Abstract

In this project we have identified three new missions for nuclear plants that will operate in the Japanese energy market in the 2030s and beyond. They are (1) flexible electricity generation at existing power plant sites, to replace retiring coal/natural gas capacity, and to complement variable generation from solar and wind; (2) flexible co-generation of electricity and heat at industrial sites, to support the production of valuable products, including hydrogen for transportation; and (3) generation of power and heat for niche markets such as remote communities/islands, military bases, mining sites, disaster relief, district heating, data centers, and freight ship propulsion. After assessing a broad set of reactor technologies, we selected three of them to satisfy the above missions, respectively: (1) a small modular boiling-water reactor for flexible electricity generation, (2) a high-temperature gas-cooled reactor for co-generation of electricity and heat at industry sites, and (3) a heat pipe micro-reactor for niche markets. We deem that such technologies can be deployed commercially in Japan by 2030, and have a high likelihood of meeting the important requirements for economics (i.e., cost competitiveness with liquified natural gas, low operation and maintenance cost), operational capabilities (i.e., load following, grid resilience), safety and security (i.e., insensitivity to external events, emergency planning zone limited to the site boundary). We developed notional layouts for three representative sites in Japan (i.e., TEPCO’s Higashidori power plant, Mitsubishi Chemical Co.’s Kamisu Ibaraki plant, TEPCO’s Hachijō-jima power plant) at which commercial demonstration of these reactor technologies could take place. The site layouts were informed by consideration of optimal construction and operations. Particular emphasis was placed on evaluating the merits of embedding the nuclear island below ground, to reduce seismic loads, reduce reactor building cost, and enhance physical security. Lastly, we explored several innovations in automation and digitalization of plant operation and maintenance that could make new nuclear plants even more cost effective and valuable to Japan.

Abstract

The objective of our project on design of risk-informed autonomous operation is to develop and demonstrate artificial reasoning systems for operator decision support, aided by autonomous control technology, for advanced nuclear reactors. One of its first tasks is the formulation of symptom-based conditional failure probabilities for selected structures, systems, and components (SSCs). This task falls under diagnostic modeling of the problem domain, since its primary goal is to aid plant personnel in deducing the probabilistic performance status of the monitored SSCs and in detecting impending faults/failure. As a bidirectional inference problem, the task of conditional failure probability estimation shall be logically tackled by the Bayesian network (BN) approach, which offers the capability of reasoning under uncertainty and graphical representation emulating the physical behavior of the target SSC. This report provides a comprehensive overview and evaluation of the BN technique and the software tools for handling implementation of BN models, along with the associated knowledge representation and reasoning paradigm that are adopted for use in this milestone. Both actual operational data and subjective expert knowledge can be readily incorporated into the knowledge base of a BN model. The challenges with data availability and collection are highlighted, and the general approach to target SSC identification is presented. Our focus is upon failure-prone and risk-important balance of plant assets—including rotating machinery and high-duty-cycle equipment—especially cases having strong operator involvement. While system analysis and risk assessment shall be further utilized to guide SSC selection when collaborating with utility partners, an example case study is conducted in this report on the failure of a general motor-driven centrifugal pump to demonstrate the usefulness and technical feasibility of the proposed artificial reasoning system using an expert system shell.

Abstract

A preliminary evaluation of the economic potential of micro-reactors for deployment in the heat and electricity markets in the state of Washington (WA) was performed.

To be economically attractive in the WA power market, the levelized cost of electricity (LCOE) for a micro-reactor ought to be significantly less than $100/MWhe. Current micro-reactor designs, entertained primarily for niche applications, do not meet those cost targets. The micro-reactor cost estimate analysis suggests that fuel cost is a prime cost driver. The micro-reactor cost estimate analysis suggests that micro-reactor designs with high-assay low-enriched uranium (HALEU) and/or expensive-to-fabricate fuel are not promising. Micro-reactor design efforts for attractive economics should focus on a core design with 5% low enriched uranium (LEU) fuel (preferably cheap uranium oxide) and relatively high specific power (>3 kW/kgHM). In particular, the high specific power entails either enhanced heat pipe technology or a move away from heat pipes altogether.

To be cost competitive in the heat markets in WA, the levelized cost of heat (LCOH) from a micro-reactor should be in the $30-50/MWht range, which appears to be within reach. micro-reactors could be co-located with major factories or industrial districts to provide process heat. We have reviewed a number of industrial sites in WA that could use heat from one or more micro-reactors. The sites were chosen based on the amount of (non-biogenic) CO2 emissions as reported in the WA Department of Ecology database. Only sites emitting 10,000 tons of CO2 per year (equivalent to an average of 6.3 MWt of heat) were considered. Only sites requiring heat at 600°C or less were considered. Many WA sites meet these criteria for heat supply by micro-reactors. The sites range from food processing plants to university campuses and airports, from district heating plants to gypsum product facilities, from paperboard mills to military bases, from chemicals production facilities to aircraft manufacturing factories. The total installed thermal capacity of these sites would be about 1,400 MWt, displacing some 2.2. million tons of CO2 per year. This installed capacity would require deployment of about 140 micro-reactors, which is a significant business opportunity. It is highly recommended that such opportunity be more thoroughly investigated by PNNL.

Assuming electricity and heat are available from a micro-reactor at $100/MWhe and $40/MWht, respective the cost of hydrogen produced by HTE coupled to a micro-reactor would be about $4.9/kg-H2, which is significantly higher than low-carbon alternatives such as steam methane reforming with CCS or wind. Therefore, micro-reactor-generated hydrogen does not appear to be particularly attractive, unless avoidance of the hydrogen storage and transportation infrastructure afforded by the micro-reactors more than compensates for its higher production cost.

Summary

We evaluated the system cost of providing electricity and heat to serve the load profiles of two types of Alaskan communities, and calculated the cost efficiency of including a nuclear microreactor in the generation portfolio. We employed a capacity expansion and dispatch model augmented to co-optimize heat and electricity generation. Since microreactor designs are still in development and the eventual capital and O&M costs are speculative, our strategy was to explore the outcomes across a wide range of capital costs, and find the range in which a microreactor is included in the least-cost portfolio and the range in which it is not. We call the boundary between the two the capital cost ceiling.

We have identified the microreactor capital cost ceiling under a range of assumptions and scenarios. This includes two different load profiles—one reflective of demand across Alaska’s Railbelt communities, and one reflective of demand at a remote Alaskan mine and neighbouring community. We assessed the impact of natural gas fuel availability, whether a community had a district heating network, future reductions in the capital cost of renewables, the price of fossil fuels, and, last-but-not-least, the need to reduce systemwide emissions.

Three factors appear to play a dominant role in setting the capital cost ceiling and answering whether a microreactor is likely to be a cost-efficient addition to the system. One of these is the availability of natural gas. Natural gas is a much cheaper source of energy than diesel fuel, and therefore the microreactor capital cost ceiling is significantly lower in communities where it is available. Most communities in the Alaskan Railbelt have access to natural gas, while few, if any, of the other communities do.

The second factor is the size of the heat load and the accessibility of a district heating network. In our results, the capital cost ceiling was much higher in scenarios where a microreactor’s waste heat was highly utilized. Communities in the Alaskan Railbelt have higher heat loads and select ones have accessible district heating networks, which facilitated the use of microreactor waste heat, and set the capital cost ceiling high. In contrast, a remote community anchored by a mine has a relatively smaller heat load, which would set the capital cost ceiling lower.

The third, and overwhelmingly most important factor, is the goal of emission reductions. Any modest emissions reduction target dramatically raised the capital cost ceiling for a microreactor, reflecting that the microreactor is very cost-efficient among low carbon options when heat and electricity are considered together. This conclusion holds broadly across both load profiles. We focused on CO2 emissions. However, we are aware that certain Railbelt communities face a critical need to reduce particulates and other criteria pollutants. Recognizing this would further boost the competitiveness of a microreactor.