ML111300561
| ML111300561 | |
| Person / Time | |
|---|---|
| Site: | Monticello  |
| Issue date: | 05/10/2011 |
| From: | Kenneth Riemer NRC/RGN-III/DRP/B2 |
| To: | O'Connor T Northern States Power Co |
| References | |
| EA-11-050 IR-11-002 | |
| Download: ML111300561 (58) | |
See also: IR 05000263/2011002
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE ROAD, SUITE 210
LISLE, IL 60532-4352
May 10, 2011
Mr. Timothy J. OConnor
Site Vice President
Monticello Nuclear Generating Plant
Northern States Power Company, Minnesota
2807 West County Road 75
Monticello, MN 55362-9637
SUBJECT: MONTICELLO NUCLEAR GENERATING PLANT NRC INTEGRATED AND
POWER UPRATE REVIEW INSPECTION REPORT 05000263/2011002 AND
EXERCISE OF ENFORCEMENT DISCRETION
Dear Mr. OConnor:
On March 31, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed integrated and
power uprate inspections at your Monticello Nuclear Generating Plant. The enclosed report
documents the inspection findings, which were discussed on April 5, 2011, with you and other
members of your staff.
The inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, licensee-identified issues were discovered that
involved violations of NRC requirements. These 10 CFR 50, Appendix R-related issues,
discussed in Sections 1RO5.2 and 4OA3.4, were screened and determined to warrant
enforcement discretion per Enforcement Guidance Memorandum (EGM) 09-002,
Enforcement Discretion for Fire Induced Circuit Failures. One additional licensee-identified
violation is documented in Section 4OA7 of this report.
Based on the results of this inspection, one NRC-identified and one self-revealed finding of
very low safety significance were identified. The findings each involved a violation of NRC
requirements. However, because of their very low safety significance, and because the issues
were entered into your corrective action program, the NRC is treating the issues as non-cited
violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.
If you contest the subject or severity of 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
a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III,
2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement,
T. O'Connor -2-
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector
Office at the Monticello 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 Monticello Nuclear
Generating Plant.
In accordance with 10 CFR 2.390 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 NRC Public Document Room or from the Publicly Available Records System (PARS)
component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website
at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Kenneth Riemer, Chief
Branch 2
Division of Reactor Projects
Docket No. 50-263
License No. DPR-22
Enclosure: Inspection Report 05000263/2011002
w/Attachment: Supplemental Information
cc w/encl: Distribution via ListServ
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No: 50-263
License No: DPR-22
Report No: 05000263/2011002
Licensee: Northern States Power Company, Minnesota
Facility: Monticello Nuclear Generating Plant
Location: Monticello, MN
Dates: January 1 through March 31, 2011
Inspectors: S. Thomas, Senior Resident Inspector
P. Voss, Resident Inspector
P. Cardona-Morales, Resident Inspector, Acting
M. Phalen, Senior Health Physicist
C. Tilton, Senior Reactor Inspector
A. Dahbur, Senior Reactor Inspector
D. Jones, Reactor Inspector
N. Shah, Project Engineer
Approved by: K. Riemer, Chief
Branch 2
Division of Reactor Projects
Enclosure
TABLE OF CONTENTS
SUMMARY OF FINDINGS ........................................................................................................... 1
REPORT DETAILS ....................................................................................................................... 3
Summary of Plant Status ........................................................................................................... 3
1. REACTOR SAFETY ....................................................................................................... 3
1R01 Adverse Weather Protection (71111.01) ............................................................. 3
1R04 Equipment Alignment (71111.04)........................................................................ 4
1R05 Fire Protection (71111.05) .................................................................................. 5
1R06 Flooding (71111.06) ............................................................................................ 8
1R07 Annual Heat Sink Performance (71111.07A) ...................................................... 8
1R08 Inservice Inspection Activities (71111.08G) ........................................................ 9
1R11 Licensed Operator Requalification Program (71111.11) ................................... 10
1R12 Maintenance Effectiveness (71111.12) ............................................................. 11
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13) ....... 12
1R15 Operability Evaluations (71111.15) ................................................................... 12
1R18 Plant Modifications (71111.18).......................................................................... 13
1R19 Post-Maintenance Testing (71111.19) .............................................................. 14
1R20 Outage Activities (71111.20) ............................................................................. 14
1R22 Surveillance Testing (71111.22) ....................................................................... 19
1EP6 Drill Evaluation (71114.06) ................................................................................ 20
2. RADIATION SAFETY ................................................................................................... 21
2RS5 Radiation Monitoring Instrumentation (71124.05) ............................................. 21
4. OTHER ACTIVITIES ..................................................................................................... 26
4OA1 Performance Indicator Verification (71151)....................................................... 26
4OA2 Identification and Resolution of Problems (71152) ........................................... 28
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153) .............. 30
4OA5 Other Activities .................................................................................................. 35
4OA6 Management Meetings...................................................................................... 38
4OA7 Licensee-Identified Violations ........................................................................... 38
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 ............................................................................................................ 12
Enclosure
SUMMARY OF FINDINGS
IR 05000263/2011002; 01/01/2011 - 03/31/2011; Monticello Nuclear Generating Plant,
Refueling Outage Activities; Follow-Up of Events; and Notices of Enforcement Discretion.
This report covers a three-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. Two Green findings, one NRC-identified and
one self-revealed, are documented in this report. These findings were considered non-cited
violations (NCV) of NRC regulations. The significance of most findings is indicated by their
color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,
Significance Determination Process (SDP). Findings for which the SDP does not apply may
be Green or be assigned a severity level after NRC management review. The NRCs program
for overseeing the safe operation of commercial nuclear power reactors is described in
NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.
A. NRC-Identified and Self-Revealed Findings
Cornerstone: Initiating Events
- Green. A finding of very low safety significance and associated NCV of 10 CFR 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed
when the licensee failed to adequately implement the requirements of their fleet tagging
procedure, a procedure affecting quality, during maintenance on the safety-related
CST-88 B low pressure coolant injection (LPCI) fill line check valve. This failure
resulted in an unintentional breach of the condensate service water (CSW) system and
subjected workers to a potentially contaminated, pressurized water source. Additionally,
at the time of the breach, the CSW system was one of the water sources being credited
in support of the shutdown safety function of inventory control. The licensee entered this
issue into the corrective ation program (CAPs 1275935 and 1275963) and took
immediate corrective actions to restore the check valve to its installed configuration to
terminate the water leakage. At the time of this report, the licensee had assembled a
team to perform a root cause evaluation.
The inspectors determined that the licensees failure to adequately implement their
tagging process to protect workers and equipment from the effects of breaching the
pressurized CSW header during maintenance on a safety-related check valve was a
performance deficiency because it was the result of the failure to meet a requirement,
the cause was reasonably within the licensees ability to foresee and correct, and
should have been prevented. The inspectors screened the performance deficiency per
IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the
issue was more than minor because the performance deficiency could have reasonably
been viewed as a precursor to a more significant event. In this instance, the
performance deficiency resulted in an unintentional breach of the operating CSW
system and subjected workers to a potentially contaminated, pressurized water source.
Additionally, at the time of the breach, the CSW system was one of the water sources
being credited in support of the shutdown safety function of inventory control. As a
result, this finding was evaluated under the Initiating Events Cornerstone.
The inspectors applied NRC IMC 0609, Significance Determination Process,
Appendix G, "Shutdown Operations Significance Determination," Attachment 1, to this
finding. The finding was determined to have very low safety significance because it did
not adversely affect core heat removal, inventory control, power availability, containment
1 Enclosure
control, or reactivity guidelines. This finding has a cross-cutting aspect in the area of
Human Performance, work control, because the licensee failed to appropriately plan
work activities by incorporating job site conditions impacting plant systems and
components (H.3(a)). (Section 1R20)
Cornerstone: Barrier Integrity
- Green. A finding of very low safety significance and associated NCV of Technical
Specification 5.4, Procedures, was identified by the inspectors when the licensee
failed to implement the requirements of their foreign material exclusion (FME) and
control procedure during new fuel receipt activities. Specifically, the inspectors
observed two operators exiting and re-entering a Level 1 FME area, without the
knowledge of the FME monitor, at a point that was not being controlled by the FME
monitor. When informed of the issue, the licensee took corrective actions to address
the issue.
The inspectors determined that the licensees failure to adequately implement the
requirements of their FME control procedure during new fuel receipt activities to prevent
the unmonitored access of two operators into a Level 1 FME area was a performance
deficiency because it was the result of the failure to meet a requirement or a standard,
the cause was reasonably within the licensees ability to foresee and correct, and should
have been prevented. The inspectors screened the performance deficiency per
IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined that the
issue was more than minor because it impacted the human performance attribute of the
Barrier Integrity Cornerstones objective to provide reasonable assurance that physical
design barriers (fuel cladding, reactor coolant system, and containment) protect the
public from radionuclide releases caused by accidents or events. The inspectors applied
IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings,
to this finding. The inspectors utilized Column 3 of the Table 4a worksheet to screen the
finding. Since the finding only had the potential to impact the fuel barrier, it screened to
be of very low safety significance. This finding has a cross-cutting aspect in the area of
Human Performance, Work Practices because the licensee did not define and effectively
communicate expectations regarding procedural compliance and perosnnel following
procedures (H.4(b)). (Section 4OA3)
B. Licensee-Identified Violations
Violations of very low safety significance that were identified by the licensee have been
reviewed by inspectors. Corrective actions planned or taken by the licensee have been
entered into the licensees corrective action program. These violations and corrective
action tracking numbers are listed in Section 4OA7 of this report.
2 Enclosure
REPORT DETAILS
Summary of Plant Status
During the first nine weeks of the inspection period, the plant operated at approximately
100 percent power except for minor power adjustments to facilitate rod pattern adjustments and
routine planned surveillance testing activities. On March 4, 2011, the licensee began a planned
downpower, and on March 5, 2011, at 00:18, the main generator breakers were opened and the
licensee began their refueling outage. The licensee remained shutdown for the remainder of
the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection (71111.01)
.1 Readiness for Impending Adverse Weather Condition - Extreme Cold Conditions
a. Inspection Scope
Since extreme cold conditions were forecast in the vicinity of the facility for
January 21, 2011, the inspectors reviewed the licensees overall preparations/protection
for the expected weather conditions. On January 20, 2011, the inspectors walked down
the emergency diesel generator (EDG) building and heating boiler system because their
safety-related functions could be affected or required as a result of the extreme cold
conditions forecast for the facility. The inspectors observed insulation, heat trace
circuits, space heater operation, and weatherized enclosures to ensure operability of
affected systems. The inspectors reviewed licensee procedures and discussed potential
compensatory measures with control room personnel. The inspectors focused on plant
managements actions for implementing the stations procedures for ensuring adequate
personnel for safe plant operation and emergency response would be available.
Specific documents reviewed during this inspection are listed in the Attachment to this
report.
This inspection constituted one readiness for impending adverse weather condition
sample as defined in Inspection Procedure (IP) 71111.01-05.
b. Findings
No findings were identified.
.2 External Flooding
a. Inspection Scope
The inspectors evaluated the design, material condition, and procedures for coping with
the design basis probable maximum flood. The evaluation included a review to check
for deviations from the descriptions provided in the Updated Safety Analysis Report
(USAR) for features intended to mitigate the potential for flooding from external factors.
As part of this evaluation, the inspectors checked for obstructions that could prevent
draining and determined that barriers required to mitigate the flood were in place and
3 Enclosure
operable. Additionally, the inspectors performed a walkdown of the protected area to
identify any modification to the site which would inhibit site drainage during a probable
maximum precipitation event or allow water ingress past a barrier. The inspectors also
reviewed the abnormal operating procedure (AOP) for mitigating the design basis flood
to ensure it could be implemented as written.
This inspection constituted one external flooding sample as defined in IP 71111.01-05.
b. Findings
No findings were identified.
1R04 Equipment Alignment (71111.04)
.1 Quarterly Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
- 11 standby liquid control (SBLC) alignment while 12 SBLC was inoperable due to
maintenance; and
- 11 core spray (CS) system while 12 CS was inoperable for maintenance.
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; 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
corrective action program (CAP) with the appropriate significance characterization.
Documents reviewed are listed in the Attachment to this report.
These activities constituted three partial system walkdown samples as defined in
IP 71111.04-05.
b. Findings
No findings were identified.
4 Enclosure
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:
- Fire Zone 9 (control room);
- Fire Zones 7-A, B, and C (Division I 125V and 250V battery rooms and
Division II 125V battery room);
- Fire Zone 23-A (intake structure pump room);
- Fire Zone 6 (refuel floor); and
- Fire Zones 19-A, B, and C (makeup demin area, essential motor control center
area, and feedwater pipe chase).
The inspectors reviewed areas to assess if the licensee had implemented a fire
protection program that adequately controlled combustibles and ignition sources within
the plant; effectively maintained fire detection and suppression capability; maintained
passive fire protection features in good material condition; and implemented adequate
compensatory measures for out-of-service, degraded or inoperable fire protection
equipment, systems, or features in accordance with the licensees fire plan.
The inspectors selected fire areas based on their overall contribution to internal fire risk
as documented in the plants Individual Plant Examination of External Events with later
additional insights, their potential to impact equipment which could initiate or mitigate a
plant transient, or their impact on the plants ability to respond to a security event.
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.
These activities constituted five quarterly fire protection inspection samples as defined in
IP 71111.05-05.
b. Findings
No findings were identified.
.2 Circuit Analyses (71111.05T)
Background
Title 10 CFR Part 50, Appendix R, Section III.G.2, identified three acceptable methods to
meet the requirement for maintaining one of the redundant trains in the same fire area,
outside of primary containment, free of fire damage. The three methods included a
combination of physical barriers, spatial separation, and fire detection and automatic
suppression systems.
5 Enclosure
In October 2009, the NRC issued guidance in Regulatory Guide (RG) 1.189,
Fire Protection for Nuclear Power Plant, Revision 2, to identify acceptable methods
for resolving issues related to circuits required for post-fire safe shutdown and circuits
important to post-fire safe shutdown. Equipment required for post-fire safe shutdown
(credited train) must use one of the three methods identified in Section III.G.2 to protect
the circuits located within the same fire area from damage, including single and multiple
spurious operations (MSOs). For important to post-fire safe shutdown circuits,
the licensee may use operator manual actions if the licensee demonstrates they can be
shown to be feasible and reliable or resolve issues using other analysis methods
including fire modeling.
In May 2009, the NRC issued Enforcement Guidance Memorandum (EGM) 09-002,
Enforcement Discretion for Fire Induced Circuit Faults, which described the conditions
limiting enforcement discretion during the resolution of the fire protection concerns
involving MSOs. The EGM limited the enforcement discretion to three years from the
date of issuance of RG 1.189, Revision 2: (1) six months following the issuance of
RG 1.189, Revision 2, for licensees to identify noncompliances related to multiple fire
induced circuit faults, place the noncompliances into their CAP and implement
compensatory measures for the noncompliances, and (2) three years following the
issuance of RG 1.189, Revision 2, for licensees to complete the corrective actions
associated with noncompliant multiple fire induced circuit faults. The enforcement
discretion would not be granted to identified noncompliances that are found to be willful
or findings that the Reactor Oversight Process (ROP) SDP would evaluate as red or
categorize at Severity Level I.
By a letter dated November 30, 2005, Nuclear Management Company (NMC) notified
the NRC of Monticello Nuclear Generating Plants (MNGP) intention to adopt NFP 805
in accordance with 10 CFR 50.48(c), National Fire Protection Association
(NFPA) Standard 805. Xcel Energy, the current Monticello licensee holding company,
later notified the NRC by a letter dated July 16, 2010, of the notice of withdrawal of their
letter of intent to transition to 10 CFR 50.48(c) for Monticello.
a. Inspection Scope
The inspectors conducted a one-week long inspection, during the week of
February 7, 2011, as part of the triennial fire protection inspection. As a result of
the licensees decision to withdraw their intention to comply with 10 CFR 50.48(c),
this inspection was completed prior to the actual date of the triennial fire protection
inspection, scheduled to be completed this year. During the inspection, the inspectors
reviewed a representative sampling of single and multiple spurious issues throughout
the plant to verify:
- The licensee successfully addressed single and multiple spurious issues in a
way that met regulations;
- The licensee properly classified equipment required for safe shutdown and
equipment important for safe shutdown;
- The adequacy of the licensees evaluation of multiple spurious actuations,
in accordance with RG 1.189 and Nuclear Energy Institute (NEI) 00-01,
Revision 2; and
- The adequacy of the licensees compensatory actions taken for identified
noncompliances.
6 Enclosure
During this inspection, the inspectors reviewed the licensees post-fire safe shutdown
analysis to verify that the licensee had identified both required and important circuits that
could impact safe shutdown. The inspectors reviewed the expert panel results for the
potential fire induced operations of components supporting safe shutdown at MNGP.
The expert panel performed this review in accordance with RG 1.189 and Guidance of
NEI 00-01, Revision 2. The purpose of the expert panel was to review the applicable
industry-developed Generic Owners Group List of MSOs for applicability to MNGP.
The expert panel was also tasked with considering plant-specific MSOs similar to those
in the Generic List, but not specifically listed. The expert panel identified several MSOs,
as applicable to MNGP, and provided recommendations to resolve these issues.
The following is a list of some MSO scenarios reviewed by the inspectors that the expert
panel recommended modifications to because of apparent violations of 10 CFR Part 50,
Appendix R,Section III.G:
- MSO 2.ab - Spurious operation (open) of both reactor core isolation cooling
(RCIC) test return to condensate storage tank (CST) valves with suction on the
suppression pool which may route the RCIC inventory to the CST;
- MSO 2.o - Spurious opening of residual heat removal (RHR) loop cross-tie
valve. Multiple fire induced spurious operation of MO-2033 and other valve(s) on
the opposite train;
- MSO 2.r - Spurious operation that creates Core Spray (CS) pump flow diversion
for injection to the reactor pressure vessel (RPV). Multiple fire induced faults on
MO-1750 circuit that may result in bypassing the torque limit switch; and
RPV injection valve. Multiple fire induced faults on MO-1752 or MO1754 circuits
that may result in bypassing the torque limit switch for each valve.
The licensee entered all identified MSO scenarios into their CAP and initiated alternate
compensatory measures, in the form of documented operator rounds, as justified per the
Fire Protection Engineering Evaluation (FPEE 2010-001, Alternate Compensatory
Measures for MSOs Identified Non-Conformances). In addition, the licensee will perform
additional circuit analysis and evaluations for the non-conformances to determine the
appropriate resolutions prior to the end of the enforcement discretion per EGM 09-002.
The licensee evaluated the aforementioned identified MSOs and determined that these
types of issues would not significantly affect the plant margin of safety since they have
low risk of occurrence and low safety consequences.
The inspectors verified that selected safe shutdown cables had either been adequately
protected from the potentially adverse effects of fire damage or mitigated with approved
manual operator actions, or analyzed to show that fire-induced faults (e.g., hot shorts,
open circuits, and shorts to ground) would not prevent safe shutdown. In order to
accomplish this, the inspectors reviewed electrical schematics associated with each of
the selected safe shutdown components. In addition, the inspectors evaluated the
adequacy of the electrical circuits protective coordination for the safe shutdown
systems electrical power and instrumentation busses.
Based upon the inspectors review, it was determined that the aforementioned identified
noncompliances associated with MSOs were violations of 10 CFR Part 50, Appendix R,
Section III.G. Because the violations were associated with multiple fire induced circuit
faults and identified during the discretion period as described in EGM 09-002,
the NRC is exercising enforcement discretion in accordance with EGM 09-002.
7 Enclosure
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 AOPs to identify licensee
commitments. The specific documents reviewed are listed in the Attachment to this
report. In addition, the inspectors reviewed licensee 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 CAP 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:
- lower 4kV switchgear room following stator cooling water leakage.
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 (71111.07A)
.1 Heat Sink Performance
a. Inspection Scope
The inspectors reviewed the licensees testing of the 12 Residual Heat Removal (RHR)
systems heat exchanger efficiency test 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 report.
This annual heat sink performance inspection constituted one sample as defined in
IP 71111.07-05.
8 Enclosure
b. Findings
No findings were identified.
1R08 Inservice Inspection Activities (71111.08G)
From March 14 through March 24, 2011, the inspectors conducted a review of the
implementation of the licensees inservice inspection (ISI) program for monitoring
degradation of the reactor coolant system, risk-significant piping and components, and
containment systems.
The inservice inspections described in Sections 1R08.1 and 1R08.5 below constituted
one inspection sample as defined in IP 71111.08 05.
.1 Piping Systems Inservice Inspection
a. Inspection Scope
The inspectors observed and/or reviewed the following non-destructive examinations
mandated by the American Society of Mechanical Engineers (ASME)Section XI Code to
evaluate compliance with the ASME Code Section XI and Section V requirements and if
any indications and defects were detected, to determine if these were dispositioned in
accordance with the ASME Code or an NRC-approved alternative requirement.
- ultrasonic examination (UT) of the reactor water cleanup (RWCU) pipe-pipe weld,
25, Report No. 2011UT033;
- UT of the reactor head meriodonal weld 49/50, Report No. 2011UT035;
Field Welds 1 and 2;
- in-vessel visual inspection of jet pump riser support pad welds 7/8; and
- magnetic particle (MT) examination of the residual heat removal service water
(RHRSW) piping, weld 10, Report No. BOP- MT-11-057.
The inspectors reviewed the following examination completed during the previous
outage with relevant/recordable conditions/indications accepted for continued service to
determine if acceptance was in accordance with the ASME Code Section IX.
- UT of nozzle to vessel weld; weld N-3C; Report No. 2009UT024.
The inspectors reviewed the following pressure boundary weld completed for a
risk-significant system since the beginning of the last refueling outage (RFO) to
determine if the licensee applied the pre-service non-destructive examinations and
acceptance criteria required by the ASME Code Section XI. Additionally, the inspectors
reviewed the welding procedure specification and supporting weld procedure
qualification records to determine if the weld procedure was qualified in accordance with
the requirements of Construction Code and the ASME Code Section IX.
- RCIC steam supply line PS-17-3 removal and reinstallation; WO 00380817.
b. Findings
No findings were identified.
9 Enclosure
.2 Identification and Resolution of Problems
a. Inspection Scope
The inspectors performed a review of ISI-related problems entered into the licensees
CAP and conducted interviews with licensee staff to determine if:
- the licensee had established an appropriate threshold for identifying ISI-related
problems;
- the licensee had performed a root cause (if applicable) and taken appropriate
corrective actions; and
- the licensee had evaluated operating experience (OE) and industry generic
issues related to ISI and pressure boundary integrity.
The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, requirements. 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 (71111.11Q)
a. Inspection Scope
On January 21, 2011, the inspectors observed a crew of licensed operators in the plants
simulator during licensed operator requalification examinations to verify that operator
performance was adequate, evaluators were identifying and documenting crew
performance problems and training was being conducted in accordance with licensee
procedures. The inspectors evaluated the following areas:
- licensed operator performance;
- crews clarity and formality of communications;
- ability to take timely actions in the conservative direction;
- prioritization, interpretation, and verification of annunciator alarms;
- correct use and implementation of abnormal and emergency procedures;
- control board manipulations;
- 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
sample as defined in IP 71111.11.
10 Enclosure
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness (71111.12)
.1 Routine Quarterly Evaluations (71111.12Q)
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following
risk-significant systems:
- 12 EDG fuel oil level switch replacement;
- CS system; and
- non-essential diesel generator (DG-13).
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 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 three quarterly maintenance effectiveness samples as
defined in IP 71111.12-05.
b. Findings
No findings were identified.
11 Enclosure
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:
- repair of leak on RWCU piping near regenerative heat exchangers;
- evaluation of potential water intrusion into pre-amp enclosures for the
Division I source range monitors (SRMs) and intermediate-range monitors
(IRMs);
- plant in yellow risk and shutdown limiting condition for operation (LCO) longer
than scheduled while replacing 12 EDG level switches;
- RFO risk assessment and risk management following shutdown;
- risk management of suspended fuel assembly during refuel bridge issues; and
- 1N6 lockout during 1AR power transfer from 10 bank transformer.
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 are listed in the Attachment to this report.
These maintenance risk assessments and emergent work control activities constituted
six samples as defined in IP 71111.13-05.
b. Findings
No findings were identified.
1R15 Operability Evaluations (71111.15)
.1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues:
- battery room ventilation issues involving V-EF-40B;
- operations with the potential to drain the vessel classifications.
12 Enclosure
The inspectors selected these potential operability issues based on the risk significance
of the associated components and systems. The inspectors evaluated the technical
adequacy of the evaluations to ensure that TS operability was properly justified and the
subject component or system remained available such that no unrecognized increase in
risk occurred. The inspectors compared the operability and design criteria in the
appropriate sections of the TS and USAR to the licensees evaluations to determine
whether the components or systems were operable. Where compensatory measures
were required to maintain operability, the inspectors determined whether the measures
in place would function as intended and were properly controlled. The inspectors
determined, where appropriate, compliance with bounding limitations associated with
the evaluations. Additionally, the inspectors reviewed a sampling of corrective action
documents to verify that the licensee was identifying and correcting any deficiencies
associated with operability evaluations. Documents reviewed are listed in the
Attachment to this report.
These operability inspections constituted three samples as defined in IP 71111.15-05.
b. Findings
No findings were identified.
1R18 Plant Modifications (71111.18)
.1 Permanent Plant Modifications
a. Inspection Scope
The following engineering design package was reviewed and selected aspects were
discussed with engineering personnel:
- Engineering Change (EC) 14638 (change main steam isolation valve (MSIV) disc
and seat rings hard face material from Stellite 6 to Stellite 21).
This document and related documentation were reviewed for adequacy of the
associated 10 CFR 50.59 safety evaluation screening; consideration of design
parameters; implementation of the modification; post-modification testing; and relevant
procedures, design, and licensing documents were properly updated. The inspectors
observed ongoing and completed work activities to verify that installation was consistent
with the design control documents. During the current RFO, EC 14638 was used to
modify the disc and seating surface for three of the four outboard MSIVs.
The modification will change the MSIV disc and seat hard-faced material from Stellite 6
to Stellite 21.
This inspection constituted one permanent plant modification sample as defined in
IP 71111.18-05.
b. Findings
No findings were identified.
13 Enclosure
1R19 Post-Maintenance Testing (71111.19)
.1 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the following post-maintenance (PM) activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
- ventilation unit V-AH-4A secondary containment (SCT) isolation dampers;
- reactor building railroad doors 45 and 46;
- 14 RHR pump; and
- 1B low vacuum scram pressure switch (PS-5-11C).
These activities were selected based upon the SSCs 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 TS, 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 PM 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 four PM 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
Refueling Outage (RFO), which began on March 5, 2011, and continued through the end
of the inspection period, 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
14 Enclosure
controls over the outage activities listed below. Documents reviewed during the
inspection are listed in the Attachment to this report.
- 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;
- 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 SCT as required by TS;
- 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;
- Licensee identification and resolution of problems related to RFO activities.
This inspection constituted one RFO sample as defined in IP 71111.20-05.
b. Findings
Introduction
A finding of very low safety significance and non-cited violation (NCV) of 10 CFR 50,
Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed
when the licensee failed to adequately implement the requirements of their fleet tagging
procedure, a procedure affecting quality, during maintenance on the safety-related
CST-88 B low pressure coolant injection (LPCI) fill line check valve. This failure
resulted in an unintentional breach of the condensate service water (CSW) system and
subjected workers to a potentially contaminated, pressurized water source. Additionally,
at the time of the breach, the CSW system was one of the water sources being credited
in support of the shutdown safety function of inventory control.
Description
On March 18, 2011, workers commenced the disassembly and inspection of CST-88,
the B LPCI Fill Line check valve. The workers had been briefed to expect that upon
disassembly of the valve they would experience a small amount of water drainage and
hence had installed a large-sized drainage device to accommodate the leakage.
15 Enclosure
However, when they began to disassemble the valve, upon loosening the bonnet bolts,
the workers were met with pressurized water. The workers determined that this amount
of water leakage was unexpectedly large and quickly retightened the bolts to restore the
valve back to its assembled condition, terminating the leakage.
The licensees investigation into this incident revealed that the check valve the workers
were disassembling had not been properly isolated. The clearance order referenced for
this maintenance activity had only isolated the valve (CST-91) immediately downstream
of the CST-88 check valve (among other valves associated with separate work
activities). The valve (CST-184) located immediately upstream of CST-88 was not
closed, leaving the check valve un-isolated from the pressurized CSW system.
This inadequate isolation left workers unprotected from the pressurized CSW header,
and led to a temporary breach of the CSW system, a system which was being credited
in support of the shutdown safety function of inventory control.
A review of the WO and clearance development activities for this task revealed that on
January 10, 2010, Clearance Order (CO) 37264 was created to support draining and
isolating portions of the RHR B system. While the CO was still in the planning stages,
other WOs were added to it including the WO for the CST-88 check valve maintenance
(WO 394266). In total, 20 additional WOs were added to CO 37264 prior to its approval
and two additional activities were added following its approval. While CO 37264 was
originally generated to support work on the RHR B system, the licensees tagging
procedure allows them to place multiple WOs under one clearance. However, the
procedure also requires that the CO be appropriately developed and reviewed to ensure
that safe boundaries are established for all maintenance activities associated with the
clearance.
During the planning and approval processes for CO 37264 when WO 394266 was added
to its scope, the following errors occurred:
- during the planning stages, the CO preparer failed to use available references or
perform a walkdown to develop a CO that included appropriate boundaries for all
work associated with the CO 37264;
- when the CO containing this work was routed for approval, the craft approver
(Supervisor/Lead Clearance Order Holder in the approval chain) failed to verify
that a safe boundary was prepared for all the work contained in CO 37264 by
using available references or walkdowns; and
- during the approval process, the approving Senior Reactor Operator (SRO)
(Operations Approver) failed to adequately verify that a safe work boundary was
established for work associated with CO 37264.
After CO 37264 was approved, the following additional errors occurred during execution
of the clearance and WO 394266:
- prior to allowing maintenance to commence work on the procedure,
the Operations Shift Supervision authorized the maintenance group to begin
work on WO 394266, but failed to appropriately authorize the commencement of
work on the procedure being performed under the WO, and failed to complete
the prerequisites specified in the procedure;
16 Enclosure
- prior to initiating the work activity, the work supervisor (Supervisor/Lead
Clearance Order Holder for the work group) failed to ensure that the tagging
boundary was appropriate for the work being performed; assessment of the
boundary included a craft walkdown, which compared the CO only to the tags
hung on the isolated valves, rather than comparing the CO to plant diagrams or
using insights from the physical valve location in the system to verify appropriate
boundaries; and
- prior to commencing the work, the supervisor failed to adequately brief the
workers on the tagging boundaries for the work.
Fleet Tagging Procedure, FP-OP-TAG-01, Revision 10, Sections 5.3 and 5.4,
specify the requirements for development and approval of CO checklists for WOs.
These sections state, in part:
- the Clearance Order/Clearance Order Checklist Preparer SHALL prepare a
Clearance Order and Clearance Order Checklist using available references
and/or walkdowns. Controlled documents SHALL be used, when available
(Sec. 5.3);
- the Clearance Order/Clearance Order Checklist Preparer SHALL complete the
information field for clearance order steps - to establish a safe work boundary,
as required (Sec. 5.3);
- the Operations Approver SHALL verify a safe boundary has been established
(Sec. 5.4); and
- the Supervisor/Lead Clearance Order Holder review SHALL verify that a safe
work boundary has been prepared, using available references and/or walkdowns
(Sec. 5.4).
Section 5.6 of Procedure FP-OP-TAG-01 specifies requirements of supervisors when
commencing a work activity:
- the Supervisor/Lead Clearance Order Holder review SHALL ensure the tagging
boundary is adequate for the work to be performed; and
- the Supervisor/Lead Clearance Order Holder review SHALL brief clearance order
holders (worker) on tagging boundaries, potential hazards/stored energy
sources, and field activities.
Additionally, when the time came to perform the work, the Operations Shift Supervision
signed the work order task Authorization to start work. However, the individual did not
sign the Approval to Commence for the procedure being implemented in the WO.
This procedure, 0255-22-IA-1, CST-88 B LPCI Fill Line Check Valve Test, contained
two prerequisites to be performed prior to beginning work on the procedure steps.
One of those prerequisites required verification that CST-88 is isolated as required.
Neither prerequisite was completed before the procedure steps were begun.
The CO development, approval, and execution activities associated with WO 394266
failed to identify the need to close the inlet isolation valve for the check valve that was
being disassembled and inspected, in order to isolate the check valve from the
CSW header. Therefore, these activities failed to ensure that the tagging boundary was
adequate for the work being performed, as required by the procedure.
17 Enclosure
The licensee entered this issue into their corrective action program (CAPs 1275935 and
1275963). Immediate corrective actions taken by the licensee included restoring the
CST-88 check valve to its installed configuration to terminate the water leakage and
revising the clearance boundary for the work to include the appropriate isolation valve.
The site performed a review of all other WOs associated with CO 37264 to validate that
safe work boundaries existed for all associated work activities and reviewed the other
COs prepared and approved by personnel associated with the event. Additionally, to
highlight the significance of the event, the licensee reset their site event clock,
communicated lessons learned from the event to the site, and assembled a team to
perform a root cause evaluation (RCE).
Analysis
The inspectors determined that the licensees failure to adequately implement their
tagging process to protect workers and equipment from the effects of breaching the
pressurized CSW header during maintenance on a safety-related check valve was a
performance deficiency because it was the result of the failure to meet a requirement,
the cause was reasonably within the licensees ability to foresee and correct, and should
have been prevented. The inspectors determined that the contributing cause that
provided the most insight into the performance deficiency was associated with the
cross-cutting area of Human Performance, having work control components, and
involving aspects associated with appropriately planning work activities by incorporating
job site conditions impacting plant systems and components H.3(a).
The inspectors screened the performance deficiency per IMC 0612, Power Reactor
Inspection Reports, Appendix B, and determined that the issue was more than minor
because the performance deficiency could have reasonably been viewed as a precursor
to a more significant event. In this instance, the performance deficiency resulted in an
unintentional breach of the operating CSW system and subjected workers to a
potentially contaminated, pressurized water source. Additionally, at the time of the
breach, the CSW system was one of the water sources being credited in support of the
shutdown safety function of inventory control. The inspectors applied IMC 0609,
Significance Determination Process, Appendix G, "Shutdown Operations Significance
Determination," Attachment 1, to this finding. The finding was determined to have very
low safety significance because it did not adversely affect core heat removal, inventory
control, power availability, containment control, or reactivity guidelines (Green).
Enforcement
Title 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings,"
requires, in part, that activities affecting quality shall be prescribed by documented
procedures, of a type appropriate to the circumstances, and shall be accomplished in
accordance with these procedures. Contrary to this requirement, the licensee failed to
adequately implement the requirements of Procedure FP-OP-TAG-01, Fleet Tagging,
a procedure affecting quality, during maintenance on the safety-related CST-88 B LPCI
Fill Line check valve. This failure resulted in a breach of the CSW system, led to
workers being unprotected from a potentially contaminated, pressurized water source,
and introduced the potential to impact a system being credited in support of a shutdown
safety function. Because the violation was of very low safety significance and was
entered into the licensees corrective action program (CAPs 1275935 and 1275963),
this violation is being treated as an NCV, consistent with Section 2.3.2 of the
18 Enclosure
NRC Enforcement Policy. (NCV 05000263/2011002-01; Inadequate System Isolation
during Check Valve Maintenance)
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:
- surveillance procedure 0192, diesel fuel quality check (routine);
- surveillance procedure 0007-A, condenser low vacuum scram instruments test
and calibration (routine);
- surveillance procedure 0021-01, reactor low level scram and low-low level
isolation transmitter calibration procedure (routine);
recirc pump trip with reactor feed pump and turbine trip testing (routine);
- procedure 0255-03-IA-2A, CS - shutdown valve operability test (inservice test
(IST)); and
- local leak rate test (LLRT) procedure137-07A, reactor steam supply valves leak
rate testing (containment isolation valve (CIV) LLRT).
The inspectors observed in-plant activities and reviewed procedures and associated
records to determine the following:
- did preconditioning occur;
- were the effects of the testing adequately addressed by control room personnel
or engineers prior to the commencement of the testing;
- were acceptance criteria clearly stated, demonstrated operational readiness, and
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 IST activities, testing was performed in accordance with the
applicable version of Section XI, ASME code, and reference values were
consistent with the system design basis;
19 Enclosure
- where applicable, test results not meeting acceptance 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
- 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 four routine surveillance testing samples, one IST sample,
and one CIV sample as defined in IP 71111.22, Sections -02 and -05.
b. Findings
No findings were identified.
1EP6 Drill Evaluation (71114.06)
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine licensee emergency drill on
February 9, 2011, to identify any weaknesses and deficiencies in classification,
notification, and protective action recommendation development activities.
The inspectors observed emergency response operations in the control room simulator
and emergency offsite facility to determine whether the event classification, notifications,
and protective action recommendations were performed in accordance with procedures.
The inspectors also attended the licensee drill critique to compare any inspector
observed weakness with those identified by the licensee staff in order to evaluate the
critique and to verify whether the licensee staff was properly identifying weaknesses
and entering them into the corrective action program. As part of the inspection, the
inspectors reviewed the drill package and other documents listed in the Attachment to
this report.
This emergency preparedness drill inspection constituted one sample as defined in
IP 71114.06-05.
b. Findings
No findings were identified.
20 Enclosure
2. RADIATION SAFETY
2RS5 Radiation Monitoring Instrumentation (71124.05)
This inspection constituted one complete sample as defined in IP 71124.05-05.
.1 Inspection Planning (02.01)
a. Inspection Scope
The inspectors reviewed the plant Final Safety Analysis Report (FSAR) to identify
radiation instruments associated with monitoring area radiological conditions including
airborne radioactivity, process streams, effluents, materials/articles, and workers.
Additionally, the inspectors reviewed the instrumentation and the associated
TS requirements for post-accident monitoring instrumentation including instruments used
for remote emergency assessment.
The inspectors reviewed a listing of in-service survey instrumentation including air
samplers and small article monitors, along with instruments used to detect and analyze
workers external contamination. Additionally, the inspectors reviewed personnel
contamination monitors and portal monitors including whole-body counters to detect
workers internal contamination. The inspectors reviewed this list to assess whether an
adequate number and type of instruments are available to support operations.
The inspectors reviewed licensee and third-party evaluation reports of the radiation
monitoring program since the last inspection. These reports were reviewed for insights
into the licensees program and to aid in selecting areas for review (smart sampling).
The inspectors reviewed procedures that govern instrument source checks and
calibrations, focusing on instruments used for monitoring transient high radiological
conditions, including instruments used for underwater surveys. The inspectors reviewed
the calibration and source check procedures for adequacy and as an aid to smart
sampling.
The inspectors reviewed the area radiation monitor alarm setpoint values and setpoint
bases as provided in the TSs and the FSAR.
The inspectors reviewed effluent monitor alarm setpoint bases and the calculational
methods provided in the offsite dose calculation manual (ODCM).
b. Findings
No findings were identified.
.2 Walkdowns and Observations (02.02)
a. Inspection Scope
The inspectors walked down effluent radiation monitoring systems, including at least one
liquid and one airborne system. Focus was placed on flow measurement devices and all
accessible point-of-discharge liquid and gaseous effluent monitors of the selected
systems. The inspectors assessed whether the effluent/process monitor configurations
21 Enclosure
align with ODCM descriptions and observed monitors for degradation and out-of-service
tags.
The inspectors selected portable survey instruments in use or available for issuance and
assessed calibration and source check stickers for currency as well as instrument
material condition and operability.
The inspectors observed licensee staff performance as the staff demonstrated source
checks for various types of portable survey instruments. The inspectors assessed
whether high-range instruments are source checked on all appropriate scales.
The inspectors walked down area radiation monitors and continuous air monitors to
determine whether they are appropriately positioned relative to the radiation sources or
areas they were intended to monitor. Selectively, the inspectors compared monitor
response (via local or remote control room indications) with actual area conditions for
consistency.
The inspectors selected personnel contamination monitors, portal monitors, and small
article monitors, and evaluated whether the periodic source checks were performed in
accordance with the manufacturers recommendations and licensee procedures.
b. Findings
No findings were identified.
.3 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 TSs/ODCM. The inspectors assessed whether:
(a) the licensee calibrated its monitors with National Institute of Standards and
Technology 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 set-points.
The inspectors assessed whether the effluent monitor alarm setpoints are 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 exists.
b. Findings
No findings were identified.
22 Enclosure
Laboratory Instrumentation
a. Inspection Scope
The inspectors assessed laboratory analytical instruments used for radiological analyses
to determine whether daily performance checks and calibration data indicate that the
frequency of the calibrations is adequate and there were no indications of degraded
instrument performance.
The inspectors assessed whether appropriate corrective actions were implemented in
response to indications of degraded instrument performance.
b. Findings
No findings were identified.
Whole Body Counter
a. Inspection Scope
The inspectors reviewed the methods and sources used to perform whole body count
functional checks before daily use of the instrument and assessed whether check
sources were appropriate and align with the plants isotopic mix.
The inspectors reviewed whole body count calibration records since the last inspection
and evaluated whether calibration sources were representative of the plants source
term and that appropriate calibration phantoms were used. The inspectors looked for
anomalous results or other indications of instrument performance problems.
b. Findings
No findings were identified.
Post-Accident Monitoring Instrumentation
a. Inspection Scope
Inspectors selected drywell high-range monitors and reviewed the calibration
documentation since the last inspection.
The inspectors assessed whether an electronic calibration was completed for all range
decades above 10 rem/hour, and whether at least one decade at or below 10 rem/hour
was calibrated using an appropriate radiation source.
The inspectors assessed whether calibration acceptance criteria are reasonable,
accounting for the large measuring range and the intended purpose of the instruments.
The inspectors selected two effluent/process monitors that are relied on by the licensee
in its emergency operating procedures as a basis for triggering emergency action levels
and subsequent emergency classifications, or to make protective action
recommendations during an accident. The inspectors evaluated the calibration and
availability of these instruments.
23 Enclosure
The inspectors reviewed the licensees capability to collect high-range, post-accident
iodine effluent samples.
As available, the inspectors observed electronic and radiation calibration of these
instruments to verify conformity with the licensees calibration and test protocols.
b. Findings
No findings were identified.
Portal Monitors, Personnel Contamination Monitors, and Small Article Monitors
a. Inspection Scope
For each type of these instruments used on site, the inspectors assessed whether the
alarm setpoint values are reasonable under the circumstances to ensure that licensed
material is not released from the site.
The inspectors reviewed the calibration documentation for each instrument selected and
discussed the calibration methods with the licensee to determine consistency with the
manufacturers recommendations.
b. Findings
No findings were identified.
Portable Survey Instruments, Area Radiation Monitors, Electronic Dosimetry, and
Air Samplers/Continuous Air Monitors
a. Inspection Scope
The inspectors reviewed calibration documentation for at least one of each type of
instrument. For portable survey instruments and area radiation monitors, the inspectors
reviewed detector measurement geometry and calibration methods and had the licensee
demonstrate use of its instrument calibrator as applicable. The inspectors conducted
comparison of instrument readings versus an NRC survey instrument if problems were
suspected.
As available, the inspectors selected portable survey instruments that did not meet
acceptance criteria during calibration or source checks to assess whether the licensee
had taken appropriate corrective action for instruments found significantly out of
calibration (greater than 50 percent). The inspectors evaluated whether the licensee
had evaluated the possible consequences of instrument use since the last successful
calibration or source check.
b. Findings
No findings were identified.
24 Enclosure
Instrument Calibrator
a. Inspection Scope
As applicable, the inspectors reviewed the current output values for the licensees
portable survey and area radiation monitor instrument calibrator unit(s). The inspectors
assessed whether the licensee periodically measures calibrator output over the range of
the instruments used through measurements by ion chamber/electrometer.
The inspectors assessed whether the measuring devices had been calibrated by a
facility using National Institute of Standards and Technology traceable sources and
whether corrective factors for these measuring devices were properly applied by the
licensee in its output verification.
b. Findings
No findings were identified.
Calibration and Check Sources
a. Inspection Scope
The inspectors reviewed the licensees 10 CFR Part 61, Licensing Requirements for
Land Disposal of Radioactive Waste, source term to assess whether calibration sources
used were representative of the types and energies of radiation encountered in the plant.
b. Findings
No findings were identified.
.4 Problem Identification and Resolution (02.04)
a. Inspection Scope
The inspectors evaluated whether problems associated with radiation monitoring
instrumentation were being identified by the licensee at an appropriate threshold and
were properly addressed for resolution in the licensee CAP. The inspectors assessed
the appropriateness of the corrective actions for a selected sample of problems
documented by the licensee that involve radiation monitoring instrumentation.
b. Findings
No findings were identified.
25 Enclosure
4. OTHER ACTIVITIES
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
Emergency Preparedness, Public and Occupational Radiation Safety
4OA1 Performance Indicator Verification (71151)
.1 Unplanned Scrams per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical
Hours Performance Indicator (PI) for the period from the 1st Quarter 2010 to the
4th Quarter 2010. To determine the accuracy of the PI data reported during this period,
PI definitions and guidance contained in the NEI Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were
used. The inspectors reviewed the licensees operator narrative logs, issue reports,
event reports, and NRC Integrated Inspection Reports for that period to validate the
accuracy of the submittals. 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.
This inspection constituted one unplanned scrams per 7000 critical hours sample as
defined in IP 71151-05.
b. Findings
No findings were identified.
.2 Unplanned Scrams with Complications
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Scrams with
Complications PI for the period from the 1st Quarter 2010 to 4th Quarter 2010.
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 6, dated October 2009, were used.
The inspectors reviewed applicable licensee operator narrative logs, issue reports, event
reports, and NRC Integrated Inspection Reports for that period to validate the accuracy
of the submittals. 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.
This inspection constituted one unplanned scrams with complications sample as defined
in IP 71151-05.
b. Findings
No findings were identified.
26 Enclosure
.3 Unplanned Transients per 7000 Critical Hours
a. Inspection Scope
The inspectors sampled licensee submittals for the Unplanned Transients per 7000
Critical Hours PI for the period from the 1st Quarter of 2010 to the 4th Quarter of 2010.
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 6, dated October 2009, were used.
The inspectors reviewed the licensees operator narrative logs, issue reports,
maintenance rule records, event reports, and NRC Integrated Inspection Reports for that
period to validate the accuracy of the submittals. 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.
This inspection constituted one unplanned transients per 7000 critical hours sample as
defined in IP 71151-05.
b. Findings
No findings were identified.
.4 Occupational Exposure Control Effectiveness
a. Inspection Scope
The inspectors sampled licensee submittals for the Occupational Radiological
Occurrences PI for the period from the 2nd Quarter 2010 through January 2011.
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 6, was used. 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 dosimetry dose rate and
accumulated dose alarm and dose reports and the dose assignments for any intakes
that occurred during the time period reviewed to determine if there were potentially
unrecognized occurrences. The inspectors also conducted walkdowns of numerous
locked high and very high radiation area entrances to determine the adequacy of the
controls in place for these areas.
This inspection constituted one occupational radiological occurrences sample as defined
in IP 71151-05.
b. Findings
No findings were identified.
27 Enclosure
.5 Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual
Radiological Effluent Occurrences
a. Inspection Scope
The inspectors sampled licensee submittals for the Radiological Effluent TS (RETS)/
ODCM Radiological Effluent Occurrences PI for the period of June 2010 through
January 2011. The inspectors used PI definitions and guidance contained in the
NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 6, to determine the accuracy of the PI data reported during those periods.
The inspectors reviewed the licensees issue report database and selected individual
reports generated since this indicator was last reviewed to identify any potential
occurrences such as unmonitored, uncontrolled, or improperly calculated effluent
releases that may have impacted offsite dose. The inspectors reviewed gaseous
effluent summary data and the results of associated offsite dose calculations for selected
dates to determine if indicator results were accurately reported. The inspectors also
reviewed the licensees methods for quantifying gaseous and liquid effluents and
determining effluent dose. 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)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and
.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 that 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.
28 Enclosure
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.
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 Selected Issue Follow-Up Inspection: Several CAPs Regarding Fatigue Rule Work Hour
Violations
a. Inspection Scope
During a review of items entered in the licensees CAP, the inspectors recognized a
corrective action item documenting multiple violations of NRC requirements associated
with the fatigue rule. In addition, the inspectors noted that there were multiple
CAPs documenting human performance errors that may result in violations of
NRC fatigue rule requirements, and a few other CAPs documenting other instances of
individual work hour violations. The inspectors reviewed the licensees actions to
address the violations and examined the sites threshold for determining whether an
adverse trend exists in this area. In addition, the inspectors reviewed all fatigue rule
related CAPs generated over the previous year and the causal analyses that were
performed when trends were identified. This review focused on determining whether the
licensee was adequately evaluating these issues, whether the corrective actions
developed by the licensee were appropriate given the results of causal evaluations, and
whether the actions the site has taken to address these issues had been effective.
This review constituted one in-depth problem identification and resolution sample as
defined in IP 71152-05.
b. Findings
During this inspection, the inspectors identified a concern regarding the licensees
implementation of fatigue rule requirements. Specifically, the inspectors reviewed an
29 Enclosure
apparent cause evaluation (ACE) that the licensee had performed after identifying
several violations of NRC fatigue rule requirements. The inspectors noted that one of
the corrective actions developed and implemented in October 2010, as a result of this
evaluation, involved tripling the period of planned shift turnover time on the front end of
schedules of individuals in one department, to account for the turnover period on the
back end of the shift. As a result of this action, the scheduled turnover period for
personnel in this department was not consistent with NRC guidance on reasonable
amounts of time for these activities. In addition, the inspectors noted that this turnover
time period was applied to the front end of the schedules of all personnel in this
department regardless of the amount of time spent performing actual turnover activities.
This may potentially be in conflict with NRC regulations, specifically with respect to
10 CFR 26.205(b)(1), regarding calculation of work hours, 10 CFR 26.205(d) regarding
work hour controls, and 10 CFR 26.203(b)(2) regarding implementation of fatigue rule
procedures to ensure compliance with 10 CFR 26.205.
The NRC inspectors plan to review actual turnover activities and associated records for
the site as a whole to examine how the corrective action of concern has been put into
practice. Pending NRC review of additional licensee information regarding site-wide
practices for exclusion of shift turnover activities, as well as information on how the
application of a fixed and potentially artificially long turnover period has affected actual
work hours reported for individuals at the site, this issue will be treated as an
Unresolved Item (URI) (URI)5000263/2011002-02; Calculation of Work Hours during
Fatigue Rule Implementation).
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153)
.1 Observations During Plant Downpower to Approximately 50 Percent Power
a. Inspection Scope
On March 4, 2011, the inspectors observed control room operators during power
reductions from approximately full power to 50 percent power. The inspectors focus
was on overall command and control, procedure usage, and conservative practices
while maneuvering the plant.
b. Findings
No findings were identified.
This event follow-up review of a non-routine evolution constituted one sample as defined
in IP 71153-05.
.2 Observation of New Fuel Receipt Inspections Conducted on the Refueling Floor
a. Inspection Scope
The inspectors performed several observations of licensee activities associated with
receipt of new fuel. These activities included unpackaging, inspecting, channeling, and
placement of new fuel in the spent fuel pool. Documents reviewed in this inspection are
listed in the Attachment to this report.
This event follow-up review constituted one sample as defined in IP 71153-05.
30 Enclosure
b. Findings
Introduction
A finding of very low safety significance and NCV of Technical Specification 5.4,
Procedures, was identified by the inspectors when the licensee failed to implement the
requirements of their foreign material exclusion (FME) and control procedure during new
fuel receipt activities. Specifically, the inspectors observed two operators exiting and
re-entering a Level 1 FME area, without knowledge of the FME monitor, at a point that
was not being controlled by the FME monitor.
Description
Over a time period of approximately one week, the inspectors observed the licensee
perform several activities associated with the receipt of new fuel. These activities
included unpackaging new fuel, inspection of the fuel assemblies, installation of fuel
assembly channels, and placing the new fuel in the spent fuel pool. A majority of
these activities were performed within the boundaries of a Level 1 FME area.
On January 24, 2011, during one of these observations, the inspectors noted that two
operators, who were participating in the fuel receipt inspection activities, entered the
FME area, without the FME monitors knowledge, at a point that was not established as
the FME area access point.
The licensee utilizes Procedure FP-MA-FME-01, Foreign Material Exclusion and
Control, to implement its processes for controlling and accounting for material, tools,
and parts to preclude their uncontrolled introduction into an open system or component
during maintenance, modification, or inspection activities. The inspectors reviewed this
procedure and discovered the following requirements which were applicable to the new
fuel receipt inspection activities.
- Workers were responsible for adhering to and maintaining FME requirements
(Step 3.2.2);
- FME monitors were responsible for monitoring work activities for proper
FME work practices and inspecting personnel, tools, and materials entering and
leaving the FME area (Steps 3.4.7 and 3.4.8);
attentive or present (Step 4.11, in part);
and is required where new fuel is inspected (Step 5.1.1, in part); and
and prepared utilizing form QF 1812, Foreign Material Exclusion Control Plan,
(Step 5.2.1).
The inspectors reviewed the QF 1812 associated with new fuel receipt activity.
The inspectors noted that the following requirements were included as part of that plan.
appropriately prepared to enter the area by securing all personal items and by
logging all items carried into the area. The FME monitor is one of the last
barriers to the prevention of foreign material entering the FME Level 1 Zone and
as such, the FME monitor must be vigilant with respect to their assigned duties.
31 Enclosure
The inspectors reviewed the training material (MT-SHE-GEN-001L) used in the
qualification of the FME monitors. This material specifically covers the duties of an
FME monitor to include: controlling the FME area when material or personnel control is
established; stopping any entry that is not within the guidelines of the procedure;
monitoring work activities for proper FME work practices; and inspecting personnel
entering and leaving an FME area.
- All personnel that are required to enter the FME Level 1 Zone shall have read
and/or been briefed on the FME plan;
The inspectors reviewed the training material (M-7730F-012) used in FME training.
With respect to FME boundaries, the training material specifically states If you see a
FME boundary, dont cross it without approval by the supervisor /FME Monitor.
Subsequent to observing the operators enter the FME area at an unmonitored point;
the inspectors brought this to the attention of the FME monitor. When questioned by
the inspectors, the FME monitor informed the inspectors that he was not aware that the
operators had entered the FME area. The inspectors also brought this issue to the
attention of the SRO that was overseeing the new fuel receipt activities.
Corrective actions taken to address this issue included stopping the work, re-briefing the
workers on FME controls, and verifying no additional material was introduced to the
FME area by the operators. The licensee entered this issue into their corrective action
program as CAP 0126760.
Analysis
The inspectors determined that the licensees failure to adequately implement the
requirements of their FME and control procedure during new fuel receipt activities to
prevent the unmonitored access of two operators into a Level 1 FME area was a
performance deficiency because it was the result of the failure to meet a requirement or
a standard, the cause was reasonably within the licensees ability to foresee and correct,
and should have been prevented. The inspectors determined that the contributing cause
that provided the most insight into the performance deficiency was associated with the
cross-cutting area of Human Performance, having Work Practices components, and
involving aspects associated with the licensee defining and effectively communicating
expectations regarding procedural compliance and personnel following procedures
The inspectors screened the performance deficiency per IMC 0612, Power Reactor
Inspection Reports, Appendix B, and determined that the issue was more than minor
because it impacted the human performance attribute of the Barrier Integrity
Cornerstones objective to provide reasonable assurance that physical design barriers
(fuel cladding, reactor coolant system, and containment) protect the public from
radionuclide releases caused by accidents or events. The inspectors applied IMC 0609,
Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, to this
finding. The inspectors utilized Column 3 of the Table 4a worksheet to screen the
finding. Since the finding only had the potential to impact the fuel barrier, the finding was
screened to be of very low safety significance (Green).
32 Enclosure
Enforcement
Monticello Nuclear Generating Plant TS, Section 5.4.1.a, requires that written
procedures shall be established, implemented, and maintained covering applicable
procedures recommended in RG 1.33, Revision 2, Appendix A, February 1978.
Contrary to this requirement on January 24, 2011, the licensee failed to successfully
implement Procedure FP-MA-FME-01, Foreign Material Exclusion and Control,
a maintenance procedure, during new fuel receipt and channeling activities. Specifically,
two operators exited and reentered a Level 1 FME area, without the knowledge of the
FME monitor, at a point not controlled by the FME monitor. Because the violation was
of very low safety significance and was entered into the licensees corrective action
program (AR 126760), this violation is being treated as NCV, consistent with
Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000263/2011002-03; Failure to
Control a Level 1 FME Area during New Fuel Receipt Activities)
.3 (Closed) Licensee Event Report (LER) 05000263/2010-006-00: Mode Change Made
with Primary Containment Isolation Valves Inoperable
On November 22, 2010, the plant was in Mode 4 with preparations for startup in
progress. The duty crew transferred the reactor vent path to the path through
main steam line drain valves MO-2373 (main steam line drain - inboard), MO-2374
(main steam line drain - outboard), and MO-2565 (steam line drain orifice bypass).
The valves were opened and their associated breakers were tagged open. At 16:47,
the change from Mode 4 to Mode 2 was completed. At 17:00, a page announcement
was made that reactor startup was commencing. The on-coming operations work
control manager recalled helping tag open MO-2373 and MO-2374, which are primary
containment isolation valves (PCIVs), on the previous night shift. He called the control
room to verify the valves had been restored prior to the mode change. He immediately
notified the duty crew and operations management of the TS violation when he was
informed they had not been restored. Startup activities were halted pending
investigation and resolution of the issue. Primary containment isolation valves
operability was subsequently restored. Startup activities were recommenced later in the
shift after prerequisites had been verified as completed and a stand-down was
conducted.
The licensee entered this issue in to their corrective action program as CAP 1259879
and conducted a Root Cause Evaluation (RCE). The licensee determined that
individuals in key roles and oversight positions did not employ sufficient barriers to
ensure error free results, during preparation for and execution of, a complex evolution
(reactor startup) which relied heavily upon knowledge and experience. In addition to
this, the licensee identified two contributing causes. The licensee identified that some
procedure quality issues existed with procedures and checklists necessary for startup.
Secondly, they identified organizational weakness, in that the operability of TS required
equipment was not assessed, evaluated, or rigorously tracked when not in the mode of
applicability for the LCO.
This licensee-identified finding involved a violation of TS 3.0.4. The enforcement
aspects of this violation are discussed in Section 4OA7 of this report. Documents
reviewed as part of this inspection are listed in the Attachment to this report.
This LER is closed.
33 Enclosure
.4 (Closed) Licensee Event Report (LER) 05000263/2009-001-02:
Containment Overpressure Not Ensured in the Appendix R Analysis
The licensee issued Licensee Event Reports (LER 05000263-2009-001-00 and
LER 05000263-2009-001-01) regarding the licensees failure to consider the spurious
opening and venting of the primary containment, via purge and vent valves, in the event
of a fire in the main control room or cable spreading room. Both LER revisions were
closed in Inspection Report 05000263/2009004 and documented as a violation of
NRC requirements. Because the licensee was transitioning to NFPA 805 and the
violation met the criteria established by the NRC Interim Enforcement Policy Regarding
Enforcement Discretion for Certain Fire Protection Issues (10 CFR Part 50.48(c)) for
licensee in NFPA 805 transition, the NRC exercised enforcement discretion to not cite
the violation in accordance with the NRCs Enforcement Policy. On December 22, 2010,
the licensee provided an update to LER 05000263-2009-001-02 to reflect their
withdrawal of the letter of intent to voluntarily implement 10 CFR 50.48(c) at the MNGP.
On May 14, 2009, the NRC issued EGM 09-002, Enforcement Discretion for
Fire Induced Circuit Faults, dated May 14, 2009, which authorized enforcement
discretion for non-compliance issues associated with fire induced multiple circuit cable
faults, providing that the licensee identified the non-compliances, entered them into their
CAPs, and instituted appropriated compensatory measures until the issues were
corrected, within the six month period following a planned revision to RG 1.189,
Fire Protection for Nuclear Power Plants. Regulatory Guide 1.189, Revision 2,
issued in October 2009, provided a method acceptable to the NRC to evaluate and
resolve multiple fire induced circuit faults. After the six month period designated for the
identification of non-compliances, the EGM further authorized enforcement discretion for
an additional 30 month period, for licensees to resolve the identified multiple fire-induced
circuit fault issues.
The inspectors screened this violation and determined that because the violation was
associated with multiple fire induced circuit faults and was identified during the discretion
period as described in EGM 09-002, the NRC is exercising enforcement discretion for
this violation in accordance with EGM 09-002. This LER is closed.
.5 (Closed) Licensee Event Report (LER) 05000263/2011-002-00: ESF [Engineered
Safety Feature] Actuation Due to a Failed Power Supply
On December 20, 2010, the plant was in Mode 1 operating at 100 percent reactor power
when the 'A' Division of the fuel pool/reactor building exhaust plenum primary power
supply failed. The failure resulted in upscale trips on both the fuel pool and reactor
building ventilation plenum radiation monitors. This condition resulted in closure of the
Group II PCIVs, isolation of SCT, initiation of the standby gas treatment system (SBGT),
and a transfer of the control room ventilation (CRV) and control room emergency
filtration (CREF) systems to the high radiation mode. The licensee entered the
appropriate TSs and verified that radiation levels were normal in the affected areas.
The isolation signals were reset and the SCT and CRV/filtration systems were restored
to a normal lineup. All systems functioned properly and there were no human
performance errors associated with this event.
A subsequent investigation identified that the 24 V DC module of the power supply had
failed due to a failure of the C20 Tantalum capacitor on the output of the module.
The capacitor failure was attributed to a manufacturing defect occurring approximately
34 Enclosure
six days after installation. The power supply was subsequently replaced and the
affected components were returned to service.
A similar power supply was installed in the B Division fuel pool/reactor building exhaust
plenum radiation monitor; however, its capacitors were from a different lot. Additionally,
the B Division power supply had not shown any issues since it was installed on
December 2, 2010, or during extensive bench testing occurring prior to installation.
The licensee entered this issue into its corrective action program as CAP 01263610.
The inspectors evaluation did not identify any concerns with the licensees response to
this issue. Since the cause of the event was due to equipment failure and not a licensee
performance deficiency, there is no violation or finding associated with this event.
This LER is closed.
This event follow up constituted one sample as defined in IP 71153-05.
.6 (Closed) Licensee Event Report (LER) 05000263/2010-004-00:
Secondary Containment Briefly Inoperable Due to Simultaneous Opening of
Airlock Doors
On November 4, 2010, at approximately 11:25 with the plant operating in Mode 1 at
93 percent power, both doors for airlock 124 (main access to reactor building) were
inadvertently opened simultaneously, breaching the Secondary Containment (SCT)
boundary. Upon recognition that both airlock doors were open, plant personnel took
prompt actions to ensure that at least one of the airlock doors was closed and the
control room was informed that SCT had been breached for approximately 5 seconds.
The control room staff determined, for the time that both airlock doors were open,
that SCT was inoperable and that the event was reportable under 10 CFR 50.72
(b)(3)(v)(C and D) - events or conditions that could have prevented a safety function of
structures or systems that are needed to control the release of radioactive material or
mitigate the consequences of an accident.
Evaluation of the issue by the licensee determined that the cause of the airlock
124 breach was an intermittent failure of the magnetic bond sensor on the door due to a
lack of periodic maintenance. Corrective actions taken by the licensee to address the
cause of this event included generating WOs to replace the magnets and switches for
the airlock interlock and to develop a periodic interlock component maintenance items
list for inclusion in their preventive maintenance program.
The inspectors did not identify any significant issues during the review of this LER.
This LER is closed.
4OA5 Other Activities
.1 Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review
a. Inspection Scope
The inspectors reviewed the final report for the INPO plant assessment conducted
during the weeks of November 30, 2009 and December 7, 2009. The inspectors
reviewed the report to ensure that issues identified were consistent with the
35 Enclosure
NRC perspectives of licensee performance and to verify if any significant safety issues
were identified that required further NRC follow-up.
b. Findings
No findings were identified.
.2 (Closed) Unresolved Item (URI) 05000263/2010008-01: Potential Concern with the
One-time Inspection Program Related to Butt Welds
During the post-approval license renewal inspection, the inspectors identified an
URI due to concerns of the one-time inspection program. This URI, documented in
Inspection Report 05000263/2010008, was related to changes the licensee made to
their original license renewal application. Specifically, in the March 25, 2006, license
renewal annual update (ML060800360), the licensee provided details of changes made
to the original license renewal application. With respect to Class 1 small bore piping, the
licensee determined that all piping in this inspection group is of actual diameter two
inches and less and that only socket weld connections are used in such applications.
Therefore, the licensee committed to perform inspections of this piping for the One-Time
Inspection (OTI) Program that will consist of visual testing VT-2 examinations during
pressure testing for system leaks upon return to service from outages and destructive
examinations of any socket welds removed from service prior to the period of extended
operation.
However, in a letter (ML101370259), dated May 14, 2010, the licensee notified the
NRC of the existence of a limited number of small-bore stainless-steel butt weld
connections (less than four inches in diameter), which was contrary to what was
identified before. As a result, the licensee changed the OTI requirements and
committed to perform augmented ISI volumetric examinations of ASME Class I
stainless steel small bore piping butt welds with a two-inch nominal pipe size through
less than four-inch nominal pipe size in accordance with the ISI aging management
program. The inspectors questioned whether the identification of stainless-steel butt
welds constituted a newly identified component or whether the commitment change was
appropriate and opened an URI pending further discussions with the Nuclear Reactor
Regulation (NRR) program office.
During this inspection period, NRR reviewed the licensees Fourth Ten-Year
ISI Examination Plan, revised in a letter (ML101670584), dated June 10, 2010.
The 10-year ISI interval covers May 1, 2003, to May 31, 2012. The revised plan
includes a section for Class 1 small-bore piping and states that, As required by license
renewal to manage aging effects, examination of small-bore piping has been added as
an augmented program to the ISI Plan. It further states that, Augmented volumetric
examinations of welds are performed on Class 1 stainless steel small-bore piping butt
welds > NPS 2 to < NPS 4. The examinations are performed in support of license
renewal and SHALL be performed through the renewed license period of extended
operation. The base scope of approximately 10 percent of the population will be
examined during each ISI interval. The NRR staff and inspectors determined the
licensees inspection sampling of 10 percent of the weld population is consistent with the
current staff sampling guidance. In addition, the 10-year ISI plan provided a detailed
weld selection methodology to ensure inspection of the most susceptible and
risk-significant welds.
36 Enclosure
The inspectors, with the assistance from NRR, concluded that Monticellos proposed
supplement adequately addresses one-time inspection of small bore piping full
penetration welds.
No finding of significance was identified. This URI is closed.
.3 Flow-Accelerated-Corrosion Inspection In Support of Extended Power Uprate (71004)
a. Inspection Scope
The inspectors performed a review to determine whether licensee programs and
procedures relative to flow-accelerated-corrosion (FAC) monitoring and maintenance
were adequately addressing plant changes resulting from extended power uprate (EPU)
in accordance with 10 CFR 50.65, the Maintenance Rule and licensee commitments to
implement Generic Letter 89-08, Erosion/Corrosion Induced Pipe Wall Thinning.
The inspectors reviewed the FAC Program to determine whether Monticello has taken
required action to detect adverse effects (wall thinning) on systems and components as
a result of operating changes related to EPU, such as increased flow in primary or
secondary systems, including their interfacing systems.
The inspectors reviewed procedures and administrative controls to determine whether
those procedures and controls ensure the structural integrity of high energy
(single phase and two-phase) carbon steel systems. The inspectors reviewed the
Monticello FAC program to determine whether the degradation of piping and
components is described in the procedures and, the examination activities are managed,
maintained, and documented. In particular, the inspectors reviewed those steps taken to
identify specific locations that were most likely to be adversely affected by a change
(increase) in operating variables (temperature, flow, etc.) as a result of increased power
levels. Also, the inspectors reviewed the licensee FAC activity to determine status and
effective utilization of the industry sponsored predictive program (CHECWORKS) to
verify the selection of the most susceptible locations for inspection and additional
locations based on unique operating conditions and industry experience. Also, the
inspectors reviewed how inspection data is trended to determine FAC wear rates and
identify the future inspection locations.
The inspectors selected portions of the feedwater system, a risk significant system
affected by EPU, for review of the licensees FAC monitoring activities and effectiveness.
The inspectors verified that the as built configuration for portions of the selected system
(piping and components) matches the plant specific FAC program isometrics.
The inspectors verified that design changes are reviewed for impact on the FAC
program and incorporated into the FAC database. The inspectors also reviewed
selected locations in this system that had been identified as susceptible to a projected
increase in FAC wear rates using the higher EPU operational variables with the
CHECWORKS model. The inspectors determined that the increase in wear rates was
recognized and being incorporated into the licensees program database for future
inspection sample selection.
b. Findings
No findings were identified.
37 Enclosure
4OA6 Management Meetings
.1 Exit Meeting Summary
On April 5, 2011, the inspectors presented the inspection results to Mr. T. OConnor, and
other members of the licensee staff. The licensee acknowledged the issues presented.
The inspectors confirmed that none of the potential report input discussed was
considered proprietary.
.2 Interim Exit Meetings
Interim exits were conducted for:
- The results of the one-week Fire Protection Inspection related to single and
multiple spurious circuit analysis with Mr. T. OConnor, and other members of
the licensee staff, on February 10, 2011. These results were also discussed
with Mr. S. Speight from the licensee on March 17, 2011;
- The results of the Inservice Inspection with Plant Manager, J. Grubb,
on March 24, 2011; and
- Radiation Monitoring Instrumentation, Occupational and Public Radiation
Safety Performance Indicator Verifications with Mr. T. OConnor,
the Site-Vice President, on February 4, 2011.
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 significance (Green) or Severity Level IV was
identified by the licensee and is a violation of NRC requirements, which meets the
criteria of the NRC Enforcement Policy for being dispositioned as an NCV.
- Technical Specification LCO 3.0.4 states, in part, that when an LCO is not met,
entry into a MODE in the applicability shall only be made when the associated
ACTIONS to be entered permit continued operation in the MODE or other
specified condition in the applicability for an unlimited period of time.
Technical Specification LCO 3.6.1.3, Primary Containment Isolation Valves
(PCIVs), states, in part, that each PCIV, except reactor building-to-suppression
chamber vacuum breakers, shall be OPERABLE in MODES 1, 2, and 3, when
associated instrumentation is required to be OPERABLE per LCO 3.3.6.1,
Primary Containment Isolation Instrumentation. Technical Specification
LCO 3.3.6.1 states, in part, that the primary containment isolation instrumentation
for Function 1, Main Steam Line Isolation, shall be OPERABLE for the Reactor
Vessel Water Level - Low Low, Main Steam Line Flow - High, and Main Steam
Line Tunnel Temperature - High functions in MODES 1, 2, and 3. Contrary to
the requirement of TS LCO 3.0.4, on November 22, 2010, the inboard and
outboard main steam line PCIVs were not operable (unable to automatically
close on a primary containment isolation signal due to an electrical isolation)
prior to entering Mode 2, and the associated actions to be entered did not permit
continued operation in Mode 2 for an unlimited period of time. Once identified,
38 Enclosure
the licensee restored electrical power to the PCIVs and entered the issue into the
corrective action program as CAP 01259879.
The inspectors applied IMC 0609, Attachment 4, Phase 1 - Initial Screening
and Characterization of Findings, to this finding. Using the Table 4a worksheet,
the inspectors answered Yes to Question 3 and applied IMC 0609, Appendix H,
Containment Integrity Significance Determination Process. Per IMC 0609,
Appendix H, the finding was considered a Type B finding; that is, a finding that
has potentially important implications for integrity of containment without affecting
the likelihood of core damage. Table 6.2, Phase 2 Risk Significance - Type B
Findings at Full Power, provided the risk significance for this finding.
For BWR Mark I reactor types, the significance of Type B findings for less than
three days duration is Green.
ATTACHMENT: SUPPLEMENTAL INFORMATION
39 Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
T. OConnor, Site Vice President
J. Grubb, Plant Manager
W. Paulhardt, Assistant Plant Manager
N. Haskell, Site Engineering Director
K. Jepson, Business Support Manager
S. Radebaugh, Maintenance Manager
M. Holmes, Radiation Protection/Chemistry Manager
D. Neve, Regulatory Affairs Manager
S. Speight, Regulatory Affairs
S. Hafen, Nuclear Oversight Manager
M. Hutin, Program Engineering Director
M. Hippe, Engineering Fire Protection
S. Kibler, Program Engineering
G. Sherwood, Program Engineering Manger
V. Bhardwaj, Design Engineering Director
M. Kelly, Fleet Program Engineering Supervisor
D. Potter, Fleet Engineering Supervisor
T. Jones, NDE Level III
P. Sauerissig, FAC Engineer
S. Oswald, Regulatory Affairs
Nuclear Regulatory Commission
K. Riemer, Chief, Reactor Projects Branch 2
A. M. Stone, Chief, Engineering Branch 2
B. C. Dickson, Chief, Plant Support Team
1 Attachment
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
5000263/2011002-02 URI Calculation of Work Hours during Fatigue Rule
Implementation (Section 4OA2.3)
Opened and Closed
05000263/2011002-01 NCV Inadequate System Isolation during Check Valve
Maintenance (Section 1R20)05000263/2011002-03 NCV Failure to Control a Level 1 FME Area during New Fuel
Receipt Activities (Section 4OA3.2)
Closed
05000263/2010-006-00 LER Mode Change Made with PCIVs Inoperable
(Section 4OA3.3)
05000263/2009-001-02 LER Containment Overpressure Not Ensured in the Appendix R
Analysis (Section 4OA3.4)
05000263/2011-002-00 LER ESF Actuation Due to a Failed Power Supply
(Section 4OA3.5)
05000263/2010-004-00 LER Secondary Containment Briefly Inoperable Due to
Simultaneous Opening of Airlock Doors (Section 4OA3.6)5000263/2010008-01 URI Potential Concern with the One-Time Inspection Program
Related to Butt Welds (Section 4OA5.1)
Discussed
None
2 Attachment
LIST OF DOCUMENTS REVIEWED
The following is a partial list of documents reviewed during the inspection. Inclusion on this list
does not imply that the NRC inspector reviewed the documents in their entirety, but rather that
selected sections or portions of the documents were evaluated as part of the overall inspection
effort. Inclusion of a document on this list does not imply NRC acceptance of the document or
any part of it, unless this is stated in the body of the inspection report.
Section 1R01
1151; Winter Checklist; Revision 65
C.4-B.08.03.A; Loss of Heating Boiler; Revision 6
B.08.07-05; Extreme Cold Weather Procedure; Revision 24
8136; SCT Penetrations; Revision 17
CAP 00743426; Reactor Head Vent Found Frozen in Place
CAP 01166397; B.08.07-05 Extreme Cold Weather Procedure; Revision 20
CAP 01209511; E-100A 11 CT Riser Valves Frozen Shut - Near Miss
Emergency Plan for External Flooding Event Reaching Elevation 918; Revision 2
1478; Annual Flood Surveillance; Revision 3
Section 1R04
2154-28; Diesel Generator Air Start System Prestart Valve Checklist; Revision 9
2124; Plant Prestart Checklist Diesel Generators and Fuel Oil System; Revision 8
2154-14; Fuel Oil System Prestart Checklist; Revision 16
NH-36051; P&ID Diesel Fuel Oil System; Revision 77
B.09.08; EDG System; Revision D
CAP 01266032; FO-16 (Fire Pump Supply) Found Out of Position
2154-07; SBLC System Prestart Valve Checklist; Revision 11
2113; Plant Prestart Checklist SBLC System; Revision 13
NH-36253; P&ID SBLC System; Revision 77
B.03.05; SBLC System; Revision 10
CAP 01254014; Received Spurious Alarm C05-B-15 (Standby Liquid Hi/Lo Temp)
00041885; Clearance Order Checklist; FINI-11-67B, Replacement of Lamp Assembly
2154-11; CS System Prestart Valve Checklist; Revision 18
NH-36248; P&ID CS System; Revision 79
B.03.01; CS Cooling System; Revision 3
Section 1R05
4 AWI-08.01.00; Fire Protection Program Plan; Revision 12
Fire Strategy A.3-09; Control Room (9); Revision 7
CAP 01266328; A.3-09; Revision 7
CAP 01266330; A.3-10; Revision 13
CAP 01266331; Discrepancies Noted in A.3 Procedures
Fire Strategy A.3-07-A; 125V Division I Battery Room; Revision 5
Fire Strategy A.3-07-B; 250V Division I Battery Room; Revision 8
Fire Strategy A.3-07-C; 125V Division II Battery Room; Revision 6
CAP 01270371; Questions Raised on 250 VDC and 125 VDC Battery Condition
Fire Strategy A.3-23-A; Intake Structure Pump Room; Revision 11
Fire Strategy A.3-06; Refuel Floor; Revision 6
Fire Strategy A.3-19A; Make-Up Demin Area; Revision 9
3 Attachment
Fire Strategy A.3-19B; Essential Motor Control Center Area (NO. 142 & 143 931 ELEVATION);
Revision 11
Fire Strategy A.3-19C; F.W. Pipe Chase; Revision 5
AR 01270032; Configuration Error Found; February 9, 2011
AR 01270498; No Switch Development for Switch 14A-S3B; February 11, 2011
FPEE 2010-01; Alternate Compensatory Measures for Multiple Spurious Operations Identified
Nonconformances; Revision 0
NX-7833-21-4; Elementary Diagram - CS System; Revision 76
NE-36404-5A; CS Pump P-208B ACB 152-605 Control; Revision S
NE-36394-18A; Emergency Service Water Pump P-111B and Scheme B4319; Revision F
NX-7833-21-4A; Elementary Diagram - CS System; Revision 77
NX-7905-46-1; Elementary Diagram - RHR System; Revision 77
NF-100335-3; Alternate Shutdown System Schematic; Revision 78
Section 1RO6
PRA-CALC-04-004; Flood Initiating Event Frequencies; Revision 0
PRA-CALC-04-003; Flood Source Identification; Revision 0
CAP 1274344; Water Leaking into Lower 4kv Room from Stator Cooling Valves
PRA-CALC-04-001; Flood Areas; Revision 0
PRA-CALC-04-005; Equipment Vulnerabilities to Flooding; Revision 0
CAP 1274346; Water Leaks by SW-250 on C/O 37330
PRA-CALC-04-006; Flood Scenarios and Effects; Revision 0
CAP 1275079; Evidence of Water Pooling in Lower Cubicles of LC-109
Section 1RO7
1136; RHR Heat Exchanger Efficiency Test; Revision 30
CA-97-113; RHR Heat Exchanger Performance Analysis
CA-97-023; RHR Heat Exchanger K Values with Two RHR and Two RHRSW Pumps in
Suppression Cooling Mode
CAP 01028386; RHR Heat Exchanger Modeled Flow Incorrectly in Several Calcs
CAP 01172846; RHR B Heat Exchanger Issue Resolution
B.03.04; RHR System; Revision 5
CAP 01271131; Question about USAR Interpretation and Accuracy
USAR 7.6.3; Primary Containment Isolation System; Revision 27
B.03.04-4 RHR System, References; Revision 40
B.03.04-6 RHR System; Revision 5
1136; RHR Heat Exchanger Efficiency Test; Revision 30
CAP 01172846; RHR B Heat Exchanger Issue Resolution
CAP 01028386; RHR Heat Exchanger Modeled Flow Incorrect in Several Calcs
12 RHR Heat Exchanger Test Data; February 15, 2011
WO 0000229; Plug No. 12 RHR Heat Exchanger Tubes; January 15, 2000
Section 1R08
PEI-02.02.01; Dry Powder Magnetic Particle Examination; Revision 1
FP-PE-NDE-03; Written Practice for Qualification and Certification of NDE Personnel;
Revision 6
FP-PE-NDE-401; UT of Ferritic Pipe Weld-Supplement 3; Revision 3
FP-PE-NDE-406; UT of Reactor Pressure Vessel Welds; Revision 1
4 Attachment
FP-PE-FAC-02; Layout and Marking of Piping and Components for Flow Accelerated Corrosion
Program; Revision 1
ISI Examination Plan, Fourth Interval; Revision 4
AR 01241927; Station OE Evaluation of NRC IN 2010-2; July 19, 2010
AR 01276343; During a QC MT Exam a Linear Indication was Found; March 19, 2011
AR 01177677; Indications Discovered In Shroud Support Legs; April 10, 2009
AR 01174890; ISI Exam Revealed Non-Rotating Bearing on Snubber; March 25, 2009
AR 01176895; Drywell/Torus Surface Inspection Results; April 5, 2009
MNGP-RFO-25-INF-11-03; Indication Notification; March 16, 2011
FP-PE-B31-PIP1-GTSM-001; Groove Welds and Fillet Welds, P1-P1, GTAW/SMAW,
without PWHT; Revision 3
Welding Procedure Specification; FP-PE-B31-P1P1-GTSM-001; Revision 2
SM-1-1; Welding Procedure Qualification Record; Revision 1
Work Order 00380817; Re-Install RCIC Steam Line and Supports; March 30, 2009
Section 1R11
SEG RQ-SS-103
Section 1R12
90-023; Minimum Allowable Fuel Oil Storage Tank Level; Revision 2
50.59 Screening 10-0319; Replace Fuel Oil Transfer Level Switch LS-7211; Revision 0
Equivalency Evaluation Equivalent/Alternate Change 12303; Replace Fuel Oil Transfer Level
LS-721 Switch; Revision 0
B.09.08; Diesel Generators; Revision 10
B.08.11; Diesel Oil System; Revision 7
1052-04; 12 Diesel Generator Auxiliary Systems Test; Revision 15
CAP 01268419; LS-7211 Replacement Switch Failed during Testing
CAP 01267884; 12 EDG Base Tank Level Switches are not Functioning
CAP 01267658; CSP System Health Color Turned YELLOW
System Health Report; CSP, CS; January 24, 2011
CAP 01261935; A CSP Pump Motor Upper Oil Reservoir Cooling Coil HX Leaking
CAP 01265872; Adequacy of Equipment EOC Questioned
CAP 01242119; P-208A Motor Cooling Coil Found with Damage during Disassembly
CAP 01246421; 12 CSP Upper Motor Bearing High Oil Level
Section 1R13
CAP 01265569; WO 420235 Results Require Extent of Condition Evaluation
CAP 01265233; Steam/Water Leak from Piping on RWCU Regenerative Heat Exchangers
CAP 01265544; Potential Adverse Impact from RWCU on SRM/IRM
CAP 01265389; Water Leaking onto SRM and IRM Amplifier Cabinet
CAP 01238597; P225A FO Transfer Pump Leaking Bearing Grease
TS Bases 3.8.1; AC Sources- Operating; Revision 7
B.09.08; Diesel Generators; Revision 10
B.08.11; Diesel Oil System; Revision 7
1052-04; 12 Diesel Generator Auxiliary Systems Test; Revision 15
USAR 08.04; Plant Standby Diesel Generator Systems; Revision 24
NX-9216-5-4A; Physical Schematic and Field Connection- Model 999 No. 12 EDG; Revision 76
NH-36051; P&ID Diesel Fuel Oil System; Revision 77
5 Attachment
CAP 01267884; 12 EDG Base Tank Level Switches are not Functioning
CAP 01268038; Condition of Removed Fuel Oil Level Switches from No. 12 EDG
CAP 01268207; New LS-7211 EDG Level Switch did not Function as Expected
CAP 01268425; Original Level Switch, LS-7211, for No. 12 EDG was Reused
CAP 01268199; Exceeded 50 Percent of LCO Required Action Time for 12 EDG Window
CAP 01268234; 12 EDG LS-7211 Wires were Rolled
WO 00421339; 12 EDG Base Tank Level Switches are not Functioning; January 28, 2011
4 AWI-08.15.03; Risk Management for Outages; Revision 6
SWI-14.01; Risk Management for Outages and On-line Activities; Revision 5
9210; Master RPV Disassembly Procedure; Revision 11
FP-OP-ROM-02; Shutdown Safety Management Program; Revision 0
FP-OP-PEQ-01; Protected Equipment Program; Revision 0
OWI-03.08; Protected Equipment Program; Revision 4
9040; Temporary Vessel Level Instrumentation Installation and Restoration; Revision 10
Operations Manual C.3; Shutdown Procedure; Revision 63
WO 394791; Title 9224 - Dryer Removal High Risk Plan; March 9, 2011
2270; Critical Safety System Checklist - week of March 7, 2011
RF-25 Defense in Depth Variance to the Rev 0 Sched - Critical Safety Functions; March 8, 2011
Outage Risk Plan for RFO 25; week of February 28, 2011
NX7955-119-1; Refueling Platform One-line Diagram; Revision 2
WO 412387; Contingency Troubleshoot/Repair Refuel Bridge; March 17, 2011
CAP 01275823; Refuel Bridge Issues during RFO-25
CAP 01276444; Latest Replacement 8-58 Bridge Hoist Joystick not Adjustable
CAP 01276451; Refuel Bridge Controller Lead Position does not Match Print
CAP 01276919; 1N6 Lockout Occurred on 1AR Power Transfer from 10 Bank
CAP 01227229; 1AR XFMR Lockout Caused by 1N6 Ground Fault
Section 1R15
CAP 01156561; Apparent Degrading Flow Trend - V-EF-40B
WO 371712; V-EF-40B Inspect Ductwork
CAP 1270531; PMT Failure for V-EF-40B, Div II 250VDC Battery Room Vent
CAP 1233587; No Documented Required Flow for RM-9021A/B
B.05.11-05; Process Radiation MonitoringSystem Operation; Revision 29
C.6-242-A-09; Annunciator Response Procedure - V-EF-40B Low Flow; Revision 5
Operations Manual B.08.13-05; Main Control Room Heating, Ventilation, and Emergency
Filtration TrainSystem Operation; Revision 18
Operations Manual B.08.13-01; Main Control Room Heating, Ventilation, and Emergency
Filtration TrainFunction and General Description of System; Revision 10
Operations Manual B.08.07-01; Heating and VentilationFunction and General Description of
System; Revision 6
C.6-242-A-09
USAR Section 7; Plant Instrumentation and Control Systems; Revision 27
USAR Appendix J; Fire Protection Program; Revision 22
ESM-01.02; Design Practices; Revision 12
CAP 01271131; Question about USAR Interpretation and Accuracy; February 17, 2011
MPS-0274; G.E. Design Specification 22A1126; Primary and SCT System
MPS-0277; G.E. Design Specification 22A1132; Containment Isolation Systems
MPS-0346; G.E. Design Specification 22A2501; Engineered Safeguards Sub Systems and
Primary Containment Isolation Systems Separation
NX-7834-67-1; Reactor Protection System; Revision 76
6 Attachment
NX-7823-4-1; Elementary Diagram Primary Containment Isolation System; Revision J
NX-7834-58-1; Interconnect Scheme Reactor Protection System; Revision J
OWI-03.03; Operation with the Potential to Drain the Reactor; Revision 3
WO 314216-14; CRD-104 for HCU 34-39 Body-to-Bonnet Leak
CO 41006; Hang C/L No. 1: CRD-104/34-39 Repair Bonnet Leak
8167-01; Freeze Sealing Using Freeze Master; Revision 9
WO 381642-06; Investigate Repair Leaking CRD-113, Scram Vlv on CRD 22-23
CO 40413; Hang CL No. 1: CRD-113/22-23, Repair/Replace Leaking Valve
WO 368061-08; Investigate and Repair Leak on CRD-104/02-23
CO 41610; Hang C/L No. 1: CRD-104/02-23 Repair Bonnet Leak
NH-36245; P&ID Control Rod Hydraulic System; Revision 77
NH-36244; Control Rod Hydraulic System P&ID; Revision 80
OPDRV Screening Chart
Section 1R18
EC 14638; Change MSIV and Seat Ring Hard-Faced Material from Stellite 6 to Stellite 21
CAP 01278168; Internal Damage to Outboard MSIVs
Section 1R19
CAP 01270939; Reactor Building Doors not Tested per Work Plan after Maintenance
1297-01; SCT Door Interlock Check; Revision 14
WO 419439; Door is Presenting Interferences for Bringing in the New Steam Dryer
4048-PM; SCT Isolation Damper Maintenance; Revision 24
CAP 01270429; V-D-61 Damper Actuator Arm Bent, Prevent Opening
CAP 01270014; Suspected Coil Leak on V-AH-4A
WO 422190; MECH - V-D-61 Damper Motor Linkage Bent
4048-PM; SCT Isolation Damper Maintenance; Revision 24
WO 378941; 186-603 Replace Lockout Relay
WO 388993; RV-1993 14 RHR Pump Suction Relief Valve Replacement
4850-603-PM; 152-603 14 RHR Pump Relay Maintenance, Calibration and Test Tripping;
Revision 6
0007-A; Condenser Low Vacuum Scram Instruments Test and Calibration Procedure
WO 406610; Replace PS-5-11C
Section 1R20
Operations Manual C.3; Shutdown Procedure; Revision 63
C.4-A; Reactor Scram; Revision 34
2300 Reactivity Adjustment; Revision 4
4 AWI-08.15.03; Risk Management for Outages; Revision 6
SWI-14.01; Risk Management for Outages and On-line Activities; Revision 5
9210; Master RPV Disassembly Procedure; Revision 11
FP-OP-ROM-02; Shutdown Safety Management Program; Revision 0
Duty Shift Manager Notes for PORC Meeting 3/1/11
9001; Reactor Well & Dryer-Separator Storage Pool Filling Procedure; Revision 23
8048; Bypass of RWM during Plant Shutdown Using Improved BPWS Control Rod Insertion
Process; Revision 4
EOC25 Shutdown Reactivity Management Plan Overview; March 1, 2011
Reactivity Maneuvering Steps; March 4, 2011
7 Attachment
Operations/Maintenance Site Clock Reset - Red Sheet; March 18, 2011
CAP 1275963; Clearance Order did not Provide Boundary for CST-88 Repair
CAP 1275935; Found Pressurized Water when Dis-Assembling CST-88
Human Performance Event Review Committee for AR 1275935 Notes; March 18, 2011
CAP 1276336; Adverse Trend in Outage Tagging
2270; Critical Safety System Checklist; Revision 3
FP-OP-TAG-01; Fleet Tagging; Revision 10
0255-22-IA-1; CST-88 B LPCI Fill Line Check Valve Test; Revision 9
NH-85509; P&ID Service Condensate SystemRadwaste Building; Revision 77
NH-36039; P&ID Service Condensate System; Revision 75
NH-36247; P&ID RHR System; Revision 79
B.08.09-02; Condensate Storage System; Revision 5
4045-OCD; RHR Loop B Leak Rate Tests; Revision 15
WO 394266; 0255-22-IA-1 CST-88 B Loop LPCI Fill Line CKV Oper
OWI-02.07; Operations Work Control; Revision 34
4263; Maintenance and Construction Pre-Job Briefing Checklist; Revision 23
4 AWI-04.05.07; Procedure Use and Adherence (FP-G-DOC-03); Revision 27
Section 1R22
CAP 01265605; TS Surveillance was Missed for Diesel Fuel Oil
0192; Diesel Fuel Quality Checks; Revision 29
8096; Fuel Oil Transfer from the Diesel Oil Receiving Tank to the Diesel Oil Storage Tank;
Revision 12
OSP-DOL-0543; Fuel Oil Receiving Quality Check; Revision 7
PRA-MEMO-11-002; Risk Assessment of Diesel Fuel Oil Missed Surveillance; January 10, 2011
Lab Number V5002355; T-83A New Diesel Fuel Oil Shipment Analysis; November 1, 2010
Lab Number V5002989; Diesel Oil Storage Tank T-44 Monthly Particulate Sample;
January 12, 2011
0007-A; Condenser Low Vacuum Scram Instruments Test and Calibration Procedure;
Revision 24
B.06.03; Main Condenser; Revision 14
0021-01; Reactor Low Level Scram and Low-Low Level Isolation Transmitter Calibration
Procedure; Revision 14
USAR 7.6; Plant Protection System; Revision 27
B.05.06; Design Basis Document: Plant Protection; Revision C
0278-B; ATWS-Recirc Trip for Reactor Pressure and Level Trip Unit Test and Calibration;
Revision 20
CAP; NRC Questions Whether ATWS Trip Cal Causes Preconditioning
0255-03-IA-2A; CS - Shutdown Valve Operability Test; Revision 21
NH-36248; MNGP P&ID CS System; Revision 79
9001; Reactor Well & Dryer Separator Storage Pool Filling Procedure; Revision 23
Ops Manual B.03.01; CS Cooling System; Revision 3
0137-07A; Reactor Steam Supply Valves Leak Rate Testing; Revision 26
EWI-08.06.01; MNGP Primary Containment Leakage Rate Testing Program; Revision 10
0137; Master Local Leak Rate Test; Revision 34
0137-A; LLRT-LRM-Makeup Flow Method; Revision 1
0137-B; LLRT Pressure Decay Method; Revision 0
0137-07A-02-OCD; Reactor Steam Supply Valve Leak Rate Testing by Pressurizing the Main
Steam Lines; Revision 15
CAP 01275312; Unexpected Configuration Found after Turnover for 0137-07A
8 Attachment
CAP 01275315; Delay in MSIV testing due to Procedure Conflicts
NH-36241; Nuclear Boiler SystemSteam Supply P&ID; Revision 82
CAP 01275532; MO-2075 and MO-2076 Failed App J Admin Limit
B.09.15; Nonessential Diesel Generator
18615.01-E031B; Specification for Standby Diesel Generator; March 18, 1989
Monticello Maintenance Rule Program; System Basis Document; Non-Essential Diesel
Generator; Revision 3
EWI-05.02.01; Monticello Maintenance Rule Program Document; Revision 16
USAR 8.4.2; Non Safeguards Diesel Generator; Revision 27
NDG Non-Essential Diesel Generator System Health Report; February 7, 2011
Unavailability Hours for 13 NDG; January 2011
Operator Rounds; January 23, 2010
Station Logs; January 13, 2011
Maintenance Rule Evaluation for CAP 01266100
Equipment Reliability Clock Evaluation for CAP 01266100
CAP 01266100; 13 Diesel Generator would not Manually Synch to LC-107
CAP 01267418; 13 D. Generator No. 2 Water Jacket Heater not Working; January 22, 2011
CAP 01215001; 13 DG B Side Engine Heater not Working Properly; January 23, 2010
CAP 01270472; No. 13 NDG MR Changed Color to Yellow; February 11, 2011
CAP 01266954; 13 DG Freq Relay Impacts Manual and Auto Breaker Close; January 19, 2011
CAP 01266099; PRA Associated with 13DG not Reflected on Schedule; January 13, 2011
CAP 01262539; 13 D. Generator Jacket Temperature Less than 90 degrees F;
December 2, 2010
Section 1EP6
MNGP Emergency Planning Drill Package; February 9, 2011
Section 2RS5
AR 01238399; Adverse Trend Identified for PRM Equipment; June 26, 2010
Efficiency Calibration Data Files for HPGe Detectors; Selected Dates
Gamma Reports for Liquid and Gaseous Samples; Selected Dates
General Atomic Company; Certificate of Radioactivity Standard; Source Type 0360-0593-01;
July 1981
Nuclear Oversight 1st Quarter 2010 Assessment Report; May 14, 2010
Nuclear Oversight 2nd Quarter 2010 Assessment Report; August 18, 2010
Nuclear Oversight 3rd Quarter 2010 Assessment Report; December 1, 2010
ODCM; Selected Revisions
Process Radiation Monitor Alarm and Trip Points; January 2010
Radioactive Source Transaction Forms; Selected Dates
Snapshot Self-Assessment; 01251738-15; Radiation Protection Instrumentation; January 2011
Title 10 CFR Part 61 Updates Documentation; Selected Dates
USAR; Section 7.5; Plant Radiation Monitoring Systems; Revision 25
0163; Stack Wide Range Gas Monitor Calibration; December 2010
0226; Semiannual Source Inventory and Smear Test; November 2009
0248; Reactor Building Vent Wide Range Gas Monitor Calibration; April 2010
5504; Whole Body Counter Calibration Checklist; Various dates 2009 and 2010
5849; PM-7 Calibration; January 2011
5854; SAM-11/LAM Calibration; Various dates 2010 and 2011
9 Attachment
5871; ARGOS Calibration; Various dates 2010 and 2011
5879; GE ARM Box Calibration Source Verification; March 2010
5598-01; Semiannual Smear Counter Functional Checks; Various dates
5728-02; Semiannual ABACUS Smear Counter Functional Checks; Various dates
Section 4OA1
AR 01211188; Number of HRA and LHRA Entries Challenges Access Control; December 2009
AR 01212497; Dose Alarm Received while Performing Survey in RWCU Room; February 2010
AR 01212747; ED Dose Rate Alarm not Heard during HRA Entry; February 2010
AR 01238088; SJAE Room HELB Barrier Locked with Personnel Working Inside; August 2010
AR 01238171; Unexpected Dose Rates Encountered during RWCU Filter Backwash;
June 21, 2010
AR 01263347; Torus to RCIC Door Lock Not Operating Correctly; December 2010
Electronic Dosimeter Dose and Dose Rate Alarm Log - January 2010 to January 2011;
February 3, 2011
RPGP-01.14; Self-Assessment Program; Revision 14
FP-PA-PI-02; NRC/INPO/WANO PI Reporting; Revision 6
Section 4OA2
CAP 01265921; Hardhats not Worn as Required
CAP 01265922; Door Checks not Being Completed as Required
CAP 01267295; NRC Observations Shared with Plant Manager Staff
CAP 01267450; Surface Oxidation/Corrosion on CRD HCU Riser Valves
CAP 01269945; Toolboxes were not Secured in the TIP Drive Room
CAP 01269953; Oil Leaking from Sight Glasses on RCIC System
CAP 01269976; V-HC-11 Leaking Outside the Catch Funnel onto the Floor
CAP 01272068; Corrosion on Mounting Bolt for Div1 250 Vdc Battery Stand
CAP 01272074; Electrical Department Toolbox not Chalked
CAP 01272253; NRC Question Regarding Fire Watch
CAP 01275597; NRC Question Regarding FME Buffer Zone Requirements
FP-S-WHL-01; 10 CFR 26 Scope of Work Hour Limits; Revision 2
FP-S-FMP-01; 10 CFR 26 Fatigue Management Fleet Procedure; Revision 2
FP-S-CWH-01; 10 CFR 26 Calculating Work Hours; Revision 1
FP-S-FAP-01; 10 CFR 26 Fatigue Assessment Procedure; Revision 1
CAPs generated between March 19, 2010 and March 19, 2011 regarding Work Hour Controls
CAP 1234747; Potential Adverse Trend Work Hour Procedure Adherence
CAP 1219126; Multiple Security Officers Exceeded 10 CFR 26 Rule
CAP 1234413; Work Hours Exceeded on May 23, 2010
CAP 1239945; Adverse Trend in Maint Grp Work Hour Procedure Adherence
CAP 1218230; Supervisor Exceeded MDO requirement of 10 CFR 26
CAP 1253396; Subyard Work Possibly not in Compliance with Work Hour Rules
CAP 1270962; Excess Work Hours for Two Covered Workers
CAP 1276434; Seven DZ Employees Violated 10 CFR 26 Work Hours
CAP 1241474; Violation of Work Hours Rules under 10CFR26
CAP 1254318; WorkForce Security Schedule Change Request
Work Schedules for Select Individuals within the Maintenance, Operations, Fire Brigade, and
Security Departments
10 Attachment
Section 4OA3
FME Control Plan for 1027 Refuel Floor; January 1, 2011 to May 2011
General Employee Training M-7730F-012; On-Line FME; Revision 1
General Employee Training MT-SHE-GEN-001L; FME Monitor Training; Revision 1
9015; Procedure for Inspection of New Fuel; Revision 32
CAP 01267670; FME Control Point Protocol not Followed
FP-MA-FME-01; Foreign Material Exclusion and Control; Revision 2
CAP 1259879; Mode Change with Inoperable PCIVs
RCE CAP 1259879; Mode Change with Inoperable PCIVs
4 AWI-04.05.07; Procedure Use and Adherence; Revision 27
4 AWI-09.02.01; Quality Control Inspections; Revision 15
PRA-MEMO-10-008; Risk Assessment of LER 2010-06; December 2, 2010
FP-G-DOC-03; Procedure Use and Adherence; Revision 9
CAP 1263610; Received Unexpected Alarm ANN-5-A-2, Reactor Bldg Vent & F P
CAP 1263610; ACE; January 19, 2011
PRA-MEMO-11-003; Risk Assessment of LER 2011-02; January 17, 2011
NJ53562; Dual Trip Circuit Drawing; Revision C
Part 21 Evaluation Power Supply Model No. 112C2235G012/ST, S/N 100927-2
Monticello Station Log Entries for December 20, 2020
CAP 1232366-01; ACE; June 9, 2010
CAP 1232366; Failure of ES-17-451B, Causes REAC BLG Vent & FP RAD CH B LO
CAP 1232366-01; ACE; July 23, 2010
CAP 1236790; FP & Plenum PRM Power Supply Refurbishment and Replacement
SC/CNT 00022414; 115349-Refurbish Safety-Related ARM Power Supplies; July 29, 2009
Section 4OA5
FAC Program MNGP 1R24 Outage Summary Report
FAC Program MNGP RFO 23 Outage Summary Report
CD 5.17; Flow Accelerated Corrosion and Service Water Inspection Program Standard;
Revision 5
II.01; Strategic Chemistry Plan; Revision 14
FP-E-MOD-04; Design Inputs; Revision 7
FP-PE-FAC-01, FAC Program; Revision 9
AR 01219342; Update FAC Master Plan; February 22, 2010
2009-04-001; NOS Observation Report - FAC Program; November 2, 2009
PBD/AMP-002, Aging Management Program Basis Document, Flow - Accelerated Corrosion
(FAC) Program; Revision 4
11 Attachment
LIST OF ACRONYMS USED
ACE Apparent Cause Evaluation
ADAMS Agencywide Document Access Management System
AOP Abnormal Operating Procedures
ASME American Society of Mechanical Engineers
ATWS Anticipated Transient without Scram
CAP Corrective Action Program
CFR Code of Federal Regulations
CIV Containment Isolation Valve
CO Clearance Order
CREF Control Room Emergency Filtration
CRV Control Room Ventilation
CST Condensate Storage Tank
CSW Condensate Service Water
DRP Division of Reactor Projects
EC Engineering Change
EDG Emergency Diesel Generator
EGM Enforcement Guidance Memorandum
EPU Extended Power Uprate
FAC Flow Accelerated Corrosion
FME Foreign Material Exclusion
FPEE Fire Protection Engineering Evaluation
FSAR Final Safety Analysis Report
IMC Inspection Manual Chapter
INPO Institute of Nuclear Power Operations
IP Inspection Procedure
IRM Intermediate-Range Monitor
ISI Inservice Inspection
IST Inservice Test
kV Kilovolt
LCO Limiting Condition for Operation
LER Licensee Event Report
LLRT Local Leak Rate Test
LPCI Low Pressure Coolant Injection
MNGP Monticello Nuclear Generating Plant
MOV Motor-Operated Valve
MSIV Main Steam Isolation Valve
MSO Multiple Spurious Operations
MSPI Mitigating Systems Performance Index
MT Magnetic Particle Examination
NCV Non-Cited Violation
NEI Nuclear Energy Institute
NFPA National Fire Protection Association
NMC Nuclear Management Company
NOS Nuclear Oversight
NRC U.S. Nuclear Regulatory Commission
NRR Nuclear Reactor Regulation
ODCM Offsite Dose Calculation Manual
OE Operating Experience
12 Attachment
OSP Outage Safety Plan
OTI One-Time Inspection
PARS Publicly Available Records System
PCIV Primary Containment Isolation Valves
PI Performance Indicator
PM Post-Maintenance
RCE Root Cause Evaluation
RCIC Reactor Core Isolation Cooling
RETS Radiological Effluent Technical Specification
RFO Refueling Outage
RG Regulatory Guide
RHRSW Residual Heat Removal Service Water
ROP Reactor Oversight Process
RT Radiographic Examination
SBGT Standby Gas Treatment
SDP Significance Determination Process
SRM Source Range Monitor
SRO Senior Reactor Operator
SSC Structure, System, and Component
TS Technical Specification
URI Unresolved Item
USAR Updated Safety Analysis Report
UT Ultrasonic Examination
Vdc Volts Direct Current
WO Work Order 13 Attachment
T. O'Connor -2-
U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector
Office at the Monticello 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 Monticello Nuclear
Generating Plant.
In accordance with 10 CFR 2.390 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 NRC Public Document Room or from the Publicly Available Records System (PARS)
component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Website
at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Kenneth Riemer, Chief
Branch 2
Division of Reactor Projects
Docket No. 50-263
License No. DPR-22
Enclosure: Inspection Report 05000263/2011002
w/Attachment: Supplemental Information
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DATE 05/02/11 05/03/11 05/10/11
OFFICIAL RECORD COPY
- Sections 1RO5.2, 4OA3.4, and Cover Letter
Letter to T. O'Connor from K. Riemer dated May 10, 2011
SUBJECT: MONTICELLO NUCLEAR GENERATING PLANT NRC INTEGRATED AND
POWER UPRATE REVIEW INSPECTION REPORT 05000263/2011002 AND
EXERCISE OF ENFORCEMENT DISCRETION
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