ML15118A096
| ML15118A096 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 04/04/1996 |
| From: | Crlenjak R, Harmon P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A094 | List: |
| References | |
| 50-269-96-03, 50-269-96-3, 50-270-96-03, 50-270-96-3, 50-287-96-03, 50-287-96-3, NUDOCS 9604240158 | |
| Download: ML15118A096 (33) | |
See also: IR 05000269/1996003
Text
VRE 1UNITED
STATES
0
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.: 50-269/96-03, 50-270/96-03 and 50-287/96-03
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242-0001
Docket Nos.:
50-269, 50-270 and 50-287
License Nos.: DPR-38, DPR-47 and DPR-55
Facility Name: Oconee Units 1, 2, and 3
Inspection Conducted: January 28 - March 9, 1996
Inspectors:
- < /'/
P.E Hron,Tenior Residen 0speoor
Date Sign d
P. G. Humphrey, Resident Inspector
L. A. Keller, Resident Inspector
N. L. Salgado, Resident Inspector
P. J. Fillion, Reactor Inspector (paragraphs 3.3 and 3.4)
G. A. Walton, Reactor Inspector (paragraphs 3.3 and 3.4)
R. L. M e, Reactor Inspector (paragraphs 4.4, 4.7 and 6.0)
L. K g Re ctor Inspector (paragraphs 4.4, 4.7 and 6.0)
Approved by:
/
R .Cre4k
ranch
ief
Dite Signed
Division of Reactor Projects
SUMMARY
Scope:
Inspections were conducted by the resident and regional inspectors in the
areas of plant operations; maintenance and surveillance testing, which
included a review of the Keowee Hydro Maintenance Program; engineering, which
included an inspection of the spent fuel and associated equipment; and plant
support.
Results:
Plant Operations
Unit 1 tripped from full power on February 28, 1996, due to a failed circuit
card in the Integrated Control System. The unit was restarted and achieved
full power on March 1, 1996. Management made a conservative decision to have
the operators responsible for the restart perform a startup on the simulator
ENCLOSURE
9604240158 960404
ADOCK 05000269
(1
2
prior to restarting the unit. The restart of the unit was accomplished
without incident (paragraph 2.2).
The periodic rotation of control room personnel to prevent complacency towards
malfunctioning alarms was considered a good practice (paragraph 3.1.2).
Maintenance
Activities reviewed within the maintenance area were performed to acceptable
standards. During a Keowee Hydro Station modification test, the licensee's
actions to exit the test when problems were encountered and enter a
contingency to back out of the modification was considered to be conservative
(paragraph 3.1.3).
A review of the Keowee Maintenance Program indicated it met regulatory
requirements, being enhanced by the Keowee Upgrade Project (paragraph 3.3).
Engineering
Addressed as Unresolved Item (URI) 96-03-01, errors were identified by the
licensee in calculation OSC-2280 involving low pressure service water net
positive suction head absolute and minimum required lake level (paragraph
4.1).
Apparent Violation 96-03-02 was identified that involved an
inoperability issue associated with the Containment Hydrogen Control Systems
that had existed since the system was originally installed (paragraph 4.2).
Plant practices, procedures, calculations, and parameters associated with the
Spent Fuel Pool (SFP) were determined to be consistent with the licensee's
engineering analysis. However, URI 96/03-03 was identified that addressed the
adequacy of the information provided by Duke to the NRC when designing the
interface taps for the supply lines from the SFP to the Standby Shutdown
Facility (paragraph 4.4.2).
The licensee continues to have difficulties in the area of NRC reporting
requirements (paragraph 4.6).
Plant Support
Two spills/leaks of low activity liquid waste resulted from the use of a wrong
size hose clamp on a transfer line and an incorrectly installed gasket in the
manway on the 'D' demineralizer (paragraph 5.1).
ENCLOSURE
REPORT DETAILS
Acronyms used in this report are defined in paragraph 8.
1.0
PERSONS CONTACTED
Licensee Employees
- M. Bailey, Regulatory Compliance
- E. Burchfield, Regulatory Compliance Manager
S. Burton, Keowee, Operations
T. Coutu, Operations Support Manager
D. Coyle, Systems Engineering Manager
J. Davis, Engineering Manager
- W. Foster, Safety Assurance Manager
- J. Hampton, Vice President, Oconee Site
D. Hubbard, Maintenance Superintendent
T. Ledford, Supervisor, Electrical Systems
C. Little, Electrical Systems/Equipment Manager
- B. Milisaps, Manager, Mechanical/Civil Equipment
- B. Peele, Station Manager
R. Severance, Mechanical Systems Engineer
J. Smith, Regulatory Compliance
J. Stevens, Electrical Systems Engineer
R. Sweigart, Work Control Superintendent
S. Townsend, Keowee, Operations
L. Underwood, Electrical Systems Engineer
J. Weir, Maintenance Engineer
- Attended Exit Interview
Other licensee employees contacted during this inspection included
engineers and technicians.
2.0
PLANT OPERATIONS (71707)
The inspectors reviewed plant operations throughout the reporting period
to verify conformance with regulatory requirements, Technical
Specifications (TS), and administrative controls.
Control room logs,
shift turnover records, temporary modification log, and equipment
removal and restoration records were reviewed routinely. Discussions
were conducted with plant operations, maintenance, chemistry, health
physics, instrument & electrical (I&E), and engineering personnel.
Activities within the control rooms were monitored on an almost daily
basis.
Inspections were conducted on day and night shifts, during
weekdays and on weekends. Inspectors attended some shift changes to
evaluate shift turnover performance.
Actions observed were conducted as
required by the licensee's Administrative Procedures. The complement of
licensed personnel on each shift inspected met or exceeded the
ENCLOSURE
2
requirements of TS. Operators were responsive to plant annunciator
alarms and were cognizant of plant conditions.
Plant tours were taken throughout the reporting period on a routine
basis. During the plant tours, ongoing activities, housekeeping,
security, equipment status, and radiation control practices were
observed.
2.1
Plant Status
Unit 1 operated at or near full power until February 28, 1996, when the
unit tripped because of problems that developed from a failed circuit in
the Integrated Control System (ICS).
The unit was restarted on March 1,
1996, and achieved full power at 3:20 a.m., on March 2, 1996.
Unit 2 operated at or near full power throughout the reporting period.
Unit 3 operated at or near full power throughout the reporting period.
2.2
Unit 1 Trip
Unit 1 tripped from full power on February 28, 1996, at 9:03 p.m. The
trip was evaluated and determined to have been initiated by a faulty
feedwater temperature compensator circuit in the ICS. This circuit
failure caused a disturbance in the feedwater system. During the
resultant transient, the condensate cooler bypass valve (1C-61) closed
as designed to control the booster pump suction pressure, but did not
re-open when required. This caused the condensate booster pumps to lose
suction and trip on low suction pressure. The loss of the booster pumps
in turn caused the main feed pumps to trip on low suction pressure,
which provided the signal that initiated the reactor trip.
Main Steam Valve 1MS-77 (Second Stage Reheater Supply Valve) failed to
close as required in response to the trip. This valve failure was
detected by the OATC and upstream steam header supply valves 1MS-76 and
79 were closed to isolate the main steamline and prevent a pressure
blowdown. Steam and feedwater systems were "walked down" by civil
engineering to ensure there was no damage to the equipment, piping, or
hangers.
Shutdown margins were maintained during the trip and operator actions
were determined to be have been adequate.
Operators that were scheduled to restart the unit performed a startup on
the simulator. This had not been a practice at ONS and was implemented
by the plant manager as a result of NSRB recommendations. The operators
felt this near-term training was very beneficial, and plan to continue
the practice in the future.
ENCLOSURE
1
3
The inspectors responded on-site to the trip and monitored the recovery
operations. In addition, the inspectors attended PORC meetings,
reviewed the trip report, and monitored the restart activities.
Within the areas reviewed, the units were operated in accordance with
procedures. An enhancement was noted prior the restart of Unit 1 by
first having the operators responsible for the restart to perform a
plant startup on the simulator.
3.0
MAINTENANCE (62703, 61726, 62700, 40500 and 92902)
3.1
Maintenance Activities
Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
personnel and that approved procedures adequately described work that
was not within the skill of the craft. Activities, procedures and work
orders were examined to verify that proper authorization and clearance
to begin work was given, cleanliness was maintained, exposure was
controlled, equipment was properly returned to service, and limiting
conditions for operation were met. Maintenance activities observed or
reviewed in whole or in part are addressed in the sub-paragraphs of 3.1
below:
3.1.1 NSM-22922 Install Y-Strainer Upstream Of 2MS-93, W095023925
On February 8, 1996, the inspector observed the installation of a
differential pressure gauge to monitor the pressure drop across a
Y-strainer that was scheduled to be installed in the main steam
line to the Unit 2 Turbine Driven Emergency Feedwater Pump during
the refueling outage scheduled to begin on March 28, 1996. The
pressure gauge and associated instrument tubing was installed to
QA safety class standards and was in accordance with applicable
procedure IP/0/A/3010/003A, Procedure for Mounting Field Run
Instrument Tubing And Cable Support Systems.
All work was performed to acceptable standards and with proper
documentation.
3.1.2 Spurious Alarms, WO 96013595-01
On February 14, 1996, multiple statalarms on panels 1SA
5,6,8,9,14,and 15 were received in the Unit 1 CR. The statalarms
were annunciating approximately every two minutes. The licensee
initiated PIP 1-096-0290 to address this recurring problem. The
inspector observed portions of the licensee's troubleshooting of
this problem. After extensive troubleshooting, the licensee
determined that the -problem was a short in the 1A FWPT oil cooler
outlet temperature gauge 1TH-141A from the alarm circuit to the
ENCLOSURE
0
4
center of the gauge needle. The licensee repaired the
malfunctioning gauge by removing the needle and reaming the
mounting hole to a larger size so that the indicator needle would
seat further on the shaft to allow for an air gap to prevent arcs.
The licensee successfully calibrated the gauge using
IP/O/B/0270/005B-1, FWPT Instrumentation Rearing Temperature and
Oil System, and returned it to service. The Shift Operations
Supervisor rotated control room personnel periodically during the
time the malfunction was occurring to prevent complacency toward
the alarms. The inspector considered this rotation to be a good
practice and concluded that the licensee's actions were
appropriate in addressing this issue.
This was the same problem identified on February 3, 1996, as
documented in PIP 1-096-0213, which was thought to be corrected by
WO 96010253. The WO 96010253 addressed a loose intermittent
connection.
3.1.3 Installation Of Keowee Unit 1 Overspeed/Overfrequency Logic,
TN/5/A/2966/BL1/08
The licensee was proceeding with TN/5/A/2966/BL1/08, Installation
of Keowee Unit 1 Overspeed/Overfrequency Logic. The purpose of
the procedure was to install overspeed/overfrequency logic in
various circuits for Keowee Unit 1. It was also to remove the
underground breaker permissive from the 94 GB circuit. On
February 23, 1996, during the post modification testing of
TN/5/A/2966/BL1/08 which involved initiating an ES signal
coincident with a governor failure signal, ACB-1 cycled
approximately twelve times. The testing was being performed
during a 72-hour LCO due to both Keowee units being out of
service. Troubleshooting procedure MP/0/A/2000/13 was initiated
to determine the problem with the breaker. The licensee tested
the anti-pump circuitry of ACB-1 and found it to be operable. The
inspector attended a PORC meeting which was convened on February
23, 1996, at 7:30 p.m. to evaluate the problem and it's effect on
the modification. The PORC recommended that the modification team
execute the preplanned contingency and back out of the
modification. The contingency plan was performed, both paths were
declared operable, and the LCO was exited. The licensee
determined that the problem with ACB-1 cycling was due to a
transformer undervoltage relay dropping out the anti-pump
circuitry. During the test of the governor failure logic, the
breakers partially closed and induced some voltage on the step-up
side of the breaker. This voltage caused the close permissive to
be removed and allowed the breaker to close. Upon closure of the
breaker, the breaker tripped due to the governor failure logic.
While developing the modification the licensee had evaluated the
possibility of ACB-1 cycling during the test. A Caution statement
documented in TN/5/A/2966/BL1/08 prior to Step 4.14.50, states
ENCLOSURE
5
"Should ACB-1 cycle continuously, Keowee Operations should HOLD
GENERATOR ACB NO. 1 control switch in the CLOSE position until
cycling stops."
However, this note did not address that the
Master Select switch needed to be in the manual position for the
cycling to terminate. The licensee had to remove control power
from ACB-1 to terminate the cycling. The licensee performed
normal maintenance checks on ACB-1 to ensure that the repeated
cycling had not adversely affected its operability. The inspector
concluded that the licensee's actions to execute the
TN/5/A/2966/BL1/08 contingency to back out of the modification was
conservative.
3.2
Surveillance Activities
The inspectors observed surveillance activities to ensure they were
conducted with approved procedures and in accordance with site
directives. The inspectors reviewed surveillance performance, as well
as system alignments and restorations. The inspectors assessed the
licensee's disposition of any discrepancies which were identified during
the surveillance. Surveillance activities observed or reviewed in whole
or in part are addressed in the sub-paragraph of 3.2 below:
3.2.1 Unit 2 RPS Channel B Calibration And Functional Test, WO 96012180
The inspector observed activities in progress during the
calibration of the Unit 2 RPS Channel B. The effort was performed
in accordance with applicable procedures, IP/0-2/A/0305/003,
Nuclear Instrument and Reactor Protective System and IP/0
2/A/0305/003B, Instrument Procedure Data Package for RPS Channel
B, and IP/0-O/A/0305/015, Nuclear Instrumentation RPS Removal and
Return to Service.
Documentation was current and work observed was performed to
acceptable standards.
3.2.2 Unit 2 RPS A,B,C,D CRD Breaker Test, WO 96005963
The inspector observed performance of procedure, IP/O/A/0305/14,
RPS Control Rod Drive Breaker Trip and Timing Test on February 1,
1996. The effort included performance of operations procedure
OP/0/A/0330/009, Power Supply Check of Control Rod Drive, and
IP/0/A/0305/15, Nuclear Instrumentation RPS Removal and Return to
Service.
The equipment was found to be within acceptable tolerances and the
activity was performed in accordance with the procedures.
ENCLOSURE
6
3.2.3 Unit 3 Control Rod Movement, PT/3/A/0600/15
On February 15, 1996, the inspector observed the performance of
PT/3/A/0600/15 which tests control rod drive operation under
actual operating conditions. The procedure met the monthly
surveillance requirements as specified in TS 4.1.2.
The operators performed the control rod movements according to the
procedure, and were cognizant of plant operating status during the
test. During the portion of the test which involved Group 5 rods,
the absolute position indication for rod one of that group dropped
to approximately 40 percent. The operator initiated WO 96007256
to address this discrepancy. The problem was determined to be a
position indicator card, which was replaced. The procedure
acceptance criteria was met. The inspector concluded that the
operations staff actions were appropriate during the performance
of this procedure.
3.2.4 Keowee Hydro Operation, PT/0/A/620/09
On February 21, 1996, the inspector observed the performance of
PT/0/A/620/09 from the Oconee CR. The test satisfied the monthly
requirement of TS 4.6.1. While performing the test, Keowee Unit 1
was aligned to the underground feeder and Keowee Unit 2 was
aligned to the overhead feeder. Keowee Unit 1 was started and
voltage was required by Step 12.16 documented and verified to be
within the allowable band of 13.8 - 14.49 KV. The voltage was
13.6 KV as indicated in the Oconee CR and 13.5 KV as read in the
Keowee CR. As required by the test, System Engineering was
notified to discuss the operability of the Keowee Unit 1.
Concurrently, the licensee generated PIP 0-096-0364. The licensee
determined that 13.5 KV was an adequate voltage and
PT/0/A/0620/009 does not account for expected synchronizer
response when the grid voltage decreases to a point that 13.8 KV
system bus voltage was below generator output voltage. The
computer point for bus voltage was reading approximately 13.6 KV.
In this condition, the generator bus voltage would be expected to
increase to 13.8 KV and then decrease as the synchronizer matched
generator and bus voltage. The licensee determined that this was
consistent with observed unit response during the performance of
the PT. The screening remarks of PIP 0-096-0364 indicated that
the PT should be written to verify operability with the
synchronizer in manual, which will make the unit respond
consistent with an emergency start where the synchronizer is
defeated by emergency start relay contacts. The licensee
continued with the remaining portions of the test and no other
problems were encountered. The inspector concluded that the
operators had adhered to the procedure, and that all the
acceptance criteria was met except for acceptance criteria 11.5,
"Each Keowee Unit OUTPUT VOLTAGE is within the allowable band.
ENCLOSURE
7
The allowable voltage band is 13.8 to 14.49 KV," for which the
licensee performed a required operability evaluation.
3.2.5 Reactor Protective System Channel "D" RC Temperature Instrument
Calibration, IP/O/A/0305/001H
On February 27, 1996, the inspector observed portions of
IP/O/A/0305/OO1H, Reactor Protective System Channel "D" RC
Temperature Instrument Calibration. The calibration satisfied TS section 3.5.1.1 Table 3.5.1-1 #5 and #6, and section 4.1.1 Table
4.1.1 #7 and #11.
The inspector verified that proper test
equipment was used, and that the licensee was adhering to the
respective procedure. The inspector concluded that all activities
observed were satisfactory.
Within the areas reviewed, no violations or deviations were identified.
3.3
Maintenance Program for Keowee
As addressed in the sub-paragraphs of 3.3 below, Regional based
inspectors reviewed and evaluated an issue identified during the
Electrical Distribution System Functional Inspection (EDSFI), NRC
Inspection Report 50-269,270,287/93-02. EDSFI Finding 6.b stated that
testing had not been performed on safety-related mechanical components
(i.e., coolers and pumps).
As a result of this finding, the licensee
has significantly upgraded the test program for mechanical components at
Keowee. In addition, at a meeting between licensee and NRC management,
the licensee committed to significantly upgrade the maintenance
procedures related to equipment at Keowee. NRC followup of this issue
was tracked under Inspector Followup Item 50-269,270, 287/95-26-02,
Review Test Program for Mechanical Components at Keowee to Resolve EDSFI
Finding 6.b.
The criteria applied by the inspectors in reviewing this issue was that
periodic testing demonstrated that the design basis requirements of the
equipment being tested was maintained, and the maintenance activities
met the requirements of 10 CFR 50, Appendix B, and FSAR Section
13.5.2.2.1, Maintenance Procedures. The licensee was in the process of
enhancing their Inservice Test program with regard to Keowee, and they
planned to submit the revised program to NRC. Since the enhanced
program had not been submitted to NRC, the enhanced Inservice Test
program was not within the scope of the inspection.
3.3.1 Site Walkdowns
The inspectors toured the Keowee facility in order to evaluate the
workmanship, cleanliness and overall operation controls being
implemented in order to maintain the facility in an emergency
operational ready condition. The facility was noted to be well
maintained, the personnel were knowledgeable of the equipment, and
ENCLOSURE
1
8
the equipment appeared to be maintained in an acceptable quality
condition. The inspector observed one generator operating and
noted oil and water leakage was maintained at a minimum level.
On February 15, 1996, at about 10:00 p.m., while craftsmen were
functional testing an electrical modification at the Keowee
station (NSM-5-2966-BL1), a short-circuit occurred in a 125 VDC
circuit. As a result of the short-circuit, arcing occurred when a
terminal block link in a termination cabinet was being closed.
Since the affected equipment was already out of service for
testing, operational consequences were minimal.
The NRC
inspectors examined the damaged terminal block and reviewed the
plan for repairing the damage and assessing the extent of damage.
The inspector agreed that the planned repairs would restore the
terminal block and wiring to good condition. This event is
described in further detail in paragraph 4.3 of this report.
3.3.2 Duke Power Self-Initiated Technical Audit (SITA) SA-95-39
A licensee audit was conducted November 13 through December 12,
1995, of the Keowee operational controls, maintenance,
surveillance and other testing, and personnel training to ensure
Keowee is operated and maintained to perform its safety-related
function. The audit identified 13 findings. However, the audit
noted that none of the findings impact the operability or
reliability of the emergency power system. All findings were
identified on PIPs to ensure comprehensive corrective actions
would be implemented.
From the list of PIPs, the inspector selected PIP 4-0-95-1720 for
review. The PIP was open at the time of this inspection and
identified that "Several Keowee maintenance and testing procedures
were reviewed and found to contain considerably less detail than
approved Oconee maintenance and testing procedures." An example
given in the audit finding was that procedure MP/1/A/2200/017,
Unit 1 Turbine, Governor, and Generator Weekly Preventative
Maintenance, does not contain instructions for the proper amount
of torque to be applied to strainer bolting. For corrective
actions, the licensee determined the deficiency identified was not
significant, but planned to enhance the procedure by incorporating
this procedure into a site procedure entitled PT/1/A/2200/001 KHU
1 Weekly Surveillance. Although this procedure had not been final
approved at the time of this inspection, the inspector reviewed it
to determine if the corrective actions addressed the audit finding
concern. The inspector noted that PT/1/A/2200/001 contained
significantly more details for the inspection of the strainer,
including the installation of the bolting material.
The licensee's overall plan to enhance the Keowee procedures and
make them comparable to the Oconee maintenance procedures
ENCLOSURE
9
consisted of: (1) delete several Keowee specific procedures that
had duplicate Oconee procedures or (2) change the procedure(s) to
PTs, as discussed above. The new or revised procedures will
incorporate changes that enhance and address the SITA findings.
3.3.3 Review of Keowee Maintenance Procedures
The inspectors reviewed eight maintenance procedures to ascertain
compliance with FSAR and 10 CFR requirements. The procedures
reviewed are listed below. Those listed with an asterisk were
also reviewed by the SITA team inspection.
-
- MP/1/A/2200/008, Unit 1 Hydraulic Turbine Inspection
-
- MP/1/A/2200/017, Unit 1 Turbine, Governor, and Generator
Weekly Preventive Maintenance
-
- MP/1/A/2200/001, Governor Number 1 Oil Pump Assemblies
Inspection and Maintenance
-
MP/2/2000/018, Unit 2 Turbine and Governor Monthly
Preventive Maintenance
-
TT/O/A/0620/012, Keowee Unit 2 Governor Oil System Test
-
OP/O/A/2000/027, Unit 1 Governor Actuator Pumping Units
-
MP/2/A/2200/001, Unit 2 Turbine, Governor, and Generator
Weekly Preventive Maintenance
-
MP/A/3019/004, Hangers, Pipe - Removal, Installation, or
Modification
-
MP/0/A/2005/001, Keowee Hydro Generator Inspection and
Maintenance
The inspector also reviewed vendor manual KM-200-0158-001, Allis
Chalmers Instruction Book and compared the vendor requirements
against the procedure requirements. The inspector found the
procedures reviewed contained sufficient guidance to permit the
maintenance/tests to be performed correctly. No significant
errors were noted.
3.3.4 Review of Maintenance and Preventive Maintenance Data
The inspectors reviewed the completed maintenance and preventive
maintenance (PM) data for ten activities performed within the last
year at Keowee. The components selected for the PM reviews were
safety related and included the Governor Oil System and Turbine
ENCLOSURE
10
Guide Bearing Oil System. The maintenance activity was for the
installation of a pipe support. The activities reviewed were:
-
Units 1 & 2, monthly test performed January 31, 1996, on the
Turbine Guide Bearing Oil System.
-
Units 1 & 2, annual test performed January 24, 1996, on Unit
1 and January 11, 1996, on Unit 2. This PM was implemented
on the Governor Oil System.
-
Unit 1, test performed February 22, 1995, for removal from
service and restoration to service of the Keowee Governor
Actuator Pumping System.
-
Unit 1, annual tests performed February 22 and October 23,
1995, for inspection and maintenance of governor number 1
oil pump assembly.
-,
Unit 2, annual tests performed February 14 and October 12,
1995, for the governor actuator oil pump.
-
Unit 2, installation of U-bolt was performed on April 25,
1995, using WO 95030111.
The inspector's evaluation found the maintenance activities were
implemented in accordance with the applicable procedure
requirements.
3.3.5 Quality Assurance Program for Repair of Copper Materials
Item 55 in the Keowee Upgrade Project consisted of creating a
safety-related procedure for the repair of copper instrumentation
lines at the Keowee Hydro Station. The licensee implemented a
soldering procedure for connecting or repairing copper lines.
This procedure (MP/0/A/1810/020, Soldering - Copper/Copper Alloys
- Tubing, Fitting, Valves) was issued November 4, 1995, and
provided instructions for repair and installation of soldered
socket type joints using the manual torch heating process.
The inspector reviewed this procedure and determined it describes
an adequate process for control of material and provides
acceptable instructions to achieve an adequate soldered joint on
copper materials. The inspector had no questions on the adequacy
of this procedure.
3.3.6 Heat Exchanger Testing Program
The inspector reviewed the licensee's heat exchanger testing
program for the Keowee Hydro Station. The licensee's original
response to Generic Letter 89-13 did not include the Keowee Hydro
ENCLOSURE
11
Station. To address the Keowee station, a procedure to obtain
trending data was generated and requires collecting data on a
monthly basis through continuous monitoring utilizing a data
acquisition program, regardless of Keowee unit operation. The
procedure (TT/O/A/0620/022, Keowee Heat Exchanger Performance Data
Test) was in the development stage and had not been reviewed or
approved by licensee management. However, the licensee performed
an evaluation to determine the adequacy of the cooling water
systems and documented that normal operating conditions bound
worst case design basis accident conditions. The configurations
of the systems were the same during normal and accident conditions
and flow indications were available and were procedurally
monitored on a periodic basis during unit operation.
3.3.7 Replacement of 13.8 kV Circuit Breakers
Keowee Upgrade Project, Item 21, involved the need for replacement
or refurbishment of the 13.8 kV, indoor, air-operated, generator
output breakers. The inspector interviewed the cognizant engineer
concerning the status of this item. He stated that the decision
was made to replace these circuit breakers with new breakers of
the same design. The reason for replacement was the age of the
breakers and number of operations as compared to the "Schedule of
Operating Endurance Capability for Circuit Breakers" in ANSI
C37.06-1987. Homewood Company, a subsidiary of Westinghouse
Electric Corporation, has the capability to manufacture the
breakers. The licensee's plan was to have Westinghouse, or
others, prepare the dedication/qualification package. The
schedule was to issue a request for bids by March 1, 1996. There
was a 40-week lead time for this equipment. The inspector agreed
that the replacement project should resolve the breaker wear out
issue for the long-term.
The above review of the maintenance/test program for the Keowee Hydro
Units indicated that the program met the regulatory requirements. The
licensee has met commitments to enhance the program as described in the
Keowee Upgrade Project.
In addition, the inspectors concluded that the SITA on the Keowee
maintenance program was comprehensive. The program was found to meet
the regulatory requirements and some good enhancements were identified.
The inspectors' review of the program had essentially the same finding
as the SITA. The licensee was committed to submitting to the NRC a
revised Inservice Test program, significantly enhanced with regard to
the Keowee Hydro Units. Therefore, Inspector Follow-up Item
269,270,287/95-26-02 is considered closed.
ENCLOSURE
- I12
3.4
Maintenance Followup Items
3.4.1 (Closed) Inspector Follow-up Item, 95-26-03, Purpose and
Limitations of the List of SSCs in the Quality Standards Manual
During a previous inspection an inspector identified the fact that
four safety-related valves were not listed in the Quality
Standards Manual. The licensee initiated PIP 0-095-1687 in
response to this finding inorder to resolve the confusion among
the affected organizational groups concerning the purpose and
limitations of the list of structures, systems and components
provided in Appendix B of the Quality Standards Manual.
During this inspection, through interviews with engineering
personnel, the inspector determined that the list of SSCs in
Appendix B of the Quality Standards Manual was not intended to be
a complete list. The fact that a particular type of item appears
on the list does not imply that the list was intended to be
complete for safety-related items of the same type. Users of the
Quality Standards Manual determine safety classifications by use
of flow chart type instructions (referred to as a "road map").
The list provided supplementary information to the flow chart. To
address concerns that may arise from users of the manual
incorrectly assuming that the list of safety-related SSCs was
complete, the licensee issued a memorandum to all managers
clarifying the purpose and limitations of the list. The inspector
interviewed two managers who confirmed that the memorandum
accurately describes how the Quality Standards manual should be
used. In response to questions by the inspector, the corrective
actions in the PIP were modified to require an instructive
memorandum be issued to all users of the Quality Standards Manual
cautioning that the list of safety-related SSCs is not complete.
The licensee was working toward generating a comprehensive
Equipment Data Base, which will indicate the quality assurance
classification of all equipment having a unique identification
number. When the Equipment Data Base is approved for use, it will
become the preferred tool for determining quality assurance
classifications of equipment, and will effectively supersede the
list in the Quality Standards Manual.
The inspector reviewed the status of the licensee's Equipment Data
Base in order to determine the projected completion of this
project. Currently, the licensee has a two-year funded project to
make the Equipment Data Base match the Quality Standards Manual.
Once this is achieved, the list in the QSM will be removed. The
effort includes field inspection of equipment and a determination
regarding whether the equipment is safety-related. The Keowee
equipment was the first equipment scheduled to be entered into the
new data base. The data base will require validation with three
ENCLOSURE
(113
levels of signatures. Most of the Keowee equipment was entered on
the data base at the time of this inspection. However, it had not
received the required validation. The target for completing the
Keowee Station was in approximately one year. The inspector had
no further questions on this activity. Based on the above facts,
Inspector Followup Item 269,270,287/95-26-03 is closed.
3.4.2 (Closed) Inspector Followup Item 269,270,287/95-26-02, Replacement
of 13.8 kv Circuit Breakers
Closure of this item is addressed in paragraph 3.3.
3.4.3 (Closed) NRC Information Notice 92-51
The inspectors reviewed the licensee's actions to address the
concerns expressed in NRC Information Notice 92-51, Supplement 1,
Misapplication and Inadequate Testing of Molded-Case Circuit
Breakers. This notice was concerned with the setpoint for the
instantaneous trip element in molded-case circuit breakers. It
alerted addressees to the possible need for checking that breakers
would not trip as a result of motor starting transient current.
These checks may involve engineering evaluation and field testing.
In general, the licensee utilized thermal magnetic circuit
breakers in combination starters for motor circuits. In a limited
number of cases magnetic-only breakers were utilized. The
inspector reviewed the licensee's Engineering Criteria Manual,
Section RE-3.03, with regard to the setting of MCC breakers and
found that the criteria were adequate. To ensure that replacement
breakers actually performed close to published time/current
characteristics, the licensee performed time-delay (thermal) and
instantaneous (magnetic) overcurrent trip test on breakers upon
receipt at the warehouse. The test procedure was specified in
CGPA-3000.00-00-0013, General Electric Molded-Case Circuit
Breakers, Procurement and Acceptance Requirements. The inspector
observed that the test ensured breakers would be within the
specified range (i.e., upper and lower limit). In addition,
periodic testing not exceeding five years was being performed to
demonstrate continued correct performance. The periodic testing
was specified in:
-
Nuclear Station Directive: 401, Maintenance and Testing of
Class 1E AC and DC Molded-Case Circuit Breakers
-
Procedure IP/0/A/3011/013, Molded-Case Circuit Breaker Test
and Inspection
The inspector reviewed the breaker sizing and setting for 150/75
hp reactor building cooling fan motor and a 15 hp valve motor (PR
1) at the Keowee plant. The breaker for the fan motor was thermal
ENCLOSURE
(
14
magnetic type with adjustable magnetic setting, and the breaker
for the valve was fixed thermal magnetic type. The inspector
concluded that the settings would allow the motor to fulfill its
safety function considering minimum voltage running and maximum
voltage starting transient. The inspector concluded that the
concerns expressed in the information notice had been addressed by
the licensee.
3.4.4 (Closed) Apparent Violation (EEI) 269,270,287/96-02-01, Inadequate
Control Over Fuel Assembly Movement
On March 5, 1996, this Apparent Violation was cited under
Enforcement Action (EA)96-019 as a Severity Level III Violation
with proposed imposition of a $50,000 Civil Penalty. Accordingly,
EEI 269,270,287/96-02-01 is administratively closed and Violation
EA 96-019-01013, Inadequate Procedural Control Over Movement of
Fuel Assemblies in the Spent Fuel Pool, is being opened.
4.0
ENGINEERING (37550, 37551, 40500, 92700 and 92903)
During the inspection period, the inspectors assessed the effectiveness
of the onsite design and engineering processes by reviewing engineering
evaluations, operability determinations, modification packages and other
areas involving the Engineering Department.
4.1
Low Pressure Service Water Pump Suction Requirements
The licensee discovered deficiencies in the calculated suction pressure
for the LPSW pumps when revising OSC-2280, LPSW NPSHA and Minimum
Required Lake Level.
The error in the calculation was that a minimum
flow rate of 10,000 gpm through the LPSW system was used as the basis
with an allowed pressure drop of 1.3 psid across the pump suction
strainer. The review of the calculation and operating parameters
revealed that the normal flow rate through the LPSW system could be as
low as 7,000 gpm during cold weather with the 1.3 psid across the
suction strainer and accident flow rates could reach approximately
15,000 gpm. An accident scenario where the CCW pumps would be
eliminated and at a time when the LPSW flow rates were at 7,000 gpm and
a strainer pressure drop of 1.3 psid, the pressure drop across the
strainer would increase significantly due to an increased LPSW flow of
approximately 8,000 gpm. At that point, there would be an inadequate
suction pressure for the LPSW Pumps to operate.
The licensee has revised their SLC, section 16.9.7, to maintain the
Keowee Lake level at 793 feet above sea level or to enter the action
statement when the level drops below that elevation. In addition, the
NLO surveillance requirements were changed to require the LPSW Pump
suction strainers to be backflushed when the pressure drop increases to
0.6 psid. The licensee has not completed past operability
ENCLOSURE
15
determinations. As a result, this item will be identified as URI
269,270,287/96-03-01, LPSW Suction Pressure Discrepancies.
4.2
Containment Hydrogen Control Systems (CHCS)
The Oconee CHCS as defined in TS 3.16.1 consists of a portable hydrogen
recombiner unit and a reactor building hydrogen purge system. Over the
years, the reactor building hydrogen purge system has not been
maintained in an operable status since TS 3.16.1 specifically states it
is not required to be operable when the hydrogen recombiner unit is
On February 1, 1996, at 1:30 p.m., Oconee entered a Limiting Condition
For Operability (LCO) per TS 3.16.3b due to the discovery that a
potential existed for condensate to collect in the common lines
associated with the hydrogen purge system and the hydrogen recombiner
for each Oconee unit. The condensate would inhibit flow to the
recombiner (as well as the already inoperable purge system), rendering
the CHCS inoperable. This condition existed on all three units since
initial construction of the system.
An accident scenario involving hydrogen gas buildup in the reactor
building would require processing by the Hydrogen Recombiner to avoid
reaching explosive limits. This condition would not occur until
approximately 15 days following the Design Basis LOCA. If the
containment atmosphere is not purged or the hydrogen is not removed, a
potentially explosive level of hydrogen could accumulate. An explosion
could breach containment. The inspectors agree with the licensee's
assessment that sufficient time would have been available to recognize
the problem with the hydrogen recombiner unit and take appropriate
actions to maintain containment integrity.
The deficiency was identified by the licensee's engineering personnel
during a review of the Hydrogen Control Systems to evaluate power
supplies to the areas designated for the portable hydrogen recombiner
unit. As a result, corrective actions were immediately started to
install a drain system in each unit to drain the loop seals in the
affected lines and return the condensation to the reactor building.
On February 6, 1996, the licensee requested an emergency TS amendment to
allow a one-time extension of the 7-day LCO for an additional 7 days.
The extension was granted on February 8, 1996, and allowed ample time to
complete the modification without shutting down all three Oconee units.
The modification was completed and LCOs were exited on February 10,
1996.
The system deficiency will be identified as an Apparent Violation, VIO
50-269,270,287/96-03-02, Inoperability of Containment Hydrogen Control
Systems.
ENCLOSURE
16
4.3
Electrical Fire in Logic Cabinet 1LC3 in Keowee Control Room,
IP/0/A/400/10
On February 16, 1996, While implementing IP/0/A/400/10, Controlling
Procedure for Troubleshooting and Corrective Maintenance at Keowee, an
electrical fire occurred in logic cabinet 1LC3 in the Keowee CR. The
licensee was troubleshooting why a DC power supply breaker tripped
unexpectedly while implementing NSM 52966 using TN/5/A/52966/BL1-07,
Modification of SK Breaker and Underground Control Circuit Logic. While
performing step fourteen of the IP, which was to close sliding link TB
18-29 in 1LC3, an electrical flash and fire began immediately. The fire
lasted approximately one minute. The licensee's immediate corrective
action was to extinguish the fire using a CO2 fire extinguisher and work
was stopped. The Unit 2 CR was notified and fire brigade members were
dispatched to the KHU where they confirmed that the fire was
extinguished. The licensee initiated PIP 0-096-0310 to resolve this
issue.
The licensee used the same IP for troubleshooting the cause of the fire.
The licensee determined that a Cutler-Hammer switch (light) Model number
10250T/91000T/E34 associated with ACB-3 indication had been incorrectly
wired on August 16, 1995, as part of TN/5/2966/BL1/01, Modification Of
Keowee Unit 1 & 2 Overspeed Protective Circuitry. The modification had
installed two switches to provide information as to which unit (ACB-3 or
ACB-4) was selected as the underground unit per TN/5/2966/BL1/01. The
licensee determined that both switches had been wired incorrectly in
August 1995. The two switches remained isolated since their
installation, due to the licensee backing out of the modification on
August 31, 1995. The incorrectly connected switch caused a short
circuit while the licensee was conducting the troubleshooting discussed
in the previous paragraph. The switch was connected according to the
drawing supplied in TN/5/2966/BL1/01. It was noted that a QC inspector
verified that the proper connections had been made. The connection
diagram for the new switch was not verified by the design engineer when
developing the modification. The engineer assumed that the vendor had
not made any changes, while in fact the vendor had upgraded the switch
and incorporated changes to the respective connection diagram. The
licensee is conducting a root cause evaluation as part of PIP 0-096-031
to ensure that appropriate corrective actions are put in place to
prevent this from recurring.
The licensee replaced the damaged terminal block in logic cabinet 1LC3.
On February 22, the licensee completed the replacement of the pretest
lights per TN/5/A/2966/BL1/10, Replacement of L141 Pretest Lights for
ACB-3 and ACB-4 Plant Support. The inspector observed portions of
TN/5/A/2966/BL1/10. No problems were identified.
ENCLOSURE
17
4.4
Spent Fuel Pool
An engineering inspection was performed on the spent fuel pool from
February 26 - March 1, 1996. The inspectors reviewed the plant
practices, procedures, calculations, and parameters associated with the
Spent Fuel Pool (SFP) and support systems to determine if these were
consistent with the description in the licensing basis as described in
the Final Safety Analysis Report (FSAR) and related Safety Evaluation
Report (SER).
Sections 9.1.2, 9.1.3, and 3.8.4 of the FSAR described
the SFP systems and structures. Amendments dated December 24, 1980, and
September 29, 1983, to the FSAR addressed SFP rerack modifications. The
interface of the SFP and the Safe Shutdown System (SSS) was addressed in
numerous NRC/Duke Power company correspondence between 1978 and 1983.
FSAR section 9.6.3.2 described the SFP incorporation as an SSS Reactor
Coolant Pump seal makeup source. Additionally, the inspectors reviewed
the potential for SFP draw down and applicability to Oconee Nuclear
station of the Millstone SFP issue.
4.4.1 SFP Licensing Basis Review
The SFP and support system configuration described in the FSAR was
verified by review of system drawings and field verification.
Licensee procedures, logs, and Technical Specifications were
reviewed to determine if FSAR referenced parameters and operating
conditions were consistent with the FSAR description. Critical
parameters reviewed included predicted decay heat loads, SFP bulk
water temperature, and SFP level.
In particular, the calculations
were reviewed to verify that the SFP decay heat loads specified in
the FSAR for various SFP loading configurations were evaluated and
the cooling system was adequately sized to maintain SFP
temperatures within the values specified for the corresponding
loading conditions. Licensee controls to assure the SFP loading
configurations did not exceed the evaluated conditions are
addressed below in sub-paragraph 4.4.3.
There are two SFPs at Oconee; a combined Unit 1 and 2 SFP and a
Unit 3 SFP. There are three trains of spent fuel cooling for each
SFP. There have been several rerack amendments approved for the
Oconee SFPs. The inspectors reviewed the amendments and
concentrated on the last of three rerack amendments to determine
the present heat loads in the SFPs. For the Unit 1 & 2 SFP
Cooling System, the design basis normal heat load assumes that
Units 1 and 2 are refueled consecutively and the rack positions
are filled with previous discharges, except for 118 spaces
reserved for a full core discharge. The design basis abnormal
heat load assumes that Unit 1 and 2 are refueled consecutively,
followed by a full core discharge after a short period of
operation. Similar normal and abnormal decay heat load
configurations were described for the Unit 3 SFP.
ENCLOSURE
18
The predicted maximum normal and abnormal heat loads for the Unit
1/2 SFP were 21.9 E6 BTU/hr and 34 E6 BTU/hr, respectively. For
the Unit 3 SFP, the respective heat loads were 12.6 E6 BTU/hr and
30.8 E6 BTU/hr. Calculation OSC-610,"Expanded Oconee 1 & 2 Heat
Load on the Spent Fuel Pool," Revision 1, analyzed the decay heat
loads for the normal and abnormal conditions and supported the
values specified in the FSAR. Calculation OSC-1765, Unit 3 Spent
Fuel Pool Heat Load, revision 0, analyzed the loading conditions
in the Unit 3 SFP. The following calculations analyzed the
cooling system capacity for each SFP and verified that the FSAR
Section 9.1.3.1.2 and FSAR Section 9.1.3.1.1 specified bulk water
temperature limits on the pools would be maintained:
OSC-616, Spent Fuel Temperature vs. Heat Load Calculation,
Revision 0
OSC-1835, Oconee Unit 3 Spent Fuel Cooling System Analysis,
Revision 0
The calculations indicated that the SFP cooling systems were
adequately designed to remove the decay heat generated from the
analyzed fuel loading and maintain pool bulk temperatures below
the design criteria referenced in the FSAR.
The inspectors reviewed graphs of the Recirculating Cooling Water
(RCW) temperatures from January 1, 1993, to December 31, 1995, for
all three units and determined that the temperatures had not
exceeded 90 F. RCW provided the heat sink for the SFP cooling
system. This is the design temperature for the RCW to the SFP
coolers. There were no tubes plugged on the coolers. The
inspectors reviewed the data sheets for the original spent fuel
coolers and the newer plate type coolers. The manufacturer's most
conservative mean temperature differences were used to calculate
heat load. The inspectors concluded that the normal and abnormal
heat load conditions for the Oconee SFPs had been analyzed and
that adequate cooling system capacity was available to maintain
the temperature limits specified in the licensing basis.
In addition to SFP decay heat load and temperature, SFP level was
a critical parameter referenced in the FSAR. FSAR Section
9.1.4.2.3 specified a minimum of 23.5 feet of water above the
spent fuel stored in the spent fuel racks. There was no minimum
SFP level referenced in the TS; however, administrative controls
allowed a level of two feet below the nominal SFP level at a site
elevation of 838 feet. The top of the racked fuel assemblies was
at the 816.5 foot elevation. This would result in a water
coverage of 21.5 feet which was not consistent with the FSAR
value. This discrepancy between the licensing basis and plant
procedures was previously identified as Deviation 50-269,270,
287/95-30-03 and corrective actions had been implemented.
ENCLOSURE
19
Licensee analysis determined that the level discrepancy would not
result in increased radiation levels in the SFP area.
The inspectors reviewed the operator logs to verify the monitored
parameters were consistent with FSAR referenced values. The
inspectors reviewed the non-licensed operator logs (NLO) for
February 18, 1996. OP/2/A/1102/20, Unit 2 Primary NLO Primary
Round Sheet, Enclosure 5.8, NLO Turnover Sheet; Enclosure 5.10,
Basement Round; and Enclosure 5.11, Round Sheet, were reviewed.
The round sheets specified a range for each parameter and the
operator verified the value was within the indicated range. An
explanation was required if the parameter was not within the
range. Enclosure 5.11 verified the spent fuel pumps on or off for
each individual pump. It also checked cooler flows within range.
The check sheet additionally addressed motor and pump bearing
temperatures and pump bearing oil level.
No actual temperature or
levels were recorded. The licensee indicated that important
parameters were trended by computer. Enclosure 5.11 checked the
SFP gas monitor operation and SFP water level at the skimmer
trough, which approximately corresponds to a level of 23.5 feet
above the fuel.
Additionally, SFP area cleanliness was checked.
SFP level and temperature indicators were in the control room.
Enclosure 13.1, Periodic Checks Schedule Sheet when RCS is Greater
than 200 degrees F., verified that the SFP water temperature is
less than 143 degrees F. The inspectors concluded that the logs
indicated that SFP parameters were maintained consistent with the
values specified in the FSAR.
The inspectors reviewed the parameters associated with the SFP
ventilation system. TS 3.8.12 requires the SFP ventilation system
to be operable whenever fuel movement is in progress. Section
9.4.2.1 of the FSAR states, "The ventilation system is designed to
maintain the SFP area at a maximum inside temperature of 104
degrees F and a minimum temperature of 60 degrees F."
The 104
degrees F temperature may have been exceeded during full core off
loads in the summer or autumn, but area temperature was not
monitored. However, the SFP water temperature had reached 110
degrees F on some occasions. Although unverified, this large heat
source could result in air temperatures greater than 104 degrees
F. The licensee initiated PIP 0-095-0389 to review this problem
and determined that the higher temperatures would not impact
safety-related equipment in the SFP area. The inspectors were
concerned that the higher temperature might have affected the
efficiency of the charcoal filters in the fuel handling building
ventilation system. The inspectors determined that no credit was
taken for the ventilation filter system in the spent fuel pool in
calculating releases during an accident.
ENCLOSURE
20
4.4.2 Potential SFP Draw Down
The Oconee SFP design provides two mechanisms for SFP draw down.
The High Pressure Injection (HPI) Pumps could provide Reactor
Coolant Pump (RCP) seal make up during a Tornado event and the
reactor make up pumps could provide RCP make up during a SSS
event. The SFP level decrease due to a Tornado event via the HPI
was physically limited to approximately 18.5 feet above the top of
the racked fuel assemblies due to a siphon break on the supply
line. The SSS interface could permit a draw down to approximately
six feet below the top of the fuel assembly if not limited by
administrative controls.
The SSS interface is located on the fuel transfer tube centerline
in the reactor building at approximately the 810 foot elevation.
This interface was provided by three-inch diameter seismically
qualified piping. The top of the racked fuel assembly was at the
816.5 foot elevation. The fuel transfer tube is a large diameter
tube which connects the SFP to the reactor building through which
the fuel assemblies are transported between these locations.
Although the transfer tube can be isolated, it is normally open to
the SFP to ensure availability of the SSS make up to the RCP
seals.
The inspectors noted that the SSS modification to the SFP deviated
from the Standard Review Plan (SRP) description of the SFPs.
Section 9.1.3 of the SRP stated that the SFP should be designed
such that the failure of inlets, outlets, piping or drains will
not result in inadvertent drainage below a point approximately ten
feet above the top of the active fuel in the SFP. The NRC
approved the SSS modification which included the interface.
However, it is not clear in the documented correspondence that the
NRC would have had the opportunity to identify this deviation from
the SRP design. The available Duke/NRC correspondence does not
include any specifics about the location of the interface tap or
relative elevations between the tap and the SFP fuel assemblies.
It is not clear whether the licensee provided adequate information
in their submittal for the NRC to identify this deviation from the
SRP design or that the SFP section of the SRP was addressed during
the SSS evaluation. Pending further NRC review, this matter is
identified as URI 269,270,287/96-03-03, Adequacy of Information
for SFP/SSF Interface.
The following references included pertinent information regarding
the process for acceptance of the Oconee SSS design which included
the RCP seal supply interface with the SFP:
a.
NRC letter to Duke Power, Mr. H. B. Tucker, dated April 28,
1983
b.
Duke letter to NRC, Mr. E. G. Case, dated, June 19, 1978
ENCLOSURE
21
c.
Duke letter to NRC, Mr. H. R. Denton, dated September 20,
1982
d.
Duke letter to NRC, Mr. H. R. Denton, dated March 28, 1980
In references (b) and (c) the licensee stated that the design of
the SSS would not specifically apply all sections of the SRP.
Reference (d) stated that the SSS provided for SFP draw down to
one foot above the fuel racks. Reference (a) included the NRC
approval of the licensee's SSS submittal and program.
The inspectors reviewed barriers which would reduce the potential
for SFP draw down. The licensee's submittal (reference d. above)
indicated that the analyzed 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> SSS event duration would
result in a SFP level of one foot above the racked fuel
assemblies, assuming no operator actions. The subsequent SFP area
radiation levels and refill capability were not addressed and this
was the issue of URI 269,270,287/94-31-06, which is discussed in
sub-paragraph 4.7.1 of this report. Barriers were provided by
administrative controls, level monitoring, alarms, and seismic
qualification of the system. The emergency procedures which
activate the SSS facility required the SFP level be monitored
after the RCP seal supply was initiated. The refill procedure was
referenced and actions to align the refill source initiated early
)
in the SSS activation procedure. A mechanism for level monitoring
via the RCM pump suction pressure parameter is provided in the
procedure if operator access to the SFP is restricted. Level
alarms near the normal operating levels would alert operators to
an unplanned level decrease. The RCM supply piping from the
SFP/fuel transfer tube was seismically qualified for the Safe
Shutdown Earthquake.
A manual isolation valve was provided for
isolation of the fuel transfer tube. Two motor operated isolation
valves were provided downstream of the RCM pump suction. These
were normally closed. The inspectors concluded that multiple
barriers were now available to prevent inadvertent draw down of
the SFP via the SSS interface.
4.4.3 Millstone Issue - SFP Loading Condition Not Evaluated
The inspectors reviewed the SFP loading conditions evaluated by
the predicted decay heat load analyses referenced in paragraph
4.4.1 of this report. SFP loading considerations included heat
loads and criticality. The heat load analyses assumed a minimum
of 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> cool down prior to transfer of fuel assemblies from
the reactor to the SFP. FSAR sections 9.1.3.1.1 and 9.1.3.1.2
assume minimum cool down of 168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br /> and 6 days (144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />) cool
down, respectively. Section 3.8.11 of the TS restricts fuel
movement from the core to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after the reactor is
subcritical. Procedure OP/0/A/1502/07, Operations Defueling/
Refueling Responsibilities, dated November 11, 1995, specified
ENCLOSURE
22
that irradiated fuel shall not be removed from the reactor core to
the SFP until the reactor has been subcritical seven days (168
hours). This administrative control assures that the 168-hour
assumption in the heat load analyses was valid.
Nuclear Engineering's routine outage task list required Nuclear
Engineering to review planned SFP loading for refueling and verify
that the calculated decay heat loads were bounded by the FSAR
specified heat loads and the following heat load calculations:
OSC-4776, Unit 3 SFP, Revision 1
OSC-4998, Units 1&2 SFP Heat-up Rate, Revision 5
OSC-5928, SFP Decay Heat Load Projections for Future
Equilibrium Core Designs, Revision 0
Decay heat loads for fuel assemblies were calculated in accordance
with NRC Branch Technical Position ASB 9-2, Residual Decay Energy
for Light Water Reactors for Long Term Cooling. PIP 0-096-0362,
dated February 20, 1996, included a corrective action to include
the routine SFP heat load review practice as an operations
procedure requirement.
Normal and abnormal decay heat loads define specific loading
conditions for evaluation that supported sizing of cooling systems
and SFP bulk water temperature criteria. The significant
difference being that the abnormal heat load included a full core
off load rather a one third core off load. Oconee has routinely
performed a full core off load during refueling outages since
1982. This condition is not prohibited by the licensing basis.
SFP loading configuration based on criticality analysis was
specified by TS 3.8.16 and implemented by procedure
PT/0/A/0750/12, Development of Fuel Movement Instructions, dated
February 22, 1996. Procedure OP/0/A/1503/09, Documentation of
Fuel Assemblies and/or Component Shuffle Within a SFP, dated
February 22, 1996 also implemented SFP configuration controls.
4.4.4 Self-Assessment
The inspectors reviewed the licensee's self-assessment in this
area. A team of engineering and licensing personnel were
assembled in the week prior to the inspection to review the SFP
design and licensing basis compliance. The team concluded that
Oconee was in compliance with the SFP design and licensing basis.
Several PIPs were initiated to address areas for improvement
identified by the self-assessment team. PIP 0-096-0362 dated
February 20, 1996, identified discrepancies with the SFP heat load
calculations. Included in these were that the FSAR heat load
ENCLOSURE
ll
23
values will be exceeded when the higher enrichment fuel is
transferred to the SFP in future off loads. Although the normal
and abnormal predicted heat loads will be higher, they will still
be within the capacity of the cooling system. PIP 0-096-0389
dated February 26, 1996, identified that ventilation system design
documentation did not support the area design temperature range of
60 - 104 degrees F referenced in the FSAR and that the temperature
may have been exceeded. The NRC is in the process of reviewing
the consistency between the FSAR descriptions and the licensee's
policy, procedures, and practices.
4.5
Keowee Voltage Regulator Problem
On February 27, 1996, the licensee made a 10 CFR 50.72 notification to
the NRC concerning a postulated failure which could drive the Keowee
voltage regulator to its lower limit and result in inadequate voltage
being supplied to some low voltage (208V) motor operated valves during a
LOOP/LOCA scenario. The licensee's current analysis does not support
operability of the underground path with this failure. The licensee
entered an LCO for the underground path. The licensee determined that
this failure does not relate to the overhead path, since existing
undervoltage relays on the 27E breaker will detect these degraded
voltages, and transfer loads to the underground.
On February 27, 1996, the licensee performed TT/0/A/620/24, Keowee
Voltage Regulator Voltage Adjust Low Setpoint, on Keowee Unit 1 to
check and adjust the Keowee regulator voltage adjust low setpoint value.
The Keowee Unit 1 low setpoint value was determined to be 11.9 KV, but
was then adjusted to 13.5 KV. The licensee's calculation OSC-5952,
Oconee-Keowee Underground Path Analysis Using CYME, documents the
operability of the underground path with a Keowee generator voltage of
13.5 KV. The licensee then exited the LCO for the Keowee underground
path. The licensee determined that Keowee Unit 2 which was lined-up to
the overhead was in an operable, but degraded condition until the low
voltage setpoint on its voltage regulator was checked and set. On March
1, 1996, the licensee performed TT/0/A/620/25, Keowee Unit 2 Voltage
Regulator Voltage Adjust Lower Setpoint, to check and adjust the Unit 2
Keowee regulator voltage lower setpoint value. The Keowee Unit 2
voltage regulator low setpoint value was 12.7 KV, but was subsequently
adjusted to 13.5 KV. The licensee continues to determine the past
operability of the low voltage motor operated valves. The inspector
will continue to follow this issue.
4.6
Failure of 1HP-276
The licensee reported to the NRC on February 19, 1996, that an Appendix
"R" fire could cause the spurious opening of valve 1HP-276 (RCP Seal
Leakoff), resulting in the Unit 1 RCS leakage rate being greater than
what was assumed in previous calculations. Since the Unit 1 SSF makeup
pump supply to the RCS through the RCP seals is marginal, the excess
ENCLOSURE
24
leakage could result in exceeding the available pump capacity. An
inadequate flow to the RCP seals could prevent RCS natural circulation,
thereby preventing decay heat removal during an Appendix "R" accident
scenario.
As indicated above, this normally closed valve is a leakoff for the
number 1 seal on the Unit 1 RCPs. When opened, it allows makeup flow to
by-pass the number 2 and 3 seals, reducing backpressure and resulting in
an increased flow that would exceed the capacity of the makeup pumps.
Corrective actions to eliminate a spurious opening of this valve
involved ensuring that the valve was closed and then opening the power
supply breaker to the valve motor.
Although engineering personnel identified the deficiency on February 2,
1996, it was not reported until February 19, 1996. The failure to meet
the 4-hour reporting requirement of 10 CFR 50.72 resulted in additional
training for the engineers. The licensee is taking actions to ensure
that reporting is accomplished in the required timeframes. This issue
of reporting requirements will be examined further during the corrective
action followup of related Violation 50-269,270,287/95-27-01.
Further
evaluations and long-term corrective actions will also be reviewed
during a closure of the licensee's LER.
4.7
Engineering Followup Items
4.7.1 (Closed) URI 50-269,270,287/94-31-06, High SFP Radiation Levels
This issue addressed the potential high radiation levels in the
SFP area resulting from the draw down of the SFP during an SSS
event.
The licensee had not evaluated the SFP radiation levels
due to loss of shielding if the level was reduced to one foot
above the racked fuel assemblies as assumed in the SSS analysis.
Additionally, the mechanism for refill of the SFP had not been
addressed by procedures. The licensee's letter to the NRC dated
March 9, 1995, specified actions to address these concerns. The
action items included a modification to provide a remote refill
capability, calculations to evaluate radiation levels and quantify
time allowances for refill', and procedures to provide guidance for
the refill activity.
The radiation level analysis was documented in PIP 0-096-0345,
dated February 16, 1996, and determined dose rates at various pool
levels. The maximum dose rate, one foot above the racks, was
50,000 R/hr. The 2,000,000 R/hr value referenced in NRC Report
50-269,270,287/94-31 was a very rough approximation which was not
supported by a detailed calculation. The refill methodology was
proceduralized in MP/O/A/3009/012A, Emergency Plan for Refilling
Spent Fuel Pools, dated December 21, 1995. This methodology
required support from local fire departments to provide at least
two fire trucks to pump water from the lake via a filter unit to
ENCLOSURE
25
the SFPs. The procedure stated that the refill pumping system
should be available 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> after initiation of SSS RC make up.
Calculation OSC-619, Analysis for Use of SFP Inventory for SSS,
Revision 9, determined that SFP level would be lowered to one foot
above the racked fuel assemblies in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Agreements with the
local fire stations and filter unit suppliers had been negotiated.
The limiting factor was the time allowance of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for the
filter unit delivery. The licensee was attempting to acquire the
filter unit for storage in the SSS facility.
Calculation OSC-6051, Verification of Alternate Method Used to
Fill SFPs Following Operation of SSF RC Make Up System, Revision
1, analyzed the capabilities for the make up source and developed
a method of monitoring SFP level via RCM pump suction pressure.
The inspectors field verified the modification which allowed
remote refill of the Unit 1/2 SFP. Installation of a remote fill
system for the Unit 3 SFP is scheduled for latter this year. The
inspectors concluded the licensee had completed the committed
corrective actions and adequately resolved this issue.
4.7.2 (Open) Violation 270/94-08-02, Inoperability of 2A Emergency
Feedwater Pump
On December 29, 1993, the licensee discovered water leaking from
pressure switch 2PS0386. This switch monitors the discharge
pressure of the 2A Main Feedwater Pump and sends a signal to start
the 2A Motor Driven Emergency Feedwater (MDEFW) Pump on low
discharge pressure of the main feedwater pump. During the switch
replacement, the electrical leads were lifted which resulted in
the elimination of a Unit 2 direct current (DC) ground that had
existed since December 14, 1993. The licensee's failure to take
aggressive action to locate and correct the ground on the DC
electrical system resulted in the prolonged condition. The issue
of allowing DC grounds to exist without performing an extensive
effort to find and eliminate the problem had previously been
identified by the NRC as a weakness and documented in NRC
Inspection Report 50-269,270,287/93-26.
An operability assessment completed on February 8, 1994,
determined that grounded pressure switch 2PS0386 had caused the 2A
MDEFW Pump to be inoperable from December 14-30, 1993. The time
that the emergency feedwater pump was considered inoperable
exceeded the seven days allowed by TS 3.4.2.a. Failure to meet
the requirement specified by the TS was identified as Violation
50-270/94-08-02. As a result of exceeding the TS limit, the
licensee submitted an LER (270/94-01) on March 10, 1994.
Corrective actions included replacing the subject pressure
switches on all three units. Additionally, the licensee developed
a report entitled "125 VDC Vital Instrumentation and Control
ENCLOSURE
ll
26
System Ground Detection, Location, and System Operation Design
Study," dated February 1, 1995. This report made recommendations
to resolve the ground issue. These recommendations included
installing ground detection equipment with the required
sensitivity, acquiring portable ground locating equipment with the
desired accuracy, and implementing proposed comprehensive alarm
response procedures. Accordingly, Violations 270/94-08-02 is
considered closed.
NRC Inspection Report 269,270,287/95-14 reviewed the ground issue
at Oconee. In this report the inspector reviewed the ground
design study and concluded that the implementation of the
recommendations would constitute acceptable corrective action to
resolve this issue in the long-term. At the time of Inspection
Report 95-14, the recommendations in the design study were still
under review by licensee management. As of the end January 1996
most of the recommendations were implemented. Ground alarm
response procedures were incorporated into the licensee's FSAR
Chapter 16, Selected Licensee Commitments (SLC 16.8.5) on January
4, 1996, and portable ground locating equipment had been
purchased. New ground detection equipment with improved ability
to detect higher resistance grounds (5000 ohms versus 500 ohms for
the existing equipment) had been purchased and was onsite but was
not scheduled to be installed until 1998 (NSM 3004). The
inspector questioned the proposed implementation date of 1998.
The licensee stated that NSM 3004 was deferred until the 1998 time
frame due to the cost of implementation. The inspector concluded
that the licensee had adequate provisions in place to respond to
ground alarms. However, the inspector remained concerned that due
to the currently installed ground detector's threshold for
detecting a ground (500 ohms or less resistance to ground) the
Vital DC System could be severely degraded without actuating the
alarm. Therefore, implementation will be followed under IFI
269,270,287/96-03-04, Installation of New Ground Detection
Equipment.
4.7.3 (Closed) LER 270/94-01, Technical Specification Limit Exceeded Due
To Equipment Failure
This event and associated issues are captured in Violation
269,270,287/94-08-02 which is addressed in sub-paragraph 4.7.2
above. Accordingly, this LER is closed.
5.0
PLANT SUPPORT (71750)
The inspectors assessed selected activities of licensee programs to
ensure conformance with facility policies and regulatory requirements.
During the inspection period, the areas of Radiological Controls,
Physical security and Fire Protection were reviewed.
ENCLOSURE
27
5.1
Liquid Waste Spill, CP/O/B/5200/54
On February 16, 1996, a technician noted that the flow totalizer was
steadily decreasing when transferring from recirculating liquid waste
(LW) to processing the LW. Due to this abnormal indication, the
technician shutdown the "A" LW feed pump. While evaluating the
situation, the technician identified a spill in Room 227. The
technician notified the CR and RP. At the time of the incident the
licensee approximated the spill to equate to 150 gallons. The
technician entered Room 227 and identified that a backflush hose
installed per a temporary modification had blown off. With RP approval,
the technician reconnected the hose. The licensee determined that the
hose failure was due to the use of the wrong size hose clamp. The
technician called another technician for support in evaluating the
situation. The two technicians identified another leak in the "D"
demineralizer manway. The licensee determined that this leak came from
a gasket that was incorrectly installed in the manway. The licensee
initiated a root cause evaluation per PIP 4-096-0314 to determine the
actual cause of the problem. The resident will continue to follow this
issue for final resolution.
Within the areas reviewed, no violations or deviations were identified.
6.0
REVIEW OF FSAR COMMITMENTS
A recent discovery of a licensee operating their facility in a manner
contrary to the FSAR description highlighted the need for special
focused review that compares plant practices, procedures and/or
parameters to the FSAR description. While performing the inspections
which are discussed in this report, the inspectors reviewed the
applicable portions of the FSAR that related to the areas inspected.
The following inconsistencies were noted between the FSAR and the plant
practices, procedures, and parameters observed by the inspectors:
FSAR 9.1.4.2.3 stated that water level over the fuel assemblies is
maintained at a minimum 23.5 feet. Plant procedures specify the
minimum water level at minus two feet from the 840 foot elevation
which would result in 21.5 feet of water above the fuel racks.
NRC deviation 50-269,270,287/95-30-03 identified this item.
SER Amendment 90, 90, 87 stated that if SFP water temperature was
initially 125 degrees F, boiling would occur greater than 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />
after loss of SFP cooling. Calculation OSC-4998 for Unit 1/2 Heat
Up Rate, determined that the actual time to boil could occur in
less than 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> for higher heat loads.
SER Amendment 90, 90, 87 stated that the required make up rate
will be less than 70 gpm for Unit 1/2 SFP. This addressed water
loss due to boil off only and did not account for the 29 gpm RCP
ENCLOSURE
28
seal supply. The combination would exceed the 70 gpm value. This was
not a concern since the refill capacity exceeded 150 gpm.
SER Amendment No. 123, 123, 120 stated that the time of 15 and 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />
for Unit 3 SFP boiling in the normal and abnormal heat load conditions
respectively, was sufficient to provided emergency SFP make up.
The
procedure MP/0/A/3009/012A, Emergency Plan for Refilling SFPs, dated
December 21, 1995, specified 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> for completion of the pumping
system for SFP refill and 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> as the upper limit to begin pumping
to the pool.
SER Amendment No. 90, 90, 87 references maximum normal and abnormal
predicted heat loads, values which will not be accurate when the higher
enrichment fuel assemblies are transferred to the SFP in future
refueling outages.
The inspectors concluded that discrepancies existed in the SER, but they did
not constitute Deviations. A Deviation from FSAR requirements was identified
is Paragraph 4.4.1 of this report.
7.0
EXIT
The inspection scope and findings were summarized on March 14, 1996, by P.
Harmon with those persons indicated by an asterisk in paragraph 1. Interim
exits were conducted on February 16, 1996, and February 29, 1996. The
inspector described the areas inspected and discussed in detail the inspection
results. A listing of inspection findings is provided. Proprietary
information is not contained in this report. Dissenting comments were not
received from the licensee.
Item Number
Status
Description and Reference
EEI 269,270,287/96-03-02
Open
Apparent VIO: Inoperability of
Containment Hydrogen Control Systems
(paragraph 4.2)
URI 269,270,287/96-03-01
Open
LPSW Suction Pressure Discrepancies
(paragraph 4.1)
URI 269,270,287/96-03-03
Open
Adequacy of Information for SFP/SSF
Interface (paragraph 4.3.4)
IFI 269,270,287/96-03-04
Open
Installation of New Ground Detection
Equipment (paragraph 4.7.2)
IFI 269,270,287/95-26-02
Closed
Review Test Program for Mechanical
Components at Keowee to Resolve
EDSFI Finding 6.b (paragraph 3.3)
ENCLOSURE
29
IFI 269,270,287/95-26-03
Closed
Purpose and Limitations of the
List of SSCs in the Quality
Standards Manual (paragraph
3.4.1)
URI 269,270,287/94-31-06
Closed
High SFP Radiation Levels
(paragraph 4.7.1)
VIO 270/94-08-02
Closed
Inoperability of 2A Emergency
Feedwater Pump (paragraph
4.7.2)
Closed
Technical Specification Limit
Exceeded Due to Equipment
Failure (paragraph 4.7.3)
EEI 269,270,287/96-02-01
Closed
Apparent VIO: Inadequate
Control Over Fuel Assembly
Movement (paragraph 3.4.4)
Open
Inadequate Procedural Control
Over Movement of Fuel
Assemblies in the Spent Fuel
Pool (paragraph 3.4.4)
8.0
ACB
Air Circuit Breaker
As Low As Reasonably Achievable
BHUT
Bleed Holdup Tank
BTO
Block Tagout
BWST
Borated Water Storage Tank
CFR
Code of Federal Regulations
Component Cooling
Condenser Circulating Water
CR
Control Room
Design Basis Accident
Direct Current
Apparent Violation
Emergency Feedwater
EPSL
Emergency Power Switching Logic
End Of Cycle
Engineered Safeguards
E6 BTU/hr
1 million British Thermal Units per hour
FWPT
Feedwater Pump Turbine
Final Safety Analysis Report
GL
Generic Letter
GPM
Gallons Per Minute
Health Physics
ENCLOSURE
I
30
High Pressure Injection
Integrated Control System
IFI
Inspector Followup Item
I&E
Instrument & Electrical
IR
Inspection Report
KHU
Keowee Hydro Unit
LDST
Letdown Storage Tank
LER
Licensee Event Report
LCO
Limiting Condition for Operation
Loss of Coolant Accident
Low Pressure Injection
Low Pressure Service Water
Motor Driven Emergency Feedwater
Maintenance Procedure
MVA
Mega Volts-Amps
Megawatts
Non-Cited Violation
Non-Licensed Operator
NPSHA
Net Positive Suction Head Absolute
NSM
Nuclear Station Modification
NSD
Nuclear System Directive
OATC
Operator At The Controls
Oconee Nuclear Station
OEP
Operating Experience Program
PSID
Pounds Per Square Inch Differential
Pounds Per Square Inch Gauge
Preventive Maintenance
Problem Investigation Process
Quality Assurance
Quality Control
QSM
Quality Standards Manual
RC
Reactor Make-up
Reactor Coolant Pump
RCW
Recirculating Cooling Water
Roentgen Equivalent Man
Refueling Outage
R/hr
Roentgen per hour
Radiation Protection
Refueling Outage
Safety Evaluation Report
Spent Fuel Pool
Selected Licensee Commitments
Significant Operating Event Report
Standard Review Plan
Systems, Structures and Components
SSF
Standby Shutdown Facility
ENCLOSURE
31
Safe Shutdown System
TS
Technical Specification
Unresolved Item
VDC
Volts Direct Current
Violation
Work Control Center
Work Order
ENCLOSURE