ML15036A527
| ML15036A527 | |
| Person / Time | |
|---|---|
| Site: | Byron  |
| Issue date: | 02/05/2015 |
| From: | John Ellegood Region 3 Branch 3 |
| To: | Bryan Hanson Exelon Generation Co |
| References | |
| IR 2014005 | |
| Download: ML15036A527 (75) | |
See also: IR 05000454/2014005
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE RD. SUITE 210
LISLE, IL 60532-4352
February 5, 2015
Mr. Bryan C. Hanson
Senior VP, Exelon Generation Company, LLC
President and CNO, Exelon Nuclear
4300 Winfield Road
Warrenville, IL 60555
SUBJECT: BYRON STATION, UNITS 1 AND 2, NRC INTEGRATED INSPECTION REPORT
05000454/2014005; 05000455/2014005
Dear Mr. Hanson:
On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Byron Station, Units 1 and 2. On January 6, 2015, the NRC inspectors
discussed the results of this inspection with the Site Vice President, Mr. R. Kearney, and other
members of your staff. The inspectors documented the results of this inspection in the enclosed
inspection report.
NRC inspectors documented five findings of very low safety significance (Green) in this report.
Four of these findings involved violations of NRC requirements. Further, inspectors
documented licensee-identified violations in Section 4OA7 of this report, which were determined
to be of very low safety significance. The NRC is treating these violations as non-cited
violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.
If you contest the subject or severity of any NCV, you should provide a response within 30 days
of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear
Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a
copy to the Regional Administrator, U.S. Nuclear Regulatory Commission-Region III,
2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement,
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident
Inspector Office at the Byron Station.
If you disagree with the cross-cutting aspect assigned to any finding in this report, you should
provide a response within 30 days of the date of this inspection report, with the basis for your
disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at
Byron Station.
B. Hanson -2-
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public
Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy
of this letter, its enclosure, and your response (if any) will be available electronically for public
inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS)
component of the NRC's Agencywide Documents Access and Management System (ADAMS).
ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html
(the Public Electronic Reading Room).
Sincerely,
/RA/
John Ellegood, Acting Chief
Branch 3
Division of Reactor Projects
Docket Nos. 50-454; 50-455
Enclosure:
IR 05000454/2014005; 05000455/2014005
w/Attachment: Supplemental Information
cc w/encl: Distribution via LISTSERV
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 05000454; 05000455
Report No: 05000454/2014005; 05000455/2014005
Licensee: Exelon Generation Company, LLC
Facility: Byron Station, Units 1 and 2
Location: Byron, IL
Dates: October 1 through December 31, 2014
Inspectors: J. McGhee, Senior Resident Inspector
J. Draper, Resident Inspector
T. Bilik, Reactor Inspector
M. Holmberg, Senior Reactor Inspector
R. Jickling, Senior Emergency Preparedness Inspector
J. Cassidy, Senior Health Physicist
M. Bielby, Operator Licensing Lead Inspector
R. Baker, Operator Licensing Inspector
C. Thompson, Resident Inspector,
Illinois Emergency Management Agency
Approved by: J. Ellegood, Acting Chief
Branch 3
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS ........................................................................................................... 2
REPORT DETAILS ....................................................................................................................... 7
Summary of Plant Status ........................................................................................................... 7
1. REACTOR SAFETY ........................................................................................................ 7
1R01 Adverse Weather Protection (71111.01) .............................................................. 7
1R04 Equipment Alignment (71111.04) ........................................................................ 8
1R05 Fire Protection (71111.05) ................................................................................... 9
1R08 Inservice Inspection Activities (71111.08P) ....................................................... 10
1R11 Licensed Operator Requalification Program (71111.11) .................................... 20
1R12 Maintenance Effectiveness (71111.12) .............................................................. 24
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13) ........ 24
1R15 Operability Determinations and Functional Assessments (71111.15) ............... 25
1R19 Post-Maintenance Testing (71111.19) ............................................................... 31
1R20 Outage Activities (71111.20) .............................................................................. 32
1R22 Surveillance Testing (71111.22) ........................................................................ 35
1EP2 Alert and Notification System Evaluation (71114.02) ......................................... 36
1EP3 Emergency Response Organization Staffing and Augmentation System
(71114.03).......................................................................................................... 36
1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04) ............ 37
1EP5 Maintenance of Emergency Preparedness (71114.05) ..................................... 37
2. RADIATION SAFETY .................................................................................................... 38
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01) .............. 38
4. OTHER ACTIVITIES...................................................................................................... 41
4OA1 Performance Indicator Verification (71151) ....................................................... 41
4OA2 Identification and Resolution of Problems (71152) ............................................ 46
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153) ............... 51
4OA5 Other Activities ................................................................................................... 52
4OA6 Management Meetings ...................................................................................... 54
4OA7 Licensee-Identified Violations ............................................................................ 55
SUPPLEMENTAL INFORMATION ............................................................................................... 1
KEY POINTS OF CONTACT..................................................................................................... 1
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED ......................................................... 2
LIST OF DOCUMENTS REVIEWED......................................................................................... 3
LIST OF ACRONYMS USED .................................................................................................. 14
SUMMARY OF FINDINGS
Inspection Report 05000454/2014005, 05000455/2014005; [10/01/2014-12/31/2014]; Byron
Station, Units 1 and 2; Inservice Inspection Activities, Operability Determinations, and Outage
Activities.
This report covers a 3-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. Five Green findings were identified by the
inspectors. Four of the findings were considered non-cited violations (NCVs) of NRC
regulations. The significance of inspection findings is indicated by their color (i.e., greater than
Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter
(IMC) 0609, Significance Determination Process (SDP) dated June 2, 2011. Cross-cutting
aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas dated
December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the
NRCs Enforcement Policy dated July 9, 2013. The NRC's program for overseeing the safe
operation of commercial nuclear power reactors is described in NUREG-1649, Reactor
Oversight Process Revision 5, dated February 2014.
NRC-Identified and Self-Revealed Findings
Cornerstone: Mitigating Systems
- Green. The inspectors identified a finding of very low safety significance and an
associated NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special
Processes, for a failure to measure the interpass temperature while performing welding
on the on the safety injection (SI) piping system. Consequently, welding was performed
without the Code and procedure required interpass temperature being monitored on a
number of welds, a parameter which can affect the mechanical properties of the material
being welded. After identification of the issue, the welders restored compliance by
measuring the interpass temperatures on the balance of the welds and verifying that the
interpass temperature did not exceed that allowed by procedure. The licensee entered
this issue into its Corrective Action Program (CAP) (IR 02391545).
The inspectors determined that this issue was more than minor in accordance with
IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because the
inspectors answered "Yes" to the More-than-Minor question, If left uncorrected, would
the performance deficiency have the potential to lead to a more significant safety
concern? Specifically, absent NRC intervention, the welders would have completed all
of the welds without having measured the interpass temperature, a welding parameter
which can affect the mechanical properties (e.g., impact properties) of some materials
being welded, and if left uncorrected, could lead to a potential failure of the weld in
service. In accordance with Table 2, Cornerstones Affected by Degraded Condition or
Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of
Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating
Systems Cornerstone because leakage on the SI piping system could degrade short
term heat removal. The inspectors determined this finding was of very-low safety
significance (Green) using Part A of Exhibit 2, Mitigating Systems Screening
Questions, in IMC 0609, Appendix A, The Significance Determination Process for
Findings At-Power, issued on June 19, 2012. Specifically, the inspectors answered
"Yes" to the screening question If the finding is a deficiency affecting the design or
qualification of a mitigating Systems Structures and Components (SSC), does the SSC
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maintain its operability or functionality? The welders proceeded to measure the
interpass temperatures on the balance of the welds and verified that the interpass
temperature did not exceed that allowed by procedure, and the issue did not result in
the actual loss of the operability or functionality of a safety system. The finding had a
cross-cutting aspect of Procedure Adherence in the area of Human Performance (IMC
0310 H.8). Specifically, the welders failed to follow procedures. (Section 1R08.b(1))
- Green. The inspectors identified a finding of very low safety significance and an
associated NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special
Processes, for the failure to perform a Liquid Penetrant Test (PT) in accordance with
the American Society for Mechanical Engineers (ASME) Code while performing a
surface examination on reactor coolant pump (RCP) flywheel 2A/D483. The vendor
conducted a demonstration in an attempt to show the differences in bleed-out between
the two dwell times, to demonstrate continued functionality of the flywheel. The results
showed little if any difference in the growth of the bleed-out given the additional time.
The licensee was developing an action plan to address the non-conformance and
restore compliance. The issue was entered into the licensees CAP as IR 02393595
and IR 02399248.
The inspectors determined that this issue was more than minor in accordance with
IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because the
inspectors answered "Yes" to the More-than-Minor question, If left uncorrected, would
the performance deficiency have the potential to lead to a more significant safety
concern? Specifically, since the liquid penetrant testing developer minimum dwell time
may not have been met, the liquid penetrant examination was not assured to accurately
measure a rejectable flaw. Absent NRC intervention, the potential would exist for a
rejectable flaw to remain in service, affecting the operability of affected systems. In
accordance with Table 2, Cornerstones Affected by Degraded Condition or
Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of
Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating
Systems Cornerstone because failure of the RCP flywheel could degrade core decay
heat removal. The inspectors determined this finding was of very-low safety significance
(Green) using Part A of Exhibit 2, Mitigating Systems Screening Questions, in
IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power,
issued on June 19, 2012. Specifically, the issue did not result in the actual loss of the
operability or functionality of a safety system; and therefore the inspectors answered
"Yes" to the screening question If the finding is a deficiency affecting the design or
qualification of a mitigating SSC, does the SSC maintain its operability or functionality?
The vendor subsequently performed demonstrations to show that the bleed-out from an
indication would not change appreciably when implementing the additional dwell time.
The licensee was still evaluating its planned corrective actions. However, the inspectors
determined that the continued non-compliance did not present an immediate safety
concern because the licensee/vendor reasonably determined the RCP flywheel
remained functional. The finding had a cross-cutting aspect of Change Management in
the area of Human Performance (IMC 0310 H.3) in that leaders failed to use a
systematic process for evaluating and implementing change so that nuclear safety
remains an overriding priority. Specifically, the licensee failed to ensure that the vendor
changed its procedure to reflect the requirements of the current edition of the ASME
Code adopted by the licensee. (Section 1R08.b(2))
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- Green. The inspectors identified a finding of very low safety significance and associated
NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special Processes, for the
failure to revise or amend a welding procedure specification (WPS) after changing
welding variables, including an increase in amperage, for welding performed on the SI
system. The licensee interviewed the welders who indicated that they would likely not
have increased the amperage to the range permitted, to restore compliance. The
licensee planned to review the use of vendor technical information (VTIP) manual
information for welding criteria and cover this issue with the work order planners. Also,
the site welding administrator planned to review the issue to be aware of possible WPS
deviations in work instructions. The issue was entered into the licensees CAP as IR
02392483.
The inspectors determined that this issue was more than minor in accordance with
IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because the
inspectors answered "Yes" to the More-than-Minor question, If left uncorrected, would
the performance deficiency have the potential to lead to a more significant safety
concern? Specifically, the welding variables were changed without appropriate process
or documentation, or meeting ASME Code, which resulted in the permitted use of a
significant increase in amperage above that in the WPS. This permitted the welders to
use an elevated heat input which could have been detrimental to the components being
welded. In accordance with Table 2, Cornerstones Affected by Degraded Condition or
Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of
Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating
Systems Cornerstone because degradation of the SI system could degrade short term
heat removal. The inspectors determined this finding was of very-low safety significance
(Green) using Part A of Exhibit 2, Mitigating Systems Screening Questions, in IMC
0609, Appendix A, The Significance Determination Process for Findings At-Power,
issued on June 19, 2012. Specifically, the inspectors answered "Yes" to the screening
question If the finding is a deficiency affecting the design or qualification of a mitigating
SSC, does the SSC maintain its operability or functionality? The welders indicated that
they would likely not have used the elevated heat inputs; and therefore, would still
comply with the original WPS, and the issue did not result in the actual loss of the
operability or functionality of a safety system. The finding had a cross-cutting aspect of
Documentation in the area of Human Performance (IMC 0310 H.7). Specifically, the
organization failed to create and maintain complete, accurate and up-to-date
documentation. (Section 1R08.b(3))
- Green. Inspectors identified a finding of very low safety significance and associated
NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions Procedures, and
Drawings, for failure to implement procedure OP-AA-108-115, Operability
Determinations (CM-1), as written when a degraded condition was identified for a
non-TS SSC that supported a TS SSC. Specifically, during a surveillance test of the
flood barrier door to the 2B emergency diesel generator (EDG) fuel oil storage tank room
in March 2014, maintenance technicians identified a degraded condition that, while not
affecting immediate functionality of the barrier, was identified to have the potential to
impact the door functionality prior to the next scheduled performance of the surveillance.
An Operability Determination was not performed for the supported TS SSCs at that time
as required by OP-AA-108-115 and in June of 2014 (the next surveillance
performance), the door failed the test, and both Unit EDGs were declared inoperable.
The issue was entered in the CAP as Issue Report (IR) 1675255. Upon discovery of the
failure of the water-tight door, a temporary water-tight barrier was immediately installed,
4
restoring operability of the Unit 2 EDGs. The permanent water-tight door was repaired
and returned to service at a later date.
Failure to perform and document an operability determination of the Unit 2 EDGs and
fuel oil transfer pumps upon discovery of the degraded condition of the support system
(i.e., flood barrier door) is a performance deficiency. The finding was more than minor
because, if left uncorrected, failure to evaluate operability through a SSCs surveillance
interval can lead to more significant safety concerns and an unevaluated assumption of
risk by the station. The finding affected the Mitigating Systems Cornerstone because it
impacted an External Events Mitigation System (degraded flood protection). Because a
complete loss of the water-tight door could impact both Unit 2 EDG trains, the NRC
Senior Reactor Analysts (SRAs) performed a more detailed significance determination
and determined that the finding was not greater than Green. The finding had a
cross-cutting aspect of Conservative Bias in the area of Human Performance
(IMC 0310 H.14) because the licensees decisions regarding disposition of the degraded
condition did not indicate a conservative bias that emphasized prudent choices over
those that were allowable. Even though mechanics identified the potential for the
condition to degrade further in the near future, the work request was not given a high
priority and continued functionality of the door was not evaluated through the next
surveillance period by the licensee. (Section 1R15)
Cornerstone: Barrier Integrity
- Green. Inspectors identified a finding of very low safety significance when the licensee
impaired a flood protection boundary that supported a required safety function for
operational convenience. Specifically, the licensee removed the flood barriers for
auxiliary feedwater system containment isolation valves and rendered the valves
inoperable prior to the plant reaching Mode 5 and thereby entered TS 3.6.3 Condition C
for operational convenience contrary to the TS Bases associated with TS 3.0.2 Limiting
Condition for Operability (LCO) Applicability. From 2010 on September 28, 2014, until
0536 on September 29, 2014, while transitioning from Mode 1 to Mode 5, the valves
were rendered inoperable. This issue has been entered in the CAP as IR 2390265.
Corrective actions included Senior Reactor Operator review of the LCO basis and
creating a logic tie in the outage schedule template tying the barrier removal to Mode 5.
The finding was more than minor because it impacted the SSC and Barrier Performance
attribute of the Barrier Integrity Cornerstone, and adversely affected the cornerstone
objective to provide reasonable assurance that the physical design barrier of the
containment system protects the public from radionuclide releases caused by accidents
or events. Specifically, with inoperable containment isolation valves the potential for an
open containment pathway is increased. The inspectors determined the finding could be
evaluated using the SDP in accordance with IMC 0609, Appendix A, The Significance
Determination Process For Findings At-Power, Exhibit 3-Barrier Integrity Screening
Questions, item B for the Reactor Containment. Both questions were answered
"No" and therefore the finding screened as Green. The finding had an associated
cross-cutting aspect of Work Management in the area of Human Performance (MC 0310
H.5) because the shutdown and outage work schedules did not contain the rigor
required to ensure the isolation valves were maintained operable as required by TS.
(Section 1R20)
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Licensee Identified Findings
Violations of very low safety or security significance that were identified by the licensee
have been reviewed by the NRC. Corrective actions taken or planned by the licensee
have been entered into the licensees CAP. These violations and CAP tracking numbers
are listed in Section 4OA7 of this report.
6
REPORT DETAILS
Summary of Plant Status
Unit 1
The unit began the period at full power and operated at or near full power until October 6 when
power was lowered to 83.5 percent at the request of the transmission operator to support
planned switchyard maintenance. After the maintenance was completed on October 8, Unit 1
returned to full power and operated there until December 30, 2014. On December 30 Unit 1
power was lowered to approximately 73 percent to support a switchyard insulator repair. The
insulator was repaired on December 31 and Unit 1 was ramped back up to full power where it
operated for the remainder of the inspection period.
Unit 2
The unit began the period shutdown with refueling outage B2R18 in progress. Unit 2 exited the
outage on October 23 and reached full power on October 26, 2014. The unit operated at or
near full power for the remainder of the inspection period.
1. REACTOR SAFETY
Cornerstone: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1 Winter Seasonal Readiness Preparations
a. Inspection Scope
The inspectors conducted a review of the licensees preparations for winter conditions to
verify that the plants design features and implementation of procedures were sufficient
to protect mitigating systems from the effects of adverse weather. Documentation for
selected risk-significant systems was reviewed to ensure that these systems would
remain functional when challenged by inclement weather. During the inspection, the
inspectors focused on plant specific design features and the licensees procedures used
to mitigate or respond to adverse weather conditions. Additionally, the inspectors
reviewed the Updated Final Safety Analysis Report (UFSAR) and performance
requirements for systems selected for inspection, and verified that operator actions were
appropriate as specified by plant specific procedures. Cold weather protection, such as
heat tracing and area heaters, was verified to be in operation where applicable. The
inspectors also reviewed CAP items to verify that the licensee was identifying adverse
weather issues at an appropriate threshold and entering them into their CAP in
accordance with station corrective action procedures. The inspectors reviews focused
specifically on the following plant systems due to their risk significance or susceptibility
to cold weather issues:
- river screen house ventilation system (VH); and
- essential service water make-up pumps (SX).
This inspection constituted one winter seasonal readiness preparations sample as
defined in inspection procedure (IP) 71111.01-05.
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b. Findings
No findings were identified.
.2 External Flooding
a. Inspection Scope
The inspectors evaluated the design, material condition, and procedures for coping with
the expected flooding conditions based on the most recent flooding hazard analysis
postulated rainfall and rises in local river levels. The evaluation included a review to
check for deviations from the descriptions provided in the UFSAR for features intended
to mitigate the potential for flooding. As part of this evaluation, the inspectors checked
for obstructions that could prevent draining, checked that the roofs did not contain
obvious loose items that could clog drains in the event of heavy precipitation, and
determined that barriers required to mitigate the flood were in place and operable.
Additionally, the inspectors performed a walkdown of the protected area to identify any
modification to the site which would inhibit site drainage during the predicted flood
conditions or allow water ingress past a barrier.
This inspection constituted one external flooding sample as defined in IP 71111.01-05.
b. Findings
No findings were identified.
1R04 Equipment Alignment (71111.04)
.1 Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
- 1B auxiliary feed pump following maintenance activities;
- 2B centrifugal charging pump following return to service after maintenance; and
The inspectors selected these systems based on their risk significance relative to the
Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted
to identify any discrepancies that could impact the function of the system and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
system diagrams, UFSAR, technical specifications requirements, outstanding work
orders (WO,) IRs, and the impact of ongoing work activities on redundant trains of
equipment in order to identify conditions that could have rendered the systems incapable
of performing their intended functions. The inspectors also walked down accessible
portions of the systems to verify system components and support equipment were
aligned correctly and operable. The inspectors examined the material condition of the
components and observed operating parameters of equipment to verify that there were
no obvious deficiencies. The inspectors also verified that the licensee had properly
identified and resolved equipment alignment problems that could cause initiating events
8
or impact the capability of mitigating systems or barriers and entered them into the CAP
with the appropriate significance characterization.
These activities constituted three partial system walkdown samples as defined in
b. Findings
No findings were identified.
.2 Semi-Annual Complete System Walkdown
a. Inspection Scope
On December 18, 2014, the inspectors performed a complete system alignment
inspection of the 2A residual heat removal (RH) system to verify the functional capability
of the system following return to service after a system maintenance outage. This
system was selected because it was considered both safety significant and risk
significant in the licensees probabilistic risk assessment. The inspectors walked down
the system to review mechanical and electrical equipment lineups, electrical power
availability, system pressure and temperature indications, component labeling,
component lubrication, equipment cooling, and piping hangers and supports. Operability
of support systems was verified to ensure that ancillary equipment or debris did not
interfere with equipment operation. A review of a sample of past and outstanding WOs
was performed to determine whether any deficiencies significantly affected the system
function. In addition, the inspectors reviewed the CAP database to ensure that system
equipment alignment problems were being identified and appropriately resolved.
These activities constituted one complete system walkdown sample as defined in
b. Findings
No findings were identified.
1R05 Fire Protection (71111.05)
.1 Routine Resident Inspector Tours (71111.05Q)
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
- 2B EDG and day tank rooms (Fire Zones 9.1-2 and 9.4-2);
- 2A containment spray pump room (Fire Zone 11.2B-2);
- 2B containment spray pump room (Fire Zone 11.2A-2);
- 2A RH pump room (Fire Zone 11.2A-2); and,
- 2B RH pump room (Fire Zone 11.2B-2).
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The inspectors reviewed areas to assess if the licensee had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant, effectively maintained fire detection and suppression capability, maintained
passive fire protection features in good material condition, and implemented adequate
compensatory measures for out-of-service, degraded or inoperable fire protection
equipment, systems, or features in accordance with the licensees fire plan. The
inspectors selected fire areas based on their overall contribution to internal fire risk as
documented in the plants Individual Plant Examination of External Events with later
additional insights, their potential to impact equipment which could initiate or mitigate a
plant transient, or their impact on the plants ability to respond to a security event. The
inspectors verified that fire hoses and extinguishers were in their designated locations
and available for immediate use; that fire detectors and sprinklers were unobstructed;
that transient material loading was within the analyzed limits; and fire doors, dampers,
and penetration seals appeared to be in satisfactory condition. The inspectors also
verified that minor issues identified during the inspection were entered into the licensees
CAP.
These activities constituted five quarterly fire protection inspection samples as defined in
b. Findings
No findings were identified.
1R08 Inservice Inspection Activities (71111.08P)
From September 29, 2014, through October 10, 2014, the inspectors conducted a
review of the implementation of the licensees Inservice Inspection (ISI) Program for
monitoring degradation of the reactor coolant system, steam generator tubes,
emergency feedwater systems, risk significant piping and components and containment
systems.
The inspections described in Sections 1R08.1, 1R08.2, R08.3, IR08.4 and 1R08.5
below constituted one inservice inspection sample as defined in IP 71111.08-05.
.1 Piping Systems Inservice Inspection
a. Inspection Scope
The inspectors either observed or reviewed the following non-destructive examinations
mandated by the ASME Section XI Code to evaluate compliance with the ASME Code
Section XI and Section V requirements and if any indications and defects were detected,
to determine whether these were dispositioned in accordance with the ASME Code or a
NRC approved alternative requirement:
- ultrasonic (UT) examination of vessel head penetrations 13, 39, 44, 45, 64, and
72;
- magnetic particle (MT) examination of main steam restraint lugs for
2MS01AA-30.25/E-2;
- liquid penetrant (PT) examination of main steam restraint lugs for
2MS01AA-30.25/E-2;
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- visual examination (VT-3) of component cooling system surge tank 2CC01T; and
- VT-3 of a safety injection restraint/support for 2SI15004X.
The inspectors reviewed the following examinations completed during the previous
outage with relevant/recordable conditions/indications accepted for continued service to
determine whether acceptance was in accordance with the ASME Code Section XI or an
NRC-approved alternative:
examination in WO 1505231;
(2RC-01-BB/SGN-03) examination in WO 1505231; and
examination in WO 1323963.
The inspectors either observed or reviewed the following pressure boundary welds
completed for risk significant systems since the beginning of the last refueling outage to
determine whether the licensee applied the pre-service non-destructive examinations
and acceptance criteria required by the Construction Code and ASME Code, Section XI:
check valve (2SI8900C) per WO 01480596;
- weld repair/replacement of Class 1, of SI system loop 2 hot leg check valve
(2SI8905B) per WO 01025526; and
Additionally, the inspectors reviewed the welding procedure specification and supporting
weld procedure qualification records to determine whether the weld procedures were
qualified in accordance with the requirements of Construction Code and the ASME Code
b. Findings
(1) Failure to Measure Interpass Temperature
Introduction: The inspectors identified a finding of very low safety significance, Green,
and an associated NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special
Processes, for a failure to measure the interpass temperature while performing welding
on the SI piping system. Consequently, welding was performed without the code and
procedurally required interpass temperature being monitored; a parameter which can
potentially affect the mechanical properties of materials being welded.
Description: The inspectors observed that welders had failed to measure the interpass
temperature while performing gas tungsten arc welding (GTAW) on SI system piping
as part of the diverse and flexible coping strategies (FLEX) modification. The inspectors
also noted that there were no temperature-measuring devices in the area.
The welders were to perform the welding activities in accordance with welding procedure
specification (WPS) 1-1-GTSM-PWHT, which specified an interpass temperature limit
to ensure that temperature was not exceeded on the work piece between passes.
11
Furthermore, Procedure MA-MW-796-101, Welding, Brazing and Soldering Records,
and Procedure CC-AA-501-1011, Exelon Nuclear Welding Program Preheat,
Interpass Temperature and Postweld Heat Treatment of Welds, used in conjunction
with the WPS, required in part that When interpass temperature is specified (on the
WPS) CHECK the interpass temperature prior to initiating the arc for each pass using
contact pyrometers, thermometers, or temperature indicating crayons. These
procedural provisions implemented Article 1 of ASME Section IX, which states that
welding must be performed as established in the WPS.
Multiple passes had already been performed on a number of welds as part of the FLEX
modification to the SI system before the inspectors observed the in-process welding and
noted the failure to measure the interpass temperature. The inspectors were concerned
that failing to follow procedures as required by the code and procedures, could impact
the quality of the welds and lead to susceptible material failing while in service, and
thereby adversely affect the integrity of the associated systems. As a result of the
inspectors concern, the welders measured the interpass temperatures on the balance of
the FLEX modification welds and verified that the interpass temperatures did not exceed
that allowed by procedure. Since the measured interpass temperatures were well below
that permitted by procedure, the inspectors concluded that there was reasonable
assurance that the previous weld passes would not have exceeded the interpass
temperature. The issue was entered into the licensees CAP as IR 02391545.
Analysis: The inspectors determined that the failure to measure the weld interpass
temperature as required by the ASME Code Section IX and site procedures was a
performance deficiency that warranted a significance evaluation. The inspectors
determined that this issue was more than minor in accordance with IMC 0612,
Appendix B, Issue Screening, dated September 7, 2012, because the inspectors
answered "Yes" to the More-than-Minor question, If left uncorrected, would the
performance deficiency have the potential to lead to a more significant safety concern?
Specifically, absent NRC intervention, the welders would have completed all of the welds
without having measured the interpass temperature; a welding parameter which can
affect the mechanical properties (e.g., impact properties) of some materials being
welded, and if not corrected, could lead to a potential failure of welds in service.
In accordance with Table 2, Cornerstones Affected by Degraded Condition or
Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of
Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating
Systems Cornerstone because leakage at this SI piping could degrade short term
heat removal. The inspectors determined this finding was of very-low safety significance
(Green) using Part A of Exhibit 2, Mitigating Systems Screening Questions, in
IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power,
issued on June 19, 2012. Specifically, the inspectors answered "Yes" to the screening
question If the finding is a deficiency affecting the design or qualification of a mitigating
SSC, does the SSC maintain its operability or functionality? The welders subsequently
performed interpass temperature measurements and demonstrated that the temperature
would remain below the required temperature of the welds in question, and the issue did
not result in the actual loss of the operability or functionality of a safety system.
The inspectors determined that the primary cause of the failure to measure the interpass
temperature while performing a manual welding process was related to the cross-cutting
12
aspect of Procedure Adherence in the Human Performance area (H.8). Specifically, the
welders failed to follow procedures.
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion IX, Control of Special
Processes, states that, Measures shall be established to assure that special processes,
including welding, heat treating, and nondestructive testing, are controlled and
accomplished by qualified personnel using qualified procedures in accordance with
applicable codes, standards, specifications, criteria, and other special requirements.
The WPS 1-1-GTSM-PWHT, used to perform welding on the Class 1, SI FLEX piping
welds, includes an interpass temperature.
Welding Procedure MA-MW-796-101, Welding, Brazing and Soldering Records,
requires in part that When interpass temperature is specified (on the WPS) CHECK the
interpass temperature prior to initiating the arc for each pass using contact pyrometers,
thermometers, or temperature indicating crayons.
Contrary to the above, while performing welding on the SI FLEX piping welds, the
welders did not accomplish the welding in accordance with the WPS in that they failed to
measure the interpass temperature. After identification by the inspectors, the welders
proceeded to measure the interpass temperature on the balance of the welds, thereby
providing reasonable assurance that interpass temperatures had not been exceeded.
Because of the very-low safety significance and because the licensee entered this
issue into its CAP, it is being treated as a NCV consistent with Section 2.3.2 of the
Enforcement Policy (NCV 05000454/2014005-01, 05000455/2014005-01; Failure to
Measure Interpass Temperature).
(2) Liquid Penetrant Testing Procedure Did Not Meet American Society of Mechanical
Engineers Code
Introduction: The inspectors identified a finding of very low safety significance, Green,
and an associated NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special
Processes, for a failure to perform a PT examination in accordance with the ASME
Code. Specifically, the liquid penetrant testing procedure used by the licensees vendor,
for a RCP flywheel, had a developer dwell time less than that required by ASME Section
V, Nondestructive Examination.
Description: The inspectors identified that vendor personnel had failed to employ the
required ASME Code developer dwell time (7 minutes versus the required 10 minutes)
while performing a PT Examination on RCP flywheel 2A/D483. The vendor that
performed the RCP motor refurbishment conducted the required PT exam per its
Procedure 80165, PT Testing. This was a generic PT procedure that was not specific
to the current edition of the ASME Code the licensee was committed to, which resulted
in the use of a dwell time less than required. The vendors liquid penetrant test report
did not record actual dwell times. Hence, there was insufficient rationale to conclude
that vendor examiners employed a dwell time longer than that stated in the procedure.
In addition, a rounded indication was identified during the PT examination, which was
dispositioned as acceptable since the bleed-out had not grown to a rejectable size.
While the initial bleed-out occurs quite rapidly, some increase in the size of the indication
can continue given sufficient dwell time. However, the indication measured was half that
13
required to be rejectable, and hence, was likely not to have reached the rejectable
threshold given the additional dwell time.
The vendor subsequently conducted a demonstration to show the effect on bleed-out
between the two dwell times on a test flaw. The results showed little if any difference in
the growth of the bleed-out given the additional time. The merits of the demonstration,
though limited, when combined with the small size of the indication identified provided
reasonable assurance to support the continued functionality of the flywheel. Also, the
dwell time employed by the vendor was standard in an earlier edition of the Code. The
licensee was developing an action plan to address the non-conformance. The issue was
entered into the licensees CAP as IRs 02393595 and 02399248.
Analysis: The inspectors determined that the failure to perform a PT examination in
accordance with the requirements of ASME Section V was a performance deficiency that
warranted a significance evaluation. The inspectors determined that this issue was
more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated
September 7, 2012, because the inspectors answered "Yes" to the More-than-Minor
question, If left uncorrected, would the performance deficiency have the potential to
lead to a more significant safety concern? Specifically, since the liquid penetrant testing
developer minimum dwell time may not have been met, the liquid penetrant examination
did not provide the level of confidence implied by the Code with respect to the
examination capability to identify a rejectable flaw. Absent NRC intervention, the
potential would exist for a rejectable flaw to remain in service, potentially affecting the
operability of affected systems.
In accordance with Table 2, Cornerstones Affected by Degraded Condition or
Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of
Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating
Systems Cornerstone because failure of the RCP flywheel could degrade core decay
heat removal. The inspectors determined this finding was of very-low safety significance
(Green) using Part A of Exhibit 2, Mitigating Systems Screening Questions, in IMC
0609, Appendix A, The Significance Determination Process for Findings At-Power,
issued on June 19, 2012. Specifically, the issue did not result in the actual loss of the
operability or functionality of a safety system; and therefore the inspectors answered
"Yes" to the screening question If the finding is a deficiency affecting the design or
qualification of a mitigating SSC, does the SSC maintain its operability or functionality?
The vendor subsequently performed a demonstration to show that the bleed-out from an
indication would not change appreciably when implementing the additional dwell time.
The licensee was still evaluating its planned corrective actions. However, the inspectors
determined that the continued non-conformance did not present an immediate safety
concern because the licensee/vendor reasonably determined the RCP flywheel
remained functional.
The inspectors determined that the primary cause of the failure to perform a PT
examination in accordance with ASME Code requirements was related to the
cross-cutting aspect of Change Management in the Human Performance area (H.3) in
that leaders failed to use a systematic process for evaluating and implementing change
so that nuclear safety remains an overriding priority. Specifically, the licensee failed to
ensure that the vendor changed its procedure to reflect the requirements of the current
edition of the ASME Code adopted by the licensee.
14
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion IX, Control of Special
Processes, states that, Measures shall be established to assure that special processes,
including welding, heat treating, and nondestructive testing, are controlled and
accomplished by qualified personnel using qualified procedures in accordance with
applicable codes, standards, specifications, criteria, and other special requirements.
Appendix A, Paragraph f, Section C, Item 4b: Inservice Inspection of Reactor Coolant
Pump Flywheel, of the UFSAR, states that the inservice inspection of the exposed
surfaces of the removed flywheel may be conducted with a surface examinations
(MT and/or PT) and that the requirements for the examination procedures and the
acceptance criteria as described in Regulatory Guide 1.14, Reactor Coolant Pump
Flywheel Integrity, will be followed.
Paragraph C.4.b(3) of Regulatory Guide 1.14 states that Examination procedures
should be in accordance with the requirements of Subarticle IWA-2200 of Section XI of
the ASME Code.
The 2001 Edition through the 2003 Addenda of ASME Section XI, IWA-2222, specifies
that liquid penetrant examinations be performed to ASME Section V, Article 6.
Table T-672, of ASME Section V, Article 6, Liquid Penetrant Examination, lists the
minimum Code required dwell times for the PT process. The minimum developer dwell
time was 10 minutes.
Contrary to the above, while performing a PT examination on RCP flywheel 2A/D483, a
licensee vendor did not accomplish the nondestructive testing in accordance with
applicable codes. Specifically, the vendor used a procedure that specified a developer
dwell time of only 7 minutes versus the Code required 10 minutes, and hence there was
insufficient basis to conclude that the required dwell time was met.
The vendor subsequently performed a demonstration to show that the bleed-out from an
indication would not change appreciably when implementing the additional dwell time. It
should be noted that the dwell time employed by the vendor was standard in an earlier
edition of the ASME Code. The licensee was still evaluating its planned corrective
actions to restore compliance. However, the inspectors determined that the continued
non-conformance did not present an immediate safety concern because the
licensee/vendor reasonably determined the RCP flywheel remained functional.
Because of the very-low safety significance and because the licensee entered this issue
into its CAP, it is being treated as a NCV consistent with Section 2.3.2 of the
Enforcement Policy (NCV 05000454/2014005-02, 05000455/2014005-02, Liquid
Penetrant (PT) Testing Procedure Did Not Meet ASME Code).
(3) Welding Procedure Specification Variables Changed Without Revision or Amendment
Contrary to American Society of Mechanical Engineers Code
Introduction: The inspectors identified a finding of very low safety significance, Green,
and an associated NCV of 10 CFR Part 50, Appendix B, Criterion IX, Control of Special
Processes, for a failure to revise or amend a WPS after changing welding variables.
Specifically, welding variable changes, including an increase in allowed amperage, were
15
made to work packages without amendment or revision to the applicable WPS for
welding performed on the SI system.
Description: While reviewing welding related work-packages developed to replace/install
small Kerotest valves, the inspectors identified that changes had been made to WPS
8-8-GTSM required non-essential variables without amendment or revision, which is
contrary to the ASME Code. Specifically, the inspectors identified that numerous work
packages used to install small Kerotest valves had a Kerotest valve vendor VTIP manual
guidance document included in the work packages. The guidance was designed to
change several welding variables in another application in order to control heat input.
However, this guidance was not appropriate for the Kerotest valve work in that it
conflicted with non-essential variables prescribed by WPS 8-8-GTSM. The inspectors
concern in this case was that the guidance supplied would actually permit an increase in
heat input beyond that allowed by the WPS (guidance allowed 150 amps vs. WPS of 50
to 100 amps) and thus increased the chances of valve seat warping.
The addition of the guideline was inappropriate and it should not have been included in
the work packages. The licensee characterized it as a legacy package preparation issue
and a work package documentation issue; both programmatic issues, which have to be
addressed. As an immediate corrective action, the licensee interviewed the welders
who indicated that they would likely not have increased the welding amperage to the
range permitted. In addition, the licensee planned to review the use of VTIP manual
information for welding criteria and cover this issue with the work order planners. Also,
the site welding administrator planned to review the issue to be aware of possible WPS
deviations in work instructions. The issue was entered into the licensees CAP as
Analysis: Inspectors determined that the failure to change the WPS welding variables in
the work packages without revision or amendment to the WPS was contrary to the
ASME Code Section IX and was a performance deficiency that warranted a significance
evaluation. The inspectors determined that this issue was more than minor in
accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012,
because the inspectors answered "Yes" to the More-than-Minor question, If left
uncorrected, would the performance deficiency have the potential to lead to a more
significant safety concern? Specifically, the welding variables were changed without
appropriate process or documentation, or meeting the ASME Code, which resulted in the
permitted use of a significant increase in amperage above that in the WPS. This
permitted the welders to use an elevated heat input, which could have been detrimental
to the components being welded.
In accordance with Table 2, Cornerstones Affected by Degraded Condition or
Programmatic Weakness, of IMC 609, Attachment 4, Initial Characterization of
Findings, issued June 19, 2012, the inspectors checked the box under the Mitigating
Systems Cornerstone because degradation of the SI system could degrade short
term heat removal. The inspectors determined this finding was of very-low safety
significance (Green) using Part A of Exhibit 2, Mitigating Systems Screening
Questions, in IMC 0609, Appendix A, The Significance Determination Process for
Findings At-Power, issued on June 19, 2012. Specifically, the inspectors answered
"Yes" to the screening question If the finding is a deficiency affecting the design or
qualification of a mitigating SSC, does the SSC maintain its operability or functionality?
The welders indicated that they would likely not have used the elevated heat inputs and
16
therefore would still comply with the original WPS, and the issue did not result in the
actual loss of the operability or functionality of a safety system.
The inspectors determined that the primary cause of the failure to revise or amend a
WPS in accordance with ASME Code requirements was related to the cross-cutting
aspect of Documentation in the Human Performance area (H.7). Specifically, the
organization failed to create and maintain complete, accurate and, up-to-date
documentation.
Enforcement: Title 10 CFR 50, Appendix B, Criterion IX, Control of Special Processes,
states that, Measures shall be established to assure that special processes, including
welding, heat treating, and nondestructive testing, are controlled and accomplished by
qualified personnel using qualified procedures in accordance with applicable codes,
standards, specifications, criteria, and other special requirements.
Section IX, QW-256, of the ASME Code contains the welding variables for the gas
tungsten-arc welding process.Section IX states in part that changes to non-essential
variables are permitted as long as the WPS is revised or amended to address the
non-essential variable change.
Contrary to the above, while replacing Kerotest check-valves in the SI system as part of
WO 01480596 and other work packages, changes were made to non-essential variables
without revising WPS 8-8-GTSM. Discussions with welders indicated that they would
not likely have increased the welding current to the level permitted, and therefore the
heat input would not have affected the valves installed.
Because this violation was of very-low safety significance and was entered into the
licensees CAP, this violation is being treated as a NCV, consistent with Section 2.3.2 of
the NRC Enforcement Policy (NCV 05000454/2014005-03, 05000455/2014005-03;
Welding Procedure Specification Variables Changed Without Revision or
Amendment Contrary to ASME Code).
.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities
a. Inspection Scope
A bare metal visual examination and a non-visual examination were required this outage
pursuant to 10 CFR 50.55a(g)(6)(ii)(D).
The inspectors observed the bare metal visual examination conducted on the reactor
vessel
head at each of the penetration nozzles to determine whether the activities were
conducted in accordance with the requirements of ASME Code Case N-729-1
and 10 CFR 50.55a(g)(6)(ii)(D). Specifically, to determine:
- if the required visual examination scope/coverage was achieved and limitations
(if applicable were recorded), in accordance with the licensee procedures;
- if the licensee criteria for visual examination quality and instructions for resolving
interference and masking issues were adequate; and
- for indications of potential through-wall leakage, that the licensee entered the
condition into the corrective action system and implemented appropriate
corrective actions.
17
The inspectors observed a number of non-visual examinations conducted on the reactor
vessel head penetrations to determine whether the activities were conducted in
accordance with the requirements of ASME CC N-729-1 and 10 CFR
50.55a(g)(6)(ii)(D). Specifically, to determine:
a. if the required examination scope (volumetric and surface coverage) was
achieved and limitations (if applicable were recorded), in accordance with the
licensee procedures;
b. if the UT examination equipment and procedures used were demonstrated by
blind demonstration testing;
c. for indications or defects identified, that the licensee documented the conditions
in examination reports and/or entered this condition into the corrective action
system and implemented appropriate corrective actions; and
d. for indications accepted for continued service, that the licensee evaluation
and acceptance criteria were in accordance with the ASME Section XI Code,
10 CFR 50.55a(g)(6)(ii)(D) or an NRC approved alternative.
The inspectors observed and reviewed records of welded repairs on the Unit 2 upper
head penetration number 6 completed during the 2014 Unit 2 refueling outage to
determine if the licensee applied the pre-service non-destructive examinations and
acceptance criteria required by the construction Code, NRC approved Code Case, NRC
approved Code relief request or the ASME Code Section XI. Additionally, the inspectors
reviewed the welding procedure specification and supporting weld procedure
qualification records to determine if the weld procedure(s) used were qualified in
accordance with the Construction Code and the ASME Code Section IX requirements.
Discovery of this indication was documented in Licensee Event Report (LER)
05000455/2014-004-00; Byron Unit 2 Reactor Pressure Vessel Head Control Rod Drive
Mechanism Penetration Nozzle Weld Indication Attributed to Primary Water Stress
Corrosion Cracking. Additional discussion of this LER is included in Section 4OA3.2 of
this report.
b. Findings
No findings were identified.
.3 Boric Acid Corrosion Control
a. Inspection Scope
The inspectors performed an independent walkdown of the reactor coolant system and
related lines in the containment, which had received a recent licensee boric acid
walkdown and verified whether the licensees boric acid corrosion control visual
examinations emphasized locations where boric acid leaks can cause degradation of
safety significant components.
The inspectors reviewed the following licensee evaluations of RCS components with
boric acid deposits to determine whether degraded components were documented in the
CAP. The inspectors also evaluated corrective actions for any degraded reactor coolant
system components to determine if they met the ASME Section XI Code.
- 2CV8117; Dry Boric Acid on Valve;
18
- 2CV131; Body to Bonnet Leakage;
- 2SI01PA; Boric Acid Leak on Flange; and
- 2SI121A; Boric Acid Leak on Flange.
The inspectors reviewed the following corrective actions related to evidence of boric acid
leakage to determine if the corrective actions completed were consistent with the
requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B,
Criterion XVI:
- IR 01613143; 2BR7006 Leaking;
- IR 01507509; 2AB022 Leak; and
- IR 01675385; 2FC01P Leak.
b. Findings
No findings were identified.
.4 Steam Generator Tube Inspection Activities
a. Inspection Scope
The NRC inspectors observed acquisition of eddy current (ET) data, interviewed ET data
analysts, and reviewed documentation related to the steam generator (SG) ISI Program
to determine if:
- in-situ SG tube pressure testing screening criteria used were consistent with
those identified in the Electric Power Research Institute (EPRI) TR-1025132,
Steam Generator In-Situ Pressure Test Guidelines and whether these criteria
were properly applied to screen degraded SG tubes for in-situ pressure testing;
- the numbers and sizes of SG tube flaws/degradation identified was bound by the
licensees previous outage Operational Assessment predictions;
the TS, and the EPRI 1013706, Pressurized Water Reactor SG Examination
Guidelines: Revision 7;
identified in prior outage SG tube inspections and/or as identified in NRC generic
industry operating experience applicable to these SG tubes;
- the licensee identified new tube degradation mechanisms and implemented
adequate extent of condition inspection scope and repairs for the new tube
degradation mechanism;
- the licensee implemented repair methods which were consistent with the repair
processes allowed in the plant TS requirements and to determine if qualified
depth sizing methods were applied to degraded tubes accepted for continued
service;
- the licensee implemented an inappropriate plug on detection tube repair
threshold (e.g., no attempt at sizing of flaws to confirm tube integrity);
- the licensee primary-to-secondary leakage (e.g., SG tube leakage) was below
3 gallons-per-day or the detection threshold during the previous operating cycle;
tubes were qualified to detect the known/expected types of SG tube degradation
in accordance with Appendix H, Performance Demonstration for Eddy Current
19
Examination, of EPRI 1013706, Pressurized Water Reactor SG Examination
Guidelines, Revision 7; and
- the licensee performed secondary side SG inspections for location and removal
of foreign materials.
The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC
review was completed for this inspection attribute.
b. Findings
No findings were identified.
.5 Identification and Resolution of Problems
a. Inspection Scope
The inspectors performed a review of ISI/SG related problems entered into the
licensees CAP and conducted interviews with licensee staff to determine if:
- the licensee had established an appropriate threshold for identifying ISI/SG related
problems;
- the licensee had performed a root cause (if applicable) and taken appropriate
corrective actions; and
- the licensee had evaluated operating experience and industry generic issues
related to ISI and pressure boundary integrity.
The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, requirements.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program (71111.11)
.1 Resident Inspector Quarterly Review of Licensed Operator Requalification (71111.11Q)
a. Inspection Scope
On November 2, 2014, the inspectors observed a crew of licensed operators in the
plants simulator during an evaluated simulator scenario for licensed operator
requalification training to verify that operator performance was adequate, evaluators
were identifying and documenting crew performance problems and training was being
conducted in accordance with licensee procedures. The inspectors evaluated the
following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of abnormal and emergency procedures;
- control board manipulations;
20
- oversight and direction from supervisors; and
- the ability to identify and implement appropriate TS actions and Emergency Plan
actions and notifications.
The crews performance in these areas was compared to pre-established operator action
expectations and successful critical task completion requirements.
This inspection constituted one quarterly licensed operator requalification program
simulator sample as defined in IP 71111.11
b. Findings
No findings were identified.
.2 Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk
a. Inspection Scope
On October 23, 2014, the inspectors observed Unit 2 startup activities from refueling
outage B2R18. This was an activity that required heightened awareness or was related
to increased risk. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of procedures;
- control board (or equipment) manipulations;
- oversight and direction from supervisors; and
- the ability to identify and implement appropriate TS actions.
The performance in these areas was compared to pre-established operator action
expectations, procedural compliance and successful task completion requirements.
This inspection constituted one quarterly licensed operator heightened activity/risk
sample as defined in IP 71111.11.
b. Findings
No findings were identified.
.3 Biennial Written and Annual Operating Test Results (71111.11A)
a. Inspection Scope
The inspectors reviewed the overall pass/fail results of the Biennial Written Examination
and the Annual Operating Test, administered by the licensee from September 17, 2014,
through December 12, 2014, required by 10 CFR 55.59(a). The results were
compared to the thresholds established in IMC 0609, Appendix I, Licensed Operator
Requalification Significance Determination Process," to assess the overall adequacy of
21
the licensees Licensed Operator Requalification Training (LORT) Program to meet the
requirements of 10 CFR 55.59.
This inspection constituted one annual licensed operator requalification examination
results sample as defined in IP 71111.11-05.
b. Findings
No findings were identified.
.4 Biennial Review (71111.11B)
a. Inspection Scope
The following inspection activities were conducted during the weeks of November 24,
2014, and December 1, 2014, to assess: (1) the effectiveness and adequacy of the
facility licensees implementation and maintenance of its systematic approach to training
(SAT) based LORT Program, put into effect to satisfy the requirements of 10 CFR 55.59;
(2) conformance with the requirements of 10 CFR 55.46 for use of a plant referenced
simulator to conduct operator licensing examinations and for satisfying experience
requirements; and (3) conformance with the operator license conditions specified in
10 CFR 55.53. The documents reviewed are listed in the Attachment to this report.
- Licensee Requalification Examinations (10 CFR 55.59(c); SAT Element 4 as Defined
in 10 CFR 55.4): The inspectors reviewed the licensees program for development
and administration of the LORT biennial written examination and annual operating
tests to assess the licensees ability to develop and administer examinations that are
acceptable for meeting the requirements of 10 CFR 55.59(a).
- The inspectors conducted a detailed review of week one and week five versions
of the biennial requalification written examination to assess content, level of
difficulty, and quality of the materials.
- The inspectors conducted a detailed review of twelve Job Performance
Measures (JPMs) (weeks one and five) and six scenarios (weeks one, three and
five) to assess content, level of difficulty, and quality of the operating test
materials.
- The inspectors observed the administration of the annual operating test to
assess the licensees effectiveness in conducting the examinations, including the
conduct of pre-examination briefings, evaluations of individual operator and crew
performance, and post-examination analysis. The inspectors evaluated the
performance of two simulator crews in parallel with the facility evaluators during
four dynamic simulator scenarios, and evaluated various licensed crew members
concurrently with facility evaluators during the administration of several JPMs.
- The inspectors assessed the adequacy and effectiveness of the remedial training
conducted since the last requalification examinations and the training planned for
the current examination cycle, to ensure that they addressed weaknesses in
licensed operator or crew performance identified during training and plant
operations. The inspectors reviewed remedial training procedures and individual
remedial training plans.
22
- Conformance with Examination Security Requirements (10 CFR 55.49): The
inspectors conducted an assessment of the licensees processes related to
examination, physical security and integrity (e.g., predictability and bias), to verify
compliance with 10 CFR 55.49, Integrity of Examinations and Tests. The inspectors
reviewed the facility licensees examination security procedure, and observed the
implementation of physical security controls (e.g., access restrictions and simulator
I/O controls) and integrity measures (e.g., security agreements, sampling criteria,
bank use, and test item repetition) throughout the inspection period.
- Conformance with Simulator Requirements (10 CFR 55.46): The inspectors
assessed the adequacy of the licensees simulation facility (simulator) for use in
operator licensing examinations and for satisfying experience requirements. The
inspectors reviewed a sample of simulator performance test records (e.g., transient
tests, malfunction tests, scenario based tests, post-event tests, steady state tests,
and core performance tests), simulator discrepancies, and the process for ensuring
continued assurance of simulator fidelity in accordance with 10 CFR 55.46. The
inspectors reviewed and evaluated the discrepancy corrective action process to
ensure that simulator fidelity was being maintained. Open simulator discrepancies
were reviewed for importance relative to the impact on 10 CFR 55.45 and 55.59
operator actions as well as on nuclear and thermal hydraulic operating
characteristics.
- Conformance with Operator License Conditions (10 CFR 55.53): The inspectors
reviewed the facility licensee's program for maintaining active operator licenses to
assess compliance with 10 CFR 55.53(e) and (f). The inspectors reviewed the
procedural guidance and the process for tracking on-shift hours for licensed
operators, and which control room positions were granted watch-standing credit for
maintaining active operator licenses. Additionally, medical records for ten licensed
operators were reviewed for compliance with 10 CFR 55.53(I).
- Problem Identification and Resolution (10 CFR 55.59(c); SAT Element 5 as defined
in 10 CFR 55.4): The inspectors evaluated the licensees ability to assess the
effectiveness of its LORT program and their ability to implement appropriate
corrective actions to maintain its LORT Program up-to-date. The inspectors
reviewed documents related to the plants operating history and associated
responses (e.g., Plant Issues Matrix (PIM) and Plant Performance Review reports;
recent examination and inspection reports; and LERs. The inspectors reviewed the
use of feedback from operators, instructors, and supervisors, as well as the use of
feedback from plant events and industry experience information. The inspectors
reviewed the licensees quality assurance oversight activities, including licensee
training department self-assessment reports.
This inspection constituted one biennial licensed operator requalification program
inspection sample as defined in IP 71111.11-05.
b. Findings
No findings were identified.
23
1R12 Maintenance Effectiveness (71111.12)
.1 Routine Quarterly Evaluations
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following
risk-significant systems:
- non-essential service water system;
- auxiliary building heating, ventilation, and cooling system; and
- the ultimate heat sink temperature control system.
The inspectors reviewed events including those in which ineffective equipment
maintenance had resulted in valid or invalid automatic actuations of engineered
safeguards systems and independently verified the licensee's actions to address
system performance or condition problems in terms of the following:
- implementing appropriate work practices;
- identifying and addressing common cause failures;
- scoping of systems in accordance with 10 CFR 50.65(b) of the Maintenance
Rule;
- characterizing system reliability issues for performance;
- charging unavailability for performance;
- trending key parameters for condition monitoring;
- ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and
- verifying appropriate performance criteria for SSCs/functions classified as (a)(2),
or appropriate and adequate goals and corrective actions for systems classified
as (a)(1).
The inspectors assessed performance issues with respect to the reliability, availability,
and condition monitoring of the system. In addition, the inspectors verified maintenance
effectiveness issues were entered into the CAP with the appropriate significance
characterization.
This inspection constituted three quarterly maintenance effectiveness samples as
defined in IP 71111.12-05.
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors reviewed the licensee's evaluation and management of plant risk for the
maintenance and emergent work activities affecting risk-significant and safety-related
equipment listed below to verify that the appropriate risk assessments were performed
prior to removing equipment for work:
24
- outage schedule week 2 and Unit 1 on-line risk impact of switchyard work
activities;
- outage schedule revision 1;
- Unit 2 transition to Mode 3 and on-line risk evaluation with TS equipment out of
service; and
- an emergent switchyard insulator failure and Unit 1 system auxiliary transformer
maintenance outage.
These activities were selected based on their potential risk significance relative to the
Reactor Safety Cornerstones. For each activity, the inspectors verified that risk
assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and
complete. When emergent work was performed, the inspectors verified that the plant
risk was promptly reassessed and managed. The inspectors reviewed the scope of
maintenance work, discussed the results of the assessment with the licensee's
probabilistic risk analyst or shift technical advisor, and verified plant conditions were
consistent with the risk assessment. The inspectors also reviewed TS requirements and
walked down portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met.
These maintenance risk assessments and emergent work control activities constituted
four samples as defined in IP 71111.13-05.
b. Findings
No findings were identified.
1R15 Operability Determinations and Functional Assessments (71111.15)
a. Inspection Scope
The inspectors reviewed the following issues:
- corrosion found in Unit 2 reactor head stud hole number 11;
- flexible hose static bend radius is less than minimum criteria;
- abnormal physical conditions in new Battery 212 cells;
- missed half-trip surveillances for Unit 1 power range nuclear instruments;
- specific gravity results for 125-volt Division 212 battery less than acceptance
criteria; and
- the degraded condition of 2B diesel oil storage tank water-tight door.
The inspectors selected these potential operability issues based on the risk significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that TS operability was properly justified and the
subject component or system remained available such that no unrecognized increase in
risk occurred. The inspectors compared the operability and design criteria in the
appropriate sections of the TS and UFSAR to the licensees evaluations to determine
whether the components or systems were operable. Where compensatory measures
were required to maintain operability, the inspectors determined whether the measures
in place would function as intended and were properly controlled. The inspectors
determined, where appropriate, compliance with bounding limitations associated with the
evaluations. Additionally, the inspectors reviewed a sampling of corrective action
25
documents to verify that the licensee was identifying and correcting any deficiencies
associated with operability evaluations.
This operability inspection constituted six samples as defined in IP 71111.15-05.
b. Findings
Introduction: Inspectors identified a finding of very low safety significance (Green) and
associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions Procedures,
and Drawings, for failure to implement procedure OP-AA-108-115, Operability
Determinations (CM-1), when a degraded condition was identified for a non-TS SSC
that supported a TS SSC. Specifically, during a surveillance test of the flood barrier door
to the 2B EDG fuel oil storage tank room in March 2014, maintenance technicians
identified a degraded condition that, while not affecting immediate functionality, could
degrade and impact door functionality prior to the next performance of the surveillance.
The licensee did not perform an Operability Determination for the supported TS SSCs at
that time as required by the procedure. During the next surveillance June of 2014 the
door failed the test, rendering Unit 2 EDGs inoperable.
Description: On March 25, 2014, the licensee performed a water-tight door inspection
on door 0DSSD194, the door to the 2B EDG fuel oil storage tank room. This door
provides a flood barrier to prevent flood waters in the turbine building from affecting both
Unit 2 trains of the EDG fuel oil transfer pumps, which are required for operability of the
Unit 2 EDGs. The door satisfactorily passed the surveillance, including a chalk test;
however during the performance of the inspection, mechanical maintenance identified a
degraded condition. The issue was entered into the CAP as IR 1638185 and
documented, the general condition of the gearbox linkages and bushings, and
adjustment screws, while acceptable per the criteria at this time, will prevent the door
from passing in the near future. Additionally, the completed work order package
contained the comment that the IR was written to document issues with the door that
may not allow it to pass next time. Operations reviewed the IR and documented the
door as functional as a flood barrier but no basis was provided to support the
assessment or the potential for further degradation to cause the door to fail in the near
future as stated in the IR. The IR was closed to a work request, but no work was
performed on the door before the next surveillance was performed.
The licensees operability determination procedure, OP-AA-108-115, includes
requirements in Attachment 4 for actions to take when an immediate functionality
assessment is performed for a non-TS SSC which supports an SSC described in
TS. The procedure states that operability must also be addressed. Step 1.2 of
OP-AA-108-115 states in part, whenever the ability of an SSC to perform its specified
safety function is called into question, operability must be determined from a detailed
examination of the deficiency. No operability assessment was documented in the IR for
the affected TS SSCs.
NRC IMC 0326, Operability Determinations & Functionality Assessments for Conditions
Adverse to Quality or Safety, describes NRC expectations for operability determinations
and functionality assessments. This document states:
"Satisfactory performance of TS surveillances is usually considered sufficient to
demonstrate operability. However, if conformance to criteria in the current
26
licensing bases (CLB) that are both necessary and sufficient to establish
operability cannot be established with reasonable expectation, then performance
of the surveillance requirement may not, by itself, be sufficient to demonstrate
operability. Failure to conform to CLB criteria that are not needed to demonstrate
operability should be addressed by the appropriate licensee process. An
example of when surveillances would not be sufficient to establish operability is
the satisfactory completion of TS surveillance but with results that show a
degrading trend and indicate that acceptance criteria might not be met before the
next surveillance test. In this case, the surveillance actually identifies the
conditions when the SSC will become inoperable and an operability evaluation
would be warranted."
On June 25, 2014, the licensee again performed an inspection on door 0DSSD194
as it has a 92-day surveillance interval. During this performance of the surveillance,
mechanical maintenance performed a chalk test on the door seal to verify the door was
adequately closing. This time, the door did not pass the chalk test, so the door did not
meet the surveillance acceptance criteria. Because this door was a flood barrier for both
Unit 2 EDG fuel oil transfer pump trains, operations declared both Unit 2 EDGs
inoperable, which forced the licensee to enter a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> required action statement to
return one EDG to operable status in accordance with TS LCO 3.8.1 Condition F.1 for
two EDGs inoperable, or to shut down the reactor in accordance with TS LCO 3.8.1
Condition G if the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> time limit was exceeded. The licensees immediate corrective
action was to install a pre-staged temporary flood barrier on the doorway to return both
Unit 2 EDGs to operable status before 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> had passed.
Subsequent to the June surveillance failure, the licensee performed an analysis and
determined that a rapid turbine building flooding event would flood to a level several feet
above door 0DSSD194 such that the resultant force on the door would close up the gap
between the door and the door frame before the flood waters could impact the fuel oil
transfer pumps of the opposite train EDG. Therefore, the licensee concluded that the
2A EDG remained operable/available and the safety function of emergency power was
never lost.
Analysis: The inspectors determined that the licensees failure to perform and document
an operability determination of the Unit 2 EDGs upon discovery of the degraded
condition of the support system (i.e., flood barrier door) is a performance deficiency.
Specifically, after the licensee identified the condition adverse to quality (e.g., degraded
condition of door 0DSSD194) on March 25, 2014, that could potentially continue to
degrade to impact the supported safety function before the next surveillance test, the
licensee documented that the door was functional but no basis was provided to support
that assessment as required by OP-AA-108-115. Additionally, the licensee failed to
evaluate the operability of the EDGs through the surveillance interval of the water-tight
door even though mechanics identified that the door might not pass its next surveillance.
The inspectors determined that this performance deficiency was of more than minor
safety significance because, if left uncorrected, the performance deficiency would have
the potential to lead to a more significant safety concern. Specifically, the licensees
failure to evaluate the operability of SSCs when their acceptance criteria might not be
met through the surveillance interval led to an avoidable inoperability of both Unit 2
EDGs. The inspectors determined that this finding impacted the Mitigating Systems
cornerstone because it was an External Events Mitigation System (degraded flood
protection). The inspectors utilized Exhibit 2, Mitigating Systems Screening Questions,
27
of IMC 0609, Appendix A, The Significance Determination Process For Findings
At-Power, dated June 19, 2012, to evaluate the significance. Because the inspectors
determined that the finding involved the degradation of equipment specifically designed
to mitigate a flooding event, the inspectors used Exhibit 4, External Events Screening
Questions, of the same Appendix to evaluate the significance. The inspectors
determined that if the flood door were assumed to be completely failed, this condition
by itself during a turbine building flood event would degrade two or more trains of a
multi-train system. Specifically, the turbine building flood would impact the diesel fuel
transfer pumps for both Unit 2 emergency diesel generators. Therefore, a Detailed Risk
Evaluation was required.
To evaluate this finding, the SRAs determined two cases that would require evaluation to
determine the risk significance of the finding. In Case 1, a random break in either the
circulating water (CW) piping or the CW expansion joints of the main condenser results
in a reactor trip, followed by a consequential loss of offsite power (LOOP) on the affected
Unit, followed by a consequential LOOP on the other Unit. In Case 2, a seismic event
results in a LOOP on both Units and a failure of either the CW piping or the CW
expansion joints.
Case 1: Random Break in CW Piping or CW Expansion Joints Followed by Dual Unit
The frequency of a break in either the CW piping or the CW expansion joints was
evaluated using EPRI Report 3002000079, Pipe Rupture Frequencies for Internal
Flooding Probabilistic Risk Assessments, Revision 3. Using Table ES-2 in the EPRI
report, the following failure rate information was obtained:
System Description Value
CW Piping Frequency of Piping Break Causing a Major 7.95E-7/yr/foot
Flood
(i.e., greater than 2000 gpm leak)
CW Frequency of Major Flood (i.e., greater than 2000 9.17E-6/yr/EJ
Expansion gpm leak) with flood rate 10,000 gpm
Joints Frequency of Major Flood with flood rate 10,000 6.08E-6/yr/EJ
gpm
Total Frequency of CW Expansion Joint Major 1.53E-5/yr/EJ
Flood
The following information and assumptions were used to obtain the frequency of a major
flooding event in the turbine building due to a break in either the CW piping or the CW
expansion joint:
- as obtained from the licensee, there is approximately 550 feet of CW
piping per Unit in the turbine building (i.e., 1100 feet total);
- there are eight CW expansion joints per Unit; and
- a flooding event on either Unit will affect both Units.
Using the above information, the initiating event frequency (IEF) of a major flooding
event in the turbine building due to a break in either the CW piping or the CW expansion
joint is given by:
28
IEF = [(7.95E-7/yr/ft) x (550 ft/Unit) + (1.53E-5/yr/EJ) x (8 EJs/Unit)] x [2 Units]
= 1.12E-3/year
The Byron Standardized Plant Analysis Risk (SPAR) model version 8.27 and Systems
Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE)
version 8.1.0 software was used to obtain the probability of a dual Unit LOOP following a
reactor trip. From the SPAR model, the following information was obtained:
SPAR Model Designation Description Value
ZT-VCF-LP-GT Probability of a LOOP Given a Reactor Trip 5.29E-3
ZT-LOOP-SITE-SC Probability of a Dual Unit LOOP 1.146E-1
(Switchyard-Centered)
The exposure time for the finding was assessed to be three months, from March 25
through June 25, 2014. Using the above information, the probability of a Dual Unit
LOOP (DLOOP) following a reactor trip is obtained as:
DLOOP = [ZT-VCF-LP-GT] x [ZT-LOOP-SITE-SC]
= [5.29E-3] x [1.146E-1]
= 6.1E-4
Taking into account that the exposure time is three months (0.25 years), and assuming
that a Dual Unit LOOP with a failure of both emergency diesel generators (EDGs) would
result in a core damage event, the delta core damage frequency (CDF) for Case 1 is
obtained as the product of the following factors:
Case 1: CDF= [IEF] x [DLOOP] x [Exposure Time]
= [1.12E-3/yr] x [6.1E-4] x [0.25]
= 1.7E-7/yr
Case 2: Seismic Event That Results in a DLOOP and a Break in CW Piping or CW
Expansion Joints
A seismic event can result in the failure of either the CW piping or the CW expansion
joints resulting in turbine building flooding. It is expected that a seismic event will also
result in a DLOOP. Since DLOOP is a consequence of the initiator, the emergency
diesel generator function is required. To obtain a bounding estimate of the delta CDF,
the frequency of a seismic event sufficient to cause plant damage is multiplied by the
probability of failure of either the CW piping or the CW expansion joints due to the
seismic event.
Using guidance from NRCs Risk Assessment Standardization Project (RASP)
handbook, only the Bin 2 seismic events were assumed to represent a CDF. Bin 2
is defined in the RASP handbook as seismic events with intensities greater than 0.3g
but less than 0.5g. Earthquakes of lesser severity are unlikely to result in large pipe
failures and earthquakes of a larger magnitude could result in major structural damage
throughout the plant which would not be representative of a delta risk. The IEF of an
earthquake in Bin 2 was estimated to be 1.6E-5/yr for Byron using Table 4A-1 of
Section 4 of the RASP handbook. To estimate the seismic capacity of the CW piping
and the CW expansion joints, an evaluation of the seismic capacity for CW piping and
expansion joints for another Westinghouse plant was referenced. For this plant, it stated
29
that the CW piping and the CW expansion joints had high seismic capacity, and a
flooding assessment due to seismic concerns was screened from the assessment.
However, making the conservative assumption that the high confidence of low
probability of failure capacity for the CW piping and the CW expansion joints was 0.3g,
a failure probability of 3.9E-2 was obtained for the CW system.
Taking into account the exposure time of 3-months (0.25 years), and assuming that a
Dual Unit LOOP with a failure of both EDGs would result in a core damage event, a
bounding value for the delta CDF for Case 2 is obtained as the product of the following
factors:
Case 2: CDF = [IEF] x [DLOOP] x [CW Failure Probability] x [Exposure Time]
= [1.6E-5/yr] x [1.0] x [3.9E-2] x [0.25]
= 1.6E-7/yr
A bounding CDF of 1.6E-7/yr was estimated for seismically-induced flooding of the
CW piping and CW expansion joints. The final CDF associated with the finding is
obtained as the sum of the delta CDF for both Case 1 and Case 2:
CDF = [1.7E-7/yr] + [1.6E-7] = 3.3E-7/yr
Since the total estimated change in core damage frequency was greater than 1.0E-7/yr,
IMC 0609 Appendix H, Containment Integrity Significance Determination Process
was used to determine the potential risk contribution due to large early release
frequency. Byron Station is a 4-loop Westinghouse pressurized water reactor with a
large dry containment. Sequences important to large early release frequency include
steam generator tube rupture events and inter-system loss-of-coolant-accident events.
These were not the dominant core damage sequences for this finding.
Based on the Detailed Risk Evaluation, the inspectors determined that the finding was of
very low safety-significance (Green).
This finding has a cross-cutting aspect of Conservative Bias in the area of Human
Performance because the licensees decisions regarding disposition of the degraded
condition did not indicate a conservative bias that emphasized prudent choices over
those that were allowable. Even though mechanics identified the potential for the
condition to degrade further in the near future, the work request was not given a high
priority and continued functionality of the door was not evaluated through the next
surveillance period by the licensee. (IMC 0310 H.14)
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures,
and Drawings, requires, in part, that activities affecting quality be prescribed by
documented procedures of a type appropriate to the circumstances and be
accomplished in accordance with these procedures.
Exelon Quality Assurance Topical Report, Chapter 1, Organization, Section 2.4,
identifies operability evaluations as a program element for implementing and/or
reviewing areas of quality of plant operations and nuclear safety. The licensee
established OP-AA-108-115, Revision 13, Operability Determinations, as the
implementing procedure for assessing the operability of SSCs and support functions
for compliance with TSs when a degraded, nonconforming, or unanalyzed condition is
identified, an activity affecting quality.
30
OP-AA-108-115, Operability Determinations (CM-1), identifies that SSCs not
explicitly required to be operable by TS, but that perform required support functions
for SSCs described in TS through the definition of operability are within the scope
OP-AA-108-115. Step 4.1.20 of this procedure requires the functionality assessment
of the SSC be performed and documented. This step is modified by a note that states in
part, For a functionality being performed for a non-TS SSC that supports an SSC
described by TS, operability should be addressed in accordance with step 4.1.4 through
step 4.1.9. The referenced steps require performance and documentation of the
operability determination of the affected SSC.
Contrary to the above, on March 25, 2014, Byron Station failed to implement the
procedural requirements of OP-AA-108-115 for evaluating and documenting the
operability of an SSC described by TS when a degraded condition of a supporting
system was identified that could impact operability. Specifically, no operability
determination was performed for the EDG fuel oil transfer pumps or the EDGs because
the functionality assessment performed by the licensee failed to assess the potential
for the condition to continue to degrade to the point that the door would become
non-functional before the next surveillance was performed. When the degraded
condition was not repaired in this instance, the door was found to be inoperable at the
next surveillance making both Unit 2 EDGs inoperable.
Because this violation was of very low safety significance and it was entered into the
licensees CAP, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC
Enforcement Policy (NCV 05000455/2014005-04, Failure to Evaluate Operability of
a TS SSC Upon Discovery of a Support System Degraded Condition).
The licensees immediate corrective actions on June 25, 2014, included installing a
temporary flood barrier on the doorway and documenting the issue in the CAP as
IR 1675255. The water-tight door was repaired and returned to service on October 5,
2014.
1R19 Post-Maintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed the following post-maintenance testing activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
- modification of the 2C condensate and condensate booster pump lube oil
pressure switch;
- repair of the 2A and 2C reactor containment fan cooler chilled water inlet header
- replacement of the 0A essential service water make-up pump;
- planned maintenance on 1B auxiliary feedwater pump;
- repair of the safety injection actuation relay train A (SARA);
- replacement of the 2B auxiliary feedwater pump power take-off;
- testing of the thermal overloads on the emergency boration valve motor; and
- repair of the 2FW009C valve (2C steam generator feedwater inlet isolation
valve).
31
These activities were selected based upon the SSCs ability to impact risk. The
inspectors evaluated these activities for the following: the effect of testing on the plant
had been adequately addressed; testing was adequate for the maintenance performed;
acceptance criteria were clear and demonstrated operational readiness; test
instrumentation was appropriate; tests were performed as written in accordance with
properly reviewed and approved procedures; equipment was returned to its operational
status following testing (temporary modifications or jumpers required for test
performance were properly removed after test completion); and test documentation was
properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR,
10 CFR Part 50 requirements, licensee procedures, and various NRC generic
communications to ensure that the test results adequately ensured that the equipment
met the licensing basis and design requirements. In addition, the inspectors reviewed
corrective action documents associated with post-maintenance tests to determine
whether the licensee was identifying problems and entering them into the CAP at the
appropriate threshold and correcting the problems commensurate with their importance
to safety.
This inspection constituted eight post-maintenance testing samples as defined in
b. Findings
No findings were identified.
1R20 Outage Activities (71111.20)
.1 Refueling Outage Activities
a. Inspection Scope
The inspectors reviewed the Outage Risk Management Profile and contingency plans for
the Unit 2 refueling outage conducted September 29-October 24, 2014, to confirm that
the licensee had appropriately considered risk, industry experience, and previous site-
specific problems in developing and implementing a plan that assured maintenance of
defense-in-depth. Inspectors review of the Unit 2 shut down and initial outage activities
was previously documented in Byron Station, Units 1 and 2 NRC Integrated Inspection
Report 05000454(455)/2014004.
During the refueling outage, the inspectors monitored licensee controls over the outage
activities listed below:
- configuration management, including maintenance of defense-in-depth
commensurate with the Outage Risk Management Profile for key safety functions
and compliance with the applicable TS when taking equipment out of service;
- implementation of clearance activities and confirmation that tags were properly
hung and equipment appropriately configured to safely support the work or
testing;
- installation and configuration of reactor coolant pressure, level, and temperature
instruments to provide accurate indication, accounting for instrument error;
- status and configuration of electrical systems and switchyard activities to ensure
that TS and Outage Risk Management Profile requirements were met;
32
- monitoring of decay heat removal processes, systems, and components;
- controls to ensure that outage work was not impacting the ability of the operators
to operate the spent fuel pool cooling system;
- reactor water inventory controls including flow paths, configurations, and
alternative means for inventory addition, and controls to prevent inventory loss;
- controls over activities that could affect reactivity;
- maintenance of secondary containment as required by TS;
- licensee fatigue management, as required by 10 CFR 26, Subpart I;
- refueling activities, including fuel handling and sipping to detect fuel assembly
leakage;
- startup and ascension to full power operation, tracking of startup prerequisites,
walkdown of the primary containment to verify that debris had not been left which
could block emergency core cooling system suction strainers, and reactor
physics testing; and
- licensee identification and resolution of problems related to outage activities.
This inspection constituted one refueling outage sample as defined in IP 71111.20-05.
b. Findings
Introduction: Inspectors identified a finding of very low safety significance, Green, when
the licensee impaired a flood protection boundary that supported a required safety
function. Specifically, the licensee removed the flood barriers for auxiliary feedwater
system containment isolation valves and rendered the valves inoperable prior to the
plant reaching mode 5 and thereby entered TS 3.6.3 Condition C for operational
convenience contrary to the TS Bases associated with TS 3.0.2 LCO Applicability.
Description: Technical Specification 3.6.3, Containment Isolation Valves, requires
containment isolation valves to be operable in Modes 1, 2, 3, and 4. On September 28,
2014, Byron Station Unit 2 began lowering power in preparation to take the unit off-line
for refueling. At 08:10 PM, with Unit 2 still in Mode 1, the licensee declared the isolation
valves inoperable and entered Condition C of that TS LCO. The operators then
authorized mechanics to remove the flood barriers for auxiliary feedwater system tunnels
which contain the containment isolation valves for the auxiliary feedwater system,
2AF013A through H. Technical Specification LCO 3.6.3 Condition C was exited at
05:36 AM on September 29 when Unit 2 entered Mode 5 and the LCO was no longer
applicable.
The work to remove the flood seals was scheduled to occur from 10:00 PM on
September 28 to 02:00 AM on September 29, 2014, but no work or other activities were
planned to begin until later in the outage. The unit was scheduled to remain in Mode 1
until midnight (12:00 AM) on September 29 and transition to Mode 3 when the unit was
shut down. The shutdown sequence moved the unit to Mode 4 at 3:53 AM on
September 29 and Mode 5 at 05:36 AM.
While the flood barriers are required to support operability of the valves, risk evaluations
performed for the period were not impacted during the activity because the isolation
function was considered available under the procedures governing equipment
availability.
33
Technical Specification LCO 3.0.2 bases states in part, The reasons for intentionally
relying on the ACTIONS include, but are not limited to, performance of Surveillances,
preventive maintenance, corrective maintenance, or the investigation of operational
problems. Entering ACTIONS for these reasons must be done in a manner that does
not compromise safety. Intentional entry into ACTIONS should not be made for
operational convenience. Alternatives that would not result in redundant equipment
being inoperable should be used instead.
Analysis: The inspectors determined that the licensees intentional entry into LCO
3.6.3.C was for operational convenience and constituted a performance deficiency.
Specifically, the licensee intentionally rendered the auxiliary feedwater system
containment isolation valves inoperable and relied on the LCO action requirements when
they removed the flood barriers prior to the Unit being in a mode where the TS was not
applicable. Since no maintenance or operating activity was required prior to Mode 5,
removal of those barriers was performed solely for operational convenience to support
the outage schedule and was contrary to the LCO 3.0.2 bases. This issue was entered
into the licensees CAP as IR 2390265. Corrective actions included reviewing TS bases
requirements with senior reactor operators and revising the schedule template to include
logic ties for the activity to schedule it after Mode 5.
The inspectors evaluated the performance deficiency in accordance with IMC 0612
Appendix B, Issue Screening. This performance deficiency was not similar to any of the
examples in IMC 0612 Appendix E, Examples of Minor Issues, issued August 11, 2009,
but was characterized as more than minor because it impacted the SSC and Barrier
Performance attribute of the Barrier Integrity Cornerstone; and adversely affected the
cornerstone objective to provide reasonable assurance that the physical design barrier
of the containment system protects the public from radionuclide releases caused by
accidents or events. Specifically, the isolation function of containment was adversely
impacted when isolation valves were made inoperable for operational convenience. The
inspectors determined the finding could be evaluated using the SDP in accordance with
IMC 0609, Appendix A, The Significance Determination Process For Findings At-
Power, Exhibit 3-Barrier Integrity Screening Questions, issued June 19, 2012, item B
for the Reactor Containment. Both questions were answered "No" and therefore the
finding screened as Green.
The inspectors determined that this finding had an associated cross-cutting aspect of
Work Management in the Human Performance area because the shutdown and outage
work schedules did not contain the rigor required to ensure the isolation valves were
maintained operable as required by TS. (MC 0310 H.5)
Enforcement: Enforcement action does not apply because the performance deficiency
did not involve a violation of regulatory requirements. Because this finding does not
involve a violation and has very low safety significance, it is identified as a FIN (FIN
05000455/2014005-05, Containment Penetration Isolation Valves Rendered
Inoperable for Operational Convenience.)
34
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed the test results for the following activities to determine whether
risk-significant systems and equipment were capable of performing their intended safety
function and to verify testing was conducted in accordance with applicable procedural
and TS requirements:
- 2BOSR XII-1; Gaseous Leak Testing of the 2RH01SA/B Valve Containment
Assemblies (Routine);
- 2BOSR 6.1.1-21; Unit Two Primary Containment Type C Local Leakage Rate
Tests and IST (Inservice Test) Tests of Containment Chilled Water System
(Isolation Valve);
- 2BOSR 6.1.1-8; Unit Two Primary Containment Type C Local Leakage Rate
Tests and IST Tests of Primary Sampling System (Isolation Valve);
- 2BVSR 6.1.1-26; Unit 2 Primary Containment Type A Integrated Leakage Rate
Test (Routine); and
- 2BOSR 4.13.1-1; Unit 2 Reactor Coolant System Water Inventory Balance
Surveillance Computer Calculation (RCS Leak Detection)
The inspectors observed in-plant activities and reviewed procedures and associated
records to determine the following:
- did preconditioning occur;
- were the effects of the testing adequately addressed by control room personnel
or engineers prior to the commencement of the testing;
- were acceptance criteria clearly stated, sufficient to demonstrate operational
readiness, and consistent with the system design basis;
- was plant equipment calibration correct, accurate, and properly documented;
- were as-left setpoints within required ranges; and was the calibration frequency
in accordance with TS, the UFSAR, plant procedures, and applicable
commitments;
- was measuring and test equipment calibration current;
- was the test equipment used within the required range and accuracy; and were
applicable prerequisites described in the test procedures satisfied;
- did test frequencies meet TS requirements to demonstrate operability and
reliability;
- were tests performed in accordance with the test procedures and other
applicable procedures;
- were jumpers and lifted leads controlled and restored where used;
- was test data and results accurate, complete, within limits, and valid;
- was test equipment removed following testing;
- where applicable for inservice testing activities, was testing performed in
accordance with the applicable version of Section XI, ASME code, and were
reference values consistent with the system design basis;
- was the unavailability of the tested equipment appropriately considered in the
performance indicator data;
35
- where applicable, were test results not meeting acceptance criteria addressed
with an adequate operability evaluation or was the system or component
declared inoperable;
- where applicable for safety-related instrument control surveillance tests, was the
reference setting data accurately incorporated into the test procedure;
- was equipment returned to a position or status required to support the
performance of its safety functions following testing;
- were problems identified during the testing appropriately documented and
dispositioned in the licensees CAP;
- where applicable, were annunciators and other alarms demonstrated to be
functional and were setpoints consistent with design requirements; and
- where applicable, were alarm response procedure entry points and actions
consistent with the plant design and licensing documents.
This inspection constituted two routine surveillance testing samples, one reactor coolant
system leak detection inspection sample, and two containment isolation valve samples
as defined in IP 71111.22, Sections-02 and-05.
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP2 Alert and Notification System Evaluation (71114.02)
a. Inspection Scope
The inspectors reviewed documents and conducted discussions with Emergency
Preparedness (EP) staff and management regarding the operation, maintenance, and
periodic testing of the primary and backup Alert and Notification System (ANS) in Byron
Stations plume pathway Emergency Planning Zone. The inspectors reviewed monthly
trend reports and the daily and monthly operability records from January 2013 through
July 2014. Information gathered during document reviews and interviews was used to
determine whether the ANS equipment was maintained and tested in accordance with
Emergency Plan commitments and procedures.
This ANS inspection constituted one sample as defined in IP 71114.02-06.
b. Findings
No findings were identified.
1EP3 Emergency Response Organization Staffing and Augmentation System (71114.03)
a. Inspection Scope
The inspectors reviewed and discussed with EP staff and management the Emergency
Plan commitments and Emergency Response Organization (ERO) on-shift and
augmentation staffing levels. A sample of 27 ERO training records for personnel
assigned to key and support positions were reviewed to determine the status of their
training as it related to their assigned ERO positions. The inspectors reviewed the ERO
36
augmentation system and activation process, the primary and alternate methods of
initiating ERO activation, unannounced off-hour augmentation tests from August 2012
through October 2014, and the provisions for maintaining the plants ERO roster. The
inspectors reviewed a sample of corrective actions related to the facilitys ERO staffing
and augmentation system program and activities from August 2012 through October
2014 to determine whether corrective actions were completed in accordance with the
site's CAP.
This ERO augmentation testing inspection constituted one sample as defined in
b. Findings
No findings were identified.
1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)
a. Inspection Scope
The regional inspectors performed an in-office review of the latest revisions to the
Emergency Plan, Emergency Plan Annex, and Emergency Plan Implementing
Procedures as listed in the Attachment to this report.
The licensee transmitted the Emergency Plan and Emergency Action Level revisions to
the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V,
Implementing Procedures. The NRC review was not documented in a Safety
Evaluation Report and did not constitute approval of licensee-generated changes;
therefore, this revision is subject to future inspection. The specific documents reviewed
during this inspection are listed in the Attachment to this report.
This Emergency Action Level and Emergency Plan Change Inspection constituted one
sample as defined in IP 71114.04 06.
b. Findings
No findings were identified.
1EP5 Maintenance of Emergency Preparedness (71114.05)
a. Inspection Scope
The inspectors reviewed a sample of nuclear oversight staffs audits of the EP Program
to determine whether these independent assessments met the requirements of
10 CFR 50.54(t). The inspectors also reviewed critique reports and samples of CAP
records associated with the 2013 Biennial Exercise, as well as various EP drills
conducted in 2013 and 2014; in order to determine whether the licensee fulfilled drill
commitments and to evaluate the licensees efforts to identify, track, and resolve issues
identified during these activities. The inspectors reviewed a sample of EP items and
corrective actions related to the licensee's EP Program and activities to determine
whether corrective actions were completed, in accordance with the sites CAP.
37
This correction of EP weaknesses and deficiencies inspection constituted one sample as
defined in IP 71114.05-06.
b. Findings
No findings were identified.
2. RADIATION SAFETY
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01)
The inspection activities supplement those documented in Inspection Report
05000454(455)/2014002 and constitute one complete sample as defined in
.1 Inspection Planning (02.01)
a. Inspection Scope
The inspectors reviewed all licensee performance indicators for the Occupational
Exposure Cornerstone for follow-up. The inspectors reviewed the results of Radiation
Protection Program audits (e.g., licensees quality assurance audits or other
independent audits). The inspectors reviewed any reports of operational occurrences
related to occupational radiation safety since the last inspection. The inspectors
reviewed the results of the audit and operational report reviews to gain insights into
overall licensee performance.
b. Findings
No findings were identified.
.2 Instructions to Workers (02.03)
a. Inspection Scope
The inspectors reviewed selected occurrences where a workers electronic personal
dosimeter noticeably malfunctioned or alarmed. The inspectors evaluated whether
workers responded appropriately to the off-normal condition. The inspectors assessed
whether the issue was included in the CAP and dose evaluations were conducted as
appropriate.
b. Findings
No findings were identified.
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.3 Contamination and Radioactive Material Control (02.04)
a. Inspection Scope
The inspectors reviewed the licensees criteria for the survey and release of potentially
contaminated material. The inspectors evaluated whether there was guidance on how to
respond to an alarm that indicates the presence of licensed radioactive material.
The inspectors reviewed the licensees procedures and records to verify that the
radiation detection instrumentation was used at its typical sensitivity level based on
appropriate counting parameters. The inspectors assessed whether or not the licensee
has established a de facto release limit by altering the instruments typical sensitivity
through such methods as raising the energy discriminator level or locating the instrument
in a high-radiation background area.
The inspectors selected several sealed sources from the licensees inventory records
and assessed whether the sources were accounted for and verified to be intact.
The inspectors evaluated whether any transactions, since the last inspection, involving
nationally tracked sources were reported in accordance with 10 CFR 20.2207.
b. Findings
No findings were identified.
.4 Radiological Hazards Control and Work Coverage (02.05)
a. Inspection Scope
The inspectors assessed whether radiation monitoring devices were placed on the
individuals body consistent with licensee procedures. The inspectors assessed whether
the dosimeter was placed in the location of highest expected dose or that the licensee
properly employed an NRC-approved method of determining effective dose equivalent.
The inspectors reviewed the application of dosimetry to effectively monitor exposure to
personnel in high radiation work areas with significant dose rate gradients.
The inspectors examined the licensees physical and programmatic controls for
highly activated or contaminated materials (i.e., nonfuel) stored within spent fuel
and other storage pools. The inspectors assessed whether appropriate controls
(i.e., administrative and physical controls) were in place to preclude inadvertent removal
of these materials from the pool.
The inspectors examined the posting and physical controls for selected high radiation
areas and very-high radiation areas to verify conformance with the occupational
performance indicator.
b. Findings
No findings were identified.
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.5 Risk Significant High Radiation Area and Very-High Radiation Area Controls (02.06)
a. Inspection Scope
The inspectors discussed with the radiation protection manager the controls and
procedures for high-risk, high radiation areas and very-high radiation areas. The
inspectors discussed methods employed by the licensee to provide stricter control of
very-high radiation area access as specified in 10 CFR 20.1602, Control of Access to
Very-High Radiation Areas, and Regulatory Guide 8.38, Control of Access to High and
Very-High Radiation Areas of Nuclear Plants. The inspectors assessed whether any
changes to licensee procedures substantially reduce the effectiveness and level of
worker protection.
The inspectors discussed the controls in place for special areas that have the potential
to become very high radiation areas during certain plant operations with first-line
health physics supervisors (or equivalent positions having backshift health physics
oversight authority). The inspectors assessed whether these plant operations require
communication beforehand with the health physics group, so as to allow corresponding
timely actions to properly post, control, and monitor the radiation hazards including
re-access authorization.
The inspectors evaluated licensee controls for very-high radiation areas and areas with
the potential to become very-high radiation areas to ensure that an individual was not
able to gain unauthorized access to the very-high radiation areas.
b. Findings
No findings were identified.
.6 Radiation Worker Performance (02.07)
a. Inspection Scope
The inspectors reviewed radiological problem reports since the last inspection that found
the cause of the event to be human performance errors. The inspectors evaluated
whether there was an observable pattern traceable to a similar cause. The inspectors
assessed whether this perspective matched the corrective action approach taken by the
licensee to resolve the reported problems. The inspectors discussed with the radiation
protection manager any problems with the corrective actions planned or taken.
b. Findings
No findings were identified.
.7 Radiation Protection Technician Proficiency (02.08)
a. Inspection Scope
The inspectors reviewed radiological problem reports since the last inspection that found
the cause of the event to be radiation protection technician error. The inspectors
40
evaluated whether there was an observable pattern traceable to a similar cause. The
inspectors assessed whether this perspective matched the corrective action approach
taken by the licensee to resolve the reported problems.
b. Findings
No findings were identified.
.8 Problem Identification and Resolution (02.09)
a. Inspection Scope
The inspectors evaluated whether problems associated with radiation monitoring and
exposure control were being identified by the licensee at an appropriate threshold and
were properly addressed for resolution in the licensees CAP. The inspectors assessed
the appropriateness of the corrective actions for a selected sample of problems
documented by the licensee that involve radiation monitoring and exposure controls.
The inspectors assessed the licensees process for applying operating experience to
their plant.
b. Findings
No findings were identified.
4. OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
4OA1 Performance Indicator Verification (71151)
.1 Mitigating Systems Performance Index-Emergency Alternating Current Power System
a. Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index (MSPI)-Emergency Alternating Current Power System Performance Indicator (PI)
(MS06) for Byron Station Units 1 and 2 for the period from the fourth quarter 2013
through the third quarter 2014. To determine the accuracy of the PI data reported during
those periods, guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, was
used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation
reports, IRs, event reports and NRC Integrated Inspection Reports for the period of
October 2013 through September 2014 to validate the accuracy of the submittals. The
inspectors reviewed the MSPI component risk coefficient to determine if it had changed
by more than 25 percent in value since the previous inspection, and if so, that the
change was in accordance with applicable NEI guidance. The inspectors also reviewed
the licensees CAP to determine if any problems had been identified with the PI data
collected or transmitted for this indicator and none were identified.
41
This inspection constituted two MSPI emergency AC power system samples as defined
in IP 71151-05.
b. Findings
No findings were identified.
.2 Mitigating Systems Performance Index-High Pressure Injection Systems
a. Inspection Scope
The inspectors sampled licensee submittals for the MSPI-High Pressure Injection
Systems PI (MS07) for Byron Station Units 1 and 2 for the period from the fourth quarter
2013 through the third quarter 2014. To determine the accuracy of the PI data reported
during those periods, guidance contained in NEI 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 7, dated August 31, 2013, was used. The
inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, IRs,
event reports and NRC Integrated Inspection Reports for the period of October 2013
through September 2014 to validate the accuracy of the submittals. The inspectors
reviewed the MSPI component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable NEI guidance. The inspectors also reviewed the licensees
CAP to determine if any problems had been identified with the PI data collected or
transmitted for this indicator and none were identified.
This inspection constituted two MSPI high pressure injection system samples as defined
in IP 71151-05.
b. Findings
No findings were identified.
.3 Mitigating Systems Performance Index-Heat Removal System
a. Inspection Scope
The inspectors sampled licensee submittals for the MSPI-Heat Removal System PI
(MS08) for Byron Station Units 1 and 2 for the period from the fourth quarter 2013
through the third quarter 2014. To determine the accuracy of the PI data reported during
those periods, guidance contained in NEI 99-02, Regulatory Assessment Performance
Indicator Guideline, Revision 7, dated August 31, 2013, was used. The inspectors
reviewed the licensees operator narrative logs, MSPI derivation reports, IRs, event
reports and NRC Integrated Inspection Reports for the period of October 2013 through
September 2014 to validate the accuracy of the submittals. The inspectors reviewed the
MSPI component risk coefficient to determine if it had changed by more than 25 percent
in value since the previous inspection, and if so, that the change was in accordance with
applicable NEI guidance. The inspectors also reviewed the licensees CAP to determine
if any problems had been identified with the PI data collected or transmitted for this
indicator and none were identified.
This inspection constituted two MSPI heat removal system samples as defined in
42
b. Findings
No findings were identified.
.4 Mitigating Systems Performance Index-Residual Heat Removal System
a. Inspection Scope
The inspectors sampled licensee submittals for the MSPI-Residual Heat Removal
System PI (MS09) for Byron Station Units 1 and 2 for the period from the fourth quarter
2013 through the third quarter 2014. To determine the accuracy of the PI data reported
during those periods, guidance contained in NEI 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 7, dated August 31, 2013, was used. The
inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, IRs,
event reports and NRC Integrated Inspection Reports for the period of October 2013
through September 2014 to validate the accuracy of the submittals. The inspectors
reviewed the MSPI component risk coefficient to determine if it had changed by more
than 25 percent in value since the previous inspection, and if so, that the change was in
accordance with applicable NEI guidance. The inspectors also reviewed the licensees
CAP to determine if any problems had been identified with the PI data collected or
transmitted for this indicator and none were identified.
This inspection constituted two MSPI residual heat removal system samples as defined
in IP 71151-05.
b. Findings
No findings were identified.
.5 Mitigating Systems Performance Index-Cooling Water Systems
a. Inspection Scope
The inspectors sampled licensee submittals for the MSPI-Cooling Water Systems PI
(MS10) for Byron Station Units 1 and 2 for the period from the fourth quarter 2013
through the third quarter 2014. To determine the accuracy of the PI data reported during
those periods, guidance contained in NEI 99-02, Regulatory Assessment Performance
Indicator Guideline, Revision 7, dated August 31, 2013, was used. The inspectors
reviewed the licensees operator narrative logs, MSPI derivation reports, IRs, event
reports and NRC Integrated Inspection Reports for the period of October 2013 through
September 2014 to validate the accuracy of the submittals. The inspectors reviewed the
MSPI component risk coefficient to determine if it had changed by more than 25 percent
in value since the previous inspection, and if so, that the change was in accordance with
applicable NEI guidance. The inspectors also reviewed the licensees CAP to determine
if any problems had been identified with the PI data collected or transmitted for this
indicator and none were identified.
This inspection constituted two MSPI cooling water system samples as defined in
43
b. Findings
No findings were identified.
.6 Occupational Exposure Control Effectiveness
a. Inspection Scope
The inspectors sampled licensee submittals for the Occupational Exposure Control
Effectiveness PI (OR01) for the period from the third quarter 2013 through the third
quarter 2014. The inspectors used guidance contained in NEI 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 7, dated August 2013, to
determine the accuracy of the Performance Indicator data reported during those periods.
The inspectors reviewed the licensees assessment of the PI for occupational radiation
safety to determine if the indicator related data was adequately assessed and reported.
The inspectors discussed with radiation protection staff the scope and breadth of its data
review and the results of those reviews; to assess the adequacy of the licensees PI data
collection and analyses. The inspectors independently reviewed electronic personal
dosimetry dose rate and accumulated dose alarms and dose reports and the dose
assignments for any intakes that occurred during the time period reviewed to determine
if there were potentially unrecognized occurrences. The inspectors also conducted
walkdowns of numerous locked high and very-high radiation area entrances to
determine the adequacy of the controls in place for these areas.
This inspection constituted one occupational exposure control effectiveness sample as
defined in IP 71151-05.
b. Findings
No findings were identified.
.7 Reactor Coolant System Specific Activity
a. Inspection Scope
The inspectors sampled licensee submittals for the Reactor Coolant System Specific
Activity PI (BI01) for Byron Station Units 1 and 2 for the period from the third quarter
2013 through the third quarter 2014. The inspectors used guidance contained in
NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7,
dated August 2013, to determine the accuracy of the PI data reported during those
periods. The inspectors reviewed the licensees reactor coolant system chemistry
samples, TS requirements, IRs, event reports and NRC Integrated Inspection Reports to
validate the accuracy of the submittals. The inspectors also reviewed the licensees
CAP to determine if any problems had been identified with the PI data collected or
transmitted for this indicator and none were identified. In addition to record reviews, the
inspectors observed a chemistry technician obtain and analyze a reactor coolant system
sample.
This inspection constituted two reactor coolant system specific activity samples as
defined in IP 71151-05.
44
b. Findings
No findings were identified.
.8 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual
Radiological Effluent Occurrences
a. Inspection Scope
The inspectors sampled licensee submittals for the Radiological Effluent Technical
Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences PI
(PR01) for the period from the third quarter 2013 through the fourth quarter 2014. The
inspectors used guidance contained in NEI 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 7, dated August 2013, to determine the
accuracy of the PI data reported during those periods. The inspectors reviewed the
licensees CAP and selected individual reports generated since this indicator was last
reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or
improperly calculated effluent releases that may have impacted offsite dose. The
inspectors reviewed gaseous effluent summary data and the results of associated offsite
dose calculations for selected dates to determine if indicator results were accurately
reported. The inspectors also reviewed the licensees methods for quantifying gaseous
and liquid effluents, and determining effluent dose.
This inspection constituted one Radiological Effluent Technical Specification/Offsite
Dose Calculation Manual Radiological Effluent Occurrences sample as defined in IP
71151 05.
b. Findings
No findings were identified.
.9 Drill/Exercise Performance
a. Inspection Scope
The inspectors sampled licensee submittals for the Drill/Exercise Performance
PI (EP01) for the period from the fourth quarter 2013 through the second quarter 2014.
Guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator
Guideline, Revision 7, was used to determine the accuracy of the PI data reported
during those periods. The inspectors reviewed the licensees records and processes
associated with the PI to verify the licensee accurately reported the DEP indicator in
accordance with licensee procedures and NEI guidance. Specifically, the inspectors
reviewed licensee records, processes, and procedural guidance for assessing
opportunities, including control room simulator training sessions, the 2013 Biennial
Exercise, and other drills during this period. The inspectors also reviewed the licensees
CAP to determine if problems had been identified and corrected.
This inspection constitutes one DEP sample as defined in IP 71151-05.
b. Findings
No findings were identified.
45
.10 Emergency Response Organization Drill Participation
a. Inspection Scope
The inspectors sampled licensee submittals for the ERO Drill Participation PI (EP02)
for the period from the fourth quarter 2013 through the second quarter 2014. The
inspectors used guidance contained in NEI 99-02, Regulatory Assessment
Performance Indicator Guideline, Revision 7, dated August 2013, to determine the
accuracy of the PI data reported during those periods. The inspectors reviewed the
licensees records associated with the PI to verify that the licensee accurately reported
the indicator in accordance with relevant procedures and NEI guidance. Specifically, the
inspectors reviewed licensee records and processes, including procedural guidance on
assessing opportunities for the PI, performance during the 2013 Biennial Exercise, drills,
and revisions of the roster of personnel assigned to key ERO positions. The inspectors
also reviewed the licensees CAP to determine if problems had been identified and
corrected.
This inspection constitutes one ERO drill participation sample as defined in
b. Findings
No findings were identified.
.11 Alert and Notification System Reliability
a. Inspection Scope
The inspectors sampled licensee submittals for the ANS PI (EP03) for the period from
the fourth quarter 2013 through the second quarter 2014. The inspectors used guidance
contained in the NEI 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 7, dated August 2013, to determine the accuracy of the PI data reported during
those periods. The inspectors reviewed the licensees records associated with the PI to
verify that the licensee accurately reported the indicator in accordance with relevant
procedures and NEI guidance. Specifically, the inspectors reviewed licensee records
and processes for assessing opportunities for the PI and results of periodic ANS
operability tests. The inspectors also reviewed the licensees CAP to determine whether
the problems had been identified and corrected.
This inspection constitutes one ANS sample as defined in IP 71151-05.
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems (71152)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
46
.1 Routine Review of Items Entered into the Corrective Action Program
a. Inspection Scope
As part of the various baseline inspection procedures discussed in previous sections of
this report, the inspectors routinely reviewed issues during baseline inspection activities
and plant status reviews to verify they were being entered into the licensees CAP at an
appropriate threshold, that adequate attention was being given to timely corrective
actions, and that adverse trends were identified and addressed. Attributes reviewed
included: identification of the problem was complete and accurate; timeliness was
commensurate with the safety significance; evaluation and disposition of performance
issues, generic implications, common causes, contributing factors, root causes,
extent-of-condition reviews, and previous occurrences reviews were proper and
adequate; and that the classification, prioritization, focus, and timeliness of corrective
actions were commensurate with safety and sufficient to prevent recurrence of the issue.
Minor issues entered into the licensees CAP as a result of the inspectors observations
are included in the Attachment to this report.
These routine reviews for the identification and resolution of problems did not constitute
any additional inspection samples. Instead, by procedure they were considered an
integral part of the inspections performed during the quarter and documented in
Section 1 of this report.
b. Findings
No findings were identified.
.2 Daily Corrective Action Program Reviews
a. Inspection Scope
In order to assist with the identification of repetitive equipment failures and specific
human performance issues for follow-up, the inspectors performed a daily screening of
items entered into the licensees CAP. This review was accomplished through
inspection of the stations daily IR packages.
These daily reviews were performed by procedure as part of the inspectors daily plant
status monitoring activities and, as such, did not constitute any separate inspection
samples.
b. Findings
No findings were identified.
.3 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a review of the licensees CAP and associated documents to
identify trends that could indicate the existence of a more significant safety issue. The
inspectors review was focused on repetitive equipment issues, but also considered the
results of daily inspector CAP item screening discussed in Section 4OA2.2 above,
47
licensee trending efforts, and licensee human performance results. The inspectors
review nominally considered the 6-month period of June 1, 2014, through November 30,
2014, although some examples expanded beyond those dates where the scope of the
trend warranted.
The review also included issues documented outside the normal CAP in major
equipment problem lists, repetitive and/or rework maintenance lists, departmental
problem/challenges lists, system health reports, quality assurance audit/surveillance
reports, self-assessment reports, and Maintenance Rule assessments. The inspectors
compared and contrasted their results with the results contained in the licensees
CAP trending reports. Corrective actions associated with a sample of the issues
identified in the licensees trending reports were reviewed for adequacy.
This review constituted one semi-annual trend inspection sample as defined in
b. Findings
No findings were identified.
.4 Annual Sample: Review of Operator Workarounds
a. Inspection Scope
The inspectors evaluated the licensees implementation of their process used to identify,
document, track, and resolve operational challenges. Minutes from the operator
workarounds (OWA) committee meetings were reviewed to verify the licensee was
meeting the station procedural requirements and were considering the appropriate
deficiencies when determining operator challenges. Inspection activities included, but
were not limited to, a review of the cumulative effects of the OWAs on system availability
and the potential for improper operation of the system, for potential impacts on multiple
systems, and on the ability of operators to respond to plant transients or accidents.
The inspectors reviewed both current and historical operational challenge records to
determine whether the licensee was identifying operator challenges at an appropriate
threshold, had entered them into their CAP, and proposed or implemented appropriate
and timely corrective actions which addressed each issue. Reviews were conducted to
determine if any operator challenge could increase the possibility of an Initiating Event, if
the challenge was contrary to training, required a change from long-standing operational
practices, or created the potential for inappropriate compensatory actions. Additionally,
all temporary modifications were reviewed to identify any potential effect on the
functionality of Mitigating Systems, impaired access to equipment, or required equipment
uses for which the equipment was not designed. Daily plant and equipment status logs,
degraded equipment logs, and operator aids or tools being used to compensate for
material deficiencies were also assessed to identify any potential sources of unidentified
operator workarounds. Electronic searches of the CAP documentation were also
performed to identify timeliness of corrective actions for any chronic or long term
equipment issues identified in other reviews.
This review constituted one operator workaround annual inspection sample as defined in
48
b. Findings
No findings were identified.
.5 Selected Issue Follow Up Inspection: Corrective Actions Unit 2 Stuck Reactor Vessel
Stud No. 11
a. Inspection Scope
On October 1, 2014, the licensee applied specialized vendor tooling and removed the
Unit 2 stuck reactor vessel stud at location No. 11, which had been abandoned in place
since May of 2002. Following stud removal, the inspectors observed the licensee
performing a visual examination with the aid of a boroscope, to determine the condition
of the stud threads and cavity below the stud No. 11. The licensee identified and
removed loose corrosion products and debris with the aid of a vacuum and then used a
special cleaning tool to remove adherent corrosion/boric acid products fixed to the
bottom of the flange stud hole. Samples of the adherent corrosion product debris were
obtained by the licensee for analysis. The analysis results determined that in excess of
1000 ppm boron was present in this debris indicating that borated water had been
present under the abandon head stud. The licensee documented the corrosion and
debris at this stud hole No. 11 location in IR 02389646. The inspectors assessed the
following attributes during review of the licensee corrective actions associated with this
issue:
- complete and accurate identification of the problem in a timely manner
commensurate with its safety significance and ease of discovery;
- consideration of the extent of condition, generic implications, common cause and
previous occurrences;
- evaluation and disposition of operability/reportability issues;
- classification and prioritization of the resolution of the problem, commensurate
with safety significance;
- identification of the apparent and/or contributing causes of the problem; and
- identification of corrective actions, which were appropriately focused to correct
the problem.
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b. Findings
No findings were identified.
.6 Selected Issue Follow-Up Inspection: Failure to Implement Compensatory Actions Per
Plant Barrier Impairment Authorization When Flood Barrier Removed For SX pump
Work.
a. Inspection Scope
During a review of items entered in the licensees CAP, the inspectors recognized an IR
documenting failure of plant staff to implement compensatory actions before they
impaired a flood barrier. Issue Report 2406628 documented that operations staff
authorized removal of the floor plug forming the flood barrier without verifying that the
49
compensatory actions required by Plant Barrier Impairment Permit (PBI)14-334 were
complete. The barrier was impaired for 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> before the operators recognized that
the compensatory actions had not been verified. The PBI specified two compensatory
actions: (1) close the discharge valve for the affected pump; and (2) close the applicable
valve pit floor drain. The inspectors determined that the discharge valve had been
closed for pump maintenance prior to the plug removal so this action had been
completed prior to barrier impairment.
The valve pit floor drain had not been previously closed, but was closed when the
omission was discovered. The hazard to be mitigated in this condition is flooding on the
346 foot elevation of the auxiliary building that would fill the valve pit, drain into the floor
drain system and back up into the pump room after sump pump failure. The inspector
reviewed the flooding analysis and piping/room drawings and while this scenario is
possible it is not considered likely to occur. The second compensatory action is a
prudent action, but would not impact the essential service water pumps.
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b. Findings
The performance deficiency and enforcement aspects of this issue are discussed in
Section 4AO7.2 of this report.
.7 Selected Issue Follow-Up Inspection: Inoperable Fire Door Due To Bent Astragal On
Double Door.
a. Inspection Scope
During a review of items entered in the licensees CAP, the inspectors recognized a
corrective action item documenting an inoperable fire door due to a partially detached
and bent astragal on the door. Issue Report 2398582 documented that on October 22,
2014, the astragal on a double door, which is designated as a fire door, was bent out
from the door allowing an open area between the stationary door and the active door.
This gap caused the fire door to be declared inoperable in accordance with Technical
Requirement Manual 3.10.g, and an hourly fire watch was instituted until the astragal
was repaired. The inspectors identified that there were five IRs documented in a
3-month span involving the astragal on this fire door. The first three of these IRs did
not identify the deficient astragal to be impairment to the fire barrier, and one was
documented 2-days before the door was declared inoperable. These IRs were all closed
to work orders and no compensatory actions were taken. After the door was declared
inoperable on October 22, 2014, maintenance attempted to repair the door, but the
astragal became detached and bent again, so another IR was documented, and a
modification was made to the door to prevent further damage to the astragal.
After further review by the inspectors and the licensee, the licensee determined that the
decision to call the fire door inoperable on October 22, 2014, was a conservative
decision, and that the deficient astragal did not actually render the fire door inoperable.
Therefore, no compensatory measures were required.
While the operability of the fire door was not impacted by the degraded astragal, the
inspectors identified that the documented functional basis for two of the CAP documents
50
(IRs 2390927 and 2398582) did not contain the detail prescribed in OP-AA-108-115,
Operability Determinations (CM-1), as they did not describe the effect of the degraded
condition on the SSCs ability to perform its specified function. The inspectors reviewed
this performance deficiency using the criteria contained in NRC IMC 0612, Appendix B,
Issue Screening, and determined the issue was not more than minor.
The inspectors reviewed the logs and work orders related to this door, as well as the
surveillance procedure and acceptance criteria for the door. The inspectors assessed
the following attributes during review of the licensee corrective actions associated with
this issue:
- complete, accurate, and timely documentation of the identified problem in the
corrective action program;
- evaluation and timely disposition of operability and reportability issues;
- consideration of extent of condition and cause, generic implications, common
cause, and previous occurrences;
- completion of corrective actions in a timely manner commensurate with the
safety significance of the issue; and,
- action taken results in the correction of the identified problem.
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153)
.1 (Closed) Licensee Event Report 05000454/2014-002: Non-Compliance with Technical
Specification 3.4.3, RCS [Reactor Coolant System] Pressure and Temperature Limits
Byron Station reported this issue on April 10, 2014, after receiving a Pressurized Water
Reactor Owners Group letter discussing an operation at another power plant impacting
RCS pressure using vacuum filling operations. TS 3.4.3 LCO is applicable at all times
and states, RCS pressure, RCS temperature, and RCS heatup and cooldown rates
shall be maintained within the limits specified in the PTLR (Pressure Temperature Limits
Report.) At Byron, the PTLR contains the curves that depict the operating limits and is
contained in the technical requirements manual. The lower bound of these curves was
zero pounds per square inch gauge (0 psig). Byron staff recognized that the site had
been using a vacuum fill operation to fill RCS piping since 2011 using Byron procedure
BOP RC-9 which provides instructions for using vacuum to fill RCS piping in Mode 5
and would allow pressure as low as 28.5 inches of mercury or a pressure of about
negative 14 psig.
After review, the inspectors concluded that this condition did not represent a violation of
the TS LCO, but did represent a condition outside of the parameters used in the analysis
used by Westinghouse to generate the PTLR curves. Westinghouse performed the
additional analysis needed to expand the lower value of the curves and revised the
PTLR at the licensees request. The revised curves for Unit 1 and Unit 2 were
electronically submitted to the NRC on March 27, 2014, under Byron transmittal letter
The enforcement aspects of this event are discussed in Section 4OA7.1 of this report.
This LER is closed.
51
This event follow-up review constituted one sample as defined in IP 71153-05.
.2 (Closed) Licensee Event Report 05000455/2014-004-00; Byron Unit 2 Reactor
Pressure Vessel Head Control Rod Drive Mechanism Penetration Nozzle Weld
Indication Attributed to Primary Water Stress Corrosion Cracking
On October 7, 2014, an indication was discovered on Unit 2 Head Penetration No. 6.
The indication was located on the outside diameter of the penetration tube and the
deepest wall depth was 0.222 inches, approximately 34.11 percent through wall.
The indication was subsequently repaired using the embedded flaw technique in
accordance with NRC approved WCAP-15987, Revision 2-A and WCAP-16401,
Revision 0. The apparent cause of the indication is attributed to Primary Water Stress
Corrosion Cracking. Corrective actions including repair of the indication on Penetration
No. 6 and revision of the inspection frequency of the Unit 2 volumetric examinations on
all 78 reactor pressure vessel penetrations to every refueling outage. Inspectors
observed repair activities and considered the actions taken to be appropriate. Additional
information regarding these repair activities was included in Section 1R08 of this report.
This LER is closed.
This event follow-up review constituted one sample as defined in IP 71153-05.
4OA5 Other Activities
.1 (Closed) Unresolved Item 05000454/2012008-02, 05000455/2012008-02, Operability
Determination Procedure Implementation Concerns
As documented in NRC Special Inspection Team (SIT) Report 05000455/2012008,
inspectors identified a concern related to the implementation of procedure
OP-AA-108-115, Operability Determinations (CM-1), Revision 11. Specifically, the
inspectors questioned whether OP-AA-108-115 was properly implemented since an
operability determination was not performed upon discovery of the design vulnerability
that was the subject of the inspection.
The special inspection reviewed the circumstances surrounding the January 30, 2012,
electrical insulator failure in the Byron switchyard that resulted in a Unit 2 automatic reactor trip and Notice of Unusual Event emergency declaration. The licensee identified
that the insulator failure resulted in a loss of a single phase on the offsite supply line to
Unit 2 and resulted in a degraded voltage condition that did not automatically disconnect
the safety busses and start the emergency diesel generators. Operators took manual
actions to open the offsite supply breaker, creating the bus undervoltage condition and
the diesels automatically transferred to energize the busses. The licensee entered the
issue into the CAP as IR 1319908 and declared the offsite line inoperable.
Following the prompt review of the event sequence, the licensee initiated IR 1322212
documenting the design vulnerability and providing an operability evaluation of the SSCs
covered by TS 3.3.5, Loss of Power Diesel Generator Start Instrumentation, based on
engineering judgment. The operators then assigned an action to engineering to provide
a more detailed technical basis for operability (i.e., an Operability Evaluation). The
licensee concluded that because the undervoltage protection system functioned as
designed, and because the NRC had reviewed and approved the design, the
requirements of TS 3.3.5 were met and the identified design vulnerability in the
52
undervoltage/degraded voltage protection scheme did not impact operability of the
undervoltage/degraded voltage protection. This decision was based largely on the
licensees position that the event was outside of their CLB or beyond the design basis.
The completed Operability Evaluation supported the original engineering judgment
conclusion. The question regarding whether the undervoltage and degraded voltage
protection design vulnerability met the requirements of general design criteria 17 and
was therefore within the stations CLB is currently under review by NRR and is being
tracked by unresolved item (URI)05000454/2012008-001, 05000455/2012008-001;
Inadequate Undervoltage Protection.
The inspectors were concerned with the licensees conclusion that the undervoltage and
degraded voltage protection systems remained operable since it appeared that the
design would not adequately mitigate a loss of A or C phase event in the absence of
operator action, which appeared to not satisfy the intent of the undervoltage and
degraded voltage protection systems to ensure that engineered safety feature (ESF)
Busses 241 and 242 were powered from either offsite power or automatically transferred
to the DGs. The inspectors identified an URI related to the implementation of operability
determination procedure OP-AA-108-115. Specifically, the inspectors questioned
whether OP-AA-108-115 was properly implemented since an operability determination
for the undervoltage and degraded voltage protection circuits was not performed upon
discovery that the undervoltage protection scheme did not disconnect the ESF busses
from the grid following a loss of a single phase. The special inspection team provided
specific insights into weaknesses in OP-AA-108-115 during the inspection. The
Inspectors review of Revision 13 of that procedure indicated that all of the teams
comments on the procedure weaknesses have since been corrected.
Inspectors have determined that the operability determinations were conducted in
accordance with Revision 11 of the procedure and that the licensees conclusions
regarding the stations understanding of the licensing basis were included in those
determinations and supporting documents. Inspector identified weaknesses in
OP-AA-108-115 have been corrected. No findings were identified. This URI is closed.
.2 (Closed) Unresolved Item 05000454/2012008-03, 05000455/2012008-03, Potential
Missed Opportunities to Identify a Latent Undervoltage Design Issue
As documented in NRC SIT Report 05000455/2012008, inspectors identified a concern
related to potential missed opportunities to identify the ESF undervoltage protection
design vulnerability through the use of operating experience. The licensee entered the
unresolved item into the CAP as IR 1327770 and asked the corporate operating
experience group to answer a series of questions concerning the operating experience
review conducted for other insulator issues that have occurred in the industry. Examples
of past single phase failures were reviewed to determine if the design vulnerability
should have been identified before this event in January 2012. Issue Reports 1325488
and 1327246 documented additional operating experience reviews performed. The
licensee concluded that the initial reviews were correct in their evaluation that Byron had
already implemented the actions recommended by the applicable operating experience
and in fact had a more robust program looking for switchyard deficiencies than that
recommended by the operating experience documents. One issue identified by the
licensee review is that the operating experience did not drive the industry as a whole to
review single phase protection schemes. Instead, the operating experience documents
focused on monitoring and identifying the failure rather than ensuring that the protection
53
scheme was robust enough to identify the failure and activate protective relays. The
licensee reviews also concluded that design vulnerabilities beyond the component level
defect were not considered credible since a single phase failure was concluded to be
beyond design bases.
After discussion with NRC regional management, inspectors determined that
URI 05000454/2012008-001, 05000455/2012008-001; Inadequate Undervoltage
Protection, is sufficient to track resolution of the overall issue as the design compliance
with GDC-17 and the Byron licensing bases remain under review by NRR. The licensee
implemented additional challenge reviews of operating experience reviews performed at
the station and implemented a modification that added protective relays to detect an
open single phase condition on the offsite power feed and automatically trip the offsite
power feed to the ESF buses on a single open-phase signal. This URI is closed.
4OA6 Management Meetings
.1 Exit Meeting Summary
On January 6, 2015, the inspectors presented the inspection results to Mr. R. Kearney
and other members of the licensee staff. The licensee acknowledged the issues
presented. The inspectors confirmed that none of the potential report input discussed
was considered proprietary.
.2 Interim Exit Meetings
Interim exits were conducted for:
- the inspection results of the inservice inspection with Mr. R. Kearney, Site Vice
President, on October 10, 2014.
- the inspection results for the areas of radiological hazard assessment and
exposure controls; and occupational exposure control effectiveness performance
indicator verification with Mr. R. Kearney on October 10, 2014;
- the inspection results of the EP area inspections with Mr. R. Kearney
conducted at the site on October 24, 2014;
- inspection observations during annual operating test with Mr. M. McCue,
Operations Training Manager, and other members of the licensee staff on
November 5, 2014;
- the annual review of Emergency Action Level and Emergency Plan Changes with
the licensee's emergency preparedness coordinator, Mr. R. Lloyd, via telephone
on December 3, 2014; and
- overall pass/fail results of the biennial written examination and annual operating
test via telephone between T. Sanders, LORT Lead, and M. Bielby, Senior
Operations Inspector, on December 15, 2014.
The licensee acknowledged the issues presented. The inspectors confirmed that none
of the potential report input discussed was considered proprietary.
54
4OA7 Licensee-Identified Violations
The following violations of very low significance (Green) were identified by the licensee
and are violations of NRC requirements which meet the criteria of the NRC Enforcement
Policy for being dispositioned as an NCV.
1. On February 1, 2014, the licensee identified that vacuum pressures were used to fill
RCS piping multiple times since 1998 resulting in RCS system pressures below 0
psig and entered the issue into the CAP process as IR 1625960. Byron TS 3.4.3,
RCS Pressure and Temperature Limits, states RCS pressure, RCS temperature,
and RCS heatup and cooldown rates shall be maintained within the limits specified in
the PTLR (Pressure Temperature Limits Report.) The PTLR is generated by
Westinghouse and contains graphs depicting the acceptable operating ranges of
RCS pressure and temperature supported by analysis. The lower bound of these
graphs was 0 psig. Byron procedure BOP RC-9, Filling an Isolated Reactor
Coolant Loop, The Pressurizer, and Drawing a Pressurizer Bubble, was used by the
station to fill the loops. This procedure allowed RCS piping pressure to go as low as
28 inches of mercury (approximately-14 psig) which is outside the lower bound of
the PTLR acceptable region. Procedural controls for the upper bounding limits were
appropriate. At the licensees request, Westinghouse performed the additional
analysis needed to expand the lower value of the curves and determined that the
lower bounding parameter could be changed to-14.7 psig with no impact to the RCS
barriers. The analysis was subsequently revised and the PTLR revised to designate
the lower boundary accordingly. 10 CFR 50, Appendix B, Criterion V, Instructions,
Procedures, and Drawings, requires, in part, that activities affecting quality be
prescribed by procedures appropriate to the circumstances. Contrary to the above,
between April 1998 and October 2013, BOP RC-9 allowed RCS pressures to be
lower than the analyzed lower bound of the parameter inputs of the PTLR graphs
and thus was not appropriate to the circumstances. The finding was more than
minor because it had the potential to adversely impact the Procedure Quality
attribute of the Reactor Safety-Barrier Integrity Cornerstone objective to provide
reasonable assurance that the RCS design barrier would function to protect the
public from radionuclide release caused by accidents or events. Given the analytical
conclusion that the condition was acceptable with the new lower bounding
parameter, the inspectors determined that there was no change in risk with the issue
and the finding was screened as Green.
2. On November 4, 2014, the licensee identified that the floor plug forming the internal
flood barrier to an essential service water pump valve pit in the auxiliary building was
removed prior to completion of the compensatory actions required by the Plant
Barrier Impairment Permit, PBI 14-334. 10 CFR 50, Appendix B, Criterion V,
Instructions, Procedures, and Drawings, requires, in part, that activities affecting
quality be prescribed by procedures appropriate to the circumstances. Plant Barrier
Control Program, CC-AA-201, assigns responsibility to Operations Management in
step 4.4.2 to ensure compensatory actions are in place prior to authorizing
permission to impair the barrier. In step 6.5.2.1 of CC-AA-201, Operations
Management is required to ensure compensatory actions are in place prior to
authorizing the impairment of the barrier. Contrary to the above, the licensee
operating staff allowed impairment of the barrier without implementing the
procedurally required compensatory actions. The licensee entered the issue in the
CAP process as IR 2406628 and immediately implemented the compensatory
55
actions on discovery of the omission. Inspectors determined that this issue was
more than minor because the performance deficiency adversely impacted the
Mitigating Systems Cornerstone objective to ensure availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences in that intentional impairment of a design barrier is a modification that
adversely impacts the attribute of design control and must be performed in
accordance with approved procedures and processes. The inspector's evaluation of
the missed actions determined that the affected systems would perform their credited
functions and using IMC 0609, Appendix A, The Significance Determination Process
For Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions,
Question A.1, determined that the finding screened as Green.
ATTACHMENT: SUPPLEMENTAL INFORMATION
56
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
R. Kearney, Site Vice President
T. Chalmers, Plant Manager
G. Armstrong, Security Manager
B. Barton, Radiation Protection Manager
T. Cain, Acting Nuclear Oversight Manager
R. Kartheiser, Emergency Preparedness Coordinator
C. Keller, Engineering Director
R. Lloyd, Emergency Preparedness Manager
K. Moss, Nuclear Oversight Assessor
D. Spitzer, Regulatory Assurance Manager
L. Zurawski, NRC Coordinator
M. McCue, Operations Training Manager
G. Contrady, Regulatory Assurance
J. Fiesel, Maintenance Director
E. Hernandez, Operations Director
S. Kerr, Training Director
B. Peters, Shift Operations Superintendent
L. Sanders, LORT Lead and Exam Author
F. Paslaski, Rad Engineering Manager
M. Yousuf, Programs Engineering Supervisor
R. McBride, Programs Engineer
Nuclear Regulatory Commission
J. Ellegood, Acting Chief, Reactor Projects Branch 3
D. E. Hills, Chief, Reactor Safety Branch 1
Attachment
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
05000454/2014005-01; NCV Failure to Measure Interpass Temperature (Section
05000455/2014005-01 1R08.1.b.1)05000454/2014005-02; NCV Liquid Penetrant Testing Procedure Did Not Meet ASME
05000455/2014005-02 Code (Section 1R08.1.b.2)05000454/2014005-03; NCV Welding Procedure Specification Variables Changed
05000455/2014005-03 Without Revision or Amendment Contrary to ASME Code
(Section 1R08.1.b.3)05000455/2014005-04 NCV Failure to Evaluate Operability of a TS SSC Upon
Discovery of a Support System Degraded Condition
(Section 1R15)05000455/2014005-05 FIN Containment Penetration Isolation Valves Rendered
Inoperable for Operational Convenience (Section 1R20)
Closed
05000454/2014005-01; NCV Failure to Measure Interpass Temperature (Section
05000455/2014005-01 1R08.1.b.1)05000454/2014005-02; NCV Liquid Penetrant Testing Procedure Did Not Meet ASME
05000455/2014005-02 Code (Section 1R08.1.b.2)05000454/2014005-03; NCV Welding Procedure Specification Variables Changed
05000455/2014005-03 Without Revision or Amendment Contrary to ASME Code
(Section 1R08.1.b.3)05000455/2014005-04 NCV Failure to Evaluate Operability of a TS SSC Upon
Discovery of a Support System Degraded Condition
(Section 1R15)05000455/2014005-05 FIN Containment Penetration Isolation Valves Rendered
Inoperable for Operational Convenience (Section 1R20)
05000454/2014-002-00 LER Non-compliance with Technical Specification 3.4.3, RCS
Pressure and Temperature Limits (Section 4OA3)
05000455/2014-004-00 LER Byron Unit 2 Reactor Pressure Vessel Head Control Rod
Drive Mechanism Penetration Nozzle Weld Indication
Attributed to Primary Water Stress Corrosion Cracking
(Section 4OA3)05000454/2012008-02, URI Operability Determination Procedure Implementation
05000455/2012008-02 Concerns (Section 4OA5)05000454/2012008-03, URI Potential Missed Opportunities to Identify a Latent
05000455/2012008-03 Undervoltage Design Issue (Section 4OA5)
Discussed
05000454/2012008-001 URI Inadequate Undervoltage Protection (Section 4OA5)05000455/2012008-001
2
LIST OF DOCUMENTS REVIEWED
The following is a partial list of documents reviewed during the inspection. Inclusion on this list
does not imply that the NRC inspector reviewed the documents in their entirety, but rather that
selected sections or portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
Section 1R01
- IR 2400815; Local Intense Precipitation (LIP) FLO-2d Modeling Issues
- ENERCON Report for Byron Station Flood Hazard Re-evaluation dated March 12, 2014
- 0BOSR XFT-A5, Revision 10; Freezing temperature Equipment Protection Non-Protected
Area Buildings
- BOP XFT-1, Revision 6; Cold Weather Operations
- M-42, Sheet 6; Revision BC; Diagram of Essential Service Water
- BAR 0VH01J-1-B5, Revision 1; River Screen House Temperature Low
- BAR 0-34-E8, Revision 54; Common HVAC Local Pnl Trouble
- Analysts, Inc. Laboratory Report: Diesel Fuel; December 19, 2014
Section 1R04
- M-37, Revision BD; Diagram of Auxiliary Feedwater
- M-138, Sheet 3A; Revision AW; Diagram of Chemical and Volume Control and Boron Thermal
Regeneration
- M-152, Sheet 9; Revision AA; Manufacturers Supplemental Diagram of Diesel Generator
Lube Oil Schematic
- M-152, Sheet 10; Revision AD; Manufacturers Supplemental Diagram of Diesel Generator
Fuel Oil Schematic
- M-152, Sheet 18; Revision R; Diagram of Starting Air
Section 1R05
- Pre-Fire Plan FZ 9.1-2, FZ 9.4-2; Revision 1; Auxiliary Building 2B Diesel Generator & Day
Tank Room - 401-0 Elevation
- Pre-Fire Plan FZ 11.2B-2; Revision 0; Auxiliary Building 346-0 Elevation 2A Containment
Spray Pump Room
- Pre-Fire Plan FZ 11.2A-2; Revision 0; Auxiliary Building 346-0 Elevation 2A RHR Pump
Room
- Pre-Fire Plan FZ 11.2C-2; Revision 0; Auxiliary Building 346-0 Elevation 2B Containment
Spray Pump Room
- Pre-Fire Plan FZ 11.2D-2; Revision 0; Auxiliary Building 346-0 Elevation 2A RHR Pump
Room
Section 1R08
- AR 01430775; Recordable Indications Discovered During ISI Examination; April 17, 2013
- AR 01501702; Seismic Support 2SI01014X (Loose Bolting, Angularity OOT); April 14, 2013
- AR 01507959; Mode 3 W/D Dry B/B Leak on 2CV8117; April 29, 2013
- AR 01503278; Recordable Indications Discovered During ISI Examination; May 17, 2013
- AR 01508214; Body-to-Bonnet Leak on 2CV131; April 30, 2013
- AR 01613143; 2BR7006 Leaking; January 27, 2014
3
- AR 01635115; Inactive Boric Acid on Flange Upstream of 2SI01PA; March 18, 2014
- AR 01672990; Boric Acid on Flange Bolting Upstream of 2SI121A; June 19, 2014
- AR 01694034; NOS ID, Finding Restraint not in ISI Plan; August 19, 2014
- AR 02393595; NRC ID, Issues with Vendor Exam Procedure; October 10, 2014
- AR 02392483; NRC-ID, Vendor Welding Guideline Document for Kerotest Vlv;
October 8, 2014
- AR 02392248; UT Indication in CRDM Penetration 6 B2R18M5; October 7, 2014
- AR 02391463; 2SI15004X (Recordable Ind. IDd During ASME IWF Exam); October 6, 2014
- AR 01676939; SX Piping Wall Thinning Acceptance Criteria Error; June 30, 2014
- AR 02395440; NOS QV IDd Preheat of Base Material Not Performed; October 14, 2014
- 80165; Curtiss Wright, Liquid Penetrant Inspection Procedure; Revision X, November 20, 2003
- VTIP F-2354.001; Welding Guidelines for Welding Small Valves into System Piping,
GTAW - Process
- WDI-PJF-1313102-FSR-001; Byron Generating Station Outage - B1R18 Reactor Vessel Head
Penetration Examination - Preliminary NDE Report Summary: Revision 0
- MA-MW-796-101; Welding, Brazing and Soldering Records; Revision 5
- M-919; Component Support Installation Guidelines and Tolerances; Revision J
- ER-AA-335-016; VT-3 Visual Examination of Component Supports, Attachments and Interiors
of Reactor Vessels; Revision 9
- Report No. B2R17-UT-022; UT of 2RC-01-BA/SGC-08; April 18, 2013
- WO 01505231; Scheduled NDE of Class 1, 2, and 3 Components; April 18, 2013
- WO 01025526; Hot Leg Check Valve Leak-By Indication; February 26, 2013, 2013
- WO 01323963; 2C NDE of the Reactor Coolant Pump Flywheels; January 31, 2013
- WO 01478575; Minor Leakage from Seal Weld on 2SI8819A; October 10, 2012
- WDI-STD-1040; Wesdyne Procedure for Ultrasonic Examination of Reactor Vessel Head
Penetrations; Revision 11
- WDI-STD-1041; Wesdyne Procedure for Reactor Vessel Head Penetration Ultrasonic
Examination Analysis; Revision 10
- PDQS; WDI-STD-1041 Revision 3; dated March 2, 2010
- PDQS; WDI-STD-1040 Revision 5; dated March 4, 2010
- WO 01480596; Replace Kerotest Check Valve 2SI8900C; February 26, 2013
- WPS 1-1-GTSM-PWHT; WPS for Manual GTAW/SMAW P1 to P1 Material; Revision 2
- PQR A-001; PQR for WPS 1-2RC1-GTSM-PWHT; October 19, 1998
- PQR A-002; PQR for WPS 1-1-GTSM-PWHT; March 9, 1999
- PQR 1-50C; PQR for WPS 1-1-GTSM-PWHT; January 3, 1984
- WPS 8-8GTSM; WPS for Manual GTAW/SMAW P1 to P1 Material; Revision 3
- PQR 1-51A; PQR for WPS WPS 8-8GTSM; December 28, 1983
- PQR 4-51A; PQR for WPS WPS 8-8GTSM; September 12, 1986
- PQR A-003; PQR for WPS WPS 8-8GTSM; February 8, 2000
- PQR A-004; PQR for WPS WPS 8-8GTSM; February 8, 2000
Section 1R11
- Cycle 14-6 Evaluated Scenario
- OP-AA-101-111-1001; Operations Standards and Expectations; Revision 14
- OP-AA-102-106; Operator Response Time Program; Revision 3
- OP-AA-105-101; Administrative Process for NRC License and Medical Requirements;
Revision 15
- OP-AA-105-102; NRC Active License Maintenance; Revisions 9, 10, and 11
- OP-BY-101-0004; Strategies for Successful Transient Mitigation; Revision 6
- OP-BY-102-106; Operator Response Time Program at Byron Station; Revision 5
4
- TQ-AA-150; Operator Training Programs; Revision 10
- TQ-AA-155; Conduct of Simulator Training and Evaluations; Revision 3
- TQ-AA-201; Examination Security and Administration; Revision 16
- TQ-AA-203; On the Job Training and Job Performance Evaluation; Revision 9
- TQ-AA-306; Simulator Management; Revision 7
- TQ-AA-306; Byron Simulator Core Model Evaluation for U-1 Cycle 20, Attachment 9,
Pressurized Water Reactor Core Performance Testing; March 28, 2014
- TQ-AA-306; Byron Simulator Core Model Evaluation for U-1 Cycle 20, Attachment 10, MTC of
Reactivity; November 18, 2013
- TQ-AA-306; Byron Simulator Core Model Evaluation for U-1 Cycle 20, Attachment 11, Rod
Worth Coefficient of Reactivity; March 28, 2014
- TQ-AA-306; Byron Simulator Core Model Evaluation for U-1 Cycle 20, Attachment 12, Boron
Coefficient of Reactivity; November 19, 2013
- TQ-AA-306; Byron Simulator Core Model Evaluation for U-1 Cycle 20, Attachment 13; Xenon
Worth; November 18, 2013
- TQ-AA-306; Byron Simulator Core Model Evaluation for U-1 Cycle 20, Attachment 16,
Approach to Criticality Using Boric Acid; March 28, 2014
- TQ-AA-306; Byron Simulator Core Model Evaluation for U-1 Cycle 20, Attachment 17,
Approach to Criticality Using Control Rods; November 18, 2013
- Byron Simulator Steady State Test; Lower Power Level; SS-1; Revision 2; June 30, 2014
- Byron Simulator Steady State Test; Mid-Range Power Level; SS-2; Revision 2; June 30, 2014
- Byron Simulator Steady State Test; Full Power Level; SS-3; Revision 2; June 30, 2014
- Byron Simulator Malfunction Test; Real Time Test; RT01; August 29, 2014
- Byron Simulator Transient Test; Manual Reactor Trip; TR-1; Revision 6; June 20, 2014
- Byron Simulator Transient Test; Simultaneous Trip of All Main Feedwater Pumps; TR-2;
Revision 7; June 20, 2014
- Byron Simulator Transient Test; Simultaneous Closure of All Main Steam Isolation Valves;
TR-3; Revision 6; June 20, 2014
- Byron Simulator Transient Test; Simultaneous Trip of All Reactor Coolant Pumps; TR-4;
Revision 6; June 20, 2014
- Byron Simulator Transient Test; Trip of Any Single Reactor Coolant Pump; TR-5; Revision 6;
June 20, 2014
- Byron Simulator Transient Test; Turbine Trip (Maximum Power Level Which Does Not Result
in Immediate Reactor Trip; TR-6; Revision 6; June 20, 2014
- Byron Simulator Transient Test; Maximum Rate Power Ramp; TR-7; Revision 6;
June 20, 2014
- Byron Simulator Transient Test; Maximum Size Reactor Coolant System Rupture Combined
with a Loss of All Offsite Power; TR-8; Revision 6; June 20, 2014
- Byron Simulator Transient Test; Maximum Size Unisolable Main Steam Line Rupture; TR-9;
Revision 6; June 20, 2014
- Byron Simulator Transient Test; Slow Primary System Depressurization to Saturated Condition
Using Pressurizer Relief Stuck open (Inhibited Actuation of Centrifugal Charging Pumps);
TR-10; Revision 6; June 20, 2014
- Byron Simulator Transient Test; Maximum Design Load Reduction; TR-11; Revision 6;
June 20, 2014
- IR1472593; TRGN-Crew Did Not Meet TCA [Time Critical Action] Time Required;
February 7, 2013
- IR1506862; SFP [Spent Fuel Pool] Level Reduced; April 26, 2013
- IR1519964; 2B and 2D RCFC Fans OLR [Online Risk] Not Communicated; May 31, 2013
- IR1521443; TRGN-Crew Failed Simulator OBE [Out of the Box Evaluation]; June 4, 2013
5
- IR1533360; Operations Deep Dive - OP Key Gap 3; July 8, 2013
- IR1567369; PI&R 2A DG Operability Concern; September 26, 2013
- IR1650818; Unexpected Alarm in MCR/1B DG Inoperable; April 23, 2014
- IR1652425; 4.0 Critique for 1B DG Inoperability; April 24, 2014
- IR1660105; TRGN-LORT Cycle 14-3 Failed DEP [Drill and Exercise Performance]
Classification; May 14, 2014
- Byron Simulator and Plant Differences Report; Revision 2; November 19, 2014
- List of Open Simulator Work Requests; dated November 24, 2014
- List of Closed Simulator Work Requests; dated November 24, 2014
- 2014 Pre-71111.11 Inspection Focused Area Self-Assessment; June 25, 2014
- 2014 Week 1 LORT Comprehensive Written Exam
- 2012 Week 5 LORT Comprehensive Written Exam
- 2014 Week 1; Scenario BY-58; Revision 6
- 2014 Week 1; Scenario BY-73; Revision 6
- 2014 Week 3; Scenario BY-61; Revision 6
- 2014 Week 3; Scenario BY-81; Revision 4
- 2014 Week 5; Scenario BY-78; Revision 5
- 2014 Week 5; Scenario BY-84; Revision 2
- Six JPMs from 2014 Week 1 of the Requalification Exams
- Six JPMs from 2014 Week 5 of the Requalification Exams
Section 1R12
- Maintenance Rule Summary for Function VC (Auxiliary Building HVAC)
- Maintenance Rule Summary for Function WS (Non-essential Service Water)
- Maintenance Rule Summary for Function SX-05 (UHS temperature control)
- IR 2403010; Maintenance Rule Unavailability Criterion Exceeded for 0SX162D
- IR 2405733; 0SX162B Exceeded Its Maintenance Rule Unavailability Limit
- System engineer evaluation and (a)(1) determination for Maintenance Rule Function SX-05
Section 1R13
- Work Week 10/6/2014 Online Risk Evaluation; Revisions 2, 3 & 4
- OU-AP-104; Revision 20
- IR 2392112; On Line Risk PRA Model Enhancement Identified
- IR 2391804; Lost DC Bus 212 Due to Crosstie Breaker Tripping Open
- 2BOA Elec-1; Revision 102; Loss of DC Bus Unit 2
- BY-Mode-009; Revision 2; TS 3.0.4.b Evaluation - Modes 3, 2and 1, Entry with 2PR11J,
2PC104M, and 2MS018B Inoperable
- Work Week December 29, 2014 Online Risk Evaluation; Revisions 2 & 3
- UFSAR Section 8.2.1; Offsite (Preferred) Power System
Section 1R15
- EC 351042; Evaluation Acceptability of Flexible Hoses on 2CV22MA, 2CV29MA, 2CV30MA,
2CV29MB, and 2CV30MB
- IR 2390770; Static Bend Radius is Less than Minimum Criteria
- IR 2390771; Static Bend Radius is Less than Minimum Criteria
- ECR 415215; Attempt to Remove Reactor Closure Stud #11
- WO 01643464; Install Reactor Vessel Head Per BMP 3118-7
- IR 2389646; Corrosion Found in Unit 2 Reactor Head Studhole 11
6
- IR 2392782; Abnormal Condition of 212 Battery Cells
- IR 2392789; Negative Plates on 212 Battery Bent
- EC 399715; Revision 0; Evaluation for the Acceptance of 212 ESF Batteries with Positive
Plate Misalignment and Bent Negative Plates
- Letter from Larry A. Carson of C&D Technologies, Inc. dated October 10, 2014; LCUN-33
Cells with Misalignment Issues
- IR 2407921; Missed Surveillance: 18-Month NIs Unit 1 Power Range 1/2 Trip
- BY-SURV-007; Revision 0; Risk Assessment Missed Surveillance - 1BOSR 3.1.7-41, 1BOSR
3.1.7-42, 1BOSR 3.1.7-43, and 1BOSR 3.1.7-44
- IR 2416985; Issue With Specific Gravity Results
- IEEE Standard 450-1995; Recommended Practice for Maintenance, Testing, and
Replacement of Vented Lead-Acid Batteries for Stationary Applications; January 24, 1995
- MA-BY-721-06;, Revision 15; 125 Volt Battery Bank Quarterly Surveillance
- TS 3.8.6, Battery Parameters, and Associated Bases
Section 1R19
- IR 2395421; 2WO007A Failed As Left Leak Rate (Second Time)
- M-118, Sheet 7, Revision AC; Diagram of Containment Chilled Water System
- WO 1632740; RCFC Cooling Coils Chilled Water Inlet Header Check Valve
- WO 1649351; LLRT for P-6 and P-10 - 2WO006A/B, 2WO007A/B
- EC 398037, Revision 1; Modify Logic for Unit 2 Condensate and Condensate Booster Pumps
Lube Oil Pressure Switches
- WO 1736197; Modify Logic for 2C CD/CB Pump Switches EC 398037
- ECR 414894; Requesting Engineering Support for Testing Criteria for Allen Bradley Type C
Control Relay
- IR 2396753; Higher than Expected Resistance on Closed Contacts
- 2BOSR 6.1.1-21, Revision 10; Unit Two Primary Containment Type C Local Leakage Rate
Tests and IST Tests of Containment Chilled Water System
- WO 1779268; 2FW009C Pump Running Every 7 Minutes
- WO 1713570; Rebuild 0A SX M/U Pump
- ER-AA-321, Revision 12; Administrative Requirements for Inservice Testing
- IR 2407973; 0A SX Makeup Pump Was Operating Outside of Acceptable Range
- WO 1761167; 0SX02PA Comprehensive IST Req for SX Makeup Pump
- WO 1776068; 0A SX Makeup Pump Operability Surv
- 0BOSR 5.5.8.SX.5-1c, Revision 7; Unit Zero Comprehensive Inservice Testing (IST)
Requirements for Essential Service Water Makeup Pump 0A
- WO 1578924; Check Alignment / Inspect / Replace Coupling
- WO 1604659; Test/Replace MCCBs
- WO 1520274; Test/Replace MCCBs on 1B Dsl Drv AF Pp 1A Batt Chgr
- 1BOSR 5.5.8.AF.5-2a, Revision 6; Unit One Group A Inservice Testing (IST) Requirements for
Diesel Driven Auxiliary Feedwater Pump 1AF01PB
- IR 2388711; SARA Sequencer Failed Testing - B2R18M4
- IR 2390820; Damaged Relay Contact Blocks on SARA Relay in 2PA13J
- IR 2390255; 2BOSR EF-1 Still Failed After Repair Attempt - B2R18M4
- IR 2390492; 2A Train SARA Relay Failure
- WO 1773616; SARA Sequencer Failed Testing - B2R18M4
- 2BOSR ER-1, Revision 5; Train A - SARA and ESF Sequencer Testing - 2PA13J
7
Section 1R20
- IR 2390534; 2A SG Secondary Manway Cover Seating Surface Anomaly
- IR 2390908; B2R18 Bus 242 Clearance Order Issue
- IR 2390926; 2SXA9A-6 UT Identified Areas Below Min. Wall Requirements
- IR 2396149; NRC Identified Issues During Containment Walkdown
- IR 2396833; NRC ID, Boric Acid Leak from 2FE-0418
- IR 2390265; NRC ID, AF [Auxiliary Feed] Tunnel Flood Seals Open Prior to Mode 5
- TS LCO 3.6.3; Containment Isolation Valves
- TS LCO 3.0.2 (failure to meet an LCO) and Associated Basis
- BY-MODE-009, Revision 2; TS 3.0.4.b Evaluation - Modes 3, 2 and 1 Entry with 2PR11J,
2PC104M, and 2MS018B Inoperable
- LS-AA-119-1001; Revision 3; Fatigue Management
- IR 2392194; Siemens for Cause Fatigue Assessment
- IR 2391809; Fatigue Assessment for IR 2391726
- Clearance Order (CO) 118593; SI Line Flex Mod EC 393365
- CO 118727; SI Pp Suction - Install Flex Mod Per 393365
- IR 2392100; NRC ID, Dry Fitting Leakage - 2FIS-0448B
- IR 2387756; NRC ID, Dry Boric Acid Deposits
- 2BGP 100-5; Revision 58; Plant Shutdown and Cooldown
Section 1R22
- 2BOSR XII-1; Revision 1; Gaseous Leak Testing of the 2RH01SA/B Valve Containment
Assemblies
- WO 1683365; Perform Leakage Test
- IR 1480456; Potential NUREG0737 Program Deficiency (1/2RH01SA/B)
- M-136, Sheet 4; Revision AZ; Diagram of Safety Injection
- 2BOSR 4.13.1-1, Revision 30; Unit Two Reactor Coolant System Water Inventory Surveillance
Computer Calculation
- WO 1637637; LLRT for P-5 and P-8 - 2WO056A/B, 2WO020A/B, and 2WO079A/B
- WO 1649351; LLRT for P-6 and P-10 - 2WO006A/B, 2WO007A/B
- 2BOSR 6.1.1-21, Revision 10; Unit Two Primary Containment Type C Local Leakage Rate
Tests and IST Tests of Containment Chilled Water System
- WO 1632051; LLRT for P-70 - 2PS9354A and 2PS9354B
- M-140, Sheet 1; Revision AQ; Diagram of Process Sampling (Primary & Secondary)
- WO 1632050; LLRT for P-70 - 2PS9357A and 2PS9357B
- 2BOSR 6.1.1-8; Revision 11; Unit Two Primary Containment Type C Local Leakage Rate
Tests and IST Tests of Primary Sampling System
- 2BVSR 6.1.1-26; Revision 8; Unit 2 Primary Containment Type A Integrated Leakage Rate
Test (ILRT)
- IR 2397833; Flow Indicated into Reactor Cavity (Incore) Sump During B2R18
- IR 2397910; RCDT Level Increase During ILRT
- BVP 800-39; Revision 11; Byron Containment Leakage Rate Testing Program
Section 1EP2
- Offsite Emergency Plan Alert and Notification System Addendum for Byron Station;
August 2009
- U. S. Department of Homeland Security, FEMA Letter; Backup Alert and Notification System;
December 10, 2012
8
- EP-AA-1000; Exelon Nuclear Standardized Radiological Emergency Plan Section E;
Revision 25
- EP-AA-1002; Exelon Nuclear Radiological Emergency Plan Annex for Byron Station,
Section 4; Revision 33
- PI-AA-126-1001-F-01; Focused Area Self-Assessment-ANS; September 24, 2014
- Byron Station Warning System Annual Maintenance & Operational Reports;
May - August 2014
- Byron Station Monthly Siren Availability Reports; January 2013 - July 2014
- Byron Semi-Annual Siren Reports; January 2013 - June 2014
- IR 1677552; Siren Failures Due to Weather Related Loss of Power; July 1, 2014
Section 1EP3
- EP-AA-1000; Exelon Nuclear Standardized Radiological Emergency Plan, Sections B and N;
Revision 25
- EP-AA-1002; Exelon Nuclear Radiological Emergency Plan Annex for Byron Station,
Section 2; Revision 33
- EP-AA-1002; Exelon Nuclear Radiological Emergency Plan Annex for Byron Station,
Addendum 1, On-Shift Staffing Technical Basis; Revision 0
- TQ-AA-113; ERO Training and Qualification; Revision 23
- Quarterly Unannounced Off-Hours Call-In Augmentation Drill Results; August 2012 - October
2014
- Emergency Response Organization Call-Out Roster; September 29, 2014
- IR 2119423; ACE-September 8 Drive In Drill OSC Did Not Meet Minimum Augmentation
Staffing In Required Time; October 2, 2014
- IR 1618395; Quarterly Call-In Drill Failure; February 7, 2014
- IR 1670721; Two ERO Duty ERO Team Members Did Not Respond to Call-In Drill;
June 12, 2014
- IR 1628153; Inadvertent Activation of Byron ERO Pagers; March 1, 2014
- IR 1527459; ERO Duty Environs Monitoring Team Member Did Not Respond to Call-In Drill;
June 21, 2013
- IR 1465323; ERO Duty OSC Director Did Not Respond to Call-In Drill; January 22, 2013
- IR 1406146; ERO Duty Team Member Did Not Respond to Call-In Drill; August 28, 2012
Section 1EP4
- EP-AA-1000; Exelon Nuclear Standardized Radiological Emergency Plan;
Revisions 24 and 25
- EP-AA-1002; Radiological Emergency Plan Annex for Byron Station; Revisions 32 and 33
- EP-AA-110-200; Dose Assessment; Revisions 4, 5, 6, and 7
- EP-AA-110-200-F-01; Dose Assessment Input Form; Revision B
- EP-AA-110-201-F-01; On-Shift Dose Assessment Input Sheet; Revision B
- EP-AA-112-100-F-02; Shift Dose Assessor; Revision F
Section 1EP5
- EP-AA-1000; Exelon Nuclear Standardized Radiological Emergency Plan Section D.3, Timely
Classification of Events-Hostile Action; Revision 25
- EP-AA-1000; Exelon Nuclear Standardized Radiological Emergency Plan Section J, Protective
Response; Revision 25
9
- EP-AA-1002; Exelon Nuclear Radiological Emergency Plan Annex for Byron Station,
Section 3,Classification of Emergencies; Revision 33
- EP-AA-1002; Exelon Nuclear Radiological Emergency Plan Annex for Byron Station,
Section 5.1, Emergency Response Facilities; Revision 33
- EP-AA-1002; Exelon Nuclear Radiological Emergency Plan Annex for Byron Station,
Addendum 2, Evacuation Time Estimates for Byron Station Emergency Planning Zone;
Revision 0
- EP-MW-124-1001-F-14; Monthly NARS Communications Test; October 20, 2014
- EP-MW-124-1001-F-15; Monthly ENS Communications Test; October 20, 2014
- EP-AA-121; Emergency Response Facilities and Equipment Readiness; Revision 12
- EP-AA-121-F-02; Byron Equipment Matrix; Revision 2
- EP-AA-120-1001; 10 CFR 50.54(q) Change Evaluation; Revision 7
- EP-AA-1002, Addendum 2; Evacuation Time Estimates for the Byron Station; Revision 1
- LS-AA-126-1005; Check-In Self-Assessment; September 18, 2014
- PI-AA-125; Corrective Action Program (CAP) Procedure; Revision 0
- PI-AA-126-1001-F-01; Focused Area Self-Assessment-NRC Pre-Inspection;
September 25, 2014
- NOSA-BYR-14-03; Emergency Preparedness Audit Report; April 9, 2014
- NOSA-BYR-13-03; Emergency Preparedness Audit Report; April 10, 2013
- EP Information #2012; Byron Station Moves to New EP Offsite Staging Area; June 2012
- Byron 2014 off-Year Exercise Evaluation Report; June 17, 2014
- Biennial Letters of Agreement; February - March 2014
- Plan of the Day EP EITER List; October 2014
- Operator Aid 2010-0004; List of Inaudible Public Address System Locations; October 22, 2014
- IR 2384610; Reschedule 18 ERO Members For Annual Requalification Training;
September 22, 2014
- IR 1681931; Off Year Exercise TSC Failed Demonstration Criteria; July 15, 2014
- IR 1643233; NOS Identified Mechanical Maintenance Less Than 50% Respiratory
Qualifications; April 4, 2014
- IR 1570488; Pre-Exercise Objective Failures For Dose Assessment and KI; dated
October 10, 2013
- IR 1562015;Loss of Phone Communications; September 21 2013
- IR 1462311; Public Address System Priorities and Operator Aid Deficiencies;
January 14, 2014
Section 2RS1
- IR 1595809; Non-Conservative Decision Making; dated November 26, 2013
- IR 1631930; Improper Egress and Ingress from a High Radiation Area; dated March 10, 2014
- IR 1501175; High Radiation Area Identified during Radiological Surveys; dated April 12, 2013
- IR 1584070; Primary to Secondary Dose Discrepancy; dated November 12, 2013
- IR 1489557; Over-Responding Neutron EDs; dated March 19, 2013
- IR 1552699; Sealed Source No. 856 Found Degraded; dated August 30, 2013
- IR 1639346; NOS ID: Incorrect Source Used for ARGOS-5 Daily Checks; dated
March 27, 2014
- RP-AA-503; Unconditional Release Survey Method; Revision 8
- RP-AA-460; Controls for High and Locked High Radiation Areas; Revision 26
- RP-AA-460-002; Additional High Radiation Exposure Control; Revision 2
- RP-AA-460-003; Access to HRAs/LHRAs/VHRAs and Contaminated Areas in Response to a
Potential or Actual Emergency; Revision 7
- Semi-Annual Source Inventory; File Location 2.12.2200.55; dated July 8, 2014
10
- Semi-Annual Source Leak Test; File Location 2.12.2200.58; dated July 8, 2014
Section 4OA1
- LS-AA-2140; Attachment 1; Monthly Data Elements for NRC Occupational Exposure Control
Effectiveness; July 2013 through September 2014
- LS-AA-2090; Monthly Data Elements for NRC Reactor Coolant System (RCS) Specific
Activity; July 2013 through September 2014
- CY-AA-130-3010; Dose Equivalent Iodine Determination; Revision 4
- LS-AA-2150; Monthly Data Elements for RETS/ODCM Radiological Effluent Occurrences;
July 2013 through September 2014
- LS-AA-2110; Monthly Data Elements for NRC ERO Drill Participation;
December 2013 - June 2014
- LS-AA-2120; Monthly Data Elements for NRC Drill/Exercise Performance;
October 2013 - June 2014
- LS-AA-2130; Monthly Data Elements for NRC Alert and Notification System Reliability;
October 2013 - June 2014
- Byron ANS Test Reports; October 2013 - June 2014
- Industry Quarterly EP Performance Indicator Results; First Quarter 2013 - Second Quarter
2014
- IR 1689782; Performance Indicator Historical Data Revision Second Quarter 2014;
August 6, 2014
- IR 1660105; LORT Training Failed DEP Classification; May 14, 2014
- IR 1618501; LORT Training Failed DEP Classification; February 7, 2014
- IR 1607567; Public Address System Speaker Correction; January 13, 2014
- BY-MSPI-001, Revision 16; Reactor Oversight Program MSPI Basis Document - Byron
Nuclear Generating Station
- LS-AA-2200, Revision 5; Mitigating System Performance Index Data Acquisition & Reporting;
- MSPI Monthly Data Elements for Emergency AC Power System (DG);
October 2013 - September 2014
- MSPI Monthly Data Elements for High Pressure Injection Systems (CV & SI);
October 2013 - September 2014
- MSPI Monthly Data Elements for Heat Removal Systems (AF);
October 2013 - September 2014
- MSPI Monthly Data Elements for Residual Heat Removal Systems (RH);
October 2013 - September 2014
- MSPI Monthly Data Elements for Cooling Water Systems (CC);
October 2013 - September 2014
- NEI 99-02, Revision 7; Regulatory Assessment Performance Indicator Guideline
- IR 1633538; 1RH8702B Failed to Reopen During 1BOSR 5.5.8.RH.3-2 (R2)
Section 4OA2
- ECR 415215; Attempt to Remove Reactor Closure Stud #11
- WO 01643464; Install Reactor Vessel Head Per BMP 3118-7
- IR 2389646; Corrosion Found in Unit 2 Reactor Head Studhole 11
- IR 2391113; RPV Stud Hole #11 Needs Threads to Be Polished
- Byron Degraded Equipment Log dated October 29, 2014
- Quarterly Presentation of Operations Concerns; Plant Health Committee Minutes dated
9/15/2014
- Open Operability Evaluations and Associated Compensatory Actions as of October 29, 2014
11
- IR 2420020; Quarterly Work-Around Meeting Missed
- Operator Work-Around Board Meeting Minutes dated May 19, 2014
- Operator Work-Around Board Meeting Minutes dated December 5, 2014
- BAP 1100-3A3; Revision 37; Plant Barrier Control Program
- BAP 1100-3A3; Revision 38; Plant Barrier Control Program
- PBI No.14-334; Barrier Impairment Authorization and Compensatory Action Tracking Form
for Work Order 1587172EC 393060, Revise Auxiliary Building Flooding Calculation Zones
G1-1A and G1-1B
- EC 400024; Revision 0; Revise Flood Calculation 3CB-1281-001
- EC 399883; Revision 1; Impact of Potential Flood on SX Pump Room with Flood Seal Open
- S&L Evaluation 2014-09017; Revision 0; Essential Service Water Pump Flooding
- IR 2406628; Issue With PBI 14-334
- IR 1694897; Astrigal Bent and Not Fastened to Door at Bottom
- IR 2390927; Metal Flashing Bent and Missing Screws
- IR 2397718; 0DSD725 Not Closing and Latching
- IR 2398582; Metal Door Strip Protruding 4-5 Inches; Personnel Safety Haz
- IR 2399230; 0DSD725 Fire Door Inoperable
- IR 2400560; 0DSD725 Fire Door Inoperable
- PBI No.14-399; Barrier Impairment Permit for Degraded Door Latch Mechanism Preventing
Door from Closing and latching
- 0BMSR 3.10.g.4, Revision 21; Fire Door Semi-Annual Inspection
- EC 339805; Fire Door Acceptance Criteria
- NFPA 252, 2012 Edition; Standard Methods of Fire Tests of Door Assemblies
- OP-MW-201-007, Revision 7; Fire Protection System Impairment Control
Section 4OA3
- IR 1625960; Potential To Exceed RCS PTLR Limits During Vacuum Fill
- BOP RC-9; Filling an Isolated Reactor Coolant Loop, the Pressurizer, and Drawing a
Pressurizer Bubble
- LER 454-2014-002-00; Non-compliance with Technical Specification 3.4.3, RCS Pressure
and Temperature Limits
Section 4OA5
- ML12087A213; Byron Unit 2 - NRC Special Inspection team (SIT) Report 05000455/2012008
- OP-AA-108-115, Revision 11; Operability Determinations (CM-1)
- OP-AA-108-115, Revision 13; Operability Determinations (CM-1)
- IR 1319908; B2F26 Unit 2 Reactor Trip Due to Electrical Fault and Unusual Event
- IR 1322212; B2F26 Potential Design Vulnerability in Switchyard Single Open Phase
- EC 387590, Revisions 001 through 008; Op Eval 12-001 - Potential Design Vulnerability in
Switchyard Single Open Phase Detection
- IR 1325902; Gaps in Guidance of Op Determination Procedure
- IR 1327246; Byron Station Review of OE26134
- IR 1325488; OE26134 Applicability Review
- IR 1327770; Missed Opportunity for Reviewing OPEX
- IR 2392644; NRC ID: Scaffold Leg Resting on Unistrut Floor Plate
- IR 2393725; Trickle Charge Light Extinguished on 2LL049E / App R Inop
- IR 2395282; 0DSSD194 All Watertight Dog Legs Not Fully Engaged - NRC Iden
12
Section 4OA7
- BAP 1100-3A3; Revision 37; Plant Barrier Control Program
- BAP 1100-3A3; Revision 38; Plant Barrier Control Program
- PBI No.14-334 (Barrier impairment Authorization and Compensatory Action Tracking Form for
Work Order 1587172EC 393060, Revise Auxiliary Building Flooding Calculation Zones G1-1A
and G1-1B
- EC 400024; Revision 0; Revise Flood Calculation 3CB-1281-001
- EC 399883; Revision 1; Impact of Potential Flood on SX Pump Room with Flood Seal Open
- S&L Evaluation 2014-09017; Revision 0; Essential Service Water Pump Flooding
- CC-AA-201; Revision 10; Plant Barrier Control Program
- BAP 1100-3; Revision 23; Plant Barrier Impairment (PBI) Program
- IR 2406628; Issue With PBI 14-334
13
LIST OF ACRONYMS USED
ADAMS Agencywide Document Access Management System
ANS Alert and Notification System
ASME American Society of Mechanical Engineers
CAP Corrective Action Program
CDF Core Damage Frequency
CLB Current Licensing Bases
CFR Code of Federal Regulations
CW Circulating Water
DLOOP Dual Unit Loss of Offsite Power
EDG Emergency Diesel Generator
EPRI Electric Power Research Institute
ERO Emergency Response Organization
ESF Engineered Safety Feature
FLEX Diverse and Flexible Coping Strategies
IEF Initiating Event Frequency
IMC Inspection Manual Chapter
IP Inspection Procedure
IR Issue Report
ISI Inservice Inspection
IST Inservice Test
LCO Limiting Condition for Operation
LER Licensee Event Report
LOOP Loss of Off-site Power
LORT Licensed Operator Requalification Training
MSPI Mitigating Systems Performance Index
MT Magnetic Particle Test
NCV Non-Cited Violation
NEI Nuclear Energy Institute
NRC U.S. Nuclear Regulatory Commission
OWA Operator Workaround
PARS Publicly Available Records System
PBI Plant Barrier Impairment
PI Performance Indicator
PIM Plant Issues Matrix
PPR Plant Performance Review
psig Pounds Per Square Inch Gauge
PT Liquid Penetrant Test
PTLR Pressure Temperature Limits Report
RASP Risk Assessment Standardization Project
RCP Reactor Coolant Pump
RH Residual Heat
SAPHIRE Systems Analysis Program for Hands-on Integrate Reliability Evaluations
SAT Systematic Approach to Training
14
SDP Significance Determination Process
SI Safety Injection
SIT Special Inspection Team
SPAR Standardized Plant Analysis Risk
SRA Senior Reactor Analyst
SSC System, Structure and/or Component
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
VTIP Vendor Technical Information
WPS Welding Procedure Specification
B. Hanson -2-
In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public
Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy
of this letter, its enclosure, and your response (if any) will be available electronically for public
inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS)
component of the NRC's Agencywide Documents Access and Management System (ADAMS).
ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html
(the Public Electronic Reading Room).
Sincerely,
/RA/
John Ellegood, Acting Chief
Branch 3
Division of Reactor Projects
Docket Nos. 50-454; 50-455
Enclosure:
IR 05000454/2014005; 05000455/2014005
w/Attachment: Supplemental Information
cc w/encl: Distribution via LISTSERV
DISTRIBUTION w/encl: Allan Barker
Kimyata MorganButler Carole Ariano
rDorlLpl3-2 Resource Linda Linn
RidsNrrPMByron Resource DRPIII
RidsNrrDirsIrib Resource DRSIII
Cynthia Pederson Jim Clay
Darrell Roberts Carmen Olteanu
Eric Duncan ROPreports.Resource@nrc.gov
DOCUMENT NAME: ML15036A527
Publicly Available Non-Publicly Available Sensitive Non-Sensitive
To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy
OFFICE RIII RIII RIII RIII
NAME JLennartz:mt JEllegood
DATE 02/05/15 02/05/15
OFFICIAL RECORD COPY