IR 05000317/1998080
| ML20216J406 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 04/14/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20216J390 | List: |
| References | |
| 50-317-98-80, 50-318-98-80, NUDOCS 9804210377 | |
| Download: ML20216J406 (30) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION I
Docket / Report Nos: 50 317/98-80 50-318/98-80 l
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Licensee:
Baltimore Gas & Electric Company l
P.O. Box 1475 l
Baltimore, Maryland 21203 Facility:
Calvert Cliffs Nuclear Power Station, Units 1 & 2
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Location:
Lusby, Maryland l
l Dates:
January 12-30,1998 and March 27,1998 l
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Inspectors:
Suresh Chaudhary, Senior Reactor Engineer l
George Morris, Reactor Engineer l
Jimi Yerokun, Senior Reactor Engineer Kenneth Kolaczyk, Reactor Engineer
Lois James, Reactor Engineer l
Thomas Mostack, Senior Reactor Engineer l
l Approved:
Glenn W. Meyer, Chief
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Civil, Mechnical, and Materials Engineering Branch I
Division of Reactor Safety j
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9804210377 980414 l
PDR ADOCK 05000317
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TABLE OF CONTENTS
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l E1 Safety System Engineering Inspection.............................. 1 i
E1.1 Ve ntilation System s...................................... 1 i
E1.2 Emergency Diesel Generator and Service Water / Salt Water System.......... 6 I
E2.
Engineering Support of Facilities and Equipment...................... 12 E2.1 Temporary and Permanent Modifications...................... 12
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E2.2 Engineering Support to Operations........................... 14 E8 Miscellaneous Engineering issues................................. 16 E8.1 Corrective Actions Program (40500)
.........................16 E8.2 Review of Updated Final Safety Analysis Report (UFSAR)........... 22
E8.3 Review of Open items
...................................23 X1 Exit Meeting
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- g EXECUTVE SUMMARY l
The inspection assessed the effectiveness of engineering activities in design and plant support to assure plant oporational safety, the safety evaluation program, and the controls for identifying, resolving, and preventing problems. The team selected three systems for detailed review; ventilation systems, emergency diesel generators, and service water / salt water system.
Ventilation System Review
BG&E has improved the quality of the ventilation system testing program. Although ventilation calculations have been refined and nonconservative or incorrect design
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assumptions removed, some control room ventilation concerns were unresolved pending NRC review of an impending BG&E submittal on control room habitability. The concerns related to the acceptability of calculated control room doses after updating, the need for a 50.59 determination, reportability, use of corrective action systems, and NRC notifications on systems not in accident analyses. Testing was initiated to verify that the ventilation l
systems can perform their design function as described in the FSAR and TS base, however, some weaknesses remained.
Emeraency Diesel Generators and Service Water System The team concluded that BG&E's engineering and design control activities regarding emergency diesel generators and the service water system were satisfactory..The engineering staff had taken prompt actions to resolve identified service water system l
problems. However, the team noted that there were some weaknesses in the thoroughness of calculations, and the adequacy of test results, evaluations and troubleshooting. Violations were identified regarding test control (unacceptable acceptance criteria for a battery test) and corrective action (repeated attempts to correct a diesel problem). A noncited violation was identified for calculational errors of minor significance, and an unresolved item was issued for battery testing in the Technical Specifications.
Enoineerina Suonort of Ooeration BGE's 50.59 safety evaluations were well-written, technically rigorous, and in accordance with implementing procedures. 50.59 screenings were appropriately performed; no temporary or modifications reviewed were erroneously screened as not requiring a full safety evaluation. Operability determinations were technically well-written and showed an improving trend through 1997 in level of detail and supporting documentation. Several minor administrative deficiencies regarding operability determinations represented a non-cited violation.
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The engineering department provided effective and timely support in response to operations' needs. Communications between the departments were generally good, with a notable exception of an instance involving degradation of the LPSI system in January 1998, judged to be a non-cited violation. POSRC presentations of safety evaluations and screenings were good. Training supplied by engineering to operators was generally good, with improvements noted subsequent to performance problems following the implementation of the digital feedwater modification.
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Corrective Action Proaram The team concluded that problems were appropriately identified, reported, and processed
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through the issue Reporting System. Root cause analyses were commensurate with the safety significance of the issue. Corrective actions were comprehensive for high priority issues but were not aggressively managed for lower category problems. Self assessments I
and audits were of high quality, having sufficient scope and depth, and the POSRC and the OSSRC were appropriately carrying out their roles and responsibilities. Management was taking appropriate measures to improve the effectiveness of the corrective action program.
Containment Tendon Surveillance l
l The tendon surveillance program was extensive and short term actions were appropriate.
l The long term action development schedule was acceptable. Inspector Follow-up item l
No.97-05-03 for both units was closed.
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Reoort Details E1 Safety System Engineering inspection
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E1.1 Ventilation Systems i
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Insoection Scoce The inspector compared the design criteria in the Final Safety Analysis Report (FSAR) and Technical Specification (TS) bases for the control room, emergency core cooling system (ECCS) pump room, and penetration room ventilation systems to the system surveillance and operating procedures. Included in the review was an examination of ventilation design calculations to ensure that Baltimore Gas &
Electric (BG&E) used valid design inputs in the analyses. Compensatory actions established to compensate for degraded conditions were reviewed to ensure the measures were adequate, and the individuals who could perform the actions were properly trained. The scopo did not include an assessment of the adequacy of the original design basis of the system.
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Observations and Findinas b.1 Control Room and Offsite Dose Calculations The team reviewed the control room ventilation system, including some aspects of offsite dose calculations due to the source term affecting both. The control room analyses were under review by BG&E based on an upcoming submittal to NRC scheduled for March 1998 to address the acceptability of the Calvert Cliffs control room ventilation design.
Historically, BG&E had committed to meet the guidance of the TMI Action Plan item lli.D.3.4, Control Room Habitability and General Design Criterion (GDC) 19. In a 1982 NRC Safety Evaluation Report (SER) the control room habitability systems were found to be acceptable previded that self contained breathing apparatus (SCBA) were available for use. In 1993 BG&E requested and the Office of Nuclear Reactor Regulation (NRR) granted a waiver from fully complying with GDC 19 which indicated that if operators donned SCBA gear in 45 minutes following a maximum hypothetical accident (MHA), the dose limits of GDC 19 would be satisfied. The waiver allowed BG&E to continue the use of SCBA on an interim basis for tne control room operators until the ventilation system was modified. The temporary waiver was due to expire in March 1998.
As such, BG&E had recently expended considerable resources to verify the design basis of ventilation systems at Calvert Cliffs, to update ventilation design calculations, and to test the performance of applicable systems. This facility effort had raised issues regarding the design and operation of the systems that were being addressed as part of the upcoming NRC submittal. The team reviewed parts of this ongoing effort and raised regulatory concerns regarding calculated control room doses, 50.59 determinations, reportability, use of facility corrective action programs, and previous FSAR increases in calculated doses, as follows.
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Calculated Control Room Doses:
The team noted that BG&E reviews had discovered that the following assumptions used in 1993 calculations had been nonconservative.
Assumed Actual Air in leakage 910cfm 3000cfm j
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Containment lodine Filter 0sec 33 see Start Time Delay l
Containment Air Filter Flow 20000 cfm 18000cfm i
Rate Control Room Recirculation 2000cfm 1800cfm Flow Containment Air Cooling 0 sec 38 sec
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System Time Delay
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'The nonconservative assumptions had been addressed via revised calculations and l'
th at BG&E did not use the same design inputs and calculational methodologies use of engineering judgment. The team reviewed the revised calculations and noted described in the FSAR to evaluate the significance of the errors. Specifically, the revised calculations utilized different atmospheric dispersion, decontamination, and dose conversion coefficients. BG&E indicated that some inputs were changed to i
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inputs were selected on the basis that the inputs better predicted accident behavior at Calvert Cliffs. Using the updated assumptions and techniques, BG&E concluded (-
that the control room and offsite dose levels were less than or equivalent to l
previously analyzed values.'As a result, BG&E concluded the errors were not E
significant.
l Nonetheless, although calculational refinements were a noteworthy initiative, the l-team could not determine whether the NRC has reviewed and accepted use of the such coefficients for analyzing the effects of a MHA scenario at Calvert Cliffs.
Therefore, when BG&E discovered the nonconservative assumptions in the design I
analysis, BG&E should have initially assessed the significance of the discovery using the methods and values stated in the FSAR to determine if the condition was l
outside the plant design basis. Operability could thc.) be determined using revised i
techniques and methods. This approach is consistent with the guidance contained l
in Generic Letter 91-18, "Information to Licensees Regarding NRC Inspection l
Manual Section on Resolution of Degraded and Nonconforming Conditions." The team concluded that had BG&E calculated control room dose and offsite dose consequences for a MHA using the existing methods and coefficients in the FSAR, the calculated doses would have been greater than the previous design values.
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The team determined that this regulatory concern should be addressed within the
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context of the pending NRR review of the BG&E submittal on control room design and that following the review NRC could more appropriately determine the acceptability of the revised design. Accordingly, this concern represents the first part of an unresolved item (UNR 50-317&318/98 80-01)
l 50.59 Determination:
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Further, BG&E did not perform a 10 CFR 50.59 determination to evaluate the actual control room design for its acceptability under 10 CFR 50.59. BG&E should have performed a 50.59 determination to confirm that the updated design was acceptable per 10 CFR 50.59 and did not represent an unreviewed safety question.
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The analyses existed to provide a basis for the 50.59 safety evaluation, but the determination (primarily addressing the three criteria) was not made.
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determined to be acceptable, the consequences of not performing the 50.59
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determination should be minimal. Further, BG&E's 50.59 safety evaluation
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performed as part of the submittal should provide additional context for this issue.
Nonetheless, the absence of a 50.59 determination on the updated design i
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represents a second part of the unresolved item (UNR 50 317&318/98-80-01).
l Reoortabilitv:
10 CFR 50.72(b)(1)(ii)(B) states that facilities shall report to the NRC within one i
hour any event or condition that results in a nuclear power plant being in a condition that is outside the design basis of the plant. BG&E did not make any such report
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regarding the actual control room design condition and contended that because the analyses of the actual conditions determined that revised doses were less than or equivalent to previously analyzed design basis doses, there was no condition
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outside the design basis, i
j The team judged that had BG&E calculated the control room dose and offsite dose
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consequences of a MHA with the actual control room ventilation parameters, the resulting doses would likely have been greater than the design basis doses, and as such, would have represented a condition outside the design basis, a reportable l
condition. Clearly, the reportability concern rests largely on the acceptability of the revised calculational method and as such, represents a third part of the unresolved item (UNR 50-317&318/98-80-01).
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Corrective Action:
BG&E procedure QL-2-100, " Issue Reporting and Assessment," specified that
"All personnel at CCNPP are responsible for identifying and promptly documenting deficiencies and nonconformances on issue reports." While it was evident to the team that considerable engineering effort was directed toward analyses of the nonconservative parameters, it was not clear how BG&E had documented the discovery of such in the corrective action program in general, or specifically why the incident report system had not been used. Accordingly, this concern represents a fourth part of the unresolved item (UNR 50 317&318/98-80 01).
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Previous FSAR Dose increases:
As part of the review of the FSAR, the team noted that Revision 20 (February 5,1997) of the FSAR provided a revised summary of results for the maximum hypothetical accident (a LOCA scenario to evaluate offsite dose consequences). Section 14.24.4 provided results which showed that the total offsite dose had increased from the previous dos's for three of the four categories, i.e., whole body dose in the exclusion area (3.0 to 10.6 Rem.), and thyroid dose (33 to 39.3 Rem.) and whole body dose (0.8 to 2.7 Rem.) in the low population zone. The increases still remained less than half of the 10 CFR 100 limits.
The team judged that the increases in calculated doses appeared to represent an unreviewed safety question (USO) in that "the margin of safety as defined in the basis for any technica.' specification (had been] reduced" (10 CFR 50.59(a)(2)) by the design " changes" that had caused the increases. No USQ had been submitted by BG&E as part of the control room evaluation. BG&E contended that no USQ
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existed because the calculated doses were well within the Part 100 limits and did not represent a reduction in the margin of safety. This concern will be reviewed by NRC following review of the submittal and represents a fifth part of the unresolved item (UNR 50-317&318/98-80-01).
b.2 Performance Testina
Since August 1997 BG&E has completed several performance tests of the ventilation systems in the auxiliary building and control room. Some testing was precipitated, in part, by a 1997 NRC-identified inspection finding which noted the spent fuel pool ventilation system was not operated in accordance with design requirements and also by the control room design submittal.
Performance testing of the control room ventilation system was thorough. The y
effects of component failures on system operation were investigated, and verification of relevant FSAR design criteria was incorporated into the testing program. Surveillance procedures appeared to test the critical system design functions as described in the plant TS cnd FSAR.
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Testing of ventilation sy:;tems in the auxiliary building was less comprehensive. For exemple, surveillance tests did not ensure or verify the system performance criteria contained in the FSAR or TS basis were met. Specifically, Section 9.8 " Plant Ventilation Systems," of the CCNPP FSAR, stated, " Airflow patterns originate in areas of potentially low contamination and progress toward areas of higher activity.
Generally negative pressures are maintained in potentially contaminated areas and positive pressure in clean areas." The FSAR and TS basis for the containment penetration and emergency core cooling systems ventilation systems indicated that the systems were designed to maintain a negative pressure in the penetration and pump rooms following a loss of coolant accident (LOCA) BG&E had not verified air flowod from areas of low to high contamination in the auxiliary building.
I When recent performance tests of those systems were conducted in December 1997, BG&E noted under certain conditions a negative pressure may not be maintained. Nevertheless, BG&E did not report these conditions as outside the plant design basis per 10 CFR 50.72(b)(1)(ii)(B). BG&E indicated they did not consider the inability of the ventilation systems to maintain a negative pressure as a reportable condition because the CCNPP accident analysis outlined in Chapter 14 of the FSAR does not assume those systems are functionalin a LOCA. To clarify the plant design basis in this regard, BG&E indicated a 50.59 evaluation would be processed as part of deleting the negative pressure criteria for these systems from the TS bases and FSAR.
The team reviewed 10 CFR 50.72 and NUREG -1022 " Event Reporting Guidelines
10 CFR 50.72 and 10 CFR 50.73," and determined that 10 CFR 50.72 and NUREG l
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l 1022 do not limit the plant design basis to systems credited in the Chapter 14
accident analysis. Therefore, it was not clear to the team whether BG&E should have notified the NRC when BG&E discovered the ventilation system for the ECCS pump and containment penetration rooms were not operating as described in the TS bases and FSAR. As such, this concern represents a sixth part of the unresolved item (UNR 50-317&318/98-80-01)pending further NRC review.
b.3 Compensatorv Measures i
To compensate for a degraded control room ventilation system, BG&E has placed
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15 SCBA in the control room for operators' use if needed following a MHA.
Additional supplies of reserve bottles are located outside the control room. The inspectors toured the control room and verified the SCBA was in the locations specified by procedures.
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SCBA gear training consists of a yearly written examination along with a practical fit test. Both tests are administered by the technical training department. The practical fit test was a new initiative implemented after the NRC identified l
performance issues regarding the operators' knowledge and ability to use the SCBA gear. Details concerning the performance issues are contained in NRC Inspection Report 50-317/318 97-06. At the time of the inspection, all operators had competed the revised training program. The team noted that operators may have to use the SCBA in the control room following an event. BG&E had not verified that
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is donned, but had plans to do so as part of the operator training program.
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Conclusions BG&E has improved the quality of the ventilation system testing program at CCNPP.
Although ventilation calculations have been refined and nonconservative or incorrect l
design assumptions removed, pending NRC review of an impending BG&E submittal, some control room HVAC concerns were unresolved. The concerns related to the acceptability of calculated control room doses after updating, the need for a 50.59 determination, reportability, use of corrective action systems, and NRC notifications l
on systems not in accident analyses. Testing was initiated to verify that the
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ventilation systems can perform their design function as described in the FSAR and
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TS base, however, some weaknesses remain.
E1.2 Emergency Diesel Generator and Service Water / Salt Water System l
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Insoection Scope
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The team selected three systems for detailed engineering and design review:
i emergency diesel generator; service water / salt water system; and HVAC system.
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i For these selected systems, the team reviewed the design / licensing basis l
documents, such as calculations and analyses, the functional requirements, and -
reliability of active components during accident or abnormal conditions; significant i
l test procedures, including acceptance criteria; consistency of normal and
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emergency operation of the system with the design basis; and control and use of l
design documents and inputs. Also, the team reviewed selected modifications to l
the systems to determine if these changes had preserved the original design bases l
system configuration, and had not introduced an unreviewed safety question as I
defined in the 10 CFR 50.59. These inspections and assessments included plant j
walkthrough inspections and observations, and interviews and discussions with l
engineering, operations, and management personnel.
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Observations and hndinas
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l b.1 Emeraency Diesel Generators (EDGs)
b.1.1 System Walkdown and Visual Insoection
The team performed a walkdown inspection of the diesel generator system and supporting mechanical systems, i.e., fuel oil, cooling water, and starting air systems
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to determine the state of equipment, tagging, any obvious discrepancy in the j
system lineup, and housekeeping. No discrepancy was observed.
b.1.2 Calculations and Desian Control The majority of the calculations reviewed were well prepared, contained identified inputs and assumptions, and had conclusions which reflected the methodology -
employed. However, some minor examples of undocumented engineering assumptions and incorrect acceptance criteria were noted. Calculation CA 01206, Safety Related 4 kV Undervoltage Protection, identified the undervoltage (UV) relay
manufacturer's instruction booklet as an input document, and this document (GEK 65535D, SLV Under voltage Relay) identified four parameters that could affect the relay setpoint. The calculation explicitly addressed two of the parameters, temperature and voltage, at very conservative values. However, the calculation did j
not address frequency and harmonic variations. While the team did not believe these parameters would affect the outcome of the UV relay setpoint, there was no written justification included in the calculation for neglecting these parameters, j
BG&E responded by generating issue report (IR) 3-000 526to address this concern.
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The team noted that the Plant AC Load Flow Analysis, calculation E-94-017, identified the maximum allowable voltages to be the switchgear maximum rated voltages. The voltage for the 4160 volt system was given as 4760 volts, consistent with the American National Standards Institute (ANSI) standards.
However, the rnaximum voltage for this calculation should have been 4400 volts, 110% of motor rated voltage. The team also noted the maximum voltage for the 480 volt system was given as 508 volts. The team found numerous examples of non safety-related loads that marginally exceeded this value without any justification as to why this was acceptable. BG&E responded by generating IR 3-000-552 to address this concern.
The load flow analysis contained a number of inputs and assumptions that had been revised. BG&E had planned to update the load flow calculation after the next refueling outage, but because of recent personnel changes, a schedule had not been finalized.
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These are violations of 10 CFR 50, Appendix B, Criterion 111, Design Control, in that BG&E failed to completely review the suitability of equipment that is essential to the safety-related functions of systems and components. However, these violations were considered to be of minor significance and are being treated as non-cited violations, consistent with Section IV of the NRC Enforcement Policy.
(NCV 50 317,318/98-80-02)
l b.1.3 Test Control and Acceptance Criteria The team determined that the acceptance criteria for the post-installation test of the 1 A diesel generator battery,1BATT14,did not properly account for the base battery voltage design.
The team confirmed that 1BATT14 was composed of 60 cells. The design basis document for the 1 A and OC Diesel Generator Systems, DBD-024, Rev.2, dated
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June 7,1996, Indicated the minimum battery cell voltage for 1BATT14 was 1.85 volts per cell [111 volts] based on the minimum voltage requirement of the diesel generator control panels of 105 volts. The team also confirmed that calculation
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D-E-92-002, Rev.1, dated March 7,1995, indicated sufficient voltage would exist l
at the control panels with a battery voltage of 117.6 volts, that is, the battery would meet its design function.
The team found that Engineering Test Procedure (ETP) 94 017, DGP 1 A Battery Pre-operational Test Procedure, Rev.0, dated June 16,1995, failed to explicitly identify an acceptance criterion for minimum battery voltage. Instead, the test instructions
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indicated that the test should be stopped if the voltage dropped below 111 volts.
The system engineer confirmed that BG&E had interpreted 111 volts to be the acceptance criteria for this test.
The team confirmed that the pre-op discharge test records indicated the battery j
terminal voltage had not dropped below 117.9 volts during the test. BG&E initiated lR3-000-505 to address the team's concern.
j This is a violation of 10 CFR 50, Appendix B, Criterion XI, Test Control, in that the test failed to incorporate the requirements and acceptance limits contained in l
applicable design limits. (VIO 50-317,318/98-80-03)
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BG&E informed the team that Calvert Cliffs had no plans to perform periodic service discharge tests on 1 A batteries. The team further observed that the plant's Technical Specifications did not address the new safety-related battery associated with the 1 A diesel generator. This battery supports the dc power and control for the diesel as well as the safety-related 4160 volt and 480 volt switchgear located in
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the 1 A diesel generator building. BG&E maintained that the battery is a support
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system for the 1 A diesel, as is the subject switchgear, and therefore does not require a separate technical specification.
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l The team noted that BG&E had listed NRC Reg. Guide 1.129, Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Nuclear Power Plants, and IEEE-450, Recommendations for Maintenance, Testing, and Replacement of Large Lead Storage Batteries for Generating Stations in the July 26,1993, submittal l
of the electrical engineering design report, Appendix A. Both these documents call for a service duty discharge test to be performed each outage, in addition to a
periodic performance discharge test. The team noted that the other four safety-(
related batteries at Calvert Cliffs, which are covered by the technical specifications, l
do have both types of discharge tests in their surveillance requirements. This will l
remain an unresolved item pending further NRC review with NRR.
(URI 50-317,318/98-80-04)
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While performing a surveillance test on emergency diesel generator (EDG) 2B, on l
January 12,1998, BG&E identified a problem when the " AUTO START BLOCKED" l
annunciator failed to clear. Subsequent troubleshooting efforts determined that the diesel's speed switch adaptor was damaged and was not functioning properly. The adaptor provided input to two speed relays: low speed (250) relay; and high speed (810) relay.
l BG&E replaced the speed switch adaptor and performed a post maintenance test l
(PMT). Following the !'MT, the EDG was declared operable. (Later, the team j
l determined that the PMT had not been completed satisfactorily and that the diesel
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l should not have been declared operable.)
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On January 13,1998, the 2B diesel trouble alarm was received in the control room.
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' investigation revealed that the jacket cooling water low temperature alarm had
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flashed in and out. The jacket cooling water pump and the lubricating oil recirculation pump were found tripped. Further investigation determined that faulty operation of the LSA relay (chattering) was the most likely cause of the pumps tripping.
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A similar problem had occurred on December 29,1997, when the local speed
l indicator (tachometer) had failed to zero (0) while the engine was running at 900
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RPM. The engine speed was verified with a hand held tachometer. Subsequent troubleshooting efforts did not identify the cause of the failure. BG&E concluded that the problem did not affect any safety function of the diesel; hence, the diesel was declared operable.
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L Following the problems that occurred in January 1998, the team judged that BG&E
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December 1997. Although the tachometer provided no safety function, engineers I
did not identify the failed component that caused the tachometer to fail and affect l
safety functions of the diesel generator. Since the tachometer did not have any safety function, repair had been deferred and diesel operability was deemed not to be affected. Furthermore, following ine post maintenance test on January 12,1998, the diesel generator was declared operable despite a chattering
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relay during the test. The condition was not properly addressed. Test personnel that observed the chattering relay did not report or resolve the problem. The team, l
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therefore, determined that BG&E's actions taken to correct deficiencies with the diesel generator had been inadequate, making the diesel generator inoperable for extended periods of time. Initially, troubleshooting efforts were not detailed enough to properly identify a failed speed switch, and later, repair efforts were inadequate l
to correct problems with the speed switch which was identified by the unsuccessful PMT. These actions represented instances of inadequate corrective actions and were contrary to the requirements of 10 CFR 50, Appendix B, Criterion XVI, Conective Actions, which requires that: " Measures shall be established to assure l
that conditions adverse to quality, such as failures, malfunctions, deficiencies, i
deviations, d ;fective material and equipment, and nonconformances are promptly identified and corrected." Therefore, this constitutes a violation'of NRC requirements. (VIO 50 317 & 318/98-80-06)
b.1.4 Desian Document Control The team noted that BG&E had minor errors regarding the correct calculation revision reference in the database. The team found two calculations that were recorded with a revision number prior to the latest revision of the calculation and received three other calculations for review that were not the latest revision to the calculation. BG&E responded by generating IR 3-000-503 to address this concern.
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Conclusions
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The team concluded that BG&E's engineering and design control activities regarding i
emergency diesel generators were satisfactory. However, the team noted that there were some weaknesses in the thoroughness of calculations, and the adequacy of test results, evaluations and troubleshooting. Violations were identified regarding test control (unacceptable acceptance criteria for a battery test) and corrective action (repeated attempts to correct a diesel problem). A noncited violation was l
identified for calculational errors of minor significance, and an unresolved item was Issued for battery testing in the Technical Specifications.
b.2 Service and Salt Water Svstems
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b.2.1 System Walkdown and Visual Insoection The team performed a walkdown inspection of the service and salt water system, including mechanical components, i.e., heat exchanger, valves, pipe and component supports, the condition of equipment, tagging, any obvious discrepancy in the system lineup, and housekeeping. The team also reviewed the list of outstanding operator workarounds and work orders for impact on safe system operation. Except for the deficiency tag on two U-bolts, as discussed in paragraph b.2.2, no other discrepancy was obgerved.
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Additionally, the team reviewed the applicable sections of the technical specification, the Final Safety Analysis Report (FSAR), systems surveillance and
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operating procedures, and system drawings. The team reviewed recent systems'
performance indicators and maintenance summaries. The areas reviewed and j
inspected were found satisfactory, b.2.2 Desian and Confiauration Control During the system walkdown, the team noted a deficiency tag on two U-bolt supports on a service water pipe in the EDG 1B room. In May 1997 BG&E had identified that two U-bolts did not meet design requirements. Issue report IR5-008-l 283 was generated to address the problem. The affected pipe (1-RV-1588)was the discharge of the heat exchanger relief valve RV-1588 to the floor drain from service ovater 6-inch line HB-1022. The line had never been evaluated for the relief valve
.j discharge load. With discharge loads considered, the U-bolt supports' limit was
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shown to be exceeded. BG&E evaluated the operability of the system with the j
degraded support and considered the system operable. The configuration was
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judged to be operable mainly because the system pressure of 89 psi (relief valve set
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point) was not expected to occur, and without this load, the U-bolts would L
adequately support the pipe. BG&E used the guidance provided in their engineering
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standard, E'S-042, Piping Functional Evaluation Criteria, and in NRC Generic Letter 91-18 to determine the system operability. The team found the engineering analysis adequate. However, the team questioned whether an ASME code relief l
was needed, because the piping was not supported as analyzed. BG&E indicated
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that since the configuration had been determined to be operable (although degraded), a relief request was not deemed necessary. Subsequent to the inspection, the team found the BG&C position to be acceptable. BG&E was also in l
the process of instituting repairs to the configuration.
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Plant personnel were diligent at identifying and taking actions to correct problems.
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Engineers closely monitored the systems and had a system performance plan in place for accomplishing corrective actions to identified problems, as well as for improvements to the system. The engineers involved with the systems were technically competent and knowledgeable.
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The review of the service water heat exchanger indicated that engineers had satisfactorily analyzed and evaluated the fouling problems in the heat exchanger, and had performed a thermal performance analysis. As a result, BG&E was making preparations to install a new heat exchanger. This new design, a plate and frame type heat exchanger was being implemented under the 50.59 process, and was l
planned for the next refueling outage. The team judged that BG&E's efforts at l
maintaining the heat exchanger operable were significant.
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b.2.3 Test Control and Acceptance Criteria The team noted that the right design information was being verified in the various periodic tests such as STP O 73A-1, Saltwater Pump and Check Valve Quarterly Operability Test, Revision 8. Engineers provided good support to operations and had developed some performance monitoring information which was incorporated into operations procedure 01-29, Saltwater, to facilitate operators' monitoring of system performance.
b.2.4 Auxiliarv Feedwater System The team determined that the system performance was closely monitored. The monthly system performance evaluation (report card) addressed several aspects of system performance, including concerns on operating conditions, significant maintenance activities, and maintenance rule indicators. Quarterly performance indicators were also generated to bring issues affecting the system to management attention. The team reviewed the system performance evaluation (report card)
dated January 5,1998, and the maintenance back log, dated January 6,1998, and noted no concerns, c.
Conclusions The team determined that engineering activities to maintain the service water / salt water system were effective. The engineering staff had taken prompt actions to resolve identified problems to assure the operational safety of the system.
E2.
Engineering Support of Facilities and Equipment E2.1 Temoorary and Permanent Modifications a.
Insoection Scone (37001)
The primary objective was to evaluate implementation of the requirements of 10 CFR 50.59 with regard to temporary and permanent modifications to plant equipment or systems. For this inspection, the training and qualifications of personnel performing safety evaluations or screenings (referred to as 50.59s) were not examined, but were inferred from the quality of the evaluations reviewed. The review also included the program for performing functional evaluations and operability determinations of potentially degraded equipment, as controlled by Administrative Procedure NO-1-106. Some of 50.59s and 50.59 screenings and evaluations were selected for detailed review. The systems involved included the polar crane in containment, CVCS, in-core instrumentation, salt / service water,1 A EDG, component cooling water, and the feed and condensate system _ _ _ _ _
,
.
b.
Observations and Findinas i
l The administrative procedure controlling the development and use of 50.59s and 50.59 screenings was EN-1-102, " Safety Evaluation Screenings and Safety Evaluations." The procedure clearly delineated personnel responsibilities and the
process to be followed to perform a 50.59 screen and subsequent 50.59 evaluation
'
(if required by the screen). The team noted that more detailed guidance concerning the evaluations was contained in engineering procedure ES-017, which was appropriately referenced in EN-1-102.
The 50.59s reviewed were well-written and technically rigorous, and included appropriate supporting documentation. The text adequately supported the checked blocks for questions pertaining to the safety analysis report, and any assumptions used in the evaluation were clearly set forth and the basis explained. The 50.59
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l screens were clear and the explanation statements adequately supported the l
selected answer to the question under consideration. For the screens reviewed, the team found no instance where a modification had been inappropriately screened as not requiring a full 50.59 evaluation.
BG&E performed operability determinations in accordance with the guidance of l
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Generic Letter 91-18 and administrative procedure NO-1-106, " Functional l
Evaluation / Operability Determination." These evaluations (termed 106s) were l
performed by engineering to support continued plant operation with degraded or non-conforming equipment. The team reviewed all the active and inactive 106s for calendar year 1997.
I In general, the 106s were well-written and provided a clear nexus between the j
evaluation and the supporting calculations and other data. The team noted an
improving trend through 1997 in the level of detail and supporting documentation contained in the 106s. However, in one instance the team noted that " corporate knowledge" appeared to substitute for an evaluation of the potential for water
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. hammer in the low pressure safety injection (LPSI) system (NO 1-100 serial number j
97023), as the evaluation was narrowly focused on the refueling water tank level l
switch and its spurious actuation. BG&E engineers described the extensive effort undertaken in the early 1990s to understand the potential for water hammer in the l
LPSI system and mitigate its effects. However, the 106 made no reference to this effort. BG&E acknowledged that its inclusion in the 106 would have been i
appropriate and would have provided a more robust evaluation.
The team did not identify any significant technical errors in the 106s reviewed.
I However, the team noted that it was not clear how safety oversight was provided to the process, as the general supervisor of nuclear operations was the approving and implementing official. NO-1-106 was a technical specification-related procedure, but the POSRC did not review the operability determinations. Also, there were several minor administrative deficiencies which indicated that the NO-1-106 procedure was inconsistently understood and implemente r L*
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The operability recommendation checklist's four statements of varying
degrees of operation were answered inconsistently and, on several (
occasions, were changed by the qualified reviewer.
l Not all copies of 106s which had status of " inactive" were so stamped and
signed by the general supervisor of system engineering. The team noted, f
,
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however, that no unstamped inactive 106s were present in the control room's file.
During 1997 the approved versions of NO-1-106 were Revisions 3 and 4.
- However, in at least one instance, the team found that the 106 was I-prepared using a revision 1 form. While the information requested did not
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differ significantly from the later revisions, and therefore did not invalidate
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the conclusion of operability, the use of a superseded revision was contrary
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to BG&E's policy concerning " user controlled" procedures, where the user is
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responsible for ensuring he uses the current revision.
i Several 106s were apparently independently reviewed and approved by.
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l telephone, and so designated by the preparer. It was not clear how this l
process was centrolled, and if permitted, documented.
l Although the above issues were violations of NRC requirements (10 CFR 50, l
Appendix B, Criterion V, Instructions, Procedures and Drawings, and Criterion VI, l
Document Control), they were of minor significance. Consequently, these issues l
are being treated as examples of a Non-Cited Violation consistent with Section IV of L
the NRC Enforcement Policy. (NCV 50-317&318/98 80-06)
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c.
Conclusions l
BGE's 50.59 safety evaluations were well-written, technically rigorous, and in l
accordance with implementing procedures. 50.59 screenings were appropriately i
performed; no temporary or modifications reviewed were erroneously screened as not requiring a full safety evaluation. Operability determinations were technically well-written and showed an improving trend through 1997 in level of detail and supporting documentation. Several minor administrative deficiencies regarding
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operability determinations represented violation of NRC requirements, but v<ere treated as a Non-Cited Violation in accordance with the NRC Enforcement Policy.
E2.2 Enaineerina Sucoort to Ooerations
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a.
Insoection Scoos (37001 and 93809)
l The team reviewed the engineering support, particularly system and design engineering, provided to the operations department to address known plant deficiencies, provide enhancements to improve plant performance, and respond to operators' requests in evaluating potentially degraded or non-conforming equipment.
The review included interviews with both engineering and operations personnel, as well as several members of the POSRC.
a
.
.
b.
Observations and Findinas in general, the team found that the engineering department had provided effective and timely support to address operations' concerns and requirements. Support was particularly noteworthy for several significant initiatives such as maintaining service water heat exchanger operability during periods of high Chesapeake Bay temperatures and the trip reduction effort. Engineering support was effectively factored into the operations department business plan, with mutually agreed-upon
deliverables and goals.
Communications between engineering and operations were generally good. As noted in section E.2.1,50.59s and operability determinations were thorough and, in the latter case, provided good support for operability decisions. In one instance, however, on January 13,1998, the team noted that engineering personnel evaluating damage found on the stanchion and restraining steel of the Unit 1 low i
pressure safety injection (LPSI) system common discharge line did not report their discovery to the shift supervisor in a timely manner to facilitate an evaluation of operability. The team discussed this issue with engineering management, who indicated that it was their expectation that problems would be brought to the attention of the shift supervisor, orally if necessary, if system operability might be degraded, even before initiating an issue report or performing an evaluation.
The team observed that when the shift was notified, the LPSI system was promptly declared inoperable and the appropriate technical specification (TS) action statement, which required the plant be shut down, entered. Operations requested an evaluation by engineering to determine the status of the LPSI system. Plant engineering promptly provided a thorough analysis which allowed operations to conclude that the LPSI system was operable with the pipe support removed, and the plant was returned to full power. (This event was reported to the NRC via Licensee Event Report 50-317/98-003.)
The team concluded that the approximately three hour delay in informing the shift supervisor had no actual safety consequence, but did impact a timely entry into TS 3.0.3 and the required plant shutdown. Based on discussions with operations personnel, the team concluded that this appeared to be an isolated event. While the
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failure to promptly enter the applicable TS action statement upon discovery of a condition placing the LPSI system outside its design basis was a violation of NRC requirements, this non-repetitive, licensee identified and corrected violation is being treated as a Non-Cited Violation, consistent with Section Vll.B.1 of the NRC Enforcement Policy. (NCV 50-317&318/98-80-07)
During observation of a number of POSRC meetings and review of POSRC meeting minutes where 50.59s wers presented with a recommendation for approval, the team noted that very few caficiencies were identified by reviewers and in most cases those few deficiencies did not substantially affect the conclusion that no unreviewed safety question existed. Engineering personnel who made presentations to the POSRC were generally well prepared and able to satisfactorily respond to committee question r
.
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Training provided to operators by engineering (primarily system engineering) on modifications to the plant was good in most cases, and corrective actions taken to address earlier deficiencies in training on several complex modifications such as
$
digital feedwater controls have been effective. The original training had been inadequate, in part because communications between engineering and operations were poor, as evidenced by several plant trips and transients following implementation of the modifications. On subsequent changes to the digital feed system, more extensive simulator training was given to each operating crew.
Additionally, system engineers were present in the control room during startups and
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I shutdowns to assist the shift in feedwater system operation. The team noted that there had been only very minor problems with operator knowledge of expected system performance following the last series of upgrades to the digital feedwater system, and that there have been no plant transients due to operator misunderstanding of feedwater system operation in the past eighteen months.
c.
Conclusions l
The engineering department provided effective and timely support in response to operations' needs. Communications between the departments were generally good, with a notable exception of an instance involving degradation of the LPSI system in January 1998, judged to be a non-cited violation. POSRC presentations of safety evaluations and screenings were good. Training supplied by engineering to operators was generally good, with improvements noted subsequent to performance problems following the implementation of the digital feedwater modification.
E8 Miscellaneous Engineering issues E8.1 Corrective Actions Prooram (40500)
a.
inspection Scope l
l The team evaluated the effectiveness of identifying, resolving, and preventing
.
(
problems that degrade plant operations and safety. This was accomplished through
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personnel interviews, plant tours, and review of several programs, including the
issue reporting system, the root cause analysis program, audit /self-assessment programs, and the activities of the on-site /off-site safety review committees.
Documents reviewed are listed in Attachment 1.
b.
Observations and Findinas
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b.1 Problem Identification and Processina The issue report (IR) system serves as the primary method for documenting, screening, and processing programmatic (~ 3,500 irs in 1997) and hardware-related (~7,400 lRs in 1997) problems. Through the issue report system, problems, in general, were found to be appropriately screened, prioritized, and assigned an issue resolution sponsor. Section E1.1 discusses isolated examples when problems were not promptly documented in an issue report by the design engineering section.
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As hardware-related irs can result in a maintenance work order (MO) and deficiency tags, the team reviewed this process. The team accompanied a systems engineer j
on a tour of various ventilation equipment rooms in the Auxiliary Building and the
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Unit 1 auxiliary feedwater pump room. Deficiency tags were found to be appropriately placed on equipment requiring repairs. Subsequently, a sample of tags was traced to their respective maintenance orders (MOs). The team determined that MOs had been developed for the hardware deficiencies and the repair activity had been appropriately scheduled. No longstanding significant deficiencies were observed. No additional hardware or housekeeping deficiencies were identified by the team.
A second method of problem documentation and processing is the multipurpose
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gold card system. Gold cards can be used to identify problems, particularly human performance related, which are below the threshold for initiation of an IR, then given to a supervisor. Supervisors are to ensure that each issue identified on a gold card is reviewed for possible escalation to an IR. Repetitive problems and negative
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performance trends identified by gold cards may also result in an IR. Additionally,
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gold cards can be used to document proper use and positive performance
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observations for consideration in the employee awards and recognition program.
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The team judged that in some cases, particularly in the maintenance department, that gold cards had inappropriately supplanted job observation records.
The team found the gold card system to be loosely structured. Card format varied between site departments. Each department administered their system differently.
Gold card coordinators have been assigned within the operations, maintenance, and
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plant engineering departments to screen cards, trend information, and identify adverse performance trends. The radiation safety department has established a gold card committee with a committee lead to carry out this function. The frequency of reviewing gold cards varied. Gold card data is captured in a variety i.f databases thereby restricting the sharing and consolidation of information. Problem category codes are customized to the respective department. Trending techniquei I
also varied widely between departments.
I The team observed that the gold card coordinators were routinely reviewing gold cards and making a conscientious effort to determine if an IR was more appropriate for the identified condition. irs have been issued for gold cards that indicated a repetitive problem or a negative performance trend. However, through field interviews and record review, the team determined that the threshold for determining whether a gold card or a Category 3 (the lowest level) lR should be written was unclear to the workforce. No written guidance had been provided to facilitate whether a gold card or an IR should be issued. Individual judgement by the initiator or the coordinator / committee-lead determined if an IR should be issued.
BG&E representatives acknowledged this concern and stated that guidance was being developed, t
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Nonetheless, low level repetitive problems and adverse trends identified on both irs and gold cards had been appropriately documented on irs and were assigned resolution sponsors. The high frequency of documenting such trends indicated that a proactive approach was the accepted way for prompt correction of minor problems whether the matter was human performance error or hardware related, c.
Conclusions I
Problem Identification and Processina l
The team concluded that through the issue Reporting System, problems are being appropriately identified and processed issues that are considered significant conditions adverse to quality are escalated to the proper management level for i
resolution. Low level repetitive problems and adverse trends are appropriately identified, analyzed, and addressed before the conditions wornis. Actions are being taken to clarify to the workforce whether a problem sinuld be documented as an issue Report or a Gold Card.
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b.2 Root Cause Analvses and Corrective Actions For 1997 two Priority 1 root cause analyses (RCAs),36 Priority 2 RCAs, and 277 Priority 3 RCAs were completed for Category 1 issue reports. The team reviewed all Priority 1 RCAs, most Priority 2 RCAs, and a sample of Priority 3 RCAs. The Priority 1 Event Reports were found to be in-depth evaluations for the reactor trips that occurred resulting from a failure of a component in the Unit 2 feedwater regulating valve positioner in November 1996 and an inadvertent opening of a Unit 1 main condenser vacuum breaker due to an electrical short in the valve's hand switch in October 1997. A Significant incident Finding Team (SIFT) was activated for each event, in-depth causal analysis was performed, the extent of similar deficient conditions was addressed, and appropriate corrective actions were recommended to preclude recurrence.
.
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Generally, the Priority 2 Root Cause Analysis Reports (RCARs) were of a quality comparable to Priority 1 event reports. The RCARs adequately evaluated the issue, including discussion of past site and industry similar events; causes for ineffective past corrective actions, when appropriate; and clear causal descriptions. The use of various analytical techniques was evident including barrier analysis, change analysis, and Human Performance Enhancement System (HPES) methods.
Corrective actions addressing the causes were presented with an identified manager
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responsible for implementing each action, and estimated completion date(s) were I
identified.
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A sample of Priority 3 root cause reports was found to be abbreviated summaries of i
investigative activities. The evaluations performed by the plant engineering section
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(PES) generally centered on summarizing the results of troubleshooting with the i
most probable cause stated for a hardware malfunction; minor consideration was l
given to human performance matters. Cause evaluations performed by the l
operations or maintenance departments appropriately considered human l-performance elements that affected the issue, such as poor self verification
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techniques, inattention to detail, and a weak questioning attitude.
Completing RCAs in a timely manner has not met site program goals and has been a l
j management concern. For i997, Priority 1,2, and 3 RCAs were completed in
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64.5,107 and 136 days on the average, respectively. In February 1997, at the
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l request of the plant general manager, a Priority 2 RCA was performed to determine l
why RCAs take an excessive amount of time. The analysis concluded that the delay has been due in part to uncleer guidance, poorly communicated management j
expectations, and low prioritization of Priority 3 RCAs compared with other scheduled work. Recent actions have been taken to address these issues, including l
revising guidance to clearly state that Priority 1,2, and 3 RCAs are to be completed j
within 30,45, and 60 days, respectively.
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The team noted the use of "Why Staircase" studies, to address underlying issues l
regarding human performance. The toolinvolved a series of why questions to j
l prompt the analyzer to evaluate underlying factors. Following completion of high priority RCAs, "Why Staircase" studies were performed summarizing the lessons learned and provided to managers and supervisors. This method was found to
.
clearly focus management attention on specific issues needing resolution to improve (
overall site performance. These studies were self critical, particularly in the areas l
where management was not proactive in recognizing precursors from site and industry experiences and self-assessments.
'
Corrective action implementation varied with IR category Generally, for priority events actions were timely. For Category 1 issues, broad-based corrective actions were evident including training enhancements, procedure revisions, equipment repairs and modifications, work practice changes, and personnel counseling. In certain cases, however, particularly with Category 2 irs, actions were not
aggressively managed. This was illustrated in IR1-046-727,regarding the repetitive l
improper and excessive use of silicon sealants on certain plant systems. The issue
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was identified in 1996, reoccurred in March 1997 (IR1-042-715),and corrective
{
actions were not planned to be fully implemented until mid-1998. In reviewing the l
measures that remain to be taken, managing of this issue did not appear timely to l
the team, j
.
.
Determining corrective action effectiveness was specified for Category 1 issues for the purpose of precluding recurring events. Although guidance was being developed for establishing when, how, and what would be evaluated in an effectiveness review, such reviews had been completed for certain issues. The reviews examined varied significantly in the level of detail but were found to appropriately address the fundamentalissue of determining if a similar event recurred.
c.
Conclusions Root Cause Analysis and Corrective Actions The team concluded that the quality of root cause analyses were commensurate with the safety significance of the issue. For significant issues, corrective actions L
were comprehensive. Management was taking actions to improve the timely completion of root cause analyses and to better evaluate corrective action effectiveness. Implementation of corrective actions was timely for high priority issues, but was not aggressively managed for lower category problems.
b.3 Self Assessments and Audits l
Management expectations for conducting self assessments were well articulated in l'
nuclear program policy and mission statements. These expectations for
" continuous quality improvement" have resulted in the self assessment process being ingrained into departmental work routines as well as formalized, detailed, periodic audits.
The engineering assessment unit, maintenance performance assessment unit, and i
operations / plant support assessment unit within the nuclear performance
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assessment department (NPAD) have provided frequent assessments of normal plant routines, insightful reactive assessments of off-normal activities, such as the l
reactor coolant pump seal replacement, and programmatic assessments of I
management controls. Detailed assessment plans were used that clearly identified the expected attributes of the assessed element. Areas of improvement were identified, issue reports were generated, action plans were developed, and programmatic issues were elevated to the appropriate management level.
Particularly noteworthy was the corrective action program self-assessment
)
completed in September 1997. This in-depth performance-based self-assessment j
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was performed by a team representing the IAU and NPAD with participation by industry peers. Insights were obtained into those programmatic weaknesses that limit organizational performance, for example, the lack of integration of the self-l assessment, corrective action, and trending processes resulting in event precursors not being promptly identified. Accordingly, detailed actions have been assigned, l
with appropriate management oversight, to improve the overall effectiveness of the corrective action program by making it less reactive and more proactive. A "Why l
Staircase" study was developed for this assessment to focus management attention
on the prevailing site behaviors, culture, and programmatic shortcomings that
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limited effectiveness.
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Internal and external assessment results were consolidated by NPAD in quarterly l
Safety Performance Assessment Reports (SPARS) and presented to senior l
management. SPARS were found to focus management on areas of concern that affect performance within the various site departments, grade performance in the SALP functional areas, and identify current trends. Success factors for areas that
,
l demonstrated significant sustained, improved performance, e.g., trip prevention and foreign material management, were compared to the present status of programs needing improvement, e.g., radiation protection exposure control. Those success factors that were missing in weak performance areas were addressed.
l l
Required audits were found to have been performed at the proper frequency, have l
been of the appropriate depth and scope, addressed performance and compliance j
items, and to have promptly initiated issue reports, with management areas that limit performance improvement identified and recommendations made. Audits reviewed are identified in Attachment 1.
c.
Conclusions l
i l
Self assessments and Audits
)
l The team concluded that self-assessments and audits were of high quality, having-
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sufficient scope and depth to identify areas for program improvement and clearly directing where increased management attention was needed. Deficiencies
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identified were addressed in a timely' manner.
b,4 On-Site and Off Site Review Committees l
l l
Through review of PORSC minutes, the team found that safety evaluations,
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engineering service packages, test procedures, temporary modifications, and issue l
reports (screened as safety significant by IRRG) were appropriately reviewed to j
l determine if an unreviewed safety question existed. POSRC members probed issues (
to comprehensively address regulatory matters, program deficiencies and pertinent l
technical problems. On several occasions, the plant general manager provided the l
committee feedback regarding his disposition of issues which involved split votes by l
POSRC members.
l l
The team observed various staff presentations made to the POSRC at a meeting
[
held on January 28,1998. The subject matter was adequately presented, clearly
'
stating the safety and regulatory implications for the topic under discussion.
Members were adequately prepared, questions were insightful, provoking an appropriate safety focus, and issues'were discussed in depth. The POSRC also challenged presenters to address relevant ancillary issues to ensure that tasks were
}
appropriately planned and potential problems anticipated in upcoming evolutions.
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OSSRC members were found to be actively involved in assessing plant activities by performing plant tours, by conducting personnel interviews, by attendance at PORSC/ maintenance planning / site manager meetings, and by frequently scheduling committee meetings. The team judged that the OSSRC challenged the effectiveness of various site programs. For example, the OSSRC has expressed concerns regarding the quality of root cause analyses;i.e., had the site's root cause j
analyses probed sufficiently deep to find the true underlying causal factors? This
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issue was under review by the responsible site departments, c.
Conclusions l
Onsite and Offsite Review Committee The POSRC and the OSSRC were appropriately carrying out their roles and
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l responsibilities. The committees appropriately challenged the plant staff to improve
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the effectiveness of the corrective action program.
E8.2 Review of Uodated Final Safety Analvsis Reoort (UFSAR)
j a.
Scope A recent discovery of a licensee operating their facility in a manner contrary to the i
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Updated Final Safety Analysis Report (UFSAR) description highlighted the need for a i
special focused review that compares plant practices, procedures and/or parameters to the UFSAR description. While performing the inspections discussed in this report, the team reviewed the applicable portions of the UFSAR that related to the area inspected, b.
Findinas and observations The team compared the discrepancies they had found in Chapter 8 with the results of BG&E's review. The team noted that BG&E had already identified the more significant discrepancies the team had found, but had failed to critically question some minor statements in the chapter.
BG&E agreed with the team's observation and noted that they too had identified other items associated with the diesel generators and had issued irs to document those discrepancies prior to this inspection. In response to those irs, BG&E had initiated a scope change to add the diesels as the sixty-second (62) topic for the UFSAR Review Project. Although the scope change had not yet completed the approval process prior to the end of this inspection, BG&E assured the team that it would be added. The team reviewed the process BG&E used to assemble review packages for the project review teams, including electronic word searches, and agreed that the review effort would likely have identified the same items as the l
l team had found.
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c.
Conclusions The team concluded that BG&E was conducting a detailed review of the UFSAR in an appropriate manner.
l E8.3 Review of Ooen items (Closed ) Containment Tendons: IFl 50-317& 50-318/97-05-03 a.
SCODO l
The team reviewed the status of the surveillance program for containment tendons, the results obtained so far, and BG&E's proposed following up actions in this matter.
b.
Observations and Findinas The team reviewed the tendon surveillance data, and noted that the liftoff tests of the tendons had been performed basically from the top end of the tendons. The liftoff forces as shown in the report were the average of the three individual readings recorded at the liftoff tests of individual tendons. The "as-found" and the
" average" liftoff forces indicated a close correlation. The double-end-stressed l
tendons around large openings required liftoff tests from both ends. In this category, only nineteen (19) representative tendons were tested, and six (6) of these tendons were detentioned for a more detailed inspection. Additional tendons were not detentioned because of the concern for containment integrity. It was determined that there had been degradation in the vertical tendons and follow up actions were required.
BG&E had developed and implemented the short term corrective actions consisting of local regreasing and sealing the grease cans with silicon to prevent further degradation and to assure operability of tendons until the long term corrective actions were developed and implemented.
The long term actions were scheduled to be finalized by the end of the first quarter of 1998. The replacement of the grease in all vertical tendons, regardless of the final long term fix, also was under consideration. BG&E had submitted a report to the NRC regarding the results of the surveillance tests, and the Office of Nuclear Reactor Regulation was reviewing the submittal. Based on the above actions and the submittal to the NRC, this item is closed.
c.
Conclusignt l
The team concluded that the containment tendon surveillance effort was extensive, f
and the short term corrective actions were appropriate. The schedule of the long
term actions was acceptable,
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X1 Exit Meeting The inspector met with the representatives of BG&E at the conclusion of the l
inspection on January 30,1998, and summarized the scope of the inspection and l
the inspection results. No proprietary materials were reviewed during the inspection. BG&E acknowledged the inspection findings at the meeting.
l l
j DOCUMENTS REVIEWED Procedures and Documents Reviewed l
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. MD -1-100, Temporary Alterations
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. EN -1 - 102, Safety Evaluation Screening & Safety Evaluations, revision 4
. ES - 017,10CFR50.59/72.48, Safety Evaluation, revision 00 I
. ES - 042, Piping Fun <:tional Evaluation Criteria j
. STP O-581, AFW Flow Path Verification, revision O.
. STP O-678-1, Auxiliary Feedwater/ Main Steam Check Valve Test, revision 1.
. STP O-73H 1, AFW Pump Large Flow Test, revision 2.
. STP O-5-1, Auxiliary Feedwater System Monthly Surveillance Test, revision 39 l
. STP 0 5A-1, Auxiliary Feedwater System Quarterly Surveillance Test, revision 4 l
. STP O-73A-1, Saltwater Pump & Check Valve Quarterly Operability Test, revision 8 l
. Temporary Alterations:
1-96-0108, Control Room HVAC Return Fan Damper 5371.
I 1-97-0012, Containment Air Coolers flow control valves.
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2 97-0018, Containment Air Coolers flow control valves.
1-97-0035, PORV Block valves 1MOV403 and 1MOV405.
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l 2 97-0120, SIT Check valve high pressure alarm.
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1-96-0091, Pressurizer Spray piping Thermocouple.
AUDITS REVIEWED Audit No. 97-15, Nuclear Safety Oversight Audit No. 97-14, Design Authority and Configuration Management Audit No. 97-11, Nuclear Plant Operations Audit No. 97-08, Testing Program Audit No. 97-07, Radiation Protection Program Audit No. 97 05, Maintenance Program l
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NPAD SAFETY PERFORMANCE ASSESSMENT REPORTS I
Third Quarter Report 1997 Second Quarter Report 1997 First Quarter Report 1997 Fourth Quarter Report 1996 Maintenance Performance Assessment Reports:
97-AR 01MPAU,11 Salt Water Header Cleaning & Inspection, July 7-10,1997 97-AR-03-MPAU, Assessment of the Reactor Coolant Pump Seal Replacement, October 6,1997 ROOT CAUSE ANALYSIS REPORTS (RCAR) REVIEWED Priority 1:
l CCER 97-01, Unit 1 Reactor Trip resulting from the unexpected opening of a main condenser vacuum breaker on October 24,1997 CCER 96-02, Unit 2 Raactor Trip due to a loss of feedwater on November 17,1996
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Priority 2:
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RCAR 97-24, investigation of Unit 2 Refueling Equipment Problems l
RCAR 97-22, Investigation of Unit 1 Containment Tendon Surveillance Violations
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RCAR 97-11, investigation of Unit 1 failed compression fitting on a Pressurizer i
l pressula sensing line I
i RCAR 97-07, investigation of an inadequate modification to the service water inlet i
control valve to the containment air coolers l
RCAR 97-02, investigation of safety tagging errors while tagging a sluice gate i
RCAR 96-09, investigation of motor failures RCAR 96-04, Evaluation of the Root Cause Analysis process regarding timeliness of completing RCAs.
POSRC MINUTES REVIEWED Meeting Nos.97-126 through 97-135 held during the period November 3 26,1997 i
Meeting Nos.97-103 through 97-112 held during the period September 3-29,1997
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Meeting Nos.97-087 through 97-095 held during the period July 1-30,1997 OSSRC MINUTES REVIEWED Meeting No. 97-12 held on November 13,1997 Meeting No. 97-10 held on October 9,1997 Meeting No. 97-08 held on July 10,1997
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LIST OF ACRONYMS USED A/E Architech/ Engineer AHU Air Handling Unit l
ANSI American Nationial Standards Institute DBD Design Basis Document DG Diesel Generator
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ETP Engineering Test Procedure HP Horsepower HVAC Heating, Ventilating and Air Conditioning IEEE Institute of Electrical and Electronics Engineers IR Incident Report
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KV Kilovolt MCC Motor Control Center
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NCV Non-Cited Violation UFSAR Updated Final Safety Analysis Report UNR Unresolved item UV Undervoltage VIO Violation PERSONS CONTACTED Baltimore Gas & Electric Comoany
- P. Katz, Plant General Manager i
- P. Chabot, Manager, NED j
'T. Pritchett, Acting Manager, NED l
'J. Lemons, Manager, NSSD
- B. Rudell, General Supervisor, Project Management
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'W. Kemper, Acting General Supervisor, DES i
- T. Sydnor, General Supervisor, Plant Engineering Persons denoted by (*) attended Exit Meeting on January 30,1998. In addition to the above, other technical, administrative, and management personnel were contacted by the inspectors as the scope of inspection / review interfaced with their work.
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U.S. Nuclear Reaulatorv Commission
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'J. Wiggins Director, Division of Reactor Safety
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