ML16039A364
| ML16039A364 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 02/08/2016 |
| From: | Kenneth Riemer NRC/RGN-III/DRP/B2 |
| To: | Davison K Northern States Power Co |
| References | |
| IR 2015004 | |
| Download: ML16039A364 (57) | |
See also: IR 05000282/2015004
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE RD. SUITE 210
LISLE, IL 60532-4352
February 8, 2016
Mr. Kevin Davison
Site Vice President
Prairie Island Nuclear Generating Plant
Northern States Power Company, Minnesota
1717 Wakonade Drive East
Welch, MN 55089
SUBJECT: PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1
AND 2-NRC INTEGRATED INSPECTION REPORT 05000282/2015004;
Dear Mr. Davison:
On December 31, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report
documents the results of this inspection, which were discussed on January 7, 2016, with you,
and other members of your staff.
Based on the results of this inspection, the NRC has identified two issues that were evaluated
under the risk significance determination process as having very low safety significance
(Green). The NRC has also determined that violations are associated with these issues. These
violations are being treated as Non-Cited Violations (NCVs), consistent with Section 2.3.2 of the
Enforcement Policy. Additionally, a licensee-identified violation for which enforcement
discretion was granted is listed in Section 4OA7 of this report.
If you contest the violations or significance of these NCVs, 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 copies to: (1) the Regional Administrator, Region III; (2) the Director,
Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001;
and (3) the NRC Resident Inspector at the Prairie Island Nuclear Generating Plant.
In addition, 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 the Prairie Island Nuclear Generating Plant.
K. Davison -2-
In accordance with Title 10 of the Code of Federal Regulations (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
System (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/
Branch 2
Division of Reactor Projects
Docket Nos. 50-282; 50-306;72-010
License Nos. DPR-42; DPR-60; SNM-2506
Enclosure:
IR 05000282/2015004; 05000306/2015004
cc: Distribution via LISTSERV
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos: 50-282; 50-306;72-010
License Nos: DPR-42; DPR-60; SNM-2506
Report No: 05000282/2015004; 05000306/2015004
Licensee: Northern States Power Company, Minnesota
Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2
Location: Welch, MN
Dates: October 1 through December 31, 2015
Inspectors: L. Haeg, Senior Resident Inspector
P. LaFlamme, Resident Inspector
K. Barclay, Resident Inspector
G. Edwards, Health Physicist
J. Cassidy, Senior Health Physicist
S. Bell, Health Physicist
A. Shaikh, Reactor Inspector
M. Garza, Emergency Preparedness Inspector
Approved by: K. Riemer, Chief
Branch 2
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY .................................................................................................................................... 2
REPORT DETAILS ....................................................................................................................... 5
Summary of Plant Status ........................................................................................................... 5
1. REACTOR SAFETY ....................................................................................................... 5
1R01 Adverse Weather Protection (71111.01) ............................................................. 5
1R04 Equipment Alignment (71111.04)........................................................................ 6
1R05 Fire Protection (71111.05) .................................................................................. 6
1R06 Flooding (71111.06) ............................................................................................ 7
1R07 Annual Heat Sink Performance (71111.07) ........................................................ 8
1R08 Inservice Inspection Activities (71111.08) ........................................................... 8
1R11 Licensed Operator Requalification Program (71111.11) ................................... 14
1R12 Maintenance Effectiveness (71111.12) ............................................................. 16
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13) ....... 16
1R15 Operability Determinations and Functional Assessments (71111.15) .............. 17
1R18 Plant Modifications (71111.18).......................................................................... 18
1R19 Post-Maintenance Testing (71111.19) .............................................................. 18
1R20 Outage Activities (71111.20) ............................................................................. 19
1R22 Surveillance Testing (71111.22) ....................................................................... 21
1EP4 Emergency Action Level and Emergency Plan Changes (71114.04) ............... 22
1EP6 Drill Evaluation (71114.06) ................................................................................ 22
2. RADIATION SAFETY ................................................................................................... 23
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01) ............. 23
2RS2 Occupational As-Low-As-Reasonably-Achievable Planning and Controls
(71124.02) ......................................................................................................... 28
2RS5 Radiation Monitoring Instrumentation (71124.05) ............................................. 30
4. OTHER ACTIVITIES ..................................................................................................... 32
4OA1 Performance Indicator Verification (71151)....................................................... 32
4OA2 Identification and Resolution of Problems (71152) ........................................... 35
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153) .............. 37
4OA5 Other Activities .................................................................................................. 40
4OA6 Management Meetings...................................................................................... 40
4OA7 Licensee-Identified Violations ........................................................................... 41
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 .............................................................................................................. 9
SUMMARY
Inspection Report 05000282/2015004, 05000306/2015004; 10/01/2015-12/31/2015;
Prairie Island Nuclear Generating Plant, Units 1 and 2; Inservice Inspection Activities; Radiation
Monitoring Instrumentation.
This report covers a 3-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. Two Green findings were identified by the
inspectors. The findings involved Non-Cited Violations (NCVs) of U.S. Nuclear Regulatory
Commission (NRC) requirements. The significance of inspection findings was 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," dated April 29, 2015.
Cross-cutting aspects were 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 February 4, 2015. The NRC's program
for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, "Reactor Oversight Process," dated February 2014.
NRC-Identified and Self-Revealed Findings
Cornerstone: Initiating Events
- Green. The inspectors identified a finding of very low safety significance (Green), and
an associated NCV of Title 10 of the Code of Federal Regulations (CFR) Part 50,
Appendix B, Criterion III, Design Control, for the licensees failure to incorporate the
American National Standards Institute (ANSI) N14.6-1978, Section 5.3.1 required
testing frequency for the reactor vessel head and reactor vessel internals lifting devices
into the controlling preventive maintenance procedure. Compliance with the ANSI
standard was documented in the Safety Evaluation Report (SER) for the licensees
control of heavy loads. The licensee documented the issue in the corrective action
program (CAP) as CAP 01497779 and performed testing on the reactor vessel head and
internals lifting devices during the outage.
The inspectors determined the licensees failure to comply with ANSI N14.6-1978,
Section 5.3.1, for the continued use testing of special lifting devices was a performance
deficiency (PD). The PD was determined to be more-than-minor and a finding because
the PD was associated with the Initiating Events Cornerstone attribute of design control,
and adversely affected the cornerstone objective to limit the likelihood of those events
that upset the plant stability and challenge critical safety functions during shutdown,
as well as power operations. Specifically, compliance with ANSI N14.6-1978,
Section 5.3.1 ensured safe load handling of heavy loads over the reactor core, and/or
over safety-related systems through established testing for the continued functionality of
the special lifting devices. The failure to perform the required frequency of testing on
special lifting devices could increase the likelihood of a load drop and could decrease
the load handling reliability of the lifting device if the device were returned to service with
potentially unacceptable flaws. The inspectors determined the finding could be
evaluated using the Significance Determination Process in accordance with Inspection
Manual Chapter 0609, Significance Determination Process, Attachment 0609.04,
Phase I - Initial Screening and Characterization of Findings, Table 3. Since the finding
was associated with shutdown conditions, the inspectors used Inspection Manual
Chapter 0609, Appendix G, Shutdown Operations Significance Determination Process.
2
The inspectors determined that none of the conditions constituting a loss of control were
met, as described in Appendix G, Attachment 1, Phase I Operational Checklists for Both
PWRs [Pressurized Water Reactors] and BWRs [Boiling Water Reactors], for this
finding, and neither a Phase II nor a Phase III analysis was required. Therefore, the
inspectors determined that this finding was of very low safety significance (Green). The
inspectors determined that this finding has a cross-cutting aspect in the area of Human
Performance, Resources, for the licensees failure to ensure that personnel, equipment,
procedures, and other resources were available and adequate to support nuclear safety.
Specifically, the licensee staff evaluated NRC Information Notice (IN) 2014-12, Crane
and Heavy Lift Issues Identified during NRC Inspections, in corrective action program
(CAP) document 01457469. However, in CAP 01457469, the licensee concluded that
issues identified in IN 2014-12 related to other licensees not performing testing in
accordance with ANSI N14.6 requirements were not applicable to the licensee at the
Prairie Island Nuclear Generating Plant. Therefore, the inspectors determined that there
was a recent missed opportunity for the licensee to have reasonably identified that the
current preventive maintenance procedure for special lifting devices was not in
accordance with the ANSI N14.6-1978 requirements, as referenced in the SER. [H.1]
(Section 1R08)
Cornerstone: Public Radiation Safety
- Green. The inspectors identified a finding of very low safety significance (Green) and
associated NCV of TS 5.5.1.a for the failure to comply with the Offsite Dose Calculation
Manual (ODCM) for not using calibration sources that were traceable to the National
Institute of Standards and Technology (NIST) or equivalent during the calibration of
station effluent monitors. The licensee entered the issues into the CAP as
CAPs 01490581 and 01500149. Immediate corrective actions included the re-calibration
of impacted monitors and the performance of an extent of condition evaluation for other
radiation monitor calibrations.
The PD was determined to be of more than minor safety significance in accordance with
IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was
associated with the plant facilities/equipment and instrumentation attribute of Public
Radiation Safety and it adversely impacted the cornerstone objective of ensuring
adequate protection of public health and safety due to failure to properly calibrate certain
effluent monitors. Subsequent calibrations of the monitors determined that the monitor
efficiency was previously overstated. The inspectors also reviewed IMC 0612,
Appendix E, Examples of Minor Issues, dated August 11, 2009, but did not identify
any similar examples. The finding was assessed using IMC 0609, Appendix D, Public
Radiation Safety Significance Determination Process, dated, February 12, 2008, and
determined to be of very low safety significance (Green), because it was associated with
the effluent release program but was not a failure to implement an effluent program,
public dose did not exceed Appendix I criteria, and the limits in Title 10 CFR 20.1301(e)
were not exceeded. A cross-cutting aspect was not assigned as this issue occurred
numerous years ago. The station has since performed monitor calibrations with
radioactive sources with known quality. (Section 2RS5)
Licensee-Identified Violations
- Violations of very low safety or security significance or Severity Level IV that were
identified by the licensee have been reviewed by the NRC. Corrective actions taken or
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planned by the licensee have been entered into the licensees corrective action
program (CAP). These violations and CAP tracking numbers are listed in Section 4OA7
of this report.
4
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at full power for the entirety of the inspection period, with the exception of brief
down-power maneuvers to accomplish planned surveillance testing activities.
Unit 2 began the inspection period at full power. On October 17, 2015, operations personnel
shut down the Unit 2 reactor to perform Refueling Outage (RFO) 2R29. Major activities
completed during the RFO included replacement of the main generator, main transformer,
containment fan coil unit (FCU) components, 21 reactor coolant pump (RCP) seal, and also
performed steam generator (SG) tube integrity testing. Operations personnel returned the
Unit 2 reactor to operation on December 3, 2015. The main generator was synchronized with
the electrical grid on December 5, 2015.
On December 17, 2015, the Unit 2 main turbine automatically tripped due to a detected
electrical fault within the main generator. This resulted in a reactor trip from 100 percent power.
The licensee began Forced Outage 2F2901HS to address the main generator issue and
remained shutdown in Mode 3 at the end of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
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 Safety Analysis Report (USAR) 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 corrective action program (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. Documents reviewed
were listed in the Attachment to this report. The inspectors reviews focused specifically
on the following plant systems due to their risk significance or susceptibility to cold
weather issues:
- D5 and D6 emergency diesel generators (EDGs) and cooling water (CL)
systems.
5
This inspection constituted one winter seasonal readiness preparations sample as
defined in Inspection Procedure (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:
- 12 motor driven auxiliary feed water (AFW) system;
- Unit 2 train A component cooling (CC) system; and
- Unit 1 caustic addition system.
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, the USAR, Technical Specification (TS) requirements, outstanding
work orders (WOs), condition reports, 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 or impact the capability of mitigating systems or barriers and
entered them into the CAP with the appropriate significance characterization.
Documents reviewed are listed in the Attachment to this report.
These inspections constituted three quarterly partial system walkdown samples as
defined in IP 71111.04-05.
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:
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- Fire Zone 42, Unit 2 reactor building, El. 697' 6";
- Fire Zone 54, Unit 2 reactor building Unit 2, El. 755';
- Fire Zone 88, Unit 2 rod control room, El. 735'; and
- Fire Zone 87, Unit 1 rod control room, El, 735'.
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 (IPEEE)
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. Using the documents listed in the Attachment to this report, 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.
Documents reviewed are listed in the Attachment to this report.
These inspections constituted four quarterly fire protection inspection samples as
defined in IP 71111.05-05.
b. Findings
No findings were identified.
1R06 Flooding (71111.06)
a. Inspection Scope
The inspectors reviewed selected risk important plant design features and licensee
procedures intended to protect the plant and its safety-related equipment from internal
flooding events. The inspectors reviewed flood analyses and design documents,
including the USAR, engineering calculations, and abnormal operating procedures to
identify licensees commitments. The specific documents reviewed are listed in the
Attachment to this report. In addition, the inspectors reviewed licensees drawings to
identify areas and equipment that may be affected by internal flooding caused by the
failure or misalignment of nearby sources of water, such as the fire suppression or the
circulating water systems. The inspectors also reviewed the licensees corrective action
documents with respect to past flood-related items identified in the corrective action
program to verify the adequacy of the corrective actions. The inspectors performed a
walkdown of the following plant areas to assess the adequacy of watertight doors and
verify drains and sumps were clear of debris and were operable, and that the licensee
complied with its commitments:
- Unit 1 and 2 AFW system rooms.
7
Documents reviewed are listed in the Attachment to this report. This inspection
constituted one internal flooding sample as defined in IP 71111.06-05.
b. Findings
No findings were identified.
1R07 Annual Heat Sink Performance (71111.07)
.1 Heat Sink Performance
a. Inspection Scope
The inspectors reviewed the licensees testing of the Unit 2 train B CC heat exchanger to
verify that potential deficiencies did not mask the licensees ability to detect degraded
performance, to identify any common cause issues that had the potential to increase
risk, and to ensure that the licensee was adequately addressing problems that could
result in initiating events that would cause an increase in risk. The inspectors reviewed
the licensees observations as compared against acceptance criteria, the correlation of
scheduled testing and the frequency of testing, and the impact of instrument
inaccuracies on test results. Inspectors also verified that test acceptance criteria
considered differences between test conditions, design conditions, and testing
conditions. Documents reviewed for this inspection are listed in the Attachment to this
document.
This inspection constituted one annual heat sink performance sample as defined in
IP 71111.07-05.
b. Findings
No findings were identified.
1R08 Inservice Inspection Activities (71111.08)
From October 19, 2015, through November 25, 2015, the inspectors conducted a
review of the implementation of the licensees inservice inspection (ISI) program for
monitoring degradation of the Unit 2 reactor coolant system (RCS), emergency
feedwater systems, risk-significant piping and components, and containment systems.
The reviews described in Sections 1R08.1 through 1R08.5 below constituted one
inservice inspection activities inspection sample as defined in IP 71111.08-05.
.1 Piping Systems Inservice Inspection
a. Inspection Scope
The inspectors reviewed records of the following Non-Destructive Examinations (NDE)
required by the American Society of Mechanical Engineers (ASME)Section XI Code,
and/or Title 10 of the Code of Federal Regulations (CFR) Part 50.55a to evaluate
compliance with the ASME Code,Section XI and V requirements, and if any indications
and defects were detected to determine whether these were dispositioned in accordance
with the ASME Code or an NRC-approved alternative requirement:
8
- Magnetic Particle Examination of Reactor Vessel Internals Lift Fixture Welds;
- Magnetic Particle Examination of Reactor Vessel Head Lift Rig Welds;
- Ultrasonic Examination of Safety Injection Elbow-to-Pipe Weld W-6;
- Ultrasonic Examination of RH Pipe-to-Elbow Weld W-5;
- Eddy Current Testing (ET) of SG Tubes;
- Visual Examination (VT-3) of AFWH-64 Sway Strut/Clamp; and
- Visual Examination (VT-3) of AFWH-79 Sway Strut/Clamp.
The licensee had not identified any recordable indications during non-destructive surface
and/or volumetric examinations performed since the last RFO. Therefore, no NRC
review was completed for this inspection procedure attribute.
The inspectors reviewed records of the following risk-significant pressure boundary
ASME Code Section XI Class 2 welds fabricated since the beginning of the last
refuelling outage to determine if the licensee: followed the welding procedure;
applied appropriate weld filler material; and implemented the applicable Section XI
or Construction Code NDEs and acceptance criteria. Additionally, the inspectors
reviewed the following welding procedure specification and supporting weld procedure
qualification records to determine if the weld procedure was qualified in accordance
with the requirements of Construction Code and the ASME Code Section XI:
- Class 1-WO 00406128; Remove and Replace Valve 2RC-7-2, Loop A to
Pressurizer CV-31228 BY-PASS.
b. Findings
Failure to Meet American National Standards Institute N14.6, Section 5.3.1
Requirements
Introduction: The inspectors identified a finding of very low safety significance (Green),
and an associated NCV of Title 10 CFR Part 50, Appendix B, Criterion III, Design
Control, for the licensees failure to incorporate American National Standards Institute
(ANSI) N14.6-1978, Section 5.3.1 required testing frequency for the reactor vessel head
and reactor vessel internals lifting devices into the controlling preventive maintenance
procedure. Compliance with the ANSI standard was documented in the Safety
Evaluation Report (SER) for the licensees control of heavy loads.
Description: The reactor vessel head and reactor vessel internals lifting devices are
classified as safety-related components at Prairie Island. The SER for the Control of
Heavy Loads Phase 1 at Prairie Island Nuclear Generating Plant, Units 1 and 2,
dated June 6, 1983, classified the reactor vessel head and reactor vessel internals
lifting devices as special lifting devices and provided documentation on how compliance
with ANSI N14.6-1978, Standard for Lifting Devices for Shipping Containers Weighing
10,000 Pounds (4500 kg) or more for Nuclear Materials, was met. Specifically,
Section 2.1.5 of the SER stated, in part, the Licensee has indicated that the reactor
vessel head and reactor vessel internals special lifting devices are inspected prior to use
in accordance with the requirements of ANSI N14.6-1978. Such inspection will include
NDE of welds and other critical components. ANSI N14.6-1978, Section 5.3.1 stated,
in part, each special lifting device shall be subjected annually (period not to exceed
14 months) to either of the following:
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- A load test equal to 150 percent of the maximum load to which the device is to
be subjected; and/or
and critical areas. If the device has not been used for a period exceeding one
year, this testing shall not be required. However, in this event, the test shall be
applied before returning the device to service.
The licensee did not perform load testing on these special lifting devices. Further, the
licensee had last performed NDE on these special lifting devices on June 3, 2005,
despite having used them during several outages since.
The inspectors reviewed the licensees preventive maintenance (PM) procedure
PM 3560-52, Reactor Head Lifting Rig Spreader & Connection Legs Assembly
Inspection, Revision 13, and identified that the procedure specified conducting NDE
once during each 10-year interval. The inspectors identified that this site procedure
requirement was contrary to the plant licensing basis as documented in the SER and
ANSI N14.6-1978. The inspectors questioned the licensees basis for decreasing the
required frequency of NDE on the special lifting devices. Specifically, the inspectors
were concerned that failure to perform NDE on the special lifting devices load-carrying
welds at the ANSI N14.6 required frequency potentially challenged continued
functionality of the devices.
The licensee documented the inspectors concerns in CAP 01497779. As part of its
immediate corrective actions, the licensee performed NDE on the reactor vessel head
and reactor vessel internals lifting devices prior to lifting the head and internals during
the outage. As part of additional corrective actions, the licensee intended to revise
procedure PM 3560-52 to correctly translate ANSI N14.6-1978, Section 5.3.1 testing
frequency requirements.
Analysis: The inspectors determined the licensees failure to comply with
ANSI N14.6-1978, Section 5.3.1 for the continued use testing of special lifting devices
was a performance deficiency (PD). The PD was determined to be more-than-minor,
and a finding, because the PD was associated with the Initiating Events Cornerstone
attribute of design control, and adversely affected the cornerstone objective to limit the
likelihood of those events that upset the plant stability and challenge critical safety
functions during shutdown, as well as power operations. Specifically, compliance with
ANSI N14.6-1978, Section 5.3.1, ensured safe load handling of heavy loads over the
reactor core, and/or over safety-related systems through established testing for the
continued functionality of the special lifting devices. The failure to perform the required
frequency of testing on special lifting devices could increase the likelihood of a load drop
and could decrease the load handling reliability of the lifting device if the device were
returned to service with potentially unacceptable flaws.
The inspectors determined the finding could be evaluated using the Significance
Determination Process (SDP) in accordance with Inspection Manual Chapter (IMC)
0609, Significance Determination Process, Attachment 0609.04, Phase I - Initial
Screening and Characterization of Findings, Table 3. Since the finding was associated
with shutdown conditions, the inspectors used IMC 0609, Appendix G, Shutdown
Operations Significance Determination Process. The inspectors determined that none
of the conditions constituting a loss of control were met, as described in Appendix G,
Attachment 1, Phase I Operational Checklists for Both PWRs and BWRs, for this
10
finding, and neither a Phase II nor a Phase III analysis was required. Therefore, the
inspectors determined that this finding was of very low safety significance (Green).
The inspectors determined that this finding has a cross-cutting aspect in the area of
Human Performance, Resources, for the licensees failure to ensure that personnel,
equipment, procedures, and other resources are available and adequate to support
nuclear safety. Specifically, the licensees staff evaluated NRC Information Notice
(IN) 2014-12, Crane and Heavy Lift Issues Identified during NRC Inspections, in CAP
01457469. However, within CAP 01457469, the licensee concluded that issues
identified in IN 2014-12 related to other licensees not performing testing in accordance
with ANSI N14.6 requirements were not applicable to the licensee at the Prairie Island
Nuclear Generating Plant. Therefore, the inspectors determined that there was a recent
missed opportunity for the licensee to have reasonably identified that the current
preventive maintenance procedure for special lifting devices (PM 3560-52) was not in
accordance with the ANSI N14.6-1978 requirements as referenced in the SER. [H.1]
Enforcement: Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires,
in part, that measures shall be established to assure that applicable regulatory
requirements and the design basis, as defined in 10 CFR Part 50.2, and as specified in
the license application, for those structures, systems, and components to which this
appendix applies are correctly translated into specifications, drawings, procedures, and
instructions. These measures shall include provisions to assure that appropriate quality
standards are specified and included in design documents and that deviations from such
standards are controlled.
Contrary to the above, since June 3, 2005, the licensee failed to correctly translate its
licensing design basis standard for the control of heavy loads into its PM procedure used
for controlling testing of special lifting devices. Specifically, the licensee failed to
translate the ANSI N14.6-1978 (as required by SER, dated June 6, 1983) testing
frequency requirements for special lifting devices into its controlling PM procedure for
special lifting devices.
The licensee subsequently took immediate corrective actions, which included NDE of
the reactor vessel head and reactor vessel internals lifting devices welds prior to lifting.
Because this violation was of very low safety significance, and it was entered into the
licensees CAP as CAP 01497779, it is being treated as a Non-Cited Violation (NCV),
consistent with Section 2.3.2 of the NRC Enforcement Policy
(NCV 05000306/2015004-01, Failure to Meet ANSI N14.6 Section 5.3.1
Requirements).
.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities
a. Inspection Scope
For the Unit 2 reactor vessel head, no examinations (visual or non-visual) were
required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D) requirements. Therefore,
no examination was conducted by the licensee and no NRC review was completed for
this inspection procedure attribute.
b. Findings
No findings were identified.
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.3 Boric Acid Corrosion Control
a. Inspection Scope
The inspectors independently walked down the Unit 2 reactor coolant system loop
piping, including the reactor coolant pumps, pressurizer, and emergency core cooling
systems within containment to identify boric acid leakage. The inspectors then reviewed
the walkdown performed by the licensee to ensure that components with boric acid
deposits were identified and entered into the CAP. The inspectors observed these
examinations to determine whether the licensee focused on locations where boric
acid leaks can cause degradation of safety significant components.
The inspectors reviewed the following licensee evaluations of components with boric
acid deposits to determine if the affected components were documented and properly
evaluated in the corrective action system. Specifically, the inspectors evaluated the
following CAP documents to determine if degraded components met the component
Construction Code and/or the ASME Section XI Code:
- CAP 01450417; Boric Acid Corrosion Control (BACC) Evaluation for ISI
Indication on CV-31325;
- CAP 01427328; BACC Evaluation for Leak Identified in Unit 2 Containment 21
Vault.
The inspectors reviewed the following CAP documents related to evidence of boric
acid leakage to determine whether the corrective actions completed were consistent with
the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B,
Criterion XVI:
- CAP 01431405; Boric Acid Leak was Found on 2RC-8-31;
- CAP 01469111; Boric Acid Packing Leak on 2SI-35-6;
- CAP 01492989; Boric Acid Built Up Below 21 Safety Injection Pump; and
- CAP 01445383; 22 Safety Injection Pump IB/OB Mechanical Seal Leakage.
b. Findings
No findings were identified.
.4 Steam Generator Tube Inspection Activities
a. Inspection Scope
The NRC inspectors observed acquisition of ET data, interviewed ET data personnel,
and reviewed documentation related to the 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-107620,
Steam Generator In-Situ Pressure Test Guidelines, and that these criteria were
properly applied to screen degraded SG tubes for in-situ pressure testing;
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- the numbers and sizes of SG tube flaws/degradation identified were bound by
the licensees previous outage Operational Assessment predictions;
the TSs and EPRI 1003138, Pressurized Water Reactor SG Examination
Guidelines;
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 licensees primary-to-secondary leakage (e.g., SG tube leakage) was below
3 gallons-per-day or the detection threshold during the previous operating cycle;
- the ET probes and equipment configurations used to acquire data from the
SG tubes were qualified to detect the known/expected types of SG tube
degradation in accordance with Appendix H, Performance Demonstration for
ET Examination of EPRI 1003138, Pressurized Water Reactor SG Examination
Guidelines;
- the licensee performed secondary side SG inspections for location and removal
of foreign materials; and
- the licensee implemented repairs for SG tubes damaged by foreign material.
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 licensees 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.
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The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action
documents reviewed by the inspectors are listed in the Attachment to this report.
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 October 6, 2015, the inspectors observed a crew of licensed operators in the plants
simulator during licensed operator requalification training. The inspectors verified that
operator performance was adequate, evaluators were identifying and documenting crew
performance problems, and that 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;
- oversight and direction from supervisors; and
- 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. Documents reviewed
are listed in the Attachment to this report.
This inspection constituted one quarterly licensed operator requalification program
simulator sample as defined in IP 71111.11-05 and satisfied the inspection program
requirement for the resident inspectors to observe a portion of an in-progress annual
requalification operating test during a training cycle in which it was not observed by the
NRC during the biennial portion of this IP.
b. Findings
No findings were identified.
.2 Resident Inspector Quarterly Observation during Periods of Heightened Activity or Risk
a. Inspection Scope
On October 16, 2015, the inspectors observed the Unit 2 shutdown activities in
preparation for the Unit 2 RFO. These were activities that required heightened
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awareness or were 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 manipulations; and
- oversight and direction from supervisors.
The performance in these areas was compared to pre-established operator action
expectations, procedural compliance and task completion requirements. Documents
reviewed are listed in the Attachment to this report.
This inspection constituted one quarterly licensed operator heightened activity/risk
sample as defined in IP 71111.11-05.
b. Findings
No findings were identified.
.3 Resident Inspector Quarterly Observation during Periods of Heightened Activity or Risk
a. Inspection Scope
On December 3, 2015, the inspectors observed the Unit 2 control room startup activities.
These were activities that required heightened awareness or were 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 manipulations; and
- oversight and direction from supervisors.
The performance in these areas was compared to pre-established operator action
expectations, procedural compliance and task completion requirements. Documents
reviewed are listed in the Attachment to this report.
This inspection constituted one quarterly licensed operator heightened activity/risk
sample as defined in IP 71111.11-05.
b. Findings
No findings were identified.
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1R12 Maintenance Effectiveness (71111.12)
.1 Routine Quarterly Evaluations
a. Inspection Scope
The inspectors evaluated the following:
- Unit 1 CC system; and
- Title 10 CFR 50.65(a)(3) periodic evaluation.
The inspectors reviewed events such as where 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 structures, systems, and
components (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 that
maintenance effectiveness issues were entered into the CAP with the appropriate
significance characterization. Documents reviewed are listed in the Attachment to this
report.
This inspection constituted two 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)
.1 Maintenance Risk Assessments and Emergent Work Control
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:
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- loss of Unit 1 & 2 emergency response computer system (ERCS) on
November 17 & 18, 2015;
- failure of a re-heat drain tank valve resulting in a thermal power increase on
November 19, 2015; and
- emergent examination of reactor special lift devices and resulting extended
duration at reduced inventory.
These activities were selected based on their potential risk significance relative to the
Reactor Safety Cornerstones. As applicable 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.
Documents reviewed during this inspection are listed in the Attachment to this report.
These maintenance risk assessments and emergent work control activities constituted
three samples as defined in IP 71111.13-05.
b. Findings
No findings were identified.
1R15 Operability Determinations and Functional Assessments (71111.15)
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issue:
The inspectors selected this potential operability issue based on the risk significance of
the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluation to ensure that TS operability was properly justified and the
subject components or systems 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 USAR to the licensees evaluation 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
evaluation. Additionally, the inspectors reviewed a sampling of corrective action
documents to verify that the licensee was identifying and correcting any deficiencies
associated with operability evaluation. Documents reviewed are listed in the Attachment
to this report.
This operability inspection constituted one sample as defined in IP 71111.15-05.
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b. Findings
No findings were identified.
1R18 Plant Modifications (71111.18)
.1 Plant Modifications
a. Inspection Scope
The inspectors reviewed the following modification:
- Unit 2 turbine building crane load capacity uprate.
The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety
evaluation screening against the design basis, the USAR, and the TS, as applicable, to
verify that the modification did not affect the operability or availability of the
affected/impacted systems. The inspectors, as applicable, observed ongoing and
completed work activities to ensure that the modifications were installed as directed and
consistent with the design control documents; the modifications operated as expected;
post-modification testing adequately demonstrated continued system operability,
availability, and reliability; and that operation of the modifications did not impact the
operability of any interfacing systems. As applicable, the inspectors verified that relevant
procedure, design, and licensing documents were properly updated. Lastly, the
inspectors discussed the plant modification with operations, engineering, and training
personnel to ensure that the individuals were aware of how the operation with the plant
modification in place could impact overall plant performance. Documents reviewed are
listed in the Attachment to this report.
This inspection constituted one permanent plant modification sample as defined in
IP 71111.18-05.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing (71111.19)
.1 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following post maintenance activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
- cooling water supply to 121 safeguards traveling water screen solenoid valve
replacement;
- 21 RCP testing following seal replacement; and
- Unit 2 emergency core cooling system (ECCS) venting following outage
maintenance activities.
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These activities were selected based upon the structure, system, or component's ability
to impact risk. The inspectors evaluated these activities for the following (as applicable):
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 USAR, 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 in the CAP
and that the problems were being corrected commensurate with their importance to
safety. Documents reviewed are listed in the Attachment to this report.
These inspections constituted three post-maintenance testing samples as defined in
IP 71111.19-05.
b. Findings
No findings were identified.
1R20 Outage Activities (71111.20)
.1 Refueling Outage Activities
a. Inspection Scope
The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for
the Unit 2 RFO conducted October 17, 2015, through December 5, 2015, 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. During the RFO, the inspectors observed portions of the shutdown
and cooldown processes and monitored licensee controls over the outage activities
listed below:
- licensee configuration management, including maintenance of defense-in-depth
commensurate with the OSP 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;
- controls over the status and configuration of electrical systems to ensure that
TS and OSP requirements were met, and controls over switchyard activities;
- 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;
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- 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 drywell (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 RFO activities.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted one RFO sample as defined in IP 71111.20-05.
b. Findings
No findings were identified.
.2 Other Outage Activities
a. Inspection Scope
The inspectors evaluated outage activities for an unscheduled outage that began on
December 17, 2015, and continued through the remainder of the inspection period. The
inspectors reviewed activities to ensure that the licensee considered risk in developing,
planning, and implementing the outage schedule.
The inspectors observed or reviewed portions of the reactor trip and associated action
taken in response the Unit 2 main generator trip, which caused an automatic turbine and
subsequent reactor trip. Additionally, the inspectors observed and reviewed outage
equipment configuration and risk management, electrical lineups, selected clearances,
control and monitoring of decay heat removal, control of containment activities,
personnel fatigue management, and identification and resolution of problems associated
with the outage. As of December 31, 2015, the cause of the main generator trip and
resultant automatic turbine and reactor trip was still under investigation. Because the
unscheduled outage was ongoing at the end of the inspection period, this inspection did
not constitute a complete other outage activities sample, as defined in IP 71111.20-05.
b. Findings
No findings were identified.
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1R22 Surveillance Testing (71111.22)
.1 Surveillance Testing
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:
Offsite Power Train A, Revision 4 (inservice testing).
The inspectors observed in-plant activities and reviewed procedures and associated
records to determine the following:
- did preconditioning occur;
- the effects of the testing were adequately addressed by control room personnel
or engineers prior to the commencement of the testing;
- acceptance criteria were clearly stated, demonstrated operational readiness, and
were consistent with the system design basis;
- plant equipment calibration was correct, accurate, and properly documented;
- as-left setpoints were within required ranges; and the calibration frequency was
in accordance with TSs, the USAR, procedures, and applicable commitments;
- measuring and test equipment calibration was current;
- test equipment was used within the required range and accuracy; applicable
prerequisites described in the test procedures were satisfied;
- test frequencies met TS requirements to demonstrate operability and reliability;
tests were performed in accordance with the test procedures and other
applicable procedures; jumpers and lifted leads were controlled and restored
where used;
- test data and results were accurate, complete, within limits, and valid;
- test equipment was removed after testing;
- where applicable for inservice testing activities, testing was performed in
accordance with the applicable version of Section XI, American Society of
Mechanical Engineers code, and reference values were consistent with the
system design basis;
- where applicable, test results that did not meet acceptable criteria were
addressed with an adequate operability evaluation or the system or component
was declared inoperable;
- where applicable for safety-related instrument control surveillance tests,
reference setting data were accurately incorporated in the test procedure;
- where applicable, actual conditions encountering high resistance electrical
contacts were such that the intended safety function could still be accomplished;
- prior procedure changes had not provided an opportunity to identify problems
encountered during the performance of the surveillance or calibration test;
- equipment was returned to a position or status required to support the
performance of its safety functions; and
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- all problems identified during the testing were appropriately documented and
dispositioned in the CAP.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted one inservice test sample as defined in IP 71111.22,
Sections-02 and-05.
b. Findings
No findings were identified.
1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
.1 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
Regional inspectors performed an in-office review of the latest revisions to the
Emergency Plan, Emergency Action Levels (EAL), and EAL Bases document to
determine if these changes decreased the effectiveness of the Emergency Plan.
The inspectors also performed a review of the licensees 10 CFR Part 50.54(q) change
process, and Emergency Plan change documentation to ensure proper implementation
for maintaining Emergency Plan integrity.
The NRC review was not documented in an SER 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 inspection constituted one EAL and Emergency Plan change sample as defined in
Inspection Procedure 71114.04-05.
b. Findings
No findings were identified.
1EP6 Drill Evaluation (71114.06)
.1 Training Observation
a. Inspection Scope
The inspectors observed a simulator training evolution for licensed operators on
October 6, 2015, which required emergency plan implementation by a licensee
operations crew. This evolution was planned to be evaluated and included in
performance indicator data regarding drill and exercise performance. The inspectors
observed event classification and notification activities performed by the crew. The
inspectors also attended the post-evolution critique for the scenario. The focus of the
inspectors activities was to note any weaknesses and deficiencies in the crews
performance and ensure that the licensee evaluators noted the same issues and entered
them into the corrective action program. As part of the inspection, the inspectors
22
reviewed the scenario package and other documents listed in the Attachment to this
report.
This inspection constituted one training evolution with emergency preparedness drill
aspects sample as defined in IP 71114.06-06.
b. Findings
No findings were identified.
2. RADIATION SAFETY
Cornerstones: Occupational and Public Radiation Safety
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01)
These inspection activities supplement those documented in IR 05000282/2015002;
05000306/2015002, and constituted one complete radiological hazard assessment and
exposure controls sample as defined in IP 71124.01-05.
.1 Inspection Planning (02.01)
a. Inspection Scope
The inspectors reviewed all licensee performance indicators (PIs) 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 Radiological Hazard Assessment (02.02)
a. Inspection Scope
The inspectors determined if there have been changes to plant operations since the last
inspection that resulted in significant new radiological hazards for onsite workers or
members of the public. The inspectors evaluated whether the licensee assessed the
potential impact of these changes and has implemented periodic monitoring, as
appropriate, to detect and quantify the radiological hazard(s).
The inspectors reviewed the last two radiological surveys from selected plant areas and
evaluated whether the thoroughness and frequency of the surveys were appropriate for
the given radiological hazard(s).
The inspectors conducted walkdowns of the facility, including radioactive waste
processing, storage, and handling areas to evaluate material conditions and performed
independent radiation measurements to verify conditions.
23
The inspectors selected the following radiologically risk-significant work activities that
involved exposure to radiation:
- 2R29-resistance temperature detector (RTD) replacement project;
- 10-year ISI/corrosion inspection-2R29;
- scaffold standard work-U2 outage; and
- primary steam generator activities-U2 outage.
For these work activities, the inspectors assessed whether the pre-work surveys
performed were appropriate to identify and quantify the radiological hazard and to
establish adequate protective measures. The inspectors evaluated the radiological
survey program to determine if hazards were properly identified, including the following:
- identification of hot particles;
- the presence of alpha emitters;
- the potential for airborne radioactive materials, including the potential presence
of transuranic and/or other hard-to-detect radioactive materials (this evaluation
may have included licensee planned entry into non-routinely entered areas
subject to previous contamination from failed fuel);
- the hazards associated with work activities that could suddenly and severely
increase radiological conditions and that the licensee had established a means to
inform workers of changes that could have significantly impacted their
occupational dose; and
- severe radiation field dose gradients that could have resulted in non-uniform
exposures of the body.
The inspectors observed work in potential airborne areas and evaluated whether the air
samples were representative of the breathing air zone. The inspectors evaluated
whether continuous air monitors were located in areas with low background to minimize
false alarms and were representative of actual work areas. The inspectors evaluated
the licensees program for monitoring levels of loose surface contamination in areas of
the plant with the potential for the contamination to become airborne.
b. Findings
No findings were identified.
.3 Instructions to Workers (02.03)
a. Inspection Scope
The inspectors selected various containers that held non-exempt, licensed radioactive
materials that could have caused unplanned or inadvertent exposure of workers, and
assessed whether the containers were labeled and controlled in accordance with
10 CFR 20.1904, Labeling Containers, or met the requirements of 10 CFR 20.1905(g),
Exemptions To Labeling Requirements.
The inspectors reviewed the following radiation work permits (RWPs) used to access
high-radiation areas and evaluated the specified work control instructions or control
barriers:
24
- RWP 155021, 10-Year ISI/Corrosion Inspection-2R29;
- RWP 152055, Scaffold Standard Work-U2 Outage; and
- RWP 152300, Primary Steam Generator Activities.
For these RWPs, the inspectors assessed whether allowable stay times or permissible
dose (including from the intake of radioactive material) for radiologically significant work
under each RWP were clearly identified. The inspectors evaluated whether electronic
personal dosimeter alarm set-points were in conformance with survey indications and
plant policies. 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 issues were included in the CAP and dose evaluations
were conducted as appropriate.
For work activities that could suddenly and severely increase radiological conditions, the
inspectors assessed the licensees means to inform workers of changes that could
significantly impact their occupational dose.
b. Findings
No findings were identified.
.4 Contamination and Radioactive Material Control (02.04)
a. Inspection Scope
The inspectors observed locations where the licensee monitored potentially
contaminated material leaving radiological controlled areas and inspected the methods
used for control, survey, and release from these areas. The inspectors observed the
performance of personnel surveying and releasing material for unrestricted use and
evaluated whether the work was performed in accordance with plant procedures and
whether the procedures were sufficient to control the spread of contamination and
prevent unintended release of radioactive materials from the site. The inspectors
assessed whether the radiation monitoring instrumentation had appropriate sensitivity for
the type(s) of radiation present.
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 indicated the presence of licensed radioactive material.
The inspectors reviewed the licensees procedures and records to verify that radiation
detection instrumentation was used at its typical sensitivity level based on appropriate
counting parameters. The inspectors assessed whether or not the licensee had
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.
25
b. Findings
No findings were identified.
.5 Radiological Hazards Control and Work Coverage (02.05)
a. Inspection Scope
The inspectors evaluated ambient radiological conditions (e.g., radiation levels or
potential radiation levels) during tours of the facility. The inspectors assessed whether
the conditions were consistent with applicable posted surveys, RWPs, and worker
briefings.
The inspectors evaluated the adequacy of radiological controls, such as required
surveys, radiation protection job coverage (including audio and visual surveillance for
remote job coverage), and contamination controls. The inspectors evaluated the
licensees use of electronic personal dosimeters in high-noise areas as high-radiation
area monitoring devices.
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 reviewed the following RWPs for work within airborne radioactivity areas
with the potential for individual worker internal exposures:
- RWP 155021; 10-Year ISI/Corrosion Inspection-2R29;
- RWP 152055; Scaffold Standard Work-U2 Outage; and
- RWP 152300; Primary Steam Generator Activities.
For these RWPs, the inspectors evaluated airborne radioactive controls and monitoring,
including potential for significant airborne levels (e.g., grinding, grit blasting, system
breaches, and entry into tanks, cubicles, and reactor cavities). The inspectors assessed
barrier (e.g., tent or glove box) integrity and temporary high-efficiency particulate air
ventilation system operation.
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 PI.
26
b. Findings
No findings were identified.
.6 Risk-Significant High-Radiation Area and Very-High Radiation Area Controls (02.06)
a. Inspection Scope
The inspectors discussed the controls in place for special areas that had 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 required
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.
b. Findings
No findings were identified.
.7 Radiation Worker Performance (02.07)
a. Inspection Scope
The inspectors observed performance of radiation workers with respect to stated
radiation protection work requirements. The inspectors assessed whether workers were
aware of the radiological conditions in their workplace and the RWP controls/limits in
place, and whether their performance reflected the level of radiological hazards present.
The inspectors reviewed radiological-related CAPs 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 that were planned or that
were taken.
b. Findings
No findings were identified.
.8 Radiation Protection Technician Proficiency (02.08)
a. Inspection Scope
The inspectors observed the performance of the radiation protection technicians with
respect to radiation protection work requirements. The inspectors evaluated whether
technicians were aware of the radiological conditions in their workplace and the RWP
controls/limits, and whether their performance was consistent with their training and
qualifications with respect to the radiological hazards and work activities.
The inspectors reviewed radiological-related CAPs since the last inspection that found
the cause of the event to be radiation protection technician error. The inspectors
27
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.
.9 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
whether they 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 involved radiation monitoring and exposure
controls. The inspectors assessed the licensees process for applying operating
experience at the facility.
b. Findings
No findings were identified.
2RS2 Occupational As-Low-As-Reasonably-Achievable Planning and Controls (71124.02)
These inspection activities supplement those documented in IR 05000282/2014002;
05000306/2014002, and constitute one complete occupational as-low-as-reasonably-
achievable (ALARA) planning and controls sample as defined in IP 71124.02-05.
.1 Radiological Work Planning (02.02)
a. Inspection Scope
The inspectors selected the following work activities of the highest exposure
significance:
- RWP 155021; 10-Year ISI/Corrosion Inspection-2R29;
- RWP 152055; Scaffold Standard Work-U2 Outage; and
- RWP 152300; Primary Steam Generator Activities.
The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and
exposure mitigation requirements. The inspectors determined whether the licensee
reasonably grouped the radiological work into work activities based on historical
precedence, industry norms, and/or special circumstances.
The inspectors assessed whether the licensees planning identified appropriate dose
mitigation features, considered alternate mitigation features, and defined reasonable
dose goals. The inspectors evaluated whether the licensees ALARA assessments had
taken into account decreased worker efficiency from use of respiratory protective
devices and/or heat stress mitigation equipment (e.g., ice vests). The inspectors
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determined whether the licensees work planning considered the use of remote
technologies (e.g., teledosimetry, remote visual monitoring, and robotics) as a means to
reduce dose and the use of dose reduction insights from industry operating experience
and plant-specific lessons learned. The inspectors assessed the integration of ALARA
requirements into work procedure and RWP documents.
The inspectors compared the results achieved (dose rate reductions and person-rem
used) with the intended dose established in the licensees ALARA planning for these
work activities. The inspectors compared the person-hour estimates provided by
maintenance planning and other groups to the radiation protection group with the actual
work activity time requirements and evaluated the accuracy of these time estimates.
The inspectors assessed the reasons (e.g., failure to adequately plan the activity and
failure to provide sufficient work controls) for any inconsistencies between intended and
actual work activity doses.
The inspectors determined whether post-job reviews were conducted and if identified,
problems were entered into the licensees CAP.
b. Findings
No findings were identified.
.2 Verification of Dose Estimates and Exposure Tracking Systems (02.03)
a. Inspection Scope
The inspectors reviewed the assumptions and bases (including dose rate and man-hour
estimates) for the current annual collective exposure estimate for reasonable accuracy
for select ALARA work packages. The inspectors reviewed applicable procedures to
determine the methodology for estimating exposures from specific work activities and
the intended dose outcome.
b. Findings
No findings were identified.
.3 Source Term Reduction and Control (02.04)
a. Inspection Scope
The inspectors used licensee records to determine the historical trends and current
status of significant tracked plant source terms known to contribute to elevated facility
aggregate exposure. The inspectors assessed whether the licensee had made
allowances or developed contingency plans for expected changes in the source term as
the result of changes in plant fuel performance issues or changes in plant primary
chemistry.
b. Findings
No findings were identified.
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.4 Radiation Worker Performance (02.05)
a. Inspection Scope
The inspectors observed the performance of radiation workers and radiation protection
technicians during work activities within in radiation areas, airborne radioactivity areas,
and/or high-radiation areas. The inspectors evaluated whether workers demonstrated
the ALARA philosophy in practice (e.g., workers were familiar with the work activity
scope and tools to be used, workers used ALARA low-dose waiting areas), and whether
there were any procedure compliance issues (e.g., workers were not complying with
work activity controls). The inspectors observed the performance of radiation workers to
assess whether training and skill levels were sufficient with respect to the radiological
hazards and the work involved.
b. Findings
No findings were identified.
2RS5 Radiation Monitoring Instrumentation (71124.05)
These inspection activities supplement those documented in IR 05000282/2014002;
05000306/2014002 and constituted one complete radiation monitoring instrumentation
sample as defined in IP 71124.05-05.
.1 Calibration and Testing Program (02.03)
Process and Effluent Monitors
a. Inspection Scope
The inspectors selected effluent monitor instruments (such as gaseous and liquid) and
evaluated whether channel calibration and functional tests were performed consistent
with radiological effluent TS/ODCM requirements. The inspectors assessed whether:
(a) the licensee calibrated its monitors with National Institute of Standards and
Technology (NIST) traceable sources; (b) the primary calibrations adequately
represented the plant nuclide mix; (c) when secondary calibration sources were used,
the sources were verified by the primary calibration; and (d) the licensees channel
calibrations encompassed the instruments alarm setpoints.
The inspectors assessed whether the effluent monitor alarm setpoints were established
as provided in the ODCM and station procedures.
For changes to effluent monitor setpoints, the inspectors evaluated the basis for
changes to ensure that an adequate justification existed.
b. Findings
Failure to Adequately Calibrate Liquid Effluent Monitors
Introduction: The inspectors identified a finding of very low safety significance (Green)
and associated NCV of TS 5.5.1.a for the failure to comply with the ODCM for not using
calibration sources, which were traceable to the NIST or equivalent during the calibration
of station effluent monitors.
30
Description: The inspectors reviewed the primary calibration records for various station
effluent monitors. These calibrations included the Unit 2 SG blowdown effluent monitor
(2R-19) and the waste effluent liquid monitor (R-18), which were both performed on
April 7, 1993. Primary calibrations are normally performed after monitor installation or
major maintenance. The purpose of primary calibrations is to determine the in-situ or
installed effluent monitor efficiency. Subsequent secondary calibrations are then
performed periodically, as specified by the ODCM, to ensure monitor response is
unchanged. During the inspection, the inspectors determined that the radioactive
sources used for these calibrations did not contain any quality information, such as NIST
or equivalent traceability. This issue of concern was then entered into the licenses CAP
on August 20, 2015. Subsequently, the licensee performed new primary calibrations
with a set of radioactive sources with an established quality. The new calibrations
resulted in a reduced efficiency when compared to the previous calibrations, which was
outside of the stations acceptance criteria. Although the new calibration efficiency was
lower, this did not require changes to the monitor alarm setpoints.
Analysis: The inspectors determined that not utilizing NIST traceable calibration sources
(or equivalent) during the primary calibration of the station effluent monitors was a PD,
the cause of which was reasonably within the licensees ability to foresee and correct,
and should have been prevented. The finding was not subject to traditional enforcement
since the incident did not result in a significant safety consequence, did not impact the
NRCs ability to perform its regulatory function, and was not willful.
The PD was determined to be of more than minor safety significance in accordance with
IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was
associated with the plant facilities/equipment and instrumentation attribute of Public
Radiation Safety and it adversely impacted the objective of ensuring adequate protection
of public health and safety due to failure to properly calibrate certain effluent monitors.
Subsequent calibration of the monitors determined that the monitor efficiency was
previously overstated. The inspectors also reviewed IMC 0612, Appendix E, Examples
of Minor Issues, dated August 11, 2009, but did not identify any similar examples. The
finding was assessed using IMC 0609, Appendix D, Public Radiation Safety
Significance Determination Process, dated February 12, 2008, and determined to be of
very low safety significance (Green) because it was associated with the effluent release
program but was not a failure to implement an effluent program, public dose did not
exceed Appendix I criteria, and the limits in 10 CFR 20.1301(e) were not exceeded. A
cross-cut aspect was not assigned as this issue occurred numerous years ago. The
station has since performed monitor calibrations with radioactive sources with known
quality. An example was the Unit 1 SG blowdown effluent monitor, which was calibrated
on August 25, 2015.
Enforcement: Technical Specification 5.5.1.a states, in part, that the ODCM shall
contain the methodology and parameters used in the calculation of offsite doses. The
ODCM Table 2.3, Radioactive Liquid Effluent Monitoring Instrumentation, Surveillance
Requirements, specifies, in part, that initial channel calibrations be performed with
NIST certified or NIST traceable sources.
Contrary to the above, on April 7, 1993, 2R-19 and R-18 were not calibrated with NIST
certified, NIST traceable, or other suitable quality radioactive source(s). Corrective
actions included the re-calibration of these monitors and an extent of condition on
additional effluent monitors. Since the finding was of very low safety significance
31
(Green) and was entered into the licensees CAP as CAPs 01490581 and 01500149,
this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC
Enforcement Policy (NCV 05000282/2015004-02, Failure to Adequately Calibrate
Liquid Effluent Monitors).
4. OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
Security
4OA1 Performance Indicator Verification (71151)
.1 Mitigating Systems Performance IndexEmergency AC Power System
a. Inspection Scope
The inspectors sampled licensee submittals for the Mitigating Systems Performance
Index (MSPI)-Emergency AC Power System PI, Units 1 and 2, for the period from the
4th quarter of 2014 through the 3rd quarter of 2015. To determine the accuracy of the PI
data reported during those periods, PI definitions and guidance contained in the Nuclear
Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator
Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the
licensees operator narrative logs, MSPI derivation reports, issue reports, event reports
and NRC integrated IRs for the period of October of 2014 through September of 2015 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 issue report database to
determine if any problems had been identified with the PI data collected or transmitted
for this indicator and none were identified. Documents reviewed are listed in the
Attachment to this report.
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 IndexResidual Heat Removal System
a. Inspection Scope
The inspectors sampled licensee submittals for the MSPI - RHR System PI, Units 1 and
2, for the period from the 4th quarter of 2014 through the 3rd quarter of 2015. To
determine the accuracy of the PI data reported during those periods, PI definitions and
guidance contained in the NEI Document 99-02, Regulatory Assessment Performance
Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors
reviewed the licensees operator narrative logs, MSPI derivation reports, issue reports,
event reports and NRC integrated IRs for the period of October of 2014 through
September of 2015 to validate the accuracy of the submittals. The inspectors reviewed
32
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
issue report database to determine if any problems had been identified with the PI data
collected or transmitted for this indicator and none were identified. Documents reviewed
are listed in the Attachment to this report.
This inspection constituted two MSPI residual heat removal system samples as defined
in IP 71151-05.
b. Findings
No findings were identified.
.3 Mitigating Systems Performance IndexCooling Water Systems
a. Inspection Scope
The inspectors sampled licensee submittals for the MSPI-CL Systems PI,
Units 1 and 2, for the period from the 4th quarter of 2014 through the 3rd quarter of
2015. To determine the accuracy of the PI data reported during those periods, PI
definitions and guidance contained in the NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were
used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation
reports, issue reports, event reports and NRC integrated IRs for the period of October of
2014 through September of 2015 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 issue report database to determine if any problems had been identified
with the PI data collected or transmitted for this indicator and none were identified.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted two MSPI cooling water system samples as defined in
IP 71151-05.
b. Findings
No findings were identified.
.4 Reactor Coolant System Specific Activity
a. Inspection Scope
The inspectors sampled licensee submittals for the RCS Specific Activity PI for the
period from the 4th quarter of 2014 through the 3rd quarter of 2015. The inspectors
used PI definitions and guidance contained in the NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, to
determine the accuracy of the PI data reported during those periods. The inspectors
reviewed the licensees RCS chemistry samples, technical specification requirements,
issue reports, event reports and NRC Integrated IRs to validate the accuracy of the
submittals. The inspectors also reviewed the licensees issue report database to
33
determine if any problems had been identified with the PI data collected or transmitted
for this indicator. In addition to record reviews, the inspectors observed a chemistry
technician obtain and analyze a RCS sample. Documents reviewed are listed in the
Attachment to this report.
This inspection constituted two RCS specific activity samples as defined in IP 71151-05.
b. Findings
No findings were identified.
.5 Occupational Exposure Control Effectiveness
a. Inspection Scope
The inspectors sampled licensee submittals for the Occupational Exposure
Control Effectiveness PI for the period from the 4th quarter of 2014 through the
3rd quarter of 2015. The inspectors used PI definitions and guidance contained in
the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 7, dated August 31, 2013, to determine the accuracy of the PI data reported
during those periods. The inspectors reviewed the licensees assessment of the PI
for occupational radiation safety to determine if indicator related data was adequately
assessed and reported. To assess the adequacy of the licensees PI data collection and
analyses, the inspectors discussed with radiation protection staff, the scope and breadth
of its data review and the results of those reviews. The inspectors independently
reviewed electronic personal dosimetry dose rate, 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.
Documents reviewed are listed in the Attachment to this report.
This inspection constituted one occupational exposure control effectiveness sample as
defined in IP 71151-05.
b. Findings
No findings were identified.
.6 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual
Radiological Effluent Occurrences
a. Inspection Scope
The inspectors sampled licensees submittals for the Radiological Effluent Technical
Specification (RETS)/ODCM Radiological Effluent Occurrences PI for the period from
the 4th quarter of 2014 through the 3rd quarter of 2015. The inspectors used PI
definitions and guidance contained in the NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, to
determine the accuracy of the PI data reported during those periods. The inspectors
reviewed the licensees CAP database and selected individual reports generated since
this indicator was last reviewed to identify any potential occurrences such as
34
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. Documents
reviewed are listed in the Attachment to this report.
This inspection constituted one RETS/ODCM radiological effluent occurrences sample
as defined in IP 71151-05.
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems (71152)
.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 condition report packages.
35
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, licensee
trending efforts, and licensees human performance results. The inspectors review
nominally considered the 6-month period of July of 2015 through December of 2015,
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
IP 71152-05.
b. Findings
No findings were identified.
.4 Annual Follow-up of Selected Issues: CAP 01494532; Safety-Related Relay for Reactor
Protection System Service Life Evaluation
a. Inspection Scope
During a review of items entered in the licensees CAP, the inspectors noted that
CAPs 01493179 and 01493183 documented safety related relays installed in the reactor
protection system had surpassed the vendor qualified life of 20 years. In their review,
the inspectors identified that the CAPs listed above did not address the impact of
exposure to low humidity conditions present during the late fall and winter months. In
response, the licensee performed a detailed evaluation under CAP 01494532 to
document the impact of low humidity on electrical equipment. The inspectors reviewed
the associated evaluation and also the procedures associated with humidity monitoring
and noted that per CAP 01495083, issued on September 29, 2015, the service building
computer room containing the ERCS reached the low humidity alarm set point and
annunciated. The inspector discussed this noted condition with operations staff and it
36
was recognized that the same alarm had annunciated in the fall of 2014. Based on the
above information, the inspectors reviewed associated CAPs and work requests that had
been generated since September of 2014 that addressed low humidity indications
present during the late fall and winter months in 2014 and 2015, respectively. The
inspectors determined that the evaluation performed under CAP 01494532 adequately
addressed the impact of low humidity on electrical components and noted that the
licensee planned to replace all applicable relays during the next RFOs for each Unit.
The inspectors noted that the associated relays addressed in CAP 01494532 remained
operable but non-conforming and therefore remained capable of performing their
required safety functions.
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b. Findings
No findings were identified.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153)
.1 Unit 2 Automatic Reactor Trip and Notice of Unusual Event
a. Inspection Scope
On December 17, 2015, Unit 2 experienced an automatic reactor trip resulting from an
automatic turbine shutdown caused by a main generator lockout. The inspectors
responded to the control room and monitored the operator actions taken to address the
event. Following the trip, the control room received unexpected fire alarms within the
Unit 2 containment. A Notice of Unusual Event was declared but subsequently exited
after the licensee verified that no fire existed within containment. The inspectors
reviewed the procedures used during this event to determine whether the control room
operators responded properly. Documents reviewed are listed in the Attachment to this
report.
This review constituted one event follow-up sample as defined in IP 71153-05.
b. Findings
No findings were identified.
.2 (Closed) Licensee Event Report 05000282/2014-002-00 and-01: Emergency Diesel
Generators Declared Inoperable Due to Not Meeting High Energy Line Break
Requirements
a. Inspection Scope
On August 4, 2014, the licensee submitted the above Licensee Event Report (LER) to
the NRC to document a condition that could have prevented the fulfillment of the D1 and
D2 EDGs safety function. The condition, identified on June 3, 2014, was associated
with a calculated turbine building (TB) high energy line break (HELB) heat-up analysis
temperature that exceeded the maximum supply and exhaust fan blade positioner
temperatures for the D1 and D2 EDGs. The licensee declared both D1 and D2
37
inoperable, entered the applicable TS action statements, and implemented
compensatory measures to bypass the supply and exhaust fan blade positioners to full
cooling mode allowing the station to exit the applicable TS action statements.
The licensee initiated a CAP and root cause evaluation that was still in progress at the
LER submittal deadline, therefore, on January 30, 2015, the licensee submitted
supplement-01 to the above LER which described the final root cause and corrective
actions.
Following submittal of the above LER supplement, the licensee received testing data
from a third party vendor that demonstrated acceptable operation of the supply and
exhaust fan blade positioners at the elevated temperatures identified within the TB HELB
calculation. Therefore, on July 23, 2015, the licensee submitted a cancellation letter to
NRC for LERs 05000282/2014-002-00 and-01 since the original condition did not result
in the prevention of the fulfillment of the D1 and D2 EDGs safety function.
The inspectors reviewed the revised analysis and the cancellation letter. No concerns
were identified. Documents reviewed are listed in the Attachment to this report. This
LER is closed.
This review constituted one event follow-up sample as defined in IP 71153-05.
b. Findings
No findings were identified.
.3 (Closed) LER 05000282/2015-001-00: 14 Fan Coil Unit Leak
a. Inspection Scope
On January 16, 2015, the licensee submitted the above LER to the NRC to document a
condition that could have prevented the fulfillment of the Unit 1 containment safety
function. The condition, identified on November 20, 2014, with Unit 1 in Mode 3, was
associated with a cooling water leak from the 14 containment fan coil unit (FCU) that
impacted containment integrity. The licensee declared the Unit 1 containment
inoperable, entered the applicable TS LCO statement, and isolated the 14 containment
FCU within the Unit 1 containment TS action completion time allowing the station to exit
the applicable TS action statement. Repairs were conducted shortly thereafter and the
14 containment FCU was returned to service.
Following submittal of the above LER, the licensee performed an engineering evaluation
that demonstrated that containment leakage past the auxiliary building special ventilation
zone and shield building would have remained less than the available containment
leakage margin. Therefore, since the 14 containment FCU leak did not represent a
condition that could have prevented the fulfillment of the Unit 1 containment safety
function, the licensee submitted a cancellation letter to NRC for
LER 05000282/2015-001-00 on September 3, 2015.
The inspectors reviewed the revised analysis and the cancellation letter. No concerns
were identified. Documents reviewed are listed in the Attachment to this report. This
LER is closed.
38
This review constituted one event follow-up sample as defined in IP 71153-05.
b. Findings
No findings were identified.
.4 (Closed) LER 05000282/2015-002-00: 14 Fan Coil Unit Leak (Lower Head)
a. Inspection Scope
On April 10, 2015, the licensee submitted the above LER to the NRC to document a
condition that could have prevented the fulfillment of the Unit 1 containment safety
function. The condition, identified on February 10, 2015, with Unit 1 in Mode 3, was
associated with a cooling water leak from the 14 containment FCU that impacted
containment integrity. The licensee declared the Unit 1 containment inoperable, entered
the applicable TS action statement, and implemented repairs to the 14 containment FCU
within the Unit 1 containment TS action completion time allowing the station to exit the
applicable TS action statement.
Following submittal of the above LER, the licensee performed an engineering evaluation
(see Section 4OA3.3) that demonstrated that containment leakage past the auxiliary
building special ventilation zone and shield building would have remained less than the
available containment leakage margin. Therefore, since the 14 containment FCU leak
did not represent a condition that could have prevented the fulfillment of the Unit 1
containment safety function, the licensee submitted a cancellation letter to NRC for LER
05000282/2015-002-00 on September 3, 2015.
The inspectors reviewed the revised analysis and the cancellation letter. No concerns
were identified. Documents reviewed are listed in the Attachment to this report. This
LER is closed.
This review constituted one event follow-up sample as defined in IP 71153-05.
b. Findings
No findings were identified.
.5 (Closed) LER 05000282/2015-003-00: Unanalyzed Condition Due to Non-Compliance
with 10 CFR 50 Appendix R
a. Inspection Scope
The inspectors reviewed information provided by the licensee regarding the
April 19, 2015, identification of inadequate procedure steps within procedure
F5 Appendix B, Control Room Evacuation (Fire), Revision 31. Specifically, during a
National Fire Protection Association (NFPA) 805 transition process review of
Engineering Change 25405, 12 Reactor Cooling Pump Seal Face Replacement, the
licensee identified that F5 Appendix B did not contain required procedural steps to open
direct current (DC) knife switches for the 11, 12, 21, and 22 RCP breakers prior to
evacuation of the control/relay and cable spreading rooms during a postulated fire event
in those areas. The unanalyzed condition was associated with the potential for fire
induced circuit damage resulting in RCP(s) restarting without adequate seal cooling
39
restored, leading to seal failure and a small break loss of coolant accident. The
unanalyzed condition only impacted the 12 RCP since the 11, 21, and 22 RCPs had
appropriately modified seals to allow time for restoring seal cooling prior to seal failure.
During the inspection, the inspectors reviewed the fire protection program documents,
licensees CAPs, the apparent cause evaluation, immediate corrective actions (F5
Appendix B procedure change), and longer term corrective actions. Documents
reviewed are listed in the Attachment to this report. This LER is closed.
This review constituted one event follow-up sample as defined in IP 71153-05.
b. Findings
One finding and NCV for which the NRC exercised enforcement discretion was identified
during the review of this LER. The inspectors determined that the finding and NCV
associated with the unanalyzed condition was best characterized as a licensee identified
finding and violation. As a result, the inspectors documented information regarding this
issue in Section 4OA7 of this inspection report.
4OA5 Other Activities
.1 Institute of Nuclear Power Operations Plant Assessment Report Review
a. Inspection Scope
The inspectors reviewed the final report for the Institute of Nuclear Power Operations
(INPO) plant evaluation conducted in September and October of 2015. The inspectors
reviewed the report to ensure that issues identified were consistent with the NRC
perspectives of licensees performance and to verify if any significant safety issues were
identified that required further NRC follow-up.
b. Findings
No findings were identified.
4OA6 Management Meetings
.1 Exit Meeting Summary
On January 7, 2016, the inspectors presented the inspection results to Mr. K. Davison,
Site Vice President, and other members of the 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:
40
- The inspection results for the areas of radiological hazard assessment and
exposure controls; occupational ALARA planning and controls; and RCS specific
activity, occupational exposure control effectiveness, and RETS/ODCM
radiological effluent occurrences PI verification with Mr. K. Klotz, Acting Radiation
Protection Manager, on November 6, 2015;
- The results of the ISI inspection with Mr. M. Pearson, Regulatory Affairs
Manager, and other members of the licensee staff on November 25, 2015;
- The inspection results for the area of radiation monitoring instrumentation via
teleconference, with Mr. D. Gauger, Chemistry Manager, on December 28, 2015;
and
- The Annual Review of EAL and Emergency Plan Changes with the Licensee's
Emergency Preparedness Manager, Mr. B. Carberry, Emergency Preparedness
Manager, via telephone on December 21, 2015.
The inspectors confirmed that none of the potential report input discussed was
considered proprietary. Proprietary material received during the inspection was returned
to the licensee.
4OA7 Licensee-Identified Violations
The following violation of very low safety significance (Green) was identified by the
licensee. The NRC is not taking enforcement action for this violation because it met the
criteria of the NRC Enforcement Policy, "Interim Enforcement Policy Regarding
Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48)," as described
below:
- Title 10 CFR 50.48(b)(2) requires, in part, that all nuclear power plants licensed
to operate before January 1, 1979, must satisfy the applicable requirements of
Appendix R to this part, including specifically the requirements of Sections III.G,
III.J, and III.O. Appendix R,Section III.G.3 of 10 CFR Part 50, requires, in part,
that alternative or dedicated shutdown capability and its associated circuits,
independent of cables, systems or components in the area, room, or zone under
consideration should be provided where the protection of systems whose
function is required for hot shutdown does not satisfy the requirement of
paragraph G.2 of this section. In addition, fire detection and a fixed fire
suppression system shall be installed in the area, room, or zone under
consideration.
Contrary to the above, on April 19, 2015, the licensee failed to ensure that
alternative or dedicated shutdown capability and its associated circuits were
independent of cables in the area. Specifically, procedure F5 Appendix B,
Control Room Evacuation (Fire), Revision 31, did not contain actions to isolate
the RCP breaker circuits to prevent restarting due to a fire induced loss of remote
trip and loss of RCP seal cooling water that could lead to an increased rate of
seal degradation and a small break loss of coolant accident. These actions were
required to achieve and maintain safe shutdown in the event of a fire that
resulted in functional loss and/or evacuation of the control/relay and cable
spreading rooms.
Section 9.1 of the NRC Enforcement Policy allows the NRC to exercise
enforcement discretion for certain fire protection related non compliances
41
identified as a result of a licensees transition to the new risk informed,
performance based fire protection approach included in 10 CFR 50.48(c), and for
certain existing non compliances that reasonably may be resolved by compliance
with 10 CFR 50.48(c) as long as certain criteria are met. This risk informed,
performance based approach is referred to as NFPA 805, Performance Based
Standard for Fire Protection for Light Water Reactor Electric Generating Plants.
The licensee is in transition to NFPA 805 and therefore the licensee-identified
violation was evaluated in accordance with the criteria established by Section
9.1(a) of the NRCs Interim Enforcement Policy Regarding Enforcement
Discretion for Certain Fire Protection Issues (10 CFR 50.48) for a licensee in
NFPA 805 transition. The inspectors determined that for this violation: (1) the
licensee would have identified the violation during the scheduled transition to 10
CFR 50.48(c); (2) the licensee had established adequate compensatory
measures within a reasonable time frame following identification and would
correct the violation as a result of completing the NFPA 805 transition; (3) the
violation was not likely to have been previously identified by routine licensee
efforts; and (4) the violation was not willful. The finding also met additional
criteria established in section 12.01.b of IMC 0305, Operating Assessment
Program. In addition, in order for the NRC to consider granting enforcement
discretion the violation must not be associated with a finding of high safety
significance (i.e., Red).
The licensee performed risk evaluation V.SPA.15.012, Revision 3, dated
December 18, 2015, and determined that this issue was not associated with a
finding of high safety significance. A region III senior reactor analyst (SRA)
reviewed the evaluation and concluded that the result was reasonable and that
the finding was less than Red and eligible for enforcement discretion. The
dominant core damage sequence from the licensees evaluation involved an
electrical cabinet fire in the relay room involving the cables that could cause
spurious operation of the RCPs and that would lead to alternate shutdown. The
licensee identified several conservative assumptions in the analysis. The SRA
agreed that some were conservative, notably that any fire affecting the cables in
the relay room that could cause a spurious start of an RCP would also result in a
loss of all seal cooling due to fire damage. The SRA used IMC 0609, Appendix
F, Fire Protection Significance Determination Process, to review the results of
the licensees evaluation. The relay room is similar to a cable spreading room
with electrical cabinets. The fire frequency for this room in Appendix F is
6E-3/yr. The probability of non-suppression was estimated to be 2E-2 and the
spurious operation probability was assumed to be 0.6. The product of these
values (7.2E-5/yr) represents a bounding relay room fire scenario delta core
damage frequency (CDF) for this finding. Since the bounding result is consistent
with the licensees conclusion, the SRA determined that the delta core damage
frequency for the finding was less than 1E-4/yr, which is less than Red.
42
In addition, the licensee entered this issue into their corrective action program
as CAP 01475242. As a result, the inspectors concluded that the violation met
all four criteria established by Section 9.1(a) and that the NRC was exercising
enforcement discretion to not cite this violation in accordance with the Interim
Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection
Issues.
ATTACHMENT: SUPPLEMENTAL INFORMATION
43
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
K. Davison, Site Vice President
T. Conboy, Director of Site Operations
E. Blondin, Engineering Director
W. Paulhardt, Plant Manager
J. Boesch, Maintenance Manager
T. Borgen, Operations Manager
B. Boyer, Radiation Protection Manager
H. Butterworth, Business Support Manager
B. Carberry, Emergency Preparedness Manager
J. Corwin, Security Manager
D. Gauger, Chemistry/Environmental Manager
S. Martin, Performance Assessment Manager
M. Pearson, Regulatory Affairs Manager
P. Wildenborg, Sr. Health Physicist
S. Redner, Project Manager, Engineering Programs
P. Brunsgaard, Manager, Engineering Programs
T. Downing, ISI Engineering
J. Wren, NDE Level III
G. Carlson, Senior Licensing Engineer, Regulatory Affairs
E. Baker, Chemist
J. Callahan, Fleet EP Manager
P. Oleson, Regulatory Analyst
U.S. Nuclear Regulatory Commission
K. Riemer, Chief, Reactor Projects Branch 2
T. Beltz, Project Manager, Office of Nuclear Reactor Regulation
Attachment
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000306/2015004-01 NCV Failure to Meet ANSI N14.6 Section 5.3.1 Requirements
(Section 1R08.1)05000282/2014005-02 NCV Failure to Adequately Calibrate Liquid Effluent Monitors
(Section 2RS5.1)
Closed
05000306/2015004-01 NCV Failure to Meet ANSI N14.6 Section 5.3.1 Requirements
(Section 1R08.1)05000282/2014005-02 NCV Failure to Adequately Calibrate Liquid Effluent Monitors
(Section 2RS5.1)05000282/2014002-00 LER Diesel Generators Declared Inoperable Due to Not
Meeting High Energy Line Break Requirements
(Section 4OA3.2)05000282/2014002-01 LER Diesel Generators Declared Inoperable Due to Not
Meeting High Energy Line Break Requirements
(Section 4OA3.2)05000282/2015001-00 LER Fan Coil Unit Leak (Section 4OA3.3)05000282/2015002-00 LER Fan Coil Unit Leak (Lower Head) (Section 4OA3.4)05000282/2015003-00 LER Unanalyzed Condition Due to Non-Compliance with
10 CFR 50 Appendix R (Section 4OA3.5)
Discussed
None.
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.
1R04 Equipment Alignment (71111.04)
- 1C28.1 AOP4; Restarting Unit 1 AFWP After Low Suction/Discharge Pressure Trip; Revision 6
- CAP 01002789; AF System Components with Incorrect Quality Level; November 3, 2005
- CAP 01271632; MRB-028 AF System Components are Incorrect Quality Level;
February 18, 2011
- C28-2; Auxiliary Feedwater System Unit 1; Revision 52
- CAP 01500181; QF1142 in WO-472499 Needs More Info; November 4, 2015
- Condition Report Search from January 1, 2010 to October 1, 2015
- DBD SYS-28B; Prairie Island Nuclear Generating Plant Design Bases Document; Revision 8
- Drawing B-15300; Min. Flow Orifice Assembly; August 27, 1970
- Drawing NF-39222; Feedwater & Aux Feedwater Unit 1; Revision 83
- Letter from Pacific Pumps Dresser to Northern States Power Company; Minimum
Flow-Nuclear Service Pumps Comments to NRC Bulletin 88-04; September 16, 1988
- Letter from U.S. NRC Office of Material Safety and Safeguards; NRC Regulatory Issue
Summary 2015-06 Tornado Missile Protection; June 10, 2015
- SE-0302 Equipment Details; Valve AF-26-5; 11 TD AFW PMP Oil Clr Outl to Sump
- SE-0302 Equipment Details; Valve AF-33-1; 11 TD AFW PMP Recirc to 11 CST
- SWI Eng-30 Addendum-A; Prairie Island Nuclear Generating Plant Q-List Downgrade
Resolution Project Position Papers; Revision 1
- Temporary Change Request 084A for SP 1100 12; Motor Driven AFW Pump Monthly Test;
Revision 84
- USAR Appendix I; Prairie Island Updated Safety Analysis Report; Revision 33
- CAP 01500373; Question by NRC in Regards to Drawings in SharePoint; November 5, 2015
- CAP 01500324; Safety Function for RCP Inlet and Outlet MVs Evaluation; November 5, 2015
- SP 2251; Caustic Addition Valve Quarterly Test; Revision 13
- H5; Motor Operated Valve Program; Revision 19
- H10.1.B; Inservice Testing Program Component Basis Document; Revision 3
- CAP 01502434; 21 Caustic Standpipe Level Spiked Low to Low Alarm Set-point;
November 18, 2015
- DBD SYS-8D; Containment Spray System Design Basis Document; Revision 4
- B18D; Containment Spray System Bases Document; Revision 9
- NF-39252; Caustic Addition System Unit 1 & 2 Flow Diagram; Revision 83
- B18D; Containment Spray System Description; Revision 9
1R05 Fire Protection (71111.05)
- NF-39228-1; Fire Protection and Screen Wash System Unit 1 & 2 Flow Diagram; Revision 91
- F5 Appendix A; Fire Area 71 Requirements; Revision 13
- F5 Appendix F; Fire Hazards Analysis Matrix; Revision 30
- NF-39228-3; Sprinkler Fire Protection System Turbine U 2-Screen-house Unit 1 & 2;
Revision 78
3
- CAP 01504212; Unexpected FP Annunciator in Unit 2 Feedwater Pump Area;
December 1, 2015
- CAP 01504521; NRC Question: Fire Strategies Shows Containment Fire Extinguishers;
December 3, 2015
1R06 Flooding (71111.06)
- 1C28.1 AOP2; Loss of Condensate Supply to Aux Feed Water Pump Suction; Revision 0
- 5AWI 8.9.0; Internal Flooding Drainage Control; Revision 15
- C31 AOP1; Fire Protection Line Break; Revision 3
- Calculation 1067-0022-001; Determination of Flow Path Input for Floor Drains; Revision 0
- Calculation ENG-ME-586; Effects of Flooding in the AFW Pump Room from a Postulated
Pipe Rupture; June 9, 2005
- Calculation ENG-ME-759; Gothic Internal Flooding Calculation for the Turbine Building;
Revision 1D
- Drawing NF-38213; Turbine Room-Concrete Plan of Base Slab Floor Drains-Class I Area;
Revision G
- H36; Plant Flooding; Revision 10
- TP 1398; Verify Physical Inputs to Internal Flooding Evaluations; Revision 5
- WO 00501079-01; TP 1398-Internal Flooding Input Verifications/Evals Eng:
TP 1398-(Non-RCA Areas) Internal Flooding Input Evals; May 5, 2015
1R07 Annual Heat Sink Performance (71111.07A)
- WO 498516-01; 22 CC HX South Internal Inspection; Revision 0
1R08 Inservice Inspection Activities (71111.08)
- Safety Evaluation Related to the Control of Heavy Loads; Dated 06/06/83
- ANSI N14.6; American National Standards for Special Lifting Devices for Shipping Containers
Weighing 10 000 Pounds or More for Nuclear Materials; 1978 Edition
- Calculation ENG-CS-361; Evaluation of the Acceptability of the Reactor Vessel Head Lift Rig,
Reactor Vessel Internals Lift Rig, Load Cell and Linkage to the Requirements of NUREG 0612;
Revision 0
- NDE Report Nos. BOP-MT-15-040-051,021-023; Magnetic Particle Examination of Reactor
Vessel Internals Lift Fixture Welds; Dated 10/27/15
- WO 00457321; Perform NDE Magnetic Particle Examination of Reactor Head Lifting Rig;
Dated 10/23/15
- NDE Report No. 2005M008; Magnetic Particle Examination of Reactor Head Lift Fixture;
Dated 06/03/05
- WO 457197-07; Perform NDE Exams of Reactor Vessel Internals Lifting Device;
Dated 10/24/15
- CAP 01457469; Operating Experience (IN 2014-02) Item Evaluated: Crane and Heavy Lift
Issues Identified; Dated 01/12/15
- Engineering Evaluation EC 26341; Reactor Vessel Internal Lift Rig Torque Tube Weld
Evaluation; Dated 10/26/15
- WO 00436724; SP 1392 Unit 1 RCS System Bolting Inspection; Dated 08/05/14
- CAP 01450417; BACC Evaluation for ISI Indication on CV-31325; Dated 10/11/14
- CAP 01450480; BACC Evaluation for ISI Indication on RC-19-1; Dated 10/11/14
- CAP 01450476; BACC Evaluation for ISI Indication on 135-011; Dated 10/11/4
- CAP 01427328; BACC Evaluation for Leak Identified in Unit 2 Containment 21 Vault;
Dated 04/17/14
4
- CAP 01498446; Functionality Assessment of Reactor Vessel Internals Lifting Device;
Dated 10/29/15
- CAP 01412727; Leak From Capped Drain Downstream of 2RC-8-19; Dated 12/30/13
- CAP 01431405; Boric Acid Leak was Found on 2RC-8-31; Dated 05/20/14
- CAP 01469111; Boric Acid Packing Leak on 2SI-35-6; Dated 03/06/15
- CAP 01492989; Boric Acid Built Up Below 21 SI Pump; Dated 09/11/15
- CAP 01445383; 22 Safety Injection Pump IB/OB Mechanical Seal Leakage; Dated 09/04/14
- WO 00406128; Remove and Replace Valve 2RC-7-2, Loop A to Pressurizer CV 31228
BY-PASS; Dated 09/28/13
- H2; Boric Acid Corrosion Control Program; Revision 25
- NDE Report No. 2015V011; VT-3 of AFWH-79 Sway Strut/Clamp; Dated 10/21/15
- FP-PE-NDE-530; Visual Examination, VT-3; Revision 8
- CAP 01499213; Internals Lift Rig Question; Dated 10/29/15
- CAP 01497779; NRC Question in Regards to ISI Exam of Reactor Head Lift Rig; Dated
10/21/15
- CAP 01497774; PM 3560-52 Needs to be Revised for Better Work Execution; Dated 10/21/15
- PM 3560-52; Reactor Head Lifting Rig Spreader & Connection Legs Assembly Inspections;
Revision 13
- CAP 01452946; ISI Indication on Hanger 1RSIH-415; Dated 10/25/14
- CAP 01414257; Non-Conformance with ASME Section XI; Dated 01/13/14
- CAP 01429434; Potential ISI Issue for ANII Procedure Reviews; Dated 05/05/14
- CAP 01452105; Metallic Item Found on the Reactor Vessel Flange; Dated 10/20/14
- NDE Report No. 2015U023; Ultrasonic Examination of SI Elbow-to-Pipe Weld W-6;
Dated 11/01/15;
- NDE Report No. 2015U044; Ultrasonic Examination of RH Pipe-to-Elbow Weld W-5;
Dated 11/05/15
- NDE Report No. 2015V013; VT-3 of AFWH-64 Sway Strut/Clamp; Dated 10/21/15
- Procedure FP-PE-NDE-402; Ultrasonic Examination of Austenitic Pipe Welds-Supplement 2;
Revision 5
SWI-NDE-ET-1; Bobbin Coil Data Analysis; Revision 6
- SWI-NDE-ET-3; Rotating Coils Data Analysis; Revision 6
- SWI-NDE-ET-6; Array Coil Data Analysis; Revision 1
1R11 Licensed Operator Requalification Program (71111.11)
- 2C1.3-M3; Unit 2 Shutdown to Mode 3; Revision 5
- 2C1.2-M2; Unit 2 Startup to Mode 2; Revision 4
- 2C1.2-M1; Unit 2 Startup to Mode 1; Revision 1
- D30; Post Refueling Startup Testing; Revision 61
1R12 Maintenance Effectiveness (71111.12)
- CAP 01198723; 11 RCP Motor Had High Breakaway Torque Reading; September 21, 2009
- CAP 01490741; IST and MOV Program Discrepancies; August 21, 2015
- WO 532146-16; 21 RCP Seal Replacement; November 30, 2015
- CAP 01500324; Unit 1 and 2 RCP CC Inlet and Outlet MV Operability Evaluation; November
6, 2015
- CAP 01250606; HELB Interaction in Aux Building Overstress CC Piping; September 21, 2010
- NF-39216-1; Cooling Water-Screen-house Unit 1 & 2; Revision 89
- EC 13000; High Energy Line Break Evaluation for Component Cooling Water Piping in the
Turbine Bldg; Revision 0
5
1R13 Maintenance Risk Assessment and Emergent Work Control (71111.13)
- Shift Manager Logs and Control Room Logs Units 1 & 2; November 17-19, 2015
1R15 Operability Determination and Functional Assessments (71111.15)
- CAP 01504216; AFW Recirc Line Recommended Procedure Change; December 2, 2015
- QF0739; AFWP Recirculation Line Evaluation NRC Response Form; December 2, 2015
- CAP 01500184; AFWP Recirculation Line Seismic Evaluation; November 14, 2015
- CAP 01501764; Additional NRC Question Related to AFW Recirc Line and HELB; November
13, 2015
- NF-39222; Flow Diagram Feedwater and Aux Feedwater Unit 1; Revision 83
- Operating Information 15-63; Auxiliary Feedwater Recirculation Flow Min-flow Requirements;
November 20, 2015
1R19 Post-Maintenance Testing (71111.19)
- H36; Plant Flooding; Revision 10
- CAP 01501977; Six of 97 FCU Pipe Flanges Required Re-torque During PMT; November 16,
2015
- WO 519240-03; Replace SV-33133; October 2, 2015
- CAP 01495575; SV-33133 Stroked Outside Ref. Range During PMT
- CAP 01495499; SV-33133 Failed PMT Testing Under WO 519240; October 2, 2015
- WO 519240-02; SV-33133 Stroke Time Outside Ref. Range; October 2, 2015
- SP 1151A; Train A Cooling Water System Quarterly Test; Revision 20
- CAP 01501698; 21 RCP did not Rotate as Expected During Alignment; November 13, 2015
- WO 492354-06; Mechanical Troubleshooting of 21 RCP; November 17, 2015
1R20 Outage Activities (71111.20)
- CAP 01500324; Safety Function for RCP Inlet and Outlet MVs; November 20, 2015
- Unit Two Refueling Outage October 2015 Shutdown Safety Assessment; Revision 0
- 2C1.4; Unit 2 Power Operation; Revision 56
- 2C1.3-M2; Unit 2 Shutdown to Mode 2; Revision 3
- 2C19.1; Containment Unit 2 Plant Operation Requirements; Revision 23
- CAP 01504150; Identified Issues During Final Unit 2 Containment Walk Through;
December 2, 2015
- CAP 01503211; U2 Rx Vsl Support Fan Motor FLA Question; November 24, 2015
- NF-39220; Unit 1 Condensate System Flow Diagram; Revision 79
- SP 2177; Core Inventory Verification; November 16, 2015
- CAP 01506302; Water Found on 755 Level of U2 CTMT Following Rx Trip;
December 17, 2015
- CAP 01506286; 25B Tube Side Relief Valve Lifted Prior to Taking 22 FWP OOS;
December 17, 2015
- CAP 01504099; Ceiling Leak in Unit 2 Rod Drive Room; December 1, 2015
- CAP 01499287; Leaching was Identified on the 21 RCP Seal Faces; October 29, 2015
- CAP 01499105; MV-32197 as Found Configuration; October 29; 2015
- CAP 01491555; Ball Valve PMs Suspended Due to Parts Unavailability; August 29, 2015
- CAP 01505839; Eddy Current Heating on Unit 2 Generator Bushing Box IPB Duct;
December 14, 2015
6
1EP4 Emergency Action Level and Emergency Plan Changes (71114.04)
- Prairie Island Emergency Plan; Revisions 50 and 51
- PINGP-1576; Emergency Action Level Matrix; Revisions 7 and 8
- F3-2.1; Emergency Action Level Technical Bases; Revision 10
- FP-R-EP-02; 10 CFR 50.54(q) Review Process, Revision 11
- QF-0724; 10 CFR 50.54(q) Review Form, Revision 6
- CAP 01506257; NRC ID Wrong Reference Used in 10 CFR 50.54(q) Evaluation; Dated
12/17/15
1EP6 Drill Evaluation (71111.06)
- P9116SE-0101; LOR Cycle 16A Simulator Evaluation; October 1, 2015
2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01)
- RPIP 1331; Radioactive Material Control; Revision 2
- RPIP 1120; Posting of Restricted Areas; Revision 40
- RPIP 1123; Alpha Characterization Smears; Revision 2
- Technical Basis Document;14-001; Alpha Radiation Protection Program; Revision 0
- FP-RP-AM-01; Alpha Monitoring Program; Revision 5
- RPIP 1135; RWP Coverage; Revision 35
- RPIP 1204; Evaluation of Airborne Radioactivity; Revision 20
- RPIP 1202; Gaseous Airborne Radioactive Monitoring; Revision 9
- RPIP 1331; Radioactive Material Control; Revision 2
- RPIP 1300; Control and Tagging of Radioactive Material; Revision 23
2RS2 Occupational ALARA Planning and Controls (71124.02)
- Prairie Island Nuclear Generating Plant 2R28 Radiation Protection Department Outage
Manual; Date Not Provided
- Prairie Island Nuclear Generating Plant; Dose Excellence Plan; 2013-2017; Revision 0
- Prairie Island Nuclear Generating Plant; 2R28 Radiation Protection Department Outage
Report; Steam Generator Project; Dated 02/03/14
- Prairie Island; 1R29 Radiation Protection Department Outage Report; Dated 02/12/15
- FP-RP-SEN-02; Radiological Work Planning and Controls; Revision 3
- RWP and Associated ALARA Files; RWP 152500; 2R29-RTD Replacement Project;
Various Dates
- RWP and Associated ALARA Files; RWP 155021; 10-Year ISI/Corrosion Inspection-2R29;
Various Dates
- RWP and Associated ALARA Files; RWP 152055; Scaffold Standard Work-U2 Outage;
Various Dates
- RWP and Associated ALARA Files; RWP 152300; Primary SG Activities-U2 Outage; Various
Dates
2RS5 Radiation Monitoring Instrumentation (71124.05)
- CAP 01490581; Missing Documents for Radiation Monitor Primary Calibrations;
August 20, 2015
- CAP 01494632; Cal of Process Rad Monitors Dose Meet H4 ODCM Standard;
September 25, 2015
- CAP 01500149; Additional Eff Rad Monitors Require Evaluation; November 4, 2015
7
- Offsite Dose Calculation Manual (ODCM); Revision 29
- 1R19; Unit 1 Steam Generator Blowdown Monitor Calibration; August 25, 2010
- 2R19; Unit 2 Steam Generator Blowdown Monitor Calibration; April 7, 1993
- 2R19; Unit 2 Steam Generator Blowdown Monitor Calibration; October 15, 2015
- R-18; Waste Effluent Liquid Monitor Calibration; April 7, 1993
- R-18; Waste Effluent Liquid Monitor Calibration; October 2, 2015
4OA1 Performance Indicator Verification (71151)
- FP-R-PI-01; Preparation of NRC Performance Indicators; Revision 3
- FP-R-PI-01; Preparation of NRC Performance Indicators; Attachment 6; RCS Specific
Activity; Various Dates
- FP-R-PI-01; Preparation of NRC Performance Indicators; Attachment 9; Occupational
Exposure Control Effectiveness; Various Dates
- FP-R-PI-01; Preparation of NRC Performance Indicators; Attachment 10; RETS/ODCM
Radiological Effluent Occurrence; Various Dates
4OA2 Identification and Resolution of Problems (71152)
- C37.9; Control, Relay, and Computer Room Ventilation; Revision 28
- C37.14; Service Building Ventilation System; Revision 13
- CAP 01469452; NRC Questioned Relative Humidity Level in Multiple Areas; March 10, 2015
- CAP 01468498; NRC Identified-Question CR Humidity Requirements; March 3, 2015
- CAP 01447443; Computer Room Low Humidity; September 21, 2014
- CAP 01498739; C37.14 Rev. 13 (Secondary); November 17, 2015
- CAP 01276040; GL-08-01 TI-177 Drawing Error on NF-39252; March 18, 2011
- PI-21.3B.002; Namco Limit Switch Series Qualification H, K; Revision 1
- EC 00026393; Relative Humidity Impact(s) on Electrical Components; Revision 0
- CAP 01495083; ERCS Alarm for Low Humidity; September 29, 2015
- CAP 01494719; Control Room Humidifiers Should be Repaired or Abandoned;
September 25, 2015
- CAP 01495292; C37.9, Revision 28, Relay, and Computer Room Ventilation; October 1, 2015
- WO 531436; ERCS Alarm for Low Humidity; October 1, 2015
- CAP 01501381; 31 Namco Position Switches are Past Qualified Life; November 11, 2015
4OA3 Follow-Up of Events and Notices of Enforcements Discretion (71153)
- CAP 01506299; NUE HU2.1 Declared Following Fire Alarm in U2 CTMT; December 17, 2015
- CAP 01506281; Flakes Found on U2 CTMT A/S Particle Filter; December 17, 2015
- CAP 01506285; Unit 2 Reactor Trip Due to Turbine Trip; December 17, 2015
8
LIST OF ACRONYMS USED
ADAMS Agencywide Document Access Management System
ALARA As-Low-As-Is-Reasonably-Achievable
ANSI American National Standards Institute
ASME American Society of Mechanical Engineers
BWR Boiling Water Reactor
BACC Boric Acid Corrosion Control
CAP Corrective Action Program
CC Component Cooling
CDF Core Damage Frequency
CFR Code of Federal Regulations
CL Cooling Water
DC direct current
EAL Emergency Action Level
EC Engineering Change
ECCS Emergency Core Cooling System
EDG Emergency Diesel Generator
EPRI Electric Power Research Institute
ERCS Emergency Response Computer System
ET Eddy Current
FCU Fan Cooling Unit
IMC Inspection Manual Chapter
INPO Institute of Nuclear Power Operations
IN Information Notice
IP Inspection Procedure
IPEEE Individual Plant Examination of External Events
IR Inspection Report
ISI Inservice Inspection
LER Licensee Event Report
MSPI Mitigating Systems Performance Index
NCV Non-Cited Violation
NDE Nondestructive Examination
NEI Nuclear Energy Institute
NFPA National Fire Protection Association
NIST National Institute of Standards and Technology
NRC U.S. Nuclear Regulatory Commission
ODCM Offsite Dose Calculation Manual
OSP Outage Safety Plan
PARS Publicly Available Records System
PD Performance Deficiency
PI Performance Indicator
PM Planned or Preventative Maintenance
PWR Pressurized Water Reactor
RCA Radiologically Controlled Area
RCP Reactor Cooling Pump
RETS Radiological Effluent Technical Specifications
RFO Refueling Outage
9
RTD Resistance Temperature Detector
RWP Radiation Work Permit
SER Safety Evaluation Report
SDP Significance Determination Process
SI Safety Injection
SRA Senior Risk Analyst
SSC Structures, Systems, Components
TB Turbine Building
TS Technical Specifications
USAR Updated Safety Analysis Report
VT-3 Visual Examination
K. Davison -2-
In accordance with Title 10 of the Code of Federal Regulations (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
System (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/
Branch 2
Division of Reactor Projects
Docket Nos. 50-282; 50-306;72-010
License Nos. DPR-42; DPR-60; SNM-2506
Enclosure:
IR 05000282/2015004; 05000306/2015004
cc: Distribution via LISTSERV
DISTRIBUTION:
Kimyata MorganButler Carole Ariano
RidsNrrPMPrairieIsland Resource Linda Linn
RidsNrrDorlLpl3-1 Resource DRPIII
RidsNrrDirsIrib Resource DRSIII
Cynthia Pederson Jim Clay
Darrell Roberts Carmen Olteanu
Richard Skokowski ROPreports.Resource@nrc.gov
ADAMS Accession Number: ML16039A364
Publicly Available Non-Publicly Available Sensitive Non-Sensitive
OFFICE RIII RIII RIII RIII
NAME KRiemer/bw
DATE 02/08/2016
OFFICIAL RECORD COPY