ML15118A277
| ML15118A277 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 12/15/1997 |
| From: | Ogle C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A275 | List: |
| References | |
| 50-269-97-15, 50-270-97-15, 50-287-97-15, NUDOCS 9712310358 | |
| Download: ML15118A277 (54) | |
See also: IR 05000269/1997015
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269, 50-210
50-287, 72-04
License 'Nos:
DPR-38 DPR-47, -DPR-55 SNM-2503
Report No:
50-269/97-15, 50-270/97-15, 50-287/97-15
Licensee:
Duke Energy Corporation
Facility:
Oconee Nuclear Station Unis 1 2. and 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
October 19 - November 15, 1997
Inspectors:
M. Scott. Senior Resident Inspector
S. Freeman, Resident Inspector
E. Christnot, Resident Inspector
D. Billings. Resident Inspector
B. Crowley, Regional Inspector (Section M1.4)
J. Blake, Regional Inspector, Review at Eddy Current
Analysis Center (Sections M1.6 and M2.2)
N. Economos, Regional Inspector (Section M2.3)
R. Franovich, Resident Inspector, Catawba (Section M1.7)
R. Moore, Regional Inspector (Sections E2.1, E3.1. and E8.1)
N. Merriweather, Regional Inspector (Sections E2.1, E3.1.
and E7.1)
D. Forbes, Regional Inspector (Sections R1 through R7)
B. Miller, Regional Inspector (Sections F1 through F7)
Approved by:
C. Ogle, Chief, Projects Branch 1
Division of Reactor Projects
Enclosure 2
9712310358 971215
PDR ADOCK 05000269
Q
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1. 2. and 3
NRC Inspection Report 50-269/97-15,
50-270/97-15, and 50-287/97-15
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a four-week
period of resident inspection, and the results of announced inspections.by
region-based inspectors.
Operations
In general, the conduct of operations was professional and safety
conscious.
(Section 01.1)_
Refuelfi gactivities were completed in a professional and conservative
manner. The use of, the reactor engineer on the refueling bridge in the
reactor building, the use of an extra licensed operator in the spent
fuel pool area during refueling, and the new level of licensee safety
conscious overview were strengths. (Section 01.2)
The licensees power reduction and replacement of a degrading Unit 2 main
seal oil pump was proactive and performed without incident.
(Section 02.1)
- .
The inspectors concluded that the licensee's program and preparations
for cold weather were good. (Section 02.2)
Maintenance
The inspectors concluded that general maintenance activities were
completed thoroughly and professionally. (Section M1.1)
During the period, the licensee searched for and found a missing piece
from the 1A1 Reactor Coolant Pump impeller. During the search, the
licensee found other reactor vessel related pieces that had been missing
since 1981. The licensee was generating an evaluation on the vessel
related piece that would remain in place. Video inspection of the
Unit 1 reactor coolant pumps had been performed and the licensee was
evaluating continued operations of the three pumps with observed
impeller degradation for an additional fuel cycle. (Section M1.2)
Strong management oversight, good communications, and sound coordination
by engineering and maintenance resulted in an error free recovery of a
-- *broken
MARB stopple plug from the low pressure service water system.
(Section M1.3)
The Failure Investigation Process team was aggressively pursuing the
root cause for the failure of the MARB0 plugging tool. All maintenance
Enclosure 2
2
and inspection activities observed for installation of the 24-inch MARBO
plug were performed in a conscientious manner by qualified personnel in
accordance with detailed procedures. Welding and non-destructive
examination activities observed and reviewed were performed in
accordance with the applicable code and procedure requirements..
(Section M1.4)
The failure by maintenance personnel to complete a Technical
Specification required surveillance on low pressure injection flow
instruments resulted in a violation. (Section M1.5)
The licensee's process for the evaluation of steam generator eddy
current .data was being conducted in accordance with current industry
guidelines and expectations. (Section M1.6)
The practice of obtaining anoil sample from the Unit 2 turbine driven
emergency feedwater pump without it running was a weakness in the oil
sampling methodology. A request by operations for a procedure to govern
the realignment of the pump's steam supply was seen as a conservative
measure to protect the steam header piping and structural supports from
possible water and steam hammers. (Section M1.7)
Assembly of low pressure service water valves with the wrong parts
resulted in an Unresolved Item concerning parts identification. (Section
M2.1)
The condition of the Oconee once-through-steam-generators has seen
additional licensee attention through Babcock & Wilcox Owners Group
sponsored tube pulls in each unit, and the contract with Dominion
Engineering Incorporated to do an independent review of the Oconee steam
generator program. (Section M2.2)
The failures of mechanical feedwater piping connections to the Unit 1B
steam generator were not being identified and trended as repeat
failures. (Section M2.2)
The licensee implemented repairs in once-through-steam-generator 1B
tubes in a conservative manner, following administrative controls and
applicable controlling procedures. Technical support provided good
guidance and oversight while the activity was in progress. (Section
M2.3)
Engineering
Based on a review of engineering activities, engineering support to
operations and maintenance was adequate. (Section E2.1)
Enclosure 2
3
Design.control for a Unit 1 low pressure service water modifications was
good. The 10 CFR 50.59 evaluations were detailed and thorough.
(Section E3.1)
The engineering self-assessments performed in,1997 were effectivin
identifying and assuring correction of deficiencies in engineering
performance. (Section E7.1)
The failure to revise the Updated Final Safety Analysis Report to
reflect different fuel enrichments since 1994 was identified as a.
violation. :The discrepancy had been previously identified, but went
uncorrected. (Section E8.3)
Plant Support
Based on. observations and procedural reviews, the inspectors determined
the licensee was effectively maintaining controls for radioactive waste
and waste processing- One unresolved item was identified to determine
monitoring requirements for radiological work in two onsite buildings.
The licensee's initiative to improve resin sluice processing systems to
maintain exposures As Low As Reasonably Achievable and to improve
environmental controls for resin sluicing was viewed as a strength.
(Section R1.1)
It was concluded that the licensee's water chemistry control program for
monitoring primary and secondary water quality had been effectively
implemented, for those parameters reviewed, in accordance with the
Technical Specification requirements and the Station Chemistry Manual
for Pressurized Water Reactor water chemistry. (Section R1.2)
The inspectors determined that the licensee had effectively implemented
a program for shipping radioactive materials required by NRC and
Department of Transportation regulations. (Section R1.3)
It was concluded that the meteorological instrumentation had been
adequately maintained and that the meteorological monitoring program had
been effectively implemented. (Section R2.1)
The inspectors determined that the licensee was performing Quality
Assurance audits and effectively assessing the radiation protection
program as required by 10 CFR Part 20.1101. The inspectors also
determined that the licensee was completing corrective actions in a
timely manner. (Section R7.1)
The licensee's fire protection staff demonstrated an aggressive attitude
in the identification and correction of fire protection deficiencies.
(Section F1.1)
Enclosure 2
4
Three non-cited violations were identified for the licensee's failure to
meet the fire protection operability requirements for three required
fire protection features. (Section F1.1)
The low number of inoperable or degraded fire protection components, in
conjunction with the good material condition of the fire protection
components and fire brigade equipment. indicated appropriate emphasis
had been placed on the maintenance and operability of the fire
protection equipment and components. (Section F2.1)
Adequate surveillance and test procedures were provided for the fire
protection systems and features, and implementation of the procedures
was effective. (Section F2.2)
The fire barrier penetration seals were' functionak However, the
licensee had implemented a project to provide documentation to identify
the design specification and bounding test criteria applicable to each
fire barrier penetration. (Section F2.3)
In general. fire protection program implementing procedures were well
written and met the licensee's commitments to the NRC requirements.
Procedure implementation for the control of ignition sources and
transient combustibles was good. Overall, general housekeeping was
satisfactory. (Section F3.1)
A violation was identified involving the failure to provide fire
fighting strategies for all plant areas which contained safety-related
equipment or presented an exposure hazard to safety-related components.
(Section F3.1)
The fire brigade organization and training met the requirements of the
site procedures. The use of the fire brigade safety officer position
during fire emergencies was identified as a program strength. (Section
F5.1)
Fire brigade performance during a drill conducted during this inspection
period was mixed. Subsequent brigade performance after resolution of
drill identified deficiencies was satisfactory. (Section F5.1)
The 1995 audit and assessment of the facility's fire protection program
were comprehensive and appropriate corrective action was promptly taken
to resolve identified issues.
(Section F7.1)
Enclosure 2
Report Details
Summary of Plant Status
Unit 1 began and ended the period in a scheduled refueling outage. Major
outage work completed included the replacement of the 1A1 reactor coolant
pump, inspection of the other reactor coolant pump impellers, and low pressure
service water system modifications.
Unit 2 began the period at 100 percent power and decreased to 56 percent power
on November 6. to repair the generator main seal oil pump motor. The unit
returned to 100 percent power on November 7. and remained at 100 percent power
for the. rest of the period.
Unit 3 began and ended the period at 100 percent power.
Review of Updated Final Safety Analysis Report (UFSAR) Commitments
While performing inspections discussed in this report, the inspectors reviewed
the applicable portions of the UFSAR that related to the areas inspected.
Except for the issues discussed in Sections E8.3 and F. the inspectors
verified that the UFSAR wording was consistent with the observed plant
practices, procedures, and 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 Refueling Activities
a. Inspection Scope (71707)
The inspectors observed portions of the defueling and refueling
activities for Unit 1.
b. Observations and Findings
The inspectors observed control room, spent fuel pool (SFP), and reactor
building (RB) activities by operations personnel. The activities were
conducted in a professional manner with emphasis on attention to detail,
conservative judgement, and timeliness. During the initial checkout of
- equipment,
problems with the RB manipulator were identified and
resolved. The licensee made enhancements in refueling activities
Enclosure 2
2
including the use of a reactor engineer on the refueling bridge in the
RB and the-use of an extra licensed operator in the SFP area during
refueling. Licensee management also articulated a new level of licensee
safety conscious overview for refueling. The inspector observed that
operators in the control room were aware of the movement of each fuel
assembly by number and monitored appropriate nuclear instrumentation.
c.
Conclusions
Refueling activities were completed in a professional and conservative
manner. The use of the reactor engineer :on the refueling bridge in the
RB, the use of an extra licensed operator in the SFP -area during
refueling, and the new level of licensee safety conscious overview were
strengths.
02
Operational Status of Facilities and Equipment
02.1 Unit 2 Power Reduction for Seal Oil Motor Replacement
a. Inspection Scope (71707, 62707)
The inspectors attended several meetings and observed work in progress
as the icensee reduced power to replace the Unit 2 seal oil pump motor.
b. Observations and Findings
On November 6 and 7, 1997, the licensee evaluated a degrading bearing on
the main seal oil pump motor. Routine vibration monitoring detected
higher than expected vibration levels on the motor, which worsened over
November 6. After a management meeting on the afternoon of November 6,
the licensee reduced power on Unit 2 to 56 percent. As the down power
continued, maintenance personnel removed the equivalent motor from
Unit 1, which was shut down for refueling, and overhauled it by
replacing the bearings. The switch between seal oil skid pumps was
safely performed and the main pump motor was changed out using the
overhauled pump from Unit 1. The unit was restored to full power on
November 7.
c. Conclusions
The licensee's power reduction and replacement of a degrading Unit 2
main seal oil pump were proactive and performed without incident.
Enclosure 2
3
02.2 Cold Weather Preparations
a. Inspection Scope (71714)
The inspectors reviewed the licensee's program for cold weather
preparations and the status of freeze protection equipment.
b. Observations and Findings
The inspectors documented in Inspection Report (IR)
50-269,270.287/96-16
previous worklorderseand discrepancies involved with freeze protection
equipment. The IR indicated the following: a corporate audit was
performed to formalize a freeze protection program for all three nuclear
sites; Problem Identification Process (PIP) report 096-0639 was
initiated to address concerns raised -by the audit: and procedure
upgrades that are planned or being evaluated by site .management were
discussed. In addition, the IR also identified three susceptible areas:
(1)
the borated water storage tank (BWST) level indication: (2)
the,.
elevated water storage tank (EWST) level indication: and (3)
the cooling
water to the condenser circulating water (CCW) pumps.
The inspectors reviewed PIP 096-0639 and observed that several
corrective actions were initiated. Among the items affected by the
corrective actions were:
plant equipment used for freeze protection,
such as heat trace and heaters: areas of the plant and equipment
requiring cold weather protection, including Keowee; and administrative
control, inspection, and maintenance procedures required to implement a
freeze protection program.
The inspectors reviewed applicable procedures and observed the
following:
IP/0/B/1606/009, Preventive Maintenance and Operational Check of
Freeze Protection, Revision 0, provided a method for inspecting,
cleaning, and performing an operational check of freeze protection
equipment.
Nuclear System Directive (NSD) 317. Freeze Protection Program,
Revision 1, provided the guidelines and requirements to ensure
that sub-freezing conditions do not impair the safe and efficient
operation of nuclear power plant equipment.
MP/0/B/3007/059, Plant Heater - Testing, Revision 1, provided
--
guidance for the testing of plant heaters.
The inspectors observed and reviewed work activities involved with
procedure IP/0/B/1606/009. These activities were performed on freeze
Enclosure 2
4
protection equipment associated with the BWST., EWST. and the CCW cooling
water supply.
c. Conclusions
.
The inspectors concluded that the licensee's preparations and program
for cold weather were good.
03
Operations Procedures and Documentation
03.1 Failure to Perform Instrument Surveillance on the Inadequate Core
Cooling Monitor (ICCM)
a. Inspection Scope (71707)
On October 29, 1997:, during the performance of PT/3/A/0600/01. Periodic
Instrument Surveillance, operations identified that Technical
Specification (TS) requirements had not been met due to the operator aid
computer (OAC) subcooling monitor calculation being non-conservative.
.
b. Observations and Findings
TS 1.5.3 requires an instrument channel check to verify acceptable
instrument performance by comparison to an independent channel measuring
the same variable. To meet this requirement for the ICCM,
PT/3/A/0600/01 required the operator compare the ICCM subcooling values
with the OAC subcooling values. PIP 097-1394 was initiated on April 30,
1997. to document a problem with the coefficients used in the OAC
subcooling monitor calculation. The operators had been initialing the
step in PT/3/A/0600/01 with a note stating that the OAC points were out
of service. This did not meet the intent of the TS surveillance. As an
interim corrective action, engineering developed a procedure to allow
operators to perform a manual calculation using control room instrument
values to verify the subcooling margin. The inspectors will continue to
follow the licensee's evaluation through Licensee Event Report (LER) 50
287/97-04 and the associated PIP 097-3784 concerning TS surveillance
requirements.
II.
Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Inspection Scope (62707, 61726)
The inspectors observed all or portions of the following maintenance
activities:
Enclosure 2
5
TT/1/A/0400/28
Standby Shutdown Facility Reactor Coolant Makeup
Pump Flow Distribution
Unit 1 Perform Video Inspection of Reactor Core
Support Area
PT/1/A/0610/01J
Emergency Power Switching Logic Functional Test
IP/0/B/1606/009
Preventive Maintenance and Operational Check of
Freeze Protection
MP/0/A/3007/059
Plant Heater - Testing
IP/0/A/3000/015
125 Volt Direct Current 230 Kilovolt Switchyard
Battery Service Test and Annual Surveillance
WO 97062732-1
Perform Annual Switchyard Battery Surveillance
b. Observations and Findings
The inspectors found the work performed under these activities to be
professional and thorough. A
work observed was performed with the
work package present and in 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 activities listed above
were completed thoroughly and professionally.
M1.2 Unit 1 Reactor Coolant Pump (RCP) Impellers and Loose Parts in Reactor
Coolant System (RCS)
a. Scope of Inspection (62707, 37551)
As discussed in IR 50-269,270,287/97-014. Section M1.9. the licensee
found a piece of the vane missing from the 1A1 RCP impeller. The
inspectors followed the licensee's actions and were informed that these
actions will be captured in PIP 097-4012.
b. Observations and Findings
The licensee inspected the RCS and reactor vessel to the maximum extent
practicable to locate the missing piece. The piece was found in the
- -bottom of the reactor vessel. Additionally, the licensee found a
Enclosure 2
6
thermal shield bolt head and a core support assembly guide block which
were previously reported missing. These parts were discussed in LER 50
269/81-11. The LER included supporting documentation from the RCS
vendor Babcock & Wilcox, to justify continued operation. The impeller
piece and bolt were removed. The guide block was firmly wedged between
the core support assembly rib section and the incore guide support
plate. The licensee was in the process of completing an evaluation of
the observed conditions at the end of the report period. To date, the
licensee's retrieval actions have been adequate.
The licensee inspected the impellers on the three remaining RCPs for
potential cavitation induced erosion. The licensee contracted with a
vendor for an articulated, high-resolution camera that could completely
inspect the details of the impellers, particularly the back side of each
impeller vane. All three impellers had indications of erosion damage
that was to be documented in PIP 097-4012. The inspectors viewed the
video tape made during the inspection and discussed the findings with
the licensee and other NRC personnel. The licensee and the pump vendor
were evaluating the damage at the end of the inspection period.
M1.3 Low Pressure Service Water (LPSW) MARBO Stopple Pluq Failure
a. Inspection Scope (62707,40500)
The inspectors reviewed documents and drawings, interviewed personnel.
and observed activities associated with the failure and subsequent
recovery of a 36-inch MARBO stopple plug in the LPSW piping.
b. Observations and Findings
On October 17. 1997, while removing the 36-inch MARBO stopple plug, a
loud knock was heard at the stopple machine and a water and oil mixture
was observed coming from the view port. Licensee personnel quickly
reacted to contain the oil and prevent a oil discharge to the lake.
Vendor personnel, with licensee approval, continued to attempt to remove
the stopple plug and close the 36-inch isolation valve. The valve
closed smoothly to the halfway point and stopped. The valve was cycled
and again an attempt was made to remove the stopple plug. The valve
would not close fully and the coordinator entered the stopple plug loss
contingency plan. A Failure Investigation Program (FIP) team was
formulated to determine the cause and PIP 097-3621 was generated.
On October 20, 1997, a video was completed by the vendor of the inside
of the valve. The video showed that the stopple plug was separated from
the ram assembly used to position the plug. The break was located at
the point where the ram met the pivot plate. The contingency plan to
remove the broken stopple plug was discussed with management. A
-modification package. TN/1/A/11029/00/01M. for performance of another
Enclosure 2
7
MARB0 plug to allow recovery of the 36-inch plug was completed on
October 23. 1997. The new 24-inch MARB0 connection was completed on
October 26, 1997. The 24-inch MARB0 plug was installed on October 27,
1997. with the subsequent recovery of the 36-inch MARB0 plug and the
removal of the 24-inch MARBO plug on October 28. 1997.
The broken 36-inch MARB0 plug was sent to Southwestern Research
Institute for metallurgical analysis.
c. Conclusions
Strong management oversight, good communications, and sound coordination
by engineering.and maintenance resulted in an error free recovery of a
broken MARBO stopple plug from the LPSW system.
M1.4 LPSW Piping Modification
a. Inspection Scope (62700)
The inspectors observed ongoing work activities relative to installation
of a stopple (MARBO) plug in a 24-inch diameter LPSW pipe. See
paragraph M1.3 for further discussion on roblems encountered with a 36
inch MARB0 plug upstream of the 24-inch plug, which necessitated the
installation of the 24-inch plug.
b. Observations and Findings
As discussed in paragraph M1.3. while removing a stopple (MARBO) plug
from the 36-inch LPSW line downstream of the C LPSW pump, the plugging
machine hydraulic ram broke before the plugging head was completely
removed from the split tee fitting and sandwich valve. The sandwich
valve could not be closed to isolate the plugging machine from the
system. Therefore, another MAR80 plug was installed in the 24-inch line
downstream of the 36-inch plug to isolate the plug so that the broken
ram and plugging machine could be removed from the 36-inch line. The
inspectors observed the following activities relative to investigation
of the cause of the ram failure for the 36-inch plug and installation of
the 24-inch plug:
Failure Investigation
A failure investigation had been initiated by a FIP team. The
inspectors discussed the failure with the FIP team leader and reviewed
-
the preliminary results of the investigation. The ram broke near the
end-cap weld at the attachment to the plugging head. Based on pictures
taken with a remote camera prior to removal of the plugging machine, the
FIP team stated that the failure appeared to be fatigue in nature. A
Enclosure 2
8
metallurgical analysis was planned after removal of the plugging
machine.
Installation of 24-inch Pluq
The 24-inch MARBO plug was installed by Minor Modification Project
Numbers ONOE-11028 and ONOE-11029. The applicable code for fabrication
and installation of the :split tee -was USAStandard Code for Pressure
Piping B31.1, July 1967 Edition. In addition to reviewing the
modificationlpackages and various in-process work procedures and
documents-, the inspectors observed and reviewed the following welding
and:inspection activities:
In-process welding was observed for Weld 6 (flange to split tee)
on Isometric Drawing 1-LPS-570. In addition, in-process final
visual and magnetic particle examinations were observed for the
weld.
Final weld surfaces were visually inspected on the split-tee Welds
2. 3. 4 and 5 on Isometric Drawing 1OLPS-570.
For Welds 2. 3. 4, 5, and 6 on Isometric Drawing 1OLPS-570, weld
process control sheets and weld material issue records were
reviewed; and welder qualification, welding material
certification, and nondestructive examination/quality control
(NDE/QC) inspector qualifications were verified.
c. Conclusions
The FIP team was aggressively pursuing the root cause for the failure of
the MARBO plugging tool. All maintenance and inspection activities
observed for installation of the 24-inch MARBO plug were performed in a
conscientious manner by qualified personnel in accordance with detailed
procedures. Welding and NDE activities observed and reviewed were
performed in accordance with the applicable code and procedure
requirements.
M1.5 Low Pressure Injection Flow Instrument Surveillance Interval Exceeded
a. Inspection Scope (62707)
The inspectors interviewed licensee personnel and reviewed documents and
work orders associated with the low pressure injection (LPI) system flow
instrumentation surveillances.
Enclosure 2
9
b. Observations and Findings
On October 7, 1997, the inspectors requested documentation to verify the
testing of the LPI system. On October 10. 1997, with Unit l.in a
refueling outage. Unit 2 at 100 percent power, and Unit 3 in hot s
shutdown, the licensee identi'fied that the surveillance for the.flow
transmitters had not been completed on Unit 1 since January 26, 1995,
and onUnit 3-since February1
1995.
The procedure containing this calibration had been performed onUnit 1.
and 3, but only the calibration of the differential pressure indicator
had:been performed. The complete surveillance, including the flow
transmitters, had been completed for Unit 2 on July 21, 1997. Following
identification of the omission, the complete calibration procedure was
completed for Unit 1 on October 11. 1997, and for Unit 3 on October 10.
1997, with no discrepancies noted.,.
An investigation was initiated to verify no other omissions of TS
surveillances. PIP 7-097-3465 and LER 50-269/97-09 were generated. The
investigation revealed no other missed TS surveillances. The root cause
was identified as failure to follow procedure. The surveillance had
been scheduled, but the technicians did not perform the procedure as
specified. Failure to complete required TS surveillances is a violation
(VIO) of TS requirements and is identified as VIO 50-269,287/97-15-01:
Failure to Complete Required TS Surveillances on LPI Flow Instruments.
c. Conclusions
The failure by maintenance personnel to complete a Technical
Specification required surveillance on low pressure injection flow
instruments resulted in a violation.
M1.6 Steam Generator (SG) Eddy Current Examinations
a. Inspection Scope (50002)
The inspector reviewed the licensee's program and procedures for eddy
current analysis, and observed the activities of the resolution analyst
team for the Oconee 1 outage, which commenced on September 18. 1997.
The procedures reviewed were as follows:
NDE-701, Multifrequency Eddy Current Examination of Steam
Generator Tubing at McGuire, Catawba. and Oconee Nuclear Stations.
Revision 3, Field Change 97-09. September 9. 1997.
NDE-703, Evaluation of Eddy Current Data for Steam Generator
Tubing, Revision 5, Field Change 97-10. September 9, 1997.
Enclosure 2
01
10.
- :NDE-707, Multifrequency Eddy Current Examination of Non-ferrous
Tubing. Sleeves and Plugs Using a Motorized Rotating Coil Probe.
Revislon 3,.Field Change 97-13, September 16, 1997.
NDE-708, Evaluation of Eddy Current Data for Non-ferrous Tubing,
Sleeves and Plugs Using a Motorized Rotating Coil Probe,
Revision 3, Field Change 97-11, September 9, 1997.
Data Management/System Administration Guidelines - Oconee Unit 1
End.oftCycle-17JEOC-17). Revision 0, September 17. 1997.
Eddy Current Guidelines', Oconee Nuclear Station, Unit 1, EOC-17.
Revision 0, September 17, 1997.
The licehsee's eddy current data evaluation facility is located on the
grounds of the McGuire Nuclear Station, near Charlotte, North Carolina
(NC).
For the Oconee Unit 1 SG eddy current examinations the primary
analysts were working in Lynchburg, Virginia (VA)- and the secondary and
resolution analysts were working at the licensee's facility.
O b. Observations and Findings
As required by the licensee's program, eddy current data were being
analyzed by two independent groups of analysts, referred to as the
primary and secondary analysts, with differences between the two
resolved by independent resolution analysts. The primary analysts for
this Oconee Unit 1 outage were working at the Framatome facility in
Lynchburg, VA, and the secondary and resolution analysts were working at
the licensee's facility at the McGuire site.
The inspector observed the activities of the resolution analysts during
resolution of differences between the results of primary and secondary
analyses. As a part of the resolution process, the analysts were able
to bring past inspection data on the screen for direct comparison of
previous signals with the current data.
c. Conclusions
The licensee's process for the evaluation of steam generator eddy
current data was being conducted in accordance with current industry
guidelines and expectations.
Enclosure 2
M1.7 Maintenance on Turbine-Driven Emergency Feedwater Pump (TDEFWP) Turbine
Steam Supply Valves
a. Inspection Scope (61726)
A Unit .2
TDEFWP .surveillance test was scheduled to be performed on
October 28, 1997, and maintenance activities were scheduled to be
performed the same Iday before pump testing.
The inspectors reviewed
surveillance test procedure PT/2/A/0600/12, Turbine Driven Emergency
Feedwater Pump Test,:Revision 53: reviewed maintenance procedure
MP/0/A/1840/040, Pumps-Motors-Miscellaneous Components-Lubrication-Oil
Sampling-Oil Change, Revision 6; reviewed operating procedure
OP/2/A/1106/06. Enclosure 3.13, Isolation and Return of Main Steam
Supply to the TDEFWP, written October 30..1997: discussed the
maintenance and testing activities with operations, maintenance, work
control and engineering personnel: observed various maintenance and
testing activities; reviewed the UFSAR, design basis documentation, and
associated system drawings; and observed pre-job briefings and various
operator actions in support of maintenance and testing activities in'the
control room.,
b. Observations and Findings
At 5:32 a.m., on October 28, 1997, the Unit 2 TDEFWP was removed from
service for planned maintenance in preparation for a quarterly TDEFWP
surveillance test. Maintenance activities included analysis of the
TDEFWP bearing oil and repair of 2SD-307. a drain valve in the main
steam supply line to the pump turbine. In preparation for the repairs
to the steam line drain valve, main steam to the TDEFWP was isolated;
auxiliary steam from the Unit 3 main steam line was available.
Oil samples were obtained from the inboard and outboard pump bearing
housings and analyzed; the results indicated that the sample was
contaminated with suspended solids. A second sample was obtained and
met acceptance criteria: the pump was declared operable (the remaining
steam drain valve repair did not require that the TDEFWP be inoperable
since auxiliary steam was available and at the required pressure).
To ensure that the pump bearings were unaffected, engineering personnel
proposed running the pump to demonstrate that the bearings were not
damaged and confirm the results of the second oil sample. Operations
personnel had already returned the TDEFW pump to service under the
assumption that, since the second sample results met acceptance
criteria, the pump was operable. Although the pump run proposed by the
engineering personnel was a conservative measure to demonstrate pump
operability, a miscommunication between the organizations resulted in a
premature return to service of the TDEFWP. Station PIP 097-3797 was
Enclosure 2
12
initiated to address the discrepant oil samples and subsequent decision
to test the pump bearings.
On October 29. 1997, a performance test of the TDEFWP-was-performed to
demonstrate that the pump bearings were functional. The inspectors
observed the pump start and run: no discrepancies were identified..
The inspectors questioned a maintenance supervisor why the initial oil
sample was contaminated. Maintenance technicians initially had drawn
the oil samples .througha.
small piece of plastic tubing by inserting one
end of the tubing into the bearing housing and using a hand-pump to
transfer the sample from the housing through the plastic tube and into a
sample bottle on the other end of the tube. Apparently, the end of
plastic tubing:had traveled along the inner wall of the bearing housing
and disturbed a film of debris on the wall surface, which was drawn into
the sample bottle. To obtain.the second sample, maintenance technicians
drained the oil from the bearing housings into a container. The oil was
stirred, and a sample was taken from the mixed medium.
The inspectors determined that the initial oil sample had not been
obtained after the pump had been run to ensure that the sample
represented a well-mixed, homogenous population of oil. The inspectors
reviewed maintenance procedure MP/0/A/1840/040. Pumps-Motors
Miscellaneous Components-Lubrication-Oil Sampling-Oil Change, Revision
6. and determined that the procedure did not require that the pump
operate prior to sampling to ensure adequate mixing of the oil.
The
inspectors discussed sampling methodology with a maintenance supervisor,
who indicated that sometimes pumps are run prior to oil sampling, but
not always. The inspectors expressed concern that the practice of not
running a pump, or other piece of equipment with components requiring
oil lubrication, prior to obtaining an oil sample could fail to reveal
contaminants in the sample and, thereby, contaminants in the population.
The inspectors considered the practice a weakness in the oil sampling
methodology.
The inspectors verified that the TDEFWP was restored to operable status
within the time allowed by TS. The inspectors also observed portions of
the maintenance to repair the steam leak on 2SD-307, which was completed
on October 29, 1997. Operations personnel raised concerns with
water/steam hammers associated with returning the isolated portion of
main steam supply piping to service. Although this realignment had been
performed in the past, it was not proceduralized and controlled to
minimize the risk of water/steam hammers. Operations requested that a
procedure be developed to govern the steam line's return to service.
The procedure. OP/2/A/1106/06. Enclosure 3.13. Isolation and Return of
Main Steam Supply to the TDEFWP. was developed on October 30, 1997. The
inspector reviewed the procedure and identified no concerns. The steam
line was returned to service without incident. The inspectors
Enclosure 2
0
13
considered the request for a procedure to govern the realignment a
conservative measure to protect the piping and structural supports.
c. Conclusions
The inspectors considered the practiceiof obtaining .an oil sample,
without running the associated equipment a weakness in the oil sampling
methodology. The request for a procedure to govern the realignment of
the Unit 2 TDEFWP steam supply was a conservative measure to protect the
piping and structural supports.
M2
Maintenance and Material Condition of Facilities and-Equipment
M2.1 Wronq ServiceWater Valve Parts
a. Scope of Inspection (61726)
During the inspection period, the licensee was rebuilding several valves
in the LPSW system. The inspectors followed activities on two valves.
O b. Observations and Findings
During re-assembly of valve 1LPSW-565. supply to reactor building
auxiliary coolers, maintenance personnel observed that the new trunnion
parts could not be installed properly. The trunnions connect the bottom
and top of the ball valve to the operating shaft; thus allowing ball
rotation/movement. The new trunnions were approximately 1/4-inch taller
than the removed trunnions. PIP 097-4025 was initiated on November 11,
1997, the day of discovery.
Investigation indicated that the eight-inch trunnion parts intended for
1LPSW-565 had been installed into 1LPSW-4, the 1A LPI cooler outlet
isolation valve, which was a ten-inch valve. This valve had been
returned to service. The 1A train of LPI was declared inoperable and
the 1B LPI train was available for service as required in Selected
Licensee Commitment 16.5.6. Tentative licensee review indicated that
the parts had been marked incorrectly and not detected prior to
dispersal from the licensee's supply.
The eight-inch parts were removed from 1LPSW-4, examined and re
certified. The 10-inch parts were re-certified and installed in 1LPSW-4
and the eight-inch parts inspected and installed in 1LPSW-565. Both
valves were tested and returned to service. As of the end of this
period, the PIP and its attendant investigation were not complete.
Unresolved Item (URI) 50-269.270,287/97-15-02, Valve Parts
Identification Problem, is identified to track this issue.
Enclosure 2
14
c. Conclusions
Assembly of LPSW valves with the wrong parts resulted in an Unresolved
Item concerning parts identification.
M2.2 Once-Through-Steam-Generators (OTSGs)
a. Inspection Scope (50002)
During the week of September 8. 1997. the inspectors reviewed licensee
and contractor reports related to the material condition of the Oconee
OTSGs. The reports reviewed included the licensee's latest steam
generator maintenance, outage summary reports for each of the units: a
component .health status determination report prepared by the licensee: a
series 'of reports prepared by Dominion Engineering Incorporated (DEI)
concerning the condition of the Oconee OTSGs: and Asea Brown Boveri
Combustion Engineering test reports about eddy current and pressure
testing-of Unit 3 OTSG tubes pullediduring the last outage.
b. Observations and Findings
Licensee Outage Summary Reports
The review of outage summary reports showed the following data
concerning the number of tubes plugged during the last outage, why they
were plugged, and the total number of tubes currently plugged in each
OTSG.
Unit 1
Unit 2
Unit 3
EOC-16 (11/95)
EOC-15 (4/96)
EOC-16 (10/96)
SG 1A
SG 1B
SG 2A
SG 2B
SG 3A
SG 3B
Dings
7
5
-
-
-
Erosion/Corrosion
17
47
0
6
23
13
Groove Intergranular 2
42
119
54
51
16
Attack (IGA)
Unit 1
Unit 2
Unit 3
EOC-16 (11/95)
EOC-15 (4/96)
EOC-16 (10/96)
SG 1A
SG 1B
SG 2A
SG 2B
SG 3A
SG 3B
Wear
4
1
8
14
2
5
% Through-Wall (TW) 27
36
11
43
3
9
1
0
0
0
1
Enclosure 2
15
Other
7
17
7
12
9
6
IGA or Precursor
-
-
5
29
-
Groove IGA
IGA:
-
-
47
55
26
42
Lane & Wedge
-
-
2
0
-
Upper Roll
-
-
-
-
-
19
Transition
Total this Outage
65
148
199
213
115
110
Previous
334
1177
138
268
455
371
Total Plugged
399
1325
337
481
570
483
% This Outage
0.42% 0.95%
0.89% 1.37%
0.74%
0.71%
.
Total Tubes
15,531 15,531
15,531 15.531 15.459 15.531
% of Total
2.57%
8.71%
2.17%
3.10%
3.69%
3.11%
Tubes
While the data from these reports indicate that OTSG lB is in the poorer
condition (8.71% plugged), the Units 2 and 3 OTSGs had a significant
number of tubes plugged due to freespan axial indications. (The
freespan axial indications are referred to as Groove IGA and IGA in the
data set.)
The outage reports for Units 2 and 3 described tube pulls that were done
as a result of a Babcock and Wilcox Owners Group (BWOG) program to
investigate free-span cracking, originally found in the-Oconee Unit 1
OTSG. There were four full-length tubes removed from the 2A OTSG. and
three full-length and two partial-length tubes pulled from the 3A OTSG.
These tubes were in addition to the seven tubes pulled from the Oconee
Unit 1 OTSG in 1994, where the free-span cracking (IGA/IGSCC) was
initially confirmed.
Electrosleevinqm field trial
Other items of interest in the outage summary reports included the fact
that during the Unit 1 outage in November 1995, Framatome Technologies
conducted a field demonstration of the Electrosleevingm process for
electro-plating metallic Nickel on the inside surface of OTSG tubes to
-seal off existing defects and provide a barrier against further
degradation. Nine tubes that were scheduled to be plugged were selected
Enclosure 2
16
and Electrosleeves" were deposited at the first support plate. The
Electrosleevingm process was jointly developed by Framatome Technologies
and Ontario Hydro Technologies. Oconee Unit 1 was the first field
deployment of the system. The use of the process under field
conditions, including processing of the electroplating solutions as
contaminated, hazardous waste, was reported as a success. The condition
of the tube and the resulting Nickel plating were not reported, in that
the tubes were plugged after-plating.
OTSG lB Feedwater Nozzle Leakage
The inspectors noted that the Unit 1 outage summary reported that repair
work was done to remove leak-seal clamps from the flange connections
between main feedwater risers No. 1 and No. 32 and the 1B OTSG shell.
This item was of interest because'the inspectors had learned that these
same two flange connections were found to be leaking last January, while
the unit wasishut down for other reasons, and were leak-sealed again.
During the review of how the licensee was handling the repeat leakage
problems on feedwater risers No. 1 and 32. the inspectors questioned
whether these failures would be considered a functional failure under
the maintenance rule. Discussions with the engineers responsible for
administering the maintenance rule program revealed that for the
feedwater system, because it is a Class 2 system, the absence of system
leakage was not one of the fifteen listed functions monitored by the
program. After additional discussions, which included the site
Engineering Manager, the licensee decided to generate a PIP form to
document the repeat failure for trending purposes, and to question
whether system leakage should be a maintenance rule function of the
portion of the feedwater system inside the containment.
Dominion Engineering, Inc. (DEI) Reports
The inspectors reviewed the following three reports concerning the
Oconee OTSGs:
DEI-483 - Evaluation of Steam Generator Tube Damage Mechanisms
DEI-484 - Steam Generator Life Prediction Analysis
DEI-485 - Review of Chemistry and Operating Procedures
These reports, dated February 1997, were provided as an independent
analysis of the Oconee 1, 2. and 3 OTSGs. During discussions with
licensee engineering, operations, and chemistry personnel, the
inspectors learned that as a direct result of recommendations in the DEI
reports, the licensee had already implemented changes.
Enclosure 2
17
The licensee had revised operations procedure OP/1/A/1106/08. Steam
Generator Secondary Hotsoak, Fill, Drain, and Layup, Revision 35.
because DEI had concluded that'the condition of the secondary water
chemistry during startup operations was more critical to the condition
of the OTSG tubes than the water chemistry during full-power operations.
The licensee had ordered equipment, and was preparing to modify the
feedwater system for the injection of titanium oxide during'the next
refueling-outage for each unit. The addition of titanium oxide is to
provide an inhibitor in an attempt to tie up sodium hydroxide (NaOH),
especially during startups, to assist in the prevention of additional
intergranular attack (IGA) to the outside surface of the OTSG tubing.
ABB Combustion Engineering Nuclear Operations (ABB CENO) Reports
The inspectors reviewed the following reports provided to the licensee
by ABB CENO concerning tests conducted on three full-length, and two
partial-length tubes removed from the 3A OTSG:
447-PENG-TR-086, Comparison of Field and Laboratory Eddy Current
Testing (ECT) Results, Helium Leak Tests and Observations of
Oconee Unit 3 Steam Generator Tube Sections
447-PENG-TR-091, Burst Testing of Oconee 3 Steam Generator Tube
Sections
The tests reported by ABB CENO were presented in the reports in a
clinical fashion; that is,
the parameters and results of the tests were
presented without final conclusions. The conclusions concerning the
tests will be provided upon completion of the metallurgical analyses of
the tube sections. This part of the examination is still under way by
ABB CENO.
c. Conclusions
The condition of the Oconee OTSGs has seen additional licensee attention
through BWOG sponsored tube pulls in each unit, and the contract with
DEI to do an independent review of the Oconee steam generator program.
The failures of mechanical feedwater piping connections to the Unit 1B
steam generator were not being identified or trended as repeat failures.
M2.3 Repairs of Unit 1 OTSG Tubing
a. Inspection Scope (50002)
Through work observation, procedure and records review, the inspector
"-determined the adequacy of OTSG 1B tube repairs in response to eddy
Enclosure 2
18
current identified indications in the roll transition area of the upper
tube sheet (UTS).
b. Observation and Findings
Background
Eddy current inspection of OTSG lB tubes was performed during the
current outage (EOC-17). This inspection showed that certain tubes
exhibited indications at the roll transition region within the UTS and
at certain freespan locations. The UTS findications were identified as
single or multiple axial or volumetric which typically require roll
repair or plugging. In general, the subject indications were
characterized as internal diameter intergranular stress corrosion cracks
(IGSCC).
The volumetric indications were believed to be the result of
intergranular attacks (IGA). In order to investigate these indications
further, the licensee selected five tubes with representative indication
for investigation. These tube sections were pulled and sent to a
laboratory for destructive and non-destructive examinations to determine
the failure mechanism. At the time of this inspection. November 3,
1997, the licensee had not received an official report on the subject
tubes. At the completion of the eddy current examination the licensee
had identified approximately 1936 tubes in OTSG 1B that required repair.
This repair involved the re-roll of a one-inch long section of tube
below the region where tube defects were identified. The repair
established a new mechanical tube-to-tubesheet structural joint and a
new primary pressure boundary within the tube.
Observation
Through work observation. document review and discussions with the
licensee's cognizant personnel and the vendor's onsite lead engineer,
the inspector ascertained the following:
Tube re-roll repairs were being performed by Framatome
Technologies, Inc., (FTI). The work was being performed under
FTI's QA program and as such FTI was responsible for control of
equipment and processes. Representatives of Duke's Supplier
Verification Group observed the subject activity and reviewed
applicable procedures, equipment calibration records and personnel
qualification records for adequacy. The verification group found
them-to be satisfactory.
During the inspection, as of November 3. 1997. the roll repair activity
was still in progress. The inspector observed the repair of selected
tubes to verify that the applied torque to achieve the desired tube
Enclosure 2
19
expansion did not exceed established procedural limits: that post-roll
tube diameter was within established maximum and minimum limits; that
equipment was properly calibrated and performing its functions and that
personnel were properly qualified. The controlling procedure for the
repair was FTI's Document 1246068A, Revision 3 dated June 18, 1997. In
addition, the inspector reviewed FTI's two nonconformance reports
applicable to this activity.. One ofthese involved a communication
problem between the computer ahd the roll expander tool and the other
involved operator error resulting in the inadvertent repair of 13 tubes.
Corrective measures taken to prevent recurrence of these problems were
considered appropriate.
Following the close of this inspection, the inspector obtained the
following information on Oconee's Unit 1 OTSG tube repairs.
Tubes Pluqqed
1A
52 tubes were removed from service. Five were located in the lower
tubesheet (LTS).
1B
122 tubes were removed from service. Five were located in the
UTS roll transition area of interest.
Tube Pulls
1A
Five tubes were pulled from LTS. These were scheduled for
analysis.
lB
Five tubes were pulled from UTS and sent for analysis. Two of
the three samples with volumetric indications were subjected to
nondestructive and destructive examinations.
Re-Roll
1A
39 tubes were re-rolled in the UTS that will remain in service
18
Approximately 1956 tubes were re-rolled in the UTS and will remain
in service.
In addition, the inspector determined that the subject repair activity
was implemented with relatively good results in that only five re-rolled
tubes failed to meet acceptance criteria and were plugged. Also, out of
approximately 2000 tubes roll repaired, only 16 were re-rolled
- -
inadvertently.
Finally, by letter dated November 18, 1997, from W. R. McCollum, Jr., to
the Nuclear Regulatory Commission, the licensee indicated that all roll
repaired tubes in the Oconee Unit 1 OTSG B UTS region, have been
Enclosure 2
20
classified as Category C-3 as defined in Technical Specifications 4.17.3.d. Therefore all roll repaired tubes will have the new roll area
inspected during future inservice inspections.
c.
Conclusion
The licensee implemented repairs in OTSG.B tubes ofUnit Pin a
conservative manner, following administrative controls and applicable
controlling procedures. Technical support provided good guidance and
oversight during the activity.
III. Engineering
E2
Engineering Support of Facilities and Equipment
E2.1 Review of Engineering Backlog
a. Inspection Scope (37550)
The inspectors reviewed the engineering support of facilities and
equipment as demonstrated by backlogs of engineering work associated
with operator workarounds. work orders on engineering hold. PIP reports,
nuclear station modifications. minor modifications, and temporary
modifications (TMs). Applicable regulatory requirements included 10 CFR
50 Appendix B and the licensee's Quality Assurance program.
b. Observations and Findings
The inspectors noted that the overall backlog in engineering had
increased during the past year. A significant portion of the increase
was in the number of PIPs. The licensee attributed this increase to the
Unit 2 pipe rupture event that occurred in September 1996 and the
ensuing code compliance work that was performed on all 3 units. The
inspectors found that the number of PIPs open for greater than 6 months
has declined for the past 3 months to the current level of approximately
315. However, this total was still higher than that in October 1996.
The licensee tracks PIPs greater than 6 months old and has established
goals to reduce this number to 204 by the end of the year.
The inspectors reviewed the active TMs and found that 12 had been
installed for greater than 18 months. Six were installed on Unit 1,
which was in a refueling outage. Of those six on Unit 1, five were
-
-
being closed or removed during this outage. The one remaining item (TM
1188) was to be closed in the next Unit 1 end-of-cycle (1EOC18)
refueling outage which was scheduled for March 1999. The licensee
indicated that a nuclear station modification was required. Temporary
modification number 1188 was installed because the 1D3 reactor building
Enclosure 2
21
auxiliary cooling coil was leaking and closing the isolation valves both
upstream and downstream of the coil did not fully isolate the leak. The
TM installed blind inserts in the LPSW line to isolate.the 1D3 'reactor
.building auxiliary cooling coil that was leaking. The inspectors
reviewed the TM and associated 10 CFR 50.59 safety evaluation and)found
them to be acceptable. The licensee indicated that two additional TMs
greater than 18-months old were also being closed. This would leave
five TMs still open that were greater than 18 months old;., however, .none
of the remaining ones involved safety-related systems.
The inspectors-found that the Mechanical Civil Equipment Group (MCE) had
a, much larger, backlog of work orders on hold over 30 days old than those
in the other engineering groups. The inspectors discussed this with the
licensee and found that MCE considered most of these items to have a
lower priority as compared to other work items such as operator
workarounds or PIPs. The inspectors discussed the status of most of
these items with the supervisors and found that the technical basis for
these items having a lower priority appeared to be acceptable.
The inspectors found that the backlog of operator workarounds was up due
to 11 new items being added between July and October of this year. The
licensee indicated that this increase was a reflection of their ability
to better identify from the PIP database those issues that are
considered operator workarounds and was not reflective of a lack of
engineering response.
The inspectors found that 36 modifications were unscheduled or
unslotted. This issue had been identified during the licensee's
Modification Selection/Activation Process Performance Assessment SA-97
58 conducted in May 1997. The assessment included a recommendation to
management to have the large number of outstanding activated
modifications be evaluated by an independent review group to assure that
each modification can be justified. The licensee indicated that this
review was scheduled for November 1997.
c. Conclusions
Engineering support to operations and maintenance was adequate.
E3
Engineering Procedures and Documentation
E3.1 Review of Modifications
a. Inspection Scope (37550)
The inspectors reviewed the modifications to the Unit 1 LPSW system and
an unrelated electrical minor modification.
The LPSW modifications
Enclosure 2
22
review included issues identified by previously identified NRC item IFI
50-269,270,287/96-13-03 related .to service water system modification and
testing., The following modifications were reviewed:
NSM-13001/AM1, Install Minimum Flow Piping at LPSW Pumps. dated
June 17. 1997
NSM-13001/AM2,. Tie in Minimum Flow Piping to LPSW Pumps, dated
August 15, 1997
NSM-13001/CM1 Installation of Valve 2LPSW-139, dated July 30, 1997
NSM-13002, Replace 1A, lB, and.1C LPSW Impellers, dated May 28.
1997
NSM-13022, Replace Valves 1LPSW-251. -252, -254. and -256. dated
August 28. 1997
NSM-12977, Replace Valves 1LPSW-4, -5. -6,
and-15. dated
September 11, 1997
S*
ONOE-10447, Hot Taps for 14-inch and 36-inch LPSW Piping, dated
August 19. 1997
ONOE-11028, Installation of 24-inch Split Tee Fitting on LPSW
Piping, dated October 19. 1997
ONOE-11029, Perform 24-inch Hot Tap and Line Stop on LPSW Piping,
dated October 23, 1997
ONOE-8790. Analog to Digital Conversion of Reactor Protection
System (RPS) Channels A.B.C,and D Hardware, dated April 1. 1997
Applicable regulatory requirements included American National Standards
Institute (ANSI) N45.2.11-1974. Quality Assurance Requirements for the
Design of Nuclear Power Plants. 10 CFR 50.59, 10 CFR 50 Appendix B,
UFSAR, and the licensee's Quality Assurance (QA) program.
b. Observations and Findings
Design change documentation adequately identified and referenced
appropriate design inputs. Post-modification testing was adequate to
verify the function of modified equipment. In particular, the
--
modification to install the new pump impellers included adequate flow
testing to establish baseline values for Section XI testing. The
testing verified that pump capacity was essentially equal to previous
capacity and consistent with the vendor pump performance curves.
Testing was performed by the vendor to verify that the minimum flow
Enclosure 2
23
capacity (500 gallons per minute) provided by the installed
recirculation lines was adequate for at Teast,24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of pump operation
as required by the recirculation line modification design criteria.
Severallmi.nor modifications were implemented to facilitate installation
of in-line piping stops (MARBO plugs) for isolation to replace valkes or
pump changes. Implementing procedures included contingency actions to
address potential problems anticipated during the plug replacement and
removal. Appropriate seismic analysis. was performed to facilitate
temporary hardware for plant installation. Field walkdowns demonstrated
that seismic supports were consistent with design drawings.
c. Conclusion
Design control for the Unit I LPSW modifications was good. The 10 CFR
50.59 evaluations were detailed and thorough.
E7
Quality Assurance in Engineering Activities
E7.1 Review of Engineering Self-Assessments
a. Inspection Scope (37550)
The inspectors reviewed engineering self-assessment activities that were
performed in 1997. Applicable regulatory requirements included 10 CFR
50 Appendix B. and the licensee's QA program.
b. Observations and Findings
The inspectors reviewed 13 self-assessment reports of engineering
support and design control activities that were performed in 1997 and
found them to be adequate. The assessments resulted in several findings
and recommendations being identified. The inspectors found that the
reports were clear and concise and that the findings were being tracked
by the corrective action program.
c. Conclusions
The engineering self-assessments performed in 1997 were effective in
identifying and assuring correction of deficiencies in engineering
performance.
E8
Miscellaneous Engineering Issues (92903)
E8.1 (Closed) IFI 50-269,270,287/96-09-03: Expected End-of-Cycle Heat Loads
- This item addressed an apparent inconsistency between the UFSAR and
supporting design calculations regarding end-of-cycle SFP heat load
Enclosure 2
e
24
values associated with normal and abnormal SFP loading. The licensee
was revising the SFP heat load calculation to address anticipated
changes in fuel design and cycle lengths at the time the item was
identified. The IFI was identified to track the licensee's verification
that the UFSAR specified heat load values for the two conditions bounded
the calculated values.
The inspectors reviewed OSC-4998, Units 1 and 2 SFP Heatup Rate
Calculation, Revision 7. and UFSAR Sections 9.1.3.1.1 and 9.1.3.3.1,
which were revised December 31, 1996, to verify resolution of this item.
The,,calculation determined the bounding heat load conditions for the
normal _and abnormal SFP loading using fuel burn-up assumptions
appropriate to the anticipated core design and cycle length. The normal
case heat load was within the previously specified UFSAR value. The
abnormal heat load for future anticipated fuel conditions slightly
exceeded the previously specified UFSAR value for this case. Both
values were within the capacity of the SFP cooling system specified in
the UFSAR. The December 31, 1996, UFSAR revision deleted the specific
heat load values and core off load descriptions from the UFSAR. The
revision additionally clarified that the abnormal case (full core
offload) was the routine condition during refueling outages.. The
inspector concluded this item was adequately resolved.
E8.2 (Clsd BaR_
52
7-03 Revision 0
0 and 1: Post LOCA Boron Dilution
Design Basis Not met Due to Deficient Design Analysis
(Closed) URI 50-269,270287/97-01-06: Boron Dilution Flow Path
Inoperability
This issue involved the identification of a possible failure of the Post
LOCA Boron Dilution flowpaths though LP-1 and LP-2. In Revision 0, the
licensee identified through an engineering evaluation of Generic Letter 96-06, that LP-1, LP-2. LP-103, and LP-104 could be inoperable due to
thermal over pressurization. This would remove both active boron
dilution flow paths from service. Following questioning by the
inspectors, the licensee realized they had conservatively neglected the
impact of the holes drilled in the upstream disk of LP-1 and the bonnet
reliefs on LP-2. These modifications had been made in 1985, 1986, and
1987. Therefore, the active path through LP-1 and LP-2 were operable
from the time these modifications were completed to the present. LP-103
and LP-104 were inoperable from initial installation until the recent
outages when a void was introduced between the valves. Engineering will
perform an evaluation to determine if any other actions are recommended
to provide additional margin for LP-1 and LP-2. This evaluation is
captured inaPIP 0-097-0279: therefore, this LER and URI are closed.
Enclosure 2
25
E8.3 (Closed) URI 50-269,270,287/97-12-02: Fuel Load UFSAR Statements
This URI concerned a discrepancy between the UFSAR and two existing
refueling 10 CFR 59.59 evaluations. Specifically, UFSAR
Section 4.3.3.1.4 stated in part that "Each fuel rod is identified by an
enrichment code, and the-design of the reactor is such that only dhe
enrichment is used per assembly." However, the licensee had installed.
fuel in Unit 2 in 1994 and Unit 3 in 1997 that contained different
enrichment (axial blankets) without indicating this discrepancy in their
safety evaluations or clarifying the statements in the UFSAR that
described one enrichment fuel.
This was an oversight, but was not
recognized until after the refuelings had occurred. Once recognized in
PIP 0-097-0448 (February 3, 1997), it was not addressed in the next
UFSAR update issued in July 1997 nor were the 10 CFR 50.59 evaluations
changed. PIP 0-097-2511, initiated on August 13. 1997, by an
independent site review, brought the matter to a head and an
investigation was performed * The 10 CFR 50.59 evaluation for the
pending Unit 1 refueling had yet to be, completed at the time that PIP 0
097-2511 was initiated. The licensee subsequently completed their
evaluation of the problem with the issuance of Root Cause Investigation
for PIP 0-097-2511, dated September 23, 1997. The inspectors discussed
the problem with the licensee and observed the corrective action scheme.
The investigation revealed that several causes had prevented a proper
10 CFR 50.59 review for a fuel change or the accomplishment of UFSAR
updates to reflect actual fuel configurations. The investigation
summary root causes were primarily attributed to misjudgement in the
level of UFSAR review for the 10 CFR 50.59 evaluation and misjudgement
in the level of validation and verification needed to assure corrective
action commitments such as a PIP were adequately documented and
responsibilities were assigned.
Based on the above, the inspector concluded that the failure to revise
the UFSAR to reflect the different fuel enrichments was a violation of
10 CFR 50.71(e). This is identified as VIO 50-270.287/97-15-09:
Failure to Update the UFSAR Regarding Fuel Enrichment.
IV.
Plant Support Areas
R1
Radiological Protection and Chemistry Controls
R1.1 Tour of Radiological Protected Areas
a. Inspection Scope (84750)
The inspectors reviewed implementation of selected elements of the
licensee's radiation protection program as required by 10 CFR Parts
Enclosure 2
0
26
20.1902. and 1904. The review included.observation of radiological
protection activities for control of radioactive material, including
pQstlngs and labeling, and radioactive waste processing.
b. Observations and Findings
At the time of the inspection. Unit 1 was shut down for a scheduled 54
day refueling outage (U1EOC17). The inspectors reviewed survey data of
radioactive material storage areas. Observations and survey results
determined the licensee was effectively controlling and storing
radioactive material and all material observed was appropriately labeled,
as required by 10 CFR Part 20.1904. The inspectors determined the
licensee was processing radioactive waste to maintain exposures As-Low
As-Reasonably-Achievable (ALARA) and to minimize quantities of
radioactive waste stored on site.
The inspectors also reviewed anddiscussed radioactive liquid processing
during tours of the radioactive waste (radwaste) facility and observed
part of a radioactive liquid discharge in progress. The licensee had
recently installed a new radwaste resin sluice system which allowed for
the transfer of spent resin from the Units 1, 2, and 3 spent fuel pools.
purification and deborating demineralizers to the resin batch tank
located in the Radwaste facility. The chief purpose of the modification
was to perform radwaste spent resin sluices inside of the facility and
not be affected by weather conditions. Another benefit of the
modification was that resin sluices could be performed in shorter times.
also minimizing personnel radiation exposure.
During tours of the auxiliary building and radioactive waste
storage/handling facilities, the inspectors observed the licensee had
performed radiological work in 2 onsite buildings, the reactor coolant
pump building and the ice blast building, not specified as monitored
pathways for radioactive material in the licensee's Offsite Dose
Calculation Manual.
The inspectors requested additional information
regarding the licensee's evaluations of the intended work scope to be
performed in the buildings and the associated radiological engineering
controls that would be applicable. Pending follow up information to be
provided and reviewed, one Unresolved Item (URI) was identified
concerning the applicability of monitoring requirements of Criterion 64
of 10 CFR 50 Appendix A and reporting requirements of 40 CFR 190 and 10
CFR 50.36a. This issue will be tracked by URI 50-269.270.287/97-15-03:
Determine the Applicability of Monitoring Requirements of Criterion 64
of 10 CFR 50 Appendix A and Reporting Requirements of 40 CFR 190 and 10
-*
CFR 50.36a.Regarding Potential of Unmonitored Release Pathways.
Enclosure 2
27
c. Conclusions
Based on observations and procedural reviews, the inspectors determined
the licensee was effectively maintaining controls for radioactive waste
and waste processing. One URI was identified to determine monito.ing
requirements for radiological work in two onsite buildings. The
licensee':s initiative to improve resin sluice processing systems to
maintain exposures ALARA and to improve environmental controls for resin
sluicing was viewed as a strength.
R1.2 Water Chemistry Controls
a. Inspection Scope (84750)
The inspectors reviewed implementation of selected elements of the
licensee's water chemistry control program for monitoring primary and
secondary water quality as described in the TS limits, the Station
Chemistry Manual, and the UFSAR. The review included examination of
program guidance and implementing procedures, as well as analytical
results for selected chemistry parameters.
b. Observations and Findings
The inspectors reviewed selected analytical results recorded for Units
1, 2 and 3 reactor coolant and secondary samples taken between August 1,
1997, and October 31, 1997. The selected parameters reviewed for
primary chemistry included dissolved oxygen, chloride, pH. and fluoride.
The selected parameters reviewed for secondary chemistry included
hydrazine, iron, and chloride. Those primary parameters reviewed were
maintained well within the relevant TS limits for power operations.
Those secondary parameters reviewed were maintained according to station
procedures. During tours, the inspectors also observed the licensee
performing primary system chromate sampling in accordance with licensee
procedures. The inspectors observed that the licensee exercised good
radiological work practices during the sampling evolution.
c. Conclusions
Based on the above reviews, it was concluded that the licensee's water
chemistry control program for monitoring primary and secondary water
quality had been effectively implemented, for those parameters reviewed,
in accordance with the TS requirements and the Station Chemistry Manual
for Pressurized Water Reactor water chemistry.
Enclosure 2
28
R1.3 Transportation of Radioactive Materials
a. Inspection Scope (86750, TI 2515/133)
The inspectors evaluated the licensee's transportation of radioacpive
materials programs for implementing the revised Department of
Transportation.(DOT) and NRC transportation regulations for shipment of
radioactive materials as required by 10 CFR 71.5 and 49 CFR Parts 100
through 177.
b. Observations and Findings
The inspectors reviewed and discussed licensee procedures and computer
tracking systems and determined that they adequately addressed the
following: assuring that the receiver has a license to receive the
material being shipped: assigning the form., quantity type, and proper
shipping name of the material to-be shipped: classifying waste destined
for burial: selecting the type of package required: assuring that the
radiation and contamination limits are met: and preparing shipping
papers.
Licensee's records for three shipments of radioactive material performed
since the last inspection of this area were reviewed and the inspectors
determined the shipping papers contained the required information. The
inspectors also determined the licensee had maintained records of
shipments of licensed material for a period of three years after
shipment as required by 10 CFR 71.91(a). In addition, the licensee
possessed a current certificate of approval (NRC Form 311) for their
"Quality Assurance Program Description for Radioactive Material Shipping
Packages Licensed Under 10 CFR 71."
c. Conclusions
Based on the above reviews, the inspectors determined that the licensee
had effectively implemented a program for shipping radioactive materials
required by NRC and DOT regulations.
R2
Status of RP&C Facilities and Equipment
R2.1 Meteorological Monitoring Proqram
a. Inspection Scope (84750)
-.
Section 2.3.3.2 of the UFSAR described the operational and surveillance
requirements for the meteorological monitoring instrumentation.
Enclosure 2
29
b. Observations and Findings
The inspectors toured the control room with cognizant.1 icensee personnel
and determined thatthe-meteorological instrumentation was operable and
that data for wind speed, wind direction, air temperature, and
,
precipitation were being collected as described in the UFSAR. -Records
revealed that the licensee had maintained-a high level of operability
for meteorology equipment during 1997. Wind speed and wind direction at
10 and 60 meters was operable approximately 99.3 percent, air
.
temperature approximately 99.3 percent, and precipitation 99.6 percent.
c. Conclusions
Based on the above reviews and observations, it was concluded that the
meteorological instrumentation had been adequately maintained and that
the meteorological monitoring program had been effectively implemented.
R7
Quality Assurance in Radiological Protection and Chemistry Activities
R7.1 Quality Assurance in Radiation Protection and Chemistry
a. Inspection Scope (84750, 86750)
10 CFR 20.1101 requires that the licensee periodically review the
radiation protection (RP) program content and implementation at least
annually. Licensee periodic reviews of the RP program were reviewed to
determine the adequacy of identification and corrective actions.
b. Observations and Findings
The inspectors reviewed the most recent QA audits in the area of RP.
chemistry, and transportation. These audits were accomplished by
reviewing RP procedures, observing work, reviewing industry
documentation, and performing plant walkdowns to include surveillance of
work areas by supervisors and technicians during normal work coverage.
The inspectors also reviewed documentation of potential radiological
problems or areas for improvement through the licensee's PIP.
c. Conclusions
The inspectors determined that the licensee was performing QA audits and
effectively assessing the radiation protection program as required by 10
CFR Part 20.1101. The inspectors also determined that the licensee was
- -
completing-corrective actions in a timely manner.
Enclosure 2
0II
30
R8
Miscellaneous Radiation Protection & Chemistry Issues (92904)
R8.1 (Closed) URI 50-269,270,287/97-01-07: Failure to Meet Requirements of
This issue involved the failure to have in place either a criticatity
monitoring system for storage and handling of new (non-irradiated) fuel
or an NRC approved exemption to this requirement contained in 10 CFR
70.24.
10 CFR 70.24 requires that each licensee authorized to possess more than
a small amount of special nuclear material (SNM) maintain in each area
in which such material is handled, used, or stored a criticality
monitoring system which will energize clearly audible alarm signals if
accidental criticality occurs. The purpose of 10 CFR 70.24 is to ensure
that, if a criticality were to occur during the handling of SNM,
personnel would be alerted to that fact and would take appropriate
action.
Most nuclear power plant licensees were granted exemptions from 10 CFR
70.24 during the construction of their plants as part of the Part 70
license issued to permit the receipt of the initial core. Generally,
these exemptions were not explicitly renewed when the Part 50 operating
license was issued, which contained the combined Part 50 and Part 70
authority. In August 1981, the Tennessee Valley Authority (TVA), in the
course of reviewing the operating licenses for its Browns Ferry
facilities, noted that the exemption to 10 CFR 70.24 that had been
granted during the construction phase had not been explicitly granted in
the operating license. By letters dated August 11. 1981, and August 31,
1987, TVA requested an exemption from 10 CFR 70.24. On May 11, 1988,
NRC informed TVA that "the previously issued exemptions are still in
effect even though the specific provisions of the Part 70 licenses were
not incorporated into the Part 50 license." Notwithstanding the
correspondence with TVA, the NRC has determined that, in cases where a
licensee received the exemption as part of the Part 70 license issued
during the construction phase, both the Part 70 and Part 50 licenses
should be examined to determine the status of the exemption. The NRC
view now is that unless a licensee's licensing basis specifies
otherwise, an exemption expires with the expiration of the Part 70
license. The NRC intends to amend 10 CFR 70.24 to provide for
administrative controls in lieu of criticality monitors.
The NRC has concluded that a violation of 10 CFR 70.24 existed. The NRC
--
has also determined that numerous other licensees have similar
circumstances that were caused by confusion regarding the continuation
of an exemption to 10 CFR 70.24 originally issued prior to issuance of
'the Part 50 license. After considering all the factors that resulted in
'-these violations, the NRC has concluded that while a violation did
Enclosure 2
31
exist, it is appropriate to exercise enforcement discretion for
Violations Involving Special Circumstances in accordance with
Section VII B.6 of the "General Statement of Policy and Procedures for
NRC Enforcement Actions"-(Enforcement Policy), NUREG-1600.
Fl
Conduct of Fire Protection Activities
F1.1 Licensee Identified Fire Protection Discrepancies
a. Inspection Scope (64704)
The inspectors reviewed the adequacy of the licensee's evaluations and
corrective actions on the following licensee identified fire protection
discrepancies in which PIP reports had been issued.
PIP No.
PIP Description
3-097-1483
Failure to Install Fire Detection in New Unit 3
Computer Room
0-097-1484
High Pressure Service Water (HPSW)/Fire Pump Enclosure
Was Not 3-Hour Fire Rated Construction
5-097-2667
Inoperable Fire Door Between Turbine and Auxiliary
Buildings
0-097-2806
Fire Protection Valves for Hose Stations Were Not
Stroke Tested
1-097-3309
Obstructed Fire Detectors in Unit 1 Reactor Building
b. Observations and Findings
The licensee's evaluations on these PIP discrepancies were thorough and
corrective action was appropriate. These identified discrepancies
demonstrated that the licensee's fire protection staff was performing
detail assessments of the site's fire protection program and were taking
appropriate action to identify the cause and take corrective action on
identified discrepancies. The inspector's observations and findings on
each of these PIP items are as follows:
PIP 3-097-1483: This issue involved the failure to extend the
automatic fire detection system to provide coverage for a new
computer room in the Unit 3 control room complex. The corrective
action for this PIP included the installation of automatic fire
detection for the Unit 3 computer room addition. In addition, the
modification in process for the Unit 1 and 2 computer rooms was
revised to include the installation of automatic fire detectors.
Enclosure 2
32
Section 9.5.1.5 of the Oconee UFSAR states that fire detector
locations were selected based on engineering judgement to monitor
areas containing vital equipment. The computer rooms adjacent to
the control rooms were not initially provided with automatic fire
detection coverage. but. the fire detection system. was provided for
this area during the upgrades to the plant fire alarm system in
the early 1990s.
Since the computers were not considered vital
equipment, automatic fire detection was not required to be
provided for this area during the NRC licensing review. This is
documented by the NRC Fire Protection Safety Evaluation Report
dated August 11, 1978. The cause for not providing fire detector
coverage for this area was identified by the licensee as a design
oversight since this area was not initially provided with fire .
detector coverage. Therefore, although.providing fire detector.
coverage for the computer rooms adjacent to the control room
complex is a good fire protection practice, the failure to
provided fire detection for these areas is outside the NRC
licensing basis for Oconee.
The inspector considered the licensee's identification and
correction of this problem as proactive.
PIP 0-097-1484: During a routine surveillance, the licensee
identified that the concrete roof construction of the HPSW/fire
pump room enclosure was equivalent to 1-hour fire rated
construction whereas the walls for these rooms had a 3-hour fire
rating.
Section 9.5.1.5.2 of the Oconee UFSAR states, "The HPSW pumps are
located in separate concrete block structures with power cables to
the motors being embedded in concrete floor. Separation is by
fire rated wall assemblies." The Oconee Fire Protection Safety
Evaluation Report dated August 11, 1978, states, "The HPSW pumps
are located in the turbine building, each in a small masonry room
enclosing the pump and motor... We find the basic water supply
system satisfies the provision of Appendix A to Branch Technical
Position (BTP) 9.5-1 and is,
therefore, acceptable."
The inspector reviewed the Oconee fire barrier drawing series
0-310K and 0-310L and noted that the drawings indicated a 3-hour
fire wall enclosure for the pumps. but did not address the fire
rating of the roofs/ceilings for the pump enclosures. The
licensee's PIP evaluation found the "as built" configuration
satisfactory since: (1)
HPSW pump rooms would not be exposed to
turbulent flame impingement from an oil pool fire; (2)
automatic
sprinkler systems installed in Turbine Building would cool, dilute
and suppress an oil pool fire before the fire reached the pump
Enclosure 2
33
rooms; (3)
combustible materials were not located on the under
side of the pump.room ceilings;-and (4)
heat from oil pool fire
which wasrnot'completely suppressed by the fire suppression system
would dissipate to the open Turbine Building and .would not
concentrate at the roofs of the HPSW .pump rooms.
Them Jnspector performed 'a walkdown inspection of the Turbine
Building and concluded that the licensee's evaluation and the fire
protection features provided for the areas were appropriate for
the hazards involved and should assure that a fire within the
Turbine Building would not damage both HPSW pumps.
The licensee issued PIP 0-097-3920 to add a note on the applicable
drawings for.drawing series 0-310K and 0-31OL-to indicate the fire
rating of the ceilings/roofs of the HPSW pump rooms had a 1-hour
fire resistance rating.
The fire resistance rating of the HPSW pump rooms was not an NRC
licensing issue: therefore, this item is not a regulatory issue.
The licensee's identification and evaluation for resolution were
considered positive actions.
PIP 5-097-2667: This issue was related to inoperable fire door
No. 325 on the 796' elevation of the Auxiliary Building. On
August 25, 1997. a member of the licensee's staff found door
number 325 with the locking mechanism removed, grey tape was
placed over the missing locking mechanism, and a plastic tie wrap
was being used for a handle. Operations personnel acknowledged
that this door had been in this configuration for at least one
day, and possibly longer, and that a work order had not been
issued to repair the door. Also, the door had not been declared
inoperable and the compensatory actions of UFSAR Section 16,
Selected Licensee Commitments (SLC). Item 16.9.5. Fire Barriers,
had not been implemented.
Paragraph 3.E of the Oconee Operating License states that the
licensee shall implement and maintain in effect all provisions of
the approved fire protection program as described in the UFSAR and
as approved in the SERs (i.e., NRC's Fire Protection Safety
Evaluation Reports).
For inoperable fire barriers, UFSAR SLC 16.9.5 Action Item a.ii
required verification that the area fire detection system was
operable and the establishment of an hourly fire watch patrol for
the area. Door 325 was located in a high traffic area; therefore,
there were many opportunities during the work day for any of the
many site employees who passed through this door to recognize that
Enclosure 2
34
the door was inoperable and to submit a work order to perform the
required repairs.
The.failure to promptly identify this inoperable fire barrier
penetration and to implement the appropriate compensatory measures
of UFSAR SLC 16.9.5 is a violation. However, this non-repetitive,
licensee identified and corrected violation is being treated as a
Non-Cited Violation (NCV). consistent with Section VII.B.1,of the
NRC Enforcement:Policy and is identified as NCV 50-269,270.287/97
15-04:
Inoperable Fire Door With No Compensatory Measures.
PIP 0-097-2806: During a review of Procedure MP/0/A/1705/032.
Fire Hose Stations., which was performed in September 1997, the
licensee's reviewer noted that the hose station valves had not
been stroke tested as required by the procedure.
The licensee reviewed the completed procedures for MP/0/A/1705/032
from 1992. through 1996 and noted that none of these procedures had
stroke tested or cycle tested the valves associated with the fire
hose system. All of the hose stations listed by UFSAR SLC 16.9.4
and SLC Table 16.9.4 were flushed and stroke tested on September
12, 1997. This demonstrated that adequate flow was available and
the valves and hose stations were operable. All additional fire
hose stations installed in facility were satisfactorily flushed
and valves were stroke tested on October 24, 1997. Enhancements
were made to the procedure to prevent recurrence. The licensee
attributed the cause of this event as a human performance error.
Personnel assigned the task of performing surveillance tests and
inspections on the fire hose system were provided with additional
training on the expectations and acceptance criteria for the fire
hose system.
Paragraph 3.E of the Oconee Operating License states. "The
licensee shall implement and maintain in effect all provisions of
the approved fire protection program as described in the UFSAR and
as approved in the SERs" (i.e., NRC's Fire Protection Safety
Evaluation Reports).
UFSAR SLC Section 16.9.4, Surveillance Item a.iii, states, "At
least tri-annually, the fire hose station valves shall be partial
stroke tested."
The failure to stroke test the valves for the fire hose station
- -
system in accordance with UFSAR SLC 16.9.4 is a violation.
However, this non-repetitive, licensee identified and corrected
violation is being treated as a Non-Cited Violation, consistent
with Section VII.B.1 of the NRC Enforcement Policy and is
Enclosure 2
35
identified as NCV-50-269,270.287/97-15-05:
Failure to Stroke Test
the Fire Hose Station Valves.
PIP r-097-3309. This issue was related to covering the smoke
detector devices in the Unit 1 RB with a plastic material to
prevent damage to the detectors during the wash down of the RB
while the unit was in a refueling outage. Most of the detectors
were only partially covered with the plastic material.
These
smoke detectors would have been able to perform their intended
function. However, on September 18. 1997, two adjacent detectors
located on the west side of the second floor of the Unit 1 RB were
completely enclosed with the plastic material and would not have
performed their intended function. On October 2. 1997, during the
performance of fire detection surveillance testing, the testing
personnel found these obstructed detectors were not capable of
performing their intended function and the RB fire detection
system was declared inoperable. The plastic material was removed
from these detectors and the system was restored to an operable
condition. The licensee determined the cause of this event to be
poor program design and work process implementation. The
requirement for maintaining the operability of the Reactor
Building fire detection systems and the required implementation of
compensatory actions for inoperable fire detection systems were
discussed with the appropriate personnel.
The inoperable smoke detectors were located in an area which
contained electrical cables to components needed to assure
reliable decay heat removal and were required to be operable.
Paragraph 3.E of the Oconee Operating License states. "The
licensee shall implement and maintain in effect all provisions of
the approved fire protection program as described in the UFSAR and
as approved in the SERs" (i.e.. NRC's Fire Protection Safety
Evaluation Reports).
UFSAR SLC Section 16.9.6, Fire Detection Instrumentation, Action
Item a states. "When more than 50% of the provided detectors for
each equipment/location, or any 2 adjacent detectors for each
equipment/location as shown in Table 16.9-6 are not OPERABLE.
appropriate action shall be taken consisting of:
within 1-hour, a
fire watch patrol shall be established to inspect the accessible
equipment/location at least once per hour or as permitted by Site
Directives." Table 16.9-6 lists the detectors provided for the RB
.
as required to be operable.
u 2
Enclosure 2
0
36
The failure to implement the, compensatory action requirements for the
inoperable fire detection system in the Unit 1 RB in accordance with
UFSAR .SLC 16.9.6 is a violation. However, this non-repetitive, licensee
identified and corrected violation is being treated as a Non-Cited
Violation, consistent with Section VII.B.1 of the NRC Enforcement Policy
and is identified as NCV 50-269/97-15-06: Failure to Implement the
Compensatory Action Requirements for the Inoperable Fire Detection
System in the Unit 1 Reactor Building.
c. Conclusions
The licensee's fire protection staff demonstrated an aggressive attitude
in the identification and correction of fire protection deficiencies.
However, three Non-Cited Violations were identified for the licensee's
failure to meet the fire protection operability requirements for three
required fire protection features.
F2
Status of Fire Protection Facilities and Equipment
F2.1 Operability of Fire Protection Facilities and Equipment
a. Inspection Scope (64704)
The inspectors reviewed the impairment log for fire protection
components and features to assess the licensee's performance for
returning degraded fire protection components to service. In addition,
walkdown inspections were made to assess the material condition of the
plant's fire protection systems, equipment, features and fire brigade
equipment.
b. Observations and Findings
Operability of Fire Protection Equipment and Components
As of November 6, 1997, there were only five fire protection components
listed on the impairment log as degraded. The following items were
identified as inoperable: one smoke detector located in the Unit 1 RB,
two smoke detectors in the Unit 2 RB. one smoke detector in the Unit 3
RB and the fire hose stations in the Unit 1 RB.
The fire detection systems for the RB were considered operable by UFSAR
SLC Section 16.9.6 since more than 50 percent of the detectors were
operable and no two adjacent smoke detectors were inoperable. The
inoperable smoke detectors were scheduled to be replaced during the next
available outage.
Enclosure 2
37
For the inoperable Unit 1 RB hose stations, the licensee was maintaining
a minimum of four fire extinguishers adjacent to the personnel hatch
entrance to the RB from the Auxiliary Building. This met the
requirements of UFSAR .SLC Section 16.9.4 Action Item b.
-The.,hose
stations for the Unit 1 RB were inoperable due to modifications i9
process on the low pressure service during the current refueling outage.
The inspectors reviewed previous impairments listed in the fire
protection impairment log and noted that a .high priority had.been placed
on restoring inoperable fire protection features to service. Most of
the inoperable features had been restored to service within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The inspectors toured the plant and noted that the material condition of
the: fire protection systems'was good and that the systemswere well
maintained.
Fire Brigade Equipment
The turnout gear for the fire brigade members was stored in lockers
adjacent to the two control rooms.
Each fire brigade member was
assigned his own personal turnout gear, consisting of a coat, pants,
boots, gloves, etc. A sufficient number of turnout helmets were
provided to equip the fire brigade members expected to respond in the
event of a fire or other emergency. This equipment was properly stored
and was well maintained.
Additional fire fighting equipment was stored on a motorized fire and
rescue vehicle and an equipment trailer stored outside the protected
area adjacent to the main administration buildings. An equipment
storage trailer and another trailer equipped with foam fire fighting
equipment were stored inside the protected area, north of the Radwaste
Building. Fire fighting equipment was also stored on carts located on
the generator level of the Turbine Building adjacent to Unit 1 and 2
control rooms and Unit 3 control room. Fire hose, nozzles, and
miscellaneous fire fighting equipment was stored on the vehicle,
trailers and equipment carts. This equipment was properly stored and
was well maintained.
c. Conclusions
The low number of inoperable or degraded fire protection components, in
conjunction with the good material condition of the fire protection
components and fire brigade equipment, indicated that appropriate
emphasis had been placed on the maintenance and operability of the fire
protection equipment and components.
Enclosure 2
38
F2.2 Surveillance of Fire Protection Features and Equipment
a. Inspection Scope (64704)
The inspectors reviewed the following completed surveillance and rest
procedures:
PT/0/A/0250/24. Fire Protection System Three Year Flow Test,
Revisions 12 to 15: performed October 14, 1996,and April 3 and 18.
1997..
PT/0/A/0250/25, High Pressure Service Water and Fire Protection
Flow Test, Revision 18; performed May 30. 1997.
PT/0/A/0250/35, Radwaste Contaminated Oil Tank Skid Areas
Sprinkler System Test, Revision 5: performed August 26, 1997.
PT/1/A/2200/006, Keowee Hydro Unit 1 C02 Fire Protection System
Three Year Flow Test. Revision 8: performed January 15, 1997.
PT/1/A/2200/006, Keowee Hydro Unit 2 C02 Fire Protection System
Three Year Flow Test, Revision 8: performed June 13, 1996 and July
30, 1996.
PT/0/A/2200/014, Keowee C02 System Test, Revision 11: performed
May 23, 1997.
TT/0/A/06201/031, Keowee Fire Pump Performance Verification Test
for CIGNA and Flow Meter Verification, Revision 0: performed June
4. 1997.
b. Observations and Findings
The completed fire protection surveillance tests reviewed by the
inspectors had been appropriately completed and met the acceptance
criteria. The test procedures were adequate to perform the fire
protection surveillance requirements specified by UFSAR Chapter 16.9,
SLC.
c. Conclusions
Adequate surveillance and test procedures were provided for the fire
protection systems and features, and implementation of the procedures
was effective.
Enclosure 2
39
F2.3 Fire Barrier Penetration Seals
a. Inspection Scope (64704)
The inspectors reviewed the installation of the following fire barrier
penetration seals to determine if the installed penetration seals met
the design documents and were bounded by configurations which
satisfactorily passed a fire-test which met the requirements of N C
Generic Letter 86-10 and NRC Information Notices, 88-04, 88-56 and. 94
28:
PENETRATION NO.
LOCATION
TYPE
SIZE (Inches)
1-M-S-2-A1
Cable Room
Silicone Foam
40x36
1 MS-8-Al
Cable Room
Silicone Foam
22x68
1-M-S-10-A1
Cable Room
Silicone Foam
1
1-M-F-17-A1
Cable Room
.. Silicone Foam
18x18
1-N-F-2-A1
Equipment Room
Silicone Foam
26x28
1-N-F-19-A1
Cable Shaft
Silicone Foam
60x96
1-P-E-2-A1
Penetration Room Silicone Foam
48x48
2-M-F-33-A1
Cable Room
Monocoat
14
2-M-N-3-A1
Cable Room
Silicone Foam
36x48
2-M-W-2-A1
Cable Room
1
3-P-E-4-A1
Penetration Room -Silicone Foam
41x42
b. Observations and Findings
The inspectors inspected each of the above penetrations and reviewed the
licensee's design, construction and surveillance inspection records for
these penetration seals. The silicone type penetration seals were
covered by 1-inch thick ceraform damming boards: therefore, it was
difficult to verify the specific design specifications that had been
used during the installation of these penetration seals.
The design and
construction documents permitted several installation seal options to
meet the design requirements. The specific requirements were dependent
on the barrier construction, thickness of the barrier, and whether the
penetratioi was through a wall or floor fire barrier.
The licensee had begun a project to revalidate the installation of these
penetration seals to determine if each penetration was bounded by a
Enclosure 2
40
specific design specification that was substantiated by qualified test
documents. During this inspection the licensee initiated PIP 0 097
3922 to expedite the completion of this project. The fire barrier
penetration seals for each unit were scheduled to be revaluated
following completion of their next scheduled refueling outage (i.g.,
early 1998 for Unit 1. Summer 1998 for Unit 2. and Winter 1999 for
Unit 3).
The licensee considered the fire barrier penetration seals to-be
operable based on the previous inspections performed following each
refueling outage using Procedure MP/1,2,3/A/1750/018. Fire Protection
Penetration Fire Barrier Inspection, (current Revisions 27, 20, 21 for
Units 1. 2. and 3, respectively). These procedures required an
inspection of each fire-barrier penetration following a unit's refueling
outage. In addition, in 1984 the licensee identified a number of
discrepancies associated with the facility's fire barrier penetration
seals, such as seals improperly installed, cracked, or missing (i.e..
actually not installed). Major modification work was required to
restore the penetration seals to operable status. Following these
modification activities, documentation was apparently not provided to
indicate the-design specification used for each penetration seal
installation.
This issue will be evaluated during a subsequent NRC inspection, upon
completion of the licensee's revalidation of the installation of the
fire barrier penetration seals. This is identified as Inspector
Followup Item (IFI) 50-269.270,287/97-15-07: Review of Licensee's
Revalidation of Fire Barrier Penetration Seals.
c. Conclusion
The inspector concluded that the fire barrier penetration seals were
functional.
However, the licensee had implemented a project to provide
sufficient documentation to indicate the seal installations met the
design specifications and were bounded by tested configurations.
F3
Fire Protection Procedures and Documentation
F3.1 Fire Fighting Fire Pre-Plans
a. Inspection Scope (64704)
The inspectors reviewed the following procedures for compliance with the
NRC requirements and guidelines:
Nuclear Station Directive (NSD) 112, Fire Brigade Organization.
Training and Responsibilities. Revision 0
Enclosure 2
41
NSD 313, Control of Combustible and Flammable Materials,
Revision 0
NSD 314, Hot Work Authorization, Revision 0
Oconee Site Directive 3.2.9, Reporting of Fire Protection.
Impairments, Revision 1/30/96
Pre-Fire Plans, Oconee Pre-Fire Plans and Procedures
Plant tours were also performed to assess procedure compliance.
b. Observations and Findings
The above procedures were the principal procedures issued to implement
the facility's fire protection program. These procedures contained the
requirements for program administration, controls over combustibles and
ignition sources, fire brigade organization and training, and
operability requirements for the fire protection systems and features.
The procedures were well written and met the licensee's commitments to
the NRC. except for the Pre-Fire Plans. Pre-Fire Plans had not been
provided for all plant areas containing safety-related components.
The inspectors performed plant tours and noted that even though the
plant was in a refueling outage, implementation of the site's fire
prevention program for the control of ignition sources, transient
combustibles were good with overall general housekeeping considered
satisfactory. Appropriate fire prevention controls were being applied
to the accumulation of transient combustible materials, the number of
maintenance activities and welding operations in process due to the
refueling outage.
During this inspection, the inspector noted that there were a number of
areas within the plant which contained or presented a hazard to safety
related components in which the licensee had not developed fire fighting
procedures. For example, fire fighting procedures had not been provided
for the Unit 3 low pressure injection hatch area on the 771-foot
elevation of the Auxiliary Building. This area contained electrical
components for the low pressure injection and component cooling systems
and presented an exposure fire hazard to the Unit 3 low pressure and
high pressure injection pumps.
Paragraph 3.E of the Oconee Operating License states that the licensee
-
-shall
implement and maintain in effect all provisions of the approved
fire protection program as described in the UFSAR and as approved in the
SERs (i.e.. NRC's Fire Protection Safety Evaluation Reports).
Enclosure 2
42
The licensee's January 6, 1978, fire protection submittal to the NRC
stated that -"in lieu of fire fighting procedures," general arrangement
drawings of-all levels within the station and yard areas have been
marked showing the location-of fire protection equipment and the
location of combustibles. These drawings have been located in each
control.room and in the Safety Supervisor's office. We intend to expand
the information on these drawings to indicate additional combustibles,
hazards and ventilation systems supplying each location."
NRC's August
11, 1978.Fire Protection Safety Evaluation Report, Section C.6.6 found
the licensee's proposed actions to provide "the necessary strategies for
fighting fires in~safety-related areas and areas presenting a hazard to
safety related equipment" to be acceptable.
However, the licensee had not provided the necessary strategies for
fighting fires in all safety-related areas and areas presenting a hazard
to safety-related equipment. This is identified as VIO 50
269,270,287/97-15-08:
Fire Fighting Strategies Not Provided for All
Safety-Related Areas.
The licensee had previously identified this problem and had developed
fire fighting procedures for all safety-related and important plant
areas. These procedures had not been issued due to several needed
enhancements. PIP 0-097-3921 was issued during this inspection to
address this issue and to expedite completing the revisions to these
procedures. Revisions to these procedures were scheduled to be
completed by June 1998.
c. Conclusions
In general, the fire protection program implementing procedures were
well written and met the licensee's commitments to the NRC requirements.
Procedure implementation for the control of ignition sources and
transient combustibles was good. Overall, general housekeeping was
satisfactory. However, a violation was identified involving the failure
to provide fire fighting strategies for all plant areas which contained
safety-related equipment or presented an exposure hazard to safety
related components.
F5
Fire Protection Staff Training and Qualification
F5.1 Fire Brigade
a. Inspection Scope (64704)
The inspectors reviewed the fire brigade organization and training
program for compliance with the NRC guidelines and requirements.
Enclosure 2
43
b. Observations and Findings
The organization and training requirements for the plant fire brigade
Were established by NSD 112. Fire Brigade Organization, Training and
Responsibilities, Revision 0. The fire brigade for each shift was,
composed of a fire brigade leader and at least four brigade members from
operations and approximately five members from maintenance. The fire
brigade leader was a senio' reactor operator (SRO)
and was normally one
of the unit shift supervisors. The other members from operations were
non-licensed plant operators. One of the fire brigade members was
normally assigned the duties of fire brigade safety officer to provide
technical and administrative assistance to the fire brigade leader and
to help assure the safe performance of each fire brigade member by
checking each member for appropriate dress out prior to entering the
fire area, maintaining records of each fire brigade exposure to fire or
radiation hazards, use of self-contained breathing apparatus, and
reviewing the pre-fire plans during the emergency for assurances that
appropriate measures are being followed for compliance with applicable
safety and fire hazards in the area. Assignment of a fire brigade
safety officer was identified as a program strength.
Each fire brigade member was required to receive initial, quarterly and
annual fire fighting related training and to satisfactorily complete an
annual medical evaluation and certification for participation in fire
brigade fire fighting activities. In addition, each member was required
to participate in at least two drills per year. The initial and annual
fire fighting training was provided by the fire science department of a
local college.
As of the date of this inspection, there was a total of 26 operations
trained fire brigade leaders and 73 operations personnel and 32
maintenance personnel on the plant's fire brigade. Approximately five
fire brigade leaders, eight operations fire brigade members and five
maintenance fire brigade members were assigned to each of the five
operations crews. This was a sufficient number to meet the staffing
requirements for the plant operations and the facility's fire brigade
complement of one team leader and nine members per shift.
The inspectors reviewed the training and medical records for the fire
brigade members and verified that the training and medical records were
up to date. The facility utilized off-site qualified state certified
fire brigade training instructors and a state fire training facility to
perform the annual fire brigade training and practical fire training
scenarios.
During this inspection, the inspectors witnessed a fire brigade drill on
November 4, 1997, involving a simulated fire in an electrical panel
'
located in Room 159. low pressure hatch area on the 771 foot elevation
Enclosure 2
44
of the auxiliary building.
The response of the fire brigade to the
simulated fire was mixed. Shortcomings were identified in the
performance of the fire brigade members and the safety officer. After
these shortcomings were resolved, the subsequent drill performance was
satisfactory. These shortcomings were identified by the licensee,
discussed in the post-drill critique, and documented in PIP 0-097-3950
for resolution.
Based upon a review of the licensee's May 1995 QA Triennial Fire
Protection Audit, a review of ten previous-fire brigade drill summaries,
and an NRC resident inspector witnessed drill documented in NRC IR 50
269.270,287/97-12 these shortcomings were not typical or a trend.
c.
Conclusions.
The fire brigade organization and training met the requirements of the
site procedures. The use of the fire brigade safety officer position
during fire emergencies was identified as a program strength. Licensee
performance during a fire brigade drill conducted during the period was
mixed.
F7
Performance in Fire Protection Activities
F7.1 Review of Triennial Fire Protection Audit
a. Inspection Scope (64704)
The inspector reviewed Triennial Fire Protection Audit, SA-95
24(ON)(RA), which was conducted May 15 through June 8. 1995.
b. Observations and Findings
Audit SA-95-24(ON)(RA) was a triennial QA audit of the facility's fire
protection program. The licensee informed the inspector that this was
the most recent comprehensive audit of the fire protection program.
Duke's December 18. 1991, letter to the NRC stated that performance
based criteria were to be used for establishing audit frequencies at the
Duke facilities. NRC's letter dated May 7. 1992, documented that this
was satisfactory. Previously, the TS had required annual, biannual and
triennial audits of the fire protection program. However, based on the
licensee's assessment of good fire protection performance, the most
recent audit performed of the Oconee fire protection program was the
1995 triennial audit. As documented in NRC Inspection Report 50
413,414/97-07 for Catawba, the NRC is re-evaluating this issue.
The inspectors reviewed the audit findings from the 1995 QA report and
the corrective actions taken on the identified discrepancies. The
report indicated that a comprehensive audit had been performed and seven
Enclosure 2
45
findings were identified. The inspector reviewed the status of each of
these items and verified that the.corrective action on each finding had
been completed.
c. Conclusions
The,1995 audit and assessment of the facility's fire protection program
were comprehensive and appropriate corrective action was promptly, taken
to resolve identified issues.
V. Management Meeting s
Xl
Exit Meeting Summary
The inspectors presented the inspection r-sulis to members of licensee
management at the conclusion of the inspection on November 18. 1997.
The licensee acknowledged the findings presented. Dissenting comments
were received from the licensee and resolved by the NRC. Proprietary
information is not contained in this report.
Partial List of Persons Contacted
Licensee
D.
Brandes, Consultant Engineer, Nuclear Engineering
E. Burchfield, Regulatory Compliance Manager
T. Coutu, Scheduling Manager
D. Coyle. Mechanical Systems Engineering Manager
T. Curtis, Operations Superintendent
B. Dobson, Mechanical/Civil Engineering Manager
W. Foster, Safety Assurance Manager
D. Hubbard, Maintenance Superintendent
C. Little. Electrical Systems/Equipment Engineering Manager
W. McCollum, Vice President, Oconee Site
M. Nazar. Manager of Engineering
B. Peele, Station Manager
J. Smith, Regulatory Compliance
NRC
D. LaBarge, Project Manager
Inspection Procedures Used
Engineering
Onsite Engineering
Installation and Testing of Modifications
Enclosure 2
46
W
Effectiveness of Licensee Controls In Identifying and Preventing
Problems.
TI-P50002
Surveillance Observations
Maintenance Program Implementation
IR62707
Maintenance Observations
4(P64704
Plant Operations
Cold Weather Preparations
Plant Support Activities
fP8f750e
Raoctive
aste 'T en
n
l
nt and Environmental
Monitr
Gi erat
MP84760
Solid Radioactive Waste Management and Transportation of
Radioactive Material
Followup - Engineering
laSFol
u - Plant Support
Enclosure 2
47
Items Opened, Closed, and Discussed
50-269,287/97-15-01
Failure to Complete Required Technical
Specification Surveillances on LPI Flow
Instruments (Section M1.5)
50-269,270.287/97-15-02
Valve Parts Identification Problem
(Section M2.1)
50-269,270V287/97-15-03,
URI: Determine the:Applicability of Monitoring
Requirements of Criterion 64 of 10 CFR 50
Appendix A and Reporting Requirements of
40 CFR 190 and 10 CFR 50.36a Regarding
Potential .of Unmonitored Release Pathways
(Section R1.1)
50-269,270,287/97-15-04
Inoperable Fire Door With No Compensatory
Measures (Section F1.1)
50-269,270,287/97-15-05
Failure to Stroke Test the Fire Hose
Station Valves (Section F1.1)
50-269/97-15-06
Failure to Implement the Compensatory
Action Requirements for the Inoperable
Fire Detection System in the Unit 1
Reactor Building (Section F1.1)
50-269,270,287/97-15-07
IFI
Review of Licensee's Revalidation of Fire
Barrier Penetration Seals (Section F2.3)
50-269,270,287/97-15-08
Fire Fighting Strategies Not Provided for
All Safety-Related Areas (Section F3.1)
50-270,287/97-15-09
Failure to Update the UFSAR Regarding Fuel
Enrichment (Section E8.3)
Closed
50-269,270,287/96-09-03
IFI
Expected End-of-Cycle Heat Loads (Section
E8.1)
-
50-269/97-03. Revs. 0 and 1 LER
Post LOCA Boron Dilution Design Basis Not
Met Due To Deficient Design Analysis
(Section E8.2)
Enclosure 2
0
48
50-269.270,287/97-01-07
Failure to Meet Requirements of 10 CFR
70.24 (Section R8.1)
50-269.270,287/97-12-02
Fuel Load UFSAR Statements (Section E8.3)
50-269.270,287/97-01-06
Boron Dilution Flow Path Inoperability
(Section E8.2)
Discussed
50-269.270,287/96-13-03
IFI
Service Water Modifications (Section E3.1)
List of Acronymns
Asea Brown Boveri
As Low As Reasonably Achievable
ANSI
American National Standard
American Society of Mechanical Engineers
Branch Technical Position
BWOG
Babcock and Wilcox Owners Group
BWST
Borated Water Storage Tank
CENO
Combustion Engineering Nuclear Operations
CFR
Code of Federal Regulations
Condenser Circulating Water
Direct Current
DEI
Dominion Engineering, Incorporated
Department of Transportation
EPSL
Emergency Power Safeguards Logic
EWST
Elevated Water Storage Tank
Failure Investigation Process
FIT
Framatome Technologies. Inc.
GPM
Gallons Per Minute
High Pressure Service Water
ICCM
Inadequate Core Cooling Monitor
IFI
Inspector Follow-up Item
IGA
Intergranular Attack
IR
Inspection Report
KV
kilovolt
LER
Licensee Event Report
Loss of Coolant Accident
Low Pressure Injection
-Low Pressure Service Water
MFB
Main Feeder Busses
MCE
Mechanical Civil Equipment Group
BMP
Maintenance Procedure
CdNorth Carolina
Enclosure 2
49
Non-Cited Violation
NRC
Nuclear Regulatory Commission
NSD
Nuclear System Directive
OAC
Operator Aid Computer
Once-Through-Steam-Generator
Public Document Room
Problem Investigation Process
Performance Test
Pressurized Water Reactor
Quality Assurance
Quality Control
RB.
Reactor Building
Reactor Coolant Pump
REV
Revision
Radiation Protection
Systematic Assessment of Licensee Performance
Safety Evaluation Report
Spent Fuel Pool
Selected Licensee Commitment
Senior Reactor Operator
SSF
Safe Shutdown Facility
TDEFWP
Turbine Driven Emergency Feedwater Pump
TM
TS
Technical Specification
TT
Temporary Test
Tennessee Valley Authority
Updated Final Safety Analysis Report
Unresolved Item
UTS
Upper Tube Sheet
V
Volt
Violation
Work Order
Enclosure 2