ML18153A485
| ML18153A485 | |
| Person / Time | |
|---|---|
| Site: | Surry  |
| Issue date: | 01/13/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18153A483 | List: |
| References | |
| 50-280-96-12, 50-281-96-12, NUDOCS 9702100455 | |
| Download: ML18153A485 (15) | |
See also: IR 05000280/1996012
Text
Docket Nos:
License Nos:
Report No:
Licensee:
Facility:
Location:
Dates:
Inspectors:
Approved by:
9702100455 970113
ADOCK 05000280
G
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
50-280, 50-281
50-280/96-12, 50-281/96-12
Virginia Electric and Power Company (VEPCO)
Surry Power Station, Units 1 & 2
5850 Hog Island Road
Surry, VA 23883
November 10 - December 14, 1996
R. Musser, Senior Resident Inspector
P. Byron, Resident Inspector
K. Poertner, Resident Inspector
G. Belisle, Chief, Reactor Projects Branch 5
Division of Reactor Projects
ENCLOSURE 2
EXECUTIVE SUMMARY
Surry Power Station. Units 1 & 2
NRC Inspection Report 50-280/96-12, 50-281/96-12
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a 5-week
period of resident inspection.
Operations
One violation was identified involving an inadequate procedure that
resulted in the Alternate Alternating Current (AAC) Diesel Generator not
being available for operation from the control room assuming a station
blackout event.
The inspectors also determined that operations
exhibited a lack of questioning attitude during return to service of the
AAC diesel generator (Section 01.2).
Unit 2 tripped from approximately 11 percent on December 13 during a
unit shutdown.
Primary plant response was normal and plant safety
systems functioned as designed.
However. four Individual Rod Position
Indicators (IRPis) failed to properly display rod position following the
trip. Control room personnel performed well during the trip recovery.
As demonstrated in previous transients, the steam generator water level
control system does not lend itself to stable operations at low power
levels (Section 01.3).
The Unit 1 Auxiliary Feedwater System was properly aligned. Equipment
operability, component labeling, material condition, and housekeeping
were acceptable (Section 02.1).
The Unit 2 Containment Spray System alignment and material condition
were found to be satisfactory. Two Updated Final Safety Analysis Report
(UFSAR) discrepancies were identified and are being resolved by the
licensee's corrective action process (Section 02.2).
Maintenance
Maintenance activities involving feedwater flow control valve positioner
adjustment and service water pump rotating assembly replacement and
surveillance activities involving control rod drop and turbine driven
auxiliary feedwater pump tests were performed in accordance with work
package requirements. The feedwater valve positioner repair evolution
was well staffed and executed, and had excellent management support
(Sections Ml.l, Ml.2, Ml.3, and Ml.4).
Engineering
Temporary modification S2-96-28 was acceptable and the associated safety
evaluation adequately justified _implementation (Section El.1).
Plant Support
Health physics practices were observed to be proper (Section Rl) .
i_ --. ----
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2
The performance of the emergency response organization during the annual
Emergency Preparedness (EP) exercise conducted November 13 was
considered fully satisfactory (Section Pl.l).
A previously identified exercise weakness was sucessfully resolved
(Section PB . 1).
Security and material condition of the protected area perimeter barrier
were acceptable (Section Sl) .
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Report Details
Summary of Plant Status
Unit 1 operated at or near 100 percent power the entire reporting period.
Unit 2 began the reporting period at approximately 100 percent power.
On
November 19, with the unit at reduced power for the quarterly turbine inlet
valve freedom test, the D reheat stop valve would not open after being
exercised to the closed position. As required by the valve freedom test
procedure, Unit 2 power was reduced to less than 50 percent (approximately 49
percent). The valve was repaired, reopened, and the unit returned to 100
percent power on November 20.
On November 25, power was again reduced to 49
percent due to the B reheat intercept valve failing to reopen during a
performance of the turbine valve freedom test procedure. The valve did not
reopen due to a failure of the electrohydraulic control dump valve. The valve
was repaired and the unit was returned to 100 percent power on November 26.
The unit operated at approximately 100 percent power until December 12 when a
unit shutdown commenced for a scheduled maintenance outage to modify the
letdown piping configuration. During the shutdown activities, a reactor trip
occurred on December 13 at 2:33 a.m. (Section 01.3). The unit remained
shutdown the remainder of the reporting period.
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 Technical Specifications
(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 Inoperable AAC Diesel Generator
a. Inspection Scope (71707)
The inspectors reviewed the circumstances surrounding the mispositioning
of the AAC Diesel Generator output breaker control switch.
b. Observations and Findings
On November 13 at 10:30 p.m. operations was tagging out the AAC Diesel
Generator for battery maintenance per procedure O-MOP-AAC-001, Removal
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- -*
2
from Service of the AAC Diesel Generator, Revision 1, when the operator
determined that the AAC Diesel Generator output breaker control switch
was already in the pull-to-lock position. The operators initiated a DR
on the as found condition of the control switch and completed the
procedure to remove the AAC Diesel Generator from service.
Review of procedure O-MOP-AAC-002, Return to Service of the AAC Diesel
Generator, Revision 1, determined that the procedure placed the control
switch in the pull-to-lock position prior to racking in the output
breaker but did not return the switch to the auto position after the
breaker was racked in. The AAC Diesel Generator automatically starts
during a station blackout scenario and the output breaker closes to
power AAC busses. The operators in the control room then manually align
the AAC busses to the emergency busses from the control room.
With the
control switch in the pull-to-lock position the generator output breaker
would not automatically close following a station blackout event.
Failure of the breaker to close would result in an alarm in the control
room and the annunciator response procedure and abnormal procedure would
direct the operator to align the AAC Diesel Generator manually. This
would require that an operator be dispatched to the AAC Diesel Generator
Building.
The licensee determined that procedure O-MOP-AAC-002 had last been
performed on September 24.
The AAC Diesel Generator had been removed
from service to allow scaffolding removal from the exhaust stack. The
procedure had also been performed on September 20 following application
of a coating to the exhaust stack. The AAC Diesel Generator had not
been run in either case because the maintenance performed did not effect
the operation of the AAC Diesel Generator. The procedure had not been
performed prior to September 20.
The licensee initiated a Category 2 root cause evaluation to determine
why the problem had occurred and to provide corrective actions to
prevent recurrence. The licensee had not completed the root cause
evaluation as of the end of the inspection period.
However, several
corrective actions had been implemented. These included revising the
deficient procedure, revising operator logs to require that the control
switch position be verified, and additional training of operations
personnel on AAC Diesel Generator operation.
The AAC Diesel Generator is not addressed in the TS's. The licensee
committed to install the AAC Diesel Generator to meet the requirements
of 10 CFR 50.63.
AAC Diesel Generator installation and testing was
completed for both units in May 1996. Station Administrative Procedure,
VPAP 2802, Notifications and Reports, Revision 6, Section 6.28,
Discretionary Reports, requires that a special report be submitted to
the NRC if the AAC system is out of service for 14 consecutive days.
The licensee submitted a special report as required by VPAP 2802.
The inspectors determined that procedure O-MOP-AAC-002 was inadequate to
return the AAC Diesel Generator to service. This item is identified as
Violation 50-280, 281/96012-01. The licensee had an opportunity to
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3
identify that the AAC Diesel Generator control switch was mispositioned
on September 24 during the second performance of procedure O-MOP-AAC-
001.
The failure to question the as-found switch position resulted in
the system not being available for operation from the control room as
designed for an extended period of time.
c. Conclusions
One violation was identified involving an inadequate procedure that
resulted in the AAC Diesel Generator not being available for operation
from the control room assuming a station blackout event. The inspectors
also determined that operations exhibited a lack of questioning attitude
during return to service of the AAC Diesel Generator.
01.3 Unit 2 Reactor Trip During Shutdown
a.
Inspection Scope (71707)
The inspectors reviewed the circumstances related to the December 13
Unit 2 reactor trip.
b. Observations and Findings
On December 13, 1996, at 2:33 a.m., Unit 2 tripped from approximately 11
percent reactor power (80 MWe).
The unit was being shutdown for a
planned maintenance outage to replace a portion of the letdown line.
Steam generator (S/G) water level was being manually controlled with the
feedwater regulation bypass valves at the time of the trip. During
previous operations at low power levels, the inspectors had observed
that the S/G water level control system does not lend itself to stable
operations. The reactor trip signal resulted from a steam flow/feed
flow mismatch coincident with a low level in the A S/G.
One of the two
channels of the A S/G water level was less than 20 percent narrow range
with one of the two channels of A S/G steam flow greater than feedwater
flow by .709E06 pounds mass per hour.
The motor driven auxiliary
feedwater pumps automatically initiated as designed. Reactor Coolant
System (RCS) temperature decreased to a minimum of approximately 539
degrees F.following the trip.
No primary or secondary power operated*
relief valves or safety valves actuated during the transient.
Four control rod Individual Rod Position Indicators CIRPis) displayed
between 10 and 32 steps (P6-17 steps, D4-34 steps, M4-11 steps, and F6-
17 steps) following the trip and the associated rod bottom light for
control rod P6 did not illuminate. Emergency boration was initiated in
accordance with the Emergency Operating Procedures (EOPs) to compensate
for the indicated rod positions. The unit was stabilized in hot
shutdown with a RCS temperature of approximately .546 degrees F.
The inspectors were in the control room at the time of the trip and
observed the immediate and recovery actions performed by the operators.
The appropriate EOPs were entered and executed. Following the trip,
command and control within the control room was good.
The unit
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4
supervisor ensured his orders were carried out before proceeding to the
next action in the EOPs.
The actions specified in the EOPs were
completed at approximately 3:10 a.m. Accordingly, the shift entered the
. general operating procedure for plant cooldown.
The event was reported
to the NRC operations center at 4:25 a.m. in accordance with 10 CFR
50.72.
A post trip debrief was conducted with the operations shift following
their relief. Other than the problems with the four IRPis and one rod
bottom light discussed above, there were no other significant additional
plant equipment problems.
Hot rod drop testing was conducted following
the trip to confirm the capability of. the four rods discussed above to
fully insert (see Section Ml.3). Plant personnel were planning to
repair the four IRPis and one rod bottom light prior to restart of the
unit.
c. Conclusions
The inspectors concluded that response of the primary plant following
the reactor trip on December 13 was normal.
Plant safety systems
functioned as designed.
However, four IRPis failed to properly display
rod position following the trip. Control room personnel performed well
during the trip recovery.
As demonstrated in previous transients, the
S/G water level control system does not lend itself to stable operations
at low power levels.
02
Operational Status of Facilities and Equipment
02.1 Auxiliary Feedwater (AFW) System Walkdown
a.
Inspection Scope (71707)
During the inspection period the inspectors walked down portions of the
Unit 1 AFW System.
b. Observations and Findings
The inspectors reviewed the AFW system alignment using procedure 1-0P-
FW-OOlA, Auxiliary Feedwater System Alignment, Revision land system
drawing 11448-FM-068A, Feedwater System.
The inspectors also reviewed
equipment operability, component labeling, general material condition,
and housekeeping.
The specific system portions inspected included the
AFW pumps, and the accessible pump suction.and discharge piping.
c. Conclusions
Equipment operability, component labeling, material condition; and
housekeeping were acceptable. The inspectors did not identify any
discrepancies between the required system alignment and the actual
system configuration.
5
02.2 Unit 2 Containment Spray (CS) System Walkdown
a.
Inspection Scope (71707)
A walkdown of the Unit 2 CS System was performed to check the major flow
paths. system material condition, and the system parameters and
- conditions specified in the TS and the Updated Final Safety Analysis
Report (UFSAR).
b. Observations and Findings
The inspectors performed a hand over hand walkdown of a majority of the
accessible portions of the Unit 2 containment spray system. This
included piping, control switches, breakers. and associated
instrumentation for proper alignment and material condition. All system
components were found in their designated position for system standby
readiness. Overall material condition of the equipment was good.
However, during the walkdown, a pressure gauge, 2-CS-PI-203 (Refueling
Water Storage Tank (RWST) Test Recirc Inlet Header Pressure), was found
pegged upscale. This was brought to the attention of the shift
supervisor who initiated action to repair the gauge.
The guage provides
local indication only. A followup walkdown revealed that the condition
had been repaired.
The inspectors reviewed the UFSAR to ensure specified system parameters
demonstrated actual plant conditions. During the review of UFSAR
Paragraph 6.3.l.3, the inspectors noted a statement concerning RWST
level being in conflict with TSs. Specifically TS 3.4.A.3, requires a
minimum RWST level of 387,100 gallons of borated water, while the UFSAR
specified 387,000 gallons. The licensee attributed this matter to a
typographical error during a previous UFSAR revision. The licensee
stated that this minor discrepancy would be resolved during an upcoming
UFSAR revision.
During the review of UFSAR Paragraph 6.3.1.2.1, the inspectors noted a
statement which described conditions within the containment spray piping
following a system actuation. The statement reads as follows; "This
system contains the sodium hydroxide solution only while operating
during an incident, which is a period of approximately 30.min." The
inspectors explored this matter further because the licensee is
currently experiencing leakage of sodium hydroxide solution from the
chemical addition tank into the system through the normally closed tank
outlet valves 2-CS-MOV-202A and 2028. This matter was brought to the
attention of the licensee. A DR (S-96~2739) was initiated. The
licensee currently monitors chemistry in the CS piping downstream of the
chemical addition tank valves. Flushing of the lines occurs if sodium
levels exceed 500 ppm.
6
c. Conclusions
The Unit 2 CS System alignment and material condition were found to be
satisfactory. Two UFSAR discrepancies were identified and are being
resolved by the licensee's corrective action process.
II. Maintenance
Ml
Conduct of Maintenance
Ml.1 Feedwater Flow Control Valve Positioner Adjustment (62707)
On December 3, the inspectors observed activities associated with Work
Order (WO) 00354668, Repair Valve Positioner, which replaced positioner
components for Feedwater (FW) Flow Control Valve (FCV) 1-FW-FCV-1478.
The maintenance was performed to prevent failure of the positioner due*
to increased valve oscillations. The work was accomplished in
accordance with the work package requirements. The operators reduced
reactor power, throttled the A FW isolation valve (1-FW-MOV-154A), and
opened the corresponding bypass valve (1-FW-MOV-155A).
FCV-1478 was
placed on the jack, repaired, stroke tested, and returned to service in
24 minutes. The evolution was well staffed and executed, and had
excellent management support. The inspectors observed that the valve
had a packing leak and steam was visible. The repair did not appear to
reduce valve oscillation .
Ml.2 Service Water Pump Maintenance (62707)
The inspectors observed portions of the work activities associated with
WO 354376, Replace rotating assembly for pump 2-SW-P-lOB.
The
maintenance activity was accomplished in accordance with procedure. O-
MCM-0130-05, Goulds 3996ST Pump Overhaul, Revision 1. The inspectors
verified that the system isolation boundary was adequate to perform the
maintenance activity and that maintenance personnel were implementing
the maintenance procedure.
Ml.3 Unit 2 Control Rod Drop Testing (61726)
The inspectors observed Unit 2 control rod drop testing conducted
December 13. The testing was performed following a Unit 2 reactor trip
discussed in Section 01.3. During the reactor trip four control rods
did not indicate less than 10 steps as required by the emergency
procedures.
The rod testing was performed using procedure 2-NPT-RX-014, Hot Rod
Drops by Bank, Revision 2. The inspectors observed the testing of all
control rod banks and reviewed the control rod drop time data obtained.
All control rod drop times were acceptable and the control rods
exhibited full insertion.
7
Ml.4 Turbine Driven Auxiliary Feedwater (TDAFW) Pump Testing (61726)
On December 11. the inspectors observed the performance of procedure
1-0PT-FW-003, Turbine Driven Auxiliary Feedwater Pump 2-FW-P-2,
Revision 7.
The procedure demonstrates the operability of the TDAFW
pump and associated valves. The inspectors monitored activities in
progress and verified that procedure acceptance criteria were met.
Ml.5 Conclusions on Conduct of Maintenance
Maintenance and surveillance activities observed were performed in
accordance with work package requirements. The feedwater valve
positioner repair evolution was well staffed and executed and had
excellent management support.
III. Engineering
El
Conduct of Engineering
El.1 Temporary Modification Review
a.
Inspection Scope (37551)
The inspectors reviewed temporary modification package S2-96-28,
Thermowell for RTD 2-FW-RTD-2118 Failed.
b. Observations and Findings
The inspectors reviewed the temporary modification package and safety
evaluation associated with temporary modification S2-96-28. * The
temporary modification was implemented to relocate the 8 feedwater line
Resistance Temperature Detector (RTD) to a spare thermowell.
The
temporary modification was required due to the failure of the RTD as the
result of thermowell leakage. The feedwater RTD supplies input to the
plant computer and the calorimetric program.
failed the plant computer calorimetric program was inaccurate and
operations was required to perform manual calorimetric calculations.
c. Conclusions
The inspectors determined that temporary modification S2-96-28 was
acceptable and that the associated safety evaluation adequately
justified implementation.
E7
Quality Assurance in Engineering Activities
E7.1 Review of UFSAR Commitments (37551)
A recent discovery of a licensee operating their facility in a manner
contrary to the UFSAR description highlighted the need for a special
focused review that compared plant practices, procedures and/or
parameters to the UFSAR description. While performing the inspections
8
discussed in this report, the. inspectors reviewed the applicable
portions of the UFSAR that related to the areas inspected.
Two UFSAR
discrepancies associated with the CS System were identified and are
discussed in Section 02.2.
IV. Plant Support
Rl
Radiological Protection and Chemistry Controls (71750)
On numerous 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 determined
that RP practices were proper.
Pl
Conduct of EP Activities
Pl.1 Annual EP Drill
a.
Inspection Scope (82301)
On November 13, the inspectors observed the performance of the
licensee's annual EP drill.
b. Observations and Findings
The purpose of the exercise conducted November 13 was to activate and
evaluate major portions of the Surry emergency response plan. The
inspectors reviewed the drill scenario and observed activities conducted
at the simulator, Technical Support Center and Operations Support
Center. Activities observed were consistent with the drill scenario and
demonstrated proper accident mitigation and damage control
considerations.
c. Conclusions
The performance of the emergency response organization was considered
fully satisfactory.
PB
Miscellaneous EP Issues (92904)
P8.l(Closed) Exercise Weakness CEW) 50-280, 281/95010-01:
damage control
teams were not timely managed. The inspectors observed an emergency
drill conducted November 13. The inspectors observed activities
conducted at the Operations Support Center throughout the drill
scenario. The drill demonstrated the ability to prioritize tasks and
identify accident mitigation activities. Damage control teams were
dispatched in a *timely manner t~ accomplish designated tasks .
9
Sl
Conduct of Security and Safequards Activities (71750)
On numerous 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 .
10
V. Management Meetings
Xl
Exit Meeting SuDIDary
The inspectors presented the inspection results to members of licensee *
management at the conclusion of the inspection on December 20, 1996.
The
licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary.
No proprietary information was
identified.
X2
SALP Presentation Meeting
On November 18, the Regional Administrator presented the results of the latest
SALP assessment.
The Regional Administrator also met with local officials and
conducted a press conference .
11
PARTIAL LIST OF PERSONS CONTACTED
Licensee
R. Blount, Superintendent, Maintenance
D. Christian, Station Manager
M. Crist, Superintendent, Operations
J. McCarthy, Assistant Station Manager, Operations & Maintenance
B. Shriver, Assistant Station Manager, Nuclear Safety & Licensing
T. Sowers, Superintendent, Engineering
B. Stanley, Director, Nuclear Oversight
J. Swientoniewski, Supervisor Station Nuclear Safety
W. Thorton, Superintendent, Radiological Protection
G. Belisle, Chief, Branch 5, Division of Reactor Projects, Region II
S. Ebneter, Regional Administrator, Region II
G. Edison, Surry Project Manager, Office of Nuclear Reactor Regulation
J. Johnson. Deputy Director, Division of Reactor Projects, Region II
M. Reinhart, Acting Director, Project Directorate II-1, Office of Nuclear
Reactor Regulation
.,.. ,J.,
IP 37551:
IP 40500:
IP 61726:
IP 62707:
IP 71707:
IP 71750:
IP 82301:
IP 92904:
Opened
12
INSPECTION PROCEDURES USED
Onsite Engineering
Effectiveness of Licensee Controls in Identifying, Resolving, and
Preventing Problems
Surveillance Observation
Maintenance Observation
Plant Operations
Plant Support Activities
Evaluation of Emergency Exercises for Power Reactors
Followup - Plant Support
ITEMS OPENED AND CLOSED
50-280, 281/96012-01
inadequate AAC Diesel Generator return to
service procedure (Section 01.2).
Closed
50-280, 281/95010-01
EW
damage control teams were not timely managed
(Section P8.1) .