractive to me.

      1. I was just pointing out that adopting it AND going to a longer cycle AND operating at a higher power – to take advantage of it, requires breaking a 50-year paradigm of capping enrichment in LWR at 5%.

      2. I was just pointing out that adopting it AND going to a longer cycle AND operating at a higher power – to take advantage of it, requires breaking a 50-year paradigm of capping enrichment in LWR at 5%. I was also showing that SWU is expensive and it doesn’t scale linearly with 235U content (as you know). This fuel product is not actually competitive in a plant that can’t realize an uprate with it (basically the u.s. fleet). My assumption was that 80 fuel assemblies can be replaced by 69. I didn’t scale it by 130% 235U content, instead I arbitrarily chose 115%.

  14. Excellent read on the effects of the “Bomb Cyclone” and how Green Energy coped with the event, and how fossil saved their posterior. Makes me wonder what is going to happen with the shutdown of the coal plants in Massachusetts and the shutdown of the First Energy plants. Hope that next winter is not as bad is this was for New England.

    https://www.netl.doe.gov/research/energy-analysis/search-publications/vuedetails?id=2594
    Click on the orange “Download” to read the report.

    1. Hopefully is IS as bad, so that the magnitude of the mistake cannot be denied and we correct course.

      1. I wonder if the plant shutdowns will slow the system’s administrative processes. I was talking with a switchman in the Ohio area yesterday who told me he’d waited days in the past for PJM to improve an outage. It won’t be easy getting things done if the power systems are on the ragged edge.

    2. Thanks Rich, indeed a sobering article. Spoiler alert: “Green Energy” did not cope with the Bomb Cyclone event. Overcast skies and high wind speed meant essentially zero solar and wind generation off 11%. Being winter, nuclear was already at max. NE gas was pipeline capacity constrained. Regional (NY, NE, PJM) gas spot prices were up 4 to 8 fold, with electricity prices to match. But in NE there was no more gas at any price. We survived due to dual-use plants having (barely) sufficient fuel oil reserve. NY imported PJM coal, which had ample spare capacity and rose to the occasion.

      That’s resilience.

      1. @Rich: Thanks for the straight line. Here’s a back-of-the-envelope with commentary.:

        From figure Exhibit 1-6 of your reference, we can estimate that NE fuel oil generated roughly 100 GWh/day for 2.5 days. Normally this figure is close to zero as those plants burn gas instead. Call it 250 GWh at 4 GW capacity.

        Consider two cases: massive CAES, and your – or rather their – favored batteries.

        A few years back there were plans to build a 1.2 GW 60 MWh CAES by desolution mining a salt dome near Delta, Utah, at a cost of $1.5 billion. NE is built on granite, not sandstone and salt, but we would need 4 of these at $6 billion. Plus the renewables to charge it. Of course, the next shortfall might not last 2 1/2 days.

        But you wanted to know of batteries, the Darling of Deep Green. Late 2017 Tesla delivered a Lithium battery pack to S. Australia to help even the strain. It has 100 MW capacity, stores 129 MWh, and ran $32.35 million + labor.

        If all we needed was the peak capacity, that’s batteries’ strong suit and 4GW/100MW = 40 plants. At $32.35 million per that’s a mere $1.3 billion. But their 5.2 GWh falls a bit short of the 250 GWh required. To meet that you’d need 1,923 Tesla battery packs at $62 billion. Now we’re talking real money.

        For all it’s overruns, 2 Vogtle projects (four AP-1000) would fill the bill and come in at about $50 billion. Barakah’s four APR-1400 reactors will run perhaps half that. Plants that actually generate power, not just soak it up.

        And deliver for more than 2 1/2 days at a stretch.

      2. Ed,
        I grew up in north eastern Ohio. I still remember stories about how the NG companies had bought up the rights to the salt caverns created by desolution pumping of the salt. There are numerous empty caverns under OH, and Michigan and Lake Erie that are used or available for this. They did this so that they could buy gas in the summer at a much lower price than in the winter and also avoid the higher prices during high demand periods. Today they are mined today in the same way they mine coal and thus would need to have the entrance sealed in some way to make them useful. Would it not make more economical sense to store NG, REAL energy, in these caverns rather than Compressed air? Or is this what they plan on storing?

      3. The problem is that it’s expensive and lossy to turn the only scalable “renewables” into “real energy”.  Air has the virtue of being free.

      4. Rich,
        No, the Delta CAES is just that, Compressed Air Energy Storage. It’s part of a lashup between local solar — Delta is southern Utah high desert — and wind transmitted from Chugwater Wyoming, some of the best in the country.

        Delta is on an exiting HVAC link to So Cal, and the CAES system is to help with California’s energy storage mandate, so economics are in a certain sense irrelevant and So Cal has Porter Ranch anyway.

        From an earlier comment I neglected to link:

        “The Intermountain Energy Project’s Wyoming –> California connection involves only 525 miles of new transmission from the wind farms at Chugwater Wyoming to the CAES facility at Delta Utah. From there the now-fairly-reliable wind energy hooks into existing coal transmission to Southern California. Pre-construction cost estimates were

        Chugwater, Wyoming 2.1 GW wind farm: $4.0 billion US.
        Delta, Utah 1.2 GW / 60 GWh CAES $1.5 billion
        Chugwater –> Delta 525 mile transmission line $2.6 billion

        “Total damage: $8.1 billion. I couldn’t find the wind Cf specifically at Chugwater, but NREL lists Southern Wyoming in general around 42%, which seems awfully low to anyone whose actually been there.

        “But it’s why they chose Chugwater. That, and there is a slight negative correlation between California wind and Wyoming’s. Still, $8.2 Billion / (2.1 GW * 0.42) = $9.3 billion per somewhat reliable GW.

        “The project is actually underway; we shall see how close were these pre-construction estimates. There is nothing first-of-a-kind about any of it; I expect they will come in fairly close.

        “60 GWh is a fair bit of storage. One could near even out California’s entire daily load fluctuation with that amount were generation exclusively thermal and hydro.”

        http://web.archive.org/web/20140924062047/https://abcnews.go.com/Technology/wireStory/wind-energy-proposal-light-los-angeles-homes-25718476

      5. Rich,
        To expand a bit, at the time I did the aforementioned “One could near even out California’s entire daily load fluctuation with that amount were generation exclusively thermal and hydro.” I did a back of the envelope that suggested with a bit more than 60 GWh storage and assuming a 24 hour charge-discharge cycle, one could average out California’s entire daily variable load with thermal plants running continually at their maximum capacity.

        $1.5 billion for this much storage is actually a pretty good deal: it could go a long ways were it used wisely.