ML102170525
| ML102170525 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 08/04/2010 |
| From: | Vincent Gaddy NRC/RGN-IV/DRP/RPB-C |
| To: | O'Grady B Nebraska Public Power District (NPPD) |
| References | |
| IR-10-003 | |
| Download: ML102170525 (41) | |
See also: IR 05000298/2010003
Text
UNITED STATES
NU C LE AR RE G UL AT O RY C O M M I S S I O N
REGION IV
6 12 EAST LAMAR BL VD , S U I T E 4 0 0
A R L I N G T O N , T E X A S 7 6 0 1 1 -41 25
August 4, 2010
Brian J. OGrady, Vice President-Nuclear
and Chief Nuclear Officer
Nebraska Public Power - Cooper
Nuclear Station
72676 648A Avenue
Brownville, NE 68321
Subject: COOPER NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT
Dear Mr. OGrady:
On June 23, 2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at
your Cooper Nuclear Station. The enclosed integrated inspection report documents the
inspection findings, which were discussed on July 1, 2010, with Brian OGrady, Vice President
and Chief Nuclear Officer, and other members of your staff.
The inspections 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.
This report documents two NRC-identified violations, one self-revealing violation and one self-
revealing finding of very low safety significance (Green). Three of these findings were
determined to involve violations of NRC requirements. However, because of the very low safety
significance and because they are entered into your corrective action program, the NRC is
treating these findings as a noncited violations, consistent with Section VI.A.1 of the NRC
Enforcement Policy. If you contest the violations or the significance of the noncited violations,
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, D.C. 20555-0001, with copies to the Regional Administrator, U.S. Nuclear
Regulatory Commission, Region IV, 612 E. Lamar Blvd, Suite 400, Arlington, Texas,
76011-4125; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission,
Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Cooper Nuclear Station
facility. In addition, if you disagree with the crosscutting 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 IV, and the NRC
Resident Inspector at Cooper Nuclear Station.
Nebraska Public Power District -2-
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, and its
enclosure, will be available electronically for public inspection in the NRC Public Document
Room or from the Publicly Available Records component of NRCs document system (ADAMS).
ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the
Public Electronic Reading Room).
Sincerely,
/RA/
Vince Gaddy, Chief
Project Branch C
Division of Reactor Projects
Docket: 50-298
License: DRP-46
Enclosure:
NRC Inspection Report 05000298/2010003
w/Attachment: Supplemental Information
cc w/Enclosure:
Gene Mace Michael J. Linder, Director
Nuclear Asset Manager Nebraska Department of
Nebraska Public Power District Environmental Quality
P.O. Box 98 P.O. Box 98922
Brownville, NE 68321 Lincoln, NE 68509-8922
John C. McClure, Vice President Randy Rohrs, Chairman
and General Counsel Nemaha County Board of Commissioners
Nebraska Public Power District Nemaha County Courthouse
1414 15th Street 1824 N Street, Suite 201
P.O. Box 499 Auburn, NE 68305
Columbus, NE 68601
Julia Schmitt, Manager
David Van Der Kamp Nebraska Department of Health
Licensing Manager and Human Services
Nebraska Public Power District Division of Public Health
P.O. Box 98 Nebraska State Office Building, 3rd Fl
Brownville, NE 68321 Lincoln, NE 68509-5026
Deputy Director for Policy
Missouri Department of Natural Resources
P.O. Box 176
Jefferson City, MO 65102-0176
Nebraska Public Power District -3-
Director, Missouri State Emergency Keith G. Henke, Planner
Management Agency Division of Community and Public Health
P.O. Box 116 Office of Emergency Coordination
Jefferson City, MO 65102-0116 P.O. Box 570
Jefferson City, MO 65102
Chief, Radiation and Asbestos
Control Section Art Zaremba
Kansas Department of Health Director of Nuclear Safety Assurance
and Environment Nebraska Public Power District
Bureau of Air and Radiation P.O. Box 98
1000 SW Jackson, Suite 310 Brownville, NE 68321
Topeka, KS 66612-1366
Ronald D. Asche, President
Melanie Rasmussen, State Liaison Officer/ and Chief Executive Officer
Radiation Control Program Director Nebraska Public Power District
Bureau of Radiological Health 1414 15th Street
Iowa Department of Public Health Columbus, NE 68601
Lucas State Office Building, 5th Floor
321 East 12th Street Chief, Technological Hazards
Des Moines, IA 50319 Branch
FEMA, Region VII
John F. McCann, Director, Licensing 9221 Ward Parkway
Entergy Nuclear Northeast Suite 300
Entergy Nuclear Operations, Inc. Kansas City, MO 64114-3372
440 Hamilton Avenue
White Plains, NY 10601-1813
Nebraska Public Power District -4-
Electronic distribution by RIV:
Regional Administrator (Elmo.Collins@nrc.gov)
Deputy Regional Administrator (Chuck.Casto@nrc.gov)
Acting DRP Director (Anton.Vegel@nrc.gov)
Acting DRP Deputy Director (Troy.Pruett@nrc.gov)
DRS Director (Roy.Caniano@nrc.gov)
Acting DRS Deputy Director (Jeff.Clark@nrc.gov)
Senior Resident Inspector (Nick.Taylor@nrc.gov)
Resident Inspector (Michael.Chambers@nrc.gov)
Branch Chief, DRP/C (Vincent.Gaddy@nrc.gov)
Senior Project Engineer, DRP/C (Bob.Hagar@nrc.gov)
CNS Administrative Assistant (Amy.Elam@nrc.gov)
Public Affairs Officer (Victor.Dricks@nrc.gov)
Public Affairs Officer (Lara.Uselding@nrc.gov)
Project Manager (Lynnea.Wilkins@nrc.gov)
Branch Chief, DRS/TSB (Michael.Hay@nrc.gov)
RITS Coordinator (Marisa.Herrera@nrc.gov)
Regional Counsel (Karla.Fuller@nrc.gov)
Congressional Affairs Officer (Jenny.Weil@nrc.gov)
OEMail Resource
ROPreports
DRS/TSB STA (Dale.Powers@nrc.gov)
OEDO RIV Coordinator (Margie.Kotzalas@nrc.gov)
ADAMS: No x Yes SUNSI Review Complete Reviewer Initials: VGG
x Publicly Available x Non-Sensitive
Non-publicly Available Sensitive
RI:DRP/C SRI:DRP/C C:DRS/EB1 S:DRS/TSB C:DRS/EB2
MLChambers NHTaylor TRFarnholtz MCHay NFOKeefe
/RA/ /RA/ /RA/ /RA/ /RA/
8/4/10 88/3/10 7/27/10 8/2/10 7/28/10
C:DRS/OB C:DRS/PSB1 C:DRS/PSB2 C:DRP/C
MHaire MPShannon GEWerner VGGaddy
/RA/BRL for /RA/ /RA/ /RA/
7/28/10 7/28/10 7/28/10 8/4/10
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket: 50-298
License: DRP-46
Report: 05000298/2010003
Licensee: Nebraska Public Power District
Facility: Cooper Nuclear Station
Location: 72676 648A Ave
Brownville, NE 68321
Dates: March 25 through June 23, 2010
Inspectors: N. Taylor, Senior Resident Inspector
M. Chambers, Resident Inspector
R. Hagar, Senior Project Engineer
R. Kumana, Project Engineer
Approved By: Vince Gaddy, Chief, Project Branch C
Division of Reactor Projects
-1- Enclosure
SUMMARY OF FINDINGS
IR 05000298/2010003; 03/25/2010 - 06/23/2010; Cooper Nuclear Station, Integrated Resident
and Regional Report; Equipment Alignments, Maintenance Effectiveness, Event Follow-up,
Other Activities
The report covered a 3-month period of inspection by resident inspectors. Four Green findings
were identified. The significance of most findings is indicated by their color (Green, White,
Yellow, or Red) using Inspection Manual Chapter 0609, Significance Determination Process.
Findings for which the significance determination process does not apply may be Green or be
assigned a severity level after NRC management review. The NRC's 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 Findings and Self-Revealing Findings
Cornerstone: Initiating Events
Green. A self-revealing noncited violation of 10 CFR 50.54.j was identified when
the licensee failed to ensure that mechanisms which may affect reactivity are
manipulated only with the knowledge and consent of a licensed operator at the
controls. Specifically, a work planner caused a feedwater heater trip by touching a
pressure regulating valve without the knowledge of the control room. This action
resulted in a feedwater transient. A subsequent reactivity increase occurred due to
the change in feedwater temperature causing the reactor to exceed the licensed
thermal power limit of 2419 MWt until reactor operators reduced power. The
licensee immediately reduced power using the recirculation pumps. The licensee
entered this issue in their corrective action program as CR-CNS-2010-03091.
The finding was more than minor because the performance deficiency could be
reasonably viewed as a precursor to a significant event in that a reactor power
transient was initiated without the knowledge of the control room. This finding was
characterized under the significance determination process as having very low
safety significance because while the finding degraded the transient initiator
contributor function of the initiating events cornerstone, it did not contribute to both
the likelihood of a reactor trip and the likelihood that mitigation equipment or
functions will not be available. The inspectors determined that this finding has a
crosscutting aspect in the area of human performance associated with the work
practices component because the work planner proceeded in the face of
unexpected circumstances by exceeding the scope of the job when he found the
leak was greater than expected H.4(a) (Section 4OA3).
Green. A self-revealing finding was identified for the licensees failure to
implement the preventive maintenance requirements of the vendor manual for the
plant traveling water screens. Specifically, Vendor Manual 140, Traveling Water
Screen, Revision 35, contained daily and weekly routine maintenance
requirements to open the channel-flushing valve to clear any accumulated debris
-2- Enclosure
from the screens. Despite the fact that the licensee incorporated this vendor
manual into their preventive maintenance system, this maintenance requirement
was overlooked. The failure to perform this maintenance task led to the trip of the
A1 and A2 traveling water screens on May 1, 2010, and required an emergent
power reduction. The licensee entered this issue in their corrective action program
as Condition Report CR-CNS-2010-03195, and implemented daily checks of the
traveling water screens and daily flushing of the screen debris troughs.
The finding was more than minor because it affected the equipment performance
attribute of the initiating events cornerstone, and adversely affected the
cornerstone objective to limit the likelihood of those events that upset plant stability
and challenge critical safety functions during shutdown as well as power
operations. This finding was characterized under the significance determination
process as having very low safety significance because it did not contribute to both
the likelihood of a reactor trip and the likelihood that mitigation functions would be
unavailable. The inspectors determined that no crosscutting aspect was
applicable to this finding because the performance deficiency was not reflective of
current performance (Section 4OA5).
Cornerstone: Mitigating Systems
Green. The inspectors identified a noncited violation of 10 CFR 50 App B
Criterion III, Design Control, in which the licensee failed to maintain
accurate design drawings of the service water system discharge piping.
Specifically, Drawing BR 2120, Yard Circ. & Service Water Piping Plan &
Sections, Revision 14 incorrectly identified the as-built configuration of the
service water system discharge piping, and was used as a design input to
numerous essential calculations. The licensee completed an operability
evaluation that demonstrated that the service water was operable despite the
condition. The licensee entered this issue in their corrective action program as
Condition Report CR-CNS-2010-03689.
The finding was more than minor because it affected the design control attribute of
the mitigating systems cornerstone, and adversely affected the cornerstone
objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences (i.e., core
damage). This finding was characterized under the significance determination
process as having very low safety significance because all of the screening
questions in the Manual Chapter 0609, Attachment 4, Initial Screening and
Characterization of Findings Phase 1 screening table were answered in the
negative. The inspectors determined that no cross cutting aspect was applicable
to this finding due to the age of the performance deficiency and the lack of recent
identification opportunities. (Section 1R04).
Green. The inspectors identified a noncited violation of 10 CFR 50.65(a)(2),
requirements for monitoring the effectiveness of maintenance at nuclear power
plants, for failure to demonstrate that the performance of the essential 4160 volt
-3- Enclosure
alternating current power system was effectively controlled through appropriate
preventive maintenance. As a result, the licensee did not establish goals or
monitor the performance of the essential power system Agastat relays per
10 CFR 50.65 (a)(1) to ensure appropriate corrective actions were initiated
when a revised evaluation of a Agastat time delay relay failure incorrectly
changed the initial functional failure determination. Incorrectly changing this
maintenance preventable functional failure resulted in the affected function,
EE-PF03A, not reaching the licensees maintenance rule (a)(1) threshold.
The licensee entered this issue in their corrective action program as
Condition Report CR-CNS-2008-07910.
This finding is more than minor because it affected the reliability objective of the
Equipment Performance attribute under the Mitigating Systems Cornerstone. The
inspectors determined that this performance deficiency was an additional, but
separate consequence of the degraded performance of the essential 4160 volt
alternating current system Agastat relays. Following the guidance of Appendix B
to MC0612 and Appendix D to IP 71111.12, the inspectors determined that this
finding occurred as a consequence of actual problems with the Agastat relays, and
that those actual problems were not attributable to this finding. This finding
therefore cannot be processed through the significance determination process,
and is considered to be Green by NRC staff review. The finding has a crosscutting
aspect in the area of human performance associated with decision-making
because the licensee did not use conservative assumptions in the functional failure
evaluation of a Agastat relay failure H.1(b) (Section 1R12).
B. Licensee-Identified Violations
None
-4- Enclosure
REPORT DETAILS
Summary of Plant Status
Cooper Nuclear Station began the inspection period at full power on March 24, 2010. On
May 1, 2010, the plant reduced power to 70 percent in response to a loss of a circulating water
pump due to intake screen fouling. The licensee cleared the screen and returned to
100 percent power later that day. On May 7, 2010, the licensee reduced power to 70 percent
for scheduled surveillance testing and returned to 100 percent power On June 4, 2010, the
licensee reduced power to 36 percent for scheduled maintenance on the recirculation pump
motor generator B. The plant returned to full power on June 10, 2010, where it remained for the
rest of the inspection period.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and
1R01 Adverse Weather Protection (71111.01)
.1 Summer Readiness for Offsite and Alternate-ac Power
a. Inspection Scope
The inspectors performed a review of preparations for summer weather for selected
systems, including conditions that could lead to loss-of-offsite power and conditions that
could result from high temperatures. The inspectors reviewed the procedures affecting
these areas and the communications protocols between the transmission system
operator and the plant to verify that the appropriate information was being exchanged
when issues arose that could affect the offsite power system. Examples of aspects
considered in the inspectors review included:
The coordination between the transmission system operator and the plants
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
The notifications from the transmission system operator to the plant when the
offsite power system was returned to normal
During the inspection, the inspectors focused on plant-specific design features and the
procedures used by plant personnel to mitigate or respond to adverse weather
conditions. Additionally, the inspectors reviewed the UFSAR and performance
requirements for systems selected for inspection, and verified that operator actions were
-5- Enclosure
appropriate as specified by plant-specific procedures. Specific documents reviewed
during this inspection are listed in the attachment. The inspectors also reviewed
corrective action program items to verify that the licensee was identifying adverse
weather issues at an appropriate threshold and entering them into their corrective action
program in accordance with station corrective action procedures. The inspectors
reviews focused specifically on the following plant systems:
Alternate AC readiness and service water systems
These activities constitute completion of one readiness for summer weather affect on
offsite and alternate-ac power sample as defined in Inspection Procedure 71111.01-05.
b. Findings
No findings were identified.
.2 Readiness to Cope with External Flooding
a. Inspection Scope
The inspectors evaluated the design, material condition, and procedures for coping with
the design basis probable maximum flood. The evaluation included a review to check
for deviations from the descriptions provided in the Updated Final Safety Analysis Report
for features intended to mitigate the potential for flooding from external factors. As part
of this evaluation, the inspectors checked for obstructions that could prevent draining,
checked that the roofs did not contain obvious loose items that could clog drains in the
event of heavy precipitation, and determined that barriers required to mitigate the flood
were in place and operable. Additionally, the inspectors performed an inspection of the
protected area to identify any modification to the site that would inhibit site drainage
during a probable maximum precipitation event or allow water ingress past a barrier.
The inspectors also reviewed the abnormal operating procedure for mitigating the design
basis flood to ensure it could be implemented as written. Specific documents reviewed
during this inspection are listed in the attachment.
These activities constitute completion of one external flooding sample as defined in
Inspection Procedure 71111.01-05.
b. Findings
No findings were identified.
-6- Enclosure
1R04 Equipment Alignments (71111.04)
.1 Partial Walkdown
a. Inspection Scope
The inspectors performed partial system walkdowns of the following risk-significant
systems:
April 14, 2010, Core spray A
May 19, 2010, High pressure coolant injection
May 26, 2010, 69kV and 12.5kV switchyard alignment
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 affect the function of the system, and, therefore,
potentially increase risk. The inspectors reviewed applicable operating procedures,
system diagrams, Updated Final Safety Analysis Report, technical specification
requirements, administrative technical specifications, outstanding work orders, condition
reports, and the impact of ongoing work activities on redundant trains of equipment in
order to identify conditions that could have rendered the systems incapable of
performing their intended functions. The inspectors also inspected accessible portions
of the systems to verify system components and support equipment were aligned
correctly and operable. The inspectors examined the material condition of the
components and observed operating parameters of equipment to verify that there were
no obvious deficiencies. The inspectors also verified that the licensee had properly
identified and resolved equipment alignment problems that could cause initiating events
or impact the capability of mitigating systems or barriers and entered them into the
corrective action program with the appropriate significance characterization. Specific
documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of three partial system walkdown samples as
defined in Inspection Procedure 71111.04-05.
b. Findings
Introduction. The inspectors identified a Green noncited violation of 10 CFR 50 App B
Criterion III, Design Control, in which the licensee failed to maintain accurate design
drawings of the service water system discharge piping. Specifically, Drawing BR 2120,
Yard Circ. & Service Water Piping Plan & Sections, Revision 14 incorrectly identified
the as-left configuration of the service water system discharge piping, and was used as a
design input to numerous essential calculations.
Description. During followup of degraded service water system performance from
Refueling Outage 25 that occurred in October 2009, the licensee discovered that the
configuration of the combined service water/circulating water common discharge lines
was not as depicted on Drawing BR 2120, Yard Circ. & Service Water Piping Plan &
Sections, Revision 14. Specifically, BR 2120 showed that the two divisional pipes
-7- Enclosure
terminated 24 feet apart, protruding from the west bank of the plant discharge canal a
few feet below the waterline. In contrast, divers discovered that the pipes instead
terminated at the bottom of the discharge canal only 6 inches apart.
Inspectors learned that the as-found piping configuration was meant by the Architect-
engineer to be an interim step in the fabrication process. Drawing BR 2120 was
developed during plant construction and was revised regularly as the service water
system and circulating water system were constructed. The service water discharge
piping first appears in the drawing in Revision 7, dated March 5, 1968. In this drawing,
the as-found piping configuration was depicted (pipes terminated at the bottom of the
canal, 6 inches apart). The architect-engineer then performed an options analysis of
different piping configurations in an effort to reduce the impact of siltation on the service
water piping, resulting in the recommendation that Nebraska Public Power District
separate the pipes by 24 feet and move their termination point to high on the west bank
of the discharge canal to avoid siltation and the likelihood of common mode failure. This
recommendation was reflected in BR 2120 Revision 13, July 12, 1970. The change
notes on the drawing indicated that the purpose of the revision was changed
termination point of 24 SW-2/CW-2 lines.
The licensees decision regarding this option was documented in Burns and Roe Design
Information Notice 2978-02, July 31, 1973, which states the following:
NPPD has approved the revised SW-2/CW-2 discharge piping into the circ water
discharge canal generally as shown in study dwg 264. Please show the revised
piping such that the 24 CW-2 discharges through the side of the canal rip rap at
center line elevation 867, approximately 2 feet past the rip rap.
Based on this discussion, BR 2120 was updated in Revision 14 to label BR 2120 as a
construction document versus a design sketch. A subsequent Burns and Roe
memorandum dated August 2, 1973, however, documents the following:
The service water piping into the discharge canal has been modified to prevent
silt blockage of the exit piping by rerouting piping through the side of the
discharge canal at an elevation 7 feet above the bottom of the canal. This is
being held in abeyance by NPPD.
The memo contained no discussion of why the design change was being held in
abeyance. The licensee was unable to find any records to help understand the rationale
for not implementing the design change. The net result is that BR 2120 reflected a
planned, but never implemented, design change to the service water system discharge
piping. No further changes were made for BR 2120 until after the discovery of the
configuration error in October 2009.
Although the licensee identified that the discharge lines were not depicted on Drawing
BR 2120, the inspectors added value by identifying that BR 2120 had been used as a
design input into NEDC 92-034, Water Hammer Analysis of Service Water System.
NEDC 92-034 is a design basis calculation that was performed to document the
-8- Enclosure
response of the service water system to potential water hammer affects during design
basis events. This calculation depended on an analytical model of the service water
system that was developed based upon available drawings, one of which was BR 2120;
however, BR 2120 contained substantial errors in that it documented the wrong
elevation of the discharge point and did not include several ninety degree pipe bends
that exist in the as-built piping. As a result, the calculation result was called into
question by the inspectors.
In response to this question, the licensee initiated CR-CNS-2010-03689 and completed
an operability evaluation that demonstrated that the service water system was operable
despite this unanalyzed condition. Additional corrective actions have since been
identified, including an action to re-perform the affected calculation. Additionally, an
extent of condition review by the licensee identified five other calculations that appear to
have used BR 2120 as a design input.
The inspectors determined that this represented a failure to document the plant design in
applicable drawings. Reviews by the inspectors did not identify any recent opportunities
to discover the error prior to October 2009.
Analysis. The inspectors determined that the finding is a performance deficiency in that
the licensee failed to maintain accurate design drawings of the service water system
discharge piping. The finding was more than minor because it affected the design
control attribute of the mitigating systems cornerstone, and adversely affected the
cornerstone objective to ensure the availability, reliability, and capability of systems that
respond to initiating events to prevent undesirable consequences (i.e., core damage).
This finding was characterized under the significance determination process as having
very low safety significance because all of the screening questions in the Manual
Chapter 0609, Attachment 4, Initial Screening and Characterization of Findings
Phase 1 screening table were answered in the negative. The inspectors determined that
no cross cutting aspect was applicable to this finding due to the age of the performance
deficiency and the lack of recent identification opportunities.
Enforcement. 10 CFR 50 Appendix B, Criterion III, Design Control, requires, in part,
that measures shall be established to assure that the design basis for structures,
systems, and components that could prevent or mitigate the consequences of postulated
accidents are correctly translated into drawings. Contrary to this requirement, from the
beginning of power operations on January 18, 1974, to present, the plant drawings used
to document the design of the service water discharge piping were incorrect. As a
result, incorrect information was used as in input to numerous essential calculations and
analyses. Because the finding is of very low safety significance and has been entered
into the licensees corrective action program as CR-CNS-2010-03689, this violation is
being treated as an NCV consistent with Section VI.A of the Enforcement Policy:
NCV 05000298/2010003-01, "Failure to Document Design of Service Water Discharge
Piping in Plant Drawings.
-9- Enclosure
.2 Complete Walkdown
a. Inspection Scope
On April 14, 2010, the inspectors performed a complete system alignment inspection of
the Reactor Core Isolation Cooling system to verify the functional capability of the
system. The inspectors selected this system because it was considered both safety
significant and risk significant in the licensees probabilistic risk assessment. The
inspectors inspected 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. The inspectors
reviewed a sample of past and outstanding work orders to determine whether any
deficiencies significantly affected the system function. In addition, the inspectors
reviewed the corrective action program database to ensure that system equipment-
alignment problems were being identified and appropriately resolved. Specific
documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of one complete system walkdown sample as
defined in Inspection Procedure 71111.04-05.
b. Findings
No findings were identified.
1R05 Fire Protection (71111.05)
Quarterly Fire Inspection Tours
a. Inspection Scope
The inspectors conducted fire protection walkdowns that were focused on availability,
accessibility, and the condition of firefighting equipment in the following risk-significant
plant areas:
April 7, 2010, Diesel generator 1B room, Zone 14B
April 7, 2010, Diesel generator 1B diesel oil day tank room, Zone 14D
April 14, 2010, Reactor building 859 feet 9 inch level, Zone 1B
April 14, 2010, Hydraulic drive pump room, Zone 1G
The inspectors reviewed areas to assess if licensee personnel 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 had 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
- 10 - Enclosure
as documented in the plants Individual Plant Examination of External Events with later
additional insights, their potential to affect equipment that could initiate or mitigate a
plant transient, or their impact on the plants ability to respond to a security event. Using
the documents listed in the attachment, 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 corrective action program.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four quarterly fire-protection inspection samples
as defined in Inspection Procedure 71111.05-05.
b. Findings
No findings were identified.
1R11 Licensed Operator Requalification Program (71111.11)
a. Inspection Scope
On April 13, 2010, and June 9, 2010, the inspectors observed a crew of licensed
operators in the plants simulator 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
Crews ability to take timely actions in the conservative direction
Crews prioritization, interpretation, and verification of annunciator alarms
Crews correct use and implementation of abnormal and emergency procedures
Control board manipulations
Oversight and direction from supervisors
Crews ability to identify and implement appropriate technical specification
actions and emergency plan actions and notifications
- 11 - Enclosure
The inspectors compared the crews performance in these areas to pre-established
operator action expectations and successful critical task completion requirements.
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of two quarterly licensed-operator requalification
program samples as defined in Inspection Procedure 71111.11.
b. Findings
No findings were identified.
1R12 Maintenance Effectiveness (71111.12)
a. Inspection Scope
The inspectors evaluated degraded performance issues involving the following risk
significant systems:
April 25, 2010, Barksdale pressure switch failures
May 12, 2010, Extent of condition review of RHR-MOV functional failure
evaluations
May 13, 2010, Safety relief pilot valve test failures
June 3, 2010, RHR-MO-15D valve failure to open functional failure evaluations
The inspectors reviewed events such as where ineffective equipment maintenance has
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)
Characterizing system reliability issues for performance
Charging unavailability for performance
Trending key parameters for condition monitoring
Ensuring proper classification in accordance with 10 CFR 50.65(a)(1) or -(a)(2)
Verifying appropriate performance criteria for structures, systems, and
components classified as having an adequate demonstration of performance
- 12 - Enclosure
through preventive maintenance, as described in 10 CFR 50.65(a)(2), or as
requiring the establishment of appropriate and adequate goals and corrective
actions for systems classified as not having adequate performance, as described
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 corrective action program with the appropriate
significance characterization. Specific documents reviewed during this inspection are
listed in the attachment.
These activities constitute completion of four quarterly maintenance effectiveness
samples as defined in Inspection Procedure 71111.12-05.
b. Findings
Introduction. The inspectors identified a Green noncited violation of 10 CFR 50.65(a)(2),
requirements for monitoring the effectiveness of maintenance at nuclear power plants,
for failure to demonstrate that the performance of the essential 4160 volt alternating
current power system was effectively controlled through appropriate preventive
maintenance. As a result, the licensee did not establish goals or monitor the
performance of the essential power system Agastat relays per 10 CFR 50.65(a)(1) to
ensure appropriate corrective actions were initiated when a revised evaluation of a
Agastat time delay relay failure incorrectly changed the initial functional failure
determination. Incorrectly changing this maintenance preventable functional failure
resulted in the affected function, EE-PF03A, not reaching the licensees maintenance
rule (a)(1) threshold.
Description. The licensee had two functional failures associated with the 4160 volt
essential power supply function EE-PF03A in 2008. EE-PF03As function is to provide
essential 4160 volt alternating current power to the Division 1 critical station electrical
auxiliary loads. These two functional failures exceeded the threshold to perform a
maintenance rule (a)(1) evaluation to determine if system performance was effectively
controlled through appropriate maintenance.
The first functional failure occurred March 3, 2008, when an Agastat time delay relay
failed repeated attempts to calibrate. This relay is required to open the Division 1 critical
feeder breaker on low voltage prior to the low voltage condition damaging essential
equipment such as the motors on emergency core cooling pumps. This was related to a
long standing problem with Agastat time delay relays having foreign material introduced
during manufacturing that introduced random changes in the timers countdown
performance. The licensee had been handling this issue for several years by frequent
preventative maintenance to monitor Agastat relays for normal wear and indications of
foreign material degraded performance. Therefore, this was a maintenance preventable
functional failure. Condition Report CR-CNS-2008-01352 was initiated to resolve this
problem.
- 13 - Enclosure
The second functional failure occurred October 28, 2008, when an essential service
water pump supply breaker failed to close and start the pump when loose screws on the
breakers micro switch prevented it from functioning. The loose screws were due to
inadequate oversight of the breaker refurbishment process and therefore, a maintenance
preventable functional failure. Condition Report CR-CNS-2008-07910 was initiated to
resolve this problem.
A December 23, 2008, licensees maintenance rule expert panel meeting determined
that these two maintenance rule preventable failures required placing the function
EE-PR03A in (a)(1) status to monitor the performance of the Division 1 essential
4160 volt alternating current supply against goals to ensure this system is capable of
fulfilling its function. Several months passed while the licensee attempted to determine
what would be the appropriate goals and corrective actions to address these functional
failures.
On March 23, 2009, the maintenance rule expert panel returned the function EE-PF03A
to (a)(2) status based on a revision of the March 3, 2008, Agastat relay functional failure
evaluation. This revised evaluation determined that the Agastat relay failure was not a
maintenance rule functional failure due to the failed relay timer results being less than
the design function time requirement of 17 seconds by 0.3 seconds. The 17 seconds is
the design basis time exposure below which essential motors are assumed to not be
damaged by undervoltage conditions. Based on this revised functional failure evaluation
conclusion, the relay was capable of providing adequate control for the associated
essential equipment and was not a functional failure. This lowered the EE-PF03A
function failures below the threshold that required meeting 10CFR50.65.(a)(1)
requirements. However, the inspectors identified that this evaluation used an invalid
assumption. It used data from the four failed attempts to calibrate an Agastat relay that
was operating unpredictably and required replacement. The use of this data was
determined to be unacceptable because it was obtained from a relay that was operating
unpredictably and required subsequent replacement. As such, the inspectors
determined that the revised functional failure was not valid. 10 CFR 50.65 (a)(2)
requires that the function EE-PR03A performance be effectively controlled through the
performance of appropriate preventative maintenance. The two functional failures
demonstrate that the requirements of (a)(2) were not being met. Therefore, the incorrect
assumption used in the revised fictional failure evaluation resulted in the Cooper Station
being in violation of 10 CFR 50.65(a)(2).
A problem identification and resolution inspection team noted similar issues with other
Agastat time delay relays during an inspection in March and April 2009. The results of
the teams finding is documented in Inspection Report 05000298/2009007 as a noncited
violation for the licensees failure to perform adequate operability determinations of
degraded and potentially degraded conditions associated with essential Agastat time
delay relays with internal foreign material contamination. One of the licensees
corrective actions was to implement a design change to replace 22 time critical Agastat
relays with digital time relays. The relay associated with the March 3, 2008, functional
failure was replaced with the digital upgrade in October 2009. The effectiveness of this
corrective action is monitored by the licensees corrective action program.
- 14 - Enclosure
Following the guidance of Appendix B to MC 0612 this finding is more than minor
because failure to monitor the effectiveness of the Division 1 essential 4160 volt
alternating current supply system affects the reliability objective of the Equipment
Performance attribute under the Mitigating Systems Cornerstone. This issue was
screened with the assistance of Inspection Procedure 71111.12, Maintenance
Effectiveness, Appendix D, Regulatory Review, that supplements the general
guidance of IMCs 0612 and 0609 by providing specific guidance on the disposition of
maintenance effectiveness issues. This is a Category II maintenance effectiveness
issue in that this failure to establish goals and monitoring for the essential 4160 volt
alternating current supply system is not attributable to poor Agastat relay performance
but a result of an inadequate licensee functional failure evaluation. Since the equipment
reliability problems were corrected by the licensees corrective action program via a
design change and the maintenance rule violation has occurred as a separate
consequence of the Agastat relay problems, this cannot be processed through the
significance determination process.
Analysis. The inspectors determined that the failure by licensee personnel to correctly
determine that the maintenance rule (a)(1) threshold had been reached was a
performance deficiency. This finding is more than minor because failure to monitor the
effectiveness of the essential 4160 volt alternating current function, EE-PF03A, affects
the reliability objective of the Equipment Performance attribute under the Mitigating
Systems Cornerstone. The inspectors determined that this performance deficiency was
an additional, but separate consequence of the degraded performance of the essential
4160 volt alternating current system Agastat relays. Following the guidance of
Appendix B to MC0612 and Appendix D to IP 71111.12, the inspectors determined that
this finding occurred as a consequence of actual problems with the Agastat relays, and
that those actual problems were not attributable to this finding. This finding therefore
cannot be processed through the significance determination process, and is considered
to be Green by NRC staff review. The finding has a crosscutting aspect in the area of
human performance associated with decision-making because the licensee did not use
conservative assumptions in the functional failure evaluation of a Agastat relay
failure H.1(b).
Enforcement. Title 10 CFR 50.65(a)(1) requires, in part, that holders of an operating
license shall monitor the performance or condition of structures, systems and
components within the scope of the rule as defined by 10 CFR 50.65(b), against
licensee-established goals, in a manner sufficient to provide reasonable assurance that
such structures, systems, and components are capable of fulfilling their intended safety
functions. 10 CFR 50.65(a)(2) states, in part, that monitoring as specified in
10 CFR 50.65(a)(1) is not required where it has been demonstrated that the
performance or condition of an system is being effectively controlled through the
performance of appropriate preventive maintenance, such that the system remains
capable of performing its intended function. Contrary to this requirement, from
December 28, 2008, to the present, the licensee did not demonstrate that the
performance of the 4160 volt alternating current system had been effectively controlled
through appropriate preventative maintenance and did not monitor against
- 15 - Enclosure
licensee-established goals in a manner sufficient to provide reasonable assurance that
the essential electrical supply system was capable of fulfilling its intended safety
functions. Specifically, the licensee failed to identify and properly account for
maintenance preventable functional failures that occurred March 3, 2008 and
October 28, 2008, that demonstrated that the performance of the Division 1 essential
4160 volt alternating current system was not being effectively controlled through the
performance of appropriate preventative maintenance and, as a result, that goal setting
and monitoring was required. Because the finding is of very low safety significance and
has been entered into the licensees corrective action program as CR-CNS-2010-5587,
this violation is being treated as a noncited violation consistent with Section VI.A.1 of the
NRC Enforcement Policy: NCV 05000298/2010003-02, Failure to Place the essential
4160 volt alternating current system Agastat relays in (a)(1).
1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)
a. Inspection Scope
The inspectors reviewed licensee personnel'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:
April 6, 2010, Diesel generator 1 work window
May 11, 2010, High pressure coolant injection filter inspection
June 3, 2010, Diesel generator 2 walkdown without Control Room notification
during Yellow window with diesel generator 1 I lockout
June 8-9, 2010, Reactor recirculation motor generator pump B maintenance and
return to service
The inspectors selected these activities based on potential risk significance relative to
the reactor safety cornerstones. As applicable for each activity, the inspectors verified
that licensee personnel performed risk assessments as required by 10 CFR 50.65(a)(4)
and that the assessments were accurate and complete. When licensee personnel
performed emergent work, the inspectors verified that the licensee personnel promptly
assessed and managed plant risk. 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 the technical specification requirements
and inspected portions of redundant safety systems, when applicable, to verify risk
analysis assumptions were valid and applicable requirements were met. Specific
documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four maintenance risk assessments and
emergent work control inspection samples as defined in Inspection
Procedure 71111.13-05.
- 16 - Enclosure
b. Findings
No findings were identified.
1R15 Operability Evaluations (71111.15)
a. Inspection Scope
The inspectors reviewed the following issues:
April 9, 2010, Service water discharge piping
April 21, 2010, RHR-MO-15D failure
May 20, 2010, Service water booster pump D water in oil
May 20, 2010, RHR-A motor heater wiring discolored
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 technical specification 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 technical specifications and UFSAR to
the licensee personnels 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 also reviewed a sampling of corrective action documents to verify that the
licensee was identifying and correcting any deficiencies associated with operability
evaluations. Specific documents reviewed during this inspection are listed in the
attachment.
These activities constitute completion of four operability evaluations inspection
sample(s) as defined in Inspection Procedure 71111.15-04
b. Findings
No findings were identified.
1R19 Postmaintenance Testing (71111.19)
a. Inspection Scope
The inspectors reviewed the following postmaintenance activities to verify that
procedures and test activities were adequate to ensure system operability and functional
capability:
May 5, 2010, Service water pump C impeller lift
May 7, 2010, Diesel generator fuel oil modification testing
- 17 - Enclosure
May 11, 2010, High pressure coolant injection filter inspection
May 13, 2010, Reactor building crane postmaintenance test
May 20, 2010, H intermediate range monitor post maintenance testing
May 21, 2010, Ronan power supply replacement post maintenance testing
The inspectors selected these activities based upon the structure, system, or
component's ability to affect 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
The inspectors evaluated the activities against the technical specifications, the Updated
Final Safety Analysis Report, 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 postmaintenance tests
to determine whether the licensee was identifying problems and entering them in the
corrective action program and that the problems were being corrected commensurate
with their importance to safety. Specific documents reviewed during this inspection are
listed in the attachment.
These activities constitute completion of six postmaintenance testing inspection samples
as defined in Inspection Procedure 71111.19-05.
b. Findings
No findings were identified.
1R22 Surveillance Testing (71111.22)
a. Inspection Scope
The inspectors reviewed the Updated Final Safety Analysis Report, procedure
requirements, and technical specifications to ensure that the surveillance activities listed
below demonstrated that the systems, structures, and/or components tested were
capable of performing their intended safety functions. The inspectors either witnessed
or reviewed test data to verify that the significant surveillance test attributes were
adequate to address the following:
Preconditioning
Evaluation of testing impact on the plant
- 18 - Enclosure
Acceptance criteria
Test equipment
Procedures
Jumper/lifted lead controls
Test data
Testing frequency and method demonstrated technical specification operability
Test equipment removal
Restoration of plant systems
Fulfillment of ASME Code requirements
Updating of performance indicator data
Engineering evaluations, root causes, and bases for returning tested systems,
structures, and components not meeting the test acceptance criteria were correct
Reference setting data
Annunciators and alarms setpoints
The inspectors also verified that licensee personnel identified and implemented any
needed corrective actions associated with the surveillance testing.
April 21, 2010, Residual heat removal pump D, motor operator 15D failure
May 12, 2010, Diesel generator fuel oil special test
May 25, 2010, Performance of offsite AC power alignment to support 6.1DG.301
May 26, 2010, Reactor coolant system leak rate checks
Specific documents reviewed during this inspection are listed in the attachment.
These activities constitute completion of four surveillance testing inspection samples as
defined in Inspection Procedure 71111.22-05.
b. Findings
No findings were identified.
- 19 - Enclosure
4. OTHER ACTIVITIES
4OA1 Performance Indicator Verification (71151)
.1 Safety System Functional Failures (MS05)
a. Inspection Scope
The inspectors sampled licensee submittals for the safety system functional failures
performance indicator for the period from the second quarter 2009 through the first
quarter. To determine the accuracy of the performance indicator data reported during
those periods, the inspectors used definitions and guidance contained in NEI Document
99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, and
NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 50.73." The inspectors
reviewed the licensees operator narrative logs, operability assessments, maintenance
rule records, maintenance work orders, issue reports, event reports, and NRC integrated
inspection reports for the period of April 2009 through March 2010, to validate the
accuracy of the submittals. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the performance
indicator data collected or transmitted for this indicator and none were identified.
Specific documents reviewed are described in the attachment to this report.
These activities constitute completion of one safety system functional failure sample as
defined in Inspection Procedure 71151-05.
b. Findings
No findings were identified.
.2 Reactor Coolant System Specific Activity (BI01)
a. Inspection Scope
The inspectors sampled licensee submittals for the reactor coolant system specific
activity performance indicator for the period from the second quarter 2009 through the
second quarter 2010. To determine the accuracy of the performance indicator data
reported during those periods, the inspectors used definitions and guidance contained in
NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline,
Revision 6. The inspectors reviewed the licensees reactor coolant system chemistry
samples, technical specification requirements, issue reports, event reports, and NRC
integrated inspection reports for the period of March 2009 through May 2010, to validate
the accuracy of the submittals. The inspectors also reviewed the licensees issue report
database to determine if any problems had been identified with the performance
indicator data collected or transmitted for this indicator and none were identified. In
addition to record reviews, the inspectors observed a chemistry technician obtain and
analyze a reactor coolant system sample. Specific documents reviewed are described
in the attachment to this report.
- 20 - Enclosure
These activities constitute completion of one reactor coolant system specific activity
samples defined in Inspection Procedure 71151-05.
b. Findings
No findings were identified.
.3 Reactor Coolant System Leakage (BI02)
a. Inspection Scope
The inspectors sampled licensee submittals for the reactor coolant system leakage
performance indicator for the period from the second quarter 2009 through the second
quarter 2010 To determine the accuracy of the performance indicator data reported
during those periods, the inspectors used definitions and guidance contained in NEI
Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6.
The inspectors reviewed the licensees operator logs, reactor coolant system leakage
tracking data, issue reports, event reports, and NRC integrated inspection reports for the
period of March 2009 through May 2010, to validate the accuracy of the submittals. The
inspectors also reviewed the licensees issue report database to determine if any
problems had been identified with the performance indicator data collected or
transmitted for this indicator and none were identified. Specific documents reviewed are
described in the attachment to this report.
These activities constitute completion of one reactor coolant system leakage sample as
defined in Inspection Procedure 71151-05.
b. Findings
No findings were identified.
4OA2 Identification and Resolution of Problems (71152)
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical
Protection
Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a review of the licensees corrective action program and
associated documents to identify trends that could indicate the existence of a more
significant safety issue. The inspectors focused their review on repetitive equipment
issues, but also considered the results of daily corrective action item screening
discussed in Section 4OA2.2, above, licensee trending efforts, and licensee human
performance results. The inspectors nominally considered the 6-month period of
- 21 - Enclosure
October 2009 through March 2010 although some examples expanded beyond those
dates where the scope of the trend warranted.
The inspectors also included issues documented outside the normal corrective action
program in major equipment problem lists, repetitive and/or rework maintenance lists,
departmental problem/challenges lists, system health reports, quality assurance
audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.
The inspectors compared and contrasted their results with the results contained in the
licensees corrective action program trending reports. Corrective actions associated with
a sample of the issues identified in the licensees trending reports were reviewed for
adequacy.
These activities constitute completion of one single semi-annual trend inspection
samples as defined in Inspection Procedure 71152-05.
b. Findings and Observations
No findings were identified. The inspectors evaluated the licensees trending
methodology and observed that the licensee had performed a detailed review. The
licensee routinely review cause codes, involved organizations, key words, and system
links to identify potential trends in their corrective action program data. The inspectors
compared the licensee process results with the results of the inspectors daily screening
and did not identify any discrepancies or potential trends in the corrective action program
data that the licensee had failed to identify. The inspectors did, however, identify
additional insights into several of these issues as documented below:
Human Error Prevention Techniques Substantive Cross-Cutting Issue Review.
The NRC identified a crosscutting theme associated with the work practices component
of the human performance area related to the use of human error prevention techniques
H.4(a) in 2008. Since the licensee recognized the theme and developed corrective
actions, a crosscutting issue was not identified for the 2008 human performance issue.
During the 2009 assessment period seven findings were identified with the crosscutting
aspect related to the use of human error prevention techniques. Five of these occurred
following full implementation of the licensees corrective actions. Based on these
findings with the repeated common theme, the NRC staff identified a substantive
crosscutting issue in the human performance area associated with work practices
related to the use of human error prevention techniques at Cooper Nuclear
Station H.4(a). These findings occurred in initiating events, barrier integrity and
occupational radiation safety cornerstones. This baseline inspection semi annual trend
continues to monitor for sustainable performance improvements as evidenced by
effective implementation of an appropriate corrective action plan that results in no safety
significant inspection findings and a notable reduction in the overall number of inspection
findings with the same common theme.
A comparison of the licensees human performance trends from their condition report
record in 2009 versus the trends from early 2010 was performed. Consequential human
- 22 - Enclosure
errors and non-consequential human errors were higher in 2009 than 2010. The
majority of 2009 errors were during the fall 2009 refueling outage, as expected, due to
the large number of activities performed during an outage versus normal plant operation.
The same effect was noted for procedure quality and adherence issues with an
increasing trend during the fourth quarter 2009 compared to a decreasing trend during
the first quarter 2010.
The licensee improvement plan while mainly implemented has a few actions that are completing
during June and July 2010. This is a non-refueling year for the licensee. The gross number of
maintenance activities is substantially lower and so the opportunities for human performance
errors are correspondingly lower. Based on the lower number of activities performed during full
power operations compared to a refueling outage and the need to allow time to observe the
effectiveness of the licensee improvement plan the NRC will continue to monitor the licensees
progress via the baseline inspection program.
Trend in Inadequate Apparent Cause Reviews:
During routine corrective action program document reviews, the inspectors noted that the
apparent cause evaluation performed under CR-CNS-2010-02875 had been flagged as
inadequate during the licensees effectiveness review. The inspectors noted that Corrective
Action Program Desk Guide #7, Just in Time (JIT) Training for Apparent Causes, Revision 0,
requires apparent cause evaluators to receive just-in-time training prior to performing this
activity. In the case of CR-CNS-2010-02875 the inspectors noted that the apparent cause
evaluator had been exempted from the licensees normal just-in-time training. As a result, the
inspectors reviewed the results of apparent cause effectiveness evaluations for the previous
year and discovered that eleven apparent cause evaluations had been flagged as inadequate.
Four of these were performed by persons who were exempted from the required just-in-time
training. Another five inadequate evaluations were performed by persons who received the
training via a video tape versus in person. Lastly, the inspectors noted that one individual had
been flagged for an inadequate evaluation on three separate occasions in the past year but had
received the initial just in time training prior to performing each of the inadequate evaluations.
The inspectors also noted that the licensee had made no attempt to evaluate this adverse trend
or take any corrective actions to improve performance. The inspectors determined that the
record of inadequate apparent cause evaluations reveals several potential gaps in the
administration of the just-in-time training required by Desk Guide #7.
Trend in Back Leakage into F Sump:
The inspectors reviewed the collection of drywell unidentified leak rate data for adverse trends.
The licensees F sump collects unidentified leakage in the drywell, and a pair of pumps
remove the water by pumping it to the liquid radwaste system. A flow totalizer measures the
total volume of water pumped every eight hours, and from this a measured unidentified leak rate
is determined to satisfy technical specification surveillance requirements. The discharge lines
from each pump contain a check valve to prevent back leakage into the sump from the liquid
radwaste system. These check valves have been historically poor at preventing back leakage.
On at least four occasions in previous twelve months, operators questioned the accuracy of the
- 23 - Enclosure
measured leak rate and isolated the pump discharge lines in order to determine a meaningful
leak rate.
The back leakage problem has routinely caused the measured leak rate to be off by over 0.1
gpm.
The inspectors reviewed Regulatory Guide 1.45, Reactor Coolant Pressure Boundary Leakage
Detection Systems, May 1973, which establishes sensitivity requirements for leak rate sensing
systems of Coopers vintage. Even with the worst case back leakage seen to date, the licensee
still satisfied the required instrument sensitivity of detecting a one gpm leak rate in less than one
hour. The back leakage problem, however, has caused unnecessary entries into Procedure 0-
CNS-OP-109, Drywell Leakage Investigation, to look for leakage that did not exist. Procedural
0-CNS-OP-109 requires operators to begin looking for leak sources when measured leakage
exceeds 0.25 gpm. The back leakage issue has caused operators to question the measured
leak rate and become accustomed to routinely entering Procedure 0-CNS-OP-109. This
effectively desensitizes control room operators to small changes in drywell unidentified leak rate
and could interfere with prompt identification of developing reactor coolant system leakage.
The licensee has a standing maintenance task to replace the leaking check valves each outage,
but this strategy has not been successful in eliminating the back leakage issue. The licensee
has planned a modification to be implemented in Refueling Outage 26, which will replace the
existing valves with a soft-seated design. The inspectors noted that this modification was also
planned for Refueling Outage 25, but was deferred due to having minimal beneficial value as
described in the response to CR-CNS-2009-00003.
4OA3 Event Follow-up (71153)
.1 (Closed) Licensee Event Report 05000298/2010-001-00, Safety Relief Valves Test
Exceeded Technical Specification Limits
a. Inspection Scope
On January 12, 2010, two safety relief valve pilot assemblies as-found pressure
setpoints exceeded the technical specification SR 3.4.3.1 limits when tested in a test
shop. Three safety relief valves and five safety relief valves pilot assemblies were
removed during the licensees fall 2009 refueling outage. The replacement pilot
assemblies installed during the fall 2009 refueling outage were refurbished and certified
to lift within the setpoint acceptance criteria prior to installation. The licensee
investigation determined the failures were due to pilot disc-to-seat corrosion bonding. A
corrective action that has not been fully implemented was developed from previous
failures described in LER 2008-002-00. This action is to submit a technical specification
license amendment to allow one or two failures out of the eight total safety relief valves
without exceeding technical specification limits. No new findings were identified in the
inspectors review. This finding constitutes a minor violation of Technical Specification
Surveillance Requirement 3.4.3.1. that is not subject to enforcement action in
accordance with Section IV of the NRC's Enforcement Policy. This Licensee Event
Report is closed.
- 24 - Enclosure
b. Findings
No findings were identified.
.2 Work Preparation Activities Cause Unplanned Increase in Reactor Power
a. Inspection Scope
On April 28, 2010, a work planner affected a leaking feedwater heater control valve
during a planning walkdown. The reactivity increase due to the change in feedwater
temperature caused the reactor to exceed the licensed thermal power limit of 2419 MWt
until reactor operators reduced power. The event was reviewed by the inspectors and a
green noncited violation was identified for the licensees failure prevent the operation of
plant equipment of which may affect the reactivity or power level of a reactor without the
knowledge and consent of a licensed operator or senior operator present at the controls.
This finding is described below.
b. Findings
Introduction. A Green self-revealing noncited violation of 10 CFR 50.54.j was identified
when a work planner caused a feedwater heater trip by touching a pressure regulating
valve without the knowledge of the control room. The reactivity increase due to the
change in feedwater temperature caused the reactor to exceed the licensed thermal
power limit of 2419 MWt until reactor operators reduced power.
Description. On April 28, 2010, a work planner was preparing a work package for repair
of an air leak on CNS-0-CD-PRV-PRV10, the pressure regulating valve for the
A5 feedwater heater level control valve. While walking down the area of the repair, the
planner observed that the leak was larger than expected. The planner then applied
pressure with his hands around the gasket in the vicinity of the leak. He did not report or
request permission for this action from the control room. When he covered the leak with
his hands, the change in leak rate resulted in a transient of the level control valve signal.
The signal transient caused the level in the A5 heater to drop by dumping condensate to
the A3 heater. The A3 feedwater heater has been operated with the level control valve
in manual since November 30, 2009, due to excessive cycling of the associated level
control valve; therefore, the A3 heater did not automatically respond to the rapid
increase in level. The control room received both the A5 HEATER LOW LEVEL and
A3 HEATER HIGH LEVEL alarm at 8:24 a.m. The A3 HEATER HIGH LEVEL TRIP
alarm came in 1 minute later. Over the next 30 minutes, the operators attempted to
stabilize feedwater heater levels. The feedwater heater trip and level transients resulted
in an approximately 0.8°F drop in feedwater temperature, which caused an increase in
reactor power to 2421 MWt. The operators immediately reduced power with
recirculation pumps to 2419 MWt.
In response to the event, the licensee performed an apparent cause evaluation and a
human performance evaluation. The human performance evaluation indicated that a
two-minute drill had not been performed. In the apparent cause evaluation, the
- 25 - Enclosure
licensee stated the planner had exceeded the scope of job by touching the component
instead of visually inspecting it. The licensee also stated in the evaluation that
interviews with valve team personnel revealed that they had cautioned a non-licensed
operator the previous day about not touching the pressure relief valve due to the
potential to affect the air control signal. The licensees corrective actions included
coaching the work planner, training plant personnel on the potential for causing a plant
transient during system walkdowns, and establishing pre-job briefs for the planning
department. In addition, caution tape was placed around the pressure regulating valve.
Analysis. The licensee failing to ensure that mechanisms which may affect reactivity
were manipulated only with the knowledge and consent of a licensed operator at the
controls was a performance deficiency. The finding was more than minor because the
performance deficiency could be reasonably viewed as a precursor to a significant event
in that a reactor power transient was initiated without the knowledge of the control room.
Using Manual Chapter 0609.04 this finding was characterized under the significance
determination process as having very low safety significance because while the finding
degraded the transient initiator contributor function of the initiating events cornerstone, it
did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation
equipment or functions will not be available. The inspectors determined that this finding
has a crosscutting aspect in the area of human performance associated with the work
practices component because the work planner proceeded in the face of unexpected
circumstances by exceeding the scope of the job when he found the leak was greater
than expected H.4(a).
Enforcement. 10 CFR 50.54.j requires, in part, that apparatus and mechanisms other
than controls, the operation of which may affect the reactivity or power level of a reactor,
shall be manipulated only with the knowledge and consent of a licensed operator or
senior operator present at the controls. Contrary to the above, on April 28, 2010, a work
planner manipulated the instrument air system, without the knowledge and consent of a
licensed operator or senior operator present at the controls, causing a feedwater
transient and reactivity change. However, because this inspection finding was
characterized by the significance determination process as having very low risk
significance (Green) and has been entered in the licensees corrective action program as
CR CNS-2010-03091, this violation is being treated as a noncited violation, consistent
with Section IV.A.1 of the NRC Enforcement Policy: NCV 05000298/2010003-03, Work
Preparation Activities Cause Unplanned Increase in Reactor Power.
4OA5 Other Activities
Failure to Perform Required Maintenance Causes Unplanned Down Power
a. Inspection Scope
On May 1, 2010, control room operators initiated a rapid power reduction after receiving
trip alarms on the A1 and A2 traveling water screens and subsequent loss of vacuum on
the main condenser. After stabilizing power below the capacity of two circulating water
pumps, operators tripped the A circulating water pump. The licensees investigation
determined that the cause of the traveling water screen trip was accumulated debris in
- 26 - Enclosure
the screen debris trough as a result of failing to perform the required routine
maintenance on the traveling water screens.
b. Findings
Introduction. A Green self-revealing finding was identified for the licensees failure to
implement the preventive maintenance requirements of the vendor manual for the plant
traveling water screens. Specifically, Vendor Manual 140, Traveling Water Screen,
Revision 35, contained daily and weekly routine maintenance requirements to open the
channel-flushing valve to clear any accumulated debris from the screens. Despite the
fact that the licensee incorporated this vendor manual into their preventive maintenance
system, this maintenance requirement was overlooked. The failure to perform this
maintenance task led to the trip of the A1 and A2 traveling water screens on
May 1, 2010, and required an emergent power reduction.
Description. On May 1, 2010, the Missouri River was in the midst of a level transient,
during which a large amount of debris was entering the intake structure and was being
removed by the traveling water screens. At the time of the event, only three of the
plants four circulating water pumps were available due to maintenance activities
affecting the fourth pump. Each circulating water pump can draw its required flow from
one of two traveling water screens (there are two dedicated screens per pump).
The event began when control room operators received alarms suggesting that the A1
traveling water screen had tripped, followed shortly by similar alarms for the A2 screen.
Operators made a failed attempt to restart the tripped screens but were unsuccessful.
Operators entered Abnormal Operating Procedure 2.4VAC and recognized degrading
vacuum on the main condenser. As a result, operators began a rapid power reduction to
avoid a low-vacuum turbine trip. After reducing power to approximately seventy percent
(within the capacity of two circulating water pumps), operators tripped the A circulating
water pump from the control room.
Operators immediately inspected the A1 and A2 screens, and found an accumulation of
river debris inside the debris flushing trough. The debris created drag on the screen
baskets. This increased drag had caused the A1 screen to trip. When the full flow of
the A circulating water pump was then diverted to the A2 screen, the high debris loading
on the screens caused a high differential pressure trip of the A2 screen. After clearing
the debris from the A1 screen, operators were again able to restore a two-screen lineup
for the A circulating water pump, start the pump, and return the plant to full power.
In the root cause investigation performed under CR-CNS-2010-03195, the evaluators
identified that the applicable vendor manual had identified a list of routine maintenance
tasks. The evaluators identified the following daily maintenance task that was never
incorporated into the licensees preventive maintenance program or system operating
procedures:
Check that debris is being washed off the screen into the debris channel and
that the channel is clear. Briefly open the channel-flushing valve if necessary.
- 27 - Enclosure
Additionally, the following weekly task was also omitted:
Open the flushing valves on the wash water jet pipes for approximately fifteen
(15) seconds to clear any accumulated debris.
The inspectors reviewed Change Evaluation Document 6014001, Traveling Water
Screens Replacement, April 19, 2005, and learned that the modification package
incorporated most of the maintenance tasks from the vendor manual, but was silent on
operation of the channel-flushing valve. Interviews with licensee personnel suggested
that this may have been due to a misunderstanding of the normal system lineup, or just
an oversight on the part of the evaluator. Regardless of the cause, the net effect was
that the design process never identified the need to routinely open the channel-flushing
valve and led directly to the screen failure on May 1, 2010.
The inspectors determined that the age of the performance deficiency and lack of recent
opportunities to discover this error suggested that this performance deficiency is not
indicative of current performance.
In response to this event, the licensee performed a review of the applicable vendor
manual preventive maintenance and instituted a nightly task to inspect the debris
channel and cycle the channel flushing valves for each traveling water screen. The
licensee also initiated actions to perform an extent of cause check of other important
equipment that had been recently installed to ensure appropriate vendor recommended
maintenance requirements have been implemented.
Analysis. The licensees failure to implement the required routine maintenance for the
traveling water screens is a performance deficiency. The finding was more than minor
because it affected the equipment performance attribute of the initiating events
cornerstone, and adversely affected the cornerstone objective to limit the likelihood of
those events that upset plant stability and challenge critical safety functions during
shutdown as well as power operations. Using Manual Chapter 0609.04 this finding was
characterized under the significance determination process as having very low safety
significance because it did not contribute to both the likelihood of a reactor trip and the
likelihood that mitigation functions would be unavailable. The inspectors determined that
no crosscutting aspect was applicable to this finding because the performance
deficiency was not reflective of current performance.
Enforcement. Enforcement action does not apply because the performance deficiency
did not involve a violation of a regulatory requirement. Because this finding does not
involve a violation of regulatory requirements and has very low safety significance, it is
identified as FIN 05000298/2010003-04, "Failure to Perform Required Maintenance
Causes Unplanned Down Power.
- 28 - Enclosure
4OA6 Meetings
Exit Meeting Summary
On July 1, 2010, the inspectors presented the inspection results to Mr. Brian OGrady, and other
members of the licensee staff. The licensee acknowledged the issues presented. The
inspector asked the licensee whether any materials examined during the inspection should be
considered proprietary. No proprietary information was identified.
On July 12, 2010, the inspectors conducted a telephonic exit meeting to present changes in the
inspection results to Mr. Dave VanDerKamp. The licensee acknowledged the changes to the
issues presented. The inspector asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was identified.
- 29 - Enclosure
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
A. Able, Instrument & Control Engineering Supervisor, Design Engineering Department
D. Anderson, Supervior, ALARA
J. Austin, Manager, Emergency Preparedness
D. Buman, Director of Engineering
B. Chapin, Manager, Outage
R. Dewhirst, Senior Project Manager
R. Estrada, Manager, Design Engineering
K. Fike, Plant Chemist, Chemistry Department
J. Flaherty, Licensing
S. Freborg, ESD Mechanical Programs Supervisor
G. Gardner, NSSS Supervisor, System Engineering Department
K. Gehring-Ohrablo, Chem Tech, Chemistry Department
T. Hough, Maintenance Rule Coordinator
N. Joergensen, Design Engineer
L. Keiser, SW and RHR System Engineer
D. Kirkpatrick, Technician, Radiation Protection
P. Leininger, Erosion/Corrosion Program Engineer
D. McMahon, REC System Engineer
A. Meinke, Chemistry Engineer, Chemistry Department
M. Metzger, System Engineer
D. Madsen, Licensing
D. Parker, Manager, Maintenance
R. Penfield, Manager, Operations
A. Sarver, BOP/Elect/I&C Supervisor, System Engineering Department
K. Tanner, Supervisor, Radiation Protection
J. Teten, Chemistry Supervisor
D. VanDerKamp, Licensing Manager
J. Webster, Director of Projects, Project Department
R. Wulf, SED Manager
A. Zaremba, Director Nuclear Safety Assurance
NRC Personnel
Runyan, Mike, Senior Risk Analyst
A-1 Attachment
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
Failure to Document Design of Service Water Discharge Piping in
Plant Drawings
Failure to Place the Essential 4160 Volt Alternating Current
System Agastat Relays in (a)(1)
Work Preparation Activities Cause Unplanned Increase in
Reactor Power
Failure to Perform Required Maintenance Causes Unplanned
Down Power
LIST OF DOCUMENTS REVIEWED
Section 1RO1: Adverse Weather Protection
MISCELLANEOUS DOCUMENTS
NUMBER TITLE DATE
EE-SY CNS System Health Report March 2010
Section 1RO1: Adverse Weather Protection
PROCEDURE
NUMBER TITLE REVISION
2.1.14 General Operating Procedure, Seasonal Weather 14
Preparations
5.1FLOOD Emergency Procedure, Flood 7
5.3GRID Emergency Procedure, Degraded Grid Voltage 29
7.0.11 Maintenance Procedure, Flood Control Barriers 9
A-2 Attachment
Section 1RO4: Equipment Alignment
MISCELLANEOUS DOCUMENTS
NUMBER TITLE REVISION /
DATE
Burns and Roe Design Information Notice, Service Water
7/31/73
System Modification Circ. Water Discharge Canal Piping
Core Spray Component Checklist 2
CNS-RCIC-1 Flow Diagram RCIC Turbine Lube Oil Subsystem 3/10/89
NEDC 92-034 Water Hammer Analysis of Service Water System 3C1
2043 Burns & Roe, Flow Diagram Reactor Core Isolation Coolant
NS4
and Reactor Feed Systems Cooper Nuclear Station
2044 Burns & Row, Cooper Nuclear Station Flow Diagram - High
N70
Pressure Coolant Injection and Reactor Feed System
2045 SH1 Core Spray System N58
95516C EG-R Governor Hydraulic System General Electric RCIC 2/08/74
Units
Section 1RO4: Equipment Alignment
PROCEDURE
NUMBER TITLE REVISION
2.2.33A System Operating Procedure, High Pressure Coolant
24
Injection System Component Checklist
2.2.67A CNS Operations Manual System Operating Procedure,
Reactor Core Isolation Cooling System Component 20
Checklist
3.7 Engineering Procedure, Drawing Change Notice 31
3.8 Engineering Procedure, Drawing Control 22
6.EE.610 Surveillance Procedure, Off-Site AC Power Alignment 24
CONDITION REPORT
CR-CNS-2009-02859 CR-CNS-2009-03689
A-3 Attachment
Section 1RO5: Fire Protection
MISCELLANEOUS DOCUMENTS
NUMBER TITLE DATE
FHA FA Drawing, FHA Matrix FA1-FZ1B 2/28/03
FHA FA Drawing, FHA Matrix FA1-FZ1G 2/28/03
93-15 Engineering Evaluation
NFPA 30 Flammable and Combustibles Liquids Code 1973 Edition
Section 1R11: Licensed Operator Requalification Program
LESSON
NUMBER TITLE REVISION
SKL0540132 0
Section 1R11: Licensed Operator Requalification Program
SCENARIO OVERVIEW
Aircraft Threat, Vehicle Accident Breaches Secondary Containment, Spurious Group 1
Isolation, Failure to Scram, Fuel Clad Failure
Section 1R12: Maintenance Effectiveness
NOTIFICATION
NUMBER TITLE
10711374
10727134 Component RHR-MO-MO15D, RHR Pump Shutdown
Cooling Suction Motor Operated Valve Functional Failure
Evaluations for Functions: RHR-PF01B, RHR-PR02B, RHR-
PF03B, RHR-PF04B and RHR-SD1
CONDITION REPORT
CR-CNS-2010-02334 CR-CNS-2010-02355 CR-CNS-2010-02709
A-4 Attachment
Section 1R13: Maintenance Risk Assessment and Emergent Work Controls
PROCEDURE
NUMBER TITLE REVISION
0.40.9 Administrative Procedure Work Activity Risk Management 2
Process
0.49 Administrative Procedure
CONDITION REPORT
WORK ORDER 4731476 473857
Section 1R15: Operability Evaluations
MISCELLANEOUS DOCUMENTS
NUMBER TITLE REVISION /
DATE
Nebraska Public Power District Letter, Response to Generic January 29,
Letter 89-13 1990
EN-OP-104 Operability Determinations 3
Section 1R15: Operability Evaluations
PROCEDURE
NUMBER TITLE REVISION
0.5.OPS Administrative Procedure, Operations Review of Condition 29
Reports/Operability Determination
2.0.11 Conduct of Operations Procedure, Entering and Exiting 27
Technical Specification/TRM/ODAM LCO Condition(s)
2.0.11.1 Conduct of Operations Procedure, Safety Function 4
Determination Program
CONDITION REPORT
CR-CNS-2006-00471 CR-CNS-2009-08848 CR-CNS-2010-02347 CR-CNS-2010-02529
CR-CNS-2010-02709 CR-CNS-2010-03592 CR-CNS-2010-03641
A-5 Attachment
Section 1R19: Postmaintenance Testing
MISCELLANEOUS DOCUMENTS
NUMBER TITLE REVISION
6.2 IRM.304 IRM Channel Calibration (Mode Switch in Run)(Div 2) 21
NEDC 91-045 Diesel Fuel Transfer Flow Rate with 8 3/8 Pump Impeller 1C1
Section 1R19: Postmaintenance Testing
PROCEDURE
NUMBER TITLE REVISION
3.4.7 Engineering Procedure, Design Calculations 31
6.1DG.401 Surveillance Procedure, Diesel Generator Fuel Oil Transfer 27
Pump IST Flow Test (Div 1)
6.1SW.101 Surveillance Procedure, Service Water Surveilllance 31
Operation (Div 1)(IST)
WORK ORDER 4625372 4656444 4664046 4731476 473857
Section 1R22: Surveillance Testing
PROCEDURE
NUMBER TITLE REVISION
6.EE.610 Surveillance Procedure, Off-Site AC Power Alignment 24
6.LOG.601 Surveillance Procedure, Daily Surveillance Log - Modes 1, 103
2, and 3, Attachment 3 Unidentified Leak Rate and
Attachment 4 Identified and Total Leak Rate Checks
6.1DG.401 Surveillance Procedure, Diesel Generator Fuel Oil Transfer 27
Pump IST Flow Test (Div 1)
6.2RHR.201 Surveillance Procedure, FHR Power Operated Valve 21
Operability test (IST)(Div 2)
A-6 Attachment
CONDITION REPORT
WORK ORDER 4705353 4705582
Section 4OA1: Performance Indicator Verification
MISCELLANEOUS DOCUMENTS
NUMBER TITLE DATE
8.4.1.1B Chemistry Report, Gamma Detector Nuclide Identification 5/20/10
Sheet for Reactor Iodine
Chemistry Department Dailies and Weeklies Hints Table 11/21/06
Chemistry Measurements Database (Open CDM) Sample 1/4/10-
Pint RX WATER 8.4.1.1.1/8.4.1.1.2/8.4.1.1.3 Dose 5/24/10
Equivalent Iodine 131
Pre-Job Brief worksheet for Reactor Water Sampling
Section 4OA1: Performance Indicator Verification
PROCEDURE
NUMBER TITLE REVISION
6.LOG.601 Surveillance Procedure, Daily Surveillance Log - Modes 1, 103
2, and 3 - Attachment 3 Unidentified Leak Rate Checks
and Attachment 4 Identified and Total Leak Rate Checks
8.4 Chemistry Procedure, Routine Sampling and Sample Valve 30
Control
8.8DWAM Chemistry Procedure, Particulate and Iodine Sample 2
Collection for Drywell Atmosphere Monitor
8.8.1.14 Chemistry Procedure, Radiochemical Iodines Analysis 16
Section 4OA2: Identification and Resolution of Problems
MISCELLANEOUS DOCUMENTS
TITLE
Primary Control Rod System Reports
A-7 Attachment
Section 4OA2: Identification and Resolution of Problems
PROCEDURE
NUMBER TITLE REVISION
6.1SW.101 Surveillance Procedure, Service Water Surveillance 31
Operation (Div 1)(IST)
CONDITION REPORT
CR-CNS-2010-02745 CR-CNS-2010-02875 CR-CNS-2010-02932 CR-CNS-2010-02935
A-8 Attachment