ML20147F565
| ML20147F565 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 03/03/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20147F568 | List: |
| References | |
| 50-266-96-18, 50-301-96-18, NUDOCS 9703260202 | |
| Download: ML20147F565 (56) | |
See also: IR 05000266/1996018
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U.S. NUCLEAR REGULATORY COMMISSION
2
REGION lli
Docket Nos.
50-266, 50-301,72-005
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License Nos.
Report No.
50-266/96018, 50-301/96018
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Licensee:
Wisconsin '.:lectric Power Company
Facility:
Point Beach Nuclear Plant
Locations:
Point Beach Site
6612 Nuclear Road
Two Rivers, WI 54241-9516
Corporate Engineering Office
231 West Michigan Street
Milwaukee, WI 53201
Dates:
Docember 2 - 13,1996 (Point Beach)
December 16 - 20,1996 (Milwaukee)
February 6 - 7,1997 (Point Beach)
inspectors:
M. Leach, Acting Deputy Director, Division of Reactor
Safety (OSTI Team Leader)
S. Ray, Senior Resident inspector, Prairie Island (OSTI
Assistant Team Leader)
J. Arildsen, Human Factors Assessment Branch, Office
of Nuclear Reactor Regulation (NRR)
M. Bailey, Operator Licensing Examiner
D. Butler, Reactor Engineer
D. Chyu, Reactor Engineer
J. Guzman, Reactor Engineer
J. Heller, Senior Resident inspector, Kewaunee
N. Hilton, Resident inspector, Byror
M. Holmberg, Reactor Engineer
M. Kunowski, Project Engineer
Approved by:
J. W. McCormick-Barger, Team Leader
Point Beach Oversight Team
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9703260202 970303
ADOCK 05000266
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EXECUTIVE SUMMARY
Point Beach Nuclear Plant, Units 1 & 2
NRC Inspection Report 50-266/96018, 50-301/96018
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This report includes the results of an operational safety team inspection (OSTI) conducted
from December 2 through December 20,1996. The OSTI was a broad evaluation of
routine operations, maintenance, and engineering. The inspection was conducted at the
Point Beach Nuclear Plant and the Wisconsin Electric Company Corporate Engineering
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Office. In addition, this report contains the results of an inspection conducted at the Point
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Beach Nuclear Plant from February 6 - 7,1997, to review the trip of a safety injection
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pump during emergency diesel generator load testing.
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Ocarations
Control room activities needed improvement: reactor operators were not routinely
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and regularly walking down the control panels, reactivity changes were conducted
informally, and 3-way communications were inconsistent. Informality in control
room activities has been a recurrent practice for several years at Point Beach. A
violation for not following a Technical Specification (TS)-required procedure was
identified for inattentiveness to the main control room panels (Section 01.1).
The inspectors identified four uamples where operating practices and procedures
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were not consistent with current industry practice. Reactor coolant system (RCS)
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leak testing was performed with no pressurizer steam bubble, procedures allowed
the two safety injection (SI) accumulators to be cross-connected, the nitrogen
backup for the pressurizer power-operated relief valves was normally isolated, and
two of the four emergency diesel generators (EDGs) were maintained with speed
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droop set in the govemor control system. An example of a violation of 10 CFR 50,
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Appendix B, Criterion V, " Instructions, Procedures, and Drawings," was identified
for an inappropriate procedure for cross-connecting accumulators (Section 01.2).
Some of the practices needlessly complicated operations during infrequent
evolutions and responses to events. The inspectors concluded that the licensee did
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not have a strong program for benchmarking its operation with industry and
reevaluating its practices based on those findings.
In a review of the licensee's TSs and TS interpretations (TSis), the inspectors
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identified several problems. Two examples of an apparent violation of Criterion
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XVI, " Corrective Actions," were identified for the failure to remove from control
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room documents two TSis that the license had previously identified as
nonconservative (Section 07.1). Three additional TSis were determined by the
inspectors to be nonconservative (Section 07.1) and two apparent violations for
two of those three were identified (Sections 07.2 and M3.1.1). In addition, the
inspectors identified two examples where the TSs were nonconservative and the
licensee used the TSI process in lieu of revising the TSs. An example of an
apparent violation of Criterion XVI was identified for the failure to change the
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nonconservative TS for the turbine crossover steam dump system (Section 07.1)
and an example of an apparent violation was identified for not changing the TS for
the loss-of-voltage relays (Section E3.2.2).
During refueling outages, the licensee routinely used the residual heat removal
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(RHR) system to flood the reactor cavity via the core deluge (upper plenum
injection) lines. This practice rendered both trains of RHR inoperable and eliminated
forced circulation through the core. The inspectors identified it as an unreviewed
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safety question and an apparent violation of 10 CFR 50.59 (Section 07.2).
A lower threshold for writing condition reports (problem reports) was a positive
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initiative, but department and senior management participation at daily condition
report evaluation meetings was poor (Section 08.1).
Maintenance
An example of a violation was identified for not following a leak check step of a TS-
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required procedure during routine monthly testing of an EDG (Section M1.1.3).
Since 1991, not all of the required safety-related loads were started during annual
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EDG testing initiated by a loss of alternating current followed by a simulated safety
injection signal. An apparent violation of TS 15.4.6.A.2 was identified (Section
M3.1.1 ).
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The monthly testing of the automatic start feature of the EDG fuel transfer pumps
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did not include the day tank level switches. An apparent violation of TS 15.4.6.A.5
was identified (Section M3.1.2).
Enaineering
Operability of the control room ventilation system was questionable given
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uncorrected discrepancies identified by the inspectors in the system equipment
surveillance program and design basis documentation (Section E1.1).
During plant walkdowns and condition report reviews, the inspectors identified
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several concoms with the seismic qualification of several components, including a
cracked wall between the Unit 1 EDGs, an SI system pipe support, and certain 3/8"
tubing on the RCS. ~ An example of a violation of Criterion V was identified for the
lack of acceptance criteria for the gaps between certain pipe supports and walls
(Section E2.1).
The practice of operating the train A EDGs (G-01 and G-02) with speed droop
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resulted in operating the motor of the train A motor-drivers auxiliary feedwater
pump motor at higher frequencies with the potential for tripping the associated
breaker on overcurrent. This practice was also a factor in the trip of the Unit 2
train A SI pump breaker during testing, for which an example of an apparent
violation of Criterion XVI was identified (Section E2.2). In addition, an example of a
v olation of Criterion V was identified for incorporating operator actions to prevent a
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trip of the motor-driven auxiliary feedwater pump breaker into caution statements
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of emergency operating procedures (Section E2.2).
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- The impact on operability was not properly assessed for conditions adverse to
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quality identified during design basis reconstitution of various systems. Seven
examples of an apparent violation of Criterion XVI were identified (Section E3.1).
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During a review of electricalissues related to design basis reconstitution efforts, the
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inspectors identified three examples of an apparent violation of Critorion XVI for the
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failure to assess the impact on operability: 1) the inadequate fault current
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interruption capability of safety-related breakers (Section E3.2.1), 2) a cable
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separation issue involving the Unit 1 containment spray system (Section E3.2.4),
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and 3) the potential common mode failure of direct current buses that could affect
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the actuation capability of the Unit 2 main steam isolation valves and engineered
safety features (Section E3.2.5), in addition, an example of an apparent violation
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of Criterion XVI was identified for the failure to change the nonconservative TS on
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safety-related bus loss-of voltage relay setpoints (Section E3.2.2), and a violation of
Criterion lil, " Design Control," was identified for using a nonconservative value for
the reactor breaker trip time in a calculation. Weak corrective action for this design
control problem constituted another example of an apparent violation of Criterion
XVI (Section E3.2.3).
From a review of a quality assurance audit of the licensee's planned change to
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Option B of 10 CFR 50, Appendix J, the inspectors identified that four spare
containment penetrations were not promptly tested after the licensee became
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aware of the need for the tests and that the NRC was not notified of the late tests.
An example of an apparent violation of Criterion XVI for the late tests and a
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violation of a 10 CFR 50.73 reporting requirement were identified (Section E7.2).
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Plant Suonort
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The licensee's initial evaluation of Information Notice 92-18, " Potential for Loss of
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Remote Shutdown Capability during a Control Room Fire," focused on " hot smart
shorts" in motor-operated valve power circuitry and did not address the control
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circuitry. The final evaluation will be reviewed during a future inspection (Section
F2.1 ).
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TABLE OF CONTENTS
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01
Conduct of 0perations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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01.1 Main Control Room Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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01.2 inconsistencies with Common industry Practices
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01.2.1 Reactor Coolant System Pressure Control During Leak Testing . .
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01.2.2 Cross-Connected Safety injection (SI) Accumulators . . . . . . . . .
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01.2.3 Control of Nitrogen Supply to the Power Operated Relief
Valves
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01.2.4 Maintaining Emergency Diesel Generators in the Speed Droop
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Mode.........................................
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01.3 Conclusions to Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . .
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03
Operations Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . 11
03.1 Procedure Adequacy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
11
03.2 Operations Department Program implementation . . . . . . . . . . . . . . . .
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07
Quality Assurance in Operations
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07.1 Technical Specifications and Interpretation issues . . . . . . . . . . . . . . .
14
07.1.1 Licensee-ldentified Nonconservative TSis . . . . . . . . . . . . . . . .
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07.1.2 Inspector-Identified Nonconservative TSIs . . . . . . . . . . . . . . .
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07.1.3 Inspector-identified Nonconservative TSs . . . . . . . . . . . . . . . .
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07.2 Alternate Path for Residual Heat Removal . . . . . . . . . . . . . . . . . . . . .
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07.3 Inappropriate Interpretation of EDG Fuel Transfer P Jmp Operability . . .
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08
Miscellaneous Operations issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
08.1 Condition Reporting and Operability Determination Process . . . . . . . . .
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M1
Conduct of Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
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M1.1 Surveillance Observations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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M1.1.1 Monthly Test of the G-04 EDG
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M1.1.2 Monthly Test of the G-02 EDG . . . . . . . . . . . . . . . . . . . . . .
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M1.1.3 Quarterly Reactor Protection and Emergency Safety Features
Test..........................................
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M3
Maintenance Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . . . . . 23
M3.1 Surveillance Procedure Deficiencies . . . . . . . . . . . . . . . . . . . . . . . . .
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M3.1.1 Inadequate EDG Test With Loss of AC Coincident With SI
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M3.1.2 inadequate EDG Fuel Oil Transfer System Test . . . . . . . . . . . .
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M3.2 CH AMPS O bservations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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M3.3 Conclusions on Maintenance Procedures and Documentation
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M8
Miscellaneous Maintenance lasues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
M8.1 O perator Workarounds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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E1
Conduct of Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
E1.1
Control Room Ventilation
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E2
Engineering Support of Facilities and Equipm'.,6st .....................
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E2.1
Seismic issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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E2.2 EDG Governor Droop Settings . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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E2.3 Conclusions on Engineering Support of Facilities and Equipment
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E3
Engineering Procedures and Documentation ........................
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E3.1
Design Basis Document Reviews . . . . . . . . . . . . . . . . . . . . . . . . . . .
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E3.1.1 Untimely Operability Determinations
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E3.1.2 Weak Operability Determinations . . . . . . . . . . . . . . . . . . . . . .
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E3.2 DBD-Related Technical issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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E3.2.1 Inadequate Fault Current Interrupting Capability of Breakers . . .
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E3.2.2 Nonconservative TS Setpoints for Loss-of-Voltage Relays
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E3.2.3 Adequacy of the Setpoint Used for the RCP UV Trip . . . . . . . .
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E3.2.4 Cable Separation issue with Unit 1 Containment Spray System .
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E3.2.5 Cable Separation lasue involving Molded-Case Circuit Breakers .
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E3.3 Revised Operability Determination Process . . . . . . . . . . . . . . . . . . . .
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E3.4 Conclusions on Engineering Procedures and Documentation
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E7
Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . . . . . . . . . .
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E7.2 Quality Assurance Audit of the Containment Leakage Rate Testing
Program
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F2
Status of Fire Protection Facilities and Equipment ....................
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F2.1
Valve Performance During Postulated Appendix R Fire Scenarios . . . . .
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Esit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52
PARTI AL LIST OF PERSONS CONTACTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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INSPECTION PROCEDURE USED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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ITEMS OPENED, CLOSED, AND DISCUSSED . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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LIST OF ACRONYMS l' SED
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Report Details
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Summary of Plant Status
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Unit 1 operated at or near full power until power was reduced to 90 percent on December
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19,1996, for the remainder of the inspection. The licensee reduced power to emphasize
to plant staff the nood to make significant improvements in operations, engineering, and
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the corrective actions program. Unit 2 remained in cold shutdown for a refueling and
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steam generator replacement outage during the entire inspection.
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1. Onorations
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01
Conduct of Operations
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01.1 Main Control Room Observations
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a.
Inspection Scope (93802)
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The inspectors observed 72 consecutive hours of main control room activities.
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During this period, the inspectors observed the operating crews ("watchstanders")
and evaluated attentiveness, communications, and operating practices.
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Additionally, the inspectors observed surveillance activities, turnovtrs, and overall
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control of shift activities.
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The inspectors also reviewed the following procedures:
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Operations Manual (OM) 4.1.6, " Alarm Response," revision O
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OM 2.2, " Duty Shift Superintendent," revision O
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OM 2.3, " Duty Operating Supervisor," revision 0
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OM 2.5, " Licensed Operators," revision O
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OM 2.15, " Operations Organization and Responsibilities," revision 5
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OM 3.1, " Main Control Room Environment Conduct and Access," revision 5
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OM 3.9, " Guidelines for Watchstanding, Logbooks, Records, and Status
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Control," revision 3
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b.
Observations and Findings
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During the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, N inspectors observed mixed operating practices with
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notable differences between crews. Significant weaknesses are discussed below,
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The inspectors noted that reactor operators, known as Control Operators (COs), did
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not routinely face the control boards (panels), but faced the back of the control
room, where the Duty Shift Superintendent (DSS) and the Duty Operating
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Supervisor (DOS) were stationed. The DSS and DOS were the onshift senior
reactor operators (SROs). The desk used by the COs contained computer monitors
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for the COs to trend reactor plant parameters. However, the inspectors noted that
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the number of parameters available to be monitored was limited, and only four
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parameters were being routinely trended.
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in addition, the inspectors observed that COs were not routinely and regularly
walking down the panels. During one period of approximately four hours on
December 3, the inspectors observed the Unit 1 CO walkdown the panels only
once, when the plant manager entered the control room. On December 4, the
inspectors observed the Unit 1 CO identify a feedwater flow meter (1F1-477, steam
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generator food flow indication) with the needle stuck on the low peg. The operator
touched the meter and the needle it.imediately returned to the normal operating
range. The inspectors observed instrument and control (l&C) technicians
subsequently verify the calibration of the instrument. The operators indicated to
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the inspectors that the motor most likely stuck on the low peg during reactor
protection analog testing performed earlier the same day. The CO identified the
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stuck meter while performing the shiftly logs. Approximately two hours elapsed
between the documented completion of analog testing and identification of the
stuck meter. A shift turnover also occurred during the two-hour period without
identification of the stuck meter.
The inspectors noted that OM 3.1, section 7.1.4, stated that "watchstanders are
expected to monitor instrumentation, including computer screens, at frequent
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intervals consistent with plant conditions and evolutions in progress." Technical
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Specification (TS) 15.6.8.1 required that the plant be operated and maintained in
accordance with approved procedures. The inspectors concluded that the failure to
identify 1F1-477 stuck on the low peg for about two hours after completion of a
surveillance did not constitute frequent monitoring consistent with plant conditions
and evolutions in progress and was therefore, contrary to OM 3.1 and a violation of
TS 15.6.8.1 (VIO 50-266/g6018-01a(DRP)).
The inspectors observed instances of good 3-way communication techniques during
the 72-hour observation period; however, examples of poor techniques during both
face-to-face and radio communications were also observed. One shift rarely used
3-way communications. Repeat-backs were infrequent. Additionally, informal
language, such as "Got your ears on?" and "Have a ball" was common. The
inspectors also noted both numerous and loud radio transmissions and page
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announcements in the control room. During significant portions of each shift,
particularly during day shift and early in the evening shift, audible communication in
the control room via the radio or page system was almost constant.
The inspectors noted that the control room was the most minimally staffed within
the Region. The crew size met the minimum staffing requirements of both TSs and
10 CFR 50; however, operators were generally not available to provide assistance
to other operators, if necessary, during events or complex evolutions. Official
licensed crew staffing consisted of a reactor operator (CO) for each Unit and one
extra reactor operator, one SRO for control room supervision (the DOS), and one
SRO as the shift manager (the DSS). Frequently, the licensee assigned an
additional SRO to a shift, but the position was not required to be filled.
The inspectors also noted during review of OM 2.2 and 2.3 that the DOS was
expected to respond to the scene of any fire. The DSS would be the only SRO
remaining in the control room and OM 2.2 required the DSS to be the fire brigade
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chief. The inspectors were concerned that with minimal manning in the control
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room, the DSS would be forced to coordinate fire fighting efforts and monitor and
respond to all potential plant transients resulting from the fire. This item will be
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reviewed during a future inspection as an inspection followup item ((IFl) 50-
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266(301)/96018-02(DRP)).
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The inspectors observed the licensee operating the reactor at 100.2 percent of
rated thermal output. A CO stated that the practice was to make up for the time
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that thermal output was less then 100 percent, thereby ensuring that the 8-hour
average was 100 percent c; less. However, when reactor power was greater than
100 percent, the CO did not make an attempt to reduce power. The inspectors
considered a more constervative practice would be to reduce power slightly
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whenever output was p,reater than 100 percent rather than waiting for power to
come down on its own. The practice of opeisting at greater than 100 percent
power may be vic6 tion of the operating license and will be reviewed further as an
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unresolved item (URI 50-266(301)/96018-03(DRS)).
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The inspectors observed of several Unit 1 boron dilution activities and two rod
movement activities. In each case, the CO performed the activity and did not
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inform an SRO either before or after the reactivity change. Additionally, no log
entry was not made. The inspectors noted that the reactivity changes were
appropriate and completed in an acceptable manner; however, the changes were
conducted very informally. The Operations Manager stated to the inspectors that
reactivity management expectations were under development.
01.2 inconeiatencies with Common industry Practices
a.
Insoection Scone (93802)
The inspectors made control room observations and reviewed technical
specification interpretations (TSis) from the Duty and Call Superintendent (DCS)
Handbook and design basis document (DBD) open items. The scope of each of
these three areas is discussed in sections 01.1,07.1, and E3.1, respectively.
During the observations and reviews, the inspectors identified four examples of
inconsistencies with common industry pcactices, as discussed below,
b.
Observations and Findinas
01.2.1 Reactor Coolant System Pressure Control Durina Leak Testina
The inspectors identified that the licensee used an abnormal pressure control
method during reactor coolant system (RCS) leak testing. The method was to
maintain the RCS " solid" (completely filled with water with no steam bubble in the
pressurizer) and balance charging and letdown flow to maintain the required
pressure. The RCS would also be heated up during the process to about 400
degrees Fahrenheit (*F). The operators were required to compensate for thermal
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expansion of the reactor coolant while maintaining pressure. The inspectors
considered this a big demand on operator attention that could be difficult during
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system transients. A solid RCS also eliminated the pressure absorbing capability of
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the pressurizer, making the system more susceptible to transients. For example, on
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March 31,1996, operators removed a reactor coolant pump from service while
" solid" and the low temperature overpressure protection (LTOP) system actuated.
The licensee identified that the original reason for performing the leak test with the
RCS " solid" was to allow the operators to reduce system pressure rapidly in the
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event of a leak. This approach had some merit at the beginning of the plant's
operating life when the tempersture at which the leak test was performed was less
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then 200 'F. However, as the nil-ductility transition temperature of the vousel had
increased and an RCS temperature of 400 *F was required prior to reaching full
RCS pressure, the merit of this approach had been eliminated.
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Also, the current method of heatup was not in agreement with the Final Safety
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Analysis Report (FSAR). FSAR Section 4.1, " Reactor Coolant System - Design
Bases," stated that the RCS heatup rate would be less than the maximum 100 SF
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per hour because of interruptions such as drawing a pressurizer steam bubble. That
implied that the design intent was to draw a bubble during heatup and ~not after the
leak test.
01.2.2 Cross-Connected Safety Iniection (Sil Accumulators
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On December 3,1996, the Unit 1 CO resolved a low pressure alarm for one of the
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two safety injection (SI) system accumulators per Operating instruction 01-100,
" Adjusting SI Accumulators Level and Pressure," revision 5. During this activity,
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the inspectors observed a placard affixed next to the accumulator pressure and
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level gauges that directed entry into a 1-hour limiting condition for operation (LCO)
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because one accumulator was inoperable when the two accumulators were cross-
connected.
In addition to the placards, step 2.7 of 01-100 stated: "If it becomes necessary to
cross connect both Si accumulators via the nitrogen inlet valves SI-834A&B and/or
the normal fill valves SI-835A&B, then it will be required to enter a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> LCO, due
'
to disabling one Si accumulator."
Although the CO was not required to cross-connect the accumulators to reestablish
the cover gas pressure in this case, the inspectors reviewed the issue further to
determine if the provision on the placard was allowed by TS 15.3.3, " Emergency ~
Core Cooling Systems, Air Recirculation Fan Coolers, and Containment Spray."
The inspectors discussed with the operations staff % placard and the provisions of
01-100 that permitted the Si accumulators to be crrss-connected. The staff
considered only one accumulator inoperable since operators would isolate the
affected accumulator, in addition, they referenced the text in the associated TS
15.3.3 bases.
TS 15.3.3 required both accumulators be operable and provided an LCO if one
accumulator was inoperable. In the TS 15.3.3 bases section, cross-connection of
8
1
)
'
,
,
the accumulators was given as an example of a condition when an accumulator
was inoperable. However, the bases referenced TS 15.3.0 as the action statement
for an inoperable accumulator and discussed an LCO that was not as restrictive as
TS 15.3.3. The discrepancy between the TS and TS bases was discussed with the
site lice 2ng personnel who committed to resolve the inconsistencies during a
suberg ot TS change. The revision to the TS basis will be reviewed during a
futurt %4ction (IFl 50-266(301)/96018-04(DRP)).
NRC Information Notice (IN) 96-31 (dated May 22,1996), " Cross-Tied SI
Accumulators," documented that a plant may be outside its design basis when
accumulators were cross-tied. If accumulators were cross-tied during a loss-of-
coolant accident (LOCA), the nitrogen cover gas was postulated to bleed off
through tra faulted accumulator. This could result in nitrogen pressure in the
operable accumulator lower than assumed in the accident analysis. The IN stated
that several other licensees recently changed procedures to prohibit cross-
connecting accumulators.
The Point Beach engineering department review (dated July 24,1996) of IN 96-31
concluded that cross-tioing accumulators might not be prudent and recommended
that the issue be reanalyzed by the emergency core cooling system vendor. The
review referenced the TS basis that implied only one accumulator was inoperable
when the accumulators were cross-connected. No action was taken to prevent the
practice while awaiting further information from the vendor.
The inspectors reviewed control room logs and did not identify any examples within
the last two years of cross-connected accumulators. After the inspectors held
several discussions with plant staff on the cross-tie issue, operations management
issued Temporary information Record Sheet No.96-138 on December 16, which
placed tags on the control board prohibiting the practice.
The inspectors did not agree with the licensee's position pertaining to cross-tioing
accumulators. If accumulators were cross-connected then both should be
considered inoperable, a condition prohibited by TS.10 CFR 50, Appendix B,
Criterion V, " Instructions, Procedures, and Drawings," required that activities
affecting quality be prescribed by procedures of a type appropriate to the
circumstances. Contrary to this requirement,01-100 did not provide appropriate
instructions pertaining to the operability of cross-connected accumulators. Failure
to provide adequate instructions is an example of a violation of Criterion V (VIO 50-
266(301)/96018-05a(DRP)).
01.2.3 Control of Nitrocan Sunolv to the Power Ocarated Relief Valves
During the review of DBD open item DBDOI-06-005, " Design requirements for l&SA
system various nitrogen bottles are unknown," the inspectors noted that the
nitrogen supply to the pressurizer power operated reliefs valves (PORVs) was
normally isolated. The PORVs were air operated valves and the nitrogen was
provided as a backup motive force when LTOP was required. However, when
LTOP was not required, the nitrogen was isolated. The inspectors verified that
9
-
- . - - - - - - - - - - . . . -
.
,
procedures specified that the nitrogen isolation valves were opened or closed as
required for LTOP.
The licensee stated that nitrogen was isolated to allow rapid depressurization of the
instrument air header if the PORV was subjected to a fire-induced short circuit.
Depressurizing the air header allowed the spring to close the PORV. The inspectors
noted that if the nitrogen was not isolated, the nitrogen bottles would depressurize
with the header.
Emergency Operating Procedure (EOP) 1.2, "Small Break Loss of Coolant Accident
(SBLOCA)," step 31, stated that if actions can be performed in the containment, an
operator should enter containment and open the nitrogen isolation valves. Step 31
was to be performed as part of placing LTOP in operation after cooling the RCS.
The PORV was one option used in EOP 1.2 to help depressurize the RCS during an
SBLOCA. Instrument air is not safety-related. Although the EOPs contained steps
to unisolate and restart instrument air, the PORV nitrogen backup would not be
available. The inspectors found the practice of routinely operating with the backup
supply (nitrogen) to the PORV isolated inconsistent with industry practice. This
practice reduced the availability of a system important to safety.
01.2.4 Maintainina Emeroency Diesel Generators in the Snead Droon Mark
The inspectors noted that the G-01 and G-02 emergency diesel generators (EDGs)
were maintained in the standby condition with speed droop set into the govemor
control system. That meant diesel output frequency would vary with generator
load when the diesel was supplying an electrical bus that was isolated from offsite
power. As further discussed in Section E2.2 of this report, this was inconsistent
with common industry practice and necessitated operator intervention during
certain accidents to prevent the motor-driven auxiliary feedwater (MDAFW) pump
from tripping.
01.3 Conclusions to Conduct of Onorations
The inspectors concluded that the conduct of operations was poor in several areas.
Operators were frequently inattentive to the panels and potentially unaware of
changing indications on the panels. Additionally, communications were frequently
both casual and distracting. The inspectors were concerned that significant reports
and communications could be misunderstood or not received. The inspectors also
noted that the control of reactor power and the changing of reactivity were
informal.
Additionally, the inspectors identified four examples where operating practices and
procedures were not consistent with current industry practice. Some of the
practices needlessly complicated operations during infrequent evolutions and
responses to events. The inspectors concluded that the licensee did not have a
strong program for benchmarking its operation with industry and reevaluating its
practices based on those findings.
10
. . _ _.-
_ . _ . _ _ _ - _ . _ . _ _ . _ _ . _ - _ .
. _ _ - . . . _ _ _ _ _ . _ . _ . _ .
-
>
'
..
.
,
1-
l
!
!
t
t
03
Operations Procedures and Documentation
.
!
j
03.1 Procedure Adeauncy
!
s.
Inanection Scone (93802)
i
,
i
!
The inspectors observed plant operations and reviewed a sample of plant
]
procedures to determine procedure adequacy. The inspectors reviewed the
!
following documents:
}
i
Operating Procedure (OP) 1 A, " Cold Shutdown to Low Power Operation,"
i
-
-
revision 57
OP 18, " Reactor Startup," revision 26
!
-
j
OP 1C, " Low Power Operation to Normal Power Operation," revision 54
l
-
OP 2A, " Normal Power Operation," revision 25
-
OP 3A, " Normal Power Operation to Low Power Operation," revision 37
!
!
-
OP 3C, " Hot Shutdown to Cold Shutdown," revision 65
j
-
Inservice Test (IT-21), " Charging Pump and Valves Test (Quarterly),"
-
>
revision 4
j
Technical Specification Test (TS)-82, " Diesel Generator Testing of G-02,"
-
j
revision 47
.,
l
Non-Destructive Examination Procedure (NDE)-6, " Procedures for Nuclear
l.
-
Power Plant Examination Operations," revision 15
'
NDE-8, " Calibration of Magnetic Particle Equipment," revision 4
-
NDE-15, " Calibration Procedure - Black Light Equipment," revision O
.
,
NDE-106, " Ultrasonic Examination: Instrument Performance Verification and
-
.
l
Search Unit Beam Spread," revision 5
l
. NDE-350, " Magnetic Particle Examination Alternating Current (AC) Yoke,"
-
i
revision 12
NDE-351, " Magnetic Particle Examination Longitudinal Magnetization - Coil
-
i
Method," revision 10
}
NDE-451, " Visible Dye Penetrant Examination," revision 11
-
i
!
b.
Oh== vations aru Findinas
.
1
A number of operating procedures included "should" statements versus "shall"
!
statements and, therefore, did not provide clear directions to the operators. The
most significant of these was in section 2.4.5 of OP-1C which stated the main
i
turbine should be tripped if turbine vibration exceeded 14 mils; however, licensee
j
management stated to the inspectors that the expectation was the operators aball
[
trip the turbine at 14 mils.
!
!
Section 2, " Precautions and Limitations," of OP-1 A contained some notes in bold
{
italics. For example, " Note: If steam generator level is less than 20 percent on the
i
narrow range, do not exceed a feedwater addition rate of 100 gpm." The
inspectors viewed these notes as operating precautions and limitations, but
questioned whether the operators would view them as such because they were
4
11
'
'!
.i
. . .
,
-.
.._
, _ , . _
-
-
.
-
- - - - _
. - - - . - . _ - - . . - _ _ - - . .
_
.
.
!
l
included as notes. The licensee agreed the items should be precautions and
limitations and should not be included as notes.
1
!
Notes on pages 4,7, and 9 of IT-21 stated that a pump warmup was not required
i
if the pump was running prior to the test. However, the statements lacked
specificity as to the duration of the previous pump run and the maximum elapsed
-
time between completion of the run and the start of the test. Therefore, the
4
i
procedure did not ensure pump warmup comparable to the required 15-minute run
j
times in steps 4.3.3,4.4.3, and 4.5.3. In addition, the procedure did not provide a
j
comprehensive list of required equipment. Use of the strobotech/phototech was
j
addressed; however, no mention was made of the potential radiological anti-
contamination material, particular vibration measurement instrument, flashlight, and
~
extension cord which the operator was required to use. In fact, while the
j
inspectors were observing the test, the operator made three separate trips to
storage lockers as the equipment noods became evident during the performance of
!
the procedure.
a
l
c.
Conclusions
i
l
The inspectors concluded that operating procedures often lacked clear direction
.
concoming marmgement expectations.
03.2 Onarations Danartment Proaram Imniamentation
i
a.
Insoection Scone (93802)
i
l
The inspectors observed activities and reviewed several procedures to evaluate
j
operations department program implementation. The inspectors reviewed the
j
following documents:
}
Operations Notebook
.
j
OM 3.13, " Operations Notebook," revision 1
-
TS-82, " Diesel Generator Testing of GO-2," revision 47
]
-
j
Nuclear Power Business Unit Procedure (NP) 1.9.15 " Danger Tag
-
l
Procedure," revision 2
Danger Tag Location Sheets: 222-6, 222-174, 222-178, and 222-190
!
l
l
b.
Observations and Findinas
!
!
The Operations Notebook was used by operations management to informally
j
communicate timely information to the on-shift operators. The inspectors noted
{
that operator review of Operations Notebook information was not always being
i
documented. OM 3.13 required on-shift personnel to review the Operations
Notebook on a daily basis or as soon as practicalif absent from shift due to
training, reliefs, vacation, sickness, and other reasons. Several on-shift personnel
j
assigned to different shifts had not initialled the review record sheet to indicate
i
review. The inspectors verified that these operators were either on shift or had
been on shift since the most recent entries in the Operations Notebook, in addition,
i
l
12
l
1
,
. , - - - - - , -
-.
,
- . , .
,.
-
-
- .. --
~
-
.-
-
.
. .
_
. - - -
-
5
.
,
'
OM 3.13 required the responsible DSS or DOS to ensure that all Operations
'
Notebook entries were reviewed by the crew. This weakness was previously
identified in NRC Inspection Report 50-266(301)/96007.
,
On December 5, the inspectors observed operators perform raonthly surveillance
testing on EDG G-02. A problem with procedure adherence is discussed further in
!
Section M1.1.3 of this report.
i
On December 6, the inspectors reviewed a sampling of safety-related danger tag
location sheets for Unit 2 AFW, SI, and residual heat removal (RHR) systems. The
location sheet contained a number of columns to identify important information,
,
such as " Required Position, Tag Sequence (upon initial hanging), Component
i
DescriptionA'ag Location, Tagged By, Checked By, Removal Sequence (upon tag
'
removal / clearance), and Removed initial." All applicable information was provided
except for the " Tag Sequence and Removal Sequence" columns which were left
blank for a majority of entries. Step 6.6.4 of NP 1.9.15 stated, in part, that "The
DSS / DOS /OS shall assign a removal sequence and desired position on the Danger
'
Tag Location Sheet."
4
Earlier, on November 28, the licensee identified a similar problem and wrote
condition report (CR) 96-1550. The CR noted that a general practice had developed
,'
among the operators to not specify an installation or removal sequence on the tag
i
sheet for " simple" tag series. Also, the CR stated that this " common" practice was
not in accordance with NP 1.9.15, and recommended that the emphasis be placed
l
on revising the procedure or putting a sequence number on the sheet. On
December 3, the corrective action was to make an entry into the Operations
)
,
Notebook as a reminder to all operators to comply with the procedural requirement
.
during tag removal. The inspectors did not identify any procedural deficiencies
!
after December 3.
10 CFR 50, Appendix B, Criterion V, " Instructions, Procedures, and Drawings"
requires that activities affecting quality be prescribed by procedures of a type
'
appropriate to the circumstances and be accomplished in accordance with these
,
procedures. Failure to assign a removal sequence to the danger tag location sheet
in use was contrary to procedure NP 1.9.15 and is a violation of Criterion V. This
licensee-identified and corrected violation is being treated as a Non-Cited Violation,
,
i
consistent with Section Vll.B.1 of the NRC Enforcement Policy (NCV
'
266(301)/96018-06(DRP)).
c.
Conclusions
'
'
The inspectors concluded that operations management was unable to show,
through proper documentation, that all operators were promptly reviewing the
Operations Notebook. The inspectors also concluded that the corrective actions for
a problem with danger tag documentation were appropriate in the short term.
13
i
__ . . __._...
. - _ _..__. _
__ _ _ . _ _ _ _ . _ . _ . _ _ . _ _ . _ _._ . ._ . __._ ,
-
!
j
-.
<
,
l
1
,
ii
j
07
Quality Assurance in Operations
07.1 Technical Snecifications and Mternretation lasues
, ;
I
a.
Insnection Scone (03802)
!
Inspectors reviewed the TSI process. This review included the 23 current TSis
!
maintained in the Duty and Call Superintendent Handbook, and the affected
i
sections of the TSs.
l
l
b.
Observations and Findings
ii'
The inspectors identified continued weaknesses in the TSis. During the September
12,1996, enforcement conference (Report No. 50-266(301)/96011), the licensee
committed to complete a review of administrative controls (including TSis) against
I
the TSs. The results of the review were documented in a letter dated October 15
i
from the corporate licensing staff to the site manager. The review identified
!
l
nonconservative TSs and TSis; however, it appeared to lack rigor in that the
l
inspectors identified additional nonconservative TSs and TSis. Further, prompt
!
action was not taken as a result of the October 15 TSI review. As of December 6,
)
{
licensee-identified nonconservative TSis were still in the DCS Handbook and action
!
i
to change the TSs or to delete or revise the TSis was minimal. However, the
'
inspectors found no instances where the TSis had been used.
l-
07.1.1 Licensee-Identified Nonconservative TSis
j
.
I
TSI DCS 3.1.20 allowed full power operation with only one 345-kilovolt (KV)
l
transmission line in service to an operating reactor instead of reducing reactor
i
l
power to 50 percent as discussed in the basis of TS 15.3.7. This conflict with the .
i
TS basis was a condition adverse to quality. The October 15 review properly
!
recommended cancellation of this TSl; however, it remained in the DCS Handbook
!
until at least December 2. The failure to remove the TSI from the DCS Handbook
on or around October 15 is an example of an apparent violation of 10 CFR 50,
Appendix 8, Criterion XVI, " Corrective Actions" which requires, in part, that
i
,
conditions adverse to quality are identified and corrected (eel 50-266(301)/96018-
,
l
07a).
)
TSI DCS 3.1.27 did not require a pressurizer PORV to be declared inoperable
i
upon placing the control switch in the main control room to the close position. This
was contrary to TS 15.3.1.A and the NRC safety evaluation of TS change request
]
(TSCR) 145, which implemented the licensee's response to Generic Letter (GL) 90-
i
06, " Resolution of Generic lasue 70, ' Power-Operated Relief Valve and Block Valve
'
,
Reliability,' and Generic lasue 94, ' Additional Low-Temperature Overpressure
'
i
Protection for Light-Water Reactors,' Pursuant to 10 CFR 50.54(f)." The October
i
15 review recommended cancellation of this TSl; however, it also remained in the
!
DCS Handbook until at least December 2. The failure to remove the TSI from the
!
DCS Hanc. book on or around October 15 is an example of an apparent violation of
i
Criterion XVI (eel 50-266(301)/96018-07b).
}
j
14
a
i
w
m
=- . - -,
e
-e--
+ - - =
e. m
raya.far-
r
ru
-
.- -
- . - - - . . - . _ . - . - - - .
.
- . - - . . - - - - -
- -
- - - -
.
.
.
.
!
f
i
07.1.2 insanctor-identified Nonconservative TSIs
<
'
The inspectors identified the following nonconservative TSis, which appeared to
i
l
change the intent or requirements of the underlying TSs:
TSI DCS 3.1.11 attempted to clarify TS 15.4.6.A.2 which described the annual
!
.
auto-start test of the EDGs initiated by a loss of normal alternating current (AC)
'
power with a simultaneous SI start signal. The TSI specified that the EDG loads
need not actually start during the portion of testing which was intended to fulfill the
l
TS. The TSI specified that only the breakers for the equipment loads need to
operate in the correct sequence and at the correct time. The inspectors considered
,
i
this TSI to contradict the intent of the TS, since the monthly tests as performed by
!
the TSI would not adequately test the EDG under accident loading conditions. The
!
,
use of this interpretation constitutes an apparent violation as discussed in Section
I
,
j
M3.1.1.
8
l
TSI DCS 3.1.17 allowed the use of an administrative 4-hour LCO for the EDG fuel
oil system prior to entering the standby emergency power LCO of TSs 15.3.7.b.1.f
i
and 15.3.7.b.1.g. The use of this interpretation is discussed further in Section
j
07.3.
!
3
TSI DCS 3.1.22 allowed the use, during refueling, of the two core deluge lines to
1
remove decay heat as an alternate to the normal RHR line. Yhis alternate path was
i
not specified in TS 15.3.1.A.3. The inspectors considered the use of the TSI as
i
j
inappropiste and an example of an apparent violation as discussed in Section 07.2.
l
.
,
j
NP-5.1.4, " Duty And Call Superintendent Handbook," revision 1, included
approximstely two pages on control and generation of TSis. The inspectors
i
!
concluded the guidance on TSI development lacked detail and that this could have
i
j
contributed to the inappropriate use of TSis. For example, the procedura did not
i
specifically require a safety evaluation for each TSI and consequently several of the
l
TSis reviewed did not have safety evaluations. Further, there was no provision for
'
a cross-reference (such as a stamp) between the controlled copies of the TSs and
the TSis to inform operators of the existence of a TSI for a given TS. Operators
relied on training and memory to know when a TS had a corresponding TSI.
07.1.3 Inacector-identified Nonconservative TSs
The inspectors identified two examples where the TSs were nonconservative and
the licensee had used the TSI process in lieu of revising the TS.
TS 15.3.4.E required that power be reduced to less than 480 megawatts
electrical (MWe) within three hours if the crossover steam dump system was
inoperable. In April of 1995, a Westinghouse analysis demonstrated that this TS
value was nonconservative and stated that power must be reduced to less than
450 MWe to ensure turbine overspeed protection. However, instead of revising the
nonconservative TS, the licensee utilized TSI DCS 3.1.25 which imposed LCOs for
the crossover steam dump system and added administrative limits to control turbine
15
1
1
l
1
--
. - - . . .-
- _ - . - . . - . - - - - . - -
-
. .
. . - . - - . . - .
- - - -
-
,
4
i
4
loads. The licensee's 50.59 screening of this issue stated that no TS change was
'
!
involved. As of December 6,1996, the licensee had not initiated a license
i
amendment to address this issue, but after continued discussions with the
inspectnrs, the licensee indicated the need for an amendment would be reevaluated.
!
- Notwithstanding the reevaluation, the failure to change TS 15.3.4.E when the
!
licensee became aware in April 1995 that the TS did not accurately specify the
!-
lowest function capability or performance level of the crossover steam dump
,
system is an example of an apparent violation of Criterion XVI (eel 50-
266(301)/96018-07c).
!
. TS 15.3.5.A required that engineered safety features (FSFs) initiation instrument
!
settings be as contained in Table 15.3.5-1. In April 1995, the licensee submitted a
!
TSCR to lower the loss-of-voltage settings. While the TSCR was being reviewed by
the NRC, the licensee determined that the requested settings were also too high;
however, no attempt was made to revise the TSCR. This item is discussed further
j
in Section E3.2.2
i
- c.
Conclusions
i
)
The inspectors identified two examples of licensee-identified nonconservative TSis
j
that were not promptly corrected, two examples of an inspector-identified
j
nonconservative TS, and three examples of inspector-identified nonconservative
!
TSis. The inspectors considered the weak administrative control of the TSI process
i
and an apparent reluctance to revise TSs to be a factor in these problems.
}
07.2 Alternata Path for Ranidual Heat Removal
]
{
a.
Inspection Scone (93802)
'
The inspectors reviewed the following documents:
i
TSI DCS 3.1.22, revision 0, March 30,1994, "Use of Core Deluge as a
-
Modified Residual Heat Removal (MRHR) Loop"
the associated 50.59 safety evaluation (SER 91-118), dated November 8,
j
.
1991
i
FSAR Section 9.3, " Auxiliary Coolant System"
.
b.
Obaarvations and Findinos
The TSl, of TS 15.3.1.A.3.b on RHR, allowed the use of the two-4" core deluge
lines (intended as the low-head, upper plenum injection lines during an SI) as an
alternate RHR return path. During non-accident operations, the normal RHR retum
path was to the 27.5" loop B cold leg. Use of the altamate path facilitated the
American Society of Mechanical Engineers (ASME) testing of certain RHR and SI
'
system check valves and limited previous problems with reactor cavity water clarity
and dose rates that occurred during refueling outages when flooding the cavity via
,
the B cold leg,
i
16
_ _ __ _ ._ _ _ _ _ _ _ _ _ ._ _ ._ _
--__._ _ _ ___ ___ _
.
,
The 50.59 safety evaluation (SE) stated that the consequences of a boron dilution
accident might be increased by using the alternate path because it did not provide
forced circulation of coolant through the core; whereas, the normal path did. To
offset this increase, the evaluation prescribed closure and tagging of certain valves
downstream of the reactor makeup water tank prior to use of the alternate path to
"eluninete" the possibility of a dilution accident. The evaluation also noted that the
attemete path precluded forced circulation in the core, but a calculation that had
been performed indicated that heat generation would not significantly increase peak
cladding temperatures.
From a discussion with the licensee and a review of documents, the inspectors
determined that the alternate RHR path had been used regularly the past several
years. This path was described in the RHR chapter of a system training manual
dated September 8,1987, but not in the FSAR, where an RHR loop was described
(Section 9.3.2) as being connected at the hot leg of one reactor coolant loop and to
the cold leg of the other reactor coolant loop. The valve repositioning involved in
the use of the core deluge lines rendered both RHR trains inoperable. The most
recent examples where the alternate RHR return path was used were for reactor
cavity flooding on or around April 3,1996 (Unit 1 refueling outage) and October
12,1996 (Unit 2 refueling outage).
The change in the RHR system from September 1987 to December 1996, when
this issued was identified by the OSTI, involved an apparent unreviewed safety
question in that the probability of an analyzed dilution accident was increased. The
licensee attempted to offset this increase through administrative controls on the
source of dilution; however, NRC prior approval was not obtained. This change to
the facility is an apparent violation of 10 CFR 50.59 which requires, in part, that
prior NRC approval be received before changes are made to the facility as described
in the FSAR that involve an unreviewed safety question (eel 50-266(301)/96018-
08).
.
c.
Conclusions
!
An apparent unreviewed safety question existed for the change to the RHR. system.
The change involved the use of an alternate RHR discharge path during cavity
l
flooding, a path different from that described in the FSAR and one which eliminated
l
forced circulation through the core.
07.3 Inanorooriate Interoretation of EDG Fuel Transfer Pumo Goerability
a.
Inapection Scone (93802)
On December 4, the inspectors identified that the licensee had written a 4-hour
LCO for diesel fuel oil pump inoperability in several procedures without amending
the TS. As part of the followup review, the inspectors reviewed the following
documents:
3
l
!
17
L
_- _ .__ _ __ _
__
-
-
__
_ _ . _ _ _ _ _ . _ _ _ _ _ _ . _ _ _ _ _ _
. _ . _ . _ _ _ _ _ _ _ _
l
.
.
i
i
TS 15.3.7.B.1, " Auxiliary Electrical Systems"
-
TSI DCS 3.1.17, " Emergency Diesel Generator Operability," dated
4
-
October 24,1996
)
TS-81, " Emergency Diesel Generator G-01 Monthly," revision 50
-
TS-82, " Emergency Diesel Generator G-02 Monthly," revision 47
j
-
l
TS-83, " Emergency Diesel Generator G-03 Monthly," revision 3
-
l
TS-84, " Emergency Diesel Generator G-04 Monthly," revision 5
IT-14, " Quarterly inservice Test of Fuel Oil Transfer System Pumps and
+
}
Valves," revision 11
f
b.
Observations and Findings
l
IT-14 stated that the test would require entry into an administrative 4-hour
i
restriction for EDG G-01 and/or G-02 and an administrative 2-hour restriction for
l
EDG G-03 and/or G-04. If test duration exceeded these guidelines, a dedicated
i
operator may be required. If a dedicated operator was not used, the appropriate
EDG LCO should be entered.
j
!
In addition, step 2.6.2.d. in TS-81, TS-82, TS-83, and TS-84 stated that a 4-hour
i
administrative restriction would be entered if the fuel oil transfer pump for EDG G-
l
01 or G-02 was inoperable and a 2-hour restriction for EDG G-03 or G-04. Further,
j
if the fuel oil transfer pump could not be repaired within the time frame, the EDG
l
would be declared out-of-service and the appropriate LCOs should be entered,
t
!
TSI DCS 3.1.17 stated that, "TS 15.3.7 allows the fuel oil transfer system to be
out of service ledministrative restriction) for four hours for EDG G-01 and G-02 and
l
two hours for EDGs G-03 and G-04." The licensee stated that the time restriction
l
was based on the capacity of day tanks and sump tanks if the fuel transfer pump
i
failed.
t
I
However, the inspectors noted that item C, " Operability," in TS 15.1, " Definitions,"
stated that auxiliary equipment required for a system to perform its functions would
be capable of performing their related support functions. If the fuel oil transfer
pump became inoperable, the EDG would become inoperable since the fuel oil
system was not capable of its EDG support functions. TS 15.3.7.B.1.f. required, in
.
part, that the standby emergency power supply (EDG G-01) to Unit 1 safety-related
buses A05/B03 or (EDG G-04) to Unit 2 safety-related buses A06/BO4 may be out-
of-service seven days provided the required redundant engineered safety features
(ESFs) are operable and required redundant standby emergency power supplies are
started within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. TS 15.3.7.B.1.g. had a similar constraint for the standby
emergency power supplies (EDG G-03) to Unit 1 safety-related buses A06/BO4 and
(EDG G-02) to Unit 2 safety-related buses A05/BOL
After this concern was identified by the inspectors, the licensee agreed that the
administrative restriction for the transfer pump was en inappropriate interpretation
of TS 15.3.7. TSI DCS 3.1.17 was subsequently revised on December 10 to
require entering the appropriate diew LCO if the associated fuel oil transfer system
was taken out-of-service.
I
18
I
I
I
i
_ _ _ _ _ . _ _ _ .
.
. _ _ _ _ . _ . _ _ _
. _ . _
__
.___
_
l
.
.
c.
Conclusion
TSI DCS 3.1.17 on the fuel oil transfer system and the related surveillance
procedures, IT-14 and TS-81 through 84, contained inappropriate direction on
entering an LCO when EDGs were rendered inoperable during testing of the
associated fuel oil transfer system. No instances were identified by the inspectors
where the LCO was not met. The licensee subsequently revised the documents.
08
Miscellaneous Operations issues
08.1 Condition Renortina and Operability Determination Process
a.
Inanection Scope (93802)
The inspectors attended several of the daily CR review meetings and also reviewed
the documents listed below:
NP 5.4.1, "Open item Tracking Systems," revision O
-
i
NP 5.3.1, " Condition Reporting System," revision 4
-
NP 5.3.7, " Operability Determinations," revision 0
-
" Root Cause Tree User's Manual"
-
b.
Observations and Findinas
The licensee recently revised the CR system to encompass various changes
including a new operability determination (evaluation) process. The procedures
incorporating the changes had been revised approximately one week prior to the
OSTI, so assessments on the new operability determination process could not be
conclusively formulated. However, the inspectors' initial observations on the
strength and weaknesses of the CR system and the new operability eva!uation
process are noted below,
Over the last few months, the Point Beach staff had increased the number of CRs
i
l
being written, and during the inspection, about 70 CRs were being generated per
l
week. The lower threshold for CR writing was viewed by the inspectors as a
positive management initiative. However, the inspectors noted that this was not
consistently applied as evidenced by lack of CRs for DBD open items (see Section
E3.1). The changes to the operability screening procedure, discussed below, were
also viewed as generally positive since the procedure required the licensee to handle
operability issues attentively and within the guidelines of GL 91-18, "Information to
Licensees Regarding Two NRC inspection Manual Sections on Resolution of
Degraded and Nonconforming Conditions and on Operability."
The inspectors noted that the success of the CR system, as currently structured,
relied heavily on the technical and regulatory expertise of the regulatory services
staff (RES). After CR initiation and operability /reportability screening, RES was
j
responsible for tracking the CR and completing the final operability and regulatory
{
screening. Regulatory screening included reviews of: 10 CFR 21 and 50.72
19
.
I
!
l
-
-.
.
-
-
..
..
.
. . _ . - - . ..- - - - ...___.- -. --
.
--
_-_
,
.
l
.
reportability: TS LCO, operability impact, and violation applicability; Manager's
Supervisory Staff (MSS, the plant onsite review committee) review requirement;
i
justification for continued operation (JCO); and whether the CR was considered a
'
significant condition adverse to quality (SCAQ).
l
For CR corrective actions, RES determined the responsible group, initiated an action
item, and verified that the action has been completed. RES thsn reviewed the CR
'
again to determine if the completed corrective actions adequately resolved the
issue.
j
At the CR screening meetings, the inspectors noted a possible lack of " buy-in" of
l
the CR system: 1) department representatives did not regularly attend, instead RES,
)
some of whom were formerly in the engineering, operations, or maintenance
departments, attended. RES would then have to " sell" the CR and the proposed
corrective actions to the affected department. 2) senior station managers did not
i
!
regularly attend.
'
i
The inspectors were concerned that the possible lack of buy-in may impact CR
i
i
prioritization and the staff's commitment to effect short and long term resolution of
l
CRs.
I
!
c.
Conclusions
I
l
The revised CR and operability evaluation process was too new to assess
i
conclusively, but the lower threshold was positive and had resulted in increased
j
!
generation of CRs. The new operability determination procedure, as written, should
]
enable Point Beach to follow the guidelines of GL 91-18. However, the inspectors
noted that the CR review meetings did not regularly include a representative from
l
each department or senior station managers, indication of a possible isck of " buy-
l
in" to the process.
II. Maintenance
!
M1
Conduct of Maintenance
I
M1.1 Surveillance Observations
l
l
a.
Insoection Scone (93802)
l
The inspectors reviewed the test procedures listed below and observed all or
l
portions of the tests:
TS-82, " Emergency Diesel Generator G-02 Monthly Technical Specification
-
Surveillance Test," revision 47
TS-84, " Emergency Diesel Generator G-04 Monthly Technical Specification
-
Surveillance Test," revision 5
l
I
I
l
20
l
-. - - .
- _ _ _ _
.
- -. _.
.. -
-
.. - .. - ~ _ - - - - . -- - - . - . - . . - - -
.-
. - - ~ .
.
i
.
.
Instrument and Control Procedure (ICP)-02.OO1, " Reactor Protection and
i
-
Emergency Safety Features Red Channel Analog Quarterly Surveillance
Test," revision 6, Unit 1
b.
Observation and Findings
M1.1.1 Monthly Test of the G-04 EDG
On December 3,1996, and prior to the briefing for the test, an SRO inspected
G-04, toured the EDG room, verified that current copies (including temporary
changes) of TS-84 were available for use, and verified that no other activities or
out-of-service equipment conflicted with the test.
The projob briefing was conducted in the control room by the SRO and included the
(
CO and the equipment operators (EOs) assigned to perform activities at the EDG.
l
The briefing addressed the major steps of TS-84, contained a good interchange of
l
information, and did not detract from other activities in the control room.
l
During the test, the operators used repeat backs to communicate information and
used the telephone when noise levels interfered with radio communications. The
inspectors reviewed the test procedure and found that it contained sufficient
information to determine out-of-specification readings. Several times during the
test, out-of-specification readings were identified, discussed, and resolved as
appropriate.
During the initial start, the inspectors observed the south air start motors engage
and start the EDG. After the EDG was running, the inspectors noted that the north
!
air start motors did not have the expected oil film on the exhaust port of the lower
air start motor which indicated proper operation during the start sequence. The
FSAR stated that both sets of air start motors will engage during an EDG start. The
inspectors discussed this with the EDG system engineer who confirmed the FSAR
statement. The inspectors asked if the observed condition was the result of a
failed oiler or an air start motor that did not engage. The engineer stated that
insufficient information was available to conclude that a problem existed, and added
that the starting sequence would be confirmed during the next monthly EDG start.
l
The performance of the air start motors will be reviewed during future inspections
(IFl 50-266(301)/96018-09(DRP)).
M1.1.2 Monthlv Test of the G-02 EDG
On December 5,1b96, the inspectors observed the testing of the G-02 EDG, per
procedure TS-82. As with the earlier TS-84 test, no problems were identified with
control room activities and communications.
'
During the EDG jacking, the inspectors observed the two EOs open all cylinder test
.
ports (20 total), jack the engine 1 full revolution (1 EO operated the jacking tool and
l
the other EO observed the shaft rotate), then close all test ports securely.
,
j
Following the EDG start, one EO toured the EDG making local readings and looking
'
)
21
.
.
. . .
..
.
- _
. - -
-
-
.
i
'
<
i
!
!
!
!
for obvious leaks. However, the inspectors noted that step 4.2.5 of TS-82 stated:
1
" Watch for fluid discharge from test ports during one full engine revolution; inform
Control if any fluid is observed." Contrary to this, the EOs did not perform a visual
i
check of the test ports during the engine jacking, but checked after the jacking.
l
The failure to follow the procedure is an example of a violation of TS 15.6.8.1 that
j
requires the plant to be operated and maintained in accordance with approved
procedures, including surveillance and test procedures for safety-related equipment
l
(VIO 50-266(301)/96018-01b).
4
M1.1.3 tb-tarly Reactor Protection and Emeroency Safety Features Test
!
On December 3,1996, the inspectors observed l&C technicians perform l&C
j
surveillance test procedure ICP-02.OO1(RD-1). The technicians maintained a
professional demeanor and performed the surveillance without difficulty. No
out-of-specification readings were identified or discussed during the testing.
3
i
However, the inspectors identified several weaknesses in the procedure, as
.
discussed below.
!
l
The inspectors questioned a procedural requirement to record instrument
adjustment values in milliamperes-direct current (mA-dc). The l&C technicians used
,
i
a piece of test equipment (Fluke digital multimeter, model 8520A or 8842A) that
j
did not read out in these units. The technicians'were required to divide the as-
l
found data by a reference value stated on a resistance decade box to obtain the
j
final value in mA-dc. This calculated data conversion was not specified in the
procedure. The licensee informed the inspectors that a similar concern had been
i
l
addressed some years earlier through a procedure revision. The earlier revision
j
modified the recorded value units to millivolts-direct current (mV-dc), the unit
]
displayed on test equipment in use, but a later revision restored the required data
units back to mA-dc.
7
l
The inspectors also identified that the procedure required the technicians to record
1
instrument readings but did not specify any circuit stabilization time. During
f
testing, the inspectors questioned the technicians about this and were informed
i
that a five-minute delay was the accepted practice, since this had been recognized
'
as a conservative value. The inspectors noted that such " skill-of-the-craft" was
routinely relied upon to ensure validity of test data. Additionally, some steps
!
required an independent verification of switch operation, while some other switch
l
manipulations did not.
I
j
c.
Conclusion
,
Surveillance activities were genera:ly completed in a thorough and professional
j
manner. A TS procedure violation wee identified for not properly checking leakage
j
from EDG test ports and an inspection followup item was identified pertaining to
]
verification that both sets of air start motors functioned during future starts of G-
!
04.
.
I
.
22
2
'
.
.
. .. -
.
_
__ .
_ _ . _ . . _
-
_
-
.
-
_
)
.
.
b
'
,
l
M3
Maintenance Procedures and Documentation
j
i
M3.1 Surveillance Procedure Deficiencies
a.
Inanection Scone (93802)
,
f
'
On December 4,1996, the inspectors identified that the licensee had not been
testing: 1) all four EDGs in accordance with TS 15.4.6.A.2, " Emergency Power
System Periodic Tests," and 2) the EDG fuel oil transfer systems in accordance
'
j
wi:5 TS 15.4.6.A.5, " Emergency Power System Periodic Tests." The inspectors
i
reWewed the following documents:
1
$
TSI 3.1.11, " Emergency Diesel Generator Annual Automatic Start Test,"
-
dated November 16,1993
'
Operations Refueling Test Procedure (ORT)-3, " Safety injection Actuation
-
1
With Loss of Engineered Safeguards AC," revision 27
j
FSAR Table 8.2-1, " Emergency Diesel Generator Loading Following Loss of
-
Coolant Accident"
,
TS-81, " Emergency Diesel Generator G-01 Monthly," revision 50
-
TS-82, " Emergency Diesel Generator G-02 Monthly," revision 47
-
,
l
TS-83, " Emergency Diesel Generator G-03 Monthly," revision 3
-
TS-84, " Emergency Diesel Generator G-04 Monthly," revision 5
-
IT-14, * Quarterly inservice Test of Fuel Oil Transfer System Pumps and
{
-
i
Valves," revision 11
,
The inspectors also observed a portion of the TS-82 surveillance on December 5
i
and TS-83 on December 6, as discussed above in Section M1.1. In addition, the
j
inspectors spoke with engineering and operations personnel on the past practice of
performing EDG loading tests during refueling outages, installation of two new
EDGs in 1994 and 1995, qualification of the new EDGs, reconfiguration of G-02
'
j
from Unit 2 Train B to A in 1996, and testing of the fuel oil transfer system.
l
b.
Obaarvations and Findinas
,
1
M3.1.1 Inadeauste EDG Test With Loss of AC Coincident With SI
)
Descnotion The inspectors reviewed TS 15.4.6.A.2 which required the automatic
l
start of each EDG and load shedding and restoration of particular vital equipment on
an actual interruption of normal AC power together with a simulated SI signal. In
addition, after the EDG had carried its loads for a minimum of five minutes, the
-
f
licensee was required to test automatic load shedding and restoration of vital loads
j
again by manually tripping the EDG output breaker. This test was required during
j
j
sach refueling outage to assure that the EDG would start and restore required loads
j
j
in accordance with the timing sequence listed in FSAR Section 8.2.
,
>
.
However, TSI DCS 3.1.11, contrary to the above requirements, stated that, "all
l
j
l
safeguards loads required in this test need not actually start and run as long as the
i
automatic control systems can be demonstrated to function automatically."
i
1
!
23
)
3
3
.
.
-
.
--
. _ .
_
.__
-.
.
- . - . - -
.-.
. - .
. . -
--
. . . . - - -
. - . . - . - - - -
. .
.
.
!
Furthermore, the TSI stated that the loads listed in FSAR Table 8.2.1 and 8.2.2
need not actually start during that portien of ORT-3 which fulfilled requirements of
TS 15.4.6.A.2. Only the breakers for the equipment were required to operate in
l
the correct sequence.
l
After reviewing ORT-3A, the inspectors confirmed that the breakers for the Si
!
pump and two containment ventilation fans were racked to the test position and
)
the pump and fans were not started per the procedure. Only the breaker closure
time was monitored. The licensee stated that TS 15.4.6.A.2 was intended to test
I
l
only the EDG sequencer and not the capability of the EDG for transient loading.
l
However, the licensee's interpretation and implementation of the automatic start
test was contrary to the requirement of TS 15.4.6.A.2. By excluding loads such as
the Si pump and two containment ventilation fans from being started and
sequenced onto the bus, the EDG's capability to handle in-rush currents and the
acceleration time of large motors had not been demonstrated in the past according
to TS 15.4.6.A.2.
Background An Electrical Distribution System Functional Inspection (EDSFI) was
performed in spring 1990 (Inspection Reports 50-266(301)/90201 and 50-
266(301)/90018). At that time, the inspectors identified that the largest pump (SI)
was not started during ORT-3. However, the licensee indicated then that the
starting of the SI pumps using the recirculation test lines was not a preferred
,
alignment because the lines were not of sufficient size and excoss pump vibration
could result. This explanation was reasonable to the inspectors.
In November 1991, the licensee increased the Unit 2 Si recirculation line size to
accommodate full recirculation flow, and in May 1992, the licensee similarly
modified the Unit 1 recirculation line. However, the licensee did not start SI pumps
during subsequent EDG testing.
Between fall 1994 and fall 1995, the licensee installed two additional EDGs, G-03
and G-04, to augment the two existing EDGs, G-01 and G-02. The licensee stated
that a qualification test was performed in 1995 on each EDG to the associated Unit
safety bus prior to its tie-in. As a part of the qualification test, each EDG was
tested with a loss of AC power followed by an Si signal. The EDG loading
sequence was verified and all the safety loads were started according to the
sequence. The licensee described the following time line for EDG modifications:
G-02 was tied (reconfigured) into Unit 2 in fall 1995 and to Unit 1 in spring
-
1996
G-03 was tied into Unit 1 in spring 1995 and to Unit 2 in fall 1995
-
G-04 was tied into Unit 2 in fall 1994 and to Unit 1 in spring 1995
-
The licensee could not conclusively state the scope of testing performed on G-01.
With the uncertainty of G-01 testing and the last automatic start test for G-04
being more than 12 months ago, the licensee declared G-01 and G-04 inoperable on
I
(
24
.
.
..
. - -.
.
_
______ _ ___ _-_
. . _ _ _ _ _ _ . _ . _ _
_ . _ - _ ___ _ -.
.
.
,
4
j
4
!
December 5,1996. The licensee realigned G-02, normally aligned to Unit 2 Train
{
A, to Units 1 and 2 Train A. and G-03, normally aligned to Unit 1 Train B, to Units
l
1 and 2 Train B.
i
!
Inanectors' Review During a subsequent review, the inspectors identified that
!
during the 1995 qualification test, all four EDGs were fully tested according to TS
l
15.4.6.A.2 with all safety-related loads started and sequenced to either the Unit 2
!
Train A or B bus.
During the Apdf 1996 qualification test for reconfiguring G-02 to Unit 2 Train A, the
'
sequencers for G-01 and G-03 were tested but an Si pump and two containment
ventilation fans were not started, and G-04 was only tested with simulated loss of
j
AC power.
!
Contrary to the testing requirements of TS 15.4.6.A.2, the licensee failed to start
i
all associated safeguard loads, specifically the SI pump and two containment
i
ventilation fans, during the annual (refueling outage) EDG test initiated by a loss of
i
AC followed by an Si signal. The inadequate tests were for G-01 from 1992 to
!
1994 and in 1996; for G-02 from 1991 to 1994; and for G-03 in 1996. This is an
j
apparent violation of TS 15.4.6.A.2 (eel 50-266(301)/96018-10).
i
!
M3.1.2 fr-ta==ta EDG Fuel Oil Transfer Svatam Test
i
,
l
TS 15.4.6.A.5 required that operability of the diesel fuel oil system be verified
j
montNy. In the montNy EDG test procedures (TS-81 through TS-84), the fuel oil
i
transfer pumps were manually started and stopped to fill the diesel day tanks. TS-
l
81 and TS-82, step 3.9, stated that Attachment B, " Fuel Oil Sump Tank Pump
i
Operability," would be performed annually for G-01 (in December) and G-02 (in
i
February). During the performance of Attachment B, the automatic start of a diesel
l
fuel oil transfer pump was tested by day tank level switch actuation.
l
In addition, TS-83 and TS-84 did not test the automatic start of a transfer pump via
j
level switch actuation. The licensee stated that there were no other procedures
'
which tested the automatic start function of the transfer pump for G-03 and G-04.
-
i
!
The inspectors discussed the concern on testing methods which satisfied the
l
requirement of TS 15.4.6.A.S. The licensee agreed that the automatic start
!
function of transfer pumps was not tested montNy, but initially stated that the
j
manual starting and stopping of the transfer pump sufficed as the monthly
,
"
verification of oil system operability.
!
'
Subsequently, the licensee concurred that the fuel oil system and the day tank level
j
i
switches had rsot been adequately tested montNy as required by the TS. The
i
licensee tested the system using Attachment B in TS-82 for G-02, and revised TS-
i
83 to include a similar Attachment B and then tested G-03. G-01 and G-04 had
i
been declared inoperable at that time due to inadequate EDG transient loading tests
and were tested later. The licensee issued Licensee Event Report (LER) 96012 on
j
January 3,1997, to address the improper testing of the fuel oil system.
)
)
25
!
i
b
- . -
.
. - . ,
-
.--
.
- - . -
.- -___- -- _.
-. . - - . . - - . - . - .
.
.
. - .._- =.. _ _ - - - _ .
- -
--
,
.
.
!
!
l
The failure to test the automatic start function of the fuel oil transfer pumps
,
j
monthly from January to November 1996 for G-01, March to November 1996 for
j
G-02, spring 1995 to November 1996 for G-03, and fall 1994 to November 1996
i
for G-04, was an apparent violation of TS 15.4.6.A.5 (eel 50-266(301)/96018-11).
t
M3.2 CHAMPS Observations
s.
Insnaction Scone (93802)
-
I
The inspectors identified several weaknesses in implementation of the
Computerized History and Maintenance Planning System (CHAMPS), the licensee's
'
work order and equipment description computer program. The inspectors reviewed
NP 8.5.2, " CHAMPS Equipment Database Usage and Control," revision 1, and
interviewed the CHAMPS manager.
i
4
b.
Observations and Findogs
i
l
The inspectors identified that the charging pump oil pressure gauges and pressure
1
gauges for most air-operated valves did not have equipment identification tags
}
attached to them. In addition, the inspectors found maintenance work sticker No.
.
{
98526 on an alarm tile in the main control room that had not been removed after
!
maintenance was completed.
!
The inspectors were concerned thu without individual equipment identification,
i
'
j
trending of instruments or gauges could not be easily performed. In addition, the
'
j
guidance provided in NP 8.5.2 did not ensure removal of stickers, which were used
I
j
where normal maintenance work tags could not be used. If not removed when
!
maintenance was completed, a sticker represented misinformation to the operators
i
on equipment status.
!
I
M3.3 Conclusions on Maintenance Procedures and Documentation
The licensee's EDG testing during each refueling outage apparently did not meet TS
requirements in that the Si pump and two containment ventilation fans were not
,
,
l
started and sequenced to the bus supplied by the EDG.
l
l
The licensee's implementation of the monthly operability verification of the diesel
i
fuel oil system apparently violated TS 15.4.6.A.5, because the automatic start of
L
the transfer pumps via day tank level switch actuation was not verified.
!
l
The CHAMPS program did not ensure removal of meintenance stickers after the
y
equipment was returned to service, and the trending of individual instruments or
gauges was not possible because much of this equipment lacked identification tags.
4
s
i
j
26
!
,
,
,
, , _ _ _ _
_
_
. . - . . . -
_ _ _ _ _ _ _ _ _ _ _ . _ . _ _ _ _
___ ___ - _.._ _ ._ _
_ . . . - _ . _ _ _ _ . _ _ _ .
4
.
.
!
1
i
.
M8
Miscellaneous Maintenance issues
!
j
M8.1 Onorator 'Norkarounds
j
a.
InsnectioigfEcorm193BD21
The inspectors performed a walkdown of the D-105 and D-106 safety-related
-
batteries and reviewed regular maintenance procedure RMP 9046-1, " Station
"
Battery," revision 21.
i
b.
Observations and Rndinos
- .
i
The inspectors observed a layer of white-colored material floating on/near the
i
surface of the electrolyte and transparent strips of material within the electrolyte for
{
most of the sixty cells in the D-105 and D-106 batteries. The inspectors reviewed
!
a letter dated September 27,1986, to the Hennig Company, a licensee ccntractor,
in which the floating material and the transparent strips were confirmed by the
battery manufacturer (based on photographs) to be " Riegel Wrap" material. The
!
letter described the material as having broken free from the edges of separators in
the cells due to oxidization of the bonding substance at the rib of each separator.
!
l
The Hennig Company examined the batteries and documented the results in a letter
dated February 4,1988. In this letter, the Hennig Company, in consultation with
j
the battery manufacturer (C&D Batteries), concluded that the " Riegel Wrap"
material did not affect the battery capacity or life. However, the inspectors
i
l
identified that it created an operator workaround that the licensee had not
l
previously identified. The finely divided " Riegel Wrap" material coating the front of
i
the cell between the electrolyte high and low level lines made monthly electrolyte
l
level checks required by procedure RMP 9046-1 difficult.
!
j
c. Conclusion
!
Based on a discussion and system walkdowns with the cognizant engineer, the
inspectors concluded that operators had to use alternative techniques (e.g., using a
flashlight and performing visual observations from above and below the marked
'
high and low level lines) to confirm the actual electrolyta level which constituted an
l
operator workaround.
'
111. Enoineering
E1
Conduct of Engineering
E1.1
Control Room Ventilation
a.
Insoection Scope (93802)
'
While exiting the control room, the inspectors noted that gauge VNCR DPI-43718,
for differential pressure (dP) between the control room and turbine building, was
27
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. . . - - . - .
1 '
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I
i
pegged high. The inspectors then watched the gauge while personnel entered and
l
exited the control room. The needle moved from the pegged high position to the
midposition and back to the pegged high position. This matter was reviewed
further.
b.
Obmarvation and Findinas
f
The inspectors attempted to determine the operability requirements of the control
1
room ventilation system by reviewing the FSAR, but found no system description.
i
!
The plant manager stated that the licensee had a similar finding and intended to
i
include a description in the next FSAR revision. The revision will be reviewed
i
during a future inspection (IFl 50-266(301)/96018-12(DRP)).
!
I
The control room ventilation and habitability DBD described four modes of operation
j
for the control room ventilation. Mode 1 was the normal (non-emergency) lineup to
meet personnel fresh air requirements. Mode 2 was the 100 percent recirculation
,
j
mode with no filtration. Mode 3 was the 100 percent recirculation mode with a
j
portion of the air circulated through the filtration system. Mode 4 was the
j
pressurization mode with filtered outside air.
]
)
i
The inspectors reviewed TS-9, " Control Room Heating and Vontilation System
I
}
Monthly Checks," and found that the acceptance criteria required verification that
control room dP was k +0.125" of water in Mode 4. The completed copy of TS-9
}
performed on November 11,1996, indicated dP (by VNCR DPI-4371B) was
l
2 0.25" of water in Modes 1 and 4. Greater than 0.25" of water was the pegged
l
high reading. The inspectors attempted to review the dP gauge calibration records,
i
but were informed by the system engineer that the gauge was not in the calibration
program and had not been calibrated since it was installed in 1991.
I
i
TS-9 operated the ventilation system in Mode 3 for several hours. However, the
i
procedure did not require documentation of dP readings between the control room
!
and the turbine building. The inspectors noted that evaluation of dP readings during
l
Mode 3 could identify excessive unfiltered inleakage.
~!
l
The inspectors walked down the ventilation system using piping and
l
instrumentation d!agram (P&lD) M-212. During the walkdown, the inspectors found
the access hatch between the cleanup filters and W-14A and B, the control room
,
l
ventilation cleanup fans, undogged and opened about %". The inspectors were
i
able to detect airflow into the system by placing a piece of paper at the opening.
The system was in Mode 1 at the time which meant that this portion of the system
was isolated by several closed dampers.
l
The licensee's subsequent investigation (documented in CR 96-1678) determined
that the dogs holding the hatch in place needed adjustment. The inspectors were
j
unable to determine how long the hatch was open and if system operability was
affected.
}
28
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_ . . _ _ . - _
_ __
.
.
4
The inspectors also attempted to review the inspection records of the isolation
dampers to determine if bypass leakage limits were established and evaluated, but
the system engineer stated that damper integrity had not been inspected.
The inspectors reviewed the control room ventilation and habitability DBD (dated
July 7,1995), and followed up on three findings: 1) habitability analysis used the
wrong distance between the containment and the outside air intake,2) the TS
required a pressure drop across the charcoal filters of 6" of water which was above
the highest pressure that the system could achieve,3) and the TS required a
laboratory charcoal test demonstrating 90 percent methyl iodide removal efficiency
while the habitability evaluation assumed 95 percent. The inspectors found that
the findings had not been evaluated for operability, corrective action had not been
taken, and the scheduled completion dates were in mid-1997.
c.
Conclusions
The inspectors were unable to determine if the control room ventilation system was
operable for the following reasons: 1) the lack of a system description in the FSAR,
2) a gauge that was continuoutJy pegged high and not in the caiibration program,
3) the failure to evaluate and rssolve, in a timely manner, discrepancies identified
during design basis reconstitution, and 4) the lack of a program to verify the
integrity of the isolation dampers. ~The question of system operability is being
pursued by NRR (IFl 50-266(301)/96018-13(DRP)).
E2
Engineering Support of Facilities and Equipment
E2.1
Seismic issues
a.
Insoection Scone (93802)
The inspectors reviewed work order (WO) 9609583 and the SE screening for
replacement of the oil sightglass on the G-04 governor. The inspectors also walked
down the supports for the G-01 and G-02 day tanks and reviewed Calculation N-
90-043 " Evaluation Of Day Tank Supports (T31 A & T318) & Day Tank Tie Lines."
During a walkdown of the SI system, on December 7,1996, the inspectors
identified a gap between an Si system pipe support baseplate and the building wall.
The inspectors reviewed NDE-754, " Visual Examination (VT-3) of Nuclear Power
Plant Components," revision 3, which performed ASME Code required inspections
of this pipe support.
The inspectors also walked down accessible portions of the instrument tubing to
2FIA-458/459 and reviewed the following documentation related to the
qualification of 3/8" tubing connected to the RCS:
CR 96-555, " Unqualified, non-OA scoped components comprise part of the
-
RCS pressure boundary"
29
.
.
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--
_ _ _ . _ _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ . _ _ _ . _ _ .
. _ _ __ _ _.._.._ _. _ . -
_ . _ . _ -
,
.
i
Draft Document Titled " Craft RCS Instrument Tubing: Seismic or Not?,"
-
l
dated October, 23,1996
.
P&lD 541F445, Sheets 1 and 3
l
Nonconformance Report (NCR) N-89-187
-
TS 15.4.3-2
-
Modifications83-178 and 83-179, " Replace the Barton flow gauges with
+
{
Midwest gauges for both 1(2)FIA-458 and 1(2)FIA-459"
!
b.
Observations and Findings
.
l.
Weak Safety Evaluation Screenina for the Reolacement of the G-04 Siahtalass
!
l
The inspectors identified that no SE had been performed for replacement of the oil
j
sightglass on the G-04 governor completed September 8,1996, per WO 9609583.
'
The licensee had determined in a SE screening on September 4, that no SE was
required because reportedly the new taller sightglass was the standard sightglass
'
supplied on all new and remanufactured EGB-13P's (mrel of governor]. The
inspectors considered this scresning weak, in that the m.a scement sightglass was
33 percent heavier and 1" longer than the original sight @s, potentially affecting
i
the seismic load on the sightglass support. No bounding paineering calculation
l
had been performed or referenced for the replacement.
i
EDG Room Wall Crackina
l
On December 6, the inspectors identified a support for the G-02 day tank (T31B),
j
which was bolted to the wall, but not welded to the embedmont plate. The
comparable G-01 day tank (T31 A) support was welded and bolted. The inspectors
l
discussed this with the licensee and subsequently reviewed Calculation N-90-043
i
which demonstrated the acceptability of the missing weld. However, the
l
inspectors identified cracks in the concrete wall separating the G-01 and G-02
i
diesel rooms above a door. These cracks appeared to be through-wall and appeared
to circumvent one side of the T-31 A and T-31B tank supports. On December 9,
the licensee wrote CR 96-1659 in response to the inspectors' concern over the
cracks. An operability assessment was completed on December 15, and a
calculation that demonstrated structural integrity of the wall was completed and
sent to NRR for review on December 20. The review found the calculation
acceptable. The licensee indicated to the NRR reviewer that plant walls were
subject to a 10-year inspection frequency. This may be in conflict with NRC
guidance on " maintenance rule" (10 CFR 50.65) implementation and will be
reviewed during a future inspection (IFl 50-266(301)/96018-14(DRP)).
No Accentance Criteria for Gans on ASME Code Sunoorts
The inspectors identified that a piping support, SI-1501R-2-S844, for the SI system
had an approximately 1/4" clearance (gap) between the building wall and support
baseplate along one side of the support. The support was safety-related and had
been found to be acceptable when inspected by the licensee in 1992 and 1994
using procedure NDE-754. The inspectors requested the engineering staff to
30
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}
j
,
.
,
c
provide the acceptance criteria for the gap, but none could be located.
.
Subsequently, on December 13, the engineering staff completed revision 1 to
i
calculation WE-100076 that demonstrated the structural integrity of Gis support.
L
i
10 CFR 50.55a(g)(4)(ii) required the inservice examination of components to
comply with the ASME Boiler and Pressure Vessel Code. The ASME Code,1986
,
j
Edition,Section XI, Table IWF-2500-1, required a VT-3 inspection on component
i
supports, which included the support up to the building structure.Section XI of the
l
ASME Code, paragraph IWA-2213(a), required the following:
l
"The VT-3 visual examination shall be conducted to determine the general
{
mechanical and structural condition of components and their supports, such
j
as the verification of clearances, settings, physical displacements, ......"
!
10 CFR 50, Appendix B, Critorion V, required procedures to include appropriate
l
quantitative or qualitative acceptance criteria for determining that important
{
activities have been satisfactorily accomplished. Contrary to these requirements,
i
NDE-754, " Visual Examination (VT-3) of Nuclear Power Plant Components,"
!
revision 3, lacked criteria to verify the acceptable clearance between the
l
component support baseplate and the building structure. The failure to include the
1
'
acceptance criteria in NDE-754 or any procedure is an example of a violation of
.
l
Criterion V (VIO 50-266(301)/96018-05b(DRS)).
j
Non-Saismic. Non-QA fWified Tubina Connected to the RCS
In 1989, the licensee identified in NCR N-89-187 that the policy exempting 3/8"
tubing from consideration as part of the RCS pressure boundary was not
appropriate, since the normal makeup (2 charging pumps) could not keep up with a
3/8" line break. The licensee changed its policy and reportedly verified that all
.
existing RCS non-QA scoped tubing and instrumentation had been seismically
installed and maintained QA-scope. However, the licensee failed to identify that
four RCS loop resistance temperature detector (R'ID) manifold flow indicator alarms
had been installed as non-seismic and using non-QA components.
As described in CR 96-555, the licensee identified that in the mid-1980s, four (2
por unit) RTD flow alarms (1(2)FIA-458 and 459) had been installed under the old
policy as non-seismic and using non-QA components. The inspectors noted that
the installation of the non-QA instruments (and approximately 8" of tubing up to an
existing test manifold) was being adequately resolved via tubing replacement,
commercial grade dedication, and SOUG (Seismic Qualification Users Group)
qualification; however, the qualification of the original tubing from the RCS to the
,
test manifold had not been addressed. Further, qualification of all other instrument
1
tubing attached to the RCS was in question due to lack of documentation and this
had not been adequately addressed. The inspectors were concerned that the
corrective actions of CR 96-555 were not comprehensive.
The inspectors requested documentation of the qualification of tubing from the RCS
to 1(2)FIA-458 and 459 and other similar tubing installed to the RCS, but the
31
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. - . - - - . - . - . -
- - . - - - . .
. - - . - . - . . - - . - . - . .
. - ~ . . _ . - .
4
.
.
i
4
engineering staff stated that no documentation had been located to support the as-
i
built tubing installations. However, the staff considered the tubing qualified based
on the installation requirements of the RCS piping code, FSAR Section 4.1.7, and
,
the design standard for reactor protection systems (Institute of Electrical and
i
j
Electronics Engineers (IEEE) 279-1968, " Proposed IEEE Criteria for Nuclear Power
Plant Protection Systems") that required the tubing to be seismically qualified.
'
Therefore, the engineering staff considered this issue a matter of either finding
missing documentation or performing a walkdown to validate that the tubing was
,
'
seismically installed. The licensee also stated that several walkdowns had been
j
initiated, but no documentation of these were available for the inspectors' review.
i
The inspectors were concerned with the initial apparent lack of aggressiveness in
.
resolving the qualification issue.
Nonqualified instrument tubing installations could potentially compound a seismic
event, through potential ruptura or failure of multiple sensing lines, which would
>
i
create an unisolable SBLOCA. The inspectors were concemed that this issue was
i
not being promptly addressed, considering the engineering staff's determination
'
that the failure of a 3/8" instrument tube was beyond the makeup capacity of the
l
charging pumps. This issue is considered an unresolved item (URI 50-
[
266(301)/96018-15(DRS)) pending the licensee's determination of the qualification
j
of 3/8" tubing connected to the RCS.
E2.2 EDG Governor Droon Settinas
a.
Insoection Scone (93802)
The inspectors reviewed the following documents to assess the effect of the
governor speed droop settings on EDG operations and safety-related equipment
supplied by the EDGs:
Special Maintenance Procedure (SMP) 1082, " Diesel Generator G-02 Load
-
Test," revision 0
Point Beach Test Procedure (PSTP)-OO6, "Special Runout / Cavitation Test of
-
1P-15B Safety injection Pump," revision O
PBTP-043, " Verify Selected 1 A05 Loads at increased Frequencies,"
-
revision 0
SE 96-025, " Change in Diesel Generator G-01 and G-02 Governor Settings"
-
SE 96-023, "Use of a Dedicated Operator for P-38A Motor-Driven Auxiliary
.
Feedwater Pump Discharge Valve AF-4012 To Control Discharge Flow"
SE 96-027, " Revision of EOPs and Applicable Procedures to include a
-
Caution Statement that the Motor-Driven AFW Pump Breaker May Trip on
Overcurrent at Flows Greater thun 200 gpm"
SE 96-028, " Release of Dedicated Operator for P-38A Motor-Driven
.
Auxiliary Feedwater Pump Discharge Valve AF-4012 To Control Discharge
Flow"
Calculation No. 96-0099, dated t.pril 21,1996
+
32
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i
i
!
l
L
b.
Observations and Findings
4
!
Speed droop in the EDG governor control system was required to parallel the EDG
)
i
to offsite power during the monthly surveillance testing to account for any offsite
!
voltage and frequency instability. For G-03 and G-04, the speed droop was kept in
the circuits during monthly surveillances, but was isolated from the governor
i
controller when an automatic start was initiated by an Si or loss of offsite power
!
(LOOP) signal. For an emergency start, the G-03 and G-04 governors would then
I
maintain constant speed and voltage when the EDGs were supplying power to the
bus.
For G-01 and G-02, speed droop was in all the time. As a result, if G-01 or G-02
was subsequently started and was supplying power to a lightly loaded 4160-volt
(V) bus (during a postulated event involving a LOOP), the no-load EDG speed would
i
be higher than a nominal value of 900 revolutions por minute (rpm) and the bus
!
frequency would be greater than 60 hertz (Hz). Prior to April 1996, G-01 and G-02
were initially set at a 5 percent speed droop such that the no-load speed was 947
,
)
rpm (63.1 Hz).
i
The engineering staff stated that it was advantageous to keep the speed droop in
l
during an emergency start of G-01 and G-02 to avoid unnecessary operator
.
adjustment of the speed droop before restoring AC power to the bus. The
!
inspectors considered the practice of keeping the speed droop in inconsistent with
common industry practice and nonconservative in that safety-related equipment on
the EDG-supplied bus would be subjected to a higher frequency. The higher bus
i
'
frequency would reduce the existing margins to breaker trip setpoints for safety-
related equipment on a lightly loaded bus supplied by G-01 or G-02.
St Pumn -1993 On April 11,1993, the licensee performed test procedure PBTP-
006 to determine Si pump performance characteristics when operated at EDG
frequencies greater than 60 Hz. For the test, the Si pump was started with the
EDG operating at its high speed limit ( = 63 Hz). The measured SI pump motor
current at pump runout conditions was 97 ampores. This exceeded the normal full
load running current (85 amperes) and the motor's overload current setpoint (90
amperes). However, the motor would not trip at the overload setpoint since a
current greater than 90 amperes for 7.3 seconds along with a current equal to the
150-ampere low instantaneous setpoint were required. Exceeding the overload
'
current setpoint only initiated an annunciator. The test indicated that motor current
would increase at higher operating frequencies. Since the licensee operated G02
(Unit 1 Train B equipment) and G01 (Unit 2 Train A equipment) at the high speed
limit along with droop, running equipment would be operated at hWeer frequencies
~
when the EDGs were lightly loaded. Sixty Hertz motor operation would not occur
i
until the EDGs were fully loaded (2850 KW). The licensee did not evaluate at this
time other safety related motors to ensure that higher operating frequencies would
not cause spurious motor tripping.
I
MDAFW Pumo-1996 On April 17,1996, the A MDAFW pump motor breaker
(1852-12C) tripped on overcurrent during G-02 testing. Bus frequency was 62.2
33
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- - . - - .-_ - - - - - -
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!
f'
Hz (due to governor droop settings) and the breaker tripped in approximately six
minutes. Included in the immediate corrective actions (as evaluated in SE 96-023)
was the assignment of a dedicated operator to operate valve AF-4012 in the event
'
l
of AFW initiation, to limit AFW flow to 200 gallons per minute (gpm) and to prevent
the trip of breaker 1852-12C on overcurrent.
i
}
Also on April 17, the licensee performed PBTP-043 to demonstrate operation of the
i
A MDAFW pump with EDG frequencies above 60 Hz. With the pump discharge
].
valve controlling pressure at 1200 pounds per square inch - gauge (psig) and the
jl
EDG frequency varied from 60.25 to 61.1 Hz, the pump motor amperage varied
from 294 to 314 amps, which was below the minimum overcurrent trip setpoint of
1
315 amps. After the test, the no-load speed setting was changed to 930 rpm (62
}
Hz) for G-01 and 931 RPM (62.1 Hz) for G-02. However, these frequencies were
j
still above the frequency at which the A MDAFW pump had been satisfactorily
tested (with the discharge valve controlling at the normal setting of 1200 psig). In
4
,
'
addition, Calculation No.96-099 was performed and demonstrated that the new
droop setting would not result in tripping the overcurrent device for other safety-
i
related equipment during a LOOP. However, the calculation did not include the Si
l
pumps or the A MDAFW pump.
On April 25, SE 96-028 was issued to rescind use of the dedicated operator for
I
valve AF-4012. The licensee determined that the proposed activity would not
i
increase the probability of occurrence of a malfunction of equipment important to
i
safety previously evaluated in the FSAR. This determination was based on:
l
readjusting G-02 no-load frequency and speed droop, implementation of caution
j
statements in the EOPs (evaluated in SE 96-027), and evaluation of simulator
i
!
scenarios to adjust AFW flow to 200 gpm in less than 250 seconds (the minimum
l
time estimated for trip breaker 1B52-12C on overcurrent).
4
}
In addition, the following EOPs were revised in October 1996 to include caution
j
statements that directed the operator to reduce AFW flow to prevent trip of the
l
motor driven pump:
i
j
EOP-0, " Reactor Trip or Safety injection"
-
EOP-0.1, " Reactor Trip Response"
i
-
l
Emergency Contingency Action (ECA)-0.0, " Loss of All AC Power"
-
l
Critical Safety Procedure (CSP)-S.1, " Response to Nuclear Power
-
J
Generation /ATWS"
l
Shutdown Emergency Procedure (SEP)-3.0, " Loss of All AC Power to a
-
l
Shutdown Unit"
)
The corrective actions for the MDAFW pump trip were inadequate in that revision
j
of the EOPs and retraining of licensed operators did not solve the root cause of the
problem (EDG droop settings); some licensed operators were evaluated during the
,
j-
performance of two different simulator scenarios for which the time elapsed to
manually control the AFW flow repeatedly exceeded 250 seconds; and no testing
a
conclusively demonstrated that the MDAFW pump could be operated in the
automatic pressure control mode for more than 250 seconds with a lightly loaded
i
l
34
4
!
,
.
.
,
. - -
-.,
.-
.
--
--
.-,
.
.
EDG. The use of the operator to maintain the A MDAFW pump operable appeared
to the inspectors to be a potential unreviewed safety question, per 10 CFR 50.59.
This issue will be tracked as an unresolved item pending further NRC review (URI
50-266(301)/96018-16).
The use of caution statements in the emergency response procedures to direct
operator actions was an example of inappropriate instructions or procedures for
l
activities affecting quality. This was considered an example'of a violation of 10
i
CFR 50, Appendix B, Criterion V which requires, in part, that activities affecting
{
quality be prescribed by documented instructions, procedures, or drawings
j
appropriate to the circumstances (VIO 50-266(301)/96018-05c). Later during the
i
inspection, the licensee indicated that the procedures were in the revision process
to remove the operator actions from the caution statements and be made distinct
j
steps in the procedures. These revisions will be reviewed during a future
i
inspection.
l
!
St Pumn--1997 During the January 31,1997, performance of Unit 2 surveillance
i
procedure ORT 3, " Safety injection Actuation with Loss of Engineered Safeguard
i
AC," the load reject portion of the test did not anticipate that the running 2P-15A
i
SI pump would trip when the EDG output breaker was opened and re-closed within
four seconds. Just prior to performing the reject test, licensee personnel heard a
g
4
chattering overload relay. An overload relay operating near its setpoint would
j
require about 20 seconds to reset. Opening the EDG output breaker initiated reset,
i
however, re-closure of the EDG output breaker applied lock rotor current (6 to 8
I
times full load current) to the overlos' relay before it fully reset and picked up the
l
150-ampere low instantaneous trip. This resulted in the unanticipated trip of the Si
i
pump.
i
!
The unanticipated trip of the pump during the EDG load rejection test had minimal
l
safety consequences. During a LOCA concurrent with a LOOP (licensing basis), the
l
Si pump would not be running until loaded on the EDG. The pump would be at full
speed in 2 to 3 seconds and the running current would be below the low
'
instantaneous setpoint. During a LOCA followed by a LOOP, the pump would be
operating from offsite power (60 Hz) at a lower current. The overload relay would
be in a reset condition and provide the full 7.3-second time delay during pump
restart. The inspectors concluded that the SI pumps powered by G-01 and G-02
were capable of performing their safety function. However, the licensee failed to
identify a potential condition adverse to quality in 1993 during the PBTP-OO6 test
when it was found that motor current would increase during high frequency
operation. The licensee did not evaluate other safety-related motors until 1996 to
ensure that higher operating frequencies would not cause spurious motor tripping.
This is considered an example of an apparent violation of 10 CFR 50, Appendix B,
Critoria XVI, " Corrective Action," which requires, in part, that conditions adverse to
quality are identified and corrected (eel 50-266(301)/96018-07d).
After the January 1997 Si pump trip, the licensee increased the overload current
setpoint to 105 amperes and reduced the time delay to about 6.3 seconds for Si
pump 1P-15A and 2P-15A on February 6,1997. The inspectors reviewed the
motor coordination curves, including the motor thermal capability curve, and
35
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~ - ~ - - . ~ - - -
f
,
.
,
!
a
!
concluded the motors were adequately protected. Since Unit 2 was in an outage,
,
'
the EDG load rejection portion of ORT 3 was re-performed with the new overload
j
setpoint. The 2P-15A.Sl pump performed satisfactorily. Following an overload
current setpoint change on Unit 1, IT-01, "High Head Safety injection Pumps and
Valves (Quarterly)," was successfully performed on the 1P-15A Si pump.
<
E2.3 Conclusions on Encinaarina Snanart of Feilities and Eauinment
The inspectors identified that procedure NDE-754, which performed ASME Code
inspections of supports, lacked acceptance criteria for the clearance between a
}
support baseplate and the building structure. The lack of criteria could allow
]
significant gaps to go undetected.
,
!
The inspectors considered that the actions taken to resolve the material grade and
j
seismic installation qualification of 3/8" tubing attached to RCS to be
i
noncomprehensive, in that the qualification of all instrument tubing was not fully
addressed. Additionally, the inspectors were concerned with the lack of
-
l
engineering staff aggressiveness in resolving this issue, since installation of non-
'
seismic tubing could increase the risk of an unisolable RCS leak.
The licensee's practice of keeping the speed droop in for G-01 and G-02 was
contrary to industry practice and nonconservative in that the safety-relateo
equipment supplied by the EDGs would be subjected to a higher bus frequency,
j'
possibly reducing the margin to breaker trip setpoints. Of particular concem was
the lack of safety focus demonstrated by the licensee's decision to implement
j
manual actions on a long-term basis to cope with the potential loss of the MDAFW
pump (from a breaker trip on overcurrent), instead of changing the practice of
.
i
operating G-01 and G-02 with speed droop permanently set.
E3
Engineering Procedures and Documentation
1
E3.1
Design Basis Document Reviews
.
!
a.
Inanection Scone (93802)
!
.
j
The inspectors reviewed a sample of the 93 open items identified by the
'
engineering department for 19 completed DBDs and open items for 2 draft DBDs.
b.
Observations and Findinas
The inspectors identified that NP 7.7.3, "As-Built Drawing Program and Design
Basis Document Program Open items," revision 0, and DBD Procedure (DBDP) 4-3,
" Design Basis Open item Management," revision 2, did not require review of DBD
open items to assess the potential operability impact. On December 11, the
inspectors asked the licensee what was the potential impact on system c,perability
of the DBD open items. This question prompted an engineering staff review of all
DBD open items and as of December 20,35 CRs had been written to screen 35
DBD open items for impact on operability.
36
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l
.
.
,
l
1
i
E3.1.1 Untimalv Onorability Determinations
i
{
The inspectors identified the following DBD open items with potential impact on
i
system operability and with late corrective actions:
DBD open item 27-001, " Reactor Protection System (RPS) Backup Trip Circuits
.
!
Do Not Fully Meet IEEE-279 Criterion," was identified by the engineering staff on
December 16,1994. Backup reactor trip circuits were identified as not meeting the
.
!
safety-related train separation criterion in IEEE 279-1968, which could impact
j
reactor trip circuits under postulated tungle failure events. The licensee wrote a CR
l
and performed an operability determination on December 16,1996, for this open
i
item. The failure to perform a prompt assessment on the impact on operability for
i
this open item is an example of an apparent violation of 10 CFR 50, Appendix B,
Criterion XVI, " Corrective Action," which requires, in part, that conditions adverse
4
!
to quality are identified and corrected (eel 50-266(301)/96018-07e).
l
DBD open item 27-002, " inadequate Ph)sical Separation and Electrical isolation
!
of Non-Safety-Related Circuits from Reactor Protection System Circuits," was
i
identified by the engineering staff on December 16,1994. The concern was that a
j
single fault in the nonsafety-related backup reactor trip circuit could propagate into
i
both RPS trains and disable the safety-related primary trip function. The licensee
,
$
wrote a CR and performed an operability determination on December 16,1996, for
!
this open item. The failure to perform a prompt assessment is an example of an
I
apparent violation of 10 CFR 50, Appendix B, Criterion XVI (eel 50-
l
266(301)/96018-07f).
i
!
DBD open item 27-003, " Loop Accuracy Requirements Could Not Be Found For
l
l
Some Reactor Protection System Trip Parameters," was identified by the
!
ongineering staff on December 16,1994. The concem was that instruments of
l
lesser accuracy than original margins had accounted for could result in
j
nonconservative TS setpo;nts for the following:
i
!
the low-low steam generator narrow range trip
-
l
reactor coolant pump undervoltage trip
-
j
reactor coolant pump underfrequency trip
i
-
{
steam flow trip
-
l
feed flow trip
-
i
j
The licensee wrote a CR and performed an operability determination on December
j
19,1996, for this open item. The failure to perform a prompt assessment is an
example of an apparent violation of Criterior: XVI (eel 50-266(301)/96018-06g).
.
?
DBD open item 30-002, " Nonsensitive Operation of Containment Condensate
,
Measuring System," was identified by the engineering staff in January 1996. The
system was operated in a manner less sensitive than described in the FSAR
4
j
(Section 6.5), and may not have the capability to detect a 1 gpm RCS leak within
four hours as described in the licensee response to GL 84-04, "SE of Westinghouse
,
l
Topical Reports Dealing with the Elimination of Postulated Pipe breaks in PWR
37
4
4
e
J
, ,
-
- -
.-.
, - . .
. _ ,
_
. , - . _ . . . _ .
. _ _
.
,
d
Primary Main Loops." The licensee wrote a CR and performed an operability
determination on December 16 for this open item. The failure to perform a prompt
j
asaoasment is an example of an apparent violation of 10 CFR 50, Appendix B,
j
l.
Criterion XVI (eel 50-266(301)/96018-07h).
4
DBD open item 30-003, " Containment HVAC Backdraft Damper Not Analyzed to
2
Withstand Dynamic Pressure Forces," was identified by the engineering staff in
January 1996. Replacement backdraft dampers were analyzed for static conditions
only and evidence that they would withstand the dynamic forces following a LOCA
was not available. The licensee wrote a CR and performed an operability
J
j
determination on December 16 for this open item. The failure to perform a prompt
i
assessment is an example of an apparent violation of 10 CFR 50, Appendix B,
'
Criterion XVI (50-266(301)/96018-07i).
i
i
!
- DBD open item 33-002, "Bechtel Calculations 6.1.2.1, Book 26 and 6.1.2.2.2,
Book 29 Related to Design of the Containment Floor Systems do not Appear to Add
4
interior Structure Loading," was identified by the engineering staff in January 1995.
l
<
The staff identified that these calculations lacked evidence to prove that the seismic
'
analysis for containment was considered in the design for the shield walls and
.
'
intermediate concrete slabs and support steel. The postulated failure of these
structures during the design basis seismic event could result in the loss of function
,
j
of safety-related components. The licensee wrote a CR and performed an
t
operability determination on December 11,1996, for this open item. The failure to
{
perform a prompt assessment is an example of an apparent violation of 10 CFR 50,
i
Appendix B, Criterion XVI (eel 50-266(301)/96018-07j).
'
p
i
. DBD open item 35-002, " Main Feedwater isolation for Small Break Loss Of
i
Coolant Accident (SBLOCA) Analysis Not Modeled as Expected to Occur," was
4
i
identified by the engineering staff in April 1995. Main feedwater flow wotJd be
lost immediately during the SBLOCA, vice having 2 seconds of full foedwater flow
j
as assumed in the accident analysis. This incorrect assumptial was expa.:ted to
'
!
raise the peak clad temperature during an SBLOCA. The licoru.ee wrota a CR x.d
!
performed an operability determination on December 13,1996, for thin open item.
!
The failure to perform a prompt assessment is an example of an apparent violation
of 10 CFR 50, Appendix B, Criterion XVI (eel 50-266(301)/96018-07k),
,
j
E3.1.2 Weak Ooarability Determinations
i
j
The inspectors considered the engineering quality of the initial operability
determinations for the DBD open items listed below to be weak. As a result of the
j
inspectors' concerns, the licensee conducted additional followup evaluations.
'
. For the operability determination associated with DBD open item 33-002
concerning the lack of consideration of seismic loads in structural ca'culations for
containment interior structures, engineering judgment was relied or' to conclude
j
that the structures were operable. The licensee concluded further analysis was
j
required.
i
38
i
'
4
i
i
1
-.
.
~ , . - -
.
~ . - -
-
.
-
--
_ . _ . _ _ _ _ _ _ . _ . ~ . .
___ _ _ .
._. _ _ _ _ _ - . _ . _ . . _ _ .
. . _ _ __.
.
.
!.
!
For the operonility determination associated with DBD open item 22-004
,
concerning the unknown minimum required setting for the reactor trip cn
undervolts9e, engineering judgment was relied on that assumed the TS setpoint
,
j
provided an adequate margin to the value used in the accident analysis. The
licensee concluded that no further evaluation was required. However, due to issues
'
raised by the inspectors (see Section E3.2) this operability determination was being
!.
rewritten.
For the operability determination associated with DBD open item 30-002
-
concerning the containment condensate measuring system, enginooring judgment
was relied on to conclude that the containment leak detection sensitivity was
-
!
within the requirements of licensing commitments. The licensee concluded further
analysis was required.
!
,
j
For the operability determination associated with DBD open item 35-002
)
concerning the nonconservative assumption for the feedwater system in a SBLOCA
l
analysis, engineering judgment assumed adequate margin existed to account for the
increase in peak clad temperature during a SBLOCA. The licensee concluded that
further analysis was required.
j
E3.2 DBD-RelatM Technical lasues
l
a.
Insnaction Scone (93802)
i.
l
The inspectors reviewed the following documents during a followup on several DBD
j
electricalissues:
4
I
CR 93-137 and the associated operability determination for the potential
-
inadequate fault current interrupting capability of breakers
j
DBD-21, "480 VAC System," revision O
I
-
DBD-22, "4160 VAC System," revision O
-
ABB impell Calculation No. 0870-150-007, dated June 1,1992
-
United Engineering & Constructors (UE&C) Calculation No. 6704-OO1-C-080,
-
dated August 30,1994
TSCR dated April 27,1995, on the loss-of-voltage relays
-
Calculation No.94-130, dated June 4,1995
-
TS Amendment Nos.167 and 171, dated December 27,1995
t
Calculation No. N-95-OO95, " Determination of Response Time of Reactor
-
Trip on 4160 Volt Bus Undervoltage, dated April 26,1995
i
Accident Analysis Basis Document DBD-T-35, " Loss of Forced Reactor
-
Coolant Flowf mvision O
CR 91-072A, on possible inadequate current limiting devices on inverters
-
and cable separation issues
DBD-P-50, " Electrical and Mechanical Separation," revision O
-
l
39
- - -
- - - ..- - -
. - . - - -.
- -
-- --- - - ----
- - -
1
'
'
i
I
- '
i
CR 97-0105, " Potential Loss of DC Buses D-19 and D-22"
-
!
an associated prompt operability determination dated January 14,1997
-
JCO 94-03, dated June 23,1994
-
..
l
.
i
b.
Obaarvation and Rndings
i
E3.2.1 leania-te Fault Current interruntino t'=a=Mity of Breakers
The 1992 AB8 Impell calculation involved a short circuit analysis with G-01 and G-
!
02. The calculation indicated that fault currents for all twelve 4160-V buses,3 of
eight 480-V buses (load centers), and 13 of twenty-six 480-V motor control
!
centers (MCCs) could be larger than the demonstrated capability of the equipment.
i
No action was taken until Mar::h 30,1993, when CR 93-137 was written. The
l
associated operability determination dated April 2,1993, stated the AC distribution
system was operable based on the following.
,
!
Conservative assumptions were made in the ABB impell calculation
I
.
The fault condition was assumed to be the single failure
.
The basis for the breaker rating was the tested capability and the breakers
.
may be able to withstand higher fault current
Appendix R assumed a failure of the overcurrent device. If the fault
.
occurred downstream of the power cable, the cable between the fault and
the overcurrent device would tend to reduce the fault current at the device,
due to cable resistance.
The operability determination relied extensively on engineering judgment with no
quantitative analysis to support the key assessment, the Appendix R item. CR 93-
137 stated that further evaluation was required. However, as of December 20,
1996, the CR was still open.
In August 1994, the licensee contracted UE&C to perform another short circuit
analysis taking into consideration the new G-03 and G-04 EDGs. This analysis
resulted in Calculation No. 6704-001-C-080, which concluded that the 480-V load
i
centers were operable. However, it again concluded that some of safety-related
,
480-V MCCs and nonsafety-related 4160-V buses could experience fault currents
greater than the interrupting capability of the breakers. Additional analysis to verify
the acceptability of this issue was not performed.
The inspectors' questions prompted a licensee review of site-specific breaker data
that determined the fault currents for all 4160-V buses were below the interrupting
capability of the breakers. However, for five safety-related 480-V MCCs (and four
nonsafety-related 480-V MCCs), the inspectors were concerned that the fault
,
currents could potentially be larger than the interrupting capability of the breakers.
Nonetheless, since there was no existing fault condition, the engineering staff
considered the breakers operable.
10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," required that conditions
adverse to quality are promptly identified and corrected. After the condition was
40
- -
-
- -
. - .
.
.
,
- - - .
- . - .
-
-
-
. _ . ~ . _ _ _ _ . _ . .
. _ _. _ ._ _ _ _ _ ._ _ _ __ _ ___._ _ _ _
4
.
.
l
.
1
identified that the fault currents may be larger than the interrupting capability of
I
breakers in March 1993, the licensee failed to take prompt corrective actions to
replace breakers oc perform quantitative analysis to address this condition. This
.
failure is an example of an apparent violation of 10 CFR 50, Appendix B, Criterion
'
XVI (eel 50-266(301)/96018 071).
1
l
E3.2.2 Nonconservative TS Satooints for I ama-of-Voltaa= Rs!sys
I
l
The licensee identified around July 12,1994, that the loss-of-voltage settings in TS
!
Table 15.3.5-1 for the 480-V relays were not conservative (DBD open item 21-
l
006). New relays had been installed previously to ensure proper coordination with
1
the 4160-V loss-of-voltage relays, but the new relays had different characteristics
j
from the original relays. As part of the corrective action, the licenses submitted a
TSCR (dated April 27,1995) for Table 15.3.5-1 to change the loss-of-voltage relay
!
setpoints on the 4160-V bus to a:3156 V with a time delay of 0.7 to 1.0 second
l
and change the 480-V bus to 256 V * 3 percent with a time delay of s 0.5
i
second.
i
j
As additional followup to the DBD item, the licensee completed Calculation No. N-
t
94-130 on June 14,1995. The calculation identified that under a heavily loaded
j
condition the proposed TS lhits for the loss-of-voltage relays would not assure that
l
l
the 480-V relays would operate before the 4160-V relays; however, no effort to
revise the submitted TSCR was made. The finding that the proposed relay settings
'
would be nonconservative was a condition adverse to quality. On December 27,
1995, the NRC issued Amendment Nos.167 and 171, which changed the loss-of-
,
!
voltage setpoints and the time delays in TS Table 15.3.5-1.
i
!
In Calculation No. N-94-130, the engineering staff identified a scenario (an SI signal
j
followed by a LOOP) wherein the TS-allowed setpoints could create a condition for
l
block loading of the EDG. ." rom attachment K (showing a voltage decay curve for a
j
heavily loaded condition) of the calculation, the engineering staff had concluded
j
that if the loss-of-voltage relay for the 4160-V bus was set at 3156 V with a delay
1
of 0.7 second and the loss-of-voltage relay for the 480-V bus was set at 248 V
!
(256 V minus 3 percent) with a delay of 0.5 second, the 4160-V loss-of-voltage
!
relay could actuate and open the associated supply breaker before the 480-V loss-
l
of-voltage relay. This would cause a load shed on the 4160-V bus before the 480-
i
V bus. Thus, when the EDG output breaker was signaled to close, the 480-V bus
loads may not have shed from the bus and a block loading of the EDG could occur.
,
To prevent the block loading, the licensee revised the maintenance procedures to
<
j
calibrate the relays to smaller tolerances than the maximum allowed by the TS.
1
The engineering staff reportedly pianned to modify the relay scheme in 1997 so
that the 480-V relays would be slaved to the 4160-V relay to better coordinate load
shedding.
<
1
j
10 CFR 50, Appendix B, Criterion XVI, " Corrective Action" requires, in part, that
conditions adverse to quality are identified and corrected. The failure on or around
June 14,1995, to correct Table 15.3.5-1 of TS 15.3.5.A when the licensee
!
identified that the proposed settings (which were subsequently incorporated into
1
41
4
)
i
i
,
,_
_
_
_ _ -
-
. - .
.
.-
_
.
-
-
.-
- - - . . - . . - - - - . - . - _
._-.- - - - -_-
.-
- . - ~ -
.
.
,
!
i
the Table) were nonconservative, a condition adverse to quality, was an example of
an apparent violation of 10 CFR 50, Appendix B, Criterion XVI (eel 50-
l
266(301)/96018-07m).
!
j
E3.2.3 M-=s v of the Satooint Used for the RCP UV Trio
1
]
Calculation No. N-95-0095 was performed by the licensee to determine the
response time associated with a reactor trip caused by a loss of AC voltage to the
l
4160-V busses, which was an initiating event assumed in the complete loss of flow
i
i
accident analysis. This calculation was used to demonstrate the adequacy of the
'
j
setpoint used for the reactor coolant pump undervoltage (RCP UV) trip, and the
i
engineering staff intended to use the calculation to resolve the issue associated
with DBD open item 22-004, "The Minimum Required Setting For The Reactor Trip
On Undervoltage Could Not Be Verified."
[
On December 17,1996, the inspectors identified that the calculated setting of
j
3081 V listed in Calculation No. N-95-0095 for the RCP UV trip setpoint
j
(accounting for instrument inaccuracies) constituted approximately 70 percent of
1
j
the observed bus voltage (about 4400 V). This setpoint was potentially contrary to
l
TS 15.2.3.1.B.(6), which required the RCP UV trip to be set at greater than or
i
!
equal to 75 percent of " normal voltage." The inspectors considered this issue to be
l
an unresolved item (URI 50-266(301)/96018-17(DRS)) pending tne outcome of the
licensee's review and clarification of the TS value for " normal voltage."
I
On December 18, the inspectors questioned the validity of the input value of 0.06
i
seconds for the reactor trip breaker trip time used in the calculation. The
1
engineering staff had selected this time based on the longest time of 0.058 second
recorded during U1R22 (Unit 1, refueling outage 22) reactor trip breaker testing and
,
}
had recorded this value as conservative. However, the inspectors identified that a
j
value of 0.15 second had been assumed for this parameter in the Accident Analysis
j
Basis Document DBD-T-35, " Loss of Forced Reactor Coolant Flow," revision 0, for
~
the complete loss of flow accident. The inspectors reviewed additional data for
Unit 1 and Unit 2 reactor trip breaker trip times, recorded during the 1995 and
1996 outages, and identified a breaker with a 0.0733 second trip time, which
confirmed that the assumed value of 0.06 second was inappropriate and
nonconservative.
10 CFR 50, Appendix B, Criterion lil, " Design Control," requires, in part, that
measures be established to assure that applicable regulatory requirements and the
design basis are correctly translated into specifications, drawings, procedures, and
instructions. Failure to ensure applicable design basis information was correctly
translated into procedures as soon with the use of a nonconservative value for the
reactor breaker trip time in Calculation No. N95-0095 is a violation of 10 CFR 50,
Appendix B, Criterion lil, (VIO 50 266(301)/96018-18(DRS)).
On December 19, the licensee completed a prompt operability determination for the
loss-of-voltage relays associated with the RCP UV trip, and concluded that the
relays were operable. This determination was based on an assumed value of 0.084
42
.
_
--
- -- -..
.- . - . . - .
-
-.--.-----.
- --
_
!
.
.
}
l
<
!
!
second for reactor trip breaker trip time, which yielded a 1.474 seconds total delay
j
time for the RCP UV trip, which was less than the 1.5 seconds assumed in the
!
accident analysis (FSAR table 14.1.8-1). The operability evaluation stated that the
'
l
0.084-second trip time was the maximum allowed by procedure RMP 26, " Reactor
Trip and Bypass Maintenance," revision 14. However, the inspectors identified that
i
the maximum time allowed by the procedure was 0.167 second. This disparity
'
prompted the engineering staff to commit to change the trip time in RMP 26 to
0.084 second.
'
t
d
Additional actions recommended by the operability assessment included revising
.
l
Calculation No. N-95-OO95 to include a statistically significant value for the
maximum breaker trip time. The inspectors identified that the licensee's corporate
engineering department had a copy of a letter sent to C. Rossi of the NRC, dated
1
l
January 19,1984, on " Draft Westinghouse Owners Group Comments to Draft l&E
j
Bulletin on UVTA Time Response Testing," which included statistically significant
j
reactor trip breaker trip times. These breaker trip times could have been used to
i
support this operability assessment. The 0.084-second trip time was not bound by
j
procedure nor demonstrated to be a statistically bound value, and thus the
inspectors concluded that the use of this number to demonstrate operability was
j
inappropriate and inadequate.
i
l
10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," requires, in part, that
i
conditions adverse to quality are identified and corrected. The use of 0.084 second
for trip breaker trip time in the prompt operability determination to demonstrate that
!
the RCP UV trip time delay was within analyzed limits was inappropriate and
1
inadequate, and is an example of an apparent violation of 10 CFR 50, Appendix B,
l
Criterion XVI (eel 50-266(301)/96018-07n).
,
4
!
E3.2.4 cahl= Senaration le== with Unit 1 Containment Snrav Svstem
I
i
On March 4,1991, the licensee identified that the current limiting devices on the
inverters may not prevent a fault in one circuit from affecting other circuits. The
j
licensee initiated CR 91-072A and several actions to address this issue. One of the
j
subsequent actions, initiated on June 9,1993, was to evaluate the need for cable
!
re-routing or installation of current limiting fuses. However, the due date for this
i
action was extended several times to April 15,1997.
!
On May 7,1996, the licensee identified in DBD-P-50 that the circuit breakers
supplying some nonsafety-related buses would not adequately isolate the buses
during a bus fault before the loss of an instrument bus. To correct this, these
!
buses and their loads would have to be either associated with their safety-related
!
channel or isolated from the safety-related supply though an isolation device
j
designed to limit fault current to a value less than the inverter current limiter value.
I
However, the licensee did not initiate another CR and did rsot track the issue with
i
other DBD open items. The licensee stated in DBD-P-50 that this cable separation
j
concern would be addressed in CR 91-072A.
4
1
43
i
I
,
._,
_ _
-
_..
.
.
_
. _ _
_ _ _ _ . _ _ - _ _ _ _ _ . _ . _ . - _
_ _ . _ _ _ _ . _ _
tj
>
.
i
!
J
On December 12, in response to the inspectors' questions, the licensee identified a
4
!
potential mechanism for multiple faults on the 120-VAC (Volts Alternating Current)
-
!
instrument power system at a single location preventing proper actuation of ESF
,
equipment. This postulated condition stemmed from the current-limiting
'
'
characteristics of the inverters in combination with the lack of physical separation
for the nonsafety-related circuits powered from each inverter. The licensee
,
I
preliminarily determined the circuit impedances would prevent a loss of multiple
i
mverters. The licensee subsequently notified the NRC per 10 CFR 50.72.
1
On January 10,1997, after further evaluation, the licensee determined that cable
impedance would provent inverter failures in all but one case. The cables for two
,
i
loads from nonsafety-related instrurnent bus 1Y31 and one load from 1Y21 were
!
routed in the same raceway. With a fault in this raceway, the inverters would
j
experience a current limit condition resulting in a loss of voltage before the supply
breakers to buses 1Y21 and 1Y31 would open. The loss of instrument buses 1YO2
(which fed 1Y21) and 1YO3 (which fed 1Y31) would result in the loss of autometic
e
l
actuation of the Unit 1 containment spray system. A 50.72 notification was also
,
j
made on this issue. The licensee immediately de-energized the three nonsafety-
'
related loads.
.
1
l
The licensee planned to reconfigure all of the nonsafety-related instrument buses to
l
be powered from the isolation transformers of instrument buses 1/2 Y-03 and 1/2
^
Y-04 prior to Unit 2 startup from its current refueling outage. The licensee
submitted LER 96013 on January 13,1997, to add ess this cable separation issue.
l
10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," requires, in part, that
i
conditions adverse to quality are identified and corrected. Since 1991, the licensee
had known of the potential for affecting multiple circuits due to the current limiting
ch rectoristics of inverters. Some corrective actions were begun on June 9,1993.
!
Through the DBD effort, the licensee reconfirmed the potential loss of inverters in
!
May 1996. However, the significance of redundant cables in the same raceways
l
was not determined in a timely manner. As a result, the Unit 1 containment spray
i
system was susceptible to a common mode failure (since plant construction). From
j
1991 to January 1997, the licensee failed to take timely actions to correct
i
problems caused by a lack of cable separation. This is considered an apparent
2
violation of 10 CFR 50, Appendix B, Criterion XVI (eel 50-266(301)/96018-070).
i
l
E3.2.5 Cable Senaration lasua involvina Molded-Case circuit Breakers
i
The inspectors followed up on the January 13,1997, identification by the licensee
'
of a potential for common mode failure of DC electrical buses due to failures of
molded-case circuit breakers (MCCBs).
l
in 1994, based on a high failure rate of magnetic trip elements in MCCBs, the
,
licensee wrote JCO 94-03. The JCO stated that the potential for failure of the
1
i
magnetic element of original DC (direct current) system MCCBs was not an
'
j
operability concem assuming single failure criterion. However, the JCO stated that
there were some nonsafety-related cables of redundant trains routed in the same
)
i
i
)
44
!
i
!
J
. - , -
-
--.
_.
-, . ,
,
,
,
,, ,
,
. __
_
__
_
_-
- . _
_ _ _
._ _ _ _
_
._. _
. _ _
. . _ .
,
,
i
raceways, possibly creating a common mode failure. The licensee concluded that
the probability of such a fault was highly unlikely and the upstream breakers would
isolate the fault if it did occur. However, the effect of losing DC buses was not
,
examined at that time.
The licensee, as part of a recent commitment to the NRC, attempted to generate an
SE for JCO 94-03. During this effort, the licensee identified thet the redundant
cables associated with the Unit 2 rod drive motor generator were routed in the
same raceway. Due to smaller cable impedances, this condition could create a fault
'
current greator than the thermal overload (TOL) interrupt capability for breakers D-
'
19-09 anl D-22-06. Failure of these breakers to clear a common fault would cause
the supply breakers to open and de-energize the safety-related loads on buses D-19
,
and D-22. This would lead to the loss of the automatic closure ca the Unit 2 main
'
steam isolation valves (MSIVs) and the automatic initiation of an tiSF actuation
signal, and to the loss of the capability for closing the Unit 2 MSIVs and for
initiating an ESF actuation from the control room. During a design basis accident,
the licensee would have to manually close the MSIVs and start individual ESF
equipment from the control room. The same condition did not exist for the
comparable Unit 1 DC buses.
I
The licensee planned to replace the breakers with ones of sufficient interrupt
capability and test the magnetic trip elements and TOLs of the replacement
breakers. The old breakers would be tested only in the thermal region to serve as a
basis for continued service of other DC MCCBs.
10 CFR 50, Appendix B, Criterion XVI, " Corrective Action," requires, in part, that
conditions adverse to quality are identified and corrected. Failure to take timely
corrective actions since 1994 to resolve the cable separation and undersized
breaker TOL concern is an example of an apparent violation of 10 CFR 50,
Appendix B, Criterion XVI (eel 50-266(301)/96018-07p).
The inspectors concluded that JCO 94-03 was weak in that the licensee did not
evaluate the effect of losing DC power to protection circuits. This was
subsequently determined to be significant. The potential loss of DC buses D-19
and D-22 would result in the inability to close Unit 2 MSIVs and to initiate a Unit 2
ESF actuation from the control room.
E3.3 Revised Onerability Determination Process
a.
Insnaction Scone
The inspec, tors reviewed the following documents to assess the changes in the
operability determination process:
NP 5.3.1, " Condition Reporting System," revision 4
-
i
NP 5.3.7, "Opercbility Determinations," revision 0
-
" Root Cause Tree User's Manual"
-
l
{
45
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1_
.
-
.
. .
.~
- . ~ . - - - - - - - - - -
- .
. - --- ..
- - - . ,
,
.
b.
Observations and Findings
The licensee had been reviewing the operability determination system since the
spring of 1996 to improve the JCO process and to use industry operating
experience with GL 91-18. On November 27, the licensee issued procedure NP
5.3.7, " Operability Determinations," revision O. Since the procedure was just
implemented within one week of the beginning of the OSTI, the inspectors were
unable to assess its effectiveness. However, the inspectors had the following
observations:
The procedure incorporated the GL 91-18 position on a prompt written
-
operability determination for degraded or nonconforming conditions and a
g
subsequent, in-depth evaluation.
Timelmess of operability determinations was definitively established.
-
The procedure required a notebook in the control rocm for operability
-
determinations for which final resolution was pending. Further, the
procedure required that for issues where corrective action would not be
accomplished before the end of an outage an SE be performed to verify the
acceptability of the non-conforming condition or to identify any unreviewed
safety questions. The inspectors considered this an improvement from the
older system, which did not readily track uncorrected and degraded but
operable structures, systems, and components.
Control of compensatory actions, such as manual operations as allowed
-
under GL 91-18, was not included in the procedure.
For non-TS structures, systems, and components, the licensee used JCOs
-
and JCO !mplementing procedures. However, the inspectors considered the
use of JCOs in this case to potentially diffuse the current attempt to develop
a centralized comprehensive process. The licenses staff stated that they
were considering phasing out the use of JCOs and incorporating
.
I
compensatory manual action controls into NP 5.3.7.
]
E3.4 Conclusions on Enoineerino Procedures and Documentation
The inspectors identified a concern with the lack of prompt corrective actions to
,
address the fault current interrupting capacity of safety-related breakers, which the
i
licensee had identified in March 1993. The inspectors' questions prompted a data
review that resolved this issue, except for breakers on nine 480-V MCCs.
The licensee had identified a scenario associated with a nonconservative TS
J
setpoint for loss-of-voltage relays which could potentially allow block loading of the
EDG. The licensee compensated by using a more restrictive setpoint in the
maintenance procedures. The inspectors considered this adequate to prevent the
!
,
3
46
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_
__.
_ _ _ _ _ . _ _ _ _ _ .
_ _ _ _ _ _ . . _ _ _ . _ _ _ _ _ _ _ . _ .
.
.
L
problem. However, the licensee's lack of actions to inform the NRC while a related
license amendment was under review or to make another TS change request to
correct this error was considered inadequate.
Inappropriately and nonconservatively, engineering judgement was used to select a
reactor trip breaker trip time used in an operability determination associated with an
RCP UV trip setpomt. Resolution of DBD open items on cable separation were not
thorough and timely. Several of the operability determinations associated with DBD
open items relied in part, or in whole, on engineering judgement, vice analysis or
calculations, which inspectors considered to demonstrate a weakness in
enginsonng technical quality.
The inspectors considered the overall DBD effort to be comprehensive and of
adequate technical quality. However, the inspectors identified 13 examples of an
apparent violation for failure to take prompt corrective actions in response to DBD
issues potentially impacting operability. DBD procedures lacked a requirement to
-
promptly assess operability impact of open items. In addition, a violation was
l
identified for not properly translating design basis information into procedures.
The operability evaluation process was too new to assess conclusively. The
inspectors considered the changes to the process to be a positive effort overall.
However, a key element that remained to be demonstrated was the effectiveness of
the operability screening process triggered by the CR system as discussed in
Section 08.1 of this report.
E7
Quality Assurance in Engineering Activities
E7.2 Quahty Assurance Audit of the Containment Leakage Rate Testina Prooram
a.
Inspection Scone (93802)
1
The licensee's OA audit of the proposed " performance-based" containment leakage
rate testing program involved a review of proposed TS changes, draft basis
documents, and the FSAR containment isolation system design in comparison to
regulatory requirements. The inspectors reviewed the audit report (A-P-96-23) and
the following related " quality" CRs (OCRs) to ascertain technical adequacy and
adherence to the licensee's program requirements:
OCR 96-059, "(SCAO) Reverse direction testing of containment isolation
-
valves does not provide equivalent or more conservative results"
OCR 96-063, " Charging and Volume Control System (CVCS) is not a closed
i
-
system for containment isolation purposes"
OCR 96-064, "No exemption exists for not doing Type C testing of safety
j
-
injection system containment isolation valves"
OCR 96-066, " Flanges and valves on spare penetrations may need to be
-
!
tested"
OCR 96-016, " Potential exists that the charging pump outlet integral chack
-
j
valves are not being tested to ASME Section XI requirements"
!
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,
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-
.
-
.
.
.
.-
-
-.
.-
- - . . - . - . -.
,_ ~ - - . - . - - - . - - . -
.
.
b.
Ohaarvations and Findings
Report A-P-96-23, issued October 8,1996, included a review of the " Containment
Leakage Rate Testing Program Basis Document" issued September 6,1996, to
address the licensee's proposed change in its containment leakage testing process
to Option B of 10 CFR 50, Appendix J. The report concluded that the testing
program was ineffective, as outlined, and needed prompt action to address specific
,
deficiencies identified in eight OCRs. Barad upon interviews with audit personne!
and review of selected OCRs, the inspectors concluded that the audit contained the
required design reviews and SEs as indicated by the quality of non-conformance
{
findings. However, the inspectors identified the several problems during a review
of the OCRs listed below:
I
i
OCR 96 059, issued September 16,1996, identified a number of containment
.
t
penetration isolation gate valves and a diaphragm valve (in each Unit) that were
reverse-direction tested, contrary to Option A, Section Ill.C.1 of Appendix J to 10
CFR 50. The audit report stated that these valves were reverse-direction tested
i
without adequate justification. The inspectors reviewed the technical evaluation
report for license amendment No. 61 and No. 66 issued June 25,1982, addressing
the Appendix J concern and noted that the report stated that reverse-direction
1
testing of four (two diaphragm and two butterfly) containment isolation valves was
acceptab!e bec use the critoria of Section Ill.C.1 had been met. The inspectors
i
discussed the discrepancy between the OCR and the regulatory requirements with
i
the licensee who acknowledged that the audit results needed further review.
OCR 96-063, issued September 16,1996, identified a design basis concern for
containment isolation systems in that CVCS may not meet the requirements for a
closed system as defined in section 3.6.7 of American National Standards
Institute /American Nuclear Society (ANSI /ANS) 56.2-1984, " Containment isolation
Provisions for Fluid Systems After a LOCA." The subsequent engineering
evaluation determined that the charging pump discharge integral check valves
would become the CVCS closed system boundary and closed out OCR 96-063 by
J
deferring corrective action to item number 2 of OCR 96-016, issued February 29,
1996. OCR 96-016 was issued in response to audit report A-P-96-02 in that the
charging pump outlet check valves were determined to be safety-related at an MSS
meeting (MSSM 93-15) held on August 3,1993, but no record of testing in
accordance with ASME Section XI requirements could be located. A written
response to the NRC dated June 19,1993, stated in part that " charging pump
outlet check valves were to be upgraded to OA and Safety Related Criterion 14."
The licensee acknowledged that these check valves should have been included in
the inservice testing (IST) program, but an engineering evaluation determined that
performance of quarterly charging pump and valve testing met the requirements of
ASME Section XI. This is an inspection followup item pending completion of the
IST program documentation upgrade projected for March 1,1997 (IFl 50-
266(301)/96018-19(DRS)).
4
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_
_
_.
,
-.-
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'
!-.
)
OCR 96-066, issued Septemoor 16,1996, identified a potential failwe to test
. spare containment penetration valves or flanges to the requirements in Appendix J
l
to 10 CFR 50. The supporting determination stated that this condition was not a
TS violation but was reportable, in OCR 96-066, CR 96-795 was referenced with
actions to have the RES review the CR and OCR items stemming from the audit
report and submit an LER concerning the testing deficiencies. On October 14,
while Unit 1 was at power operations and Unit 2 was at cold shutdown, an
engineering evaluation in response to the OCR determined that penetrations P-12b
(both Units) and P-30s (both Units) contained blind flanges inside containment
which were not welded and had not been Type B tested since 1984. The
evaluation revealed that ORT-29 and ORT-41 had been cancelled in 1985 and had
been used for testing P-12b and P-30a. Corrective action, completed on October
25, was to rewrite ORT-29 and ORT-41 to include testing of the penetrations.
The inspectors identified that CR 96-795 did not address the penetration testing
concern and that RES was unaware of the reportability issue. The RES noted that
the past policy was to address such issues regarding 10 CFR 50, Appendix J,
testing as a program concern and not as a TS issue. Since TS 15.4.4.11 (under
revision prior to November 1996) required that penetrations which employed
resilient seals, gaskets, or sealant compounds be Type B tested during each
shutdown for major fuel reloading and the interval between tests shall not be
j
greater than two years, the RES acknowledged the significance of reviewing this
issue. As a result, an SE review was performed and completed on January 9,
1997. Testing of the Unit 1 spare containment penetrations was completed on
January 10, and the licensee cwtended that the Unit 1 containment (the operating
Unit) was operable throughout this evaluation period.
I
The inspectors determiwd that since October 14,1996, the engineering staff had
been aware that P-126 and P-30s had not been Type B tested in accordance with
Appendix J and TS 16.4.4.11 requirements, and had not effectively communicated
this conditico to the RES. The TS required that containment penetrations which
employ resilient seals, gaskets, or sealant compounds; piping penetrations fitted
with expansion bellows; and electrical penetrations fitted with flexible metal seal
j
assemblies be tested duiing each shutdown for major fuel reloading and in no case
shall the interval be greater then two years.
'
TS 15.4.0.3 required that when a surveillance was not performed within its
specified frequency, then the requirement to declare the system or component
inoperable and enter the LCO may be delayed from the time of discovery up to 24
hours, if the surveillance frequency was greater than or equal to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, or up to
the limit of the specified frequency, whichever was less. TS 15.3.0.B required that
in the event an LCO cannot be satisfied because of equipment failures or limitations
beyond those specified in the permissible conditions of the LCO, action be initiated
within one hour to place the affected unit in 1) Hot shutdown within seven hours of
i
(
entering this specification; AND 2) Cold shutdown within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br /> of entering this
specification. This specification was applicable during power operation, low power
a
operation, and shutdown with temperature .2. 200 'F.
!
l.
49
r-
3--
r
y
y--
--
-
r
-
w
m-
w-
uwy
i
_ _ _ _ _ _ . _ _ _ ._ _ _
_ __ ..___ _ _ ___ _ _ _._ _ _
_
,
.
,
I
Contrary to the TSs discussed above, between October 14 and December 20,
1996, while Unit 1 was at power operation and Unit 2 was at cold shutdown, spare
4
containment penetrations P-12b (both Units) and P-30s (both Units) were
i
inoperable in that these penetrations had not been tested since 1984. With both
i
containment penetrations inoperable and Unit 1 at power operations, the licensee
i
failed to take prompt action to perform the missed surveillance or place Unit 1 in an
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operstmg condition in which TS 15.4.4 did not apply. 10 CFR 50, Appendix B,
{
'
Criterion XVI, " Corrective Action," requires, in part, that conditions adverse to
l
quality are identified and corrected. The failure to test the penetrations when the
licensee became aware of the problem on October 14 is an example of an apparent
,
l
violation of 10 CFR 50, Appendix B, Critorion XVI, (eel 50-266(301)/96018-07q).
l
The Appendix J testing program deficiencies appeared to be clearly identified on
!
CRs generated as a result of the OA audit. However, when the inspectors
!
questioned the RES about the specific issue discussed above, the inspectors were
informed that no notification had been made to the NRC. As of December 20,
1996, the licensee had not submitted a written notification of this event to the
-
i
Commission. Failure to submit a written report within 30 days of discovery of the
J
TS noncompliance was a violation of 10 CFR 50.73(a)(2)(i)(B) (VIO 50-
!
266(301)/96018-2O(DRP)). The inspectors considered that a potential cause for
the breakdown in communication among engineering and licensing staff was that
,
the concerns in OCR 96-066 were not incorporated into CR 96-795.
l
The licensee submitted LER 97002 on February 6,1997, addressing the missed
}
tests.
}
c.
Conclusions
!
l
The OA audit of the performance-based containment leakage rate testing program
was comprehensive and of adequate technical quality. The audit identified a failure
i
to test four spare containment penetrations; however, the inspectors identified that
j
!
followup testing was not done and reporting requirements were not met. The need
j
to test the penetrations and report the earlier missed tests was clearly identified in
!
the CR.
'
I
iv. piant suonort
j
F2
Status of Fire Protection Facilities and Equipment
4
i
i
F2.1
Valve Performance Durina Postulated Anoendix R Fire Scenarios
'
a.
Insoection Scone
The inspectors reviewed the licensee's evaluation (dated April 5,1993) of
Information Notice (lN) 92-18, " Potential for Loss of Remote Shutdown Capability
during a Control Room Fire," dated February 28,1992, and interviewed cognizant
engineers. In addition, the inspectors reviewed:
50
.
.
. .
.
!
various Appendix R P&lDs
+
AOP-10A, " Safe Shutdown Local Control," revision 18
.
AOP-108, " Safe to Cold Shutdown in Local Control," revision 4
-
l
b.
Observations and Findinas
IN 92-18 identified the potential for loss of remote shutdown capability during a
control room fire. The fire could cause short circuits that result in the bypassing of
motor-operated valve (MOV) limit and torque switches (" hot smart shorts"). The
MOVs would then go to a stall condition, since the control signal would not be
l
available to stop power to the motor. This could cause valve and or operator
degradation prior to plant personnel taking local control of the valve, which for
j
Appendix R-required MOVs could result in the loss of safe shutdown capability.
'
The licensee's response to IN 92-18, dated April 1993, was inadequate in that it
focused only on hot smart shorts in the power circuitry and did not address hot
smart shorts within the MOV control circuitry. To address this inadequacy, the
licensee generated CR 96-1249 with a due date of February, 28,1997. The
inspectors were concerned with the due date, since the regulatory screening
performed in CR 96-1249 allowed continued operation without further evaluation.
Additionally no technical basis had been established for this determination. The
determination relied solely on the following: "there is nothing to indicate that Point
Beach is susceptible to these issues, ... therefore there is nothing to indicate that
an immediate operability concern exists."
In response to the inspectors' concerns, the engineering staff accelerated the
planned analysis to verify that all Appendix R MOVs would be operable under the
hot smart short scenario. However, the licensee did not complete this analysis prior
to the end of the OSTl. At Point Beach, the majority of Appendix R MOVs were in
the AFW and charging systems along with support systems such as service water.
Many of the MOVs were DC-powered. The licensee intended to demonstrate via
testing that the actual stall thrusts for various MOVs were less than analytically
determined in the stall calculation, because of motor torque reduction from
increased temperatures. The licensee planned to use thermography on " uncapped"
motors to ascertain tha increased motor temperatures. The inspectors reviewed the
preliminary calculations which indicated that the structural integrity of the valves
and actuators would not be damaged with spurious operation resulting in stall
conditions. The inspectors identified two concerns:
It was not clear that stall efficiency values were consistently used when
-
determining stall thrust. The inspectors requested the technical basis for
using other-than-stall efficiency values in a stall calculation.
The licensee was using the design stem coefficient (SFC) value of 0.15.
-
The inspectors requested the basis for using this value versus as-found SFC
data, since in a stall thrust calculation, use of the as-found value would be
more conservative (if lower than 0.15).
51
.
.
l
Based on the inadequate initial response to IN 92-18, the inspectors considered the
j
licensee's subsequent evaluation a less than aggressive or technically rigorous
!
effort. However, upon notification of the inspectors' concern, the licensee's
!
analyris and planned testing to demonstrate MOV acceptability were responsive
and technically based. Until demonstrated by the completion of the ongoing
analysis, the plant may not have alternative shutdown capability, because potential
fire-induced hot emart shorts may put the plant outside of the Appendix R safe
shutdown design basis. This would be contrary to 10 CFR 50, Appendix R, Section
j
lli.G, Fire Protection of Safe Shutdown Cwability. Resolution of the licensee's
j
response to IN 92-18 is considered an v. 3 solved item (URI 50-266(301)/96018-
21(DRS)) pending NRC review of the licensee's final evaluation.
l
c.
Conclusions
i
i
Based on the inadequate initial response to IN 92-18, the inspectors considered the
!
licensee's evaluation a less than aggressive or technically rigorous effort. However,
1
upon notification of this concern, the licensee's subsequent analysis and planned
l
testing to demonstrate MOV acceptability were responsive and technically based.
<
j
V. Management Meetings
.
j
X1
Exit Meeting Summary
i
l
On January 31,1997, the preliminary results of the OSTI were presented to the
licensee at an exit meeting open to public observation. The licensee did not identify
any likely inspection report material as proprietary.
I
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PARTIAL LIST OF PERSONS CONTACTED
l
Licensee
'
4
R. R. Grigg, President and Chief Nuclear Officer
4
S. A. Patuiski, Site Vice-President
,
A. J. Cayia, Plant Manager
T. G. Staskal, Acting Operations Manager
,
W. B. Frornm, Maintenance Manager
j
J. G. Schweitzer, Site Engineering Manager
T. C. Guay, Regulatory Services Manager
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INSPECTION PROCEDURE USED
(
Operational Safety Team inspection (OSTI)
!
l
ITEMS OPENED, CLOSED, AND DISCUSSED
f
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Onened
f
.
j
50-266(301)/96018-01
Failure to follow TS 15.6.8.1 procedures (2
j
examples)
j
50-266(301)/96018-02
IFl
Fire brigade and control room staffing
l
50-266(301)/96018-03
Routine operation at 100.2 percent power
i-
50-266(301)/96018-04
IFl
Revise TS bases on accumulator cross-tie
j
50-266(301)/96018-05
Appendix B, Criterion V procedure problems (3
j
examples)
l
50-266(301)/96018-06
NCV Danger tag records incomplete
50-266(301)/96018-07
eel
Appendix B, Criterion XVI problems (17 examples)
'
50-266(301)/96018-08
eel
50.59 violation on RHR
!
50-266(301)/96018-09
IFl
Diesel air start motor sequencing
',
50-266(301)/96018-10
eel
TS 15.4.6.A.2 violation on load testing of EDGs
!
50-266(301)/96018-11
eel
TS 15.4.6.A.5 violation of fuel oil pump start
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50-266(301)/96018-12
IFl
FSAR revision for control room ventilation
50-266(301)/96018-13
IFl
Control room ventilation duct hatch
'
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50-266(301)/96018-14
IFl
Wall inspection frequency
i
50-266(301)/96018-15
Nonqualified 3/8" RCS tubing
60-266(301)/96018-16
Use of operator actions for A MDAFW pump
50-266(301)/96018-17
50 266(301)/96018-18
Appendix B, Criterion ill problem with breaker
trip times
50-266(301)/96018-19
IFl
CVCS may not be a closed system
50-266(301)/96018-20
No LER for missed leakage tests
50-266(301)/96018-21
" Hot smart short" potential
Closed
None
1
Discussed
i
None
1
54
1
1
__ _ _ _._ _. _ __ _ _ _.. _ _._.._ _ ,_ .
_ . . . . . _ _
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LIST OF ACRONYMS USED
l
Alternating Current
amps
amperes
j
ANSl/ANS
American National Standard institute /American Nuclear Society
j
Abnormal Operating Procedure
American Society of Mechanical Engineers
CFR
Code of Federal Regulations
CO
Control Operator
i
CHAMPS
Computerized History and Maintenance Planning System
i
CR
Condition Report
Chemical and Volume Control System
'
Design Basis Document
Direct Current
Duty and Call Superintendent
- F
Degrees Fahrenheit
Duty Operating Supervisor
dP
Differential Pressure
Duty Shift Superintendent
EDSFl
Electrical Distribution System Functional inspection
eel
Escaldted Enforcement item
Equipment Operator
Emergency Operating Procedure
Engineered Safety Feature
Final Safety Analysis Report
GL
Generic Letter
Heating, Ventilation, and Air Conditioning
Hz
Hertz
l&C
Instrument and Control
Instrument and Control Procedure
IEEE
Institute of Electrical and Electronics Engineers
IFl
Inspection Followup Item
IN
Information Notice
Inservice Testing
laservice Test
JCO
Justification for Continued Operation
KV
Kilovolt
LCO
Limiting Condition for Operation
LER
Licensee Event Report
Loss of Coolant Accident
Low Temperature Overpressure Protection
mA-dc
Milliamperes-direct current
Motor Control Center
Mold Case Circuit Breaker
Motor Driven Auxiliary Feedwater
55
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_ _ _ _ _ _ ._
_ _ _ .
.
__ _ _ _ . _ _ _ . ._
_ . _ _ .
4
a <.
l
MSS
Manager's Supervisory Staff
4
mV-dc
Millivolts-direct current
MWe
Megawatts-electric
Nonconformance Report
Non-cited Violation
NP
Nuclear Power Business Unit Procedure
NRC
Nuclear Regulatory Comtr.ission
Office of Nuclear Reactor Regulation
Operations Manual
i
OP
Operating Procedure
ORT
Operations Refueling Test
OS
Operating Supervisor
OSCR
Off-Site Review Committee
l
PBNP
Point Beach Nuclear Plant
PBTP
Point Beach Test Procedure
P&lD
Piping and instrumentation Diagram
Power Operated Relief Valve
psig
Pounds Per Square Inch - Gauge
OA
Quality Assurance
Quality Condition Report
1
Reactor Coolant Pump Undervoltage
I
Regulatory Services
Routine Maintenance Procedure
'
rpm
Revolutions Per Minute
'
Small Break Loss of Coolant Accident
'
SCAO
Significant Condition Adverse to Quality
i
Safety Evaluation
!
Safety injection
Special Maintenance Procedure
SOUG
Seismic Qualification Users Group
,
Senior Reactor Operator
TM
'
Thermal Overlood
TS
Technical Specification
TS-#
Technical Specification Test (licensee procedure)
3
TSCR
Technical Specification Change Request
Technical Specification Interpretation
.
UE&C
United Engineers and Constructors
i
Unresolved item
Violation
Work Order
56
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DOCUMENT DIVIDER
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INSERTED BY DDGUMENT CONTROL SECTION!
..