ML18152A546
| ML18152A546 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 05/24/1995 |
| From: | Belisle G, Branch M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18152A547 | List: |
| References | |
| 50-280-95-07, 50-280-95-7, 50-281-95-07, 50-281-95-7, NUDOCS 9506200154 | |
| Download: ML18152A546 (12) | |
See also: IR 05000280/1995007
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
50-280/95-07 and 50-281/95-07
Licensee:
Virginia Electric and Power Company
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, VA
23060
Docket Nos.:
50-280 and 50-281
License Nos.:
Facility Name:
Surry 1 and 2
Inspection Conducted:
April 2 through 29, 1995
Lead Inspector:
Inspectors:
Approved by:
~ft./~
W. Branch, Senior Resident Inspector
D. M. Kern, Resident Inspector
G. A. Harris, Resident Inspector
~~nChief
Reactor Projects Section 2A
Division of Reactor Projects
SUMMARY
Scope:
s;=-.2,~9:r-
Date Signed
This routine resident inspection was conducted on site in the areas of plant
status, operational safety verification, maintenance inspections, engineering
inspections, plant support, and Licensee Event Report follow-up.
Inspections
of backshift activities were conducted on April 19, 21, and 26.
Results:
Operations
The Unit 2 Safety Injection system configuration was properly controlled and
material condition was good (paragraph 3.2).
Overtime controls, including monitoring for indicators of fatigue, were
effective during the Unit 2 refueling outage (paragraph 3.3) .
9506200154 950524
ADOCK 05000280
G
2
Conservative decision making was noted when Unit 1 was manually tripped to
ensure plant conditions were boundJwhen problems were encountered after a
control rod dropped into the core (paragraph 3.1).
Maintenance
Material condition of the Spent Fuel Pool Cooling System did not meet the
plant's normal high standards (paragraph 3.4).
Engineering
A weakness was noted in procedure 1-0PT-RX-004, Reactor Power Calorimetric
Using Feed Flow With P-250 Out of Service (Manual), (paragraph 5.1).
Plant Support
Confined space entry (CSE) training was comprehensive and appropriate to
support personnel safety at the station. Personnel demonstrated sound
knowledge of CSE requirements and atmosphere test equipment (paragraph 6.2) .
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
2.
- W. Benthall, Supervisor, Licensing
- H. Blake, Jr., Superintendent of Nuclear Site Services
- R. Blount, Superintendent of Maintenance
- D. Christian, Station Manager
J. Costello, Station Coordinator, Emergency Preparedness
D. Erickson, Superintendent of Radiation Protection
- B. Garber, Licensing
B. Hayes, Supervisor, Quality Assurance
D. Hayes, Supervisor of Administrative Services
- D. Llewellyn, Superintendent, Nuclear Training
C. Luffman, Superintendent, Security
- R. MacManus, Supervisor, System Engineering
- J. McCarthy, Assistant Station Manager
- A. Price, Assistant Station Manager
- S. Sarver, Superintendent of Operations
R. Saunders, Vice President, Nuclear Operations
K. Sloane, Superintendent of Outage and Planning
- E. Smith, Site Quality Assurance Manager
T. Sowers, Superintendent of Engineering
- B. Stanley, Supervisor, Station Procedures
J. Swientoniewski, Supervisor, Station Nuclear Safety
Other licensee employees contacted included plant managers and
supervisors, operators, engineers, technicians, mechanics, security
force members, and office personnel.
NRC Personnel
- M. Branch, Senior Resident Inspector
D. Kern, Resident Inspector
G. Harris, Resident Inspector
- Attended Exit Interview
Acronyms used throughout this report are listed in the last paragraph.
Plant Status
Unit 1 began the inspection period at 100% power.
On April 12, control
rod J-7 dropped to the fully inserted position, causing a turbine
runback.
Operators stabilized the unit at 74% power.
A CRDM cable
failure precluded operators from recovering control rod J-7 to the
desired group position.
The fully inserted control rod resulted in a
higher axial flux difference than was permitted for power operations
above 50%.
Operators reduced reactor power to 45% and manually tripped
the reactor (paragraph 3.1).
2
Unit 1 was restarted and placed on-line on April 16 following CROM
System repairs. Operators observed an unexpected steam.flow imbalance
between SGs as the reactor approached full power.
The B SG was
producing about 200,000 pounds mass/hour less steam flow than either the
A or C SGs.
Initial licensee evaluation concluded that the reactor trip
had removed an oxide layer from the B SG U-Tube region which resulted in
a temporary reduction of heat transfer capability. Operators stabilized
reactor power at 98.5% to reduce the magnitude of the steam flow
imbalance.
Unit 1 remained at 98.5 % power through the end of the
inspection period.
Unit 2 operated at 100% power throughout the entire inspection period.
3.
Operational Safety Verification (71707)
The inspectors conducted frequent tours of the control room to verify
proper staffing, operator attentiveness and adherence to approved
procedures.
The inspectors attended plant status meetings and reviewed
operator logs on a daily basis to verify operational safety and
compliance with TSs and to maintain overall facility operational
awareness.
Instrumentation and ECCS lineups were periodically reviewed
from control room indication to assess operability. Frequent plant
tours were conducted to observe equipment status, fire protection
programs, radiological work practices, plant security programs and
housekeeping.
Deviation reports were reviewed to assure that potential
safety concerns were properly addressed and reported.
3.1
50.72 Report
At 5:56 pm, on April 12, Unit 1 was manually tripped from 45
percent reactor power.
All control rods inserted into the core as
designed.
Auxiliary feedwater automatically initiated as designed
on low-low steam generator level following the trip.
No primary
safety or power operated relief valves were actuated during the
event.
No secondary safety relief valves actuated; however, the A
main steam power operated relief valve was actuated briefly at the
start of the transient. It subsequently closed and reseated. All
electrical buses transferred properly following the trip and all
emergency diesel generators were operable.
The manual reactor trip was well coordinated and demonstrated
conservative decision making.
There were no Technical
Specification or procedural requirements to shutdown the unit.
Plant maintenance and engineering personnel had determined that a
high probability existed for dropping additional control rods if
an orderly shutdown was attempted.
Troubleshooting was being
performed as a result of a dropped control rod, which occurred
earlier that day at approximately 8:20 am.
At 9:20 pm the licensee informed the NRC via the Emergency
Notification System of the event.
The inspectors determined that
the event was properly reported as required.
. .
3
3.2
SI System Lineup Verification
3.3
The inspectors reviewed the material conditions and positions of
approximately 70 SI system valves within the Unit 2 Safeguards
Building to verify that the SI system was correctly configured to
perform the LHSI safety function.
The general material condition
of the system was good.
Minor discrepancies including packing
leaks, a missing label, and a degraded position indicator were
discussed with the Supervisor of Shift Operations and appropriate
corrective actions were initiated. All SI system valves inspected
were found properly positioned in accordance with procedure
2-0P-SI-OOlA, SI System Alignment, revision 2.
The current
position of SI system valves was properly documented in the system
lineup library maintained by the Operations Department.
The
inspectors concluded that the Unit 2 SI system configuration was
properly controlled and maintained.
Personnel Overtime Controls During Outage
VPAP-0103, Working Hours and Limitations, rev1s1on 2, establishes
policy to control overtime work.
The inspectors reviewed
VPAP-0103, timekeeping records, interviewed personnel, and
observed outage work activities to determine whether overtime
controls were effectively implemented .
VPAP-0103 clearly defined administrative overtime limits for
personnel who perform safety-related functions.
These limits and
approval authority were consistent with NRC GL 82-12, Nuclear
Power Plant Staff Working Hours.
The inspectors reviewed overtime
records for the February-March, 1995 period.
With limited
exceptions, workers requested and received Station Manager's
approval prior to exceeding station administrative overtime
limits.
The Administrative Services department reported
authorized and unauthorized overtime usage (above the
administrative limits) to the station manager on a weekly basis.
When appropriate, station DRs were initiated to resolve
discrepancies regarding pre-authorization to exceed administrative
overtime limits. The inspectors determined that overtime controls
were implemented consistent with VPAP-0103.
The inspectors observed that, on several occasions, a single
request to exceed overtime limits for selected activities was
written for an entire department (i.e., electrical maintenance -
60 people, mechanical maintenance - 90 people).
However, only
approximately 10 to 15% of those persons authorized under the
blanket overtime authorization actually exceeded the guidance.
The inspectors questioned whether the program continued to
preclude excessive worker fatigue when blanket overtime
authorization of this scale was granted.
The inspectors discussed
this concern with the Station Manager who noted that several
actions to prevent worker fatigue and monitor for fatigue were
effective during the outage.
These included rescheduling of work
. .
~~
-
-~---
4
to maintain crew continuity, frequent in-plant observation tours
by management, human factors assessment of DRs and job rework, and
QA oversight.
In addition, workers received behavioral
observation training annually.
The inspectors independently
interviewed workers during the outage and attended daily work
progress meetings.
Workers did not appear to be adversely
affected, physically or mentally, due to working overtime.
The
quality of work performed was not negatively impacted by use of
overtime.
The inspectors concluded that licensee overtime
controls, including continued monitoring for indicators of
fatigue, satisfied the intent of NRC GL 82-12.
3.4
Spent Fuel Pool Cooling and Purification System Walkdown
On April 11 and 12, the inspectors performed a valve alignment
verification and an evaluation of the material condition of the
spent fuel cooling pumps, skimmer, and purification system
components.
The inspectors noted that the material condition of
these components, while generally adequate, was not in keeping
with that in the rest of the station. Discrepancies noted
included the following:
Several pressure gage isolation valves were found to be out
of their specified full open position.
For example, the
spent fuel cooling pump A suction pressure gage isolation
valve, l-FC-6 was found nearly closed causing the gage to
read abnormally low.
In another example, spent fuel cooling
pump B discharge pressure gage isolation valve, l-FC-10, was
found throttled. These isolation valves we~e for gages that
provided local indication only ..
Both inboard and outboard mechanical seals for the IA and 18
spent fuel cooling pumps appeared to have been leaking as
evidenced by the accumulation of a considerable amount of
The oil bubbler for the 18 spent fuel cooling pump was
observed to be abnormally low for a period of two days while
the pump was in service. Oil was added to the pump on the
third day.
The coatings for both the IA and 18 spent fuel cooling water
pumps and their base plates were significantly degraded.
Spent fuel pool cooling heat exchanger component cooling
water pressure gage, l-CC-PI-1018, read offscale high.
The local power control hand switches for the IA spent fuel
cooling water pump was not labelled in accordance with
station standards. This was the only example of a labeling
problem identified.
-
---- ---- -- ----- ---- -
5
Both the 3A and 3B purification pumps had extensive rust on
the base plates and their coatings were degraded.
Both the 2A and 2B skimmer pumps had oil and water
accumulation on their base plates resulting in an
undesirable radioactive mixed waste.
The inspectors concluded that despite the noted discrepancies the
spent fuel cooling water pump, skimmer and purification pumps were
operable. These discrepancies were discussed with station
management for investigation and correction as necessary.
Within the areas inspected, no violations or deviations were identified.
4.
Maintenance Inspections (62703)
During the reporting period, the inspectors reviewed the following
maintenance activities to assure compliance with the appropriate
procedures.
4.1
Battery Status Update
In October 1994, the 2A station battery became inoperable due
to a degraded cell as documented in NRC Inspection Report Nos.
50-280/94-32 and 50-281/94-32.
NRC and licensee follow-up
identified several programmatic weaknesses which resulted in
failure to recognize battery degradation in a timely manner.
Station management subsequently issued a management expectation
policy statement which directed that *a station DR be written each
time a battery cell is found in the Alert performance range. This
action was taken to ensure that indications of battery degradation
were raised to management's attention before a battery became
The licensee also initiated a RCE to assess battery
performance throughout the station. The inspectors reviewed
battery maintenance activities to determine whether the policy
statement had been implemented in an effective manner.
The number of DRs pertaining to the IA and 2A station batteries
dramatically increased since October 1994. -in addition, the
number of DRs reported pertaining to the EDG, TSC, Black, and
security inverter batteries also increased as the policy statement
was implemented.
Prior to October, very few battery problems were
documented.
The inspectors observed that improved documentation
of marginal battery performance has been beneficial in
highlighting continuing problems with the station batteries for
management, driving corrective actions to be taken, and in
increased maintenance support.
In December 1994, six IA station battery cells were replaced.
The
replacement cells were spares obtained from another facility. The
replacement cells had been in service for approximately two years
at the other facility, and then stored for approximately three
6
years. Several ,of the replacement cells exhibited marginal
performance following installation, warranting increased
attention.
Two cells were replaced a second time prior to reactor
startup in December 1994.
In March 1995, eighteen 2A station
battery cells were replaced. This included replacement of the
cell which had caused the battery to be inoperable in October
1994.
The jumper which had temporarily bypassed the inoperable
cell was removed and the 2A station battery was restored to its
design condition. Several additional maintenance activities have
been completed in the past six months to improve the condition of
the EDG, TSC, Black, and security inverter batteries.
Marginal cell voltage and non-uniform specific gravities were
observed following cell replacements on IA and 2A station
batteries. These conditions persisted despite repeated battery
equalization charges.
System engineers determined that low
equalization charge voltage was a major contributor to these
problems.
It was not possible to increase the equalization charge
voltage further for these batteries due to DC bus voltage
limitations. This limited the amount of battery improvement that
can be gained from a charge.
The RCE team discussed this
situation with the vendor and continued to evaluate alternate
solutions to improve the condition of the station batteries.
The licensee RCE team determined that following the IA and 2A cell
replacements, station battery performance was acceptable.
However, there were RCE recommendations that addressed IA cell
replacement during the Fall 1995 Unit 1 RFO and possible station
battery replacement at a later date.
The RCE team also examined
the appropriateness of post maintenance test selection for cell
replacements following problems encountered on the IA replacement.
The inspectors reviewed the licensee RCE for station battery
problems and determined that it was thorough.
The increase in DRs
associated with battery problems indicated increased sensitivity
to early problem identification and resolution.
The licensee's
lower threshold for problem identification as outlined in the
October 1994 management policy statement has been effective in
early identification of equipment degradation. Additionally, as
outlined in the licensee RCE, even though the batteries remain
operable, further maintenance actions and possible battery
replacement are necessary to restore the material condition of
some of the more degraded batteries.
Within the areas inspected, no violations or deviations were identified.
5.
Engineering Inspections (37551)
During the reporting period, the inspectors reviewed engineering
activities to assure compliance with the appropriate procedure and TS
requirements.
7
5.1
Review of Reactor Power Calorimetric Manual Method
During a walkdown of the Unit 1 mechanical equipment room the
inspectors observed that one of the local feedwater temperature
indicators was missing. This instrument had been removed to allow
installation of the downstream RTD into the piping thermowell.
The thermowell for the RTD had developed a leak and had been
plugged.
The feedwater RTD provides input to the P-250 computer
for temperature information used in the computerized calorimetric
calibration of Nis.
The P-250 computer used for calorimetric calibration of the Nis
was out of service and the licensee was planning to perform a
manual calorimetric if the computer could not be returned to
service in time.
The computer was returned to service and the
computerized calorimetric was completed on time.
The inspectors reviewed procedure l-OPT-RX-004, Reactor Power
Calorimetric Using Feed Flow With P-250 Out of Service {Manual),
revision 1.
This was the procedure that the licensee would have
used to perform the calorimetric_if the computer was not
available.
The inspectors noted that the procedure required the
use of the local temperature instruments to measure feedwater
temperature.
As noted previously, one of the referenced
temperature instruments was removed and would not have been
available if needed.
The three local feedwater temperature
instruments were designated l-FW-TI-154-A, 8, and C.
These local
temperature instruments were made by Ashcroft with a span of
200 - 700 °F with 5 degree graduations on the gage face.
Given
the needed precision of the calorimetric, the inspectors reviewed
the assumed accuracy in the licensee's calculational basis for NI
setting and adjustment.
Calorimetric assumptions and calculations were contained in
"Phase 2 Results of Nuclear Unit Efficiency Study for Surry Unit 1
{VEPCO Contract No. FHN-074-0219) April 25, 1984.
11
This study
defined the assumed feedwater temperature error as the sum of
instrument specified tolerances+ instrument drift+ readout
error. The total feedwater temperature error assumed was 1.75 °F.
The inspectors reviewed licensee's vendor information on the
Ash~roft local temperature instruments to determine specified
accuracy. Additionally, I&C calibration data was reviewed to
determine calibration accuracy.
The vendor manual specifies and the licensee's lab calibrates
these type instruments to an accuracy of+/- 1% of full scale
{1% of 500 degrees or 5 °F).
The licensee's field calibration
specifies a+/- 2% full scale accuracy {2% of 500 degrees or
10 °F).
Neither of these values were within the values assumed in
the calorimetric calculation. It should be noted that, the
calorimetric formula applies instrument uncertainty in a
statistical manner.
Therefore, the increased feedwater
8
temperature error impact on the assumed calorimetric uncertainty
is unclear but believed to be slight.
The inspectors also reviewed previous calibration records for one
of the three local feedwater temperature instruments.
The
inspectors selected 1-FW-TI-154A for review.
The licensee's
records indicated that this instrument was last calibrated on
May 4, 1990, by WO 094487.
Additionally, the inspectors noted
that the local feedwater temperature instruments were not in the
periodic calibration program.
The inspectors held discussions
with reactor engineering personnel and questioned the
acceptability of using non-calibrated gages with accuracies
outside those assumed in the calculation for performing
calorimetric calibrations.
The licensee is currently performing a
review to determine the potential impact on calorimetric
uncertainties and management has placed a hold on the use of
procedures 1 & 2-0PT-RX-004.
The inspectors did not identify
cases where this procedure had been recently used to provide
values for adjustment of Nis.
The inspectors considered this
issue to be a weakness in the licensee's program and will continue
to follow the licensee's actions.
Within the areas inspected, no violations or deviations were identified.
6.
Plant Support (71707, 71750)
The inspectors conducted facility tours, work activity observations,
personnel interviews, and documentation reviews to determine whether
programs were effectively implemented to comply with regulatory
requirements in the areas of radiological protection and security.
6.1
Plant Tour Observations
The inspectors observed radiological control practices and
radiological conditions throughout the plant.
Portal and hand-
held monitors were observed to be in good condition and within
proper calibration periodicities. Radiological posting and
control of contaminated areas were good.
The licensee continued
decontamination efforts to manage the amount of contaminated floor
area to a minimum.
The inspectors observed good worker practices
regarding radwaste minimization and tool issue from the
contaminated tool locker.
Selected aspects of plant physical security were reviewed during
regular and backshift hours to verify controls were in accordance
with the security plan and implementing procedures.
This review
included security measures, vital and protected area barrier
integrity, maintenance of isolation zones, personnel access
control, searches of personnel, packages and vehicles, and
escorting of visitors.
No discrepancies were noted.
"
(I
'
..
9
6.2
Confined Space Entry Training
Certain portions of the station have been identified as confined
spaces, for which personnel require specialized training prior to
access.
The training and requirements of VPAP-1901, Industrial
Safety and Health, revision 4, were established for personnel
safety. The primary hazards of concern are flammable gas, toxic
fumes, and an oxygen deficient or enriched atmosphere.
The
inspectors attended confined space entry training prior to
inspecting LHSI components in the valve pit level of the Unit 1
and Unit 2 Safeguards Buildings.
The instructor was knowledgeable
and the training material was comprehensive.
RP personnel
demonstrated sound knowledge of confined space entry requirements
and atmosphere test equipment usage when accompanying the
inspectors to the valve pits. The inspectors concluded that the
level of training was appropriate to support personnel safety
during confined space entries.
Within the areas inspected, no violations or devi~tions were identified.
7.
Licensee Event Report Follow-up (92700)
The inspectors reviewed LERs to verify accuracy, description of cause,
previous similar occurrences, and effectiveness of corrective actions.
The inspectors considered the need for further information, possible
generic implications, and whether the events warranted further on-site
follow-up.
The LERs were also reviewed with respect to the requirements
of 10 CFR 50.73 and the guidance provided in NUREG 1022, Licensee Event
Report System, and its associated supplements.
(Closed) LER 50-281/93-03, Unit 2 Automatic Reactor Trip Due to Low
Steam Generator Water Level Coincident with Steam/Feedwater Flow
Mismatch Resulting from Spurious Closure of "A" MFRV.
The LER describes
the August 3, 1993 Unit 2 reactor trip. Safety systems responded as
designed and the event did not pose a threat to public health and
safety.
The trip resulted from a sudden and unanticipated loss of FW
flow to the A SG.
The licensee determined that a 15 vdc MFRV controller
power supply failed, causing the A MFRV to fail closed.
The event,
causal analysis, and corrective actions were previously documented in
NRC Inspection Report Nos. 50-280/93-20 and 50-281/93-20.
The
inspectors reviewed the resultant RCE and confirmed that corrective
recommendations had been implemented.
The LER was accurate and met the
requirements of 10 CFR 50.73.
Within the areas inspected, no violations or deviations were identified.
8.
Exit Interview
The inspection scope and findings were summarized on May 5, 1995, with
those persons indicated in paragraph I. The inspectors described the
. .
10
areas inspected and discussed in detail the inspection results addressed
in the Summary section and those listed below.
Item Number
LER 50-281/93-03
Status
Closed
Description/(Paraqraph No.)
Unit 2 Automatic Reactor Trip
Due to Low Steam Generator
Water Level Coincident with
Steam/Feedwater Flow Mismatch
Resulting from Spurious
Closure of "A" MFRV
(paragraph 7).
Proprietary information is not contained in this report. Dissenting
comments were not received from the licensee.
9.
Index of Acronyms and Initialisms
CFR
CODE OF FEDERAL REGULATIONS
CROM
CONTROL ROD DRIVE MECHANISM
CSE
CONFINED SPACE ENTRY
DR
DEVIATION REPORT
EOG
GL
GENERIC LETTER
LER
LICENSEE EVENT REPORT
LHSI
LOW HEAD SAFETY INJECTION
MAIN FEEDWATER REGULATING VALVE
NI
NUCLEAR INSTRUMENT
NRC
NUCLEAR REGULATORY COMMISSION
QUALITY ASSURANCE
ROOT CAUSE EVALUATION
RADIOLOGICAL PROTECTION
RESISTANT TEMPERATURE DETECTOR
SAFETY INJECTION
TS
TECHNICAL SPECIFICATION
voe
VOLT DIRECT CURRENT
VPAP
VIRGINIA POWER ADMINISTRATIVE PROCEDURE
WORK ORDER
~F
DEGREES FAHRENHEIT