ML102080143
| ML102080143 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 07/26/2010 |
| From: | Robert Orlikowski Reactor Projects Region 3 Branch 4 |
| To: | Schimmel M Northern States Power Co |
| References | |
| IR-10-003 | |
| Download: ML102080143 (57) | |
See also: IR 05000282/2010003
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE ROAD, SUITE 210
LISLE, IL 60532-4352
July 26, 2010
Mr. Mark A. Schimmel
Site Vice President
Prairie Island Nuclear Generating Plant
Northern States Power Company, Minnesota
1717 Wakonade Drive East
Welch, MN 55089
SUBJECT:
PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2,
NRC INTEGRATED INSPECTION REPORT 05000282/2010003;
Dear Mr. Schimmel:
On June 30, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed a baseline
inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed report
documents the inspection findings, which were discussed on July 8, 2010, 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, one NRC-identified and two self-revealed findings of
very low safety significance were identified. Two findings 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 VI.A.1 of the NRC Enforcement Policy.
If you contest the subject or severity of any NCV, you should provide a response within 30 days
of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear
Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with
a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III,
2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement,
U.S. Nuclear Regulatory Commission, Washington, DC 20555 0001; and the Resident Inspector
Office at the Prairie Island Nuclear Generating Plant. In addition, if you disagree with the
cross-cutting aspect assigned to any finding in this report, you should provide a response within
30 days of the date of this inspection report, with the basis for your disagreement, to the
Regional Administrator, Region III, and the NRC Resident Inspector at the Prairie Island Nuclear
Generating Plant.
M. Schimmel
-2-
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 by Kenneth Riemer for/
Robert J. Orlikowski, Acting Chief
Branch 4
Division of Reactor Projects
Docket Nos.
50-282; 50-306;72-010
License Nos. DPR-42; DPR-60; SNM-2506
Enclosure:
Inspection Report 05000282/2010003; 05000306/2010003
w/Attachment: Supplemental Information
cc w/encl:
Distribution via ListServ
Enclosure
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket Nos:
50-282; 50-306;72-010
License Nos:
Report No:
05000282/2010003; 05000306/2010003
Licensee:
Northern States Power Company, Minnesota
Facility:
Prairie Island Nuclear Generating Plant, Units 1 and 2
Location:
Welch, MN
Dates:
April 1 through June 30, 2010
Inspectors:
K. Stoedter, Senior Resident Inspector
P. Zurawski, Resident Inspector
D. Betancourt, Reactor Engineer
L. Haeg, Resident Inspector - Monticello
D. Jones, Reactor Inspector
R. Langstaff, Senior Fire Protection Inspector
R. Lerch, Project Engineer
M. Phalen, Health Physics Inspector
Approved by:
R. Orlikowski, Acting Chief
Branch 4
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) ...................................................................... 5
1R05
Fire Protection (71111.05) ................................................................................. 6
1R06
Flooding (71111.06) .......................................................................................... 7
1R08
Inservice Inspection Activities (71111.08P) ........................................................ 7
1R11
Licensed Operator Requalification Program (71111.11) ...................................11
1R12
Maintenance Effectiveness (71111.12) .............................................................12
1R13
Maintenance Risk Assessments and Emergent Work Control (71111.13) ........13
1R15
Operability Evaluations (71111.15) ...................................................................13
1R18
Plant Modifications (71111.18) .........................................................................14
1R19
Post-Maintenance Testing (71111.19) ..............................................................16
1R20
Outage Activities (71111.20) ............................................................................17
1R22
Surveillance Testing (71111.22) .......................................................................19
1EP6
Drill Evaluation (71114.06) ...............................................................................21
2.
RADIATION SAFETY ..................................................................................................21
2RS8
Radioactive Solid Waste, Processing and Radioactive Material Handling,
Storage, and Transportation (71124.08) ...........................................................21
4.
OTHER ACTIVITIES ...................................................................................................25
4OA1
Performance Indicator Verification (71151) .......................................................25
4OA2
Identification and Resolution of Problems (71152) ............................................26
4OA3
Follow-Up of Events and Notices of Enforcement Discretion (71153) ...............27
4OA5
Other Activities .................................................................................................36
4OA6
Management Meetings .....................................................................................37
4OA7
Licensee-Identified Violations ...........................................................................37
SUPPLEMENTAL INFORMATION ............................................................................................. 1
Key Points of Contact ............................................................................................................. 1
List of Items Opened, Closed and Discussed ......................................................................... 1
List of Documents Reviewed .................................................................................................. 3
List of Acronyms Used ...........................................................................................................12
1
Enclosure
SUMMARY OF FINDINGS
IR 05000282/2010003; 05000306/2010003; 4/1/2010 - 6/30/2010; Prairie Island Nuclear
Generating Plant, Units 1 and 2; Event Follow-Up.
This report covers a 3-month period of inspection by resident inspectors and announced
baseline inspections by regional inspectors. Two self-revealed and one NRC-Identified Green
findings were identified. Two of the findings were considered non-cited violations 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 self-revealed finding of very low safety significance was identified following an
automatic reactor trip on April 16, 2010. Specifically, the licensee failed to appropriately
establish and implement actions to correct the causes of a turbine trip/reactor trip in
2001 and a turbine trip in 2003 even though the actions were required by the corrective
action procedure in use at the time of the event. The failure to appropriately establish
and implement actions to correct the causes of the previous events resulted in creating a
large difference in Unit 2 condenser pressures while operating at lower power levels and
a subsequent turbine trip/reactor trip. Corrective actions for this issue included
correcting system deficiencies which led to the large difference in condenser pressures
and improving procedural guidance regarding the sealing steam system.
The inspectors determined that this issue was more than minor because it was
associated with the design control, configuration control and procedure quality attributes
of the Initiating Events Cornerstone and impacted the cornerstone objective of limiting
the likelihood of those events that upset plant stability and challenge critical safety
functions during shutdown as well as power operations. This finding was determined to
be of very low safety significance because it did not contribute to a reactor trip with
mitigating equipment not available. No cross-cutting aspect was assigned to this finding
because the decisions made in regard to the 2001 and 2003 actions were made more
than 2 years ago. No violation of NRC requirements was identified because the system
deficiencies that contributed to the turbine trip/reactor trip were associated with non
safety-related systems. (Section 4OA3.7)
Cornerstone: Mitigating Systems
Green. A self-revealed finding of very low safety significance and a non-cited violation of
Technical Specification 5.4.1 was identified on April 9, 2010, due to the licensees failure
to implement Step 5.1.1 of Procedure FP-G-DOC-03, Procedure Use and Adherence.
Step 5.1.1 of FP-G-DOC-03 required that personnel perform activities affecting quality
using working copies of continuous or reference use procedures. However, operations
personnel failed to use a working copy of reference use Procedure C37.13,
Containment and Auxiliary Building Cooling System, when performing valve alignments
2
Enclosure
to support the performance of a surveillance test. The failure to use a working copy of
C37.13 resulted in the operator performing a valve alignment incorrectly and a loss of
one-half of the Unit 2 containment cooling system. Corrective actions for this issue
included restoring the containment cooling system, briefing licensee personnel on the
event, and reinforcing the use of the human performance tools.
The inspectors determined that this finding was more than minor because it was
associated with the human performance attribute of the Mitigating System Cornerstone
and impacted the cornerstone objective of ensuring the availability, reliability, and
capability of systems that respond to initiating events to prevent undesirable
consequences. The inspectors determined that this finding was of very low safety
significance because it did not represent a loss of a system safety function, the fan coil
units were inoperable for less than the Technical Specification allowed outage time, and
the finding was not potentially risk significant due to external events. The inspectors
determined that this finding was cross-cutting in the Human Performance, Work
Practices area because licensee personnel did not ensure human error prevention
techniques were used such that work activities were performed safely (H.4(a)).
(Section 4OA3.8)
Green. A finding of very low safety significance and a non-cited violation of
10 CFR Part 50, Appendix B, Criterion V was identified by the inspectors on
March 15, 2010, due to the licensees failure to have instructions and procedures
appropriate to the circumstance for performing Work Order 382152 and Surveillance
Procedure 1295, D1 Diesel Generator 6 Month Fast Start Test. The failure to have
instructions and procedures appropriate to the circumstance resulted in rendering the
D1 diesel generator inoperable for 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> due to the introduction of foreign material
into the lube oil sump during oil addition activities. Corrective actions included retrieving
the hose and nozzle, replacing the plastic oil cans with new solid metal cans, and
revising the pre-job brief instructions and Are You Ready checklist to include a
question whether foreign material will be generated through the use of portable
equipment or tools.
The inspectors determined that the finding was more than minor because it was
associated with the procedure quality and human performance attributes of the
Mitigating Systems Cornerstone and impacted the cornerstone objective of ensuring
the availability, reliability and capability of systems that respond to initiating events to
prevent undesirable consequences. The inspectors determined that this finding was of
very low safety significance because it did not represent a loss of a system safety
function and the diesel generator was inoperable for less than the Technical
Specification allowed outage time. This finding was determined to be cross-cutting in
the Human Performance, Work Control area because the licensee failed to appropriately
plan work activities by incorporating job site conditions which may impact plant
structures, systems, or components (H.3(a)). (Section 4OA3.10)
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.
3
Enclosure
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at full power levels throughout the inspection period.
Unit 2 operated at or near full power levels with the following exceptions:
In early April, operations personnel began reducing reactor power to perform
valve testing prior to the refueling outage.
On April 16, 2010, the Unit 2 reactor automatically tripped from 13 percent power
due to a high differential pressure condition within the main condenser;
Refueling Outage 2R26 began immediately following the automatic reactor trip on
April 16, 2010;
Operations personnel began Unit 2 startup activities on May 19, 2010;
The Unit 2 reactor achieved criticality on May 22, 2010;
On May 25, 2010, the Unit 2 reactor automatically tripped from 31 percent power
due to the loss of the 21 feedwater pump;
The Unit 2 reactor returned to criticality on May 26, 2010.
Operations personnel identified a primary to secondary leak and entered
Abnormal Operating Procedure 2C4 AOP 2, Steam Generator Tube Leak, on
May 28, 2010.
Operations personnel returned Unit 2 to 100 percent power on May 31, 2010.
1.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
1R01 Adverse Weather Protection (71111.01)
.1
Readiness of Offsite and Onsite Alternating Current Power Systems
a.
Inspection Scope
The inspectors verified that plant features and procedures for operation and continued
availability of offsite and onsite alternating current (AC) power systems during adverse
weather were appropriate. The inspectors reviewed the licensees procedures affecting
these areas and the communications protocols between the transmission system
operator (TSO) and the licensee to verify that the appropriate information was being
exchanged when issues arose that could impact the offsite power system. Examples of
aspects considered in the inspectors review included:
The coordination between the TSO and operations personnel during off-normal or
emergency events;
The explanations for the events;
The estimates of when the offsite power system would be returned to a normal
state; and
The notifications from the TSO to operations personnel when the offsite power
system was returned to normal.
4
Enclosure
The inspectors also verified that plant procedures addressed measures to monitor and
maintain availability and reliability of both the offsite AC power system and the onsite
alternate AC power system prior to or during adverse weather conditions. Specifically,
the inspectors verified that the procedures addressed the following:
The actions to be taken when notified by the TSO that the post-trip voltage of the
offsite power system at the plant would not be acceptable to assure the continued
operation of the safety-related loads without transferring to the onsite power
supply;
The compensatory actions identified to be performed if it would not be possible to
predict the post-trip voltage at the plant for the current grid conditions;
A re-assessment of plant risk based on maintenance activities which could affect
grid reliability or the ability of the transmission system to provide offsite power;
and
The communications between the licensee and the TSO when changes at the
plant could impact the transmission system, or when the capability of the
transmission system to provide adequate offsite power was challenged.
Documents reviewed are listed in the Attachment to this report. The inspectors also
reviewed corrective action program (CAP) items to verify that the licensee was
identifying adverse weather issues at an appropriate threshold and entering them into
their CAP in accordance with the corrective action procedures.
This inspection constituted one readiness of offsite and alternate AC power systems
sample as defined in Inspection Procedure (IP) 71111.01-05.
b.
Findings
No findings of significance were identified.
.2
Readiness for Bio-fouling Concerns
a.
Inspection Scope
During the week of April 14, 2010, the inspectors observed licensee activities associated
with the treatment of raw water systems to control the population of zebra mussels. The
inspectors observed pre-job briefings to determine whether the briefings met licensee
standards. The inspectors reviewed prerequisites identified in Procedure D104.1,
Zebra Mussel Control Treatment: Circulating Water System, to determine whether
they were completed prior to the initiation of treatment. The inspectors were specifically
interested in the licensees actions to ensure that the following safety-related equipment
was not impacted by mussel settling:
Diesel-Driven Cooling Water Pump Heat Exchangers, and
D1 and D2 Diesel Generators.
As the zebra mussel treatment progressed, the inspectors periodically reviewed licensee
activities and data collection to determine whether mussel settlement was being properly
monitored. The inspectors also reviewed CAP items to verify that the licensee was
identifying zebra mussel treatment issues at an appropriate threshold and entering them
5
Enclosure
into the CAP in accordance with procedures. Specific documents reviewed during this
inspection are listed in the Attachment to this report.
This inspection constituted one seasonal adverse weather sample as defined in
b.
Findings
No findings of significance 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:
Spent Fuel Pool Cooling System;
21 Motor-Driven Auxiliary Feedwater (AFW) Pump; and
D6 Diesel Generator.
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, Updated Safety Analysis Report (USAR), Technical Specification (TS)
requirements, outstanding work orders (WOs), CAP documents, 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 were operable. The
inspectors examined the material condition of the components and observed operating
parameters of equipment to verify that there were no obvious deficiencies. The
inspectors also verified that the licensee had properly identified and resolved equipment
alignment problems that could cause initiating events or impact the capability of
mitigating systems or barriers and entered them into the CAP with the appropriate
significance characterization. Documents reviewed are listed in the Attachment to this
report.
These activities constituted three partial system walkdown samples as defined in
b.
Findings
No findings of significance were identified.
6
Enclosure
.2
Semiannual Complete System Walkdown
a.
Inspection Scope
On April 1, 2010, the inspectors performed a complete system alignment inspection of
the Unit 2 diesel generator fuel oil system to verify the functional capability of the
system. This system was selected because it was considered both safety significant
and risk significant in the licensees probabilistic risk assessment. The inspectors
walked down the system to review mechanical and electrical equipment line ups,
electrical power availability, system pressure and temperature indications, as
appropriate, component labeling, component lubrication, component and equipment
cooling, hangers and supports, operability of support systems, and to ensure that
ancillary equipment or debris did not interfere with equipment operation. A review of a
sample of past and outstanding WOs was performed to determine whether any
deficiencies significantly affected the system function. In addition, the inspectors
reviewed the CAP database to ensure that system equipment alignment problems were
being identified and appropriately resolved. Documents reviewed are listed in the
Attachment to this report.
These activities constituted one complete system walkdown sample as defined in
b.
Findings
No findings of significance were identified.
1R05 Fire Protection (71111.05)
.1
Routine Resident Inspector Tours (71111.05Q)
a.
Inspection Scope
The inspectors conducted fire protection walkdowns, which were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
areas:
Fire Zone 8 - Auxiliary Building Ground Floor;
Fire Zone 40 - Unit 2 Auxiliary Building 695 Foot Elevation;
Fire Zone 51 - Auxiliary Building Unit 2 Operating Level Elevation 735;
Fire Zones 3, 4, and 14 - Unit 1 Turbine Building; and
Fire Zone 20 - Bus 15 and 16 Switchgear Rooms.
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 licensees Individual Plant Examination of External Events with later
additional insights and their potential to impact equipment, which could initiate or
7
Enclosure
mitigate a plant transient. Using the documents listed in the Attachment to this report,
the inspectors verified that fire hoses and extinguishers were in their designated
locations and available for immediate use; that fire detectors and sprinklers were
unobstructed; that transient material loading was within the analyzed limits; and fire
doors, dampers, and penetration seals appeared to be in satisfactory condition. The
inspectors also verified that minor issues identified during the inspection were entered
into the licensees CAP. Documents reviewed are listed in the Attachment to this report.
These activities constituted five quarterly fire protection inspection samples as defined in
b.
Findings
No findings of significance were identified.
1R06 Flooding (71111.06)
.1
a.
Inspection Scope
As discussed in NRC Inspection Report (IR) 05000282/2010010; 05000306/2010010,
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 design documents, including the USAR,
engineering calculations, and abnormal operating procedures to identify licensee
commitments. 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 CAP documents with
respect to past flood-related items to verify the adequacy of the corrective actions. The
inspectors performed a walkdown of the following plant area to assess the adequacy of
doors and that the licensee complied with its commitments:
11, 12, 21, and 22 Battery Rooms.
The documents reviewed during this inspection are listed in the Attachment to NRC
IR 05000282/2010010; 05000306/2010010.
This inspection constituted one internal flooding sample as defined in IP 71111.06-05.
b.
Findings
A preliminary greater than green finding was identified. See Section 4OA5 of NRC
IR 05000282/2010010; 05000306/2010010 for additional details.
1R08 Inservice Inspection Activities (71111.08P)
From April 19 through May 13, 2010, the inspectors conducted a review of the
implementation of the licensees Inservice Inspection (ISI) Program for monitoring
degradation of the reactor coolant system (RCS), steam generator tubes, emergency
feedwater systems, risk-significant piping and components and containment systems.
8
Enclosure
The inspections described in Sections 1R08.1, 1R08.2, 1R08.3, 1R08.4, and 1R08.5
below constituted one ISI sample as defined in IP 71111.08.
.1
Piping Systems Inservice Inspection
a.
Inspection Scope
The inspectors observed 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 of the residual heat removal system elbow to elbow
weld 18, Report Number 2010U001; and
Ultrasonic examination of the residual heat removal system elbow to pipe weld 19,
Report Number 2010U002;
The inspectors reviewed records of the following non-destructive examinations:
Visual examination of the reactor vessel closure head, Report
Number PI2RF2010;
Liquid Penetrant examination of the N2 to Loop B, steam generator
reactor coolant pressure boundary isolation, 2RC-8-41, pipe to elbow weld 2;
Report Number BOP-PT-08-047; and
Liquid Penetrant examination of the N2 to Loop B, steam generator reactor
coolant pressure boundary isolation, 2RC-8-41, socket weld-pipe to valve weld 8;
Report Number BOP-PT-08-051.
During non-destructive surface and volumetric examinations performed since the
previous refueling outage, the licensee had not identified any recordable indications.
Therefore, no NRC review was completed for this inspection procedure attribute.
The inspectors reviewed the following pressure boundary welds completed for
risk-significant systems during the last refueling outage to determine if the licensee
applied the pre-service non-destructive examinations and acceptance criteria required
by ASME Code Section XI. Additionally, the inspectors reviewed the welding procedure
specification and supporting weld procedure qualification records to determine if the
weld procedures were qualified in accordance with the requirements of Construction
Code and the ASME Code Section IX.
ASME Section XI repair/replacement welding of reactor coolant system, ASME
Class 1, Valve 2RC-8-41 in N2 to Loop B steam generator reactor coolant
pressure boundary isolation, WO 304396.
b.
Findings
No findings of significance were identified.
9
Enclosure
.2
Reactor Pressure Vessel Upper Head Penetration Inspection Activities
a.
Inspection Scope
For the Unit 2 reactor vessel head, a bare metal visual examination was required this
outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).
The inspectors reviewed records of the visual examination conducted on the Unit 2
reactor vessel head at penetrations 12, 21, 25, and 33 to determine if the activities were
conducted in accordance with the requirements of ASME Code Case N-729-1 and
10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors confirmed that:
the required visual examination scope/coverage was achieved and limitations
(if applicable were recorded) in accordance with the licensee procedures;
the licensee criteria for visual examination quality and instructions for resolving
interference and masking issues were adequate; and
if indications of potential through-wall leakage were identified, the licensee
entered the condition into the CAP and implemented appropriate corrective
actions.
The licensee did not perform any welded repairs to vessel head penetrations since the
beginning of the preceding outage for Unit 2. Therefore, no NRC review was completed
for this inspection procedure attribute.
b.
Findings
No findings of significance were identified.
.3
Boric Acid Corrosion Control
a.
Inspection Scope
The inspectors performed an independent walkdown of all portions of accessible
containment systems, which had received a recent licensee boric acid walkdown and
verified whether the licensees boric acid corrosion control visual examinations
emphasized locations where boric acid leaks can cause degradation of safety significant
components.
The inspectors reviewed the following licensee evaluations of RCS components with
boric acid deposits to determine if degraded components were documented in the CAP.
The inspectors also evaluated corrective actions for any degraded RCS components to
determine if they met the component ASME Section XI Code.
Condition Evaluation 1227969, MV-32169 Unit 2 RCS Loop B Cold Leg Residual
Heat Removal Injection Motor Valve Boric Acid Evaluation; and
Condition Evaluation 1195401, 2SI-10-2 Body to Bonnet Gasket Leak Corrosion
Evaluation.
The inspectors reviewed the following corrective actions related to evidence of boric acid
leakage to determine if they were consistent with the requirements of the ASME Code
Section XI and 10 CFR Part 50, Appendix B, Criterion XVI.
10
Enclosure
21 Boric Acid Transfer Pump Shut Down Due to Seal Leakage; WO 386738; and
Boric Acid on 21/22 Residual Heat Removal Heat Exchanger Outlet Flow Element
b.
Findings
No findings of significance were identified.
.4
Steam Generator Tube Inspection Activities
a.
Inspection Scope
The NRC inspectors observed acquisition of eddy current (ET) data, interviewed ET data
analysts, and reviewed documentation related to the steam generator (SG) ISI program
to determine if:
in-situ SG tube pressure testing screening criteria used were consistent with those
identified in the Electric Power Research Institute (EPRI) TR-107620, Steam
Generator In-Situ Pressure Test Guidelines, and that these criteria were properly
applied to screen degraded SG tubes for in-situ pressure testing;
in-situ pressure test records demonstrated pressure and hold times consistent
with EPRI TR-107620;
in-situ pressure test results were properly applied to SG tube integrity
performance criteria identified in EPRI TR-107621;
the numbers and sizes of SG tube flaws/degradation identified was bound by the
licensees previous outage Operational Assessment predictions;
the SG tube ET examination scope and expansion criteria were sufficient to meet
the TSs, and EPRI 1003138, Pressurized Water Reactor Steam Generator
Examination Guidelines, Revision 6;
the SG tube ET examination scope included potential areas of tube degradation
identified in prior outage SG tube inspections and/or as identified in NRC generic
industry operating experience applicable to these SG tubes;
the licensee identified new tube degradation mechanisms and implemented
adequate extent of condition inspection scope and repairs for the new tube
degradation mechanism;
the licensee implemented repair methods which were consistent with the repair
processes allowed in the plant TS requirements and to determine if qualified
depth sizing methods were applied to degraded tubes accepted for continued
service;
the licensee implemented an inappropriate plug on detection tube repair
threshold (e.g., no attempt at sizing of flaws to confirm tube integrity);
the primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons
per day or the detection threshold during the previous operating cycle;
the ET probes and equipment configurations used to acquire data from the SG
tubes were qualified to detect the known/expected types of SG tube degradation
in accordance with Appendix H, Performance Demonstration for Eddy Current
Examination, of EPRI 1003138, Revision 6; and
the licensee performed secondary side SG inspections for location and removal of
foreign materials.
11
Enclosure
b.
Findings
No findings of significance were identified.
.5
Identification and Resolution of Problems
a.
Inspection Scope
The inspectors performed a review of ISI/SG related problems entered into the
licensees CAP and conducted interviews with licensee staff to determine if:
the licensee had established an appropriate threshold for identifying ISI/SG
related problems;
the licensee had performed a root cause (if applicable) and taken appropriate
corrective actions; and
the licensee had evaluated operating experience and industry generic issues
related to ISI and pressure boundary integrity.
The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50,
Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action
documents reviewed by the inspectors are listed in the Attachment to this report.
b.
Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program (71111.11)
.1
Resident Inspector Quarterly Review (71111.11Q)
a.
Inspection Scope
On April 6, 2010, the inspectors observed a crew of licensed operators in the simulator
during licensed operator training to verify that operator performance was adequate,
evaluators were identifying and documenting crew performance problems, and training
was being conducted in accordance with licensee procedures. The inspectors evaluated
the following areas:
licensed operator performance;
crews clarity and formality of communications;
ability to take timely actions in the conservative direction;
prioritization, interpretation, and verification of annunciator alarms;
correct use and implementation of abnormal and emergency procedures;
control board manipulations;
oversight and direction from supervisors; and
ability to identify and implement appropriate TS actions.
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.
12
Enclosure
This inspection constituted one quarterly licensed operator requalification program
sample as defined in IP 71111.11.
b.
Findings
No findings of significance 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:
Steam Exclusion System; and
External Circulating Water System.
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/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 two quarterly maintenance effectiveness samples as defined
in IP 71111.12-05.
b.
Findings
No findings of significance were identified.
13
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:
emergent work on multiple diesel generators and the potential impact on spent
fuel pool cooling functionality;
delays in returning the blue channel of over power delta temperature to service
following an unexpected channel failure;
emergent work on the Unit 1 AFW system due to an unexpected regulating valve
failure;
emergent work on the Unit 2 residual heat removal system due to a surveillance
testing failure;
unplanned Orange Shutdown Safety Assessment due to the RCS not being intact
when expected; and
emergent work associated with the breaker for the D5 and D6 fuel oil transfer
pumps.
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.
These maintenance risk assessments and emergent work control activities constituted
six samples as defined in IP 71111.13-05.
b.
Findings
No findings of significance were identified.
1R15 Operability Evaluations (71111.15)
.1
Operability Evaluations
a.
Inspection Scope
The inspectors reviewed the following issues:
CAP 1207232; Load Sequencer Alarm Sensing Capabilities with Laptop;
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Enclosure
CAP 1226049; Low Wall Thickness Found on Line 24-CL-13;
CAP 1229117; Pressurizer Power-Operated Relief Valve Isolation Valve Dual
Indication;
CAP 1231470; Cooling Water System Piping Below Minimum Wall in Two
Locations;
CAP 1233935; Potential Common-mode Failure of Unit 2 Fuel Oil Transfer
Pumps; and
CAP 1230668; Unit 1 Safeguard Bus Source Breakers.
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.
This operability inspection constituted six samples as defined in IP 71111.15-05.
b.
Findings
No findings of significance were identified.
1R18 Plant Modifications (71111.18)
.1
Temporary Plant Modifications
a.
Inspection Scope
The inspectors reviewed the following temporary modification:
Temporary Air Compressor for Service Air System (EC 12617)
The inspectors compared the temporary configuration change and associated
10 CFR 50.59 screening and evaluation information against the design basis, the USAR,
and the TS, as applicable, to verify that the modification did not affect the operability or
availability of the affected system(s). The inspectors also compared the licensees
information to operating experience information to ensure that lessons learned from
other utilities had been incorporated into the licensees decision to implement the
temporary modification. The inspectors, as applicable, performed field verifications to
ensure that the modification was installed as directed; the modification operated as
expected; modification testing adequately demonstrated continued system operability,
availability, and reliability; and that operation of the modification did not impact the
operability of any interfacing systems. Lastly, the inspectors discussed the temporary
15
Enclosure
modification with operations, engineering, and training personnel to ensure that the
individuals were aware of how extended operation with the temporary modification in
place could impact overall plant performance. Documents reviewed in the course of this
inspection are listed in the Attachment to this report.
This inspection constituted one temporary modification sample as defined in
b.
Findings
No findings of significance were identified.
.2
Permanent Plant Modifications
a.
Inspection Scope
The following engineering design package was reviewed and selected aspects were
discussed with engineering personnel:
Generic Letter (GL) 2008-01, Vent Valve Modification for Emergency Core
Cooling System (ECCS) Piping in Unit 2.
This document and related documentation were reviewed for adequacy of the
associated 10 CFR Part 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. The modification was completed in response to
GL 2008-01, Managing Gas Accumulation in Emergency Core Cooling, Decay Heat
Removal, and Containment Spray Systems. This modification will help prevent the
accumulation of gas voids in the Safety Injection, Residual Heat Removal, and
Containment Spray Systems. Documents reviewed in the course of this inspection are
listed in the Attachment to this report.
This inspection constituted one permanent plant modification samples as defined in
b.
Findings
No findings of significance were identified.
16
Enclosure
.3
Permanent Plant Modifications Associated with Temporary Instruction 2515/177,
Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and
Containment Spray Systems
a.
Inspection Scope
As discussed in Section 1R18.2 above, the following engineering design package
associated with the scope of GL 2008-01, Managing Gas Accumulation in Emergency
Core Cooling, Decay Heat Removal, and Containment Spray Systems, was reviewed
and selected aspects were discussed with engineering personnel:
EC 13483; GL 2008-01 Vent Valve Modification for ECCS Piping in Unit 2.
The inspectors verified that the licensing basis verification documents were updated or
were in the process of being updated to reflect the modifications associated with the
licensees resolution of GL 2008-01 (Temporary Instruction (TI) 2515/177,
Section 04.01). The verified documents included TS, TS Bases, USAR, and licensee
controlled documents and bases, such as the Technical Requirements Manual.
In addition, the inspectors verified that the drawings were up-to-date with respect to
recent hardware changes and that any discrepancies between as-built configurations
and the drawings were documented and entered into the corrective action program for
resolution (TI 2515/177, Section 04.02.a.6).
Similarly, the inspectors verified that Piping and Instrumentation Diagrams accurately
described the subject systems, that they were up-to-date with respect to recent
hardware changes, and any discrepancies between as-built configurations, the isometric
drawings, and the Piping and Instrumentation Diagrams were documented and entered
into the CAP for resolution (TI 2515/177, Section 04.02.b).
Documents reviewed are listed in the Attachment to this report.
This inspection effort counts towards the completion of TI 2515/177, which will be closed
in a later Inspection Report.
b.
Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing (71111.19)
.1
Post-Maintenance Testing
a.
Inspection Scope
The inspectors reviewed the following post-maintenance activities to verify that
procedures and test activities were adequate to ensure system operability and
functional capability:
Various procedures following D5 diesel generator refueling outage maintenance;
Surveillance Procedure (SP) 2073A; Monthly Train A Shield Building Ventilation
System Test following maintenance on a shield building ventilation damper;
17
Enclosure
D6 break-in run after maintenance;
SP 2102; 22 Turbine-Driven AFW Pump Monthly Test;
SP 2331; 21 Motor-Driven AFW Pump Auto Start and Functional Testing Each
Refueling Shutdown; and
Various vent valve locations; GL 2008-01, Vent Valve Modification for ECCS
Piping in Unit 2.
These activities were selected based upon the structure, system, or component's ability
to impact risk. The inspectors evaluated these activities for the following (as applicable):
the effect of testing on the plant had been adequately addressed; testing was adequate
for the maintenance performed; acceptance criteria were clear and demonstrated
operational readiness; test instrumentation was appropriate; tests were performed as
written in accordance with properly reviewed and approved procedures; equipment was
returned to its operational status following testing (temporary modifications or jumpers
required for test performance were properly removed after test completion); and test
documentation was properly evaluated. The inspectors evaluated the activities against
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 post-maintenance tests to
determine whether the licensee was identifying problems and entering them in the CAP
and that the problems were being corrected commensurate with their importance to
safety. Documents reviewed are listed in the Attachment to this report.
This inspection constituted six post-maintenance testing samples as defined in
b.
Findings
No findings of significance were identified.
1R20 Outage Activities (71111.20)
.1
Refueling Outage Activities
a.
Inspection Scope
The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the
Unit 2 refueling outage (RFO), conducted April 16 through May 22, 2010, to confirm that
the licensee had appropriately considered risk, industry experience, and previous
site-specific problems in developing and implementing a plan that assured maintenance
of defense-in-depth. During the RFO, the inspectors observed portions of the shutdown
and cooldown processes and monitored licensee controls over the outage activities
listed below. 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;
18
Enclosure
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 secondary containment as required by TS;
Refueling activities;
Startup and ascension to full power operation;
Tracking of startup prerequisites and a walkdown of the primary containment to
verify that debris had not been left which could block ECCS suction strainers; and
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
No findings of significance were identified.
.2
Refueling Cavity Leakage
a.
Inspection Scope
Over the past 7 months both units have undergone refueling outages. During each
outage, the inspectors have monitored licensee actions to resolve refueling cavity
leakage. As part of outage activities, the licensee implemented measures to resolve the
leakage through weld repairs to susceptible leakage areas in the lower portion of the
cavity. Primary repair areas included the internals stands and the change fixture
supports. As a result of these repairs, the licensee estimated the leakage had been
reduced by approximately 95 percent. Following the 2R26 weld repairs and cavity
flood-up, the licensee noted leakage into Sump C. Additionally, the licensee identified
an approximate 0.8 gallon per hour (gph) leak into Sump B during the few days following
the cavity flood-up. This leak diminished to 0.02 gph four days after the cavity flood-up.
The licensee intended to continue monitoring outage related cavity leakage with specific
focus on the sealing of sand plug covers. As part of the first refueling outage following
refueling cavity leak repairs for each unit, the licensee planned to evaluate the condition
of the containment pressure vessel, concrete, and rebar through a small excavation in
Sump C. Additionally, concrete degradation will be assessed by obtaining a concrete
sample from a location known to have been wetted by borated water leakage from the
refueling cavity. These upcoming evaluations were part of the licensees license
renewal commitments. Previous evaluations have not revealed any degradation of the
containment pressure vessel, concrete, or rebar due to refueling cavity leakage.
19
Enclosure
This activity was conducted as part of the normal baseline activities discussed in
Section 1R20.1 of this report and therefore, was not considered an inspection sample.
b.
Findings
No findings of significance were identified.
.3
Other Outage Activities
a.
Inspection Scope
The inspectors evaluated outage activities for an unplanned outage that began following
an automatic reactor trip on May 25, 2010, and continued through May 26, 2010. The
inspectors reviewed activities to ensure that the licensee considered risk in implementing
the outage schedule.
The inspectors observed or reviewed outage equipment configuration and risk
management, electrical lineups, selected clearances, control and monitoring of decay
heat removal, startup and heatup activities, and identification and resolution of problems
associated with the outage.
This inspection constituted one other outage sample as defined in IP 71111.20.
b.
Findings
No findings of significance were identified.
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:
SP 2314; 22 Battery Refueling Outage Discharge Test (routine);
SP 1090B; 12 Containment Spray Pump Quarterly Test (inservice testing);
SP 1094; Bus 15 Load Sequencer Test (routine);
SP 2277; General Examination of the Containment Liner for ASME
Subsection IWE (routine);
SP 2431; Main Steam Safety Valve Test (Power Operation) (routine);
SP 2083; Unit 2 Integrated SI Test With a Simulated Loss of Offsite Power
(containment isolation valve);
SP 2070; Reactor Coolant System Integrity Test (reactor coolant system).
20
Enclosure
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, demonstrate 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 were used;
test data and results were accurate, complete, within limits, and valid;
test equipment was removed after testing;
where applicable for inservice testing activities, testing was performed in
accordance with the applicable version of ASME Section XI and reference values
were consistent with the system design basis;
were applicable, test results not meeting acceptance criteria were addressed with
an adequate operability evaluation or the system or component was declared
were applicable for safety-related instrument control surveillance tests, reference
setting data were accurately incorporated in the test procedure;
were 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 inservice
testing sample, one RCS leak detection inspection sample, and one containment
isolation valve sample as defined in IP 71111.22, Sections -02 and -05.
b.
Findings
No findings of significance were identified.
21
Enclosure
1EP6 Drill Evaluation (71114.06)
.1
Training Observation
a.
Inspection Scope
The inspector observed a simulator training evolution for licensed operators on
April 6, 2010, which required emergency plan implementation by a licensee operations
crew. This evolution was planned to be evaluated and included in performance indicator
data regarding drill and exercise performance. The inspectors observed event
classification and notification activities performed by the crew. The inspectors also
attended the post-evolution critique for the scenario. The focus of the inspectors
activities was to note any weaknesses and deficiencies in the crews performance and
ensure that the licensee evaluators noted the same issues and entered them into the
corrective action program. As part of the inspection, the inspectors reviewed the
scenario package and other documents listed in the Attachment to this report.
This inspection of the licensees training evolution with emergency preparedness drill
aspects constituted one sample as defined in IP 71114.06-05.
b.
Findings
No findings of significance were identified.
2.
RADIATION SAFETY
Cornerstones: Public and Occupational Radiation Safety
2RS8 Radioactive Solid Waste, Processing and Radioactive Material Handling, Storage, and
Transportation (71124.08)
This inspection constituted one radioactive solid waste processing and radioactive
material handling, storage, and transportation sample as defined in IP 71124.08-05.
.1
Inspection Planning (02.01)
a.
Inspection Scope
The inspectors reviewed the solid radioactive waste system description in the USAR, the
Process Control Program (PCP), and the recent radiological effluent release report for
information on the types, amounts, and processing of radioactive waste disposed.
The inspectors reviewed the scope of any quality assurance audit in this area since the
last inspection to gain insights into the licensees performance and inform the smart
sampling inspection planning.
b.
Findings
No findings of significance were identified.
22
Enclosure
.2
Radioactive Material Storage (02.02)
a.
Inspection Scope
The inspectors selected three areas where containers of radioactive waste are stored,
and evaluated whether the containers were labeled in accordance with 10 CFR 20.1904,
Labeling Containers, or controlled in accordance with 10 CFR 20.1905,
Exemptions to Labeling Requirements, as appropriate.
The inspectors assessed whether the radioactive materials storage areas were
controlled and posted in accordance with the requirements of 10 CFR Part 20,
Standards for Protection Against Radiation. For materials stored or used in the
controlled or unrestricted areas, the inspectors evaluated whether they were secured
against unauthorized removal and controlled in accordance with 10 CFR 20.1801,
Security of Stored Material, and 10 CFR 20.1802, Control of Material Not in Storage,
as appropriate.
The inspectors evaluated whether the licensee established a process for monitoring the
impact of long term storage (e.g., buildup of any gases produced by waste
decomposition, chemical reactions, container deformation, loss of container integrity, or
re-release of free-flowing water) that was sufficient to identify potential unmonitored,
unplanned releases or nonconformance with waste disposal requirements.
The inspectors selected six containers of stored radioactive materials, and assessed
them for signs of swelling, leakage, and deformation.
b.
Findings
No findings of significance were identified.
.3
Radioactive Waste System Walkdown (02.03)
a.
Inspection Scope
The inspectors walked down accessible portions of selected radioactive waste
processing systems to assess whether the current system configuration and operation
agreed with the descriptions in the USAR, offsite dose calculation manual, and PCP.
The inspectors reviewed administrative and/or physical controls (i.e., drainage and
isolation of the system from other systems) to assess whether the equipment which was
not-in-service or abandoned in place would not contribute to an unmonitored release
path and/or affect operating systems or be a source of unnecessary personnel exposure.
The inspectors assessed whether the licensee reviewed the safety significance of
systems and equipment abandoned in place in accordance with 10 CFR Part 50.59,
Changes, Tests, and Experiments.
The inspectors reviewed the adequacy of changes made to the radioactive waste
processing systems since the last inspection. The inspectors evaluated whether
changes from what was described in the USAR were reviewed and documented in
accordance with 10 CFR Part 50.59, as appropriate and to assess the impact on
radiation doses to members of the public.
23
Enclosure
The inspectors assessed whether the waste stream mixing, sampling procedures, and
methodology for waste concentration averaging were consistent with the PCP, and
provided representative samples of the waste product for the purposes of waste
classification as described in 10 CFR Part 61.55, Waste Classification, for selected
waste processes.
The inspectors evaluated whether the tank recirculation procedures provided sufficient
mixing for systems that provide tank recirculation.
The inspectors assessed whether the licensees PCP correctly described the current
methods and procedures for dewatering and waste stabilization (e.g., removal of
freestanding liquid).
b.
Findings
No findings of significance were identified.
.4
Waste Characterization and Classification (02.04)
a.
Inspection Scope
The inspectors selected the following radioactive waste streams for review:
Dry Active Waste (DAW);
High Level Resin; and
Low Level Filters.
For the waste streams listed above, the inspectors assessed whether the licensees
radiochemical sample analysis results (i.e., 10 CFR Part 61 analysis) were sufficient
to support radioactive waste characterization as required by 10 CFR Part 61,
Licensing Requirements for Land Disposal of Radioactive Waste. The inspectors
evaluated whether the licensees use of scaling factors and calculations to account
for difficult-to-measure radionuclides was technically sound and based on current
10 CFR Part 61 analyses for the selected radioactive waste streams.
The inspectors evaluated whether changes to plant operational parameters were taken
into account to: (1) maintain the validity of the waste stream composition data between
the annual or biennial sample analysis update; and (2) assure that waste shipments
continued to meet the requirements of 10 CFR Part 61 for the waste streams selected
above.
The inspectors evaluated whether the licensee had established and maintained an
adequate Quality Assurance program to ensure compliance with the waste classification
and characterization requirements of 10 CFR 61.55 and 10 CFR 61.56, Waste
Characteristics.
b.
Findings
No findings of significance were identified.
24
Enclosure
.5
Shipment Preparation (02.05)
a.
Inspection Scope
The inspectors observed shipment packaging, surveying, labeling, marking, placarding,
vehicle checks, emergency instructions, disposal manifest, shipping papers provided to
the driver, and licensee verification of shipment readiness. The inspectors assessed
whether the requirements of applicable transport cask certificate of compliance had been
met. The inspectors evaluated whether the receiving licensee was authorized to receive
the shipment packages. The inspectors evaluated whether the licensees procedures for
cask loading and closure procedures were consistent with the vendors current approved
procedures.
The inspectors observed radiation workers during the conduct of radioactive waste
processing and radioactive material shipment preparation and receipt activities. The
inspectors assessed whether the shippers were knowledgeable of the shipping
regulations and whether shipping personnel demonstrated adequate skills to accomplish
the package preparation requirements for public transport with respect to:
the licensees response to NRC Bulletin 79-19, Packaging of Low-Level
Radioactive Waste for Transport and Burial, dated August 10, 1979; and
Title 49 CFR Part 172, Hazardous Materials Table, Special Provisions,
Hazardous Materials Communication, Emergency Response Information, Training
Requirements, and Security Plans, Subpart H, Training.
Additionally, due to limited opportunities for direct observation, the inspectors reviewed
the technical instructions presented to workers during routine training. The inspectors
assessed whether the licensees training program provided training to personnel
responsible for the conduct of radioactive waste processing and radioactive material
shipment preparation activities.
b.
Findings
No findings of significance were identified.
.6
Shipping Records (02.06)
a.
Inspection Scope
The inspectors evaluated whether the shipping documents indicated the proper shipper
name; emergency response information and a 24-hour contact telephone number;
accurate curie content and volume of material; and appropriate waste classification,
transport index, and UN number for the following radioactive shipments:
Shipment Number 09-024; Hn-215 Cask - Dewatered Resin; November 2009;
Shipment Number 09-025; Hn-215 Cask - Dewatered Resin; November 2009;
Shipment Number 09-030; DAW Sealands; December 2009;
Shipment Number 10-005; DAW Sealands; January 2010; and
Shipment Number 10-008; DAW Sealands; February 2010.
25
Enclosure
Additionally, the inspectors assessed whether the shipment placarding was consistent
with the information in the shipping documentation.
b.
Findings
No findings of significance were identified.
.7
Identification and Resolution of Problems (02.07)
a.
Inspection Scope
The inspectors assessed whether problems associated with radioactive waste
processing, handling, storage, and transportation, were being identified by the licensee
at an appropriate threshold, were properly characterized, and were properly addressed
for resolution in the licensees CAP. Additionally, the inspectors evaluated whether the
corrective actions were appropriate for a selected sample of problems documented by
the licensee that involve radioactive waste processing, handling, storage, and
transportation.
The inspectors reviewed results of selected audits performed since the last inspection of
this program and evaluated the adequacy of the licensees corrective actions for issues
identified during those audits.
b.
Findings
No findings of significance were identified.
4.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
.1
Reactor Coolant System Leakage
a.
Inspection Scope
The inspectors sampled licensee submittals for the RCS leakage performance indicator
(PI) for Units 1 and 2 for the period of the second quarter 2009 through the first quarter
of 2010. To determine the accuracy of the PI data reported during those periods, PI
guidance contained in Nuclear Energy Institute Document 99-02, Regulatory
Assessment Performance Indicator Guideline, Revision 6, was used. The inspectors
reviewed the licensees operator logs, RCS leakage tracking data, CAPs, event reports
and NRC Integrated Inspection Reports for the period listed above to validate the
accuracy of the submittals. The inspectors also reviewed the licensees corrective action
system to determine if any problems had been identified with the PI data collected or
transmitted for this indicator. Documents reviewed are listed in the Attachment to this
report.
This inspection constituted two RCS leakage samples as defined in IP 71151-05.
b.
Findings
No findings of significance were identified.
26
Enclosure
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: the complete and accurate identification of the problem; that timeliness was
commensurate with the safety significance; that 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 attached List of Documents Reviewed.
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 of significance 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 licensees 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 of significance were identified.
27
Enclosure
.3
Semiannual Trend Review
a.
Inspection Scope
The inspectors performed a review of the licensees CAP and associated documents to
identify trends that could indicate the existence of a more significant safety issue. The
inspectors review was focused on repetitive equipment issues, but also considered the
results of daily inspector CAP item screening discussed in Section 4OA2.2 above,
licensee trending efforts, and licensee human performance results. The inspectors
review nominally considered the period of December 2009 through June 2010 although
some examples expanded beyond those dates where the scope of the trend warranted.
The review also included issues documented outside the normal CAP in system health
reports, quality assurance audit/surveillance reports, self assessment reports, and
Maintenance Rule assessments. The inspectors compared and contrasted their results
with the results contained in the licensees CAP trending reports. Corrective actions
associated with a sample of the issues identified in the licensees trending reports were
reviewed for adequacy.
This review constituted a single semi-annual trend inspection sample as defined in
b.
Findings
No findings of significance were identified.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion (71153)
.1
Retraction of Event Notification 45855: Limiting Condition for Operation 3.0.3 Entry and
Loss of Safety Function Due to Loss of Turbine Building High Energy Line Break
Compensatory Measure
a.
Inspection Scope
The inspectors reviewed the event notification, the notification retraction, a supplemental
engineering change, and discussed the event notification with operations personnel to
determine whether the licensees retraction was performed in accordance with NRC
requirements. 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.
b.
Findings
No findings of significance were identified.
28
Enclosure
.2
(Closed) Licensee Event Report 05000282/2009-006-00: Unanalyzed Condition Due to
Potential Safety System Susceptibility to Turbine Building Flooding Due to a Postulated
a.
Inspection Scope
This Licensee Event Report (LER) discussed the potential for turbine building flooding to
occur following a high energy line break. The licensee postulated that the subsequent
turbine building flooding may be sufficient to impact the safety function of multiple
safety-related systems. The details of this LER, and the inspectors review of this issue,
were documented in NRC IR 05000282/2010010; 05000306/2010010 as a potentially
greater than Green finding. The documents reviewed are listed in IR 2010010.
This event follow-up review constituted one sample as defined in IP 71153-05.
b.
Findings
One potentially greater than Green finding was identified. See IR 05000282/2010010;
05000306/2010010 for additional details. This LER is closed.
.3
(Closed) Licensee Event Report Supplement 05000282/2009-006-01:
Unanalyzed Condition Due to Potential Safety System Susceptibility to Turbine Building
Flooding Due to a Postulated High Energy Line Break
a.
Inspection Scope
This LER provided supplemental information regarding the licensees review of the
potential for turbine building flooding to occur following a high energy line break. The
inspectors discussed the supplemental information with engineering and operations
personnel as part of an inspection documented in NRC IR 05000282/2010010;
05000306/2010010. The documents reviewed are listed in IR 2010010.
This event follow-up review constituted one sample as defined in IP 71153-05.
b.
Findings
One potentially greater than Green finding was identified.
See NRC IR 05000282/2010010 for additional details. This LER is closed.
.4
(Closed) Licensee Event Report 05000306/2010-001-00: Unit 2 Turbine Trip During
Reactor Shutdown Resulting in a Reactor Scram
a.
Inspection Scope
This LER provided information regarding the reactor trip discussed in Section 4OA3.7 of
this inspection report. No new information was provided in this LER.
This event follow-up review constituted one sample as defined in IP 71153-05.
b.
Findings
See Section 4OA3.7 of this report for finding details. This LER is closed.
29
Enclosure
.5
(Closed) Licensee Event Report 05000282/2010-002-00: Postulated Flooding of Unit 1
Fuel Oil Transfer Pump Motor Starters Could Have Resulted in Reduced Fuel Oil
Inventory
a.
Inspection Scope
This LER documented a condition where the motor starters for the diesel-driven cooling
water fuel oil transfer pumps could have been rendered inoperable by an internal flood in
the plant screenhouse. The inspectors reviewed the information provided in the LER
and compared this information with the inspection item documented in Section 1R06.1 of
NRC IR 05000282/2010002; 05000306/2010002 to ensure that no new information was
provided.
This event follow-up review constituted one sample as defined in IP 71153-05.
b.
Findings
An inspector-identified Green NCV was identified in Section 1R06.1 of
NRC IR 05000282/2010002; 05000306/2010002. This LER is closed.
.6
Failure of D6 Direct Current Breaker 8/WCS1/D6
a.
Inspection Scope
The inspectors observed the licensees maintenance plan and troubleshooting efforts
associated with finding direct current breaker 8/WCS1/D6 in a tripped condition. The
inspectors efforts included discussing the issue with operations, engineering, and
maintenance personnel, reviewing drawings and design basis information, and reviewing
the licensees repair plan to ensure that the maintenance activity was performed in
accordance with regulatory requirements.
This event follow-up review constituted one sample as defined in IP 71153-05.
b.
Findings
No findings of significance were identified.
.7
Unit 2 Reactor Trip on April 16, 2010
a.
Inspection Scope
The inspectors observed operations personnel in the control room, reviewed procedures,
strip chart records, sequence of event logs, narrative logs and emergency response
computer system data, and held discussions with licensee personnel to determine the
cause of a Unit 2 automatic reactor trip. The inspectors also used this information to
determine whether operations personnel had responded appropriately following the
This event follow-up review constituted one sample as defined in IP 71153-05.
30
Enclosure
b.
Findings
Introduction: A self-revealed finding of very low safety significance was identified
following a Unit 2 automatic reactor trip on April 16, 2010. Specifically, the licensee
failed to appropriately establish and implement actions to address previous events in
2001 and 2003. As a result, several of the actions to address these events were not
completed. This resulted in a sequence of events that led to a turbine trip and a reactor
trip.
Description: At 7:00 p.m. on April 16, 2010, operations personnel began lowering Unit 2
reactor power in preparation for beginning Refueling Outage 2R26. At 10:34 p.m., the
Unit 2 reactor automatically tripped from 13 percent power. The inspectors were in the
control room when the trip occurred. The inspectors observed operations personnel
respond to the reactor trip condition. No issues were identified.
The licensee initiated CAP 1227647 to document the reactor trip. The licensee also
completed a root cause evaluation of this event. The licensee determined that the Unit 2
reactor trip occurred because the slope of the sealing steam line to the moisture
separator reheater (MSR) safety valves on the south side of the Unit 2 turbine allowed a
buildup of condensation that eventually blocked the flow of sealing steam. The lack of
sealing steam to the MSR safety valves as the MSR shell became sub-atmospheric,
allowed the MSR safety valves to partially open. The partially open safety valves
caused a rapid reduction in condenser vacuum. Once the difference in vacuum between
the condensers exceeded a specific level an automatic trip signal was sent to the turbine
and the reactor.
The licensee also identified the following contributing causes:
inadequate procedural guidance for aligning gland sealing steam and air ejectors
to the heating steam system prior to a large power reduction;
inadequate procedural guidance regarding the maintenance of gland sealing
steam pressure when the system is aligned to the heating steam system;
inadequate alarm response guidance for addressing high air ejector flow rates;
degraded gland seal segments on low pressure turbine 2; and
inadequate corrective action for previous similar events.
The inspectors reviewed the licensees corrective action system and found that a similar
event had occurred in 2001 and 2003. Specifically on May 9, 2001, Unit 2 experienced
a manual turbine trip and reactor trip after experiencing a high differential pressure
condition between the two condensers. The licensee determined that this event likely
occurred due to air leakage through the MSR relief valves to the condensers due to
inadequate sealing steam pressure. Unit 2 also experienced an automatic turbine trip on
September 12, 2003, due to air in-leakage caused by steam inlet pressure to the low
pressure turbine becoming sub-atmospheric. Corrective actions for the 2001 event
included identifying operational requirements or modifications needed to provide
adequate sealing steam pressure to the MSRs and changing operating procedures to
ensure that adequate guidance was provided to prevent high air leakage flows from
flooding the air ejectors. No evidence could be found to show that these actions were
taken.
31
Enclosure
The licensee conducted an equipment investigation of the 2003 event and
recommended that the slope of the sealing steam lines to the MSR safety valve headers
be verified. Another recommendation was made regarding the need to install more
appropriate steam traps on the sealing steam lines. The inspectors found that the
licensee had not considered these recommendations to be corrective actions because
this event had not caused a reactor trip. This was contrary to the requirements of
FP-PA-ARP-01, Action Request Process, Revision 1 (the revision in place in 2003)
which required that the 2003 event be classified as a significance level B condition.
This procedure also required that significance level B conditions have actions
established and implemented to correct the condition. Lastly, the inspectors found
documentation from 2004 showing that the recommendations from the 2003 event
became focused on the steam trap installation. As a result, actions to verify the slope of
the sealing steam lines were not completed.
Analysis: The inspectors determined that the failure to appropriately establish and
implement actions to address the previous turbine trip and/or reactor trip events in
2001 and 2003 was a performance deficiency that required a Significance
Determination Process (SDP) evaluation. The inspectors determined that this finding
impacted the Initiating Events Cornerstone. The inspectors determined that this finding
was more than minor because it was associated with the design control, configuration
control, and procedure quality attributes of the Initiating Events Cornerstone and
impacted the cornerstone objective of limiting the likelihood of those events that upset
plant stability and challenge critical safety functions during shutdown as well as power
operations. This finding was determined to be of very low safety significance in
accordance with IMC 0612 Significance Determination Process Attachment 4 Table 4a,
because it did not contribute to a reactor trip with mitigating equipment not available.
This finding was not cross-cutting because decisions regarding the 2001 corrective
actions and the 2003 recommendations were made more than two years ago. (Finding
(FIN) 05000306/2010003-01: Failure to Address Design Vulnerability Results in Reactor
Trip).
Enforcement: No violations of NRC requirements were identified since the sealing
steam system and the MSR safety valves were non-safety related. Corrective actions
for this event included revising the appropriate gland sealing steam and alarm response
procedures, repairing the gland seal segments on the low pressure turbine, and
correcting the slope of the gland seal piping.
.8
Failure to Implement Procedure Use and Adherence Requirements Results in Partial
Loss of Containment Cooling
a.
Inspection Scope
The inspectors reviewed operator logs and corrective action documentation to determine
the sequence of events that led to a partial loss of Unit 2 containment cooling on
April 9, 2010.
This event follow-up review constituted one sample as defined in IP 71153-05.
b.
Findings
Introduction: A self-revealed finding of very low safety significance and an NCV of
TS 5.4.1 was identified on April 9, 2010, due to operations personnel failing to implement
32
Enclosure
requirements designated in Procedure FP-G-DOC-03, Procedure Use and Adherence.
This resulted in an operator failing to use Procedure C37.13, Containment and Auxiliary
Building Cooling System, during system alignments for the 22/24 fan coil unit valve
stroke test and a partial loss of Unit 2 containment cooling.
Description: On April 9, 2010, operations personnel were scheduled to perform
SP 2245B, 22/24 Fan Coil Unit Valve Stroke Test. Prior to performing this test,
operations personnel needed to perform valve alignments using Procedure C37.13.
These valve alignments included the opening of two manual valves to ensure that
cooling water to the 22 and 24 fan coil units was not lost during the performance of
SP 2245B. As operations personnel began performing SP 2245B, cooling water to the
22 and 24 fan coil units was unexpectedly lost. This resulted in a loss of one half of the
cooling capacity for the Unit 2 containment building. Control room personnel quickly
restored the fan coil unit valve alignment, which allowed the restoration of cooling to the
Unit 2 containment.
Step 5.1.1 of Procedure FP-G-DOC-03 required that personnel use working copies of
continuous or reference use procedures when performing activities affecting quality.
Procedure C37.13 directed activities affecting quality and was designated as a reference
use procedure. However, the operator performing the valve alignment reviewed but did
not print a copy of Procedure C37.13 for use at the work location. Additionally, the
licensees evaluation concluded the operator had performed the system alignment a
number of times and over-confidence was involved in the operators decision to perform
the task without the procedure. Due to the lapse in procedure usage, the two manual
valves required to be open were overlooked as part of the alignment process.
Analysis: The inspectors concluded that the failure to follow Step 5.1.1 of
Procedure FP-G-DOC-03 and use Procedure C37.13 for the system alignment was
a performance deficiency that required an evaluation using the SDP. The inspectors
determined that this finding was more than minor because the finding associated with
the human performance attribute of the Mitigating Systems Cornerstone and impacted
the cornerstone objective of ensuring the availability, reliability, and capability of systems
that respond to initiating events to prevent undesirable consequences. The inspectors
determined that this finding was of very low safety significance in accordance with
IMC 0612 Significance Determination Process Attachment 4 Table 4a, because it did
not represent a loss of a system safety function and the fan coil units were inoperable for
less than the TS allowed outage time. The inspectors determined that this finding was
cross-cutting in the Human Performance, Work Practices area because licensee
personnel did not ensure human error prevention techniques were used such that work
activities were performed safely (H.4(a)).
Enforcement: Technical Specification 5.4.1 requires that written procedures be
established, implemented, and maintained covering the applicable procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Section 1.d of Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, requires
that written procedures be established, implemented and maintained regarding
procedural adherence.
Procedure FP-G-DOC-03, Procedure Use and Adherence, was the licensees
procedure used to implement the requirements of Regulatory Guide 1.33, Section 1.d
and TS 5.4.1.
33
Enclosure
Step 5.1.1 of Procedure FP-G-DOC-03 stated that all personnel shall perform activities
affecting quality using working copies of continuous or reference use procedures.
Procedure C37.13, Containment and Auxiliary Building Cooling System, directed
activities affecting quality and was designated as a reference use procedure.
Contrary to the above, on April 9, 2010, operations personnel failed to implement the
procedure use and adherence requirements designated in Procedure FP-G-DOC-03.
Specifically, the operators failed to use a working copy of reference use procedure
C37.13, an activity affecting quality, while performing a system alignment. This resulted
in the failure to manipulate two valves and a partial loss of Unit 2 containment cooling.
However, because this violation was of very low safety significance and was entered into
your corrective action program as CAP 1226738, it was treated as an NCV consistent
with Section VI.A.1 of the Enforcement Policy (NCV 05000306/2010003-02; Lack of
Operator Procedure Use During System Alignment). Corrective actions for this issue
included the completion of a human performance event investigation, briefing plant
personnel on the details of this event, and reinforcing the expectation to use the human
performance tools.
.9
Unit 2 Automatic Reactor Trip Due to the Loss of Operating Feedwater Pump
a.
Inspection Scope
The inspectors responded to the control room, attended meetings, reviewed the
licensees post-trip report, and monitored the licensees troubleshooting efforts to
determine the cause of a Unit 2 automatic reactor trip from 33 percent power on
May 25, 2010.
This event follow-up review constituted one sample as defined in IP 71153-05.
b.
Findings
Introduction: One unresolved item was identified.
Description: During Unit 2 power ascension activities on May 25, 2010, operations
personnel experienced an automatic reactor trip from 33 percent power. The inspectors
observed the operators response to the event and reviewed the licensees post-trip
report. The inspectors preliminarily determined that the Unit 2 reactor automatic trip was
caused by an unexpected turbine trip. The turbine trip was caused by the unexpected
shut down of the operating feedwater pump. The licensee conducted troubleshooting
activities and determined that the feedwater pump shut down after receiving a low
suction pressure signal. The low suction pressure signal was caused by components
inside a pressure switch becoming disconnected. The licensee subsequently replaced
the pressure switch. The licensee also inspected several other pressure switches to
ensure that the internal components would remain connected during plant operation.
The cause of the internal components becoming disconnected remained under review at
the conclusion of the inspection period. As a result, the inspectors were unable to
determine whether a performance deficiency resulted in the unexpected feedwater pump
shutdown and the reactor trip. This issue was determined to be unresolved pending the
inspectors review of the licensees corrective action evaluation. (Unresolved Item
(URI)05000306/2010003-03; Review Licensees Evaluation to Determine Whether
Performance Deficiency Existed).
34
Enclosure
.10
Introduction of Foreign Material Renders Diesel Generator Inoperable
a.
Inspection Scope
The inspectors reviewed applicable procedures and CAP documents to determine the
sequence of events that resulted in introducing foreign material into the D1 lube oil
sump.
This event follow-up review constituted one sample as defined in IP 71153-05.
b.
Findings
Introduction: A finding of very low safety significance and an NCV of 10 CFR Part 50,
Appendix B, Criterion V was identified by the inspectors on March 15, 2010, due to the
licensees failure to have instructions and procedures appropriate to the circumstance for
performing WO 382152 and SP 1295, D1 Diesel Generator 6 Month Fast Start Test.
The failure to have instructions and procedures appropriate to the circumstance resulted
in rendering the D1 diesel generator inoperable for 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> due to the introduction of
foreign material into the lube oil sump during oil addition activities.
Description: On March 15, 2010, the licensee implemented WO 382152 which directed
the performance of surveillance procedure SP 1295. Step 3.7 of SP 1295 directed
operations personnel to check the engine oil level using the dipstick. If the oil level was
low, the SP directed the operators to add oil as necessary. The operators determined
that approximately 20 gallons of oil needed to be added. After adding about 5 gallons of
oil using a 1 gallon oil safe container, the containers tube and nozzle became
disconnected and fell into the lube oil sump. The introduction of this foreign material (the
tube and nozzle) into the sump rendered the D1 diesel generator inoperable until the
material was retrieved. The licensee initiated CAP 1222649 to document this issue.
The inspectors reviewed the licensees apparent cause investigation report for this
event. The licensee determined that the foreign material was introduced into the D1
lube oil sump because operations personnel failed to consider potential foreign material
impacts when performing routine tasks or when confronted with changes in job
conditions. The licensees apparent cause report also documented that the operators
were sensitive to the foreign material concerns of having the oil fill connection open to
the environment and this was discussed as part of the pre-job brief. However, the
introduction of the oil nozzle into the fill connection was not recognized or discussed at
the pre-job brief.
The inspectors independently reviewed the following documents:
WO 382152; SP 1295 D1 Diesel Generator 6 Month Fast Start;
SP 1295; D1 Diesel Generator 6 Month Fast Start;
FP-G-DOC-03; Procedure Use and Adherence; and
5AWI 8.7.0; Foreign Material Exclusion Program Description.
Based upon this document review, the inspectors were not in full agreement with the
licensees apparent cause. The inspectors determined that Section 6.1 of 5AWI 8.7.0
required that a determination be made regarding which systems or components must be
opened or accessed in connection with a scheduled task as part of the work planning
35
Enclosure
process. The inspectors reviewed WO 382152 and found that it failed to contain a
determination or any other information regarding the need to invoke foreign material
exclusion requirements even though Step 3.7 of SP 1295 could result in opening the
D1 diesel generator lube oil system to add oil. The inspectors also noted that Step 3.7
of SP 1295 directed operations personnel to add oil using a 55 gallon drum of filtered
oil as necessary. Prior to mid-2009, operations personnel added oil by transporting a
55 gallon drum of oil into the diesel generator room. Due to the erection of partial walls
to protect the diesel generators from the impact of an internal flood, 55 gallon drums
were no longer able to be easily transported into the diesel generator rooms. As a
result, the method of performing Step 3.7 of SP 1295 had changed. However, this
change had not been evaluated for potential impact by operations personnel. The
inspectors also questioned whether a procedure change needed to be initiated to
address the change in methodology. Had a procedure change been initiated, the need
for additional foreign material exclusion controls may have been identified.
Analysis: The inspectors determined that failure to provide instructions and procedures
appropriate to the circumstance was a performance deficiency that required an
evaluation using the SDP. The inspectors determined that the finding was more than
minor because it was associated with the procedure quality and human performance
attributes of the Mitigating Systems Cornerstone and impacted the cornerstone objective
of ensuring the availability, reliability and capability of systems that respond to initiating
events to prevent undesirable consequences. The inspectors determined that this
finding was of very low safety significance in accordance with IMC 0612 Significance
Determination Process Attachment 4 Table 4a, because it did not represent a loss of a
system safety function and the diesel generator was inoperable for less than the TS
allowed outage time. This finding was determined to be cross-cutting in the Human
Performance, Work Control area because the licensee failed to appropriately plan work
activities by incorporating job site conditions, which may impact plant structures,
systems or components (H.3(a)).
Enforcement: 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and
Drawings, requires, in part, that activities affecting quality shall be prescribed by, and be
accomplished in accordance with, documented instructions or procedures appropriate to
the circumstance. Contrary to the above, on March 15, 2010, the licensee failed to
accomplish WO 382152 and SP 1295 (activities affecting quality) with instructions and
procedures appropriate to the circumstance. Specifically, both the SP and the WO failed
to contain a determination regarding the need for foreign material exclusion controls
even though steps were taken to open the D1 diesel generator lube oil sump and the
methodology for adding the oil had changed. This resulted in the introduction of foreign
material into the D1 lube oil sump rendering the diesel generator inoperable. Since this
finding was of very low safety significance, and because it was entered into the
corrective action program as CAP 1222649, this violation is being treated as an NCV
consistent with Section VI.A of the Enforcement Policy. (NCV 05000282/2010003-04;
Inadequate Foreign Material Exclusion Controls Associated with Work on Emergency
Diesel Generators). Corrective actions included retrieving the hose and nozzle,
replacing the plastic oil cans with new solid metal cans, and revising the pre-job brief
instructions and Are You Ready checklist to include a question whether foreign
material will be generated through the use of portable equipment or tools.
36
Enclosure
4OA5 Other Activities
.1
(Discussed) NRC Temporary Instruction 2515/177: Managing Gas Accumulation in
Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems (NRC
As documented in Section 1R18 of this report, the inspectors reviewed permanent
modifications made to the above systems to address the reduction or elimination of air in
system piping. This inspection effort counted towards the completion of TI 2515/177,
which will be closed in a later inspection report.
.2
(Closed) Unresolved Item 05000282/2009007-03; 05000306/2009007-03:
Sequential Starting of Fire Pumps
The inspectors reviewed a previously identified issue concerning the starting sequence
for fire pumps. The Prairie Island Nuclear Generating Plant fire pumps were arranged to
start sequentially upon decreasing pressure in the fire protection system. Specifically,
the electric-driven fire pump would start at 95 pounds per square inch gauge (psig) and
the diesel-driven fire pump would start at 90 psig. The pumps were installed in parallel.
At the time of the April 2009 inspection, the licensee provided information to the
inspectors that no time delays had been incorporated into the pump circuits. A lack of
time delays is contrary to National Fire Protection Association (NFPA) 20 - 1969,
Standard for the Installation of Stationary Pumps for Fire Protection requirements to
incorporate sequential timing devices in the controllers for multiple pump units.
On April 9, 2010, the licensee informed the inspectors that the controller for the
diesel-driven fire pump incorporated a 10-second time delay and that previously
provided information was incorrect. The inspectors reviewed the schematic diagrams for
the diesel fire pump circuitry and confirmed that there was a 10-second time delay
shown as part of the circuitry. In addition, the licensee confirmed through review of
computer logs of previously conducted surveillance tests, that there was a 10-second
time delay from the time the pressure reached the set point and when the diesel fire
pump started. The inspectors considered the installed time delay to be sufficient to meet
the intent of the NFPA 20 standard requirement to prevent multiple pumps from starting
simultaneously.
Based on this review, this URI is closed.
.3
Unit 2 Primary-to-Secondary Leakage
a.
Inspection Scope
The inspectors reviewed the operator response and procedure guidance regarding the
identification of a primary to secondary leak on Unit 2. Specifically, the inspectors
reviewed the licensees abnormal operating procedure and compared the procedure
guidance to industry information developed by the EPRI and endorsed by the NRC. The
inspectors also monitored the results of the licensees sampling program and ensured
that the frequency met procedural requirements. At the conclusion of the inspection
period, the inspectors were continuing to monitor the licensees efforts to identify the
affected steam generator and the amount of leakage.
37
Enclosure
b.
Findings
No findings of significance were identified.
4OA6 Management Meetings
.1
Exit Meeting Summary
On July 8, 2010, the inspectors presented the inspection results to Mr. Mark Schimmel
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 radioactive solid waste processing and radioactive material
handling, storage, and transportation inspection with Mr. Brad Sawatzke,
Director Site Operations, on April 30, 2010;
The results of the inservice inspection with Mr. Brad Sawatzke,
Director Site Operations, on May 13, 2010; and
The closure of URI 05000282/2009007-03; 05000306/2009007-03,
Sequential Starting of Fire Pumps, with Mr. Kevin Ryan, Plant Manager, and
other members of the licensees staff via telephone on June 10, 2010.
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 violations of very low safety significance (Green) were identified by the
licensee and are violations of NRC requirements, which meet the criteria of
Section VI.A.1 of the NRC Enforcement Policy for being dispositioned as NCVs.
Section 50.65 (a)(iv) of Title 10 of the Code of Federal Regulations requires that
licensees assess and manage the increase in risk that may result from proposed
maintenance activities prior to performing maintenance. Contrary to the above,
on May 12, 2010, the licensee failed to properly assess and manage the risk
associated with establishing the RCS as intact, releasing the containment airlock
operator from duties, and the removal of equipment hatch from the Unit 2
containment. This resulted in Unit 2 entering an unplanned orange shutdown
safety assessment path for the containment closure function. This issue was
documented in CAP 1232396. Corrective actions included re-establishing the
RCS as intact, closing the equipment hatch, re-instating the airlock operator,
developing a procedure to clearly state the requirements to be met to declare the
RCS intact, and a review of other outage activities to ensure that they were
governed by specific procedures appropriate to the circumstance.
The inspectors determined that the failure to properly assess plant risk in
accordance with 10 CFR Part 50.65(a)(iv) was a performance deficiency that
38
Enclosure
required an SDP evaluation. The inspectors consulted Inspection Manual
Chapter (IMC) 0609, Appendix K, Maintenance Rule Risk Assessment
Significance Determination Process, and found that this appendix could not be
used due to the qualitative nature of shutdown safety assessments. Appendix K
suggested that qualitative risk assessment issues be evaluated through a
management review performed in accordance with IMC 0609, Appendix M. The
inspectors were concerned with this approach since Unit 2 was shut down at the
time this finding occurred. The inspectors consulted a Region III Senior Reactor
Analyst (SRA) for additional assistance. Using IMC 0609, Appendix G,
Significance Determination Process for Shutdown Conditions, the SRA
determined that Unit 2 was in plant outage state #2. The SRA also found that the
shutdown SDP stated that IMC 0609, Appendix H, Containment Integrity
Significance Determination Process, should be used for shutdown findings
related to containment issues. Using Section 4.0 of Appendix H, the SRA
determined that this finding was a type B finding since it was related to a
condition that had potentially important implications for the integrity of
containment without affecting the likelihood of core damage. The SRA then used
Section 6.2, Approach for Assessing Type B Findings at Shutdown, and
determined that this finding was of low safety significance (Green) because it
occurred during the late time window of the outage.
Criterion V to 10 CFR Part 50, Appendix B, requires that activities affecting
quality be prescribed by instructions, procedures and drawings appropriate to the
circumstance. Contrary to the above, on May 19, 2010, the procedure for testing
the 21 and 22 residual heat removal pump suction line check valves, SP 2369,
was not appropriate to the circumstance. Specifically, the procedure was not
written to appropriately account for system and testing configuration changes
made to address previously identified voiding issues. As a result, the test failed
to meet the pre-established acceptance criteria. This issue was documented in
CAP 1233577. Corrective actions for this issue included revising the testing
methodology to account for the system and test configuration changes and
successfully re-performing the test. The licensee also planned to review other
procedure changes made to address the voiding issue.
The inspectors determined that the failure to have a procedure appropriate to the
circumstance was a performance deficiency that required an SDP evaluation.
The inspectors determined that this finding was of very low safety significance
(Green) because it was not a design or qualification deficiency, it did not
represent a loss of safety function, and it did not screen as potentially risk
significant due to a seismic, flooding or severe weather initiating event.
Technical Specification 5.4.1 requires that written procedures be established,
implemented, and maintained covering the applicable procedures recommended
in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Regulatory Guide 1.33, Revision 2, Appendix A, February 1978, Section 9.b
requires that preventive maintenance schedules be developed to specify the
inspection or replacement of parts that have a specific lifetime. Contrary to the
above, on January 26, 2010, the licensee determined that a preventive
maintenance schedule for the motor capacitors for the diesel-driven cooling
water pump oil storage tank pumps were not developed such that the motor
capacitors (which have a 10 year lifetime) were replaced on a periodic basis.
39
Enclosure
As a result, the 122 diesel cooling water pump oil storage tank pump failed
surveillance testing due to a failed motor capacitor. This issue was documented
in CAP 1215266. Corrective actions for this issue included replacing the 122 oil
storage tank pump and developing a periodic capacitor replacement schedule.
The inspectors determined that the failure to develop a preventive maintenance
schedule for replacement of the motor capacitors was a performance deficiency
that required an SDP evaluation. The inspectors determined that this finding was
of very low safety significance (Green) because it was not a design or
qualification deficiency, it did not represent a loss of safety function, and it did not
screen as potentially risk significant due to a seismic, flooding or severe weather
initiating event.
ATTACHMENT: SUPPLEMENTAL INFORMATION
1
Attachment
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
M. Schimmel, Site Vice President
B. Sawatzke, Director Site Operations
K. Ryan, Plant Manager
J. Anderson, Regulatory Affairs Manager
S. Derleth; Radiation Protection Shipping Specialist
C. England, Radiation Protection/Chemistry Manager
D. Kettering, Site Engineering Director
J. Lash, Operations Manager
R. Madjerich, Production Planning Manager
M. Milly, Maintenance Manager
J. Muth, Nuclear Oversight Manager
S. Northard, Performance Improvement Manager
K. Peterson, Business Support Manager
A. Pullam, Training Manager
Nuclear Regulatory Commission
J. Giessner, Reactor Projects Branch 4 Chief
R. Orlikowski, Reactor Projects Branch 4 Chief (Acting)
T. Wengert, Office of Nuclear Reactor Regulation Project Manager
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED
Opened
050000306/2010003-01
Failure to Address Design Vulnerability Results in Reactor
Trip
050000306/2010003-02
Lack of Operator Procedure Use During System Alignment
050000306/2010003-03
Review Licensees Evaluation to Determine Whether
Performance Deficiency Existed
050000282/2010003-04
Inadequate Foreign Material Exclusion Controls Associated
with Work on Emergency Diesel Generators
Closed
050000306/2010003-01
Failure to Address Design Vulnerability Results in Reactor
Trip
050000306/2010003-02
Lack of Operator Procedure Use During System Alignment
050000282/2010003-04
Inadequate Foreign Material Exclusion Controls Associated
with Work on Emergency Diesel Generators
05000282/2009-006-00
LER
Unanalyzed Condition Due to Potential Safety System
Susceptibility to Turbine Building Flooding Due to a
Postulated High Energy Line Break
2
Attachment
05000282/2009-006-01
LER
Unanalyzed Condition Due to Potential Safety System
Susceptibility to Turbine Building Flooding Due to a
Postulated High Energy Line Break
05000306/2010-001-00
LER
Unit 2 Turbine Trip During Reactor Shutdown Resulting in a
Reactor Scram
05000282/2010-002-00
LER
Postulated Flooding of Unit 1 Fuel Oil Transfer Pump Motor
Starters Could Have Resulted in Reduced Fuel Oil Inventory 05000282/2009007-03; 05000306/2009007-03
Sequential Starting of Fire Pumps
Discussed
2515/177
TI
Managing Gas Accumulation in Emergency Core Cooling,
Decay Heat Removal and Containment Spray Systems
3
Attachment
LIST OF DOCUMENTS REVIEWED
The following is a list of documents reviewed during the inspection. Inclusion on this list does
not imply that the NRC inspectors reviewed the documents in their entirety but rather that
selected sections of 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.
1R01 Adverse Weather
- Procedure D104.1; Zebra Mussel Control Treatment: Circulating Water System; Revision 10
- CAP 1181810; CT 12 Gas Pressure Low Out of Spec; May 12, 2009
- CAP 1187578; Negative Dissolve Gas Trends for 2GT, 2M, and 1GT Transformer;
June 20, 2009
- CAP 1188320; CT1 High Voltage Bushings Degraded and Needs to be Replaced; July 7, 2009
- CAP 1189481; Missing Section of Filter Media on 2GT Transformer; July 15, 2009
- CAP 1189513; PM 4910-16 for Six Month Large Transformers Advisory Items; July 16, 2009
- CAP 1191004; Evaluate NRC IN 2009-10: Transformer Failures - Recent Operating
Experience; July 27, 2009
- CAP 1192491; Unable to Perform Quarterly Planned Preventive Station Transformers;
August 6, 2009
- CAP 1195856; CT 12/XFMR the Breaker for the Fans and Heaters Tripped; August 31, 2009
- CAP 1199559; PI Requested 101.8 Percent Post-Trip Volts due to Inadequate C20.3;
September 25, 2009
- CAP 1202922; 2RS Transformer low Gas Pressure; October 17, 2009
- CAP 1207827; Damaged Cooling Fan on 10 Bank; November 22, 2009
- CAP 1510022; Maintenance Procedures for 1R Transformers Not Implemented by PMRQs;
December 9, 2009
- CAP 1212590; CT1 Transformer Dissolved Gas Analysis Shows High Oxygen Content;
January 5, 2010
- CAP 1213070; CT-12 Transformer Gas Pressure at Vacuum During Cold Weather;
January 9, 2010
- CAP 1222094; CT1 Transformer Dissolved Gas Analysis Shows High Oxygen Content;
March 10, 2010
- CAP 1236672; 10 Bank Transformer Total Dissolved Combustible Gas Level into Condition 2;
June 9, 2010
- CAP 1236667; CT 12 Transformer Dissolved Gas Analysis Shows Step Change in Oxygen
Content; June 9, 2010
- C20.3 AOP12; Grid Voltage or Frequency Disturbances; Revision 5
- C20.3; Electrical Power System Security Analysis; Revision 15
- Transformer Health and Status Report; June 10, 2010
1R04 Equipment Alignment
- Procedure C1.1.20.7-13; D6 Diesel Generator Valve Status; Revision 14
- Procedure C1.1.20-7-14; D6 Diesel Generator Auxiliaries and Local Panels and Switches;
Revision 12
- Procedure C1.1.20.7-15; D6 Diesel Generator Main Control Room Switch and indicating Light
Status; Revision 6
- Procedure C1.1.20.7-16; D6 Diesel Generator Circuit Breakers and Panel Switches;
Revision 8
4
Attachment
- Procedure C16-1; Spent Fuel Pool Cooling System Prestart Checklist; Revision 14
- Operations Manual B16; Spent Fuel Pool Cooling System; Revision 7
- Operations Manual C-16; Spent Fuel Pool Cooling System; Revision 52
- CAP 1231015; MC-32122 Closed with no Operator Action; May 4, 2010
- WO 385223; Three Year Pressure Test SP 1168.5; April 16, 2010
- D5 Diesel Generator Maintenance Rule a(1) Plan; Revision 5
- Health and Status Report; D5 Diesel Generator; March 26, 2010
- Procedure C1.1.20.7-10; D5 Diesel Generator Auxiliaries and Local Panel Switches;
Revision 11
- Procedure C1.1.20.7-11; D5 Diesel Generator Main Control Room Switch and Indicating Light
Status; Revision 5
- Procedure C1.1.20.7-12; D5 Diesel Generator Circuit Breakers and Panel Switches;
Revision 9
- Procedure C28-7; Auxiliary Feedwater System Unit 2; Revision 50
- C1.1.20.7-9; D5 Diesel Generator Valve Status; Revision 11
- CAP 1206719; Connecting Rod Bearing Part 21 Issues; November 12, 2009
- CAP 1210203; Rockwell-Edwards Valve, Part 21 Issues; December 10, 2009
- CAP 1097138; Oil Sump Level Switch Mount Discrepancy; June 15, 2007
- CAP 1090396; DG Surveillance Test Procedures; May 1, 2007
- CAP 1049042; EDG Frequency Variation Impact; September 8, 2006
- CAP 831627; D5 Slow Start Surveillance Terminated due to High Crankcase; April 11, 2005
- CAP 1086210; Unable to reduce D5 EDG Load<800 KW During Shutdown; April 5, 2007
- CAP 1221675; U2 D5 Engine 2 Crankcase Pressure; March 8, 2010
- CAP 1217274; D-5 Lock-Out; February 8, 2010
- CAP 1201138; U2 SP 2093 Couldnt Reduce D5 Load <700KW; October 5, 2009
1R05 Fire Protection
- Fire Hazards Analysis
- Safe Shutdown Analysis
- Procedure F5, Appendix A; Fire Zone Plans and Maps; Various Revisions
1R08 Inservice Inspection Activities
- FP-PE-NDE-402; Ultrasonic Examination of Austenitic Pipe Welds - Supplement 2; Revision 2
- Procedure 2H25.1; Unit 2 Degradation Assessment; Revision 6
- Procedure 2H25.2; Unit 2 Steam Generator Condition Monitoring; Revision 6
- Procedure 2H25.3; Unit 2 Steam Generator Tube Repair Criteria; Revision 3
- Procedure D27.21; Steam Generator Tube Repair; Revision 30
- PI-400-001; Multi-frequency Eddy Current Examination of Non-Ferromagnetic Steam
Generator Tubing; Revision 11
- PINGP 1507; Boric Acid Corrosion Control Leak Inspection; Revision 2
- SP 2403; Reactor Vessel Closure Head Bare Metal Visual Examination; Revision 3
- SP 2407; Leakage Examination of Pressure Retaining Components on the Reactor Vessel
Head; Revision 3
- H2 Boric Acid Corrosion Control Program; Revision 15
- MSIP 1078; Leak Walkdowns; Revision 0
- SWI-NDE-VT-6.0; Visual Examination for Leakage on Reactor Vessel Penetrations (VT-2);
Revision 0
- WO 304396; Install EC 11442, Pipe and Valve Downstream of 2RC-8-39
5
Attachment
- WPS FP-PE-B31-P8P8-GTSM-037 Groove Welds and Fillet Welds, P8-P8, GTAW/SMAW,
Without PWHT; Revision 2
- DAEC-W-66; PQR for WPS FP-PE-B31-P8P8-GTSM-037; October 12, 1989
- SP 2392; Unit 2 Insulated Bolted Connection Inspection; Revision 4
- SWI NDE-PT-1; Solvent Removable Visible Dye Penetrant Examination; Revision 1
- H10.5; 4th Interval Inservice Inspection Plan - Units 1 and 2, December 21, 2004, through
December 20, 2014; Revision 5
- CAP 1228864; Loose Nut on Clamp; April 22, 2010
- CAP 1230558; Loose Bolt on Top Side of Tie Back; April 26, 2010
- CAP 1153719; Evaluate the 2R25 SG Degradation; October 4, 2008
1R12 Maintenance Effectiveness
- Health and Status Report; Steam Exclusion; April 7, 2010
- Health and Status Report; External Circulating Water; June 2, 2010
- Maintenance Rule System Specific Basis Document; Revision 14
- CAP 1209247; Found 48335 Out-of-Tolerance During SP 1599; December 3, 2009
- CAP 1139238; Loss of FME Control in ZD System; May 30, 2008
- CAP 1143615; Steam Exclusion Temp Out Of Tolerance; July 9, 2008
- CAP 1147073; Inadequate Documentation and Parts for Damper on PO XH-505;
August 8, 2008
- CAP 1168075; CD-34188 Wont Go Full Close Per SP 1112; February 4, 2009
- CAP 1187281; TI-7005112, Bus 111 and 121 STM EXCL B Train Deviating; June 28, 2009
- CAP 1199304; TE 15688 Failed SP 1112 Out of Spec High; September 23, 2010
- CAP 1209241; Found 48326 Out-of-Tolerance During SP 1599; December 3, 2009
- CAP 1221928; SV-91308 121 Bypass Gate Emergency Open Solenoid Valve Sticking;
March 10, 2010
- CAP 1223961; 121 Intake Screenhouse Bypass Gate Didnt Open on Loss of Power;
March 24, 2010
- CAP 1227411; SV-91308 Failed on First Attempt on Loss of Power Twice in 2 Week Period;
April 15, 2010
- CAP 1227625; Need to Revisit Resolution/Closeout of Root Cause Evaluation 171;
April 16, 2010
- CAP 1160660; SV-91308 and SV-91311 121 and 122 Bypass Gate Emergency Open
Solenoid Valves; November 26, 2008
1R13 Maintenance Risk Assessment and Emergent Work
- Stoplight Memo; Unit 2 Shutdown Safety Assessment Unplanned Orange Condition;
May 12, 2010
- Procedure 2C4.2; Reactor Coolant System Inventory Control - Post Refueling; Revision 25
- Narrative Logs; May 11-12, 2010
- Procedure 2C1.6; Shutdown Operations - Unit 2; Revision 23
- FP-G-DOC-03; Procedure Use and Adherence; Revision 8
- CAP 1232396; Reactor Coolant System was Declared Intact When 2RC-21-1 was Open;
May 12, 2010
- Unit 2 Shutdown Safety Assessments; May 11-12, 2010
- CAP 1226555; Delays in Returning Blue Channel to Service; April 9, 2010
- Procedure FP-WM-IRM-01; Integrated Risk Management; Revision 3
- WO 382583; Bad Output During SP 2003 - Replace 2TM-403V; April 8, 2010
- QF 2010; Work Order Risk Screening Worksheet; Revision 6
6
Attachment
1R15 Operability Evaluations
- CAP 1226049; Low Wall Thickness Found on 24-CL-13; April 6, 2010
- Evaluation 1226049; Low Wall Thickness Found on 24-CL-13; April 7, 2010
- CAP 1230668; Unit 1 Bus Source Breakers; May 3, 2010
- Evaluation 1230668; Unit 1 Bus Source Breakers; Revision; May 10, 2010
1R18 Modifications
- 50.59 Screening #3424; EC 13483 - GL 08-01 Vent Valve Modification for ECCS Piping in
Unit 2; Revision 1
- EC 13483; GL 08-01 Vent Valve Modification for ECCS Piping in Unit 2; Revision 0
- BOP-VE-10-021; Ultrasonic Examination Report; May 09, 2010
- BOP-VE-10-020; Ultrasonic Examination Report; May 09, 2010
- BOP-VE-10-034; Ultrasonic Examination Report; May 15, 2010
- BOP-VE-10-031; Ultrasonic Examination Report; May 15, 2010
- BOP-VE-10-033; Ultrasonic Examination Report; May 15, 2010
- BOP-VE-10-034; Ultrasonic Examination Report; May 15, 2010
- BOP-VE-10-039; Ultrasonic Examination Report; May 16, 2010
- BOP-VE-10-038; Ultrasonic Examination Report; May 16, 2010
- BOP-VE-10-037; Ultrasonic Examination Report; May 16, 2010
- BOP-VE-10-041; Ultrasonic Examination Report; May 17, 2010
- BOP-VE-10-042; Ultrasonic Examination Report; May 17, 2010
- BOP-VE-10-044; Ultrasonic Examination Report; May 18, 2010
- BOP-VE-10-047; Ultrasonic Examination Report; May 18, 2010
- Drawing SK-EC-13483-01; General Construction Notes; Revision 0A-1
- Drawing SK-EC-13483-02; Vent Valve Installation Void Location 2CS-02; Revision 0A-1
- Drawing SK-EC-13483-03; Vent Valve Installation Void Location 2CS-03; Revision 0A-1
- Drawing SK-EC-13483-04; Vent Valve Installation Void Location 2CS-06; Revision 0A-1
- Drawing SK-EC-13483-05; Vent Valve Installation Void Location 2CS-07; Revision 0A-1
- Drawing SK-EC-13483-06; Vent Valve Installation Void Location 2CS-10; Revision 0A-1
- Drawing SK-EC-13483-07; Vent Valve Installation Void Location 2CS-11; Revision 0A-1
- Drawing SK-EC-13483-08; Vent Valve Installation Void Location 2CS-12; Revision 0A-1
- Drawing SK-EC-13483-09; Vent Valve Installation Void Location 2CS-13; Revision 0A-1
- Drawing SK-EC-13483-10; Vent Valve Installation Void Location 2CS-14-1; Revision 0A-1
- Drawing SK-EC-13483-11; Vent Valve Installation Void Location 2CS-15; Revision 0A-1
- Drawing SK-EC-13483-12; Vent Valve Installation Void Location 22PIT-02-1; Revision 0A-1
- Drawing SK-EC-13483-13; Vent Valve Installation Void Location 22PIT-02-2; Revision 0A-1
- Drawing SK-EC-13483-14; Vent Valve Installation Void Location 22PIT-05; Revision 0A-1
- Drawing SK-EC-13483-15; Vent Valve Installation Void Location 2RH-06; Revision 0A-1
- Drawing SK-EC-13483-15A; Vent Valve Installation Void Location 2RH-06; Revision 0A-1
- Drawing SK-EC-13483-16; Vent Valve Installation Void Location 2RH-09; Revision 0A-1
- Drawing SK-EC-13483-17; Vent Valve Installation Void Location 2RH-10; Revision 0A-1
- Drawing SK-EC-13483-20; Vent Valve Installation Void Location 2SI-12; Revision 0A-1
- Drawing SK-EC-13483-21; Vent Valve Installation Void Location 2SI-12; Revision 0A-1
- Drawing SK-EC-13483-22; Vent Valve Installation Void Location 2SI-13; Revision 0A-1
- Drawing SK-EC-13483-23; Vent Valve Installation Void Location 2SI-14A; Revision 0A-1
- Drawing SK-EC-13483-24; Vent Valve Installation Void Location 2SI-14B; Revision 0A-1
- Drawing SK-EC-13483-25; Vent Valve Installation Void Location 2SI-2; Revision 0A-1
- Drawing SK-EC-13483-26; Vent Valve Installation Void Location 2SI-33B; Revision 0A-1
- Drawing SK-EC-13483-27; Vent Valve Installation Void Location 2SI-33A; Revision 0A-1
7
Attachment
- Drawing SK-EC-13483-28; Vent Valve Installation Void Location 2SI-44; Revision 0A-1
- Drawing SK-EC-13483-29; Vent Valve Installation Void Location 2SI-44; Revision 0A-1
- Drawing SK-EC-13483-30; Vent Valve Installation Void Location 2SI-46; Revision 0A-1
- Drawing SK-EC-13483-31; Vent Valve Installation Void Location 2SI-16; Revision 0A-1
- Drawing SK-EC-13483-32; Vent Valve Installation Void Location 2RH-06; Revision 0A-1
- ENG-ME-449; Assessment of Containment Heat Sinks; Revision 1
- FP-PE-NDE-426; Ultrasonic Examination for Determination of Fluid Levels; Revision 1
- EC 12617; Temporary Air Compressor for Service Air System; Design Input Checklist - Part A
Engineering Programs and Departmental Reviews; No Date
- EC 12617; Temporary Air Compressor for Service Air System; Design Input Checklist - Part B
Design Considerations, Requirements, and Standards; No Date
- EC 12617; Temporary Air Compressor for Service Air System; Design Input Consultation
Form; April 30, 2008
- EC 12617; Temporary Air Compressor for Service Air System; Modification Classification;
April 30, 2008
- 50.59 Screening; EC 12617; Temporary Air Compressor for Service Air System; Revision 0
- C33; Station Air System; Revision 33 (with temporary change mark-ups)
- CAP 1226570; Portable Air Compressor Near Fuel Oil Storage Tanks; April 9, 2010
- EC 12617; Connect a Temporary Air Compressor to the Service Air System Using Existing
2-1/2 Inch System Header; May 14, 2008
1R19 Post-Maintenance Testing
- SP 2102; 22 Turbine-Driven AFW Pump Monthly Test; Revision 88
- WO 399163; Replace 22 Turbine-Driven AFW Pump Turbine Thermocouple; April 12, 2010
- WO 393350-14; D6 Diesel Break In Run; May 14, 2010
- Work Plan 393350-14; D6 Diesel Break In Run; May 14, 2010
- CAP 1211427; D5 Bearing Replacement Timing/ Methodology; December 21, 2009
- Evaluation 1206719; Part 21 Reporting of an Issue with Wartsila/SACM UD-45 Connecting
Rod Bearings; November 13, 2009
- SP 2331; 21 Motor-Driven AFW Pump Auto Start and Functional Testing Each Refueling
Shutdown; Revision 19
- WO 326939; SP 2331 21 Motor-Driven AFW Pump Auto Start and Function Testing Each
Refueling Shutdown; May 1, 2010
1R20 Refueling and Outage
- 2C1.4; Unit 2 Power Operation; Revision 45
- 2C1.3; Unit 2 Shutdown; Revision 67
- D30; Post Refueling Startup Testing; Revision 48
- D58; Heavy Loads Program; Revision 33
- D58.2.9; Unit 2 Reactor Vessel Head Removal; Revision 17B
- D58.2.10; Unit 2 Reactor Vessel Head Replacement; Revision 15
- MSIP 7004; Unit 1 and Unit 2 Reactor Vessel Head Removal Pre-Job Briefing; Revision 8
- CAP 1228394; Non-Conservative Input Used in Heavy Load Drop Dose Analysis;
April 21, 2010
- 50.59 Screening; Eliminate Opening Allowances in Containment while Moving Heavy Loads
Over Irradiated Fuel in C19.9; April 22, 2010
- C19.9; Containment Boundary Control During Mode 5, Cold Shutdown and Mode 6, Refueling;
Revision 13
8
Attachment
- C19.9-2; Inventory and Refueling Integrity Containment Boundary Checklist - Unit 2;
Revision 18
- WO 387079-01; SP 2421 Unit 2 Reactor Vessel Bottom Head Bare Metal Visual Examination;
April 24, 2010
- WO 327134-01; SP 2405 Unit 2 Mid-Cycle and Refueling Outage Boric Acid Corrosion
Examination Inside Containment; April 14, 2010
- SP 2405; Unit 2 Mid-Cycle and Refueling Outage Boric Acid Corrosion Examinations Inside
Containment; Revision 4
- SP 2421; Reactor Vessel Bottom Head Bare Metal Visual Examination; Revision 2
- Calculation 2005-05621; Analysis of Postulated Reactor Head Load Drop; Revision 1
- WO 00326749-01; PM 3160-1 21 Containment Polar Crane Mechanical Inspection;
April 15, 2010
- PM 3160-1; Containment Polar Crane Mechanical Inspection; Revision 13
- WO 00393473-10; Unit 2 Conduct ISI Exams in Containment in 2R26; April 6, 2010
- NDE Report 2010P005; CRD32 Latch Housing and Head Adapter; April 28, 2010
- NDE Report 2010P006; CRD22 Latch Housing and Head Adapter; April 28, 2010
- NDE Report 2010P007; CRD31 Latch Housing and Head Adapter; April 28, 2010
- NDE Report 2010P008; CRD26 Latch Housing and Head Adapter; April 28, 2010
- SWI NDE-PT-1; Solvent Removable, Visable Dye Penetrant Examination; Revision 1
- SP 2750; Post Outage Containment Close-Out Inspection; Revision 34
- SP 2177; Core Inventory Verification; Revision 15
- WO 327160-01; SP 2177 Refuel Core Inventory Verification
- Unit 2 Cycle 26 Core Inventory Verification Video; May 6, 2010
- 50.59 Evaluation #1076 (Document #03FH02-226); Unit 2 Cycle 26 Core Reload; Revision 0
- Westinghouse Reload Safety Evaluation - Prairie Island Unit 2 Cycle 26
- Prairie Island Nuclear Generating Plant Core Operating Limits Report - Unit 2 Cycle 26;
Revision 0
- Reactor Startup Following 2R26 Plant Operations Review Committee Meeting 3109 Meeting
Minutes; May 21, 2010
- Operating Experience Smart Sample FY2007-03; Crane and Heavy Lift Inspection; Revision 0
- Shutdown Safety Assessments; dated April 17, 2010, through May 21, 2010
- SP 2277; General Visual Examination of the Containment Vessel for ASME Subsection IWE;
Revision 2
- NRC Commitments 1028 and 1029; Reply to Notice of Violation 92-06 - Inadequate
Procedure for Draindown to Midloop; June 1, 1992
- 50.59 Evaluation 1077; Removal of NRC Commitments 1028 and 1029 for Non-Intrusive
Reactor Coolant System Level Indicators During Reduced Inventory Operations;
April 19, 2010
- Procedure 2C12.2; Purification and Chemical Addition - Unit 2; Revision 24
- Plant Operations Review Package; May 21, 2010
- SP 2750; Post Outage Containment Close-Out Inspection; Revision 34
1R22 Surveillance Test
- WO 376539-01; SP 2431 Main Steam Safety Valve Test (Power Operation); April 14, 2010
- SP 2431; Main Steam Safety Valve Test (Power Operation); Revision 1
- WO 367330-01; SP 2070 Reactor Coolant System Integrity Test; April 17, 2010
- SP 2070; Reactor Coolant System Integrity Test; Revision 38
- WO 397239-01; SP 1094 Bus 15 Load Sequencer; May 04, 2010
- SP 1094; Bus 15 Load Sequencer; Revision 27
9
Attachment
- WO 327093-01; SP 2083 Unit 2 Integrated SI Test with a Simulated Loss of Offsite Power;
April 17, 2010
- SP 2083; Unit 2 Integrated SI Test with a Simulated Loss of Offsite Power; Revision 31
- WO 367335-01; SP 2277 General Visual Examination of the Containment Liner for ASME
Subsection IWE; April 17, 2010
- SP 2277; General Visual Examination of the Containment Liner for ASME Subsection IWE;
Revision 1A
- WO 397929-01; SP 1090B 12 Containment Spray Pump Quarterly Test; May 4, 2010
- SP 1090B; 12 Containment Spray Pump Quarterly Test; Revision 17
2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and
Transportation
- CAP 1157726; Radioactive Material Shipment Exceeded DOT Limits; Revision 2
- C49.10; Clamshell Operations; Revision 13
- D11.7; Radioactive Material Shipment LSA/SCO/LDT Quantity to a Licensed Facility;
Revision 21
- D11.11; Radioactive Material Shipment LSA/SCO/LDT Quantity to a Licensed Processing
Facility; Revision 17
- D20.13; Sluicing Resin from 12 Mixed Bed IX to 121 Spent Resin Tank; Revision 19
- D20.16; Sluicing Resin from 11 Evap Condensate IX to a Resin Shipping Liner; Revision 16
- D59; Process Control Program for Solidification/Dewatering of Radioactive Waste from Liquid
Systems; Revision 9
- FP-WM-IRM-01; Integrated Risk Management; Revision 3
- Radiological Survey Records; Various Dates
- RPIP 1303; Packaging of Radioactive Material for Shipment; Revision 5
- RPIP 1307; Radioactive Waste Classification; Revision 8
- RPIP 1310; Radioactive Waste Streams Scaling Factors; Revision 8
- RPIP 1319; Loading LSA Boxes/Sealand Containers; Revision 17
- RPIP 1721; Resin Sluice; Revision 19
- QF-2007; (FP-WM-IRM-01); Planning and Approval of High Risk or Scheduled Risk Work;
Revision 3
- QF-2010; (FP-WM-IRM-01); Work Order Risk Screening Worksheet; Revision 6
- Shipment Number 09-024; Hn-215 Cask - Dewatered Resin; November 2009
- Shipment Number 09-025; Hn-215 Cask - Dewatered Resin; November 2009
- Shipment Number 09-030; DAW Sealands; December 2009
- Shipment Number 10-005; DAW Sealands; January 2010
- Shipment Number 10-008; DAW Sealands; February 2010
4OA1 Performance Indicator Verification
- SWI O-53; Operations Performance Indicators Reporting; Revision 5
- Monthly Data for RCS Identified leakage
- CAP 1186923; NRC Identifies Discrepancies with Reported Data; June 25, 2009
- SP 1001AA; Daily Reactor Coolant System Leakage Test; Revision 51
- SP 2001AA; Daily Reactor Coolant System Leakage Test; Revision 48
4OA2 Identification and Resolution of Problems
- CAP 1208884; Unit 2 Fuel Oil Out of Specification - Fuel Oil Receiving Tank;
December 2, 2009
10
Attachment
- CAP 1223538; Document the Basis for 21 D5/D6 Fuel Oil Receiving Tank Satisfying H30;
March 20, 2010
- CAP 1226499; Lack of Parts to Perform 2R26 Preventive Maintenance Activities;
April 28, 2010
- CAP 1210203; 10 CFR Part 21 for Rockwell Edward Valves; December 10, 2009
- CAP 1233549; Unit 2 Charging System Design Pressure Exceeded; May 19, 2010
- CAP 1233070; Lifted Relief Valve Upon Startup of Charging Pump on Outage Unit;
May 16, 2010
- Procedure 2C19.1; Containment Unit 2; Revision 20
- Maintenance Rule Monthly Reports; December 2009 - May 2010
- System Health Reports; December 2009 - May 2010
4OA3 Follow-up of Events and Notices of Enforcement Discretion
- Event Notification 45855; Loss of Safety Function Due to Loss of Turbine Building High Energy
Line Break Compensatory Measure; April 19, 2010
- Event Notification Retraction 45855; Loss of Safety Function Due to Loss of Turbine Building
High Energy Line Break Compensatory Measure; April 22, 2010
- EC 16032; Internal Flooding Evaluation for 4/18/2010 Screen Door Closing Event;
April 20, 2010
- Initial Trip Summary; April 17, 2010
- 2C1.3; Unit 2 Shutdown; Revision 66
- 2C1.4; Unit 2 Power Operation; Revision 45
- CAP 527451; Unable to Restore Condenser Vacuum After Turbine Tripped;
September 13, 2003
- Equipment Problem Investigation Report; September 20, 2003
- Engineering Work Request 028155; Possible Engineering Change/Minor Modification to
Re-Slope and Trap MSR Sealing Steam Lines to MSR Headers; September 19, 2003
- Engineering Work Request 030335; Possible Minor Modification to Install Trap MSR Sealing
Steam Lines to MSR Headers; January 14, 2004
- CAP 20014153; During Performance of 2C1.3 - Unit 2 Turbine Manually Tripped Due to High
Condenser Differential Pressure with Vacuum Decreasing; May 9, 2001
4OA5 Other Activities
- NE-40014-3; 122 Diesel Fire Pump Schematic; Revision V
- NE-40014-4; 122 Diesel Fire Pump Schematic; Revision K
- NF-40318-1; Interlock Logic Diagram for Fire Protection and Screen Wash System, Units 1
and 2; Revision L
- 2C4 AOP2; Steam Generator Tube Leak; Revision 18
- EPRI Document; Pressurized Water Reactor Primary-to-Secondary Leak Guidelines;
Revision 3
4OA7 Licensee-Identified Findings
- Stoplight Memo; Unit 2 Shutdown Safety Assessment Unplanned Orange Condition;
May 12, 2010
- Procedure 2C4.2; Reactor Coolant System Inventory Control - Post Refueling; Revision 25
- Narrative Logs; May 11-12, 2010
- Procedure 2C1.6; Shutdown Operations - Unit 2; Revision 23
- FP-G-DOC-03; Procedure Use and Adherence; Revision 8
11
Attachment
- CAP 1232396; Reactor Coolant System was Declared Intact When 2RC-21-1 was Open;
May 12, 2010
- Unit 2 Shutdown Safety Assessments; May 11-12, 2010
- CAP 1233577; Unit 2 RHR Suction Check Valves Fail SP 2369 Closed Function;
May 19, 2010
- CAP 1215266; 122 Diesel Cooling Water Pump Oil Storage Tank Pump Failure;
January 26, 2010
12
Attachment
LIST OF ACRONYMS USED
Alternating Current
Agencywide Document Access Management System
American Society of Mechanical Engineers
Corrective Action Program
CFR
Code of Federal Regulations
Dry Active Waste
Division of Reactor Projects
EC
Engineering Change
Electric Power Research Institute
Eddy Current
Finding
GL
Generic Letter
gph
Gallons Per Hour
IMC
Inspection Manual Chapter
IP
Inspection Procedure
IR
Inspection Report
Inservice Inspection
LER
Licensee Event Report
Non-Cited Violation
National Fire Protection Association
NRC
U.S. Nuclear Regulatory Commission
Outage Safety Plan
Publicly Available Records System
Performance Indicator
Refueling Outage
Significance Determination Process
Surveillance Procedure
Senior Reactor Analyst
TI
Temporary Instruction
TS
Technical Specification
Transmission System Operator
Unresolved Item
Updated Safety Analysis Report
Work Order
M. Schimmel
-2-
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 by Kenneth Riemer for/
Robert J. Orlikowski, Acting Chief
Branch 4
Division of Reactor Projects
Docket Nos. 50-282; 50-306;72-010
License Nos. DPR-42; DPR-60; SNM-2506
Enclosure:
Inspection Report 05000282/2010003; 05000306/2010003
w/Attachment: Supplemental Information
cc w/encl:
Distribution via ListServ
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OFFICE
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NAME
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- RML for
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DATE
07/26 /10
0726/10
OFFICIAL RECORD COPY
Letter to M. Schimmel from R. Orlikowski dated July 26, 2010.
SUBJECT:
PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2,
NRC INTEGRATED INSPECTION REPORT 05000282/2010003;
DISTRIBUTION:
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