IR 05000277/1985040
| ML20137U695 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 01/31/1986 |
| From: | Beall J, Gallo R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20137U676 | List: |
| References | |
| 50-277-85-40, IEIN-84-70, NUDOCS 8602190294 | |
| Download: ML20137U695 (30) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-277/85-40 Docket No. 50-277 License No. DPR-44 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 19101 Facility Name:
Peach Bottom Atomic Power Station Unit 2 Inspection At: Delta, Pennsylvania Inspection Conducted: October 26 - December 31, 1985 Inspectors:
T. P. Johnson, Sr. Resident Inspector J. H. Williams, Resident Inspector H. I. Gregg, Lead Reactor Engineer S. V. P'ullani, Fire Protection Engineer J. E. Beall, Project Engineer I
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Reviewed by:
yE.Beall,ProjectEngineer date Approved by:
MhN-4$,
Robert M. Gallo, Chief date Reactor Projects Section 2A, DRP Inspection Summary:
Routine, on-site regular and backshift resident inspection (223 hours0.00258 days <br />0.0619 hours <br />3.687169e-4 weeks <br />8.48515e-5 months <br />) of accessible portions of Unit 2, operational safety, RHR pumps, snubbers, radiation protection, physical security, control room activities, licensee events, surveillance testing, maintenance, outage activities and out-standing items. Review of feedwater hammer transient and scra:n on December 26, 1985.
Results: The cause of Radwaste Building c61e tray fire remains undetc. mined.
The licensee identified a failure to follow lew.c %al Specificati*. LC0 action
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statement regarding inoperable containment isolation "alv :, (uetail 6.2.2).
A control rod was blocked out of service at position 48 with the unit at power; the ability to meet Technical Specification shutdown margin requirements for this condition is unresolved (Detail 4.1.9).
8602190294 860 g77 Pcg ADOCK 0 pg.
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DETAILS 1.
Persons Contacted J. F. Mitman, Maintenance Engineer
- R. S. Fleischmann, Manager Peach Bottom Atomic Power Station A. A. Fulvio, Technical Engineer A. E. Hilsmeier, Senior Health Physicist D. L. Oltmans, Senior Chemist F. W. Polaski, Outage Planning Engineer S. R. Roberts, Operations Engineer
- D. C. Smith, Superintendent Operations S. A. Spitko, Administration Engineer
- J. E. Winzenried, Superintendent Plant Services Other licensee employees were also contacted.
- Present at exit interview on site and for summation of preliminary findings.
2.
Unit 2 The unit began the inspection period at 100% power. On November 10, 1985, a cable tray fire occurred in the Radwaste Building (see detail 4.2.1).
On November 29, 1985, during a scheduled plant shutdown for maintenance, the unit scrammed from 33% power during turbine stop valve testing (see detail 4.2.2).
The unit remained in cold shutdown until December 24, 1985.
Licensee work activities during this shutdown included RHR pump inspections, mechanical snubber changeout, environmental equipment quali-fication modifications and preventive maintenance, and testing.
On December 24, 1985, the unit restarted and on December 26, 1985, the unit scrammed from 44% power during feedwater pump and level control sys-tem troubleshooting.
During this troubleshooting a feedwater hammer tran-sient caused a feedwater leak on the feedwater pump suction piping (see detail 4.2.3).
The unit restarted on' December 29, 1985.
3.
Previous Inspection Item Update 3.1 (Closed) Violation (277/82-25-01).
Failure to maintain the seismic qualifications of the ADS Back-Up Nitrogen Supply and to perform val-id checks of nitrogen supply as required by procedure.
The inspector verified that the corrective actions specified in the licensee's let-ter_ of February 25, 1983, had been taken.
The surveillance test which was previously revised because of a violation to include visual inspection of the seismic bottle restraints was revised to more clearly require that all bottles be placed in the installed racks and restraints be secured.
In addition, an individual " restraint se-cured" check-off was required for each bottle.
The inspector had no further questions. This item is closed.
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3.2 (Closed) Unresolved Item (277/82-06-03).
Emergency diesel generator (DG) fuel oil Technical Specification (TS) requirements. On March 28, 1982, the licensee's DG fuel supply was less than the 104,000 gallon TS minimum. The licensee reported the low fuel supply with-an LER (#2-82-08), which was reviewed in NRC Inspection 277/82-06. The inspector at that time expressed a concern regarding the adequacy of DG fuel oil Technical Specification; specifically the fuel oil storage and transfer system operability and the monthly check of fuel oil quantity. The inspector reviewed Technical Specification 3.9.A.2 and Technical Specification 4.9.A.1, and ST 8.1, DG Full Load Test. TS 4.9.A.1.C requires a monthly check of diesel fuel quantity, however the licensee performs the check daily pe-ST 9.1-22, the Surveillance Log. Technical Specification 4.9.A.1.a requires a monthly operability check of the diesel fuel oil transfer system and ST 8.1 performs this check weekly on the diesel fuel oil transfer pumps and day tanks.
Based on the above, this item is closed.
3.3 (Closed) Inspector Follow Item (277/81-24-04).
Review of off gas system design. The licensee performed modification #84-116 to re-place the Unit 2 compressed storage off gas system with an ambient charcoal absorber system. This modification was reviewed in NRC Inspection 277/85-08.
This item is closed.
3.4 (Closed) Unresolved Item (277/81-24-05).
Root valves not included on system prints.
The licensee is currently implementing a Critical Equipment Monitoring System (CEMS).
CEMS is a data acquisition and status system for plant equipment including all plant valves (remote-ly operated, manual, root, and instrument).
CEMS implementation in-cludes detailed system walkdown, equipment identification and rigging, and P&ID updating to include missing valves.- The licensee intends to continue with CEMS implementation until completion. Based on the above, the unresolved item for root valves is closed. The inspector will follow CEMS implementation.
3.5 (Closed) Violation (277/85-12-01).
Failure to maintain the seismic qualification of nitrogen bottle 0855385. This violation was caused by errors in judgment of operations personnel performing ST 7.9.2,
" Daily Check of Seismic Gas Supply Bottle Pressures".
The licensee instructed operations personnel on the requirements for seismic qual-ification of the nitrogen bottles and posted signs near the gas bot-tle racks to describe the seismic restraint requirements.
The inspector examined a sampling of the signs in the Unit 2 Reactor Building and the Rad Waste Building. The inspector had no further questions.
This item is closed.
3.6 (Closed) Violation (277/82-25-03).
Failure to write a Maintenance Request Form (MRF) for malfunctioning main steam line drain valves. '
The licensee responded to the violation in a letter dated February 25, 1983. The inspector reviewed the licensee's response and found
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it to be adequate.
The licensee had failed to investigate and docu-ment on a MRF the equipment malfunction.
The individuals involved were counseled. The inspector will continue to routinely check equip-ment status and MRFs for equipment malfunctions during daily tours.
Based on the above, this item is closed.
3.7 (Closed) Inspector Follow Item (277/83-12-04).
Control rod position indication probe (PIP) functional test. When a control rod PIP was replaced, a complete functional test was not performed.
The inspec-tor reviewed maintenance procedure M-3.1, Control Rod Drive Replace-ment, Revision 18, March 21, 1985 and ST-10.8, Control Rod Withdrawal Tests, Revision 10, December 12, 1984.
M-3.1 requires post mainte-nance testing including the performance of ST-10.8.
ST-10.8 requires a check of rod position information system (RPIS) during control rod exercising including the RPIS full in (green light), full out (red light) and notch positions.
Based on the above, this item is closed.
3.8 (Closed) Unresolved Item (277/84-15-03).
The licensee had previously noted that during lifting of the reactor vessel head,- the Unit 2 re-
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actor head strongback could contact the reactor building crane sup-port beams prior to actuation of the overtravel limit switch. ANSI B 30.2 requires the actuating mechanism on the limit device to be lo-cated so that it will trip the device under all conditions in suffi-cient time to prevent contact of the hook or load block with any part of the trolley or crane. The matter was unresolved pending licensee actions to correct the deficiency.
Under Modification 1494 the licensee replaced the one setpoint geared limit switch with a dual setpoint geared limit switch. This modification was performed on both Units c and 3.
The inspector reviewed the modification docu-mentation including:
the minutes of the PORC review; the Safety Evaluation dated January 2,1985; Maintenance Request Forms (MRF)
numbered 2-17-M8502009, 2-17-M8502010, 3-17-M 8502011, and 3-17-M8502012; and, the modification acceptance test, MAT 85-009, dated-May 9, 1985.
The inspector also discussed the modification with the Modification Engineer and maintenance engineering personnel.
The licensee's tests demonstrated that the load or hook could not make contact with the trolley or crane.
This item is closed.
3.9 (Closed) Inspector Follow Item (277/81-09-01).
ECCS room drain com-munication. To prevent room-to-room leakage, the licensee has plugged ECCS room drains. COL GP-2A, Reactor Startup Order, Revision 62, July 1,1985, step 6 has a sign-off for verifying ECCS room drains are plugged.
This item is closed.
3.10 (Closed) Inspector Follow Item (277/E5-21-01).
Emergency diesel gen-erator (DG) interpolar connector bars on Colt Industries supplied generators.
In May, 1985, a 10 CFR 21 report was made regarding Colt Industries generators at Calvert Cliffs.
Peach Bottom utilizes a similarly designed generator.
The generator has an interconnecting bar between adjacent poles on the rotor which could potentially break
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off causing damage to the generator stator. The failure mechanism was evaluated as fatigue cracking. The licensee removed the inter-polar connector bars on all four DGs per SP-813, DG Interpolar Connector Removal, Revision 0, June 14, 1985. The inspector observed the interpolar bars removed on the E-2 DG on June 17,1985 (reference NRC Inspection 50-277/85-25) and on the E-1 DG on July 30, 1985 (reference NRC Inspection 50-277/85-30). The interpolar bars were removed on the E-3 DG on September 23, 1985 and on the E-4 DG on September 4, 1985. The inspector reviewed the applicable MRFs for the E-3 DG (MRF 3-52-M8504945) and the E-4 DG (MRF 3-52-M8504946).
No unacceptable conditions were noted.
Based on the above, this item is closed.
3.11 (0 pen) Inspector Follow Item (277/85-08-04). The licensee identi-fied a problem with the control rod drive hydraulic control unit (HCU) scram outlet valve isolatf or valves (13-112) on Unit 2.
This valve (13-112) is the manual isolation gate valve on the scram dis-charge riser pipe. The problem concerns cracking of the valve stem to valve gate (disc) connection in one of 18 valves inspected. The cracking was completely through one wall of the valve disc connec-tion, however the other wall remained intact and no separation of the stem and disc occurred.
If separation were to occur, the valve disc (valve is normally open and is required to be open for control rod to scram) could potentially then " float" and jeopardize the capability of the control rod to sc'am. The Unit 2 valve supplier is Dresser, r
Inc. (Hancock valves) and the disc material is 420 stainless steel.
The inspector reviewed MRF 2-03-M8501589 which replaced all 185 HCU 13-112 valve discs, stems, and bonnet gaskets with supposedly less susceptible material, Type 410 stanless steel.
The HCU 13-112 valve maintenance was completed on March 26,.1985, and the operational verification form was cumpleted on June 21, 1985, prior to Unit 2 startup after the 1984-1985 pipe replacement outage.
This item remains open pending further NRC review of the material susceptibility question.
3.12 (Closed) Inspector Follow Item (277/85-08-01). Minor errors in P&ID M-358, Standby Liquid Control (SBLC) system.
The licensee submitted a drawing change request to correct the SBLC P&ID. The inspector reviewed P&ID M-358, Revision 15, dated March 25, 1985.
The missing
" locked closed (LC)" designations and incorrect valve identifications were corrected. This item is closed.
3.13 (Closed) Unresolv'ed Item (277/85-15-02). Certain battery rack cell spacer rods in the 125/250 VDC Class IE batteries were found not in-stalled as required by the battery vendor and a silicone compound not specifically identified by the vendor was used as a lubricant du' ring battery installation. The licensee reverified all battery rack nut-bolt torque settings and the inspector independently verified that none of the nuts was loose.
The licensee obtained written confirma-tion from the battery vendor that the silicone compound used during
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battery installation was compatible with cell materials. The inspec-p tor reviewed the vendor's response dated May 29, 1985, and had no further questions at this time.
This item is closed.
3.14 (Closed) Unresolved Item (277/85-15-04). - Uncovered fluid ports of-
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hydraulic snubbers.
The inspector reviewed the licensee's recently amended snubber Technical Specification (TS) (amendment ~107/111) dat-ed March-19, 1985,'and verified that the issue of' uncovered fluid ports is now addressed 'in 4.11.D.3 TS.
The licensee's TS 4.11.D.3
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contains the standard TS provision for uncovered fluid ports. This item is closed.
4.
Plant Operations Review 4.1 Station Tours The inspector observed plant operations during daily facility tours.
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The.following areas were inspected:
Control Room
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Cable Spreading Room
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Reactor Building
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Turbine Building
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l Radwaste Building
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' Pump House
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Diesel Generator Building
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Protected and Vital Areas
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Security Facilities (CAS, SAS, Access Control, Aux SAS)
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High Radiation and Contamination Control Areas
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Shift Turnover
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u4.1.1 Control Room and facility shif t staffing was frequently
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checked for compliance with 10 CFR 50.54 and Technical Specifications.
Presence of a senior licensed operator in the control room was verified frequently.
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4.1.2 The inspector frequently observed that selected control room instrumentation confirmed that instruments were opera-i ble and indicated values were within Technical Specifica-l tion requirements and normal operating limits.
ECCS switch
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positioning and valve lineups were verified based on con-trol room indicators and plant observations. Observations included flow setpoints, breaker positioning, PCIS status, and radiation monitoring instruments.
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'4.1.3 Selected control room off-normal alarms (annunciators)
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were discussed with control room operators and shift super-vision to assure they were knowledgeable of alarm status,
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plant conditions,- and that corrective action, if required, was being taken.
In addition, the applicable alarm cards were checked for accuracy. The operators were knowledge-able of alarm status and plant conditions.
4.1.4 The inspector checked for fluid leaks by observing sump status, alarms, and pump-out rates; and discussed reactor coolant system leakage with licensee personnel.
4.1.5 Shift relief and turnover activities were monitored daily, including backshift observations, to ensure compli-ance.with administrative procedures and regulatory guid-ance. No inadequacies were identified.
4.1.6 The inspector observed main stack and ventilation stack radiation monitors and recorders, and periodically reviewed traces from backshift periods to verify that radioactive gas release rates were within limits and that unplanned releases had not occurred. No inadequacies were identified.
4.1.7 The inspector observed control room indications of fire detection instrumentation and fire suppression systems, monitored use of fire watches and ignition source controls, checked a sampling of fire barriers for integrity, and ob-served fire-fighting equipment stations. No inadequacies were identified.
4.1.8 The inspector observed overall facility housekeeping conditions, including control of combustibles, loose trash and debris. Cleanup was spot-checked during and after maintenance.
Plant housekeeping was generally acceptable.
4.1.9 The inspector verified operability of selected safety related equipment and systems by in plant checks of valve positioning, control of locked valves, power supply avail-ability, operating procedures, plant drawings, instrumenta-tion and breaker positioning.
Selected major components were visually inspected for leakage, proper lubrication, cooling water supply, operating air supply, and general conditions. No significant piping vibration was detected.
The inspector review ~ed selected blocking permits (tagouts)
for conformance to licensee procedures.
During a tour of Unit 2 reactor building at 12:30 p.m. on December 26, 1985, the inspector noted that control rod hydraulic control unit (HCU) #22-11 was blocked out of ser-vice. The four directional control valve solenoids were unplugged and tagged, and the HCU isolation valves were closed and tagged. The inspector proceeded to the Control Room and noted that control rod #22-11 selector switch was blocke.
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The full core display indicated that the control rod #22-11 was at position 48 (full out) and the process computer OD-7, control rod notch positions also indicated that'the control rod was at position 48. The reactor was at 44%
power and power was constant while the feedwater level
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control system was being tested.
The inspector questioned the licensed operators and licensee engineers regarding the ability of control rod
- 22-11 to scram and the status of the shutdown margin for i
Unit 2.
Since the control rod #22-11 was blocked with the
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HCV isolation valves closed, at position 48, the rod would not scram on a reactor protection system actuation.
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licensee acknowledged the inspector's concern, and initiated
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action to remove the block in order to return control rod
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- 22-11 to an operable status, i
i The inspector reviewed the blocking permit and the MRF (#2'3-M8509148) which authorized removing control rod j
- #22-11-from service to perform corrective maintenance on i
a leaking HCU accumulator'.
The blocking permit was author-t ized at 10:20 a.m. and was completed (i.e., blocked out of service) by 12:05 p.m. on December 26, 1985. When the shift superintendent was informed of the situation by the i
inspector, the permit was cleared, the MRF cancelled, and i
the control rod #22-11 was returned to service by 1:45 p.m.
i on December 26, 1985. Unit 2 subsequently scrammed at 2:12 i
p.m. on December 26, 1985 (see detail 4.2.3).
- 22-11 did fully insert to notch position 00 as verified by
the inspector by checking the full core display rod l
position and the 00-7 computer printout.
j The inspector reviewed system operating procedure i
S.4.2.C, Removing a Control Rod and Its Hydraulic Con-i trol Unit from Service During Reactor Operation, Revi-
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sion 0, 12/15/72.
Step 1 of system procedure S.4.2.C
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requires placing the control rod in the full-in posi-tion.
Failure to perform this step prior to removing a
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control rod from service during reactor power operation I
is an apparent violation (277/85-40-01).
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Technical Specification (T.S.) 3.3.A.2 requires that if i
a fully or partially withdrawn control rod cannot be
moved with control rod drive or scram pressure, contin-
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ued reactor power operation is allowed if the shutdown
margin of T.S. 3.3.A.I is met.
T.S. 3.3.A.1 requires j
that a sufficient number of control rods be operable so i
that the core could be made sub-critical with the
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l strongest control rod stuck full out at the most nega-i tive condition. The inspector questioned whether or not i
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shutdown margin could be met with control rod #22-11 inoperable and full out, and the most reactive rod stuck full out at the most reactive core condition.
The licensee is evaluating this above condition. The abili-ty to meet shutdown margin requirements is unresolved pending licensee evaluation and NRC review.
(277/85-40-05)
The inspector asked if blocking control rods full out was a normal practice.
Licensee management indicated that it was not. The Shift Superintendent was unaware of the blocking permit and MRF. The MRF and permit were approved by the Control Operator (licensed reactor operator) and the Shift Supervisor (licensed senior reactor operator). The Unit 2 Reactor Operator was also aware of the control rod #22-11 block. The licensee indicated that the blocking sequence
- 3-1204, Rev. 2 would be revised to include the requirement that control rods blocked during reactor operations would be fully inserted as required by procedure S.4.2.C.
(A blocking sequence is a pre-defined permit for specific equipment blocking.) The licensee is preparing an LER regarding this occurrence.
The leaking accumulator for control rod #22-11 was replaced and returned to service prior to reactor startup on December 29, 1985. The inspector observed the post main-tenance control rod scram time testing per ST 10.13 (see detail 7) on December 31, 1985. The control rod scram times met the acceptance criteria of TS 3.3.C.
As noted above one violation and one unresolved item were identified.
4.1.10 On November 6, 1985, the inspector noted that the Containment Atmosphere Dilution (CAD) system oxygen ana-lyzer was inservice because the normal containment oxy-gen analyzer system was out of service.
Since the normal oxygen analyzer had been tested earlier that day and found to be satisfactory, the inspector questioned the cause of inoperability so soon after testing. After discussing the problem with the operators and reviewing completed ST 9.10 " Containment Oxygen Measurement and Analyzing System Functional Test", the inspector deter-mined tnat the failure was caused by water in the sample line. Water in the line occurred due to the temperature difference and the humidity considerations between the torus and Reactor Building.
The licensee indicated that they would drain the line more frequently to remove water in the line. The inspector did not observe any more failures of the containment oxygen analyzer system during the report perio,-
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No violations were identified.
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4.2 Followup On Events Occurring.During the Inspection i
j 4.2.1 Radwaste Building Cable Tray Fire i
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At 4:02 p.m. on November 10, 1985, smoke was reported by i
a roving fire watch on the 150 and 165 foot level of the j
common Rad Waste Building.
Unit 2 was at 100% power. The i
licensee's fire and damage team responded, and discov-ered a fire in a cable tray and in the diver's cage di-
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rectly below the cable tray at the 150 foot level of the
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Rad Waste Building. The fire in the tray was extin-
guished within a few minutes with portable carbon diox-
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ide and Ansul extinguishers and the fire in the divers
cage was extinguished with water.
Damage was confined
to a small section of the cable tray and associated ca-i bles and to the diver's cage. The affected equipment
included the liquid radwaste processing system and asso-l
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ciated controls.
No safety related cables nor equipment
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During the fire, voltage on the static
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inverter dippet. causing a Unit 2 EHC and recirculation
pump runback to 75% power. Although not required by 10 CFR
50.72, the licensee made an ENS call. The licensee
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identified the affected cables and replaced the damaged
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ones. Unit 2 was returned to 100% power on November 11,
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l The inspector toured the fire damage area on November 12, i
1985, and discussed the fire and damage team response with the licensee.
Cable tray RR020 on the 150' level of the
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Rad Waste Building was damaged by the fire. The inspector j
independently reviewed the listing of the cables in this l
tray, and determined no safety related equipment was
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affected. The cause of the Unit 2 runba-k to 75% power was
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de-energization of the reactor recirculation relays 2A-K8A
and 2A-K8AX (M-I-S-4, Revision 21) which placed the 60%
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speed limiter for both recirculation pumps into operation
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(M-I-S-6, Revision 13). The speed limiters thus decreased recirculation pump speeds to 60% resulting in a reactor l
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power decrease to 754 power.
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The licensee has conducted an investigation concerning
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the fire, however the cause of the fire is currently undetermined.
Pending identification of the cause of the fire by the licensee and NRC review, the item is unre-
solved.
(UNR 277/85-40-02)
NRC Inspection 50-277/85-41 further reviews this cable
tray fire.
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4.2.2 Reactor Scram During Plant Shutdown On November 29, 1985 At 12:02 p.m. on November 29, 1985, Unit 2 scrammed from 33% power while a planned shutdown was in progress.
The cause of the scram was turbine stop valve (TSV) closure. A malfunction in the TSV test circuitry apparently caused all 4 TSVs to close, resulting in a reactor scram.
The licensee declared an Unusual Event and made an ENS call per 10 CFR 50.72.
The-inspector monitored post scram recovery operations from the Control Room.
The Control Room recorder trac-es, computer event log and control room indications were reviewed. The inspector discussed the event with licensee operators and engineers.
The inspector re-viewed the completed GP-18, " Scram Review Procedure".
The scram response was normal. All control rods insert-ed and the reactor was shutdown.
Reactor level initial-ly decreased due to the shrink, however the reactor feed pumps remained on-line and recovered level to normal.
During the level decrease, PCIS groups II and III actu-ated on low reactor water level as required.
The PCIS signal was reset, and affected systems were returned to normal.
The licensee determined the cause of the scram to be main turbine stop valve (TSV) closure when #2 TSV closed during troubleshooting causing #1, #3 and #4 TSVs, which are slaves to #2 TSV, to also close. The licensee effected necessary repairs to the TSV controls.
The unit remained shutdown for a 4 week maintenance outage. No unacceptable conditions were identified.
4.2.3 Reactor Scram and Feedwater Transient on December 26, 1985 4.2.3.1 Event Summary and Sequence of Events Event Summary Unit 2 scrammed from 44% power on low reactor water level at 2:12 p.m. on December 26, 1985.
The cause of the level decrease was the loss of "A" reactor feed pump (RFP) on overspeed trip combined with feedwater level control system fluctuations.
The "B" and "C" RFPs were being swapped to troubleshoot RFP and level control instabilities identified during the reactor startup on December 25, 1985.
During the swapping of "B" and "C" pumps, the RFP check valves slammed three or more times
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causing a hydraulic transient in the RFP suc-
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tion piping.
The hydraulic transient resulted in the shearing off of a 1 inch drain line on the 20 inch suction piping to the "C" RFP, causing a steam and water leak in the turbine building. The licensee made an ENS call and declared an Unusual Event due to the unplanned shutdown.
Reactor water level decreased to-35 inches (-178 inches is the top of the ac-tive fuel). The MSIVs remained open and the
"B" RFP recovered water level to normal. When the feedwater leak was reported to the control room, the operators isolated the condensate and feedwater systems, and this action stopped the leak.
The RCIC system was manually start-ed to control reactor water level.
There was no radioactive release from the leak. No per-sonnel contamination occurred.
The main stack release was 0.6% of Technical Specification limit due to the scram and resultant offgas transient (normal release for a scram).
Sequence of Events Date Time Event December 24 9:56 p.m.
Reactor critical after 3 week outage December 25 6:05 a.m.
"C" RFP in service - reac-tor power 10%
December 25 2:15 p.m.
"B" RFP in service
"C" RFP would not control level in automatic December 25 4:00 p.m.
"C" RFP in service
"B" RFP would not control level in automatic December 26 5:00 a.m.
Generator synchronized to grid
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y December 26 11:30 a.m.
"A" RFP in service in manual, December 26 12:30 p.m.
for m'otor gear unit (MGU). reset (
by I&C
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December 26 2:00 p.m.
"B" and "D" RFPs being swapped -
"A" RFP in auto i
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- reactor at 44%
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and "B" and "C" RFP check valves t
begi'c hlareming
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December 26 2:11 p.m.
"A" RFP trips on i
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i overspeed December 26 2:12 p.m.
Reactor auto scrams on low water level -
Group II/III PCIS December 26 2:15 p.m.
Feedwater leak in turbine building
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December 26 2:19 p.m.
Reactor scram reset
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December 26 2:20 p.m.
ENS call to NRC December 26 2:45 p.m.
Feedwater leak isolated - RCIC
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controlling wa-
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ter level
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I 4.2.3.2 I.11tial Licensee Actions and NRC Review The Senior Resident Inspector was in the Con-trol Room at the time of the transient and scram. Operator post scram and recovery ac-tions were observed.
Theinspectorvefified
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that emergency trip procedures T-100, Scram i
and T-99, Post Scram Restoration were followed i
by the licensee. The trip procedures imple-
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mentation was coordinated by the Shift
Supervisor.
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The inspector observed control room indica-I tions for reactor water level, reactor power,
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control rod position, radiation monitoring
,
'
instrumentation, etc. The inspector verified that the reactor was shutdown by checking
source range instrumentation on scale and ver-ifying that all control rods were inserted.
-
The inspector noted that reactor water level i
decreased to -35" and was recovered to normal level with the "B" RFP. The inspector veri-
'
fled that PCIS Group II/III isolations actuat-
'
ed as required on low reactor water level.
No unusual nor unexpected releases occurred.
l The inspector observed licensee actions in response to the feedwater leak. The Control Room 'was informed of a leak in the feedwater line in the turbine building 135 foot level.
The licensee initially attempted to isolate the leak by closing the "C" feedwater heater string isolation valves, however the leak con-
,
tinued. The operators then started the RCIC system in manual, and removed the feedwater
,
and condensate systems from service.
This
action stopped the. leak. The inspector ob-l served RCIC system operations and vessel in-jections to control level.
Within the scope of the review of licensee
actions taken during the scram and feedwater
'
leak isolation, no unacceptable conditions
'
were noted.
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4.2.3.3 Damage Assessment
.
j The feedwater transient and water hammer caused by RFP check valves slamming resulted
,
j in damage to feedwater and condensate system
piping and supports. A one inch drain line was sheared off the 20 inch "C" heater string line t'
(18GF reference P&ID M-308, Rev. 20), result-ing in a feedwater leak into the turbine
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building. The inspector examined the damage to
'
the drain line and feedwater piping in the tur-bine building 135 foot level at 4:00 p.m. on December 26, 1985.
The drain line had been
,
sheared off at the pipe nipple apparently due to
!
movement of the 20 inch feedwater pipe. Most of l
the water that leaked out collected on the tur-bine building floor and went into the floor drains to radwaste.
Some water did leak down to
the 116 foot level of the turbine building where
,
'
the water was contained. The inspector toured
the turbine building 135 and 116 foot levels at j
4:30 p.m. on December 26, 1985. The inspector
'
noted that water was contained and radiological surveys were being performed. No spread of con-tamination occurred. The licensee repaired this
drain line on December 27, 1985.
The water clean
'
up was completed on December 26, 1985.
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The licensee initiated a walkdown of the feed-water and condensate system piping and supports by the corporate mechanical engineering group, test engineers and maintenance ISI group. These walkdowns identified numerous piping and support deficiencies. The deficient items were cate-
.
gorized by priority, responsible group, MRF
'
number and estimated time to repair. The licensee utilized a priority "1" for those items i
that were required to be repaired prior to restart.
The inspector performed an independent walkdown of selected feedwater and condensate system piping, supports and components. Deficiencies noted by the inspector were cross checked against the
'
licensee's deficiency list. All items noted by the inspector were previously identified by the licensee and included on the licensee's itemized list. The licensee marked up sets of P& ids and
!
l isometric drawings to perform these walkdowns and
- .
to document the noted deficiencies.
The inspec-tor reviewed the licensee's marked up drawings.
The 18 priority "1" items were repaired by the licensee prior to restart on December 29, 1985.
The remaining items are documented on MRFs and
!
will be repaired on a schedule to be determined by the licensee. No violations were identified.
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4.2.3.4 Event Cause On December 26, 1985, just prior to the event, the unit was operating at 44% reactor power with
"A" Reactor Feed Pump (RFP) in auto, and "B" and
"C" RFPs in manual.
The "B" and "C" pumps were being swapped to troubleshoot the Feedwater Level Control System (FWLCS) instabilities experienced earlier during startup. During the swapping process, the discharge check valves on "B" and
"C" RFPs began cycling when the operators attempted to close the discharge motor operated valve (MOV) of the "C" pump while bumping open the discharge MOV of the "B" pump. The initia-tion of the check valve cycling is theorized to be caused by the parallel operation of the "B" and "C" pumps with their discharge MOVs being partially open and moving in opposite directions (the "B" MOV opening and the "C" MOV closing).
When the "B" pump introduced increased flow and pressure to the common feedwater header, as a re-sult of the existing manual signal, the
"C" dis-charge check valve slammed closed due to the in-creased back pressure.
Subsequently, when the increasing discharge pressure of the "C" pump opened the "C" discharge check valve, the resul-ting increased flow and pressure to the common header slammed closed the "B" discharge check valve.
Cycling of the check valves conti.nued for a period of time, about one to two minutes, because the closing stroke time of the "C" dis-charge MOV was long, about three to four minutes.
The long MOV stroke time is attributed to the large differential pressures across the valve gate created by the cycling check valves.
The extended cycling of the check valve caused a hydraulic transient and a water hammer in the feedwater piping which in turn caused the damage described in section 4.2.3.3 above.
When the "C" pump speed was subsequently re-duced to its low speed stop (LSS), the "C" discharge valve closed and remain'ed closed.
The "C" pump flow went to zero which caused the speed of "A" pump which was in auto to go to maximum in response to the level signal from the FWLCS.
Subsequently, when the "B"
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discharge MOV was fully opened and additional flow and pressure from this pump was intro-i duced to the common feedwater header as a re-sult of the existing manual signal, the "A" discharge check valve closed and the "A" pump flow decreased to zero. When the operator
responded by switching.the "A" pump control to
'
manual and manually increased its speed, the
"A" pump tripped on overspeed. The reactor was
at 44% power with one RFP operating in manual control and reactor level decreasing. The resul-ting low reactor water level transient caused a
reactor scram and a Group II and III primary l
containment isolation.
The cause of the feedwater transient and the resulting scram is attributed partly to lack of adequate procedural guidance for swapping
,
the RFPs. The operator currently uses a com-bination of two operating procedures for this purpose: (1) S.7.6.B. Placing Second and-Third Reactor Feed Pumps In Service, Revision 5 and (2) S.7.6.C,. Shutdown of a Reactor Feed Pump Turbine, Revision 3.
The operator executes these two procedures concurrently which in-volves opening of the discharge MOV~for the pump being started and closing of the dis-charge MOV for the pump which is to be subse-
'
quently stopped.
During the operation, a good deal of operator judgement'is required in bal-ancing the flows between the pumps. Operating with 3 RFPs in parallel and in manual control at low power levels (i.e., 44%) with reduced RFP l
flows is a complex situation for reactor water
level control.
Imperfect RFP manipulation could induce the check valve cycling such as that which was experienced during the event.
~
The licensee indicated that RFPs would no longer
be swapped at such power levels.
Power would be reduced to approximately 25 percent (1 pump oper-ation limit), the pump to be taken out of service would be stopped, the desired pump would be started, and then power would be increased to the original or desired level.
By this method, the complex operation of balancing the flows between the 3 pumps during the swapping operation is avoided.
The licensee plans to prepare and issue a new or revised operating procedure for the revised mode of operation. Until the new procedure is issued,
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by a memo dated December 27, 1985, the licensee issued an interim instruction to the operator not to attempt the swapping operation.
No violations were identified.
4.2.3.5 Corrective Actions The licensee's short term corrective actions include:
Conducted a walkdown of the damaged systems
--
- completed on December 27, 1985.
Repaired 18 Priority I items from the
--
list of damages - completed on December 29, 1985. The Maintenance Request Forms (MRFs) for the remaining items are initi-ated and will to be repaired on a sched-ule to be determined by the licensee.
Issued an Upset Report for the event,
--
including sequence of events, discussion and analysis of the event - completed on December-28, 1985~.
Issued interim guidance to the operators
--
preventing swapping of the RFPs until the new procedure is issued - completed on.
December 27, 1985.
The Senior Resident Inspector reviewed the above short term actions in preparation for the plant restart.
This review was completed on December 28, 1985. The plant was restarted up on December 30,.1985. The RFPs were tested satisfactorily on December 30 and 31, 1985.
The licensee's long term corrective actions include the preparation and issue of a new or revised operating procedure for exchange of RFPs at ie.termediate power levels (see sections 4.2.3.4 of this report)..
Revision of the opera-ting procedure is an unresolved item pending com-pletion of the above action by the licensee and review by NRC (UNR 277/85-40-03).
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i 4.3 Logs and Records
'
The. inspector reviewed logs and records for accuracy, complete ~
ness, abnormal conditions, significant operating changes and trends, required entries, operating and night order propriety, correct equipment and lock-out status, jumper log validity, con-formance to Limiting Conditions for Operations, and proper report-Ing. The following logs and records were reviewed: Shift Supervision Log, Reactor Engineerin'g Log, Reactor Operator's Log, j
Control Operator Log Book and STA Log Book, Night Orders, i
'
Radiation Work Permits, Locked Valve Log, Maintenance Request
Forms and Ignition Source Control Checklists. Control Room logs i
were compared against Administrative procedure A-7, Shift i
Operations.
Frequent initialing of entries by licensed operators, shift supervision, and licensee on-site management constituted i
evidence of licensee review. No unacceptable conditions were identified.
4.4 Engineered Safeguards Features (ESF) System Walkdown The inspector performed a detailed walkdown of portions of the RHR
system in order to independently verify the operability of the "A"
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loop of the RHR system. The RHR "A" system walkdown included ver-l ifications of the following items:
--
Inspection of system equipment conditions.
!
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Confirmation that the system check-off-list (COL) and operat-t ing procedures are consistent with plant drawings.
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Verification that system valves, breakers, and switches are
properly aligned.
i Verification that instrumentation is properly valved in and
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Verification that valves required to be locked have appropri-
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-ate locking devices,
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Verification that control room switch positions, indications
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and controls are satisfactory.
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Verification that surveillance test procedures properly im-t plement the Technical Specifications surveillance requirements.
-Within the scope of the ESF walkdown, no unacceptable conditions i
were identified.
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5.
IE Information Notices Which Require No Response The inspector reviewed licensee actions regarding IE.Information Notice-No. 84-70 Supplement 1, dated August 26, 1985, regarding reliance on water level instrumentation with a common reference leg. The above referenced Notice delineates an event at another BWR during reactor startup where plant licensed operators incorrectly concluded that a low level indication on the GEMAC narrow range instrument was erroneous, which led to the undetected inoperability of the two RPS. level switch instruments due to reference leg leakage.
The inspector reviewed the Peach Bottom reactor level instrumentation including the following items:
type of reference log columns (YARWAY vs. GEMAC) and those instru-
--
ments which share columns
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level instrumentation panel device nrmbering and nomenclature, range, panel indications, local racks and logging requirements level instrumentation calibration procedures and conditions (i.e.,
---
calibrated hot or cold)
Technical Specification sections 3.1.1, 3.2.A,B,F,G requirements
--
and instrumentation functions (i.e., indication, alarm, device initiations,etc.)
--
Licensed operator awareness and knowledge of level instrumentation and associated formal training The inspector interviewed selected reactor operators and determined they were knowledgeable of reactor level instrumentation.
During re-view of licensed operator training lesson plan, LOT-050, Reactor Vessel Instrumentation, November 7, 1984, minor errors were noted in two of.
the transparencies. These transparencies describe how to correct indi-cated level ~to actual level for reactor conditions other than normal operating temperature and pressure. The inspector discussed these training lesson plan minor errors with licensee training and operating personnel who indicated corrections would be made.
In addition, during discussions with licensee operational personnel, it was indicated that reactor level indicatiot, panel nomenclature is being upgraded to identify which instruments share common reference legs.
The upgrade is part of the overall control room upgrade. No violations'were identified.
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6.
Review of Licensee Event Reports (LERs)
6.1 LER Review The inspector reviewed LERs submitted to NRC:RI to verify that the details were clearly reported, including the accuracy of the de-scription and corrective action adequacy. The inspector deter-mined whether further information was required, whether generic implications were indicated, and whether the event warranted on-site followup. The following LERs were reviewed:
LER No.
LER Date Event Date Subject 2-85-21-Motor Driven Fire Pump out of service
' November 27, 1985 September 30, 1985
'
November 15, 1985 reactor feedwater pumps October 17, 1985 2-85-23 November 21, 1985
- Electrical Separation Criteria
October 22, 1985
- 2-85-24 Primary Containment Isolation Valves December 6, 1985 November 3, 1985 6.2 On-Site-Followup For LERs selected for on-site followup and review (denoted by as-
terisks above), the inspector verified that appropriate corrective action was taken or responsibility assigned and that continued
,
operations of the facility was conducted in accordance with Tech-nical Specifications and did not constitute an unreviewed safety question as defined in 10 CFR 50.59.
Report accuracy, compliance with current reporting requirements and applicability to other site systems and components were also reviewed.
6.2.1 LER 2-85-22 concerns a reactor scram on low reactor level from 100% power due to loss of reactor feedwater.
This event was reviewed in NRC Inspection 277/85-29. No inadequacies were noted relative to this LER.
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6.2.2 LER 2-85-24 concerns an inoperable containment isolation valve and subsequent failure to follow the required Technical Specification action.
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At 3:00 p.m. on November 1, 1985, ST 6.2, PCIS Normally Open Valves, Revision 12, was performed unsatisfactorily due to failure of two of the seven containment oxygen analyzer solenoid valves, SV-2671A and SV-2671C.
These solenoid valves are normally open 1/2 inch valves locat-ed in the torus room which fail. closed on a. loss of
[
power.
A redundant solenoid valve (SV-2978A thru G) is in se-
'
ries with each of the seven above mentioned valves (2671A thru G). The redundant solenoid valve is locat-ed in the reactor building.
Reference P&ID M-367, Con-tainment Atmosphere Control, Revision 17. All-14 of these solenoid valves are listed in TS Table 3.7.1 as primary containment isolation valves. Operation of valve SV-2671A caused blown fuses and therefore the valve failed the ST 6.2.
SV-2671C failed the ST 6.2 due to j
failure of the valve to isolate flos When the inoperable valves were di" e _ red, the licensee
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.
implemented ST 5.3, Inoperable ' e.ation Valve Position i
Daily Log, Revision 4 and applied a permit (#2-85-318)
to block the two manual valves (upstream of SV-2671A and C) as required by TS 3.7.D.2 and TS 4.7.D.2.
MRFs were also initiated for SV-2671A (2-7-M8507623) and for
!
SV-2671C (2-7-M8507676).
f The licensee repaired SV-2671A by replacing the solenoid coil and the valve internals. At 1:35 a.m. November 3,
1985, the permit (#2-85-318) which blocked the two manu-al valves for both SV-2671A and C was cleared, and the manual valves were opened.
However, SV-2671C had not been repaired and therefore remained inoperable. At 11:30 a.m.
on November 4, 1985, the licensee's STA noted that valve SV-2671C was inoperable, however the TS 3.7.D.2 action
requirement to isolate the line was not being implemented.
At 11:45 a.m., the licensee initiated a permit (#2-85-319)
to block the SV-2671C manual valve and implemented ST-5.3
'
for the inoperable containment isolation valve to comply with TS 3.7.D.2 and TS 4.7.D.2.
In addition, the licensee initiated a permit (#2-85-320) to block the SV-2671A, because
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valve operation was still blowing fuses and the valve i
failing in the closed position.
The licensee.was in non-compliance with TS 3.7.D.2 (isolating the line with an.
inoperable containment isolation valve) and TS 4.7.D.2 (daily recording the position of another valve in the line having the inoperable valve) for approximately 34 hours3.935185e-4 days <br />0.00944 hours <br />5.621693e-5 weeks <br />1.2937e-5 months <br />.
- The inspector reviewed the above referenced two MRFs and three blocking permits, the completed ST 6.2 and ST 5.3, and discussed the event with the licensee.
The cause of the event was reported by the licensee in the LER as failure of the on-shift licensed operator to adequately ensure that maintenance was completed on both solenoid
- valves SV-2671A and C prior to clearing the blocking permit #2-85-318.
This operator was counselled on his actions. The entire operating shift was instructed that permits used'as administrative controls should include specific purpose and conditions necessary for removal of the permit. The inspector verified these licensee
- corrective actions by conducting interviews with li-censed operators and spot checks of shift permits.
- Failure to follow TS 3.7.D.2 and TS 4.7.D.2 for inopera-ble containment isolation valves is a violation of Tech-nical Specifications, however because the NRC wants to encourage and support licensee initiative for self-identification and correction of problems no notice of violation is issued since (1) the licensee identified the problem, (2) it fits Severity Level IV or V, (3) the
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violation was reported as an LER, (4) measures were tak-
~
en to correct the problem and additional measures were taken to prevent recurrence, and (5) it is not a viola-tion that could reasonably be expected to have been pre-vented by correction of a previous violation.
In
addition, this event is mitigated by the operability of redundant isolation valves, SV-2978A and C, in the 1/2 inch lines containing the SV-2671A and C valves. The
'
inspector had no further questions at this time.
7.
Surveillance Testing j
The inspector observed surveillance tests to verify that testing had
'
been properly scheduled, approved by shift supervision, control room l
operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were avail-
.
-able for service as required, test instrumentation was calibrated, work was performed by qualified personnel, and test acceptance criteria were met. Parts of the following tests were observed:
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ST 6.14, River Temperature Monitoring, Revision 9, 1/3/84, per-
--
formed on November. 26, 1985.
ST 9.12, Reactor Vessel Temperature, Rev. 7, 8/10/84, performed
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once per shift while shutdown.
ST 9.12C, Reactor Vessel Head Flange Temperature Surveillance,
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Rev. 0, 9/1/83, performed hourly while the vessel head is ten-sioned and less than 212 degrees F.
-ST 9.17, Reactor Coolant Leakage Test, Revision 5, 6/20/85, per-
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formed on November 26, 1985.
ST 2.5.14, Functional Check of the RPS "A" Card File, Revision 9,
--
3/12/84, performed on December 3, 1985.
ST 2.5.16, Functional Check of the RPS "C" Card File, Revision 10,
--
6/20/84, performed on December 3, 1985.
ST 10.13, CRD Scram Insertion Timing of Selected Control Rods,
--
Revision 3, 10/11/85, performed on CRD's 22-11 and 30-27 on December 31, 1985.
In addition, a review of the following completed surveillance tests was performed:
ST 15.80.5B-3, Functional Test of U/3 165' Radwaste Bldg. Smoke
--
Detectors, Rev. 0, 9/22/83, performed on February 7, 1984 and Jan-uary 19, 1985.
--
ST 15.80.58-2, Functional Test of U/2 165' Radwaste' Bldg. Smoke Detectors, Rev. O, 9/22/83, performed on February 7, 1984 and Jan-uary 19,1985.
--
ST 15.80.5A-2,3, Calibration Test of the 165' Radwaste Bldg. Smoke Detectors, Rev. O, 9/27/85, performed on July 24, 1985 and Septem-ber 11, 1984.
--
ST 6.2, PCIS Normally Open Valves, Revision 12, 7/26/85, performed on November 1, 1985.
--
ST 5.3,~ Inoperable Isolation Valve Position Daily Log, Revision 4,
'10/30/84, performed on November 1, 2, 4-7, 1985.
No inadequacies were identifie.
8.
,RHR Pumps Based on impeller wear ring failures on the Unit 3 RHR pumps (reference NRC Inspection 278/85-41), the licensee inspected the internals of the 2A and 2C RHR pumps during the period December 1-3, 1985.
In addition, the 2A RHR was scheduled to be inspected during the December, 1985 out-age as a result of flow and pressure abnormalities (reference NRC In-spection 277/85-29,278/85-33).
The results of the licensee's inspections (memo dated December 6,1985)
of the 2A and 2C RHR pumps were as follows:
The 2A RHR pump impeller wear rings were intact, and initially showed
--
no signs of cracking.
Subsequent visual inspections revealed surface cracks on the impeller wear rings.
The impeller suction vanes were much thicker than the normal feathered vanes on other RHR pumps.
The 2C RHR pump impeller showed signs of mechanical wear on the suc-
--
tion vanes and pump internals.
No cracked wear rings were identified.
The 2A RHR pump impeller and motor had been replaced in June, 1982, due to motor rubbing and pump seal failure.
The 2C RHR pump had the original impeller.
The inspector examined the 2A RHR pump impeller on December 12, 1985.
The inspector noted that the impeller wear rings were intact and that the suc-tion vanes were not feathered as were the other RHR impellers. On December 30, 1985, the inspector examined the 2A RHR pump impeller lower wear ring.
Several surface cracks about 1/2 inch long were visible to the naked eye.
The licensee repaired both the 2A and 2C RHR pumps with replacement impel-lers. The 2C RHR pump was tested satisfactorily on December 10, 1985, and the 2A RHR pump on Decembe'r 13, 1985.
The inspector reviewed the results of ST 6.8, RHR "A" Pump Valve, Flow and Unit Cooler Functional, Revision 29, performed on December 20, 1985.
ST 6.8, for pumps 2A and 2C, demon-strated that acceptance criteria for flow and pressure were met.
Based on the results of the six RHR pump inspections (4 pumps on Unit 3; 2A and 2C on Unit 2) and based on the 2B and 2D RHR pump performance, the licensee decided not to inspect the 28 and 2D RHR pumps prior to Unit 2 restart. The inspector questioned the licensee's basis for this decision and a NRC/ Licensee conference call was held on December 13, 1985 to dis-cuss the basis for restarting Unit 2.
The licensee stated that only one RHR pump (3C) experienced a catastrophic inservice failure and the failure occurred after three days of pump run with high bearing temperatures that were not noticed.
The six RHR pumps were repaired with either a new or a repaired impeller and tested satisfactorily.
The licensee committed to the following for the 28 and 2D RHR pumps:
.
.
Increase the frequency of ST 6.9, which includes testing and mon-
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itoring pump flow, discharge pressure and running current, from monthly, as currently required by the Technical Specifications, to weekly.
Conduct 28 and 2D RHR pump internal inspections within 120 days after
--
Unit 2 startup.
Monitor bearing temperatures during pump operation.
--
The inspector reviewed Unit 2 RHR pump test data since 1983.
The test data was compiled by the licensee based on surveillance test results.
The following parameters were trended in tabular format and graphically:
--
pump differential pressure (PSI)
motor amps
--
--
pump vibration (mils)
pump flow.(gpm)
--
The inspector discussed the RHR pump test data with the licensee. The inspector asked if any trend information could be detected.
The licensee noted a degraded performance in 2A RHR pump (reference NRC Inspection 277/
85-29).
In addition, the 2D RHR pump was in the " alert" range for differ-ential pressure for the ASME Section XI ISI criteria since the 1984-1985 refueling.
The " alert" range is defined as between 0.90 and 0.93 of the reference value of 250 psi differential pressure (225 to 232.5 psi).
The 2D RHR pump met the TS flow requirements of 11,500 gpm. As of May 26, 1985, the licensee doubled the 2D RHR pump test frequency required by ASME Section XI, paragraph IWP-3230.
At 6:45 a.m. on December 21, 1985, the 2D RHR pump experienced several motor overcurrent alarm conditions while in the shutdown cooling mode of operation. The licensed reactor operator stopped the pump ~ and the licensee inspected the pump and motor for damage.
The motor inspection identified no damage; however, the pump lower impeller wear ring was broken and off the impeller, and a 6" section was missing. The. licensee conducted a search for the missing section and found nothing. The licensee concluded that the missing piece was essentially ground away by impeller rubbing.
The licensee repau ed the 2D RHR pump with a replace-ment impeller with new wear rings.
The inspector discussed the overcurrent condition and event with the licensee operators.
The operators observed a motor current of 335 amps on control room indications.
The normal running current is 240 amps.
The inspector reviewed alarm card #203D-3 and verified that the opera-
~
tors took appropriate immediate corrective actions on the alarm conditio.
.
The inspector reviewed the surveillance test data for the 2D RHR pump prior to failure. The test, ST-6.9F, was run on December 19, 1985, and the results were satisfactory.
The inspector reviewed operating logs and determined the 2D RHR pump had been run on shutdown cooling after ST 6.9F completion from 11:45 p.m. on December 19, 1985, to 6:45 a.m. on December 21, 1985 when the overcurrent alarms occurred. The run time was 31 hours3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br />.
The inspector observed portions of the 2D RHR pump and motor maintenance on December 23, 1985. The maintenance was being performed in accordance M10.1,. Residual Heat Removal (RHR) Pump Maintenance, Revision 4.
The 2D RHR pump was repaired, tested and declared operable on December 24, 1985.
The inspector reviewed the ST-6.9 test results for the 2D RHR pump and all test acceptance criteria were met.
The licensee is currently drafting a formal report addressing the RHR pump failures. The report will include maintenance findings and evaluations, engineering evaluations and historical test results, repair activities and conclusions.
The inspector will continue to follow the RHR pump testing and inspection
,
plans for.the 2B RHR pump.
The inspector will also review the licensee's
'
formal report on the RHR pumps when it is completed (IFI 277/85-40-04).
9.
Radiation Protection During this report period, the inspector examined work in progress in both units, including the following:
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Health Physics (HP) controls
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Badging
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Protective clothing use
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Adherence to Radiation Work Permit (RWP) requirements
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Surveys
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Handling of potentially contaminated equipment and materials The inspector observed individuals frisking in accordance with Health-Physics procedures. A sampling of high radiation doors was verified to be locked as required. Compliance with RWF 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 un-acceptable conditions were identified.
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10.
Physical Security
The inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, includ-ing: operations of the CAS and SAS, checks of vehicles on-site to ver-ify proper control, observation of protected area access control and badging procedures on each shift, inspection of physical barriers, checks on control of vital area access'and escort procedures. No inad-equacies were identified.
i 11.
In-Office Review of Public and Special Reports 1-The inspector reviewed the following:
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Report of Plant Startup Following Sixth Refueling Outage, dated October 28, 1985
Within the scope of this review, no unacceptable conditions were identified.
12. Mechanical and Hydraulic Snubbers Based on the high number of functional test failures (47 of 71) of me-chanical snubbers on Unit 3, the licensee is currently replacing Unit 2 mechanical snubbers, except-for six recently installed snubbers on the recirculation system pumps and on the RBCCW system.
The replacement mechanical snubbers are from Limerick and have never been used.
The inspector determined that the licensee has also performed a visual inspection of the snubbers per ST.9.15-28 on December 1-3, 1985, and has made a preliminary assessment that identifies five mechanical and three hydraulic snubbers as-inoperable.
Final determination of opera-
bility status was performed by corporate engineering.
l The inspector was concerned that the removed snubbers were not to be tested until.a later date and that all snubbers removed should be tested i
for freedom of motion since they could have caused damage to the supported piping or component if locked. The licensee had a similar concern and was
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.
performing tests for freedom of motion through the entire stroke range for all of the removed mechanical snubbers. Additionally, the licensee initia-
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ted plans for testing all removed mechanical snubbers.
Snubber testing was completed on December 19, 1985. The test results were as follows:
-Snubbers Failure Mechanism (s)
Size Number Acceleration Test Drag Test Damaged
PSA-35
0
0'
PSA-10
15
0 PSA-3
0
0 i
PSA-1
0
1 PSA-1/2
0
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The inspector reviewed the vendor test documentation for snubbers trans-ferred from Limerick and for the six recently installed on the recircula -
tion system pumps. No inadequacies were identified.
The inspector' reviewed the engineering safety evaluation dated December 20, 1985, performed by the licensee regarding snubber failures as required by TS 4.11.D.6 The evaluation concluded that the inoperability of noted snubbers had no adverse effects on piping systems and components and did-not result in an adverse condition.
No inadequacies were identified.
13. Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable violations or deviations.
Unresolved items are discussed in details 4.1.9, 4.2.1 and 4.2.3.5.
14.
Inspector Follow Items Inspector follow items are items for which the current inspection findings are acceptable, but due to on going licensee work or special inspector interest in an area, are specifically noted for future follow-up. Follow-up is at the discretion of the inspector and regional management. An inspector follow item is discussed in Detail 8.
15. Management Meetings 15.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the Assistant Station Superintendent at the conclusion of the inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the residuit inspectors. No written inspection material was provided to the. licensee during the inspection.
No proprietary information is included in this report.
15.2 Attendance at Management Meetings Conducted by Region-Based
Inspectors The resident inspectors attended entrance and exit interviews by
,
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region-based inspectors as follows:
Inspection Reporting Date Subject Report No.
Inspector October 28 (Ent)
Fire 85-39 Pullani November 1 (Exit)
Protection -
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Alternate Safe
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Shutdown l
Modifications i
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Inspection Reporting Date Subject Report No.
Inspector November 13 (Ent)
Cable Tray 85-41 Krasapoulos Fire November 25 (Ent)
Security 85-43 Bailey November 27 (Exit)
November 14 Enforcement 85-42 Pasciak Conference -
Transportation
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