ML15118A198
| ML15118A198 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 04/21/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A196 | List: |
| References | |
| 50-269-97-01, 50-269-97-1, 50-270-97-01, 50-270-97-1, 50-287-97-01, 50-287-97-1, NUDOCS 9705080200 | |
| Download: ML15118A198 (30) | |
See also: IR 05000269/1997001
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269, 50-270, 50-287, 72-04
License Nos:
DPR-38, DPR-47, DPR-55, SNM-2503
Report No:
50-269/97-01, 50-270/97-01, 50-287/97-01
Licensee:
Duke Power Company
Facility:
Oconee Nuclear Station, Units 1, 2 & 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
February 9 - March 22, 1997
Inspectors:
M. Scott, Senior Resident Inspector
G. Humphrey, Resident Inspector
N. Salgado, Resident Inspector
D. Billings, Resident Inspector
C. Rapp, Reactor Inspector (Section E3.1)
Approved by:
C. Casto, Chief, Projects Branch 1
Division of Reactor Projects
Enclosure 2
9705080200 970421
PDR ADOCK 05000269
G
.PDR
EXECUTIVE SUMMARY
Oconee Nuclear Station. Units 1, 2 & 3
NRC Inspection Report 50-269/97-01,
50-270/97-01. 50-287/97-01
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a six-week
period of resident inspection: in addition, it includes the results of an
announced inspection by one regional inspector.
Operations
On February 12. Unit 1 returned to power operation with an
elevated vibration level on the 1A1 Reactor Coolant Pump (RCP)
that was analyzed to be acceptable for an interim period.
Management and controls for the startup were adequate. Problems
during the startup and power escalation were appropriately
addressed by the licensee. (Section 01.2)
On February 26, while in refueling conditions, Unit 3 experienced
a loss of Reactor Coolant System (RCS) inventory to the Letdown
Storage Tank (LDST). Core cooling was not jeopardized. The loss
was due to a valve mispositioning that is identified as a third
example of a previous violation (VIO 269,270.287/96-17-06) for
which corrective action had yet to be completed. (Section 01.3)
On March 6, Unit 3 achieved criticality after a 160 day refueling
outage. No problems were identified during the observation of the
criticality evolution or during low power physics testing.
Performance by Operations personnel was thorough and professional,
and Reactor Engineering provided appropriate guidance. (Section
01.4)
On March 21. the Unit 3 reactor tripped from approximately 70%
power. The unit trip recovery was well controlled by the reactor
operators. The post trip report was thorough and accurately
reflected the root cause of the trip. A procedural weakness was
identified in that Procedure IP/0/A/0305/014-1 did not include any
steps for ensuring that fuses were not open in the reactor trip
confirm circuitry. An Inspector Followup Item (IFI) was
identified to followup on the licensee's inspection of the Unit 1
and Unit 2 Reactor Trip Confirm Circuits to ensure proper fuse
installation/sizing. (Section 01.5)
Although .some water/steam hammers were noted during the Unit 3
startup, the licensees efforts were effective in minimizing this
problem. The automated control system performed well and
eliminated the need for manual operation of the valves with the
unit operating at power; and thereby eliminating the personnel
hazards involved with the manual operation. (Section 01.6)
Enclosure 2
2
Maintenance
The inspectors concluded that the general Maintenance and
Surveillance activities observed were completed thoroughly and
professionally. (Section M1.1)
The licensee adequately identified and corrected an incorrectly
assembled emergency feedwater pump turbine steam admission valve.
Post modification testing was pending due to the unit status.
(Section M8.3)
A violation was identified in which Maintenance personnel did not
comply with the requirements of a valve repair procedure while
working on multiple Appendix "R" valves.
(Section M8.1)
Engineering
As part of the licensee's Generic Letter 96-06 activities, a
special Low Pressure Service Water (LPSW) test was adequately
performed with good engineering cooperation and support. The
results were acceptable and provided the licensee a better
understanding of plant response in Loss of Offsite Power
.(LOOP)/Loss of Coolant Accident (LOCA) conditions.
(Section E1.1)
The inspectors concluded that Unit 3 Integrated Control System
(ICS) testing (two sections of TT/3/B/0326/001 and all of
TT/3/B/0326/002) was satisfactorily performed in accordance with
the licensee's test procedures, and that deficiencies identified
during the testing were resolved appropriately. Control of all
test activities was considered good. Positive observations were
made.relating to test briefings, control room briefings, and
communication and coordination of the test evolutions.
(Section
E1.2)
Post validation and verification changes to Unit 3 ICS software
resulted in an error being introduced. This occurrence resulted
in a minor plant perturbation but was discovered in the system
testing phase. The occurrence was considered a substantial
weakness in the overall ICS modification process. An IFI was
initiated to.follow the corrective actions associated with this
occurrence, which will take place during planned ICS modifications
on the other two units.
(Section E3)
As a fallout from the licensee's Generic Letter 96-06 evaluation
efforts, two 10 CFR 50.72 reports were made this period. One
concerned the water hammer susceptibility of LPSW piping to the
Reactor Building Cooling Units. The other involved the potential
for thermal pressurization making the active boron dilution flow
path valves inoperable. The inspectors assessed the compensatory
Enclosure 2
3
actions taken and identified two Unresolved Items with respect to
each issue. (Section E8.2)
Plant Support
An unresolved item was identified in which the licensee did not
meet the requirements of 10 CFR 70.24, Criticality Accident
Requirements. (Section R2.1)
Enclosure 2
Report Details
Summary of Plant Status
Unit 1, which had been shutdown in early October 1996 for secondary piping
of inspections and water hammer.modifications, was tied to the grid on
February 12, 1997. It subsequently operated at or near full power throughout
the rest of the reporting period.
Unit 2 operated at or near full power throughout the reporting period.
During this inspection period the licensee completed the Unit 3 End of Cycle
16 refueling outage. The outage length was 160 days. The principal causes
for the extension of the outage were secondary piping inspections and water
hammer reducing modifications. Unit 3 achieved criticality on March 6. 1997,
and increased power to specified power levels for Integrated Control System
(ICS) testing. While holding at 70%.power for ICS testing on March 20, 1997,
the unit tripped. It was subsequently restarted on March 21, 1997.
Review of UFSAR Commitments
While performing inspections discussed in this report, the inspectors reviewed
the applicable portions of the Updated Final Safety Analysis Report (UFSAR)
that related to the areas inspected. The inspectors verified that the UFSAR
wording was consistent with the observed plant practices, procedures, and/or
parameters.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure 71707, the inspectors conducted frequent
reviews of ongoing plant operations. In general, the conduct of
operations was professional and safety-conscious. Specific events and
noteworthy observations are detailed in the sections below.
01.2 Unit 1 Startup
a. Inspection Scope (93702, 71707).
The inspectors observed various phases of the Unit 1 return to power
operations and attended associated pre-job briefs for each major
evolution.
b. Observations and Findings
Unit 1 was connected to the electrical grid on February 12, without any
major problems. The secondary experienced a few minor water hammers
Enclosure 2
2
that were observed, in part, by the inspectors. These minor water
hammers were similar to those previously experienced by Unit 2. which
had recently also returned from outage conditions with a modified
secondary. The licensee captured the occurrences within their
corrective action program. As with Unit 2 (see Inspection Report 96
20), the licensee's engineering staff observed and evaluated the plant
secondary as it went through power transition. Procedure changes
associated with equipment changes, equipment and piping changes
themselves, and operator training had occurred prior to the restart.
The 1A1 Reactor Coolant Pump (RCP) vibrations, that were elevated during
preparations for startup, persisted into normal power operations.
Vibration levels were evaluated by the licensee and reviewed by the
inspectors prior to any power escalation. The mis-alignment vibration
which was due to transitional change in pump parametric performance was
understood and appropriately documented in a 50.59 evaluation and
Problem Identification Process (PIP) Report 1-97-568. The evaluation
recognized that the running of the pump would be limited and Unit 1
would be shutdown for repair of the RCP after Unit 3 was at power, which
was initially scheduled for March 14, and then rescheduled for March 28.
1997.
Control rod drop times prior to returning to power operations were
observed and found to be acceptable with three control rod drop times
slightly exceeding the licensee's refueling outage restart
administrative limit. The licensee evaluated the condition and, in
light of the remaining core life fuel/operational time, the licensee
considered them acceptable.
c. Conclusions
Management and controls for the Unit 1 startup were adequate. Problems
encountered during startup and power escalation were appropriately
handled.
01.3 Valve 3HP-5 Mispositioning
a: Inspection Scope (93702)
During the inspection period, Unit 3 had a loss of Reactor Coolant
System (RCS) inventory event. The inspectors were alerted to its
occurrence by the licensee and followed the details of the
investigation.
b. Observations and Findings
While returning from Unit 3 outage conditions on February 20, Operations
performed Enclosure 3.7, Procedure for Establishing Low Pressure
Injection (LPI) Purification, of OP/3/A/1104/04, Low Pressure Injection
Enclosure 2
System. Step 2.2 of the Enclosure. Purification Lineup, verified that
Valve 3HP-5 (first letdown isolation valve off the RCS) was closed.
On February 26. the RCS was at 40 psig on a pressurizer nitrogen bubble
with RCS temperature at 108 degrees F. Further into the preparation for
return to power operations, the High Pressure Injection (HPI) system was
being aligned for return to service in accordance with OP/3/A/1104/02,
High Pressure Injection System, Enclosure 5.1, HPI System Startup. Step
2.3 of that enclosure opened 3HP-78, Letdown Storage Tank (LDST) Inlet
Stop Check. When this valve was opened, approximately 720 gallons of
water from the RCS (as indicated by pressurizer level drop)
inadvertently flowed into the LDST before being identified and isolated
by Operations personnel. The flow persisted from 3:19 to 4:30 a.m. when
Valve 3HP-5, had been discovered opened and was closed. Venting of the
HPI pumps was also in progress at the time. Pressurizer level went from
105 inches to 76 inches.
The amount of water removed from the RCS did
not challenge Decay Heat Removal (DHR) capability. Within approximately
20 minutes Operations made up to the RCS to partially refill the
pressurizer to a level greater than existed before to the event (120
inches)..
The LDST level went up from 83 inches to 100 inches (the maximum tank
level). LDST pressure reached a maximum of approximately 50 psig which
was well below the setpoint of LDST relief Valve 3HP-79. It was also
noted that the volume in the Bleed Holdup Tank (relief valve discharge
point) did not change.
On February 26, prior to opening 3HP-78, an operator had performed step
2.1 of Enclosure 5.1 (OP/3/A/1104/02) that directed the operator to
"Complete the following check lists".
Enclosure 5.15 of Procedure
OP/3/A/1104/02, which was contained in/listed under step 2.1, checked
Valve 3HP-5 closed. Enclosure 5.15 was last completed in the December
10 - 20, 1996, time frame. No procedural guidance had been provided to
the operators regarding valve checklist performance frequency. Normal
Operations' practice was that if the list had been performed the same
post outage time period, no repetition of list performance need occur
since the licensee's system removal and restoration tagout process would
be used to maintain system configuration control. The operator
performing Enclosure 5.1 knew that Enclosure 5.15 had been performed in
December and he believed that was sufficient information to proceed with
the system startup lineup.
After the Unit 3 RCS inventory loss to the LDST, Operations re-performed
a number of Emergency Core Cooling System (ECCS) valve checklists. None
of the re-checks identified any of the valves out of position. A
computer historical data base on plant valve position indicated that
3HP-5 was opened in lieu of being closed as required during performance
of Procedure OP/3/A/1104/04, Enclosure 3.7 on February 20.
Enclosure 2
4
The above misposition event, in conjunction with those previously
identified in Violation 50-270/96-17-06 and Non-Cited Violation 50
269/96-13-01, indicates .a
potential negative trend in valve
mispositioning problems. The licensee, who had reached the same
conclusion regarding the negative trend, had yet to complete the
corrective'actions indicated in their response to Violation 50-270/96
17-06 (dated February 26, 1997).
Paragraph 3 of the response indicated
that actions would be continuing under a licensee's Continuous
Improvement Team. The licensee recently formed a Continuous Improvement
Team to evaluate the problem and the inspectors have been tracking the.
actions of Operations and the team. The licensee has elicited response
from the operators and is drafting additional procedural guidance on
configuration control.
Continuing future actions for valve
configuration during Maintenance is also addressed in the violation
response. Accordingly, as these 'corrective actions are still underway,
this most recent mispositioning event will be dispositioned as another
example of a cited violation 50-270/96-17-06, Failure to Maintain
Configuration Control.
c. Conclusions
The licensee had a recent significant mispositioning event that
persisted for some period of time prior to the control room staff
discovering it. This situation was mollified by plant conditions (low
RCS pressure) and LDST status (intact with its relief valve functioning
as required). The event follows on the heels of a previous event
similar in nature and corrective action. The licensee has responded to
these configuration control issues and was taking actions to address a
potential negative trend.
01.4 Unit 3 Startup Activities
a. Inspection Scope (71707)
The inspectors observed the Unit 3 startup evolution to assess control
room operations and operator decorum.
b. Observations and Findings
On March 6, at 1:30 p.m., the inspector attended the pre-job briefing on
the startup evolution conducted by the Operations Shift Manager (OSM)
and the lead reactor engineer. Procedure OP/3/A/1102/01, Controlling
Procedure For Unit Startup, provided the guidance for the unit startup.
The inspector concluded that the briefing was conducted thoroughly with
appropriate emphasis on safety.
On March 6, 1997, Unit 3 achieved criticality. It was noted that a
trainee withdrew the control rods under appropriate supervision.
Reactor engineers, performing 1/M plots after the withdrawal of the
first four banks of control rods, interfaced with operations during the
0
Enclosure 2
5
control rod withdrawal evolution. The frequency of the 1/M plots
increased as the unit was approaching criticality. Reactor Engineers
then performed 0% power physics testing, which did not identify any
problems.
Due to several Integrated Control System (ICS) questions that were
raised during the low power ICS tuning, the licensee decided to evaluate
the need to make a design change to the new ICS modification (see
Section E3.1).
Power escalation was held at approximately 70% power for
ICS tuning on March 20, at which time Unit 3 experienced a reactor trip
during Reactor Protection System (RPS) Testing (see Section 01.5).
c. Conclusion
The inspector concluded that the restart of Unit 3 was conducted
thoroughly and professionally by Operations personnel. Reactor
engineering personnel provided appropriate guidance as necessary.
01.5 Unit 3 Reactor Trio
a. Inspection Scope (93702)
The Unit 3 reactor tripped from approximately 70% power on March 20,
1997, at 9:12 a.m..
The inspector was in the control room immediately
following the reactor trip and observed operator responses. The
inspector also reviewed the post trip report, procedures, and applicable
PIPs.
b. Observations and Findings
Prior to the unit tripping, the licensee was performing Procedure
IP/0/A/0305/014-1., RPS Control Rod Dri*ve Breaker Trip and Events
Recorder Timing Test. The licensee had completed testing Control Rod
Drive (CRD) breaker 10, and had returned RPS Channel A to its normal
state. When RPS Channel B was placed in manual bypass for testing. CRD
breaker Number 11 was tripped and the reactor trip subsequently
occurred. The licensee's post investigation determined that the cause
of the trip was due to an electrical short to ground which occurred in
the circuit associated with Relay K3 in the Reactor Trip Confirm A
logic. The licensee discovered the short at electrical connector J2 of
the Electronic Trip Enclosure in the CRD Group 5 regulating power-supply
cabinet. Threads on a screw which secured a clamp at the back of the
electrical connector had cut into the insulation of one of the wires
entering the connector. This was original Oconee installed equipment.
When the electrical short to ground occurred (measured later at 0.6 ohms
to ground), sufficient fault current existed to open Fuse F3. This
nonsafety-related fuse provides branch circuit protection for the K3
relay circuit and isolates a fault in this circuit.
When the fault
occurred, the fuse performed its intended function by opening to isolate
this fault.
The result was that Relay K3 de-energized, which provided a
Enclosure 2
6
trip signal to the reactor trip confirm A logic circuit.
Channel A trip
confirm generated a generator backup lockout which opened the generator
breakers PCBs 58 and 59. This caused a turbine trip due to power/load
unbalance which caused a reactor trip.
Post trip response was normal with the exception of the loss of 3X1 and
3X3 nonsafety-related switchgear. Following the trip, load center 3X1
and 3X3 feeder breakers opened. The licensee's investigation found that
the reactor trip confirm signal tripped the generator breakers, but not
the generator. The generator was tripped 0.75 seconds later after a
backup timer timed out and energized the shutdown lockout relay. This
caused a power transfer which allowed the undervoltage relays for 3X1
and 3X3 to operate and trip the load centers. All equipment operated as
designed. The licensee generated PIP 3-097-1013 to evaluate the time
setting for the backup timer.
The licensee discovered that the F3 fuse opening and the K3 relay de
energization were not alarmed to any type of remote indication. The
only indication of this is a "blown-fuse" indicator on the F3
fuseholder. 'This indicator would normally illuminate if the fuse was
blown. These fuses are located inside a cubicle located above the AC
Reactor Trip Breaker cabinets which were not normally observable. The
blown-fuse indicator, a light, associated with fuse F3 was also non
functional and in the same cubicle. These conditions could have existed
since the completion of the last performance of Procedure
IP/0/A/0305/014-1 on February 20, 1997.
The procedure for performing the testing did not include any steps for
ensuring that no fuses were open in the reactor trip confirm circuitry.
This was identified as a procedural weakness. Steps will be added to
the procedures (Units 1, 2, and 3) for reactor trip breaker testing to
ensure that visual inspections for blown fuses in the reactor trip
confirm circuitry will be made prior to initiating any testing-related
breaker trips.
An additional item observed during the investigation involved
discrepancies with the fuses installed in the redundant trip confirm
circuitry. The licensee initiated PIP 0-097-1014 to resolve these
discrepancies. It was noted that two vendor drawings which show these
nonsafety-related (but important to safety) fuses are in disagreement as
to the proper fuse size for fuses F1-F4. One drawing showed them to be
0.5 Amp(A) fuses and the other drawing showed them as 0.25A slow blow
fuses. It was determined that the 0.25A fuses were the correct size.
The licensee will revise the vendor drawings to show the correct fuse
sizes in the near future. It was also noted that the fuses installed in
the field were not the correct size. Of the eight fuses installed, six
of them were 1.OA fuses and two were 0.5A fuses. The licensee
determined that the larger size fuses would have adequately protected
the circuitry. The licensee will conduct an inspection of Unit 1 and 2
Reactor Trip Confirm circuit fuses to ensure that the correct fuses are
Enclosure 2
7
installed at the next available opportunity. Inspector Followup Item
(IFI) 50-269,270/97-01-01, Reactor Trip Confirm Circuit Fuse Inspection,
will be used to follow this issue.
The unit trip recovery was well controlled by the reactor operators. A
four-hour non-emergency 10 CFR 50.72 notification was made in a timely
manner by the licensee. Unit 3 remained at hot shutdown during the
investigation process. The inspector reviewed the licensee's trip
report and attended the Plant Operating Review Committee meeting for
evaluating the trip and authorization for restart.
The unit was restarted on March 21. 1997, with no noted problems.
c. Conclusions
The Unit 3 trip'recovery.was well controlled by the control room
operators. The post trip report was thorough and accurately reflected
the root cause of the trip. A procedural weakness was identified in
that Procedure IP/0/A/0305/014-1 did not include any steps for ensuring
that fuses were not open in the reactor trip confirm circuitry. Because
of the incorrect sized fuses found in Unit 3, an IFI was identified to
followup on the licensee's inspection of the Unit 1 and 2 Reactor Trip
Confirm Circuits.
01.6 Unit 3 Heater Drain System Modifications
a. Inspection Scope
Review of the Unit 3 modified heater drain system and operating
procedure revisions for plant startup and operation.
b. Observations and Findings
The inspector reviewed the implementation of the Unit 3 modified heater
drain system and associated equipment that was modified per NSM ON
32941. The modification was a result of a water/steam hammer incident
that caused a steam drain pipe rupture in Unit 2 on September 24, 1996.
All three of the Oconee units were modified as a result, in an attempt
the eliminate water/steam hammers in the system. Post modification
testing was performed during unit restart. A problem report. PIP 0-096
2420, was generated to document and track recommendations based on the
investigation and analysis of the steam line break and track the issues
until corrective actions were completed. The modifications and
procedure upgrades have been completed on all three units and Units 1
and 2 were returned to service at earlier dates.
Approximately 25 procedures were revised for each unit. The inspectors
performed a random sampling of the procedures that were initiated or
revised due to the modifications. This review was performed for each
unit prior to restart and included administrative controls for procedure
Enclosure 2
8
changes such as administrative hold instructions. It also involved
verifying that the latest procedure/revision had been placed in.the
control room for operator use.
A walkdown of the plant steam reheat and drain system was performed by
the licensee's engineers and the inspectors during the Unit 3 restart.
Some water hammers were noted during startup of the main turbine, which
was similar to those noted during the restart of Units 1 and 2. PIP 3
097-0922, was generated to document the issue and specify corrective
actions. The corrective actions require some minor modifications and
procedure revisions to further refine the secondary system operation on
all three units.
c. Conclusions
Although some water/steam hammers were noted during the plant startup,
the licensees efforts were effective in minimizing this problem. The
automated control system performed well and eliminated the need for
manual operation of the valves with the unit operating at power: and
thereby eliminating the personnel hazards involved with the manual
operation.
02
Operational Status of Facilities and Equipment
02.1 Engineered Safety Feature System Walkdowns
a. Inspection Scope (71707)
The inspectors used Inspection Procedure 71707 to walkdown accessible
portions of the following safety-related systems:
Keowee Hydro Station
Unit 3 HPI System.
Unit 1 and 3 Low Pressure Service Water (LPSW) System
Unit 1, 2 and 3 Penetration Rooms
Unit 1, 2 and 3 Condenser Circulating Water (CCW) Pump and Intake
Structure
Unit 1, 2 and 3 Electrical Equipment Rooms
b. Observations and Findings
Equipment operability, material condition, and housekeeping were
acceptable in all cases. Several minor discrepancies were brought to
the licensee's attention and were corrected. The inspectors identified
no substantive concerns as a result of these walkdowns.
On February 25, 1997, the inspectors conducted a safety inspection of
the Unit 3 Reactor Building (RB) prior to the Unit startup. The
inspectors performed an inspection of the Unit 3 RB after Quality
Assurance (QA) had performed their final walkdown. Several minor
Enclosure 2
9
discrepancies were identified to the licensee for resolution. The items
were evaluated prior to the Unit 3 startup and resolved as necessary.
05
Operator Training and Qualification
05.1 Unit 3 Integrated Control System (ICS) Training
a. Inspection Scope (71707)
On February 15, 1997, the inspector attended the classroom portion of
the operator training provided on TT/3/B/0326/001, ICS/NNI Transient
Testing at Power: ICS/NNI System Upgrade, NSM ON-32989/AL1 and
TT/3/B/0326/002, ICS Loss of Power Testing at 25% Reactor Power: ICS/NNI
System Upgrade, NSM ON-32989/AL1.
b. Observations and Findings
The training. was provided to one reactor operator and one senior reactor
operator from each shift, with all shifts being represented. The
terminal objective of the "just in time" training was to demonstrate the
ability to perform TT/3/B/0326/001, and TT/3/B/0326/002 in accordance
with the applicable guidelines of each of these procedures. The
operators questioning attitude led to numerous changes to both draft
procedures. The training included performing the procedures on the
simulator, including taking actions as necessary per contingency plans.
c. Conclusions
The inspector concluded that the "just in time" training was conducted
thoroughly and professionally. The operators' questioning attitude led
to numerous changes to both draft procedures.
08
Miscellaneous Operations Issues (92901)
08.1
(Closed) Licensee Event Report (LER) 50-269/95-001-00:
Potential
Unanalyzed Main Steam Line Break Scenario
The circumstances described in this voluntary LER were documented in
Inspection Report 50-269,270,287/95-01 and were to be tracked by
Deviation 269,270,287/93-31-01. The subject deviation was closed in IR
50-269,270,287/95-09; therefore, this LER is closed.
Enclosure 2
- 10
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (61726, 62707, 92902)
The inspectors observed all or portions of the following maintenance and
surveillance activities:
OP/1/A/1106/02
Enclosure 3.17 Taking 1B Feedwater Pump Turbine
(FWPT) Off Hand Jack
PT/1/A/600/12
Turbine Driven Emergency Feedwater Test
PT/O/A/0300/01
Control Rod Drive Trip Time Testing
WR # 97007993:
I/R U-1 Bias Control on 1B FDW Pump
TT/2/B/027/012
Controlling Procedure for NSM 22941 for Testing
& Tuning Controllers Associated With 2MS-112,
2MS-173, 2HD-92, 2HD-95, 2HD-37, 2HD-52.
TT/3/A/025/63
LPSW Flow Test
0II)OP/0/A/1105/09
Recovery of a Dropped/Misaligned*Safety Control
Rod, Enclosure 14.9
TT/3/A/160/19
Start 3A Reactor Building Cooling Unit (RBCU) in
Fast Speed
IP/.0/A/0100/001
Attachment 1. Trouble Shooting Plan, ICS Testing
Procedure
0
TT/3/B/0326/001
ICS/NNI Transient Test at Power
0
OP/3/A/1106/06
Enclosure 3.2, Emergency Feedwater Pump Turbine
Overspeed Test
0
IP/0/A/4980/027G ITE 27N Relay Test
0
PM Yellow Bus Degraded Grid UV Relay 27YBDGX
Perform the #3 Main Steam Relief Valve (MSRV)
Setpoint Pop Test
OP/0/A/1106/19
Keowee Hydro At Oconee, Enclosure 3.6,
Operabili.ty Verification
Enclosure 2
11
Perform Mulsifyre System Annual "Wet" Test
Unit 2., RPS A. B, C. D CRD Breaker Test
IP/0/A/2005/003
Keowee Hydro Station - Westinghouse WTA Voltage
Regulator Test
OP/3/A/1006/01
Enclosure 3.18, Turbine Overspeed Testing During
Startup
Unit 1. Reset RPS HI Flux Trip Set Point To
104.75%
Unit 2, RPS A, B, C. D CRD Breaker Test
Unit 2, Assist In Tuning HD/MSRH Drain Tank
Levels
Unit 3, RPS A, B. C, D CRD Breaker Test
Unit 3. Replace Pressure Transmitter, 3PT 41B
b. Observations and Findings
The inspectors found the work performed under these activities to be
professional and thorough. All work observed was performed with the
work package present and in active use. Technicians were experienced
and knowledgeable of their assigned tasks. The inspectors frequently
observed supervisors and system engineers monitoring job progress.
Quality control personnel were present when required by procedure. When
applicable, appropriate radiation control measures were in place.
c. Conclusion
The inspectors concluded that the Maintenance and Surveillance
activities listed above were completed thoroughly and professionally.
M1.2
Unit 3 Emergency Feedwater Pumo Turbine Overspeed Test
a. Inspection Scope (62707)
The inspector observed the licensee's first attempt to perform procedure
OP/3/A/1106/06. Emergency Feedwater Procedure, Enclosure 3.2 Emergency
Feedwater Pump Turbine (EFWPT) Overspeed Test, and associated PIPs.
b. Observations and Findings
On February 18, 1997, during the performance of Procedure
OP/3/A/1106/06, Enclosure 3.2, at step 2.18, Operations halted the test,
and identified that a procedure change was required to reset the trip on
Enclosure 2
12
Valve 3MS-94 (EFWPT Stop Valve) in order for the system to operate.
During the re-performance of the overspeed test it appeared that Valve
3MS-93 (EFWPT Steam.Admission Valve) operated backwards. The licensee
initiated PIP 3-97-639 to investigate the problem. Upon further
investigation the licensee determined that 3MS-93 was set up to fail
closed rather than fail open.
Valve 3MS-93 was disassembled and reassembled during the Unit 3 outage
under Work Orders 96036488 and 95093317. Maintenance personnel failed
to follow Procedure MP/0/A/1200/33, Valve - Fisher - "U" Design - 300
Pound and 16 Inch 150 Pound Vee-Ball - Disassembly, Repair and Assembly,
on step 11.4.17 and 11.4.24. If steps 11.4.17 and 11.4.24 of
MP/0/A/1200/33 had been performed correctly, 3MS93 would have operated
as designed. The licensee had not retested the valve to that point
because of the plant status. The retest, which scheduled via WO 95093317 to be performed after the overspeed test, would have identified
the problem. The licensee's corrective action to disassemble and
reassemble the valve was completed under WO 97007963.
Conclusion
The inspector concluded that the licensee adequately identified and
corrected the incorrectly'assembled 3MS-93 EFWPT Steam Admission Valve.
M8
Miscellaneous Maintenance Issues (92902)
M8.1
(Closed) Unresolved Item (URI) 270.287/96-17-07: Incorrect Electrical
Connection of 2LP-1, 2LP-2, 3LP-1, and 3LP-2
This item concerned the discovery of incorrect wiring to the motor
operators on four Low Pressure Injection Loop (LPI) Suction Valves on
Unit 2 and Unit 3. The wiring leads were rolled at the Motor Control
Center (MCC) and at the valve. The licensee determined that this
allowed the valve to operate correctly from the Control Room, but would
have operated in the reverse direction if an intervening temporary
Appendix R panel had been installed and used during a hypothetical
event. The licensee postulated that if the motor operated in reverse
during an Appendix R event, the motor would have driven the valve into
the seat, tripped the breaker, and damaged the motors such that the
valves would not have opened electrically. This would have rendered the
valves, and therefore, the LPI system inoperable for decay heat removal.
Since these valves are located in the containment, they would have been
inaccessible until a Reactor Building entry could have been made. Decay
heat removal under these postulated conditions would have been
accomplished using the Safe Shutdown Facility, Auxiliary Feedwater Pump,
and the Steam Generators. The additional time could have prevented the
unit from being in cold shutdown within the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> per the Appendix R
requirements.
Enclosure 2
13
Technical Specification (TS) 6.4.1 requires that the station be
maintained in accordance with approved procedures. To the contrary,
the station was not maintained in accordance with Instrumentation
Procedure IP/O/A/3001/010, Maintenance of Limitorque Valve Operators.
Specifically, for an indeterminate time since the compliance audit with
Appendix "R" in 1987, the phases at the MCC and the valve operator for
LP-1 and LP-2 on Units 2 and 3 were reversed at the MCC. Accordingly,
the URI will be closed and this violation (VIO) of valve electrical
configuration control will be identified as VIO 50-270,287/97-01-03,
Failure to Follow Procedure.
M8.2 (Closed) VIO 50-270/96-13-10: Failure To Perform An Adequate 10 CFR
50.59 Evaluation
This violation was identified during a review of the completed
modification ONS-22975, Replace HPI Check Valves 2HP-126. 2HP-127. 2HP
152, and 2HP-153. The review of the modification identified the lack of
a fatigue analysis. This had generic implications for all three units.
The violation was discussed in IR 50-269,270,287/96-20 for Unit 2.
During this inspection period, the inspector reviewed the corrective
actions for identification and evaluation of the modifications for Units
1 and 3. The evaluations for Units 1 and 3 were completed prior to unit
startup. The inspector did not identify any weaknesses or deficiencies.
This item is considered closed.
M8.3 Institute of Nuclear Power Operations (INPO) Report Review
During the inspection period, the inspectors reviewed the most recently
completed INPO report that had been performed this period by
representatives from the World Association of Nuclear Operators. The
findings of the report, which spanned the dates of inspection from
September 30 to October 11, 1996. were consistent with NRC findings of
the last 18 months. The last INPO visit/inspection had been in January
1995.
III. Engineering
El
Conduct of Engineering
E1.1 LPSW Containment Piping Tests
a. Inspection Scope (37551, 61726)
Generic Letter (GL) 96-06 water hammer issues which were discussed in
Inspection Report 96-20 were further investigated by the licensee during
this inspection period (PIP 97-311). The licensee performed tests on
the outage unit similar to their normal LPSW ES tests with new
additional instrumentation. The tests were collecting data for input
Enclosure 2
14
into the LPSW piping model.
The inspector observed all of the test/data
collection.
b. Observations and Findings
On February 22, an adequate pre-job brief was held regarding details of
Test Procedure TT/3/A/025/63, LPSW Flow Test, and personnel involvement
during the evolution. Prerequisites for this Unit 3 test had been
established prior to the test. Operations clearly understood their part
in the test. With appropriate communication established, engineering
personnel were located in the RB, by the LPSW pumps, and in the piping
penetration room for the data collection and observation of potential
LPSW piping movement. The inspectors observed all three data collection
runs from the control room and then from the piping penetration room.
As part of the prerequisites, instrumentation had been hooked up to LPSW
piping test points. The instrumentation was to collect hydraulic
pressure pulse data on the piping leading into the RB (to the RBCUs) and
the associated return piping. A vendor, who was an expert in water
hammer evaluation, had hooked up computers to the instrumentation to
monitor and analyze the hydraulic data.
Test performance and data collection went smoothly. The single running
LPSW pump was shut off for 33 seconds and then restarted.on three
separate data runs. Data collection began before the pump was shut down
and ended two minutes after the restart. The actual water column
rejoining pressure pulses were well below the licensee's computer RELAP
5 Model bounding values with short duration pressure spikes of
approximately 125 to 135 psig. Very little piping movement was observed
(on the order of less than !12 inch side to side). The collected
information will be evaluated for inclusion into or in the tuning of the
RELAP-5 Model predictions.
c. Conclusions
The overall LPSW test was performed professionally with good engineering
cooperation and support. The results were acceptable and provided the
licensee a clearer understanding of plant response in Loss of Offsite
Power(LOOP)/Loss of Coolant Accident (LOCA) conditions.
0
Enclosure 2
15
E1.2 ICS Testing
a. Inspection Scope (61726, 62707, 61701)
The inspectors observed complex post modification testing of the new
Unit 3 ICS.
b. Observations and Findings
Testing Objectives
The testing was being controlled by two separate temporary tests,
TT/3/B/0326/001, ICS/NNI Transient-Testing at Power: ICS/NNI System
Upgrade, NSM ON-32989/AL1 and TT/3/B/0326/002, ICS Loss of Power Testing
at 25% Reactor Power: ICS/NNI System Upgrade, NSM ON-32989/AL1.
Procedure TT/3/B/0326/001 was written to test the functional
requirements of various features of the ICS. The scope of the test
included functional verification of the design basis ICS response to a
turbine trip at 15% power, a loss of electrical lOaD at 25% power, a
feedwater pump trip at 70%, a maximum runback transient from 65% to 50%
power, and a reactor coolant pump trip from 50% power. Procedure
TT/3/B/0326/002 was written to test the functional requirements of the
ICS/NNI system to cope with loss of ICS HAND and loss of ICS AUTO power.
The scope of the test involved tripping the ICS HAND circuit breaker.
verifying the response, then restoring ICS HAND power. Then the test
involved tripping the.AUTO circuit breaker, verifying the response, then
restoring AUTO power.
Conduct Of Testing
Test Preparation Activities
Refer to Section 05.1.
Pre/Post-Test Briefing
Prior to each test section (for both tests), the licensee conducted pre
test briefings for all personnel involved in the testing.
Pre-test
briefings were conducted by the manager (or his designee), who was
assigned oversight of the test, and a test coordinator. The manager
emphasized safety and.control room decorum during his briefs. The test
coordinator focused on the test evolution control and communications.
The inspector considered the pre-briefs to be thorough and with the
appropriate focus on nuclear safety.
After .completion of each test, a post-test brief was conducted by the
test coordinator with all personnel involved in the test. The briefs
focused on data acquisition results, test acceptance criteria, lessons
learned, necessity for procedure changes prior to.continuing, and other
Enclosure 2
16
concerns. The inspectors considered the test post-briefs to be
thorough, and they appropriately addressed issues requiring resolution
prior to continuation of testing.
Control Room Activities
The inspectors monitored testing activities from the Unit 3 control
room. The test coordinator and management designee was located in the
Unit 3 control room for all testing. Command and control in the control
room during all testing was good. Control room briefings for the
Operations crew were conducted by the Unit 3 shift management team prior
to initiation of each test section for both tests. Good communication
and coordination were noted. The test coordinator maintained good
control of all test evolutions. The inspectors concluded that testing
activities conducted.in the Unit 3 control room were good and operators
maintained appropriate focus on nuclear safety at all times.
TT/3/B/0326/001 Test Results
The licensee performed the first two test sections of this procedure
during this inspection period:
Turbine Trip At 15% Power
The licensee conducted the turbine trip at 15% power on March 14,
1997. All acceptance criteria was met for this test. Minor
discrepancies were noted, and resolved appropriately.
Load Reject Test
During the test, the Operations Senior Reactor Operators (SROs)
and test coordinator maintained good control of the overall
evolution. Operations personnel were well focused and understood
the test details, as well as their roll in test performance. At
the time of the test, the plant was stable with all prerequisites
met. At the point of the Main Turbine Generator (MTG) load
rejection, the inspector was in position at the MTG front standard
to observe the I&E rotating element speed instrumentation and Non
Licensed Operator (NLO) performance in case the .MTG over-sped with
the loss of load. Upon the loss-of load, the turbine control
valves closed and element speed approached within 4 RPM of the MTG
mechanical trip point, leaving the MTG running in an unloaded
condition. This was acceptable. Speed subsequently returned to
its normal setpoint value of 1800 RPM. The inspector proceeded
down the side of the turbine observing that the intercept valves
had closed as required and that bypassed steam that was no longer
entering the control valves had been appropriately diverted to the
condenser via the steam bypass valves. The MTG-ran very smoothly
through out this test.
Enclosure 2
17
Satisfied that the MTG and its associated equipment had performed
well and had responded to the ICS and Electro-Hydraulic Control
(EHC) system (on a loss of load EHC took over for many MTG control
functions), the inspector entered the control room to observe how
the ICS and reactor had responded to the perturbation. The
control room annunciator boards exhibited only three minor and
expected statalarms that resulted from the test parametric
changes. As anticipated by the test procedure, feedwater, Once
Through Steam Generator (OSTG) level controls, and reactor
controls were still in automatic and controlled in an expected
manner. RCS Tavg had risen one degree Fahrenheit, which was well
within expectations. The operators electrically reloaded the MTG
and resumed power escalation to 25% power.
The inspectors observed that the load rejection test met all
acceptance criteria. The Operations personnel, who were well
supported by other plant staff., performed the test in a controlled
manner.
TT/3/B/0326/002 Test Results
On March 15, 1997, the inspector observed the performance of Procedure
TT/3/B/0326/002 in the control room. Unit 3 was at 25% power for this
test which was within the required band described in the procedure. All
acceptance criteria was met for the Loss of HAND Power Test and for the
Loss of AUTO Power Test. Minor discrepancies were identified, and
evaluated by Engineering and Operations.
c. Conclusions
The inspectors concluded that the ICS testing (two sections of
TT/3/B/0326/001 and TT/3/B/0326/002) was satisfactorily accomplished in
accordance with the licensee's test procedures, and that deficiencies
identified during the testing were resolved appropriately. Control of
all test activities was good. Positive observations were made relating
to test briefings, control room briefings, and communication and
coordination of test evolutions.
E3
Engineering Procedures and Documentation
E3.1 Unit 3 ICS Tuning - Post Modification
a. Inspection Scope (37550, 37551)
The inspectors observed operational tuning and testing of the ICS
modification installed in Unit 3. During the performance adjusting or
tuning phase of the ICS modification prior to the testing addressed in
Section E1.2 above, the Engineering staff induced a problem in the
evolution. The inspectors followed up on the investigation and
identified problem resolution.
Enclosure 2
18
b. Observations and Findings
During the period of tuning, with the Unit 3 ICS at low reactor power
prior to actual testing, site engineering held meetings to discuss
information and problems that had been encountered. Meetings were
primarily held on March 9 and 12, to discuss problems found in the
control of feedwater and rod control. During these meetings, problems
were explored and teams were formed to bound the problem areas and
provide resolution. The meetings were chaired by ICS project engineers
and well attended by management.
On March 9, software changes were determined to be needed to reduce main
feedwater valve control oscillations and manage other ICS control
problems. These software changes were made through the Duke engineering
software change process. The approved changes were installed on
computers.
ICS was designed to automatically switch between Low Level Limits (LLL)
and Feedwater Flow control of steam generator level when certain plant
conditions were met. During a power increase to 15% Reactor Thermal
Power (RTP), those plant conditions were met. However, when the ICS
attempted to automatically switch to Feedwater FLow control of steam
generator levels, the ICS generated feedwater crosslimits due to
excessive mismatch between feedwater flow and reactor power. In
response. ICS automatically reduced reactor power to clear the feedwater
crosslimits as designed. When reactor power was reduced below the power
limit for Feedwater Flow control, ICS automatically switched back to
LLL; thereby, effectively removing the feedwater crosslimits. Reactor
power stabilized at about 8% RTP. Several minutes later, the Reactor
Master and Steam Generator Master controllers transferred to manual.
The licensee determined that the software which provided total feedwater
flow 'value to the ICS control modules was inadvertently deleted during a
routine software update of ICS response constants (PIP 3-97-910). This
inadvertent deletion was identified after the above problem occurred
when the previous copy and the updated copy of the software were
compared. It was not detected on the initial review because the
licensee only reviewed that portion of the software that was modified.
The licensee replaced the missing software and reprogrammed the affected
ICS control module. The licensee also reviewed all other recent
software changes and did not identify any additional undetected software
errors.
The licensee discussed the potential causes for the Reactor Master and
Steam Generator Master controllers transferring to manual, but was
unable to identify any ICS control condition that would cause this
transfer. During this discussion, it was noted that these controllers
transferred to manual when an ICS cabinet door was closed. The licensee
wrote a special troubleshooting procedure to determine if a loose
connector or wire could have been the cause.
Using a high-speed data
Enclosure 2
19
logger, the licensee identified that the transfer relay was susceptible
to contact "bounce." As a precaution, the licensee had manually
transferred the Reactor Master and Steam Generator Master controLlers to
manual. Therefore, there was no positive indication that contact
"bounce" was the root cause. The licensee did replace the relay before
resuming power ascension.
After the licensee had resumed power ascension, significant feedwater
oscillations were observed during the transfer from the startupflow
control valve to the main feedwater regulating valve.
The licensee
reduced power below 10% RTP and conducted troubleshooting. The licensee
determined that the feedwater integral gain factor for feedwater flow
control was set too high, resulting in the ICS responding too quickly to
minor feedwater flow/steam generator level errors. The licensee
reviewed the feedwater integral gain factor setting for the Unit 1 ICS
and found that it was set at 4.5 repeats per minute. The licensee also
stated that the value for the original Unit 3 ICS was about 4.0 repeats
per minute. The feedwater integral gain factor for the Unit 3 ICS was
set at 25 repeats per minute based on V&V simulator testing results.
The licensee adjusted the Unit 3 feedwater integral gain factor setting
to 4.5 and again increased power. Feedwater oscillations were observed:
however, these oscillations were much smaller in magnitude than
previously observed. The licensee also adjusted the proportional gain
constant resulting in a longer period for the feedwater oscillations
than previously observed. The 'B'
loop did transfer from the startup
flow control valve to the main feedwater regulating valve at about 13%
RTP: however, the 'A'
loop did not transfer even after power was
stabilized at about 15% RTP. The licensee attributed this to
differences in flow characteristics between the two loops. The licensee
stated .that they would adjust ICS to allow the 'A'
and 'B'
loops to
transfer at the same time.
c. Conclusions
The inspectors observed the troubleshooting and determined that it was
conducted in a methodical and controlled manner. Appropriate
precautions were taken to guard against unintended reactivity changes.
The failure of the licensee to detect an unintended software change
prior to placing modified.software in service was a substantial concern.
As documented in Inspection Report 96-20, inspector concerns were
expressed that unintended software error could be introduced due to
weaknesses in the V&V program. In response, the licensee had placed the
finalized version of the ICS control module software in the licensee's
Quality Assurance (QA) control program for engineering calculations.
Changes to engineering calculations were independently reviewed to
ensure accuracy. However, the independent review failed to detect the
software error, indicating that a simple independent review may not be
sufficient.
Enclosure 2
20
The large feedwater integral gain factor was another area for concern.
This factor was derived based on V&V simulator testing which was
supposed to accurately reflect Unit 3 dynamic response. As stated in
Inspection Report 96-20. the V&V simulator was not validated for Unit 3
dynamic response. Furthermore, the difference between the initial value
of integral gain (25 repeats per minute) and the original Unit 3 ICS
value (about 4 repeats per minute) indicated that the licensee did not
compare response constants to ensure reasonable and stable ICS
operation. This would also be of concern because, as documented in
Inspection Report 96-20, the V&V tests to be conducted during power
ascension did not test the full range of ICS response. Other large
response constants may be present in the ICS software, which would only
be evident at specific plant conditions, and may result in unstable ICS
operation.
The licensee was aware of the inspectors' concerns and was developing
corrective actions.
The licensee was to determine root cause on this loss of computer code
event under their corrective action program. This condition was
discovered during tuning of the ICS after the software validation had
occurred. The licensee i.ntends to .install this same ICS modification on
Units 1 and 2 during future refueling outages. Accordingly, review of
ICS software implementation during those outages will be tracked under
IFI 50-269,270/97-01-04, Adequacy of Review Software Change,
Additionally, IFI 50-270/96-20-08, ICS Post Modification Testing, will
be evaluated upon the completion of the Unit 3 testing that is to be
completed during the next inspection period.
Post validation and verification changes to Unit 3 ICS software resulted
in an error being introduced. This occurrence resulted in a minor plant
perturbation but was discovered in the system testing phase. The
occurrence was considered a substantial weakness in the overall ICS
modification process.
E8
Miscellaneous Engineering Issues (40500, 90712, 92903)
E8.1 (Closed) LER 50-269/95-002-00: Vendor Analysis Deficiency Results InA
Condition Outside Design Basis Of The Plant
This LER was issued because B&W had discovered an error in the non
conservative direction which resulted in an error of greater than 50
degrees F in the final peak clad temperature. As described in
Inspection Report 50-269,270,287/95-01, the licensee addressed this
issue by restricting the allowable axial imbalance which could be
present at the beginning of the event. The new, restrictive limits for
axial imbalance were imposed after review by the Plant Operations Review
Committee (PORC). and implemented by a conditional operability
evaluation. The new limits were considered temporary until B&W
Enclosure 2
21
completes their analysis for Oconee, and provides a new initial
condition limit for axial imbalance. Duke re-evaluated the Core
Operating Limits Report (COLR) based on.the information provided by B&W.
and the COLRs for all three units were revised restoring the operating
limits to their previous values before identification of the B&W error.
All three units' COLRs and associated procedures and alarm limits were
revised on March 9, 1995. Therefore, this item is closed.
E8.2 Generic Letter (GL) 96-06 Followup
IR 96-20, Section E2.1, discussed the licensee's efforts to review and
respond to GL 96-06. Assurance of Equipment Operability and Containment
Integrity During Design Basis Conditions. During this inspection
period. the licensee has made two.10 CFR 50.72 reports as followup to
these efforts. The associated issues are as follows:
" LER 97-02. dated February 20. addressed a potential "Reactor
Building Cooling Unit [RBCU] Technically Inoperable Due to Design
Deficiency" problem. As part of the GL 96-06 evaluation, Duke
engineering has been performing detailed thermal-hydraulic
analyses to determine if any portion of the Low Pressure Service
Water (LPSW) piping which served the RBCUs were susceptible to
water hammer. .On January 24. 1997. the analyses determined that
during certain design basis scenarios condensation induced water
hammers associated with the nonsafety-related auxiliary cooling
units could result in safety-related RBCUs being unable to perform
their intended function. This resulted in the first 10 CFR 50.72
report. The root cause of this potential problem will be
addressed in a supplement to the LER. The licensee had taken
compensatory actions (discussed in the IR 96-20) to eliminate the
problem by making valve lineup/position changes. Until this issue
is resolved, this shall be identified as URI 50-269.270.287/97-01
05. LPSW Piping .to the RB Cooling Inoperability.
" On March 17, the licensee made the second 10 CFR 50.72 report as
followup on inoperable boron dilution flow paths (BDFP). There
are three redundant BDFPs provided in the Oconee design. Two of
these paths are available by positioning certain valves to
establish the flowpath (active paths), and one is available
internal to the reactor vessel via a passive path. The active
flowpaths can be established by open valves LP-1 and LP-2 or the
other path by opening LP-103 and LP-104. The UFSAR required that
two of the three flowpaths be available in the event of a LOCA.
Prior to the recent return to power operations by the three units,
past operability questions were postulated with the active
flowpaths on all three units. The postulated problem was that
thermally induced overpressurization of the water volume between
the two pairs of valves could make opening of the valve pairs not
possible. Thus, the active flow paths may not have been
available., IR 96-20 addressed compensatory actions taken prior to
Enclosure 2
22
the returh to power operations while the licensee continued their
evaluation. On March 17, with their analysis now complete, the
licensee determined that the active paths were past inoperable,
resulting in the above report with a LER to follow. Until this
issue is resolved, this shall be identified as URI 50
269.270.287/97-01-06, BDFP Inoperability.
IV.
Plant Support Areas
R2
Status of RP&C Facilities and Equipment
R2.1 10 CFR 70.24 Criticality Accident Requirements
a. Inspection Scope (71750)
The inspector reviewed the licensee's compliance with 10 CFR 70.24,
Criticality Accident Requirements. The review became necessary
following the identification at other nuclear sites that were not in
compliance with the regulation.
b. Observations and Findings
The inspector reviewed the Oconee Nuclear Station license, emergency
procedures, Technical Specifications, and interviews with site
personnel.
Based on this review, it was identified that Oconee Nuclear
Station, Units 1. 2. and 3. neither satisfies nor is exempted from the
requirements of 10 CFR 70.24 (a)1 or (a)2. This issue is being
identified as Unresolved Item (URI) 50-269,270,287/97-01-02, Failure to
Meet Requirements of 10 CFR 70.24.
c. Conclusions
The licensee did not meet the .requirements of 10 CFR 70.24, Criticality
Accident Requirements. A URI was opened pending further NRC evaluation
of the enforcement action.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors presented the inspection results to members of licensee
management at the conclusion of the inspection on March.20. 1997. The
licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materials examined during the
inspection should be considered proprietary. No proprietary information was
identified.
Enclosure 2
23
Partial ,List of Persons Contacted
Licensee
E. Burchfield,. Regulatory Compliance Manager
T. Coutu, Operations Support Manager
D. Coyle, Systems Engineering Manager
T. Curtis, Operations Superintendent
J. Davis, Engineering Manager
B. Dobson, Systems Engineering Manager
W. Foster, Safety Assurance Manager
J. Hampton. Vice President, Oconee Site
D. Hubbard, Maintenance Superintendent
C. Little, Electrical Systems/Equipment Manager
B. Peele, Station Manager
J. Smith, Regulatory Compliance
NRC
D. LaBarge, Project Manager
J. Ganiere, Electrical Engineer
Enclosure 2
24
Inspection Procedures Used
IP90712:
In-Office Review of Written Event Reports
IP71750:
Plant Support Activities
IP71707:
Plant Operations
IP61726:
Surveillance Observations
IP62707:
Maintenance Observations
IP40500:
Self-Assessment
IP37551:
Onsite Engineering
IP92901:
Followup - Operations
IP92902:
Followup - Maintenance
IP92903:
Followup - Engineering
IP93702:
Prompt Onsite Response to Events
IP61701:
Complex Surveillance
Items Opened, Closed, and Discussed
Opened
50-269,270/97-01-01
IF.1
Reactor Trip Confirm Circu'it Fuse
Inspection (Section 01.5)
50-269,270287/97-01-02
Failure to Meet Requirements of 10 CFR
70.24 (Section R2.1)
50-270,287/97-01-03
Failure to Follow Valve Procedure (Section
M8.1).
50-269,270/97-01-04
IFI
Adequacy of Review Software Change
(Section E3.1)
50-269F270,287/97-01-05
Inoperability (Section E8.2)
50-269,270,287/97-01-06'
BDFP Inoperability (Section E8.2)
Closed
50-269/95-001-00
[ER
Potential Unanalyzed Main Steam Line Break
Scenario (Section 08.1)
270,287/96-17-07
Incorrect Electrical Connection of 2LP-1,
2LP-2, 3LP-1, and 3LP-2 (Section M8.1)
50-270/96-13-10
Failure to Perform Adequate 10 CFR 50.59
Evaluation (Section M8.2)
sEnclosure2
25
50-269/95-002-00
LER
Vendor Analysis Deficiency Results In A
Condition Outside Design Basis Of The
Plant (Section E8.1)
Discussed
50-270,287/96-20-08
IFI
ICS Post Modification Testing (Section
E3.1)
List of Acronyms
ACB
Air Circuit Breaker
amp
ampere
BDFP
Boron Dilution Flow Path
Babcock and Wilcox
Core Flood
CFR
Code of Federal Regulations
Condenser Circulating Water
Core Operating Limits Report
CR
Control Room
Control Rod Drive
Core Flood
Emergency Feedwater
Electro-Hydraulic Control
End Of Cycle
Electrical Power Research Institute
Engineered Safeguards
FDW
FWPT
Feedwater Pump Turbine
GL
Generic Letter
HD
Heater Drain
High Pressure
Hig.h Pressure Injection
In accordance with
Integrated Control System
I&E
Instrument & Electrical
Institute of Nuclear Power Operations
IR
Inspection Report
IP
Inspection Plan
IFI
Inspector Followup Item
KHU
Keowee Hydro Unit
LDST
Letdown Storage Tank
LER
Licensee Event Report
LCO
Limiting Condition for Operation
LLL
Low Level Limits
Loss of Coolant Accident
Loss of Offsite Power
.
Low Pressure
Enclosure 2
26
Low Pressure Injection
Low Pressure Service Water
Maintenance Procedure
MS
MSRH
Main Steam Re-heater
Main Turbine Generator
Non-Cited Violation
Non-Licensed Operator
NNI
Non-Nuclear Instrumentation
NRC
Nuclear Regulatory Commission
NSM
Nuclear Station Modification
NSD
Nuclear System Directive
Oconee Nuclear Station
OP
Operations Procedure
Operations Shift Manager
Once Through Steam Generator
PCB
Power Circuit Breaker
Public Document Room
Problem Investigation Process
Preventive Maintenance
Plant Operations Review Committee
Performance Test (surveillance)
Quality Assurance
Reactor Building
RBCU
Reactor Building Cooling Unit
Reactor Coolant Pump
RP&C
Radiation Protection and Chemistry
Revolutions Per Minute
Senior Reactor Operator
ReactorThermal Power
Tavg
Temperature Average of the RCS
TS
Technical Specifications
TT
Temporary Test
Unresolved Item
Updated Final Safety Analysis Report
Violation
V&V
Validation and Verification
Work Order
Work Request
Enclosure 2