ML24029A143
| ML24029A143 | |
| Person / Time | |
|---|---|
| Issue date: | 02/20/2024 |
| From: | Figueroa G NRC/OE |
| To: | |
| References | |
| DPO-2016-003 | |
| Download: ML24029A143 (1) | |
Text
DPO Case File for DPO-2016-003 The following pdf represents a collection of documents associated with the submittal and disposition of a differing professional opinion (DPO) from an NRC employee involving approving license amendments based on using the risk management technical specifications 4b and 5b risk initiatives, and changing the reporting guidelines for loss of off-site power.
Management Directive (MD) 10.159, The NRC Differing Professional Opinions Program, describes the DPO Program. https://www.nrc.gov/docs/ML2312/ML23123A099.pdf The DPO Program is a formal process that allows employees and NRC contractors to have their differing views on established, mission-related issues considered by the highest level managers in their organizations, i.e., Office Directors and Regional Administrators. The process also provides managers with an independent, three-person review of the issue (one person chosen by the employee). After a decision is issued to an employee, they may appeal the decision to the Executive Director for Operations (or the Commission, for those offices that report to the Commission).
Because the disposition of a DPO represents a multi-step process, readers should view the records as a collection. In other words, reading a document in isolation will not provide the correct context for how this issue was reviewed and considered by the NRC.
It is important to note that the DPO submittal includes the personal opinions, views, and concerns by NRC employees. The NRCs evaluation of the concerns and the NRCs final position are included in the DPO Decision.
The records in this collection have been reviewed and approved for public dissemination.
Document 1: DPO Submittal Document 2: Memo Establishing DPO Panel Document 3: DPO Panel Report Document 4: Independent Review of DPO Panel Report Document 5: DPO Decision Document 6: DPO Appeal Submittal Document 7: Statement of Views Document 8: DPO Appeal Decision
Document 1: DPO Submittal
Document Markings...
NRG FORM 680 U.S. NUCLEAR REGULATORY COMMISSION DPO Case Number H}9-,f11!,;
DPo- o \\
- 00 3 M<tMO 1r; 159
(i)
DIFFERING PROFESSIONAL OPINION
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Name and Title of Submitter$
Organization Telephone Number (10 numeric digits)
R Mathew.TL; J. Zi,n:-r.erma1:. BC T. Matinez-Navedo. EE.
G. Matharu Sr. EE: S Ray. Sr EE* and S. Som Sr. EE.
NRR/DE'EEEB (301) 415-8324 Name and Title of Supervisor Organization Telephone Number (10 numeric digits)
John Lubinski Division Direct1*,. Division of Engineerii g NRR/DE!EEEB (301) 415-3298 When was the prevailing staff view, existing decision or stated position established and where can it be found?
Date 8/13/15,2/2/15.2/14/13 Where (i.e., ADAMS ML#, if applicable): ML1:-J22A l 'l7, \\1 U60.'* 'A 1 1)7, :\\il 12.'C,3..\\ilhl Subject of DPO
- rhe NRC mission to protect public health, safety, and the environment is directly affectE:d by approving the license amendments h;;sec on using the RMTS 4b and Sb risk initir;tives; and c:har19:ng the reporting guidelines for LOOP.
Summary of prevailing staff view, existing decision, or stated position. (Use continuation pages or attach Word document)
Reason for DPO, potential impact on mission, and proposed alternatives. (Use continuation pages or attach Word document)
Do you believe the issue represents an irnmediate L{J Yes, (Explain on continuation page(s) or attach Word pubic health and sarety concern?
No LJ document).
Is the issue directly relevant to a decision pending
[2J No D
Yes, Reference Document before the Commission?
(i.e., ADAMS ML#)
l{J lnfonnal discussions took place (Identify with 1-1 Extenuating circumstances prevented informal discussions whom and time frame of discussions)
Part of the NCP process.. Discussed with ORA and DORL ODs and BCs (2015-20 1 5 and DIRS ODs and BCs (2012-2013)
Proposed panel members are (in priority order):
- 1. rhomas Koshy, Sr. Electrical Engineer. RES/DE/ICEEB
- 3.
Kenn Milter. Sr. Electiicai Engineer. RES/DE/ICEE8
- 2. Paul Rebstock Jr :-1*. f & C Eng 11eer, RESiDE.ICEEB D
No names of potential panel members will be provided.
When the process is complete, I would like the DPO case file:
D Non-Public 0
Public S
- rrr, E OF SUBMffTERS" DATE
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4'A- //).,<£ £i.. '---.)11v (
/tp6 SIGNATURE OF CO-SUBMITTER (If any) _/ h,,-(J
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DATE SCAN THE SIGNED AND DATED FORM (INCLUDE ANY CONTINUATION PAGES OR WORD DOCUMENTS) AND E-MAIL TO: DJ?OPI\\IL.Resource@nrc.gov s
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ANAGER
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L Delete Continuation Pa_ge**1 DPO accepted LJ DPO returned I Add Continuation PageJ I
Document 2: Memo Establishing DPO Panel
November 8, 2016 MEMORANDUM TO:
Robert K. Caldwell, Panel Chairperson Office of New Reactors Tom Koshy, Panel Member Office of Nuclear Regulatory Research Sara E. Kirkwood, Panel Member Office of the General Counsel Robert C. Daley, Panel Member Region III THRU:
Patricia K. Holahan, Director /RA/
Office of Enforcement FROM:
Renée M. Pedersen /RA/
Sr. Differing Professional Views Program Manager Office of Enforcement
SUBJECT:
AD HOC REVIEW PANEL - DIFFERING PROFESSIONAL OPINION ON RISK MANAGEMENT TECHNICAL SPECIFICATION (RMTS) 4b AND 5b RISK INITIATIVES AND EVENT REPORTING FOR LOSS-OF-OFFSITE POWER (LOOP)
In accordance with Management Directive (MD) 10.159, The NRC Differing Professional Opinion Program; and in my capacity as the Differing Professional Opinion (DPO) Program Manager; and in coordination with Patricia Holahan, Director, Office of Enforcement; Bill Dean, Director, Office of Nuclear Reactor Regulation; and the DPO submitters; you are being appointed as members of a DPO Ad Hoc Review Panel (DPO Panel) to review a DPO submitted by U.S. Nuclear Regulatory Commission (NRC) employees.
The DPO (Enclosure 1) involves concerns related to approving the license amendments based on using the Risk Management Technical Specification (RMTS) 4b and 5b risk initiatives and changing the event reporting guidelines for loss-of-offsite power (LOOP). The DPO has been forwarded to Mr. Dean for consideration and issuance of a DPO Decision.
CONTACTS: Renée Pedersen, OE (301) 415-2742 Marge Sewell, OE (301) 415-8045
The DPO Panel has a critical role in the success of the DPO Program. Your responsibilities for conducting the independent review and documenting your conclusions in a report are addressed in the handbook for MD 10.159 in Section II.F and Section II.G, respectively.
The DPO Web site also includes helpful information, including interactive flow charts, frequently asked questions, and closed DPO cases, including previous DPO Panel reports. We will also be sending you additional information that should help you implement the DPO process.
Because this process is not routine, we will be meeting and communicating with all parties during the process to ensure that everyone understands the process, goals, and responsibilities.
Disposition of this DPO should be considered an important and time sensitive activity. The timeliness goal for issuing a DPO Decision is 120 calendar days from the day the DPO is accepted for review. In this case, the DPO was accepted for review on October 18, 2016 and therefore, the timeliness goal for issuing this DPO Decision is February 15, 2017.
Process Milestones and Timeliness Goals for this DPO are included as Enclosure 2. The timeframes for completing process milestones are identified strictly as goalsa way of working towards reaching the DPO timeliness goal of 120 calendar days. The timeliness goal identified for your DPO task is 75 calendar days.
Although timeliness is an important DPO Program objective, the DPO Program also sets out to ensure that issues receive a thorough and independent review. The overall timeliness goal should be based on the significance and complexity of the issues and the priority of other agency work. Therefore, if you determine that your activity will exceed your 75-day timeliness goal, please send an e-mail to Mr. Dean with a copy to DPOPM.Resource@nrc.gov and include the reason for the extension request and a proposed completion date for your work. Mr. Dean can then determine if he needs to submit an extension request for a new DPO timeliness goal to the Executive Director for Operations for approval.
An important aspect of our organizational culture includes maintaining an environment that encourages, supports, and respects differing views. As such, you should exercise discretion and treat this matter appropriately. Documents should be distributed on an as-needed basis.
In an effort to preserve privacy, minimize the effect on the work unit, and keep the focus on the issues; you should simply refer to the employees as the DPO submitters. Avoid conversations that could be perceived as hallway talk on the issue and refrain from behaviors that could be perceived as retaliatory or chilling to the DPO submitters or that could potentially create a chilled environment for others. It is appropriate for employees to discuss the details of the DPO with their co-workers as part of the evaluation; however, as with other predecisional processes, employees should not discuss details of the DPO outside the agency. If you have observed inappropriate behaviors or receive outside inquiries or requests for information, please notify me.
On an administrative note, please ensure that all DPO-related activities are charged to Activity Code ZG0007.
We appreciate your willingness to serve and your dedication to completing a thorough and objective review of this DPO. Successful resolution of the issues is important for NRC and its
stakeholders. If you have any questions or concerns, please feel free to contact me or Marge Sewell. We look forward to receiving your independent review results and recommendations.
Enclosures:
- 1. DPO-2016-003
- 2. Process Milestones and Timeliness Goals cc: w/o
Enclosures:
B. Dean, NRR S. McDermott, NRR M. Weber, RES I. Jung, RES M. Doane, OGC M. Lemoncelli, OGC M. Mayfield, NRO M. Shuaibi, RIII K. OBrien, RIII R. Mathew J. Zimmerman T. Martinez-Navedo G. Matharu S. Ray S. Som P. Holahan, OE M. Sewell, OE
stakeholders. If you have any questions or concerns, please feel free to contact me or Marge Sewell. We look forward to receiving your independent review results and recommendations.
Enclosures:
- 1. DPO-2016-002
- 2. Process Milestones and Timeliness Goals cc: w/o
Enclosures:
B. Dean, NRR B. McDermott, NRR M. Weber, RES I. Jung, RES M. Doane, OGC M. Lemoncelli, OGC P. Holahan, OE M. Sewell, OE ADAMS Package: ML16313A328 MEMO: ML16313A260 - ML16295A102 - ML1629A102 OE-011 OFFICE OE: DPO/PM OE: D NAME RPedersen PHolahan DATE 11/08/2016 11/08/2016 OFFICIAL RECORD COPY
Document 3: DPO Panel Report
May 10, 2018 MEMORANDUM TO:
Brian E. Holian, Acting Director Office of Nuclear Reactor Regulation FROM:
Robert K. Caldwell, Panel Chairperson /RA/
Office of New Reactors Thomas Koshy, Panel Member /RA/
Office of Nuclear Regulatory Research Sara B. Kirkwood, Panel Member /RA/
Office of the General Counsel Robert C. Daley, Panel Member /RA/
Region III
SUBJECT:
DIFFERING PROFESSIONAL OPINION PANEL REPORT ON RISK MANAGEMENT TECHNICAL SPECIFICATION (RMTS) 4b AND 5b RISK INITIATIVES AND EVENT REPORTING FOR LOSS-OF-OFFSITE POWER (LOOP) (DPO-2016-003)
In a memorandum dated November 8, 2016, you appointed us as members of a Differing Professional Opinion (DPO) Ad Hoc Review Panel (Panel) to review a DPO regarding approving the license amendments based on using the Risk Management Technical Specification (RMTS) 4b and 5b risk initiatives and changing the event reporting guidelines for loss-of-offsite power (LOOP). Specifically, (1) the Safety Evaluation for the Vogtle License Amendment Request to implement risk-informed completion times (as a pilot plant) per TSTF-505, Revision 1, Provide Risk-Informed Extended Completion Times - RITSTF Initiative 4b was approved without a sound technical and regulatory basis; (2) the Safety Evaluation for the relocation of all surveillance frequency requirements to another section of the Technical Specifications per RITSTF Initiative 5b, such that the license can change them without prior approval of the staff did not provide adequate regulatory and technical bases to conclude that all deterministic criteria were met; and (3) recent changes to NUREG-1022, Event Reporting Guidelines: 10 CFR 50.72 and 50.73, which apply the 10 CFR 50.72/73 regulation only to safety-related structures, systems, and components, inappropriately excludes the offsite power system from reportability requirements that is essential for assessing the continued availability of the preferred source of power. The Panel reviewed the DPO in accordance with Management Directive 10.159, The NRC Differing Professional Opinions Program. The Panels report is enclosed for your consideration.
CONTACT: Robert Caldwell, NRO (301) 415-2367
2 In the panels opinion, the underlying issue for first two concerns appear to be similar.
Specifically, RITSTF Initiatives 4b and 5b are being implemented in more of a risk-based manner rather than in a risk-informed manner as directed by the commission. The panel did not reach any consensus on these issues. The submitters DPO helped identify concerns issues with respect to 4b. The agency is taking measures to address the concerns in part. The third concern about tracking loss of offsite power and its potential impact on its event frequency is also addressed.
The panel did not reach unanimous conclusions, and thus the report identifies the views of individual panel members.
Please do not hesitate to contact us if you have any questions regarding the enclosed report.
Enclosure:
DPO Panel Report cc: Anne Boland, Director, OE
ML18193B040 OFFICE NRR OGC RIII NRO NAME TKoshy`
SKirkwood RDaley RCaldwell DATE 5/10/2018 5/10/2018 5/10/2018 5/10/2018
4 Differing Professional Opinion (DPO) on approving the license amendments based on using the Risk Management Technical Specification (RMTS) 4b and 5b risk initiatives and changing the event reporting guidelines for loss-of-offsite power (LOOP) (DPO-2016-003)
DPO Panel Report
________ _/RA/ ________
Robert K. Caldwell, Panel Chair
_______ __/RA/ ________
Thomas Koshy, Panel Member
________ _/RA/ ________
Sara B. Kirkwood, Panel Member
______ ___/RA/ ________
Robert B. Daley, Panel Member Date: May 10, 2018 Enclosure Introduction Differing Professional Opinion (DPO-2016-003) was received on October 12, 2016. The concerns in the DPO are related to approving the license amendments based on using the Risk Management Technical Specification (RMTS) 4b and 5b risk initiatives and changing the event reporting guidelines for loss-of-offsite power (LOOP). The memorandum from the Director, Office of Nuclear Reactor Regulation, establishing the DPO Panel was issued on November 8, 2016.
The memorandum tasked the Panel to conduct a review of the issues, maintain the scope within those identified by the original written DPO, and issue a report. The Panel met with the submitters on November 15, 2016, and established a concise statement of the submitters concerns (See below). The submitter approved the statement of concerns on April 19, 2017.
During the course of the Panels review, the Panel interviewed the DPO submitters, conducted NRC document reviews, and interviewed members of the staff. The document reviews included a multitude of related non-concurrences (NCP-2015-009; NCP-2015-012; NCP-2016-005; NCP-2016-010; NCP-2016-011; NCP-2016-012; NCP-2017-004, NCP-2017-005 and NCP-2017-008),
which were reviewed to the extent the issues raised in the NCPs relate to the issues raised by the DPO.
Summary of Issues Based on a review of the DPO package and interviews with the submitters, the following concerns were identified by the Panel:
1.
RITSTF Initiative 4b. Safety Evaluations associated with RITSTF Initiative 4b are being prepared with a primary focus on probabilistic risk (risk-based principles established by TSTF and Topical Report rather than risk-informed principles that complement the deterministic principles). Consequently, the technical bases established in relevant NRC requirements including plant-specific design and licensing basis are not specifically addressed to justify approval of license amendments referencing RITSTF 4b, and therefore reasonable assurance of adequate protection of the public health and safety is not provided.
2.
RITSTF Initiative 5b. Safety Evaluations associated with RITSTF Initiative 5b are being prepared with a primary focus on probabilistic risk (risk-based principles established by TSTF and Topical Report rather than risk-informed principles that complement the deterministic principles). Consequently, the technical bases established in relevant NRC requirements including plant-specific design and licensing basis are not specifically addressed to justify approval of license amendments referencing RITSTF 5b, and therefore reasonable assurance of adequate protection of the public health and safety is not provided.
3.
Event Reporting Guidelines for Loss of Offsite Power (LOOP). By interpreting 10 CFR 50.72/50.73 to apply only to safety-related structures, systems, and components, NUREG-1022 Rev 3, inappropriately excludes the offsite power system from reportability requirements that is essential for assessing the continued availability of the preferred source of power. The under-reporting of LOOP causes non-conservative plant-specific risk assessments as well as Reactor Oversight Process Significance Determination Process evaluations because of changes in initiating event frequencies.
The above overarching statements of concern were developed based on a litany of specific issues the panel identified form the submitters input. Subsequently, in conjunction with the submitter, the concern was written at a level to address the submitters underlying issue.
The submitters suggested remedies were:
1.
Withdraw the approval of both risk initiative 4b and 5b 2.
Issue a RIS highlighting the issues raised in the DPO 3.
Revise NUREG 1022 to require the reporting of all LOOPs Concern 1: Risk-informed extended completion times-RITSTF Initiative 4b. Safety Evaluations (SEs) associated with RITSTF Initiative 4b are being prepared with a primary focus on probabilistic risk (risk-based principles established by TSTF and Topical Report rather than risk-informed principles that complement the deterministic principles). Consequently, the technical bases established in relevant NRC requirements including plant-specific design and licensing basis are not specifically addressed to justify approval of license amendments referencing RITSTF 4b, and therefore reasonable assurance of adequate protection of the public health and safety is not provided.
Discussions and Conclusions View of Panel Member Caldwell & Kirkwood We would like to acknowledge, up front, the efforts of the submitters to raise these concerns.
Given the length of the review time for this DPO, we believe it is appropriate to document some of the history of this DPO concerning the implementation of the Risk Managed Technical Specification (RMTS) guidelines. The DPO was developed subsequent to the Vogtle license amendment request (LAR) which was the pilot for this risk-informed effort1. The safety evaluation (SE) for this LAR was originally routed for concurrence in the summer of 2015. During that routing, a non-concurrence was tendered by EEOB1 staff (NCP-2015-009, ADAMS Accession No. ML15322A197) and supported by the EEOB branch chief. Following disposition of the NCP and, in part, based on some of the issues raised by the non-concurring staff, the NRC staff developed a significant number of additional questions regarding this LAR. Exploration of these issues resulted in the licensee removing some of the actions originally included, providing additional justification for selected technical specification (TS) actions, and introducing additional constraints to implement the risk-informed TS completion time (RICT) program.
This DPO and the associated NCPs on the implementation of the RITSTF Initiative 4b (risk-inform Technical Specification Completion Times), have in no small part, resulted in program improvements and yielded positive results in the NRC staff working collaboratively through difficult and highly technical issues. Some of the more notable changes were:
Additional justification was provided to demonstrate how defense-in-depth is maintained while in a RICT; Additional constraints were added for addressing the possibility of common-cause failure for both emergent failures and planned maintenance while in a RICT; Some actions were identified as not being appropriate for applying a RICT; Additional constraints were applied to TS loss of function (TS LOF) situations; A license condition was added for change control of the PRA used to calculate a RICT.
Additionally, it is important to note the generic impact as well. Although the Vogtle LAR did not directly reference TSTF-505, Revision 1 (TSTF-505), which provides model TS changes to adopt RICTs in accordance with NEI 06-09, Revision 0-A, the application was considered a pilot for implementing a RICT program. The concerns identified during the NRCs review of the Vogtle LAR also caused the NRC staff to suspend approval of TSTF-505 (ADAMS Accession No. ML16281A021), pending resolution of the subject issues. That effort is currently ongoing.
1 We note that the TSTF refers to South Texas as the pilot for this effort. However, it appears that Vogtle was also considered a pilot for the LAR, and was granted a fee waiver on that basis. See ML102910351.
As indicated above, the submitters identified several issues that needed to be resolved prior to implementing the RITSTF 4b program. Subsequently, the NRC suspended approval of RITSTF 4b on November 15, 2016 (ML16300A245). In a letter to the Technical Specifications Task Force, dated November 15, 2016 (ML16281A021) the NRC specifically identifies the issue with the definition of Probabilistic Risk Assessment (PRA) Functional and how to use the program when Technical Specifications (TS) conditions involve mode changes or unit shutdown. As of this date, the RITSTF 4b program is still being reviewed by the Technical Specifications Task Force.
The NRC has been working with industry and other stakeholders for some time be improve the use of risk and identifying and assessing changes to plants. The use of a formal and well understood process improves the transparency and predictability of the agencys actions. On April 23, 2007 the ACRS sent a letter (ACRSR-2245) to the EDO concerning their briefing on Risk-Informed Technical Specifications Initiative 4b, Risk-Managed Technical Specifications (RMTS) Guidelines which concluded that ACRS concurred with the staff that the program requirements of NEI 06-09 were acceptable for referencing by licensees proposing to amend their technical specifications to implement RMTS. Specifically, the ACRS commented that: The major benefit of this initiative is that it provides flexibility to the licensees to operate the plants according to the risk associated with specific plant configurations. It heightens the operators awareness of the existing risk profile of the plant, and avoids unnecessary plant shutdowns.
One of the significant issues raised by the submitters was the lack of balance between the historic deterministic license reviews and the newer more risk-based approach in the RITSTF 4b program. The panel reviewed the previous implementing guidance (RG 1.174, revision 2 dated May 2011) and compared it to the new guidance (RG 1.174, revision 3 dated January 2018). The new guidance document was more detailed and provided the opportunity to better balance the deterministic defense-in-depth review with the PRA insights. A review of the final Safety Evaluation for Vogtle Amendments 188 and 171 (ML15127A669), which included an OGC review, demonstrated how the new RG 1.174 Rev 3 is expected to be implemented for risk informed decisions on plant specific changes, which includes RITSTF 4b type requests. The review continues to focus on the five principles in RG 1.174, which include both a deterministic perspective and a PRA perspective. However, RG 1.174, revision 3 has substantially enhanced the principles by providing more specifics on what is needed to be reviewed. The current RG provides a sound structure to develop a risk-informed conclusion.
Additionally the NRC has worked to better understand the effort needed to implement the risk-informed regulatory structure. On May 11, 2017, the Commission was briefed of risk-informed regulation (ML17135A407). During this briefing RITSTF 4b was specifically discussed, as well as aspects of this DPO and its positive impact. The staff identified that they thought it was necessary to first conduct a pilot review for RITSTF 4b implementation, which is not unusual for complex first-of-a-kind power reactor reviews and the case for the pilot involved was the subject Vogtle LAR. In the briefing, it was stated that there were some significant concerns raised by staff on the implementing guidance and how the applicants were using that guidance and the staff efforts to resolve these issues were not effective. Ultimately, the positive aspect of this experience was that the level of collaboration between the engineering staff and the PRA practitioners to work through the issues associated with risk-informed tech specs has resulted in greater shared understandings that will significantly help as we review other risk-informed initiatives in the future.
This Commission briefing resulted in SRM M170511, where the Commission directed the staff to provide the Commission with an information paper discussing its plans for increasing staff capabilities to use risk information in decision-making activities. The paper was to identify challenges towards further progress in risk-informed decision making and discuss measures to overcome these challenges. The paper was also to summarize the current mandatory training requirements related to risk-informed decision making for managers and staff. Subsequently, the staff provided the Commission with SECY-17-0112, Plans for Increasing Staff Capabilities To Use Risk Information in Decision-Making Activities, dated November 17. 2017 (ML17270A197), which identified challenges to further developing a risk-informed decision-making framework. The paper also identifies strategies to overcome these challenges. The strategies are already in progress with the goal to provide for a better overall understanding of risk methods and the benefits it can provide.
The original Safety Evaluation for Vogtle license amendment requests 175 and 157 was drafted by the APLA and DRA staff and then provided to the responsible technical branch (EEOB) for concurrence. This process is different than discussed in the current NRR licensing procedure where the expectation is that the technical and PRA branches will work together to develop the Safety Evaluation and then it would go through the concurrence process. It is important that the deterministic review is accomplished by the respective technical branches concurrently with the risk branches in order to ensure a complete risk-informed result is accomplished. Now that the 4b-like process has been approved for Vogtle, the inspection program needs to be updated.
Currently the only IP available is Inspection Procedure (TI 2515/170) and this was applicable only to STP and expired on 11/31/2009. Additionally, inspectors will need to be trained on these procedures and technical branch license reviewers will need programmatic familiarization.
We note that the DPO submitters, as well as other Staff members raised significant concerns regarding this initiative. The Agency has considered those concerns by suspending its approval of the TSTF. The DPO submitters also raised several more generic concerns regarding the way the Agency is approaching the risk initiatives. This report will address the generic concerns in the context of Concern 2, regarding risk initiative 5b.
Finding: Agree in part, and disagree in part. The original SE for the Vogtle LAR to implement RITSTF 4b did not document a balanced qualitative and qualitative assessment. By not initiating the technical branch review until the concurrence process, a full understanding of the qualitative assessment was not presented. This LAR was not implemented by the site until significant changes were made and the responsible technical branch had completed their review.
Recommendation:
(1) Ensure the technical branches are involved in developing the Safety Evaluations (SE) for LARs in their area of technical expertise at the beginning of the process.
(2) Create an Inspection Procedure (IP) and training for conducting inspections of 4b implementation.
Observation: Considering the complexity and significance of this program, OGC review of the first SER for the first pilot process would have been appropriate. Potential issues could have been resolved/identified earlier if the technical branch and PRA branches communicated better and OGC had reviewed the SER.
View of Panel Member Koshy DC Bus Voltage The DPO states, in summary, that outage time extensions for DC power systems has vulnerabilities that are currently not evaluated such as the potential for locking up the actuation logic for emergency core cooling, which is an undesirable failure mode that could lead to the plant entering an unanalyzed condition. The current Technical Specification restriction on a very narrow DC bus outage time is delicately engineered to protect against undesirable safety challenges.
The DPO expands on the uniqueness of the control system design and how the power supply degradation resulting from an extended outage can impact safety systems. The DPO asserts that technical specification limits on a narrow DC bus outage time was delicately balancing the early designs within its limited capabilities for preserving nuclear safety.
The licensing review on 4b appears to dwell on the philosophy that the outage time currently allowed in the technical specification can be extended if other risk contributors can be managed and it further assumes that the current completion time was derived from reasonable time to fix potential problems and increase safety system availability. Therefore, the limiting condition during a Technical Specification allowed outage time is only in the incapability to withstand another single failure. While this line of reasoning may be applicable for some RICT, it is incorrect to apply this reasoning globally to all completion times, especially in control systems that are operated directly or indirectly (vital AC) from DC power. The PRA modeling does not go into the fine details of sensor signals and I&C logic processing nor connect with its dependencies for generating RPS and ECCS actuations. The absence of modeling into such level of detailed logic systems leads wrong conclusions (with modeling at higher level) that increase in DC bus related outage time will not have any negative impact on plant safety.
The DC power supply outage time limitation to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> was based on the duration the battery can sustain adequate voltage while supplying the operational loads in the absence of a charger and still retaining sufficient capacity to safely bring the plant to an orderly shutdown. In order to increase this limit to more hours (23 days or 7 days with 30 days considered as back stop), the impact of reduced voltage on the DC power and consequently vital AC power degradation was not specifically addressed. Because of the control system vulnerabilities, RG 1.93 makes the statement The licensee should closely monitor the required functions of the DC system during the shutdown process and take necessary actions (such as cross-connecting a supply or shedding optional loads) to ensure safe shutdown to be sensitive to the potential complications from degraded DC voltage. The LAR review for 4b, with primary focus on PRA, has not addressed the power supply outage limitations in RG 1.93 or how such vulnerabilities are compensated in the extension of outage time.
A plant specific design bases evaluation is required to consider only single failure as in loss of voltage and not a degrading voltage condition for DC power and logic control systems.
Therefore, if the outage time is extended, the evaluation should include factors such as impact of reduced voltage and its consequences such as assessing the failure mode from a degrading voltage, the acceptability of the variety of failure modes in the RPS and ECCS logic functions, and its independent and collective impact on plant safety. The nuclear system supplier and Architect Engineers (A/E) have not consistently designed 2/4 logic systems with desirable failure modes for voltage degradation. In certain cases, the safety related logic systems were designed with 2/3 channels for actuation. The power supply for actuation logic is drawn from 2 divisions for 4 instrument channels. Loss/degradation of one division of control power, needs to be addressed for relaxing the outage time to avoid potential entry into an unanalyzed condition. A logic designed from 2/3 may be blocked by a degradation in the source that feed 2 channels or it could lead to a spurious actuation and such I&C relay logic is not modeled into PRA. As discussed in the information notices below, such inappropriate actuations were experienced in the opening of power-operated relief valve and containment sump recirculation actuation. The designers found it difficult to fix the failure modes and therefore settled to increase reliability of power and avoid such undesirable results.
The DPO points to an event (Forsmark-BWR in Sweden) where logic system failures led to unsafe conditions and caused a LOCA by opening dump valves in a BWR event while the degraded injection system attempted to keep the core covered. This condition originated from a common cause, an electrical fault and consequential voltage spike that originated from 400Kv switchyard. The undesirable failure mode of UPS failure from voltage transient, to more than one channel exacerbated the plant transient making it difficult to keep the core covered. Below are further examples I found of such exacerbating failure modes of control system failures from control power supply issues in US plants.
(1) Info. Notice 1997-81: Deficiencies in Failure Modes and Effects Analyses for Instrumentation and Control Systems On May 15, 1997, while Waterford Unit 3 was at 100-percent power, the licensee discovered that in the postulated conditions of a LOCA with one RWST-level monitoring channel placed in a tripped state [as allowed by the Technical Specifications], if a single failure, such as a failure of another RWST-level channel occurs, a potential for premature initiation of the recirculation mode exists [when containment sump is empty]. In another situation, with one channel of steam generator (SG) differential pressure (DP) instrumentation associated with the emergency feed water actuation signal placed in a tripped state, an event such as a main steam line break or a feed water line break concurrent with a single failure such as loss of another SG DP instrument channel, results in a potential for not isolating the faulted SG from the emergency feed water supply line (LER 97-16, Accession No: 9706180379).
On October 30, 1996, while ANO-2 was at 100-percent power, the licensee discovered that while one plant protective system (PPS) channel is in bypass, a scenario consisting of a LOOP concurrent with a single failure, such as a loss of the train A dc bus, would result in a failure of certain engineered safeguard function (ESF) systems to actuate automatically. ESF systems that would be affected are the containment isolation system (CIS), containment spray system (CSS), and emergency feedwater system (EFWS). The consequence of a dc bus failure alone could lead to the same failures with loss of off-site power and loss of on-site power in the affected train (LER 96-04-01, Accession No:
9702120360).
(2) Info Notice 1993-11: Single Failure Vulnerability of Engineered Safety Features Actuation Systems If power is lost to either one of the two dc vital buses, both the safety injection actuation signal and sump recirculation actuation signal would be simultaneously initiated. The recirculation actuation signal would result in tripping all low pressure injection pumps.
Also, the spurious sump recirculation actuation signal would cause one of the containment sump outlet valves to open. [Pumps coming on with no water available for suction.] It is to be further noted that the CE plants of this vintage had to disable two of the 2/4 logic system because the design could not be modified to desirable failure mode against all the scenarios to be addressed.
The loss of all dc power to one actuation train would cause a power -operated relief valve in the other train to open. In addition, when control power alone is lost to only the sensor cabinets in a single actuation train, spurious high pressurizer pressure signals would cause the relief valves in both trains to open. Both cases would result in a loss of primary coolant.
(3) LER 2010-003-001 from Clinton Power Station It was reported that during full power operation, several containment isolation valves closed and several components were tripped. The actuations were the result of Division-2 load driver card that spuriously actuated its loads without a valid Loss of Coolant Accident signal or a manual initiation signal and it was reported to NRC. The root cause was not identified until a spurious actuation happened in Division -1. The cause of the actuation was a slight voltage degradation to the Self Diagnostic System card. The same system was utilized in the reactor protection and emergency core cooling systems.
This event further illustrates the greater sensitivity of electronic digital equipment to slight voltage degradations. In this specific case it was serendipitous that the failure did not lead to an unsafe conditions because the design does not account for this failure mode.
Depending on the application, it could fail to actuate, not actuate, or lock up and the load relay could lead the plant to an unanalyzed condition and challenge plant safety.
I reviewed the RAIs and consulted with the NRR electrical branch and the lack of plant specific review of logic system functions continue to remain unaddressed in the review of LAR for 4b.
Problems of this nature could remain unnoticed because the DC bus and technical specification review responsibility comes under electrical branch but impact of the bus voltage degradation/interruption affects the control systems under I&C review.
The DC bus outage time extension mentioned in the DPO was originally presented to NRC for approval by the Westinghouse Owners Group (WCAP-15622-NP) ADAMS #ML011770404 on June 15, 2001. It was withdrawn because the owners group could not provide answers to the safety concerns on the logic system failure modes presented and those issues remain unaddressed while the RICT was granted extension.
Finding: Agree. Initiative 4b was not implemented with adequate technical evaluation from the cognizant technical branches to ensure that potential safety issues were addressed in that the known design weaknesses were not exacerbated in the I&C area of RPS & ECCS.
Specifically, depending on the design, a vulnerability can be introduced with extending DC bus outage time (see DC Bus Voltage starting on page 8).
Recommendations:
(1) Approve increased outage time only for plants that can confirm that a reduction in DC voltage will be limited to one instrument channel and the additional time permitted to only one channel at a time OR the failure mode of the logic system will be fail-safe for RPS and ECCS for any degradation of voltage (i.e., the inappropriate logic actuation will not result in opening of PORVs, ADS, sump recirculation actuation etc., similar to the plant event described in IN 1993-11.
(2) Conduct an in-depth review of the existing regulatory guidance and revise the regulatory guidance when the RICT is in conflict.
Observation:
(1) A technically viable solution to the issue identified above would be the installation of a dedicated battery and charger for each protection system channel. (Currently most pants are building four channels from essentially two trains of safety related batteries) Such an approach would allow extending the outage time for DC power systems without causing undesirable outcomes (2) Not all items in electrical logic control systems and its dependencies can be modeled in a practical sense, therefore input from the cognizant technical branches are extremely important for safety evaluation (3) Problems of this nature could remain unnoticed because the DC bus and technical specification review responsibility comes under electrical branch but impact of the bus voltage degradation/interruption affects the control systems under I&C review.
View of Panel Member Daley Due to time constraints, my review of this concern was fairly limited. However, in the short review that was performed, enough problems were noted to warrant a recommendation to perform a comprehensive review of the program. Additionally, the documents reviewed were older versions that were already in place when the DPO was submitted. More recent versions of these documents may have corrected some of the issues found during this review.
Adherence to 10 CFR 50.36 The only rationale in the SE for NEI 06-09 states, The LCOs themselves would remain unchanged, as would the required remedial actions or shut down requirements in accordance with 10 CFR 50.36(c).
The assumption of this statement appears to be that the Completion Time is not a part of the technical specifications under 50.36.
Using the same logic expressed above, removal of the Completion Time would be acceptable from a legal basis since they are not part of the Technical Specification per 50.36 because the word Completion Time does not specifically appear in 50.36. I do not ascribe to this logic, because an LCO with a remedial action and no Completion Time would make no sense.
In fact, the Technical Specifications define ACTIONS (in the Definitions section of the Technical Specifications) as the following:
ACTIONS shall be that part of a Specification that prescribes Required Actions to be taken under designated Conditions within specified Completion Times.
It is very clear that ACTIONS contain all three elements - Conditions, Required Actions, and Completion Times - and each technical specification is structured with this in mind. Stating that remedial actions are unchanged is contradictory to the decades long precedence that the Technical Specifications have established for what constitutes those actions.
The NEI 06-09 Safety Evaluation justification for meeting 50.36 does not provide appropriate justification for approval of the change. It just muddies the water in relation to the different terms that have been long established regarding the Technical Specifications. This is not to say that there is no legal justification for the 4b initiative, but rather that the one that is given in the Safety Evaluation is sketchy at best.
Defense-in-Depth The evaluation of defense-in depth in the SE seems to rely on two primary aspects of the program: 1. the quantitative risk analysis; and 2. the use of compensatory measures. The SE also restates the defense-in-depth guidance from RG 1.174 and RG 1.177.
The SE states the following:
The use of extended CTs is restricted to conditions which do not involve a total loss of function, which assures preservation of redundancy and diversity. Both the quantitative analysis and the qualitative considerations assure a reasonable balance of defense in depth is maintained...
It is not clear how ensuring that there is not a loss of function assures redundancy and diversity.
It only assures that the function will not be completely lost. Having only one system or component available to perform a function assures that there is not a loss of function; however, redundancy does not exist. Additionally, the second sentence, discusses qualitative considerations. NEI 06-09 discusses that qualitative assessments can be used to supplement the quantitative assessment. However, there is no guidance or criteria for what that qualitative assessment would entail. This does not seem to be the type of assessment that could be used to support a defense in depth review in an SE, because there is no way to know what the assessment is.
As stated previously, this leaves only the quantitative risk analysis and the use of compensatory measures as a justification for retaining acceptable defense in depth. By the nature of Risk-Managed Technical Specifications (RMTS), defense in depth is reduced. The defense in depth evaluation should concentrate on whether that reduction is acceptable and the defense in depth philosophy is maintained. The SE for NEI 06-09 never even acknowledges that a reduction in defense in depth exists. The Vogtle Amendment did recognize this reduction.
The quantitative analysis is strictly risk-based and while it serves as useful insight, it does not substitute for traditional methods. As stated in RG 1.177:
If a comprehensive risk analysis is done, it can provide insights into whether the extent of defense-in-depth (e.g., balance among core damage prevention, containment failure, and consequence mitigation) is appropriate to ensure protection of public health and safety. However, to address the unknown and unforeseen failure mechanisms or phenomena, traditional defense-in-depth considerations should be used or maintained. The evaluation should consider the intent of the general design criteria, national standards, and engineering principles such as the single failure criteria...
The SE discussion regarding compensatory measures does not address this either. The compensatory measures are primarily to reduce the overall plant risk and therefore are again primarily risk-based. In fact, NEI 06-09 refers to these measures as compensatory risk management actions.
In conclusion, there appears to be no traditional defense in depth review documented. Reliance is entirely on risk principles. This does not appear to be the intent of RG 1.174, RG 1.177, and the Commissions 1995 Final Policy Statement on the use of risk.
Safety Margin The evaluation states the following:
The design, operation, testing methods, and acceptance criteria for SSCs, specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plant licensing basis (including the final safety analysis report and bases to TSs), since these are not affected by risk-informed changes to the CTs. Similarly, there is no impact to safety analysis acceptance criteria as described in the plant licensing basis.
Thus, safety margins are maintained by the proposed methodology, and the third key safety principle of RG 1.177 is satisfied.
It is completely unclear how this conclusion was reached, because the rationale and bases for such a conclusion was not documented. Just saying that safety margin is maintained does not make it so. The technical and regulatory bases for such a broad, sweeping statement certainly does not exist in the SE itself.
As stated in the DPO, RG 1.93 is an integral part of the SAR at most plants, so the conclusion above would have to be false, unless the authors were thinking that such a change to the CTs would not be allowable unless a license basis change were made in addition to the calculations in the RMTS. This is extremely doubtful, though, considering the issues and backdrop of the 5b initiative as well.
Additionally, the NEI 06-09 Topical Report was approved with very little guidance concerning the review of future plant specific amendments. The Safety Margin evaluation leads the reader to believe that this evaluation could be cut and pasted into any licensees amendment request.
Every plant has a unique license basis. The rationale that formulated certain license basis documents was based upon the specific plant design, and the docketed correspondence between the NRC and the licensee during both the pre-operational and operational stage. This is especially true of the SAR. Any plant specific review of a license amendment associated with the RMTS would need to contain a technical and regulatory review of this license basis, because this clearly was not accomplished (certainly not documented) during the review of the NEI 06-09 Topical Report.
External Events Review During the review of the NEI 06-09 Topical Report for this DPO, a separate concern was identified.
External events risk can be addressed by the following:
Provide a reasonable technical argument (to be documented prior to implementation of the RMTS program) that the external events are not modeled in the PRA are not significant contributors to configuration risk.
The obvious question that this evokes is what constitutes a reasonable technical argument.
This unclear nature of this statement will lead to inconsistent implementation throughout the industry. A reasonable technical argument could be exceedingly different from one plant to the next, not to mention from one individual evaluator to the next.
This type of statement provides an exit out option, and the lack of guidance and criteria associated with a reasonable technical argument lends to an implementation that is wildly different across the industry and could lead to changes that are far outside the scope of what we may be aiming for.
PRA Functional Finally, nothing in NEI 06-09 demonstrates the lack of clarity in this document better than the term PRA Functional which is introduced as a method to still credit an inoperable component.
NEI 06-09 states, For emergent conditions, a RICT may be applied when all trains of equipment required by the Technical Specifications LCO would be inoperable, provided one or more trains are considered PRA functional...
Further on in the document, it states the criteria necessary for declaring an inoperable SSC as PRA Functional. Essentially, the three criteria are as follows:
1.
If a component is declared inoperable due to degraded performance parameters, but the affected parameter does not and will not impact the success criteria of the PRA model.
2.
If the functional impact of the condition causing the inoperability is capable of being assessed by the PRA model, then the remaining unaffected functions of the component may be considered PRA functional in the RICT calculation.
3.
If the function(s) affected by the condition causing a component to be inoperable is not modeled in the PRA, and the function has been evaluated and documented in the RMTS program as having no risk impact, then the RICT may be calculated assuming availability of the inoperable component and its associated system, subsystem, or train.
The first criteria hinges PRA functionality on the impact to the success criteria. I have not found where this success criteria is defined. The best bet is that it depends upon the plant and how it defines success.
The second criteria is really not a criteria at all. It is really just a method for applying PRA functions.
The third criteria essentially negates the first two criteria for components not modeled in the PRA, and then it allows the components to be treated as available if they have no risk impact. The standard and criteria for no risk impact is not defined.
In conclusion, based upon a (very) quick review of NEI 06-09, it is my professional opinion that this document needs a thorough scrub. There is too much affected by a broad, sweeping change such as this to allow a document that appears to be very unclear in its instructions and other content to be applied to something as important as the Technical Specifications without a thorough review being conducted by personnel who understand the entirety of the program and its effects.
Finding: The DPO submitters concern that NEI 06-09 and the agencys approval of that Topical Report was risk-based as opposed to risk informed appears to be substantiated.
Additionally, there are weaknesses within the RMTS program itself that need to be addressed.
Recommendation:
Perform a comprehensive review (a scrub) of all the documents associated with the 4b initiative to ensure that we have identified all pitfalls associated with the program. Do not perform this review in the branches which tend to be specialized, but rather have individuals perform the review who have a broad range and strength of knowledge, and especially a very strong understanding of technical specifications and license basis.
Additional View of Panel Member Kirkwood I largely agree with the position on this concern given by Panel Chair Caldwell, and have joined in it. However, I am fundamentally uncomfortable as a DPO panel member expressing a view on Concern 1. A DPO is supposed to be a disagreement with an established staff view or established agency practice. See MD 10.159 at 2. Issues that are still under Staff review are not to be considered in the DPO process because they are concerned premature or predecisional.
MD 10.159 Handbook at 5. In the instant case, the DPO was submitted on Oct. 12, 2016.
Concern 1 involves concerns about Risk Initiative 4B. Specifically, it is concerned about the safety evaluation for TSTF-505 implementing risk initiative 4 as well as the safety evaluation written implementing risk initiative 4B at the Vogtle site. Shortly after the DPO was submitted, on Nov 15, 2016, the NRC suspended its approval of TSTF-505 based on a wide variety of concerns, including some raised by the submitters. See ML. 16281A021. Suspension of TSTF approval. The revised SE for TSTF -505 is currently in the concurrence process. It appears that some of the concerns of the submitters might be resolved in this version, for example OGC is on concurrence. Some of their concerns are more fundamental to our use of risk. That being said, I am hesitant, as a panel member, to weigh in on a matter that is still in the process of being resolved internally.
With respect to the Vogtle SE, adopting initiative 4B, it does not appear to me that it was even final when the DPO was submitted. The amendment was issued on August 8, 2017. At least one of the submitters of the DPO, concurred on the Vogtle amendment suggesting that at least that individuals concerns were satisfied. See ML15316A419.
It does not appear to be the appropriate role of a DPO panel to attempt to determine which of the DPO submitters may continue to have concerns. When the panel raised this concern to OE, we were told to write our report against the documents as they stood at the time the DPO was submitted (e.g. the suspended TSTF SE, and the draft Vogtle SE as it was in the fall of 2016).
While this approach has the advantage of being responsive to the DPO in one sense, I do not see how it is helpful to the agency as a whole. Essentially, as I view it, concerns were raised, and NRR did the right thing and suspended their approval of the TSTF. Both the ultimately approved Vogtle SE, and the TSTF SE currently going through concurrence look substantially different than what the DPO submitters had before them in the fall of 2016. I am concerned that only considering the past simply dredges up old disputes, which have already been resolved. I do recognize that many of the concerns raised in the DPO relate to both 4B and 5B. For those concerns, I would have preferred that the Panel address those solely in the context of 5B.
However, I did not get my colleagues to agree to this approach.
Furthermore, I am concerned that we as a DPO panel have expanded the scope of the DPO beyond the concerns raised by the submitters, and without following the procedure set forth in MD. 10.159. A DPO panel is supposed to confine its review to the issues determined to be within the scope of the DPO and the agreed statement of concerns with the submitters. See MD 10.159 at 14. If the DPO panel identifies issues beyond the scope of the DPO, those issues and associated recommendations are supposed to be identified in a separate memorandum. See MD 10.159 at 16. In my view, in several places this report goes beyond the scope of the DPO, and in some cases enters into disputes occurring elsewhere in the agency.
Specifically, in the concern 1 discussion, my colleague calls out an issue whether or not risk initiative 4B adheres to 50.36, and appears to be asserting that the SE for 4B needs to make a better legal case for why the completion times need to be included in the technical specification for limiting conditions for operation. Typically, the agency does not put legal analysis into safety evaluations. In cases where additional legal analysis is needed, that analysis would typically be provided to the relevant staff management in a privileged attorney-client memorandum. Not written into a public safety evaluation. That being said, since I do not see where this issue is raised in the DPO, I consider it out of scope, and thus I will not respond to it further in this context.
Concern 2: RITSTF Initiative 5b. Safety Evaluations associated with RITSTF Initiative 5b are being prepared with a primary focus on probabilistic risk (risk-based principles established by TSTF and Topical Report rather than risk-informed principles that complement the deterministic principles). Consequently, the technical bases established in relevant NRC requirements including plant-specific design and licensing basis are not specifically addressed to justify approval of license amendments referencing RITSTF 5b, and therefore reasonable assurance of adequate protection of the public health and safety is not provided.
Discussions and Conclusions View of Panel Member Daley The extensive and complex nature of this DPO resulted in a similarly complex discussion for the evaluation of the issues and resulting conclusions. This shorter preliminary section provides a higher level discussion of some of those more important conclusions without delving into the very extensive research performed in support of those same results. The actual rationale behind these conclusions are discussed in much more detail further on in this evaluation. Because the DPO did not specifically take issue with the actual probabilistic risk methods of the 5b initiative, this portion of the 5b initiative will not be addressed. The primary concerns of the DPO involved the acceptability of the deterministic review and the regulatory acceptability of the initiative.
After discussions with the DPO submitters, one of the primary concerns was that the 5b initiative was risk-based as opposed to risk-informed. This point appears to have some validity. The deterministic elements of a risk-informed review/decision as outlined in Regulatory Guides 1.174 Rev 2 and 1.177, Rev 1 did not seem to be adequately addressed during the review of the licensee submittals for initiative 5b. In fact, it can readily be argued that the deterministic review elements were delegated to the licensee during the review and approval of the 5b initiative.
While this was not explicitly stated in any of the associated SERs, and the NRR staff that were interviewed did not believe that the responsibility was delegated to licensees, it is very difficult to conclude that it is elsewise after careful examination of the documents associated with 5b. This ultimately leaves the review of actual changes to the licensee and any regulatory review to the regional inspection staff. However, RG 1.174 and 1.177 were written with the express purpose of having this review performed by the staff at headquarters when issuing license amendments.
Yet again delegating the review of another highly complex technical and regulatory program to an ever shrinking regional inspection staff challenges the boundaries of our abilities to be able to effectively regulate.
The NRC 1995 policy statement on the use of PRA methods expected that PRA be used to complement the NRCs deterministic approach to reviews and to support a defense-in-depth philosophy. The DPO submitters argued that the deterministic review was not adequately performed resulting in a risk-based approach that did not follow, in principle, the Commissions 1995 policy statement. This evaluation of the DPO reached a similar conclusion.
Additionally, these same deterministic criteria which are now being used by the licensee to perform qualitative assessments of the acceptability of their surveillance frequency changes are noticeably lacking in specificity. This provides licensees with great latitude in the interpretation of those criteria, and conversely, leaves the agency with little guidance or basis for regulation of the Surveillance Frequency Control Program (SFCP) moving forward. It should be noted that this same qualitative assessment allows the licensee to bypass risk criteria that is used to ensure the impact of changes to Core Damage Frequency (CDF) and Large Early Release Frequency (LERF) as well as cumulative impact to CDF and LERF; criteria for ensuring adherence to the Commissions Safety Goal Policy.
The result is a far reaching program (the SFCP) with a lack of clarity for adequate implementation and an unclear regulatory structure. This is compounded by the lack of familiarity and understanding of the same program by the regional inspection staff. For a program that has such a high potential impact to the plant, there are few inspectors who have a firm comprehension of the 5b initiative and program. Additionally, there is only sparse guidance, and no present inspection requirement, for inspecting this area. It is highly recommended that more specific deterministic criteria is established for the deterministic reviews performed by the licensees in this area. Additionally, comprehensive inspector training and guidance in this area appears to be warranted to ensure adequate oversight of this important area in the future.
Of special note is the belief by many that were initially interviewed that plant license basis will still be maintained regardless of changes made through the SFCP, because of the requirements of 10 CFR 50.59. This is not the belief of the majority of the industry which maintains that a change to surveillance frequencies is allowed because the program was approved via license amendment. If the change affects the license basis in the UFSAR, the UFSAR can be changed via a screening which cites acceptance based upon an evaluation under the SFCP. In the industrys view, 10 CFR 50.59 does not apply to any changes made under the SFCP. Add this further reduction in programmatic checks and balances to the already defacto delegation of deterministic review elements (defense-in-depth, safety margin, etc.) to the licensees, and the cause for concern over consistent implementation of the program and repeatable outcomes is heightened. While licensees and a number of NRC staff agree that 10 CFR 50.59 does not apply, there are also a number of NRC staff members who believe that the legality of such a position is questionable. Additionally, the effects of such an interpretation has broad implications for the future effectiveness of the 50.59 rule. The rationale for this position will be explored more in the body of this section.
The submitters also argued that the relocations of surveillance frequencies through the implementation of 5b violates 10 CFR 50.36(c)(3). While there is no concrete evidence that the initiative does not meet 10 CFR 50.36, neither is there evidence that it does meet 10 CFR 50.36.
The justification for regulatory acceptability provided in both the NEI topical report and subsequent SERs does not provide a strong basis for adherence to 10 CFR 50.36, and it can be argued that there is a level of past precedence and acceptance that the surveillance frequencies are a part of the surveillance requirement and therefore required by 10 CFR 50.36. Because there is not enough information to determine compliance with 10 CFR 50.36(c)(3), this evaluation could not reach a definite conclusion on this assertion by the submitters. However, based upon the lack of documented support for the assertion that a surveillance frequency is not a legal part of a surveillance requirement, a formalized position and/or interpretation would be recommended.
Finally, since many of these amendments have already been approved, it is most important, moving forward, that licensees and the NRC have appropriate guidance and criteria established such that frequency changes can be made in a consistent, reasonable, and regulatory sound manner such that both the industry can make changes and the agency can provide oversight in an effective way such that safety is ensured. From a careful review of the 5b initiative, this does not appear to be the case today.
View of Panel Member Kirkwood As will be further discussed below, I view much of the disagreement as centered on the appropriate role of risk in our regulatory framework. The DPO submitters appear to view the defense in depth and margin of safety reviews as being a deterministic review. They would have the staff separate the deterministic review and the probabilistic review.
It appears that NRR management has made a choice to conduct integrated reviews, utilizing both deterministic principles and PRA principles, depending on the issue at hand. This choice is reflected both in Rev3 of RG 1.174, and in the approval of the NEI 04-10. This is a legitimate, defensible choice. Moreover I disagree with the implicit suggestion that the staff did not realize how far reaching the SFCP program would be when they approved it. I have carefully reviewed the regulatory history of the approval of the amendment, including the RAIs written both on NEI 04-10 specifically, and the Limerick pilot amendment. Those RAIs, and the answers to them, reflect that the staff understood at the time they prepared their licensing documents, that licensees adopting the SFCP would be allowed to alter their surveillance frequencies in ways that would differ from the deterministic surveillance frequencies.
The SFCP program, as written, appears to be a safe conservative way of determining the appropriate surveillance frequency for individual SSCs.
View of Panel Member Caldwell The RITSI 5b, as implemented through NEI-04-10, Revision 1, dated April 2007 was intended to provide the technical methodology to support a risk-informed and licensee controlled surveillance frequency program for specific surveillance requirements approved by the NRC. NEI-04-10 invokes, as guidance, NRC Regulatory Guide 1.174, Probabilistic Risk Assessment (PRA) methods for determining the impact of revised intervals. RG 1.174 provides an approach acceptable to the staff for developing risk-informed applications for a licensing basis change and it also provides general guidance. The specific RG purpose is to support regulations 10 CFR 50.90 and 10 CFR 50.92. Prior to implementing 5b, surveillance frequencies (SF) were considered an integral part of the technical specification and a change to a SF would go through the 10CFR50.90 process to obtain prior NRC approval. However, with the advent of the 5b program, it was recognized that the specific SF is not integral to the technical specification and therefore it was considered appropriate to establish this program so that licensees control the SF based on better site-specific and near real time plant risk. The 5b program has been implemented, but the program implementation and basis have not been effectively communicated to many inspectors and technical reviewers so that they are familiar with this change in the agency practices. As indicated above, during the panel interviews, some individuals expressed very different understandings of this programs implementation requirements, some staff indicating they still expected to see 10CFR50.59 screening documentation as part of the 5b license change process and others indicating that no 10CFR50.59 screening would occur under the 5b program. Because of the fundamental change in how the agency is going forward with RITSTF 5b, a change management process would have been appropriate. However, as indicated in the RITSTF 4b write-up, the Commission has directed that the staff become more attuned to risk and PRA applicability which will resolve this concern.
As indicated above, In order to implement the 5b program, as envisioned, it is expected that the oversight process will be the NRCs single ongoing program verification line of defense. It is important that there is a clear regulatory basis so inspectors can be appropriately trained to verify the program. Two additional observations identified during this review were:
1.
NRC Inspection Procedure 71111, Attachment 22, Surveillance testing, dated July 1, 2015 states in Attachment 1 - Revision History for IP71111.22 that staff will be trained on this procedure after the IP is issued. The effective date of this IP was July 1, 2015 yet based on conversations with some regional inspection staff, they were unaware if this training has occurred.
2.
One outcome of 5b implementation is that the NRC will no longer require licensees to commit to updated codes and standards because the licensees are no longer making these changes under the 10CFR50.90 (LAR) process (voluntary changes). However, in the NEI-04-10 guidance, it says that if a licensee is departing from the surveillance frequency listed in a code or standard-they have to consider both the committed version and the new version of the code or standard. Therefore, one program change the staff sees is that for these type of changes, licensees are in more control of their licensing basis.
The second fundamental concern of the submitters was that the 5b program was substantially more risk-based than risk-informed as directed in Commission Policy. The basic agency guidance for 4b and 5b risk initiatives are fundamentally the same (RG 1.174 & RG 1.177) and as indicated in concern 1, these documents at the time of the DPO submittal, did not adequately support predictable and transparent risk-informed reviews. Since that time, substantial progress has been made in better elaborating on how to conduct a qualitative and deterministic review.
More improvements should be made to better support the balancing between the insights of PRA and the deterministic/qualitative components of the review. These additional improvements will help provide consistent and transparent review results throughout the industry. This aspect of the concern is discussed in Concern 1.
Finding: Agree in part, and disagree in part. The guidance used to implement RITSTF 5b does not document a balanced qualitative and qualitative assessment. The qualitative guidance will not help ensure a consistent process is followed by licensees or readily understood by staff.
Recommendation: Continue the actions directed by the Commission to improve staff guidance and understanding of how PRA and qualitative assessments are integrated to provide a risk-informed regulatory structure.
Concern 2.
Specific Issue 1: Relocation of Surveillance Frequency Requirements out of the Technical Specifications and into a licensee controlled document violates 10 CFR 50.36(c)(3).
Discussions and Conclusions View of Panel Member Daley 10 CFR 50.36(c)(3) states in part that:
Technical Specifications will include... surveillance requirements. Surveillance requirements are requirements related to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met.
The rationale in NEI 04-10 for the proposed change meeting current regulations is the following:
NEI 04-10, Revision 1, supports relocating the surveillance frequencies from the TSs to a licensee-controlled program by providing a NRC-approved methodology for control of the surveillance frequencies, The SRs themselves would remain in the TSs, as required by 10 CFR 50.36(c).
This change is consistent with other TS changes in which the surveillance frequencies are relocated to licensee-controlled documents, such as surveillances performed in accordance with the In-Service Testing Program or the Primary Containment Leakage Rate Testing Program. Thus, this proposed change meets the first key safety principle of RG 1.177 Rev 1 by complying with current regulations.
The SE for NEI 04-10 repeats the same exact statements word for word, with no additional evaluation expanding on the basis for the rationale within NEI 04-10.
The salient point in the relocation of the SR frequencies, as opposed to the actual verbiage of the SR itself, seems to split hairs. From a review of the many Federal Register notices associated with 10 CFR 50.36, with one exception, there does not appear to be much specific discussion of the frequencies. However, there is also no discussion of the surveillance requirement being a separate entity of the surveillance frequency as well. It deserves mentioning that a surveillance requirement without a surveillance frequency has no meaning or value. If no frequency was required, the assurance that an SR provides that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met is non-existent, because there would be no time that the requirement would have to be performed.
The one exception in the Federal Register where the frequency is mentioned - July 22, 1993 - is the Commissions Final Policy Statement on Technical Specifications in the Policy Statement, in which the Commission expected that appropriate Surveillance Requirements and Actions should be retained for each LCO which remains or is included in the Technical Specifications. It further states the following:
Each LCO, Action and Surveillance Requirement should have supporting Bases.
The Bases should as a minimum answer the following questions and cite references to appropriate licensing documentation (e.g. FSAR, Topical Report) to support the Bases... What are the Bases for each Surveillance Requirement and Surveillance Frequency; i.e., what specific functional requirement is the surveillance designed to verify? Why is this surveillance necessary at the specified frequency to assure that the system or component function is maintained, that facility operation will be within the Safety Limits, and that the LCO will be met?
The statement, What are the Bases for each Surveillance Requirement and Surveillance Frequency, could lead some to hypothesize that the separation of the requirement and frequency in this sentence seems to imply that the two are separate. However, when placed in context with the rest of the paragraph, the first statement talks about three entities: LCO, Action and Surveillance Requirement, and the need for Bases. Considering this, it can just as easily be interpreted that the Surveillance Requirement combined with the Frequency make up the functional requirement (or Surveillance Requirement) and thus the remainder of the sentence, what specific functional requirement is the surveillance designed to verify. In any case, the statement is far from conclusive, and it certainly does not specifically call out the Frequency as a separate entity from the functional Surveillance Requirement.
In conclusion, its not clear that anything legally can be extracted from this; however, it is worthy to note that there was clearly a certain amount of emphasis on the frequency having a direct effect on systems, components, and Safety Limits, and ultimately LCOs. Additionally, it seems that such an inconclusive statement should not be the regulatory basis for a major change and philosophical shift in the technical specifications such as the SFCP.
Furthermore, the technical specifications themselves (the Standard Technical Specifications) list the surveillance frequency under the section entitled Surveillance Requirement. Each Surveillance Requirement consists of a Surveillance and a Frequency. Its not clear how the frequency could be separate from the surveillance requirement when every technical specification LCO is structured such that the frequency, along with the surveillance, is a subset of the Surveillance Requirement. Either the Standard Technical Specifications have been incorrect for decades, and still are, or the interpretation that was made for the 5b initiative was incorrect.
It should be noted that the first documented occurrence (that I am aware of) of this position appears to be in NEI 04-10. This position/interpretation appears to be in contradiction to decades of precedence in the actual way that the technical specifications are constructed, with the Surveillance and the Frequency being sub-parts of the Surveillance Requirement section. It would seem reasonable that such a position should, and would, get some type of further evaluation other than a restatement in an SER of a position that is proposed in an NEI topical report. Additionally, while there have been numerous discussions in regard to the Commissions discretion in interpreting 50.36 to exclude surveillance frequencies (which is always a potential resolution), no documented evidence of such a discussion could be produced to show that the Commission agreed or disagreed with this interpretation.
Additionally, much emphasis was put on the prior relocation of surveillances to the In-Service Testing Program or the Primary Containment Leakage Rate Testing Program as a basis for this relocation of surveillance requirements. The only similarity between these relocations is that surveillance frequencies were relocated. Neither of the relocations of SR frequencies to the In-Service Testing Program and the Primary Containment Leakage Rate Testing Program were based upon the Surveillance Frequencies not being a part of the Surveillance Requirements.
The relocations were based upon regulations that were already in place that governed the SRs and frequencies: 10 CFR 50, Appendix J, Options A and B, and 10 CFR 50.55a. Both Programs, like the Surveillance Frequency Control Program (SFCP), are programs located in the Administrative section of the Technical Specifications, Section 5.
The Primary Containment Leakage Rate Testing Program lists both Options A and Options B.
Option A specifically states that nothing in these Technical Specifications shall be construed to modify the testing frequencies required by 10 CFR 50, Appendix J. In other words all the surveillance frequencies are still governed under regulation by both the Technical Specifications and 10 CFR 50, Appendix J, Option A. Option B states, A program shall establish the leakage rate testing of the containment as required by 10 CFR 50.54(o) and 10 CFR 50, Appendix J, Option B, as modified by approved exemptions. This program shall be in accordance with the guidelines contained in Regulatory Guide 1.163, "Performance-Based Containment Leak-Test Program," dated September, 1995.
RG 1.163 incorporates NEI 94-01 which establishes the SRs based upon performance based (not risk based) criteria. In essence, even for Option B, the surveillance frequencies, as designated by RG 1.163 and NEI 94-01, are still a part of the Technical Specifications, incorporated by reference.
Additionally, the technical specification changes were an integral part of the rulemaking for Appendix J, Option B. The rule states, in part, that a licensee... may adopt Option B, or parts thereof... by submitting its implementation plan and request for revision to technical specifications. Additionally in the Federal Register Statement of Consideration, Implementation section, it states, At any time thereafter, a licensee or applicant may notify the NRC of its desire to perform containment leakage-rate testing according to Option B. Accompanying this notification, a licensee must submit proposed technical specifications changes which would eliminate those technical specifications which implement the current rule and propose a new technical specification referencing the NRC regulatory guide.
The new rule itself was the regulatory basis for the change to the technical specifications.
As already stated, In-Service Testing Requirements are already included in 10 CFR 50.55a as part of the regulation. The In-Service Testing Program designates surveillance frequencies to be in accordance with the ASME OM Code.
Also, similar to the Primary Containment Leakage Rate Testing Program, the In-Service Testing Program applies to a very specific portion of testing. The SFCP, on the other hand, applies to a wide range of surveillance requirements.
The SFCP relocates all surveillance frequencies to a completely licensee controlled program that only has the requirement that changes to the frequencies... shall be made in accordance with NEI 04-10. The requirements are distinctly different and the controls in place are much looser for the SFCP. Again, the only real similarity between the SFCP and the other two programs is that the surveillance frequencies for all three are no longer located in the specific LCO. The actual regulatory justification for the Primary Containment Leakage Rate Testing Program and the In-Service Testing Program has no bearing in the regulatory justification for the SFCP.
The only justification left then, is that the surveillance frequencies are regulatory separate from the surveillance requirement. There appears to be no evidence that this argument was used for establishing the acceptability of the Primary Containment Leakage Rate Testing Program and the In-Service Testing Program. Additionally, outside of the statement made in NEI 04-10, there is no other evidence used to support the repeat of that same statement in the associated SER.
In conclusion, there is no basis in the SER for NEI 04-10 for the regulatory acceptability of the SFCP other than a statement in NEI 04-10 delineating the separation of the surveillance requirement from the frequency. It is unclear how the verification of this statement was established, or if the actual statement is indeed correct.
Finding: Indeterminate, since there is no actual verified basis for the regulatory acceptability of the changes contained within the SER for NEI 04-10 Recommendation:
1.
Either provide a comprehensive basis for the determination that surveillance frequencies are not a part of the surveillance requirement, or if it is determined that the surveillance frequency is a part of the surveillance requirement, then provide the legal basis for removing the frequencies from the requirements within the technical specifications.
2.
If the surveillance frequency is not part of the surveillance requirement, consider restructuring future generic technical specifications such that the Surveillance Requirement section of the technical specification no longer contains the frequency, or relabel the Surveillance within the Surveillance Requirement section as the Surveillance Requirement View of Panel Member Kirkwood The Commission is granted a great deal of discretion in how it interprets its own enabling statute, the Atomic Energy act, and its own regulations. 10 CFR 50.36(c)(3) defines surveillance requirements as requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within safety limits, and that the limiting conditions for operation will be met. This definition does not include surveillance frequencies. Surveillance frequencies specify the intervals at which the licensee must meet the surveillance requirements, but there is nothing that legally compels the inclusion of the surveillance frequencies in the technical specifications.
My colleague appears to hold the view that more evidence is needed to support removing the frequencies from the technical specifications. To the contrary, the regulation defines what must be included in the technical specifications. Thus, anything that is not specifically listed as something that must be included in the technical specifications may be excluded. The surveillance requirement itself must be included, the specific frequency upon which the surveillance occurs need not be included in the technical specification itself. When the plain language of the regulation allows for the change, no further support for making the change is needed.
Moreover, the statement by the DPO submitters that the original SE for the NEI-04-10 methodology was not reviewed by the Office of the General Counsel is factually incorrect. The ADAMS Accession number cited in the DPO (ML071200238) is the SE for NEI-06-09, allowed outage times. The original SE for NEI 04-10 is found at ML062700012 and the concurrence page for that SE reflects a concurrence from Marian Zobler in the Office of the General Counsel on Sept. 20, 2006. The adoption of the SFCP amendment using NEI 04-10 was also litigated when Southern California Edison applied for the amendment at San Onofre, which led to significant Office of the General Counsel involvement in the amendment. (Indeed, of the proposed contentions in that proceeding, which was not admitted, was that removing the surveillance frequencies from the technical specifications was illegal.)
I also respectfully disagree with my colleague that a surveillance requirement without a frequency has no meaning. In order to be considered operable, the plant has to be capable of meeting its surveillance tests. In other words, if an operator was aware that the diesel generators were inoperable, it would have to take the appropriate action, regardless of when the surveillance had last been tested.
Moreover, the fact that for many years surveillance frequencies were included in technical specifications does not suggest that they are required to be maintained in the technical specifications. As previously stated, the Commission has a great deal of discretion in determining what is needed to be in technical specifications. While it would certainly be legitimate for the Commission to insist that the frequencies be contained in the technical specifications, the Commission may also appropriately look at new ways of regulating. As the use of PRA has become more refined, it is legitimate for the Commission to determine that determining surveillance frequencies using plant specific PRA calculations is a sufficient method of ensuring safety, and this would not be possible without removing the frequencies from the technical specifications.
Concern 2.
Specific Issue 2 The EEEB staff noted that the original SE prepared by NRR/APLA staff (lead review group) for approval of TR NEI 04-10 methodology also did not provide adequate regulatory and technical bases to conclude that all deterministic criteria are met... The SE, in general, is written based on risk-based principles rather than risk-informed principles that complement the deterministic process.
View of Panel Member Daley and Koshy RG 1.174 Rev 2 and RG 1.177 Rev 1 were the agencys guidance for making risk-informed decisions for reviewing licensing basis and Technical Specification changes. It is important to again note that these documents were written to provide guidance on the use of risk information to support licensee requests to change the license basis and technical specifications. This point is made by both RGs. In fact, RG 1.174 Rev 2, which pertains to licensing basis changes, states that it does not address licensee-initiated changes to the license basis that do NOT require NRC review and approval such as 10 CFR 50.59 governed changes.
Additionally, RG 1.177 Rev 1 states the following:
The NRC staff has defined an acceptable approach to analyzing and evaluating proposed TS changes. This approach supports the NRCs desire to base its decisions on the results of traditional engineering evaluations, supported by insights (derived from the use of PRA methods) about the risk significance of the proposed changes. Decisions concerning proposed changes are expected to be reached in an integrated fashion, considering traditional engineering and risk information, and may be based on qualitative factors as well as quantitative analyses and information.
However, the qualitative assessment as defined in NEI 04-10 allows the quantitative analysis to be bypassed and thereby does not address the NRCs Safety Goal. Specifically, NEI 04-10 states the following:
This step is performed to determine if qualitative information is sufficient to provide confidence that the net impact of the STI change would be negligible (or zero) from a CDF and LERF perspective. It is recognized that in certain cases, such as a SMA, qualitative analysis is the only evaluation that can be performed.
For each risk contributor as determined in the initial assessments performed in Step 10 above, if the qualitative information is deemed sufficient, then proceed to Step 15 and provide the basis for the qualitative conclusions to the IDP. Since only qualitative considerations are provided in this case, the impacts of the STI change are not incorporated into the cumulative impacts described in Step 12.
NEI 04-10 describes these qualitative considerations in Step 7 of the SFCP. In this section, it provides a list of these considerations, including defense-in-depth and codes and standards (safety margin) attributes. What is noticeably missing is any specific criteria for acceptability to evaluate these considerations against.
Additionally, this allowance to perform a qualitative assessment and then skip to step 15 allows licensees to skip the quantitative steps that measure the impact that a change makes to CDF and LERF as well as adding that impact to the cumulative impact to CDF and LERF from all changes to surveillance frequencies made through the SFCP. In essence, this allows a licensee to bypass the very criteria that ensures that the Commissions Safety Goal Policy is adhered to.
The guidance does require that the licensee provide confidence that the net impact of the STI change would be negligible (or zero). However, there is no definition of negligible and no criteria for determining what negligible would look like from a qualitative perspective.
It could be argued that the guidance in Step 7 provides the necessary basis for performing a qualitative assessment, but, as stated before, the items in Step 7 are just considerations and do not establish clearly defined criteria for determining that a change is negligible (or zero).
Defense-in-Depth The two primary deterministic criteria considered in RG 1.174 Rev 2 and RG 1.177 Rev 1 are Defense-in-Depth and Safety Margin. While the verbiage in each RG is a little different, the elements and criteria for maintaining Defense-in-Depth are nearly identical.
As stated in RG 1.174 Rev 2, Defense-in-Depth is an extremely important philosophy. It states, The defense-in-depth philosophy has traditionally been applied in reactor design and operation to provide multiple means to accomplish safety functions and prevent the release of radioactive material. It has been and continues to be an effective way to account for uncertainties in equipment and human performance and, in particular, to account for the potential for unknown and unforeseen failure mechanisms or phenomena, which (because they are unknown or unforeseen) are not reflected in either the PRA or traditional engineering analyses. If a comprehensive risk analysis is done, it can provide insights into whether the extent of defense-in-depth (e.g., balance among core damage prevention, containment failure, and consequence mitigation) is appropriate to ensure protection of public health and safety. However, to address the unknown and unforeseen failure mechanisms or phenomena, traditional defense-in-depth considerations should be used or maintained.
In another section of the same RG, it states, Traditional engineering analysis provides insight into available margins and defense-in-depth. With few exceptions, these assessments are performed without any quantification of risk.
RG 1.174 Rev 2, similar to RG 1.177 Rev 1, then gives the elements to be considered, which are as follows, A reasonable balance is preserved among prevention of core damage, prevention of containment failure, and consequence mitigation.
Over-reliance on programmatic activities as compensatory measures associated with the change in the LB is avoided.
System redundancy, independence, and diversity are preserved commensurate with the expected frequency, consequences of challenges to the system, and uncertainties (e.g., no risk outliers).
Defenses against potential common-cause failures are preserved, and the potential for the introduction of new common-cause failure mechanisms is assessed.
Independence of barriers is not degraded.
Defenses against human errors are preserved.
The intent of the plants design criteria is maintained.
This is a fairly subjective list of criteria. When subjective criteria are used, it is even more important to ensure that the reviews made have the requisite focus on regulatory basis, technical adequacy, and safety significance.
NEI 04-10 restates the above elements and states that consistency with the defense-in-depth philosophy will be maintained if those elements are considered. It provides no specificity on how to meet those elements. For three of the elements it states the following:
Redundancy, diversity and independence of safety systems are considered as part of the risk categorization to ensure that these qualities are not adversely affected. Independence of barriers and defense against common cause failures are also considered in the categorization. The improved understanding of the relative importance of plant components to risk resulting from the development of this program should promote an improved overall understanding of how the SSCs contribute to a plants defense in depth.
This only addresses three of the elements (redundancy, diversity, independence), and it only addresses defense-in-depth from a risk perspective for those three elements. Therefore, it can be concluded that NEI 04-10 does not really address defense-in-depth from a truly qualitative or deterministic perspective. In fact, it only simply restates the same subjective criteria/elements that are provided in the RGs (which are specifically designed for NRC staff reviews) with no accompanying specificity on how those same criteria/elements will be maintained. In fact, if the evaluation is taken at face value, it can be inferred that at least three of those elements will only be evaluated using risk information.
The SE for TR NEI 04-10 reviewed the topical report for consistency with the Defense-is-Depth philosophy as well. The review consisted of quoting the same elements above and then providing a paragraph stating that compliance with RG 1.174 Rev 2 and RG 1.177 Rev 1 are met in that both the quantitative risk analysis and the qualitative considerations assure a reasonable balance of defense-in-depth is maintained to ensure protection of public health and safety, satisfying the second key safety principle of RG1.177 Rev 1. This evaluation, again, did not perform any type of qualitative, deterministic evaluation. Additionally, the TSTF itself simply restates the same thing as the RGs and NEI 04-10 in regard to deterministic/qualitative reviews of defense-in-depth and safety margin.
This pattern carries forward into the approval of plant specific LARs. For instance, the LaSalle LAR simply requests approval of their LAR based upon the approval of TSTF-425 and then just lists variations or deviations from TSTF-425, and attaches a documentation of probabilistic risk assessment technical adequacy. The SE for this plant specific LAR, again, simply references the same criteria/elements contained in the RGs and then talks about risk evaluations in the same manner as NEI 04-10. It essentially relies on the NEI 04-10 document and the associated SE for any sort of deterministic/qualitative review.
No true deterministic or qualitative evaluation exists in any of these documents. It appears that each document either points to the other to determine qualitative acceptability, or it was the purpose of the SEs to pass on responsibility of these reviews to the licensee when they perform changes to surveillance frequencies. If it is the first case, the review was just simply missed. If it was the second case, then review responsibility was passed on to the licensee with criteria/elements that are exceedingly subjective. Regardless, the deterministic review that is stressed in the RGs appears to have never been accomplished by the staff.
Additionally, with no clear guidance on how to evaluate these subjective defense-in-depth elements, licensees are left to interpret those criteria any way that they feel fit. This is in stark contrast to other change mechanisms that the agency has in place. An example of this are changes to the facility as described in the SAR under 10 CFR 50.59 which has a number of specific questions asked within the rule itself and endorsed, well established guidance in the form of NEI 96-07 for conducting these changes. From discussion with NRC staff and management, there appears to be a thought that any inappropriate changes to surveillance requirements will somehow be caught by regional inspectors. This is just not the case, since there presently is no required baseline inspection for this area (there are optional inspection elements for resident inspectors), and the inspection staff has not been trained on this very complex program.
Additionally, even if this was not the case, with no guidance for acceptability on subjective criteria/elements, its not clear how inspectors would be able to successfully regulate any issues.
Finding: Agree.
Recommendation:
1.
Establish guidance that pertains to licensee review of defense-in-depth and safety margin review. This should be established separately from the RG 1.174 and 1.177 criteria which applies to NRC review of amendments.
2.
Perform a complete review of the qualitative assessment being performed under the SFCP. This should include the following:
a.
Establishment of clear criteria for an acceptable evaluation of defense-in-depth.
- b. Review the unclear guidance involving Safety Margin contained within NEI 04-10 and establish what should constitute an acceptable Safety Margin for changes under the SFCP.
c.
Establish criteria for review of a plants Safety Margin.
d.
Provide clear criteria/definition of the term negligible (or zero) in regard to the net impact of a change in relation to the Commissions Safety Goal.
3.
Establish the regulatory applicability of 10 CFR 50.59 to the changes, and the effects of changes, made under the SFCP.
View of Panel Member Kirkwood It appears to be the view of the submitters, as well as my colleagues, that any risk informed amendment review needs to have a probabilistic review, and then a separate deterministic review Moreover, it appears to be the view that defense in depth and margin of safety belong to the deterministic review, and must be reviewed using only deterministic principles. If you start from this premise, then it is true that the NEI 04-10 SE did not do this. However, I do not think such a review is automatically necessary. Rather, the staff review must be appropriate to the circumstances. Indeed, the Commission explicitly rejected the idea that the probabilistic and deterministic reviews must be seen as two separate distinct reviews as early as 1995 in its Policy Statement on the use of PRA. (One commentator stated that the use of probabilistic analysis is simply an extension of deterministic analysis. They are not separate and distinctive concepts.
The Commission agrees with this concept.. The Commission believes that the PRA method plays a complementary role in relationship to the deterministic method.) 60Fed. REG. 42622, 42625 (Aug. 16, 1995). The recently published Rev 3 of RG 1.174 expands on the defense in depth philosophy and notes that it consists of 4 layers of defense; Robust plant design to survive hazards and minimize challenges that could result in an event occurring.
Prevention of a severe accident (core damage) if an event occurs, Containment of the source term if a severe accident occurs, and Protection of the public from any releases of radioactive material (e.g., through siting in low population areas and the ability to shelter or evacuate people, if necessary.
RG 1.174 sets forth 7 considerations to determine how a licensing basis change impacts defense in depth.
1.
Preserve a reasonable balance among the layers of defense.
2.
Preserve adequate capability of design measures without an overreliance on programmatic activities as compensatory measures.
3.
Preserve system redundancy, independence, and diversity, commensurate with the expected frequency and consequences of challenges to the system, including consideration of uncertainty.
4.
Preserve adequate defense against potential common cause failures.
5.
Maintain multiple fission product barriers.
6.
Preserve sufficient defense against human errors.
7.
Continue to meet the intent of the plants design criteria.
Each of these considerations, as it relates to the SE for NEI 04-10 will be discussed below.
It is not immediately apparent how a change to surveillance frequencies might impact the layers of defense. The DPO does not identify how changing the surveillance frequencies impacts the layers of defense. Similarly, my colleague does not identify how the layers of defense are impacted. While it is true that the SE does not speak to this point, if the SE was written utilizing the current RG 1.174 it appears that it could have just identified this consideration and stated that the SFCP amendment had no impact on the layers of defense. Thus, the failure to do so does not appear to be a consequential failure.
Similarly, it is not apparent how preserving an adequate capability of design measures without an overreliance on programmatic activities is impacted by the SFCP amendment. RG 1.174 states that a licensing basis change that does not impact how safety functions are performed or does not reduce the reliability or availability of the SSCs that perform those functions would meet this defense in depth consideration. It appears that the SFCP amendment would fall into that category.
The NEI 04-10 SE specifically states that the system redundancy, independence, and diversity are not impacted by the amendment. Such a statement is fully in keeping with RG 1.174. There does not appear to be any further analysis of this consideration needed.
The NEI 04-10 SE notes that the risk assessment in NEI 04-10 takes into account the potential for common cause failures. It further notes that the potential impact on detection of component degradation that could lead to increased common cause failures is included as a qualitative consideration in the NEI 04-10 methodology. RG 1.174 notes that PRA models common cause failures, so that risk provides some insight into this consideration, but that the potential for common cause failures should also be evaluated qualitatively. While the SE for NE 04-10 does not provide precisely what is listed in the most recent revision to RG 1.174, the spirit of the analysis called for in the RG appears to have been met.
Admittedly, the NEI 04-10 SE does not address the multiple fission product barriers consideration. RG 1.174 calls upon this consideration to be evaluated by ensuring that the change 1) does not cause an increase in the frequency of existing challenges to the integrity of the barriers; 2) does not significantly increase the failure probability of any barrier and 3) does not introduce new or additional failure dependencies among barriers that significantly increase the likelihood of a failure. It is not apparent how the SFCP amendment could challenge a fission barrier.
RG 1.174 calls for the defense against human errors consideration to be evaluated by determining whether the change would (1) create new human actions that are important to preserving the layers of defense or (2) significantly increase the probability of existing human errors by significantly affecting performance shaping factors, including mental and physical demands and level of training. While these particular points are not discussed in the SE, it does not appear that the SFCP amendment would impact either of the identified items. Moreover, the SE does note that the risk analysis embodied in the SFCP amendment does include the probability of human errors.
RG 1.174 instructs that whether or not the plant continues to meet the intent of its design criteria should be evaluated. The SE for NEI 04-10 notes that none of the GDC address surveillance frequencies. The DPO suggests that the SFCP amendment does not comply with GDC 17 or 18, nor does it comply with several IEEE standards. However, GDC 17 and 18 set forth the design criteria for the electric power system, including the need to design it so as to permit appropriate periodic testing. The GDC do not set forth the periodicity at which such testing should occur.
There is nothing in the SFCP that alters the design of the electric power system (or indeed the design of any part of the plant.) The DPO asserts that GDC 17 and 18 have not been complied with, but does not explain how it is not complied with. Thus, the statement in the SE for NEI 04-10 is accurate. The DPO further cites several IEEE standards, and states that a plant that adopts the SFCP amendment could no longer meet its licensing basis. This is true, and irrelevant. A license amendment, by definition, alters the licensing basis of a plant. Thus, the fact standing alone, that an amendment allows a plant to alter its licensing basis, does not suggest that the amendment should be denied (nor for that matter does it suggest the amendment should be granted.) Regardless, there is nothing to suggest that the SFCP amendment alters the design criteria of a plant.
Thus, after reviewing the SE and NEI 04-10, comparing them to current guidance on considering defense in depth, while recognizing that the Staff who prepared the SE for NEI 04-10 did not have the benefit of having Rev. 3 of RG 1.174, I conclude that defense in depth is maintained, and thus I disagree with the DPO on this point.
Finding: Disagree, the SE, in a risk-informed manner, adequately explains how the SFCP program is consistent with the defense-in-depth philosophy and maintains sufficient safety margin.
View of Panel Member Daley and Koshy Safety Margin In the case of safety margin, both RG 1.174 Rev 2 and 1.177 Rev 1 are again very similar. Both documents give the following two guidelines for maintaining sufficient safety margins:
Codes and standards or their alternatives approved for use by the NRC are met; Safety analysis acceptance criteria in the License basis (e.g., FSAR, supporting analyses) are met or proposed revisions provide sufficient margin to account for analysis and data uncertainty.
In addition to concerns with inadequate reviews of safety margins, the DPO also expresses a concern that, due to the incorporation of TSTF-425 into the Technical Specifications for many plants, there is no longer an adherence to consensus standards. Specifically, the DPO states, The staff acceptance of electric power system surveillance requirements is based on plant-specific licensing documents and NRC guidance document such as RG 1.9, Application, and Testing of Safety-Related Diesel Generators in Nuclear Power Plants, RG 1.118, Periodic Testing of Electric Power and Protection Systems, RG 1.129, Maintenance, Testing, and Replacement of Vented Lead-Acid Storage Batteries for Nuclear power Plants, to ensure validation of performance capabilities of equipment.
The SE for NEI 04-10 restates the same justification provided in NEI 04-10, stating that the design, operation, testing methods, and acceptance criteria for SSCs, specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plant licensing basis (including the final safety analysis report and bases to TS),
since these are not affected by changes to the surveillance frequency. This statement seems to imply that the authors believed that surveillance frequencies, although a part of the technical specifications, are either not considered to be a part of the licensing bases, or that the surveillance frequencies do not affect the design, operation, testing methods, and acceptance criteria for SSCs. Its not clear what constitutes the basis for this assertion.
Plant specific SEs for the implementation of the Surveillance Frequency Control Program (SFCP) contain the following generic wording:
The engineering evaluation that will be conducted by the licensee under the SFCP, when frequencies are revised, will assess the impact of the proposed frequency change in accordance with the principle that sufficient safety margins are maintained. The guidelines used for making that assessment will include ensuring the proposed surveillance test frequency change is not in conflict with approved industry codes and standards or adversely affects any assumptions or inputs to the safety analysis, or, if such inputs are affected, justification is provided to ensure sufficient safety margin will continue to exist.
If viewed simplistically, this would appear to answer the concern in the DPO; however, the wording in the last sentence stating that the change is not in conflict with approved industry codes and standards can be interpreted a couple of different ways. One would be that any approved (endorsed) codes and standards should receive a review under the SFCP. Another way to interpret it would be that only NRC approved codes and standards that are in the plants license basis need be reviewed. It would appear that the second interpretation is the more appropriate one, because, as stated in NEI 04-10, maintaining sufficient safety margins is assured... since the SSC design, operation, testing methods, and acceptance criteria specified in applicable Codes and Standards, or alternatives approved for use by the NRC, will continue to be met as described in the plant licensing basis (e.g., FSAR, or Technical Specifications Bases).
This is important, because the evolution of codes and standards, and associated RGs that endorse them, over the years has generally been to include more information due to operating experience and better developed guidance and technical bases. A very good example of this is the evolution of RG 1.9 which is also mentioned in the DPO. The different versions of RG 1.9 have endorsed various versions of IEEE 387, IEEE Standard Criteria for Diesel-Generator Units Applied as Standby Power Supplies for Nuclear Power Generating Stations. The original versions of the RG endorsed IEEE 387-1977. This standard contained information about the type of tests to be performed, but it provided little information concerning surveillance frequencies. On the other hand, IEEE 387-1995, which was endorsed by the NRC through RG 1.9, Revision 4, dated March 2007, contains an entire table outlining what the surveillance frequencies for EDGs should be. This was included after a great deal of experience was obtained from past EDG testing and operations and it is approved by a committee that has a voting population including EDG manufacturers, electric utilities, nuclear system design engineers and regulators with each category not exceeding 30 percent of the balloting pool. It is again reviewed by a corporate Standards Board of experts before it is published.
The licensing bases for most plants in the country will contain FSAR commitments to early versions of RG 1.9; however, since most plants were licensed before 2007 and before 1995 (the date of the IEEE standard), the newer versions with surveillance frequencies included would not be a part of the license basis. Based upon NEI 04-10, evaluating extension of surveillance frequencies for EDGs would only require evaluation against the committed to (part of the license basis), earlier versions of the RG, as opposed to the newer RG, Revision 4. In essence, this bypasses an important review that would have been performed by the NRC staff had the surveillance frequency extension been submitted through a LAR, since the staff would have undoubtedly taken the most recently endorsed RG into consideration when deciding the acceptability of the change to the facility.
Because this, and this type of, NRC staff review is essentially bypassed, and was never captured by the SEs for NEI 04-10 and the individual plant LARs, there is agreement with the DPO that the staff acceptance of electric power system surveillance requirements will no longer be based upon NRC guidance documents that are outside of the plants license basis. This appears to be a valid concern.
Additionally, based upon interviews conducted for this DPO review, there is a belief by many that the plant license basis will still be maintained regardless of changes made through the SFCP, because of the requirements of 10 CFR 50.59. This is not the belief of the majority of the industry which maintains that a change to surveillance frequencies is allowed because the program was approved via license amendment. If the change affects the license basis in the UFSAR, the UFSAR can be changed via a screening which cites acceptance based upon an evaluation under the SFCP. In the industrys view, 10 CFR 50.59 does not apply to any changes made under the SFCP. The industry believes that a change to a surveillance frequency under the program obviates the need to perform a 50.59 evaluation even if the change affects the SAR.
This is a large leap, since the review performed under NEI 04-10 is primarily risk informed (CDF and LERF), and the qualitative assessment is very subjective in nature. The 50.59 evaluation which would be performed for such a change affecting the SAR would be quite different and would largely revolve around concerns related to equipment reliability. To state it simply, the questions asked are substantially different.
Additionally, the review of an amendment for the SFCP would be reviewed from a much different perspective than a review of a change to the SAR based upon the plant specific licensing basis.
Changing surveillance frequencies in the technical specifications may be acceptable based upon a more holistic review of the SFCP; however, when a frequency is actually changed in the plant, a similar test or maintenance activity in the SAR may have a much different purpose based upon the plant specific licensing basis. This licensing basis was most likely established during initial plant licensing based upon NRC review, Q&As, and other docketed correspondence. In fact, the test could be the basis for acceptability of more than just the SSC in question. The 50.59 review establishes the basis for conducting such a change, and this evaluation is much different than an SFCP evaluation or the review of an SFCP amendment.
What has also changed is that NRC endorsed standards and codes that are outside the licensing basis are no longer required to be considered when extending a SR frequency; whereas, in the past, the NRC would have most likely considered these documents during the review of a LAR for an extended SR frequency.
The previous discussion leads to a more important question: If NEI 04-10 maintains that sufficient safety margins are assured... since the SSC design, operation, testing methods, and acceptance criteria specified in applicable Codes and Standards, or alternatives approved for use by the NRC, will continue to be met as described in the plant licensing basis (e.g., FSAR, or Technical Specifications Bases), then the conclusion of NEI 04-10 seems to be saying that surveillance frequencies have no effect on safety margin or the plant license basis This is a hard conclusion to follow, since the frequency has always established a portion of adherence to the surveillance requirement. In addition, the technical specifications in their entirety are also a part of the plants licensing bases, and the surveillance frequencies are contained therein.
Furthermore, these surveillance frequencies are being relocated to the SFCP which is a licensee controlled program that is included in the TS Administrative Controls section. The TS Administrative Control requirement states that Changes to the Frequencies listed in the Surveillance Frequency Control Program shall be made in accordance with NEI 04-10, Risk-Informed Method for Control of Surveillance Frequencies, Revision 1. Thus, the circular daisy chain continues, since NEI 04-10, as already discussed, states that there is no impact to safety analysis acceptance criteria as described in the plant licensing basis:
If NEI 04-10, the associated SE, and the new TS Administrative Control are to be taken at face value, the conclusion would be that the Surveillance Frequency has never been a part of the licensing basis, but if that were the case, the SRs would not have to be relocated to the SFCP, and could be simply removed. Additionally, the SE for NEI 04-10, Revision 1, in the Introductory and Background section, states the following:
NEI 04-10, Revision 0, supports relocation of the surveillance frequencies of various SRs from the TSs to a licensee-controlled document, which are controlled in accordance with the requirements of 50.59 of Title 10 of the Code of Federal Regulations (10 CFR). Revisions to the surveillance frequencies are then made in accordance with a new program, the Surveillance Frequency Control Program (SFCP).
On one hand, the case is made that the licensing basis is never affected, but on the other hand, we clearly believed that relocation under the controls of 50.59 and Section 5.5, Programs and Manuals, was essential. We seem to be remarkably confused, considering the enormity of this regulatory change.
In conclusion, there appears to be so many disconnects and circular pointers that there is no clear understanding of what the agencys expectations were, and are, in this regard. What does appear to be the case is that the lack of clarity leaves the nuclear industry with a strong justification to not do anything at all when evaluating safety margins, and the agency appeared to have delegated the responsibility of that same review directly to the industry.
Recommendation (Panel Member Koshy): A change in surveillance and its frequency that exceeds the industry standards or an existing regulatory guidance should be specifically reviewed by the cognizant technical branches before it is authorized to implement.
View of Panel Member Kirkwood First, I note that the vast majority of the code or standard, is still met. As stated by the SER, the design, operation, testing methods, and acceptance criteria for SSCs, specified in applicable codes and standards (or alternatives approved for use by the NRC) will continue to be met as described in the plant licensing basis (including the final safety analysis report and bases to TS),
since these are not affected by changes to the surveillance frequency. NEI 04-10 SE. In other words-the relevant code or standard contains substantially more criteria than a particular surveillance frequency. It contains the design of an SSC, it contains how an SSC should operate, it contains the methods to the test the SSC, and it contains the acceptance criteria for that SSC. All that is changing is the specific frequency upon which the SSC should be surveilled.
Second, the panel interviewed several people who had been involved in the issues raised by the DPO. I was persuaded by the point made by George Wilson regarding the surveillance frequencies contained in many codes and standards. As I understood him, he stated that these frequencies were determined by groups of people determining that the frequency was about right. By contrast, the SFCP program uses a risk based evaluation which takes performance data from the equipment at issue, and determines the appropriate surveillance frequency.
Third, the SFCP program specifically requires the consideration of codes and standards. In its review of NEI 04-10, the Staff asked RAIs observing that RG 1.174, An approach for using Probabilistic Risk Assessment in risk-informed decision on plant specific changes to the licensing basis, states that safety margin is maintained through compliance with codes and standards.
The RAI specifically identified IEEE-387-1984 as an example of a standard that contained a surveillance frequency. The Staff asked NEI to provide deterministic criteria for when a frequency would be changed that would differ from a frequency in a code or standard such as IEEE-387-1984. See Letter from B. Bradley, NEI, to T. Kobetz, NRC, Response to RAIs and NEI 04-10, Final Revision 0, "Risk-Informed Method for Control of Surveillance Frequencies,"
dated July 28, 2006 (ADAMS Accession No. ML062120081). The industry responded noting that the surveillance frequency was only a small portion of IEEE-387-1984, and compliance would be maintained with the vast majority of referenced standards, such as IEEE-387-1984 (e.g. design and maintenance practices, test methods, etc.) The industry also modified Step 7 of NEI 04-10 to provide that before a licensee makes a change to a surveillance frequency, the licensee must be a review of both committed and current codes and standards. The modified Step 7 also provided that any deviations from the surveillance frequencies that are currently committed in the plant licensing basis shall be reviewed and documented. Id. Thus, this demonstrates that any change to a code or standard must be reviewed against both committed and current codes and standards, and the departure must be justified.
RG 1.174 Rev 3 states that safety margin is maintained when 1) the codes and standards, or their alternatives approved for use by the NRC are met, and 2) safety analysis acceptance criteria in the licensing basis are met or proposed revisions provide sufficient margin to account for uncertainty in the analysis and data. In the instant case, the DPO submitters are focused on whether or not applicable codes and standards are met. While I agree that the SFCP program allows a licensee to depart from the surveillance frequency found in a code or standard, I disagree that this demonstrates that the safety margin is not met.
Concern 2.
Specific Issue 3 The Topical Report SE for NEI 04-10 was not reviewed by OGC.
View of Panel Member Daley The DPO expresses the concern that NEI 04-10 was not reviewed by OGC. A similar concern was expressed in NCP-2015-012. The response to that NCP stated, There is no requirement for seeking OGC review on the NRC staff SE for the Topical Report.
LIC-500, Topical Report Process, section 4.2.8, states that the SE should follow the general guidance in OI LIC-101 and then lists a couple of exceptions that are not important for this discussion. With that statement in mind, since LIC-101 applies to License Amendment Reviews, it should be assumed that the Topical Report review should be the same, or extremely similar, to an Amendment review. LIC-101, in section 5.2 states, OGC must review all license amendments except under previously agreed upon conditions (e.g., see Section 8.2.2 regarding the CLIIP). OGC reviews the amendment package for legal adequacy and defensibility (i.e., no legal objection).
Additionally, section 4.2.9 of LIC-500 states, Prior to issuing the final SE, the PLPB PM shall forward a copy of the draft SE to OGC to determine whether the final SE should be considered a rule with respect to the CRA (Congressional Review Act).
While the CRA review was discussed in the response to NCP-2015-012, and evidently a no legal objection determination by OGC was given, no discussion of the linkage between LIC-500 and LIC-101 was discussed, except in view of the eventual review of individual plant license amendments. From a strict read of LIC-500 in conjunction with LIC-101, it would appear that an OGC review was required, in contradiction to the response to NCP-2015-012.
Finding: Disagree. (Please see the documentation below for background on the associated recommendation.)
Recommendation: Perform a review of both LIC-101 and LIC-500 to determine their adequacy moving forward. Consider more clearly defining required actions within these documents, or combine LIC-101 and LIC-500 so that all required steps are contained within one document.
View of Panel Member Kirkwood The statement by the DPO submitters that the original SE for the NEI-04-10 methodology was not reviewed by the Office of the General Counsel is factually incorrect. The ADAMS Accession number cited in the DPO (ML071200238) is the SE for NEI-06-09, allowed outage times. The original SE for NEI 04-10 is found at ML062700012 and the concurrence page for that SE reflects a concurrence from Marian Zobler in the Office of the General Counsel on Sept. 20, 2006.
Since, the SE was in fact reviewed by OGC, and the LIC argument raised by my colleague above was not raised by the DPO submitters, and thus is out of the scope this report, I will not respond further to it in this context.
Finding: Disagree Concern 2.
Specific Issue 4:
Licensees are extending surveillance frequencies through 50.59 evaluations and/or screenings.
View of Panel Member Daley After approval of the SFCP, the program is placed into the plant technical specifications as a program in section 5.5, Programs and Manuals. According to the SFCP, changes to surveillance frequencies shall be made in accordance with NEI 04-10. NEI 04-10 primarily limits changes based upon risk analysis results.
Qualitative assessment by the licensee is performed in a large part by analyzing the effects on defense-in-depth and safety margin. The problems associated with these evaluations were covered in issue 2.
The SFCP change process is described in NEI 04-10. The process starts out with identifying surveillance test intervals for adjustment. In the case of Commitments, the process states that the commitments can be changed using a method acceptable to the NRC, e.g., NEI 99-04. NEI 99-04 contains language that ensures that the proper control mechanism is being used. It states, Is the existing commitment located in the Updated Final Safety Analysis Report, Emergency Plan, Quality Assurance Plan, Fire Protection Program, or Security Plan. It then directs the evaluator to address the changes through the change processes associated with these programs. Using 10 CFR 50.59 for changes that affect the UFSAR is consistent with the regulation and would be acceptable.
This does not diminish the concern that deterministic criteria is not being addressed adequately.
In fact, strictly speaking, the extension of surveillance frequencies by the SFCP is not really being changed through 10 CFR 50.59 evaluations. The frequencies are being changed by the SFCP itself. If the change affects the license basis in the UFSAR, many licensee are changing the license basis via a screening which cites acceptance based upon an evaluation under the SFCP. Much of the industry takes the view that 10 CFR 50.59 does not apply to any changes made under the SFCP.
On a different note, and arguably of greater importance, is the relocation of the surveillance frequencies to the SFCP which is primarily a risk-based methodology as opposed to a risk-informed methodology. Historically, other technical specification relocations have specifically outlined the mechanisms necessary for changing technical specifications that have been relocated. When technical specifications and surveillance requirements and frequencies were relocated to the Technical Requirements Manual (TRM, or the Operational Requirements Manual (ORM) at some plants), each associated specification/requirement was designated a control mechanism such as 50.59, 50.54, etc. In the vast majority of cases, the change mechanism was 10 CFR 50.59. By designating this as the control mechanism, the requirements were, in essence, relocated to the SAR, thereby assuring that changes would get the requisite review.
An example of why this control mechanism is important occurred in the late 1990s and early 2000s. After relocation of certain technical specifications and surveillance requirements and frequencies to the TRM, a number of plants proceeded to completely delete a number of those same requirements. After these changes were reviewed by regional inspectors, it was determined that this deletion could not have been made by the licensee, and it could not have passed a 50.59 evaluation. If a proper change mechanism had not been designated for these relocated technical specifications, this could not have been prevented.
While the SFCP provides a change mechanism, the mechanism is solely risk based. The responsibility for the review of deterministic attributes (defense-in-depth and safety margins),
which was decidedly not performed in the license amendment process in the SFCP, was essentially transferred to the licensees. If this same type of license amendment had been allowed during the relocation of technical specifications to the TRM, the licensees would have little constraint in how they changed and/or entirely deleted requirements and surveillances.
In conclusion, there is agreement with the DPO that the licensees are able to extend surveillance frequencies through nothing more than a screening; however, there is reason to believe that the vast majority of the industry does not follow 10 CFR 50.59 when changing surveillance frequencies. Of the greatest concern, however, is that there is little regulatory structure and criteria for changes to the surveillance frequencies within the SFCP itself.
Deterministic/Qualitative evaluations have been left totally up to the licensees with no distinct criteria or regulation to ensure that these type of reviews are performed adequately. The only structured change process in the SFCP is based upon probabilistic analysis, which ultimately makes this a risk based process as opposed to a risk informed process.
Finding: Indeterminate. In many cases, licensees are making changes to the UFSAR under the SFCP. While it is widely assumed that changes made by the SFCP that affect the UFSAR are being evaluated by 50.59 evaluations, in reality, 50.59 is being bypassed and the rationale for the changes are being made exclusively by the SFCP.
Recommendation: Establish the regulatory applicability of 10 CFR 50.59 to the changes, and the effects of changes, made under the SFCP.
View of Panel Member Kirkwood I agree with the submitters that the surveillance frequencies are being extended by licensees that have adopted the SFCP, without further approval by the NRC. I disagree that these extensions are problematic or that the extensions violate the licensing basis of the licensee. When the SFCP amendment was granted, the licensing basis for the licensee was altered. Thus, so long as the licensee is following its SFCP, no further approval on the part of the NRC is needed. I disagree that a licensee who is following the SFCP needs to also review the frequency change under 50.59 as a generic matter. However, and most significantly, I view the issue of whether or not a 50.59 review is needed in addition to the SFCP review, to be outside the scope of this DPO. This issue was not raised by the DPO submitters, but rather by a panel member. This is the subject of a current disputed violation. Thus, I will not respond further to this topic in this forum.
Finding: Both Agree and Disagree Concern 2.
Specific Issue 5:
NRC staff acceptance of SRs is based upon guidance documents such as RG 1.9, 1.118, and 1.129. These documents have not been adequately addressed.
View of Panel Member Daley:
This concern was addressed under Specific Issue 2. Specifically, the discussion in issue 2 concluded that this type of NRC staff review was essentially bypassed, and was never captured by the SEs for NEI 04-10 and the individual plant LARs and that there is agreement with the DPO that the staff acceptance of electric power system surveillance requirements will no longer be based upon NRC guidance documents that are outside of the plants licensing basis. It was also discussed that the licensing basis is being changed solely through use of the SFCP, which for practical purposes results in any disagreement between a change in the SFCP and a RG and other standard in the UFSAR to be essentially screened out and changed without the necessity for further evaluation. The bypassing of these reviews appears to be a valid concern.
However, if a licensee were to actually use 10 CFR 50.59 to justify a change, the allowance for the licensee to change surveillance frequencies and evaluate those changes against their license basis is no different than what is already allowed under 10 CFR 50.59 for changes to the facility.
This appears to be in line with other relocated technical specifications which are normally controlled by other appropriate change mechanisms (i.e., 50.59, 50.54, 10 CFR 20, etc.). What has changed is that NRC endorsed standards and codes that are outside the licensing basis are no longer required to be considered when extending a SR frequency; whereas, in the past, the NRC would have most likely considered these documents during the review of a LAR for an extended SR frequency.
Finding: Agree. Rationale is provided below, but it is also provided in greater detail under Specific Issue 2.
Recommendation:
None: See recommendations under Specific Issue 2.
View of Panel Member Kirkwood I disagree that there has been a wholesale abandonment of the RG. To the extent a licensee is following a RG, they will continue to do so. The only thing the SFCP changes is that to the extent that RG might provide a specific surveillance frequency, the frequency of the surveillance will now be governed by the SFCP rather than the RG. This appears to be the same concern as the concern about codes and standards, discussed above. The SFCP allows surveillance frequencies to be determined by specific data regarding the SSC to be surveilled, rather than governing the frequency through a statement in a generic regulatory guide.
Finding: Disagree.
Concern 3: Event Reporting Guidelines for a Loss of Offsite Power (LOOP). By interpreting 10 CFR 50.72/50.73 to apply only to safety-related structures, systems, and components, NUREG-1022, Revision 3 inappropriately excludes the offsite power system from reportability requirements that is essential for assessing the continued availability of the preferred source of power. The under-reporting of LOOP causes non-conservative plant-specific risk assessments as well as Reactor Oversight Process Significance Determination Process evaluations because of changes in initiating event frequencies.
Discussions and Conclusions View of Panel Member Kirkwood NUREG-1022 provides implementing guidance for 10 CFR 50.72, Immediate notification requirements for operating nuclear power reactors, and 10 CFR 50.73, Licensee event report system. The purpose of 10 CFR 50.72 is to provide timely and accurate reporting of significant events at operating nuclear power plants, where immediate Commission action may be needed to protect the public health and safety or where the Commission needs accurate and timely information to respond to heightened public concern. See Immediate Notification Requirements of Significant Events at Operating Nuclear Power Reactors, 49 Fed. Reg. 39039, (Aug. 29, 1983). 10 CFR 50.73 created the Licensee Event Report system, which is intended to provide the information necessary for engineering studies of operational anomalies and trends and patterns analysis of operational occurrences. The same information can also be used for other analytic procedures that will aid in identifying accident precursors. See Licensee Event Report System, 48 Fed Reg. 33850 (July 26, 1983). Neither the language found in 10 CFR 50.72 nor the language found in 10 CFR 50.73 state that all LOOPs are reportable.
The concern raised by the DPO submitters is about the reporting requirements for a certain subset of LOOPs sometimes referred to as partial LOOPs. The submitters are specifically concerned that if there is a loss of one or more of the required offsite power sources into the switchyard there may not be an actuation of a safety system that would cause the event to be reportable under the revised reporting guidelines. Operating plants have been designed to prefer the offsite power to power the safety buses in case of an event because its reliability is higher than onsite emergency power supplies. By not monitoring (through event reporting) this partial LOOP grid reliability is not being monitored and thus the data for maintaining event mitigating capability is not current because it does not include these partial LOOP events.
Previous revisions of NUREG-1022 required the reporting of all LOOPs, including partial LOOPs. In the discussion of creating Revision 2 of NUREG-1022, the Staff stated that all LOOPs are reportable. The Staff further noted that the inclusion of all LOOPs in reporting guidelines should have a negligible impact on reports because most events involving LOOPs are reportable for other reasons. The language of the regulation itself does not compel the conclusion that all LOOPs are reportable. While the previous Staff position may have been that all LOOPs are reportable, the Staff is entitled to change its interpretation of the regulations.
The DPO submitters give several reasons as to why all LOOPs should be reportable and NUREG-1022 should be revised to reestablish the previous reporting requirements. They believe that all LOOPs should be reportable pursuant to 50.72(b)(3)(v) and 50.73(a)(2)(v).
50.72(b)(3)(v) states that the NRC must be notified within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of Any event or condition that at the time of discovery could have prevented the fulfillment of the safety function of structures or systems that are needed to: (A) shut down the reactor and maintain it in a safe shutdown condition; (B) remove residual heat; (C) Control the release of radioactive material; or (D) mitigate the consequences of an accident. 50.73(a)(2)(v) contains the identical language for when a Licensee Event Report must be submitted.
Revision 2 of NUREG-1022 stated that If either offsite power or onsite emergency power is unavailable to the plant, it is reportable regardless of whether the other system is available.
Revision 1 of the document has a similar statement but includes a parenthetical (i.e., completely lost). Revision 3 of the document deleted this language, but included several examples of when a LOOP would be reportable.
The DPO submitters stated that for many operating power plants the offsite power system is a standby system and therefore a LOOP would not cause the Emergency Diesel Generators to start because the safety buses are powered by the plant main generator. This condition might be more significant because during this undetected partial LOOP condition, the operator may take non-conservative equipment outages, which may result in a reduction of defense-in-depth.
However, this does not justify why it would make an undetected partial LOOP reportable.
Because of the diversity in design, it does not appear that this type of LOOP would prevent the fulfillment of a safety function. Moreover, there appears to be an implicit argument that the operator would be unaware that the LOOP is occurring, but making it reportable pursuant to 10 CFR 50.72 or 10 CFR 50.73 would make the operator aware of the event. However, these are reporting requirements for events that the operator is aware is occurring. In addition, the reporting requirement does not apply until the operator is aware of the event and the time frames for reporting run from the discovery of the event. Thus, to the extent the submitters have identified a potential safety issue, it is not impacted by the reporting requirements of 10 CFR 50.72 or 10 CFR 50.73.
The DPO submitters state that the offsite power system is important to safety. I find that the statement is generally correct but it does not clearly justify why the loss of the system would be reportable under the requirements of 10 CFR 50.72 or 10 CFR 50.73. Similarly, the DPO submitters state that Chapter 15 and Chapter 6 of the FSAR review a number of events with or without offsite power available. I find that the statement is correct but it does not justify why a LOOP would be reportable under the requirements of 10 CFR 50.72 or 10 CFR 50.73.
The DPO submitters state that a LOOP is a TS limiting condition of operation which calls for either the restoration of power or shutdown. The DPO panel finds that the statement is correct but it does not justify why a LOOP would be reportable under the requirements of 10 CFR 50.72 or 10 CFR 50.73. To the extent a plant shutdown is required because of the LOOP due to the TS requirement, it is reportable pursuant to 10 CFR 50.72(b)(2)(I), which calls for the report of any plant shutdown required by the TSs. If the offsite power was able to be restored within the LCO, it does not appear that it would be reportable.
The DPO submitters state that underreporting of LOOPs will lead to incorrect risk assessments since a LOOP is a substantial contributor to the risk profile at a nuclear power plant. The DPO panel finds that it does not justify why a LOOP would be reportable under the requirements of 10 CFR 50.72 or 10 CFR 50.73. Discussions with the agency staff and an Idaho National Laboratory representative with expertise on risk assessments found that LOOPs without a plant transient were not factored into the risk assessment from the beginning and do not contribute to plant risk as an initiating event. However, the condition of a LOOP without a plant transient can be a factor in risk mitigation since the offsite power system can be used to mitigate the consequences of certain initiating events. It is not clear to what extent the data in risk assessments (related to the risk mitigation) have relied on the information available in the 10 CFR 50.72 and 10 CFR 50.73 reports.
In summary, I agree that previous versions of NUREG-1022 required the reporting of all LOOPs, and the staff further noted that the inclusion of all LOOPs in reporting guidelines should have a negligible impact on reports because most events involving LOOPs are reportable for other reasons. The language of 10 CFR 50.72 or 10 CFR 50.73 itself does not compel the conclusion that all LOOPs are reportable. While the previous Staff position may have been that all LOOPs are reportable, the Staff is entitled to change its interpretation of its regulations. Therefore, I find that there is no clear basis for requiring the reporting of all LOOPs under 10 CFR 50.72 or 10 CFR 50.73.
Finding: Disagree with the DPO submitters.
View of Panel Member Koshy I reviewed the Electrical Branch bases for needing the records on partial LOOPs and concluded that several electrical branch assessments depend on that information. Therefore I further reviewed the matter to address how the non-conservative reporting has influenced the Electrical Branch assessments for electrical system reliability for accident mitigation/ emergency core cooling.
I contacted the RES representative associated with risk modeling and engaged in meetings with the following individuals:
John C. Lane, RES/DRA/PRB. Senior Reliability & Risk Engineer Don G. Marksburry, RES/DRA/PRB John Schroeder, INEL Stacy Rosenberg, BC, PRA-Branch A, NRR Jeff Circle, PRA Branch A, NRR The discussions led to the following conclusions:
The Loss of Offsite Power Events that do not cause a plant transient were not factored into the risk assessment from the beginning. Those are referred to as partial LOOPs (a new PRA definition) and do not contribute to plant risk because it does not lead to a plant transient leading to initiating events. The electrical definition for LOOP is the loss of offsite power -that is considered the most reliable source for accident mitigation in accordance with 10CFR 50 Appendix A, GDC-17, and it is independent of any impact or lack of impact in causing a plant transient). The Technical Specification allows each offsite power to be out for a certain duration and more restricted time for plant operation when both offsite power sources are out because offsite power is the most rugged source of power for emergency core cooling. The absence of both offsite power sources will not cause a plant transient for the majority of the operating plants.
This fact is not realized by most of the PRA staff members that were interviewed. The unusual plant configuration that would cause a plant transient or trip and the change in the amount of reports received are explained later in this section. PRA attributes greater reliance on the safety related power source (generally EDGs). The offsite power availability and recovery curve has been factored in to the Standardized Plant Analysis Risk (SPAR) model. The risk contribution from LOOP is considered as 10-2 for computing Conditional Core Damage Probability for plant events in the absence of offsite power. This factor is not revised and no inputs are collected for partial LOOP that do not cause a plant trip or a transient. Therefore, the change in increased frequency of partial LOOP (PRA definition) or an increased duration in the recovery period will remain unrecognized in the SPAR models. This assessment would be incorrect if the plant is physically located in an area where the offsite power undergoes frequent outages.
Risk assessments should be influenced by the plant specific offsite power availability and reliability because of its significant safety contribution rather than assuming a fixed value that is never revised for actual grid conditions at the plant. Before the risk assessments were developed, partial LOOPs were reported, and those reports were factored in to the determination to allow for extended outage time for EDGs when unanticipated maintenance activities are urgently needed.
The over-simplified risk characterization of a partial LOOP that remain unconsidered irrespective of its duration needs further review: GDC 17, the design basis considers offsite power supply as the preferred choice for accident mitigation and its capability is considered to be superior to the best emergency diesel generator available on site. Because of the ruggedness of the offsite power, the plant operating procedures generally advise to reconnect the safety bus to the offsite power even though it was unavailable at the onset of the plant event. The capability of the accident mitigation system performance significantly depends on the reliability and ruggedness of offsite power. The historical record on interruption frequency and duration of the loss of offsite power are indicators for the regulatory confidence on accident mitigation system capability. In general, it appears the grid management plan is progressing towards more decentralized control, leading the greater influence from local generation and loading, and that potentially leads to increased response time based on energy sources and loading. The reliability and availability of the offsite power, the primary source for accident mitigation, needs to be monitored and periodically assessed.
A partial LOOP event, as defined by PRA consideration, could cause a plant transient only on very limited plant configurations driven by the following conditions (It is recognized there are a few isolated exceptions to this configuration):
(1) During start up and power ascension to about 25% power level (when Offsite power is lined up to feed house loads)
(2) During planned shutdown process when the power level comes down below 40% output (when Offsite power is manually lined up to feed house loads)
(3) Certain isolated plant bus line up necessitated by grid conditions where the onsite electrical loads are always directly lined up to offsite power.
The above mentioned unusual electrical bus line ups are needed because the design bases is to avoid an offsite power transient when the plant main generator trips and onsite loads fast transfer (within a few AC cycles) to offsite power (that is unhindered by the trip of a main generator output) needed for residual heat removal and ECCS.
Two other unusual offsite electrical lineups that could cause a reportable LOOP under the present NUREG guidance are: (1) If the offsite power is taken from the same power grid point where the generator is feeding, the 1000MW power plant trip would cause an immediate voltage reduction/transient that will make the offsite power unavailable at the required voltage (this is not the case in our current US operating reactors); and (2) when there is an adverse environment such as salt spray on generator feeder circuits at coastal plants, or heavy winds that could cause a generator trip, the plant may opt to keep safety bus connected to the offsite power that is unaffected by such external events. These conditions would create a pant transient that could lead to a trip and consequently a report to the NRC.
There is an economic reason for the preferred line up such that the plant hotel loads are being powered directly from the main generator during operation. This case could reduce the cost of onsite power consumption as opposed to buying power from the grid at the selling price in a deregulated utility environment. Therefore, the revised reporting requirements for a LOOP in 10CFR50.72/73 results in 3-5 partial LOOPs per year in the PRA consideration. Most of the partial LOOPs (as designed in accordance with GDC-17) will remain un-noticed and unreported because the offsite power is in standby mode (backup power). The previous interpretation resulted in 117 records when counted from 2010-16. It is undesirable to find out that the offsite power designed to be the primary source is unavailable when there is a valid demand.
The current PRA modeling practice does not incorporate the full reliability and availability of offsite power. This is inconsistent with the design requirement in GDC-17 to have specified requirements such as [p]rovisions shall be included to minimize the probability of losing electric power from any of the remaining [power] supplies as a result of, or coincident with the loss of power generated by the nuclear power unit, the loss of power from the transmission network, or the loss of power from the onsite electric power supplies.
Following the northeast blackout in August 14, 2003, NRR electrical branch worked with the North American Electric Reliability Council (NERC) and the Federal Energy Regulatory Commission (FERC) to ensure that nuclear stations had priority to reestablish power feeders because it helped ensure another layer in nuclear safety. After approximately two years of continued efforts, FERC mandated a procedure to confirm the priority of aligning power feeder to nuclear stations and to keep nuclear station operators promptly notified on power supply contingencies. The non-reporting of partial LOOPs can potentially lead to ignoring this condition it and will further have a chilling effect on FERC that responded to our pressing need for nuclear safety. This is contrary to sustaining the importance of preserving the priority of offsite power as the preferred source of energy for accident mitigation.
The DPO submitters want to address the weaknesses in safety assessments caused by this revised partial LOOP interpretation. It results in a prolonged outage of offsite power to both trains and remaining unreported and un-noticed on such an outage as it did not cause a plant transient or EDG start. This condition will be further magnified due to the anticipated changes in the electric grid. Specifically, the increased use of renewables and the advanced monitoring and control systems is relied on to reduce the grids spinning reserves necessary for localizing the impact of electrical faults and loss of local generation. The last study conducted in this area indicated a reduction of LOOPs (without a plant transient) but longer duration to recover from a LOOP. The increase in duration of offsite power recovery has a greater impact on NPPs. While this is the general trend, the regional power grid performance could be much different at plant locations. Without reporting all partial LOOPs (even those that do not cause a plant transient), as required by the former guidance, the following electrical branch assessments become problematic:
(1) The continued confidence in the offsite power capability considered in the licensing bases cannot be reaffirmed to ensure adequate safety for current condition or future amendments, if not monitored.
(2) The continued confidence in the Station Blackout (SBO) licensing bases (time to recover from LOOP, onsite capabilities, etc.,) cannot be monitored to ensure adequate safety for current conditions or future amendments.
(3) PRA assessments on mitigation system availability/capability has no feedback or correction based on LOOP (with or without plant transient are much more frequent) duration or its frequency.
(4) There will be no information available on offsite power performance history in order to grant enforcement discretion for a greater outage period for addressing an emergent problems with emergency diesel generator urgent repair/ maintenance Note: The local grid performance may change if the decentralized grid management concept, continues to progress. How this change would influence grid voltage regulation and grid resiliency will need further research to assess the potential impacts on nuclear safety and it will vary in each plant location.
Finding of Member Koshy: Agree Recommendations of Member Koshy:
1.
The organization responsible for NUREG-1022 should evaluate the agencys uses of the information on LOOPs reported pursuant to 10 CFR 50.72 or 10 CFR 50.73 reports for the above four actions conducted by electrical branch and revise NUREG-1022 to report all LOOPs as was previously the case 2.
Collect data on partial LOOP (according to PRA definition) through a formal process to effectively address the four issues mentioned above, and periodic revision to plant specific risk model based on the partial LOOP data indicating availability and reliability of the preferred power source for accident mitigation system.
- 3. The designed offsite power should be monitored for its availability and reliability, because the offsite power sources is the preferred power source for emergency core cooling as stated in GDC 17. If this not necessary anymore, agency action is needed with stakeholder involvement because this is a major change to the defense in depth for accident mitigation.
Finding of Member Daley I agree with both prior Panel Member positions, which are quite different, but not necessarily mutually exclusive of each other. However, I do not necessarily agree that the LOOP event should have been determined to be non-reportable.
There does appear to be some latitude in regard to legal interpretation of the reportability requirements; however, stating that the rule can be re-interpreted is not the same as saying that it should be re-interpreted. Precedence is an important baseline, and overturning that precedent should not be taken lightly. Unless there is clear evidence that the past interpretation is decidedly incorrect, re-interpretation starts taking the form of the desires of those who have the most influence on the changes. In this case, I have yet to see the decided information that was available for making this change (It may exist, but I have not seen it yet.). Additionally, the information that was available for omitting LOOP reportability seems to be no different than the information available when the LOOP event was determined to be reportable years previously.
The Statement of Consideration for 10 CFR 50.73 states the following (48 FR 33851):
This rule identifies the types of reactor events and problems that are believed to be significant and useful to the NRC in its effort to identify and resolve threats to public safety. It is designed to provide the information necessary for engineering studies of operational anomalies and trends and patterns analysis of operational occurrences. The same information can also be used for other analytic procedures that will aid in identifying accident precursors.
The need for this information is outlined as well in (46 FR 3542), which gives the following reasons:
1.
Performing probabilistic risk assessment calculations of accident probabilities and public risks.
2.
Revising component test intervals and downtimes.
3.
Quantifying the impacts of human errors.
4.
Identifying trends and patterns in operating experience.
5.
Obtaining detailed component engineering information.
6.
Relating current incidents to previous failures.
7.
Determining where identical components are installed.
8.
Relating current failures to previous testing.
9.
Issuing Abnormal Occurrence Reports.
- 10. Issuing Operating Experience Journal of Power Reactor Events.
Many of the reasons outlined above encompass the rationale given in the view preceding this one. Additionally, the primary staff members that would be evaluating information related to the LOOP event would be the same individuals who submitted the DPO. There is evidently still a rationale for receiving this information among the NRR staff who would primarily use it in their work, so changing the past precedence would appear to at least be contrary to the expressed need for this information (based upon past precedent for reporting the LOOP event) contained in the Statements of Consideration.
At very least, it would seem that alternative means for obtaining this information should now be considered, since omission from reporting did not appear to take into account the specific needs of the staff that needed the information most. However, if the rationale - described in the Statements of Consideration - for collecting much of this information is no longer valid, it should be arguable that the rule has outlived its usefulness and needs to be revised to provide a more efficient and effective process that serves the agency best and reduces the burden on the licensees.
Recommendation
- 1. Determine the information that is still needed by the staff in regard to the LOOP event. Provide the best method for obtaining that information so that the staff can still perform their function effectively.
View of Panel Member Caldwell I am in fundamental agreement with Panel Member Daley. The agency process was appropriately followed to revise the reporting requirements for 10CFR50.72 and 50.73, including the non-concurrence process where this specific issue was originally addressed, NCP-2012-008, LOOP Reporting (ADAMS ML12363A061). The NCP outlines the technical arguments and the reasons the Division Director responsible for the program decided to remove the reporting requirement. However, given the arguments provided by the technical branch which used the information in the reports, the fact that they stated the reports were useful in their decision-making process I would have recommended that the reporting requirement remain as originally implemented. Since the reporting requirement has been deleted, it will require significant agency resources to re-establish it, including developing a robust safety case.
Currently, licensees are generally dependent of Regional Transmission Officers (RTOs) to identify when a LOOP takes place that does not directly impact the plant and cause a plant transient. LOOPs that cause plant transients are reported under other reporting criteria currently in place. In deference to the paperwork reduction act, if a government already requests information then another agency or department that wants/needs that information is obligated to get it from the initial agency. The Department of Homeland Security is the national department responsible for the energy infrastructure of the United States. Additionally, FERC and NERC have responsibilities in this area. Depending on the safety significance of the information, as defined by the technical branch that requires the information, it is appropriate to attempt to gather this information from these and/or other sources, prior to attempting to re-impose the previous reporting requirements.
Finding: Agree and disagree.
Recommendation:
Same as Panel Member Daley
Document 4: Independent Review of DPO Panel Report
UNITED STATES NUCLEAR REGULATORY COMMISSION REGION I 2100 RENAISSANCE BOULEVARD, SUITE 100 KING OF PRUSSIA, PA 19406-2713 June 28, 2018 MEMORANDUM TO:
Brian E. Holian, Acting Director Office of Nuclear Reactor Regulation FROM:
Raymond K. Lorson, Independent Reviewer, Director
/RA/
Division of Reactor Projects, Region I
SUBJECT:
INDEPENDENT REVIEW OF DIFFERING PROFESSIONAL OPINION PANEL REPORT ON RISK MANAGEMENT TECHNICAL SPECIFICATION (RMTS) 4b AND 5b RISK INITIATIVES AND EVENT REPORTING FOR LOSS-OF-OFFSITE POWER (LOOP) (DPO-2016-003)
I was tasked to review the report from the Differing Professional Opinion (DPO) Review Panel (DPO Submission ML16295A102) that had been formed to review a DPO regarding the approval of license amendments for implementation of Risk Management Technical Specification (RMTS) 4b and 5b risk initiatives, and a change to the event reporting guidelines for a loss-of-offsite power (LOOP). The DPO Panel was unable to develop a consensus position on any of the items in the DPO and the purpose of this independent review was to assess the information discussed in the DPO Panel report and to provide recommendations to the NRR Office Acting Director regarding disposition of the issues raised in the DPO.
The findings and recommendations from the independent review are discussed in. The independent reviewer determined that since TSTF-505, Provide Risk-Informed Extended Completion Times -RITSF 4b, has been suspended for use, and is currently being revised, that the DPO remedy related to this area has been satisfied. The independent reviewer disagreed with the DPO regarding the need to retract the RITSTF Initiative 5b, and also with the DPO request to retract the latest revision to the event reporting guidelines related to losses of off-site power. The independent reviewer did make several recommendations in the attached report to improve oversight and approval of risk informed actions, many of the recommendations are already on-going as part of NRRs Risk Informed Decision Making Action Plan.
Please do not hesitate to contact me if you have any questions regarding the enclosed report.
Enclosure:
Independent Review of DPO Panel Report cc: Submitter Director, OE DPO Project Manager CONTACT: Raymond K. Lorson, Director Region I/Division of Reactor Projects (610) 337-5229
ML18179A480 SUNSI Review Non-Sensitive Sensitive Publicly Available Non-Publicly Available OFFICE RI/DRP NAME RLorson DATE 6/28/18
Enclosure Independent Review of DPO Panel Report 2016-003 The independent reviewer was tasked to review the findings and recommendations provided by the DPO Panel for DPO-2016-003 and to provide recommendations to the NRR Office Director (Acting) regarding how to best disposition the issues identified in the DPO. The DPO had three primary concerns, which are discussed in detail below.
As discussed in the transmittal memo to the DPO Panel Report, the DPO Panel formed to review these issues was ineffective in that they were unable to reach a consensus position. Instead the DPO Panel members documented their individual findings and recommendations for each of the issues.
As part of this effort, the independent reviewer reviewed a number of documents for reference, and to better understand the points raised by each of the DPO Panel members. In addition to the original DPO and Panel report for DPO-2016-003, the independent reviewer examined: NEI 04-10, NRC Non-concurrence (NCP) NCP-2012-008, Regulatory Issue Summary (RIS) RIS 2001-14, NRRs Risk Informed Decision Making Action Plan (RIDM), NRC Regulatory Guide 1.174, Revision 3, the NRC Inspection Manual, NUREG 1022 Revisions 2 and 3, and 10 CFR Part 50. In addition, the independent reviewer discussed some of the issues with applicable subject matter experts, and with one DPO Panel Member, to seek clarity and to better understand the views documented by this member in the DPO Panel Report.
The independent reviewers findings, recommendations, and observations/discussions of the concerns identified in DPO-2016-003 are discussed below.
Concern 1: Risk-informed extended completion times - RITSTF Initiative 4b. Safety Evaluations (SEs) associated with RITSTF Initiative 4b are being prepared with a primary focus on probabilistic risk (risk-based principles established by TSTF and Topical Report, rather than risk-informed principles that complement the deterministic principles). Consequently, the technical bases established in relevant NRC requirements, including plant-specific design and licensing basis, are not specifically addressed to justify approval of license amendments referencing RITSTF 4b, and therefore, reasonable assurance of adequate protection of the public health and safety is not provided.
The submitter's suggested remedy for this concern, included withdrawing the approval of risk initiative 4b and issuing a RIS highlighting the issues raised in the DPO.
Findings and Recommendations The independent reviewer examined the views expressed by each DPO Panel member regarding Concern 1 as documented in their report. As stated in their transmittal memo, the DPO Panel was unable to develop a consensus position regarding the issues raised in the DPO. However, in reviewing the DPO Panel report, there appeared to be some areas where general agreement was achieved regarding Concern 1, including:
observations related to the quality of the initial documentation for the safety evaluation
2 Enclosure performed by the staff in approving RISTF Initiative 4b at Vogtle, the need to ensure that staff with the right technical skills are involved with the review of RISTF Initiative 4b licensing applications, and also that the approval of RISTF Initiative 4b appeared to be a "risk-based as opposed to risk informed. Two of the DPO Panel members also recommended further review and assessment of the underlying guidance documents used to support risk informed licensing amendments, whereas the two other DPO Panel members recognized that Revision 3 to Regulatory Guide 1.174 offered much improvement in this area.
Finding 1: Given that RISTF Initiative 4b is currently suspended, has been extensively revised, and is out for comment, the submitters suggested remedies for Concern 1 have been addressed. The need to issue a separate RIS highlighting the issues in the DPO related to Concern 1 is unnecessary, since the normal agency actions associated with comment resolution will establish a basis for disposition of comments received.
The DPO Panel report provided a statement in the cover memo that the approval of the RISTF Initiative 4b safety evaluation was risk based as opposed to risk informed.
Based on a review of information contained in the DPO Panel report, the independent reviewer was unable to determine the specific basis for this conclusion, but based on a review of comments provided by the DPO Panel members, believes that this statement was likely developed based on issues related to earlier guidance documents that were in effect when the safety evaluation for RISTF Initiative 4b was being developed. In addition, the timing and assignment of staff to conduct development of this safety evaluation (i.e. some of the statements in the DPO Panel report indicated that the technical and risk reviews were completed separately and not as an integrated effort) may had supported this assessment as well.
Finding 2: The independent reviewer does not agree with the assessment provided by the DPO Panel that the approval of RISTF Initiative 4b was risk based and determined that the approval was consistent with a risk informed approach. Specifically, while not mentioned in the DPO Panel report, the RISTF Initiative 4b limits technical specification completion time extensions to a maximum duration of 30 days, even though many underlying risk assessments would likely support much longer durations. A risk based, as opposed to a risk informed approach, would not limit the approval of completion time extensions. Notwithstanding any differences in opinion in this area, Recommendations 1-3 describe specific actions that should help alleviate future concerns.
Recommendation 1: The DPO Panel members appeared aligned on the need to ensure that qualified staff in all relevant technical areas, and not just risk experts, are fully involved with risk informed licensing review efforts. In their Risk Informed Decision Making (RIDM) plan (Task 1), NRR has identified the benefits associated with expanding the use of multi-disciplinary teams for review of risk informed licensing actions. No further action is needed in this area other than for NRR to continue to effectively implement RIDM Task 1.
3 Enclosure Recommendation 2: Two DPO Panel members expressed concerns related to some of the guidance documents associated with risk informed licensing actions. The agency has already taken action to improve the quality and completeness of certain documents in this area, such as the recent issuance of Revision 3 to Regulatory Guide 1.174, and a recent memo from the Director of NRR (Acting) in June 2018, informing staff how to properly integrate multiple review standards and guidance documents in support of regulatory decisions. NRR should continue to review and update program documents and guidance associated with risk informed licensing activities, as described in their Risk Informed Decision Making Action Plan, and as further directed by the Risk Informed Steering Committee. Since these are on-going and evolving efforts to improve the quality of guidance supporting risk informed decision making, no further actions beyond those specified by RIDM and RISC are necessary.
Additionally, the DPO Review Panel provided observations related to: the scope of the DPO Panel review effort (i.e. one panel member expressed a concern that some members of the DPO review panel went beyond just a review of issues contained in the original DPO and also questioned whether it was appropriate to review this issue since RISTF Initiative 4b was not a final product at the time the DPO was initiated). Other issues included a statement questioning the adequacy of information provided by risk models when evaluating technical specification completion time action statements associated with safety-related DC circuits, and a need to provide training for inspectors regarding RISTF Initiative 4b.
Recommendation 3: The Office of Enforcement has an on-going action to review the differing professional opinion and non-concurrence programs. Suggest that the observation related to "out of scope" comments by DPO Panel members and whether it is appropriate to initiate a DPO before a final agency action has been issued to be considered as part of this review effort.
Recommendation 4: The need to establish guidance and to train inspectors on risk informed licensing actions, like RISTF Initiative 4b, is necessary to ensure that inspectors have the proper tools to ensure consistent and reliable oversight and enforcement in this area. Recommend that the Division of Inspection and Regional Support and the Division of Risk Analysis review and update, as necessary, inspection guidance for oversight of licensee implementation of risk informed licensing activities and update as necessary. As part of this effort, the Division of Inspection and Regional Support should consider and develop appropriate training for inspectors.
Recommendation 5: One DPO panel member provided comments related to the adequacy of risk models to assess plant conditions associated with postulated DC voltage failure modes. The postulated failure mechanisms, discussed in the DPO Panel report, had the potential to result in certain types of initiating events and/or safety-system malfunctions. The panel member referenced selected scenarios using a deterministic fault analysis approach, but did not provide any information, other than a general statement, that existing risk models are unable to capture some of these failure
4 Enclosure modes and effects. The information in the DPO panel report did not discuss how operating experience is often factored into risk modelling assumptions and did not attempt to capture or address how a risk informed decision to increase a technical specification allowed outage time could actually help maintain plant safety margins by not putting the plant through the risk associated with a mode transition with a degraded or out-of-service safety system. Based on a review of the information discussed in the report, the independent reviewer did not identify the need to revise any current risk informed licensing activities, but, recommends that the Division of Risk Assessment and the Division of Engineering meet to understand the comments in this section of the DPO Panel report and to assess whether any action is needed to update guidance related to use of NRC risk models to support decision making.
Concern 2: RITSTF Initiative 5b. Safety Evaluations associated with Topical Report SE for NEI 04-10 are being prepared with a primary focus on probabilistic risk (risk-based principles established by TSTF and Topical Report rather than risk-informed principles that complement the deterministic principles). Consequently, the technical bases established in relevant NRC requirements, including plant-specific design and licensing basis, are not specifically addressed to justify approval of license amendments referencing RITSTF 5b, and, therefore, reasonable assurance of adequate protection of the public health and safety is not provided.
The DPO Submitter suggested remedy was to withdraw the approval of risk initiative 5b and to issue a RIS highlighting the issues in the DPO.
Findings and Recommendations The independent reviewer examined the views expressed by each DPO Panel member regarding Concern 2 was documented in their report. Several of the DPO panel members appeared to be aligned regarding whether the qualitative criteria specified in NEI 04-10 was sufficiently prescriptive, such that it could be applied in a consistent and predictable manner. Closely related was a concern that more guidance and training of inspectors was needed to ensure consistent and reliable oversight of a licensees implementation of their surveillance control program. Finally, some DPO panel members noted that implementation of the surveillance control program could result in practices that may deviate from industry codes and standards and/or NRC regulatory guides. However, one panel member noted that these deviations were narrowly limited to surveillance frequency requirements and all other aspects of codes and regulatory guides, for example the types of tests to be performed would remain in effect. In addition, there appeared to be general agreement that since a licensee could modify their surveillance frequency requirements, without requesting a license amendment, that the level of review and standards would likely be different than if a license amendment had been submitted to the NRC.
The independent reviewer noted that the NRC has already issued, for many licensees, RITSTF Initiative 5b, and to withdraw approval of this amendment would require a backfit analysis. The independent reviewer did not identify any specific safety concern
5 Enclosure or information in the DPO panel report that would provide justification for withdrawal of RITSTF Initiative 5b. The potential impact to plant safety associated with a longer surveillance test frequency is that it could allow a degraded equipment condition to remain undetected for a longer period of time. While the surveillance frequency could be extended using this program, the extension would be required to be supported by a site specific technical analysis justifying the surveillance interval. In addition, it is important to note that there are multiple programs in place to monitor, assess and take action to maintain acceptable equipment performance. The independent reviewer is not aware of any information that would suggest that safety system performance has been adversely impacted since approval of RITSTF Initiative 5b. Safety system performance (availability and reliability) is governed and confirmed by how the equipment is designed, manufactured, operated, maintained, and types of testing performed.
Equipment performance does not rely upon how often it is tested. In fact, the independent reviewer noted that surveillance testing can, in some cases, degrade plant safety margins through equipment wear and tear associated with testing, through establishment of plant configurations that present elevated risk, and/or remove the ability of the system to respond to an actual demand signal.
Current regulations, and the reactor oversight process include a number of requirements and areas where licensee activities and follow-up NRC inspection oversight is adjusted based on equipment performance trends and issues. Some of these requirements and oversight activities include: Appendix B, Criterion XVI, Corrective Actions, maintenance rule requirements associated with balancing equipment reliability and availability, performance indicators tracked and assessed per the reactor oversight process, and evaluating the significance of findings associated with equipment problems attributed to licensee performance deficiencies. While licensees have the ability to independently adjust surveillance test frequencies under RITSTF Initiative 5b, the independent reviewer determined that the above requirements and the reactor oversight program follow-up activities provide sufficient elements to monitor and assess equipment performance and to require specific actions if a licensees efforts to respond to a degraded equipment condition are not sufficient.
In addition, the independent reviewer examined the list of qualitative factors (like specific site history and operating experience) described in NEI 04-10 that would be used to adjust surveillance frequencies and found that, if a licensee properly implemented this guidance, then there appeared to be a site specific technical basis for selecting system test frequencies, as opposed to what would typically be specified by following a generic or industry wide specification.
Finding 3: Retain and do not retract RITSTF Initiative 5b.
6 Enclosure The DPO panel identified several specific issues during their review, which are summarized below. In completing this independent review, each of the below specific issues was reviewed and commented on.
Specific Issue 1: Relocation of Surveillance Frequency Requirements out of the Technical Specifications and into a licensee controlled document violates 10 CFR 50.36(c)(3). And closely related was Specific Issue 3: The Topical Report SE for NEI 04-10 was not reviewed by OGC.
With respect to compliance with 50.36(c)(3), the independent reviewer noted that one of the DPO panel members was an attorney with OGC who provided a clear and logical analysis articulating why relocation of surveillance frequencies to a licensee controlled program did not violate 10 CFR 50.36. This panel member noted that there was nothing in the regulation that would legally compel the inclusion of surveillance frequencies in the technical specifications. The DPO Panel member also provided specific information that OGC had reviewed and provided an NLO on the Topical Report SE for NEI 04-10.
Based on the above, the independent review determined that approval of RITSTF Initiative 5b did not violate any requirements associated with 10 CFR 50.36 and had been properly reviewed by OGC.
Finding 4: RITSTF Initiative 5b did not violate 50.36 and an appropriate legal review by OGC had been completed prior to its issuance.
Specific Issue 2: The EEEB staff noted that the original SE prepared by NRR/APLA staff (lead review group) for approval of TR NEI 04-10 methodology also did not provide adequate regulatory and technical bases to conclude that all deterministic criteria are met... The SE, in general, is written based on risk-based principles rather than risk-informed principles that complement the deterministic process. And closely related was Specific Issue 5: NRC staff acceptance of SRs is based upon guidance documents such as RG 1.9, 1.118, and 1.129. These documents have not been adequately addressed.
The DPO panel members differed in terms of their assessment regarding the adequacy of the safety evaluation performed in support of NEI 04-10. Two of the panel members stated that NEI 04-10 did not provide explicit criteria to guide licensee personnel performing qualitative reviews to revise surveillance test frequencies regarding how to consider areas like defense-in-depth, safety margin, and how to complete this review when the revised test frequency could be at conflict with a NRC endorsed industry code or standard. In contrast one of the other panel members highlighted information from Regulatory Guide 1.174, Revision 3 and the considerations that should be applied when reviewing how a licensing change could impact items like defense-in-depth. In addition, this DPO Panel member noted that while a test frequency for a component in a code could change, the majority of a code or standard would still be met. In addition, this member noted that defense in depth would not be impacted as only the test frequency for the safety system and not its performance or method of testing would be impacted.
Similarly, the panel member noted that while a licensee may establish a surveillance
7 Enclosure frequency under a surveillance frequency control program that could differ from the frequency specified in a regulatory guide, that all other elements of the regulatory guide to assess system performance would remain in effect. In addition, in another section of the DPO Panel report a member expressed concern regarding the need to develop inspection guidance and to train inspectors on how to review licensee assessments that are used to support surveillance test frequency extensions.
The independent reviewer looked at the issues raised by the DPO Panel members and noted that the safety evaluation had been prepared prior to issuance of Regulatory Guide 1.174 Revision 3, which provided enhanced clarity and guidance regarding how to conduct reviews that may include both deterministic and risk information.
As noted above, the independent reviewer did not have a generic concern associated with the overall intent of RITSTF Initiative 5b to allow licensees flexibility to adjust surveillance test frequencies under appropriate control, however, the reviewer agreed with the DPO Panel members that inspection guidance needed to be improved in this area. Attachment A, Risk Management Technical Specifications Initiative 5b Surveillance Frequency Control Program (SFCP), to NRC Inspection Procedure 71111.22, Surveillance Testing, directs inspectors to review whether the licensee has properly followed NEI 04-10 when making a change to a surveillance test frequency, but does not provide specific criteria for the inspector when making these assessments. As licensees implement RITSTF Initiative 5b, a new type of licensee performance deficiency is being introduced that would involve misapplication of NEI 04-10 to improperly extend a surveillance test frequency. Better guidance is needed so the inspectors can evaluate these types of inspection findings and issues. There is no additional recommendation in this area since Recommendation 4 above should address this concern.
Specific Issue 4: Licensees are extending surveillance frequencies through 50.59 evaluations and/or screenings.
The independent reviewer noted that this issue is closely related to a contested violation that is currently under review and will not comment on this question within the scope of this DPO Panel review. The reviewer would note that improved inspection guidance and clarity as discussed above can help minimize the potential for future contested violations associated with implementation of RISTF Initiative 5b.
Concern 3: Event Reporting Guidelines for a Loss of Offsite Power (LOOP). By interpreting 10 CFR 50.72/50.73 to apply only to safety-related structures, systems, and components, NUREG-1022, Revision 3 inappropriately excludes the offsite power system from reportability requirements that is essential for assessing the continued availability of the preferred source of power. The under-reporting of LOOP causes non-conservative plant-specific risk assessments as well as Reactor Oversight Process Significance Determination Process evaluations because of changes in initiating event frequencies.
8 Enclosure The submitters suggested remedy for this concern was to revise NUREG 1022 to require the reporting of all LOOPs.
Findings and Recommendations The independent reviewer examined the views expressed by each DPO Panel member regarding Concern 3 as documented in their report. The independent reviewer also reviewed NUREG 1022, Revisions 2 and 3, Regulatory Issue Summary 2001-14, Position on Reportability Requirements for Reactor Core Isolation Cooling System Failure, and Non-concurrence (NCP)-2012-008, which dispositioned a similar non-concurrence in 2012 before the change was made to NUREG 1022 to remove the requirement to report losses of off-site power under the reporting criteria specified in 10 CFR 50.72(b)(3)(v) for any event or condition that could have prevented the fulfillment of a safety function. The DPO panel members were unable to reach a consensus on this issue and views ranged from disagreement with the DPO submitter, to agreement with the DPO submitter, and also some DPO Panel members, who both agreed and disagreed with the DPO submitter, regarding the reporting of all LOOP events under 50.72(b)(3)(v) that were not reportable for some other reason. A majority of the DPO panel members agreed on the important role that off-site power systems play in nuclear plant safety and indicated that the agency should have access to good information and data regarding off-site power system problems to inform agency decisions.
The independent reviewer examined the basis for removing the reportability of off-site power system failures under 50.72 (b)(3)(v), as documented in the response to NCP-2012-008 and found that the agency provided a compelling basis for removal of this reporting requirement, including consistency with the intent and basis provided in the initial rule, and Regulatory Issue Summary 2001-14. Specifically, these documents clarified that reporting under this section of 50.72 (and similarly under 50.73(a)(2)(v))
was only required for system failures that would prevent the ability of the system to perform a credited accident mitigation function as described in the UFSAR. The independent reviewer did not identify any information, in either the original DPO or the DPO panel report that would have refuted this conclusion. Instead, portions of these documents that addressed this issue tended to focus on the importance of off-site power and the need to have reliable data regarding its performance to support agency decisions.
The independent reviewer determined that while the DPO submitter and DPO panel members provided a number of reasons why having better information regarding the performance of off-site power is important, they did not provide any compelling basis or reason to conclude that the prior determination regarding what the rule (i.e. 50.72 and 50.73) actually required was incorrect. As a result, the independent reviewer found that the agency decision to remove the reporting of off-site system failures as described in NUREG 1022, Revision 3, was correct, consistent with the stated intent of the rule, and dis-agreed with the DPO submitter.
9 Enclosure The independent reviewer also noted that a complete loss of off-site power would likely be reportable under a number of other reporting requirements and so the agency would have good information regarding complete losses of off-site power. Some of the other plant conditions accompanying a complete loss of off-site power, that could meet the criteria for reporting under 50.72 and/or 50.73, could include: plant events and transients, emergency action declarations, completion of a shutdown required by technical specifications, and/or reporting of an unplanned engineered safeguards system actuation.
The DPO Panel also reviewed and discussed reporting of partial losses of off-site power and mistakenly believed that they were required to be reported per NUREG 1022, Revision 2. In fact, the reporting requirement 50.72(b)(3)(v), only requires the reporting of any event or condition that could have prevented the fulfillment of a safety function.
Since off-site power systems typically include multiple, redundant and 100% capable subsystems, the independent reviewer does not believe that the partial loss or the loss of a single train of off-site power were required to be reported under prior versions of NUREG 1022. This understanding is consistent with the concern stated in NCP-2012-008 that is clearly associated with a total loss of off-site power to the safety buses. A partial loss of off-site power is never mentioned in the NCP.
Finding 5: Disagree with DPO submitter; no change or revision to NUREG 1022, Revision 3 to require the reporting of loss of off-site power events as an event or condition that could have prevented the fulfillment of a safety function under 50.72(b)(3)(v) is necessary.
Recommendation 6: The DPO submitter, and some members of the DPO panel, provided information regarding the importance of having good data for partial losses of off-site power. As part of the NRC Transformation effort, the use of big data was discussed as a new or emerging technology that can help improve future agency decision making. Recommend that the Division of Engineering remain engaged in future agency efforts in this area and champion efforts where better data (such as partial losses of off-site power) can be leveraged to help inform future decisions.
Document 5: DPO Decision
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 July 12, 2018 MEMORANDUM TO:
Roy K. Mathew, Senior Electrical Engineer Electrical Engineering Operating Reactors Branch Division of Engineering Office of Nuclear Reactor Regulation Jacob Zimmerman, Chief Enrichment and Conversion Branch Division of Fuel Cycle Safety, Safeguards and Environmental Review Office of Nuclear Material Safety and Safeguards Tania Martinez-Navedo, Chief Electrical Engineering New Reactors and License Renewal Branch Division of Engineering Office of Nuclear Reactor Regulation Gurcharan S. Matharu, Senior Electrical Engineer Electrical Engineering Operating Reactors Branch Division of Engineering Office of Nuclear Reactor Regulation Sheila Ray, Senior Electrical Engineer Electrical Engineering New Reactors and License Renewal Branch Division of Engineering Office of Nuclear Reactor Regulation FROM:
Brian E. Holian, Acting Director /RA/
Office of Nuclear Reactor Regulation
SUBJECT:
DIFFERING PROFESSIONAL OPINION INVOLVING APPROVING LICENSE AMENDMENTS BASED ON USING THE RISK MANAGEMENT TECHNICAL SPECIFICATIONS (RMTS) 4b and 5b RISK INITIATIVES, AND CHANGING THE REPORTING GUIDELINES FOR LOSS OF OFFSITE POWER (LOOP) - (DPO 2016-003)
On October 12, 2016, in accordance with Management Directive 10.159, The NRC Differing Professional Opinions Program, you submitted a differing professional opinion (DPO) involving CONTACT: Trent L. Wertz, NRR 301-415-1568
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concerns related to approving the license amendments based on using the Risk Management Technical Specification (RMTS) 4b and 5b risk initiatives and changing the event reporting guidelines for loss-of-offsite power (LOOP). Specifically, your DPO raises concerns with approving the Vogtle LAR using TSTF-505 and TR NEI 06-09 methodologies. More specifically, the safety concern is allowing a licensee to change the Completion Times for LCOs for SSCs, such as AC and DC electric power systems, based on risk without clearly understanding and evaluating the consequences to the plants accident mitigation safety systems. The purpose of this memorandum is to respond to your DPO.
Additionally, I note for the record that NRR responded to similar concerns in a separate, publicly available, DPO associated with the one-time extension of a Palo Verde emergency diesel generator allowable outage time (ML17202G468). Actions have been taken to improve guidance, safety evaluation documentation, and internal procedures as part of NRRs focus on enhancing its ability to use risk information in making regulatory safety decisions.
On November 8, 2016, a DPO Ad Hoc Review Panel (the Panel) was established and tasked to meet with you, review your DPO submittal, and issue a DPO report, including conclusions and recommendations regarding the disposition of the issues presented in your DPO. On May 11, 2018, after reviewing the applicable documents, completing internal interviews of relevant individuals and completing their deliberations, the Panel issued their report to me. Because the DPO Panel was unable to come to a consensus, I tasked the Acting Deputy Director for Engineering, NRR, to do an independent review of the issue. He sent his report to me on June 28, 2018.
As part of my review of the issues, we met on July 2, 2018, to discuss the Panels report, the independent review report, and to get your insights and comments. I reviewed your DPO submittal, the Panels report, the independent review report, and considered your comments to me.
Statement of Concern Based on a review of the DPO package and interviews with the submitters, the following concerns were identified by the Panel:
- 1. RITSTF Initiative 4b. Safety Evaluations associated with RITSTF Initiative 4b are being prepared with a primary focus on probabilistic risk (risk-based principles established by TSTF and Topical Report rather than risk-informed principles that complement the deterministic principles). Consequently, the technical bases established in relevant NRC requirements, including plant-specific design and licensing basis, are not specifically addressed to justify approval of license amendments referencing RITSTF 4b, and therefore reasonable assurance of adequate protection of the public health and safety is not provided.
- 2. RITSTF Initiative 5b. Safety Evaluations associated with RITSTF Initiative 5b are being prepared with a primary focus on probabilistic risk (risk-based principles established by TSTF and Topical Report rather than risk-informed principles that complement the deterministic principles). Consequently, the technical bases established in relevant NRC requirements, including plant-specific design and licensing basis, are not specifically addressed to justify approval of license amendments referencing RITSTF 5b, and therefore reasonable assurance of adequate protection of the public health and safety is not provided.
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- 3. Event Reporting Guidelines for Loss of Offsite Power (LOOP). By interpreting 10 CFR 50.72/50.73 to apply only to safety-related structures, systems, and components, NUREG-1022 Rev 3, inappropriately excludes the offsite power system from reportability requirements that is essential for assessing the continued availability of the preferred source of power. The under-reporting of LOOP causes non-conservative plant-specific risk assessments, as well as Reactor Oversight Process Significance Determination Process evaluations because of changes in initiating event frequencies.
The above overarching statements of concern were developed based on a litany of specific issues the panel identified from the submitters input. Subsequently, in conjunction with the submitters, the concerns were written at a level to address the submitters underlying issues.
The submitters suggested remedies were:
- 1. Withdraw the approval of both risk initiative 4b and 5b.
- 3. Revise NUREG 1022 to require the reporting of all LOOPs.
Panel Findings and Recommendations The Panel was unable to come to a consensus on the findings and recommendations. The Panel report lists the different Panel members findings and recommendations.
Independent Review This DPO raised several complex issues, with each having a long background. Since the Panel was unable to come to a consensus, I consulted with the Office of Enforcement (OE) and asked the Acting Deputy Director for Engineering, NRR, (a previous inspector and well-respected engineering manager) to do an independent review of the DPO and the Panel report.
That review is attached. That report included the following findings and recommendations:
Concern 1 Finding 1: Given that RISTF Initiative 4b is currently suspended, has been extensively revised, and is out for comment, the submitters suggested remedies for Concern 1 have been addressed. The need to issue a separate RIS highlighting the issues in the DPO related to Concern 1 is unnecessary since the normal agency actions associated with comment resolution will establish a basis for disposition of comments received.
Finding 2: The independent reviewer does not agree with the assessment provided by the Panel that the approval of RISTF Initiative 4b was risk-based and determined that the approval was consistent with a risk-informed approach. Specifically, while not mentioned in the Panel report, the RISTF Initiative 4b limits technical specification completion time extensions to a maximum duration of 30 days, even though many underlying risk assessments would likely support much longer durations. A risk-based, as opposed to a risk-informed approach, would not limit the approval of completion time extensions. Notwithstanding any differences in opinion in this area, Recommendations 1-3 describe specific actions that should help alleviate future concerns.
Recommendation 1: The Panel members appeared aligned on the need to ensure that qualified staff in all relevant technical areas, and not just risk experts, are fully involved with risk-
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informed licensing review efforts. In the Risk Informed Decision Making (RIDM) plan (Task 1),
NRR has identified the benefits associated with expanding the use of multi-disciplinary teams for review of risk-informed licensing actions. No further action is needed in this area other than for NRR to continue to effectively implement RIDM Task 1.
Recommendation 2: Two Panel members expressed concerns related to some of the guidance documents associated with risk-informed licensing actions. The agency has already taken action to improve the quality and completeness of certain documents in this area, such as the recent issuance of Revision 3 to Regulatory Guide 1.174, and a recent memo from the Director of NRR (Acting) in June 2018, informing staff how to properly integrate multiple review standards and guidance documents in support of regulatory decisions. NRR should continue to review and update program documents and guidance associated with risk-informed licensing activities, as described in their Risk Informed Decision Making Action Plan, and as further directed by the Risk Informed Steering Committee. Since these are ongoing and evolving efforts to improve the quality of guidance supporting risk-informed decision making, no further actions beyond those specified by RIDM and RISC are necessary.
Recommendation 3: OE has an on-going action to review the differing professional opinion and non-concurrence programs. Suggest that the observation related to "out of scope" comments by DPO Panel members and whether it is appropriate to initiate a DPO before a final agency action has been issued to be considered as part of this review effort.
Recommendation 4: The need to establish guidance and to train inspectors on risk-informed licensing actions, like RISTF Initiative 4b, is necessary to ensure that inspectors have the proper tools to ensure consistent and reliable oversight and enforcement in this area. Recommend that the Division of Inspection and Regional Support and the Division of Risk Analysis review and update, as necessary, inspection guidance for oversight of licensee implementation of risk-informed licensing activities and update as necessary. As part of this effort, the Division of Inspection and Regional Support should consider and develop appropriate training for inspectors.
Recommendation 5: One Panel member provided comments related to the adequacy of risk models to assess plant conditions associated with postulated DC voltage failure modes. The postulated failure mechanisms, discussed in the Panel report, had the potential to result in certain types of initiating events and/or safety-system malfunctions. The panel member referenced selected scenarios using a deterministic fault analysis approach but did not provide any information, other than a general statement, that existing risk models are unable to capture some of these failure modes and effects. The information in the Panel report did not discuss how operating experience is often factored into risk modelling assumptions and did not attempt to capture or address how a risk-informed decision to increase a technical specification allowed outage time could actually help maintain plant safety margins by not putting the plant through the risk associated with a mode transition with a degraded or out-of-service safety system.
Based on a review of the information discussed in the report, the independent reviewer did not identify the need to revise any current risk-informed licensing activities, but recommends that the Division of Risk Assessment and the Division of Engineering meet to understand the comments in this section of the Panel report and to assess whether any action is needed to update guidance related to use of NRC risk models to support decision making.
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Concern 2 Finding 1: Retain and do not retract RITSTF Initiative 5b.
Finding 2: RITSTF Initiative 5b did not violate 50.36, and an appropriate legal review by OGC had been completed prior to its issuance.
Concern 3 Finding 1: Disagree with DPO submitters; no change or revision to NUREG 1022, Revision 3 to require the reporting of loss of off-site power events as an event or condition that could have prevented the fulfillment of a safety function under 50.72(b)(3)(v) is necessary.
Recommendation 1: The DPO submitters, and some members of the DPO panel, provided information regarding the importance of having good data for partial losses of off-site power. As part of the NRC Transformation effort, the use of big data was discussed as a new or emerging technology that can help improve future agency decision making. Recommend that the Division of Engineering remain engaged in future agency efforts in this area and champion efforts where better data (such as partial losses of off-site power) can be leveraged to help inform future decisions.
Director Decision This has been a difficult DPO to resolve, as evidenced by the previous non-concurrence (NCP),
the length of time for the Panel to finish its report, and the varied views among the Panel members. This DPO demonstrates the need for disagreements on technical or process issues to be discussed and communicated (and hopefully resolved) early in the process.
First, I highlight two paragraphs from the Panel report which speak positively to the DPO submitters involvement and the positive changes made as a result:
- 1. Following disposition of the NCP and, in part, based on some of the issues raised by the non-concurring staff, the NRC staff developed a significant number of additional questions regarding this LAR. Exploration of these issues resulted in the licensee removing some of the actions originally included, providing additional justification for selected technical specification (TS) actions, and introducing additional constraints to implement the risk-informed TS completion time (RICT) program.
- 2. Ultimately, the positive aspect of this experience was that the level of collaboration between the engineering staff and the PRA practitioners to work through the issues associated with risk-informed tech specs has resulted in greater shared understandings that will significantly help as we review other risk-informed initiatives in the future.
I note that because of your submittal, NRR suspended the TSTF traveler until generic improvements were made. During my discussion with you, I recognized some frustration that staff may feel constrained to not engaging until when the processes (NCP, DPO) allow it, which is, by design, late in the process. Additionally, Im aware of the stress this places on the submitters, as some may experience, or feel, pressure from the organization from resulting delays. OE is currently reviewing both processes. During my recent interviews with the OE staff considering lessons learned, I highlighted this DPO for their study to evaluate allowing interjection earlier in the process.
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I also note that at least one member of the Panel raised concern over the Panel itself expanding the DPO response to include issues beyond the original DPO. OE, as part of its program evaluation, should consider additional guidance as appropriate.
Second, due to the length of the Panel report, I highlight below several statements related to the various concerns which succinctly capture important aspects and which resonate with me.
Regarding the Risk Managed Technical Specification Guidelines:
[T]he ACRS commented that: The major benefit of this initiative is that it provides flexibility to the licensees to operate the plants according to the risk associated with specific plant configurations. It heightens the operators awareness of the existing risk profile of the plant, and avoids unnecessary plant shutdowns.
However, [t]he current Technical Specification restriction on a very narrow DC bus outage time is delicately engineered to protect against undesirable safety challenges.
Regarding the fact that regional inspections are tasked with verifying proper program implementation:
[D]elegating the review of another highly complex technical and regulatory program to an ever shrinking regional inspection staff challenges the boundaries of our abilities to be able to effectively regulate.
[C]omprehensive inspector training and guidance in this area appears to be warranted to ensure adequate oversight of this important area in the future.
Regarding the question of relocating surveillance requirements:
[T]he staff understood at the time they prepared their licensing documents that licensees adopting the SFCP would be allowed to alter their surveillance frequencies in ways that would differ from the deterministic surveillance frequencies. The SFCP program, as written, appears to be a safe conservative way of determining the appropriate surveillance frequency for individual SSCs.
[I]t is legitimate for the Commission to determine that determining surveillance frequencies using plant specific PRA calculations is a sufficient method of ensuring safety.
Regarding the discussion on defense-in-depth:
[T]he Commission explicitly rejected the idea that the probabilistic and deterministic reviews must be seen as two separate distinct reviews as early as 1995 in its Policy Statement on the use of PRA. (One commentator stated that the use of probabilistic analysis is simply an extension of deterministic analysis. They are not separate and distinctive concepts. The Commission agrees with this concept.)
Regarding reporting on partial loss of offsite power (LOOP):
It is undesirable to find out that the offsite power designed to be the primary source is unavailable when there is a valid demand.
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However, [n]either the language found in 10 CFR 50.72 nor the language found in 10 CFR 50.73 state[s] [sic] that all LOOPs are reportable.
After careful consideration of all the inputs, I agree with the recommendations from the independent review and have tasked the appropriate staff in NRR to carry out the recommendations and assigned appropriate dates for the completion of the recommendations.
For Concern 1, Recommendation 4, DIRS is assigned as the lead to review and update, as necessary, inspection guidance for oversight of licensee implementation of risk-informed licensing activities and update as necessary. As part of this effort, DIRS should consider and develop appropriate training for inspectors. Due date: June 28, 2019 For Concern 1, Recommendation 5, DRA and DE are assigned to meet to understand the comments in this section of the Panel report and to assess whether any action is needed to update guidance related to use of NRC risk models to support decision making. An outcome of the updated guidance is to ensure that the technical basis is to be included in the safety evaluation. Due date is August 31, 2018.
For Concern 3, Recommendation 1, DE is assigned to remain engaged in future agency efforts in this area and champion efforts where better data (such as partial losses of off-site power) can be leveraged to help inform future decisions. Additionally, I add a task to Concern 3 for DIRS to interface with industry and the Institute for Nuclear Power operations regarding whether they more closely track partial LOOPs.
A summary of the DPO will be included in the Weekly Information Report (when the case is closed) to advise interested employees of the outcome.
Thank you for raising your DPO and for your active participation in the DPO process. An open and thorough exploration of how we carry out our regulatory processes is essential to keeping these programs effective. Your willingness to raise concerns with your colleagues and managers and ensure that your concerns are heard and understood is admirable and vital to ensuring a healthy safety culture within the Agency.
Enclosures:
1: DPO Panel report, dated March 19, 2018 2: Independent Review, dated June 28, 2018 cc: R. Lorson, RI L. Dudes, NRR M. Evans, NRR M. Franovich, NRR M. Miller, NRR E. Benner, NRR J. Giitter, NRR A. Boland, OE G. Figueroa-Toledo, OE M. Johnson, OEDO
Pkg: ML16300A253; Memo: ML18193A468; : ML18193B040; Enclosure 2: ML18179A480 OFFICE NRR NAME BHolian DATE 7/12/18
Document 6: DPO Appeal Submittal
Document 7: Statement of Views on DPO Appeal Submittal
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 September 24, 2018 MEMORANDUM TO:
Margaret M. Doane Executive Director for Operations FROM:
Ho K. Nieh, Director /RA/
Office of Nuclear Reactor Regulation
SUBJECT:
STATEMENT OF VIEWS REGARDING APPEAL OF DIFFERING PROFESSIONAL OPINION CONCERNING DPO-2016-003 The purpose of this memorandum is to provide you my statement of views on the appeal of differing professional opinion (DPO), DPO-2016-003,1 concerning the U.S. Nuclear Regulatory Commissions (NRC) approval of license amendment requests using the Risk-Managed Technical Specifications (RMTS) 4b and 5b risk initiatives for electrical power systems and the changing of event reporting guidelines for loss-of-offsite power (LOOP) events.
On August 6, 2018, one of the DPO submitters sent an appeal to you regarding the DPO response decision because the DPO response did not provide a coherent Agency Decision with sufficient technical and regulatory bases to resolve the concerns raised in DPO-2016-003 and the final DPO response provided was not in accordance with the guidance provided in MD 10.159. I have reviewed the associated documents for this DPO and have had several discussions with the appealer to deepen my understanding of the issues raised over this risk-informed regulatory activity. My views are as follows.
Risk-informed decision-making requires us to strike an appropriate balance among risk insights, deterministic considerations, engineering judgment, defense-in-depth and safety margins. The issues raised in the DPO involve technical and regulatory complexities that remind us that risk-informed decision-making is often not a simple black-and-white formula. This point is further highlighted by the lack of consensus among the DPO Panel members.
The risk-informed activity disputed by the DPO is consistent with the Commissions 1995 policy statement on the use of probabilistic risk assessment (PRA) information. In particular, the NRC is enabling the use of PRA information to complement its traditional deterministic approach and defense-in-depth philosophy. This risk-informed activity is also a good example of how PRA information can be used to reduce unnecessary conservatisms in current requirements, which is an objective called out in the Commissions 1995 PRA policy statement.
CONTACT: Trent L. Wertz, NRR 301-415-1568 1 On May 11, 2018, the DPO Ad Hoc Review Panel (the Panel) issued its report to the acting NRR Office Director (ML1819B040).
Because the Panel was unable to reach consensus, the acting NRR Office Director tasked the acting NRR Deputy Director for Engineering to do an independent review of the Panel report and to provide recommendations for disposition of the issues. This independent review report was issued on June 28, 2018 (ML18179A480). On July 12, 2018, the acting NRR Office Director provided a response decision to the DPO submitters (ML18193A468).
This DPO reinforces that different perspectives add value to the regulatory process and that it is important for the NRC to seek out all perspectives early in the decision-making process. As an example in this case, the DPO submitters focused further attention to the safety significance of certain electrical power systems. As a result, the implementation of this risk-informed activity is being modified to include so-called deterministic backstops to limit the duration of times when such equipment can be out of service.
Regarding the implementation of the DPO process described in MD 10.159, the appealer did not consider the independent review of the Panel report to be part of the MD 10.159 process.
While an independent review is not explicitly defined in MD 10.159, the management directive does note that in rare and exceptional cases, the OD or the RA may believe an addendum to the DPO Panel report is necessary. Given the circumstances of this case, I consider that the acting NRR ODs request for an independent review was appropriate and consistent with the most likely intent of the before-quoted section of the management directive.
I also note that significant improvements to NRR processes and collaborative work methods have been implemented as a result of this DPO and a previous DPO related to a one-time extension of a Palo Verde emergency diesel generator allowable outage time (ML17202G468).
Specifically, actions have been taken to improve guidance, safety evaluation documentation and internal procedures as part of NRRs focus on enhancing its ability to use risk information in making regulatory safety decisions.
Overall, it is my view that the DPO response and recommendations, including the input from the independent review, are sufficiently coherent to address the underlying technical and regulatory concerns raised in the DPO.
ML18243A166 OFFICE NRR NAME HNieh DATE 9/24/18
Document 8: DPO Appeal Decision
MEMORANDUM TO:
Roy K. Mathew Retired FROM:
Daniel H. Dorman Executive Director for Operations
SUBJECT:
DIFFERING PROFESSIONAL OPINION APPEAL INVOLVING APPROVING LICENSE AMENDMENTS BASED ON USING THE RISK MANAGEMENT TECHNICAL SPECIFICATIONS 4b and 5b RISK INITIATIVES, AND CHANGING THE REPORTING GUIDELINES FOR LOSS OF OFFSITE POWER -
(DPO 2016-003)
The purpose of this memorandum is to inform you of my considerations and conclusions regarding the Differing Professional Opinion (DPO) appeal you submitted on August 6, 2018. In your appeal, you raised concerns related to approving the license amendments based on applying the Risk Management Technical Specification 4b and 5b risk initiatives and changing the event reporting guidelines for loss of offsite power (LOOP). The concerns raised in the appeal pertained to the Vogtle license amendment request using Technical Specification Task Force Traveler (TTSTF-505), Provide Risk-Informed Extended Completion Times-RIT Initiative 4B and Topical Report (TR) NEI 06-09, Risk-Informed Technical Specifications Initiative 4B, Risk-Managed Technical Specifications (RMTS) Guidelines, methodologies and allowing a licensee to change the completion times for limiting conditions for operation (LCOs), such as LCOs for AC and DC electric power systems, based on risk without clearly understanding and evaluating the consequences to the plants accident mitigation safety systems.
After careful consideration of your appeal, I conclude the underlying technical and regulatory concerns you raised in the appeal have been adequately and appropriately addressed.
Therefore, no further action is needed.
Additionally, I recognize and appreciate the unique process issues encountered during this DPO process and have directed the Office of Enforcement to review and update DPO program guidance. Specifically, I have instructed that DPO guidance be updated to include addressing scenarios in which a DPO panel cannot reach consensus as well as instances wherein guidance documents referenced in a DPO case are under revision.
Your DPO appeal raised three specific issues. A paraphrased summary of issues and my conclusions for each are as follows.
CONTACT: Hector Rodriguez, OEDO 301-415-6004 January 24, 2024 Signed by Dorman, Dan on 01/24/24
R. Mathew 2
Issue 1: Risk-informed extended completion times (RITSTF) Initiative 4b safety evaluations are being performed in a risk-based manner, rather than a risk-informed manner.
Answer 1: The underlying technical and regulatory concerns of this issue have been appropriately and sufficiently addressed by guidance updates and the actions Nuclear Reactor Regulation (NRR) took in response to the initial DPO. In addition, since you filed your appeal, the Commission provided further relevant direction to the NRC staff in the context of the NuScale Design Certification Application. Specifically, in a Staff Requirements Memorandum dated July 2, 2019, on SECY-19-0036 (ML19183A408), the Commission stated that in any licensing review, the staff should apply risk-informed principles when strict, prescriptive application of deterministic criteria is unnecessary to provide for reasonable assurance of adequate protection of public health and safety. The Commission further noted that this approach is consistent with the Commissions safety goal policy and associated core damage and large release frequency goals and existing Commission direction on the use of risk-informed decision-making. Based on my review of your concerns and the actions taken by NRR, I conclude that the existing guidance for review of licensing actions associated with RITSTF Initiative 4b provide a technically sound approach to demonstrate that authorized completion time extensions are of sufficiently low risk that the prescriptive application of additional deterministic review is not necessary to demonstrate reasonable assurance of adequate protection of public health and safety and that this conclusion is consistent with the Commission's direction and the considerations set forth in Regulatory Guide 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decision on Plant-Specific Changes to the Licensing Basis.
Issue 2: RITSTF Initiative 5b is a risk-based, rather than a risk-informed, program.
Answer 2: For the reasons set forth above, I also conclude that the review guidance for RITSTF Initiative 5b is also a sound approach to demonstrate that authorized changes to surveillance intervals are of sufficiently low risk that the prescriptive application of additional deterministic review is not necessary to demonstrate reasonable assurance of adequate protection of public health and safety and that this conclusion is consistent with the Commission's direction and the considerations set forth in Regulatory Guide 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decision on Plant-Specific Changes to the Licensing Basis.
Issue 3: NUREG-1022, Revision 3, Event Report Guidelines 10 CFR 50.72 (b)(3(xiii),
inappropriately excludes reporting of certain LOOP events.
Answer 3: In your appeal, your state that Revision 3 of NUREG-1022 should not have removed the guidance to report only certain LOOPs (i.e., LOOPs that cause initiation of engineered safety features systems). You assert that the initial DPO review and decision included flaws.
Understanding that your concern is with a complete loss of offsite power, rather than a partial loss of offsite power, and further understanding that you have a concern that LOOP events will be underreported creating numerous trickle-down effects, I support NRRs decision to maintain Revision 3 of NUREG-1022. The independent review report noted that a complete loss of off-site power would likely be reportable under a number of other reporting requirements and so the agency would have good information regarding complete losses of off-site power. As part of my review, I analyzed LOOP events that were reported prior to NUREG-1022, Revision 3 from 1996-2013. All LOOP events that were reported during that time frame were reported under other reporting requirements. I am confident that the current guidance under NUREG-1022, Revision 3 provides adequate information for the agency and supports all needed regulatory decisions.
R. Mathew 3
Thank you for taking the time to raise your concerns and for the detailed information you provided in support of the DPO and subsequent appeal. Your willingness to raise concerns using the DPO process directly supports the NRCs organizational values Openness and Commitment.
In accordance with MD 10.159, a summary of this appeal decision will be included in the Weekly Information Report and posted on the NRCs public web site to advise interested employees and members of the public.
R. Mathew 4
SUBJECT:
DIFFERING PROFESSIONAL OPINION APPEAL INVOLVING APPROVING LICENSE AMENDMENTS BASED ON USING THE RISK MANAGEMENT TEHNICAL SPECIFICATIONS 4b AND 5b RISK INITIATIVES, AND CHANGING THE REPORTING GUIDELINES FOR LOSS OF OFFSITE POWER - (DPO-2016-003), DATED: JANUARY 24, 2024 cc: D. Dorman, OEDO S. Morris, OEDO R. Furstenau, OEDO H. Rodriguez, OEDO A. Veil, NRR J. Hoellman, NRR D. Pelton, OE D. Solorio, OE G. Figueroa Toledo, OE ADAMS Accession No.: ML24022A258 OFFICE OEDO/ETA OEDO/EDO NAME HRodriguez DDorman DATE 01/ 23 /24 01/24/24