ML20203D742
| ML20203D742 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 11/26/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20203D715 | List: |
| References | |
| 50-334-97-08, 50-334-97-8, 50-412-97-08, 50-412-97-8, NUDOCS 9712160278 | |
| Download: ML20203D742 (36) | |
See also: IR 05000334/1997008
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U. S. NUCLEAR REGULATORY COMMISSION
~ REGION I
e
. License' Nos. DPR 66,' NPF-73
Report Nos. 50-334/97-08, 50-412/97-08'
Docket Nos. 50-334, 50-412
Licensee: Duquesne Light Company-(DLC)_ ,
Post Office Box 4 :
Shippingport, PA 15077
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i- Facility: - _
Beaver Valley Power Station, Units 1 and 2
Inspection Period: October 5,1997 through November 15,1997
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' inspectors: D. Kern, Senior Resident inspector -
F. Lyon, Resident inspector
G. Dentel, Resident inspector
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J. Furia, Senior Radiation Specialist, DRS
L. Eckert, Radiation Specialist, DRS
S. Chaudhary, Senior Reactor Engineer, DRS
Approved by: P. Eselgroth, Chief
Reactor Projects Branch 7
9712160278 971126
PDR- ADOCK 05000334
R PDR
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EXECUTIVE SUMMARY
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Beaver Valley Power Station, Units 1 & 2
NRC Inspection Report 50-334/97-08 & 50 412/97-08
This integrated inspection included aspects of licensee operations, engineering,
maintenance, and plant support. The report covers a 6-week period of resident inspection;
in addition, it includes the results of announced inspections by regional inspectors in the
areas of radiation protection, rt riioactive effluent control, and inservice inspection.
Operations
- Rod cluster control assembly (RCCA) R-19 was mispositioned during insert change-
outs due to inadecuate position verification by contractor personnel and inadequate
supervisory oversight of the evolution by DLC staff, inspectors assessed that the
licensee root cause analysis for the RCCA mispositioning was thorough and that
DLC took reasonable corrective actions to prevent recurrence. (Section 01.2)
- Tagging the Unit 1 containment iodine fans and the steam generator blowdown tank
out-of-service, even though the equipment was required in some emergency
response procedures, was an isolated instance due to inadequate review and
implementation of the Retired Equipment Program. (Section O3.1)
- Operators demonstrated a strong questioning attitude in identifying a longstanding
discrepancy in the auxiliary feedwater surveillance test. (Section 04.1)
- Operators' failure to question the acceptability of charging pump gas accumulation-
data and lack of system engineering guidance was a weakness. (Section 04.1)
- Operator response to a fuel filter leak during emergency diesel generator (EDG)
testing was conservative, and operator response in the control room to the loss of
the EDG was appropriate, inspectors noted good control of event response by
control room supervisors. (Section M1.3)
Maintenance
- Poor work practices resulted in a fuel filter leak during EDG testing and a thrust
bearing failure during post maintenance testing on an auxiliary feedwater pump.
The licensee appropriately dispositioned the failures in accordance with the
Maintenance Rule. (Sections M1.2 and M1.3)
Enaineerina
e The licensee's review and corrective actions adequately addressed the inadvertent
actuation of the Control Room Emergency Breathing Air Pressurization System
(CREBAPS) on October 6,1996. The CREBAPS Focused Design Review conducted
in response to the event was a thorough evaluation of the system and provided
good recommendations for resolving the longstanding problems. However, the
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long-term action to eliminate the spurious activation of this engineered safety
features system has not been implemented yet, showing a slow response on the
licensee's part to resolve the longstanding operator work-around. (Section 08.1)
e Engineers determined that under certain con % ions the voltage supplied to the
Unit 1 nuclear instrumentation system power supplies could potentially adversely
affect the reactor trip system protective action functions. Engineers' performance
during assessment of this issue and extent of condition reviews was conservative
and demonstrated a strong questioning attitude. Corrective actions, including
design change implementation, were timely and technically sound. (Section E1.1)
- The licensee's team evaluating the gas binding events for the Unit 2 High Head
Safety injection (HHSI) pumps uncovered weaknesses in the original engineering
analysis performed to establish venting frequencies. Strong questioning by licensee
management and team members led to these findings. The venting frequency
established in 1988 to ensure minimal gas accumulation in the suction lines was
inadequate to prevent gas binding of the Unit 2 HHSI pumps. The inadequate
corrective actions to preclude gas binding of the pumps were addressed in NRC
Inspection Report 50 334 and 412/97-07. Further, the inspectors determined,
venting of the HHSI pump suction lines immediately prior to TS surveillances may
be a violation of NRC requirements pertaining to test validity and is unresolved.
(Section E2.1)
e The licensee's inservice inspection program plan for Unit 1, with relief requests,
was satisfactorily maintained and implemented. The non-destructive examination
personnel were properly qualified and certified, examination procedures were
adequate to assure valid examinations, and deficiencies were appropriately
evaluated and resolved. The new data management software appeared to be
effective. (Section E8)
Plant Sucoort
- The program for control of radiological work during the Unit 1 refueling outage was
generally effective; however, one violati< of NRC requirements was identified
regarding radiation worker knowledge of radiation levels in their work and transit
areas. (Section R1)
- Overall, the radioactive liquid and gaseous effluent control programs were good.
The Radiation Monitoring System (RMS) reliability was adequate; however, a
violation pertaining to RMS calibration practice was noted. (Section R2.1)
- The ventilation system surveillance program for radioactive effluent control was
well implemented. (Section R2.2)
e Good quality control and quality assurance programs were established for
radi active effluent control. (Section R7)
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TABLE OF CONTENTS
EX EC U TIV E S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TAB LE O F C O NT E NT S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv
1. Operations .................................................... 1
O1 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 General Comments (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
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02 Operational Status of Facilities and Equipment . . . . . . . . . . . . . . . . . . . 3
02.1 Engineered Safety Feature System Walkdowns (71707) . . . . . . . 3
03 Operations Procedures and Documentation (92901) . . . . . . . . . . . . . . . 3
03.1 (Closed) Unresolved item 50-334 and 412/97-07-01 ......... 3
04 Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 4
04.1 Questioning Attitude of Operators . . . . . . . . . . . . . . . . . . . . . . . 4
08 - Miscellaneous Operations issues . . .......................... 5
-08.1 (Closed) Licensee Event Report (LER) 50-334/96-012 . . . . . . . . . 5
08.2 (Closed) LER 50-334/97 004-01 (92901) . . . . . . . . . . . . . . . . . . 7
08.3 (Closed) LER 50-334/97-032 (92901) . . . . . . . . . . . . . . . . . . . . 7
11. M a i nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
M1 Conduct of Maintenance .................................. 7
M 1.1 Routine Maintenance Observations (62707) . . . . . . . . . . . . . . . . 7
M1.2 Routino Surveillance Observations (61726) ................ 8
M1.3 Leak on Unit 1 EDG Fuel Oil Filter (71707, 92902) . . . . . . . . . . . 9
111. E ng i n e e ri n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
El Conduct of Engineering ................................... 9
E1.1 Vital Bus Voltage Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
E2 Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 11
E2.1 (Closed) Unresolved item (URI) 50-334 and 412/97-07 04 .... 11
E8 Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
E8.1 Inservice Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . ..... 14
E8.2 (Closed) VIO 50-334/96-05-02 (92903) . . . . . . . . . . . . . . . . . . 18
IV . Pl a n t S u p p o rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
R1 Radiological Protection and Chemistry (RP&C) Controls . . . . . . . . . . . . 19
R2 Status of RP&C Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . . 21
R2.1 Calibration of Effluent / Process / Area / Accident Radiation
Monitoring Systems (RMS) . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
R2.2 Air Cleaning Systems .............................. 24
R5 Staff Training and Qualification in RP&C . . . . . . . . . . . . . . . . . . . . . . 24
R7 Quality Assurance (QA) in RP&C Activities . ................... 25
L1 Review of FS AR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
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V. Ma nag em e nt Meeting s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
X1 Exit M e eting Summ ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
X2 Pre-Decisional Enforcement Conference . . . . . . . . . . . . . . . . ...... 26
PARTI AL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
INSP?.CTIO N PROCEDURES U SED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
ITEMS OPENED, CLOSED AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . _ 29
LI ST O F A C R O N Y M S U S E D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
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Report Details
Summary of Plant Status
Unit 1 began this inspection period in Mode 6 (refueling) for the 12th refueling outage. On
October 10, the reactor vessel was defueled. On October 20, fuel reloading commenced
and the unit re-entered Mode 6. On October 29, the reactor vessel head was tensioned
and the unit entered Mode 5 (cold shutdown).
Unit 2 operated at 100% power this inspection period.
l. 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 ffiscositioned Rod Cluster Control Assembiv (RCCA)
a. insoection Scone (92901)
Inspectors reviewed the licensee root cause analysis for the mispositioning of an
RCCA in the spent fuel pool. The review included interviews with selected staff -
and managers, and review of applicable refueling procedures, Nuclear Power
Division Administrative Procedures (NPDAPs) regarding vendor services, work
location conditions, and corrective actions,
b. Observations and Findinas
During RCCA eddy current testing and insert change-outs on October 12, RCCA R-
19 was incorrectly inserted into spent fuel pool (SFP) rack location M107 instead of
N107 following removal from the eddy current test stand. The RCCA movements
were being performed in accordance with Refueling Procedure Book 111 - 1RP-12R-
3.22, " Insert Changeouts, Reposition Fuel Assemblies, and Assembly Verification in
Spent Fuel Pit."
Movement of the RCCAs was conducted by two contractor personnel, a SFP bridge
operator and a spotter, and a DLC refueling engineer assistant. Shortly after the
' Topical headings such a 01, M8, etc., are used in accordance with the NRC
standardized reactor inspection report outline. Individual reports are not expected to
address all outline topics.
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movement of RCCA R 19 to its post-inspection location in the SFP, the bridge
operator realized that it had been moved to the wrong location. Contractor
supervision, the nuclear shift supervisor, and the DLC Refueling Supervisor were
immediately notified. A fuel assembly handling deviation report was prepared and
approved in accordance with procedure and R-19 was moved to its proper location.
if the positioning error had not been recognized by the bridge operator, refueling -
procedures contained additional checks later in the process which would likely have
caught the error.
DLC senior management learned of the mispositioned RCCA two days afterward
when Condition Report 971817 was reviewed during processing. All assembly,
insert, and tool movement was halted until an investigation was completed and
corrective actions were put in place to prevent recurrence. The DLC root cause
analysis highlighted the following deficiencies:
1. Poor self-verificction techniques were used by the contractor personnel.
Contributing factors were poor lighting on the index rail and the light blue
color of the lettering.
2. The refueling assistant did not perform independent verification of RCCA
position. The refueling assistant had no formal training and there was no
pre-evolution briefing.
Corrective actions for the mispositioning of R-19 included: changes were made to
enhance the refueling procedures, a formal training program was initiated for
refueling engineer assistants, the lighting was improved at the index rails, and an
ISEG review of the event was initiated.
Inspectors also reviewed the vendor oversight requirements of NPDAP 9.8, Rev.4,
" Request for Contracted Services," and the current Rev.5, and assessed that the
mispositioning did not involve a programmatic concern with vendor control. The
root cause analysis and recommended corrective actions were presented to the
Nuclear Safety Review Board. The inspectors noted that having the Plant Manager
present the analysis and recommended corrective actions diminished the
independence of the NSRB review and subsequent recommendations to the Plant
Manager. Inspectors assessed that the licensee root cause analysis for the RCCA
mispositioning was thorough and that DLC took reasonable corrective actions to
prevent recurrence.
TS 6.8.1.a requires that, " Written procedures shall be established, implemented,
and maintained covering...the applicable procedures recommended in Appendix "A"
of Regulatory Guide 1.33, Revision 2, February 1978." Regulatory Guide 1.33
includes procedures for refueling. Mispositioning RCCA R-19 was a failure to
implement refueling procedure 1RP-12R-3.22 and was a violation of TS 6.8.1.a.
This non-repetitive, licensee identified and corrected violation is being treated as a
Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy
(NCV 50-334/97-08-01).
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c. Conclusion
RCCA R-19 was mispositioned during insert change-outs due to inadequate position
verification by contractor personnel and inadequate supervisory oversight of the
evolution by DLC staff. The misposition was immediately recognized by the
personnel involved and immediate corrective actions were taken to move the RCCA
to its correct position, inspectors assessed that the licensee root cause analysis for
the RCCA mispositioning was thorough and that DLC took reasonable corrective
actions to prevent recurrence.
O2 Operational Status of Facilities and Equipment
O2.1 Enoineered Safety Feature System Watkdowns (71707)
The inspectors walked down accessible portions of selected systems to assess
equipment operability, material condition, and housekeeping. Minor discrepancies
were brought to DLC staff's attention and corrected. No substantive concerns were
identified. The following systems were waWed down:
e Unit 1 Containment
- Unit 1 Residual Heat Removal System
03 Operations Procedures and Documentation (92901)
03.1 (Closed) Unresolved item 50-334 and 412/97-07-01: Retired Equipment Program
Inspectors reviewed the Retired Equipment Program following the licensee discovery
that some equipment was tagged as " retired in place" that was required for use in >
emergency operating procedures. The issue and the licensee's immediate corrective
actions were documented in NRC Inspection Report 50-334 and 412/97-07,
Section 03.1.
The licensee extent of condition review did not identify any additional equipment
tagged out that was required for use in emergency or abnormal operating
procedures (EOPs or AOPs). The candidate components and systems identified by
system engineers and operators for potential retirement were entered into the
evaluation process per Nuclear Power Division Administrative Procedure 8.33,
Rev.0, " Retired Equipment Program." Tha Director, System Engineering, expected
the evaluations to be completed by December 15. No additional concerns were
noted by the inspectors,
inspectors concluded that there were no safety consequences to having the
containment iodine fans and the steam generator blowdown tank (1FW-TK-1)
t igged out as " retired in place," %cause the equipment was not safety-related,pnd
was not depended upon in accident analysis. In addition, alternate methods of
emergency response other than the iodine fans and blowdown tank were
proceduralized, inspectors assessed that tagging the equipment out-of-service was
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an isolated instance due to inadequate review and implementation of the Retired
Equipment Program.
TS 6.8.1.a requires that, " Written procedures shall be established, implemented,
and maintained covering...the applicable procedures recommended in Appendix "A"
of Regulatory Guide 1.33, Revision 2, February 1978." Regulatory Guide 1.33
includes p,ocedures for combating emergencies and other significant events.
Equipment was retired-in-place without recognizing that it was required in certain
EOPs. Failure to maintain the EOPs current was a violation of TS 6.8.1.a. This
non-repetitivt licensee-identified and corrected violation is being treated as a Non-
Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy
(NCV 50-334 and 412/97-08-02).
04 Operator Knowledge and Perlormance
04.1 Questionino Attitude of Ooerators
a. insoection Scoce (71707)
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During routine control room tours, inspectors observed operator activities and
response to degraded conditions.
b. Findinos and Observations
in general, the inspectois noted that operators wera knowledgeable of plant
conditions and out-of-service equipment. The inspectors observed two particular
instances that reflected on the questioning attitude of the operators. . , .
Operators questioned steps in the surveillance test for the auxiliary feedwater
pumps. During performance of auxiliary feedwater (AFW) pump testing, the manual
discharge isolation valve is shut to prevent AFW flow to the steam generators. In
accordance with Technical Specification (TS) 4.7.1.2.a.4, an operator is stationed
at the pump and is in constant communication with the control room. if needed,
the operator is expected to open the discharge valve. The operators questioned
whether this is physically possible due to the pressure differential across the valve.
Engineering calculations show that the operator would not be able to open the
valve. The issue and corrective actions are being tracked under Condition Report
971892. The inspectors noted that operators displayed an excellent questioning
attitude in identifying this longstanding practice of stationing the operator at the
pump.
Since the beginning of September 1997, Quality Service personnel have performed
ultrasonic examinations to determine gas accumulation in the suction lines of the
charging pumps (see Section E2.1 and NRC Inspection Report 50-334 and 50-
412/97-07). The gas accumulation was reported to the control room operators in
units of inches. Based on interviews, the inspectors determined that the operators
did not have a clear understanding of what the values meant nor their impact on
operability of the charging pumps. After inspectors' questioning and discussions
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with operations and system engineering management in October, the system
engineering staff provided guidance to the operators on the quality service
examinations results. The inspectors observed that the current practice provided
the operators with a well defined gas volume limit to make an operability
determination. The lack of adequate guidance, prior to the inspectors' questioning
of the issue, resulted from poor questioning from the operators and failure of
system engineers to provide appropriate guidance to the operators,
c. Conclusion
The inspectors had mixed observations with regard to the questioning attitude of
the reactor operators. In one instance, operators using a strong questioning attitude
identified a longstanding discrepancy in an AFW pump test. However, operators'
failure to question the acceptability of charging pump gas accumulation data was a
weakness.
08 f11sc611aneous Operations issues
08.1 (Closed) Licensee Event Report (LER) 50-334/96-012: Entry into Technical
Specification 3.0.3 Due to isolation of Control Room Emergency Breathing Air
Pressurization System,
a. Insoection Scone (71707)
On October 6,1996, Unit 2 control room operators inadvertently actuated the
Control Room Emergency Breathing Air Pressurization System (CREBAPS).
CREBAPS provides pressurized air to the dual unit control room. Unit 1 operators ,
isolated CREBAPS (to mitigate the consequences) and, as a result, entered into -
Technical Specification (TS) 3.0.3. This event was previously discussed in NRC
Inspection Report 50-334 and 50-412/96-08. The inspectors reviewed LER 50-
334/96-012 and other licensee documents. The inspectors also interviewed
licensee personnel to evaluate corrective actions, the effects of the CREBAPS bottle
isolation operator work-around, and reliability of the system. The following
documents were reviewed:
- "CREBAPS Focused Design Review Report," Rev.1
- Problem Report 2-96-610, " Inadvertent CREBAPS Stuation"
- Unit 1 Maintenance Rule System Basis Document, " Area Ventilation Systems
- Control Area, System 44A," Rev. 3
e 2DBD-44A2, Rev. 3, Design Basis Document for Area Ventilation Systems -
Control Area
- Unit 2 Shift Logs for August 1997
- Unit 1 Equipment Out of Service Log, 01/01/97 - 10/31/97
- Unit 1 Work Around Log, dated 09/25/97.
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b. Observations and Findinas
There have been 20 LERs written at BVPS 1 and 2 since 1987 due to spurious
CREBAPS actuations and entry into TS 3.0.3. Most of the inadvertent actuations
were due to radiation monitor noise and electronic sensitivity problems. To prevent '
an inadvertent air bottle discharge during testing of the radiation monitors,
surveillance procedures were revised to isolate the CREBAPS bottles, and TS 3.7.7.1 (Unit 1) and TS 3.7.7 (Unit 2) were amended to allow isolation of the
CREBAPS bottles for up to 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The licensee identified the isolation of the
bottles as an operator work-around in August 1995. There have been 5 spurious
actuations of the CREBAPS system this year. There were no discharges of the
system because the CREBAPS bottles were isolated through the proceduralized
operator work around.
Licensee corrective actions listed in LER 50-334/96-012 have been completed and
are appropriate to the specifics of this event. As part of the corrective actions, the
licensee performed a focused design review of the CREBAPS. The inspectors
assessed that the CREBAPS Focused Design Review Report was a very thorough
evaluation of the system, and the recommended corrective actions addressed the
root causes of the spurious actuations. Many of the recommended corrective
actions of the Focused Design Review have been implemented and have been
beneficial. The licensee installed Technical Evaluation Report (TER) 10587 in late
June for control room area radiation mor :.or RM-218A, and in September for RM-
2188. This TER improved grounding in the instrument tack, improved coaxial
shielding, installed snubbers and in-line resistor-capacitor filters, and installed a
delay modification in the radiation monitors to prevent false alarms upon startup or
following a source check. These modifications were positive improvements. *
However, several spurious actuations have occurred since the modifications.
System engineering staff concluded that additional corrective action to install a time
delay in the radiation monitor actuation circuitry is necessary; however, it has not
been scheduled yet. Therefore, the longstanding operator work-around has
continued.
Through review of the August Unit 2 operating shift togs, the inspectors determined
that portions of the CREBAPS system had been isolated 21% of the time.
Approximately 3% of the time was 'iue to the testing and surveillance operator
work around, 7% for periodic maintenance, and 11% due to unscheduled corrective
maintenance. The inspectors interviewed the licensee system engineer, the
maintenance rule program coordinator, and PRA engineer to determine the
applicability of system unavailability to the Maintenance Rule. The CREBAPS
system was considered a non-risk-significant standby system and was tracked
through plant level criteria, with a limit on maintenance preventable functional
failures (MPFFs) tracked for the standby safety-related functions. The inspectors
determined that this level of tracking was in accordance with the Maintenance Rule.
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c. Conclusions
The licensee's review and cc,rrective actions adequately addressed the inadvertent
actuation of the Control Room Emergency Breathing Air Pressurization System
(CREBAPS) on October 6,1996. The CREBAPS Focused Design Review conducted
in response to the event was a thorough evaluation of the system and provided
good recommendations for resolving the longstanding problems. However, the
long term action to eliminate the spurious activation of this engineered safety
features system has not been implemented yet, showing a slow response on the
licensee's part to resolve the longstanding operator work-around.
08.2 (Closed) LER 50-334/97-004-01 (92901): Failure to Test Post DBA Hydrogen
Control System Recombiners in Accordance with Technical Specifications.
The issue was documented in NRC Inspection Report 50-334 and 412/97-02,
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Section M8.2. No new issues were raised in the LER revision. The scheduled
completion dates for corrective actions were revised or updated.
08.3 (Closed) LER 50-334/97-032(92901): Emergency Diesel Generator (EDG)
Automatic Start During Bus Transfer from Unit to System Station Transformer.
The issue was documented in NRC Inspection Report 50-334 and 412/97-07,
Section E2.3 No new concerns were raised in the LER. Inspectors noted that the
licensee has submitted a TS arnendment request (Proposed Operating License
Change Request No.243, dated November 4,1997) for Unit 1 to revisc the
emergency bus undervoltage trip setpoint, allowable value and time delay for EDG
start. This is intended to be a permanent corrective action to prevent unnecessary..
EDG starts during fast bus tran.cfers and while starting reactor coolant pump 1 A.
The licensee also intends to review the TS amendment history associated with the
event to determine if the existing T/S amendment process has any adverse impact
and to identify and implement appropriate enhancements, if necessary, by February
27,1998.
II Maintenance
M1 Conduct of Maintenance
M 1.1 Routine Maintenance Observations (62707)
The inspectors observed selected maintenance activities on important systems and
components. The activities observed and reviewod are listed below.
- 1PMP-13RS-P-Leak Test-1 M Recirculation Spray Pump Leak Test
- DCP 2209 ARPI Electronics Upgrade
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9
8
The activities observed and reviewed were performed safely and in accordance with
proper procedures, except as noted below. Inspectors noted that an appropriate
level n' supervisory attention was given to the work depending on its r iority and.
difficulty.
Motor driveri auxiliary feedwater pump FW-P 3A was overhauled during the
refueling outage under MWR 067122. During post-maintenance testing, the inboard
pump bearing was destroyed. Investigation revealed that the balance drum had not
been set correctly by maintenance technicians during pump reassembly. The root
cause was attributed to poor workmanship. The issue was documented on
Condition Report 971956. Following repairs, the pump was tested satisf actorily
and returned to service. The licensee concluded that the issue was not a
maintenance preventable functional failure (MPFF) under the Maintenance Rule
because the pump was out-of service for overhaul and was not required in Mode 5
(cold shutdown), and the failure was discovered during post-maintenance testing.
Inspectors discussed the issue with system engineering staff and agreed that it was
not an MPFF. Corrective actions to prevent recurrence were under evaluation at the
end of the period.
M1.2 Routine Surveillance Observations (6172fd
The inspectors observed portions of selected surveillance tests. Operational
surveillance tests (OSTs) reviewed and observed by the inspectors are listed below.
- 10ST-36.1, Rev.17 Diesel Generator No.1 Monthly Test
- 10ST-24.8, Rev.6 Motor Driven AFW Pumps Check Valves and Flow Test
- 10ST 36.4, Rev 9 Diesel Generator No.2 Automatic Test
- 10ST-13.11, Rev.4 OS System Operability Test
- 20ST 26.1, Rev.13 Turbine Throttle, Governor, Reheat Stop and Intercept
Valve Test
- 10ST-47.2, Rev.18 Containment Integrity Verification
The surveillance testing was performed safely and in accordance with proper
procedures. AddiUunal observations regarding surveillance testing are discussed in
the following sections. The inspectors noted that an appropriate level of
supervisory attention was given to the testing, depending on its sensitivity.
__ _ . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ -_________.__ _ ___-____-_ _
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M1.3 Leak on Unit 1 EDG Fuel Oil Filter (71707. 92902)
10ST-30.4 performs an automatic start of emergency diesel generator (EDG) No.2
by simulating a loss of offsite power to 4kV bus 10. Immediately after the EDG
start, a Train "B" safety injection signal is actuated to ensure proper sequencer
operation. Required loads are then verified to trip and then sequence onto
emergency bus 1DF. Following logic functional testing, EDG trips are disabled and
a load reject test of greater than 600KW is performed on the EDG.
During test performance on Novernber 8, the EDG undervoltage start and sequencer
operation was satisfactory. However, about 30 seconds into the run, operators
noted fuel oil spraying from engine mounted duplex fuel oil filter 1EE-FL-10B.
Operators shut the EDG fuel rack to stop the diesel and the leak. Loss of the EDG
resulted in loss of power to the 4kV bus 1DF, 480V bus 9P, and all "B" train
120VAC loads Vital buses 2 and 4 remained energized from their respective .
batteries. There was minimalimpact on the plant due to the initiallineup for the
test. Operators restored power to the affected buses in accordance with applicable
alarm response procedures within 45 minutes, inspectors observed the event from
the control room and toured the EDG room shortly afterward. The amount of fuel
oil spilled was small due to quick operator action in securing the EDG. Inspectors
assessed that operator response at the EDG to the fuelleak was conservative, and
operator response in the control room to the loss of the EDG was appropriate,
inspectors noted good control of event response by control room supervisors.
The fuel oil filter gasket was inspected, reseated, and tested satisf actorily.
Maintenance technicians concluded that the gasket had not been sufficiently
compressed during installation, possibly because a new gasket material was being
used. The issue was documented under Condition Report 972111 for evaluation
and corrective actions. The surveillance test on the EDG was successfully
performed on November 10.
p til. Enalneerina
E1 Conduct of Engineering
E1.1 Vital Bus Voltaae Evaluation
a. Insoection Scooe (37551. r 2700. 92903)
While reviewing plans to upgrade existing solid state protection system (SSPS)
relays, engineers identified a concern regarding the adegaacy of voltage supplied to
the nuclear instrumentation system (NIS) power supplies. The inspectors
interviewed personnel, reviewed design documents and observed design charge
implementation activities to evaluate licensee resolution of this issue.
_ _ _ . -
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b. Observations and Findinas
On October 8,1997, engineers determined that under certain conditions the voltage
supplied to the Unit 1 NIS power supplies could be outside of the vendor's
recommended range (11812.5 volts). This condition could potentially adversely
affect the reactor trip system (RTS) protective action functions that respond to
power level data from the NIS. The inspectors discussed the issue with operations
and engineering personnel and noted that the issue was properly reported to the
NRC in accordance with 10 CFR 50.72 and 10 CFR 50.73
1
The inspectors observed that engineers were conservative in assessing a cumulative
worst case scenario. Engineers applied the maximum allowable variation in the
invertor and regulating transformer output voltages combined with the worst case
voltage drop from the transformer to the NIS protection rack (due to various vital
bus and NIS protection rack loadirg). Engineers also applied the most restrictive
available tolerance band to the NIS power supplies. The Unit 2 NIS power supplies
have a vendor specified voltage tolerance of 11815% volts. Although the Unit 1
and Unit 2 NIS power supplies are very similar, the documented tolerance for Unit 1
(found in the vendor troubleshooting manual) is much more restrictive. Even though
the Unit i NIS voltages were outside of vendor recommendations, engineers believe
power supplies were likely to have functioned properly as installed, because they
were similar in design to the Unit 2 power supplies. Notwithstanding, since
documentation of acceptable NIS performance outside of the specified voltage, . sand
was not available, engineers recommended upgrading the existing Unit 1 NIS pow r
supply voltage transformers. Engineers determined that the existing Unit 2 NIS
pov'er supply was acceptable, based on design drawings, calculations, and voltage
measurements.
As an immediate action, operators verified that voltages were within the vendor
specified range each operating shift. In addition, maintenance records
demonstrated that the voltages were within the specified range when last verified
per periodic maintenance. Engineers reviewed Unit 1 operating history documents
and did not identify any actual plant conditions during which voltage was outside of
the vendor's recommendations. The unit was in cold shutdc ivn at the time of
discovery. Engineers closely communicated with the vendor, initiated a design
change to upgrade the power conditioning, and reviewed the potential extent of
condition for additional vital bus loads for both units. The inspectors determined
that initial actions were timely and technically sound.
Design change package (DCP) 2296, " Vital Bus Vo'tage Requirements", was written
to upgrade the NIS power supply regulating transformers (11811% volts) and
improve connections from the vital bus distribution panels. The inspectors reviewed
the DCP and observed portions of the field installation and testing. The DCP was
properly implemented and closely coordinated with operations personnel to establish
prerequisite plant conditions for installation and testing.
Calculation Nos. 8700-E-231(232) were initiated to model vital bus component
performance for all four vital buses and downstream components. These
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calculations were nearing completion at the end of this report period. No additional
safety related load discrepancies had been identified. Based on the results of the
completed Unit 1 calculations, engineers will determine whether a detailed Unit 2
analysis is needed.
c. Conclusions
Engineers determined that under certain conditions the voltage supplied to the Unit
1 NIS power supplies could potentially adversely affect the reactor trip system
protective action functions. Engineers' performance during ascessment of this issue
and extent of condition reviews, was conservative and demonstrated a strong
questioning attitude. Corrective actions, including design change implementation,
were timely and tv.chnically sound.
~
E2 Engineering Support of Facilities and Equipment
E 2.1 (Closed) Unresolved item (URI) 50-334 and 412/97-07-04: Adequacy of the High
Head Safety injection Pump Surveillance Tests to Ensure Operability
a. Inspection Scone (37551)
The inspectors reviewed the adequacy of the surveillance procedure to determine
functionality of the high head safety injection (HHSil/ charging pumps. The
inspectors interviewed operators, system engineers, and system engineering
managcment. The inspectors reviewed the following documents:
- Inservice Testing (IST) data for the Unit 2 HHSl pumps since 1991;
- Completed surveillance procedures for Unit 2 HHSI pumps for 1996 and
1997;
- The last five revisions to the surveillance proceduros for the Unit 2 HHSI
pumps;
- Minimum operating performance curves (located in the Inservice Testing
Program for Pumps and Valves)
b. Observations and Findinas
The inspectors identified several issues in NRC inspection Report 50-334 and
412/97-07 that were related to the adequacy of the Unit 2 surveillance procedures
20ST-7.4(5)(6), " Centrifugal Charging Pump [2CHS*P21 A(B)(C))," to determine
functionality of the HHSI pumps.
Syryeillance Procedure /IST Acceotability
The surveillance procedures require that at specific flow rates (~ 200 gpm),
operators obtain IST data including pump bearing temperatures, motor bearing
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temperatures, pump vibration data, pressures, and flow rates. Af ter recordinq this
data, the procedures allow throttling of the flow to meet the Technical Spech tion
(TS) required difierential pressure. Based on review of the TS, the minimum
operating performance curves, and basis for the differential pressure values, the
inspectors determined that the procedure was acceptable to measure end determine
whether pum; performance met the TS required differential pressures.
The acceptance criteria in the surveillance procedure require that the pumps operate
within the limits of the ASME Section XIIST program. The inspectors determined
from past IST results and procedure rev;ews, that the data was collected at a
constant flow rate which ensured the data would provide meaningful trending
information. The ASME acceptance criteria for differential pressure were not clearly
linked to the flow reo due to poor procedure human factors; however, the
inspecters determined the performtnce data was properly evaluated to correlate to
the acceptanco criteria. Based on engineering memorandums and IST program
infermation reviewed, the inspectors determined that the licensee had established a
nexus between the acceptance criteria and the minimum cperating performance
curve. The minimum operating performance curve establishes the required flow for
safety analysis. This clases URI 50 334 and 412/97 07 04.
Mditional Back4NMDilBiprmation
in Ma'ch 1988, Beaver Valley experienced gas binding of the Unit 2 HHSI pump
(2CHbP21 A). NRC Information Notice 88 23, " Potential for Gas Binding of High-
Pressua Safety injection Pumps During a Loss-of-Coolant Accident," highlighted the
indus ssue. Engineering performed model testing and ultrasonic testing (UT)
exami )ns of piping to <ietermine gas growth rates. Several colutions were .
evalunt and a manual venting path was established for both units. The venting
times were established based on UT measurements of gas accumulation in 1988
and an estimated maximum gas accumulation limit (based on prior history).
The licensee did not find the Unit 2 UT examination results performed in 1988
during tecords reviews in 1997. The conclusions derived lgas accumulation rates)
from those results were documented and used to establish the pump venting
frequencies. Unit 1 gas accumulation rates were established based on 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> of
data taken in 1988. Between 1989 and August 1997, the licansee did not conduct
UT testing for Unit 1 or Unit 2 to verify gas accumulation rates were valid. Unit 2
UT examinations conducted since August 1997 showed that the majority of the gas
accumulation occurred during pump shutdown and not during steady stato
conditions. However, the overall Unit 2 gas accumulation rate, were bounded by
the 1988 conclusions. Auditional UT examinations for Unit 1 were cor' ducted on all
three Unit 1 HHSI pump suction lines in early November. The gas accumulation
rates are still under investigation.
Prior to March 1988, the licensee had experienced 21 safety injection events at
Unit 1 without failure of the HHSI pumps. The maximum gas accumulation limit
(8.1 cubic feet) was determined using past suavsful HHSI pump operation and
engineering analysis in evaluating the void size during those events. Based un this
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analysis a maximum gas accumulation limit was established for Unit 1 and Unit 2.
The use of Unit 1 data to support a Unit 2 rnaximum gas accumulation limit may
have been inappropriate due to the different piping configurations.
In October 1997, the licensee team investigating the gas binding events asse:; sed
that the maximum gas accumulation limit should be reevaluated for Unit 1 and
Unit 2. Based on preliminary evaluation, system engineers have established a
maximum gas accumulation limit of 0.5 cubic feet for Unit 2. The limit is based on
vendor recommendation to minim!ze entrained gas to 5% by volume. Daily UT
measurements on Unit 2 suction lines have been performed to verify that the limit
has been met. The Unit 1 preliminary datermination of gas accumulation lirait will
be completed prior to Mode 4 entry. The final evaluation of ge= eccumulation limit
is under investigation by the team for Unit 1 and Unit 2. Thti l'.;ensee is
reevaluating the engineering analysis for the Original values and vo.ndor information
to determine an appropriate maximum gas accumulation limit. This effort includes
construction of a model to help address cuestions on gas ccumulation and
transportation of that gas to the pump.
In addition, the established vent path was ineffective due to inmfficient driving
force to move the gas from the charging pump piping to the col 6ction tank.
Periodic venting did not always aJequately vent the Unit 2 HHSI pump suction lines.
The Unit 2 "C" HHSI pump experienced gas binding during multiple starts in June
1993 and during starts in November 1996 and August 1997. The repeated gas
binding events were the most likely cause for the pumps' degraded performance ,
and subsequent replacement in September 1997. The inadequate venting and gas !
binding events were documented in Nf4C Inspection Report 50 334 and 412/97 07.
Based on the gas binding events that occurred on Unit 2 "C" HHSl pump, the
inspectors determined that the established vent path and venting frequencies were
inadequate to ensure proper pump performance. The inadequate venting system
and the questionable acceptable gas accumulation limits resulted in inadequate
venting frequencies. From 1988 to August 1997, the licenseo setied on the venting
i frequencies to maintain acceptable low levels of gas entrainment for operability of
the HHSI pumps. The failure to take appropriate corrective actions to preclude gas
binding of the pumps was an apparent violation documented in NRC Inspection
Report 50 334 and 412/97 07.
Ventino Prior to Manual Pumo Starts
i
( During review of the surveillance procedure and discussions with system engineers
and operations management, the inspectors determined that HHSi pump suction
'
lines were routinely vented prior to performing manual pump starts, including the
periodic surveillance test. The procedures allowed venting the HHSI pump prior to
starting the pump at the nuclear shift supervisor's discretion. Unit 1 and Unit 2
c,perators typically vented the HHSI pumps prior to performing the quarterly
surveillances, safeguards protection system testing (GO testing), and 18-month full
flow testing. The venting prior to pump start was done to eliminate any gas in the
system to enhance pump long-term reliabili'y.
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The venting frequency established to ensure minimal as accumulation in the
suction lines was inadequate to prevent gas binding or the Unit 2 HHSI pumps. 'The ,
inspectors determined that venting the suction lines immediately prior to performing i
'
the surveillance testing changed the as found condition of the system from that
which would normally be present if the system was automatically called upon to 1
perform its safety function. . Changing the as-found condition of the HHSI pump
suction lines immediately prior to performing periodic surveillance tests may
interfere with the licensee's ability to properly assass the operability of the system.
10 CFR 50, Appendix B, Criterion XI, " Test Control", requires, in part, that "... the
test is performed under suitable environmental conditions." Suitable environmental-
- conditions include conditions representative of the expseted conditions when the
aquipment is required to perform its safety function. The normal practice of venting - >
prior to surveillance testing may be a violation of NRC requirements pertaining to
the validity of the test results, depending upon the periodic venting program . ,
implemented between the surveillance tests. This is considered an unresolved item
pending further NRC review. (URI 50 334 and 412/97 08 03). ,
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c. Conclusion
The inspectors observed that the licensee's team evaluating the gas binding events
in August 1997 had uncovered weaknesses in the original engineering analysis
perfortned to establish venting frequencies. Strong questioning by licensee
management and team members led to these findings, inspectors identified
weaknesses in the licensee's oversight of gas accumulation in the safety significant
HHSI system from 1988 to 1997, in that the licensee did not verify the original gas
accumulation rate assumptions, and d!d not verify the adequacy of the periodic vent
path used during that time period.
Periodic venting practices established in 1988 to ensure minimal gas accumulation
in the suction lines was inadequate to prevent gas binding of the Unit 2 HHSI
pumps. The frequency of venting should be based on a good venting method, an
established gas accumulation limit, and an established gas accumubtion rate. Since
the venting method was not effective and the established gas accumulation rate and
limits were incorrect, the venting frequency was inadequate. The inadequate
corrective actions to preclude the gas binding of the pumps were addressed in
Inspection Report 50 33t, and 412/97 07. Acceptability of the pre surveillance test
venting that had been in effect is unresolved.
E8 Miscellaneous Engineering Issues
E8.1 Inservice Insoection
a. Insoection Scone (73753. 92903) .
An inspection of the inservice inspection (ISI) program was conducted by a regional
inspector from October 20 24,1997. The objective of this inspection was to verify
that the inservice inspection (ISI), repair, and replacement of Class 1,2, and 3
pressure retaining components are performed in accordance with the Technical
4
, ....me,,. , , , , - . - - e..,..,r .. - . . , ~ .- . . .- . . ,,,,-. _ # - + ~ , , , ,24,. ... . .,,y -v-o, ,c-,- ,.enww,,.~,.w.
_. . . - . - - . _ -
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15
Specifications (TS), the applicable ASME Code, NRC requirements, and industry
initiatives, including any relief requests granted by the NRC.
i
The scope of the inspection included the review of the licensee's ISI program plan i
for Beaver Valby Unit 1, orocedures, qualification of inspection / examination l
personnel, schdule vi planned Isis for the refueling outage IR12, and observation l
of ISI work. '
b. Observation and Findinas
1. The ISI Prooram Plan
The ISI program plan for the third 10 year interva! was submitted to the NRC
on September 17,1997. The plan includes several relief requests and
alternate inspection methods. Although the plan has not yet been approved
by the NM, the licensee has implemented the proposed plan with the
rationale that many of these relief requests and alternate inspection methods
had been approved by the NRC for the previous plan, thus it would be
acceptable for the third interval. However, if the NRC does ' it approve nny
of tM proposed relief requests or alternates, the licensee ha two mea
scheouled " outages" to modify and implement an approved plan,
2. Steam Generator Tube Eddy Current insoection
Duquesne Light Company (DLC), the licensee for Beaver Valley Unit 1 (BV-
1), had nearly completed its steam generator (SG) tube eddy current
inspections for the current refueling outage. BV-1 has three Westinghouse
Model 51 SGs with carbon steel drilled hole tube support plates and -
WEXTEX joints in the tubesheet. DLC performed fulllength bobbin coil eddy
current inspections of all active tubes in each SG. The licensee also
performed specialized inspections using the plus point probe of the low row
U bends, hot and cold leg top of the tubesheet (TTS), most bobbin coil
indications, and rolled plugs. DLC also conducted a secondary side visual
inspection of the wrapper supports and found no degradation.
Through bobbin coil inspections, DLC identified four pluggable (i.e., greater
than 40% throughwall) wear indications due to cold lag thinning and anti-
vibration bar (AVB) wear. The licensee also detected tube support plate
(TSP) cracking through bobbin coilinspection and followed up using the plus
point probe to confirm about fifteen suc,h indications in the patch plate
region. The licensee is evaluating how to dispusition the affected tubes.
DLC inspected 100% of the TTS on the hot leg side and 20% of the TTS on
the cold leg side in each SG. The axial extent of the tubesheet inspections
included six inches above the TTS to three inches below the TTS, On the
hot leg side, the licensee reported 127 repairable indications. Most were
identified as axially-oriented outside-diameter stress corrosion cracking
(ODSCC) located above the TTS in the tube " collar" region (area of heavy
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16
tube deposits not removed through sludge lancing). A few were axial and
circumferentially-oriented indications located below the WEXTEX expansion
transition inside the tubesheet. On the cold leg side, the licensee identified
nine axially-oriented ODSCC indications located above the TTS; for this SG,
the licensee expanded its inspection scope to include 100% of the TTS
region. The longest extent for a circumferential crack was about 90' and
the longest axial crack was reported to be about 0.8 inches long. Eight
volumetric indications (some pit-like) were found in the TTS region as well.
DLC inspected 100% of the row 1 and 2 U bends and 20% of the row 3 U-
bends. The licensee reported 11 row 1 U bend indications and 1 row 2 U-
bend indication characterized as primary water stress corrosion cracking
(PWSCC) and located in the bend tangent. DLC's low row U bends have
been stress relieved.
The licensee performed a 100% inspection of dents > 5 volts, a 20% sample
of dents >205 volts, and 100% of all dents and dings (dents located in the
freespan) >2 volts located between the TTS and the 3rd TSP. No
indications were reported.
DLC inspected 100% of its inconel 600(1-600) rolled plugs and 20% of its
Inconel 690 (1690) rolled plugs. The licensee reported seven 1600 plug
indications. The licensee intends to replace these with l 690 rolled plugs
during this outage. No I 690 plug indications were reported.
For the identified degradation mechanism, the licensee has selected the most
limiting (based on length, depth and voltage) indications for insitu pressure
testing. At the time of this inspection, the pressure testing of SG tubes was
in progress. The inspector witnessed one such test from the remote test
control location.
3. Qualification /Cortification of NDE Personnel
The inspector reviewed the qualification and certification records of
approximately seven individuals engaged in non-destructive examination
(NDE) of the ISI program. The review indicated that the inspectors were
properly qualified by formal and practical training, and were certified to
proper levels of inspection / examination responsibility in different examination
methods; e.g., visual examination (VT), liquid penetrant (PT), magnetic
particle (MT), or ultrasonic examination (UT).
4. Observation of ISI Examinations
The inspector observed / witnessed several NDEs to assess the adequacy of
procedures, knowledge and proficiency of test personnel, and the validity of
the test results. The following tests were observed:
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1. Surface examination by dye penetrant: CH 23 3 5-03, and CH 23 4-
i F 06 inside containment; ;
2. Volumetric examination by UT: 1 SA 41 FD24 in the auxiliary
building; and ,
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3. Pressure test of steam generator tube: 5A21 from the remotu
display / control test facility for SG tube examination and tests. ,
'
The tests / examinations were performed by knowledgeable and qualified i
Individuals, using approved proc?dures, materials, and calibrated equipment.
The results were properly recoroad. 7
'
5. Evaluation and Resolution of Deficiency
i
The inspector reviewed the evaluation and resolution by Engineering of three
" unsatisfactory" test results. These deficiencies were documented in
Condition Reports 970792,970793 and 970836, and were related to PT
,
surface examinations.
>
In all cases, the disposition of the indication by grinding and blending the
surface profile to established contour was appropriate. '
O. NDE Procedures
The inspector reviewed the following NDE procedure to assess the clarity
and technical adequacy of established requirements.
GP-105 Evaluation of PSl/ISI Flaw Indications, Rev. 6
LP-101 Solvent Removable Visible Dye, Rev.15
MT-201 Magnetic Particle Examination, Rev.13
UT-301 Linearity of Ultrasonic Instruments, Rev. 9
UT-303 Ultrasonic Examination of Piping Welds, 2" to 6" Thick and
Vessels Less than or Equal to 2" Wall Thickness, Rev.12
a The inspector determined that the procedures were clearly written, estbblished
technically valid requirements and were appropriately maintained, controlled, and ~
used by NDE personnel.
Additionally, the licensee has implemented a new data management software for
tracking and managing ISI program. Th' new system appears comprehensive and
has been successfully used at other utilities.
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c. ConclutdQnt
Based on the above observation, review of documentation, and discussions with
personnel responsible for ISI program, the inspector concluded that the licensee's
ISI program plan is satisfactorily maintained and implemented. The NDE personnel
are properly qualified / certified, examination procedures are adequate to assure valid
examinations, and deficiencies are appropriately evaluated and resolved. The new
data management software appears effective.
E8.2 (Closef f) VIO 50 334/96 05-02(92903): Inadequate cap'eration for UT
examinations
The above violation pertained to a failure to perform a calibration for UT
examination using a reflector perpendicular to the cound beam for examinations ,
!
with the sound beam to the weld seem (circumferential examinations) on six ASME
class 2 pipe weld examinations. Also, for two calibrations (C 96-57 and C 96-46)
sido drilled holes were not used to construct the distance amplitude correction
(DAC) curve.
In response to the Notice of Violation, the licensee initiated entrective actions to
resolve the deficiency, and to prevent similar occurrences in tue future. The
licensee's actions included the following:
1. Problem Reports 196 487,196-488 and 196 489 were submitted to the
Operations Experience Group on May 17,1996. These problem reports
identified the scope of incorrect calibrations and provided technical
assessments of the deficiencies identified during the exit meeting on
May 16,1996.
2. An independent review of the problem reports was performed by Materials
and Standards Engineering to address poter.tial operability concerns.
3. Independent root cause evaluation using the Taproot root cause evaluation
method was performed on the problems identified.
Actions Taken to Prevent Recurrence
As a result of the recommendations in the root cause evaluations, the following
corrective actions were being taken:
1. UT Procedure UT-303 was revised for clarification and to allow ID notch
calibration and was demonstrated to the authorized nuclear inservice
inspector (ANil).
2. NDE catractor training has been included in procedure OSP 2.5, which
provides procedural contrels for onsite training of contracted NDE personnel
using DLC. NDE procedures.
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3. The calibration report forms have been revised to more clearly define
calibration orientation and calibration reflectors used.
4. The dissimilar metal welds examined using only the ID notch for calibration
were re-examined using a qualified UT technique during 1R12.
The inspector verified the licensee's corrective actions by review of documentation
and discussion with cognizant personnel, and found the actions acceptable and
effective. Based on the above observation, this item is closed.
IV. Plant Support
R1 Radiological Protection and Chemistry (RP&C) Controls
a. Insnection Scone (83750)
The inspectors reviewed the licensee's program for radiation protection during a
refueling outage (1R12). Areas reviewed included high and locked high radiation
area controls, radiation worker performance indicators, including maintaining
occupational exposures as low as is reasonably achievable (ALARA), and radiation
worker practices. The inspection was accomplished by a review of plant
dncuments and procedures, interviews with personnel, and walkdowns of the
related areas,
b. Observations and Findinas
The inspectors reviewed the licensee's performance during the Unit 1 refueling
outage (1R12) which commenced in late September. Outage goals previously
established included completion of the outage in 40 days (with a challenge goal of
36 days), an occupational exposure goal of not more than 201 person rem, and a
personnel contamination event goal of not more than 180. During the period of this
specialist inspection, outage activities included eddy current testing in all three
steam generators, reactor head and upper core internals removal, and the first 36
hours of fuel removal.
The inspectors reviewed the licensee's control of high ar.d locked high radiation
areas, especially those located in the containment. All areas reviewed, which
included the entrances to the steam generator / reactor cociant pump cubicles, were
determined to be appropriately controlled, barricaded and posted in accordance with
plant technical specifications. Workers interviewed in the high radiation areas were
aware of their work area exposure rates and appropriate radiological controls to
minimize their exposures. Health physics technicians were observed providing
d3 tailed and extensive briefings to workers and providing appropriate job coverage.
Of particular note was the licensee's utilization of remote teledosimetry, closed
circuit cameras and communication fa steam generator eddy current testing. By
i utilizing this type of control, the licensee was a' ole to significantly reduce total job
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exposures, especially for the radiological cor tmis technicians, while providing real ;
time exposure rate data so ac to minimize suam generator worker exposures.
As noted above, the licensee had established an outage ALARA goal of not more
than 201 person-rem, and through day 12 of the outage the exposures appeared to
be tracking well, although the licensee does not track exposure against percentage
of work completed and the outage was estimated to be two days behind schedule.
The inspector noted that the licensee was focused on personnel contamination
events (PCEs) and had established an outage goal of not more than 180 PCEs.
During the specialist inspection, the inspectors noted that workers entering the
radiologically controlled areas (RCAs) were not checking the posted general area
survey maps located at the primary plant staff and contractor entry points, as
specified in the licensee's radiation work permits. Since the licensee did not utilize
a direct verbal briefing system between workers and the health physics staff prior to
entries, it appeared to the inspectors that the potential existed for workers to be in
portions of the RCA without knowing the radiological conditions. On October 7th
and 8th, the inspectors conducted a random survey of workers located in the
general areas of the primary auxiliary building, especially the transit path to the
containment personnel hatch, and inside the containment, in the outer annulus
regions. None of the ten workers interviewed could identify the radiological
conditions in the areas they were standing in or had walked through. None of the
workere could identify their nearest ALARA low dose waiting area. The inspectors
further noted that workers failed to review the radiological survey maps placed at
the two main RCA entrances, as required by their RWPs. Further, the inspectors
noted that a number of the posted survey maps at the RCA access points were
outdated and did not accurately reflect current plant conditions. Failure of workers
to follow instructions contained in their RWPs is a violation of TS 6.8.1.a, which
requires that written procedures and instructions be established, implemented and
maintained regarding radiation protection procedures. (VIO 50 334/97-08-04).
On two separate occasions, the inspectors observed workers in the containment
who appeared to be unaware of their surroundings. One worker was observed lying
on the floor on the 692' elevation next to a desk and chair at the health physics
control point for that level, while another was outside the "C" steam generator
cubicle on the 718' elevation. Neither location was a designated low dose waiting
area. Both workers had their eyes closed, and did not open them cr notice the
inspector until just as the inspector passed them. The inspector notified plant
supervisors of his observations, and his concern that personnel, not actively
engaged in work in the RCA, should be outside the RCA or in posted ALARA low
dose waiting areas. The first example was subsequently documented in a plant
condition report.
During tours of the containment, the inspectors noted generally poor radiological
housekeeping. The same observation was made by the plant Health Physics
Manager, who stressed the importance of this issue at a morning management
meeting attended by the inspectors. By the end of the specialist inspection,
l housekeeping had improved but was still considered poor.
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The inspectors also reviewed the license's most recent results from the National
Voluntary Laboratory Accreditation Program (NVLAP) of its thermoluminescent -
dosimetry program. During NRC Inspection Report 50 334 and 412/97-02, the
inspectors noted that the licensee had failed test criteria 1, Accideni ' ow Energy
Photon. Since that time the licensee has resubmitted 15 test dostw/.ers, five per
month for three months, and has received a passing grade from NVLAP.
c. Conclusions
Generally effective radiological controls were in place for the refueling outage,
especially for the control of work in high and locked high radiation areas. However;
radiological housekeeping was poor, some posted survey maps of the RCA were out
of date, and two workers were observed in the RCA who were not aware of their
surroundings. One violation of NRC requirements was also identified concerning
workers failing to follow the RWP requirement to review the applicable survey maps
of the RCA prior to entry.
R2 Status of RP&C Facilities and Equipment
R2.1 Calibration of Effluent / Process / Area / Accident Radiation Monitorino Svstems (RMS)
a. Insoection Scope (84750)
,
The inspector reviewed the most recent radiological and electronic calibration
results and calibration procedures for the effluent / process RMS. The inspector also
held discussions with Health Physics and instrumentation and Controls staff, and
the RMS System Engineer.
The inspector utilized the following documents as a basis to determine whether the
calibration procedures contained sufficient detail and guidance to verify conversion
factors (calibration factors) and monitoring capability for the intended range
(linearity):
o Regulatory Guide 1.21, " Measuring, Evaluating, and Reporting Radioactivity
in Solid Wastes and Releases of Radioactive Materials in Liquid and Gaseous
Effluents from Light Water Cooled Nuclear Power Plants, February 1979"
, o Regulatory Guide 4.15, " Quality Assurance for Radiological Monitoring
Programs (Normal Operations)- Effluent Streams r, rid the Environment.
February 1979"
e ANSI N42.18,1980, " Specification and Performance of On-Site
Instrumentation for Continuously Monitoring Radioactivity in Effluents"
e EPRI TR-102644, " Calibration of Radiation Monitors at Nuclear Power r)lants,
March 1994"
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- - Victoreen Installation, Operation, and Maintenance Instruction Manual Beta
'
Scintillation Detectors Models 843 20,843 20A, and 843 20B *
- Victoreen Instruction Manual Gamma Scintillation Detector Model 843 30 l
The following Unit 1 RMS were reviewed.
- Liquid Waste Effluent
'
- Component Cooling Recirculation Spray Heat Exchange
- Process Vent Noble Gas
- Auxiliary. Building Noble Gas
- Supplementary Leak Collection Noble Gas
- Containment Air
. * Containment Purge
The following Unit 2 RMS were reviewed.
- Liquid Waste Effluent
- Ventilation System Noble Gas
- Elevated Release Noble Gas
- Decontamination Building Noble Gas
- Waste Gas Storage Vault
- Condensate Polishing Building Noble Gas
'
- Containment Purge Noble Gas
b. Observations and Findinas
Electronic calibrations were appropriate. Linearity checking was appropriate. Good
tracking and trending of the RMS was noted. The inspector noted that despite the
age of RMS, reliability has been good. There were few open work orders at the
time of the inspection.
The inspector did note that the licensee typically used supervisory discretion
(permitted by procedure) rather than using the detailed guidance within the Health
Physics Department procedure 5.11 for establishing a high voltage setting. Of the
22 channels of RMS reviewed, only 3 channels met EPRI guidance for establishing
the operating high voltage. The inspector noted that the practice was contrary to
existing standards and industry guidance documents.
RM-1RM 215A (Unit 1 containment particulate; Victorcen detector type 843-20A)
operating voltage was established at 650 volts. Per licensee calibration data, the
4 percent change over 50 volts at 650 volts on a operating voltage vs. count rate
curve was 365% The inspector noted that the vendor instruction manual directed
the user to generate a plateau curve and noted that at 1100 volts the count rate
should reach the lower end of the plateau. Contrary to the vendor instruction
manual and the above noted guidance documents that operating high voltage be set
on the plateau, the licensee established operating high voltage by changing high
. _~- - . -,
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- voltage to a point at.which actual counts equalled expected counts with a National
Institute of Standards and Technology (NIST) traceable source.
RM 1LW-104 (Unit 1 liquid waste effluent; Victoreen detector type 843 30)
operating voltage was established at 450 volts. Per licensee calibration data, the
percent change over 50 volts at 450 volts on a operating voltage vs. count rate
curve was 133% The inspector noted that the vendor instruction manual
specifications for operating voltage were 500 to 1400 volts. The inspector also
noted that the vendor manual recommended that the operating high voltage be
established by generating a signal to noise ratio curve and setting high voltage to
the peak value on the curve (this method is also described in EPRI TR 102644).
Contrary to the vendor instruction manual and the above noted guidance
documents, the licensee established operating high voltage by changing high -
voltage to a point at which actual counts equalled expected counts with a NIST !
traceable source.
TS 6.8.1.a requires, in part, that written procedures shall be established,
implemented, and maintained covering the activities recommended in Appendix A of
Regulatory Guide 1.33 (RG 1.33), Revision 2, February 1978. Appendix A of the
RG 1.33, " Typical Procedures for Pressurized Water Reactors and Boiling Water
Reactors," describes typical procedures for the control of radioactivity, including
procedures involving radiation monitoring systems.
Contrary to the above, the licensee failed to establish adequate RMS calibration
instructions in regard to determining RMS operating high voltage. Specifically,
operating high voltage was not established on a plateau for RM 1RM 215A (Unit 1
Containment Particulate) and RM 1LW-104 (Unit 1 Liquid Waste Effluent). This was
contrary to vendor manual "Victoreen Installation,- Operation, and Maintenance, ~
Instruction Manual Beta Scintillation Detectors Models 843 20, 843-20A, and 843-
20B" and "Victoreen instructional Manual Gamma Scintillation Detectors Model
843-30" respectively; and was contrary to RMS calibration standards and industry
guidance documents. This is a violation of NRC requirements (VIO 50-334/97-08-
05).
In reviewing as found and as left high voltages for the above noted RMS calibrations
- and a synopsis of similar data provided by the RMS Health Physicist, the inspecte."
noted that typically there was little if any high voltage drift. In one case, a drift of
30 volts was noted. For this particular RMS, the operating high voltage had been
set close to the plateau and, as a result, this relatively large drif t in operating high
voltage had very little impact on the accuracy of RMS output. While the technique
used to establish operating high voltage was technically deficient, the inspector did
not identify any case in which high voltage drift had led to error such that the
validity of data provided in the annual effluent report was questionable. During the
inspection and at the exit meeting, licensee representatives indicated that prior to a
planned batra release a sample is taken, thereby providing a check on RMS
operability.
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The inspector questioned the licensee as to whether they could provide any
information pertaining to new/ refurbished detector failures. The Health Physics I
Marager informed the inspector that if BVPS identified a faulty detector, it was I
replaced; but, the f ailure cause may not be documented. This matter will be l
reviewed further (IFl 50-334/97 08-06).
c. Conclusion
RMS reliability has generally been good. Electronic alignment and linearity checking
were good. The inspector noted that the licensee had failed to implement industry
guidance (EPRI TR 102644 and ANSI N42.18) which specifically direct that the
operating voltage be set on a plateau and, in two cases, had failed to implement
vendor manual instructions for establishing operating high voltage. The inspector
concluded that this was a poor calibration practice which has the potential for ,
leading to instrument error. Instrument error could impede or prevent an accurate
assessment of public exposures and environmental impact in the case of an
inadvertent release of radioactive materials.
R2.2 Air Cleanino Systems
a. Insoection Scoco (84750)
The inspectors reviewed the licensee's most recent surveillance test results,
including visual inspections, in-place High Efficiency Particulate Air (HEPA) leak
tests, in-place charcoal leek tests, air capacity tests, pressure drop tests, and
laboratory tests for the iodine collection efficiencies for the Supplementary Leak
Collection and Release Systems (SLCRS).
b. Observations and Findinas
All test results were within the licensee's acceptance criteria. No procedural
inadequacies were noted. Unsatisfactory test results were analyzed and corrective
actions were implemented in a timely manner. The inspectors noted that attention
given to the air cleaning systems was good. System Engineers monitored and
trended the performance of the air cleaning systems.
c. Conclusions
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Those portions of the test program reviewed were wellimplemented with strong
monitoring and trending of air cleaning system performance parameters.
R5 Staff Training and Qualification in RP&C
l
a. Insoection Scone (83750)
+
The inspectors reviewed the qualifications of 23 contractor health physics
technicians to ensure they were appropriately classified as junior or senior
technicians. The records were selected by the inspectors at random.
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b. Observations l
8
The licensee hired 86 contractor health physics technicians (66 senior and 20
junior) in ordet to support the Unit 1 refueling outage. The inspectors selected 23 i
records at random and reviewed the licensee's calculations for technician !
experience. All calculations reviewed were determined to be appropriate, and in
general, the inspectors determined that the licensee was conservative in reviewing
technician qualifications. ,
c. Conclusions
,
The licens9e appropriately classified contractor health physics technicians with
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regards to previous experience.
. R7 Quality Assurance (QA)in RP&C Activities ,
a. Inspection Scope (84750)
'
The inspection consisted of: (1) review of the 1996 Quality Services Unit (OSU)-
audit of the Site Radiological Effluent and Environmental Monitoring Programs, (2) '
QSU surveillances and (3) self assessments.
b. Observations and Findinas
Audit team members included a technical specialist from another utility. The depth
>
of the audit was good. The audit team identified several minor discrepancies and
matters for enhancing the radioactive liquid and gaseous effluent control programs..
No items were of regulatory significance. l
! Surveillances and self assessments were also well-targeted arcl helped to augment
the audit.~
!
c. Conclusion
This program area was wellimplemented.
L1 Review of FSAR Commitments
l
l_ - While performing the inspections discussed in this report, the inspectors leviewed
'
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the applicable parts of the UFSAR that related to the areas inspected. The
inspectors verified that the UFSAR wording was consistent with the observed plant
practices, procedures and/or parameters.
.
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V. Mananoment Meetinas
X1 Exh Meeting Summery
The inspectors presented the results of the radiation protection and radioactive effluent ~i
control inspections to Mr. R. Vento on October 10,1997. The results of the ISl program
inspection were presented to Mr. S. Jain and Mr. R. LeGrand on October 24. The licensee
acknowledged the findings presented. After further in office review of information
pertaining to the RMS calibration, the inspector concluded that a violation of NRC
requirements had occurred. '
The inspectors conducted an interim exit with Mr. S. Jain on November 10,1997, to
discuss the apparent violation documented in this report. The inspectors presented the
remainder of the inspection results in a meeting with Mr. J. Cross and members of his staff
at the conclusion of the inspection on November 21,1997. The licensee acknowledged i
the findings presented with one exception, i
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The licensee disagreed with the NRC's position that venting the HHSl pumps immediately
prior to surveillance test preconditioned the pumps. The licensee stated that the purpose ,
of venting the suction lines on the HHSl pumps prior to surveillance testing was to ensure
long term reliability of the pumps. The venting was not performed to create an enhanced l
test environment.~ The licensee stated that venting the pump would not change the <
environment such that it could be considered preconditioning.
- The inspectors asked the licensee whether any materials examined during the inspection
!
should be considered proprietary. No proprietary information was identified.
X2 Pre-Decisional Enforcement Conference
'
The pre-decisional enforcement conference referred to in NRC Inspection Report 50-334
and 50-412/97 07 has been scheduled for December 10 at the NRC Region i office to 3
discuss the apparent violation documented in that report and URI 50 334 and 412/97-08- ,
03 of this report.
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PARTIAL. LIST OF PERSONS CONTACTED
QLG
J. Cross, President,' Generation Group ,
R. LeGrand, Vice President, Nuclear Operations / Plant Manager
S. Jain, Vice President, Nuclear Services
M. Pergar, Acting Manager, Quality Services Unit
B. Tulte, General Manager, Nuclear Operations
R. Hansen, General Manager, Maintenance Programs Unit
R. Vento, Manager, Health Physics
D. Orndorf, Manager, Chemistry
F. Curl, Manager, Nuclear Construction
J. Matsko, Manager, Outage Management Department
T. Lutkehaus, Manager, Maintenance Planning & Administration
.T. McGhee, Coordinator, Onsite Safety Committee
Ji Macdonald, Manager, System & Performance Engineering
K. Beatty, General Manager, Nuclear Support Unit
J. Arias, Director, Safety & Licensing
W. Kline, Manager, Nuclear Engineering Department
R. Brosi, Manager, Management Services
O. Arredondo, Manager, Nuclear Procurement
NBC
D. Kern, SRI
G. Dentel, Ri
F. Lyon, RI -
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INSPECTION PROCEDURES USED
.
IP 37551: Onsite Engineering
IP 61726: Surveillance Observation
IP 62707: Maintenance Observation l
lP 71707: Plant Operations .
IP 71750:- Plant Support !
!
IP 73753: Inservice inspection
IP 83750: Occupational Exposure
IP 84750: Radioactive Waste Treatment, and Effluent and Environmental
Monitoring
IP 92700: Onsite Follow up of Written Reports of Nontoutine Events at Power ;
Reactor Facilities
IP 92901: Follow up - Operations
IP 92902: Follow up - Maintenance i
IP 92903: Follow up - Engineering
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. . _ . _ _ _ _ _ _ _. _ _ - _ - _ . _ _ _ _ _ _ _ _ _ . . _ _ _ _ _ _ . _ - - _ _ _ . _ _ _
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ITEMS OPENED, CLOSED AND DISCUSSED
>
Ooened
50 412/97 08-03 URI Test Control High Head Safsty injection Pumps
(Section E2.1)
!
50-334/97-08-04 VIO Workers were Unaware of Radiological Conditione in i
their Work and Transit Areas in the RCA (Section R1)
50 334/97 08-05 VIO Failure to Calibrate RMS in Accordance with Propor
Procedures (Section R2.1)
,
50 334/97 08-06 IFl Documentation of RMS Detector Failures (Section R2.1) ,
Ooened/ Closed
50 334/97 08 01 NCV Mispositioning of RCCA in the SFP (Section 01.2)
50 334 and 312/97 08 02 NCV implementation of the Retired Equipment Program
(Section 03.1)
Closed
50 334/96-012 LER Entry into Technical Specification 3.0.3 Due to Isolation
of Control Room Emergency Breathing Air Pressurization
System (Section 08.1)
50 334/97-004-01 LER Failure to Test Post DBA Hydrogen Control System
Recombiners in Accordance With Technical
Specifications (Section 08.2) ,
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50 334/97-032 LER EDG Automatic Start During Bus Transfer from Unit to
System Station Transformer (Section 08.3)
50 334 and 412/97-07 04 URI Adequacy of the High Head Safety injection Pump
! Surveillance Tests to Ensure Operability (Section E2.1)
50 334/96-05 02 VIO Inadequate Calibration for UT examinations
,
(Section E8.2)
50 334 and 412/97-07-01 URI implementation of the Retired Equipment Program
(Section 03.1)
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LIST OF ACRONYMS USED
1R12 Unit 112th Refueling Outage
AFW Auxiliary Feedwater Pump
ALARA As Low As is Reasonably Achievable
ANil Authorized Nuclear Inservice inspector
AOP Abnormal Operating Procedure
l
AVB Anti Vibration Bar i
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BVPS Bebver Valley Power Station
- CR Condition Report
CREBAPS Control Room Emergency Breathing Air Pressurization System
DCP Design Change Package
DLC Duquesne Light Company
EDG Emergency Diesel Generator ,
eel Est stated Enforcement issue ,
EOP Emergency Operating Procedure
.ESF Engineered Safety Feature
HEPA High efficiency Particulate Air
HHSl High Head Safety injection
l&C Instrumentation and Controls
ISI Inservice Inspection '
IST Inservice Surveillance Test
LER Licensee Event Report
MPFF Maintenance Preventable Functional Failures
MSP Maintenance Surveillance Procedure
MT Magnetic Particulate
NCV Non-Cited Violation
NDE Nondestructive Examination
NIS Nuclear Instrumentation System
NIST National Institute of Standards and Technology
NPDAPS Nuclear Power Division Administrative Procedure ,
NVLAP Nuclear Voluntary Laboratory Accreditation Program
ODCM Offsite Dose Calculation Manual
ODSCC Outside Diameter Stress Corrosion Cracking
OST Operational Surveillance Test
PCE Personnel Contamination Event
PDR Public Document Room
PMP Preventive Maintenance Procedure
PWSCC Primary Water Stress Corrosion Cracking
QA Cuality Assurance
OC Quality Control
OSU Quality Services Unit
RCA- Radiological Controlled Area
RCCA Rob Jiuster Control Assembly
RMS Radiation Monitoring System
RP&C Radiological Protection and Chemistry
RTS Reactor Trip System
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RWP Radiological Work Permit
- SFP Spent Fuel Pool
SLCRS _ Supplementary Leak Collection and Release System
SSPS- Solid State Protection System
TER ~ Technical Evaluation Report
-TS = Technical Specification
TSP Tube Support Plate
TTS Tubesheet
UFSAR Updated Final Safety Analysic Report
URI Unresolved item
UT Ultrasonic Examination
VIO Violation -
VT' Visual Examination
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