ML20141F830
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| ML20141F830 | |
| Person / Time | |
|---|---|
| Site: | Haddam Neck File:Connecticut Yankee Atomic Power Co icon.png |
| Issue date: | 05/08/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20141F808 | List: |
| References | |
| 50-213-97-01, 50-213-97-1, NUDOCS 9705220064 | |
| Download: ML20141F830 (101) | |
See also: IR 05000213/1997001
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
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Docket No.: 50-213
License No.: DPR-61
Report No.: 50-213/97-01 ,
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Licensee: Connecticut Yankee Atomic Power Company i
P. O. Box 270 l
Hartford, CT 061410270
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Facility: Haddam Neck Station
Location: Haddam, Connecticut
Dates: January 6 - April 7,1997
Inspectors: William J. Raymond, Senior Resident inspector
Ronald L. Nimitz, Senior Radiation Specialist
Laurie A. Peluso, Radiation Physicist
Eben L. Connor, Project Engineer
Approved by: John F. Rogge, Chief, Projects Branch 8
Division of Reactor Projects
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9705220064 970508 "
PDR ADOCK 05000213
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EXECUTIVE SUMMARY
Haddari Neck Station
NRC Inspection Rsport No. 50-213/97-01
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a three month period of resident
inspection; in addition, it includes the results of announced inspections by regional
inspectors in the areas of radiological controls, environmental monitoring, and plant
procedures.
Plant Operations:
The conduct of opereting activities was acceptable, as were the operator actions to
maintain stable defueled conditions, and to monitor the status of spent fuel cooling and
systems in long term preservation. An inspection item will follow licensee initiatives to
categorize and control plant systems for decommissioning, and to reduce the number of
illuminated annunciators. The quality of procedures used for shutdown operations was
acceptable, and licensee initiatives to improve and maintain procedures were satisfactory.
However, inadequate calibration procedures resulted in the declaration of all gaseous and
liquid effluent radiation monitors required by the technical specifications to be inoperable,
and the need to implement compensatory measures to monitor effluents by the associated
release pathways. Cold weather preparations were adequate to protect support systems
for spent fuel cooling; however, the failure to complete thorough plant walkdowns and ,
poor insulation conditions on some piping resulted in freeze damage to a process line.
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As in past inspections, human performance errors by operators and workers detracted from
good performance. The procedure violation resulting in the operation of red tagged
equipment was a significant and recurrent event. Several other examples of failure to j
adequately follow plant procedures were noted. Poor performance was demonstrated in
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the administration of the licensed operator training program, and to assure that operators
are fully qualified initially and remain qualified through periodic retraining. Weaknesses
were noted in the control of overtime to assure that excessive work hours were approved
per the administrative guidelines. Although the spent fuel remained adequately cooled at ;
all times, a discrepancy in the design basis and deficiencies in the material condition of the
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service water system created a challtinge to the adequacy of the spent fuel cooling
system. Licensee actions to address these deficiencies, as well as the operator actions to I
implement alternate cooling methoris for the spent fuel pool, were acceptable. l
Maintenance:
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The maintenance and surveillance activities completed this period were generally 1
acceptable to assure important plant s'/ stems remained operable, to support operability )
evaluations and design change work, and to address emergent issues that challenged j
adequate cooling of the spent fuel. Exceptions to good performance included a weakness
in the process to examine service water (SW) pipe for corrosion, and a faulty test method
used to measure leakage through a check valve. Additional discrepancies were noted in
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plant material conditions, in the implementation of the program to identify and correct
material discrepancies, and in the lack of progress in addressing deficient conditions.
Poor performance was noted in the failure by station personnel to follow procedur6s to
implement the operational surveillance program, and in the repetitive failure to adequately
implement technical specification surveillances in a timely manner. The extensive
corrosion and general degradation in the service water system resulted in an inoperable
condition for the system relied upon to cool the spent fuel. This finding appears as another i
example of poor plant material conditions that challenge systems important to plant safety. i
The recurrence of plant material deficiencies and problems in the area of technical
specification surveillance testing revealed ongoing weaknesses in the corrective action
process. ;
Ennineerina:
Mixed performance was noted in the engineering support of operations. Engineering
performance was good in response to emergent design basis issues and corrosion
degradation in the SW system. Engineering evaluations were good to identify the
inoperabilities in the SW piping, to assess the interim use of the degraded system, and to
support the correction of design and corrosion issues. Engineering support for design i
changes was also good to correct the SW problems. Exceptions to good performance
. were noted in the failure to fully integrate site and corporate engineering support, and to
assure continued chemical (Bulaab) treatment of the SW system during shutdown
conditions. Poor performance was noted in the failures to track design issues to
completion (waterhammer), to properly classify design issues (two phase flow) for the
shutdown condition of the plant, and to track commitments to the NRC. These issues
appear as weaknesses in the corrective action process.
Several design basis discrepancies were discovered either by good licensee staff and QAS
initiatives to identify and resolve discrepancies, or by the Configuration Management Plan
(CMP) group as the reviews to reconstitute the plant design and licensing basis are
completed. The identification of additional design basis issues is expected until the
completion of the CMP plan for the shutdown and decommissioned plant. However, l
exceptions to good performance were noted in the failure to address the design basis issue
adequately relative to SW temperature, which appears as an example of a corrective action
weakness. Inspection items will track the completion of licensee actions to correct
discrepancies in the plant design and material conditions.
Plant wide weaknesses in the corrective action process were noted during this period as
events occurred that were a repeat of past problems. While the number of deficiencias
identified by licensee has generally increased, a large number of deficiencies were
identified either by self disclosing events or by the independent oversight groups. The
licensee has yet to complete initiatives to improve the corrective action program to assure
consistent quality root cause investigations and to implement effective corrective actions.
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Plant Support:
The licensee continued to implement controls for work within the radiological controlled
area in accordance with commitments outlined in its December 9,1996, letter to the NRC.
A number of program improvements, in response to the November 2,1996, fuel transfer
canal event, were completed. Weaknesses were identified in the contamination control
and ALARA program that should be addressed prior to decommissioning. The capabilities
of the quality assurance organization were enhanced through the addition of individuals
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with extensive radiological controls experience and experience in decommissioning.
Because of NRC concerns regarding the adequacy and effectiveness of the radiological )
controls program, a Confirmatory Action Letter (CAL 1-97-007) was issued on
March 4,1997. ,
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The licensee continued to implement an overall effective radiological environmental 1
monitoring program (REMP) including management controls, quality assuranco audits,
radiological environmental monitoring, and meteorological monitoring program. The
Radiological Effluent Monitoring and Offsite Dose Calculation Manual (REMODCM) was
properly implemented. The 1996 audit report effectively assessed program strengths and
weaknesses and had improved from previous audit assessments. No deficiencies in the
Updated Final Safety Analysis Report commitments were identified. An inspection follow-
up item was identified related to determining the licensee's conformance with 40 CFR 190.
Safety Assessment & Quality Verificatioru
Several findings by the QA audit and surveillance groups during the period demonstrated
good performance by the oversight groups to identify deficiencies in plant operating
activities. The failures to complete correc.tive actions, including the failure to complete
committed regulatory actions, were a previously identified weakness. The licensee has i
implemented plans to address this area and to improve performance. Despite the progress I
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in identifying deficiencies, the licensee had demonstrated continued weaknesses in
implementing adequate corrective actions. While the number of deficiencies identified by l
licensee staff has generally increased, a large number of deficiencies were identified either 1
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by self disclosing events, by the independent oversight groups (quality organization, NRC).
There have been further examples of events that occurred which were a repeat of past
problems. The examples included the deficiencies in the tracking and timely completion of
surveillance activities; the recurrence of personnel performance areas in broad areas of
plant operations; and, the failure to preclude plant operation outside the design basis (river
water temperature, service water two phase flow). The licensee has yet to complete its
initiatives to improve the corrective action program to assure consistent quality root cause
investigations and to implement effective corrective actions.
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TABLE OF CONTENTS i
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EXEC UTIV E StJ M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TABLE OF CONTENTS . . . . . . . . . . . . . . . . . . . . . . . ...................... V
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R E PO RT D ETAI LS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Su m m a ry o f Pla nt St a tu s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1. O P ERA TI O N S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
. 01 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
01.1 Review of Operating Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
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01.2 Status and Control of Systems in the Defueled Mode (URI 97-01-01) . . . 2
01.3 Spent Fuel Pool Cooling and Building Ventilation ................. 3
01.4 Inoperable Spent Fuel Cooling System . . . . . . . . . . . . . . . . . . . . . . . . . 4-
. . 01.5 Implementation of Alternate SFP Cooling ...................... 6
01.6 Loss of a 115 kV Distribution Line ........................... 7
01.7 Inoperable Effluent Monitoring System ........................ 8
01.8 Control of System Configuration (VIO 9 7-01 -0 2. a ) . . . . . . . . . . . . . . . . 8
01.9 Inadequate Control of Boiler Operations (VIO 9 7-01 -02.b) . . . . . . . . . . 10
01.10 Conclusions for Conduct of Operations ...................... 11
02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . . 11
O2.1 Cold Weather Preparations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
03 Operations Procedures and Documentation ......................... 13
03.1 Procedure Quality for Shutdown Operating Activities . . . . . . . . . . . . . 13 ,
05 Operator Training and Qualification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
05.1 Inaccurate Operator Training Records (URI 9 7-01 -0 3 ) . . . . . . . . . . . . . 14 '
06 Operations Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . 17
06.1 Staffing and Control of Overtime (VIO 9 7-01 -0 2.c ) . . . . . . . . . . . . . . . 17
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08 Previous Operations Open issues (92901) . . . . . . . . . . . . . . . . . . . . . . . . . . 19
08.1 (Closed) VIO 94-21-01, inadvertent Boron Dilution . . . . . . . . . . . . . . . 19
08.2 (Closed) URI 94-27-01, Loss of Electrical Separation . . . . . . . . . . . . . . 20
08.3 (Closed) LER 94-011-00, Unplanned Loss of Spent Fuel Cooling ..... 20
08.4 (Closed) LER 94-015-01, Main Steam Vaives Exceed Lift Setpoints . . . 21
08.5 (Closed) IFl 96-08-01, RHR Calibrations and Leakage . . . . . . . . . . . . . 22
08,6 (Closed) LER 95-023-00, Failure to Prepare Special Report . . . . . . . . . 22
08.7 (Closed) URI 96 201-10, Alternate Auxiliary Feedwater Sources ..... 22
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08.8 (Closed) LER 96-015-00, Containment Air Monitor Trip Valve . . . . . . . 23
II . M AI NT EN A N C E . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
M1 Conduct of Maintenance ...................................... 23
M1.1 Maintenance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
M1.2 Surveillance Observations ................................ 28
M2 Maintenance and Material Condition of Facilities and Equipment .......... 31
M 2.1 Material Condition Deficiencies (VIO 97-01-02.d, URI 97-01-04) ..... 31
M3 Maintenance Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . 33
M3.1 TS Surveillances Covered by Procedures (VIO 97-01-02.e) ......... 33
M4 Maintenance Staff Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . 34
M4.1 Failure to Complete Surveillances (VIO 97-01-05, VIO 97-01-06) . . . . . 34
M8 Area Summary and Status of Regulatory Findings .................... 37
M8.1 (Closed) IFl 96-01-01, Cable Vault Materials Condition , . . . . . . . . . . . 37
M8.2 (Closed) DEV 96-04-02, Heavy Load Program Commitments . . . . . . . . 37
M8.3 (Closed) IFl 96-08-04, Auxiliary Feed Water Overspeed Trip ........ 37
M8.4 (Closed) IFl 96-08-05, Steam Generator Hold Down Bolts . . . . . . . . . . 38
M8.5 (Closed) IFl 96-08-06, Observations of Procedural Quality.. . . . . . . . . . 38
M8.6 (Open) URI 96-08 15, Start-up issues (7/24/95 NRC Letter) ........ 38
M8.7 (Closed) URI 94 27-04, Surveillance Frequency Exceeded . . . . . . . . . . 39
M8.8 Conclusions for Maintenance .............................. 39
t il . E N G I N E E R I N G . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40
El Conduct of Engineering ....................................... 40
E1.1 Service Water System Modification - Water Hammer (URI 97-01-07) .. 40
E1.2 Service Water System Evaluations - Corrosion (URI 9 7-01 -0 8 ) . . . . . . . 43
E1.3 Conclusions for Conduct of Engineering ...................... 45
E3 Engineering Documentation - Design Basis Discrepancies (40500) . . . . . . . . . 45
E3.1 Handling Loads Over Stored Fuel ........................... 40
E3.2 Control Room Habitability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46
E3.3 Mis sed Commitm e nts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
E3.4 Service Water Design Basis issues .......................... 48
E3.5 Service Water System Water Hammer . . . . . . . . . . . . . . . . . . . . . . . . 49
E3.6 Inoperable Effluent Monitor - Stack Noble Gas . . . . . . . . . . . . . . . . . . 50
E3.7 Spent Fuel Building and Yard Crane Design Basis issues . . . . . . . . . . . 50
E3.8 Conclusions for Engineering Documentation (URI 97-01-09) ........ 51
E6 Engineering Organization and Administration ........................ 51
E6.1 Corrective Action Program Weaknesses . . . . . . . . . . . . . . . . . . . . . . . 51
E8 Miscellaneous Engineering issues (92902) . . . . . . . . . . . . . . . . . . . . . . . . . . 53
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E8.1 Spent Fuel Pool Design to Support Full Core Off-load . . . . . . . . . . . . . 53
E8,2 (Closed) IFl 94-09-03, HPSI Relief Valve Setpoint Drift ............ 54
E8.3 (Closed) VIO 96-04-03, inadequate Safety Evaluation . . . . . . . . . . . . . 55
E8.4 (Closed) IFl 96-04-04, Heavy Load Controls . . . . . . . . . . . . . . . . . . . . 55
E8.5 (Update) URI 96-06-06, Battery Oscillations and Ground . . . . . . . . . . . 55
E8.6 (Closed) URI 96-201-12, Analysis Supporting LPSI Pump Shutdown .. 56
E8.7 (Closed) URI 96-201-31, RWST instrument Calibrations ........... 56
E8.8 (Open) URI 96-02-03, Control Room Habitability ................ 57
IV. PL A NT S U PPO RT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
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-R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . . . . . . 59
R1.1 External and Internal Exposure Controls . . . . . . . . . . . . . . . . . . . . . . . 59
R1.2 ALARA Program ....................................... 61
R1.3 Radiological Environmental Monitoring Program (IFl 97-01 -10) . . . . . . . 63
R1.4 Meteorological Monitoring Program (MMP) . . . . . . . . . . . . . . . . . . . . . 66
R2 Status of RP&C Facilities and Equipment ........................... 67
H2.1 Inoperable Ef fluent Monitors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67
R3 RP&C Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69
R3.1 Whole Body Counting ................................... 69
R3.2 Contamination Controls (URI 9 7 -01 - 1 1 ) . . . . . . . . . . . . . . . . . . . . . . . 70
R5 Staff Training and Qualification in RP&C (URI 9 7-01 - 12 ) . . . . . . . . . . . . . . . . 70
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R6 Radiological Protection and Chemistry (RP&C) Organization and
Administration ............................................. 71
R6.1 Management Controls ................................... 72
R7 Quality Assurance in RP&C Activities ............................. 73
R7.1 Quality Assurance Audit Program . . . . . . . . . . . . . . . . . . . . . . . . . . . 73
R7.2 Quality Assurance of Analytical Measurements ................. 75
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R8 Miscellaneous RP&C issues .................................... 76 !
R8.1 Decommissioning Project Planning .......................... 76 l
R8.2 Followup of the November 2,1996, Fuel Transfer Canal Event ...... 76 i
R8.3 (Open) URI 96-12-01,02: Exposure Assessment, Dose Calculations .. 79 l
R8.4 H ou s e k e e ping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
R8.5 Confirmatory Action Letter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
R8.6 UFSAR .............................................. 83
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P2 Status of EP Facilities, Equipment, and Resources .................... 84 l
P2.1 Emergency Plan Staffing ................................. 84 )
S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . . . . . . 85
S1.1 Fit n e s s f or D uty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85
S1.2 Guard Inattentive To Duty ................................ 85 i
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S1.3 Response to Potential Threat .............................. 85
S1.4 Failure to Search Packages (VIO 97-01-02.f) ................... 85
V. MANAGEMENT MEETINGS ....................................... 86
X1 Exit M e eting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
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REPORT DETAILS
Summarv of Plant Status
Haddam Neck remained shutdawn with the reactor in a defueled condition during the
inspection period. The licer.see formally ended refueling outage RFO #19 and maintained
stable plant conditions while planning the activities needed to prepare the post shutdown
decommissioning activit" report and prepare for decommissioning the plant. NRC activities
at the site during the peiiod included the reviews by the resident inspector of post
operating activities and the plans to commence decommissioning, and the inspections by
region based personnel in the areas of effluent monitor calibrations, radiological controls,
and the environmental monitoring program.
Significant events during this period included the discovery that contaminated materials
had been inadvertently released from the site, and that the radiation channels monitoring
plant effluents had not been properly calib.ated. Although spent nuclear fuel stored in the
spent fuel pool remained adequately cooled, the licensee declared the spent fuel cooling
system inoperable due to analyses that showed that service water cooling lines might not
remain operable for certain design basis events, and due to corrosion induced defects in
the service water piping. Licensee actions were in progress at the conclusion of the period
to address concerns in these areas.
Several changes in the licensee management organization occurred during the period, and a
major organizational change was announced on March 11,1997. Mr. Russell Mellor was
appointed to the new position of Director, Site Operations and Decommissioning, reporting
directly to Mr. Ted Feigenbaum, Executive Vice President and Chief Nuclear Officer. Mr. .
Mellor began his new duties in March 24,1997. Mr. Jere LaPlatney resigned from the
position of Unit Director effective March 27,1997. Mr. Gary Bouchard was named as the
Unit Directoc, with responsibility over the functional areas of operations, maintenance,
health physics, security, chemistry and building services. Mr. Gerald Waig assumed the
position of Operations Maneger, and Mr. Douglas Heffernan assumed the position of
Maintenance Manager. Mr. J. Haseltine remained the Engineering Director with oversight
over design engineering, engineering programs, corrective actions and the configuration
management plan. Mr. Brain Wood was named the Business Manager, with responsibility
for materials management, contracts, administration and finances. Mr. Noah Fetherston
assumed the position of Decommissioning Project Manager, with oversight for cost and
scheduling. Mr. Richard Sexton assumed the position Health Physics Manager effective on
March 31,1997. Lastly, on January 22, the licensee announced that Mr. Bernard Fox
would resign from the position of Chairman of the Board for Northeast Utilities effective on
August 1,1997.
NRC activities at the site during the period also included the following visits and tours:
members of the NRR Decommissioning Projects Directorate including Mr. Michael Masnick, ;
Mr. Morton Fairtile, and Mr. Seymour Weiss toured the site on January 9,14 and February l
10,1997. Mr. John Rogge, Chief of Reactor Projects Branch #8 toured the site on ;
Jaruary 14,15, March 12 and 13,1997. l
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l. OPERATIONS
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01 Conduct cf Operations'
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Using inspection Procedure 71707, the inspector conducted periodic reviews of 3
plant status and ongoing operations. Operator actions were reviewed during
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periodic plant tours to determine whether operating activities were consistent with l
. the procedures in effect and the conditions of the license requirements. . ! !
The purpose =of this inspection was to review the licensee activities to maintain the l
i plant in the defueled condition, and to prepare for decommissioning activities.
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01.1 ' Review of Ooeratino Activities ,
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Operating activities during this period included those operations needed to maintain i
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stable plant conditions with the reactor defueled, to maintain adequate level in the 'l
spent fuel pool, and to assure adequate cooling of the spent fuel. The inspector ;
reviewed the licensee controls over those systems needed to assure the adequate j
: cooling of spent fuel under design basis conditions, and to monitor the status of - l
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radiological conditions at the plant and in plant effluents to the environment. The '
inspector independently verified that plant systems were properly aligned to satisfy. 4 .
the license conditions. l
The licensee maintained one service (SW) pump operating (pumps were rotated to j
. equalize the run times) to support spent fuel pool cooling. One component cooling j
.wster pump, and one of two turbine building closed cooling water pumps remained 1
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in service. . The normal and emergency electric distribution system remained in ]
service (except for periods of testing and repair).to support spent fuel pool cooling i
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and plant operations. A number of control board annunciators (approximately 90) J
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remained illuminated consistent with the plant shutdown and defueled. The
inspector reviewed the status of each annunciator and the reason it existed, and . ,
determined that the conditions were normal for the shutdown and defueled l
. condition of the plant. Operator actions in response to off normal conditions were I
reviewed and were found to be consistent with the respective annunciator
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01.2 Status and Control of Systems in the Defueled Mode (URI 97-01-01)
Following the end of refueling outage #19 with the completion of defueling, and the
licensee shutdown plant equipment and placed systems in standby or layup
. conditions for long term preservation. The licensee continued to implement
' , procedure NOP 2.0-4, Layup of Systems and Components, which provided the ! guidance for the general alignment and preservation of systems and components 4 '
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Topical' headings such as o1, M8, etc., are used in accordance with the
NRC_ standardized reactor inspection report outline. Individual reports are
not expected to address all outline topics.
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during extensive plant shutdowns and outages. The inspector independently verified
that the reactor, reactor coolant system and the containment were maintained in a
satisfactory condition for long term preservation.
The Operations Manager issued a directive (memorandum ODM 96-157) allowing
the manipulation of systems as specified by existing plant procedures for
maintaining shutdown conditions, but restricting the modification of Mant operating
configuration until a process was developed to assure the orderly transition from an
operating status.
Licensee actions continued during this period to develop a process to identify the
proposed system changes necessary to support decommissioning, and which would
assure the safety evaluations required under 10 CFR 50.59 would be done.
Additionally, the licensee began preparation of a proposed change to the technical
specifications that would address the permanently defueled condition. The licensee
planned to devise a means to deactivate or eliminate the annanciators that were not
needed for the defueled condition, with a goal of achieving a black board again. In
preparations for decommissioning, the licensee developed a procedure (ENG 1.7-6)
that provided a method to classify all plant systems into one of the following four
categories: operable, available, lay-up, or abandoned. _Licentee engineering-
personnel began a review during this period of all plant syste ms as identified on the
list of critical plant drawings to classify plant systems according the criteria in ENG
1.7-6. The licensee recognized the need for a method to provide a clear display of
plant system status on the main control boards as plant systems are classified and
released from operations.
The inspector reviewed the licensee plans to provide for a smooth transition from an
operating to a decommissionin0 status. NRC review of this area was in progress at
the end of this inspection period. This item is considered unresolved pending the
completion of licensee actions listed above, and subsequent review by the NRC.
Specifically, this item covers the actions to (1) classify plant systems to identify
which need to remain operable to assure maintenance of spent fuel pool cooling,
and which can be modified or abandoned in accordance with 10 CFR 50.59 and
removed permanently from service; (ii) devise and implement a method to provide a
clear display of plant system status on the main control boards as nierit systems are
classified and released from operations; and, (iii) to reduce or eliminate unnecessary
annunciators to facilitate operator actions te monitor plant conditions and respond
to off normal conditions (URI 97-01-01).
014 Scent Fuel Pool Coolina and Buildina Ventilation
a. Inspection Scoce (71707)
The purpose of this inspection was to review the licensee activities to monitor the
status of fuel stored in the spent fuel pool and assure the adequate cooling of spent
fuel.
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b. Q)servations and Findinas
The spent fuel ventilation and cooling systems were maintained functioning per
normal operating procedures (NOP) 2.10-1 and 2.15-3 to keep the spent fuel
cooled. The "B" spent fuel pool (plate) heat exchanger and at least one of the two
spent fuel cooling pumps remained in service to keep fuel pool temperature below
150 degrees Fahrenheit (F). The spent fuel building enclosure and ventilation
systern remained operable. The inspector reviewed licensee activitie.s to assure
compliance with the following Technical Specifications (TS):
TS 3.9.11, SFP Water Level
TS 3.9.12, Spent Fuel Building Air Cleanup System
TS 3.9.15, SFP Cooling
There were no activities during this period involving the movement of fuel or heavy
loads over the spent fuel pool. The licensee maintained the boron concentration in
the spent fuel pool at greater than 2500 ppm. The licensee conducted routine
surveillance of the spent fuel pool and building, which included the tours by the
nuclear side operators once each shift per SUR 5.1-0A. No inadequacies were
identified.
I
Spent fuel pool temperature remained in the range of 80 to 85 degrees F, until I
March 18,1997, when the pool was cooled down to 75 degrees F in preparation
for work on the service water (SW) cooling lines (see Section 01.4 below for
further details on the installation of an alternate cooling system). Spent fuel pool
temperature increased to a maximum of 100 degrees when the alternate cooling
system was installed on March 31. Operator observations noted a pool heatup rate
of about 1.3 degrees F/ hour while implementing the bypass, which agreed well with
the licensee prediction that pool heat up rate would be less than 1.7 degrees
F/ hour. Stable pool temperatures were maintained in the range of 95 to 98 degrees
F while on the bypass, with changes attributed to slight variations in nver j
temperature and supply flow.
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01.4 Inocerable Soent Fuel Coolina Svstem
On March 11, the licensee declared the spent fuel uooling system inoperable at
6:01 p.m. based on an engineering evaluatior, that concluded the service water
pipes providing cooling water to the SFP hr at exchangers might become inoperable
due to postulated waterhammer events fahowing a loss of normal power event
(LNP). The NRC review of the waterhamnier issue is provided in Section E1.1 of
this report. Although inoperable per the technical specifications, the spent fuel
cooling and service water systems remained functional to keep the fuel adequately
cooled at all times. The licensee reported this event to the NRC on March 11 per
10 CFR 50.72(b)(2)(l) as plant operation in a degraded and unanalyzed condition.
Technical Specification 3.9.15 requires that the spent fuel cooling system be
operable during the storage of irradiated fuel assemblies from a full core offload in
the pool. The specification requires that both spent fuel cooling pumps be operable
.
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5
with at least one pump and the plate heat exchanger in operation. The heat
exchanger was deemed inoperable due to the reliance on the service water system
for cooling, the operability of the SW system could not be assured for a design
basis event. Althouph the operability of the ultimate heat sink (including the service
1 water system) is m <,obed in TS 3.7.12, the requirements of that specification
applied to operational modes 1 through 4, and were not applicable for operation in
the defueled condition. The action statement for TS 3.9.15 with the SFP cooling
system inoperable was to suspend operations to add irradiated fuel to the pool and
to initiate corrective actions to restore the SFPCS to an operable status as soon as
possible.
The inspector reviewed licensee actions to stage equipment and revise procedures
for alternate cooling of the SFP heat exchangers using fire hoses. The licensee
revised AOP 3.2-59 (TPC 97-59) by adding Attachment 9 to describe the use of the
temporary cooling method. The revised AOP was reviewed by the plant operations
review committee (PORC) on March 13,1997. Procedure SUR 5.1-0A was also
changed (TPC 97-56) to have the NSO stage equipment to implement the alterriate
cooling if the pool temperature reached 120 degrees F. The use of fire hoses had
been previously demonstrated to be operationally feasible in the Fall of 1996 when
e a similar alternate supply had been established (reference Bypass 96-63 and
Engineering Memorandum CYDE-96-0564).
The temporary alternate cooling method was technically acceptable in an October
1996 engineering evaluation, which showed that for a spent fuel decay heat load of ;
2 x 10 ** BTU /hr, the pool temperature could be maintained below the license limit j
of 150 degrees F by supplying the pool with as little as 100 gpm of cooling flow
supplied by 3 inch diameter fire hoses. The 1996 evaluation was updated in Safety
Evaluation SY-EV-97 01, which was approved by the PORC on March 14,1997.
The updated analysis showed that for the current pool heat load following the full i
core discharge (4.0 x 10 +' BTU / hour), the fire hosns supplying a minimum of 100
gpm was sufficient to maintain pool temperatures below 150 degrees F, assuming
river temperatures at the design basis maximum of 90 F. The licensee installed one
section of metal pipe in the temporary return side header to measure the cooling
flow with an on line flow instrument (controlatron) while on the bypass. Service l
water cooling flow remained in the range of 160 to 180 gpm. The inspector j
verified that the fire hoses were consistent with the design specifications assumed
in the safety evaluation (reference PONN Supreme fire hose specifications).
On March 26, the licensee declared the SW return pipmg imm the SFP heat
exchangers inoperable at 7:15 p.m. as a result of a corrosion defect in the 6 inch
carbon steel pipe. The pipe was inoperable based on an engineering evaluation that
concluded that the pipe could not support design basis loads barod on an ,
engineering evaluation (see Section M1.1 - authorized work order 97-806) for l
further details on this issue). The licensee reported this event to the NRC on March l
26 per 10 CFR 50.72(b)(2)(1) as plant operation in a degraded and unanalyzed l
condition. The licensee approved a change to NOP 2.24-3 (TPC 97-60) which
added instructions in (Attachment 7) to use the fire hose equipment previously
staged for the March 11 event in the event alternate SFP cooling was needed on a
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non-exigent basis. The licensee implemented the NOP 2.24-3 on March 31 to
install the alternate service water cooling lines while actions were completed to i
install the check valve and replace piping as needed due to corrosion induced
defects.
Licensee engineering completed an assessment that was approved by the Plant
Operations Review Committee on March 26 to evaluate the acceptability of the
continued use of the normal service water supply and return piping. The licensee
found it acceptable to continue to use the normal service water system to cool the
SFP pending the completion of repairs. The assessment included considerations for
the types of deficiencies (physical or analytical) postulated in the supply and return
piping, the consequences of pipe failure, including postulated flooding if a line
failed, and the additional measure to maintain the SFP area under augmented
operational surveillance. The licensee switched to the alternate cooling method for
the SFP heat exchanger on March 31.
01,5 Imolementation of Alternate SFP Cnolina_
in preparation for maintenance work on the service water (SW) system that supplies
cooling water for the spent fuel pool (SFP) heat exchanger including the addition of -
a check valve in the supply line and replacement of a section of return piping with !
reduced wall thickness, operations setup of fire hoses was reviewed.
I
At4:48 a.m. on March 31,1997, operations isolated the SW to the SFP cooling I
heat exchanger with the pool temperature at 75 F. This system isolation was l
performed using temporary procedure change (TPC) 97-60 to NOP 2.24-3, Filtered 1
Service Water System and Adams Filter Operation. The TPC, PORC approved on
March 27,1997, added Attachment 7 for the temporary supply and return of SW to
SFP heat exchangers while work was in progress to install a new check valve. The
plan was to connect two hoses from the PAB second floor Adams filter drain lines
to the SFP heat exchanger inlet manifold check valves and have a single fire hose
return the SW to the PAB ground level valve connection. This was the same
hookup used earlier for other SW work.
1
Maintenance removed the spool pieces and hooked up the previously used nozzles.
The OAS inspection plan called for a visual check for debris or foreign materialin
the lines prior to operations hookup of the fire hoses. Step 1.8 was to open SW-V-
643A and rod out pipe nipple and valve to remove any debris. Maintenance
assisted operations in performing Step 1.9, Install 2" globe valve and 2 % or 3 inch l
hose connection at open end of piping from SW V-643A. Someone questioned if
QAS was to inspect the open pipe and work control was contacted. Work control i
contacted QAS who insisted that the installed valve had to be removed prior to his
inspection, so that was done.
The inspector noted that operations / maintenance f ailed to stop after Step 1.8 for
the OAS hold point. However, there was no indication'in the procedure where the ;
hold point was and the OAS inspection plan never indicated the step number where '
the inspection was intended. The inspector considered this a poor plant work
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practice. In discussions with the inspector, QAS pointed out that communications )
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were less than adequate and agreed that indicating the step number on the QAS
inspection plan was a good idea. Prior to the end of this inspection, QAS had .
modified QASI-PS-CY-2.02A, Step 6.3.2 to include detailed instructions to indicate '
the procedure step at which the [QAS] inspection will be performed.
'
Although this work was scheduled to be completed before the end of day shift i
March 31,1997, considerable delays, mostly due to personnel availability, were l
encountered and the SW cenectior through the fire hoses for SFP cooling was not
restored until 8:04 p.m. The SFP water exiting the heat exchanger was 85 F and
the pool temperature had increased to 94 F. With SW being supplied by fire hoses,
the SFP bulk temperature decreased about 1 degree F per shift.
In summary, the licansee operations to supply temporary service water cooling to
the spent fuel pool via fire hoses were adequate. QAS was responsive to improve
their communications with operations / maintenance for QAS hold points. The spent
fuel cooling system remained in a degraded condition with the plant in the action
statement for TS 3.9.15 at the end of the inspection period. The licensee
proceeded with engineering evaluations, modifications and maintenance activities in ;
n an expeditious manner to restore the spent fuel cooling system to an operable
, status. The modifications included the implementation of a design. change request
(DCR) 97-002 to install a check valve in the SW supply line. The new check valve
was welded in and acceptance testing was being performed at the end of the
inspection period.
01.6 kgjitpf a 116 kV Distribution Line
On March 13,1997, a problem in the offsite electrical distribution network resulted
in the loss of redundancy in the 115 kV power supply for the Haddam Neck Site
(adverse condition report ACR 97-130). Specifically, an electrical perturbation
during the startup of an electrical generation station in Middletown, Connecticut '
resulted in a plant trip. When the breaker that would normally operate to separate
the plant from the 115 kV system failed to open, the offsite electrical protection
scheme tripped a secondary breaker that de-energized Line 1572 at 6:00 a.m. Line
1572 is the normal supply to Middletown 1772, which is one of two feeds for the
Haddam Neck station. Line 1772 remained energized by a feed from Haddam Line
1206 through OCB 389T399, which is normally closed to cross connect the offsite
supplies in the Haddam Neck 115 kV switchyard. Thus, all plant buses remained '
i energized throughout the electrical transient. The emergency diesel generators
were operable at the time, but were not required to operate. There was no impact
on plant operations or operating equipment.
The Haddam Neck plant operators communicated with the offsite load dispatcher to
identify the cause of the problem to the Haddam Neck offsite supply, the actions
being taken to correct the problem, and the estimated time to recover Line 1772. i
Line 1772 was re-energized from its normal source at 9:10 a.m. on March 13. The
event occurred as the licensee was taking measures in response to a plant design
deficiency and associated analysis, which postulated that the service water system
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8
providing cooling water to the spent fuel pool cooling system might fail due to
water hammer loads associated with a loss of offsite power event. Plant operators
responded appropriately to the challenge to the onsite power supply.
01.7 Inocerable Effluent Monitorina System
Technical Specifications (TS) 3.3.3.7 and 3.3.3.8 require that certain radiation
monitors be operabia at all times to monitor the status of liquid and gaseous
releases from the site. The licensee declared all technical specification monitors
inoperable on February 5,1997, as a result of an NRC inspection (reference
Inspection 97-02) which found inadequacies in the calibrations program. NRC
identified deficiencies in the procedure used to calibrate the gaseous and liquid
effluent monitors, such that the accuracy of the monitors could not be assured.
The radiation monitors affected included liquid (RM 18 and RM 22) and gaseous
(RM 14A) effluent monitors. Inspection 97-02 also identified deficiencies in the
calibration of the wide range stack monitor, RM 14B, and in the spent fuel pool
radiation monitor R 19. The inspector reviewed licensee actions this period in
response to this issue. Although the detection channels were TS inoperable, all
channels remained on line (except for periods of maintenance or testing) and
available for operator use to monitor the associate pathway.
The licensee completed compensatory actions to comply with the action statement
of TS 3.3.3.7 and 3.3.3.8, which included the evaluation of releases via the
associated pathways. The licensee obtained and analyzed periodic grab samples
whenever effluents by the associated pathway were in progress. The inspector
reviewed licensee compensatory samples and analyses on February 4, for the
release of the A waste test tank. The release was processed in accordance with
release permit L-10 and Action 46 of Technical Specification Table 3.3-9, which
required that two independent samples of the tank be analyzed to assure it is
acceptable for release, and that the release calculations and discharge valving be
independently verified. No inadequacies were identified. The inspector verified
licensee actions to implement the compensatory measures periodically during the
, inspection.
All channels remained inoperable at the end of the inspection period pending
completion of licensee actions to complete a proper calibration on the channels.
Inspection 97-02 and Section R2.1 of this report provide further details on this
matter.
01.8 Control of System Confiauration (VIO 97-01 -02.a)
The purpose of this inspection was to review the licensee process to control the
physical configuration of the plant. This review included the implementation of the
tagging process during the conduct of work activities, and the control of systems
removed from service due to plans to decommission the plant. Licensee actions to
issue and/or remove tags under the following clearances were reviewed:
.
9
* Spent Fuel Cooling Pump Preventive Maintenance (96-055)
* North Service Water Header (97-032)
* EG-2B Testing and Troubleshooting (97-043)
* A HPSI Pump Supply Breaker (96-748)
* A Charging Pump Supply Breaker (96-808)
* Service Water Containment Header (96-662,659,846,1097)
* Service Water SFP Header (97-108,130)
Except as noted below, no discrepancies were identified.
Violation of Red Tan Controls
On February 19,1997, during preparation for "A" prefilter changeout, a contracted
health physics worker opened the prefilter access door with a Red Danger tag taped
to the front of the door. Once the door was opened, the danger tag was not visible
to other workers, so they also entered the prefilter area to continue the work. The
danger tag warned of the automatic initiation of the carbon dioxide fire protection
system, thus, this was a personnel safety issue. At CY, all tagging is governed by
WCM 2.4-1, Equipment Tagging. This procedure clearly prohibits equipment tagged
out shall not be manipulated in any way. The individual involved stated that he had
received a pre-job briefing, knew that the system had been tagged out of service,
and that the tagging walkdown had been performed. He said he saw the danger tag ,
on the door and assumed that it was one of the isolation tags for his work. j
i
The licensee issued ACR 97-93 to describe and assess this event and to implement
corrective actions. ACR 97-93 suggested that the danger tag should have been
removed when the prefilter was isolated, the tag was not hung in a manner that j
was clear to the workers, and the worker should not have opened the door. Plant
management was active in the requirement that all managers review company
policy regarding observance of all tags. The licensee looked at previous correctia
actions and found they had been ineffective in that repeated tagging errors have
continued over the past several years. They have had Station Staad Downs, where
no work in a particular area or in all areas is allowed, provided tagging training, and
held discussions with plant personnel. They conclude that personnel appear not to
have realized the consequence of operating red-tagged equipment.
The licensee's corrective actions for this event included: 1) operations sent a station
memo to all station personnel emphasizing the importance of not operating red-
tagged equipment; 2) the tagging group was to verify that any conflicting tags are
removed before adding a new clearance to a piece of equipment: 3) all department
supervisors were to verity that conflicting tags are removed before starting system
work; 4) the training department was to change the computer-based training (CBT)
for station tagging to an annual cycle and make it mandatory; and 5) establishing
different method of enforcing confined entry controls, through the installation of a
sign on the ventilation door. The inspector reviewed the records provided by the
licensee that showed that all departments have reviewed the CY Access Training
Supplement: Equipment Tagging.
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The inspector noted that the failure to observe red tag controls and the failure by
contractor personnel to observe station work practices were recurrent issues at
Haddam Neck, in December 1995, a contractor operated a red tagged 480 volt l
breaker - reference Inspection 95-27, Section 3.3). The February 19 event showed
that past licensee corrective actions were not effective. The failure to heed a
posted Red Tag on February 19 was a serious event that could have led to plant or :
personnel damage. This was a violation of a plant procedures, and one of six i
examples of a violation of Technical Specification 6.8.1. (VIO 50-213/97-01-02.a)
014 Inadeauate Control of Boiler Operations NIO 97-01 -02.b)
Several events occurred during the period in which licensee management identified l
and addressed deficiencies in performance by plant personnel, including operators. I
Adverse condition report (ACR) 97-19 concerned the discovery on January 5,1997 i
that a nuclear side operator had left a key ring unattended for 45 minutes. i
Corrective actions included security checks of vital areas, counseling the individual, i
'
and adolessing expectations with all plant departments. The licensee noted this
was the third event of this type in the last two years.
Two events occurred which had minimal impact on plant safety, but which l
demonstrated poor operator performance. The events concerned the overflow of. !
non-radioactive water from the heating steam condensate receiver tank, which
provided feed water to the plant heating boilers, a non-safety related system. ACR l
97-24 concerned the inadvertent overflow of about 100 gallons of water from the !
condensate receiver tank on January 11. The event occurred because the nuclear j
side operator (NSO) started a manual fill evolution of the condensate tank, and left
the tank unattended while he continued other rounds. The operator chose to
manually fill the tank to a higher level because of his concerns on the reliability of
the automatic level controls based on past experiences. ACR 97-27 was issued on
January 15 when the automatic makeup valve HC-MOV-491 A failed open while the
tank was aligned for automatic makeup. The tank overflow to the floor drain was
discovered by the NSO during routine rounds. ACR 97-74 concerned the overflow
of the condensate tank on February 9 when an NSO (different NSO than the
January 11) began a manual makeup and then left the tank unattended as he
continued other ror.nds.
For each event, the licensee took action to counsel the operators involved and to
review management expectations on performance with plant operators. The l
licensee also reviewed the spills .o sssure no release limits were exceeded. The
boiler activities were generally governed by procedure NOP 2.19-8A, but after initial
boiler startup, the condensate tank fill evolutions were generally conducted as a
" skill of the trade." The licensee had recognized the need to improve the controls in
NOP 2.19-8A and added requirements in Revision 3 dated January 31,1997 for the I
operator to stay in attendance whenever manually filling the tank. However, Step
6.1.12a requires the operator to maintain the condensate receiver tank one-half to
two-thirds full when operating the condensate makeup manually. Collectively, the '
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events demonstrated poor operator attention to duties, poor licensee control of
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processes, and inadequate corrective action to correct deficiencies. !
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The failure to properly fill the condensate tank was contrary to NOP 2.19-8A; and !
,
was the second of six examples of a violation of Technical Specification 6.8.1 (VIO l
97-01-02.b). i
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01.10 Conclusions for Conduct of Operations
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The conduct of operating activities was acceptable, as were the operator actions to
'
maintain the plant stable in a defueled condition and to monitor the status of
systems in layup of long term preservation. ' An inspection item will follow licensee 1
initiatives to better control the status and categorization of plant systems in post
operations mode, and to reduce the number of illuminated annunciators.
Although the spent fuel remained adequately cooled at all times, a discrepancy in
.
the design basis and deficiencies in the material condition of the service water i
system created a challenge to the adequacy of the spent fuel cooling system. ;
'
Licensee actions to address these deficiencies, as well as the operator actions to -
- y ' implement alternate cooling methods for the spent fuel pool, were acceptable. [
Jnadequacies in the procedures used to calibrate certain radiation monitors resulted
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1 in the declaration of e!.I gaseous and liquid effluent monitors required by the ;
'
technical specifications to be inoperable, and the need to implement compensatory
measures to monitor effluents by the associated release pathways.
I -
As in past inspections, human performance errors by operators and workers i
detracted from good performance. The violation of procedures resulting in the -
gperation of red tagged equipment was a significant event that could have resulted i
in unsafe conditions. Several other examples of a failure to adequately follow plant !
procedures were noted.
02 Operational Status of Facilities and Equipment
- 02.1 Cold Weather Preparations
.
a. Inspection Scope (71714)
,
The purpose of this inspection was to review licensee actions to assure plant ,
systems were adequately protected from freezing.
b. Observations and Findinas
The licensee had a program to assure systems were protected from cold weather !
conditions. The plant design features and processes remained as noted by past i
NRC inspections in this area (reference inspections 93-22 and 96-01), which '
included heat traced circuits for process piping and tanks, and administrative
controls to assure the freeze protection circuits were maintained and operating. The ;
administrative controls included a walkdown by maintenance personnel of all j
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circuits per procedure PMP 9.9-146 to verify the condition of heat trace circuits,
and identify and repair deficiencies; and, the operator checks of heat trace panels
and circuits per operations department instruction ODI-146. Additional controls in
this area included periodic reviews by the quality assurance group, such as the QAS
surveillance (CY-96-090) cornpleted on December 13,1996.
Problems in adequately implementing the administrative controls were identified.
The QAS surveillance noted a weakness in the planning and implementation of the
annual preventive maintenance on some freeze protection circuits (adverse condition
report ACR 96-1351), and problems establishing the proper temperature setpoint for
a circuit on the demineralized water storage tank (ACR 96-1350). These issues
were reviewed by plant management and corrective actions were initiated to
address the discrepancies.
Despite the preparations and controls for cold weather, the licensee actions were
not sufficient to preclude damage to a plant process line. The licensee identified on
January 3,1997 that a 3/4 inch service water line providing filtered water to a
steam generator (SG) sample cooler had burst due to freezing. Actions were taken
to isolate the leak and to report the deficiency (ACR 97-002). The leak did not
. jeopardize cooling to important plant systems. The SG sample cooler was not
required to be operable due to the shutdown status of the plant. The followup
investigation determined that the heat trace circuits were energized, but damaged
and wet insulation had resulted in a freeze condition in the line.
The licensee followup actions were to review the status of insulation on other lines
and address other deficiencies in the freeze protection circuits. The action plan and
summary of actions taken were provided in memorandum CYDE-97-003 dated
January 8,1997, and in a memorandum to the Maintenance Manager dated
January 22,1997. Based on previous industry operating experiences, the licensee
was sensitive to the protection of the spent fuel pool and provided enhanced
visibility and monitoring of building temperature around the boundary. Supplemental
heating was used in some plant areas (pipe trenches). A longer term action
included the plan to review the basis for plant freeze protection after completing the
system categorizations necessary to decommission the plant.
c. Conclusions
The licensee implemented established procedures and controls to assure plant
systems were adequately protected from cold weather conditions. Important plant
systems, including the spent fuel pool and support systems and the containment,
were adequately protected from freezing. However, the failure to complete
thorough plant walkdowns and poor insulation conditions in some process piping
resulted in freeze damage to a process line. Licensee actions to respond to this i
event were acceptable.
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03 Operations Procedures and Documentation l
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03.1 Procedure Quality for Shutdown Operatina Activities ;
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a. Inspection Scooe (42700)
.
The purpose of this inspection was to review plant procedures governing activities
to support testing, maintenance and operation of plant in a shutdown and defueled
condition. ;
b. Observatiens and Findinas
This inspection was performed in response to NRC concerns raised by an
operational event (reference NRC Inspection 96-80), in which some procedures for l'
"
shutdown operations were inadequate. In response to that finding, the licensee
initiated actions to rewrite procedures and improve procedure quality. The licensee ,
completed a major effort to upgrade shutdown and refueling procedures prior to the {
resumption of activities to offload the core from the reactor coolant system to the l
spent fuel pool. The core offload was completed on November 15,1996. NRC l
j , review of the initial procedure upgrade effort was described in inspection 96-11,-
which found that, generally, procedure quality had improved because of the licensee
initiatives completed prior to the core offload.
The list of procedures reviewed during this period is provided in Attachment 1, and
included those procedures already in effect for plant operation, test and
maintenance activities, along with new procedures or procedure revisions that the
licensee found to be necessary to address deficiencies. The inspector found that
< the procedures reviewed conformed with the requirements of the technical
specifications and met the guidance of Regulatory Guide 1.33. The procedures
were technically adequate and useable. The inspector noted minor discrepancies
(such as typographical errors, or enhancements in cross referencing or wording) that
could be attributable to the lack of attention to detail in the preparation and approval
of procedures. No procedure deficiencies were identified that would have resulted
in an unsafe condition for the plant or plant personnel.
4
The overall controlling document for procedure preparation and approval remains
Administrative Control Procedure (ACP) 1.2-6.5A, Station Procedures. Temporary
Procedure Change (TPC) 96-802 added a new Section 1.9.3 that instituted a "Do
Not Use" process to remove unneeded procedures when the related systems are
,
permanently removed from service. This TPC was incorporated into ACP 1.2-6.5A,
Revision 1, effective March 7,1997. Instead of a blanket cancellation of unneeded
procedures, CY's plan was to replace the procedure in the controlled manuals
(control room, work planning and control, administration, and applicable
departments) with a signed and approved Do Not Use (DNU) notice sheet as each
procedure comes up to its biennial review date. Of the approximate 1100
operations procedures, about 200 have been so marked at the end of the
inspection.
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For the Emergency Operating Procedures (EOPs), all emergency responso
procedures (Reactor Trip, Safety injection, Steam Generator Tube Rupture, etc.)
were labeled DNU when EOP 3.1-0, the controlling procedure, was revised. In
addition, EOP 3.1-12, Emergency Boration, and EOP 3.1-21, Pressurizer Spray
Valve Malfunction, have been labeled DNU. EOP 3.1-48, Loss of Refueling Cavity :
'
Inventory resulted from an NRC commitment and will be handled separetely later.
All other EOPs are being converted to Abnormal Operating Procedures (AOP) as
shown below.
EOP 3.1-10 Partial Loss of AC AOP 3.2-68
EOP 3.134 Complete Loss of Control Air AOP 3.2-66 ,
EOP 3.1-46 Total Loss of Semi-Vital Power AOP 3.2-65 l
EOP 3.1-49 Partial Loss of DC AOP 3.2-67
EOP 3.1-50 Loss of MCC-5 AOP 3.2-64
The AOPs not needed any more are being labeled DNU again as each procedure
comes up to its biennial review date. At the time of the inspection,12 of the 41, -
not including the new ones listed above, had been so labeled. The inspector l
reviewed the AOPs labeled DNU and found no improperly labeled procedures.
The other procedures under operation's control, ACPs, Normal Operating Procedures
(NOPs), Preventive Maintenance Procedures (PMPs), Surveillance (SUR),
Annunciator (ANN), Work Control Manual (WCM), and some Administrative (ADM) l
'
procedures, will be classified DNU, if no longer needed, at its biennial review date.
' For a listing of procedures reviewed by the inspectors, see Attachment 1.
c. Conclusion
This review found that procedure quality was acceptable, and that licensee
initiatives to improve, control and maintain procedures in accordance with the ;
technical specifications were satisfactory. The licensee's approach to remove l
I
unneeded procedures from controlled manuals as each procedure approached its
required review date was acceptable. A notable example of poor procedure quality
were the findings relative to the proper calibration of the radioactive effluents
instrumentation channels, as described in another NRC inspection that occurred
during this period (reference inspection 97-02). The inadequate calibration
procedures resulted from licensee activities prior to the plant shutdown in July,
1996, and prior to the subsequent licensee initiatives to improve plant procedures.
05 Operator Training and Qualification
05.1 Inaccurate Ooerator Trainino Records (URI 97-01-03)
a. Insoection Scoog
. i
The purpose of this inspection was to review operator training records and the l
management response to the discovery of deficiencies in the program to maintain !
qualification records for personnel who applied for an NRC licenses.
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b. Observations and Findinas
1
On February 7,1997, the licensee identified deficiencies in the program to maintain I
qublification records for personnel who applied for an NRC license to operate l
Haddam Neck. Following the failure by severallicensee personnel to pass an NRC
licensed exam on Millstone 1 in December 1996, Northeast Utilities initiated an
Independent Review Team (IRT) to investigate the cause for those failures. The IRT
identified deficiencies in the process to train and qualify the candidates for the ,
exam. Based on these findings, NU expanded the scope of the IRT review to j
'
include a review of the most recent operator licensed program for Millstone 2,
Millstone 3, and Haddam Neck. The last licensed operator program for Haddam l
Neck was completed in August 1996, in which all 12 of the candidates who I
completed the examination process received a license. The IRT began a review of
the training records for the 1996 class in January 1997, and reported its preliminary
findings to the licensee (CYAPCo) on February 6,1997 in Adverse Condition Report
(ACR) 97-63.
1
The IRT found that, based on a review of the required training for the Haddam Neck
1996 Licensed Operator Upgrade Training (LOUT) and Licensed Operator Initial
ec Training (LOIT) programs, the licensee submitted inaccurate information to the NRC
on Form 398 in support of an application for a license under 10 CFR 50.55. The
form is required to be submitted by the licensee prior to the candidate being
examined by the NRC. One purpose of the form is to certify that the individual has i
successfully completed the facility licensee's requirements to be licensed as a
reactor operator or senior reactor operator. The IRT found that three of the LOUT
students did not meet the program requirements for standing watch while under
instruction for the required number of hours (at least 320). Other deficiencies were
identified, including the failure by some candidates to complete the required number
of reactivity manipulations, and the failure of one candidate to complete program
prerequisites for on the job training. 10 CFR 55.9 requires that information provided
to the NRC by an applicant for a license shall be complete and accurate in all
material respects.
There were 12 candidates who completed the 1996 licensing class. As of February
7,1997, nine of these 12 operators were not using their licenses at the facility
because of transfers to other facilities as part of the licensee's staff reductions for ,
the plant decommissioning. Two licensed operators were on the operations l
department watch bill, as was a licensed senior reactor operator. The SRO
subsequently left Haddam Neck for a position at another facility. The Operations !
manager issued a directive on February 13,1997 (memorandum ODM 97-018)
stating that none of the 12 operators from the 1996 class could perform licensed
duties until the training program discrepancies were resolved. The two operators
who remained at Haddam Neck were allowed to remain on the watch bill and
allowed to perform non-licensed duties.
The licensee formally notified the NRC of these deficiencies in a letter dated March
3,1997, which also described the actions taken to investigate this matter, identify
the causes, and to correct the deficiencies in the operator training program and its
.
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16
administration. The licensee classified the deficiencies in ACR 97-63 as a severity
level "B" issue that required a root cause investigation to determine why the
deficiencies occurred. Additional corrective actions included plans to rectify the
deficient information submitted to the NRC, review the matter for reportability,
expand the IRT reviews to include the training for previous licensed operator
classes, and complete a review to assess whether similar problems existed in the
operator requalification program. The licensee committed to conduct additional
reviews of the licensed operator requalification program by April 4,1997. The NRC
formally recognized the licensee's corrective action plan in a confirmatory action
letter issued on March 7,1997.
On March 27,1997, after review of the training records from the 1995-1996
licensed operator initial training , program for three individuals, the Haddam Neck
Operations Manager concluded that, although there were several administrative
errors, all three individuals successfully completed all requirements of the training
program. Thus, the Operations Manager removed the restrictions from the conduct
of licensed duties for all three operators (ODM 9'7-054, 055, 056).
l
On April 3, the licensee completed the review of the licensed operator
4- requalification training (LORT) program and identified deficiencies similar to those in
the LOIT (ACR 97-166). The problems included deficiencies in administering the
LORT, and the failure of candidates to attend all LORT training sessions. The :
Operations Manager reviewed the audit results against the operators still holding i
active licenses at Haddam Neck, and identified on April 9 one operator who might
not have completed all the LORT program requirements. This individual was not l
presently assigned to the control room watch bill, (ACR 97-180), but was removed j
from licensed duties pending a complete review of actions to meet the LORT
programs requirements. !
Finally, a licensed operator identified to his supervision that he may not have met I
the reactivity manipulation requirements of the LOIT (ACR 97-190). The Operations i
Manager issued a memorandum on April 10 to remove this individual from licensed
duty pending a full review of the actions to meet the LOIT program requirements.
The individual involved noted that although he was in the control room and in l
attendance for reactivity manipulations, he participated in some exercises as an
observer and did not actually perform the reactivity manipulation. The deficiency in
ACR 97-190 was significant in that it was not identified by the IRT review of the
individual's participation in the 1996 LOIT. When determining whether licensed
operator candidates had completed the number of reactivity manipulations required
by the training prograra, the IRT had relied on a review of training documentation,
but had not interviewed the candidates. The licensee was reviewing this finding for
generic implications for both the CY and Millstone training programs.
NRC review of this area was in progress at the completion of this inspection period.
This matter is unresolved pending the completion of licensee actions as required by
the March 7 Confirmatory Action Letter, and the completion of the NRC reviews of
this matter (URI 97 01-03).
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c. Conclusions
Poor performance was demonstrated in the administration of the licensed operator
training program, and to assure that operators a fully qualified initially and remain
qualified through periodic retraining. The NRC and licensee review of Haddam Neck
licensed operator training program was in progress at the end of this inspection
period.
06 Operations Organization and Administration
06.1 Staffina and Control of Overtime (VIO 97-01 -02.c)
a. Insoection Scoce (71707)
The purpose of this inspection was to review the licensee's actions to organize and
reduce operations staffing to support the decommissioning mode, and to control
work hours but critical plant staff. l
b. Observations and Findinas l
l
The operations department staffing was reduced by about half during this inspection !
"iod as a result of the decision to decommission the plant. The licensee also (
.iounced the selection a new Operations Manager effective on February 24, I
a 997. Starting in January 1997, the operations department was comprised of i
about 30 personnel, with the shift operators organized into 5 four-person crews on
a rotating shift schedule. Each shift (labeled Crew B through F) had 1 senior reactor
operator / shift manager (SM),1 reactor operator / control operator (CO), and 2 non-
licensed operators / nuclear side operators (NSO). Additional personnel were
assigned to the work crew (tagging), a procedures and training group, and for
administrative support. By letter dated February 19,1997 (B16196), the licensee
notified the NRC of the nineteen licensed operators who would discontinue licensed l
duties at Haddam Neck due to transfers to jobs outside of the station.
Technical Specification 6.2.2 establishes the facility staffing requirements and
establishes the minimum shift crew composition for operational modes 1 through 6.
The minimum staffing for a defueled condition was not specified in the current
license conditions. The licensee maintained minimum shift staffing in accordance
with the requirements for Mode 6 - refueling. The licensee maintained a five
member fire brigade, as required by Section II.1.6 of the Technical Requirements
Manual. The fire brigade was comprised of the control operator as fire brigade
leader, the two NSOs and the health physics and chemistry representatives
assigned to each shift. Further, as a result of the deficiencies identified in the
licensed operator training program (discussed in Section O.5 above), the Operations
Manager issued a memorandum on February 13,1997 limiting two licensed
operators to non licensed duties. The inspector verified that the licensee met the
intended shift manning requirements despite the above constraints. The licensee
intends to address minimum shift staffing requirements for the defueled condition in
a formal revision to the f acility technical specifications; the licensee plans submit
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18
the proposed TS revision in April 1997. The present shift staffing levels would
meet the proposed TS requirements.
Technical Specifications 6.8.1 and 6.2.2.f require that administrative procedures be
developed and implemented to limit the working hours of facility staff who perform
safety related functions. These procedures should follow the general guidance of
the NRC Policy Statement on working hours (Generic Letter No. 82-12). The
licensee implemented procedure NGP 1.09 to meet the requirements of TS 6.2.2.f,
which provides limits on the use of overtime that meets the guidance in the generic
letter. During this period, the licensee determined that the NGP 1.09 requirements
for the use and approval of overtime were not met in two occasions. The first
instance was documented in adverse condition report (ACR) 97-64, and concerns
the discovery that a licensed operator exceeded the guidelines during work shifts on
February 5-6,1997. The operator worked two shifts with less than eight hours
off in-between shifts. NGP 1.09 states that personnel must have prior approval to
work with less than 8 continuous hours off between scheduled work periods
(including shift turnover time). The operator was not approved to work in excess of
the guidelines because the operations supervisor who scheduled the work was not
aware of the procedure limits requiring that shift turnover time be included in the 8 ;
. hours of time off from werk. The procedure violation was discovered (after the l
fact) by the operator assigned to do the work. Licensee corrective actions were l
described in memorandum ODM 97-20, which included counseling the supervisor j
who scheduled the work, and reiterating the NGP 1.09 requirements to all shift ;
managers. The inspector reviewed the use of overtime by operations (union)
- personnel for the week ending February 1,1997, which included a summary of all
overtime worked in 1997. Although overtime was scheduled on a regular basis, the
amount of overtime worked either weekly or for the year-to-date (YTD) was not
excessive. The overtime worked ranged from none to a high of 13.5 hours for the
weekly summary, and ranged from none to a high of 26.5 hours for the YTD
category. There were no instances (except as described in ACR 97-64) where Gie
overtime worked required approval per NGP 1.09.
The second instance of overtime limit violations was described in ACR 97-33, and
concerns the findings by the nuclear safety and oversight (NS&O) organization. The
NS&O group conducted an investigation in response to a concern transmitted to the
NRC regarding the control of work inside the containment at Haddam Neck during a
forced shutdown in July 1994 following a fire in a reactor coolant pump (reference
NRC inspections 94-17 and 94-18). The concern provided to the NRC indicated
that a Health Physics Technician worked eight straight days without a day off, and
on the eighth day after ten hours of work, the technician was required to work
additional excessive hours. The licensee summarized the results of the investigation
of this matter in a letter to the NRC dated January 17,1997 (B16099). The
licensee concluded that there were six instances for which overtime authorization
records could not be found for some of the Health Physics and Instrumentation &
Controis personnel involved in the 1994 event, and that the TS limits for work in
excess of 72 hours, or for working 24 hours in a 48 hour period, had been
exceeded. The following specific violation of the NGP 1.09 and TS 6.2.2.f limits
were noted:
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* For the week ending 7/30/94, Individual A exceeded the limits for 16 hour of
work in a 24 hour period, and for working 24 hours in a 48 hour period;
* For the week ending 8/13/94, Individual A and Individual B exceeded the
limits for working 72 hours in a 7 day period; and,
* For the week ending 8/20/94, Individual C and Individual D exceeded the
limit for working 72 hours in a 7 day period. i
i
The licensee's investigation found that many other personnel worked overtime in ;
-
excess of the guidelines following that event, but this work was authorized as l
required by NGP 1.09. In response to this matter, and as described in the followup !
to ACR 97-33, the licensee's corrective action included plans to address this issue
'
,
generically by reiterating the importance of observing overtime limits in ]
supervisory / manager safety meetings with station employees. The failure to control ,
and approve the use of overtime in 1994 and in 1997 in accordance with the i
administrative requirements of NGP 1.09 was a failure to follow procedure NGP
1.09, and was the third of six example of a violation of Technical Specification
6.8.1, and a violation of TS 6.2.2.f (VIO 97-01-02.c).
c. Conclusions
The licensee completed a reduction in the operations staffing in response to the
decision to decommission the plant. The licensee maintained shift staffing sufficient
to mrt minimum staffing levels for the number of licensed operators, and to meet
the iire brigade requirements. NRC review of the adequecy of the reduced
resources to administer the operations procedures work load was in progress at the
conclusion of the inspection. Weaknesses were noted in the licensee controls to-
assure that work hours for operators and other personnel who perform safety
related work functions were limited in accordance with guidelines on the use and
<
approval of overtime.
08 Previous Operations Open issues (92901)
08.1 (Closed) VIO 94-21-01. Inadvertent Boron Dilution
During inspection 94-21, the inspector reviewed a reactivity anomaly that resulted
from operators failure to obtain the required chemistry samples of demineralized
effluent following a 17 minute flush to ensure equilibrium. The boron concentration
was lower then the primary and about 270 percent millitho (pcm) of reactivity was
added as a result of this operation. This was a violation of Technical Specification
6.8.1. By letter dated November 15,1994, CYAPCO responded to the violation
delineating the corrective actions taken. Due to the December 5,1996 notification
to permanently cease operation of the Haddam Neck facility pursuant to 10 CFR
50.82(a)(1)(1), the possibility for reactor reactivity anomalies no longer exists. This
issue is considered closed.
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00.2 (Closed) URI 94-27-01. Loss of Electrical Seoaration
During inspection 50-213/94-27, the inspector questioned the practice of cross-
connecting motor control centers (MCCs) between redundant safety trains. MCC-3
and 4 received power from redundant 480 volt buses 4 and 7; MCC-8 received
power from redundant buses 5 and 6. Buses 4 and 5 are powered from emergency
diesel generator EG-2A; buses 6 and 7 are powered from EG-2B. Abnormal
operating procedure (AOP) 3.2-28, " Locating 480 Volt AC Grounds," allowed
shutting a cross-tie breaker on MCC-3, MCC-4, or MCC-8. Although the AOP
required operators to enter technical specification (TS) action 3.8.3.1.1.a (with an
allowed outage time of 8 hours) when the cross-tie breakers were shut on MCC-3,
4 or 8, shutting these tie breakers for ground search investigations cross-connected
redundant safety trains for several minutes. The licensee revised AOP 3.2-28 on i
December 29,1994 to preclude closure of the MCC 3,4 and 8 tie breakers during I
ground isolation. Operator logs for 1994 showed five instsnces where grounds
were identified on 480 volt buses. In one case, Ju.i 10,1994, the operators shut ;
the manual cross-tie breaker for MCC-3 for four minutes. For the other cases, the l
licensee did not close the cross-tie breakers on the specified MCCs. This issue was l
left unresolved pending NRC review of the proposed LER, and verification of i
additional corrective actions.
By letter of January 25,1995, CYAPCO forwarded LER 50-213/94-29-00, Motor
Control Center Tie Breakers Prohibited by TS. This LER says the root cause was a l
procedural deficiency due to an incorrect interpretation of the action statement for
TS 3.8.3.1. Corrective actions taken include the above-mentioned procedure
revision and a change to Administrative Control Procedure (ACP) 1.2-6.5A, Station
Procedures, to require that, as part of the biennial review, all TS Action Statements
. are clearly identified and applicable to the Limited Condition for Operation. The -
l
inspector found these corrective actions acceptable, therefore, this unresolved issue
is closed.
08,3 (Closed) LER 94-011-00. Unolanned Loss of Soent Fuel Coolina
During inspection 50-213/94-14, LER 94-011-00 was reviewed. The event related
to failure of the "B" spent fuel pool (SFP) cooling pump seal. Inspector review of
the LER noted that the licensee did not document the root cause for the
misalignment and seal f ailure of the "B" spent fuel pool cooling pump. Additionally,
the inspector did not identify any maintenance controls for the scheduled preventive
maintenance duration to assure that the bulk pool temperature would not exceed
166 F. Therefore, the LER remained open for inspection of these two issues.
In Final Safety Analysis Report Change Request (FSARCR) 96-CY-27, approved
November 7,1996, CYAPCO proposed updates to Sections 7.6, All Other
Instrumentation Systems Required for Safety, and Section 9.1.2, Spent Fuel
Storage. This FSAR update greatly improves the description and analyses for the
spent fuel pool system.
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in response to inspector questions, the licensee provided plant information report
(PIR) 94-079, Spent Fuel Pool Pump Seal, and a September 22,1994 PIR 94-079
Followup Memo This followup memo indicates that the components of the failed
SFP pump revealed severely overheated and damaged bearings, shaft, shaft seals,
and mechanical seal. The amount of oil in the reservoir was found to be lower than
recommended and it showed signs of being burnt. The historical data section
states that, both the "A" and "B" SFP cooling pumps are of similar design
(however, supplied by different vendors and of different sizes] and have had
numerous failures over the last few years.
In discussions with the past SFP system engineer, the inspector learned that the
"A" pump old shaft seal was replaced with a new labyrinth type shaft sealin 1994,
that a "B" pump breaker tripping problem was resolved in 1995, and that a failed
"B" pump discharge check valve was relocated downstream to reduce vibration and
replaced with a new check valve in 1996. Review of maintenance records indicate
repetitive problems with bearing tube oil adequacy and leakage have occurred over
the years. The engineer explained that this was due to the critical " bubbler" level
that controls the amount of oil around the shaft. Operations and maintenance have
learned to keep the bubbler set correctly. It was also stated that the unbalanced
SFP pumps supplied by different vendors and of different size did not perform well ;
s together. An Engineering Work Request (EWR) had been submitted to System
Engineering to purchase replacement pump or upgrade existing pump to increase
capacity on May 25,1995. This was being tracked as 95-SE099. However, this
EWR was not funded and has been dropped. The engineering management
. committed to re-review the EWR recommendations based on the critical need for
the SFP system even when the Nuclear Island concept is adopted.
'
Since the Maintenance Rule Functional Failures (MRFF) criterion allows three failures
in a rolling 24 month period and the check valve failure was found during normal
preventive maintenance, the licensee counted only one MRFF of the SFP cooling
system (the 1994 failure of the "B" SFP cooling pump seal). Thus, the SFP system
has been categorized as a 10 CFR 50.65(a)(2), not requiring special monitoring
system. The inspector indicated that further review of MRFF performance would be
performed at a later time during the NRC Maintenance Rule Inspection required at all
plants.
08.4 (Closed) LER 94-015-01. Main Steam Valves Exceed Lift Setooints
On June 16,1994 during setpoint verification testing, the licensee determined that
four main steam (MS) safety valve (SV) pilot valves were outside the TS 3.7.1.1
allowed setpoints. The two pilot valves for MS-SV-24 lifted at a higher value then
allowed and were declared out-of-service. The licensee's root cause was seat
adhesion resulting from similar materials being used for both the pilot disc and
nozzle. A similar problem with five active pilot valves associated with the four main
steam valves was reported in LER 94-006, dated March 23,1994. The immediato
corrective action was to readjust the setpoints. Long term corrective action was to
evaluate possible replacement of the pilot valves with new types.
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The LER 94-015-01 supplement was submitted on March 2,1995, to provide the
'
results of corrective actions to date. CYAPCO, working with the oilot valve vender,
found that dissimilar materials (such as inconel 718 and Cobalt MP-35N) performed
acceptably on bench tests. The licensee replaced the eight pilot valves with the
improved design in July 1994. This LER is closed.
08.5 (Closed) IFl 96-08-01. RHR Calibrations and Leakaae
!
During inspection 50-213/96-08, operators experienced a delay in reaching cold
,
shutdown due to an initial inability to meet a limit specified in procedure NOP 2.9-1.
'
This NOP was revised (by temporary procedure change 96-387) to increase the heat
exchanger bypass flow (from 500-1000 gpm to 1000-1500 gpm), and to allow the
use of hand held temperature gauges to compensate for a suspected calibration
problem with the permanently installed instruments. The cooldown to Mode 5 was
completed within the time limits specified by TS 3.0.3. The licensee initiated
adverse condition report (ACR) 96-790 to address questions on the leakage of FCV-
796 and instrument calibrations. Due to the decision to permanently cease-
operation of the Haddam Neck facility, the leakage of FCV-796 and instrument
' calibrations is no longer important. This issue is considered closed.
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08,6 LClosed) LER 95-023-00. Failure to Prepare Special Report
On December 29,1995, the licensee determined that a Special Report should hava
been issued within 90 days, in accordance with TS 3.5.1, for charging injection
: flow into the reactor after manual initiation of safety injection during the manual
l reactor trip on July 27,1995. The manual trip of the reactor and turbine was
initiated following steam flow / feed flow mismatch alarms after the "B" main feed
pump motor breaker trip. -The initiating event, according to LER 95-016-00, dated
August 22,1995, was a ground on 4160 volt bus "A."
,
The licensee provided a copy of the required Special Report letter, dated March 5,
1996. This letter recaps the event and states that the cause of the failure to report
. was misinterpretation of what constitutes " injection flow." Originally, the plant
staff concluded that the safety injection system did not actually inject water
because the reactor pressure remained above the shutoff head of the high and low
pressure safety injection pumps. However, the charging pumps, running during
power operation for normal makeup and RCP seal water injection, did switch
suction from the volume control tank to the refueling water storage tank (RWST).
Since the RCS pressure dropped to 1740 psig, the charging pumps with a nominal
2700 psig discharge pressure, did inject RWST water into the reactor. The licensee
analysis for this LER was acceptable. This LER is closed.
08,7 (Closed) URI 96-201-10. Alternate Auxiliarv Feedwater Sources
During inspection 96 201, concerns regarding demineralized water storage tank
makeup flow path configurations, transfer flow rate capabilities, as well as the
, operator's ability to establish emergency procedure directed makeup flow paths
before the onset of turbine-driven auxiliary feedwater pump cavitation were
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23
expressed. However, due to the decision to permanently cease operation of the
Haddr.m Neck facility, these concerns are no longer important. This issue is
considered closed.
08.8 (Closed) LER 96-015-00. Containment Air Monitor Trio Valve
On July 27,1996, during local leek rate testing (LLRT) in cold shutdown, the 3/4
inch outboard containment air monitor isolation valve, VS-SOV-12-1, failed its Type
C test. The actualleak rate could not be quantified and was assumed to be greater
than allowed because of the inability to pressurize the test boundary. The in-series
inboard containment isolation valve, VS-TV-1848, was operable and passed its
LLRT. After removal, it was discovered that the rubber valve disc was separated
from the stem. The cause of the separation was incorrect assembly of the valve's
internals during manuf acturing or installation. The licensee was to replace this
valve with a different design during the refueling outage. However, due to the
decision to permanently cease operation of the Haddam Neck facility, this was
never done.
The inspector determined that the requirements of TS 3.9.4, that each penetration
. providing direct access from the containment to the outside shall be closed off, was
met during the final core offload by having the VS-TV-1848 isolation valve closed.
Thus, this issue is closed,
ll. MAINTENANCE
M1 Conduct of Maintenance
Using Inspection Procedure 71707,61726 and 62703, the inspectors conducted periodic
reviews of plant status and ongoing maintenance.
M 1.1 Maintenance Observations
a. Insoection Scope (62707)
The inspectors observed all or portions of the following work activities:
* PMP 9.1-31, Diesel In-Leakage and Fuel Oil Transfer Pump Availability
* PMP 9.2-20, Calibration of IST Gages for SW system (AWO 96-1699)
* PMP 9.2-19, Calibration of IST Pressure Gagas, F1-1438A (AWO 96-1699)
* AWO 96-8735, SW Return Line 6-WS-151-250, Lower Level SFB
* AWO 97-1469, SW Supply Line 6-WS-151-126, All Levels SFB
e AWO 97-1468, SW Return Line 6-WS-151-250, All Levels SFB
* AWO 97-806, SW Return Line 6-WS-151-250, Lower Level SFB
e AWO 96-3991, Spent Fuel Cooling Pump P21 1 A Lubrication
* PMP 9.9 5, Spent Fuel Cooling Pump Coupling Inspection (Section 0.7)
* AWO 96-9836, North Service Water Header NDE Exams
* AWO 97-1451, SW-CV-963 Installation (DCR97-002)
* AWO 97-1455, SW-V-964 Installation (DCR97-002)
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:o AWO 97-1518, Repair SW Return Line 6-SW-WS-151-250
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Except as described below, thu inspector had no further comments in this area. .
- b. Observations and Findinas
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i AWO 96-3991 The inspector observed licensee personnel complete preventive i
maintenance inspections and lubrication of the "A" SFP cooling pump per AWO 96-
,
3991 and procedure PMP 9.9 5. The work was completed in accordance with the .
l work controls and procedure. instructions. Maintenance personnel were !
i knowledgeable of the equipment.- No discrepancies were identified.- -
AWO 97-806 On March 21,1997, the licensee performed ultrasonic inspection of a
3 inch segment of line 6 WS-151-250, which is part of the service water return
:
i header from the spent fuel heat exchangers located on the lower level of the SFB. ;
'
The inspection was performed as a part of the monitoring program to follow general
corrosion noted in the line during an inspection in October,1996 (AWO 96-8735). >
When replacing a pipe "T" in the return line, the licensee identified general corrosion :
4
over a 3 inch section of pipe just down stream of the butt weld for the "T". The l
u : degraded pipe in October.1996 had a minimum wall thickness of 0.100 inches, as
F -
compared to the nominal O.280 inch wall for the schedule 40 carbon steel pipe. ,
;
The October defects in were dispositioned as acceptable per NCR 96-267 '
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The March 21 inspections noted continued corrosion with general wallloss over the ;
{
. . -same areas identified in October 1996, but with a 0.030 inch wall loss noted in one 2
4 - localized area (grid section 10-11); the minimum wall thickness at that location was
- O.067 inches. This defect was evaluated under nonconformance report (NCR) 97-
,
- 003 and was found unacceptable in that a structural analysis showed that the pipe !
could not withstand all design basis loads. The line was considered inoperable, as
was the SW cooling lines for the SFP cooling system. Based on these results, the
licensee began a program of expanded UT examinations of other locations in the i
SW system supply and return piping to establish the extent of the general corrosion
*
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problem. The licensee also took actions to repair degraded service water piping in
3
accordance with the ASME Code. This matter is discussed further in Section E1.2.
No discrepancies were identified in the troubleshooting efforts or operability
l evaluations. l
AWO 97-1468 and 14769 Ultrasonic (UT) examinations were completed on March
l 27, March 31 and April 1 as a result of the defect identified on March 21 (AWO 97- l
806) that rendered the SW system return header inoperable. The licensee followed i
the guidance of Generic Letter 90-05 to select a sample of 5 locations for UT 1'
examination that would be in piping similar to the original defect, and deemed
susceptible to corrosion. The objective of the sample selection was also to
e
determine the extent of the corrosion problem.
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For the first sample set of 5 locations, the licensee performed ultrasonic inspection l
(UT) at two locations on line 6-WS 151-126 (AWO 97-1469), which is part of the
~
'
service water supply header to the spent fuel heat exchangers located on the lower i
.
y ,wy ,,
y p w--,o-- ,
e-c-- r< ,- g a- 4 - v.,, ,,,m_..,a e ee... .. _,, , __.,__. . --s .-_ s m ,- --- .. -
. .
25
and mid levels of the SFB The licensee also performed ultrasonic inspection at
three locations line 6-WS-151-250 (AWO 97-1468), which is part of the service
water return header from the spent fuel heat exchangers located on the lower, mid
and upper levels of the SFB, Allinspections examined the general wall conditions
around the pipe circumference over a two inch long segment using a one inch
square inspection grid, inspection areas were expanded longitudinally as needed to
characterize any defects.
The UT results showed evidence of general wallloss and corrosion, but to a much
lesser extent than the initial defect. The pipe wall thickness was above 0.150
inches in all areas inspected except one (UT Location #5 - see the table below). l
The pipe wall thicknesses remained generally above 0.200 inches, with a few
locations showing pitting with remaining wall thickness below 0.200 inches. The
degraded pipe sections were evaluated on April 1,1997 (reference Calculation No.
96-SDS-1556MY, Change #2); all defects were found acceptable in that a structural
analysis per ASME Section XI Code Case N-480 showed that the pipe could
withstand all design basis loads. A new Tmin for the pipe was established at 0.142
inches by this calculation, with a minimum allowable local wall thickness of 0.064 {
inches for the defect (Taloc). Although the defect did not create an inoperable )
g condition, the licensee took actions to repair degraded service water pipe segment-
in accordance with the ASME Code.
The licensee's initial response was to stop the piping examinations at this point, l
based on the erroneous assumption that no further expansions were required based l
+n all defects showing wall thicknesses greater than the Taloc value of 0.064 !
inches. The inspector questioned this approach with licensee engineering, and j
stated that if any defects were found with wall thickness below the Tmin value of
0.142 inches, then the guidance of GL 90-05 would require that additional ;
examinations be performed. After further consultation between the site and design !
engineering groups, the licensee expanded the UT examinations of the SW piping to
an additional 5 locations. The second sample of UT examinations (UT Locations #6
through #10) were selected in both the supply and return headers at locations that
were deemed susceptible to the corrosion mechanism.
The minimum wall thickness (Tmin) observed at each of the ten areas inspected
was as follows:
UT Minimum Wall Measurements on Service Water Pipe
Expansion Sample No.1
UT # UT LOC #1 UT LOC #2 UT LOC #3 UT LOC #4 UT LOC #5
ID/elve Supply (30") Return (30)' Return (40') Supply (40') Return (50')
T min 0.178 in 0.152 in 0.154 in 0.182 in 0.116 in
. - - ._.
.
i
.
26
'
Expansion Sample No. 2 l
UT # UT LOC #6 UT LOC #7 UT LOC #8 UT LOC #9 UT LOC #10 PAB *
ID/elev Supply (50') Supply (63') Return (63') Return (63') Return (32')
T min 0.196 inch 0.148 inch 0.150 inch .160 inch 0.100 in
(0.040 in pit)
i
Based on the data in the second expansion sample, the UT data at Location #10 !
showed an apparently deep pit with a general wall thinning down to 0.100 inches
within one examination grid, and a very localized but very deep pit within that area
showing a remaining wall of 0.040 inches. This defect was found in a section of
the return piping located just above the east door of the auxiliary building and just ;
upstream of the tie in to the main SW return header (ACR 97-179). The licensee
' initiated actions to complete calculations to support an operability determination for '
this portion of the SW header, and to obtain additional nondestructive examination
data that would allow better characterization of the defect. The UT results at
Location #10 showed substantial wall thickness remained over most of the
circumference of the pipe, with wall thicknesses in the range of 0.200 - 0.256 inch
in the upper (unwetted) hemisphere of the pipe, and wall thicknesses in the range of ;
" O.143 to 0.178 inches in the 60wer (wetted) hemisphere of the pipe. The general !
wall thickness within the 4 square inch UT exam locations around the 0.040 inch !
defect site was in the range of 0.174 to 0.198 inches. Licensee actions in this area .
were in progress at the conclusion of the inspection. ,
Licensee engineering used the above data to evaluate the conditions in the service ,
water system. Similar to the first set of data, the second expansion sample showed
pipe wall thicknesses generally above 0.200 inches with extensive but randomly
distributed pitting, and some pits that resulted in remaining wall thicknesses below
0.200 inches, as shown in the table. A general pattern emerged in which corrosion
resulted in pitting that was generally worse in the return header that in the supply,
which was attributed to the fact that the return header was not always full (the SW ,
system that was open to the atmosphere). The pattern shown by the UT data was
also supported by visual exam on the two pipe spools that were cut out of the
return header as part of the repair of the defects that were unacceptable. The
inspector observed the cut out cross sections of piping and noted that substantial
pipe wall thickness was evident over a significant portion of the spool, even in the
areas of generalized pitting corrosion. The deep pits were highly localized.
This matter is discussed further in Section E1.2. No discrepancies were identified in
the conduct of piping inspections and the actions to characterize degraded wall
thickness.
AWO 971518 The inspector reviewed this work activity on April 5 - 7, which
involved the repair of a section of the SW return piping. The repair location was in
Line 6-SW-WS-151250 just upstream of support WS-RH-6A on the 30 ft elevation
of the spent fuel building. The repair involved replacement of a segment of piping
that included the pipe wall defect that rendered the SW system inoperable (AWO
.
.. __ ~- -- .-.
'
i
r
' '
27
97-806: UT exams completed on 3/21/97), as well as the segment of pipe with
general wallloss down to 0.152 inches (UT Loc #2). The repair replaced the pipe
with the original defects plus at least 1 inch of pipe beyond the defect. UT exams t
were used to assure the adjacent pipe had sufficient wall thickness that was not ;
affected by the generalized corrosion. The inspector observed the QA inspector
complete a liquid penetrant examination (LPE) on April 7 of the root pass for the
. two butt welds per procedures NU-VE-2 and NU-LP-1. The quality of the welds
was generally good, as indicated by the appearance and the results of the LPE. The !
workers were familiar with the welding and LPE processes and procedures.
Licensee activities were in progress at the end of the inspection period to complete
and accept final welds. No inadequacies were identified.
AWO 97-1519 The inspector reviewed this work activity on April 7-8, which
involved the repair of a section of the SW return piping. The repair location was in ,
'
Line 6-SW-WS 151-250 about 4 feet above the floor on the 47 ft elevation of the
spent fuel building. The repair involved replacement of a segment of piping that
included the pipe wall defect showing a minimum wall thickness of 0.116 inches-
(AWO 97-1468: UT Loc #5). Additional supports were added to support the line in l
the vertical direction while the affected spool piece was replaced. The inspector ,
I
m . noted the licensee used additional UT inspections (UT Loc #5A) to assure the .I
adjacent pipe had sufficient wall thickness that was not affected by the generalized l
corrosion. Licensee activities were in progress at the end of the inspection period-
to prepare the site to cut the affected line and install the new spool piece. No
inadequacies were identified. l
AWO 97-1451 The purpose of this work activity was to install check valve SW- 4
CV-963 in the service water supply header 6-WS-151-126 as part of Design I
Chango Request DCR 97-002. The inspector reviewed the activities in progress j
during this period to complete the installation, which was completed satisfactorily. I
The welding appeared to be of good quality, as evidenced by the appearance of the
root and final welds, and by the satisfactory completion of non destructive !
examinations.
.
AWO 97-1455 The purpose of this work activity was to install test valve SW-CV-
964 in the service water supply header 6-WS-151-126 as part of Design Change
Request DCR 97-002. The inspector reviewed the activities in progress during this
period to complete the installation, which was completed satisfactorily.
. c. Conclusions
The maintenance activities observed this period were acceptable. The work was
generally of good quality and was performed by knowledgeable personnel. The
control of work was good, with evidence of good planning and coordination of the
personnel involved in the work. Licensee actions were appropriate and conservative
to complete SW piping inspections, characterize defects and to repair sections
,
'showi6g degraded wall thickness. The extensive corrosion and general degradation
in the service water system resulted in an inoperable condition for the system relied
~
!
4
-, ,
. __
. .
.
t.
i
28 l
;
' upon to cool the spent fuel. This finding ~ appears as another example of poor plant
material conditions that challenge systems important to plant safety.
ML2 Surveillance Observations-
Using Inspection Procedure 71707,61726 and 62703, the inspectors conducted periodic
j . reviews of plant status and ongoing surveillance.
a. - Insoection Scope (61726)
l The inspectors observed portions of the following surveillance activities:
e Emergency Diesel EG-2B Manual Starting and Loading (SUR 5.1-1578)
e Emergency Diesel EG-2A Manual Starting and Loading (SUR 5.1-157A) )
J
e Radiation Monitoring System Calibration (SUR 5.2-81.6, Rev 18) a
e All Modes Locked Valve Checklist (SUR 5.1-126, Rev 24)
e- SW Check Valve SW-CV-963 Bench Test (AWO 97-1448)
e SW Hydrostatic Pressure Test (ENG 1.7-65, AWO 97-1451)
e . Functional Testing of SW-CV-963, (ST .11.7-201)
w e SFP Heat Exchanger Temporary SW Supply Flow Test (ST 11.7-203)
t e- . Inservice Testing of SW Supply.to SFP Cooling Check Valve (SUR 5.7-217) .
-e . inservice Testing of SW Pump Discharge Check Valve (SUR 5.7-89)
b. Observations and Findinas
SUR 5.1-17B The purpose of this test on January 22 was to demonstrate the
4 standby readiness of EG-28. The test was performed by starting the diesel
manually from the excitation control panel. When the operator started the engine,
, rather than run initially at 450 rpm speed as expected, the engine went to full speed
at 900 rpm and automatically flashed the field. An engine start failure alarm l
annunciated. The operators shutdown the diesel pending further troubleshooting
'
,
and repair. The deficiency was described in ACR 97-39. Licensee investigations on
January 23 and 24 included troubleshooting the engine start circuitry, running the
diesel with test instrumentation to monitor the performance of the speed sensing
i relays in the starting circuit, and a satisfactory test of the diesel at rated load. The i .
failure could not be repeated and no defective component was identified.
The licensee concluded the deficiency was probably caused by one of two relays in
!- the manuel start circuit, whose failure could not prevent the diesel from performing C
.its design basis function. An engineering evaluation completed on January 27,
1997 concluded that EG-2B remained operable (reference CY-TS-97-033). The
licensee continued to test EG-2B weekly until February 19 while instrumented to
monitor the start circuits; however, the deficiency did not reoccur. The licensee
resumed a normal test interval for EG-2B of once per month. The inspector
,
reviewed the troubleshooting plan and activities, reviewed the engine start circuits
!- and logic (reference drawing 16103 31099 sheet 3), the engineering operability
. evaluation, and the subsequent augmented testing on the engine. No discrepancies.
'
' were identified.
4 -. _ , . . , - . ~ - _ ._ ,,,, _ -
- . _ _ _ .
- _. _ . .
.
29
SUR 5.1-17A The purpose of this test on February 12 was to demonstrate the
operational readiness of EG 2A. The test was completed satisfactorily in that the
diesel started, loaded and energized the associated 480 volt emergency bus as
required. However, when the engine was shutdown, the licenses noted that the
engine remained at 900 rpm instead of 450 rpm as expected for a 11 minute
cooldown period during the shutdown sequence. The licensee evaluated the
possible causes for the problem and concluded the safety function of the diesel was
not affected. Licensee troubleshooting in March identified a faulty relay, and plans
were made to replace the relay during the April test outage of the diesel. The
problem recurred during a EG-2A monthly operability tests in March (ACR 97-127)
and April (ACR 97-178), but the diesel performed all safety functions correctly to
start and carry associated loads. The planned relay repairs were not completed in
April due to operational restraints in removing EG-2A from service with degradations
in the service water system. The repairs were deferred until the May test period.
The engine remained operable and in standby pending further relay repairs and
investigation of the problem.
SUR 5.1-178 On February 5,1997, the inspector observed a special performance
(extra test) of surveillance (SUR) 5.1-17B, Emergency Diesel Generator (EG)-2B
su Manual Starting and Londing Test. EG-2A had twice experiencing.an abnormal . ;
- shutdown where the cooldown sequence (operation at half-speed for about 12
minutes) had not automatically occurred. This condition was documented in two
ACRs and AWO 97-0873 was prepared for troubleshooting the problem with EG-2A
during the next system outage (scheduled for May 12,1997).
The extra surveillance of EG-2B was to ensure its operability since EG-2A was not
shutting down correctly. To allow for this special test, starting the EG but not
loading the generator and tying to the emergency bus, Temporary Procedure
Change (TPC) 97-17 to SUR 5.1-17B, authorizing EG startup to full speed without l
loading, was PORC approved on January 30,1997. For this observed test, EDG-2B ,
automatically slowed down to half speed for unit cooldown, as designed. l
1
Prior to the EDG-2B surveillance run, a chemical technician collected a sample of the
fuel oil from the 550 gallon engine mounted day tank. The inspector noted that the
technician had no paper work with him but was knowledgeable about collecting the '
i
sample. The oil collection was in accordance with SUR 5.4-41, Diesel Oil
Surveillance, and had been scheduled by Work Order CY-96-07919. Nothing in CY-
96-07919 or SUR 5.4-41 required data entry (tne procedure had no sign-off blanks).
This was considered acceptable because it was within the skill of the technicians.
AWO 97-1448 The purpose of this test on March 26 was to conduct a pre-
installation leakage test of the 6 inch swing check valve that would be installed in
the service water supply line (6-WS-151-126) to the SFP heat exchangers per DCR
97-02. The Anchor Darling swing check valve (serial # E6318-54-5) was an ASME
lil, Class 2 component rated for 100 degrees F at 275 pounds. The purpose of the
plant modification was to assure that the SW supply lines remained filled with water
following a postulated loss of power. The engineering evaluation for DCR 97-02
assumed that this function would be assured so long as back leakage past the
,
30
check valve seat was limited to 2 gallons per minute for the approximate 48 second
interval between the loss of power end the start and load of the emergency diesel
generator and associated SW pump during an LNP. The licensee established a
leakage limit of the check valve of 2 gpm and 0.5 gpm, for insitu and bench testing,
respectively.
The inspector observed the test setup and results of the bench testing completed on
March 26. The check valve was pressurized in the reverse flow direction at a
pressure of 8 psig, as leakage was measured with a graduated cylinder. The
inspector verified that the test pressure corresponded to the maximum pressure for
the elevation head of water from the high point in the service water system to the
elevation the location of the check valve. The licensee measured 20 ml/ min during
the test, which was less than 0.01 gpm and much less than the 0.5 gpm
acceptance limit. Test personnel were familiar with the test equipment and AWO
controls. Engineering personnel provided good oversight of the test activities.
ENG 1.7-65 The purpose of this test on April 4 was to verify the integrity of the
safety class 3 service water supply header following the installation of check valve
SW-CV-963. The hydrostatic pressure test was conducted in accordance with
- ASME Code Section XI,1983 Edition. The 110 psig class system was tested to-
121 psig (110%) with a 10 minute hold period, followed by an inspection for
leakage at the new welded and mechanical joints. The results were satisfactory.
No inadequacies were identified.
ST 11.7-201 This functional test of SW-CV-963 was performed on April 4 to
assure adequate flow to pravent flutter. The test was completed successfully to
demonstrate that SW flow to the heat exchangers was not degraded by the
additional restrictions introduced by the new check valve in the SFP supply line.
The measured flow was satisfactory at 920 gpm, which was above the minimum
valve assumed in the design basis of 855 gpm. Further, the test identified the
minimum flow the licensee needed to maintain through the supply line to avoid
valve flutter under low flow conditions. No inadequacies were identified.
SUR 5.7-217 The purpose of this inservice test of SW-CV-963 was to assure it
opened to allow adequate cooling of the SFP and, to verify that it closed and was
leak tight to assure the back leakage met the safety function assumed in DCR 97-
002. The acceptance criteria was that measured back leakage was less than 7570
cc/ min, met the assumptions in the safety evaluation for DCR 97-002. The
licensee's engineering evaluations (CREARE letter dated March 17,1997) showed
that if back leakage from the SW supply header was limited to 2 gpm, the
postulated waterhammer event on during a LNP condition would be prevented.
The test was completed satisfactorily to show that the check valve opened and
provided adequate flow to the SFP heat exchangers. The licensee also measured
zero back leakage from the check valve during the performance of the test on April
4 (test method for SUR 5.7-217 Revision 0). However, test personnel noted the
need to improve the test method to isolate the test boundary, and that a partial
vacuum was drawn in the piping upstream of the check valve pr;or to the
31
measurement of back leakage. The inspector reviewed the test method and results,
and determined that the SW piping was partially drained during the test, and that
the test method had failed to adequately measure actual back leakage. The
inspector's concerns were discussed with the operator in charge of the test on April
4. The licensee prepared ACR 97-173 to describe the deficiencies in the test
method. Licensee actions were in progress at the conclusion of the inspection
period to revise the test method and measure back leakage from SW-CV-963.
ST 11.7-203 The purpose of this test was to measure flow to the SFP heat
exchangers with the temporary hoses installed per NOP 2.24-3 for various supply
and return configurations. This test was successfully completed to provide the data
for an engineering evaluation of the adequacy of service water cooling flow to the
SFP heat exchangers when using the fire hoses,
c. Conclusions
The surveillance activities observed this period were acceptable. The preparations
for and conduct of testing was generally good. Pre-job briefs were very good and
provided for good planning and coordination of the personnel involved in the test,
a: and good control of test activities. The surveillances were performed by-
knowledgeable personnel. Although evaluations to address degraded condition on
the emergency diesels were acceptable, two diesel problems remained not fully
resolved and licensee actions to address deficiencies on the emergency diesel i
generators were not as aggressive as in the past. The tests conducted were
acceptable to demonstrate the operability and readiness of plant equipment. An
exception to good performance in testing was the faulty test method used on ST j
11.7-201 to verify acceptable back leakages from service water valve SW-CV-963. )
l
M2 Maintenance and Material Condition of Facilities and Equipment i
M 2.1 Material Condition Deficiencies (VIO 97-01-02.d. URI 97-01-04)
1
a. Inspection Scope j
l
The purpose of this inspection was to assess the status of the plant material I
conditions, and the performance of licensee processes to address discrepant
conditions,
b. Qbservation and Findinas
in the work controls area, the licensee documented a finding (ACR 97-90) on
February 18,1997, that trouble report tags were not removed as required following
maintenance activities. Based on a review of 275 trouble report tags hanging
throughout the plant, operators found that 113 (41%) were associated with trouble
reports and work orders that had been completed. Trouble reports (TRs) that
remained after the work was complete made it hard for operators to perform their
job properly to identify discrepant plant conditions, since some items that are not ,
operating properly are not being reported under the trouble report system because it l
l
l
l
.
a
32
is assumed that there is an active trouble report and repair plan in existence. The
licensee determined that this problem occurred because workers were either not
familiar with or were not following the requirements of procedures WCM 2.1-1,
Work Control Process, and WCM 2.12, Trouble Report / Job Scoping. TRs that are
deleted because the work is performed under minor maintenance WOs are difficult
to track and the workers may not be aware of the existence of a TR tag.
;
The ACR was discussed at the February 20,1997 meeting of the management
review team (MRT) and assignments were made to correct this problem. Licensee
actions to address this matter were in progress at the end of the inspection period.
However, Work Control Manual WCM 2.1-2, Trouble Reporting / Job Scoping,
Revision 3, requires in Steps 1.2.3 and 1.3.3 that trouble report tags be removed
and closed epon development of work packages, or for work that will be completed
under blanket authorized work orders. The failure to remove TRs was a failure to
implement WCM 2.1-2, and was an example (the fourth of six) of a violation of
Technical Specification 6.8.1 (VIO 97-01-02.d).
Other discrepancies in plant material conditions were noted during the period, and
included the corrosion degradation of the service water piping (described in Section
e M1.1 above), the generally poor conditions around the service water Adams filter
area in the upper level of the auxiliary building, and the poor lighting conditions in
the containment caused by a number of lights that have burned out. Other material
discrepancies included the recurring problems with the radiation monitoring system,
including an unresolved design defect in the SCANRAD computer.
The licensee tracks key performance indicators (KPis), including the backlogs in l
total trouble reports and work orders, and the trends in work deferrals and the ;
amount of rework. The KPis for the above parameters show a large amount of
outstanding work, with little progress over the first quarter of 1997 to improve
performance. The lack of progress was attributable to several reasons, including a
decision to not conduct work on systems that were no loager operable or required i
for decommissioning; a decision to defer outage related testing on systems that I
were no longer operable or required for decommissioning; the management decision )
'
to restrain the conduct of work in the radiologically controlled area, pending the
development and implementation of plans to improve radiological controls; and, the
reduction in available workers as the staff was reduced to the decommissioning
organization. The adequacy of staffing in the maintenance area to address plant
material conditions and to preserve the systems that remain important to the safe
storage of fuel remains an area that requires further evaluation by the NRC.
This item is unresolved pending further NRC review of licensee actions to address
the deficiencies in ACR 97-90, and licensee performance to address the backlog of
4
station work (URI 97-01-04).
__.
-- . .
.
.
33
c. Conclusions
Past NRC inspections have identified concerns with discrepancies in plant material
conditions and the performance of licensee programs to preserve systems important
to safety (reference Inspections 96-80, 96-10, 96-11 and 96-12). The above
findings appear as recurrent problems in this area.
.
M3 Maintenance Procedures and Documentation
M3,1 TS Surveillances Covered by Procedures (VIO 97-01 -02.e)
,
'
a. Insoection Scooe (61726)
This inspection was performed to review the licensee actions to periodically review
station procedures. During inspector review of a change to Administrative Control l
Procedure (ACP) 1.2 6.5A, Station Procedures, a concern was raised.
b. Observations and Findmag ,
l
m ACP 1.2-6.5A, Station Procedures, Revision 0 dated November 13,1996, states in
Section 1.3.6 that procedures in the Surveillance Procedure category are reserved !
for surveillance inspections or tests which are required by the Technical
Specifications (TS). ACP 1.2-6.5A also requ;res, as part of the biennial review, that
plant personnei verify all TS Action Statements are clearly identified and applicable -
l to the Limited Condition for Operation. The licensee implemented this requirement I
through a revision to Work Control Manual (WCM) 3.3-1, Technical Specification
Surveillance (TSS) Tracking, Revision 2, issued July 18,1995. WCM 3.3-1
4 established a master database for all TSS with an administrator, required an annual
audit of the master list database to ensure each TSS was on the database and tied
to a specific surveillance procedure, specified a January action request for review of
all TSS procedures, and provided critical function review questions. ,
l
The inspector requested the licensee to provide the resu!ts of the annual audit of
surveillance procedures required to be done per ACP 1.2-6.5 and WCM 3.3-1. In
response to the inspector's February request regarding reviews to assure all TS
realized requirements are covered by surveillance procedures, the licensee reported !
that a review of the master database had not been completed per WCM 3.3-1 and
initiated the required review. Although the assignment to complete the review had
been made (via February Action Requests), the reviews were stillin progress as of
April 4,1997. Further, in response to the inspector's request, the licensee provided
a OAS audit showing numerous problems in implementing the operational -
surveillance program. Two of the problems identified were:il one surveillance (SUR
5.2-69) where a second TSS requirement was not reference and the first TSS was I
no longer required; and, ii) nor surveillance procedures PMP 9.1-31 and ESP 14.1-4 j
were used to meet TSS requnments. The deficiencies identified by the NRC and l
the QAS audit were conditions contrary to procedures ACP 1.2-6.5A and WCM 3.3-
,
1. The failures to implement the surveillance program per these administrative
!
I
<
.
34
procedures were the fifth of six examples of a violation of TS 6.8.1 (VIO 97-01-
02.e).
C. Conclusions
The deficiencies described above showed poor performance by plant personnel in
following station procedures and in implementing the operational surveillance
program.
M4 Maintenance Staff Knowledge and Performance
M4.1 Failure to Comolete Surveillances (VIO 97-01-05. VIO 97-01-06)
a. Inspection Scope (61726)
The scope of this inspection was to review the licensee performance for completing
surveillance tests in accordance with the technical specification requirements.
b. Observations and Findinas
Several events occurred during this period in which the licensee's staff failed to
complete required surveillances as required. Most incidents were identified by
licensee personnel and were entered in the ACR program for management review
and followup. The issues noted during this period are summarized below:
ACR 97-57 wd, issued due to the discovery on February 4,1997 of the failure to
complete a fire system surveillance (18 month fire system inspection) as required by
the technical requirements manual TRM 16.1-3. The surveillance was due to be
performed in September 1996. The test was not done due to a communications
error among operations personnel during the scheduling of surveillance tests. The
error occurred because another test completed per TRM 16.1-13 on 9/30/96 was >
mistakenly listed as the completion of TRM 16.1-3. The fire system inspection was
subsequently completed satisfactorily,
t
ACR 97-66 was issued due to the discovery on February 6,1997 that the reactor
coolant chemistry had not been verified as required by the technical specifications.
TS 4.7.7 requires that the RCS be sampled every 72 hours to assure that chloride,
fluoride and oxygen levels are below certain limits to minimize the potential for
stress corrosion cracking of reactor vessel and RCS components. The last RCS
taken and analyzed was on November 15,1996 when the RHR system was
shutdown following completion the core offload into the spent fuel pool. The
licensee stopped taking the samples because chemistry personnel believed the TS
requirements were no applicable in the defueled condition. TS 3/4.4.7 states that
the chemistry limits and surveillance requirements are applicable at all times.
Immediate corrective actions were to recommence RCS sampling in accordance
with the TS requirements. The RCS water was well within the requirements for
chloride and fluoride contamination (by an order of magnitude). The licensee had
4
35
continued to sample reactor cavity water to assure chloride and fluoride levels were
satisf actory, but these samples were obtained from the cavity purification system
and could not be assured to be representative of the water in the reactor vessel. ,
Thus, there is some uncertainty as to what the chloride and fluoride levels inside the )
reactor vessel were during the period from November 1996 until February 1997. l
Licensee investigations for ACR 97-66 determined that RCS sampling was also
stopped in the past when the reactor was defueled for extended periods (e.g.,
during the work on the core shroud in the late 1980's).
l
This event was reported as licensee event report (LER 97-02). The safety I
significance of this surveillance and technical specification violation was low relative
to future Haddam Neck operations since the chloride stress corrosion cracking i
mechanism is a concern for subsequent operation of the RCS at normal operating l
temperatures and pressures. Due to the decision to permanently cease plant
operations, the reactor fuel can no longer be loaded into the reactor, and the RCS
will no longer be operated at the normal operating conditions of 550 degrees F and i
2000 psig. However, the failure to sample and analyze RCS Chemistry from )
Nove " >r 15,1996 to February 6,1997 was a violation of TS 4.7.7 (VIO 97-01- 1
05).
ACR 97-77 was issued on February 11,1997 concerning to failure to complete two
surveillances as required by the technical specifications on the B main station l
battery, BT-18. The following tests were scheduled to be performed in October l
1996 to meet the requirements of the technical specifications: SUR 5.7-37, Station
Battery Cellinspection, Cell Resistance and Rack inspection, which is required to be
performed once per 18 mc..ths per TS 4.8.2.2. and 4.8.2.1.c; and, SUR 5.7-38,
BT 1B Battery Service Test, which is required to be performed once per 18 months
per TS 4.8.2.2 and 4.8.2.1.d. The tests were deferred to December 1996, which
was acceptable since the surveillance would have been within the 125% window.
However, the scheduled conduct of the tests was deferred due to the management !
work stoppage placed in effect in November 1996. Plant personnel failed to l
adequately track completion of the tests against the required surveillance due date.
The test were preformed satisfactorily un February 18-21,1997. Although TS
3.8.2.2 required only one DC distribution system be operable for Mode 5 & 6
operation (none is required with the reactor defueled), the licensee policy was to
maintain both DC distribution trains operable and tested per the TSs.
ACR 97-81 was issued for the discovery on 2/12/97 that the service water pumps
were not tested as required per TS 4.7.3.b.2. The TS require that the pumps be l
demonstrated operable at least once per 18 months by starting on a condition
involving a loss of normal power. The TS surveillance was due on 9/26/96; the
25% extension interval expired on 2/10/97. This portion of the SW pump starting
logic is normally tested each refueling outage during the conduct of SUR 5.1-18 and
19, the Test of the Train A and B Safety injection Actuation System with Loss of
Normal Power. This test was not performed during RFO#19 because of the
decision to permanently shutdown the f acility. The licensee initiated actions to
, write a new procedure to test the LNP feature in the SW pump start circuiL
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ACR 97-142 was issued following the discovery on March 21,1997 that the
surveillance of locked valves had not been completed per the schedule required by
the technical specifications. TS 4.5.7.C requires that all accessible valves be
verified to be locked in the correct position at least once per 18 months. The tests
in performed per SUR 5.1-126 which was started and in progress during this
inspection period with an assumed required completion date of March 1997. This
date was based on the assumption that the surveillance had last been performed in
September,1995. On March 21, the duty shift manager noted that SUR 5.1-126
had last been completed in March 1995, and was therefore due to be completed by
September 1996. The scheduling discrepancy occurred due to an operator error in
recording the date when SUR 5.1-126 was last done, which was taken from the
shift logs and was assumed to be in September 1995. The licensee determined that
September 1995 was the date when the shift logs were updated when revision 23
of SUR 5.1-126 was replaced with revision 24. The licensee continued the
verification of the locked valve checklist, which was stillin progress at the end of
the inspection period.
ACR 97-126 was issued on March 12,1997 as a r=uit <>f an audit by the QAS
group that concluded that the station tracking systems for ensuring the completion j
of TS surveillances while in a defueled condition were susceptible to missing a
surveillance. The OAS audit found that surveillances were being scheduled to start
after the required frequency (but within the 25% grace period); surveillances were l
not always scheduled within the production maintenance management system l
(PMMS); surveillance requirements are not always tracked by plant departments;
the surveillance procedures for calibrating effluent monitors do not reference the i
technical specifications, which creates the potential for a missed surveillance; some
TS surveillances are performed by non surveillance procedures (i.e., procedures
other than SURs); and; surveillances are being completed without the use of
automated work orders (which assures tracking and scheduling within the PMMS). !
Licensee action in response to the QAS findings were in progress at the conclusion
of the inspection period.
The inspector noted that although the above discrepancies were identified as a
result of initiatives by either the line organization or the oversight groups, there was
a demonstrated weakness in completing surveillance in accordance with the
technical specification requirements. Further, this has been a weakness in the past
at Haddam Neck, and a concern previously described by the NRC (reference
Inspection item 94-27-01 and LERs 96-22, 96-17, 96-04 and 95-12). Tne f ailures
to complete the surveillances as described in the above ACRs were a violation of
the associated technical specifications. The failure of past licensee actions to
correct this condition adverse to quality was a violation 10 CFR 50, Appendix B,
Criterion XVI (VIO 97-01-06).
c. . Conclusions
Poor performance was noted in the repetitive failure by licensec personnel to
adequately implement the technical specification operational surveillance program.
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M8 Area Summary and Status of Regulatory Findings
M8.1 (Closed) IFl 96-01-01, Cable Vault Materials Condition
During inspection 50-213/96-01, the licensee determined that the material condition
of housekeeping in the cable vault had degraded because the building ventilation
system and the two sump pumps had become inoperable. This resulted in
excessive moistwe in the room along with a buildup of accumulated water on the
lower level of the vault. The inspector toured the cable vault on several occasions
during the period and verified that the moisture and water did not cause an
immediate impact on plant equipment. This matter was left open pending the
completion of licensee actions to address the poor housekeeping and material
conditions in the cable vault, and subsequent review by the NRC. The inspector
visited this area to confirm corrective actions. The floor has been recoated, new
grating and non-slip pads were being installed, and the sump pumps were operable
although a small amount of water was still on the floor. This inspection follow-up
item is closed.
M8.2 (Closed) DEV 96-04-02. Heavy Load Proaram Commitments
During inspection 50-213/96-04, deviations of CYAPCO's commitments of July 20,
1981 and April 16,1982, to satisfy NUREG 0612 (Phase 1) expectations on crane
operator qualifications, were reviewed. In addition, a licensee letter dated June 29, j
1984, stated that nondestructive testing will be done on the identified lift devices '
. on a ten-year cycle. One identified lift device was the PAB floor block lift device.
Plant procedure PMP 9.5-131, "Special Lifting Device Inspection and/or Load
Testing," did not have this lift device included in the procedure. The NRC's safety
evaluation on the " Control of Heavy Loads (Phase 1)," dated August 20,1984 noted
that Phase I was acceptable at Haddam Neck.
The licensee response to these deviations, dated August 12,1996, included j
commitments to revise procedure ACM 2.2-9, Control of Crane Operations, and On- 1
The-Job Training Guide to include and verify physical qualifications, in additicn,
WCM 2.2-7, PAB/ Pipe Trench Floor Block Lifting Procedure, was revised to
designate the use of the lift rig when lifting floor blocks. The inspector confirmed
these changes were made. This deviation is closed.
M8.3 (Closed) IFl 96-08-04, Auxiliary Feed Water Overspeed Trio
During a quarterly test of the "B" auxiliary feedwater pump mechanical overspeed
trip device, the trip valve did not fully close. The proposed corrective actions
include developing a preventive maintenance procedure for the mechanical
overspeed trip device, revising the acceptance criteria to define acceptable
mechanical overspeed trip function, and replacing the trip linkages during the
upcoming refueling outage. The issues were lef t for an inspector follow-up in IR 50-
213/96-08. Due to the decision to permanently cease operation of the Haddam
Neck facility pursuant to 10 CFR 50.82(a)(1)(l), the auxiliary feedwater system is no
longer of safety importance. This issue is considered closed.
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M8.4 (Closed) IFl 96-08-05. Steam Generator Hold Down BQ1ts
During a containment inspection, the licensee discovered that one of the #2 steam
generator hold down bolts was broken. The 3 inch diameter by about 32 inch long
bolt was found lying on the floor near its sliding / support block located ori the lower
skirt assembly. It was presumed that the bolt " popped" out of its hole in the
support block. This matter was left for inspection followup in IR 50-213/96-08.
Due to the decision to permanently cease operation of the Haddam Neck facility,
the steam generators are no longer of safety importance. This issue is considered
closed.
MQJ (Closed) IFl 96-08-06. Observations of Procedural Quality
During inspection 50-213/96-08, the NRC identified that no periodic or preventive
maintenance program exists for (Westinghouse] safety-related with lockout (WL)
relays. Inspector review of the maintenance history of the WL relays identified one
corrective maintenance activity in 1990 to replace switch contacts on the "B" high
containment pressure relay. It was also noted that the WL relays are tested and
provided successful results in the past three refueling outages during the
+ performance of SURs 5.1-18 and 5.1-19. This issue was discussed with the
licensee during the course of the inspection. The licensee initiated an assignment to
consider the development of a periodic maintenance program for these safety
related relays.
The inspector was provided a licensee engineering and electrical maintenance i
analysis of the classified of these relays, within the scope of 10 CFR 50.65, dated l
March 20,1997. This analysis concluded that, based on the limited wear the relays
see, the limited benefits of an "out of the board" PM, and the fact that there is a 4
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large potential for human error involved in removal and re-installation of the relays,
the outage-based surveillance procedure tests are felt to be the best and most
informative preventive measure available to ensure fulfillment of the Maintenance
Rule, it was also pointed out that due to the permanent shutdown of Haddam Neck
that virtually all safety related WL relays, outside of electrical distribution, are now
no longer required. The inspector confirmed that there were no Westinghouse
safety related WL relays in the electrical distribution system. This inspection
followup issue is closed.
M8.6 (Onen) URI 96-08-15. Start-un issues (7/24/95 NRC Letter)
In a July 24,1996 letter from the NRC to the licensee, seven technical issues,
some involving possible amendment requests were identified that need to be
resolved for a plant restart. The major modifications and technical issues to be
addressed during the outage include:
a) CAR f ans alternate service water modifications and license amendment; this
item includes the performance of an integrated safety assessment to address
the known related service water system issues (operating pressure, CAR fan
performance and containment integrity).
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b) modifications to mitigate a main steam line break event - the main feedwater !
pump trip and discharge valve closure on high containment pressure, and j
license amendment. I
c) the conduct of the station battery test using the profile with the AFW ;
hydraulic pumps running, j
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d) the completion of a new station battery calculation to demonstrate battery j
operability with the AFW pumps shutdown. !
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e) actions to address other discrepancies in material conditions, such as steam I
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generator hold down bolts and main steam bridge structural steel.
f) modifications to address RHR NPSH - eliminate the reliance on containment
back pressure, and to upgrade the containment sump. ,
g) Type "B" leak rate of containment penetration P-50. j
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Due to the decision to permanently cease operation of the Haddam Neck facility,
a issues a) CAR fans performance, b) main steam line break, part of e) dealing with
steam generator hold down bolts, f) RHR containment back pressure NPSH, and g)
containment penetration P-50 leak rate test, are no longer important to the ;
permanently shutdown, defueled, and later decommissioned status. These issues ;
are considered closed. Likewise, issues, c) conduct of station battery profile test, !
d) new station battery calculations to demonstrate battery operability, and the part !
- of e) dealing with main steam bridge structural steel, remain to be corrected by the '
licenseo and inspected by the NRC. 1
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M8.7 (Closed) URI 94-27-04. Surveillance Frecuency Exceeded )
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This item was created in response to a failure to adequately complete surveillance
requirements. The initial corrective actions were reviewed and NRC followup
review (Inspection 95-14) left the matter open pending further review of the i
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conduct of surveillances for adverse trends. Licensee performance in the conduct
of operational surveillances has declined, as summarized above in Inspection items
97-01-04 and 97-01-05. Licensee responses to NRC concerns in this area will be
tracked under Inspection item VIO 97-01-05 & 06. Inspection item 94-27-01 is
closed.
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M8.8 Conclusions for Maintenance
The maintenance and surva%nce activities completed this period were generally
acceptable to assure important plant systems remained operable, to support
operability evaluations and design change work, and to address emergent issues
that challenged adequate cooling of the spent fuel. Exceptions to good performance
included a weakness in the process to examine SW pipe for corrosion, and a faulty
test method used to measure back leakage from a check valve. Additional
discrepancies were noted in plant material conditions, in the implementation of the
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program to identify and correct material discrepancies, and in the lack of progress in
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addressing deficient conditions.
Poor perforrnance was noted in the failure by station personnel to follow procedures
to implement the operational surveillance program, and in the repetitive failure to
adequately implement technical specification surveillances in a timely manner. The
extensive corrosion and general degradation in the service water system resulted in *
an inoperable condition for the system relied upon to cool the spent fuel. This
finding appears as another example of poor plant material cond;tions that challenge
systems important to plant safety. The recurrence of plant material deficiencies and
problems in the area of technical specification surveillance testing revealed ongoing
weaknesses the corrective action process.
Ill. ENGINEERING !
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E1 Conduct of Engineering
E1.1 Service Water System Modification - Water Hammer (URI 97-01-07)
a. Inspection Scoce (37551)
The purpose of this inspection was to review the licensee evaluations of the
potential for two phase flow in the service water system, and to complete
modifications to preclude postulated waterhammer events,
b. Observations and Findinos
The inspector reviewed the licensee's actions in response to a concern raised by a
previous NRC inspection in which the potential for two phase flow and water
hammer loads in the service water system were identified. The NRC concern was ;
identified during the Engineering and Licensing inspection conducted in 1996, and -
was identified as inspection item 96-201-24.
Following the inspector's request this period for information of the status of the
engineering review of this issue, the licensee found that the potential for two phase i
flow in the service water system had been identified, but not completely resolved.
Specifically, following the inspections in 96-201, the licensee contracted the
services of a vendor to analyze the potential for two phase flow in the SW system.
The initial engineering evaluations were reported to the licensee in vendor report
TM 1788 dated July 9,1996, which concluded that there was no significant
potential for column separation in the SWS following a loss of normal power (LNP)
event. However, following additional analyses, the vendor submitted a revised
technical eva!uation in report TM-1788a dated August 14,1997, in which there
were two locations in the SWS where column separation could occur. Specifically,
the locations were in the higher elevations of the SW supply and return lines to the
spent fuel pool cooling system (SFPCS) heat exchangers (63 foot elevations on the
6-WS-151-126 supply piping, and 63 foot elevation of the 6-WS-151-250 return
piping).
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The vendor's analysis for two phase flow conditions was postulated to occur as a
result of the draining of water from the high points in the SW headers to the I
SFPCS, as would occur when the SW pumps shut down following a loss of
electrical power. As the water drained from the high points in the system, a partial
vacuum condition inside the piping would result in separation of the water column in l
to a vapor and liquid phase (column separation). The separation occurs at the high l
point elevations because the water pressure at the top of the column falls below the
vapor pressure of the liquid while the bottom of the column is open to atmosphere.
On a LNP, the SW pumps would trip and the piping system would depressurize l
within about 2 seconds. On restoration of power following the start of the
emergency diesel generators, the SW pumps would be started in about 45 seconds
from the start of the LNP event. The sudden repressurization of the SW lines and
the collapse of the water column would result in waterhammer in the piping system. l
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The vendor analysis postulated that the associated water hammer loads could be
excessive, and result in as much as a three inch displacement of the piping system
when the collapsed water column reached sharp bends in the piping system. j
On receipt of the vendor's report in August 1996, the licensee completed a
preliminary assessment of the SFPCS supply lines, which concluded that the SW
a- cooling lines had not been affected adversely affected by the design deficiency...
This conclusion was based on the observation that there had been LNP events in
the past 28 years of the plant (either as a result of planned testing, or inadvertent
power outages), and that a postulated three inch displacement of the piping system !
would have been either observed or left evidence in the piping system. A licensee
design engineer walked down the SW headers and identified .no evidence in the
piping or attached insulation indicative of a waterhammer event in the lines.
Although the resolution of the analysis results remained unresolved in August,
1996, the licensee classified the matter as an issue that had to be resolved prior to
plant restart, and assigned the project to a plant engineer to develop a modification
that would resolve the issue (modifications involving vacuum breakers and check
valves were under consideration). However, the project was not completed for
various reasons, and no action was taken to complete the modifications or to
otherwise resolve the analytical problem through the end of 1997,
in response to the NRC inquiries this period, licensee engineering reviewed the
status of the vendor's analyses. The vendor evaluations in August assumed that
the SW return side isolation valve SW-AOV-9 would fail open on a LNP, since that
was a conservative assumption in the analysis of the SW system for plant
operations at full power. In practice, SW-AOV-9 would fait closed on a LNP. The
vendor evaluated the potential for column sepatation assuming AOV-9 operates as
designed, and concluded that the SW return lines would remain operable under
these conditions. However, the supply side piping could continue to drain into other
headers (e.g., the diesel generator supply piping) in the 45 seconds the SW pumps
were not operating, and result in column separation. Engineering evaluations in
March 1997 of the effects of the postulated water hammer concluded that the pipe
stress levels would be unacceptable for the postulated transient. This conclusion
wes based on the postulated piping stresses and support loads at the locations of
the highest waterhammer loads, and included the conservative assumptix that the
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service water pipe wall thickness was at the lowest value seen as a result of
erosion and corrosion inspection. The assumed minimum wall thickness was that
identified and repaired at a "T" fitting in the SW return line from the "A" and "B"
SFP heat exchangers in the Fall of 1996. Under these conditions, the licensee
concluded that the SW pipe pressure boundary would fail under a design basis LNP
event.
Based on the above, the licensee declared the spent fuel cooling system inoperable
on March 11,1997, and made a report to the NRC per 10 CFR 50.72(b)(2)(l)
regarding plant operation in a degraded and unanalyzed condition. The licensee
initiated actions this period to address the design deficiency. Possible fixes
considered included additional analyses of the potential for two phase flow, and
design changes to install either vacuum breakers of a check valve in the affected
piping. The option selected was the development of design change request (DCR
97-002) to install a check valve (SW-CV-963) and associated test valve (SW-CV-
964) in the SW supply line to the SFP heat exchangers. The licensee installed a 6
inch Anchor Darling swing check valve in the SW supply header located in the
southeast corner of the auxiliary building near the Adams filters. The inspector
verified that the check valve rated for 150 psi service conditions and was procured
2.- as a safety related component. The licensee also contacted the original vendor >
whose engineering evaluations assisted in the identification of the design deficiency
to provide assistance in developing the check valve performance criteria needed to
eliminate the potential for excessive water hammer loads. Licensee actions were in
progress at the end of this inspection period to install and test the check valve, and
to complete and approve the safety evaluation for DCR 97-002.
Several discrepancies in licensee performance were noted in development and
< resolution of this item. Once the licensee's contractor had identified the potential-
two phase flow as a design discrepancy, the licensee inappropriately classified the
issue as a plant " restart" item in August 1996. The design discrepancy was a
condition adverse to quality that was relevant to plant operations in the shutdown
condition, which should have been resolved in the Fall of 1996 prior to the offload
of the core into the spent fuel pool. The design engineering group used reasonable
engineering judgements based on a walk down of the SW lines in August 1996 to
assess the actual potential for excessive water hammer loads, but left final
resolution of the matter inconclusive. Further, the design engineering group showed
poor performance to track the issue internally to assure the timely completion of
further analyses and the development of modifications to address the issue. This
was an example of weaknesses in the licensee's corrective action process to assure
that conditions adverse to quality are promptly addressed to preclude recurrence.
Finally, licensee actions to track and resolve NRC inspection item 96-201-24 were
poor. The design vulnerabilny in the SFP support systems would have remained
had it not been for the NRC followup of this matter.
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c. Conclusions
These issues are similar to deficiencies in licensee performance highlighted by past
NRC inspections and addressed at the escalated enforcement conference held on
December 5,1996. As followup to this issue under ACR 97-119, the licensee
planned to perform a root cause investigation to determine how this issue was
tracked by engineering, and to verify that other issues were property resolved. The
licensee also planned to assess this discrepancy and report his evaluation per 10
CFR 50.73. This item is unresolved pending the completion of licensee actions to
address the SW two phase design deficiency, and subsequent review by the NRC
(URI 97-01-07).
EL2 Service Water System Evaluations - Corrosion (URI 97-01-08) >
On March 26, the licensee declared the SW return piping from the SFP heat ,
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exchangers inoperable at 7:15 p.m. as a result of corrosion induced excessive wall
thinning in a 6 inch carbon steel pipe 6-WS-151-250 (ACR 97-154). The defect
was located in a three inch area of heat exchanger return piping about one foot
downstream of the common heat exchanger return tee ('T'). See Section Mt.1
., (authorized work order 97-806) for further details on this issue. ;
The corrosion defect was identified during a planned ultrasonic (UT) inspection of.
the line in an area of known wall thinning. The pipe wall thinning was previously
identified during inspections on 1996 for microbiologically influenced corrosion and
was found acceptable at that time (reference Calculation 96-SDS-1556MY, Revision
- O dated 10/27/96). Using the data available in October 1996, the licensee assumed
that the pipe would remain operable for up to 1 year based on the predicted
7 corrosion rates, and recommended that re-inspection be performed in six months.-
The pipe was determined to be inoperable in March 1997 as a result of additional
wall thinning at the site of the original defect, based on an engineering evaluation
by the Structural and Design support Group that concluded that the pipe could not
withstand design basis loads - a combination of deadweight, pressure and seismic
(reference Calculation 96-SDS-1556MY, Revision 1, dated 3/27/97).
The analyses were performed in accordance with the methods specified in Geric !
Letter 90-05, and ASME Section XI Code Case N-480, as appropriate. The !
licensee's calculations predicting inoperability were conservative due to the use of
worst case moments when evaluating the loads in the piping system. This
assumption was necessary because the licensee does not have detailed pipe 1
stresses at all points in the SW system, but does have moments at certain points in
the system from the design basis calculation of record (Stone and Webster Letter
dated May 23,1966, and NUS Corporation Report TR-76-27 dated January 27,
1977). The inspector independently evaluated the structuralintegrity of the SW i
piping using the licensee data and the GL 90-05 and ASME calculational methods to j
verify the licensee's conclusions. !
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The licensee implemented plans to replace the defective pipe section and to conduct
a repair in accordance with the ASME code (details are provided in Section M1.1).
An engineering evaluation was completed on March 26,1997 to assess whether :
the normal supply lines to the spent fuel cooling system could remain in service. l
The licensee concluded that continued use of the SW lines was justified until a j
bypass was piaced in service as the repairs began during the week of March 31. l
The engineering assessment considered the conservatism of the calculations; the l'
ruggedness and ductility of the piping, such that catastrophic failure was unlikely-
the heat up rate of the pool and the availability of alternate cooling supplies for the )
SFP heat exchangers; the location of the degraded sections such that the safety '
function would be performed if the further degradation occurred; and, the
consequences of flooding from postulated leakage in the SW li" should I
degradation occur. As part of the corrective actions, the licen. oegan a program
to examine more locations in the supply and return headers to identify the extent of
piping degradation. The licensee adopted the approach of Generic Letter 90-05,
which required that pipe exams be extended to 5 similar locations. The sample
expansions would continue until no further unacceptable defects were found. No
inadequacies were identified in the engineering evaluation, or in the initial plan to
examine more SW piping. NRC inspector input was required to assure the
e. appropriate second expansion sample was selected, due in part to the failure to fully
integrate the technical support from the site and design engineering groups.
Past NRC inspections reviewed licensee actions to disposition degraded conditions '
in a timely manner (reference lospection 94-05, 94-07, 94-14 and item 96-06-05).
As a result of the decision to permanently shutdown the plant, the licensee
identified that all areas of the service water system was considered to be at risk to
MIC degradation. This included all main supply header piping, all branch 1
connections, the emergency diesel generator supply and return piping, and the i
spent fuel pool cooling supply and return piping. The licensee's program for MlC
prevention continued to use Bulaab 8007 to combat potential MIC. However,
Bulaab injection was terminated af ter the initial startup of the system in mid-1996
due to mechanical difficulties and problems with the injection skid. Following the
preoperational test phase of the new system, the licensee had discontinued Bulaab
injection and had not resumed the syste.m operation as of March 1997. This was
caused in part by uncertainties (and erroneous assumptions) regarding the status of
the SW system following the decision to decommission the plant. The licensee has
since recognized the need to continue Bulaab injection as a M!C mitigation measure
for as long as the SW system has a safety function in the plant design and licensing
basis. Licensee actions were in progress at the end of the inspection period to
commence Bulaab treatment.
The short term actions included repair of known SW corrosion defects and
examinations of the SW system to evaluate the overall status of the piping.
However, the licensee recognized the need to provide an alternative to SW for long
term cooling of the spent fuel pool. The licensee had developed plans as part of the
Decommissioning project to create a " nuclear island" around the spent fuel pool,
which would eliminate the reliance on the SW system. The licensee decided this
period to accelerate the development of the nuclear island that would allow the
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partialimplementation by the end of 1997 of the mechanical portion of the alternate !
SFP cooling system. The licensee briefed the inspector on the conceptual design.
The new system included the use of an intermediate cooling loop that used
demineralized water and which would tie into the SW side of the SFP heat ,
exchangers. The intermediate cooling loop would include the e7 of spray coolere,
which would be supplied make up water from an another new ' stem. Neitho of
the new systems would be susceptible to MIC corrosion.
The licensee addressed these issues and his plans to address them in ietters to the
NRC dated March 31, and April 2,1997. Licensee activities were in progress at the
conclusion of the inspection to complete the actions described above. This item is ;
open pending further NRC review of the licensee actions to assure adequate
systems for the spent fuel pool cooling. Specifically, the item is open pending (l)
further NRC review of licensee implementation of the program to prevent and
mitigate MIC corrosion in the SW service water system; (ii) the completion of s
licensee actions address degraded welds and piping; (ii) the completion of licensee '
actions and evaluations to assure that the existing SW system will remain
acceptable source for SFP cooling for as long as the SW system is needed to 1
provide that function; and (iv) the completion of license long term actions to install
; an alternative cooling system for the SFP (URI 97-01-08).
E1,3 _Qonclusions for Conduct of Enaineerina
Mixed performance was noted in the engineering support of operations. Engineering i
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performance was good in response to emergent design basis issues and corrosion
degradation in the SW system. Engineering evaluations were good to identify the
inoperabilities in the SW piping, to assess the acceptability of interim use of the
degraded system, and to support the corrective actions to address the design and
material discrepancy issues. Engineering support for design changes was good to
provide timely corrective actions to mitigate the design and corrosion induced )
problems. Exceptions to good performance were noted in the failure to fully
integrate site and corporate engineering support, and to assure continued chemical
(Bulaab) treatment of the service water system during shutdown conditions. Poor
performance was noted in the f ailures to track design issues to completion
(waterhammer), to properly classify design issues (two phase flow) for the !
shutdown condition of the plant, and to track commitments to the NRC. These j
issues appear as additional weaknesses in the corrective action process to assure j
that conditions adverse to quality are promptly addressed to preclude recurrence. !
E3 Engineering Documentation - Design Basis Discrepancies (40500)
Severalissues were identified during the period which appeared as additional
examples of problems in defining or implementing the plant design basis, in meeting
licensing commitments, and in completing effective corrective actions. The
examples are summarized below.
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E3.1 _H_gndlina Loads Over Stored Fuel
On February 19, the licensee notified the NRC per 10 CFR 50.72 (b)(1)(ii)(B) of a
condition constituting plant operation outside the design basis. The condition also
was a past violation of Technical Specification (TS) 3.9.7. TS 3.9.7 was
implemented in 1989 and states that loads in excess of 1650 pounds shall be
prohibited from travel over fuel assemblies in the storage pool. The limit was
chosen to ensure plant practices were consistent with assumptions used in the
accident analyses. The TS bases states that the restriction of loads in excess of the
nominal weight of a fuel and control assembly and associated handling tool ensures
that, in the event the load is dropped, (i) the radioactivity released will be limited to
that contained in a single fuel assembly, and (ii) any possible fuel distortion will not
result in a critical array. The weight of 1650 pounds was considered to be the
nominal weight of the fuel, control rod and handling tool combination. During
reviews on February 4,1997 (ACR 97-56), the licensee discovered there was no
documented basis nor calculation justifying the load limit of 1650 pounds.
The nominal weights of fuel and associated components varied for different fuel
cycles. The nominal combined weights for the components used between 1989
c and 1994 was 1690 pounds [? 187 pounds (fuel assembly) + 153 pounds (control ,
;
rod) + 350 pounds (handling tool)]. From 1994 to 1996, the nominal weight was
'
approximately 1725 pounds [1250 pounds (fuel assembly) + 175 pounds (control 1
rod) + 300 pounds (handling tool)]. The licensee was in conformance with the
design basis when the load drop analysis was revised in 19S iur loads up to 2300 ,
- pounds (vendor report HI 941225). However, the, TS limit was not revised and !
remained at 1650 pounds. !
1
- The licensee identified this matter during reviews in response to an NRC request for
information contained in a letter dated January 9,1997. The licensee responded to l
the NRC in a letter dated February 19,1997 (B16185), and committed to assess i
the need for a TS revision to remove any ambiguity. The licensee stated that no
fuel would be moved in the spent fuel pool until this issue was resolved. The
completion of licensee actions to assure the movement of any load over in the spent
fuel pool is in conformance with the limits in TS 3.9.7 is considered an open item,
and is Part A of unresolved item 97-01-08.
E;L2 Control Room Habitability
1
On February 7,1997, the licensee notified the NRC per 10 CFR 50.72 (b)(2)(iii)(D)
of a conditica that could have prevented the fulfillment of a safety function of
systems needed to mitigate the consequences of an accident, in particular, to meet
the NRC requirements for TMI Action Plan item til.D.3.4, the licensee credited the l
use of self contained breathing apparatus to protect the operators in the control <
room as actions were taken to mitigate poctulated design basis accidents. The
assessments of control room habitability did not use formal calculations subject to
quality assurance checks, and was lacking in that an important input assumption,
the amount of control room inteakage, was not verified. The licensee concluded
that this condition was a violation of 10 CFR 50 Appendix B, Design Control, and
, 4
47
was also reportable per 10 CFR 50.73 (a)(2)(v). The licensee planned to submit a
licensee event report to document this issue and describe the followup actions
needed to resolve the discrepancy. The potential radioactive source terms from the
postulated design basis accidents for an operating plant were no longer a concern
for a permanently shutdown reactor. The licensee has yet to complete the accident
analyses for the decommissioning phase, and intends to address the future design
requirements for control room habitability when that work is complete. NRC
concerns for this area are already tracked by inspection item 96-02-03.
fyL2 Missed Commitments
By letter dated January 6,1997 (B16047), the licensee notified the NRC of
commitments that had not been met. In a previous response to a Notice of
Violation dated August 21,1996 (reference inspection 96-04), the licensee
committed to take several actions to correct a violation and a deviation from NRC .
requirernents, and to take actions to avoid recurrence. The violation concerned an
inadequate safety evaluation for moving fuelin the spent fuel pool (VIO 96-04-03),
and the deviation involved a lifting device that had not been inspected per the heavy
loads program (DEV 96-04-02). During this inspection, the inspector reviewed the
L following completed actions to assure all commitments were met:
(i) UFSAR change request 06-CY-28 was completed on December 19,1996 to
state in Section 15.5.2.2 that a minimum of 7 feet of water submergence
will be maintained for spent fuel in transit in the spent fuel pool. The change
request will be included in the 1997 UFSAR update submittal.
(ii) The Reactor Engineering Manager completed a review of the safety
evaluation to justify use of a sling with the spent fuel handling tool. The
review was completed on November 8,1996, and identified the weaknesses
in the original evaluation that caused the violation.
(iii) The licensee revised the training guides for crane operators (OJT Guides MM-
510-025, MM-510-024 and MM-510-014) to require the verification that
workors are physically qualified to the requirements of standard ANSI B30.2.
The guides were updated by November 9,1996.
(iv) Work control procedure WCM 2.2-7 was revised in Step 1.4.3 to delete
reference to a speciallifting rig, and to refer to rigging equipment when
lifting the floor blocks in the primary auxiliary building. The procedure was
rcvised on October 22,1996, and,
(v) The licensee completed a review of other commitments to assure no others
had been missed. The review was described in memorandum NL\CY 97-08
dated January 27,1997, which also identified the reasons why the
commitments made in the August 1996 submittal were missed along with
actions to assure future commitments would be met. The licensee attributed
the past failures to new personnel assigned to the Nuclear Licensing
. .
48
department, who were inadequately trained on the process for tracking
commitments and assuring assignments were completed in a timely manner.
Further NRC review of other licensee actions in response to inspection 96-04 is
described in Section E8.4 of this report. Except as summarized below, the
inspector ha o further comments at this time on the actions by the licensee to
address the vution identified in Inspection 96-04.
E14 Service Water Desian Basis issues
Inspection item 96-01-02 was open due to the identification of a number of
discrepancies between the plant licensing and design bases, and the plant operating
procedures and practices. One example of the concern was the licensee's
discovery in February 1996 that the plant was operating outside the design basis
due to river water temperatures that were colder than assumed in the design basis
and as listed in the Updated Final Safety Analysis Report (UFSAR). Inspection 96-
01 describes the licensee actions to address the technical concerns associated with
this matter (Section 4.2). The issue was reported to the NRC on 2/7/96 per 10 CFR
50,72 (b)(1)(ii)(B) and as licensee event report (LER) 96-02 as operation outside the
-
design basis. Corrective actions at that time included the completion of an
engineering evaluation to show that plant operation with temperatures as low as 28
degrees was acceotable. Planned corrective action included revising the licencing
and design basis to reflect the new lower temperature limit.
On January 8,1997, the licensee identified additional discrepancies between the
licensing basis and operating practices, as described in adverse condition report
ACR 97-22. The licensee noted that the river water temperature was 34.6 degrees
F, which was less that the design basis temperature of 35 degrees F. The licensee
determined that, contrary to the intentions following the February 1996 temperature
discrepancy, no action had been taken to update the UFSAR or to revise the design
basis regarding the lower limit for SW temperatures. Thus, the SW system
licensing and design basis remained 35 degrees F. The licensee completed a
reportability evaluation for this matter (ACR 97-26) and determined on January 14,
1997 that the issue was reportable per 10 CFR 60.72 (b)(1)(ii)(B) as operation
outside the design basis. LER 97-01 was submitted to the NRC on February 11,
1997. This LDB discrepancy was caused by the failure to complete the previous
corrective actions to revise the design basis calculations and to update the UFSAR.
The licensee had intended to revise the lower SW temperature Smit as part of the
UFSAR revision planned in 1996, which was not completed. As further corrective
actions, the licensee planned to develop a new tracking system to identify this type
of commitment to ensure they would be completed. The licensee initiated a review
of the remaining backlog of proposed UFSAR changes to assure there are no other
similar discrepancies. As part of the configuration management plan, the licensee
plans to formally identify and correct UFSAR inaccuracies. During its review of this
issue, the licensee identified an additional programmatic deficiency in the treatment
of the licensing basis,in that the update to the plant licensing basis was taken to
coincide with the annual revisions of the UFSAR made in accordance with 10 CFR
50.71(e). The licensing basis needs to be a "living document" that is revised and
.
49
made accurate on an ongoing basis to assure the adequacy of safety evaluations
completed per 10 CFR 50.59. This would require a system to maintain a site
working copy of the licensing basis, inclusive of the UFSAR, which could be revised
as design changes and safety evaluations were completed. The UFSAR update filed
with the NRC could then be completed after the fact per 10 CFR 50.71(e).
A second licensing design basis (LDB) discrepancy described in ACR 97-22
concerned the process to chlorinate the service water. While reviewing practices
for freeze protection of systems at the intake structure, plant operators noted that
the injection of sodium hypochlorite had been suspended due to the plant
operational status with no circulating water pumps in operation. This was contrary
to UFSAR Section 9.2.1.1 which states that the service water system is
continuously injected with sodium -hypochlorite at the pump suction. At the time of
discovery in January 1997, only one of 4 service water pumps was required to be
in operation to support the cooling of plant equipment with the reactor in the
defueled condition. Further, all four circulating water pumps were secured and ;
were not required to operate in the shutdown condition (a circulating water pump ;
was started occasionally as needed to provide dilution water for liquid discharges).
Further, as a condition of the plant Nuclear Pollution Discharge Elimination System
t (NPDES) permit, the hypochlorite must be isolated with no circulating water pump.s .
in operation. Licensee engineering concluded in an operability evaluation dated I
January 14,1997 (CY-TS-0011) that the function of the service water system was
not impaired because the intention was to chlorinate the SW system when the
potential for macro and micro fouling existed, and the potential for this corrosion
mechanism was low with cold river temperatures. The licensee addressed this area
in a temporary procedure change (TPC 97-10) to NOP 2.20-4 which clarified that
chlorination of the SW system is not required when river water temperatures are
below 35 degrees F, and to assure that chlorination is not aligned for injection when
intake freeze protection is provided by a slip stream from the SW pumps (which
assured compliance with the NPDES requirements). The inspector observed
operator actions to comply with the revised procedure instructions as river
temperature varied around 35 degrees, and identified no inadequacies.
This item is unresolved pending the completion of licensee actions to (l) develop a
process to provide a site working copy of the licensing basis that is updated
continually to assure the adequate completion evaluations per 10 CFR 50.59; (ii)
complete a review of the backlog of proposed UFSAR changes for similar operability
concerns; and, (iii) complete the 1997 UFSAR revision to address the design basis
discrepancies discussed above (SW system normal operating temperature, SW
chlorination, and submergence of fuel on the spent fuel handling tool). This item is
unresolved pending the completion of the above items, and subsequent review by
the NRC. This is Part B of unresolved item 97-01-08.
IL3
2 5 Service Water System Water Hammer
This issue, discussed in Section E1.1 above, concerns the discovery in March 1997
of an original design deficiency in the SW supply and return lines to the SFP cooling
system. Licensee engineering evaluations found that two phase flow in the SW
_.
.
-
50
piping could result in water hammer and excessive piping and support loads in the
- event of a loss of normal power. The issue was reported to the NRC per 10 CFR ,
50.72(b)(2)(i) on March 11 as plant operation in a degraded and unanalyzed '
condition. ;
The issue was another example of inadequate past engineering evaluation of plant ;
systems and performance, which failed to assure the plant could operate )
< satisfactorily for events considered in the design and licensing basis. The
development and progress of this issue within the licensee's organization in the
August 1996 to March 1997 time period also showed weaknesses in the processes i
'
to classify, track and correct conditions adverse to quality.
E3.6 Inocerable Effluent Monitor - Stack Noble Gas
NRC and licensee QAS review of stack low range noble gas monitor, radiation !
monitor channel RM-14A, questioned the adequacy of the sample' probe geometry i
,
(see Inspection 97 02, Section R2.1). The sample probe is located in a ventilation t
housing in the effluent pathway to the main stack. The sample probe consists of a
single fueled head monitored in the middle of the ventilation duct. Technical
e Specification 3.3.3.8 requires that the RM 14A be operable.at all times to provide
'
indication of gaseous effluents via the stack, and be capable of providing alarm and
autvisatic isolation of the waste gas effluents.
On April 4, the licensee issued ACR 97-110 to document the results of an
, engineering evaluation-which concluded that the sample probe was not
representative of the stack effluents, due to the potential for nonuniform mixing of
the effluent flow steam as it passes the probe. The licensee reported this !
,
- discrepancy to the NRC at 11:15 a.m. on April 4 per 10 CFR 50.72(b(1)(ii)(B) as an l
event or condition outside the design basis of the plant. The licensee initiated plans I
to route the sample probe from radiation monitor channel RM148, which uses an
isokinetic probe mounted in the main stack, to the input of channel RM14A. The
resolution of this and other RMS issues (see also Section R2.1) will be tracked as
followup to the NRC concerns identified in Inspection 97-02. 1
i
El Spent Fuel Buildina and Yard Crane Desian Basis issues
ACR 97-34 was issued on January 20,1997 based on the findings by the l
configuration management plan working group that the calculations for the spent j
fuel building and yard cranes do not support the conclusions that the cranes are
acceptable for handling design basis loads. Discrepancies were identified in
calculations CY 524990-178-GC, Revision 0, for the Yard Crane, and 94-NS-02-
1050 CY, Revision 0, for the Fuel Building Crane. The issues included: the
objectives stated in the safety evaluation for the calculation were not supported in
the body of c61culations; the adequacy cf modeling; the adequacy of the
acceptance criteria with the exclusion of safe shutdown earthquake loads, the
adequacy with which wind and tomado loads were addressed; the adequacy of the l
assumptions used to address critical connections; the adequacy of the analysis of
i
!
;
-
_ . ~ _ _ _ _ _ _.
.
.
51
members critical to the lateral strength of the structure; and, the adequacy of the ;
documentation for the calculations.
This matter is unresolved pending the completion of licensee actions to resolve the
issues identified in ACR 97-34, and subsequent review by the NRC. This is Part C ,
,
of unresolved item 97-01-08.
1
E33 Conclusions for Enaineerina Documentation (URI 97-01-09)
The design basis discrepancies discussed above were discovered either by good
licensee staff and QAS initiatives to identify and resolve discrepancies, or by the
Configuration Management Plan group as the reviews to reconstitute the plant
design and licensing basis are completed. Licensee immediate corrective actions in
response to the individual issues were appropriate. The existence of design and
licensing basis discrepancies was a concern previously addressed by the NRC in
past inspections and a pending enforcement action for inspections 96-06,96-08,
96-80 and 96-201. The identification of additional design basis issues is expected t
until the completion of the CMP plan for the shutdown and deconmissioned plant. ,
However, exceptions to good performance were noted in the failure to adequately )
--g address the design basis issue relative to SW temperature, which appears as an _ ;
example of a corrective action weakness.
The completion of licensee actions to address issue described above that are
important to plant safety during decommissioning will be reviewed in subsequent
. NRC inspections. Specifically, this item is open pending the completion of licensee
actions to resolve (i) the handling of loads over the SFP; (ii) service water system
design basis issues; and, (iii) the analytical issues for the spent fuel cranes (URI 97-
01-09).
E6 Engineering Organization and Administration
EQl Corrective Action Proaram Weaknesses
QAS Surveillances and Audits
Several findings by the QA audit and surveillance groups during the period
demonstrated good performance by the overs ~ight groups to identify deficiencies in .
plant operating activities. Some examples included the following deficiencies: l
, inadequacies in E-Plan remedial training (ACR 97-122); the failure to properly
control software in the radiological effluents program (ACR 97-32); adverse trends
in the reliability of the radiation monitoring system, which indicated the RMS was I
not meeting the design basis (ACR 97-73); SIP CY-P-97-008: the failure to l
implement the radwaste program in a manner to ensure compliance with 10 CFR 61
(ACR 97 76); the lack of an isokinetic probe for RMS-14A, and a design deficiency
in which the sample nozzle was not rated for all flow conditions (ACR 97-110); the
failure to adequately implement the radiological environmental monitoring program !
'
, (ACR 97-139) and, Audit A24057/A25119: the failure to perform the 1996 annual
update of the Fire Hazards Analysis as required by procedure NGP 2.14.
!
,
. .
52
Effectiveness of Corrective Actions
The failures to complete corrective actions, including the failure to complete
committed actions, were examples of ongoing weaknesses in the licensee's
program tc meet 10 CFR 50 Appendix B, Criterion XVI, which requires that the
licensee identify and correct conditions adverse to quality. The licensee has plans
to address this area and to improve performance as part of the actions taken and in
progress in response to inspections 96-06, 96-08, 96-80 and 96-201. The plan to
improve the corrective action program at Haddam Neck prior to decommissioning
the plant is described in Sections 12 and 19 of the Decommissioning Project
Manual. A dedicated manager has been assigned to administer the ACR program,
who is also responsible for enhancing the process. Actions in progress to improve
the corrective action program include developing: a new simpler ACR process to
assure problems are identified at a low significance level; a simpler action tracking
system to replace the existing system (action item trending and tracking system -
AITTS); new procedures to standardize the causal factors used to evaluate problems
to assure consistent evaluations of causes station wide; new procedures for
tracking and trending problems to assure programmatic and reoccurring causes are
easily recognized and effectively corrected; and, initiatives to develop and !
- promulgate management standards at the department level to ensure participation
and open communications at alllevels within the new organization. The actions to
improve the corrective action program at Haddam Neck is expected to be completed
during the second quarter of 1997.
Despite the progress in identifying deficiencies, the licensee had demonstrated
continued weaknesses in developing and implementing adequate corrective actions.
Some examples of the deficiencies in this area included: ACR 97-122: the failure to
develop implement and conduct remedial training to assure effective corrective
action in response to the August 1996 Emergency Plan Exercise (reference
'
Inspection 96-07); ACR 97-124: management failure to develop, implement and
monitor corrective action commitments made in response to the November 2,1996
contamination event in a manner that will prevent recurrence; ACR 97-31 the failure
to take or provide adequate documentation of corrective actions for problems
identified in Level D ACRs; ACR 97-59: issued on February 6,1997 due to the OAS
finding that due dates for ACR action items were being inappropriately extended;
and, ACR 97-134: the failure to investigate and take adequate corrective actions in
response to a previous deficiency with the auxiliary building filters (showed high
differential pressure - contributed to failures this period).
The licensee recognized the need to improve the tracking and trending of action
items placed into the corrective action system as a result of adverse conditions.
The licensee issued memorandum DCY 961004 on March 26,1997 to address
weaknesses in the process defined by ACP 1.2-16.5. The licensee issued guidance
that would improve the traceability of ACR assignments by issuing a single AR
number for a given ACR, and then making sub-ascignments as necessary for all
associated actions. The guidance also clarified the instructions on making
assignments and clarified the relationship between the ACR and the AR status (i.e.,
.. . -- . . . - . - - .-- . -- . .-
.
!
i
*
'
.
53
.
the ACR remained open until all evaluations are completed and tracked until all !
,
associated ARs are completed. >
'
Further examples of weaknesses in the corrective action program were noted during ;
this period as events occurred that were a repeat of past problems. The examples
included the deficiencies in the tracking and timely completion of surveillance i
activities (see Section M4.1); the recurrence of personnel performance areas in
,
broad areas of plant operations (see Section 01.8. 01.9, 06.1, M2.1, M3.1 and
i S1.4); the failure to preclude plant operation outside the design basis (river water
temperature); and, the failure to assure quality in operating and test procedures
(reference irs 96-80,96-11 and 97-02). Additional examples of weaknesses in
corrective action in the engineering area are described in Section E1.3 and E3.8.
Further examples were noted of repetitive pr recurrent deficient personnel and
!
program performance, such as: ACR 97-063: failure to verify completeness of
-
training program requiremer ts for the 1995-1996 licensed operator initial training
program and failure to assure complete and accurate information to the NRC on
Form 398.
Licensee actions to address these concerns will be tracked as part of the !
*- enforcement action for Inspections 96-06, 96-08, 96-80 and 96-201, and in *
, particular Inspection item 96-201-19. In summary, while the number of deficiencies ,
identified by licensee staff has generally increased under the ACR program, a large
- number of deficiencies were identified either by self disclosing events, by the
!
independent oversight groups (quality organization, NRC). The licensee has yet to
complete its initiatives to improve the corrective action program to assure
consistent quality root cause investigations and to implement effective corrective
+
actions.
!
E8 Miscellaneous Engineering lasues (92902)
EHd Soent Fuel Pool Desion to Suocort Full Core Off-load
Y
a. Inspection Scoce
'
in response to a finding at another facility that " full core off-loads" had been
performed when prohibited by the licensing basis (UFSAR), the regions were
instructed to review all facilities for similar problems,
b. Observations and Findinos
By letters dated August 21 and December 19,1975 (as supplemented by three
other letters), the licensee provided a preliminary design concept and an application
for a license amendment to increase spent fuel pool (SFP) storage capacity from
366 to 1172, respectively. These letters show the licensee's intent to always
provide for full core off-load. Amendment 7, authorizing this change, was issued
June 8,1976.' The original FSAR stated that the SFP cooling system was capable
of removing the residual heat produced by one and one-third cores while
, _ -. _ _ _
- _ _ - _. _ _ _ - -
l l
1
l i 54
maintaining the pool water temperature below 170 F. No specifics of the heat
balance were provided. ]
The question of SFP cooling and storage was addressed during NRC inspection 50- l
213/77-02, when an unresolved issue was identified. The licensee was increasing ,
SFP cooling and storage capacities in accordance with Amendment 7, however, the j
new fuel racks would be installed before the additional SFP heat exchanger and a j
second pump were scheduled to be installed. During inspection 50-213/77-11, the ,
'
unresolved issue was closed bases on limiting the SFP storage capacity to the
original 336 spent fuel assemblies until the parallel heat exchanger and pump were l
operable.
l
By application dated March 31,1995, as supplemented by letter of November 14,
1995, the licensee again requested an amendment to increase the SFP storage
capacity to 1480 fuel assemblies. This was to allow full core off-load through the ;
end of the operating license,2007. The heat balance for this change was for a ]
river inlet of 90 F, a SFP maximum of 150 F, and a heat load of 22.4E6 Btu /hr. The j
request was approved (with special agreed upon surveillance, analysis, and !
restrictions) by Amendment No.188, issued January 22,1996. This amendment l
also added a new LCO which requires that a delay of fuel movement to the SFP
'
"
was dependent upon the river water temperature. The current UFSAR continues to l
allow full core off-loads.
c. Conclusions
1
The inspector concluded that the Haddam Neck license including the TS and the
UFSAR have never prohibited full core off-loads. The issue of cooling system ;
design for full core off-loads was also addressed in IR 50-213/95-20, Section 4.3.- !
This issue remains resolved.
E82 (Closed) IFl 94-09-03. HPSI Relief Valve Setooint Drift
During inspection 50-213/94-09, the root cause for the premature lifting of the high
pressure safety injection (HPSI) system discharge relief valve had not been
determined although CYAPCO assessment of the short-term operability was
appropriate. During inspection 50-213/95-19, CYAPCO implemented short-term
actions to replace the valve spring and process a set-point change request to allow ;
a revised setpoint. In discussions with the valve vendor, the issue of horizontal
mounting the valve providing uneven seat loading was identified and the licensee
initiated plans to reorient the relief valve. Due to the December 5,1996
notification to permanently cease operation of the Haddam Neck facility pursuant to
10 CFR 50.82(a)(1)(l), the HPSI discharge relief valves are no longer of safety
importance. This issue is considered closed.
,
f
W
__
55
MJ (Closed) VIO 96-04-03. Inadeauate Safety Evaluation j
During the review of fuel handling activities documented in IR 50-213/96-04, two i
cases were identified where no written or inadequately written safety evaluations
existed. First, for refueling activities conduct prior to May 1,1996, the fuel
handling tools providing less than 8 feet of fuel submergence contrary to the design
documents, and a defacto change to the facility as described in UFSAR Section
15.5.2.2 and 9.1.4.2. Second, a modification.made to the fuel handling tool for the
North Spent Fuel Building crane on May 2, adding a sling to increase the length of
the hoist-tool configuration by one foot, was made with an inadequate safety
evaluation. The SE did not address the effect of the change on the normal
operation of the fuel handling equipment for the safe handling and storage of spent
fuel. The modified fuel handling tool, in part, caused an irradiated fuel assembly
suspended from the spent fuel building hoist to be incapable of safe storage for 25
'
hours.
in the August 21,1996 response to these violations, CYAPCO stated that an
approved safety evaluation and a change to the UFSAR to make the licensing basis
documents consktent at 7 feet minimum submergence was made. In addition, a
,- comprehensive review of the safety evaluation prepared to initiate the fuel transfer
evo;ution was performed. The inspector reviewed the Safety Evaluation, dated
August 13,1996, the UFSAR proposed update, and an internal Memo, Minimum i
We.ter Depth for Fuel Movement at Haddam Neck, dated May 28,1996. This !
review indicated that appropriate corrective actions were taken. This issue is ;
consiclered closed.
@4 (Closed) Ifl 96-04-04. Heavv Load Controls
During inspection 96-04, the inspector questioned why the mor.cra!? above the
emergency diesel generators (EDG) did not have specific procedural heavy load
program controls. The licensee said that controls would be during trouble report job
scoping and informal involvement of the system engineer when questions are raised
by the workers. The licensee believes tnat most heavy load lifts for the diesel
generator occur during outages when the equipment is considered inoperable. The
issue was left open for review after licensee corrective actions were completed.
The licensee modified Work Control Manual (WCM) 2.2-8, Control of Heavy Loads,
Revision 4, effective October 22,1996 to include a constraint that no loads will be
lifted with the monorails over the EDG unless they are out of service. The inspector
found the procedure change acceptable and, therefore, this inspector followup item
is closed.
BJ (Undate) URI 96-06-06. Batterv Oscillations and Ground
During inspection 50-213/96-06, an issue related to ongoing current oscillations and
noise problem existing in the dc battery charger "A" and in the de system ra.ses
potential for a long term impact on the battery. This highlighted the need for
monitoring the battery conditions until the battery is replaced and these issues are
_ _ _ _ ._.. _ _ _ _ _ _ __
.
!
~
56
satisfactorily resolved. This issue was left unresolved pending the licensee's -
satisfactory resolution of these issues and further review by the NRC. The licensee
i stated that they expect to have the response completed by May 20,1997. This
issue remains unresolved until then .
~
ERJ (Closed) URI 96-201-12. Analysis Sucoort,inLPSI Pumo Shutdown
During inspection 50-213/96-201, the team reviewed UFSAR Chapter 15.3.1.3
regarding accident sequence timo lines, as well as the licensee's integrated safety
evaluations (ISE)/CY-93-005, dated June 28,1993, regarding changes to the CAR
fan logic and CY-95-013, dated March 15,1995, regarding stopping of the LPSI
pump (s). The team found that the licensee's technical basis for securing LPSI t
pump (s) in certain EOP scenarios did not comprehensively address the broad
spectrum of design-basis LOCA break sizes, as well as credible single 4ailure 1
scenarios as required by 10 CFR 50.4'5 and Appendix K. This issue was left !
unresolved pending additional NRC review of the alytical bases for the
. interruption of ECCS flow during transition to sump recirculation. Due to the ,
decision to permanently cease operation of the Haddam Neck facility, the CAR fan
logic and stopping of the LPSI pump issues are no longer important to the safety of i
;- the shutdown, defueled, and later decommissioned reactor. These issues are- ,
i
considered closed.
ERJ. (Closed) URI 96-201-31. RWST Instrument Calibrations
- During inspection 50-213/96-201, the team found that reactor water storage tank
(RWST) Level Instrumentation Surveillance Procedures SUR 5.2.10, RWST Analog
Channel Operational Test, (Revision 12), and SUR 5.2.68, RWST Level Calibration,
s (Revision 11), did not correlate the transmitter output for the calibration points, or
the actuation of alarm trip and reset points, to tank water volume on the basis of
the physical configuration of the installation. In addition, the team found that there
was no basis to correlate the actual height of water above the instrument elevation >
(hydrostatic head) to the level accuracy measurement indicated in SUR 5.2.10. In
response to the team concerns in this area, the licensee stated that a calculation '
was not available which directly provided the basis for the RWST level alarm
setpoints and the calibration procedures. Lack of a design calculation for the RWST
level alarm setpoints and indication is contrary to the guidelines presented in
procedure SP-EE-320, " Guidelines for Calculating Instrumentation Setpoints for
Safety Systems," Revision 1, dated May 23,1994; Americt n National Standards
Institute (ANSI)/ISA-S67.04-1988, "Setpoints for Nuclear Safety-Related
Instrumentation," and RG 1.105, " Instrument Setpoints for Safety-Related System,"
Revision 2, dated February 1986, which are referer>ced by procedure SP-EE-320.
This issue remained unresolved pending completion of NRC review of the licensee
actions to ensure all calculation factors are properly considered in the RWST level
instrumentation calibration procedure. The licensee placed SUR 5.210 and SUR
5.2-68 in the "Do Not Use" category on December 13,1996. Due to the decision
to permanently cease operation of the Haddam Neck facility, the reaci.or water
storage tank levelissues are no longer important to the safety function of the
_ _. ______ _ _ _ - _ _ _ _ _ _ _
. .
57
shutdown, defueled, and later decommissioned reactor status. These issues are
considered closed.
fjLQ IOpen) URI 96-02-03. Control Room Habitability
This item was last reviewed in inspection 96-11 and was open pending NRC review
of licensee actions to assure the control room environment remained acceptable for
the operators followirig design basis events. The radioactive source terms from
postulated design basis accidents for an operating plant were no longer a concern
for a permanently shutdown reactor. Licensee reviews were in progress during this
inspection as part of the configuration management plan (CMP) to recreate the plant
design basis. The licensee intends to complete the accident analyses for the
decommissioning phase, and intends to address the future design requirements for
control room habitability when that work is complete. The CMP group will also
review the commitments made under the integrated safety assessment program
(ISAP) to determine which items need to be maintained for decommissioning in
general, and control room habitability in particular. This item remains open pending
the completion the licensee actions under the CMP to disposition control room
habitability issues, and the subsequent review by the NRC.
(Closed) URI 96-08-12: Containment Isolation Valves
This issue concerned the circuits that controlled certain valves in the letdown and ,
the feedwater systems in response to a signal to isolate the primary containment. I
Due to the licensee's decision to cease plant operations and place the reactor in a
permanently defueled condition, the containment isolation function for the valves is
no longer required. The licensee plans no further action to address this issue
(memorandum CY-TS-97-114). This item is closed.
(Closed) URI 96-06-0_5: Timelv Evaluation of MIC Corrosion
This item was open, in part, pending further reviews of licensee actions to
disposition degraded conditions in a timely manner. The licensee addressed this
concern in a revision to procedure ENG 1.7-131, CY Microbiologically influenced
Corrosion (MIC) Prevention, Monitoring and Mitigation Program, Revision 3.
Specifically, in Step 6.1.1.g, the licensee required that, following piping
examinations for MIC corrosion, any reports of nonconforming conditions would be
immediately forwarded to design engineering for a preliminary operability evaluation
(to be completed within 72 hours), with a final disposition within 14 days. The
inspector noted that nonconforming conditions (pitting defects) identified during
examinations of service water piping for MIC corrosion in March 1997 were
promptly reviewed by design engineering for operability.
Section E1.2 describes additional SW system degradation caused by further
corrosion. Item 97-01-08 will track further NRC review of the licensee's program to
prevent and mitigate MIC corrosion in the service water system. This item is
closed.
,
_ _ _ . _ _ _ _. _ . _ ._. , . _ _ _ _ _ _ . _ ___ _ . _ _ _ _ _ . _. _
.
.
.
,
:
L
j- "
58 J
l
7 LER 97-01: River Tamoerature Below UFSAR Limit l
!
'This LER concerned the recurrence of the a'dverse condition in which the plant !
i operated outside the UFSAR design basis for minimum service water temperature. ;
>
- - This matter was also reported in LER 96-02. This matter is described in Section
. 4 E3.4 of this report. This LER is closed. j
- . J
LER 9617: Main Stack Samole Performed Late 1
4 ;
This LER concerned the untimely collection (27 minutes late) of a main stack sample l
following the plant shutdown on July 22,1996. This event was contrary to ,
2
Technical Specification 4.11.2.1.3, which requires that stack samples taken within -
- 8 hours following a plant shutdown. The licensee determined the event was caused l
by a programmatic failure when an excessive number of unprioritized sample j
}! requests contributed to the chemist's failure to take the sample as required. The 4
~I
sample taken at 3:10 a.m. on July 23 showed that no elevated releases were in
. progress. Corrective actions to preclude recurrence included a review and revision .E
of procedures CHM 7.6-32 and CHDP 6.1-4 to improve the guidance for stack ,
sampling, eliminate unnecessary samples during transients, and providing a "
a -m . prioritized checklist for collecting sample; The safety significance for this event was t-- , .i
- : low. However, the event was an example of an NRC concern in the timely . !
"
completion of required surveillances. Past similar events were reported in LERs 94- ,
,
23 and 91-27. NRC concerns for the proper completion of surveillances are '
.
discussed in Section M4.1 above. This LER is closed.
LER 97-02: Reactor Coolant Samole Not Taken
' This LER concerned the failure to collect and analyze reactor coolant system (RCS) . ;
samples for chlorides and fluorides since November 15,1996. Chemistry personnel
stopped the chemistry analyses at that time because it was believed it was no
longer required with the plant in a~defueled condition. The deficiency was identified 1
on February 6,1997; the licensee reinstituted RCS sampling at that time. This !
event was contrary to Technical Specification 4.4.7, which requires that RCS
samples taken every 72 hours, with a mode of applicability of "at all times."
t
The licensee reviewed past practices and determined that RCS chemistry sampling
had also been suspended during past period when the reactor was defueled. The ;
licensee determined the event was caused by the incorrect interpretation of the I
technical specification requirements. The samples taken on February 6 and r
thereafter showed that the TS limits for chlorides and fluorides were met. >
Corrective actions to preclude recurrence included counseling technicians on the
proper interpretation of the TSs, and reviewing all other surveillance requirements to
'
assure no other surveillances were inappropriately stopped. No others were I
identified.
The safety significance for this event was low since the limits chemistry limits
established by TS 4.4.7 were established to protect the reactor vessel against
,. degradation due to chloride stress corrosion cracking with the reactor operating at ;
,
h
.
-
-
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.
-
59
1
normal operating temperatures and pressures. Following the decision to cease plant
'
operations and permanently defuel the reactor, the RCS will no longer be operated
at 550 degrees F and 2000 psig. However, the event was an example of an NRC
concern in the timely completion of required surveillances. Past similar events wers
reported in LERs 94-23,9617 and 96-22. NRC concerns for the proper completion
of surveillances are discussed in Section M4.1 above. This LER is closed.
IV. PLANT SUPPORT
R1 Radiological Protection and Chemistry (RP&C) Controls
BL1 External and Internal Exoosure Controls
a. Insoection Scope (83750)
:
The inspector toured the radiological controls area and reviewed radiological
controls including posting, barricading, and access control, as appropriate, to
radiation and high radiation areas and contaminated areas. The inspector also
reviewed radioactive contamination controls, in addition, the inspector selectively
l
0 reviewed planned radiologicai controls for diving operations within the spent fuel
l
transfer canal.
b. Observations and Findinas
As a result of the November 2,1996, fuel transfer canal airborne radioactivity event
(see NRC Inspection Report 50-213/96-12, dated December 19,1996), the licensee
suspended all radioactive work that could si0nificantly challenge the radiological
controls program pending completion of appropriate corrective actions. The
licensee was implementing the corrective actions outlined in its December 9,1996,
' letter provided to the NRC. The principal corrective action was the required review '
of any significant radiological work by the acting RPM and the work services
director. A significant amount of planned program upgrades remain to be
completed. A number of significant program upgrades were tentatively scheduled
for completion on or about the end of February 1997 (see Section R8.1 of this
report for a discussion of corrective actions).
4
Access to the radiological controlled area continued to be controlled through the use
of general and specific radiation work permits. Personnel signed in on the permits
electronically and obtained an electronic dosimeter. As part of the corrective
actions, all radiation work permits were required to be reviewed and approved by
either the radiation protection manager or the radiation protection supervisor. The
inspector identified no on-going radiological work activities. Radiation and high
radiation areas were selectively reviewed and noted to be properly posted and
controlled. Contaminated areas were properly identified with some minor
exceptions that were brought to the licensee's attention. The licensee appeared to
be providing adequate planning and preparation for diving operations. At the tune
of the inspection, diving operations, to complete securing of the blank flange in the
fuel transfer canal was on hold due to licensee questions on work procedures.
~ - - .- . - .-- - - - - - - - - . . ..- -- .- . . . .
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$ ' :
4
60
Regarding radiological control of work activities, the inspector discussed the
following observations with licensee representatives: 4
- The licensee's work control memorandum dated December 12,1996, did not
l
specifically address work activities in potential high risk alpha areas not
,
necessarily located in high radiation areas. In response, the licensee -
indicated that all work activities would be reviewed for radiological controls
concerns and all work with potential radiological concerns (e.g., primary :
F system piping work, sump work), would be handled in accordance with !
~
controls outlined in the memorandum. ,
,
- The inspector questioned the level and consistency of radiological oversight
of work performed as minor maintenance since minor maintenance work may
not necessarily be fermally scheduled via the licensee's weekly work ,
planning program, in response, the licensee indicsted that the radiological {
conditions for minor maintenance work would be reviewed and the work
would be formally scheduled and planned if it was deemed to be high risk i
[ work. On January 16,1997, the radiation protection supervisor issued j
guidance regarding prohibition of performance of minor maintenance based 1
'
-
on radiological conditions, j
l
,
The following additional observations were brought to the licensee's attention: I
- ,- The' licensee designated outdoor yard areas as portions of the radiological
- controlled area (RCA). Personnel egress main plant buildings (e.g., auxiliary
j building) to access the outdoor areas. The licensee did not require personnel
to frisk for contamination prior to exiting the plant buildings. This was
"
considered a program weakness in that personnel may inadvertently track -
contamination outdoors from the main plant buildings. In addition, the
> inspector noted that as the station entered an active decommissioning phase, c the likelihood of inadvertent tracking of contamination outdoors would
increase. The licensee indicated background radiation levels precluded
installation of friskers. Further, the licensee indicated radiological ;
characterization surveys in the outdoor RCA areas,in support of !
'
decommissioning activities, were to be performed and that the chemistry
group performs sampling of storm drains within the yard areas for
radioactivity. The licensee initiated a review of this matter.
-
The inspector identified one individual who appeared to be exiting an j
alarming portal monitor at the protected area egress point. The individual '
was called back and re-monitored with no contamination identified.
Subsequent inspector review identified that the personnel contamination !
monitors at the protected area egress were subject to periodic false alarms
due to electrical shorting conditions. The monitors were located next to
doors which allowed rain and snow to be blown in or be tracked to the
~
:
monitors. Although security personnel would reset the monitors and require {
personnel to re enter the monitors, the inspector questioned the adequacy i
and effectiveness of the monitors. Further, at the time of the inspection,
e i
i
, ')
4
.%.. , 5 _._, .- - _ ,__ _ _ _ _ . . . _ _ _ _
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61
personnel appeared to tolerate the false alarms and no action had been taken
to initiate repair actions or take the affected monitor out-of-service. T%
licensee subsequently took the affected monitor out-of-service and provided
guidance to security personnel as to when appropriate personnel should be
,
notified to initiate repairs.
4
- Personnel who had received medicalisotopes for diagnostic or treatment
purposes were permitted to exit the protected area and alarm the portal
monitors without a secondary check by radiation protection personnel. The -
inspector noted that although security personnel maintained a list of such :
personnel and reset the monitors once the person alarmed it, no secondary i
check, by radiation protection personnel, was performed to ensure
radioactivity, attributable to licensee operations, was not inadvertently or
purposely removed from the station. The licensee indicated this matter
would be reviewed.
'
- As discussed below, the licensee was performing a feasibility study relative l
to decontamination of primary systems piping and components to support
xposure reduction during decommissioning. The inspector noted that the ;
'
-
ystem decontamination may change normal radionuclide - ,
, :oncentrations/ ratios within systems and/or the radiological controlled area. !
,
Consequently, the change may require revisions to instrument calibration i
orograms, radiological survey programs, the 10 CFR Part 61 waste stream j
enalysis, and the bioassay programs among others. The licensee indicated {
:at these areas will be reviewed.
c. Conclusions
Work restrictions were implemented in accordance with licensee commitments to
the NRC. The radiological controls program was not challenged due to a conscious
4
decision to suspend all unnecessary significant radiological work. Personnel
contamination controls for egress of station buildings to outdoor radiological
controlled areas was considered weak. There was a need to review various
radiological controls programs in anticipation of potential changes in the
composition of radioactive contamination following chemical decontamination.
R1,2 ALARA Proaram
a. Insoection Scope (83750) l
The inspector selectively reviewed the program to maintain occupational radiation ,
exposure to as-low-as-is-reasonably-achievable (ALARA). In particular, the l
inspector reviewed the licensee's evaluations relative to performance of pnmary j
'
system decontamination in order to reduce personnel radiation exposures to
ALARA. The inspector also reviewed the licensee's ALARA program relative to
support of decommissioning activities. l
l
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_
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.
>
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62
b. Observations and Findinas
At the time of the inspection, the licensee was evaluating the decontamination of
the primary system to reduce radiation dose rates on primary piping, to support '
decommissioning. The licensee was in Phase 1 of the five-phase decontamination
process. Phase 1 involved a feasibility study of among other matters, cost / benefit
and decontamination methods including flow paths and solvent, and expected
;
person-rem savings. Phase 2 of the program invoNes engineering evaluation while
phases 3,4, and 5 involve equipment setup, operations, and demobilization,
respectively. The decontamination process is described in Electric Power Research
Institute (EPRI) Document EPRI-TR-106386, Decontamination for Decommissioning,
dated May,1996.
The inspector noted that the licensee established a 1996 refueling outage ALARA ;
goal of 420.7 person-rem and a 1996 yearly ALARA goal of 455.4 person-rem. !'
Due to the licensee's decision to cease operationc and decommission the station,
the licensee sustained 178.6 person-rem for 1996 of which about 147.8 person- i
rem was accrued during limited outage activities, including reactor defueling.
Because of the cessation of work activities, the inspector was not able to critically t
a evaluate ALARA program perforrnance during the outage, on a per-job basis.
However, the licensee was tracking exposure daily and publishing a daily exposure
ALARA report. Performance was being tracked against an expected daily accrued
exposure for all work activities. The licensee has established 1997 ALARA Goals
and Targets by department. The 1997 annual goal was 17.5 person-rem with a
target of 9 person-rem. The licensee was continuing to evaluate these goals.
The inspector made the following observations relative to the ALARA program and
its capabilities to effectively support decommissioning activities:
-
The ALARA program was not structured to provide for a real-time systematic
evaluation of accrued radiation exposure for work activities as the activities
progressed. Specifically, there was no clear guidance or expectation
regarding the level of review required to ensure that final ALARA
goals / targets would be met. The inspector noted that subjective reviews
were being performed. Consequently, it was not apparent that the ALARA
program, as currently described / implemented, would be capable of providing
effective evaluation of ALARA program effectiveness in support of
decommissioning activities.
-
The ALARA program, for job pre-planning purposes, permitted subjective
evaluation, by job supervisors, of expected worker accrued radiation
<
exposure.
-
The ALARA program reviews did not provide for evaluation and control of
committed dose equivalent in consideration of the licensee's identified
concern with transuranic contamination (i.e., alpha contamination) in
selected areas of the station.
~- _.
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.
63
ihe inspector noted that the licensee was aware of weaknesses in ALARA planning
and had recently tasked ALARA personnel with performing ALARA pre-job reviews,
in lieu of job supervisors. As of the end of this inspection period, the licensee had l
revised ALARA program procedures to provide enhanced ALARA controls.
c. Conclusions
The licensee was performing a feasibility study of a decontamination process to
reduce radiation exposures during decommissioning to ALARA. This was j
considered a good initiative. Weaknesses in the ALARA program, relative to ALARA l
'
planning for initial and on-going work activities, were identified.
B1.3 Radioloaical Environmental Monitorina Proaram (IFl 97-01-10)
1
a. Insoection Scoce (84750) l
The radiological environmental monitoring progra.m (REMP) was inspected against ,
Sections E.1 and E.2 of the Radiological Effluent Monitoring and Offsite Dose !
Calculation Manual (REMODCM), Regulatory Guide 4.1, " Programs for Monitoring -
I
-
Radioactivity in the Environs of Nuclear Power Plants," and the Updated Final Safety
Analysis Report (UFSAR). The following activities were conducted to assess the
licensee's capability to implement the program.
- Examination of the air samplers and automatic water compositors;
determination of operability and calibration status.
- Observation of personnel collecting samples from selected sampling
locations.
-
Discussion of any modifications to the REMP regarding decommissioning.
-
Review of any REMP procedure and ODCM changes.
-
Review of the results of the Land Use Census.
-
Review of control locations to wind direction and D/Q.
-
Review of sample results and assessment of licensee's evaluation methods.
-
Discussion of tritium in the wells adjacent to canal.
-
Discussion of with licensee compliance with EPA limits 40 CFR 190.
-
Observation and walkdown of the protected area fence to review the
location of TLDs.
l l l .
64
b. Observations and Findinal
The Radiological Assessment Branch (RAB) continued to maintain oversight for the
implementation of the REMP, including overall responsibility for quality assurance
oversight within the program and most meteorological monitoring program
responsibilities. Members of the Production Operations Services Laboratory (POSL)
had the responsibility to implement collection of samples of erwironmental media
such as water, soil, sediment, fish and airborne particulates. The environmental
samples were prepared and sent to the contractor, Yankee Atomic Environmental
Laboratory, for routine analyses. Other responsibilities of the POSL included
exchanging and reading environmental thermoluminescent dosimeters (TLDs) and
calibrating and maintaining the air samplers.
The inspector visited the POSL and selected sampling stations to determine whether
samples were being obtained from the locations designated in the REMODCM and
whether air samplers were operable and calibrated. The sampling stations included
air samplers for particulate and airborne iodine, milk sampling stations, a sediment
sample location, the composite water sampler, and a number of thermoluminescent
dosimetry (TLD) stations for direct ambient radiation measurements. All air
e samplers and the water compositor at the selected locations were operational since
the previous inspection. The observed air sampling equipment was well maintained,
and the associated air volume measurement equipment was calibrated. The air
samplers were collecting the amount of air (1-1.5 cfm) as required in the procedure.
Milk samples were available and the TLDs were placed at locations designated in
the REMODCM. Sediment, water, and air filter collections were observed. The
sampling techniques were good and performed according to the appropriate
procedures.
The licensee discontinued sampling for air iodines as a result of the decision to
decommission site. The requirements were changed in the ODCM, effective
February 28,1997. Air iodines were sampled and analyzed through
March 3,1997, as required in the previous revision of the REMODCM. The licensee
expects this change to be the only change to the REMP as a result of
decommissioning. All other aspects of the REMP will remain the same.
The air sampling and sediment sampling procedures were reviewed and determined
to be acceptable with one exception in the air sampling procedure. The procedure
had not been revised to reflect the discontinuation of sampling and analyzing for air
iodines at CY. This procedure was used for both the CY and Millstone sites.
Millstone continues to sample and analyze for air iodines. The licensee stated that
this procedure will be reviewed and changes will be made where appropriate.
The inspector reviewed the licensee's TLD program conducted at POSL. Overall,
the program was acceptable. The ionization chamber (condenser R-meter) used to
verify operability of the Shepherd Panoramic irradiator and ensure
thermoluminescent dosimeters are accurately irradiated, was calibrated in
January 1997 (see Section R1.1 of the Integrated Inspection Report 50-245;
50-336;50-423/96-09 for details). The results of the calibration showed an
- - _ _ _ . _ _ _ - - - _ _ _
.
65 insignificant difference between the "as found" and the "as left." From these results, it can be concluded that the R-meter verified operability of the Shepherd Panoramic irradiator and ensured the thermoluminescent dosimeters were accurately irradiated prior to January 1997. The Land Use Census required by the REMODCM was conducted using Procedure RAB B-7, " Environmental Sample Location Census." The census, performed in 1995, detailed garden and milk locations within 5 miles around the site. Changes as a result of the census will be documented in the 1996 Annual Radiological Environmental Operating Report (REOR). Also, the inspector reviewed the locations of control stations for milk and air sampling. Control stations appear to be in the least prevalent wind directions and lowest D/Q, as required. Analytical data from certain environmental samples from January 1996 to March 1997 were reviewed by the inspector. In general, no significant anomalies or increased concentrations as a result of plant effluents were noted. The inspector noted that the required environmental LLDs were met. The inspector also reviewed the tritium (H-3) levels in the onsite well (#15) located adjacent to the discharge canal. The levels of H-3 in the well have historically been detectable and are e attributable to discharge of H-3 from normal plant effluents. Groundwater samples- were collected quarterly from the site welllocated one half mile ESE from the site, and from the control station located about 2.8 miles SE from site. The highest concentration detected at well #15 was 2.0 i O.2E3 pCi/l collected in the first quarter of 1995. Subsequent concentrations were lower, in fact, tritium was not- detectable during the fourth quarter of 1995. In 1996, the highest concentration detected was 1.5 i O.5 E3 pCi/l in third quarter and in 1997, the concentration for the first quarter was 9.91 i O.5 E2 pCill. The reporting level for H-3 is 2.0 E4 pCi/l, as required by the REMODCM, Section E.1, Table E-2. Since shutdown in September 1996, these levels have gradually decreased. The annual dose, reported in the 1995 annual Radioactive Effluent Release Report, from liquid effluents for an individual in an unrestricted area from all pathways of exposure was 0.176 millirem, which was less than the annual limit of 3 millirem to the total body, as required by T.S. 3.11.1.2. The inspector discussed compliance with the Environmental Protection Agency (EPA) regulation 40 CFR 190 with the licensee. The inspector walked along the protected area fence with a member from POSL and noted the location of the extra environmental TLDs (documented in the REOR). A set of TLDs deployed by Health Physics (HP) was also on the fence. The inspector determined that the environmental TLDs posted on and near the protected area fence were considered as extra environmental TLDs and were not intended to measure direct radiation from the site to demonstrate compliance with 40 CFR 190. The TLDs for the HP proram were only considered for on site measurements to ensure compliance with cer%in 10 CFR 20 requirements. This inspection area was incomplete and further dit.ussion and information regarding how the licensee ensure compliance with 40 CFR 190 remains to be reviewed. (IFl 97-01-10).
. _ _ - _ _ _ _ _ _ _ _ _
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66
c. Conclusions
Overall, Haddam Neck continued to maintain an effective REMP. Environmental
sample media were collected and analyzed as required by REMODCM. Sample
collection was performed according to the procedure and the sampling technique
was good. The TLD program, including the quality assurance, was good. The R-
chamber had been calibrated in January 1997 in response to an NRC finding during
a REMP inspection at Millstone. The "as found" compared wall to the "as left"
results of the R-chamber. The discontinuation of collecting and analyzing for air
iodine was appropriate and the change made to the REMODCM prior implementation .
was also appropriate.
R 1.4 Meteorolonical Monitorina Proaram (MMP)
a. Inspection Scope (84750)
The Meteorological Monitoring Program (MMP) was inspected against TS
Section 3.3.3.4, UFSAR Section 2.3.3 and Regulatory Guide 1.23 commitments.
The following activities were conducted to assess the licensee's ability to
implement the program.
- Review of calibration procedures, calibration results, and channel check logs.
- Discussion of data acquisition, availability of data, and EDAN parameters.
- Observation of coMition of meteorological equipment.
b. Observations and Findi.c
Personnel from POSL are responsible for maintaining and calibrating the
meteorological monitoring instrumentation. A member from POSL, familiar with the
monitoring instrumentation and data acquisition, demonstrated Environmental Data
, Acquisition Network $ DAN) parameters. The licensee had recently upgraded the
EDAN2 to EDAN3. Data acquisition is now personal computer (PC) based.
Meteorological data can be acquisitioned from any one of the many meteorological
monitoring locations including the control room, emergency operating facility, the
-
POSL office, and from the Millstone meteorological towers. The UFSAR was
'
reviewed regarding the upgrade. No changes were made since the same data can
be requested and the UFSAR does not stipulate a specific version of EDAN.
Calibration checks were performed weekly in accordance with the weekly
surveillance. The weekly calibration check was not observed during this inspection
due to scheduling changes made by the licensee. However, the inspector reviewed
the results of that particular surveillance and noted that no problems were
encountered during the surveillance. Selected calibration checks from June 1995
through March,1997 were reviewed. The inspector noted that the licensee is
,
capable of resolving problems, when encountered. Most problems were minor in
nature due to the high level of attention to the equipment.
_________ __
*
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67
Calibrations were performed quarterly, more often than semiannual as required by
TS. Calibration results from July,1995 through December 1996 were reviewed.
The results were within the licensee's acceptance criteria. Calibrations were
performed according to the licensee's procedures. The meteorological monitoring
procedures are PORC-approved.
Channel checks are required daily by the TS. Operations personnel performed the
channel checks every shift, thereby ensuring compliance with TS. The inspector
selected and reviewed the shift log from February 24 to March 19,1997, and noted
that the channel checks were performed every shift during that time period.
The inspector noted a new multi-point chart recorder located in the equipment
house of the primary tower. The associated calibration procedure was updated to
reflect the new chart recorder type. The inspector determined that a change to the
UFSAR was not required because it is not prescriptive regarding the type of
recorder. A new chart recorder is planned for installment in the control room after
approval. All the equipment was in very good condition. The i?spector reviewed
Section 2.3.3 of the UFSAR and noted no deviations in this area.
c. Conclusions
Based on the direct observations, discussions with personnel, and examination of
procedures and records for calibration of equipment, the inspector determined that
overall, the licensee's performance of maintaining and calibrating the meteorological
monitoring instrumentation was very good. The data were available as required and
were easily accessed from severallocations including the control room and the EOF
as specified in the UFSAR.
R2 Status of RP&C Facilities and Equipment
R2.1 Inocerable Effluent Monitors
Technical Specifications 3.3.3.7 and 3.3.3.8 require that certain radiation monitors
be operable at all times to monitor the status of liquid and gaseous releases from
the site. The licensee declared all technical specification monitors inoperable on
February 5,1997 as a result of an NRC inspection which found inadequacies in the
calibration program. This issue was described in adverse condition report (ACR) 97-
65. The radiation monitors (RM) affected included channels RM-18, RM-22, RM-19,
RM-14A and RM-14B. Although inoperable per the technical specifications, the
monitors remained functional and available to monitor the effluent pathways.
Section 01.6 of this report describes NRC review of licensee compensatory actions
to comply with the action statement of TS 3.3.3.7 and 3.3.3.8, which included
periodic sample and analysis of releases via the associated pathways.
Several other discrepancies in the effluent monitors were identified during the period
as a result of continued testing and reviews by the licensee chemistry personnel,
and through quality assurance audits and surveillances. RMS deficiencies included:
the failure of the RM-18 low flow alarm to reset following testing due to lower SW
. .
68
system flows (ACR 97-28); a recurrent failure of the Scanrad Computer to lockup,
resulting in involuntary entry into TS 3.3.3.7 and 3.3.3.8 on numerous occasions
(ACR 97-47); RMS-22 failed during testing on February 5 (ACR 97-62); area
radiation monitors R-20 and R-21 were found inoperable during testing per SUR 5.1-
11 (ACR 97-72); the trip setpoint for liquid monitor RM-22 was not conservatively
established (ACR 97-79); the lack of traceability of calibration sources used for RMS
calibrations (ACR 97-96); multiple failures (channel cross talk) of area radiation
monitors during testing per SUR 5.1-11 (ACR 97-133) and, the determination that
the sample probe for stack gas monitor RM-14A was not isokinetic and did not
meet the design basis to adequately sample the flow stream (ACR 97-110). This
latter deficiency was found to be reportable; the licensee notified the NRC per 10
CFR 50.72(b)(1)(ii)(B) on April 4,1997 (ACR 97-169).
QAS audit CY-P-97-006 identified an adverse trend with the reliability of the RMS.
The adverse trend was highlighted by many problems (22 issues noted) over the
period from October 1996 to February 1997, which continued to occur despite
corrective actions. QAS found that although actions were taken to correct
immediate problems, the RMS reliability issue has not been addressed. Problems '
;
with failed calibrations, failed sensors, system lockups (scanrad computer), set
point drift, improper use of procedures, inadequate procedures, no alarm response
and annunciation failures have continued with no overall adequate resolution. QAS
determined, based on the current conditions of the system, it was not apparent that j
the design basis was being met by the system in the current configuration (ACR 97-
73).
i
Licensee plans and schedules to recalibrate the monitors were described in letters to
the NRC dated February 24 and March 27,1997. A Special Report per TS 6.9.2 to
address the status of RM-14B was submitted to the NRC on February 19,1997
(B16268). The licensee determined that the recent calibration deficiencies occurred
as a result of recent changes in responsibility between departments to conduct
radiation monitor calibrations. The change occurred in 1996 as the licensee
implemented plant modifications to upgrade the radiation monitoring system. These
modifications were partially implemented prior to the plant shutdown in July 1996,
and then were not completed. To address the calibration deficiencies, the licensee
actions included: revising calibration methods and procedures to conduct an insitu
primary calibration of the channels; the use of new calibration test stands; the
procurement of new sources (Cs-133 and Co-60) to improve the calibration method;
and, additional reviews with the RMS vendor to improve the reliability of the
Scanrad computer.
The licensee also committed to evaluate any potential inaccuracies identified by the
new calibrations to determine the impact on past operations. During a calibration of
channel RM-14B on February 26,1997, the licensee identified that the mid range
detector channel was significantly out of tolerance low (ACR 97-101). When tested
per SUR 5.2-69, the channel read 2400 cpm, which was below the required
acceptance criteria to be within the range of 6777 to 8283 cpm.
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Licensee actions to assess the as found accuracy of the radiation monitor channels
relative to periods of past plant operations was in progress at the conclusion of the .
inspection period. As of April 7, the licensee had procured new sources, l
constructed new calibration equipment and revised the procedures to calibrate RM- !
22, RM-14A and RM-18. The licensee planned to complete the new calibrations
and restore all channels to an operable status by May 2,1997. The licensee i
assembled a team comprised of l&C, chemistry, engineering personnel to develop l
an Action Plan to address all RMS deficiencies in a comprehensive manner. The
draft Action Plan was under review at the end of the inspection period.
;
R3 RP&C Procedures and Documentation
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R3,1 Whole Body Countina )
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^
a. inspection Scope (83750)
As part of the follow-up to the November 2,1996, fuel transfer canal airborne-
radioactivity event, the inspector used an anthropomorphic phantom (Humanoid
Systems), to qualitatively check the licensee's whole body counter and dose
% assessment capabilities. The whole body counter, a standup counter (Canberra
Model 2250 FASTSCAN) maintained at the Emergency Operations facility, was
- used by the licensee, in addition to other data (e.g., fecal analyses), to quantify the
intake of airborne radioactivity following the November 2,1996, event. The
phantom's lungs contained known quantities of radioactive material (including the
principle gamma emitting radionuclide identified during the November 2,1996
,
. event) which the licensee was requested to estimate. The phantom was removed
from and placed back into the counter and counted several times to evaluate
geometry considerations. Further, the licensee was requested to perform a dose
estimats based on inspector-provided radionuclide characteristics (e.g., transport
class and particle size).
b. Observations and Findinas
The inspector's review indicated the licensee's whole body counter provided a
reasonable qualitative estimate of radioactivity contained within the lungs of the
phantom. Further, once the deposited activity was estimated, the licensee
performed reasonable dose estimates based on assumptions provided by the
inspector,
c. Conclusions .
The whole body counter and procedures used by the licensee to estimate intake of
,
gamma-emitting radionuclides provided a good qualitative estimate of radioactivity
contained within the lungs of a test phantom. Further, the dose assessment
performed by the licensee was reasonable based on assumptions provided.
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R3.2 Contamination Controls (URI 97-0_1-11)
a. Inspection Sg_qp_g
The inspector reviewed selected aspects of the licensee's contamination control
program. The review was in response to the identification by a vendor on
February 27,1997, that video equipment, picked up by the vendor at the Haddam
Neck facility as clean equipment on February 19,1997, was identified by the
vendor to exhibit radioactive contamination.
b. Observations and Findinas
identification of Contaminated Equipment at an Offsite Vendor Facility
On February 26,1997, the licensee was informed that low level radioactive
contamination had been detected on video cables that had been released from the
station on February 19,1997. The contamination was detected by the vendor's
personnel who normally perform routine contamination surveys of video equipment
that is returned to the vendor's f acility from reactor f aci;ities, interim actions were
taken (February 27,1997) to restrict the release of material from the radiological-
controlled and protected areas pending evaluation of the event and development
and implementation of long term corrective actions. The details of the NRC review
of this matter will be included in a future inspection report. As a result of this event i
I
and other concerns involving radiological controls, t; a NRC issued a Confirmatory
Action Letter (CAL No. 1-97-007) on March 4,1997, specifying actions to be taken
to effect overall program improvement.
c. Conclusions
Contaminated material was detected outside the radiological controlled area
including in the possession of a non-licensed individual. The details of the NRC
review of this matter will be included in a future inspection report. The
effectiveness of contamination controls is an unresolved item. (URI 97-01-11)
R5 Staff Training and Qualification in RP&C (URI 97-01-12)
a. Insoection Scone (83750)
The inspector selectively reviewed the training provided to the licensee's radiation
protection staff relative to the programmatic weaknesses identified during the
November 2,1996, fuel transfer canal airborne radioactivity event. The inspector
also reviewed training of personnel to perform contamination monitoring.
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b. Observations and Findinos
b-1. November 2,1996, Fuel Transfer Canal Event i
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The licensee provided training to the radiological controls group on the
circumstances surrounding the November 2,1996, fuel transfer canal airborne
radioactivity event. The NRC inspection report, which detailed the NRC reviews of
the event, was provided to the staff including the licensee's internal lessons learned
document. Also, the licensee provided training on NRC Information Notice No. 92- -
75, " Unplanned Intakes of Airborne Radioactive Material By individuals at Nuclear ,
Power Plants," dated November 12,1992, which was referenced in the inspection
report.
!
b 2. Contamination Controls
!
The inspector reviewed the training and qualifications of personnel who calibrated j
and operated the waste sorting table. As discussed above, camera equipment, that i
was apparently surveyed for contamination by use of the waste sorting table was ,
identified to be contaminated and located at an offsite vendor facility. The I
inspector's review indicated the following. ]
1
'
- The inspector was not able to identify a formal training program or training
records for the individuals who calibrate the waste sorting table or bag i
monitor. Calibration procedures were established. l
- The inspector was not able to identify forrnal training records for several
individuals who operated the waste sorting table.
The training and qualification of personnel for calibration and operation of
contamination monitoring equipment is an unresolved item. (URI 97-01 12)
c. Conclusions
The licensee provided training of the radiological controls group on the !
November 2,1996, event. An unresolved item was identified in the area of training
and qualification of personnel who calibrate and operate contamination monitoring
equipment.
R6 Radiological Protection and Chemistry (RP&C) Organization and Administration
a. Insoection Scoot
The inspector selectively reviewed the licensee's organization and staffing relative
to information contained within the Technical Specifications. The inspector also
discussed the proposed organization to support decommissioning activities. j
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b. Observations and Findinas
The licensee developed a proposed interim and final decommissioning organization
and staffing levels. At the time of the inspection, the licensee was continuing to
maintain the normal radiological controls organization, but expected to transition to
the interim decommissioning organization on or about April 9,1997, and transition
to a final decommissioning organization on or about December 31,1997. Staffing
levels for these proposed station organizations was expected to decrease from the
current 322 personnel to 171 personnel (interim) to approximately 106 personnel
(final). The radiation protection organization was expected to decrease from the
current 34 person staff level to approximately 26 personnel. The licensee's
proposed interim and final decommissioning organization included the establishment
of associated responsibilities and authority for assigned positions. The licensee re-
posted all positions essentially requiring current staff members to submit
applications for decommissioning organization positions.
The licensee was reviewing the proposed organizations and had contacted other
stations undergoing decommissioning to attempt to determine appropr!ste
organizational design and staffing levels to support decommissioning activities. The
licensee's station services director indicated that, based on expected work
reductions, the staffing levels in the area of chemistry personnel and radwaste
technicians was expected to decrease.
As part of the proposed organizational structure, the licensee provided for enhanced
attention to radiation protection and safety programs, in that a new safety manager
position was established. In addition, an enhanced QA organization (to
provide /obtain staff experienced in radiological control / decommissioning activities)
was established.
c. Conclusions
The licensee developed proposed organizational structures and staffing levels to
support decommissioning activities and was evaluating industry experience in this
area. The licensee's initial efforts in establishing a decommissioning organization
were considered adequate.
R6.1 Manaaement Controh
a. Inspection SSone (84570)
The inspectcr reviewed organization changes and the responsibilities relative to
oversight of the REMP and MMP, and the Annual Radiological Environmental
Operating Report to verify the implementation of Section 6.9.1.6 of the TS.
b. Observations and Findinas
Organization changes affecting RAB occurred in 1996. The RAB was moved from
Nuclear Engineering to Nuclear Design Engineering back to Nuclear Engineering for
. . . . _. .
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a 6-month time period. In addition, the group was physically moved from the
corporate office, located in Berlin to the Millstone station where they remained for a
short period of time, and then were moved to an office in New Britain. The RAB
personnel and responsibilities remained the same during these changes.
The Annual Radiological Environmental Operating Report for 1995 and the analytical
data from 1996 and 1997 were reviewed. The report included a summary of the j
results of the radiological environmental monitoring program from the report period
'
including a summary of the analytical results of the environmental samples and
radiation measurements taken from locations specified in the REMODCM. The
report also included the land use census and the interlaboratory comparison results,
as required by TS. No obvious omissions were noted. Inconsistencies between the
REMODCM and the annual reports regarding distances documented in the land use
consus, appeared to be administrative errors. No anomalous data were noted in
the 1996 or 1997 data. The REMP reports met the TS and REMODCM reporting
requirements. ,
l
c. Conclusions !
*, -- Based on the above review, the inspector determined that the licensee implemented
good management control and oversight of the REMP and MMP and effectively
implemented Section 6.9.1.6 of the TS requirements.
R7 Quality Assurance in RP&C Activities
a. incoection Scope (83750)
.The inspector selectively reviewed the licensee's quality assurance efforts.
b. Observations and Findinas
To oversee decommissioning activities, the licensee has hired individuals into the
quality assurance group with extensive experience in radiological controls programs
and decommissioning. This was considered a good initiative. )
!
c. in
i
_Conclu_tona
The licenste enhanced the radiological controls and decommissioning oversight
capabilities of the quality assurance group. This was considered a good initiative.
82d Qua'ity Assurance Audit Proaram
a. Inspection Scope (84750)
The Quality Assurance (OA) audit and surveillance reports were reviewed to
determine if the licensee was making an effort to identify deficiencies in the
sampling, measurement and quality assurance programs.
.
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4
74
- QAS Audit Report, (95-4314), " Radiological Effluent Monitoring and Offsite
Dose Calculation Manual (REMODCM) - 1995," October 5,1995
- Nuclear Safety and Assessment Audit Report, 96-A10-02, l
October 15-22,1996 l
1
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Surveillance Report (SIP No. CY-P-97-024)
b. Observation and Findinas
The assessment of the REMP as documented in the 1995 QAS audit report,
performed by the Quality Assurance Surveillance (QAS) group, was very limited.
There were no concerns regarding programs strengths or weaknesses. The report
'
combined audits of the effluent and environmental programs from both CY and
Millstone thus making the audit report confusing and difficult to understand and
interpret. Requirements and deviations from requirements were not clearly stated
and issues were vague. No discussions of audit findings were evident. Based on
the report, the 1995 audit appeared as an ineffective effort.
- The OAS group have made noticeable irnprovement efforts to better identify
deficiencies and assess the strengths and weaknesses of the environmental and- j
, meteorological monitoring programs. The 1996 QAS audit of tt.a i
REMP/RETS/ODCM was more critical than the 1995 rudit. The report identified l
four ACRs (one REMP related) and several observations. The responses to ACRs - !
were timely and appropriate. The effectiveness of the corrective actions in
response to the 1995 audit were reviewed and docemented in the 1996 audit
report. All five audits (Seabrook, Millstone 1, 2 and 3, and Connecticut Yankee)
s were then compiled into one audit report. Discussions of audit findings were clearly.
documented and issues were easy to understand and interpret. Audit findings were
appropriate and appeared reasonable.
. The CY Oversight group became effective in January 1997. This group will perform
audits and surveillances of CY exclusively. The group recently completed a
surveillance specific to implementation of the REMP. The findings of the
surveillance were appropriate and appeared reasonable, issues were formally
documented and processed. This group is scheduled to perform an audit of the
REMP in October 1997,
c. Conclusions
.
Based on the 1996 audit and 1997 surveillance, and discussions with the CY
oversight group, the inspector concluded that the audits have improved significantly
since the 1995 audit and the QA Oversight group will conduct audits and
surveillances of the REMP at CY.
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872 2 Quality Assuritoce of Analvtical Measurements
_ ,
a. Inspection Scope (84750)
The inspector reviewed the quality assurance (QA) and quality control (QC)
programs against Section E.3 of the REMODCM and recommendations of Regulatory
Guide 4.15, " Quality Assurance for Radiological Monitoring Programs (Normal
Operations) - Effluent Streams and the Environment" to determine whether the
licensee had adequate control with respect to sampling, analyzing, and evaluating
data for the implementation of the REMP. The following issues were discussed.
- Participation of the Yankee Atomic Environmental Laboratory (YAEL) in the
Environmental Protection Agency (EPA) Interlaboratory Comparison (cross-
check) program (1995)
;
- ~ Review the cross-check program provided by Analytics to determine Ine
effectiveness of the program,
b. Observations and Findinos
The performance of the contractor laboratory, Yankee Atomic Environmental
Laboratory (YAEL), continued to be excellent. During an inspection at Millstone, the
inspector visited the laboratory and assessed the quality assurance program. See-
Section R7.2 of the Combined inspection Report Nos. 50-245/96-09, 50-336/96-
09, and 50-423/96-09 for details.
i
The EPA discontinued the interlaboratory comparison program, with the exception
-
of drinking water,in January 1,1995. The licensee was timely in finding a
laboratory, Analytics, Inc., to continue the interlaboratory comparison program, as
required in the REMODCM. Spike samples, similar to those provided by the EPA
cross-check program, were provided to YAEL where the analyses were performed. i
YAEL sends the analytical results to Analytics for review. Analytics compares the !
ratio of the observed result to the expected result. The inspector reviewed the
analytical results of this program and noted the results were within the licensee's l
'
acceptance criteria. The inspector also reviewed the results of the 1995 EPA cross-
check program and noted that most of the results were within the EPA acceptance
l
crit::ria. Overall, the licensee's performance in this area was very good.
c. Conclusions
Based on the above observations, the inspector determined that the performance of
the contract laboratory was excellent and the interlaboratory program was effective.
,
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R8' . Miscellaneous RP&C lasues 1
Bil Decommissionina Proiect Plannina _ -
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a. Insoection Scope
{
,
The inspector selectively reviewed the licensee's decommissioning project planning. ;
-
t ,
i b. Observations and Findinas
The licensee established a decommissioning project milestone schedule and flow
chart. The document identified expected deliverables as well as task team leaders.
At the time of the inspection, the manual contained approximately 28 separate
'
tasks and schedules. ' The tasks included such items as development of the Post ,
'- - Shutdown Decommissioning Activities Report, revision of the UFSAR, and various .;
accident analyses tasks. i
,
.
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c. . Conclusions ]
1
;r - Th'e licensee established decommissioning project plans and schedules to support 1
- decommissioning project planning. !
R8.2 Followuo of the November 2.1996. Fuel Transfer Canal Event
l'
a. Insoection Scope
'
-The inspector selectively reviewed immediate and interim corrective actions
e implemented by _the licensee following unplanned personnel exposure event . -
. discussed in NRC Inspection Report No. 50-213/96-12, dated December 19,1996. .
b. Observations and Findinos
1
The inspector's review indicated the licensee implemented the following immediate !
and interim corrective actions for the fuel transfer canal airborne radio::ctivity event. I
i'
- The licensee initiated work control measures for work within the radiologi::al
controlled area to preclude similar events pending establishment and
implementation of appropriate corrective actions to address program
weakness identified by the licensee's two root cause evaluations and the
findings of the licensee's independent review team. Work within areas
designated as high risk areas was to be specifically reviewed ar.d approved
by the work services director or the unit director to ensure that there was a ,
need to perform the work and that the work had adequately been planned !
.and prepared. Memoranda detailing these controls were issued on
. November 25,26 and December 12,1996.. The November 25 memorandum
- detailed controls for backshift and weekend work and the latter two
memoranda detailed work controls for high risk areas.
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The licensee provided details of the work restriction to the NRC in a letter
dated December 9,1996. As of the date of this inspection, no radiologically
significant work activities occurred. The licensee did floodup the reactor
cavity and off-load the reactor core during the month of November 1996.
Constant health physics technician coverage was provided for this activity
and no radiological concerns were noted.
- The licensee issued a Licensee Event Report (LER) No. 50-213/96-030-00 on
December 6,1996. The LER discussed, among other matters, the event and
provided preliminary dose assessments and a discussion of apparent root i
cause for the November 2,1996, event. This LER is closed.
- During the week following the event, radiation protection management met
with radiological controls department personnel to discuss the event and its
apparent root causes and corrective actions. A follow-up meeting was held
with radiction protection department personnel once it was determined that
an apparent overexposure to airborne radioactivity may have occurred and to
discuss findings of initial root cause analyses.
- The unit director issued memoranda (November.4,1996) to station managers
and supervisors regarding expectations for notification to the control room
and notification of work supervisors of work stoppages and the need for
effective pre-job briefings.
1
- A station work stand down was held on January 28,1997, for purposes of l
re-emphasizing the need for industrial and radiation safety. The licensee's
work services director also met with station departments in January 1997,
to discuss the November 2,1997, event and its root causes, and lessons
learned.
-
Following the event, radiation protection management took a number of
immediate and interim actions to strengthen radiological controls as follows. ,
1
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The licensee permanently assigned an additional radiation protection
technician (day shift) to the RCA control point to challenge workers entering
the RCA as to their purpose for entry and to ensure appropriate RWPs were
implemented. (November 6,1996) As discussed above, the licensee
prohibited backshif t and weekend work without specific approvals.
-
Alllicensee and contractor radiation protection technicians were required to
read (November 11,1996) NRC Information Notice 90-33, Sources of
Unexpected Occupational Radiation Exposures at Spent Fuel Storage Pools,
dated May 9,1990, in support of fuel movement.
-
The licensee eliminated use of field counting / checks of air samples as a basis
for reduction in worker radiological controls. (January 10,1997)
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-- The licensee revised applicable radiatit x permits to ensure compliance - _
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with Technical Specification High Rac . Area requirements (i.e., provision
of job area radiation surveys) or dear ..ed the RWPs to prevent their use. l
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(December 1,1996) ,
!
- The licensee implemented (January 1,1997) zone radiation protection ,
technician coverage to provide for technician familiarity of work area :
!
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radiological conditions and improved ownership of work within the RCA.
' - - The licensee developed an action plan to implement corrective actions for the ;
findings of the Independent Review Team (IRT).
i !
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- .The licensee initiated action to review the ALARA and alpha contamination i
control programs. The licensee established an alpha program review / revision ,
y task force. The task force developed a series of recommendations for .;
revision of the alpha control program. i
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- The licensee assigned (November 26,1996) radiation protection technicians j
to read / review procedures. l
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The licensee issued guidance (January 7,1997) regarding inappropriate use
'
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. of " clean" terminology when briefing personnel.
- On or about November 22,1996, the licensee required supervisors to
approve all RWPs.
- The licensee implemented enhanced oversight and control of work and
e- developed a draft conduct of work guidenne based on radiation work risk -
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assessment (i.e., establishment of controis based on radiological conditions ;
- identified).
- The. licensee developed standard pre-job briefings for expected high risk work
- that may occur (e.g., spent fuel evolutions, diving, resin liner transfers, and
filter changes). (January 8,1997)
1
-The inspector's review indicated the licensee planned radiological controls program
- upgrades by the end of February 1997. Program upgrades, among others, were j
'
identified for the following areas:
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- Develop and implement improved procedures for high risk evolutions,
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including performance of representative pre-job surveys.
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Enhance the ALARA program to address both external and internal exposure
controls. !
Require use of respiratory protective equipment in all high risk alpha areas
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until acceptable airborne conditions were determined. j
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- Upgrade the RWP program to provide for clear descriptions of authorized
work and controls, including realistic dose controls with appropriate margins
and limits.
As of March 6,1997, the licensee had revised and updated and issued six
procedures to provide enhanced radiological controls including those controlling -
RWP initiation and risk assessment, health physics job coverage, ALARA reviews,
non routine whole body counting, and radiological surveys.
c. Conclusions
The licensee initiated and took a number of corrective actions in response to the
November 2,1996, fuel transfer canal event. However, a significant number of
program improvements, although not yet due at the time this area was reviewed,
have yet to be completed. The licensee placed all significant radiological work on
hold pending program improvements as described in the licensee's 4
December 9,1996, letter to the NRC. l
R8.3 (Ocen) URI 96-12-01,02: Exposure Assessment, Dose Calculations )
l
a. Insoection Scoo_g
The inspector reviewed the licensee's calculations of deep dose equivalent (DDE),
shallow dose equivalent (maximum extremity and whole body) (SDE), lens dose i
equivalent (LDE), committed effective dose equivalent (CEDE), committed dose l
equivalent (CDE), and total effective dose equivalent (TEDE) for the two workers j
who entered the fuel transfer canal on November 2,1996. The workers
unknowingly carried a bag of debris, later measured to indicate between 20 R/hr to
60 R/hr on contact. Also, the workers sustained an intake of airborne radioactivity
which included transuranic contaminants. The review was against criteria
contained within 10 CFR 20 and guidance contained within apolicable NRC
Regulatory Guides.
b. Observations and Findinas
Dose Attributable to Radiation and Contamination External to the Body
The inspector's review indicated that relative to the external exposure of the
workers, the licensee made measurements of the bag of debris with TLDs placed at
various distances from the bag. The licensee calculated the potential unmonitored
deep dose equivalent (DDE), shallow dose equivalent (SDE), and maximum exposure
to the extremities, and lens dose equivalent essociated with collecting and handling
the bag of debris and walking in the canal. The inspe:: tor noted that the licensee
did not initially calculate, for Worker A, the dose attributable to peeling paint chips
from the surface of the fuel transfer canal wall and did not calculate, for Individual
B, the shallow dose to the skin due to potential contamination of the back of the
coveralis when sliding against the wall of the fuel transfer canal. The licensee also
did not calculate maximum lens dose equivalent associated with the activity. The
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licensee subsequently calculated the exposures for the individuals. The licensee '
provided the following radiation doses (as measured with TLD) and potential
unmonitored dosec which were added to the workers' radiation exposure histories.
j Based on the inspector's review, the measured and estimated external doses were
considered reasonable and well within applicable limits, :
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Table 1 Deep Dose Equivalent (DDE) (millirem)
Worker DDE by TLD for Additional DDE by Total DDE for Total DDE for 10 CFR 20.1201
11/2 event evaluation for 11/2 event 11/2 Event 1996 annual limit
A 233 152 385 396 5,000
(DDE + CEDE)
8 157 56 213 473 5,000
(DDE + CEDE)
Table 2 Shallow Dose Equivalent (SDE), Whole Body (WB) (millirem)
Worker SDE, WB by TLD for Additional SDE, WB by Total SDE, WB Total SDE, WB 10 CFR ,
11/2 event evaluation for 11/2 event for 11/2 Event for 1996 20.1201
annual limit
~
A 233 154 387 398 50,000
B 157 56 213 473 50,000
Table 3 Shallow Dose Equivalent (SDE), Maximum Extremity (ME) (millirem)
Worker SDE, ME by TLD for Additional SDE, ME by Total SDE, ME Total SDE, ME 10 CFR 20.1201
11/2 event evaluation for 11/2 event for 11/2 Event for 1996 annual limit
A 233 920 1,153 1,164 50,000
B 157 284 441 701 50,000
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Note: The licensee calculated an additional 12 millirem to the face of Worker A (due
to working in close proximity to the bag of debris) that is to be added to the lens of
the eye dose and shallow dose to the whole body and extremity. Consequently the
totallens of the eye dose to Worker A was 397 millirem for the event,399 millirem
to the shallow dose equivalent to the whole body, and 1,165 shallow dose
equivalent maximum extremity.
Dose Attributable to Contamination Internal to the Body
The inspector reviewed the licensee's calculation of committed effective dose equivalent
(CEDE), committed dose equivalent (CDE), and total effective dose equivalent (TEDE) for
the two workers who entered the fuel transfer canal on November 2,1996. The licensee
evaluated the dose to the workers using (among other data), whole body counts, air
sample analysis data, fecal sample analysis results, and sample analysis results for samples
of material collected within the fuel transfer canal. The following doses, attributable to
intake of airborne radioactivity, were calculated by the licensee.
Table 4
Committed Effective Dose Equivalents (CEDE)
1996 TEDE !
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Worker CEDE Previous
for 11/2 1996 (DDE, from Table 1, 10 CFR 20.1201
,
event CEDE Column 5, plus CEDE for Annual limit
(millirem) (millirem) 11/2 event (millirem) (millirem) *
A 250 none 646 5,000 ;
8 440 none 913 5,000 j
* Note: The annual limit of 5,000 millirem is for the Total Effective Dose equivalent
(TEDE) which is the sum of the deep dose equivalent (DDE) and the committed i
effective dose equivalent (CEDE).
Based on the above analysis, neither worker received radiation exposures in excess
of 10 CFR 20.1201 limits.
Regarding committed dose equivalent due to intake of airborne radioactive material
(e.g., dose to the bone surface attributable to transuranics), the inspector noted that
the licensee's contractor calculated the doses by use of a combination of an
inhalation and an ingestion model and assumed an intake of 1 micron diameter
particles. The following doses were calculated.
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Table 5
Total Organ Dose Equivalents (TODE)
Worker CDE for 11/2 TODE 10 CFR 20.1201
event (CDE + DDE from Table Annual Limit
(millirem) 1 column 5) (millirem)
A 3,000 3,396 50,000
B 5,400 5,873 50,000 j
Based on the above analysis, the licensee concluried that neither worker sustained a
TODE in excess of 10 CFR 20.1201 limits.
The individual worker's dose records (NRC Form 5) were updated to reflect the
measured and calculated exposures.
At the conclusion of the inspection, the inspector had not completed an
independent analysis of the licensee's dose calculation. This unresolved item
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continues to remain open pending additional NRC review of the licensee's CDE dose -
assessment.
R8.4 Housekeepina
The inspector noted that overall housekeeping was good.
R8,5 Confirmatory Action Letter i
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Since November 2,1996, the licensee experienced several radiological
events / problems attributable to weaknesses in managing and controlling radiological
work at the facility. These included the November 2,1996, reactor cavity airborne
radioactivity event (Reference NRC Inspection Report No. 50-213/96-12), the
programmatic deficiencies associated with calibration of effluent monitoring
systems (Reference NRC Inspection Report No. 50-213/97-02), and the problems
associated with release of contaminated material to an unrestricted area. As a
result of these issues, the NRC issued Confirmatory Action Letter (CAL 1-97-007)
to confirm the licensee's actions and commitments to identify and effectively
resolve weaknesses and deficiencies in the implementation of the radiological
controls program.
B3J UFSAR
A recent discovery of a licensee operating their facility in a manner contrary to the
Updated Final Safety Analysis Report (UFSAR) description highlighted the need from
a special focused review that compares plant practices, procedures and/or
parameters to the UFSAR description. While performing the inspection discussed in
this report, the inspectors reviewed the applicable portions of the UFSAR that
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related to the areas inspected. The inspectors verified that the UFSAR wording was
consistent with the observed practices and procedures and/or parameters.
.
P2 Status of EP Facilities, Equipment, and Resources
f)2d Emeroency Plan Staffino
.
a. Insoection Scope (71750) !
)
The purpose of this inspection was to review licensee changes to the site
emergency response organization, and the licensee response to deficiencies in i
meeting plant commitments. !
b. Observations and Findinos i
;
Several staffing or training discrepancies in Emergency Preparedness area were
noted during the inspection period. The deficiencies included: the failure to '
complete timely remedial training of an individual in the site emergency response !
organization (SERO) who had failed a requalification exam (ACR 96-1371); the poor ,
4 SERO response to a quarterly radiopager test conducted on February 5 in which 4 !
on-site responders and 6 off-site responders did not callin (ACR 97-61); the poor
SERO response to a followup radiopager test conducted on February 6 in which 4
on-site responders and 9 off-site responders did not callin (ACR 97-67); the !'
inadvertent termination of site access of an employee who transferred to Millstone,
which might have delayed the response to Haddam Neck to perform a SERO duty
(ACR 97-88); the poor SERO response to a quarterly radiopager test conducted on
February 26 in which 6 on-site responders did not callin (ACR 97-100); and, the ;
findings by QAS regarding inadequate emergency plan training in the development
of table-top exercises (ACR 97-122). i
Most problems appeared to be due to occur during the period of transition from the i
full plant staff in place for power operations, and the reduced staff designated to
remain for plant decommissioning. The licensee evaluated each discrepancy as it
occurred and found that none would have precluded implementation of the
emergency plan. Appiupriate corrective actions were taken for each discrepancy.
The licensee continued to review the causes for the poor responses during
radiopager drills, which were attributed to equipment and personnel failures. NRC
and licensee review of this area were in progress at the end of the inspection
period.
The licensee revised the emergency plan procedures during this period to delete the
use of a Duty Officer at the station during the back shift periods (reference
memorandum CY-GHB-97-031). The Duty Officer position had been established
during plant operations to provide additional resources on-site to assist the Shift
Manager classify events and implement actions under the emergency plan. This
resource was found to be necessary to lessen the burden on the shift manager as
he monitored th plant status and directed crew actions to mitigate the operational
event. The Duty Officer resource was found to be no longer needed based on the
.
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status of the facility and the decision to cease operations. The shift manager
assumed responsibility event classification and notification under the new
procedures, until the SERO was fully staffed. The change was evaluated per 10 '
CFR 50.54 (q) was found acceptable since it did not decrease the effectiveness of
the emergency plan. The change became effective on April 4,1997. The inspector
reviewed the licensee's actions and identified no deficiencies relative to maintaining
an effective emergency response capability relative to the duty officer position,
c. Conclusions
Licensee actions in response to deficiencies in meeting emergency plan !
commitments were acceptable. The change to the SERO by deleting the use of the
Duty Officer was acceptable.
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S1 Conduct of Security and Safeguards Activities j
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S1,1 Fitness for Duty I
The inspector reviewed licensee actions on April 2 in response to a fitness for duty
- event that was detected while conducting pre-access testing for a new employee . ..
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(reference Security memorandum CY-3550). The event did not involve supervisory
personnel. Licensee actions were appropriate to identify and investigate a potential
problem, and to take corrective action. No inadequacies were identified. :
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_S1,2 Guard Inattentive To Duty
The inspector reviewed licensee actions to the discovery on April 3,1997 of a
guard who was inattentive to his duties. The individual had not worked overtime in
excess of the administrative limits. The guard was stationed within a vital area as a
compensatory measure for other security equipment that was inoperable. The
licensee took appropriate actions to immediately assess the area, re-establish -
appropriate security controls, and take corrective actions. The incident occurred
within about two hours from when the guard started his daily shift. No
inadequacies were identified.
S1.3 Resoonse to Potential Threat
The inspector reviewed licensee actions on April 2 in response to a telephone call
from an individual located off site. Licensee actions were appropriate to assess the
caller as a potential threat to the plant (the threat potential was not deemed
. credible) and to coordinate with offsite and local authorities in regards to the
incident. No inadequacies were identified.
S1,4 Eailure to Search Packaaes NIO 97-01 -02.f)
The inspector reviewed licensee actions on March 13 - 15 in response to the
discovery that several boxes containing personal office supplies were brought into
the protected area without receiving the required security search (ACR 97-132).
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The event occurred when a stockhandler, trained and assigned responsibility for
searching materials that enter the protected area by the warehouse, failed to
conduct that task. Following the discovery of the failure to follow security
procedures, the licensee follow up actions were good to investigate the incident,
search the site to assure the vital and security areas were secure, and to take
corrective actions. The licensee terminated the individual's site access on March 13
pending the completion of a review of the event. The licensee subsequently
terminated the individual for integrity issues.
Although licensee response actions to the event were good, this event in another
example of a broader NRC concern in the failure by plant personnel to follow
procedures. The f ailure to search packages prior to entry into the plant protected
area was contrary to security procedure SEC 1.3-8, Step 6.2.1.b, which requires
that all packages be searched prior to entry into the protected area by either x-ray . ;
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examination or visual search. This was a failure to follow procedure SEC 1.3-8, and
the sixth of six examples of a violation of Technical Specification 6.8.1 (VIO 97-01- ;
02.f). l
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V. MANAGEMENT MEETINGS
X1 Exit Meeting Summary
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on April 7,1997. The licensee acknowledged the findings
presented. No proprietary information was examined during the inspection.
In addition to the final exit surnmary, management briefings were conducted during the
.. inspection period as NRC reviews were completed. . Pre exit briefings were also conducted ,
on the following dates:
Inspection Reporting Area
Dates Inspector Inspected
January 1317 Nimitz Radiological Controls
February 7-11 Jang/Echert Effluent Monitoring
March 17-21 Peluso Environmental Monitoring
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PARTIAL LIST OF PERSONS CONTACTED
Licensee -
C. Bellamy, Chief of Security-
. G. Bouchard, Work Services Director
J. Bourasse,-Quality Assurance Supervisor
T. Cleary, Senior Licensing Engineer '
_ R. Crandall, Supervisor-Radiological Engineering
R. Gault, Radiation protection Supervisor
, J. Goergen, Assistant Health Physics Manager
.
G. Goncarovs, Chemistry Manager
~ W. Eakin, Senior Engineer, Radiological Engineering
D. Erickson, Acting Health Physics Manager
,
.J._ La Platney, Unit Director
T. Mc Cance, Nuclear Licensing
' J. Pandolfo, Security Manager
R. Sachatello, Radiation Protection Manager
J. Stanford, Operations Manager
M. Sweeney, Radiation Protection Services Supervisor
G. Waig, Maintenance Manager
.
G. van Noordennen, Licensing Manager
J. Warnock, Quality Assurance Manager
G. Wilson, Public Information
NRC
E. Conner, Haddam Neck Project Manager
R. Nimitz, Senior Radiation Specialist
L. Peluso, Radiation Physicist
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INSPECTION PROCEDURES USED I
IP 40500: Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing
Problems
IP 62703: Maintenance Observation
IP 64704: Fire Protection Program
IP 71707: Plant Operations
IP 73051: Inservice inspection - Review of Program
IP 73753: Inservice Inspection
. IP 83729: Occupational Exposure During Extended Outages
IP 83750: Occupational Exposure
, IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor l Facilities
IP 92902: Followup - Engineering
IP 92903: Followup - Maintenance
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
ITEMS OPEN, CLOSED, AND DISCUSSED
Open
97 01-01 URI Control of systems in Defueled Mode
97-01-02 VIO Failure to Follow Procedures (Multiple)
97-01-03 URI Inaccurate Operator Training Records
97-01-04 URI Deficiencies in Material Conditions
97-01-05 VIO Failure to Complete TS Surveillance
97-01-06 VIO Failure to Correct Adverse Conditions
97 01 07 URI Actions to Address SW Waterhammer
97 01-08 URI Actions to Address SW Corrosion
97-01-09 URI Actions to Address Design Basis Discrepancies
97-01-10 IFl Compliance with 40 CFR 190 not verified
97-01-11 URI Review Release of Contaminated Material
97-01-12 URI Training to Operate Waste Sorting Table
Closed
94-21-01' VIO Inadvertent Boron Dilution
94-27-01 URI Loss of Electrical Separation
94-011-00 LER. Unplanned Loss of Gpent Fuel Cooling
94-015-01 LER Main Steam Valves Exceed Lift Setpoints
96-08 01 IFl RHR Calibrations and Leakage
95-023-00 LER Failure to Prepare Special Report
96-201-10 URI Alternate Auxiliary Feedwater Sources
96 015-00 LER Containment Air Monitor Trip Valve
196-01-01 IFl Cable Vault Materials Condition
96-04-02 DEV Heavy Load Program Commitments
96-08-04 ' ICI Auxiliary Feed Water Overspeed Trip
96-08-05 IFl Steam Generator Hold Down Bolts
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; 96-08-06 lFl Observations of Procedural Quality
- 94-27-04 URI Surveillance Frequency Exceeded ,
i 94-09-03 IFl HPSI Relief Valve Setpoint Drift l
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96-04-03 VIO Inadequate Safety Evaluation
96-04-04 IFl Heavy Load Controls
4 96-201-12 URI Analysis Supporting LPSI Pump Shutdown
96-201-31 URI RWST 'astrument Calibrations
1 96-030-00 LER Woiker Contamination in Reactor Cavity
I Discussed
- 96-02-03 URI Control Room Habitability l
j 96-06-06 URI Battery Oscillations and Ground
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96-08-15 URI Start-up issues (7/24/95 NRC Lauer)
; 96-12-01 URI Exposure Assessment
- 96-12-02 URI Review of dose calculations for two workers who entered the fuel
transfer canal on November 2,-1996. t
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LIST OF ACRONYMS USED
ACM Administrative Control Manual :
'
ACP Administrative Control Procedure
ACR Adverse Condition Report ;
ADM Administrative Procedure
AFW Auxiliary Feedwater
AITTS Action item Trending & Tracking System
ALARA As Low As is Reasonably Achievable ,
,
ANN Annunciator Response Procedure i
ANSI American National Standards institute
AOP Abnorma! Operating Procedure l
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AOV Air Operated Valve
ASME American Society of Mechanical Engineers
CAL Confirmatory Action Letter
CAR Containment Air Recirculation
CBT Computer Based Training
CEDE Committed Effective Dose Equivalent i
CFR Code of Federal Regulations
CHDP Chemistry Department
CHM Chemistry
CMP Corrective Maintenance Procedure
CMP Corrective Management Plan i
CO Control Operator
CYAPCo. Connecticut Yankee Atomic Power Company
CYDE CY Design Engineering
DCR Design Change Request
DCY Design Change Yankee
DDE Deep Dose Equivalent
DEV Deviation
DNO Do Not Use
ECCS Emergency Core Cooling System
EDAN Environmental Data Acquisition Network
EDG Emergency Diesel Generator i
ENG Engineering Procedure l
EOP Emergency Operating Procedure
ESP Environmental Services Procedures
EWR Engineering Work Request
F Fahrenheit ;
FSAR Final Safety Analysis Report !
GL Generic Letter
HP Health Physics
HPSI High Pressure Safety injection
IFl Inspection Followup item
IR inspection Report
IRT Independent Review Team
ISAP Integrated Safety Assessment Program i
KPl Key Performance Indicators
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LDB Licensing Design Basis
LDE- Lens Dose Equivalent ' i
- . LER Licensee Event Report l
L -LLD Low Level Dose !
LLRT' Local Leak Rate Testing .!
LNP Loss of Normal Power Event !
LPSI- Low Pressure Safety injection
Licensed Operator initial Training
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LOIT !
LORT. Licensed Operator Requalification Training
LOUT- . Licensed Operator Upgrade Training-
LPE = Liquid Penetrant Examination !
MCC Motor Control Center i
MIC. Microbiologically influenced Corrosion !
MMP. Meteorological Monitoring Program j
MRFF Maintenance Rule Function Failures i
NOP Normal Operating Procedure l
NGP- Nuclear Generation Procedure
NOP Normal Operating Procedure !
NOV Notice of Violation
. NPDES Nuclear Pollution Discharge Elimination. System -
NPSH' Net Positive Suction Head
NRC Nuclear Regulatory Commission
NRR - Nuclear Reactor Regulation l
NSO Nuclear Site Operator i
NS&O- Nuclear Safety and Oversight Organization !
NUS Nuclear Utilities Service !
ODCM Offsite Dose Calculation Manual l
ODM - Operations Department Memorandum j
OJT On the Job Training ;
PAB Primary Auxiliary Building !
PC Personal Computer !
PDR Public Document Room l
PIR Plant inspection Report !
PMMS Production Maintenance Management System !
PMP Preventive Maintenance Procedure l
PORC Plant Operations Review Committee {
POSL Production Operations Services Laboratory
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QA Quality Assurance
QAS Quality Assurance Surveillance
GC Quality Control i
RAB Radiological Assessment Branch l
RCA Radiological Controlled Area :
RCS: Reactor Coolant System !
REMODCM Radiological Effluent Monitoring and Offsite Dose Calculation Manual !
REMP Radiological Environmental Monitoring Program i
REOR Radiological Environmental Operating Report l
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RHR Residual Heat Removal
:RFO Refueling Outage
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RM Radiation Monitors l
RP&C Radiological Protection & Chemistry {
RWST Refueling Water Storage Tank i
- SDE Shallow Dose Equivalent -{
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SERO Site Emergency Response Organization ,
SFB Spent Fuel Building !
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SFP Spent Fuel Pool
SFPCS Spent Fuel Pool Cooling System ;
SM Shift Manager j
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SUR Surveillance Procedure i
SW Service Water
TEDE Total Effective Dose Equivalent
TLD Thermoluminescent Dosimeter 7
TMI Three Mile Island j
TPC Temporary Procedure Change
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TRM Technical Requirement Manual ;
<
TS Technical Specification i
TSS Technical Specification Surveillance !
UFSAR Updated Final Safety Analysis Report l
-UFSARCR Updated Final Safety Analysis Report Change Request - .{
URI Unresolved item !
UT Ultrasonic inspection .
VIO Violation
YAEL Yankee Atomic Environmental Laboratory
YTD Year to Date ;
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WCM Work Control Manual
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WL With Lockout
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Attachment 1
List of Procedures Reviewed
The following procedures were reviewed during this inspection as part of the review of
procedure quality and adequacy for plant shutdown operation.
Operating Procedures
NOP 2.6-1, Operation of the Control Air System, Revision 11
NOP 2.20-4, Hypochlorite System Operation, Revision 15 (TPC 97-10)
NOP 2.10-1, Spent Fuel Pit Cooling system Operation, Revision 14
NOP 2.9-3, Refueling Cavity Filling, Revision 24 (TPC 97-16)
ANN 4.7-23A, Spent Fuel Pit High Level, Revision 6
ANN 4.7-238, Spent Fuel Pit Low Level, Revision 6
ANN 4.7-14, Spent Fuel Pit High Temperature, Revision 6
NOP 2.24-1, Service Water System Startup, Revision 19 (TPC 96-787)
NOP 2.24-2, Service Water System Shutdown, Revision 14 (TPC 96-143)
NOP 2.24 3, Filtered SW System and Adams Filter Operation, Revision 17 (TPC 97-60)
NOP 2.15 3, Spent Fuel Building Ventilation Operation, Revision 14
Maintenance Procedures
PMP 9.2-20, Calibration of IST Gages, Revision 12
PMP 9.1-36, Service Water Pump Strainer Operation, Revision 9
PMP 9.1-31, Diesel In-Leakage and Fuel Oil Transfer Pump Availability, Revision 11
PMP 9.1-27A, Electric Fire Pump (P-4-1 A) Test, Revision 10
Surveillance Procedures
SUR 5.1-126, All Modes Locked Valve Checklist, Revision 24 (TPC 96-608)
SUR 5.1-104C, Boric Acid Flowpath Heat Trace Operabi!ity Test, Revision 1
ENG 1.7-114, inservice Test of Emergency Diesel Generator Heat Exchangers, Revision 9
SUR 5.1-153B, AC and DC Distribution Normal Configuration (Modes 5 and 6), Revision 5
SUR 5.7-148A, inservice Test of A, B, C, D Service Water Pumps, Revision 10
SUR 5.1-178, Emergency Diesel Generator EG-2B Manual Start and Loading, Revision 16
ENG 1.7-131, CY MIC Prevention, Monitoring, and Mitigation Program, Revision 3
ENG 1.7 65, Hydrostatic Pressure Tests, Revision 8
ST 11.7 201, Functional Testing of SW CV-963, Revision O
ST 11.7-203, SFP Heat Exchanger Temporary SW Supply Flow Test, Revision O
SUR 5.7-217, inservice Testing of SW Supply to SFP Cooling Check Valve, Revision 0,1
Administrative Procedures
ACP 1.2-6.5A, Station Procedures, Revision 0,1
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