California has Excess Power
San Onofre is permanently shut down and California has excess power without San Onofre and Diablo Canyon nuclear power reactors, according to data from the California Public Utilities Commission (CPUC), the California Energy Commission (CEC) and the electricity grid operator, the California Independent System Operator (ISO).
California historically imported significant amounts of electricity, since its wholesale power markets in the region are relatively open and generation from outside the state is often less expensive. Some power plants located in adjacent states are partially owned by California utility companies, and special agreements exist for exporting power to California. For instance, 18% of the Palo Verde Nuclear Power Plant, located in Tonopah, Arizona, is owned by California-based utilities. See San Onofre nuclear outage contributes to Southern California’s changing generation profile – EIA November 2012.
Energy Saving Tip
Use the SMUD Vampire Load Calculator to see savings from items that are turned off but still plugged in. Note: SDG&E rates are about $0.38 per kWh at the higher end, which is where you will save. SMUD’s calculator maximum is $0.30, so set the calculator kWh to $0.19 and then double the amount for actual savings. See more energy saving tips below.
Slow Progression to Renewable
This 12-year California Power Mix Trend Chart shows a slow progression to renewable energy. The California Energy Commission (CEC) doesn’t count distributed solar (e.g., rooftop solar) and other power sources under 1MG. However, this chart shows major improvements are still needed in the area of renewable energy. Part of this web page includes information on problems with the implementation of renewable energy in California and recommended solutions.
The California 2013-2014 ISO Transmission Plan proves San Onofre and Diablo Canyon are not critical to the electric grid, even though we were told otherwise.
Diablo Canyon‘s 2400 MW of nuclear power is also not needed. The ISO and CEC should be required to develop a renewable and energy efficiency plan for replacement of Diablo Canyon instead of renewing the license for this aging nuclear plant that sits on multiple active earthquake faults and damages millions of sea life every year (due to once-through cooling).
The 2012-2013 Transmission Plan Conclusion, page 169, it states the absence of the Diablo Canyon Power Plant does not have a negative impact on the reliability of the transmission system. The results of this analysis are still valid per Stakeholder Comments, Draft 2015-2016 Study Plan Stakeholder Meeting, February 23, 2015, page 25
This 2013 ISO presentation states “No material mid-term or long-term transmission system impacts associated with [the loss of] Diablo Canyon.” Decision on the 2012/2013 ISO Transmission Plan, Neil Millar, Executive Director, Infrastructure Development, March 20-21, 2013, slide 7
In spite of this, the 2014-2015 ISO Transmission Plan assumes Diablo Canyon will not be shut down. It assumes the license will be renewed and the once-through cooling non-compliance will be resolved or ignored. Page 42:
Nuclear Retirements –Diablo Canyon was modeled on-line and was assumed to have obtained renewal of licenses to continue operation…
OTC Generation: Modeling of the once-through cooled (OTC) generating units followed the compliance schedule from the SWRCB’s Policy on OTC plants with the following exception: base-load Diablo Canyon Power Plant (DCPP) nuclear generation units were modeled on-line…
Most of the electric power generated by Diablo is exported to other areas.
Page 77 Kern Area
The Kern area is located south of the Yosemite-Fresno area and north of the Southern California Edison’s (SCE) service territory. Midway substation, one of the largest substations in the PG&E system, is located in the Kern area and has 500 kV transmission connections to PG&E’s Diablo Canyon, Gates and Los Banos substations as well as SCE’s Vincent substation
Page 81 Central Coast and Los Padres Areas
The 2,400 MW Diablo Canyon Nuclear Power Plant (DCPP) is also located in Los Padres. Most of the electric power generated from DCPP is exported to the north and east of the division through 500 kV bulk transmission lines — in terms of generation contribution, it has very little impact on the Los Padres division operations. There are several transmission ties to the Fresno and Kern systems with the majority of these interconnections at the Gates and Midway substations. Local customer demand is served through a network of 115 kV and 70 kV circuits. With the retirement of the Morro Bay Power Plants, the present total installed generation capacity for this area is approximately 950 MW, including the recently installed photovoltaic solar generation resources, which includes the 550 MW Topaz and 250 MW California Valley Solar Ranch facilities on the Morro Bay-Midway 230 kV line corridor. The total installed capacity does not include the 2,400 MW DCPP output as it does not serve the Los Padres division.
The 2015 ISO planning assumptions [as directed by state policy] continue to rely on Diablo Canyon license renewal and resolving or ignoring once-through-cooling compliance requirements. See Final 2015-2016 Transmission Planning Process Unified Planning Assumptions and Study Plan, March 31, 2015, page 21. These assumptions do not address potential reliability and cost issues of an aging nuclear reactor.
Below ISO Table from ISO 2014-2015 Transmission Planning Process Stakeholder Meeting on November 19, 2014, shows electric generation capacity for nuclear and other energy sources, and lists what was actually dispatched. Pacific Gas & Electric (PG&E) owns Diablo Canyon and has applied for license renewal.
The Western Electricity Coordinating Council (WECC) referenced on the above Table includes other Western states and countries. California uses nuclear energy from Arizona’s Palo Verde nuclear power plant. See map.
The ISO’s 2013 plan kept us in power for all of 2013 without San Onofre. This included electricity needed for peak load periods in the summer as well as voltage and grid stability. They stated “…the reliability risks to southern Orange and San Diego counties are “marginally more challenging” this summer, but still within planning standards.” See ISO 5/6/2013 News Release.
- Handout: No Blackouts With San Onofre Shut Down
- California has Excess Power Without Nuclear Factsheet
- CEC Joint Workshop on Electricity Infrastructure Issues Resulting from SONGS Closure – 7/15/2013 Slide Presentations
- ISO 2013 Summer Load and Resource Assessment 5/6/2013
- ISO Briefing: Summer 2013 Outlook & SONGS Mitigation Planning 3/20/2013 These solutions address 2013 reliability needs without excessive reliance on load-dropping schemes:
- Convert Huntington Beach units 3 & 4 into synchronous condensers for voltage support only.See details in this FERC filing. The annual millions of dollars of costs are itemized at the end of the report (Attachment A). Also see FERC decision to deny JP Morgan’s attempt to stop the conversion to synchronous condensers, and FERC 1/4/2013 order on reliability must run agreement (references ownership of HB 3 & 4 by Edison)
- Install capacitors (80 MVAR each at Santiago and Johanna, 160 MVAR at Viejo).
- Split Barre-Ellis 220 kV circuits (from 2 to 4 lines).
- Confirm new resources South of Lugo.
- Support adequate funding for Flex Alerts and continue to explore applicable demand response.
- ISO Briefing: Decision on 2012/2013 ISO Transmission Plan – March 20-21, 2013
- CPUC 5/10/2013 approved sale of electricity marketing rights at Huntington Beach and two other natural gas-fired plants from JP Morgan Chase to Southern California Edison, clearing the way for summer improvements to the region’s power grid. (UTSanDiego 5/14/13)
- ISO Briefing: Nuclear Generation Studies Preliminary Results 12/13-14/2012
- ISO Legislative and State Regulatory Update Memo 12/6/2012
- California ISO prepares for another potential summer without San Onofre generation – 9/13/2012
- ISO Addendum to 2013 Load Capacity and Technical Analysis without San Onofre – 9/20/2012
- ISO Presentation: Briefing on Summer 2013 Outlook – SONGS Mitigation 9/13/2012
- ISO Presentation: Overview Preliminary Reliability Assessment Results 2012/2013 (w/o San Onofre portion is near end of document) 9/26-27/2012
- CEC request to ISO for 2013 and 2014 plan without San Onofre 9/13/2012
- SDG&E Presentation: 2012 Grid Assessment Results – ISO 9/26-27/2012
- 2012/2013 ISO Reliability Assessment Results for San Diego Gas & Electric
- 2012/2013 ISO Reliability Assessment Results for North of SONGS
- No rolling blackouts with San Onofre shut down – ISO 3/22/2012
- ISO Presentation: Briefing on Summer 2012 Operations Preparedness – 3/22/2012
- CAISO 2012 Annual Report on Market Issues & Performance – April 2013
- CEC Summer 2011 Electricity Supply and Demand Outlook
- CEC AB 1632 Report – Assessment of California’s Nuclear Power Plants
- CPUC 04-14-2011 Senate Energy, Utilities, and Communications Committee Informational Hearing: After Japan: Nuclear Power Plant Safety in California
- California ISO 2010-2011 Transmission Plan
- “The study results from various studies show that there are no thermal overloads, voltage or stability concerns related to the SONGS [San Onofre] units under normal or emergency conditions. Following plots for two of the most severe contingencies and for a sudden loss of load demonstrate that there are no stability concerns related to SONGS units.” [Page 155]
- Non-nuclear once-through cooling (OTC) power plants will be shut down first as the 33% renewables come on-line. The OTC nuclear power plants will remain on-line. [Page 274]. [See also CAISO Once-Through Cooling Generation.]
- California ISO 2011-2012 Transmission Plan
- The study results from various studies show that there are no thermal overloads or transient stability concerns related to the SONGS units under normal or emergency conditions. In 2021, SONGS G-2 [both reactors off-line] contingency results in post-transient divergence. This can be mitigated by increasing generation in the LA Basin. The ISO has historically addressed this concern by maintaining minimum generation dispatch requirements in Southern California in accordance with the SCIT Nomogram. No additional mitigation is considered necessary other than periodically updating and following established minimum generation requirements.
- The following plots for two of the most severe contingencies and for a sudden loss of load demonstrate that there are no stability concerns related to the SONGS units. [Page 195]
- The California ISO 3/22/2012 News Release states “…if both SONGS units remain offline this summer, San Diego and portions of the Los Angeles Basin may face local reliability challenges.” It then states “Fortunately, there are resource options available to help mitigate reliability risks.” The 3/22/2012 briefing by ISO’s Neil Millar addresses the mitigation options and proves there are adequate mitigation options to cover high peak demand and thus avoiding rolling blackouts this summer.
Bill Powers’ 9/21/2012 Quail Brush presentation shows SDG&E has a surplus of energy without San Onofre and does not need to build new gas plants to meet local needs. (Data based on ISO 2012 Summer Loads and Resources Assessment 3/15/2012).
- State “reserve margin” requirement is 15% to 17%. Reserve margin means additional power supply available beyond what is needed to meet the typical weather year peak load.
- Forecast 2012 peak reserve margin for Southern California (SoCal Edison + SDG&E) with San Onofre is 29%. This is over 8,000 MW above projected peak load of 27,399 MW.
- Forecast 2012 peak reserve margin for SoCal without San Onofre is 23%. This is over 6,000 MW above projected peak load of 27,399 MW.
Federal Energy Regulatory Commission (FERC) Chairman Jon Wellinghoff says we’ll be in fine shape without San Onofre this summer.
“…and there certainly may be the opportunity to retire certain types of resources like nuclear facilities if the state were to chose to do so,” the FERC chairman said. UT San Diego 06-04-2012
The FERC Summer 2012 Energy Market and Reliability Assessment supports this:
Without the 2.3 GW from this [San Onofre] plant, NERC forecasts that projected reserve margins in California may be close to, but still be above, the regional target of 15.1 percent.
See NERC’s 2012 Summer Reliability Assessment (page 8 and 9).
The North American Electric Reliability Corporation’s (NERC) mission is to ensure the reliability of the North American bulk power system.
Southern California Edison says they have ample power without San Onofre – OC Register 02-02-2011
San Onofre’s two reactors have been shut down since January 31, 2011 due to critical equipment problems. There have been no resulting blackouts or brownouts in Southern California. The electricity grid was able to compensate for this loss.
California has a huge amount of gas plant capacity that’s not running at any time during the day – CA Independent System Operators
Rolling blackouts have not occurred with San Onofre offline
- 1/31/2012 Radiation Leak: San Onofre has been offline since January 31, 2012 due to a radiation leak from a defective steam generator and decades of premature wear on all four steam generators. There have been no rolling blackouts. See Prediction of rolling blackouts has not occurred.
- 9/8/2011 Southern California and Arizona Power Outage: Southern California had sufficient energy for all 1.4 million SDG&E customers without San Onofre when power was restored after the major Southwestern power outage of September 8th, 2011. When power was restored, San Onofre was still off line. (Units 2 and 3 were restarted and synchronized to the electric grid within 65 and 87 hours, respectively). Southern California did just fine without San Onofre even with very hot days. The electricity grid was able to compensate for this loss of power.
- See April 2012 FERC/NAERC report on Arizona – California Outages on September 8, 2011 (Causes and Recommendations (P.78)
- See FERC Approves Fifth Settlement in 2011 Southwest Blackout Case, November 28, 2014.
- The Federal Energy Regulatory Commission (FERC) has approved a stipulation and consent agreement among FERC’s Office of Enforcement, the North American Electric Reliability Corporation (NERC), and the California Independent System Operator (CAISO) that includes a $6 million civil penalty and resolves the investigation by FERC Enforcement staff and NERC into CAISO’s involvement in the Sept. 8, 2011, Southwest blackout.
- …Enforcement staff and NERC concluded that CAISO had failed to appropriately monitor the current flow on Path 44, or otherwise take corrective action to avert operation of the intertie separation scheme at the San Onofre nuclear generating plant switchyard. Initiation of the intertie separation scheme contributed to tripping the San Onofre nuclear generating plant offline, and eventually resulted in the complete blackout of San Diego and the Baja California control area operated by Comisión Federal de Electricidad…
Nuclear Plant Owners Refuse to Provide Plans for Shutdown
- California nuclear plant owners have not provided plans for alternate sources of energy to replace nuclear power.
- Plans are needed in case of emergency shutdown and to prepare for license expiration of the plants. Their plan is to continue relicensing these old plants. The plants were originally designed for a lifespan of 40 years or less. San Onofre licenses expire in 2020. Diablo Canyon licenses expire in 2024 and 2025.
- The plant owners have refused to comply with state requests to provide their plan for an alternative energy source prior to relicensing.
- Nuclear power is not a reliable source of power, as shown by the months of unplanned shutdown of San Onofre since January 2012.
Percent of power from San Onofre
There are numerous percentages quoted regarding how much electricity San Onofre provides. However, the real question is not how much it provides, but how much it needs to provide. However, for those interested in the percentages, here they are:
- San Onofre provides only 5.5% of the energy CONSUMED in California, according to the California Energy Commission.
- San Onofre provides less than 7% of California’s overall electricity SUPPLY. (According to California Energy Commissioner James Boyd, California’s nuclear power plants provides approximately 13% of California’s overall electricity supply — San Onofre 2150MW and Diablo Canyon 2061MW.)
- SDG&E’s current Power Content Label shows nuclear power provides 16% of SDG&E’s 2010 Power Mix. This may include nuclear power from the Palo Verde nuclear power plant in Arizona.
- SCE’s current Power Content Label shows nuclear power provides 19% of SCE’s 2010 Power Mix. This may include nuclear power from the Palo Verde nuclear power plant in Arizona.
- See CEC 2010 Total Electricity System Power for details on this and related information, such as other sources of electricity (both in-state and elsewhere). In-state generation is reported generation from units 1 MW and larger.
- Reactor Unit 1 is being decommissioned. In service January 1, 1968 to November 30, 1992
- Reactor Unit 2 is being decommissioned. It provided up to 1070MW, in service 1983 to January 10, 2012.
- Reactor Unit 3 is being decommissioned. It provided up to 1080MW, in service 1984 to January 31, 2012.
- See NRC website Plans for Decommissioning of San Onofre Nuclear Generating Station Units 2 and 3. NRC Unit 1 website lists estimated date for closure as 2030.
Diablo Canyon (located in San Luis Obispo), is owned and operated by Pacific Gas & Electric (PG&E)
- Reactor Unit 1 provides up to 1073MW, in service since 1985.
- Reactor Unit 2 provides up to 1087MW, in service since 1986.
Cost of Nuclear Power
Reports of nuclear power costing less than other sources of energy needs to be reevaluated in California, especially at San Onofre. For example, the cost analysis to replace the San Onofre steam generators assumed high gas prices. It also excluded the cost of storing tons of toxic radioactive waste for tens of thousands of years as well as numerous other costs. It excluded all energy efficiency alternatives, such as targeted and increased cost incentives to replace residential and commercial inefficient air conditioners and load balancing in the Edison and SGD&E utility districts.
- See energy saving tips.
- See available rebates.
- Heating and cooling are almost half of energy consumption, yet rebates are limited or non-existent for heating and air conditioning systems (HVAC).
- SCE and SDG&E are given billions of dollars of ratepayer money for energy efficiency programs. SCE currently has about half a billion dollars in energy efficiency funds that must be used by the end of 2012.
- California’s concerns about peak energy demand in the summer and carbon emissions can more effectively be addressed with more aggressive incentives and programs for central air conditioner replacements — especially in the area served by the San Onofre nuclear power plant.
- SCE and SDG&E offer residential customers no rebates to upgrade to more efficient central heating and cooling (HVAC) systems. They only offers rebates on installation costs for new air conditioning systems. The number of contractors to choose from is limited and there are other hurdles that make this program less attractive. The information is difficult to find on SDG&E’s website. They send you to a vendor website for information, without mentioning the amounts of rebates possible for installation.
- SDG&E’s Energy Efficiency Business Rebates Product Catalog lists rebates available to business. No central air conditioning systems are included.
- SCE’s Business Solutions Directory contains the most complete and current list of eligible equipment (solutions) and qualification criteria for incentives available to customers through SCE’s 2010–2012 Energy Efficiency Program. It also includes a summary of Demand Response Technology Incentives available for customers installing qualified equipment that enables load-shifting strategies. For updates on program changes (due to funding availability or other other reasons), go to SCE Energy Management Online Application Tool. SCE has recently added ice storage air conditioning installation rebates to their HVAC Optimization Program.
California Mandates 33% Renewable Energy by 2020
- California requires utility companies to increase the percentage of renewable energy in the state’s electricity mix to 33 percent by 2020.
- This process should be expedited, with nuclear energy being the first replaced with renewable energy. However, the ISO Transmission Plan (page 274) uses renewables to replace gas plants instead of California’s nuclear plants.
- ISO reported California saved 10 million pounds of CO2 output solar power in one day on August 14, 2012.
Southern California Edison stalls solar projects for years
Millions of dollars in renewable energy projects intended to provide power to facilities in California’s national parks and forests have been sitting idle for years because of Southern California Edison.
There’s 24-plus systems in the Southern California Edison area that have been installed in the last three years that we have not been able to negotiate an interconnection agreement on,” said Jack Williams, who retired this month as the National Park Service’s Oakland-based regional facilities manager. “We think we are close at times, but then nothing. We were successful with PG&E, but with Southern California Edison…. They have been a bit more difficult. We’ve raised the flag many times. It’s an issue for all federal agencies.”
California Solar Initiative – Solar Rebates
The California Solar Initiative (CSI) is the solar rebate program in California for customers of investor-owned utilities – PG&E, Southern California Edison and SDG&E. The CPUC is providing $2.1 billion to businesses, nonprofit organizations, public agencies and homeowners.
Nuclear Power is no solution to Climate Change
See NIRS slide presentation explaining why nuclear power is no solution to climate change.
- Takes too many reactors
- Too little safety
- Too much waste
- Too much carbon
- Too much emissions
- Not suited for warming climates
- Uses too much water
- Too slow to build
- Renewables and efficiency are faster, cheaper, safer and cleaner
- Too expensive
A Plan to Power 100 Percent of the Planet with Renewables
A 2009 Stanford University study ranked energy systems according to their impacts on global warming, pollution, water supply, land use, wildlife and other concerns. The very best options were wind, solar, geothermal, tidal and hydroelectric power—all of which are driven by wind, water or sunlight (referred to as WWS).
Nuclear power, coal with carbon capture, and ethanol were all poorer options, as were oil and natural gas. The study also found that battery-electric vehicles and hydrogen fuel-cell vehicles recharged by WWS options would largely eliminate pollution from the transportation sector.
To ensure that our system remains clean, they considered only technologies that have near-zero emissions of greenhouse gases and air pollutants over their entire life cycle, including construction, operation and decommissioning. For example, when burned in vehicles, even the most ecologically acceptable sources of ethanol create air pollution that will cause the same mortality level as when gasoline is burned. Nuclear power results in up to 25 times more carbon emissions than wind energy, when reactor construction and uranium refining and transport are considered.
About the Authors
Mark Z. Jacobson is professor of civil and environmental engineering at Stanford University and director of the Atmosphere/Energy Program there. He develops computer models to study the effects of energy technologies and their emissions on climate and air pollution.
Mark A. Delucchi is a research scientist at the Institute of Transportation Studies at the University of California, Davis. He focuses on energy, environ¬mental and economic analyses of advanced, sustainable transportation fuels, vehicles and systems.
Fuel Cell Technology
- Examples of current fuel cell technology
- What is a fuel cell?
- 30% federal tax credit
- Clean Power Guide – comparing clean technologies
Nuclear Power in France: Setting the Record Straight
France gets nearly 80% of its electricity from its 58 nuclear reactors. However, such a heavy reliance on nuclear power brings with it many major, unresolved problems most especially that of radioactive waste. As a result, France has a hugely complex and unsolved radioactive waste problems, as well as health, environmental, and financial problems.
Like the United States:
- France has not solved its nuclear waste problem.
- French nuclear power has been costly to taxpayers.
- French reactor technology is aging and unsafe.
- French reactors, and reactor construction projects, are unreliable.
- The French do not all love their nuclear power.
- France’s nuclear power has produced serious health and environmental problems.
Thorium “fuel” has been proposed as an alternative to uranium fuel in nuclear reactors. There are not “thorium reactors,” but rather proposals to use thorium as a “fuel” in different types of reactors, including existing light-water reactors and various fast breeder reactor designs. Contrary to the claims made or implied by thorium proponents, however, thorium doesn’t solve the proliferation, waste, safety, or cost problems of nuclear power, and it still faces major technical hurdles for commercialization. See Fact Sheet by the Institute for Energy and Environmental Research and Physicians for Social Responsibility.
AP1000 Nuclear Reactor
The new AP1000 nuclear reactor has serious design flaws. On a 4 to 1 vote, the NRC Commissioners approved building this in Georgia, even though numerous problems exist with the design and lessons learned from Fukushima have not been implemented. Vogtle nuclear plant now under construction in eastern Georgia.
- For example, see Containment Leakage, An Unreviewed Safety Issue, April 7, 2010, Arnie Gundersen, Fairewinds Associates.
- The AP1000, as well as other new reactor designs, use high burnup fuel. High burnup fuel waste is so dangerous, the NRC will not approve a transportation container for it and will only approve 20 years of dry storage for it. More…
- George ratepayers are required to pay for the construction of this plant before it’s even built, with no guarantees it will be successful.
Small Modular Reactors (SMR)
Small modular reactors present many of the same problems as other reactors, as well as introducing additional problems as noted in Prognostics Health Management for Advanced Small Modular Reactor Passive Components, October 7, 2013, Ryan M. Meyer, et.al. Harsher operating environments and up to 30 years between refueling make it a challenge to adequately inspect for degradation. Technology needed is not available or not adequate.
2.1. Operating Environment and Materials Degradation
Passive components in AdvSMRs will be subject to relatively harsh operating environments in comparison to LWRs. This includes higher temperatures, fast neutron fluxes, and corrosive coolant conditions. Materials for advanced nuclear reactor applications generally consider radiation damage resistance, environmental stability, and high-temperature capability as paramount (Yvon & Carre, 2009; Zinkle & Busby, 2009). Volumetric swelling and dimensional stability, embrittlement, stress corrosion cracking, irradiation and thermal creep, and corrosion are critical materials degradation issues. Welds are problematic in nuclear structures as preferred sites for environmental degradation and stress-assisted degradation processes. Compatibility issues arise with regard to liquid metal coolants for liquid metal fast reactors (LFRs and SFRs) when metals and alloys in flowing coolant experience unwanted chemical reactions or leaching. In addition to driving the degradation issues, the harsh operating environment will negatively impact the performance of sensors for health monitoring and constrain their deployment…
2.4. Refueling Schedules
Several advanced reactor concepts are intended to operate for extended periods between outages. For LWRs, outages are scheduled every 18–24 months for refueling but several advanced reactor concepts are intended to operate with much longer periods between refueling. The Toshiba 4S concept, for instance, is designed to operate up to 30 years without refueling (Tsuboi, Arie, Ueda, Grenci, & Yacout, 2012). The SSTAR is another advanced reactor concept with targeted operation periods of 15 to 30 years between refueling activities (Smith, Halsey, Brown, Sienicki, Moisseytsev, & Wade, 2008). Several other reactor concepts such as the liquid fuel MSRs and pebble bed-type VHTRs may have the capability to refuel while operating. Thus, it will be important that PHM systems for AdvSMRs are capable of utilizing data obtained from on-line measurements as well as data collected during outages…
3.1. Sensors and Instrumentation for Condition Assessment of Passive Components
Because opportunities to perform inspections and maintenance of passive components when the plant is offline will be limited in many designs, there is a need to monitor risk-significant passive components during plant operation for degradation. In addition, there is a need to monitor the stressors (time at temperature, fluence, mechanical loads, etc.) that are expected to contribute to degradation of these components. Requirements for sensors and instrumentation (whether for on-line or off-line condition assessment or for stressor monitoring) include: • Ability to tolerate the harsh operating conditions in AdvSMRs. • High sensitivity, to ensure that reliable measurements from earlier stages of degradation are possible. • Capability to quantify the amount of degradation from the measurements…
6. CONCLUSIONS AND DISCUSSIONS
PHM for passive components in AdvSMRs can play a key role in facilitating the deployment of AdvSMRs by minimizing controllable day-to-day costs associated with plant O&M. Although potential concepts and designs for AdvSMRs vary significantly, there are some general features that can help define the requirements of a PHM system for passive components. Degradation may be sampled in AdvSMRs through online and offline measurements. A PHM system is likely to be most effective if prognostics algorithms can use both types of measurements. A basic illustration is provided of a prognostics method based on the PF technique for predicting passive component failure due to thermal creep degradation. The illustration simulates sampling of creep degradation with offline NDE measurements. The illustration only represents the start of prognostic algorithm development as additional functionality to address many the requirements in Section 3 will need to be demonstrated. The approach is to alternately add functionality and demonstrate that added functionality with accelerated aging studies.