IR 05000250/1997013
| ML17354A815 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 02/19/1998 |
| From: | Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17354A813 | List: |
| References | |
| 50-250-97-13, 50-251-97-13, NUDOCS 9803040213 | |
| Download: ML17354A815 (57) | |
Text
U. S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos.:
License Nos.:
50-250 and 50-251 DPR-31 and DPR-41 Report Nos.:
Licensee:
50-250/97-13 and 50-251/97-13 Florida Power and Light Company Facility:
Turkey Point Units 3 and 4 Location:
9760 S.
W. 344 Street Florida City, FL 33035 Dates:
December 14, 1997
- January 24.
1998 Inspectors:
T.
P. Johnson, Senior Resident Inspector J.
R.
Reyes, Resident Inspector J. J. Blake. Division of Reactor Safety (DRS) Inspector (Sections M2. 1 and M7.2)
R.
F. Aiello. DRS Inspector (Sections 05. 1
- 05.4)
P.
M. Steiner
.
DRS Inspector (Sections 05. 1 - 05.4)
Approved by:
K. Landis, Chief. Reactor Projects Branch
Division of Reactor Projects 98030402i3 9802i9 PDR ADOCK 05000250
EXECUTIVE SUMMARY TURKEY POINT UNITS 3 and
Nuclear Regulatory Commission Inspection Report 50-250.251/97-13 This integrated inspection to assure public health and safety included aspects of licensee operations'aintenance.
engineering.
and plant support.
The report covers a six week period of resident inspection.
In addition. the report includes regional announced inspections of maintenance and operator licensing requalification programs.
Operations Operations demonstrated good knowledge and was well prepared for operating the units in a cold weather environment; however.
a weakness was identified in that no formal guidance existed on how to measure refueling water storage tank solution temperature (Section 01. 1).
The energization of each units'oltage regulator power system stabilizers was well planned and thoroughly briefed, with strong coordination and oversight noted (Section 01.2).
The auxiliary feedwater systems were appropriately aligned for both units.
The licensee maintained very good configuration control for these safety-related and risk significant system (Section 02. 1).
t The seismic instrumentation system was appropriately aligned and maintained (Section 02.2).
A non-cited violation was identified for failure to provide adequate procedures and document controls (Section 03. 1).
The facility's philosophy of safe reactor operation was supported and reinforced by training and consistent conservative decision making (Section 05 overall).
An unresolved item was identified pending NRC's review to determine if a Part 55 licensee's medical condition is potentially disqualifying (uncorrected)
such that a license condition must be placed on the individual's NRC operating license (Section 05. 1).
The inspectors determined that the licensee was effective in conducting remedial written and operating examinations to ensure operator mastery of the requalification training program content (Section 05.2).
The inspectors determined that the licensee was effective in conducting written and operating examinations to ensure operator understanding of the requalification training program content (Section 05.3).
The inspectors concluded that all personnel received equal hours of training relative to the active watchstanders and that the total number of hours were in accordance with NRC expectations (Section 05.4).
Plant Manager "all-hands" employee briefings were well performed, self-critical and these meetings demonstrated a strong self-assessment capability (Section 07. 1).
~
The licensee's self-assessment capability was demonstrated to be very good as evidenced by effective safety committee performance.
and by senior corporate and plant management involvement (Section 07.2).
Maintenance Instrumentation and Control personnel were very knowledgeable regarding the operation and calibration of the seismic monitoring system (Section 02.1).
~
Observed Maintenance and Surveillance activities were well performed (Section H1.1).
~
The Intake Cooling Water pump surveillance continues to be one of the most challenging surveillance for Operations.
Excellent technical support by engineering was noted.
A lack of questioning attitude was noted when Operations personnel were performing the surveillance using flow gauges which had deficiency tags and had not questioned the operability of the flow gauges.
However,, heightened management involvement and testing performed by very well experienced Operations personnel'rovided for an excellent test which was performed on January 16, 1998 (Section M1.2).
The maintenance histories for the charging pumps and the component cooling water pumps and heat exchangers indicated an improvement in the material condition of these components during the past two years (Section H2.1).
Quality Assurance was noted as being active in identifying weaknesses in plant work order documentation accuracy and completeness (Section M7. 1).
The licensee's Quality Assurance personnel provide real-time quality assessments through a continuing surveillance program (Section H7.2).
A non-cited violation of NRC requi rements was identified when the licensee used some plant installed gauges that were not in a calibration program to perform Technical Specification surveillances.
The previous unresolved item was closed (Section H8. 1).
En ineerin
~
Efforts to remove the auxiliary feedwater turbine electrical over speed trip device were well performed. with strong coordination among all site disciplines (Section E2. 1).
Engineering was well focused towards a reliability issue for the auxiliary feedwater system.
A temporary system alteration to modify the
instrument air filter configuration was appropriately implemented.
and excellent work coordination was observed (Section E2.2).
Engineering performed a good evaluation and documentation of the instrumentation and showed that there existed no functionality concerns associated with operating the reactor coolant pump number one seal differential pressure indicators and the narrow range pressure indicators in a long term pegged high condition (Section E2.3).
Plant Su ort Site radiation dose reduction initiatives remained strong and focused.
Areas for improvement are being appropriately pursued (Section Rl. 1).
The licensee was proactive in upgrading the radiation controlled area control point (Section R2. 1).
The inspectors identified weaknesses in the workers implementation of the licensee's radiological programs.
Examples included radiation work permit knowledge and in contamination control (Sections R4. 1 and R4.2).
A new radiation protection manager met the regulatory qualification requirements (Section R6. 1).
The licensee's operating experience feedback system was strong as evidenced by security's response to a potential weakness in explosive detector performance (Section S2. 1).
The licensee appropriately reported a fitness for duty event (Section S4.1).
The fire brigade and the support groups were appropriately exercised during drills (Section F5. 1).
TABLE OF CONTENTS Summary of Plant Status..
I.
Operations II.
Maintenance
..13 III.
Engineering
IV.
Plant Support
V.
Management Meetings.
Partial List of Persons Contacted.
List of Inspection Procedures Used.
List of Items Opened, Closed and Discussed Items List of Acronyms and Abbreviations
28
29
Summa of Plant Status Unit 3 REPORT DETAILS At the beginning of this reporting period. Unit 3 was operating at or near 100K reactor power and had been on line since August 14.
1997.
The unit operated at full power during the period.
Unit 4 At the beginning of this reporting period. Unit 4 was operating at or near 100K reactor power and had been on line since October 14.
1997.
The unit operated at full power during the period.
I. 0 erations
Conduct of Operations 01. 1 Cold Weather Pre arations a.
Ins ection Sco e
71714 The inspectors assessed the licensee's readiness for operation in a cold weather envi ronment.
b.
Observations and Findin s Actions taken to address operation in cold weather conditions were described in procedure O-ONOP-103.2.
Cold Weather Conditions.
The licensee enters this procedure if any of the following conditions are found:
1)
auxiliary building temperature less than 65'F. or 2)
actual outside air temperature less than 55', or 3)
outside air temperature is predicted to go below 32'F.
The licensee used this Off-Normal Operating Procedure (ONOP) to ensure compliance with Technical Specification (TS) 3.5.4 and 4.5.4.
Refueling Water Storage Tank (RWST):
and TS 3. 1.2.4 and 4. 1.2.4.
Borated Water Source.
In addition. the ONOP provided guidance for protection of other plant equipment under cold weather conditions.
Outside air and auxiliary building temperatures were measured daily as part of the regular Senior Nuclear Plant Operator (SNPO) log readings.
In addition, control room annunciator X 7/6. Boric Acid Ambient Temperature Monitoring Trouble.
alarms if temperature falls below 60'F.
Outside air temperature was measured at 12:00 a.m..
8:00 a.m..
and 4:00 p.m..
Auxiliary building temperatures were measured at 4:00 a.m.
and 4:00 p.m.
Increased temperature measurements were made at the Nuclear Plant Supervisor (NPS) discretion, based on expected weather condition The SNPOs used forms 418 and 419 to measure the auxiliary building and outside air temperatures, respectively.
There were four temperature measurements taken throughout the auxiliary building.
If any temperature fell below 65'F.
then the instructions requested the operator to inform the NPS and refer to the cold weather condition ONOP.
At each of the four locations.
there was one temperature element and one temperature indicator.
The temperature elements transmitted a signal to and were read from the R74 recorder.
and the temperature indicators were used as a backup temperature measurement if the recorder was out of service.
Also. the R74 recorder transmitted a signal to the control room annunciator panel X for window 7/6.
During the SNPO log readings, if outside air temperature was less than 43'F
~ the instructions requested that the RWST temperature be measured to determine if it was within limits.
Additionally. if the RWST temperature was determined to be less than 43'F. then the instructions requested the SNPO to inform the NPS and refer to procedure 0-ONOP-103.2.
Howevers the inspectors found that neither form 419 nor the cold weather ONOP gave guidance on how to measure the RWST temperature.
The inspectors discussed the RWST temperature measurement method with various operations personnel.
and questioned the on-shift control room operators including the Watch Engineer and the NPS.
The inspectors determined that Operations did not have a prescribed method of measuring the RWST temperature.
Various "potential" methods were described.
Operations finally took the position that if the RWST solution temperature needed to be taken, they would call on engineering to request guidance on the method to take the measurement.
The licensee subsequently wrote a condition report (CR No. 97-2074) to address the RWST temperature measurement method and to add that guidance to the SNPO logs and to the cold weather condition ONOP.
The inspectors found that the SNPOs regularly used data loggers instead of the hard copy forms.
The hard copy forms would be used if the data loggers were not available.
The procedures on forms 418 and 419 were reviewed and compared with the procedures in the data logger, and the inspectors verified that the information and instructions (relating to cold weather)
were consistent.
Also. the inspectors walked the Auxiliary building and RWST temperature measurement areas with SNPOs and noted that the SNPOs had good knowledge of the cold weather preparation requirements and were well versed with the procedures.
All the temperature elements'ndicators, and the R74 recorder were found to be in good condition and no outstanding PWOs were noted.
Additionally. the inspectors verified that the heaters and electrical extension cords were stored in the Boric Acid Storage Tank room and were available for operation as required by the cold weather ONOP.
The inspectors reviewed the calibration for the R74 recorder and the temperature indicators.
All the temperature indicators were found to be in the calibration Preventive Maintenance (PM)
program and were within their calibration periodicity.
However. it was noted that the
indicators had recently been added to the PM program as a result of a calibration PM program review which the licensee had recently completed (see Section M8. 1).
Further.
inspection of procedure O-PME-048.2.
Boric Acid Ambient Temperature Recorder Calibration: drawing 5610-E-1734.
Boric Acid Ambient Room Air Temperature Recorder:
and review of the history of preventive maintenance calibration on the R74 recorder revealed that the temperature elements which transmitted a signal to the R74 recorder were not included in the procedure which calibrated the recorder.
Additional discussions were held with engineering, and the inspectors questioned the justification for excluding the temperature elements in the calibration of the recorder.
Engineering performed a
review of the calibration of the recorders the sensing elements, and the overall temperature measurement application, and subsequently described that the sensing elements were copper-constantan thermocouples.
Based on the review, which included the thermocouple materials, sensor packaging'he low temperature and non-harsh environment being sensed.
i.e.-
~ the auxiliary building temperatures.
discussions with the licensee's thermocouple vendor, and additional temperature data review.
engineering concluded that it was not warranted to include the thermocouples in the calibration of the R74 recorder.
The inspectors reviewed engineering's findings and data and concluded that for this particular application. calibrating the R74 recorder without the thermocouples was acceptable.
Conclusions The licensee demonstrated good knowledge and was well prepared for operating the units in a cold weather condition.
The instrumentation and equipment required for cold weather operation was verified to be in good condition.
However, the inspectors identified a weakness in the cold weather ONOP in that Operations could not provide a consistent method of measuring the RWST solution temperature.
Power S stem Stabilizer PSS Ener i zations 71707 On January 7.
1998. the licensee successfully energized the PSSs f'r both units.
The PSSs were previously tested in October 1997 (reference NRC Inspection Report No. 50-250.251/97-11).
The PSS supplements the main.generator voltage regulation ci rcuitry to dampen potential generator rotor swings.
Prior to energizing the PSSs.
the licensee performed administrative procedure 0-ADM-217. Conduct of Infrequent Tests and Evolutions.
Briefings were held by the NPS and engineering support was provided.
Further. off normal operating procedures 3/4-ONOP-090.
Abnormal Generator Mega Watt/Mega Volt-Ampere Reactive (MW/MVAR) Oscillation. were developed and operators were appropriately trained.
The inspectors attended the pre-evolution briefing, reviewed the ONOPs, observed the energization activities'nd discussed the process with operators and engineers.
Training Brief No.
708 was developed by the nuclear training department to promulgate both the PSS information and the new ONOP.
The inspectors concluded that the process was well
02.1 planned and briefed.
and strong oversight and coordination were provided.
Operational Status of Facilities and Equipment Auxiliar Feedwater AFW S stem Walkdowns 71707 During the period, the inspectors performed several walkdowns of the Unit 3
~ Unit 4.
and common portions of the AFW systems.
Field verifications of valve positions were performed using system lineup sheets and piping diagrams.
Walkdowns were performed after planned maintenance and testings temporary system alteration (TSA) activities.
and modification work.
These activities are described in sections Ml.1, E2. 1.
and E2.2 of this report.
The inspectors concluded that the licensee maintained very good configuration control of these safety related and risk significant systems.
The AFW systems for both units were appropriately aligned for automatic initiation.
02.2 Seismic Instrumentation Walkdown Ins ection Sco e
71707 The inspectors reviewed 'the requirements for seismic instrumentation and performed a Walkdown of the system.
Observations and Findin s UFSAR section Appendix 5A delineates the requirements and states that a
three axial component seismograph or a strong motion accelerograph model 1 (SMA-1) is located in the Unit 3 electrical penetration room at
'elevation 12 feet adjacent to the containment floor.
The SHA-1 instrument is maintained by the maintenance instrumentation and control (I8C) group.
I8C preventive maintenance procedures (PMIs) implemented the routine checks and calibrations.
These included the following procedures:
O-PHI-103.1
~ Seismograph Quarterly Functional Check and Tri-Annual Battery Checks and O-PMI-103.2, Seismograph Annual Film Replacement.
and O-PHI-103.3.
Seismograph 18 Month Replacement for Calibration Recertification.
The inspectors reviewed these procedures, including a check against SMA-1 instruction manual No.
F3464.
The inspectors also verified that the PHIs were completed within thei r requi red frequencies.
The inspectors examined the device in the field, questioned I8C and operations personnel, and reviewed emergency plan implementing procedure (EPIP) 0-EPIP-20106.
Natural Emergencies, Section 5.4.
Earthquak The inspectors noted that neither the PMIs nor the EPIP addressed the conversion from film displacement (obtained from the seismograph output)
measured in millimeters to axial acceleration measured in G's.
Turkey Point is designed for.05 G and
. 15 G maximum ground acceleration.
The seismic trigger is set for.01G.
The licensee located a
PWO data sheet which provided the conversion.
PMI and EPIP revisions were planned to include reference to the conversion.
Conclusions The inspectors concluded that the licensee met its seismic instrumentation requirements, and that the calibrations were current.
I&C and operations personnel were very knowledgeable regarding the system.
The licensee adequately addressed an issue relative to procedural displacement to acceleration conversions.
Operations Procedures and Documentation Procedure And Document Control Ins ection Sco e
71707 The inspectors reviewed the licensee's root cause and corrective actions on two issues relating to procedures and document control.
Observations and Findin s On December 30, 1997. during an Emergency Diesel Generator (EDG) room walk down. the inspectors found outdated procedures in the Unit 3 diesel building.
Procedure number 3-ARP-097.DG, Diesel Generator Panel Annunciator Response, had a review date of 6/10/97.
In additions procedure number 3-0NOP-023.2.
Emergency Diesel Generator Failure.
had a
review date of 12/6/97.
The inspectors reviewed the similar procedures in the-Unit 4 EDG room and found that procedure 4-ARP-097.DG, Diesel Generator Panel Annunciator Response, was also outdated and had a review date of 12/24/95.
The licensee was informed of these findings and they immediately replaced the outdated procedures with updated procedures.
Operations wrote CR No. 97-2100 to address this issue.
The licensee found the root cause of having outdated documents in the field was due to a lack of training of the document control technician resulting in weaknesses in understanding the procedures distribution process.
The licensee found that procedure 3-0NOP-023.2, Emergency Diesel Generator Failure.
was really not outdated.
rather there had been a typographical error on the procedure's date.
However, the licensee verified that the diesel annunciator response procedures (ARPs) were in fact outdated.
Immediate corrective actions included verifying that no other "field" procedures were out-of-date.
revising the distributions list document.
providing clarification of requirements, and providing training to document control personnel.
The outdated documents were reviewed by the licensee to determine if there had been any significant changes relating to safety and none were found.
Additionally. the
licensee indicated they completed a verif'ication of all operations controlled documents.
Two prints were found to be outdated.
However, the licensee determined that the changes to the prints did not include any operations related nor safety issues.
Additional long term corrective actions included putting a full time person in the control room that would oversee document controls in the power block and the work control center.
The individual would perform weekly and quarterly documents audits which included Emergency Operating Procedures (EOPs).
ONOPs.
and ARPs.
Lastly, the licensee indicated that procedure 0-OSP-200. 1, Schedule Of Plant Checks And Surveillance.
was going to be revised to require a Nuclear Watch Engineer, Nuclear Plant Supervisor.
or an Assistant Nuclear Plant Supervisor to perform monthly documents audit in the control room.
The inspectors verified the licensee's immediate corrective actions and veri.fied that there were no safety issues associated with having the outdated procedures in the emergency diesel generator room. or with the out dated prints that were found.
Additionally, the inspectors found that the full time employee in the control room had already started working there.
The employee was well versed with the procedures documentation process and noted that she previously had a similar job position in the control room.
Apparently. this was not a completely new position.
A similar position in the control room had previously been eliminated by management.
On December 18, 1997, the licensee found that a procedure which had been originated and processed for an "on-the-spot-change" (OTSC)
had not been approved by management within 14 days of origination as requi red by Technical Specifications 6.8.3.
The licensee wrote CR No. 97-2075 to address this issue.
During the extent of condition review, the licensee found an additional four OTSCs that had not been approved within the
day requi rement.
The licensee wrote two additional condition reports to capture this information in CR Nos.
97-2094 and 98-0018.
Interim corrective actions included a requirement to have the responsible manager approve the OTSC prior to implementation.
thereby eliminating the need to track the OTSC 14 day approval.
Additionally.
the control room would send a copy of the original OTSC to the Plant Nuclear Safety Committee (PNSC) coordinator and a daily OTSC status report would be included on the plan of the day report.
In summary.
the licensee determined that the root causes were due to a
recent process change and a lack of understanding of the OTSC procedure 0-ADM-102. On-The-Spot-Changes To Procedures.
Previously, the procedure
, required the original OTSC document to be sent to the PNSC coordinator.
Official tracking of the OTSC was done by the PNSC coordinator.
The OTSC tracking was dependant on the PNSC coordinator verifying that certain tasks were completed throughout the OTSC cycle.
The tasks included a
PNSC meeting if requi red and obtaining appropriate managerial approvals depending on the type of OTSC being processed.
The managerial approvals hierarchy and process for OTSC varied.
For example.
some
OTSCs required plant manager's approval prior to implementation, others required only the Nuclear Plant Supervisor's approval.
others required PNSC approval
.
and others required PNSC approval but not prior to implementation.
The procedure change which was implemented on November 18, 1997.
required the original OTSC procedure to be sent to the document controls department for scanning.
This change was part of a new database (Lotus Notes)
implementation that the licensee was using for procedures and document controls.
The document controls department would then send the OTSC procedure to the PNSC coordinator for tracking.
Of the five OTSCs that were found to be late. the licensee found that three OTSCs were not sent from the documents control department to the PNSC coordinator.
A fourth OTSC document was never sent to the document controls department.
The originator of the OTSC is responsible for sending the OTSC to the documents controls department, but it was not sent.
The fifth OTSC document was being tracked by the PNSC coordinator.
However, the responsible manager had to resolve some questions prior to approving the OTSC.
Both the PNSC coordinator and the manager subsequently took leave during the same time.
There had not been a designated acting PNSC coordinator and therefore that OTSC was not being tracked during thei r absence.
The licensee found that there existed three different databases which contained information relating to OTSCs.
Each database was independently owned by a different department and none was used as an official plant OTSC database tracking system.
Long term corrective actions included modifying the OTSC procedure and additional upgrades to the Lotus Notes data base to include an official OTSC tracking system, and training on any revision made to the OTSC process and Lotus Notes database..
The inspectors reviewed the late OTSC procedures and verified that there were no safety or operability concerns.
Additionally. the inspectors reviewed the modifications made to the Lotus Notes database which was now being used as an official OTSC tracking system.
Further'he inspectors attempted to interview the PNSC coordinator.
However. the coordinator was away on leave, and therefore.
the inspectors questioned the acting coordinator.
The acting coordinator was well versed with the PNSC coordinator responsibilities and demonstrated the application of the newly implemented Lotus Notes database and the tracking process of OTSC procedures.
The acting coordinator demonstrated the controls that were in place to assure proper tracking of the OTSCs in the absence of the PNSC coordinator or an acting coordinator.
The inspectors concluded that appropriate training had been provided to the acting PNSC coordinator and that the OTSC process and tracking was no longer dependant on a single individual.
c.
Conclusions Technical Specification (TS) requirements relating to these two issues on procedures and document controls are described in TS 6.8. 1, 6.8.2, and 6.8.3.
The licensee's failure to provide adequate procedures and
document controls is a violation of NRC requirements.
The OTSC related issue was a licensee identified and corrected violation and is being treated as a non-cited violation (NCV) per Section VII.B.1 of the NRC Enforcement Policy.
The EDG procedures and related issues constituted a violation of minor significance and is being treated as a Non-Cited Violation, NCV 50-250.251/97-13-01.
consistent with Section IV of the NRC Enforcement Policy.
The licensee's response to these issues were timely and comprehensive.
This non-cited violation with two examples was closed.
Operator Training and gualification 05. 1 Review of 0 erator Feedback Re orts and Student Course Criti ues a.
Ins ection Sco e
71001 The inspectors reviewed licensed operator student critiques to verify that the licensee was adequately addressing feedback as required by 10 CFR 55.59.
b.
Observations and Findin s The inspectors identified one course critique which contained a
negative comment that was not adequately resolved by the licensee.
In one critique, an individual identified a licensed operator that had recurring bouts of vertigo during class.
The inspectors reviewed the operator 's medical records.
The records indicated that the operator was placed on medication for this condition in June 1995.
The critique was written in June 1997.
The licensee responded to the critique by stating that the said condition was already known and documented.
However. the inspectors were concerned with the effectiveness of the prescribed medication and
~ts impact on the operator's ability to stand no-solo.
The inspectors reviewed the operator's license for a medical license condition.
The inspectors found no condition as required by ANSI 3.4, paragraphs 5.2.2 and 5.3.
The facility Medical Review Officer is questioning whether this condition constitutes a
license restriction.
This issue will be identified as an Unresolved Item (URI).
Final resolution of the URI will be determined by the NRC's licensed physician.
C.
Conclusions The inspectors identi fied a URI regarding a licensed operator
'
current medical condition and the conditions listed on his part 55 license.
Resolution to the URI is pending the NRC's licensed physician review.
This item is identified as URI 50-250.251/98-13-02, Medical License Conditio.2 Licensed 0 erator Re uglification Remediation Ins ection Sco e
71001 The inspectors reviewed the licensee's Licensed Operator Continuing Training (LOCT) program for its ability to adequately remediate the individual operators and crews as required by 10 CFR 55.59.
b.
Observations and Findin s The inspectors reviewed all requalification failures and events requiring remediation in 1997.
The inspectors found that in all cases'he operators were adequately remediated and that the remediation was properly documented.
Conclusions The inspectors determined that the licensee was effective in conducting remedial written and operating examinations to ensure operator mastery of the requalification training program content.
t 05.3 Licensed 0 erator Re uglification Simulator Job Performance Measures JPMs and Written Examinations Part
"A" and "B" a.
Ins ection Sco e
71001 The inspectors reviewed the licensee's LOCT Program to ensure the licensee was effective in conducting discriminating written and operating examinations as required by 10 CFR 55.59..
b.
Hbservations and Findin s The inspectors reviewed the 1998 final requalification examination for LOCT segment six. week one.
Crews 2A and 2B.
The observations and findings are as follows:
1)
Simulator:
One crew required remediation for placing letdown in service with Safety Injection (SI) not terminated.
The inspectors reviewed the draft simulator crew evaluation reports.
Evaluator comments matched NRC observations.
The scenarios discriminatory value was in accordance with NRC standards.
2)
JPHs:
The inspectors reviewed the JPH sets that were scheduled to be administered in the current annual examination.
The inspectors found that there were no JPMs repeated from week to week.
Each operator will receive a
set of five JPHs that consist of at least two in-plant JPMs and two simulator JPHs.
The inspectors found two sets of
'
JPMs that did not require an in-plant JPM in the Radiologi cally Controlled Area (RCA).
The licensee stated that this was an oversight.
and not in agreement with their olicy of ensuring at least one JPM in the RCA.
The icensee stated that the two sets would be revised prior to administration.
One JPM.
Manual Emergency Boration.
was identified as having a high importance but lacked discrimination value.
The facility committed to removing low discriminatory value JPMs from future annual examinations.
3)
Written:
The inspectors reviewed the written examination to ensure that improvements to the discriminating value of the test were made based on findings from the previous requalification inspection.
A detailed review was conducted in the areas of technical accuracy, level of knowledge.
direct look-ups.
and distractor plausibility.
The inspectors found that the overall quality had improved, and was in line with NRC expectations.
The licensee had taken the experience gained from writing the initial operator licensing examination and molded it into the requalification program.
The written examination was critiqued by several members of the training staff, as well as the training manager.
Each distractor was provided with a basis for its pl ausibi 1 ity.
c.
Conclus ions The inspectors determined that the licensee was effective in conducting written and operating examinations.
05.4 Licensed 0 erator Re uglification Trainin Hours a.
4ns ection Sco e
71001 The inspectors reviewed the licensee's requalification program for licensed operators to ensure that each received an adequate number of classroom and simulator training for the years of 1996 and 1997 as required by 10 CFR 55.59.
Observations and Findin s The inspectors reviewed each licensed operator's hours of classroom and simulator training for the years of 1996 and 1997.
All operators received approximately 240 hours0.00278 days <br />0.0667 hours <br />3.968254e-4 weeks <br />9.132e-5 months <br /> of training with no disparity between on shift operators and staff members.
All operators received an evaluation for each segment of the requalification training.
When poor performance was demonstrated.
the operator received remediation training and re-evaluatio c.
Conclus ions The inspectors concluded that all licensed personnel received equal hours of training relative to the active watchstanders and that the total number of hours were in accordance with NRC expectations.
Quality Assur ance in Operations 07. 1 Plant Mana er Briefin s a.
Ins ection Sco e
40500 The inspectors reviewed the licensee's self-assessment capability relative to plant manager briefings for all employees.
b.
Observations and Findin s During the period. the plant manager briefed site personnel regar ding past achievements and accomplishments, future goals and challenges, and areas for improvement.
1997 achievements included positive regulatory performance and the following discussed items:
Successful Unit 3 Cycle 16 and Unit 4 Cycle 17 refueling outages with most goals met.
High unit availability (Unit 3 86K, Unit 4 88K).
Good radiation protection performance, (e.g.,
lowest two outage year exposure).
Excellent personnel safety performance.
Other FPL awards and achievements (e.g..
best ever unit performance for a two outage year)
~ and Lowest ever end-of-year backlogs.
1997 weaknesses included improvements needed in self-assessment, radiological controls, workforce productivity. employee retention, aging of components, employee morale.
and housekeeping.
The 1998 goals were addressed relative to unit availability and outage performance.
radiation exposure.
and personnel safety.
Notwithstanding past achievements, management communicated to all employees that 1998 would be another challenging year.
Attention to detail. conservative operation and decision making.
and nuclear and personnel safety were stresse The inspectors attended one of the briefings.
and discussed this with site and plant management.
The inspectors reviewed the 1997 performance, areas for improvement.
and 1998 goals.
Conclusions The inspectors concluded that the licensee was self-critical.
and thei r self-assessment capability was strong.
Inde endent Reviews and Self Assessment Ins ection Sco e
40500 and 71707 The inspectors reviewed the licensee's self-assessment process including safety committee performance and corporate oversight.
Observations and Findin s The inspectors attended a portion of the Company Nuclear Review Board (CNRB) meeting No.
450 held at Turkey Point on January 20.
1998.
The inspectors verified that the meeting was conducted in accordance with Technical Specification 6.5.2, NP-803 (Nuclear Policy-CNRB), and the CNRB implementing procedures.
The CNRB normally meets eight times a
year. rotating the location of the meeting between the two FPL sites (i.e., Turkey Point and St. Lucie).
Usually representatives from the sites, headquarters.
and consultants are present at each meeting.
The inspectors also attended several PNSC meetings that involved activities that were being inspected in greater detail. i.e..
operations events.
etc.
Technical Specification and procedure requi rements were verified, including meeting frequency.
quorum.
and review responsibilities.
The inspectors noted that the CNRB and PNSC meetings met procedural guidelines.
Excellent safety focus was observed by safety committee members.
The CNRB complemented the site on continued strong performance.
Further.
the CNRB early warning performance indicator program continued to demonstrate a proactive posture.
The inspectors attended the January 2.
1998.
Turkey Point status meeting.
These meetings are held periodically at the site to assess performance.
Senior corporate management was noted to be in attendance.
including the FPL Chief Executive Officer (CEO). Nuclear Division President.
Director Nuclear Assurance.
and Engineering and Site Vice Presidents.
Items discussed included recent performance trends, safety focus issues'epartment reports'nd future challenges.
The inspectors noted frank and open discussions.
Conclusion The inspectors concluded that the licensee's self-assessment capability was demonstrated to be very good as evidenced by critical questioning,
senior corporate and plant management involvement.
a strong safety focus.
and effective safety committee performance.
Institute of Nuclear Power 0 erations INPO Evaluation The inspectors reviewed the October 1997 INPO Evaluation Report for Turkey Point.
The results of the INPO evaluation were generally consistent with NRC evaluations and assessments.
The inspectors discussed the specific issues with plant management.
II. Maintenance Conduct of Maintenance General Comments Ins ection Sco e
61726 and 62707 Maintenance and surveillance test activities were witnessed or reviewed.
The inspectors witnessed or reviewed portions of the following maintenance activities in progress:
Auxiliary feedwater (AFW) maintenance, modification.
and TSA activities (Sections 02. 1.
E2. 1.
and E2.2).
The inspectors witnessed or reviewed portions of the following test activities:
AFW surveillance testing (Section E2.2).
Intake Cooling Water In Service Test ( IST) (Section M1.2).
Observations and Findin s For those maintenance and surveillance activities observed or reviewed.
the inspectors determined that the activities were conducted in a satisfactory manner and that the work was properly performed in accordance with approved maintenance work orders.
The inspectors also determined that the above testing activities were performed in a satisfactory manner and met the requirements of the technical specifications.
Conclusions Observed maintenance and surveillance activities were well performed.
Intake Coolin Water ICW Surveillance Ins ection Sco e
61726 and 71707
NRC Inspection Report No. 50-250.251/97-06 reported significant changes which had been made to the Unit 3 and Unit 4 quarterly ICW pump surveillance procedures, 3-OSP-019.
1 and 4-OSP-019. 1. Intake Cooling Water Inservice Test.
The changes to the survei llances were made as a
result of an inadvertent low intake cooling water flow rate through the component cooling water heat exchangers which had occurred during this surveillance.
Through procedures review. interviews. field inspections and observations, and data review with the IST engineers.
the inspectors assessed the licensee's performance and test results of the Unit 4 intake cooling water pump inservice tests.
b.
Observations And Findin s On December 29.
1997. at 9:45 am, the licensee declared the 4A ICW header inoperable and entered a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement.
per TS 3.7.3.
During the performance of the 4C ICW pump surveillance, the inspectors observed that there were plant work order (PWO) tags on the flow rate gauges which measured the ICW outlet flow rate from the component cooling water (CCW) heat exchangers.
The PWO tags indicated that the gauges were sticking and needed to be calibrated.
These flow gauges are read throughout the surveillance procedure to ensure that the operable header meets the minimum flow rate and to insure correct flow rate for pump vibration acceptance criteria measurements.
The inspectors noted that the operators performing the surveillance had not questioned the operability of these gauges.
The inspectors informed the Nuclear Plant Supervisor (NPS) of the PWO tags on the flow gauges.
The licensee subsequently wrote CR No. 97-2095.
Operations later informed the inspectors that Operation's investigation determined that the flow gauges had recently been calibrated but the PWO tags had not been removed.
The inspectors verified that the flow gauges had been calibrated after the PWO had been written on the flow gauges.
The 4C ICW pump vibration data fell into the alert range.
The alert range was between
. 15 and
.36 inches per second (in/sec)
and the data recorded was
.28 in/sec; The surveillance was subsequently discontinued when difficulties arose with the check valve testing.
The licensee determined that the differential pressure gauge.
which measured differential pressure between the two ICW headers, was not properly vented.
The gauge was vented and the 4C test was repeated.
The results of the second test indicated that all the vibration data fell into the normal range and the check valve testing was completed satisfactorily.
On December 30.
1997. the 4A pump test was completed.
The pump fell into the alert range for developed head.
The alert range is between 26.48 and 27.05 psid.
and the developed head was recorded as 26.79 psid.
On December 31, 1997. during perfor'mance of the 4B pump testing.
Operations discontinued the test.
Operations was unable to take the pump suction lift measurement from the 4B1 well due to scaffolding present in the well.
On January
~
1998 'ST engineering reviewed the ICW pump vibration data with the inspectors.
Engineering believed that there was a potential issue.
namely biological fouling. associated with the flowmeters used to measure the ICW water going through the component
cooling water heat exchangers.
It was believed that incorrect flow measurements might be contributing to the "alert" data that had been recorded.
Engineering indicated that the flow gauges would be calibrated and that the differential pressure sensing lines would be flushed to remove any biological fouling. and all three pump test would be, perform again.
On January 9.
1998. during the retest of the 4A ICW pumps Operations discontinued the test.
During the process of measuring the suction lift, the tape measure was pulled by the pump suction and broke.
Three feet of tape.
along with the screw driver which was acting as a weight.
was pulled into the suction area of the pump.
The measurement of the suction lift entailed lowering a tape measure (with a screw driver taped to the end acting as a weight) into the well to measure the suction water height.
CR No.98-035 was written to address this issue.
Vibration testing was subsequently done on the 4A ICW pump to assess potential damage on the pump and no irregularities were found.
Also. the licensee inspected the 4A ICW basket strainer and did not find the -screw driver.
The licensee declared the pump operable.
Later that evening.
a diver entered the well to recover the tape and screw driver.
The inspectors observed the diver and noted that a screw driver, a
wrench, and other miscellaneous hardware was found.
However. the screw driver that was attached to the tape measure was not found.
Licensee corrective actions included modifying the tape measure to use a float instead of a weight on the tape measure.
Also. the amount of tape that could pull out was limited to 25 feet, which prevented the tape from reaching the pump suction area.
However, the condition report did not address a root cause.
The inspectors discussed their concerns relating to the overall observations of the IST pump testing with Operations management.
However, management did not believe that there existed a problem with the performance of this test.
Management indicated that each of the items discussed above were isolated cases and there existed no generic issue with the performance of this surveillance.
On January 16.
1998. the licensee finalized the details on the new tape measuring tool which would be used to measure the ICW well pump suction lift.
The entire surveillance was scheduled to be redone on peak shift.
At 6: 10 p.m.. the licensee declared the 4B ICW header inoperable and initiated valve manipulation to perform the vibration testing on the 4A ICW pump.
At 10:35 p.m.. the licensee completed testing on the third pump. the 4C ICW pump.
and returned the inoperable header back to service.
All three pumps completed the testing satisfactorily and no issues materialized during the testing.
The inspectors observed portions of the testing at the intake canal and at the CCW pump room and the control room activity throughout the surveillance testing, including the test performed on January 16 '998.
Additionally. the inspectors attended the tail board meeting held on January 16.
The tail board meeting was held outside of the control room.
Attendance included the Watch Engineer and the 3 Operators performing the surveillance.
Turbine operator, Unit 4 ANPS and reactor operator (RO).
and an IST engineer providing oversight and was available
for technical support.
In addition.
an operator-trainee attended the meeting.
The inspectors noted that the ANPS held an excellent tail board meeting.
Marked-up and hi-lighted prints were reviewed.
individual responsibilities were summarized.
the procedure was reviewed in its entirety, system line up and administrative prerequisites were reviewed and verified. 3-point communications was summarized with examples.
nuclear and personnel safety.
and self-checking using Stop-Think-Act-Review (STAR) were emphasized.
Additionally. the ANPS questioned the SNPOs and the Watch Engineer on some of their activities and testing criteria.
During the surveillance testing, the inspectors noted strong procedure adherence.
The inspectors questioned the SNPOs and the Watch Engineer performing the tests and noted that they were very well versed with this surveillance.
The Watch Engineer had good awareness of all the on-going activities at the intake canal and at the CCW heat exchanger room and was continuously monitoring the overall activities at both places.
Also. after discussing the test and various parts of the surveillance procedure with the SNPOs and the Watch Engineer.
the inspectors noted that the SNPOs and the Watch Engineer performing the tests (on January 16, 1998)
had significant amount of experience with this test and with plant operations.
During the testing, the inspectors entered the control room and questioned the Unit 4 ANPS and RO on the on-going surveillance testing.
Both were aware of the specifics of the testing and what part of the procedure was presently being performed and were following the test activities on copies of the surveillance procedure.
The inspectors noted good three point communications between the control room. the field operators and with the Watch Engineer.
The inspectors verified the calibration data on the METE and plant installed gauges used during this surveillance and reviewed the completed signed-off surveillance procedure.
IST engineering informed the inspectors that CR No.98-097 was written to address the biological fouling which was identified in the Unit 4 flow gauges.
IST noted the fouling had not been an issue during the Unit 3 ICW surveillance.
Further, the licensee found that the work instruction on the calibration of the Unit 3 and Unit 4 flow gauges were not the same.
Specifically. the lines which were in question (fouled)
were not required to be cleaned on the Unit 4 work order.
but were required to be cleaned on the Unit 3 work order.
c.
Conclusions The Intake Cooling Water pump IST surveillance continues to be one of the most challenging surveillance for Operations.
Excellent technical support by IST engineering was noted.
A lack of questioning attitude was noted when Operations was performing the surveillance using flow gauges which had PWO tags and had not questioned the operability of the flow gauges.
However.
heightened management involvement and testing performed by very well experienced Operations personnel.
provided for an excellent test which was performed on January 1.6.
199 Haintenance and Haterial Condition of Facilities and Equipment Haterial Condition Ins ection Sco e
62700 The inspectors conducted inspections.
and reviewed maintenance documentation.
relating to the material condition of the charging pumps.
component cooling water (CCW) pumps'nd CCW heat exchangers.
Observations and Findin s The inspectors conducted walk-through inspections of the CCW pump and heat exchanger rooms, and the charging pump rooms.
One tour in each area was conducted in the company of the system engineers for each system.
The system engineer for each of these systems was conversant in the.maintenance history for the assigned system:
The inspectors reviewed summary printouts of all maintenance activities initiated during 1996 and 1997 for the components selected.
As a macro review of the maintenance history for these components.
the maintenance requests were plotted against the month of initiation.
The resulting plots indicated that the CCW pumps appeared to have been fair ly low-maintenance components during the past two years.
The plots for the charging pumps and the CCW heat exchangers showed a steadily increasing number of maintenance activities from early 1996 through August 1996.
which appeared to have been the peak of activity for these components.
After a rapid decline in the monthly number of maintenance requests through November 1996 'he charging pumps and CCW heat exchangers have also appeared to be relatively low maintenance components.
Conclusions The maintenance histories for the charging pumps and the component cooling water pumps and heat exchangers indicated an improvement in the material condition of these components during the past two years.
Quality Assurance Work Control Documents 62707 During the period, the inspectors noted that Quality Assurance (QA) had identified a decline in plant work order (PWO) accuracy and completeness.
Of 150 PWOs reviewed during the third quarter of 1997.
QA identified errors in 50. or about a 33K reject rate.
CR No. 97-1872 was initiated to address the issue.
A previous CR (No.96-905)
had also been initiated; however. corrective actions were apparently ineffective.
The maintenance group concluded that the recent issue was caused by lack of attention to detai l by the journeymen who fill out the PWO.
Hissing items including initials, dates*
~ signatures.
and parts information were noted.
Further.
poor supervisory review of PWOs was also a causal
factor.
A number of corrective actions were initiated or planned.
These included retraining of journeymen.
a team review of completed PHOs.
development of a monthly indicator.
and some additional process improvements.
QA intends to continue their review on a periodic basis.'he inspectors reviewed the QA report. the two CRs. the PRO and selected maintenance procedures.
and discussed this issue with QA and maintenance personnel.
The inspectors confirmed that the PRO errors did not adversely affect equipment operability or maintenance that was performed.
The inspectors concluded that QA was active in reviewing maintenance performance.
and in identifying weaknesses in the PMO accuracy and completeness.
Material Condition ualit Assurance A
Assessments Ins ection Sco e
62700 The inspectors reviewed QA activities in the area of material condition assessments and maintenance.
The latest QA audit of maintenance was a
biennial audit conducted in early 1997 and reviewed maintenance activities in 1995-1996.
Observations and Findin s The strength of the licensee's QA program appeared to be in providing real-time quality assurance coverage through a surveillance program wherein the QA personnel observe, evaluate.
and report on the daily activities of the plant staff and the material condition of plant systems and components.
The inspectors noted that QA personnel had observed and reported on several hundred maintenance-related activities during the last quarter of 1997.
During the inspectors'eview of a summary of the survei llances conducted during the last quarter of 1997 'he inspectors found one indication of what was considered to be an "Unsat" surveillance listed as "Sat" on the printout.
Surveillance 97-0591 dated November 26.
1997 '
weekly housekeeping surveillance.
contained an -observation-concerning two snubbers which appeared to require corrective action.
Further review showed that as a di rect result of surveillance 97-0591, CR No. 97-2008 was generated on November 26 '997, with appropriate actions and evaluations.
The licensee's explanation was that the material condition problem was found during a "housekeeping-inspection:
The housekeeping was satisfactory.
and the QA inspectors decided not to confuse the issue by reporting housekeeping
"Unsat" because of a material condition.
The inspectors pointed out that by reporting the problem the way that it was presented.
the issue could have been not reported (An "Unsat-material condition reported as an "Observation" ).
QA appeared to be helping present a success story. rather than being an independent observer.
The licensee agreed that if it is important to keep
c'.
M8
housekeeping separate from material condition.
a separate
"Unsat-survei llance report should have been prepared rather than including the problem in the housekeeping report as an observation.
Conclusions The licensee's Quality Assurance personnel provided real-time quality assessments through a continuing surveillance program.
Miscellaneous Maintenance Issues M8.1 Closed VRI 50-250 251/97-11-01 Per formin Surveillance Testin With Ga es Not in a Periodic Calibration Pro ram.
Ins ection Sco e
71707 and 92903 The.inspectors reviewed the licensee's corrective actions on condition report that was generated after the, inspectors found that the licensee was performing a technical specification surveillance using plant installed gauges that were not in a periodic calibration program.
Observations and Findin s NRC Inspection Report No. 50-250.251/97-11, reported that during a
resident inspector surveillance observation of the Standby Steam Generator Feedwater (SSGF)
pumps, the inspectors found that the licensee was using plant installed gauges that were not in a calibration program to assess technical specification acceptability criteria.
The licensee subsequently wrote CR No. 97-1638 to address this issue.
The inspectors found that the QA organization had previously identified other instances where plant installed gauges used for technical specification acceptance criteria were not in a calibration program.
Additienally, there had been condition reports written which described instrumentation read during daily SNPO tours which needed to be in the PH calibration program and were not.
In discussing these previous findings with management. it was revealed that actions had already been started.
prior to the inspectors findings on the SSGF surveillance.
to address this issue on a programmatic level.
Inspection of licensee interoffice correspondence verified that on September 2.
1997. the plant manager approved a
memo requesting the formation of a "cross-discipline task team-to address the issues associated with the installed instrumentation calibration program.
The instructions requested the team to start the evaluation after the Unit 4 refueling outage in October 1997.
The task team determined that the programmatic root cause was inappropriate guidance in procedures 0-ADM-101. Procedure Writer'
Guide and QI-12-PTN-3, Calibration Of Installed Plant Instrumentatio Findings and corrective actions included the following:
13 instruments.
which are either used for technical specification action requirements or used in technical specification surveillance.
were added to the PH calibration program.
howevers operability assessments were made and no operability issues were identified.
~
As a result of the control room log book.
OSP.
EOPs.
and ONOPs procedures review.
a total of 271 instruments were added to the PH calibration program,
~
Procedure O-ADM-101, Procedure Writer's Guide.
was modified to requi re that all gauges used to verify acceptance criteria be in a calibration program,
~
.
Procedure QI 12-PTN-3. Calibration of Installed Plant Instrumentation'ould be modified based on the teams recommendation.
The licensee indicated this would be completed by April 1998.
The inspectors held various discussions with the team members during their review.
The inspectors verified a sampling of the instruments that were added to the PH program and that procedure 0-ADH -101.
Procedures Writer's Guide.
was modified to include the calibration requirement on gauges used to verify acceptance criteria.
Additionally, throughout the inspection period. the inspectors verified calibration
'equirements on instruments used in the observed Technical Specification surveillance and no additional issues were identified.
c.
Conclusions A violation of NRC requirements was identified when the licensee used plant installed gauges that were not in a calibration program to assess Technical Specification acceptance criteria.
This non-repetitive.
licensee identified and corrected violation is being treated as a Non-Cited Violation (NCV) per Section VII.B.1 of the NRC Enforcement Policy.
URI 50-250,251/97-11-01 and NCV 50-250.251/97-13-03.
Performing surveillance testing with gauges not in a periodic calibration program.
were closed.
III. En ineerin E2 Engineering Support of Facilities and Equipment E2. 1 Auxiliar Feedwater AFW Turbine Electrical Overs eed Tri Elimination 37551 During the period, the licensee completed plant change/modification (PC/H) No.97-033 which eliminated the AFW turbine electrical overspeed trip.
The licensee's safety evaluation addressed
CFR 50.59 requirements'nd concluded that PC/H did not constitute an unreviewed
safety question nor a change to TSs.
The basis for this determination included the following:
The UFSAR does not take credit for the electrical overspeed trip device in the accident analysis.
The electrical overspeed trip device was installed during the 1980's for reliability reasons:
howevers recent inadvertent actuations have decreased reliability.
The AFW woodward governor (speed limiter) and mechanical overspeed trip device remain intact.
Other plants have removed or have never had an electrical overspeed trip device installed.
The AFW response, design.
safety margin and functions remained unchanged.
The inspectors reviewed the PC/N, design documents, the UFSAR. training material, electrical drawings, and other related information.
The inspectors observed portions of PC/H work. the post modification testing.
and the surveillance testing.
The inspectors concluded that the PC/0 was appropriately designed, implemented, and tested.
Good coordination among operations, engineering.
and maintenance was observed.
E2.2 Auxiliar Feedwater AFW Tem orar S stem Alteration TSA a.
Ins ection Sco e
37551 The inspectors reviewed the licensee's approval and implementation of TSA No. 3-98-75-01 on the common AFW system.
The TSA modified the in-line i~strument air ( IA) filter configuration for the AFW flow control valves (FCVs).
b.
Observation and Findin s Recent AFW testing determined that debris from the IA galvanized piping was being introduced downstream of existing IA filters.
Previous issues with debris from the IA system unfiltered bypass line use were discussed in NRC Inspection Report Nos. 50-250.251/97-06 and 97-10.
The purpose of TSA was to install IA in-line filters upstream of the check valves that supply control air to the AFW FCVs.
As described in CR No. 97-1914 'ailures of the AFW backup nitrogen consumption tests (procedures 3/4-0SP-075.6 and 3/4-0SP-075.7)
were likely the result of air line check valve fai lures caused by the introduction of debris from the galvanized piping located between the filters and check valves.
The new filters were located closer to the check valves.
downstream of the
secti ons of gal vani zed piping.
The licensee intends to restore the TSA by a subsequent PC/M.
The licensee issued and approved Request for Engineering Assistance (REA) No.97-028 to pursue this future planned PC/H.
IA to the AFM FCV's uses Parker Pneumatic (14F178) five micron filters located upstream of the respective Nupro (SS-CHS-8-10)
Several feet of /," galvanized piping exists between the existing IA filter and check valve.
The TSA installed 12 additional Parker type filters. identical to those already installed, upstream of the check valves and in series with the existing filters.
All galvanized piping downstream of the new filters was replaced with stainless steel tubing in order to eliminate any galvanized piping through which IA flows unfiltered.
To ensure that adequate control air pressure is maintained at the supply to the AFW FCVs with the new filters installed in series with the existing filters, the existing filters were bypassed using the existing bypass line.
The bypass line is permanent plant equipment.intended for facilitating maintenance on the existing filters.
The pressure drop across the existing filters was addressed by isolating the existing filters and aligning air flow through the bypass line.
Operating diagrams and isometric drawings were changed.
Installation was performed per PMO work instructions.
The new filters remained in the vertical, upright position.
The
CFR 50.59 review and safety evaluations were performed as required.
PNSC approved the TSA on January 12.
1998.
The licensee implemented the TSA on Units 3 and 4 Train 1 during the week of January 12 '998.
and on Train 2 during the week of January 19, 1998.
Post maintenance testing included leakage checks and OSP performance.
The inspectors reviewed the TSA and safety evaluation documentation and testing activities in the field, reviewed the drawing and procedure updates, and discussed the work with engineering, operations.
and maintenance personnel.
The inspectors noted that the PNSC provided an excellent review and assessment of the TSA.
A strong safety focus and a very good questioning attitude was displayed by PNSC members.
Excellent work coordination was noted between system engineering and maintenance personnel.
Operations clearance.
and testing.
and configuration control activities were also very good.
Out-of-service time was minimized by good planning.
and process enhancement feedback after the first train work.
Conclusions The licensee was well focused towards addressing a reliability issue for the AFW system.
A TSA to modify the instrument air filter configuration was appropriately implemented and excellent work coordination among
operations.
engineering.
and maintenance was observed.
PNSC demonstrated a strong safety focus in reviewing this issue.
Control Room Pe ed Hi h Indicators Ins ection Sco e
37551 The inspectors reviewed the licensee's evaluation on operating the reactor coolant system (RCS) narrow range pressure indicators and the reactor coolant pump (RCP)
number one seal injection differential pressure indicators in a long term "pegged high" condition.
Observations and Findin s During a control room board walk down. while Unit 3 and Unit 4 were operating at 100K power, the inspectors noted that the RCS narrow range pressure indicators and the number
RCP seal injection differential pressure indicators were pegged high.
The RCS narrow range indicators pegged high at 1000 psig and the number
RCP seal injection differential pressure indicators pegged high at 400 psid.
The inspectors questioned the functionality of the indicators due to the indicators operating in a long term over pressure condition.
Engineering evaluated the construction of the instruments and the internal forces and electrical currents associated with operating the instruments in the over pressure condition.
Additionally. the Rosemount transmitters which provide a current signal to the indicators were reviewed for the applications.
Engineering obtained design information and specifications from the transmitter and instrument vendors.
namely, Rosemount and Westinghouse, respectively.
Additionally, engineering reviewed the as found data on the three most recent calibration results on each indicator.
The data did not show any degradation in the calibration accuracy of the instruments.
Based on the evaluation and data review, the licensee concluded that the indicators were not being operated outside its design specifications and therefore there were no concerns relative to operating the instruments in a long term "pegged high" condition.
Engineering wrote a
CR No. 97-2062 to capture this evaluation and have it available for future reference.
The inspectors reviewed the construction and the application of the instruments and had various discussions with engineering and operations.
The calibration data was verified and did not show any degradation in instrument accuracy.
Conclusions Engineering performed a good evaluation and documentation of the instrumentation and showed that there existed no functionality concerns associated with operating the RCP number one seal differential pressure indicators and the narrow range RCS pressure indicators in a long term pegged high conditio IV. Plant Su ort Rl Radiological Protection and Chemistry (RP&C) Controls Rl. 1 Radiation Dose Performance 71750 The inspectors reviewed Turkey Point's radiation dose history for the past four years.
Although the 1997 yearly and Unit 4 refueling outage goals were not met
~ the site did achieve its best ever two-outage radiation dose year.
and the 3-year rolling average per unit dose has continued to decrease.
Y R~l. tlf R t
.
~DR 1994 1995 1996 1997 474 214 186 414 The previous 3-year rolling average was 146 Rem per unit and the current 3-year average is 136 Rem per unit.
The current 1998 goal (one outage scheduled)
is 185 Rem.
The inspectors also attended the January 1998 monthly As-Low-As-Reasonably Achievable (ALARA) Review Board (ARB).
At this meeting.
performance during 1997 and goals for 1998 were discussed.
The inspectors concluded that site radiation dose reduction initiatives remained strong and focused.
Areas for improvement are being identified by the licensee and are being appropriately pursued.
The ARB process was effective.
R2 Status of RP&C Facilities and Equipment R2. 1 Health Ph sics HP Radiation Controlled Area RCA Control Point U
rades 71750 During the period. the licensee modified and upgraded the HP RCA control point.
Changes included better egress and ingress areas.
building enhancements.
better HP technicians monitoring facilities, and improved arrangement of HP monitoring equipment.
The changes became effective December 31.
1997. with complete swapover completed on January 2,
1998.
The inspectors monitored the progress of the upgrades'bserved the swapover activities.
and discussed these changes with HP and plant management.
The inspectors concluded that the licensee was proactive in performing these upgrades to the HP RCA control point.
R
R4 R4.1 R4.2
Staff Knowledge and Performance in RP8C Radiation Work Permit RWP Knowled e 71750 On January 1,
1998. Health Physics (HP) posted signs at the entrance to the radiologically controlled area (RCA) requesting everyone entering the RCA to first read thei r 1998 RWP for information on potential changes.
On January 2.
1998, prior to entering the RCA. the inspectors read the hard copy of 1998 RWP No. 98-6 and noted that the dose and dose rate alarm values were not written on the RWP.
However, upon logging onto the RWP, the computer showed a
new value for the dose rate alarm.
namely, it had increased from 100 to 150 mRem/hour.
The inspectors noted that the computer did not denote this change. i.e..
one had to know what the previous alarm values were in order to recognized that there had been a change.
The HP manager later explained to the inspectors the increase in the dose rate alarm on that RWP was because the resident inspectors have access to high radiation areas.
On January 6.
1998. the inspectors entered the RCA and at random asked licensee personnel if they knew what RWP they were working under and what their dose and dose rate alarm digital alarming dosimeter (DAD)
levels were.
All individuals knew what RWP they were assigned.
However. of the 20 individual that were asked'nly four answered the correct values for the alarm levels.
The other replies varied.
Some individuals answered with incorrect values.
others confused the dose with the dose rate values, and others answered that they did not know.
The inspectors communicated the findings to the licensee.
The licensee later informed the inspectors that people entering the RCA would at random be quizzed to assess their knowledge of their RWP information and radiation work safety practices.
Workers are required to respond to an audible alarm on the DAD, regardless of whether they know the alarm setpoints.
The inspectors concluded that there was a lack of worker's knowledge of DAD alarms.
Auxiliar Bui ldin Contamination Event On January 9,
1998. at 10:00 a.m..
a senior nuclear plant operator (SNPO) alarmed the portal monitor at the RCA exit in the HP control point.
Shoe and floor contaminations were detected'nd RCA access was suspended.
Subsequent surveys identified multiple contaminations associated with the SNPO's travel path inside and outside of the auxiliary building.
All contaminated areas and the SNPO's shoe were successfully deconned.
The contamination levels ranged from 500 F 000 disintegrations per minute (dpm) to F 000 dpm.
The licensee's investigation (CR No. 98-40) determined that the SNPO had initially alarmed the alternate RCA control point (turbine building)
The SNPO incorrectly assumed that the alarm was due to a small amount of radioactive gas, and then proceeded to the main RCA control point to be counted by another portal monitor.
The licensee
'
R6 R6.1 S2 S2.1 S4.1
concluded that the SNPO most likely picked up the shoe contamination in a clean area of one of the auxiliary building rooms.
The SNPO had performed the normal operator tour.
and had not entered any posted contaminated areas.
The inspectors learned of this issue during a routine plant tour on the same day.
The inspectors observed HP actions.
reviewed the completed CR.
and discussed the event with the SNPO and HP and plant management.
Corrective actions to counsel and retrain the SNPO, and to brief the entire operations staff were verified.
The inspectors noted that the SNPO response to the initial portal monitor alarm was based on an incorrect assumption of short-lived gas contamination.
As a results the spread of contamination was more extensive than it should have been.
Fortunately, no contamination was spread outside the RCA, and only minimal dose was received by the SNPO.
No other workers received contamination from this event.
The inspectors noted timely and appropriate response by HP personnel.
However. the SNPO's initial actions were poor and this was considered to be a weakness in implementation of radiological programs.
RP8C Organization and Administration Radiation Protection Hang er 71750 Effective January 5.
1998, Hr. Stanley F. Wisla became the site Radiation Protection Manager
.
The inspectors reviewed NRC Regulatory Guide 1.8.
September 1975 and TS 6.3. 1 and verif'ied that minimum qualifications were met.
Status of Security Facilities and Equipment
Ex losiye Detector Performance 71750 On December 5.
1997.
based on feedback from another facility. the licensee identified a potential weakness in the explosive detector performance.
Security personnel immediately initiated compensatory measures and wrote CR No. 97-2037.
The CR addressed longer term actions.
The inspectors observed the vulnerability at the nuclear security entrance building.
and confirmed that immediate compensatory measures were initiated.
The inspectors also reviewed the CR and discussed the issue with security personnel.
The inspectors concluded that the licensee's operating experience feedback system was strong and that security's response was both timely and appropriate.
Security and Safeguards Staff Knowledge and Performance Fitness For Dut Event 71750 At 2:43 p.m.
on January 14, 1998.
the licensee made a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> notification report per
CFR 26 to the NRC regarding information they
F5 F5.1
received the day before.
Apparently, an employee had been previously arrested last year in March 1997 for substance possession.
The employee did not report this information to the site based on the wrong assumption that it was only reportable if a conviction was obtained.
The employee has been temporarily suspended pending an investigation.
The licensee confirmed that random testing since the March 1997 arrest were all negative.
The inspectors reviewed and discussed the reportabi lity of this event with licensee personnel.
Since the employee had acted temporarily as a
supervisor.
the
CFR 26 reporting requirements apply.
The inspectors concluded that the licensee reported this issue per the NRC requirements.
Fire Protection Staff Training and Qualification Fire Dril 1 71750 During the period the licensee held fire drills which included a
simulated injury to an employee.
The licensee has increased the emphasis on first aid and medic participation in thei r drills.
The fire drill location was near the Unit 4 lube oil reservoir.
Smoke and flames were simulated under the hood of a truck.
The fire drill scenario also simulated the truck driver having been soaked with hydrazine after accidentally backing the truck into a hydrazine tank.
The inspectors observed the licensee's responses to selected fire drills.
Relative to a January 2,
1998 'rills the fire team took good control of the activities and the team very quickly assessed the situation at the fire site.
The response from the support groups such as security. first aid
~
and the medics was good.
The injured employee was removed from the fire site and given first aid until the medics arrived.
He was subsequently taken to a shower site to have the hydrazine removed from his body.
The fire team leader took good command and control at the fire site and the fire was very quickly extinguished using dry chemical spray.
The inspectors concluded that the fire brigade security. first aid.
and the medics response was prompt and effective in addressing the fire and the injured employee.
Relative to a January 19 '998 'rill, performance was satisfactory.
However.
weaknesses were identified in the timeliness of response and in the actions to remove the injured person.
These issues were appropriately addressed at the critique following the drill.
The inspectors concluded that the fire brigade and the support groups were appropriately exercised during drill X1 Exit Meetin Summar V.
Mana ement Heetin s
The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on January 27.
1998.
The licensee acknowledged the findings present.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identified.
Partial List of Persons Contacted Licensee T.
V. Abbatiello, Site Quality Hanager R. J. Acosta, Director, Nuclear Assurance J.
C. Balaguero, Plant Operations Support Supervisor P.
M. Banaszak, Electrical/?&C Engineering Supervisor T. J. Carter, Maintenance Support Supervisor B.
C.
Dunn. Mechanical Systems Supervisor R. J. Earl, QC Supervisor S.
H. Franzone.
Electrical Maintenance Supervisor J.
R. Hartzog.
Business Systems G.
E. Hollinger, Licensing Manager R. J.
Hovey, Site Vice-President M. P.
Huba, Nuclear Materials Manager D.
E. Jernigan, Plant General Manager T. 0. Jones.
Operations Supervisor H.
D. Jurmain.
I&C Supervisor V. A. Kaminskas.
Services Manager A. N. Katz. Mechanical Maintenance Supervisor J.
E. Kirkpatrick, Protection Services Manager G.
D. Kuhn, Procurement Engineering Supervisor R. J.
Kundalkar
~ Vice President.
Engineering and Licensing M. L. Lacal. Training Manager Vince Laudato.
Fire Protection Supervisor E. Lyons. Engineering Administrative Supervisor J.
A. Marco.
Human Resources Manager D.
D. Hiller. Projects Supervisor C. L. Howrey. Licensing Specialist H.
N.
Paduano.
Manager, Licensing and Special Programs H. 0. Pearce.
Maintenance Manager K.
W. Petersen.
Site Superintendent T.
F. Plunkett.
President.
Nuclear Division K. L. Remington
~ System Performance Supervisor R.
E.
Rose, Work Control Manager C.
V. Rossi.
QA and Assessments Supervisor W. A. Skelley. Plant Engineering Manager R.
N. Steinke, Chemistry Supervisor
E.
A. Thompson.
Engineering Manager D. J.
Tomaszewski.
Systems Engineering Manager J.
X. Trejo. Health Physics and Chemistry Supervisor G. A.
War riner, (juality Surveillance Supervisor J.
D. Webb, Plant Change Control Supervisor R.
G. West. Operations Manager S.
F. Wisla.
HP Supervisor Other licensee employees contacted included construction craftsmen.
engineers.
technicians.
operators, mechanics.
and electricians'.
Inspection Procedures Used IP 37551 IP 40500 IP 61726 IP 62703 IP 71001 IP 71707 IP 71714 IP 71750 IP 92903 Onsite Engineering Effectiveness of Licensee Controls in Identifying'esolving.
and Prevent Problems Surveillance Observations Maintenance Observations Licensed Operator Requalification Program Plant Operation Cold breather Plant Support Activities Followup - Maintenance Items Opened and Closed 50-250.251/97-13-01 50-250.251/97-13-02 50-250.251/97-13-03 Closed 50-250.251/97-11-01 50-250,251/97-13-01 50-250.251/97-13-03 NCV Failure to provide adequate procedures and document controls (Section 03. 1).
URI Medical licenses condition (Section 05. 1).
NCV Performing surveillance testing with gauges not in a periodic calibration program (Section M8.1).
URI Performing surveillance testing with gauges not in a periodic calibration program (Section M8.1).
NCV Failure to provide adequate procedures and document controls (Section 03. 1).
NCV Performing surveillance testing with gauges not in a periodic calibration program (Section M8.1).
A
~
ANSI ARB ARP CCW CFR CNRB CR dpm DPR DRS EDG e.g.
gpm HP Mz IA IKC IST JPH MRO ME/HVAR NCV No.
NP NPS NRC ONOP OSP OTSC PC/H PDR p.m.
PM PME PHI PNSC psig(d)
PSS LIST OF ACRONYHS USED Administrative (Procedure)
Auxiliary Feedwater As-Low-As-Reasonably Achievable Ante Meridiem American National Standards Institute ALARA Review Board Annunciator Response Procedure Component Cooling Water Code of Federal Regulations Company Nuclear Review Board Condition Report disintegrations per minute Power Reactor License Division of Reactor Safety Emergency Diesel Generator For Example Emergency Operating Procedure Emergency Plan Implementing Procedure Degrees Fahrenheit Flow Control Valve Florida Florida Power and Light ground acceleration Gallons Per Minute Health Physics Hertz Instrument Air Instrumentation and Control In Service Test Job Performance Measurement Medical Review Officer Hega Watts/Mega Volts Amperes Reactive Non-Cited Violation Number Nuclear Policy Nuclear Plant Supervisor Nuclear Regulatory Commission Off-Normal Operating Procedure Operations Surveillance Procedure On-the-Spot Change Plant Change/Modification Public Document Room Post Meridiem Preventive Maintenance Preventive Maintenance
- Elect Preventive Maintenance
- I8C Plant Nuclear Safety Committee Pounds Per Square Inch Gauge (Differential)
Power System Stabilizer
PTN PWO QA QI RCA RCP RCS Rem/mRem REA rpm RWP RWST SI SMA SNPO SSGF TS TSA UFSAR URI
Project Turkey Nuclear Plant Work Order Quality Assurance Quality Instruction Radiation Control Area Reactor Coolant Pump Reactor Coolant System Roentgen Equivalent Man/milli-Rem Request for Engineering Assistance Revolutions Per Minute Radiation Work Permit Refueling Water Storage Tank Safety Injection Strong Motion Accelerograph Senior Nuclear Plant Operator Standby Steam Generator Feedwater Technical Specification Temporary System Alteration Updated Final Safety Analysis Report Unresolved Item