IR 05000247/2007003
Download: ML072200163
Text
August 8, 2007
Mr. Fred R. DacimoSite Vice President Entergy Nuclear Operations, Inc.
Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249
SUBJECT: INDIAN POINT NUCLEAR GENERATING UNIT 3 - NRC INTEGRATEDINSPECTION REPORT 05000286/2007003
Dear Mr. Dacimo:
On June 30, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection atIndian Point Nuclear Generating Unit 3. The enclosed integrated inspection report documents the inspection results, which were discussed on July 13, 2007, with Mr. Anthony Vitale and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's 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 inspection finding of very low safety significance(Green) was identified. Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. The NRC is treating this violation as anon-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy because of the very low safety significance and because it is entered into your corrective action program. If you contest this non-cited violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement; and the NRC Senior Resident Inspector at Indian Point Nuclear Generating Unit 3.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public inspection in the F. Dacimo2NRC Public Document Room or from the Publicly Available Records (PARS) component ofNRC's 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 by Donald E. Jackson For/Eugene W. Cobey, ChiefProjects Branch 2 Division of Reactor ProjectsDocket No. 50-286License No. DPR-64
Enclosure:
Inspection Report No. 05000286/2007003
w/Attachment:
Supplemental Information cc w/encl:J. Wayne Leonard, Chairman and CEO, Entergy Nuclear Operations, Inc.
G. J. Taylor, Chief Executive Officer, Entergy Operations M. Kansler, President & CEO/CNO, Entergy Nuclear Operations, Inc.
J. T. Herron, Senior Vice President, Entergy Nuclear Operations, Inc.
M. Balduzzi, Senior Vice President & COO, Regional Operations NortheastSenior Vice President of Engineering and Technical Services J. DeRoy, Vice President, Operations Support (ENO)
A. Vitale, General Manager, Plant Operations (Acting)
O. Limpias, Vice President, Engineering (ENO)
J. McCann, Director, Nuclear Safety and Licensing (ENO)
C. D. Faison, Manager, Licensing (ENO)
E. Harkness Director of Oversight (ENO)
P. Conroy, Director, Nuclear Safety Assurance T. R. Jones, Manager, Licensing T. C. McCullough, Assistant General Counsel, Entergy Nuclear Operations, Inc.
M. Balboni, Deputy Secy, New York State Energy, Research and Development Authority P. Eddy, Electric Division, New York State Department of Public Service C. Donaldson, Esquire, Assistant Attorney General, New York Department of Law D. O'Neill, Mayor, Village of Buchanan J. G. Testa, Mayor, City of Peekskill R. Albanese, Four County Coordinator S. Lousteau, Treasury Department, Entergy Services, Inc.
Chairman, Standing Committee on Energy, NYS Assembly Chairman, Standing Committee on Environmental Conservation, NYS Assembly Chairman, Committee on Corporations, Authorities, and Commissions M. Slobodien, Director, Emergency Planning W. Dennis, Assistant General Counsel
SUMMARY OF FINDINGS
...................................................iii
REPORT DETAILS
..........................................................1REACTOR SAFETY...................................................1
1R01 Adverse Weather Protection .......................................1
1R04 Equipment Alignment.............................................2
1R05 Fire Protection .................................................2
1R06 Flood Protection Measures ........................................31R11Licensed Operator Requalification Inspection ..........................3
1R12 Maintenance Effectiveness ........................................41R13Maintenance Risk Assessment and Emergent Work Control ..............41R15Operability Evaluations ...........................................51R19Post-Maintenance Testing ........................................61R20Refueling and Outage Activities ....................................61R22Surveillance Testing .............................................7
1EP2Alert and Notification System Evaluation ..............................71EP6Drill Evaluation
OTHER ACTIVITIES (OA)
....................................................94OA1Performance Indicator Verification ..................................9 4OA2Identification and Resolution of Problems............................104OA3Event Followup................................................14 4OA5Other Activities.................................................20 4OA6Meetings, including Exit..........................................23 4OA7Licensee-Identified Violations.....................................23ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
................................................A-1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
...........................A-1
LIST OF DOCUMENTS REVIEWED
..........................................A-2
LIST OF ACRONYMS
......................................................A-7
iiiSUMMARY
- OF [[]]
FINDINGSIR 05000286/2007-003; 04/01/2007 - 06/30/2007; Indian Point Nuclear Generating Unit 3;Event Followup.The report covered a three-month period of inspection by resident and region-based inspectors.One Green finding was identified. The significance of most findings is indicated by their color(Green, White, Yellow, Red) using Inspection Manual Chapter 0609, "Significance
Determination Process." Findings for which the significance determination process (SDP) 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
NRC Identified and Self-Revealing FindingsCornerstone: Initiating EventsGreen. The inspectors identified a finding of very low safety significance (Green), inthat, Entergy failed to identify in the corrective action program an adverse condition
associated with the 'B' phase high voltage bushing on the 31 main transformer (MT) that
was discovered during testing. The data from that test indicated potential degradation
of the 'B' phase high voltage bushing. As a result, this condition was not adequately
evaluated before placing the transformer back in service, and the bushing subsequently
failed. The transformer failure was entered into their corrective action program.
Entergy replaced the 31 main transformer and conducted a root cause analysis
associated with the failure. The inspectors determined that this finding was more than minor because it isassociated with the equipment performance attribute of the Initiating Events
cornerstone, and it affected 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. Specifically, Entergy did not place this issue in thecorrective action process, and as a result, did not conduct an adequate evaluation of a
degraded condition associated with the 'B' phase high voltage bushing on 31 MT.
Subsequently, the bushing failed during power operation and resulted in a reactor trip,
an explosion in the transformer yard, and the declaration of a notification of an unusual
event. The inspectors evaluated the significance of this finding using Phase 1 of
Inspection Manual Chapter (IMC) 0609, Appendix A, "Significance Determination of
Reactor Inspection Findings for At-Power Situations." This finding was determined to be
of very low safety significance because, while it was a transient initiator that resulted in a
reactor trip, it did not contribute to the likelihood that mitigation equipment or functions
would not be available.The inspectors determined that this finding had a cross-cutting aspect in the area ofproblem identification and resolution, because Entergy failed to promptly identify an
adverse condition in the corrective action program in a timely manner commensurate
with its safety significance. (Section 4OA3)
ivB.Licensee-Identified Violations A violation of very low safety significance, which was identified by the licensee, has been
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensee's corrective action program. This violation and Entergy's
actions are described in Section 4OA7 of this report.
EnclosureREPORT
- DETAIL [[]]
SSummary of Plant StatusIndian Point Nuclear Generating Unit 3 began the inspection period returning to full power aftercompletion of refueling outage 3R14. On April 3, 2007, operators initiated a manual reactor trip
due to a loss of speed control of the only operating main boiler feed pump. Entergy returned
the unit to power on April 4, 2007. On April 6, 2007, during power ascension with the unit at
approximately 91 percent power, the unit tripped automatically as a result of a main generator
lockout and main turbine trip. The cause of the event was the failure of the 'B' phase high
voltage bushing on the 31 main transformer. As a result of this event, a notification of an
unusual event (UE) was declared due to the report of an explosion associated with the bushing
failure. Following repair activities on the main transformer, Entergy returned the plant to full
power on May 5, 2007, and continued to operate the plant at or near full power for the
remainder of the inspection period.
- 1.REACT [[]]
- OR [[]]
- SAFETY [[Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather Protection (71111.01 - 1 sample) a.Inspection Scope The inspectors reviewed Entergy's adverse weather procedures, operating experience,corrective action program (]]
CAP), Updated Final Safety Analysis Report (UFSAR),
Technical Specifications (TS), operating procedures, and applicable plant documents to
determine the types of adverse weather challenges to which the site is susceptible.The inspectors performed plant walkdowns and reviews to verify that plant features andprocedures for operation and continued availability of the ultimate heat sink during
adverse weather were appropriate, including equipment availability for performance of
the reactor shutdown function under the weather conditions assumed prior to shutdown.
The intake structure, fire suppression system, and control building ventilation system are
risk-significant systems that are required to be protected from adverse weather
conditions and were selected for inspection. The documents reviewed during this
inspection are listed in the Attachment. Collectively this inspection represented one
inspection sample of risk-significant systems. b. FindingsNo findings of significance were identified.
2Enclosure1R04Equipment AlignmentPartial Walkdown (71111.04Q - 4 samples) a.Inspection ScopeThe inspectors performed four partial system walkdowns to verify the operability ofredundant or diverse trains and components during periods of system train unavailability
or following periods of maintenance. The inspectors referenced the system procedures,
the
- UFS [[]]
AR, and system drawings to verify that the alignment of the available train was
proper to support its required safety functions. The inspectors also reviewed applicable
condition reports and work orders to ensure that Entergy had identified and properly
addressed equipment discrepancies that could potentially impair the capability of the
available train. The documents reviewed during this inspection are listed in the
Attachment. The inspectors performed partial walkdowns of the following systems,
which represented four inspection samples:*Diesel driven fire pump and motor driven fire pump following maintenance andtesting;*Containment spray system following maintenance and testing;
- Auxiliary feedwater system following replacement of 31 auxiliary boiler feedwaterpump minimum flow throttle valve (BFD-33), and 33 auxiliary boiler feedwater
pump minimum flow throttle valve (BFD-35); and*32 emergency diesel generator (EDG) with 33 emergency diesel generator out ofservice. b. FindingsNo findings of significance were identified.
1R05Fire Protection (71111.05Q - 10 samples) a.Inspection ScopeThe inspectors conducted tours of the ten areas listed below to assess the materialcondition and operational status of fire protection features. The inspectors verified that
combustibles and ignition sources were controlled in accordance with Entergy's
administrative procedures; fire detection and suppression equipment was available for
use; passive fire barriers were maintained; and compensatory measures for
out-of-service, degraded, or inoperable fire protection equipment were implemented in
accordance with Entergy's fire plan. The inspectors used procedure
DC-161,
"Transient Combustible Program," in performing the inspection. The inspectors
evaluated the fire protection program against the requirements of License
Condition 2.H. The documents reviewed during this inspection are listed in the
Attachment. This inspection satisfied ten inspection samples of fire protection tours.
3EnclosureThe areas inspected included: * Fire Zones 1, 1A, 2, 2A, 58A;* Fire Zone 264;
- Fire Zone 265;
- Fire Zone 390;
- Fire Zone 14;
- Fire Zones 5, 6, 7, 8, 17A, 18A, 19A, 20A;
- Fire Zones 3, 4, 8A, 9A, 10A, 11A, 12A, 15A, 16A;
- Fire Zones 26A, 27A, 28A, 29A, 30A;
- Fire Zones 5A, 61A, 62A, and 68A; and
- Fire Zones 90A,
- 91A. b. FindingsNo findings of significance were identified.1R06Flood Protection Measures (71111.06 - 1 sample) a.Inspection ScopeThe inspectors reviewed the Indian Point Unit 3 Individual Plant Examination (
- UFS [[]]
AR concerning external flooding events. The inspection
included a walkdown of accessible areas of the plant to detect potential susceptibilities
to external flooding and to verify the assumptions included in the site's external flooding
analysis. The inspectors also reviewed relevant abnormal operating and emergency
plan procedures. This inspection was conducted during a period of severe weather in
mid-April 2007. The documents reviewed during this inspection are listed in the
Attachment. This inspection represented one inspection sample of external flood
protection. b. FindingsNo findings of significance were identified.1R11Licensed Operator Requalification Inspection (71111.11Q - 1 sample) a.Inspection ScopeOn May 14, 2007, the inspectors observed licensed operator simulator training to assessoperator performance during several scenarios to verify that operator performance was
adequate and evaluators were identifying and documenting crew performance problems.
The inspectors evaluated the performance of risk significant operator actions, including
the use of emergency operating procedures. The inspectors assessed the clarity and
effectiveness of communications, the implementation of appropriate actions in response
to alarms, the performance of timely control board operation and accurate control
manipulation, and the oversight and direction provided by the shift manager. The
inspectors also reviewed simulator fidelity with respect to the actual plant. Licensed
4Enclosureoperator training was evaluated against the requirements of 10 CFR 55, "Operator'sLicenses." The documents reviewed are listed in the Attachment. This observation of
operator simulator training represented one inspection sample. b.FindingsNo findings of significance were identified.1R12Maintenance Effectiveness (71111.12Q - 1 sample) a.Inspection ScopeThe inspectors reviewed performance-based problems involving selected structures,systems, or components (SSCs) to assess the effectiveness of the maintenance
program. Reviews focused on:*Proper Maintenance Rule scoping;*Characterization of reliability issues;
- Changing system and component unavailability;
- 10 CFR 50.65 (a)(1) and (a)(2) classifications;
- Identifying and addressing common cause failures;
- Trending of system flow and temperature values;
- Appropriateness of performance criteria for SSCs classified (a)(2); and
- Adequacy of goals and corrective actions for SSCs classified (a)(1).The inspectors reviewed system health reports, maintenance backlogs, and MaintenanceRule basis documents. The inspectors evaluated the maintenance program against the
requirements of 10 CFR 50.65. The documents reviewed during this inspection are listed
in the Attachment. The following maintenance rule sample was reviewed and
represented one inspection sample:* Vapor containment pressure relief system. b.FindingsNo findings of significance were identified.1R13Maintenance Risk Assessment and Emergent Work Control (71111.13 - 5 samples) a.Inspection ScopeThe inspectors reviewed planned or emergent activities to verify that the appropriate riskassessments were performed prior to removing equipment from service for planned
work. The inspectors verified that risk assessments were performed as required by
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 documents reviewed during this inspection are listed in the Attachment.
5EnclosureThe following four emergent activities and one planned activity were observed andtreated as five inspection samples:*Main generator voltage regulator repair, including turbine generator shut downand start up operations;*38 service water pump planned maintenance;
- Boric acid flow to the charging pump suction at lowered volume control tankpressures troubleshooting and repair activities;*32 central control room (CCR) air conditioning unit out of service during modechange for startup; and*Circulating water pump standby drive maintenance following trip of 32, 34 and 36circulating water pumps. b.FindingsNo findings of significance were identified.1R15Operability Evaluations (71111.15 - 4 samples) a.Inspection ScopeThe inspectors reviewed operability determinations to assess the acceptability ofthe evaluations, the use and control of compensatory measures, and compliance with
Technical Specifications. The inspectors' review included a verification that the
operability determinations were made as specified by
OP-104, "Operability
Determinations." The technical adequacy of the determinations was reviewed and
compared to the
UFSAR, and associated design basis documents. The documents
reviewed during this inspection are listed in the Attachment. The following evaluations
were reviewed and represented four inspection samples:*Condition report
FCV-406D, "33 Auxiliary Boiler FeedwaterPump to 34 Steam Generator Control Valve," will not operate with local regulator
controls;*Condition report
PT-M108. b.FindingsNo findings of significance were identified.
6Enclosure1R19Post-Maintenance Testing (71111.19 - 8 samples) a.Inspection ScopeThe inspectors reviewed post-maintenance test procedures and associated testingactivities for selected risk-significant mitigating systems to assess whether the effect of
maintenance on plant systems was adequately addressed by control room and
engineering personnel. The inspectors verified that test acceptance criteria were clear,
demonstrated operational readiness and were consistent with design basis
documentation; test instrumentation had current calibrations and the range and accuracy
for the application; and tests were performed, as written, with applicable prerequisites
satisfied. Upon completion, the inspectors verified that equipment was returned to the
proper alignment necessary to perform its safety function. Post-maintenance testing was
evaluated against the requirements of
XI, "Test
Control." The documents reviewed during this inspection are listed in the Attachment.
The following post-maintenance test activities were reviewed and represented eight
inspection program samples:* Work order
- WO [[]]
- IP 3-07-19744, 31 and 33 auxiliary boiler feedpump minimum flow throttle valves after replacement;* Work order
- IP 3-06-22068, Post work test for 31 component cooling water pumpmechanical seal replacement;* Work order
IP3-07-19329, Post work test for 31 main transformer deluge systemafter transformer replacement. b.FindingsNo findings of significance were identified.1R20Refueling and Outage Activities (71111.20 - 2 samples) a.Inspection Scope The inspectors observed plant start up activities, including the approach to criticalityassociated with two forced outages during the inspection period. In addition, the
inspectors observed the main generator synchronization to the electrical grid, and initial
power ascension. The documents reviewed during this inspection are listed in the
7EnclosureAttachment. The combined efforts described above represent two inspection programsamples. b.FindingsNo findings of significance were identified.1R22Surveillance Testing (71111.22 - 5 samples) a.Inspection ScopeThe inspectors witnessed performance of surveillance tests and/or reviewed test data ofselected risk-significant
Technical Requirements Manual, and Entergy procedure requirements. The inspectors
verified that test acceptance criteria were clear, demonstrated operational readiness and
were consistent with design basis documentation; test instrumentation had current
calibrations and the range and accuracy for the application; and tests were performed, as
written, with applicable prerequisites satisfied. Upon surveillance test completion, the
inspectors verified that equipment was returned to the status specified to perform its
safety function. The inspectors evaluated the surveillance tests against the requirements
in TS. The documents reviewed during this inspection are listed in the Attachment. The
following surveillance tests were reviewed and represented five inspection samples (one
RCS leakage rate sample, one inservice testing sample, and three other surveillance test
samples):* 3-PT-CS-004, "Low Head Injection, Accumulator & Residual Heat Removal ValveTest," Revision 19;* 3-PT-Q83, "RWST Level Instrument Check and Calibration (LIC-921),"Revision 25;* 0-SOP-LEAKRATE-001, "Reactor Coolant System Leakrate Surveillance,Evaluation, and Leak Identification," Revision 00;* 3-PT-Q132, "Emergency Boration Flow Path Valve
MOV-333," Revision 2;and* 3-PT-Q062A, "31 Charging Pump Operability Test," Revision 8. b.FindingsNo findings of significance were identified.Cornerstone: Emergency Preparedness (EP)1EP2Alert and Notification System Evaluation (71114.02 - 1 sample)a.Inspection ScopeRegion-based specialist inspectors reviewed Entergy's corrective actions related to theexisting Indian Point alert and notification system (ANS) failures, and reviewed the
progress made in the design and installation of the new siren system. Inspection
8Enclosureactivities were conducted onsite periodically between April 12 and June 28, 2007. Thisinspection was conducted in accordance with the baseline inspection program deviation
authorized by the
EDO) in a memorandum dated
October 31, 2005, and renewed by the
ANS is being installed around the Indian Point Energy Center to satisfycommitments documented in an NRC Confirmatory Order (dated January 31, 2006) that
implements the requirements outlined in the 2005 Energy Policy Act. In January 2007,
Entergy requested an extension of the deadline for completing the ANS project as
described in the Confirmatory Order. The Confirmatory Order set a January 30, 2007,
deadline for completing installation. Entergy's extension request cited several issues that
were beyond their control as the basis for the delay. On January 23, 2007, the NRC
granted Entergy's extension request and established April 15, 2007, as the new
installation completion date. Entergy conducted a full-system demonstration test of the
new ANS on April 12, 2007, and the results of that test failed to meet the acceptance
criteria for the new system. On April 13, 2007, Entergy requested another extension
which was subsequently denied. On April 23, 2007, the NRC issued a Notice of Violation
and civil penalty for Entergy's failure to comply with the siren operability date in the
Confirmatory Order.The inspectors conducted the following onsite inspection activities during this quarter.
- The inspectors observed the full-volume sounding on April 12, 2007 to meet theApril 15, 2007 deadline.*The inspectors reviewed supplemental bench testing done by Entergy's vendor toverify test results from the degraded battery voltage testing performed in the
previous quarter.*The inspectors observed and inspected the degraded voltage re-test of one of theback-up batteries for the new ANS system. The re-test was done because during
the first test there was a problem with the resistive load used for the simulated
activation. This testing conducted from May 29, 2007 to June 6, 2007 assured
that the battery at the siren would operate at its end-of-life condition after having
lost alternating current power for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.*During all onsite siren inspection activities, the regional inspectors also reviewedthe status of and corrective actions for the current ANS to assure that Entergy
was appropriately maintaining the system, including the quarterly full-system
growl test of the current ANS conducted on June 28, 2007 to demonstrate its
functionality. b.FindingsNo findings of significance were identified.
9Enclosure1EP6Drill Evaluation (71114.06 - 1 sample) a.Inspection ScopeThe inspectors observed an emergency preparedness drill conducted on May 16, 2007. The inspectors used NRC Inspection Procedure 71114.06, "Drill Evaluation," as guidance
and criteria for evaluation of the drill. The inspectors observed the drill and critiques that
were conducted from the participating facilities on-site, including the Indian Point Unit 3
plant simulator, and the emergency operations facility. The inspectors focused the
reviews on the identification of weaknesses and deficiencies in classification and
notification timeliness, quality, and accountability of essential personnel during the drill.
The inspectors observed Entergy's critique and compared the licensee's self-identified
issues with the observations from the inspectors' review to ensure that performance
issues were properly identified. The observation of the drill represented one inspection
sample. b.FindingsNo findings of significance were identified.4.OTHER
- ACTIVI [[]]
TIES (OA)4OA1Performance Indicator Verification (71151- 2 samples) a.Inspection ScopeThe inspectors reviewed performance indicator (PI) data for the below-listedcornerstones and used Nuclear Energy Institute 99-02, "Regulatory Assessment
Performance Indicator Guideline," Revision 4, to verify individual PI accuracy and
completeness.Initiating Events Cornerstone*Unplanned Scrams With Loss of Normal Heat Removal
Mitigating Systems Cornerstone* Safety System Functional Failures
The inspectors reviewed data and plant records from April 2006 to March 2007. Therecords reviewed included PI data summary reports, licensee event reports, operator
narrative logs, maintenance rule records, maintenance records and condition reports for
affected systems. The inspectors verified the accuracy of the data reported, and
interviewed licensee personnel associated with the PI data collection and evaluation. b.FindingsNo findings of significance were identified.
10Enclosure4OA2Identification and Resolution of Problems.1Routine Problem Identification and Resolution (PI&R) Program Review a.Inspection ScopeAs required by Inspection Procedure 71152, "Identification and Resolution of Problems,"and in order to help identify repetitive equipment failures or specific human performance
issues for follow-up, the inspectors performed a daily screening of all items entered into
Entergy's CAP. The review was accomplished by accessing Entergy's computerized
database for condition reports (CRs) and attending
CAP itemsacross the Initiating Events, Mitigating Systems, and Barrier Integrity cornerstones for
additional follow-up and review. The inspectors assessed Entergy's threshold for
problem identification, the adequacy of the cause analyses, extent of condition review,
operability determinations, and the timeliness of the specified corrective actions. The
CRs reviewed are listed in the Attachment. b.Findings and Observations No findings of significance were identified.
.2Semi-Annual Trend Review (71152 - 1 sample) a.Inspection ScopeThe inspectors performed a semi-annual review to identify trends that might indicate theexistence of a more significant safety issue. The inspectors included in this review
repetitive or closely related issues that may have been documented by Entergy outside of
the normal CAP, such as trend reports, performance indicators, major equipment
problem lists, maintenance rule assessments, and maintenance and
CAP database during the first and second quarters of2007 to assess the total number and significance of condition reports written in various
subject areas, such as equipment or processes, to discern any notable trends in these
areas. The inspectors reviewed Entergy's quarterly assessment/trend reports for bothCAP and Quality Assurance for the fourth quarter of 2006 and the first quarter of 2007 to
ensure they were appropriately evaluating and trending identified conditions. b.Assessment and ObservationsNo findings of significance were identified.
The inspectors determined that Entergy was appropriately identifying and evaluatingtrends in identified conditions.
11Enclosure.3Fitness-For-Duty (FFD) Program (71152) a.Inspection ScopeThe inspector reviewed the actions taken by Entergy in response to an employeedisplaying unusual behavior. The actions taken by the employee's supervisor and the
Fitness-for-Duty personnel in the Medical Department were reviewed along with
Entergy's
- FFD policies and procedures. b.Findings and ObservationsNo findings of significance were identified. The inspectors determined that Entergy tookappropriate actions in accordance with applicable
NRC regulatory requirements and
internal
PI&R Sample Review: Control Room Air Conditioning Unit Performance Issues (71152 - 1 sample) a.Inspection ScopeThe inspectors conducted reviews of problems associated with the performance of the 31and 32 control room air conditioning units, and the placement of the 32 control room air
conditioning unit in a 10CFR50.65 a(1) monitoring status. The inspectors interviewed
engineers responsible for the system, reviewed applicable condition reports from 2005 to
present, and reviewed the associated engineering evaluations and corrective actions.
The documents reviewed during the inspection are listed in the Attachment. b.Findings and ObservationsNo findings of significance were identified. The inspectors determined that Entergy'sthreshold for problem identification was appropriate, and associated causal analyses,
extent of condition reviews, and corrective actions were adequate..5Annual Sample: Safety Conscious Work Environment Corrective Actions(71152 - Unit 2: 1 sample, Unit 3: 1 sample) a.Inspection ScopeOn December 21, 2006, the
- NRC [[issued a letter []]
ADAMS Ref. ML063560335] requestingthat Entergy provide its plan for evaluating a potential chilling effect onsite and its plan of
action for addressing the matter to the NRC. This letter and its enclosure documented
the results of problem identification and resolution (PI&R) team inspections at the Indian
Point Energy Center (IPEC). The letter stated that the NRC had become aware of
incidents where workers perceived that individuals were treated negatively by
management for raising issues. As a result of these incidents, some workers expressed
reluctance to raise issues under certain circumstances. While most workers made a
distinction between nuclear safety issues and other concerns, the teams noted that some
of the illustrative examples provided by plant workers could have nuclear safety
2Enclosureimplications. However, the teams did not identify any more than minor issues which hadnot been raised. The teams also noted that Entergy had not fully evaluated the results of
a 2006 safety culture assessment to understand the causes of negative responses and
declining trends related to the safety conscious work environment onsite.Entergy responded in a letter dated January 22, 2007 [ADAMS Ref. ML070240242]. Based primarily on the results of interviews conducted by an independent assessment
team, Entergy reported that a "perception exists within a segment of the
- IP [[]]
EC workforce
that they may suffer in some way if they were to raise a safety concern." The results of
the interviews were consistent with
PI&R inspections and
generally consistent with the results of the independent safety culture assessment. Entergy's letter provided a plan with actions intended to improve the safety consciouswork environment (SCWE). Specifically, the plan included corrective actions to improve
communications; identify and prevent retaliation, chilling effect, and the perception of
retaliation; enhance the corrective action program; enhance the employee concerns
program; and improve the broader work environment at
- IP [[]]
EC. Entergy also indicated
that metrics would be developed to measure performance at achieving the components
of a healthy
- SC [[]]
WE and an assessment would be conducted to confirm the effectiveness
of its actions in early
NRC reviewed Entergy's response and concluded that Entergy's completed andplanned diagnostic activities were reasonable to characterize the challenges to the safety
conscious work environment onsite and the planned corrective actions were appropriate.
The results of the NRC's review were documented in a letter to Entergy dated February
26, 2007 [ADAMS Ref.
- ML [[070570518]. This letter also stated that the]]
NRC would
monitor Entergy's corrective actions through baseline inspection activities.In June 2007, the inspectors performed
- PI&R sample inspections on each operating unitto review the status of Entergy's corrective actions related to the
SCWE at Indian Point.
The inspection included over 50 interviews and discussions with technicians, staff,
supervisory and management personnel in a representative cross section of work
groups. The inspectors also attended selected meetings and reviewed supporting
documentation for corrective actions. b.Findings and ObservationsNo findings of significance were identified.
The inspectors concluded that Entergy's progress on corrective actions related to theSCWE was adequate. The inspectors observed that Entergy implemented a number of
actions to address previously identified issues affecting the work environment, as
revealed in a 2006 safety culture assessment, NRC inspections, and an independent
assessment conducted on behalf of Entergy.Based on interview results and document reviews, the inspectors determined that severalactions were effective in communicating the site's commitment to a safety conscious
work environment.
13EnclosureThese actions included:*Site Vice President meetings with small groups;*Site-wide communications on safety conscious work environment; and
- Changes to site schedules that allowed supervisors and managers to spend moretime in the field.The inspectors identified two corrective actions that were not yet effective. Both of thesewere associated with Entergy's actions to detect and prevent retaliation, chilling effect,
and the perception of retaliation. These items constituted issues of minor significance,
because there was no actual impact on the work environment. *First, the inspectors identified a deficiency in the implementation of the ExecutiveReview Board (ERB), which was established to review proposed personnel
actions to ensure: they were not in violation of 10 CFR 50.7 employee protection
regulations; they did not involve retaliation; and any potential chilling effect was
addressed. Specifically, the inspectors identified that the potential for retaliation
or a chilling effect for raising safety issues was not considered for some adverse
personnel actions that went before the ERB. In response to this observation,
Entergy entered the issue in the corrective action program with an action for the
ERB to review the personnel action cases for the potential for retaliation or a
chilling effect related to raising safety issues. *Secondly, the inspectors identified that the Executive Protocol Group (EPG) wasnot fully meeting its charter in providing advice to senior management on issues
that may be related to retaliation or a chilling effect. For example, the EPG had
not reviewed a specific event involving an individual who felt reluctant to raise
issues based on the actions of a site manager. Additionally, the inspectors
observed that the EPG was not reviewing some data and trending information as
specified in its process document. For example, the
- SC [[]]
WE-related data from condition reports or findings from surveys and
assessments. Entergy made several enhancements to the EPG meeting process
to incorporate the inspectors' observations.The inspectors also observed that Entergy's process for tracking and trending
- SC [[]]
WE-related trend codes was being performed on a 6-month basis, which may not be
timely for management to respond to and mitigate new issues or trends that could affect
the work environment. During interviews with the inspectors, all personnel indicated that they would raise issuesthat they recognized as a nuclear safety concerns. Some individuals stated they had
heard of others who may be hesitant to raise issues, due to events that had happened in
the past. A few individuals stated that they may not raise low level issues, because they
did not believe the issues would be corrected.When questioned about the site's initiatives in the area of
- SC [[]]
WE, most individuals wereaware of the ongoing efforts. Some believed that the corrective actions were having a
14Enclosurepositive effect. Others were more skeptical of the corrective actions, based on theirobservations or what they had heard about statements made by management. Some
personnel indicated that they were awaiting a demonstrated commitment to a
- SC [[]]
WE,
rather than just communications.The inspectors noted that Entergy has a number of actions planned to continue itsprogress in improving the
- SCWE onsite. These actions include:*Departmental action plans to address the safety culture aspects of a 2007Entergy Employee Survey;*A second round of Site Vice President meetings with small groups to continue thedialogue on
SCWE;*Ongoing efforts to conduct facilitated discussions and additional activities toimprove the work environment in the Instrumentation and Controls work group;
and*Refresher training on
have been self-critical. For example, Indian Point management held a meeting in April
2007, to discuss and take corrective actions for certain events and management
behaviors that were not conducive to establishing and maintaining a healthy safety
conscious work environment onsite. Additionally, a recent Entergy corporate assessment
and a quality assurance audit identified opportunities for improvement in this area.4OA3Event Followup (71153 - 2 samples).1Manual Reactor Trip - Loss of 32 Main Boiler Feed Pump Speed Control and(Closed) LER 05000286/2007-001-00On April 3, 2007, operators performed a manual reactor trip of Indian Point Unit 3 due toa loss of 32 main boiler feed pump speed control while conducting maintenance on the
main boiler feed pump speed control system. The loss of speed control caused steam
generator levels to lower, such that a manual reactor trip was required by procedures.
The loss of speed control was attributed to operators de-energizing a power supply that
was thought to provide power to the speed control system for only the 31 main boiler
feed pump, which was shut down in preparation for the maintenance evolution. A discrepancy in the plant drawing being used for developing the blocking points for theassociated safety tagging led to a misunderstanding of how power was supplied to the
speed control system. In actuality, speed control system power was supplied to both
main boiler feed pumps through the circuit that the operators de-energized. In addition, a
second power supply that was not working properly was forced to carry load when
operators turned off what they thought was the correct circuit breaker. This led to an
unexpected speed control problem with the 32 main boiler feed pump, which was the only
pump in operation. Thus, both the plant drawing discrepancy and the degraded second
power supply contributed to the loss of speed control.
15EnclosureOperators correctly diagnosed the situation and tried to restore main boiler feed pumpspeed control to normal. They were unsuccessful in this attempt, leading to the need to
actuate a manual reactor trip. All systems functioned normally after the trip, and the
plant was quickly stabilized in a hot shutdown condition.Entergy replaced the affected power supplies, established planned maintenance toreplace the control system power supplies, performed an extent of condition review, and
implemented revisions to system controlled documents. The inspectors reviewed the licensee event report (LER) and identified no findings ofsignificance or violations of NRC requirements. A finding was not identified because
although a performance deficiency did exist associated with plant drawings not being
accurate, it would take the failure of another power supply to lead to the loss of the 32
main boiler feed pump. There was no violation of NRC requirements because the
affected equipment is not safety-related, and therefore does not fall under requirements
of 10 CFR 50 Appendix B. Entergy documented the event and corrective actions in
condition report
LER 05000286/2007-002-00On April 6, 2007, while at 91 percent power, the Indian Point Unit 3 reactor automaticallytripped due to a main turbine trip and generator lockout caused by an electrical fault in
the 31 main transformer. The electrical fault in the 31 main transformer resulted in an
explosion originating in the 'B' phase high voltage bushing, which is a integral part of the
transformer. The electrical fault and explosion were only evident for a few seconds, and
the ensuing fire was extinguished by the fire brigade in about 10 minutes. Operators
declared a notification of a UE once it was realized that an explosion had occurred.
However, this declaration was delayed due to personnel not immediately making the
control room staff aware that an explosion had been observed. Although the explosion
was transient in nature, left little evidence that it had occurred, and quickly became
observable as a fire in the 31 main transformer, there were some Entergy personnel that
were aware that an explosion had taken place. A number of these people did not contact
the control room with their observation because the fire was quickly announced by the
control room staff, and these personnel felt that the added communication with the
control room would not be desirable as the control room was already taking actions to
mitigate the event. The inspectors confirmed that the shift manager made a timely and appropriate eventclassification once he was made aware that an explosion had occurred. Entergy
documented this concern in the corrective action program as
IP3-2007-02036, and
determined, as a part of their review, that additional site staff training is necessary to
sensitize plant staff that the shift manager needs to be made aware of observations such
as an explosion so that event classification can occur. Entergy's current training program
meets the requirements of their emergency plan. The inspectors determined that
operator actions after the reactor trip were in accordance with station emergency
operating procedures, and the plant responded as expected to the reactor trip.
16EnclosureThe inspectors identified a performance deficiency, in that, plant staff did not immediatelymake the shift manager aware of their observation that an explosion was observed from
the 31 main transformer bushing. The Indian Point Emergency Plan Event Classification
Guide requires that the Shift Manager declare a notification of a UE upon receiving a
report from plant personnel of an observation of an explosion within the protected area of
the plant. Inherent in this requirement is that when personnel observe an explosion in
the protected area of the plant they promptly report the observation to the central control
room. The inspectors determined that the performance deficiency was of minor safety
significance because its occurrence would not lead to a significant event, nor could it
become a more significant safety concern. In addition, no performance indicator would
be affected by the deficiency. Finally, the performance deficiency did not affect the
Emergency Preparedness cornerstone objective because Entergy provided adequate
measures to protect public health and safety. Entergy replaced and tested the 31 main transformer and associated bushings; testedand inspected the 32 main transformer, unit auxiliary transformer, and high voltage
equipment; developed plans to establish testing acceptance criteria and data trending;
and performed an extent of condition review. Entergy documented the failed component
and corrective actions in condition report
NRC requirements. ThisLER is closed.FindingsIntroduction. The inspectors identified a finding of very low safety significance (Green),in that, Entergy failed to identify in the corrective action program an adverse condition
associated with the 'B' phase high voltage bushing on the 31 main transformer (MT) that
was discovered during testing. The data from that test indicated potential degradation of
the 'B' phase high voltage bushing. As a result, this condition was not adequately
evaluated before placing the transformer back in service, and the bushing subsequently
failed. Description. On April 6, 2007, the 'B' phase high voltage bushing on 31 MT failed whilethe unit was at approximately 91 percent power, in power ascension. The failure resulted
in an explosion in the main transformer yard, a turbine trip, a reactor trip, and the
declaration of a notification of a
UE indicates a potential
degradation in the level of safety of the plant, and that no release of radioactive material
requiring offsite response or monitoring is expected unless further degradation occurs.Following this failure, the inspectors reviewed maintenance activities associated with the31 MT that were performed during a plant outage which occurred between March 6,
2007, and March 30, 2007. A power factor test was performed on March 27, 2007. This
test is commonly used to determine the insulation integrity of high voltage equipment.
The results from that test indicated potential degradation of the 'B' phase bushing. The
nameplate power factor ratings and the most recent power factor test results are shown
in the table below. The power factor test result on the 'B' phase bushing was identified
17Enclosureby the vendor performing the test as requiring further evaluation, and the site engineeringstaff was notified.Bushing Power Factor In Percent (%) By PhaseABCBushing Name Plate Rating.44%.30%.43%
Test Results From 1999.48%.54%.49%
Test Results From March 2007.53%1.43%.53%The engineering staff identified this as a potential adverse condition but did not place thisissue into the corrective action program. Entergy's engineering staff reviewed the results
of the test, and contacted an Entergy transmission and distribution system expert to
determine the significance of the test results. Engineering personnel determined that the
data was not representative of insulation degradation that would result in premature
failure based on past operational history, recent thermography, and the work performed
during the refueling outage. They concluded the 'B' phase bushing could be replaced
during the next refueling outage. The transformer was returned to service following this
determination.The inspectors reviewed the transformer maintenance history, applicable operatingexperience, Entergy's initial evaluation of the identified condition, and industry standards
for power factor testing acceptance criteria. The inspectors also reviewed Entergy's root
cause evaluation of the failure. The inspectors determined that, during Entergy's initial evaluation of the test results, theIndian Point Energy Center system engineer did not have complete information on the
power factor testing acceptance criteria. In addition, the evaluation did not include a
review of past operating experience specific to this particular bushing design, a General
Electric Type U bushing. The inspectors noted that there was significant industry
experience with failures of this particular bushing design. Several sources have provided
power factor acceptance limits specific to this design. The inspectors evaluated
acceptance criteria provided by General Electric (GE), Doble Engineering, and ABB, in
addition to generic criteria provided in Institute of Electrical and Electronics Engineers
(IEEE) standards.Specific to the Type U bushing design, the GE criteria states that if the power factorexceeds 3.0 percent, the bushing needs to be replaced. If the value is between 1.0
percent and 3.0 percent, it is in a "region of concern," but there is little risk of failure if the
capacitance change is less than 5.0 percent. A bushing in this "region of concern"
should be monitored on an annual basis. Doble Engineering recommends replacing a
bushing if the power factor exceeds 1.5 percent, or if it exhibits a sudden increase in
value beyond 1.0 percent. A bushing with a power factor above 1.0 percent, or less than
1.0 percent but exhibiting a sudden increase, should be considered questionable and
18Enclosureretested within six months. The capacitance recommendation is the same as
ABBrecommends replacement if the power factor doubles the nameplate value, or the
capacitance increases to 110 percent of the nameplate value.The inspectors found that Entergy relied upon the recommendation of their transmissionand distribution system expert who determined that, based on the power factor number
measured on March 27, 2007, the bushing would function properly until the next plant
refueling outage. Based on interviews conducted with an Indian Point Energy Center
system engineer, the inspectors determined that the transmission and distribution system
expert had requested the previous test data for comparison; but, it was not made
available. The inspectors determined that this was a necessary piece of information,
given the available operating experience and the testing results, for the expert to assess
the condition of the bushing. Therefore, the conclusion that the bushing was in
acceptable condition was made without all the necessary information to provide a sound
engineering justification, because no comparison to the previously conducted test result
could be performed. Specifically, interpretation of the results depends primarily on
comparing previous results with current test results. In addition, Doble Engineering and
- ABB acceptance criteria are dependent on the change in power factor over time.Entergy's root cause evaluation stated that the power factor test met the
GE acceptancecriteria, therefore the bushing condition was satisfactory and the failure was the result of
a random failure. The inspectors noted that the test results did meet the acceptance
criteria provided by GE; however, these criteria had not been substantially modified since
being established in 1979. Since that time, several other vendors have provided
acceptance criteria which incorporate more recent test and failure data, both generically
and associated with this particular bushing design. Acceptance criteria from Doble
Engineering was provided in 1985;
- IE [[]]
EE industry standards were dated 1995 and 2000;
and ABB provided standards in 1998. Based on any of these criteria, with the exception
of the GE criteria, the bushing should have been replaced prior to placing the transformer
back into service. The previous power factor test was performed in 1999 and the results
are listed in the table above. The test data from 2007 showed a significant increase for
the 'B' phase bushing (from 0.54 percent to 1.43 percent) and would have led to a
replacement of the bushing based on Doble Engineering and ABB acceptance criteria.The inspectors determined that the numerical value for the bushing power factor of 1.43percent would not always require replacement. However, given the significant rise since
the last test, the industry experience associated with failures of this particular bushing
design, and the basis for the various acceptance criteria, the inspectors determined that
a thorough evaluation should have resulted in the replacement of the bushing prior to
returning the transformer to service. While the inspectors determined that the bushing
would not have required replacement based on the GE acceptance criteria, as stated by
Entergy, these criteria do not appear to take into account the significant operating
experience and data gathered since 1979. In addition, a facility within the Entergy fleet
has used the Doble Engineering criteria as the standard for replacement of a bushing,
therefore it would be reasonable to assume that the same criteria would be considered at
Indian Point Energy Center. On February 15, 2007, a notice was received by the staff at
Indian Point Energy Center describing a concern identified at the Grand Gulf Nuclear
Station. This notice discussed the industry issues with the GE Type U bushing and
19Enclosurestated that the station had used the criteria specified by Doble Engineering in theirevaluations which led to bushing replacement. Grand Gulf Nuclear Station's engineering
evaluation of the issue provided a basis for the use of these criteria. The bushing
associated with the Grand Gulf Nuclear Station transformer was replaced based on its
power factor being greater than 1.5 percent. However, since Entergy used the Doble
Engineering criteria to make this determination, they should have reached the same
conclusion to replace the bushing if they had power factor test results and history similar
to that of Indian Point due to the criteria recommending replacement of a bushing with a
power factor of greater than 1.5 percent, or that exhibits a sudden increase and is
greater than 1.0 percent. Analysis. The inspectors determined that the failure to identify, in the corrective actionprogram, the adverse condition of the 'B' phase high voltage bushing on 31 MT is a
performance deficiency, because it is contrary to the requirements of Entergy's
procedure
LI-102, "Corrective Action Process." This procedure requires employees
to initiate a condition report for all adverse conditions. Traditional enforcement does not
apply since there were no actual safety consequences or potential for impacting the
NRC's regulatory function, and the finding was not the result of any willful violation of
NRC requirements or Entergy's procedures.The inspectors determined that this finding was more than minor because it is associatedwith the equipment performance attribute of the Initiating Events cornerstone, and it
affected 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. Specifically, Entergy did not place this issue in the corrective action process,
and as a result, did not conduct an adequate evaluation of a degraded condition
associated with the 'B' phase high voltage bushing on 31 MT. Subsequently, the bushing
failed during power operation and resulted in a reactor trip, an explosion in the
transformer yard, and the declaration of a notification of a UE. The inspectors evaluated
the significance of this finding using Phase 1 of IMC 0609, Appendix A, "Significance
Determination of Reactor Inspection Findings for At-Power Situations." This finding was
determined to be of very low safety significance because, while it was a transient initiator
that resulted in a reactor trip, it did not contribute to the likelihood that mitigation
equipment or functions would not be available. The inspectors determined that this finding had a cross-cutting aspect in the area ofproblem identification and resolution, because Entergy failed to promptly identify an
adverse condition in the corrective action program in a timely manner commensurate with
its safety significance. (P.1(a))In response to the inspectors' initial conclusion, Entergy provided further informationwhich the staff subsequently reviewed. Entergy stated that the transmission and
distribution system expert could make an adequate recommendation concerning the
bushing without reviewing the 1999 power factor test results. The NRC staff disagrees
with this conclusion, and considers the rapid change in power factor from test to test to
be relevant in determining whether or not the bushing should remain in service.
20EnclosureIn addition, Entergy asserted that the operating experience associated with theGrand Gulf Nuclear Station transformer was fundamentally different; in that, the power
factor testing result was greater than 1.5 percent and required bushing replacement.
The NRC staff acknowledged this fact. However, the staff concluded that Entergy
utilized the Doble Engineering criteria to replace the bushing at the Grand Gulf Nuclear
Station; and had the same criteria been utilized at Indian Point Energy Center, it is
reasonable to conclude that bushing replacement would have occurred in this
circumstance because the Doble Engineering criteria also recommends bushing
replacement if a sudden increase in power factor occurs between tests, if above 1.0
percent power factor. Furthermore, Entergy stated that utilizing their corrective action process would notnecessarily have led to a different decision on their part. The NRC staff disagrees with
this conclusion and believes that implementation of the guidance in Entergy procedures
DC-115, "Engineering Request Response Development," would have resulted in a
determination that the bushing should be replaced prior to returning it to service.Evaluation. No violation of regulatory requirements occurred. The inspectorsdetermined that the finding did not represent a noncompliance, because the failure to
enter the degraded condition into the corrective action program or adequately evaluatethe condition occurred on a non-safety-related system. (FIN 05000286/2007003-01,Failure to Identify in the Corrective Action Process, or Adequately Evaluate a
Degraded Condition Associated with a High Voltage Bushing on a Main
Transformer)4OA5Other Activities.1 Groundwater Contamination Investigation a.Inspection ScopeContinued inspection of Entergy's plans, procedures, and characterization activitiesaffecting the contaminated groundwater condition at Indian Point, relative to NRC
regulatory requirements, was authorized by the NRC Executive Director for Operations in
a Reactor Oversight Process deviation memorandum dated October 31, 2005
(ADAMS Accession number ML053010404) and renewed on December 11, 2006
(ADAMS Accession number ML063480016). Accordingly, continuing oversight of
Entergy's progress has been conducted throughout this quarterly inspection report period
consisting of onsite inspections, independent split sample analyses of selected
monitoring well samples, review of action plan completion status, and periodic
communications with Federal, State, and local government stakeholders.Inspectors conducted an onsite review of tracer test sampling results onMay 9 and 10, 2007. New York State Department of Environmental Conservation
officials observed and participated in the proceedings. The onsite meeting provided for
an independent hydrology review of Entergy's tracer test findings and associated
re-evaluation of the current site groundwater model.
21Enclosure b.Findings and ObservationsNo findings of significance were identified.The objective of the tracer test, as mentioned above, was to identify groundwater flowand direction by injecting fluorescent tracer dye into a subsurface location representing
the source of leakage, and tracking its natural groundwater migration as it was
intercepted by existing monitoring wells and storm drain locations. The fluorescein dye
was injected into a specially designed tracer injection co-located near monitoring well
SFP). On February 8, 2007, the tracer
test began with injection of approximately 200 gallons of dye at a subsurface elevation
equivalent to the bottom of the Unit 2 spent fuel pool. The natural groundwater migration
of this tracer has been tracked for approximately 13 weeks by measuring the dye content
in either charcoal samplers or water samples collected at selected onsite monitoring
wells and storm drain locations.The tracer test was designed as an analogue to the Unit
GZA, described (through its visualizations) how the tracer entered
the unsaturated zone above the local water table similar to the abnormal releases from
the Unit 2 SFP, and moved horizontally to adjacent wells before moving vertically into the
saturated zone. GZA also noted the roles of backfills which provide preferential paths to
the storm drains as was demonstrated from tracer material observed in the manholes
near the Unit
- 2 SFP. [[]]
GZA indicated that its preliminary assessment considered flow and transport in theInwood Marble formation to be dominated by porous media flow conditions, and that the
fractures were so numerous and interconnected at the site scale that it may not be
reasonable to single out and ascribe parameters for fracture flow and transport
modeling. The
USGS) indicated the possibility that analysis of
borehole data (e.g., downhole logging data), pump test and ambient flow results, and
observed fracture orientations and spacing using the
- WELLC [[]]
AD code could provide
insights to discern the presence of significant fracture zones, and their transmissivities
(i.e., flow parameters). To this end,
USGS to accomplish
an independent analysis considering an alternative conceptual model of flow and
transport. Additional review and evaluation is expected to ascertain if there could be any
significant difference in groundwater flow that would affect the overall assessment of
public dose.GZA noted that it was in the process of modifying its dose assessment model to factor inmore realistic, site-specific conditions and parameters that were revealed from the
recovery well
- US [[]]
GS, and
NRC staff agreed that it was important to effectively consider the groundwater recharge
zones and net flow discharge zones, and couple the information with the data developed
from the pumping and tracer test; and the transmissivity values for the fracture zone as
derived from
- WELLC [[]]
AD modeling results. Such effort is expected to provide a more
refined estimate of groundwater effluent release and dose assessment.
2EnclosureNRC,
GZA staff discussed the development of a site-wide, long-term monitoring program plan to be linked to the dose assessment model. The plan
would identify which existing wells and manhole sampling locations could provide the
best performance indicators of the groundwater flow system behavior, and provide early
detection of any abnormal radiological releases from onsite structures, systems, and
components. Based upon the technical discussions, current remediation strategies include thecontinued processing of the Unit 1 spent fuel pool utilizing filter/demineralization
processes; the eventual removal of the spent fuel to dry cask storage; and subsequent
draining of the Unit 1 spent fuel pool. Such activities are planned to be accomplished by
Entergy in 2008. Currently, Entergy has no plans for further pumping tests using RW-1
since it was demonstrated that pump-out of the groundwater through this location will
result in cross-contamination of groundwater in the vicinity of Unit 2. Entergy indicated
that the groundwater conditions would continue to be evaluated for remediation, as
necessary, upon completion of the Unit 1 spent fuel pool activities. Monitoring for tracer material is expected to continue through July 2007, and samplingresults will be reported to the
- NYS [[]]
- DEC. [[]]
GZA agreed to provide well logging,
pumping test, and fracture characterization data for
WELLCAD modeling.
Follow-on technical meetings will focus on GZA's final monitoring report which
incorporates their new dose assessment model;
WELLCAD analyses; and
development of a site-wide groundwater monitoring plan.The
NRC's contract laboratory, theOak Ridge Institute for Science and Education, Environmental Site Survey and
Assessment Program (ORISE/ESSAP) radioanalytical laboratory. The NRC's
assessment of Entergy's sample analytical results data indicated that their analytical
contractor continued to report sample results that were comparable with the NRC's
analytical results. Information to date continues to support that the estimated radiological
release fraction through groundwater is negligible relative to
ML071900462. To date, sample results
from site boundary wells and offsite environmental groundwater sampling locations have
not indicated any detectable plant-related radioactivity..2(Closed)
- URI 05000286/2006301-01, Examination Development Issue a.Inspection ScopeIn response to a notification by the licensee that a potential compromise in examinationsecurity may have occurred, the
NRC initiated an investigation (Office of Investigations,
1-2007-003). This investigation included reviewing licensee procedures, training records,
and interviews with applicants, trainers, and supervisors. The investigation assessed
whether a compromise had occurred and, if substantiated, determined the extent of the
compromise, and gathered information to support potential enforcement actions.
23EnclosureThis issue was initially documented as
CFR 55, "Operator's Licenses," and the
guidance of
- NUR [[]]
EG-1021, "Operator Licensing Examination Standards for Power
Reactors," Revision 9, were used as criteria. b.FindingsA licensee-identified violation is documented in section
OA6Meetings, including ExitExit Meeting SummaryOn July 13, 2007, the inspectors presented the inspection results to Mr. Anthony Vitaleand other Entergy staff members, who acknowledged the inspection results presented.
Entergy did not identify any material as proprietary.4OA7Licensee-Identified ViolationsThe following Severity Level
NRC Enforcement
Policy,
- NUREG 1600, for being dispositioned as a non-cited violation.Prior to administering the 2006 initial licensed operator
NRC examination, Entergyinformed the NRC that regulations and guidelines regarding examination security may
not have been followed. Specifically, a training supervisor was directing training to be
conducted for examination topics that were not previously covered during the applicants'
training. After receiving this report, the NRC, in parallel with Entergy, conducted an
investigation to determine the nature and extent of the issue. The NRC determined that
the extent of the compromise was ultimately limited to two questions on the written
examination and one job performance measure (JPM). To ensure the integrity of the
written examination, these two questions and twenty three others were removed from the
examination. These questions were replaced with other randomly selected test items
that were provided by the
JPM was replaced. Based upon the
replaced JPM, the nature of the operating examination, and the security arrangements,
the NRC did not consider the operating examination to be compromised. The
examination was determined to be valid and was administered. The investigation
continued to gather information to support potential enforcement actions. Following the administration of the examination, the NRC further investigated thepersonnel and events surrounding this issue and determined that the training supervisor
had misinterpreted NRC guidance regarding what was, and what was not, appropriate
activities for a person in his position. Regardless of his understanding, and although his
actions were identified and corrected prior to the administration of the examination, the
NRC requirements as
stated below. NRC regulations prohibit facility licensees from engaging in any activity
that could compromise the integrity of any examination required by 10 CFR 55,
"Operator's Licenses."
24EnclosureThis finding was determined to be more than minor because the failure to administer anequitable and consistent licensed operator qualification examination had the potential to
cause a credible impact on safety since operators could have been considered for
licensing without demonstrating an adequate level of knowledge. This finding was
considered as traditional enforcement because the issue had the potential for impacting
the NRC's ability to make a licensing decision to permit individuals to operate the controls
of a nuclear power plant. This finding was determined to be a Severity Level IV non-cited
violation because no willfulness was involved, it was not repetitive, it was entered into the
licensee's corrective action program, and the licensee notified the
CFR 55.49, "Integrity of Examinations and Tests," states in part that, "applicants,licensees, and facility licensees shall not engage in any activity that compromises the
integrity of any application, test, or examination required by this part. The integrity of a
test or examination is considered compromised if any activity, regardless of intent,
affected, or, but for detection, would have affected, the equitable and consistent
administration of the test or examination. This includes activities related to the
preparation and certification of license applications and all activities related to the
preparation, administration, and grading of the tests and examinations required by this
part." Contrary to the above, Entergy developed and submitted the 2006 Initial LicensedOperator Qualification Examination for NRC review and approval and then subsequently
engaged in training activities in a manner which compromised the integrity of the
examination. The training activities in question occurred in late August 2006 and
throughout September 2006 in the weeks leading up to the examination which was
originally scheduled for the weeks of October 23 and 30, 2006. These training activities
were identified by the licensee and reported to the NRC. Subsequent investigations by
the NRC during the weeks of October 10 through December 15, 2006, determined that a
compromise, and thus a violation, had occurred. Entergy provided focused training on
examination test items just before the examination was to be administered, thereby
undermining the ability of the NRC to infer adequate mastery of the necessary
knowledge and abilities for making a licensing decision. Entergy entered this issue into their corrective action program (CR IP3 2006-02786 and03108) and immediately initiated a root cause investigation. Entergy's investigation
made a determination regarding the extent of the compromise, which corresponded to
the results of an independent investigation conducted by the NRC. Because the issue
was placed in the corrective action program and compliance was restored before the
examination was administered and because the issue was not repetitive nor willful, this
violation is being treated as a Severity Level IV non-cited violation, consistent with
Section
- ATTACH [[]]
- MENT [[:]]
- SUPPLE [[]]
- MENTAL [[]]
- INFORM [[]]
- INFORM [[]]
- POINTS [[]]
- OF [[]]
- CONTAC [[]]
TLicensee PersonnelF. Dacimo, Site Vice PresidentJ. Comiotes, Director, Nuclear Safety Assurance
A. Williams, Acting Site Operations Manager
A. Vitale, Acting Plant Manager
T. Barry, Security Manager
J. Donnelly, Manager, Maintenance
P. Conroy, Manager, Licensing
B. Sullivan, Emergency Planning Manager
T. Jones, Licensing Supervisor
L. Lee, Systems Engineering Supervisor
T. Orlando, Manager, Design Engineering
P. Cloughhessy, Maintenance Rule Program Coordinator
N. Azevedo, Codes and Fire Protection
S. Verrochi, System Engineering Manager
S. Davis, Superintendent, Operations Training
R. Christman, Training Manager, Indian Point Energy Center
D. Huntington, Senior Instructor
- LIST [[]]
- OF [[]]
- ITEMS [[]]
- AND [[]]
DISCUSSEDOpened and Closed05000286/2007003-01FINFailure to Identify in the Corrective Action Process,or Adequately Evaluate a Degraded Condition
Associated with a High Voltage Bushing on a Main
TransformerClosed05000286/2006301-01URIExamination Development Issue
05000286/2007-001-00LERManual Reactor Trip Due to Decreasing SteamGenerator Levels as a Result of the Loss of
Feedwater Flow Caused by the Failure of 32 Main
Feedwater Pump Train A Control Logic Power
Supply
A-2Attachment05000286/2007-002-00LERAutomatic Reactor Trip Due to a Turbine-GeneratorTrip Caused by a Fault on the 31 Main Transformer
Phase B High Voltage BushingLIST
- OF [[]]
- REVIEW [[]]
EDSection 1R01: Adverse Weather ProtectionProcedures3-SOP-RW-002, Rev 22: "Intake Structure Operation"3-SOP-RW-001, Rev 29: "Circulating Water System Operation"
OAP-008, Rev 2: "Severe Weather Preparations"
OAP-48, Rev 4: "Seasonal Weather Preparation"
3-SOP-FP-001, Rev 28: "Fire Protection System Operation"
3-SOP-V-006, Rev 15: "Heating and Ventilation Systems"Work Orders:IP3-06-01219IP3-05-01995I3-027709969IP3-06-01230
COL-FPV-1, Rev 2: "Fire Pump House Verification"3-COL-FW-2, Rev 29: "Auxiliary Feedwater System"
3-PT-M042B, Rev 4: "Diesel Fire Pump Test"
3-PT-Q117B, Rev 5: "32 Containment Spray Pump Functional Test"
CSV-1, Rev 5: "Containment Spray Verification"Drawings9321-F-201939321-F-201839321-F-201739321-F-204139321-F-275039321-F-27353Condition ReportsIP3-2005-05226IP3-2007-00687
Work OrdersI3-017701087IP3-06-02130IP3-04-09148IP3-07-00257IP3-06-16687IP3-06-16638IP3-05-14887IP3-04-06137Section 1R05: Fire ProtectionProceduresENN-DC-161, Rev 1: "Transient Combustible Program"SMM-DC-901, Rev 2: "IPEC Fire Protection Program"
A-3AttachmentMiscellaneousPre-Fire Plan 306, Rev 0: "General Floor Plan- Primary Auxiliary Building"Pre-Fire Plan 264, Rev 0: "Intake Structure - Exterior Buildings"
Pre-Fire Plan 265, Rev 0: "Diesel Fire Pump House - Exterior Buildings"
Pre-Fire Plan 351, Rev 5: "480V Switchgear Room- Control Building"
Pre-Fire Plan 308A, "Volume Control Tank- Primary Auxiliary Building," Revision 0Condition ReportsIP3-2007-02302347Section 1R06: Flood Protection MeasuresProcedures2-AOP-FLOOD-1, Rev 5: "Flooding"3-AOP-FLOOD-1, Rev 3: "Flooding"
- EN [[-DC-147, Rev 2: "Indian Point Units 2 & 3 Eddy Current Program"0-HTX-400-GEN, Rev 1: "Eddy Current Inspection of Heat Exchanger Tubes"Section 1R11: Licensed Operator Requalification ProgramProceduresE-0, Rev 21: "Reactor Trip or Safety Injection"E-3, Rev 20: "Steam Generator Tube Rupture"Other DocumentsLRQ-SES-37, Rev 8: "MFRV Fails Closed,]]
- LI -102, Rev 8: "Corrective Action Process"Condition ReportsIP3-2006-02827IP3-2006-00565IP3-2006-01001IP3-2007-01545MiscellaneousENN-MS-S-008, Attachment 7.2, Rev 0: "Maintenance Rule Action Plan for Unit 3 ContainmentBuilding Pressure Relief Valve
PCV-1190"
A-4AttachmentSection 1R13: Maintenance Risk Assessment and Emergent Work ControlProceduresIP-SMM-WM-101, Rev 1: "On-Line Risk Assessment"IP-SMM-WM-100, Rev 5: "Work Control Process"
MA-125, Rev 2: "Troubleshooting Control"
3-AOP-VAC-1, Rev 4: "Loss of Condenser Vacuum"Work OrdersIP3-07-00739IP3-07-20519IP3-06-21771IP3-07-21140IP3-07-00415Condition ReportsIP3-2007-02148IP3-2007-02350IP3-2007-02357IP3-2007-02594IP3-2007-02595IP3-2007-02312IP3-2007-02327IP3-2007-02324MiscellaneousSystem Description 27.2, "Exciter"Troubleshooting Control Form , "Reactivity Anomaly of the RCS"
Entergy letter
- NL -05-026, dated February 22, 2005; regarding Alternate Source Term licenseamendment request.Entergy letter
- NL -04-068, dated June 2, 2004; regarding Full Scope Adoption of AlternateSource Term.Section 1R15: Operability EvaluationsProcedures
IP-SMM-AD-102, Rev 4: "IPEC Implementing Procedure Preparation, Review and Approval"EN-OP-104, Rev 4: "Operability Determinations"
LI-102, Rev 8: "Corrective Action Process"
3-PT-Q016, Rev 19: "EDG and Containment Temperature
SWN-1176 & 1176A andSWN-TCV-1104 & 1105"3-PT-R090D, Rev 12: "Emergency Local Operation of Auxiliary Boiler Feed Pumps"
3-SOP-ESP-001, Rev 17: "Local Equipment Operation and Contingency Actions"
3-PT-M108, Rev 3: "RHR/SI System Venting"
SOP-SI-001, Rev 38: "Safety Injection System Operation"Condition ReportsIP3-2005-00695IP3-2007-02059IP3-2007-02442IP3-2007-02441
Drawings93-13102: Darling Double Disc Gate Valve
A-5AttachmentCalculationsCN-SEE-03-128-R.1: "Indian Point Unit 3 Containment Spray
BOP Licensing Report
ProceduresEN-DC-105, Rev 0: "Configuration Management"ENN-DC-103, Rev 1: "Design Process"
DC-115, Rev 6: "ER Response Development"
DC-117, Rev 4: "Post Modification Testing and Special Testing Instructions"
3-OSP-WDS-001, Rev 2: "RCS and Refueling Cavity Cleanup"
OAP-7, Rev 10: "Containment Entry and Egress"
3-AOP-SW-1, Rev 2: "Service Water Malfunction"
LI-102, Rev 8: "Corrective Action Process"Section 1R19: Post-Maintenance TestingProceduresOAP-024, Rev 2: "Operations Testing"3-SOP-FW-004, Rev 26: "Auxiliary Feedwater System Operation"
3-PT-Q117B, Rev 5: "32 Containment Spray Pump Functional Test"
0-VLV-413-MOV, Rev 2: "Motor Operated Valve Minor Preventive Maintenance"
0-VLV-412-MOV, Rev 2: "Use of Motor Operated Valve Diagnostics"
3-PT-Q088, Rev 15: "Component Cooling Pumps Functional Test"
3-PMP-003-CCW, Rev 0: "Inspection/Repair of the Component Cooling Pump"
0-VLV-420-GEN, Rev 0: "Inspection and Repair of Conval Clampseal Piston Check Valves"
3-PT-Q062A, Rev 8: "31 Charging Pump Operability Test"Work OrdersIP3-07-19935IP3-07-19744IP3-07-00739IP3-07-20519IP3-07-12275IP3-02-22193IP3-03-23793IP3-03-10580
IP3-2007-02370Section 1R20: Refueling and OutageProcedures3-POP-1.2, Rev 49: "Reactor Startup"3-SOP-RC-001, Rev 27: "Full Length Rod Control and RPI System Operation"
3-AOP-ROD-1, Rev 01: "Rod Control and Indication Systems Malfunction"
A-6Attachment3-POP-1.3, Rev 51: "Plant Startup from Zero to 45% Power"3-POP-4.2, Rev 23: "Operation Below 20% Przr Level with Fuel in the Reactor"OAP-007, Rev 10: "Containment Entry and Egress"3-POP-4.2, Rev 23: "Operation Below 20% Pressurizer Level with Fuel in the Reactor"
3-POP-4.1, Rev 25: "Operation at Cold Shutdown"Condition ReportsIP3-2007-02099IP3-2007-01998
Work OrdersIP3-07-00736Section 1R22: Surveillance TestingProceduresSOP-WDS-010, Rev 13: "Monitoring Leaks Within The Containment Building"Condition ReportsIP3-2005-02985IP3-2005-03336IP3-2005-03289IP3-2005-01896IP3-2006-03061IP3-2006-02834IP3-2007-02338IP3-2007-02377
- IP 3-2007-02357Work OrdersIP3-05-16829IP3-05-15435IP3-05-22984IP3-06-17297IP3-05-22763IP3-07-13796Section
- EP -AD1, Rev 1: "Maintaining Emergency Preparedness"Condition ReportsIP2-2007-02051IP2-2007-02053IP2-2007-02054IP2-2007-02055IP2-2007-02056Section
- EN -LI-114, Rev 2: "Performance Indicator Process"NEI 99-02, Rev. 4: "Regulatory Assessment Performance Indicator Guideline"
LI-114, Attachment 9.2, Rev 2: "NRC Performance Indicator Technique Sheet" Condition Reports:IP3-2007-02552IP3-2006-00046IP3-2006-01001
A-7AttachmentMiscellaneous:Maintenance Rule Program Quarterly Report, First Quarter 2007Section
- EN [[-NS-116, Rev 2: "Access Authorization Processes"EN-NS-102, Rev 3: "Fitness for Duty Program"MiscellaneousIndian Point Energy Center Quarterly Trend Report- 4th Quarter 2006Indian Point Energy Center Quarterly Trend Report- 1st Quarter 20072006 Unit 3 Annual Report, Central Control Room]]
- HV [[]]
- AC [[]]
- AFW [[]]
- IP 2-2007-00682IP3-2007-01867IP3-2007-01870IP2-2007-01514IP3-2007-01803IP3-2006-00511IP2-2005-03898IP2-2006-04874
- OF [[]]
ACRONYMSADAMSagencywide documents and management systemANSalert notification system
AFWauxiliary feed water
CAPcorrective action program
- CF [[]]
RCode of Federal Regulations
- DE [[]]
CDepartment of Environmental Conservation
- ESSA [[]]
PEducation, Environmental Site Survey and Assessment Program
IMCinspection manual chapter
IP2Indian Point Nuclear Generating Unit 2
IP3Indian Point Nuclear Generating Unit 3
IPEindividual plant examination
A-8AttachmentLERlicensee event reportMWmonitoring well
- NE [[]]
- NR [[]]
- ORIS [[]]
- PA [[]]
RSpublicly available records
PIperformance indicator
RHRresidual heat removal
RW recovery well
SDPsignificance determination process
SFP spent fuel pool
SIsafety injection
SSCsystems, structures, components
TStechnical specifications
UEunusual event
- UFS [[]]
ARupdated final safety analysis report