IR 05000277/1987022
| ML20235T979 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 09/24/1987 |
| From: | Linville J, Williams J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20235T963 | List: |
| References | |
| 50-277-87-22, 50-278-87-22, IEIN-87-030, IEIN-87-30, NUDOCS 8710130310 | |
| Download: ML20235T979 (26) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
Report No. 50-277/87-22 & 50-278/87-22 Docket No. 50-277 & 50-278 License No. DPR-44 & DPR-56 4'
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 18 - August 28, 1987 Inspectors:
T. P. Johnson, Senior Resident Inspector R. J. Urban, Resident Inspector L. E. Myers, Resident Inspector
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2/FS f!?#
Reviewed By:
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H. Williams, Project Engineer
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d' ate Approved By:
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14 f 21 J.' Linville, Chie, /
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Reactor Projects Section 2A, Division of Reactor Projects i
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Inspection Summary:
Routine, on-site regular and backshift resident inspection (135 hours0.00156 days <br />0.0375 hours <br />2.232143e-4 weeks <br />5.13675e-5 months <br /> Unit 2; 134 hours0.00155 days <br />0.0372 hours <br />2.215608e-4 weeks <br />5.0987e-5 months <br /> Unit 3) of accessible portions of Units 2 and 3, operational safety, radiation protection, physical security, control room activities, licensee events, surveillance testing, refueling j
and outage activities, maintenance, and outstanding items.
Results: Numerous shutdown cooling system isolations have occurred on both units during this and the previous inspection period (section 4.1.12 and 4.2).
Temporary clearance and subsequent re-application of permits do not take into account changing plant conditions (section 4.2.7).
A fire header leak resulted in both fire pumps being out of service so repairs could be performed (section 4.2.2).
The removal of the RHR pump motor surge ring brackets is unresolved
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(section 5.1).
8710130310 871002 PDR ADOCK 05000277 G
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DETAILS 1.0 Persons Contacted B. L. Clark, Administrative Engineer G. F. Dawson, Maintenance Engineer A. A. Fulvio, Technical Engineer i
i J. F. Mitman, Radwaste Engineer D. L. Oltmans, Senior Chemist F. W. Polaski, Operations Engineer D. P. Potocik, Senior Health Physicist
G. R. Rainey, Superintendent Plant Services l
M. B. Ryan, Outage Engineer
- D. C. Smith, Superintendent Operations
- D. M. Smith, Manager, Peach Bottom Atomic Power Station.
J. E. Winzerried, Staff Engineer Other licensee employees were also contacted.
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- Present at exit interview on site and for summation of r.reliminary findings.
2.0 Plant Status 2.1 Unit 2 The unit began the inspection period preparing for reactor vessel reassembly. The reassembly was completed on July 28, 1987, and the vessel head tensioning was completed on July 31, 1987.
The completion of outage related maintenance work and testing continues.
'i 2.2 Unit 3 i
Unit 3 remained shutdown in a cold condition with the reactor mode switch in the " shutdown" position as required by NRC Order dated March 31, 1987. Preparations for the pipe replacement outage began during this inspection period.
j 3.0 Previous Inspection Item Update 3.1 (Closed) Inspector Follow Item (277/86-07-02). Modifications (MOD) for the reactor feed pump (RFP) air operated minimum flow valves.AO-2(3)139A, B and C.
Valve failures had occurred in the past primarily due to the design and physical location.of the valves. The licensee performed MOD 1695 on Unit 2 during the current 1987 refueling. MOD 1695 relocates the valves adjacent to the condenser with new high pressure drop, low recovery air operated valves. The purpose of this valve modification is to eliminate the currently high maintenance requirements while improving overall plant and equipment reliability. The inspector reviewed the
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- modification package including the safety evaluation, PORC approval, construction job memo, engineering work letter, revised drawings and proposed testing. The inspector performed a walkdown of portions of the new piping and valves and discussed MOD 1695 with licensee
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engineers and operators. The same MOD is scheduled for Unit 3 during i
the upcoming refueling. The inspector follow item is closed.
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3.2 (Closed) Inspector Follow Item (277/81-07-05; 278/81-09-04).
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Review licensee progress on modifications to reduce potential
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radioactive liquid releases.
NRC I&E Bulletin 80-10 also
addressed the issue of unmonitored releases. The Bulletin I
response was reviewed in NRC Inspection 277/82-16, 278/82-16, i
277/86-19 and 278/86-20.
Bulletin 80-10 is closed. The inspector J
follow item was reviewed in NRC Inspection 277/82-19 and 278/82-18, 277/82-25 and 278/82-24, and 277/83-16, 278/83-16. The
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item remained open pending completion of modifications of the EHC
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cooler drain hose. The inspector verified that the modification was performed. The inspector follow item is closed.
3.3 (Closed) Inspector Follow Item (277/84-07-02; 278/84-07-02).
Modification of the standby gas treatment system (SGTS) to include remote damper control. A modification (MOD 18) had been proposed in 1975 to provide damper controls and duct pressure indication in the control room. The controls for the SGTS filter train inlet and outlet dampers are currently in the control room.
However, damper controls for the modulating vortex and bypass dampers are local. A design flaw in 1980 resulted in postponement of MOD 18.
An engineering redesign of MOD 18 has been completed.
The.
inspector reviewed an engineering letter dated June 30, 1987, detailing the MOD.
The inspector also reviewed the current MOD package, and discussed it with the system and modification engineers.
No unacceptable conditions were identified.
The inspector follow item is closed.
The inspector will continue to monitor MOD 18 performance.
3.4 (Closed)InspectorFollowItem(277/84-22-06).
Review of vendor documents was not timely. An NRC team inspection identified a weakness related to the licensee review of vendor (primarily GE, i
Bechtel and CBI) procurement specifications and interface manuals.
I The licensee formally responded to the weakness in a letter dated November 9, 1984.
The inspector reviewed the response and discussed it with licensee personnel.
Based on the licensee response, the inspector follow item is closed.
4.0 Plant Operations Review l
4.1 Station Tours The inspector observed plant operations during daily facility tours. Most accessible plant areas were inspecte.
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4.1.1 Control Room and facility shift staffing was frequently checked for compliance with 10 CFR 50.54 and Technical Specifications. The presence of a senior licensed operator and the Nuclear Operations Monitving Team member 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 flow setpoints, breaker positioning, PCIS status, and radiation monitoring instruments.
4.1.3 Selected control room off-normal alarms (annunciators)
were 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.
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 periodic backshift observations, to ensure 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 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 observed fire-fighting equipment stations. Other than a temporary loss of both fire pumps (see section 4.2.2), no inadequacies were identified.
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1 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 i
after maintenance.
Plant housekeeping was generally
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acceptable with the exception of several of the RHR g
rooms (see section 4.1.14).
Licensee activities in this area will be reviewed in a future inspection.
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4.1.9 The inspector observed the shutdown nuclear: instruments-subsystems (source range and intermediate range monitors)
and the reactor protection system to verify that. the required channels were operable.
4.1.10 The inspector frequently verified that the required l
off site electrical power startup sources and emergency J
onsite diesel generators were operable.
Partial losses of_ off site power occurred on August 16, 1987 (see
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section 4.2.4) and on August 20, 1987 (see section
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4.2.5).
4.1.11 The inspector monitored the frequency of in plant and
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control room tours by plant and corporate management.
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The tours were generally adequate.
4.1.12 The inspector verified operability of selected safety j
related equipment and systems by in plant checks of
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valve positioning, control of locked valves, power
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supply availability, operating procedures, plant
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drawings, instrumentation and breaker positioning.
i 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
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inspector reviewed selected blocking permits (tagouts)
j for conformance to licensee procedures.
Systems checked
included the Units 2 and 3 RHR including the shutdown cooling systems.
During the inspection period, eight automatic isolations of shutdown cooling occurred (six on Unit 2, and two on Unit 3).
These events are reviewed in section 4.2 of this report. Also, during the last inspection period three shutdown cooling automatic isolations occurred.
I The following table depicts the causes of these recent l
shutdown cooling isolations:
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Date Unit (s)
Cause July 10
Blown fuse (unknown reason)
July 10 2, 3 Partial loss of off site power due to lightning strike i
July 28
Probable personnel error -
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contractor worker bumping E-322 l
breaker compartment j
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August 16 2,3 Partial loss of off site power
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due to line fault August 20
.2,3 Partial loss of off site power j
due to personnel error (crane operator)
August 20
Probable personnel error -
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I&C personnel moved a flexible conduit, causing a relay short circuit August 28
Personnel error - inadequate blocking due to reapplication of permit The inspector expressed concern over the number of l
shutdown cooling isolations.
Two common causes appear l
to be loss of off site power and personnel errors. The l
personnel errors were by different work groups on site.
The inspector will continue to follow this item in future inspections.
4.1.13 The inspector performed backshift and weekend tours of
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the facility on the following days:
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Tuesday, July 21, 1987, 4:20 a.m. - 6:00 a.m.
Sunday, August 9, 1987; 8:45 a.m. - 2:15
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p.m.
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Thursday, August 13, 1987; 5:30 a.m. -
6:00 a.m.
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Friday, August 28, 1987; 5:00 a.m. - 6:00 a.m.
4.1.14 On August 11, 1987, the Regional Administrator and NRC managers from headquarters toured the Peach Bottom station. A list of identified deficiencies and material conditions was provided to the licensee.
The inspector i
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l will. follow the short term and long term corrective l
actions for these identified items in a future inspection.
4.2 Followup On Events Occurring During the Inspection 4.2.1 Unit 2 Containment Isolation With Unit 2 in a refueling outage, a partial outboard.
group I and II containment isolation occurred at 1:15 p.m., on July 28, 1987.
Shutdown cooling and reactor water cleanup were isolated when various group II
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isolation valves closed. The isolation occurred when
l the feeder breaker (E-322) connecting the #3 startup.
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source to the E-22 4KV emergency bus tripped open. A
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fast transfer to the (/2 startup source occurred to the alternate breaker (E-222), but a 480V three second lockout occurred as designed.
The three second loss of
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power caused several group II valves to isolate because i
their control relays lost power. Other affected group II valves were already closed.
Numerous outboard group III containment isolation valves lost _ power to i
i their solenoids.
If the valves would have been open, they would have isolated.
The event was not considered a group III isolation because the valves did not move i
and logic power for the group III isolation was not l
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lost.
In addition, no emergency diesel generator starts occurred nor were required.
The isolations were reset at 1:20 p.m.,
reactor water cleanup was restored at 1:25 p.m., and shutdown cooling I
was restored at 1:30 p.m.
The licensee made a four hour j
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ENS call at 2:20 p.m.
The cause of the E-322 breaker opening is unknown.
No associated work or testing was being performed; but there were personnel near the breaker cabinet using a mobile ground truck. The E-322 breaker trip could have been caused by bumping the cabinet.
The individuals stated that they did not bump the cabinet; however, they were reminded of the need to be cautious when working near breakers. No other preventive actions were taken due to the unknown cause of the event.
The inspector reviewed the preliminary upset report, LER 277/87-014 and electrical schematic diagrams. A discussion was also held with the assistant operations engineer. The inspector agreed with the findings in the LER, however, the inspector pointed out that two inboard isolation valves closed because two outboard isolation valves closed. The LER was unclear in this respect because the LER implied that the valves closed due to a
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loss of power. The assistant operations engineer agreed.
The inspector had no further questions. No violations were noted.
4.2.2 Fire Pumps Out of-Service Due to Header Leak On July 31, 1987, while excavating for the foundation of the new radwaste building, a branch of the fire header to the present radwaste building'was found to be leaking.
past a coupling.
The coupling, a clamp-type sleeve,.had apparently been loosened by construction work in preparation for the new building foundation. The contractor workers were digging the area with hand shovels to prevent damaging the fire header pipe when the leak in the coupling was discovered. At 10:08 a.m.
a few minutes before the leak was discovered, the motor driven fire pump (MDFP) automatically started on low system water pressure'(140 psig). About 8 inches of water collected on the 91'6" elevation of the radwaste building due to water leaking past the concrete sleeve to the radwaste building.
Attempts were made to isolate the fire supply to the radwaste building but failed due to leaky isolation valves.
The fire supply to the radwaste building is supplied by two branches, one from the turbine building, and the other from the fire header outside the plant.
The fire water is maintained pressurized to 150 psig with two low capacity high pressure lube water supply pumps (HPLSPs). When pressure continues to drop to 140 psig, the MDFP l
automatically starts.
If pressure dropr. to 130 psig,
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the diesel driven fire pump (DDFP) starts. The MDFP was suf ficient to maintain fire system pressure greater than 140 psig.
At 3:30 p.m., in order to repair the leak, the DDFP and MDFP were temporarily removed from service. The licensee made an ENS call at 4:15 p.m. to report that the fire pumps were inoperable in accordance with Technical Specification 3.14.A.3.
The HPLSPs were also isolated from the fire system.
The pipe was temporarily repaired.
by welding a blank flange.
During the period that the fire pumps were inoperable, no back-up fire supply was provided.
The licensee's basis for this was that both fire pumps could have been returned to service within minutes. TS 3.14.A.3 requires a backup supply within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of removing the two pumps from service.
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At 8:00 p.m. the repair was completed and the fire water system was vented and repressurized using the HPLSPs.
Once the fire water system was repressurized, the MDFP and DDFP were returned to service at 10:45 p.m.
l Construction of the new radwaste building provides for
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replacement of the underground fire water piping behind
the present radwaste. building. This includes
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replacement of the piping from the fire header branch to j
the radwaste building.
The radwaste building fire i
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water is currently being supplied by the turbine building branch until the piping is replaced.
l The inspector reviewed the licensees Suspected Licensee l
Event Report (SLER), upset report, and discussed the event with licensed operators and engineers.
The break occurred and inspected the damage to the pipe.
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inspector toured the area where the fire water header addition, the inspector reviewed the licensee's special report of the event (see section 11.0).
l No violations were noted.
4.2.3 Auxiliary Operator Reading Unauthorized Material On Duty On August 16, 1987, while making a tour of the plant, the Plant Manager discovered an auxiliary operator (AO)
reading unauthorized material (a newspaper) in the A0 break room.
The break room is located on the 116'
elevation of the turbine building.
The A0 has received a letter of reprimand which will be placed in his
personnel records.
The inspector was informed of this I
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item by the Plant Manager. Discussions were held with the Plant Manager, and the inspector had no further
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questions at this time.
4.2.4 Partial Loss of Off Site Power On August 16, 1987 At 5:01 a.m., on August 16, 1987, an overvoltage condition on the No. 2 startup source caused a partial loss of off site power.
The fault in the 220-08 line tripped the SU-25 breaker resulting in the partial loss i
of off site power (No. 2 startup emergency source) to both units.
No. 1 and 4 13KV non-vital auxiliary buses were lost. A fast transfer of the Unit 2 E-12 and E-32, and Unit 3 E-23 and E-43 4KV emergency buses to No. 3
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startup emergency source occurred.
The fast transfers l
actuated as designed and no diesel generator starts were
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required nor occurred. A Unit 2 inboard Group II isolation, a Unit 3 outboard Group II isolation, and a loss of shutdown cooling (SDC) occurred. The "2A" RPS MG
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i set tripped on undervoltage during the fast transfer and resulted in a half scram and closure of the SDC inboard n
isolation valves.
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Unit 2 was in the cold shutdown mode after a refueling
outage with the core reloaded and the reactor vessel head
tensioned. Coolant temperature was approximately 145 i
degrees F.
Unit 3 was in the cold shutdown mode with the coolant temperature.at about 150 degrees F.
.The licensee transferred non-vital loads to the No. 3 startup' source at 5:03 a.m.
The fault on the No. 2 startup source was
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corrected and normal lineup to the No. 2 startup source was I
restored at 5:04 a.m.
Shutdown cooling was restored to l
both units at 5:16 a.m.
The licensee made a four hour ENS i
call at 6:15 a.m. due to the ESF actuations. At 5:46 a.m.,
all emergency buses were normalized. No increase of coolant temperatures resulted.
The inspector reviewed the preliminary upset reports, control room logs, and discussed the event with licensed operators. An LER will be submitted, and the inspector will review it in a future inspection.
No violations were noted.
4.2.5 Partial Loss of Off Site Power On August 20, 1987 At 1:05 p.m. on August 20, 1987, the No. 2 startup source was lost when an 80 ton maintenance crane boom approached the 220-08 KV line at the south end of the station.
The crane operator had been told by his supervisor that the line was de-energized because the plant was shut down.
The crane was moving some mobile trailer boxes that were located between the emergency diesel building and the Unit 2 turbine building. The crane operator positioned the crane to lift the boxes,
placed a vehicle ground to a station ground, and placed i
the crane on the stabilizers. One stabilizer was in contact with a rail of the railroad track to the turbine building.
The crane boom was positioned over the box, nylon lifting straps were affixed to box and the crane boom was
raised to lift the box to a new location, with three workers stabilizing the box with ropes.
As the crane boom approached within approximately five feet of the 220-08 KV line, an electrical arc passed to the crane.
The resulting electrical power surge passed to. ground by the stabilizer and ground line. No workers in the area nor the crane operator were injured.
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The resulting arc from the No. 2 startup emergency source caused supply breaker SU-25 to trip, de-energizing the No I and 4 non-vital auxiliary 13 KV buses by tripping the 2SU-A and 2SU-E breakers. A fast transfer of the emergency buses of Unit 2 (E-12 and E-32) and of Unit 3 (E-23 and E-32) to the No. 3 startup emergency source occurred.
The fa.st transfers actuated as designed. A Unit 2 inboard Group II isolation and Unit 3 outboard Group.II isolation occurred v:ith the loss of shutdown cooling to both units.
Unit 2 was in the cold shutdown mode after a refueling outage, with tha core reloaded and the reactor vessel-head tensioned.
Unit 3 was in the cold shutdown mode in accordance with the NRC Shutdown Order of March 31, 1987.
Reactor coolant temperature in both units was about 150 degrees F.
The licensee transferred loads to the No. 3 startup source at 1:06 p.m.
Shutdown cooling was restored to Unit 3 at 1:15 p.m. and to Unit 2 at 4:40 p.m.
The licensee made a four hour ENS call at
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2:00 p.m., to report the ESF actuation.
The No. 2 startup and emergency source was de-energized to complete the crane operations. At 6:02 p.m., the 13 KV non-vital auxiliary buses were normalized..The 4KV emergency-buses remained on the No. 3 startup source for scheduled work on the 2SU-E transformer. The 4KV emergency buses were normalized at 8:48 a.m. on August 23, 1987, following completion of work on the 2SU-E transformer.
The inspector reviewed the preliminary upset report and control room logs, and discussed the event with licensed operators. The inspector observed the maintenance crane l
after the event and discussed the event with the crane operator, safety representatives, and engineers. A meeting was held by the station safety committee the following day to discuss the safety aspects of this I
event and how to prevent recurrence.
The licensee's immediate corrective actions are to require permission of the plant electrical supervisor before any lifting in i
the area of electrical overhead lines. A directive has l
gone out to all supervisors stating this requirement. A
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review of long term corrective actions will be performed in a future inspection.
Within the scope of the review of this event, no violations were identified.
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4.2.6 Unit 2 Shutdown Cooling Isolations on August 20, 1987 At 10:15 a.m. and 10:35 a.m. on August 20, 1987, Unit 2
lost shutdown cooling due to a group IIB primary containment isolation signal in the "A" RHR isolation logic.
The signal in the
"A" RHR logic causes an inboard and outboard isolation of RHR suction valves M0-2-10-17 and 18 which results in a trip of the RHR pump.
Unit 2 was in cold shutdown with reactor coolant temperature at approximately 150 degrees F. The refueling outage was near completion with the core reloaded and the reactor vessel head tensioned.
Investigation of the cause of the first isolation revealed that fuse 10A-F2A of the "A" RHR logic had blown.
It was replaced; the isolation was reset, and the RHR pump was returned to service. When the second isolation i
occurred at 10:35 a.m.,
fuse 10A-F2A was found blown again.
j Procedure A-42.1, " Temporary Circuit Modifications During i
Troubleshooting of Plant Equipment" was initiated to determine the cause of the blown fuse. The reactor vessel-water level was raised to 50 inches in accordance with l
procedure GP-12, " Core Cooling Procedure," to establish I
natural circulation between the core and the annulus.
The cause of the blown fuse was determined by the licensee to be a flexible metal conduit in the 20C32 panel shorting relay 10A-132A.
The metal conduit had been moved by I&C personnel to facilitate removal of relays while working on modification 959A.
The metal conduit was i
l repositioned, the fuse was replaced, and at 11:25 a.m.,
the isolation was reset.
At 11:38 a.m.,
the RHR pump was returned to service and shutdown cooling was restored.
The inspector reviewed the preliminary upset reports and
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control room logs, and discussed the event with licensed operators.
The conduit and relay in panel 20C32 were also inspected. The licensee intends to submit an LER for this event. The LER and corrective actions will be reviewed in a future inspection.
No violations were noted.
4.2.7 Unit 2 Shutdown Cooling Isolation on August 28, 1987
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The Unit 2 shutdown cooling system isolated at 10:48 while reapplying a system a.m. on August 28,1984,it was in the cold shutdown mode The un i
blocking permit.
with coolant temperature at about 160 degrees F.
The system block called for pulling a fuse (F1 in panel 20C32) that would de-energize the 75 psig isolation signal. This resulted in the closure of the MD-17 and M0-18 valves, and in tripping the 2D RHR pump. The j
licensee replaced the fuse, restored shutdown cooling at i
10:54 a.m., and made an ENS call at 12:38 p.m.
The j
licensee determined that the apparent cause of the-
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isolation was an inadequate blocking sequence on the l
permit, j
The inspector reviewed control room logs, blocking permit #2-02L-87-1855, system electrical schematics, and discussed the event with licensed operators and
engineering personnel.
The system blocking permit had J
been initially applied to perform MOD #1457 (reactor l
level instrumentation) on April 29, 1987. At that time the core was offloaded into the fuel pool and shutdown
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cooling was out of service.
The permit was. temporarily cleared on May 31, 1987, to support shutdown cooling for fuel load, and was.then reapplied on August 28, 1987.
This reapplication caused de-energization of the 75 psig reactor pressure interlock; thus, a shutdown cooling group IIB containment isolation occurred. The inspector
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reviewed the administrative controls for permit
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temporary clearance and subsequent reapplication in j
accordance with procedures A-26, A-41, and the " Rules for Permits & Blocking" handbook.
The inspector i
concluded that the instructions for the reapplication of l
permits do not provide guidance for re-verification of the blocking sequence consistent with possible changing
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plant conditions. This item is unresolved pending I
licensee LER submittal and corrective actions (UNR
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277/87-22-01,278/87-22-01).
I Upon review of the event, the inspector noted that MO-25B, the "A" RHR shutdown cooling injection valve, did not close. Discussions were held with licensee engineers, and the inspector reviewed the~RHR and PCIS
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electrical schematics (MI-S-65 and 23).
Technical
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Specification Table 3.7.1 lists the M0-258, M0-17, and MO-18 valves as PCIS group IIB valves. The notes for the table indicate that PCIS group IIB valves are actuated by reactor vessel low level, high drywell pressure and reactor high pressure during shutdown mode.
The inspector questioned licensee engineers about why MC-25B did not close during the event.
_A review of the electrical schematics indicated that the M0-25B (and o
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M0-25A) valve is not designed to close on a high reactor pressure-(75 psig) signal while in shutdown cooling.
This was also verified by reviewing FSAR section 7.3.
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The inspector stated that the Technical Specification Table 3.7.1 notes need to be modified to eliminate the confusion associated with the PCIS group IIB isolation
.l signals. The licensee agreed and stated that it would
be corrected.
The inspector will review this in a l
future inspection.
q No violations were noted.
4.3 Logs and Records
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The inspector reviewed logs and records for accuracy, completeness, abnormal conditions, significant operating changes and trends,
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required entries, operating and night order propriety, correct l
equipment and lock-out status, jumper log validity, conformance to l
Limiting Conditions for Operations, and proper reporting.
The following logs and records were reviewed:
Shift Supervision Log,
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Reactor Engineering Logs, Unit 2 Reactor Operator's Log, Unit 3 I
Reactor Operator's Log, Control Operator 1'g Book and STA Log Book, l
Radiation Work Permits, Locked Valve Log,
.intenance Request Forms, j
Temporary Circuit Modification Log, and Is. ition Source Control Checklists.
Control Room logs were reviewed for compliance with
Administrative Procedure A-7, Shift Operations.
Frequent initialing j
of entries by licensed operators, shift supervision, and licensee on i
site management constituted evidence of licensee review. With the i
exception of permit reapplication (section 4.2.7),' no unacceptable l
conditions were identified.
4.4 Refueling Outage Activities 4.4.1 Unit 3 Chemical Decontamination The Unit 3 "B" reactor recirculation pump was chemically decontaminated the week of August 10, 1987, to examine the effectiveness of the method used to reduce radioactive contamination within the recirculation piping.
This was
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done in support of the reactor recirculation piping replacement outage scheduled to begin in October 1987.
The method used was the three step LOMI-NP-LOMI (low oxidation-state metal ion-nitric acid permanganate oxide)
process. After blocking closed the suction and discharge valves of the "B" recirculation loop, the solutions entered the piping, passed through the pump, and exited via the chemical addition connection flanges on the valves.
Following the decontamination procedure, the licensee determined that the overall decontamination factor for the piping and pump was 5.2.
The general area exposure was
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l reduced by a factor of 2.1.
The licensee determined that the decontamination method was successful.
Further decontamination'of the reactor recirculation piping is j
planned early in the Unit 3 outage.
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The inspector reviewed the decontamination special procedure, monitored the in plant aspects of the work, and discussed overall decontamination efforts with licensee engineers. The inspector will continue to
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follow the decontamination efforts.
No violations were j
noted.
4.4.2 Unit 2 Core Spray Logic Wiring Error On August 5, 1987, during a modification acceptance test (MAT) for MOD 959A (DC type HFA relay coil replacement),
l the licensee noted a wiring error in the Unit 2 "A" core spray system logic.
Cable 202Q1229G, which terminates in panel 20C32, had two wires swapped between terminals JJ-58 and JJ-61. These swapped wires defeated the one out of two twice logic in the manual opening circuit for the Unit 2 "B" loop inboard injection valve (MO-2-14-128).
Therefore, only one relay (14A-K98) was performing the reactor pressure permissive function.
The inboard injec-tion valve (M0-2-14-12B) is normally closed and is inter-locked with the outboard injection valve (MO-2-14-118) so that both valves cannot be open at the same time when.
reactor pressure is greater than 450 psig. This reactor pressure permissive function protects the low pressure core spray piping from over pressure conditions.
The licensee found an old tag on the affected cable referring to a change in location for one of_the two wires. Apparently, the wires were swapped during this
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The licensee performed various document
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searches and could not pinpoint when or how the wires were swapped.
For corrective actions, the licensee properly rewired the
"A" circuit logic and troubleshoot the system logic for the other loop injection valve (M0-2-14-12A). Also, the licensee performed special procedure SP 1041,1043 and 1044 to verify that the reactor pressure permissive logic was wired correctly for the Unit 3 core spray system, and the Unit 2 and Unit 3 RHR injection valves.
No other discrepancies were found during the licensee review.
During the review, the inspector spoke with the technical engineer and the I&C technical assistant and reviewed the following documents:
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Suspected Licensee Event Report (SLER)
dated 8/5/87;
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A42.1, " Temporary Circuit Modifications During. Troubleshooting of Plant Equipment," Rev..0, 4/18/86; SP 1042, Testing of RHR Reactor Pressure
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Permissive Logic for the MO-3-10-25A and
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B and M0-3-10-154A and B Valves," Rev. O, 8/11/87; SP 1043, " Testing of Core Spray Reactor j
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Pressure Permissive Logic for the
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M0-3-14-12A and B Valves," Rev. O,
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8/11/87;
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SP 1044, " Testing of RHR Reactor Pressure l
Permissive Logic for the M0-2-10-25A and B and M0-2-10-154A and B Valves," Rev. O, 8/11/87; and 6280-M-1-S-40 series electrical schematic
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I diagrams.
The inspector determined that the safety significance of this error was minor.
The wiring error was in the manual valve controls' portion of the logic; the automatic portion of the logic was not affected.
In
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order for a problem to occur, relay 14A-K98 would have i
to receive a spurious low pressure signal (energize)
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when reactor pressure was greater than 450 psig.
In addition, the operator would then have to manually open
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M0-2-14-128 inadvertently. After further reviaw, the licensee determined that this event is not reportable.
The inspector had no further questions or concerns at this time.
No violations were noted.
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4.4.3 Plant Operation Review Committee Meeting The inspector observed a Plant Operation Review i
Committee (PORC) meeting on August 26, 1987.
The meeting, No.87-173, was chaired by the Superintendent of Operations, the designated alternate for the Plant Manager. As specified in Technical Specification (TS) 6.5.1, a quorum of two members and two alternate members was present.
The committee reviewed a proposed change to Technical Specifications, changes in plant procedures, temporary changes to procedures and modifications to plant equipment. The reviews were adequate and were in accordance with TS 6.5.1.6 and 6.5.1.7.
Within the scope of this review, no violations were noted.
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3, 4.5 Degraded Voltage and Undervoltage Emergency Bus Protection i
The inspector reviewed protective. functions for the.4KV emergency buses that prevent damage to safety related equipment in the event; of a sustained degraded voltage or undervoltage condition..The degraded voltage protective-functions are necessary if voltage:
remains between.90% and 60% of rated voltage for extended. periods of time.
The undervoltage protective functions (60%'of rated voltage or less) respond faster and can;also start the diesel generators-if emergency bus voltages are extremely. low (25%;. dead -
bus).
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As part of the review, the inspector held discussions with the system engineer.and reviewed the following documents:
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Peach Bottom Technical Specifications (TS);
Surveillance Tests (ST) 12.4.12, 13, 22, 23, 32,
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33, 42, 43,'"4KV Emergency Power System Voltage Relay Calibration," Revs.-4, 5;
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ST 13.11A, B, C, D, "4KV Undervoltage Relays
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Functional Test," Revs. 4, 5, 6;
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ST 13.12A, B, C, D, " Unit.2 4KV Simulated'
Undervoltage Relay Functional Test," Revs. 1, 2; j
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ST 13.13A, B, C, D, " Unit 3 4KV Bus.Undervoltage
'j Relay Functional Test'," Rev. 4; j
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ST 13.14A, B, C, D, "4KV Simulated Undervoltage
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Relay Functional Test," Rev. 4; and
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S.8.3.D.2, " Unscheduled Tripping of Two Off Site
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Startup Sources," Rev. 8.
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The first degraded voltage protective function consists of an instantaneous relay -(ITE) initiated at 90% voltage that initiates a 60 second time delay relay and a six second time delay relay The six second time delay relay requires the presence of.a safety injection signal in order to function. The second' degraded voltage protective function is an inverse time voltage' relay (CV-6) initiated at 87% voltage. 'At 80% voltage the time delay is l
60 seconds, at 70% voltage the time. delay is 30 seconds, and at 60% voltage-the time delay is 20 seconds. The-first undervoltage protective function is an inverse time. voltage-relay (IAV)
initiated at 60% voltage that initiates a 1.8 second time delay-relay. When any one of.the above_ timing sequences is complete,.
l the corresponding 4KV emergency circuit breaker trips and a fast transfer occurs to the alternate off.. site emergency power source.
The second undervoltage protective function'is an.HGA relay'that initiates at 25% voltage.
It causes a fast transfer.in 0.25 seconds and starts the diesel generators in 0.50 seconds if both
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feeder breakers to the emergency bus are open.
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Technical Specification Tables'3.2.B and 4.2.B state various requirements for the above relays, such as minimum number of operable relays per bus, trip function and setting, and instrument functional testing and calibration frequency. The: inspector determined that surveillance test procedures adequately addressed TS requirements, and the system procedure was consistent with the j
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TS and surveillance test procedures.
The inspector had no further questions in this area, and no unacceptable conditions were noted.
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4.6 Diesel Generator Trip logic In response to an identified potentially generic problem at$ nother'.
plant, the inspector reviewed the Peach Bottom diesel generator (DG)
trip logic.
Certain non-essential OG protective trips are bypassed during accident conditions ~. As stated in FSAR section 8.5, the I
following DG trips are bypassed during a loss of coolant accident
(LOCA) signal (e.g., high drywell pressure or triple low reactor water level):
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high temperature (Jacket coolant or lube oil)
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low pressure (jacket coolant, lube oil, after coolant, or fuel oil)
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high pressure (crankcase)
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Cardox discharge DG trips which are not bypassed include the following:
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engine overspeed (electrical or mechanical)
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electrical fault or overcurrent (generator or 4KV bus)
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anti-motoring (reverse power)
NRC Regulatory Guide 1.9, Revision 2, " Selection, Design, and Quali-fication of Diesel-Generator Units Used As Standby (Onsite) Electric Power Systems at Nuclear Power Plants," states that measures should be taken to ensure that spurious DG trips, other than overspeed and electrical fault, do not prevent the DG from performing its safety function.
The DG auto starts on either a LOCA ("MCA" relay) or dead bus signal (loss of power to the 4KV emergency buses).
The dead bus start requires both startup emergency feeder breakers to be open..and a 0.5 second time delay. During the dead bus start the non-essential DG trips are not bypassed.
The inspector reviewed the DG logic as. stated in FSAR section 8.5; in electrical schematic drawings ES-7, E-188, E-190, and E-193; and, in Colt DG instruction book #E5-49. The inspector also discussed the logic and operation of the DG with the system engineer, licensed operators, and plant management. The inspector verified that the non-essential DG trips are bypassed.during a LOCA signal and are ng
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bypassed during a dead bus start. The inspector reviewed the logic to determine the effect of spurious signals. The following trip coincidence applies:
I non-essential trips are 2 of 3 coincidence except for
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CO (Cardox) discharge which is 2 of 4 coincidence
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overspeed trip is non-coincidence (i.e.,1 of 2)
all electrical fault trips are non-coincidence (i.e., 1
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of 1).
In addition, the inspector reviewed the power supply for the DG trip logic. The logic is powered from station vital batteries (125 VDC)
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as follows:
l E-1 DG - Unit 2 "A" 125 VDC
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E-2 DG - Unit 2 "B" 125 VDC
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E-3 DG - Unit 3 "C" 125 VDC
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E-4 DG - Unit 3 "D" 125 VDC
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The inspector questioned whether the DG trip logic is periodically tested including the bypass features.
The system engineer stated that ST 8.1.6, " Diesel Generator Annual Inspection Post Maintenance Test," Revision 6, May 18, 1987, verifies the correct DG logic.
ST 8.1.6 is performed after the DG annual inspection as required by Technical Specification 4.9.A.I.e.
The inspector reviewed ST 8.1.6 and verified that the "MCA" relay bypass of the non-essential DG trips during a LOCA is tested. Also, the non-essential DG trips are j
each tested during the performance of ST 8.1.6.
The inspector discussed the DG trip logic with PECo corporate electrical engineering.
DG trip logic and bypass features are also being reviewed for the Limerick Station.
Pending further review by l
the NRC, future followup inspection may be warranted.
No violations were noted.
5.0 IE Information Notices Which Require No Response l
5.1 RHR pump Motor Surge Ring Brackets j
t NRC Information Notice No. 87-30, " Cracking of Surge Ring Brackets I
in Laroe GE Electric Motors," was issued July 2, 1987.
The Notice j
alerts recipients to a potential problem associated with the loss of large GE electric motors caused by the cracking of the surge
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ring brackets (also referred to as " stator ring support clips").
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These brackets or clips are "L" shaped; made of carbon steel; are
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about 2" x 1" long, 1" wide and 1/8" thick; and, are welded to the stator surge ring and bolted to the motor casing. Their purpose is to assist the stator surge ring bracing structure withstanding the additional starting forces and in minimizing possible stator coil movements during full voltage motor starts.
Failure of these l
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brackets may lead to a reduction in motor insulation resistance and possible motor failure, or may cause motor degradation / failure
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due to the broken loose parts.
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PEco initiated M3dification (M00) #1742 in August 1985 based on
.n recommendations from GE to remove the brackets from the RHR pump
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motors. This recommendation was based on an observed-adequate condition of stator windings and provided the period without the-
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brackets was limited to an 18 month operating cycle.
PEC0's safety evaluation (August 8, 1985) concluded that the removal of the.
brackets ar not an unreviewed safety question, nor was a Technical Specification change required.
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The brackets were removed from all Unit 3 RHR pumps (3A, 3B, 3C,
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3D) during the 1985-1986 oute.ge; anos from two' Unit 2 RHR pumps (2A, 2C) during a December 1985 mini outage. The 2B and 20 Unit 2 RHR pumps were inspected and the brackets were not removed.
TheinspectorreviewedMODpackage#!74),includingthesafety i
I evaluation, completed MRFs, GE correspondence, and the special f
procedure (SP 841) for b*acket removal.
The' inspector also reviewed Information Notice No. 87-30 and discussed this subject with licensee engineers. The licensee. stated that corporate i
engineering was in contact with GE regaroing justification for Unit 2 operation for an additional cycle, with only the 2A'and 2C RHR pump motor surge ring brackets removed.
In addition, longer term modifications and/or corrective actions for all of tne Unit 3 I
RHR pumps, as well as the 2A and 2C Unit 2 RHR pumps are to be
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addressed by the licensee. This item is unresolved pending licensee
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review and approval of the safety evaluation and corrective actions,
and subsequent NRC review (UNR 277/87-22-02;278/879-02).
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No viciations were identified
6.0 Review of_ Licensee Event Reports (LERs)
I 6.1 LER Review The i'ispector reviewed LEh to verify that the details were clearly reported, including the accuracy of the description and corrective act on adequacy.
The inspector determined whether further information was required, whether generic implications were incicated, and whether the event warranted on-site followup.
The following LERs were reviewed:
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LER No.
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LER Date Event Date Subject
- 2-87-07, Rev. 1 Scram with core offloaded August 5, 1987 June 39, 1987
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- 2-87-07 Scram with core offloaded
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July 17,1987 June 19, 1987
- 2-87-10 ESF actuation due to an inadequate blocking July 30, 1987 permit
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June 30, 1987
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- 2-87-11 ESF actuation due to blown fuse August 10, 1987 July 10,1987 l
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- 2-87-12 Partial loss of off site power j
l August 10, 1987
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i July 10, 1987
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- 2-87-14 ESF actuation due emergency bus breaker August 27, 1987 opening July 28, 1987
3-87-01, Rev. 1 Unit 3 scram on high flux due to EHC failure l
July 17, 1987 March 17, 1987 6.2 LER On-Site Followup i
For LERs selected for on site followup and re:iew (denoted by asterisks above), the inspector verified that appropriate
corrective action was taken or responsibility assigned and that continued operation 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 2-87-07 concerns an unplanned shutdown reactor scram with no rod motion that occurred on June 19, 1987, on Unit 2 with the core' offloaded during IRM testing.
The event was reviewed in NRC Inspection 277/87-17. The licensee review of the event concluded that both personnel error and procedural inadequacies caused the unplanned scram.
The reactor operators involved were given oral warnings and the senior reactor operator was
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counselled. The licensee revised the IRM surveillance test procedure (ST 3.2.3).
The revision added a caution to discontinue use if unexpected response occurs, and also for clarity, split the procedure into two sections (one for each RPS channel). The inspector discussed the LER with the licensee and verified the procedural changes.
The inspector had no further questions at this time.
6.2.2 LER 2-87-10 concerns an ESF actuation on Unit 2 caused by an inadequate blocking permit. The event was reviewed during NRC Inspection 277/87-17. No inadequacies were noted relative to this LER.
6.2.3 LER 2-87-11 concerns an ESF actuation on Unit 2 caused by a blown fuse for unknown' reasons. The event was reviewed during NRC Inspection 277/87-17. No inadequacies were noted relative to this LER.
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6.2.4 LER 2-87-12 concerns a partial loss of offsite power when a lightning strike tripped the #3 startup source for Unit 2 and 3.
The event was reviewed in NRC
Inspection 277/87-17 and 278/87-17. No inadequacies were noted relative to this LER.
6.2.5 LER 2-87-14 concerns an event which is discussed in i
section 4.2.1 of this report.
7.0 Surveillance Testing The inspector observed surveillance tests to verify that testing had been properly scheduled, approved by shift supervision, control room operators were knowledgeable regarding testing in progress, approved procedures were being used, redundant systems or components were 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:
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ST 9.32-2,3; Reactor Cold Shutdown Data Log, performed hourly on
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I both Unit 2 and 3 during the inspection period.
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No inadequacies were identified.
l 8.0 Maintenance j
For the following maintenance activities the inspector spot-checked administrative controls, reviewed documentation, and observed portions of the actual maintenance:
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Maintenance Procedure /
Document Equipment Date Observed M-4.400 and Reactor Cavity Decontamination July 21, 1987 Associated (Unit 2)
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Traveller
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M-4.408 Vessel Head Stud Decontamination July 27, 1987 (Unit 2)
l M-4.411 Install Vessel Head (Unit 2)
July 28, 1987 M-4.401 Heating Reactor Vessel Head July 28, 1987 (Unit 2)
M-4.412 Cleaning and Tensioning Reactor July 29, 1987 Vessel Studs (Unit 2)
SP-1039 Control Room Board Upgrades'and Various (MOD #2132)
Painting l
SP-1040 Unit 2 Drywell Sumps August 9, 1987 Decontamination Administrative controls checked included maintenance request forms (MRFs), blocking permits, fire watches and ignition source controls, item handling reports, QC involvement, plant conditions, TS LCOs, equipment turnover information, and post maintenance testing.
Documents reviewed included maintenance procedures, material certifications RWPs, MRFs, and receipt inspections.
l No inadequacies were identified.
i 9.0 Radiation Protection l
9.1 Routine Observations 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, use of radiation protection instruments and handling of potentially contaminated equipment and materials.
The inspector observed individuals frisking. in accordance with HP l
procedures. A sanpling 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-l I
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i personnel had provided the required information, and people working in RWP areas were observed to be meeting the applicable requirements. No unacceptable co'nditions were identified.
9.2 Access Control System On August 1, 1987, the licensee implemented the Access Control System Program.
This is a total exposure accountability program Most entries to the power block RCA are through the main access
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for personnel exposure in all radiological control areas (RCA).
control point located in the ground level access control facility.
Limited access to the power block is provided thru the access
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control point established at the bridge between the administration building and the turbine building. All entries to any RCA require either a radiation work permit (RWP), a general purpose RWP, and if a specific job is to be performed, a specific RWP.
At the control point the worker receives a briefing on the RWP, I
reads or reviews the RWP, and signs the RWP.,
Then the worker is
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issued a self reading dosimeter (SRD) and a dose card which contains i
the record number, the time on and off the RWP and the dose l
l accumulated during the time interval on the RWP. The system is j
l designed to provide documentation of each entry to the RCA so that methods of reducing total radiation exposure can be. applied. The dose card method of recording will be replaced by a computer system at a later date.
To support the program, a temporary building was constructed at l
I the north end of the Unit 3 turbine building which houses the main
access control point, RWP of fice, applied health physics j
supervisor, and the ALARA section. All workers requiring entry to the RCA were required to attend Health Physics Procedures Training which covered the changed procedures HP-310, " Radiation Work Permits," and HP-601, " Access Control and Dose Tracking." The
changeover to the new program met with minimal disruptions due to the
efforts of applied health physics personnel and to the commitment to
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training of the workers previous to the changeover.
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The inspector reviewed the overall implementation including the HP
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procedures, and attended the training class for access control.
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This new access control system will be continuously reviewed in I
future inspections. No inadequacies were identified.
9.3 High Contamination Levels in the Outboard Main Steam Isolation Valve (OBMSIV) Room During the Regional Administrator!s tour of the Peach Bottom facility on August 11, 1987 (see section 4.1.14), a review of the surface contamination levels in the Unit 2 OBMSIV room was
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l conducted.
Pre-1987 refueling outage surveys (February 15;. March 14, and 21) were reviewed and compared to post-maintenance surveys
(June 9 and July 28,1987).
Contamination levels increased from a i
maximum of 20 mrad /hr/sq.ft. to 120 mrad /hr/sq.ft. Other contamination I
levels in the room also increased.
Similar high levels of loose surface contamination levels were also noted in the reactor water cleanup rooms These high contamination levels are indicative of-long standing maintenance deficiencies.(i.e., leaks) and make it
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difficult to perform work in the area due to protective clothing requirements.
The licensee acknowledged these concerns and this item will be reviewed in a future inspection.
10.0 Physical Security W
10.1 Routine Observations The inspector monitored security activities for compliance with
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the accepted Security Plan and associated implementing procedures, I
including:
operations of the CAS and SAS, checks of on-site vehicles
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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.
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10.2 Drug Use by Sergeant of the Guards On July 27, 1987, a contractor Burns Security Sergeant of the
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l Guards was given a routine annual physical examination, which includes a drug screening test. On August 4, 1987, the licensee was notified that the individual had tested positive for marijuana. The individual was interviewed and he admitted to using marijuana.
He stated that he had never reported to work under the influence of marijuana, nor had he ever used it on site.
The individual's employment was terminated, his security badge was pulled, and the Nuclear Employee Data System (NEOS) was notified.
As an added precaution, all key cores within the protected and vital area were changed on August 5 and 6, 1987. The inspector had no other questions or concerns at this time.
11.0 In-Office Review of Public and Special Reports The inspector reviewed the following:
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Peach Bottom Monthly Operating Report for June 1987, dated July 15, 1987.
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Peach Bottom Monthly Operating Report for July 1987, dated August 14, 1987 l
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Special 14-day report:
"Both Fire Pumps Out of
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Service", dated August 14, 1987.
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No unacceptable conditions were noted.
12.0 Unresolved Items Unresolved items are items about which more information is required to ascertain whether they are acceptable violations or deviations.
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Unresolved items are discussed in sections 4.2.7 and 5.1.
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13.0 Management Meetings 13.1 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 j
included in this report.
13.2 Attendance at Management Meetings Conducted by Region Based Inspectors Inspection Reporting Date Subject Report No.
Inspector 8/10-19/87 QA/QC 87-23/23 Napuda 8/3/87 Enforcement 87-17/17 Kane Conference