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The Future of the Electric Grid

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This report aims to provide a comprehensive, objective portrait of the U.S. electric grid and the challenges and opportunities it is likely to face over the next two decades. It also highlights a number of areas in which policy changes, focused research and demonstration, and the collection and sharing of important data can facilitate meeting the challenges and seizing the opportunities that the grid will face.

This study is the sixth in the MIT Energy Initiative’s “ Future of ” series. Its predecessors have shed light on a range of complex and important issues involving energy and the environment. While the previous studies have focused on particular technologies and energy supply, our study of the grid necessarily considers many technologies and multiple overlapping physical and regulatory systems. Because of this breadth, our efforts were focused on integrating and evaluating existing knowledge rather than performing original research and analysis. In addition, this study’s predecessors focused on implications of national policies limiting carbon emissions, while we do not make assumptions regarding future carbon policy initiatives. Instead, we mainly consider the implications of a set of ongoing trends and existing policies.

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• Published: 12 January 2021

5G as a wireless power grid

• Aline Eid 1 ,
• Jimmy G. D. Hester 1 , 2 &
• Manos M. Tentzeris 1  

Scientific Reports volume  11 , Article number:  636 ( 2021 ) Cite this article

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• Devices for energy harvesting
• Electrical and electronic engineering

5G has been designed for blazing fast and low-latency communications. To do so, mm-wave frequencies were adopted and allowed unprecedently high radiated power densities by the FCC. Unknowingly, the architects of 5G have, thereby, created a wireless power grid capable of powering devices at ranges far exceeding the capabilities of any existing technologies. However, this potential could only be realized if a fundamental trade-off in wireless energy harvesting could be circumvented. Here, we propose a solution that breaks the usual paradigm, imprisoned in the trade-off between rectenna angular coverage and turn-on sensitivity. The concept relies on the implementation of a Rotman lens between the antennas and the rectifiers. The printed, flexible mm-wave lens allows robust and bending-resilient operation over more than 20 GHz of gain and angular bandwidths. Antenna sub-arrays, rectifiers and DC combiners are then added to the structure to demonstrate its combination of large angular coverage and turn-on sensitivity—in both planar and bent conditions—and a harvesting ability up to a distance of 2.83 m in its current configuration and exceeding 180 m using state-of-the-art rectifiers enabling the harvesting of several μW of DC power (around 6 μW at 180 m with 75 dBm EIRP).

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Introduction.

Our era is witnessing a rapid development in the field of millimeter-wave (mm-wave) and Internet of Things (IoT) technologies with a projected 40 billion IoT devices to be installed by 2025 1 . This could result in a huge number of batteries needing to be continuously charged and replaced. The design and realization of energy-autonomous, self-powered systems: the perpetual IoT, is therefore highly desirable. One potential way of satisfying these goals is through electromagnetic energy harvesting. A powerful source for electromagnetic scavenging is mm-wave energy, present in the fifth-generation (5G) of mobile communications bands (above 24 GHz), where the limits of allowable transmitted Effective Isotropic Radiated Power (EIRP) by the Federal Communications Commission (FCC) regulations are pushed beyond (reaches 75 dBm) that of their lower-frequency counterparts. Following the path loss model defined by the 3rd Generation Partnership Project Technical Report 3GPP TR 38.901 (release 16) in outdoor Urban Macro Line of Sight conditions (UMa LOS), the power density expected to be received at 28 GHz for a transmitted power of 75 dBm EIRP is 28 μW cm −2 at a distance of 100 m away from the transmitter. This demonstrates the ability of 5G to create a usable network of wireless power. In addition to the advantage of high transmitted power available at 5G, moving to mm-wave bands allows the realization of modular antennas arrays instead of single elements, thereby allowing a fine scaling of their antenna aperture, which can more than compensate for the high path loss at these frequencies through the addition of extremely-large gains 2 . However, one limitation accompanies large gain antennas: their inability to provide a large angular coverage. As the relative orientations of the sources and harvesters are generally unknown, the use of large aperture mm-wave harvesters may seem limiting and impossible. Individual rectennas, constituted of small antenna elements, can realistically be DC combined. However, this approach does not increase the turn-on sensitivity (lowest turn-on power) of the overall rectenna system: RF combination is needed.

Beamforming networks (BFNs) are used to effectively create simultaneous beam angular coverage with large-gain arrays, by mapping a set of directions to a set of feeding ports. An important class of these multiple networks is the microwave passive BFN that has been widely used in switched-beam antenna systems and applications. Hybrid combination techniques, based on Butler matrix networks, have been used in previous works for energy harvesting at lower frequencies 3 , 4 ,—more specifically at 2.45 GHz—to achieve wider angular coverage harvesting. However, these Ultra-High Frequency (UHF) arrays are impractically large for IoT applications and the implementation of their Butler matrices at higher frequencies would necessitate costly high-resolution fabrication. While sub-optimal—because of its large size—in the UHF band, the Rotman lens becomes the BFN of choice in the realm of mm-wave energy harvesting. Compared to their lower frequencies counterpart, fewer implementations are presented in the literature targeting energy harvesting at higher frequencies, more specifically 24 GHz and above. However, these systems later displayed in the table of comparison 5 , 6 , 7 , suffer from a narrow angular coverage.

In this paper, the authors demonstrate a full implementation of an entirely flexible, bending-resilient and simultaneously high gain and large angular coverage system for 5G/mm-wave energy harvesting based on a Rotman lens. For IoT applications, there is a benefit to making extremely low-profile devices that can conformally fit onto any surface in the environment such as walls, bodies, vehicles, etc. Therefore, thanks to the use of mm-waves, antennas with such features can be readily designed and fabricated. A Rotman lens-based rectenna has been first proposed in 8 , where a preliminary prototype and approach were presented, resulting in a quasi-flexible system, 80° angular coverage and 21-fold increase in the harvested power compared to a non-Rotman-based system. Here, the previously-predicted potential of 5G-powered nodes for the IoT and long-range passive mm-wave Radio Frequency IDentification (RFID) devices, is further taken advantage of, and effectively demonstrated. In order to do so, a thorough analysis of the lens itself—a structure that was not revealed in 8 —is first presented, exposing its key design parameters and resulting measured broadband behavior tested in both planar and bent conditions over more than 20 GHz of bandwidth. In addition, a scalability study of the approach, outlining the optimal size of such a system is reported, thereby proving the extent of the capability of providing a combination of good array factor and wide beam coverage. The novelty of this system also lies in the realization of a fully-flexible 28 GHz Rotman-lens-based rectenna system, completed by the design of a new DC combiner on a flexible 125 μm-thin polyimide Kapton substrate. The new DC combiner uses a reduced number of bypass diodes and increases the angular coverage of the system by more than 30% compared to 8 . Furthermore, the frequency-broadband behavior enabled by the use of the Rotman lens makes the full rectenna system bending-resilient, a property now demonstrated through its characterizations in flexing and conformally-mounted configurations. Finally, the system’s potential for long-range mm-wave harvesting is expressed for the first time, by reporting an unprecedented harvesting range of 2.83 m.

Experiments, results and discussions

Rotman lens scalability study for harvesting applications.

The Rotman lens, introduced in the 1960s, constitutes one of the most common and cost-effective designs for BFNs and is commonly utilized to enable multibeam phased array system 9 and wide-band operation, thanks to its implementation of true-time-delays 10 . By properly tuning the shape of the lens according to the geometrical optics approximation with the goal of focalizing plane waves impinging on the antenna side of the lens to different focal points on the beam-ports side of the lens, one achieves a lens-shaped structure with two angles of curvatures: one on the beam-ports side, and the other on the antenna side 11 . Because the lens is capable of focusing the energy coming from a given direction into its geometrically-associated beam port, the proposed scheme loads each of these ports with a rectifier, thereby channeling the energy coming from any direction to one of the rectifiers as shown in Fig. 1 a. This subsection investigates the effect of varying the number of antenna ports Na and beam ports Nb in the Rotman lens on its maximum array factor and angular coverage. The ( Na , Nb ) set, resulting in the best combination, will define the Rotman lens design parameters used for this work. Structures of varying sizes were designed using Antenna Magus and identical material parameters (substrate, conductors) as the ones of the presented design, before being simulated in CST STUDIO SUITE 2018. The simulated data was then processed in MATLAB to output the array factors created by the respective lens structures using a modified version of Eq. ( 1 ) 12 , presented next in Eq. ( 2 ):

where AF , n , Na , k , d , \(\theta\) and \(\beta\) are, respectively, the lossless array factor, the antenna number, the total number of antenna ports, the wave vector, the spacing between the elements, the direction of radiation and the difference in phase excitation between the elements. Since this formula describes a lossless array with a single antenna port, we introduced the following equation that takes into account the losses induced by the feeding network as well as the introduction of multiple feeding ports.

where \(AF_j\) and \(S_{nj}\) are, respectively, the array factor for beam port j and the S parameters between antenna ports n and beam ports j . The maximum value of the array factors as well as their total (accounting for the aggregated coverage of all ports) 3 dB beamwidths where then tabulated. The five simulated lenses had the following ( Na , Nb ) combinations: (4,3), (8,6) representing the system implemented in this work, (16,12), (32,24) and (64,48). Figure 1 b shows the increase in the array factor until reaching a peak of around 7.8 dB for a lens surrounded by 16 antennas and 12 beam ports, after which the array factor starts dropping, down to approximately 5.2 dB for a 64 antennas structure with 48 beam ports. The array factor reduction is explained by the increased losses within the lens accompanied by the increase of complexity and internal reflections, as the lens grows in electrical size. The same plot shows the decrease in angular coverage from 180° with 4 antennas down to 80° with 64 antennas. This study shows that the combination composed of eight antennas and six beam ports, offers a nearly optimal compromise, with these materials, between a high array factor of 5.95 dB and a 120° total angular coverage, while maintaining a reasonable number of antennas and beam ports. It should be noted that the choice of the number of beam ports is related to the 3dB-beamwidth of the individual antennas, the reason for which will be detailed later.

( a ) Dual combining (RF + DC) enabled by the use of the Rotman lens between the antennas and the rectifiers, ( b ) plot of the simulated maximum array factors and angular coverages for different-size Rotman lenses and ( c ) picture of the fabricated Rotman lens structure.

Flexible broadband Rotman lens design

After setting the number of antenna ports and beam ports, the design was printed on flexible copper-clad Liquid Crystal Polymer (LCP) substrate ( \(\varepsilon _r = 3.02\) and \(\hbox {h}= 180\,\upmu \hbox {m}\) ) using an inkjet-printed masking technique followed by etching, resulting in the structure shown in Fig. 1 c. It should be noted that the use of impedance-matched dummy ports is common with Rotman lenses 13 , 14 , 15 , 16 . Nevertheless, the goal in the implementation hereby described is not (as is usually the case) the generation of clean beam patterns with low side-lobe levels. Here, the lens’ properties are used for harvesting. Consequently, as long as the presence of the side lobes does not significantly interfere with the level of the array factor at broadside, side lobes are of no concern. Such a structure, including eight antenna ports and six beam ports—and, therefore, six radiating directions—was designed, simulated, and tuned. The structure, shown in Fig. 1 c, with the antenna ports connected to matched loads, was then tested in planar and bent configurations—cylinders with different bending radii ranging from 1.5 to 2.5 in. radii—to assess the effect of bending on the S parameters behavior. Figure 2 a shows the measured reflection coefficient of the Rotman lens at beam port 4 for four different scenarios, in comparison with the simulated structure in a planar position. The results reveal the Rotman lens’ ability to be mounted on curved surfaces down to a radius R = 1.5″, while maintaining a stable matching and minuscule losses compared to being held in a planar position.

( a ) Plot of the simulated and measured reflection coefficients at beam port 4 under planar and bent conditions and ( b ) Plots of the maximum array factors and angular directions of beam ports P1, P3 and P5 with respect to frequency.

The gain and angular bandwidths of this structure—defined by the frequency range in which the maximum array factor and angular direction per beam are stable within 3 dB and 5° respectively,—are studied next. The ultimate assessment of these properties involves calculating the beams’ magnitude and angular directions over a wide range of frequencies 17 , in order to ascertain their stability or lack thereof. For this purpose, the maximum array factors were calculated and the beams’ angular directions were extracted and plotted in Fig.  2 b for the first, third and fifth beam ports, P1, P3 and P5, representing the edge, secondary and central beams in this symmetrical structure. These plots prove the unique capabilities offered by the Rotman lens; although the Rotman lens is designed at a specific frequency—28 GHz in this work—this analysis proves that both the magnitude and the angular direction of the beams remain relatively stable over a very wide frequency range. In Fig. 2 b, three plots refer to the maximum array factors of the three beam ports, where minor fluctuations between 4 and 7 dB are observed over the range from 10 to 43 GHz for ports P3 and P5 and similar fluctuations over a fairly reduced frequency range for the extreme edge beam P1. On the same graph, three plots present the angular direction’s stability of P1, P3 and P5 beams, where P3 (in particular) preserves its angular direction over 33 GHz of bandwidth. The lens’ angular coverage resides between ports 1 and 6 and can be extracted from Fig. 2 b. Knowing that the structure is symmetrical and that beam port P1 is at around \({-54}^\circ\) , the overall structure covers an angle larger than 100° in front of the lens, a result further detailed in the next subsection. It should be noted that such a beamwidth is maintained over a large angular bandwidth exceeding 20 GHz, as shown in Fig. 2 b. This study demonstrates the stability and robustness of a low-cost, printed and flexible mm-wave Rotman lens structure, tested with respect to bending and frequency, and supports the choice of such an architecture at the heart of the harvesting system proposed in this work.

Flexible, high-gain and wide-angular-coverage mm-wave Rotman-lens-based antenna array

Eight of the linear antenna sub-arrays introduced in 8 were then added to the antenna ports of the array, and its beam-ports were extended by microstrip lines to enable their connection to end-launch \({2.92}\,\upmu \hbox {m}\) connectors. The antenna sub-array consists of five serially-fed patch antenna elements, providing an operation centered at 28.55 GHz with a reflection coefficient \(S_{11}\) lower than \({-20}\)  dB within this range. Their E-plane beamwidth of about \({18}^\circ\) (provided by the five antennas) is appropriate for most use cases, where environments expand mostly horizontally. Its simulations showed a gain of 13 dBi and a H-plane beamwidth of 80° in the plane perpendicular to the linear array. In this configuration, six beams were chosen to intersect at angles providing 3dB lower gain than broadside. Eight antennas provide a 3dB-beamwidth of 15°, which covers a total of \(6\times {18}^\circ = {108}^\circ\) in front of the array. The design was then also printed on flexible LCP substrate, resulting in the structure shown in Fig. 3 a, mounted on a 1.5″ radius cylinder. The radiation properties of the lens-based antenna system were simulated using the time-domain solver of CST STUDIO SUITE 2018, resulting in the six gain plots shown in Fig. 3 b. The gain of the Rotman lens at every port was also accurately measured using a 20 dBi transmitter horn antenna and by terminating all five remaining ports with a \({50}\,\Omega\) load for every port measurement to guarantee the proper operation of the lens. Both simulated and measured radiation patterns (shown in Fig. 3 b) display a remarkable similarity with a measured gain of approximately 17 dBi, and an angular coverage of around 110°, thereby validating the operation of the antenna array. The gains on the first three ports were also measured for the bent structure over a curvature of 1.5″ radius, shown in Fig. 3 a and compared to the measured results on a planar surface. The previous subsection in addition to previous works 18 , 19 have demonstrated that the performance of the Rotman lens is not deteriorated by wrapping or folding the structure compared to its conventional planar counterpart. However, after adding the antenna arrays, bending the structure can indeed have effects on its phase response, especially if the structure is large and the bending is severe. Figure  3 c shows the gains of P1, P2 and P3 for the two scenarios (three ports only because the structure is symmetrical), demonstrating again the ability of the lens in maintaining a stable gain (especially over the center beams) upon bending. The beam located at the edge, however, suffers additional deterioration in received power under bending, because of the shift of the source away from the broadside of the bent antenna arrays.

( a ) Picture of the flexible Rotman-lens-based antenna array, ( b ) measured (solid lines) and simulated (dashed lines) gains of the antenna array held in a planar position and ( c ) measured gains of the antenna array for beams P1, P2 and P3 only (because of the symmetry of the structure) in planar and bent conditions.

Fully-flexible 28 GHz Rotman lens-based system

Rotman-lens-based rectenna.

In this section, the fully-flexible rectenna system—based on the Rotman lens and a new DC combiner network—is presented. This architecture, shown in Fig. 4 a, consists of a series of eight antenna sub-arrays attached to the Rotman lens from one side, facing six rectifiers at the opposite side where DC serial combination is implemented. The basic rectenna elements, that are the antenna and the rectifier, are presented in details in 8 . The diode used in this work is the MA4E2038 Schottky barrier diode from Macom. The Rotman-based rectenna was first characterized as a function of its received power density. The system was positioned at a specific harvesting angle (approximately \(-25^\circ\) ) and illuminated with a horn antenna with a gain of 20 dBi, placed at a distance of 52 cm away from the rectenna array, within the far field region starting at 23 cm, and outputting powers ranging from 18 to 25 dBm, corresponding to an RF input power sweep from around − 9 dBm to − 2 dBm. The array was loaded with its optimal load impedance of 1  \(\hbox {k}\Omega\) , corresponding to the optimal load of a single rectifier—since only one rectifier will be “ON” at a time, given that the Rotman lens focalizes all the power to one beam port depending on the direction of the incoming wave—as detailed earlier. The results of this experiment are shown in Fig. 4 b, where the harvested voltages and powers of the array are shown. It can be observed that, at low powers, the Rotman-based rectenna effortlessly produces an output. The Rotman-based rectenna turns on well below − 6 dBm cm −2 , which compares quite favorably to the literature 6 . The output voltage of the rectenna was also measured over its operating frequency range. Like in the first experiment, the system was positioned at the same harvesting angle, at a range of 25 cm away from the source’s horn antenna. The output voltages under open load conditions were recorded and plotted, as shown in Fig. 4 c for the Rotman lens-based rectenna, for \(P_d = {9}\,{\hbox{dBm cm}}^{-2}\) , \(P_d = {10.5}\,{\hbox{dBm cm}}^{-2}\) and \(P_d = {12}\,{\hbox{dBm cm}}^{-2}\) incident power densities. The plots present a wide frequency coverage—from 27.8 to 29.6 GHz.

( a ) Picture of the fully-flexible Rotman-based rectenna, ( b ) plot of the measured voltages and output powers versus incident power density for the Rotman-based rectenna and ( c ) plot of the measured voltages with respect to frequency for the Rotman-based rectenna.

Flexible DC combining network

Power summation is very critical when it comes to the unbalanced rectification outputs produced from realistic RF sources, and can be implemented differently depending on its costs and benefits 20 .

This paper does not rely on a direct voltage summation topology (i.e. back-to-back RF diodes); however, it introduces a minimalist architecture relying on a total of \(2\times (N-1)\) bypass diodes, where N is the number of RF or rectifying diodes. Equipped with a low turn-on voltage of 0.1 V, the Toshiba 1SS384TE85LF bypass diodes used in the DC combiner design create a low resistance current path around all other rectifiers that received very low or close to zero RF power. This topology is optimal when only one diode is turned on, which can be assumed if a single, dominant source of power irradiates this particular design from a given direction. This new combiner circuit is shown in the schematic of Fig. 5 a. This simplified schematic—shown for four rectifying diodes—uses different colors to highlight the paths that the current will take for every case where an RF diode turning “ON” while the serially-connected diodes are “OFF”. This DC combiner was then fabricated on a flexible \({125\,\upmu \mathrm{m}}\) -thin polyimide Kapton substrate and connected to the Rotman lens-based rectenna through a series of single connectors to make the entire system fully flexible and bendable. The harvested power under a load of 1  \(\hbox {k}\, \Omega\) versus the angle of incidence of the mm-wave energy source for the Rotman-lens-based rectenna is compared for both rigid (presented in 8 , and relying on \(2\times N\) bypass diodes) and flexible new DC combiners. For this experiment, a horn transmitter antenna was used to send 25 dBm of RF power at 28.5 GHz to the lens placed 70 cm away, as shown in Fig. 5 b, while the array was precisely rotated in angular increments of 5°. Figure 6 a shows that the new DC combiner, with a reduced number of diodes, was able to provide a complete angular coverage of almost 110° over the entire lens spectrum as presented in Fig. 3 b, thus solving the voltage nulling occurring at the first and last ports, using the rigid DC combiner adopted previously in 8 . The new DC combiner offers therefore, an increase of more than 30% in the system’s spatial angular in addition to enabling a fully-bendable structure due to the unique fabrication on flexible Kapton substrate and connection to the rectenna using individual interconnects.

( a ) Rotman-based rectenna power summation network and ( b ) picture of the setup used to measure the angular response of the rectenna.

( a ) Plot of the measured harvested powers by the rectenna with respect to the source’s incidence angle for the two DC combiners, rigid and flexible and ( b ) plots of the measured harvested powers and voltages with respect to the incident power density under different load conditions for the Rotman lens rectenna with and without the flexible DC combiner.

As mentioned earlier, the DC combiner is mainly used with the Rotman-lens-based rectenna to automatically direct the active rectifier’s output to a single DC common port, independent of which port this might be. An alternative to the DC combiner in the Rotman lens-based system, would be to manually connect to the active port if the location of the source were known. To study the effect of the implemented DC combiner on the turn-on sensitivity of the system, the output voltage of the rectenna was measured for a specific source location with and without the combiner over a range of RF transmitted power and load variations; the direction was chosen such that the non-DC-combined rectifier would output its maximum power. Figure  6 b shows eight different plots where three of them represent the harvested power with a direct connection to the active rectifier for 1  \(\hbox {k}\Omega\) , 10  \(\hbox {k}\Omega\) and 100  \(\hbox {k}\Omega\) conditions. Plotted with the same colors are the other three, representing the harvested power with the addition of the DC combiner for the same load values. The last two plots display the measured voltages with and without the combiner under open load conditions. The rectenna was placed 61 cm away from the transmitter horn antenna and the power was swept from 10 to 25 dBm. The results show the performance superiority in all considered load conditions when the contact is made directly to the rectifier and not through the DC combiner. The lens-based system is able to achieve a turn-on power as low as \(-15\,{\hbox{dBm cm}}^{-2}\) in this case. This behavior is explained by the voltage drop introduced by the bypass diodes present in the combiner—that consistently decrease the expected output voltage by 0.1 to 0.2 V—when one or two diodes are, respectively, added to the current path. The variation of load values also shows that the rectenna can achieve better efficiencies at lower loads. More importantly, the reduction in the turn-on sensitivity—the minimum power density required output 10 mV—induced by the combiner is only of about 2 dB in loaded conditions, while the combiner enables an increase in the angular coverage of the rectenna system from about 18° to 110°. The remarkable angular and high-power turn-on sensitivity offered by the Rotman-lens-based rectenna are finally benchmarked using the following table for comparison with several state-of-the-art works, as presented in literature. In Table  1 , the striking performance of the proposed system is displayed, highlighted by its flexibility and ability of achieving an angular coverage as large as 110° at extremely high turn-on sensitivity, thereby allowing mm-wave long-range harvesting in ad-hoc and conformal-mounting implementations.

Rectenna system performance under bending

This section displays the operation of the Rotman-lens-based system under different bending scenarios. This and previous work 18 , 19 show that the lens is able to maintain an efficient electromagnetic energy distribution across the output ports under convex and concave flexing conditions. The lens-based rectenna was placed on cylinders with different curvatures, 70 cm away from the transmitter sending 25 dBm of power at 28.5 GHz, as shown on Fig. 7 a. The voltage was collected using a load of 1  \(\hbox {k}\Omega\) for the planar and three bent conditions and plotted in Fig.  7 b with respect to the source’s angle of incidence. The graph shows an unprecedented consistency and stability in the system’s scavenging and rectification abilities, knowing that several sub-systems are exposed to warping and the pressures of bending: the antenna sub-arrays, the Rotman lens and the rectifiers. Slight attenuation can be observed at the edges, but the system otherwise performs unimpeded by the bending. This remarkable property qualifies this system as a perfect candidate for use in wearables, smart phones and ubiquitous, conformal 5G energy harvesters for IoT nodes.

( a ) Picture of the flexible Rotman lens-based rectenna placed on a 1.5″ radius cylinder and ( b ) measured harvested powers versus incidence angles for different curvatures, ( c ) long-range harvesting testing setup.

Long-range harvesting

As described earlier, one of the main appeals of the proposed approach is its ability to use the high EIRPs allowed for 5G base-stations while guaranteeing an extended beam angular coverage, which is a necessary feature for ad-hoc ubiquitous harvesting implementations. In order to demonstrate the lens based-rectenna for longer-distance harvesting and detect that maximum range, a high-performance antenna system—comprised of a 19 dBi conical horn antenna and a 300 mm-diameter PTFE dielectric lens (for high directivity) providing an additional 10 dB of gain—was used as shown in Fig. 7 c. With a transmitted power of 25 dBm (and an associated EIRP of approximately 54 dBm), corresponding to an incident power density of approximately − 6 dBm cm −2 , the lens-based rectenna displayed an extended range of 2.83 m under open load conditions, with an output voltage around 10 mV, thereby demonstrating (to our knowledge) the longest-ranging rectenna demonstration at mm-wave frequencies. With a transmitter emitting the allowable 75 dBm EIRP, the theoretical maximum reading range of this rectenna could extend to 16 m. In addition, the use of advanced diodes—designed for applications within the 5G bands and enabling rectifiers’ sensitivities similar to that common at lower (UHF) frequencies—are showing a potential path towards achieving a turn-on sensitivity of the rectifiers as low as − 30 dBm 21 , 22 . If this were practically applied to the Rotman lens system presented in this work, the harvesting range could be extended beyond 180 m (where the received power density for a transmitted power of 75 dBm is \({7.8}\,\upmu \hbox {W cm}^{-2}\) ), which is only slightly smaller than the recommended cell size of 5G networks 23 . This observation enables the striking idea that future 5G networks could be used not only for tremendously-rapid communications, but also as a ubiquitous wireless power grid for IoT devices.

Through the use of the Rotman lens, this paper demonstrates that the usual paradigm constrained by the (often considered fundamental) trade-off between the angular coverage and the turn-on sensitivity of a wireless harvesting system can be broken. Using the reported architecture, one can design and fabricate flexible mm-wave harvesters that can cover wide areas of space while being electrically large and benefit from the associated improvements in link budget (from source to harvester) and, more importantly, turn-on sensitivity. The approach has been shown, however, to only be scalable up to the degree where the additional incremental losses introduced by the growing lens counterbalance the increase in the aperture of the rectenna. Nevertheless, this inflection point only appears (in the particular context considered in this paper) after the arraying of 16 elements, or up to a scale of \(8\lambda\) . In the 5G Frequency Range 2 (FR2), this translates to harvesters of 4.5 cm to 9.6 cm in size, which are perfectly suited for wearable and ubiquitous IoT implementations. With the advent of 5G networks and their associated high allowed EIRPs and the availability of diodes with high turn-on sensitivities at 5G frequencies, several \({\upmu \hbox {W}}\) of DC power (around 6  \({\upmu \hbox {W}}\) with 75 dBm EIRP) can be harvested at 180 m. Such properties may trigger the emergence of 5G-powered nodes for the IoT and, combined with the long-range capabilities of mm-wave ultra-low-power backscatterers 24 , of long-range passive mm-wave RFIDs.

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Acknowledgements

This work was supported by the Air Force Research Laboratory and the NSF-EFRI. The work was performed in part at the Georgia Tech Institute for Electronics and Nanotechnology, a member of the National Nanotechnology Coordinated Infrastructure (NNCI), which is supported by the National Science Foundation (Grant ECCS-1542174).

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Integration of EVs into the smart grid: a systematic literature review

• Vivian Sultan 1 ,
• Arun Aryal 1 ,
• Hao Chang 1 &
• Jiri Kral 1  

Energy Informatics volume  5 , Article number:  65 ( 2022 ) Cite this article

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Integration of electric vehicles (EVs) into the smart grid has attracted considerable interest from researchers, governments, and private companies alike. Such integration may bring problems if not conducted well, but EVs can be also used by utilities and other industry stakeholders to enable the smart grid. This paper presents a systematic literature review of the topic and offer a research framework to guide future research and enrich the body of knowledge. The systematic literature review presented in this paper does not contain all the material available on this subject. It does, however, include most of the key publications readily available in a power-utility or technical-reference library together with some of the earlier papers in the field (the anchor papers). For this review, we selected appropriate digital sources (digital libraries and indexing systems; IEEE Xplore and Web of Science), determined the search terms, and conducted a broad automated search. This article also details the components of the research theme—EV integration into the smart grid—as well as its accompanying use cases. The analysis of the relevant papers indicated four types of key research concerns: power-grid, power-system, and smart-grid reliability and the impacts of changes on them. These results can help guide future research to further smart-grid development. Future research can also expand the reach of this research to address its limitations in scope and depth.

Introduction and research background

Integration of electric vehicles (EVs) into the smart grid can be leveraged by utilities and other industry stakeholders to bring several benefits and to enable the smart grid. Mwasilu et al. ( 2014 ) emphasized the importance of vehicle to grid (V2G), an example of services on the grid that will allow the shift of the static power system to the efficient virtual power grid. San Diego Gas and Electric ( 2015 ) reported that deploying networks of EV charging stations can stabilize and bring advantages to the grid in locations with excess power; EV charging can absorb mid-day solar overgeneration and alleviate wind curtailment at night. Sultan et al. ( 2017 ) highlighted how charging EVs when nondispatchable assets, such as solar and wind generators, are producing more energy can help flatten out the demand curve and reduce the extent to which supply suddenly escalates. All these characteristics reduce system costs, benefit ratepayers, and improve the profitability of generators (San Diego Gas and Electric 2015 ).

On the international stage, the EV industry has been prominently used as a tool by countries to meet their carbon-footprint-reduction goals. EVs also have spurred a potential new avenue of electricity sales while at the same time impacting maintenance costs by adding to peak loads and changing historical grid-load patterns. The integration of EVs with electrical grids is giving rise to the concept of smart grids. This integration can come from potential bidirectional charging (V2G), grid storage research, and innovative energy generation (Denholm et al. 2015 ).

EVs can potentially serve a dual purpose, an alternate form of grid storage offloaded to the public. It can allow the vehicle owners to be compensated for providing electric service when the vehicle is not in use, helping to reduce the cost of ownership. Also, the quality of life for large urban centers can increase due to the potential opportunity to move emissions from large population centers. This relocation of energy production can improve air quality and public health in metropolitan cities, while remaining emission production further decreases as remaining energy needs are met by renewable resources (Denholm et al. 2015 ).

However, it is important to note that the integration of many EVs into the electric power system is a major challenge which requires a thorough evaluation and examination in terms of economic impacts, operation, and control benefits at ideal circumstances (Mwasilu et al. 2014 ). Large-scale integration of EVs into the smart grid may bring a series of problems if EVs are not integrated carefully into the smart grid. According to Green et al. ( 2011 ), several works analyzed the impact of EVs on the power-distribution system. Examples of the anticipated adverse impacts are power transformers overheating and the need for new investments in distribution facilities (Mwasilu et al. 2014 ).

A major challenge is the impact of simultaneously charging many EV batteries on the power network, this could change the overall load profile of the grid significantly. The issue is that the charging behaviors of EVs are only regulated by the customer so it’s not within the control of the grid operators and the electric utilities. The risk of grid overload can lead to a degradation of the grid performance, bad power quality and/or voltage deviations, even a blackout of the whole power system if EV charging is not managed properly. However, time-of-use rates can guide an EV charging, and V2G benefits can be easily ramped up and down in response to the load on the system, improving voltage regulation and droop control.

The high cost of integration due to inadequate charging infrastructure and competition from other energy-storage technologies are additional challenges to EV integration. Pumped hydroelectric storage is considered, for example, to be much cheaper than the V2G option. According to Hernández-Moro et al. ( 2012 ) and Mullan et al. ( 2012 ), pumped hydro has greater efficiency (up to 99%) and can store energy for long periods as compared to the EV battery (Hernández-Moro et al. 2012 ).

On the other hand, EVs have advantages when operated in the V2G mode to feed power to the utility grid. The primary advantages stem from the EV battery’s ability to provide power when needed. EV technology can provide grid support by delivering ancillary services such as peak power shaving, spinning reserve, and voltage and frequency regulation (Ehsani et al. 2012 ).

Peak shaving means reducing the highest demand levels at the power plant. From a utility perspective, EVs can be viewed as both dynamic loads which may not be easy to predict, but also potential backup for the electric grid through the V2G technology (Mwasilu et al. 2014 ). So, EVs can respond to changes in demand, they provide a spinning reserve and can dramatically reduce the need to use expensive peaking plants, savings that utilities can pass on to their customers in the form of lower energy costs.

Another point is that mismatches between power supply and demand can lead to oscillations in the supplied voltage, phase angle, and frequency. These oscillations degrade power quality, possibly damaging utility customers’ sensitive electronic equipment. EVs can both provide and absorb power and energy so to help dampen both intra- and interarea power oscillations. Mwasilu et al. ( 2014 ) claim that EVs have the potential to assist in voltage and frequency regulation, thus enhancing electric-grid reliability and power quality.

A modern grid that is well equipped to handle the additional EV loads and reap the benefits from the intersection of the EVs and the electric power network could contribute to an enhanced grid with real environmental benefits for all customers.

Thus, more research is needed, and it is critical especially with the increasing penetration of EV charging into the electric power system. Unease about global warming, energy security, and the current health of the environment has caused more interest in EVs. The existing power grid suffers from unpredictable and intermittent supply of the electricity from wind and photovoltaic (PV) solar sources, so EV charging and V2G services are a promising solution to balance the generation from renewable energy sources (International Electrotechnical Commission 2012 ).

The intent of this paper is to present a systematic literature review of EV integration into the smart grid and develop a research framework to guide future research and enrich the body of knowledge. A systematic literature review is a particularly influential tool in research; it allows a scholar to gather and recap all the information about a specific field (Spanos and Angelis 2016 ).

This paper is organized as follows. In the “Introduction and research background”, we introduce and present the topic’s research background. In the “Methodology”, we delineated our research methodology. The “Results” describes the results of the review and offers a bibliography of anchor papers. The “Discussion” discusses the results. Finally, “Conclusion” concludes.

Methodology

This paper’s systematic literature review follows the three stages defined by Kitchenham ( 2004 ) and Kitchenham et al. ( 2009 ): planning, conducting, and reporting. In the first stage, we create the research protocol. The second stage is the actions of reviewing literature based on the protocol, and the last stage manifests the article’s results section.

Research protocol

The research protocol established in the planning stage guided the systematic literature review. The first step is to identify the need for a systematic review. Although several studies try to investigate EV integration into the smart grid, no comprehensive review has so far summarized all these studies and offered a deeper insight. Therefore, the need for a systematic literature review providing solid foundations and equipping researchers with pertinent information is clear.

To develop the review protocol, we define the research questions, select the search strategy, establish the study’s inclusion and exclusion criteria, select quality-assessment criteria, and identify the data to be extracted from the studies. Three research questions guide our review.

What are the themes within research on EV integration into the smart grid?

What are the results of the studies?

What research methods are used?

To conduct the systematic literature review, we adopted a broad automated search, a method that includes the selection of the most appropriate digital sources (digital libraries and indexing systems) and the determination of the search terms (Spanos and Angelis 2016 ). We selected two digital libraries, IEEE Xplore and Web of Science, as they are the most relevant digital sources in electricity-infrastructure research. Our searches relied on the titles of the papers to avoid retrieving irrelevant papers. The search strings we used were.

Inclusion and exclusion criteria

According to Spanos and Angelis ( 2016 ), a systematic literature review’s inclusion and exclusion criteria must be distinct and clearly stated. We used three selection criteria and one exclusion criterion in our systematic review.

Quality assessments

Once each paper has passed the relevancy test, we peruse the papers based on the quality-assessment criteria. These rigorous criteria ensure all studies included in the systematic literature review achieve an adequate level of quality. After consulting with domain experts and independent researchers, we decided to include each article for the final analysis if it satisfies three criteria:

The data description is available, and its existence can be verified.

Research methodology is clearly described.

Results presentation is clear and impactful.

Once the articles had passed the inclusion and quality-assessment criteria, we recorded the data features of the papers for the final analysis: (1) title, (2) authors, (3) publication year, (4) authors’ affiliations, (5) journal title, (6) number of papers citing the article, (7) abstract, (8) research questions, (9) research methodology, and (10) results.

For this survey, we analyzed results from 724 papers relevant to integration of EVs into the smart grid, 260 papers from the IEEE Xplore and 464 papers from the Web of Science. The analysis process considered the research results, as stated by the authors, and was mainly conducted throughout the abstract, conclusion, and results sections if required. Tables 1 and 2 present counts of document identifiers and publication years. Table 3 presents summary statistics.

The analysis of the relevant papers indicated four types of key research concerns.

• Assessing power-grid reliability considering EV integration.

• Improving power-system reliability considering EV integration.

• Planning for smart-grid reliability in preparation for EV integration.

• Evaluating the impacts of adding EVs and charging stations on grid reliability.

The research methodologies of the included papers can be classified into two categories, analytical and simulation. Analytical techniques “represent the system by mathematical models and evaluate the reliability indices from these models using mathematical solutions” (Faulin et al. 2010 ). Simulation views problems as a series of real experiments, such as Monte Carlo simulation which is used for the prediction of probability for various outcomes when dealing with random variables. Table 4 presents the statistics for the different research methods. Finally, 58 papers used the Monte Carlo simulation method.

Based on the results of the systematic literature review, we have constructed a smart-grid–EV-integration framework highlighting research components of EV integration into the smart grid, with goals, themes, use cases, and research tools.

Research contribution: framework

In this section, we propose the smart-grid–EV-integration framework with three main research domains (Fig.  1 ), solutions for charging, microgrids and distributed generation, and managing power demand. This framework recognizes these three EV-integration domains as cardinal research-movement drivers for studying the benefits and challenges of integrating EVs into a smart grid. We also propose technological and socioeconomic solutions. Next, based on our literature analysis, we present common themes within the domains. The first theme, integrating EVs, drives the enhancement of EV technologies. The second theme, advancement of the smart grid, drives the advancement of distributed generation. The third theme, smart-grid reliability with EV applications, drives power-demand management and smart-grid reliability in the context of EV integration.

Smart-Grid–EV integration framework

The use cases in the research framework are classified based on under which research theme(s) they fall (see Fig.  1 ). Smart-charging infrastructure use cases deal with the reformation of current structures to achieve both physically and technically suitable charging solutions. “Apart from the technological innovation of EV, effective charging infrastructure plays a fundamental role in supporting the wider adoption of EV” (Chen et al. 2020 ). An important area of infrastructure adjustments is, for instance, planning for EV smart charging stations, involving both geographical research and charging-management system implementation.

According to Zhou et al. ( 2021 ), commercial buildings with EV charging stations and PV panels are common prosumers in the smart grid. Thus, “the energy management of commercial buildings has significant potential for electricity cost saving, load levelling, and distributed generation consumption.” Site-integrated EV charging solutions for workplaces and other business or commercial areas are interesting use cases, where growth in EV smart-grid penetration calls for improved charging load management. Algorithms, charging and discharging impacts on smart-grid peak loads, and cost benefits are worthy of investigation.

Residential-building use cases explore the impacts of EV integration on a household, very often in combination with implementation of photovoltaic or wind-energy appliances. Charging solutions can have economic benefits. Residential storage, on the other hand, like EVs, can be both flexible and time shiftable and can significantly increase residential-demand elasticity (Rassaei et al. 2015 ). The use cases explore how to manage smart-home energy in a residential smart grid and how energy stored in the EV can be used for distributed generation either for the household or for a larger residential area. This area also involves associated-risks investigation, including increased power losses, overloads, and voltage fluctuations, and how they influence the smart grid.

EV Cybersecurity use cases investigate EV integration into the smart grid from the perspectives of energy safety, usage, user information, and transactions. According to Sanghvi et al. ( 2021 ), EV integration can potentially leave the grid “vulnerable to cyberattacks from both legacy and new equipment and protocols, including extreme fast-charging infrastructure.” Since EV participation in the smart grid will unavoidably partially depend on accessing power and communication networks and systems, such a system might become a target of such attacks. Thus, cybersecurity and energy security are crucial areas of research around smart-grid–EV integration.

Technological enhancement of smart charging and discharging evaluates problems caused by advancements in charging technologies to identify strategies, benefits, and risks and evaluate and propose how EV charging and discharging can help improve a smart grid’s flexibility and effectiveness in response to energy fluctuations in the distribution area. According to Aghajan-Eshkevari et al. ( 2022 ), “it is essential to manage the charging and discharging of EVs [that] can be also considered sources of dispersed energy storage and used to increase the network’s operation efficiency with reasonable charge and discharge management.” Use cases may also include improvement of fast-charging technologies, battery technologies, wireless charging, and roadway electrification.

Utility-scale energy storage solutions help maintain a balance between energy generation and consumption in the smart grid. As the EV market grows, more degraded batteries can be further used for other purposes. “In particular, the repurposing of EV [lithium-ion batteries] in stationary applications is expected to provide cost-effective solutions for utility-scale energy storage applications” (Steckel et al. 2021 ). Use cases in this category involve addressing questions of battery recycling sustainability, degradation, participation of EVs in the load balancing through the dispatch of batteries, and other areas.

Demand-response management and pricing use cases focus on both technical and socioeconomic areas of energy supply and demand for smart-grid operators, charging-station operators, and EV users and their demand response during the peak time. While smart-grid–EV integration has a significant impact on energy demand, they also represent an energy resource. “Therefore, in smart grid, the consumer demand is expected to be controlled so as to coordinate with the electricity generation, which is the main objective of demand response management” (Yu et al. 2016 ). Power demand response can positively impact peak shaving and load balancing, and open new possibilities for energy market and energy trading through energy-aggregator demand-response programs (Ren et al. 2021 ).

Evaluation and maintenance throughout the addition of EVs can involve mathematical modeling for both technological and economic evaluation of EV deployment’s impacts on the smart grid, predictive maintenance solutions for distribution transformers under the increased EV load, energy-dispatch strategies, involved systems’ life cycles, charging behavior, and other methods to maintain a balanced smart grid with growing numbers of EVs.

Energy-management systems are crucial to the smart grid’s ecosystem. Integrated EVs can contribute to the important task of effectively maintaining the power supply–demand balance and decrease the peak load. Energy-management systems also handle sharing or exchanges among different energy sources, including EVs, to establish reliable and effective supply. Use cases in this category involve many topics like energy-quality management systems, optimization systems, energy-consumption control systems, and scheduling systems. Energy-management systems are also closely linked to demand management and response (Meliani et al. 2021 ).

Public safety in EV adoption must be considered. As countries around the globe strive to meet energy objectives while decreasing their climate impact, it is crucial to identify and regulate new EV-related technologies to protect the public from potential undesirable effects. A growing number of EVs increases risks from, for instance, disposed or damaged batteries. Therefore, proper risk-mitigation techniques—professional training, recycling policies, and standardization—must ensure public safety and environmental protection (Brown et al. 2010 ).

Mobility behavioral science explores the questions associated with human behavior’s impact on transportation and energy and is crucial for understanding of how future EV and smart-grid technologies should be implemented. According to Rames et al. ( 2021 ), “exploring multidimensional aspects of differences in technology adoption, travel, and vehicle ownership across settlement types can help inform energy-efficient and affordable mobility system goals.” Thus, research in this area involves modeling EV owners' usage and driving behavior for effective power planning and operations, drivers’ motivation to participate in peak shaving, and implementation of localization technologies to adjust charging behavior and manage demand.

We aim to help resolve problems in the EV-integration field using such tools as machine learning, deep learning, networking, distributed systems, middleware systems, embedded systems, optimization and control, databases and big data management, human–computer interfaces, behavioral information systems research, design-science research, and mixed-methods research. When applied to the EV-integration field, these tools have the potential to significantly increase knowledge in the field and solve some of the problems it faces.

Smart-grid–EV-integration research framework founded on the previous literature

In addition to our smart-grid–EV-integration perspective, Fig.  2 illustrates our smart-grid–EV-integration research framework founded on the previous literature and our view of the domain. The framework focuses on two main areas: EV integration and the smart grid. The first research focus involves systems connecting EVs, transportation infrastructure, power grid, buildings, and renewable energy sources (Meintz 2022 ). Adjusting infrastructure, charging solutions, and associated costs are all possible goals in the EV-integration research focus.

Smart-grid–EV-integration research framework

The smart grid (the second research focus) refers to the electric grid, a network of transmission lines, substations, transformers, and more that deliver electricity to a set location, integrated with digital technology allowing for sensing and two-way communication between the utility and its consumers (Department of Energy, Office of Electricity 2022 ). Adaptation of V2G systems in the smart grid, smart charging infrastructure, grid planning, and impacts of EV charging on the smart grid’s reliability are the possible goals within the smart-grid research focus.

In the context of a smart-grid–EV-integration research framework, scenarios and use cases can be classified into infrastructure addition, future technologies, policies, charging-demand conditions, changes driven by causes, operating protocols, cybersecurity, information and communication technologies, energy-management systems, energy redistribution, optimizing the smart grid for EV penetration, scheduling, V2G, and vulnerability.

Anchor papers on the integration of EVs into the smart grid

One way to ensure the grasp of the main core of a subject is to examine the references cited in the current articles and highlight repeatedly cited papers. In this literature review, papers cited more than one standard deviation above the average are considered anchor papers.

From the articles that passed the filter criteria, we identified anchor papers, highly cited and influential papers. To identify anchor papers, we used the same search string without an exclusion criterion (no year-range restriction) to pull all journal and magazine publications matching the search criteria from the database. We sorted the extracted articles (700 total) in descending order based on the number of articles citing each focal article, calculated the standard deviation for the articles’ number of citations, and identified the outliers (articles whose number of citations exceeded one standard deviation greater than the mean). The search string that we used for IEEE Xplore is ("Document Title":electric vehicle) AND ("Document Title":smart grid) and refined by Content Type: Conferences, Journals, and Early Access Articles. Meanwhile, for Web of Science, we used the search TOPIC: (electric vehicle AND smart grid) refined by DOCUMENT TYPES = (ARTICLE) Timespan = All years. Indexes = SCI-EXPANDED, SSCI, A&HCI, ESCI.

Based on this analysis, we found 61 anchor papers and passed them through a relevancy test to see if they are related to grid-reliability research. As each paper passed the relevancy test, we peruse it to apply quality-assessment criteria. After excluding the irrelevant papers and those not meeting the quality criteria, we identified 45 anchor papers (Table 5 ).

Table 6 presents a bibliography and analysis of anchor papers on the subject of the integration of EVs into the smart grid. Based on this analysis, Table 7 presents the distribution and percentages of anchor articles by research theme or question previously identified as follows. Optimizing grid usage to EV needs and the impacts on EV applications of smart-grid implementation or V2G communication have received the most attention. Environmental changes due to EV or grid applications show the lowest percentages of anchor articles.

Table 8 presents the research methods used by the authors of the anchor papers. Though simulation is the dominant research method considering the entire literature, articles using analytical approaches seem to get more attention based on articles citing them.

Bearing in mind the research themes and the methods illustrated in the anchor papers, we posit that simulation has been a popular topic in research and that there is need for more research in the area of environmental changes due to EV or grid applications, how to adjust the reliability and adequacy of charging stations and impacts on EV and grid applications.

Analytics using machine learning and big-data management would help the research community plan and improve EV integration into the smart grid. In future research, we intend to highlight the novel use of analytics to predict research themes such as environmental changes due to EV or grid applications, how to adjust the reliability and adequacy of charging stations and impacts on EV applications of grid applications. The goal is to offer an enhanced viewpoint for this research topic, while considering the impact of changes, EVs’ integration, and the potential benefits to the smart grid.

To enable more robust research on smart-grid–EV integration, we both plan our own research and invite other authors to submit original papers on topics including, but not limited to,

EV battery charging optimization

Mobility behavioral science

Location analytics for EV integration

Demand management and pricing for EVs in the electricity network

Internet of things and sensors for EV integration

Recent advancement in analytics for EV integration and microgrids

Innovative charging strategies for EVs

As described in the previous section, this systematic literature review provides a solid foundation to equip researchers with pertinent information.

The intent of this paper is to present a systematic literature review of smart-grid–EV integration and offer a research framework to guide future research and enrich the body of knowledge. Because the systematic literature review presented in this paper focuses on two digital libraries and searches only article titles, it does not contain all the material available on this subject. It does, however, include most of the key publications readily available in a power-utility or technical-reference library together with some of the earlier papers in the field (the anchor papers).

To conduct a systematic literature review, we completed a broad automated search, a method that includes the selection of appropriate digital sources (digital libraries and indexing systems) and the determination of the search terms. We selected the digital libraries IEEE Xplore and Web of Science for the systematic review. This article also details the components of our research theme and its accompanying use cases.

This review is limited to the IEEE Xplore and Web of Science digital libraries to facilitate an automated search of the literature. This limitation is reasonable because these sources are most likely to be available in a power-utility or technical-reference library. However, a broader search may find other research not analyzed here. Additionally, the search was restricted to article titles to reveal those research projects most closely related to the topics of interest. A broader search of abstracts and full text would certainly find more articles, but would likely involve considerably more false positives.

Analytics using machine learning and big-data management could help the research community plan and improve smart-gid–EV integration. Based on the four types of key research concerns (power-grid, power-system, and smart-grid reliability and the impacts of changes on them), we intend to highlight the novel use of analytics to predict research themes in future research. The goal is to offer an enhanced viewpoint for smart-grid–EV integration while considering the impact and the potential benefits to the smart grid of such changes and EVs’ integration.

Availability of data and materials

Additional supporting data is available from the first author.

Abbreviations

Electric vehicle

Photovoltaic

• Vehicle to grid

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Revamping the Texas Power Grid: Insights from Rice University’s Electricity Research

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Daniel S. Cohan and James Doss-Gollin, "Revamping the Texas Power Grid: Insights from Rice University's Electricity Research" (Houston: Rice University's Baker Institute for Public Policy, November 10, 2023),  https://doi.org/10.25613/5FJJ-T074 . 

Executive Summary

How we generate electricity matters to our air, our climate, our wallets, and our quality of life. Texas power plants burn more coal and natural gas and emit more air pollutants and greenhouse gases than those in any other state. But Texas also leads the nation in wind power, has the fastest growing solar sector, and is home to companies that are driving technological innovations in geothermal energy. Widespread power outages during the February 2021 freeze and price spikes during heat waves have highlighted the vulnerability of our isolated power grid to extreme weather events amid growing demand, an aging power plant fleet, an inadequately winterized natural gas supply system, and increasing reliance on variable wind and solar power.

This report synthesizes research published by Professors Daniel Cohan and James Doss-Gollin and their research groups at Rice University since 2020 and updates those studies to the latest conditions in Texas and the Electric Reliability Council of Texas (ERCOT) market. Though not a comprehensive review of Texas electricity, this report provides important insights as the state works to improve the reliability and sustainability of its power supply amid a changing climate.

The report is organized into four sections, with key highlights presented here:

Section 1 discusses how Texas power plants affect air quality, health, and climate. Although Texas environmental regulators have historically focused on reducing power plant nitrogen oxide (NO x ) emissions to address ongoing nonattainment of ozone standards in Texas cities, this section shows that power plants are even more pivotal as the source of 59% of statewide emissions of the sulfur dioxide (SO 2 ) that forms sulfate particulate matter (Table E1). Our review of scientific literature finds that sulfate is one of the top two components of fine particulate matter (PM 2.5 ) across Texas field studies, comprising 21%-57% of PM 2.5 at each site. Thus, control of power plant SO 2 emissions will be crucial to helping several Texas counties attain the more stringent proposed PM 2.5 ­ standards that they currently exceed and helping other counties attain SO 2 standards that they already violate (Table E2).

The need to attain these air quality standards and protect public health will likely require additional emissions controls at most Texas coal power plants, which could prompt the plants to convert to gas or retire amid competition from cheaper wind, solar, and natural gas power producers. All four remaining Texas coal plants in the Southwest Power Pool already plan to close or switch to gas by 2028. Of the 10 remaining coal plants in ERCOT, only two have announced retirement dates, but others may follow suit due to poor operational performance, challenging market conditions, and more stringent environmental regulations. The Environmental Protection Agency’s (EPA) Good Neighbor Plan will require power plant NO x emissions to fall by half by 2028, and its proposed Regional Haze Plan for Texas will require SO 2 controls at the state’s largest coal plants — Parish and Martin Lake. Taken together, we estimate that these air quality regulations will prompt at least 8.6 gigawatts (GW) of the remaining 13.6 GW of coal plants in ERCOT to install major emissions control devices, convert to gas, or retire. Given the poor profitability of these plants and the high cost of emission control devices, retirements are the most likely outcome.

Table E1 — Power Plant Emissions in Texas in 2021 and Their Share of Texas Emissions Overall and of US Power Plants

Table E2 — Texas Regions That Violate the 70 ppb Ozone Standard, Counties That Would Violate EPA’s Proposed 9 or 10 µg/m 3 PM 2.5 Standard (vs. Current 12 µg/m 3 ), and Counties that Violate the 75 ppb SO 2 Standard

Section 2 explores the complementary roles that solar and wind can play in replacing the output of closing coal plants and meeting growing power demand in Texas. Although it is not sunny or windy all of the time, our analysis shows that it is either sunny or windy somewhere in Texas over 90% of the time. Solar power that peaks midday, together with wind power that peaks at night in West Texas and on summer afternoons with coastal sea breezes, can provide complementary sources of power most of the time. However, there is substantial variability and occasional periods when it is neither windy nor sunny (Figure E1).

In January 2020, solar and wind capacity in ERCOT were at 6.0 GW and 31.1 GW, respectively. By 2025, these numbers are projected to grow to a respective 34.9 GW and 39.7 GW, a reflection of the increasingly important role of wind and solar in easing the burden on the aging power plant fleet. This requires a paradigm shift from focusing on peak gross load to net load instead, after accounting for variable renewable generation (Figure E2). For example, whereas the burden on dispatchable resources traditionally peaked alongside demand on summer afternoons, peak net load is now shifting to the hours around sunset. We project that the wind and solar farms expected to be added in 2023 and 2024 will provide an average of 8 GW and reduce the burden on dispatchable resources by 4­–8 GW during the hours of peak net load in 2025 (Figure E2). This would more than offset projected growth in electricity demand under typical meteorology and could contribute to offsetting some of the potential loss in output from coal power plants. However, the heat wave of 2023 demonstrates that extreme heat can further raise demand, warranting analysis that is beyond the timeframe of this study.

Figure E1 — Wind and Solar Capacity Factors in ERCOT by Hour and Month from 2017–22

Figure E2 — Gross Load and Net Load (Subtracting Wind and Solar Output) in 2020–22 and Projected for 2025

Section 3 provides a brief overview of opportunities for geothermal energy in Texas as a prelude to studies that will be issued by the Cohan group later this year.

Section 4 delves into the impact of temperature extremes on heating and cooling demands, which influence peak loads on the power grid. Understanding these risks can inform exercises such as ERCOT’s seasonal assessment of resource adequacy (SARA). Although we do not explicitly link temperature to overall electricity demand, which varies due to factors like population, technology, behavior, and building types, quantifying the risk of temperature extremes is vital for anticipating peak loads and ensuring resilience of the energy system. This section highlights two main analyses. First, the section compares the February 2021 temperature extremes in Texas to past cold snaps. Using temperature-based proxies for heating and cooling demand (akin to heating degree days or cooling degree days), we demonstrate that there have been several events of similar magnitude since 1950. Although the 2011 cold snap was used as a basis for the extreme scenario in the winter 2020–21 SARA, it was relatively minor compared to the complete historical record. Second, the section examines how climate change has already impacted heating and cooling demands in Texas. Analyzing the same temperature-based proxies reveals that, on an annual average basis, heating demand is decreasing while cooling demand is increasing, as would be expected from a warming trend. However, weather patterns causing extreme cold are highly variable and show no clear trends. Our findings suggest that although climate change has led to increased cooling demand and decreased heating demand overall, the risk associated with major cold extremes has not diminished. Collectively, the findings from Section 4 emphasize the inadequacy of existing methods used to assess seasonal resource adequacy, and the imperative of making better use of climate models, the complete observational record, and the changing relationship between extreme temperatures and electricity demand to ensure energy system resilience.

Figure E3 — Annually Aggregated Peak Demand for Heating (Red) and Cooling (Blue) in the Region Served by ERCOT

Taken together, the findings of this report show that Texas has a tremendous opportunity to transition away from the coal-fired power plants that are causing a disproportionate share of its climate-warming emissions and air pollution nonattainment challenges and adopt more affordable sources of power. However, intensifying summer heat waves, volatile winter weather, growing power demand, and inadequate transmission within and beyond ERCOT all pose challenges to electric reliability amid this transition. Simultaneous efforts to improve efficiency, expand transmission, add dispatchable resources, and foster continued growth of wind and solar will be needed to overcome these challenges and secure an affordable, sustainable, and reliable power supply for all Texans.

Section 1: Air Quality, Health, and Climate Impacts of Fossil-Fueled Power Plants

Fossil-fueled power plants, especially coal plants, are among the largest emitters of air pollutants and greenhouse gases in Texas, with serious consequences for health and climate. This section provides context on air quality in Texas and the role of power plant emissions. It also discusses how market forces and environmental regulations might lead some coal plants to close or convert to natural gas.

1.1 Texas Air Pollution Challenges: Ozone, Fine Particulate Matter, and SO 2

Air quality management in Texas has long focused mostly on ground-level ozone, since multiple regions have for decades violated federal standards for this potent respiratory irritant. This has led the state to prioritize emissions controls for nitrogen oxides (NO x ), an ozone precursor, rather than sulfur dioxide (SO 2 ), an air pollutant and precursor of fine particulate matter (PM 2.5 denotes particles smaller than 2.5 microns in aerodynamic diameter). State implementation plans issued by the Texas Commission on Environmental Quality (TCEQ) for ozone nonattainment regions required power plants to install control technologies such as low-NO x burners and selective catalytic reduction to reduce their emissions of NO x , but they neglected requirements for SO 2 controls. However, several Texas regions may soon face nonattainment of proposed new EPA standards for PM 2.5 , an air pollutant that is estimated to cause far more deaths and illnesses than all other air pollutants combined. Several other counties violate SO 2 standards near coal-fired power plants.

The Houston-Galveston-Brazoria [2] and Dallas-Fort Worth [3] regions have been in nonattainment of various federal ozone standards since at least 1990. Although peak ozone concentrations have declined since then, both regions — along with El Paso and San Antonio — have failed to attain the more stringent 70 part per billion (ppb) eight-hour ozone standard issued in 2015 (Table 1.1). [4] The design values for the regions based on 2020-22 data are 77 ppb in Dallas-Fort Worth, 81 ppb in El Paso-Las Cruces, 78 ppb in Houston, and 75 ppb in San Antonio. [5] Thus, substantial further reductions in ozone and its precursor emissions are needed. Ozone forms from atmospheric reactions involving nitrogen oxides (NO x ) and hydrocarbons, and tends to be most sensitive to NO x emissions on the hot afternoons that determine attainment of peak ozone standards. [6] Power plants emit 10% of Texas NO x emissions, mostly outside of nonattainment regions, and are thus a contributing but not leading cause of ozone nonattainment in Texas.

Table 1.1 — Ozone Design Values and Nonattainment Status in Texas Regions Based on 2020–22 Data

Fine Particulate Matter (PM 2.5 )

Meanwhile, fine particulate matter (i.e., PM 2.5 , denoting particles smaller than 2.5 microns in diameter) is the deadliest air pollutant [8] and causes substantial health effects — even at levels below the EPA’s 12 microgram per cubic meter (μg/m 3 ) annual standard. [9] However, ongoing attainment of that standard by narrow margins across Texas regions has led Texas regulators to focus less on PM 2.5 and its precursors (e.g., SO 2 and ammonia) than on ozone-forming NO x . With the World Health Organization recommending [10] a PM 2.5 standard of 5 μg/m 3 and the EPA’s Clean Air Science Advisory Committee recommending 8–10 μg/m 3 , [11] further reductions in PM 2.5 and its precursors would help protect public health.

In January 2023, the EPA proposed tightening the annual PM 2.5 standard to a level between 9 and 10 μg/m 3 . [12] Based on PM 2.5 measurements reported to the EPA by TCEQ in 2020–22, Harris, Hidalgo, Kleberg, and Webb counties would violate a 10 g/m 3 standard, and Bowie, Cameron, Dallas, El Paso, Tarrant, and Travis counties would also violate the standard if a 9 g/m 3 limit is chosen (Table 1.2 and Figure 1.1). If those pollution levels persist, TCEQ would — for the first time — need to develop PM 2.5 attainment plans for the Houston, McAllen, Kingsville, and Laredo regions, as well as the Dallas-Fort Worth and Austin regions under a 9 g/m 3 standard. Nonattainment regions typically extend beyond the county with the violating monitor, to ensure that upwind sources are adequately controlled. Thus, substantial portions of the Texas population and industrial facilities could fall within PM 2.5 nonattainment regions for the first time.

Table 1.2 — Annual PM 2.5 Design Values in Texas Counties, Based on 2020–22 Data

Figure 1.1 — Map of Regions That Would Have Exceeded EPA’s Proposed 9 μ g/m 3 or 10 μg/m 3 Annual PM 2.5 Standard Based on 2019–21 Data [13]

It should be noted that TCEQ measures PM 2.5 in only 20 of the state’s 254 counties (Table 1.2) and at far fewer monitors than it operates for ozone. Hybrid analysis synthesizing satellite observations with modeling that the EPA included in its regulatory impact analysis (Figure 1.2) indicates that PM 2.5 may exceed 9 μg/m 3 across many of the state’s most populous regions. This could lead to calls to expand the state’s PM 2.5 monitoring network if the EPA tightens the national standard.

Figure 1.2 — Annual Average PM 2.5 Concentrations Based on a Hybrid Approach Assimilating Satellite Data with Modeling [14]

Sulfur Dioxide (SO 2 )

In 2010, the EPA tightened federal standards for SO 2 , a potent respiratory irritant that is also a precursor of PM 2.5 . Several Texas counties violate SO 2 standards, mostly in the vicinity of coal-fired power plants (Figure 1.3).

Figure 1.3 — Map of Texas SO 2 Nonattainment Areas as of March 2023

1.2 The Role of Power Plant Emissions in Texas Air Pollution

Because they burn more coal and natural gas than those in any other state, Texas power plants lead the nation in emissions of NO x , SO 2 , and CO 2 ­ (Table 1.3). [15] Power plants emit the majority of SO 2 in Texas and large shares of NOx and CO 2 .

Table 1.3 — Power Plant Emissions in Texas in 2021 and Their Share of Texas Emissions Overall and of U.S. Power Plants [16]

The leading role of power plants in SO 2 emissions will make them pivotal to the attainment of the more stringent PM 2.5 standards that the EPA is expected to issue in 2023. Sulfate ranks alongside organic carbon as the top two components of PM2.5 in many regions. [17] Texas lacks sufficient regulatory monitors to adequately speciate the composition of its PM 2.5 . However, scientific field studies have found sulfate to be the largest or second-largest component of particulate matter in several parts of Texas. In eight field studies across various sites in Southeast Texas, sulfate comprised 21%–57% of fine particulate matter (Table 1.4). Since SO 2 is the main precursor of sulfate particulate matter and 59% of Texas SO 2 emissions come from coal-fired power plants, [18] reductions of power plant SO 2 emissions could be pivotal to bringing Texas regions into attainment of tightened PM 2.5 standards.

Table 1.4 — Sulfate Contribution to Particulate Matter in Texas Field Studies

a Ion chromatography

b Quadrupole aerosol mass spectrometer

c Aerosol chemical speciation monitor

d Soot particle aerosol mass spectrometer

e High-resolution time-of-flight aerosol mass spectrometer

* Nonrefractory particles with aerodynamic diameter smaller than 1 micron

All of the coal-fired power plants in ERCOT are located in the eastern half of the state, putting them near the state’s most populous regions and most of the regions that violate the current ozone standard or would exceed a tightened PM 2.5 standard (Figure 1.3 and Tables 1.1 and 1.2). Four additional coal-fired power plants — Harrington, Pirkey, Tolk, and Welsh — operate outside ERCOT in the Southwest Power Pool; all are scheduled to cease coal burning between 2023 and 2028.

Figure 1.4 — Coal Power Plants Operating in ERCOT in 2019

1.3 Implications for Coal Power Plant Retirements

Several coal power plants have closed in Texas since 2017, including Big Brown, Monticello, JT Deely, and Oklaunion. Market forces and environmental regulations are likely to prompt several more coal plants to retire or convert to natural gas by the end of the decade. All 4 GW of the remaining coal power plants in the Texas portion of the Southwest Power Pool (Harrington, Pirkey, Tolk, and Welsh) along with Coleto Creek in ERCOT have announced plans to retire or convert to natural gas by 2028 or sooner. [29] Thus, we will focus on how recent environmental regulations may accelerate the retirements or conversions of remaining coal-fired power plants in ERCOT.

In March 2023, the EPA issued the Good Neighbor Plan, aimed at reducing interstate formation of ozone smog. The plan will shrink ozone-season NO x emissions budgets for each state in cap-and-trade markets, including a nearly 50% cut to the Texas budget from 2023 to 2029 (Figure 1.5). [30] Modeling by the EPA showed that the plan would likely prompt Martin Lake to convert from coal to gas. [31] Additional measures at other plants will be needed to further cut NO x emissions.

Figure 1.5 — Ozone Season NO x Emissions at Texas Power Plants Subject to the Cross-State Air Pollution Rule in 2021 and 2022, and The Emissions Budgets Under EPA’s Good Neighbor Plan for 2023–29 [32]  

In April 2023, the EPA proposed a Regional Haze Plan for Texas that would mandate steep SO 2 emissions reductions at the Parish, Martin Lake, and Coleto Creek coal plants in ERCOT and the Harrington and Welsh power plants in the Southwest Power Pool. [33] The EPA expects Texas power plant SO 2 emissions will fall by more than half under the plan. Since Coleto Creek, [34] Harrington, [35] and Welsh [36] have already announced plans to cease coal operations between 2025 and 2028, the Regional Haze Plan would primarily affect Parish and Martin Lake. Those two plants emitted more SO 2 in 2021 than all other Texas power plants combined. [37] Three units at each plant began operation between 1977 and 1980, just before SO 2 scrubbers were required at all new coal-fired power plants. The units at Martin Lake now have scrubbers that are far less effective than modern designs, whereas the Parish units lack scrubbers altogether. Emissions from Martin Lake are responsible for the SO 2 nonattainment area in Rusk and Panola Counties. TCEQ does not operate any SO 2 monitors near Parish in Fort Bend County.

Table 1.5 summarizes factors that could affect the retirement of ERCOT coal plants. Only Coleto Creek [38] and Limestone [39] have announced retirement dates. The EPA’s proposed Regional Haze Plan for Texas [40] would require Martin Lake to upgrade its scrubbers and two units at Parish to add scrubbers, convert to gas, or retire. The EPA’s Good Neighbor Plan sets Texas’ ozone-season NO x budget at 21,623 tons in 2028, a 54% cut below 2022 emissions at affected sources (Figure 1.5). [41] That cap-and-trade rule will add urgency to cutting NO x emission rates, which averaged 1.24 lb/MWh at Texas coal plants in 2021. [42] Furthermore, in April 2023, the EPA proposed cutting the mercury emissions limit for lignite-burning plants such as San Miguel and Twin Oaks by 70%. [43] Taken together, 8.6 GW of the 13.6 GW of coal power plants in ERCOT would likely need substantial SO 2 and/or NO x emissions controls or a conversion to natural gas to continue operations (Table 1.5). Additional steps may be needed to comply with new effluent limitations on wastewater discharges from steam power plants, which were issued by the EPA in March 2023. [44]

Table 1.5 — Coal Power Plants in ERCOT and Pending Retirements and Emissions Control Needs [45]

Section 2: Complementarity of Wind and Solar Power in Texas

Electricity has historically been produced mainly from sources that can be turned on and off —natural gas, coal, nuclear, and hydropower. These resources are known as “dispatchable” sources of electricity. By contrast, the fastest growing sources of electricity — wind and solar — are “non-dispatchable” because they can generate power only when the wind blows or the sun shines. That poses challenges to electric grid operators. However, if the wind blows and the sun shines at different times, the output of wind and solar farms could complement each other and lessen the number of hours when neither resource is available.

2.1 Prior Publications by the Cohan Research Group

The Cohan research group at Rice University has pioneered research quantifying the complementarity of wind and solar power in ERCOT, most notably with studies published by Joanna H. Slusarewicz and Daniel S. Cohan (2018) and Richard Morse et al. (2022). [46]

The Slusarewicz/Cohan study considered hypothetical wind farms and solar farms in two parts of ERCOT — West Texas, where both wind and solar farms were historically most prevalent, and South Texas, where a growing number of wind farms were being deployed near the coast at the time of the study. Slusarewicz and Cohan showed that, on average, winds blow most strongly in West Texas at night, and along the southern Texas coast on summer afternoons and evenings with the sea breezes. These findings suggest that wind farms from different regions can be complementary with each other and with solar power, which peaks midday when winds tend to be slow.

The Morse study, which was funded by the Energy Foundation, extended beyond the Slusarewicz/Cohan study by considering all wind and solar farms in the ERCOT interconnection queue as of June 2020 (Figure 2.1). Using the NREL System Advisor Model and WIND Toolkit to simulate the hypothetical output of each project under 2009–11 meteorological conditions, Morse et al. found that during the winter, spring, and fall, winds across ERCOT blow most strongly at night, complementing the daytime output of solar farms (Figure 2.2). During summer months, a more spatially heterogeneous pattern emerges, with West Texas winds continuing to peak at night, but winds along the southern Texas coast peaking with afternoon and evening sea breezes, consistent with the Slusarewicz findings.

Figure 2.1 — Wind (Top) and Solar (Bottom) Projects in the ERCOT Interconnection Queue as of June 2020, Aggregated by County [47]

Figure 2.2 — Average Regional Capacity Factor of Wind (Left) and Solar (Right) Sites in ERCOT Interconnection Queue in Peak Demand Months of January (Top), July (Middle), and September (Bottom)  

The complementary output modeled by Morse can also be observed in actual wind and solar generation data in ERCOT in recent years (Figure 2.3). Wind output peaks at night throughout the years, while solar follows expected patterns. Close inspection of the figure shows that in recent years it has been relatively rare for wind capacity factors to drop below 20% at night when solar power is unavailable. As will be shown in Table 2.3, a substantial number of wind and solar projects are now in ERCOT’s interconnection queue in all of these regions.

Figure 2.3 — Wind and Solar Capacity Factors in ERCOT by Hour and Month from 2017–22

Morse et al. conducted optimization modeling to identify combinations of wind and solar projects that could together replace most of the output that ERCOT received from coal-fired power plants. They found that it would be impossible to fully replace coal with wind and solar alone without the use of battery storage or other backup resources. This is due to the fact that there are occasional times when it is neither windy nor sunny anywhere in ERCOT. Instead, the optimization modeling identified a least-cost ensemble of 15,798 MW of wind farms and 10,156 MW of solar farms from the June 2020 queue that would leave just 10% of the output from coal plants uncovered (what the study termed “slack” to be covered by natural gas, storage, or other options), producing surplus output at other times. The output from that ensemble would have fallen below a 20% capacity factor during 8.8% of all half-hour periods in the 2009–11 meteorological conditions considered in that study (Table 2.1). Such low output would have occurred mainly on fall and spring nights, when power demand was relatively low. Surpluses would have occurred during most daylight hours, thanks to the output from solar farms.

Table 2.1 — Frequency of Low Output From a Cost-Optimized Wind and Solar Deployment Scenario Under 2009–11 Meteorological Conditions, and the Average and Maximum Load During Those Times [49]

Four important caveats must be noted that limit the applicability of the Morse study. First, the study did not consider battery storage. Second, the study assumed ample transmission capacity and did not quantify the additional high-voltage transmission lines that would be needed to transmit power from the windiest and sunniest regions to the cities and industrial centers that need it most. Third, the study assumed that wind farms and solar farms perform as well as wind speeds and solar irradiance allow. However, freezing precipitation and condensation during the February 2021 and February 2023 winter storms severely impaired output from many wind farms and some solar farms. [50] Most Texas wind turbines lack de-icing equipment, and solar panels can be covered with snow. Finally, wintertime peak demand has grown dramatically since 2011, as the population has grown and the proportion of homes heated with electric resistance heating or heat pumps has reached 60%. [51] That heightens the importance of studying how all generation resources perform under the freezing precipitation, shifting wind speeds, and frigid temperatures that can accompany winter storms. It should be noted that coal and gas power plants and the natural gas supply suffered severe impairments during the February 2021 freeze, [52] and that coal plants have failed during various other severe weather events. [53]

2.2 Updated Analyses

The Slusarewicz/Cohan and Morse studies were written amid a time of rapid growth in wind and solar in Texas. Wind and solar outputs rose sharply from 2017 through 2022 (Figure 2.4) and are projected to continue to grow.

Figure 2.4 — Wind and Solar Output in ERCOT by Month From 2017–22

ERCOT’s interconnection queue has greatly expanded since the June 2020 queue considered by Morse et al. (Table 2.2). Numerous solar, natural gas, and battery projects have been added to the queue, though wind projects have dipped. Meanwhile, more than 5 GW of wind, 8 GW of solar, and 2 GW of batteries have been built in ERCOT since 2020 (Table 2.2). Proposed projects span each region of ERCOT (Table 2.3). Thus, any update to the Morse study would start from a larger baseline of existing renewable resources and find greater opportunities to add solar projects and complement their variable output with new natural gas plants and batteries.

Table 2.2 — Total Capacity (in MW) of Projects in the ERCOT Generator Interconnection Status Report in June 2020 and January 2023, Compared with Operational Capacity Reported by ERCOT Resource Capacity Trend Charts

Table 2.3 — Regional Distribution of the Wind and Solar Capacity Online in the Summer 2023 Seasonal Assessment of Resource Adequacy, and of the Wind and Solar Projects in the June 2023 ERCOT Generator Interconnection Status Report That Have Requested a Full Interconnection Study

ERCOT expects that solar will continue to lead all other sources of new generation capacity (Figure 2.5). That could ease, rather than worsen, strains on dispatchable resources. Solar power tends to be abundant during summer afternoons when air conditioning use peaks and on days when winds are slow. Thus, it can help satisfy summertime peaks in demand and ease the burden on thermal power plants when winds are slow during daytime hours.

Figure 2.5 — Trends in Generating Capacity from Solar (Upper Left), Wind (Upper Right), Gas Combined Cycle (Lower Left), and Other Gas Power Plants (Lower right), in ERCOT Resource Capacity Trend Charts Issued in January 2023

A closer look at periods of record summer and winter peak demand in 2022 and 2023 (Figure 2.6) suggests that a new paradigm is needed for assessing resource adequacy. When summer demand hit an all-time high of 80 GW on July 20, 2022, [54] wind and solar provided over 15 GW of power (Figure 2.6a). Wind and solar provided 20 GW of power when a new record of 85 GW was set on August 10, 2023 (Figure 2.6b). Peak net load came on August 25, 2023, when gross load was 78 GW, but wind and solar output fell below 8 GW amid slow winds around sunset (Figure 2.6c), prompting a voluntary conservation notice.

When winter demand hit an all-time high of 74 GW on December 23, 2022, wind provided 23 GW of power during nighttime conditions (Figure 2.6d). Tighter conditions and higher prices came later that week, when winds slowed and net load on thermal resources peaked (Figure 2.6d). Seasonal assessments of resource adequacy reports focus on the hours of peak demand , but it is now the hours of peak net load (demand minus variable renewable output), as well as times of unexpectedly high-power plant outages, that pose the greatest risks of shortfalls.

Figure 2.6 — Electricity Generation by Energy Source in ERCOT During the Weeks of Peak Gross Load During (a) Summer of 2022 and (b) Summer of 2023; (c) Peak Net Load in Summer of 2023; and (d) Peak Gross Load in Winter of 2022–23

Those times of peak net load deserve closer scrutiny because they must be satisfied by an aging fleet of thermal power plants. More than 30 GW of power plants in ERCOT are now older than 30 years, including more than 20 GW of power plants that are more than 40 years old (Figure 2.7). Retirements and outages at those plants can threaten reliability as power demand continues to grow.

Figure 2.7 — Dispatchable Resources Sorted by Year Entering Service, as Reported by ERCOT’s Seasonal Assessment of Resource Adequacy for Summer 2022

To examine trends and projections of gross load and net load, we projected gross load to 2025 based on the growth ratios from ERCOT’s 2023 Long-Term Load Forecast Report (Figure 2.8). The forecast anticipates 2.1% annual average growth rates from 2023–32, compared to the 2.6% growth rates that were observed from 2013–22.

Figure 2.8 — Annual Energy Trends and Projections from ERCOT’s 2023 Long-Term Load Forecast

We then plotted cumulative distribution functions of gross load and net load in each hour of 2020–22, where net load was computed by subtracting wind and solar generation from gross load (Figure 2.9a-c). Across those three years, growth in wind and solar output (Figure 2.4) nearly kept pace with growth in load, allowing net load to grow far more slowly than gross load (Figure 2.9a-c) and thus mitigating the burden placed on dispatchable resources. Applying the growth rates from the Long-Term Load Forecast to the three base years of meteorological conditions, we created a synthetic projection of gross load for 2025 (Figure 2.9d). We note that this projection is below the 85 GW record load observed in August 2023 amid a record heat wave, illustrating the potential for extreme weather to drive demand above historical norms.

We then computed wind and solar output based on either the capacity that existed at the end of 2022 (brown swath in Figure 2.9d) or the capacity that is expected in 2025 as wind and solar farms proliferate (brown plus purple swaths). As can be seen in the figure, projected growth in wind and solar is sufficient to nearly eliminate hours when more than 60 GW is needed from dispatchable resources under historical (2020–22) meteorology. However, if adverse policies halt the growth in wind and solar, far greater burdens would be placed on the aging fleet of dispatchable power plants. Projected growth in wind and solar by 2025 would reduce peak net load during the top 100 hours of the year by an average of 4 GW, and by 6 GW during the top 500 hours, while producing an annual average of nearly 8 GW (Figure 2.10). Thus, despite the variability of solar and wind power, their complementary nature and strong performance during heat waves and cold fronts allow them to substantially reduce peak demands on thermal power plants. Still, the 60 GW remaining projected net load in 2025 (Figure 2.9d) (or more under extreme weather conditions) is far greater than the 51 GW that natural gas power plants provided during peak net load in summer 2023 (Figure 2.6d). This indicates that additional dispatchable generation and storage resources will be needed if most coal plants close.

Figure 2.9 — The Cumulative Number of Hours that the ERCOT System has More Than Each Amount of Load Per Year

Figure 2.10 — Extent to Which the New Wind and Solar Farms (9.5GW and 28.6 GW, Respectively) Anticipated to be Added in 2023 and 2024 are Expected to Reduce Net Load in 2025, With Hours Ranked by Net Load

2.3 Energy Efficiency

Since very little new thermal capacity is likely to be added in ERCOT before 2025 (Table 2.2 and Figure 2.3) and most coal plants face environmental challenges (Table 1.5), it will be crucial to consider the demand side of the equation to keep supply and demand in balance. Energy efficiency and demand response are crucial to maintaining the reliability of the grid. The American Council for an Energy Efficient Economy ranks Texas 29th among states for its energy efficiency policies and finds substantial opportunities to improve building efficiency. [55] Texas also lags in its implementation of demand response measures, which specifically aim to reduce peaks in demand. [56]

Although energy efficiency and demand response are beyond the scope of this study, they are likely to be pivotal to efforts to make Texas electricity reliable, affordable, and clean.

Section 3: Opportunities for Geothermal Energy in Texas

Geothermal power plants harness heat from within the Earth to generate electricity. That heat can also be used directly for district heating or certain industries that require low-temperature heat. Life-cycle greenhouse gas emissions from this renewable resource are similar to those from solar photovoltaics and are more than an order of magnitude lower than fossil fuels. [57]

Historically, most geothermal electricity has been generated from hydrothermal resources, where hot water or steam is available at shallow depths. High-quality hydrothermal resources are available at only a limited number of accessible sites nationwide, none of them in Texas (Figure 3.1). Thus, geothermal power plants generated only 17 gigawatt hours (0.4%) of U.S. electricity and virtually none in Texas in 2022, according to data from the U.S. Energy Information Administration.

Figure 3.1 — Geothermal Resources in the United States

Technologies developed by the oil and gas industry can make it possible to access higher temperature fluids at depth in locations that have too little permeability for conventional technologies. Enhanced (or, “engineered”) geothermal systems (EGS) inject fluids deep underground to create flows of hot water that can be used for direct heat or to generate electricity. The Department of Energy (DOE) Frontier Observatory for Research in Geothermal Energy’s (FORGE) site in Utah has enabled companies and researchers to test emerging technologies for EGS. In 2022, DOE established an Enhanced Geothermal Earthshot that aims to bring the cost of EGS down to $45 per megawatt hour by 2035. Researchers are also exploring how geothermal power could be dispatched flexibly to balance fluctuations in load and wind and solar output. [58]

In 2023, researchers from five Texas universities and their collaborators issued a major study on opportunities for geothermal power in Texas. [59] The study noted that EGS or related technologies for closed loop geothermal systems or hybrid approaches could be applicable in Texas if costs come down sufficiently. The study noted that most of the best geothermal resources in Texas are located in the eastern half of the state, including locations in close proximity to major population centers (Figure 3.2).

Ongoing research in the Cohan group, funded by Project InnerSpace, is exploring the extent to which geothermal resources could be deployed in Texas and nationally if costs decline to near the levels sought by the DOE Earthshot. That research is comparing cost estimates from the Geothermal Electricity Technology Evaluation Model (GETEM) and GEOPHIRES model, [60] and using NREL’s Regional Energy Deployment Systems (ReEDS) capacity expansion model to simulate electricity supply, demand, and transmission. Results from that study will be available in late 2023.

Figure 3.2 — Temperatures at 6.5 km Depth in Texas, Based on SMU Geothermal Laboratory Estimates [61]

Because hotter geothermal resources are available in western states and initial deployments are being spurred by regulatory policies in California that require clean firm power, [62] Texas is unlikely to be a hotbed for geothermal deployments this decade. However, Texas companies are taking a leading role in developing advanced geothermal technologies. At least 12 geothermal startups are headquartered in Texas, [63] and various incumbent oil and gas companies are exploring opportunities to invest in geothermal companies or pivot their technologies to geothermal applications. If learning by doing elsewhere is able to bring down the costs of advanced technologies, geothermal could become viable in Texas as a firm and reliable complement to variable wind and solar power.

Section 4: Climatology of Texas Temperature Extremes and Electricity Demand

In recent years Texas has experienced both hot and cold temperature extremes that have strained the energy and electricity systems, highlighting the limitations of existing methods to assess resource adequacy. For example, ERCOT estimates that peak demand without load shedding during the February 2021 cold snap would have been 76,819 GW, [64] which dramatically surpassed ERCOT’s “extreme winter forecast” of 67,208 MW in its seasonal assessment of resource adequacy. [65]

Three issues must be addressed. First, because temperature extremes, particularly cold extremes, are driven by unique weather patterns that occur infrequently, short observational records are inadequate for risk assessments. Instead, extended records and model simulations should be used. Second, climate change has altered and will further increase the frequency and intensity of hot extremes; no trend in cold extremes is significant within the historical record. Third, the relationship between temperature and demand changes rapidly from one year to the next. Collectively, these challenges highlight the limitations of existing approaches to assess resource adequacy.

4.1 Short Observational Records are Inadequate for Risk Assessment

The seasonal assessment of resource adequacy published by ERCOT for the 2020–21 winter [66] used the February 2011 cold snap as a basis for assessing risk. February 2011 saw the coldest weather in several decades across Texas. However, when contextualized within the full historical record, the 2011 cold snap stands out as relatively unexceptional. For example, Figure 4.1 shows temperature anomalies across Texas during historical cold snaps. The most severe one-day, three-day, and five-day periods are shown. Qualitatively, the February 2021 cold snap looks like the February 1951, December 1983, and December 1989 events. The February 2011 cold snap is qualitatively less extreme than the earlier storms. This qualitative comparison suggests that the 2011 cold snap was not particularly extreme when contextualized within the full historical record.

To make these qualitative insights more quantitative, James Doss-Gollin et al. [67] computed the “inferred demand for heating” by i) calculating the amount of heating needed at each grid cell to reach a comfortable indoor temperature and then ii) aggregating across each grid cell in the region served by ERCOT, weighting each cell by its 2020 population. Then, the annual maximum series of the aggregated inferred demand for heating were computed. Figure 4.2(a) shows the time series of the peak six-hour and two-day demands for heating for each year in the dataset. At the six-hour duration, the 1989 cold snap was colder than the February 2021 storm, and others were nearly as cold at both durations. Figure 4.2(b) shows the estimated return periods for the 2021, 1989, and 2011 storms. While the specific values (2021 is estimated to be a 50-to-100-year event, depending on duration) are sensitive to methodological assumptions and should be interpreted with care, the overall finding that the February 2021 cold snap had multiple precedents within the historical record is robust.

Figure 4.1 — Temperature Anomalies During the February 2021 Cold Snap Were Qualitatively Similar to Those Experienced in Previous Storms

Figure 4.2 (a) — Time Series of the Annual Maximum Inferred Demand for Heating at the Six-Hour and Two-Day Durations; (b) — Estimated Return Periods for the 1989, 2011, and 2021 Storms at Different Durations

Although the February 2021 cold snap had substantial precedent when aggregated across the state, there were specific locations that experienced more severe cold. Figure 4.3 shows the estimated local return periods. Some areas (bright yellow) experienced cold in February 2021 that they would have expected to exceed with 1% probability in a given year. In most areas, however, including locations where specific infrastructure components failed, the return period was between 20 and 50 years. As for Figure 4.2b, the specific values are sensitive to methodology and should be interpreted with caution.

Figure 4.3 (a) — Population Density in 2020; (b, c, e, f) — Estimated Return Period of the Cold Observed in February 2021 at Each Grid Cell (Contours Show 50- and 100-year Levels); (d) — Location of Electricity Generation Infrastructure

4.2 Effects of Climate Change on Temperature Extremes

While most electricity systems are designed to handle peak demand during summer months, pathways to deep decarbonization generally electrify building heating, thus increasing electricity demand during winter. A key question is how climate variability and change will affect peak heating and cooling demand in an electrified future.

A collaborative analysis between the Doss-Gollin lab at Rice University and a research team from Columbia University assessed trends in temperature-based proxies for electricity demand over the past 70 years. In Texas, demand for heating (cooling) decreases (increases) over most of the contiguous U.S. However, while climate change drives robust increases in peak cooling demand, trends in peak heating demand are generally smaller and less robust. Because the distribution of temperature exhibits a fat left tail, severe cold snaps dominate the extremes of thermal demand. As building heating electrifies, system operators such as ERCOT must account for these events to ensure reliability.

Total annual demand for heating (Figure 4.4, red line) has been slowly decreasing since 1980, while total demand for cooling has been increasing (Figure 4.4, blue line). These effects are broadly consistent with the first-order warming effects of climate change. Combined, the total demand for heating and cooling (calculated in degrees Fahrenheit as in Section 4.1) is roughly constant (black line), though it is important to note that because this demand does not account for the efficiency of heating, the energy source considered, or building characteristics, it does not correspond directly to electricity demand (see Section 4.3).

Figure 4.4 — Annually Aggregated Mean Inferred Demand for Heating (Red) and Cooling (Blue), and Total (Black) in the Region Served by ERCOT

While trends in demand for heating and cooling are important for understanding total energy requirements, understanding trends in peaks is important for assessing system risks. Figure 4.5 shows the trends in annual peak demands for heating and cooling. Peak demand for cooling, i.e. the hottest 24 hours of the summer, shows a small, possibly zero, upward trend. Taken with Figure 4.4, this suggests that the effect of warming on Texas demand for cooling has been primarily to increase the number of hot days rather than a large increase in how hot these days are. Peak demand for heating (red line) shows much larger interannual variability than demand for heating. No trend is readily apparent. As noted in Section 4.1, the large interannual variability of cold extremes means that the recent past is insufficient for risk assessment.

An important point is that most U.S. electricity systems, including ERCOT, are designed to meet peak loads during summer months, when demand for cooling peaks. However, infrequent but severe cold temperatures may lead the largest electricity demands to occur during rare winter peaks, particularly as the electrification of home heating continues (see Section 4.3).

Figure 4.5 — Annually Aggregated Peak Demand for Heating (Red) and Cooling (Blue) in the Region Served by ERCOT

4.3 Response of Demand for Electricity to Peak Temperatures

Assessing resource adequacy involves mapping scenarios of possible temperatures onto electricity demand. This is a challenging and imprecise task because the relationship between temperature and electricity demand evolves rapidly over time due to changing demographics, technologies, industrial needs, and other factors. This is illustrated in Figure 4.6, which shows how the relationship between temperature and daily average power demand has changed from 1996 to 2020 using data from ERCOT. [70]

Figure 4.6 — Relationship Between Temperature and Electricity Demand in 1996 Versus 2020

Different studies have used different methods to model the response of electricity to temperature. For example, Jangho Lee and Andrew Dessler use a polynomial regression model while Blake Shaffer, Daniel Quintero, and Joshua Rhodes use a temperature fixed effects model. [71] Both identify two challenges. The first is that there is, by definition, a lack of data at the extremes, meaning that estimates of electricity demand at temperatures that have been experienced rarely or not at all in the recent historical record are subjective and difficult to verify a priori. The second is that the relationship evolves over time, as shown in Figure 4.6, and because this change depends on factors like the rate of adoption of electric vehicles, the price of heat pumps, and the speed of population growth, it is difficult to model accurately.

Section 5: Conclusion

The research and data synthesized here provide important insights as Texas works to improve the reliability and sustainability of its power supply amid a changing climate. The power grid of today leaves Texans vulnerable to outages under extreme weather conditions even as emissions from coal plants damage our air quality, health, and climate. Environmental regulations and economic factors are likely to drive the closures of some coal-fired power plants, heightening the need to add other resources to meet the needs of a growing economy.

Continued growth in wind and solar generation is crucial to easing the burden on other resources. Our research has demonstrated that wind and solar power production tend to be complementary in Texas, including during times of peak demand. Nevertheless, wind and solar resources leave key gaps, especially around sunset and during winter freezes, that must be met by dispatchable resources. Energy efficiency and demand response can curb growth in electricity demand and make it more flexible. Still, there will be a need for construction of more dispatchable generation and storage resources along with transmission to enhance the reliability and resilience of electricity in ERCOT.

Taken together, our research shows that Texas has a tremendous opportunity to transition away from the coal plants that are causing a disproportionate share of its climate-warming and health-damaging emissions. However, intensifying summer heat waves, volatile winter weather, growing power demand, and inadequate transmission within and beyond ERCOT all pose challenges to electric reliability amid this transition. Simultaneous efforts to improve efficiency, expand transmission, add dispatchable resources, and foster continued growth of wind and solar will be needed to overcome these challenges and secure an affordable, sustainable, and reliable power supply for all Texans.

Acknowledgments

Funding for this study was provided by the Energy Foundation. The authors acknowledge Chen Chen for analysis of wind, solar, and load data and Chun-Ying Chao for a literature review of particulate matter measurements in Texas.

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[30] EPA, “State Budgets under the Good Neighbor Plan for the 2015 Ozone NAAQS,” accessed April 27, 2023, https://www.epa.gov/csapr/state-budgets-under-good-neighbor-plan-2015-ozone-naaqs .

[31] EPA, “State Budgets under the Good Neighbor Plan for the 2015 Ozone NAAQS.”

[32] EPA, “Clean Air Power Sector Programs: Ozone Season Data 2021 vs. 2022,” accessed April 27, 2023, https://www.epa.gov/power-sector/facility-level-comparisons#OzoneSeason ; EPA, “State Budgets under the Good Neighbor Plan for the 2015 Ozone NAAQS.”

[33] EPA, “Revision and Promulgation of Air Quality Implementation Plans; Texas; Regional Haze Federal Implementation Plan; Disapproval and Need for Error Correction; Denial of Reconsideration of Provisions Governing Alternative to Source-Specific Best Available Retrofit Technology (BART) Determinations,” Code of Federal Regulations, Title 40, Parts 52, 78, and 97 (2023): 1–216, https://www.epa.gov/system/files/documents/2023-04/Texas%20BART%20FIP_NPRM_2023-04-19_ADMIN_signed%20pre-publication%20copy.pdf .

[34] “Mark Rosenberg, “Coleto Creek Power Plant shutting down by 2027,” Victoria Advocate , updated November 4, 2022, https://www.victoriaadvocate.com/counties/goliad/coleto-creek-power-plant-shutting-down-by-%202027/article_261596c8-342b-11eb-92e8-0f9c2d927a2b.html .

[35] Frazier, “Xcel Energy’s Harrington Power Plant to convert to natural gas by 2025.”

[36] Darren Sweeney, Taylor Kuykendall, and Anna Duquiatan, “More than 23 GW of coal capacity to retire in 2028 as plant closures accelerate,” S&P Global Market Intelligence , February 10, 2022, https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/more-than-23-gw-of-coal-capacity-to-retire-in-2028-as-plant-closures-accelerate-68709205 .

[37] EPA, eGRID Data Explorer .

[38] Rosenberg, “Coleto Creek Power Plant shutting down by 2027.”

[39] “Limestone Generating Station,” Global Energy Monitor Wiki, accessed April 27, 2023, https://www.gem.wiki/Limestone_Generating_Station .

[40] EPA, “Revision and Promulgation of Air Quality Implementation Plans,” Code of Federal Regulations, Title 40, Parts 52, 78 and 97.

[41] EPA, eGRID Data Explorer .

[42] EPA, eGRID Data Explorer .

[43] EPA, “Biden-Harris Administration Proposes to Strengthen the Mercury and Air Toxics Standards for Power Plants,” news release, April 5, 2023, https://www.epa.gov/newsreleases/biden-harris-administration-proposes-strengthen-mercury-and-air-toxics-standards-power .

[44] EPA, “Effluent Limitations Guidelines and Standards for the Steam Electric Power Generating Point Source Category-Initial Notification Date Extension,” Federal Register 88, no. 60 (March 29, 2023): 18440, https://www.federalregister.gov/documents/2023/03/29/2023-04985/effluent-limitations-guidelines-and-standards-for-the-steam-electric-power-generating-point-source.

[45] EPA, eGRID Data Explorer .

[46] Joanna H. Slusarewicz and Daniel S. Cohan, “Assessing Solar and Wind Complementarity in Texas,” Renewables: Wind, Water & Solar 5, no. 1 (2018): 7, https://doi.org/10.1186/s40807-018-0054-3 ; Morse et al., “Can Wind and Solar Replace Coal in Texas?”

[47] Morse et al., “Can Wind and Solar Replace Coal in Texas?”

[48] Morse et al., “Can Wind and Solar Replace Coal in Texas?”

[49] Morse et al., “Can Wind and Solar Replace Coal in Texas?”

[50] Electric Reliability Council of Texas (ERCOT), “Update to April 6, 2021 Preliminary Report on Causes of Generator Outages and Derates During the February 2021 Extreme Cold Weather Event,” 2021, https://bit.ly/3SxF9pU ; “The Timeline and Events of the February 2021 Texas Electric Grid Blackouts,” The University of Texas at Austin Energy Institute, July 2021, https://bit.ly/3QRLdZ3 ; Diana DiGangi, “Texas Wind Energy Freeze-out Shows Need for Better Resource Adequacy, Says NRG VP,” Utility Dive , February 6, 2023, https://www.utilitydive.com/news/texas-wind-freezout-renewables-resource-adequacy/642031/ .

[51] Blake Shaffer, Daniel Quintero, and Joshua Rhodes, “Changing Sensitivity to Cold Weather in Texas Power Demand,” iScience 25, no. 4 (2022): 104173, https://doi.org/10.1016/j.isci.2022.104173 .

[52] ERCOT, “Update to April 6, 2021 Preliminary Report on Causes of Generator Outages and Derates During the February 2021 Extreme Cold Weather Event.”

[53] Benjamin Storrow, “How Coal Failed in the Texas Deep Freeze,” E&E News , March 18, 2021, https://www.eenews.net/articles/how-coal-failed-in-the-texas-deep-freeze/ .

[54] ERCOT, “Summer 2022 Operational and Market Review,” 2022, https://bit.ly/40shFEg .

[55] Sagarika Subramanian et al., “2022 State Energy Efficiency Scorecard,” ACEEE, December 2022, https://www.aceee.org/sites/default/files/pdfs/u2206.pdf .

[56] Federal Energy Regulatory Commission (FERC), “2021 Assessment of Demand Response and Advanced Metering,” December 2021, https://bit.ly/47pvaH0 .

[57] National Renewable Energy Laboratory, “Life Cycle Assessment Harmonization,” accessed July 26, 2020, https://www.nrel.gov/analysis/life-cycle-assessment.html .

[58] Dev Millstein, Patrick Dobson, and Seongeun Jeong, “The Potential to Improve the Value of U.S. Geothermal Electricity Generation Through Flexible Operations,” Journal of Energy Resources Technology 143, no. 1 (2021), https://doi.org/10.1115/1.4048981 ; Wilson Ricks, Jack Norbeck, and Jesse Jenkins, “The Value of In-Reservoir Energy Storage for Flexible Dispatch of Geothermal Power,” Applied Energy 313 (2022): 118807, https://doi.org/10.1016/j.apenergy.2022.118807 .

[59] Jamie Beard et al., The Future of Geothermal in Texas: The Coming Century of Growth & Prosperity in the Lone Star State , accessed March 11, 2023, https://energy.utexas.edu/research/geothermal-texas .

[60] Gregory L. Mines, “GETEM User Manual,” Idaho National Laboratory, July 2016, https://workingincaes.inl.gov/SiteAssets/CAES%20Files/FORGE/inl_ext-16-38751%20GETEM%20User%20Manual%20Final.pdf ; Koenraad F. Beckers and Kevin McCabe, “GEOPHIRES v2.0: Updated Geothermal Techno-Economic Simulation Tool,” Geothermal Energy 7, no. 1 (2019): 5, https://doi.org/10.1186/s40517-019-0119-6 .

[61] Beard et al., The Future of Geothermal in Texas .

[62] California Public Utilities Commission Energy Division (CPUC), “CPUC Orders Historic Clean Energy Procurement To Ensure Electric Grid Reliability and Meet Climate Goals,” June 24, 2021, https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-orders-clean-energy-procurement-to-ensure-electric-grid-reliability .

[63] Michelle Lewis, “Here’s Why Texas Is a Geothermal Energy ‘Sleeping Giant,’” Electrek , January 25, 2023, https://electrek.co/2023/01/25/texas-geothermal-energy/ .

[64] B. Magness, “Review of February 2021 Extreme Cold Weather Event,” ERCOT, 2021, accessed May 2, 2021, https://bit.ly/3u7rg7H .

[65] ERCOT, “Final Seasonal Assessment of Resource Adequacy for the ERCOT Region (SARA): Winter 2020/2021,” 2020, accessed May 2, 2021, http://www.ercot.com/content/wcm/lists/197378/SARA-FinalWinter2020-2021.pdf .

[66] ERCOT, “Final Seasonal Assessment of Resource Adequacy for the ERCOT Region (SARA): Winter 2020/2021.”

[67] James Doss-Gollin et al., “How Unprecedented Was the February 2021 Texas Cold Snap?” Environmental Research Letters 16, no. 6 (2021), https://doi.org/10.1088/1748-9326/ac0278 .

[68] Hans Hersbach et al., “The ERA5 Global Reanalysis,” Quarterly Journal of the Royal Meteorology Society 146, no. 730 (2020): 1999–2049, https://doi.org/10.1002/qj.3803 .

[69] Doss-Gollin et al., “How Unprecedented Was the February 2021 Texas Cold Snap?”

[70] Jangho Lee and Andrew E. Dessler, “The Impact of Neglecting Climate Change and Variability on ERCOT’s Forecasts of Electricity Demand in Texas,” Weather, Climate, and Society 14, no. 2 (2022): 499–505, https://doi.org/10.1175/WCAS-D-21-0140.1 .

[71] Lee and Dessler, “The Impact of Neglecting Climate Change and Variability on ERCOT’s Forecasts of Electricity Demand in Texas”; Shaffer, Quintero, and Rhodes, “Changing Sensitivity to Cold Weather in Texas Power Demand.”

This material may be quoted or reproduced without prior permission, provided appropriate credit is given to the author and Rice University’s Baker Institute for Public Policy. The views expressed herein are those of the individual author(s), and do not necessarily represent the views of Rice University’s Baker Institute for Public Policy.

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How the Massive Growth in Solar Power Is Affecting Power Grids

The Solar Energy Industries Association (SEIA) reported in March that the U.S. solar industry installed 32.4 GWdc of capacity in 2023 , a remarkable 51% increase compared to 2022. It was the industry’s biggest year by far, exceeding 30 GWdc of capacity for the first time. Overall, photovoltaic (PV) solar accounted for 53% of all new U.S. electricity-generating capacity additions in 2023, making up more than half of new generating capacity for the first time. The utility, commercial and industrial, and residential sectors all set annual installation records, while the community solar sector was within 5 MWdc of an annual record.

Yet, this is not just a U.S. story, solar capacity is growing exponentially around the world. In its Renewables 2023 report , the International Energy Agency (IEA) said 2023 saw a step change in renewable capacity additions, driven by China’s solar PV market. It said global annual renewable capacity additions increased by almost 50% to nearly 510 GW last year—the fastest growth rate in the past two decades. 2023 was the 22nd year in a row that renewable capacity additions set a new record, according to the IEA.

While the increases in renewable capacity in Europe, the U.S., and Brazil hit all-time highs, China’s acceleration was extraordinary. In 2023, China commissioned as much solar PV as the entire world did in 2022. Solar PV accounted for three-quarters of renewable capacity additions worldwide.

Utility-scale projects are what really drive the industry. In the U.S., utility-scale installations spiked to 22.5 GWdc of capacity, according to SEIA, a 77% increase over 2022. The temporary moratorium on anticircumvention tariffs applicable to certain imports from four Southeast Asian countries brought some relief to the solar supply chain, helping projects move forward last year. The moratorium ends in June 2024, however, so we’ll see how that affects projects in the second half of this year.

The Texas Grid Evolves

Texas was the leading state for solar installations in 2023. Since 2021, more than 15 GW of new solar capacity has been added in Texas. Furthermore, SEIA predicts Texas will lead the nation with nearly 100 GW of new solar capacity additions from 2024 to 2034, outpacing the next closest state by a two-to-one margin.

According to the Electric Reliability Council of Texas (ERCOT), the grid operator for about 90% of the load in Texas, solar generation supplied 32.4 TWh to its grid in 2023—7.29% of the annual total. In the first quarter of 2024, the percentage increased to 8.16%, which is notable because the winter season is not typically a prime period for solar production. It’s also notable in that solar was not far behind nuclear (9.92%) or coal (12.10%) in ERCOT’s first quarter energy mix. Natural gas–fired generation (40.42%) and wind (29.41%) were the clear leaders in Texas , however.

While solar only accounts for 13.2% of Texas’ installed capacity, according to ERCOT’s December 2023 Capacity, Demand, and Reserves (CDR) report for Summer 2024 , it can have a significant impact on the grid during peak times. An April 2024 ERCOT fact sheet shows the solar generation record of 18,881 MW was set on March 28 this year. The solar penetration record was also set that day at 42.98%. While those numbers are astounding, it seems likely that the generation record will be eclipsed sometime this summer, and on a regular basis in the not-to-distant future.

The Duck Curve Waddles into Texas

The increase in solar generation in Texas is starting to create a duck curve in the ERCOT grid, similar to what has long been observed in the California Independent System Operator’s (CAISO’s) grid. For a little background, the duck curve was first brought to light in 2013 when CAISO published a chart that showed the difference in electricity demand and the amount of available solar energy throughout the day. The curve was a snapshot of a 24-hour period in California during springtime, which is when the effect is most extreme because it’s sunny but temperatures remain cool, so demand for electricity is low because people don’t need to use much electricity for air conditioning or heating. CAISO showed how the pattern created by the midday dip in the net load curve, followed by a steep rise in the evening when solar generation drops off, looks like the outline of a duck, hence the name.

Since 2013, California’s duck curve has only gotten deeper as more and more solar power has been added to the CAISO grid. In fact, on some days, the net demand curve is going negative in California.

The situation in Texas is nowhere near as extreme as that seen in California. However, the increase in solar generation is beginning to have a noticeable effect. The U.S. Energy Information Administration (EIA) published an article on April 9 comparing ERCOT’s average hourly electricity generation in winter 2022–2023 to winter 2023–2024 . The solar-caused dip was distinctively larger this past winter. Furthermore, it’s been observed that the duck curve is increasingly occurring in other parts of the world in places where the share of solar generation is growing compared to generation from conventional sources.

Every power grid is different and operators will end up dealing with increases in solar capacity in their own unique ways. In ERCOT’s case, it has much more dispatchable gas-fired generation to play with than CAISO does and its significant wind resources tend to complement solar rather than amplifying the problem, so it may have an easier time managing the situation, at least for the time being.

— Aaron Larson is POWER’s executive editor.

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Advanced Nuclear Power Reactors

• Improved designs of nuclear power reactors are constantly being developed internationally.
• The first so-called Generation III advanced reactors have been operating in Japan since 1996. These have now evolved further.
• Newer advanced reactors now being built have simpler designs which are intended to reduce capital cost. They are more fuel efficient and are inherently safer.
• Many new designs are small – up to 300 MWe. These are described in a separate information paper.*

* For smaller advanced reactors see the companion page on Small Nuclear Power Reactors .

The nuclear power industry has been developing and improving reactor technology for more than five decades and is starting to build the next generation of nuclear power reactors to fill new orders.

Several generations of reactors are commonly distinguished. Generation I reactors were developed in 1950-60s, and the last one shut down in the UK in 2015. Generation II reactors are typified by the present US and French fleets and most in operation elsewhere. So-called Generation III (and III+) are the advanced reactors discussed in this paper, though the distinction from Generation II is arbitrary. The first ones are in operation in Japan and others are under construction in several countries. Generation IV designs are still on the drawing board and will not be operational before the 2020s.

Over 85% of the world's nuclear electricity is generated by reactors derived from designs originally developed for naval use. These and other nuclear power units now operating have been found to be safe and reliable, but they are being superseded by better designs.

Reactor suppliers in North America, Japan, Europe, Russia, China and elsewhere have a dozen new nuclear reactor designs at advanced stages of planning or under construction, while others are at a research and development stage. Fourth-generation reactors are at the R&D or concept stage.

So-called third-generation reactors have:

• A more standardized design for each type to expedite licensing, reduce capital cost and reduce construction time.
• A simpler and more rugged design, making them easier to operate and less vulnerable to operational upsets.
• Higher availability and longer operating life – typically 60 years.
• Further reduced possibility of core melt accidents.*
• Substantial grace period, so that following shutdown the plant requires no active intervention for (typically) 72 hours.
• Stronger reinforcement against aircraft impact than earlier designs, to resist radiological release.
• Higher burn-up to use fuel more fully and efficiently, and reduce the amount of waste.
• Greater use of burnable absorbers ('poisons') to extend fuel life.

* The US NRC requirement for calculated core damage frequency (CDF) is 1x10 -4 , most current US plants have about 5x10 -5 and Generation III plants are about ten times better than this. The IAEA safety target for future plants is 1x10 -5 . Calculated large release frequency (for radioactivity) is generally about ten times less than CDF.

The greatest departure from most designs now in operation is that many incorporate passive or inherent safety features* which require no active controls or operational intervention to avoid accidents in the event of malfunction, and may rely on gravity, natural convection or resistance to high temperatures.

* Traditional reactor safety systems are 'active' in the sense that they involve electrical or mechanical operation on command. Some engineered systems operate passively, eg pressure relief valves. They function without operator control and despite any loss of auxiliary power. Both require parallel redundant systems. Inherent or full passive safety depends only on physical phenomena such as convection, gravity or resistance to high temperatures, not on functioning of engineered components, but these terms are not properly used to characterize whole reactors.

Another departure is that most will be designed for load-following. European Utility Requirements (EUR) since 2001 specify that new reactor designs must be capable of load-following between 50 and 100% of capacity. While most French reactors are operated in that mode to some extent, the EPR design has better capabilities. It will be able to maintain its output at 25% and then ramp up to full output at a rate of 2.5% of rated power per minute up to 60% output and at 5% of rated output per minute up to full rated power. This means that potentially the unit can change its output from 25% to 100% in less than 30 minutes, though this may be at some expense of wear and tear.

A feature of some new designs is modular construction. The means that many small components are assembled in a factory environment (offsite or onsite) into structural modules weighing up to 1000 tonnes, and these can be hoisted into place. Construction is speeded up.

Many are larger than predecessors. Increasingly they involve international collaboration.

However, certification of designs is on a national basis, and is safety-based – see section below .

Another feature of some new designs is modular construction. Large structural and mechanical sections of the plant of up to 1000 tonnes each are manufactured in factories or on site adjacent to the plant and lifted into place, potentially speeding construction.

A contrast between the 1188 MWe Westinghouse reactor at Sizewell B in the UK and the modern Westinghouse AP1000 of similar power illustrates the evolution from 1970-80 types. First, the AP1000 footprint is very much smaller – about one-quarter the size, secondly the concrete and steel requirements are lower by a factor of five*, and thirdly it has modular construction. A single unit has 149 structural modules broadly of five kinds, and 198 mechanical modules of four kinds: equipment, piping & valve, commodity, and standard service modules. These comprise one-third of all construction and can be built offsite in parallel with the onsite construction.

* Sizewell B: 520,000 m 3  concrete (438 m 3 /MWe), 65,000 t rebar (55 t/MWe);  AP1000: <100,000 m 3  concrete (90 m 3 /MWe, <12,000 t rebar (11 t/MWe).

At Sanmen and Haiyang in China, where the first AP1000 units were grid connected in August 2018, the first module lifted into place weighed 840 tonnes. More than 50 other modules used in the reactors' construction weigh more than 100 tonnes, while 18 weigh in excess of 500 tonnes.

US, EU and UK design certification

In the USA, the federal Department of Energy (DOE) and the commercial nuclear industry in the 1990s developed four advanced reactor types. Two of them fell into the category of large 'evolutionary' designs which build directly on the experience of operating light water reactors in the USA, Japan and Western Europe. These reactors are in the 1300 megawatt range.

One was an advanced boiling water reactor (ABWR) derived from a General Electric design and then promoted both by GE Hitachi and Toshiba as a proven design, which is in service in Japan and was being built in Taiwan. Four are planned in the UK.

The other type, System 80+, was an advanced pressurized water reactor, which was ready for commercialization but was never promoted for sale. It was the basis of the Korean Next Generation Reactor programme and many of its design features are incorporated into eight South Korean reactors, specifically the APR1400, which is operating in South Korea and being built in South Korea and the UAE and marketed worldwide.

The US Nuclear Regulatory Commission (NRC) gave final design certification for both in May 1997, noting that they exceeded NRC "safety goals by several orders of magnitude". The ABWR has also been certified as meeting European utility requirements for advanced reactors and is undergoing the generic design assessment process in the UK ( see below ).

Another, more innovative US advanced reactor was smaller – 600 MWe – and had passive safety features (its projected core damage frequency is more than 100 times less than NRC requirements). The Westinghouse  AP600  gained NRC final design certification in 1999 (AP = Advanced Passive).

These NRC approvals were the first such generic certifications to be issued and were valid for 15 years. As a result of an exhaustive public process, safety issues within the scope of the certified designs were fully resolved and hence are not open to legal challenge during licensing for particular plants. Using such certified designs, US utilities are able to obtain a single NRC licence to both construct and operate a reactor before construction begins.

Both GE Hitachi and Toshiba in 2010 submitted separate applications to renew the US design certification for their respective versions of the ABWR (Toshiba's incorporating design changes already submitted to the NRC in connection with the South Texas Project combined construction and operating licence application). The Japanese version of it differs in allowing modular construction, so is not identical to that licensed in the USA. In mid-2016 Toshiba withdrew its design certification renewal application, and in August 2017 GE Hitachi put its review by the NRC on hold.

Separate from the NRC process and beyond its immediate requirements, the US nuclear industry selected one standardized design in each category – the large ABWR and the medium-sized AP600, for detailed first-of-a-kind engineering (FOAKE) work. The US$ 200 million program was half funded by DOE and meant that prospective buyers then had fuller information on construction costs and schedules.

The 1100 MWe-class Westinghouse  AP1000 , scaled-up from the AP600, received final design certification from the NRC in December 2005 – the first Generation III+ type to do so. It represented the culmination of a 1300 man-year and $440 million design and testing program. In May 2007 Westinghouse applied for UK generic design assessment (GDA, pre-licensing approval) based on the NRC design certification, and expressing its policy of global standardization. The application was supported by European utilities, and was granted in 2017.

Overnight capital costs were projected to be very competitive with older designs, and modular design is expected to reduce construction time eventually to 36 months. The AP1000 generating costs are also expected to be very competitive and it has a 60-year operating life. It is being built in China (four units under construction, with many more to follow) and in the USA (initially four units at two sites). It is planned for building in the UK. It is capable of running on a full MOX core if required.

In February 2008 the NRC accepted an application from Westinghouse to amend the AP1000 design, and this review was completed with revised design certification in December 2011. The NRC chairman said that the revised AP1000 design is one that seems to most fully meet the expectations of the commission’s policy statement on advanced reactors. "The design provides enhanced safety margins through use of simplified, inherent, passive or other innovative safety and security functions, and also has been assessed to ensure it could withstand damage from an aircraft impact without significant release of radioactive materials." This design change increased the capital cost.

In December 2016 Westinghouse requested the NRC to extend the design certification of its AP1000 reactor for five years from 2021 to 2026. In the light of operational experience of the first few reactors it would then apply for renewal of US design certification.

The ESBWR from GE Hitachi received US design certification in September 2014.

The South Korean APR1400 received US design certification in August 2019.

In January 2017 NuScale submitted its small modular reactor design to the NRC for design certification. The application consisted of nearly 12,000 pages of technical information. The certification process is expected to take 40 months. See information page on Small Nuclear Power Reactors for reactor details.

Longer term, the NRC expected to review the Next Generation Nuclear Plant (NGNP) for the USA (see  US Nuclear Power Policy information page) – essentially the Very High Temperature Reactor (VHTR) among the  Generation IV  designs. It will also focus on small reactor designs.

In Europe there are moves towards harmonized requirements for licensing. Here, since 1991, reactors may also be certified according to compliance with European Utility Requirements (EUR) of 12 generating companies, which have stringent safety criteria. The EUR are essentially a utilities' wish list of some 5000 items needed for new nuclear plants. Designs certified as complying with EUR include Westinghouse's AP1000, Gidropress's AES-92 and VVER-TOI, Areva's EPR, Mitsubishi’s EU-APWR and in 2017 KHNP's APR1400 (EU-APR). GE's ABWR, Areva's Kerena, and Westinghouse's BWR 90 also have some measure of EUR approval. China's Hualong One – EU HPR1000 – joined them in 2020 in meeting EUR.

European regulators are increasingly requiring large new reactors to have some kind of core catcher or similar device, so that in a full core-melt accident there is enhanced provision for cooling the bottom of the reactor pressure vessel or simply catching any material that might melt through it. The EPR and VVER-1200 have core-catchers under the pressure vessel, the AP1000 and APWR have provision for enhanced water cooling.

The UK’s Office for Nuclear Regulation (ONR) undertakes generic design assessment (GDA) of nuclear reactors. A GDA of each type can then be followed by site- and operator-specific licensing. ONR made initial assessments of four designs which were submitted in 2007: UK EPR for Areva, AP1000 for Westinghouse, ESBWR for GE Hitachi, and ACR-1000 for AECL in Canada. The latter two were withdrawn from the process in 2008 and in 2013 the GE Hitachi ABWR was added. The ONR and Environment Agency jointly issued design acceptance confirmations (DAC), and statements on design acceptability (SODA) for the EPR December 2012, and for the AP1000 in March 2017. In 2013 Hitachi-GE applied for UK generic design approval for the ABWR, and after some design changes this is likely to be granted at the end of 2017.

As the GDA for the EPR design proceeded, issues arose which were in common with new capacity being built elsewhere, particularly the EPR units in Finland and France. This led to international collaboration and a joint regulatory statement on the EPR instrumentation and control among ONR, US NRC, France's ASN and Finland's STUK. More broadly it relates to the Multinational Design Evaluation Programme and will help improve the harmonization of regulatory requirements internationally.

In 2012 Rosatom announced that it intended to apply for design certification for its VVER-TOI reactor design of 1200 MWe, with a view to Rusatom Overseas building them in UK.

In 2016 China General Nuclear Power Group (CGN) applied for GDA for the 1150 MWe Hualong One (HPR1000) reactor design, with a view to building it at Bradwell. General Nuclear Systems, a joint venture with EDF holding 33.5% and CGN 66.5%, was formed for progressing the GDA, which commenced in January 2017 and moved to its fourth and final stage in February 2020.

Small modular reactors (SMRs) are a further GDA task impending for the ONR.

Joint initiatives and collaboration

Three major international initiatives have been launched to define future reactor and fuel cycle technology, mostly looking further ahead than the main subjects of this paper:

The Multinational Design Evaluation Programme ( MDEP ) was launched in 2006 by the US NRC and the French Nuclear Safety Authority (ASN) to develop innovative approaches to leverage the resources and knowledge of national regulatory authorities reviewing new reactor designs. It is led by the OECD Nuclear Energy Agency and involves the IAEA. Ultimately it aims to develop multinational regulatory standards for design of Gen IV reactors. The US Nuclear Regulatory Commission (NRC) has proposed a three-stage process culminating in international design certification for new reactor types, notably Generation IV types. Twelve countries are involved so far: Canada, China, Finland, France, India (from 2012), Japan, Korea, Russia, South Africa, Sweden (from 2013), UK, USA, and others which have or are likely to have firm commitments to building new nuclear plants may be admitted – the UAE is an associate member.

The MDEP pools the resources of its member nuclear regulatory authorities for the purpose of: 1) co-operating on safety reviews of designs of nuclear reactors that are under construction and undergoing licensing in several countries; and 2) exploring opportunities and potential for harmonization of regulatory requirements and practices. It also produces reports and guidance documents that are shared internationally beyond the MDEP membership.

The Generation IV International Forum (GIF) is a US-led grouping set up in 2001 which has identified six reactor concepts for further investigation with a view to commercial deployment by 2030. See Generation IV Nuclear Reactors information page.

The IAEA's International Project on Innovative Nuclear Reactors and Fuel Cycles (INPRO) is focused more on developing country needs, and initially involved Russia rather than the USA, though the USA has now joined it. It is now funded through the IAEA budget.

At the commercial level, by the end of 2006 three major Western-Japanese alliances had formed in the world reactor supply market, and since then another has become prominent:

• Areva with Mitsubishi Heavy Industries (MHI) in a major project and subsequently in fuel fabrication.
• General Electric with Hitachi as a close relationship: GE Hitachi Nuclear Energy (GEH), 60% GE; and Hitachi-GE Nuclear Energy based in Japan, 80% Hitachi.
• Westinghouse had become a 77%-owned subsidiary of Toshiba (with The Shaw Group 20%). Toshiba is now an 87% owner, having sold 10% to Kazatomprom and bought the 20% share.

Ten years later, in 2016, Westinghouse has collaborated with China’s State Nuclear Power Technology Corporation (SNPTC) in developing the AP1000 design to a CAP1000 and also a larger CAP-1400, and China is gaining a high profile as reactor vendor alongside Russia’s Rosatom. Areva was substantially restructured due to huge cost overruns on two EPR projects, and Electricite de France (EDF) took over the nuclear power plant part. Japanese vendors are overshadowed by the after-effects of the Fukushima accident. South Korea’s KEPCO through KHNP is building its APR1400 on budget and schedule in the United Arab Emirates, but faces new political challenges at home.

There have also been a number of other international collaborative arrangements initiated among reactor vendors and designers, but it remains to be seen which will be most significant.

Who is marketing what?

Apart from small reactors, the following are the main models actively being marketed:

• EDF (Framatome): EPR2, Atmea1, Kerena
• Westinghouse: AP1000
• GE Hitachi: ABWR, ESBWR, PRISM
• KHNP: APR1400, EU-APR
• Mitsubishi: APWR, Atmea1
• Rosatom: AES-92, AES-2006, VVER-TOI
• SNC-Lavalin: EC6
• CNNC & CGN: Hualong One
• SNPTC: CAP1400

Advanced power reactors operational

Other advanced power reactors under construction

Advanced power reactors ready for deployment

Light water reactors

(Power reactors moderated and cooled by water)

Areva NP (formerly Framatome ANP) developed a large (4590 MWt, typically 1750 MWe gross and 1630 MWe net) European pressurized water reactor ( EPR ), which was accepted in mid-1995 as the new standard design for France and received French design approval in 2004. It is a four-loop design derived from the German Konvoi types with features from the French N4, and was expected to provide power about 10% cheaper than the N4. It will operate flexibly to follow loads, have fuel burn-up of 65 GWd/t and a high thermal efficiency, of 37%, and net efficiency of 36%. It is capable of using a full core load of MOX. Availability is expected to be 92% over a 60-year service life.

It has double containment with four separate, redundant active safety systems, and boasts a core catcher under the pressure vessel. The safety systems are physically separated through four ancillary buildings on the same concrete raft, and two of them are aircraft crash protected. The primary diesel generators have fuel for 72 hours, the secondary back-up ones for 24 hours, and tertiary battery back-up lasts 12 hours. It is designed to withstand seismic ground acceleration of 600 Gal without safety impairment.

The first EPR unit commenced construction at Olkiluoto in Finland, the second at Flamanville in France, the third European one was to be at Penly in France. However the first EPR to be grid connected was at Taishan in China. It entered commercial operation at the end of 2018. The EPR has undergone UK generic design assessment, with some significant changes to instrumentation and control systems being agreed with other national regulators, and two are being built at Hinkley Point C in the UK.

Questions arose regarding the steel quality in the top and bottom reactor pressure vessel heads for Flamanville, forged by Areva’s Creusot Forge plant. The pressure vessel for Olkiluoto was forged in Japan, and those for Taishan by MHI and Dongfang Electric.

A US version, the US-EPR quoted as 1710 MWe gross and about 1580 MWe net, was submitted for US design certification in December 2007, but this process is suspended. The first unit (with 80% US content) was expected to be grid connected by 2020. It is now known as the Evolutionary PWR (EPR). Much of the one million man-hours of work involved in developing this US EPR was said to be making the necessary changes to output electricity at 60 Hz instead of the original design's 50 Hz. The main development of the type was to be through UniStar Nuclear Energy.

Areva NP with EdF developed a ‘new model’ EPR, the EPR NM or EPR2 , “offering the same characteristics” as the EPR but with simplified construction and significant cost reduction – about 30%. The basic design was to be completed in 2020, and in mid-2019 the French regulator ASN said it was happy with most aspects of the design. Emergency core cooling is significantly different to the EPR. EdF said that it, not the complex EPR being built at Flamanville, would be the model that replaced the French fleet from the late 2020s. Poland appears to be a candidate for the demonstration plant.

The Westinghouse AP1000 is a two-loop PWR which has evolved from the smaller AP600, one of the first new reactor designs certified by the US NRC. Simplification was a major design objective of the AP1000, in overall safety systems, normal operating systems, the control room, construction techniques, and instrumentation and control systems provide cost savings with improved safety margins. It has a core cooling system including passive residual heat removal by convection, improved containment isolation, passive containment cooling system to the atmosphere and in-vessel retention of core damage (corium) with water cooling around it. No safety-related pumps or ventilation systems are needed. The AP1000 gained US design certification in 2005, and UK generic design assessment approval in 2017. However, the structural design for the USA and UK was significantly modified from 2008 to withstand aircraft impact.

It has been built in China at Sanmen and Haiyang, and is under construction at Vogtle in the USA. The units are being assembled from modules. It is 1250 MWe gross and 1110-1117 MWe net in the USA, 1157 or 1170 MWe net in China (3415 MWt). Westinghouse earlier claimed a 36-month construction time to fuel loading. The first ones being built in China were on a 57-month schedule to grid connection, but took about 110 months. Progress was delayed, particularly by the need to re-engineer the 91-tonne coolant pumps, of which each rector has four. After the first four units in China, the design is known as the CAP1000 there.

SNPTC and SNERDI in China have jointly developed a passively safe 1500 MWe (4040 MWt) two-loop design from the AP1000, the CAP1400, or Guohe One, with 193 fuel assemblies and improved steam generators, operating at 323°C outlet temperature, 60-year design lifetime, and 72-hour non-intervention period in event of accident. Average discharge burn-up is about 50 GWd/t, maximum 59.5 GWd/t. Operation flexibility includes extra control rods for MOX capability, 18 to 24-month cycle, and load-following. Seismic rating is 300 gal. The CAP1400 project may extend to a larger, three-loop CAP1700 or CAP2100 design if the passive cooling system can be scaled to that level. Westinghouse has agreed that SNPTC will own the intellectual property rights for any AP1000 derivatives over 1350 MWe. Construction of the first unit at Shidaowan started without public announcement in 2019. Exports are intended.

The advanced boiling water reactor (ABWR) is derived from a General Electric design in collaboration with Toshiba. Two examples built by Hitachi and two by Toshiba have been in commercial operation in Japan (1315 MWe net), with another two under construction there and two in Taiwan. More are planned in Japan and four are planned in the UK.

The ABWR has been offered in slightly different versions by GE Hitachi, Hitachi-GE and Toshiba, so that 'ABWR' is now a generic term. It is basically a 1380 MWe (gross) unit (3926 MWt in Toshiba version), though GE Hitachi quotes 1350-1600 MWe net. Toshiba outlines development from its 1400 MWe class to a 1500-1600 MWe class unit (4300 MWt). Tepco was funding the design of a next generation BWR, and the ABWR-II is quoted as 1717 MWe.

Toshiba was promoting its EU-ABWR of 1600 MWe with core catcher and filtered vent, developed with Westinghouse Sweden. The Hitachi UK-ABWR may have similar features but be similar size to Japanese units.

The first four ABWRs were each built in 39-43 months on a single-shift basis. Though GE and Hitachi have subsequently joined up, Toshiba retains some rights over the design, as does Tepco. The design can run on full-core mixed oxide (MOX) fuel, as for the Ohma plant being built in Japan. Design operating lifetime is 60 years. Unlike previous BWRs in Japan the external recirculation loop and internal jet pumps are replaced by coolant pumps mounted at the bottom of the reactor pressure vessel. Safety systems are active – GEH describes it as “the pinnacle of the evolution of active safety.”

Both Toshiba and GE Hitachi have applied separately to the NRC for design certification renewal, though these are respectively withdrawn or on hold. The initial certification in 1997 was for 15 years and in 2011 the NRC certified for GE Hitachi an evolved version which allows for aircraft impacts. UK generic design assessment approval for Hitachi's version of the ABWR is expected at the end of 2017. 

GE Hitachi was also designing a 600-800 MWe version of the ABWR, with five instead of ten internal coolant pumps, aiming at Southeast Asia. In addition, a 400 MWe version was envisaged.

GE Hitachi Nuclear Energy's ESBWR is an improved design "evolved from the ABWR" but that utilizes passive safety features including natural circulation principles. It is the ninth evolution of the original BWR design licensed in 1957, and was developed from a predecessor design, the SBWR at 670 MWe. GEH says it is safer and more efficient than earlier models, with 25% fewer pumps, valves and motors, and can maintain cooling for seven days after shutdown with no AC or battery power. The emergency core cooling system has eliminated the need for pumps, using passive and stored energy. The used fuel pool is below ground level.

The ESBWR (4500 MWt) will produce approximately 1600 MWe gross, and 1520 MWe net, depending on site conditions, and has a design operating lifetime of 60 years. It is more fully known as the Economic Simplified BWR (ESBWR) and leverages proven technologies from the ABWR. GE Hitachi gained US NRC design certification for the ESBWR in September 2014, following design approval in March 2011. It was submitted for UK generic design assessment in 2007, but withdrawn a year later.

GEH is selling this alongside the ABWR, which it characterizes as more expensive to build and operate, but proven. The ESBWR is more innovative, with lower building costs due to modular construction, lower operating costs, 24-month refuelling cycle and a 60-year operating lifetime. In the USA plans to build as Detroit Edison’s Fermi 3 and Dominion’s North Anna 3 are not proceeding.

Mitsubishi's large APWR – advanced PWR of 1538 MWe gross (4451 or 4466 MWt) – was developed in collaboration with four utilities (Westinghouse was earlier involved). The first two are planned for Tsuruga, originally to come online from 2016. It is a four-loop design with 257 fuel assemblies and neutron reflector, is simpler, combines active and passive cooling systems in a double containment, and has over 55 GWd/t fuel burn-up. It is the basis for the next generation of Japanese PWRs. The planned APWR+ is 1750 MWe and has full-core MOX capability.

The US-APWR is 4451 MWt, about 1600 MWe net, due to longer (4.3m instead of 3.7m) fuel assemblies, higher burn-up (62 GWd/t) and higher thermal efficiency (37%) (2013 company description). It has 24-month refuelling cycle. Its emergency core cooling system (ECCS) has four independent trains, and its outer walls and roof are 1.8 m thick. US design certification application was in January 2008 with certification expected in 2016, but halted. In March 2008 MHI submitted the same design for EUR (European Utility Requirements) certification, as the EU-APWR, and this certification of compliance was granted in October 2014. MHI planned to join with Iberdrola Engineering & Construction in bidding for sales of this in Europe. Iberdrola would be responsible for building the plants.

The Japanese government was expected to provide financial support for US licensing of the US-APWR. Washington Group International was to be involved in US developments with Mitsubishi Heavy Industries (MHI). The US-APWR was selected by Luminant for Comanche Peak, Texas, a merchant plant.

APR1400, EU-APR, APR+, APR1000

South Korea's APR1400 advanced PWR design has evolved from the US System 80+ with enhanced safety and seismic robustness and was earlier known as the Korean Next Generation Reactor. Design certification by the Korean Institute of Nuclear Safety was awarded in May 2003. It is 1455 MWe gross in Korean conditions according to an IAEA status report, 1350-1400 MWe net (3983 – nominal 4000 MWt) with two-loop primary circuit. The first of these are operating in Korea – Shin Kori 3&4 – with Shin Hanul 1&2 under construction. It was chosen for the United Arab Emirates (UAE) nuclear programme on the basis of cost and reliable building schedule, and four units are under construction there, with the first expected online in 2020.

Fuel in 241 fuel assemblies has burnable poison and will have up to 55 GWd/t burn-up, refuelling cycle around 18 months, outlet temperature 324ºC. It is designed "not only for the base-load full power operation but also for a part load operation such as the load following operation. A standard 100-50-100% daily load follow operation has been considered in the reactor core design as well as in the plant control systems." Ramp up and down between 100% and 50% takes two hours. Plant operating lifetime is 60 years, seismic design basis is 300 Gal. A low-speed (1800 rpm) turbine is used. An application for US design certification was lodged in 2013 and a revised version accepted in March 2015. The NRC confirmed its safety in September 2018 and design certification was approved in May 2019 and formally awarded in August.

Based on this, KOPEC has developed an EU version (APR1400-EUR or EU-APR) with double containment and core-catcher which was given EUR approval in October 2017. It is 4000 MWt, 1520 MWe gross, with a design lifetime of 60 years and 250 Gal seismic rating.

KHNP is also developing a more advanced 4308 MWt, 1560 MWe (gross) version of the APR1400, the APR+ , which gained design approval from NSSC in August 2014. It was “developed with original domestic technology”, up to 100% localized, over seven years since 2007, with export markets in view. It has modular construction which is expected to give 36-month construction time instead of 52 months for the APR1400. It has 257 fuel assemblies of a new design, 18- to 24-month fuel cycle, and passive decay heat removal. Also it is more highly reinforced against aircraft impact than any earlier designs. Seismic rating is 300 Gal.

In addition some of the APR features are being incorporated into an exportable APR-1000 intended for overseas markets, notably Middle East and Southeast Asia, and will be able to operate with an ultimate heat sink of 40°C, instead of 35°C for the OPR-1000. Improved safety and performance will raise the capital cost above that of the OPR, but it this will be offset by reduced construction time (40 months instead of 46) due to modular construction.

The Atmea1 has been developed by the Atmea joint venture established in 2007 by Areva NP and Mitsubishi Heavy Industries to produce an evolutionary 1100-1150 MWe net (3150 MWt) three-loop PWR using the same steam generators as EPR. This has 37% net thermal efficiency, 157 fuel assemblies 4.2 m long, 60-year operating lifetime, and the capacity to use mixed-oxide fuel for full core load. Fuel cycle is flexible 12 to 24 months with short refuelling outage and the reactor has load-following (100-25% range) and frequency control capability. The first units are likely to be built at Sinop in Turkey.

Following an 18-month review, the French regulator ASN approved the general design in February 2012. The reactor is regarded as mid-sized relative to other modern designs and will be marketed primarily to countries embarking upon nuclear power programs. It has three active and passive redundant safety systems and an additional backup cooling chain, similar to EPR. It has a core-catcher, and is available for high-seismic sites. Canadian design certification is under way.

Together with German utilities and safety authorities, Areva NP has also developed another evolutionary design, the Kerena, a 1290 MWe gross, 1250 MWe net (3370 MWt) BWR with 60-year design life formerly known as SWR 1000 , The design, based on the Gundremmingen plant built by Siemens, was completed in 1999 and US certification was sought, but then deferred. It has not yet been submitted for certification anywhere, but is otherwise ready for commercial deployment.

It has two redundant active safety systems and two passive safety systems, including a core-catcher, similar to EPR. The reactor is simpler overall and uses high-burnup fuels (to 65 GWd/t) enriched to 3.54%, giving it refuelling intervals of up to 24 months. It can take a 50% MOX load, and uses flow variation to improve fuel usage. It has 37% net efficiency and can load-follow down to 70% using recirculation pumps only, and down to 40% with control rods.

AES-92, V-392

Gidropress late-model VVER-1000/V-392 units with enhanced safety (AES-92 & -91 power plants) have been built in India and China. Two more (V-466B variant) were planned for Belene in Bulgaria. The AES-92 is certified as meeting EUR. The V-392 has four coolant loops, 163 fuel assemblies, and is rated 3000 MWt.

AES-2006, MIR-1200

The third-generation AES-2006 plant with VVER-1200 (V-392M or V-491) reactors of 3212 MWt is an evolutionary development of the AES-92 and AES-91 plants with the VVER-1000, with longer operating lifetime (60 years for non-replaceable equipment), greater power, and greater efficiency (34.8% net instead of 31.6%) and 60 GWd/t burn-up. Cogeneration heat supply capacity is 300 MWt. It retains four coolant loops and has 163 FA-2 fuel assemblies, each with 534 kg of UO 2 fuel enriched to 4.95%. Core outlet temperature is 329°C.

The lead units were being built at Novovoronezh II (V-392M) and Leningrad II (V-491), the first one starting operation in 2016. The first of two V-491 units at Ostrovets in Belarus commenced operation in 2020. Units based on the V-392M are being built Akkuyu in Turkey (V-509) and Rooppur in Bangladesh (V-523). The single V-522 in AES-2006E at Hanhikivi in Finland is based on the V-491.The Novovoronezh units provide 1114 MWe net each, and the Leningrad II units 1085 MWe net each, with a capacity factor of 90%. Two steam turbines are offered: Power Machines (Silmash) full-speed; and Alstom Arabelle half-speed, as proposed for MIR-1200 and Hanhikivi in Finland.

Overnight capital cost was said to be $1200/kW (though the first contract was about $2100/kW) and serial construction time 54 months. They have enhanced safety including that related to earthquakes and aircraft impact (V-392M especially) with some passive safety features, double containment, and core-catcher.

While OKB Gidropress is responsible for the actual 1200 MWe reactor, Moscow AEP and Atomproekt St Petersburg are going different ways on the cooling systems, and the V-392M version is the basis of the VVER-TOI. Passive safety systems prevail in Moscow's V-392M design, while St Petersburg's V-491 design focuses on active safety systems based on the Tianwan V-428 design. In both, long-term decay heat removal does not rely on electrical power or ultimate heat sink. (Details in the information page on Nuclear Power in Russia .) Atomenergoproekt says that the AES-2006 conforms to both Russian standards and European Utilities Requirements (EUR). In Europe the V-491 technology is being called the Europe-tailored reactor design, MIR-1200 (Modernised International Reactor) or AES-2006E, with some Czech involvement. Those bid for Temelin are quoted as 1158 MWe gross,1078 MWe net. That for Hanhikivi is 1250 MWe gross, due to cold water.

In 2010 Atomenergoproekt announced the VVER-TOI (typical optimized, with enhanced information) design based on V-392M. The basic Gidropress reactor is V-510. It has upgraded pressure vessel, increased power to 3312 MWt and 1255 MWe gross (nominally 1300, hence VVER-1300), improved core design still with 163 fuel assemblies to increase cooling reliability, larger steam generators, further development of passive safety with 72-hour grace period requiring no operator intervention after shutdown, lower construction and operating costs, and 40-month construction time. It will use a low-speed turbine-generator and can undertake daily load-following down to 50% of power. The project was initiated in 2009 and the design was completed at the end of 2012. In June 2012 Rosatom said it would apply for design certification in UK through Rusatom Overseas, with the VVER-TOI version. The first units are being built at Kursk II and planned for Smolensk II in Russia.

Details of MIR-1200 and VVER-TOI are in the Nuclear Power in Russia information page.

Gidropress has developed the VVER-600/V-498 for sites such as Kola, where larger units are not required. It is a two-loop design based on the V-491 St Petersburg version of the VVER-1200 and using the same basic equipment but without core-catcher (corium retained within RPV). It will have 60-year life and is capable of load-following. Export potential is anticipated. It supercedes the VVER-640/V-407 design.

Hualong One, HPR1000

In China, there are two indigenous designs based on a French predecessor but developed with modern features. CNNC developed the ACP1000 design, with 1100 MWe nominal power and load-following capability, and 177 fuel assemblies. In parallel but somewhat ahead, China Guangdong Nuclear Power Corporation, now China General Nuclear Power (CGN) led the development of the 1100 MWe ACPR-1000, with 157 fuel assemblies (same as the French M-310 predecessor), and about 30 of these have been built. However, due to rationalization over 2011-13, this design has been dropped in favour of the Hualong One, essentially the ACP1000 with some features from the ACPR.

The Hualong One thus has 177 fuel assemblies 3.66 m long, 18-24 month refuelling interval. It has three coolant loops delivering 3050 MWt, 1170 MWe gross, 1090 MWe net (CNNC version). It has double containment and active safety systems with some passive elements, and a 60-year design lifetime. Average burnup is 45,000 MWd/tU, thermal efficiency is 36%. Seismic shutdown is at 300 gal. Instrumentation and control systems will be from Areva-Siemens. Estimated cost in China is $3500/kWe. The first units under construction are Fangchenggang 3&4 (CGN) and Fuqing 5&6 (CNNC). It is also being built in Pakistan.

CNNC and CGN in December 2015 formed a 50-50 joint venture company – Hualong International Nuclear Power Technology Co – to market it. The version promoted on the international market, is called HPR1000 (Hualong Pressurized Reactor 1000), based on the CGN version, with Fangchenggang as the reference plant. In October 2015 CGN submitted the HPR1000 for certification of compliance with European Utility Requirements (EUR).

Fuller details of the situation are in the Nuclear Power in China information page.

OKBM's VBER-300 PWR is a 295-325 MWe unit (917 MWt) developed from naval power plants and was originally envisaged in pairs as a floating nuclear power plant. It is designed for 60 year life and 90% capacity factor. It now planned to develop it as a land-based unit with Kazatomprom, with a view to exports, and the first unit will be built in Kazakhstan.

The VBER-300 and the similar-sized VK300 are more fully described in the Small Nuclear Power Reactors information page.

Heavy water reactors

(Moderated and mostly cooled by heavy water)

In Canada , the government-owned Atomic Energy of Canada Ltd (AECL) had two designs under development which are based on its reliable CANDU-6 reactors, the most recent of which are operating in China. In 2011 the reactor division of AECL was sold and became Candu Energy Inc , a subsidiary of SNC-Lavalin. One of these earlier designs continues, with associated fuel cycle innovation. 

The CANDU-9 (925-1300 MWe) was developed from the CANDU-6 also as a single-unit plant. It had flexible fuel requirements which have been taken forward to the EC6. A two year licensing review of the CANDU-9 design was successfully completed early in 1997, but the design has been shelved.

Some of the innovation of the CANDU-9, along with experience in building recent Korean and Chinese units, was then put back into the Enhanced CANDU-6 (EC6). This is to be built as twin units – with power increase to 740-750 MWe gross (690 MWe net, 2084 MWt) and flexible fuel options, plus 4.5 year construction and 60-year plant life (with mid-life pressure tube replacement). EC6 is presented as a third-generation design based on Qinshan Phase III in China, and is under consideration for new build in Ontario and overseas. Phase 2 of CNSC’s vendor pre-project design review was completed in April 2012, with phase 3 on target for 2013.

Versatility of fuel is a claimed feature of the EC6 and its derivatives. As well as natural uranium, it can use direct recovered/reprocessed uranium (RU) from used PWR fuel, natural uranium equivalent (NUE – DU + RU), MOX (DU + Pu), fertile fuels such as LEU + thorium and Th with Pu, and closed cycle fuels (Th + U-233 + Pu). The NUE fuel cycle with full-core NUE is being demonstrated at Qinshan in China in CANDU-6 units*. There is also a program for the Advanced Fuel Candu Reactor (AFCR) – an adaptation of EC6 – on direct use of RU, and also LEU + thorium-based CANDU fuel. Finally a CANMOX fuel is proposed with EC6 for disposal of the UK’s plutonium stock.

* RU with 0.9% U-235 plus DU gives 0.7% NUE, which is burned down to about 0.25% U-235.

The EC6 has design features, notably its automated refuelling, which enable third-party process monitoring in relation to non-proliferation concerns.

The Advanced Fuel CANDU Reactor (AFCR) is a 740 MWe development of the EC6, designed to use recycled uranium and also thorium-based fuels. It has been developed by Candu Energy with CNNC’s Third Qinshan Nuclear Power Corp, which plans to convert the two Qinshan CANDU-6 PHWR units to AFCRs. Then new-build AFCRs are envisaged in China. One AFCR can be fully fuelled by the recycled uranium from four LWRs’ used fuel. Hence deployment of AFCRs will greatly reduce the task of managing used fuel and disposing of high-level waste, and could reduce China’s fresh uranium requirements. Late in 2014 a joint venture framework agreement between CNNC and Candu Energy was signed to build AFCR projects domestically and develop opportunities for them internationally. In September 2016 an agreement among SNC-Lavalin, CNNC and Shanghai Electric Group was to set up a joint venture in mid-2017 to develop, market and build the AFCR, with NUE fuel.

India is developing the Advanced Heavy Water Reactor (AHWR) as the third stage in its plan to utilize thorium to fuel its overall nuclear power program. The AHWR is a 300 MWe gross (284 MWe net, 920 MWt) reactor moderated by heavy water at low pressure. The calandria has about 450 vertical pressure tubes and the coolant is pressurized light water boiling at 285ºC and circulated by convection. A large heat sink – 'gravity-driven water pool' – with 7000 cubic metres of water is near the top of the reactor building. Each fuel assembly has 30 Th-U-233 oxide pins and 24 Pu-Th oxide pins around a central rod with burnable absorber. Burn-up of 24 GWd/t is envisaged. It is designed to be self-sustaining in relation to U-233 bred from Th-232 and have a low Pu inventory and consumption, with slightly negative void coefficient of reactivity. It is designed for 100-year plant life and is expected to utilize 65% of the energy of the fuel, with two-thirds of that energy coming from thorium via U-233. A co-located fuel cycle facility is planned, with remote handling for the highly-radioactive fresh fuel. At the end of 2016 the design was complete and large-scale engineering studies were validating innovative features of the design. No site or construction schedule had been announced for the demonstration unit.

Once it is fully operational, each AHWR fuel assembly will have the fuel pins arranged in three concentric rings:

Inner: 12 pins Th-U-233 with 3.0% U-233. Intermediate: 18 pins Th-U-233 with 3.75% U-233. Outer: 24 pins Th-Pu-239 with 3.25% Pu.

The fissile plutonium content will decrease from an initial 75% to 25% at equilibrium discharge burn-up level.

As well as U-233, some U-232 is formed, and the highly gamma-active daughter products of this confer a substantial proliferation resistance.

In 2009 an export version of this design was announced: the AHWR-LEU . This will use low-enriched uranium plus thorium as a fuel, dispensing with the plutonium input. About 39% of the power will come from thorium (via in situ conversion to U-233), and burn-up will be 64 GWd/t. Uranium enrichment level will be 19.75%, giving 4.21% average fissile content of the U-Th fuel. While designed for closed fuel cycle, this is not required. Plutonium production will be less than in light water reactors, and the fissile proportion will be less and the Pu-238 portion three times as high, giving inherent proliferation resistance. The AEC says that "the reactor is manageable with modest industrial infrastructure within the reach of developing countries."

In the AHWR-LEU, the fuel assemblies will be configured: Inner ring: 12 pins Th-U with 3.555% U-235, Intermediate ring: 18 pins Th-U with 4.345% U-235, Outer ring: 24 pins Th-U with 4.444% U-235.

High-temperature gas-cooled reactors

(Graphite-moderated)

These reactors use helium as a coolant at up to 950ºC, which either makes steam conventionally (Rankine cycle) or directly drives a gas turbine for electricity and a compressor to return the gas to the reactor core (Brayton cycle). Fuel is in the form of TRISO particles less than a millimetre in diameter. Each has a kernel of uranium oxycarbide, with the uranium enriched up to 17% U-235. This is surrounded by layers of carbon and silicon carbide, giving a containment for fission products which is stable to 1600°C or more. These particles may be arranged: in blocks as hexagonal 'prisms' of graphite, or in billiard ball-sized pebbles of graphite encased in silicon carbide.

HTR-PM, HTR-PM 600

The first commercial version will be China's HTR-PM, being built at Shidaowan in Shandong province. It has been developed by Tsinghua University's INET, which is the R&D leader and China Nuclear Engineering & Construction Group (CNEC), with China Huaneng Group leading the demonstration plant project. This will have two reactor modules, each of 250 MWt/105 MWe (equivalent), with a single steam generator, and using 8.5% enriched fuel (245,000 elements) giving 90 GWd/t discharge burnup. With an outlet temperature of 750ºC the pair will produce steam at 566ºC to drive a single steam cycle turbine at about 40% thermal efficiency.

This 210 MWe Shidaowan demonstration plant is to pave the way for commercial 600 MWe reactor units using the twin reactor modules (3x210 MWe), also using the steam cycle. These are being promoted by CNEC. Plant life is envisaged as 40 years with 85% load factor.

Fuller descriptions of HTRs is in the Small Nuclear Power Reactors paper.

Fast neutron reactors

(Not moderated, cooled by liquid metal)

Fuller description of fast neutron reactors is in that information page.

Several countries have research and development programs for improved fast breeder reactors (FBR), which are fast neutron reactors (FNR) configured with a conversion or breeding ratio of more than 1 ( i.e. more fissile nuclei are produced than are fissioned). These use the uranium-238 in reactor fuel as well as the fissile U-235 isotope used in most reactors, and can readily use the world’s 1.5 million tonnes of depleted uranium as fuel. They are now often designed to burn actinides as well.

About 20 liquid metal-cooled FBRs have already been operating, some since the 1950s, and some have supplied electricity commercially. About 400 reactor-years of operating experience have been accumulated. Today Russia and India have FNRs high profile in their nuclear programs, with Japan, China and France also significant. See also Fast Neutron Reactors page.

India's 500 MWe prototype fast breeder reactor at Kalpakkam is expected to be operating in 2018, fuelled with uranium-plutonium oxide (the reactor-grade Pu being from its existing PHWRs) and with a thorium blanket to breed fissile U-233. This will take India's ambitious thorium program to stage 2, and set the scene for eventual full utilization of the country's abundant thorium to fuel reactors.

The Russian BN-600 fast breeder reactor at Beloyarsk has been supplying electricity to the grid since 1981 and has the best operating and production record of all Russia's nuclear power units. It uses uranium oxide fuel and the sodium coolant delivers 550°C at little more than atmospheric pressure. The core is 0.88 metres active height and 0.75 m diameter. The BN-350 FBR operated in Kazakhstan for 27 years and about half of its output was used for water desalination. The BN-600 is configured to burn the plutonium from its military stockpiles.

The first (and probably only Russian) BN-800, a new more powerful (789 MWe, 880 MWe gross, 2100 MWt) fast neutron reactor from OKBM with Atomenergoproekt at St Petersburg with improved features, was grid-connected at Beloyarsk in December 2015. It is designed to have considerable fuel flexibility – U+Pu nitride, MOX, or metal, and with breeding ratio up to 1.3, though only 1.0 as configured at Beloyarsk. The core is a similar size to that of the BN-600. Initially it is being run with one-fifth MOX fuel, but will have a full MOX core from about 2020. It does not have a breeding blanket, though a version designed for Sanming in China has up to 198 DU fuel elements in a blanket. Its main purpose is to provide operating experience and technological solutions, especially regarding fuels, that will be applied to the BN-1200. Further details in the information paper on Fast Neutron Reactors .

The BN-1200 is being designed by OKBM for operation with MOX fuel initially and dense nitride U-Pu fuel subsequently, in closed fuel cycle. It is significantly different from preceding BN models, and Rosatom plans to submit the BN-1200 to the Generation IV International Forum (GIF) as a Generation IV design. The BN-1200 has a capacity of 2900 MWt (1220 MWe gross), a 60-year design life, and burn-up of up to 120 GWd/t. The capital cost is expected to be much the same as that of the VVER-1200. Its breeding ratio is quoted as 1.2 to 1.4, using oxide or nitride fuel. OKBM envisages about 11 GWe of such plants by 2030, including South Urals nuclear plant. The detailed design was completed in May 2017, and the first unit is to be built at Beloyarsk possibly from 2020. This is part of a federal Rosatom program, the Proryv (Breakthrough) Project for large fast neutron reactors.

Russia has experimented with several lead-cooled reactor designs, and used lead-bismuth cooling for 40 years in reactors for its seven Alfa class submarines. Pb-208 (54% of naturally-occurring lead) is transparent to neutrons. A significant new Russian design from NIKIET is the BREST-300  fast neutron reactor, of 300 MWe (700 MWt) with lead as the primary coolant, at 540ºC, and supercritical steam generators. It is inherently safe and uses a high-density U+Pu nitride fuel with no requirement for high enrichment levels. No weapons-grade plutonium can be produced (since there is no uranium blanket – all the breeding occurs in the core. Used fuel can be recycled indefinitely, with on-site reprocessing and associated facilities. A demonstration unit is planned at Seversk by 2022, and 1200 MWe (2800 MWt) units are proposed. Both designs have two cooling loops. BREST-300 has 17.6 tonnes of fuel, BREST-1200 about 60 tonnes. See information page on Nuclear Power in Russia for further details.

Today's PRISM is a GE Hitachi design for compact modular pool-type reactors with passive cooling for decay heat removal. After 30 years of development it represents GEH's Generation IV solution to closing the fuel cycle. Each PRISM Power Block consists of two modules of 840 MWt, 311 MWe each, operating at high temperature – over 500°C. The pool-type modules below ground level contain the complete primary system with sodium coolant. PRISM is suited to operation with dry cooling towers due to high thermal efficiency and small size.

The Pu & DU fuel is metal, and obtained from used light water reactor fuel. However, all transuranic elements are removed together in the electrometallurgical reprocessing so that fresh fuel has minor actinides with the plutonium. Fuel stays in the reactor about six years, with one-third removed every two years. Breeding ratio depends on purpose and hence configuration, so ranges from 0.72 for used LWR recycle to 1.23 for breeder. Used PRISM fuel is recycled after removal of fission products. The commercial-scale plant concept, part of an 'Advanced Recycling Center', uses three power blocks (six reactor modules) to provide 1866 MWe. See also Electrometallurgical 'pyroprocessing' section in Processing Used Nuclear Fuel information paper.

A variant of this is proposed to utilize the UK's reactor-grade plutonium stockpile. A pair of PRISM units built at Sellafield would be operated initially so as to bring the material up to the highly-radioactive 'spent fuel standard' of self-protection and proliferation resistance. The whole stockpile could be irradiated thus in five years, with some by-product electricity and the plant would then proceed to re-use that stored fuel over perhaps 55 years solely for 600 MWe of electricity generation. GEH has launched a web portal in support of its proposal.

Westinghouse LFR

Westinghouse is developing a lead-cooled fast reactor ( LFR ) design with flexible output to complement intermittent renewable feed to the grid. Its high temperature capabilities will allow industrial heat applications. Westinghouse expects it to be very competitive, having low capital and construction costs with enhanced safety. Further operational and safety enhancements are also achieved by adoption of a fuel/cladding combination with high temperature capability based on those under development by Westinghouse in the Accident Tolerant Fuel program .

Japan plans to develop FBRs, and its Joyo experimental reactor which has been operating since 1977 is now being boosted to 140 MWt. The 280 MWe  Monju  prototype commercial FBR was connected to the grid in 1995, but was then shut down for 15 years due to a sodium leak. It restarted in 2010 before closing down again due to an ancillary mechanical problem and is now being decommissioned. Mitsubishi Heavy Industries (MHI) is involved with a consortium to develop a Japan Standard Fast Reactor (JSFR) concept, though with breeding ratio less than 1:1. This is a large unit which would burn actinides with uranium and plutonium in oxide fuel. It could be of any size from 500 to 1500 MWe.

See also information page on Fast Neutron Reactors .

Generation IV designs

See information page on six Generation IV Reactors .

Small reactors

See also information page on Small Nuclear Power Reactors for other advanced designs, mostly under 300 MWe. This paper includes some designs which have become significantly larger than 300 MWe since first being described, but which are outside the mainstream categories dealt with here.

Accelerator-driven systems (ADS)

A related development has been the merging of accelerator and fission reactor technologies to generate electricity and transmute long-lived radioactive wastes.

A high-energy proton beam hitting a heavy metal target produces neutrons by spallation. The neutrons cause fission in the fuel, but unlike a conventional reactor, the fuel is subcritical, and fission ceases when the accelerator is turned off. The fuel may be uranium, plutonium or thorium, possibly mixed with long-lived wastes from conventional reactors.

Many technical and engineering questions remain to be explored before the potential of this concept can be demonstrated. See also ADS briefing paper .

Notes & references

General sources.

Nuclear Engineering International, various, and 2002 Reactor Design supplement. March 2012: Atmea1 reactor. ABB Atom Dec 1999; Nukem market report July 2000; The New Nuclear Power, 21st Century, Spring 2001, Lauret, P. et al, 2001, The Nuclear Engineer 42, 5. Smirnov V.S. et al, 2001, Design features of BREST reactors, KAIF/KNS conf.Proc. OECD NEA 2001, Trends in the Nuclear Fuel Cycle Technical and Economic Aspects of Load Following with Nuclear Power Plants , OECD Nuclear Energy Agency (June 2011) Carroll D & Boardman C, 2002, The Super-PRISM Reactor System, The Nuclear Engineer 43,6; Twilley R C 2002, Framatome ANP's SWR1000 reactor design, Nuclear News, Sept 2002. Torgerson D F 2002, The ACR-700, Nuclear News Oct 2002. IEA-NEA-IAEA 2002, Innovative Nuclear Reactor Development Perera, J, 2003, Developing a passive heavy water reactor, Nuclear Engineering International, March Sinha R.K.& Kakodkar A. 2003, Advanced Heavy Water Reactor, INS News vol 16, 1 US Dept of Energy, EIA 2003, New Reactor Designs. Matzie R.A. 2003, PBMR - the first Generation IV reactor to be constructed, WNA Symposium LaBar M. 2003, Status of the GT-MHR for electricity production, WNA Symposium Carelli M 2003, IRIS: a global approach to nuclear power renaissance, Nuclear News Sept 2003 Perera J. 2004, Fuelling Innovation, IAEA Bulletin 46/1 AECL Candu-6 & ACR publicity, late 2005 IAEA Status report 83 – APR1400 Atomenergoproekt website

Appendix 1: US Nuclear Regulatory Commission draft policy, May 2008

The Commission believes designers should consider several reactor characteristics, including:

• Highly reliable, less complex safe shutdown systems, particularly ones with inherent or passive safety features;
• Simplified safety systems that allow more straightforward engineering analysis, operate with fewer operator actions and increase operator comprehension of reactor conditions;
• Concurrent resolution of safety and security requirements, resulting in an overall security system that requires fewer human actions;
• Features that prevent a simultaneous breach of containment and loss of core cooling from an aircraft impact, or that inherently delay any radiological release, and;
• Features that maintain spent fuel pool integrity following an aircraft impact.

Appendix 2: Other advanced PWR ventures and concepts

The Reduced-Moderation Water Reactor (RMWR) is a light water reactor, essentially as used today, with the fuel packed in more tightly to reduce the moderating effect of the water. Considering the BWR variant (resource-renewable BWR – RBWR), only the fuel assemblies and control rods are different. In particular, the fuel assemblies are much shorter, so that they can still be cooled adequately. Ideally they are hexagonal, with Y-shaped control rods. The reduced moderation means that more fissile plutonium is produced and the breeding ratio is around 1 (instead of about 0.6), and much more of the U-238 is converted to Pu-239 and then burned than in a conventional reactor. Burn-up is about 45 GWd/t, with a long cycle. Initial seed (and possibly all) MOX fuel needs to have about 10% Pu. The void reactivity is negative, as in a conventional LWR. A Hitachi RBWR design based on the ABWR-II has the central part of each fuel assembly (about 80% of it) with MOX fuel rods and the periphery uranium oxide. In the MOX part, minor actinides are burned as well as recycled plutonium.

The main rationale for RMWRs is extending the world's uranium resource and providing a bridge to widespread use of fast neutron reactors. Recycled plutonium should be used preferentially in RMWRs rather than as MOX in conventional LWRs, and multiple recycling of plutonium is possible. Japan Atomic Energy Research Institute (JAERI) started the research on RMWRs in 1997 and then collaborated in the conceptual design study with the Japan Atomic Power Company (JAPCO) in 1998. Hitachi has also been closely involved, with its RBWR concept which has a major aim of burning actinides.

A new reprocessing technology is part of the RMWR concept. This is the fluoride volatility process, developed in 1980s, and is coupled with solvent extraction for plutonium to give the Fluorex process. In this, 90-92% of the uranium in the used fuel is volatalized as UF6, then purified for enrichment or storage. The residual is put through a Purex circuit which separates fission products and minor actinides as high-level waste, leaving the unseparated U-Pu mix (about 4:1) to be made into MOX fuel.

Hitachi conducted joint research on RBWRs with MIT, University of Michigan, and UC Berkeley from 2007 to 2011, on the burning of transuranic elements. In a further stage of joint research from 2014, and applying the more accurate analysis methods developed by the three American universities, Hitachi will continue to evaluate the safety and performance of the new reactor concepts, and will study plans for tests with a view towards practical applications.

Norway’s Thor Energy is exploring the operation of U-233 - thorium oxide (Th-MOX) fuel in an advanced reduced-moderation BWR (RBWR). This reactor platform, designed by Hitachi Ltd and JAEA, should be well-suited for achieving high U-233 conversion factors from thorium due to its epithermal neutron spectrum and flexible uranium-plutonium fuels in which high conversion or actinide destruction can be achieved. It is based on the ABWR architecture but has a shorter, flatter pancake-shaped core and a tight lattice to ensure sufficient fast neutron leakage and a negative void reactivity coefficient.

Areva-EdF-CGNPC project

Early in 2012 Areva and EdF agreed in principle with China Guangdong Nuclear Power group (CGN) to develop a mid-size PWR on the basis of CGNPC’s CPR-1000, with third-generation safety features. A further three-way agreement was signed in September, with a view to having an outcome by mid-2013. It is not clear whether Mitsubishi Heavy Industries might be involved, though Areva has said that it wants the design "to have the highest possible technical convergence" with Atmea1. If a new reactor design results, it would be a competitor for Atmea1. However, Areva says that the talks are not aimed at joint development of a 1000 MWe reactor, so much as "to see if the three companies can converge on specifications for such a design that would allow deeper collaboration". This appears to have been overtaken by Hualong One.

Another US-origin but international project which is a few years behind the AP1000 is the IRIS (International Reactor Innovative & Secure). Westinghouse is leading a wide consortium developing it as an advanced third generation project. IRIS is a modular 335 MWe pressurized water reactor with integral steam generators and primary coolant system all within the pressure vessel. It is nominally 335 MWe but can be less, e.g. 100 MWe. Fuel is initially similar to present LWRs with 5% enrichment and burnable poison, in fact fuel assemblies are "identical to those ... in the AP1000". These would have burn-up of 60 GWd/t with fuelling interval of 3 to 3.5 years, but IRIS is designed ultimately for fuel with 10% enrichment and 80 GWd/t burn-up with an eight-year cycle, or equivalent MOX core. The core has low power density. US design certification was at pre-application review stage, but the concept appears to have evolved into the Westinghouse SMR. Estonia once expressed interest in building a pair of IRIS. Some consortium partners were interested in desalination, one in district heating.

The VVER-1500 model was being developed by Gidropress. It will have enhanced safety, giving 1500 MWe gross from 4250 MWt. Design was expected to be complete in 2007 but the project was shelved in 2006 in favour of the evolutionary VVER-1200. It remains a four-loop design, with increased pressure vessel diameter to 5 metres, 241 fuel assemblies in core enriched to 4.4%, burn-up 45-55 and up to 60 GWd/t and life of 60 years. If revived, it will meet EUR criteria.

Appendix 3: Other advanced PHWR designs and concepts

The Advanced Candu Reactor (ACR), a third generation reactor design, was a more innovative concept, but has now been shelved. While retaining the low-pressure heavy water moderator, it incorporates some features of the pressurized water reactor. Adopting light water cooling and a more compact core reduces capital cost, and because the reactor is run at higher temperature and coolant pressure, it has higher thermal efficiency.

The ACR-700 design was 700 MWe but is physically much smaller, simpler and more efficient as well as 40% cheaper than the CANDU-6. But the ACR-1000 of 1080-1200 MWe (3200 MWt) became the focus of attention by AECL (now  Candu Energy  Inc). It has more fuel channels (each of which can be regarded as a module of about 2.5 MWe). The ACR will run on low-enriched uranium (about 1.5-2.0% U-235) with high burn-up, extending the fuel life by about three times and reducing high-level waste volumes accordingly. It will also efficiently burn MOX fuel, thorium and actinides.

Regulatory confidence in safety is enhanced by a small negative void reactivity for the first time in CANDU, and utilising other passive safety features as well as two independent and fast shutdown systems. Units will be assembled from prefabricated modules, cutting construction time to 3.5 years. ACR units can be built singly but are optimal in pairs. They will have 60-year design life overall but require mid-life pressure tube replacement.

ACR-1000 was moving towards design certification in Canada, and a three-phase vendor pre-project design review was completed in 2010. In 2007 AECL applied for UK generic design assessment (pre-licensing approval) but then withdrew after the first stage. All licensing progress has ceased.

The  CANDU X  or SCWR is a variant of the ACR, but with supercritical light water coolant ( e.g. 25 MPa and 625ºC) to provide 40% thermal efficiency. The size range envisaged is 350 to 1150 MWe, depending on the number of fuel channels used. Commercialization envisaged after 2020.

The Advanced Fuel CANDU Reactor (AFCR) is being developed in China as a Generation III 700 MWe class reactor which essentially runs on the used fuel from four PWRs.

Appendix 4: Other advanced HTR designs and concepts

South Africa's  Pebble Bed Modular Reactor  (PBMR) was being developed by a consortium led by the utility Eskom, with Mitsubishi Heavy Industries from 2010. It drew on German expertise and aimed for a step change in safety, economics and proliferation resistance. Production units would be 165 MWe. The PBMR would ultimately have a direct-cycle (Brayton cycle) gas turbine generator and thermal efficiency about 41%, the helium coolant leaving the bottom of the core at about 900°C and driving a turbine. Power is adjusted by changing the pressure in the system. The helium is passed through a water-cooled pre-cooler and intercooler before being returned to the reactor vessel. (In the demonstration plant it would transfer heat in a steam generator rather than driving a turbine directly.) However, development has ceased due to lack of funds and customers.

A larger US design, the  Gas Turbine - Modular Helium Reactor  (GT-MHR), is planned as modules of 285 MWe each directly driving a gas turbine at 48% thermal efficiency. The cylindrical core consists of 102 hexagonal fuel element columns of graphite blocks with channels for helium and control rods. Graphite reflector blocks are both inside and around the core. Half the core is replaced every 18 months. Burn-up is about 100,000 MWd/t. It is being developed by General Atomics in partnership with Russia's OKBM Afrikantov, supported by Fuji (Japan). Initially it was to be used to burn pure ex-weapons plutonium at Seversk (Tomsk) in Russia. The preliminary design stage was completed in 2001, but the program has stalled since. In February 2010 General Atomics announced its Energy Multiplier Module (EM 2 ) design, superseding the GT-MHR.

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