IR 05000250/1997001
| ML17354A447 | |
| Person / Time | |
|---|---|
| Site: | Turkey Point  |
| Issue date: | 03/07/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17354A446 | List: |
| References | |
| 50-250-97-01, 50-250-97-1, 50-251-97-01, 50-251-97-1, NUDOCS 9703270315 | |
| Download: ML17354A447 (80) | |
Text
U.
S.
NUCLEAR REGULATORY CONNISSlON
REGION II
Docket Nos.:
50-250 and 50-251 License Nos.:
'I Report
- Nos.:
50-250/97-01 and 50-251/97-01 Licensee:
Florida Power and Light Company h
Facility:
Turkey Point Units 3 and 4 Location:
9760 S.
W. 344th St.
Florida City, FL 33035 Dates:
January 1 through February'5, 1997 Inspectors:
T.
P. Johnson, Senior Resident Inspector M. J.
Morgan, Resident Inspector, Browns, Ferry Plant(06.2,M4. 1)
R.
P. Croteau, NRR Project Manager'(E3. 1)
G. T. Hopper, DRS Licensing Examiner(05. 1)
P.
M. Steiner, DRS Licensing Examiner(05. 1)
J.
W. York. Acting Resident Inspector D.
R.
Lanyi Resident Inspector, St. Lucie Plant'(Ml'.2,M2. 1)
C.
W. Rapp, DRS'nspector(E2.4)
'pproved. by:
C. A. Juliane Acting Chi.ef Reactor Projects Branch
Division of Reactor Projects 97032703i5 970307 PDR ADOCK 05000250
EXECUTIVE SUMMARY TURKEY POINT UNITS 3 and 4 Nuclear Regulatory Commission Inspection Report Nos. 50-250,251/97-01 0'
~
The licensee demonstrated excellent performance during the planning for and execution of routine load reductions on both units for turbine testing.
Skilled operator performance, strong procedure compliance, and excellent teamwork were observed.
Management's decision to shutdown 'Unit 4 to Mode 2 to complete the valve testing was conservative.(section 01.1).
r Operator response to a Unit 3 dropped rod was very good.
Procedure and Technical Specification compliance was excellent.
Conservatism was noted as evidenced by initial troubleshooting oversight, and by management's decision to voluntarily shutdown the unit to Mode 3 to address rod control issues (section 01:2).'
.
Cold weather actions and procedure implementation were proactive and appropriate.
Further, the licensee identif'ied enhancements to the process (section 01.3).
~
New fuel receipt, inspection, and handling, and spent fuel pool "
, pre-refueling activities were appropriately planned and.executed, with very good teamwork noted.
Further, the licensee appropriately responded to equipment problems and performance concerns (section 01.4).
t
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Periodic inspector verifications of system lineups determined that the auxiliary feedwater
. component cooling watei, rod control, reactor protection, and nitrogen backup systems were appropriately aligned (section 02.1).
Inspector review of general, off-normal and emergency operating procedures" noted several procedural weaknesses.
The licensee addressed these'issues appropriately and in a timely manner
'sections 03. 1, 03.2 and 05. 1).
Licensed operator requalification training programs were very good; however, improvements are needed in the area of written exam quality (section 05.1).
The Operations Supervisor was transferred to the St. Lucie plant.
and a qualified replacement was named (section 06. 1).
This integrated inspection to assure public health and safety included aspects of licensee operations, maintenance, engineering, and plant support.
The report covers a six week period (January 1 to February 15, 1997) of resident and project manager inspection.
In addition, the report includes regional announced inspections of licensed operator requalification training programs
.
and service water followup.
0 erations
Plant Nuclear Safety Committee activities were in accordance with regulatory requirements.
Committee discussions were thorough, and reflected nuclear safety concerns (section 06.2).
Strong self-assessment capability was demonstrated during the annual plant manager all-hands meetings.
This included past and present performance, future goals, and areas for improvement (section 07:1).
Operations'rror reduction programs appeared to be effective.and were proactive.
A new peer check process was recently implemented and,should be proceduralized to ensure consistency (section 07.2).
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The periodic Turkey Point status meeting was noted to be an effective self-assessment mechanism, and was attended by senior corporate management (section 07.3)..
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Operations oversight of the Unit 3 startup transformer outage w'as very good, including minimizing the out-of-service 'time (section M4.1).
Maintenance Routine maintenance and surveillance testing activities observed were well performed (section Ml.l).
Auxiliary feedwater pump maintenance on the electrical overspeed trip device was very. good.
Issues with a newly developed procedure were appropriately dispositioned (section M1.2).
A failure of the 30 intake cooling water pump'otor was appropriately addressed (section Hl.3).
Component cooling water heat 'exchanger retubing activities were well planned and performed.
Strong field supervision was evident (section M1.4).
l Steam leak repairs were appropriately made on the 3B steam
'enerator feedwater pump flange and the 3C feedwater control valve (sections Hl..5 and M2.1').
Instrumentation and Control personnel responded timely to a minor.
steam generator level perturbation, and were able'o identify and correct the problem.
Strong system knowledge was evident (section H2'.2).
Maintenance and test activities associated with a pl.armed Unit 3
'tartup transformer outage were excellent (section H4.1):
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I
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A new Maintenance Manager was selected to replace an individual who resigned (sectien M6. 1).
En ineerin
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Very good engineering support was noted f'r maintenance and operations (sections 01.1, 01.2, M1.3. M1.4, Ml.5 and M4.1)
and M1.2).
Strong risk assessment
'support was noted when one Unit 3 intake cooling water pump failed and other equipment was'cheduled for
'aintenance, and duiing the planned Unit 3 startup transformer outage '(sections M1.3 and M4.1).
Event Response Team performance was excellent, and good root cause investigations were performed (sections M1.2 and E2..2).
Licensee engineering personnel appropriately identified and reported a potential surveillance testing deficiency with,steam line isolation logic (section El.l).
A xenon poison concentration anomaly was conservatively dealt with by operations an'd reactor engineer personnel during a Unit 3 startup.
However, this issue could have been better pursued, communicated, and resolved prior to rod withdrawals (section El. 2).
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A very good problem identification program noted, an issue with periodic hydrostati'c testing of nitrogen bottles.
Engineering appropriately evaluated and dispositioned the issue (section
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E2.1).
Rod control power supply'nd electronic card. failures have challenged the licensee and caused several unplanned shutdowns, primarily on Unit 3,.
The licensee's plans to address these issues appeared to be appropriate (section E2.2).
The licensee's criticality monitors met regulatory requirements (section E2,3).
The service water followup open item was closed.
Further,.
licensee corrective actions were effective except in two cases (section E2.4).
An unresolved item was identified r'elative to engineering safety evaluations to support modific'ations and safety analysis report updates (section E3. 1).
S A new systems engineer manager was named (section E6. 1).
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Routine and Special reports were timely and well written (section'S 1)
T
Plant Su ort
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The licensee appropriately documented.
dispositioned, and corrected several health physics related issues that were reported anonymously through the condition report system (section Rl. 1).
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The licensee adequately addressed an issue regarding the lack of phones in the turbine building control point (section R1.2).
~ 'icensee efforts to reduce site radiation exposure have been effective as demonstrated by "best-ever" Person-Rem performance in 1996 and ALARA Review Board activities (section R6. 1).
~
Periodic testing of the Unit 3 startup transformer deluge system was very good, with excellent procedures (section H4. 1).
TABLE OF CONTENTS Summary of Plant Status I.
Operations
..
.
II.
Maintenance
..11 III.
Engineering IV.
Plant Support
..18
..30 V.
Management. Meetings Partial List of Persons Contacted List of Items Opened, Closed and Discussed Items List of 'Inspection Procedures Used List of Acronyms and Abbreviations
.32
34
35
5 J
REPORT DETAILS Summary of Plant Status Unit 3 At the beginning of this reporting period, Unit 3 was operating at or near full power, and had been on line since September 27, 1996.
A routine load reduction to'40K power for testing occurred during the period January 5-6, 1997 (section 01. 1).
A voluntary unit shutdown due to a dropped rod occurred on January 15, 1997.
The unit restarted the following day (sections 01.2 and El.2).. On January 30, 1997, the 3B steam generator feedwater pump (SGFP)
developed a flange leak causing the unit load to be reduced to 55K 'power (section H1.5).
The unit was
.
returned to full power on January 31, 1997, and remained there for the rest of the inspection period.
Unit 4 At the beginning of this reporting period. Unit 4 was operating at or near full power, and had been on line since October 24, 1996.
A routine load reduction to 40K power for testing occurred on February 3, 1997.
The licensee voluntarily shutdown the unit to Mode 2 to address turbine testing issues.
The pnit returned to service later-that same day (section 01.1).
The unit operated at full power the remainder of the inspection period.
~Com on NRC Chairman Shirley A. Jackson and the Region II Regional Administrat'or.
Luis A. Reyes,visited Turkey Point on January 24, 1997.
They toured the facility and met with FPL management personnel.
A special assist from headquarters and the region reviewed'the licensee's security systems and guard performance.
This will be-documented, in NRC Inspection Report No.
Nos. 50-250..251/97-02.
ti
Conduct of Operations 01. 1 Units 3 and 4 Planned Load Reductions for Turbine Testin 71707
Operators reduced the load on Unit 3 from 100K to 40K power on January
.
5, 1997. to perform routine turbine valve'esting per procedures 3-OSP-089.
Main Turbine Valves Operability'est, and 3-0SP-200.3, Hain Turbine Trip Test.
The unit was returned to full power at 8:30 a.m.
on January 6,
1997.
Unit 4 load was also reduced to 40K to perform turbine testing and routine maintenance on February 3; 1997.
Problems with the test
.
(procedure 4-0SP-089, Main Turbine Valves Operability Test)
caused
01.2
operators to abort the valve testing.
No.
1 control valve oscillations were observed.
Licensee management elected to remove the unit (Hode 2)
from service.
The OSP was successfully performed with the unit off-.
line.
The licensee followed up with Condition Report No.97-187, and concluded that the problem was probably associated with the test mechanism and its interaction with the No.
1 control valve servo motor.
Corrective actions included initiation of CR No.97-151, and plans to conduct a complete root cause and repair when possible.
Until then, the licensee intends to remove the unit 'from service to conduct turbine valve testing.
The unit was returned to service at 7:55 p.m. that same day.by manually paralleling due to problems with the auto synchronizing circuit.
The inspector observed portions of the testing and reviewed the completed OSPs,.reviewed operator logs, observed portions of the power changes, and discussed these evolutions with operators and management.
The inspector concluded that the planning and execution of these load reductions were excellent.
.Procedure compliance and teamwork were noted to be strong.
Malfunctions of the Unit 4 valve testing and automatic synchronizing ci rcuits were appropriately dispositioned by an Event Response Team (ERT).
Good engineering support.was noted.
The inspector also reviewed the turbine testing requirements.
Technical Specification (TS) revisions in the early 1990's removed the testing requirement; however, the licensee tests the turbine valves to meet turbine vendor recommendations and warranty requirements.
Currently the testing is quarterly, but the licensee is reviewing. this frequency.
Unit 3 Rod Dro and Power Reductions 71707 93702 At 8:40 a.m.
on January 15 1997, with Unit 3 at 100K power, control rod E-11 in shutdown bank B failed to respond to outward rod bank motion during procedure 3-0SP-028.6, Rod Periodic Test.
Operators entered both procedure 3-0NOP-028, Reactor Control System Malfunction and Technical Specification (TS) 3. 1.3.5.
In addition, a power range deviation alarm occurred, and operators also entered.3.-0NOP-059.9, Excessive Quadrant Power Tilt Ratio (QPTR).
Additionally, at 9:34 a.m.,
rod E-11 dropped into the reactor core when shutdown bank B was returned'to a *full out position (e.g.,
228 steps).
The'rod was declared inoperable:
TSs
.
'.
1.3. 1.d.3 and 3.2.4 were entered; and, procedures'3-.0NOP-028.
1, Rod
"
Misalignment, and 3-0NOP-028.3, Dropped Rod, were both implemented.
As required by the various ONOPs and TS Action Statements (TSASs). unit power was reduced initially to 70% by 10:22 a.m. then to 63K by 11:53 a.m.,
and eventually to <50K by 12:02 p.m.
As required. by the TSASs, the power range high flux trip setpoints were reduced to 52K.
Reportabi lity requirements per
CFR 50.72 and procedure O-ADH-115.
Notification of Plant Events were reviewed.
The licensee concluded that a single rod drop was not reportable based on no RPS actuation, no TS required shutdown, and other requirements reviewed.
18C personnel
'began troubleshooting the rod control system.
Based on potential risk to the
'unit during continued troubleshooting, the licensee elected to shut down Unit 3.
Mode 3 was entered at 6:38 p.m. later that da e
The inspector and an operator licensing examiner were in the control room during the rod drop, and for event followup observing-licensee actions.
TSAS and ONOP compliance and use were independently verified.
The inspector also reviewed reportabi lity requi rements, and concluded the event to be not formally reportable to the NRC.
However, the licensee informed the resident inspector as a courtesy notification.
The inspector observed the power reductions and overall licensee response.
The inspector'oncluded that the licensee response was very good and appropriate.
.ONOP and TS comp'liance was sound:
command and control, and communications were very good; and, conservative operation and decisions were noted as evidenced during troubleshooting and 'the decision to shutdown the unit.
Very good support from engineering and maintenance was also observed.
NRC followup to the rod problem, and restart activities are discussed in report sections E2.2 and E1.2, respectively.
Cold Weather Im lementation 71714 During the weekend of January 17-20, 1997, measured outside air temperature less that 39'F required operatoirs to enter procedure 0-ONOP-103.2, Cold Weather. Conditions.
The lowest noted temperature was about 33'F.
During this period, the Unit 3 and 4 diese1 driven instrument air compressors (3CD and 4CD) failed to start during routine operator testing.
The licensee attributed this to low oil temperatures caused by the cold weather, and a failed heater on compressor 3CD.
Corrective actions included repai'rs and ONOP revisions to check compressor 3CD and 4CD, and all other diesel related equipment during cold weather conditions.
This was documented in Condition Report (CR) No.97-072, including Maintenance Rule applicability.
The inspector reviewed operator logs, the CR, and ONOP implementation; verified procedure.compliance; and, discussed.this item with operations and shift management.
The inspector concluded that ONOP implementation was appropriately p'erformed.
Further, operators appeared proactive in dealing'ith the effects of col.d weather, as evidenced by precautionary actions and monitoring prior to the ONOP entry requirements.
Corrective actions relative to cold weather effects on the outside instrument air diesels (3CD and 4CD) were a
ro riate.
01.3 Also during the inspection period, the new fuel was moved from the storage racks, to the spent fuel pit (SFP),
and pre-refueling shuffle pp p
01.4 Unit 3 New Fuel Recei t and Pre-Refuelin Shuffle 60705 During the'nspection period, the licensee received five shipments, of new fuel for the upcoming Unit 3, Cycle 16 refueling outage.
The shipping containers were unloaded and stored temporarily.
The new fuel
,'as then opened and unloaded, inspected, and then moved to the new fuel storage racks.
The licensee used procedures O-OSP-040.11, Receipt of New Fuel, 0-0P-040.1, Handling New Fuel Shipping Containers and New Fuel Assemblies and 0-ADM-035. Limitations and Precautions For Handling New Fuel Assemblie 'Ig
02.1 activities were performed.
This was per p'rocedure 3-0P-040.3, Refueling Pre-shuffle in the SFP.
and procedure O-ADM-556, Fuel Assembly and Insert Shuffle.
This activity was temporarily stopped based on third party observations and related management concerns.
Issues associated with equipment problems and oversight were addressed and the fuel activities were re-commenced.
The licensee. developed an operating department instruction (ODI) ODI-C0-002, Guidance For Movement of Fuel From New Fuel Room to Spent Fuel Pit.
The procedure strengthened oversight by requiring senior licensed operators (SROs) in both areas (e.g.,
SFP and new fuel room),
and further required a briefing per procedure O-ADM-217, Conduct of Infrequently Performed Tests or Evolutions.
The inspector reviewed the above referenced procedures, observed the new fuel movement, receipt and shuffle activities, and discussed these activities with licensee personnel.
The, inspector verified that SROs were in cha'rge of al'l evolutions, and that the criticality monitors per
. 10 CFR 70.24 (e.g.. radiation monitors 1421 and 1423) were oper able.
See section E2.3 for'further information.
The inspector concluded that these new fuel activities were appropriately performed.
Enhancements to the process based on feed back from observations were'ppropriately.
implemented.
Good teamwork among operations, reactor engineering, Health Physics (HP), security; and Quality Control (QC) was noted.
Operational Status o'f Facilities and Equipment S stem Verification 71707 During the inspection period, the inspectors verified'system lineups from the control room and in the field.
Probabilistic Safety Assessment
.(PSA)
information was utilized, and the following risk significant
,systems were i.nspected:
Unit 3 and Unit 4 AFW (section M1.2)
Unit 3 CCW (section Ml.4)
Unit 4 RPS (section M1.1)
Unit 3 rod control (sections 01.2 and E2.2)
Nitrogen backup to safety systems (section E2.1)
The'nspector did not identify any li'neup deficiencies.
Strong performance was noted relative to AFW system realignments and the use of independent verifications.
Minor issues were discussed with operators.
and management personne.1 03.2
Operations Procedures and Documentation Emer enc and Off-Normal 0 eratin Procedures EOPs and ONOPs 71707 During the inspection period; the inspector reviewed selected EOPs and ONOPs.
This was accomplished during actual procedure Implementation (sections 01.2 and 01.3). during training use, and during table top/office reviews.
The inspector also reviewed recent Condition Reports (CR) which addressed EOPs and ONOPs.
CR 96-1587 addressed post-'ccident'hemical addition as required by EOPs 3/4-EOP-E-1.
Loss of Reactor or Secondary Coolant (LOCA).
The CR questioned a temperature limit for chemical addition and mixing'n the boric acid batching tank.
The CR appropriately dispositioned the issue, and EOP changes were effected.
The inspector reviewed the CR and EOPs.
Attachment 1 of procedures 3/4-EOP-E-1 delineated the requirements'for mixing and injecting the post-accident chemicals (borax) for pH control of the primary containment.
sump, and RHR systems. 'his action is required to begin within eight hours. of a LOCA.
The EOPs did not specify the location of the,
'hemicals; therefore, the inspector questioned. several licensed operators 'regarding their location.
Apparently the chemical stor'age
'location had changed, thus there was some confusion as to the current storage location.
The chemicals were located in the central receiving facility..
The inspector was informed that a periodic OSP verified the location and inventoried the chemicals monthly.
The inspector concluded that the EOP should be revis'ed.to delineate the storage location for the post-LOCA chemicals.
The licensee agreed.
and initiated a change.
Other reviewed ONOPs and EOPs were well written a'nd generally acceptable to accomplish. the abnormal or emergency condition.
Specific comments
.
and'improvements were discussed with the licensee (section 05;1).
General 0 eratin Procedures GOPs
'1707 During Unit 3 and Unit 4 power changes (see sections 01.1, 01.2, and H1.5), the inspector observed the following proceduresimplementation:
3/4-GOP-103, Power Operation to Hot Standby 3/4-GOP-301, Hot Standby to Power Operation The inspector noted excellent procedural compliance and positive oversight by shift and operations management.
The inspector noted that
.
step 5. 16 of procedure 3/4-GOP-103 delineated guidance for steam generator level control when less than 15K power.
The inspector identified enhancements in the GOP relative to the automatic and manual control of the main feedwater regulating valves.
and interfaces with the bypass valves.
The licensee intends to address these issue~.
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05.1
Operator Training and Qualification Licensed 0 erator Re uglification Pro ram Ins ection Ins ection Sco e
71001 The NRC conducted a routine, announced inspection of the licensed operator requalification program during the period January 13-17, 1997.
The inspectors reviewed and observed annual requalification examinations conducted by the licensee and, conducted inspection activities in accordance with Inspection Procedure 71001.
Acti.vities reviewed included examination development and administration, evaluator performance, remedial training, and conformance with operator license conditions.
e Observations and Findin s The inspectors reviewed the sample plan developed for the examination which. covered the last two year cycle.
The. overall sample plan construction was satisfactory.
The inspectors reviewed two biennial written examinations administered last year for quality and content.
The written examinations content covered a range of topics selected from the sample plan including events, plant modifications, and PSA topics.
The inspectors found a
weakness in the area of quality and reliability.
The examinations contained numerous questions which directed the operators to a specific procedure where the answer was highlighted in a note or caution.
This direct-look-up type of question is not an acceptable. means to measure an operator"s knowledge in an open reference examination.
In addition, the-inspectors reviewed the scores for Licensed Operator Continuing Trainin'g
.1995/96 annual examinations, and found that over 50K'of the licensed operators scored 95K or higher.
These findings indicated that the written examinations were not as useful.a tool as they could be to
. discriminate a competent operator, from a non-competent operator
.
Having an operator look up an answei does not measure his or her level o'
competence..
The exams should be constructed to assure operational validity. i.e. closer to job requirements by testing at a higher level of comprehension and analysis.
Greater reliability and validity of an examination increases the confidence factor that'n operator who passes the examination is competent.
,
The inspectors also reviewed remedial training programs and the operational and industry events feedback process into the continuous training program.
No deficiencies were noted in these areas.
The inspectors observed the operators'erformance during simulator scenarios.
In addition, the inspectors observed.evaluation critiques performed by licensee evaluators.
The inspectors found the evaluators'erformance in identifying'and documenting both individual and crew performance deficiencies to be satisfactor c
06.1
The inspectors observed both the evaluators and the operators during the administration of some Job Performance Measures (JPM).
The evaluators'dministration of the examination was satisfactory.
The performance of the operators was overall satisfactory.
However, one particular JPM,.
"Align Safety Injection for Cold Leg Reci rc," was failed by 25 percent of the operators taking the test.
During performance of the task, the three operators incorrectly performed step 19 of procedure 3/4-ES-1.3, Transfer to Cold Leg Recirculation.
The step.
repeated below. did not specify which of the four High-head Safety Injection (HHSI) pumps to place in pull-to-lock (PTL).
The intent of'his step was to ensure a
pump would not start while its inlet and outlet valves were shut in subsequent steps of the procedure.
Place The Following Pumps In Pull-To-Lock:
o Contai'nment spray pumps o
High-head SI pumps One operator placed only the one operating pump in PTL prior to closing the suction and discharge valves.
A second operator did not place the pumps in PTL, and closed the suction and discharge valves on a running HHSI pump.
This. action would have caused pump destructioh.
A third operator, stopped the one operating pump and did not place any pumps in PTL.
A fourth operator successfully completed the JPM and placed all four HHSI Pumps in PTL.
However, he did not restore them to standby upon completion of the task, thereby rendering the other units HHSI pumps inoperable.
The inspectors concluded that Step 19 of procedure 3/4-ES-1.3 did not contain sufficient detail to enable operators to successfully.complete the intent of the procedure.
The operators were not sure if all four pumps or only the pumps aligned to the affected
. unit were to be placed in pull to lock.
The procedure also did not
. contain guidance to realign the pump switches following completion of the task.
The licensee initiated CR'No. 97-65 and corrected step 19 of procedure 3/4-ES-1.3 prior to the c'ompletion of the period.
E Conclusions The inspectors concluded that the licensee's requalification program complied with. the requirements of 10 CFR 55.59 for the areas-inspected.
The inspectors found that the program was capable of ensuring safe power.
plant operation by adequately evaluating individual operator's mastery of the training objectives.'ritten examination quality was one area in need of improvement to ensure examination validity.
Operations Organization and Administration 0 erations Su ervisor Chan es 71707 Effective February 5, 1997, the Operations Supervisor.,
Mr. A.
M. Singer was transferred to St. Lucie.
Mr. T. 0. Jones, was appointed as the replacement Operations Supervisor.
Mr. Jones was previously ari acting I
Operations Supervisor and a former NPS.
The inspector verified that his qualifications and training met regulatory requirements.
06.2 Plant Nuclear Safet Committee PNSC Meetin a.
Ins. ection Sco e
71707 and 40500 The inspector attended a regularly scheduled licensee PNSC meeting to evaluate licensee self-assessment activi,ties, and to determine if PNSC activities were performed in accordance with Technical Specification (TS) 6.5. 1 requirements.
b.
Observations and Findin s On February 11, 1997, the inspectors attended a regularly scheduled PNSC meeting in order to assess activities and compliance with TS requirements.
A required TS quorum was present.
Items recommended for approval did not present any new unreviewed safety questions (USQ)..
Plant Change/Modifications (PC/M) and agenda issues were thoroughly discussed and the following associated committee actioris were taken
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PC/M 95-081
- Abandonment of AUxiliary/Radwaste Building Auxiliary Steam (AS) Desuperheater Stations, Condensate Recovery Transfer Pumps and AS Components.
The issue involved a proposed UFSAR change to allow for post-LOCA chemical batching at 39'F rather than 55'F. With
'emoval of the AS supply, 55'F would not always be achievable.
A licensee engineering safety evaluation (SE)
(ENG-SEMS-97-006)
was performed.
The evaluation determined that AS. system abandonment did not involve a USQ and batching at 39'F was acceptable.
Also.
according to the evaluation, post-LOCA chemical (Sodium Tetraborate Decahydrate) solubility would not be affected, and the current TS margin of safety would not be reduced.
The PNSC recommended approval.
This PNSC-approved modification will'abandon in.place" AS
~
to the Boric Acid/Waste Disposal Evaporators and also to the batch
", tank and control building heating.
Condensate recovery items are to also be "abandoned in place".
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PC/M 96-040
- Documentation
'Changes For Resolution of'ppendix R
Condition Reports.
The issue involved various revisions'that were made to accurately describe current '"as found" Apperidix R design features.
Revisions included changes to the licensee's Appendix R
Safe Shutdown Analysis, the Essential Cable/Equipment Lists, Fire Wrap drawings and related changes to licensee procedure 0-ONOP-16. 10.
No actual (i.e., physical) modifications were presented by the proposed changes.'
licensee engineering safety evaluation determined that the proposed resolutions would not impact safety,-
constitute a
USQ or require changes to the licensee TS.
The PNSC recommended approval.
Temporary System Alteration (TSA) 3-97-006-003 -. To Provide Temporary Power To The Containment During The 1997 Unit 3 Outage.
This TSA involved'establishment of'p of two temporary power supplies
P
to the containment via existing electrical penetration T3P63.
Spare conductors in the penetration were proposed for use.
Temporary power was necessary for operation of eddy current testing equipment during'-
the upcoming Unit 3 outage.
The penetration's conductor capability and design capacity were discussed, and an associated design analysis was presented.
A containment penetration integrity analysis was also presented, discussed, and approved.
The TSA was recommended for approval by the PNSC.
c.
Conclusions The inspectors found performance of PNSC activities to be acceptable and in accordance with established licensee practices and NRC requirements.
Activities performed followed prescribed actions contained in TS Section 6.5. 1 and associated subsections.
Committee discussion of issues was thorough, and the PNSC recommendations were appropriate and reflected nuclear safety concerns.
Quality Assurance in Operations 07. 1 Plant Mana er Briefin s 40500 During the peri.od, the plant manager briefed site personnel regarding past achievements and accomplishments, future goals and challenges, and areas for improvement.
1996'chievements included strong regulatory performance and the following discussed items:
Successful Unit 4 Cycle 16 refueling outage with all goals met, Both units completed a power uprate.to 2300 megawatts thermal, High un'it availability (Unit 3 95K. Unit.4 88K),
Excellent radiation'rotection performance (e.g.,
186 Rem exposure, low contamination events.
and minimal contaminated floor space),
Good personnel safety performance',
and Other FPL awards and achievements;
The 1997 goals were addressed rel'ative to unit availability and outage performance, radiation exposure; and personnel safety.
Notwithstanding
. past achievements, management communicated to. all employees that 1997 would be a challenging year.
Attention to detail, conservative operation 'and decision making, and nuclear and personnel safety were stressed.
The inspector attended one of the briefings, and.discussed this with site and plant 'management.
The inspector reviewed the 1996 performance, areas for improvement, and'997 goals.
The inspector. concluded that the
'icensee was self-critical, and their self-assessment capability was stron J
07.2 Error Reduction Pro rams 71707 and 40500 a.
Ins ection Sco e
The inspector reviewed the licensee's operations er ror reduction programs.
b. Observations and Findin s Operations management recently conducted meetings with each shift re-eni'orcing expectations and requirements.
Further, each NPS discussed the subject during shift turnover and crew briefings.
Items reviewed included the following:
Self-checking in accordance with the Stop-Think-Act-Review (STAR)
policy.
Three point communications, Annunciator response guidelines, and procedure compliance per O-ADM-201, Operations Procedure Usage, Valve manipulation errors and expectations per the operating department instructions (ODI-C0-18),
Independent and dual concurrent verifications per procedure O-ADM-31, Independent Verification, Peer checks per memo dated December 23, 1996, and Skill of the Craft Month Program.
The licensee uses the above programs, procedures.
and processes in order to minimize human errors..
A negative trend in valve mispositioning
.
events was addressed during the period late 1995 to early 1996.
These issues were addressed in previous NRC Inspection Reports.
The inspector reviewed the peer check process for control room operators
per the above referenced operations memo.
This process requires that all control room manipulations be checked by another operator of equal
.
or higher qualification.
The second operator will verbally acknowledge, that the correct device has been selected.
prior to the first operator erforming the manipulation.
This process has not been proceduralized, owever, the licensee is considering incorporating the Peer Check process into an ODI or an ADM.
The inspector also reviewed the peer check process with regards to minimum TS control room staffing (e.g.,
RCO on each unit and one SRO).
Since the RCO is the "operator at the controls". the inspector questioned whether one unit RCO could peer check the other. unit RCO.
The licensee stated that this was acceptable as long as the peer check was brief (e.g..
a few seconds)
and did not require the checker to
0,
physically exit the "at the controls" or surveillance area per procedure O-ADM-200, Conduct of Operations.
Further, the checker should not be distracted from his or her safety duties.
c. Conclusion Operations'rror reduction programs appeared to be effective and proactive.
Recent trends have shown some'hort term success.
The new p'eer check process should be proceduralized to ensure consistent implementation.
, 07.3 Turke Point Status Meetin 40500 The inspector attended the January 28, 1997, Turkey Po'int status meeting.
These meetings are held periodically at the site to assess performance.'enior 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, department reports, and future ch'all'enges.
The inspector noted frank and open discussions.
The inspector concluded that the licensee's self-assessment capability was demonstrated as evidenced by critical questioning, senior corporate and plant management involvement.
and a
strong safety focus.
II. Maintenance
~M1 Conduct of Maintenance Ml.1 Gener al Comments a.
Ins ection Sco e
62707 and 61726 Maintenance and surveillance test'activities were witnessed or reviewed.
~ The inspector witnessed or reviewed portions of the following maintenance activities in progress.
t Unit 3 rod control troubleshooting (sections 01.2 and E2.2).
I Unit 3 3A steam generator (S/G) level control perturbation (section M2.2).
Unit 3 3C feedwater control valve repair (section M2.1).
Auxiliary Feedwater (AFW) A overspeed trip device repai r (section M1.2).
'
3C intake cooling water (ICW) mot'or replacement (section Ml.3).
M1.2
3B component cooling water (CCW) heat exchanger retubing repairs.
. (section Ml.4).
3B steam generator feedpump (SGFP) flange leak repair (section M1.5).
The inspectors witnessed or reviewed portions of the following test activities:
AFW train 1 and 2 routine testing (section M1.2),
4A reactor protective system,(RPS)
testing,
\\
Unit 3 rod control testing (sections 01.2 and E2.2).
P b.
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.
c.
Conclusions Observed maintenance and surveillance activities were well performed.
Auxiliar Feedwater AFW Overs eed Tri Device a.
Ins ection Sco e
61726 and 62707 During a operational surveillance performance test (OSP)
on the A AFW
'Pump per procedure 4-OSP-075. 1, on January 7,
1997, an overs'peed trip device actuation occurred during steady state operations.
.The inspector reviewed troubleshooting, maintenance, and testing activities in the followup to this, abnormal occurrence.
b. Observations and Findin s During the OSP on the A AFW.pump, the turbine's trip and throttle valve shut on an apparent electrical overspeed si'gnal.
The licensee declared the pump inoperable, and entered Technical Specification (TS) Aetio'n Statement (TSAS) 3'.7.1.2.
which required both trains of AFW to be operable within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
A Condition Report (CR)
No.97-020 was written to document the problem.
The licensee performed a pull test on the governor. stem per work order (WO) 97000306, and initiated an overspeed trip test of the A AFW per procedure 3/4-0SP-75.9.
Both tests were completed satisfactorily with no abnormalities noted.
The licensee aligned the C AFW pump to train 1 of the system, and verified-
operability of both trains exiting the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> TSAS.
This allowed the licensee to enter a 30 day TSAS for a single inoperable AFW pump.
The licensee assembled an event response team (ERT) and performed a root cause analysis for the event.
The ERT determined that the most likely cause was a spurious trip of the oyerspeed trip device.
A speed sensor problem was not ruled out.
Electricians noted that the speed sensor voltage dipped from 47 volts (V) at a turbine speed of 5900 revolutions per minute (rpm) to 36 V,at 6200 rpm.
The speed sensor provides the
tachometer with a signal that is converted to an output signal proportional to speed.
The licensee chose to replace the sensor with a new one.
The new sensor exhibited normal voltage characteristics.
The overspeed trip device was susceptible to internal component malfunctions, radio interference, and electronic interference.
Although the licensee could not reproduce the false trip signal, they believed that this component,was the most likely cause.
The A AFW pump turbine tachometer was replaced with an upgraded version.in August 1995.
The reason f'r the replacement was to al.low the tachometer to.serve as a
spare for the other AFW pumps.
The licensee decided to reinstall the original tachometer into 'the A AFW turbine control system.
'However, electricians could not get reproducible results on the bench.
.
A new tachometer module was purchased, dedicated, installed and calibrated on January 9,
1997.
The inspector observed portions of'he
.installation and calibration of the device.
Electricians used procedure O-PHE-075.2, A Auxi.liary Feedwater Turbine Speed Monitor and Overspeed Trip Calibration.
This was a first time use procedure, and the normal editorial problems were detected and properly corrected by the electricians.
The procedure had the electricians adjust the HETER CAL potentiometer to an indicated speed of 4000 rpm.
Next the frequency generator was adjusted to an output of 5760 Hertz to check the rpm. The
'utput was outsi,de of the acceptance criteria, and no guidance was given on how to proceed.
Electricians stopped work and requested Engineering's assistance.
Engineering conferenced'ith the vendor and determined that there should be a band specified'hen the METER CAL potentiometer was adjusted.
This would be an iterative process to get the module adjusted appropriately.
Engineering performed an On-The-Spot-Change (OTSC 006-97) to the procedure to correct the deficiencies.
The calibration was completed satisfactorily, and the AFW system was restored to normal operation by operations.
c. Conclusions The licensee was conservative in declaring the A AFW Pump inoperable.
All Technical Specifications were met, and an appropriate awareness was placed on the system by Operations.
Electrical department performance was very good.
A sound questioning attitude was maintained by the technicians throughout the project.
Engineering support, including ERT
'followup, was competent.
There were some problems with the first time use procedure used to'complete the tachometer calibratio '14 3C Intake Cool in Water ICW Pum Failure 62707 With Unit 3 shut down for a rod control problem (see section 01.2), the 3C ICW pump tripped at 12:50 a.m.
on January 16, 1997.
ICW low.pressure alarms and B phase overcurrent trips were observed.
The standby ICW pump was started, and the ICW low pressure condition was adequately addressed.
Operators entered TSAS 3.7.3.a (7 days with 3A and 3B ICW pumps operable with independent power supplies).
Condition Report No.
97-59 was generated to.address the issue.
Maintenance performed motor and cable checks, and concluded that 'the 3C ICW motor had failed '(e.g.,
the B phase was shorted).
The motor was removed, and an on-site spare motor was installed.
Testing and maintenance was successfully completed and, the 3C ICW pump was declared operable on January 19, 1997.
The licensee returned the failed motor to the vendor (Tampa Armature) for the warranty checks and root'ause failure analysis.
This determined the failure t'o be attributed to vendor work.
Long term corrective actions including Maintenance Rule issues are pending.
The inspector intends to review this in a future inspection.
The inspector verified appropriate TSAS complianc'e and observed portions of maintenance activities.
The inspector concluded that operator and
. electrical'aintenance personnel appropriately responded to this
'ailure.
The inspector noted a strong safety.and risk conscious attitude as the 3B CCW heat exchanger was OOS for retubing
'imultaneously (section M1.4).
Although allowed by TSs and the OOS equipment matrix in procedure O-ADM-210, On-Line Maintenance, the licensee convened 'a special PNSC to review the risk significance.
The PNSC reviewed the above documents and a June 30, 1995, risk impact assessment (JPN-NR-95-038)..
The corporate risk group also reviewed the impact of single-ICW header being OOS during basket str ainer cleanings.
The PNSC concluded and recommended to plant management that.risk had been appropriately 'addressed for the above combinations of OOS
.'quipment.
Engineering support for these risk assessment activities was very good.
Ml.A 3B Com onent Coolin Water CCW Heat Exchan er Re-tubin 62707 On January 16, 1997, the licensee removed the Unit 3 3B.CCW heat exchanger from service to replace the tubes (re-tube).
The Turkey Point units each'ave three 50K CCW heat'xchangers.
TS 3.7.2.b only requires two heat exchangers, thus the third is an installed spare.
Since no TSAS exists for one OOS heat exchanger, the l,icensee voluntanly uses a
,'2-hour administrative guidance.
Because this retubing activity was scheduled for longer than 72-hour administrative guidance, the PNSC reviewed and approved an extension of up to 12 days.
Risk assessment was also performed. with no. appreciable increase in core damage frequency (CDF), preceived even with simultaneous OOS equipment (see section M1.3).
The inspector reviewed the risk assessment and maintenance activities.
.During the tube removals; the licensee noted foreign material within the shell side.
Condition Report No. 97-70 was written, and an operability assessment concluded that all other Unit 3 CCW heat exchangers
.remained operable even if they contained similar foreign material.'he foreign material was analyzed to he initial startup strainer wire mesh (probably from the 1970's).
These are original heat exchangers on Unit 3.
The Unit 4 CCW heat exchangers were replaced in the 1980's.
The licensee intends to inspect the remaining two heat exchangers (3A and 3C) during future maintenance activities.
The inspector reviewed the CR and related maintenance work, including heat exchanger cutting and retubing.
and radiograph requirements.
Further an NRC specialist also reviewed these issues.
The inspector
'oted that the maintenance was completed and the 3B CCW heat exchanger returned to service on January 27, 1997, within the PNSC approved administrative extension.
The inspector concluded that the maintenahce activities were well planned and executed.
Field supervision and engineering support were strong, and evident at all times.
3B Steam Generator Feedwater Pum SGFP Re air 62707 At 5:50 p.m.
on January 30, 1997, fire watch personnel reported a steam leak which was traced to the 3B SGFP flange.
Operators reduced Unit 3 load to 55K and removed the 3B SGFP from service at 6:40 p.m.
The power change was purposely slow to account for the effects of xenon late in core life for Unit 3.
Maintenance'nd engineering personnel inspected the flange leak.
and performed a temporary repai r per procedures.
The 3B SGFP had been previously repaired using furmanite material, and the licensee believes that the cycling of the unit (shutdown on January 15. 1997,)
caused the'lange leak to recur.
The licensee had already planned to effect
'ermanent repai rs during the Unit 3 Cycle 16 refueling outage (March 1997).
The 3B SGFP was returned to service, and the unit returned to full power, on January 31, 1997.
The inspector examined the SGFP and leak areas, and observed temporary repairs.
The inspector concl.uded that repairs were consistent with procedural guidance.
Good teamwork between engineering'nd maintenance was observed.
Maintenance and Material Condition.of Facilities and Equipment M2. 1 Unit 3 Feedwater Valve Bonnet Leak Re air 62707 On January 7,
1997, the inspector noted that the Unit 3 feedwater control valve FCV-3-498, to the 3C Steam Generator had a steam leak emanating from one of the flange bolt holes.
Further. the leak was impinging on an adjacent nut.
The inspector discussed this observation with the appropriate maintenance,.
engineering, and operations personnel; The inspector also reviewed the'rocesses used to correct the proble The FCV serves as the safety-related feedwater isolation valve.
The licensee had identified that FCV-3-498.had a body to bonnet steam leak in Condition Report No.96-111, and subsequently performed a
temporary Furmanite leak repair.
Later it was noted that the leak had reformed, and the licensee generated another Condition Report (CR No.
97-0019) dated January 8,
1997.
The new CR requested another Furmanite injection sequence and to solicit any operability concerns that Engineering might have.
Engineering performed a detailed ev'aluation of:
the problem and repair process, and had no additional concerns.
Mechanical Maintenance performed work under work order (WO) No. 97000122 which referenced the Furmanite procedure N-97000 as guidance.
All Engineering recommendations were incorporated into'the WO; The valve was successfully repaired on the morning of January 9,
1997.
The inspector concluded that engineering performed an effective review of the repair to the safety-related FCV.
The licensee performed appropriate levels of review to determine the adequacy of the repair procedure and to determ'ine any.operability concerns.
Maintenance performance was in accordance with procedures.
The inspector verified that permanent repair s were scheduled. during the next refueling outage.
3A Steam Generator SG Level Control Problem 62707 At 9: 11 a.m.
on January 9,
1997, operators received feed flow and steam flow mismatch alarms for the 3A SG, Unit 3 was at 100K power steady-state with the 3A SG l.evel control system in automatic.
The alarms cleared and the feedwater regulati.ng flow. control valve (FCV) remained in automatic control.
The unit operator (RCO) and ANPS notified operations management and maintenance (I&C) personnel.
The SG level perturbation was minor (e.g.,
a, few X change).
I&C engineers and specialists inspected the 'Magan and control board cabinets for possible anomalies.
System and wiring drawings were reviewed, and system response during, the minor SG level transient were also reviewed.
I&C personnel observed a grounding wire which apparently had been touched and moved by engineers inspecting a control board cabinet.
This wire was in close proximity to a steam flow input dev'ice for the 3A SG FCV control circuitry.
Apparently the.grounding wire had momentarily shorted the steam flow input at the terminal board causing the SG level perturbations.
I&C repai red this wiring deficiency.
and inspected other Unit 3 and 4 similar wiring connections.
No'ther anomalies were observed.'he inspector was in the control room during followup activities.
The inspector observed 3A SG level and flow chart recorders, discussed the event with operations and I&C personnel, and inspected the control board cabinets'erminal board connections.
The inspector confirmed the
.
deficiency; however, did not observe any others.
,The inspector concluded that operations and I&C responded timely and very well to thi's
'problem.
'Strong system kn'owledge'as evident.
,
. ~
e
e
N4. 1
Maintenance Staff Knowledge and Performance Unit 3 Start-U Transformer Maintenance Activities a.
Ins ection Sco e
61726 and 62707 The inspectors observed various maintenance activities associated with the Unit 3 startup transformer.
Inspectors also reviewed related licensee pre-outage preparation and post-maintenance testing activities.
b. Observations and Findin s On February 10, 1997, the inspectors noted that operability testing of the emergency diesel generators (EDGs) was adequately performed.
The inspectors also noted that all testing was completed prior to removing the transformer from service on February 11, 1997.
Ove'rail EDG testing was further noted as satisfactory and in accordance with licensee-approved EDG operating and test procedures.
EDG voltages and frequencies were acceptable.
Prior to work being. performed, the. inspectors, during routine walkdowns of the turbine building area, verified that clearance tagging for the affected 4KV breakers (3AB05, 3AA05. and 4AA22), was pr'operly performed.
The inspectors observed that tagging was.correct and in accordance with requirements of work order (WO) No. 96016336..
The inspectors noticed that the licensee's current practice of dual tagging by the'li.censee's off-site Transmission and Distribution group, and their on-site Operations group might be susceptible to'oordination problems.
The plant Operations group danger'ag might not always be the first tag hung and the last tag removed:
The inspectors brought this item to the attention of plant management.
Although this practice hasn:t presented past problems, management has expressed the same interests with the issue.
The licensee is currently looking into various corrective action options to reduce the susceptibility.
On February 11, 1997, the inspectors observed preventative maintenance (PH) activities associated with the 4KV breaker 3AB05.
Craft personnel were knowledgeable about required PMs, and were aware of current vendor recommended PH activities for this type of breaker.
A. high level of craft skill was apparent.
However, after examination of the 'PM work pack'age (WO No. 96013344) the inspectors noticed that recent. breaker vendor information (closing motor relay checks and use of breaker greases)
was not present in the package.
The inspectors noted that WO information lacked adequate updates/revisions.
This issue was. brought to
.'he attention of plant management.
Management agreed with the issue and stated that the'absence of such intormation did not meet their expectations.
The. licensee indicated that they would conduct a follow-up investigation into the issue.
On February 11, 1997, the inspectors observed PH testing of the transformer fire protection (FP) deluge system.
Deluge system testing was perf'ormed per licensee-approved procedure O-SNN-016.9.
The
h J
M6.1 III E1 El. 1
inspectors further noted that the licensee FP group's current practice of functionally and thoroughly testing the system from detector to the deluge sprinkler heads was very good.
During the observed test a desi red fog pattern was noted, only one system nozzle exhibited partial
~
~
lugging, and system deluge was actuated within 20 seconds of applying eat to detector.
Overall system testing was satisfactory.
The inspectors verified that the TSAS and OOS time were within requirements.
The outage was scheduled for 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />, and the TSAS was 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.
No other risk significant equipment was taken OOS during the transformer outage.
No risk related secondary or primary work was scheduled or allowed.
Operations and management maintained very good oversight of plant activities, including switchyard surveill,ance.
c. Conclusions The inspectOrs found'that Unit 3 startup transformer maintenance and
.testing activities were appropriate, and were performed in accordance with licensee-approved procedures.
Very good teamwork was noted among operations, maintenance (includi'ng off-site support organizations),
and engineering.
The inspectors noted a very good practice of performing a
thorough "from detector to sprinkler head",deluge system test, (i.e...a full functional test of the'deluge system).
Haintenance Organization and Administration Maintenance Mana er Chan es 62707 Effective January 17, 1997, Mr. R.
G. Heistermann resi'gned. as Turkey
.
Point Site Maintenance Manager.
Mr. Michael 0.
Pearce (Projects 5upervisor)
was appointed as the replacement Maintenance Manager etfective January 23, 1997.
The Maintenance Manager has direct reports from mechanical, electrical.
18C, projects, and support groups.
En ineerin Conduct of Engineering Generic Letter GL 96-01 Testin Re ortabilit 37551 90712 and
~92700 During GL 96-01 testing'reviews, the licensee identified a condition that could have resulted in missed surveillance testing for Units 3 and 4 main steam (MS) isolation valve (MSIV) logic.
This condition was reported to the NRC as required by a
CFR 50.72 ENS call on January 15, 199?
and LER 96-004, Supplement'
on January 30, 1997.
The licensee documented the issue initially in Condition Report No.97-006.
TS Table 4.3.2 items 4a and 4c require trip actuating device
. operational tests once per refueling for MS logic (manual'isolation and containment high-high pressure).
Surveillance procedures 3/4-OSP-072. 1,
. Main Steam Isolation Test, and 3/4-OSP-203. 1(2), Train A(B) Engineered
0'
Safeguards Integrated Test, implemented these TS requirements.
Because of'he logic design (e.g.,
common train isolation push button)
and a
note in the OSP allowing test exceptions or. waivers, the possibility existed of not adequately testing the MS logic.
Further. if the note was to be applied to more than one of six MS logic trains, the possibility existed that single fai lure criteria would'ot be met.
(There are 3 MSIVs per unit, and each MSIV has redundant MS isolation logic trains except for the common manual isolation push buttons.)
Document review concluded that the note had been invoked twice in the past.
Each time only one valve and one logic train were affected.
The licensee concluded that the TS surveillance was met, and neither'f the units were outside their design bases.
However, since the possibility existed, the licensee concluded this issue was reportable.
The inspector reviewed the above-mentioned documents (e.g.,
generic
'etter, TS, procedures, CR
~
and the'ER).
The inspector concluded that the licensee was thorough in their review, and appropriately notified the NRC of this condition.
The inspector independently confi rmed this possibility by reviewing the TS and logic diagrams.
Further, the safety significance was appropriately evaluated as being minimal.
The bases for this determination were that the licensee was never in a condition of'ot meeting testing requi rements nor outside thei r design bases.
Thus, no violagions of regulatory requirements occurred.
Corrective factions included procedure changes to remove the note.
Further, the final GL 96-01 submittal will also address this issue.'he LER was appropriately submitted, well written, and was closed.
Unit 3.Startu 37551 PNSC and plant. management authorized startup of Unit 3 at about 10:00.
a.m'.
on January 16, 1997.following rod E-11 drop event (sections 01.2 and E2.2).
Reactor engineering and the Shift Technical Advisor (STA)
performed criticality predictions as required by procedure 0-0SP-040.4, Estimated Critical Conditions (ECC)..
Rod,withdrawal began at about noon.
After the third source range doubling, predicted criticality was.
425 percent millirho (pcm) greater than the ECC or at about 190 steps on control bank D.
Operations management directed the control rods re-'nserted until. the ECC issue could be addressed and a. lower control bank D position could'be achieved.
CR No. 97-0061 was written by reactor engineering.
The OSP allowed startup continuation
'as long as the prediction was within 500.pcm.
Furtker, the overall acceptance criteria was within the r'equi rement of 1000 pcm.
Reactor engineering contacted the corporate nuclear fuels group.
The fuels group criticality prediction.was more consistent with what was seen during the startup.
Differences appeared to be in the Xenon poison modelling.
The fuels group used a more 'accurate three dimensional computer model.
The site reactor engineering group used the curves in the plant curve book.
Because of the complicated power history curve
'aused by the dropped rod; multiple down power changes, and axial and radial flux distributions, differences in the two models existed.
PSNC
reviewed these differences, approved the CR disposition and a procedure change for O-OSP-040.4 (OTSC No. 019-97).
Subsequently, new criticality predictions were made by reactor engineering, the STA, and the fuels group.
Close agreement was noted and restart was authorized.
The unit achieved criticality at 5:48 p.m.
on January 16, 1997.
Reactor critical data was 547.6'F, 418 ppm boron
.and control bank D at 72 steps.
The inspector reviewed the-ECC preparations, PNSC activities, control room rod withdrawals, reactor engineering followup, and the OTSC to the ECC procedure.
The inspector also observed selected activities.
The inspector concluded that the licensee responded conservatively, and within the guidance of the procedures..
No violations were noted.
'owever, this xenon poison anomaly and ECC differences could have been better pursued, communicated.
and addressed prior t'o the'nitial rod withdrawals.
The licensee concurred with this finding and intends to address corrective actions.
E2 Engineering Support of Facilities and Equipment E2. 1 Nitro en Bottles'7551 The inspector reviewed CR No. 96-1607 which detailed an issue with out-of'-date hydrostatic tests for a number of Nitrogen bottles on-site.
Some of these bottles provided safety-related backup for AFW, HSIVs, and steam dumps.
The hydrostatic test is required by 49 CFR 173 (Transportation-gases and packaging)
every 5 to 10 years, depending on service.
The licensee performed a three-day operability assessment.
and concluded
.that the safety-related Nitrogen backup. remained operable.
This was based on satisfactory visual inspections of the bottles.
immediate change out of the out-of-.date bottles, vendor assessment of acceptable
. use,. and interpretation, that the 5 to 10 year requirement was primarily for bottle refilling.
Additional corrective actions included ope'rations
.
surveillance. procedure upgrades, PNSC review, successful hydrotesting of all out-of-date bottles, and safety department review of Nitrogen bottle purchase requirements.
The inspector reviewed the completed CR,.including correcti've actions.
Discussions were held with operations and engineering personnel.
The inspector concluded that the licensee's processes self-identified and adequately dispositioned this issue.
E2.2 Control Rod Is'sues Ins ection Sco e
37551 As followup to the Unit 3 dropped control rod event that occurred on
'
January 15, 1997. the licensee initiated an event response. team'(ERT)
and Condition Report No. 97-53.
The ERT reviewed this specific dropped I
~
'
rod indications and circumstances, and also reviewed historical rod control issues.
The inspector reviewed ERT.activities, and overall licensee followup, including Maintenance Rule applicability.
b.
Observations and Findin s
Each Turkey Point unit has 45 control rods or rod cluster control assemblies (RCCAs).
The RCCAs are moved by a control rod drive mechanism (CROM) which is located on the reactor head.
The CRDH uses magnetic forces to engage the RCCA lead screw.
Three gripper coils (stationary, moveable, and lift) are energized from the solid state rod control system.
A logic cabinet generates current. orders which are sent to four power cabinets.
The power cabinets fire silicon controlled rectifiers which send rectified AC power to the various coils from the rod drive motor generator (HG) sets via the reactor trip breakers.
The stationary grippers use 4.4 amps to hold. and 8.0 amps, to engage when stepping ro'ds.
lhe logic cabinet uses phase control, regulation, and
.firing cards to distribute and control CROM gripper coil currents.
The ERT suspected a problem with stationary gripper coil. or rod control signals from either the logic or power cabinets.
Coil integrity was verified to be appropriate.
As dir ected by the ERT, I8C personnel conducted rod testing and troubleshooting activities initially at power, and then when the unit was shutdown to Mode 3.
Based on reviewing rod current traces, the licensee concluded that rod E-ll's stationary gripper coi 1 current orders were remaining at 4.4 amps, and were not being increased to 8.0 amps during rod movements'stepping)..
Thus the rod "let go" and fell into the core during the rod, exercising test (e.g., stationary coi 1 magnetic force was overcome by
,the spring and gravity):
An AC amplifier card (slot A814, serial number
.0039)
was determined to be faulted.
The card was located in the logic cabinet and transmitted stationary current orders to the power cabinet firing card.
Root cause was.a random failure, attributed to a shorted zener diode on-the circuit card.
The card was manufactured in 1974.
and was refurbished by the vendor (Westinghouse)
in 1992 - 1993.
This specific card,was a spare that was placed in,service in 1996.
The licensee also reviewed rod control historical failures over the past few years.
Since 1994, mul.tiple failures have occurred.
The inspector independently reviewed historical fai lures and noted the following:
Eight rod control problems have occurred (seven on Unit 3.
and only one on Unit 4).
Three of the problems were caused by power supply fai lures, which have since been replaced on both units.
Three of the problems were caused by circuit card fai lures.
All-occurred on Unit 3 but in different cabinets:
2BD power cabinet, logic cabinet to 1BD. logic cabinet to 2BD, and 2AC power,:cabine t
Four of the eight problems resulted in dropped rods.
One due,to power supply failure, two due to circuit card failure, and one caused by an external event (water intrusion).
One automatic trip from full power occurred; one manual trip from full power and one manual trip from shutdown conditions occurred; and, three shutdowns (one required by TSs.and two voluntary)
resulted.
Modifications to logic cards (different cards than those noted failures) were performed in September 1995 (Unit 3) and in March 1996 (Unit 4).
These modifications were in response to the GL 94-04 asymmetrical rod withdrawal generic issue.
All of the rod control circuit card problems were on Unit. 3
~
and occurred after the last refueling outage in September 1995.
Rod control room (3B Motor Control. Center)
high ambient temperature occurred in May 1995 due to air conditioning failures and may be related to two failures of the power cabinet ci.rcuit cards (February and September 1996)
The recent card fai lure (logic cabinet)
was not related to this temperature aging issue.
Relative to the. Maintenance Rule, the licensee reviewed for possible maintenance preventable functional fai lures and performance criteria.
Based on corrective actions pending for the outage, on rod control not being a risk related system, and on performance criteria (e.g.,
system and plant) being met', the licensee concluded that. the rod control system should remain in normal monitoring status.
Thus category A(2) of 10 CFR.
50.65 was maintained.
The inspector reviewed licensee corrective actions.
which included:
Unit 3 'rod control troubleshooting, repair activities, and
.integrated,'testing.
II Review of zener diode failures to address possible. replacements.
\\
Continue with plans to lower room temperature, including internal cabinet cooling.
Plans to perform vendor card dynamic testing during the upcoming refueling outages (March 1997 - Unit 3, September 1997
- Unit 4).
Planned card maintenance during the next refueling outages.
I Maintenance Rule applicability.
The inspector reviewed the following'eferences:
NRC Inspection Report Nos. 50-250,251/94-18.
95-9. 95-19. 96-2.
96-11, and 96-1,
0,
LERs Nos. 94-4, 95-4. 95-7, 96-10, and 95-16.
CR Nos.95-299, 96-165, 96-1062, 96-1185, 97-53, and 95-1054.
UFSAR Section 14.1.4.
c.
Conclus ions Turkey Point has'experienced rod control system failures primarily due to power supply failures and circuit card failures.
The power supply failures were appropriately addressed on both units in 1994 and 1995 by replacing'the suspect power supplies.
The circuit card failures have all occurred on Unit 3 since the last refueling outage (September 1995).
Further, the power cabinet card fai lures may be related to high temperature related aging due to Unit 3 room ambient temperature problems that occurr'ed in May 1995. 'he most recent car'd failure was not temperature-aging related, and appeared to be random.
The licensee's efforts to address these problems through their corrective action programs and Haintenance Rule processes appeared to be appropriate.
Further-, previously identified correcti ve actions continue to be valid and 'are scheduled f'r the upcoming Unit 3 Cycle 16 refueling outage (March 1997).
Critica 1 it Monitor s a.
Ins ection Sco e
37551 The inspec'tor reviewed the licensee's compliance with 10 CFR 70.24, Criticality Accident Requirements at Nuclear Plants.
The following
'information was obtained by document review; by procedure review;
.through discussions with operations, maintenance, and other plant personnel; and, through in-field inspections.
. Observations and Findin s The Turkey Point Operating Licenses
'(DPR 31 and 41) do not have any exemptions from the
CFR 70.24 requi rements.
The UFSAR does not explicitly delineate which monitors're criticality'onitors.
However, licensee procedures and the design basis document (DBD) for the Area Radiation Monitoring (ARM) systems (5610-066-.DB-001, Revision 5) stated that the following monitors are taken credit for in order to meet
CFR 70.24:
Monitor s
'RM
- 1421 (1422)
ARM - 1423 (1424)
Source Range N31, N32 Gamma Metrics A, B
Area Unit 3 (4)'pent fuel. pit Unit 3 (4) new fuel room.
Unit 3 and 4 containment Unit 3 and 4 containment
~Te gamma gamma neutron neutron
E2.4 E2.4
The detectors meet the sensitivity and alarm requirements of 10 CFR 70.24.
Alarm setpoints are between 5 and 20 mrem/hour.
The detectors are within 120 feet of the special nuclear material.
The inspector verified that all monitors were operable, and provided local and remote (control room) displays.
The licensee calibrated the ARMs per procedure O-PMI-066.2, Area Radiation Monitoring System Channel Calibration.
The neutron monitors were calibrated per several SMI procedures.
Routine functional 'tests (channel checks)
were also being-performed.
Emergency and off-normal procedures were available per procedures 0-EPIP-20101, Duties of the Emergency Coordinator, O-ONOP-066, High Area Radiation Monitoring System Alarm, 3/4-0NOP-033.3, Accidents Involving New or Spent Fuel, and Alarm Response Procedures (ARP).
In addition, procedure O-OP-066, Area Radiation Monitoring System, delineated normal system operating guidance.
Operators are tasked with alarm response, and HP personnel perform alarm validation with use of in-field portable radiation monitors.
Training programs and emergency drills included fuel accidents and inadvertent criticality scenarios.
The inspector also noted that QA had recently performed a review of 10
.CFR 70.24 requirements per Quality Report No. 97-0018.
QA concluded that Turkey Point.complied with all requi rements audited.
The QA review'as in response to recent noted industry problems.
The inspector 'also
. noted a recent issue with Unit 3.gamma metric neutron detectors (CR No.
97-23).
The 3A monitor did not track power changes.
The licensee initiated an'RT.
and found 'and repaired a faulty power supply c.
Conclusions The i.nspector concluded that the licensee's compliance.'ith
CFR 70.24 requi rements was appropriate.
Service Water Ins ection Followu 92903 (CLOSED) IFI 50-250',251/95-08-01:
(SWS) Service Water Inspection Findings Disposition The licensee conducted a Service'Water System Operational Performance Self Assessment (SWSOPA) during March and May of 1995 in response,to Generic Letter (GL) 89-13, SWS Problems Affecting Safety-Related Equipment.
A final report on the assessment.
issued July 14, 1995, concluded that the service water systems could meet the thermal and hydraulic performance requi rements assumed for accident heat removal.
However, there were five findings identified for further attention by the licensee.
The inspector reviewed the licensee's corrective actions to each of these, findings.
Based on the inspector's review, the corrective. actions adequately address most of the findings; however,
'dditional corrective actions were required for two of the finding ~'
The SWSOPA team identified 16 SWS valve mispositionings between 1993 and 1995.
Finding 3 related these valve mispositionings to a weakness in verification of valve position.
The licensee changed procedure 0-ADM-31. Independent Verification, to requi re a "hands-on" verification of the valve being manipulated.
Procedure O-ADM-200, Conduct of Operations, was also revised to provide explicit expectations for valve position verification and procedure ODI-C0-018,. Valve Manipulation Expectations, was issued to provide a programmatic method to monitor and train on valve position verification.
However, in 1996. the licensee again identified mispositioned valves as. an area for improvement.
The.
licensee recently instituted several additional programmatic actions to'ddress this problem.
The SWSOPA team also identified a weakness when Condition Reports (CRs)
were entered into the Plant Managers Action Item (PMAI) Tracking System.
The PMAI Tracking System allowed due dates for corrective actions to be extended without plant manager approval and the adequacy of corrective actions were not technically evaluated.. Also, the CR originator was not included in the approval process for close-out of cerrective actions..
The licensee changed procedures 0-ADM-054.
PMAI Corrective Action,
'racking Program, and O-ADM-518, Condition Reports, to address these weaknesses.
A Quality Assurance audit dated May 23, 1996 again identified that the corrective actions for CRs transferred to the PMAI Tracking System were not completed when the PMAI item was closed.
The licensee determined that an Information Bulletin and subsequent training were adequate corrective actions.
The inspector also r'eviewed the report for overall content.
The report addressed the functional areas of GL 89-13 and the questions raised by the SWSOPA team were generally answered completely.
The inspector did note one case where the engineering justification provided was not supported by an engineering evaluation.
Specifically. the SWSOPA team
~questioned if the manual isolation valve for Reactor Coolant Pump (RCP)
thermal barrier return could be closed against reactor system pressure.
The response to this question stated that the "valve assemblies"
.were designed to close against design RCS pressure.
Th'e inspector.
'noted the response did not fully answer the SWSOPA team's question.
and asked for the engineering calculation or 'evaluation that demonstrated the valve could be closed.
The licensee did not have any such calculation, but'ubsequently performed an analysis.
This analysis demonstrated that an operator would have to apply about 65 ft-lbs torque to close the valve manually.
The li.censee stat'ed that a valve wrench could also be-attached to the valve reducing the required torque.
The licensee also indicated that a throttle valve on the RCP thermal barrier return would limit the pressure in the return piping to less than RCS pressure further reducing the required closing torque for the manual valve.
The licensee produced additional documentation that demonstrated the SWSOPA team did receive an engineering evalu~tion for this question.
The inspector also noted that the SWSOPA did not identify a potential'ulnerability associated with mispositioned valves and the lack of ICW instrumentation in the control room.
The SWSOPA.report documented an
~'
incident in January 1995 that resulted in valve 3-50-310, ICW 'A'eader
.Isolation Valve, inadvertently closing during maintenance.
Since the
'A'nd 'B'CW headers were cross-tied, the ICW low header pressure alarm did not annunciate.
The failure of the header low pressure alarm to annunciate and the lack of ICW flow instrumentation in'the control room resulted in control room operators not recognizing the loss of ICW
'A'eader flow until notified by maintenance personnel about 15 minutes after the valve closed.
The licensee's corrective action was to conduct more frequent monitoring of local ICW fl.ow indications during maintenance activities.
However, this corrective action did not address the situation where a valve could be mispositioned.
The SWSOPA report also'documented that a mi'spositioned ICW valve could go undetected for up to eight 'hours.
The licensee stated that ICW valve alignment was changed only during maintenance activities and the valve alignment was
~
independently verified during restoration.
Additionally the system engineers were required to routinely perform a system flow path verification walkdown which provide'd another opportunity to detect mispositioned valves.
The inspector concluded that these compensatory, actions would probably detect a mispositioned valve within eight hours.
The licensee also stated that an. isolated ICW header for any significant time would result in changes to secondary parameters.
The inspector agreed that the mispositioned valve may be self identifying prior to the eight hours stated in 'the.SWSOPA report.
In summary, the SWSOPA addressed each of the areas in GL 89-13.
Ouestions were properly identified and adequately documented; however, the justification for accepting the resolution to a particular question lacked the same level of detail.
The inspector conc1uded that the licensee's corrective actions 'to the findings were effective except in two cases..
The additional corrective actions.were only recently implemented so the inspector could not assess the effectiveness. of these additional corrective actions.
E3
'ngineering Procedures and Documentation E3. 1 V dated Final Safet Anal sis Review UFSAR Revision 13 And Safet Evaluation Reviews C
a.
Ins ection Sco e
37551 Revision 13 to the UFSAR'was submitted on October 7, 1996.
Selected sections were reviewed to determine the appropriateness of the changes and the adequacy of the associated
.safety evaluations.
b.'bservations and Findin s Diesel Fuel Oil DFO Air-0 crated Valve UFSAR section, 9. 15, Emergency Diesel Generator (EDG) Auxiliaries, was changed to add a description of the existing air-operated valve from the fuel oil storage tank to the day tank.
This valve opens automatically
'n low day tank level to allow the fuel pump to provide oil from the
storage tank.
The UFSAR change included a statement that the valve could be locally opened if instrument air was not available.
Safety evaluation JPN-PTN-SEMS-95-052, Revision 0, dated 9/30/95, associated with this UFSAR change was reviewed.
The evaluation addressed the changes to the UFSAR, as well as the TS Bases, to clarify the acceptability of Unit 3 EDG fuel transfer system with Instrument Air unavailable.
The TS bases change went beyond the UFSAR change by indicating that manual action to operate this valve was acceptable,
.even for performance of TS 4.8.1. 1.2.b which states
"Demonstrate at least once per 92 days that a fuel transfer pump starts automatically and transfers fuel from the storage system to the day tank."
The inspector was concerned that this would allow the prolonged use of manual action with instrument air unavailable.
This essentially changed 'the facility to allow indefinite prolonged use of manual actions instead of the automatic operation of.the valve.
In performing the'nreviewed safety question determination associated with this evaluation, the licensee answered thq question
"does the proposed activity increase the probability of occurrence of a malfunction of equipment 'important to'afety previously eval'uated in the Safety Analysis Report" as follows:
"The use of manual actions to fulfillthe Unit 3 EDG fuel transfer function in case of the loss of
. instrument air is accounted for as a design provision.
There are no proposed physical modifications that would interact with equipment
'important to safety.
Therefore, the probability of occurrence of any equipment malfunction important to safety previously evaluated in the UFSAR will not be affected." 'here was no discussion of the probability of failure to manually take action to open the valve as compared to the fai lure. of the valve to automatically open.
The purpose of the evaluation was to document the use of manual actions for fuel transfer'.
yet the answer to this question was that manual actions was already accounted for as. a design provision.
The probability of fai lure to take manual action should have been compared to the probability of failure of the automatic action in order to perform the unreviewed safety question determination.
Therefore, this safety evaluatio~
was weak.
The associated surveillance procedure was reviewed, however, it did not address manually operating the valve in question.
The need for this evaluation arose in response to CR No.95-929.which identified the loss of automatic transfer capability from the U3 Diesel Oil Storage Tank to 3A and 3B EDG Day Tanks.
This capability was lost while performing*maintenance on an Instrument Air (IA) valve during a
24-hour test on the 3B EDG.
During the 24-hou'r test.
an annunciator for low fuel oil level in the day tank was received since the air to the makeup valve was, isolated.
IA was restored and the valve opened to supply oil to the day tank.
At the time. both EDGs were declared inoperable since the automatic feature of the 'design was made inoperative.
Engineering evaluation JPN-PTN-SEHS-95-050 was performed to address the operability of the Unit 3 EDGs with IA isolated.
This evaluation concluded that the EDG fuel oil transfer system was capable of performing its intended function with the use of manual actions.
It also concluded that the loss of instrument air is a recognized failure mode for the fill isolation valves and the need for manual action is'cknowledged in the Emergency Power Design Basis Document.
Therefore, it was concluded that the EDG remained operable with the loss of instrument air in accordance with the guidance in GL 91-18.
GL 91-18/NRC Inspection Manual Part 9900 Technical Guidance, Resolution of Degraded and Nonconforming Conditions, section 6.7 addressed the use of manual action in place of automatic action.
This section states that the licensee's determination must focus on the physical differences between automatic and manual action and the abi 1'ity of the manual action to accomplish the specified function.
It also states that this is expected to be a temporary condition until the automatic-action can be promptly corrected in accordance with 10 CFR 50, Appendix B, Criterion XVI, Corrective Action.
Evaluation JPN-PTN-SEMS-95-050, evaluated the condition and the ability of the manual action to substitute for the automatic action in this case.
Evaluation JPN-PTN-SEMS-95-052, concluded that the EDG'uel oil transfer system, is capable of performing its requ'ired support function with the use of proceduralized manual actions in case of a loss of instrument'air.
In additi'on,'he TS surveillance is met by testing the auto start of the transfer pump and transfer of fuel oil to the day tank with or without instrument air.
The licensee stated that. uSe.of manual actions for this fuel transfer function is within the original design basis of the plant.
The inspector concluded that the licensee had not demonstrated that manual. actions could be used to satisfy the surveillance requirements or
.
substitute for automatic action at any time.
The licensee intends to address the TS bases and surveillance procedure issues, and,to issue a
revision'to the safety evaluation.
Fire Protection Pro 'ram Re ort Chan es Several changes associated with UFSAR section 9. 6A,'ire Protection Program Report, were reviewed.'eficiencies were noted with some of the evaluations associated with increases in combustible loadings of certain fire zones.
Safety evaluation JPN-PTN-SEMP-96-004 addressing the use of AP Armaflex insulation in fire zones 34, 36, and 40 was reviewed.
The UFSAR lists
~ 'he combustible loadings for these areas and the addition of this insulation required a change to the UFSAR.
The largest increase in combustible loading was approximately twenty percent to fire zone 34 resulting in a revised heat load of 23,200 BTU/sq. ft. (British Thermal Units per square foot).
In the evaluation for the fire zone.
the licensee merely listed the previous and revised heat loa'ds and stated that "as can be seen from the data above.
the insignificant amounts of combustible loading added to the fire zones will not have an adverse
affect on plant safety."
In discussions with the licensee, they
'ndicated that revised fire loadings are compared with the fire rating of a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> barrier which they stated was approximately 80,000 BTU/sq.
ft.
The inspector concluded tha't thi's information should have been included in the safety evaluation.
In addition, the distribution of combustibles added, distribution of existing combustibles, and the effect on equipment in the area should have been included in the evaluation.
Minor Engineering Package (HEP)
PC/M 95-177, Pipe Insulation In Auxiliary Building For Containment Air Conditioning, was also reviewed.
This PC/M added combustible loads to fire zone 15 and also required an UFSAR update.'owever, the l.icensee could not provide a
CFR 50.59 safety evaluation for this UFSAR change during the inspection.
,The PC/P cover sheet did contain a
CFR 50.59 screening in which. the licensee improperly stated that the change did not represent a change to the facility as described in the UFSAR.'t appeared that a
CFR 50.59
'valuation was not performed for this change.
The inspector concluded that safety evaluation JPN-PTN-SEHP-96-004 was weak and a
CFR 50.59 safety evaluation may not have been performed for PC/M 95-177.
The licensee initiated CR No.97-196 to address this issue..
c'.
Conclusions Several other UFSAR and associated safety evaluations were review and found to be adequate.
The deficiencies noted above indicate that additional attention may be necessary in this area.
These items are considered an Unresolved Item (URI) 50-259,251/97-01-01.
Possible Deficient Safety Evaluations.
E6 Engineering Organization and Administration E6. 1 Mana ement Chan es On January 13, 1997, Hr.'.. J.
Tomaszewski was assigned as the Systems Engineering Manager reporting to the Site Engineering Manager.
This responsibility includes oversight of the electrical.
IEC, mechanical, and component system engineers, and procurement engineering.
The
.
previous manager was transferred to St. Lucie.
E8 E8.1 Miscellaneous Engineering Issues S ecial and Periodic Re ort Review 90712'0713 92700 The inspector reviewed the following licensee written reports:
LER 96-004.
Supplement 3'(see section El.l),
Monthly Operating Reports for December 1996 and January 1997, and
'
J
Uprate Startup Report (L97-001) dated January 9,
1997.
These reports were requi red by 10 CFR 50.73, TS 6.9. 1.5, and TS 6.9.1.1, respectively.
The inspector verified reporting requirements and timeliness, reviewed report correctness and accuracy, and discussed the reports with licensee personnel.
No deficiencies were identified.
The inspector concluded that the above reports were. thorough, well written, and met time reporting requirements.
IV. Plant Su ort R1 Radiological Protection and Chemistry (RP8C) Controls (71750)
Rl. 1 Health Ph sics HP Related Condition Re orts CRs During the inspection period, the inspector noted that six HP related CRs were anonymously submitted..
The CRs addressed HP performance issues and concerns as follows:
CR No.
96-1530 96-1603
~
97-0051 97-0062
.
97-0075 97-0085
~TQ 1C HPSS using an outdated form in procedure 0-HPS-96. 1. Decontamination of Tools, Equi.pment, and Areas.
Spill Kits in the RCA poorly maintained and ineffective in'ombatting radioactive spills.
Procedure O-HPT-16.9, Calibration and Operation of the Eberline Automated Conveyor Monitor (Model ACM-100A), being
'sed beyond its scope.
Contaminated floor space minimization program not being followed.
Weakness associated with procedure 0-ADM-607, Radioactive Waste Minimization Program, regarding the use of cool suits.
Poor.HP work practice with respect to respiratory equipment.
The licensee addressed each CR, including corrective actions.
In
'dditions management directed Nuclear Safety Speakout to independently
.
'ssess the HP organization including tolerance of degraded conditions, A
R1.2 R6 R6.1
procedure use and adequacy, supervisor (HPSS)
performance, and HP.
technician performance.
The inspector reviewed each CR and the 'associated corrective actions, and discussed this issue with Hanagement and selected workers.
The inspector attended a meeting of operations and HP super vision with all HP personnel.
At this meeting each of the CRs were discussed, including corrective actions.
The inspector noted the meeting was a good vehicle to discuss departmental.
issues.
The inspector concluded that the CR program was being effectively used to document and cor rect issues.
This issue will be reviewed by a specialist NRC=inspector in a future
'
inspection.
Auxi1iar Control Point The licensee has two control points into the radiological controlled area:
(1) the mai'n control point in the HP building; and, (2) an auxiliary control point into the turbine building.
The auxiliary control point is not normally manned by an HP; however, camera surveillance is installed.
The purpose of the auxiliary control point is to make auxiliary bui'lding access easier for operations, security, fire watches, and HP personnel.
~ During a routine tour on February 12, 1997, the inspector noted that there was no phone in the auxiliary control point.
A phone would be necessary if personnel'larmed the portal monitors and thus 'needed to call HP for assistance.
The inspector informed operations, HP, and management.
Recent CRs '(Nos.97-176 and 97-200)
had also documented this concern.
Apparently.a WO was previously generated in December 1996 to also address this issue.,
However, the WO either was canceled or not worked.
The licensee is pursuing the reason for'this.
Once the CRs were reviewed, management took timely action to obtain a phone for the auxiliary (turbine building) control point.
. The inspector verified this on February 20, 1997.
RPLC Organization and Administration ALARA Review Board ARB The inspector attended the January 28, 1997, ARB meeting.
Th'e inspector noted good attendance by all site disciplines, including, plant management; An agenda was effectively utilized.
Dose goals for 1997 and for the Unit 3 Cycle 16 outage were discussed.
These goals were 475 Rem and 165 Rem, respectively.
The achievement of Turkey Point's best
'ver 1996 exposure of 186 Rem was also discussed.
(This was well below the goal.)
Good practices were noted in that the licensee discussed other utility good ALARA practices, with the intention of incorporating these
'improvements into their.'own ALARA initiatives.
Further, the concept of
.
department exposure budgets continued. with frequent monitoring and evaluation by management and supervision.
Overall, the ARB appeared to
be functioning well. and was proactive in their efforts to minimize site dose.
FS Miscellaneous Fir e Protection Issues FS. 1 Thermola Heetin The inspector attended a thermolag status meeting at NRC/NRR on January 7,
1997.
The licensee presented their plans and schedules for addressing the fire protection barriers which use Thermo-lag material.
NRR will issue a meeting summary report..
V.
Hang ement Heetin s
X1 Exit Meetin Summar The inspectors presented the inspection results to members of licensee management at the conclusion of 'the inspection on February 25, 1997.
The licensee acknowledged the findings presented.
The inspectors asked the licehsee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identifie I'~
Partial List of Persons Contacted Licensee T.
V. Abbatiello, Site Quality Manager R. J. Acosta, Director, Nuclear Assurance J.
C. Balaguero, Plant Operations Support Supervisor P.
H. Banaszak, Electrical/l&C.En'gineering Supervisor
~ G.
M. Blinde, Operations Training Supervisor J.
L. Broadhead, FPL CEO T. J. Carter, P'roject Engineer B.
C.
Dunn, Mechanical Systems Supervisor
'.
J. Earl, QC Supervisor S.
M.. Franzone, Electrical Maintenance Super visor
.
R. J. Gianfrancesco..Maintenance Support Supervis'or 0.
Hanek, Licensing Engineer J.
R. Hartzog, Business Systems Manager P.
C. Higgins, Outage Manager G.'. Hollinger, Licensing Manager R. J.
Hockey, Site 'Vice-President M.
P.
Huba, Nuclear Materials Manager D.
E. Je'rnigan, Plant General Hanager T; 0; Jones, Acting Operations Supervisor M.
D. Jurmain, I&C Maintenance Supervisor V. A. Kaminskas,'ervices Manager J.
E. Kirkpatrick. Fire Protection, EP, Safety Supervisor J.
E. Knorr, Regulatory Compliance Analyst G.
D. Kuhn, 'Procurement'ngineering Supervisor R. J. Kundalkar, Vice President, Engineering and Licensing M. L. Lacal, Training.Manager J.
D. Lindsay., Health Physics Supervisor.
J.
T. Luke, Engineering Manager E. 'Lyons, Engineering Administrative Supervisor F:
E. Marcussen, Security, Supervisor R.
B. Marshall',
Human Resources Manager H.
N. Paduano, Manager, Licensing and Special Projects M. 0. Pearce, Maintenance Manager K.
W. Petersen, Site Superintendent T.
F. Plunkett, President, Nuclear Division K.'L. Remington, System Performance Supervisor R.
E'.
Rose, Outage Manager
'
C.
V. Rossi, QA and Assessments Supervisor A.
M. Singer, Operations Supervisor W. Skelley, Plant Engineering Manager R.
N. Steinke, Chemistry Supervisor E. A. Thompson, Project Engineer D. J.
Tomaszewski, Systems Engineering Manager B.
C. Waldrep, Mechanical Maintenance Supervisor G. A.
War riner, Quality Surveillance Supervisor R.
G. West. Operations Manager
J
Other licensee employees contacted included construction craftsmen, engineers, technicians, operators, mechanics, and electricians.
NRC Resident Inspectors T.
P. Johnson, Senior Resident Inspector J.
W. York, Acting Resident Inspector Partial List of Opened, Closed, and Discussed Items
'
0 ened 50-250,251/97-01-01 URI, Possible Deficient Safety Evaluations (section E3. 1)
Closed 50-250,251/95-08-01, IFI, Service Water Followup (section'E2.4)
.None Discussed LER 50-250/96-004 Supplement 3,
GL 96-01 Testings Reportability (section E1.1)
E List of'nspection Procedures Used IP 37551:
IP 40500:
IP 60705:
IP 61726:
Onsite'ngineering Effectiveness of Licensee Controls in Identifying, Resolving, and Preventing Problems Preparation for Refuelinq Surveillance Observations IP 62707:
Maintenance Observations IP 71001:
IP 71707:
Licensed Operator Requalification Program.
f Plant Oper ation
0
IP 71750:
IP 90712:
IP 90713:
IP 92700:
IP 92902:
IP 92903:
IP 93702 Plant Support Activities Inoffice Review of Written Reports Review oi Periodic Reports Onsite Followup of Written Reports of Nonroutine Events at Power. Reactor Facilities Followup - Engineering Followup - Service Water Inspection Onsite Response to Events List of Acronyms.and Abbreviations AC ADH AFW ALARA a.m.
amp ANPS ARB ARH ARP AS BTU/sq.ft CCW CD
'DF CEO CFR CR CRDH DB/DBD DFO DPR DRS ECC EDG e.g.
'RT ES/E Alternating'urrent Administrative (Procedure)
Auxiliary Feedwater As Low As Reasonably Achievable Ante Heridjem Ampere Assistant Nuclear Plant Supervisor Alara Review Board Area Radiation Honitor
.
Annunciator Response Procedure Auxi 1 iary Steam.
British Thermal Units per square foot Comp'onent Cooling Water Instrument Air Compressor (diesel)
Core Damage Frequency Chief Executive Officer'ode of Federal Regulations Condition Report Control Rod Drive Hechanism Design Basis (Document).
Diesel Fuel Oil
.Powei Reactor License Division of Reactor Safety Emergency Containment Cooler/Estimated Critical
'oncentration Emergency'iesel Generator For Example Engineering Emergency Notification System End of Life Emergency Operating Procedure
, Emergency Preparedness Event Response Team Types of EOPs
oF FCV FL FP FPL GL GOP HHSI HP
,HPA HPS HPSS HPT IA I&C ICW i.e.
IFI JPM JPN KV L
LER LOCA LPDR MEP MG MS MSIV No.
.NPS NR NRC
. NRR, ODI-CO ONOP OOS OP OSP OTSC PC/M pcm
'DR pH p.m.
PM(E)
Degrees Fahrenheit Flow Control Valve Florida Fire Protection Florida Power and Light Generic Letter General Operating Procedure High Head Safety Injection Health Physics Health Physics. - Administrative Health Physics
- Surveillance HP Shift Supervisor Health Physics
- Technical Instr ument Air Instrumentation and Control Intake Cooling Water
-
That Is Inspector Followup Item Job Performance Measurement Juno Project Nuclear (Nuclear Engineering)
'i 1 ovolt Letter (licensing)
Licensee Event Report Loss-of-Coolant Accident Local PDR milli Minor Engineering Package Motor Generator Main Steam Main Steam Isolation Valve.
Number Nuclear Plant Supervisor Corporate Risk Group Nuclear Re'gul.atory Commission Office of Nuclear Reactor Regulation Operations Department Instructions (Conduct of Operat'ions)
Off-Normal Operating Pro'cedure Out-of-Service Operating Procedure Operations. Surveillance Procedure On-the-Spot Change Plant Change/Modification Percent Millirho Public Document Room Hydrogen Ion Concentration Post Meridiem Preventive Maintenance (Electrical)
Plant Nuclear Safety Committee Parts Per Million Probabi 1 isti c Sa fety Assessment Pull-to-Lock Project Turkey Nuclear I
0'
'QA QC QPTR RCC RCCA RCS RCO RCP Rem.
RHR rpm RPS SE SEMP SEMS SENS SFP
.SG SGFP SMI SMM SNPO SRO STA STAR SWS TS TSA TSAS UFSAR
.URI
,V WO
Quality Assurance Quality Control Quadrant Power Tilt Ratio Rod Control Cluster Rod Control Cluster Assembly Reactor Coolant System Reactor Control Operator Reactor Coolant Pump Roentgen Equivalent. Man Residual Heat Removal Revolutions Per Minute Reactor Protective'ystem l
Safety Evaluation Safety Evaluation Mechanical
-
PEG Safety Evaluation Mechanical
- Site Safety Evaluation Nuclear-Site
'pent Fuel Pit Steam Generator SG Feedwater Pump Surveillance
-
I&C Maintenance Surveillance Maintenance
- Mechanical Senior Nuclear Plant Operator Senior Reactor Operator Shift Technical Advisor Stop-Think-Act-Review Service Water System Technical Specification Temporary System Alteration
. TS Action Statement Updated Final Safety Analysis Report Unresolved Item Valt Work Order