ML20140D205
| ML20140D205 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 06/04/1997 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20140D148 | List: |
| References | |
| 50-277-97-02, 50-277-97-2, 50-278-97-02, 50-278-97-2, NUDOCS 9706100291 | |
| Download: ML20140D205 (61) | |
See also: IR 05000277/1997002
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U. S. NUCLEAR REGULATORY COMMISSION
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REGION I
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' Docket / Report No. 50-277/97-02
License Nos. DPR-44
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50-278/97-02
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Licensee:
PECO Energy Company
P. O. Box 195
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Wayne, PA 19087-0195
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- Facility Name:
Peach Bottom Atomic Power Station Units 2 and 3
Dates:
March 8,1997 - May 3,1997
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Inspectors:
W. L. Schmidt, Senior Resident inspector
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M. J. Buckley, Resident inspector
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B. D. Welling, Resident inspector
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D. J. Florek, Sr. Operations Engineer
S. L. Hansell, Resident inspector
A. X. Lohmeier, Senior Reactor Engineer
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N. T. McNamara, Emergency Preparedness Specialist
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J. W. Shea, NRR Project Manager
G. C. Smith, Sr. Security Specialist
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Approved By:
Richard R. Keimig, Chief
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Reactor Projects Branch 4
Division of Reactor Projects
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9706100291 970604
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ADOCK 05000277
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EXECUTIVE SUMMARY
Peach Bottom Atomic Power Station
inspection Report 97-02
This integrated inspection report includes aspects of resident and region based inspection
of routine and reactive activities in: operations; surveillance and maintenance; engineering
and technical support; and plant support areas.
Overall Assurance of Quality:
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PECO Energy (PECO) operated both units safely over the period.
The inspectors conducted a pro'blem identification and resolution inspection during this
period and concluded that:
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The performance enhancement process (PEP) effectively identified and resolved
problems, contributed to improved plant operation, and has had a positive impact on
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the reduction of plant challenges. The station identified and documented problems
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at a low threshold, and management supported the identification of problems. The
screening of PEP issues was generally performed according to station guidance.
Documentation of PEP reviews and investigations were typically very detailed and
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complete, and PEP corrective actions were completed in a timely manner.
While the inspectors identified two areas for improvement in the PEP process,-
station management had properly identified other needed improvements and had
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undertaken some good enhancement initiatives. The inspectors concluded that
these efforts reflected a strong, self-critical approach toward the improvement of
the PEP process.
The plant material condition was excellent. The continued plant preservation and
good housekeeping activities reflected on management's and workers'
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commitments to maintain the high standards throughout the plant. Equipment
problems were identified and addressed in a timely manner.
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PECO implemented an excellent program for reviewing and incorporating operating
experience feedback into the station processes, which was supported strongly at
the daily management meetings.
PECO me'1agement has maintained a strong self-assessment culture throughout, the
station, resulting in continued improvement in plant performance.
The independent safety engineering group (ISEG) performed effective and
independent assessment of station activities and the nuclear review board (NRB)
contributed significantly to the self-assessment and corrective action process.
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The nuclear quality assurance (NOA) division fulfilled the program requirements
described in Appendix D of the updated final safety analysis report (UFSAR) and
implemented several positive initiatives.
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Plant Ooerations:
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Operators performed wellin response to several plant transients, including an electro-
hydraulic control system reservoir low level and several recirculation system problems with
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a 30% runback and a manual reactor scram. The inspectors noted that, as in the recent
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past, non-safety-related equipment failures continued to challenge the operators.
PECO implemerited the improved technical specifications (ITS) in accordance with the NRC
safety evaluation, including controls over relocated or new requirements under the 50.59
process for changes. Both the PECO assessment findings and the NRC inspection findings
indicated that the administrative controls for the ITS and safety function determination
programs could be enhanced.
In review of 50.59 changes to the ITS bases, the inspector noted that some of the PECO
station qualified reviewers were not aware of the method to review the UFSAR changes
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made, but not yet incorporated into the UFSAR. An unresolved item was identified to
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evaluate PECO's review of this issue once completed. (Unresolved item 50-277&278/97-
02-01).
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The inspector closed Unresolved item 96-04-02 after concluding that the TS provided no
specific administrative controls over normally closed primary containment valves and blind
fianges in the drywell and that all the required valves were in the correct position.
However, the linking of known valve positions in December 1995 to the administrative
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controls for drywell access in the surveillance procedure was weak.
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Maintenance:
The inspectors concluded that PECO performed a modification to the high pressure coolant
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injection system (HPCI) steam line effectively and in accordance with approved procedures.
This modification reduced the magnitude of the steam line vibration.
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PECO personnel conducted the observed surveillance tests (STs) well demonstrating good
communications and plant systems knowledge. However, as noted below in the
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engineering section, the inspectors identified several instances where either the basis for
STs was not fully understood or documented, or where the STs specified to meet TS
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requirements did not fully verify operability.
The inspectors verified, for selected safety-related components, that PECO conducted the
inservice testing (IST) program according to code requirements and NRC guidance. The
licensee had initiated some IST program enhancements consistent with NUREG-1482
guidelines.
During maintenance activities in the plants, the inspectors identified that PECO failed to
properly implement its established procedure for scaffolding construction (M-C-700-335,
" Scaffold Request; Erection; and Disassembly"). This resulted in failure to maintain safety-
related components in an evaluated condition, since scaffolding was in contact with or in
close proximity to the components. The scaffolding amounted to an unanalyzed temporary
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modification to the plant. The inspectors considered this a violation of 10CFR50 Appendix
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8, Criterion 111, DESIGN CONTROL, which requires that PECO evaluate changes in the
design of the plant prior to implementation. (Violation 50-277,50-278/97-02-02).
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In a review of overtime usage by maintenance workers, the inspectors found that PECO
failed to document prior approval for severalindividuals that worked greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
in a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period during emergency diesel generator maintenance in February 1997. The
inspectors found that this issue was of low safety consequence and determined that it met
the conditions for a non-cited violation in accordance with Section IV of the NRC
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Enoineerina:
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PECO conducted the station blackout (SBO) line testing well. However, the test
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acceptance criteria could not be clearly justified or specifically linked to the design load as
specified in the PECO calculations. Further, the UFSAR and technical requirements manual
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(TRM) contained no detail on line loading or test acceptance criteria. The inspector
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considered this issue unresolved pending review of PECO actions to address these issues.
(Unresolved item 97-02-03).
The inspectors found that operations' understanding and engineering's review and
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communications were weak, in review of a condition where PECO found the Unit 3 C
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reactor feed pump high water reactor vessel level trip function circuit inoperable. The trip
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function circ 9itry was incapable of operating, due to a blown fuse, from April 4 to April 14,
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exceeding the TS limit of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to restore the high water level trip capability or be <
25% reactor pows. TNs violation was cited due to the time that it took for PECO to
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understand this condition fully. (Violation 97-02-04) The inspectors noted that the safety
significance of this issue was limited since only the C feed pump was affected (i.e., the
main turbine and the two other feed pump high reactor vessel level trips were operable).
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Further, the inspectors found the daily channel check ST test specified for the high reactor
vessel level trip channel check to be inadequate, in that it did not verify power available to
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the feed pump trip logic. The inspector considered this an unresolved item pending review
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of PECO's actions to identify other circuits that need power to operate. (Unresolved item
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97-02-05)
The inspectors reviewed the system configuration and operability testing on the emergency
diesel genesator (EDG) room ventilation systems, finding that STs did not verify the
capability of the system to perform at its design function under design conditions of
outside air temperature and EDG loading. However, the EDGs have criteria to carry the
design load for an hour during testing which gives reasonable assurance that the EDGs
have been operable. This issue remains unresolved pending review of PECO's actions to
develop ventilation operability criteria and testing to support EDG operability. (Unresolved
item 97-02-06)
PECO responded well to a minor leak from the Unit 3 high pressure service water (HPSW)
system. Engineering staff fo!! owed GL 90-05 guidance for assessing the structural
integrity of the affected piping and made plans for code repairs, both of which were
performed in a prompt, thorough manner. However, initial plans for delaying the
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augmented piping inspections discussed in GL 90-05 were judged to be non-conservative.
Other planned and completed corrective actions were considered very good. The
inspectors will review PECO's failure analysis once it is completed.
The discrepancy, identified by the inspectors, between the IST acceptance criteria and the
design and licensing basis data for the core spray (CS) system minimum flow rate revealed
weaknesses in both engineering documentation and performance. Further, engineering had
missed opportunities to identify this discrepancy during recent design basis reviews.
The Core Engineering inspection was completed during this period and concluded the
following:
Engineering comprehensively pursued the resolution of the battery rupture issue,
including a corrective action program believed by PECO to preclude future battery
explosions under these conditions.
PECO took adequate corrective actions to address weak engineering oversight and
training of modification contractors as noted in inspection report 96-08.
Unresolved item 95-018-01 will remain open, pending successful completion of the
scheduled program to determine the root cause for and correct the excessive HPCI
pipe vibration. Some success has been achieved in reducing the vibration.
The general appearance of facilities was clean and orderly.
The system managers were knowledgeable about the functioning and management
of their respective systems.
The inspector found that PBAPS engineering continues to provide a well coordinated
effort to identify, publicize, and resolve chronic plant issues.
The UFSAR verificetion review to date has been a well managed program to provide
documents with corrected errors, absent of ambiguity, and an accurate reflection of
the structural and operating requirements of the plant.
The quality of the rewritten DBDs was good. The absence of many review
signatures in the documents is an inspector follow-up item, pending location of the
original review documents or completion of the review process. (Inspector Follow-
up item 97-02-07).
Plant Support:
Emergency Preparedness:
The licensee continues to maintain a very good emergency preparedness program, as
evidenced by:
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Management and organizational changes did not have an adverse impact on
program operation or implementation.
The emergency response plan and implementing procedures were current and
effectively implemented, but the quality control process is somewhat weak. During
a review of recent emergency plan and procedure changes, the inspector found
some minor discrepancies and errors.
With the exception of the alarming dosimeters at the TSC, the inspector concluded
that the licensee maintained a very good inventory program and that the emergency
facilities and equipment were operationally ready.
The emergency response organization personnel training and qualifications were
current.
Quality assurance audits and surveillance satisfied NRC requirements. However, the
audit report lacked detail to support its conclusions.
The licensee maintains a very good rapport with off-site agencies and support
organizations.
The inspector closed inspector Follow-up Item 95-14-03, regarding EP organization
changes.
Security:
The inspector determined that the licensee was conducting its security and safeguards
activities in a manner that protected public health and safety, and meeting Security Plan
commitments, as follows:
The protected area (PA) intrusion detection systems (IDSs) met commitments and
NRC requirements.
The alarm stations and communications met commitments and NRC requirements.
Security equipment repairs were timely. The use of compensatory measures was
found to be appropriate and minimal. The maintenance and testing being
implemented were reasonable to ensure equipment reliability.
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Training had been conducted in accordance with the Plan and was considered
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effective.
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Management provided very good support for the program.
Licensee controls, including results, indicated that performance errors were being
minimized and that controls were effectively implemented to identify and resolve
potential weaknesses.
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The inspector reviewed the corrective actions associated with and closed Violation 96-11-
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VII
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TABLE OF CONTENTS
EX E C UTIVE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TABLE OF CO NTENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . viii
SUMMARY OF PLANT ACTIVITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
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O PE R ATI O N S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01
Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 Manual Reactor Scram and Startup - Unit 3 . . . . . . . . . . . . . . . . 1
01.2 Single Loop Operation following Recirculation Pump Trip -
Unit 3...........................................
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01.3 Conclusions
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03
Improved Technical Specification (ITS) Implementation (Tl 2515/130)
(OPEN) Unresolved item 97-02-01; Station Qualified Reviewer
Use/ Review of Open Changes to the U(> dated Final Safety Analysis
Repon ............................................... 2
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Operator Knowledge and Performance . . . . . . . . . . . . . . . . . . . . . . . . . 5
04.1
Unit 2 EHC Reservoir Low Level Event . . . . . . . . . . . . . . . . . . . . 5
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Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
07.1 Problem identification and Resolution Inspection
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Miscellaneous Operations and issues . . . . . . . . . . . . . . . . . . . . . . . . . 17
08.1 (CLOSED) Unresolved item 96-04-02: Verification of Primary
Containment Valves and Blank Flanges in the Drywell . . . . . . . . 17
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MAINTENANCE AND SURVEILLANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
M1
- Conduct of Maintenance and Surveillance . . . . . . . . . . . . . . . ... . . . . 17
M1.1 Conduct of Maintenance
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M1.2 High Pressure Coolant Injection System Modification Work -
Unit 3..........................................
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M1.3 Surveillance Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
M1.4 Conclusions - Conduct of Maintenance and Surveillance . . . . . . 18
M2
Maintenance and Material Condition of Facilities and Equipment
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M2.1 Scaffolding Installation and Control (OPEN) Violation 97-02-02:
Scaffolding Erected Causing Unanalyzed Conditions
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M3
Maintenance Procedures and Documentation . . . . . . . . . . . . . . . . . . . 20
M3.1 Inservice Testing Program Review . . . . . . . . . . . . . . . . . . . . . . 20
M8
Miscellaneous Maintenance issues (92902) . . . . . . . . . . . . . . . . . . . . 21
M8.1 Use of Overtime During Unplanned Maintenance
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TABLE OF CONTENTS (Continued)
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ENGINEERING..............................................
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General Engineering Comments . . . . . . . . . . . . . . . . . . . .
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E1.1
Station Blackout Line Testing . . . . . . . . . . . . . . . . . . . . . . . . . 22
E1.2 Battery Cell Rupture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
E1.3 Improper Documentation of E42 Bus Modification Finding . . . . . 23
E2
Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 24
E2.1
(UPDATE) Unresolved item 95-18-01; High Pressure Coolant
injection Steam Line Vibration
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E2.2 (OPEN) Violation 97-02-04; inoperable Reactor Feed Pump
High Reactor Level Trip (OPEN) Unresolved item 97-02-05;
Review of Instruments that Require Electrical Power to Perform
a Technical Specification Function
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E2.3 Emergency Diesel Generator Ventilation Review (OPEN)
Unresolved item 97-02-06: Operability Testing of the
Emergency Diesel Generator Ventilation Systems . . . . . . . . . . . 26
E2.4 High Pressure Service Water System Piping Leak . . . . . . . . . . . 27
E2.5 Core Spray System Minimum Flow Rate
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E4
Engineering Staff Knowledge and Performance . . . . . . . . . . . . . . . . . . 30
E4.1
Walkdown of Plant Facilities with System Managers . . . . . . . . . 30
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Quality Assurance in Engineering Activities . . . . . . . . . . . . . . . . . . . . 31
E7.1
Updated Final Safety Analysis Report Review Program (37550) . 31
E7.2 Design Basis Document Revision; (OPEN) Inspector Follow item
97-02-07; Review of Design Basis Document Review and
Approval Proce ss . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31
E8
Miscellaneous Engineering issues . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
E8.1
PBAPS Site Equipment and Material Focus Prograr"
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IV
P LA N T S U PPO RT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
P1
Conduct of Emergency Preparedness Activities
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P1.1
Effectiveness of Licensee Controls
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P2
Status of Facilities, Equipment and Resources
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P2.1
Operational Readiness of Emergency Facilities . . . . . . . . . . . . . 33
P3
Procedures and Documentation . . . . . . . . . . . . . . . . . . . . . .
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P5
Staff Training and Qualification
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P6
Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
P7
Quality Assurance in Emergency Preparedness Activities . . . . . . . . . . . 37
P8
Miscellaneous issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
P8.1
Updated Final Safety Analysis Report inconsistencies . . . . . . . . 38
P8.2 IFl 50-277,278/95-14-03, Adequacy of the EP Program After
Management and Organizational Changes . . . . . . . . . . . . . . . . 39
S1
Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 39
S7
Status of Security Facilities and Equipment
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S2.1 Protected Area Detection Aids . . . . . . . . . . . . . . . . . . . . . . . . 39
S2.2 Alarm Stations and Communications . . . . . . . . . . . . . . . . . . . . 40
S2.3 Testing, Maintenance and Compensatory Measures . . . . . . . . . 40
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TABLE OF CONTENTS (Continued)
Security and Safeguards Staff Training and Qualification
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Security Organization and Administration . . . . . . . . . . . . . . . . . . . . . . 41
S7
Quality Assurance in Security and Safeguards Activities . . . . . . . . . . . 42
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S7.1 Effectiveness of Management Controls . . . . . . . . . . . . . . . . . . 42
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- S8.1 Review of Updated Final Safety Analysis Report
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S8.2 (CLOSED) Violation 96-11-01/EA 96-144, 243; " Failure to
Properly Control Safeguards Information"
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M AN AG EM ENT M EETIN G S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
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Management Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . 43
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SUMMARY OF PLANT ACTIVITIES
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OPERATIONS
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Conduct of Operations'
PECO Energy (PECO) operated both units safely over the period. Unit 2 operated at near
rated power. Unit 3 entered the period in single loop operation, foliowing a low lubrication
(lube) oil level alarm on the B recirculation pump. On March 9, as operators lowered
reactor power to allow a drywell entry to correct the low lube oil level, the A recirculation
pump tripped, due to a faulty non-safety-related circuit breaker position switch, and
operators manually scrammed the unit. PECO returned Unit 3 to operation on March 12.
While operating at 100% power on April 9, the B recirculation pump tripped unexpectedly
due to a fault to ground in the power cabling to the motor generator set. The unit operated
safety in sino% loop operation until April 10 when the B recirculation pump was returned to
service following repairs. On April 21, the recirculation system automatically reduced flow
to 30% (runback) following the failure of a non-safety related feedwater system control
computer power supply. Following replacement of the power supply, operators returned
the unit to 100% power.
01.1 Manual Reactor Scram and Startup - Unit 3
On March 9, the operators performed wellin inserting a manual scram when the running A
recirculation pump tripped following the transfer of house loads, during a downpower
operation. Operators lowered reactor power to less than 20% to allow drywell entry to
investigate and correct a low lube oil level in the B recirculation pump, which had been
secured on March 8.
PECO found that a faulty circuit breaker position monitoring switch for the 13 KV generator
supply breaker to the recirculation pump power supply caused the trip. Operators had
transferred the power supply to offsite power in preparation for securing the turbine
generator; however, following the turbine trip, due to the faulting position switch, the
recirculation pump also tripped. The faulty switch allowed the recirculation pump logic to
believe that the generator continued to supply the pump at the time that the turbine
tripped.
Maintenance technicians repaired the faulty position switch and entered the drywell to
correct the low oil level in the B recirculation pump. Operators restarted the unit on March
13, folluwing these corrective actions.
The inspectors observed that operators conducted the shutdown and start-up activities -
well. This included documentation of cool-down and heat-up rates, and monitoring of
reactor parameters.
1Topacal heaenga such as 01, MS, etc., se used m eccordance with the NRC standsered reactor mopection report outhne Indwedual reports are not expected to address aN Outhne
topecs,
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01.2 Single Loop Operation following Recirculation Pump Trip - Unit 3
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On April 9, Unit 3 entered single loop operation following the tripping of the B recirculation
pump, on a power fault to ground. The protective relaying functioned properly and
operators performed wellin reducing and stabilizing reactor power. Maintenance
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technicians found the fault in one of the five electrical power supply lines from the
associated transformer to the recirculation pump motor generator set. The failed line was
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isolated and the recirculation pump successfully restarted on April 10.
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01.3 Conclusions:
Operators performed wellin response to several plant transients and a manual reactor scram. The inspectors noted that, as in the recent past, non-safety-related equipment
failures continued to challenge the operators.
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03
Improved Technical Specification (ITS) Implementation (Tl 2515/130) (OPEN)
Unresolved item 97-02-01: Station Qualified Reviewer Use/ Review of Open
Changes to the Updated Final Safety Analysis Report
a.
Scope:
The inspector verified that the improved technical specification (ITS) reflected the
appropriate provisions or conditions of the NRC safety evaluation. The inspector put
particular emphasis on PECO procedures and controls for those requirements relocated
from the custom TS to other documents. The inspector used Temporary Instruction (TI)
2515/130, " improved Standard Technical Specification Implementation Audits," to perform
the review.
Specifically, the inspector reviewed:
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The administrative procedures related to the ITS conversion process, as listed in
Attachment 1, Section 1.
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The relocated, modified, or deleted technical specification requirements listed in
Attachment 1, Section 2 were used to verify use of appropriate controls.
The new surveillance requirements listed in Attachment 1, Section 3 were used to
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verify adequate development of new procedures.
Self-assessment audits performed on the ITS conversion and implementation
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process.
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The new program for Safety Function Determination and Control of the TS Bases.
b.
Observations and Findinas:
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The items relocated from the technical specifications were relocated into a technical
requirements manual (TRM), plant procedures, updated final safety analysis report
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(UFSAR), offsite dose calculation manual (ODCM) or core operating limits report (COLR).
To control and track the specific relocated items, PECO developed a technical specification
relocation matrix and placed the matrix in the TRM . The matrix was consistent with the
changes approved in the NRC safety evaluation.
All relocated technical specification items reviewed were addressed in a procedure or
document that had controls which would require a 50.59 determination for changes. Plant
procedures were found that addressed all the new surveillance requirements reviewed.
UFSAR changes were incorporated into the UFSAR or scheduled for the 1997 UFSAR
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update.
PECO used its commitment tracking system to annotate specific sections of plant
procedures for relocated items. This commitment tracking system provided an
identification method such that any change to this item would require a 10 CFR 50.59
evaluation.
Administrative controls to make changes to the technical specification bases, TRM, ODCM,
COLR, and technical specification relocation matrix in the TRM were acceptable and were
controlled under the 50.59 process.
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However, some specific concerns were identified. Not all station qualified reviewers (SQR)
were aware of the method to review the posted changes to the UFSAR (those changes
made but not yet been placed into the book). As a result,50.59 determinations made by
these individuals may not have been properly assessed for the safety analysis report
impact determination. During this inspection, PECO staff took actions to notify all the SQR
reviewers at Peach Bottom, Limerick and Chesterbrook of the need and method to review
the posted UFSAR changes. In addition, PECO developed a performance enhancement
process (PEP) item to track this issue, including review of completed 50.59 reviews. Ans
unresolved item was identified to evaluate the review.
Changes made to the technical specification relocation matrix in the TRM were acceptable
with the exception of item number 3.3.8.1 R04 related to the trip level settings for 4KV
Emergency Bus Undervoltage Relay. This item was deleted from the technical specification
relocation matrix in PORC 95-72 R-005. This relay was notably different than the other
items contained in PORC 97-72 R-005. The inspector determined that the trip level setting
for this relay, which was changed to N/A in the technical specification, should have
remained in the technical specification relocation matrix and its procedure so annotated,
j
with an appropriate commitment tracking number. A procedure to verify the trip level
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< setting of this relay existed, but without appropriate commitment tracking. In addition, the
50.59 determination which made the change did not address the UFSAR pages associated
with this relay. PECO indicated that the procedure will be appropriately annotated.
Technical specification bases 3.6.1.3 was missing a reference 5 that was added in a prior
revision and had incorrectly been removed in a subsequent revision. Revision 5 was cited
in the body of the text. PECO could not explain the reason for deletion of revision 5 from
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the technical specification bases. A PEP issue was identified for further evaluation by
PECO.
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The technical specification relocation matrix in the TRM had numerous errors. Some
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procedure numbers were missing and others were incorrectly identified. This was one of
the findings in the March 1997 PECO Energy self-assessment as well this inspection.
!
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Additional information from the NRR Project Manager identified that the NRC staff did not
consider the technical specification relocation matrix a controlled document fo!!owing
verification that all relocated items were appropriately implemented. PECO Energy had not
decided on the future use of the matrix based on the findings of both the PECO Energy
audit and NRC inspection.
!
AA-C-5, " Preparation and Control of Procedure and Guidelines" was not updated to reflect
ITS. PECO Energy generated a procedure change tracking number for this item.
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PECO Energy agreed that the following documents could be enhanced:
t
A-C-4 to correct a UFSAR reference
I
A-C-43, A-C-79-2 and LR-C-1-1 to reflect use of TRM
Surveillance test (ST)-O-003-450 and ST-O-60F-405 to add an annotation for
,
commitment tracking
FH-6C and FH-35 to add consistent wording for operations with the potential for ,
draining the reactor vessel.
PECO Energy revised the operations manual to address the new technical specification
.
program for safety function determination. The program was acceptable. The inspector
had a minor concern regarding the scope of the determination if only the exhibits in the
operations manual were used. The program developer did not intend for the exhibits in the
operations manual to be the complete representation of support or supported systems. For
1
example, some support systems (remote shutdown instrumentation and emergency diesel
< generator (EDG) fuel oil, lube oil or starting air) were not listed. OM-P-12.2 or the exhibits
could be enhanced to state the limitation on the use of the exhibits.
4
c.
Conclusions:
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I
PECO implemented ITS in accordance with the NRC safety evaluation. All of the
implementing procedures reviewed contained the relocated or new technical specification
requirements and were under the control of the 50.59 process for changes. The
administrative controls for the ITS and safety function determination programs could be
' enhanced based on both the PECO assessment findings as well as by the NRC inspection
.l
findings.
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The most significant conclusion was that some of the PECO station qualified reviewers
were not aware of the method to review the UFSAR changes made, but not yet
incorporated into the UFSAR, when performing their 50.59 determinations. As a result,
50.59 determinations made by these individuals may not have been properly assessed for
the safety analysis report impact determination. PECO was reviewing the 50.59
,
evaluations made by these individuals to confirm the determinations were properly
assessed for safety analysis report determination. An unresolved item was identified to
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evaluate this review when completed. (Unresolved item 50 277&278/97-02-01).
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04
Operator Knowledge and Performance
04.1 Unit 2 EHC Reservoir Low Level Event
a.
Scooe: (71707)
On April 1, the Unit 2 reactor operators (ROs) responded well to a valid electro-hydraulic
control (EHC) reservoir low level alarm annunciator. Reactor power was reduced from
100% to approximately 48% due to a leak at a main turbine control valve (TCV) drain line.
The inspectors observed the operators' and plant support personnel's response to the EHC
problem from the main control room,
b.
Observations and Findinas:
The reactor operators immediately recognized the EHC low level alarm and notified the shift
manger (SM) and control room supervisor (CRS), and the plant equipment operators (EOs),
and referenced the overhead alarm responso procedure. The EOs verified the validity of
the alarm noting to the ROs that the level had dropped six inches from the previous day.
Preparations were started to add a 55 gallon barrel of EHC fluid to the reservoir. The alarm
response procedure noted that the EHC pumps should be secured if EHC reservoir level
reached 23 inches. The overhead annunciator alarmed at approximately 24.1 inches. The
reservoir level dropped to its lowest level of 23.7 inches as the first barrel of EHC fluid was
added to the reservoir.
The SM conservatively directed the control room personnel to reduce reactor power to
90% based on the indication of a leak. After reviewing the EHC piping and valve
diagrams, the operators determined that the leak could be isolated and repaired if the main
~ turbine was removed from service. Based on this the SM continued to display a
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conservative operational approach by directing the crew to continue the power reduction to
below 50%. At approximately 72% sower the RO swapped electrical power supplies from
the auxiliary transformer to the Unit 2 feed buses in anticipation of removing the main
turbine from service. The swapover was performed c<rrectly using system operating
procedure (SO) 53.2.A-2, Rev. 8, " Transferring Unit 2 Auxiliary Loads from the Unit
Auxiliary Transformer to the Startup Feed Buses."
The ROs routinely used good self-checking techniques prior tc control board manipulations
to ensure operations of the correct component. Throughout the plant evolution all control
room personnel used clear communications and appropriate repeat backs. The CRS
directed a controlled power reduction and provided plant status updates to the entire
control room team at key points in the evolution. The SM stood back and maintained a
broad perspective during the shift response.
Troubleshooting % forts revealed that the oil leak had started following swapping of the
EHC reservoir cooling heat exchangers. The heat exchanger that was placed inservice was
physically smaller than the previous in service heat exchanger, which resulted in a higher
back pressure in the TCV oil drain line and TCV sealleakage. The leak stopped when the
original heat exchanger was placed back in service. The plant personnel have initiated PEP
10006817, to evaluate and determine the root cause(s) for the leak event.
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c.
Conclusions:
The operators responded excellently to the EHC reservoir low level. The SM and CRS
displayed excellent command and control as noted by the SM's conservative decision to
reduce reactor power in anticipation of the possible main turbine removal from service.
The CRS and SM provided clear direction and timely crew briefings throughout the
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evolution. RO performed manipulations well, and consistently used "self-checking"
techniques. Overall, communications were good and the response by the equipment
operators, engineering, health physics and other support groups was excellent. The
response reflected on good training programs and operation management's enforcement of
high operational standards and attention to detail.
07
Quality Assurance in Operations
07.1 Problem Identification and Resolution Inspection
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a.
Scope: (40500)
From March 31 to April 4, three inspectors conducted a performance based and
programmatic evaluation to determine the effectiveness of PECO's controls in identifying,
resolving, and preventing problems that affect station safety or are adverse to quality at
Peach Bottom. The inspection was performed using the guidance of Inspection Procedure
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40500, " Effectiveness of Licensee Controls in Identifying and Resolving Problems."
O.7.1.1 Performance Enhancement Program
The primary process used at PBAPS for the identification and resolution of conditions
adverse to quality is the PEP. This process is also used to identify other performance
enhancement opportunities. PECO procedure LR-C-10, " Performance Enhancement
Program," provides direction for the implementation of the PEP program. The overall
process remained essentially the same as that described in NRC inspection report Nos. 50-
277 & 278/95-80. The inspectors reviewed a number of completed and in-progress PEP
reports and discussed these issues with station personnel. Also, the inspectors
interviewed several station personnel on the implementation of the PEP program.
New PEP issues were presented at the daily leadership meetings. Appropriate managers
accepted the issues, and discussions of the PEPS were usually very good.
The inspectors reviewed a sample of the PEPS written during the past year and identified
no unaddressed operability or reportability concerns. In addition, the inspectois reviewed
licensee reportability evaluations for a few PEPS that the licensee had initially viewed as
potentially reportable and found the determinations of not reportable to be acceptable.
The PEP documentation was recorded on a computer-based system that also provided for
the tracking of corrective actions as well as reviews of corrective action effectiveness.
The tracking system for PEP issues was well-monitored, and allowed for advance
notification for those PEP review actions that were coming due. As such, the PEP
4
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corrective actions were generally performed in a timely manner, and overdue PEP
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evaluations were infrequent.
The inspectors found that the documentation of PEP reviews and investigations was
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typically very detailed and complete, for example:
l
PEP 10005984, which described an unexpected roll of the high pressure coolant
'
injection (HPCl) turbine during testing on August 13,1996, included several pages
of lessons learned, root cause analysis, and other discussion. This PEP report also
documented over 15 corrective action evaluations. The corrective actio% for PEP
issues typically included thorough reviews for the generic implications or the
potential extent of condition for the issues.
PEP 10006519, which was initiated on January 23,1997, for a missed NRC
commitment, described an extensive review of commitment files for 1993 through
1996. Based on this review, the licenseo was able to conclude that the missed
commitment was an isolated occurrence.
The experience assessment coordinator performed the initial screening of identified PEP
j
issues with the assistance of other experience assessment staff members. The assignment
of the PEP significance level and classification for the degree of review was generally
1
performed according to the program guidance. Typically, the more significant issues
required a detailed review including a root cause analysis, while those of lower significance
required less investigation. The Level 1 issues are the most significant conditions adverse
to quality that could result in a major impact on plant safety or a substantial hazard to the
safety and welfare of the public or plant personnel. Level 2 issues involve moderate
challenges to plant or personnel safety. Level 3 issues represent minor challenges to plant
i
or personnel safety and Level 4 issues are related to process enhancements. Examples of
Level 1, 2, 3, and 4 issues are described in PEP procedure exhibit LR-C-10-3.
The inspectors noted that some of the significance level assignments, however, were not
consistent with the PEP program criteria contained in Exhibit LR-C-10-3. For example, five
i
PEPS (10005059,10005960,10005944,10005636 and 10004681) associated with
operational transients (OTs) should have been assigned a significance Level 2, but were
issued at Level 3. In contrast, two OT PEPS (10004732 and 10004767) were assigned a
Level 2 classification as recommended by the PEP procedure criteria. The Unit 2 EHC oil
low reservoir event discussed in Section 04.1 above, PEP No. 10006817, was a recent
example of a Level 2 plant issue that was classified as a Level 3 PEP. The EHC event
resulted in a power reduction of greater than 100 megawatts electric (MWe) for more than
one day. Exhibit LR-C-10-3 lists the above criteria as an example of a Level 2 PEP. The
PEP was classified as a Level 3 issue on April 3,1997. Although some flexibility in
assigning significance level was allowed, the justification for the lower significance level
was not always documented. While these inconsistencies had minimalimpact on the
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scope of the investigation for the issues, they did reflect a minor degree of informality in
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adhering to the written program guidance.
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The inspectors determined that station personnel generally identified PEP issues at a low
threshold, and management support of PEP issue identification was good. The inspectors
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noted that the total number of PEP issues identified had decreased from 975 in 1994, to
625 in 1995, and 512 in 1996. Through interviews with several personnel, the inspectors
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found that this decrease was due to a combination of factors, including: 1) the combining
of severalindividual problems on a single PEP report during the critique of significant
maintenance or outage work,2) issuance of soma self-identified PEPS with more than one
issue, and 3) improvements in overall station performance. The inspectors also noted that
the percentage of self-revealing and consequential problems had not increased during this
time period. Based on these factors, reviews of numerous PEPS, and tours of the station,
the inspectors concluded that despite the decrease in number of identified PEP issues, the
threshold for issue identification remained low.
The inspectors noted that PEP lssue Review Leaders (PIRLs) were trained in the PEP
process and in root cause analysis. Most PIRLs were members of the engineering
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organization, or were maintenance or operations supervisors. PIRLs led the investigations,
assigned corrective action evaluations, and reviewed the corrective actions. The PIRLs
also assigned root cause codes for lower significance PEPS or performed root cause
analyses for significant issues. The inspectors reviewed the root cause analyses for
several Level'2 PEPS and found them to be well-documented with clear descriptions of -
causal factors.
During interviews of personnel who had been PIRLs, the inspectors noted a number of
comments related to a high level of administrative burden for PEP issues. Some personnel
indicated that the burden of performing PEP reviews had the potential for affecting their
decision on whether to identify issues as PEPS, particularly items of lower significance.
'
' This possible reluctance to use the PEP process was of concern, because the licensee may
j
miss opportunities to identify and document lower level, precursor issues.
i
Station managemtsnt had recognized the PEP process burden and took actions to reduce it.
Specifically, the experience assessment group had adopted some enhancements to the PEP
process, including: 1) documenting PEP issues related to a common maintenance or
system outage together as part of a " critique PEP," 2) assigning experience assessment
personnel as mentors for significant PEP issues, and 3) providing a more streamlined,
" tabletop" resolution process for minor issues. Additionally, experience assessment was
developing a simplified PEP issue identification form that would require only brief
descriptions of problems instead of a detailed narrative. The inspectors reviewed fouro
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critique PEPS finding them to include several maintenance / planning improvement issues and
~
~ some valuable, positive feedback for the reviewed activity. Although these PEP process-
enhancements should reduce the amount of unnecessary PEP documentation, they had not
been incorporated in the PEP procedure and some personnel were not fully aware of them.
In addition to the administrative burden reouctions, the station had identified other
opportunities for improvement in the PEP process. The inspectors considered these to be
good self-assessment observations, reflecting an appropriate self-critical approach toward
improving the PEP process. Examples included:
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9
The experience assessment group had observed that many PEP narratives did not
fully describe the root cause(s) of issues
Some root cause codes assigned were not supported by the facts in the PEP reports
Some reviews of human performance issues did not fully investigate the cause of
the human performance errors or inappropriate actions
The inspectors reviewed recent PEP trending reports and noted that the station had
suspended the quarterly root cause code trending report. This was done as a result of
comments by station management and the Nuclear Review Board that the trending reports
provided little value. The experience assessment group was considering alternative
trending analyses or reports that would provide more useful information.
The inspectors noted two instances in which the station missed opportunities to identify or
correct issues before they became more significant.
PEP 10006509, initiated on January 21,1997, identified that feedwater temperature
inputs to reactor heat balance calculations had been calibrated incorrectly. This
occurred in June 1995, due to faulty test equipment. The PEP investigation noted
that technicians had questioned the test results at that time because they had to
make adjustments on all four feedwater temperature channels, and the test
equipment was subsequently found to be out of tolerance. Although the PEP
investigation was thorough, the PEP did not identify that this long-term issue could
have been averted had the technicians documented their initial questions or
potential concerns formally, such as on a PEP. Thus, this issue represented a
missed precursor event.
PEP 10005120, dated February 13,1996, could have resulted in a less significant
event if more timely corrective actions were taken to address the incorrect shear pin
size from an earlier PEP, No. 10005059, dated February 4,1996. The shear pins at
the inner travelling screen are physically larger than the outer screen pins. The first
PEP noted that incorrect replacement shear pins were stored at the inner screen
location. Subsequently, the wrong shear pins were located at the inner screens for
the second event and resulted in additional complications during the restoration of
the circulating water system. After the second event, the proper shear pins and a
measuring gauge were placed at both the inner and outer screen locations. The
inspectors performed a walkdown of both areas and noted that the proper pins were
still in place to address the original problem. In addition, the second PEP did not
reference the first PEP issue or recognize the missed opportunity to correct the
problem if more timely corrective actions would have been taken.
07.1.2
Plant Material Condition
During individual tours and tours with EOs, the inspectors found excellent plant material
and housekeeping conditions. The continued plant preservation and good housekeeping
activities reflected on management's and workers' commitment to maintain the high
standards throughout the plant. Equipment problems were identified and addressed in a
.
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10
timely manner. Examples of the housekeeping high standards were particularly noticeable
in the maintenance shop and control room areas.
07.1.3
Operating Experience Feedback
The inspectors found that PECO implemented the operating experience review in
conformance with procedure LR-C-4, " Operating Experience Assessment Program."
The inspectors determined that the operating experience (OE) databases were informative
and helpful in enhancing PBAPS personnel knowledge of industry information. Employees
could access the database program to view information on operating experiences. The
experience assessment department reviewed the nuclear network computer database each
j
morning to retrieve information about industry events that may add value, and forwarded
the applicable information unedited to the operations department, training and the
independent safety engineering group (ISEG). The experience assessment group reviewed
the OE data and performed a thorough screen of the information to determine items
applicable to PBAPS, and shared that with the site directors and mangers from all
departments at the morning leadership meeting.
Action items were assigned to appropriate departments to incorporate the OE information
into the PBAPS processes. The experience assessment group tracked the OE action items
and associated corrective actions to ensure the timely inclusions into station program and
procedures, in addition, PBAPS's rnonthly publication, "PECO Nuclear Experiences,"
provided lessons learned for both successes and failures at Limerick and Peach Bottom
stations.
07.1.4
Self Assessment
The inspectors reviewed self assessment aciivities that Peach Bottom and PECO Nuclear
conducted in 1995,1996 and 1997. Procedure AG-CG-19, "Self Assessment Guideline"
provides general guidance on self assessment activities and articulates the general
philosophy for self assessment activities at the station and department levels.
1997 Self Assessment Activities
The station performed numerous self assessment activities on an annual basis and included
the following: 1) annual station wide; 2) individual department; 3) experience assessment
- evaluations; 4) post-Technical Specification (TS) maintenance critiques; 5) operations and
maintenance worker observation cards; and 6) the overview PORC process. The
assessments evaluated the areas that would benefit from additional attention to improve
the station performance for both hardware and human performance issues. The self
assessment evaluation results relied mainly on the PEP data, worker input, and department
trends from the previous year. The focus areas established to improve performance were
visible in the work place and clearly understood by the applicable station personnel. In
addition, the operations and maintenance departments used observation cards to provide
real time assessment for the work activities. Management routinely monitored the
effectiveness of the self assessment focus areas to ensure the corrective actions were
providing the desired change.
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The post TS limiting condition for operation (LCO) maintenance critique program was an
example of the continued strong commitment to the self assessment process. The work
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week managers conducted a post job critique for LCO maintenance activities and
documented the results, both positive and areas for improvement, in detail as a " Level 4"
PEP item. As needed, corrective actions were assigned to improve plant performance. The
inspectors reviewed a sample of PEP documents and concluded that the post LCO
maintenance critiques developed meaningful and valuable insight to limit safety system out
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of service time and have resulted in improved LCO maintenance performance.
e
1996 Self Assessment Activities
The inspectors reviewed the January 1996 " Nuclear Generation Group Evaluation of Peach
Bottom Atomic Power Station" (Peach Bottom Corporate Assessment) and the December
1996 "PECO Nuclear Evaluation of Limerick Generating Station" (Limerick Corporate
Assessment). The Peach Bottom assessment team comprised staff from Chesterbrook,
Limerick and several outside organizations. The assessment concluded that overall station
performance was strong with several areas requiring attention, including the modification
process and human performance. The assessment found widespread, healthy attitudes
toward safety, accountability and teamwork, good horizontal and vertical communications,
and that supervision and management were accessible and responsive to assisting
personnel in eliminating barriers to satisfactory job performance.
The inspectors also reviewed the Limerick Corporate Assessment, conducted in November
1996. That assessment concluded that while overall station performance was strong,
there were several elements in the Limerick station culture that needed prompt
management attention. Examples of concerns included management presence in the field
(perceived as looking for mistakes or checking schedule rather than coaching) and
perceptions that the PEP process was primarily punitive.
The inspectors conducted interviews with PECO staff and sought feedback on the
applicability of the significant weaknesses identified in the LGS Corporate Assessment to
Peach Bottom. The inspectors interviewed the leader of the Limerick Corporate
Assessment Team and the Peach Bottom Vice President. The interviews revealed that
PECO clearly acknowledged that some portion of the work force was experiencing the
types of disaffections described in the Limerick Assessment and understood the potential
impact of these problems. The inspection team found through interviews that senior
management is focussed on understanding the scope, origin and nature of work force
concerns and is committed to addressing them.
o
Follow-Up of Previous Self Assessments
The inspectors reviewed the 1995 Station Self Assessment conducted at the direction of
the site Vice President by all organizations onsite. The management focus areas identified
in the 1995 Self Assessment included:
o
Work Control - emphasis on plant operation leading role in work control,
including operator responsibilities to control work and remain aware of work
activities.
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Administrative Procedures - reduce complexity of certain administrative
procedures to make them less cumbersome to use and therefore improve
compliance with those procedures.
Corrective Action Process - PEP process viewed as disciplinary tool by some
staff. Plant management identified the need to provide greater emphasis on
post-job critiques to prevent events and thereby reduce post event
investigations. Identified need to address individual human performance
,
problems outside of PEP process and refocus PEP on issues that provide
organizational learning.
i
Modification Control - trending problem with installation and testing of
station modifications.
e
Human Performance -identified need for increased emphasis on " healthy
skepticism" and " questioning attitude."
The inspectors reviewed the follow-up to these focus areas. With regard to concerns
about the PEP process, the inspectors determined that PECO had implemented the concept
of critique PEPS as a means of identifying and capturing lessons learned from major and -
routine work events. The critique PEP process provides for all significant participants in a
work event to meet at the conclusion of the event ta document those parts of the activity
that went well and those parts of the process where improvements can be made. PECO
has observed that the plant staff is more willing to identify performance weaknesses in a
collaborative review of an entire job that identifies positive as well as negative aspects of
performance than they would during investigations that focussed exclusively on negative
events. PECO recently recognized that the mechanics of the PEP process including the
software is cumbersome and may in itself be a barrier to use of the process. The
inspectors confirmed this during interviews with front line managers, some of whom relied
on others more familiar with computers to interface with PEP programs for their
organization. PECO indicated that they are considering changes to the PEP process that
would remove this kind of barrier.
The inspectors conducted a limited review of followup to department and division level self
assessment findings from the 1995 station wide self assessment. The inspectors observed
that self assessment findings were assigned Action Request (AR) numbers and due dates
in PIMS. The inspectors did not observe any ARs from the 1995 assessment that had not
been closed out.
07.1.5
Safety Review Committees
Plant Ooerations Review Committee
The inspectors reviewed selected plant operations. review committee (PORC) meeting
minutes for the last year and attended one PORC meeting. The meeting discussed a
planned change to the operations manual to allow for the implementation of a dual-role
senior reactor operator / shift technical advisor, and proposed changes to technical
specifications regarding localleak rate testing. The inspectors observed that the PORC
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13
members demonstrated a proper safety perspective and maintained a questioning attitude
during the meeting. The inspectors concluded that PORC critically reviewed safety-related
activities consistent with station procedures and regulatory requirements,
o
Indeoendent Safety _hai erina Grouc
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The inspectors reviewed the activities of the ISEG for the period September 1995 through
December 1996. During that period, ISEG performed assessments for a broad range of
activities and events. ISEG completed 13 formal reports during 1996 and a number of
brief reviews which were de ,umented on a monthly basis. The brief reviews generally
documented the results of ISEG field observation activities and less in depth reviews of
plant processes. The reports reviewed by the inspectors demonstrated that ISEG
performed thorough evaluations and challenged issues when appropriate.
4
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Of particular note was a series of reports on various aspects of a steam leak detection
system modification. ISEG reviewed the adequacy of the design inputs, the
implementation of single failure and separation criteria in the modification design, the
!
adequacy of acceptance test scope, and the adequacy of surveillance tests to meet
Technical Specification Channel Functional Test requirements. The series of reports was
critical and identified problems with the implementation of separation criteria, the adequate
use of design input documents by the modification team and concerns about the scope of
acceptance testing specified in the modification package. ISEG determined that specific
concerns in each of these areas for the steam leak detection modification were addressed
before completion of the modification. The ISEG review of the steam leak detection
modification provided a detailed horizontal review of the modification process and
supported concerns with the modification process that were identified through other means
during that time frame.
ISEG report production was a concern to NQA management and the NRB in 1995 as
documented in NRC Inspection Report No. 95-80. At that time, the ISEG organization was
undergoing a organizational change that included a reduction in the number of ISEG
members from five to three and the organization of ISEG as a self-directed work team. In
December 1996, ISEG presented a self-assessment to NRB regarding its effectiveness,
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ISEG concluded that the self directed work team approach was working well and that the
!
formalISEG report production was appropriate for the number of engineers. NRB
concluded that ISEG reports were very well written. NRB also commented that measures
j
could be taken to improve ISEG report timeliness and thereby report production.
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Nuclear Review Board
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The inspector attended the March 6 nuclear review board (NRB) meeting held at Limerick
and reviewed meeting minutes for NRB meetings from December 1995 through February
1997. NRB is responsible for assessing the safety of plant operations and plant
management's ability in identifying actual and potential problems and, in implementing
)
corrective actions to prevent recurrence. From the review of the meeting minutes and
1
observation of the March meeting, the inspectors concluded that NRB provides a critical
review of plant operations, engineering, quality assurance and PECO Nuclear performance
issues.
s
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14
For example, NRB discussion of Boraflex-related issues, as described in the minutes of the
January 1997 NRB meeting showed a balanced discussion of technical and management
issues associated with PECO's handling of Boraflex concerns and included critical reviews
of the PEP process at the February 7,1997 meeting.
The membership of NRB was stable over the course of 1996 and early 1997. The
inspectors previously reviewed the expertise of the members and concluded that the NRB
membership provides a broad range of expertise. The inspectors observed that the NRB
recognized a periodic need to augment expertise in the areas of fuel issues and chemistry
as well as in basic root cause analysis.
Nuclear Quality Assurance Audits and Assessments
The inspectors reviewed surveillance reports and assessment reports generated by NQA
during 1996 and early 1997, and found them generally well written with a broad range of
topics.
The inspectors observed that PECO has, consistent with industry trends, transferred
responsibility for many QA activities to the responsible line organizations over the past few
years. The inspectors reviewed the efforts of the NQA organization to monitor the
adequate performance of QA functions by the line organizations. One example of this was
the resolution of conditions adverse to quality (CAQs) which are identified by the NQA
organization.
CAQs identified by NQA are classified as corrective action requests (CARS) or deviations
and are tracked by the line organization through the PEP process. Closecut of corrective
actions for CARS formerly required the concurrence of the NOA organization. As part of
the organizational changes made in conjunction with the NEEDs process, closeout of CAR
related corrective actions was transferred to the line organization responsible for the issue.
A transition monitoring plan was implemented by NQA to review the line organization
closeout of CARS. The transition plan included a review of 100% of CAR corrective
actions by NQA after the line organization had indicated the corrective actions was closed.
During the transition phase, if NQA determines that the closure of the corrective action
would have been rejected by NOA, the line organization is contacted and requested to
address the closeout deficiencies identified by NOA. NQA has determined that the reject
rate for CAR corrective action closure remains at approximately the same level as it did
prior to transfer of closecut responsibility to the line organization, indicating that line
organization closure was no less thorough than would have been the case prior to the
transition. NOA is evaluating discontinuation of the transition monitoring progrart .
In Surveillance Report PSR-96-086, NQA documented a review of the corrective action
effectiveness review provisions of the PEP process. LR-C-10 requires that the affected
organization perform a determination of the probability that completed corrective actions
1
will prevent the recurrence of an issue. Such determination is required for alllevel 1 and 2
PEPS and all CARS. NQA reviewed 24 PEP issues and determined that the corrective
action effectiveness review criteria and closure documentation were generally adequate
with a few discrepancies noted. NQA indicated that it will continue to monitor this aspect
of the PEP process.
.
4
15
The inspectors reviewed meeting minutes of the NOA Engineering Oversight Activity. This
activity was an initiative by which representatives from the Chesterbrook, Limerick and
Peach Bottom NQA organizations coordinate activities with regard to oversight of PECO's
engineering activities. The inspectors reviewed minutes of periodic meetings of the NOA
working leads in which NOA working leads identify emerging issues and areas for future
NQA focus. Finally, the inspectors reviewed guidance from the manager of the Peach
Bottom Quality Division which identified NQA overall focus areas in 1996. Among areas
listed for NQA focus were modification process implementation and maintenance rule
implementation.
Assessment AO967118, conducted in October and November of 1996,
identified a number of weaknesses in rnodification installation activities. The
inspectors concluded that NOA initiatives with regard to modification issues
have been consistent with the problems identified in this area over the past
few years and that assessment and review activities in this area have been
focussed and provided a contribution to the improvement of quality in this
area.
With respect to the maintenance rule implementation, the inspectors
s
determined that NQA had participated in a line organization assessment of
the Peach Bottom maintenance rule and NOA conducted a surveillance of
maintenance rule maintenance preventable functional failures in 1995, NQA
did not conduct an independent assessment of the maintenance rule program
prior to July 1996 implementation. Subsequently, the NRC issued a Severity
Level ill violation to Peach Bottom for maintenance rule implementation
weaknesses in 1996.
The inspectors concluded that NOA identification of and focus on programmatic focus
.
areas was good overall although additional evaluation of maintenance rule implementation
could potentially have identified the weaknesses in this area prior to the NRC inspection.
c.
Conclusions:
PEP Process
The Peach Bottom station corrective action and root cause analysis programs contributed
to improved plant operation and have had a positive impact on the reduction of plant
challenges. The improvements were related to the following indicators: an increased
number of self identified problems; improved plant capacity factor; reduced equipment
outage times; and initiatives such as " experience assessment PEP mentoring," critiques,
and "just in time experience feedback" programs.
The inspectors concluded that the PEP program was effective in identifying and resolving
problems. The inspectors found that the station identified and documented problems at a
low threshold, and management supported the identification of problems. The screening of
PEP issues was generally performed according to station guidance. Documentation of PEP
reviews and investigations were typically very detailed and complete, and PEP corrective
actions were completed in a timely manner.
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The inspector noted two areas for PEP program improvement.
PECO missed opportunities to identify or correct issues before they became
significant,
Although some flexibility existed in assigning the initial PEP significance level, the
e
justification for the lower significance level was not always documented. The
procedure inconsistencies reflected a minor degree of informality in adhering to the
written program guidance.
Station management had properly identified opportunities for improvement in the PEP
process and had undertaken some good enhancement initiatives. The inspectors
concluded that these efforts reflected a strong, self-critical approach toward the
improvement of the PEP process.
Plant Material Condition
The plant material condition was excellent. The continued plant preservation and good
L
housekeeping -activities reflected on management's and workers' commitments to maintain
the high standards throughout the plant. Equipment problems were identified and
addressed in a timely manner. Examples of the housekeeping high standards were
particularly noticeable in the maintenance shop and control room areas.
Operating Experience
PBAPS's prcgrams for reviewing and incorporating operating experience feedback into the
station processes were excellent and supported strongly at the daily management
meetings. Industry information from various sources was forwarded to a wide distribution
of plant personnel to maximize the ability learn about generic problems and minimize the
occurrence at Peach Bottom.
e
Self-Assessment
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PBAPS management has maintained a strong self-assessment culture throughout the
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station. Continued improved plant performance was noted as a result of the strong
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commitment to perform and monitor the meaningful self assessment evaluations.
Safety Review Committees and Nuclear Quality Assurance
i
The inspectors concluded that ISEG was performing effective and independent assessment
'
of station activities and the nuclear review board contributes significantly to the self-
assessment and corrective action process. The Peach Bottom Quality Assurance Division
fulfills the program requirements described in Appendix D of the Peach Bottom UFSAR.
Assessment activities, including identification of specific and programmatic deficiencies
and tracking of these deficiencies was considered good. Initiatives such as the transition
monitoring of CAR closecut and the engineering oversight activity were positive.
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08
Miscellaneous Operations and Issues
08.1 (CLOSED) Unresolved item 96-04-02: Verification of Primary Containment Valves
and Blank Flanges !n the Drywell
This item related to PECO Energy's use of administrative controls to satisfy SR 3.6.1.3.5
when entering Mode 3 from Mode 4 with the containment de-inerted. SR 3.6.1.3.5
concerns position verification of manual primary containment isolation valves and blind
flanges inside primary containment. On June 24,1996, PECO performed ST-O-007-340-3
to satisfy SR 3.6.1.3.5 prior to entering mode 3 from mode 4 with the containment de-
)
inerted, using clearance CLR 95006238 as a basis for completion. The clearance
prevented drywell access during power operations since December 4,1995. PECO
believed that since there was no entry into the drywell since December 4,1995, the
position of the valves and blind flanges could not have changed. Use of this logic and type
of administrative control can satisfy the administrative control permitted in SR 3.6.1.3.5.
However, June 24,1996 was the first time that SR 3.6.1.3.5 was performed following the
implementation of the Improved Technical Specifications. The surveillance procedure did
not document that all the valves and blind flanges were known to be in the required
position in December 1995. Subsequent to the performance of the ST-O-007-340-3,
PECO verified, using check-off lists and other clearance work, that all of the required
valves and blind flanges were known to be in the proper position following the Unit 3
outage in October 1995. In addition, following the forced outage in March 9,1997, PECO
personnel performed ST-O-OO7-340-3 by actual position verification of all required valves
and blind flanges, noting no discrepancies.
The inspector concluded that the linking of known valve positions in December 1995 to the
administrative controls for drywell access in the surveillance procedure was weak.
,
However, since no specific administrative controls were defined in the technical
specification and all the required valves were in the correct position, a violation of technical
specification SR 3.6.1.3.5 did not exist. This item was closed,
11
MAINTENANCE AND SURVEILLANCE
M1
Conduct of Maintenance and Surveillance
M1.1 Conduct of Maintenance
The inspectors observed the conduct of portions of the following maintenance work, and
identified no negative issues:
WO C0176136, Repair Leaking HPSW Pipe Below RO-3789B (Unit 3)
M1.2 High Pressure Coolant injaction System Modification Work - Unit 3
a.
Scone (62707)
The inspectors observed portions of maintenance work on the Unit 3 high pressure coolant
injection (HPCI) system associated with a modification to reduce steam line vibration.
.
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b.
Observations and Findinas
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The inspectors observed maintenance work performed under work order C0172662, which
modified hangers and replaced some small bore piping on the HPCI steam supply piping.
The modification was part of a program to reduce the excessive vibration observed on this
piping (URI-95-018-01). The program to reduce the vibration is also discussed in section
E2.1 of this report.
The inspectors noted appropriate use of procedures and good work controls. Maintenance
personnel were familiar with the job scope and task requirements. The inspectors
. identified no negative issues.
Following HPCI system restoration, the inspectors observed that the magnitude of the
piping vibration had been reduced. Some minor vibrations still exists, and the licensee
plans to install vibration measurement devices to help determine the future corrective
actions.
M1.3 Surveillance Activities
- The inspectors observed the conduct of portions of the following surveillance tests (STs),
identifying no negative issues:
Residual heat removal (RHR) Heat Exchanger Performance test
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RHR Heat Exchanger Performance Calculation test
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E3 EDG Load Run test
Calibration Check of reactor core isolation cooling (RCIC) Steam Line High test
Average power range monitoring (APRM) System Calibration During Two Loop
Operation test
e
Core spray (CS) Loop B Pump, Valve, Flow, and Cooler Functional and inservice test
M1.4 Conclusions - Conduct of Maintenance and Surveillance
The inspectors concluded that PECO performed the HPCI steam line modification work
effectively, in accordance with approved procedures. This modification reduced the
magnitude of the steam line vibration.
PECO personnel conducted the observed STs well demonstrating good communications
and plant system knowledge.
However, as noted in sections E1.1, E2.2, E2.3 and E2.5, the inspectors identified several
instances where either the basis for surveillance testing was not full understood and
documented or where the surveillance test specified to meet TS requirements did not fully
verify operability.
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M2
Maintenance and Material Condition of Facilities and Equipment
M2.1 Scaffolding installation and Control (OPEN) Violation 97-02-02: Scaffolding Erected
Causing Unanalyzed Conditions
Scone:
During a plant tour on March 21, the inspectors noted scaffolding installed in contact with
or in very close proximity (less than an inch) to safety-related equipment in the Unit 3 A'
and C RHR pump rooms. A review of the design and procedural requirements for scaffolds
followed to verify the adequacy of this temporary construction with potential impact on
safety-related systems and components,
b.
Observations and Findings:
During the walk down, the inspectors identified a concern with scaffolding constructed in
,
contact with or in close proximity (within 1 inch) to safety-related components. The
inspectors related these concerns during a meeting with PECO management. The items of
concern, which had not been reviewed by PECO engineering to assess the possible effects
on safety-related equipment, were as follows:
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MO-3-10-089A limitorque operator
"A" RHR room cooler emergency service water (ESW) piping and flow indicator
Vent line to RHR heat exchanger with HV-3-10-165A
Seismic support to MO-3-10-089C
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Electric supply cable to "A" RHR cooler fan
RHR CLG coil 3A out throttle VV DP
MO-3-10-15C motor
RHR heat exchanger discharge sample line
On March 24, PECO engineering discussed the conditions of scaffolds in the "A" and "C"
RHR pump rooms and concluded that a close inspection should be done. During this
inspection, engineering identified unreviewed deficiencies between the installation and the
scaffold specification M-C-700-335, " Scaffold Request; Erection; and Disassembly" in the
RHR pump room and at Unit 3 HPCI. PECO, through M-C-700-335, set standards for the
control of deviations from quality standards for design of scaffolds. PECO engineering
concluded that no operability concerns were associated with the scaffolding erected in the
Unit 3 "A" and "C" RHR pump rooms, but PECO chose to correct scaffold deviations
immediately in lieu of rigorous evaluations to determine the resultant effects on safety-
related components.
On March 26, the inspectors found other deviations while touring the D HPSW pump bay,
including scaffolding up against the electrical connector box to the Unit 2 D HPSW pump
motor, and other concerns as follows:
Scaffolding touching the conduit from PS-02380B HPSW 2B/D pumps discharge
header pressure switch
Proximity to the oil line from the Unit 2 D HPSW pump
.
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20
PECO performed a stand-down of the scaffold team craft, planners, and supervisors. A
walkdown of all scaffolds in safety-related areas performed by the licensee revealed a total
of 38 items that deviated from the standard, without prior engineering approval. These
items have been evaluated as not affecting the safety function, or have been corrected.
c.
Conclusions:
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PECO established the procedure M-C-700-335, " Scaffold Request; Erection; and
Disassembly" to provide measures to ensure that appropriate quality standards were
specified and included in design documents, and that deviations from such standard were
controlled.
The failure of scaffolding personnel to follow M-C-700-335, as described above and the
failure of PECO to self-identify this issue, resulted in f ailure to maintain safety- related
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components in an evaluated condition. The scaffolding amounted to an unanalyzed
temporary modification to the plant. The inspectors considered this a violation of
10CFR50 Appendix B, Criterion 111, DESIGN CONTROL, which requires PECO to evaluate
changes in the plants design prior to implementation. (Violation 50-277,50-278/97-02-02).
M3
Maintenance Procedures and Documentation
M3.1 Inservice Testing Program Review
a.
Scoce (73756):
The inspectors reviewed selected aspects of the Peach Bottom inservice testing (IST)
program.
b.
Observations and Findinas:
The inspectors conducted a review of IST program requirements for selected components
in the RHR, RCIC, CS, high pressure coolant injection (HPCI), and high pressure service
water (HPSW) systems. The selection of these systems was based, in part, on their risk
significance in the Peach Bottom Probabilistic Safety Analysis (PSA). The inspectors
verified that PECO performed these tests according to code test methods and frequencies,
reviewed administrative controls for tracking tests, and reviewed test acceptance criteria
and results. The inspectors also assessed the program using guidance in NUREG-1482,
Guidelines for Inservice Testing at Nuclear Power Plants.
PECO adequately documented the IST program in specification M-710, Revision 6, dated
December 15,1995. The inspectors noted that the program was in the process of being
revised based on the guidance issued in NUREG 1452, dated April 1995.
The inspectors found that the licensee was performing a design bases review in
conjunction with developing and reviewing an IST bases document as recommended in
NUREG-1452. The inspectors observed that the IST coordinator was resolving some
potential non-conforming conditions as part of this review. These items were being
addressed on an individual basis, which was inconsistent with the recommendations in
.
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Section 7.2 of NUREG-1452. Specifically, the NRC recommended that, before
commencing the design bases review, tre licensee develop a document to address the
non-conformances on a programmatic basis.
The inspectors reviewed the IST program and test results for selected pumps and valves
and found that testing was generally being performed consistent with requirements and
NRC guidance. The inspectors noted and discussed a few discrepancies between the draft
IST bases document and the IST program with the IST coordinator, who stated that they
were being addressed as potential non-conformances. The inspector also found a notable
discrepancy with the IST acceptance value for the core spray (CS) pump minimum flow
check valves, as discussed in Section E2.5 of this report.
c.
Conclusions:
The inspectors concluded that PECO conducted !ST on selected safety-related components
according to code requirements and NRC guidance. The licensee had initiated some IST
program enhancements consistent with NUREG-1482 guidelines.
M8
Miscellaneous Maintenance issues (92902)
M8.1 Use of Overtime During Unplanned Maintenance
a.
Scope:
During the repair of the E1 EDG in February 1997, PECO used overtime to complete
governor replacement and tuning. The inspectors reviewed documentation to verify that
the licensee satisfied TS 5.2.2 requirements for use of overtime,
b.
Observations and Findinas:
During troubleshooting, governor replacement, and post-maintenance testing
on February 4 through February 10,1997 to restore the E1 EDG, the NRC inspector noted
individuals with a significant number of overtime hours. TS and administrative procedures
limit the number of hours that individuals can work on safety-related tasks without PECO
management's prior approval. Overtime is not to be used on a routine or continuous basis,
unless during an outage. A subsequent review of the daily time worked record / sheets and
working hours limitation deviation form, showed workers had exceeded the limit of 24
hours worked over a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period without prior approval. Documentation showed that
three individuals had worked 41.5,29.75, and 26.0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> within a 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period without
prior PECO management approval.
c.
Conclusions:
The failure by PECO to provide management's documented prior approval for individuals to
work greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in any 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> period on the restoration of the El EDG is a
violation of TS 5.2.2. The inspector found that this issue was of low safety consequence
and determined that it met the conditions for a non-cited violation in accordance with
Section IV of the NRC Enforcement Policy.
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ENGINEERING
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E1
General Engineering Comments
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E1.1
Station Blackout Line Testing (OPEN) Unresolved item 97-02-03: Station Blackout
!
Line Load Testing Acceptance Criteria and Basis Documentation
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a.
Scope:
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--The inspector reviewed the testing conducted on the station blackout (SBO) line during the -
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week of April 28. PECO conducted this testing to meet a commitment made in its August
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1992 submittal to the NRC and in the subsequent NRC safety evaluation. The inspector
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specifically reviewed the basis for the magnitude of the KW loading during the test.
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b.
Findinas & Observations:
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The inspector found:
3
- LPECO-put the SBO line in a proper configuration to allow the testing using portable
-e
resistive load banks. The plant configuration was properly controlled using the ST
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and associated sos procedures.
[
inconsistencies between the surveillance test loading / acceptance criteria and the
o
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PECO calculated design line load. The PECO ST stated that the line would be tested
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at greater than 7,000 KW. This was consistent with the PECO submittal and the
NRC safety evaluation which stated that 7,000 KW would be the design load to .
'
get both units to safe shutdown. The inspector found that, per calculation PE-
- 0154, including a revision made in July 1996, the design KW load from the
.
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Conowingo transformer was 8,350 KW, which, due to impedance and resistance
!
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loss, would supply the designed 7,210 kw to the safety-related emergency busses.
!~
During the actual test, PECO reached a load at the load banks of 7,600 KW.
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'The SBO design and testing requirements were not clearly discussed in the UFSAR
or the TRM basis. Neither document gave specifics as to the design loading and
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testing requirements.
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The inspector discussed these issues with PECO engineering. PECO stated that they
would review these issues.
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c.
Conclusions:
1
4
PECO conducted the SBO line testing well. However, the test acceptance criteria could
not be clearly justified or be specifically linked to the design load as specified in the PECO
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calculations. Further, the UFSAR and TRM contained no detail on line loading or test
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acceptance criteria. The inspector considered this issue unresolved pending review of
PECO actions to address these issues. (Unresolved item 97-02-03),
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E1.2 Battery Cell Rupture
a.
Scone (37550):
The inspector reviewed PBAPS engineering performance following the rupture of 3A
Station Battery Cells 49/50 on April 14,1996 while on a single cell charge of 2.5 Volts,
b.
Observations and Findinas:
The inspector found that PBAPS engineering staff conducted an extensive investigation
into the root cause of the battery rupture and provided for specific corrective action to
preclude similar failures in the future. The investigation included review of battery
inspection procedure, electrolyte specific gravity measurements, probability of ignition of
explosion from external or internal spark, and anomalies in the battery design.
In conducting the investigation, the licensee utilized the collective expertise from within
PECO Energy (including examination by the PECO Energy Valley Forge Materials
Laboratory), battery manufacturers, battery consultants, and a comparison with a recent
similar incident at Perry Nuclear Power Station (PNPS).
The inspector found the battery maintenance / testing procedures to correctly follow the
recommendations of IEEE 450, and the battery charging was within acceptable voltage
levels. Reported specific gravity measurements of the electrolyte were found to be low,
but subsequent checks of the measurement technique found incorrect use of a digital
hydrometer by test personnel. Comparative analysis of this incident with a similar failure
at the Perry Station provided no clue to the root cause of the PBAPS failure. There were
mixed professional opinions as to whether the explosion ignition was from external or
internal sources.
Corrective action taken by the licensee included changes in the battery inspection
procedure, training in the correct use of the digital hydrometer, and careful observation of
the quality of the battery internals.
c.
Conclusions:
PBAPS engineering comprehensively pursued the resolution of the battery rupture issue.
Although the reason for the explosion was not determined, the licensee provided a
corrective action program that it believed would preclude future battery explosions.
E1.3 Improper Documentation of E42 Bus Modification Finding
a.
Scope (37550):
The inspector reviewed the engineering performance related to the inadvertent
simultaneous closure of bus breakers E242 and E342, paralleling two offsite power
sources.
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24
b.
Observations and Findinos:
The inspector found that during a licensee walkdown of bus breaker modification P00262
E42, it was annotated in an Engineering Change Request (ECR) that an undocumented
jumper was left installed by modification personnel (contractors). The ECR did not give
instructions nor did the design drawings note the disposition of the undocumented jumper.
Consequently, problems occurred with the proper functioning of the breaker E342 during
testing. However, the testing continued without determining the root cause of the E342
malfunction, and further maloperation occurred.
The engineering director emphasized the importance of stopping further testing until
troubleshooting the problem is completed. The corrective actions implemented by the
licensee included the responsibility of ECR reviewers to be aware of the findings
documented in the walkdown report. Discrepancies identified are to be documented for
evaluation of plant impact. Since the modification was performed by an outside firm, they
,
will be trained in the expectations of verification signoffs. Lessons learned from this event
will be distributed to plant engineering and engineering branch heads.
c.
Conclusions:
,
The inspector determined that the engineering oversight and training of modification
contractors was weak in this instance, but that PECO had taken adequate corrective
actions.
E2
Engineering Support of Facilities and Equipment
E2.1
(UPDATE) Unresolved item 95-18-01: High Pressure Coolant injection Steam Line
Vibration
.
.
a.
Scoce (37550):
The inspector reviewed the status of the progran; to determine the root cause of the
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excessive HPCI steam supply pipe vibration, and the action taken to reduce the level of
this vibration.
b.
Observations and Findinos:
The inspector found the welding of Unit 3 HPCI system steam line piping supports is near
completion, and the program is proceeding on schedule to install the necessary vibration
and flow characterization instrumentation on/in the HPCI and MSL steam lines. The
licensee reported that reductions in steam line vibration have already been noted as a result
of changes in the numbers and locations of pipe supports completed to date. In reviewing
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generic information, the licensee found that improving support of the HPCI piping system
has reduced pipe vibration at other plants. The licensee also found that reductions of
steam pressure were noted in other plants with vibrating HPCI steam lines. Reduction in
steam pressure of similar levels in the Unit 3 HPCI steam line was also noted, however, the
relationship between the reduced steam pressure and vibration has not been determined.
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c.
Conclusions:
The inspector found that the progrem to determine the root cause of the excessive
HPCf/MSL pipe vibration and corrective action to reduce the level of vibration in this steam
line continues on schedule. Some success was achieved in reducing the vibration. URI-
95-018-01 will remain open, pending successful completion of the program.
E2.2 (OPEN) Violation 97-02-04; Inoperable Reactor Feed Pump High Reactor Level Trip
(OPEN) Unresolved item 97-02-05; Review of instruments that Require Electrical
Power to Perform a Technical Specification Function
a.
Scoce:
PECO entered a two hour TS action (TSA) on April 14 for loss of the C reactor feed pump
_
(RFP) high water level trip capability on Unit 3 due to the discovery of a blown fuse. The
blown fuse made the trip function, required by TS 3.3.2, inoperable. After fuse
replacement, PECO exited the TSA. The inspector reviewed the sequence of events
leading to identification of the blown fuse.
b.
Findinas and Observations:
The inspector found:
On April 4, the RO noted that the "C" RFP turbine reset indicating light was not
properly lit. PECO wrote Action Request (AR) A1083198 for this issue and
changed the bulb; however, the light was still not lit after the bulb replacement.
The AR noted no operability concem.
At that point, operators were unaware that this normally lit red light also indicated
availability of power to the RFP trip circuit, including the high reactor vessel level
trip.
On April 11, the system manager identified that the light being out could indicate
loss of power to the high level trip and informed engineering management of the
possible two hour required action in TS. The system manager recommended that
the fuse be checked. The system manager noted this on AR #A1083198.
The fuse identified by the system manager went unchecked until April 14. After .
replacement of the light socket during troubleshooting of a battery ground and
trying to get the light relighted, the FIN team discovered the blown fuse UU F11
This resulted in PECO entering an LCO from 9:50 a.m. to 10:18 a.m. during the
fuse replacement. The inspector noted the entry in AR# A1083198 and brought it
to the control room operators' attention.
Following identification by the inspector on April 14 that PECO should have taken
actions to correct the condition earlier, on April 15 PECO initiated a PEP to
investigate the issue. Further, PECO confirmed that the fuse for the high water
level trip capability on the C RFP had been inoperable since April 4, longer than the
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two hour limit in TS Section 3.3.2.2. PECO found that this condition was
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reportable and submitted a licensee event report.
'
During review of this issue the inspector identified that the surveillance test specified by
PECO to meet the daily channel function check of the high level trip instrument was not
complete, since it did not verify power to the feed pump trip logic. PECO agreed with this
finding and was reviewing other instrumentation to determine if similar conditions existed
elsewhere.
c.
Conclusions:
Engineering follow-up of the C RFP high water reactor vessel level trip function circuit fuse
issue was poor. The trip function circuitry was incapable of operating from April 4 to April
14. This exceeded the TS limit of two hours to restore the high water level trip capability
and, therefore, a violation of the TS Section 3.3.2.2 occurred. (Violation 97-02-04)
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The surveillance test specified for the high reactor vessel level trip channel check was
inadequate in that it did not verify that the power was available to the feed pump trip logic.
'The inspector considered this an unresolved item pending review of PECO's actions to
identify other circuits that need power to operate. (Unresolved item 97-02-05)
E2.3 Emergency Diesel Generator Ventilation Review (OPEN) Unresolved item 97-02-06:
Operability Testing of the Emergency Diesel Generator Ventilation Systems
a.
Scope:
The inspectors walked down the EDG ventilation system, reviewed the design basis, and
reviewed the criteria for system and component operability against design basis
assumptions. The inspector also performed a review of testing, maintenance, and operation
of the compartment ventilation to assure PECO's actions verified this support system's
ability to support EDG capability.
b.
Findino and Observations:
Tours of each EDG ventilation system showed that the louvers of each system were in
various configurations. The inspector reviewed system operating procedures and piping
and instrument drawings and discussed the operation with the system manager. The
inspector found that these louvers are positioned based on the internal temperature of the
EDG compartments. However, it was unclear why some dampers were closed and some
half open, when, by design, they all should have been in the same position.
Review of the EDG surveillance procedures indicated a lack of verification of the proper
operation of the EDG ventilation system fans and louvers during the monthly test runs.
The operations services manager agreed that some change to these procedure would be
appropriate but believed that the EDG had remained operable. Because the EDGs have
operated satisfactorily during the test run for short periods of time (i.e.1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> under load),
the confidence that the EDGs are and have been operable is reasonable.
The inspector reviewed calculation PM-498, " Emergency Diesel Generator Building Cooling
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27
Load and Ventilation Requirements," and determined that PECO has established that at the
design basis maximum outside temperature of 95 F the diesel room temperature would be
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107.7 F. This temperature is above the alarm setpoint of 107 F for the compartment
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maximum temperature, but below the 110 F maximum compartment temperature for
3250KW rated load for the EDG. The calculation also indicated the need for only the
supply fan operability when the outside temperature remained below 80 F. Above 80 F,
both supply and supplemental fans are required for the proper functioning of the EDG.
The design basis outside temperature for the EDG to be rated at 3250 KW is 95 F. This
criterion was used to size the equipment in the EDG compartments for ventilation. This
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would maintain the temperature less than the maximum temperature at this rating of 110F.
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The maximum room temperature for the EDG to maintain 3100 Kw it.122 F, which
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corrt.3onds to a temperature of 107 F max outside temperature. A sammary of these
parar dters is provided below:
Outside Max Temp
Compartment Max
Fans Required
Rating
e Temp
r
< 80 F
1110 F
Supply Fan Only
3250KW
> 80aF
110*F
Both Fans Operable
3250KW
,
,
<95 F
110 F
Both Fans Operable
3250KW
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< 107 F
122*F
Both Fans Operable
2600KW
> 107 F
122 F
Both Fans Operable
< 2600KW
,
When outside temperature is above 107 F, the EDGs are inoperable, but could cany some
!
andeterminate amount of load.
!
c.
Conclusions:
,
The EDGs have criteria to carry the design load for an hour during testing which gives
reasonbble assurance that the EDGs have been operable. To ensure full capability, the
,
support systems for the EDG must also be verified operable. The opercbiWty of the EDG is
I
dependent on the operability of the ventilation system and, therefore, operability
verification of the ventilation system is required. This issue remains unresolved pending
review of PECO's actions on the verification and documentation of assurance of the
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compartment ventilation systems' to support EDG safety function capability. (Unresolved
i
item 97-02-06).
!
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E2.4 High Pressure Service Water System F.;. ng Leak
.
a.
Scone (375511:
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The inspector reviewed PECO's c':tions following the discovery of a through-wall leak in
the Unit 3 high pressure service water (HPSW) system.
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b.
Observations and Findinas:
On April 15, a non-licensed operator discovered a minor through-wall leak in the Unit 3
HPSW system, downstream of the B residual heat removal (RHR) heat exchanger. The size
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of the hole was estimated to be about 2 mm in c"ameter, and the leak rate was less than 1
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gallon per minute. The hole was in the vicinity of a weld near a flow orifice.
Engineering and operations took prompt actions to evaluate the leak per NRC guidance in
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Generic Letter (GL) 90-05 and to perform an operability determination. Initialinvestigation
determined that the leak was within the capability of the room sump pumping capacity,
and its location did not have the potential to impact the heat removal capability of the RHR
heat exchanger. PECO performed initial ultrasonic (UT) measurements of the pipe wallin
the vicinity of the leak on April 15. These UT results showed that there were other flaws
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below the minimum wall thickness. Engineering performed calculations that demonstrated
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that the piping structural integrity was maintained and the system was determined to be
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operable. Operations covered the affected area with rubber for housekeeping purposes.
PECO performed more accurate UT measurements on April 17, which revealed thinner wall
thicknesses,-in specific locations, than the original lesults. However, engineering revised.
the original calculations and verified that structural integrity was still maintained. The
licensee found minor weaknesses in the methodology for the original UT measurements
and initiated corrective actions.
The inspectors reviewed the licensee's calculations and operability determination and
identified r.
oncerns. Station management discussed the plans for repair of the HPSW
piping and for additional inspection of piping as specified in GL 90-05. The inspectors
were concerned about engineering's initial plans to delay the additional inspections of the
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piping until the cause of the leak was determined. After further review, engineering
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concluded that additional inspection prior to detailed evaluation of the cause was a more
appropriate and conservative approach.
Repair of the HPSW piping was accomplished in early May by replacing the affected
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section of piping with a flanged spoolpiece. The faulty sectiv cf pipe was sent for
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laboratory analysis, to determine the mode of failure.
The licensee performed inspections of five additional locations in the Unit 3 HPSW system
and found all to be within code allowable thickness requirements. As further generic
corrective action, engineering added 32 welds to the HPSW preventive maintenance weld
(
inspection program. The inspectors considered these actions to be good.
!
c.
Conclusions:
4
The inspectors concluded that overall engineering performance in response to the minor
leak in the Unit 3 HPSW system was very good. Engineering staff followed GL 90-05
guidance for assessing the structural integrity of the affected piping and made plans for
r.de repairs, both cf which were performed in a prompt, thorough manner. However,
initial plans for delaying the augmented piping inspections discussed in GL 90-05 were
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29
judged to be non-conservative. Other planned and completed corrective actions were
considered very good.
E2.5 Core Spray System Minimum Flow Rate
a.
Scope (37551):
The inspectors compared selected IST acceptance criteria with the design and licensing
bases for the CS.
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b.
Observations and Findinas:
During a review of valve IST requirements for CS, the inspectors noted a discrepancy
between the rWnimum flow line flow rate for the pumps, as specified in IST/ surveillance
i
test procedures, and the corresponding required flow rate listed in design and licensing
,
basis documents.
The minimum flow line is designed to allow for a minimum amount of flow in the system to
prevent pump damage due to overheating when opersting at or near shut-off head
conditions. The CS Design Basis Document P-S-44, states that the minimum flow rate is
312.5 gpm, or 10% of rated system flow. This safety related parameter was also
'
documented in PECO's response to NRC Bu'letin No. 88-04, dated June 30,1988.
Further, the updated final safety analysis report (UFSAR) Figure 6.4.2, Core Spray System
Process Diagram, lists the design flow rate as 312.5 gpm. Additionally, the Peach Bottom
IST basis data sheets for the core spray minimum flow check valves, which were in draft
form at the time of the inspection, indicated the same design flow rate.
Contrary to this design basis data, the IST/ST acceptance criteria for the minimum flow
check valves was only 165 gpm. The inspectors brought this discrepancy to the attention
of the back-up system manager. After review, the system manager and his supervisor
indicated that engineering had made a change to the minimum required flow rate from 10%
of rated system flow, to 5% of rated system flow, or about 156 gpm. The change was
based on a 1991 PECO memorandum that referenced a Boiling Water Reactor Owners
Group interim response to NRC Bulletin 98-04. The system manager recognized that the
memorandum was not adequate design change documentation and stated thm c . initiated
ar. engineering change request to design engineering to provide the engineeririv .> asis for
this change.
At the end of the incpection period, design engineering was still reviewing the adequacy of
the IST/ surveillance test acceptance criteria. Preliminary results of this review indicated
that the 165 gpm IST criteria was acceptable, given the f act that the maximum period the
pump would be expected to operate at the minimum flow rate would be 30 minutes during
design basis accident conditions. However, this position was not currently documented.
Engineering staff also stated that they considered the 312.5 gpm specification to be a
nominal value, rather than a minimum value. Again, this was not reflected in design basis
documents. The inspectors will review the final results of tv design engineering review.
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The licensee also reviewed the actual recorded surveillance test results for the core spray
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minimum flow rate and found they were consistently about 312.5 gpm. Thus, the test
results reflected values close to the design basis flow rate. Based on this information, the
!
inspectors concluded there was no operability concern and the safety impact of the issue
was minimal.
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l
The inspector observed that engineering had missed relatively recent opportunities to
identify the flow rate discrepancy. These opportunities included: a) the development and
review of the core spray system Design Basis Document in December 1993, b) Peach
Bottom's UFSAR review project begun in the summer of 1996, and c) the development of
the IST basis documents, which were stillin progress.
c.
Conclusions:
The inspectors concluded that the issue regarding a discrepancy between the IST
!
acceptance criteria and the design and licensing basis data for the core spray system
minimum flow rate revealed weaknesses in both engineering documentation and
,
performance. Further, engineering had missed opportunities to identify this discrepancy
during recent design basis reviews.
E4
Engineering Staff Knowledge and Performance
E4.1 Walkdown of Plant Facilities with System Managers
a.
Scope (37550):
The inspector conducted walkdowns of the Unit 2 and 3 EDG facilities, the Unit 3 HPCI
pump piping, and the safety-related battery rooms to assess the overall cleanliness and
'
orderliness of the facilities. To assess the capability of the respective system engineer, the
inspector discussed with each engineer the management of the facility, significant events,
l
the mode of training and utilization of back-up system managers.
b.
Observations and Findinas:
The inspector found good cleanliness and an orderly control of the working environment.
The battery rooms and EDG facilities were in excellent condition. The Unit 3 HPCI pump
and turbine room piping was under modification to support the vibration studies and
modification of pipe supports. There was a reasonable degree of orderliness for a facility
under modification.
i
The inspector discussed system operational issues with the systems managers during the
walkdown, and the managers responsively reflected knowledge of operation and
maimenance procedures, recent significant events, an ownership attitude for their
respective facilities,
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Re inspector found that the system manager for the battery and HPCI facilities had a
designated back-up responsible for management of that system should the need arise. The
!
back-up position was also a training opportunity for system management position for that
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facility. In the case of the EDG facility, there was no designated back-up, but the EDG
system manager for Limerick was present during the walk-down and the system rnanager
indicated his availability should the need arise.
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c.
Conclusions:
The inspector found the general appearance of facilities inspected to be clean and orderly.
l
The system managers of the facilities were knowledgeable in the functioning and
management of their respective systems.
E7
Quality Assurance in Engineering Activities
E7.1
Updated Final Safety Analysis Report Review Program (37550)
a.
Scoce (37550):
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The inspector reviewed the PBAPS Updated Final Safety Analysis Report (UFSAR)
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verification program to identify discrepancies between the UFSAR and the facility.
i
b.
Observations and Findinos:
The inspector found that PECO targeted UFSAR' sections for review on the basis of
probabilistic safety assessment (PSA) significance and engineering judgement. The
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program was planned to be implemented in three phases. Initially, in Phase I,30 sections
of the UFSAR were examined by three person teams. Phase 11 provided for a more
j
structured review, expending four man-years to complete a review of 20% of the UFSAR.
At present, PBAPS was giving consideration to completion of the verification program in
Phase Ill, but no definitive decision had been reached.
)
The inspector noted that the review team assignments were specific, with specific goals to
]
be achieved at particular times. Results of findings were monitored in terms of discrepancy
'
findings, changes implemented, and change document aging,
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1
c.
Conclusions *
The PBAPS UFSAR verification review to date has been a well managed program to provide
documents with corrected errors, absence of ambiguity, and an accurate reflection of the
structural and operating requirements , 'he plant.
,
E7.2 Design Basis Document Revision; (OPEN) Inspector Follow item 97-02-07; Review
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of Design Basis Document Review and Approval Process
a.
Scoce (37550):
The inspector reviewed the performance of PBAPS engineering in review and correction of
the design basis documents (DBDs) as part of an overall configuration management
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program.
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d,
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b.
Observations and FindinLqs:
r
The inspector reviewed the DBD revision program. Review of three system documents
RHR PS-09, EDG Auxiliaries PS-07, and HPCI PS-03 found them to clearly describe the
system operation and reference sources. However, in document PS-07, the inspector
noted that the review signatures were not complete. Several others had no review
signatures, other than a typed acknowledgement that PECO NQA procedures had been
,
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followed. On notification of this finding by the inspector, PECO immediately reviewed all
the completed DBDs and found many others incomplete. However, the licensee indicated
' that the reviews had been completed, but the signatures had not been included in the DBD
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documents.
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,
c.
Conclusions.
l
The quality of the rewritten DBDs was good. The absence of many review signatures in
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the documents is an inspection follow item, pending location of original review documents
i
or completion of the review process. (Inspector Follow item 97-02-07).
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E8
Miscellaneous Engineering issues
E8.1
PBAPS Site Equipment and Material Focus Program
a.
Scope (37550):
The inspector reviewed the PBAPS Site Equipment and Material Condition Focus Program.
b. -
Observations and Findinos:
The inspector found that the program provided a list of key site issues recognizing potential
I
challenges to plant operation, operational enhancements, and plant strategies in resolution
of problems. PBAPS engineering documented a detailed description of the issues,
,
assignment of responsible engineers, and a schedule for completion of problem resolution.
i
)
c.
Conclusions:
The inspector found that PBAPS engineering continues to provide a well coordinated effort
to identify, publicize, and resolve chronic plant issues.
i
IV
PLANT SUPPORT
P1
Conduct of Emergency Preparedness Activities
P1.1
Effectiveness of Licensee Controls
3
a.
Scope (82701):
The inspector reviewed the licensee's tracking systems used for tracking EP related action
items. Also, the EP self assessment program was reviewed to determine the effectiveness
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33
of licensee controls,
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b.
Observations and Findinas:
PECO generated action items were from drill critiques, self assessment findings and
training feedback. The inspector reviewed these items and found that they were
appropriately prioritized and closed in a timely manner. PECO stated that it plans to begin
performing a monthly trending analysis to identify the number of EP action items per
emergency facility, as well as repeat items.
.The licensee initiated an EP self-assessment program in late 1995. The inspector reviewed
the self-assessment report for 1996. The report contained " strengths," " weaknesses,"
and " watch areas." The inspector noted that all corrected weaknesses were upgraded to a
" watch area" for continual review and assessment. The inspector noted this to be a very
good initiative because the licensee continued to review the previous weaknesses to
ensure that corrective actions was appropriate.
The EP staff maintains an automatad job task tracking system for routine work
assignments to ensure Emergency Plan (E-Plan) commitments were met in a timely manner.
For example, the system included quarterly verification of phone numbers, and monthly or
quarterly surveillance tests, and equipment inventories. The inspector reviewed the job
assignment list and determined that it served as an excellent tool for the EP staff in
assuring that E-Plan and Emergency Response Procedure (ERP) commitments were met in a
timely manner.
c.
Conclusions:
PECO is very good at identifying, tracking, and resolving generated action items. The EP.
generating tracking system is an excellent tool for assuring EP assignments were
completed. The self assessment process was good.
P2
Status of Facilities, Equipment and Resources
P2.1 Operational Readiness of Emergency Facilities
a.
Scoce (82701):
The inspector conducted an audit of emergency facilities and equipment kits in the
operations support center (OSC), technical support center (TSC) and emergency operations
facility (EOF). A tour of the local community hospital was also conducted (see section P8).
The inspector reviewed facility equipment inventories and surveillance tests conducted
during the past year for completeness, accuracy, and compliance.
b.
Observations and Findinas:
The equipment and inventory program for the emergency facilities is maintained by the EP
Facilities Equipment Technical Assistant, and equipment and supply inventories were
conducted on a quarterly basis. The inspector reviewed equipment and supply inventory
. _ .
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34
checklists for 1995 and 1996, respectively. The inspector determined that inventories
were conducted in a timely manner and immediate corrective action was taken on
identified deficiencies.
The inspector toured the emergency facilities and found them to be operationally ready.
The TSC was recently upgraded and included a new state-of-the-art telephone system and
the public announcement system was upgraded in the OSC due to several audio problems
identified in past drills and exercises. The inspector checked several emergency equipment
kits and emergency supply cabinets located in the emergency facilities and found them to
be stocked in accordance with licensee procedures.
Prior to entering the TSC, ERO staff assigned to the TSC are required to acquire a
thermoluminescent dosimeter (TLD) and a personal alarming dosimeter. The inspector
performed operability checks on the 50 alarming dosimeters and found: 1) five alarming
'
dosimeters out of calibration; 2) four alarming dosimeters with low batteries; and 3) ten
alarming dosimeters that were inoperable. The inspector reviewed the methods for
maintaining these instruments and found that the calibration period was 180 days, the
instruments were calibrated and replaced on the same day, and were not required to be
'
operability tested during the quarterly inventory checks. The inspector discussed this
matter with the dosimetry specialist and the manager, EP who were unaware of the
problems. The dosimetry specialist immediately replaced all the dosimeters and modified a
station routine test procedure requiring calibration verification of the dosimeters on a
monthly basis. The me nger, EP, added to the quarterly inventory list routine operability
checks to be performed during inventory checks. Although the licensee did not have these
instruments available for some indeterminate period of time, the inspector determined that
TSC personnel would have had their TLDs and additional alarming dosimeters could be
obtained kom onsite within approximately 20 minutes,
c.
Conclusions:
With the exception of the problem with the alarming dosimeters at the TSC, the inspector
concluded that the licensee maintained a very good inventory program and that the
emergency facilities and equipment were operationally ready.
P3
Procedures and Documentation
a.
S_coce (82701):
1
The inspector reviewed the changes made to the common (Peach Bottom and Limerick)
'
PECO Nuclear E-Plan and the Peach Bottom ERPs since the last inspection. The changea
were reviewed in the NRC Region I office prior to arriving onsite and discussed with the
licensee during this inspection. A list of the changes reviewed is included as Attachment 2
to this report.
b.
Observations and Findinas:
The inspector discussed with the licensee several deletions and changes recently made to
its E-Plan Most of the changes were insignificant; however, the inspector noted some
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35
paragraphs were deleted that were initially determined by the inspector as decreasing the
'
effectiveness of the plan. For example, paragraph 5.2.9, Revision 8 of the E-Plan,
describing the direct communication tie lines between Peach Bottom and the Conowingo
Dam in the event of a flood or failure at the dam was deleted. The licensee stated that this
,
paragraph had been omitted due to communication upgrades; however, they still
l
,
maintained the capability, but not as originally described in the E-Plan. The licensee
recognized that a change should have been made rather than a deletion and immediately
committed to adding a revised paragraph describing the changed process.
Other examples included: 1) the deletion of the services support position in the TSC in the
ERO organization chart, (Exhibit 3-3), which wasn't deleted but redefined and moved under
,
a different selection manager; 2) IRP 340 entitled, " Field Survey Group", where several
j
paragraphs were deleted for describing responsibilities while doing field surveys. When
questioned concerning these omissions, PECO stated that the reason for the omission was
J
not entirely known but it would be pursued. In a previous NRC inspection (50-
'
277,278/95-14), similar problems were identified. The licensee acknowledged that its
quality control process for E-Plan and ERP changes still needs to be improved and has
committed to review the inspector's comments, make the needed corrections, and
continue to improve their E-Plan quality control process.
c.
Conclusions:
Except for the minor problems noted by the inspector, which the licensee committed to
correct, the inspector concluded that none of the changes reduced the emergency planning
effectiveness and assessed this area as adequate. The licensee stated that it needs to
improve the quality control process for changes and deletions to it's E-plan and ERPs and
to ensure that they do not compromise the original intent of the approved plan.
P5
Staff Training and Qualification
a.
Scone (82701):
The inspector reviewed EP training records, training procedures, status reports, ERPs and
the licensee's E-Plan to evaluate the licensee's EP training program. Also, the inspector
'
reviewed drill and exercise critiques, surveillance and pager test records to ensure the
licensee was adhering to the commitments made in its E-Plan.
4
b.
Observations and Findinas:
)
The EP Drills / Training Analyst maintains the EP training records for ERO responders. The
inspector reviewed the ERO training records and verified that the ERO responders were
qualified to fill their assigned emergency response positions. Also, the inspector verified
that new responders who had not completed ERO qualification training, were not on the
weekly on-call responder list. Monthly, the licensee sent a training status report to all ERO
Selection Managers (SM). This allowed the SM to ensure that ERO qualifications for their
team members were met. If an individual's ERO qualifications expired, they were
immediately removed from the ERO list and an action request letter was sent to the SM.
s
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36
This required the SM to respond in writing and the SM was ultimately held responsible for
ensuring that individuals on the teams were qualified or replaced.
The EP staff provided emergency response training for the ERO. In reviewing lesson plans,
critiques and discussions with training attendees, the inspector found that the EP staff was
very conscientious, thorough and dedicated to maintaining an excellent training program.
For specialized classes, (chemistry or health physics), lesson materials were reviewed by
managers with technical expertise and classes were conducted with the assistance of that
manager. Also, the EP staff appeared to be very responsive to class critiques and made
adjustments accordingly.
The inspector reviewed drill, exercise, pager and surveillance test records for 1995,1996,
and the first quarter of 1997. All required drills, exercises and tests were conducted.
Particularly noteworthy is that the licensee ensured that all records were reviewed by
management and the information was trended for identification of any long term problems.
The corporate training program was reviewed during the Limerick NRC program inspection
>
conducted in October,1996 and found to be excellent.
c.
Conclusions:
The inspector determined that the ERO members were currently qualified and all required
drills, exercises pager and surveillance tests were conducted. Training was effectively
being conducted by the EP staff. Overall, the inspector assessed this area as very good.
P6
Organization and Administration
a.
Scope (82701):
The inspector reviewed the licensee's EP group staffing, management and ERO personnel
to determine if changes that had occurred since the last Peach Bottom program inspection
(July 1995) had any adverse effect on the EP program. Also, the inspector interviewed the
EP management to assess the adequacy of EP management involvement and control.
b.
Observations and Findinas:
The licensee continues to maintain strong management support for the EP program. The
inspector interviewed the director, site support services, manager, EP/ nuclear security and
the corporate nuclear security /EP manager separately regarding the EP program, program
initiatives and significant issues. All responses were consistent; therefore, the inspector
concluded that good communications exist with the EP group.
In the previous program inspection, the licensee had eliminated the site EP supervisor
position, one technical EP staff member and acquired the emergency response training
program. In March 1996, the site EP Manager / Security was reassigned to Corporate
Nuclear Security /EP program and the Corporate EP Manager was reassigned to the onsite
EP program. During this inspection, the inspector was informed that in May 1997, the
licensee will be switching the rnanagers to the positions they held previously. The
_
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37
inspector discussed this matter with both the Corporate and onsite managers and they
indicated that their one-year rotational assignments were positive experiences and believed
the program has improved. The inspector reviewed these changes, interviewed the EP
staff and in accordance to the findings of this inspection, and determined that these
changes had no adverse effect on the EP program. The inspector determined that a
4
contributing factor to the success of the rotation was the experience and knowledge of the
individual EP staff members.
i
c.
Conclusions:
Overall, the management and organizational changes to the EP Program appeared to have
no adverse effect on the EP program.
P7
Quality Assurance in Emergency Preparedness Activities
!
a.
Scoce (82701):
The inspector reviewed Audit Reports No. A0956203 and A0967117, of the PECO Nuclear
EP Program, conducted in 1995 and 1996, respectively. The inspector also reviewed audit
plans, checklists procedures and interviewed personnel from the Nuclear Quality Assurance
(NOA) Department regarding the process for conducting a program audit,
b.
Observations and Findinas:
The NOA staff conducted a combined annual audit of the EP Program at Limerick, Peach
Bottom and Corporate Headquarters over a three week period in 1995 and 1996. Audits
were conducted using six person team members from all three sites and the team utilized
an audit plan and detailed checklist. The 1996 audit included an individual outside of the
NQA Department and the 1997 audit is scheduled to include an independent EP technical
specialist from another utility. The inspector noted that this was a good practice because
'
it provides an independent perspective. Also, the licensee conducted several NOA
surveillance throughout the year to determine if the training program and the drills and
exercises were sufficient.
-
The 1996 audit report contained recommendations and deficiencies and the reports me+.
the requirements specified in 10 CFR 50.54(t). However, the inspector noted that the
!
reports did not contain the level of detail expected for describing the activities of the audit
team and their observations for supporting their audit findings.
c.
Conclusions:
The audit reports met the requirements of 10 CFR 50.54(t); however, the audit reports
lacked detail. The inspector assessed this area as good.
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P8
Miscellaneous issues
P8.1
Updated Final Safety Analysis Report inconsistencies
A recent discovery of a licensee operating its facility in a manner contrary to the UFSAR
description highlighted the need for a special focused review that compares plant practices,
procedures and/or parameters to the UFSAR description. Since the UFSAR does not
, specifically include EP requirements, the inspector compared licensee activities to the E-
Plan, which is the applicable document. The following was reviewed as part of the UFSAR
review and was found to satisfactorily meet the E-Plan commitments.
1
,
The inspector reviewed chemistry procedure CHE-110 describing the operation of
the Post Accident Sampling System (PASS). The procedure was comprehensive
and detailed and the inspector verified that the PASS was tested by chemistry
'
technicians on a quarterly basis. The licensee conducted the required PASS drills
for 1995 and 1996. Under emergency conditions, the licensee is required by its E-
Plan to request, acquire, analyze, and provide PASS sample results within a three
hour time limit. The inspector noted during drills and exercises, the licensee had
j
,
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" simulated the taking of a PASS sample that never demonstrated if the time -
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requirement would be met. Discussions with the Chemistry Manager believed that
j
they would meet the three hour requirements, however, the licensee has committed
]
to add this demonstration to its objectives for an upcoming drill that will be
conducted in 1997 to ensure this requirement is met.
,
'
The inspector toured the Harford Community Hospital and interviewed the
administrative coordinator to determine the adequacy of the licensee's medical
drills, radiological training and the f acility for decontaminating patients. The hospital
has a dedicated facility for patient radiological decontamination that was fully.
i
equipped and operationally ready. The administrative coordinator was very
enthusiastic about the program and indicated that training conducted by the EP staff
was very good. Also, the licensee was commended by the administrative
.
coordinator for being very responsive to training and drill critique comments. The
inspector determined that the licensee had an excellent rapport with this offsite
agency and maintained a very good medical radiological training program.
The licensee conducted surveillance tests on the main control room (Train A and B)
and the TSC emergency ventilation system for filter train leakage of particulate and
halides. Also, the surveillance tests were conducted to verify sufficient radioactive
methyl iodide adsorption of charcoal filters and sufficient filter train flow to satisfy
requirements of the licensee's technical specifications 4.11.A.2.(a)(b)(c).
J
3
The licensee had a contractor perform the annual surveillance test and to
analyze the cartridges to determine the absorption collection efficiency of the
charcoal beds. The inspector reviewed the 1995 and 1996 surveillance test
procedures and a contractor report for 1996 to verify the results of the
ventilation tests. The surveillance test procedure was very thorough and
detailed and the contractor report confirmed that the licensee had adequately
met its technical specification requirements.
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P8.2 IFl 50-277,278/95-14-03, Adequacy of the EP Program After Management and
'
'
Organizational Changes
The inspector concluded through interviews and this program inspection that the
management and organization changes did not appear to have an adverse effect on the EP
Program (see section P6). This item is considered closed.
S1
Conduct of Security and Safeguards Activities
a.
Scoce:
4
The inspector reviewed the security program during the period of April 8 through April 11,
1997. Areas inspected included: effectiveness of management controls; management
support; protected area (PA) detection equipment; alarm stations and communications;
,
.
testing, maintenance and compensatory measures; training and qualification; and control of
'
vehicles. The purpose of this inspection was to determine whether the licensee's security
,
i
program, as implemented, met the licensee's commitments in the NRC-approved security
i
plan (the Plan) and NRC regulatory requirements.
b.
Observations and Findinos:
,
Management support was evident by the upgrades to the security communications system,
j
upgrading and strengthening the process for handling safeguards information, and
'
'
upgrades in the alarm station consoles to facilitate data input.
Alarm station operators were knowledgeable of their duties and responsibilities and
security training was being performed in accordance with the NRC-approved training and
qualification (T&O) plan. ' Management controls for identifying, resolving, and preventing
'
programmatic problems were generally effective.
The PA detection equipment satisfied the Plan commitments and security equipment
testing was being performed as required by the Plan. Maintenance of security equipment
was being performed in a timely manner as evidenced by minimal compensatory posting
associated with non-functioning security equipment.
,
c.
Conclusions:
i
The inspector determined that the licensee was conducting its security and safeguards
'
activities in a manner that protected public health and safety.
S2
Status of Security Facilities and Equipment
S2.1 Protected Area Detection Aids
a.
Scope:
- Conduct a physical inspection of the PA intrusion detection systems (IDSs) to verify that
the systems are functional, effective, and meet the Plan commitments.
__
.
.
40
b.
Observations and Findinas:
On April 9 the inspector determined by observation of selected testing that the IDSs were
functional and effective, and were installed and maintained as described in the Plan,
c.
Conclusions:
The PA IDSs met the Plan commitments and NRC requirements.
S2.2 Alarm Stations and Communications
a.
Scoce:
Determine whether the central alarm station (CAS) and secondary alarm station (SAS) are:
1) equipped with appropriate alarm, surveillance and comrnunication capability, 2)
continuously manned by operators, and that 3) the systems are independent and diverse so
that no single act can remove the capability of detecting a threat and calling for assistance,
'
or otherwise responding to the threat, as required by NRC regulations.
b.
Observations and Findinas:
Observations of CAS and SAS operations verified that the alarm stations were equipped
with the appropriate alarm, surveillance and communications capabilities, as described in
the Plan.
Interviews with CAS and SAS operators found them knowiec'geable of their duties and
responsibilities. The inspector also verified through observations and interviews that the-
CAS and SAS operators were not required to engare in activities that would interfere with
their assessment and response functions, and that the licensee had exercised
communications methods with the local law enforcement agencies as committed to in the
Plan.
c.
Conclusions
The alarm stations and communications met the Plan commitments and NRC requirements.
S2.3 Testing, Maintenance and Compensatory Measures
a.
Scooe:
Determine whether programs are implemented that will ensu.re the reliability of security-
related equipment, including proper installation, testing and maintenance to replace
defective or marginally effective equipmer.t. Additionally, determine that when security
related equipment fails, the compensatory measures put in piace are comparable to the
effectiveness of the security system that existed prior to the failure.
1
.
.
41
b.
Observations and Findinas:
Review of testing and maintenance records for security-related equipment confirmed that
the records were on file, and that the licensee was testing and maintaining systems and
equipment as committed to in the Plan. A priority status was assigned to each work
request and repairs were normally being completed in a timely manner for all work
necessitating compensatory measures.
c.
Conclusions:
Security equipment repairs were timely. The use of compensatory measures was found to
be appropriate and minimal. The maintenance and testing being implemented were
reasonable to ensure equipment reliability.
Security and Safeguards Staff Training and Qualification
a.
Scoce:
Determine whether members of the security organization are trained and qualified to
perform each assigned security-related job task or duty in accordance with the T&O plan.
b.
Observations and Findinas:
On April 10,1997, the inspector met with the security training staff and discussed the
training requalification program and its effectiveness. Additionally, the inspector
interviewed a number of supervisors and officers to determine if they possessed the
requisite knowledge and ability to carry out their assigned duties and reviewed the initial
training records for two new officers hired since the last inspection.
c.
Conclusions:
The inspector determined that training had been conducted in accordance with the T&O
plan. Besed on the supervisors' and officers' responses to the inspector's questions, the
training provided by the security training staff was considered effective.
S6
Security Organization and Administration
a.
Scoce:
Conduct a review of the level of management support for the licensee's physical recurity
program.
b.
Observations and Findinas:
The inspector reviewed various program enhancements made since the last program
inspection, which was conducted in February 1996, and discussed them with security
management. These enhancements included: upgrades to the security communication
system, e.g., installation of a new distributed antenna system to eliminate areas of
_.
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_
_
.
,
42
marginal radio coverage; upgrade of the offsite communication system to enhance
reliability and decrease system maintenance costs; installation of new alarm station
console software to facilitate data inputting; and upgrades to strengthen the program for
the control of Safeguards Information.
c.
Conclusions:
l
Management Support for the physical security program was determined to be very good.
S7
Quality Assurance in Security and Safeguards Activities
S7.1 Effectiveness of Management Controls
a.
Scope:
^
,
J
Conduct a review to determine if the licensee has controls for identifying, resolving and
preventing programmatic problems.
b.
Observations and Findinas:
The inspector reviewed the licensee's controls for identifying, resolving and preventing
security program problems. These controls included the performance of the required
annual quality assurance (QA) audits, an ongoing self-assessment program and ongoing
security shift supervisor oversight. The licensee was also using industry data, such as
violations of regulatory requirements identified by the NRC at other facilities, as a criterion
for self-assessment.
c.
Conclusions:
A review of the licensee controls, including results, indicated that performance errors were
being minimized and that controls were effectively implemented to identify and re::olve
potential weaknesses.
S8.1 Review of Updated Final Safety Analysis Report
A racent discovery of a licensee operating its facility in a manner contrary to the UFSAR
description highlighted the need for a special focused review that compares plant practices,
procedures, and parameters to the UFSAR description. Since the UFSAR does not
specifically include security program requirements, the inspector compared licensee
activities to the NRC-approved physical security plan, which is the applicable document.
While performing the inspection discussed in this report, the inspector reviewed Section
3.2.2 of the Plan titiet " Vehicle and Cargo Access Portals and Posts." Based on direct
observations, discussions with security supervision and procedural reviews, the inspector
determined that all vehicles were being properly searched prior to entry into the PA and
controlled while in the PA, as described in the Plan and applicable procedures.
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S8.2 (CLOSED) Violation 96-11-01/EA 96-144,243; " Failure to Properly Control
Safeguards information"
This violation concerned instances where safeguards information was not properly
'
controlled. The follow-up investigations by the licensee were comprehensive and in-depth.
Corrective actions were prompt and comprehensive, and included: the safeguards
information being properly controlled immediscely; :ndividuals involved with safeguards
information were retrained; the quantity of Safr: wards Information, the number of
'
individuals who handle it, and the number of it uations where it is stored were reduced; and
+
appropriate procedures were revised to upg.% the expectations for handling safeguards
information. Additionally, the licensee established the position of Safeguards Administrator
,
who will be responsible for providing safeguards training, conducting periodic audits,
!
performing self-assessments, and recommending any necessary programmatic changes.
)
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The inspector reviewed the corrective actions associated with the violation, and concluded
that the cencerns were adequately addressed. This violation is closed.
j
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V
MANAGEMENT MEETINGS
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Management Meeting Summary
I
The inspector presented the inspection results to members of licensee management at the
conclusion of the inspection on May 14,1997. The licensee acknowledged the findings
-
presented.
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LIST OF ACRONYMS USED
action request (AR)
9
action statement (AS)
,
2
administrative guideline (AG)
APRM gain adjust factor (AGAF)
!
as-low-as-reasonably-achievable (ALARA)
t
average power range monitors - neutron (APRMs)
Conowingo Generating Station (CGS)
control rod drives (CRDs)
control room deficiency list (CRDL)
control room emergency ventilation (CREV)
'
control valve (CV)
L
core operating limits report (COLR)
core power and flow log (CPFL)
i
' core spray (CS)
.
core thermal power (CTP)
l
'l
design basis document (DBD)
design input document (DID) .
diaphragm alternative response test (DART)
'
- electro-hydraulic control (EHC)
l
eleventh refueling outage (2R11)
emergency core cooling system (ECCS)
-
emergency diesel generators (EDG)
,
3
'
emergency service water (ESW)
end-of-cycle (EOC)
engineering change request (ECR)
engineered safety feature (ESF)
equipment operators (EOs)
equipment study list (ESL)
. functional testing (FT)
general procedure (GP)
Generic Letter (GL)
health physics (HP)
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 (IFis)
Institute of Electric and Electronics Engineers (IEEE)
instrument and control (l&C)
intermediate range monitor - neutron (IRM)
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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.-
2
loss of coolant accident (LOCA)
,
loss of off-site power (LOOP)
'
low pressure coolant injection (LPCI)
lubricating oil (LO)
modification (MOD)
motor generator (MG)
{
nuclear maintenance division (NMD)
nucisar management resource council (NUMARC)
nuclear quality assurance (NOA)
nuclear review board (NRB)
'
offsite dose calculation manual (ODCM)
offsite power start-up source #2 (2SU)
'
offsite power start-up source #3 (3SU)
,
operating experience (OE)
performance enhancement program (PEP)
'
PEP issue review leaders (PIRLs)
plant equipment operator (PEO)
plant operations leview committee (PORC)
post-maintenance testing (PMT)
primary containment (PC)
primary containment isolation system (PCIS)
primary containment isolation valve (PCIV)
probabilistic safety assessment (PSA)
protected area (PA)
quality assurance (QA)
radiologically controlled area (RCA)
rated thermal power (RTP)
reactor core isolation cooling (RCIC)
reactor engineer (RE)
reactor feed pump (RFP)
reactor operator (RO)
reactor protection system (RPS)
refueling outage (RFO)
reliability centered maintenance (ROM)
safety evaluation report (SER)
safety related structures, system and components (SSC)
scram solenoid pilot valve (SSPV)
senior reactor operator (SRO)
shift manager (SM)
shift supervisor (SS)
shift update notice (SUN)
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3
source range monitor (SRM)
spent fuel pool (SFP)
standby gas treatment (SGTS)
!
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station blackout (SBO)
station qualified reviewers (SQR)
structure, system and component (SSC)
surveillance requirement (SR)
surveillance test (ST)
systems approach to training (SAT)
technical requirements manual (TRM)
technical specification (TS)
temporary instructor (TI)
temporary plant alteration (TPA)
!
,
turbine control valve (TCV)
'- '-
turbine stop valve (TSV)
unresolved item (URI)
updated final safety analysis report (UFSAR)
,
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INSPECTION PROCEDURES USED
IP 37551: Onsite Engineering Observations
IP 40500: Effectiveness of Licensee Controls in identifying, Resolving,and Preventing
Problems
IP 61726: Surveillance Observations
IP 62707: Maintenance Observation
IP 64704: Fire Protection Program
IP 71707: Plant Operations
IP 71750: Plant Support Observations
IP 83750: Occupational Exposure
IP 92700: Onsite Follow of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 92901: Operations Followup
IP 92902: Followup - Engineer
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:
URI 97-02-01
Station Qualified Reviewer Use/ Review of Open Changes to the
Updated Final Safety Analysis Report
VIO 97-02-02
Scaffolding Erected Causing Unanalyzed Conditions
URI 97-02-03
Station Blackout Line Load Testing
VIO 97-02-04
Inoperable Reactor Feed Pump High Reactor Level Trip
URI 97-02-05
Review of Instruments that Require Electrical Power to Perform a
Technical Specification Function
URI 97-02-06
Operability Testing of the Emergency Diesel Generator Ventilation
Systems
IFl 97-02-07
Review of Design Basis Document Review and Approval Process
Closed:
URI 96-04-02
Verification of Primary Containment Valves and Blank Flanges in the
Drywell
Vio 50-227,278/
EA 96-144,243
Failure To Properly Control Safeguards information
Discussed:
URI 95-018-01
High Pressure Coolant injection Steam Line Vibration
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ATTACHMENT 1, SECTION 1
ADMINISTRATIVE PROCEDURES
A-3.2
Completing and Processing a Temporary Change, Rev 0
AA-C-5
Preparation and Control of Procedures / Guidelines, Rev 6
AA-C-5.2
Document Review Checklist, Rev 4
AA-C-7
Preparation and Control of Manuals, Rev 1
AG-CG-4
PORC Administration /SQR and Chesterbrook Review and Approval of
Documents, Rev 4
,
i
AG-CG-4-4
Minor Non-Technical Revisions, Rev 0
A-C.4
Plant Operations Review Committee, Rev 1
l
A-C-4.2
Station Qualified and Quality Reviewer Program, Rev 3
A-C-43
Surveillance Test Program, Rev 0
A-C-79 2
Generic Procedure Usage / Level Designation, Rev 1
4
LR-C-1
Commitment Tracking Program, Rev 8
LR-C-1.1
Document Sources for Commitments / Corrective Actions, Rev 7
LR-C-01-4
Commitment Revision Evaluation, Rev 7
LR-C-8
Control of Changes to Facility Operating Licenses, Appendices and Technical
Specification Base' , Rev 4
s
LR-C-9
Control of Changes to the Updated Final Safety Analysis Report, Rev 5
LR-C-13
10 CFR 50.59 Reviews, Rev 6
LR-CG-06
Guideline for the Control of Revisions Due to License Document Revisions,
Rev 1
LR-CG-13
Performing 10 CFR 50.59 Reviews, Revision O
MO D-C-9
Design Control and Processing of Engineering Change Requests (ECRs), Rev
8
OM-P-12.1
Operation Action Logs, Rev 5
OM-P-12.2
Safety Function Determination Program, Rev 1
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ATTACHMENT 1, SECTION 2
RELOCATED ITEMS
i
)
i
i
DESCRIPTION OF RELOCATED ITEM
RELOCATION
3.3.1.1
Table 4.1.2 Notes
Discussion / Specifics equipment required
Deleted PORC Mtg
{
1 &2
for the test
95 72
'
3.3.6.1
Table 3.2.B; Table
Requirement for a low Pressure Function
I
4.2.8 Item 4
3.3.6.1
Table 3.2.B
Setpoints for HPCI and RCIC isolation on
Procedures
low steamline pressure
3.3.6.1
Table 3.2.A;
Trip level settings
Deleted PORC Mtg
'
Table 3.2.B;95-072
l
Table 3.2.D
3.3.6.1
Table 3.2.A Note
Compensator actions associated with
TS Bases
9
recovery of a loss of ventilation in the
mainsteam line tunnel
3.3.6.1
3.2.A.2 Note 3:
Reactor Cleanup System High
Table 3.2.A Item
Temperature Isolation Function
11; Table 4.2.A
.j
ltem 7
3.3.6.2
Table 3.2.D
Trip level settings
Deleted PORC Mtg
95 72
3.3.B.1
Table 3.2.B
Trip level settings
Deleted PORC Mtg
95 72
3.3.8.1
Table 3.2.B; Table
Details on the instruments
4.2.8
3.4.1
3.6.F.1
Requirements for recirculation pump start
Procedures
3.4.1
4.6.F.1
Obtain neutron flux noise data
Procedures
3.6.B.2
3/4.6.B.2
Reactor water chemistry control
3.6,1.1
4.7. A.2.f; Table
List of containment penetrations
3.7.2: Table
3.7.3; Table
3.7.4; Table
!
Notes 2,3,&9 22
3.6.1.1
4.7.A.2.g
Requirement for a continuous leak rate
Procedures
monitor
3.6.1.1
4.7.A.2.h;
Visualinspection of suppression chamber
Procedures
4.7.A.4.c
interior and vacuum breakers
3.6.1.2
4.7. A.2.f; Table
The value of Pa
TS Bases 3.7.2 Note 8
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DESCRIPTION OF RELOCATED ITEM
RELOCATION
3.6.1.3
Table 3.7.1
List of primary containment isolation
valves
3.6.1.3
4.7.D.2.b
Post maintenance testing on primary
Procedures
containment isolation valves
3.6.1.3
4.7.D.1.b.1
Details of surveillance testing
Procedures
3.6.1.3
4.7.D.1.b.2
Power level to perform MSIV testing
Procedures
3.6.1.3
4.7.D.1.c
MSIV testing method
Procedures
3.6.2.1
4.7.A.2
Suppression pool temperature monitoring
Procedures
3.6.2.3
4.5.8.1.d
Torus cooling MOV testing requirements
Procedures
t
3.6.4.1
4.7.C.1.c
Secondary containment capability testing
Procedures
prior to refueling
i
3.6.4.1
4.7.C.1.d
Testing of standby gas treatment after
Procedures
j
violation of secondary containment
'
3.6.4.1
3.7.C.1.d
Secondary containment integrity during
Procedures
fuel cask moves
I
3.6.4.1
3.7.C.1.c
Details of the design
4.9.A.1.2.1
Emergency diesel generator accelerated
Procedures
testing requirements
5.0
6.9.1.c
Requirements for reporting challenges to
Procedures
I
safety and relief valves.
5.0
6.9.2.h.1; 6.18
Changes to the Radwaste Treatment
i
System
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ATTACHMENT 1, SECTION 3
4
NEW SURVEILLANCE ITEMS
l
i
NEW SURVEILLANCE -
DESCRIPTION OF NEW SURVEILLANCE
l
REQUIREMENT
HPCI lsolation Drywell Pressure Channel Check
HPCI isolation Drywell Pressure Channel Functional
1
SR.3.3.6.1.5
HPCI Isolation Drywell Pressure Channel Calibration
HPCI Isolation Drywell Pressure Logic System Functional
RCIC isolation Drywell Pressure Channel Check
j
RCIC lsolation Drywell Pressure Channel Functional
RCIC isoiation Drywell Pressure Logic System Functional
RWCU lsolation on SLC initiation Logic System Functional
j
r
RWCU isolation on low water Logic System Functional
Shutdown cooling system isolation on low water level Logic
System Functional
Mainsteam kne isolation on high radiation Logic System Functional
Primary Containment Isolation reactor water level low isolation
Channel Functional
Primary Containment isolation reactor water level low isolation
]
Logic System Functional
i
Prirr.ary Containment isolation high drywell pressure isolation
Channel Functional
j
I
Primary Containment Isolation high drywell pressure isolation Logic
System Functional
Feedwater Recirculation isolation on reactor pressure high Logic
System Functional
1
Loss of Power Channel Functional
Loss of Power Channel Calibration
Loss of Power Logic System Functional
ECCS Spray / Injection Valve Test
LPCI Cross Tie Valve Position Test
Recirculation Pump Discharge Valve Operability Test
Secondary Containment Access Doors
SR. 3.6.4.1.3
Standby Gas Treatment
Standby Gas Treatment
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ATTACHMENT 2
EMERGENCY RESPONSE PLAN AND IMPLEMENTING PROCEDURES REVIEWED
Document
Document Title
Revision
No.
ERP-C-1000
EOF Activation / Deactivation
Rev.3
j
ERP-C-1200
Emergency Response Manager
Rev.6
ERP-C-1300
EOF Dose Assessment Team Leader
Rev.6
ERP-C-1300-1
Dose Assessment Team Leader initial Actions
Rev.1
ERP-C-1300-6
Assessment Group Initial Actions
Rev.O
ERP-C-1300-7
Obtaining EPDS MET / RAD Data
Rev.O
l
ERP-C-1300-8
Use of Mode A/ Mode B CDM
Rev.O
ERP-C-1300-9
Obtaining Met Data from National Weather Svc.
Rev.O
ERP-C-1320
EOF Field Survey Group Leader
Rev.4
ERP-C-1320-1
Field Survey Group Leader Initial Actions
Rev.1
ERP-C-1320-2
Field Survey Group Leader Turnover Sheet
Rev.1
ERP-C-1400
Engineering Support Team
Rev.3
ERP-C-1400-1
Engineering Support Team Checklist
Rev.4
,
ERP-C-1500
Logistic Support Team
Rev.2
ERP-C-1900
Recovery Phase implementation
Rev.2
ERP-C-1900-2
PBPS Recovery Acceptance Checklist
Rev.1
ERP-C-1900-3
LGS Recovery Acceptance Checklist
Rev.1
j
ERP-C-1900-4
Recovery Plan Outline
Rev.1
,