DOMINION NUCLEAR CONNECTICUT, INC. (DNC) MILLSTONE POWER STATION UNITS 2 AND 3 RESPONSE TO AN APPARENT VIOLATION IN NRC SPECIAL INSPECTION REPORT 05000336/2014011AND 05000423/2014011; EA-14-12
As stated in the summary section of NRC Special Inspection Report,05000336/2014011 and 05000423/2014011, during an NRC team inspection conducted between June 2 and July 15, 2014, "the NRC identified a Severity Level Ill Apparent Violation (A V) of Title 10 of the Code of Federal Regulations (10 CFR) 50.59, "Changes, Tests, andSo the NRC inspectors should have been in many outage and design change meetings and seen their documents. What didn't the NRC on their own see the Millstone design change on the transmission system and the circuit change, this was big, and entailed an increase of risk. Is the bifurcation of nuclear safety responsibilities between a on site transmission authority and near site transmission authorities a unreviewed safety issue.
Experiments," for Dominion's failure to complete a 10 CFR 50.59 evaluation and obtain a license amendment for a change made to the facility as described in the Updated Final Safety Analysis Report (UFSAR). Specifically, ... aNRC OIG Inspection: On June 7, 2006, SCE notified NRC of its intent and timeline to replace Units 2 and 3 steam generators under 10 CFR 50.59. The SCE briefing document indicated there would be no associated power uprate and that associated technical specification1changes were scheduled to be identified in 2007.
special protection system (SPS), known as severe line outage detection (SLOD), [was removed] which was described in the UFSAR. Dominion concluded in the 10 CFR 50.59 screening that a full 10 CFR 50.59 evaluation wasNRC OIG: An attachment to the inspection report listed, by number, the 15 screens, 8 evaluations, and 12 plant modifications the inspectors reviewed. Included within the list of eight evaluations reviewed was number 800071702, which OIG learned was the number SONGS assigned to its 10 CFR 50.59 screening and evaluation pertaining to its Unit 2 replacement steam generators. 1
not required and, therefore, prior NRC approval was not needed to implement this change. The team concluded that prior NRC approval likely was required because the removal of SLOD may have resulted in more than a minimal increase in the likelihood of occurrence of a malfunction of the offsite power system as described in the UFSAR."Well, there is lots of Millstone's management levels who had to sign off on this?
Response to the Apparent Violation
Dominion Nuclear Connecticut, Inc. (DNC) submits the following information in response to NRC Special Inspection Report 05000336/2014011 and 05000423/2014011 which was issued by the NRC on August 28, 2014. DNC chooses to respond in writing to AV 05000336/2014011 and 05000423/2014011 and declined the opportunity for a Pre-decisional Enforcement Conference (PEC) and the opportunity to request Alternative Dispute Resolution (ADR) during a phone call on September 8, 2014, between Lori Armstrong of DNC and Raymond McKinley, Chief, Division of Reactor Projects Branch 5, NRC Region I.
1) The reason for the Apparent Violation (AV) or, if contested, the basis for disputing the violation DNC does not contest the apparent violation.
NRC's review and approval of the change to the Millstone Power Station Unit 2 (MPS2) and 3 (MPS3) licensing basis for the removal of SLOD was not requested by DNC because
of an inadequately prepared 10 CFR 50.59 screen. In the 10 CFR 50.59 screen, Engineering personnel failed to consider that the removal of SLOD was an adverse changeSo why didn't Dominion send a notification to the the Plant NRC inspector of major work on our local transmission system potentially affecting safety, we find no increase in risk...please cover our backs with checking out our work???
Why does the licensee and NRC sounds more like enemies to each other, at a complete state of total war with each other relationship, instead of everyone covering each other's back(morally and ethically). Do it the right way and no taking shortcuts?
Honestly, I can't imagine the NRC not nosing around the site their own and finding the major work was going on in transmission system in the document and the list of potential and on going major work going on. Doesn't that say a lot they couldn't discover this on their own? How much else does the NRC miss with not being "intrusive".
According to the NRC OIG report on SONGs, the NRC is coming out with a major committee report on the agency's lessons learned on the SONGS SG debacle late this fall. I can't wait to see this guy?
relating to DNC's compliance with General Design Criteria (GDC) 17, and therefore did not conclude that a 10 CFR 50.59 evaluation was needed.NRC OIG:
The root cause evaluation for this AV identified the direct cause as a lack in proficiency and skill in performing 10 CFR 50.59 screens. The root cause for this AV was determined to be that continuing training was not adequate to maintain the proficiency and skills for consistent, accurate screens. Corrective actions were needed to address the screening deficiency identified in the apparent violation.
The complexities associated with the technical issue, multiple responsible entities involved, and understanding of the MPS2 and MPS3 licensing basis are also relevant to understanding the contributing factors for the AV. During review of this AV, it was determined that DNC's error of not performing a 10 CFR 50.59 evaluation occurred during the design development for the removal of SLOD by the transmission owner, Northeast Utilities (NU). During the design development, DNC did not recognize that NU's removal of SLOD resulted in a change in the method of compliance with GDC 17 that required DNC to perform a 10 CFR 50.59 evaluation. This matter is further addressed in the Additional Information provided below.
2) The corrective steps that have been taken and the results achieved
With removal of SLOD, and as discussed in the Additional Information provided below, the station no longer met the method for compliance with GDC 17 approved by the NRC at the time of original licensing of MPS3. As documented in NRC Special Inspection Report 05000336/2014011 and 05000423/2014011, DNC implemented a compensatory measure by issuing an Operations standing order for interim guidance on future offsite line outages and plant generation output. In March 2014, prior to the NRC Special Inspection, DNC had separately implemented improvements in the procedural guidance for performing 10 CFR 50.59 screenings.
These improvements were the result of DNC identified gaps in performance of 10 CFR 50.59 screenings. Improvements included a major rewrite and expansion of the guidance for completing 10 CFR 50.59 screens using a more user-
"According to the former NRR Director, if there were problems with the 50.59 process, it would have manifested itself in many more issues than just the steam generator issue."
friendly format. The procedure now includes more detailed guidance for responses to each section of the screen formNRC OIG: "In his opinion, the NEI 96-07 guidance is too vague, allows for too many judgment calls, and needs solidifying of definitions. From his experience, the licensee and NRC routinely get into disagreements because of interpretation of the guidance.
including direct references to NEI 96-07, Guidelines for 10 CFR 50.59 Implementation.
In August 2014, training was provided on an expedited basis to a select population (the majority) of 10 CFR 50.59 screeners. The training included discussion on the fundamentals of GDC compliance and the importance of identifying and reviewing the impacts of design changes upon the licensing basis, including the FSAR. Only personnel who have received the training are presently qualified to perform 10 CFR 50.59 screens.Why don't we need NRC national training on all licencing issues and qualification testing?
Design changes scheduled for implementation in the remainder of 2014 have been reviewed by Design Engineering to determine whether adequate licensing basis reviews were conducted as part of the 10 CFR 50.59 screenings. No 10 CFR 50.59 screens were identified which should have concluded a 10 CFR 50.59 evaluation was required.
3) The corrective steps that will be taken
To become qualified to perform 10 CFR 50.59 screens, future training will include a discussion of the fundamentals of GDC compliance and the importance of identifying and reviewing the impacts of design changes upon the licensing basis, including the FSAR.
A review of the 10 CFR 50.59 screens for FSAR changes processed in the past three years will be conducted by April 1, 2015 to determine whether adequate licensing basis reviews were conducted.So the instrumentation was getting unreliable and obsolete...just rip it out without telling the NRC.
DNC is evaluating options for addressing compliance with GDC 17. To complete this work, engineering analysis, including consideration of potential design modifications, is necessary. Upon completion, a License Amendment Request (LAR) will be submitted to the NRC requesting review and approval of a licensing basis change to the MPS2 and MPS3 FSAR that addresses the removal of SLOD. DNC will keep the senior resident inspector informed of the status and schedule for resolution.
4) The date when full compliance will be achieved
Full compliance was achieved when training was provided in August 2014. To ensure future continued compliance, the 10 CFR 50.59 training module will be updated to include a discussion of the fundamentals of GDC compliance and the importance of identifying and reviewing the impacts of design changes upon the licensing basis, including the FSAR.
The SLOD system was owned by the transmission system owner, NU. Removal of SLOD was a result of a major transmission line upgrade project to improve grid reliability by separating lines and towers leaving the MPS switchyard. This separation allowed NU to eliminate SLOD, which they no longer considered reliable or secure.
The upgrade, as it was presented, reduced risk to MPS and improved grid reliability to MPS.Why wasn't the NRC invited to a meeting?
Representatives of DNC and NU participated in multiple Nuclear Plant Interface Meetings (NPIMs) coordinated by ISO New England (the transmission system operator). These meetings, which began several years in advance of the actual physical modifications, included discussions of proposed changes to the transmission system.I bet you the overarching ideal was to yank this gear out of the system before it caused an inadvertent trip on fault.
The transmission upgrade project by NU involved rerouting the transmission lines from four lines on two towers to four lines on four separate towers. The removal of SLOD was presented in the aggregate as an improvement in grid reliability, conforming to present transmission system standards. According to the North American Electric Reliability Corporation standard on special protection systems (SPSs), SPSs such as SLOD carry with them unique risks including, risk of failure on demand and inadvertent activation, and risk of interacting with other SPSs in unintended ways. Thus, at the time, DNC,
ISO New England, and NU believed that separation of the towers/lines removed the vulnerability which SLOD was installed to mitigate and represented an improvement in grid reliability. Therefore, following tower line separation, SLOD was disabled and eventually removed. DNC recognizes that during the design development for the modified transmission circuits, there were opportunities to understand that the Millstone licensing basis was impacted by the removal of SLOD and that a 10 CFR 50.59What about worrying about the collapse of the Pennsylvania and New York grid on past documents?
evaluation would be required. DNC accepted the changes proposed and approved by NU, ISO New England, and the Northeast Power Coordinating Council without adequately considering the impact to the MPS licensing basis. The complexities associated with the specific technical issue, multiple responsible entities involved, and understanding of the licensing basis all played a part in the failure to recognize the impact of the change on the licensing basis.Of Interest:
The 10 CFR 50.59 screen failed to consider that the removal of SLOD was an adverse change relating to DNC's compliance with GDC 17, and therefore did not conclude that a 10 CFR 50.59 evaluation was needed. It was the belief that the tower and line separation project, including SLOD removal, was undertaken by NU for the sole reason to enhance grid stability and reliability, providing a more stable source of offsite power to MPS. That belief resulted in the DNC mindset that the removal of SLOD references from the FSARs did not require further evaluation. Following the May 25, 2014 event, DNC recognized that SLOD was credited for GDC 17 compliance and its removal should have been considered an adverse change requiring a 10 CFR 50.59 evaluation.
Extensive engineering analysis, including consideration of potential design modifications, is ongoing to address DNC's compliance with GDC 17. Upon completion of this work, a LAR will be submitted to the NRC requesting review and approval of licensing basis changes to the MPS2 and MPS3 FSARs for GDC 17.
As noted in the response to Question 3, improving sensitivity to the license basis and the 10 CFR 50.59 requirements is being addressed by training to prevent future similar situations.
"After filing the motion, however, the group learned that the plant’s final safety analysis report, a document required by the plant’s license, had been changed last year, altering the methodology for measuring seismic safety and stating that the plant can withstand shaking up to .75 times the force of gravity. Such a fundamental change, the group argues, requires amending the operating license itself, a process in which the commission must give the public the opportunity to comment.
Report not public
Instead, the revised safety analysis report wasn’t available to the public on the commission’s website. When Friends of the Earth requested a copy, they received a redacted version.
Commission spokeswoman Uselding said information related to nuclear plant safety is often released to the public on a case-by-case basis, after a commission staff member has reviewed the request to address national security concerns."
"The Severe Line Outage Detection (SLOD) system is designed to prevent instability and loss of all generation at Millstone Station. Besides avoiding unit instability, a distribution system casualty with generation above 1300-1400 MW at Millstone Station could have severe, adverse consequences on Pennsylvania and/or New York grid reactive and thermal operating conditions. The SLOD system is continuously armed and avoids instability and loss of all generation at Millstone by tripping only pre-selected units when certain conditions exist. The tripping logic associated with the SLOD system was modified to remove all trips associated with Millstone Unit No. 1. The Double Line and Breaker Failure Detection Unit Rejection Special Protection System (DBURS), two more Special Protection Systems (SPS) used to trip pre-selected units at Millstone, were deleted and removed since their functions were no longer needed due to the loss of Millstone Unit No. 1 generation. CRP-909 was connected to the master supervisory panel in the 345-kV switchyard via a new fiber optic cable. Switches on CRP-909 for control of Millstone Unit No. 1 switchyard circuit breakers and motor operated disconnects were removed."
"Summer Readiness of Offsite and Alternate Alternating Current (AC) Power Systemsa. Inspection Scope
The inspectors performed a review of plant features and procedures for the operation and continued availability of the offsite and alternate AC power system to evaluate readiness of the systems prior to seasonal high grid loading. The inspectors reviewed Dominion’s procedures affecting these areas and the communications protocols between the transmission system operator and Dominion. This review focused on changes to the established program and material condition of the offsite and alternate AC power equipment. The inspectors assessed whether Dominion established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system. The inspectors evaluated the material condition of the associated equipment by interviewing the responsible system manager, reviewing condition reports (CR) and open work orders, and walking down portions of the offsite and AC power systems including the 345 kilovolt (KV) switchyard and transformers. Documents reviewed for each section of this inspection report are listed in the Attachment."