IR 05000280/1984036
| ML20127N842 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 02/19/1985 |
| From: | Burke D, Marlone Davis, Elrod S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20127N606 | List: |
| References | |
| 50-280-84-36, 50-281-84-36, NUDOCS 8505230619 | |
| Download: ML20127N842 (9) | |
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NUCLEAR REGULATORY COMMISSION -
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o REGION 11
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101 M ARIETTA STpEET. N.W.
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o ATLANTA, GEORGIA 30303 t
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Report Nos.: 50-280/84-36 and 50-281/84-36
.. Licen see: Virginia Electric and Power Company i
Richmond, VA 23261 Docket _Nos.:.50-280 and 50-281 License Nos.: DPR-32 and DPR-37
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Facility Name:
Surry Units 1 and 2 7;
Inspection Conducted:
December.1, 1984 - January 4, 1985 Inspectors: [ w / M d._, E A[l9 fI
- D/ J. Burke, Senfor )fesident Inspector D&te Signed
+ J hsr L ah1W M/ J. Davis' Re 16ept Inspector SatefSigned
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-Approved by:
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S'. 'Elrod, Section Chief
'Dat'e Signed Division of Reactor Projects
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SUMMARY
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Scope: This routine, unannounced inspection involved 200 inspector-hours on site in the areas of' plant operations, and. operating records, refueling operations, plant maintenance and surveillance, plant security,- followup of events, and licensee event reports.
.Results:
In the areas ' inspected, one violation was identified in the area of
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plant operations; opposite unit AFW system not available as required by TS 3.6.D-
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paragraph 5.F.
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REPORT DETAILS 1.
Licensee Employees Contacted R. F. Saunders, Station Manager
'D. L. Benson,~ Assistant Station Manager H. L. Miller,~ Assistant Station Manager D. A. Christian, Superintendent of Operations M. R._Kansler, Superintendent of Technical Services H. W. Kibler, Superintendent of Maintenance D. Rickeard, Supervisor, Safety Engineering Staff S. Sarver, Superintendent of Health Physics R. Johnson, Operations Supervisor R. Driscoll, Site QA Manager E. Grecheck, Superintendent of Technical Services (from December 24,1984)
W. R. Runner, Supervisor, Administrative Services Other licensee employees contacted included control room operations, shift technical advisors (STAS), shift supervisors, chemistry, health physics, plant maintenance, security, engineering, administrative, records, and contractor personnel and supervisors.
2.
Exit Interview The inspection scope and findings were summarized on a biweekly basis with certain individuals in paragraph 1 above.
3.
' Licensee Action on Previous Enforcement Matters This subject was not addressed in the inspection.
4.
Unresolved ~ Items Unresolved items were not identified during this inspection.
5.
Operations a.
Unit 1 and 2 were inspected and reviewed during the inspection period.
The inspectors routinely toured the control room and other plant areas to verify that' plant operations, testing, and maintenance were being conducted in accordance with the facility Technical Specifications (TS)-
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and procedures. The inspectors verified that monitoring equipment was recording as required, equipment was properly tagged, and plant housekeeping efforts were. adequate.
The inspectors also determined that appropriate radiation controls were properly established, clean areas were ~ being controlled in accordance with procedures, excess material or equipment was stored properly, and combustible material and
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. debris were disposed of expeditiously. During. tours, the inspectors
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' looked for~ the existence of unusual fluid leaks, piping vibrations, piping hanger and seismic restraint settings, various valve and breaker positions, equipment caution and danger tags, component positions, adequacy of. fire fighting equipment, and instrument calibration dates.
Some tours were conducted on backsbifts. Inspections included areas in the Unit I and 2.' cable vaults, sitchgear rooms, control rooms, auxiliary building, and cable penetration areas to verify certain breaker and equipment positions for safety related components. The inspectors routinely conduct partial walkdowns of Emergency Core Cooling System (ECCS) and Engineered Safeguards Feature (ESF) systems.
b.
Unit 1 ' began.the reporting period in a cold shutdown condition completing a refueling and maintenance outage. The unit was restarted on December 25, 1984, in preparation for low power physics testing.
Unit 1 experienced a reactor trip on December 31 during performance of PT 8.1, the periodic test of reactor protection logic. During testing of the recently installed auto shunt trip device on the 'A'
reactor trip breaker (RTB), instrument technicians apparently bumped or inadvertently depressed the 'B' auto shunt trip test pushbutton (both A and B pushbuttons were labeled 'B') or the breaker itself, causing.the
'B'
reactor trip breaker to open and the reactor to trip.
Safety
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systems functioned normally. The unit was subsequently restarted and returned to power operations. Additional labeling and protection were installed on the breakers and. circuitry to prevent recurrence. The inspectors also recommended that a stepstool or small ladder be available for the auto shunt trip test so the technician does not have to. stand on the instrument suitcase (s) in the RTB cubicle to reach the test buttons; the licensee agreed.
c.
'The inspectors were also concerned with the length of time a simulated
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or dummy signal was placed into the 'B' loop RTD, protection channel II circuitry due to nuclear instrumentation (NI) calibration problems. At 11:47 a.m.
on December 31, 1984, the instrument technicians placed
. simulated signals into the channel II temperature circuitry which feeds the over pressure (0P) and over temperature (OT) delta temperature (T)
protection systems, to prevent a reactor trip while rescaling/recali-
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brating the NI. Channel II bistables had been placed in the tripped condition due to an erratic RTD output in this channel, however, this trip must be removed during NI rescaling since the NI feeds into the OP and OT delta T channels (1-PT-2.1 was used).
At 1:24 p.m.
on December 31, 1984, the reactor trip discussed above occurred; the unit was restarted at 6:00 p.m.
At 1:00 a.m. on January 1,1985, operation personnel reaffirmed that a simulated signal was still being inputed to channel II with the bistables in the untripped condition (Reactor at 35 percent power). The NI was rescaled and the bistables returned to the tripped condition by 3:30 a.m.
The calibration problems with the l
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NI was due -to r al setpoint miscalculation received from the nuclear Lengineer; 'an -incorrect -power level was referenced for the setpoints provided. :The error was corrected and the NI reset by the end of the
. day. _.Therefore, -the ' 0P and "0T delta.T -protection circuitry did not
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fulfil 1 Ethe degree of redundancy (operable channels / minimum channels needed to. trip -RPS) requirement in TS Table -3.7-1, items 5 and'6, for
.approximately 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> (required redundancy was 1; actual was0).
lHowever, TS 3.7.C permits blocking of failed Table 3.7.1 channels.for short periods ofitime when operable channels are tested, to prevent ~
unnecessary reactor trips. The' event will be discussed in an LER.
d.
' Unit 2 began the reporting period operating at full = power. The unit experienced a trip from full power on December 11, 1984, when electri-cians working on a temperature controller circuit for the
'A' Boric Acid Storage Tank accidentally droppe'd aL screw into the electrical 3 junction box which_ caused a short on the number 1 vital instrument bus and resulted in a momentary voltage spike on the bus. This caused a pressurizer high level signal on channel 1.
Channel 2 pressurizer high level was ~already. in the trip mode due to a valve packing leak, which1
'had recently been repaired; technicians were awaiting refill of the reference leg,-which takes several hours, before returning the channel
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to - normal. Coincidence of the channel 1 and,2 signals resulted in the reactor trip. Safety systems responded normally.
During the subsequent restart later.that aday, another turbine trip /
reactor trip 1was experienced.
the turbine trip was caused by a low condenser vacuum condition due to a manway. leak on the main steam-cross
'under piping. The. leak was due to a gasket problem on the manway which was subsequently repaired. ' Safety systems responded normally. 'The 33-unit was subsequently returned to power operation.
On December 16,1984,- Unit 2 was ramping down to repair an unisolable
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steam leak on a high pressure turbine drain'line. At approximately.20
. percent power with the ' A' main feed _ pump secured, the 'B main _ feed
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pump tripped due to low flow caused.by a' sluggish feedwater recircula-tion valve response.
The loss of both. main feed pumps initiated a
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turbine ' trip and subsequent reactor trip. 'All systems responded normally. :The unit was restarted later that day.
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Unit 2 performed a normal rampdown on December 30, 1984, to secure the main turbine for repair of 2-SD-42, a manual-isolation valve downstream g
of the nonreturn valve in the high pressure (HP) heater drain line
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? going to the HP heater. drain tank. The valve disk _had become separated from the' valve stem and had beenLlimiting power to approximately-86 percent. Following repair-of 1-S0-42, the unit -experienced a reactor.
' trip shortly after the turbine was placed on line. The reactor tripped Edue to low level on the -'B' steam generator with a steam flow / feed flow mismatch due to operator error in controlling feed flow manually. All
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systems responded normally. The unit was subsequently restarted and finished the reporting period operating at power.
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e.
During the recent refueling outage, a spare reactor coolant pump (RCP)
electrical motor from North Anna was installed on the Unit 1
'B'
reactor coolant pump. The motor from the IB RCP was installed in the Unit 2A RCP which had been damaged during a reactor trip recovery on October 29, 1984. The old 2A RCP motor will be installed in Unit-1 following motor inspections and repairs.
Since the North Anna motor is of a different physical configuration, the Unit IB RCP oil leak collection system in place at Surry could not be used.for fire protection.
The inspectors verified that the compensatory measures discussed in VEPCO's letter of November 16, 1984,
. Serial Number 665, for operation with an interim oil leak collection arrangement were in place.
Specifically, reduced setpoints for temperature-related parameters on the 'B' RCP have been placed in the computer.
These parameters are being displayed on the digital trend monitor. Additional heat detec-tion instrumentation has also been installed. Annunciator procedures have been revised to require immediate investigation to determine the reason for increasing temperatures or alarms; shutdown of the affected pump and response by the fire brigade is also specified. Fire brigade members have received special training instructions and training on the potential for fire in the IB cubicle and on the means to mitigate such-fires.
Fire suppression equipment is being maintained by the containment entrance hatch for use by the fire brigade in the event of a lube oil fire. Refrasil fire protection material covers were added on the floor penetrations on the minus three foot six inch elevation and a four inch lip was added to the cubicle entrance floor so that any oil leakage into the cubicle will be contained in the cubicle or delivered to the containment sump through the floor drains.
Spray shields were ' also-installed on the RCP piping and oil lines to prevent oil from spraying into the hot surfaces or reactor coolant-piping.
f.
During Auxiliary Feedwater (AFW) system inspections in the steam safeguards building on-December 4,1984, licensee personnel discovered
- an alignment error in the discharge valves which crossconnect the Unit 1 AFW system to Unit 2, (Unit 2 was operating at power and Unit I was in the cold shutdown condition). To perform maintenance on certain Unit _1 AFW motor operated valves (MOV) (e.g - MOV-FW-1510), the six inch discharge header WAPD-1-601 was isolated by closing manual AFW valves 1-FW-155, 170, and 140, and removing electrical power from normally closed AFW cross-tie valve MOV-FW-260A, which was correct per piping and instrumentation diagram (P&ID) print FM-68B. This valve tagout was implemented on September 28 and 29, 1984. Electrical power was restored to MOV-FW-260A and its electrical breaker 1H1-211 on November 15, 1984, following fire protection electrical upgrading. An
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error: on Print FM-688 showed MOV-FW-260A connected to AFW discharge
. header WAPD-1-601 and. manual valves 155,170, and 140, when in fact, the. cross-tie valve MOV-FW-260A was connected to the alternate - ARd discharge header WAPD-2-601 and manual valves L 156,171, and 141 from
.the AFW pumps..Therefore, with the Unit I side valves 1-FW-155,170, and 140 closed and power removed. from MOV-FW-260A, neither Unit 1. ARd.
train was available to Unit 2 from September 28, 1984 until October 29, 1984, at which time Unit:2 was shutdown below 350 degrees F in the RCS.
Since TS 3.6.B.1 and 3.6.D require that one of the three.AFW pumps for the opposite unit shall be available, including system piping, valves, a'nd control board indication required for the operation of the opposite-unit AFW pump,- this is a_ violation (50-281/84-36-01).
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The. inspectors verified that the AFW cross-connect line installation
. from Unit 2 matched the ' installation described on P&ID print FM-688.
Three AFW pumps and two main feedwater pumps were operable as required
~ for Unit 2; two AFW pumps on Unit I were also. " operable.". If a fire
' had occurred ' in 'the Unit 2 safeguards room which houses the -three
. Unit'2~AFW pumps, operators could use the main feedwater pumps, reclose
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the electrical breaker.1H1-211 beneath the control room, or manually
' open MOV-FW-260A to supply-water to the Unit 2 steam generators.
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weakness in the valve alignment' checkoff sheets was subsequently noted by the -inspectors. The Unit-2 valve checkoff sheet OP-31.2A verifies.
.that valves 2-FW-270 and 271 are open and MOV-FW-160A and 160B are closed and energized. While :these valves are located in the Unit 2 safeguards building, they. are not associated with Unit 2 ~ LCO, but are required for Unit.1~ operation. A similar example exists in the Unit-1 operating procedure OP-31.2A. The licensee is' revising these proce-dures, g.
' Several needed procedural corrections in addition to those discussed above have been identified: The Surry Emergency Plan (SEP), Section 4,
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-Emergency. Conditions, which ' details the initiating conditions for Site
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Area Emergencies (SAE) and General Emergencies (GE), contained typo-
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graphical errors.
For example, page 4.37 in the SEP requires GE conditions when the Process Vent (PV): monitor indicates incorrectly greater than "5X10X10+1," owhile EPIP-1.01 requires the same for:PV activities : greater than -5.10 E+1 uCi/cc. Also, page 4.27 in the SEP ~
requires SAE conditions when-the Ventilation Vent (VV) monitor indicates-greater than 2.26XE+2 uCi/cc, while EPIP-1.01 requires the same for VV~
-activities' greater than 2.26XE-2 uCi/cc.
The SEP is being corrected.
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.DieselsGenerator Fire On. December 18,1984, at 7:40 a.m.,
while conducting a preservice test on
.the number. 3 Emergency Diesel Generator (EDG), a fire broke out in the area
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of the exhaust driven turbocharger. Operators attempted to extinguish the fire with a dry chemical hand held unit, but a reflash condition occurred.
The operators exited the cubicle and actuated the Carbon Dioxide deluge system.
The deluge system functioned normally and the fire was extin-Lguished._ A Notification of an Unusual Event was declared and implemented.
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A leak on the number 1 cylinder fuel injector tube fitting had caused fuel oil to drain into the oil crankcase. This led to the failure of the turbo-charger bearings / bushings and a fuel / oil mixture leak into the exhaust side of the turbo-charger which ignited. Operators extinguished the fire in the area of the turbocharger twice prior to exiting the cubicle. Vapors in the crankcase subsequently ignited, blowing certain valve covers and inspection port covers off the diesel casing.
The fuel injector nozzles had been replaced during the recent Unit 1 refueling outage; the fuel tubing appeared somewhat loose and not properly e
seated into its fitting. Maintenance personnel inspected the injector lines on the redundant EDG and found no leaks.
Following replacement of the turbocharger unit, th'e number 3 EDG was thoroughly inspected and satisfactorily tested on December 20, 1984, and returned to service within the seven day time limit required by the TS.
The oil in the EDG is sampled and analyzed for impurities and viscosity on a quarterly basis. The inspector noted that evidence of number 2 fuel oil was-previously detected in Februar.y 1984, and August 1983, in the number 3 EDG crankcase sump; action was taken and the oil in the EDG was changed. The viscosity of oil in EDG number 1 and 2 did not vary significantly during 1983 or 1984. The licensee will consider scribing and monitoring the EDG crankcase _ oil level dipsticks on a daily basis to detect abnormal level changes. The number 3 EDG sump, which normally holds 465 gallons of oil, increased by approximately 60 to 70 gallons due to the fuel leak, while the hot and cold oil viscosity decreased from 75 and 907 Saybolt Universal Standard (SUS) to 44 and 164 SUS units respectively.
Open Item (281/84-36-02) - Daily 011 level Inspections of EDGs.
7.
Maintenance Inspection Items Prior to' the Unit I restart from the refueling and maintenance outage, the inspectors-inspected, reviewed, or. verified the following items:
a.
The stuck Unit 1 peripheral control rod (B-6) dropped to the fully inserted position when the lifting tool was placed on the rod.
Subsequent examination in the spent fuel-pool determined that one of the two L-shaped corner clamps atop the fuel assembly was missing. The corner clamps hold the upper fuel assembly leaf springs in place and are secured to the fuel assembly with two hex hold-down bolts; the bolt heads are tack welded to the clamp. Both bolts were found sheared; the bolt heads were in the corner clamp and the threaded sections were still in.the fuel assembly.
All parts were recovered. The corner clamp was found in the assembly and determined to have caused the stuck rod. No additional failures of this type were found during subsequent inspection of the fuel assemblies; all corner clamps were observed in place and intact. The vendor-(Westinghouse) stated that only one other failure of this type has occurred with approximately 4,000 assemblies in use, and thus does not consider the failure to be generic.' A supplement to the LER will be submitted.
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b.
The. inspectors toured and inspected the Unit I containment during refueling - operations and. prior to restart to ascertain that systems were properly tested and operable following outage maintenance and that
' work was performed in accordance with approved procedures.
-1.
The inspector discussed type C testing on new Unit 1 fuel transfer chute flange (PT16.3A). Although the new installation did not provide appropriate test connections, the licensee satisfactorily tested the area between the end flange o-rings and the seal weld area as required utilizing special procedures.
2.
The inspectors observed small areas of rust or peeling paint on a Service Water System piping elbow attached to the "A" recircula-tion Spray Heat Exchanger, the containment lines in the area of the RHR. flat, and the ventilation duct on a containment recir-culating air fan and cooler. - The painted areas (approx. I sq. ft.
or less) appeared to have been nicked or bumped, which exposed the metal surface and precipitated rust formations between the metal and paint, which led to peeling. All such areas were sanded or brushed to remove the rust or loose paint.
3.
The containment sumps were properly cleaned and washed; no debris l
was observed prior to startup.
c.
The' inspectcrs observed portions of Design Change (DC) 82-35, M0V rerate work on the Unit 1 Service Water (SW) MOV SW-103A-D. The DC installed larger Limitorque operators (SMB-00) on the valves to ensure operation during reduced voltage conditions.
Limiting plates were installed on 'the torque switch.es to limit forces on the valve and stem; additional documentation detailing the adequacy of the butterfly valve
stems with the larger operators was placed in the DC package by engineering. The inspectors also observed.that the SW valve discs were clean, but not' repainted with marine growth inhibitor due to the more stringent painting requirements implemented at the station. Since the painting did appear to reduce marine growth in the valves,-the licensee will work to approve this painting and reinstate it in their SW MOV procedures.
8.
LER Review
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The inspectors reviewed the Licensee Event Reports (LERs) listed below to ascertain that NRC reporting requirements were being met and to determine the appropriateness of corrective action taken and planned.
Certain LERs
.were reviewed in greater detail to certify corrective action and determine compliance with TS and other regulatory requirements. The' review included examination of logbooks, internal correspondence and records review of Station Nuclear Safety Operating Committee (SNSOC) meeting minutes, and discussions with various staff members.
Within the areas inspected, no violations were identified.
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- (Closed) 'LER 280/84-13 concerned' the cycling of _ a power operated. relief
- valve,(PORV)'in. response to an overpressure condition while the. unit _was at
- cold shutdown. The event-occurred while placing the charging system in-service when the charging pump discharge valves'were opened. The event was caused; by the. improper preparation and verification of.a -tagging report prepared for s maintenanceT on the Boron - Injection Tank -bypass line flow-
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eelement,11-SW-1940.. Valve 1-SI-174, the normally closed flow element bypass valve,-~as returned to the open position following tag clearance. The. valve w
. was closed and adde,d to the Containment Integrity Valve Checklist to prevent
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overpressure events.
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-~(Closed) LER 280/84-14 concerned ~a reactor trip due to the loss of the 1A
. main feed pump.; The feed. pump had tripped on -loss. cf -lubrication oil
- pressure due _ to' sheared lube. oil -lines. The oil line-sheared when bearing i housing capscrews vibrated 1_oose allowing.the _ bearing housing to spin with the pump shaft. _Following repairs'to the pump'the Unit was restarted.
(Closed) J LER 280/84-16 concerned a reactor trip from low power during auxiliary-feed pump testing when 2_of 4 nuclear power channels exceeded 10 percent. power _ without the turbine being latched.
Precautions have. been
.added to_ station procedures OP-1.4 and PT 15.1c toLprevent testing the steam
. driven auxiliary feed pump near the P-10 setpoint without the main turbine bei.ng latched.
.(Closed) LER 280/84-22 concerned a' contract employee.eceiving greater than.
1.25 rem durings the third quarter of 1984 without. having a properly-completed NRC Form 4.on file. The individual-. failed to thoroughly review
. exposure history. data utilized in preparation of the NRC form 4.
The
- Training Department was instructed to emphasize the importance of disclosing-all information requested-by NRC Form 4 to prevent a similar event.
(Closed) -LER ~281/84-01'. concerned a manual reactor _ trip initiated upon
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closure of the
'A' main steam trip valve.
A' crack in an - air line pipe
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nipple on the valve actuator allowed pressure to bleed allowing the disc to be deflected and closed by main steam. The leaking nipple was replaced and-instrument - air lines of all ' main steam trip valves were inspected and
' tested.
9.
' Plant Physical Protection The inspectors verified the following by observation.
a.
. Gates and doors in protected and vital area barriers were closed and locked when.not attended.
b.:
Isolation zones described in the physical. security plans were not compromised.or_ obstructed.
c.
Personnel were properly identified, searched, authorized, badged and escorted as necessary for plant access control.
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