ML20129E469
| ML20129E469 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 08/23/1996 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20129E394 | List: |
| References | |
| 50-317-96-06, 50-317-96-6, 50-318-96-06, 50-318-96-6, NUDOCS 9610010090 | |
| Download: ML20129E469 (41) | |
See also: IR 05000317/1996006
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
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License Nos.
DPR-53/DPR-69
Report Nos.
50-317/96006;50-318/96006
Licensee:
Baltimore Gas and Electric Company
Post Office Box 1475
Baltimore, Maryland 21203
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Facility:
Calvert Cliffs Nuclear Power Plant, Units 1 and 2
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Location:
Lusby, Maryland
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Dates:
July 7,1996 through August 24,1996
Inspectors:
J. Scott Stewart, Senior Resident inspector
Henry K. Lathrop, Resident inspector
Fred L. Bower Ill, Resident inspector
Edward King, Physical Security inspector, DRS
Ron Albert, Physical Security inspector, DRS
David Silk, Senior Emergency Preparedness Specialist, Division
of Reactor Safety
Nancy McNamara, Emergency Preparedness Specialist, DRS
Thomas Moslak, Project Engineer, DRP
Gregory Galletti, Human Factors Specialist, NRR
Approved by:
Lawrence T. Doerflein, Chief
Reactor Projects Branch 1
Division of Reactor Projects
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9610010090 960923
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ADOCK 05000317
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EXECUTIVE SUMMARY
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Calvert Cliffs Nuclear Power Plant, Units 1 and 2
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Inspection Report Nos. 50-317/96-06 and 50-318/96-06
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This integrated inspection report includes aspects of BGE operations, maintenance,
engineering, and plant support. The report covers a seven week period of resident
inspection and includes the results of announced inspections by emergency preparedness
and security specialists. in addition, the results of a team inspection of the BGE corrective
action programs are summarized.
Plant Operations
A reactor coolant pump impeller replacement included an extended period of
reduced inventory and was accomplished safely with appropriate management
oversight and very good coordination of plant activities.
The inspectors considered the delay of outage maintenance and other preparations
for severe weather during the threat of Hurricane Bertha to be appropriately focused
on plant safety,
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The Unit 1 startup was well coordinated and completed with appropriate attention
to detail. Feedwater system operations during startup were completed smoothly
indicating that modifications to the feedwater control system made during the
outage were effective.
The identification of a nuclear instrument problem in the early phase of power
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escalation was an example of thorough monitoring of reactor protection system
(RPS) performance by operations and engineering personnel,
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The recurrence of mispositioning of safety related components following service
water system maintenance was considered evidence that additional attention was
needed to ensure that the heat exchanger realignment for maintenance did not
result in a reduction of system reliability. The issue was cited as a violation of NRC
requirements.
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Maintenance
The miswiring of two reactor protection system detectors required an unplanned
entry into technical specification 3.0.3 and a power reduction. The miswiring was
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repaired and power escalation was resumed. The inspectors considered the issue
unresolved pending completion of the BGE root cause evaluation.
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During emergency diesel generator testing (EDG) following maintenance, the engine
shutdown on high jacket water cooling temperature when the actual temperature
was normal. BGE identified that jacket water cooling temperature sensors had been
removed from the system, incorrectly calibrated, and replaced in the EDG.
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Although setpoint drift as high as 70 degrees was observed on the bench no
evaluation of continued operability of the switches was conducted and system
engineering personnel stated that they were not aware that the switches were
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Executive Summary (cont'd)
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found out-of-calibration. BGE conducted an extensive evaluation of the event and
identified root causes and specified appropriate corrective actions. The issue was
considered a non-cited violation in accordance with the NRC enforcement policy.
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Troubleshooting of reactor coolant pump high vibration was well-planned and
completed in a systematic manner. The subsequent pump replacement required
extensive preparations b/ maintenance, operations, engineering, and radiation
controls personnel. The replacement was well coordinated with proper focus on
nuclear and personnel safety.
Enaineerina
The continued operability of the service water system has been challenged by micro
and macrofculing of the service water heat exchangers. Repeated mechanical
cleanings have resulted in extended out-of-service time and has challenged
operations and maintenance personnel. BGE stated that the simultaneous
degradation of both trains of service water on August 21 was due to accelerated
and unanticipated biofouling from the Chesapeake Bay.
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Saltwater system pumps, pump motors, and pump discharge check valves have
been subject to recurring failures. Additional engineering attention appears
warranted to these problems.
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The inspectors concluded that BGE's investigation of the issues surrounding the
11B RCP suction deflector had been rigorous and detailed.
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Plant Sup' Arttr
Excellent ALARA principles were used to maintain a low overall exposure for the
Unit 1 reactor coolant pump replacement.
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BGE continued to maintain a good emergency preparedness program. The
emergency response plan and implementing procedures were current and effectively
implemented.
Emergency response facilities, equipment, instruments and supplies were found to
be maintained in a state of readiness. All required 1995 and 1996 surveillances
were completed. A sampling of emergency response organization personnel training
records indicated that training and qualifications were current, although the training
manual was not specific regarding required topics. Quality assurance audits and
surveillances were thorough and satisfied NRC requirements.
Based upon interviews and training records, BGE was found to maintain a very good
rapport with off-site agencies and support organizations.
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Executive Summary (cont'd)
BGE had an effective security program. Management support was good as
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evidenced by the timely completion of a computer software upgrade and aggressive
follow-up on security events that occur at other nuclear plants.
The inspectors found that central and secondary alarm station operators were
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knowledgeable of their duties and responsibilities and were not engaged in activities
that would interfere with their response functions.
Security training was being performed in accordance with the NRC-approved
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training and qualification plan. The nuclear security officers were found to possess
the requisite knowledge to carry out their assigned duties and that the training
program was effective,
Maintenance of security equipment was being performed in a timely manner as
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indicated by minimal compensatory postings associated with security equipment
repairs.
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The inspectors concluded that BGE audits of security activities were comprehensive
in scope and depth, that the findings were reported to the appropriate levels of
management, and that the programs were being properly administered.
Safety Assessment / Quality Verification
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The inspectors found that an appropriate threshold was being used for initiating
issue reports for potential conditions adverse to quality and an extensive process
with multiple barriers had been established for reviewing and prioritizing issue
reports. Appropriate controls were in place for resolving and escalating
disagreements identified during the review process. The inspectors also concluded
that effective controls were established to track the closure of issues and conditions
adverse to quality.
An effective program has been established for identifying and tracking issues to
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resolution. However, BGE management expectations concerning corrective action
timeliness and effectiveness monitoring were not being consistently met.
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Regular and thorough self-assessments and quality assuranco audits have been
generally effective in identifying issues and focusing management attention on
continued improvement of the corrective action process,
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Although root cause analyses were generally effective in describing the issues, the
probable causes, and recommending corrective actions, many examples of
weaknesses in the documentation of past similar events and planned effectiveness
reviews were noted. A BGE evaluation of the quality of issue reports and root
cause analyses was an initiative that has provided valuable program feedback.
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Executive Summary (cont'd)
Periodic, routine, reactive, and preemptive assessments were properly focused on
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safety; balancing compliance and performance issues. As a result, performance
problems were being identified, evaluated and effectively resolved to preclude
recurrence.
The Trip Prevention Program was a notable broad based initiative that has
apparently contributed to a reduction in the number of plant trips at Calvert Cliffs.
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TABLE OF CONTENTS
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EX E C UTIVE S U M M A RY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ii
TA B LE O F CO NT ENT S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vi
S u m m a ry of Pla nt St a t u s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
1. O p e ra ti o n s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
O1
Conduct of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.1 General Comments (71707) . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
01.2 ECCS Room Cooler Switch Not Restored Following
M a int e n a nc e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
07
Quality Assurance in Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
07.1 Problem Identification and Resolution
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07.2 Root Cause Analysis and Human Performance . . . . . . . . . . . . . . 6
07.3 Self-Assessment Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
I I . M a i nt e n a n c e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
M1
Conduct of Maintenance
12
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M1.1 Routine Maintenance Observations . . . . . . . . . . . . . . . . . . . . . 12
M1.2 - Emergency Diesel Generator Shutdown on High Jacket Water
Te m pe ratu re . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
M1.3 Reactor Coolant Pump Failure and Replacement . . . . . . . . . . . . 15
M 1.4 Unit 1 Reactor Protection System Detectors incorrectly
i n st a lle d . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
M1.5 Routine Surveillance Observations . . . . . . . . . . . . . . . . . . . . . . 18
Ill. Engineering
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E2
Engineering Support of Facilities and Equipment . . . . . . . . . . . . . . . . . 18
E2.1
Service Water Heat Exchanger Cleaning and Continued
Operability
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I V. Pl a n t S u p p o rt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
P1
Conduct of Emergency Preparedness (EP) Activities . . . . . . . . . . . . . . 20
P2
Status of EP Facilities, Equipment, and Resources
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P3
EP Procedures and Documentation
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P5
Staff Training and Qualification in EP . . . . . . . . . . . . . . . . . . . . . . . . . 23
P6
EP Organization and Administration . . . . . . . . . . . . . . . . . . . . . . . . . . 24
P7
Quality Assurance (QA) in EP Activities . . . . . . . . . . . . . . . . . . . . . . . 24
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P8
Miscellaneous EP Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
P8.1
Updated Final Safety Analysis Report (UFSAR) Inconsistencies
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P8.2 ERO Response and Availability . . . . . . . . . . . . . . . . . . . . . . . . 25
P8.3 Of f-site interf ace . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
P8.4 (Closed) Follow-Up Item 50-317&318/95-01-02:
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Taole of Contents (cont'd)
S1
Conduct of Security and Safeguards Activities . . . . . . . . . . . . . . . . . . 26
S7
Quality Assurance in Security and Safeguards Activities . . . . . . . . . . . 29
S8
Miscellaneous Security and Safeguards issues . . . . . . . . . . . . . . . . . . 29
V. Management Meetings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
X1
- Exit Meeting Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
L1
Review of UFSAR Commitments . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
ATTACHMENTS
Attachment 1:
Partial List of Persons Contacted
Inspection Procedures Used
items Opened, Closed, and Discussed
List of Acronyms Used
Attachment 2:
Partial List of Procedures Reviewed
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Report Details
Summarv of Plant Status
Unit 1 began the inspection report period in a refueling outage. Following repairs to the
11B reactor coolant pump, the reactor was taken critical on July 29 and Mode 1 was
entered on July 31. On August 2, Unit 1 was placed in Mode 2 following identification of
a problem with two channels of the reactor protection system (RPS). On August 3, the
unit returned to Mode 1 and full power was achieved on August 10. Unit 1 remained at
full power for the remainder of the report period.
Unit 2 remained at full power for the inspection period with exception of a planned power
reduction to 90 percent on August 2 for preventive maintenance.
1. Operations
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Conduct of Operations '
01.1 General Comments (71707)
Overall plant operations were conducted safely with a proper focus on continued
nuclear safety. The reactor coolant pump impeller replacement included an
extended period of reduced inventory and was accomplished safely with appropriate
management oversight and very good coordination of plant activities. The
inspectors considered the delay of outage maintenance and preparations for severe
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weather during the threat of Hurricane Bertha to be appropriately focused on plant
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safety.
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The Unit 1 startup was well coordinated and completed with appropriate attention
to detail. Feedvtater system operations during startup were completed smoothly
indicating that raodifications to the feedwater control system made during the
outage were eff 9ctive. The identification of a nuclear instrument problem in the
early phase of power escalation was an example of thorough monitoring of RPS
system performance by operations and engineering personnel. Continued
performance problems in the saltwater and service water systems challenged plant
operators and additional management attention in this area is warranted.
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During the inspection period, the inspectors reviewed the recent institute for
Nuclear Power Operations (INPO) performance evaluation of Calvert Cliffs Nuclear
Power Plant. No items for further NRC review were identified.
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' Topical headings such as 01, M1, etc., are used in accordance with the NRC standardized
reactor inspection report outline found in MC 0610. Individual reports are not expected to
address all outline topics.
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01.2 ECCS Room Cooler Switch Not Restored Followina Maintenance
a.
Insoection Scope
The inspectors reviewed BGE activities associated with the mechanical cleaning of
11 service water heat exchanger. Following the cleaning, operators returned the
system to operation using Calvert Cliffs Operating Instruction 01-29, " Saltwater
System." Operators subsequently determined that a safety related switch had not
been properly positioned during the restoration,
b.
Observations and Findinas
On August 13, the 11 saltwater system header was taken out of service for
bulleting of the 11 service water heat exchanger and other maintenance. Following
the maintenance, plant operators returned the header to service then established
conditions to complete a thermal performance test on the heat exchanger. The test
conditions included removing the 1B emergency diesel generator (EDG) from
service.
During the thermal performance test, operators determined that the 11 header
emergency core cooling system (ECCS) room cooler fan control switch,1-HS-5406,
was in the STOP position. The specified operational position for the switch was
AUTO to allow the fans to cycle on and off for ECCS pump room temperature
control. When the 1B EDG had been removed from service, the operators had
inadvertently entered technical specification (TS) 3.0.5, because the 11 ECCS room
cooler was out of service due to the switch position and the 12 ECCS room cooler
backup power supply was out of service due to the 1B EDG. The operators
formally entered the action statement which required unit shutdown if at least one
train of room coolers were not made fully operable within two hours. The
inspectors noted that the Calvert Cliffs Updated Safety Analysis Report, Section
9.8.2.3, states that operation of the ECCS pump room ventilation and the resultant
effects on offsite dose calculations were assumed in the accident analysis.
Within minutes of discovery, the switch was returned to the AUTO position and the
technical specification was exited. The operations department initiated a review of
the occurrence and identified that the reactor operators had improperly performed a
procedure step which placed the fan switch in the AUTO position when returning
the saltwater header to service. A root cause evaluation of the occurrence was
initiated by BGE.
During July and August, the reactor operators had aligned saltwater and service
water systems for heat exchanger cleaning nominally twice per week and had also
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completed other corrective maintenance system alignments. On March 20,1996,
the 21 service water heat exchanger had been removed from service and, on
restoration, blowdown recovery valve 2-SRW-640 was not placed in the correct
position. The March 20 occurrence was considered a noncited violation of NRC
requirements in accordance with Section Vll.B of the NRC enforcement policy,
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(NUREG 1600). The recurrence of a failure to properly position safety related
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components following service water system maintenance on August 13, was
considered evidence that the BGE corrective actions for the March 20 occurrence
were not effective. The inspectors were concerned that the switch mispositioning
following heat exchanger cleanings had resulted in a reduction of safety system
reliability. The failure to follow procedures during the return to service of the
11 saltwater header following maintenance was considered a violation of NRC
requirements (VIO 50-317&318/96-06-01).
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C.
Conclusions
During July and August, each service water heat exchanger was required to be
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mechanically cleaned every two weeks. Therefore, operators made SW heat
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exchanger lineup changes about twice per week. On two occasions, one of which
occurred during this inspection period, safety related components were not returned
to their normal operational position during restoration from the cleanings. The
recurrence of mispositioning of safety related components following service water
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system cleanings was considered a violation of NRC requirements. Additional BGE
management attention was needed to ensure that heat exchanger realignment from
maintenance did not result in a reduction of system reliability.
07
Quality Assurance in Operations
07.1 Problem Identification and Resolution
a.
Jnspection Scoce (40500)
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The inspectors reviewed BGE's processes for identifying, tracking, reviewing,
resolving, and preventing recurrence of problems. A sample of issue reports (irs),
program deficiency reports, corrective action reports, and associated administrative
procedures were reviewed. The inspection also included observations of issue
report review group (IRRG) meetings and interviews cf BGE personnel. Although
the IR process is for both hardware and programmatic problems, this inspection
concentrated primarily on issues in the programmatic portion of the IR process.
b.
Observations and Findinas
BGE procedure OL-2-100, " Issue Reporting and Assessment," provided for initiating,
reviewing, and processing issue reports for controlling hardware and equipment
deficiencies and for resolution of issues. The procedure was most recently revised
in January 1996 to incorporate management expectations that were expected to
address concerns related to the timeliness and effectiveness of the corrective action
program. Two main areas of concern with the corrective action program were
quality of root cause analyses (RCAs) and issue resolution.
The inspectors found that issue reports were initiated by BGE staff and included the
hardware and/or non-hardware information, and whether there were safety,
operability, reportability, or trip concerns. If any of these concerns were identified
immediate supervisory was required; otherwise, three days were specified for
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supervisory review. In the plant, tags were used to identify hardware or equipment
that had outstanding issue reports. Between July 1,1995, and June 30,1996,
10,125 issue reports were initiated to identify 6918 hardware issues, 2587
programmatic issues, and 610 issues that were included in both categories. Based
on a review of a sample of issue reports the inspectors concluded that BGE
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personnel effectively identified and documented problems with an appropriate
threshold.
Following documentation, hardware issues were forwarded to the operations
maintenance coordinator for verification that an operability concern did not exist and
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initiation of a maintenance work order. Programmatic issues were forwarded to the
issues assessment unit (IAU) for independent screening and entry into the IR
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tracking system. Issues that contained both hardware and programmatic facets
were processed by both groups.
The Issues Assessment Unit (IAU) screener performed an initial review of issue
reports for programmatic issues, mode change restraints, security concerns,
Appendix R concerns, and assigned a safety significance classification. Those
programmatic issues at the lowest level of significance (L-3) were closed without
further action. Work orders for low priority hardware issues were tracked in the
maintenance tracking system. Those issues at the highest level of significance (L-1)
were processed in accordance with QL-2-103, " Program Deficiency Reporting."
Program Deficiency Reports required quality assurance to review proposed
corrective actions and estimated completion dates. Quality assurance was also
responsible for verification of the corrective actions prior to the closure of program
deficiencies.
The issue reports with a significance classification of L-2 were screened and
processed further by the IAU to identify a proposed issue resolution sponsor and to
assign a category. The IAU screener used a risk matrix that was based on
significance and recurrence probability factors to categorize class L-2 issue reports.
These issue reports were , ut into one of three categories: category lil required no
formal documentation of corrective action; category 11 required cause determination
and tracking to completion; and category I required a formal root cause analysis
(RCA) and lAU verification of completion. Of the 3197 programmatic issue reports
initiated between July 1,1995, and June 30,1996,410 were determined to be
category I issue reports requiring an RCA.
An assigned BGE sponsor determined the appropriate level of corrective and
preventive actions for each issue report. OL-2-100 identified several management
expectations related to the resolution process. For category I and ll issue reports,
acknowledgement of the issue report in the tracking system was expected within
seven days and establishment of a completion due date was expected within an
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additional 14 days. Additionally, QL-2-100 required the development of milestones
for verifying the effectiveness of corrective actions for each category I issue report.
OL-2-100 identified a goal that category I issue report be resolved within 90 days.
However, due dates were expected to be established based on priority. Extensions
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were expected to be justified based on safety significance and the probability of
recurrence prior to the completion of corrective actions.
A BGE quality assurance audit of the corrective actions program in April 1996,
identified that some issue reports were not being reviewed and accepted by the
resolution sponsor within the 21 days allotted. The audit noted that plant
engineering section (PES) had worked effectively with the IAU to implement
corrective actions that would eliminate the 21 day delay. Discussions with PES
personnel indicated that this was achieved by having the PES representative to the
IRRG cccept issue reports with a blanket 90 day due date immediately after each
IRRG meeting. The inspectors questioned whether this corrective action met the
management expectation that due dates Se' established based on priority. BGE
management stated that future issue report due dates would be prioritized and that
the backlog of issue reports in PES would be reviewed to verify that an appropriate
due date was assigned.
BGE also identified that the goal of 90 days for fully resolving category I issue
reports was being exceeded. The average time to complete RCA was 185 days and
the average time to achieve resolution was 271 days. -The oldest outstanding RCA
was 823 days as of July 17,1996. BGE management had identified this as an
issue and a team was assembled to complete a priority 2 root cause.
A sample of issue reports that had root cause and resolution due dates extended
was reviewed to assess the adequacy of the justification for extension, in terms of
risk to safety and/or probability of recurrence. The inspectors found that 9 of 10
extension forms were marked to indicate that the risk was considered but they did
not have documented justification. Discussions with BGE management indicated
that documented justification was expected and that this expectation would be
reinforced. An issue report was written to capture and investigate the issue and -
identify corrective actions.
The most recent revision to QL-2-100 added an action item to track the
performance of an effectiveness review of corrective actions for category Iissue
reports. Discussions with BGE personnel indicated that the process enhancement to
review the effectiveness of corrective actions for each category Iissue report was
not being consistently implemented by all site groups. The inspectors noted that
although this has been highlighted in several status reports to management since as
early as April 1996, no issue report had been issued to investigate and resolve this
issue. An issue report was generated during this inspection and BGE management
indicated that this management expectation would be reinforced.
The inspectors discussed the information in the administrative procedures with
several staff members from operations, plant engineering, maintenance, IRRG and
the IAU. In all cases individuals were knowledgeable of the guidance regarding the
issue report and RCA screening and review processes, reviewer responsibilities,
categorization of the issue reports, und the prioritization of RCAs.
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BGE evaluated the effectiveness of the Corrective Action Program (CAP) by mid-
year self-assessments performed by the issues Assessment Unit. As a result of
critical evaluation, changes were under review for improving the timeliness and
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methods for gauging process effectiveness. The inspectors concluded that candid
evaluations of the corrective action program had been conducted that identified
where BGE management attention should be directed.
c.
Conclusions
The inspectors found that an appropriate threshold was being used for initiating
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issue reports. An extensive process with multiple barriers had been established for
reviewing and prioritizing issue reports. IAU and IRRG categorization of issue
reports was found to be conservative. Appropriate controls were in place for
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resolving and escalating disagreements identified during the review process. The
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inspectors also concluded that effective controls were established to track the
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closure of issues and conditions adverse to quality.
The inspectors concluded that an effective program has been established for
identifying and tracking issues to resolution. The BGE management expectations
concerning timeliness of issue report closures, justification of extension of issue
report closures, establishing due dates based on priority and significance, and
performance of effectiveness reviews were not always met; however, based on the
irs reviewed, no immediate safety concerns were noted. Regular and thorough
self-assessments by BGE have identified timeliness issues and focused management
attention on continued improvement of the corrective action process.
07.2 Root Cause Analysis and Human Performance
a.
Inspection Scone
The inspectors reviewed the BGE programs for root cause analysis (RCA) to assess
the adequacy of the related administrative controls and implementing procedures,
and to ensure that the BGE staff were performing the root cause analyses in a
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manner consistent with this guidance. A sample of root cause analyses were
reviewed to ensure that the issues were adequately described, that causes were
identified, and that recommendations were appropriate. The inspectors reviewed
the BGE methods of trending and evaluating the results of RCAs and BGE training
on RCA and human performance investigations.
b.
Observations and Findinas
The root cause analysis programs were controlled primarily through site quality
assurance administrative procedures OL-2-100, " Issue Reporting and Assessment,"
and QL-2-101, " Event investigations and Root Cause Analysis." Several line
organizations had further implementing guidance for their specific RCA reports,
including self-evaluation of RCAs (e.g., Plant Engineering Guideline (PEG)-6, " Root
Cause Analysis").
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The inspectors reviewed the guidance in OL-2-101 regarding the categorization of
issue reports and the criteria used to prioritize the level of RCA required for a given
issue. A sample of issue reports were reviewed to determine if the resolution
sponsor's classification of the report was commensurate with the guidance in OL-2-
101 and to determine if the reviewers were qualified (i.e., had completed human
performance evaluation system (HPES) or other root cause training) to perform the
reviews. The inspectors found the root cause program to be effective for
identifying plant and personnel performance issues, determining the causes for the
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events, and providing reasonable recommendations for preventing recurrence of the
issues. The inspectors noted that in all cases, individuals assigned responsibility for
the RCA review had completed the BGE required RCA training. The inspectors
observed that the level of detail associated with the report narratives, probable
j
causes for the events, and proposed corrective actions generally appeared
appropriate. However, the inspectors determined that the current implementation of
the OL-2-100 and OL-2-101 guidance appeared to be non-uniform across line
organizations with respect to content of the RCA reports as well as categorization
when irs require an RCA.
A review of a sample of irs and RCAs indicated that various interpretations of
QL-2-101 guidance were being implemented. Guidance for RCA content regarding
past identification and treatment of similar events, and inclusion of an effectiveness
j
monitoring discussion were not consistent. In some cases there did not appear to
be any method to determine if similar events were identified or evaluated. In many
cases the sources of the historical information provided were not apparent.
Additionally, the inspectors could not determine if appropriate databases had been
reviewed in cases where the screenings were not documented. For those reports
where similar events were identified, the corrective actions associated with the
i
earlier incidents were not consistently recorded, in at least one instance the
)
corrective actions following RCA were not documented in such a manner that they
'
could be retrieved for the review.
The inspectors reviewed the database of issue reports since January 1,1996 to
{
determine what percentage of reports were being downgraded from Category I
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(RCA required) to other categories which do not require such review. The data
indicated that severalline organizations were frequently downgrading the issue
report categorizations contrary to the IRRG recommendations and the guidance from
QL-2-100 and QL-2-101. Discussions with BGE staff indicated that in some cases
the issue reports were downgraded as a result of additional information on the issue
being subsequently identified. One area where it appeared that a large percentage
of downgrades were occurring involved the implementation of the OL-2-101 criteria
for the functional failure of the maintenance-rule scoped equipment. BGE staff
noted that the issue was primarily one of interpretation of what constituted a
functional failure and not one of downgrading issue reports which were determined
to be functional failures. BGE acknowledged that there was a need to clarify the
criterion in QL-2-101 and to disseminate management expectations in this area.
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The inspectors reviewed the methods employed by the BGE operations,
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maintenance, and plant engineering departments as well as the operations
1
.
.
8
experience group (OER) to determine if controls were in place to effectively evaluate
the quality of the RCAs issued. The inspectors reviewed sample documents and
discussed the program effectiveness with management and OER personnel, in all
cases BGE personnel were knowledgeable of the methods used tc assess the RCA
,
programs and were able to provide written reports and discuss the self-assessment
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findings from their organizations. The plant engineering group developed detailed
RCA evaluation criteria which was incorporated into their departmental procedures.
This evaluation tool provided a method for supervision to judge the thoroughness of
root cause investigations. This method was being considered by BGE for site-wide
implementation at the time of the inspection.
1
In addition the inspectors reviewed the various databases the line organizations had
established to track their human performance and equipment performance issues.
j
In all cases the databases provided a detailed method for trending and tracking
information. The inspectors noted that as a result of developing these databases
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BGE had been able to identify some negative equipment and personnel performance
trends and take actions (e.g., initiate issue reports, develop event free seminars) to
further identify and correct the problems. In addition the databases were used to
provide insight on precursors to potential performance problems. Most notable was
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the operations gold card program database which provided operations line
J
management with an effective tool for assessing operations performance and was
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used routinely to support their event free seminar reports.
,
c.
Conclusions
The inspectors concluded that the RCA programs were generally effective in
providing detailed narratives of the issues, the probable causes for the eyents, and
proposed recommendations for mitigating recurrence. However, the inspectors
noted the format and content of RCAs varied widely among line organizations and
weaknesses were noted in the documentation of past similar events and planned
effectiveness reviews. The inspectors also noted many examples where RCAs were
apparently downgraded due to lack of explicit guidance in administrative control
documents. BGE acknowledged that there was a need to clarify the management
expectations in this area.
The inspectors concluded that the BGE evaluation of the quality of issue reports and
RCAs provided valuable program feedback. The reviews of human and equipment
performance that the line organizations as well as those the IAU and OER groups.
conducted were considered a proactive initiative directed at continuous
improvement.
07.3 Self-Assessment Activities
a.
Insoection Scope
The scope of this inspection was to evaluate the effectiveness of the self-
assessment activities including the scope and frequency of periodic audits, routine
assessments, pre-emptive assessments performed prior to implementing major
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programmatic changes, and reactive assessments conducted in response tc site
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incidents.
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b.
Observations and Findinas
BGE's phitusophy and expectations for conducting self-assessments were
I
articulated by senior management in nuclear program policy and mission
statements. These expectations for " continuous quality improvement" had rerulted
in the self-assessment process being ingrained into the normai work routines of the
site departments as well as formalized, detailed, periodic audits of station activities.
i
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The Quality Audits Section within the Nuclear Quality Assurance Department had.
responsibility for carrying out routine audits as required by 10CFR50 Appendix B.
The inspectors reviewed a sample of completed audits addressing the Corrective
Action Program (Audit 96-02), Nuclear Safety Oversight (Audit 96-03), Special
Processes (Audit 96-06), and Fuel Management & Independent Spent Fuel Storage
Installation (Audit 96-08).
The inspectors determined that the audits were performed at the proper frequency,
addressed performance as well as compliance related issues, documented findings
in issue reports (IR) and program deficiency reports for departmental response and
action plan development, and received the appropriate level of management
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attention. The assessments were constructed using procedure OL-3-300, " Audit
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Program," for developing checklists to assure pertinent safety issues and
departmental performance were appropriately addressed. Particular noteworthy is
that audit findings as a separate entity are eliminated and are promptly captured as
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issue reports or program deficiencies for expeditious follow-up.
f
Routine self-assessments were a continuous process within the Calvert Cliffs
j
organization.' The inspectors reviewed these activities within the Operations and
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Nuclear Engineering Departments. Operations Administrative Policy 91-8,
" Operations Self-Assessment Program," provided the methodology and the
1
responsibilities for the operations staff and management to critically evaluate and
track watchstanding, procedural use, shutdown safety, and various operational
practices to identify process improvements. Through a combined strategy, program
elements included supervisory observations, gold card (documentation identifying
low threshold concerns that do not require an Issue Report), administrative reviews,
]
and operator rounds validation audits. - Twenty-two separate checklists identifying
specific management expectations were provided to assist supervision in observing
such diverse activities as post-maintenance testing, procedure use, radiological
j
controls practices, and plant operator rounds. Strengths and weaknesses were
rated and the results were discussed with the individual observed. A matrix
classifying operational significant incidents caused by personnel or procedural
inadequacy by severity level and documentation of "near misses" using the gold
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cards and issue reports provided a method of identifying event precursors and
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recognizing negative performance trends. Data was categorized and compiled in the
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Operations Monthly Performance Indicator Report for management review and
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overall performance trends were graphically presented for communications, self
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verification, conservative decision making, demonstration of a questioning attitude,
pre-evolution briefs, and responsibility / accountability.
A similar self-assessment program was established in the Nuclear Engineering
Department, using the gold card (customized to engineering activities) as the
primary means of reporting and tracking low-threshold concerns that affect the
quality and effectiveness of this department's products and services.
Quarterly safety performance evaluations were performed by the Plant Operating
Experience Group of the Operating Experience Review (OER) section. These reports
assessed operations, engineering, maintenance, and plant support using the
categories of performance indicaters, events, and performance management (self-
assessment, corrective actions, and precursors). Scoring of these categories
'
provided a ready measurement of adverse performance symptoms and facilitated
management analysis of contributing factors. The Industry Operating Experience
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Group of the OER section performed reviews to apply industry experience to
l
Calvert Cliffs. The inspectors concluded that relevant industry experience was
being screened and systematically applied to site activities.
'
Refueling Outage self-assessments were conducted. The assessment was a joint -
effort of departmental site managers to critique the control and execution of outage
related activities from the standpoint of pre-outage planning and scheduling, change
control, contingenc/ planning, control of high risk evolutions, and identification of
3
incident precursors,
j
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A Joint Utility Management Audit, in which an independent audit by external (third
j
party) organizations, was performed to assess the effectiveness of the Nuclear
i
Quality Assurance Department (NOAD) programs and initiatives. In response to
audit findings, several NOAD program enhancements were underway including
establishment of an Audit Process Improvement Team, development of an
Operations Integrated Assessment Team (in which a multi-disciplinary team
performs quarterly audits vice a biannual audits by a sole auditor), and re-alignment
i
of responsibilities within the NOAD.
!
As a result of the maintenance rule implementation shortcomings identified in a
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4th Quarter BGE Multi-Area Audit (95-04), BGE management directed that a
dedicated assessment be performed by a consultant to correct program deficiencies
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prior to the Rule's effective date. The results of this effort have better prepared site
!
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organizations for carrying out the regulatory requirements.
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Reactive self-assessments have been performed by the Independent Safety
Evaluation Group (ISEG) within the Operating Experience Review Section. The
!
inspectors reviewed ISEG Evaluation 95-16 that addressed differences between the
approved plant configuration drawings and the actual field conditions. This
evaluation was found to be of high quality; addressing root causes, safety
i
implications, and corrective actions. This effort was a prompt and aggressive
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response to issue reports that captured print /as-found mismatches.
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in response to a high reactor trip rate during 1994 and 1995, BGE management
directed that a causal analysis be performed and corrective actions be implemented
to preclude recurring problems. Four causes were identified: (1) certain activities
were conducted without an adequate evaluation of trip potential, (2) an inconsistent
discipline in problem solving and work control was applied before and after events,
(3) an inconsistent accountability to site standards and expectations existed, and
(4) equipment aging was not aggressively managed. Corrective action plans were
developed for each of these causes and responsibilities assigned.
Collectively the resolutions are known as the " Trip Prevention Program" and consist
of a variety of supporting programs. Specific programs included: the Event Free
Operations program that provided performance indicators and trending mechanisms
for "near misses" and unplanned plant transients as a means to identify incident
precursors; the development and use of the "Why Staircase" to comprehensively
evaluate critical factors, including the human performance, behavioral and work
culture aspects, contributing to an incident; and the development of system Report
Cards for evaluating and trending the performance of selected systems. Additional
corrective actions included the identification of trip sensitive equipment and areas,
wide dissemination of performance standards / expectations to site personnel, and
initiation of the Reactivity Management Program and the System Maintenance
Improvement (SMI) plan. The inspectors concluded that the Trip Prevention
Program was a broad based initiative that has apparently contributed to a significant
reduction in the number of plant trips at Calvert Cliffs.
The inspectors reviewed two "Why Staircase" case studies: (1) Case Study 9 that
addressed the partial loss of off-site power and reactor trip of February 29,1996,
and (2) Case Study 10 that addressed the potential fatal near-miss when keys on an
electrician's belt touched an energized circuit on April 15,1996. The case studies
addressed (per the established methodology) accurate event description, specific
symptoms leading to the event, problems resulting from procedure non-adherence,
programmatic shortcomings, team behavioral traits, and work culture weaknesses.
In response to the lessons learned, supervision was tasked with providing staff
training to improve work controls.
c.
Conclusions:
BGE management had used self-assessments as a tool to monitor progress in
achieving performance goals through a continuous quality improvement philosophy.
Periodic, routine, reactive, and pre-emptive assessments were properly focused on
safety and balanced compliance and performance issues. Resources were available
and utilized for tracking, trending, and retrieving assessment data. Through the
self-assessment process, performance problems were being promptly identified and
comprehensively evaluated. In particular, the Trip Prevention Program was a
notable broad based initiative that has apparently contributed to a reduction in the
number of plant trips at Calvert Cliffs.
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11. Maintenance
M1
Conduct of Maintenance
M1.1 Routine Maintenance Observations
Using Inspection Procedures 62703,62707, and 61726, the inspectors observed
the conduct of maintenance and surveillance testing on systems and components
important to safety. The inspectors also reviewed selected maintenance activities
to assure that the work was performed safely and in accordance with proper
procedures. The inspectors noted that an appropriate level of supervisory attention
was given to the work depending on its priority and difficulty. Maintenance
activities reviewed included-
MO1199600459
Repack Manual Valve 1-SI-311
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M01199504597
Votes Test 1-SI-656 MOV
MO2199601410
Sample Oil and Lubricate 21 AFW pump Turbine
MO1199603264
Replace 11 AFW Pump Inboard Bearing
MO2199603238
Clean Tubes in No. 21 Service Water Heat Exchanger
M1.2 Emeraency Diesel Generator Shutdown on Hiah Jacket Water Temoerature
a.
Inspection Scope
The inspectors reviewed scheduled preventive maintenance conducted on an
emergency diesel generator (EDG) during plant operation. The inspection was
focused on the BGE evaluation of crankshaft strain and a calibration check of jacket
water cooling temperature sensors. An engine shutdown that occurred due to high
jacket water temperature during testing that followed the maintenance was also
reviewed,
b.
Observations and Findinas
On July 10,1996, scheduled preventive maintenance was initiated on the 2A EDG.
The maintenance included an evaluation of crankshaft strain and a calibration check
of the jacket water cooling temperature sensors. BGE stated that the crankshaft
strain was monitored to ensure that excessive loads were not placed on the engine
crankshaft, particularly from generator misalignment, which could cause premature
bearing failure.
During the preventive maintenance, BGE identified a crankshaft strain of -0.00275
inches which exceeded the vendor recommended allowable range of 0 to
.002
inches. The vendor was contacted and BGE initiated additional inspections to
evaluate wear to the crankshaft bearings and to check overall engine alignment.
Also, an evaluation of continued operability was completed.
The additional inspections did not identify any unusual component degradation.
BGE stated that allinspections and measurements on the main and generatcr
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bearings were within specifications. Oil and grease samples did not indicate bearing
erosion. Additionally, BGE identified no other indications of alignment problems.
BGE stated in their operability determination that the condition was a slow trend of
increasing strain that would not result in equipment damage without additional
indication. To ensure that the additional indications were identified, BGE specified
additional monitoring and specified a temporary strain limit of -0.004 inches. Also,
generator vibration data would be evaluated to monitor generator bearing
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performance during engine operation.
)
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The preventive maintenance also included a calibration check of the three jacket
water cooling temperature switches. The temperature switches were removed from
the engine for the calibration check which was done in accordance with BGE
Technical Procedure FTI-339, " Calibration of Allen Bradley Temperature Controllers
and Switches." The procedure specified that the switches be placed, one at a time,
in a temperature bath in which the temperature was slowly raised or lowered until
the switch tripped or reset, as appropriate. A temperature standard was also placed
)
in the temperature bath for the calibration.
j
On July 10, the instrument technicians used a dry block heat source instead of a
water bath as was customary for the calibration check. The procedure did not
specify a heat source for the calibration. The inspectors were told by BGE that the
dry block was selected because the temperature controllers were known to drift
high out-of-specification, were calibrated to 195 i2,200 *2, and 20512 degrees
,
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Fahrenheit PF), and the water bath was not able to be easily raised to these
temperatures.
The calibration of the temperature switches resulted in the following adjustments, in
degrees Fahrenheit.
1
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July 10,1996
TS-4803
TS-4804
TS-4805
AS FOUND
263
237
275
AS LEFT
197
201
205
!
DESIRED
195i2
200 i 2
205 i 2
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ADJUSTMENT
-66 Deg
-36 Deg
-70 Deg
After calibration, the switches were reinstalled in the engine cooling system. The
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post-maintenance operability test was conducted on July 12,1996. Approximately
46 minutes after start of the engine, the high jacket water temperature alarm
3
actuated. Personnel in the diesel room noted that indicated jacket water
temperature was normal, at about 158 F, the engine was running as expected, and
other engine temperature indications were normal. Within two minutes after the
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high temperature alarm, the engine shutdown on high jacket water temperature
when temperature switches, TS-4803 and TS-4805 actuated.
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Engineering review of the engine shutdown indicated that a problem with the
temperature switches might have been the cause. The switches were removed
from the diesel and a calibration check was performed using the wet bath as a heat
source. The switch setpoints were found approximately 50 degrees below the
desired values at 153,168.5, and 158.3 F for TS4803,4804, and 4805,
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respectively.
BGE evaluation of the miscalibration identified that use of a dry bath heat source
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contributed to the problem. It was determined that the dry bath heat blocks did not
provide an equilibrium temperature for the particular switches because the insertion
length of the switch did not fully match the receptive fit of the dry bath and the dry
bath did not provide even heating over the length of the switch because the upper
portion of the dry bath was not heated. The temperature standard properly
indicated dry bath temperature but in the configuration used to calibrate the
switches, the sensed temperature was not that of the inserted switch.
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BGE retrieved new temperature switches from stock and after calibration using a
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wet bath heat source, installed the switches in the generator and completed a
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successful operability test. The dry block heat sources were removed from service
and an operability evaluation of components calibrated using the dry block was
completed.
The inspectors considered the installation of miscalibrated temperature switches in
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the 2A EDG to be a safety significant issue. Specifically, had the miscalibration
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gone undetected during the operability run, the diesel may not have been available
to provide safety related needs following a loss of offsite power event.
Additionally, the miscalibration of the temperature sensors was an example of a
common mode failure for the water cooled EDGs.
I
The inspectors reviewed calibration history for the temperature switches and found
that in the previous two calibrations in March 1994 and January 1992, switch TS-
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4803 had drifted two degrees low but otherwise, no adjustments were required.
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Calibrations prior to 1992 required negative setpoint adjustments because the
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switches had drifted high. The inspectors questioned BGE as to the acceptability of
returning to service temperature sensors with an identified as-found drift as high as
70 degrees. BGE stated that replacement of the switches was scheduled for
i
October 1996, therefore the occurrence was an isolated case and excessive sensor
drift was not considered in returning the switches to service. No evaluation of the
]
observed setpoint drift was conducted and system engineering personnel stated
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that they were not aware that the switches were found out-of-calibration.
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BGE conducted a root cause evaluation of the factors that contributed to the engine
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shutdown during testing on July 10. The factors identified by BGE included that
the test equipment shop was not consulted when the dry bath was selected for
calibration, technicians were not familiar with the differences between the dry bath
calibrators and the wet bath, and both the technicians and supervision did not
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recognize when they had deviated from routine practice, therefore evaluation of the
I
change was not conducted. Corrective actions addressed the identified causes.
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The inspectors considered the issue to be a violation of 10CFR 50, Appendix B,
Criterion XII, Control of Measuring and Test Equipment, which required that
instruments be properly calibrated. However, because the issue was identified by
BGE, including completion of a formal root cause evaluation, corrective actions have
been specified and were being implemented, the miscakbration was not willful, and
the occurrence was not a repeat occurrence, discretion not to issue a Notice of
Violation was used in accordance with NUREG 1600, Section Vil, B.1.
c.
Conclusions
During 2A emergency diesel generator maintenance on July 10, Jacket water
cooling temperature sensors were removed from the system, incorrectly calibrated,
and replaced in the EDG, As a result, the engine shutdown on high Jacket water
cooling temperature when the actual temperature was as expected. Although
setpoint drift as high as 70 degrees was observed on the bench, no evaluation of
continued operability of the switches was conducted and system engineering
i
personnel stated that they were not aware that the switches were found out-of-
calibration. BGE conducted an extensive evaluation of the event and identified root
causes and specified appropriate corrective actions.
BGE identified the 2A EDG crankshaft strain exceeded the vendor
recommendations. BGE actions to evaluate the issue, perform an operability
determination, and perform additional monitoring were appropriate.
M1.3 Reactor Coolant Pumo Failure and Reolacement
a.
Inspection Scope (71707)
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The inspectors reviewed the circumstances surrounding mechanical failure of the
118 reactor coolant pump (RCP) and its repair, The inspectors also assessed BGE's
root cause analysis of the failure.
b.
Observations and Findinas
On July 7, in preparation for Unit 1 startup, control room operators started the 11B
RCP. Immediately after pump start, increasing vibration was observed. When
vibration increased rapidly from the normal 8-10 mils, operators tripped the pump.
The maximum vibrations recorded were 34 mils on the motor and 73 mils on the
pump.
BGE suspended preparations to restart Unit 1 and formed an investigative team to
diagnose the cause of the high vibration. The team conducted troubleshooting in a
preplanned sequence so as to not destroy any potential evidence. No problems
were found with either the motor or the motor pump alignment. The motor bearings
and the pump hydrostatic bearing were also found in good condition. Upon
examination of the pump casing and impeller using a camera placed inside the
reactor coolant system, BGE found that the suction deflector had broken off and
wedged against one of the impeller vanes. The suction deflector was normally held
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16
in place by two 51/2 inch long, A-286 stainless steel cap screws, torqued to 50 ft-
Ibs. The cap screw was prevented from backing out by a tack-welded locking bar
on the cap. BGE found that both of the cap screws for the suction deflector had
broken at the thread / shank interface and one of the screws had broken the locking
bar. Den the locking bar and the broken screw were missing. The other cap screw
althoi go broken at the shank, remained attached to the deflector bv the locking bar.
The pump was removed from the reactor coolant system and inspeciions verified
,
that the cap screw and locking bar were the only missing parts. The pump impeller
remained intact with no evidence of erosion or damage. A search of the reactor
coolant piping in the vicinity of the removed pump was conducted and neither of
the missing parts was found. Also, the cold-leg resistance temperature detector
(RTD) wells downstream of the RCP were examined visually and by inserting a rod
in each well to detect any bending which could have resulted from impact by the
failed cap screw. No abnormalities were observed.
The rotating assembly of the 11B RCP was replaced with a new assembly that did
not incorporate a suction deflector. In this model, the impeller was welded to the
pump shaft to eliminate suction deflector failures and to improve pump shaft
balance. Also, BGE inspected the 11 A,12A and 12B RCPs and found no indication
of degradation to the suction deflectors, cap screws or locking bars for these
pumps. The pump replacement required extensive planning and preparations by
maintenance, operations, engineering, and radiation controls personnel. Component
staging, reactor coolant system inventory control, and maintenance conduct were
well coordinated with significant focus on nuclear and personnel safety. Cameras
were used to limit personnel exposure and the replacement was conducted with an
overall exposure of 4.2 person-rem.
BGE performed an evaluation of the potential deleterious effects of the missing cap
screw and locking bar on the RCS. Based in part on previous experience with the
failure of the 22B RCP suction deflector in June 1987, BGE concluded that the most
likely location of the broken cap screw was the flow skirt region of the reactor
vessel. An analysis performed in 1988 by Combustion Engineering (CE)
demonstrated that in the worst case, the cap screw would not erode through the
cladding of the reactor vessel over the period of the operating cycle. This worst
case required that the cap screw remain agitated by RCS flow in one location for
the operating cycle. The analysis also determined that the resultant corrosion
would be minor if wear through the clad occurred.
BGE coulu not limit the iocation of the missing locking bar to areas outside the fuel
assemblies. Because Calvert Cliffs used fuel assemblies (216 out of a total of 217)
incorporating a special debris filter on the bottom of each assembly (Guardian"
fuel), there was a reduced possibility of fuel damage due to erosion from the locking
bar. BGE indicated that operation of Unit 2 after the 228 RCP event resulted in five
fuel pia leaks over the period, which was about normal for that time. To date, there
were no known debris-related failures of Guardian * fuel either at Calvert Cliffs or
other CE plants using that fuel. The BGE analysis concluded that fuel damage due
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to debris from the failed suction deflector was bounded by technical specification
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fuel damage limits.
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BGE also , valuated the possibility of future suction deflector failures and concluded
that th:. cap screw failures observed were unlikely once the RCPs were in operation.
The analysis indicated that the failure of the deflector cap screws occurred on pump
start due to high torque on the deflector plate. Hydrostatic pressure and the recess
into which the deflector was fitted held the deflector in position when the pump
was running, regardlest of cap screw condition. BGE also evaluated each of the
other uses of the A-286 stainless steel materialin the RCS and concluded that no
significant hazard to continued reactor operation existed.
Based on the results of the analysis and review by the plant operations safety
review committee (POSRC) the plant general manager concluded on July 25,1996,
that there were no adverse safety consequences from the missing parts and
authorized restart of Unit 1. Additionally, there were no identified concerns with
the continued operation of Unit 2.
c.
Conclusions
A reactor coolant pump replacement required extensive planning and preparations
'
by maintenance, operations, engineering, and radiation controls personnel.
Troubleshooting was well-planned and completed in a systematic manner. Excellent
ALARA principles were used to maintain a low overall exposure for the effort. The
replacement was well coordinated with proper focus on nuclear and personnel
safety.
The inspectors concluded that BGE's investigation of the issues surrounding the
11B RCP suction deflector had been rigorous and detailed.
M1.4 Unit 1 Reactor Protection System Detectors Incorrectiv Installed -
On August 2, during power esec'ation following the Unit 1 refueling outage, BGE
,
personnel noted a diverging trend in axial shape index (ASI) at 30% power. Nuclear
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instrument excore detector channels A and D were trending as predicted, but
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channels B and C were not as expected. Based on divergence between the two
channel pairs, the operators declared ASI out of service for channels B and C and
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entered Technical Specification 3.0.3. A report was made to the NRC and
operators reduced power to Mode 2 to place the unit in a mode where the technical
specifications for ASI did not apply.
BGE wrote an issue report to track the resolution of this issue and a root cause
investigation was initiated. The detectors for channels B and C had been replaced
during the outage while channels A and D were not disturbed. BGE identified that
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the divergence was due to reversed leads for the upper and lower detectors in the B
and C channels. A containment entry was made, and the reversal of the leads was
corrected. A licensee event report for this issue was initiated. The inspectors
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y
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considered the miswiring of the detectors to be unresolved pending completion of
the root cause evaluation by BGE (URI 50-317&318/96-06-02).
M1.5 Routine Surveillance Observations
The inspectors witnessed / reviewed selected surveillance tests to determine whether
approved procedures were in use, details were adequate, test instrumentation was
properly calibrated and used, technical specifications were satisfied, testing was
performed by qualified personnel, and test results satisfied acceptance criteria or
were properly dispositioned.
The surveillance testing was performed safely and in accordance with proper
procedures. The inspectors noted that are appropriate level of supervisory attention
was given to the testing depending on its sensitivity and difficulty. Surveillance
testing activities that were reviewed are listed below:
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01-30
Nuclear Instrument Channel Calibration (Daily)
STP-O-5-2
AFW Monthly Surveillance Test
STP-065E-2
Saltwater Pump Discharge Check Valve Test
STP-M200-1
Reactor Trip Breaker Testing
STP-08A-1
Test of 1 A Emergency Diesel Generator
STP-F696-0
Fire Pump Flow Test
01-89
Seismic Instrument Monthly Surveillance
111. Enaineerina
E2
Engineering Support of Facilities and Equipment
E2.1
Service Water Heat Exchanaer Cleanina and Continued Operability
a.
Insoection Scope
The inspectors reviewed biofouling of the service water heat exchangers and
problems with the saltwater system pumps, pump motors, and pump discharge
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b.
Findinas and Observations
On August 21, the inspectors observed mechanical cleaning of the 21 service water
heat exchanger. The heat exchanger had closely approached a differential pressure
limit for operability due to a combination of micro and macro fouling. With BGE
mechanical maintenance personnel approximately 50 percent complete with the
cleaning, operations personnel halted the cleaning and requested that maintenance
restore the heat exchanger ts service to allow expedited cleaning of the 22 service
water heat exchanger. The 22 heat exchanger also had approached the differential
pressure limit for continued operability and either additional fouling or an increase in
bay temperature would require entry into technical specification 3.0.3, which
required reactor shutdown.
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BGE stated that the simultaneous degradation of both trains of service water was
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due to accelerated and unanticipated biofouling from the Chesapeake Bay. Since
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bay temperatures had been relatively low, engineering personnel delayed mechanical
cleaning of the heat exchangers to for seven days from the planned 14 day routine
that had been implemented in July. However, the delay did not was not made in
full consideration to possible differential pressure degradation due to shells and
debris clogging the heat exchanger tubes.
The inspectors also noted there have been repeated mechanical problems with the
saltwater pump discharge check valves. During the cleaning of 21 header, the
check valve for 21 pump was replaced because reverse flow had been observed
through the valve. After replacement, a satisfactory test of the valve was
conducted; however, the next day, when maintenance again secured 21 saltwater
header for mechanical cleaning of the service water heat exchanger, the pump was
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observed rotating backwards indicating that the check valve had not fully reseated.
The inspectors noted that check valve failures due to debris was a recurring
problem.
The inspectors also noted degradation of differential pressure and flow for the
saltwater pumps. At the time of the Unit 1 reactor startup, two of the three
saltwater pumps was identified in the alert range for differential pressure, as
measured during ASME Section XI inservice testing. The inspectors also observed
that one pump and two pump motors on Unit 2 required recent replacement due to
operational failures.
Biofouling of the service water heat exchangers had also impacted control room
operations by requiring reactor operators to perform additional monitoring of
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saltwater flow to the service water heat exchangers, differential pressure across the
service water heat exchangers, and bay temperature. Operators were required to
perform system alignments for emergent and scheduled heat exchanger cleanings
and bulleting, shift component cooling flow to the reactor coolant pumps to allow
adequate saltwater flow to the service water heat exchangers when differential
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pressure was high, and determine system operability using a series of complex
graphs and charts. Frequent realignment of the service water system for cleaning
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of the heat exchangers has contributed to two component misalignments by control
room operators (See section 01.2).
The inspectors found that frequent maintenance on the system challenged reactor
operators by requiring mechanical and electrical alignment changes, affected
reliability of plant safety systems due to overall out of service time, and challenged
maintenance personnel by requiring emergent corrective maintenance. The
operability of the service water syttem appears to have been challenged by
repeated biofouling of the service water heat exchangers. The effectiveness of the
BGE corrective actions was indeterminate at the time of the inspection. The issue is
considered unresolved (URI 50-317&318/96-06-03).
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c.
Conclusions
The continued operability of the service water system was challenged by micro and
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macrofouling of the service water heat exchangers. Repeated mechanical cleanings
of service water heat exchangers had increased out-of-service time and challenged
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operations and maintenance personnel.
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Saltwater pump discharge check valves were subject to recurring failures due to
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debris in the system preventing seating of the valves. Saltwater pumps and pump
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motors have been subject to degradation and have required replacement.
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IV. Plant Support
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P1
Conduct of Emergency Preparedness (EP) Activities
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a.
Inspection Scoce (82701)
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The inspectors reviewed the BGE action item tracking system, the
Emergency Planning Unit's (EPU) self-assessment program and root cause
analysis reports to determine the effectiveness of licensee controls in
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b.
Observations and Findinas
The EPU performed numerous self-assessments of the EP program in 1995
and 1996 that included assessments of exercise deficiencies and audit
findings. The EPU management closely monitored the program for trends of
repeated discrepancies or issues. If an actual or suspected deficiency or
nor , informance was identified, an issue report (IR) was submitted to the
issues Assessment Unit (IAU) and tracked as an action item.
The EPU performed 144 self-assessments in 1995 and over 100 in 1996.
The EPU submitted 39 of the assessments as issue reports. Three findings
from issue reports were assigned a Category 1; 28 were assigned a Category
ll and eight were assigned a Category ill. The inspectors reviewed a
selection of the self-assessments and all Category 1,11, and 111 action items
and determined that the assessments appeared to be appropriately self-
critical; and, with one exception, corrective actions were implernented for
the closed action items.
The inspectors noted that one Category 11 action item was closed without
correcting the initial problem identified by the EPU. (Details are in Section
P8.1.) BGE representatives stated that, since the action item was assigned a
Category ll, no independent review had been done to verify if the corrective
action taken was appropriate.
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The inspectors reviewed the root cause analysis reports that were performed
for the three Category I action items. The reports were detailed and
thorough, and conclusions were supported with additional documentation.
c.
Conclusions
BGE has an adequate action item tracking system in place for tracking issue
reports identified in EP exercises, audits, or self-assessments. The EPU
utilizes the self-assessment program for program enhancements,
identification of program weaknesses, and resolution of issues.
P2
Status of EP Facilities, Equipment, and Resources
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a.
Inspection Scope (82701)
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The inspectors conducted an audit of emergency equipment in the Control Room,
Operations Support Center, Technical Support Center (TSC), TSC Annex,
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Emergency Operations Facility, Farm Demonstration Building, and Joint Information
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Center. A tour of the local community hospital and a county Emergency Operations
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Center (EOC) was also conducted (see Section 8.3). The inspectors reviewed
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facility equipment inventories conducted during the past year for completeness and
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accuracy.
b.
Observations and Findinas
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The inspectors checked several emergency equipment kits and emergency supply
cabinets located in the emergency facilities and found them to be stocked in
accordance with BGE procedures. They also verified that survey meters, personnel
dosimetry, and respirator canisters were calibrated and operational.
The inspectors reviewed equipment and supply inventory checklists for 1995 and
two quarters in 1996. The inspectors determined that inventories were conducted
in a timely manner, inventory checklists were properly completed and reviewed, and
immediate corrective actions were taken on identified deficiencies.
c.
Conclusions
The inspectors concluded that the BGE maintained a very good inventory
program, and that the emergency facilities and equipment were operationally
ready.
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P3
EP Procedures and Documentation
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a.
Inspection Scope (82701)
The inspectors reviewed recent emergency response plan (ERP) and implementing
procedure (ERPIP) changes to assess the impact on the effectiveness of the EP
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program. The inspectors also assessed the process that BGE uses to review ERPIPs
and changes made to them.
b.
Observations and Findinas
The inspectors reviewed the BGE commitments in the ERP, Section 6.V, " Program
Review and Update," and ERPIP-900, " Preparation of Emergency Response Plan and
Implementation Procedures," regarding the processing of ERP and ERPIP changes
and reviews. The ERP and ERPlPs received the required reviews from on-site and
off-site review committees. As a new initiative, BGE assigned specific procedures
to be reviewed by the appropriate technical unit. The inspectors considered this to
be a good initiative. The Emergency Preparedness Director (EPD) regularly certified
that the ERP and the ERPIPs were current.
In accordance with ERPIP-900, proposed changes to these documents were to be
reviewed against federal requirements, guidance in NUREGs, and commitments in
the updated final safety analysis report (UFSAR). The inspectors reviewed several
change packages and determined that BGE had reasonable explanations to justify
and support the changes. An in-office review of revisions to the ERP and ERPIPs
submitted by BGE was completed by the inspectors. A list of the changes reviewed
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are included in Attachment 2 to this inspection report. The inspectors concluded
that the revisions did not reduce the effectiveness of the EP program.
The inspectors determined that BGE had no documentation specifying the required
training for the site emergency coordinator position. The inspectors inquired about
the original commitment regarding training for the site emergency coordinator. The
licensee showed the inspectors Revision 2 (1982) of the ERP, which contained a list
of the training topics for the site emergency coordinator. The inspectors found that,
over time, the list of topics was moved from the ERP into an ERPIP; and, eventually,
in subsequent changes, the list no longer existed. The inspectors reviewed the
topics in Revision 2 and determined that they were necessary and applicable to the
site emergency coordinator position in the performance of his duties. By reviewing
the current training material, the inspectors also determined that the topics stated in
Revision 2 of the ERP were still being taught because of stability in the BGE EP
staff. However, without a specific list of required topics, staff changes in the EP
unit could result in incomplete site emergency coordinator training. That would fail
to meet the original commitments of the ERP and could result in an unintentional
reduction in the effectiveness of the ERP. In response, BGE conducted a review of
the issue and updated the training manual accordingly,
c.
Conclusions
BGE had sufficient processes and controls to address ERP and ERPlP reviews and
changes.
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P5
Staff Training and Qualification in EP
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a.
Insoection Scooe (82701)
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The inspectors reviewed EP training records, training procedures, lesson plans,
ERPIPs and the BGE ERP to evaluate the BGE EP training program.
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b.
Observations and Findinas
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The inspectors verified that drills (fire, medical, post-accident sampling) and annurl
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exercises were being conducted as stated in the ERP and ERPIP-905, " Exercises,
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Tests and Drills." Critiques were forwarded to management for review. The
inspectors reviewed the BGE documentation for tracking exercise objectives and
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determined that they were being accomplished as required.
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The inspectors reviewed individual emergency response organization (ERO) training
records and determined that all ERO qualifications were current. BGE performed a
monthly check to monitor ERO qualification status. As stated in Section P.3 for the
4
site emergency coordinator, the inspectors noted that there was no specific listing
of topics to be covered during initial or annual retraining. BGE reviewed previous
document revisions that specified training topics and put those topics into the
Emergency Response Training Program Manual (ERTPM) to ensure that those topics
will continue to be covered in future training.
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BGE had implemented the following training initiatives: (1) exercise and drill
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critiques were electronically distributed to everyone to inform them of identified
1
issues; (2) training conducted at the emergency response facilities for the
responders assigned to that facility covered major points of the specific procedure
for each position to familiarize the duties of each position; and (3) ERO training is
conducted during the months of June, July, and August as a means to effectively
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utilize training resources. The inspectors considered these initiatives to be
enhancements to the training program.
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The inspectors verified by reviews and interviews that appropriate training was
being conducted for off-site agencies and support organizations. Annual emergency
action level (EAL) training for state and counties was very comprehensive. Fire,
rescue, and medical training were well attended. Training materials provided for
media personnel were informative and well organized.
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c.
Conclusion
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The inspectors determined that all ERO members were qualified and their
qualification status was being closely monitored by the EPU. Training of off-site
agencies and support organizations was of good quality and was being completed
as required. The initiatives implemented demonstrated a progressive attitude to
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improve the training process. Overall, the inspectors assessed this area as very
good.
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P6
EP Organization and Administration
a.
Inspection Scope (82701)
The inspectors reviewed EP group staffing and management to determine what
ct.anges have occurred since the last program inspection (January 1995) and if
those changes had any adverse effect on the EP program.
b.
Observations and Findinas
There were no changes within the EPU since the last inspection; however,
the emergency preparedness director plans to eliminate the emergency
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planning technician position by January 1997. He has concluded that
elimination of this position will not reduce the ability to administer the EP
program effectively.
The inspectors interviewed the Nuclear Support Services Manager (NSSM)
and emergency preparedness director separately regarding the EP program,
program initiatives and significant issues. All responses were consistent.
In a May 1996 memo to the NSSM, the emergency preparedness director
committed to several program initiatives for 1996 and 1997. The inspectors
reviewed those initiatives and found them to be appropriate. BGE stated that
each of the suggested initiatives have management support.
c.
Conclusions
The EP staff was able to meet its commitments with the present staffing level.
Management support of EP program was good, as evidenced by the findings of this
inspection.
P7
Quality Assurance (QA)in EP Activities
a.
Inspection Scoce (82701)
The inspectors reviewed QA audit and surveillance reports of the EP program,
conducted in 1994 and 1995. The inspectors interviewed the lead QA auditor
regarding the process for conducting a program audit.
b.
Observations and Findinqs
Annual QA surveillances and audits were conducted by individuals independent of
the EPU. The 1994 and 1995 reports were appropriately detailed and contained
positive and negative comments, with recommendations, addressing the areas
specified in 10 CFR 50.54(t). No repeat items were found by the inspectors. The
reports were distributed to BGE management and off-site agencies as appropriate.
No programmatic problems were identified.
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The lead auditor was familiar with the EP program. There was not any specific EP
expertise on the audit or surveillance teams. However, the lead auditor used
technical specialists, as necessary, to evaluate areas within their expertise program.
c.
Conclusion
The QA findings were detailed and critical, and the reports met the requirements of
10 CFR 50.54(t). The inspectors assessed this area as good.
P8
Miscellaneous EP lssues
P8.1
Uodated Final Safety Analysis Report (UFSAR) Inconsistencies
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The inspectors observed no discrepancies between the UFSAR and the ERP or
ERPIPs. Since the UFSAR does not specifically include EP requirements, the
inspectors compared BGE activities to the ERP. The inspectors reviewed off-site
training, media training, public information, post-accident sampling system
procedures and training, and recovery phase actions and organization. No
discrepancies were noted. The quality of the annual EAL training and the materials
available for media and public information were strengths. However, the inspectors
found that in October 1995, BGE removed digital voice protection (DVP) from the
emergency response radios to improve the quality and clarity of the signal received.
In January 1996, the EPU performed a self-assessment and identified that a
reference to DVP remained in UFSAR Section 7.8.2.6, " Radio Telephone System,"
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and this section was not consistent with the ERP or ERPIPs. The EPU initiated an
issue report that was assigned as a CLtegorv ll action item. The corrective action
was to change ERPIP-900, " Preparation of Emergency Response Plan and
Implementation Procedures," to include a review for UFSAR inconsistencies when
changes are made to the ERPIPs. However, the corrective action did not include
changing the UFSAR for the removal of the DVP. The inspectors stated that, while
the corrective action taken by the EPU was a good initiative in assuring that a
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UFSAR review would be conducted, the corrective action did not address, nor
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resolve, the initial problem. Prior to the exit meeting, BGE initiated a UFSAR/USAR
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Change Request to remove the DVP reference in order to accurately describe their
current radio system. This item is an unresolved item (URI 50-317&318/96-06-04).
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P8.2 ERO Response and Availability
Whenever the ERO is activated, the entire organization is notified to respond. The
inspectors determined that there were no administrative controls to ensure that all
positions were capable of being filled. For example, the inspectors determined that
four ERO positions had only two personnel currently qualified to fill those positions.
(BGE is in the process of qualifying additional personnel for these positions.) The
inspectors asked if there were any methods to ensure that the qualified individuals
in these, and other, positions were available to respond to an event because
individuals rnay be physically unable to respond due to health reasons or being out
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of the area. BGE personnel stated that no administrative controls were in place to
verify an individual's status. The licensee demonstrated that, historically, there
have always been ample personnel who have responded to fill every position.
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P8.3 Off site Interface
The inspectors toured the Calvert County EOC and interviewed the County
Emergency Management Chief to assess the BGE interface with the off-site
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agency. The county official indicated that BGE had maintained an excellent
rapport, is very responsive to the county's concerns, and that there were no
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outstanding issues.
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The inspectors also visited one local hospital, toured the designated emergency
radiological area, and interviewed members of the medical staff to verify the
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adequacy of the radiological training provided by BGE. The inspectors found that a
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portable radiological detection instrument was malfunctioning and two storage bags,
containing thermoluminescent dosimeters (TLDs), had no calibration date.
Apparently, the instrument had failed since the last quarterly inventory conducted
by BGE, and the calibration stickers had fallen from the bags. BGE immediately
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verified that the TLDs were in calibration, placed a calibration sticker on each bag,
and replaced the malfunctioning instrument.
Based upon the interviews, the inspectors concluded that the quality of training for
off-site agencies and support organizations (Section P.05.b) was very good and that
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BGE maintains a very good rapport with off-site entities.
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P8.4 (Closed) Follow-Up item 50-317&318/95-01-02:
Determine whether the training requirements of ERTPM are being met. This item
was opened because emergency response training program ownership was
undergoing a transition from the EPU to various training units. The ERTPM was
written to outline the requirements of this new program. However, the manual was
not being distributed to all responsible individuals and there was no method to
control changes made by the various units to ensure that the ERTPM was being
properly implemented. The ERTPM is now being distributed to all applicable
individuals who have signed an acknowledgement statement describing their
training responsibilities and limitations. The inspectors determined that the ERTPM
addressed the concerns raised during issue report 95-01 and effectively controls the
administration of training.
S1
Conduct of Security and Safeguards Activities
a.
Inspection Scoce
The inspectors reviewed various areas of the security program including previously
identified items; effectiveness of management controls; management support and
audits; protected area detection equipment; alarm stations and communications;
testing, maintenance and compensatory measures; and training and qualifications.
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The purpose of this inspection was to determine whether the BGE security program,
as implemented met NRC requirements.
b.
Observations and Findinas
The inspectors conducted a physical inspection of the protected area (PA) intrusion
detection systems (IDSs). The inspectors determined by observation that the IDSs
were installed and maintained as described in the NRC-approved security plan (the
Plan). Additionally, the inspectors observed licensee testing of the IDSs at the
independent spent fuel storage installation (ISFSI) on August 15,1996. The
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inspectors determined, basud on observations and discussions with security
supervision, that the IDSs were being properly tested in accordance with licensee
procedures and the Plan, and that the IDSs detection capability was effective.
The inspectors observed Central Alarm Station (CAS) and Secondary Alarm Station
(SAS) operations, and verified that the alarm stations were equipped with the
appropriate alarm, surveillance, and communication capabilities. The inspectors
interviewed CAS and SAS operators and found them knowledgeable of their duties
]
and responsibilities. The inspectors also verified that the CAS and SAS operators
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.were very alert and attentive to duties, and were not required to engage in activities
that would interfere with assessment and response functions, and that the licensee
had exercised communications methods with the locallaw enforcement agencies as
committed to in the Plan.
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The inspectors reviewed testing and maintenance records for security-related
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equipment and confirmed that the records were on file and that BGE was testing
and maintaining systems and equipment as committed to in the Plan. A review of
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these records indicated that repairs were being completed in a timely manner and
that a priority status was assigned to each work request. The inspectors also noted
that security equipment repairs are normally completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> from the
time a work request is generated and that security equipment rework has decreased
due to the focused efforts of the maintenance group.
The inspectors reviewed the use of compensatory measures and found them to be
appropriate and minimal. It was apparent that priority repair efforts were carried out
by the maintenance group when equipment problems required compensatory
measures.
The inspectors reviewed the training, physical, and firearms qualification and
requalification records of nine nuclear security cfficers (NSOs) selected at random.
The inspectors determined that training had been conducted in accordance with the
NRC-approved security training and qualification (T&Q) plan and that it was properly
documented.
The inspectors observed tactical range and tactical movement training for one NSO
on August 15,1996. The training consisted of tactical weapons manipulation,
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target acquisition and tactical movement, and stressed the use of cover and
concealment. The instructors did an excellent job controlling the drills and the
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range was controlled in a safe manner. Additionally, the inspectors interviewed
several NSOs and determined that, based on the NSOs responses to the inspectors'
questions, the training provided by the security training staff was effective.
Management support for the physical security program was determined to be
excellent. This determination was based on the inspectors' review of various
program enhancements made since the last inspection, which was conducted in
April 1996. These included completion of the vehicle barrier system installation,
procurement of the personnel access data system (PADS), the approval to hire
additional NSOs to address manning needs, the allocation of monetary resources for
additional training initiatives, and the aggressive review and follow-up of security
events that occur at other nuclear plants to determine the susceptibility of the
Calvert Cliff's security system and program to similar events.
The inspectors determined that the licensee had controls for identifying, resolving,
and preventing security program problems. These controls included the
performance of the required annual quality assurance (QA) audits, an ongoing and
active suggestion program for the NSOs that addresses programmatic concerns,
performance of benchmarking exercises, and ongoing security shift supervision
oversight. The licensee also utilizes industry data, including adverse data, such as
violations of regulatory requirements identified by the NRC at other facilities, as a
basis for self-assessment to determine if similar conditions exist in its program.
A review of documentation applicable to the aforementioned programs indicated
that initiatives to minimize security performance errors and to identify and resolve
potential weaknesses were being implemented and were effective,
c.
Conclusions
BGE had an effective security program in place. Management support was good as
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evidenced by the timely completion of the vehicle barrier system, the completion of
.a computer software upgrade and aggressive follow-up on security events that
occur at other nuclear plants. The central and secondary alarm station operators
were knowledgeable of their duties and responsibilities and were not engaged in
activities that would interfere with their response functions.
Security training was being performed in accordance with the NRC-approved
training and qualification plan, and management controls for identifying, resolving,
and preventing programmatic problems were effective. The nuclear security officers
were found to possess the requisite knowledge to carry out their assigned duties
and that the training program was effective.
Protected area detection equipment was installed and maintained in accordance
with the NRC-approved Physical Security Plan (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 indicated by minimal
compensatory postings associated with security equipment repairs.
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S7
Quality Assurance in Security and Safeguards Activities
The inspectors reviewed the 1995 Or.ality Assurance (QA) audit of the security
program conducted in October 190';, five surveillances (Surveillance Nos. S-95-4-7,
S-95-4-9, S-95-4-12, S-95-4-13, and S-95-4-14), and the 1995 audit of the fitness
for duty (FFD) program (Surveillance S-95-3-8) conducted in August 1995. The
inspectors determined that the audits were conducted in accordance with the Plan
and FFD rule. To enhance the effectiveness of the FFD audit, the audit team
included an independent technical specialist. The 1995 security program audit
identified one finding concerning the manner in which security plan changes were
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processed and the 1995 FFD audit identified one finding concerning the collector's
failure to adhere to procedural guidance during a pre-access drug and alco' ol test.
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The audits also included recommendations. The inspectors determined that the
findings were not indicative of programmatic weaknesses, and the
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recommendations would enhance program effectiveness. The inspectors also
determined, based on discussions with security and FFD supervision and a review of
the responses to the findings, that the actions taken in response to the audits were
effective.
The inspectors concluded that BGE audits of security activities were comprehensive
in scope and depth, that the findings were reported to the appropriate levels of
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management, and that the programs were being properly administered.
S8
Miscellaneous Security and Safeguards issues
(Closed)IFl 50-317 and 50-318/96003-01: During Inspectior No. 95-04, the
inspector noted a weakness concerning the lack of a control to alert security
screening unit personnel when a person has been absent from a behavioral
observation program for more than 30 days. During inspection 96-03, conducted in
April 1996, the inspectors reviewed the actions taken to resolve the concern and
noted that the applicable revised procedure had not been implemented in a timely
manner. Therefore, the procedure's effectiveness could not be properly evaluated.
During this inspection, the inspectors determined that the action taken to resolve
the concern was adequate. The action involved the revision of Security Standard
- 11, titled "30 Day Hold," dated April 9,1996. Based on a reviaw of applicable
documentation and discussions with security management, the corrective actions
appear adequate. No similar problems were noted.
V. Manaaement Meetinas
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Exit Meeting Summary
During this inspection, periodic meetings were held with station management to
discuss inspection observations and findings. On September 9,1996, an exit
meeting was held to summarize the conclusions of the inspection. BGE
management in attendance acknowledged the findings presented.
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L1
Review of UFSAR Commitments
A recent discovery of a licensee operating its facility in a manner contrary to the
Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a
special focused review that com' ares plant practices, procedures and/or parameters
p
to the UFSAR description. While performing the inspections discussed in this
report, the inspectors reviewed the applicable portions of the UFSAR that related to
the areas inspected to verify that the UFSAR wording was consistent with the
observed plant practices, procedures and/or parameters. Inconsistencies were
noted concerning emergency preparedness activities as discussed in Section P8.1.
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ATTACHMENT 1
PARTIAL LIST OF PERSONS CONTACTED
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P. Katz, Plant General Manager
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K. Cellers, Superintendent, Nuclear Maintenance
K. Neitmann, Superintendent, Nuclear Operations
P. Chabot, Manager, Nuclear Engineering
T. Camilleri, Director, Nuclear Regulatory Matters
B. Watson, General Supervisor, Radiation Safety
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' C. Earls, General Supervisor, Chemistry
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L. Gibbs, Director, Nuclear Security
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T. Sydnor, General Supervisor, Plant Engineering
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T. Forgette, Director - Emergency Preparedness
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J. Hardinson, Emergency Preparedness Training Coordinator
M. Polak, Supervisor - Quality Assurance Unit
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J. Thorpe, General Supervisor, Instrument and Controls Maintenance
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Deoartment of Public Services and Safety (Calvert Countv)
D. Hall, Chief, Calvert County Emergency Management
NRC
R. Keimig, Chief, Emergency Preparedness and Safeguards Branch, DRS
INSPECTION PROCEDURES USED
IP 62703: Maintenance Observation
IP 71707: Plant Operations
IP 93702: Prompt Onsite Response to Events at Operating Power Reactors
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IP 61726: Surveillance Observations
IP 37550: Engineering
IP 37551: Onsite Engineering
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IP 71750: Plant Support Activities
IP 83750: Occupational Exposure
IP 92700: Onsite Followup of Written Reports of Nonroutine Events at Power Reactor
Facilities
IP 92902: Followup - Engineering
IP 82701: Operational Status of the Emergency Preparedness Program
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2
ITEMS OPENED CLOSED, AND DISCUSSED
Opened
50 317&318/96-06-01
VIO Safety system misalignments during saltwater and service
water system maintenance.
50-317&318/96-06-02
URI Two nuclear instrument detectors were miswired
50-317&318/96-06-03
URl Effectiveness of corrective actions regarding biofouling of
the saltwater cooling systems
50-317&318/96-06-04
URI Survey team radios noncompliance with UFSAR
Closed
50-317&318/95-01-02
IFl Determine whether the training requirements of ERTPM are
being met
50-317&318/96-03-01
IFl Lack of a control to alert security screening unit personnel
when a person has been absent from a behavioral observation
program for more than 30 days
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LIST OF ACRONYMS USED
As Low As Reasonably Achievable
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Root Cause Analysis
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SWP
Special Work Permit
kV.
Kilovolts (1000 volts)
GS-NPO
General Supervisor - Nuclear Plant Operations
Updated Safety Analysis Report
Motor Operated Valve
Low Pressure Safety injection
Digital Voice Protection
Emergency Action Level
Emergency Operations Center
ERP
Emergency Response Plan
ERPIP
Emergency Response Plan implementing Procedure
ERTPM
Emergency Response Training Program Manual
Emergency Response Organization
IR
lssue Report
IAU
lssues Assessment Unit
NSSM
Nuclear Support Services Manager
Post-Accident Sample System
Quality Assurance
,
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SEC
Site Emergency Coordinator
Thermoluminescent Dosimeter
'
RCAR
Root Cause Analysis Report
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ATTACHMENT 2
EMERGENCY RESPONSE PLAN AND IMPLEMENTING PROCEDURES REVIEWED
Document
Document Title
Revision, Change
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ERP
22
ERPlP-102
Superintendent - Nuclear Operations
2
!
ERPIP-104
NRC Emergency Notification System Communications
0, Change 3; 1
l
ERPIP-105
Control Room Communicator
3
q
ERPIP-107
Interim Radiological Assessment
2
'
ERPIP-108
Interim Radiation Protection
O
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ERPIP-109
Radiation Monitoring System (RMS) Communicator
1
ERPIP-201
Technical Support Center Director
2, Change 3
ERPIP-202
Plant General Manager
2
ERPIP-203
Chemistry Director
1
ERPIP-207
TSC Computer Maintenance Staff
2
ERPIP-208
Plant Parameters Communications, TSC
1
ERPIP-209
Technical Support Center Communicator
3
ERPIP-210
CR/TSC Monitor
1; 2
ERPIP-3.0
Radioactivity Release - Dose Estimate
18, Change 6
ERPIP-3.0
Placekeeper, Attachment 22
18, Change 1
ERPIP-301
Operational Support Center
3, Changes 1 & 2
ERPIP-302
Engineering Director
1, Change 1
ERPIP-303
Radiation Protection Director
1, Change 2
ERPIP-304
Operational Support Center (OSC) Engineer
1, Change 1
ERPIP-307
Operations Team Leader
2
ERPIP-309
Dosimetry Team Leader
2
ERPIP-310
Maintenance Team Leaders
1, Change 1
ERPIP-311
Chemistry Team Leader
1, Change 1
ERPIP-312
First Aid Team Leader
1, Change 2
ERPIP-314
OSC Communicator
1, Change 1
ERPIP-315
Plant Parameters Communicator
0, Change 3
ERPIP-316
Operational Support Center Monitor
1; 2; 2, Change 1
ERPIP-319
Dosimetry Team Members
1
,
ERPIP-322
First Aid Team Members
1
'
ERPIP-403
NEF Monitor
1; 2
ERPIP-501
Site Emergency Coordinator
3
ERPIP-502
Recovery Officer
2
ERPIP-503
Emergency Operations Facility (EOF) Director
2, Change 1
ERPIP-504
Environmental Assessment Director
1
ERPIP-507
Off-site Monitoring Team
O, Change 3,4, S
ERPIP-508
Plant Parameters Communications, EOF
1
ERPIP-509
Emergency Operations Facility Communicator
3
ERPIP-511
Radiological Assessment Director
1
ERPIP-512
Radiological Assessment Specialist
1
ERPIP-700
Cafeteria Assembly Area
1, Change 2
ERPIP-701
Warehouse 3 Assembly Area
1
ERPIP-703
Security Processing Building Monitor
0, Change 4
ERPIP-710
Farm Demonstration Building Decontamination Facility
1
ERPIP-720
Technical Representatives
2
ERPIP-750
Security
4
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2
ERPIP-760
Plant Parameters Communications, Media Access
1
ERPIP-801
Core Damage Assessment Using Containment Radiation
Dose Rates
1
ERPlP-802
Core Damage Assessment Using Core Exit Thermocouples
1
ERPIP-803
Core Damage Assessment Using Hydrogen
1
ERPIP-804 - Core Damage Assessment Using Radiological Analysis
,
'
of Samples
1
ERPIP-810
Main Steam System Radioactivity Release Estimate
1
,
!
ERPIP-821
Accidental Radioactivity Release Monitoring and
Sampling Methods
1
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ERPIP-831
Radiation Exposure Guidance
2
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ERPIP-832
Emergency Work Permits
2
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ERPIP-840
RCS/LPSI instructions
2
ERPIP-841
Containment Atmosphere Instructions
1
' ERPIP-842
Wide Range Noble Gas Monitor Instructions /
,
Precautions
1
ERPIP-900
Preparation of Emergency Response Plan and
implementation Procedures
4
ERPIP-901
Communications Equipment
2
ERPIP-902
Records
1, Change 1
ERPIP-904
Training
3
ERPIP-905
Exercises, Tests and Drills
1; 1, Change 1
ERPIP-B.1
Equipment Checklist
18, Change 3; 19
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