IR 05000335/1997003
| ML17229A319 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 04/28/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML17229A318 | List: |
| References | |
| 50-335-97-03, 50-335-97-3, 50-389-97-03, 50-389-97-3, NUDOCS 9705080270 | |
| Download: ML17229A319 (60) | |
Text
U.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos: 50'-335, 50-389 License Nos:
DPR-67, NPF-16 Report Nos: 50-335/97-03, 50-389/97-03 Licensee:
Florida Power 8 Light Co.
Facility:
St. Lucie Nuclear Plant, Units
& 2 Location:
6351 South Ocean Drive Jensen Beach, FL 34957 Dates:
February 16 - March 29.
1997 Inspectors:
H. Hiller. Senior Resident Inspector J.
Hunday, Resident Inspector D. Lanyi, Resident Inspector J.
Kreh, Regional Inspector (P2.1.2.2,3.1,3.2.5.1.5.2.7.1)
F. Wright, Regional Inspector (Rl. 1.3. 1)
Approved by:
C. Julian, Acting Chief, Reactor Projects Branch
Division of Reactor Projects 9705080270 970428 PDR ADQCK 05000335
EXECUTIVE SUMMARY St. Lucie Nuclear Plant.
Units
& 2 NRC Inspection Report 50-335/97-03, 50-389/97-03 This integrated inspection included aspects of licensee operations, engineer-ing, maintenance, and plant support.
The report covers a 6-week period of resident inspection; in addition, it includes the results of region-based inspections in the areas of Emergency Planning, Health Physics, and Chemistry.
~0erations The operating crew responded in a proper and timely manner to the reactor trip.
The inspector observed good coordination between operators and supervision during the evolution.
The licensee's root cause investigation was found to be methodical and comprehensive (Section 01.2).
The inspector found the reactor and turbine startup to be well performed.
Both operating crews worked well together as teams to perform a safe and methodical evolution.
The inspector also noted that good training was provided to the operator trainees by the licensed operators (Section 01.3).
Improper implementation of an Equipment Clearance Order on Unit 1 led to an inadvertent routing of approximately 135 gallons of Volume Control Tank inventory to the 1C charging pump cubicle floor drain and seal tank.
The inspector noted that this violation is similar to Violation, VIO 50-335/97-01-01,
"Failure to Follow the In-Plant Equipment Clearance Orders Procedure."
That violation documented an inattention to detail by the operators in performing Equipment Clearance Orders, however, the corrective actions for that violation have not yet been implemented.
This licensee identified violation is being treated as a Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy (Section 01.4).
The inspector concluded that the control room ventilation systems would perform their intended functions when called upon.
The licensee has taken steps to correct known deficiencies.
but minor equipment problems continued.
The licehsee maintained an adequate surveillance program to ensure that Technical Specifications were not violated.
However, the licensee's poor work practices caused a Control Room Outside Air Intake radiation monitor to be inoperable, except for indication, for over four years.
The inspector also determined that Engineering placed the appropriate emphasis on the system with respect to the Maintenance Rule (Section 02.1)
.
The inspector concluded that an unpl'armed release from a gas decay tank did not result in a violation of release limits.
The inspector concluded that the release could have been prevented had Operations revised the inadequate procedure when it was first identified.
A non-cited violation was identified regarding the licensee's failure to update the Updated Final Safety Analysis Report appropriately following modification to the system (Section 04.1).
~
The inspector concluded that the unusually rapid downpower, combined with a lack of'perator experience and a lack of appropriate communications, led to a fai lure to effectively control power at the conclusion of taking Unit 1 off-line.
The licensee's assessment of the event was adequate, but did not fully document and detail individual weaknesses.
Documentation of the event in the'control room logs was unsatisfactory (Section 04.2).
~
The inspector concluded that, due to a failure to maintain an adequate Reactor Control Operator population (from the standpoint of qualifying Reactor Control Operators),
the impact of recent Reactor Control Operator attrition and promotion placed the licensee in the position of having to rely on the routine heavy use of overtime to support plant operations.
This was identified as an unresolved item (Section 06. 1).
~
Inspector Followup Item, IFI 50-335,389/95-22-03,
"Steam Generator Level Channel Inaccuracies Due to Sensing Line Blockage," is closed (Section 08.1).
Licensee Event Report, LER 50-335/96-015.
"Operation Prohibited by Technical Specifications Due to Loss of Under voltage Protection on Safety Related Electrical Bus," is closed (Section 08.2).
The inspector concluded that, in an evolution involving securing the only operable shutdown cooling train to expedite cavity fill, the licensee did not violate Technical Specifications or procedural requirements (Section 08.3).
Maintenance
~
The inspector noted no discrepancies with the performance of maintenance on the 2B Intake Cooling Water Pump or the Unit 2 Purification Ion Exchanger Resin Outlet Valve (M2.1).
~
The inspector noted that the individual performing a Diesel Lube Oil Sample was familiar with the equipment he was using and completed the activity in accordance with the procedure with no discrepancies (Section M2.2).
~
Although the two Measuring and Test Equipment programs observed on site were structured slightly differently. both met all regulatory and industry requirements.
Both programs were generally well managed and were successful at accomplishing their missions (Section M7.1).
~
Violation, VIO 50-335/96-15-04
"Failure to Control Measuring and Test Equipment," is closed (Section M7.2).
~E
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The inspector concluded that the licensee's voluntary Updated Final Safety Analysis Report Review process had been effective in identifying
fault protection control power field conditions which did not'conform to the Updated Final Safety Analysis Report.
The licensee's corrective
= action plans were prompt and appropriate.
The licensee's overall effort was considered responsible and was an example of a questioning attitude on the part of the reviewers involved.
NRC concluded that, while the identified condition represented a de facto violation of the requi rements of 10 CFR 50.59, current NRC Enforcement Policy directs that this issue will be treated as a non-cited violation (Section E1.1).
~
The inspector found that additional significant review was required to appropriately address failures leading to, and following the identification of, errors introduced into the Digital Data Processing System which resulted in Unit 1 operating in excess of licensed thermal power limits during the current fuel cycle.
Consequently, three unresolved items were identified (Section E1.2).
Plant Su ort
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Licensee effluent sampling process met regulatory requirement.
Chemistry technicians demonstrated good understanding of effluent sampling procedures and good use of procedures during observed effluent sampling (Section R1.1).
Personnel responsible for shipments of radioactive material were knowledgeable of the changes in Department of Transportation and Nuclear Regulatory Commission regulations and had adequately implemented those changes in plant procedures (Section R3. 1).
The licensee developed and implemented significant improvements in both the automated and manual backup systems for notification of the Emergency Response Organization (Section P2. 1)..
Emergency response facilities were adequately equipped and were mai ntai ned at a suitable level of operational readiness.
The new Operational Support Center provided enhanced physical and communications capabilities (Section P2.2).
Changes made to the Radiological Emergency Plan since the October 1996 inspection did not decrease Plan effectiveness, and implementation of selected Radiological Emergency Plan commitments was now found to be fully satisfactory (Section P3.1).
Violation, VIO 50-335,389/96-18-03,
"Inadequacies in Certain Emergency Plan Implementing Procedures,"
is closed.
A program weakness identified in the Nuclear Regulatory Commission's Enforcement Letter dated January 10, '1997, was addressed through appropriate corrective action (Section P3.2).
The licensee had developed and partially implemented significant improvements in the training program for the Emergency Response Organization (Section P5. 1).
.
Unresolved Item, URI 30-335,389/96-18-05,
"Emergency Response Organization Personnel Not Qualified Through Drill/Exercise Participation," is closed (Section P5.2).
~
The licensee had made good progress in addressing the more significant outstanding Emergency Preparedness deficiencies, and had considerably reduced the backlog of open items in its Emergency Preparedness program (Section P7.1).
Re ort Details Summar of Plant Status Unit Unit 1 entered the report period at full power.
On March 3, the unit tripped on low Reactor Coolant System flow caused by the loss of the 1A2 Reactor Coolant Pump.
The unit was restarted on Harch 6 and attained full power the following day.
It remained at essentially full power for the remainder of the period.
Unit 2 Unit 2 operated at full power for most of the report period.
The unit was down powered from February 18 to February 19 to allow replacement of a feedwater regulating valve controller.
I. 0 erations
01.1 01.2 Conduct of Operations Gener a 1 Comments 71707 Using Inspection Procedure 71707, the inspectors conducted frequent reviews of ongoing plant operations.
In general, the conduct of opera-tions was professional and safety-conscious; specific events and noteworthy observations are detailed in the sections below.
Unit 1 Tri Recover 71707 Inspection Scope On March 4, Unit 1 tripped on low Reactor Coolant System (RCS) flow when the lA2 Reactor Coolant Pump (RCP) breaker unexpectedly opened.
The inspector observed the crew's performance during the trip recovery.
Observations and Findings At 12:22 p.m.,
on March 4, the 1A2 RCP tripped.
The subsequent low flow caused an automatic reactor trip.
Host plant parameters responded normally, and operator response was appropriate.
The B Hain Feed Regulating Valve (HFRV) failed open due to a controller failure and started to overfeed the B Steam Generator (SG).
The board operator took manual control securing main feed.
Later the Auxiliary Feedwater Actuation System (AFAS) properly initiated on low A SG water level.
Within approximately ten minutes.
the crew had exited Procedure 1-EOP-01, Revision 11,
"Standard Post Trip Actions" and entered Procedure 1-EOP-02, Revision 10,
"Reactor Trip Recovery."
Since the lA1 RCP was stopped, Procedure 1-EOP-02 directed the crew to depressurize the plant to 1850 psia to maintain RCP lower cavity temperature less than 300 F.
The briefing for the depressurization was thorough and efficient.
The crew commenced reducing pressure at 12:35 p.m.
and reached 1800 psia by
1:18 p.m.
The inspector observed that the evolution was well controlled and supervised.
By 1: 17 p.m.. the crew exited Procedure 1-EOP-2 and the plant was stable in Mode 3.
Following the trip, the licensee formed an Event Response Team (ERT) to determine root cause and corrective actions.
The inspector followed the licensee's investigation of the cause of the lA1 RCP. trip.
The licensee noted that no protecti ve relay flags had set, indicating that no obvious fault or under voltage condition existed.
The licensee then tested each relay and circuit associated with the RCP protective relaying scheme.
with no deficiencies identified.
Additionally. the licensee verified that no short circuits existed due to burned out light bulbs or problems in light sockets, ensured that no work was being conducted on associated circuits, and verified that no control ci rcuit shorts existed.
The ERT eventually narrowed the potential root causes to either a
problem in the subject breaker's internal trip mechanism, a problem in the adjustment of the breaker's floor tripper mechanism, or unauthorized operation of the breaker locally.
With regard to the breaker's internal trip mechanism being a potential cause, the team concluded that replacing the breaker with a similar breaker would insure that the failure mode would not recur.
The inspector was present at an ERT meeting in which the Plant General Manager (PGM) challenged the team to go further in pursuing this cause.
The PGM stressed that treating this failure as a "black box" failure mode would not allow for appropriate, generic, corrective actions.
As a
result of the PGM's involvement, the team determined that the breaker should be sent to a vendor facility for testing and inspection.
At the close of the inspection period, the breaker was with the vendor and no trip mechanism deficiencies had been identif'ied.
With regard to the floor tripper adjustment, the concern was that, with a misadjusted floor tripper, vibrations or breaker movement could lead to a.trip of the breaker.
The floor tripper was a feature of this and other breakers meant to insure that, if an attempt was made to rack out a closed breaker, the breaker would trip prior to being racked out to a point that personnel injury might result.
In investigating this cause.
the licensee found that the adjustment was slightly off.
The licensee then performed adjustments of this and other breakers'loor trippers to insure that, if this was the cause, a similar trip would not recur.
As regards unauthorized operation, the licensee augmented security precautions in a manner the inspector found appropriate.
Overall, the inspector found the licensee's root cause investigation to be methodical and comprehensive.
Especially noteworthy was the PGM's intervention into the process in a manner that challenged the ERT to expand thei r efforts without tainting the proces.3 Conclusions The operating crew responded in a proper and timely manner to the reactor trip.
The inspector observed good coordination between operators and supervision during the evolution.
The licensee's root cause investigation was found to be methodical and comprehensive.
Unit 1 Restart 71707 Inspection Scope The licensee restarted Unit 1 on March 6.
The inspector observed the licensees preparations for startup, reactor startup, and synchronization of the turbine to the grid.
Observations and Findings The inspector examined the Post Trip Review package prior to the Nuclear Plant Supervisor (NPS) authorizing restart of Unit 1.
The inspector noted that all data was complete.
Key post trip parameter status was appropriately documented and explained.
The inspector attended the Facility Review Group (FRG) review meeting.
Some of the members had minor questions or comments that were handled by the NPS or the Shift Technical Advisor (STA).
The inspector had no concerns about the Post Trip Review.
The inspector observed the pre-startup crew briefing led by the ANPS.
The briefing was thorough and included the operating crew, operator trainees, the STA, the Reactor Engineer (RE), the Reactivity Manager, and members of Operations Management.
The operating crew commenced the reactor star tup in accordance with Procedure NOP-1-0030122, Revision 4,
"Reactor Startup," at 9:12 p.m.,
on March 6.
The reactor was declared critical at 11: 19 p.m.
and power stabilized at approximately 5x10'ercent shortly thereafter.
The inspector observed watch relief at this point and noted that it was performed in a controlled manner.
The inspector had several observations on the approach to criticality.
The desk Reactor Control Operator (RCO) performed several Estimated Critical Positions (ECP) to cover the entire shift.
The inspector independently performed the same calculations and noted no significant discrepancies.
The RCO performing the startup had a trainee under his direct supervision f'r all reactivity manipulations.
The inspector noted that the RCOs were thorough in their explanations to the trainees on what to look at, what to expect.
and actions to take if something
.unexpected occurred.
The approach to criticality was methodical; the RE performed periodic 1/M plots as required by the startup procedure.
Periodically the inspector verified the calculations and convergence of'he plot.
Criticality was achieved within the allowances of the ECP and power was then raised deliberately to approximately 5x10'ercent powe The mid shift crew briefed rolling the turbine and synchronizing to the grid.
Once again the brief was thorough and included the appropriate personnel.
Reactor power was raised and then stabilized at two to four percent power.
The crew commenced rolling the turbine at 3:20 a.m.
per Procedure NOP-1-0030124, Revision 7, "Turbine Startup Zero to Full Load."
The generator was synchronized to the grid at 5:00 a.m.
and feedwater control was shifted to the MFRVs at 6:00 a.m.
Trainees performed the majority of the control room manipulations under the direct supervision of licensed operators.
The inspector noted that each evolution was well briefed and meticulously performed.
Conclusions The inspector found the reactor and turbine startup to be well performed.
Both operating crews worked well together as teams to perform a safe and methodical evolution.
The inspector also noted that good training was provided to the operator trainees by the licensed operators.
Inade uate E ui ment Clearance Order Execution 71707 Inspection Scope On March 25.
a Senior Nuclear Plant Operator (SNPO)
was performing an Equipment Clearance Order (ECO) boundary modification for work on the 1C charging pump.
After starting the boundary modification, the operator noted water spraying out of'he pump discharge seal tank lid and immediately shut the suction iso')ation valve.
Subsequent investigation determined that the cause of the event was inadequate execution of the original ECO.
Observations and Findings Equipment Clearance Order 1-97-03-106 was authorized on March 24, to allow maintenance on the 1C charging pump suction accumulator.
The following morni'ng, a boundary modification to the ECO was issued to allow filling and venting the pump.
When the charging pump suction valve was opened.
the SNPO observed water spraying from the pump discharge seal tank lid.
The SNPO shut the valve stopping the observed leakage and notified the control room.
A Reactor Coolant System.(RCS)
inventory balance verified RCS integrity shortly thereafter.
A subsequent investigation determined that the charging pump discharge drain isolation valve was open and had an ECO tag hanging on it.
This drain path led to a floor drain and to the seal tank, the source of the water
.
The initial ECO was originally written to include the drain valve tagged in the open position, but was later determined by the ECO verifier that this valve was not requi red for the clearance.
The verifier printed a
new ECO but failed to remove the prepared tag (Tag g6) from the clearance package.
The verifier later stated that this had occurred
near the end of his twelve hour shift, and that'e felt that fatigue may have been a significant factor in this error.
r The clearance was approved by the Assistant Nuclear Plant Supervisor (ANPS) and given to the SNPO for execution with the extra tag still in the clearance package.
Although the ECO did not have a step to hang the tag on the drain valve, the SNPO opened the valve, installed the tag and signed it.
The ECO was then given to another operator for independent verification.
As expected.
there was no independent verifier signature found on the drain valve tag.
There were at least three potential opportunities to identify and correct the error.
First, the ECO verifier should have printed out a
new set of tags with the revised ECO as required by Procedure OP-0010122.
Revision 87, "In-plant Equipment Clearance Orders," Step 8.10.16.
Second, although there was no direct procedural requirement to compare the tags to the ECO form, the ANPS could have caught the fact that Tag ¹6 was not identified on the form.
Third, the SNPO should have realized that Tag ¹6 was not identified on the ECO form while executing the order.
At the end of the report period. the licensee started enacting corrective actions to prevent recurrence.
This included procedural enhancements and operator training.
The inspector determined that these corrective actions should be sufficient to prevent recur rence.
. Technical Specification 6.8. 1.a required that written procedures be established, implemented, and maintained covering the activities recommended in Appendix A of Regulatory Guide 1.33.
Revision 2.
February, 1978.
Procedure QI 5-PR/PSL-1.
Revision 75, "Preparation, Revision, Review/Approval of Procedures,"
Section 5.14. 1, requi red strict adherence to procedural requirements.
Procedure OP-0010122, Revision 87, "In-plant Equipment Clearance Orders," stated that qualified operators will "execute Clearance Orders as written and in the sequence detailed."
The failure of the ECO verifier to print out a new set of tags as requi red and the failure of the SNPO to properly execute the ECO are two examples of a failure to follow procedures.
This licensee identified and corrected violation is being treated as Non-Cited Violation, NCV 50-335/97-03-01,
"Failure,to Adequately Implement an Equipment Clearance Order."
c.
Conclusions Improper implementation of an Equipment Clearance Order on Unit 1 led to an inadvertent routing of approximately 135 gallons of Volume Control Tank (VCT) inventory to the 1C charging pump cubicle floor drain and seal tank.
The inspector noted that this violation is similar to Violatioo, VIO 50-335/97-01-01,
"Failure to Follow the In-Plant Equipment Clearance Orders Procedure."
That violation documented an inattention to detail by the operators in performing ECOs, however, the corrective actions for that violation have not yet been implemented.
This licensee identified violation is being treated as a Non-Cited
02.1 a.
Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy.
Operational Status of Facilities and Equipment Walkdown of Control Room Ventilation 71707 62707 Inspection Scope The inspector performed a detailed walkdown of both units'ontrol room ventilation systems.
Observations and Findings The inspector walked down all accessible mechanical portions of both ventilation systems.
In general, both systems'lant drawings matched the as-built configuration.
Several minor labeling deficiencies were noted by the inspector on both units and were forwarded to the system engineer for correction.
The inspector also verified that the systems were lined up per Procedures 1-1900020, Revision 20, and 2-1900020, Revision 8,
"Reactor Auxiliary and Control Room Ventilation System Operation" for Unit 1 and Unit 2 respectively.
The inspector also validated that the Off-Normal Operating Procedures (ONOPs),
ONOP 1-1900030, Revision 21, and ONOP 2-1900030, Revision 18,
"Reactor Auxiliary Building, Diesel Generator Building, and Control Room Ventilation" would work as written and would perform the desired purposes.
The inspector had no concerns with these procedures.
With the assistance'f Operations personnel, the inspector inspected the interiors of breaker and other electrical cabinets for debris, loose material, jumpers, or other potential problems.
On Unit 1, the inspector noticed that flow switch FS-25-16B was wired to fan HVE-13A.
The purpose of this'flow switch is to insert a permissive signal to allow manual securing of the HVE-13B fan during control room recirculation operations and to restart an idle fan if flow through the operating fan is lost.
The way this switch was wired would not allow securing either fan during recirculation mode.
Flow switch FS-25-16A was similarly wired to fan HVE-13B.
The inspector then noticed that a
Plant Work Order (PWO) had been written on this problem about one week earlier.
Discussion with the system engineer revealed that this discrepancy became known during the Updated Final Safety Analysis Report (UFSAR) review.
The reviewer s noted that the Unit 1 UFSAR, Section 7.3.1.3.5, stated that one of the booster fans (HVE-13A or 13B) could be manually stopped during a Containment Isolation Signal (CIS), which causes the ventilation system to go into recirculation.
However discussion with the operators indicated that this was not true.
A walkdown by Engineering identified the reversed wires.
At the close of the report period, the licensee had developed plans to correct the deficiency prior to the Unit 2 outage.
Further discussions with the system engineer indicated that no other significant UFSAR discrepancies were identified by the license i
The inspector verified local breaker positions and control room breaker position indications.
No disparities were noted.
The inspector verified that Component Cooling Water (CCW) was proper ly aligned to the Unit 2 air conditioning units.
The only discrepancy noted there was that the inlet filter drain valves were not labelled.
The CCW system was lined up to support operation of the ventilation system.
The inspector verified that all instrumentation was properly installed and properly functioning.
The inspector identified two areas of concern.
First, on the Unit 2 HVE-13A and 13B filter assemblies, there were several temperature elements (TE-25-48,51,and 55) with calibration stickers dated January, 1983.
The system engineer has been notified so that appropriate corrective actions may be taken.
Second, the licensee performed a primary calibration on the Unit 1 B
side Control Room Outside Air Intake (CROAI) radiation monitor in response to a violation identified in Inspection Report 96-17 (VIO 50-335/96-17-08 "Failure to Develop and Haintain Adequate Calibration Procedures for CROAIHs").
During this calibration, performed in accordance with Procedure 18C 1-1220053, Revision 3, "Calibration of the Control Room Outside Air Intake Monitors," the licensee discovered that the B portion of the control room ventilation would not go on recirculation due to a high radiation signal.
The engineer was contacted and determined that a jumper was missing that was to supply power to the initiating contacts.
The system was restored to match the design configuration.
and the system retested satisfactorily.
Condition Report 97-0108 was generated to determine the cause of the missing jumper and determine any operability concerns or reportabi lity requirements.
Unit 1 Technical Specification (TS), Section 3.3.3.1, discusses radiation monitoring, but does not provide any requirements for the CROAI radiation monitors.
The operability assessment determined that the radiation monitor was not capable of alarming, actuating the closure of the CROAI valves, or starting HVE-13B upon detection of a high radiation condition from July 24, 1992 when the ratemeter was replaced until January 17, 1997, when the jumper was properly installed.
The monitors themselves did indicate proper radiation levels at the control room meters, however.
The licensee also determined that the
.
radiation monitor functions that were not operable were backup to the control room ventilation isolation signal from a CIS.
The UFSAR does not credit automatic control room isolation from the CROAI monitors, however the monitors are used to determine which outside source will be aligned for fresh air makeup.
The inspector determined that the licensee's actions were appropriate.
The inspector verified that the licensee was properly performing the TS surveillance requirements.
Unit 1 TS 4.7.7.1 and Unit 2 TS 4.7.7 document the required surveillance for the control room ventilation systems.
The inspector determined that all requirements were being met by various procedures.
The inspector determined that more detailed investigation into the charcoal filter and HEPA surveillance was warranted since this surveillance was performed by a contractor organizatio Chemistry Procedure C-74, Revision 17. "Particulate and Iodine Filter Testing,"
has been the licensee's procedure that provided the frequency and acceptance criteria for Engineered Safety System (ESF) ventilation testing.
The procedure accurately translated the TS requirements into procedure requi rements.
The procedure also clearly stated that Unit
filters must be tested in accordance with ANSI N-510-1975,
"Testing of Nuclear Air Cleaning Systems."
and Unit 2 in accordance with ANSI N-510-1980,
"Testing of Nuclear Air Cleaning Systems."
Procedure C-74 also referenced Procedure QI 7-PR/PSL-1,
"Control of Purchased Material, Equipment, and Services."
Procedure QI 7 PR/PSL-1 described in detai l the requi rements that must be followed while using a vendor.
This included formal evaluations of the organization and individuals performing the work, a formal evaluation of work procedures to ensure that all required standards were met, and a formal evaluation of work practices.
The FRG review of the ventilation test procedure used by the vendor was completed on February 20, 1990.
The licensee inserted the documentation required by Procedure QI 7-PR/PSL-1 into the report issued by the vendor.
The inspector reviewed the applicable vendor procedures and compared them to the applicable ANSI standards.
The inspector also verified that the data from the last test performed on each unit was satisfactory.
The inspector had no further concerns.
The inspector noted that there had been several failures of dampers on both units over the last year.
Both systems ar'e considered (a)(2) under the Maintenance Rule since the systems have not had two maintenance preventable functional failures in the last 18 months.
However, on February 18, 1997, the inlet damper to HVE-13A failed to open, effectively disabling the A ventilation system.
A Condition Report (CR 97-0269)
was initiated to determine the cause.
The system engineer determined that he had improperly diagnosed the cause of a previous failure of this damper in October, 1996.
The system engineer believed that the original cause of the failure was a misalignment of the linkage arms.
At the end of the report period. the licensee was developing an action plan to accurately determine the root cause of the failures.
Based on these two failures, the system engineer has determined that he will present the Unit 2 control room ventilation system to the Expert Panel for consideration as an (a)(1) system.
The design of the Unit 1 dampers was different than the Unit 2 design.
The licensee put in place a new program in December, 1996 to ensure that the linkage arms were set properly.
Electrical Maintenance Procedure 1-EMP-25.05.
Revision 1,
"Damper Linkage Validation Siebe Model MA-418 Actuators" implemented this program.
At the close of the report period, approximately one third of the Unit 1 dampers had been reset using the new procedure.
The inspector determined'that these were adequate actions to ensure proper operation of the systems.
Conclusions The inspector concluded that the control room ventilation systems would perform their intended functions when called upon.
The licensee has taken steps to correct known deficiencies, but minor equipment problems
04.1 continued.
The licensee maintained an adequate surveillance program to ensure that TSs were not violated.
However, the licensee's poor work practices caused a
CROAI radiation monitor to be inoperable, except for indication, for over four years.
The inspector also determined that Engineering placed the appropriate emphasis on the system with respect to the Maintenance Rule.
Operator Knowledge and Performance Un lanned Release of Fission Gases from the 1B Gas Deca Tank 71707 Inspection Scope The inspector reviewed the operator logs, proce'dures, condition report, and root cause evaluation concerning an unplanned release of the 1B gas decay tank which occurred on January 29, 1997.
Observations and Findings On January 28, the Waste Gas system was aligned to the 1B gas decay tank to facilitate purging of fission gases from the Volume Control Tank (VCT).
Upon completion of that activity, the 1B gas decay tank was isolated and the Waste Gas system was realigned to the plant vent so that maintenance could be performed on the 1B waste gas compressor.
On January 29, the SNPO reported that the 1B gas decay tank pressure had dropped approximately 10 psi.
The SNPO determined that the 1B gas decay tank was aligned such that it was actually being vented to the plant stack.
The procedure controlling this acti vity was OP 1-0530020.
Revision 27.
"Waste Gas System Operation."
It contained steps to isolate the normal flow path to the gas decay tank but did not isolate the sample flow path to the waste gas analyzer.
After the gas travelled through the analyzer it was exhausted to the gas surge tank which in turn was released through the plant stack.
Upon identifying the release path. the SNPO isolated the sample flow path which secured the release.
A root cause evaluation was performed which concluded that the procedure used when performing this evolution lacked sufficient detail.
It further identified that the procedural inadequacies were identified when the same evolution was performed successfully the previous week.
In addition, the evaluation determined that the SNPO's knowledge of the waste gas analyzer was deficient.
Corrective actions completed or planned included; 1) revise the waste gas system operating procedures to provide sufficient detai 1, 2) review the event during requalification training emphasizing the importance of not living with known procedural deficiencies, 3) review the training material related to the waste gas system and ensure that it is taught periodically.
and 4) issue a night order to alert Operations personnel of the event.
During this inspection, the inspector noted that the procedure revisions had been delayed because the safety evaluation performed for the revision identified that the system was not being operated as desc'ribed in the UFSAR.
PC/M 150-190 modified the system and the way it was
oper ated in 1990 but failed to update the UFSAR accordingly.
The inspector reviewed the modification package for PCM 150-190 and noted that a safety evaluation had been completed in accordance with 10 Code of Federal Regulations (CFR) 50.59, however, it concluded that a change to the plant as described in the UFSAR would not take place.
In 1992, the licensee discovered this error and generated the necessary paperwork to facilitate a revision to the UFSAR, however. the revision was never made.
At the end of this inspection period, the licensee was in the process of revising the UFSAR to agree with the system configuration in the plant.
Upon completion of that revision, the appropriate procedure revisions will be made.
CFR 50.71(e)
requires, in part, that the UFSAR be revised to include the effects of all changes made in the facility as described in the UFSAR.
This licensee-identified violation was not willful and was not one that could reasonably have been prevented by the corrective action for a previous violation or licensee finding that occur red within the last two years.
The licensee intends to include the appropriate revisions with the next update of the UFSAR.
This licensee-identified and corrected violation is being treated as a
Non-Cited Violation, consistent with Section VII.B.1 of the NRC Enforceme'nt Policy.
This NCV will be tracked as NCV 50-335/97-03-02.
"Failure to Update the UFSAR Following Modification of the Waste Gas System."
Following the release, the licensee sampled the gas decay tank to verify that release limits had not been exceeded.
The inspector reviewed the results and verified they were acceptable.
The inspector also noted that although the release was unplanned it was not unmonitored.
The waste gas system would have automatically isolated if the activity level had reached the alarm limit.
In addition, the plant vent monitor would also have alarmed if the activity level exceeded the alarm setpoint.
Conclusions Although the release was unplanned, the inspector concluded that it did not result in a violation of release limits.
Regardless, the inspector concluded that the release could have been prevented had Operations revised the inadequate procedure when it was first identified.
A non-cited violation was identified regarding the licensee's failure,to update the UFSAR appropriately following modification to the system.
Control of Low Power 0 erations 71707 Scope Inspection Report 96-20 described a Unit 1 downpower and removal from service due to a leak in the Digital Electrohydraulic Control (DEH)
System.
The inspectors observing the event found the downpowering of the unit to be well-controlled.
Following the removal of the unit from service, operators had difficulty counteracting the effects of xenon buildup and the reactor's power dropped from the target band of 2 to 5 percent to 10'ercent before power was restored to the band.
During
the current period. the inspectors reviewed the event and the licensee's fact-finding efforts relative to the event.
b.
Observations and Findings Through reviews of logs, sequence of events recorder output, and interviews with operators involved in the event, the inspector assembled the following timeline:
0150 Nuclear Plant Operator (NPO) Reports DEH Leak (log)
0155 Pzr Placed on Reci rc (log)
0201 lA Charging Pump started for downpower (log)
0448 Commenced downpower (log)
0536 Increased rate due to worsening leakage (log)
0605 Secured 18 Feedwater Pump (log)
0617 Nuclear Plant Supervisors turnover (log)
06Z8 Swapped to Startup Transformers (log)
0641 Tran'sferred feedwater regulating valves (FRVs) to 15 percent (log)
~
Spare NWE assumes feed control watch, controlling SG levels (NWE)
0700 Oncoming operator relieves NWE at the feed controls (RCO 1)
0717 Tripped Turbine (log)
~
Turnover occur red after turbine trip (RCO 1)
~
STA moves to desk to input logs (STA)
0725 Unit in Mode 2 (log)
Time unclear, but after Mode 2:
~
Rods at LTSS insertion limits and plant stable (RCO Z)
~
Power begins falling off, additions of water directed to VCT and suction of CHPPs (RCO 2)
~
NPS directs that power be increased (RCO 2)
~
NPS again directs that power be increased (RCO 2)
~
NPS directs thi rd CHPP start due to low observed power (approx 0 percent)
(RCO 1)
0809 1C Charging Pump started to maintain power at 1 percent (log)
Time unclear
~
RCO 2 had been adding water in batches (100 to 150 gallons)
both to the VCT and the suction of'he charging pumps trying to overcome xenon effects.
Ke eventually used rods (about
steps),
but was hesitant to do so based upon his training (rods were for ASI. boron for temperature).
When he established a positive startup r ate (SUR) of approximately
.5 DPM. he was uncomfortable with the rate and stepped them in to slow it (RCO 2).
~
STA looked at power and saw nuclear instrument (NI) power (as indicated on the RPS) at 0-1 percent.
Ke then looked at a control power recorder and saw power at 1E-3 - lE-4.
~
STA asked RCO 3 what power was (STA)
~
NPS overheard this and became angry.
He had directed that power be maintained at 2-3 percent several times (STA)
~
NPS saw RCO 2 driving in rods
- done to decrease SUR from.5 DPM to approximately
.25 DPM
~
NPS relieved RCO 2, swapping him with the RCO controlling the secondary side of the plant (RCO 2)
In discussing the event with personnel involved. additional information obtained indicated that there were a "pool of people" in the control room (due to shift turnover) which impeded crew teamwork and communication.
The inspector reviewed the licensee's assessment of the event and noted that the licensee determined that crew communications broke up after taking the unit off-line; the turnover process began and formal communications suffered.
Further, the assessment found that the lack of a rapid downpower procedure and inexperience on the part of the RCO controlling power with rapid downpowers led to difficulties in predicting and managing the effects of xenon once the unit was stabilized.
Other causal factors identified included the lack of cohesive crews due to a current shortage in licensed operators and stress induced by a perception on the part of operators that too much time elapsed between the onset of the leak and the decision to shut down (and additional stress imposed when the leak worsened and the downpower rate was incr eased).
The inspector found that, while the licensee's assessment (prepared by the operators involved) was comprehensive in its scope, it fai'led to provide meaningful details for some of the causal factors cited.
Additionally. the inspector found that the assessment failed to include the following items, both ancillary and directly related to the issue, that represented worthwhile followup items:
The RCO at the controls stated to the inspector that his decision not to employ Control Element Assembly (CEA) motion to maintain ower while he waited for the effects of dilutions was based on is training, which espoused the use of CEAs for ASI control only.
The RCO at the controls stated to the inspector that the "pool of people" in the control room for turnover contributed to his not communicating the fact that he was having difficulty controlling power.
The inspector noted that a third operator augmented the normal two operators at the controls and controlled feedwater during the downpower.
As best the inspector could ascertain in building the timeline above, the NPS identified that the RCO at the controls was haying difficulties controlling power at least twice prior to relieving him of reactivity control responsibilities; however. it appeared that the ANPS was never directed to the problem as might be expected; given the chain of command.
No reference to the event or the relieving of the operator at the reactivity controls could be found in the control room log In addition to the crew assessment.
the inspector reviewed calculations performed by the licensee's Reactor Engineering organization which assessed the worst-case reactivity condition for the core during the transient.
The inspector agreed with the licensee's conclusion that the unit did not enter Node 3 during the event (i.e. the event,did not represent an unapproved mode change),
however, the inspector noted (and the crew assessment stated) that the RCO at the controls could not have known this at the time.
The licensee's corrective actions for this event included the initiation of training on rapid downpower maneuvers, the development of a procedure for the activity. and training on the specific event.
c.
Conclusions The inspector concluded that the unusually rapid downpower, combined with a lack of operator experience and a lack of appropriate communications, led to a failure to effectively control power at the conclusion of'aking Unit 1 off-line.
The licensee's assessment of the event was adequate, but did not fully document and detail individual weaknesses.
Documentation of the event in the control room logs was unsatisfactory.
Operations Organization and Administration 06. 1 Reactor Controls 0 er ator Overtime 71707 a. 'cope Inspection Report 97-01 documented a review of operator overtime and noted that the licensee was controlling overtime within TS guidelines for maximum hours worked without prior management approval.
The inspector noted at the time that, while the licensee was complying with maximum hour limitations, overall overtime usage was high among Reactor Control Operators (RCOs).
The inspector reviewed the issue of RCO overtime usage for compliance to the St. Lucie TSs.
TS 6.2.2.f states, in part:
.
"Administrative procedures shall be developed and implemented to limit the working hours of unit staff who perform safety-related
.functions: e.g.,
senior reactor operators, reactor operators...
Adequate shift coverage shall be maintained without routine heavy use of overtime.
The objective shall be to have operating personnel work a normal 8-hour day, 40 hour4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> week while the plant is operating.
However, in the event that unforeseen problems require substantial amounts of overtime to be used, or during extended periods of shutdown for refueling, major maintenance or major plant modification, on a temporary basis the following guidelines shall be followed:
e ~
l.
An individual should not be permitted to work more than
hours straight, excluding shift turnover time.
An individual should not be permitted to work more than
hour s in any 24-hour period, nor more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period.
nor more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7-day period, all excluding shift turnover time.
3.
A break of at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> should be allowed between work periods, including shift turnover time.
Except during extended shutdown periods, the use of overtime should be considered on an individual basis and not for the entire staff on a shift."
The inspector reviewed NRC Generic Letter 82-12, which stated that administrative procedures shall set forth a policy to "...prevent situations where fatigue could reduce the ability of operating personnel to keep the reactor in a safe condition.
The controls established should assure that, to the extent practicable, personnel are not assigned to shift duties in a fatigued condition that could significantly reduce thei r mental alertness or their decision making ability."
The GL went on to state that "...enough plant operating
'ersonnel should be employed to maintain adequate shift coverage without routine heavy use of overtime."
FPL letter L-82-417, which responded to the subject Generic Letter, documented that the licensee had reviewed their controls of overtime and had concluded that they "...meet the spirit and intent of..." the NRC's policy statement.
Based on the above, the inspector reviewed the current status of the use of overtime on the part of RCOs.
b.
Observations and Findings Recent attrition and promotions have resulted in the population of RCOs (Licensed Reactor Operators and Senior Reactor Operators responsible for manipulations of plant controls) dropping to 24 for the site.
Of the 24, two were assigned to the Clearance Center to aid in clearance writing.
TSs required two RCOs per shift per unit, such that, for five section rotation, the licensee would require
RCOs to satisfy staffing requirements.
The limited 'number of RCOs was such that. while maintaining an eight hour shift in five section rotation. the licensee had inadequate operator staffing to cover cases of sickness and vacation; consequently, the licensee resorted to overtime usage to cover these eventualities.
The licensee recently shifted from an eight hour work schedule to a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> schedule for RCOs with the operators divided into two shifts, day and night.
The RCOs were assigned to a schedule comprised of five,
hour, shifts (excluding turnover time) with two days off between five day on-shift periods.
The benefits to this approach included:
e ~
e
Predictability in schedules The lack of the need to rotate between shifts, a practice which results in the loss of time off as the operator moves from day to night shift (e.g.
an operator leaves day shift at 7 p.m. f'r two days off, but must return at 7 p.m.
on the second day off to assume a night shift schedule).
The disadvantage to this schedule was that operators would have to work 60 hour6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> work weeks as a r'egular work schedule.
In a meeting with the NRC on March 27. the licensee acknowledged the high use of overtime necessitated by the shortage of RCOs and stated that:
~
The move to 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts was requested by operators
~
The additional operators on each shift (made available by collapsing five shifts into two') allowed the licensee to accommodate:
~
RCO vacations (250 hrs)
~
New fuel operations (500 hrs)
~
Outage preparations (700 hrs)
~
Requalification training The inspector noted that no regulatory requirement would compel the licensee to utilize RCOs for outage preparations.
Further, the inspector found that, as of April 1, 1997. the actual vacation balances
for RCOs totaled approximately 3480 hours0.0403 days <br />0.967 hours <br />0.00575 weeks <br />0.00132 months <br />.
RCO scheduled vacation for the balance of the calendar year totaled approximately 3760 hours0.0435 days <br />1.044 hours <br />0.00622 weeks <br />0.00143 months <br />.
The inspector reviewed the use of overtime by RCOs 'and found that, as of March 14, RCOs had worked 2663.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> of overtime for 1997.
The inspector reviewed overtime usage on a pay period basis for each operator from December, 1996, to March 14, 1997.
The inspector found that usage was, in general, concentrated.
Examples are included in the table below.
RCO Overtime by Pay Period End Date 0 erator 12/20/96 1/3/97
"1/17/97 1/31/97 2/14/97 2/28/97 3/28/97 36.5 28.5
43 26.5
31
42.5 45.5
18 16.5 52.5
41.5
47.5 5.5 36.5 56.5 26.5 11.5
54.5 ll.25 14.5
29 23.5
42
, The inspector reviewed shift staffing for the period of March 15 through April 11, and found that concentrations of overtime on a day-to-day basis were more apparen Daily Totals For Three Reactor Control 0 erators Date 3/15 3/16 3/17 3/18 3/19 3/20 3/21 3/22 3/23 3/24 3/25 3/26 3/27 3/28 3/29 3/30 3/31 4/1 4/2 4/3 Dail Total
12
12
12
12
12
0
12
Operator A
Rolling
Hours
12
24
24
12
24
24
12
24 Rolling 7 Oay
60
48
60
60
60
60
60 Dail Total'2
12
12
12
12
12
12 Operator 8 Rolling
Hours
24
24
24
12
24
24
12 Rolling 7 Oay
48
72
60
60
60
60
60 Dail Total
12
12
12
12
12
12
12
Operator C
Rolling
Hours
24
24
12
24
24
24
12
24 Rolling 7 Day
60
72
72
72
60
60
60 4/4
24
12
60
24
4/5 4/6 4/7 4/8 4/9'/10 4/11
12
12
24
~ 12
24
24
60
60
60
12
12
24
24
12
60
60
72
60
0
60
48
24
Asteris e
va ues in icate t at insu icient ata is avai a
e or calculation of the value.
Values in bold indicate dates on which TS guidelines for overtime are reache Considering the new 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift arrangement.
the calculation of operator overtime was. more straightforward.
Simply put, each RCO was to work 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> of overtime per 7 day period.
The only exceptions were to be when an operator was on vacation or during the upcoming Unit 2 outage in April, 1997, when the schedule was to shift to a 6 day, 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shift.
The inspector inquired as to the potential for adding additional RCOs to the shift rotation.
The licensee reported that two licensed operator classes were in progress; one with three "instant" Senior Reactor Operators (SROs) scheduled for completion in June, and one with 16 potential RCOs scheduled for completion in October.
08.1 Conclusions
. NRC continues to be concerned about the heavy use of overtime for the RCOs.
This matter will be treated as an Unresolved Item for further inspection.
UNR 50-335,389/97-03-03,
"Excessive Overtime Usage Among Reactor Control Operators."
Miscellaneous Operations Issues Closed IFI 50-335 389/95-22-03
"SG Level Channel Inaccuracies Due to Sensin Line Blocka e" 71707 The subject IFI discussed a
1996 Unit 2 trip in which erroneous steam generator low level indications and signals were received due to clogging in SG level transmitter sensing lines.
The inspector noted two areas of concern in opening the IFI, the disposition of a St. Lucie Action Report (STAR) on the issue, and weaknesses associated with the post trip review performed at the time.
With regard to the disposition of the issue, the inspector reviewed the completed disposition of STAR 9600439.
The inspector concluded that the licensee had appropriately addressed the issue.
With regard to post-trip review adequacy, the original issue involved a
failure of operators to understand the individual Reactor Protection System (RPS) channel trips which had been received during the event.
Specifically, when the inspector asked why SG'ow level trip bistables were illuminated, operators hadn', to that point, noticed.
The subsequent post-trip review failed to identify the trips as anomalous.
The inspector found that the post-trip review procedure was weak in that it did not specifically require an assessment of all of the RPS channels which tripped.
The inspector reviewed Unit 2 trips which had occurred previous to the January, 1996, trip and found that similar weaknesses in the review process existed.
A review of Sequence of'vents Recorder (SOER) output from those previous trips indicated that sluggish response on the part of SG level transmitters was identifiable as far back as a Unit 2 trip
which occurred on January 15, 1990.
The trip, which resulted from low steam generator level due to low feedwater flow, showed, via SOER output, sluggish RPS response in which approximately 10 seconds passed between the actuation of the HA low SG level trip and the HB low level trip.
The procedure was revised following the January, 1996, findings to require personnel to identify the trips which occurred (both the trip channels 'that caused the unit to trip and the channels that actuated subsequent to the plant trip) and to describe why the trips occurred.
IR 96-14 documented a failure to properly employ this revised methodology during the post trip review associated with an August, 1996, manual trip of Unit 1, in that ancillary RPS trips caused by the actual reactor trip (e.g.
loss of load trip. thermal margin local power (THLP)
trip) were not explained as being appropriate.
The inspector reviewed the post-trip review package associated with the Unit 1 trip which occurred during the current inspection period.
The inspector concluded that the licensee had correctly employed the post-trip review process, documenting each RPS channel bistable actuation and reviewing it against expected system response.
The inspector concluded that, while the licensee had in the past performed weak post-trip reviews, the licensee has made improvements to the post-trip review process since the January, 1996, Unit 2 event.
The post-trip review procedure has evolved to include the appropriate reviews for the acceptability of'rotective system responses.
This item is closed.
Closed LER 50-335/96-015
"0 eration Prohibited b
Technical S ecifications Oue to Loss of Undervolta e Protection on Safet Related Electri ca 1 Bus" 71707 On October 29, 1996, a Unit 1 ANPS was reviewing a
PWO which would have deenergized 1B3 4.16kV bus undervoltage relays for a short period of time (approximately 10 seconds)
to clear a "locked up" solid state electrical problem in alarm relays.
In considering the issue, the ANPS realized that removing a fuse designated for the task had the same effect as opening a 125 V DC feeder breaker to the relays as was normally done in Procedure ONOP 1-0960030,
"DC Ground Isolation."
The ANPS then questioned the overall acceptability of the practice vis-a-vis TS 3.3.2. 1, Table 3.3-3, which required that two loss of voltage and two degraded voltage relays be operable on each safety-related 4.16 kV bus (busses 1A3 and 183).
No TS AS existed for the case of the loss of all protective relays, which would have placed the unit in TS 3.0.3 (requiring that a shutdown be commenced within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />).
The ANPS subsequently prohibited the activity.
The licensee determined that the condition.
as created by past DC ground isolation efforts, constituted a condition prohibited by TS and prepared an LER on the subject.
The inspector reviewed the subject LER and found that the licensee's proposed corrective actions, involving an upgrade to
ground isolation procedures and the requirement for site senior management approval prior removing the subject control power to the relays, were appropriate to the event.
The inspector further concluded that the identification of the issue was the result of excellent attention to detail on the part of the ANPS.
This LER is closed.
08.3 Unit 1 Shutdown Coolin 71707 a.
Scope During the inspection period, the inspector became aware of an evolution, conducted during the 1996 refueling outage, in which operators secured the only operable shutdown cooling train to allow for a more rapid flooding of the reactor cavity.
The inspector followed up on this issue to ensure that TS were adhered to during the evolution.
b.
Observations and Findings Through a review of operator logs, the inspector was able to produce the following timeline:
5/10/96
~
00:08 Commenced draining the reactor cavity in accordance with OP 1-1600024.
Initial level was 60 feet and the target level was 54 feet, 7 inches.
~
Ol:40 Secured the draindown at the target level.
02:40 Recommenced draindown with a target level of 49 feet.
04:00 Secured draindown at the target level.
Hechanical Haintenance began hookup/lift activities for the Upper Guide Structure.
04:44 B LPSI pump secured for filling cavity to 54 feet
inches.
TS AS 3.9.8. l.a entered.
~
04:52 B LPSI pump started to fill cavity in accordance with OP 1-1600024.
05:21 B LPSI pump secured with cavity level at target level.
05:28 B LPSI pump started for shutdown cooling in accordance with OP 1-0410022.
AS exited.
During this evolution, the A train of shutdown cooling was inoperable due to work being performed on the train.
The use of the LPSI pump for cavity fill involved realigning the suction of the B LPSI pump from the RCS hot leg to the Refueling Water Tank (RWT), which allowed a rapid volume increase to the RCS/cavit The inspector discussed this event with a number of operators on shi ft at the time and found that several refused to perform the evolution,'inding the practice of voluntarily entering a TS AS contrary to their training.
Additionally, they stated that, while a significant volume of coolant existed in the cavity (above and in communication with the core), the practice of voluntarily securing the only operable train of shutdown cooling did not appear prudent.
The inspector reviewed TS 3.9.8. 1, which requi red at least one shutdown'ooling loop be operable in Mode 6 with cavity water level greater than or equal to 23 feet.
The AS associated with the TS stated that, with less than one shutdown cooling loop in operation,'perations involving an increase in decay heat loads or a reduction in boron concentration of the RCS be suspended.
Additionally, the inspector reviewed OP 1-160024, Revision 38, "Filling and Draining the Refueling Canal and Cavity,"
which was in affect at the time.
The procedure included provisions for the evolution in question in step 8.2.3,
"Filling the Refueling Canal and Cavity using LPSI Pump with one operable Shutdown Cooling Loop."
'he inspector found that the procedure was implemented properly.
Additionally. the inspector concluded that the TS AS was satisfied.
While the inspector found the subject evolution unusual.
the inspector concluded that regulatory and procedural controls had been complied with.
Conclusions The inspector concluded that, in an evolution involving securing the only operable shutdown cooling train to expedite cavity fill, the licensee did not violate TS or procedural requi rements.
II. Maintenance Conduct of Maintenance Maintenance on 2B Intake Coolin Water ICW Pum 62707 Inspection Scope The inspector observed portions of the maintenance performed on,the 28 ICW pump.
Observations and Findings Mechanical Maintenance (M/M) performed preventive maintenance on the 2B ICW pump per Procedure 2-M-0035, Revision 23, "Intake Cooling Water Pump Disassembly, Repair, and Reassembly."
The inspector reviewed the procedure in progress and noted that the maintenance was being performed in accordance with the procedure.
The inspector verified that crane operations for heavy load lifts were performed in accordance with Procedure AP 0010438, Revision 30, "Control of Heavy Loads."
The inspector also verified that all M&TE was calibrated, checked out.
and used properl Conclusions
M2 M2.1 M2.2 Maintenance on the 28 ICW pump was performed in accordance with applicable procedures.
Appropriate controls on heavy loads were employed.
The inspector also noted proper control and use of METE by the mechanics.
Maintenance and Material Condition of'acilities and Equipment Unit 2 Purification Ion Exchan er Resin Outlet Valve Maintenance 62707 Inspection Scope On March 20. the inspector witnessed portions of the replacement of the air diaphragm f'r the 28 Purification Ion Exchanger Resin Outlet Valve, V2391.
Observations and Findings The maintenance was conducted in accordance with Work Order (WO)
96012530.
The inspector reviewed the WO and verified that it contained
'ufficient detail to perform the work.
In addition, the torque values listed in the WO were verified against those stated in the vendor manual for the valve.
The inspector noted that a Radiation Protection
'ndividual was present at the job site.
The Radiation Work Permit was, reviewed and verified to have been complied with.
In addition, the inspector reviewed the clearance, 2-97-03-040, and verified it was adequate to safely complete this activity.
Conclusions The inspector noted no discrepancies with the performance of this maintenance.
Diesel Generator 18 Lube Oil Sam le 62707 Inspection Scope The inspector observed. the licensee obtain a lube oil sample from the
Diesel Generator in accordance with General Maintenance Procedure 1-M-0018, Revision 46,
"Mechanical Maintenance Safety-Related Preventive Maintenance Program."
Observations and Findings The inspector verified that the individual performing the maintenance had the correct procedure in hand and was qualified to perform the task.
The individual drawing the sample.was well versed in the operation of the sample pump rig.
The sample bottles were properly labelled.
Conclusions
M7 M7.1
The inspector noted that the individual performing this task was familiar with the equipment he was using and completed the activity in accordance with the procedure with no discrepancies.
Quality Assurance in Maintenance Activities Measurin and Test E ui ment M8TE Control 35750 Inspection Scope The inspector reviewed the licensee's program to control M&TE.
Observations and Findings The inspector reviewed FPL's requirements for the H&TE program.
Topical Quality Assurance Report (TQAR) TQR 12.0 "Control of Measuring and Test Equipment," Revision 5, Quality Instructions QI 12-PR/PSL-1, Revision 22, "Control and Calibration of M&TE," and QI 12-PR/PSL-2, Revision 22,
"Calibration of M&TE" essentially executed the requirements of 10 CFR 50, Appendix B, Criterion XII, and IEEE Standard 498-1980.
"IEEE Standard Requirements for Calibration and Control of Heasuring and Test Equipment Used in Nuclear Facilities."
In the past, each maintenance division has been responsible for a
majority of it's METE (Electrical Maintenance, M/H, etc.).
The licensee started placing control of all H&TE under I8C late last year, and planned on completing the mergers some time this summer.
Since this unification had not yet occurred, the inspector reviewed the processes and facilities in both the H/H and I8C Departments.
The inspector toured both the M/H and the I8C H&TE facility and verified that it met all of the requi rements of QI-12/PSL-2, Revision 22.
The inspector noted the following:
~
All H&TE and reference standards sampled were uniquely identified with a permanent identification marking that would not interfere with operation
~
All H&TE was properly tagged with the appropriate calibration status, and restricted use labels and rejected labels were in place as necessary
~
The location, storage, and security of the M&TE areas were appropriate
~
All out of calibration, broken, or otherwise unusable H&TE were properly segregated from the in service equipment
~
Historical files of H&TE were maintained as required The inspector reviewed the process of day shift and back shift issuance of H&TE with the I8C H&TE technician.
I8C uses a computer based logging
system to issue and receive H&TE.
The computer system will not allow any piece of H&TE to be checked out of the area if the tool calibration will expire prior to its scheduled return.
On day shift, the H&TE technician is responsible for the distribution of all METE from his shop.
On back shift, the worker's supervisor is responsible to ensure that all equipment is checked out properly.
If the computer system fails, there are paper logs available as a backup.
The inspector noted that back shift issuance of H/H H&TE was similar to I8C's method.
However, M/H implemented the requi rements of QI 12-PR/PSL-2 in General Maintenance Procedure GMP-02, Revision 14,
"Use of H&TE by Mechanical Maintenance."
This procedure provided more detailed information on the use and calibration of H&TE used by M/H (torque wrenches, pressure gauges, and micrometers).
The procedure as written requi red a Nuclear Plant Work Order (NPWO) to allow the H/H H8TE technician to repair or calibrate any piece of equipment.
Also the inspector noted many minor technical inadequacies that might have confused the procedure users.
The licensee has issued a Plant Manager's Action Item (PMAI), PM97-02-149, to ensure that these deficiencies are corrected.
H/H did not use a computer tracking system to issue tools.
They used a
hand written log instead.
This was allowable under QI 12-PR/PSL-2 and GHP-02.
All M/M torque wrenches have been calibrated at the same time.
This simplifies the calibration due date tracking.
However, earlier this year there was some confusion among the interacting organizations.
Planning had been told that all H8TE was now under the cognizance of I8C and therefore believed that M/H no longer required NPWOs to perform thei r calibrations.
I&C had not yet merged M/M M&TE into thei r organization and had not yet developed the proper procedures to control H/H H&TE.
Therefore, H/M still requi red NPWOs to perform thei r function but were not receiving them from planning.
CR 97-0210 documented the problem, and PMAI PM97-02-148 was issued to ensure that the work orders continued to be issued until I8C could complete its absorption of H/M H&TE.
The inspector reviewed the method in which I&C determines when a tool is coming due for calibration.
Although not proceduralized.
the M8TE technician requested a list of all tools that were due to be calibrated in the next week or two from the computer data base.
This list was divided into two sections.
One section listed all tools that could be calibrated on-site, while the other list was for M&TE that was requi red to be calibrated off-site.
These tools were then pulled for calibration.
If a tool happened to be in use at the time, the technician was able to inquire as to the user's identification.
The inspector noted that I8C's H8TE calibration program was procedurally driven.
Unlike the H/H procedures, the approved I&C procedures were sufficient to allow proper calibration and documentation for any piece of METE without the use of NPWOs.
The inspector asked the H8TE supervisor about the qualification
requirements for the H8TE technicians.
The I&C technicians are journeyman I8C technicians with specific documented training on H8TE calibration and procedures and are well versed in the requirements of IEEE standard 498-1980.
The inspector observed several calibration checks by the M/H H&TE Technicians and had no concerns.
c.
Conclusions Although the two H&TE programs observed on site were structured slightly differently. both met all regulatory and industry requirements.
Both programs were generally well managed and were successful at accomplishing their missions.
M7.2 Closed VIO 50-335/96-15-04
"Failure to Control H&TE" 35750 This violation was written when an inspector noticed that the Biddle model BM-10 ohmmeter used to test Unit 1 linear range power detector g9 was not logged out f'r that job as required by Procedure QI 12-PR/PSL-1.
Revision 21.
"Control and Calibration of Measuring and Test Equipment (M&TE)."
The procedure required that each item of H&TE have a log sheet filled out identifying each activity where the item was used.
Procedure-QI 12-PR/PSL-2 was revised in August.
1996 to state that borrowing M&TE was prohibited.
This information was incorporated into I8C training and into the other maintenance organizations procedures.
A memorandum was issued to all maintenance personnel on September 17, 1996, instituting additional controls to access M&TE including locked storage areas.
The inspector considers the corrective actions implemented to prevent recurrence adequate.
This item is close i
III. En ineerin Conduct of Engineering Reactor Coolant Pum Penetration Protection 37551 Scope The inspector reviewed CR 97-0311, which reported that overcurrent, protection for Reactor Coolant Pump (RCP) penetrations was not consistent with the Updated Final Safety Analysis Report (UFSAR).
Observations and Findings The CR described an issue, identified by the licensee's UFSAR review project, which involved a failure to provide independent control power sources to the primary and secondary means of protection (two levels of 6.9 kV breakers)
against high current conditions in RCP power sources which could result in damage to RCP electrical penetrations into the Unit 2 containment which might result in containment breeches.
Specifically, the licensee found that Unit 2 Licensing Condition 2.c. 11 required that, prior to startup following the first refueling outage.
the licensee was to complete design modifications to provide independent primary and backup fault protection for each electrical conductor penetrating containment.
In reviewing the issue, the licensee determined that, while independent relays acted to deenergize RCPs in two levels of breaker protection, the power sources to the relays was not consistent with the UFSAR, which stated, in response to Question Number 430A.4, page 430A.4-1, that the "...control circuit for backup protection will be provided given a different 125V dc train than the primary protection."
The license condition in question was inspected in NRC inspection report 89-07.
The report documented the execution of PC/H 15-283, which installed backup protection relays.
As a result of the inspection, the NRC issued a Safety Evaluation Report (SER) related to license amendment 41 stating that the subject license condition had been satisfied and that the license condition could be deleted.
The inspector reviewed th'
subject inspection report and found no specific discussion of protective relay power sources or UFSAR commitments.
As corrective action to the subject condition, the licensee is planning to implement a PC/0 during the upcoming Unit 2 outage to provide the UFSAR-specified redundant dc power supplies to the primary and secondary fault protection breakers.
Such a modification would bring the unit into conformance with the UFSAR for this subject.
The licensee stated that a letter was being prepared to the NRC describing this condition and describing corrective actions.
In discussing this issue with the licensee, it was agreed that a safety evaluation prepared to support the as-installed configuration would involve an Unreviewed Safety Question (USQ), in that the reduction in
independence manifested in the field would necessarily increase the probability of failure of a component important to safety (one or more RCP electrical penetrations).
However, the licensee stated that the condition in the field did not represent a "change to the facility as described" in the UFSAR (a condition of applicability for 10 CFR 50.59)
but rather a nonconforming condition being corrected under the licensee's corrective action program.
The inspector referred to Enforcement Guidance Memorandum 96-05,
"Enforcement Issues Associated with FSARs, Section 8. 1.3 Enforcement of FSAR Commitments," which appended enforcement guidance contained in NUREG-1600,
"General Statement of Policy and Procedures for NRC Enforcement Actions."
In the reference, it was stated
"Section 50.59 required a process to be followed in evaluating proposed changes from the description of the facility and its procedures described in the FSAR.
However,
CFR 50.59 is also used to form the basis for citations when the facility or procedures never met the description in the FSAR.
These cases represent de facto changes from the FSAR."
After review by NRC management, the inspector concluded that, while the identified condition represented a de facto violation of the
.
requi rements 'of 10 CFR 50.59, it should be a non-cited violation.
This issue will be treated as non-cited violation NCV 50-389/97-03-04,
"Nonconforming Reactor Coolant Pump Penetration Fault Protection".
Conclusions The inspector concluded that the licensee's voluntary UFSAR Review process had been effective in identifying fault protection control power field conditions which did not conform to the UFSAR.
The licensee's corrective action plans were prompt and appropriate.
The licensee's overall effort was considered responsible and was an example of a questi oning attitude on the part of the reviewers involved.
Unit 1 Over ower Event 37551 Scope On February 21, the licensee identified an error in the constants used in the Unit 1 Digital Data Processing System (DDPS) computer which resulted in the online calorimetric power indicating approximately
.63 percent low.
The net effect of this error was that the steady state power for Unit 1 exceeded the licensed limit of 2700 MWth for the current operating cycle.
The inspectors followed the licensee's root cause evaluation for the event.
Observations and Findings While performing feedwater flow loop calibrations on February 21 due to repairs on a feedwater flow transmitter, maintenance personnel determined that the DDPS scaling constants for all six flow inputs were
incorrect.
The scale should have reflected 4-20 mA for a 800 inches DP.
Instead, it reflected a span of 0-790 inches.
This effected the online calorimetric function of DDPS.
as feedwater flow is a prime contributor to the calculation.
The effect was that of underestimating feedwater flow, thereby directly underestimating reactor power
.
While DDPS was not safety-related and had no automatic safety functions, it did affect safety systems.
as the calorimetric output was used nightly to calibrate safety-related Nuclear Instrumentation (NI) and Delta T power channels, which provided both indication and input into the Reactor Protection System (RPS).
The timeline for subsequent events is as follows:
1730 on 2/21 1740 on 2/22 1755 on 2/21 0100 on 2/22 0120 on 2/22 1200 on 2/22 1330 on 2/22 2127 on 2/22 The control room was notified that DDPS constants for feedwater may be in non-conservative error.
Downpower to 99 percent commenced to provide margin to error.
Dow'npower secured at 99 percent
. Interim disposition to CR 97-0327 was received stating that no operability concern existed with reactor power 99 percent or less by DDPS indication.
Nuc/Delta T Power calibration completed (log only included reference to channels C and D).
ILC placing new constants into the DDPS system 18C completed placing new constants in DDPS.
Indicated Calorimetric Power now 99.73 percent.
Nuc/Delta T calibrations performed.
The licensee promptly formed an Event Response Team, comprised of engineers and maintenance personnel, and initiated CR 97-0327 to document the condition.
The inspector responded to the site and, after being briefed on the condition, performed a manual calorimetric per Procedure OP 1-3200020, Revision 25,
".Primary System Manual Calorimetric," and verified that the licensee was not exceeding licensed power limits after the downpower.
The inspector questioned the ANPS as to whether the DDPS calorimetric data point was operable and whether DDPS data points were typically'ogged in the out-of-service (OOS) log.
The ANPS stated that the data points were typically logged in the OOS log and that he did not consider this point inoperable, as the ERT had assured him that the magnitude of the error was known.
CR Generation The inspector reviewed CR 97-0327, generated when the subject condition was identified.
The inspector noted that the condition describe'd was as follows:
"It appears Unit One is operating approximately 0.6 percent higher in power than is indicated on the DDPS system."
The inspector found that the CR did not document the condition (i.e. the erroneous constants identified in DDPS) but rather the impact on the system, which was unsupported by calculation in the CR.
The inspector noted that the CR was correctly characterized as a nonconformance.
The CR received an interim operability assessment on February 22 which stated that no operability concern existed for reactor power at or below 99 percent.
The assessment did not state what operability was in question.
The assessment did state that the inaccuracy introduced by the erroneous constants.
when applied against the known instrument uncertainty upper bound did not result in reactor power having exceeded 102 percent, the accident analysis limit.
The inspector found that the interim operability assessment had not received a
FRG review, as required by Procedure (AP) 0006130, Revision 7, "Condition Reports," step 8.7. 10.C, which required that, for CRs which specify repair or use-as-is interim dispositions of, nonconformances, FRG review be obtained prior to declaring systems/components operable or returning them to service.
At the close of the inspection period, additional information was required to determine whether the apparent failure to obtain a
FRG review was the result of a procedural interpretation problem (e.g.
an operability, assessment not being considered an interim disposition).
Consequently, this issue will be tracked as an Unresolved Item, URI 50-335/97-03-05,
"Failure to Obtain FRG Review f'r Interim CR Disposition."
J During the day shift on February 22, the licensee input the correct constants into DDPS for feedwater flow.
The licensee reported that the online calorimetric output subsequently increased the predicted amount.
Later that day, the inspector questioned operators as to the accuracy of RPS setpoints.
Nightly, operators performed RPS calibrations per Procedure OP 1-1200051, Revision 19,
"Nuclear and Delta T Power Calibration."
The methodology of the procedure involved performing a
manual calorimetric in accordance with Procedure OP 1-3200020, Revision 25,
"Primary System Manual Calorimetric," and comparing this value with the DDPS calorimetric.
If the two values differed by less than
percent, the DDPS value was used to adjust indicated Nuclear Instrumentation (NI) power.
Once NI power was adjusted to agree with
'DDPS, the difference between NI power and Delta T power (a power signal produced by the RPS by multiplying the core differential temperature by RCS mass flow rate and the specific heat of the coolant)
was nulled such that DDPS, NI, and Delta T power all agreed.
The inspector asked whether the (known) errant DDPS calorimetric output had been used in performing the last Nuclear and Delta T calibrations.
Operators said that it had.
The inspector then pointed out that, since the power signals had been adjusted based on an artificially low DDPS power, and since no calibration had been performed since the new (correct)
constants were loaded, the RPS was still being fed artificially low power signals.
While this slight error did not affect steady state power (operators were still maintaining power less than 100 percent), it did affect RPS variable high power and Thermal Margin/Low Pressure (TM/LP) trips, which, used the power signals.
Operators concurred in the
inspector's assessment and, at 9:27 p.m., the Nuclear and Delta T power calibrations were reperformed.
At the close of the inspection period, the inspector required documentation which controlled the installation of the new OOPS constants to examine the basis for not performing a
nuclear and delta T calibration following the installation of the constants as a post-maintenance test.
Consequently, this issue will be tracked as an Unresolved Item, URI 50-335/97-03-06,
"Post-Maintenance Testing Issues Associated with DDPS Constant Changes."
At the close of'he inspection period, the inspector was still reviewing the licensee's root cause evaluation for this event.
While a cursory review indicated that software control and validation and verification issues (V8V) existed, additional review was required to determine whether violations oi NRC requi rements occurred.
Specifically, while reviews indicated that V8V was performed by the maintenance organization, questions exist as to the appropriateness of maintenance performing this function.
Additionally, it was clear that inappropriate controls were in place f'r DDPS software and for manuals generally available in the control room.
However. additional reviews were required to determine whether the lack of controls constituted a fai lure to meet the requi rements of the licensee's Quality Assurance Plan.
Finally, additional reviews were required to determine whether the licensee had prior opportunities to prevent or mitigate this event.
In reviewing the licensee's ERT package, the inspector noted LER 50-389/92-008-01, "Digital Data Process System Calorimetric Error due to Instrument Calibration Error," which documented errors in software control which led to inaccurate burnup constants being loaded into DDPS for self-powered rhodium incore detectors.
Additionally. the inspectors noted that, throughout the fall of 1996, the licensee had indications that Unit 1 was outperforming Unit 2 thermally.
Additional reviews were requi red to determine whether this (or possibly, consi stent devi ations between the manual and DDPS calorimetrics)
should have alerted the licensee to the problem earlier.
As a result of the additional reviews required to determine whether violations of NRC requi rements existed, the issue will be tracked as an Unresolved Item, URI 50-335/97-03-07,
"Issues Relating to Exceeding Unit I Licensed Steady State Power Levels."
Specific issues to be resolved under 'this URI include:
Whether the licensee's software V8V processes were adequate and in agreement with the licensee's Quality Assurance Plan Whether the licensee's QA Plan requirements were violated regarding control of software and manuals Whether corrective actions to previous events should have prevented this event and whether data available to the licensee should have resulted in earlier detection of the condition
P
~
The extent to which licensed steady'state power limits for Unit 1 were exceeded during the current Unit 1 fuel cycle.
Conclusions The inspector found that additional significant review was required to appropriately'address fai lures Teading to.
and following the identif'ication of, errors introduced into the DDPS system which resulted in Unit 1 operating in excess of licensed thermal power limits during the current fuel cycle.
Consequently, Unresolved Items 50-335/97-03-05, 06.
and 07 were opened to track resolution of these issues.
IV. Plant Su or t Radiological Protection and Chemistry Controls Radiolo ical Effluent Monitorin 84750 Inspection Scope The purpose of this inspection effort was to evaluate whether the licensee was monitoring radiological effluents in accordance with the requirements of licensee TS and that procedures for implementing the effluent monitoring program were established, implemented, and maintained in accordance with TS 6.8. 1.
Observations and Findings The inspectors accompanied chemistry technicians collecting routine samples of radiological effluent streams.
Activates associated with sample preparation, analysis, and logging of information were observed.
The inspectors reviewed the licensee procedures associated with the sampling and analysis of effluent streams and verified that the procedures were properly controlled.
Overall, the procedures provided sufficient instructions for completing task observed.
The procedures included good quality control measures for collecting the sample; communications; ensuring plant monitoring equipment was operated properly; and samples were properly prepared, analyzed; and results
'ecorded.
During the inspection, the inspectors found chemistry technicians were knowledgeable of the imp'lementing procedures.
Good use of procedures by chemistry technicians throughout all of the observed rocesses were observed by the inspectors.
The procedures were utilized y the technicians in the laboratory and at sampling locations:
Conclusion The licensee's effluent sampling processes met the regulatory requi rements.
Chemistry technicians demonstrated good understanding of effluent sampling procedures and good use of procedures was observed during effluent samplin R3.1 P2 P2.1
Radiation Protection and Chemistry Procedures and Documentation Im lementation of Revised
CFR Parts 100-179 and
CFR Part
ITTI2515/133 Inspection Scope Selected transportation'rocedures were reviewed to evaluate whether the licensee had revised applicable licensee procedures for the implementation of various changes in Revised
CFR Parts 100-179 and
CFR Part 71.
Documentation of a recent licensee shipment of radioactive waste for disposal was closely examined for compliance with the licensee's, procedures.
Observations and Findings The licensee procedures adequately implemented the applicable requirements.
A licensee shipment of radioactive waste f'r disposal was closely examined for compliance with licensee and regulatory requirements.
The inspectors verified the licensee's classification, quantity calculations were correct, and the licensee was effectively implementing the revised requirements.
Conclusions The inspectors determined that the licensee personnel responsible for the shipments of radioactive material were knowledgeable of the regulatory changes and had adequately implemented those changes in plant procedures.
Status of EP Facilities, Equipment, and Resources Hobilization of the Emer enc Res onse Or anization 82701 Inspection Scope The inspectors reviewed the licensee's strategy and provisions for notification and mobilization of its emergency response organi zation (ERO) personnel in the event of an off-hour emergency declaration requiring activation and staffing of emergency response facilities (ERFs).
The requirements with respect to this process were described in Section 2.4 of the Radiological Emergency Plan (REP).
Observations and Findings As a result of a special inspection of the licensee's emergency reparedness (EP) program in October 1996. the NRC determined that the icensee had failed to adequately maintain ERO call-out capabilities with respect to the automated system (from about July 22 to October 3, 1996)
as well as the manual backup system (during an indeterminate
per iod of't least the last several years).
This finding was identified as Violation, VIO 50-335,389/96-18-01,
"ERO Augmentation Scheme Not Maintained Adequately. "
The inspectors reviewed the licensee's response, dated February 6,
1997, to the NRC's Notice of Violation and Proposed Imposition of Civil Penalties, dated January 10, 1997.
The response delineated several specific corrective actions to address the subject violation and to avoid further violations in this area of EP.
The inspectors independently verified the satisfactory implementation of all corrective steps associated with this violation.
Conclusions Through the independent verification effort described above, the inspectors determined that the licensee had developed and implemented significant improvements in. both the automated and manual backup systems for notification of the ERO.
VIO 50-335,389/96-18-01,
"ERO Augmentation Scheme Not Maintained Adequately" is closed.
Facilit Ins ection 82701 Inspection Scope The inspectors selectively examined the licensee's ERFs and associated equipment to assess their adequacy and to determine whether they were maintained in a state of operational readiness as described in the REP.
Observations and Findings The inspectors toured the Unit 1 Control Room, the adjacent Technical Support Center (TSC),
and the Operational Support Center (OSC).
Selected equipment and supplies within these facilities were inspected, including communications systems, radiological instruments, and miscellaneous supplies stored in cabinets.
All inspected equipment was found to be in operable/acceptable condition, and no discrepancies in equipment and supplies were identified in comparison with the inventory.
The licensee conducted a monthly surveillance of emergency equipment, instruments, and supplies in accordance with Procedure HP-90,
"Emergency Equipment."
Records of survei llances and periodic tests were inspected for the period January 1996 through February 1997, and indicated that the subject activities had been performed as required.
The documentation recorded that deficiencies identified during these survei llances were expeditiously corrected.
In February 1997, the licensee relocated the primary OSC to the second floor of the South Service Building (formerly in the North Service Building).
This change represented a significant upgrading of the OSC because of the improved physical facilities and a new layout which allowed OSC management personnel to sit together at a conference table for enhanced internal communications.
A closed-circuit audiovisual link
with the TSC enabled the monitoring of briefings in that facility by OSC ersonnel.
According to licensee records, drills using the new facility ad confirmed and refined its design and capabilities.
The inspectors commended the licensee's improvements in this area.
Conclusions Emergency response facilities were adequately equipped and were maintained at a suitable level of operational readiness.
The new OSC provided enhanced physical and communications capabilities.
EP Procedures and Documentation Radiolo ical Emer enc Plan 82701 Inspection Scope The inspectors reviewed the licensee's maintenance of the REP and selected commitments therein, and reviewed a recent revision to the REP to determine whether any changes had been made which decreased the effectiveness of the Plan.
Observations and Findings The version of the REP in effect at the time of the current inspection was Revision 32, effective January 29, 1997.
This was the only REP revision since the special inspection of the EP program conducted in October 1996.
The inspectors'eview of Revision 32 determined that the changes were primarily editorial or administrative in nature, with some minor emergency action level and organizational modifications.
The most significant changes in the subject REP revision were in Section 7.2.2 regarding the role of drill and exercise participation in emergency response organization (ERO) qualification standards.
The rationale and bases for this change were discussed with licensee representatives.
This modification brought the-St.
Lucie REP into consistency with the REP for the licensee's Turkey Point Plant.
The changes made in Revision 32 did not decrease the effectiveness of the REP.
An apparent deviation from licensee commitments was identified during the October 1996 inspection and tracked as Escalated Enforcement Item, EEI 50-335,389/96-18-02,
"Deleted Technical Specification Not Relocated to Security Plan and REP."
An NRC letter dated January 10, 1997, transmitting a Notice of,Violation and Proposed Imposition of Civil Penalties, informed the licensee that the subject finding was not a
deviation.
This item is therefore administratively closed.
However, the January 10.
1997, letter also stated that "the NRC continues to believe that the language utilized in both plans is imprecise and could be revised to improve clarity and intent."
The inspectors observed that the licensee's inclusion of the referenced deleted TS requirement in REP Revision 32 appropriately addressed the original finding, notwi'thstanding the NRC's ultimate determination that a deviation had
not occurred.
The inspectors were informed by the licensee (but did not confirm) that an analogous addition was made to the Security Plan.
Conclusions Changes made to the REP since the October 1996 inspection did not decrease Plan effectiveness, and implementation of selected REP commitments was found to be now fully satisfactory.
P3.2 Plant Emer enc Procedures 82701 Inspection Scope The inspectors reviewed the licensee's administration of selected REP requi rements through evaluation of the adequacy of the implementing details contained in the Emergency Plan Implementing Procedures (EPIPs).
Maintenance of controlled copies of the EPIPs was also inspected.
Observations and Findings A finding from the October 1996 inspection was identified as VIO 50-335,389/96-18-03,
"Inadequacies in Certain Emergency Plan Implementing Procedures."
The violation involved two examples:
(1) recovery activities, discussed conceptually in REP Section 5.4. were not adequately addressed in the EPIPs; and (2) the EPIPs did not adequately describe and delineate the licensee's ERO and the detailed
'eans for notifying ERO members in an emergency.
The inspectors reviewed the licensee's response, dated February 6,
1997, to the NRC's Notice of Violation and Proposed Imposition of'ivil Penalties, dated January 10, 1997.
The response delineated several specific corrective actions to address the subject violation and to avoid further violations in this area of EP.
The inspectors independently verified the satisfactory implementation of all corrective steps associated with this violation.
A third example of inadequate EPIPs was originally identified as part of apparent Violation, VIO 50-335,389/96-18-03, along with the two examples delineated above.
This example asserted that REP Section 2.4.4, addressing OSC relocation, was not adequately implemented by the EPIPs.
The NRC letter dated January 10, 1997, (which transmitted the aforementioned Notice of Violation) categorized this finding as an EP program weakness, and requested the licensee's response.
The corrective actions described. in the licensee's February 6, 1997, response were independently verified by the inspectors as having been fully implemented.
Selected copies of the EPIPs which were available for use at the Control Room, TSC, and OSC were checked and found to be current revision c.
Conclusions
VIO 50-335,389/96-18-03,
"Inadequacies in Certain Emergency Plan Implementing Procedures" is closed.
A program weakness identified in the NRC's Enforcement Letter dated January 10, 1997, was addressed through appropriate corrective action.
P5 Staff Training and gualification in EP P5. 1 Initial Trainin and Annual Retr ainin of ERO Personnel 82701 a.
Inspection Scope The inspectors reviewed the licensee's ERO training program as described in REP Section 7.2.2,
"Training of On-Site Emergency Response Organization Personnel."
and as implemented by Procedure EPIP 3100034E,
"Maintaining Emergency Preparedness
- Emergency Response Plan Training."
b.
Observations and Findings During the October 1996 inspection.
three examples of failure to implement specific REP requirements regarding ERO training were collectively identified as VIO 50-335,389/96-18-04,
"Training Program Not Adequately Implemented."
The inspectors reviewed the licensee's response, dated February 6.
1997.
to the NRC's Notice of Violation and Proposed Imposition of Civil Penalties.
dated January 10, 1997.
The response delineated several specific corrective actions to address the subject violation and.to avoid further violations in this area of EP.
The inspectors independently verified the implementation of most of the corrective steps associated with this violation.
Licensee management was informed that this violation would remain open pending the NRC's receipt and review of'he following:
~
'evision of Procedure EPIP 3100034E, expected to implement a
quarterly drill program (among other changes).
The procedure was in draft form at the time of the inspection.
and was scheduled for issuance by April 1, 1997.
~
Documentation of completion of the upgraded ERO training program, in conformance with the requirements of the revised Procedure EPIP 3100034E.
The licensee stated that approximately 70 percent of ERO personnel had received initial training under the new program as of March 6.
1997; the target date for the completion of this effort was April 1, 1997.
Verification of the implementation of Procedure QI 5-PR/PSL-1, Revision 0, "Preparation, Revision, Review/Approval of Procedures."
approved January 22, 199 c.
Conclusions
Through the independent verification effort described above, the inspectors determined that the licensee had developed and partially implemented significant improvements in the training program for the ERO.
VIO 50-335.389/96-18-04,
"Training Program Not Adequately Implemented" remains open pending the NRC's receipt and review of'he documentation delineated above.
P5.2 Exercises and Drills 82701 a.
Inspection Scope The inspectors reviewed recent changes to the licensee's exercise and drill program.
b.
Observations and Findings During the previously referenced October 1996 inspection, the NRC determined that the licensee had not provided a programmatic method to
'nsure that each individual, through participation in a drill or exercise, demonstrated an ability to perform assigned emergency functions, as apparently required by REP Section 7.2.2.
Pending receipt and evaluation of additional information from the licensee, this matter was identified as Unresolved Item, URI 50-335.389/96-18-05,
"ERO Personnel Not Qualified Through Drill/Exercise Participation."
The inspectors determined that the changes made in REP Revision 32 adequately addressed the subject URI.
(See Section P3.1 above for additional information.)
This item is closed based on the clarifications provided in Revision 32 regarding the ERO training program.
c.
Conclusion URI 50-335,389/96-18-05,
"ERO Personnel Not Qualified Through Drill/Exercise Participation" is closed.
P7 Quality Assurance in EP Activities P7. 1 Corrective Action Pro ram 82701 a.
Inspection Scope The inspectors reviewed the licensee's program for identifying and correcting weaknesses and deficiencies in EP.
This review was primarily a follow-up of previously identified issues with respect to the corrective action progra b.
Observations and Findings
Several related finding's from the October 1996 inspection were collectively identified as an EP Program Weakness, and were tracked as Inspection Follow-up Item. IFI 50-335.389/96-18-06,
"Untimely Corrective Actions For Some Emergency Preparedness Deficiencies."
The specific examples identified in the inspection report were:
(1) failure to address concerns in a timely manner regarding the audibility of the Gaitronics (or plant public-address system) formally identified in late 1994; (2) failure to provide timely corrective action to address a
questionable capability for notification of the State of Florida within 15 minutes of an emergency declaration; and (3) failure to implement timely corrective actions for deficiencies and recommendations identified by the critique of the Hurricane Erin response in August 1995.
The inspectors reviewed each of the three issues listed above and made the following determinations, respectively:
(1)
Within the Power Block, repairs to the PA system were completed before the end of 1996 following a testing program to identify areas having audibility problems.
Certain areas outside the Power Block were also identified as having inadequate PA audibility, and work on these was still in progress.
The licensee was identifying many electrical problems with the system.
Two electricians were assigned to this effort on a full-time basis.'2)
Five Rotating Haintenance Shift Supervisors were trained for the position of Control Room Communicator (handling offsite communications).
(3)
A new Procedure ADA-04.01, "Hurricane Season Preparation,"
Revision 0, approved January 31, 1997, was developed to enhance St. Lucie's general state of readiness during the hurricane season.
Revisions to Procedures AP-0006128,
"Hur ricane Preparation
- On-Site Staffing," and AP-0005753,
"Severe Weather Preparations" were in process to address critique issues from Hurricanes Erin and Bertha.
The actual corrective actions for most of the substantive issues from those critiques were
. completed.
c.
Conclusions IFI 50-335.389/96-18-06.
"Untimely Corrective Actions For Some Emergency Preparedness Deficiencies" is closed based on completed and in-progress efforts in the previously problematic areas.
The licensee had made good progress in addressing the more significant outstanding EP deficiencies, and had considerably reduced the backlog of open items in its EP progra V. Hang ement Heetin s and Other Areas X1 Exit Heeting Summary The inspectors presented the inspection results to members of licensee management.at the conclusion of the inspection on April 4, 1997.
An interim exit meeting was held on March 7, 1997, to discuss the findings of Region Based inspection.
The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary.
No proprietary information was identified.
During the inspection period, the licensee reported that NRC IR 96-20 erroneously reported that several operational and maintenance factors, including the extended 1996 Unit 1 outage.
led 'to the licensee exceeding their annual dose goal of 326 man-rem.
The licensee presented excerpts from their 1996 Business Plan, which established a 1996 collective exposure goal for St. Lucie of less than or equal to 485 man-rem.
The licensee stated that the 326 man-rem figure represented a site goal which was more aggressive than the FPL business plan goal.
PARTIAL LIST OF PERSONS CONTACTED Licensee H. Allen. Training Manager C. Bible, Site Engineering Manager W. Bladow, Site Quality Manager G. Boissy, Materials Hanager H. Buchanan, Health Physics'upervisor D. Fadden, Services Manager R. Heroux, Business Manager H. Johnson, Operations Manager J.
Marchese, Maintenance Manager C. Harple. Operations Supervisor J. Scarola, St. Lucie Plant General Manager A. Stall, St. Lucie Plant Vice President E.
Weinkam, Licensing Manager W. White. Security Supervisor Other licensee employees contacted included office. operations, engineering, maintenance, chemistry/radiation, and corporate personnel.
IP 35750:
IP 37551:
IP 62707:
IP 71707:
IP 82701:
INSPECTION PROCEDURES USED QA Program Measuring and Test Equipment Onsite Engineering Maintenance Observations Plant Operations Operational Status of the Emergency Preparedness Program
IP 84750:
Radioactive Waste Treatment, and Effluent and Environmental Monitoring TI 2515/133:Implementation of Revised
CFR Parts 100-179 and
CFR Part
ITEMS OPENED.
CLOSED, AND DISCUSSED
~0ened 50-335/97-03-01 50-335/97-03-02 NCV NCV
"Failure to Adequately Implement an Equipment Clearance Order" (01.4)
"Failure to Update the UFSAR Following Modification of the Waste Gas System" (04. 1)
50-335,389/97-03-03 URI
"Excessive Overtime Usage Among Reactor Control Operators" (06. 1)
50-389/97-03-04 50-335/97-03-05
50-335/97-03-06 50-335/97-03-07 Closed 50-335,389/95-22-03 50-335/96-15-04 50-335,389/96-18-01 50-335,389/96-18-02 50-335 '89/96-18-03 50-335,389/96-18-05 50-335,389/96-18-06 NCV URI URI URI IFI VIO VIO EEI VIO URI IFI
"Nonconforming Reactor Coolant Pump Penetration Fault Protection" (El.1)
"Failure to Obtain FRG Review for Interim CR Disposition" (E1.2)
"Post-Maintenance Testing Issues Associated with DDPS Constant Changes" (E1.2)
"Issues Relating to Exceeding Unit 1 Licensed Steady State Power Levels" (E1.2)
"SG Level Channel Inaccuracies Due to Sensing Line Blockage" (08.1)
"Failure to Control M&TE" (M7.2)
"ERO Augmentation Scheme Not Maintained
'dequately" (P2. 1)
"Deleted Technical Specification Not Relocated to Security Plan and REP" (P3. 1)
"Inadequacies in Certain Emergency Plan Implementing Procedures" (P3.2)
"ERO Personnel Not Qualified Through Drill/Exercise Participation" (P5.2)
"Untimely Corrective Actions For Some Emergency Preparedness Deficiencies" (P7. 1)
50-335/96-015-00 Discussed 50-335/96-17-08
LER
"Operation Prohibited by Technical Specifications Due to Loss of Underyoltage Protection on Safety Related Electrical Bus" (08.2)
"Failure to Develop and Maintain Adequate Calibration Procedures for CROAIMs" (02. 1)
50-335,389/96-18-04 VIO
"Training Program Not Adequately Implemented (P5.1)
50-335/97-01-01 50-389/92-008-01 VIO
"Failure to Follow the In-Plant Equipment'learance Orders Procedure" (01.4)
LER
"Digital Data Process System Calorimetric Error due to Instrument Calibration Error" (E1.2)
LIST OF ACRONYHS USED ADH AFAS ANSI AP ASI ATTN CCW CEA CFR CIS CR CROAIH DBD OOPS DEH DOT DP DPH DPR ECO ECP EEI EMP EOP EP EPIP ERF ERO ERT ESF F'dministrative Procedure Auxiliary Feedwater Actuation System American National Standards Institute Administrative Procedure Axial Shape Index Attention Component Cooling Water Control Element Assembly Code of Federal Regulations Containment Isolation System Condition Report Control Room Outside Air Intake Monitor Design Basis Document Digital Data Processing System Digital Electro-Hydraulic (turbine cont Department Of Transportation Differential Pressure Disintegration Per Minute Demonstration Power Reactor (A type of Equipment Clearance Order Estimated Critical Positions Escalated Enforcement Item Electrical Maintenance Procedure Emergency Operating Procedure Emergency Preparedness Emergency Plan Implementing Procedure Emergency Response Facility Emergency Response Organization Event Response Team Engineered Safety Feature Fahrenheit rol system)
operating license)
FPL FRG FRV FS FSAR GL GMP HEPA HVE ICW IEEE IFI IP IR IV KV KW LCO LER LOOP LPSI M/M M8tTE MFRV MWt NCV NI Nos.
NOP NOV NPF NPO NPWO NRC NUREG ONOP OOS OSC PA PC/M PDR PGM PMAI psi psia Pslg PSL PWO OI RCO RCP RCS
The Florida Power 8 Light Company Facility Review Group Feedwater Regulating Valve Flow Switch Final Safety Analysis Report
[NRCj Generic Letter General Maintenance Procedure High.-Efficiency Particulate Air Heating and Ventilating Exhaust (fan, system, etc.)
Intake Cooling Water Institute of Electrical and Electronics Engineers
[NRCj Inspector Followup Item Inspection Procedure LNRC] Inspection Report Independent Verification Kilovolt(s)
Kilowatt(s)
TS Limiting Condition for Operation Licensee Event Report Loss of Offsite Power Low Pressure Safety Injection (system)
Mechanical Maintenance Measuring 8 Test Equipment Main Feedwater Regulating Valves Megawatt(s).
Thermal
[Energy from the Reactorj Non-cited Violation (of NRC requirements)
Nuclear Instrument Number Normal Operating Pressure Notice of Violation Nuclear 'Production Facility (a type of operating license)
Nuclear Plant Operator Nuclear Plant Work Order Nuclear Regulatory Commission Nuclear Regulatory (NRC Headquarters Publication)
Off'ormal Operating Procedure Out Of Service Operations Support Center Public Address Plant Change/Modification NRC Public Document Room Plant General Manager Plant Management Action Item Pounds Per Square Inch Pounds per square inch (absolute)
Pounds per square inch (gage)
Plant St. Lucie Plant Work Order Quality. Instruction Reactor Control Operator Reactor Coolant Pump Reactor Coolant System
REP RII RO RPS RWT SER SG SNPO SOER SRO St.
STA SUR TE TI TMLP TQAR TS TSC UFSAR URI USNRC USQ VCT
Radiological Emergency Plan Region II - Atlanta, Georgia (NRC)
Reactor [licensedj Operator Reactor Protection System Refueling Water Tank Safety Evaluation Report Steam Generator Senior Nuclear Plant [unlicensedj Operator Sequence of Events Recorder Senior Reactor flicensedj Operator Saint Shift Technical Advisor Startup Rate Temperature Element
[NRC] Tempo ary Instruction Thermal Margin Local Power Topical Quality Assurance Report Technical Specification(s)
Technical Support Center Updated Final Safety Analysis Report
[NRCj Unresolved Item United States Nuclear Regulatory Commission Unreviewed Safety Question Volume Control Tank Violation (of NRC requirements)
Work Order