ML20127N652
| ML20127N652 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 01/25/1993 |
| From: | Anderson C NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20127N649 | List: |
| References | |
| 50-277-92-32, 50-278-92-32, NUDOCS 9302010016 | |
| Download: ML20127N652 (20) | |
See also: IR 05000277/1992032
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U. S. NUCLEAR REGULATORY COMMISSION-
REGION I l
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Docket / Report No. ' 50-277/92-32 License Nos. DPR-44-
50-278/92-32-- - DPR-56 -
Licensce: Philadelphia Electric Company
Peach Bottom Atomic Power Station
P. O. Box 195
Wayne, PA 19087-0195
Facility Name: Peach Bottom Atomic Power Station Units 2 and 3 -
Dates: December 15,1992 - January 18, 1993
Inspectors: J. J. Lyash, Senior Resident inspector .
M. G. Evans, Resident Inspector:
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F. P. Bonnett, Resident Inspector
B. E. Korona, Technical Intern .
Approved By: \. l.010hv O cR$ Jos 'i3
C.'X Anderson, ChfelQ Date
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Reactor Projects Section 2B ~ ~[
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Division of Reactor Projects
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9302010016 930125
PDR ADOCK 05000277
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EXECUTIVE SUMMARY
Peach Bottom Atomic Power Station j
Inspection Report 92-32 -
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Plant Operations
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The licensee declared an Unusual Event due to degradation of their emergency communication )
capabilities. Weaknesses in the drawings and device labeling at the licensee's Training and j
-Simulator Building contributed to a loss of power to the communications equipment during '!
performance of planned maintenance (Section 2.1). ']
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The licensee identified that the breaker for the 'A' emergency service water (ESW) pump sluice j
gate was incorrectly left in the closed position for about two months. This resulted in the ESW i
system being in a condition that was outside the design basis of 10 CFR 50, Appendix R. Upon
discovery of the error, the breaker was promptly opened. The licensee and the NRC inspectors
identified several specific weaknesses during follow-up to this event. The licensee previously
identified a broader problem with component mis-positions, and initiated corrective actions.
The NRC will perform additional inspection to evaluate the specific ESW event and the
licensee's corrective actions, and to assess the licensee's effectiveness in addressing the overall
component mis-position problem (Section 2.1,50-277/50-278 URI 92-32-01). ,
The licensee declared the Unit 2 high pressure coolant injection system inoperable when the
system failed to attain rated flow and pressure within the required time while performing a
surveillance test (ST). The technical staff completed comprehensive troubleshooting and ,
repairs, and presented the results of their activities and the. plans for system testing during start-
L up to the Plant Operations Review Committee (Section 2.3).
Maintenance and Surveillance
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The inspectors observed the licensee's inspection and replacement of the inner seal for the '2B'
reactor recirculation pump. The inspector determined that the licensee's evaluation and
corrective actions were good. The licensce's staff identified and corrected pump operating
procedures that contributed to this, and possibly to previous seal failures. (Section 5.1)
Encineerine and Technical Sunoort
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During the period two inboard main steam isolation- valves (MSIV) failed to close in..the
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required time during an ST. In response to these failures the licensee's technical staff, working -
with the maintenance staff, performed troubleshooting and extensive valve air manifold disas-
sembly and inspection. The licensee was unable to' identify the root cause of the problem, but
has committed to implementation of an augmented MSIV testing program to establish confidence
that valve:: will continue to perform acceptably (Section 5.2).
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The inspectors focused on problems encountered during Unit 2 power. ascension testing,
particularly those associated with the new digital feedwater control system and modifications to
the electro-hydraulic control system. The inspectors assessed the licensee's evaluation process
and the design changes made to the systems as a result of their evaluation. The inspectors ' .
determined that the licensee's actions were appropriate (Section 3.1 and 3.2).
Assurance of Ouality
The inspectors evaluated the licensee's approach to assessing safety system operability during
the performance of preventive maintenance and surveillance testing. They determined that the
licensee's approach was not consistent with the NRC position, in that systems rendered incapa-
ble of performing their design functions during testing were not considered to be inoperable.
The licensee has taken several immediate and Interim corrective actions, and committed to
review and revise appropriate STs, the Operations Management Manual, and the ST Writers
Guide within the next six months (Section 4.0) (50-277/50-278 URI 92-32-02).
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Radiologini Controls
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The inspectors accompanied members of the Health Physics start during the semi-annual
inspection of the Unit 1 exclusion area. All areas were found to have dose levels less than 2
i millirem per hour and no loose cr airbome contamination were detected. The inspectors noted
that the inspection was well organized and the procedure was executed well (Section 6.0).
The inspector observed portions of the Health Physics support activities during the replacement
of the '2B' reactor recirculation pump seal. The inspectors concluded that pre-maintenance
planning and job execution were good. Persons performing the. inspection neceived a low
radiation dose during the work, and did not have to wear respirators except when the primary
boundary was breached (Section 5.1).
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-TABLE OF CONTENTS:
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EXECUTIVE SUMMARY . . . ...................................Lii .
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1.0 ' PLANT OPERATIONS REVIEW ...,,..................._...1- _
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2.0 FOLLOW-U P OF PLANT EVENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . - 1- :
2.1 Unusual Event Declared Due to loss of Emergency Communications .. . .. -1
2.2 Emergency Service Water System Outside the Appendix R Design
Basis............................................ 3
2.3 Slow Unit 2 High Pressure Coolant Injection System Response Time . . . 6
3.0 ENGINEERING AND TECHNICAL SUPPORT ACTIVITIES . . . . . . . . . . . . 7
3.1 Digital Feedwater Control System Modification . . . . . . . . .. . , . . . . . . 7
3.2 Turbine Control Valve Oscillations . . . . . .. :. . . . . . . . . . . . . . . . . .-.8
4.0 SURVEILLANCE TESTING OBSERVATIONS . . . . . . . . . . . . . .. . . . . . . . 9-
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5.0 MAINTENANCE ACTIVITY OLSERVATIONS . . . . . . . . . . . . . . . . . . . 12
5.1 Unit 2 '23' Recirculation Pump Seal Repair . . . . . . . . . . . . . . -. . . 12
5.2 Main Stcam Isolation Valve Air Manifold Repair . . . . . . . . . . . . . .. . 13-
6.0 RADIOLOGICAL CONTROLS . . . . . . . . . . . . . . . . . . . . . . . , . : . . 15
7.0 PHYSICAL SECURITY ................................... 15
8.0 M A N A GEM ENT M ELTI NGS . . . . . . . . . , . . . . . . . . . . . . . . . . . . . . . 16
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DETAILS
1.0 PLANT OPERATIONS REVIEW (71707)*
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! The inspectors completed NRC Inspection Procedure 71707, " Operational Safety Verification,"
L by directly observing safety signincant activities and equipment, touring the facility, and
interviewing and discussing items with licensee personnel. - The inspectors independently
verified safety system status and Techni:al Specification (TS) Limiting Conditions for Operetion
j (LCO), reviewed corrective actions, and examined facility records and logs. The inspectors
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performed six hours of deep backshift and weekend tours of the facility. -
i Unit 2 started this report period at 27% power. During power ascension testing, the first stage
of the '2B' Reactor Recirculation Pump Seal indicated that it had failed. The licensee consulted
the manufacturer of the pump seal and determined that the unit could safely continue power
ascension. Unit 2 reached 80% power when testing was restricted due to multiple problems
with the electro-hydraulic control (EHC) system and the digital feedwater control system
(DFC5). Unit 2 began a planned maintenance outage on January 2,1993, to repair the recircu-
lat:on pump seal, EHC problems, and DFCS, Details of these maintenance items are discussed
in Section 3.0 and 5.0 of this report. Unit 2 restarted on January 13,1993, and was operating
at 100% power by the end of the report period.
Unit 3 operated at 100% power for most of the period. One significant power reduction was
completed to remove the turbine-generator from service for repair of an EHC fluid leak and to
clean the six main condenser water boxes. The unit was returned to end operated at full power
for the remainder of the period.
2.0 FOLLOW-UP OF PLANT EVENTS (93702, 71707)
During the report period, the inspectors evaluated licensee staff and management response to .
plant events to verify that the licensee had identified the root causes, implemented appropriate
corrective actions, and made the required notifications. Events occurring during the period are
discussed individually below.
2.1 Unusual Event Declared Due to Loss of Emergency Communications
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On December 19,1992, at 7:35 a.m., the licensee declared an Unusual Event (UE) due to a -
loss of emergency communication capabilities. Both units were operating at 20% power. The
licensee had planned and initiated the replacement of the transformer that supplies electrical'
power to the Training and Simulator Building. This building houses the site telephone equip-
ment, the Technical Support Center (TSC), the control room simulator and training facilities.
While planning the job the licensee recognized that normal power would be lost to the TSC. -
- The inspection procedure from NRC Manual Chapter 2515 that the inspectors used as guidance is
parenthetically listed for each report section.
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The. safety tagging associated with the job was developed to ensure that the TSC emergency
diesel generator would be available to provide power, in the event that TSC activation was
needed. However, the individual preparing the tagging did not recognize that the normal power
supply for the site telephone switching devices would be lost. Contributors to this oversight-
were lack of accurate electrical distribution drawings for the facility, and lack of component
labeling.
When power was secured to replace the transformer, the telephone power supply automatically.
transferred to its eight-hour battery back-up. Since the maintenance staff was unaware of the
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impact of the outage on the telephone system, steps were not taken to complete the task before
the eight-hour battery supply was depleted. The system automatically notified the offsite
telephone service provider that the normal power supply had been lost. -Because the switching
equipment and power supply is located at the plant site, the technician dispatched by the
provider was not familiar with the location and configuration of the system, and was unable to
resolve the problem. At 5:03 a.m. the control room staff noted that the Emergency Notification
System (ENS) line to the NRC was not in service, and began to investigate the cause. Further
investigation indicated that the ENS was not operable, and that the onsite telephone system and
many of the offsite commercial lines were not functioning properly. Some commercial tele-
phone service to the control room was still available. However, the Shift Manager elected to
declare an UE based on the degradation of the communications system, and notified the affected
State and County agencies, and NRC about the problem. The UE was termiaated at 10:15 a.m.- .
after the licensee had installed a portable diesel generator and energized the necessary electrical
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busses and battery chargers. The licensee initiated a Reportability Evaluation / Event Investiga-
! tion Form (RE/EIF) to track determination of the event root causes and implementation of
l corrective actions. The licensee will also submit a Licensee Event Report (LER) documenting _
l the results of their investigation.
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l The inspector interviewed technical and operations staff members involved in the event, and
reviewed event notification documentation, drawings, and_ emergency response procedures. The
inspector also reviewed NRC Bulletin 80-15, "Possible Loss of Emergency Notification System
with Loss of Offsite Power," Information Notice 85-77, "Possible Loss of Emergency. Notifica-
- tion System Due to Loss of AC Power," Generic Letter 91-14, " Emergency Communications,"
and the modifications implemented by the licensee in response to these documents. -The
objective of this review was to assess the adequacy of the emergency notification system power
supply configuration. The inspector concluded that the licensee's system included both a.
primary power supply and an adequate battery back-up. -The licensee's investigation was
progressing at the end of the period, and their final determination of root causes and corrective
actions will be documented in the associated LER.
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2.2 Emergency Service Water System Outside the Appendix R Design Basis
2.2.1 Background
On December 23,1992, at 8:45 a.m., the licensee identified that the breaker to the 'A' emer-
gency service water (ESW) pump sluice gate (MO-2213) was closed. This resulted in the ESW
system being in a condition outside that assumed in the licensee's analysis demonstrating
compliance with 10 CFR 50, Appendix R. The licensee promptly opened the breaker, applied
the required tagging clearance and notified the NRC via the ENS. - The licensee initiated an
RE/EIF to track determination of the event root causes and implementation of corrective
actions. The licensee will also submit an LER documenting the results of their investigation.
The logic cables for the two ESW pump bay sluice gate motor operators run through a common
fire area. In the event of an Appendix R fire, these cables may be affected in such a way that
the gates would close spuriously, isolating the ESW pump suction sources and rendering ESW
unavailable. During implementation of their Appendix R analysis, the licensee committed to
administratively control these components by opening the gates and breakers, and applying an
administrative clearance to preclude re-closing the breakers. Since opening the breaker de-
energizes the control circuit, the position indication in the control room does not function. As
part of the administrative clearance described above, the licensee would apply an information
tag on the control switches explaining the situation. Contrary to assumptions made in the
Appendix R analysis, the breaker supplying one of the sluice gate motor operators was closed,
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however, the sluice gate was open and ESW was capable of performing its safety function-
! during design basis events. Assessment of the significance of this apparent noncompliance with
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the Appendix R analysis will require additional licensee and NRC review.
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2.2.2 Inspector Follow-up
To assess the cause of the event, the inspector reviewed the clearances applied to the 'A' ESW
system in the past year. The licensee removed administrative clearance 92000872 on October
7,1992, during the Unit 2 refueling outage. This was done to perform required TS surveillance
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on the 'A' ESW system. Maintenance clearance 92005183 was applied to support the surveil-
lance. The licensee planned to immediately follow completion of that activity by applying a
second maintenance clearance, 92006814. Clearance 92006814 directed the operators to re-
apply the administrative clearance when work was complete. Due to a change in job schedul-
ing, the second maintenance job and cicarance were delayed into November. When the first
clearance, 92005183, was released on October 12 and the ESW system returned to service, the
administrative clearance was not applied. Also, the MO-2213 breaker was specified on the
restoration line-up to be in the " closed" position instead of the "open" position.
Tbc licensee applied the second maintenance clearance, 92006814, on November 19 and
released it on November 20. During the restoration, the administrative clearance was not
applied even though a special instruction on the maintenance clearance existed. The restoration
j steps again directed that the MO-2213 breaker be placed in the " closed" position. The error in
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the breaker position and the failure to apply tne administrative clearance were not discovered -
until December 23,1992.
The inspector interviewed several licensed operators to assess other indications or controls
available to draw attention to the breaker mis-position and lack of an administrative clearance
on MO-2213. The operators perform shiftly control room panel walk-downs to ensure the
alignment of certain systems. As an operator aid, red and green dots are affixed to the panels
near the indications to reflect the normal alignment. These aids are used by the operators in
performing their panel walk-downs. In the case of MO-2213, a red dot was affhed and the red
light was lit because the breaker was closed. The operators stated that they were aware there
are Appendix R concerns associated with the MO-2213, however, there are no logs or operator
aids that would cause them to question the missing administrative clearance.
Near the end of the report period the inspector discussed the preliininary results of the licen-
see's investigation with responsible personnel. The licensee had identified all applicable
clearances, the deficiency in tracking and application of the administrative clearance and the
weakness in the operator aid applied to the control room panel. The inspector observed several
additional event causal factors warranting corrective action as discussed below.
The inspector reviewed the licensee's " Clearance and Tagging Manual" and discussed the
process for tracking administrative clearances with the licensee. Presently some equipment
requiring special treatment, such as the ESW sluice gate motor operators, are tracked only by
instructions on clearances. Other equipment which requires special positions to maintain
compliance with the Appendix R analysis are controlled with a sign-off step in the General
Procedure (GP) for plant start-up. For example, opening and taggmg of the inboard and
outboard shutdown cooling isolation valve breakers is a specific step in the start-up procedure.
The licensee's treatment of these similar component requirements is inconsistent.
The inspector reviewed check-off list (COL) 33.1. A-2, " Emergency Service Water System (Unit
2 and Cs mmon)," to try to determine the reason why the Chief Operator specified the MO 2213
breaker to be restored in the " closed" position on both maintenance clearances. The COL
33.1. A-2 specified position for the breaker was " Locked Off." A footnote was included
indicating that this position was based on a letter justifying continued operation dated November
28, 1986, addressing Appendix' R nonconformances. The inspector discussed with a chief
Operator how the restoration _ positions for released breakers were determined. The operator
referred to COL 56E.1.A, "480 Volt Emergency Motor Control Center (EMCC) System,
Common Plant " The MO-2213 breaker target position on COL 56E.1.A was " Closed." It -
appears that the operator used COL 56E,l.A in identifying the restoration position. The
inspector brought this COL disagreement to the licensce's attention.
The inspector reviewed COL 33.1.A-2 and COL 56E.1.A performed in support of the Unit 2
-start-up conducted on December 5. The inspector noted that COL 56E.1. A, which aligned the
breaker in the " closed" position, was performed and independently verified on November 30,
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1992. COL 33.1.A-2, which places the breaker in the " locked off" position, was' also per-
formed on November 30, and was independently verified on December 4,1992. As previously
stated, the breaker was later found to be closed.
Unit 3 scrammed on October 15,1992, and remained shutdown until November 8,1992. Since
ESW is a common system shared between both units, the inspector reviewed the GP procedure
for the start-up on November 8. The ESW system was signed and accepted in the GP as being
properly aligned as per COL 33.1. A-3, " Emergency Service Water System (Unit 3 and Com-
mon)." The inspector noted that this COL also directs the MO-2213 breaker to be " locked off,"
however, the COL was last performed and independently verified in December 1991. - The
licensee explained that the Unit 3 ESW system was not affected during the Unit 2 outage and
the COL was the most up-to-date available. However, the licensee did not consider that the
pumps and sluice gate motor operators are common to both units and were worked on in
October during the Unit 2 outage. It appeared to the inspector that the licensee did not maintain
the proper coordination between Unit 3 start-up procedures, COLs and this common equipment.
At the time of the inspector's questioning, the licensee had not identified the conflict in the
positions specified in the COLs for the breakers, the inconsistency in treatment of Appendix R
related equipment restrictions or the potential weakness in maidenance of current COLS for
equipment common to both units. It appeared to the inspector that the licensee had overlooked
these issues in their follow-up. However, since the licensee's associated documentation and
management review were not yet complete, the inspector could not draw a final concicion
regarding the adequacy of the licensee's follow-up. The licensee agreed to incorporate the
inspector's observations into the event investigation and LER.
2.2.3 Conclusion
The mis-position of the breaker did not impact the ability of.ESW to perform its design
function. However, it did place the plant in a configuration other than that assumed in the
Appendix R analysis. The following issues require additional review ana resolution: 1) the
significance of the noncompliance with the Appendix R analysis; 2) the licensee's approach to
tracking of administrative clearances; 3) the conflict between breaker positions specified in the
COLs and the root cause of the discrepancies; and 4) the coordination of COLs for common
systems. At the close of the inspection period the licensee was evaluating these issues.
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During the past several years the licensee, through analysis of data generated by their internal ,
event reporting system, has recognized a generic problem with the number of component mis-
positioning events at Peach Bottom. Licensee management has initiated a number of corrective
actions to address this issue, including personnel training, and a self-checking program. It is .
clear that licensee management is aware of the problem and taking action. 'However, the
inspector informed the licensee that this item would remain unresolved pending completion of
the licensee's investigatior, of the specific items discussed above, and additional inspector
review of the licensee's broader corrective actions addressing the general problem of component
mis-position events (50-277/50-278 URI 92-32-01).
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2.3 Slow Unit 2 High Pressure Coolant Injection System Response Time -
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On January 1,1993, the licensee informed the NRC, via the ENS, that the Unit 2 high pressure
coolant injection (HPCI) system had been declared inoperable. While implementing a planned
plant shutdown for maintenance, the licensee performed Surveillance Test (ST) 6.5R-2, "HPCI
Response Time Test." One of the test acceptance criteria is that the system attain rated flow
and pressure within 30 seconds following a cold start. During the January 1 test HPCI took
30.2 seconds to attain the required Ow, prompting the licensee to declare the system inopera-
ble.
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The TS require periodic testing of the HPCI system. During these routine tests the system is
prepared for operation, manually started, and flow and pressure are increased to the required
test point. General Electric Service Information Letter.(SIL) 136, " Surveillance Testing
Recommendations for HPCI and RCIC Systems," recommended that licensecs perform an
additional periodic HPCI test to monitor the system ability to automaticdly start from a cold
condition. By ensuring that HPCI is idle for at least 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> before the test, and then perform-
ing a quick start, the thermal and hydraulic response of the system can be evaluated. During -
the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> pre-test hold the turbine and steam inlet piping cool, and the hydraulic and lubricat-
ing oil system will partially drain into the sump. The delay resulting from re-filling.the oil
system in particular, can cause extended start-up times. In response to SIL 336 the licensee
developed and implemented ST 6.5R-2.
Following the planned plant shutdown, the licensee performed extensive troubleshooting and
testing of the HPCI oil system, the turbine governor and the stop valve ramp generator. The -
licensee identified that a check valve located between the oil system duplex filter and the turbine
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stop valve was not seating properly, allowing additional oil draining. The licensee repaired the
valve, and also adjusted the ramp generator that controls turbine stop valve oper,ing during
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system start-up. The ramp generator aJjustment will result in opening the valve more quickly,
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and faster system response. The technica't staff presented the results of their testing and repair
activities, and the plans .for system testing during start-up, to the Plant Operations Review
Committee (PORC) before plant restart,
o During power ascension the licensee performed a HPCI system flow test at 150 psig and a-
second test at 1000 psig reactor pressure as required by TS. As of the end of the report period,
ST 6.5R-2 had not been re-performed, but was planned to be' e 'pleted. The inspector will
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i continue to follow-up the results of this ST during the ncat wport period. ~ The inspector
concluded that the licensee technical staff had been thorough in their approach to investigating
l the HPCI response time problem, had involveJ the appropriate' management and the PORC in
--its resobtion,- and had conducted the testing needed to verify the effectiveness of their correc-
tive actions.
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3.0 ENGINEERING AND TECHNICAL SUPPORT ACTIVITIES (37700) .
The inspectors routinely monitor and assess licensee support staff activities. During this
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inspection period, the inspectors focused on problems encountered during the power ascension
testing for two system modifications incorporated during the Unit 2 refueling l outage. The
results of these reviews are discussed in detat' below.
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3.1 Digital Feedwater Control Systetu Modification
During the recent Unit 2 refueling catage, the licensee replaced the existing analog feedwater
control system with a digital feedwater control system (DFCS). The principal objectives of the D
replacement were to solve hardware obsolescence , 'blems, improve reliability and maintain-
ability through fault tolerance, and improve vessel level control following reactor scrams using
a setpo:nt setdown feature. The licensee developed and implemented Modification (MOD)
1843, " Replacement Feedwater Control System." The licensee implemented this modification ,
for Unit 3 during the eighth refueling outage in the fall of 1991. During previous aspections
the inspectors reviewed the modification package, its implementation on Units 2 and 3, and the
Unit 3 modification acceptance test (MAT). The inspectors witnessed portions of the Unit 2
acceptance test during the current inspection period.
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On December 17, 1992, during conduct of Unit 2 MAT 1843Q, " Digital Feedwater Control
System Fault Tolerance Test," a lock-up of the '2B' reactor feed pump (RFP) occurred. The
licensee performed troubleshooting and found that the RFP lock-up was the result of a design
deficiency in the surge protection for the 10-50 milliamp (ma) DC circuitry in the motor control
unit (MCU). As the control signal from the MCU to the RFP motor gear unit (MGU) was-
increased, the circuit high side voltage increased to a value greater than the activation voltage
of the under-sized surge protection circuit. The surge protection activated, causing a mis-match
between the RFP MGU comrol signal calculated by the computer and the actual control signal,
and resulting in the RFP lock-up. The licensee determined that this condition only occurred as
the_RFP MGU approached its high speed stop, at a manual / auto (M/A) station output of about :
97%.
The licensee initiated Action Request (AR) A0683181 and Nonconformance Report (NCR) 92-
01022 which _ documented the condition. As an interim disposition for Unit 2, the licensee
implemented changes to the DFCS software to limit the M/A stat. ion output to less than 95%,
below the point at which a lock-up would occur. The final disposition was to reduce the size -
of the feedback dropping resistor in the 10-50 maDC circuitry, reducing the high side voltage
to below the lowest activation voltage of the surge protection circuit. On Jar.uary 8,1993,
during the' Unit 2 shutdown, the licensee replaced the resistors for eaca RFP, implemented
DFCS software changes in support of the change in resistor size, restored the M/A station
output limit to 100%, and performed a post-maintenance test which demonstrated that the RFPs
did not lock-up when the output of the M/A station was taken to 100%.
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The licensee found that this design deficiency was also present on Unit 3. However, a RFP'
lock-up had not been experienced because the Unit 3 RFP MCU panels were not properly -
grounded by the vendor. This rendered the surge protection ineffective. The licensee docu-
mented and evaluated the condition in NCR 92-01022, and determined that the impact of the '
condition was minimal, and continual operation was acceptable. The licensee's final disposition
of the deficiency will be to install the missing ground in the MCU panels and to replace the
resisters for each RFP. The licensee plans to implement the final disposition during the next
Unit 3 maintenance outage.
The inspector reviewed the DFCS vendor manual, the applicable DFCS drawings, the NCR, AR
and applicable work orders and discussed them with licensee personnel. The inspector found
the licensee's actions to be appropriate.
3.2 Turbine Control Valve Oscillations
On December 17, 1992, during power ascension testing Unit 2 experienced turoine control
valve (TCV) oscillations. Unit 2 was operating about 89.5% power when the oscillations
occuned. The operations staff promptly took corrective action to reduce reactor power _and
stabilized the plant at 76.5% power. The engineering staff performed troubleshooting on the
EHC system circuitry and determined that the oscillations only occurred at power levels above -
.
80 %. Steam leaks were identified in the area of the pressure transmitters that provide the
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primary input to the EHC control logic, but the magnitude of the leaks and their effect on the
system were not known. After further investigation, the licensee determined that the plant was
stable at powers less than 80%, and that it could continue to operate at 78% power until it was
shutdown for a planned maintenance outage in January.
During the recently completed refueling outage the licensee implemented a modification to
install new Rosemount transmitters to replace the_ obsolete main steam line (MSL) pressure
transducers in the EHC system. They replaced the Shaveits Linear- Variable Differet.tial
L Transformer (LVDT) type transducers. The LVDT transducers produced a 0 to 5 volt dinct
j current (vde) input signal as a function of the displacement of an iron / bellows assembly. The
L twc instruments required a matching calibration, which was difficult to achieve. The LVDT -
L transducers were highly affected by environmental conditions, which has caused setpoint drifting
_
. problems and internal component damage. Signal drift can not be _ tolerated during pressure
control by EHC because a slight variation between the transducer output values can cause a
reactor scram.
l The EHC modification was designed by General Electric Corporation and incorporated -the-
L Rosemount Model 1151GP Smart Pressure Transmitter. This model provides the technician the
ability to interrogate, configure, test, or digitally trim the transmitter from any' wiring termina-
tion point in the circuitry. The design intent was that these new transmitters maintain the
original performance characteristics of the devices replaced. The transmitters operate over a-
nominal range of 0 to 1000 psig input with a 4 to 20 milliamp DC output. Signal conditioning _
cards which have an I/E converter were added to process the current input to the proper 0 to 5
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vde output. Thn modification-used the existing power supplies from the EHC system. A
modification acceptance test was performed satisfactorily. The test verified, under static
conditions, that the Rosemount and associated 1/E converter provided the necessary 0 to 5 vde
signal to the EHC logic based upon input pressures of 0 (4 made) to 1050 (20 made) psig.
The licensee's troubleshooting revealed that a number of factors contributed to the TCV
oscillations. They found that 1) the I/E converter card was very sensitive to changes in voltage,
and its power sunply evidenced less than adequate voltage regulation; 2) the response of the
Rosemount Smt.rt Transmitters included a time delay in their initial response that was not
properly considered during the design; 3) steam leaks existed on valves located on the main
steam averaging header that may have influenced transmitter response; and 4) a number of
ground connections from circuit cards in the EHC cabinet were not properly made.
To correct these problems the licensee 1) modified the I/E converter card power supply to ;
'
ensure proper voltage regulation; 2) replaced the Rosemount Smart Transmitters with Rose-
mount Model 1152GD9E transmitters that do not exhibit the time delay feature; 3) repaired all
steam leaks on the averaging header and 4) repaired the various EHC cabinet ground connec-
tions.
,
The inspector discussed the event, the evaluation process, and corrective actions taken with the
licensee's representatives. The technical and I&C staffs were very knowledgeable. The
inspector concluded that the licensee was cautious in their approach during troubleshooting and
that the licensee used available resources by contacting the vendor and other utilities that were
familiar with this modification in supporting their troubleshooting activities. The performance
of the operations and technical staffin the control roo.m during the original event, and dunng
troubleshooting was excellent.
4.0 SURVEILLANCE TESTING OBSERVATIONS (61726, 71707)
The inspectors observed conduct of ST to verify that approved procedures were being used, test
instrumentation was calibrated, qualified personnel were performing the tests, and test accep-
' tance criteria were met. The inspectors verified that the STs had been properly scheduled and
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approved by shift supervision prior to performance, control room operators _were knowledgeable
about testing in progress, and redundant systems or components were available for service as
,
required. The inspectors routinely verified adequate performance of daily STs including instru-
l ment channel checks and jet pump and control _ rod operability. The inspectors found the
licensee's activities to be acceptable, except as noted below.
During the period, the inspectors evaluated the licensee's approach to assessing safety system
operability during performance of preventive maintenance and surveillance testing. The
inspectors found that the licensee generally considers components and systems _to be operable
during surveillance testing, regardless of the impact of the test on the ability of the components
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and systems to perform their required safety functions. In addition, the inspectors identified a
related example of.a system not being declared inoperable during performance of a preventive
maintenance task that impacted its ability to perform its safety function.
On December 30, 1992, the inspector observed performance of a Unit 3 HPCI logic system
functional test. The test is performed once every six months and hsts about one shift. It
includes placing the HPCI amiliary oil pump in pull to-lock, and installing jumpers and test
switches. During the test the HPCI system is rendered incapable of automatically starting and
4
providing core cooling. While the staff could take action to restore the system if it is needed,
these actions could not be completed quickly enough to ensure HPCI availability approaching
that assumed in the accident analysis. The licensee did not declare the HPCI system inoperable
during the testing, and did not enter the TS LCO, consistent with the general approach previ-
ously described.
On December 22,1992, the inspectors observed performance of motor operator valve (hiOV)
diagnostic testing on Unit 3 residual heat removal (RHR) pump shutdown cooling suction valve
'
hf 0-10-15B. In order to perform the test the licensee closed RHR pump torus suction valve
- hlO-10-13B, and opened the associated breaker. The duration of this testing was about one
,
hour. The RHR torus suction valve is normally open, and has no automatic open signal. With '
1
the torus suction valve closed the 'B' low pressure coolant injection (LPCI) loop would not
i automatically initiate in response to a valid signal. The operating and mamtenance staff could
take action to return the shutdown cooling suction valve to service and open the torus suction
'
valve. However, the time required to take these actions is inconsistent with the LPCI response
L time described in the Updated Final Safety Analysis Report (UFSAR). The estimated time for
4 reopening the hiO-10-13B is about 120 seconds, while the UFSAR states that LPCI attains rated -
flow in 30 seconds. The licensee had not declared the affected pump inoperable, and did not
enter the applicable TS LCO.
4
In both of these examples the redundant trains or safety systems were operable during the tests,
'
so that the overall safety functions were not significantly impaired. The HPCI test procedure
- required verification that the other emergency core cooling systems and the reactor core
' isolation cooling system were operable before beginning the test. Operators reviewed RHR
- . system status before releasing the hlOV diagnostic test for work to ensure that no other RHR
- components were inoperable. The inspector verified that no LCO was exceeded. The lic-
ensee's approach to treatment of testing did not appear to be consistent with current NRC
positions.
t
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The TS state that a system is operable when it is capable of performing its specified function.
'
NRC's Generic Letter (GL) 91-18, "Information to Licensee's Regarding Two NRC Inspection
hianual Sections on Resolution of Degraded and Nonconforming Conditions and on Operabili-
ty," provides clarification on applying the operability definition to performance of preventive
j- maintenance and surveillance tests. - Section 6.4 of GL 91-18 states that if preventive mainte-
j nance or TS surveillance requires that safety equipment be removed from service and rendered
incapable of performing its safety function, the equipment is inoperable. Section 6.7 of GL
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91-18 indicates that application of compensatory measures, such as manual action in place of
automatic action, may be acceptable in some cases. However, in those cases the licensee must
evaluate all applicable factors, such as physical differences, recognition of input signals, time -
required for action, etc. Reliance on these compensatory measures must be preceded by
implementation of appropriate procedures and training. The NRC position described in GL 91-
18 was further discussed in an April 10,1992, memorandum from the NRC Technical Specifi-
cations Branch entitled Operability Requirements During Testing and Requirements for
Alternate Train Testing." That memorandum was placed in the Public Document Room on May-
12, 1992.
The inspector concluded that the licensee's approach to treatment of safety system operability
during testing in general, and in the two specific examples discussed, was inconsistent with the
NRC positions described above, it appeared to the inspector that preventive maintenance and
surveillance testing could be generally classified into three categories; 1) tests that do not impact -
operability because of the nature of the test, or due to design features that automatically realign -
. the system; 2) tests that render the system incapable of performing its function, and therefore
inoperable; and 3) tests that affect the system's ability to function in a manner such that
compensatory actions are evaluated, prescribed and implemented so that operability will be
maintained. In the past the licensee has not taken this approach to evaluating the impact of
'
individual STs. The licensee recently eliminated most of the alternate train testing requirements
from the TS. Before these amendments were issued declaring systems inoperable during testing
may have been impractical.
The inspector discussed this issue with licensee management. After reviewing the examples
cited, the licensee concluded that under their existing guidance the operators should have
declared the 'B' LPCI inoperable during the test. The licensee also agreed that the current
approach to evaluating operability during testing should be revised. As immediate corrective
action the Operations Superintendent initiated an RE/EIF to track follow-up, discussed the
problem with all Shift Managers, and began discussion of operability during testing in the
operator requalification program. As interim action the licensee developed a required reading
package on the topic, and issued Night Orders discussing the proper approach to review of
testing activities such as MOV diagnostics and directing that systems be declared inoperable
during logic system functional tests. The inspectors reviewed these materials and concluded that -
they appropriately addressed the issue. The licensee also committed to complete the following
actions within six months: 1) review and revise appropriate STs_to idectify those that render _
systems inoperable and to reorganize tests that require compensatory measures to maintain -
system operability; 2) review and revise the Operations Management Manual, Section.16, to ,
'
clarify guidance in this area; and 3) review and revise the ST Writer's Guide to ensure incorpo-
ration of proper guidance into future STs. The inspector concluded that the corrective actions
taken or planned by the licensee reflected a safety oriented approach to resolving the issue and
would address the apparent conflict. This item will remain unresolved pending completion of
the licensee's corrective actions, the licensee's response to GL 91-18, and additional inspector- ,
!
review (50-277/50-278 URI 92-32-02).
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5,0 MAINTENANCE ACTIVITY OBSERVATIONS (62703)
The inspectors observed portions of ongoing maintenance work to verify proper implementation ,
of maintenance procedures and controls. The inspectors veriRed proper iraplementation of
admimstrative controls including blocidng. permits, fire watches, and ignition source and
radiological controls. The inspectors reviewed maintenance procedures, action requests, work
orders, item handling reports, radiation work permits (RWP), material certifications, and receipt -
inspections. During observation of maintenance work, the inspectors verified appropriate
QA/QC involvement, plant conditions, TS LCOs, equipment alignment and turnover, post-
maintenance testing and reportability review. The inspectors found the licensee's activities to
be acceptable.
5.1 Unit 2 '2B' Recirculation Pump Seal Repair
,
On December 7,1992, during the Unit 2 plant start-up, the first stage (inner) seal for the '2B'
Recirculation Pump indicated that it had failed. Unit 2 was at 450 psig reactor pressure with
2 bypass valves open, when the recirculatior, pump's second stage (outer) seal high/ low flow
annunciator alarmed. The System Manager (SM) locally verified at the cable spreading room
that a high flow condition existed. The centrol room indication for the inner seal indicated 500
psig and the outer seal indicated 455 psig. The outer seal normally indicates about half the
inner seal pressure. The licensee contacted the pump manufacturer; Byron-Jackson, to discuss
operation of the pump on one seal at' elevated pressures. The licen ze determined that the unit
could continue to operate on the outer pump seal until a planned January maintenance outage. ;
'
No further degradation of the pump seal occurred before the outa.;e.
Following the planned plant shutdown, the licensee replaced the '2B' Recirculation pump seal
cartridge. During the inspection of the seal cartridge,-the licensee found that the U-cup in the
inner seal area had extruded out between the rotating face assembly and the lower spring coil
assembly. The U-cup provides the seal between the rotating portion of the inner seal and the -
shaft sleeve. With the U-cup extruded in this fashion, a gap was created vehich increased-
leakage flow up the shaft sleeve to the outer seal.
This type of seal problem has occurred several times in the past. Tlie licemee believed that the
problem _was caused by misoperation of the seal purge system when the plant operator placed
_ _
it in service, The vendor representative, however, explained that the seal failure was caused by
'
the removal of the seal purge system. When purge flow is removed from the seals, it should
be accomplished gradually to allow the inner and outer seal pressures to equalize. When purge
,
flow is abruptly removed while the reactor is depressurized, the coil _ spring assembly is forced
L down the shaft to relieve the inner seal pressure. This opens the gap between the iotating face
assembly and the spring coil assembly. The outer seal is still at it's original pressure which will
draw the U-cup into the gap. Once the pressures are equalized the U-cup is caught between the
l two assemblies. When the plant is restarted, increasing pressures would force the spring coil
l
assembly upward preventing the inner seal from correcting itself.
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The licensee reviewed System-Operating (SO) Procedures SO3.2.A-2, " Control Rod Drive
Hydraulic System Shutdown," and SO 2A.I.C-2, " Operation of the Recirculation Pump Seal
Purge System." Both sos direct the operator to shut the motor operated valve when securing _
seal purge, causing abrupt removal of flow. The licensee has taken action to correct these two
'
procedures.
The inspector observed portions of the maintenance activities, discussed the issue with licensee
personnel, and concluded that the seal replacement activity was well planned and managed.
Pre-inaintenance briefs involving Ms:tenance and Health Physics personnel were conducted
explaining the scope and detail of the activity. Housekeeping in the vicinity of the '2B' recircu-
lation pump was very good. Perscas performing the inspection received a low radiation dose
during the drywell work, and did not have to wear respirators except when the primary bound-
ary was breached.
5.2 Main Steam Isolation Valve Air Manifold Repair
On January 3,1993, the licensee completed a planned Unit 2 shutdown for maintenance. After
breaking condenser vacuum and opening the reactor head vents, the operators performed the -
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quarterly main steam isolation valve (MSIV) stroke time test. The acceptance criteria for the '
MSIV closing stroke is three to five seconds. The expected MSIV opening stroke time is eight
to twelve seconds. During the test inboard MSIV 80A 'never indicated full closed, maintaining
-
split indication, and took nearly 20 minutes to re-open fully. Also, inboard MSIV 80C closed
in about 47 minutes, and took 4 minutes 25 seconds to re-open. Outboard MSIV 86A closed
in 5.23 seconds, exceeding the acceptance criteria slightly. The remaining five MSIVs per-
formed acceptably. These valves were retested about five hours later, under similar conditions,
,
and they closed and opened within the allowable range.
There are four main steam lines, each isolated by one i_nboard and one outboard MSIV. The -
MSIVs are angle globe valves manufactured by Atwood & Morrill Company. The instrument
nitrogen system provides the opening motive force, and integral springs supplemented by the
same nitrogen system are used to close the valve. The nitrogen supply for opening and closing
the valve is controlled by~ three solenoid operated valves (SOV), a four-way pilot operated-
valve, and a three-way pilot operated valve. The combined action of the SOVs and pilot valves
ports nitrogen to or from the underside or top of the main valve actuator piston. The SOVs and
pilot operated valves are manufactured by the Automatic Valve Company (AVC). The MSIV
'
_
closing speed is adjusted through use of an oil dashpot and needle valve.
During the recently completed Unit 2 refueling outage the Ucensee performed extensive mainte-
nance on the inboard MSIVs. They replaced the MSIV internals with an improved design,
replaced the oil in the dashpot, inspected and tested the dashpot and air actuator, and replaced
the SOVs and pilot operated valves. The replacement SOVs and pilot valves were procured
from AVC already assembled, and installed by the licensee. The valves were stroke tested
several times, the timing was set and local leak rate testing was completed before plant restart.
The plant had operated at power for about one month before the failure.
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The licensee performed a minor adjustment to the stroke time of MSIV 86A. Although its
closure time had exceeded the five second maximum, the deviation was minor and was within
a band explainable given drift. The licensee's technical and maintenance staffs began trouble-
shooting, testing and inspection of MSIVs 80A and 80C to determine the cause of the excessive-
ly slow valve operation. The licensee operated the valves several times under visual observa-
tion and verined that the valves stroked smoothly. They inspected the valve stem, closing
springs and spring guide rods for indications of binding or damage, but no adverse conditions
were identified. The maintenance staff removed, disassembled and inspected the SOVs, four-
way pilot operated valve and three-way pilot operated valve from both MSIVs. No signs of
damage or excessive wear were identified. All 'O' rings and seals were of the correct material
and in good condition. No indication of improper or excessive lubrication was identified. The
pilot valves and SOVs were rebuilt and re-installed. The licensee blew-down the instrument
nitrogen system at the two problem MS!Vs. No significant foreign material was identified.
The licensee also contacted AVC to discuss the performance observed, and to obtain informa-
tion concerning any similar industry experience, however, ne useful insights were gained. The
valves were reassembled, the stroke time adjusted and retested satisfactorily.
In order to ensure continued acceptable performance of these valves the technical staff proposed
a power ascension testing program that included additional stroke time testing at 1) 150 peg;
2) 1000 psig; and 3) 75 % reactor power. They also proposed to reduce power to 75 % and
perform stroke time testing 1) two weeks following the test at 75 % power; 2) again four weeks
later; 3) and again eight weeks later. If all tests are satisfactory the licensee plans to return to
a quarterly test frequency. The results of the licensee's investigation and the proposed test plan
were presented to and approved by the Plant Operations Review Committee before plant restart.
The inspector reviewed the maintenance and modification histories of the affected MSIVs,
maintenance- procedures used, applicable vendor manuals and technical information, and
-industry experience relevant to Atwood & Morrill MSIVs and AVC pilot operated valves. The
inspector observed the disassemble and inspection of the SOVs and pilot operated valves, and -
the results of the instrument nitrogen system testing. The inspector also observed portions of -
the MSIV stroke time testing performed before restart and during power ascension._Before plant-
start-up the inspector confirmed that the licensee was committed to implementation of the testing
. plan outlined above. In addition, a conference call involving representatives from the NRC
Office for Analysis and Evaluation of Operational Data, Nuclear Reactor Regulation and Region -
I was held to review the licensee's investigation results. The inspector concluded that the
licensee had taken reasonable action to evaluate the cause of the slow MSIV closure times, and
to implement an augmented testing program to ensure acceptable performance.
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6.0 RADIOLOGICAL CONTROLS (71707)
The inspectors examined work in progress in both units to verify proper implementation of
health physics (HF) procedures and controls. The inspectors monitored ALARA implemen-
tation, dosimetry and badging, protective clothing use, radiation surveys, radiation preRction
instrument use, and handling of potentially contaminated equipment and materials. In addition,
the inspectors veri 6ed compliance 'vith RWP requirements. The inspectors reviewed RWP line
entries and verified that personnel had provided the required information. The inspectors
observed personnel working in the RWP areas to be meeting the applicable requimments and
individuals frisking in accordance with HP procedures. During routine tours of the units, the
inspectors verified a sampling of high radiation area doors to be locked as required. All
activities monitored by the inspectors were found to be acceptable.
The inspectors accompanied members of the HP staff during the semi-annual inspection of >
Unit 1. Unit 1 is a High Temperature Gas-Cooled Reactor that was shutdown in 1974. Itis
currently in a safe storage (SAFSTOR) condition and will remain SAFSTOR until it is decom-
missioned with Units 2 and 3. The HP Technicians performed ST-H-099-960-2, " Unit One
Exclusion Area Semi-Annual Inspection." This procedure inspects the Unit 1 exclusion area
security barriers, performs a radiological survey of surface contamination and air particulate
activity, and replaces the high efficiency particulate filter on the containment breather. /dl
areas were found to have dose levels less than 2 millirem per hour and no loose or airborne
contamination were detected. The hower areas and sumps were dry, but traces of water
inseepage were detected. The inspectors were informed that small amounts of inseepage does
occur after a heavy rain, however, no radiological problems have resulted because of it. The
inspectors noted that the inspection was well organized and the procedure executed well. The
licensee includes the results of this ST in the PBAPS Unit 2 and 3 NRC Annual Report which
is in accordance with TS Appendix A, Section 2.3 (b).
7.0 PHYSICAL SECURITY (71707)
The inspectors monitored security activities for compliance with the accepted Secunty Plan and
associated implementing procedures. The inspectors observed security staf6ng, operation of the
Central and Secondary Access Systems, and licensee checks of vehicles, detection and assess-
ment aids, and vital area access to verify proper control. On each shift, the inspectors observed
protected area access control and badging procedures. In addition, the inspectors routinely
inspected protected and vital area barriers, compensatory measures, and escort procedures. The
inspectors found the licensee's activities to be acceptable.
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8.0 MANAGEMENT MEETINGS (71707,30702)
The Resident inspectors provided a verbal summary of preliminary findings to the Peach Bottom
Station Plant Manager at the conclusion of the inspection. During the inspection, the Resident
inspectors verbally notified licensee management concerning preliminary findings. The inspec-
tors did not provide any written inspection material to the licensee during the inspection. This
report does not contain proprietary information. _l
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