ML15118A259
| ML15118A259 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 10/06/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML15118A257 | List: |
| References | |
| 50-269-97-12, 50-270-97-12, 50-287-97-12, NUDOCS 9710230065 | |
| Download: ML15118A259 (53) | |
See also: IR 05000269/1997012
Text
U.S. NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
50-269. 50-270, 50-287, 72-04
License Nos:
DPR-38, DPR-47, DPR-55. SNM-2503
Report No:
50-269/97-12. 50-270/97-12, 50-287/97-12
Licensee:
Duke Energy Corporation
Facility:
Oconee Nuclear Station, Units 1, 2, and 3
Location:
7812B Rochester Highway
Seneca, SC 29672
Dates:
July 27 - September 6, 1997
Inspectors:
M. Scott, Senibr Resident Inspector
S. Freeman, Resident Inspector
E. Christnot, Resident Inspector
D. Billings, Resident Inspector
R. Moore, Regional Inspector (Sections E4.2, E8.5 to E8.9)
H. Whitener. Regional Inspector (Sections M8.6,.8.7)
N. Economos, Regional Inspector (Sections M8.3 to M8.5)
W. Stansberry, Regional Inspector (Sections S1 to S5. S8)
Approved by:
C. Ogle, Chief, Projects Branch 1
Division of Reactor Projects
Enclosure 2
9710230065 971006
ADOCK 05000269
G
EXECUTIVE SUMMARY
Oconee Nuclear Station, Units 1, 2, and 3
NRC Inspection Report 50-269/97-12,
50-270/97-12, and 50-287/97-12
This integrated inspection included aspects of licensee operations,
engineering, maintenance, and plant support. The report covers a six-week
period of resident inspection, as well as the results of announced inspections
by four regional inspectors.
Doerations
Receipt and storage of the new fuel in the spent fuel pool was
conducted with appropriate procedures and good communications.
(Section 01.2)
0
During the discovery and evaluation period of increased reactor
coolant system leakage from valve 2LP-1, the inspectors concluded
that: operators were following the applicable Technical
Specifications conservative decision making was evident: and
management was involved with the evaluation. The inspectors
considered the licensee's actions prudent and well thought out.
(Section 01.3)
o
The inspectors concluded that the Unit 2 planned shut down and
cooldown activities for 2LP-1 work were performed effectively.
(Section 01.4)
o
A Non-Cited Violation was identified for a motor operated valve
design deficiency implementation addressed in licensee event
report 50-269/95-08. (Section 08.3)
Maintenance
0
The inspectors concluded that the maintenance activities listed in
the general work observation section were completed thoroughly and
professionally. (Section M1.1)
o
During licensee maintenance activities to determine letdown
storage tank reference leg fluid evaporation, the inspectors
concluded that the replacement of the Unit 2 instrumentation test
tees was performed in accordance with approved procedures with
quality control and supervisory oversignt.
The inspectors also
concluded that no appreciable evaporation occurred. The
performance of the personnel invo ved was considered excellent.
(Section M1.2)
During the dual Keowee Hydro Plant outage. the inspectors
concluded that maintenance activities were accomplished in
accordance with approved procedures, personnel were knowledgeable
in the systems, practiced good engineering judgement, and had
sufficient supervi sory oversight.
The inspectors also concluded
Enclosure 2
that the material condition of the equipment observed was good.
(Section M2.1)
The failure to detect a potentially unacceptable valve stroke
surveillance in a timely fashion is identified as a weakness.
However, licensee management's disposition of the issue when
identified was good. Corrective items were appropriately
addressed or captured by the licensee's corrective action program.
(Section M3.1)
O
During this period, the licensee increased the normal operating
voltage of the Keowee main transformer and the unit startup
transformers by altering transformer tap positions. The work was
performed on a QA-1 safety-related piece of equipment without
using the work order invoked procedure (the procedure was struck
through or lined out as allowed under local instructions). An
inspector followup item was identified to review the requirements
concerning quality assurance with regard to safety related
equipment.
(Section M3.2)
Engineering
o
During a prorammatic review of the Updated Final Safety Analysis
Report, the ficensee discovered that a fuel enrichment statement
had not been addressed by the 10 CFR 50.59 evaluation.
The
licensee entered the discrepancy into their corrective action
program.
'An Unresolved Item has been opened.
(Section E1.1)
o
The inspectors concluded that the Keowee Hydro Plant modifications
were installed in accordance with app roved packages with
supervisory and engineering oversight.
The replacement of the
voltage regulator motor timer was an example of good engineering
activities. (Section E1.2)
o
The licensee initiated adequate measures to track and evaluate
water hammers in the various piping systems. (Section E2.1)
The partial discharge test of the Keowee Hydro Plant underground
cable was under the control of engineering personnel.
The
activities were conducted in a deliberate and professional manner.
The test was performed without difficulty. (Section E2.2)
O
An existing minor body to bonnet leak worsened on a Unit 2 Low
Pressure Injection valve that was unisolatable from the RCS.
The
inspectors concluded that the expected leak repair activities:
were discussed with appropriate management involvement: had good
engineering input
had appropriately developed procedures; and had
an approved method for injecting approved sealant with appropriate
Enclosure 2
3
on-line sealing guidance for ASME Class 1 and 2 components.
(Section E2.3)
During a degraded grid undervoltage relay setpoint change, workers
did not have as-found set points evaluated due to a potential
procedure problem. This test control issue was left as an
unresolved item until the licensee completed a corrective action
review.
The licensee understood the nature of the problem and
initiated appropriate corrective evaluation. (Section E3.1)
o
Engineering and site management have recently instituted a new
focus and direction for the plant through process improvement
efforts.
Preliminary output from the effort Kos been positive.
(Section E4.1)
o
The licensee implemented appropriate measures to incorporate
lessons learned from the Unit 3 integrated control system
modification into the Unit 1 modification. Design and operational
deficiencies identified in the Unit 3 modification were adequately
addressed for Unit 3 and addressed in the Unit 1 design and
modification implementation procedure changes. (Section E4.2)
0
Engineering management has instituted a practice of monthly system
engineer tours with non-licensed operators. (Section E4.3)
Plant Support
o
The inspectors identified a violation for test personnel exiting a
contaminated area without properly removing protective clothing.
(Section R4.1)
o1
During an August emergency plan drill, control room drill
personnel showed a good questioning attitude and properly used
three-way communications. (Section P1.1)
o
The licensee used compensatory measures that ensured the
reliability of security related equipment and devices. (Section
o
The access controls for vital areas were in compliance with the
Physical Security Plin. (Section S2.1)
0
An incident of failure to secure safeguards information properly
was a licensee identified, non-repetitive, corrected, non-willful
event. Consequently, a Non-Cited Violation was issued. (Section
S4.2)
The security force was being trained according to the Training and
Qualification Plan and regulatory requirements. (Section S5.1)
Enclosure 2
14
Two incidences of failure to notify security of the termination of
personnel in a timely manner were licensee identified, non
repetitive, corrected, non-willful events. Consequently, a Non
Cited Violation was issued. (Section S8.1)
During a fire drill. the inspectors concluded that the method
employed for attacking the fire was appropriate, the drill.
scenario was good, fire brigade personnel exercised good fire
fighting techniques, and the post-fire drill briefing was
effective. (Section Fi.1)
Enclosure 2
Reoort Details
SLmmary of Plant Status
Unit 1 began and ended the period at achievable power (73 percent with one
reactor coolant pump out-of-service).
Unit 2 began the period at 100 percent power shutting down on September 4, to
repair valve 2LP-1. The unit remained shutdown for the rest of the period.
Unit 3 remained at 100 percent power for the entire period.
Review of Uodated Final Safety Analysis Reoort (UFSAR) Commitments
While performing inspections discussed in this report, the inspertors reviewed
the applicable portions of the UFSAR that related to the areas ispected. The
inspectors verified that the UFSAR wording was consistent with the observed
plant practices, procedures, and/or parameters.
I. Operations
01
Conduct of Operations
01.1 General Comments (71707)
Using Inspection Procedure-71707. the inspectors conducted frequent
reviews of ongoing plant operations. In general the conduct of
operations was professional and safety-conscious: specific events and
noteworthy observations are detailed in the sections below.
01.2 Preparation For Refueling
a. Inspection Scope (607051
The inspectors used Inspection Procedure 60705 to verify the adequacy of
procedures for the conduct of refueling.
b. Observations and Findings
Unit 1 received new fuel for its upcoming refueling outage scheduled to
begin September 18. 1997.
The inspectors observed portions of the receipt, inspection, and storage
of new fuel in the spent fuel pool (SFP). Quality Assurance (QA)
personnel w.re on hand to verify cleanliness of the fuel and to take
receipt. Observations of the movement of spent fuel within the SFP in
preparation of the receipt of the new fuel and maintenance activities on
the upender were also made. SFP water clarity was excellent.
Enclosure 2
2
c. Conclusions
Receipt and storage of the new fuel in the SFP was conducted with
approPriate procedures and good communications.
01.3 Unit 2 Reactor Coolant System (RCS) Leakage from 2LP-1; Low Pressure
Injection (LPI)
Suction Valve
a.
Insoection Scooe (71707. 93702)
Beginning August 27. Unit 2 operators observed a slight increase in RCS
leakage.
Entry into the reactor building (RB) revealed additional
leakage from valve 2LP-1 beyond that which had been identified during a
May 22. 1997. startup (0.04 gallons per minute (gpm),
see Section 02.1
of Inspection Report (IR) 50-269.270.287/97-05). Operations called the
Senior Resident on August 30 keeping him informed. The residents
followed the licensee actions through the remainder of the inspection
period.
b. Observations and Findings
Several entries into the Unit 2 RB and leak rate checks revealed slowly
increasing leakage from the valve 2LP-1 seal ring area. The seal ring
provides a gasket-like seal between the body and bonnet of the valve.
Fhe valve is the first LPI valve off of the RCS and is unisolatable from
the RCS. The unidentified leakage from the Unit 2 RCS increased from
0.17 gpm on July 27, to 0.32 gpm on August 18. and to 0.86 gpm on August
31. 1997.
On August 31, an inspector responded to the site and observed, reviewed.
and discussed the leakage with licensee personnel.
The amount of
identified leakage from the valve pressure seal was determined (from a
direct measurement during a RB entry) to be from 0.28 gpm to 0.35 gpm.
The possible repair actions.were discussed. Options identified by the
licensee included a re-torque of bonnet to body fasteners, an over
torque of these same fasteners, and/or injection with sealing material.
The inspectors were informed that the re-torque could be performed by
licensee personnel if needed, the over-torque would need approval by the
vendor, and the injection of a sealing material would have to be agreed
to by the vendor, the sealing material contractor, and licensee
engineering personnel. The inspectors were also informed that overall
corrective action plan would require management approval. (Additional
observations are found in section E2.3 of this report.)
On August 31. the inspectors reviewed the applicable Technical
Specifications (TS) and observed that:. TS 3.1, Reactor Coolant System,
Section 3.1.6, Leakage, Subsection 3.1.6.1 states, in part, that the
reactor must be shut down if the total leakage exceeds 10 gpm. TS
Subsection 3.1.6.2 states, in part, that the reactor must be shut down
Enclosure 2
3
if the unidentified leakage exceeds 1 gpm. The inspectors were informed
by the licensee that the 0.28 gpm value for measured leakage would be
applied as identified leakage.
Based on engineering recommendation, site management reached the
- conclusion that the plant was required to be shutdown to effect leak
injection repairs. On September 4 with the valve leakage stabilized
around 0.5 gpm, the unit was brought off line electrically, the reactor
was shutdown, and the RCS partially depressurized. Replacement of the
seal ring would have required cold shutdown and core off load.
c. Conclusions
During the discovery and evaluation period of increased RCS leakage from
valve 2LP-1, the inspectors concluded that: operators were following the
applicable TS: conservative decision making was evident; and management
was involved with the evaluation. The inspectors considered the
licensee's actions were prudent and well thought out.
01.4 Unit 2 Shutdown Observations
a. Insoection Scope,(71707. 61726)
The inspectors observed shut down and cooldown activities in the Unit 2
control room on September 4 and 5.
b. Observations and Findings
The unit was shutdown and cooled down to 250 degrees Fahrenheit (F) and
350 pounds per square inch gauge (psig).
This was done to make repairs
to a leaking pressure seal in valve 2LP-1. The plant shutdown and
cooldown below hot shutdown conditions was characterized by clear
operator communications, effective control by shift supervision, and
management oversight. Operators used appropriate procedures, performed
a control rod timing test, and maintained close monitoring of the
letdown storage tank level.
Management on shift was present in the
control room. A yet to be approved total RCS leakage computer program
was being observed for correctness of function during the shutdown- this
program will be utilized as an operator aid as part of a corrective
action (EA 97-297, 298) when finally approved. The program operated as
expected during the shutdown.
c. Conclusions
The inspectors concluded that the Unit 2 planned shut down and cooldown
activities for 2LP-1 work were performed effectively.
Enclosure 2
4
02
Operational Status of Facilities and Equipment
02.1 General Plant Tours
The inspectors used Inspection procedure 71707 to walkdown accessible
portions of the following safety-related systems:
o
Keowee Hydro Plant
0
Unit 1 and Unit 3 High Pressure Injection (HPI) Pump Areas
0
Unit 1 LPI and Spray Pump Area
o
Condenser Circulating Water (CCW) Intake Area
0
Unit 1 and 2 Penetration Rooms
o
Unit 2 Reactor Building
o
Unit 1, 2. and 3 Low Pressure Service Water (LPSW) Pump Areas
Equipment operability, material condition, and housekeeping were
acceptable in all cases. Several minor discre2ancies were brought to
the icensee's attention and were corrected.
the inspectors identified
no substantive concerns as a result of these walkdowns.
08
Miscellaneous Operations Issues (92901, 92700)
08.1
(Closed) Violation (VIO) 50-269.270.287/95-27-01: Inadequate Procedures,
Two Examples
This violation addressed two examples of inadequate procedures. The
first example was a failure to make a four-hour report as required for
having a train of LPI out of service. Nuclear Station Directives (NSD)
202 has been reviewed and revised to prevent recurrence.
The second examole was an inadequate block tag out that allowed the
removal of a relief valve which resulted in a spill. The inspector
verified that OP/1,2.3/1502/08, Block Tagout Procedure, was revised to
designat.e relief valves as boundary valves, if aoplicable. The
inspector verified training had been completed for operations shift and
staff personnel.
The inspector also completed a search of the Problem
Investigation Process (PIP) database for other items related to
inadequate relief valve tagouts or reportability errors. No items were
found that appeared to be related. These items are closed.
08.2 (Closed) Unresolved Item (URI) 50-269.270.287/96-20-01: Standby Shutdown
Facility (SSF) Past Operability
During a site-wide review of uncertainties in engineering calculations
(started in August, 1996, IR 50-269.270.287/96-16), potential
shortcomings in the 1988 revision "0" of SSF Pressurizer Level
Instrument .Loop Uncertainty Calculation OSC-2746 were identified. A
preliminary review indicated that the SSF pressurizer heaters could
potentially be uncovered prior to reaching this heater group's
Enclosure 2
electrical cutoff setpoint. This was based on the fact that the
reference leg calculation used a reference leg water temerature of 68F
instead of a hypothetical maximum RB temiioerature of 271F.
The SSF
heaters were located within Group B. Bank 2. of tie pressurizer heaters
at a maximum height of 44 inches inside of the pressurizer.
Their 126
kilowatts of heat is required to be available within two hours after a
loss of offsite power in order to establish and maintain natural
circulation. The nine SSF heater elements must be operable for startup.
Engineering initiated investigation of the potential problem.
OSC-6847. Revision 0. SSF Pressurizer Level Uncertainty in Support of
PIP 97-0273, indicated that post-reactor trip pressurizer water level
for the worst case condition would reach a level of 47 inches. Thus,
the SSF required unenergized heaters would not be uncovered.
Pressurizer and RCS volumes would recover from this level and return to
approximately 100 inches prior to the SSF heaters being required on a
design basis SSF event.
Therefore, with the then existing indication
and control system setpoints. the heaters would have been operable. The
inspectors reviewed the calculations, discussed the findings with
engineering, reviewed the UFSAR sections 7.7.5.2 and 9.6: reviewed TSs 3.18 and 4.20. Further, the inspectors agreed with the conclusions of
PIP 97-0273 on the subject. Additionally, the licensee per PIP 97-0273
was enhancing several points in the SSF event scenario documentation and
procedures and have redoneOSC-2347 calculation (revision 2) including
the new boundary conditions and assumptions. This URI is closed.
08.3 (Closed) Licensee Event Report (LER) 50-269/95-08: Containment
Isolation Valve Inoperable Due To Deficient Design Condition (Inclusive
of Revision 1)
The substance of the LER is also found in two other documents.
IR 50-269,270.287/95-30, Section 3.0 discussed an abnormal/failed
November 27. 1995. stroke test of 1RC-6 which is a Unit 1 pressurizer
fluid sample valve and RB isolation boundary valve. The failure was
discovered when the valve stroked faster than expected. PIP 1-095-1570
addressed past operability finding the valve past technically inoperable
since a motor operated valve (MOV) gear and valve type replacement in
May 31, 1990. With an incorrect gear ratio installed, the valve would
not have closed 'against high (RCS) differential pressure under accident
conditions while in a sampling mode of operation. Normally, during
sampling, flow is isolated downstream of 1RC-6. The paired series
isolation valve. 1RC-7 (springto close pneumatic valve), was operable
and would have provided isolation of the sample line. The licensee
reviewed other valves on all three units for similar problems. Valve
3RC-5, a pressurizer steam space sample valve which is not routinely
used, was also found to be inoperable (January 24. 1996. review, PIP 3
96-179).
Enclosure 2
6
With the 1995 discovery of the 1RC-6 problem and the subsequent 3RC-5
problem. the licensee took appropriate immediate and long term
corrective actions.
The valves were aDropriately dispositioned and
the licensee submitted a timely LER and followed it with a supplement
(revision 1 dated February 19. 1996).
An NRC search of the licensee's
problem reporting data-base indicated no other examples of similar type
events within the two years prior to the time of the event.
The root cause for 1RC-6 problem and the 3RC-5 corrective action review
was determined to be deficient design changes. The valves and their
operators where changed in 1987 (3RC-5) and 1990 (1RC-6)..
During the
like-for-like valve operator change.out. the (incorrect) operator gear
ratios were not checked on the replacement Limitorque type SMB
operators. The design change to the valve operator and valve did not
specify the correct gear ratio for either valve.
Subsequent valve
testing in 1992 of both valves did not identify the gear ratio problems.
The licensee's valve testing program was fully implemented in 1993 and
the 1995 testing of 1RC-6 did identify the problem. The lack of early
(1992 or at installation work package review) problem identification
prevented entry into any operationally limiting TS 3.6.3.c limiting
condition for operation (LCO) prior to the 1995 discovery date.
Revision 1 of the subject LER indicated that had an accident occurred
during Unit 1 pressurizer sampling, the outboard isolation valve. 1RC-7,
would have closed to provide necessary isolation. Since 1990. 1RC-7
had no work history or stroke time problems.
With only 1RC-7 closed,
leakage through this sampling enetration would have been low enough to
meet TS 4.4.1.2.3 penetration leakage criteria.
This design deficiency was a violation of 10 CFR 50. Appendix B.
Criterion III. Design Control, in that desigp control processes did not
ensure that imoortant design aspects were reviewed and controlled.
Accordingly, the inspector concluded that this failure to comply n
represented a licensee-identified and corrected violation. This non
repetitive. licensee-identified-and corrected violation is identified as
a Non-Cited Violation (NCV). consistent with Section VII.B.1 of the NRC
Enforcement Policy. NCV 50-269.287/97-12-01. MOV Design Deficiency
Implementation. This LER and Revision 1 to it are closed.
08.4
(Discussed- ODen) VIO 50-269,270.287/96-05-01: Failure to Make Proper
10 CFR 50.72 Notification
Since this subject violation was identified, several other documents
have been issued or events occurred that may impact item closure. These
are as follows:
On June 19, 1997, a letter from the NRC's Office for Analysis and
Evaluation of Operational Data (AEOD) was issued regarding the
licensee's reporting practices.
Enclosure 2
7
On July 30. 1997. the Region II NRC office issued Inspection
Report 50-269, 270. 287/97-11 that addressed a reporting practice
(Section IV)
which has vet to be resolved.
o
On August 27, 1997.
EA97-297. 298 Notice of Violation was issued
that included enforcement discretion for a licensee reporting
practice (cover letter and enclosure 2).
o
On September 4. 1997, the licensee issued a letter responding to
the June 19 AEOD letter. In that letter, the licensee .asked for a
meeting to discuss reporting practices.
Until the above components are reviewed and discussed, this item shall
remain open.
II. Maintenance
M1
Conduct of Maintenance
M1.1 General Comments
a. Insoection Scooe (62707. 61726)
The inspectors observed all or portions of the following maintenance
activities.
o
IP/0/A/0310/012B
Engineered Safeguards System Logic
Surveillance Test Online Channel 3
o
PT/3/A/.0202/11
High Pressure Injection System
Performance Test
o
OP/0/A/1102/06 Encl. 3.3
Procedure For Removal From and
Return To Service of 6900/4160/600
Volt Breakers
0
MP/OA/1500/008
New Fuel Receipt
o .
Work Order (WO) 97052701-13
Replace STAR Modules 3ICSCORC06,
3ICSCORCO7. and 3ICSCORCOS
0
Change Degraded Relay Setpoints
Enclosure 2
8
b. Observations and Findinas
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.
c. Conclusion
The inspectors concluded that the maintenance activities listed above
were completed thoroughly and professionally.
M1.2 Evaporation in Reference Legs for Letdown Storage Tank (LDST) (Unit 2)
a.
-section
_Scooe_627071
The inspectors observed and reviewed the activities involved with the
Unit 2 LDST level instrument reference legs. IR 50-296.270,287/97-02.
identified concerns involving the instrumentation for the LDSTs in Units
1. 2, and 3. The specific maintenance activities observed were to check
for evaporation from the reference legs. IR 50-269.270,287/97-08, an
Augmented Inspection Team (AIT) report, also identifies concerns
involving compression fittings.
b. Observations and Findings
On July 28. the inspectors observed instrumentation and electrical
(I&E)
maintenance workers perform a verification test for possible
evaporation from both of the LDST reference legs.
If evaporation had
occurred, the level would have indicated higher than actual.
Prior to the work activities, the inspectors attended a pre-job briefing
in the I&E work shop. The pre-job briefing emphasized expectations for
items such as safety, questioning attitude, and following procedures.
At the work site, the inspectors observed that the test tees, with
compression fittings, on the level instruments, 2HPI LT 0033P1 and P2.
were replaced with new ones prior to the testing activities. The
inspectors noted, from a review of procurement documents. that the tees
were Swagelok and were American Society of Mechanical Engineers (ASME).
Section III, certified. The inspectors also observed, during the
installation, the following:
that the threads on the tee's and fittings
were inspected the tubing and tee's were inspected for foreign
material and the fittings were verified as being snug tight by the use
of a template. The inspections and verification were performed by a
quality control inspector and the technicians. A leakage test was
performed satisfactorily after the installation.
Enclosure 2
The inspectors also reviewed the following documents and procedures:
Procedure IP/0/A/0075/010. Instrument Line, Impulse Line Filling.
Revision (Rev) 3;
o
Procedure IP/0/A/5090/001, Tube Fitting and Tubing Installation.
Rev 1:
W
WO 97043780 with tasks 01, 02 and 03; and
o
Procedure IP/0/B/0202/001F. High Pressure Injection System Letdown
Storage Tank Level Instrument Calibration, Rev 31.
Among the concerns identified in the AIT inspection report. Section
M8.1.b. Compression Fitting Issues, were: the mixing of parts from
different manufacturers: foreign material exclusion: and the over
tightening of fittings.
The inspectors observed during the review of
procedure IP/0/A/5050/001 the following:
section 3.1.4.B stated, in part, do not mix or interchange parts
of tube fittings from different manufacturers;
o
enclosure 4.8. Swagelok Fittings Installation, of the procedure,
section 4.8.3 required a check for no foreign material:
o
section 4.8.3. of the enclosure, required a check for no
scratches, deformations, or damaged threads:
o
a note following section 4.8.10. insert tubing with fittings,
stated, if resistance is felt when threading nut finger tight the
fitting should be replaced; and
o
section4.8.11 required that the fittings be tightened to snug
tight.
The fittings on the level instruments were changed when it was
discovered that resistance was felt when finger tightening the nuts.
The inspectors observed the check for evaporation from the LDST
reference legs. An as-found reading for reference leg P2 was taken and
indicated 86.72 inches. The reference leg was felled in accordance with
procedure IP/0/A/0075/010. An as-left reading was taken and indicated
86.62 inches. The same process was performed on reference leg P1 with
the as-found indicating 86.48 inches and the as-left indicating 86.44
inches. This procedure was last performed three months ago. The
maximum allowed difference per procedUre IP/0/B/0202/001F was 0.75
.
inches. The inspectors noted with the differences in the as-found and
the as-left indications being 0.04 inches and 0.10 inches that no
appreciable evaporation occurred.
Enclosure 2
10
c. Conclusions
During licensee maintenance activities to determine LDST reference leg
fluid evaporation, the inspectors concluded that the replacement of the
Unit 2 instrumentation test tee's were performed in accordance with
aporoved procedures with Quality Control and supervisory oversight.
The performance of the personnel involved was considered excellent.
M2
Maintenance and Material Condition of Facilities and Equipment
M2.1
Maintenance and Material Condition of Keowee Hydroelectric Plant (KHP)
a.
Insoection ScoDe (62707)
During a dual KHP outage. the inspectors observed, reviewed, and
discussed major maintenance activities on and the material condition of
equipment at the KHP. The activities involved the KHP Unit 1 and Unit 2
voltage regulators, batteries, and the hydraulic water turbine governor
systems. The material condition included various pumps, air
compressors, and fire protection deluge systems.
b. Observations and Findinqs
The major maintenance activities were controlled by maintenance WO and
procedures. Among the WOs observed were those listed in section M1.1 of
this report. Among the procedures used were the following:
0
IP/0/A/2005/003, Westinghouse Voltage Regulator Test
0
IP/0/A/3000/026, Battery Corrosion and Connector Resistance
0
IP/0/A/0100/001,.Controlling Procedure for Troubleshooting and
Corrective Maintenance
0
MP/1(2)/A/2200/001, Keowee Governor Oil Pumps Assemblies
Inspection and Maintenance
o
MP/1(2)/A/2200/003. Keowee Governor Inspection and Maintenance
o
MP/1(2)/A/2200/006,
Keowee Permanent Magnet Generator and Speed
Switches
o
OP/0/A/1107/011, Removal and Restoration of Current
Transformer - Reactor Coolant Above 200 Degrees F
The maintenance activities included:
0
disassembling the connectors on 28 KHP battery cells, removing
corrosion, reassembling, and checking connector resistance
Enclosure 2
1
checking and adjusting the voltage regulators for proper operation
disassembling. inspecting, cleaning. and reassembly of components
within the governor and the permanent magnet generator assemblies
During the work activities on the components in the governor for KHP
Unit 1. maintenance personnel observed that the shutdown solenoid and
net head comparator sub-assembly was loose.
The mounting bolts had
backed out but not far enough for the sub-assembly to fall.
The bolts
were inspected by the system engineer, reinstalled, and torqued to 30
foot-pounds using thread locking compound.
The corresponding Unit 2
sub-assembly was checked immediately but did not appear to be loose.
After Unit 1 was returned to service, the Unit 2 subassembly mounting
bolts were similarly inspected, reinstalled, and also torqued to 30
foot-pounds with the locking compound present.
The inspectors observed that during the performance on Unit 1. of
Section 10.9, Voltage Error Detector Module Test, of procedure
IP/0/A/2005/003. the technicians were having difficulty with the Unit 1
module adjustments.
The difficulty with the adjustment was because the
gain on the card was at the high end of its range: this condition
probably had been that way since Keowee unit startup but had not
affected unit performance.
The inspectors observed that the gain on
both the KHP 1 and 2 modules were readjusted to a- more median prescribed
(lower) setting. The gain adjustment of the voltage error detector
module card was an example of good engineering and supervisory
oversight.
c.
Conclusions
During the dual Keowee Hydro Plant outage, the inspectors concluded that
maintenance activities were accomplished in accordance with approved
procedures, personnel were knowledgeable in the systems. practiced good
engineering judgement. and had sufficient supervisory oversight. The
inspectors also concluded that the material condition of the equipment
observed was good.
M3
Maintenance Procedures and Documentation
M3.1
Stroke Time Testinq of Safety Related Valves (Units i
2 and 3
a.
Inspection Scooe (61726)
As a result of a supervisory review, licensee personnel discovered that
a Unit 2 HPI suction valve potentially did not meet the stroke time
acceptance criteria during a surveillance test.
The discovery was made
six days after the completion of the test.
Enclosure 2
b. Observations and Findinas
Licensee personnel performed a surveillance on July 31 which stroke time
tested HPI suction valve 2HP-25.
(The valve and 2HP-24 are suction
valves in the HPI system.)
An approval review of the surveillance was
performed on Aug ust 6. During the review, it was discovered that the
valve potentially did not meet the stroke time acceptance criteria. The
stroke time was recorded as 14 seconds and the acceptance range was 11
to 13 seconds. The UFSAR time limit for this valve was 14 seconds
(integer valUe). The valve was declared inoperable, a stroke time test
was re-performed, the procedure tester was sought for interview, and a
PIP was initiated.
On August 7, the inspectors attended a management meeting at which all
HPI suction valve testing for all units was discussed.
Among the topics
of discussion were the stroke time testing and the lifting of links
during engineered safeguards (ES) testing of the valves. The lifting of
the links disabled the automatic operation of the suction valves. The
rounding off of stroke time testing results was also discussed.
The
inspectors were informed that the valve was retested and indicated a
time of 13.48 seconds that was consistent with the interview debrief of
the July 31 procedure tester.
During fact finding,.it was found that
this particular valve traditionally tested around this stroke time
length.
The PIP described the problem as a recording error where the
tester had mistakenly written down the maximum time as the stroke test
time.
.A decision at the management meeting was made to place the ES testing
procedures for the suction valves on hold, initiate changes to the
applicable procedures, and implement the procedure changes..
The inspectors observed, reviewed, and discussed this issue with the
licensee. As a result of observations and discussions four concerns
were identified.
The first concern involved the stroke time testing
review of valve 2HP-25.
The second concern involved the lifting of
links during testing. The third concern was associated with the second
and involved entering an applicable limiting condition for operation
(LCO)
during the time that the links were lifted.
The fourth concern
involved Dersonnel performing stroke time testing, and other testing, in
that results were rounded off.
Among the items reviewed for the concerns were:
0
Procedure PT/2/A/0152/11, HPI System Stroke Test. Revision 3;
PIP 2-097-2421, Stroke time of 2HP-25 recorded at 14 seconds:
o
Procedure PT/0/A/0310/012A, ES Logic Subsystem 1 On Line Test,
Change 26 and Revision 27:
Enclosure 2
13
PIP 0-097-2429. ES testing of HPI suction valves: and
PPT/0/A/0310/013A. ES Logic Subsystem 2 On Line Test. Revisions 31
and 32.
The inspectors observed from the review the following:
section 9.0. subsection 9.1, of stroke test procedure directed
that times be rounded off up or down to whole numbers;
o
section 10.9.5, subsections 10.9.5.b. c. and d of change 26 of the
logic subsystem 1 test directed electrical links be lifted and the
operators be informed that Unit 1. 2, or 3 HP-24 valve will not be
aDle to perform the intended safety function (during this out-of
service period):
o
section 10.9.5 and subsections 10.9.5.b. c and d of revision 31 of
the subsystem 2 test directed the same activities except Unit 1.
2, or 3 HP-25 valve was affected: and
o
revisions 27 and 32 respectively removed the requirement to open
the electrical links.
The inspectors' review results of the above concerns are as follows:
o
The operations staff did not remember such a recording error
previously nor had they had a previous problem in the reviewing
stroke test data on the shift that it was accomplished.
Inspectors reviewed the PIP data base to substantiate this
information. As a result of this isolated case, the inspectors
observed that unit operations supervisors were directed via
written shift guidance to review and verify the results of the
operations test group's acceptance criteria.
O
The licensee had historically lifted the ES signal links to
prevent reactivity changes during ES logic testing in that the
orated water storage tank (BWST)
head of water could flow into
the suction of HPI pumps.
Due to recent operations department
agreements and procedure changes LDST pressure has been increased
during testing to account for BWST head thereby minimizing
reactivity changes. Testing of suction valves have been altered to
delete the lifting of the links.
o
The inspectors reviewed the historical operator logs for the
reriods when suction valve surveillance was performed. Applicable
COs were entered when the links were lifted.
o
At the direction of operations management, specific round off
requirements have and are being added to the valve stroke
Enclosure -2
14
procedures.
Also, as a side issue, although a preliminary
overview of their personnel revealed no problems,
I&E staff have
agreed to review their rounding off methodology in the near
future.
The PIP corrective action and other information became available as the
investigation proceeded. The management decisions and licensee's
preliminary corrective actions determined that: in this case, rounding
of stroke time was performed incorrectly and that individual has been
counseled; the length of time it took to review the stroke test was
excessive but was an isolated case (with procedure changes forthcoming):
removal of valve control electrical links was unnecessary and
procedurally deleted: and overall valve testing expectations have been
clarified.
The licensee revealed additional facts concerning the valves. A valve
open position of approximately 17 percent would provide sufficient flow
for the HPI pumps. This would occur at 3-4 seconds after start of
stroke. One HPI suction valve would provide enough flow for all three
HPI pumps.
c. Conclusions
The failure to detect a potentially unacceptable valve stroke
surveillance in a timely fashion is identified as a weakness. However,
licensee management's disposition of the issue when identified was good.
Corrective items were appropriately addressed or captured by the
licensee's corrective action program.
M3.2 Startup Transformer Tan Chanoes
a.
InsDection Scone (62707)
During this period, the licensee increased the normal operating voltage
of the Keowee main transformer and the unit startup transformers by
altering transformer tap positions. The inspectors observed portions
of this work (see Section P1.2).
b. Observations and Findins
During the startup transformer tap changing activities, maintenance
reviewers closing the work package initiated
PIP 3-97-2600 on the work
covered under the minor modification OE 9370.
The PIP identified two
questions dealing with (1) the acceptability of reusing aluminum bolts,
and, (2) the fact that a WO invoked procedure was not used during the
work (the procedure was struck-through or lined-out as allowed under
local instructions). Based on their review of this issue and
examination of the fasteners, the inspectors have no concerns with the
reuse of the fasteners. The rationale in the PIP for the second problem
Enclosure 2
SII
was that the work was being performed on a QA-1 (safety-related) niece
of 20Ui pment and the PIP originator felt that the lined out orocedure
shoul'd have involved QA inspection on the work. The i nspector.will
review the requirements concerning QA with regard to safety-related
work.
This is identified as Inspector Followup Item (IFI) 50
269,270.287/97-12-04. Maintenance Oversight.
M8
Miscellaneous Maintenance Issues (92902)
M8.1
(Closed)_LER 50-287/95-01: Packing Leak Due to Inappropriate Action
Results in Unit Shutdown
IR 50-269.270.287/95-17 discussed this event and described the root
cause. The licensee has subsequently implemented a corrective action
plan (described in PIP 3-095-0923) that included repacking two steam
valves which had been packed using the same packing as the failed valve.
changing two procedures to provide for better verification of packing
follower installation, and purchasing a fiber optic camera to allow for
better inspection of valve stuffing boxes.
The inspectors reviewed the plan and determined it was adequate.
The
insDectors found the corrective actions specified in PIP Report 3-095
0923 imolemerted as stated except for the procedure changes'.
Corrective
Action humber 3 specified three changes to Procedures MP/O/A/1200/001.
Valves - Non NRC 89-10 - Adjusting and Packing: and MP/O/A/1200/001D.
Valves - NRC 89-10 - Re placing and Adjusting Packing. One of the
changes specified a double verification step had been added for
technicians to sign that the packinq follower was not cocked.
The
inscectors found this steD in Procedure MP/O/A/1200/001 but not in
Procedure MP /O/A/1200/001b.
Procedure MP/O/A/1200/001D only contained a
caution on cocked packing followers.
The inspectors later determined,
after discussions with maintenance manacptment. that procedure changes
specified in Action Number 3 were actually implemented by Corrective
Action Number 4 to' the PIP report and that maintenance Dersonnel had
incorrectly specified the procedure changes in Action Number 3 after
Action Number 4 had been completed.
The inspectors agreed the
corrective actions had been implemented, however,
the inspectors also
considered the documentation in the PIP report to be poorly done without
proper attention to detail.
The inspectors further determined that, at the time of the event.
maintenance personnel did not properly follow procedures when repacking
Valve 3RC-3, constituting a violation of 10 CFR 50. Appendix B,
Criterion V, Procedures.
This non-recetitive. licensee-identified, and
corrected violation is being treated as a Non-Cited Violation,
consistent with Section VII.B.I of the NRC Enforcement Policy, NCV 50
287/97-12-08. Failure to Followi Valve Packing Procedure.
Enclosure 2
16
M8.2 (Closed) LER 50-287/95-02: Drop of Control Rod Group Due to Unknown
Cause Results in Reactor Trip
This event was discussed in IR 50-269,270.287/95-18. No new issues were
revealed by the LER.
M8.3 (Discussed - Open) VIO 50-269.270.287/96-10-03: Weld Procedure
Qualifications Welded, Tested, Certified and Approved by Same Individual
This violation was identified when the inspectors determined that the
licensee's weld procedure qualification program failed to provide an
independent QA review for the qualification process.
The licensee acknowledged the violation on September 11.
1996.
The
licensee attributed the violation to a lack of sufficient guidance in
the Duke Power Welding Program. Procedure L-100 in that it did not
reflect the independent QA review requirement of American National
Standards Institute (ANSI)
N-18.7-76.
Corrective actions taken to address this oroblem included discussion
with technical personnel to assure that they understood the QA
requirement for independent review of qualification records.
Also. the
licensee revised the subject document such that it requires that the QA
review be performed by an individual other than the one who performed
the qualification.
By this review, the inspectors ascertained that the revised procedure.
L-100. did not include directly or by reference the applicable QA
documents, e.g., Duke's QA Topical Report. Duke- or ANSI 18.7-76. The
licensee plans to revise the subject procedure to reference the
applicable QA commitments.
The inspectors discussed this observation with the cognizant engineer
who agreed to discuss it with management before incorporating it. in the
L-100 procedure. The inspectors indicated that this item will remain
open until final action had been taken on this matter.
M8.4
Closed) URI 50-269.270.287/96-17-04: Engineering Evaluation for the
Replacement of Carbon With Stainless Steel Piping
This item was identified due to a concern over the possibility that
large diameter e.g., greater than or equal to 24-inch, carbon steel
piping could have been replaced with piping made from stainless steel
material without sufficient engineering analysis to verify adequacy as
required by Revision 17 of theapp licable pipe specification PS300.4.
The licensee's review of data collected during tne pipe branch
connection analysis revealed that there was only one location per unit
where this substitution could have taken place.
This location was
identified as a 24-inch diameter pipe section, downstream of the "D
Enclosure 2
SII
17
heater drain tank pumps.
This pipe section connects the heater
vent/drain system to the condensate system.
Through discussions with the cognizant engineer and review of applicable
drawings. the inspector verified that Pipe replacement in the
aforementioned location had not taken place.
The inspectors concluded
that the licensee's investigation and findings were satisfactory.
M8. S-(Discussed - Ooen) VIO 50-269.270.287/96-17-09:
LPSW Modification Did
Not Meet ASME Code Section Xi Non-Destructive Examination (NDE)
Requirements
This violation was identified when the insoectors determined that the
licensee had failed to perform Code required examinations on certain
newly fabricated welds in the LPSW "B" line header.
The licensee acknowledged the violation on March 12,
1997 and listed the
corrective actions taken to fix the problems and the actions taken to
preclude their recurrence.
Through di scussi ons with cognizant personnel
and a review of records, the inspectors verified that the subject welds
were successfully hydrostatically tested per code requirements.
Welding Technical Support and Engineering had been assigned specific
responsibilities and were given auoropriate training for implementing
special code requirements as applicable. Also, certain process control
forms had been revised to address more clearly post-maintenance testing
requirements, e.g.. hydro versus an alternate test method. Steps taken
to preclude the recurrence of this problem were addressed as near and
long term corrective actions in PIP 0-097-1691.
These actions were the
result of a Quality Improvement Team (QIT) assessment of Oconee's Post
Maintenance/Modification Testing (PMT)
Program.
Previous root cause
inspections found that the program was fragmented and that there 'was not
sufficient technical support and management oversight to assure that the
program served its intended function.
A summary of the major recommendations made by the QIT included:
development of a comDrehensive guidance document addressing PMT
activities: establish scheduling ties and reporting methods: establish a
PMT Working Group: establish a test .coordinator and adequately staff PMT
functions: and formalize weld process control and PMT testing
requi rements.
These recommendations were subsequently evaluated and
grouped into short and long term categories in PIP 0-097-1691.
The short term recommendations were to be resolved prior to the upcoming
Unit 1 refueling outage.
The insoectors stated that this matter would
remain ooen until the inspectors had an opportunity to review the
identified short term recommendations for adequacy prior to the
aforementioned outage.
Enclosure 2
18
M8.6
(Closed) IFI 50-269.270.287/93-20-01:
Instrument Impulse Lines and
Associated Inservice Inspection (ISI) Requirements
The inspectors had identified instrument impulse lines off of safety
related Emergency Core Cooling Systems (ECCS)
which were seismic, QA-1,
safety related lines up to the first instrument root valve (pressure
boundary) and were non-seismic, non-safety related lines from the root
valves to the instruments. The inspectors had raised the concern that a
loss of inventory or release of radiation could occur if the non-seismic
portions of the lines fail since the root valves to.these non-safety
related instruments are normally open valves.
The licensee performed an investigation of this situation -and a review
of documents to determine the required status of these lines.
report No. 0-094-0309 was opened to track actions and document results
of this investigation. The inspectors reviewed UFSAR Section 3.9.3.1.3.
and a letter dated May 6. 1996, from Duke Power Company (J. W. Hampton)
to the NRC formally acknowledging a verbal commitment made to the NRC to
upgrade .ECCS instrument lines to QA-1 status.
Also, the insoectors
reviewed the evaluations and corrective actions described in PIP 0-094
0309. reviewed portions of a draft calculation, OSC-6163, which .
documented the results of instrument line walk down inspections, and
confirmed that plant drawings and instrument details had been upgraded
to show the instrument impulse lines as QA-1.
QA-1 status assures that
these lines will be maintained i.n accordance with 10CFR50. Appendix B.
The inspectors also reviewed several walkdown packages. Wal kdown check
sheets included items such as the following:
verify instrument line is flexible enough to absorb the thermal
and seismic movements;
0
verify sufficient clearance exist such that seismic interaction
with adjacent equipment is not a concern:
o
verify instrument line is sufficiently supported to ensure failure
will not occur during a seismic event: and.
o
verify instrument valve is sufficiently supported to ensure that
failure will not occur during a seismic event.
The insoectors concluded that through the corrective actions the
licensee has met the coimmitment made to the NRC to upgrade the ECCS
instrument impulse lines to QA-1 status.
Enclosure 2
19
M8.7 (Closed) URI 50-269/96-04-04: Root Cause Assessment of Failures to
This item involved failures of valves in two separate systems which are
discussed below.
1MS-77, Second Stage Reheater Al Inlet Valve
1MS-77, a non-QA-1, non-safety related valve, failed to go closed on
demand. Troubleshooting showed the valve to be wedged in the backseat
with the thermal overloads tripped. When attempting to recycle the
valve the breaker tripped instantly. The licenee's investigation
determined that the open limit switch was set at 2 percent when the
procedure required 5 percent.
The licensee concluded that the valve was
going into the backseat every time the valve was fully opened.
This
resulted in requiring an excessive amount of motor torque to pull the
valve off of its backseat.
This problem then led to the motor on the
valve operator failing and causing the breaker to trip.
The licensee concluded that the valve failed because of improper valve
set up. The cause was personnel error. The root cause was considered
inadequate training. Training and Qualification Guide, ETQS # MOV-Q
LIMITORQUE, was amended to highlight this condition. The inspectors
reviewed the guide and confirmed the revised training instructions.
Additionally, the inspectors reviewed the task completion comments, PIP
.1-096-0417, and procedure IP/0/A/3001/010, "Maintenance Of Limitorque
Valve Operators."
The procedure was considered adequate and this issue
was considered resolved.
LPSW Valve 1LPSW 254. LPI Cooler Outlet Isolation
Valve 1LPSW-254 is the Unit 1 train A LPI cooler outlet isolation valve.
Valve 1LPSW-251 is the flow control valve for the same cooler and is
located immediately upstream of 1LPSW-254. Due to numerous LPSW system
component failures in the past, an adverse condition was identified.
The licensee's identification, testing, and proposed corrective actions
are identified and tracked in PIP 0-095-1491. Because of the similar
configurations of the LPSW cooler installations. this PIP is applicable
to all three Oconee Units.
A review of the numerous LPSW comoonent failures indicated that
vibration problems were principal'contributors.
Therefore, the licensee
performed extensive vibration testing and component inspections. The
results indicated that the excessive LPSW system vibrations were caused
by flow induced cavitation through the flow control valves. Based on
the vibration study and component inspection, the licensee had developed
an Urgent Nuclear Station Modification (NSM)
3022 which will.be
implemented on each unit at the next refueling outage.
The inspectors
Enclosure 2
20
reviewed portions of the Unit 1 modification package, NSM 13022. This
modification will replace flow control valves 1LPSW-251 and 1LPSW-252.
and associated downstream isolation valves 1LPSW-254 and 1LPSW-256. with
valves designed to reduce the flow induced cavitation and noise. Also,
flow control valves will be relocated to increase the distance between
flow Control and isolation valves.
Carbon steel piping immediately
downstream of the flow control valves will be replaced by stainless
steel piping.
The inspectors concluded that the licensee had identified the root cause
and developed necessary actions to correct the vibration problem. The
Unit 1 modification package had been developed and was scheduled for
implementation at the next Unit 1 refueling outage (September 1997).
Units 2 and 3 will receive the same modification. The licensee stated
that these modifications are in the preparation stage and will be
implemented at the next refuel-ing outage for each unit.
The inspectors concluded that the licensee had identified the root cause.
and taken action to correct the problem and prevent recurrence.
I II. E ngjneerng
El
Conduct of Engineering
E1.1 UFSAR Fuel Load Requirements
a.
Scooe of Inspection (71707. 37551)
Through Oconee site initiated PIP 0-97-2511. the licensee identified
that fuel enrichment had not been as specified in the UFSAR Section
4.3-3.1.4. This was discovered during a recent (August 13, 1997)
internal site review of the UFSAR.
b. Findings and Observations
The UFSAR section stated in part that "Each fuel rod is identified by an
enrichment code, and the desi gn of the reactor is such that only one
enrichment is used Per assembly."
This was not the case in all Oconee
units (starting in 1994 on Unit 2).
There are currently multiple
batches of fuel in use at Oconee that have axial blankets (regions of
reduced enrichment at the upper and lower ends of the fuel rods). Also,
the fuel currently being received for the upcoming Uni't 1 outage
contains fuel pins of varying enrichment within the same assembly (this
is the first such fuel used at Oconee). The 10 CFR 50.59 review that
was generated by the corporate office for this upcoming Unit 1 fuel load
change did not address this UFSAR statement. TS 6.9 covered fuel
analysis methodology and other NRC - licensee transmittals had
Enclosure 2
21
previously approved fuel design techniques with stringent critical
parameter limits.
Previous fuel reload and 10 CFR 50.59 analysis were being reviewed by
the licensee and a root cause analysis was on-going to determine how the
UFSAR requirement was overlooked. The licensee has stated in the above
PIP that the there is no present operability concern. Until the
licensee completed their 10 CFR 50.59 and fuel load UFSAR revie,, this
item will be identified as URI 50-269,270.287/97-12-02. Fuel Load UFSAR
Statements.
c. Conclusions
During a programmatic review of the UFSAR. the licensee discovered that
a fue enrichment statement had not been addressed by the 10 CFR 50.59
evaluation. The licensee entered the discrepancy into their corrective
action program.
An URI has been identified on this issue.
E1.2 Modifications to Startup Transformers and Keowee Voltage Requlators
a. Inspection Scope (37828)
The inspectors observed, reviewed, and discussed the installation of
minor modifications (MM)
to the startup transformers, the degraded grid
relays, the KHP main transformer, and the KHP voltage regulators. The
activities started on August 18 and completed on August 22. During this
time frame, maintenance activities were also observed and are documented
in Sections M2.1 and 3.2 of this report.
b. Observations arid Findings
The MM installations observed were the following:
0
MM. 10264, changed the set point on the degraded grid relays:
o
MM 9368, changed the taps on startup transformer CT 1. (similar
MMs were performed on startup transformers CT2 and 3 as well as
the KHP main transformer);
0
MMs 9323 and 9324, installed a new logic network in the KHP Unit 1
and 2 voltage regulators ; and
a
MM 9375, changed the relay settings for the KHP main transformer.
The MM for the voltage regulators were installed in order to return the
base and voltage adjusters to a preset level when an emergency start
signal is received. When the units are operating to the grid the
regulators may be set at a voltage output different from the required
emergency start output.
Enclosure 2
22
The ins ectors observed the post modification testing.
Durin testing
of the Unit 2 KHP regulator, a small electric motor timer failed to meet
a time required. The motor was replaced under engineering direction and
the MM was successfully tested. The test of the startup transformers
and the KHP main transformer indicated adequate output voltages.
c. Conclusions
The inspectors concluded that the Keowee Hydro Plant modifications were
installed in accordance with approved packages with supervisory and
engineering oversight. The replacement of the voltage regulator motor
timer was an example of good engineering activities.
E2
Engineering Support of Facilities and Equipment
E2.1 Water Hammer Status
a. Inspection Scope (37551)
The inspector reviewed engineering evaluations of water hammer issues
documented in various PIPs. The licensee had a severe water hammer
event in 1996 as discussed in IRs 50-269,270,287/96-13 and
50-269,270.287/96-15.
b. Observations and Findings
Following the heater drain line break in late September 1996. the
licensee had become more sensitive to water hammer issues.
Since that
date, approximately 30 PIPs have been generated to have engineering
evaluate water hammers that have been identified.
For example, these
water hammers have been identified in the main steam reheater drain
piping. steam separator reheater drain piping, main feedwater piping,
and auxiliary steam piping.
Engineering continues to evaluate and
monitor water hammers as they occur. No major problems have been
identified with water hammers to date.
c. Conclusions
The licensee initiated adequate measures to track and evaluate water
hammers in the various piping systems.
E2.2
Partial Discharge Testing of Electrical Power Cables (Keowee)
a. Insoection ScopeL375511.
The inspectors observed, reviewed, and discussed, with the licensee's
engineering personnel, the performance of a partial discharge test
(PDT).
The test was performed on the underground 1.3.8 kilo-volt (kV)
power cable feeds from the KHP to the transformer CT.
Enclosure 2
23
b. Observations and Findings
On August 5, 1997, licensee personnel and a vender representative
(vender-rep) performed a PDT on the six, two per phase. KHP underground
power cables. The cables are each rated at 10 kV phase-to-phase. 8 kV
phase-to ground, and operate at 13.8 kV phase-to-phase. The cables are
approximately 4000 feet long.
The test equipment used by the vendor-rep was especially fabricated for
the licensee. It consisted of a view screen, a computer, an operating
keyboard, and a floppy drive. The equipment also had calibration
devices.
The inspectors observed the determinating and terminating of the cables,
the hook up of the test leads, and the performance of the PDT by the
vender-rep. The inspectors observed that the activities were documented
in WO 96089265 and procedure IP/0/A/2000/01, Power and Control Cable
Inspection and Maintenance, Revision 4. The test set up contained a low
power/high voltage alternating current source, a high voltage interface
device, hookup wiring, and the special test equipment. The PDT on each
cable was performed at rated and at 110 percent of rated phase-to-ground
voltage.
The inspectors also observed and concluded from the reviews,
observation, and discussions the following:
0
the oversight of determinating and terminating of the power cables
and the identifying of the specific cables was performed by onsite
engineering personnel;
o
personnel from corporate and the McGuire Nuclear Station were at
the KHP observing the test and were briefed by the vender-rep and
engineering personnel;
the PDT was performed by the skill of the vendor-rep, with
assistance and oversight from engineering personnel;
0
information on how the test equipment functioned and how to
operate it was shared by the vendor-rep and site personnel:
o
the vender rep established a preset trigger level for detecting
partial discharges;
o
a step-by-step procedure for the operation of the test equipment
was not available;
o
however, view screen pictures. with explanations, showing various
aspects of the PDT were available; and
Enclosure 2
24
the maximum voltage applied during the test was set by engineering
personnel and was from 9.02 to 9.4 kV.
The inspectors were informed and observed that no partial discharges
were detected above the preset trigger level at rated voltage and at 110
percent of rated phase to ground voltage. The inspectors were also
informed that, based on the results of the PDT, the six cables were in
excellent condition.
c. Conclusions
The PDT of the Keowee Hydro Plant underground cable was under the
control of engineering personnel.
The activities were conducted in a
deliberate and professional manner. The test was performed without
difficulty.
E2.3 Pressure Seal Leak On Valve 2LP-1 (Unit 2)
a. Inspection Scooe (37551)
The inspectors observed, reviewed, and discussed with licensee
management. operations, maintenance, and engineering personnel the
corrective action plan for the pressure seal leak in valve 2LP-1.
The
leak is also discussed in section 01.3 of this report. The inspectors
also attended working level and management level meetings at which the
leak was discussed.
b. .Observations and Findings
The inspectors used NRC Part 9900 Technical Guidance, On-Line Leak
Sealing Guidance for ASME Code Class 1 and 2 Components, dated July 15.
1997, during the observations and reviews of the leak sealing
activities. Among the items reviewed were the following:
0
Temporary Modification (TM) 1376, Seal Leak Repa.ir on Valve 2LPI
1:
0
procedure TN/1/A/1376/TSM/00M, Installation of TSM-1376:
o
10 CFR 50.59. Unreviewed Safety Question Evaluation, for TSM-1376;
o
procedure PT/2/A/0152/12. Stroke Testing: and
a
maintenance WO 97076613-01.
The insorctors attended several meetings, with both management and
engineering, during which the valve was discussed.
The inspectors also
attended P ant Operating Review Committee (PORC)
meetings which also
Enclosure 2
25
discussed the leak. The inspectors observed during-the meetings and
reviews the following:
Managers, i ncluding senior managers. were actively involved in the
assessment, options, and evaluation of the leak;
o
engineering personnel stated that the injection would be made into
a void above the pressure seal ring of the valve, therefore, the
pressure boundary was not involved;
a
licensee personnel considered the valve as being operable and
would remain capable of performing the required safety function
throughout the sealing activity;
o
the injection would be performed with the primary system at 360 to
380 psig and at 260 to 300 degrees F;
o
following the expected successful injection, with the leak
stopped, the valve would be stroked to verify operability;
o
the cause of the leak was not specifically discussed
(historically, an :ngineering evaluation on this valve had existed
since the May 22. 1997 startup):
o
the valve fasteners were observed to be intact, by the use of
video tape, and they appeared to be covered by the boric acid and
water solution escaping from the leak:
o
engineering personnel stated that the small amount of sealant to
be injected, (20 cubic inches maximum), the number of holes
drilled (six maximum), the number of injections allowed (maximum
of two), and the location of the holes would not affect 1.e
structural integrity of the valve:
o
a plan was discussed which directed that should the seal fail
during the repair activity personnel were to evacuate the reactor
building as quickly as possible: and
o
engineering personnel stated that the valve would be disassembled,
inspected, and the seal ring would be replaced, possibly with a
new type, during the next refueling outage.
The inspectors were informed that the valve was a cast valve and
technical information only gave minimum thicknesses and not actual
thicknesses. The use of a physical drill stop would not apply under
these conditions. The method to be used was.that the holes would be
drilled slowly, by hand, and would be stooped as soon as pressurized
water was reached. The inspectors were also informed that if the leak
Enclosure 2
26
could not be stoyped the plant would be taken to cold shutdown and
defueled for rep acement of the pressure seal.
At the end of this report period Unit 2 was at the planned reoair
temperature and pressure. The sealing activity had not started..
c. Conclusions
An existing minor body to bonnet leak worsened on a Unit 2 LPI valve
that was unisolatable from the RCS.
The inspectors concluded that .the
expected leak repair activities: were discussed with appropriate
management involvement; had good engineering input; had appropriately
developed procedures; and had an aproved method for injecting approved
sealant with appropriate on-line sealing guidance for ASME C ass 1 and 2
components.
E3
Engineering Procedures and Documentation
E3.1
Degraded Voltage Relay As-Found Condition
a.
Inspection Scope (62707.
37551).
The inspectors observed the performance of WO 97027649-01, Change
Degraded Relay Setpoints.
b. Observations and Findings
This work order implemented MM ONOE-10264: 27YBDGX. Y. Z Degraded Grid
Relay Set Points, which changed the 230KV degraded grid undervoltage
relay setpoints by changing the calibration procedure.and then
reca :brating the relays using the revised procedure.
On August 18, 1997 technicians changed the setpoints on Degraded Grid
Undervoltage Relays 27YBDGX, 27YBDGY. and 27YBDGZ by recalibrating the
relays to the new setpoints specified in the modification. The
technicians used Procedure IP/0/A/4980/27G, IPE 27N Relay. Revision 5.
which had been revised to incorporate the new setpoints, to perform the
setpoint change.
When technicians measured as-found setpoint values for
the relays, the values were out-of-tolerance from those specified in the
procedure.
However, the technicians did not notify engineering of the
out-of-tolerance as-found condition because Procedure IP/0/A/4980/27G
contained a step permitting the option of not reporting an out-of
tolerance as-found condition if the condition resulted from a procedure
change. The revised procedure did not give any guidance as to whether
the relay was actually within the tolerance specified from the previous
calibration.
The inspectors discussed this with engineering personnel who stated
their expectations were for all out-of-tolerance conditions to be
Enclosure 2
27
reported to engineering who would then determine whether or not the
condition warranted further corrective action.
The inspectors also
reviewed several other relay calibration procedures and found all of
them to contain a step permitting the option of not reporting an if the
condition resulted from a procedure change. The licensee entered the
condition into their PIP 0-097-2796.
The circumstances surrounding this issue will be tracked as
URI 50-269.270.287/97-12-03, Relay As-Found Conditions, pending review
of: 1) the administrative requirements for documentation and evaluation
of as-found test conditions, and 2) the determination of the extent to
which the option of not reporting an out-of-tolerance as-found condition
existed.
c. Conclusions
During a degraded grid undervoltage relay setpoint change. workers did
not have as-found set points evaluated due to a potential procedure
problem. This was left as an unresolved test control issue until the
licensee completed a corrective action review.
The licensee understood
the nature of the problem and initiated appropriate corrective
evaluation.
E4
Engineering Staff Knowledge and Performance
E4.1
Management Activities
a. Insoection Scooe (37551. 40500)
During the period, the inspector observed manacement activities at the
site.
b. Observations and Findings
During this period, the licensee has initiated several new process
improvement efforts.
The inspectors have observed that engineering
operability evaluation progress, plant concerns, and action register
items have been added to the agendas of the three main plant meetings.
This has been formalized in trackable handouts that are actively
discussed at each of the meetings. The increased level of detail and
the focus that these provide is noteworthy.
The residents attended engineering daily review meetings that have
evaluated: the engineering work in progress to suDDort the plant; plant
deficiency closeout progress; and modification package pcogress. PIP
backlogs have been reduced and additional engineering support added.
Several plant management requested assessments have been accomplished
during tne past several months.
These have focused on understanding
Enclosure 2
28
plant interactions and problem areas.
The inspectors have attended
several of the exit meetings of these assessments and local management
has responded well to the negative findings particularly in the areas of
welding and post modification and maintenance testing controls.
Also,
the equipment mispositioning assessment has been on going with recent
recommendations delivered in PIP 97-2292. The licensee has a major
electrical reliability assessment to be completed by the end of the
year.
The Site Vice President has held several meetings to communicate clear
expectations. He has met with managers and has held a large plant staff
general meeting at a local auditorium to clearly discuss recent plant
problems and re-identification of expectations. The senior resident
attended a portion of the large general meeting and found the
presentation to be informative with the message well defined.
c.
Conclusions
Engineering and site management have recently instituted a new focus and
direction for the plant through process improvement efforts.
Preliminary output from the effort has been positive.
E4.2 Unit 1 Integrated Control System (ICS) Modification
a. Insoection Scope (37550)
The inspector reviewed the licensee's activities to incorporate lessons
learned from the Unit 3 ICS modification into the upcoming Unit 1 ICS
modification.
Applicable regulatory requirements included 10 CFR 50 Appendix B. Updated Final Safety Analysis Report (UFSAR). and American
National Standards Institute (ANSI) N45.2.11 - 1974, Quality Assurance
Requirements for the Design of Nuclear Power Plants.
b. Observattons and Findings
The licensee identified deficiencies during the Unit 3 ICS
post-modification.testing which were entered into the PIP process for
tracking and resolution. An ICS design feature which initiated
automatic feedwater valve control when the ooerator station was in
manual and a steam generator (SG)
low level limit was reached caused
operator confusion (PIP 3-97-0854).
This feature will remain in Unit 3
until the next Unit 3 outage. The design feature was deleted from the
Unit 1 design as demonstrated by revision DB to Unit 1 drawing 0.M.
201.H-0183.001. Feedwater Control, Loop A Valves and Low Level Limits.
Poor control at low power/low feed flow conditions due to the power/flow
error signal inconsistency at this condition was corrected by a square
root extractor function in the module code for Unit 3 (PIP 3-97-0858).
The Unit 1 design was changed to use the level transmitter in the linear
mode which provided a more reliable power/flow error signal.
Enclosure 2
29
Inadvertent shift of the ICS component STAR modules to hand (manual)
mode was noted (PIP 3-97-1015).
The cause was determined to be a
characteristic of the module self-checking circuit which was corrected
by requiring three points per self-check rather than one.
This
modification was being programmed into the individual STAR modules. The
program code correction implemented to resolve feedwater
valve cycling at ten to fifteen percent power resulted in the
inadvertent deletion or overwrite of required program code functions
(PIP 3-97-0910).
The corrective action added barriers to the process
for ICS program code revisions.
c. Conclusion
The licensee implemented appropriate measures to incorporate lessons
learned from the Unit 3 ICS modification into the Unit 1 modification.
Design and operational deficiencies identified in the Unit 3
modification were adequately addressed for Unit 3 and addressed in the
Unit 1 design and modification implementation procedure changes.
E4.3 Expandino Engineerin. Knowledoe Base
a. Insoection Scope (71707.-37551
During the course of this period; inspectors observed engineering
personnel in the control room and in the plant making rounds with the
non-licensed operators (NLO).
b.
Observations and Findings
Engineering management provided direction that their staff become more
operationally focused. Part of this philosophy was direction for system
engineers to perform monthly walkdowns of systems and to accompany a
non-licensed operator on rounds. The inspectors observed this being
implemented in several instances.
Site engineers were observed to be in the Unit 1 and 2 common control
room at the operations morning briefing. The operations Onshift Manager
indicated-that these engineers would be going with the NLO on their
plant rounds and should be provided any support and information that
they requested.
c. Conclusions
Engineering management has instituted a practice of monthly system
engineer tours with non-licensed operators.
Enclosure 2
30
E8
Miscellaneous Engineering Issues (92903)
E8.1
(Discussed - ODen) Deviation (DEV) 50-269.270.287/94-24-04: Design Basis
Requirements for the Penetration Room Ventilation System (PRVS)
IR 50-269,270.287/94-24 discussed the issue of leakage from the PRVS.
Testing in 1992 had revealed that the PRVS ability to maintain a
negative pressure was affected by auxiliary building air handling
unit/fan combinations. The licensing basis assumes all leakage into the
penetration room will be filtered prior to release. There is no
provision for any leakage to bypass the PRVS via leakage into the
auxiliary building. The only method to ensure all leakage into the
penetration room gets filtered is to have the penetration room airtight
or at a negative pressure with respect to its surroundings (i.e. both
the atmos here and the auxiliary building) during an accident. The
licensee has completed extensive testing and sealing of identified leak
paths from the penetration room to other surrounding rooms.
The licensee has decided to pursue a licensing approach by uodating the
current off-site dose calculations to presently accepted methodology.
This will allow the deletion of the PRVS from TS.
Implementation of the
TS and UFSAR changes have been assigned due dates of December 31. 1997
and July 5, 1998. respectively.
E8.2 Li.ussed - Op en) IFI 50-29.270.287/95-03-01: Clarification of TS 3.3.1
This item addressed HPI operability requirements below 60 percent power.
In November 1990 with their then existing engineering analysis, the
licensee identified that below 60 percent power an injection line nozzle
break could result in insufficient flow to the reactor core assuming a
single failure if only two HPI pumps were operable.
The licensee 'has
committed to revise TS 3.3.1. The revision was submitted to NRC on
March 31. 1997. Due to events involving the HPI pumps in April of 1997,
the licensee has committed to conduct an HPI reliability study. This
study is due to be submitted to the NRC on December 31. 1997. The TS
revision will be completely processed following the review of the
reliability study; segments of the revision may be completed earlier,
based on a September 4. 1997, licensee docketed request.
E8.3
(Closed) ADarent Violation (EEI
50-269.270.287/96-03-02 (EA 96-090):
Inoperability of Containment Hydrogen Control Systems
This item addressed a lack of drainage for condensate that could block
flow during operation of the hydrogen recombiner.
This issue was closed
by letter dated April 16,
1996. granting enforcement discretion.
Enclosure 2
31
E8.4 (Closed) LER 50-270/95-02: Incorrect Timer Setting Due to a Design
Deficiency Results in a Reactor Trip
The reactor trip of Unit 2 was discussed in IR 50-269,270.287/95-06.
The LER stated that modifications would be installed in each unit to
change the timer set points for the loss of excitation relays. The
inspectors observed that minor modifications ON0E 8045, 8051. and 8085
were installed on Units 1. 2. and 3. respectively, which changed the set
points.
The set points were raised from 0.8 to 30 seconds. The LER
also stated that a review would be performed so that other protective
relay timers would be set as required. The review was completed and
processes are in place, such as procedure changes and minor
modifications, to ensure that both safety related and non-safety related
relays have.adjustment information. Based on the licensee's actions
this LER is closed.
E8.5 (Closed) VIO 50-287/97-02-06: Inadequate Control of Purchased Material
and Equipment
This item addressed inadequate procurement control activities which
contributed to the receipt and installation of a safety related eight
inch ball valve (LP-40) which did not meet the Duke Power specification
referenced in the purchase order. The incorrect reverse acting valve
contributed to a loss of RCS shutdown inventory on February 1. 1997.
Additional issues associated with this item included an operation's poor
practice for manual valve position verification and maintenanceIs poor
communication of the abnormal equipment configuration represented by the
reverse acting valve.
The licensee's response to the violation, dated July 2. 1997, specified
corrective actions to address performance deficiencies by the
procurement, operations, and maintenance organizations. The inspector
reviewed a licensee vendor follow up audit, operations and maintenance
procedure revisions, and training documentation which documented
completion of the corrective actions stated in the licensee's response.
The inspector concluded that the procurement, operations. and
maintenance performance deficiencies which contributed to the
installation of the incorrect safety related valve (LP-40) were
adequately resolved.
E8.6 (Closed) VIO 50-269.270.287/97-02-08: Inadequate Corrective Action and
Design Control for Reactor Building Cooling Unit (RBCU)
Fuses
This item addressed the licensee's inadequate corrective action to
resolve an identified incorrect fuse installation in the RBCUs.
The
corrective action did not adequately evaluate the equipment design to
determine the appropriate fuse size and type for the application.
Additionally, the corrective action did not identify the operability
Enclosure 2
32
significance of the issue and did not properly categorize the associated
PIP.
The licensee response to the violation dated July 2, 1997. specified
corrective actions to include a root cause analysis, minor modifications
to install the correct fuses, PIP program improvements in screening PIPs
for significance, and clarified responsibilities for fuse selection.
The root cause analysis was documented in PIP 0-097-1109, dated April 1,
1997. The minor modification to replace the fuses were completed in
January. 1997. The PIP screening process was revised in late 1996.
which was after the inappropriate categorization of the original RBCU
fuse issue PIP. The inspector concluded this item was adequately
resolved.
E8.7
Closed) IFI 50-269.270.287/95-14-01: Qualification Extension of Keowee
Batteries
This item was initiated to follow up on the licensee's qualification
extension of the Keowee batteries from ten to twenty years. The initial
qualification extension report reviewed by the inspector in 1995
indicated that several battery cells did not meet the electrical
capacity requirement following the seismic test. The test report did
not address the failed cells and therefore the qualification was not
conclusive. The licensee subsequently contracted with a vender, Nuclear
Logistics Incorporated (NLI), to evaluate the battery for qualification
extension. The qualification was documented in Keowee Battery
Qualification Calculation, C-017-050-1. dated August 22, 1996.
Calculation C-017-050-01 based the ten-year qualification extension on
two separate tests conducted at Wyle laboratories on similar batteries.
The seismic test which verified the structural/mechanical properties was
documented in Wyle test report 44681-2 dated February 1. 1981.
This
test was performed on a similar but heavier battery which was
conservative for the Keowee battery application. The battery was
artificially aged.which resulted in loss of cell electrolyte but did not
impact the results of the structural/mechanical properties.
Wyle test report No. 45110-1. dated March 21, 1996,
for NLI verified the
electrical properties of the battery for extension by testing a similar
battery which had been naturally aged for 24 years. As in the previous
test, the battery was subjected to seismic vibration conditions which
enveloped the seismic test response spectra for the Keowee batteries.
Electrical testing after the vibration test verified the batteries.
exceeded the 80 percent capacity required to establish qualification.
The conclusion of qualification calculation C-017-050-01 was that the
Keowee batteries were qualified for a total of 20 years, which included
the 10-year extension.
The inspector concluded the qualification
extension was appropriately supported by testing and analysis.
Enclosure 2
33
E8.8 (Discussed-Ooen) IFI 50-269.270.287/96-03-04: Installation of New Ground
Detection System
This item addressed the licensee's planned actions to improve their
limited capability to detect vital direct current (DC) system grounds.
A 1995 study of the issue recommended several actions to improve the
capability to detect grounds. The study established a 500 ohm.critical
value for grounds which impact safety related equipment. The present
setpoint for the ground detection system is 1500 ohms which would
provide detection before impact on safety related equipment.
The study
indicated that balance of plant equipment could be impacted by less
significant grounds, i.e., those greater than 1500 ohms and not
detectable by the present ground detection system. This impact could.
result in plant transients which could eventually challenge the plant
safety systems. The modification to install the more sensitive qround
equipment, although tentatively planned, is not currently scheduled or
developed. Due to the importance of the new ground detection system
this item remains open to track implementation of this modification.
E8.9
(Closed) Deviation 50-269.270.287/95-09-03: Fatigue Analysis for RCS
Auxiliary Piping
This item addressed the fact that RCS auxiliary piping had not been
inspected. designed, and tested as Class I piping in accordance with
USAS B31.7, Code for Pressure Piping, Nuclear Power Piping, dated
February, 1968, as stated in the UFSAR. The piping had been designed,
tested and inspected as Class II piping.
The licensee's response to the
deviation dated July 21.
1995, stated that a fatigue analysis of the RCS
auxiliary piping would be performed to establish that the Class I Code
requirements were met. It further stated that a schedule for the Diping
analysis would be developed by March 1, 1996 and all analysis would be
completed by August 31. 1999. Additionally, the UFSAR would be updated
to reflect the as-built condition until the fatigue analysis was
complete.d.
The inspector reviewed the RCS auxiliary piping fatigue analysis
schedule which was provided to the NRC by a Duke Power lettor dated,
February 22, 1996, and verified the scheduled commitments were being met
up to the date of this inspection. These included awarding a vendor
contract to perform the analysis and development of the applicable
specifications.
The UFSAR amendment dated December 31. 1996, stated the
Class I piping analysis would be completed on August 31. 1999. Based on
completed and scheduled corrective actions, the inspector concluded this
item was adequately being addressed and tracked.
Enclosure 2
34
IV. Plant Su port Areas
R4
Staff Knowledge and Performance in Radiological Protection and Control
(RP&C)
R4.1 Test Technicians Radioloical Practices
a. Inspection Scope (71750)
The inspectors observed the radiological practices of test technicians
performing testing on the Unit 3 HPI System.
b. Observations and Findings
On August 27. 1997 during performance of PT/3/A/0202/11, HPI System
Performance Test, technicians made pump pressure readings inside a
contaminated area and communicated with the control room via a phone
outside the contaminated area.
As protective clothing the technicians
wore cotton liners and rubber gloves on their hands with cloth booties.
and rubber covers on their shoes. Both technicians made readings and
talked with the control room. When crossing the contaminated area
boundary, the inspectors observed each technician remove shoe covers and
rubber gloves, leave them inside the contaminated area boundary, and
exit the area wearing the cloth booties and cotton gloves.
Upon re
entry, the technicians put on the same rubber gloves and shoe covers
that had been removed earlier.
This practice occurred more than once
while the inspectors were watching.
When questioned, the test technicians indicated that they felt the
practice to be acceptable based on their past experience, however.
licensee radiological personnel indicated this was not an acceptable
practice without the direcL assistance of radiation protection
personnel.
No radiation protection personnel were present at the job
and radiQlogical personnel only provided general procedural guidance on
the use of the practice.
The licensee has established a System Radiation Protection Manual in
order to meet the requirements of 10 CFR Part 20 and the technical
specifications.
The inspectors reviewed Procedure 1-13. Use of
Protective Clothing and Related Equipment. Revision 2 from this manual.
Step 5.3 of this procedure described the process for removing protective
clothing and instructed users to "Remove booties as you transfer to the
step-off pad which is considered clean."
The inspectors determined that
test technicians failed to follow Procedure 1-13 when removing
protective clothing while performing the HPI System Performance Test on
August 27. 1997 and this constituted a violation of 1OCFR Part
20.1101(a).
This will be identified as Violation 50-287/97-12-05,
Failure to Remove Protective Clothing.
Enclosure 2
c. Conclusions
The inspectors identified a violation for test personnel exiting a
contLami nated area without properly removing protective clothing.
P1
Conduct of EP Activities
P1.1
Emeroency Planning Drill
a. Insoection Scooe (71750)
The inspectors observed portions of the emergency drill conducted August
26. 199
b. Observations and Findinas
During the scenario, the plant experienced a simulated earthquake with a
magnitude of greater than 0.05g. The procedure for damage assessment
required an examination of the tendon gallery in order to confirm the
earthquake magnitude and directed the plant be taken to cold shutdown if
the magnitude was greater than 0.05g. Personnel in the simulated
control room challenged the Technical Support Center (TSC) on the length
of time taken to assess the earthquake magnitude with the plant in'
hot
shutdown conditions. Control room personnel also challenged the TSC on
the decision to remain in hot shutdown with water present in the LPI
pump rooms. Control room personnel felt the plant should be taken to
cold shutdown before conditions in the LPI rooms degraded any further.
The decision to remain in hot shutdown later proved to be correct.
however, the challenges by control room Dersonnel showed a good
questioning attitude. Control room personnel also used three-way
communications extensively during the scenario, particularly when
performing emergency operating procedures.
c. Conclusions
During an August emergency plan drill, control room personnel showed a
good questioning attitude and properly used three-way communications.
S1
Conduct of Security and Safeguards Activities
S1.1 Comoensatory Measures
a. Inspection Scone (81700)
The inspector evaluated the licensee's program for compensatory measures
of security equipment that was not functioning as committed to in the
Physical Security Plan (PSP) and procedures. This was to ensure that
the implemented measures were equal or better that the commitments made
by the licensee.
Enclosure 2
36
b. Observations and Findings
The three compensatory measures operational during this inspection were
reviewed. These measures compensated for inoperable equipment and
consisted of the application of specific procedures to assure that the
effectiveness of the security system was not reduced.
c. Conclusions
Through observations, interviews. and documentation review, the
inspector concluded that the licensee used compensatory measures that
ensured the reliability of security related equipment and devices. This
evaluation verified that the licensee employed compensatory measures
when security equipment fails or its performance was impaired. The
inspector found no violations of regulatory requirements in this area.
S2
Status of Security Facilities and Equipment
S2.1 Vital Area Access Controls
a. Inspection Scope (81700)
The inspector evaluated the licensee's program to control access of
packages, personnel, and vehicles to the vital areas according to
criteria in the PSP.
b. Observations and Findings
The inspector's review was to ensure that the licensee provided
appropriate access controls for the vital areas.
Personnel, hand-carried packages or material, delivered packages or
material, and vehicles were searched before being admitted to the
protected area and, subsequently, the vital areas. Security personnel
searched for firearms, explosives, incendiary devices, and other items
that could be used for radiological sabotage. These searches were
either by physical search or by search equipment. Security personnel
searched certain delivered packages and materials, approved by NRC and
specifically designated by the licensee, within vital or protected
areas. This was for reasons of safety, security, or operational
necessity. Vehicle searches included'a search of the cab, engine
compartment. undercarriage, and cargo areas.
The inspector found the following circumstances concerning personnel
access control. A picture badge identificat.ion system was used for
personnel who were authorized unescorted access to protected and vital
areas. A coded, numbered badge system was used for personnel authorized
unescorted access to vital areas. The code corresponded to vital areas
to which individuals authorized access. Picture badges issued to non
Enclosure 2
37
licensee personnel indicated areas and periods of authorized access
information magnetically encoded and showed that no escort was required.
Personnel displayed their badges while within the vital area, and
returned them upon leaving the protected area. Visitors authorized
escorted access to the protected area were issued a badge that showed an
escort was required, and were escorted by licensee-designated escorts
while in the vital area.
Unescorted access to vital areas was limited
to personnel who required such access to do their duties. Security
personnel controlled access to the reactor containment when frequent
access was necessary to assure that only authorized personnel and
material entered the reactor containment.
Access control program records were available for review and contained
sufficient information for identification of persons authorized access
to the vital areas.
The licensee maintained access records of keys, key
cards, key codes, combinations, and other.related equipment during a
person's employment or for the duration of use of these items.
The inspector found the following circumstances concerning control of
the entry and exit of packages and material to the vital area. Security
personnel confirmed the authorization of, and identified packages and
material at access control portals before allowing them to be delivered.
The licensee used security force personhel to identify and confirm the
authorization of material before allowing it to enter reactor
containment.
The inspector found the following circumstances concerning vehicle
access control.
Individuals who controlled the admittance control
hardware that allowed vehicle access to vital areas were armed, within
the vital area, or had control of the keys that open the vital area.
Security force personnel escorted non-designated vehicles while within
the protected and vital area.. No vehicle entered licensees' vital areas
during this inspection.
c. Conclusions
This evaluation of the vital area access controls for packages,
personnel and vehicles revealed that the criteria of tie PSP were
carried out. The inspector identified no violations of regulatory
requirements in this area.
S4
Security and Safeguards Staff Knowledge and Performance
S4.2 Control of Safeguards Information
a. Insoection Scone (81810)
The inspector reviewed PIP 4-097-2397 concerning an electrical systems
engineer's (ESE) Safeguards container that had not been properly
Enclosure 2
38
secured. This review was to determine whether Safeguards Information
(SGI), as defined in 10 CFR 73.21. Nuclear Systems Directive 206.
"Safeguards and Information Controls." Rev. 5. dated June 16. 1997, and
Security Guideline - 17. "Safeguards Workplace Procedures." dated August
7. 1997, had been disclosed or compromised.
b. Observations and Findings
The licensee's investigation revealed the following:
o
Between the hours of 5:37 p.m., August 4, 1997 and 5:52 a.m.
August 5. 1997 a drawer of an ESE safeguard container was left
unsecured in the Engineering Safeguards Work Area (ESWA).
The safeguard's container was within the protected area.
o
The ESWA was monitored by an alarm system.
The main entrance door
was controlled by an electrical keypad lock.
The second door was
locked from inside. Review of the annunciator records/logs showed
that no entries into the ESWA during the above time were made.
o
All documents within the container were accounted for based upon a
review of container contents against the containerinventory
listing.
The immediate corrective action was the securing of the container and
it's content. Intermediate and long term corrective actions were as
follows:
0
Corrective action concerning the individual who left the container
unsecured had not been completed during this inspection.
Counseling was recommended in the PIP.
A final barrier was added at the egress point from the ESWA to
remind personnel to self-check the security of the ESWA.
Additional signage was added to remind personnel of the need to
self-check the area.
o
All site "Routine Users" of SGI were made aware of the incident to
enhance their security awareness.
o
All site "Routine Users" of SGI were reminded of the importance of
using self-checking processes to ensure compliance with the SGI
control program.
Security Guideline -18, states, "SGI not being utilized, must be secured
in
designated containers.'
This non-repetitive. non- willful, licensee
identified, and corrected violation is being treated as a Non-Cited
Enclosure-2
39
Violation, consistent with Section VII.B.1 of the NRC Enforcement
Policy. NCV 50-269,270.287/97-12-06. Failure to Secure a Safeguard
Container That Stored Safeguards Information.
c. Conclusions
This incident of failure to secure safeguards information was a licensee
identified, non-repetitive, corrected, non-willful event. Consequently,
a Non-Cited Violation was issued.
Security Safeguards Staff Training and Qualification
S5.1 Security Training and Oualification
a. Insoection Scope (81700)
The inspector interviewed security personnel and reviewed security
personnel training and qualification records to ensure that the criteria
in the Security Personnel Training and Qualification Plan (T&QP) were
b. Observations and Findings
The inspector interviewed ten security non-supervisor personnel, three
supervisors, and witnessed approximately 14 other security personnel in
the erformance of their duties. Members of the security force were
know edgeable in their responsibilities, plan commitments and
procedures. Sixteen randomly selected training records were reviewed by
the inspector concerning training, firearms. testing, job/task
performance and requalification.
The inspector found that armed response personnel had been instructed in
the use of deadly force as required by 10 CFR Part 73. Members of the
securityorganization were requalified at least every twelve months in
the performance of their assigned tasks, both normal and contingency.
This included the conduct of physical exercise requirements and the
completion of the firearms' course. Through the records review and
interviews with security force personnel, the inspector found that the
requirements of 10 CFR 73, Appendix B. Section 1.F. concerning
suitability, physical and mental qualification data, test results, and
other proficiency requirements were met.
c. Conclusions
The security force was being trained according to the T&QP and
regulatory requirements. There were no violations of regulatory
requirements identified in this area.
Enclosure 2
40
S8
Miscellaneous Security and Safeguards Issues
S8.1
Protected Area Access Control
a. Inspection SCODe (71750)
The inspector evaluated the licenseeIs program to control access of
terminated personnel according to criteria in Chapter .6 of the PSP and
appropriate directives and procedures.
b. Observation and Findings
This was to ensure that the licensee had positive access controls of
personnel entering and exiting the protected area.
During a review of
entries in the Safeguards Event Log. the inspector noted two events of
orotected area badges of favorably terminated personnel that had not
been deactivated in a timely manner.
These two events involved two
employees, with no instances of gaining access to the protected area
after they were terminated from employment and unauthorized to access
the protected area. The two events were caused by contractor/vendor
management failing to notify security within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after favorable
termination. Dates of the events were both on January 9, 1997.
The
corrective actions were prompt, comprehensive and effective to prevent
recurrence. The licensee's analysis and corrective actions of the two
events were documented in PIP 0-97-0136. The cause of the events was
human error, not programmatic. These events were violating Nuclear
Policy Manual-Volume 2. Nuclear System Directive 218. "Notification
Responsibilities for Termination." paragraph B.1, Rev. 0. dated June 27.
1996 that states in effect that for voluntary and involuntary
termination, that management shall.be responsible for verbally notifying
site security to delete the terminated individuals badge.
Because the events were licensee identified, effective in corrective
action, con-repetitive. non-willful, and not a programmatic issue, the
violation is being treated as a Non-Ci.ted Violation, consistent with
Section VII.B.1 of the NRC Enforcement Policy, NCV 50-269.270.287/97
12-07, Failure to Notify Security of Terminated Employees.
c. Conclusion
Two incidences of failure to notify security of the termination of
personnel were licensee identified, non-repetitive, corrected, non
willful events. Consequently, a Non-Cited Violation was issued.
Enclosure 2
41
F1
Control of Fire Protection Activities
F1.1 Fire Drill
a. InSDection Scooe (71750. 92904)
The inspectors observed a fire drill on August 15.
b. Observations and Findings
The area selected for the drill was the maintenance support building
located next to the turbine building. Among the items observed were:
- 0
Fire Brigade (FB) personnel responded to the assembly area dressed
out in appropriate fire gear;
a
the FB leader exercised good command and control;
o
FB personnel were aware of the location of additional self
contained breathing apparatus oxygen bottles:
0
control room personnel provided overall direction during the drill
and entered tne applicable emergency classification:
0
the controllers gave clear and precise information to the FB
leader and personnel regarding the simulated fire, this included
colored photographs: and
a post-fire drill briefing was conducted.
One noteworthy licensee identified drill deficiency was identified.
A
person left in the area by the controllers was not found when the Fire
rigade leader directed that a search of the area be made.
A minor
deficiency was identified in the area of communications which involved
fire fighting team identification.
Both of these items were discussed
at the post-drill briefing.
c.
Conclusions
The inspectors concluded that the method employed for attacking the fire
was appropriate, the drill scenario was good. fire brigade personnel
exercised good fire fighting techniques. and the post-fire drill
briefing was effective.
Enclosure 2
42
V. Management Meetings
X1
Exit Meeting Summary
The inspectdrs presented the inspection results to members of licensee
management at the conclusion of the inspection on September 10. 1997.
The licensee acknowledged the findings presented.
X2
Escalated Enforcement Results
On July 23, 1997, a Predecisional Enforcement Conference for EA Case
Nos.97-297 and 97.298. covered in Inspection Reports. 97-07 and 97-08,
respectively, was
eld in the Regional Office with the Licensee in
attendance. The following apparent violations (EEls) were discussed:
EFI 50-269.270.287/97-07-01
EEI 50-269,270.287/97-07-02
EEI 50-287/97-08-01
EELI 50-287/97-08-02
FEI 50-269.270,287/97-08-03
EE1 50-269.270.287/97-08-04
EEI 50-287/97-08-05
Following the conference,, a Notice of Violation (NOV)
was issued on
August 27, 1997.
Based on the NOV issued, the above EEls are closed and
the violations identified in the above Notice of Violation will be
tracked as:
Failure to Adhere to Technical
Specification Requirements for the Unit 3
High Pressure Injection System
Failure to Establish Measures to Assure
Cracks in High Pressure Injection Safe End
Nozzles Are Promptly Identified and
Correc ted
Failure to Take Corrective Action for
Temperature Differentials in the Safety
Related High Pressure Injection Makeup
Piping
Failure to Follow Operations Procedures
During the Unit 3 Cooldown on May 3. 1997
Failure to Follow Operations Procedures
Relating to Low Temperature Overpressure
Protection Recuirements
Enclosure 2
43
Failure to Follow Maintenance Procedures
for the Installation of Tubing Caps
Failure to Assure Design Configuration
Control was Maintained for Letdown Storage
Tank Level Instrumentation Valves
Partial List of Persons Contacted
Licensee
E. Burchfield, Regulatory Comoliance Manager
T. Coutu, Operations Support Ianager
D. Coyle, Systems Engineering Manager
T. Curtis, Operations Superintendent
J. Davis, Engineering Manager
B. Dobson, Systems Engineering Manager
W. Foster. Safety Assurance Manager
J. Ham pton. Vice President, Oconee Site
D. Hubbard. Maintenance Superintendent
C. Little, Electrical Systems/Equipment Manager
B. Peele, Station Manager
J. Smith. Regulatory Compliance
NRC
D. LaBarge, Project Manager
Inspection Procedures Used
Engineering
Onsite Engineering
Installation and Testing of Modifications
Effectiveness of Licensee Controls In Identifying and Preventing
Probl ems
Prepartion for Pefueling
Surveillance Observations
Maintenance Observations
Plant Operations
Plant Support Activities
Physical Security Program For Power Reactors
Protection of Safeguards Information
OnsiteFollovup of Written Event Reports
Followup - Plant Operations
Followup - Maintenance
Followup - Engineering
Followup-Plant Support
1P93702
Prompt Onsite Response to Events
Enclosure 2
44
Items Opened, Closed, and Discussed
Ocened
50-269,287/97-12-01
MOV Design Deficiency Implementation
(Section 08.3)
50-269,270,287/97-12-02
Fuel Load UFSAR Statements (Section E1.1)
50-269,270.287/97-12-03
Relay As-Found Conditions (Section E3.1)
50-269,270,287/97-12-04
IFI
Maintenance Oversight (Section M3.2)
50-287/97-12-05
Failure to Remove Protective Clothing
(Section R4.1)
50-269,270.287/97-12-06
Failure to Secure a Safeguard Container
That Stored Safeguards Information
(Section S4.2)
50-269,270,287/97-12-07
Failure to Notify Security of Terminated
Employees (Section S8.1)
50-287/97-12-08
Failure to Follow Valve Packing Porcedure
(Section M8.1)
EA 97-298-01012
Failure to Adhere to Technical
Specification Requirements for the Unit 3
High Pressure Injection System (Section
X2)
EA 97-297-02023
Failure to Take Corrective Action for
Temnerature Differentials in Safety
Related High Pressure Injection Makeup
Piping (Section X2)
EA 97-297-02013
Failure to Establish Measures to Assure
Cracks In High Pressure Injection Safe End
Nozzles Are Promptly Identified and
Corrected (Section X2)
EA 97-298-03014
Failure to Follow Operations Procedures
During the Unit 3 Cooldown on May 3, 1997
(Section X2)
EA 97-298-04014
Failure to Follow Operations Procedures
Relating to Low Temperature Overpressure
Protection Requirements (Section X2)
Enclosure 2
45
.
EA 97-298-05014
VIG
Failure to Follow Maintenance Procedures
for the Installation of Tubing Caps
(Section X2)
EA 97-298-06014
Failure to Assure Design Configuration
Control was Maintained for Letdown Storage
Tank Level Instrumentation Valves (Section
X2)
Closed
50-287/97-08-01
EEl
Failure to Adhere to Technical
Spec ificat ion Operability Requirements for
the HPI System on Unit 3 (Section X2)
50-287/97-08-02
Failure to Follow Operations Procedures
During the Unit 3 Cooldown and/or Event
Response on May 3. 1997 (Section X2)
50-269,270,287/97-08-03
EEl
Failure to Take Adequate Corrective
Actions for Conditions Adverse to Quality.
(Section X2)
50-269,270,287/97-08-04
EEl
Failure to Provide Adequate Design Control
Measures for, the Letdown Storage Tank,
Level and Pressure Instrumentation
0
(Section X2)
50-287/97-08-05
Failure to Make a Report Within the Time
Required by 10 CFR 50.72 (b) (Section X2)
50-269.270,287/95-27-01
VID
Inadequate Procedures Two Examples
(Section 08.1)
50-269,270.287/96-20-01
SSF Past Operability (Section 08.2)
50-269/95-08. Revision 0
LER
Containment Isolation Valve Inoperable Due
to Deficient Design Cond-tion (Section
08.3)
50-269/95-08, Revision 1
LER
Containment Isolation Valve Ino erable Due
to Deficient Design Condition (ection
08.3)
50-287/95-01
LER
Packing Leak Due to Inappropriate Action
Results in.Unit Shutdown (Section M8.1)
Enclosure 2
46
50-287/95-02
LER
Drop of Control Rod Group Due to Unknown
Caus -e Result-LS in Reactor Trip (Section
M8.2)
50-269,270,287/96-17-04
Engineering Evaluation for the Replacement
of Carbon With Stainless Steel Piping
(Section M8.4)
50-269,.270,287/93-20-01
IFI
Instrument Impulse Lines and Associated
ISI Requirements (Section M8.6)
50-269/96-04-04
Root Cause Assessment of Failures to
Valves 1MS-77 and iLPSW-254 (Section M8.7)
50-269,270,287/96-03-02
El
Inoperability of Containment Hydrogen
Control Systems (Section E8.3)
50-270/95-02
LER
incorrect Timer Setting Due to a Design
Deficiency Results in a Reactor Trip
(Section E8.4)
50-287/97-02-06
VID
inadequate Control of Purchased Material
and Equipment (Section E8.5)
50-269,270,287/97-02-08
VID
Inadequate Corrective Action and Design
Control for Reactor Building Cooling Unit
Fuses (Section E8.6)
50-269,270.287/95-14-01
iFI
Qualification Extension of Keowee
Batteries (Section E8.7)
50-269,270,287/95-09-03
DEV
Fatigue Analysis for RCS Auxiliary Piping
(Section E8.9)
50-269,270,287/97-07-01
EEl
Inadequate Implementation of Augmented
inspections (Section X2)
50-269.270,287/97-07-02
Inadequately Addressed Thermal
Strati fication (Section X2)
Discussed
50-269,270,287/96-05-01
V/1
Failure to Make Proper 10 CFR 50.72
Notification (Section 08.4)
50-269U270,287/96-10-03
Weld Procedure Qualifications Welded.
Tested, Certified and Approved b Same
Individl
(Section M8.3)
Enclosure 2
47
50-269.270,287/96-17-09
LPSW Modification Did Not Meet ASME Code
Section XI Non-Destructive Examination
Requirements (Section M8.5)
50-269,270,287/94-24-04
DEV
Design Basis Requirements for the
Penetration Room Ventilation System
(Section E8.1)
50-269,270,287/95-03-01
IFI
Clarification of TS 3.3.1 (Section E8.2)
50-269,270.287/96-03-04
IFI
Installation of New Ground Detection
System (Section E8.8)
List of Acronyms
Office of Analysis and Evaluation of Operational Data
Augmented Inspection Team
ANSI
American National Standard
Americab Society of Mechanical Engineers
BWST
Borated Water Storage Tank
CFR
Code of Federal Regulations
Condenser Circulating Water
Direct Current
EE I
Apparent Violation
ESWA
Engineering Safe uards Work Area
ETQS
Training and Quaiication Guide
Engineered Safeguards
F
Fahrenheit
GPM
Gallons Per Minute
High Pressure Injection
Integrated Control System
I&E
Instrument & Electrical
IFIInspector
Report
IRInspection Repor
Inservice Inspection
KHP
Keowee Hydro (electric) Plant
KV
KiloVolt
LDST
Letdown Storage Tank
LER
Licensee Event Report
LCO
Limiting Condition for Operation
Low Pressure Injection
Low Pressure Service Water
MM
Minor Modification
Motor Operated Valve
Non-Cited Violation
Non-Licensed Operator
NRC
Nuclear Regulatory Commission
Enclosure 2
0NSM
Nuclear Stati on Mdfcto
NSD
Nuclear System Directive
Oconee Nuclear Station
Public Document Room
PDT
Partial Discharge Test
Problem Investigation Process
Post Maintenance/Modification Testino
'PORC
Plant Operating Review Committee
PRVS
Penetration Room Ventilation System
Pounds Per Square Inch Gauge
Physical Security Plan
Performance Test
Quality Assurance
QIT
Quality improvement Team
Reactor Building
RBCU
Reactor Building Cooling Unit
REV
Revision
Spent Fuel Pool
Safeguards Information
SSF
Safe Shutdown Facility
TM
Training and Qyalification Program
TS
Technical Specification
Technical SuUSort Center
0
Updated FinalV Safety Analysis Report
Unresolved Item
VI
Violation
MO
Work Order
Enclosure 2