ML18142A559
| ML18142A559 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 06/18/1985 |
| From: | Burke D, Marlone Davis, Elrod S NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18142A557 | List: |
| References | |
| 50-280-85-19, 50-281-85-19, NUDOCS 8507110799 | |
| Download: ML18142A559 (7) | |
See also: IR 05000280/1985019
Text
..
Report Nos. :
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
50-280/85-19 and 50-281/85-19
Licensee:
Virginia Electric and Power Company
Richmond, VA
23261
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted:
May 7 - June 3, 1985
Inspectors: ~
0.... .\\?4 tp.
D.~Senior Resident Inspec~
~ ll. P1-M2
~
M~sident Inspector
Approved by: JJ ~- ~
.
fe-.r S. Eld/Section Chief
Division of Reactor Projects
SUMMARY
Date Signed
Scope:
This inspection involved 200 inspector-hours on site in the areas of
plant operations and operating records, environmentally qualified (EQ) equipment
installation, plant maintenance and surveillance, plant security, followup of
events and licensee event reports (LER).
Results:
One violation was identified in the area of EQ equipment installations,
failure to implement an adequate Quality Assurance (QA) program for Design Change 81-103, which upgraded electrical components in containment, paragraph 6 .
. . 8507110799 850625
-~
ADOCK 05000280
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.
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
2.
3.
R. F. Saunders; Station Manager
D. L. Benson, Assistant Station Manager
H. L. Miller, Assistant Station Manager
D. A. Christian, Superintendent of Operations
E. S. Grecheck, Superintendent of Technical Services
D. Rickeard, Supervisor, Safety Engineering Staff
S. Sarver, Superintendent of Health Physics (HP)
R. Johnson, Operations Supervisor
R. Driscoll, Site QA Manager
W. R. Runner, Supervisor, Administrative Services
Other licensee employees contacted included control room operations, shift
technical advisors (STA), shift supervisors, chemistry, health physics,
plant
maintenance,
security,
engineering,
administrative,
records,
contractor personnel and supervisors.
Exit Interview
The inspection scope and findings were summarized on a biweekly basis with
certain individuals in paragraph 1.
The licensee did not identify as
proprietary any of the materials provided to or reviewed by the inspectors
during this inspection.
Licensee Action on Previous Enforcement Matters
a.
Closed -
Inspector Followup Item (IFI) 280/83-20-04 concerned the
omission of non-licensed STAs from the licensed Operator Requalifi-
cation program.
STAs currently participate- in the Operator Requali-
fication program and are given a separate examination.
The STA
Training program was previously ins*pected by the NRC Training Assess-
ment Team in Inspection Reports 280, 281/84-31.
b.
Closed -
Violation 280, 281/83-20-05 concerned the lack of valve
exercise testing following minor maintenance such as adjustment of stem
packing.
Administrative procedure ADM-71,
ASME Code Section XI
Repair/Replacement Program,
was
revised to ensure the testing
requirements are met~
4.
Unresolved Items
Unresolved Items were not identified during this inspection.
2
5.
Operations
a.
Units 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* Specificatio11s (TS)
and procedures. The inspectors verified that monitoring eqµipment was
recording as required, that equipment was properly tagged and that
plant housekeeping efforts were adequate.
The
inspectors also
determined
that appropriate
radiation
cont
1rols were
properly
established; 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 inspectors 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
backshifts.
Inspections included areas in the Units 1 and 2 cable vaults, vital
battery rooms, diesel generator rooms, fire pump house, switchgear
rooms, control room, auxiliary building, Unit 2 containment and cable
penetration areas to verify certain breaker and equipment positions for
safety-related components.
The inspector routinely conduct partial
wal kdowns of* emergency core cooling. (ECCS) and engineered safety
features (ESF) systems.
b.
The inspectors reviewed the May 11, 1985, event concerning the minor
fire in the reactor coolant system (RCS) head vent post accident
monitoring (PAM) panel in the Unit 1 control room.
While performing
Periodic Test PT-18.6H, the operators cycled solenoid operated valve
(SOV) SOV-RC-lOlA-1 (pressurizer head vent) and noticed the position
indicating light flickering on the control panel. The rear door to the
PAM panel was opened, and dark smoke billowed out.
A short burst of
carbon dioxide from a control room portable fire extinguisher was
manually discharged into the console/panel, while the electrical
breaker for the valve was opened to de-energize the circuits.
The
electrical leads to the bulb socket assembly were charred (burned).
A
short had apparently developed in the indicating light bulb sotket or
the attached 1900 ohm resistor, causing melting and smoking of the wire
insulation and melting of the lamp socket base. The correct bulb was
installed in the socket and the resistor still measured some 1800 ohms
resistance when tested. The battery voltage normally operates between
130 and 134 volts de (Vdc). The 125 Vdc lamp, socket and resistor were
replaced.
While examining the inside of the PAM panel, the inspector
noted a second blackened area similar to the SOV-RC-lOlA-1 panel area
which was blackened by the fire discussed above.
A similar socket
assembly failure and fire had apparently occurred some years ago during
testing.
Licensee and inspector review of this item continues (IFI
280/85-19-02).
c.
Unit 1 began the reporting period in a Cold Shutdown condition during a
two-week maintenance outage.
The unit returned to power operation on
,.
3
May 15, 1984, and operated at power for the remainder of the reporting
period.
Unit 2 remained shutdown in a refue 1 i ng maintenance outage for the
duration of the reporting period.
The inspectors routinely observed
refueling operations.
6.
Environmentally Qualified (EQ) Instrumentation and Electrical Seal Assembly
Review
Recently, while troubleshooting an EQ pressure transmitter (PT-2456, Pres-
surizer Pressure Protection) in the Unit 2 containment, licensee personnel
found standing water and internal corrosion inside the stainless steel
housing of the Rosemount Model 1153, Series D transmitter.
Additional
inspections identified snubber oil in a similar 1153 D transmitter (FT-2484,
Main Steam Line Flow) in the Unit 2 containment.
A rigorous inspection
program was initiated on both units following the Unit 1 shutdown due to
increasing RCS leakage through a residual heat removal (RHR) valve stem
packing.
The following problems were identified.
a.
The Conax electrical conductor seal assembly threaded body was not
properly positioned on the metal tube of the feedthrough subassembly.
The midlock ferrule (similar to a swagelock seal) which seals the
assembly* was found improperly positioned on several Conax assemblies in
each Unit.
In addition, several entire Conax seal assemblies were
installed backwards by threading the conduit National Pipe Thread (NPT)
end into the transmitter; the installations were corrected.
b.
The Conax threaded seal subassembly was not properly tightened on a few
assemblies.
The installation procedures require the midlock cap to be
torqued to 150-180 foot-pounds to properly crush the midlock ferrule
onto the conductor feedthrough tube; however, one assembly was found
only hand-tight, while others were under and over torqued.
In addition,
this significant torque.apparently resulted in broken transmitter neck
seals on several 1153 D transmitters; the factory sealed threaded neck
between the sensing cell and the cy_lindrical stainless steel electronics
housing was found cracked (loose). M*ost of these failures appeared to
have occurred recently during assembly removal and inspections due to
the failures referred to above.
The licensee designed an adjustable
support brace to secure the assemblies during torquing.
c.
Various materials were used to seal the one-half inch NPT threaded end
of the Conax assembly into the Rosemount transmitter head (e.g., RTV,
tefl on tape, nothing, Neo-1 ube 100).
Con ax recommends no sea 1 ant,
tape or lubrication on the Conax assembly threads, however, Rosemount
requires the use of Grafoil tape (qualified thread sealant) on the 1153
transmitters.
The licensee installed Grafoil tape before rethreading
the Conax assemblies into the Rosemount transmitters.
4
d.
Discrepancies were also observed inside the Rosemount transmitters.
Certain screw heads on the two sma 11 phi 11 i ps head screws which
terminate the signal leads inside the transmitter were found cracked at
the base or missing .. The original equipment screws were hollow (bored)
to accept a standard miniature test plug for testing purposes.
The
vendor supplied solid terminal screws, which were installed iii the
transmitters by licensee personnel, to alleviate screw head cracking
during screw installation and removal.
In summary, all 64 EQ transmitters (including
1their Conax assemblies)
and 27 of the 35 SOV assemblies in the Units 1 and 2 containments were
disassembled, inspected and retested, utilizing upgraded procedures.
The eight Target Rock SOV assemblies on the.Units 1 and 2 reactor head
vent systems (four per unit) were visually inspected with no discrepan-
cies observed; the assemblies were not disassembled because of their
inaccessibility; Eight Target Rock SOV assemblies similar to those on
the head vent were disassembled and no discrepancies were found.
In
addition, 12 of the 48 installed SOV limit switch Conax assemblies were
removed and inspected, and no discrepancies were found; the remaining
28 EQ limit switch assemblies are being installed in Unit 2 during this
outage, in accordance with 10 CFR 50.49.
The current Unit 2 refueling
outage is the second after March 31, 1982, and the scheduled deadline
for finalizing the EQ of. the electric equipment (except for NRR
extensions).
Results:
(1) Out of 64 transmitters and assemblies in Units 1 and 2 contain-
ments, at least six were verified inoperable (unqualified) due to
corrosion, water, etc. inside the transmitter or unseated (hand
tight) or reversed ferrules.
An additional 32 transmitters and
seal assemblies may have been unqualified due to misposition of
the ferrule or reversed assembly installation. The broken necks,
thread sealants and terminal screws could have led to additional
transmitter disqualification or failures.
(2) Out of 70 Conax assemblies to the SOV's, four were inoperable
(unqualified) due to corrosion, recessed ferrule or incorrect seal
assembly (Conax PL type vs. containment qualified ECSA type).
Four
were potentially inoperable due to incorrect positioning of the
midlock ferrule on the feedthrough tube subassembly.
(3) 12 of the 48 installed Conax assemblies to the valve limit
switches were inspected and no discrepancies were found; the
remaining 28 assemblies are being installed during the current
Unit 2 outage.
Based on the above data, where ten environmentally qualified safety-
related electrical components were determined to be unqualified, and at
least 36 of the remaining 200 EQ components inside the containments may
have been unqualified due to inadequate i_nstallation procedures, as
well as failure to follow these procedures and to verify that the
Ii.**'
<'
5
activities had been properly performed, a Violation of Appendix B to
10 CFR 50, Criterion V was issued (280, 281/85-19-01).
7.
Licensee Event Report Review
The inspectors reviewed the 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 corrective action and
determined compliance with TS and other regulatory requirements. The review
included examination of logbooks, internal correspondence and records review
of Station Nuclear Safety and Operating Committee meeting minutes, and
discussions with various staff members.
(Closed) LER 280/85-05 concerned the locking out of automatic ihitiatfon of
carbon dioxide for fire zone seven with no fire watch present.
When operations
personnel tagged out fire zones five and seven construction personnel *had
intended that only zone five be tagged out; hence, a fire watch was posted
in zone five only. Operations personnel are to verify that a fire watch has
been posted in the area affected prior to removing any fire protection
system for service.
(Closed) LER 280/85-07 concerned a reactor trip/turbine trip due to the
11A11
main feed pump tripping at 17 percent power.
At the time of the trip~ no
valid trip conditions were indicated for the feed pump.
The actuator arm on
the pump's recirculation valve was found to possibly not properly depress
the limit switch associated with the valve position signal to the pump trip
logic.
When th~ recirculation valve opened at the specified low discharge
flow setpoint, it was determined that a valve open signal was apparently not
sent to the feed pump trip logic, which resulted in the pump trip. The
recirculation valve actuator arm was modified to ensure proper limit switch
actuation.
(Closed) LER 280/85-08 concerned the locking out of automatic initiation of
carbon dioxide for fire zone five with no fire watch present.
An operator
tagging out fire zone eight mistakenly placed the tag on fire zone five.
The
11 Red Tag
11 system is to be used when removing carbon di oxi ode systems
~ from service instead of the
1181 ue Tag 11 system.
This requires independent
verification by operations personnel and verification by the party requesting
the tagout that the proper systems were removed or were returned to service.
Within the areas inspected, no violation~ were identified.
8.
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.
6
b.
Isolation zones described in the physical security plans were not
compromised nor obstructed.
c.
Personnel were properly identified, searched, authorized, badged and
escorted as necessary for plant access control.
d.
The inspector observed the monthly test of the Security emergency
diesel generator in accordance with PT 22.5.
Indication of emergency
power is provided on the Secondary Alarm Station via a
11Generating 11
light when the security diesel is running.
No false alarms were
generated during the switchover to emergency power.
A 11 security
alarms and equipment remained operable while being supplied by the
emergency power system.
No violations or deviations were noted.