IR 05000277/1998001
| ML20217P745 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 05/01/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20217P725 | List: |
| References | |
| 50-277-98-01, 50-277-98-1, 50-278-98-01, 50-278-98-1, NUDOCS 9805070051 | |
| Download: ML20217P745 (45) | |
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U. S. NUCLEAR REGULATORY COMMISSION
REGION I
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Docket Nos.
50-277,50-278 License Nos.
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Report Nos.
98-01 l
Licensee:
PECO Energy Company Facility:
Peach Bottom Atomic Power Station Units 2 and 3 Dates:
January 18,1998 to March 14,1998 Inspectors:
A. McMurtray, Senior Rosident inspector M. Buckley, Resident Inspector B. Welling, Resident inspector K. Young, Reactor Engineer L. Cheung, Senior Reactor Engineer K. Mortensen, NRR Digital Instrumentation & Control Engineer L. Peluso, Radiation Specialist J. Williams, NRR Project Manager I'
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EXECUTIVE SUMMARY
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Peach Bottom Atomic Power Station '
NRC Inspection Report 50-277/98-01,50-278/98-01 This integrated inspection report includes aspects of licensee operations; surveillance and
_ maintenance; engineering and technical support; and plant support areas.
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Piant Operations:
e-The practice of the control room supervisor leaving the main control room work station for brief periods without temporary relief from another senior reactor operator demonstrated weak oversight of control room activities.
On January 28,1998, the control room supervisor left the main control room work station without temporary' relief for several minutes and failed to verify-acknowledgment of an expected alarm. This resulted in an NRC identified violation of technical specification 5.4.1 requirements for procedures due to the control room supervisor failing to verify alarm acknowledgment as required by the Operations Manuals. (Section 01.3) -
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The recirculation loops were not operated outside of the TS SR 3.4.1.1 and 3.4.1.2 I
requirements when the unit 2 reactor operator failed to perform ST-O-02F-560-2on January 2,1998. However, the TS requirements for SRs 3.4.1.1 and 3.4.1.2 were not met on January 2 since ST-O-02F-560-2 was not performed and Unit 2 was in Mode 2 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This licensee identified issue resulted in violations of requirements for SRs 3.4.1.1 and 3.4.1.2. (Section 03.1)
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Several examples of weak control room oversight of activities were noted from the I
Unit 2 main turbine trip during start-up on January 1,1998. These examples were as follows: 1) The Control Room Supervisor directed the pulling of control rods to increase reactor coolant system pressure while the turbine condition remained
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unknown. 2) Shift turnover and the shift meeting occurred while the turbine was in this unknown condition even though members of the crew knew that the turbine
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_ had come off of the turning gear. 3) The crew with the watch during most of this event had not received any just-in -time training such as simulator runs even though this was the first reactor start-up for the Plant Reactor Operator and the Control Room Supervisor.
Several examples of a violation of TS 5.4.1, " Procedures" occurred when the Unit 2 main turbine tripped during start up on January 1,1998. This violation occurred i
due to the following: 1) Inadequate instrument and Control and Operations procedures that failed to restore the Electro-Hydraulic Control system to the alignment required for start-up. 2) The failure of Operations personnel to refer to the main turbine start-up procedure when directed by the plant start-up procedure.
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. Executive Summary (cont'd)-
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. 3) The failure of operations personnel to properly monitor the control room panels or recognize the main turbine status, position of the turbine control valves, or the selection of the speed set for the Electro-Hydraulic Co,itrol system.; The monitoring
- and recognition of equipment status were required by Operation-Manual procedures, OM-C-6.1 and OM-P-3.3. (Section 04.2)
e The Nuclear Review Board provided good independent discussion and evaluations of the topics presented during the February 5,1998 meeting. The questions directed to the presenters by the members of the Board during this meeting were probing and insightful. (Section 07.1),
Maintenance:
o From June 12,1995 through January 21,1997, PECO failed to identify and correct inaccurately calibrated feedwater temperature instruments, resulting in the operation of Unit 3 as high as 0.6% above licensed thermal power level for approximately -
fifteen months. This was considered a violation of tha facility operating license.
Further, PECO did not adequately control the measuring and test equipment used to calibrate the feedwater temperature instruments. Although this issue was identified by the licensee, there were several significant missed opportunities to identify this
' issue sooner. (Section M8.1)
e Incomplete Rod Withdraw Block surveClance testing, from 1989 through January 1996, was a non-compliance with Cudtem Technical Specification 4.2.C, Minimum Test and Calibration Frequency for Control Rod Blocks Actuation. Deficiencies in standby gas treatment system and residual heat removal system surveillance testing of system logic channels were violations of Technical Specifications 3.3.6.2.5, and 3.3.5.1.5, respectively, which required logic system functional tests of these j
systems...These non-repetitive, licensee-identified and corrected violat, ions are being treated as Non-Cited Violations, consistent with Section Vll.B.1 of the NRC Enforcement Policy. -(Section M8.2)
Enaineerina:
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-e Revisions to the end dates for the second 10-year Inservice Inspection (ISI) and inservice Testing (IST) program intervals for Units 2 and 3 were in accordance with Section IWA 24000 of the applicable ASME Code edition, and were therefore in accordance with 10 CFR 50.55a(g)(4). (Section E1.1)
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The replacement of the original Unit 3 source range and intermediate range monitors j
with a digital wide range neutron monitoring system (WRNMS) was implemented appropriately. An acceptable surveillance program to satisfy the technical specification requirements for the new WRNMS and new response procedures for
- the WRNMS alarms were properly established. (Section E2.1)
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e Executive Summary (cont'd)
The licensee was proactive in identifying, scoping, evaluating, and correcting the e
Westinghouse HFA and FA molded case circuit breakers failure to fully latch.
Engineering and other station personnel exhibited a rigorous and systematic approach to the resolving this deficiency. The licensee performed an acceptable operability determination for the breakers. (Section E2.2)
Plant Sunoort The Radiological Environmental Monitoring (REMP) and Meteorological Monitoring i
- (MMP) Programs were effective. The licensee's performance regarding environmental monitoring, meteorological monitoring, and quality assurance audits
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was good.' Equipment for both of these programs was well maintained and properly calibrated. (Sections R1.1, R1.2, and R7.1)
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'4 TABLE OF CONTENTS '
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' EXECUTIVE SUMMARY
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Summary of Plant Status
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l. O peratio n s..................................................... 1
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Conduct of Operations.................................... 1 01.1 General Comments.................................. 1 01.2 ~ Unit 3 Reactor Shutdown for Maintenance Outage 3J12....... 1 01.3 Control Room Supervisor Leaving Work Station Without Relief Resulting in a Failure to Properly Verify Alarm Acknowledgment.. 2
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Operations Procedures and Documentation................'...... 2 03.1' - (Closed) Unresolved item (URI) 50-277/97-08-03: Missed Technical Specification Surveillance Requirement Test for
. Verification of Proper Flow in the Recirculation Loops......... 2 i
Operator Knowledge and Performance......................... 2 04.1 High Pressure Coolant injection Post-Maintenance in-Service Test. 2 04.2 (Closed) URI 50-277/97-08-04: Unexpected Trip of Unit 2 Main Turbine During Start-up
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Quality Assurance in Operations............................. 4 07.1 Nuclear Review Board Meeting..........................4
Miscellaneous Operations issues............................. 4
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08.1 - (Closed) URI 50-277(278)/97-02-01: Station Qualified Reviewer Use/ Review of Open Changes to the Updated Final Safety Analysis Repon......................................... 4
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- ll. Maintenance and Surveillance....................................... 4 M1 Conduct of Maintenance and Surveillance'....................... 4 M 1.1 E4 Emergency Diesel Generator Outage and Refurbished Governor R e plac em e nt..................................... '. 4 M3 Maintenance Procedures and Documentation.................... 5 M3.1 Procedure Usage and Documentation for Refuel Floor Activities-During Refueling Outage 3R11
.........................5 M8 Miscellaneous Maintenance issues............................ 6 M8.1 (Closed) Unresolved item 50-277(278)/97-01-01: Core Thermal Power Greater Than Technical Specification Limit............ 8
- M8.2 Licensee Event Reports (LERs).......................... 8
- Ill. ' Engineering................................................... 9 E1 Conduct of Engineering.................................... 9 E2 Engineering Support of Facilities and Equipment.................. 9
- E2.1 Wide Range Neutron Monitoring System (WRNMS)........... 9
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LE2.2 Scope of WRNMS Upgrade.............................' 9 E2.3 - As-Installed Dir; ital Modification........................ 11 E2.4 Licensee and Vendor Interface
........................13 E2.5 Maintenance, Surveillance and Abnormal Operating Procedures. 14 v
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O Table of Contents (cont'd)
E2.6 Updating of UFSAR, Plant Drawings, and Other Relevant Documentation.................................... 15 E2.7 Modification Training of Operators and Technicians.......... 16 '
E2.8 _ Setpoints and Related Uncertainties..................... 16 E2.9 Handling and Storage of Spare Parts.................... 17 E2.10 Failure of Westinghouse HFA Breakers to Latch............ 18 E2.11 (Closed) URI 50-277(278)/97-05-03 Auxiliary Contact Failures.. 19 E3 Engineering Procedures and Documentation.................... 20 E3.1 Inservice Testing / inservice Inspection Interval Extension...... 20 ES Engineering Staff Training and Qualification
....................21 E8-Miscelleneous Engineering Issues........................... 21 IV. Plant Support
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R1 Radiological Protection and Chomistry (RP&C) Controls............ 22 R1.1 Implementation of the Radiological Environmental Monitoring Prog ra m........................................ 2 2 R1.2 -Implementation of the Meteorological Monitoring Program..... 24 R2 Status of RP&C Facilities and Equipment
......................24 R2.1 High Radiation Locked Door inspection
..................24 R7 Quality Assurance in RP&C Activities......................... 24 i
R7.1 Quality Assurance Audit Program
......................24-R7.2 Quality Assurance of Analytical Measuroments............. 26 R8 Miscellaneous Radiological Protection Issues.................... 27 R8.1 (Closed) URI 50-277(278)/97-01-03:Use of Draft NUREG Reportability Guidance for LERs........................ 27 V. Ma nagem ent Meeting........................................... 2 7 X1 Exit Meeting Summ ary................................... 27 X2 Review of Updated Final Safety Analysis Report (UFSAR) Commitments. 28 LIST O F ACRO NYM S U SED...................... -.................... 31 INSPECTION PROCEDURES USED..................................... 33 ATTACHMENT -
Attachment 1 - List of Acronyms Used
- Inspection Procedures Used-Items Opened, Closed, and Discussed
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b Report Details Summary of Plant Status PECO operated both units safely over the period of this report.
Unit 2 began the period operating at 100% power. On January 30-31, operators reduced power to about 93% to allow for repairs to the 2C circulating pump discharge valve. On February 6, power was reduced to about 90% to investigate trip problems with the 2A reactor feed pump turbine. On February _11, the unit was returned to 100%, where it remained for the rest of the period.
Unit 3 began the period operating at 94% power. The unit was operating at less than full power due to recirculation system flow rate limitations because of weld cracks on the jet pump risers. On February 13, power was increased to 100%, as allowed by the operating strategy for the jet pump riser cracks. On March 6, power was reduced to 94%, and on March 13, the unit was shutdown for outage 3J12, to perform repairs to the jet pump risers. -
1,. Operations
Conduct of Operations 01.1 General Comments (71707)
Throughout the inspection period, the inspectors attended the Daily Leadership Meeting. During this morning meeting, the plant experience assessment group routinely presented industry events that occurred at other nuclear power plants.
~ Senior plant management reviewed and discussed these events to obtain insights into potential problems that the Peach Bottom station could encounter.
The inspectors observed these reviews and noted that insights from these reviews provided information to allow Peach Bottom to avoid similar events and equipment challenges. The inspectors concluded that these reviews were proactive and provided information that allowed the station to continue to improve performance.
01.2 Unit 3 Reactor Shutdown for Maintenance Outaae 3J12 (71707)
The inspectors observed portions of the reactor shutdown evolution in the control room on March 13, and found that operators performed well. Specifically, the inspectors noted that:
Use of procedures (including general plant procedures, system operating
procedures, and alarm response cards) was good.
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1 Topical headings such as 01. MS, etc., are used in accordance with the NRC standardized reactor inspection report outline. Individual reports ers not empacted to address as cuttine topic [:
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Turnover between shift crews was conducted at an appropriate time while
plant conditions were stable. The turnover process was thorough.
Shift supervision placed heavy emphasis on ensuring actions were performed
in a careful, deliberate manner.
Supervisory and management oversight was very good. Shift supervision
appropriately coached operators in a few minor instances, such as when an operator was slow in maintaining the main generator electro-hydraulic control (EHC) load set at the proper setting.
Communications and briefings were good.
- 01.3.Q_ontrol Room Suoervisor Leavina Work Station Without Relief Recultino in a Failure to Properly Verifv Alarm Acknowledoment a.
Insoection Scooe (71707)
On January 28,1998, the inspectors observed that the control room supervisor (CRS) was outside of the designated main control room work station area for several minuter; while the inspectors were in the control room performing routine tours. No other individual had control room oversight during this time. The inspectors questioned operations personnel and reviewed Operations Manual (OM)
procedures and applicable NRC guidance for insights and guidance on oversight of control room activities.
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Observations and FirdiDEA Although several licensed senior reactor operators were available on this shift, the CRS had not obtained any temporary relief when he left the main control room work area. Also, the shift manager was in his office next to the main control room the entire time the inspectors were present, but he was not used for relief while the CRS was away. After the CRS returned to the main control area, the inspectors learned that he had been in the lunch room behind the main control board panels
. eating his lunch.
During the time that the CRS was away, the inspectors observed an expected annunciator alarm come in on the Unit 3 panels. The Unit 3 reactor operator (RO)
acknowledged the alarm, however; the CRS did not verify alarm acknowledgment because he was not in the main control room area.
During the previous inspection period, the inspectors had also observed a CRS leave the main control room work station and go behind the panels to the lunch room or i
rest room without any temporary relief. This occurred during a recirculation pump speed change to increase reactor power.
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l Operations Manual, OM-P-3.2, Revision 9, " Senior Licensed Operators" documented I
that a CRS must be in compliance with one of the following conditions to move to other parts of the control room outside of the main control work station:
Remain in sight of, or in audible range of, the Unit ROs.
- Remain in the audible range of the Control Room annunciators.
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Operations Manual, OM-P-7.1, Revision 0, " Alarms and Indications" documented L
the following actions when an expected alarm actuates:
Expected alarms shall be acknowledged by raising a hand. No further
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communication is required by the RO/ plant reactor operator (PRO) unless the l
CRS has a question concerning the alarm.
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The CRS shall verify alarm acknowledgment visually by looking toward the
l alarming unit. If visual verification is not made (i.e. CRS does not see the j
PRO /RO's hand raise), the CRS should verbally communicate alarm
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j acknowledgment with the RO/ PRO.
The inspectors determined that the intent of OM-P-3.2 for remaining in the audible
range of the ROs or Control Room annunciators was not met when the CRS failed to verify the alarm acknowledgment of the expected alarm. The inspectors also noted that this second example of the CRS being outside of the main Control room work station without any relief showed lapses in the oversight of activities in the control room.
The failure of the CRS to adhere to the requirements of OM-P-7.1 was a violation of technical specification (TS) 5.4.1. Technical specification 5.4.1 requires, in part, i
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that written procedures are implemented covering the applicable procedures
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recommended in Regulatory Guide 1.33, Appendix A, November 1972. (VIO 50-l 277(2781/98-01-01)
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Conclusions l
The practice of the control room supervisor leaving the main control room work station for brief periods without temporary relief from another senior reactor operator demonstrated weak oversight of control room activities.
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On January 28,1998, the control room supervisor left the main control room work station without temporary relief for several minutes and failed to verify l
acknowledoment of an expected alarm. This resulted in an NRC identified violation l.
of technical specification 5.4.1 requirements for procedures due to the control room supervisor f ailing to verify alarm acknowledgment as required by the Operations Manuals.
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j 03-Operations Procedures and Documentation 03.1 (Closed) Unresolved item (URl) 50-277/97-08-03: Missed Technical Soecification l
Surveillance Raauirement Test for Verification of Proper Flow in the Recirculation k99RE i
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Inspection Scope (71707)
i On January 2,1998, the Unit 2 reactor operator failed to perform the TS surveillance requirements (SRs) for verification of proper flow in the recirculation
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loops. The inspectors discussed this issue with operations and operating experience personnel and reviewed the documentation associated with these missed SRs to determine complia.ce with TS requirements. The inspectors also reviewed this issue for reportability per 10 CFR 50.73.
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Observations and Findinas
On January 3, operations personnel discovered that they had missed performing sections of the formal surveillance test that verified that TS SRs 3.4.1.1 and 3.4.1.2 were met. This test, Surveillance Test (ST)-O-02F-560-2, Revision 0,
" Daily Jet Pump Operability," verified that the recirculation loops were operating within TS requirements and that the recirculation system jet pumps were operable.
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Unit 2 was in Mode 2, "Startup," at the time the surveillances were missed.
Surveillance test, ST-O-02F-560-2,was satisfactorily performed on January 3 after the missed SRs were discovered.
i Technical specification SR 3.4.1.1 verified that recirculation loop Jet pump mismatch was within specifications and TS SR 3.4.1.2 verified that core flow as a function of
THERMAL POWER was also within specifications. Both of these SRs were required to be performed in Modes 1 and 2 once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
The Unit 2 RO thought, based on the wording in ST-O-02F-560-2,that TS surveillances 3.4.1.1 and 3.4.1.2 were not required to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after greater than 25% reactor thermal power. The operator discussed the ST requirements with the CRS and the supervisor agreed after reviewing the ST that j
the RO's interpretation of the GT was correct.
This event was documented in PEP 10007762. The " Regulatory Review" section of this PEP noted that the licensee determined that TS SRs 3.4.1.1 and 3.4.1.2 were satisfied on January 2 using alternate methods other than the ST-O-02F-560-2.
These methods included verifying that SR 3.4.1.2 was satisfied through the data in the operator's daily surveillance log and SR 3.4.1.1 was satisfied by the reactor operator's panel walkdowns and routine operator checks, in addition, parameters i
on computer printouts showed that recirculation loop Jet pump mismatch was within specifications of SR 3.4.1.1. Based on these alternate methods, the licensee concluded that this issue was not reportabl l
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The inspectors noted during the review of ST-O-02F-560-2that the ST was unclear and contained conflicting information regarding when each of the TS SRs were required. - The inspectors also determined based on the review of the PEP and all other pertinent information that the recirculation loops were not operated outside of the.TS SR requirements. However, the inspectors learned after discussions with operations personnel that during previous start-ups and shutdowns, ST-O-02F-560-
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2 was used to perform TS SRs 3.4.1.1 and 3.4.1.2 with the reactor in mode 2.
l Also, the inspectors noted that OM-C-9.1, Revision 0, " Procedure Use", required an ST to be performed to meet the requirements of TS SRs.
The inspectors reviewed NUREG-1022, Revision 1, " Event Reporting Guidelines 10 CFR 50.72 and 50.73." The inspectors determined that a Licensee Event Report (LER) per 10 CFR 50.73 was not required for this issue based on the requirements in Section 3.2.2(3). This section documented that an LER was not required if the missed surveillance test (s) were performed satisfactorily before the surveillance interval plus allowed surveillance interval extension plus the Limiting Condition for Operation action statement time expired. The Limiting Condition for Operation.
action statement time for both of these SRs was 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The inspectors noted that the surveillance was performed satisfactorily within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the time beyond the surveillance interval.
The failure to perform ST-O-02F-560-2 on January 2,1998 resulted in violations of TS SRs 3.4.1.1 and 3.4.1.2. _ Technical Specification SRs 3.4.1.1 and 3.4.1.2 require; in part, that the recirculation loop jet pump flow mismatch and the core -
flow as a function of Thermal Power be verified every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when the reactor is in Modes 1 or 2. (VIO 50-277/98-01-02and VIO 50-277/98-01 03)
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Conclusions The inspectors concluded that the recirculation loops were not operated outside of the TS SR 3.4.1.1 and 3.4.1.2 requirements when the unit 2 reactor operator. failed to perform ST-O-02F-560-2 on January 2,'1998. However, the inspectors also concluded that the TS requirements for SRs 3.4.1.1 and 3.4.1.2 were not met on January 2 since ST-O-02F-560-2 was not performed and Unit 2 was in Mode 2 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This licensee identified issue resulted in violations of requirements for SRs 3.4.1.1 and 3.4.1.2._ The inspectors determined that this issue'was not reportable based on the guidance in NUREG 1022, Revision 1.
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Operator Knowledge and Performance
'04.1 Hiah Pressure Coolant Iniection Post-Maintenance Testino -
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Insoection Scope (71707 &' 61726)
The inspectors observed control room operators performing a Unit 2 High Pressure Coolant injection (HPCI) system post-maintenance test.
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Observations and Findinas Operations performed surveillance procedure, ST-O-023-301-2, Revision 19, "HPCI Pump, Valve, Flow and Unit Cooler Functional and in-Service Test" to verify operability of the Unit 2 HPCI system on March 13,1998, after a scheduled maintenance outage. This test included a HPCI pump flow rate verification of greater than or equal to 5000 gpm against a system head corresponding to reactor system pressure. The procedure also verified proper operation of several HPCI valves and checked the performance characteristics of the HPCI compartment coolers.
The control room supervisor held a pre-job brief prior to the test. Station personnel were stationed at the HPCI turbine and pump to monitor for proper operation during the test. This monitoring included measuring vibration directly on the HPCI booster pump.
After the start of the HPCI pump / turbine, the inspectors observed high HPCl; vibration meter and recorder readings in the control room. The meter indicated greater than 5.0 mils and the recorder had spikes up to 5.92 mils. Prior to any operations personnel taking any action for this discrepancy, the inspectors
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questioned shift management as to the significance of these readings.
The Control Room Supervisor referred to the operating procedure, SO 23.1.B-2, Revision 11, "_HPCI System Manual Operation," for the limit on vibration. _ Personnel monitoring the booster pump vibrations locally communicated to the control room that HPCI pump operation was in the alert range, but no exact number was determined. The shift management then directed the Unit 2 operator to shutdown the HPCI turbine. Maintenance attached additional equipment to the turbine to
. monitor for abnormal operation and the HPCI pump and turbine was tested during a
'second run. All vibration readings were in the normal range during this second run l
and the HPCI system'was successfully returned to service following this run.
The inspectors discussed this issue with operations personnel and the HPCI system manager. The inspectors learned that the vibration monitoring instrumentation in the control room may have provided incorrect readings and that this equipment was known to have been unreliable for a long time. The inspectors noted that the -
precautions in SO 23.1.B-2 directed the operator to immediately trip the HPCI Turbine if excessive vibration (greater than 3.5 mils) was observed. If the vibration
- monitoring equipment in the control room was inaccurate and indicated higher than actual readings when the HPCI pump / turbine was operated, the inspectors were
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concerned that a normally operating HPCI pump could be shutdown when needed to
perform its safety functio E;y
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Conclusions The inspectors were concerned that the operators failed to immediately trip the HPCI turbine when the meter and recorder in the control room indicated that the vibration was above the procedural limit. However, the possibility that the meter and recorder had been inaccurate for a long time and could cause the operators to shutdown a normally operating HPCI pump when needed to perform its safety function was of greater concern to the inspectors.
This issue appeared to' be a violation of TS 5.4.1," Procedures" due to the concerns of the adequacy of the testing and operating procedures to identify and address
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concerns with the vibration monitoring equipment. This issue will be tracked as an j
Unresolved item (URI) pending additional reviews of the procedures used to test and -
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operate the HPCI pump / turbine, review of the status and repair history of the
. control room vibration monitoring equipment, and further discussions with the -
system manager and operations personnel. (URI 50 277/98-01-04)
J 04.2 (Closed) URI 50-277/97-08-04: Unexpected Trio of Unit 2 Main Turbine Durina i
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Inspection Scoos (71707)
d During the Unit 2 reactor startup on January 1,1998, the main turbine tripped automatically after it was inadvertently rolled to a speed of 1400 rpm. The inspectors reviewed the recorded data, reviewed all applicable procedures used, and
~ had additional discussions with operations and reactor engineering personnel as part of the follow-up for this event.
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Observations and Findinas On December 31,1997, the Unit 2 reactor operator (RO) reset the mechanical trip
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1 valve in the main turbine overspeed trip system and selected 1800 rpm on the-j speed set, at the main turbine (EHC) control panel to support work by instrument and control (l&C) personnel. The RO also adjusted pressure set to 930 psig during this testing. The I&C work procedure did not provide direction to restore the EHC system configuration to the condition set prior to the testing. Therefore, the main turbine, the pressure set setting, and speed select push-button were not restored to the original line-up established by GP-2, Revision 85, " Normal Plant Start-up."
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On the morning of January 1, the on-coming shift manager noted that pressure set was at 930 psig and the setting was readjusted to 150 psig (minimum setting).
Unit 2 reactor was made critical at 5:46 p.m. When reactor coolant system (RCS)
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pressure reached 50 psig, GP-2 directed to reset the main turbine per Station Operating (SO) procedure.1B.1.A-2, Revision 22, " Main Turbine Startup and Normal Operation." The RO verified that the main turbine was reset, but did not refer to all of the instructions in SO 1B.1.A-2, which contained instructions to verify that the l
speed set "ALL VALVES CLOSED" was selected.
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At 6:25 p.m. during shift turnover, with RCS pressure at 15'7 psig, the main turbine l
control valves opened causing the. main turbine to roll off the turning gear. Both-off-going and on-coming operations personnel failed to recognize that the control -
valves had opened. ;The on-coming RO noted that the turbine was not on the
turning gear at about 6:35 p.m.' The off-going RO cracked opened the 'C' reactor feedwater pump discharge valve to restore a low reactor vessel level condition at l
the end of his shift.~ Subsequently, the on-coming control room supervisor (CRS)
. directed the RO to commence rod pulls to raise RCS pressure to'open the turbine bypass valves..The CRS wanted to raise RCS pressure so that plant conditions -
would steady out and prevent possible reactor vessel level swings due to turbine bypass valve cycling. No changes in the positions of any of the bypass valves were ~
observed as RCS pressure increased. Just prior to the main turbine trip, the taain
. turbine lube oil high temperature alarm and hydrogen seal oil / stator water cooling.
trouble alarm were received in the control room.
During discussions with the CRSs, the inspectors learned the following from the on-coming CRS:
He believed that a turbine bypass valve had opened because the off-going
RO announced that the bypass valve was open.
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Even though the RO and he knew that the turbine had come off the turning gear, the crew remained very busy with activities to support continuation of the unit start-up and they did not slow down to evaluate the significance of the turbine coming off of the gear.
He thought that the reason that the turbine came off of the gear was due to
the turbine lift pumps.
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The crew determined that the turbine was not in shell or chest warming.
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This was suspected as a possible reason that the turbine came off of the gear. However, during the event the turbine chest pressure reached approximately 142 psig. Normally, the turbine nhest pressurs would be near 0 psig unless the turbine control valves were open or the turbine was in chest or shell warming. The indication for turbine shen pressure was located on one of the front control board panels.
i He did not dispatch an equipment operator to monitor the turbine after it-
'
came off of the turning gear.
He was focused on raising reactor coolant system pressure, by pulling the
_
control rods, to get a constant steam flow through the bypass valves so that reactor coolant vessel level and pressure would be stable.
During most of the time that the turbine was spinning, the crew was
. involved with turnover and the shift meeting.
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.He was uncomfortable assuming the watch with the reactor not steaming
,
, sthrough the turbine bypass valves at this point in the start-up. However, he did not express his discomfort to any other station personnel. The
.
' inspectors noted during a review of Operations Manual procedure, OM-C-6.1, L
Revision 1, " Shift Turnover" that if crucial or abnormal operations occur -
_
during the normal shift turnover period, the on-duty Shift Manager may direct that shift turnover be delayed until stable conditions are achieved. No discussion of a delay of turnover occurred during this event.
He noted that this was his first reactor start-up. It was also the first start-up
for the plant reactor operator (PRO).
His crew had not performed any just-in -time training including simulator runs
prior to the start-up.
- The inspectors reviewed the following data points from this event: reactor vessel level, reactor feedwater total flow, reactor pressure, turbine speed, total turbine -
'
control valve position, and turbine chest pressure. The inspectors noted that turbine speed increased steadily from around 6:25 p.m., until the turbine tripped at 8:39 p.m.. Also, reactor feedwater total flow increased steadily during this event.
.The inspectors observed that the indications for turbine speed set, turbine speed, and reactor feedwater total flow were displayed on the front section of the control
- panels..The inspectors also noted that the turbine control valve indicated up to q
50% open. -The inspectors observed that the indications for the turbine control valves were located on the one of the back panels. During this transient, reactor
.
vessel level remained fairly constant after the 'C' feedwater valve was cracked open.
'
and vessel level was restored. Reactor pressure increased very slightly during this event. Based on discussions with'the operations personnel and review of l_
documentation, reactor power also remained fairly constant during this event.
The inspectors noted the following after reviewing the procedures used during this event and applicable Operations Manual documents:
'
Instrument and Control procedure,1C-11-00497, Revision 4, " Alignment
Procedure for the Electro-hydraulic Control (EHC) System of the General Electric Turbine Generator" and any associated clearances did not contain
- instructions to rostore the main turbine, the EHC pressure set setting, and EHC speed select push-button to the line-up required for plant start-up.
_
- Operations procedure, GP-2, Revision 85, " Normal Plant Start-up" did not -
)
- -
contain any instructions in the " Pre-Startup Preparation" steps to restore the main turbine and EHC settings to the required start-up position. The only requirements for resetting the turbine were contained in Step 6.2.4 of GP-2 after the reactor was at approximately 50 psig. The inspectors noted that
- Step 6.2.4 of GP-2 required the main turbine to be reset in accordance with SO 1B.1.A-2. When the operators got to this step in the procedure, they did
'
not refer to SO 18.1.A-2 because the turbine was already reset and had been reset during the I&C work. Procedure SO 18.1.A-2, Revision 22, " Main l'
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L.--
Turbine Startup and Normal Operations", Stop 4.3.4 directed the operators to verify that the speed set was selected to "ALL' VALVES CLOSED." This step was missed since the procedure was not referred to. During discussions with the Shift Managers and the CRSsithe inspectors learned that operations personnel were not required to review a child document when it was referenced by a parent document if the action had already occurred.
Operations Manual procedure,' OM-C-6.1, Revision 1, " Shift Turnover, " Step.
l 5.2 noted that on-coming and off-going duty ROs and PROS should jointly l~
inspect instruments, equipment, and areas under their control during their shift turnover.
Also, OM-C-6.1' Step 5.4 noted that the CRS shell perform panel walkdowns
,
with sufficient detai! and verify a thorough understanding of plant conditions.
!
Operations Manual procedure, OM-P-3.3, Revision 5, " Licensed Operators",
Section 1.1, Step 1.a.2 noted that operators shall monitor the console and panel displays frequently to determine trends and to detect the development i
of problems. Section 1.1, Step 1.a.3 noted that operators shall take prompt a::tions to determine the cause of abnormalities, advise Shift Management of the abnormalities, and take corrective action. Section 1.1, Step 1.b noted that the Quality Assurance Program required frequent monitoring end '
checking of plant systems. Such monitoring shall include status in the j
Control Room and general operating conditions in the operating areas of the
- plant. : The primary method of monitoring operating status and conditions was the observation of equipment, controls, and displays including the.
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i configuration of the equipment or system. Observation of these items is the i
primary activity of the Operations Shift Teams personnel.
i The inspectors determined that'IC-11-00497 ano GP-2 failed to restore the EHC system to the alignment required for start-up. Since SO 1B.1.A-2 was l
not referred to when the turbine was reset per GP-2, operations personnel
missed the opportunity to' identify and correct the wrong turbine speed select
'
setting on the front control panel. The inspectors also determined that operations personnel did not adhere to the requirements of OM-C-6.1 and OM-P-3.3 for monitoring and walking down the panel displays since several abnormal indications were present at various indicators and were not -
recognized by operations personnel. In addition, the CRS did not take prompt actions to determine why the turbine came off of the turning gear.
The failure of the l&C and Operations procedures to restore the EHC system to the required alignment prior to start-up and the failure of Operations i
i.
personnel to detect the mispositioned EHC speed select or the changes in
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indications for the main turbine were examples of a violation of technical specification (TS) 5.4.1. Technical specification 5.4.1 requires, in part, that
- written procedures are maintained and implemented covering the applicable l
l l
E.
o i
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. procedures recommended in Regulatory Guide 1.33, Appendix A, November 1972. (VIO 50-277/98-01-05).
l c.
Conclusions Several examples of weak control room oversight of activities were noted from the Unit 2 main turbine trip during start-up on January 1,1998. These examples were as follows: 1) The Control Room Supervisor directed the pulling of control rods to increase reactor coolant system pressure while the turbine condition remained unknown. 2) Shift turnover and the shift meeting occurred while the turbine was in this unknown condition even though members of the crew knew that the turbine had come off of the turning gear. 3) The crew with the watch during most of this event had not received any just-in -time training such as simulator runs even though this was the first reactor start-up for the Plant Reactor Operator and the Control Room Supervisor.
The inspectors concluded that several examples of a violation of TS 5.4.1,
" Procedures" occurred when the Unit 2 main turbine tripped during start-up on January 1,1998. This violation occurred due to the following: 1) Inadequate instrument and Control and Operations procedures that failed to restore the Electro-Hydraulic Control system to the alignment required for start-up. 2) The failure of Operations personnel to refer to the main turbine start-up procedure when directed by the plant start-up procedure. 3) The failure of operations personnel to properly monitor the control room panels or recognize the main turbine status, position of the turbine control valves, or the selection of the speed set for the Electro-Hydraulic Control system. This monitoring and recognition of equipment status was required
,
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by Operations Manual procedures, OM-C-6.1 and OM-P-3.3.
Quality Assurance in Operations 07.1 Nuclear Review Board Meetina (71707)
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I On February 5,1998, Nuclear Review Board (NRB) Meeting #344 was held at Peach Bottom. The inspectors observed the following portions of this meeting.
The Peach Bottom plant manager discussed several significant operating abnormalities that had occurred during the previous two months. Event investigations and changes to the Performance Enhancement Program (PEP) process were discussed. The scope and depth of Safety System Functional inspections (SSFI; performed by the station was also discussed.
The inspectors observed good independent discussion and evaluations of the topics presented. Several probing and insightful questions were directed to the presenters
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by the members of the NRB. The inspecters concluded that the NRB provided an
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independent review of operation of the station as described in Appendix D of the i-UFSAR during this meetin &
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08 Miscellaneous Operations issues.-
08.1 (Closed) URI 50-277(2781/97-02-01: Station Qualified Reviewer Use/ Review of
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j Open Chanoes to the Undated Final Safety Analysis Report
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' In NRC Inspection Report 50-277(278)/97-02,the inspectors identified that some -
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- Station Qualified Reviewers (SORS) for procedure changes were not aware of the method to review the' posted changes to the Updated Final Safety Analysis Report (UFSAR).L As a result, the 10 CFR 50.59 safety determinations made by these
.
individuals may not have been properly assessed for UFSAR impact determination.
An unresolved item was opened to evaluate the licensee's review of this issue.
PECO conducted an investigation and found that nearly all SQRs were knowledgeable of the need to review posted changes to the UFSAR. However, engineering and operations personnel believed that the procedural guidance could be-l enhanced and made a revision to procedure LR-CG-13, " Performing 10 CFR 50.59 Reviews." in addition, personnel from both'of these groups reviewed a number of past 50.59 determinations and found that none were impacted by posted changes to the UFSAR.
The inspectors verified that LR-CG-13 was revised to more clearly describe the need to review posted /pending changes to the UFSAR. The revision included a change to the 50.59 determination form. The inspectors discussed this issue with a sample of station qualified reviewers and found that all were aware of the need to review
.
posted changes to the UFSAR. In addition,' the inspectors identified no concerns in
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I a review of past 50.59 determinations.
The inspectors concluded that PECO's actions for this issue were appropriate. The
,
inspector identified no violations of NRC requirements.
11. Maintenance and Surveillance i
M1 Conduct of Maintenance and Surveillance
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M1.1 E4 Emeroency Diesel Generator Outaae and Refurbished Governor Replacement i
'a.
Inspection Scope (61726 &62707)
During the week of February 22,1998, the E4 emergency diesel generator (EDG)
was removed from service for replacement of the Woodward governor and the 18 month preventive maintenance activities. The inspectors observed portions of this
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work including post-maintenance testing and reviewed the designated maintenance
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L and test procedures.
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Observations and Findinas i
L, E4 EDG maintenance activities included replacement of the diesel engine oil and I
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maintenance and inspection or examination of various diesel and generator
. components.' The Woodward governor on the diesel was replaced with a
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refurbished governor. Personnel from I&C pe; formed the alignment and tuning of
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the reinstalled governor.
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The inspectors observed tuning of the governor for the diesel generator and
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reviewed the documentation for the diesel maintenance'and post-maintenance -
testing. The inspectors observed that the system manager and l&C supervision were present at the jobsite during the work activities and post-maintenance testing.
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During the post-maintenance testing activities,- the only out of specification readings
.;
l were a low direct current volt meter field volts reading and a low generator amps i
L reading. These readings were recorded during a two hour full load test. The field volts reading was 156 with an acceptance criteria of 160 to 180 volts. The
,
l remaining three readings were all within this acceptance criteria. The generator
- amps reading was 330 with an acceptance criteria of 333 to 480 amps. Both
conditions were documented on Action Request # A1136948 for future trending.
The inspectors noted that the E4 EDG maintenance activities including governor ;
refurbishment and post-maintenance testing was generally.well performed. - The
- Inspectors had no immediate concerns with the two out of specification readings."
However, the inspectors noted during observations of the governor tuning that licensee management needed to maintain diligence in stressing procedural
' adherence in their "Back to Basics" program based on the performance of the mechanics and l&C technicians observed, t
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Conclusions Maintenance and post-maintenance testing activities were generally well conducted
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during the E-4 emergency diesel generator 18 month overhaul.
M3 Maintenance Procedures and Documentation
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M3;1 Procedure Usaae and Documentation for Refuel Floor Activities Durina Refuelina -
Outaae 3R11 j
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Insoection Scope (62707)
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The inspectors reviewed several completed procedures used on the refuel floor
'during refueling outage 3R11 (October 1997) to verify that work steps and activities
"
were properly completed. Procedures reviewed included:
M-OO4-200, Revision 8, " Reactor Pressure Vessel Disassembly"
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M-C-700-332, Revision 6, " Rigging and Handling Heavy Loads"
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M-004-114, Revision 1, " Fuel Floor Auxiliary Platform Operation"
M-004-400, Revision 8, " Reactor Pressure Vessel Reassembly"
M-C-700 200, Revision 6, " Lifting and Landing of Electrical Leads."
- The inspectors also interviewed Nuclear Maintenance Division personnel who performed or supervised work on the refuel floor to determine how procedures were controlled and how work progress was documented.
b.
Observations and Findinos The inspectors found that workers / supervisors appropriately filled out the applicable sections of the refuel procedures. Based on the completed documentation, the activities were performed as specified in the procedures; notifications to operations and other organizations were accomplished; and inspections / verifications were completed as required. The inspectors discussed selected activities with the cognizant personnel and determined that the documentation agreed with their recollection of the sequence of events.
The inspectors found that the official copies of procedures for refuel floor activities were maintained in the office on the refuel floor. Other information/ working copies of procedures were used at various locations within radiologically controlled and contaminated areas. Some of these working copies were only partially signed off and the sign offs and other information were transferred to the official copy at the conclusion of the activity. This sign off methodology was specifically authorized by the guidance in administrative procedure, A-C-079, Revision 1, " Procedure Adherence and Use." The inspectors also noted that the training for maintenance j
technicians was consistent with this guidance.
c.
Conclusions The inspectors concluded that refuel floor activities during 3R11 were performed and documented in accordance with plant procedures.
M8 Miscellaneous Maintenance issues M8.1 (Closed) Unresolved item 50-277(278)/97-01-01: Core Thermal Power Greater Than Technical Specification Limit NRC Inspection Report 50-277(278)/97-01 noted that due to inaccurately calibrated, feedwater temperature instruments, Unit 3 operated for an extended period of time above licensed rated thermal power. Specifically, PECO identified that Unit 3 had operated as high as 100.6% during the period from June 12,1995, through January 21,1997. Preliminary investigations determined that the lack of knowledge of the effect of feedwater temperature on core power was a major contributor to this issue. The inspectors considered the knowledge of plant instrumentation inputs that could affect core thermal power and the controls over test equipment an unresolved item, pending additional inspector revie l..
.
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PECO completed the Performance Enhancement Program (PEP) investigation and corrective action effectiveness determination for this issue in February 1998. The investigation determined that:
Technicians, operators, and supervisors failed to adequately review
completed surveillance data for the feedwater temperature instruments in June 1995. This information indicated that all four channels of feedwater temperature were adjusted during the surveillance by at least 5 degrees.
The surveillance instruction did not indicate the significance of feedwater
temperature on core thermal power calculations.
Identification of problematic measuring and test equipment was poor. The
decade box used to perform the inaccurate calibration had a history of repeated repairs.
The plant remained within design basis event assumptions, which account
for excursions up to 102% power.
The period during which the plant exceeded licensed power was from
October 1995 through January 1997. The plant was in coastdown while the calibration that found this deficiency was performed.
The inspectors reviewed the completed PEP corrective actions and considered them adequate. PECO conducted reviews and made revisions to surveillance tests that affect core thermal power calculations. The event was discussed with plant personnel who make adjustments to equipment found outside of the expected range and with personnel who perform reviews of surveillance tests. Further, a number of improvements were made to the controls for measuring and test equipment, i
including review of test equipment history when out-of-tolerances are identified and consideration for scrapping the equipment, as appropriate.
The inspectors determined that plant personnel missed multiple opportunities to j
identify and correct the inaccurately calibrated feedwater temperature instruments:
j l
In June 1995, technicians had difficulties with the original performance of
the surveillance instruction for the feedwater temperature instruments. The
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problems were discussed with a supervisor and were believed to be resolved.
However, the problems were not documented in the remarks section of the surveillance instruction, nor was any formal corrective action document initiated.
I Technicians' concerns over the adjustments to all four channel of feedwater
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temperature were not documented or brought to the attention of I
management or operations personnel.
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. Reviews of the completed surveillance instructions by operations /engineerina
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personnel knowledgeable of significance of feedwater temperature did not l.
identify the issue.
The out-of-tolerance test equipment was reported to plant personnel in July
1996, but they did not recognize the safety impact, namely the effect on the core thermal power calculation.
The inspectors considered the actual and potential safety impact of this issue to be low, based on the fact that the plant remained in operation at power levels below 102%. This was the design power used in plant safety analyses. The NRC has documented that for brief periods, on the order of a few minutes to an hour, minor power excursions above rated thermal power were acceptable. This position did not apply to long periods of operation above rated power levels.
. The inspectors also noted that, despite several instances of out-of-tolerance for the affected test equipment (Decade box #46-0161),the equipment continued to be used on plant components. The inadequate identification of the problematic nature of this equipment did not affect safety related equipment, and therefore was not 1-considered a violation of 10 CFR 50 Appendix B, Criterion XII, Control of Measuring and Test Equipment." However, this deficiency was an important causal f actor in this event.
. Errors in the calibration of feedwater temperature instruments resulted in exceeding rated thermal power by as high as 0.6% during the period October 22,1995, through' January 21,1997. This was a violation of the facility operating license, DPR-56, section 2.C.(1), which authorized PECO to operate Unit 3 at steady state reactor core power levels not to exceed 3458 megawatts thermal (i.e.100%
power). (VIO 50-278/98-01-06)
i Conclusions The inspectors determined that from June 12,1995, through January 21,1997,
'i PECO failed to identify r.id correct inaccurately celibrated. feedwater temperature instruments, resu! ting in the operation of Unit 3 as high as 0.6% above licensed thermal power level. This was considered a violation of the facility operating
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license, DPR-56, section 2.C.(1). Further, PECO did not adequately control the measuring and test equipment used to calibrate the feedwater temperature
instruments.' Although this issue was identified by the licensee, there were several
. significant missed opportunities to identify this issue sooner.
M8.2 Licensee Event Reports (LERs) (92902)
a.
(Closed) LER 50-277(2781/2-97-OO8:Loaic System Functional Testina did not meet all Technical Specification Surveillance Reauirements During engineering reviews performed during October 1997 in response to NRC Generic Letter 96-01, the licensee identified that contacts within the standby gas j
o
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treatment (SBGT) and residual heat removal (RHR) systems logic channels were not being tested as required per the technical specification surveillance testing program.
The untested SBGT system contacts were associated with the ' initiation of heaters for both trains. The RHR testing deficiency involved an insufficient method of '
verifying whether the reactor low pressure relays were open or closed during j
surveillance performance.
i Following discovery, the licensee promptly tested all affected contacts and found that they operated correctly. Engineering personnel determined that the surveillance testing procedures were deficient due to inadequate procedure development and reviews.
b.-
IQased) LER 50-277(2781/2-97-005: Technical Soecification Non-Comoliance
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associated with Rod Block Contact Testina-
)
i in August 1997, PECO found that two Rod Withdraw Block logic channel relay-contacts were not being tested in accordance with the current Technical
)
Requirements Manual (TRM). Further, these contacts had not being tested in accordance with the original Custom Technical Specifications from 1989 until
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Improved Technical Specifications were implemented in January 1996. This particular testing requirement was relocated to the TRM after the improved
- Technical Specifications were implemented.
Subsequently, these contacts were tested and found to be functional. -The licensee determined that'the cause of this testing deficiency was an improperly performed-surveillance test procedure revision in 1989.
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NRC Review / Conclusions
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The inspectors reviewed both LERs and the documentation related to the reviews in response to NRC Generic Letter 96-01.' The inspectors determined during on-site -
inspections, that the potential safety impact of these testing deficiencies was minimal, since all contacts were found to be satisfactory following revised testing.
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The generic implications of these issues were. addressed in the' Generic Letter 96-01 logic circuit review project. Surveillance test procedure changes were also initiated.
Further, the inspectors considered these findings to be isolated cases, given the extensive review of logic circuits that was completed in response to Generic Letter 96-01, incomplete Rod Withdraw Block surveillance testing, from 1989 through January 1996, was a non-compliance with Custom Technical Specification 4.2.C, Minimum
Test and Calibration Frequency for Control Rod Blocks Actuation. Deficiencies in standby gas treatment system and residual heat removal system surveillance testing of system logic channels were violations of Technical Specifications 3.3.6.2.5, and 3.3.5.1.5, respectively, which required logic system functional tests of these systems. These non-repetitive, licensee-identified and corrected violations are being treated as Non-Cited Violations, consistent with Section Vll.B.1 of the NRC-Enforcement Policy. (NCV 50-277(278)/98-01-07)
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l11. Engineering E1'
Conduct of Engineering E1.1 Inservice Testina/ inservice insoection Interval Extension a.
Insoectinjsgoe (37551)
The inspectors reviewed a series of letters (dated August 17,1988, February 25, 1991, March 27,1995, June 12,1996, January 30,1997, and October 21,1997)
)
in which PECO informed the NRC of revisions to the end dates for the second 10-
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year Inservice Inspection (ISI) and Inservice Testing (IST) program intervals for Units 2 and 3.
i l
b.
Observations and Findinas j
The second 10-year ISI and IST intervals commenced on July 6,1984 and j
December 13,1984 for Units 2 and 3, respectively. The net effect of the interval revisions made by PECO in the referenced letters was to extend the end of the second 10-year ISI interval to November 4,1998 and August 14,1998 for Units 2 l
and 3, respectively. The submittal also revised the end of the second 10-year IST program interval to August 14,1998 for both Units 2 and 3.
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The ASME code of record for the Peach Bottom ISI and IST programs was the ASME Code,1980 Edition through Winter 1981 Addenda. Section IWA-2400*
allowed licensees to extend 10-year intervals for up to one year to correlate to scheduled outages and to extend the interval by an amount equwalent to the duration of out of service periods of six months or greater, in its submittal, PECO extended the ISI and IST program intervals to allow for scheduled outage correlation for both units, to account for extended out of service periods in 1984 and between 1987 and 1989 for Unit 2, and to account for extended out of service periods between 1987 and 1989 for Unit 3.
c.
Conclusions The inspectors reviewed PECO's submittal of revisions to the end dates for the second 10-year Inservice Inspection (ISI) and Inservice Testing (IST) program
Intervals for Units 2 and 3. The inspectors concluded that PECO's revisions were in j
accordance with Section IWA-2400* of the applicable ASME Code edition, and
{
were therefore in accordance with 10 CFR 50.55a(g)(4),
i E2 Engineering Support of Facilities and Equipment i
O
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l E2.1 Wide Ranae Neutron Monitorina Svstem (WRNMS) (52001)
in January 1995, the licensee submitted a request to the NRC for Technical l
Specifications (TS) changes to the source range monitor (SRM) and the intermediate range monitor (IRM) requirements. These TS changes resulted from the L
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replacement of the original SRM anu IRM with a new digital wide range neutron monitoring system (WRNMS), manufactured by General Electric Company (GE). The
' NRC reviewed tb licensee submittal, and issued the safety evaluation report (SER)
for the WRNMS installation, but not for the changes to the TS, on June 9,1995.
'Because the licensee had previously submitted its improved Technical Specifications application for Peach Bottom Units 2 and 3, which was then undergoing separate staff review, the staff could not complete the review of the WRNMS-related--
'
changes to the TS until the staff's review of PECO Energy's improved Technical-
.
Specifications application had been completed. The staff received the needed TS
_
_
input in January 1997. The TS changes were approved by the NRC in May 1997.
Unit 3 completed the WRNMS installation in October 1997. Unit 2 installation was scheduled for the next refueling outage in the fall of 1998.
E2.1.1 Scoos of WRNMS Uoarade f
a.
Insoection Scope The inspectors reviewed GE document NEDO-32368, " Nuclear Measurement
'
Analysis and Control (NUMAC) Wide Range Neutron Monitoring System Licensing Report for Peach Bottom Atomic Power Station, Units 2 and 3," and other supporting documents to determine the extent of the WRNMS upgrade, including system components, digital hardware and software and their architecture. The review was to determine whether the scope of the modification was consistent with
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the SER and the licensee's commitments. The inspectors also conduct a walkdown of system components in the main control room and in other accessible areas
~,
outside the containment where portions of the digital WRNMS retrofit were housed.
. b.
Observations and Findinas
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The licensee elected to replace the original SRM and IRM systems because of the high failure rate the licensee was experiencing with the detectors in the original system and because the operators frequently caused a reactor trip during startup due to not switching the IRM range switches as needed. ' The'new WRNMS detectors are less prone to failure because they do not need to be retracted. The
- WRNMS also eliminated the need for the operators to manipulate IRM range switches during startup.
LThe original neutron monitoring system consisted of four source range neutron
- detectors and eight intermediate range neutron detectors, each of which had to be withdrawn from the core as reactor power increased to prevent depletion of the uranium-235 inside the detectors. The WRNMS replaced the 12 detectors with L
' eight breeder-type detectors. The WRNMS breeder detectors can remain in the core
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for up to 7 years of operation at full power before they need to be replaced. The new detectors contain a mixture of uranium-234 and uranium-235. Uranium-234 is converted to uranium-235 in the presence of neutron flux, constantly replenishing
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L the depleting quantity 'of uranium-235.
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The WRNMS provides eight channels of computer-controlled monitoring of' neutron -
flux over 11 decades of reactor power, i.e., from 1x10' percent:to 100 percent of full power...Therefore, the range switches on the main control panel are no longer -
needed and had been removed. The original indicators on the main control panel had been replaced by the eight channels of WRNMS flux-level and period indication.
The WRNMS pre-amplifiers (8 per unit), control room monitor (CRM) drawers (8 per
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unit), the period recorders (4 per unit, each recorder serving two channels) and operator display assemblies (ODA) (4 per unit, each ODA shared by.two channels)
are housed in the original enclosures, powered by the original power supplies, and
. used some of the original cables. -
I The WRNMS uses a 80C86 microprocessor in each CRM drawer and a 64180 j
(Z80 derived) microprocessor in each ODA. Each of these two assemblies contains j
programmable read-only memory (PROM) modules, in which the functional,- display, and self-test software resided. All of the WRNMS software (monitoring, display,
,
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and self-test) was considered to be safety-related and received the safety-related level of verification and validation (V&V) effort. The V&V process for the WRNMS j
is described in the topical report for the WRNMS NUMAC system. The NRC has '
'
approved the V&V process for the NUMAC WRNMS as indicated in the SER issued
' for the generic WRNMS manufactured by GE.
- The only hardware input to each WRNMS channel was one cable per channel from
)
each of the eight neutron detectors in the reactor core. The only outputs from each j
WRNMS channel were the period-short rod block trip nnd the period-short reactor protection system (RPS) trip. The WRNMS interfaced with both trains of RPS and Rod Block logic with signals that were equivalent to those that were in'the original system.
Other inputs to the CRM drawers came from within the WRNMS or from operator manualinputs through the ODA that were under administrative control. There were.
additional outputs from the eight CRM drawers to the indicators, recorders and annunciators in the control room. The inspectors found that the WRNMS provided I
information and indication to the operators that was at least equivalent to that of the original system and was consistent with the SER.
The inspectors did not observe any unacceptable condition during the walkdown of system components, c.
Conclusions The inspectors concluded that the digital WRNMS provided information and indication to the operators that was at least equivalent to that of the original system and was consistent with the SER.
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E2.1.2 As-Installed Diaital Modification a.
insoection Scooe The inspectors reviewed selected licensee documentation, including design documents, installation drawings, licensee submittal, vendor manuals, and schematics, and conducted a walkdown of selected components of the WRNMS to determine whether the installed digital modification was in accordance with the SER, design drawings and licensee commitments.
'b.
Observations and Findinas The inspectors' review of licensee desiga and installation documents revealed that the design and installation of the WRNMS at Peach Bottom were generally in accordance with licensee's commitments. However, during the inspection, the licensee pointed out that there were two places where the installed system differed from the SER and one of the licensee's submittals. The inspectors' review of selected documents revealed the following discrepancies:
WRNMS Cable Routina The SER for Peach Bottom WRNMS states:
"WRNMS is designed to meet the separation guidelines of RG 1.75, Rev. 2, with respect to the scope of the replacement system.- Safety-related and nonsafety-related replacement equipment is separated physically and electrically. Where interfaces occur between safety and nonsafety equipment, appropriate isolation d9 vices (relays) are used per the existing design for channel independence as required by IEEE 279. The eight WRNM channels are electrically isolated and physically separated from one another except immediately under the reactor veuel, where complete physical separation is not practical. The staff finds the above separation features to be consistent with IEEE 279 and RG 1.75, and therefore, acceptable."
However, there were at least two areas in the WRNMS installation for both new and existing cables where separation was not consistent with L 31.75. The first area was in the mixing of safety-related and nonsafety-related cables in cable trays and in control cabinets. Specifically, for the Peach Bottom existing installation, nonsafety-related cables were routed be safety-related trays in a manner that did not q
meet the definition of associated cables as specified in RG 1.75. However, this installation was consistent with Peach Bottom licensing basis as described in the final safety analysis report (FSAR) sections 7.1.6.1," Cable Routing and Separation," and 8.4.5, " Description of Auxiliary Power System." The second area related to new cable routing inside safety-related control cabinets, where safety-related electric cables and nonsafety-related fiber-optic cable (total eight pieces)
were routed together, and the fiber-optic cable could not meet the associated cable
criteria, and was not physically separated. The licensee stated that the fiber-optic j
cable did not carry electric current, and its failure would not damage the y
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- y i:
,.
22'
,'
surrounding safety-related c.sbles, therefore, the licensee considered this
!
' configuration acceptable. The inspectors agreed that this configuration would not
'
,
affect the. safe operation of the WRNMS.
Neutron Detector Cable.
In ' PECO's submittal (LCR 93-18) dated January 17,1995, Attachment 3,'
Section 2, " System Description," the licensee referred to Figure 2-2 for a block
. diagram of a single channel NUMAC-WRNMS. Figure 2-2 showed that the neutron l-detector cable from the connector (underneath ths reactor vessel) to the pedestal junction box was 75 ohm mineral-insulated cable. However, the Peach Bottom installation used organic-insulated cable (total eight pieces of cable) instead. This cable was subject to high radiation during operation, although environmental qualification was not required.. Further review of licensee documents indicated that this cable was Rockbestos RSS 6-110A/LEcoaxial cable, and was qualified to a total integrated dose (TID) of 200.12 megarads, as described in Rockbestos Report
- QP-6802, " Report on Qualification test for Rockbestos Adverse Service, Coaxial, Twinaxial, and Triaxial cable, Generic Nuclear Incident for Class 1E Service in Nuclear Generating Stations," dated March'12,1986. The qualified dose is higher than the total operating dose of 17 megarads. Therefore, the inspectors considered the Rockbestos cable an acceptable substitute for mineral-insulated cable.
On January 23,1998, the licensee sent a letter to the office of NRR, identifying the above discrepancies. Discussion with NRR staff indicated that NRR was following h,
the cable sepan. tion issue.
l
- c.
Conclusions l
l
' The inspectors concluded that the WRNMS as installed at Peach Bottum was
'
L generally consiste'nt with licensee commitments (submittall and the SER with two
'
exceptions: cable separation not consistent with RG 1.75, and the use of organic-
!
insulated neutron detector cable. The first exception was being followed by NRR, j
and the second exception was determined ty the inspectors to be' acceptable. Both l
. exceptions would not affect the safe operation of the WRNMS.
!>
. E2.1.3 Licensee and Vendor Interface a.
Insoection Scope The inspectors reviewed licensee supporting documentation to assess the licensee
and vendor interface during factory testing, system installation and integration, and
post-modification software upgrade.
i b.
Observations a'nd Findinas
- The licensee had developed a factory test plan entitled " Acceptance Test Plan for Modification P-271, Wide Range NMS - Unit 3," dated July 25,1997, and factory test records. The inspectors' review of this document indicated that the factory i
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-l tests discussed in the test plan were comprehensive and consistent with licensee's commitments. The licensee also sent a team of engineers and technicians to the factory to witness and participate in the factory acceptance testing. In addition, the vendor had provided site representatives to deal with technical issues during system installation, integration, calibration and post-modification testing. The inspectors found that the interface between the licensee and vendor for the WRNMS modification was good.
A modification was made to the WRNMS software in the programmable-read-only-memory (PROM) after the factory acceptance testing had been completed. The software upgrade was to resolve the potential problem involving the system's power adjustment factor (PAF), which GE had identified in the WRNMS at a foreign nuclear plant. The PAF is a field-configurable gain parameter used to match average power range monitor (APRM) power at the point of taking the mode switch to j
"Run" (i.e., it serves as a gain calibration adjustment to the APRM system at overlap). It was discovered that if the PAF was reduced to below 0.25, the WRNM down scale setpoint (3 cps) was affected in a conservative manner, causing it to trip at a higher count rate (between 4 and 7 cps, depending upon the PAF setting)
instead of the specified 3 cps.
i The software (PROM) fix for the above condition involved extending the allowable low-power span of the drawer to go to a power level below the equivalent power value to 3 cps for low values of PAF. The software fix was verified at Peach j
Bottom for each WRNMS drawer during testing by setting the down scale trip setpoint at 3 cps and verifying that it remained at 3 cps for variations of PAF values down to 0.05. The change makes it easier for the operators to achieve the 3 cps setpoint.
The inspectors considered the above a good example for correcting design j
weakness through the licensee and vendor interface.
c.
Conclusions The inspectors concluded that the licensee and vendor interface during factory testing, system installation and integration, and post-modification software upgrade was good.
E2.1.4 Maintenance. Surveillance and Abnormal Operatino Procedures a.
Inspection Scope The inspectors reviewed station procedures to determine: 1)if maintenance and surveillance procedures were correctly updated to satisfy the new Technical l
Specifications (TS) requirements; and 2) annunciator response procedures had been appropriately updated to reflect the new alarm condition i
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b.
. Observations and findinas The surveillance test requirements were prescribed in Peach Bottom Technical
' Specifications (TS) Sections SR 3.3.1.1.5 through 3.3.1.2.6. The test frequencies of several of the channel functional tests.had been changed from 7 days to 31 days -
,
. and the calibration frequencies had also been changed from 184 days to
- 24 months. The basis of the changes had been reviewed and accepted previously by the NRC. The inspectors reviewed two surveillance test procedures, one for 31-day functional tests, and the other for 24-month calibrations,' and verified that the new test frequencies matched the TS requirements.
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The inspectors also reviewed station procedures 30C205L and 30C205R which prescribed alarm response process for WRNM count rate low (less than 3 cps),
short period / trouble, and reactor auto scram. The inspectors found the response q
procedures for the above' alarm condition appropriate.
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l c.
Conclusions The inspectors concluded that the licensee had established an acceptable surveillance program to satisfy the TS requirements for the new WRNM system, and
. that the response procedures for the WRNM system alarm were appropriate.
j E2.1.5 Updatina of UFSARiPlant Drawinas, and Other Relevant Documentation a.
Insoection Scooe L
The inspectors reviewed Peach Bottom updated final safety analysis report
!
(UFSAR), appropriate licensee documents and selected plant drawings to determine if these documents had been properly updated to reflect the replacement system.
.
b.
Observations and Findinas L-The inspectors' review of Peach Bottom UFSAR indicated that the UFSAR had not yet been updated to reflect the WRNMS retrofit. However, the licensee provided for j
the inspectors' review an engineering change request (ECR) No. PB95-03442,
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entitled "Startup Range Neutron Monitoring System improvement," Revision 1. This document contains the marked-up copies for future UFSAR changes upon the
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completion of the installation of the WRNMS into the remaining unit (Unit 2). The l
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inspectors reviewed the marked-up UFSAR pages and two completed drawings for Unit 3 and found that these accurately reflect the implementation of the WRNMS.
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c.
Conclusions
The' inspectors concluded that appropriate process had been provided by the licensee to update the UFSAR and other relevant licensing documents to reflect the WRNMS retrofit.
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- E2.1.6 Modification Trainina of Ooerators and Technicians
- a..
Insoection Scone The inspectors reviewed licensee's training program for providing _WRNMS-specific -
training to operators and technicians to determine whether sufficient training was provided to those personnel involved with WRNMS activities. The inspectors also
interviewed operators and technical personnel to determine their knowledge in this area and to assess the effectiveness of the training.
b.
Qbservations and Findinas
' Three courses of WRNMS-specific training were provided to engineers, technicians, and operators. ' Course P213-97008 was to provide the knowledge required to understand the operation and hardware of the GE WRNMS Course P213 97007 was provided to a team of 10 engineers and technicians who were responsible for installing and troubleshooting the system. Course PLOR-96-10B was provided to control room operators to familiarize themselves with the installation and operation
,
of the WRNMS; this course was also required for licensed operator requalification -
,
training. The inspectors reviewed the training materials for these courses and found J
them containing extensive information of the WRNMS. The inspectors interviewed the two instructors who taught the abo /e courses and found them very familiar -
- with the system. One of the instructors was also a technician. The inspectors also ~
interviewed two control room operators to test their knowledge of the system.
These operators demonstrated full knowledge of the operational aspect of the WRNMS. All interviewed operators expressed their appreciation of the new system,
- which was much simpler to operate compared with the old systems (source range -
monitor and intermediata range monitor), especially in avoiding unnecessary rod blocks and reactor trips. During the course of the inspection, the inspectors had
. many discussions with licensee technical staff. The inspectors found them very familiar with the system.
,
c.
Conclusions The inspectors concluded that extensive training was provided to the control room operators and technical personnel. The instructors, the control room operators, and the technical personnel involved with WRNMS activities were familiar with the system.
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L E2.1.7 Setooints and Related Uncertainties
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,
a.
Inspection Scone l
The inspectors reviewed licensee documents to verify that: 1) setpoints and related uncertainty terms had been adequately evaluated and to reflect the WRNMS retrofit; and 2) the calculated setpoints had been accurately installed in the WRNMS software.
.
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.
b.
Observations and Findinas The inspectors reviewed GE calculation PE-0224, entitled " Wide Range Neutron Monitoring Set Point Calculation for Peach Bottom," Rev 1, and found that in.
)
calculating.these setpoints, GE used its standard, NRC-approved, setpoint methodology. The inspectors also found that the assumptions for uncertainties and setpoint drift were adequately evaluated to reflect the WRNMS upgrade and properly documented and justified. The calculated setpoints were accurately installed into the WRNMS software.
c.
Conclusions I
The inspectors concluded that the setpoints and related uncertainty terms had been
]
adequately evaluated to reflect the WRNMS upgrade and that the calculated setpoints had been accurately installed into the WRNMS software.
E2.1.8 Handlina and Storaae of Soare Parts a.
Inspection Scope The inspectors reviewed the procedures for handling and storing WRNMS spare parts to determine whether these procedures were consistent with the licensee's commitments and manufacturer's recommendations. The inspectors examined i
some of the spare printed circuit boards (PCBs) in the store room where the spare parts are stored and handled.
b.
Observations and Findinas The licensee had developed four station procedures: P-C-3, " Receipt of items";
P-C-4, " Control and Handling of Materials"; P-CG-4, " Storage Practices"; and
" Peach Bottom Inventory Parts Catalog, Stock Code 116 70662" for the handling and storage of spare parts. The inspectors reviewed these procedures and found that these procedures adequately prescribed the handling and storing attributes.
The inspectors also examined several of the PCBs used in the WRNMS drawers.
The inspectors observed that the PECO employee who handled the PCBs wore a grounding strap, opened the containers at a grounded work station, and observed proper precautions to prevent damage to the parts from electrostatic discharge.
The inspectors found that the handling and storage of WRNMS spare parts was consistent with the licensee's commitment and the manufacturer's recommendations.
l The licensee stated that they would not perform any repairs on WRNMS spare l
PCBs. All PCBs would be returned to the vendor for repair. The licensee kept two spares of each PCB and each PROM set, one for Unit 2 and one for Unit 3.
One PCB, the RS 232, has a battery. The battery has a shelf life of 10 years. The inspectors observed that this PCB was flagged for periodic battery replacement.
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c.
Conclusions The inspectors concluded that the handling and storage of spare parts for the WRNMS was consistent with the licensee's commitment and the manufacturer's recommendations, and that sufficient spare parts were onsite for immediate replacement.
E2.2 Failure of Westinohouse HFA Breakers to Latch Closed a.
Insoection Scoce (37551)
On January 27,1998, maintenance personnel observed that the Westinghouse HFA breaker for valve operator, MO-2-12-005D,was not fully latched closed. This observation was made during scheduled auxiliary contact resistance testing.
Approximately nine additional Westinghouse HFA and FA breakers, for various Unit 2 and 3 components, were found not fully latched. The inspectors reviewed drawings, work procedures, vendor manuals, and engineering operability anelysis related to the failure of these breakers to latch. The inspectors discussed this issue with engineering personnel. The inspectors also visited PECO Corporate Laboratory, Valley Forge, PA, to independently verify PECO Energy's operability determination of the breakers.
b.
Observations and Findinas For each of the untatched breakers, maintenance personnelidentified that the vari-depth
)
mechanism, which was external to the molded case circuit breaker, was holding the j
breaker closed. When the vari-depth mechanism was rotated downward and relaxed from the breaker operating handle; the breaker would trip open. If the breaker was reclosed and was not fully latched; movement of the vari-depth downward produced the same results. This failure to latch condition was not found with the Westinghouse HFB breakers.
This condition resulted in questions about the reliability of these breakers to remain closed during a seismic event or any other event that would cause movement of the breaker and the vari-drive mechanism. All faulty breakers were energized when this deficiency was found. None of these breakers had inadvertently opened or had any history of opening during plant operation.
Engineering and work week planning personnel scoped and bounded all of the safety significant and important to safety HFA and FA breakers in both units. The total population of HFA and FA breakers scoped was over 300. Work plans were issued to inspect all of these breakers. If the breakers were found to be not fully latched during these inspections, the breakers were cycled several times in an attempt to latch the l
breaker. If the breaker would not latch after cycling, the breaker was replaced with an
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HFB breaker, i
f Maintenance personnelinspected approximately 200 breakers. Most of the breakers l
Inspected were for safety related equipment. The breakers ranged in size from 10
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'6
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amps to 225 amps. Each breaker inspected or replaced was properly removed from L
service and the technical specification, Limiting Condition for Operation was entered, if required.
The licensee planned to inspect apprnximately an additional 100 breakers during scheduled maintenance weeks for the next couple months. Eventually, the licensee.
intended to replace all of the HFA and FA breakers in both units with HFB breakers.
The licensee forwarded the faulty HFA breakers to their laboratory at Valley Forge for
. analysis.' Preliminary information revealed that some of the breakers would fail open-during a simulated event. The preliminary cause of the failure of the breaker to fully latch closed appeared to be hardened grease and oxidation on the latching mechanism.
The inspectors reviewed the licensee's troubleshooting efforts to determined the root
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cause and operability determination of a 10-ampere Westinghouse HFA molded case circuit breaker. This particular circuit breaker was analyzed by PECO Corporate Laboratory for movement of the operating handle with the breaker contacts in the closed position. -The inspectors verified, through observation, this breaker's inability to latch closed when the operating handle was moved to the ON positi,n and that the operating handle could be moved by' touch. The licensee determined through uting, that the movement of the operating handle did not affect the operation of the breaker.
i The licensee stated i;ectrical tests found the breaker able to provide its rated current when in the failed-t,-latch-closed condition. The licensee also stated that in the event of an overcurrent condition at the load, the breaker would appropriately trip. The inspectors verified that when the operating handle was moved to the ON position, the main contacts'close, and remain closed even though the operating handle can be moved. The inspectors also verified that the trip function is independent of the ON/OFF function of the breaker. The licensee attributed the movement of the operating handle to the inability of the ON/OFF linkage within the breaker to properly align. The inspectors observed this inability of the ON/OFF linkage to properly align by physical ~
inspection and noted that in some instances this caused the circuit breaker not to l
properly. latch closed. The licensee stated that the inability of the ON/OFF linkage to properly align was due to hardened grease and oxidation at lubrication points along the linkage. The inspectors had no concerns with this assessment. The inspectors found the ON/OFF linkage to be stiff when it was manually manipulated.
'
l The inspectors questioned the ability of the circuit breaker to remain latched during a seismic event. The licensee provided their bases for maintaining the breaker closed based on engineering judgement. - The inspectors found that the vari-depth unit i
provides an interface between the cubicle ON/OFF handle and the ON/OFF toggle, j
which is located within the bucket inside of the cubicle. The licensee stated that the
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vari-depth could maintain the breaker in the latched closed position because of the way e
l.
it interfaces with the breaker and the cubicle components. The inspectors noted the l
l vari-depth has a detent to ensure proper alignment of the external ON/OFF handle when
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the cubicle door is closed. The inspectors concluded that the detent and vari-depth unit
'
should maintain the breaker in the latched close condition for normal operation and seismic events. The licensee stated that they planned to assemble a team to further
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assess seismic concerns for the vari-depth / circuit breaker combination. Specifically, E
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29 the licensee plans to evaluate if the vari-depth can maintain the circuit breaker in the latched closed condition during seismic events. The inspectors had no concerns with this approach.
The inspectors discussed with engineering personnel and reviewed the documentation for scoping and bounding the HFA and FA breakers. The inspectors noted that station
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personnel exhibited a rigorous and systematic engineering approach to determining
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which breakers to inspect ard cycle or replace. The inspectors also reviewed the work plans for inspecting, cyclir.g, and replacing the breakers and observed portions of the breakers and vari-depth mechanism out in the plant. The inspectors noted that the scoping, evaluation, inspection, and corrective actions for this issue were comprehensive and performed in a timely manner.
c.
Conclusion j
The inspectors concluded that the licensee was proactive in identifying, scoping,
)
evaluating, and correcting the Westinghouse HFA and FA molded case circuit breakers
'
failure to fully latch. Engineering and other station personnel exhibited a rigorous and systematic approach to resolving this deficiency. The inspectors also concluded that i
the licensee performed an acceptable operability determination for the breakers.
E2.3 (Closed) URI 50-277(278)/97-05-03Auxiliarv Contact Failures a.
Insoection Scoce (375511 The inspectors reviewed the licensee's analysis of circuit breaker auxiliary contact problems initiated after the failure of two high pressure service water (HPSW) system motor operated valves to stroke closed on July 1,1997.
b.
Observations and Findinas The failure to close of the Unit 2 HPSW system dischargo isolation valves (MO-2-89A and MO-2-10-89C) and other historical auxiliary contacts failures prompted PECO engineering to initiate an analysis of auxiliary contact failures. Auxiliary contacts are used in both safety and non-safety related applications to actuate valves, provide indication, and provide permissive signals.
Using PEP 10006255, engineering personnel analyzed auxiliary contact performance
,
back to 1984 to find causes and identify corrective actions to reduce or prevent additional failures. Data taken and reviewed included the resistance, humidity, and temperature of selected auxiliary contacts in the plant. Engineering personnel concluded that there was not an environmentallink to any contact fa!!ures. Failed -
j auxiliary contacts sent to the Valley Forge Laboratory revealed no common mode of failure.
The inspectors reviewed the data for the environmental study of the selected auxiliary contacts and found no correlation of failure or change in resistance related to temperature or humidity. Although resistance changes had occurred, the operation of i
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. the equipment and the resistance reading changed very little in the contacts used for -
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operation.
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During an independent review'of auxiliary contact failures, the inspectors noted that the HPSW discharge valve to the 'A' residual heat removal heat exchanger (MO-3-10-
.089A) failed to stroke open on April 16 and on May 14,'1993. Further investigation of
- the action request for this issue revealed that there were problems with the maintenance performed after the April failure. After the May failure, maintenance personnel identified and corrected the previous maintenance problems. The inspectors noted no additional maintenance issues or contact failures.
c.
Conclusions After reviewing the failure of two high pressure service water (HPSW) system motor operated valves to stroke closed on July 1,.1997, the inspectors determined that the licensee had made adequate progress in analyzing auxiliary contact failures. The inspectors concluded that corrective actions were responsive to previous auxiliary contact failures, particularly the more recent data gathering and mock-up testing.
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IV. Plant Sunocrt
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R1 Radiological Protection and Chemistry (RP&C) Controls R1.1 Imolementation of the Radioloaical Environmental Monitorina Proaram '
a.
Inspection Scoos (84750)
The following areas of the REMP were assessed and reviewed:
selected sampling and analysis procedures;
viewed selected sampling locations and discussed sample techniques;
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operability of air samplers and water compositors;
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calibration status of air samplers;
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the results of the 1997 Land Use Census; the 1996 annual Radiological Environmental Operating Report; e
' the analytical data (1997 and 1998) for sample frequency and analysis
q requirements specifit.o in the Offsite Dose Calculation Manual (ODCM); and
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the ODCM, Revision 10.
- I b.
Observations and Findinas i
The inspector reviewed selected sampling and analysis procedures and toured selected sampling stations. The procedures provided appropriate guidance to perform REMP '
.-
.
tasks.- The air sample equipment were operable during'1997 to present, as evidenced
'
in the sample logs and sample analysis results. The air sample equipment calibration results were within tolerance, and calibrations were performed within the frequency specified in the procedure. The inspector reviewed the water compositor sample logs L
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a
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fro n the intake and discharge structures. The water compositor sample lines j
experienced freezing during the first quarter of 1997. The inspector noted that the
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licensee performed compensatory grab sampling according to the ODCM..The inspector also noted that the licensee had issued an Action Request (AR) and installed heat tracing to help prevent freezing in the future'. (See Section R7.1 of this inspection report for further details.). The inspector noted that the licensee had installed a new water compositor at the Conowingo Dam, a downstream location. The inspector noted that the compositor was operating and collecting samples as required.
l The inspector reviewed the.1997 Land Use Census. The census was performed during the growing season, and met the requirements of the ODCM.
The inspector reviewed the Annual Radiological Environmental Monitoring Report for 1996. ' The report included results of the environmental monitoring program, land use census, and interlaboratory comparison program, as required. Overall, the reports provided a comprehensive summary of the results of the REMP around the Peach -
Bottom site and met the TS (Section 5.6.2) reporting requirements.
c.
Conclusions
. Based on the above review, the insmetor concluded that (1) the licensee's overall performance was good, (2) tSe equipment was well maintained and calibrated, and (3)
' the REMP was effective.
R1.2. Imolementation of the Meteoroloaical Monitorina Proaram
)
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I a.-
Insoection Scone (84750).
.
The following areas of the MMP were assessed and reviewed:
the meteorological monitoring equipment calibration procedures;
_ the calibration methods and results from 1997; l
. *
. data availability and data acquisition status reports;
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Yearly Tracking Action Request (AR) for 1997; and
weekly functional checks for 1997.
- b.
Observations and Findinas The inspector verified system operabRity, calibration _ status of the meteorological '
instrumentationiand reviewed the associated calibration and functional check procedures.' The wind speed, wind direction, and temperature sensors on the towers J
_
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were operable. ' Equipment availability for data acquisition was greater than 90% as evidenced by the Yearly Tracking AR for 1997, the monthly status reports, and the weekly functional checks. - The calibration procedures provided the appropriate guidance to perform calibrations and functional checks. The reviewed calibration results were within the licensee's acceptance criteria. Calibrations and functional checks were performed withia the frequency recommended in Regulatory Guide 1.23, j
' Revision 1.
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Conclusion l.
. Based on the above review, the inspector concluded that (1) the equipment availability.
' for meteorological data scquisition was high and (2) performance in maintaining'and.
- calibrating the meteorological monitoring tower and associated instruments was good.
-R2'
Status of RP&C Facilities and Equipment l
R2.1 Hich Radiation Locked Door inspection (71710)
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- During tours of.the facility, the inspectors observed the postings and' tested -
approximately 12 to 15 doors to high radiation areas. All doors tested were properly locked and areas were properly posted as required by TS Section 5.7...The inspectors
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ldid not identify any deficiencies with high radiation areas during these tours.
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R7
- Quality Assurance in RP&C Activities
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' R7.1 Quality Assurance Audit Proaram l
a.
insoection' Scone (84750)
I I
The inspector reviewed the following audit reports:
)
Nuclear Quality Assurance (NOA) audit reprt (#A1067413),1997;
Primary Analytical Contract Laboratory, GPU Environmental Radioactivity
- Laboratory, (ERL) audit report (#A1096921),1997; NQA Surveillance Reports of the MMP,1997; and
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Nuclear Procurement issues Committee (NUPIC) audit report (#9601047),1996.
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b.
. Observations and Findinas
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.
Several suggestions for improvement to the REMP and MMP were documented in the
.
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NQA ' audit (#A1096921)and the surveil. lance reports,'respectively. The inspector j
reviewed the suggestions and determined that the suggestions were appropriate.. One
. finding and one recommendation was identified in the NQA audit (#A1067413)
I regarding the operability of the intake and discharge water compositors due to freezing
{
during the first quarter oi 1997. A Performance Enhancement Program (PEP) issue was generated, as appropriate, as a result of the finding. (The PEP is the licensee's j
corrective action process.) The finding was of no safety significance. The inspector reviewed the licensee's corrective actions regarding the PEP issue. ' The corrective
- actions and follow up evaluations were thorough and appropriate, and the PEP issue was closed.
The NUPIC audit of Teledyne Browne Engineering Environmental Services (TBE) was performed by GPU Nuclear, Niagra Mohawk, and Omaha Public Power District. TBE is the licensee's secondary contract laboratory for quality control. The audit assessed the
.
adequacy and implementation of the laboratory's quality' assurance program. Eight j
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findings were identified during the audit. The findings were of no safety significance.
! All the findings had been closed during a NUPlC follow up audit, c.
Conclusion E
Based on the above reviews, the inspector determined that (1) the' licensee met the QA
,
!'
audit requirements and (2) the audits were thorough and of sufficient depth to assess the. quality of the REMP and MMP.
R7.2 Quality Assurance of Analvtical Measurements l
l a;
Inspection Scone (84750) -
i The inspector reviewed the following aspects of the QA/QC program of the primary i
l.
. analytical contract laboratory:
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- the semiannual QA report;
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the results of quality control program (split, duplic' ate, blind samples);.
j the results of the Interlaboratory Comparison (cross-check) program.'
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b.
Observations and Findinas
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The QA/QC program for analyses of REMP samples is conducted by the primary
analytical contract laboratory,'GPU Environmental Radioactivity Laboratory (ERL). The ERL has interlaboratory and intralaboratory QC' programs. The QC program consisted of.
, i p
. measurements of blind duplicate, spike,'and split samples. The inspector reviewed the -
L results and noted that the results were within the licensee's acceptance criteria. The.
l laboratory continued to participate in the EPA Cross-Check Program and the
.I interlaboratory Comparison Program provided by a vendor laboratory (Analytics, Inc.).
The inspector reviewed the results of these programs. The results were within the EPA'
j and licensee's acceptance criteria, r_espectively.
The ERL published a Quality,.
l Assurance report semi-annually. The inspector reviewed the reports from 1996 and l
1997.L Comparisons of QC data listed in the semi-annual Quality Assurance reports l
were within the ERL's acceptance criteria.
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i c.
Conclusion'
j l
Based on the above review, the inspector determined that (1) the contractor's QA/QC
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i program for the REMP provided effective validation of analytical results and (2) the _
j program is capable of ensuring independent checks on the precision and accuracy of,
'
the measurements of radioactive materialin environmental media.
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.R8.
Miscellaneous Radiological Protection issues
. R8.1 (Closed) URI 50-277(2781/97-01-03:Use of Draft NUREG Reportability Guidance for'
LEBA
' On February 13,1997, a health physics technician found high radiation area door #
192, " Reactor 2,135, "Drywell Equipment Hatch Access (Neutron Door)"" unlocked.
The high radiation area inside door #192 was greater than 1000 mr/hr. This unlocked
- door was a violation of Technical Specification 5.7, which required that high radiation areas above 1000 mr/hr be locked. Technical Specification 5.7 is located in the -
administrative section of the technical specifications. A non-cited violation (NCV) was issued for this issue.
L The licensee determined that a Licensee Event Report (LER) per 10 CFR 50.73 was not required for this issue based on guidance contained in the Second Draft of NUREG 1022, Revision 1, " Event Reporting Guidelines 10 CFR 50.72 and 50.73." The
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inspectors questioned the use of a draft NUREG to avoid reporting a violation of a requirement from the administrative section of the technical specifications.
In January'1998, Revision 1 to NUREG 1022 was issued. Section 3.2.2 of this revision contained guidance for submitting LERs required per 10 CFR 50.73(a)(2)(1)(B)
. involving any operation or condition prohibited by the plant's Technical Specifications.
Section 3.2.2 specifically noted that an administrative procedure violation, such as -
failure to lock a high radiation area door was not reportable under 10 CFR 50.73.
Based.on the guidance in the latest revision to NUREG 1022, the inspectors have no further concerns with this issue.
V. Manaaement Meetina X1 Exit Meeting Summary The inspectors presented the inspection results to members of licensee management at the conclusion of the inspection on March 19,1998. The licensee acknowledged the findings presented.
The inspectors asked the licensee whether any materists examined during the inspection should be considered proprietary. No proprietary information was identified.
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Review of Updated Final Safety Analysis Report (UFSAR) Commitments l
l A discovery of a licensee operating their facility in a manner contrary to the Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a special focused review that compares plant practices, procedures and/or parameters to the
. UFSAR descriptions. While performing the inspections discussed in this report, the inspectors reviewed the applicable portions of the UFSAR that related to the areas inspected. The inspectors verified that the UFSAR wording was consistent with the observed plant practices, procedures and/or parameter O ATTACHMENT 1 LIST OF ACRONYMS USED
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i action request (AR)
action statement (AS)
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administrative guideline (AG)
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APRM gain adjust factor (AGAF)
as-low-as-reasonably-achievable (ALARA)
average power range monitors neutron (APRMs)
central alarm system (CAS)
control rod drives (CRDs)
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control room emergency ventilation (CREV)
control room monitor (CRM)
core power and flow log (CPFL)
core spray (CS)
core thermal power (CTP)
{
counts per second (CPS)
design input document (DID)
electro-hydraulic control (EHC)
eleventh refueling outage (3R11)
]
emergency core cooling system (ECCS)
{
emergency diesel generator (EDG)
emergency operating procedures (EOP)
emergency service water (ESW)
end-of-cycle (EOC)
engineering change request (ECR)
engineered safety feature (ESF)
GPU environmental radioactivity laboratory (ERL)-
final safety analysis report (FSAR)
fitness-for-duty (FFD)
fix-it-now (FIN)
functional testing (FT)
General Electric Company (GE)
general proceduro (GP)
generic letter (GL)
health physics (HP)
high efficiency particulate (HEPA)
high pressure coolant injection (HPCI)
high pressure service water (HPSW)
hydraulic control unit (HCU)
improved TS (ITS)
independent safety engineering group (ISEG)
inservice inspection (ISI)
inspector followup items (IFls)
inntitute of electrical and electronic engineers (IEEE)
instrument and control (l&C)
intermediate range monitor - neutron (IRM)
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intrusion detection systems (IDS)
licensee event report (LER).
. limited senior reactor operators (LSROs)
limiting conditions for operation (LCO)
load tap changer (LTC),
local leak rate test (LLRT)
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loss nf coolant accident (LOCA)
loss of off-site power (LOOP)
low pressure coolant injection'(LPCI)
lubricating oil (LO)
main control room (MCR)
meteorological monitoring program (MMP)
modification (MOD)
motor generator (MG)
nuclear maintenance division (NMD)
nuclear measurement analysis and control (NUMAC)
a nuclear quality assurance (NOA)
. NRC approved physical security plan (The Plan)
nuclear procurement issues committee (NUPIC)
nuclear review board (NRB)
offsite dose calculation manual (ODCM).
offsite power start-up source #2 (2SU)
J offsite power start-up source #3 (3SU)
operator display assemblies (ODA)
Peco Energy (PECO)
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performance enhancement program (PEP)
plant operations review committee (PORC) -
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post-maintenance testing (PMT)
.' power adjustment factor (PAF)
primary containment (PC).
primary containment isolation system (PCIS) -
. primary containment isolation valve (PCIV)
printed circuit board (PCB)-
programmable read only memory (PROM)
. protected area (PA)
quality assurance (QA)
. quality control (OC)
radiation monitoring system (RMS)
- radiologically controlled area (RCA)
radiological' environmental monitoring program (REMP)
radiological protection and chemistry (RP&C)
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- rated thermal power (RTP)
i y
. reactor core isolation cooling (RCIC)
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reactor engineer (RE)-
reactor feed pump (RFP)
J reactor operator (RO)'
' reactor protection system (RPS)
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Attachment 1
regulatory guide (RG)
reliability centered maintenance (ROM)
safety evaluation report (SER)
safety related structures, system and components (SSC)
scram solenoid pilot valve (SSPV)
secondary alarm system (SAS)
- secondary containment (SC)
security force members (SFM)
senior reactor operator (SRO)
shift update notice (SUN)
source range monitor (SRM)
spent fuel pool (SFP)
standby gas treatment (SGTS)
station blackout (SBO)
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structure, system and component (SSC)
surveillance requirement (SR)
surveillance test (ST)
)
systems approach to training (SAT)
)
technical requirements manual (TRM)
technical specification (TS)
teledyne browne engineering-environmental services (TBE)
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temporary plant alteration (TPA)
total integrated dose (TID)
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training and qualification (T&O)
i turbine control valve (TCV)
turbine stop valve (TSV)
unresolved item (URI)
updated final safety analysis report (UFSAR)
vehicle barrier system (VBS)
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verification and validation (V&V)
wide range neutron monitoring system (WRNMS)
INSPECTION PROCEDURES USED IP 37551:
Onsite Engineering Observations IP 52001:
Digital Retrofits Receiving Prior Approval IP 61726:
Survoillance Observations IP 02707:
Maintenance Observation IP 71707:
Plant Operations IP 71750:
Plant Support Observations
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IP 84750:
' Radioactive Waste Treatment, and Effluent and Environmental Monitoring IP 92700:
Onsite Follow of Written Reports of Nonroutine Events at Power Reactor Facilities -
IP 92901:
Operations Followup IP 92902:
Followup - Engineering IP 92903:
Followup - Maintenance IP.92904:
Plant Support Followup IP 93702:
Prompt Onsite Response to Events at Operating Power Reactors ITEMS OPENED, CLOSED, AND DISCUSSED Opened
' 50-277/98-01-01 VIO Inadequate Verification of Alarin Acknowledgement Due to Control Room Supervisor Leaving Work Station Without Relief 50-278/98-01-01 VIO Inadequate Verification of Alarm Acknowledgement Due to Control Room Supervisor Leaving Work Station Without Relief 50-277/98-01-02 VIO Missed Technical Specification Surveillance Requirement Test for Verification of Proper Flow in the Recirculation Loops.
50-277/98-01-03 VIO Missed Technical Specification Surveillance Requirement Test for Verification of Core Flow as a Function of Thermal Power 50-277/98-01-04 URI HPCI Post-Maintenance Testing Procedural inadequacies 50-277/98-01-05 VIO Unexpected Trip of Unit 2 Main Turbine During Start-up 50-278/98-01-06 VIO Unit 3 Exceeded Licensed Power Level Due to inaccurately Calibrated Feedwater Temperature Instruments 50-277/98-01-07 NCV. Logic System Testing Deficiencies -
50-278/98-01-07 NCV Logic System Testing Deficiencies Closed 50-277/97-01-01 URI Core Thermal Power Greater Than Technical Specification Limit 50 278/97-01-01 URI. Core Thermal Power Greater Than Technical Specification Limit 50 277/97-02-01 URI Station Qualified Reviewer Use/ Review of Open Changes to the UFSAR 50-278/97-02-01 URI Station Qualified Reviewer Use/ Review of Open Changes to the UFSAR 50-277/2-97-05 LER Technical Specification Non-Compliance Associated with Rod
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Block Contact Testing 50-278/2-97-05 LER Technical Specification Non-Compliance Associated with Rod Block Contact Testing 50-277/2-97-08 LER Logic System Functional Testing Did Not Meet All Technical Specification Surveillance Requirements 50-278/2-97-08 LER Logic System Functional Testing Did Not Meet All Technical
.
. Specification Surveillance Requirements 50-277/98-01-07-NCV Logic System Testing Deficiencies 50-278/98-01-07 NCV Logic System Testing Deficiencies
- 50-277/97-01-03 URI Use of Draft NUREG Reportability Guidance for LERs
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Attachment 1
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50-278/97-01-03 URI Use of Draft NUREG Reportability Guidance for LERs 50-277/97-08-03 URI. Missed Technical Specification Surveillance Requirement Test for l
Verification of Proper Flow in the Recirculation Loops
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50-277/97-08-04 URI Unexpected Trip of Unit 2 Main Turbine During Start-up
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