IR 05000280/1982001
| ML20054D977 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 03/01/1982 |
| From: | Bruke D, Burke D, Dance H, Marlone Davis NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20054D960 | List: |
| References | |
| 50-280-82-01, 50-280-82-1, 50-281-82-01, 50-281-82-1, NUDOCS 8204230560 | |
| Download: ML20054D977 (7) | |
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UNITED STATES g
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NUCLEAR REGULATORY COMMISSION n
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E REGION li 101 MARIETTA ST., N.W., SUITE 3100 o,
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ATLANTA, GEORGIA 30303 s
Report fios. 50-280/82-01 and 50-281/82-01 Licensee:
Virginia Electric and Power Company Richmond, VA 23261 Facility flame: Surry Units 1 and 2 Docket flos. 50-280 and 50-281
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License fios. DPR-32 and DPR-37 InspectionatSrrysftenearSurry, Virginia Inspectors:
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3 hffL ft. J. Davis
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06 te' Signed Approved by:
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C. Dance, Section Chief, Division of Date Signed Resident and Reactor Project Inspection SUlitiARY Inspection on December 14, 1981 - January 22, 1982 Areas Inspected This inspection involved 220 resident inspector-hours on site in the areas of
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plant operations and operating records, plant maintenance, calibration, testing, licensee event reports, and plant security.
Results In the six areas inspected, no violations or deviations were identified in five areas; one violation was identified in the area of testing (failure to take prompt and adequate. corrective action on Unit 2 containment leakage identified
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Jduring routine testing'- paragraph 8).
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DETAILS 1.
Persons Contacted Licensee Employees
- J. L. Wilson, Station Manager
- R. F. Saunders, Assistant Station Manager
- G. E. Kane, Operations Superintendent D. A. Christian, Superintendent of Technical Services
- D. Rickeard, Supervisor, Safety Engineering Staff S. Sarver, llealth Physics Supervisor Other licensee employees contacted included control room operators, shift supervisor, WC, llP, plant maintenance, security, engineering, chemistry, administrative, records and contractor personnel.
- Attended exit interview 2.
Management Interviews The inspection scope and findings were summarized on a biweekly basis with those persons indicated in paragraph 1 above.
3.
Licensee Action on Previous Inspection Findings Not inspected.
4.
Unresolved items Unresolved items were not identified during this inspection.
5.
Unit 1 Operations Unit 1 operations were inspected and reviewed during the inspection period.
During this time, the inspectors routinely toured the Unit 1 control rooms and other plant areas to verify that the plant operations, testing and maintenance were being conducted in accordance with the facility Technical Specifications and procedures. Within the areas inspected, no violations were identified.
Specific areas of inspection and review included the following:
a.
Review of annunciated alarms in the control room and inspection of
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safety-related valve and pump alignments on -the consoles and in the plant.
b.
Unit I returned to operation on -December 11, 1981, following a two-week outage, to replace the "A" reactor coolant pump motor.
On December 16,
1981, Unit 1 experienced a reactor trip from full power caused by the loss of "A" station service transformer.
Electricians had been l
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attempting to change the transfomer tap setting and caused the transformer lockout relay to activate; the taps cannot be adjusted on the service transformers during power operaticn. The transformer was removed and is being inspected for internal damage.
The sudden pressure relief device on the transfonner had actuated.
The licensee is reviewing electrica! procedures to determine if additional peccautions are necessary for transfonner tap changer adjustments.
Since the station service transformers are fed directly from the main generator during operations, the "A" transformer lockout initiates a generator trip, which trips the reactor.
The unit was restarted some two hours later with the "A" bus supplied by the A reserve station service (RSS) or startup transfonner.
c.
On January 5,1982, a fire smoldering in the duct joint grounding straps on the isolated phase bus duct cooler line to "C" fiain Transformer resulted in Unit I ramping down to repair the damage to the
straps and bus duct.
At 16 percent power, while going onto the steam dump valves following turbine trip, the cross under safeties lifted, coinciding with a safety injection (SI) from main steam header to line high differential pressure.
The safety equipment functioned as required. A combination of calibration drift errors in the steam pressure transmitters and comparators (which reduced the 120 psid setpoint) and turbine building vibration from the crossunder safeties
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lifting appears to have caused the fiS header to line high differential
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pressure signal resulting in a safety injection.
(The header instruments are in the turbine building).
Itomentary spikes have been observed on steam pressure instrumentation when the pressure tran-
smitters are bumped or physically shocked (eg - support vibration). A report on the event is being prepared by the licensee, d.
On January 7,1982, while at hot shutdown, Unit 1 again experienced a Safety Injection signal from steam line to header high differential pressure.
Instrument technicians had been working on the main steam line pressure instruments and had placed one high pressure switch in each steam line in trip. One additional pressure instrument was apparently bumped and initiated the two out of three coincidence (per steam line) required for the SI.
Since the unit was shutdown and the inadvertent signal was only in momentarily, the activated engineered safeguards equipment was evaluated and quickly secured.
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Unit 2 Operations Unit 2 operations were inspected and reviewed during the inspection period.
The inspector routinely toured the Unit 2 control rooms and other plant areas to verify that the plant operations, maintenance and testing were being conducted in accordance with the facility Technical Specifications (TS) and procedures. Within the areas inspected,' no violations or
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deviations were identified.
Specific areas of inspection and review included the following:
a.
Review of alarms in the control room and inspection of safety-related valve and pump alignments on the consoles and in the plant, during operations.
b.
Unit 2 went critical on December 28, 1981, following a refueling outage.
Following completion of low power physics testing on December 31, 1981, the unit was shut down to correct a vibration problem on 'C' reactor coolant pumps.
After shaft balancing on the pump the reactor was again taken critical at 1150 on December 31. At 1411 hours0.0163 days <br />0.392 hours <br />0.00233 weeks <br />5.368855e-4 months <br /> an instrument air line was ruptured by an object inadvertently dropped by a construction worker above the line. The ruptured airline caused the component cooling (CC)
water trip valve to the 'B' reactor coolant nump to close. The pump was tripped due to loss of CC and an orderly shutdown was initiated.
Following repairs to the instrument airline, the reactor was taken critical at 1555 on December 31 and Unit 2 was on line at 1745 hours0.0202 days <br />0.485 hours <br />0.00289 weeks <br />6.639725e-4 months <br />.
c.
On January 2,1982, Unit 2 experienced a reactor trip /turte!ne trip from 81 percent power, caused by high level in 6B feedwater heater.
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cause of the high level condition appears to be an obstruction in the heater drain line to the main condenser.
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d.
On January 7,1982, Unit 2 experienced a reactor trip from a turbins trip caused by loss of EHC hydraulic pressure.
Hydraulic pump fiP-2 end
plate gasket blew causing the loss of EHC hydraulic pressure. The
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pump was repaired and the Unit restarted in approximately two hours.
Unit 2 remained at 35 percent power for several hours until the
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secondary system chemcical impurities were removed with the condensate polishing systems.
7.
Electrical Reviews
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Following the loss of power from the B Reserve Station Service (RSS) or startup transformer on January 18, 1982, the inspectors reviewed the installation of new power cable from the switchyard to the B RSS trans-former.
Ice and salt deposit on the B RSS power line bushings (insulated standoffs) led to the B RSS transformer; protective breakers opened to isolate the_ fault and the transformer. The B RSS -transformer was not damaged, ho' wever certain underground 34.5 kV cables to the transformer were apparently overstressed during the event and were replaced following testing. The replacement lines were run above ground to the B RSS transformer:due to the cold and wet ground conditions in addition to other considerations. These primary electrical' source repairs were completed within the required 7 days (TS 3.16.B.2).
The licensee prepared equipment
, and procedures to assure that the dependable alternate source (backfeed)
could be.made operable within the required 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.
During installation of s
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the above ground cables to the B RSS transformer, the inspectors observed that the cables were run under the 500 kV main output power lines from Unit 2.
Since the original cables to the RSS transformers (and to the station)
were underground, the licensee stated that the temporary installation of the above ground cables to the B RSS will be reviewed again to specifically address General Design Criterion 17 (Electric Power Systems) of Appendix A to 10 CFR 50, which requires that the power to the onsite systems be
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supplied by 2 independent circuits designed and located to minimize the likelihood of simultaneous failure.
(0 pen item 280/82-01-01).
Following the loss of B RSS, which feeds emergency bus 2H through the E transfer bus, vital bus I was momentarily lost until the #2 emergency diesel generator started and re-energized the 2H bus (2H supplies vital bus I); tha vital bus loss caused a Unit 2 runback from 90% to 45% power.
Unit I remained at full power during the event (Emergency busses supplied by RSS A and C).
Since operation of both units continued with B RSS and Unit 1 A station service (see para 5.b) transformers out of service, the potential for electrical
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problems following a unit trip were discussed with the licensee.
For example, if either unit tripped, the BSS would be lost along with the equipment it supplies (eg-reactor coolant pump B); if Unit 2 tripped. A RSS would supply Unit 1 ("A" SS out of service) and Unit 2, and the amperage required would exceed the 2,000 amp. design of the underground cable from the RSS transformer by the more than 1,000 amps.
The licensee issued instructions to the operating staff to address the above concerns.
B RSS was returned to service on January 22, 1982.
8.
Unit 2 Containment Leak Rate Testing t
The inspectors reviewed the Unit 2 Type A (ILRT), B, and C leak rate testing completed on 12/19/81. The Type A integrated leak rate test was a failure due to excessive leakage through electrical penetration A-18, which supplies 4160 V power to a reactor coolant pump (RCP) inside containment. The Type A test was successfully completed following repairs to A-18.
(See IE Inspection Report 50-280,281/81-34).
The Unit 2 Type B testing prior to the Type A test did not identify the leakage due to the test method on the Amphenol penetrations. The 57 Amphenol electrical containment penetrations
on Unit 2 were Type B retested prior to startup; 33 Conax type penetrations did not require retesting. The inspectors reviewed the history of leakage on the penetration nitrogen filled space and observed that the weekly
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Periodic Test 34 (Electrical Penetration Leakage Test) identified leakage on
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penetration A-18 in January,1981; the leakage increased to the point where
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10 psig could not be sustained on A-18 for 5 minutes on October 15, 1981.
Adequate corrective action was not taken to correct the leakage or to verify that the 0.6 La limit for. Type B and C tests was not exceeded.
Following Unit 2 shutdown on November 7,1981, and containment testing through December 19, 1981, the leakage was measured and corrected.
The failure to take prompt and adequate corrective action on the leakage from October 15, 1981, is a Violation of Criterion XVI of Appendix B to 10 CFR 50 and Section 16 of the VEPC0 NPS QA Manual.
(Violation, 281/82-01-01)
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9.
The inspector reviewed the LERs listed below to ascertain that NRC reporting requirements were being met and to determine the appropriateness of L
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corrective action taken and planned.
Certain LER's were reviewed in greater detail to verify corrective action and determine compliance with the Technical Specifications and other regulatory requirements. The review included examination of log books, internal correspondence and records, review of SNS0C meeting minutes, and discussions with various staff members.
Within the areas inspected, no violations were identified.
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a.
(Closed) LER 280/81-61 concerned a main steam line snubber compressed such that the end bolts of the snubber body were in contact with the clevis of the mounting bracket on the steam line, preventing further compression of the snubber. The bracket clevis corners were trimmed to allow snubber compression and the snubber returned to operable status.
A stress analysis was performed on the main steam line which showed that it was not overstressed.
b.
(Closed)LER 280/81-66 concerned relocated fire protection piping which had not had a Technical Review initiated after completion of a design change package. Technical Review was initiated and station drawings were updated.
c.
(Closed) LER 280/81-67 concerned a component cooling trip valve TV-CC-109B which would not close remotely due to a hole in a diaphragm in the pilot operated solenoid. The valve positioner was replaced and the valve returned to service.
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d.
(Closed) LER 280/81-69 concerned a loss of flow through a radiation monitor sample pump RM-GW-101/102. The sample pump circuit breaker was discovered tripped.
The breaker was reset, air flow was verified, pump motor was verified turning freely and drawing normal current.
e.
(Closed) LER 280/81-70 concerned a fire protection valve that *
'ot in position. The valve inspection was added to the periodic tn t f.
(Closed)LER's 280/81-71, 72 and 79 concerned high Iodine 131 Dose Equivalent Activity in the reactor's coolant system following reactor trips due to known duel defects. An accelerated sampling program was implemented until RCS specific activity returned to less than the TS limit. The transient TS limit was not exceeded.
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(Closed) LER 280/81-74 concerned component cooling radiation monitors RM-CC-105 and 106 setpoints greater than twice background due to fluctuations in activity levels.
The alann setpoints were reset as required. A TS change is under review.
h.
(Closed)LER 280/81-76 concerned low level in the diesel fire pump fuel oil tank. The level had been below the administrative minimum for two days prior to exceeding the TS low level.
The tank was filled and operations personnel were reinstructed.
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(Closed) LER 280/81-78 concerned M0V-LCV-1115E which failed to respond
properly to a train
'B' SI signal following replacement of BFD relays.
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The cause was incorrectly connected limit switch leads.
The leads were reconnected properly and a special test performed to verify proper operations.
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(Closed) LER 80-81-80 concerned heat tracing failure on the BIT recirculation line to Boric Acid Storage Tank.
The tape was replaced and tested within the TS time requirements.
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(Closed)LER 281/81-70 concerned "as found" leakage on various containment isolation valves exceeding limits during performance of Type C testing.
Repair actions were initiated and subsequent testing verified valves to be within specifications.
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(Closed)LER 281/81-71 concerned Main Steam Safety Valves SV-MS-202A and 204A not lifting within three percent of their required setpoints.
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The safety valves were reset to within one percent of their setpoints and retested, m.
(Closed) LER 281/81-78 concerned the loss of containment integrity during refueling when two SI trip valves were removed for maintenance at the same time.
Fuel movement was halted upon the discovery of the breach of containment integrity. The inside trip valve, TV-SI-201A,
was resinstalled while maintenance continued on TV-SI-2018. Operations personnel were cautioned not to tag inside and outside trip valves on
the same system at the same time when containment integrity is required.
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The following LER's are also considered closed:
LER 280/81-83 LER 281/81-62 LER 281/81-77 LER 281/81-79 10. Plant Physical Protection The inspector verified the following by observations:
a.
Gates and doors in protected and vital area barriers were closed and locked when not attended.
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Isolation zones described in the physical security plans were not l
compromised or obstructed.
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Personnel were properly identified, searched, authorized, badged and escorted as necessary for plant access control.
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No violations were identified.
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