IR 05000277/1990006
| ML20043A755 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 05/15/1990 |
| From: | Doerflein L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20043A751 | List: |
| References | |
| 50-277-90-06, 50-277-90-6, 50-278-90-06, 50-278-90-6, NUDOCS 9005230082 | |
| Download: ML20043A755 (37) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Docket / Report No. 50-277/90-06 License Nos. DPR-44 f
50-278/90-06 POR-56
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i Licensee:
Philadelphia Electric Company Correspondence Control Desk P. 0. Box 7520
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Philadelphia, Pennsylvania 19101 Facility Name:
Peach Bottom Atomic Power Station Units 2 and 3 Dates:
February 20 to April 2, 1990 Inspectors:
J. J. Lyash, Senior Resident Inspector
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R.~ J. Urban, Resident Inspector L. E. Myers, Resident Inspector a
J. A.
akoski, Reactor Engineer Approved By:
/./ A LC 5[15 /')O L. T. Doerfleing Chief, Reactor Projects I0 ate Section 2B, ivision of Reactor Projects Areas Inspected:
Routine.--on-site regular, backshift and deep backshift inspection of accessible portions of Units -2 and 3.
The. inspectors reviewed operational safety radi-ation-protection, physical. security,. control room activities, licensee events, surveillance testing, engineering and technical support activities, mainten-i ance, Unit 2 outage activities and the fire protection program.
Four viola-tions of NRC requirements were identified during the inspection.
9005230082 900515,
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Executive Summary Peach Bottom Atomic Power Station-Inspection Report 90-06 Plant 0perations':
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1.
During August,1989 an unacceptable Emergency Service Water (ESW) system alignment existed for about 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />, in violation of the Technical Speci-fications-(TS), and potentially placing the plant in an unanalyzed con-dition. The misalignment would have prevented ESW flow to all Unit 2 emergency core cooling equipment'during a loss of cooling accident, which includes a loss of offsite power. The incident resulted from inadequate restoration from maintenance. While the facts regarding the incident-were documented in an Operations Incident Report, their significance went un-recognized-by the licensee (NV 90-06-01, Section 1.3).
2.
On February 22 improper restoration from maintenance activities, similar in nature to the inadequacies leading to the incident described above in paragraph 1, resulted in operation of the A-ESW pump without a: suction source.
Improper. implementation of provisions for use of "Special Con-
-dition Tags," specification'of equipment' restoration position as " Tag Off," and failure to perform system lineup check-off lists contributed to the problem (UNR_90-06-02, Section 1.3).
3.
.The licensee identified a violation of TS 4.14.A.1.b which requires that certain fire protection system valves be locked, secured or their position surveilled monthly.
Five val s added during plant modifications in were not= added to plant-drawings and procedures. ' They were not locked, secured or surveilled (NON 90-06-05, Section 8.7).
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The inspectors' review of the licensee's fire protection program indicated
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that staffing, training and procedures are being effectively implemented.
However, several issues needing additional licensee attention were iden-ti fied _(UNR 90-06-06, Section 8.9).
5.
Two: examples of failure to: control locked valves in accordance with Administrative-Procedure A-8, " Control of Locked Valves," were idcntified by the inspectors (NV4 90-06-03, Section 3.0).
Maintenance and Surveillance:
1.
During performance of a local leak rate test on the standby liquid control system, licensee maintenance personnel implemented an unauthorized change to the test procedure. When the problem was pointed out the test was halted and the change properly reviewed and approved. This appears to be an -isolated incident and was not significant from a technical perspective (Section 4.1).
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i Executive Summary
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2.
On April 2, 1990, during performance of electrical post-maintenance test-ing of the E242 bus an inadvertent start of the E4 diesel generator occurred. The start was the result of ineffective communication between the test personnel and the control room operator (Section 2.4),
3.
On two occasions inadequate review of surveillance test results for~ safety-
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related equipment resulted in failure to identify that acceptance criteria had.not been met (Section 4.2).
Engineering and Technical Support:
I 1.
The licensee's approach to analysis and testing of the ESW system in re-sponse to concerns raised by an NRC Safety System Functional Inspection Team was found to be detailed and displayed a sound safety perspective (Section 3.0).
2.
The licensee's outage and ALARA planning in preparation for the Unit 2
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mid-cycle maintenance outage resulted in completion of activities on
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schedule and'within the established goals.
Radiological Controls:
1.
During the report period the inspectors reviewed two instances in which personnel. failed to adhere to requirements clearly established on applic-able-radiation work permits (RWP).
In each case the failures were iden-tified by the licensee and documented on radiological-occurrence reports.
However, similar examples have been identified in the recent past (see licensee identified violation NV 90-01-04), and corrective _ actions taken have not been effective in preventing recurrence. This may be indicative of broader problems with radiation worker practf ies (NV4 90-06-04,. Section 6.2).
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i TABLE OF CONTENTS Page 1.0 Plant'0perations Review'(71707, 71710)
11 Operatior.a1 Safety Verification and Station Tours...........
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1.2 Engineered. Safeguard Features (ESF) System Wal kdown..........
I 1.3 Improper Restoration of the ESW System Following=
Maintenance.................................................
2.0 Follow-upof.PlantEvents.(93702,62705,61720)
2.1 Unit 3 Automatic Reactor Scram Due to Loss of Generator s
Stator Cooling..............................................
2.2 Unit 2 Inboard Main Steam Isolation Valves Fail Local Leak i
Rate Test'...................................................
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2.3 Unit 2 Main Steam Line Drain Valves Fail Local Leak Rate Test........................................................
2.4 Inadvertent Emergency Diesel Generator Start................
-3.0 NRC Safety System Functional Inspection Follow-Up (37700, 37702, _
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37701,92700)....................................................
4.0 Surveillance Testing Activities (61726, 71707, 61701, 61720)
j 4.1-Standby Liquid Control System Local Leak Rate Testing.......
1 4.2 Surveillance Test Results Review............................
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5.0 - Maintenance Activities (62703, 61700)............................
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t 6.0 Radiological Controls (71707, 83750)
j 6.1 Routine Observati:7s........................................
i 6.2 Failure.to Comply With Radiation Work Permits...............
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7.0 Physical Security (71707)........................................
' 8.0 ' Fire Protection Program Review (64704)...........................
-f l-i 9.0 Review of Licensee Reports (90712, 90713, 92700).................
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10.0 Previous Inspection Item Update (64704, 95702)...................
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11.0 Management Meeti ng s (30703, 30702)'..............................
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DETAILS.
'1.0 Plant Operations Review Unit'2 began a scheduled mid-cycle maintenance outage on March 3, 1990 to'
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complete some once per cycle surveillance and local leak rate testing
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(LLRT), modifications, and maintenance items.
The scheduled _ outage work F
was completed March 29, however emergency service water system testing delayed the restart of Unit 2.
Unit 3 operated at 100% power until March 6 when a reactor scram occurred following a loss of main generator stator cooling. Reactor power on March 21 was reduced to 75% when extraction steam was lost to a feedwater
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heater.
Reactor power was returned to 100% on March-25 and remained there through the end of the report period.
A detailed chronology of plani events occurring during the inspection period is included in Attachment I.
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1.1 Operational Safety Verification and Station Tours
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The inspector completed NRC Inspection Procedure 71707, " Operational
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Safety: Verification,"'by direct observation of activities and equip-ment, tours of the facility, interviews and discussions with licensee personnel, independent verification of safety system status and-limiting conditions for operation, corrective actions, and review of j
facility. records and logs. The inspectors' performed 124 total hours of on site backshift time, including:4 hours of deep backshift and i
weekerd tours.of th ' facility,
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i 1.2 Engineered Safeguards Features (ESF) System Walkdown I-The inspector performed a detailed walkdown of the "A" loop of the
Unit 2 residual heat removal (RHR). system in order to independently verify the ability of the system to perform its intended safety func-tions.
In preparing for and during the performance of the walkdown, L
the-inspector utilized the documents listed in Attachment II. The-inspection was conducted with Unit 2 shutdown, and the "B" loop of RHR in shutdown cooling.
During the system walkdown the inspector identified 1several-concerns.
The future fill pump to RHR stayfull block valve (HV 2-10-21596) was
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found open and backseated to isolate a packing leak. The system check off list COL 10.1 B-2 and the system piping and instrument diagram (P&ID) required the valve to be closed. An equipment trouble tag (ETT) was on the valve identifying the packing leak.
The inspec-tor determined that the ETT had not been entered into the ETT track-l ing system and therefore, a maintenance request form (MRF) had-not H
been initiated. To correct the situation, the valve was reclosed'and MRF 9002503 was written to repack the valve.
The inspector found the
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i condensate demineralizer block valve to RHR stayfull (HV 2-10-21612)
open.
System COL 10.1.B-2 required the valve to be closed, while the system P&ID indicated the valve should be open. To correct the situ-ation, the valve was closed in accordance.with the system COL. The.
COL 10.1.B-2 and the system P&ID are being reviewed by the licensee and will be_ revised.
In both examples the out of normal valve posi-tions were not adequately tracked. The licensee recently implemented an equipment status list as a result of similar problems. The equip-
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ment status list will be used to record off normal component status.
During review of surveillance test ST 6.8-2, " Unit 2 A RHR Loop,
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Pump, Valve, Flow and Unit Cooler Functional," performed on February
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22, 1990, the inspector identified a step that was not signed-off.
Unsigned step 11 of enclosure 2 required independent position veri-fication for the RHR pressurizing line supply valve to shutdown a
cooling loop A (HV 2-10-710).
The licensee determined that the valve
was in the required position.
The step was completed but was in-
~i advertently not signed-off. All remaining surveillance tests re-viewed were completed. adequately. All data required was recorded and-met the specified acceptance -criteria, While performing'the RHR: system walkdown in the torus room the in-spector noted that the manual handwheel for the torus header valve
(M0 2-10-039A) was lying on the grating beneath.the valve. Addi-l tionally, the inspector noted that a loose pipe support was lying
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across some RHR. piping below the torus room catwalk.
The Maintenance 1'
Superintendent was informed and. the conditions were corrected. Over-all=the condition of the."A" loop of-RHR was acceptable. The' exist-
ing. system configuration agreed with the P&ID and COL except as pre-viously noted.
1.3 Improper Restoration of the ESW System Following Maintenance The' inspector' reviewed portions of the operation and maintenance
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history-for the emergency service water pumps. Maintenance request-i forms (MRF) completed on the pumps and Operations Incident Investi-
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gation Reports concerning the system were evaluated. Several con-cerns were identified.
The inspector reviewed Operations Incident Report 2-89-63 titled
" Undesirable Emergency Service Water System Alignment." The report described an event that the inspector considered to represent a sig-
-nificant unanalyzed condition. On August 1, 1989 permit 3-33-M87-09149 was applied so that work could be performed on B ESW isolation motor operated valve M0-3972.
The permit tagged the A ESW isolation valve MO-2972 closed,' applied a special condition tag (SCT) to MO-3972, and tagged open the ESW manual crosstie valves HV-0-33-512A and B.
The A and B ESW pump discharges are usually crosstied through the 2 MOVs. Opening the manual crosstie valves maintained the ability of the pumps to feed either unit. On August 11, 1989 the licensee i
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cleared the permit and closed HV-0-33-512A and B, but the specified restoration positions for M0-2972 and MO-3972 were " Tag-Off" (TO). A
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note in the comment section indicated that double verification was to be' performed.by completing a check off list (COL), but no particular COL was specified.
COL 33.1. A-3 was performed, but it didn't contain MO-2972 cr HV-0-33-512A and B, and the step verifying M0-3972 posi-
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tion was not performed. -As a result of these errors no independent verification of HV-0-33-512A and B was performed, and M0-2972 and MO-3972 were left in the closed position.
On August 13, 1989 the emergency cooling water (ECW) pump was removed from service and blocked under permit 2-33-L88-63432. At 11:55 p.m.
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.on that same day _the E-2 emergency diesel generator (EDG) was removed from service for an annual maintenance outage and the control station was placed in pull-to-lock.
Because of the valve misalignment de-scribed above, and the inoperability of the ECW pump, only the A ESW pump-remained capable of supplying cooling water flow to Unit 2 equipment. The equipment of concern is the safeguards and reactor core isolation cooling (RCIC) system compartment coolers, the core spray pump motor oil coolers, and the residual heat removal pump seal-water coolers. The E-2 EDG is the source of emergency power for the A ESW pump. By rerroving the E-2 EDG from service, the A ESW pump was also made inoperable.
In the event of a design basis accident (loss of coolant accident with a coincident loss of offsite power) the A ESW pump would not have operated. The B ESW pump would have started and provided cool-ing water flow to the remaining 3 in service EDGs, but because of the valve misalignment no flow would reach the Unit 2 ESW loads. This wouldn't have been readily detectable from the control room because pump start and adequate discharge pressure would-have been observed.
No direct indication of flow-to the Unit 2 loads is available. The 2 M0s could be opened from the control room if the problem was diagnosed.
The first indication of the problem, however, may be equipment fail-ure due to lack of cooling.
Since this lack of cooling affects all 8 core spray and low pressure injection pumps, the high pressure cool-ant injection system and RCIC it represents a potential common mode failure of all or part of these core cooling systems. The licensee discovered the mispositioned valves at 7:30 a.m. on August 15, 1989.
Unit 2 had been in this apparently unanalyzed condition for about 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />.
Technical Specification (TS) 3.0.0 states that a system determined to be inoperable solely because its emergency power source is in-operable may be considered operable provided its normal power source and all its redundant systems are operable. Unless this condition is satisfied the unit shall be placed in hot shutdown within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
The associated TS bases state that it specifically prohibits operation when 1 division is inoperable because its emergency power source is inoperable and a system in
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another division is inoperable for another reason, Removal of the emergency power source for the A ESW pump from service, with the B ESW pump isolated from the Unit 2 ring header for a period of 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br /> constitutes a violation of TS 3.0.0 (NV 90-06-01). No Notice of Violation is being issued for this violation at the present time.
Enforcement action will be treated in conjunction with the ESW issues raised by the NRC Safety System Functional Team Inspection (50-277/50-278 90-200).
As noted previously the licensee did initiate an Operations Incident Report. The details of the incident and the contributing factors are described in the report. The report indicates that although undesir-able, this degraded ESW availability is permitted by the plant Tech-nical Specifications. The report was reviewed by the Operations Support Department and it was determined not to be significant enough to warrant review by the Plant Operations Review Committee. The corrective action recommended in the report was to implement operator training on the blocking error. This was accomplished by incorporat-ing the details of the incident into nonlicensed operator training course TP-110. However, this lesson plan also states that although undesirable it did not violate TS. The final report was approved by the Plant Manager on January 24, 1990.
While the report contains the relevant information, it appears the. *.he significance of this inci-dent was not recognized by the licen h.
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The licensee frequently uses SCT tags for equipment which may need to be operated by maintenance technicians during or following com-pletion of their activities. Administrative Procedure A-41, " Control of Safety Related Equipment," generally outlines the licensee's per-mit and blocking program. The Peach Bottom Permit and Blocking Manual contains detailed instructions regarding the implementation of the program. Neither of these documents contain instruction for use of the SCT. The licensee has implemented training on the use of SCTs and an informal written description of their application is avail-able. This training and written material indicate that the main-tenance personnel shall clearly communicate the as-left position of the tagged components prior to closure of the permit.
In this case the as-left position of the valve apparently was not communicated.
Procedure A-41 and the Blocking Manual allow restoration from block-ing to be "T0" for cases in which positioning the equipment to its normal alignment may not be possible or necessary. This provision is intended for cases where multiple tags have been applied to a single component. Step 7.4.6 of A-41 requires that if the restoration of componer.ts is "TO," completion of 2 COLs which include the components is required to provide for independent verification of restoration.
In this case no other permits had been applied so there apparently was no valid reason tu specify TO.
In addition, the appropriate COLs were not completed.
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l The inspector reviewed a second incident involving improper restora-tion of the ESW system from maintenance. On February 19, 1990 block-ing permit 2-33-M89-10438 was applied to A ESW sluice gate motor operator MO-2213. The initial tagged position of the sluice gate was closed, but an SCT was applied to allow maintenance personnel to operate the. gate.
Following completion of the maintenance activities on February 22, the permit was cleared. The restoration position for MO-2213 was TO.
It appears that the as left position of the gate l
(closed) was not clearly communicated to the control room.
In addi-r tion, no partial system COL was performed following removal of the blocking.
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Subsequently, the A ESW pump was started for adjustment of the pack-
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ing.
About 15 minutes later the "A EMERG SERVICE WATER HEADER LOW PRESSURE" alarm and a B ESW pump auto start were received.
The
operator secured both pumps and dispatched an auxiliary operator to.
investigate. No abnormalities were noted and the operator concluded that the maintenance personnel in the area had probably bumped the local pressure switch. The A ESW pump was restarted and the low
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pressure alarm and B ESW pump auto start again initiated.
The pump
discharge pressure and motor ~ current were observed to be fluctuating.
The operator secured the pumps.
After reviewing those portions of the system alignment observable from control room indications, the operator recognized that the sluice gate was closed. Operating the pump with the gate closed had drawn down the pump bay, cavitating the pump.
This instance appears to be another example of improper restoration from maintenance activities.
Use of the SCT without clear communica-tions, and specifying the restoration position as "T0" results in a lack of knowledge of the final equipment alignment.
It also appears that the system COLs needed to establish and verify the equipment's
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proper return to service are not being performed in all cases. The it cumulative effect of these poor practices can significantly impact
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equipment operability.
Similar problems have been identified by the licensee in several recent Operations Incident Reports.
Closure of i
these reports will require the licensee to implement corrective i,
action. This issue, including actions to correct the problem, are i
still under evaluation by the licensee. This item will remain un-k resolved pending further review of the licensee's actions to correct this problem (UNR 90-06-02).
2.0 Follow;up_Of Plant Events
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The inspector evaluated licensee response to plant events to ensure that prompt snalysit tas performed, reasonable root causes were identified, and sopropriate correctdve actions were implemented.
In each case, the in-spector reviewed aRD11 cable administrative and technical procedures, interviewed personnel and examined the affected systems and equipment.
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r 2.1 Unit 3 Automatic Reactor Scram Due To Loss of Generator Stator Cooling On March 6,1990, at 1:00 a.m., the "B" generator stator water cool-
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ing pump was blocked to repair a leaking drain plug. At 2:27 a.m.,
the "A" stator water cooling pump tripped, causing an alarm, an p
immediate generator load runback, and sequential trips of both E
reactor recirculation pumps in anticipation of the decreased steam demand. The system runback design initiates a turbine trip if gene-rator load does not reach 7726 amps within 31/2 minutes. If reactor power is still above 30%, a reactor scram will result from the tur-bine trip.
The Unit 3 operator entered Operational Transient Procedure OT-112
" Recirculation Pump Trip," and began inserting an established sequence of control rods while the Shift Technical Advisor (STA)
monitored the reactor for thermal hydraulic instability; none was observed. When the timer expired (in 3 minutes, 10 seconds), gene-i rator amperage was above 7726 amps and a turbine trip occurred.
Since reactor power wa> still above 30%, a reactor scram occurred.
Reactor vessel level shrink following the scram reached -5 inches,
initiating primary containment isolation system (PCIS) group II and
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III isolations.
The scram and PCIS isolations were reported to the NRC via the ENS phone.
The licensee reset the scram and the PCIS isolations.
Pressure con-trol was maintained using turbine bypass valves and the main conden-ser as the heat sink.
Vessel level was maintained with the conden-sate pumps, a, reactor feedwater pump, and the startup level control valve.
After conditions had stabilized, the shift wanted to start one of the
" twp idle recirculation, pumps.
However, Technical Specifications (TS)
prohibit starfing' a recirculation pump if the temperature differen-
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tial between the reactor vessel bottom head and the dome is greater
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than 145 degrees Fahrenheit (F).
The bottom head temperature is sensed on the bottom head drain line. Continuous flow through the l
drain line is maintained by RWCU, ensuring a representative tempera-ture.
Shortly after the scram, the bottom head drain temperature
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quickly decreased to 185 c'egrees F, due to a clogged drain line. The
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i other vessel metal and water temperatures remained between 460 to 490 degrees F.
l The licensee tried ceveral RWCU system manipulations in an attempt to reestablish flow through the bottom head drain without success.
Reactor de pressurization was begun to reduce vessel temperatures to
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within the 145 degree F limit. When this condition was met, a re-l circulation pump was started and the bottom head drain temperature i
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increased to within 50 degrees F of the other vessel metal and water
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Starting the recirculation pump apparently cleared the blockage.
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The "A" stator water cooling pump trip which had initiated th'e transient occurred because its "B" phase motor 1:ad termination wore
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through its electrical tape and arced to the metal conduit. All three leads were retaped and were meggered successfully. The pump l
was returned to service on March 7. The "B" pump was repaired by re-l'
placing the drain plug, and was returned to service on March 6.
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The generator load runback to 7726 amps did not occur before the time
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delay relay had expired. Therefore, a turbine trip and subsequent l'
reactor scram occurred.
Calibration procedure RT 5.40 allowed the load runback ramp and time delay to be set within the same time band
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(3 to 3 1/2 minutes).
RT 5.40 previously performed on November 9, 1989, determined.that the load runback was set to reach 7726 amps in 3 minutes and 28 seconds while the time delay was set to expire in 3 minutes and 11 seconds.
Therefore, a turbine trip would always occur in this configuration.
RT 5.40 will be revised to require the time delay to expire at least 15 seconds after the load runback reaches 7726. amps.
Prior to startup of Unit 3, RT 5.40 was temporarily changed to permit proper setup of the runback and time delay. Unit 2 was checked and the time delay relay and load runback were setup properiv.
The in-spector had no further questions.
2.2 Unit 2 Inboard Main Steam Isolation Valve Fails Local Leak Rate '
Test On March 4,1990, the local leak rate test (LLRT) of Unit 2 inboard main steam isolation valve (MSIV) 808, failed in the as-found con-
'dition. The leakage rate was 59.6 standard cubic feet per hour (scf/hr) at 25 psig test pressure. Technical Specification (TS)'
4.7.A.f. specifies a limit of 11.5.
The licensee made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS call at 11:43 a.m. to report the leak rate exceeding TS. Outboard MSIV/86B was found to have a leak rate of 2.5 scfm/hr which was satisfactory. MSIV 80B was disassembled to clear, and polish the valve seat and disk. No mechanical problems
were found. A LLRT after reassembly was satisfactory.
2.3 Unit 2 Main Steam Line Drain Valves Fail local Leak Rate Test On March 5, 1990, Unit 2 main steam line (MSL) drain isolation valves M0-74 and MO-77 failed LLRT ST 20.029. The as-found condition indicated each valve had a leak rate of greater than 125,000 cubic
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The acceptable value is less than
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1500 cc/m.
This leak rate combined with other minimum pathway leakage rates for all penetrations exceeded La.
The results of the LLRT were reported to the NRC via the ENS. The
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l valves were dissembled and the excessive leakage was determined to be
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due to excess clearance between the valves disks and seats in the closed position. The valves were rebuilt using new disks and seats purchased to the manufceturer's recommended tolerances.
The licensee
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contacted the manufacturer and is investigating possible causes of the valve failures.
The licensee is required to submit a Licensee Event Report (LER) on this incident which will include corrective actions. A LLRT of the rebuilt valves was successful.
The inspector had no further questions at this time. The LER will be reviewed at a later time as part of the routine inspection program.
2.4 Inadvertent Emergency Diesel Generator (EDG) Start
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On April 2, 1990, at about 2:00 a.m., undervoltage relay 127-18 associated with Unit 2 4 Ky emergency bus 242 failed.
The loss of i
the bus caused a trip of the "D" RHR pump which was operating in the
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shutdown cooling mode.
Shutdown cooling flow was restored by align-ing the "A" loop of RHR and starting the "C" RHR pump.. The reactor t
vessel coolant temperature increased 3 degrees Fahrenheit in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> before the flow was restored.
The failed relay was replaced.
Sur-veillance testing was initiated to verify operability of the under-
voltage relays following the replacement.
Prior to starting surveillance test (ST) 13.110, "E42 4 Kv Bus Under-voltage Relays Functional Test and E-42 and E-424 Alternative Shut-
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down Control Functional Test," a copy was distributed to individuals involved with the test, and a pretest briefing was held. Performance of the ST would cause a momentary loss of power to E42 so steps were taken to minimize the operational effects of the dead bus. The test verifies the automatic transfer of the E42 bus from the #3 to the #2 offsite power source. Only a partial test was required because the E-424 alternative shutdown control portion of the system was not affected.
Steps 1 through 4 and 24 through 29 were to be completed.
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The engineer in charge of the test was located in the E-42 switchgear room communicating by radio with the chief operator in the control room.
Steps 1 and 2 successfully tested the fast transfer capability of the E-242 bus from the #3 to the #2 offsite power source. The engineer intended to request the chief operator (CO) to perform steps 3 and 4.
Poor communication resulted in the C0 perceiving that step 24 was to be performed.
Instead of matching target positions of the control switches in the control room, the C0 opened the breaker supplying power to the E-42 bus. A dead bus occurred and the E4 l
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l emergency diesel generator (EDG) started and loaded on the bus at 1:39 p.m.
E4 was secured and the E-42 bus was reenergized by normal offsite power.
The licensee made an ENS report at 2:40 p.m.
Poor radio communica-j-
tion practices between the engineer and the CO along with a hig'h level of activity and noise in the control room caused the event. Not using
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repeat acknowledgements of instructions while working in an atmosphere with a high level-of distraction created the environment for error.
The event and contributing factors were discussed with the involved
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In addition, the licensee's Independent Safety Engineering Group is evaluating the root cause and causal factors.
The inspector
had no further questions.
3.0 NRC Safety System Functional Inspection Follow-Up An NRC SSFI was conducted at Peach Bottom during February and early March, 1990.
The team focused on review of the design and testing of the common emergency service water (ESW) system and the Unit 3 high pressure coolant injection (HPCI) system.
Significant issues were raised by the team, re-quiring an immediate licensee response.
During this inspection period the resident inspectors monitored licensee analysis and testing performed in response to the SSFI findings to assess their adequacy and the short-term impact on the operability of these safety systems.
Emergency Service Water System Testing and Analysis The SSFI team identified that a clear ESW system design basis hadn't been established. _In addition, neither the original preoperational testing,-
nor any integrated system test since plant licensing, had fully demonstrated the system capability.
The routine surveillance program did not provide assurance that the system had been maintMned functional.
In fact, avail-able information indicated that performan a had degraded.
In response to the team's concerns the licensee agreed to proceed with the previously plannet Unit 2 shutdown for a mid-cycle maintenance outage on March 3 not to restart Unit 2 until the issue had been resolved and to shutdown Unit 3 on March 6 if ESW operability for the unit could not be demonstrated.
The ESW system consists of two 100 % capacity pumps and a distribution network supplying Unit 2 & 3 heat loads.
The pumps feed flow in parallel to the 4 common emergency diesel generators, and a ring header in each unit.
Each ring header supplies the associated unit's emergency core cooling system (ECCS) and reactor core isolation cooling (RCIC) system
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compartment coolers, the core spray pump motor oil coolers and the resi-
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~ dual heat removal pump seal water coolers.
Each ECCS and RCIC pump room L
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contain-two redundant compartment coolers.
Licensee analysis established that the design basis for the ESW system required that it be capable of supplying adequate cooling water flow to maintain the serviced equipment operable under the following conditions:
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1) loss of coolant accident; 2) loss of offsite power; 3) loss.of the in-l strument air system, and 4) any single active failure.
Equipment environ-mental qualification (EQ) documentation was reviewed to determine the maximum allowable room temperatures for the individual equipment rooms
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cooled by ESW. The licensee analytically determined the maximum postu-lated heat loads in the rooms under accident conditions. Assumptions were made regarding cooler internal and external fouling factors, cooling fan
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flows and the maximum anticipated inlet water temperature in order to calculate the required ESW flow rates.
Since Unit 2 had been shut down the licensee elected to isolate the Unit 2 ring neader, reducing the load on the ESW system. A series of tests t
were performed on the Unit 3 ESW distribution system (" Unit 3 only" test)
to determine if continued operation could be supported.
The licensee de-veloped a test method to establish the limiting system configuration, and to measure individual cooler flows in that condition.
The test method was first applied to the " Unit 3 only" configuration, but was subsequently used for Unit 2 diagnostic testing and a final " dual unit" test.
For the
" Unit 3 only" test the licensee simulated a loss of offsite power and in-strument air by failing open all Unit 3 cooler inlet and outlet valves.
The "A" and "B" ESW pumps were run one at a time and the ESW inlet and outlet ring header pressures were measured.
The pressure data associated with the ESW pump producing the lowest ring header differential pressure (dp) was used during the remainder of the testing.
The ESW pumps were secured to prevent overcooling the diesel generator lube oil. The pre-viously observed ring header dp was reestablished using the service water (SW) system, and individual cooler flows measured.
The flow measurements were obtained using.two independent techniques: 1) an ultrasonic flow sensing device, and 2) differential pressure measured across recently in-stalled throttle valves with a known flow constant.
The test results con-firmed that with the Unit 2 ring header isolated, ESW was operable for Unit 3.
The licensee developed and approved a justification for continued operation (JCO) to allow continued Unit 3 cperation in this configuration.
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The licensee performed a series of diagnostic tests on the Unit 2 cooler.
at a range of ring header dp values. Again 2 independent methods of flow measurement were used: 1) ultrasonic, and 2) directly measuring flow out of the individual coolers by routing it into a graduated drum. No throttle valves have been installed on Unit 2 so this method was unavailable.
Based on these test results the licensee concluded that 11 of the 20 Unit 2 safeguards compartment coolers would not pass the required flow under the design basis conditions.
The historical inoperability of the ESW system for Unit 2 was reported to the NRC via ENS.
The licensee initiated an extensive program of cooler inspection and
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cleaning.
Retesting following the cleaning showed some improvement in cooler flow rates.
The licensee developed and approved a safety evalu-ation to allow, under strict administrative control, opening of the Unit 2 ring header isolation valves for performance of a duel unit test.
Sur-veillance Procedure ST 21.5.1, " Dual Unit ESW Test of ESW to ECCS Ring l
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Headers and Diesel Generator Coolers," was written to align both units in the design basis configuration, and to open the Unit 2 ring header isola-tion valve. The licensee maintained an operator at the valve and in radio communication with the control room throughout the testing.
Unit 3 ring
header flows and pressures were monitored during the test to ensure that i
ESW operability for Unit 3 was maintained. With the ESW system in this dual unit configuration the dp for the Unit 2 and Unit 3 ring headers was
collected for each ESW pump. Again the data associated with the pump
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generating the lowest ring header dp was used for subsequent flow testing.
Satisfactory Unit 2 flows still could not be achieved.
The source of the Unit 2 flow restriction appears to be poorly designed and significantly degraded ring headers. The Unit 3 ring headers had pre-viously been replaced and replacement of the Unit 2 headers was planned for early 1991. The licensee determined that the diesel generators were receiving significantly more than the required flow, and that only 1 of t
the 2 redundant coolers in each equipment room was needed to support operation.
Near the end of the inspection period the licensee performed a test with the diesel generator cooling water flow throttled, and with I of the 2 coolers in each Unit 2 equipment room valved out of service.
Pre-liminary measurements of the remaining in service Unit 2_ coolers appeared acceptable. The licensee initiated the engineering analysis needed to determine if plant operation of the diesels and the Unit 2 coolers in this configuration is allowable.
-The inspector reviewed the licensee's analyses, test procedures and safety evaluations used to support the ESW review.
The inspectors also attended
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many of the Plant Operations Review Committee meetings associated with the procedure and SE approval, and observed in field testing of the F.SW system.
The inspector concluded that the licensee has taken a conservative, methodical approach to the evaluation and resolution of this problem.
Concern for the establishment of a clear understanding of the state of system performance and potential impacts on plant safety was evident on the part of both licensee staff and management.
However during the course of the inspection the inspector did observe some personnel performance weaknesses as discussed below.
On March 19, 1990, the inspector was observing work associated with ESW system testing. Blocking permit 2-40B-M90-01918 was issued to allow in-ternal cleaning of RCIC room coolers.
The inspector noted four normally
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locked valves (HV-2-33-21078 A&B; RCIC "A" and "B" room cooler "B" inlet block valves, and HV-2-33-21079 A&B; RCIC "A" and "B" room cooler outlet block valves) that were unlocked which did not appear on the blocking per-mit. The inspector questioned a test engineer concerning control of these valves and was told that the locked valve log was the method of control.
The inspector reported to the control room and determined that two of the four valves (HV-2-33-21078 A&B) were not included in the locked valve log.
Procedure A-8, " Control of Locked Valves," requires certain actions for
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The key is obtained from the key cabinet in the control room. A back copy of the LVR is attached to the valve denoting that it is out of position.
Once the valve is returned to its normal position the valve is locked, the LVR is removed and discarded, the key is returned, the locked valve log is completed, and the valve receives verification that it has been restored to its proper position. These actions are necessary to ensure that un-monitored valves are maintained or restored in their proper position.
Initial corrective action consisted of restoring the valves to their normal locked position, writing an incident report and performing a partial check off list to verify ESW valves were properly aligned.
The inspei '.or in-formed the licensee that the failure to control locked valves in accordance with procedure A-8 is a violation of TS 6.8 (NV4-90-06-03).
High Pressure Coolant Injection System Follow-up (HPCI)
The inspector had previously noted that the HPCI gland seal condenser (GSC),
associated piping, vacuum pump and condensate pump were non-Q, and non-seismic. The licensee had established the position that HPCI is operable without this support system functional. As stated in inspection report 90-01, Section 2.2, the inspector referred this concern to the SSFI for follow-up. After being questioned by the SSFI, the licensee reevaluated their position and recognized that although the HPCI pump and turbine could. operate without the GSC subsystem, the equipment room would reach temperatures in excess of the environmental qualification (EQ) limit for some components in the room.
The licensee initiated an engineering review to determine if all needed components in the room were qualifiable to the new, higher,. expected temperature.
Several solenoid valves and governor electronic components were found to be past their qualified life under the reanalyzed conditions, and were replaced.
The licensee developed and approved a justification for continued operation (JCO) to support plant restart while EQ document files are being compiled for the remaining com-ponents. The inspector reviewed the licensee's analyses, JC0 and attended the related PORC meetings.
The issue and the licensee's actions were dis-cussed with Region I and headquarters technical specialists.
No additional concerns were identified.
l The inspectors will continue to monitor licensee actions implemented in response to the SSFI team findings.
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4.0 Surveillance Testing I,
The inspectors observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were L
being used, redundant systems or components were available for service as l
required, test instrumentation was calibrated, work was performed by I
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qualified personnel, and test acceptance criteria were met.
Daily sur-ve111ances including instrument channel checks, jet pump operability, and control rod operability were verified to be adequately performed. A de-tailed list of the surveillances observed is included on Attachment III.
i In addition, reviews of completed surveillance tests were performed and are included in Attachment IV.
4.1 Standby Liquid Control System Local Leak Rate Testing On March 7 the inspector observed performance of portions of surveil-lance tests (ST) 20.073-1 and 2, " Local Leak Rate Testing (LLRT) -
Standby Liquid Control (SLC)." ST 20.073-1 checks for leakage past the SLC inboard primary containment isolation valve (check valve No.
11-16) while ST 20.073-2 checks for leakage past the SLC outboard primary containment isolation valves (squib valves XV 4A and B).
The as-found LLRT performed on the squib valves (ST 20.073-2) was acceptable.
In order to perform the LLRT on check valve 11-16, a vent path was necessary.
This is accomplished by firing one of the two squib valves in accordance with ST 20.073-1.
However, test per-sonnel decided to remove the inlet spool piece to XV 14A and then remove its trigger assembly to create the vent path instead. Main-tenance request form (MRF) 9000259 was written to perform this task.
Two maintenance workers began to remove the spool piece in accordance
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with MRF 9000259. Once the bolts were removed, trouble was encoun-
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tered removing the spool piece due to tight clearances. The workers loosened several pipe supports so that the pipe could be spread to remove the spool piece.
The inspector asked the workers what docu-
ment allowed them to disassemble the SLC pipe supports.
Work was ima.ediately stopped and the workers contacted their supervisor.
The inspector reviewed the work package which contained the STs and MRF 9000259. Step 4 (prerequisite) of ST 20.073-1, stated to verify that one of the two squib valves was fired to create a vent path.
However, the worker signed the step "N/A" and wrote in the margin,
" vent path provided thru spool piece removal." In accordance with administrative procedure A-3, " Temporary Changes to Procedures," the worker should have reworded step 4 to referetice MRF 9000259, obtained a temporary change traveler, and received two approvals from plant management. The workers changed an approved procedure without authorization.
In this case, the change was not properly processed as outlined in A-3.
However, the alternate approach was technically acceptable, was being performed under a valid MRF and the erro-appears to be an isolated case. The licensee stated that section 5 of the MRF would be used to document loosening the pipe supports.
The maintenance workers returned the pipe supports to their as-found conditions and documented the activity on the MRF.
ST 20.073-1 was temporarily changed in accordance with A-3 to allow removal of the a
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spool piece to provide a vent path. MRF 9000259 was revised to enable spool piece removal without disturbing SLC pipe supports. The LLRT on check valve 11-16 was successfully performed, the SLC system was l
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reassembled, and an as-left LLRT of the squib valves was successfully
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performed.
L 4.2 Surveillance Test Results Review r
I During the period the inspector reviewed a sample of completed sur-veillance tests (ST) to assess if the licensee had appropriately re-
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viewed the results, and taken action where.needed. Tne licensee does
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not include a separate test acceptance criteria section in STs.
In-stead test steps which affect system operability and constitute the
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acceptance criteria are highlighted in the body of the test with an asterisk. The cover sheet for each procedure states that if one or more asterisked steps were completed unsatisfactorily, the test is unsatisfactory and the reviewer is referred to the appropriate Tech-nical Specification (TS).
Several tests were selected, and completed procedures for the preceding 12 months were reviewed. The inspector
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identified several concerns.
ST 6.1.2-2, " Unit 2 Standby Liquid Control Pump Functional Test for IST
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Surveillance Test ST 6.1.2-2 is performed quarterly to test the oper-ability and performance of the standby liquid control (SLC) pumps and discharge. check valves.
It also satisfies the Inservice Test Program (IST) requirements.
The inspector reviewed the results of the last 4 procedure performances of this quarterly test.
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On February 9, 1990, the licensee performed ST 6.1.2-2.
Pump A flow rate was measured as 56.1 gpm, and pump B was 46.2.
These values
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were recorded in the body of the test and are test acceptance cri-teria.
The performer is required to transfer the data to Attachment
1 of the procedure, a graphical. representation of the IST acceptable, alert and action ranges. Both observed flow rates were in the action
range, but both graphs were marked as being in the acceptable range and the test was signed as satisfactory. The completed test was re-viewed by the Reactor Operator (RO), Shif t Supervisor (SSV), and the Shift Technical Advisor (STA) and approved as acceptable.
The approved test was sent to the IST Coordinator for incorporation into the' system performance trending data base.
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r The IST coordinator apparently recognized the discrepancy on February 12, 1990 and returned the test to operations. A successful retest
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demonstrating that the pumps were operable was performed on February 14 and the original test cover sheet was resigned as unsatisfactory on February 15. No Operations Incident Report was initiated, and the r
inspector could find no evidence that any additional corrective action
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had been taken. When the concern was raised by the inspector the licensee initiated an investigation and Operations Incident Report 2-90-20.
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Both SLC pumps failed the quarterly flow rate surveillance test in the IST action-range on February 9.
The licensee's surveillance pro-cedure and Administrative Procedure A-127,." Inservice Testing," re-quire that if component performance is in the action range the com-ponent is to be considered inoperable.
Shift Management is directed to consult the applicable TS LCO.
TS require that with both SLC pumps inoperable the unit is to be in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and cold shutdown within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Because of the data tran-scription error and an inadequate test results review no action was
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ccsen. While the discrepancy was apparently identified by the IST ccordinator on February 12, the retest was not performed until
Febru y it.
The reason for this delay is unclear. Although sub-sequent :
cing proved that the equipment had been operable, both SLC pumps were in an indeterminate state for about 5 days.
ST 6.2-3
"PCIS Normally Open Valves" On February 5,1990 the licens*1 performed ST 6.2-3.
This test is
completed quarterly to demonsteate the operability of normally open primary containment isolation system (PCIS) valves. No direct valve i
position indication is provided for solenoid operated sample valves SV-3671A through G or SV-3978A through G.
In order to demonstrate closure the test subjects the penetration to a vacuum and measures
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the leakage.
If the leak rate is less than 10 standard cubic feet
,per hour (SCFH) the valve is considered to be closed and the test satisf actory. During the test on February 5, SV-3671A and SV 3978G failed.
The failures were noted in the body of the test at the appropriate asterisked step. Despite these failures the test cover sheet was signed by the performer, R0 and SSV as satisfactory. TS require that if a containment isolation valve is found to be inoper-
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able, the redundant valve in that penetration is to be closed and disabled in'the closed position.
Because the test was signed as satisfactory this action was not taken.
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On February 8 the STA identified the discrepancy and reported it to shift manegement. Apparently a decision was made to hold the test, I
and any action, until the system engineer involved in the original i
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been completed. When the involved engineer returned on February 9 he indicated that no action had been taken. At this point the TS LCO was entered and the appropriate action taken.
The licensee initiated
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an Operations Incident Report to document the problem. The test was reperformed and SV-3971A passed, but SV-3978G again failed. A follow-up local leak rate test of SV-3978G determined that the valve was closed and had an acceptable leak rate. The valve was disassem-bled and inspected with no noted problems.
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The inspector expressed concern that this was a second example of failure to appropriately treat deficient TS required surveillance-test results.
It appears that the initial reviews were inadequate, and that once the problem was identified no action was taken for an additional 2 days. Additionally, the inspectors review of previous.
results of this ST noted that these valves frequently fail the quar-terly ST, and are retested successfully without any repair or adjust-ment.
This indicates a potential problem with (tratic valve perform-ance or a deficient test method.
The licensee stated that a review of the test procedures and valve performance would be initiated.
Program and Administrative Guidance fer Surveillance Test Results Review The inspector reviewed administrative procedures and guidance dis-cussing the ST results review process, Administrative Procedure A-43,
" Surveillance Testing System," establishes the licensee's program for scheduling and performance of STs. The procedure tasks the RO, SSV, and Shift Manager with coordination of testing and disposition of deficient test results. However, no specific instructions regarding the scope or depth of the review are included.
Operations Management Manual Chapter OM-7, Section E, states that the Shift Supervisor shall review the results of the surveillance tests performed during their shif t to verify the completeness of the test and to confirm that the results are within the established acceptance criteria.
It also states that the Shift Technical Advisor shall re-view the results and sign the cover sheet.
No more detailed guidance is provided.
In the two instances discussed above unacceptable ST results were not identified due to the performer incorrectly signing the test cover sheet as satisfactory.
In both cases several levels of review failed to detect the error. Once the problem was detected by the licensee there appears to have been further delay in taking action. A Notice of Violation was issued with Inspection Report 90-01 (NV4 90-01-01)
involving the licensee's failure to appropriately disposition un-satisfactory ST results.
The licensee has not had time to respond to that violation. The inspector informed the licensee that corrective actions taken in response to these two additional examples will be reviewed in conjunction with follow-up to the previously issued violation.
5.0 Maintenance Activities The inspectors reviewed administrative controls and associated documenta-tion, and observed portions of work on the following maintenance activi-ties:
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e, Document Equipment Date Observed MRF 9000259 Remove spool piece on SLC system 3/7/90 MRF 9000396 Remove "A" SRM 3/19/90 MOD 5201 Install 2 gal. oil reservoir on 3/9/90 2A recire pump motor In _ addition, a review of the following completed maintenance procedures was performed:
M-011-002, " Standby Liquid Control XV-14, Explosive Valve Mainten-
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MRF 9001049, Repair "K" main steam relief valve coil
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Administrative controls checked included blocking perniits, fire watches and ignition source controls, QA/QC involvement, radiological controls, plant conditions, Technical Specification LCOs, equipment alignment and turnover information, post-maintenance testing and reportability.
Docu-ments reviewed included maintenance procedures (M), maintenance request forms (MRF), item handling reports, radiation work permits (RWP), material certifications, and receipt inspections.
6,0 Radiological Controls 6.1 Routine Observations During the report period, the inspector examined work in progress in both units and included health physics procedures and controls, ALARA implementation, dosimetry and badging, protective clothing use, ad-herence to radiation work permit (RWP) requirements, radiation sur-veys, radiation protection instrument use, and handling of potentially contaminated equipment and materials.
The inspector observed individuals frisking in accordance with HP procedures. A sampling of high radiation area doors was verified to be locked as required.
Compliance with RWp requirements was verified during each tour.
RWP line entries were reviewed to verify that per-sonnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements.
No unacceptable conditions were identified.
F 6.2 Failure to Comply with Radiation Work Permits On March 27, 1990, two maintenance workers made an entry.into the Unit 2 "A" and "C" RHR pump rooms tc inspect the room coolers for leaks and to remove some tools and equipment.
The workers decided to continue their work in the "B" and "D" RHR pump rooms, gaining access to the pump room by passing through the torus room, a high radiation area. While in the "B" and "0" RHR pump rooms they were I
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I observed by a reving HP technician who questioned if they had per-mission to cross through the torus room.. Due to the noise level in the area communications were difficult and it is not clear that the question and response were understood by the personnel involved. The HP technician in the "B" and "D" RHR pump room exited, checked with the drywell control point HP technician and discovered that the workers had not obtained permission to enter the torus room. Meanwhile, the
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two workers re-entered the torus room, crossed over to the "A" and
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"C" RHR pump rooms, and exited where they were met by the drywell
control point HP technician and another HP technician.
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The radiation work permit (RWP) contrsiling the activities in these areas stated that for passage through the torus room, an alarming dosimeter and poti1 ve HD coverage was required. The drywell control point HP technician stated that he had questioned the workers before
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they made entry to the "A" and "C" RHR pump rooms several times about the possibility of passing through the torus room.
The workers re-i plied that they would not need entry into the torus room since they were only going to work in the "A" and "C" RHR pump rooms.
The workers were then briefed on the conditions in the "A" and "C" RHR pump rooms and made the entry.
The licensee initiated a Radiological Occurrence
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Report (ROR) to document the RWP violation.
The inspector reviewed RWP 2-90-54200, "RX 2 RHR, Core Spray, HPCI, RHR rooms; Test / Inspection / Flush ESW System, Build / Remove Scaffold,"
Surveys of the "A", "C", "B" and "D" RHR rooms and the torus room, HP logs, and the preliminary ROR. The inspector interviewed the HP technicians involved with this event and reviewed the initial response
,to the ROR by the responsible management. The ROR procedure requires that the worker's supervisor respond with corrective actions which may include disciplinary actions af ter reviewing the incident.
The response by the workers' supervisor is reviewed and approved by the Health Physics Supervisor, the Senior Health Physicist (RPM), and the Superintendent of Plant Services.
The initial corrective action by the HP group was to deny these workers entrance to radiological con-trolled areas. A preliminary corrective action proposed by the Main-tenance Superintendent did not appear effective and was not approved by the Senior Health Physicist.
The entry of the two maintenance workers into a high radiation area, twice, without being briefed of the dose rates levels and radiation i
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hazards in the area, and without being provided alarming dosimeters as required by the RWP is a violation of A-107, " Radiation Work Permit Program," which specifies that individuals are responsible for com-plying with the requirements of the RWP.
A second incident involving RWP violations occurred on March 28, 1990, when four maintenance workers working on the sample line to the waste
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surge tank on the 116 foot elevation of the Rad Waste building con-taminated themselves and the area.
The workers were clearing the
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sample line of stoppage by blowing nitrogen gas through the lines into the floor drain. The workers were wearing shoe covers and gloves.
A fitting backed nff blowing contaminated water over the area and on the workers. The area was contaminated to 100,000 DPM/100 cm2. The workers' clothing was contaminated, however nasal smears and whole
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body counts were negative.
RWP 2-90-5471 controlling the activity included special instructions which specified that for a breach of
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the line, the controlling HP technician must be present and full pro-L tective clothes and respiratory equipment must be worn.
The failure to inform the.HP technician of the breach and wear protective clothes and respiratory equipment was failure to comply with the RWP, there-fore a violation of A-107. The licensee initiated a ROR to document the RWP violations. The inspector reviewed RWP 2-90-5471, surveys, and HP logs.
The initial corrective action was counseling the workers by their supervisor to comply with the requirements of the RWP.
The workers were instructed to read and understand the RWP before initi-ating work and to maintain good communication with the controlling HP technician.
The inspector reviewed RORs since January 1990 to determine if there has been a trend of noncompliance with the requirements of RWPs.
There have been three incidents where individuals did not comply with the protective clothes dress requirements of the RWP. Also, there were three incidents where individuals entered high radiation areas without complying with the RWP. One incident was reported in Inspec-tion Report 90-01, Section 7.1, as a licensee identified violation when two test engineers entered a high radiation area without being on and complying with the requirements of the RWP for the area. An earlier incident occurred on January 3,1990, when an HP technician controlling entry to a high radiation area allowed workers to enter the. area without alarming dosimeters.
The RWP specified that indi-viduals making entry must wear alarming dosimeters and have positive HP coverage.
The HP technician was disciplined for not ensuring implementation of the RWP and TS requirements for high radiation area.
The workers were aware of the RWP and TS requirements but followed the instructions of the HP technician.
The last incident with high radiation area was the torus room entry cited above.
It appears that there could be a general problem with personnel compliance with the special instructions of RWPs.
The inspector informed the licensee that failure to adhere to the RWP requirements for these two examples occurring on March 27 and 28, 1990 censtitutes a violation of TS 6.8.1 (NV4 90-06-04).
7.0 Physical Security Routine Observations The inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, including: security
staffing, operations of the CAS and SAS, checks of vehicles to verify l
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s proper control, observation of protected area access control and badging procedures on each shift, inspection of protected and vital area barriers, checks on control of vital area access, escort procedures, checks of de-tection and assessment aids, and compensatory measures. No inadequacies were identified.
8.0 Fire Protection Program 8.1 Introduction The inspectors performed a broad inspection of the fire protection area.
Included were general plant tours, followup of items from pre-vious inspection reports, review of two fire protection related LERs, fire suppression system walkdowns, fire brigade training and quali-fication, QA audits, and review of fire protection related surveil-lance tests and associated Technical Specifications.
8.2 Plant Tours During the report period, the inspectors walked-down various areas of the plant, paying particular attention to fire protection equip-ment, control of combustibles, control of fire risk maintenance acti-vities and fire barriers.
On March 1, the inspector noted that tags on several hose reeis in the turbine and reactor buildings were not signed-off as having been inspected for the month of February. The inspector obtained the latest performance of ST 16.1.1, " Fire System Hose Station Visual Inspection,"
and determined that it was performed on 2/17.
The security group recently took over authority for the performance of this ST.
The individuals who performed the test were not aware that the cards were to be initialed and dated; the ST did not require it.
Fire protection personnel stated that NFPA standards require either signing and dating cards on the hose reels or maintaining a record of hose reels inspec-tions.
Since the licensee keeps a record of hose reel inspections by virtue of performing ST 16.1.1, the cards will ba removed from the
fire hose stations. The inspector had no further questions on this topic.
8.3 Fire Brigade Training
The fire brigade members, including leaders, receive initial class-room instruction, in accordance with 10CFR Part 50, Appendix R and this program is repeated every 5 years.
This training is a two day program. held at the PECo West Conshohocken Fire School. Annually all i
fire brigade members attend a one day refresher training course at
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the West Conshohocken facility which is a hands on practice session l
with fire fighting equipment and actual fires.
Each fire brigade i
member receives site specific fire fighting training prior to joining i
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i a fire brigade team and every two years thereafter.
Each fire brigade
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i team meets quarterly to review changes in the _ fire protection program and other subjects as necessary.
Fire drills are held at least twice a year for each fire brigade member.
In addition, each fire brigade
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leader attends a one day fire brigade leadership training class which
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L includes the use of Firesoft Fireground Commano Simulator, a computer
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program which simulates a fire and requires the leader to make command
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decisions.
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The inspector reviewed the lesson plans for PBAPS Fire Brigade L
Leadership, Training Plan 343 and Site Specific Fire Brigade Train-ing, LP-FBS-FBS. The lesson plans were adequate. The fire brigade
training qualifications were reviewed. The Operations Support group l
has a training coordinator who collates the information from the Training Section on qualification and training dates of each fire
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brigade member. This information is provided monthly to the shift clerks. The inspector had no further questions.
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8.4 Fire Drill t
On March I the inspectors witnessed an unannounced fire drill con-ducted by the fire protection group. The drill was staged in the radwaste hopper room on the 150 foot elevation in the radwaste build-ing.
The postulated class A fire was due to a large pile of transient combustibles.
Fire alarm activation and licensed operator assessment of the fire's location was done quickly.
Notification of the fire, its location and fire brigade assembly area were anr.ounced over the PA system within one minute.
l The fire brigade leader (FBL) reported to the fire within 3 minutes.
He performed a good assessment of the situation and provided good information to the control room.
However, the FBL had difficulty locating the nearest fire hose because he did not have pre-fire strategy plans (PFs); he had to wait for the control room shift i
supervisor to bring the appropriate PF to the scene. The inspectors questioned why the PFs were not located at some of the fire 'ighting
cages in the plant so that the FBL would have them in hand 9en he reported to a fire.
The drill coordinator agreed to place the PFs in selected fire cages in the plant.
Command and control of the fire brigade by the FBL was adequate.
Once the fire brigade was assembled, the FBL did not immediately direct the members to fight the fire; prompting from a fire brigade member was necessary.
The inspectors determined that the floor fore-man recently (mid-February) took over the FBL position from the shift
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supervisors.
Although the FBL performed the job adequately, leader-ship (dri11manship) should improve over the next several months.
Firefighting strategy and techniques were good; however, several
' brigade members were hampered by poorly fitting equipment.
Now that
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women are members of the fire brigades, the men's equipment is fre-quently too large.
The inspectors noted several of the women
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Overall, fire alarm effectiveness and notification was good, fire brigade assembly was timely, effective fire fighting techniques were evident, and FBL performance was adequate. All drill objectives were met and the inspectors had no further questions.
8.5 Fire Suppression System Walkdowns The inspectors walked-down three fire suppression systems: diesel driven fire pump (DDFP); high pressure coolant injection (HPCI) room Cardox system; and motor driven fire pump (MDFP).
The inspectors observed the following items:
system equipment condition,
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valve, breaker, and switch alignment,
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locking devices of locked valves,
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control room switches, indications, and alarms.
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Equipment condition of the DDFP system was good.
Valves, breakers, and switches were properly aligned, valves required to be locked were locked, and control room switches, indications, and alarms were func-tional. No abnormalities were noted by the inspectors.
Equipment condition of the MDFP system was good. However, the in-spector noted that local flow indicator FI-7054 was reading approxi-mately 750 gpm while the system was static.
The instrument is used once per cycle to determine flow rate and Technical Specification (TS) operability of the fire pump systems. The inaccuracy did not appear to effect the validity of recently completed STs.
The inspec-tor passed the observation on to operations and fire protection per-sonnel. A MRF has been written to re-calibrate the gauge.
Valve,
- breaker, and switch alignment was proper, and control room switches, l
indications and alarms were functional.
However on March 2, the in-
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spector noted that a valve required to be locked open, was open but unlocked. HV-0-370-12444, discharge block valve for the MDFP, did not have the chain around its handwheel and the lock was open. Ad-ministrative Procedure A-8:C, " Locked Valve List-Common," Revision 4, l
requires the valve to be locked open, unless it is entered in the l
locked valve log as being in another position for testing or other reasons. The inspector examined the locked valve log and determined that the last authorized movement of the valve was on February 15 for I
performance of ST 6.16, " Motor Driven Fire Pump Operability Test,"
Revision 12. The valve was signed-off as having been restored to its locked open position.
Procedure A-8, " Control of Locked Valves,"
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Revision 6, requires the requestor to complete a locked valve request
(LVR) and obtain shift management approval for each locked valve to be moved, and to obtain a key from the control room key cabinet.
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addition to HV-0-37C-12444, two other valves, HV-0-37C-12443 and
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12345 were manipulated without completing LVRs, receiving shift man-
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agement approval and obtaining a key from the control room key cabi-net. These actions constitute a violation of Procedure A-8 and TS
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f 6.8(NV490-06-03).
Procedure A-8 requires control of the keys for locked valves to be maintained, including frangible fire protection valve locks.
It appears that the keys for these fire protection valves are not con-trolled and have been distributed to various onsite personnel. In
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this case the nonlicensed operator didn't need to complete a LVR to P
obtain a key, because he already possessed a key.
In addition, the inspector pointed out that ST 6.16 did not state to lock the valve
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once it was reopened nor did it require independent verification to determine if the valve had been restored to its locked open position.
Initial corrective action consisted of immediately locking the valve and issuing an-incident report to determine circumstances surrounding the event, including key control of frangible locks.
8.6 Quality Assurance Audits The inspector reviewed two audits of the Peach Bottom Fire Protection
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Program. The first audit, PA-88-500, was conducted in accordance with TS 6.12.a which requires an annual audit utilizing e'.
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qualified offsIte licensee personnel or an outside fire protec-
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firm.
The second audit, PA-89-36, was conducted in accordance <-
TS 6.12.b, which requires a triennial audit utilizing a qualifieo outside fire consultant.
Audit PA-88-500 was conducted from December 5-9, 1988, by the licen-see's Nuclear Quality Assurance (NQA) organization. As a result, two NQA corrective action requests (CAR) were issued concerning:
the lack of an approved procedure to document portable fire
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extinguisher monthly inspections; and
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two STs that were approved as satisfactory when they were actu-
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ally unsatisfactory.
The inspector verified that both NQA CARS were resolved in a timely manner.
Audit PA-89-36 was conducted from December 4-8, 1989, by several fire protection consultants. As result, one NQA CAR was issued concerning a deviation from National Fire Protection Association (NFPA) standards t
concerning heat detection systems installed in the diesel generator
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I rooms. The inspector determined that work necessary to close the CAR has been finished. The inspector had no further questions in this area.
8.T Surveillance Test Review The inspector reviewed the fire protection surveillance tests listed
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l-in Attachment IV. The STs were reviewed to determine if associated TS requirements were being implemented, if STs were performed within
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their required frequency, and whether they were technically accurate.
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All the STs were performed on time and were satisfactory or properly
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dispositioned. The inspector questioned the technical adequacy of ST 8.1.2-1, " Diesel Fuel Sample Fire System." The inspector pointed out that the ST requires the Junior Technical Assistant (JTA) to transmit the fuel oil samples between operations and chemistry.
However, the JTA position has been eliminated. The inspector also questioned the sampling technique used to obtain fuel oil samples.
The ST requires six samples to be taken at six specific locations. Guidance in the ST does not support effective sampling.
The licensee is currently reviewing this area (see section 8.9).
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TS 4.14. A.I.b requires verification that each unmonitored valve in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position once each 31 days.
ST 16.23,
" Fire System Valve Position Verification," was written to meet the requirements of this TS. However, the inspector found five under-
ground gate valves (I-5, D-8, 0-9, D-10, D-11) which appeared to meet the criteria of TS 4.14.A.1.b that were missing from ST 16.23. These valves were found on ST 16.24 " Fire System Unmonitored Valve Posi-tion Verification Test," but the ST was only being performed quar-terly to meet an American Nuclear Insurers (ANI) commitment.
The inspector expressed his concern to the fire protection super-visor. The inspector was shown a draft revision to ST 16.23.that had been PORC approved in meeting 90-036 on March 1.
All of the above five fire valves had been added to the ST to ensure compliance with the TS.
The fire protection supervisor also stated that he con-sidered these valves "otherwise secured" for the following reasons:
1) they are several feet below ground, 2) an underground valve wrench is needed to operate the valve, and 3) this wrench is kept locked in the radwastt building.
In addition, the fire protection supervisor
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produced NFPA 26, " Supervision of Valves Controlling Water," which states that underground gate valves with roadway boxes need not be
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supervised. The inspector pointed out that there was an underground valve wrench on the ground behind the reactor building near some of these underground gate valves, and the NFPA standard does not relieve a licensee from a TS requirement. Based on the inspector's observa-tion of an uncontrolled underground valve wrench, these fire valves could not be considered "otherwise secured." However, since the
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review and appropriate corrective actions were initiated, this item
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is considered a licensee identified violation and no NDV will be issued (NDN 90-06-05).
l The inspector noted that valves D-8, D-9, D-10, and D-11 were not on I.
the fire system P&ID. Apparently when the Administration building was enlarged, these valves were added to the fire system as part of i
the modification.
The P& ids were never updated.
The licensee has
red-lined their controlled P&lDs to better reflect the as-built fire system. The licensee is continuing their review in this area to de-termine what permanent revisions need to be made to the P&lDs, and if l-other previous modifications affected the fire systems.
Finally, several underground gate valves were missing identification a
tags.
Over time, the wire holding the tags has broken and they have fallen down in the pit, making identification difficult.
The licen-s see has committed to re-tag these valves.
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8.8 Licensee Event Report Review LER 2-89-19 concerned a fire protection surveillance test (ST) that failed to functionally test all fire doors as required by Technical Specifications (TS) 4.14.D.2.a.
During a previous fire barrier modi-fication and'a TS change, five fire doors were inadvertently left off a revision to ST 7.8.16, " Fire Door Supervision System Functional
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l Corrective action consisted of testing the missing five fire doors, They were all found to be satisfactory on August 30, 1989. A per-i manent revision was also made to ST 7.8.16 to add the missing doors.
Long-term corrective action for a previous similar LER (2-88-24) was to review all STs controlled by the fire protection section for tech-
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nical adequacy.
However, LER 2-89-19 stated that the depth and com-
pleteness of the past review was inadequate because it failed to identify the missing doors.
Therefore, the licensee committed to re-review and revise as appropriate, STs controlled by the-fire pro-tection section.
The licensee stated that long-term corrective ac-tion, re-reviewing and revising STs controlled by the fire protection section that implements TS fire protection surveillance requirements, was performed and no further problems were found.
8.9 Conclusion Fire protection equipment was well maintained, combustibles were well controlled, adequate fire watches were observed and no deficient fire barriers were noted.
Fire brigade training and qualifications were up-to-date and acceptable.
The observed fire drill was successful.
Fire suppression system lineup and condition were generally accept-able.
QA audits were performed and corrective actions were either t
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complete or near completion.
Several minor problems were noted in l
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the surveillance test review area, including a licensee identified l:
violation.
The following issues will remain unresolved (UNR 277/90-06-06) pend-ing review of. licensee corrective actions:
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purchase and receive smaller size fire fighting equipment;
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recalibrate FI-7054;
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L revise ST 8.1.2-1 to better describe proper sampling of the DDFP
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fuel oil;
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mine if drawings and procedures are correct; review and update fire system P& ids; and
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check and re-tag underground valves if necessary.
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9.0 Review of Licensee Reports The Peach Bottom 1989 Exposure Report dated March 3, 1990, and the Semi-y:
Annual Effluent Release Report, No. 28, dated February 29, 1990 were re-viewed. No discrepancies were noted.
10.0 Previous Inspection Item Update (Closed) Unresolved Item (277/89-15-01; 278/89-15-01).
A number of fire
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protection program deficiencies were noted including: combustibles behind
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one of the inttrument panels in the control room; a nitrogen gas tank dis-connected from the Supervisory Alarm System to Turbine Bearing 2-9
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Sprinkler System; inspection tags not on the portable foam carts; operat-
ing ' procedures did not reflect Cardox hoses in the control room having been blanked off; and fire extinguishers (FE) in contaminated or high radiation areas were not included in the plant FE inspection program.
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The combustibles behind the instrument panels of the control room were immediately removed when the concern was identified.
No similar combust-ibles concerns have been noted since that time. The nitrogen gas tank was immediately connected to the Supervisory Alarm System when the inspector informed the licensee of the condition.
The inspector has not noted any
additional deficiencies in this area. The portable foam carts are in-spected annually by procedure Routine Test (RT) 24.45, revision 0.
The inspector confirmed that this procedure was affequate to address the con-
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cern.
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The carbon dioxide line of the Cardox System to the control room has been blanked off by capping the line at the hose connection.
This was done by Temporary Plant Alteration (TPA) 37A-1 which is governed by the TPA pro-cedure, A-42. Modification 5041 will completely remove the carbon dioxide
line and the hose station from the control room. A review of operating
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procedure 50 37A.1.3, " Unit 2 Turbine Building and Common Plant Cardox System Startup and Normal Operations", revision 0, and the associated check-off-list now reflect that the control room cardox has been blocked
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off. The inspector had no further questions.
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Procedure RT 24.40, " Inspection of the Fire Extinguishers," will be re-i vised so that inspection of FEs located in radiologically controlled areas
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will be tracked and inspected at appropriate intervals.
The inspector had
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no further questions.
(0 pen) Unresolved Item (UNR 277/90-01-03). Main steam line flow trans-mitter failures. On January 5,1990, operations personnel took approxi-mately 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> to place the primary containment isolation system (PCIS)
group I "B" channel in a tripped condition af ter the 1168 main steam line (MSL) flow transmitter local indicator indicated a downscale condition.
Although Peach Bottom TS do not provide guidance on a time limit, standard TS stipulate a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> time limit.
The inspector was concerned with the amount of time taken for troubleshooting activities and to take apprc-priate TS action.
The Superintendent of Operations wrote a letter to all Shift Managers and Shift Supervisors concerning Rosemount transmitter failures.
The letter discussed the fact that not all failures of the
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transmitters will bring up a gross failure alarm in the control room.
Confusion regarding the failure mode was part of the reason for the delay
on January 5.
Further deley was caused by the belief that the local in-dicator had failed rather than the transmitter itself.
The letter stressed the importance of taking investigative action immediately to de-termine if the transmitter or the indicator has failed.
Finally, the letter emphasized inserting a half-trip condition as expeditiously as possible.
The inspector determined that the letter adequately addressed the first part of the unresolved item.
The remaining area of concern was the amount of time that an instrument
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can be valved out of service while its associated channel is not in a tripped condition.
Peach Bottom TS do not provide a time limit, but standard TS allow 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. On January 6, the licensee had the MSL flow
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transmitter valved out of service for 21/2 hours without the channel in a tripped condition.
Licensee procedures do not restrict or track this out-of-service time. This area is still being pursued by the licensee to determine the appropriate time limit and this item will remain open pend-
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ing NRC review.
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~11.0 Management Meetinas'
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A verbal: summary of preliminary findings was provided to the Peach Bottom-
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Station' Plant Manager at the conclusion.of the inspection. During the in-
.spection,. licensee management was periodically notified verbally,of the
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F preliminary findings by the resident. inspectors.
No written inspection l
! o-material was provided to the. licensee during the inspection. No pro-i Lf..
prietary.information is included in this report.
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ATTACHMENT 1 i
Facility and Unit Status
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Unit 2
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February 20 Unit at 73% power, limited to less than 75% power due to
isolating the "2A" feedwater string because of a tube leak.'
G February 22 Power dropped to 66% when the "B" condensate pump was removed
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from service for normal maintenance.
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L February 23 Unit returned to 73% power.
March 3 Unit shut down for mid-cycle outage.
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Unit 3
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February 20 Unit at 100% power, t
March 6 Due to loss of generator stator cooling, insufficient generator lead reduction caused a turbine trip and a subsequent reactor
scram from 35% power.
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March 10 Mode switch to startup and reactor critical.
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March 11 Generator synchronized to the grid.
March 13 Reactor power held at 80% due to chemistry limits.
March 14 Reactor power at 87%.
March 16 Reactor power reduced to 60% for control rod adjustment and
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maintenance work on the "A" reactor feedwater pump linkage.
March 21 Reactor power reaches 100%.
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March 24 Reactor power reduced to 75% oy procedure when extraction steam is lost to the 3 "A" feedwater heater.
March 25 After repair to an air line to the drain valve on the 3 "A"
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feedwater heater, power was returned to 100% and remained there
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through the end of the period.
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ATTACHMENT II
. Documents Reviewed Durina RHR System Review l
FSAR section 4.8-
" Residual Heat Removal System" T
" Core Standby Cooling Systems Control and Section 7.4
- Instrumentation"
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L P&ID M-361
" Residual Heat Removal System" i.
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TS 3/4.5.A-
" Core Spray and LPCI Subsystems"
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TS 3/4.5.B
" Containment Cooling System" E
TS 3/4.2.B
" Core-and Containment Cooling System - Initiation and Control" S0.10.1.A-2
" Residual Heat Removal System Set Up for Automatic
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Operation" COL 10.1.A-2A
" Residual Heat Removal System Set Up for Automatic Operation" COL 10.1.B-2
"RHR Common Valve Set Up for Automatic Operation"
' Residual Heat Removal System Routine Inspection" SO 10.8.A-2
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ST 1.6-2
"RHR Logic 'A' System Functional Test" n
ST 6.6-2
" Unit 2'.'A' RHR Loop, Pump, Valve, Flow and Unit Cooler Functional"
ST 6.8.1
" Daily RHR ' A' System and Unit Cooler Operability" ST'11.2-2
"LPCI Simulated Automatic Actuation Test"
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k ATTACHMENT III
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Surveillance Tests Observed
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ST/ERP-22,'" Fire Drill," performed 3/1/90 l
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ST/LLRT 20.01A,02, " Main Steam Isolation Valve Local Leak Rate," performed
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[m 3/9/901
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ST. 8.5-20,:" Unit 2l 'D' 125 volt Battery Service Test," performed 3/15/90
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. ST/LLRT 20.130,"LLRT-Scram Discharge Volume Vent and Drain Valves," performed j
3/12/90
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r ST 6.5-3, "HPCI Pump, Valve, Flow, Cooler," performed 4/2/90 I
i SI-2L-2-101-CICO, " Calibration Check of Reactor low Level Loop Instruments,"
performed 3/30/90
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-ST-20.073-1 and-2, " Local Leak Rate Testing - Standby Liquid Control,"
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performed 3/7/90
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s ATTACHMENT IV Surveillance Tests Reviewed ST 6.16, " Motor Driven Fire Pump Operability Test," performed on 2/15/90 St 6.17, " Diesel Driven Fire Pump Operability Test," performed on 2/27/90 ST 6.16.1, " Motor Driven Fire Pump Flow Rate Test," performed on 9/1/89 ST 6.17.1, " Diesel Driven Fire Pump Flow Rate Test," performed on 5/23/89 ST 16.2.1, " Fire System Weekly Test," performed on 2/14/90
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ST 16.2.2, " Diesel Driven Fire Pump' Battery Check," performed on 1/31/90 ST 16.23, " Fire System Valve Position Verification," performed on 2/24/90 ST 16.24, " Fire System Unmonitored Valve Position Verification Test," performed on 2/20/90
.ST 16.12, " Underground Fire Main Flow Test," performed on 10/4/89 ST 8.1.2-1, " Diesel Fuel Sample, Fire System," performed on 1/9/90 ST 8.1.5,." Diesel Driven Fire Pump Inspection," performed on 7/15/89
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ST 16.1.1, " Fire System Hose Station Visual Inspection," performed on 2/17/90
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ST 6.23-A-8:C, " Locked Valve Survey," performed 12/5/89 and 2/26/90 ST 3A-2-MSC-BIFM, " Functional Test Main Steam Line High Flow Instrument of RPS
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"B" Card File,", performed 3/23/90 ST2M-60F-kTI-B2MO, " Response Time of Condenser Low Vacuum Scram Channels,"
performed 3/23/90 ST 9.12.0-3, "Drywell Temperature Monitoring-Unit 3," performed 3/23/90 ST2L"25-91-BICQ, " Calibration Check of HPCI Suppression Chamber Level Instruments LS2-23-91B," performed 3/23/90 ST3M-8C-5084-XXCM, " Calibration Check of Recombiner Hydrogen Monitor H21T 5084/5084X," performed 3/23/90 ST 9.12-3, " Jet Pump Operability," performed 3/13/90 ST 2P-2-71-JIW, " Calibration Check of ADS Relief Valves Below Pressure Switch, PS 2-2-71J," performed 3/14/90 s-
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Attachment IV
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~ ST 9.6, "Drywell-Torus Vacuum Breakers," performed 3/29/90
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ST 8.1.16, " Emergency Diesel Generator Main Fuel Oil Storage Tank Water Removal," performed 3/29/90 ST 6.1.2-2, " Unit 2 Standby Liquid Control Pump Functional Test for IST,"
performed on 11/10/89, 2/9/90, and 2/13/90 ST 6.1-2, " Unit 2 Standby Liquid Control Pump Functional Test," performed on 12/11/89 and 1/5/90 ST 6.2-3, "PCIS Normally Open Valves (Unit 3)," performed on 11/10/89, 1/14/90 and 2/5/90 ST 6.1.2-3, " Unit 3 Standby Liquid Control Pump Functional Test For IST,"
performed on 2/16/90 ST 6.2.2, "PCIS Normally Open Valves (Unit 2)," performed on 5/3/89, 5/4/89, 5/7/89, 8/3/89, 8/25/89, 11/1/89, and 2/3/90
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