IR 05000259/1997005
| ML18038B890 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 06/05/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18038B888 | List: |
| References | |
| 50-259-97-05, 50-259-97-5, 50-260-97-05, 50-260-97-5, 50-296-97-05, 50-296-97-5, NUDOCS 9706120171 | |
| Download: ML18038B890 (62) | |
Text
U.S.
NUCLEAR REGULATORY COHHISSION
REGION II
Docket Nos:
License Nos:
50-259, 50-260.
50-296 DPR-33, DPR-52, DPR-68 Report Nos:
50-259/97-05, 50-260/97-05, 50-296/97-05 Licensee:
Tennessee Valley Author ity Facil.ity:
Browns Ferry Nuclear Plant, Units 1,
8 3 Location:
Corner of Shaw and Browns Ferry Roads Athens,'AL 35611 Dates.
- Harch 30
- Hay 10, 1997 Inspectors:
Approved by:
L ~ Wert, Senior Resident Inspector H.. Horgan, Resident Inspector J'. Starefos, Resident Inspector J. Coley, Reactor Inspector (Section H2.1)
D. Thompson, Safeguards Inspector
'(Sections S3.1, S3.2, and P8.1)
H. Lesser, Chief Reactor Projects Branch
Division of Reactor Projects Enclosure
'P706120i7l 970605 PDR ADOCK 05000259
ik
EXECUTIVE SUMMARY Browns Ferry Nucleat Plant, Units 1,
8 3 NRC Inspection Report 50-259/97-05, 50-260/97-05, 50-296/97-05 This integrated inspection included aspects of licensee operations, engineering, maintenance, and plant support.
The report covers a six-week
.period of resident inspection; in addition, it includes the results of an announced inspection by two region-based inspectors.
0 erations The licensee's review of a scram and HSIV closure was thorough.
Control room operators responded well to the incident.
With the exception of the steam line flow instrumentation, safety equipment performed as expected.
The licensee intends to address the instrumentation issues which could cause an inadvertent HSIV closure on a turbine trip.
(Inspection Followup Item 260/97-05-04, Spurious Hain Steam Isolation Valve Closure on Turbine Trip, Section 01.1)
Control room operators failed to promptly reset a locked recirculation pump scoop tube when an automatic runback of the 3B recirculation pump was called t
for but did not occur..
(Violation 50-296/97-05-01, Failure to Reset Locked Recirculation Pump Scoop Tube, Section 01.3)
NRC inspectors identified examples in which some auxiliary equipment operator s (AUOs).did not question equipment conditions or pursue deficiency resolution adequately.
Similar observations have been noted in previous inspection.
reports.
During the final week of this inspection report period, the licensee revised work assignments for the AUOs.
This is intended to reduce interruptions of. AUOs.while on plant tours and is expected to improve the effectiveness of the rounds.
(Section 02.1)
Maintenance h
Ultrasonic examinations performed by NRC to determine the structural condition of the Unit 3 torus revealed plate readings below the nominal thickness but acceptable in accordance with Section XI of the American Society of Mechanical Engineers Code.
In addition the inside surface condition of the torus as revealed by volumetric examination was very good..
(Section H2.1)
il
Two events occurred during the inspection period involving significant deficiencies in work practices by the involved technicians.
In retent months there have been several incidents at Browns Ferry in which important plant equipment was affected because of deficient second party or self checking practices.
The licensee's investigations into the HPCI steam supply line valve closure event and the reactor scram were thorough.
The investigation into one of the incidents identified that there were several deficiencies in the use of the Volt-Ohm-Heter.
Identification of the closed HPCI steam line valves by the CR operator was timely considering no alarm was received when the valves were closed.
(Violation 260,296/97-05-02, Failures to Implement Haintenance Procedures, Sections Hl.3 and Hl.4)
Workers involved in the testing of a seismic monitoring accelerograph were cautious and performed second party verification in accordance with procedures.
Post maintenance testing intended to test the loss of power alarm was not well written.
A discrepancy between plant equipment and the UFSAR was identified by the inspector.
The number of procedural problems was high and it appeared that the validation process was being used to 'develop the procedure in some areas.
(Sections H1.5 and E8.1)
The process implemented.to ensure that properly qualified workers are assigned to Fix-It-Now minor maintenance tasks was adequate.
(Section H1.6)
Poor implementation of controls to reduce the possibility of employee exposures to asbestos and radioactive contamination was identified associated with the removal of Unit 2 feedwater, heater level control valve seats and gaskets.
The licensee's corrective actions f'r the deficiencies were.
adequate.
(Non-Cited Violation 50-260,296/97-05-03, Failure to Obtain Radiological Control Surveys, Section M8.1)
En ineerin The inspectors identified a mal functioning Emergency Diesel Gener ator Building flood prevention check valve.
The condition, while not desirable, did not represent a significant condition adverse to quality.
However, the licensee had not effectively addressed previous deficiencies involving the same valve.
(Section E2.1)
Unit 2 Reactor Core Isolation Cooling system maintenance and troubleshooting was not well conducted.
Although the allowed 7-day inoperability period'as not. exceeded, the return of RCIC to an operable status was delayed by ineffective troubleshooting.
Technical support early in the troubleshooting process was not strong.
Information indicated that some engineers were not reviewing available performance data after testing of safety related equipment.
(Section E2.2)
Plant Su ort On April 23, 1997, the inspector observed an emergency preparedness training drill from the simulator control room.
Overall, the operators performance was good.
(Section Pl. 1)
~
i
0
The inspectors determined that the chain of custody is maintained for samples collected during random and for-cause drug test.
The inspectors determined that there were no noted equipment or personnel errors not logged in the Security Equipment L'ogs, that caused the licensee to be in non-compliance with regulatory requirements.
(Section S3.1, S3.2)
The inspectors found that the licensee's actions implemented regarding IN96-71 was good.
Licensee inspection data sheets provided adequate coverage of plant areas, systems, and equipment.
(Section P8.1)
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Summar of Plant Status Re rt Details Unit 1 remained in a long-term lay-up condition with the reactor defueled.
Units 2 and 3 operated near full power for most of the report period.
On April 24, 1997, Unit 2 scr ammed due to a personnel error during a surveillance test (Sections 01.1 and H1.3).
Unit 2 was returned to full power operation on April 30.
On Hay 6, Unit 3 reduced power to about 95 percent for-appr oximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> to isolate a steam leak on a level control column on the 3C1 feedwater heater.
While performing the inspections discussed in this report,
.the inspectors reviewed the applicable portions of the Updated Final Safety Analysis Report (UFSAR) that related to some of the areas inspected.
During obser vation of seismic monitoring instrumentation testing, the inspector identified that the enclosure around the monitors was not constructed as described on an UFSAR drawing.
Sections Hl.5 and E8.1 address this issue.
I. 0 rations t
Conduct of Operations 01.1 Unit Two Reactor Scram and Hain Steam Isolation Valve HSIV Closure a.
Ins ection Sco e
71707 93702 The resident inspectors observed and reviewed portions of the licensee's recovery actions, root cause investigation, and corrective actions associated with a Unit 2 reactor scram and HSIV closure.
b.
Observations and Findin s At 6:14 p.m.,
CDT on April 24, Unit 2 scrammed from 100 percent power.
The reactor scram was initiated by a turbine trip.
The turbine trip was caused by personnel error during surveillance testing involving reactor water high level instrumentation.
Immediately following the scram, an,
'unexpected Group I isolation occurred.
The inspectors responded to the site and observed control room (CR)
indications and verified that plant conditions were stable.
Discussions were held with some of the operators involved in the transient.
The initiating signal also tripped the three feedwater pumps and Control Room (CR) operators initiated Reactor Core Isolation Cooling (RCIC).
As preparations were being made to start, the High Pressure Coolant Injection (HPCI) system, reactor water level decreased to the actuation setpoint and HPCI automatically injected into the vessel.
Actions were completed as required by Abnormal Operating Procedures and Emergency Operating Procedures including: verification of control rod insertion and
0
~,
operation of the main steam relief valves (HSRVs). Information reviewed by the inspectors indicated that all other safety systems performed as expected.
The scram and HPCI injection were reported to the NRC operations center as required.
The licensee concluded that the HSRVs lifted within the TS setpoint range.
Information indicated that at least 11 of the 13 valves lifted on the initial pressure increase and peak pressure was just over 1100 psig.
Subsequently, in accordance with procedures, the operators opened one HSRV manually (operation of a CR switch)
and decreased pressure to about 815 psig.
Section Hl.3 of this report contains additional details involving the surveillance testing deficiency which initiated the turbine trip.
A Group I isolation was received and the Hain Steam Isolation Valves (HSIVs) shut.
As part of the Incident Investigation, the licensee investigated the cause of the Group I isolation.
During the transient, CR annunciators indicating high steam line flow had been received.
The inspector's discussions with the operators indicated that they had verified that a steam line break did not exist before they reopened the HSIVs.
After detailed review, the licensee, with the assistance of several General Electric (GE) engineer s, concluded that a high steam flow signal caused the HSIV closure.
Differential pressure is monitored across the steam line flow r estrictor s and actuates an isolation at high flow as protection in case of a main steam line break.
The setpoint is approximately 100 psid.
Review of instrumentation data indicated that the sensed differential pressure momentarily was high enough to actuate at least several of the switches.
The inspectors reviewed data which indicated that the main steam line high flow logic was actuated for only 20 milliseconds during the transient and reset within about 350 milliseconds of the scram signals The inspectors reviewed the UFSAR and noted that an HSIV closure is addressed in Section 14.5.
A turbine trip without turbine bypass operation is also described in Section 14.5.
The inspectors concluded that the scram and HSIV closure event was bounded by the analyzed transients in Chapter 14.
The inspectors reviewed a
GE evaluation dated April 26, 1997, which addressed the HSIV closure.
The evaluation described potential effects of pressure pulses or waves in the main steam lines, the lifting of several HSRVs, and turbine bypass valve cycling.
The evaluation stated that the combined effects of these events could have resulted in a short duration high steam flow being sensed at a main steam line flow ventur is.
The evaluation addressed the application of Service Information Letter (SIL) 463, Process Instrumentation Noise, to this iqcident.
This SIL addressed problems associated with high speed Rosemount main steam line differential pressure transmitters and instrument noise.
GE noted that Browns Ferry had previously installed
4l
capacitors to prevent such instrumentation noise effects.
The evaluation noted that the Browns Ferry transient apparently involved actual pressure wave effects on the differential pressure instrumentation, not just noise.
The licensee maintained Unit 2 in hot shutdown and performed some maintenance activities while continuing to review the incident.
One of the inspectors observed additional portions of the incident investigation and attended the restart Plant Operations Review Committee (PORC) meeting.
The inspector noted that the licensee addressed several equipment issues identified during recovery actions including a reactor water cleanup pump issue and a short delay in restoring the recirculation pumps due to a lockout signal that had to be reset.
At the PORC meeting, discussion was held regarding whether the incident was bounded by the UFSAR analyzed transients.
The licensee completed an evaluation of the safety implications of operating with the potential for an HSIV closure on a turbine trip.
Plant management also discussed that an increased sensitivity will be given to the operability of high pressure injection systems.
The licensee concluded that restart of Unit 2 was acceptable and additional review will be performed regarding the response time of the main steam line high flow instrumentation.
Conclusions The inspectors concluded that the licensee's review of the scram and the HSIV closure was thorough.
Control room operators responded well to the incident.
With the exception of the steam line flow instrumentation, safety equipment performed as required.
The high steam flow instrumentation issues require additional review.
Apparently the actual response time of the differential pressure instrumentation is much faster than values assumed in the design analysis.
The inspectors were not able to determine if Browns Ferry instrumentation response times are significantly different than other BWR facilities.
The GE evaluation stated that GE is not aware of a previous similar occurrence of an HSIV closure after a turbine trip.
The licensee clearly recognizes that inadvertent HSIV closure on a turbine trip is not desirable and intends to correct the problem.
Additional NRC review of this issue and the licensee's resolution will be necessary.
This issue is addressed as Inspection Followup Item 260/97-05-04, Spurious Hain Steam Isolation Valve Closure on Turbine Trip.
Unit Two Startu Ins ection Sco e
71707 The licensee restarted Unit 2 following the April 24, 1997, scram discussed in section 01.1.
The inspector observed portions of the Unit 2 startup from the control room on April 26-27, 199 b.
a.
b.
Observations and Findin s The inspector noted that the operators used procedures during the startup and were adequately focussed on issues which affected entry into Technical Specification Limiting Conditions for Operation.
Recir c Pum HG Set Baile Positioner Lock Not Reset In A Timel Hanner Ins ection Sco e
71707 The inspectors reviewed the licensees actions taken after a reactor feedwater pump (RFP) problem.and subsequent low reactor water level caused the reactor recirculation pumps to runback.
Observations and Findin s On April 1, 1997, Unit 3 experienced a reactor feedwater pump low flow (<20 percent),
and subsequent trip, and a low reactor water level (26.5 inches)
which caused the reactor recirculation pumps to receive a
runback signal.
Prior to the event, the 3B recirculation pump motor generator had the Bailey Positioner (scoop tube) electrically locked.
This lock was in place due to problems unrelated to the event.
The condition had been discussed during shift turnover.
The scoop tube lock invoked, procedural steps which required the Unit Operator to take manual action if the runback signal was received, by depressing the reset pushbutton in the control room to allow the 3B recirculation pump to runback.
During the event, the automatic runback did not occur on the 3B recirculation pump because the Bailey Positioner was locked.
It took approximately foul minutes for the Unit Operator to manually reset the scoop tube and allow the 3B recirculation pump to runback.
A subsequent discussion with the Operations Training Hanager verified that the expectation was for the operators to know what actions they need to take.
The licensee indicated that the required action to be
.taken by the operator in the event of a recirculation pump runback had been reviewed during the shift turnover meeting.
The inspectors concluded that it was expected that operators would verify automatic actions and take manual action if an automatic action did not occur.
Operating Instruction 3-0I-68, Reactor Recirculation System, Revision 9, section 8.8, Lock of Recirc Pump Bailey Positioner states that Recirc Pump runback (both pumps) will occur when any individual RFP flow is <20 percent and reactor water level <=27 inches.
It further states that if conditions are present that require a Recirc Pump runback, depress pushbutton, Scoop Tube 3A(3B) Reset, 3-HS-96-15(16),
on Recirc Pump with scoop-tube-lock and verify Recirc Pump runs back.
While the feedwater pump conditions were not clear ear ly in the incident, discussion with the involved operators and plant management indicated that the operators had noted that there was a runback signal present on the other recirculation pump and yet did not immediately reset the locked scoop tub il
,02 C.
Licensee management initiated a number of significant corrective actions, including incorporation of similar issues into simulator training.
At the close of the report period, the inspectors had not completed a detailed review of the licensee's corrective actions or examined their effectiveness.
Conclusions The failure of the CR operators to take prompt action to depress the Scoop Tube 3B Reset pushbutton when the automatic runback of the 3B recirculation pump did not occur, was a failure to follow Operating Instruction 3-0I-68, Reactor Recirculation System, Revision 9.
This is identified as Violation 50-296/97-05-01, Failure to Reset Locked Recirculation Pump Scoop Tube.
Operational Status of Facilities and Equipment 02.1 a.
b.
E ui ment Condition and Watchstandin Activities Ins ection Sco e
71707 The inspectors examined the condition of important plant equipment during tours of the plant.
One of the inspector s also observed the Unit 2 Reactor Building Assistant Unit Operator (AUO) during the performance of dayshift rounds.
Observations and Findin s On April 12, 1997, the inspector accompanied an Assistant Unit Operator (AUO) during day-shift rounds for the Unit 2 Reactor Building.
Overall, the AUO performed the routine in a thorough manner, contacting the appropriate groups such as radcon for assistance when needed.
Nearly every accessible area of the reactor building was visited.
The AUO was knowledgeable of the numerous oil leaks in the area of the recirculation
~ pump motor generator sets and indicated that a recent review of the work requests identified that many of the leaks were scheduled for the Unit 2 refueling outage.
During the tour, the inspector observed that the Residual Heat Removal (RHR) Heat Exchanger B&D Service Water (SW) Radiation Honitor was in service.
Upon discussion with the licensee, the licensee determined that the pump had been operated the previous night and should have automatically stopped.
The licensee initiated work request C348988 to address this problem.
On April 26, 1997, one of the inspectors noted a fuel oil and steam leak was present on the front of an operating auxiliary boiler.
A bucket had been placed under the leak to contain the fuel and water mixture that was dripping from piping.
The AUO stationed at the auxiliary boiler stated that the leak had been present for some 'time and a Work Request (WR) had been initiated.
Subsequently, it was determined 'that the AUO was mistaken and no open WR existed for the leak.
A WR was initiate C.
The inspector noted that a
PER was not generated to address the issue of why a WR had not been initiated on a significant material prbblem.
On April 30, 1997, one of the inspectors observed that the air cooling return screens, on the B3 Essential Equipment Cooling Water (EECW)
pump motor was substantially clogged by a grease and dust mixture.
The inspector reviewed control room indications and noted that the motor temperatures were not approaching alarm conditions.
The condition was reported to maintenance and WR C384918 was initiated to clean the screens and inspect/clean. the screens on the other EECW pump motors.
Section M1.1 of this report describes maintenance that was performed on the B3 EECW pump several days before the screens were found dirty..
The motor had been returned to service with the dirty screens.
Cleaning of the motor screens is a preventive maintenance task which is scheduled for every 18 months and was due on the B3 motor in July 1997.
During a routine tour on April 11, 1997, one of the inspectors noted that water was present just under grating at the floor level in the Unit 3 emergency diesel generator building.
The inspector determined that the building flood prevention check valve pit was full of water.
Water had filled up the drain line and caused the water to be present just below the floor grating inside the building.
Section E2.1 addresses this issue in more detail.
Conclusions The inspectors noted several examples where AUOs did not question conditions or pursue resolution adequately.
Similar observations have been noted in previous inspection reports.
During the final week of this inspection report period, the licensee revised work assignments for the AUOs.
Equipment area AUOs are now designated as "support" or
"rounds" AUOs.
Rounds AUOs. are specifically tasked with performing detailed tours and logging plant parameter s. Support AUOs perform assigned tasks and respond to control room operator requests.
This rearrangement is intended to reduce interruptions of AUOs while on 'plant tours and is expected to improve the effectiveness of the rounds.
II. Maintenance M1 Conduct of Maintenance.
M1.1 Residual Heat Removal Service Water RHRSW Pum B3 Packin Installation and Im eller Reali nment a.
Ins ection Sco e
62707 The inspectors observed performance of packing gland packing replacement and impeller realignment on the B3 RHRSW pump.
In accordance with IP62707, the inspectors also performed a field review of the B3 RHRSW pump maintenance procedure, work order (WO) 97-003942-000, and the associated work packag il ll
Observations and Findin s On April 24, 1997, the inspector observed scheduled corrective maintenance activities being performed on the B3 RHRSW pump.
These included pump gland r epacking, vertical realignment of the impeller, and motor-to-pump coupling adjustment.
These activities were to be performed in accordance with Work Order (WO) 97-003942-000 and selected portions of,procedure HCI-0-023-PHP002, RHRSW Pump Disassembly, Inspection, Rework and Reassembly, Revision 26.
During field review of job documentation, the inspector noted that pump packing installation was to be performed in accordance with HCI-0-023-PHP002, Steps 7.4.60 thru 7.4.62.
and pump coupling eccentricity measurement was to be performed in accordance with Step 7.4.59.9.
Step 7.4.59.9 referenced procedure Attachment 4.
The inspector noted that pages 99 and 110 (of 110 pages)
were missing from this procedure.
The worker s had not yet completed this portion of the procedure.
With page 99 missing, Steps,7.4.60.1 through 7.4.60.2 (and associated NOTES which detail packing installation techniques)
were missing from the procedure.
With page 110 (Attachment 4) missing, a necessary drawing (used for locating a dial indicator mounting point for coupling eccentricity measurement)
was also unavailable.
The inspector could not find the missing pages in the work package.
The inspector pointed out the discrepancies to the job site foreman.
These discrepancies were immediately corrected and the maintenance activity was completed in a satisfactory manner.
Conclusions The inspector noted that job foreman actions to immediately address and
.correct the discrepancies was adequate.
The inspector also noted that the pump repacking and realignment work was subsequently performed in a satisfactory manner.
Coolin Tower One Substation 1D 480VAC Feeder Breaker Preventive Haintenance Ins ection Sco e
71707 The inspectors observed performance of preventive maintenance performed on the gl Cooling Tower (C/T) Substation 1D 480VAC Feeder Breaker.
The inspectors also reviewed the associated preventive maintenance procedure, the work order (WO) 96-009317-000, and work package.
Observations and Findin s On April 11, 1997, the inspectors observed scheduled preventive maintenance activities being performed on the gl C/T Substation 1D 480VAC Feeder Breaker.
The inspectors noted that activities were performed in accordance with WO 96-009317-000 and applicable portions of maintenance procedure EPI-O-OOO-BKR007, GE-Type AK-50 Circuit Breakers and Switchgear Haintenanc il
C.
H1.3 a.
b.
During field review of job documentation, the inspectors noted that a
iece of Haintenance and Test Equipment (HSTE)
(ohmmeter f891581)
was eing used during the maintenance; however, this piece of test equipment was not listed in the maintenance procedure or the WO as the H8TE 'being used for the work.
The workers told the inspector that they had intended to add all required H8TE numbers and additional worker signatures in the appropriate places of the WO after they r einstalled the breaker.
The inspector noted that the.
WO allowed for out-of-sequence performance of the WO steps by skilled craft personnel.
As art. of the preparation to perform the work; HSTE numbers are to be isted in the maintenance procedure.
After discussion with the workers and the job foreman, the equipment was recorded.
Conclusions The inspector noted that the workers promptly addressed the logging of HTSE issue.
The breaker condition appeared to be good and,preventive maintenance of the breaker's moving parts was performed satisfactorily.
Unit Two Scram Due to Personnel Error Durin Surveillance Testin Ins ection Sco e
61726 62707 92902 Section 01.1 of this report descr,ibes review of a Unit 2 reactor scram which occurred due to an error during the performance of a surveillance test.
The inspectors reviewed the applicable surveillance procedure and related documentation, inspected the equipment conditions present at the job location, and discussed the incident with Instrument Haintenance (IH) workers and management.
Observations and Findin s During the performance of Section 7.17 of procedure 2-SI-4.2.B-ATU(C)
Core and.Containment Cooling Systems Analog Trip Unit Functional Test,
'an inadvertent reactor water high level turbine trip and loss of main feedwater pumps was actuated.
IH technicians were performing the section of the test associated with the
"C" channel of water level instrumentation in the auxi.liary instrument room.
As part of the test, a meter is connected to a relay to verify the contacts change state when the analog trip unit is tripped by a test signal.
A signal is dialed in on a calibration module located on the front of the instrument panel.
The technicians incorrectly connected a Volt-Ohm-Heter (VOH) across contacts for the relay associated with the "A" channel.
The involved relays are Agastat relays accessed through the back of the instrument cabinet.
When the
"C" channel was subsequently tripped by the testing, effectively both the "A" and the "C" relay contacts were.closed and a. turbine trip signal was generated.
The inspectors observed that the "A" and
"C" relays are cl.early marked on the top of the rela'ys and are located next to each other.
Access to the meter plug-in.points was difficult since the relays are very close to the floor and the plug-in points are beneath
il il
the relay.
Apparently, the second party verification and self checking was performed on the correct relay but as the technicians bent down to plug in the meter 1'eads, eye contact was lost with the correct relay.
Verification of the correct relay was not properly performed again before the leads were plugged in.
Conclusions The inspectors concluded that the licensee's investigation into the event had identified the appropriate issues.
Some of the causal factors
. involved in this incident appear very similar to those involved in an April 14 incident in which a CR operator started the 3D emergency diesel generator rather than the 3C. In both cases, workers lost eye contact with the involved equipment and failed. to perform adequate self checking prior to further. actions.
This incident had more adverse impact on safety systems due to the safety system challenges caused by the scram.
Additionally, as discussed in Section N1.4 of this report, two Unit 3 High Pressure Coolant System steam line valves were inadvertently shut on April 10 during a surveillance test.
The failure to comply with procedures which resulted in a reactor scram is identified as the first example of Violation 260,296/97-05-02, Failures to Implement Maintenance Procedures.
Hi h Pressure Coolant In ection HPCI Isolation Durin Surveillance T~estin Ins ection Sco e
61726 92902
. 40500 On April 10, 1997, during surveillance testing of the Unit 3 High Pressure Coolant, Injection (HPCI) system low steam line pressure switches, the HPCI steam supply valves were inadvertently shut.
The inspectors reviewed the surveillance procedure and related documentation, observed some review associated with. a Volt-Ohm-Heter (VON),, discussed the incident with. Instrument Haintenance supervision,
~ and reviewed the licensee's Incident Investigation report.
Observations and Findin s On April 10, 1997, at approximately 1:04 am CDT, a Unit 3 Control Room (CR) operator identified that the HPCI steam line isolation valves were shut.
3-SI-4.2.8-38FT, HPCI System Steam Supply Low Pressure Functional Test, was in progress.
The surveillance includes verification of the functioning of four pressure switches (3-PS-73-1A,-18,-1C and-1D) and relays necessary to actuate an isolation of the HPCI system on low steam line pressure.
IH workers had completed the 3-PS-73-1A and 3-PS-073-18 portions of'he testing and were proceeding to testing of'he 3-PS-073-1C switch when the problem was noted.
The testing was stopped, the valves were reopened and the incident was reported to the NRC Operations Center.
as required.
Other safety systems were operable and no limiting conditions for operability were exceede Problem Evaluation Report (PER)
970666 was initiated and an Incident Investigation (II) team reviewed the issues.
Subsequent review indicated that a HPCI isolation trip signal had closed valves 3-FCV-73-2 and 3-FCV-73-3 approximately five minutes before the operator had noted the problem.
One of the inspectors monitored progress of the investigation through discussions with team members and the leader.
After detailed review of the incident including walkthroughs of the surveillance procedure, diagnostic testing of the involved c'ircuitry and interviews of the workers, the II team concluded that the incident was the result of the workers inadvertently causing the pressure switch logic to be shorted during the testing.
The team concluded that the problem occurred during testing of the 3-PS-073-1A switch.
The investigation concluded that self-checking and second party verification was not properly performed during the testing.
The II team noted that the testing was being performed at a fast pace when compared to other performances of the same testing (about 2-3 minutes per switch instead of 6-7 minutes).
The investigation identitied that the VOH used during the surveillance had a blown fuse which caused it to not properly function when being used for resistance checks in greater than the X1 range.
One of the inspectors observed some of the testing associated with the Volt-Ohm-Heter (VOH) issues involved in this event and discussed the issues with IH supervision.
This condition also affected voltage reading operations with the VOH.
As part of the testing, voltage readings were to be obtained.
These readings were not valid due to the condition of the meter.
The workers performing the testing were aware that the VOH did not function in a resistance range greater than Xl before they began the wor k, but did not understand all of the effects.
The malfunctioning VOH did not directly cause the event.
Information indicated that some IH workers were not aware that the impedance of the meter was such that the VOH would provide a current bypath in such conditions as seen during this testing.
(Even if the VOH was functioning properly.)
The inspectors concluded that this lack of awareness may have been a factor in the speed in which the workers were conducting the testing.
The inspectors have observed that worker s are usually cautious when performing activities in which it is clearly under stood that an error may result in a scram or safety system actuation.
Corrective actions listed in the PER addressed most of the VOH issues, IH second party verification problems, and included recommendations for improvement of'he surveillance testing method for HPCI and Reactor Core Isolation Cooling (RCIC) testing.
A Haintenance Safety Notice was issued on April 11, 1997, addressing the VOH issues.
Briefings were given to other onsite work groups to increase awareness of the self-checking and second party verification issue i
C.
H1.5 a.
b.
Conclusions The inspectors.concluded that the licensee's investigation into the event was thorough and identified all 'pertinent issues.
Identification of the closed HPCI steam line valves by the CR operator was timely considering no alarm was received when the valves were closed.
This indicated that CR operators are performing sufficiently detailed control board reviews.
This event involved significant deficiencies in work practices by the involved technicians.
Over the last two years, with the exception of the scram discussed in Section M1.3 of this report, there have not been any inadvertent engineered safety feature actuations due to IH work practice deficiencies.
However, in recent months there have been several incidents at Browns Ferry in which important plant equipment was affected because of deficient second party or self checking practices.
This issue is identified as the second example of Violation 260,296/97-05-02, Failures to Implement Maintenance Procedures.
Post Modification Testin of Seismic Honitorin Instrumentation Ins ection Sco e
61726 62707 71707 As required by Inspection Procedure 71707, the inspector observed portions of the testing of seismic monitoring accelerograph O-ACGR-52-5.
The accelerograph had been replaced with an upgraded model through Design Change Notice (DCN) T28024A.
The procedure and observed work practices were reviewed using the guidance in Inspection Procedures 61726 and 62707.
The inspector reviewed surveillance instruction O-SI-4.2.J.lC(B),
Seismic Monitoring Triaxial Time His'tory Accelerograph (0-ACGR-52-5) Calibration and observed portions of the functional testing.
Observations and Findin s The inspector reviewed the DCN package and verified that the replacement accelerograph would meet basic criteria specified in TS Table 3.2.J and the UFSAR.
The inspector noted that a Change Request to Licensing Document (CRLD) had been processed to revise the UFSAR Sections 2.5.5.1-3.
The new instrument is a solid state device and a personal computer is used to access the stored data instead of tape storage as was previously used.
The DCN also added the capability for a control room annunciator to actuate if power to the instrument's battery charger is lost.
A safety assessment for the DCN had been completed.
The inspector verified that the control room Alarm Response Procedures were correctly revised prior to the instrumentation being declared operable.
The overall conduct of the observed functional testing was good.
The surveillance instruction was being used for the first time to test the new instrumentation and as such was considered a validation procedure.
The workers involved with the testing had been trained on the new instrumentation and were reasonably familiar with details of its
4I~
ik
operation.
The prebriefing with operations personnel was conducted well.
The inspector speci,fically noted that second party verification was implemented in accordance with procedures and the workers were careful regarding equipment identification.
Orange tape was used to
"mark" components during the work as directed by management as a
corrective action for the recent personnel performance issues.
The workers stopped. testing and asked for additional guidance from engineering when questions or difficulties surfaced.
Three issues were noted during. the review:
~
Numerous problems with the procedure were encountered during the testing.
The inspector observed that the workers recorded most of the issues as "validation comments" for correction.
It appeared to the inspector that a more thorough "walk through" review of the procedure would have identified some of the issues.
The validation edition of this test procedure seemed to be a "trial" rocedure.
In some areas, significant revision will be necessary efore the test procedure is adequate.
IH management placed the procedure on administrative hold due to the discrepancies.
~
Surveillance Instruction O-SI-4.2.J.1C(B)
was also being performed as post modification testing (PHT) for the DCN.
The inspector identified that surveillance instruction O-SI-4.2.J.1C(B)
would not have specifically tested the ability of the loss of power annunciator to actuate as designed.
An Urgent Intent Change (UIC)
was completed which revised the test procedure.
The inspector noted that if the test had been conducted without the UIC, the alarm would have actuated, potentially alerting the operator to the procedure problem.
~
The inspector noted that the clear ance between the top of the wire cage enclosure and the lid of the accelerograph as it was being removed, was not very large.
Upon additional review, the inspector identified that the dimensions of the enclosure did, not match a note cont'ained on UFSAR figure 2.5-17.
The note stated that the enclosure will be 30 inches high.
The enclosure was only 18 inches high.
This was reported to engineering and licensing personnel and a
PER was initiated.
(Section E8.1 addresses this UFSAR discrepancy).
c.
Conclusions The observed testing indicated that the accelerograph was operating satisfactorily.
The IH workers involved in the testing were cautious and performed second party verification in accordance with procedures.
The portion of the post maintenance testing intended to test the loss of power alarm was not well written.
A discrepancy between plant equipment and the UFSAR was identified.
The number of procedural problems was high and it appeared that the validation process was being used to develop the procedure in some areas rather than as an enhancemen ~
~
0
Conduct of FIN Team Maintenance Ins ection Sco e
62707 The inspectors reviewed numerous Work Orders (WOs) assigned to a Fix-It-Now (FIN) crew using the licensee's E-HPAC maintenance tracking computer system.
The inspector specifically selected work involving Emergency Diesel Generators for this review.
Observations and Findin s The inspectors reviewed numerous WOs assigned to a FIN crew using the licensee's E-HPAC maintenance tracking computer system.
The inspector specifically selected work involving Emergency Diesel Generators for this review.
Several of the WOs did not specify personnel qualifications or training required for the work.
SSP-6.2, Haintenance Management System, Revision 24, section 3.3, General Planning Requirements for WOs, Subsection 3.3.2, General Planning Guidelines, states for the planner to review the training task listing to determine the applicable task for the work to be performed.
All applicable tasks should be listed on Appendix D (even if planned as skill of the craft)
as an aid to assist the Foreman in work assignments.
The inspector determined that the WOs which had not specified personnel qualifications or training requirements were performed using.the minor maintenance or toolpouch processes.
The inspector determined that the work had been completed and the work activities were documented on the work request card.
Wos were subsequently filled out to document a
history of the work.
Site Standard Practice (SSP)
procedure SSP-6.2, Maintenance Management System, Appendix U, Implementing Minor Maintenance, describes this process.
During an interview with the FIN team Instrument Maintenance (IH)
Foreman, the inspectors discussed how the Foreman decided if the work could be done within the scope of the FIN team and his resources.
The preplanning included determining the safety significance of the component being worked, review of applicable procedures, evaluating for Operations support, and cr aft skills.
The Foreman would discuss what would be necessary to do the job with the Shift Support Supervisor, Unit Supervisor, or Shift Manager.
A decision would then be made to either complete the work as minor maintenance or send the Work Request to planning for the IH shop'to work.
An inter view with the FIN team Mechanical Maintenance (HH) Foreman indicated that currently all work that is done on the Emergency Diesel Generators is planned through HH planning prior to being worked by the HH FIN team.
This was consistent with actions taken during a FIN team screening meeting that was observed on April 30, 1997.
The inspector noted that the FIN team General Foreman sent a work order (to add oil to an EDG) to HM planning; it was not accepted as a FIN team minor maintenance work activity prior to planning.
The Foreman also indicated that.his crew of three assigned technicians had one individual who was
qualified on all of the EDG Task Codes and another individual which was trained to some of the EDG Task Codes.
The inspector reviewed training records and found that one individual was trained on five of the six Mechanical Maintenance EDG Task Codes.
The Task Code that the individual was not trained to was HHJ 504: Assemble/Disassemble Emergency Diesel Engine (Power Pak).
The inspector concluded that this complex task would clearly not be assigned to the FIN team as minor maintenance.
SSP-6.1, Conduct of Maintenance, Revision 5, Section 3.4.5, Control of Related Activities, states that safety-related maintenance work can be considered to be within the ski11s of the craft and performed without a procedure if the appropriate Haintenance Organization supervisor evaluates and approves the maintenance in accordance with SSP-6.2.
SSP-6.2 Section 3.7, Work Order Review and Approval Prior to Implementation, Subsection 3.7.1 under Foreman/Designee responsibilities, states that personnel shall not be assigned to work independently who are not trained and qualified for the assigned tasks.
The procedure also states that the Foreman identify all required task(s)
for the work activities to be performed by using Appendix D, personal knowledge of the work, and/or tasks lists from the Nuclear Employee Training Periodic.
The inspectors concluded that the Foremen who were interviewed were knowledgeable of their responsibilities to determine the qualifications of their workers prior to assigning work.
Conclusions The inspectors review concluded that the process implemented by the licensee to perform minor maintenance using the FIN team was adequate to expect that qualifications of worker s would be assessed prior to assigning work activities.
Procedurally, the responsibility lies with the General Foreman to determine skill of the craft activities and with the Foreman to determine the qualifications of his workers and their
~ ability to perform the task.
Based upon the interviews with the Foremen, the inspectors concluded that they are knowledgeable of their responsibilities to determine the qualifications of their workers prior to assigning work.
Maintenance and Material Condition of Facilities and Equipment Ultrasonic Examination of Unit 3 Torus for Thickness Ins ection Sco e
57080 Effective September 9,
1996, 10 CFR 50.55a was modified to include the requirements of the 1992 edition with the winter 1992 addenda of Subsections IWE and IWL of Section XI, Division 1 of the American Society of Mechanical Engineers (ASHE) Boiler and Pressure Vessel (B&PV)
Code for the inspection of'ontainment structures.
This rule
change carries with it an examination implementation date of'eptember 9, 2001.
However, licensees were expected to implement the requirements of IWE and IWL for all repair and replacement activities conducted after the implementation date of September 9,
1996.
In preparation for the inspection, Subsection IWE of Section XI to the ASME Code, and Section 5.2 of the Browns Ferry FSAR were reviewed in detail.
On April 24 8 25, 1997, an independent ultrasonic examination of shell plates was conducted by.NRC to determine the general structural condition of the Unit 3 Torus.
Each plate in eight of sixteen torus bays were examined from the bottom center line to sixteen feet up each side of the torus.
A total of 240, 12mx 12" inspection sites were scanned to determine the inside surface condition and minimum remaining plate thickness.
Also included in selection of'ample sites were critical points where the torus structure attaches to building supports.
Observations and Findin s Pittsburgh-Des Moines Steel Company fabrication Drawings No.
E3 and E4 were used to determine the nominal plate thickness of the suppression chamber (Torus) plates.
Two ultrasonic (UT) instruments were provided by the licensee to perform these examinations, as well as one Level III Nondestructive examination (NDE) examiner to record the ultrasonic readings, and a Level II NDE examiner to record paint thicknesses on the outside surface of the torus.
All UT readings were taken by the NRC inspector.
The initial UT readings included the paint thickness on both the inside and outside surfaces of the torus.
The painted surface on the outside of the torus where the minimum UT reading was taken was then read with a paint gage.
The gage reading as well as
.015" for the paint on the inside surface was subtracted from the UT reading.
Fifteen mils was chosen for the thickness of the paint on the inside surface because TVA's Procedure No. N1A-930, Appendix A, for special protective coatings required three coats of paint on the.torus with a dry film thickness of 3-5 mils each.
The nominal plate thickness for the torus was.750".
~The minimum UT reading, less the paint, obtained in each bay is delineated below:
~Ba No.
No. of Ins ection Sites Minimum UT Readin Less Paint
3
7
11
15
27
27
32
32
.743"
.736"
.731m
.730"
.730"
.734"
.720"
.734" The average minimum reading for all 240 inspection sites, less the paint, was.739".
The lowest reading obtained on the torus was.720".
Although the average minimum readings in each of the suppression chamber bays were below the.750" nominal plate thickness, the 1992 edition of
ili II
C.
H2.2 a.
b.
Section XI to the ASHE Code, Paragraph IWE-3122.1, Entitled: Acceptance by Examination, states that components whose examination resQlts meet the acceptance standards listed in Table IWE-2500-1 shall be. acceptable.
Table IWE-.2500-1, Examination Category E-C, Item No. E4.12 lists Paragraph IWE-3512.3 as the acceptance standard for volumetric examination.
Paragraph IWE-3512.3, Enti'tied: Ultrasonic Examination, only required containment vessel examinations which reveal material loss exceeding 104 of nominal plate thickness to be documented and evaluated.
Paragraph IWE-3430, Entitled:
Acceptability, also states that,
"Flaws or areas of degradation that do not exceed the allowable acceptance standards of IWE-3500 for the respective examination category shall be acceptabl.e.
As noted above, the minimum UT readings obtained by the inspector were thicker than the 10'.675") reduction allowed by the Code.
Conclusion Ultrasonic examinations performed on the Unit 3 torus revealed plate readings below nominal thickness but acceptable in accordance with Section XI of the ASHE Code.
The inside surface condition of the torus as revealed by volumetric examination was very good.
Condition of Torus Coatin s
Ins ection Sco e
As part of an April 29-30, 1997, Division of Reactor, Safety (DRS)
-inspection, a site resident inspector and a visiting DRS inspector performed various inspections of the Unit 2 and Unit 3 suppression chamber (torus) coatings.
Observations and Findin s During the inspection period; the site and visiting inspectors walked adown various external areas of the Unit 2 torus and the Unit 3 torus.
They noted that external coatings were very sound and they found no evidence of coating delamination on either the torus support weldments or torus surface areas.
Torus supports and surfaces were coated with adequate layers of primer paint and primer paint adhesion to torus metal surfaces appeared very good.
No evidence of'eeling was observed.
Painted areas on various weld joints (both surface area weld joints and support joint weldments)
appeared quite sound.
Observed torus coating conditions presented evidence that the torus sur'face preparation prior to application of paint and primer had been thoroug O~
MS. 1 a.
b.
Miscellaneous Maintenance Issues (62707, 92902)
Removal of Unit 2 Feedwater Heater Level Control Valve Seats and Gaskets Ins ection Sco e
62707 The inspectors reviewed the corrective actions associated with Problem Evaluation Reports (PERs) which addressed potential deficiencies involving valve asbestos gasket and seat removal activities (BFPER961672 and BFPER961675).
In accordance with guidance in IP92902, the inspectors also inter viewed valve refurbishment workers and examined documentation to verify conformance with procedures.
Observations and Findin s On December 3,
1996, workers were tasked with removal of valve flange gaskets and seats from various Unit 2 (LCV-006 Series)
feedwater heater level control valves.
The valves had been removed from the Unit 2 heater drain system and were stored in a radiologically controlled area of the licensee's Low Level Radwaste (LLRW) Warehouse.
These valves were being reworked for Unit 3 use under Work Plan (WP),gW26519-029.
After interviews with the valve refurbishment workers and job foreman, the inspectors noted that the initial refurbishment (removal of the original valve actuators and valve bushings)
had been performed in April and Hay 1996.
The remaining activities, valve seat removal and body and valve flange clean-up, continued in December 1996.
The inspectors reviewed plant modification WP gW26519-029.
Step 17, asbestos removal, stated that asbestos was to be removed per Site Standard Practice SSP-1.5, Administering the Nuclear Power Safety and Health Manual, and the licensee's Nuclear Power Safety and Health Manual (NPSSHH).
Step 17 of the WP also contained a "yes/no" question on whether asbestos removal was required.
On August 23, 1996, during WP evaluations performed by supervisory personnel, the "no" block was
~ checked.
Since
"no" had been checked, procedural controls regarding asbestos were not followed.
The workers used scrappers, grinders and wire wheels to remove the valve flange gaskets rather than cutting away the old gasket material as prescribed in NPSEHH,Section VI, Part VI-G.
The worker s did not wear protective masks/respirators and coveralls while removing the gaskets and extracting the old valve seats and bushings.
On December 5, 1996, the workers questioned their management on whether the gaskets might have contained asbestos.
In response, the licensee stopped further valve refurbishment work, sampled the refurbishment area, and checked valve internal and external areas for indications of'sbestos.
A contracted environmental sampling group's testing revealed the following:
~. Asbestos, approximately 80'f it Chrysolite, was found in residue from four flange gaskets which had not been completely remove ~ Air samples taken two days after the original gasket removal activity indicated no airborne asbestos.
~
Samples taken indicated that a small amount of asbestos (at and below OSHA prescribed minimums)
had been released.
~
Five samples of floor residue indicated that asbestos levels (listed as a percentage of total material) were very small (0 to 2 percent).
Five workers with a potential of asbestos exposure were given lung exams and internal exposures were found to be very low (less than OSHA planned exposure levels).
No evidence of significant asbestos inhalation was detected.
On January 13, 1997, an "Asbestos Material Lessons Learned" memorandum was issued to all contract laborers, foremen, supervisors, and other management personnel.
The memorandum:
~
Discussed specifics of the above incident and emphasized immediate contact with the site Asbestos Abatement Group prior to performance of any work involving asbestos material.
~
Stressed that if anyone was unsure of whether asbestos was present, they were. to contact the abatement contractor for determinations.
~
Emphasized that recommended methods of asbestos removal should be used whenever possible.
~
'Reminded managers/supervisors that newly-hired workers were to attend Asbestos Abatement Awareness classes during their job orientation.
In subsequent inspector interviews, the workers also questioned the thoroughness of pre-job briefs performed prior to the gasket removals and the valve seat replacements.
They stated that the pre-job briefs
.failed to adequately address work performed on equipment or components containing asbestos or contaminated material.
On January 31, 1997, a Modifications Management Directive (MND $1) Pre-Work Briefings for Work Orders, was revised in order to heighten worker awareness of potential asbestos hazards in some of the site jobs.
The inspectors noted that the licensee's maintenance group subsequently issued stronger guidance on future work order preparations involving gasket removal.
Future work orders are to contain requirements for ascertaining asbestos in gaskets.
Also, a validation of such a
determination (by work order signature) is to be made by maintenance supervisory personnel.
In. April. 1996, when the feedwater heater level control valves were first savored in the LLRW Warehouse area, they were initially labeled
"Radiological Material" because they contained low-level fixed contamination.
Although RADCON personnel told the workers that valve
actuator repairs (the removal. of valve actuator assemblies located on the valve externals)
could be performed, the workers were informed that no internal work or "surface disturbing activities" (grinding, welding or other hot work) were to be performed.
In meetings with the foreman and the worker s, the inspector was informed that in April/Hay 1996, grinding of bushing tack welds (an activity which is executed on the inside.of the valves)
was performed to extract the old valve bushings.
This activity was contrary to the directions provided by RADCON.
In order to resume refurbishment activities (the removal of the valve seats),
on December 3,
1996, the foreman contacted the RADCON Shift Coordinator.
The job foreman told the coordinator that a survey had already been performed.
The inspectors later noted that a survey (which indicated no loose contamination inside the valve)
had been performed; however, this survey was performed prior to initiation of valve seat removal activities.
The coordinator, without additional review of.
appropriate data and without ordering a more representative, up-to-date, survey, approved continuation of valve refurbishment activities.
The coordinator based his approval on what the job foreman had told him about the earlier survey.
This action was contrary to procedure RCI-1, Steps 6.5.1 and 6.5.2, which require up-to-date sampling in order to determine the latest radiological conditions in the job area.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation (NCV), consistent with Section VII.B.1 of NRC Enforcement Policy.
During interviews with the job foreman, the inspector questioned the foreman's assertion that radiological conditions would have remained unchanged during valve seat replacement work.
The foreman indicated that since radiological concerns were not presented during the earlier performed, Spring 1996, valve bushing removals and since seat extraction activities were similar to bushing removals (both required grinding of internal tack welds),
he felt that it was highly unlikely that any problems would be presented during seat removals.
On December 5,
1996, the workers questioned their management on whether the valves may have contained loose contamination because of their work on,the valve internals.
On December 7, 1996, RADCON personnel performed surveys of the immediate valve body and general work areas.
They also sampled the refurbishment tools, craft gloves, and surrounding work area equipment.
The surveys and the licensee's follow-up investigation of the incident indicated the following:
~
Loose surface contamination levels up to 10,000 dpm/100 cm'ere found on the internal surfaces of the valves; near the valve seats.
~
Loose surface contamination had not spread to the general work area, the tools, the gloves or on nearby equipment.
~. Although the control valves were enclosed in the warehouse and inside a designated RCA, they were not within a boundaries specifically designated as contaminated area As a precaution, worker bioassays were taken and were found to be negative.
The valve refurbishment area was immediately designated as a
contaminated area and all rework activities were suspended until licensee recommended corrective actions were implemented.
A licensee investigation of the incident determined "inattention to detail" and "failure to apply licensee designed self-checking principles" as causes of the incident.
The following additional corrective actions were immediately implemented:
~
The valves were removed from the LLRW warehouse to a designated contaminated area in the Unit 3 turbine building.
~
Disciplinary action was taken in accordance with administrative procedures and licensee guidelines.
~
The licensee emphasized to the Jefurbishment crew, the importance of adhering to WP details and licensee-approved procedures.
They also emphasized the importance of applying self-checking principles.
~
The licensee clarified "scope of work" guidance and they placed greater restrictions on work being performed on potentially contaminated equipment.
Conclusions The inspectors concluded that this incident involved poor implementation of licensee controls intended to reduce the possibility of employee exposures to asbestos and radioactive contamination.
The inspectors concluded that inadequate implementation of radiological controls procedures occurred during this incident.
The licensee attributed the procedural noncompliances to poor performance by the RADCON shift coordinator.
After a detailed review, the inspectors concluded that this was a reasonable conclusion.
The inspectors concluded that the
~ licensee's corrective actions for both of the issues was adequate.
This licensee-identified and corrected violation is being treated as a Non-Cited Violation (NCV), consistent wi'th Section VII.B.1 of NRC Enforcement Policy (50-260,296/97-05-03, Fai.lure to Obtain Radiological Control Surveys)
~
III. En ineerin Engineering Support of Facilities and Equipment Emer enc Diesel Generator Buildin Flood Prevention Check Valves Ins ection Sco e
37551 40500 On April 11, 1997, one of the inspectors identified that the emergency diesel generator (EDG) building flood prevention check valves did not appear to be operating correctly'.
The building flood prevention check
Oi ll
valve pit was full of water.
Water had filled up the drain line and caused the water to be present just below the floor grating inside the building.
The inspectors monitored the licensee's immediate corrective actions, and reviewed the significance of the issue to verify that no potential EDG operability concerns were present.
b.
Observations and Findin s As described in Inspection Report 94-20, the EDG flood prevention valve are intended to drain water out of the building in case of a service water line leak and shut against high external water level (river flooding of the yard).
Subsequent testing of the flood prevention valves identified that one of the valves (0-CKV-40-519) was stuck in a not fully.closed position.
This was allowing the water in the pit to
'ravel up the drain pipe and be visible inside the building.
The other valve was operating correctly.
Simi.lar conditions associated with the same equipment had been identified and reviewed by the NRC inspectors in 1994.
In 1988, the licensee had identified similar conditions.
Paragraph 6.a of Inspection Report 94-20 contains a.detailed discussion of the operation of these valves.
Problem Evaluation Report (PER)
970740 was initiated on April 22 to address the latest issue.
Corrective actions f'r previous PERs included cleaning of'.the pits and establishment of a preventive maintenance program on the valves.
Corrective actions initiated due to the latest valve failure were as follows:
~
Water was pumped out of the valve pit and the trash (soda cans,
.papers)
was removed.
~
The valve disc was freed from its stuck position,. inspected, and cleaned.
The valve was left in a functional condition.
~ It was noted that the pit for the O-CKV.-040-519 valve was not draining as well as the other pit. Silt and mud in the pit was removed and some of the crushed stone in the pit was replaced.
~
System engineering monitored the water level in the pit and confirmed that it was draining adequately.
The inspector was informed that the engineers had also identified that significant quantities of water were sometimes added to the 519 pit as a result of fire protection testing of equipment.
The inspector was informed that the testing would, be revised to reduce the quantity of water added to the pit.
~
The most recent issues indicate that the preventive maintenance frequency may not have been sufficient to prevent valve failure. The
.frequency of the preventive maintenance will be increased to yearl ggi il'l
C.
E2.2 a.
b.
Conclusions The inspectors
.reviewed Technical Operability Evaluation 0-94-040-0337 which addressed the earlier problem and concluded that the justification and conclusions remained valid for this case.
Established alarm response procedures address EDG building flooding.
All information indicates that the other Unit 3 flood check valve was operable.
After review of the issues.
the inspectors concluded that the stuck 519 valve, while not a desirable condition, did not represent a significant condition adverse to quality.
The inspectors conc'luded that the licensee had not effectively addressed previous valve problems.
At the close of the inspection period, the licensee was reviewing alternatives for additional corrective actions.,
Reactor Core Isolation Coolin RCIC Testin and Troubleshootin Ins ection Sco e
37551 62707 61726 The inspectors observed some of the testing, troubleshooting, and corrective maintenance associated with a Reactor Core Isolation Cooling (RCIC) maintenance inoperability period.
Observations and Findin s At 7:55 p.m.,
CDT on April 29, 1997, the Unit 2 RCIC system was removed from service to perform planned preventive and corrective maintenance activities.
A 7-day limiting condition for operation (LCO). was entered.
The activities were scheduled and planned in detail.
A fr agnet was developed on the activities.
Several of the planned activities involved work on the 2-FCV-71-10, the RCIC governor throttle valve.
This included replacement of valve stem materials with Inconel to improve system reliability (corrosion materials had caused the failure of similar turbines at other facilities).
In August 1996, the Unit 2 RCIC
~experienced flow control oscillations due to problems with -the 71-10 valve.
Details of the 71-10 material issue is discussed in Section H2.2 of.Inspection Report 96-08.
Additional corrective maintenance was scheduled to be performed during the RCIC inoperability period which was scheduled to last about 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
On the evening of Hay 1, 1997, one of the inspectors observed post maintenance testing of the RCIC system in accordance with Operating Instruction OI-71, RCIC Operation.
The inspector noted that the pre-briefing for the evolution was not very detailed.
The technical support engineer involved in the testing did not seem confident when questioned by the plant manager regarding an initial setting on a component in the RCIC governor system.
The inspector noted that an additional operator was brought to the Unit 2 CR to perform the suppression pool temperature monitoring surveillance.
Operators were formal in their communications throughout the testing.
Required flowrate at rated pressure could not be achieved and RCIC was shutdown for investigatio ~
i
E8
Subsequently, it was determined that two control oil lines in the governor system had been incorrectly connected after the maihtenance.
The lines were correctly connected and RCIC was operated for further troubleshooting.
Operations logs indicated that the RCIC controller problems still existed and that only the manual mode allowed flow and discharge pressure to be controlled near normal.
The logs further indicated that when placed in auto, the flow could be varied by throttling the test valve only and discharge pressure remained well below rated.
On Hay 2, 1997, the inspector observed portions of the RCIC system flow controller troubleshooting associated with work order 97-004914-00.
The flow controller was removed from the control room panel and work was done in the Instrument Haintenance shop.
The flow controller was determined to not be the cause of the problems being experienced.
The licensee continued to troubleshoot the symptoms and finally determined that the cause of the experienced symptoms was an incorrect null voltage setting on the EG-R.
The licensee reset the null voltage setting.
On Hay 3, 1997, the inspector observed portions of the performance of surveillance instruction (SI) 2-SI-4.5.F.l.d, RCIC System Rated Flow at Normal Operating Pressure, from the control room.
The inspector also reviewed portions of the documentation associated with the SI, and did not identify any problems.
The licensee declared the Unit 2 RCIC System operable at 1:05 a.m.,
CDT on Hay 4, 1997.
During some of the initial troubleshooting discussions, the inspectors noted indications that some RCIC performance data was not routinely reviewed by some technical support engineers.
The licensee's Integrated Computer System (ICS) collects data on governor and valve performance during HPCI and RCIC operations.
This data may provide indications of degradation even when surveillance test acceptance criteria are met.
This observation was discussed with engineering and plant management.
c.
Conclusions The inspectors concluded that the RCIC maintenance and troubleshooting was not well conducted.
Although the 7-day LCO period was not exceeded, the return of RCIC to an operable status was delayed by ineffective troubleshooting early on.
The inspectors observed that technical support early in the troubleshooting process was not strong.
Hiscellaneous Engineering Issues (92903)
E8.1 0 en Ins ector Followu Item 269 260 296/97-01-01 Resolution of FSAR Discrepancies.
Section H1.5 describes an UFSAR discrepancy identified during observation of seismic monitoring testing.
The inspector
'identified that the dimensions of the instrumentation enclosure did not match the dimensions specified in a note contained on UFSAR figure 2..5-17.
A PER was initiated.
The licensee has not yet completed the final phase of the UFSAR review program.
The IFI remains open pending additional NRC review of the licensee's UFSAR review progra Conduct of EP Activities
IV. Plant Su rt P1.1 a.
b.
S3.1 a.
b.
C.
Emer enc Pre aredness Tr ainin Drill Ins ection Sco e
71750 71707 During the inspection period, the inspector observed most of the scheduled emergency preparedness training drill from the simulator contr'ol room.
Observations and Findin s On April 23, 1997, the inspector observed an emergency preparedness training drill from the simulator control room.
Overall, the operators'erformance was good.
The inspector particularly noted that the Unit Supervisor's briefings to the simulator control room crew were frequent and clear.
In addition, the Unit Supervisor continued to reassess the event through the use of the Emergency Operating Instructions (EOI)
charts.
The inspector attended the control room drill critique on April 24, 1997.
The controllers presented good observations of issues identified during the drill.
Security and Safeguards Procedures and Documentation Fitness for Dut Pro ram Review Ins ection Sco e
81502 To determine whether the licensee's Fitness for Duty Program meets commitments identified in licensee's procedures and 10CFR Part 26.
Observations and Findin s On Hay 7, 1997, the inspector determined that the licensee continues to implement the Fitness for Duty in accordance with their plans and procedures.
The inspector reviewed the licensee's collection facility and concluded that samples are collected, secured, sent, and tested in the manner consistent with other drug screens.
The inspector determined that the chain of custody and all other quality control procedures were appropriately followed.
Conclusions There were no violations of regulatory requirements.
The inspectors determined that the chain of custody is maintained for samples collected during random and for-cause drug tes il ib
S3.Z a.
B Securit Events Lo Review Ins ection Sco e
71750
C.
To determine if the licensee is maintaining a Safeguards Event Log (SEL)
of events that are required to be reported to the NRC, i.e.,
equipment and personnel failures.
Observations and Findin s The inspectors reviewed the SEL to determine if the licensee was logging equipment and personnel failures during the months of January and February 1997.
During review of the SELs, the inspectors noted during the two month.
period that the licensee had logged personnel and equipment failures that were outside regulatory requirements.
The inspectors also determined that there are events of personnel and equipment errors not logged in the SEL when the errors do not cause the licensee to be outside regulatory requirements.
Additionally, the inspectors reviewed Physical Security Instruction Hanual (PSIH), Section 108, Revision 6, Patrols Inspection, dated February 3, 1997.,
and.determined that the procedure provided instructions for the duties and responsibilities of security exterior and owner-controlled area patrols.
The inspector s noted that the procedure precluded patrols from being involved in any duties that would preclude their abilities to perform alarm assessment and contingency response, which is their first priority.
Conclusion The inspectors determined that there were no noted equipment or personnel errors not logged in the SELs that caused the licensee to be
~ in.non-compliance with regulatory requirements.
There were no violations noted in this area.
Hiscellaneous Security and Safeguards Issues P8.1 a.
Licensee Res onse to USNRC I'nformation Notice 96-71 Ins ection Sco e
71750 b.
The inspectors performed a review of the licensee's response to NRC Information Notice (IN) 96-71, Licensee Response to Indications of Tampering, Vandalism, or Halicious Hischief.
Observations and Findin s On December 27, 1996, the NRC issued IN96-71 in order to alert licensees to the value of planning formal, predetermined, responses to indications of tampering, vandalism, or malicious mischief.
On April 25, 1997, the
Oi
Il
licensee issued Abnormal Operating Instruction (AOI) 100-8, Security Event Response.
AOI-100-8 provides guidance for the license& Operations Management group if site security events such as tampering, vandalism or malicious mischief are discovered.
The licensee expects AOI-100-8 to help the licensee's Operations group in evaluation. of such indications and it provides prescribed responses to these issues.
The AOI also provides a formalized interface between Operations and the licensee's Nuclear Security Services.
c.
Conclusions The inspectors found that the licensee's actions taken to implement.
IN96-71 were good.
Licensee inspection data sheets provided adequate coverage of plant, areas, systems, and equipment.
The response/
instruction presented a heightened licensee sensitivity to the issue.
V. Mana ement Meetin s X1 Exit Meeting Summary The resident inspectors presented inspection findings and results to licensee management on Hay 13, 1997.
Other meetings to.discuss report issues were conducted during the report period.
A.formal meeting with plant management was conducted on April 25, 1997.
The licensee acknowledged the findings presented.
Proprietary information is not included in this inspection report.
PARTIAL LIST OF PERSONS CONTACTED Licensee T. Abney, Licensing Hanager J. Brazell, Site Security Manager R. Coleman, Acting Radiological Control Manager J. Corey, Radiological Controls and Chemistry Manager T. Cornelius, Emergency Preparedness and Planning C. Crane, Site Vice President, Browns Ferry R..Greenman, Hanager training J.
Johnson, Site guality Assurance Manager R. Jones, Operations Manager S.
Kane, Licensing Supervisor K. Singer, Maintenance Manager H. Williams, Site Engineering Manager
'INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering IP 40500:
Licensee Self-Assessments t
IP 62707.:
Haintenance Observations
'P 61726:
Sur veil 1 ance Observations IP 71707:
Plant Operations
~,
iP
IP 71750:
IP 81502:
IP 92901:
IP 92902:
IP 92903:
IP 93702:
Plant Support Activities Fitness For Duty Program Followup-Plant Operations Followup-Haintenance Followup-Engineering Prompt Onsite Response to Events at Operating Power Reactors
~Oned ITEMS OPENED CLOSED AND 'DISCUSSED
~T Item Number VIO 50-296/97-05-01 Status Open Descri tion and Reference Failure to Reset Locked Recirculation Pump Scoop Tube.
(Section.01.3)
VIO 50-260,296/97-05-02 Open Failures to Implement Haintenance Procedures.
(Section Hl.3 and H1.4)
NCV 50-260,296/97-05-03 Open/
Closed Failure to Obtain Radiological Control'urveys.
(Section H8.1)
~
IFI 50-260/97-05-04 Open Spurious Hain Steam Isolation Valve Closure on Turbine Trip. (Section 01.1)
Discussed
~T Item Number Status IFI 260,296/97-01-01 Open Descri tion and Reference Resolution of UFSAR Discrepancies.
(Sections H1.5 and E8.1)
e 0