ML16154A621
| ML16154A621 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 06/16/1994 |
| From: | Harmon P, Sinkule M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A618 | List: |
| References | |
| 50-269-94-16, 50-270-94-16, 50-287-94-16, NUDOCS 9406290237 | |
| Download: ML16154A621 (17) | |
See also: IR 05000269/1994016
Text
A
REGU
UNITED STATES
o
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/94-16, 50-270/94-16 and 50-287/94-16
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: May 1 - June 4, 1994
.r
.Harmon,
Senior R
dent Inspector
D Ate ignd
W. K. Poertner, Resident Inspector
L. A. Keller, Resident Inspector
P. 'G.
Humphrey, Resident Inspector
Approved by:
t
-
c?
6
/
,
M. V. Sinkule, Chief,
Date Signed
Reactor Projects Branch 3
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, surveillance testing, maintenance activities,
and engineering and technical assistance.
Results:
An apparent violation (with two examples) was identified
involving the failure to follow refueling procedures (paragraph
2.c).
Additionally, a violation occurred when a control room operator
inadvertently diluted the Unit 3 Reactor Coolant System (paragraph
2.d).
The licensee discovered a potential single failure vulnerability
in the Engineered Safeguards (ES) System involving a loss of
manual control of certain ES equipment from the control room
following a failure of a common grounding wire. The Licensee
completed an operability evaluation for this configuration which
is being reviewed by the NRC. This issue was identified as an
Unresolved Item (paragraph 4.b).
The inspectors noted that the reactor coolant pump seal injection
flow path and the normal makeup flow path were isolated during the
9406290237 940616
PDR ADOCK 05000269
G
2
performance of a High Pressure Injection pump run-out test. These
flow paths would normally be open during an accident and could
result in different pump run-out flows than that produced during
the test. This item was identified as an Inspector Followup Item
(paragraph 3.b.(3)).
Inconsistencies between the Final Safety Analysis Report, the
Emergency Operating Procedures, the Design Basis Document, and
various calculations were noted regarding the minimum Reactor
Building sump level required for adequate Reactor Building Spray
pump net positive suction head (paragraph 4).
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- B. Peele, Station Manager
- S. Benesole, Regulatory Compliance Manager
D. Coyle, Systems Engineering Manager
J. Davis, Engineering Manager
T. Coutu, Operations Support Manager
- B. Dolan, Safety AssuranceManager
W. Foster, Superintendent, Mechanical Maintenance
- J. Hampton, Vice President, Oconee Site
D. Hubbard, Component Engineering Manager
C. Little-, Superintendent, Instrument and Electrical (I&E)
S. Perry, Regulatory Compliance
- G. Rothenberger, Operations Superintendent
R. Sweigart, Work Control Superintendent
Other licensee employees contactedincluded technicians, operators,
mechanics, security force members, and staff engineers.
- Attended exit interview.
.2.
Plant Operations (71707)
a.
General
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 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
b.
Plant Status
Unit 1 was in a scheduled refueling outage throughout the
inspection period.
Units 2 & 3 operated at or near 100 percent power throughout the
inspection period.
c.
Unit 1 Refueling Activities
The licensee commenced Unit 1 refueling activities on May 25,
1994. Refueling activities were controlled by procedure
OP/1/A/1502/07, Refueling Procedure. Step 1A of Enclosure 5.2,
Refueling Verification Form, required Fuel Assembly 585 located in
Spent Fuel Pool location C62 to be inserted in core location N14.
Fuel Assembly 585 was the first fuel assembly to be inserted into
the reactor vessel for core reload.
During a routine review of
refueling activities the inspectors determined that Fuel Assembly
585 was located in core location 013 with the fuel assembly still
grappled to the fuel handling mast. Discussions with the
refueling Senior Reactor Operator (SRO) determined that Fuel
Assembly 585 was located in core location 013 per an intrastation
letter from Nuclear.Engineering. The letter identified
intermediate core locations for Fuel Assemblies
585,587,58F,5RV,5RL,57G, and 5T9.
The purpose of the alternate
fuel moves was to obtain data on source counts at the different
locations to determine if regenerative source rods were needed to
bring the new Gamma-Metric Nuclear instruments on scale. The
inspectors questioned the acceptability of positioning fuel
assemblies in intermediate locations without approved procedural
guidance. Based on the inspectors' concerns the licensee
suspended fuel handling activities until alternate fuel handling
steps were generated in Enclosure 5.2A of OP/1/A/1502/07 to
reflect the fuel handling activities requested by the intrastation
letter.
(Note: only fuel assemblies 585 and 587 underwent
positioning in intermediate locations.)
OP/1/A/1502/07, Refueling Procedure, Step 4.2, Procedure, Note 2
states:
If it becomes necessary to alter the planned refueling
sequence, a note should be placed in Enclosure 5.2 (Refueling
Verification Form) where the departure occurs. The alternate
moves shall then be documented in enclosure 5.2A (Alternate Core
Loading Verification Form).
The failure to meet the requirements
of OP/1/A/1502/07 with respect to documenting the alternate fuel
movement activities associated with Fuel Assembly 585 is
identified as Apparent Violation 269/94-16-01:
Failure to Follow
Refueling Procedures.
On May 26, 1994, at approximately 4:10 p.m., the licensee
determined that the fuel assembly located in core location M4 was
not the correct fuel assembly required by the refueling procedure.
The licensee identified the problem during the performance of step
3
70 of enclosure 5.2, Refueling Verification Form. Step 70
required Fuel Assembly 75L located in Spent Fuel Pool location K1
to be placed in core location N9. When the Spent Fuel Pool bridge
operators went to location KI to retrieve Fuel Assembly 75L, the
location was empty.
Subsequent investigation by the licensee
determined that Spent Fuel Pool location Li contained a fuel
assembly. This location should have been empty per the refueling
procedure. Step 38 of enclosure 5.2, Refueling Verification Form
required Fuel Assembly 75V located in Spent Fuel Pool location Li
to be placed in core location M4. The-licensee then verified that
core location M4 contained Fuel Assembly 75L. Fuel Assembly 75L
was placed into core location N9 as required by the refueling
procedure and Fuel Assembly 75V was then placed in core location
M4. The failure to meet the requirements of procedure
OP/1/A/1502/07, Enclosure 5.2, step 38 is identified as another
example of Apparent Violation 269/94-16-01:
Failure to Follow
Refueling Procedures.
The licensee was cited three times in the past four years for
failure to maintain configuration control of fuel assemblies in
the Spent Fuel Pool and the Reactor Vessel during core offload and
reload activities. The last citation occurred on December 31,
1992, when Fuel Assembly 4MU was placed in core location M13
instead of Fuel Assembly 5R4 as required by the refueling
procedure.
The most recent examples demonstrate a continued
weakness in the licensee's program for fuel handling, as well as a
continued lack of attention to detail on the part of the fuel
handling staff.
d.
Inadvertent Dilution Of Unit 3 Reactor Coolant System
At approximately 11:00 p.m., on May 23, 1994, the Chemistry
Department requested the Unit 3 Balance Of Plant (BOP) reactor
operator to de-lithiate the reactor coolant system (RCS) for 10
minutes.
De-lithiation of the RCS via demineralizers in the
letdown portion of the High Pressure Injection (HPI) system is a
routine process for RCS pH control. The BOP operator discussed
using the 38 Deborating Demineralizer for this process, as the
Control Room Turnover Sheet designated using this boron saturated
demineralizer for de-lithiation. The appropriate procedure for
this process was OP/3/A/1103/04, Soluble Poison Concentration
Control, Enclosure 3.17, Operation of 3B Deborating Demineralizer
to De-lithiate Unit 3. The BOP operator inadvertently utilized
Enclosure 3.16, Operation of 3A Deborating Demineralizer to De
Lithiate Unit 3", which routed letdown flow through the non-boron
saturated 3A Deborating Demineralizer, for 10 minutes. At 11:30
p.m., the control room operators noted the control rods were
inserting and discovered the use of the wrong Enclosure. Feed and
bleed via the 3A Bleed Holdup Tank (BHUT) was initiated
immediately to restore previous RCS boron concentration. As a
result of the dilution, the Integrated Control System (ICS)
automatically inserted the control rods from 93.5% to 87.5% on
4
Group 7 (23.2 % on group 7 was the rod insertion limit).
The
total deboration of the RCS was 6 ppm, from 1071 to 1065 ppm.
Utilization of Enclosure 3.16 (Demineralizer 3A) and 3.17
(Demineralizer 3B) is procedurally controlled by initial condition
verification.
Initial Condition Step 1.1 of Enclosure 3.16 to
OP/3/A/1103/04 requires verification that:
"Operations notified
by Chemist that de-lithiation is required with the use of 3A
Deborating Demineralizer." The BOP operator mistakenly
initialed/verified this step and utilized Enclosure 3.16. The
chemist had in fact requested the 3B Deborating Demineralizer,
which was consistent with the Control Room Turnover Sheet. This
matter is identified as Violation 287/94-16-02:
Failure to Follow
Procedure Results in Inadvertent Dilution.of the RCS.
e.
Mid-loop/Reduced Inventory Activities
During the Unit 1 End Of Cycle 15 Refueling Outage, the licensee
reduced RCS inventory and reached the mid-loop operations level on
May 3, 1994, at 9:24 p.m. This was done for the purpose of
removing the steam generator manway covers and installation of
steam generator nozzle dams. The inspectors reviewed the
licensee's program prior to the reduction of RCS inventory and
verified that the requirements were met while operating at the
OP/3/A/1103/11, Draining And Nitrogen Purging Of RC System,
reducedlinventoryr leel As dspecifid inOperations Procedure
5nclosure 3.6, Requirements For Reducing RXV Level To < 50" on LT
5. This procedure stipulated the sequence and steps required for
reduction of RCS inventory and mid-loop operation. It further
specified the precautions and limitations to be adhered to while
in mid-loop.
Step 1 of Enclosure 3.6 specifically addressed the ability to
establish containment closure. The licensee implemented a
Shutdown Protection Plan for the outage which required the
containment to be closed except as necessary to bring materials
and tools in and out of the Reactor Building. It further required
that penetrations be closed except for those with temporary cables
installed for necessary outage activities (e.g., steam generator
tube testing, maintenance, etc.).
In both instances when
containment integrity was not maintained, a plan for quick closure
was addressed.
The requirement for two independent trains of RCS le vel monitoring
was met when operating at reduced inventory. It was accomplished
by the use of one permanently installed instrument (LT-5) and two
temporarily installed ultrasonic instruments for the outage.
Level indications were displayed in the control room on the LT-5
indicator, the Inadequate Core Cooling Monitor, and on the
Operations Aid Computer.
5
The inspector verified that two trains of core exit thermocouples
were available/utilized while at reduced inventory and that two
sources of inventory makeup and cooling were either in use or
available for operation., In addition, the inspector verified that
contingency plans existed to re-power vital busses from available
alternate electrical power supplies in the event of a loss of the
primary source.
During the time that Unit 1 was in a reduced inventory status, the
licensee implemented and maintained the requirements specified for
the condition. The unit exited the mid-loop operating regime on
May 4, 1994, at 6:05 p.m. The unit was in mid-loop operations for
20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> and 41 minutes. The program was well implemented and the
operation at reduced inventory was accomplished without incident.
f.
Missing Unit 1.Steam Generator Plug
On May 5, 1994, the licensee identified that the rolled tube plug
installed in Steam Generator IB lower tubesheet row 130, tube 89,
was missing. The missing plug was identified during a video scan
of the lower tubesheet. The missing plug was an inconel 600 plug
that was installed during the Unit 1 End of Cycle (EOC) 11
refueling outage in January 1989. The plug was inspected with a
Motorized Rotating Pancake Coil (MRPC) eddy current probe during
the last Unit 1 refueling outage (EOC 14) in December 1992, and no
degradation was observed. The licensee verified by review of a
video tape made of the installation of a nearby rolled plug (row
131, tube 88) that the plug was in place as of December 1992.
The
licensee verified that no other plugs were missing and initiated
plans to search for the missing plug and retrieve it. The plan
included inspecting the 1B steam generator lower bowl drain line,
the Reactor Vessel and the fuel assemblies during core off-load.
On May 10, 1994, during core off-load activities the licensee
identified two pieces of metal on the bottom of Fuel Assembly 57M
located in core location K7. The fuel assembly was transferred to
the Spent Fuel Pool and the pieces of metal were removed from the
fuel assembly and stored in the Spent Fuel Pool.
Video inspection
of the pieces showed that they were definitely part of a tube plug
and that the total length approximated an intact plug. The pieces
were removed from the pool and shipped to Babcock & Wilcox (B&W)
for review and failure analysis.
Licensee activities associated with steam generator inspections
were reviewed by,Region based specialists during the weeks of May
16 and May 23, and licensee activities were found to be
acceptable. These activities are documented in NRC Inspection
Report 269,270,287/94-17. As of the end of this inspection
period, the licensee had not identified the failure mechanism that
resulted in the plug failure.
6
Within the areas reviewed one violation and one apparent violation were
identified. The violation involved an inadvertent dilution of the Unit
3 RCS. The apparent violation involved two examples of failure to
follow refueling procedures.
3.
Maintenance and Surveillance Testing (62703 & 61726)
a.
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 (WO) 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:
(1) Work Order Task, 94000681-01, Perform OE-5803, Modify ICS
BTU Limit Circuit (Minor Modification).
On May 4, 1994, the inspector reviewed activities in
progress on Unit 1 during the implementation of the minor
modification to simplify the BTU Limits Circuitry that feeds
the Integrated Control System (ICS).
The modification was
to simplify the ICS BTU circuitry by removing the Reactor
Coolant flow and Feedwater temperature inputs to the BTU
limit calculation. The new calculation for BTU limits would
be based on the T-hot and Once Through Steam Generator
(OTSG) outlet pressure inputs only.
The primary purpose of the BTU Limits Circuitry is to alert
the operator of potential BTU limit conditions and assure
rapid runback of feedwater flow following a reactor trip.
The technical basis for the modification was documented in
B & W Document, 12-1175342-00 which determined that only the
T-hot and the OTSG outlet pressure inputs were needed.
The inspector reviewed the licensee's safety evaluation
which determined the modification met acceptable criteria
for implementation. In addition, the work efforts were
reviewed and it was concluded that the activity was
performed per the work instructions and properly documented.
(2) Work Order 94018639-01, Investigate and Repair 3FDW-107.
During the performance of a quarterly stroke test
(PT/3/A/0150/22A), 3FDW-107 did not give a full open
indication. This valve is the Unit 3 "B" steam generator
sample isolation valve, located inside containment. This
normally closed valve is a motor operated containment
7
isolation valve that receives an Engineered Safeguards close
signal. A containment entry was made to investigate the
apparent failure to fully open. The investigation revealed
a problem with mechanical binding within the valve.. Given
the recent problems at Oconee with Limitorque valve torque
switches (see IFI 94-11-02), the inspector observed the
troubleshooting efforts to verify that the problem was not
related to the torque switch. The valve was subsequently
closed and its feeder breaker left tagged in the open
position. The licensee indicated that the valve would be
repaired at the next available outage.
(3) Work Order 94012651-01, Repair ES Analog Channel B Jack.
The inspector reviewed the work order and monitored work in
progress during the implementation of this work activity.
The activity was performed per the work instructions and
properly documented on the work order.
(4) Work Order 94040400-01, Implement Minor Mod OE-6668.
The inspector reviewed the work package and monitored work
in progress during the implementation of this work activity.
Minor Modification OE-6668 was implemented to connect the
neutral side of the Engineered Safeguards (ES) unit control
module latch permissive relays (K1 and K2) to AC neutral
instead of instrument ground as previously configured. This
modification was implemented to correct a problem identified
during component ES testing (see paragraph 4.b).
The work
activities observed were performed in accordance with
approved procedures and properly documented in the work
package.
b.
Surveillance activities were conducted with approved procedures
and in accordance with site directives. The inspectors reviewed
surveillance performance as well as system alignments and
restorations. The inspector assessed the licensee's disposition
of discrepancies which were identified during the surveillance.
Surveillance activities observed or reviewed in whole or in part:
(1) Work Order Task 93081903-01, Perform Test On CT-1 Relays.
On May 12, 1994, the inspector reviewed performance testing
of the CT-i relays that are utilized in the electrical power
,transfer to the startup busses upon loss of the normal
feeder busses. The testing was part of the Unit 1 refueling
outage scheduled activities to be performed while the
reactor was defueled. Some minor discrepancies were noted
in the step signoff sequence in that more than one step in
the instructions had been performed prior to the craftsmen
8
signing for the work completion. After the inspector
identified the discrepancy, immediate corrections were made.
(2) Turbine Driven Emergency Feedwater (TDEFW) Pump Cooling
Water Supply Valve Test (PT/3/A/0150/22L).
This quarterly test verifies cooling water supply to TDEFW
pump cooling jackets and oil coolers. The inspector
observed portions of the test conducted on the Unit 3 TDEFW
pump on May 12, 1994.. The test revealed that the stroke
times for 3LPSW-138 (cooling water supply to pump jacket),
and 3HPSW-184 (cooling water supply to pump oil cooler) were
not within the acceptance criteria (1-2 seconds for both
valves). The stroke time observed during this test was 4
seconds for both valves. 3LPSW-138 and 3HPSW-184 are
pneumatically operated valves that are designed to fail open
following a loss of power or loss of instrument air. These
valves are normally closed and are designed to open
automatically following a pump start. As a result of the
slow stroke times, the licensee declared these valves
inoperable per their Inservice Test (IST) program. The
switch that manually controls both valves was subsequently
placed in the bypass position. This failed open both
valves; thereby, establishing continuous cooling water flow
through the pump jacket and oil cooler. The licensee stated
that this arrangement resulted in the TDEFW pump being
operable, despite the valves being inoperable, since the
valves were in their "fail safe" position.
The inspector noted that the licensee did not perform a
10 CFR 50.59 or other formal engineering evaluation for this
abnormal lineup. However, OP/0/A/1102/06, Removal and
Restoration of Station Equipment, was used to remove the
control switch from its normal position. This
required/resulted in an evaluation of the impact on plant
equipment by two licensed individuals, one of which held a
senior reactor operator license. The inspector questioned
whether continuous flow of relatively cool water through the
idle pump and oil cooler might result in increased moisture
in the oil.
Oil samples taken on May 16, revealed that
moisture levels had not increased. The licensee
subsequently performed numerous stroke tests of these valves
to determine if the stroke times were degrading. The.valves
consistently stroked at 2.5 seconds. On May 26, after
changing the stroke time acceptance criteria to 1-4 seconds
the licensee declared the valves operable and restored them
to their normal (closed) status. The inspector concluded
that there was no impact on TDEFW pump operability, nor a
design basis issue associated with extending the stroke time
acceptance criteria.
9
(3) High Pressure Injection (HPI) Pump Run-Out Test
(TT/1/A/251/41).
This temporary test procedure was conducted to verify that
the flow resistance in the HPI system piping was sufficient
to prevent the HPI pumps from reaching a pump run-out
condition when the injection valves were completely open and
RCS pressure was at 0 psig. The normal pump run-out flow
value is 525 gpm, but the licensee has received concurrence
from the pump vendor that flow rates up to 585 gpm are
acceptable if Net Positive Suction Head (NPSH) available is
greater than 30 feet of head. The licensee takes credit for
throttling HPI flow within ten minutes following an accident
to ensure HPI flows are balanced.
The test consisted of running each HPI pump individually and
measuring injection flow and minimum recirculation flow with
the respective HPI valve fully open. Pump vibration data
was monitored throughout the test and if vibration levels
exceeded 0.75 in/sec the pump was to be immediately secured.
The A, B, and C HPI pumps developed approximately 545 gpm,
562.5 gpm and 562 gpm respectively with the injection valves
fully open. Vibration levels remained below 0.75 in/sec.
The inspector noted that the reactor coolant pump seal
injection flow path and the normal makeup flowpath were
isolated during the performance of the test. These
flowpaths would normally be open during an accident and
would decrease system resistance in the A injection header
and would affect the pump run-out flows for the A and B HPI
pumps. This item was discussed with the accountable
engineer and he stated that the test was for data
acquisition and that the possible affect on delivered flow
would be reviewed by Design Engineering. The inspectors
plan to review this item further after the licensee
evaluation is completed. This is identified as Inspector
Followup Item 269/94-16-04: HPI Pump Run-out Flow Testing.
The inspectors reviewed the test procedure and witnessed the
entire testing sequence for all three HPI pumps. The
licensee plans to perform this special test on both Units 2
and 3 during the next scheduled refueling outages.
(4) SSF Service Water Test with ASWP, HVAC Pump, and DESWP
Running Simultaneously (TT/O/A/600/12).
The purpose of this temporary test procedure was to
demonstrate and document the ability of the Safe Shutdown
Facility (SSF) service water piping to provide adequate
suction pressure and flow while the SSF auxiliary service
water pump (ASWP), SSF HVAC pump, and diesel engine service
water pump were running simultaneously. The test was
conducted with the Unit 2 Condenser Circulating Water (CCW)
system in service and supplying suction to the SSF service
water systems. Under SSF conditions the Unit 2 CCW system
would not be operating. Discussions with the system
engineer determined that plans were being established to
reperform this test during the next Unit 2 refueling outage
when the CCW system could be secured so that actual system
conditions could be verified.
The procedure established a minimum suction pressure of 5
psig for the ASWP and the DESWP, and 2 psig for the HVAC
pump. The minimum suction pressure observed during the test
was 21.8 psig. The inspectors reviewed the test procedure
and witnessed the performance of the entire test.
(5) Turbine Stop Valve Movement (PT/O/A/290/04).
This is a monthly test to verify the proper operation of the
Main Steam Stop Valves (MSSVs) and Intercept Valves. The
inspector observed the test for Unit 3 conducted on May 19,
1994.
No discrepancies were noted.
No violations or deviations were identified. One IFI was identified
regarding the system lineup during a HPI pump run-out test.
4.
Onsite Engineering (37551)
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.
a.
Design Basis Documentation Issues Associated With Reactor Building
Spray.
On Mayp17, 1994, the inspector observed the Reactor Building Spray
(RBS) pump test (PT/3/A/0204/O7) for Unit 3.. As part of this
activity the inspector reviewed various design basis documents to
evaluate how well this test verified that the RBS system performed
its design basis functions. The inspector noted that Section
6.1.3 of the Oconee Final Safety Analysis Report (FSAR) stated, in
part, that the NPSH available to the Low Pressure Injection and
RBS pumps during the post-LOCA recirculation phase has been
calculated based on three feet of level remaining in the BWST at
time of switchover, and water level in the Reactor Building of 6.5
feet above basement level.
It further indicated that based on the
6.5 foot water level, there would be 19.8 feet of NPSH available
to the RBS pumps (only slightly greater than the pump
manufacturers required NPSH of 17.0 feet)..
the inspector noted that this conflicted with step 14.0 of section
CP-601 of the Emergency Operating Procedure (EOP) which instructed
the operators to swap RBS suction to the Reactor Building
Emergency Sump when BWST level was less than 6 feet, and RB level
was greater than 3.5 feet. The licensee's Design Basis
Specification for the Reactor Building Spray System (OSS-0254.00
00-1034) also stated that the minimum reactor building level
setpoint was 3.5 feet.
When questioned about the apparent discrepancy between the FSAR
and the EOP, the licensee stated that the information in Section
6.1 of the FSAR was inaccurate, and that it would be corrected
during the next update to the FSAR.
In responding to the inspector's questions regarding the basis for
the EOP's guidance for swapover (BWST level < 6 ft, and RB level >
3.5 ft), the licensee provided OSC-2820, Emergency Procedure
Guideline Setpoints, which indicated that a reactor building level
of at least 3.75 feet was necessary to ensure adequate RBS pump
NPSH. This was different from both the EOP & DBD (3.5 ft) and the
FSAR (6.5 ft).
In fact, revision 3 to OSC-2820, dated July 17,
1989, specifically changed the setpoint for swapover from 3.5 to
3.75 feet. Both the licensee and the inspector were unclear as to
what the actual requirement was for minimum sump level to ensure
adequate NPSH for the RBS pumps, or if the EOP guidance was
adequate. Shortly thereafter, the licensee concluded that the
current EOP guidance was acceptable due to the fact that an
injection of BWST water into the RB which reduces BWST level below
6 feet, assuming an initial level of at least 46 feet (TS
requirement), would ensure at least 5 feet of RB water level.
Based on independent calculations, the inspector agreed with this
assessment for immediate EOP acceptability. However, the
inspector was concerned that a revision to the licensee's
procedure for EOP setpoints which specifically changed a setpoint
was not incorporated into the EOP, and that this was not realized
by the licensee until questioned by the NRC approximately 5 years
later.
Given the many conflicting references, the inspector concluded
that there were shortcomings in the licensee's program for
maintaining their design basis documentation for the RBS system.
The licensee should determine the actual minimum RB water level
necessary to ensure adequate NPSH for the RBS pumps, and adjust
their documentation accordingly.
b.
Engineered Safeguards (ES) Wiring Discrepancies
On May 20, 1994, during the performance of ES functional testing
on valves 1PR-8 and 1PR-10 the licensee found that with an ES
signal present, manual control of the valves could not be achieved
using the manual pushbutton on the RZ module located on the
vertical board in the control room. The ES testing of 1PR-8 and
1PR-10 was being conducted as part of a post modification test
requirement for minor modification OE-6338. The licensee reviewed
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all wiring changes performed per the minor modification and
determined that the inability to take manual control from the RZ
module under ES conditions was not related to the implementation
of the minor modification. A troubleshooting work order was
initiated to identify and correct the problem.
Subsequent investigation by the licensee determined that the
manual control relays inside the ES cabinets' unit control modules
were connected to the instrument ground system and that the
electrical circuit for manual control after an ES actuation relied
on the instrument ground system, through the station ground
system, through the regulated power panelboard 1KRA neutral
conductor, to the 120 volt vital power inverters' neutral
conductor. The Unit 1 vital inverters and manual bypass switches
had been replaced earlier in the current outage per modification
NSM-ON-12881. This modification had replaced the single pole
bypass switch with a double pole bypass switch. The double pole
design switches both the hot wire and the neutral wire between the
vital inverter and the regulated power supply, whereas the old
single pole switch only switched the hot wires and a common
neutral was maintained between the vital inverters and the
regulated power supply. With the vital inverters in service
following the vital inverter modification, the electrical circuit
for manual control following an ES signal was defeated. The
licensee plans to modify the Unit 1 Engineered Safeguards
electrical circuitry to correct this deficiency prior to
completion of the Unit 1 refueling outage. The licensee planned
to connect the manual control relays to the vital 120 VAC neutral
wire to ensure that an electrical circuit could be achieved.
The licensee performed an operability evaluation on the present
Unit 2 and 3 Engineered Safeguards systems. The Unit 2 and 3
systems still contained single pole bypass switches and relied on
a common neutral wire, instrument ground system, and station
ground system to establish an electrical circuit. The instrument
ground system, station ground system, and regulated power supply
system were not considered safety-related and the electrical
circuit relied on a common electrical cable in several locations
to maintain an electrical circuit for manual control of ES
components following an ES actuation.
The licensee determined that the Unit 2 and Unit 3 ES systems were
operable based on the fact that the grounding system was a passive
system and no credible single failure could be postulated for any
design basis events.. The licensee's operability evaluation was
13
still under NRC review at the end of the inspection period and is
identified as Unresolved Item 269,270,287/94-16-03: Engineered
Safeguards Wiring Discrepancies.
No violations or deviations were identified. One Unresolved Item
regarding Engineered Safeguards neutral and ground wiring arrangements
was identified.
5.
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 following areas were reviewed:
a.
Combustible Material In The Reactor Buildings
The inspectors toured the Unit 1 reactor building on May 5, 1994,
during the refueling outage. At this time, less than 100 bundles
of fuel had been removed from the reactor core. The inspectors
noted that large amounts of non-flame retardant plastic had been
used to cover equipment and other plant items for protection
during containment decontamination and had remained after
decontamination was completed. In addition, it was noted that
rolls of the plastic material were stored in the building and
there was no apparent control over the location or amount allowed.
A violation (VIO 287/93-31-03) was issued by the NRC for use of
non-fire retardant plastic in the Unit 2 penetration room in
December 15, 1993. The use of this material in the unit 3 Reactor
Building was questioned during the previous Unit 3 refueling
outage and the inspectors learned that fire loading in the Reactor
Building was not addressed in the site directives. As a result,
Oconee Nuclear Site Directive 3.2.7, Control Of Combustible
Materials, was revised. Step 12.7 of the revised directive
addressed specific areas of the Reactor Building necessary for
cables and equipment important for decay heat removal and required
that the Reactor Building Coordinator or designee monitor and
control the use of combustibles in those areas through periodic
inspections.
Although the directive did not limit the use of combustible
materials in the Reactor Building, or require an evaluation for
the use of this material, the licensee agreed that the amount
appeared excessive and the fire loading was reduced to a much
lower level.
b.
Maintenance Chemicals With Wintergreen Odor
The inspector detected the smell of wintergreen during a tour of
the turbine building on May 12, 1994. Wintergreen odor is
utilized in the Carbon Dioxide and Halon fire protection systems
at Oconee to alert personnel in those areas of an actuation of the
14
system. After the inspector exited the area and notified the
control room of the odor, he learned that plant maintenance
utilized a chemical with this odor to assist in loosening bolts.
The inspector questioned the use of this chemical for maintenance
activities given that the licensee plant systems training course
emphasized the specific use of wintergreen in the carbon dioxide
and halon fire protection systems as a warning device for system
activation. The licensee agreed that the use of chemicals with
wintergreen odor for other than fire protection would defeat the
original purpose for detecting a carbon dioxide or halon release.
The licensee subsequently discontinued the use of wintergreen odor
in the plant with the exception of the fire protection system.
No violations or deviations were identified.
6.
Review of Licensee Event Reports (92700)
The below listed Licensee Event Reports (LER) were reviewed to determine
if the information provided met NRC requirements. The determination
included: adequacy of description, compliance with Technical
Specification and regulatory requirements, corrective actions taken,
existence of potential generic problems, reporting requirements
satisfied, and the relative safety significance of each event. The
following LER is closed:
a.
(Closed) LER 270/93-04, Emergency Feedwater Required Technical
Specification Surveillance Interval Exceeded Due To Management
Deficiency.
The licensee identified that the required surveillance for the
initiating circuitry for the Unit 2 Motor Driven Emergency
Feedwater (MDEFW) pumps had not been performed in the time
interval required by the Technical Specification.
The problem was
identified on August 23, 1993,' with the unit at 100 percent power.
The time allowed by the surveillance had been exceeded by 28 days.
As a result, the surveillance was immediately performed with
satisfactory results.
The licensee determined that the deficiency had occurred as a
result of placing the surveillance in the "suspend" mode at the
time the test was due. It was further determined that the
personnel involved believed that once the test was in the suspend
mode, the computer program would reschedule the test prior to
exceeding the Technical Specification time limit. However, the
program did not have this feature, and therefore,' the surveillance
was not rescheduled. This resulted in the failure to perform. the
work within the required time period with a 28 day over-run.
The licensee's corrective action was to revise Maintenance
Directive 7.3.6, Preventative Maintenance Program, step 5.5.4,
Suspending Or Deferring a Predefined Work Order, -to require an
15
engineering evaluation for suspending work orders that cannot be
performed within the allowable time frame.
The inspectors reviewed the licensee's documentation that the
surveillance was performed, reviewed the revised Maintenance
Directive, and verified that the commitment was properly
implemented.
No violations or deviations were identified.
7.
Exit Interview
The inspection scope and findings were summarized on June 2, 1994, with
those persons indicated in paragraph 1 above. The inspectors described
the areas inspected and discussed in detail the inspection findings
addressed in the summary and listed below. The licensee did not
identify as proprietary any of the material provided to or reviewed by
the inspectors during this inspection.
Item Number
Description/Reference Paragraph
50-269/94-16-01
Apparent Violation:
Failure to Follow
Refueling Procedures -
two examples
(paragraph 2.c).
50-287/94-16-02
Violation: Failure to Follow Procedure
Results in Inadvertent Dilution of the RCS
(paragraph 2.,d).
50-269,270,287/94-16-03
Unresolved Item:
Engineered Safeguards
Wiring Discrepancies (paragraph 4.b).
50-269/94-16-04
Inspector Followup Item:
HPI pump run-out
flow testing (paragraph 3.b.(3)).