ML15118A294
| ML15118A294 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 06/01/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A291 | List: |
| References | |
| 50-269-98-05, 50-269-98-5, 50-270-98-05, 50-270-98-5, 50-287-98-05, 50-287-98-5, NUDOCS 9806160291 | |
| Download: ML15118A294 (32) | |
See also: IR 05000269/1998005
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269. 50-270, 50-287, 72-04
License Nos:
DPR-38. DPR-47, DPR-55, SNM-2503
Report No:
50-269/98-05, 50-270/98-05, 50-287/98-05
Licensee:
Duke Energy Corporation
Facility:
Oconee Nuclear Station, Units 1, 2, and 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
March 22 - May 2, 1998
Inspectors:
M. Scott, Senior Resident Inspector
S. Freeman. Resident Inspector
E. Christnot, Resident Inspector
D. Billings. Resident Inspector
M. Sykes, Resident Inspector, McGuire (Sections 08.3. E8.1)
T. Cooper. Resident Inspector. Crystal River (Sections 07.1.
F8.2)
E. Lea. Project Engineer (Sections 08.1, 08.2. E8.2)
D. Forbes, Regional Inspector (Sections R1.1, R1.2, R2.1.
R5.1, R8.1, R8.2)
H. Whitener, Regional Inspector (Portions of Section M1.1)
J. Blake. Regional Inspector (Sections M1.2. M1.3)
P. Kellogg, Regional Inspector (Section E8.3)
Approved by:
C. Ogle, Chief. Projects Branch 1
Division of Reactor Projects
Enclosure 2
9806160291 980601
PDR ADOCK 05000269
G
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1, 2, and 3
NRC Inspection Report 50.-269/98-05,
50-270/98-05, and 50-287/98-05
This integrated inspection included aspects of licensee operations,
maintenance, engineering, and plant support. The report covers a six-week
period of resident inspection, as well as the results of announced inspections
by five region based inspectors. [Applicable template codes and the
assessment for items inspected are provided below.]
Operations
The licensee properly completed the operations and maintenance spent
fuel pool procedural enhancements listed in the Oconee probability and
public risk analysis of December 4, 1996. (Section 03.1, [1C, 2B
Adequate])
Refueling activities on Unit 2 were completed in a professional and
conservative manner. Locating the defueling/refueling administrative
and fuel tracking activities in a separate area adjacent to the control
room was seen as a positive. (Section 04.1, [1A - Good])
The inspectors identified a corrective action violation regarding lack
of quality assurance review of engineering instructions for minor and
temporary modifications. The licensee had identified this low level
problem approximately two years earlier but instances of lack of review
ave continued. (Section 07.1, [SC - Poor])
The corrective actions implemented for the failure to have a procedure
for reactor building closeout were adequate. (Section 08.1. [SC
Adequate])
The corrective actions implemented for the failure to make a timely
notification in accordance with Title 10, Code of Federal Regulations,
Part 50.72 following a reactor trip on March 16. 1996. were adequate.
(Section 08.2, [5C - Adequate])
The addition of operations procedural guidance to verify that fuel
assemblies were properly positioned, the fuel bridge mast was properly
secured, and spent fuel pool water level was maintained at least eight
feet above the fuel storage racks was considered adequate to resolve the
issue of previous occurrences of inadequate procedure control over spent
fuel movement. (Section 08.3. [5C - Adequate])
Retraction of the four-hour notification for the Keowee Unit 1
unanticipated start of April 9, 1998, was appropriate. (Section E2.1,
[lB - Adequate])
The licensee used conservative judgement in declaring Keowee Unit 2
inoperable in response to the April 20, 1998, failure to synchronize due
to the speed adjustment motor. During this normal start for commercial
power generation, an unknown condition was properly addressed with the
operability determination. (Section E2.1, [1A - Adequate])
(II0
2
Maintenance
.Pump,
engine, and valve on-line maintenance was generally completed in a
thorough and professional manner. Personnel were knowledgeable of the
assigned tasks and demonstrated attention to detail.
Procedures were
detailed and actively used on the job. Data was recorded as the steps
were performed and compared to the acceptance criteria. Pre-job
briefings were thorough and communication between test personnel was
good. Work performance during these activities demonstrated that
maintenance processes were positively in place. (Section M1.1, [2B. 3A,
3B - Good])
The licensee properly completed a commitment to adjust the automatic
voltage regulator for the main generators. These corrective actions
were considered adequate resolution of the problem that previously
resulted in a Unit 2 reactor trip. (Section M1.1, [5C - Adequate])
The licensee's augmented inservice inspection programs for the high
pressure injection connections to the reactor coolant system cold legs
ave been improved since the.piping failure in the Spring of 1997.
(Section M1.2, [2B - Adequate])
Inspection and testing of the Unit 2 once through steam generators were
being conducted in a thorough and conservative manner. Unexpected
findings were thoroughly evaluated for significance and potential impact
on the operating units. (Section M1.3. [2B - Good])
The inspectors concluded that the Unit 2 emergency power switching logic
test was successfully performed. This was indicative of adequate y
maintained equipment. (Section M1.4, [2A, 2B - Adequate])
Engineering
A more thorough pre-test review of the quality and completeness of the
procedure for the Unit 2 emergency power switching logic test could have'
precluded some of the minor discrepancies observed during the test and
was considered a weakness. (Section M1.4, [3C - Poor])
The technical resolution of the failure of the Keowee Unit 2 speed
adjustment motor on April 20, 1998, was adequate. (Section E2.1. [5C
Adequate])
The inspectors concluded that the failure of the speed adjustment motor
on April 20, 1998, did not affect the safety function of Keowee Unit 2
but did reflect poorly on the material condition of the speed adjustment
motor. (Section E2.1, [2A, Poor])
Good engineering support was provided and good troubleshooting methods
were used on the speed adjustment motor in response to the April 20.
1998, failure of Keowee Hydro Unit 2 to synchronize. (Section E2.1,
[4B - Good])
The performance of the licensee's failure investigation process team
concerning the Keowee Unit 1 overcurrent and undervoltage disturbance of
April 26, 1998, was excellent. (Section E2.1, [5B. 5C - Excellent])
3
@
0
Changes to low pressure service water system design basis to allow for
use of industry and Nuclear Regulatory Commission guidance concerning
vulnerable target area and probability of impact of a turbine missiles
was considered appropriate. The licensee's effort to understand their
design was adequate. (Section E8.1, [4A - Adequate])
The accountable engineer (individual performing modification) failed to
list a snubber in the Technical Specification surveillance procedure
which caused a required inspection to be missed and resulted in a non
cited violation. (Section E8.2, [3A - Poor])
The licensee's identification of a missed surveillance following a
snubber installation was adequate. (Section E8.2, [5A - Adequate])
Corrective actions identified by the licensee in response to a missed
snubber surveillance test were adequate to provide reasonable assurance
of not missing TS required inspection when new snubbers are installed.
(Section E8.2, [5C - Adequate])
The inspector noted that the siphon seal water, emergency condenser
circulating water, and essential siphon vacuum system test procedures
were well written and required no changes. Only a few enhancements were
identified during the conduct of the procedures. (Section E8.3. [2B
Excellent])
The inspector attended the pre-job briefing for several of the seal
water, emergency condenser circulating water, and essential siphon
vacuum system tests and noted that the briefings were thorough.
(Section E8.3. [3A, 3B - Good])
Good control of the testing evolutions was demonstrated by the test
coordinators. (Section E8.3, [lA - Good])
Plant Support
The inspectors determined the licensee was effectively maintaining
controls for personnel monitoring, control of-radioactive material,
radiological postings, radiation area controls, and high radiation area
controls as required by 10 CFR Part 20. Efforts to reduce personnel
contaminations was positive. (Section R1.1, [IC - Good])
Based on licensee planning efforts to reduce source term and the
licensee's efforts to achieve established exposure goals which were
challenging, the inspectors determined the licensee's programs for
controlling exposures as low as reasonably achievable were effective.
All personnel exposures to date in 1998 were below regulatory limits.
(Section R1.2, [1C - Adequate])
Review of breathing air testing records verified that the licensee was
calibrating breathing air compressor equipment and sampling in-use
breathing air systems for certification in accordance with procedural
requirements. For the tests reviewed, breathing air met Grade D or
better quality requirements. Survey instrumentation had been adequately
maintained. (Section R2.1, [2A - Adequate])
4
The respiratory protection program was being implemented as required by
10 CFR Part 20 Subpart H. (Section R2.1. [1C - Adequate])
The inspectors concluded that the check sources identified by the
inspectors were exempt sources and were controlled appropriately.
(Section R4.1, [IC - Adequate])
Personal frisking practices in the Interim Radwaste Facility were
acceptable. (Section R4.1, [3B - Adequate])
Chemistry personnel were knowledgeable and competent during collection
of a reactor coolant system sample. (Section R4.1, [3A, 3B - Adequate])
Based on the training activities reviewed and interviews, the inspectors
determined the radiation protection technicians had been provided an
adequate level of training to perform routine survey activities
involving radiation and control of radioactive material.
(Section R5.1,
[3B - Adequate])
The proposed change to the Updated Final Safety Analysis Reports for
additional requirements for performing radioactive work in the reactor
coolant pump and ice blast buildings was considered appropriate.
(Section R8.1, [1C - Adequate])
The inspectors identified a configuration control and design violation
for improper bend radius in two locations on the Unit 2 vent radiation
monitors.
(Section R8.2. [2A - Poor])
The failure to include instructions for an electrical damage check of
breakers in the procedure for operational guidelines following a fire
resulted in a non-cited violation. The failure could prevent alignment
of the low pressure injection system following a fire. (Section F8.1.
[1C - Poor])
The licensee's identification and resolution of. deficiencies in
operational guidelines following a fire were adequate. (Section F8.1,
[5A.5C - Adequate])
Due to improper assumptions regarding pressure downstream of the reactor
coolant pump seals, reactor coolant system leakage during a scenario
identified for Title 10, Code of Federal Regulations, Part 50.. Appendix
R, could have exceeded design limits for the reactor coolant makeup
system and resulted in a non-cited violation. (Section F8.2, [1C, 4A
Poor])
The licensee's identification and resolution of a procedure problem
involving excessive reactor coolant pump seal leakage. following a fire
was adequate. (Section F8.2, [5A, SC - Adequate])
Report Details
Summary of Plant Status
Unit 1 began and ended the period at 100 percent power.
Unit 2 began and ended the period in a scheduled refueling outage. Major
outage work completed included the replacement of the 2A1 and 2B1 reactor
coolant pumps and low pressure service water modifications.
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. 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 (IP)
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.
02
Operational Status of Facilities and Equipment
02.1 Operations Clearances (71707)
The inspectors reviewed portions of the following clearances and Block
Tag Outs (BTO) during the inspection period:
2-98-0646
BTO 5
Condenser Circulating Water
(CCW)
2-98-1158
TN/2/A/2932/00
CCW/Siphon Seal Water (SSW)
2-98-0868
BTO 17
Building Spray
The inspectors observed that the clearances were properly prepared and
authorized and that the tagged components were in the required positions
with the appropriate tags in place.
02.2 Engineered Safety Features System Walkdown (71707)
The inspectors performed a walkdown of accessible portions of the
following systems:
Unit 1 Emergency Feedwater System
Unit 2 Emergency Feedwater System
2
.0
Unit 2 Essential Siphon Vacuum System
Unit 2 Siphon Seal Water System
Unit 3 East.Penetration Room Containment Isolation Valves
No discrepancies or concerns were identified.
03
Operations Procedures and Documentation
03.1 Spent Fuel Pool Procedural Controls
a. Inspection Scope (71707)
The inspectors independently reviewed the implementation of spent fuel
pool procedural enhancements as part of the Oconee probability and
public risk analysis of December 4, 1996.
b. Observations and Findings
The licensee committed to the following enhancements:
Change Procedures OP/1.2,3/A/1102/15. Filling and Draining Fuel
Transfer Canal, to provide explicit steps to close the fuel
transfer canal deep end drains and fill the deep end with one foot
of water before removing fuel transfer tube flanges:
Change Procedure MP/0/A/1405/001, Fuel Transfer Tube Cover Plate
Installation and Removal, to require verification that water is
standing in the fuel transfer canal deep end, the deep end drains
are closed, and fuel transfer tube isolation valves SF-1 and SF-2
are closed using a remote camera before removing fuel transfer
tube flanges: and
Add steps to procedures for spent fuel pool draindown sequences
involving standby shutdown facility (SSF) piping during normal
operation to direct operators to attempt to arrest the draindown
by closing SF-1 and SF-2.
The licensee implemented these enhancements as corrective actions under
Problem Investigation Process (PIP) Report 0-096-2656. The inspectors
determined that all changes were made as stated.
c. Conclusions
The licensee properly completed the spent fuel pool procedural
enhancements listed in the Oconee probability and public risk analysis
of December 4, 1996.
0III
3
04
Operator Knowledge and Performance
04.1 Unit 2 Refueling Activities
a. Inspection Scope (71707)
The inspectors observed portions of the defueling and refueling
activities for Unit 2.
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. The inspectors observed that
operators in the control room were aware of the movement of each fuel
assembly by number and monitored appropriate nuclear instrumentation.
Management oversight of operations in the control room ensured focus was
maintained on the refueling and defueling activities. Outside
distractions were minimized by locating the refueling/defueling
activities to the shift supervisor's office whereas they had been
previously located in the control room.
The inspectors also reviewed tapes of the debris scan and core
verification scan. No items were identified for followup.
c. Conclusions.
Refueling activities on Unit 2 were completed in a professional and
conservative manner. Locating the defueling/refueling administrative
and fuel tracking activities in a separate area adjacent to the control
room was seen as a positive.
07
Quality Assurance in Operations
07.1 Review of Licensee Corrective Action Reports
a. Inspection Scope (40500)
The inspectors reviewed a number of licensee PIP reports in order to
identify potential issues and the licensee response to these issues.
b. Observations and Findings
PIP Report 4-098-1682, issued on April 1, 1998. identified that
engineering instructions in Minor Modification 11772, did not receive
Quality Assurance (QA) review prior to issuance. The detailed problem
description of the PIP report stated that this was a repetitive problem
that had been identified on several PIP reports over a two year period.
The inspectors reviewed these PIP reports and confirmed that three
temporary modifications and 12 minor modifications were identified where
the modification was installed without prior QA review of the
engineering instructions. The QA review was required for minor
modifications by Site Directive 2.2.1. Minor Modification Program, dated
July 11, 1996, and for temporary modifications by Site Directive 2.1.4,
4
Control of Temporary Modifications, dated March 30. 1995. Site
Directive 2.1.4 was changed February 2, 1998. However the revision
dated March 30, 1995, applied to al
temporary modifications covered by
the PIP reports listed elow.
The inspectors reviewed the problem evaluations sections for the PIP
reports referenced in PIP Report 4-098-1682 as follows:
PIP Report 0-096-0518 regarding temporary modifications, dated
March 14, 1996, stated the QA review requirement was overlooked.
A team meeting was held May 1. 1996, to review the PIP report.
PIP Report 0-096-2298 regarding minor modifications, dated
November 8, 1996, stated that because engineering instructions
were generic it was not the practice to route them for QA review
unless engineering felt it was necessary. No specific corrective
actions were documented for this PIP report.
PIP Report 3-096-2540 regarding minor modifications, dated
December 4, 1996, stated the missed review was an unintentional
oversight. Training was planned to be conducted but no corrective
actions were documented for this PIP report.
PIP Report 1-097-1747 regarding temporary modifications, dated
June 10. .1997, stated the responsible engineer did not follow
procedure. As corrective action the responsible engineer reviewed
the procedure.
PIP Report 2-097-1580 regarding minor modifications, dated May 20,
1997, acknowledged the failure to follow procedure. As corrective
action a team meeting was held on June 1.8. 1997, to remind all
minor modification preparers that QA personnel must be given the
opportunity to review engineering instructions.
PIP Report 3-097-1614 regarding minor modifications, dated May 26.
1997, stated that the accountable engineer understood that QA .
personnel did not need or want to review engineering instructions
if all work was governed by approved station instructions. The
engineer was counseled and discussed the PIP report with QA
personnel.
PIP Report 1-097-4061 regarding minor modifications, dated
November 13, 1997, stated that the apparent cause was human
erformance. but the problem was resolved as addressed in PIP
Reports 0-096-2298 and 3-096-2540.
PIP Report 1-097-4125 regarding minor modifications, dated
November 18, 1997, stated that the QA engineer was contacted at
home but was not aware of the requirement for QA to review
engineering instructions. No specific corrective actions were
documented for this PIP report.
PIP Report 1-97-4132 regarding minor modifications, dated November
19. 1997, stated the engineering instructions were not specific
instructions but a guideline. The PIP report was discussed at a
5
team meeting on January 8, 1998.
PIP Report 1-098-0054 regarding minor modifications, dated January
7, 1998, referred to PIP Report 1-97-4132 for cause, resolution,
and corrective actions.
PIP Report 0-098-0470 regarding minor modifications, dated
February 1, 1998. was not yet evaluated as of the end of the
inspection period.
The inspectors determined minor and temporary modifications continued to
be issued without the opportunity for QA personnel to review engineering
instructions. The low level problem continued even though it was
identified numerous times since 1996, and there have been several team
meetings and counseling sessions to correct the problem.
The
inspectors determined this constituted a failure to correct a condition
adverse to quality and was a violation of 10 CFR 50, Appendix B,
Criterion XVI. Given that the licensee had opportunities to correct
this problem as a result.of several findings over the previous two
years, this issue will not be subject to discretion. This is identified
as violation (VIO) 50-269,270,287/98-05-01: Inadequate Corrective
Actions for Recurring Problems With Engineering Instructions for Minor
c. Conclusions
The inspectors identified a corrective action violation regarding lack
of quality assurance review of engineering instructions for minor and
temporary modifications. The licensee had identified this low level
problem approximately two years earlier but instances of lack of review
have continued.
08
Miscellaneous Operations Issues (92901)
08.1
(Closed) VIO 50-269,270,287/96-20-04: Failure to Have RB Material
Condition Closeout Procedure
This violation identified the failure of the licensee to have a
procedure for RB closeout as required by 10 CFR 50, Appendix B,
Criterion V. The inspectors reviewed the licensee's response to the
violation, in letters submitted to the NRC dated April. 9, 1996, and
October 23, 1997. The inspectors also reviewed PIP Report 0-097-1038,
which the licensee initiated to track the finding identified in the
Notice of Violation (NOV) and the corrective actions identified as a
result of the NOV. The inspectors determined that the corrective
actions were adequate. The inspectors reviewed associated documentation
and verified that the corrective actions identified by the licensee had
been implemented. Based on the completed implementation of the
correction actions, this violation is closed.
08.2 (Closed) VIO 50-269,270.287/96-05-01: Failure to Make Proper 10 CFR
50.72 Notification
This violation documented the failure of the licensee to make a 10 CFR
50.72 notification within the required time period, following a reactor
6
trip on March 16, 1996. The inspectors reviewed the licensee response
to the NOV, and PIP Report 3-096-0536, which the licensee initiated to
track the NOV, and associated documentation. The inspectors reviewed
the corrective actions identified in the PIP. The corrective action
included revisions to selected site procedure and additional training to
selected site personnel. The inspectors verified that the corrective
actions identified in the PIP had been completed. The inspectors
concluded that the licensee's implementation of the corrective action
adequately addressed the concerns associated with the violation. This
violation is closed.
08.3 (Closed) VIO 50-269,270.287/E96-19-01013: Inadequate Procedure Control
Over Movement of Spent Fuel
The inspectors performed followup inspection of licensee corrective
actions to address the failure to provide adequate procedures for fuel
handling activities. The inspectors reviewed revised fuel handling
procedures for activities within the RB, spent fuel building and the
interim spent fuel storage installation. During the review, the
inspectors confirmed that the licensee had incorporated specific
instructions to verify that fuel assemblies were properly positioned in
acceptable storage locations and the fuel bridge mast was properly
secured. The licensee also incorporated procedural guidance to inform
control room operators of fuel handling evolutions in progress and to
provide notifications when these activities were completed or suspended.
In accordance with a commitment made during the February 21, 1996, pre
decisional enforcement conference, the licensee performed a Self
Initiated Technical Audit (SITA) to evaluate and review plant design
basis and fuel handling activities. As a result of the SITA, the
licensee indicated their intention to provide additional guidance to
operators to ensure spent fuel pool water level is maintained at least
eight feet above the top of the irradiated fuel storage racks to have
adequate shielding during SSF events. This was verified to be
implemented in procedures.. The inspectors concluded that the licensee's
implementation of these corrective actions adequately addressed the
concerns associated with the violation. This violation is closed.
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:
TT/2/A/0750/017
Recovery of Jammed Control Rod Handling Tool,
Revision 0
MP/0/A/1500/009
Fuel Handling Operations, Revision 15
7
PT/0/A/0400/004
Standby Shutdown Facility (SSF) Diesel Engine
Service Water Pump Test. Revision 16
CP/1/A/2002/04D
Test Procedure for Operation of Post Accident
Liquid Sample System. Revision 25
PT/0/A/0750/11
Defueling/Refueling Activities Enclosure 13.1
Fuel Movement Verification Form Core Offload
Sequence. Revision 14
OP/2/A/1106/006
Turbine Driven Emergency Feedwater Pump
Overspeed Test, Revision 78
PT/2/A/0610/001J Emergency Power Switching Test, Revision 18
PT/3/A/0204/007
Reactor Building Spray Pump Test. Revision 50
PT/1/A/0251/003
Concentrated Boric Acid Transfer Pump Test,
Revision 35
PT/3/A/0152/016
Purge System Valve Stroke Test, Revision 1
PT/1/A/0400/007
SSF Reactor Coolant (RC) Make Up Pump Test,
Revision 25
PT/0/A/0400/004
SSF Diesel Engine Service Water Pump Test,
Revision 16
2CCW-14 Repair Seat Leak on Valve
Repair V, Inch Hole in TDEFW Pipe
Repack Unit 2 TDEFW Pump
b. Observations and Findings
The inspectors found the work performed under these activities to be
professional and thorough. All work observed-was performed with the
work package present and in 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.
The inspectors documented in NRC Inspection Report (IR)
50
269,270.287/97-10. a trip of the Unit 2 reactor, from 100 percent power,
due to the automatic voltage regulator control network not being
properly adjusted. The IR also documented the adjustment of the Unit 2
automatic regulator. The licensee committed to adjusting the Unit 1 and
Unit 3 automatic regulators. The Unit 3 regulator was adjusted during a
forced outage and performed adequately. The Unit 1 regulator was
adjusted during the most recent refueling outage. The regulator
performed adequately during the post refueling runback and power
escalation testing. These actions completed the commitment.
8
c.
Conclusion
The inspectors concluded that the maintenance activities listed above
were completed thoroughly and professionally.
On-line maintenance and surveillance activities involving the 3B reactor
building spray pump, the concentrated boric acid storage tank transfer
pump, the standby shutdown facility diesel engine service water pump,
the standby shutdown facility reactor coolant make-up pump, and valves
in the purge system were generally completed in a thorough and
professional manner. Personnel were knowledgeable of the assigned tasks
and demonstrated attention to detail.
Procedures were detailed and
actively used on the job. Data was recorded as the steps were performed
and compared to the acceptance criteria. Pre-job briefings were
thorough and communication between test personnel were good. Licensee
performance during these evolutions was good.
The licensee properly completed a commitment to adjust the automatic
voltage regulator for the main generators. These corrective actions
were considered adequate resolution of the problem that previously
resulted in a Unit 2 reactor trip.
M1.2 Augmented Inservice Inspection (ISI)
a. Inspection Scope (73753)
The inspector reviewed data from augmented ISI of the high pressure
injection (HPI) connections to the main loop cold legs.
b. Observations and Findings
The licensee radiographed the HPI nozzle connections to the main loop
cold legs to verify that required thermal sleeves were still located
properly. Thermal sleeves were provided to protect the pressure
boundary piping from thermal stresses when relatively cold water is
injected into the operating system.
The inspectors reviewed the radiographs taken-during the current outage,
and compared them with the radiographs taken during the Spring 1997
outage. The comparison showed that there had been no measurable
movement of the thermal sleeves.
The inspectors reviewed ultrasonic test (UT) data from inspection of the
HPI piping and safe-end connections to the nozzle connections. The
inspectors also reviewed the licensee's plans for the UT inspection of
the inner radius of the nozzle connection to the main loop cold legs.
To provide meaningful inspection results, the planned inspections
required the use of a calibration block with cracks rather than notches
as the reference standard.
Receipt of the calibration block was
scheduled for the week of April 12, 1998.
c. Conclusions
The licensee's augmented inservice inspection programs for the high
pressure injection connections to the main loop have been improved since
9
the piping failure in the Spring of 1997.
M1.3 Once Through Steam Generator (OTSG) Inspections
a. Inspection Scope (50002)
The inspector reviewed OTSG-inspection procedures and observed Unit 2
OTSG inspection activities.
b. Observations and Findings
The eddy current inspection of the Unit 2 OTSGs included 100 percent
bobbin coil inspection of the inservice tubes. During the bobbin coil
inspection of the 2A OTSG, the licensee discovered five tubes which had
been improperly installed during the manufacture of the OTSG. The five
tubes involved were installed at locations R21-C28, R21-C29, R22-C30.
R22-C31, and R23-C31. The tubes were installed such that they were in
one location in the lower tubesheet (LTS) and then crossed over to an
adjacent location in the upper tubesheet (UTS). The tube from location
R21-C28 in the LTS crossed to location R22-C30 in the UTS: LTS R22-C30
crossed to UTS R23-C31: LTS R23-C31 crossed to UTS R22-C31: LTS R22-C31
crossed to UTS R21-C29: and finally LTS R21-C29 crossed to UTS R21-C28.
The "twisted-tube" problem was discovered because two of the tubes were
supposed to have been plugged during the Unit 2. End of Cycle-15 (EOC
15) outage: in fact they were only plugged at the LTS. Full-length
bobbin coil eddy current examinations have historically been conducted
from the lower tubesheet of the OTSGs. As a result of eddy current
examinations in EOC-15; tubes R21-C28 and R23-C31 (as indexed from the
lower tubesheet) were found to have rejectable indications and were
plugged. (That is,
locations R21-C28 and R23-C31 on both tubesheets
were plugged.)
During EOC-16 attempts to eddy current inspect locations
R21-C29 and R22-C30, obstructions were noted which turned out to be the
plugs which had been installed at UTS locations R21-C28 and R23-C31.
he licensee generated PIP 2-098-1617 to document the problem,
corrective actions, and potential impact on the operating Units 1 and 3.
The OTSG is a vertical, straight tube heat exchanger. With this design,
the tube locations should match in the upper and lower tubesheets. The
presumption that these tube locations are as designed is the basis by
which all tube inspections and repairs are accomplished. Tube plugging
requires positive identification of the tube by its location in each
tubesheet; because of the design, there is not a requirement that the
tube be verified to be the same tube "hole" in each tubesheet.
To determine the scope of the manufacturing problem, the licensee used
eddy current equipment located on both upper and lower tubesheets to
verify that the remainder of the tubes were at the same tube locations
in both tubesheets. When it was determined that the set of five
"twisted" tubes were unique in the 2A OTSG. the licensee elected to
remove all five tubes from service by plugging.
The licensee conducted in-situ pressure testing of ten tubes from the 2A
OTSG during the EOC-16. The tubes were subjected to test pressures of
1450 pounds per square inch (psi). 2900 psi, and 4300 psi, representing
10
normal operating differential pressure, main steam line break
differential pressure, and Regulatory Guide 1.121 Structural Limit
Pressure, respectively. Tubes tested were as follows:
Tube
Defect Type
Location
Comments
R6-C10
Axial
R20-C28
Mixed
UTE-UTS
Leaker found during bubble
test
R22-C30
Axial
Mispositioned R21-C28 Lower
R22-C31
Axial
Mispositioned R23-C31 Lower
R26-C3
Volumetric
R32-C2
Axial
R46-C21
Axial
R73-C17
Axial
R145-C35
Axial
R150-C19
Axial
The inspectors witnessed the in-situ pressure testing of tubes R22-C30
and R22-C31, which had been left in service with only the LTS plugged.
Both of these tubes successfully passed pressure testing at 1450 psi
(operating differential pressure) and 2900 psi (main steam line break
pressure). Tube R22-C30 passed the Reg. Guide 1.121 structural limit
pressure test at 4300 psi, but R22-C31 developed a through-wall leak at
about 4200 psi.
(The leak was determined to be through an axial
indication just below the UTS.)
The fact that the two defective.tubes,
left in service with only one end plugged, passed the main steam line
break differential pressure test provided assurance that these tubes
should have maintained leak integrity during accident conditions during
the past operating cycle.
The inspectors also reviewed the licensee's justification for continued
operation of Units 1 and 3' considering the potential for having rotated
tube groups similar to the one found in the 2A OTSG. After reviewing
the calcul ations, which included stresses expected if the rotation
occurred between the two closest spaced support plates, and having
witnessed the pressure testing of the 2A OTSG degraded tubes, the
inspectors agreed that there should be'no concern that would require
shutdown and inspection of either of the units prior to the next
scheduled refueling.
c. Conclusions
Inspection and testing of the Unit 2 once through steam generators were
being conducted in a thorough and conservative manner. Unexpected
11
findings were thoroughly evaluated for significance and potential impact
on the operating units.
M1.4 Emergency Power Switching Test
a. Inspection Scope (61726)
The inspectors observed, reviewed, and discussed the performance of the
18-month Technical Specifications (TS) required emergency power
switching test. The test was performed to verify that the main feeder
busses are energized by the most reliable source without operator
actions.
b. Observations and Findings
The test, Procedure PT/2/A/0610/01J, Emergency Power Switching Logic
Functional Test, Revision 18. consisted of manually tripping switchyard
breakers, manually initiating engineered safety channels, and disabling
selected relays. The relays were disabled to ensure that only the load
shed relays would actuate the breakers. During the conduct of the test
the inspectors observed several items which required on the spot
procedure changes and the issuance of test discrepancies. The test
-coordinator issued PIP Report 2-098-2393 to document and track
discrepancies. Among the items were the following:
Enclosure 13.1 required the undervoltage relays for the individual
4160 volt (V) switchgear breakers to be disabled prior to
performing the test, however. Section 12.4 required the same
undervoltage relays to be checked for proper operation following a
power transfer;
Section 8.19, referred to a mislabeled undervoltage relay on a
breaker for the SSF;
Section 12.5 directed the operators to manipulate a switch on the
wrong Engineered Safeguards (ES)
panel. and channel and:
Section 8.33 omitted several breakers from the lists for removal
of red breaker closed indicating bulbs and for verifying voltage
on opened links, and improperly -identified an open link.
The inspectors found from the reviews, observations, and discussions
that none of the changes or discrepancies had an impact on the success
of the test. The inspectors did find that these changes and
discrepancies could have been avoided if a more thorough pre-test
technical and administrative review had been performed.
c. Conclusions
The inspectors concluded that the Unit 2 emergency power switching logic
test was successfully performed. This was indicative of adequately
maintained equipment.
A more thorough pre-test review of the procedure for the Unit 2
emergency power switching logic test could have precluded some of the
12
minor discrepancies observed during the test and was considered a
weakness.
III. Engineering
E2
Engineering Support of Facilities and Equipment
E2.1 Keowee Activities
a. Inspection Scope (37551, 92903. 93702)
The inspectors reviewed drawings, observed activities, reviewed
procedures, and discussed with licensee personnel the circumstances
surrounding three different events affecting Keowee Hydro Units 1 and 2.
b. Observations and Findings
On April 9, 1998, Keowee Units 1 and 2 were operating to the grid
producing commercial power. Both units received an emergency start
signal and separated from the grid as designed. On April 20, 1998,
Keowee Unit 2 failed to synchronize to the grid during a normal start.
On April 26, 1998. with Keowee Unit 1 tied to the grid at 78 megawatts
--and Unit 2 in standby, an undervoltage and an overcurrent condition was
received by Unit 1. The over current condition lasted for one second
and the undervoltage condition lasted for 13 seconds.
The emergency start on April 9. 1998, was caused by an inadvertent start
signal from Oconee Unit 2, which was in refueling outage. Maintenance
activity of wire tracing was being performed in the Keowee Emergency
Start Channel A cabinet in the Oconee Unit 2 cable room. A four hour
non-emergency notification was made to the NRC based on the possibility
that the start was triggered by an Engineered Safeguards Features (ESF)
module. The maintenance activities required the door to the cabinet to
be open. The event occurred when the cabinet and/or relay was bumped.
The licensee initiated PIP K-098-1854 to troubleshoot and attempt to
determine the root cause of the actuation. Subsequently, licensee
personnel were able to duplicate the event, but were unable to pinpoint
the exact cause. Suspected modules were changed out and the licensee
will monitor the system. At the end of the inspection period, the
licensee retracted the notification but indicated that they may submit a
voluntary LER.
When Keowee Unit 2 failed to synchronize during a normal start on April
20, 1998, the licensee declared the unit inoperable and issued PIP
K-098-2061. During the inspectors' review of troubleshooting
activities, the licensee revealed that the speed adjustment motor for
the governor had failed. The cause of the failure was excessive carbon
dust, produced by motor brush operation, in the motor. The motor was
cleaned and the unit was returned to operable status. An inspector
review of the operating controls and schematic, a review of vendor
information on governor operation, and discussions with the licensee
indicated that the failure of the motor did not affect the safety
function of the unit. The motor adjusts the base speed of the unit
between 58 and 63 hertz and it is used to auto synchronize the unit to
the grid during normal start operation. The circuit used to synchronize
13
to the grid automatically is not required during a safety related
emergency start operation. The licensee was considering preventive
maintenance on the motors.
The licensee initiated a failure investigative process (FIP) team and
PIP K-098-2215, to review the April 26.'1998. overcurrent and
undervoltage condition on Keowee Unit 1. Based on the reviews,
observations, and discussions, the inspectors understood the following:
The Oconee Unit 2 control room operators closed a switchyard
breaker to backfeed the unit from the grid through it's main and
auxiliary transformers;
the Keowee operators observed an electrical disturbance and the
Keowee plant computer indicated a high current indication with a
low voltage condition;
the Keowee plant computer indicated that the high current
condition cleared within 1 second and the low voltage condition
lasted for approximately 13 seconds;
a review of the event recordings of such items as the switchyard
yellow buss voltage, the Oconee Units 1 and 3 generator outputs.
and the megavolts reactive (MVARs) indicated that a transient of
approximately 13 seconds occurred when the main and auxiliary
.transformers were brought on to the grid: and
the FIP team did not observe the presence of any phase to phase
detrimental harmonics, a check of the electrical condition of the
transformers indicated no deficiencies, and a review of historical
data indicated that low voltage conditions had occurred during
backfeed operations.
The inspectors found that the 13 second transient on the grid and on the
Oconee units corresponded to the 13 second Keowee low voltage condition.
The inspectors also found that the electrical disturbance observed by
the Keowee operators was a normal MVAR transient resulting from placing
the transformers, a large electrical load, on-to the grid. A review of
historical information indicated that in the past the transformers had
not been placed on to the grid with any of the Keowee units on line.
c. Conclusions
Retraction of the four hour notification for the Keowee Unit 1
unanticipated start of April 9', 1998. was appropriate.
The technical resolution of the failure of the Keowee Unit 2 speed
changer motor on April 20, 1998, was adequate. The inspectors concluded
that the failure of the speed adjustment motor on April 20, 1998. did
not affect the safety function of Keowee Unit 2 but did reflect poorly
on the material condition of the the speed adjustment motor. The
licensee used conservative judgement in declaring the unit inoperable
due to failure of the speed adjustment motor. Good engineering support
was provided and good troubleshooting methods were used on the speed
adjustment motor.
14
The performance of the licensee's failure investigative process team
concerning the Keowee Unit 1 overcurrent and undervoltage disturbance of
April 26, 1998, was excellent.
E8
Miscellaneous Engineering Issues (92903)
E8.1
(Closed) LER 50-269/97-05: Low Pressure Service Water System (LPSW)
Outside Design Basis for High Trajectory Turbine Missile
The circumstances surrounding this item have been previously discussed
in IR 50-269.270,287/97-02 and IR 50-269,270,287/97 -05. Enforcement
discretion for this issue was granted in the cover letter for IR 50
269,270,287/97-05 dated July 18, 1997.
The inspectors evaluated this LER describing operation of the Oconee
Units 1, 2, and 3 outside system design basis for high trajectory
turbine missiles. The inspectors verified that the installed system did
not conform to the design basis description. To correct the situation,
the licensee made changes to the UFSAR to revise the design basis
description for the system. The revision allowed use of industry and
NRC guidance concerning vulnerable target area and probability of impact
of a turbine missile without shielding or separation protection. The
.-
change was submitted for review and accepted by the staff. No
unreviewed safety questions were identified. The inspectors determined
that the revision to the design basis, approved by the staff in
correspondence dated May 16, 1997, was an adequate change to the plant
design and was confirmation that no other corrective actions were
necessary. Additionally, the licensee's effort to understand their
design was adequate. The inspectors also noted that operability of the
LPSW system was maintained. This LER is closed.
E8.2 (Closed) LER 50-269/96-05: Failure to Perform TS Required Inspection
This LER identified an issue in which the licensee failed to perform a
TS required inspection of snubber S/R# 1-03-401H. Specifically, the
licensee failed to perform an 18-month inspection of the snubber as
required by TS 4.18.1. Documentation reviewed indicated that following
a modification, implemented in January 1993, the accountable engineer
failed to ensure that the snubber had been entered into the TS
surveillance maintenance procedure. PIP 1-096-1497 provided corrective
actions to change procedures for engineering personnel to review
snubbers for TS applicability and to ensure proper testing. Following
the review of all associated documentation, the inspectors concluded
that the corrective actions identified by the licensee were adequate to
provide reasonable assurance of not missing TS required inspection when
new snubbers are installed. The inspectors also verified that each of
the corrective actions had been implemented.
The inspectors also concluded that the failure to perform the TS
required inspection was a violation. However, this non-repetitive,
licensee-identified and corrected violation is being treated as an Non
Cited Violation (NCV), consistent with Section VII.B.1 of the NRC.
Enforcement Policy. This is identified as NCV 50-269/98-05-02; Failure
to Perform Snubber Inspection as Required by TS.
15
E8.3 (Closed) Inspector Followup Item (IFI) 50-269.270.287/96-13-03: Testing
of the Modifications to the Low Pressure Service Water System.
The inspectors reviewed the following test procedures:
PT/2/A/0261/007 Revision 18. Emergency CCW System Flow Test
TT/0/A/0251/070 Revision 0, Siphon Seal Water Test
TT/2/A/0261/010 Revision 0, ECCW/ESV Integrated Post-Modification
Test
PT/2/A/0251/023 Revision 8, LPSW Flow Test
The above listed procedures were reviewed for precautions, limitations,
test acceptance criteria and contingency planning.
The inspectors
attended pre-job briefings for the procedures, and witnessed the
performance of portions of each test. The acceptance criteria for each
test was successfully met. The LPSW flow test demonstrated that the new
essential siphon vacuum (ESV) system could maintain the condenser
circulating water (CCW) system headers full of water with one operating
unit (Unit 1) and one shutdown unit (Unit 2) taking LPSW suction from
the unit 2 CCW crossover header in siphon flow.
The inspectors noted that the procedures were well written and required
no changes and only a few enhancements were identified during the
conduct of the procedures. The inspectors attended the pre-job briefing
for several of the procedures and observed that the briefings were
thorough. The briefings included the purpose of the testing, the
precautions and limitations, the general outline of the test, the test
acceptance criteria, and the contingency plans for terminating the test.
Personnel safety and self-checking were emphasized. The importance of
slow deliberate actions were emphasized and caution was stressed. The
inspectors also observed operations shift turnovers. These were
conducted in a very professional manner. The status of the testing was
discussed as well as.the expected results and changes in plant
configurations that would occur during the testing were addressed. The
test coordinators were very effective in conducting the testing and were
very familiar with the procedures. Good control of the testing
evolutions was demonstrated by the test coordinators observed.
This testing demonstrated the ability of the ESV system to maintain the
emergency condenser circulating water (ECCW) first and second siphon for
,a
period of at least eight hours. At the end of the LPSW flow test, the
headers were still full of water and thus were capable of providing
cooling water for the ECCW. These modifications and testing complete
the required actions for the closure of this item on Unit 2. The Unit 3
ESV system was scheduled to be completed during the Fall 1998 outage and
Unit 1 in the Spring 1999 outage. While the test acceptance criteria for
the ECCW/ESV integrated test was met, a review by the licensee's
engineering department identified that the air removal rate was less
than the design rate of the ESV system. Discussion with the float valve
manufacturer indicated that the float may be too light for the test
conditions experienced at the time of the test. The licensee was in the
0process
of modifying and testing different float weights to improve the
16
air removal rate. Based on the results of this testing the licensee was
planning to modify the Unit 2 installed float valves and to re-run the
ECCW/ESV integrated test.
The testing to be conducted on Units 3 and 1 is similar to the testing.
that has been completed on Unit 2. These tests will include a
hydrostatic test of the units piping to the CCW pumps and motors and ESV
tanks and pumps, a Siphon Seal Water (SSW) test to verify adequate SSW
flow to the unit pumps and motors, an ECCW system flow test to verify
the amount of air in leakage, an ECCWLESV integrated test to verify that
the ESV system can remove air from the ECCW siphon headers, and a LPSW
flow test to demonstrate the LPSW pumps can take a suction from the ECCW
siphon for an extended period of time. Successful completion of this
testing on each unit will be identified as IFI 50-269,287/98-05-03:
Units 1 and 3 Low Pressure Service Water Testing.
IV.
Plant Support Areas
R1
Radiological Protection and Chemistry Controls
R1.1 Tour of Radiological Protected Areas
a. Inspection Scope (83750)
The inspectors reviewed implementation of selected elements of the
licensee's radiation protection program as required by 10 CFR Parts
20.1201, 1501. 1502, 1601, 1703, 1802
1902, -and 1904. The review
included observation of radiological protection activities including
personnel monitoring controls, control of radioactive material,
radiological surveys and postings,. and radiation area and high radiation
area controls.
b. Observations and Findings
During tours of the turbine building, reactor building, auxiliary
building, and radioactive waste storage and handling facilities, the
inspectors reviewed survey data and performed'selected independent
radiation and contamination surveys to verify area postings and labeling
of radioactive material.
The inspectors also reviewed storage locations
for radioactive material and radioactive sources. Observations and
survey results determined the licensee was effectively controlling and
storing radioactive material.
However, the inspectors observed three
exempt quantity sources used for source checking instruments that were
not marked as radioactive material. The licensee returned these
unlabeled exempt quantity sources to labeled containers. These exempt
quantity sources are not subject to NRC regulations. The licensee
initiated a PIP to investigate the controls for these sources. Also,
the inspectors discussed the storage of some flammable radioactive
sources in storage lockers with other hazardous materials. The licensee
was in the process of obtaining a special locker for these sources. The
licensee initiated a PIP Report 0-098-1475. to review the controls for
storage and handling of radioactive sources.
17
- During plant tours, the inspectors observed that extra high radiation
areas (locked high radiation areas) were locked as required by licensee
procedures. The inspectors reviewed key controls for extra high
radiation area and very high radiation area keys. The inspectors
inventoried key storage locations and all keys were accounted for at the
time of the inspection. The licensee had logged keys out to personnel
qualified to work in these areas and the key boxes were locked when not
in use as required by procedure to maintain control of the keys. Logs
reviewed determined the keys had been accounted for once a shift.
However, the inspectors found a means to bypass the lock on a desk that
contained a key to open the box that stored the extra high radiation
keys. The inspector discussed the potential for bypassing existing key
controls with licensee management. The licensee removed the key from
the desk drawer and initiated PIP Report 0-098-1471, to review the
controls for the desk drawer containing the key. The inspectors also
observed appropriate dosimetry controls for these areas were established
in radiation work permits (RWPs) as required by licensee procedures.
The licensee's records determined the licensee was maintaining
approximately 126,081 square feet (ft
2) of floor space as a
radiologically controlled area (RCA). Rpcords also determined the
licensee maintained approximately 559 ft' or less than 1 percent of the
-.RCA as contaminated during the week of the inspection.
The inspectors .reviewed personnel contamination event (PCE) reports
prepared by the licensee to track, trend, determine root cause, and any
necessary followup action. The licensee established a goal of 216 PCEs
for 1998. As of March 26, 1998, approximately 45 PCEs had occurred
during 1998 which included both particles and dispersed contamination
events for clothing and skin contaminations. Licensee efforts in 1998
to reduce personnel contaminations had been positive.
RWPs established for performing work were reviewed. These controls
included the use of RW Ps to be reviewed and understood by workers prior
to entering the RCA. The inspectors reviewed selected RWPs for adequacy
of the radiation protection (RP) requirements based on work scope,
location, and conditions. For the RWPs reviewed, the inspectors noted
that appropriate protective clothing, and dosimetry were required.
During tours of the plant, the inspectors observed the adherence of
plant workers to the RWP requirements.
c. Conclusions
Based on observations and procedural reviews, the inspectors determined
the licensee was effectively maintaining controls for personnel
monitoring, control of radioactive material, radiological postings,
radiation area controls, and high radiation area controls as required by
10 CFR Part 20. Efforts to reduce personnel contaminations were
positive
18
R1.2 Occupational Radiation Exposure Control Program
a. Inspection Scope (83750)
The inspectors reviewed the licensee's implementation of 10 CFR
20.1101(b) which requires that the licensee shall use, to the extent
practicable, procedures and engineering controls based upon sound RP
principles to achieve occupational doses and doses to members of the
public that are As Low As Reasonably Achievable (ALARA).
b. Observations and Findings
The inspectors interviewed licensee personnel and reviewed records of
ALARA program results and activities.
An effective Unit 2 chemical shutdown crudburst had resulted in reactor
building average dose rate reductions of approximately 1 millirem/hour.
Dose rates in the steam generator bowls were reduced by approximately
twenty-one percent. The licensee had established an annual exposure
projection for 1998 of approximately 292 person-rem or 97.3 person
rem/unit. The licensee established an exposure goal of 109 person-rem
for the current Unit 2 refueling outage. At the time of the inspection,
the licensee was tracking approximately 44 person-rem year to date which
was below year to date estimates of 64 person-rem. All personnel.
exposures to date in 1998 were below regulatory limits.
During tours of the facility, the inspectors observed RP technicians
controlling access to work areas to minimize personnel exposure and
briefing workers in the work areas as radiological conditions changed.
The inspectors also observed effective use of shielding, teledosimetry,
remote cameras and wireless communications systems for controlling
personnel exposures during maintenance evolutions.
The inspectors attended an ALARA committee meeting where the licensee
discussed responsibilities of the ALARA committee, current radiation
exposure status for the site, Unit 2 outage exposure-status and goals,
temporary and permanent shielding projects, and future ALARA
initiatives. The meeting was well managed and participation and
attendance by primary committee members was observed to be good.
c. Conclusions
Based on licensee planning efforts to reduce source term and the
licensee's efforts to achieve established exposure goals which were
challenging, the inspectors determined the licensee's programs for
controlling exposures ALARA were effective. All.personnel exposures to
date in 1998 were below regulatory limits.
19
R2
Status of RP&C Facilities and Equipment
R2.1 Breathing Air Testing and Ouality
a. Inspection Scope (83750)
Title 30 CFR 11.121 requires that compressed, gaseous breathing air meet
the applicable minimum grade requirements for Grade D or higher quality.
Title 10 CFR Part 20 Subpart H provides requirements for respiratory
protection programs. Title 10 CFR 20.1501 requires licensees ensure
instruments and equipment used for quantitative radiation measurements
are calibrated.
b. Observations and Findings
The inspectors reviewed and discussed with the licensee representatives
the program for testing and qualifying breathing air as Grade D. The
inspectors examined breathing air manifolds for physical integrity and
current calibration of gauges. In addition, the inspectors further
noted that the supplied air hoods and hoses available for use were
compatible per manufacturer's instructions as were air supplied
respirators and hoses. All respiratory protection equipment observed
during facility tours was being maintained in a satisfactory condition.
During facility tours, the inspectors noted that survey instrumentation
and continuous air monitors observed in use within the RCA were operable
and currently calibrated. The inspectors toured the instrument
calibration room and discussed the portable instrument program with
cognizant personnel. The inspectors determined the licensee had an
adequate number of survey instruments available for use during the
outage and the instruments were being calibrated and source checked as
required by licensee procedures.
c. Conclusions
Review of breathing air testing records verified that the licensee was
calibrating breathing air compressor equipment and sampling in-use
breathing air systems for certification in accordance with procedural
requirements. For the tests reviewed, breathing air met Grade D or
better quality requirements. The respiratory protection program was
being implemented as required by 10 CFR Part 20 Subpart H. Survey
instrumentation had been adequately maintained.
R4
Staff Knowledge and Performance in RP&C
R4.1 Observations of Source Control and Frisking Requirements
a. Inspection Scope (71750)
The inspectors toured radiological areas, interviewed personnel, and
reviewed licensee procedures in accordance with Inspection Procedure
71750 for sampling, personnel monitoring, and control of sources.
20
b. Observations and Findings
The inspectors located and reviewed requirements for the following
sources:
Two Cs-137 sources of approximately 8 microcuries located in the
shift RP area, used for background check sources, were found
attached to two clipboards;
The sources located in the body burden room were contained in a
locked cabinet. These sources were two Eu-152 sources of
approximately 3 microcuries, one old internal check source from a
Victorine 497 (a depleted Uranium source), and two CS-137 sources;
An Am-241 and a Cs-137 source were located in the respirator area
in a cardboard box'with yellow and magenta tape: and,
The source at the Independent Spent Fuel Storage Facility (ISFSI)
area was for frisker background check and was located in a
shielded lead lock box, the source was a depleted Uranium source
also from a Victorine 497.
The above listed sources were identified as exempt sources used for
instrument checks. No NRC requirements for exempt sources were
identified.
While touring the Interim Radwaste Storage Building the inspectors
observed that there was no personnel contamination monitor present. The
facility was part of the RCA and was posted as a radiation area. The
inspectors reviewed the frisking requirements for the facility and
determined that a whole body frisk was required upon exit. There was a
hand-held frisker available that could be used to perform a whole body
frisk. The inspectors later accompanied several RP and chemistry
personnel to the facility; all frisked properly upon leaving.
The inspectors observed a chemistry technician obtaining a reactor
coolant system (RCS) sample.
The technician-wore appropriate personnel
protective devices, observed applicable RP practices, stayed on station
during sample flush and collection, and took satisfactory safety
actions. The procedure was a reference use procedure and was taken to
the sample site. Operations was notified prior to starting to sample
the RCS as required by procedure. The sample sink hood sash was
maintained below the maximum height posted and the sample sink was
posted appropriately. The technician changed gloves frequently and
frisked upon completion of obtaining the sample. The inspectors.
verified that the sample rooms are normally unlocked spaces. The door
to the back of the sample sink is kept locked for contamination control
reasons but is not required to be locked.
c. Conclusions
The inspectors concluded that the check sources identified by the
inspectors were exempt sources and were controlled appropriately.
Personal frisking practices in
the Interim Radwaste Faci ity were
21
acceptable. Chemistry personnel were knowledgeable and competent during
collection of the RCS sample.
R5
Staff Training and Qualification
R5.1 RP Technician Training
a. Inspection Scope (83750)
Training of RP technicians was reviewed to determined whether the
technicians had been provided adequate training in procedures to
minimize radiation exposures and control radioactive material as
required by 10 CFR Part 19.12.
b. Observations and Findings
The inspectors discussed training requirements with training personnel.
reviewed lesson plans and reviewed qualification records for personnel
operating portable survey instruments and count room equipment. The
inspectors compared training records for qualified individuals to daily
and weekly survey records and determined personnel performing equipment
checks had been formally qualified to use the survey instruments. The
inspectors interviewed five personnel and discussed instrument
background checks, source checks, use of sample containers, and counting
procedures. The inspectors also discussed instrument calibration and
counting procedures with cognizant technical personnel. The inspectors
determined the licensee was following established procedures for the use
of counting equipment. During facility tours, the inspectors observed
work practices to determine the effectiveness of surv
activities
involving radiation and control of radioactive materia
c. Conclusions
Based on the training activities reviewed and interviews, the inspectors
determined the radiation protection technicians had been provided an
adequate level of training to perform routine survey activities
involving radiation and control of radioactive material.
R8
Miscellaneous RP&C Issues
R8.1 (Closed) Unresolved Item (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
During tours of the auxiliary building and radioactive waste
storage/handling facilities the week of October 27-31, 1997. the
inspectors observed the licensee had performed radiological work in two
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 licensee's
review of this issue confirmed only work involving low levels of
radioactive material had been performed in the buildings. The licensee
proposed a change to the UFSAR to provide additional requirements for
the buildings when performing radioactive work. The inspectors reviewed
22
what the licensee did regarding this issue and this issue is closed.
R8.2 (Closed) URI 50-270/98-02-13: Unit 2 Monitor Inlet Sample Tubing Bend
Radius Not as Described by Design Drawings
The inspectors identified on February 11, 1998, the Unit 2 vent RIA
monitor inlet sample tubing for RIA's 43 and 44 did not alppear to have
the correct bend radius in two locations as specified on licensee
configuration control and design drawings number(s) 0-440A, Revision 37
and 0-440B Revision 38, Auxiliary Building Piping Layout Plan. This
concern was addressed as URI 50-270/98-02-13. The licensee initiated a
PIP regarding this item, confirmed the tubing did not have the correct
bend radius, and modified the tubing bend radius as specified on
licensee configuration and design drawings.
10 CFR Part 50. Appendix B, Criterion V. requires that activities
affecting quality shall be prescribed by documented instructions,
procedures, or drawings, of a type appropriate to the circumstances, and
shall be accomplished in accordance with these instructions, procedures,
or drawings. Duke Energy Corporation Topical Report Quality Assurance
Program states Duke Energy Corporation conforms to applicable regulatory
requirements such as 10 CFR 50, Appendix B.
This URI is being upgraded into a violation and is identified as VIO 50
270/98-05-04: Inadequate Configuration Control of Unit 2 RIAs-43 and 44
Particulate and.Iodine Sample Tubing.
F8
Miscellaneous Fire Protection Issues
F8.1 (Closed) LER 50-269/98-007-00: Potential Operation Outside Design Basis
for Appendix R Fire Due to an Inadequate Procedure
The circumstances described in this LER were documented in NRC IR 50
269,270,287/98-02. Affected procedures for LP-1. LP-2, CF-1, and CF-2
were placed on hold pending completion of revisions to incorporate
provisions to prevent closing the breakers during post Appendix R fire
damage assessments. The licensee also plans to develop appropriate
circuit validation process for use during post Appendix R assessments.
The failure to have an adequate procedure for operation of the valves
following a fire is contrary to the requirements of Appendix R. The
inspectors concluded that the licensees' identification and resolution
of this issue were adequate. This non-repetitive, licensee-identified,
and corrected violation is being treated as a NCV consistent with
Section VII.B.1 of the NRC-Enforcement Policy. This is identified as
NCV 50-269,270,287/98-05-05: Inadequate Appendix R Procedure.
F8.2 (Closed) LER 50-269/96-03: Reactor Coolant (RC) Makeup System
Technically Inoperable for Appendix R Scenario Due to Design Analysis
On February 5, 1996, the licensee identified that an evaluation
completed in 1987 had assumptions on Reactor Coolant Pump (RCP) seal
lea kage that did not agree with the assumptions that the licensee was
including in plant procedures. The licensee evaluated the situation and
concluded that when the current RCP seal leakage limits were applied to
an Appendix R scenario, the RC system leakage could have exceeded the
23
reactor coolant makeup system design limits. If an Appendix R fire
caused valve 1HP-276 to spuriously open, the back pressure downstream of
the RCP seals could decrease below the vapor pressure of the liquid
assing through the seal, resulting in two phase flow across the seal.
This could cause, degradation of the seal, possibly resulting in failure
and leakage in excess of design makeup flow.
The licensee took the immediate action of closing 1HP-276 and opening
the breaker to the motor .operator for the valve. The inspector verified
that subsequently, the licensee revised procedures OP/1/A/1104/02, HPI
System, OP/1/A/1102/01, Controlling Procedure for Startup,
PT/1/A/1103/06, Reactor Coolant Pump Operation, and OP/1/A/1102/10,
Controlling Procedure for Shutdown, to assure that when RCS temperature
was greater than 250 degrees F, 1HP-276 would be closed with its breaker
open. The breaker for 1HP-276 was labeled with a warning that closing
the breaker with RCS temperature greater than 250 degrees F was in
violation of the Appendix R requirements. The licensee's identification
and resolution of this issue were adequate. This non-repetitive,
licensee-identified, and corrected violation is being treated as a NCV
consistent with Section VII.B.1 of the NRC Enforcement Policy. This is
identified as NCV 50-269/98-05-06: Reactor Coolant Makeup System
Inoperable for Appendix R Scenario.
V. Management Meetings
X1
Exit Meeting Summary
The inspectors resented the inspection results to members of licensee
management at te conclusion of the inspection on May 6, 1998. The
licensee acknowledged the findings presented. No proprietary
information was identified to the inspectors.
X2
Management Oversight Group Meeting
On April 22, 1998, the NRC Oconee Management Oversight Group met with
Oconee Site Management to discuss trends in licensee performance. This
was the first of the scheduled meetings. Meetings will be scheduled on
an approximate bimonthly agenda.
X3
NRC License Renewal Team Meeting
On April 29, 1998, the NRC met with licensee management to discuss
information and responses for the Oconee reactor building license
renewal evaluation. This meeting was open to the public. This meeting
was to gather information and therefore no specific findings were
identified.
X4
NRC Management Meetings
On April 22, 1998, Mr. Samuel J. Collins, Director of the Office of
Nuclear Reactor Regulation and Mr. Luis Reyes, Regional Administrator.
Region II,
were at the site to tour the facility and meet with licensee
personnel.
24
Partial List of Persons Contacted
Licensee
L. Azzerello, Mechanical Systems Engineering Manager
E. Burchfield. Regulatory Compliance Manager
T. Coutu, Nuclear Section Manager, Valves
T. Curtis, Operations Superintendent
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
J. Forbes, Station Manager
J. Smith, Regulatory Compliance
J. Twiggs, Manager, Radiation Protection
Other licensee employees contacted during the inspection included technicians,
maintenance personnel, and administrative personnel.
NRC
D. LaBarge, Project Manager
Inspection Procedures Used
Onsite Engineering
Installation and Testing of Modifications
Effectiveness of Licensee Controls In Identifying and Preventing
Problems
Surveillance Observations
Maintenance Observations
PlantOperations
Plant Support Activities
Inservice Inspection
Occupational Exposure
Solid Radioactive Waste Management and Transportation of
Radioactive Materials
Onsite Followup of Written Event Reports
Followup - Plant Operations
Followup - Maintenance
Followup - Engineering
Follow
- Plant Support
Prompt nsite Response to Events
25
Items Opened, Closed, and Discussed
Opened
50-269,270,287/98-05-01
Inadequate Corrective Actions for
Recurring Problems With Engineering
Instructions for Minor and Temporary
Modifications (Section 07.1)
50-269/98-05-02
Failure to Perform Snubber
Inspection as Required by TS
(Section E8.2)
50-269,287/98-05-03
IFI
Units 1 and 3 Low Pressure Service
Water Testing (Section E8.3)
50-270/98-05-04
Inadequate Configuration Control of
Unit 2 Vent Monitor Particulate and
Iodine Sample Tubing (Section R8.2)
50-269,270.287/98-05-05
Inadequate Appendix R Procedure
(Section F8.1)
50-269/98-05-06
Reactor Coolant Makeup System
Inoperable for Appendix R Scenario
(Section F8.2)
Closed
50-269,270,287/96-20-04
Failure to Have RB Material
Condition Closeout Procedure
(Section 08.1)
50-269,270,287/96-05-01
Failure to Make Proper 10 CFR 50.72
Notification (Section 08.2)
50-269.270,287/E96-19-01013
Inadequate Procedure Control Over
Movement of Spent Fuel (Section
08.3)
50-269/97-05
LER
LPSW System Outside Design Basis for
High Trajectory Turbine Missile
(Section E8.1)
50-269/96-05
LER
Failure to Perform TS Required
Inspection (Section E8.2)
50-269,270,287/96-13-03
IFI
Testing of the Modifications the
Low Pressure Service Water System
(Section E8.3)
26
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 Section (Section R8.1)
50-270/98-02-13
Unit 2 Monitor Inlet Sample Tubing
Bend Radius Not as Described by
Design Drawings (Section R8.2)
50-269/98-07-00
LER
Potential Operation Outside Design
Basis for Appendix R Fire Due to an
Inadequate Procedure (Section F8.1)
50-269/96-03
LER
RC Makeup System Technically
Inoperable for Appendix R Scenario
Due to Design Analysis (Section
F8.2)
List of Acronyms
As Low As Reasonably Achievable
American Society of Mechanical Engineers
BTO
Block Tag Outs
Babcox & Wilcox
Condenser Circulatin
Water
CFR
Code of Federal Re
ations
ECCW
Emergency Condenser Circulating Water
End-of-Cycle
Engineered Safeguards
Engineered Safeguards Features
ESV
Essential Siphon Vacuum
F
Fahrenheit
FT
Square Feet
Failure Investigation Process
High Pressure Injection
IFI
Inspector Followup Item
IP
Inspection Procedure
IR
Inspection Report
Independent Spent Fuel Storage Installation
Inservice Inspection
LDST
Letdown Storage Tank
LER
Licensee Event Report
Low Pressure Injection
Low Pressure Service Water
LSE
Less Significant Events
LTS
Lower Tubesheet
Megavolt Reactive
Non-Cited Violation
NRC
Nuclear Regulatory Commission
27
NSD
Nuclear System Directive
Operations Shift Manager
Once Through Steam Generator
Personnel Contamination Event
Public Document Room
Problem Investigation Process
Per Square Inch
Quality Assurance
Reactor Building
RC
Radiation Control Area
Reactor Coolant Pump
Radiation Protection
Radiation Work Permit
Spent Fuel Pool
SITA
Self-Initiated Technical Audit
Structure System Component
SSF
Standby Shutdown Facility
Siphon Seal Water
TS
Technical Specification
Updated Final Safety Analysis Report
.-
Unresolved Item
Ultrasonic Test
UTS
Uper Tubesheet
V
Vo
Violation
Work Order
OneTruhSta0eeao