ML18153A083
| ML18153A083 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 10/07/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153A080 | List: |
| References | |
| 50-280-96-09, 50-280-96-9, 50-281-96-09, 50-281-96-9, NUDOCS 9610220117 | |
| Download: ML18153A083 (30) | |
See also: IR 05000280/1996009
Text
, *
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License Nos:
Report Nos:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9610220117 961007
ADOCK 05000280
G
50-280, 50-281
50-280/96-09, 50-281/96-09
Virginia Electric and Power Company (VEPCO)
Surry Power Station, Units 1 & 2
5850 Hog Island Road
Surry, VA 23883
July 28 - September 7, 1996
R. Musser, Senior Resident Inspector
M. Branch, Senior Resident Inspector
D. Kern, Resident Inspector
W. Poertner, Resident Inspector
P. Fillion, Reactor Inspector (Section El.1)
J. York, Reactor Inspector (Sections E2.l, E3.2,
E4.l, E5.2, and E7.1)
R. Moore. Reactor Inspector (Sections E2.l,
E3.2, E4.l, E5.2, and E7.1)
G. Edison, Project Manager, NRR (Sections El.3,
E3.l, and E5.l)
R. Gibbs, Reactor Inspector (Sections M8.6,
M8.7, M8.8, and El.2)
D. Taylor, Resident Inspector, North Anna
(Section Ml.2)
G. Belisle, Chief, Reactor Projects Branch 5
Division of Reactor Projects
ENCLOSURE 2
EXECUTIVE SUMMARY
Surry Power Station, Units 1 & 2
NRC Inspection Report 50-280/96-09, 50-281/96-09
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support.
The report covers a six-week
period of resident inspection; in addition, it includes the results of
announced inspections by four regional inspectors, the North Anna Resident
Inspector, and the Office of Nuclear Reactor Regulation Surry Project Manager.
Operations
Primary plant response following the Unit 2 reactor trip on August 3 was
normal and the unit was promptly placed in a stable hot shutdown condition by
the operating crew. Safety systems functioned as designed and equipment
problems were evaluated and resolved prior to returning the unit to power.
Operator action to trip the unit following the closure of the turbine governor
valves was appropriate and demonstrated excellent awareness of ongoing
activities that could potentially challenge plant operation (Section 01.2).
The licensee's actions in repairing the failed Consequence Limiting Safeguards
(CLS) relay were appropriate. The initiation of a controlled plant shutdown
approximately six hours prior to expiration of the Limiting Condition of
Operation (LCO) demonstrated a sound and safe operating judgement (Section
01.3).
Preparations for Hurricane Fran were conservative. Operators communicated
closely during the storm while responding to heavy storm debris fouling at the
low level intake structure (Section 01.4).
A Non-Cited Violaton (NCV) was identified for not maintaining Unit 2 control
room logs in the form required by procedures (Section 01.5).
Maintenance
The inspectors concluded that the licensee's repair of the letdown line was
acceptable. However, this leak is the third such occurrence in the last nine
months and no root cause had been identified (Section Ml.1).
Appropriate corrective action was taken to restore 1-SW-P-lA to service prior
to Hurricane Fran arriving on-site. Operators performed the operability
surveillance procedure in a professional manner (Section Ml.2).
One NCV was identified for operating with a non-isolable leak (Section M8.8).
Engineering
The inspectors performed a review of 348 Deviation Reports (DRs) covering
various systems, significance levels and time periods. Observations and
findings from this review indicated that the conduct of engineering was good.
A violation was identified for failing to specify breaker set points in a
design change package which resulted in incorrect set points and breakers
spuriously tripping during operation of the plant (Section El.l).
2
The inspectors concluded that through careful management attention, the number
of Temporary Modifications CTMs) for both units has been maintained at a low
level (fewer than ten) for several years (Section El.3).
The engineering process for material upgrade and item equivalency evaluation
adequately provided for installation of appropriate quality level material in
safety related applications (Section E2.1).
The inspectors concluded that the licensee's 10 CFR 50.59 procedures were
comprehensive, thorough, and well written (Section E3.1).
Manager training on a wide variety of subjects was being used to enhance the
engineering supervision in making more informed decisions (Section E5.2).
The Design Control and Engineering Program audit was thorough, detailed and
resulted in meaningful findings (Section E7.1).
Plant Support
Radiological protection personnel took prompt and appropriate action when
notified that contaminated steel plating may have been inadvertently shipped
to the site (Section R8.1) .
Report Details
Summary of Plant Status
Unit 1 operated at approximately 100 percent power the entire reporting
period.
Unit 2 operated at approximately 100 percent power until August 3, when the
reactor was manually tripped due to a loss of Electro Hydraulic Control (EHC)
pressure during a maintenance evolution. Following repairs. the unit was
taken critical at 12:57 a.m. on August 5, and reached 100 percent power at
8:51 p.m. the same day.
Unit 2 remained at approximately 100 percent power
until August 27, at 3:19 a.m., when the licensee initiated a shutdown in
accordance with Technical Specification (TS) 3.7-2 due to a failed relay in
the Hi Hi Consequence Limiting Safeguards (CLS) logic system.
At 7:27 a.m.,
with power at approximately 30 percent, repairs were completed and the
Limiting Condition of Operation (LCO) was exited. Unit 2 was returned to 100
percent power at 8:14 p.m.
Unit 2 remained at approximately 100 percent power
until September 6, when at 5:01 a.m., the operations shift began reducing
power due to debris in the river causing fouling problems at the low level
intake structure. At 9:39 a.m., the unit had been reduced to 49 percent
power.
At 12:49 p.m., a power increase commenced until a maximum attainable
power level of approximately 94 percent was achieved.
Power was limited due
to reduced flow through the main condenser.
Unit 2 remained at this power
level for the remainder of the inspection period while repairs were being
completed at the intake.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707, 40500)
The inspectors conducted frequent control room tours to verify proper
staffing, operator attentiveness. and adherence to approved procedures.
The inspectors attended daily plant status meetings to maintain
awareness of overall facility operations and reviewed operator logs to
verify operational safety and compliance with TSs.
Instrumentation and
safety system lineups were periodically reviewed from control room
indications to assess operability. Frequent plant tours were conducted
to observe equipment status and housekeeping. Deviation Reports (DRs)
were reviewed to assure that potential safety concerns were properly
reported and resolved. The inspectors found that daily operations were
generally conducted in accordance with regulatory requirements and plant
procedures.
01.2 Unit 2 Reactor Trip
a.
Inspection Scope (71707)
At 3:05 p.m. on August 3, the Unit 2 reactor operator manually tripped
Unit 2 from 88 percent power due to closure of the turbine governor
2
valves and intercept valves. The inspectors reviewed the circumstances
surrounding the Unit 2 trip and independently reviewed the plant
response following the reactor trip.
b.
Observations and Findings
On August 3, a leak was identified on a one-inch EHC compression fitting
located on the emergency trip header for the turbine governor and
intercept valves. The licensee attempted to stop the leak by tightening
the compression fitting. While tightening the leaking fitting, tubing
separated from another union that was not being tightened. The loss of
EHC oil pressure resulted in the closure of the turbine governor and
intercept valves. The control room operator was monitoring turbine
governor valve position and manually tripped the reactor prior to an
automatic trip signal being generated. The potential for a reactor trip
during the maintenance activity had been briefed by the operating crew
prior to allowing the work to commence. After the reactor trip, four
Individual Rod Position Indicators (IRPis) indicated between 10 and 12
steps withdrawn and then drifted to zero within two minutes.
Licensee
procedures require that all IRPis indicate less than 10 steps following
a reactor trip. The reactor coolant system was borated in accordance
with procedures and the shutdown margin was verified. The Auxiliary
Feedwater System (AFW) automatically initiated as designed and no
primary or secondary power operated or safety relief valves actuated
during the trip.
The licensee determined that the leaking compression fitting and the
compression fitting that separated had not been properly installed,
i.e., the ferrule was not properly set on the tubing due to inadequate
crimping torque. The two compression fitting unions that initiated the
reactor trip were repaired and four additional fittings adjacent to the
failed fittings were inspected using GO/NO GO gauges. These fittings
were loose and were repaired. The licensee was unable to determine when
the compression fittings were installed (most likely during original
construction) but did determine that no work had been performed on the
fittings during the last Unit 2 refueling outage.
The cause of why four IRPis did not initially indicate less than 10
steps was investigated. Minor adjustments were required on the signal
conditioning card for one IRPI.
No other problems were identified. Hot
rod drop testing was performed on the four rods (G3, F6, Fl2, and Jl3)
and the inspectors verified that rod drop times were acceptable.
The inspectors independently reviewed the post trip review and attended
the restart meetings conducted by the licensee. The unit was taken
critical at 12:57 a.m. on August 5, and was returned to 100 percent
power at 8:51 p.m. later that same day.
c. Conclusions
Primary plant response following the reactor trip on August 3 was normal
and the unit was promptly placed in a stable hot shutdown condition by
3
the operating crew. Safety systems functioned as designed and equipment
problems were evaluated and resolved prior to returning the unit to
power. Operator action to trip the unit following the closure of the
turbine governor valves was appropriate and demonstrated excellent
awareness of ongoing activities that could potentially challenge plant
operation.
01.3 Unit 2 Power Reduction
a.
Inspection Scope (71707. 92901)
On August 27, at 3:19 a.m., the licensee initiated a shutdown of Unit 2
in accordance with TS 3.7-2 due to a failed relay in the Hi-Hi CLS logic
system.
The inspectors were notified of the condition and responded to
the site to follow the licensee's actions.
b. Observations and Findings
On August 26, during the performance of monthly Hi-Hi CLS logic testing,
train A would not reset rendering the A train inoperable. A 12-hour
to hot shutdown LCO was initiated at 9:10 p.m., in accordance with
TS 3.7-2. Investigation revealed that a relay (3-CLS-2AMX) failed
resulting in the train being inoperable. Replacement of the relay
required the development and installation of a Temporary Modification
(TM).
Appropriate personnel were called into the station to support the
repair effort.
The inspectors were informed of the problem at approximately 2:20 a.m.
on August 27, and responded to the site to review the licensee's
actions. At 3:19 a.m., the licensee began a controlled reactor shutdown
by reducing power at approximately 150 megawatts electric per hour.
This problem was appropriately reported to the NRC Operations Center in
accordance with 10 CFR 50.72 at 3:27 a.m.
The inspectors arrived on
site and attended the Station Nuclear Safety and Operating Committee
(SNSOC) review of the TM and plant status. The TM was appropriately
reviewed and approved.
At 6:50 a.m., with Unit 2 at 30 percent power,
the power reduction was stopped while the repair effort was underway.
The operations shift and maintenance personnel were appropriately
briefed by the cognizant engineer.
An extra reactor operator was placed
in the control room to monitor plant parameters while the repair was in
progress. The relay was replaced, successfully tested and the system
returned to service. The LCO was exited at 7:27 a.m.
Unit 2 was
returned to 100 percent power at 8:14 p.m.
c. Conclusions
The licensee's actions in repairing the failed CLS relay were
appropriate. The initiation of a controlled plant shutdown
approximately six hours prior to expiration of the LCO demonstrated
sound and safe operating judgement.
4
01.4 Preparations for Hurricane Fran
a.
Inspection Scope (71707)
The inspectors reviewed the Updated Final Safety Analysis Report
(UFSAR), the Virginia Power Hurricane Response Plan, revision 2, and
monitored the licensee's hurricane preparations. Additionally, on
September 5 and 6, the inspectors toured outside areas looking for loose
or unsecured items and monitored the low level intake structure to
evaluate the storm's effect on the water supply for the ultimate heat
sink.
b. Observations and Findings
Hurricane Fran approached the North Carolina coast on September 5.
The
licensee monitored the storm track and implemented severe weather
preparations in accordance with Operations Checklist (OC)-21, Severe
Weather, and O-AP-37.01, Abnormal Environmental Condition, revision 6.
The Virginia Electric Power Company (VEPCO) Hurricane Response Plan is
triggered by the prediction of hurricane force winds on-site by the
Vi rgi ni a Power Weather Center. Hurricane force wi nd_s were not predicted
during the approach of Hurricane Fran; however, the licensee did
implement the plan on September 5 as a precautionary measure when the
storm was predicted to pass through the area. The inspectors reviewed
the licensee's preparations, reviewed the status of important systems,
and monitored the storm's progress. The outside areas inspected were
clean. Siding at the high level intake structure which became loose
during the high winds was promptly secured.
Maintenance and
surveillance activities performed by the licensee were minimized during
the approach of the storm. Repairs to Emergency Service Water (ESW)
pump 1-SW-P-lA (see Section Ml.2) continued through all three shifts and
the pump was declared operable at 10:15 p.m. on September 5 prior to the
storm's arrival.
Heavy debris from the river began fouling the low level intake structure
screens early on September 6 as the storm reached the site. Two
Circulating Water (CW) pumps became unavailable due to heavy screen
fouling and screen damage.
The inspectors observed operator activities
in the control room and at the low level intake structure. Operators
reduced reactor power sufficiently to maintain normal intake canal level
while the water supply from the river was degraded. Operators worked
diligently to maximize the number of available CW pumps.
Power to both onsite meteorological towers was lost when the storm
reached the site. The licensee maintained contact with local weather
services to ensure they maintained accurate tracking of area wind speed.
The maximum sustained onsite wind speed was 40 mph with gusts to 54 mph.
Following the storm, Unit 2 reactor power was increased from 49 percent
to 94 percent. Hurricane force winds were not observed onsite and the
VEPCO Hurricane Response Plan was terminated at 1:55 p.m. on September
6.
5
At 12:40 p.m. on September 6, the licensee determined that 26 of 61
emergency warning sirens for the surrounding Emergency Planning Zone
(EPZ) were inoperable. Storm damage caused power to be lost to 23 of
the 26 sirens. The licensee made a I-hour non-emergency notification to
the NRC and a 4-hour notification to state officials to report the
partial loss of off-site emergency notification capability. The
inspectors discussed alternate notification methods with emergency
preparedness personnel. Alternate notification methods to the effected
areas by local officials are established by letters of agreement.
Repairs were promptly initiated. Fifty-six sirens were operable by noon
on September 7 and all 61 sirens were operable by 7:30 a.m. on
September 9.
c. Conclusions
The licensee's actions in preparation for Hurricane Fran were
conservative. Operators communicated closely during the storm while
responding to heavy debris fouling at the low level intake structure.
01.5 Operations Logs
a.
Inspection Scope (71707)
On September 6, the inspectors performed a control room tour to review
current plant conditions.
As a part of this activity, control room logs
were reviewed.
b. Observations and Findings
During the review of plant conditions, the inspectors determined that at
approximately 2:00 p.m. on September 6, no official Unit 2 control room
log had been initiated for the day shift (8:00 a.m. - 4:00 p.m.)
operating crew.
At the Surry Power Station, control room logs are
normally maintained on the plant computer system. The inspectors
observed that only an informal log was being maintained by the Unit 2
reactor operator.
When the inspectors questioned the operating shift
about this matter, the inspectors were informed that because the site
computer was out of service, an informal log was being maintained until
the plant computer was returned to service.
The inspectors had recently reviewed procedure OPAP-0004, Logs and
Operating Records, revision 5, which stated that handwritten narrative
logs should be written on pre-formatted loose-leaf pages approved by the
Superintendent, Operations. The inspectors questioned the shift
supervisor about this matter and he was unaware of this requirement.
The plant computer was returned to service shortly after this
observation and the informal log was transcribed into the computer.
The inspectors brought this matter to the attention of the
Superintendent. Operations. who stated he would ensure the operations
staff was informed of this requirement. The inspector's concern in this
matter was the lack of formality for the official record of the plant
6
six hours into the operating shift. The Superintendent, Operations,
stated that this matter did not meet his expectations and would be
corrected. This was an isolated observation. This failure to maintain
the handwritten narrative logs in a form as required by procedures is a
violation. This failure constitues a violation of minor significance
and is being treated as an NCV, consistent with Section IV of the NRC
Enforcement Policy (50-281/96-09-01).
c. Conclusions
A. NCV was identified for not maintaining Unit 2 control room logs in the
form required by procedures. This was an isolated observation.
II. Maintenance
Ml
Conduct of Maintenance
Ml.1 Unit 2 Letdown Line Repair
a.
Inspection Scope (62703)
On August 13, plant operators determined that Unit 2 total Reactor
Coolant system (RCS) unidentified leakage had increased from previous
values.
A containment entry revealed a leak on the normal letdown line
(2-inch line) downstream of valve 2-CH-HCV-2200C.
The inspectors
monitored the licensee's repair of the normal letdown line.
b. Observations and Findings
On August 13, following the identification of a leak on the normal
letdown line, normal letdown was isolated and excess letdown was placed
into service.
RCS unidentified leakage never exceeded TS allowed
values.
Inspection of the leak revealed a 1-inch crack on the vertical
weld on the tee downstream of letdown orifice isolation valve 2-CH-HCV-
2200C. This weld had previously failed in 1987.
The horizontal weld on
the same tee experienced two previous failures in December 1995 and
March 1996 (See NRC Inspection Report Nos. 50-280, 281/95-23 and 50-280,
281/96-02).
Station management conducted numerous meetings on this matter to
determine a course of action to repair the leak. A number of repair
options were proposed, one of which included shutting down and repairing
the leak with the unit offline. A unit shutdown was decided against due
to the challenges the operating shift would face in shutting down the
unit without normal letdown in service.
On August 14, the licensee
determined that the repair_ would take place with the unit online.
The repair was conducted by machining and grinding the defective weld
and rewelding the joint with the unit at power.
The joint was
successfully tested following its repair. This repair method eliminated
the affected area, preventing any meaningful failure analysis. Repairs
7
were completed and normal letdown was returned to service on August 16.
The licensee's engineering staff concluded that the most probable cause
of the failure was adverse flow induced vibration due to two phase flow.
To alleviate this, an interim support was proposed for installation
upstream of the 2-CH-HCV-2200C valve. A support is installed in Unit 1
at the same location. Additionally, the licensee plans to evaluate the
need to redesign the Unit 2 letdown piping configuration.
c. Conclusions
The inspectors concluded that the licensee's repair of the letdown line
was acceptable.
However. this leak is the third such occurrence in the
last nine months and no root cause had been identified.
Ml.2
ESW Pump Surveillance Observation
a. Inspection Scope (61726)
On September 4, the inspectors observed personnel performing O-OPT-SW-
001, Emergency Service Water Pump (ESWP) 1-SW-P-lA, revision 6.
The
diesel driven pump had tripped on overspeed on September 3, and the test
was being performed to prove operability after corrective maintenance to
the overspeed trip device. Approximately 11 minutes after pump start,
the pump tripped again on an apparent overspeed condition. The pre-test
brief. procedure preparation and pump start were observed.
b. Observations and Findings
The pre-test brief was thorough.
Procedure preparation steps were
observed to be properly performed. During the performance of procedure
step 6.1.7, which required pump house ventilation air dampers to be
opened, the operator noted that water tight hurricane covers had been
placed over the four wall damper openings.
The ceiling damper was not
obstructed. The covers were recently placed over the dampers due to
potential adverse weather conditions. The covers appeared to defeat the
intent of the step. After consultation with engineering and the unit
Senior Reactor Operators (SROs), the operator signed the step as
complete but made a reference to the covers in the procedure (the
dampers were open). A procedure change request was initiated to
recognize this condition for future procedure performance.
The
inspectors verified by an UFSAR review that operation of the diesel-
driven ESW pumps would not be affected with the damper covers installed.
The pump was started, and pump speed was increased to approximately 900
Revolutions Per Minute (rpm). After 11 minutes of operation, the pump
tripped on an apparent overspeed condition.
Pump rpm was not being
monitored at the time of the trip; however, there was no evidence that
pump speed had actually increased. Maintenance personnel consulted with
the vendor and system engineers and ran the pump several times to
evaluate the overspeed trip setpoint. Engineers found the trip setpoint
to be inconsistent and replaced the overspeed trip device.
Mechanics
8
readjusted the trip setpoint and ran the pump to demonstrate trip
setpoint repeatability and pump reliability. Procedure 1-0PT-SW-001 was
successfully performed as a post maintenance test and 1-SW-P-lA was
declared operable at 10:15 p.m. on September 5, in advance of Hurricane
Fran's arrival. The inspectors verified that the procedure was revised
to permit the test to be run with the hurricane covers installed over
the four wall dampers.
c. Conclusions
The inspectors concluded that test performance was good. Appropriate
corrective action was taken to restore 1-SW-P-lA to service prior to
Hurricane Fran arriving onsite.
Ml.3 Work Order 00343977 (62703)
The inspectors observed maintenance activities associated with Work
Order (WO) 00343977, Investigate Possible Grounds on 480 Volt Load
Center 2H.
The work activity involved obtaining ground detection system
voltage readings to allow comparison between the 3 phases and determine
if grounds were present. The inspectors observed activities in progress
and discussed the data obtained with engineering personnel. The work
activity was accomplished in accordance with the WO's instructions and
proper electrical safety precautions were implemented.
The voltage
readings obtained did not indicate that grounds were present.
Ml.4 Emergency Diesel Generator Testing (61726)
On August 31, the inspectors observed portions of the testing conducted
on the number 2 Emergency Diesel Generator (EOG).
The testing was
accomplished in accordance with procedure 2-0PT-EG-009, Number 2
Emergency Diesel Generator Major Maintenance Operability Test,
revision 0. Testing observed was accomplished in accordance with the
procedure and no discrepancies were noted.
The inspectors also reviewed
the completed procedure and verified that the acceptance criteria was
met prior to the licensee declaring the EDG operable.
MB
Miscellaneous Maintenance Issues (92700, 92902)
M8.l (Closed) Violation 50-280. 281/94-173 01014:
failure to identify and
promptly correct conditions adverse to quality.
On June 16, 1994, a
chemical release occurred which degraded both Auxiliary Ventilation
Exhaust Filter (AVEF) trains beyond TS requirements. The licensee
failed to recognize the potential for AVEF filter degradation and failed
to perform TS required filter efficiency testing in a timely manner.
The event and corrective actions were previously documented in NRC
Inspection Report Nos. 50-280, 281/94-21, 94-24, and 94-33 and Licensee
Event Reports (LERs) 50-280/94008-00, -01, and -02.
The licensee had
not anticipated filter damage from limited exposure to chemicals used
for Steam Generator Chemical Cleaning (SGCC).
Follow-up evaluation
failed to identify the specific chemical which caused the damage, but
did conclude that chemicals used for SGCC did damage the AVEF charcoal
9
filters. The inspectors reviewed corrective actions for this event to
determine whether they were adequately implemented to preclude
recurrence.
A broad TS review for event driven surveillances was completed.
Procedure revisions were implemented as appropriate to highlight the
need to perform specific event driven surveillances. Subsequent filter
testing confirmed that the replacement filters did not degrade following
SGCC completion. A mechanical jumper was installed to permit the non-
safety-related charcoal filters to be used for containment purge
operation during outages. including SGCC operations. This modification
in addition to procedure revisions were effective in minimizing the time
during which the category I safety-related AVEF filters are used for
routine operations. The inspectors observed that lessons learned from
this event were clearly communicated and implemented for the Unit 2 SGCC
outage. Operations personnel continued to properly implement these
lessons learned including greater sensitivity to event driven
surveillance requirements through the end of this report period. The
inspectors concluded that corrective actions for this event were
properly implemented.
M8.2
(Closed) LER 50-280/94008-01 and -02: entry into TS 4.0.3 for failure
to test new charcoal in accordance with TS 4.12.B.7(b) and a missed TS
surveillance. These LERs documented the dual train AVEF filter
degradation described in Section M8.1.
The two LER updates were
submitted to document subsequent charcoal filter efficiency test results
and clarify that the current test standards for new charcoal satisfied
TS requirements.
The LERs accurately documented the event and met
10 CFR 50.72 reporting criteria. The inspectors independently reviewed
charcoal filter test results and confirmed that the test results met the
TS acceptance criteria. The NRC is presently reviewing testing
requirements used by the industry and specified in TS to determine if
changes in requirements are warranted.
Any further review in this area,
if any, will be conducted as followup on that effort.
Corrective actions to review event driven TS surveillance requirements,
identified that a visual inspection following sensitized stainless steel
piping flushes was not performed as required by TS 4.2 during certain
occasions in the past. However, the piping has been successfully
visually inspected in accordance with the American Society of Mechanical
Engineers (ASME)Section XI program on a periodic basis. The missed
visual inspections following pipe flushes did not adversely affect
public health and safety. Procedures were revised to clearly identify
the visual inspection requirement. The inspectors determined that
corrective actions described in the LERs were complete.
M8.3
(Closed) LER 50-281/94001: both AVEF trains inoperable.
On January 24,
1994, the Unit 1 A train AVEF fan 1-VS-F-58A tripped repeatedly due to
excessive air flow and was declared inoperable. The normal power supply
to the redundant train fan, 1-VS-F-588, was unavailable due to a
surveillance test configuration. Operators declared both AVEF trains
inoperable and entered a six-hour LCO as required by TS 3.0.2. Both
10
AVEF trains were returned to service later that day, within the time
interval permitted by TS.
An alternate power supply remained available
to the 1-VS-F-58B fan throughout this event. The inspectors therefore
concluded that this event did not adversely effect public health and
safety.
Engineering determined that when the AVEF system was aligned other than
in its accident configuration, small flow anomalies can cause the
running fan to trip. Corrective actions included tighter controls for
making ventilation system adjustments and more frequent filter cleaning
to provide more margin between normal operations and the fan trip
setpoints. The inspectors reviewed procedure revisions, posted operator
aids, and log revisions. These actions have improved AVEF system
operation since the event. Engineering additionally proposed a design
change which would greatly reduce ventilation duct alignment
sensitivity. Engineering plans to have the design change fully
developed for management approval and implementation by October 1996.
The inspectors concluded that corrective actions were appropriate.
M8.4
(Closed) LER 50-281/94004: station battery 2A inoperable longer than
allowed due to personnel error.
On four separate occasions in October
1994, documented station battery 2A voltage readings indicated that cell
52 was inoperable. Licensee personnel failed to recognize the
inoperable condition and therefore failed to implement TS required
actions. Violation 50-281/94032-01 was issued for failure to promptly
identify and correct conditions adverse to quality.
NRC Inspection
Report Nos. 50-280, 281/94-24, 94-32, 95-07, 95-17, and 96-03 previously
documented the event and corrective actions. The LER documented the
event and causal factors in adequate detail and satisfied reporting
criteria specified in 10 CFR 50.72. The inspectors verified that
corrective actions for this event were appropriate and had been
completed.
The inspectors identified one minor error in the LER.
The
LER stated that the licensee verbally requested a Notice of Enforcement
Discretion for the inoperable station battery on October 27, 1994.
The
actual request date was October 28, 1994. The inspectors determined
that this error was administrative in nature and did not alter the
event's significance.
No LER update is necessary.
M8.5
(Closed) LER 50-280/96001-01: station and EDG battery connections not
coated with anti-corrosion material due to procedural error. The
original LER stated that a 24-hour LCD was entered for not completing TS
surveillance requirements for Station Battery 18 and EDG Batteries 1, 2,
and 3. This LER update was submitted to clarify that the LCD also
applied to Station Battery 28. This LER update corrected the original
omission. This event was documented in NRC Inspection Report 50-280,
281/96-07 and resulted in NCV 50-280, 281/96007-01.
M8.6 (Closed) Deviation 50-280. 281/96002-03: deviation from commitment to
reduce probability of core damage from flooding. This item reported two
deviations from commitments concerning inspections of CW rubber
expansion joints, i.e., internal inspections of the joints were not
being conducted in accordance with the vendor's recommendations, and
M8.7
11
changes to the inspection and service life replacement of these joints
were not receiving SNSOC review.
The first deviation was subsequently
withdrawn by the NRC, due to a change in the vendor's recommended
inspection of the joints. The deviation concerning SNSOC review was
acknowledged by the licensee and the following corrective actions were
specified in the licensee's response: 1) Revise model WOs for joint
inspections to require an 18 month inspection frequency (matching the
original commitment) and require SNSOC review of any changes to
inspection frequency; 2) Revise mechanical maintenance procedure
O-MCM-1003-01 to require SNSOC review of inspection frequency changes;
3) Revise VPAP-0803 to require SNSOC review of PM task evaluations and
deferrals for expansion joints; and, 4) Replace 16 expansion joints and
inspect four joints during the 1996 Unit 2 refueling outage.
The inspectors verified that procedures O-MCM-1003-01, Expansion Joint
- Removal, Inspection and Installation, revision 2 Change P2, and VPAP-
0803, Preventive Maintenance Program, revision 6, had been revised to
include the SNSOC review requirements.
The inspectors reviewed a sample
of the model WOs and verified that proper inspection frequency and SNSOC
review requirements were included (Reference WOs 297013-01, 334126-01,
252622-01, 297009-01, 341927-01, and 341973-01).
In addition, the
inspectors reviewed a scheduling matrix which showed each CW joint along
with the last inspection and replacement date, and the next inspection
and replacement date, and verified that the dates had been adjusted to
match the licensee's original inspection and replacement commitments
(i.e., inspection every 18 months and replacement every eight years).
Additionally, the inspectors verified that the dates on the matrix
reflected that 16 joints had been replaced and four joints had been
inspected during the Unit 2 outage. The inspectors also reviewed a
sample of the completed WOs which accomplished the inspection and
replacement work (Reference 336640-01, 336641-01, 355179-01, 338875-01,
and 335180-01).
Based on this review the inspectors concluded that adequate corrective
actions had been completed to close this deviation.
(Closed) Unresolved Item (URI) 50-280. 281/96002-04:
review preventive
maintenance program deferral process. This unresolved item was issued
due to concerns related to the Preventive Maintenance (PM) deferral
process discovered during the investigation that led to Deviation 50-
280, 281/96-02-03. The concern was that PM deferrals were being
approved without an adequate technical basis, and rescheduling dates
were not being accurately established based on these deferrals.
As stated in the closure of Deviation 50-280, 281/96002-03 (Section
M8.6), the inspectors verified the accuracy of the scheduling dates for
the CW system joint inspections and replacements.
Inspection of the
licensee's PM program for the Low Head Safety Injection system,
documented in NRC Inspection Report Nos. 50-280, 281/96-07, included a
detailed review of inspection frequencies, scheduling dates, and the
technical adequacy of PM deferrals. That inspection concluded that
these areas were satisfactory. In addition, scheduling personnel
12
conducted a 100 percent review of all PM deferrals issued in the past
two and a half years to verify scheduled date accuracy.
The inspectors
reviewed the results with the scheduling supervisor and determined that
over 99 percent of the PM deferrals reviewed had correctly scheduled due
dates. The errors identified were promptly corrected and the PM
performed as necessary to bring them within the required periodicity.
Based on the review of Deviation 50-280, 281/96002-03, additional
inspections documented in NRC Inspection Report Nos. 50-280, 281/96-07,
and the 100 percent deferral review, the concerns which were the subject
of this URI were resolved.
M8.8 (Closed) LER 280/95007-00. (Open) LER 280/95007-01 (90712): operation
with non-isolable leak in pressurizer instrumentation nozzles. This LER
reported a leak in two of the upper pressurizer instrument line nozzles
on Unit 1. This condition was discovered by the licensee while other
work was being performed on the pressurizer during an outage.
The
licensee's immediate corrective actions included boroscopic and liquid
penetrant inspection of the two defective nozzles, and additional
inspection of the other instrument line penetrations into the
pressurizer. Cracks were found in the two leaking nozzles.
No evidence
of leakage on the other pressurizer penetrations was found.
The leaking
nozzles were removed and new nozzles were subsequently installed.
One
of the removed nozzles was retained for a detailed metallurgical
examination.
An evaluation for the continued operation of Unit 2
determined that the unit could be safely operated until an inspection of
the Unit 2 pressurizer could be conducted at the next forced or
scheduled outage.
Corrective actions to prevent recurrence of this deficiency included:
1) Perform a visual inspection of the Unit 2 pressurizer nozzles; 2)
Conduct a metallurgical examination of the nozzle removed from Unit 1:
and, 3) Report the results of the metallurgical examination and any
additional corrective actions in a supplement to this LER.
The
inspectors reviewed evidence of the completion of these corrective
actions. Inspection of the Unit 2 pressurizer nozzles determined that
there was no leakage. The results of the metallurgical examination were
issued and the supplement to this LER (i.e., LER 95007-01) was issued.
The LER supplement indicated that an additional inspection of the Unit 1
pressurizer nozzles would be necessary prior to the specification of any
further long term actions concerning this problem.
As a result of the
completion of corrective actions specified in LER 95007-00 the LER will
be closed, additional followup of the completion of corrective actions
for this issue will be accomplished by review of LER 95007-01.
The inspectors determined that the pressurizer nozzle leakage was in
violation of TS section 3.1.C.4, which prohibits continued operation
with a non-isolable RCS leak. This licensee identified violation is
being treated as a NCV, consistent with Section VII.~.l of the NRC
Enforcement Policy (NCV 50-280/96009-02) .
13
III. Engineering
El
Conduct of Engineering
El.1 Review of Deviation Reports
a.
Inspection Scope (37550)
The inspectors performed a review of DRs.
The purpose of the review was
to discern whether any adverse trends existed, whether the resolution of
problems was thorough and whether any violations of NRC requirements had
occurred with regard to the conduct of engineering. A secondary purpose
of the review was to form a basis for making a conclusion regarding the
effectiveness of the engineering organization. At the inspectors'
request. the licensee generated various summaries of DRs, which*gave a
succinct statement of the problem and corrective action. The summary
reports reviewed by the inspectors were sorted as follows:
All the DRs classified as "significant" by the licensee and
initiated since August 1994. There were eight in this sort. The
problems described in these DRs were operational or maintenance
type problems that did not have a direct bearing on the
performance of the engineering organization, therefore, none were
selected for further review.
All the DRs classified as "potentially significant" by the
licensee and assigned to engineering and initiated since October
1995.
In this sort, 29 were associated with Unit 1, 23 were
associated with Unit 2 and 7 applied to both units. After review
of the summary, seven were selected by the inspectors for further
review. These were DRs S-95-2442 and 2919; S-96-0064, 0798, 0850,
0851 and 1136.
All the DRs written against the top three systems from the risk
perspective since August 1995. These systems were Emergency
Electrical Power (including the EDGs). AFW, and Safety Injection.
There were 109 DRs written against Emergency Electrical Power, but
this did not represent all the DRs associated with electrical or
instrumentation and control equipment because DRs could also be
written against a mechanical system for that type problem.
Nine
DRs from the Emergency Electrical Power sort were chosen for
further review. These were: S-95-2705, S-96-0243, 0284, 0360,
0422, 0445, 0489, 1081 and 1445.
Review of these DRs led to
review of DR S-93-1383 having to do with a fault on a 34.5 kV
cable in the switchyard.
In addition, an ongoing investigation
concerning recent unusual indications of the DC ground detection
lamps in the main control room was evaluated by the inspectors .
The DRs for the Feedwater and AFW Systems could not be sorted separately
since both these systems were coded FW.
There were 89 DRs in this sort.
14
The sort for the Safety Injection System contained 83 DRs.
None of the
AFW or Safety Injection DRs received further review.
The inspectors
did, however, conclude that no adverse trends in these systems were
indicated by the DRs written against them.
Reviewing of a DR included review of relevant documents, questioning of
the cognizant engineer, and inspection of installed equipment to verify
corrective actions as deemed appropriate.
b. Observations and Findings
Through review of the selected DRs, the inspectors made the following
observations and findings:
Batteries The inspectors identified that there was a small amount of
corrosion on several terminals of the 125 VDC and 48 VDC batteries in
the 230 kV switchyard relay house. These batteries were non-safety-
related, however, they were important to safety, in that, they were
important to the reliability and functionality of the offsite power
system.
The licensee determined, after consultation with the
manufacturer, that the corrosion was nickel cobalt due to corrosion of
the stainless steel hardware; and white lead due to moisture and oil.
The inspectors met with the Superintendent of Substation Maintenance,
who stated that the corrosion would be cleaned off and lubricant as
recommended by the manufacturer would be applied to the terminals. This
work would take place no later than October 1996. This corrective
action was acceptable to the inspectors. The inspectors noted that
these batteries had recently passed the capacity tests which
demonstrated that the observed corrosion was not creating any high
resistance connections.
The inspectors did not observe any indicators of battery degradation
such as sedimentation, deformation, cracking, etc. The inspectors
inquired as to the age of the batteries. The licensee responded that
the date codes stamped on the posts indicated that the batteries had
been shipped in August 1969. This meant that the batteries were 27
years old. The licensee stated that the batteries were being subjected
to annual capacity tests as recommended in IEEE Standard 450,
Recommended Practice for Maintenance, Testing and Replacement of Large
Lead Storage Batteries for Generating Stations and Substations. The
licensee stated that the batteries were testing above 100 percent
capacity.
Circuit Breakers On February 4, 1996, there was a fault on the
transmission system near the plant. Immediately following the fault,
breakers for the service water pump (1-VS-P-1D) and the chilled water
pump (1-VS-P-2D) associated with chiller Din the mechanical equipment
room tripped. This resulted in shutdown of safety-related chiller D
(1-VS-E-4D).
On March 8, 1996, there was a fault on the 34.5 kV system
in the switchyard. The same breakers tripped and the chiller shutdown
as before. These two events were the subjects of DRs S-96-0243 and
0489. After the second occurrence, the licensee's investigation
e
15
determined the cause of the chiller shutdown to be wrong set points of
the molded-case magnetic-only circuit breakers protecting the circuits
for the pumps.
The breakers in question were in a motor control center which was
installed in 1993 as part of Design Change Package (DCP)90-008. This
plant modification installed several new safety-related chillers. The
new breakers were magnetic-only type in contrast to the thermal magnetic
type which were utilized in the rest of the motor control centers in the
plant. The magnetic-only type breakers have a fairly wide range of
adjustments from which the user can select to protect a given motor.
The DCP did not specify a set point for the breakers nor did it provide
specific guidelines for that purpose.
The set points were determined by
the test group as they performed the start-up tests on the breakers.
The test group did not contact the engineers responsible for the DCP to
obtain a set point, but rather used guidelines provided by the breaker
manufacturer.
The set points, as confirmed by the test data sheets, were approximately
ten times the motor full load amperes. These set points were too low in
that, they did not.take into account all the relevant design
considerations, and in effect were too sensitive. The short-circuits
described above were followed by voltage transients which caused the
motors in question to slow down to stall speed.
When the voltage
recovered, the motors drew full starting current which was above the set
point of the circuit breaker, and the breakers tripped.
With loss of
the auxiliary equipment, the chiller shutdown as designed.
The two breakers in question were reset according to the licensee's
design guides, STD-EEN-0011, Standard for Protective Device Settings.
The inspectors noted that the new set points were acceptable. The
licensee also initiated Engineering Commitment (EC) 96-44 to review the
set points of all the new magnetic-only circuit breakers (approximately
six additional breakers). This EC had a due date of October 15, 1996,
and the work had not been completed at the time of this inspection.
10 CFR 50, Appendix B, Criterion V. Instructions, Procedures and
Drawings, requires that activities affecting quality shall be prescribed
by documented instructions appropriate to the circumstances. The fact
that DCP 90-008 did not specify any set points for the breakers being
installed by the modification was in conflict with that requirement.
This deficiency resulted in the breakers being set at a too sensitive a
setting as evidenced by the fact that two breakers tripped during an
anticipated transient that should not have caused tripping of the
breakers. The safety significance of the wrong breaker set points was
that safety-related equipment could have spuriously de-energized due to
normal starting current during an accident or reactor event.
Additionally, this chiller provided cooling to the Emergency Switchgear
Room and Control Room.
These systems are identified in the top 10 list
of risk-significant systems for the plant. The licensee identified the
set point problem; however, the underlying problem that the set point
was not specified in the design package was not identified. The
16
corrective action of reviewing other similar applications was proceeding
slower than appropriate for the significance of the problem and work
involved (i.e., problem was identified in March 1996 and reviewing and
resetting of six breakers was scheduled to be completed in October
1996). The circumstances of the breaker set point problem constitute a
violation of 10 CFR 50, Appendix B, Criterion V, and will be identified
as Violation 50-280/96009-03, Design Change Package Failed to Specify
Breaker Set Point.
c. Conclusion
The inspectors did not identify any adverse trends during the review of
the licensee's DRs.
With one exception, corrective action associated
with the problems described in the DRs were thorough.
The corrosion on
the non-safety-related switchyard batteries identified by the inspectors
represented a maintenance item. and did not indicate any deficiency in
the conduct of engineering. A violation of NRC requirements was
identified for failure to provide adequate instructions for setting
safety-related molded case circuit breakers.
The inspectors concluded
that the engineering organization was effective in supporting plant
operations. This statement was based on the fact that 348 DRs were
reviewed and only one problem was identified. The violation involving
breaker set points did not change the overall positive conclusion.
El.2 High Head Safety Injection Electrical Logic
a.
Inspection Scope (37551)
A problem occurred recently at another utility which raised a concern
requiring investigation at Surry.
The problem at the other utility
involved the design of the electrical logic for the High Head Safety
Injection (HHSI) pumps, which allowed two of the three pumps to start
and run on the same degraded electrical bus.
Due to similarities
between the plant at the other utility and Surry, the Surry design was
reviewed.
b. Observations and Findings
Investigation of this issue determined that a similar problem (but not
the same problem) had been identified in NRC Violation 50-280, 281/
91024-02. This issue was closed in NRC Inspection Report NOs. 50-280,
281/93-13 based on additional administrative controls that corrected the
identified problem. Subsequently, the licensee installed a design
change (DCN 92-064-3) to permanently correct the HHSI pump electrical
logic. The inspectors reviewed the electrical logic in this design
change and the test procedure (2-FDTP-92-64-3-1, Charging Pump Logic
Modifications/Surry Units 1 and 2, revision 0) which verified the
operability of the new logic, and concluded that Surry's HHSI pump logic
would not allow two HHSI pumps to start and run on the same degraded
electrical bus.
17
c. Conclusions
Surry's HHSI pump electrical design will not permit two HHSI pumps to
start and run on the same degraded electrical bus.
El.3 Review of 10 CFR 50.59 Process
a.
Inspection Scope
The inspectors reviewed 12 change packages including DCPs, UFSAR change
packages (FSs), and Temporary Modification (TM) packages.
Most of the
documents were issued during the previous 12 months.
Five of the
documents (all DCPs) had been determined, through activity screening,
not to require a 10 CFR 50.59 evaluation.
The other seven included five
FSs, one DCP, and a TM.
The inspectors also reviewed the status of TMs.
b.
Observation and Findings
The inspectors confirmed that the five DCPs, which had not been
evaluated pursuant to 10 CFR 50.59, did not require a safety evaluation
according to 50.59. The activity screening criteria had been properly
evaluated .
The inspectors confirmed that adequate safety evaluations had been
performed for five FSs, a DCP, and a TM in accordance with 10 CFR 50.59.
The inspectors determined that several administrative errors had been
made in preparing the documents; however, these were of a minor nature.
Signoff/concurrence procedures were followed for all change packages.
The inspectors visited the control room and determined that procedures
for TMs were being followed.
Logs of TMs were present for both units as
required and appropriate signatures existed for current active TMs.
Only seven TMs were active, four on Unit 1 and three on Unit 2.
Records
indicated that the number of TMs for two units has been maintained at a
low level, fewer than ten, for several years through careful management
attention.
c. Conclusions:
The inspectors concluded that the five DCPs not evaluated pursuant to
10 CFR 50.59 did not require 10 CFR 50.59 safety evaluations and that
the activity screening criteria had been properly evaluated. It was
further concluded that through careful management attention, the number
of TMs for both units has been maintained at a low level (fewer than
ten) for several years.
" *
I I
18
E2
Engineering Support of Facilities and Equipment
E2.1 Engineering Support- Procurement Engineering
a.
Scope
The inspectors reviewed engineering activities related to procurement of
replacement equipment, materials, and parts. This included item
equivalency evaluations and dedication of commercial grade items for use
in safety related applications. A sample review consisted of 15
material upgrades and 15 item equivalency evaluations. The following
provided regulatory guidance for this inspection area:
Regulatory Guide 1.123, Quality Assurance (QA) Requirements for Control
of Items and Services for Nuclear Power Plants
ANSI N45.2.13-1976, QA Requirements for Control of Items and Services
for Nuclear Power Plants
NRC Generic Letter 91-05, Licensee Commercial Grade Procurement and
Dedication Programs.
b. Observations and Findings
Procurement Technical Evaluations (PTEs) demonstrated that critical
characteristics for material upgrades and item substitutions were
adequately identified and appropriate tests or inspections were
specified for quality verification.
PTEs included documentation of
appropriate 50.59 safety evaluation screening. Receipt inspection
reports documented the verification of the specified critical
characteristics. Vendor exceptions to purchase order requirements and
receipt inspection deficiencies were adequately resolved.
Equipment
requiring post installation testing for critical characteristics was
appropriately tagged.
The inspectors identified no occurrences in which
unqualified equipment or materials were installed in safety related
applications.
The inspectors noted that the licensee's self-assessment in the
engineering material upgrade process was limited to a minimal review in
a 1994 procurement audit. The licensee indicated that the scheduled
1996 procurement audit could include this activity.
c. Conclusions
The engineering process for material upgrade and item equivalency
evaluation adequately provided for installation of appropriate quality
level material in safety related applications .
. *
19
E3
Engineering Procedures and Documentation
E3.l Review of 10 CFR 50.59 Process
a.
Inspection Scope
The inspectors reviewed procedures governing the 50.59 process,
including those controlling DCPs, procedure changes, TMs, FSs, and
safety evaluations.
In addition the inspectors reviewed policy
documents (Nuclear Standards) on which the procedures were based.
b. Observation and Findings
The inspectors found the procedures governing the 50.59 process to be
comprehensive, thorough, and well written.
One procedure, VPAP-3001
(safety evaluations), had two features of particular interest.
VPAP-
3001 appeared to adopt the approach of NSAC-125 including one area where
the NRC staff has not yet accepted the approach.
Where a change in
probability is so small or the uncertainties in determining whether a
change in probability has occurred are such that it cannot be reasonably
concluded that the probability has actually changed, VPAP-3001 follows
NSAC-125 in stating that the change need not be considered an increase
in probability. The NRC staff is still considering the merits of that
approach and has not yet accepted it. In reviewing change packages
during the audit, the inspectors found no instance where this was an
issue. A second feature of interest is that "Safety Analysis Report" is
defined in VPAP-3001 as a broad spectrum of documents which includes
much more than the UFSAR.
It also includes the operating license, TS
and bases, technical requirements manual, emergency plan, quality
assurance program, offsite dose calculation manual, all correspondence
supporting submittals approved by NRC, NRC safety evaluations and
referenced correspondence, final environmental statement, and Appendix R
fire protection report. Thus, when the licensee applies 10 CFR 50.59 to
changes in the "Safety Analysis Report," it is a very conservative
application compared to that required by a literal reading of the
regulation.
c. Conclusions:
The inspectors concluded that the licensee 10 CFR 50.59 procedures were
comprehensive, thorough, and well written.
E3.2
UFSAR Update Process
a.
Scope
The inspectors discussed the approach to be taken by the licensee for
evaluating and updating the UFSAR at Surry.
,* *
20
b. Observations and Findings
In May 1996, the licensee formed a UFSAR project team for both Surry and
North Anna to examine the state of the UFSARs at both sites. The team
identified problems in the current UFSAR processes, content and usage.
The project team collected relevant data, identified problem areas. and
proposed corrective actions. The licensee developed long term
corrective actions to resolve many of the content and usage problems.
Included in the strategy of the plan.were several near-term actions to
assess current UFSAR quality and develop recommendations based on
assessment findings.
Recommendations in the process and user
improvement areas involved developing a UFSAR writers guide, simplify
administrative controls, electronic versions of the document, and
conduct awareness training.
The licensee stated that the Nuclear Energy Institute (NEI) approach
would be used to review the UFSAR.
An evaluation of four systems would
be performed, two safety related systems, and two non-safety related
systems.
At Surry these systems are safety injection, auxiliary
feedwater. component cooling water, and circulating water.
The
assessment at Surry will be completed by October 11, 1996, with the NEI
initiative due by June 1, 1997.
Conclusions
The licensee formed a UFSAR project team to examine the state of the
The NEI approach would be used to review the UFSAR.
E4
Engineering Staff Knowledge and Performance
E4.1 Engineering Self Assessment Program
a.
Scope
A review of the licensee's engineering self assessment program was
conducted by the inspectors to see if strengths and weaknesses were
identified and if corrective actions were initiated for the weaknesses.
b. Observations and Findings
The inspectors reviewed procedure SSES-1.3, Controlling Procedure for
Engineering Self Assessment, revision 0, dated May 1, 1996.
The
licensee had completed one self assessment project and has five more in
progress. The inspectors reviewed parts of the following self
assessments.
ENG-SA-96-001, Plan of the Day Effectiveness (Involves engineering
support to other site organizations)
ENG-SA-96-002, Procedural Compliance
J
21
ENG-SA-96-003, UFSAR Update Process.
The first self assessment resulted in improvement in the engineering
internal and external communications process. Part of this assessment
was a survey of engineering's customers (planning, maintenance,
electrical. scheduling, and Nuclear Site Services) in order to evaluate
the customers perception of the engineering group's response to requests
for support emanating from the Plan of the Day meetings.
Eighteen
people representing a cross section of personnel requesting engineering
support in their daily tasks rated the engineering support as very good.
c. Conclusions
The new self assessment process was still in its early stages of
development and it was too early to form an analysis of the licensee's
efforts.
E5
Engineering Staff Training and Qualification
E5.1 Review of 10 CFR 50.59 Process
a.
Inspection Scope
The inspectors reviewed training records for staff who had
completed training in the requirements and procedures for
10 CFR 50.59 evaluations.
b. Observation and Findings
The inspectors determined that 10 CFR 50.59 training is required
by the licensee to be current for all staff who perform or review
safety evaluations. About 200 staff have received the training.
Annual requalification is required with a 3-month grace period.
Although SNSOC members/alternates and offsite Management Safety
Review Committee (MSRC) members are not required to take the
training, most of the SNSOC members/alternates had taken the
training and maintained it current. Only one MSRC member had
current training.
c. Conclusions:
The inspectors concluded that 10 CFR 50.59 training was maintained
current for all personnel who performed and provided 10 CFR 50.59
safety evaluations.
E5.2 Engineering Manager Training
a.
Scope
A review was made of some of the training being conducted for the
engineering managers at the Surry site.
22
b. Observations and Findings
The inspectors discussed the leadership development/awareness training
for the engineering supervisors.
In particular. the review of issues,
processes, and process revisions conducted during the supervision staff
meetings was examined.
Some of the topics discussed during these
meetings were:
plant safety analysis, the maintenance rule, 10 CFR
50.59 safety analysis standard, outage safety assessment, discrepancy
trend report, UFSAR update of self assessment, operator workarounds,
hurricane response plan, NRC Bulletin 96-01 summary results, vibration
monitoring, and other. These topics have been covered over a seven
month period at Surry. The awareness training conducted for the
engineering supervision staff was considered a positive finding.
c. Conclusions
Manager training on a wide variety of subjects was being used to enhance
the engineering supervision in making more informed decisions and was
identified as a positive finding.
E7
Quality Assurance in Engineering Activities
E7.1 Design Control Program Audit
a.
Scope
The inspectors reviewed part of an audit (part identified for Surry and
corporate engineering) covering the design control program.
b. Observations and Findings
The inspectors reviewed the results of Audit Number 96-04, Design
Control and Engineering Programs, conducted during March and April 1996,
at Surry, North Anna, and at corporate Engineering. The audit reviewed
controls for plant design and modifications, engineering programs for
scaling, set points, seismic qualifications, design basis documents,
software control, and potential problem plant controls.
Findings were identified with multiple examples. Several of the
findings identified a number of procedural compliance, quality, and
human performance deficiencies within the Engineering organization.
Some corrective actions such as reinstruction of individuals, procedure
improvements, calculation revisions, design change package revisions,
lessons learned memorandums, etc., have been taken or were in progress.
Longer term corrective actions were being undertaken by the Engineering
Redesign Project Team.
One of the goals of this team was to improve
design quality and conform_ance.
23
c. Conclusions
The Design Control and Engineering Program audit was thorough, detailed
and resulted in meaningful findings. The high quality of this audit was
identified as a positive finding.
IV. Plant Support
Sl
Conduct of Security and Safeguards Activities (71750)
On several occasions during the inspection period. the inspectors
performed walkdowns of the protected area perimeter to assess security
and general barrier conditions.
No deficiencies were noted, and the
inspectors concluded that security posts were properly manned and that
the perimeter barrier's material condition was properly maintained.
Rl
Radiological Protection and Chemistry (RP&C) Controls (71750)
On several occasions during the inspection period, the inspectors
reviewed Radiation Protection (RP) practices including radiation control
area entry and exit, survey results, and radiological area material
conditions.
No discrepancies were noted, and the inspectors concluded
that RP practices were proper.
RS
Miscellaneous Radiation Protection and Chemistry Issues
R8.l Potentially Contaminated Construction Materials (71750)
On July 26, another nuclear power facility found that a shipment of 1/4
inch steel plate construction material was contaminated. The source and
batch number of the contaminated steel was identified.
VEPCO was one of
several utilities who received material from this same batch. The
inspectors discussed the issue with the Superintendent RP to determine
whether Surry Station had received contaminated steel from the suspect
batch. Fifteen steel plate sheets from the suspect batch were received
at North Anna Power Station. Licensee personnel initiated action to
account for the steel plating usage and final location. Material
records indicated that Surry Station did not receive material from the
suspect batch. The inspectors determined that licensee response to the
potentially contaminated steel issue was appropriate.
V. Management Meetings
Xl
Exit Meeting SUD1Dary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on September 12 and 23 and
October 7.
The licensee acknowledged the findings presented.
24
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary.
No proprietary information was
identified .
,. *
25
PARTIAL LIST OF PERSONS CONTACTED
Licensee
R. Blount, Maintenance Superintendent
D. Christian, Station Manager
M. Crist, Operations Superintendent
J. McCarthy, Assistant Station Manager, Operations & Maintenance
R. Saunders, Vice President, Nuclear Operations
8. Shriver, Assistant Station Manager, Nuclear Safety and Licensing
T. Sowers, Engineering Superintendent
8. Stanley, Director Nuclear Oversight
J. Swientoniewski, Supervisor, Station Nuclear Safety
W. Thorton, Superintendent, Radiological Protection
IP 37550:
IP 37551:
IP 37700:
IP 40500:
IP 61726:
IP 62703:
IP 71707:
IP 71750:
IP 90712:
IP 92700:
IP 92902:
IP 92901:
26
INSPECTION PROCEDURES USED
Engineering
Onsite Engineering
Design Changes, and Modifications
Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
Surveillance Observation
Maintenance Observation
Plant Operations
Plant Support Activities
Inoffice Review of Written Reports of Nonroutine Events at Power
Reactor Facilities
Onsite Followup of Written Reports of Nonroutine Events at Power
Reactor Facilities
Followup - Engineering
Followup - Plant Operations
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-281/96009-01
failure to maintain Unit 2 control room
logs in the form required by procedures
(Section 01.5)
50-280/96009-02
50-280/96009-03
Closed
50-280, 281/94-173 01014
50-280/94008-01
50-280/94008-02
operation with non-isolable leak in
pressurizer instrumentation nozzles
(Section M8.8)
design change package failed to specify
breaker set point (Section E.1.b)
failure to identify and promptly correct
conditions adverse to quality (Section
M8.l)
LER
entry into TS 4.0.3 for failure to test
new charcoal in accordance with TS 4.12.B.7(b) and a missed TS surveillance
(Section M8.2)
LER
entry into TS 4.0.3 for failure to test
new charcoal in accordance with TS 4.12.B.7(b) and a missed TS surveillance
(Section M8.2)
r-----------------------------------------* -
27
50-281/94001
LER
both AVEF trains inoperable (Section M8.3)
50-281/94004
LER
station battery 2A inoperable longer than
allowed due to personnel error (Section
M8.4)
50-280/96001-01
LER
station and EOG battery connections not
coated with anti-corrosion material due to
procedural error (Section M8.5)
50-280, 281/96002-03
DEV
deviation from commitment to reduce
probability of core damage from flooding
(Section M8.6)
50-280, 281/96002-04
review preventive maintenance program
deferral pProcess (Section M8.7)
50-280/95007-00
LER
operation with non-isolable leak in
pressurizer instrumentation nozzles
(Section M8.8)
50-281/96009-01
failure to maintain Unit 2 control room
logs in the form required by procedures
(Section 01.5)
50-280/96009-02
operation with non-isolable leak in
pressurizer instrumentation nozzles
(Section M8.8)
Discussed
50-280/95007-01
LER
operation with non-isolable leak in
pressurizer instrumentation nozzles
(Section M8.8)