Fission heated gas turbines address MIT Future of Nuclear challenges. Easier, straighter, less costly path
Addressing Recommendations of MIT Future of Nuclear Energy In a Carbon Constrained World
The Massachusetts Institute of Technology (MIT) is a world renowned institution that has produced thousands of highly educated engineers and scientists. It is generously supported by foundations, corporations and governments. In 2003, the MIT Energy Initiative, began publishing a series of reports on the future of various energy sources.
The Future of Nuclear Energy in a Carbon Constrained World, the ninth and most recent report in the series, identifies the major issue facing nuclear energy advocates and developers. Unless nuclear energy costs can be controlled, there isn’t much room for significant growth.
The report offers three recommendations that would help nuclear energy developers establish better control over system costs. The fourth recommendation is more about increasing costs for competitors than about lowering nuclear costs.
- An increased focus on using proven project/ construction management practices to increase the probability of success in the execution and delivery of new nuclear power plants.
- A shift away from primarily field construction of cumbersome, highly site-dependent plants to more serial manufacturing of standardized plants.
- A shift toward reactor designs that incorporate inherent and passive safety features.
- Decarbonization policies should create a level playing field that allows all low-carbon generation technologies to compete on their merits.
Aside: The title of the report indicates that the study group leaders believe this fourth recommendation is the most likely to be implemented successfully. The first three recommendations are rather conventional wisdom that has yet to be implemented successfully in “The West.” There is hope if governments can agree to implement programs that penalize energy sources that produce carbon dioxide or that reward nuclear for its emission free power generation, or that both penalize emissions and subsidize nuclear. End Aside
Though it would be good for nuclear and may be good for all of us on several different measures if the playing field was leveled, it’s not a good idea to build an industry on hopes and promises that depend on election cycles and political pressure alone.
Though this article is mostly a revision of an article published in August 2017, it is an overview of a short cut way of addressing recommendations 1-3. It isn’t a radical new reactor, but instead is a power production system that combines well-developed systems. The end result is a new system with well established supply chains, an experienced labor force with refined skills, and a functional maintenance model.
The description is purposely hazy on such details as size and power output because the intent is to be able to take full advantage of a large infrastructure that has already produced and operated millions of power-production machines covering a broad spectrum of sizes and power levels.
I cannot resist the temptation to point out that the committee-produced report from the MIT study group, despite its high powered institutional support and broad range of contributors, didn’t mention nuclear gas turbines. Instead, this article was written by an individual who has been refining this concept since 1991. It’s possible that the path described here is too straight and has too few remaining challenges to capture institutional attention.
Heat engines, not reactors
It is a modern day truism that natural gas power plants are cheap while nuclear power plants are expensive. Natural gas plants can also be built in a variety of sizes by a larger number of suppliers who have a pretty good record of completing projects in a relatively short and predictable amount of time.
Another truth is that nuclear fuel can be very cheap on a per unit heat basis, even when compared to what is often called “cheap natural gas.” For the past three decades, the total cost of nuclear fuel has been consistently close to 60 cents per MMBTU; the price of natural gas has been somewhere between $1.80 and $4.50 for the past ten years.
Credit: U.S. Army
When natural gas prices are near their low point, efficient, affordable, and reliably constructed natural gas combined cycle plants give that fuel the ability to dominate electricity production and sales. That is even more true in a market where gaseous waste product disposal is generously provided for free.
That’s our current situation. Nuclear plant construction costs are out of sight and schedules cannot be predicted. Fuel costs remain consistently low and emissions are virtually non existent, but gas is dominating.
It’s time to change the game by adapting the well-proven, flexible and reliable combined cycle to be able to use nuclear fuel. That will match the best available heat conversion system with the superior fuel that is more abundant, needs no pipelines, produces manageable quantities of solid waste, and can operate inside sealed buildings.
If you can’t beat them, copy them.
Simple Cycle Gas Turbines (Brayton Cycle Machines)
Modern natural gas plants include Brayton Cycle gas turbines. The cheapest ones per kilowatt of generating capacity are classified as simple cycle machines. They have no additional components designed to improve plant thermal efficiency. They consist of a compressor, a heat source, and a turbine with some inlet air ducting and filters, a fuel supply system and a stack for exhausting waste gases.
They are so cheap that they can be economically viable even if run a few hundred hours per year to meet peaks in demand. Their fuel costs are high due to low thermal efficiency. They are so simple that they can be remotely controlled and often don’t need on site operating staff. They can spin up from a cold condition to full power in 15-20 minutes.
They can burn either natural gas or distillate fuel; the main requirement is that the fuel needs to be zero or very low ash and it cannot contain sulfur or other contaminants that can attack turbine blades.
When run on natural gas, these peaking plants are dependent on “just in time” fuel delivery systems. In some regions, especially New England, natural gas delivery can be interrupted when the turbines are needed the most. That problem can be solved by installing dual fuel capability and a distillate fuel oil storage tank. Duel fuel machines with on-site storage can then burn distillate fuel oil in an emergency situation.
Unfortunately, distillate fuel often costs 4-10 times as much as natural gas on a heat content basis. This choice is made affordable by running the turbines on premium fuel only when the need is high enough to spike electricity prices.
Brayton cycle machines made their way into the electrical power business because they filled an important customer need for reliable sources of power to meet demand peaks. Since they were not expected to operate steadily, their construction costs needed to be low enough so that they could sit idle without driving the accountants crazy.
Advantages Of Brayton Cycle Machines Over Steam Turbines
These machines, derived mainly from experience in producing powerful, compact, lightweight, reliable, flexible, and cost effective engines for aircraft and ship propulsion, have numerous advantages over the venerable steam turbine power plants that have been in use on ships and in electrical power production since the First World War.
Unlike steam plants, gas turbines depend on a working fluid that doesn’t change phase over the full range of pressures and temperatures found in the operating cycle. It is a gas at the beginning, middle and end of the cycle. This attribute shrinks and simplifies the system by eliminating the need for valves, piping, and heat exchangers to separate and recover condensation. Water droplets can destroy rapidly spinning turbine blades and must be eliminated before using the high pressure, high temperature water vapor to turn a turbine.
The gases used as the working fluid also undergo a much reduced change in volume per unit mass over the range from the highest system pressure and temperature to the lowest. This cycle attribute leads to compact turbines where the size difference between stages is far less than a comparable steam turbine. Depending on the gas used, the number of stages in the turbine may also be significantly reduced compared to a steam turbine.
Gas turbine power plants do not require large tanks of tightly controlled pure water to provide system make-up to compensate for inevitable leakage and purposeful use of working fluid to clean the surfaces of heat exchanger tubes.
Simple cycle gas turbines also save space and weight by using fuels that produce purely gaseous waste products with little, if any ash particles. By using only zero or very low ash content fuels, simple Brayton cycles eliminate expensive, space-consuming heat exchangers (boilers or steam generators) that steam plants use to transfer the heat of combustion into boiling water. Instead, they spin turbines by directly expanding heated, compressed gas through the turbine’s acceleration nozzles and blade stages.
As a result of the above features, complete Brayton cycle gas turbine-based power plants are often less that 1/4th the size and mass of a comparably capable steam turbine power plant. They thus require less construction material and fewer labor hours to assemble. They are simpler to harden against seismic stresses. They need fewer, smaller buildings for the plant and also for supporting the smaller staff of people compared to steam plants.
Turning Peakers Into Longer Running Facilities
Gradually, Brayton cycle peaking plants proved their value and demonstrated their easy reliability. Customers showed they were interested in spending more for improved performance, especially in terms of specific fuel consumption.
Engineers suggested that the most dramatic efficiency improvement could come from combining Brayton cycle machines with Rankine cycles in a cascading series of heat conversions. The exhaust gases depart Brayton cycle turbines at a high enough temperature to function as the heat source for water boilers known as heat recovery steam generators (HRSG).
Maximum thermal efficiency in a simple Brayton cycle tops out at less than 40%; in a combined cycle, it is possible to achieve efficiency closer to 60%.
Of course, combining Brayton cycles with Rankine cycles reintroduces some of the cost, size and complexity of pure Rankine steam systems, but a 1000 MWe combined cycle plant includes a steam plant that is less than 1/3 the size of a 1000 MWe steam plant since about 2/3 of its output comes from the Brayton cycle turbines. It is also a more flexible power system that usually includes at least three turbines, each of which may be able to operate without the other turbines being in operation. (Many HRSG’s have the ability to be directly fed from an auxiliary boiler instead of from waste gases from the Brayton Cycle machines.)
Why Does Steam Still Dominate In Nuclear Projects?
One might logically ask if Brayton cycle machines are so obviously cheaper and simpler than Rankine cycle steam turbines, why are any steam turbines being built? Why haven’t at least a few nuclear projects using Brayton Cycle machines been commercially deployed?
Even though a few of the advanced systems being designed have Brayton cycle heat conversion systems, they are still in the minority. Even those that do are not as simple as they could be, despite the fact that capital cost reduction should be at the top of a design criteria list for any plant designer who wants to succeed in the market.
It is unfortunate, but many people trained as nuclear engineers have only a dim understanding of the massive structures, systems and components required outside of the highly refined reactor cores that are their main area of responsibility. They are experts at modeling the interactions of neutrons, a wide range of isotopes, varying coolant properties and widely differing support structures, but they don’t appear to spend much time thinking about the challenges of building, operating and maintaining enormous steam plants, pure water systems, cooling water systems, valves, pumps and some of the world’s largest saturated steam turbines.
They spend even less time thinking about the costs and schedules associated with building the massive foundations, buildings and supporting systems that those large steam plants require.
Addressing the costs of systems and structures related to converting nuclear fission heat into useful power is more important that most nuclear engineers realize. Though it’s difficult to find published studies with this information, a statement often heard in gatherings of nuclear project experts is that ~ 80% of the construction budget for fission heated steam plants is consumed outside of the “nuclear island.”
Heat Conversion Requirements Drive Nuclear Technology Selection
If a plant designer starts with the goal of adapting gas turbines to effectively operate with fission heat, it becomes almost immediately obvious that conventional light water reactor plants and their associated fuels cannot do the job.
The maximum temperatures available from such a system can’t drive a Brayton cycle machine with anything close to the desired efficiency.
Sodium cooled reactors come a bit closer, but the boiling point of sodium at atmospheric pressure is still too low for reasonable Brayton cycle efficiency. Many engineers have good reason to be wary of sodium coolant at low pressure; they would have even more cause for concern if asked to consider high pressure sodium as a primary coolant.
Even molten salt reactors, which were initially developed with the idea of using them as the heat source for Brayton cycle jet engines or turbo-props, have heat exchanger material limitations that make it unlikely they can produce gas turbine inlet temperatures above about 800 ℃. A complex Brayton cycle that includes large, expensive components like recuperators and intercoolers can effectively use that temperature to produce reasonable cycle efficiency, but there isn’t much headroom for improvements without a material breakthrough.
The added complexity of the system negates some of the previously described Brayton cycle advantages.
High temperature gas cooled reactors have been under almost continuous development and refinement since the 1940s. They have demonstrated the capability to deliver gas at temperatures at temperatures as high as 1200 ℃ using technologies available in the mid 1960s. Though most high temperature reactor designs today aim for a more modest introductory temperature of 750-800 ℃, there is headroom for future improvements.
Triso Inside™
One of the keys that may unlock high temperature gas reactors and free them for wide use in an almost unlimited number of applications is the Triso coated fuel particle. This innovation, developed almost 50 years ago, coats a tiny particle of fission fuel in multiple layers of material that combine to seal fission products inside the particle.
As long as the coatings are properly applied and remain intact, radioactive materials remain securely contained. Even if there are minor releases from improperly coated or damaged particles, the public is protected by several additional barriers. Through a lengthy, well-controlled, well-designed and consistently managed development program, the U.S. DOE and its partners have developed credible, repeatable processes that result in reliable fuel capable of long core exposures.
As long as high temperature reactors have “Triso Inside™” and are designed to ensure that their fuel temperatures remain within a broad band, currently reaching as high as 1800 ℃, they should be able obtain construction and operating permission on the basis of providing adequate protection.
Fuels with Triso Inside will be more expensive than conventional nuclear fuels when they are first introduced, but there is a well trodden path towards mass production cost improvements. Triso fuel suppliers should act like traditional fuel suppliers to encourage widespread use of their product, including creating identity advertising, assisting with licensing, training system designers, and potentially offering financing to developers who are creating innovative ways to use their product.
Perhaps some well capitalized fuel suppliers with exceptional project management and marketing skills could leverage their chemical engineering expertise into a lucrative new line of work.
Cooled By Nitro™
The other decision that can throw the door wide open on developing nuclear heated Brayton cycles for almost any conceivable energy application is selecting a working fluid that can take advantage of existing Brayton cycle machinery.
A small niche of nuclear plant designers has been interested in using hot gases passed directly though high temperature reactors to spin gas turbine machines since the earliest days of nuclear power development. Unfortunately, nearly all of them assume that helium is the only gas that can be used to directly cool a nuclear reactor.
That assumption – which is false – leads in two possible direction. One is the path that General Atomics and PBMR took on paper, which was to conceive of the use of a helium turbo machine. That path turned into an effective dead end in the real world; the challenges associated with developing helium turbo machinery are far greater than imagined. PBMR ran out of money before approaching a useable machine; GA took the safer path of not even trying to exit development studies on their own dime.
The other alternative is to use helium cooling for the reactor, but to add a gas to gas heat exchanger to move the heat into air or nitrogen so that conventional turbo machinery designed for combustion turbines can be used. This path adds a large, costly component and reduces system efficiency because of the inevitable drop in turbine inlet temperature caused by the heat transfer process. Adding the heat exchanger is particularly problematic when looking into the future; there are well identified paths for increasing the temperature capability of Triso particle-based fuels, but material breakthroughs will be required to enable cost effective heat exchangers at temperatures higher than 800-850 ℃.
There have been three nuclear heated Brayton cycle machines operated in the US. Two – HTRE-1 and HTRE-2 – used atmospheric air and put the turbine gases directly into the desert air in the location where they were tested. The other was the ML-1, which was designed to produce 300 KWe and to be mounted on a trailer that could be pulled to a remote communications site.
The ML-1 was “cooled by Nitro™” which allowed it to use conventional turbo machinery. After all, nitrogen gas makes up 80% of atmospheric air and has almost identical thermodynamic characteristics.
Unlike helium, nitrogen is available in almost unlimited quantities in an unlimited number of geographic locations. It also works well in the same machines that have been developed and refined to use atmospheric air and combustion products. Using nitrogen as the reactor coolant and the working fluid for the turbo machines eliminates the need for a separate heat exchanger.
High temperature nitrogen cooled reactors will be large, low power density components, but the “reactor” performs the functions of heating the turbine gas, storing the fuel, and providing effective decay heat mitigation. When comparing sizes to other potential power sources, the important metric is the size, cost and schedule for complete systems instead of focusing on certain components.
During early stages of development and deployment, system designers should keep it simple and not worry much about thermal efficiency. They can build roadmaps for future improvements, however, that build on the advances that have already been proven to work well in combustion Brayton cycles, including developing combined cycles, co-generation for process heat applications, co-generation for district heating, and inter cooling and regeneration.
One improvement path that can be carefully developed is uniquely available to closed Brayton cycle systems. Unlike air breathing systems, it is possible to increase the pressure in closed Brayton cycles so that the same volumetric gas flow produces greater amounts of heat transfer and improved power output. Designers should be cautioned to start slowly in this area, there are safety and simplicity benefits associated with using system pressures that are the same as those used in combustion gas turbines.
Though all of this may seem logical and almost obvious when laid out in this manner, there are some valid reasons why this path has not yet been taken. Diving into those reasons is beyond the scope of this document; suffice it to say that most of the barriers have been overcome except the one at the starting line. There are impressive returns available to those that recognize that it’s time to open the gate and let the contestants begin their race.
Disclosure: Rod Adams founded the now defunct Adams Atomic Engines, Inc. His company developed nuclear gas turbines from 1993-2010.
Some other considerations:
There are limited sites with access to bodies of water to serve as heat sinks as well as water supplies for cooling towers. This puts a premium on thermodynamic efficiency.
There will be periods of time where NG will be inexpensive enough that nuclear will be temporarily uncompetitive. Yet nuclear must maintain a highly competent but expensive staff regardless of whether the plant is producing any power. The expense of maintaining a large staff for an uncertain period of time was a significant factor in closing San Onofre.
Plant operation should be automated to the maximum practical extent. This includes reactor operators. As someone who’s career in nuclear power was heavily involved with simulators it pains me to say that if a proposed plant design retains the model of overwhelming reliance humans being repeatedly trained in simulators for every casualty, your design needs to be reconsidered.
The Burger King approach of “Have it your way” and allowing the utilities of wide ranging competencies to modify designs or request changes has to stop.
The day to day routine maintenance function are best handled by on site staff. Beyond this, the remainder would best be provided by a service contract with the vendor. Even the on site people could be vendor employees. This distributes training and personnel costs over a wider base and makes smaller reactors feasible for smaller entities such as municipal utilities or manufacturing interests.
At least Kairos power wants to “co-fire” the natural gas combustion turbine with a radiator like was used for the MSRE. I love the idea of Brayton cycle using nuclear heat. Bearing lubrication is a major hurdle for “direct cycle” where reactor coolant passes through the core – the lube oil will soot-up the core and cement it together. High temperature magnetic bearings for a 10-ton rotor don’t exist outside the pages of General Atomics reports. The MAIN engineering problem is a materials problem: what material is going to allow 1000C+ average and 1200C+ hot spot surface temperature on your fuel element and not degrade/erode over the fuel’s years of residence time…. TRISO? Maybe, but TRISO seems like it will remain expensive! Sintered ceramic pellets are CHEAP; sift, press & heat. TRISO involves physical vapor deposition; they literally grow the graphite coating in a methane atmosphere at coal gasification temperatures.
Open and closed cycle gas brayton are two different machines, and costs. Natural gas turbines are open cycle. Any direct cycle nuclear gas turbine will be closed cycle, with a much lower pressure ratio, and huge recooperator heat exchangers added, and the added complexity is harder to balance/operate.
What killed ML-1 was not the reactor, but immaturity of the closed cycle gas turbine. While I think a closed cycle gas turbine is perfectly viable, it is not just a simple switch to the gas turbine system.
And has turbines, and TRISO fuel is expensive. Stick with the simpler fuel compacts.
You could reduce operating cost/MWe by building 8-12, 1 GWe nuclear plants at o e site, like Canada and China do along the coast of the ocean or large capacity lakes, all the same, shared services, one permanent refueling team, c ok moon parts Lower per plant inventories.
FHR, MIT wanted to do gas confirming, but do we know if Kairos kept that part? I heard there were some other changes, when they are left the university IRP DIE funded team.
Ed
You’re confusing the cycle mods needed or suggested for closed cycle helium turbines with those needed to simply close a Brayton cycle.
The only real difference between closed and open cycles is that the “heat sink” part of the cycle is a large heat exchanger instead of the atmosphere.
Helium adds several complexities, including special turbines, special compressors and real temptation to add additional heat exchangers like recuperators and intercoolers.
Adams Engines uses N2 because its thermodynamic properties are essentially the same as air without the corrosion potential and activation issues of 20% O2.
There is a small effect on reactivity and a minor activation issue because N14 has a moderate neutron cross section for an n-p reaction that results in C14.
Though C14 has a long half-life, it is a commercially valuable isotope that produces a pure, low energy beta particle when it decays.
Before assuming lubrication is an issue, it might be worth doing some additional research and testing.
As you’ve noted, GA papers are full of assumptions about magnetic bearings, but there are many reasons why I take GA papers with a large, probably unhealthy dose of salt.
I’ve a different judgement about the cost trajectory for manufactured, coated particle, actinide fuels. The materials used are cheap and abundant. The vapor deposition process is ripe for scale and experience improvements.
I’m pretty sure X-Energy agrees.
GE claims 44% for the LMS100 in simple-cycle operation, but that is certainly on a lower heating value basis. On HHV it’s almost exactly 40%, though.
Perhaps they would be best served by studying the use of supercritical CO2 as a coolant and working fluid, because the machinery required to produce the same amount of power as an air-cycle gas turbine is positively minuscule by comparison (let alone a steam turbine). At the critical point the density of CO2 is 0.4682, and that’s about what it is at the COLD end of the system. Given the fluid and power densities involved, the major problem appears to be making the machinery strong enough.
NetPower is developing an Allam cycle plant which uses (mostly) sCO2 as its working fluid. There may be a route forward on this for nuclear heat very soon.
Actually, I’d advise the opposite. For a nitrogen turbine, the major thermodynamic factors are the base temperature and ratio of specific heats. Notice that pressure is not one of them. If you multiply the input gas density by 3 at the same temperature the only thing that’s going to change is the shaft torque (power); all the stage temperatures should stay about the same. This happens in reverse in aircraft; the shaft speeds and pressure ratios stay about the same, but the air density (and mass flow) drop radically with increasing altitude.
If you need to change output power, running the system pressure up and down is an excellent way to do it. The gas turbine itself won’t care much.
@E-P
Can you point me to the suppliers of supercritical CO2 machinery? I’d like to get some reliable quotes for cost estimating purposes. I’d also like to review operating experience, service support options, training programs for operators and maintainers, and warranty options.
Before using system pressure changes as your method of power output control, I hope to take the time to move off of paper and test the response of real machinery to the variations in torque, blade forces, and other material stresses. I’m confident you’ll find that there is some margin available to use moderate pressure variation, but suspect that doubling or tripling pressure will either require substantial machinery alterations or will result in reliability challenges.
Ask NetPower. They’re either making it or getting it from someone.
Once they’ve got a few units in service that will be available. It should only be a few years, and I know you’ve been waiting since the 80’s.
It’s a little early to expect that yet, but given the glut of natural gas in NA and the demand for CO2 for EOR it can’t be too far off.
The irony is that the fossil fuel industry will gift a fossil-killer power cycle to nuclear.
You already have this in aircraft gas turbines, albeit decreasing from sea level as altitude increases. All that’s necessary is to calculate the aerodynamic vs. centrifugal stresses and look to see when greater input gas density makes the former a significant factor to net loads. Given typical turbine speeds I’ll bet it will be multiples of 1 bar.
Actually, I’ve only been interested in nuclear gas turbines since the fall of 1991. Can’t quite date my interest back into the 1980s.
Variation in atmospheric pressure for aircraft engines goes in the lower torque & stress direction. Pressurizing closed cycle gas turbines to produce higher power output from smaller machines goes in the opposite direction.
There’s plenty of room for improved tech along the path I suggest, but the best way to produce the sustainable revenues that can provide revenues to pay for the R&D needed is to build what we can build today with the factories that already exist.
Toshiba is the supplier of the net power supercritical CO2 turbine. E.g. https://spectrum.ieee.org/energy/fossil-fuels/this-power-plant-runs-on-co2
Not the topic but now California is presumably committed to 100% clean energy. That ought to mean for transportation, space heating and electrical power. Ok, so everything becomes electric. A reasonable estimate is that California will need to somewhat more than triple electricity generation, assuming this is just moonbeams.
So maybe Californians will swallow hard and accept some new nuclear power plants to meet this ambitious goal.
Maybe New York is going to do the same?
I’ll be so bold as to suggest a three stage design with a molten salt thermal store in the middle. The reactor working fluid stays in the reactor passing heat through an integral heat exchanger. That should make the NRC happy, well, happier anyway. The thermal store feeds enough heat through an exchanger for the load following generator, possibly a CCGT based on what I read in this article.
But please feel free to tell me that is just more moonbeams; it has been that sort of week already.
GA is He, which has less mass, and less lift capacity, compared to N2. As Rod, says, N2 is sir, whose bearings DO work, as that is the most common form of power being installed today.
He point being, N2 turbines have reliability and cost today, scCO2 is still far, far from that. You need high reliability to put it on a nuclear plant due to the high capital cost.
To follow up on my earlier comment on need of s recooperator, the alternative to a recooperator is a steam rankine bottoming cycle to recover that bottom section of the T-S curve. That is what nat gas turbines do, combined cycle, and what FHR did even though they were lower temperature, bottoming cycle. FHR was 650C air working temperature, and not very economic as baseload plant with such a low temperature, the gas portion, as baseload, is hard to justify for such a low dT on the gas system, even with a combined cycle, so they had to add gas confirming to add economics.
Indeed, Elysium is considering either an N2 gas turbine at 700C initially, fuel at salt 750C. dT 700-550 = 150C for an open air cycle. But, the goal is to hit 950C power/process heat cycle, dT=350C, 1000C fuel salt. N2 has certain reactor advantages, and obvious power system advantages.
I have future hope’s for SCCO2, but it is clearly not there yet on reliability and cost knowledge yet. ScCO2 is very complicated at the near liquid end.
GA is He, which has less mass, and less lift capacity, compared to N2. As Rod, says, N2 is sir, whose bearings DO work, as that is the most common form of power being installed today.
“It is unfortunate, but many people trained as nuclear engineers have only a dim understanding of the massive structures, systems and components required outside of the highly refined reactor cores that are their main area of responsibility.”
Just look at ThorConIsle and compare fission island and steam supply to power conversion.
http://thorconpower.com/wp-content/uploads/2018/03/20180323_91_Power_conversion_01.jpg
“The other alternative is to use helium cooling for the reactor, but to add a gas to gas heat exchanger to move the heat into air or nitrogen so that conventional turbo machinery designed for combustion turbines can be used.”
Isn’t that the design of the HTR-10 pebble bed reactor at Tshingua University? And the commercial plant on the coast?
Not exactly. HTR-10 and HTR-PM have helium to water/steam heat exchangers that are similar in design and function to steam generators in PWRs.
The big deal with helium (and all noble gases) is that the ratio of specific heats (γ) is much higher than N2/air: 5/3 vs. 7/5.
The istentropic gas equation is Pv^γ = C. Given that Pv = RT still holds, this yields:
RT v^(γ-1) = C
T = C/(R v^(γ-1))
T goes up much more quickly when γ-1 is 2/3 than when it’s 2/5. This means you need intercoolers between compressor stages to get a high pressure ratio with noble gases.
The beauty of sCO2 is that γ gets close to unity at the critical point, and there is very little temperature increase in compression. This radically decreases the energy input in the compressor and thus the back-work.
I expect the Allam cycle to take off due to oil-field demands. Restrictions on flaring will drive demand for something which can turn unshippable gas into exportable electricity, and the CO2 will find use immediately as a fracking fluid and also a miscible solvent for extracting oil that water cannot drive out of formations (see “fractional flow”). The upshot is that there will be a LOT of Allam cycle machines in operation fairly quickly.
With a large installed base, bugs in the system will be worked out at someone else’s expense. All someone has to do is buy one (or a few) minus the oxygen plant and water condenser and put a nuclear heat source.
I don’t think reliability is all that big of a deal. The first-cut units are small, only 50 MW(e). A reactor of substantial size would use several of them. One could break down and the plant would still operate; you’d just isolate the failed machine with valves and fix it at leisure.
As s Rod said HTR PM 200 produces 565C Ultra Super Critica (USC) steam. 3 of them ganged together will replace the odern coal boiler to clean the air in China. Th hey DO plan to backfit them. But, on as go forward basis, I can’t see MSRs doing new USC plants. USC power systems are ultra super costly too, and are only justified in coal by fuel savings of higher efficiency, whereas nuclear, especially MSR has minimal effect l fuel costs, so can not s as very much to justify the cost of USC steam power plants. Hence looking at superheated steam or gas turbine with steam bottoming cycle.
Well – If you are going to dream about what to do with the gaseous heat from a high temperature reactor. Think outside the box just a little. Forget the turbine. Solve a few bugs in the works, use conventional combined cycle and get near 60% efficiency. Find some bauxite and sell aluminum to the world.
https://en.wikipedia.org/wiki/Magnetohydrodynamic_generator
Before you say anything, remember, “Man will never fly.”
I’m confused by your comment. You said “forget the turbine” and then immediately recommended use of a conventional combined cycle.
Turbines are part of both the gas and the steam cycles that are merged together to make combined cycles.
The Adams Engine technology development road map certainly includes combined cycle plants in future iterations, but the FIRST one should be as simple as possible to allow iterative problem solving.
If ultra super critical steam plants were super expensive, how was China able to build them at a rate that approached 1/week for so long?
Sure, there are some complexities and some material selections that are not the cheapest available, but once organizations fully learn how to build them, they are reproducible for competitive costs.
I forget some time when I am communicating with technical types that I have to be very exact. Forget the first turbine.and use MHD. The second turbine (steam) will still be needed until we think of a better way to make use of the remainder of the waste heat. The MHD that replaces the first turbine has no moving parts. Per Wikipedia the combination of the MHD and conventional cycle can give (theoretically) up to 60 percent efficiency.
Parts left out cost nothing and never need repair – paraphrased Charles F. Kettering quote.
Maybe by the time the natural gas gets scarce we’ll have developed quirk free MHD.
Eino, as I recall the coal-fired MHD systems still had issues with erosion of the electrodes under the conditions of extreme temperature and chemical characteristics of the gas and ash. They never got to the point of being economic.
Today we’re at 62+% efficiency with natural gas CCGT using (temporarily) cheaper fuel, and the Allam cycle plants are promising ~50% with zero emissions. I’m not sure where MHD fits anymore.
California has either a law or state Constitutional amendment prohibiting any new nuclear power facility regardless of design until a permanent nuclear waste disposal option is available.
My guess is that once the last nuclear power station is cold, dark and beyond resuscitation, a nuclear waste disposal option will suddenly become acceptable.
Building a nuclear reactor in California that IS the nuclear waste repository solution, i.e., consumes the LWR waste like ElysiumIndustry.com, would therefore meet California requirements and be allowed to be built in California, right.
MHD doesn’t make Rankine/Brayton obsolete, it would instead top them for another layer of “combined cycle”.
Not with a governor whose family wealth comes from natural gas interests.
I am not following. Reactors might make 1000C, but CCGT goes up to 1300-1400C already. So, how do you see MHD as a gas turbine topping cycle?
MHD goes up as hot as you can get. It would fit well with oxy-fuel combustion to get the highest possible temperature and thus best ionization.
1. Feed compressor output plus fuel to MHD system (probably require separate compressors for oxygen and diluent streams). Tap off maybe 30%.
2. Dilute MHD exhaust stream to maximum turbine inlet temperature and feed through gas turbine.
3. GT exhaust to HRSG.
If you can get 30% off in the MHD stage your theoretical efficiency goes from 62% to maybe 72-74%.
I personally am skeptical about the usefulness of MHD in this area. SOFC seems to have much better prospects as a GT topping cycle. If you can skim off 60% of the energy using a SOFC with an 800°C exhaust temperature, you should be able to just about idle the GT with zero or minimal co-firing of additional fuel. You can then co-fire to run the TiT up to the rated maximum, which is 1380°C for the LMS100.
Guesstimating 500°C compressor outlet temp for the LMS100, 800°C FCoT suggests an equivalent fuel burn to a straight 1250°C burner outlet temp (750°C gain). You then have another 580°C of headroom before reaching TiT limits. If the fluidic/mechanical efficiency is unchanged (it will take a hit) the efficiency figures look like this:
750/1330 = 56.4% of fuel used in SOFC @ 60% efficiency = 33.8% net output from SOFC
22.6% of total fuel heat exhausted by SOFC.
43.6% of fuel after-fired into turbine, for total of 66.2% of total fuel energy input to turbine.
44% turbine efficiency = 29.1% of fuel energy output as turbine work.
Net efficiency about 63% before whatever you can grab using a HRSG and ST. Figure about 74% overall in SOFC/CCGT operation. If you can run higher temps in your SOFC you can do better, but this leads to materials problems and the push has been to get temperatures down to increase lifespan and get rid of exotic, expensive alloys and such.
I was just speaking to the fact that if MHD became a thing with any future heat source for power generation, it would not replace Rankine or Brayton; instead it would be upstream. I wasn’t thinking of any particular application for MHD.
So a fossil fuel system. This is about nuclear heated systems.
@ David B. Benson:
Okay, have it your way: it’s all just moonbeams.
I still think it wise to consider having a secondary loop between the reactor as heat supply and the generator as heat sink.
Then one can further consider developing the secondary loop into a thermal store.
Fine. But realize that heat exchangers and separate loops add cost and potential failure points.
I’ll keep advocating for safe enough, far cheaper systems that simply need the right fuel.
David, that idea is attractive, but it comes with costs:
1. Delta-T across the new heat exchangers cuts thermal efficiency, decreasing revenue.
2. Another pump or two to fail, more pipes to break, etc.
3. Extra capital cost.
I keep leaning toward the idea of thermal and electric dump loads. You’d have some lower-priority, interruptible load which takes heat, electricity or both. You use it to consume excess system output and turn it into other revenue streams. One obvious scheme is applying Frank Shu’s torrefaction process to municipal solid waste. Converting MSW into clean pyrolysis gas and stable char would slash landfill costs several ways, not the least of which would be making the product instantly stable and eliminating any requirement for capturing the methane product of anaerobic breakdown after closure.
I am impressed by what the Moltex Energy website states about their stable salt fast neutron reactor design. I note that that design has a secondary loop.
David,
Moltex has fission products in both the chloride fuel salt and fluoride cooling salt, then a 3rd salt to isolate water from the fast core. That basically adds a loop relative to most MSRs.
Engineer-Poet, I would prefer not to call those “dump loads” for fear of offending the owners. 🙂
However, I have yet to read of such being constructed. Decades ago in the USA about 43 pumped hydropower sstations were constructed to precisely consume the excess overnight power from the nuclear power plants so that the latter could run at constant setting. But in the current state of the grid none of the 4 proposed pumped hydro schemes here in the Pacific Northwest can receive financing.
It’s the preferred term of art; I doubt it offends anyone. Processing material otherwise destined for landfill and removing ~70% of it from the MSW stream would make the process an anti-dump load, to coin a phrase.
Because they haven’t. One of my favorite suggestions for Duane Arnold and Ft. Calhoun is to centralize fuel-ethanol processing at those sites and use nuclear steam to mash, distill and dehydrate the product with carbon-free heat. Oddly, nobody but me seems to think this is a good idea. With molten-salt reactors or HTGRs, torrefaction/pyrolysis with excess primary heat becomes possible. The pyrolysis gas appears to be well-suited for partial conversion to methanol without further adjustment, with pumping of CH4 into the natural gas pipeline system and combustion of excess H2 in gas turbines for peaking. Yet, somehow, this rather obvious waste-diversion and polygeneration scheme has no proponent. It is a mystery.
IIUC, the PNW suffers (if that’s the word) from an excess of hydro and wind during the spring melt period when demand is close to minimum. The PNW is also an area of large production of forestry byproducts. Converting chipped logging slash into solids plus H2/CH4/CO/CO2 and thence into pipeline methane, methanol and ammonia for fertilizer with this excess energy might enable more of this energy to be put to productive use.
World Nuclear News [wnn at world-nuclear dot org]
“Transatomic Power, which had been developing a molten salt reactor with the ability to consume nuclear waste, has ceased operations. The Cambridge, Massachusetts-based company said it intends to open-source its intellectual property, making it available for any interested researchers, and is in discussions with the US Department of Energy Gateway for Accelerated Innovation in Nuclear initiative, which has previously made grants to the project, to ensure the work remains publicly accessible.”
Engineer-Poet — Thank you for the reply. Your assessment of the Pacific Northwest in the spring is accurate.
The dozen large forestry operations in the state of Washington have centralized wastes which are burned in the fall and winter, providing a steady aggrigate of about 600 MW at the time of year with low water flows and higher demand; every MW is valued. Despite the decent wholesale prices, the forestry operations lose money running their waste burners to produce some electrical power. But they lose less than other means of disposal.
My PhD topic is very similar to the concept described Although the application is ship propulsion. An interesting addition to the concept is waste heat recovery and salt storage. The thermal salt storage tanks make a useful radiation shield for the reactor and decouple peak power output from peak reactor power.
Also using a direct cycle gas reactor for powering ships has president in programmes in the US (search EBOR in google) and Germany. Apparently Rickover despite all his other attributes and successes in Nuclear power was not a fan and went out of his way to try and stop any projects in this direction. My guess is he saw any work in the early years which wasn’t developing PWR’s as diverting resource which was dearly needed at the time.
With regards to marrying a turbine to a nuclear reactor, CO2 turbines in a direct cycle are not a particularly good fit. The reason being that CO2 tends to break down to Carbon Monoxide freeing oxygen when exposed to radiation inside the reactor core, a problem which gets worse as temperature and pressures rise. This creates oxidation issues in the core from both from the CO and free O. Higher the temperature and pressure the worse the problem. The AGR’s in the UK which use CO2 coolant manage this issue by a very complicated flow path (creating a very large expensive and low power density reactor) to keep the carbon moderator at temperatures around 300 degrees and only allowing the hottest CO2 to pass through the fuel assemblies which are conventional fuel pins with SS cladding to protect the cladding from corrosion. CO2 as a HTGR coolant is incompatible with a carbon moderator and fuel (BeO might be a possibility but its cost is prohibitive) and even when this is removed at high temperatures the corrosion problems are not insignificant.
The other issue with CO2 turbines is their operating outlet pressure from the compressor is very high and would require a RPV in the direct cycle variant to withstand pressures higher than current PWR RPV. When coupled with a lower power density of a HTGR compared to a PWR and therefore larger diameter RPV the pressure vessel wall thickness would become very thick potentially making the RPV prohibitively expensive and very difficult to manufacture.
The upside of CO2 turbines is they can offer similar efficiencies at around 550 C as you can get with a steam cycle but far more compact and simple. The potential is there to replace steam cycles on HTGRs that use intermediate heat exchangers and use CO2 turbines as a bottoming cycle on a HTGR with a direct coupled gas turbine. Either of the above options are available to any plant designer and would be dictated based on the economic competitiveness of the available technology and don’t greatly Impact the overall nuclear side of a HTGR design.
I do concur in general with keeping the number of heat exchanges down to a minimum although the cost is highly dependent on pressure differential and overall system pressure. Some of the reactor technologies that use atmospheric liquid coolant can afford more heat exchanges due to the high volumetric heat capacity fluid and small pressure differences keeping heat exchanger materials thin. this keeps the cost of the extra heat transfer step small enough that the benefits (TES for example) are worth having. This is especially the case for Moltex’s Reactor.
For a Gas reactor heat exchanges are quite expensive as the coolants are pressurised driving up heat exchanger shell thicknesses, low volumetric heat transfer and often large pressure differentials between each working fluid.
Fascinating, Jeremy.
A while back I did some research on the NuScale reactor as a prospect for container ships. Curious fact: the upgraded 60 MW NuScale unit is now sufficient to power an Emma Maersk-scale vessel with just 2 of them, and the 700 ton module weight is less than 1/3 of the 2300 tons of the RT-flex96C which currently powers them. That, combined with the elimination of most of the fuel oil that would otherwise power the ship, should give a substantial increase in cargo tonnage while allowing the ship to cruise at 100% power while in open seas.
@Jeremy
How do you feel about N2 as a working fluid?
Very positive, I have just started my PhD on a concept you might approve of 🙂
The first stage in establishing N2 as a coolant and working fluid is to demonstrate the effect on core reactivity is sufficiently small that the changes in reactivity from pressurised to unpressurised are small enough to be counteracted by a small temperature rise coupled with a strong negative temperature coefficient (first part of my research). Once demonstrated then the possibility of utilising Nitrogen as a coolant and working fluid in a gas turbine can be explored.
Nitrogen properties are such that it doesn’t readily react with other materials (although can cause nitriding of steels via diffusion this is limited to only the surface of the steel and therefore would only create a hard surface not affecting the bulk properties) therefore it’s not expected to present a material challenge at high temperatures, although it would need demonstrating in a strong radiation field (nitrogen is already used in autoclaves at high temperatures because it is generally unreactive).
HTGR and coolant choices have unfortunately been driven by early rational decisions. in the 1950’s when most of these concepts were being considered gas turbines were still in their infancy, nobody considered a helium turbine being anymore of a challenge than a nitrogen turbine and therefore considering the superior neutronic properties of helium and on paper superior thermodynamic cycle properties helium made perfect sense. Unfortunately the view was then created that a HTGR is cooled with helium and very little further thought was considered to coolant options even when the practicalities of helium turbomachinery and the availability of conventional gas turbines became apparent.
I like it better because it can reform in only one way with a mono-element. Sure there is some nitidimg, but not as bad as having nitrogen, oxygen, methane, and water as in a normal open air gas turbine. Much simpler by comparison.
New claddings like SiC pretty much eliminate issues with nitriding and oxidation under sane conditions. This lets you pick your coolant for its other properties.
Question for anyone with expertise in the field:
What’s the net effect of CO2 on reactivity? Does the (n,p) cross-section of oxygen give CO2 more negative reactivity coefficient than the moderating effect of the carbon?
Attn: Robert Hargraves and Ed Pheil
In light of TransAtomic’s [not so] surprising announcement that it is ceasing ‘operations’, no doubt partially due to their claims not holding up to peer review, I pose the following question to Ed Pheil and Robert Hargraves, who are MSR proponents (Elysium and ThorCon respectively):
Knowing that the Elysium proposal is a fast reactor…
Why have I not seen discussion of moderating MSRs with double-walled water tubes instead of a graphite (or in TransAtomic’s case – hydride) core structure? Presumably, a design could employ circulation of water in those tubes at low pressure (atmospheric) so long as a gas gap or evacuated annulus insulated the moderating channels from convection (neutron and photon heating alone). This would be similar to the CANDU geometry, but inverted so the calandria is a flowing fueled region and the pressure tubes are unpressured moderating channels. You could expect +97% of the fission energy to be deposited in the salt (inferred from knowledge of LWR fuel).
Using liquid water also makes possible several trustworthy reactivity control mechanisms. For instance, if you control the inlet subcooling of the moderating channels you would have a strong reactivity ‘knob’ in varying their void fraction (like BWR). If you were to keep the water in the tubes solid, then you could dissolve boron in the moderator (like BWR). These different tacks would each you to load and suppress excess reactivity, change power level, and provide shutdown margin. Start-up in a boiling channel core could begin with dry moderator channels which are gradually flooded in order to traverse source/intermediate/low power range. Start-up in a subcooled solid water channel core would be a simple boron dilution. Major ‘selling points’ for MSR are high temperature (i.e. > 800C) and low pressure (near atmospheric) – so I couldn’t suggest something that would defeat those selling points.
Nothing moderates like hydrogen and nothing packs hydrogen like water. On average a neutron loses half of its kinetic energy per collision with hydrogen. It is a flat probability curve; I’m sure that you are familiar with it; the probability for an incident neutron to lose 90% energy in a collision is the same as the probability to lose 10% of its energy. Diffusion length is on the order of 3 cm in water vs. half a meter in carbon. Moderating with water will absolutely minimize (the limit) the diffusion length in MSR and allow a smaller system to be ‘thermal’ than possible with graphite. The outer tube would be something like thin-walled Hastalloy and the inner tube would be thin-walled zirconium alloy. The pressure across the tubes would be p*g*h; a couple of atmospheres at the most; the tubes could be thin walled and even triple walled with leak detection to reduce water-salt event probability.
I would like to state that as a career nuclear engineer I am an opponent of MSR technology since MSRs do not contain the fission products in cladding and are therefore difficult to maintain and operate from a radiological safety perspective. I have secondary and tertiary arguments against them as well; in my opinion, solid clad fuels are the past, the present and the future.
Hey, up towards the top of the thread I addressed a question to you and Ed Phiel regarding MSR moderation.