IR 05000277/1986013
| ML20206S729 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 09/09/1986 |
| From: | Eselgroth P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20206S726 | List: |
| References | |
| 50-277-86-13, 50-278-86-14, NUDOCS 8609220359 | |
| Download: ML20206S729 (24) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
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Report No. 50-277/13 & 50-278/14 Docket No. 50-277 & 50-278 License No. OPR-44 & OPR-56 Licensee: Philadelphia Electric Company 2301 Market Street Philadelphia, Pennsylvania 19101 Facility Name:
Peach Bottom Atomic Power Station Units 2 and 3 Inspection At: Delta, Pennsylvania Inspection Conducted: July 4 - August 15, 1986 Inspectors:
T. P. Johnson, Senior Resident Inspector J. H. Williams, Resident Inspector Approved By:
f-k84 Peter W. Eselgr Chief date DRP, Section 2 Inspection Summary:
Routine, on-site regular and backshift resident inspection (140 hours0.00162 days <br />0.0389 hours <br />2.314815e-4 weeks <br />5.327e-5 months <br /> Unit 2; 138 hours0.0016 days <br />0.0383 hours <br />2.281746e-4 weeks <br />5.2509e-5 months <br /> Unit 3) of accessible portions of Unit 2 and 3, operational safety, radiation protection, physical security, control room activities, licensee events, surveillance testing, outage activities, maintenance, and outstanding items.
Results: Two scrams on Unit 3 were caused by electrical faults and equipment failure. The RPS alternate power supply feeder breakers experienced a failure.
Corrective action on lighted control room alarms is not always timely.
The lubrication program implementation is unresolved. A procedural violation occurred, identified by the licensee, for work on safety related equipment without a MRF and blocking permit.
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OETAILS 1.
Persons Contacted J. W. Austin, Superintendent Peach Bottom Section Construction Division A. L. Blanchard, Assistant General Superintendent, Construction Division
- J. B. Cotton, Superintendent Plant Services
- R. S. Fleischmann, Manager, Peach Bottom Atomic Power Station A. A. Fulvio, Technical Engineer A. E. Hilsmeier, Senior Health Physicist R. M. Jones, Senior Engineer, E&R QC J. F. Mitman, Maintenance Engineer 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, Staff Engineer
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Other licensee emplenes were also contacted.
- Present at exit interview on site and for summation of preliminary findings.
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2.
Plant Status 2.1 Unit 2 Unit 2 began the inspection period at full power. On July 18, 1986, the unit reduced power to less than 30% to remove the turbine generator from service. Repairs were made to steam leaks on the moisture separator lines and the unit was returned to full power on July 20, 1986.
On August 7, 1986, the unit was shutdown to repair a steam packing
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leak on RCIC valve A0-22. W:
'e the unit was shutdown, other l
maintenance and testing was p=. formed. At the end of the l
inspection period the unit remained shut down for EQ inspections l
of Limitorque wiring (see detail 12).
2.2 Unit 3 Unit 3 began the inspection period at full power.
Loss of one
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reactor feed pump occurred on July 5, 1986, causing a runback to
67% power (see detail 4.2.1).
The unit was returned to full power
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on July 6,1986.
Load drops occurred daily due to main power l
transformer high oil temperatures. On July 13, 1986, the 3A recirculation pump inner seal failed (see detail 4.2.2).
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The unit scrammed on high flux from 87% power on July 19, 1986, due to loss of one off-site power source which caused one MSIV to close (see detail 4.2.3).
The unit remained shut down for 12 days to perform maintenance and testing activities. The unit restarted on July 31, 1986.
During the power ascension the 3C condensate pump failed, limiting power to 85-86%.
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On August 11, 1986, the unit scrammed on low level from 86% powcr (see detail 4.2.5) when a breaker fault in a non-vital motor control center caused a loss and trip of one reactor feed pump.
At the end of the inspection period the unit remained shut down for EQ inspections of Limitorque wiring.
3.
Previous Inspection Item Update 3.1 (0 pen) Inspector Follow Item (277/86-03-01).
Reactor Protection System (RPS) Power supply Trip Circuit Breakers. Tne licensee submitted a 10 CFR Part 21 report dated June 16, 1986, regarding the recent failures of the shunt trip coils on the Westinghouse circuit breakers in the RPS. The licensee determined that the failures were caused by a combination of breaker misoperation in the presence of a minor manufacturing defect. The misoperation
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entails reclosing the breaker with a trip signal present. The manufacturing defect is described as " insufficient spin-over",
whereby extra metal on the bottom of a rivet on the breaker handle post causes binding between the handle and the operating mechanism.
The licensee's corrective actions include the actions described in NRC Inspection 277/86-03 and 278/86-03; and hardware modifications planned to add a series circuit interlock to each RPS shunt trip coil circuit to ensure that the shunt trip coil is not energized beyond its momentary rating. The modification (MOD 1916) is scheduled as follows: Unit 2 refueling outage, March 1987; and Unit 3 mid cycle outage, January 1987.
The inspector reviewed the 10 CFR Part 21 report and discussed it with licensee engineers. (The inspector also discussed MOD 1916 with licensee modification engineers.) The inspector will continue to follow th'e licensee's short term and long term corrective actions.
With Unit 3 at full power and RpS power being supplied by the MG set normal feed, at 2:55 a.m. on July 10, 1986, the alternate RPS power supply breakers tripped. The breakers were reclosed at 3:05 a.m., and the licensee performed ST 13.54, "RPS Breaker Coil Continuity Check" at 5:00 a.m.
The licensee determined that both shunt trip coils on the RPS breakers had failed. These alternate I
supply RPS breakers were not in service at the time of failure.
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The alternate supply is powered from the E-134-W-A motor control l
center which is fed from the #3 startup and emergency (3 SUE)
off-site power source.
Frequent voltage transients on 3 SUE
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(apparently due to the #1 transformer outage in the North Substation) have resulted in numerous trips of the alternate RPS breakers. The failure mechanism for these two breakers is currently under review by licensee engineering.
Replacement breakers were installed and tested satisfactorily.
The licensee is currently pursuing a modification (MOD #1359) for a new static
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inverter or equivalent power supply for the Unit 2 and 3 RPS alternate feed supply. This modification was also stated in the
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corrective actions of LERs 2-86-04, 2-86-06 and 3-86-01.
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LERs were reported by the licensee when the alternate RPS power supply was in service. Subsequent large motor starts (i.e.,
recirculation MG set) caused a voltage dip on the #2 or #3 startup i
source resulting in emergency bus (E-12) voltage dips. The E-1 bus voltage transient then resulted in trip of the alternate RPS supply, causing a half scram, half PCIS Group I isolation, and
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PCIS Group II/III isolations.
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l The inspector discussed this event with licensee engineers and
operators. The proposed modification for static inverters remains
under engineering review.
Since the repair of the RPS alternate f
supply trip breakers, voltage transients continue to cause breaker trips. After each trip, the licensee recloses the breakers and l
performs ST 13.54. The inspector will continue to follow this i
testing.
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The inspector follow item remains open pending completion of the l
modifications to the RPS breakers and to the feed for the j
alternate RPS power supply.
3.2 (Closed) Violation (277/85-40-01).
Failure to place control rod
- 22-11 full in prior to removing from service. The licensee
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responded to the violation in a letter dated March 13, 1986. The
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inspector reviewed the licensee response and determined it to be L
adequate. The licensed operators involved were disciplined.
The blocking sequence was revised to include a cautionary note to ensure that a control is full in prior to maintenance. The inspector interviewed selected licensed operators regarding the event and the corrective actions. The operators were knowledgeable and aware of reactor safety.
The inspector also reviewed QA audit AP86-23 PR, dated June 6, 1986.
The QA audit
reviewed the corrective actions of the violation.
Based on licensee response to the violation, operator awareness interviews, and tne QA audit, the violation is closed.
3.3 (Closed) Unresolved Item (277/85-40-03).
Swapping Reactor Feed Pumps (RFP) at power. A reactor scram on low level, and RFP check valve slam and water hammer occurred on Unit 2 on December 26,
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1985. The root causes for this event and scram were operator error and a procedural deficiency in the swapping of RFPs at power. The licensee reported corrective actions in LER 2-85-27 which was reviewed in NRC Inspection 277/86-03; 278/86-03.
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Corrective actions include revisions to RFP operating procedures S.7.6.A,B,C, and instructions to the operating shift not to simultaneously remove one RFP from service while placing another RFP into service. The inspector reviewed the operating procedures and interviewed operators regarding RFP swapping.
No unacceptable conditions were noted, and this item is closed.
4.
Plant Operations Review 4.1 Station Tours The inspector observed plant operations during daily facility tours. The following areas were inspected:
Control Room
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Cable Spreading Room
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Switchgear and Battery Rooms Reactor Buildings
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Turbine Buildings
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Radwaste Building Recombiner 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 4.1.1 Control Room and facility shift staffing was frequently checked for compliance with 10 CFR 50.54 and Technical Specifications.
Presence of a senior licensed operator in the control room was verified frequently.
4.1.2 The inspector frequently observed that selected control room instrumentation confirmed that instruments were operable and indicated values were within Technical Specification requirements and normal operating limits.
ECCS switch positioning and valve lineups were verified based on control room indicators and plant observations.
Observations included f. low setpoints, breaker positioning, PCIS status, and radiation monitoring
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instruments.
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I 4.1.3 Selected control room off-normal alarms (annunciators)
were routinely discussed with control room operators and shift supervision to assure they were knowledgeable of alarm status, plant conditions, and that corrective action, if required, was being taken.
In addition, the applicable alarm cards were checked for accuracy. The operators were knowledgeable of alarm status and plant conditions.
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The inspector performed a review of lighted (alarmed)
annunicators in the control room, and at local panels in the Ur.it 2 reactor and turbine buildings. The review included the status of operator and management awareness and documentation of alarms, and of appropriate actions to correct the alarmed condition. By questioning reactor operators about the alarmed annunciators on Unit 2, Unit 3, and common alarm panels, the inspector determined that reactor operators were knowledgeable of lighted alarms.
In February 1986, the licensee began a systematic review of lighted alarms with the implementation of a monthly routine test procedure (RT 9.12-1). The inspector reviewed RT 9.12-1, Annunciator Panel Review, performed on February 10, March 14, April 10, May 16, June 16, and July 7, 1986. The RT documents existing alarms on the control room annunciator panels. Most of the control room alarms are maintained satisfactorily and provide reliable indications of plant change.
However, it was noted that several alarms were repeatedly observed on these routine tests and during an inspection on July 16,
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1986. While the reasons for the alarmed conditions were known and corrective actions stated to be initiated, the correction is not always timely.
For example, the following alarms were frequently observed:
Alarm Dates Observed Unit 3 Area Rad Monitor 3/14, 5/16, 6/16, 7/7, Downscale 7/16 Unit 3 Reactor Bldg 195'
2/10, 3/14, 4/10, 5/16, i
and Refuel Floor Hi-Low 6/16, 7/7, 7/16 Delta P Rad Waste Tank Level Hi 2/10, 5/16, 7/6 Unit 3 A Recirc Pump Motor 5/16, 6/16, 7/7, 7/16 Cooling Water Leak Units 2 and 3 CRD Hydraulic 2/10, 4/10, 5/16, 6/16, Hi Temp 350 Degrees 7/16 Sewage Wet Pit Vent Low 5/16, 6/16, 7/7, 7/16 Flow Unit 3 System II Torus 3/14, 4/10, 5/16, 6/16, Water Hi Temp Failure 7/7, 7/16
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Unit 3 CST Hi-Low Level 3/14, 4/10, 5/16, 6/16, 7/16 Unit 2 CST Hi-Low Level 3/14, 4/10, 7/7 Unit 3 A, B, and C 3/14, 4/10, 5/16, 6/16, Condensate Pump Hi Vib 7/7, 7/16 Unit 3 Offgas Holdup 3/14, 4/10, 5/16, 6/16, Pipe Hi-Low Press 7/7 Recombiner Bldg Rad 3/14, 4/10, 5/16, 7/7 Monitor Trouble Based upon discussions with operations personnel, the condensate pump high vibration alarm has been up since the modification was made to install vibration monitors over two years ago. The information tag on the alarm indicates a refueling outage is needed to fix the monitors.
Unit 3 started up from a refueling outage in March 1986. On August 2, 1986, the "C" condensate pump was taken out of service with a damaged pump bearing and
pump motor. Had the alarm been functioning, this damage may not have occurred.
The licensee has a priority system based upon colored lights associated with the control room annunciators.
Red lights are top priority alarms.
No red lights were observed during this inspection. Yellow lights are of intermediate priority. Alarms associated with yellow lights are corrected quickly and no yellow lights were (
observed for multiple time periods. Alarms up for extended time periods are white lights which are the
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lowest priority.
Blue alarm lights are used for loss of secondary containment. Green lights are used to
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indicate that selected equipment is normally operating during power operation.
The inspector reviewed an EP-QC report dated May 28, i
1986, on Control Room Annunciators. The report I
recommended that RT 9.12-1 include information on length of time the alarm has been up and documentation of more l
formal followup actions. Based upon the inspectors L
review, these appear to be sound recommendations.
On July 31, 1986, the inspector reviewed local alarm panels in the Unit 2 reactor and turbine buildings. The following conditions were observed:
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Panel No. Alarms /No. Alarms Lighted 20C76 Fuel Pool Pumps 12/5 l
00C133 Radwaste Ventilation 71/3 20C11 10/1 20C131 Turbine Bldg. Ventilation 26/4 20C89 Condensate Demineralizers 59/1 There is no historical data to compare the local panel conditions to at the present time. The inspector will continue to observe the status of local panel alarms.
Within the scope of the review of annunciators and alarm status, no violations were noted.
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.
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i 4.1.5 Shift relief and turnover activities were monitored daily, including backshift observations, to ensure
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compliance with administrative procedures and regulatory guidance.
No inadequacies were identified.
4.1.6 The inspector observed the main stack and both reactor building ventilation stack radiation monitors and
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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,
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monitored use of fire watches and ignition source
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controls, checked a sampling of fire barriers for integrity, and observed fire-fighting equipment
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stations.
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On August 8, 1986, the licensee reported that reanalysis of fire areas as part of a 10 CFR 50 Appendix R l
requirement identified cable encapsulation problems in L.
fire area 2 (Radwaste Building).
Six different types of l
encapsulation problems were identified in four separate
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rooms. A one hour roving fire watch was established for these areas. The Itcensee will make a thirty day LER
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report with further details. The inspectors will follow l
these activities.
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i 4.1.8 The inspector observed overall facility housekeeping
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conditions, including control of combustibles, loose trash and debris. Cleanup was' spot-checked during and after maintenance.
Plant housekeeping was generally acceptable.
t 4.1.9 The inspector observed the nuclear instrumentation subsystems (source range, intermediate range and power range monitors) and the reactor protection system to l
verify that the required TS channels were operable.
4.'1.10 The inspector frequently verified that the required TS off-site electrical power startup sources and emergency
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on-site diesel generators were operable.
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4.1.11 The inspector monitored the frequency of in plant and
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control room tours by plant and corporate management.
The tours were generally adequate.
t 4.1.12 The inspector verified operability of selected safety
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related equipment and systems by in plant checks of valve positioning, control of locked valves, power supply availability, operating procedures, plant drawings, instrumentation and breaker positioning.
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Selected major components were visually inspected for leakage, proper lubrication, cooling water supply,
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operating air supply, and general conditions. No significant piaing vibration was detected. The
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inspector reviewed selected blocking permits (tagouts)
for conformance to licensee procedures.
Systems checked included Unit 2 and 3 RCIC systems and tagouts for Limitorque EQ inspection.
Except for Limitorque work (see detail 12), no inadequacies were identified.
4.2 Followup On Events Occurring During the Inspection 4.2.1 Unit 3 Reactor Feed Pump (RFP) Trip On July 5,1986 j
l At 4:20 p.m., on Saturday, July 5,1986, with Unit 3 at
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l 88% power, the 38 RFP experienced flow oscillations while in automatic control. Two load drops had been affected at 1:30 and 3:00 p.m., earlier that day, due to high main transformer oil temperatures. A 3B RFP low flow alarm occurred and the operator attempted to take manual control of the 3B RFP, however it did not respond. The 3B RFP discharge check valve slammed
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several times and the operator tripped the 3B RFP and closed the discharge valve. A reactor low level alarm
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occurred at 17 inches and a recirculation pump and EHC
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load set runbacks commenced. The 60% speed recirculation pump runback initiates if one condensate (
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or one feed pump is unavailable, and a reactor low level alarm occurs.
In addition, if feed flow is greater than 95%,.an EHC load set runback occurs.
The recirculation runback was manually continued to 40% speed by operator action. The EHC runback did not reset at less than 95%
total feed flow, and continued to close the turbine control valves (TCV) at 1% per second. The effect of the concurrent runbacks resulted in a power decrease, and the opening of seven turbine bypass valves (BPVs).
The EHC runback finally reset and operator action was taken to close the BPVs by manually raising the turbine load set.
The plant was stabilized at 67% power, 40% recirculation pump speed, 3A and 3C RFPs in automatic, and all BPVs closed. The 3B RFP control linkage was greased and returned to service.
The cause for the EHC runback not resetting when feed flow was less than 95% is unknown.
However, the licensee suspects a sticky time delay relay (62-C2) similar to an event in 1984.
Power was increased to 100% following the return to service of the 3B RFP.
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The inspector noted the occurrence of this event during a morning control room tour and review on July 7,1986.
The inspector reviewed the control room logs, examined the control room recorder traces and alarm typers, and discussed the event with the on shift operators.
Reactor level decreased to +15 inches as indicated by recorder PR/LR-3-6-96.
(Scram level is 4 inches.)
Level was returned to normal (23 inches) by the 3A and 3C RFPs. The inspector determined that operator response was timely and in accordance with procedure OT-101, Reactor Low Level. Quick and adequate operator response probably prevented a unit scram as the EHC runback continued past its reset setpoint.
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l The licensee prepared an Upset Report on this event.
The inspector reviewed the report and discussed it with licensee operators and engineers. The report noted a similar occurrence on Unit 3 on February 9,1984.
In this instance, a manual trip of the 3B RFP due to high vibration resulted in a reactor scram on high neutron flux. The scram occurred when the EHC runback failed to l
reset,' and when all BPVs opened, a pressure spike caused
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an APRM scram on high neutron flux. The inspector reviewed LER 3-84-05 and Upset Report 3-84-2 regarding this previous event.
The previous event was reviewed during NRC Inspection 277/84-03; 278/84-03.
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Licensee followup to the Unit 3 February 9,1984, event and scram included a proposed modification (MOD 1474) to remove the EHC load set runback. Apparently, the EHC runback logic and circuitry came with the turbine package.
It is designed to prevent the EHC system from counteracting the recirculation pump runback when the plant is operating in a load follow mode.
Load follow mode is not used (reactor follows turbine changes) and
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thus, the licensee determined that the EHC runback is not necessary.
The inspector reviewed MOD 1474 package and discussed it with licensee engineers. The modification is scheduled for the 1987 Unit 2 and 3 refueling outages. Within the scope of the review of this event and followup, no violations were noted.
The inspector will follow the progress of the modification to remove the EHC load set runback circuitry.
4.2.2 Unit 3 3A Recirculation Pump Seal Failure
On July 13, 1986, the 3A recirculation pump second stage seal pressure began oscillating between 400 and 650 i
psig.
Normal seal pressure is steady at approximately 500 psig. A degraded inner seal was indicated. Both recirculation pump seals are designed to withstand full dif ferential pressure (i.e.,1000 psig to atmospheric
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pressure).
The inspector reviewed licensee actions to increase the monitoring of the 3A recirculation pump seal parameters j
including:
seal pressures and temperatures, seal purge flows, and control room alarms. The inspector accompanied a licensee system engineer to monitor seal
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performance on a daily tour on July 14, 1986.
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inspector interviewed operators on the seal performance and actions to be taken if seal failure occurred. The
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operators were knowledgeable of the seal configuration,
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the increased seal performance monitoring, and actions l,
to be taken on seal failure.
The licensee repaired the seal during an outage which began on July 19, 1986. The new seal has performed satisfactorily since replacement. Within the scope of the review of the degraded seal and licensee followup,
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no violations were noted.
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4.2.3 Unit 3 Scram On July 19, 1986 Unit 3 scrammed from 87% power at 4:07 p.m., on July 19, 1986, due to high APRM neutron flux.
Reactor level decreased to about -32 inches resulting in Group II and III PCIS signals at 0 inches. The three reactor feedwater pumps increased speed to recover level and subsequently tripped on overspeed. The "C" reactor feed pump was reset and used to control reactor level with automatic controller LIC-9091.
An electrical ground fault caused the 3 SUE and 3SU-2 breakers to trip.
Breaker 3 SUE is the off-site 4.16 KV feed to emergency buses E-13, E-22, E-33, and E-42.
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automatic fast transfer to the other off-site (2 SUE)
i power source occurred for the emergency buses, and the associated emergency load centers E-134, E-224, E-334,
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E-424 de-energized for three seconds as designed.
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Emergency load center E-134 supplies panel 30Y033 which
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supplies electrical power to the inboard main steam isolation valve (MSIV) AC coils.
Since the inboard MSIV
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j A0-80B had a failed DC coil, loss of AC power caused loss of nitrogen pressure to the valve operator and the i
valve failed closed as designed. The resulting reactor pressure spike caused a neutron flux spike of sufficient magnitude to initiate an APRM high flux scram. The unit
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was depressurized to cold shut down to allow repair of the RCIC M0-15 valve which had a packing leak and was causing higher than normal drywell temperatures.
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The inspector discussed the event with operations personnel, reviewed the logs, control room instrument traces, sequence of events logs, Procedure GP-18 C.0.L.,
" Scram Review Procedure", and the draft Upset Report.
All safety systems responded as designed. The licensee adequately determined the cause of the scram and evaluated system response. However, a minor error was made in the GP-18 procedure for the calculated time from APRM scram to time of scram reset. The licensee calculated the time from APRM high-high alarm rather l
than from the time of the APRM scram. Thus, the licensee documented a more conservative time on GP-18.
All calculated times were less than the required 1.15 l
seconds of Technical Specification 1.1A.
The inspector
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discussed this minor error with the individual who b
performed the GP-18 procedure and with licensee engineers. The inspector will continue to review GP-18 procedures.
IT Within the scope of review of the Unit 3 scram, no violations were noted.
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4.2.4 Unit 3 IRM Alarm and Trip At approximately 6:30 p.m., on July 24, 1986, Unit 3 received an IRM high flux and IRM high high flux alarm from the "C" IRM without receiving a half scram.
The unit was in cold shutdown at the time of the event.
The reactor operator noted that the IRM high and high-high lights were lit on the panel.
The IRM high-high flux trip and reset were logged on the process computer at 18:28:24-18 (6:28 p.m., 24 seconds, 18 cycles). The IRM trip signal was less than one cycle (1/60 of a second).
The operator immediately placed the IRM channel "C" mode switch out of operate, causing a half scram in RPS
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At 10:20 p.m., ST 3.2.3, "IRM Functional and Calibration Check" was completed satisfactorily.
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"C" IRM channel was then bypassed with the joy stick and reset the half scram.
Testing was performed on July 25, 1986, to ensure compliance with Technical Specification 3.1.8, which requires system response times of 50 milliseconds or less from the opening of the sensor contact up to and including the opening of the trip actuator contactor.
Additional testing was performed to determine if a momentary interruption of power to the HFA relay would produce a half scram. However, power interruptions of one cycle or less could not be created.
The licensee contacted a vendor representative who indicated that the HFA relay would not respond to a loss of power of one cycle or less. The vendor representative felt that the relay would operate with power losses of 1.5 to 2 cycles. The licensee concluded the "C" IRM had experienced a momentary spike and had functioned properly. The licensee returned the "C" IRM channel to
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service on July 25, 1986, after PORC review.
An IRM high high flux signal causes a DC relay (K4) to de-energize at the IRM panel. The K4 relay causes DC relays K8 and K16 and AC HFA relay (K11) to operate.
Operation of K8 produces the computer printout and K16 l
produces the control room annunciation.
Operation of HFA relay K11 produces the scram initiation by dropping out the AC scram contactor (K13). During the event K4,
K8, and K16 operated, with no indications of operation
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of K11 or K13.
The inspector reviewed the licensee's actions and discussed the event with operations and instrumentation personnel. A review of RWP's for work in the Unit 3 drywell showed that no work was being done in the
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subpile room to cause the action.
Based upon this review, the inspector concluded that the licensee had taken thorough and appropriate action to investigate the problem. No unsatisfactory conditions were observed.
4.2.5 Unit 3 Scram On August 11, 1986 i
Unit 3 scrammed on low level (4 inches) at 5:01 a.m. on August 11, 1986.
The cause of the scram was loss of the 3G4-T-A motor control center (MCC) due to the supply feeder breaker trip when the A stator coolant pump breaker experienced an electrical fault. The loss of the 3G4-T-A MCC resulted in a loss of power to the C reactor feed pump (RFP) turbine protective instruments and the A lube oil pump, and the C RFP tripped on thrust bearing wear. A Group II and III PCIS also occurred at
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0 inches.
Reactor level decreased to -48 inches indicated; resulting in HPCI and RCIC system initiations, and reactor recirculation pump trips.
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Water level was recovered by the A and B RFPs, and the HPCI/RCIC systems. The licensee made an ENS call at j
5:50 a.m.
The unit proceeded to cold shutdown.
The inspector reported to the Control Room about 7:00 a.m., on August 11, 1986.
The inspector reviewed control room indications, instrument chart traces, sequence of events, computer log and operator logs; and, discussed the event with operators. Operator response was in accordance with emergency procedures. The licensee prepared an Upset Report and completed GP-18, Scram Review Procedure. The inspector reviewed these documents and discussed them with the licensee.
The inspector examined the failed breaker compartment noting a wire short in one phase that caused the wire to contact the metal compartment. The licensee replaced the breaker and returned the MCC to normal.
Within the scope of the review of this event, no violations were noted.
4.3 Logs and Records The inspector reviewed logs and records for accuracy, j
completeness, abnormal conditions, significant operating changes l
and trends, required entries, operating and night order propriety, correct equipment and lock-out status, ju: per log validity, i
i conformance to Limiting Conditions for Operations, and proper reporting. The following logs and records were reviewed:
Shift
Supervision Log, Reactor Engineering Logs, Unit 2 Reactor
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Operator's Log, Unit 3 Reactor Operator's Log, Control Operator Log Book and STA Log Book, Night Orders, Radiation Work Permits,
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Locked Valve Log, Maintenance Request Forms and Ignition Source Control Checklists.
Control Room logs were compared against Administrative Procedure A-7, Shift Operations.
Frequent initialing of entries by licensed operators, shift supervision, and licensee on-site management constituted evidence of licensee review.
No unacceptable conditions were identified.
4.4 SIL No. 440 Followup The inspector reviewed GE Service Information Letter (SIL) No.
440, " Rod Worth Minimizer Cc,mputer Program Stall Alarms", dated July 15, 1986, and licensee actions related to this SIL.
SIL No. 440 describes an experience at another BWR in which the Rod Worth Minimizer (RWM) program was aborted by the process computer operating system stall timer. No rod blocks were applied when the RWM aborted.
In such an event, the plant Technical Specification's requirement for RWM operability may oe impacted.
The SIL recommends that licensees review plant startup and shutdown procedures to verify RWM operability.
The licensee's review of the RWM-computer systems interface determined that a RWM program abort without rod blocks could occur
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at Peach Bottom.
PORC approved revision to procedures GP-2, Appendix 1, "Startup Rod Withdrawal Sequence Instructions, GP-9-2,
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Appendix 1 and GP-9-3, Appendix 1 " Shutdown Instructions", adding
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to each a RWM operational verification step at the beginning of
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each rod group.
In addition, software modifications are being l
pursued to provide RWM programs abort alarms to the reactor
operator.
The inspector discussed the problem with the licensee and reviewed the changes made to the startup and shutdown procedures dated August 8, 1986, as well as the PORC meeting minutes. The inspector had no further questions and no violations were noted.
4.5 Engineered Safeguards Features (ESF) System Walkdown The inspector performed a detailed walkdown of portions of the Reactor Protection System (RPS) and Control Rod Drive Hydraulic
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System (CRDHS) in order to independently verify the operability of the Unit 2 and 3 systems. The walkdown included verification of the following items:
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Inspection of system equipment conditions.
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Confirmation that the system check-off-list (COL) and L
operating procedures are consistent with plant drawings.
Verification that system valves, breakers, and switches are
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properly aligned.
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Verification that inst.rumentation is properly valved in and
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Verification that valves required to be locked have
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appropriate locking devices Verification that control room switches, indications and
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controls are satisfactory.
Verification that surveillance test procedures properly
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implement the Technical Specifications surveillance requirements.
Within the scope of the review of the Unit 2 and 3 RPS and CRDHS, no unacceptable conditions were identified.
i 4.6 Containment Isolation Valves for Reactor Building Closed Cooling Water (RBCCW) and Drywell Chilled Water During the review of the EQ inspection of Limitorque motor operated valves (MOVs) internal wiring (see detail 12), the inspector noted that the following six MOVs per unit were included in the work list:
Valve Description M0-2(3)373 RBCCW to recirc pumps M0-2(3)374 RBCCW from recirc pumps M0-2(3)200A and B Drywell chilled water to/from drywell coolers M0-2(3)201A and B Drywell chilled water to/from drywell coolers These valves are non-automatic containment isolation valves located outside containment in six inch lines for RBCCW and in eight inch lines for drywell cooling.
FSAR Table 7.3.1 states
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that these valves are normally open during operation and closed on post accident conditions.
The valves meet General Design Criteria 57 in 10 CFR 50, Appendix A for closed system isolation valves.
The valves can be remotely closed from the control room.
The inspector questioned which plant emergency procedure (TRIP procedure) directed the closing of these valves.
The licensee stated that no procedure currently exists to specify how or when to close these 12 valves (six valves per unit). The licensee also stated that the TRIP procedures direct the operator to maximize drywell cooling in an effort to reduce drywell temperature and pressure. Thus, the drywell chilled water valves that supply the drywell coolers would remain open under certain conditions per procedure T-102, Containment Control.
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This item is unresolved pending licensee evaluation and possible revision of FSAR Table 7.3.1 and the TRIP procedure, and NRC review. (UNR 277/86-13-01; 278/86-14-01).
5.
IE Bulletin 86-02 Followup IE Bulletin number 86-02 regarding static "0" ring (SOR) differential pressure (D/P) switches was issued July 18, 1986.
The bulletin required licensees to review plant design and equipment and to report whether SOR D/P switches were installed in the plant or equipment important to safety within seven days.
The licensee reported the results of this review in a letter dated July 25, 1986.
The licensee report that no SOR D/P swi~tches were currently installed nor planned to be installed as electrical equipment important to safety.
The inspector reviewed the licensee's response letter and discussed it with licensee engineers.
The inspector could find no equipment important to safety that utilized the SOR D/P switches. Within the scope of the review of IE Bulletin 86-02, no unacceptable conditions were noted.
IE Bulletin 86-02 is closed.
6.
Review of Licensee Event Reports (LERs)
6.1 LER Review The inspector reviewed LERs submitted to the NRC to verify that the details were clearly reported, including the accuracy of the description and corrective action adequacy. The inspector determined whether further information was required, whether generic implications were indicated, and whether the event warranted on-site follcwup.
The following LER's were reviewed:
LER No.
LER Date Event Date Subject
- 2-86-14 Shutdown due to TS, loss of ESW July 18, 1986
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June 18, 1986 2-86-15 Exceeding local leak rate limits of 10 CFR 50, July 21, 1986 Appendix J
June 20, 1986 2-86-16 HPCI inoperable due to failed control device August 5, 1986 July 9,1986
- 3-86-15 RWCU system isolation due to blown fuse i
July 22,1986 June 24, 1986
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6.2 LER'On-Site Followup For LERs selected for on-site followup and review (denoted by asterisks 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 Technical 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 2-86-14 concerns a Unit 2 shut down due to loss of ESW on June 18, 1986. This event was reviewed in NRC Inspection 277/86-12 and 278/86-13. There were no l
unacceptable conditions relative to the LER.
6.2.2 LER 3-86-15 concerns a Unit 3 RWCU system isolation caused by a blown fuse due to circuit overload. The event was reviewed in NRC Inspection 277/86-12 and
278/86-13.
The circuit overload was caused by a
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portable tool being plugged in to a wall receptacle.
The as found condition differed from the plant drawing
for the RWCU instrument and the wall receptacle.
The licensee is continuing this review of a wiring error and will revise the LER when root cause is determined.
The inspector will review the revised LER.
7.
Surveillance Testing
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been properly scheduled, approved by shift supervision, control room
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operators were knowledgeable regarding testing in progress, approved j
procedures were being used, redundant systems or components were l
available 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:
ST 6.9.F, RHR "B" Pump, Valve, Flow & Unit Cooler Functional -
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Flow Test, Rev. 4, performed on Unit 3 on July 31, 1986.
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ST 3.1.3, SRM Functional and Calibration Test, Rev. 5, performed l
on Unit 3 on July 31, 1986.
ST 3.2.3, IRM Functional and Calibration Check, Rev. 7, performed
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ST 3.3.6, APRM Functional Test and Calibration Check, Rev. 3, performed on Unit 3 on July 31, 1986.
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ST 10.5, RWM Operability Check, Rev. 12, performed on Unit 3 on July 31, 1986.
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ST 10.6, RSCS Functional Test, Rev. 15, performed on Unit 3 on
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July 31, 1986.
ST 13.54, RPS Breaker Coil Continuity Check, Rev. 1, performed on
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the Unit 3 alternate RPS feed on August 8, 1986.
ST 2.4.04C, Calibration Check of LT/LSH/LSC/LSLL 2-2-3-72C, Rev.
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9, performed on Unit 2 on August 12, 1986.
No inadequacies were identified.
8.
Maintenance 8.1 Monthly Maintenance Observations For the following maintenance activities the inspector spot-checked administrative controls, reviewed documentation, and observed portions of the actual maintenance:
Maintenance Procedure /
Document Equipment Date Observed ST 2.15.23 Unit 2 HPCI speed control and July 10,1986 and governor troubleshooting RT 1.12 MOD 86-099 3C condensate pump and August 7-8, and transformer 15, 1986 MRF M8606003 3G4-T-A MCC Maintenance August 11, 1986 CJM #2062 Limitorque Wiring Inspections August 13-15, l
1986 l
M52.5 E-3 air blower replacement August 14, 1986 Administrative controls checked included maintenance requests, blocking permits, fire watches and ignition source controls, item handling reports, and shift turn'over information. Documents
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reviewed included procedures, material certifications and receipt
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inspections.
I Except for the Limitorque work (see detail 12), no inadequacies
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l 8.2 Plant Equioment Lubrication Program The inspector reviewed the lubrication program which is part of preventive maintenance (PM) on equipment.
Preventive maintenance lubrication responsibilities are divided between the Engineer
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Maintenance and Operations Engineer.
Equipment which can be lubricated only while it is out of service is included in the maintenance staff's PM program.
If the equipment can be lubricated while operating, the responsibility is given to the operating staff and follows a program described in routine test procedure RT 1.1, Rev.1, Lubrication Program, dated March 3, 1982. This procedure indicates that weekly lubrication sheets are distributed to about fifteen plant operators to be completed during the week. The operator is responsible for lubricating the equipment described on the sheet and documenting the actions taken.
Lubrication sheets are returned to the shift supervisor for review and then given to the shift clerk to document on an equipment history card. The procedure requires that the shift clerk gives the Operations Engineer a list of discrepancies for his review and appropriate actions.
Upon discussing the lubrication program with the licensee, it was
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determined that apparently no program was being implemented by the
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operating staff. The program apparently stopped about two years
ago. The licensee had recently initiated efforts to revise the program to make,it more effective. The inspector informed the licensee that Regulatory Guide 1.33, November, 1972 and ANSI N18.7-1972 required a lubrication program to keep safety related equipment in proper working condition. After these discussions, the licensee re-initiated the lubrication program, with the goal i
of revising the program in the future. The inspector verified that the operation lubrication program was started and reviewed lubrication sheets for calendar week 28 of 1986. The inspector raised questions on followup of problem areas noted on the sheets and sheets that were not returned.
The inspector noted that
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industry-wide experience as reported in NUREG/CR 2000 volumes 3 (1984) and 4 (1985) on LERs indicated that about 130 events were
caused by faulty lubrication and the licensee did not appear to place proper management priority on the program.
The inspector
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reviewed the lubrication sheets for weeks 1-5, and noted a large number of pieces of safety related equipment, indicating that the program is being implemented.
The inspector will review plant records to determine if safety related equipment failed because
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of lubrication problems brought on by the lack of lubrication program implementation. This item is unresolved pending the equipment review and licensee actions to followup on lubrication problems.
(UNR 277/86-13-02; 278/85-14-02).
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9.
Radiation Protection
During the report period, the inspector examined work in progress in both units, including health physics (HP) procedures and controls,
dosimetry and badging, protective clothing use, adherence to radiation work permit (RWP) requirements, radiation surveys, radiation protection
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instruments use, and handling of potentially contaminated equipment and materials.
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The inspector observed individuals frisking in accordance with HP procedures. A sampling of high radiation 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 personnel had provided the required information and people working in RWP areas were observed to be meeting the applicable requirements.
No unacceptable conditions were identified.
10. Physical Security The inspector monitored security activities for compliance with the accepted Security Plan and associated implementing procedures, including: operations of the CAS and SAS, checks of vehicles on-site to verify 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 inadequacies were identified.
11.
In-Office Review of Public and Special Reports The inspector reviewed the Unit 3 Startup Report Following Sixth Refuel-ing Outage, July 7,1986.
No unacceptable conditions were identified.
12.
Environmental Qualification (EQ) Inspections of Limitorque Motor Operator Valves (MOVs) Wiring On August 8,1986, the licensee informed the inspector that another reactor had recently found problems in the EQ of Limitorque MOVs.
In response to this problem and IE Information Notice 86-03 (January 14, 1986), the licensee initiated EQ inspections of MOV wiring on Unit 2 on August 9, 1986, and on Unit 3 on August 11, 1986. Unit 2 was previously shut down on August 7,1986, to repair a steam leak on the RCIC A0-22 packing; and Unit 3 auto scrammed on low level on August 11, 1986 (see detail 4.2.5).
The inspections involved 166 valves total on both units.
Initially inspections were performed by electrical maintenance personnel, however, the job was turned over to the on-site construction division on August 12, 1986.
NRC regional personnel, the inspector and PECo personnel conducted a telephone conference call on August 12, 1986, to discuss licensee actions regarding the EQ inspections. The licensee intends to inspect all Limitorque jumper wiring and replace all wires that cannot be positively identified by markings. The replacement wiring is to be marked with manufacturer's name on each strand of wire.
The removed wiring is being saved for future engineering analysis.
The inspector reviewed the following documentation:
IE Information Notice 86-03, January 14, 1986.
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M 9.1, limitorque Switches Inspection Procedure, Rev.11.
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Construction Job Memo, MOD #2062, Limitorque Wiring Inspection,
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EQ equipment sheets, 2/19/86.
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Selected Maintenance Request Forms (MRFs) for EQ inspections.
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Special Instructions for QC Inspection, MOD 2062, 8/14/86.
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Limitorque Instruction Manual #6280-C62-10.
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Electrical Wiring Drawings E-911 sheets 1 thru 9, Rev. 38.
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Selected Electrical Schematic Diagrams for Core Spray, RHR, PCIS.
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TI 2515/75, Inspection of Limitorque MOVs, 3/27/86.
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The inspector discussed the inspections with licensee engineers and management personnel. The licensee is using an actual Limitorque MOV mock-up (SMB-2 and 000) to train inspection and QC personnel for the inspections. The inspector accompanied construction and QC personnel on an inspection of Unit 2 core spray MOVs 2-14-005D and 2-14-007D on August 14, 1986. The inspector noted that QC personnel were present during the inspections and that QA was performing a surveillance of work activities.
On "Y" shift (3-11 p.m.) on August 13, 1986, construction division personnel worked on four MOVs that had no MRF nor blocking permit. The MOVs were the core spray minimum flow valves (M0-2-14-5A,B,C,D).
The construction division electrician obtained the valves to be worked from a list of MOVs that were not yet blocked rather than the correct list
of MOVs which had authorizing MRFs.
The control roon operators noted
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that the four MOVs indicating lights were out between 11:30 p.m. and
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12:IO a.m.
The shift researched the problem and found that the MOVs were worked on without MRFs. The Shift Superintendent stopped work on
the EQ inspections and made a four hour ENS call at 3:50 a.m., August l
14, 1986, per 10 CFR 50.72(B)(2)(111).
The MOV indicating lights were I
out because the unauthorized work blew several control power fuses for E
the MOVs.
Administrative Procedure A-26A,. " Procedure for Corrective and i
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Preventive Maintenance Using CHAMPS," Rev. 25, requires that section 5 (equipment turnover) of the MRF be completed prior to performing safety
related work.
Engineering Procedure ERDP 14.1, " Procedure for the Use j
of MRFs at Peach Bottom", Rev. 7, requires that engineering and i
research department personnel (i.e., construction division) utilize approved MRFs for work in accordar.ce with procedure A-26A.
Failure to
have an approved MRF for EQ inspections of core spray valves
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M0-2-14-5A,B,C,D is a violation of procedure A-26A.
No Notice of Violation is being issued because the violation meets the criteria of 10 CFR 2, Appendix C, for a licensee identified violation.
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Corrective action by the licensee included:
counselling of the individual involved, informing all individuals performing EQ inspections of the event, revising the QC procedures and checklists, adding a construction division sub-foreman to the
"Y" shift, and assigning a construction division superintendent to manage the EQ inspection activities.
The inspector discussed these actions with construction division management personnel.
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The safety impact on plant systems was minimal.
TS 3.5.F.3 allows all core spray and RHR systems to be out of service in cold shutdown as long as no work is in progress that can drain the vessel, The licensee replaced the blown fuses and returned core spray minimum flow valves to service. The A and C core spray pumps would have injected into the reactor vessel if a valid start signal had occurred.
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At the end of the inspection period the licensee was continuing to
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perform the Limitorque wiring EQ inspections.
The EQ issues pertaining
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to the Limitorque MOV wiring is unresolved pending completion of i
licensee inspections, licensee engineering evaluation, and NRC review.
(UNR 277/86-13-03; 278/86-14-03).
f 13. Ur solved Items
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Ute% solved items are items about which more information is required to asMrtain whether they are acceptable violations or deviations.
Ur resolved items are discussed in details 4.6, 8.2 and 12.
14. &nagement Meetings 14.1 Preliminary Inspection Findings A verbal summary of preliminary findings was provided to the Manager, Peach Bottom Station at the conclusion of the inspection. During the inspection, licensee management was periodically notified verbally of the preliminary findings by the resident inspectors. No written inspection material was provided to the licensee during the inspection.
No proprietary information is included in this report.
14.2 Attendance at Management Meetings Conducted by NRC The resident inspectors attended entrance and exit meetings as follows:
Inspection Date Subject Report No.
Inspector July 14, 1986 Control Room Hone Ramirez Design Review
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Rerack, ESW 278/86-15 Repairs, OIs i
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