ML20217B985
| ML20217B985 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley |
| Issue date: | 03/17/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20217B975 | List: |
| References | |
| 50-334-97-11, 50-412-97-11, NUDOCS 9803260243 | |
| Download: ML20217B985 (43) | |
See also: IR 05000334/1997011
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U. S. NOCLEAR REGULATORY COMMISSION
REGION I
Report Nos. 50-334/97-11;50-412/97-11
Docket Nos. 50-334,50-412
Licensee: Duquesne Light Company (DLC)
Post Office Box 4
Shippingport, PA 15077
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Facility: Beaver Valley Power Station, Units 1 and 2
Inspection Period: December 28,1997 through February 7,1997
Inspectors: D. Kern, Senior Resident inspector
F. Lyon, Resident inspector
. G. Dentel, Resident inspector
E. King, Physical Security inspector 3
Approved by: N. Perry, Acting Chief
Reactor Projects Branch 7
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PDR - ADOCK 05000334
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EXECUTIVE SUMMARY
Beaver Valley Power Station, Units 1 & 2
NRC Inspection Report 50-334/97-11 & 50-412/97-11
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 an announced inspection by a regionalinspector of the
security program.
Ooerations
e On January 30,1998, Unit 1 operators declared both trains of the Reactor Plant
Component Cooling Water system and the River Water system inoperable due to
failure to test system valves as required by technical specifications (TS). Previous
interpretation of the TS was too narrowly focussed, as it did not address all system
valves which service safety related components. This issue was licensee identified
through corrective actions to address previous escalated enforcement action. The
licensee was unable to complete the TS surveillance requirements or to justify a
basis for enforcement discretion to permit additional time to complete the required
testing. Operators safely performed a TS required shutdown on January 31.
(Section 01.2)
e The TS surveillance test program review team identified numerous instances where
existing procedures did not properly implement TS surveillance test requirements.
The review project began slowly due to resource limitations. Additional staffing
since November 1997, has improved both the speed and comprehensiveness of
reviews. Over thirty potential testing deficiencies were identified this report period
and properly resolved. Several of the identified discrepancies required the units to
enter TS Limiting Conditions of Operation (LCO) shutdown action statements, which
operators properly implemented. Unit 1 shut down on January 31, due to missed
TS required surveillance tests and remaineo shut down at the close of the period to
resolve additional testing issues. The management decision to maintain the unit
shut down pending resolution of additional testing issues was appropriate. (Section
01.3) ,
e Unit 1 operators demonstrated a good questioning attitude and identified a problem
with the feedwater flow instruments during startup activities on January 21.
Operations and maintenance resolution of the issue was adequate. However, failure
to document TS 3.03 and 3.3.1.1 LCO action entries / exits was a violation. '
Although the Nuclear Shift Supervisor (NSS) was aware of the TS LCO applicability
and implemented the applicable TS LCOs, this event demonstrated continued
logkeeping problems and weaknesses in shift turnover during periods of increased
control room activity. (Section 04.1)
e; . Operations staff worked large amounts of overtime during the past year, but hours
were carefully tracked to manage the use of overtime. Overtime deviation
authorizations were generally properly processed in accordance with procedures.
Low shift staffing levels were being addressed by the licensee, but continued to be
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a problem, due in part to the long period of time required for training and licensing
new operators. Management of overtime and workload continued to challenge the
licensee, compounded by the extended outages of the past year. However, no
safety related events occurred that were attributed to fatigue or excessive
workload. (Section 06.1)
e inadequate operations procedures resulted in failure to implement applicable TS LCO
action statements as documented in two recent licensee event reports. Both issues
were licensee identified and corrected. (Sections 08.1 and 08.2)
Maintenance
o The procedural guidance / management control to ensure important instrumentation
(including feedwater flow instrumentation) is returned to service was a weakness.
The corrective actions comprehensively addressed the weakness. Maintenance
response to the identified problem with the feedwater flow transmitter was
adequate. (Section M1.2)
e On January 27,1998, technicians used incorrect input values when calibrating Unit
1 power range neutron flux instrumentation which affects the overtemperature-delta
temperature reactor protection system trip setpoint. This error remained undetected
prior to restoring the equipment to operation. The inspectors concluded that post-
maintenance reviews by Maintenance and Operations Department personnel, prior
to restoring equipment to an operable status were inadequate. (Section M1.3)
e Electricians demonstrated appropriate care when handling the station battery cells.
However, work instruction detail was inadequate, supplemental work instructions
were not properly controlled, and a fire barrier was not properly controlled.
Electricians failed to properly reattach an intercell connector following battery cell
replacement. Prompt action in response to smoke emanating from the battery
during a full capacity discharge test prevented significant battery damage.
(Section M2.1)
Eneineerina
e The temporary modification to jumper out a degraded cell from the 2-1 station
battery was technically sound and properly evaluated. Engineers demonstrated a
good working knowledge of the supporting engineering calculations. The
subsequent management decision to replace six battery cells demonstrated an
appropriate safety perspective. Post-maintenance testing following replacement of ,
six battery cells was generally good. An exception was that individual cell voltage !
acceptance criteria to support battery operability following restoration from the
discharge capacity test was not specified. (Section M2.1)
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e Engineers' determined that several assumptions previously used for various design - I
basis accident control room and exclusion area boundary radiological dose
assessments were non-conservative. Licensee assessment of the issue including
extent of condition reviews was comprehensive. However, communications
between radiation engineers and design engineers were inconsistent which delayed
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issue resolution and design change implementation by several weeks. The licensee
identified three associated unreviewed safety questions and promptly submitted
associated regulatory documents for NRC review and approval. Safety evaluations
and Nuclear Safety Review Board assessment of the issues were excellent.
(Section E1.1)
- The modifications made to the Unit 1 rod position indication system resulted in
improved monitoring and ability to maintain and/or to return quickly to technical
specification limits. The post installation testing was closely monitored and
controlled. (Section E1.2)
- Reliance on personnel knowledge and communications in lieu of formal procedural
controls to address a known TS deficiency, the response time for the 4.16 Kv loss
of voltage trip feeder function, was poor. The resulting TS violation did not
represent a significant safety event, but was considered a weakness in addressing a
long time known deficiency. (Section E8.1)
- The excellent questioning attitude by the operator and engineers that led to the
identification of the control room emergency venti!ation system design deficiency
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and comprehensive corrective actions in addressing the deficiency were the basis
for the NRC exercise of enforcement discretion. (Section E8.2)
Plant Sucoort
- The amount of radiologically contaminated area within the protected area was
significantly reduced during 1997 (currently less than 1 percent). This performance
improved equipment accessibility to operations and maintenance personnel.
(Section R2)
- The licensee is maintaining an effective program, and management is competently
administrating the security program. Audits were thorough and in-depth, alarm
station operators were knowledgeable of their duties and responsibilities, and
communications requirements were being performed in accordance with the NRC-
approved physical security plan (the Plan). Assessment aids, in general, had good
picture quality and excellent zone overlap. However, due to long fields of view in
several zones, the alarm station operator's ability to properly assess the cause of an
alarm would be limited if it were not for the alarm station operator's usage of the
video capture system as an enhancement to the assessment program.
Personnel, packages, and vehicles were being properly searched prior to protected
area access. Effective access controls were in place, which included a self-
assessment program, for identifying, resolving, and preventing programmatic
problems. Security training was performed in accordance with the NRC-approved
training and qualification (T&O) plan.
As an enhancement to the inspection, the UFSAR initiative, Section 13.7 of the
Plan, titled, " Protection of Safeguards information," was reviewed. The inspectors
determined by observations and procedural reviews, that safeguards information
was being controlled and maintained as required in the Plan. (Sections S1 - S7)
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TABLE OF CONTENTS
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EX EC UTIVE SU M MA RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . i
TABLE O F CO NTE NTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iv j
l. Operations .................................................... 1 ,
O1 Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 1
01.1 General Comments (71707) ........................... 1 I
O 1.2 Unit 1 TS Required Shutdown . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.3 Multiple TS 3.0.3 Entries due to Missed TS Surveillance Tests . . . 4 ,
04- Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 6 /
04.1 Operational Response to Discovery of Feedwater Transmitters isolated
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06 Operations Organization and Administration . . . . . . . . . . . . . . . . . . . . . 7
06.1 Control of Overtime Hours and Workload . . . . . . . . . . . . . . . . . . 7
08 Miscellaneous Operations issues (71707,92700) . . . . . . . . . . . . . . . . . 9 )
08.1 (Closed) Licensee Event Report (LER) 50-334/97-041 ......... 9
08.2 (Closed) Licensee Event Report (LER) 50-334/97-042 . . . . . . . . 10
l l . M ai nt e n a nc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
M1 Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11
M1.1 Routine Surveillance Observations (61726) . . . . . . . . . . . . . . . . 11
M1.2 Isolation of Feedwater Transmitters During Startup . . . . . . . . . . 11
M1.3 incorrect Data Entered During Power Range Instrument Calibration
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M2 Maintenance and Material Condition of Facilities and Equipment . . . . . . 14
M2.1 Inoperable 125 Volt DC Station Battery 2-1 ............... 14
lil . E ng ine e ri ng . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
E1 Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
E1.1 Non-Conservative Radiological Dose Assessment for Design Basis
Accidents (DBA) .................................. 18
E1.2 Startup Testing and Combustion Engineering Rod Position Indication
(C ERPI) Te sting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
E8 Miscellaneous Engineering issues (37551,92700,92902) . . . . . . . . . . 21 4
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E8.1 (Closed) Licensee Event Report (LER) 50-412/97-006 . . . . . . . . 21
E8.2 (Closed) Unresolved item 50-334 and 412/97-09-02 . . . . . . . . . 23
E8.3 (Closed) Licensee Event Report (LER) 50-412/97-008 . . . . . . . . 24
E8.4 (Discussed) Violation EA 50-412/97-517 01013 . . . . . . . . . . . . 24
E8.5 (Closed) eel 50-412/9 7-07-0 3 . . . . . . . . . . . . . . . . . . . . . . . . . 24
I V. Pl a nt Su pport . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
R2 Status of RP&C Facilities and Equipment (71750) . . . . . . . . . . . . . . . . 24 i
L1 Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 j
S1 Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 25 ;
S2 Status of Security Facilities and Equipment . . . . . . . . . . . . . . . . . . . . . 26 l
33 Security and Safeguards Procedures and Documentation . . . . . . . . . . . 27 j
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S3.1 Review of Updated Final Safety Analysis Report (UFSAR) . . . . . . 27
S4 Security and Safeguards Staff Knowledge and Performance . . . . . . . . . 27
SS Security and Safeguards Staff Training and Qualification . . . . . . . . . . . 28
S6 Security Organization and Administration . . . . . . . . . . ........... 28
S7 Quality Assurance in Security and Safeguards Activities ........... 29
V. Ma nagemen t Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
X1 Exit Meeting Sum m ary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
X4 Duquesne Light Company Managernent Reorganization ............ 31
PARTIAL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
INSPECTION PROCEDURES USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
ITEMS OPENED, CLOSED AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
LIST O F ACRO NYM S U SE D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
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Report Details
Summary of Plant Status
Unit 1 began this inspection period in Mode 3 (hot standby) following the 12th refueling
outage. On January 4, Unit 1 was cooled down to Mode 5 (cold shutdown) until Class
1E/non-Class 1E electrical separation issues associated with the secondary process racks
could be reviewed and resolved. The process rack issue was documented in NRC
Inspection Report Nos. 50-334 and 412/98-80. On January 20, Unit 1 entered Mode 2
(startup) and commenced low power physics testing. Unit 1 entered Mode 1 (power
operation) on January 21, and the main generator was synchronized to the grid on January
22, marking the end of the refueling outage (118 days). Unit 1 reached full power on
January 28. On January 31, Unit 1 performed a Technical Specification 3.0.3 required
shutdown after DLC determined that valve position verifications and stroke testing for
some reactor plant component cooling and river water system valves had not been
completed in accordance with surveillance requirements. Unit 1 entered Mode 5 on
February 1.
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Unit 2 began this inspection period in Mode 5 (cold shutdown) in a forced outage awaiting
resolution of Control Room Emergency Air Cleanup and Pressurization System issues. Unit
2 remained in the forced outage awaiting resolution of the process rack and valve position
verification and stroke testing issues mentioned above for Unit 1.
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l. Operations
01 Conduct of Operations
01.1 Gengtal Comments (71707)' l
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Using Inspection Procedure 71707, the inspectors conducted frequent reviews of I
ongoing plant operations. In general, the conduct of operations was professional l
and safety-conscious; specific events and noteworthy observations are detailed in l
the sections below. l
01.2 Unit 1 TS Reovired Shutdown
a. Insoection Scoce (71707,92901,92903,93702) i
On January 30,1998, Unit 1 operators declared both trains of the reactor plant ;
component cooling (CCR) and river water (RW) systems inoperable and as a result i
performed a TS required shutdown on January 31. The inspectors reviewed the
basis for the shutdown and associated licensee activities to evaluate licensee
resolution of the issue.
' 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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b. Observations and Findinas
Missed TS Surveillances s
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Since June 1997, the licensee has been performing a detailed review of TS
surveillance requirements to verify both units are properly implementing all
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applicable TS surveillinces. This effort was initiated as a corrective action to
programmatic weaknesses previously addressed by escalated enforcement action
s EA 97-255. About January 20,1998, the TS surveillance test program review.-
team identified a potential discrepar.ty concerning which Unit 1 CCR and RW valves
and Unit 2 component cooling primary (CCP) and service water (SWS) system
valves were tested to meet various TS requirements. TS 4.7.3.1.b (c) and
4.7.4.1.b (c) require valve position verification every 31 days, and power operated
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valve cycling every 18 months for system valves that service " safety related -
equipment." The central issue, was how the licensee determined which system
valves herviced safety related equipment. After further research, the issue was
raised to station management on January 28.
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'The review team identified and promptly resolved two testing discrepancies.
Beyond this, the team determined that existing station procedures properly tested >
s system valves which serviced safety-related equipment which provided a design
basis accident (DBA) mitigation function or ensured the ability to shut down the
reactor and maintain it in a safe shutdown condition following a DBA. Engineering
and licensing personnel assisted the review team in further assessing this issue and
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proposed that the existing test program did not satisfy the scope of testing required
by TS. Specifically, the definition of " safety related equipment" had been too
narrowly interpreted. Operations Department personnel accepted the team position,
that existing procedures properly te,sted the valves required by TS 4.7.3.1.b (c) and
4.7.4.1.b(c). The' inspectors reviewed the TS requirements and questioned
Operations management concerning their interpretation of the TS.
On January 30, station management determined that the existing scope of valves
tested was too narrowly focussed. All equipment identified as safety related in the
station Material Equipment List (MEL) should be considered safety related
equipment. This included equipment relied upon to maintain the reactor coolant
system pressure boundary integrity following a DBA. The licensee concluded that
additional valves required testing to meet the requirements of the current Beaver -
Valley Unit 1 and 2 TSs.
At 7:40 p.m. on January 30,1998, operators declared both trains of CCR'and RW
inoperable due to failure to comply with TS 4.7.3.1.b (c) and 4.7.4.1.b (c)
surveillance testing requirements. Operators immediately entered TS 3.0.3 and TS
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4.0.3 and initiated efforts to complete surveillance test requirements which had :
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been missed. The inspectors independently determined that the decision to apply
TS 3.0.3 and TS 4.0.3 was correct, in that the licensee had previously failed to test -
, -_ valves required hy their TS.
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The inspectors observed portions of the valve position verification activities. The )
Nuclear Shift Su9ervisors (NSS) at both Unit 1 and 2 properly oversaw the !
verification activities. Over the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, using the revised interpretation of
the TS requirements, the review team identified approximately 110 additional ;
valves inside containment (for Units 1 and 2 combined) and several hundred valves !
outside containment which required surveillance. In addition, up to 37 Unit 1 power l
operated valves required further review to determine whether the 18 month valve l
cycle requirement was satisfied. By noon on January 31, the reverification of Unit
1 CCR and RW valve positions outside containment was nearly complete, with all 4
found in their correct position.
Consideration of Reauest for Enfoicement Discretion
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A conference call was conducted on January 31, between Duquesne Light l
Company (DLC) and the NRC to discuss the TS surveillance testing issue and DLC's
progress toward establishing a basis for requesting enforcement discretion to allow
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additional time to complete the surveillance requirements of TS 4.7.3.1.b (c) and ;
4.7.4.1.b(c). During this conference call, the NRC staff identified severalissues j
which had not been sufficiently addressed to warrant enforcement discretion.
These included: (1) additional review of maintenance records to verify the status of -)
valves inside containment; (2) determine which power operated valves outside
containment require stroking; (3) complete a safety consequence assessment of the )
issue based on fi dogs of the two previous items; and, (4) on-site safety committee
review. DLC management agreed that those issues required closure prior to !
requesting enforcement discretion.
The conference call ended, and DLC continued to evaluate the valves in question.
The inspectors observed licensee activities being performed to evaluate the potential
safety consequences. Within the next few hours, DLC management concluded that :
insufficient time remained for DLC to properly prepare and review justification for
enforcement discretion. From January 30 to 31, the inspectors noted that
communication weaknesses among the various departments made it difficult for the i
licensee to properly establish a basis for enforcement discretion. Management j
correctly assessed the situation and directed that Unit 1 be shut down. In addition, i
senior management conducted a critique of activities performed to support i
requesting NRC enforcement discretion. The inspectors noted this critique was a
good initiative to improve the licensee's ability to resolve similar issues in the future. I
Unit Shutdown '
Unit 1 operators began a TS required shutdown at 6:04 p.m. on January 31. The
unit achieved cold shutdown (Mode 5) at 5:35 p.m. on February 1. Unit 0 remained
in Mode 5 since an unrelated TS required shutdown on December 16,1997. The
inspectors monitored portions of the shutdown. The licensee properly reported the l
event as required by 10 CFR 50.72 and safely completed tM sutdown within the l
time specified by TS 3.0.3. Both units remained in mode 5 at the close of the j
inspection period. j
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Failure to perform the surveillance testing requirements of.TS 4.7.3.1.b (c)'and
4.7.4.1.b (c) was a violation. This violation was licensee identified through
corrective actions taken to address a previous escalated enforcement action (EA 97-
255) documented in NRC Inspection Report Nos. 50-334(412)/97 02 and NRC
letter to Mr. J. Cross dated July 3,1997. The root cause for this violation is si'milar
to that for the initial problem. The safety significance of the initial problem remains i
unchanged. immediate corrective actions were properly implemented and long-term )
actions to preclude recurrence are in progress with a completion date of April 1,
1998. Therefore, consistent with Section Vll.B.4 of the NRC Enforcement Policy
enforcement discretion is exercised and no violation will be issued (NCV 50-334,
412/97 11-01).
c. - Conclusions
. On January 30,1997, Unit 1 operators declared both trains of CCR and RW
inoperable due to failure to test system valves as required by TSs. Previous
interpretation of the TS was too narrowly focussed, as it did not address all system ]
valves which service safety related components. This issue was licensee identified {
through corrective actions to address previous escalated enforcement action. The
licensee was unable to complete the TS surveillance requirements or to justify a
basis for enforcement discretion to permit additional time to complete the required
testing. Unit 1 operators safely performed a TS required shutdown on January 31.
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01.3 Multiole TS 3.0.3 Entries due to Missed TS Surveillance Tests
a. Inspection Scope (71707,92901. 92903)
Since June 1997, the licensee has been performing a detailed review of TS
surveillance requirements to verify both units are properly implementing all
applicable TS surveillances. This effort was initiated as corrective action to
programmatic weaknesses previously addressed by escalated enforcement action
EA 97-255. During this report period, the review team identified numerous
instances where existing procedures did not properly implement TS surveillance test
requirements. The inspectors observed licensed operator activities to evaluate their
response to team identified issues.
b. Observations and Findinas
< The inspectors noted that the TS review project started slowly as resources were
used to address'other issues. Even with minimal resources, several TS surveillance
testing discrepancies were identified between June and November 1997. In late .
' November, additional resources were added to the TS surveillance test program
review team. The team then included six senior reactor operator (SRO) licensed
personnel, including four contractors, all of which had outside industry experience
from other utilities. Based on these reviews, the team, supported by various other
departments, identified numerous TS surveillance requirements which were not {
n being properly implemented.' Approximately 30 potential testing discrepancies were ]
identified during this report period. The inspectors observed team review activities,
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condition report processing, and licensed operator actions based on the issues
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- raised by the team. Several procedures were revised to clarify wording and/or to
reduce the potential for missed surveillance tests. In addition, several longstanding ,
missed TS surveillances were identified. Several issues required entry into TS 3.0.3
and TS 4.0.3 or would have required entry if the unit was not already in shutdown
mode. These issues are listed in the following table:
UNIT DATE TS 3.0.3 TS CR# CONDITION REPORT
TS 4.0.3 REQUIREMENT
1 1/28 3.0.3/4.0.3 4.1.2.2.c & 980140 Boron injection Flow Path /ECCS
4.5.2.f.1 Verification :
1 1/29 3.0.3 4.6.2.1.a.1 980152 QS Purnp Bearing Cooling Valve )
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Verification l
% 1/30 2.0.3/4.0.3 4.7.3.1.b' &- 980169 Valve Position / Stroke Testing.
4.7.4.1.b* CCR/RW CCP/SWS !
% 2/6 4.0.3 4.8.1.1.2.b.1 980248 EDG PM Requirement
2 1/12 4.0.3 4.6.3.1.2 980050 Containment isolation Check
g Valve Stroke Testing
Several additional TS surveillance testing issues were being evaluated by the
licensee at the close of the inspection period. _ The inspectors determined that
licensed operators properly applied TS 3.0.3 and 4.0.3, and made 10 CFR 50.72
reports to the NRC when applicable. NRC enforcement action for these missed TS l
surveillances will be addressed through inspection closeout of VIO EA 97-255 and
associated LERS when licensee corrective actions are complete.
c. Conclusiqng
The TS surveillance test program review team identified numerous instances where
existing procedures did not properly implement TS surveillance test requirements. l
The review project began slowly due to resource limitations. Review activities have
been comprehensive, and the rate of review has improved since additional resources '
were assigned in November 1997. Numerous testing deficiencies were identified
this report period and properly resolved. Several of the identified discrepancies i
required the units to enter TS LCO shutdown action stataments, which operators
properly implemented. Unit 1 shut down on January 31, due to missed TS required ,
surveillance tests and remained shut down at the close of the period to resolve i
additional testing issues. The management decision to maintain the unit shutdown
pending resolution of additional testing issues was appropriate.
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04 Operator Knowledge and Performance
04.1- Ooerational Response to Discovery of Feedwater Transmitters Isolated
a. Inspection Scooe (71707; 92901)
. The inspectors reviewed Unit'1 operators' response to steam generator (SG)
feedwater flow transmitter problems through observations and interviews with the
operations crew, operations management, and instrumentation and control (l&C)'
. personnel.
b. Observations and Findinas
During preparations for synchronization to the grid on January 21, the operators
identified that both 'A' SG feedwater flow transmitters were not responding as
expected (see Section M1.2 for further details). The Nuclear Shift Supervisor (NSS)
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promptly dispatched l&C technicians who determined that the two transmitters
were isolated. With both flow transmitters isolated, the unit was below the
minimum number of operable channels and was in TS 3.0.3. After extensive
interviews with licensee personnel, the inspectors determined that the operators
recognized that having both channels out of service resu!ted in the TS 3.0.3 entry; j
however, operations staff failed to log the entries and exits into TS 3.3.1.1 and j
TS 3.0.3. The TS 3.3.1.1 Limiting Condition of Operation (LCO) actions were -I
appropriately !mplemented as the channels were identified as isolated and remained
in effect until the transmitters were unisolated, filled, and vented. The first
transmitter was unisolated, filled, and vented within one hour. Flow readings
responded upward, but remained relatively low. Both feedwater instruments were
unisolated, filled,' vented, and calibrated within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The NSS's ,
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decision to ensure that the calibration procedure was performed after return to
service of the first isolated feedwater transmitter prior to synchronization was an ,
appropriate decision. . However, the inspectors determined that the basis for -i
declaring the individual feedwater flow channels operable was not documented, and j
was questionable, based on the response of the channels after being placed back in
service. The absence of documentation in the shift operations logs contributed to i
this weakness.
Based on the interviews and review of the control room logs, the inspectors
determined that the control room staff failed to log applicable TS LCO entries and !
exits as required by procedure %-OM-48.5.A. In addition, the offgoing NSS and !
assistant NSS signed off their watch (performed turnover) without properly
certifying the accuracy of oporhtions log entries made during their shift as required
by procedures %-OM-48.1.C anc' %-OM-48.5.A. The inspectors identified that ;
contributing causes to this failure to log LCO entries / exits were increased control
room activity to support startup activities and shift turnover occurring during the l
identification of this issue. Management supervision was present in the control
room but did not provide oversight to ensure documentation of the activities. The !
licensee was tracking the failure to log TS entries and exits in their corrective action j
program under CR 980290. ;
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The inspectors expressed concern that this event represented a continued problem
regarding the accuracy of shift operating logs, and the adequacy of shift turnover
during periods of increased control room activity. Initial corrective actions,
including development of an operator training element regarding lessons learned i
from this event and increased involvement by on-shift reactor operators appeared j
well directed, but remained conceptual at the close of this inspection report period. )
Failure of operators to log TS LCO entries and perform proper shift turnover is a
violation of TS 6.8.1.a, which requires that written procedures and instructions be i
established, implemented and maintained regarding log entries and shift turnover
(VIO 50-334/97-11-02).
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c. Conc!usions ]
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Unit 1 operators demonstrated a good questioning attitude and identified a problem j
with the feedwater flow instruments during startup activities. Operations and j
maintenance resolution of the issue was adequate. However, failure to document
the TS 3.0.3 and 3.3.1.1 LCO entries / exits was a violation. l
06 Operations Organization and Administration
06.1 Control of Overtime Hours and Werkload
a. Insoection Scoce 171707)
Inspectors reviewed the working hours and use of overtime by operations staff
during 1997, with attention to the Unit 1 refueling outage, to verify compliance
with TS 6.2.2.f. The review included condition reports, records maintained by the
operations shift administrative assistant and Director, Administrative Services, and
discussions with the administrative assistant and various operators.
b. Observations and Findinas
Limitations on unit staff working hours required by TS 6.2.2.f were implemented by
Nuclear Power Division Administrative Manual (NPDAM) Directive 1.2.8, "Use of
Overtime," Rev. 4, and Nuclear Power Division Administrative Procedure (NPDAP)
2.15, " Administrative Controls," Rev. 3. The inspectors noted that the
administrative assistant was knowledgeable of the TS overtime guidelines and
maintained thorough tracking of operations staff work hours. The average number
of overtime hours worked in 1997 for Unit 1 and 2 reactor operators, nuclear
operators, senior reactor operators (SROs), and shift technical advisors (STAS)
combined was 580 hours0.00671 days <br />0.161 hours <br />9.589947e-4 weeks <br />2.2069e-4 months <br /> / person. Reactor operators and nuclear operators
averaged the most overtime (650 hours0.00752 days <br />0.181 hours <br />0.00107 weeks <br />2.47325e-4 months <br /> / person). Unit 1 SROs worked an average
of about 486 hours0.00563 days <br />0.135 hours <br />8.035714e-4 weeks <br />1.84923e-4 months <br /> of overtime, and Unit 2 SROs worked about 229 hours0.00265 days <br />0.0636 hours <br />3.786376e-4 weeks <br />8.71345e-5 months <br /> of
overtime. Operations staff overtime hours were carefully tracked to manage the use
of overtime.
a
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Deviations from the TS overtime limits were reviewed and authorized in accordance
with NPDAP 2.15. Inspectors reviewed the " Request for Overtime Deviation
Authorization" forms (Attachment 2 of NPDAP 2.15) maintained by Administrative
Services for the site for 1997. About 20 of a site total of 188 request forms were
for operations staff. In general, the requests were in accordance with NPDAP 2.15
and provided reasonable justification for exceeding the overtime guidelines. j
However, at least 25 requests of the total were approved after the actual overtime !
work, including about 14 for operations staff. This was contrary to NPDAP 2.15
and NPDAM Directive 1.2.8 requirements, which required that overtime deviations
be authorized by the Unit General Manager / Manager prior to the overtime
assignment. The inspectors determined that the majority of the 25 requests were
for short durations (i.e.,1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />) and represented unforeseen circumstances.
Personnel delays exiting the radiologically controlled area (RCA) due to gaseous !
activity (RADON) decay were a common example.
I
Only three condition reports were written sitewide in 1997 to docurnent use of
overtime prior to obtaining authorization. The inspectors did not find any egregious
human performance errors due to fatigue or excessive work hours and concluded
that this was an administrative weakness. The failure to properly implement
procedures required by TS 6.2.2.f constitutes a violation of minor significance and
]
is being treated as a Non-cited Violation, consistent with Section IV of the NRC
Enforcement Policy (NCV 50 334 and 412/97-11-03).
1
Review of the shift staffing matrix (non-outage six shift rotation with 12 operators ;
pc r shift) showed that there was an adequate number of personnel to fill all shift i
positions, except on Tuesday of each week, when a shift rotation occurred. The l
number of personnel did not support any absences for reasons such as sickness,
vacation, holidays, convenience days, or the Tuesday shift rotation. All absences
were filled in with overtime.
The issue of shift staffing has been a long-standing concern of both the NRC and
licensee and was documented in Systematic Assessment of Licensee Performance
Report 50-334 and 412/96-99,due to the potential adverse impact of excessive
workload for control room SROs and STAS. TS 6.2.2.f states that, " Administrative
procedures shall be developed and implemented to limit the working hours of unit
staff who perform safety related functions... The objective shall be to have
operating personnel work a normal 8-hour day,40-hour week while the plant is
operating." Licensee management has taken steps to address the issue; however,
the length of time required to train and license additional staff has made it a long-
term problem. The difficulty of scheduling staff hours was compounded by the
extended outages over the past year. Three additional SROs at Unit 1 and four at
Unit 2 were added in 1997. In addition, three new Unit 1 SROs were licensed this
period. In 1998, three Unit 1 SROs (April), four Unit 2 SROs (August), and five Unit
2 ROs (August) are scheduled to take their license exams. Also, a class of 14 ,
nuclear operators (non-licensed) began training this period. While no events have I
occurred that have been attributed to fatigue or excessive workload, management l
of overtime and workload continued to be a challenge. l
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c. Conclusions
Operations staff worked significant amounts of overtime, but hours were carefully
tracked to manage the use of overtime. With some minor exceptions, overtime
deviation authorizations were properly processed in accordance with NPDAP 2.15. -
Low shift staffing levels were being addressed by the licensee, but continued to be- .,
,
a problem, due in part to the long period of time required for training.and licensing {
.new operators._ Management of overtime and workload continued to challenge the
licensee due to low shift staffing levels, compounded by the extended outages of
the past year. However, no events occurred that were attributed to fatigue or
. excessive workload.
08 Miscellaneous Operstions !ssues (71707,92700) _ .j
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08.1 (Closed) Licensee Event Remrt (LER) 50-334/97-041: Failure to Remove Power
from the Isolated Reactor Coolant System (RCS) Loop Isolation Valve Operators >
Withiri One Hour as Required by TSs. .
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The inspectors reviewed the LER through field inspection activities and in office
reviews. The licensee committed to perform a TS surveillance review as part of
their response to Notice of Violation EA 97-255. As part of the ongoing review, the
licensee found that no documentation existed to show that power was removed
from the B and C RCS loop isolation va5ve motor operators within one hour of loop
isolation on September 30,1997, as required by TS 3.4.1.4.2.
The TS bases states that, "An RCS loop is considered isolated in Modes 5 and 6
- whenever the hot and cold leg isolation valves on one RCS loop are both in the fully
closed position at the same time." Following TS amendments to Unit 1 in March
1996 and Unit 2 in April 1996, the operating procedures at both units were
improperly changed to state that, "an RCS loop is considered an isolated loop when
both isolation valves are closed for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or when both loop isolation valves are
closed and the loop has started to be drained (TS 3.4.1.5). The loop isolation
valves are required to be de-energized when the loop is an isolated loop (TS 3.4.1.4.2). If the loop isolation valves are not de-energized before the loop . .
becomes an isolated loop, TS 3.4.1.4.2 action will be entered." The cause of the )
event was inadequate implementation of the TS amendments.
Upon discovery, the licensee performed a review of loop isolation evolutions back to
January 1995. Only the evolutions performed on September 30,1996, could not
be documented to be in compliance with the one hour TS requirement. There were
no safety consequences to the event. Loop restorations were performed in
accordance with proper procedures to ensure that no undesirable reactivity changes
occurred. Inspectors reviewed the applicable Unit 1 and Unit 2 procedures to verify
that they had been revised to conform to the TS bases and TS 3.4.1.4.2. Also, the
licensee revised administrative procedure NPDAP 7.1, " Technical Specification
Control Program," on May 30,1997, to require a Safety & Licensing Department
review of procedure, manual, or administrative controls that are to be changed as
.part of a license. amendment implementation.
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Failure to comply with TS 3.4.1.4.2 was a violation of NRC requirements. This
violation was licensee identified through corrective actions taken to address a
previous escalated enforcement action (EA 97-255) documented in NRC Inspection
Report Nos. 50-334(412)/97-02 and NRC letter to Mr. J. Cross dated July 3,
1997. The root cause for this violation is similar to that for the initial problem. The
safety significance of the initial problem remains unchanged immediate corrective
actions were properly implemented and long-term actions to preclude recurrence are
in progress with a completion date of April 1,1998. Therefore, consistent with
Section Vll.B.4 of the NRC Enforcement Policy enforcement discretion is exercised
and no violation will be issued (NCV 50-334/97-11-04).
08.2 (Closed) Licensee Event Report (LER) 50-334/97-042: Failure to Perform Axial Flux
Difference (AFD) Monitor Surveillance as Hequired by Technical Specifications.
The inspectors reviewed the LER through field inspection activities and in office
reviews. The licensee committed to perform a TS surveillance review as part of
their response to Notice of Violation EA 97-255. As part of the ongoing review, the
licensee found that TS surveillance requirement 4.2.1.1.a.2 was not being complied
with since September 1993. The requirement states that, "The indicated axial flux l
difference shall be determined to be within its limits during power operation above I
15 percent of rated thermal power by monitoring the indicated AFD for each I
operable excore channel at least once per hour for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after restoring
the AFD Monitor Alarm to operable status." The licensee determined that
monitoring of the AFD had been accomplished by automatic data acquisition
utilizing the process computer, instead of manuallogging.
The cause of the event was a misinterpretation of the TS requirement which was
then implemented in the procedures for performing the surveillance.
There were minimal safety consequences to the event. In order to substitute l
computer AFD monitoring for the hourly manuallogging following restoration of the
AFD to service, it was required that there be no penalty minutes for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior
to, and during, the AFD monitor reinoval from service time period. Upon return to
service, the AFD was reset to zero minutes. This method eliminated any chance for
bad data to affect the AFD calculation. Based on this, the number of penalty
minutes accumulated prior to, during, and following restoration of the AFD monitor
was always known and accurate.
Inspectors reviewed the applicable operating procedures and surveillance tests to j
verify that they had been revised to reflect the correct TS surveillance requirement
and verified that the incorrect TS interpretation had been removed. The licensee's
corrective actions included a review of other TS interpretations for applicability. .
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Failure to comply with TS 4.2.1.1.a.2 was a violation of NRC requirements. This
violation was licensee identified through corrective actions taken to address a l
previous escalated enforcement action (EA 97-255) documented in NRC Inspection l
Report Nos. 50-334(412)/97-02and NRC letter to Mr. J. Cross dated July 3, I
1997. The root cause for this violation is similar to that for the initial problem. The
safety significance of the initial problem remains unchanged. Immediate corrective ,
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actions were properly implemented and long-term actions to preclude recurrence are
in progress with a completion date of April 1,1998. Therefore, consistent with
Section Vll.B.4 of the NRC Enforcement Policy enforcement discretion is exercised
and no violation will be issued (NCV 50-334/97-11-05).
II. Maintenance
M1 Conduct of Maintenance
M 1.1 hutine Surveillance Observations (61726)
The inspectors observed portions of selected surveillance tests. Tests reviewed and
observed by the inspectors are listed below.
- 1 RST-2.1 Initial Approach to Criticality After Refueling, Rev. 3
- 1 RST-2.2 Core Design Check Test, Rev. 2
Both RSTs were conducted as infrequently performed tests or evolutions (IPTE)
during Unit 1 restart from the refueling outage. Added precautions and
management oversight were appropriately established. The inspectors noted good.
coordination between Operations, instrument & Controls (l&C), and reactor
engineering staff.
- 1 RST-2.3 Nuclear Power Range Calibration, Rev. 3
- 10ST-26.4 Pedestal Checks, Rev. 4
- 10ST-36.1 Diesel Generator No.1 Monthly Test, Rev.18
- 2OST-2.3 Nuclear Source Range Channel Functional Test, Rev. O
The surveillance testing was performed safely and in accordance with proper
procedures. The inspectors noted that an appropriate level of supervisory attention
was given to the testing, depending on its sensitivity.
M1.2 Isolation of Feedwater Transmitters Durino Startuo
a. Inspection Scope (71707,92901,92902)
Technicians failed to unisolate two safety related feedwater flow transmitters prior
to Unit 1 startup. The inspectors reviewed records and conducted interviews to
evaluate licensee resolution of this event.
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b. Observations and Findinas
During startup of the Unit 1 secondary plant on January 21, operators noted that
steam generator "A" feedwater flow indicators were not responding. The plant was
.
operating at 5-10 percent power. Feedwater flow transmitters FT-FW-476 and 477
were found to be isolated. As immediate corrective actions, the transmitters were
unisolated and vented before the transmitters were returned to service. The
remaining feed flow transmitters were verified to be unisolated. The issue was
documented on Condition Report 980097. These transmitters provide an input to
the " steam /feedwater flow mismatch and low steam generator water level" reactor
protection function (TS 3.3.1.1, Table 3.3-1, functional unit 15), and to the
Anticipated Transient Without Scram Mitigating System Actuation Circuitry
(AMSAC) circuit (when above 40 percent turbine load).
The licensee investigation concluded that the transmitters were isolated on
November 16 during 1MSP-24.26,"F-1FW-476, Loop 1 Feedwater Flow Channel IV
Calibration," and 1MSP-24.27,"F-1FW-477, Loop 1 Feedwater Flow Channel lli
Calibration." The transmitters were not filled and vented after the MSPs, because
the feedwater system was drained for outage work. The MSPs required that if the
transmitters were not filled and vented at the end of the procedure (because of
existing plant conditions), the l&C supervisor should be notified. The supervisor
was responsible for tracking the information to ensure that the transmitters were
properly returned to service at a later time when plant conditions permitted, in this
instance, the information was either not communicated or not retained. This was
determined to be the root cause of the event. The inspectors determined that the
informal procedural control for tracking an isolated transmitter was poor and was
not adequately implemented.
A potential barrier to operating with the transmitters isolated was 1MSP-4.03, "ESF
and Miscellaneous Safety Related instrumentation Valve Alignment and Calibration
Verification." The purpose of MSP-4.03 was to assure proper alignment of key
instruments whose monitored and process function is not or cannot be routinely 9
verified through performance of surveillance tests or observed response during
heatup. However, MSP-4.03 was completed before MSP-24.26 and MSP-24.27
were done, and there was no surveillance schedule interlock or sequencing
requirement between the MSPs.
As corrective action, over 100 maintenance procedures were revised to specifically
require that when equipment is not properly returned to service (for example not
vented and filled), a tracking entry is made in the TS Turnover Checklist and out of
. service (OOS) stickers are placed on the corresponding control room indications.
. These actions were added to the previous required action to inform the maintenance
supervisor.1 Failure to ensure the feedwater flow channels were in service prior to
1
entry into Mode' 2 was a violation of TS 3.3.1.1. 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- .
@ 334/97-11-06). i
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c. Conclusion
The inspectors concluded that procedural guidance / management control to ensure
safety-related instrumentation is returned to service following maintenance was a
weakness. The corrective actions comprehensively addressed the weakness.
Maintenance response to the identified problem with the feedwater flow transmitter j
was adequate.
M1.3 incorrect Data Entered Durina Power Ranae Instrument Calibration !
a. Insoection Scone (92902)
Technicians used incorrect values when calibrating Unit 1 power range neutron flux f
instrumentation. Operations personnel failed to recognize this error prior to
declaring the affected equipment operable. The inspectors reviewed records and
conducted interviews to evaluate licensee resolution of this issue. ]
!
b. Observations and Findinas
i
While performing 1MSP-2.04," Power Range Neutron Flux Channel N42 Refueling i
Calibration," during the Unit 1 power ascension program on January 27, instrument
and Controls (l&C) technicians used the wrong values while adjusting the detector
test signals for the overtemperature-delta temperature (OT Delta-T) trip setpoint.
The values were taken from an engineering data sheet attached to the MSP and ]
inserted into the body of the procedure. Instead of using detector test signals at 0
'
percent axial offset normalized to 120 percent power level, test signals for the O
percent axial offset normalized to 100 percent power level were inserted.
The error was discovered during a review of the MSP by the l&C support engineer
after the channel had been returned to service. He informed the nuclear shift !
supervisor (NSS), and operators declared the OT Delta-T channel cut of service in
accordance with TS 3.3.1.1, Table 3.3-1, functional unit 7. The calibration of N43
was in progress. As a result, two of the three OT Delta-T channels were out of
service, and Unit 1 entered TS 3.0.3. The calibration of N43 was satisfactorily l
completed 1.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> later, and TS 3.0.3 was exited. l&C technicians then re-
performed the N42 calibration satisfactorily to restore it to service. The issue was ]
documented on Condition Report 980139.
Licensee review of the data found that the calibration error was in the conservative
direction. The delta flux input to OT delta-T was larger than it would have been
with the correct data and would therefore have caused a larger delta flux penalty
than would have been generated by the correct data. Inspectors reviewed the ;
values generated by the data and agreed. At the time of the event, however, N43
was out of service, and an immediate determination of N42 operability could not be
made. The NSS conservatively entered TS 3.0.3 and took the appropriate actions.
Since the incorrect calibration data for N42 was conservative, the licensee i
concluded that an actual TS 3.0.3 condition did not exist. The inspectors agreed !
with the licensee's conclusion. l
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The root cause of the event was inadequate self-checking by the l&C technicians.
There was no requirement for independent verification of the values transferred
from the data sheet to the body of the MSP. A contributing factor was that '
supervisory review of the completed MSP was inadequate. Following completion of
the MSP by the two l&C technicians, the MSP was reviewed by the nuclear shift
supervisor (NSS). However, the NSS review only verified that the acceptance
criteria had been met and acknowledged the completion of the MSP. Following
completion of the MSP and a satisfactory channel functional test surveillance, the
NSS declared N42 operable and allowed N43 to be removed from service for
calibration. There was no requirement for a detailed MSP review before proceeding
with calibration of the next channel. The MSP was subsequently reviewed by two
l&C supervisors who failed to note the data translation error. The l&C support
engineer later noted the error during his routine MSP review.
1
The inspectors noted that immediate corrective actions were appropriate, the
interim evaluation on TS 3.0.3 entry was completed and final corrective actions j
were being tracked under the corrective action program (CR 980139). j
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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, Rev.2, February 1978." Appendix "A" includes l
procedures for performing surveillance tests, procedures, and calibrations of the
reactor protection system. Failure to conduct the calibration of N42 in accordance
with the MSP 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 50-334/97-11-07). j
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c. Conclusion I
On January 27,1998,l&C technicians used incorrect input values when calibrating I
Unit 1 power range neutron flux instrumentation which affects the overtemperature-
delta temperature reactor protection system trip setpoint. This error remained
undetected prior to restoring the equipment to operation. The inspectors concluded
that post-maintenance reviews by Maintenance and Operations Department j
personnel, prior to restoring equipment to an operable status were inadequate. j
M2 Maintenance and Material Condition of Facilities and Equipment j
i
M 2.1 Inocerable 125 Volt DC Station Batterv 2-1
a. Insoection Scooe (62707. 92902. 92903) ,
!
The 2-1 station battery was declared inoperable on January 26,1998, due to its
pilot cell (cell #40) voltage reading 2.05 volts. Unit 2 was in cold shutdown at the
time of discovery. The inspectors observed maintenance activities, interviewed j
maintenance and engineering personnel, and reviewed maintenance documentation j
to evaluate battery repair efforts.
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b. Observations and Findinas
Station Batterv Temocrary Modification
Pilot cell voltage dropped significantly since the previous quarterly surveillance test,
when voltage was 2.15 volts. The inspectors noted that the 2-1 battery was 13
years old, which was well within the 20 year vendor projected battery life. Based
on this unexpected voltage drop, engineers concluded that the pilot cell may have
begun to experience an internal fault and recommended jumpering out cell #40
using a temporary modification (TM). The inspectors reviewed TM 2-98-05, the
associated safety evaluation, engineering calculation 10080-E-201-1,and the
Updated Final Safety Analysis Report (UFSAR) sections 8.3 and 15.2. The 4
inspectors determined that TM 2-98-05 was technically sound and properly .ff
evaluated to modify the station battery to include 59 cells in lieu of 60 cells.
Engineers demonstrated a good working knowledge of the supporting engineering M
calculations.
The inspectors observed electricians moving the inoperable cell to an end of rack
position and repositioning operable cells in accordance with maintenance work
request (MWR) 69496. Electricians took appropriate care in moving the battery
cells and retorquing rack components in place to restore seismic stability. While
observing MWR 69496 work activities, the inspectors noted that the work
instructions did not specifically instruct that the intercell connector between cells
- 39 and #40 (the suspect faulted cell) be removed prior to connecting the interrack
connection to cell #39. The electrical supervisor stated that the work instructions ,
were sufficient since the connecting bolts were not long enough to attach the j
interrack connector to the cell electrode without first removing the intercell l
connector. In addition, electricians had sufficient system 1:nowledge to know they {
should first remove the intercell connector. The inspectors subsequently measured l
the bolts and connectors and determined that the interrack connector could indeed i
be connected over the intercell connector to the cell #39 electrode. The inspectors )
determined that work instruction detail was poor, in that it introduced the possibility j
that the battery may remain connected to the faulted cell (cell #40). l
The inspectors also noted that a separate sheet of paper, which discussed the job in
greater detail than the MWR work instructions, was available at the job site. This 1
sheet had no marking indicating that it was part of the MWR 69496 work package. l
The sheet clearly stated that the cell #39 to #40 intercell connector plate was to be j
removed prior to connecting the interrack connection to cell #39. The inspectors 1
asked whether this sheet was part of the MWR and whether it was part of the pre-
job brief. The work crew foreman informed the inspectors that the sheet was
neither a part of the MWH or the pre-job brief. However, the inspectors were later
informed by the electrical supervisor and the system engineer that this sheet was
intended for the work package and was part of the pre-job brief. The different i
responses indicated confusion over the source and use of this uncontrolled sheet of
instructions. The inspectors expiessed concern that uncontrolled wmk instructions ;
could get into the field and be used for job performance on safety olated I
maintenance activities without receiving appropriate reviews as part of the MWR
planning and authorization process. The Electrical Manager removed the l
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16
uncontrolled sheet from the field. The Maintenance Manager informed the
inspectors that planners were expected to verify that all work instructions were
clearly marked with the MWR number prior to issuance to the field. However, the
inspectors did not find this expectation specified in NPDAP 7.5, " Processing a
MWR," Rev.10. The Maintenance Manager subsequently informed the inspectors
of additional actions which would be taken to provide better control over MWR
work instructions.
Replacement of Six Batterv Cells on Batterv 2-1
Electricians measured cell voltage for each of the 59 cells after restoring the battery
to float charge. Although all individual cell voltages (ICVs) were adequate,
engineers noted voltage variability and lower than expected ICVs for cell 8 and 33.
After reviewing cell performance trende, management decided to replace the three
battery jars (2 cells per jar) containing cells 8,33, and 40. The inspectors
determined this decision demonstrated an appropriate safety perspective which
minimized the potential that the 2-1 battery would become inoperable during power l
operations and impose a plant shutdown action requirement.
Electricians began replacing the,three battery Jars on January 29, using MWR
69526. The inspectors observed portions of the cell replacement. Electricians
demonstrated appropriate care in handling the battery cells. The inspectors
observed that the 2-1 battery room door was propped open on January 30, to !
facilitate easier handling of the battery jars and personnel access. Appropriate I
security measures were established. However, the inspectors noted poor control of
the door as a fire boundary. Relaxation of the fire boundary had not been planned ,
as part of the MWR and compensatory measures were not established. The !
inspectors discussed the fire door with operations personnel who corrected the j
condition and took appropriate action to preclude recurrence. This was an isolated !
occurrence of a weakness and did not reflect a programmatic problem. )
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2BVT-1.39.6, Station Batterv 2-1 Performance Discharae Test, Rev.1
On January 31, a battery discharge capacity test at the vendor rated capacity of l
approximately 480 amps was performed as a post-maintenance test (PMT). Twelve !
minutes after beginning the discharge test, personnel entered the battery room in i
preparation for recording test data. Smoke was observed rising from the intercell
connector bar between cells #9 and #10. The test was promptly aborted and the
battery disconnected. Visualinspections identified that the bolts for the intercell !
connector bar were loose, which resulted in localized high impedance at that I
location. This resulted in overheating of the cell and potentially significant battery
damage. The inspectors viewed the cell and noted that the intercell connector nuts
and lock washers were backed off of the connecting bar by 3-4 threads. No signs
of damage other than melted grease from the connector bar was noted. Engineers
informed the inspectors of their observations at the battery and discussed planned
inspection and retest requirements to determine whether the cell or the entire
battery had been damaged. Reinspection confirmed that the battery had not been
damaged. The inspectors noted that the prompt action taken by the test crew
prevented, what may otherwise have been, significant battery damnge.
'!
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17
The inspectors reviewed the MWR 69526 work instructions and verified that the
cell #9 to #10 intercell connector bar should not have been worked on. The loose
bolts were in an inconspicuous location and had the potential to cause significant
damage. The inspectors questioned whether the loose bolts may have resulted
from tampering. Station management reviewed the event and concluded that
tampering was unlikely. The most likely cause of the loose bolts was attributed to
~ inadequate detail in the work instructions and incomplete job briefings, which
resulted in inadequate tightening of the #9 to #10 intercell connector. The
inspectors discussed these findings with station management and concluded they
were reasonable.
2BVT-1.39.6 was successfu!!y re-performed, achieving 110 percent of rated
capacity, on February 2. The inspectors noted that the test was well written and
included several conservative factors to assure battery performance margin was
properly tested. Following the test, each of the 60 cells were inoperable, as
expected, due to low voltage. The battery was promptly placed on charge to I
restore cell voltage and battery capacity. The inspectors noted that neither MWR
69526 nor 2BVT-1.39.6 contained sufficient work instructions to verify.the charge
restored the battery to an operable condition. The MWR indicated that ICVs for
each of the 60 cells should be recorded and that the weekly operability test should-
be performed on the pilot cell. The inspectors expressed concern that no
acceptance criteria was specified for the measured ICVs and the existing specified
PMT was inadequate to verify 2-1 battery operability. Following this discussion,
engineers added appropriate ICV acceptance criteria to the work instructions. . The
battery was declared operable on February 4.
The inspectors determined that engineering assessment of station battery 2-1 ,
' performance and recommended corrective maintenance were consistent with the I
vendor technical manual and applicable Institute of Electrical and Electronics ,
Engineers standards. However, work instruction quality and imp!amentation were !
inadequate and almost resulted in battery demage. TS 6.8.1 requires that written l
procedures be properly established and implemented covering activities ,
recommended in Appendix "A" of NRC Regulatory Guide (RG) 1.33, Rev. 2, j
February 1978. NRC RG 1.33 states that maintenance which can affect the
performance of safety related equipment should be properly pre-planned and
performed in accordance with written procedures and documented instructions ,
appropriate to the circumstances. The inspectors concluded that the documented - i
work instructions of MWR 69496 and 69626 were inadequate in that they did not ;
provide sufficient detail to assure intercell connectors were properly controlled.
y Further, a supplemental work instruction for jumpering cell #40 from the 2-1 station
battery was not properly controlled in that it did not receive appropriate reviews as l
part of the MWR planning and authorization process. In addition, acceptance
criteria for cell voltages to certify battery operability following the battery 21 fuli ;
. capacity discharge test were not specified. 'This is a violation of TS 6.8.1 ;
(VIO 50-412/97-11-08).
{
>
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18
c. Conclusions
The temporary modification to jumper out a degraded cell from the 2-1 station
battery was technically sound and properly evaluated. Engineers demonstrated a
good working knowledge of the supporting engineering calculations. The
subsequent management decision to replace six battery cells demonstrated an
appropriate safety perspective. Post maintenance testing following replacement of
six battery cells was generally good. An exception was that individual cell voltage
acceptance criteria to support battery operability following restoration from the
discharge capacity test was not specified.
Electricians demonstrated appropriate care when handling the station battery cells.
However, work instruction detail was inadequate, supplemental work instructions
were not properly controlled, and a fire barrier was not properly controlled.
Electricians failed to properly reattach an intercell connector following battery cell
replacement. Prompt action in response to smoke emanating from the battery
during a full capacity discharge test prevented significant battery damage.
111. Enaineerina
E1 Conduct ct Engineering
E1.1 Non-Conservative Radioloalcal Dose Assessrnent for Desian Basis Accidents (DB.A_1
a. Jnspection ScG2p_Q7551,71707. 71750,92903,93702)
In late December 1997, engineers determined that the Unit 2 control room
emergency ventilation system (CREVS) did not meet single failure design criteria
(see Section E8.2). While resolving that issue, engineers identified that several of
the assumptions previously used for various DBA radiological consequence
asnessments were non-conservative. The incpectors reviewed design documents,
previaus license amendment submittals, and interviewed various personnel to
assess licensee resolution of the DBA dose assessment issues.
b. Observations and Fincjings
While developing design changes for the CREVS (documented in NRC IR Nos. 50-
334(412)/98-80), engineers identified that ventilation flowrate may be much higher q
than previously assumed in the UFSAR Chapter 15 accident analysis. When j
performirg dose calculations to support system design changes, radiological j
engineers determined that the increased flowrate would increase radiological dose q
to control room operators for the main steam line break outside containment
accident. They additionally noted that previously performed station accident
analysis, for several accidents which credit the CREVS, had incorrectly assumed
that a minimum vs.lue for contrcl room ventilation flowrate would provide the most
limiting dose assessment results. Previous analysis used 690 standard cubic feet '
l
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- 1
a
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19
per minute (scfm) as the limiting flowrate. Radiation engineers determined, that if
all other assessment assumptions remained unchanged, the increased flowrate
experienced if two fans were permitted to run simultaneously could cause exposure
to control room operators to exceed the acceptance criterion established in a safety
evaluation.
The inspectors noted that TS required surveillance tests, demonstrated that
ventilation flowrate was between 800 and 1000 scfm. Therefore, even a single
ventilation fan running, following the proposed design changes, could cause the
analyzed control room dose to be highur than previously analyzed and documented
in the UFSAR. The inspectors discussed this issue with radiation engineers and
questioned (a) what other accidents may be adversely affected and (b) whether
each of the other accident analysis assumptions remained valid. The licensee
performed a comprehensive review of these issues, along with other actions already
initiated through CR 972390to assess CREVS flowrate. Specific CREBAPS testing
received exce!!ent coordination and oversight by the en0 ineering and operations
staff. However, the inspectors noted that communications between radiation
engineers and design engineers to address the CREVS single failure issues were
inconsistent, which delayed issue resolution and design change implementation by
several weeks. Licensee findings which potentially invalidated previous radiological
dose consequence assessments included the following:
)
1. The minimum CREVS flowrate was reduced from 690 scfm to 600 scfm for
certain accidents. The maximum single train flowrate of 1030 scfm
(including instrument error) was more limiting for other accidents.
i
l
2. The minimum control room emergency bottled air pressurization flowrate
(CREBAPS) of 690 scfm had been extrapolated from a preoperational test
performed on the original Unit 1 control room. The system failed to 5 ovide
this flowrate during a performance test, run during this inspection period.
Engineers selected 600 scfm as a revised conservative minimum flowrate.
i
3. The CREVS initiation timer accuracy ( i 3 minutes) had not been I
incorporated into dose assessmont calculations. Timer accuracy was
subsequently improved toi1 minute by a design change.
l
4. The post accident control room purge flowrate of 19,800 scfm was too high
and required reduction to 16,800 scfm.
5. Certain accident analysis did not properly use a conservative reactor coolant
system (RCS) inventory estimate as had been intended.
Radiological consequence assessments for each of the five UFSAR accidents which
take credit for the CREVS were re-performed, for each unit, with revised analysis
assumptions, based on the radiological engineers' findings. Revised analysis for the
main steam line break outside containment indicated that control room operator
radiological dose may exceed acceptance criterion established in a safety
evaluation. This analysis used the current 11.75 gallon per minute (gpm) Unit 1
faulted steam generator (SG) RCS primary to secondary leakage limit which was
.
.. *
20
established to support TS Amendment 205, for alternate steam generator tube
repair criteria. Dose calculations were not required to account for this faulted SG
leakage contribution prior to NRC approval of this licensee amendment which
authorized use of alternate SG tube repair criteria. The licensee administratively
lowered the RCS primary to secondary leakage limit to 8.0 gpm to address this
problem. The resulting dose consequence was lowered to acceptable values which I
were below those previously documented in the UFSAR. The inspectors
independently verified that the worst case Unit 1 faulted SG leakrate projected for
the end of the current operating cycle was less than 8.0 gpm. The resulting 10
CFR 50.59 safety evaluation concluded that the reduced allowable leakage and
resultant radiological dose consequences did not create an unreviewed safety )
question (USO). -(
Q"
Additional safety evaluations were performed for the other UFSAR accident
analyses using the corrected, or more conservative input parameters. New
radiological dispersion factors (X/Q) were also used based on NRC Regulatory Guide
1.145, Atmospheric Dispersion Models for Potential Accident Consequence
Assessments at Nuclear Power Plants, Rev.1. While reviewing Westinghouse
Nuclear Safety Advisory Letter (NSAL)93-016, the licensee determined that the
methodology previously used for Unit 2 small break loss of coolant accident (LOCA)
radiological consequence analysis had not been previously reviewed and approved
by the NRC. The safety evaluations identified three USQs,
- Unit 1 Waste Gas System Rupture resulted in a slightly increased control
room dose consequence, due to the slightly lower minimum CREBAPS
flowrate.
- Unit 2 Small Break LOCA dose assessment methodology had changed.
- Unit 2 Locked Reactor Coolant Pump Rotor dose assessment resulted in
increased control room, exclusion area boundary (EAB), and low population
zone (LPZ) dose consequences. ,
1
The Nuclear Safety Review Board (NSRB) reviewed each of the USQs. The l
inspectors independently reviewed the dose consequence assessments and j
corresponding safety evaluations. In each case the control room, EAB, and LPZ j
radiological consequences remained below the corresponding regulatory limit. The ~l
safety evaluations were comprehensive and the NSRB reviews were excellent. The
licensee promptly submitted the USQs as well as revised TS amendment
justifications for alternate SG tube repair criteria for NRC review. Senior licensee
management determined that the existing USQs did not require NRC review prior to
unit restart. The inspectors concluded that the licensee's disposition and evaluation
of the USQs with regard to the Unit 1 startup were consistent with GL 91-18,
Information to Licensees Regarding NRC Inspection Manual Section on Resolution of
- Degraded and Nonconforming Conditions, Rev.1.
J_ ,
g 10 CFR 50 Appendix B, Criterion ill, " Design Control" states that " measures shall
'
,
be established to assure that applicable regulatory requirements and the design
'
basis are ... correctly translated into specifications, drawings, procedures, and
,
1
.
.
21
instructioris." Failure to ensure that the design values used in control dose
calculation corresponded to actual plant conditions was a violation of 10 CFR 50
Appendix B, Criterion 111, " Design Control." The inspectors noted that the overall
safety significance of the radiological dose increase was small and within 10 CFR
50, Appendix A, Criterion 19 limits. In addition, the licensee extent of condition
reviews were comprehensive, and the issues were effectively corrected. 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
334(412)/97-11-09).
c. Conclusions
Engineers determined that several assumptions previously used for various design
basis accident control room and exclusion area boundary radiological dose
assessments were non-conservative. Licensee assessment of the issue including
extent of condition reviews was comprehensive. However, communications
between radiation engineers and design engineers were inconsistent which delayed
issue resolution and design change implementation by several weeks. The licensee
identified three associated unreviewed safety questions and promptly submitted
'
associated regulatory documents for NRC review and approval. Safety evaluations
and Nuclear Safety Review Board assessment of the issues were excellent. j
E1.2 Startuo Testino and Combustion Enaineerina Rod Position Indication (CERPI) Testina
The inspectors observed portions of 1BVT-1.1.7, Rev. 2, " Rod Position Indication
System Calibration Verification," performed after installation of Analog Rod Position
Indication Upgraded, DCP 2209, on Unit 1. The post installation testing was
closely monitored and controlled. The operators observed several alarms as control
rods were moved for testing and during the subsequent reactor startup, but the
CERPl system returned the rod position indication to within Technical Specification l
limits quickly. The operators noted that the CERPI system indication follows control
rod motion more closely than the previously installed analog rod position indication
(ARPI) system. Based on operator interviews and inspector observations, the
inspectors concluded that the new CERPI system was an improvement over the
previous ARPI system.
E8 Miscellaneous Engineering issues (37551,92700,92902)
E8.1 (Closed) Licensee Event Report (LER) 50-412/97-006: Technical Specification
Requirements for 4.13 kV Bus Undervoltage Trip Feeder Breaker Function ESF
Response Time Not Met.
a. inspection Scope
The inspectors reviewed Licensee Event Report (LER) for failure to meet technical ;
specification (TS) requirements and entry into TS 3.0.3. The inspectors discussed
the issue with system engineers, reviewed the LER and corrective actions, and
observed operations response.
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22
b. Observations and Findinas
On December 1,1997, a system engineer noted that the overall Engineered Safety
Feature (ESF) response time for the 4.16 kV loss of voltage trip feeder function (TS
limit 1 *0.1 seconds) was exceeded for both trains. Operators entered TS 3.0.3
and exited within two hours after rnaintenance surveillance procedures were revised
and performed. The inspectors noted good communication and coordination
between operators, maintenance technicians, and system engineers to expeditiously
complete the procedures.
The licensee determined that the apparent cause was that relay calibration
procedures, for the undervoltage relays in the loss of voltage trip feeder function,
were not revised to specify time delay values which would ensure compliance
with TS. Historically, the licensee relied upon verbal communications between the
relay crew and system engineers to place the relay time delay values in the lower
end of their range. The possible problem was originally identified in 1992. The
relays' time delays were tested and recalibrated in October and November without
the knowledge of the ESF response engineer. Therefore, the relay crew was not ,
informed of the more restrictive time response band on the relays. The total ESF !
time allowed is comprised of the time required for undervoltage relay actuation (TS
'
lirnit l iO.1 seconds), combined with additional auxiliary relay actuation and breaker
tripping. The licensee had submitted a TS amendment request to remove the ESF
times from the TS with the intent to change the ESF response time for this function
to s 1.3 seconds. The TS amendment (TS Amendment 210 for Unit 1 and
Amendment 88 for Unit 2) was approved January 20,1998. The inspectors
reviewed the 50.59 for the change to s 1.3 seconds and found the evaluation to
be satisfactory.
Corrective actions included revising the maintenance surveillance procedures to
provide the acceptable range for the time delay settings and review of the LER and
lessons learned with system engineers. The inspectors determined that the q
corrective actions addressed the issue. The subsequent TS amendment and i
changes to the allowable ESF time was an appropriate long-term solution. The
inspectors noted that the long-term problem and solution of revising the allowable
ESF response time was recognized by the licensee, but was not described in the
LER. The inspector concluded that the additional information would have enhanced
the information in the LER.
i
The failure to meet the ESF response time for the 4.16 kV loss of voltage trip feeder 1
function (TS limit l iO.1 seconds) for both trains is a violation of TS 3.3.2.1. This l
- non-repetitiveilicensee-identified and corrected violation is being treated as a Non- l
~ Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy 1
'
- (NCV 50-412/97-11-10).
I
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. . . . . . . . .. .... . .
. . . .. .. - . .
.
.
23
c. Conclusions
. .
Due to a reliance on personnel knowledge and communication to address a TS
deficiency without changing applicable procedures,' the ESF response time for loss
of voltage trip feeder function was slightly exceeded. The resulting technica!
specification violation did not represent a significant safety event, but was
considered a weakness in addressing a long time known deficiency.
E8.2 ' (Closed) Unresolved item 50-334 and 412/97-09-02: Control Room Emergency.
Pressurization Ventilation System Design Deficiency.
The inspectors reviewed the Unit 2 control room emergency ventilation system and
the design and licensing basis for the system. The licensee had identified several
examples where the system could not meet single failure design criteria. Further
'
details of the failures and licensee identification of the issue were described in NRC
Inspection Report 50-334 and 412/97-09 and LER 50-412/97-008,
10 CFR 50, Appendix B, Criterion ill states that " measures shall be established to
'
assure that applicable regulatory requirements and the design basis ... are correctly
translated into specifications...." Unit 2 UFSAR Section 9.4.1.1 describes the
design criteria ,which includes " single failure criterion, as it relates to air-conditioning
and emergency supply filtration equipment. Prior to initial Unit 2 startup, the
licensee failed to identify several single failures associated with a pressure switch in
the control room emergency ventilation system that would render the system unable
to fulfill the design safsty hinnibn. Indr;,endent reviews, prior to startup also failed
to identify this design deficiency. Faiiure of the system to meet the design basis is
a violation of 10 CFR 50, Appendix B, Criterion Ill.
Corrective actions were taken to redesign the control room emergency ventilation
system to establish single failure reliability. The design changes included adding
backdraft dampers, an additional pressure switch, higher accuracy control room
actuation timers, and repositioning of the pressure switch. The detailed design was
reviewed and documented in NRC inspection Report 50-334 and 412/98-80.
Design Changes 2306 and 2311 were installed and successfully tested prior to the
end of this reporting period. The NRC concluded that the corrective actions address
the failure to meet single failure criterion. The licensee also committed to perform
additional extent of condition reviews on similar QA Category 1 ventilation systems.
During reviews of the control room emergency ventilation system, the licensee and
NRC identified discrepancies in the control room dose calculations (see
Section E1.1).
The inspectors noted that excellent _ questioning attitude by the operator and
y
~~
engineers led to identification of the design deficiency. The issue also was not
likely to be identified by routine licensee activities. The immediate and long-term
corrective actions were comprehensive and performed within a reasonable time
frame. In accordance with Section Vll.B.3 of the Enforcement Policy, the NRC is
-
exercising enforcement discretion with respect to the 10 CFR 50 Appendix B
,,
,
Criterion til violation (NCV 50-412/97-11-11).
g x w -
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24
-E8.3 (Closed) Licensee Event Report (LER) 50-412/97-OO8: Failure to Meet Single Active
Failure Criteria for C. R. Emergency Ventilation System Results in Entry into TS 3.0.3.
The inspectors reviewed the LER through field inspection activities and in office .
reviews. This LER is closed based on the above discussion.
E8.4 (Discussed) Violation EA 50-412/97-51701013: Failure to Prevent Gas Binding of'
High Head Safety injection (HHSI).
During Unit 1 extended refueling outage and the Unit 2 forced outage, the licensee
replaced the recirculation flow orifices on five of the six HHSI pumps. The Unit 1
and Unit 2 replacement orifices were installed and operationally accepted by
December 12,1997, and January 3,1998, respectively. The licensee intends to
replace the last orifice on the Unit 2 "B" HHSI pump prior to or during the next
refueling outage. The new 24-stage orifices replaced the old 11-stage orifices
which were identified as the principal cause of the gas binding events in the HHSI
pumps. The acceptable gas void fraction limit was established for the Unit 1 and
Unit 2 HHSl pump suction piping by December 23,1997. The inspectors reviewed
initial ultrasonic examination results after orifice replacement which showed minimal
gas buildup in the HHSl piping. The results were preliminary, and further reviews
will be conducted by the licensee prior to reducing the frequency of ultrasonic
testing examinations and venting frequencies of the pumps.
E8.5 - (Closed) eel 50-412/97-07-03: Failure to Prevent Gas Binding of High Head Safety
injection (HHSI).
This eel was closed in NRC letter dated January 6,1998. (VIO 50-412/
EA 97-517 01013) l
l
i
IV. Plant Support
R2 Status of RP&C Facilities and Equipment (71750)
The inspectors noted a significant reduction in contaminated areas throughout the j
plant over the past year due to efforts by the Health Physics staff. Contaminated !
areas had been reduced from a total of about 4.75 pe. cent (11,870 square feet) at 'l
the beginning of 1997 to about 0.8 percent (1986 square feet) at the beginning of l
1998. Much of the improvement was attributed to the work of a dedicated
decontamination crew during outages and use of new steam cleaning equipment.
Reduction in contaminated areas resulted in less contaminated waste and easier
access to equipment and spaces by operators and maintenance technicians. ,
L1 Review of UFSAR Commitments
!
While performing the inspections discussed in this report, the inspectors reviewed
'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. !
. .. .
. . . . . . . . . . . . . .. .. . .
. . . .. .. . ... . . . . . . . . .
. 4
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25
81- Conduct of Security and Safeguards Activities
a. insoection Scone (81700)
The inspectors determined whether the conduct of security and safeguards
activities met the licensee's commitments in the NRC-approved security plan (the
Plan) and NRC regulatory requirements. The security program was inspected during
the period of January 5-8,1998. Areas inspected included: alarm stations;
communications; and protected area access control of personnel, packages, and
vehicles.
~ b. Observations and Findinas
Alarm Stations. The inspectors observed operations of the Central Alarm Station
- (CAS) and the Secondary Alarm Station (SAS) and verified that the alarm stations -
were equipped with appropriate alarms, surveillance and communications
capabilities. Interviews with the alarm station operators found them knowledgeable
of their duties and responsibilities. The inspectors also verified, through
observations and interviews, that the alarm stations were continuously manned,
independent and diverse so that no single act could remove the plants capability for.
- detecting a threat and calling for assistance, and the alarm stations did not contain
any operational activities that could interfere with the execution of the detection,
assessment and response functions.
Communications. The inspectors verified, by document reviews and discussions
with alarm station operators, that the alarm stations were capable of maintaining
continuous intercommunications, communications with each security force member
(SFM) on duty, and were exercising communication methods with the local law
enforcement agencies as committed to in the Plan.
Protected Area (PA) Access Control of Personnel and Hand-Carried Packaaes. On
- January 6 and 7,1998, the inspectors observed personnel and package search
activities at the personnel access portal. The inspectors determined, by
observations, that positive controls were in place to ensure only authorized
individuals were granted access to the PA and that all personnel and hand carried
items entering the PA were properly searched.
PA Access Control of Vehicles. On January 7,1998, the inspectors observed
vehicle access control activities at the main vehicle access control entry point. The
observations included SFM's verification of vehicle authorization and escort
requirements and the performance of vehicle searches prior to granting PA access.
Additionally, the inspectors verified that the active land vehicle barrier was being
utilized in accordance with Plan commitments. The inspectors concluded that
vehicles were being controlled and maintained in accordance with the Plan and l
applicable procedures.
,
/
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26
c.- Conclusions
.The licensee was conducting its security and safeguards activities in a manner that
protected public health and safety and that this portion of the program, as.
implemented, met the licensee's commitments and NRC requirements.
82 Status of Security Facilities and Equipment
a. Inspection Scone (81700)
Areas inspected were testing, maintenance and compensatory measures;
assessment aids; and personnel search equipment.
b. . Observations and Findinas
Testina, Maintenance and Comoensatory Measures. The inspectors reviewed
testing and maintenance records for security-related equipment and found that
documentation was on file to demonstrate that the licensee was testing and
maintaining systems and equipment as committed to in the Plan. A priority status
'was being assigned to each work request and repairs were normally being
completed within the same day a work request necessitating compensatory
measures was generated. The inspectors reviewed security event logs and
maintenance work requests generated over the last year. These records indicated
that the need for establishing compensatory measures due to equipment failures
was minimal and when implemented, the compensatory measures did not reduce
the effectiveness of the security systems as they existed prior to the failure.
Assessment Aids. On January 6,1998, the inspectors evaluated the effectiveness
of the r.3sessment aids, by observing on closed circuit television (CCTV), a
walkdown of the PA. The assessment sids, in general, had good picture quality and
excellent zone overlap. However, due to existing long fields of view in several
zones, the alarm station operator's ability to properly assess the cause of an alarm
would be limited if it were not for the use of the video capture system as an
. enhancement to the assessment program. Additionally, to ensure Plan
commitments are satisfied, the licensee has procedures in place to compensate in
the event the alarm station operator is unable to properly assess the cause of an
alarm or the video capture system becomes inoperative.
Personnel and Packaae Search Eauioment. The inspectors observed both the
routine use and the daily performance testing of the licensee's personnel and
package search equipment. The inspectors determined, by observations and
procedural reviews, that the search equipment performs in accordance with licensee
procedures and Plari commitments.
c.. Conclusions
The licensee's security facilities and equipment were determined to be well
,
maintained and reliable and were able to meet the licensee's commitments and NRC
- requirements.
l
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.
27
S3 Security and Safeguards Procedures and Documentation
a. Inspection Scooe (81700)
Areas inspected were implementing procedures and security event logs,
b. Observations and Findinas
Security Prooram Procedures. The inspectors verified that the procedures were
consistent with the Plan commitments, and were properly implemented. The
verification was accomplished by reviewing selected implementing procedures
associated with PA access control of vehicles, testing and maintenance of
personnel search equipment and control of safeguards information,
Security Event Loos. The inspectors reviewed the Security Event Log for the
previous twelve months. Based on this review, and discussion with security
management, it was determined that the licensee appropriately analyzed, tracked,
resolved and documented safeguards events that the licensee determined did not
require a report to the NRC within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
c. Conclusions
Security and safeguards procedures and documentation were being properly
implemented. Event Logs were being properly maintained and effectively used to
analyze, track, and resolve safeguards events.
S3.1 Review of Uodated Final Safety Analysis Report (UFSAR)
Since the UFSAR does not specifically include security program requirements, the
inspector compared licensee activities to the NRC-approved physical security plan,
which is the applicable document. While performing the inspection discussed in this
report, the inspectors reviewed Section 13.7 v? the Plan, titled, " Protection of
Safeguards information." The inspectors determined by observations and
procedural reviews, that safeguards information was being controlled and
maintained as required in the Plan.
S4 Security and Safeguards Staff Knowledge and Performance
a. Insoection Scope (81700)
Areas inspected were security staff requisite knowledge and capabilities to
accomplish their assigned functions.
..
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28
]
b. Observations and Findinas
Security Force Reauisite Knowledae. The inspectors observed a number of SFM's
in the performance of their routine duties. These observations included alarm
station operations, personnel, package and vehicle searches, visitor processing, and
requalification classroom instruction. Additionally, the inspectors interviewed SFMs
and based on the responses to the inspectors' questioning, determined that the
SFMs were knowledgeable of their responsibilities and duties, and could effectively
carry out their assignments.
c. Conclusiong
The SFMs adequately demonstrated that they have the requisite knowledge .
necessary to ~ effectively implement the duties and responsibilities associated with
their position.
.S5 Security and Safeguards Staff Training and Qualification
I
^
a. Inspection Scone (81700)
Areas inspected were security training and qualifications, and training records.
b. . Observations and Findinas
Security Trainina and Qualifications. On January 7,1998, the inspectors randomly
selected and reviewed T&O records of 16 SFMs. Physical and requalification
records were inspected for armed, unarmed, and supervisory personnel. The results
of the review indicated that the security force was being trained in accordance with
the approved T&Q plan. Additionally, the inspectors observed requalification
classroom instruction, performed by the training staff, which addressed the areas of
use of force, lighting requirements, and bomb search techniques. The instructors
were knowledgeab!a of the course material and presented it in an effective manner.
Trainina Records. The inspectors were able to verify, by reviewing training records,
that the records were properly maintained, accurate and reflected the current
qualifications of the SFMs.
, c. Conclusions
Security force personnel were being trained in accordance with the requirements of
the Plan. Training documentation was properly maintained and accurate and the
training provided by the training staff was effective.
S6 Security Organisation and Administration
a. insoection Scone (8170Q)
' Areas inspected were management support and effectiveness, and staffing levels.
.-
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b. Observations and Findinas
Manaaement Support. The inspectors reviewed various program enhancements
made since the last program inspection, which was conducted in May 1997. These
enhancements included the procurement of 2 portable trailer mounted guard booths,
the procurement of a new security patrol vehicle, and the procurement of a digital
camera for investigative purposes.
Manaaement Effectiveness. The inspectors reviewed the management
organizational structure and reporting chain. Security management's position in the
organizational structure provides a means for making senior management aware of
programmatic needs. Senior management's positive response to requests for
equipment, training and resources, in general, has contributed to the effective
administration of the security program.
.Staffina Levels. The inspectors verified that the total number of trained SFMs
immediately available on shift meets the requirements specified in the Plan
c. Conclusions
The level of management support was adequate to ensure effective implementation
of the security program, and was evidenced by adequate staffing levels and
continued resource allocation to improved training and equipment to enhance
effective implementation of the security program.
S7 Quality Assurance in Security and Safeguards Activities ,
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a. Inspection Scope (81700) i
Areas inspected were audit /self-assessment program, problem analyses, corrective
actions and effectiveness of management controls.
b. Observations and Findinas
Audit /Self-Assessment Proaram. The inspectors reviewed the 1997 QA audit of the
fitness-for-duty (FFD) program, conducted August 12 - September 11,1997, (Audit
No. BV C-97-07). The audit was found to have been conducted in accordance with
the FFD rule. To enhance the effectiveness of the audit, the audit team included an
independent technical specialist.
The audit report identified four deficiencies documented as condition reports (CR).
The CRs were associated with procedural deficiencies and procedural adherence
issues. The inspectors determined that the findings were not indicative of
programmatic weaknesses, and the findings would enhance program effectiveness.
Inspectors' discussions with security management and FFD staff revealed that all of
the responses to the CRs had not been finalized. The inspectors determined that
the responses would be reviewed during a subsequent inspection.
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The self-assessment program was well defined and structured. The program
consisted of the performance of an annual site specific self-assessment and the
performance of a departmental self-assessment program, which included the
performance of observation tours by security supervision. To enhance the
effectiveness of the departmental self-assessments, all supervisory personnel
received proceduralized training on the performance of observation tours prior to
being assigned observation tour responsibilities. During 1997, security supervision
conducted 107 observation tours. All of the observation tours were tracked and
trended and when needed, corrective actions implemented.
Problem Analyses. The inspectors reviewed data derived from the self-assessment
programs. Potential weaknesses were being properly identified, tracked, and
trended.
Corrective Actions. The inspectors reviewed corrective actions implemented by the
licensee in response to the OA audit and self-assessment programs. The corrective
actions were effective, as evidenced by a reduction in personnel performance issues
and loggable safeguards events. 1
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Effectiveness of Manaaement Controls. The inspectors observed that the licensee
has programs in place for identifying, analyzing and resolving problems. They
include the performance of annual QA audits, self-assessment programs and the use
of industry data such as violations of regulatory requirements identified by the NRC
at other facilities, as a criterion for self-assessment.
c. Conclusions
The review of the licensee's Audit /Self-Assessment program indicated that the audit I
was comprehensive in scope and depth, that the audit findings were reported to the j
appropriate level of management, and that the program was being properly
administered. In addition, a review of the documentation applicable to the self-
assessment program indicated that the program was effectively implemented to
identify and resolve potential weaknesses.
V. Maneaement Meetinas
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X1 Exit Meeting Summary ,
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The inspectors met with licensee representatives at the conclusion of the security
inspection on January 8,1998. At that time, the purpose and scope of the inspection j
were reviewed, and the preliminary findings were presented. The licensee acknowledged
the preliminary security inspection findings. ;
The inspectors presented the inspection results to members of licensee management at the
conclusion of the inspection on February 24,1998. The licensee acknowledged the
findings presented.
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The inspectors asked the licensee whether any materials examined during the inspection
should be considered proprietary. No proprietary information was identified.
X4 Duquesne Light Company Management Reorganization
On January 28,1998, Duquesne Light Company (DLC) announced a reorganization of
senior managers. Mr. Sushil Jain was promoted to the position of Senior Vice President
(VP) - Nuclear Services Group. He will retain direct responsibilities for engineering and
licensing activities in addition to his new duties. Mr. Ronald LeGrand assumed the position
of VP - Operations Support Group, responsible primarily for outage planning, security, and
training activities. Mr. Richard Brandt assurned the duties of VP - Nuclear Operations
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Group & Plant Manager, previously performed by Mr. LeGrand. Mr. Brandt joined DLC in
December 1997 following three years as Plant Manager at Perry Nuclear Power Station.
The reorganization described above became effective the first week in February 1998.
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PARTIAL LIST OF PERSONS CONTACTED
D.kG
J. Cross, President, Generation Group
S. Jain, Senior Vice President, Nuclear Services Group & Plant Manager
R. Brandt, Vice President, Nuclear Operations Support Group l
R. LeGrand, Vice President, Nuclear Operations / Plant Manager
M. Pergar, Acting Manager, Quality Services Unit
B. Tuite, General Manager, Nuclear Operations .
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R. Hansen, General Manager, Maintenance Programs Unit
D. Kline, Director Nuclear Security Operations 1
'J. Macdonald, Manager, System & Performance Engineering 4
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R. Vento, Manager, Health Physics j
D. Orndorf, Manager, Chemistry ]
F. Curl, Manager, Nuclear Construction '
J. Matsko, Manager, Outage Management Department
T. Lutkehaus, Manager, Maintenance Planning & Administration
T. Cosgrove, Coordinator, Onsite Safety Committee
K. Beatty, General Manager, Nuclear Support Unit
J. Arias, Director, Safety & Licensing
W. Kline, Manager, Nuclear Engineering Department
R. Brosi, Manager, Management Services i
O. Arredondo, Manager, Nuclear Procurement
M. Johnston, Manager of Security
N. DiPiotro, Supervisor Security Services
J. Belfiore, Supervisor, Quality Services Unit
D. Kopp, Medical Administrator
B. Sepelak, Senior Licensing Engineer l
NRG ,
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D. Kern, SRI i
G. Dentel, RI
F.Lyon,RI
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INSPECTION PROCEDURES USED
Procqdures mentioned in this .eoort
IP 37551: ' Onsite Engineering
IP 61726: Surveillance Observation
IP 62707: Maintenance Observation
IP 71707: Plant Operations
IP 71750: Plant Support
IP 81700: Physical Security Program for Power Reactors
IP 92700: Event Reports
IP 92901: Operations Follow-up
-IP 92902: Maintenance Follow-up
-IP 92903: Engineering Follow-up
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
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ITEMS OPENED, CLOSED AND DISCUSSED
Ooened'
50-334/97-11-02 VIO Failure of Operators to Log TS LCO Entries and Perform
Proper Shift Turnover (Section 04.1)
50-412/97-11-08 VIO Inadequate MWR Work Instructions for Battery 2-1
Repair (Section M2.1)
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Opened / Closed
50-412/97-11-01 NCV Unit 1 TS Required Shutdown (Section 01.2)
50-334 and 412/97-11-03 NCV_ Management of Overtime (Section 06.1)
50-334/97-11-04 NCV Failure to Remove Power from Isolation RCS Loop !
Isolation Valve Operators Within One Hour as Required
by TS (Section 08.1)
50-334/97-11-05 NCV Failure to Perform Axial Flux Difference (AFD) Monitor
Surveillance as Required by TS (Section 08.2)
50-334/97-11-06 NCV Maintenance Error Results in Failure to Ensure
Feedwater Flow Channels in Service Prior to Mode 2
Entry (Section M1.2) .
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50-334/97-11-07 NCV Incorrect Data Entered During Power Range Instrument
Calibration. Inadequate Post Maintenance Review
(Section M1.3)
50-334 and 412/97-11-09 NCV Nonconservative Radiological Dose Assessment for
DBAs (Section E1.1)
50-412/97-11-10 NCV Technical Specification Requirements for 4.16 kV Bus
Undervoltage Trip Feeder Breaker Function ESF
Response Time Not Met (Section E8.1)
50-412/97-09-11 NCV Control Room Emergency Pressurization Ventilation
System Design Deficiency (Section E8.2)
Closed
50-334 and 412/97-09-02 URI Control Room Emergency Pressurization Ventilation
System Design Deficiency (Section E8.2)
50-334/97-041 .LER Failure to Remove Power from isolated RCS Loop
Isolation Valve Operators Within One Hour as Required
by TS (Section 08.1)
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50-334/97-042 LER Failure to Perform Axial Flux Difference (AFD) Monitor
Surveillance as Required by TS (Section 08.2)
50-412/97-006 LER Technical Specification Requirements for 4.16 kV Bus
Undervoltage Trip Feeder Breaker Function ESF
Response Time Not Met (Section E8.1)
50-412/97-008 LER Failure to Meet Single Active Failure Criteria for CR
Emergency Ventilation System - Entry into TS 3.0.3
(Section E8.3)
50-412/97-07 03 eel Failure to Prevent Gas Binding of High Head Safety
injection (Section E8.5)
Discussed
50-334 & 412/EA 97-255 VIO Programmatic TS Surveiilance Testing Deficiencies
(Section 01.3)
50/412/EA 97 517 VIO Failure to Prevent Gas Binding of HHSI (Section E8.4)
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LIST OF ACRONYMS USED
AFD Axial Flux Difference
AMSAC ATWS Mitigating System Actuation Circuitry
ATWS Anticipated Trensient Without Scram
BVPS Beaver Valley Power Station
CAS Central Alarm System
CCP Component Cooling Primary
CCR Component Cooling Water
CCTV Closed Circuit Television
CERPl Combustion Engineering Rod Position Indication
CFR Code of Federal Regulations
CR Condition Report
CREV Control Room Emergency Ventilation System
DBA Design Basis Accident
DCP Design Change Package
DLC Duquesne Light Company ;
EA Enforcement Action j
EA Exclusion Area
EAB Exclusion Area Boundary
ESF Engineered Safety Feature
GL Generic Letter
gpm gallons per minute
HHSI High Head Safety injection ,
l&C Instrumentation & Control I
ICV Individual Cell Voltage
LCO Limiting Condition of Operation
LER Licensee Event Report
MEL Material Equipment List
MSP Maintenance Surveillance Procedure j
MWR Maintenance Work Request
NCV Non-cited Violation l
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NPDAM Nuclear Power Division Administrative Manual
NPDAP Nuclear Power Division Administrative Procedure
NRC Nuclear Regulatory Commission
NSAL Nuclear Safety Advisory Letter
NSRB Nuclear Safety Review Board
NSS Nuclear Shift Supervisor
OT Overtemperature
PA Protected Area
PDR Public Document Room
PMT Post Maintenance Test
GA Quality Assurance
RG Regulatory Guide i
RP&C Radiation Protection & Chemistry Control
RW River Water '
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SAS Secondary Alarm System
scfm Standard Cubic Feet per Minute
SFM Security Force Member
SRO Senior Reactor Operator
STA Shift Technical Advisor
SWS Service Water System
T&Q Training and Qualification
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
VIO Violation
VP Vice President
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