ML18142A178
| ML18142A178 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 11/28/1984 |
| From: | Burke D, Marlone Davis, Elrod S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18142A174 | List: |
| References | |
| 50-280-84-30, 50-281-84-30, IEB-84-03, IEB-84-3, NUDOCS 8502060333 | |
| Download: ML18142A178 (6) | |
See also: IR 05000280/1984030
Text
Report Nos.:
50-280/84-30 and 50-281/84-30
Licensee:
Virginia Electric and Power Company
Richmond, VA
23261
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry" 1 and 2
Inspectiondld
Conduct d:
October 1 - November 2, 1984
Inspectors: ~----+---------------------
0. ~,~J1r,~7, Senior Resident Inspector
Approved
dft1Jl#
M. J. Davis, Resident Inspector
lrod, Section Chief
Division of Reactor Projects
SUMMARY
igned
ti l~rlrr
Defte Signed
Scope:
This routine, unannounced inspection entailed 180 inspector-hours at the
site, in the areas of plant operations and operating records, refueling operations,
plant maintenance and surveillance, plant security, followup of events, licensee
event reports, and IE Bulletins.
Results:
In the areas inspected, one violation was identified in the plant
maintenance and surveillance area (inadequate electrical maintenance and testing
procedures - paragraph 5.b).
8502060333 850fi6
PDR ADOCK 05000280
G
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, Director, QA, Nuclear Operations
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 I above.
The violation of paragraph 5.b
was discussed with licensee management.
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.
Units I and 2 operations were inspected and reviewed during the inspec-
tion period.
The inspectors routinely toured the control room and
other plant areas to verify that plant operations, testing, and main-
tenance were being conducted in accordance with the facility Technical
Specifications (TS) 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 the appropriate radiation controls were properly
established, critical clean areas were being controlled in accordance
with procedures, excess material or equipment was stored properly, and
combustible material and debris were disposed of expeditiously.
During
tours, the inspector 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
2
tags, component positions, adequacy of fire fighting equipment, and
instrument calibration dates.
Some tours were conducted on backshifts.
Inspections included areas in the 1 and 2 cable vaults, swit_chgear
rooms, contra 1 rooms, and cab 1 e penetration areas to verify certain
breaker and equipment positions for safety re 1 ated components.
The
inspector routinely conducted partial walkdowns of ECCS systems.
During the inspection period, the inspectors conducted periodic inspec-
tions in the accessible areas of the Unit 2 Safeguards Building and
valve pit-checking ECCS trains, auxiliary feedwater systems, and
containment spray trains.
Unit 1 containment inspections verified
shutdown systems were operable and refueling cavity levels and boron
concentrations were within requirements.
The inspectors examined the Unit 1 refueling cavity seal ring to verify
that the design was different from the seal mentioned in IE Bulletin
84-03, and adequate.
The Surry design utilizes two independent seals.
The first consists of a J-type inner seal which seats atop the reactor
vessel flange ring and a similar outer seal which contacts the refueling
cavity floor to seal the space between the vessel and refueling cavity.
The second seal is a dual inflatable rubber seal which is mounted on a
vertical support in the seal ring and expands against the vertical edge
of the reactor vessel flange; a similar outside seal expands from the
support to the refueling cavity floor flange.
New inflatable seals
were installed on the seal ring and tested prior to ring installation
and use during this outage.
A pair of circumferential troughs are
permanently installed beneath the inner and outer ring seals to collect
any water which may leak by the seals. This is used to verify positive
sea 1 i ng when the refue 1 i ng cavity or can a 1 is being fi 11 ed from the
RWST.
The troughs drain through installed piping to the loop rooms in
containment, which are monitored periodically for leakage.
The inspec-
tors also verified that the seal testing and installation procedure,
MMP-C-RC-037,
specifies inflatable seal pressure (20 psig).
The
licensee performed evaluations with regard to refueling cavity water
sea 1 fa i 1 ures and revi sect Abnorma 1 Procedure AP-22 to address sea 1
assembly leakage or failure.
The inspectors had no further questions
at this time.
IE Bulletin 84-03 remains open pending further NRC
Region II review.
b.
Unit 1 began the reporting period shutdown for a refueling and main-
tenance outage.
Unit 2 began
the reporting period operating at full power.
On
October 29, 1984, during undervoltage testing on the
10 1 transfer bus,
the 2A main feedwater pump tripped due to automatic load shedding
initiated by the testing.
The test procedures failed to specify the
positioning of the load shed mode selector switch to manual position or
opening the defueled Unit 1 breaker 15Al.
The Reserve Station Service
(RSS) load shedding is actuated by simultaneous loading of both units
on a transfer bus, e.g., close bfeaker 15Al and 25Al.
One main feed-
water pump and one condensate pump are then automatically shed for
3
each unit.
The trip of the
1 2A 1 main feedwater pump resulted in a
12C 1
steam generator low water level and resultant reactor trip. During the
electrical transfer from station service to reserve station service or
off-site power following the trip, the
1A
1 reactor coolant pump stopped
since its RSS power source, the
10 1 transfer bus was isolated.
Rod
M-10 in control bank
18 1 appeared to hang up momentarily at 30 steps
when the unit tripped.
Subsequent rod exercises and rod drop testing
was satisfactory at intermediate shutdown conditions.
The rod was
dropped from the fully withdrawn position in 1.2 seconds, which is
normal.
Additional rod drop testing is scheduled to be performed at
normal operating conditions prior to Unit 2 restart.
Following restart
of the 1A1 reactor coolant pump, increased seal leakoff, vibration and
increasing temperature on the lower thrust bearing resulted in the
operators securing the pump.
The Unit ended the reporting period in
the cold shutdown condition with the 'A' loop drained for reactor
coolant pump seal and bearing repair on the
1A1 reactor coolant pump.
A low oil level in the RCP motor bearing reservoir apparently caused
the bearing failure; there was no annunciation or alarm of low oil
level due to the failure of the level switch itself.
The failure to provide adequate electrical testing and maintenance
operations procedures for the October 29 testing and maintenance
described above, which led to the RSS load shedding and reactor trip,
is a violation (280 & 281/84-30-01). Another example of this violation
occurred on October 20, 1984, during electrical switching of lighting
busses while defueling the Unit 1 core.
Inadequate electrical proce-
dures and switching orders resulted in the temporary loss of electrical
power to the lights in the Unit 1 containment and loss of the direct
communications between the contra 1 room and the refue 1 i ng cavity
manipulator crane in containment (TS 3.10.A.10) during irradiated fuel
movement in the cavity poo 1.
A 11 fue 1 movement stopped until the
communications and lighting were restored.
6.
Technical Specification Review
The inspectors reviewed the Surry Units 1 and 2 Technical Specifications
(TS) to determined if the systems required to be operable by Section 3 had
surveillance requirements in Section 4 which verified or demonstrated
operability.
The Surry non-standard TS, originally issued in 1972 but
amended regularly, does describe certain operability requirements or LCOs
in Section 3 which are not covered by surveillance requirements in Section 4.
However, the safety-re 1 a ted systems and equipment survei 11 ance to verify
operability are included in the Inservice- Inspection and Testing Programs,
which are reviewed and approved by the NRC.
Examples included the component
cooling water (CCW) pumps described in Section 3.13 of the TS.
The CCW pump
performance requirements are not specified in Section 4 of the TS, however,
the pumps are tested monthly by periodic test procedure PT 41.1,
11 CCW Pump
Operabi 1 ity and Performance Test,
11 under the IST program.
The inspectors
also identified certain TS Section 3 items, such as TS 3.14.A.2.a, which-
requires flow through one bearing cooling water heat exchanger, which did
not appear in Section 4 or the ISI program.
This inspection will continue
4
under inspector followup item (280/84-30-02).
The bearing cooling water
system cools the main generator, turbine, and other secondary equipment as
well as the instrument and service air compressors.
7.
Instrumentation Review
8.
Fo 11 owing the Unit 1 shutdown, Service Water ( SW) testing was performed
which included stroking the SW inlet isolation valves to the recirculation
spray heat exchangers and flowing the system.
When flow was established, 5
of the 6 SW flow instruments (FI-SW-105s and 106s) did not respond, and the
one instrument that did indicate flow remained upscale when the inlet valves
were closed.
The licensee is inspecting the Units 1 and 2 SW flow instruments
to identify the problem (!FI 280/84-30-03).
LER Review
The inspectors reviewed the License 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 verify correction action and determine
compliance with TS and other regulatory requirements.
The review included
examination of logbooks, internal correspondence and records review of SNSOC
meeting minutes, and discussions with various staff members.
Within the
areas inspected, no violations were identified.
(Closed)
LER 281/83-40 concerned ra i nwate*r grounding the 3A Auxi 1 i ary
Feedwater Pump Motor.
The motor windings were dried and the pump returned
to service.
Subsequent repairs to the safeguards building roof have been
completed.
(Closed) LER 280/83-37 concerned a possible dropped rod accident analysis
that may not represent the limiting case. A detailed evaluation documented
the NFE technical Report No. 334, determined that the current UFSAR rod drop
analysis is the most limiting for all core cycles.
(Closed) LER 280/83-44 concerned inoperable snubbers found during snubber
inspections. The inoperable snubbers were repaired. A 100 percent inspec-
tion of snubbers was subsequently performed.
(Closed) LER 281/83-37 concerned FCV-FW-2488, the
1B1 Main Feedwater Regu-
lating Valve failing to fully close on a SI signal.
The feedwater control
valves have been rebuilt and are currently performing satisfactorily.
(Closed) LER 281/83-52 concerned a containment spray pump breaker tripping
during attempts to start the pump.
The breaker overloads were checked and
the armature stop screw on the overload device was found to be loose. This
caused armature vibration and premature breaker tripping.
The stop screw
was tightened and the instantaneous trip settings were adjusted.
The pump
was tested satisfactorily.
5
9.
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.
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.