A clear objective of NHES is better to utilize our natural resources, reducing withdrawals from the environment and impact on the environment due to waste stream emissions. One aspect of this environmental stewardship is the reduction of greenhouse gas (GHG) emissions. This is commonly measured in terms of the equivalent amount of CO2 emitted when all GHG are summed and adjusted based on their energy adsorption capacity.

Total water withdrawal for an ecosystem is becoming increasingly important, especially in consideration of the impact of erratic weather patterns and atmospheric temperature excursions that affect the available surface water at a given location. In arid climates where surface waters are practically nonexistent or where ground water withdrawals have already drained subterrain aquifers, water conservation is an essential requirement. Higher-temperature advanced reactors (non-water cooled) operate at higher efficiencies than traditional LWR systems, resulting in less waste heat that must be ejected to the environment. This not only reduces the thermal output to the environment, but it also reduces the water loss in the condenser cooling loop.

Land withdrawals are defined as permanent alteration to land that results from installation of the facility, such as modification of mountain tops to install wind capacity, disposal of coal ash waste that results from coal combustion (typically dumped into landfills or ash ponds near coal-fired power plants), or clearing land based on the required plant footprint and associated exclusion zone. These modifications can impact an ecosystem just as much as waste emissions, including long-term life­cycle impacts on resident species. The adverse effects of ejecting waste heat to the environment are an additional environmental consideration.

Environmental impacts could be due to resource or feedstock extraction or production; impact of emissions, including both gaseous emissions and ejection of high-temperature water; or impact of energy transmission requirements. Electricity production located at some distance from the end user may require the installation of a new long-distance high-voltage power line in some regions, but rail transportation of an energy product (e. g. hydrogen, synthetic fuels) might have fewer regulatory constraints and lower environmental impact.

Environmental stewardship requires that the build-out of modern energy infrastructure consider the long-term outlook for scarce resources, such as water, land, carbon feedstock, etc. Unfortunately, the long-term horizon is often overlooked or underemphasized. Evaluation and design of tightly coupled, small-scale hybrid energy systems focus on selecting system configurations that are environmentally responsible while meeting the demand for a variety of energy commodities.

There are three areas where engineering-based assessments are being conducted. These are (1) evaluating A-SMRs in a load-following hybrid energy system (HES) architecture, (2) collecting fundamental data on sodium to carbon dioxide (CO2) heat

exchangers, and (3) demonstrating the operation of supercritical CO2 (S-CO2) power conversion system (PCS) to match with A-SMRs providing enhanced conversion efficiencies up to 50%.

Initial assessments are being conducted of A-SMR concepts for an SFR, HTGR, and FHR in load-following HES architectures to analyze A-SMR performance characteristics and reactor dynamic operations. The hybrid operation will focus on integration of these A-SMR concepts with wind power. The SFR concept is to be studied in an HES configuration to produce electric power, methanol, and hydrogen. The aforementioned supercritical CO2 PCS is being included as part of some of the HES analyses.

SFR designs will likely have intermediate heat exchangers. To reliably design sodium heat exchangers, fundamental data are needed on the draining of sodium from heat exchanger channels to understand the potential stresses resulting from inadvertent freezing and remelting. Sodium drain and fill test designs shall provide a means to experimentally verify that the heat exchanger sodium channel configuration and orientation provides for efficient draining and subsequent refill of sodium. Inadvertent freezing and thawing of sodium is known to have caused failure of specific sodium components.

DOE-NE’s A-SMR is leveraging work conducted by Sandia National Laboratory over the past several years to further develop and demonstrate its S-CO2 PCS. This is also a program that has been supported by DOE-NE’s ARC program as well. A 1 MW S-CO2 Brayton cycle test assembly has been developed and is undergoing testing [11]. The split-flow recompression loop test assembly as presented in Figure 14.7 is the focus and provides the basis for conducting R&D under the ART R&D program for extrapolating the performance of the 10 MWe system.

The current scope of work under the ART program is to develop the engineering basis for such a system that will lead to a 10 MWe system design, including achieving the pressure and temperature design points. Performance studies are planned to

High temp
Printed circuit heat

exchanger recuperator 2.2 MW Low temp Printed circuit heat exchanger recuperator 1.6 MW

Printed circuit heat
exchanger
gas precooler

0.5 MW

Electrical immersion

heaters 130 kW each,
ASME 810K/1000F
Ш 2600 psia (18 MPa)

Turbo-alternator-compressor
re-compressor, 122 kWe

Turbo-alternator-compressor main compressor, 124 kWe

Figure 14.7 Sandia S-CO2 Brayton test assembly [11].

examine options for pressure ratios, turbine inlet temperature, compressor inlet temperature, and mass loading.

As the technology develops for the S-CO2 Brayton cycle as an advanced PCS technology, issues have been identified with heat exchangers due to cost for compact printed circuit heat exchangers and possible high-temperature corrosion of diffusion bonded stainless steel under stress. A testing program is also being developed to examine the corrosion of stainless steels under stress at 550 °C.

The fluid system has been designed to ensure the safety goal of the Gen IV reactor system and enhance the economics through a tradeoff study between various proposed design candidates based on proven technologies. The fluid transport system is composed of a heat transport system and safety system.

The heat transport system consists of a primary heat transport system (PHTS), intermediate heat transport system (IHTS), and power conversion system (PCS). The decay heat removal system (DHRS) is employed as one of the safety design features to remove the decay heat of the reactor core after the reactor shutdown when the normal heat transport path is unavailable. The PHTS is a pool type in which all the primary components and primary sodium are within a reactor vessel to prevent primary sodium from leaking outside of the containment. Two PHTS pumps and four intermediate heat exchangers (IHXs) are immersed in the sodium pool inside a reactor vessel. The PHTS pump is a centrifugal type mechanical pump with a capacity of 290.3 m3/min. The IHX is a counter-flow shell and tube types (TEMA type S) with a vertical orientation inside the reactor vessel where PHTS sodium flows through the shell side and IHTS sodium flows through the tube side. The core inlet and outlet temperatures are 365 and 510 °C, respectively. The IHTS is two loops, and two IHXs are connected to one steam generator and one IHTS pump in each loop. An IHTS pump is a centrifugal type with a capacity of 209.8 m3/min and is located in each cold leg.

A steam generator is a helical tube type with a thermal capacity of 776.7 MWt. The IHTS sodium flows downward through the shell side while the water/steam goes up through the tube side. Steam temperature and pressure at a 100% normal operating condition are 471.2 °C and 17.8 MPa, respectively. The cold leg of the IHTS piping is a bottom-up U-shape with sufficient height to prevent sodium-water reaction products from reaching the IHX in case of a steam generator tube failure. Also, the IHTS piping is arranged to enhance the natural circulation capability in IHTS pump trip case.

The PCS employs a superheated steam Rankine cycle. It was designed in such a way to minimize the total heat transfer area of IHX and steam generator and maximize the plant efficiency.

The DHRS is composed of two passive decay heat removal circuits (PDRCs) and two active decay heat removal circuits (ADRCs). It was designed to have sufficient capacity to remove the decay heat in all design base events by incorporating the principles of redundancy and independency. The heat removal capacity of each loop is 9 MWt. The PDRC is a safety-grade passive system which is comprised of two independent loops with a decay heat exchanger (DHX) immersed in a hot pool region and a natural-draft sodium-to-air heat exchanger (AHX) located in the upper region of the reactor building for each loop. It is operated based on the natural circulation by density and the elevation difference between the DHX and AHX. The ADRC is a safety-grade active system, which is comprised of two independent loops with a DHX, a forced-draft sodium-to-air heat exchanger (FDHX), an electromagnetic pump, and an FDHX blower for each loop. The electromagnetic pump and FDHX blower derive the sodium circulation in the loop and the air flow in the shell side of FDHX, respectively. Because the ADRC can also be operated in natural convection mode against a loss of power supply, the heat transferred to the DHRS can be finally dissipated to the atmosphere through AHXs and FDHXs by the natural convection mechanism of sodium and air.

4.3.1 Setting the enrichment of the fissile material

The first stage in the nuclear design of an iPWR (or any reactor, large or small) is to determine the enrichment requirements for the fuel to provide the energy output over the time period requested by the utility. (As for large PWRs, the current design limit, primarily on fuel manufacturing and transportation (both from a criticality control perspective) is 5 wt% U-235.) Once a reactor is at equilibrium conditions (for example, after several cycles/years of operation), the cycle length and operations are more constant, e. g., how many assemblies in a reload of fuel or target burnup. At these conditions, the enrichment is unlikely to change a great deal. However, in the early cycles of operation, and as equilibrium operations are approached, the enrichment will need to vary to reflect these changes. Similarly if the utility changes cycle length, such as going from 12 to 18 months between outages, again the enrichment requirements will change. Even though eventually the enrichments may not need to be changed to achieve the required cycle length, the nuclear design, including the development of the loading pattern (see Section 4.3.3), and assessment of the key safety and performance criteria still have to be completed.

Clearly the designer has to define the enrichment to obtain the required cycle length. But equally important is that the fuel needs to have sufficient enrichment to ensure sufficient reactivity not just for the next cycle, but for its design lifetime, which is typically anywhere between one and four cycles of operation depending on the iPWR, and the fuel design (as described later in this section). For the initial estimate, and prior to completing the detailed nuclear design using reactor analysis
tools (such as CASMO-SIMULATE or PARAGON-ANC), the designer usually relies on either rules of thumb, or an experience base that they can call upon for a specific reactor to provide the initial estimate. Linear reactivity models can also be used to assist in the estimation.

The nuclear designer has to work closely with the utility at this point because they will have analyzed the optimum cycle length of operation for their reactor, from an electricity demand perspective, duration of outage and for planning, e. g., if there are several iPWR units on the same site, there will be a master schedule for maintenance and refueling outages throughout the year. The utility will have forecast the practical and economic optimum for operations, including the potential for early shutdown or stretch out in operations.

Since the enrichment of the fuel is governed by the desired cycle length of operation and the burnup of the discharged fuel, the fraction of the core replenished each cycle has to also be considered. Generally in iPWRs (as in all large PWRs), a fraction of the core (referred to as a ‘batch’) is replaced after each cycle of operation. The remainder of the fuel is then reloaded back into the core, albeit in different locations to their previous location — the locations within the core of the fresh and previously irradiated fuels are known as the ‘core loading pattern’ which is described in Section 4.3.3. However, in at least some iPWR designs, there is a plan to discharge all of the fuel after each cycle. The proportion of the core replaced and the frequency in which is replaced is known as the ‘fuel management’ scheme. Here are some examples to illustrate:

• 4 X 12 month fuel management scheme: lA of the fuel assemblies are replaced months;

• 3 X 18 month fuel management scheme: Vs of the fuel assemblies are replaced months;

• 2 X 24 month fuel management scheme: й of the fuel assemblies are replaced months;

• 1 X 48 month fuel management scheme: all of the fuel assemblies are replaced months.

It should be noted that the cycle length is the time interval between one cycle beginning and the start of the next subsequent cycle. This means that the durations quoted above include the time required for the maintenance and refueling outage. As such they are not the length of time that the core is operating at full power. Therefore, in calculating the actual energy produced in that time, capacity factors have to be taken into account.

The capacity (or load) factor is the percentage of electrical power that a reactor actually produced in a given period compared with the electrical power that could be produced if the unit were operated continuously at full power in the same period. For example, if a reactor’s name-plate capacity was 1 000 MW hours of electrical power, but in a given year it produced 800 MW hours, then the capacity factor would be quoted as 80%.

In the above examples, the first number not only indicates the proportion of the core replaced, but it also refers to the number of cycles of irradiation that the fuel
will be in the core for; 4, 3, 2 and 1 respectively. Therefore, to calculate the discharge burnup of the fuel batch on average, one simply needs to multiply the cycle length (in MWd/MTHM) by the number of cycles.

Therefore, at equilibrium, the discharge burnup of a batch of fuel assemblies is:

BDischarge = N x S x L x C [4.2]

where : N = number of batches,

: S = specific power of the iPWR (MWth/tonne)

: L = length of cycle (in days)

: C = capacity factor (%)

For example, assume an iPWR has a thermal power of 500 MW, 12 MTHM of fuel, a capacity factor of 90% and a cycle length of 15 months (~450 days), for a three batch scheme, the discharge burnup would be:

BDischarge = 3 x (500/12) x 450 x 0.90 [4.3]

= 50 625 MWd/MTHM

It should be noted that this is the batch average burnup, and not all of the fuel assemblies discharged at the end of that cycle of operation will have achieved the same burnup because the fuel in that batch is positioned in different locations in the core and will be irradiated at slightly different powers, may have had control rods inserted into them during operation, etc. Similarly, because of their location in the core, in the assembly, next to guide thimbles, BPs, etc., each fuel rod will have a different burnup, as will the pellets in the fuel rods. As explained above, the assemblies, rods, and pellets will have limits that the designer has to check are not violated.

For example, for a quoted ‘batch average’ burnup of 45 GW d/MTHM, a typical peak assembly burnup within that batch would be 50 GW d/MTHM, a peak pin burnup would be typically 55 GW d/MTHM, and a peak pellet, of the order of 60 GW d/ MTHM. This illustrates very clearly why it is important for the designer to minimize the variation of the burnup of pins within the assembly, and of assemblies within the batch, because large variations will lead to violations of the limits/warrantees potentially, and therefore limit the utilization of the entire batch unnecessarily.

An increase in the number of batches results in an increase in discharged burnup achievable, while requiring lower enrichments, and therefore results in a lower fuel cost overall. This is most easily represented by the equation:

2n

^Discharge = "—— B1 [4.4]

(n + 1)

where n = number of batches and B1 = burnup of single batch core (which is equivalent to the cycle length).

For example, a two-batch core design will have an equilibrium discharge burnup ~33% greater than a single batch, and a three-batch core design will be 50% greater than the single batch. The theoretical limit in the improvement is 100% over the single batch. However, increasing the number of batches decreases the cycle length, and results in more frequent refueling, which decreases the capacity factor of the iPWR. Even with a small number of assemblies in the core that need refueling and/ or reloading, this can have a notable impact on the economics, and so generally a compromise of two to four batches is used.

NSSS control systems are key to the daily operation of the plant. They are designed to be automatic wherever possible, with manual override options for operator control if needed. In a traditional PWR there are over 100 NSSS control loops that provide everything from the monitoring of temperatures and automatic alarms to the full automatic control of the feedwater and main steam systems. In the iPWR world, the number of control loops will be much less than the 100 plus loops mentioned above. This is partly due to the small nature of the design: fewer tanks, less piping, fewer valves, less peripheral equipment. And it is partly due to the incorporation of gravity-fed or passive cooling systems. New iPWR designs have made use of the 50 plus years of existing operating experience and have improved and simplified the steam system architecture where possible, making for much simpler control systems. The following sections will discuss the unique nature of iPWR NSSS control instrumentation.

iPWR NSSS control systems will most likely use some of the same isolated safety related instrumentation signals as found in current PWRs, but some of the instrumentation will be unique to NSSS control, like feedwater pressure and boron tank measurements, and will not require the same nuclear pedigree as safety system measurements. These measurements may likely be accomplished with the same devices that are used in traditional PWRs. The constraint in the non-safety category instruments is primarily a size constraint. The need for smaller instruments may drive an evolution in the secondary side, non-safety instrumentation.

On the other hand, the fact that NSSS instrumentation does not have the strict class 1E qualification that safety related applications demand, may make transitions to state-of-the-art technological advances a natural evolution. Definition of the non-safety I&C requirements has only just begun in most iPWR designs, so how the instrumentation is going to be developed to meet these requirements is still uncertain.

Some of the biggest challenges during large plant outages are to manage the multitude of resources and maintain a high level of situation awareness to ensure the continued safety of plant personnel and to ensure that equipment is protected. Some nuclear utilities have refined the outage process to a fine art, but all struggle with the need to manage the complex communication processes during outages. Multimedia and wireless communication technologies are already proving to be an indispensable boon to outage teams and this is likely to become a standard feature of outage management in future. In particular, the need for collaboration and information sharing is satisfied by a range of information displays in the outage control centre. Large interactive displays (called ‘smart boards’) and collaborative work support systems allow real­time access to information, schematics, procedures, and all kinds of scheduling and resource information. This is augmented by a variety of handheld information and communication devices like tablets, smartphones, handheld computers, barcode readers and cameras.

Advanced HSIs and communication devices will also help to eliminate or reduce distractions in the control room caused by maintenance personnel traffic, noise, nuisance alarms and non-critical activities, while helping the operators to maintain situation awareness. For the maintenance teams, technologies mentioned above will help to minimize down time, and improve communication and resource management.

R. A. Bari

Brookhaven National Laboratory, Upton, NY, USA

Notice: The material provided in this chapter relies heavily on the work (GenlV International Forum, 2011b) done by the PR&PP Working Group of the Generation IV International Forum. The author of this chapter has been an international co­chairman of that organization over the past decade.

This manuscript has been authored by an employee of Brookhaven Science Associates, LLC, under contract DE-AC02-98CH10886 with the US Department of Energy.

9.1 Introduction

This section defines proliferation resistance (PR) and physical protection PP and describes why and how PR&PP matter for SMRs.

10.5.1 Modularization

The realization of NPP encompasses the phases of site preparation, construction and start-up. Traditionally, the construction phase of a NPP was performed on site, with specialized workers erecting all the civil structures, nuclear island and balance of plant (BoP) systems starting from raw material and main equipment. Every NPP construction was nearly hand-crafted, specific to the site and the plant design. Conversely, the SMR plant layout may be conceived from its design phase in a number of sub-systems or ‘modules’ that may be fabricated in a parallel way and then shipped and assembled on-site. The construction of the SMR plant systems on-site is reduced and the fabrication activity tends to be shifted in factory, with the following main benefits:

• controlled work conditions and improved quality standards;

• possibility to apply mini-serial production, fostering the learning accumulation and decreasing the overhead cost of the production lines;

• use of less specialized personnel on-site;

• in principle, reduction of the construction schedule due to the shift from series to parallel activities;

• as a consequence of the previous, lower financial cost escalation during construction.

On account of the smaller size of their components and systems, SMRs can achieve higher degrees of design modularization (Carelli et al., 2007b, 2010). The indivisibility of some subsystems and their large scale in the LR plants compels their construction on-site, while the lower physical size of SMRs allows a greater number of systems to be factory-fabricated and then shipped to the site. Modularization requires more project management effort and transportation complexity. Communication and cooperation between suppliers and contractor has to be accurate, in order to create the schedule and ensure synchrony of the shipments. Modularization turns into real cost and time advantages as long as these additional burdens are counterbalanced by a plant layout simplification and a plant design conceived ad hoc to implement and ease the modularization.

The mature production volumes for small reactor plants predict tens of units being produced per year. With a standardised product approach there is a business rationale to invest in tooling and techniques that bring about both unit cost reduction and also lead time improvement. For example with ten units in manufacture each year using conventionally deployed nuclear sector manufacturing techniques, the value of work in progress would be significant, requiring capability to be duplicated to deliver the required volume. As a simplistic example, in a facility that produced ten components per year, any activity that takes more than 36 days to complete would require investment in a parallel capacity to achieve the volume. A specific example could be the weld cladding and staged inspection of a vessel.

The deployment of any new manufacturing technique, even one that has been validated in other comparable industrial sectors, will still need to satisfy the regulatory agencies prior to any plant incorporation. This point on securing regulatory acceptance has specific importance for a small reactor.

A number of process heat applications have been considered for hybrid systems integration. Many of these applications have been analyzed under the NGNP and Advanced Reactor Concepts programs [3,4,19-27] for co-generation applications with the high-temperature gas-cooled reactor concept. These applications include:

• hydrogen production —

о high-temperature steam electrolysis (HTSE) о steam methane reforming;

• coal to gasoline production via methanol production;

• natural gas to gasoline production via methanol production;

• coal to diesel production via Fischer Tropsch synthesis;

• natural gas to diesel production via Fischer Tropsch synthesis;

• ammonia production —

о hydrogen and nitrogen from steam methane reforming о hydrogen and nitrogen from HTSE

о hydrogen from HTSE and nitrogen from air separation unit;

• steam-assisted gravity drainage applied to oil sands;

• oil shale processing (ex situ or in situ);

• olefins via methanol production;

• seawater desalination — о reverse osmosis,

о multi-stage flash distillation, о multi-effect distillation.

Small nuclear reactors are already used for district heating applications in some remote locations. Other possible applications that could be coupled in a hybrid configuration could include metal refining and hydrogen production via thermal chemical water splitting.