IR 05000250/1993026
| ML17352A353 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 12/22/1993 |
| From: | Binoy Desai, Johnson T, Landis K, Moore L, Trocine L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17352A352 | List: |
| References | |
| 50-250-93-26, 50-251-93-26, NUDOCS 9401040018 | |
| Download: ML17352A353 (37) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTASTREET, N.W., SUITE 2900 ATLANTA,GEORGIA 30323-0199 Report Nos.:
50-250/93-26 and 50-251/93-26 Licensee:
Florida Power and Light Company 9250 West Flagler Street Miami, FL 33102 Inspection Conducted:
October 31 through November 27, 1993 Inspectors:
~c.
T.
P. Johnson, Senior Resident Inspector B. B. Desai, Resident Inspector Date Signed J~ 2-2-r" Date Signed Docket Nos.:
50-250 and 50-251 License Nos.:
DPR-31 and DPR-41 Facility Name:
Turkey Point Units 3 and '4 L
L. Trocine, Resident Inspector z~-zz.-
Date Signed Approved by:
. Moore, Reactor Inspector Plant Systems Section Divisi of R or Safety
.
D.
Lan is, Chief Reactor Projects Section 2B Division of Reactor Projects Date Si ned 2-ZZ Date Signed SUMMARY Scope:
This routine resident inspectors'ite in the areas of surveillance operational safety, plant events, were performed in accordance with Results:
inspection involved direct inspection at the observations, maintenance observations, and self assessment.
Backshift inspections NRC policy.
Within the scope of this inspection, the inspectors determined that the licensee continued to demonstrate satisfactory performance to ensure safe
'W01040018 931222 PDR ADOCK 05000250
The following non-cited violation was identified and reviewed during this inspection:
Non-cited Violation 50-250/93-26-02, mispositioned Chemical and Volume Control System clearance valves (section 6.2. 1).
The following inspector 'followup items were identified:
Inspector Followup Item 50-250,251/93-26-01, emergency containment cooler valve failures (section 4.2.1).
Inspector Followup Item 50-250,251/93-26-03, safety injection pump motor rotor bar cracking (section 7.2.2).
During this inspection period, the inspectors had comments in the following Systematic Assessment of Licensee Performance functional areas:
Plant 0 erations A non-cited violation was identified for failure to position five Chemical and Volume Control System valves in accordance with tagout instructions.
The licensee appropriately responded to this incident that highlighted a concern in the conduct of operations as it relates to attention to detail, as well as, a deficiency in the independent verification process.
As a result, managers provided shift coverage to observe, to provide feedback, and to enhance oversight of field operations practices (section 6.2.1).
Additionally, the working stations for the Unit 3 and 4 Assistant Nuclear Plant Supervisors were shifted to the control room to enhance the conduct and oversight of operations within the control room (section 6.2.2).
These activities appear effective in improving operator performance.
Deficiencies were identified relative to operation's knowledge and tracking of the availability of the post accident sampling system (section 6.2.3).
Deficiencies were noted in two off-normal operating procedures:
one dealing with the loss of control room annunciators (section 6.2.5)
and the other dealing with fire protection backup for the screen wash system (section 6.2.4).
Non-licensed operator rounds were effective in assuring that plant equipment and areas were periodically monitored (section 6.2.9).
aintenance and Surveillance Naintenance and surveillance testing activities were effectively performed (sections 5. 1 and 4.1, respectively).
The licensee is continuing to evaluate emergency containment cooler valve failures (section 4.2. 1),
and this item will be reviewed in a future inspection.
Instrumentation and Control troubleshooting activities regarding control rod position indication problems were well performed and were performed in accordance with approved procedures (section 5.2.1)
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n ineerin and Technical Su or t Strong system engineering involvement in plant operations and mainte-nance was noted (sections 6.2.3 and 7.2.2).
The licensee's Shift Technical Advisor program met NRC expectations.
The Shift Technical Advisors displayed strong and effective involvement and support in operations activities. (section 6.2.6).
Proactive and strong engineering support was noted in the establishment of a program to reduce the number of long-standing operator work-arounds (section 6.2. 10).
The licensee has appropriately responded to a rotor bar cracking issue associated with the safety injection pump motors (section 7.2.2); this item will-be reviewed in a future inspection.
Plant Su ort Radiolo ica Contro s
E er enc Pre aredness Secur t Chemistr Fire Protection Fitness For Out and Housekee in Co trois Special and periodic licensee written reports were appropriate (section 3.2).
The licensee effectively implemented an outage on one of two fire protection raw water tanks (section 6.2.4).
The health physics program was determined to be appropriately implemented; however, some minor weaknesses were noted (section 6.2.7).
The licensee performed satisfac-torily during an emergency preparedness drill (section 6.2.8).
The use of a biometric, hand geometry, personnel identification program for security access was well planned and smoothly implemented (section 6.2. 11).
The licensee was initially slow in establishing corrective actions for high radiation in the Unit 3 residual heat removal rooms (section 7.2.1).
REPORT DETAILS 1.0 Persons Contacted Licensee Employees
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- ¹
M. J.
R. J.
S.
M.
R. J.
R.
G.
P.
C.
G.
E.
D.
E.
H. H.
V. A.
J.
E.
J.
E.
R. S.
J.
D.
J.
Ma C. L.
L. W.
M. 0.
T. F.
D. R.
R.
E.
R.
N.
F.
R.
H. B.
E. J.
Bowskill, Reactor Engineering Supervisor Earl, Acting Site guality Manager Franzone, Instrumentation and Controls Maintenance Supervisor Gianfrancesco, Maintenance Support Services Supervisor Heisterman, Mechanical Maintenance Supervisor Higgins, Outage Manager Hollinger, Training Manager Jernigan, Operations Manager Johnson, Operations Supervisor Kaminskas, Services Hanager Kirkpatrick, Fire Protection/Safety Supervisor Knorr, Regulatory Compliance Analyst Kundalkar, Engineering Manager Lindsay, Health Physics Supervisor rchese, Site Construction Manager Howrey, Licensing Assistant Pearce, Plant General Manager Pearce, Electrical Maintenance Supervisor Plunkett, Vice President, Turkey Point Powell, Technical Manager Rose, Nuclear Materials Manager Steinke, Chemistry Supervisor Timmons, Security Supervisor Wayland, Maintenance Manager Weinkam, Licensing Manager Other licensee employees contacted included construction crafts-man, engineers, technicians, operators, mechanics, and electri-cians.
1.2 NRC Resident Inspectors
¹B. B. Desai, Resident Inspector
- ¹ T.
P. Johnson, Senior Resident Inspector
- ¹ L. Trocine, Resident Inspector 1.3 Other NRC Personnel on Site Note:
P.
M. Steiner, Operator Licensing Examiner, Operator Licensing Section, Division of Reactor Safety, Region II Attended exit interview on December 3, 1993 Attended exit interview on December 22, 1993 An alphabetical tabulation of acronyms used in this report is listed in the last paragraph in this repor.0 'lant Status 2.1 2.2 Unit 3 The unit operated at full power for the entire reporting period and has been on line since October 20, 1993.
Unit 4 The unit operated at full power for the entire reporting period and has been on line since August 17, 1993.
3.0 Onsite Followup and In-Office Review of Written Reports of Nonroutine Events and
CFR Part 21 Reviews (90712/90713/92700)
3.1 Inspection Scope Licensee initiated reports discussed below were reviewed.
The inspectors verified that reporting requirements had been met, root cause analysis was performed, corrective actions appeared appro-priate, and generic applicability had been considered.
3.2 3.2.1 3.2.2 3.2.3 Inspection Findings ECCS Annual Report The inspectors reviewed the licensee's annual report for 10 CFR 50.46, Acceptance Criteria for ECCS, dated October 29, 1993.
Analysis for both small and large break loss of coolant accidents met the acceptance criteria of less than 2200'F peak fuel clad temperatures.
The inspectors concluded that this report met the regulatory requirements for the annual report as well as the ECCS acceptance criteria.
October 1993 Honthly Operating Report The inspectors reviewed the report and determined it to be appro-priate.
Safeguards Event Log Entries The inspectors reviewed the report covering the period July 1 to September 30, 1993.
The inspector had no questions regarding this report.
4.0 Surveillance Observations (61726)
4.1 Inspection Scope The inspectors observed TS required surveillance testing and verified that the test procedures conformed to the requirements of the TSs; testing was performed in accordance with adequate
procedures; test instrumentation was calibrated; limiting conditions for operation were met; test results met acceptance criteria requirements and were reviewed by personnel other than the individual directing the test; deficiencies were identified, as appropriate, and were properly reviewed and resolved by management personnel; and system restoration was adequate.
For completed tests, the inspectors verified testing frequencies were met and tests were performed by qualified individuals.
The inspectors witnessed/reviewed portions of the following test activities:
procedure 3-0SP-75.7, Auxiliary Feedwater Train 2 Backup N, Test; procedure O-OSP-59.9, Computer Axial Flux Nonitor System; and procedure 4-0SP-55.1, Emergency Containment Cooler Operabil-ity Test.
The inspectors determined that the above testing activities were performed in a satisfactory manner and met the requirements of the TSs.
4.2 4.2.1 Inspection Findings Emergency Containment Cooler Valve Failures On November ll, 1993, during the performance of procedure 4-0SP-055.1, the 4B ECC outlet valve CV-4-2906 failed to open as required.
The B train of the ECC system was declared out-of-service, and a 72-hour action statement pursuant to requirements of TS 3.6.2.2 was entered.
A night order was put into effect on November 1,
1993, due to a recent failure of the ECC outlet valves to function during tests, and ILC was requested to troubleshoot and identify the cause of the failure.
The ECC system is an ESF system designed to remove containment heat as well as maintain containment pressure within acceptable limits following an accident.
The ECC outlet valves are butterfly valves whose operators use air pressure as the motive force.
The valve operator is equipped with an air accumulator that provides air pressure to operate the valve in the event of loss of instrument air.
Air to the valve operator is routed through ports of a pilot operated valve via a solenoid
"
operated valve which has to function to achieve valve motion.
The normal condition of these valves is:
solenoids energized, air pressure to actuators, and valves closed.
The safety condition of the valves is:
solenoids deenergized, no air pressure to actua-tor, and valves ope Of the four failures that have occurr'ed since August 1993, the licensee has attributed three to the solenoid valve and, one to the pilot operated valve.
All solenoid valves and the failed pilot valve were replaced.
The cause of the solenoid valve failures have not been determined, but the licensee suspects that time (i.e., time that the solenoid valve stays energized)
is a factor.
A root cause investigation with ASCO (solenoid valve vendor) is underway.
Pending the results, the licensee'as increased the frequency of ECC valve surveillances from monthly to weekly.
The inspectors discussed the failures with the licensee and viewed in-house tests that were performed.
The inspectors concluded that the licensee is appropriately pursuing this problem.
Pending feedback from ASCO and results from the increased surveillance, this issue will be tracked as IFI 50-250,251/93-26-01, ECC valve failures.
5.0 Haintenance Observations (62703)
5.1 Inspection Scope Station maintenance activities of safety-related systems and components were observed and reviewed to ascertain they were conducted in accordance with approved procedures, regulatory guides, industry codes and standards, and in conformance with the TSs.
The following items were considered during this review, as appro-priate:
LCOs were met while components or systems were removed from service; approvals were obtained prior to initiating work; activities were accomplished using approved procedures and were inspected as applicable; procedures used were adequate to control the activity; troubleshooting activities were controlled and repair records accurately reflected the maintenance performed; functional testing and/or calibrations were performed prior to returning components or systems to service; gC records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were properly implemented; gC hold points were estab-lished and observed where required; fire prevention controls were implemented; outside contractor force activities were controlled in accordance with the approved gA program; and housekeeping was actively pursued.
The inspectors witnessed/reviewed portions of the following maintenance activities in progress:
I ECC CV-4-2906 troubleshooting (WR No. 93-031146)
(Refer to section 4.2.1 for additional information.),
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5.2 5.2.1 Unit 4 control rod G-5 position indication troubleshooting (Refer to section 5.2.1 for additional information.),
RWT No.
2 repairs (Refer to section 6.2.4 for additional information.),
and 3A CCW heat exchanger service water side hydro-blasting.
For those maintenance activities observed, the inspectors deter-mined that the activities were conducted in a satisfactory manner and that the work was properly performed in accordance with approved maintenance" work orders.
Inspection Findings Rod Position Indication Troubleshooting The inspectors reviewed the licensee's process for troubleshooting control rod RPI problems.
Unit 4 experienced a drifting RPI for control rod G-5 during the period October 19-29, 1993.
The licensee declared this RPI inoperable and performed actions as required by TSs 3.1.3.1 and 3. 1.3.2.
This included a 4-hour check of all RPIs and periodic flux maps to assure that the rod G-5 remained in the full out position at 228 steps.
The inspector verified and documented these activities in NRC Inspection Report Nos. 50-250,251/93-24.
In contact and conjunction with Westinghouse, the licensee per-formed troubleshooting activities on RPI G-5 per procedure O-GMI-102.1, Troubleshooting and Repair Guidelines, per procedure HI-028.30, How to Handle RPI Trouble Calls, and per work order No.
93-028413.
These activities included a check of resistances and voltages on both the RPI system primary and secondary circuits.
The RPI system consists of a primary circuit with an AC voltage applied to the coil stack.
Depending on actual rod position, a
secondary induced AC voltage in the coil stack is displayed as rod position.
Licensee experience has indicated that faults in the field wiring and connectors has periodically caused RPI problems.
This was apparently due to contamination of connector pins from a re-designed connector.
The licensee is in the process of replacing these connectors.
FPL procedures allow a "zapping" type operation which puts several hundred volts DC through the primary or second-ary circuits in order to burn off potential contamination and clean any oxidation areas off of the field cables and the connec-tors.
Westinghouse has acknowledged this process at Tur key Point and at other similar facilities and has concluded that no detri-mental effects to the RPI system would occur.
After several operations of "zapping," the licensee was successful in cleaning the connector contacts, and the RPI for rod G-5
indicated normal (228 steps).
The licensee then successfully performed surveillance testing per procedure OP-1604. 1, Full Length RCC-Periodic Check, and declared the G-5 RPI operable on October 29, 1993.
The licensee is further developing and testing a circuit for a failed primary RPI coil.
In this case, a 117-volt AC power supply could be connected to the secondary circuit, and a conditioning circuit would then measure the output dependent on actual rod position.
Experiments were conducted during October and November 1993 and showed positive results.
The inspectors reviewed the related documentation and procedures, and discussed these issues and processes with licensee engineers, technicians and management personnel.
The inspectors concluded that the licensee appropriately implemented all related TS re-quirements and that the ISC troubleshooting was well controlled and performed in accordance with approved procedures.
6.0 Operational Safety Verification (71707)
6.1 Inspection Scope The inspectors observed control room operations, reviewed applica-ble logs, conducted discussions with control room operators, observed shift turnovers, and monitored instrumentation.
The inspectors verified proper valve/switch alignment of selected emergency systems, verified maintenance work orders had been submitted as required, and verified followup and prioritization of work was accomplished.
The inspectors reviewed tagout records, verified compliance with TS LCOs, and verified the return to service of affected components.
By observation and direct interviews, verification was made that the physical security plan was being implemented.
The implementa-tion of radiological controls and plant housekeeping/cleanliness conditions were also observed.
Tours of the intake structure and diesel, auxiliary, control, and turbine buildings were conducted to observe plant equipment conditions including potential fire hazards, fluid leaks, and excessive vibrations.
6.2 6.2.1 Inspection Findings Mispositions Valves And Independent, Verification Problems On November 1, 1993, operators found five valves in the CVCS system out of the position required by clearance order No. 0-93-10-054.
The five CVCS valves (1129, 1131, 1134A, 1134B, and 1138C) were required to be open.
However, they were found closed after they had been independently verified to be open as
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required by the clearance order.
The clearance was to accommodate a freeze seal to replace two valves on the A waste holdup tank portion of the CVCS system.
There were a total of approximately 25 valves that were required to be tagged under the clearance by non-licensed operators.
The mispositioned valves were identified by the licensee during a check prior to initiating work on the system.
The five mispositioned valves were to be left open as a
drain path for the freeze seal and did not affect operability of any safety-related systems.
Upon identification, the licensee stopped all work associated with the clearance and notified the appropriate supervisors.
A correc-tion was made to the clearance, and the five mispositioned valves were restored to their required positions.
A condition report (93-932)
was initiated to further investigate and correct the problem, and a night order discussing the event was also issued.
The following corrective actions were implemented as a result of this incident:
The NWE was required to triple verify all future clearances.
This was performed through November 22, 1993.
During this time, no further misalignments or problems with independent verification were identified.
All existing clearances on safety and radwaste systems were verified.
No problems were identified.
The importance of independent verification and self checking was discussed at each shift's turnover meetings.
A requirement to not sign clearance tags until the component is in the position required by the clearance was imposed.
Tags were modified to include space for the independent verifier's signature.
The two non-licensed operators involved in. the event were disciplined.
Additionally, the Plant General Manager issued an Operations oversight policy statement which included placing an addi-tional supervisor (ANPS or above)
on shift to ensure that Operations personnel understood and followed plant manage-ment expectations.
The inspectors reviewed the clearance associated with the freeze seal and walked down portions of the CVCS system affected by the clearance.
The five mispositioned valves are diaphragm valves with a rising stem that clearly indicates the position of the valve.
The inspectors believe that a possible contributor to the incident was that all the other valves associated with the clear-ance were required to be shut, and the operator performing the
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6.2.2 6.2.3 tagout did not pay enough attention to detail to recognize that the five valves were required to stay open per the clearance.
As for the independent verification, the two operators involved stated to licensee management that they had been performing the valve alignment together.
Licensee procedures and training require valve positioning and independent verification to be performed separately.
Thus, proper independent verification was not performed in this case.
This incident had no direct nuclear safety or personnel safety impact.
The operator's failure to properly position the five valves in accordance with the instructions provided in the tagout constitued a violation of NRC requirements to implement procedures.
This violation demonstrated a weakness in the conduct of operations as it relates to attention to detail.
Although, the independent verification process problem did not violation NRC requirements, a weakness in the independent verification process was hightlighted.
The inspectors recognized that licensee management took aggressive and immediate actions to curtail similar incidents.
These actions have since had a positive impact.
The licensee identified violation is not being cited because criteria specified in Section VII.B of the NRC Enforcement Policy were satisfied.
Thus, this violation is identified as NCV 50-250/93-26-02, Nispositioned CVCS clearance valves.
The inspectors will continue to review activities in this area.
Changes to ANPS Work Area As a result of the overdilution event discussed in NRC Inspection Report Nos. 50-250,251/93-24, the licensee made some changes with regard to the working area for the Unit 3 and Unit 4 ANPSs.
The working area was shifted from the back room within the control room to inside the control room panels area.
A temporary pedestal and chair were placed in each unit's control room to accommodate the change.
This change is on a trial basis, and based on experi-ence gathered from this, a permanent change may follow.
The inspectors believe that the increased presence of the ANPS in the control room control panels area will enhance the overall conduct of operations within the control room.
Post Accident Sampling System During routine safety reviews at the November 4, 1993, plan-of-the-day meeting, an inspector noted the shared Unit 3 and
PASS was out-of-service for testing.
The inspector noted that this status was documented on the chemistry status report but not on the equipment out-of-service report.
Further, the inspector checked with the control room, and operators were unaware of the PASS status.
In addition, there were no equipment out-of-service or operator log entries.
The ANPS immediately contacted chemistry and system engineering, and determined that PASS had been
6.2.4 out-of-service for one day due to troubleshooting of the flush flow line and valves.
On November 2, 1993, the licensee initiated work request No. 93-016235 to perform PASS flush flow troubleshooting.
This was in followup to a condition report (93-591) written to document the problem.
Since there were no TS action statements associated with PASS, no entries were made in any operator logs or the equipment out-of-service log.
Procedure O-ADM-213, Technical Specification Related Equipment Out-of-Service Logbook, required only equipment associated with TS action statements to be logged in the out-of-service log.
PASS is addressed only in the Administrative Controls Section of TSs (TS 6.8.4.d);
however, no action statements are required.
Thus, operations did not make any equipment out-of-service log entries.
The licensee completed the PASS work on November 5, 1993, and the system was returned to its normal standby service.
The inspector reviewed the PWO, UFSAR section 9. 13, TSs, procedure O-ADM-213, condition report No.93-591, and related PASS operating procedures.
In addition, the inspector discussed the issue with the system engineer.
The inspector also conducted in field walkdowns of PASS with the system engineer.
The inspector con-eluded that the PASS system engineer was very knowledgeable regarding system design and operation.
Regarding the equipment out-of-service log, the inspector dis-cussed the issue with operations and plant management.
The license agreed that PASS operability should be logged in the equipment out-of-service log even though no TS action statement exists.
The licensee initiated an Operations night order book entry and briefed each operating crew regarding this item.
The inspector concluded that the licensee was responsive and appropri-ately responded to this issue.
Fire Protection Raw Water Tank Outage On November 15, 1993, the licensee removed the No.
RWT from service to repair damage that occurred during the August 1992 hurricane.
This includes repairs to a bent pipe nozzle, damaged coating and panels, and the tank roof.
Licensee compensatory measures for the out-of-service RWT included establishing the screen wash system as the alternate supply per TS 3.7.8. l.a.,
which allowed this compensatory measure for an unlimited period of time.
The licensee established this backup per off normal operat-ing procedure O-ONOP-16.7, Screen Wash Emergency Makeup to the Fire Protection System.
The repairs are currently scheduled to take about three months.'oth fire pumps (electrical and diesel driven)
and the No.
Each RWT retains greater than 100 percent of the required capacity for the fire protection system.
RWT No.
1 was destroyed during the hurricane and was previously replace.2.5 The inspector reviewed the RMT outage schedule, work scope, and related PC/H (93-149); operations procedures including the ONOP; the TSA necessary for fire pump recirculation line changes; and the appropriate PSID and electrical drawings.
In addition, the inspector attended the PNSC meeting that reviewed and approved this activity; walked down the system and related system changes in the field; and discussed these activities with operators, fire protection personnel, engineers, and management.
During this review, the inspector noted that the ONOP would only be partially implemented.
The licensee installed the hose from.
the screen wash system to the fire header; however, the licensee did not open the appropriate tie valves.
Further the ONOP did not address simultaneous use of the screen wash system for screen backwashing and fire header supply.
The licensee acknowledged these issues and immediately initiated a procedure change (OTSC)
to include steps and notes that appropriately responded to the inspector's questions.
The inspector concluded that licensee activities in this area were appropriate.
Loss of Control Room Annunciators 6.2.6 During an emergency plan drill on November 9, 1993 (Refer to section 6.2.8 for additional information.),
one of the scenarios was a complete loss of Unit 3 control room annunciators.
The inspector noted that no ONOP existed for this plant condition.
The control room crew responded per procedure ARP-097.CR, Annunci-ator Response Procedure Hanual.
These response actions included event recognition and declaration, maintenance involvement, and increased equipment and panel surveillance by operators.
However, not all of these actions were addressed in procedure ARP-097.CR.
The NRC issued an Information Notice (IN 93-47)
on June 18, 1993 related to loss of annunciators.
Based on recent industry events, the IN recommended procedures for recognizing and responding to a loss of annunciators.
FPL initially reviewed this IN and concluded that they did not need an ONOP.
The inspector disagreed with this initial assessment and internal response.
Although the crew properly responded during the drill, a well written ONOP would aid crew response.
Additional licensee review concluded that an ONOP was necessary.
The inspector reviewed this final licensee internal IN response dated November 17, 1993, and concluded it to be appropriate.
The inspector will continue to follow this ONOP development.
Shift Technical Advisor The NRC issued an Information Notice (IN 93-81)
on October 12, 1993, regarding implementation of engineering expertise'n shift.
The licensee meets this requirement with an on shift STA.
The STA is on a 12-hour shift rotation (7:00 a.m. to 7:00 p.m.
and
7:00 p.m. to 7:00 a.m.) for seven consecutive days.
The licensee has eight qualified STAs, six of which are currently on shift rotation.
6.2.7 The licensee reviewed this IN and concluded that its program met NRC expectations.
To further address and document STA expecta-tions, the licensee issued an STA expectation memo dated October 20, 1993, and revised administrative procedure O-ADM-513, Duties and Responsibilities of the STA, on November 4, 1993.
These expectations included guidance in the following areas:
shift relief, tours, log reviews, turnover meetings, uniforms, beepers, emergency response, condition reports, gA records, daily trends, TS LCO hours, OTSC, operations support, training, schedule and daily reports.
The inspector reviewed the IN, the licensee's response dated November 18, 1993, the expectation memo, and procedure O-ADM-513.
The inspector concluded that the licensee's STA program meets NRC expectations.
However, the inspector did note that during, the 3:35 p.m. shift turnover meeting on October 15, 1993, the STA did not attend.
Existing procedures at that time did not require attendance because the STA is on a 12-hour rotation, and the STA had attended the 7:35 a.m. meeting.
Since then, the licensee has revised its procedures to require attendance at all shift turnover meetings.
The inspector noted that STA involvement in shift activities was strong and effective based on the following recent observations:
the STA's excellent knowledge and continued tracking of the Unit 3 unidentified RCS leak rate, effective STA participation in the simulator training and emergency preparedness exercise, and inspector interviews with most of the current STAs.
Health Physics Program Inspections The inspector reviewed the licensee's implementation of the HP program.
This included a review of the following administrative procedures:
O-ADM-600, Health Physics Manual; O-ADM-601, Health Physics Conduct of Operation; and O-ADM-604, Radiological Protec-tion Guidelines and Practices.
The inspector also interviewed HP technicians and radiation workers, observed in field work, and held discussions with HP and plant management personnel.
The inspector concluded that the HP program is being appropriately implemented.
Some minor deficiencies were identified.
These included inconsistencies with the placement of dosimetry devices on individuals, with contamination area and step-off pad markings, and with frisking activities.
Further, the inspector noted that a
few plant areas remained contaminated that adversely affect operator rounds.
These areas included the charging pump rooms, two of the RHR pump rooms, and portions of the piping and valve penetration rooms.
All of these areas are located in the
6.2.8 6.2.9
auxiliary building.
These issues were discussed with licensee management personnel.
The inspector will continue to review these issues in future inspections.
Emergency Plan Drill The inspectors observed portions of an announced emergency plan drill that was conducted on November 9, 1993.
The inspectors monitored drill performance from the control room simulator and the TSC.
The inspectors concluded that drill performance was satisfactory and that the licensee effectively conducted and critiqued drill performance.
Specific issues noted included the lack of procedure (ONOP) for loss of control room annunciator alarms (Refer to section 6.2.5 for additional information.),
a slow fuel damage assessment by the TSC/EOF, and information missing from TSC status boards.
The inspector discussed these issues with emergency preparedness personnel and drill participants.
The inspector will review these issues during future drills and during the graded annual exercise.
Operator Rounds and Tours The inspectors assessed the conduct of non-licensed operator periodic rounds and tours.
This included the NPO rounds in the turbine building, the SNPO rounds in the auxiliary building (both inside and outside),
and the NPO rounds in the water plant.
The inspectors reviewed instruction ODI-C0-003, gualification and Use of Trainees On Shift, dated September 27, 1993.
This document specifies good watchstanding practices to be performed for each area covered in the specific operator round.
The inspectors also reviewed the NPO and SNPO log sheets which document specific readings taken during the rounds.
The inspectors accompanied selected operators'ounds for all areas and interviewed non-licensed operators, licensed operators, and Operations management personnel.
The inspectors noted that all rounds were professionally conducted and performed per instruction ODI-CO-003 and that readings were logged as required.
Abnormal readings and noted deficiencies were brought to the attention of control room personnel.
The inspectors concluded that non-licensed operator rounds were effective in assuring that plant equipment and areas were appropriately monitored and that abnormal conditions were identified and appropriately communicated to the control room for action.
6.2. 10 Engineering Review of Operator Work-Arounds The licensee's engineering organization recently began a program to identify and correct long-standing operator work-arounds.
Operator work-arounds are existing equipment or design deficien-cies in the plant that require operations personnel to perform
special or additional actions in order to do their normal job functions.
For example, a control valve that is not functioning in automatic requires operators to compensate for this and to perform manual actions.
The engineering organization coordinated a survey with operations to obtain a current scope of operator work-arounds.
This survey then became a working list of items which were initially and then periodically reviewed by engineering and operations.
To date,
issues were identified and tracked, with 3 items closed.
Engineering also reviewed these items for safety system operability impact.
No operability issues were identified.
The inspector reviewed the operator work-around list and met with engineering personnel.
The inspector reviewed selected items, and did not identify any safety system operability issues.
The inspector concluded that the program appears to be effective and demonstrates a proactive'pproach by engineering to resolve operational deficiencies and related issues.
Implementation of Biometric Access Control System Effective November 12, 1993, the licensee implemented a biometric access control system at the main entrance point into the plant protected area.
This system employs scanners that use hand geometry as the basis for personnel identification.
Under the old system, unescorted access into the plant protected area was controlled through the use of a photograph on the badge along with a personal identification number.
The hand geometry scan replaced the personal identification number as a means of identification.
Currently, the badges are still issued, stored, and retrieved at the entrance/exit point.
However, following approval to the requested exemption from certain requirements of 10 CFR 73.55 from the NRC, the badges will no longer be stored at site, and individ-uals will be allowed to take the badge offsite. It should be noted that wearing of the badge in the protected area and access to vital areas is not affected by this change.
The licensee received this exemption in a letter dated November 29, 1993.
Since the implementation of the hand geometry scan, there have not been any reportable or loggable events associated with personnel
'ccess control, and the change has gone smoothly.
Turkey Point is the first plant in the country that is utilizing the biometric access control system.
6.2.12 General Results As a result of routine plant tours and various operational obser-vations, the inspectors determined that the general pla'nt and system material conditions were satisfactorily maintained, the
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plant security program was effective, and the overall performance of plant operations was good.
7.0 Plant Events (93702)
7.1 7.2 7.2.1 Inspection Scope The following plant events were reviewed to determine facility status and the need for further followup action.
Plant parameters were evaluated during transient response.
The significance of the event was evaluated along with the performance of the appropriate safety systems and the actions taken by the 1'icensee.
The inspec-tors verified that required notifications were made to the NRC.
Evaluations were performed relative to the need for additional NRC response to the event.
Additionally, the following issues were examined, as appropriate:
details regarding the cause of the event; event chronology; safety system performance; licensee compliance with approved procedures; radiological consequences, if any; and proposed corrective actions.
Inspection Findings Unit 3 RHR Room High Radiation During a routine tour of the auxiliary building, the inspector noted that the Unit 3 RHR rooms were posted as high radiation areas due to a 10 times increase in general area radiation levels.
The inspector questioned the cause for this increase.
The inspec-tor determined that during the Unit 3 short notice outage (Refer to NRC Inspection Report Nos. 50-250,251/93-24 for additional information.),
a crud burst occurred that was not cleaned up by the CVCS.
The inspector questioned HP personnel regarding this issue and noted that no condition report had been generated.
A review of procedure O-ADM-518, Condition Reports, enclosure 1,
Guidance for the Issuance of Condition Reports, did not indicate that a condition report was required.
However, after discussion with licensee management, a condition report (93-899)
was written to capture this event and to determine root cause and corrective actions.
I The licensee completed condition report No.93-899, and plant management approved it on November 17, 1993.
The licensee deter-mined that the cause of high radiation in the RHR room was the securing of the CVCS deminer alization during the shutdown/cooldown for the short notice outage of October 1-7, 1993, to repair the pressurizer manway leak.
Lack of procedural guidance and poor communication among the outage group, operations, chemistry, and HP apparently occurred.
Licensee corrective actions included revision of plant shutdown, plant cooldown, and CVCS operating procedures to include CVCS demineralizer requirements for radioac-tivity cleanup after a crud burst; minimization of work activity and monitored personal exposures in the RHR rooms; and development
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of a temporary procedure to flush the RHR system in order to remove the high radioactivity and to reduce area dose rates.
The inspector reviewed the condition report, related radiation surveys, the revised procedures, the TP, related correspondence and documentation, and appropriate dose records.
The inspector also discussed the event with operators, HP personnel, chemistry, and management personnel.
The inspector concluded that personnel were "initially slow in performing a root cause analysis and in identifying appropriate corrective actions.
However, once a
condition report was written and the appropriate personnel became involved, an aggressive and thorough detailed'vent review includ-ing root causes assessment and corrective action initiation was performed.
The inspector will continue to follow licensee actions in this area, including high dose rate controls and elimination activities.
7.2.2 Broken Rotor Bars on 4A Safety Injection Pump Motor On or about November 4, 1993, the licensee was informed by Westinghouse that during the inspection of a SI motor, 5 of its 46 rotor bars were found broken and/or cracked.
This motor had served the 4A SI pump and had been removed for inspection in March 1993.
A new spare motor was installed on the 4A SI pump following the removal of the old motor which was later found to have broken and/or cracked rotor bars.
The 3A, 3B, 4B, and the old 4A SI pump motors are 2-pole, 350-hp, 4. 16-kv motors with 509-US frames.
The currently installed 4A SI pump motor is a newer design with a 5009-HZ frame.
The SI system is a safety-related system with the four SI pumps shared by both units.
The SI pumps are normally in the standby mode.
They are run during performance of periodic surveillances and system tests.
The SI pumps are also routinely used to refill accumulators which are passive ECCS components.
A condition report (93-953)
was initiated by the licensee as a result of this discovery.
Additionally, Westinghouse was requested by the licensee to provide a written evaluation addressing past operability of the subject motor, operability of the existing three motors of the older design, other industry experience on cracked rotor bars, and on-line techniques to detect cracked or broken rotor bars.
The cause of the rotor bar cracking and/or breaking was determined by Westinghouse to be due to deflection of unswaged rotor bars.
Unswaged bars are bars that have been put in a designated slot and only secured at the ends by a brazed joint.
During motor starting conditions and prior to achieving full running speed, cyclic loading of the rotor bars occurs due to slip-related field fluctu-ations.
This produces the potential for fatigue-type failures at the edge of the brazed slot.
The number of starts on a motor is
directly related to the probability of fatigue-related rotor bar failures.
Based on experience and available data, Westinghouse believes that rotor bar cracking due to fatigue is a slow process and that it takes approximately 3000 starts for a 4 second acceleration speed to cause cracking.
The 4A SI motor had experienced approximately 2400 starts.
The new 5009-HZ design motor, which is currently, installed on the 4A SI pump, employs a swaging technique to better secure the rotor bars.
These motors are expected to exceed 50,000 starts before signs of any fatigue-related cracking are expected.
With regard to past operability of the 4A SI pump/motor, based on evaluation provided Westinghouse, the licensee concluded that the 4A SI pump/motor would have started and operated at rated load as required to perform its safety-related function.
This conclusion was based on visual evidence suggesting no movement of the rotor bars from the original position.
Additionally, there was no evidence of arcing.
A review of past experience with cracked rotor bars indicated that Indian Point 2 had experienced a failure of a safety-related motor due to arcing in 1981.
This arcing was caused due to a fractured and bent rotor bar which deflected outward through the air gap and shorted against the motor stator.
The motor vibration readings had been reading 5 mils (expected value 1.5 mils) for several months.
Twelve bars on this motor were found to have completely separated from the resistance ring, and many bars were found with cracks.
Other industry motors, including one at Turkey Point, were also found to have cracked rotor bars.
No other motor except the one at Indian Point resulted in a failure of the motor.
Currently at Turkey Point, the motor s on the 3A, 3B, and 4B SI pumps do not have swaged rotor bars.
The licensee has estimated that the 3A motor, which was overhauled in 1984, has had approxi-mately 1080 starts.
The 3B motor, which was inspected in 1988, has had approximately 2400 total starts of which 600 have been since the 1988 inspection; and the 4B motor, which has never been inspected, has also had approximately 2400 starts.
The licensee, based on recommendation from Westinghouse, deter-mined that these motors were operable.
The basis for this deter-mination was motor vibration trends which have remained stable and below 3.0 mils for the past 4 years.
The licensee will monitor and trend motor vibration data on a quarterly basis to identify any changes.
A horizontal motor vibration threshold of 3.0 mils
&as recommended by Westinghouse.
Beyond this, an evaluation is recommended to determine operability.
Additionally, the licensee is administratively preventing the use of the 3A, 3B, and 4B SI pumps for accumulator refills.
A night order and information tags are in place informing that only the 4A SI pump be used to perform accumulator refill ~
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The licensee tentatively has plans to replace and/or overhaul the 3A, 3B, and 4B at the next available opportunity.
The exact date for the replacement will be determined during the disposition of the fore-mentioned condition report.
It should be noted that a
spare SI pump motor of the new design is currently on site if an immediate need arises.
Pending the resolution of the condition report and the inspection data obtained for the remaining three motors, this issue will be classified as IFI 50-250,251/93-26-03, SI pump motor rotor bar cracking.
A review of other systems pertaining to possibility of similar problems with rotor bar cracking was also performed by the licensee.
At Turkey Point all other safety-related motors with the exception of the containment spray pump motors employ four poles.
The higher number of poles reduces the likelihood of rotor bar cracking as the slip loading and'he mound of deflection is reduced.
The containment spray pump motors which are two pole have substantially fewer starts as well as fewer hp/pole (120 hp/pole versus 175 hp/pole for the SI motors).
Therefore, in licensees judgement, susceptibility of the containment spray motors to experience similar problems is low.
The inspectors, including regional specialists, discussed this issue with the licensee, reviewed the condition report which included the evaluation performed by Westinghouse, and reviewed past IST data associated with the SI pumps.
The inspectors believe that the licensee's actions pertaining to this matter are appropriate.
The inspectors will continue to monitor this issue through the IFI.
8.0 Exit Interview The inspection scope and findings were summarized during management interviews held throughout the reporting period with the Site Vice President and selected members of his staff.
Exit meetings were conducted on December 3 and 22, 1993.
The areas requiring management attention were reviewed.
The licensee did not identify as proprietary any of the materials provided to or reviewed by the inspectors during this inspection.
Dissenting comments were not received from the licensee.
The inspectors had the following findings:
Ite umber 50-250,251/93-26-01 50-250,/93-26-02 50-250,251/93-26-03 es t'o ere ce IFI -
ECC valve failures (section 4.2.1).
NCV - Mispositioned CVCS clearance valves (section 6.2.1).
IFI - SI pump motor rotor bar cracking (section 7.2.2).
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9.0 Acronyms and Abbreviations
AC ADH ANPS ARP ASCO CCW CFR CR CV CVCS DC ECC ECCS EOF ESF oF FPL GHI HP hp I&C IFI IN IST kv LCO
. MI mil N2 No.
NPO NRC NWE ODI ONOP OP OSP OTSC P&ID PASS PC/H PNSC PWO QA QC RCC RCS RHR RPI Alternating Current Administrative Assistant Nuclear Plant Supervisor Annunciator Response Procedure Automatic Switch Company Component Cooling Water Code of Federal Regulations Control Room Control Valve Chemical
& Volume Control System Direct Current Emergency Containment Cooler Emergency Core Cooling System Emergency Offsite Facility Engineered Safety Feature Degrees Fahrenheit Florida Power
& Light General Maintenance I&C Health Physics horse power Instrument
& Control Inspector Followup Item Information Notice (NRC)
Inservice Test Kilovolt Limiting Condition for Operation Maintenance Instruction Millionths of an Inch Nitrogen Number Nuclear Plant Operator Nuclear Regulatory Commission Nuclear Watch Engineer Operation Department Instruction Off Normal Operating Procedure Operating Procedure Operations Surveillance Procedure On-the-Spot Change Piping and Instrumentation Diagram Post Accident Sampling System Plant Change/Modification Plant Nuclear Safety Committee Plant Work Order Quality Assurance Quality Control Rod Control Cluster Reactor Coolant System Residual Heat Removal Rod Position Indication
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RWT SI SNPO STA TP TS TSA TSC UFSAR WR
Raw Water Tank Safety Injection Senior Nuclear Plant Operator Shift Technical Advisor Temporary Procedure Technical Specification Temporary System Alteration Technical Support Center Updated Final Safety Analysis Report Work Request