IR 05000317/1993016
| ML20046B241 | |
| Person / Time | |
|---|---|
| Site: | Calvert Cliffs  |
| Issue date: | 07/22/1993 |
| From: | Larry Nicholson NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION I) |
| To: | |
| Shared Package | |
| ML20046B237 | List: |
| References | |
| 50-317-93-16, 50-318-93-16, NUDOCS 9308030390 | |
| Download: ML20046B241 (22) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION I
Report Nos.
50-317/93-16; 50-3 3/93-16 License Nos.
DPR-53/DPR-69
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Licensee:
Baltimore Gas and Electric Company
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Post Office Box 1475 Baltimore, Maryland 21203 Facility:
Calvert Cliffs Nuclear Power Plant, Units 1 and 2
Location:
Lusby, Maryland l
Inspection conducted:
May 30,1993, through July 3,1993 Inspectors:
Peter R. Wilson, Senior Resident Inspector
Carl F. Lyon, Resident Inspector Henry K. Lathrop, Resident Inspector
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r Approved by:
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/7 liarry/. Nicholson, Chief
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R r Projects Section No. lA Division of Reactor Projects Insnection Summary:
This inspection report documents resident inspector core, regional initiative, and reactive inspections performed during day and backshift hours of station activities including: plant
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operations; radiological protection; surveillance and maintenance; emergency preparedness; security; engineering and technical support; and safety assessment / quality verification.
Results:
See Executive Summary.
I 9308030390 930722 5{
PDR ADOCK 05000317 Q
G-PDR a
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EXECUTIVE SUMMARY l
Calvert Cliffs Nuclear Power Plant. Units 1 and 2 Insnection Reoort Nos. 50-317/93-16 and 50-318/93-16 i
Plant Ooerations: (Operational Safety Inspection Module 71707, Prompt Onsite Response to Events at Operating Powe-Reactors Module 93702) Several operational events occurred during the period. While there were no actual safety consequences as a result of these
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events, several contributing factors were noted, including lack of a questioning attitude by operators, failure of operators to adequately assess plant conditions, and inadequate procedural control of. rip-sensitive valves (this was determined to be a non-cited violation).
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As a result, an NRC Special Inpection (50-317 & 318/93-23) was initiated to review the
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circumstances surrounding the events and make an independent assessment of the causal factors.
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Radiolocical Protection: (Module 71707) Based on direct observation of access controls and radiological safety practices and discussions with radiological controls personnel, the radiological protection program and implementation were excellent.
Maintenance and Surveillance: (Maintenance Observations Module 62703, Surveillance Observations Module 61726) hs general, an acceptable level of performance was observed
during maintenance activities. B'i&E's actions in response to the identification of a failed component cooling water valve were prompt and appropriate. During an auxiliary feedwater pump surveillance test, operators failed to recognize a steam generator high differential pressure condition that resulted in aa inadvertent protective system actuation.
Emercency Prenaredness: (Module 71707) An acceptable level of emergency preparedness was found based on inspection of facilities, review of procedures, and discussion with operations and emergency planning personnel. BG&E appropriately declared an Unusual Event on June 10 after implementing the emergency operating procedure for loss of offsite i
power following a loss of the Unit 2 500 kV (red) bus.
Security: (Module 71707) Based on direct observation, the security plan was professionally implemented.
Eneineerine and Technical Suppst: (Module 71707) BG&E's actions were appropriate in response to the identification of several plant areas where a postulated Appendix R fire could result in the loss of both trains of control room air conditioning. A previously existing unresolved item regarding this issue remains open pending the resolution of long term
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Executive Summary corrective actions. BG&E's evaluation and response to a high containment temperature
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condition resulting from boric acid buildup on the containment air coolers demonstrated good
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Safety Assessment /Ouality Verification: (Modules 71707, 30703) Based on direct
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observation, the onsite safety review committee performed a comprehensive review of the l
events that occurred during the period, with a good safety perspective. BG&E effectively implemented shutdown safety measures during the recent refueling outage. BG&E's decision to shutdown a unit on two occasions during the period was assessed to be prudent and to demonstrate a good safety perspective. The shutdowns were made to evaluate and repair problems that had the potential to degrade if left uncorrected.
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SUMMARY OF FACILITY ACTIVITIES Unit 1 began the period at full power. The unit was manually tripped on June 10 due to concern of a potential loss of the 500 kV (black) bus, following a loss of the Unit 2 500 kV (red) bus. During startup on June 11, the unit automatically tripped from approximately 16% power as a result of high level in the feedwater heaters. Unit I was again started up on June 12 and returned to full power. The two reactor trips are discussed in section 2.2. On June 23, a shutdown to hiode 4 (hot shutdown) was commenced to clean the containment air coolers (CACs), following the discovery that boric acid had built up on the coolers and appeared to be reducing their cooling capacity. This issue is discussed in section 7.2.
Following cleaning of the CACs and evaluation of the issue, the unit was restarted and returned to full power on June 29.
Unit 2 began the period in Mode 5 (cold shutdown) in a refueling outage. Upon completion
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of outage work, BG&E conducted a heatup and startup as follows:
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June 4 heatup to Mode 4 (hot shutdown)
j June 5 heatup to Mode 3 (hot standby).
On June 10, while diluting boron concentration to achieve criticality, a loss of power to the Unit 2 500 kV (red) bus caused a reactor trip. The reactor tripped on low flow when power j
to all reactor coolant pumps was lost. BG&E declared an Unusual Event due to the partial loss of offsite power. Following restoration of reactor coolant flow and normal site electrical lineup that day, the Unusual Event was terminated. The reactor trip and Unusual Event are j
discussed in section 2.2. Unit 2 recommenced startup as follows
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l June 11 entered Mode 2 (startup) and began critical operations and low power physics testing June 12 entered Mode 1 (power operation) and began main turbine and power escalation testing June 13 paralleled the main generator to the grid and completed the refueling outage On June 24, a power reduction to Mode 2 was begun and the main turbine was taken off the grid to repair a leaking vent plug on a reactor coolant flow transmitter. While raising power on June 25 following the repair, a low water level in 21 steam generator caused an automatic reactor trip. Reactor power was about 3% at the time of the trip, which is discussed in I
section 2.2. The unit returned to full power on June 29.
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2.0 PLANT OPERATIONS 2.1 Operational Safety Verification The inspectors observed plant operation and verified that the facility was operated safely and i
in accordance with licensee procedures and regulatory requirements. Regular tours were i
conducted of the following plant areas:
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- control room
-- security access point
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-- primary auxiliary building
-- protected area fence
-- radiological control point
-- intake structure
-- electrical switchgear rooms
-- diesel generator rooms
- auxiliary feedwater pump rooms
-- turbine building i
Control room instruments and plant computer indications were observed for correlation
between channels and for conformance with technical specification (TS) requirements.
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Operability of engineered safety features, other safety related systems and onsite and offsite
power sources was verified. The inspectors observed various alarm conditions and confirmed that operator response was in accordance with plant operating procedures.
Routine operations surveillance testing was also observed. Compliance with TS and
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implementation of appropriate action statements for equipment out of service was inspected.
Plant radiation monitoring system indications and plant stack taces were reviewed for
unexpected changes. Iegs and records were reviewed to determine if entries were accurate
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and identified equipment status or deficiencies. These records included operating logs, l
turnover sheets, system safety tags and temporary modifications log. Plant housekeeping controls were monitored, including control and storage of flammable material and other
potential safety hazards. The inspectors also examined the condition of various fire protection, meteorological, and seismic monitoring systems. Control room and shift manning
were compared to regulatory requirements and portions of shift turnovers were observed.
The inspectors found that control room access was properly controlled and that a professional i
atmosphere was maintained.
In addition to normal utility working hours, the review of plant operations was routinely
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conducted during backshifts (evening shifts) and deep backshifts (weekend and midnight
shifts). Extended coverage was provided for 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br /> during backshifts and 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> during deep backshifts. Operators were alert and displayed no signs ofinattention to duty or fatigue.
The inspectors observed an acceptable level of performance during the inspection tours
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detailed above. General plant housekeeping was excellent over the period.
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2.2 Followun of Events Occurring During Inspection Period During the inspection period, the inspectors provided onsite coverage and followup of unplanned events. Plant parameters, performance of safety systems, and licensee actions
were reviewed. The inspectors confirmed that the required notifications were made to the i
NRC. During event followup, the inspectors reviewed the corresponding CCI-ll8N (Calven
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Cliffs Instruction, " Nuclear Operations Section Initiated Reporting Requirements")
documentation, including the event details, root cause analysis, and corrective actions taken to prevent recurrence. The following events were reviewed.
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Unusual Event - Partial loss of Offsite Power and Dual Unit Trip on June 10 BG&E declared an Unusual Event at 8:50 a.m. on June 10 when a loss of power to the Unit 2 500 kV (red) bus caused a Unit 2 reactor trip. The loss of the red bus caused a loss of the l
24 4kV vital bus and the Unit 1 14 4kV vital bus. Unit 1 was then manually tripped by operators who anticipated a possible loss of the Unit 150013 (black) bus. The 500 KV red i
and black busses serve as common points of connection between the other 500 KV j
switchyard components and the 500 KV transmission system (offsite power). These buses also serve as the connection point between the 500 KV switchyard and the 13.8 KV system via the plant service transformers (black bus to P-13000-1 and red bus to P-13000-2). The P-13000-1 and P-13000-2 buses in turn supply power to the sites' 4 KV vital buses and
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reactor coolant pump 13.8 KV buses.
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Unit 2 operators were in the process of diluting boron concentration to criticality following a refueling outage when the loss of power occurred. The Unit 2 reactor tripped on reactor coolant system low flow when power to all reactor coolant pumps (RCPs) was lost. Unit I was at full power at the time of the trip. All emergency diesel generators (EDGs) responded as designed. The 21 EDG automatically started and supplied 24 4kV vital bus, and 12 EDG automatically started and was aligned to the 14 4kV vital bus by operators. The 11 EDG did j
not start since the buses it supplies did not lose power, but it was available. The NRC was informed of the event in accordance with 10 CFR 50.73.
Unit 2 equipment responded as expected to the trip. Impact on the primary plant was minimal since there was no power history. Power to the RCPs was restored via the black bus, and reactor flow was reinitiated at 10:21 a.m. At 1:05 p.m., the red bus was restored, the site electrical lineup was returned to normal, and BG&E exited the Unusual Event.
There were no actual safety consequences to the trip. Following BG&E's post trip review, unit startup testing was recommence.
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Unit 1 equipment responded as expected during the event with the following exceptions:
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The 12 saltwater pump suffered a failure of its lower guide bearing at 9:35 a.m. The
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pump was secured, and another available pump was placed in service. BG&E's post
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trip investigation did not uncover any evidence linking the bearing failure to the plant transient.
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Both steam generator feed pumps tripped on high discharge pressure following the Unit 1 trip. This condition, which has occasionally occurred on previous unit trips,
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has been recognized as a degraded condition by BG&E. A major modification to install a new feedwater control system that is designed to correct the condition is planned for the 1994 Unit I refueling outage. The modification was installed on Unit 2 during the recently completed outage.
There were no safety consequences to the trip. Following BG&E's post trip review and l
repair of some minor outstanding items, a unit startup was commenced. An automatic reactor trip occurred at approximately 16% power during the startup on June 11. The automatic trip is discussed in section 2.2.b below.
Inspectors were in the control room at the time of the loss of the red bus and monitored recovery actions. Operators responded professionally and deliberately to stabilize the units in a safe condition. Recovery actions were rigorously controlled in accordance with applicable emergency operating procedures. The on-shift crew had been augmented with additional operators prior to the event, and additional experienced personnel were immediately available for event investigation and recovery. The General Supervisor - Nuclear Plant Operations was in the control room at the time of the event and immediately began evaluation of the
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plant conditions and oversight of shift recovery actions. Other senior operations and plant management immediately responded to the control room. After completing the emergency actions for the partial loss of offsite power, management conservatively elected to remain in the Unusual Event until the site electrical lineup was restored to normal. Inspectors attended the post trip reviews and concluded that they were careful and complete.
The Plant General Manager established a Significant Incident Finding Team (SIFT) to determine the root causes, initiate corrective actions, and formulate recommendations to prevent recurrence of the event. Inspectors discussed the event with the SIFT and attended Plant Operations and Safety Review Committee (POSRC) discussions of the SIFT findings.
Inspectors found that the SIFI' conducted an exceptionally thorough investigation; however, their final report was not yet complete at the end of the inspection period.
Preliminary investigation by BG&E has concluded that the red bus was lost when a protective
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relay on a tie breaker between the Unit 2 main generator and the red bus actuated. The j
breaker is located in the control house of the switchyard at Calvert Cliffs. The event occurred while BG&E was performing work in the control house on a new 500 kV offsite line; however, the preliminary investigation did not establish a connection between the work
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.5 in progress and the suspect relay. There were no Lown relay problems or any troubleshooting in progress when the trip occurred. The relay opened the remaining feeder breakers to the red bus and deenergized it. As part of the pre-startup corrective actions, the comparable relay on Unit I was verified to be functioning properly and the suspect relay was replaced on Umt 2. BG&E believed that the most likely cause of the relay actuation was induced vibration; however, their investigation was continuing into the root causes and any generic implications, including the planning, control, and communication of work in the
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inspectors discussed the decision to trip Unit I with BG&E management and operations personnel. Based on a quick scan of control room indications, the Unit I control room supervisor (CRS) believed that a total loss of offsite power was in progress; in actuality, only the red bus was lost. The CRS ordered the reactor to be manually tripped in anticipation of
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an automatic shutdown. The operators' actions following the manual trip were excellent,
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demonstrating decisive control of the plant. Based upon the CRS's diagnosis of a loss of
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offsite power, inspectors concurred that the decision to trip was prudent and conservative in i
ensuring nuclear safety. BG&E is evaluating the scenario to determine if simulator and
operator training can be enhanced as a result oflessons learned from the event.
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Based on direct observation of the event and subsequent review, the inspectors concluded that operator response to the event was satisfactory and that BG&E's response and investigation were prompt and comprehensive.
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b.
Automatic Trip of Unit 1 on June 11
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An automatic reactor trip of Unit 1 occurred on June 11 during restart following the manual trip on June 10. With reactor power at approximately 16% and being raised, a high water level occurred in the 12C low pressure feedwater heater (RVH). This resulted in a main turbine protective trip and subsequent reactor trip on loss of load.
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The unit responded as expected to the trip. Operators reacted promptly and in accordance with applicable emergency opemting procedures. Senior operations managers were in and about the control room at the time of the trip monitoring the startup. Inspectors responded to the control room and monitored recovery actions. Initial investigation revealed that the RVH high level condition was a consequence of the high level dump valves being shut. The low pressure RVH high level dump (HLD) valves should have been open during the startup.
The NRC was informed of the trip in accordance with 10 CFR 50.73.
The turbine is protected from overspeed damage by a RVH high level trip. When the plant is at low power level, RVH pressures fluctuate with steam flow changes. As RVH pressure changes, liquid flashes to steam in the RVH and causes the float level in the RVH to chatter. To preclude an inadvertent turbine trip signal generated by pressure surges from
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flashing liquid, the FWH HLD valves are left open during plant startup. They are then shut later at high power. The FWH HLD valves are controlled by handswitches in the control
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room.
The Plant General Manager established a Significant Incident Finding Team (SIFT) to determine the root causes, initiate corrective actions, and formulate recommendatians to i
prevent recurrence of the event. The SIFT has conducted an investigation into the trip, but their final report was not completed at the end of the inspection period.
Preliminary investigation by BG&E and independent review by the inspectors indiccted that there were several contributing factors that led to the trip:
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Operators responded to the manual reactor trip on June 10 in accordance with emergency operating procedure (EOP) 0, " Post Trip Immediate Actions," and EOP-1,
" Reactor Trip," as required. Since no abnormalities from the trip required further unit cooldown, operators then entered operating procedure (OP) 2, " Plant Startup from Hot Standby to Minimum Load," to recover the plant. Under normal
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conditions, during a plant shutdown from power in accordance with OP-3, " Normal
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Power Operation," operators would be required to open the low pressure FWH HLD
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valves at 30% power. The valves would then be open for a subsequent plant startup.
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However, the valves were not referenced in EOP-0, EOP-1, or OP-2, until the plant reached high power.
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OP-2 directed the operators for plant startup to complete the initial conditions for turbine startup per operating instruction (OI) 43A, " Main Turbine and Generator / Exciter Operation." OI-43A directed the operators to align the FWH vents
and drains per OI-8B, "Feedwater Heater Vents and Drains." The startup section of l
OI-8B did not reference the HLD. valves. They were only referenced in Attachment 1 to OI-8B, the system valve lineup, which ider.tified the startup position of the HLD valves as open.
Operators only checked the startup section of OI-8B. They did not check the Attachment I lineup, as that was not the expected practice. Following a trip, operations management expected operators to question which valve positions were changed from their normal operating position. Operators were expected to check only those valves they suspect are not controlled by other methods and are not expected to check the complete valve lineups.
As a result, inadequate procedures and inadequate control of the HLD valves was a contributing factor to the trip.
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The senior reactor operator dedicated to the unit startup and the reactor operator i
recognized that the FWH HLD valves were shut when they checked the initial conditions for startup. They briefly discussed the issue, but believed that a later step (
in the startup procedures would open the valves.. They did not pursue the question to
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resolution.
A control room operator later cycled the HLD valves from shut to open to shut as part of the OP-2 startup checklist. He believed that maintenance in progress at the
time on the FWH relief valves required the valves to remain shut. He did not pursue the question to resolution.
i A new crew came on shift after reactor criticality was achieved to continue the
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startup. The position of the HLD valves was not discussed during turnover and was not noted by th: oncoming crew.
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As a result, lack of a questioning attitude by operators was a contributing factor to the q
trip.
There were no safety consequences to the trip. Inspectors attended the post trip review and
determined that it was satisfactory. Changes were implemented prior to startup to correct the procedural deficiencies which contributed to the event. Preliminary lessons learned were
promulgated to operators. The design of the FWH alarm circuits was evaluated and found to
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be appropriate for their intended function. In addition, BG&E intends to troubleshoot the q
alarm circuits to confirm that they are operating as designed. BG&E's investigation is continuing into the root causes of the event and any generic implications. A Licensee Event Report was being prepared as the period ended. Inspectors concluded that BG&E's response to the event was appropriate.
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Notwithstanding BG&E's corrective actions, as documented above, TS 6.8.1 requires that
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written procedures shall be established, implemented, and maintained covering the applicable l
procedures recommended in Appendix A of Regulatory Guide (RG) 1.33, Revision 2,
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February 1978. RG 1.33 requires a procedure for turbine startup and synchronization of i
generator. OI-43A was inadequate in that it failed to provide sufficient guidance on the I
required position of the FWH HLD valves for turbine startup, which contributed to the unit trip. This was a violation of TS 6.8.1. The violation was not cited because the criteria for discretion specified in Section VII.B of the NRC Enforcement Policy were satisfied.
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Automatic Trip of Unit 2 on June 25 i
i On June 25,1993, a Unit 2 automatic trip occurred from approximately three percent power j
due to low water level in 21 steam generator. The control room operators were unable to i
control steam generator level using the recently installed digital feedwater control system.
j The NRC's review of this event will be documented in NRC Special Inspection Report 50-317 and 318/92-2 o
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Inadequate Restoration of 12 Service Water Heat Exchanger on July 1 Following Maintenance On July 1, while restoring the 12 service water (SRW) heat exchanger to service following maintenance, a low head tank level and low SRW pressure condition occurred in the only operable SRW train. Operators filled the heat exchanger too rapidly for the makeup system to compensate. NRC review of this event will be documented in NRC Special Inspection Report 50-317 and 318/92-23.
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3.0 RADIOLOGICAL CONTROLS During tours of the accessible plant areas, the inspectors observed the implementation of selected portions of the licensee's Radiological Controls Program. The utilization and
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compliance with special work permits (SWPs) were reviewed to ensure detailed descriptions l
of radiological conditions were provided and that personnel adhered to SWP requirements.
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The inspectors observed that controls of access to various radiologically controlled areas and
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use of personnel monitors and frisking methods upon exit from these areas were adequate.
Posting and control of radiation areas, contaminated areas and hot spots, and labelling and control of containers holding radioactive materials were verified to be in accordance with licensee procedures.
Health Physics technician control and monitoring of these activities were determined to be good. Overall, an excellent level of performance vvas observed.
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MAINTENANCE AND SURVEILLANCE 4.1 Maintenance Observation The inspector reviewed selected maintenance activities to assure that:
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the activity did not violate technical specification limiting conditions for operation and that redundant components were opemble;
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required approvals and releases had been obtained prior to commencing work; procedures used for the task were adequate and work was within the skills of the
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activities were accomplished by qualified personnel;
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where necessary, radiological and fire preventive controls were adequate and implemented;
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quality verification hold points were established where required and observed; and
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equipment was properly tested and returned to service.
The work observed was performed safely and in accordance with proper procedures.
Inspectors noted that an appropriate level of supervisory attention was given to the work depending on its priority and difficulty. Notable observations are included below for selected activities. Maintenance activities reviewed included:
MO 19206981 Replace anodes on 12 ECCS pump room air cooler
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MO 19207269 Inspect 12 ECCS pump room air cooler duplex strainer MO 19301855 Inspect 12 ECCS pump room air cooler
MO 19207265 Clean / bullet 12 SRWHX i
MO 19207286 Clean / bullet 12 CCHX
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t MO 19302162 Correct 12 EDG breaker annunciator circuit modification FCR 84-027 MO 19303176 CCI 117 troubleshooting of 1-RI-1752' drifting indication (Unit 1 main condenser off gas monitor)
n MO 19203634 Remove, test and reinstall 12 emergency diesel generator service water relief valve
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MO 19301841 Test 12 emergency diesel generator fuel injectors i
MO 19303354 Overhaul 13 component cooling water pump
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Inspectors monitored selected portions of the maintenance activities associated with the planned outage of the 12 saltwater header on June 30. The outage was part of BG&E's t
Quarterly System Schedule, which is an effort to consolidate maintenance associated with.
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LCOs in order to minimize the time that safety related equipment is out of service. In
. general, the 12 saltwater header outage was satisfactorily planned and executed.
4.2 Surveillance Observation The inspectors witnessed / reviewed selected surveillance tests to determine whether properly
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.
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The surveillance testing was performed safely and in accordance with proper procedures.
Inspectors noted that an appropriate level of supervisory attention was given to the testing i
depending on its sensitivity and difficulty. Notable observations are included below for
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selected activities. The following surveillance testing activities were reviewed:
STP O-5A-2 AFW System Quarterly Test
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STP M-3-2 Main Steam Safety Valve Testing
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ETP 90-49R RCP 21 A and 21B Test Run
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STP O-73H-2 AFW Pumps I2rge Flow Testing 4.3 Inadvertent Protective System Actuation On June 8, while in Mode 3 and conducting STP O-73H-2 on the 21 AFW pump, a reactor protection system (RPS) and auxiliary feedwater actuation system (AFAS) actuation occurred on Unit 2 when the differential pressure between steam generators rose to greater than 115 pounds per square inch (psi).
With the main steam isolation valves shut, the 21 AFW pump was being driven by steam from the 21 steam generator and was feeding both steam generators, in accordance with the STP. When 21 steam generator pressure fell to greater than 115 psi below the 22 steam
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generator pressure, an asymmetric steam generator trip signal was generated in the RPS. All of the reactor trip circuit breakers opened; however, the control element assemblies (CEAs)
were already fully inserted. No rod testing was in progress. AFW flow to 21 steam generator was also isolated by an AFAS Block signal, which was generated because the differential pressure signal indicated a steam generator fault to AFAS. The plant responded as designed to the RPS and AFAS actuation.
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There were no safety consequences to the trip. After evaluation by BG&E, the systems were reset and the STP was performed satisfactorily. Since the actuation was unanticipated, a four hour report was made to the NRC as required by 10 CFR 50.72. An issue report was
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initiated to document the event and track corrective action to prevent recurrence, and a
Licensee Event Report was being prepared by BG&E as the inspection period ended.
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Inspectors reviewed the STP and discussed the event with operators and the General Supervisor - Nuclear Plant Operations (GS-NPO). Several factors appear to have contributed to the event, including (1) lack of realization by the operators that the test conditions would
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create the potential for excessive steam generator differential pressure to develop, (2) lack of
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procedural cautions that would alert the operators to the potential condition, and (3) lack of a pretrip alarm which would have given the operators warning of the impending condition.
There was a pretrip alarm for the trip; however, it was inoperable at the time of the STP for corrective maintenanc.
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BG&E's final corrective actions are awaiting completion of their investigation. The i
l preliminary intention of BG&E is to change the initial condition of the STP to draw steam
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from both steam generators rather than only one, and add appropriate cautions to the STP.
The event was promulgated to operators via the GS-NPO Notes and Instructions. Inspectors concluded that BG&E's response was appropriate.
4.4 Technical Specification 3.0.3 Entry On June 30,1993, during post maintenance testing of the 13 component cooling water (CCW) pump, BG&E operations personnel discovered the CCW outlet valve from the 11
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shutdown cooling heat exchanger failed closed. The actuator arm had separated from the valve stem, apparently after the pivot locking plate had fractured and fallen out. BG&E'
declared the "A" header of CCW inoperable. Since the "B" header of CCW was also inoperable due to an associated service water header outage, BG&E entered Technical Specification (TS) 3.0.3 at 2:00 p.m. The shutdown cooling heat exchangers, cooled by CCW, were required to provide post-accident containment spray cooling. The inspectors l
reviewed BG&E's actions concerning the TS 3.0.3 entry and valve repair / investigation and
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discussed the operability determinations wit) engineering personnel.
Repairs were completed, and the valve was declared operable at 2:37 p.m. following successful post maintenance testing. BG&E made the appropriate non-emergency. report to the NRC in accordance with 10 CFR 50.72. A review of the three other similar valves in the CCW system of both units showed that one pivot locking plate was intact, one was cracked, and the third was broken in half. A maintenance order was written to repair the broken plate; however, BG&E concluded that the valve was still operable. Their conclusion was based on engineering judgment, physical examination, and cycling of the valve. Similar valves / actuators in the service water system were inspected and no deficiencies were found.
At the end of the period, BG&E was continuing their investigation into possible generic implications and was in contact the valve vendor for assistance.
The entry into TS 3.0.3 and notification to the NRC were prompt and appropriate. Repairs to Unit i valve CV-3828 returned the valve and actuator to its design condition. BG&E's operability determination for Unit 2 valve CV-3828 was appropriate. A maintenance order was written to replace the cracked pivot plate. Inspectors assessed that BG&E's overall actions in response to the issue were appropriate.
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The inspectors toured the onsite emergency response facilities to verify that these facilities were in an adequate state of readiness for event response. The inspectors discussed program implementation with the applicable personnel. The resident inspectors had no noteworthy findings in this are.-
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A site emergency preparedness drill was held on June 17. The scenario included a letdown line break, loss of coolant accident, and high pressure safety injection system failure. There were.no outside agencies involved in the drill.
BG&E appropriately declared an Unusual Event on June 10 when they implemented EOP-2,
%ss of Offsite Power," following a loss of the Unit 2 500kV (red) bus. The event is
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documented in section 2.2 above.
6.0 SECURITY t
During routine inspection tours, the inspectors observed implementation of portions of the
security plan. Areas observed included access point search equipment operation, condition of
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physical barriers, site access control, security force staffing, and response to system alarms and degraded conditions. These areas of program implementation were determined to be l
adequate. No unacceptable conditions were identified.
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7.0 ENGINEERING AND TECHNICAL SUPPORT l
7.1 Appendix R Fire Issues Undate l
In October 1992, during a ventilation systems design basis reconstitution effort, BG&E
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discovered that a postulated fire in the room containing the control room heating, ventilation
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and air conditioning (HVAC) units could potentially prevent the safe shutdown of both units.
The loss of the HVAC units would result in the loss of all cooling to the Unit I and Unit 2 vital bus inverters and distribution panels in the cable spreading rooms. - This issue was documented in NRC Inspection Report 50-317 and 318/92-27. Unresolved Item 50-317 and 318/92-27-02 was opened pending further BG&E and NRC evaluation.
On May 25,1993, BG&E identified nine other plant areas where a postulated Appendix R fire could result in the simultaneous loss of both trains of control room HVAC. BG&E found that inadequate Appendix R separation existed between control room HVAC electrical cabling and/or ventilation ducting in these ares. The plant areas where inadequate separation existed were as follows:
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Unit 1 Cable Spreading Room
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Cable Chase IC Control Room
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Unit 1 West Electrical Penetration Room
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Spent Fuel Pool Area Ventilation Equipment Room
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Unit 1 Main Plant Exhaust Ventilation Equipment Room
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Control Room HVAC Room
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Auxiliary Building roof in the vicinity of the control room HVAC coolers
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Unit 1 Containment Access Area l
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The inspectors conducted an independent review of BG&E's actions in response to this discovery.
The inspectors found that BG&E had promptly performed and documented an operability determination. BG&E concluded that the control room HVAC units remained operable with the implementation of several compensatory measures. These included limiting hot work, minimizing transient combustibles and the use of fire watch patrols in some areas. The inspectors conducted a review of BG&E's fire watch log and verified that the required patrols were performed. They also performed walkdowns of the affected areas and did not
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identify any significant fire hazards. The inspectors concluded that BG&E's compensatory
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measures were adequate.
BG&E informed the inspectors that long term corrective actions were still under development. This issue remains open pending the completion and evaluation of these actions.
7.2 Unit 1 Shutdown Due to High Containment Temnerature In June 1993, operators noted that the Unit I containment average air temperature was increasing above the expected value for the seasonal air and water temperatures. During a containment tour, BG&E discovered that a coating of boric acid powder had obstructed the air flow on all four containment air coolers (CACs) such that their performance had degraded to about one-third normal capacity. A BG&E engineering evaluation determined that the
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CACs were still operable. However, on June 21, the average air temperature peaked at 119.5 F. The TS maximum allowable temperature was 120*F, and efforts to reduce containment temperature were unsuccessful. On June 23, BG&E shutdown Unit 1 to further evaluate and correct the problem.
Containment cooling is provided by the four CACs, which also serve as a redundant system
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for controlling containment temperature and pressure during accident scenarios. The inspectors conducted a detailed review of this problem. The review consisted of interviews with engineering and management personnel and review of engineering documents, photographs and videotapes.
BG&E traced the source of the boric acid to the in-core instrumentation (ICI) flanges, which are mounted in the reactor vessel head. A boric acid buildup was noted on seven of the eight flanges. Close inspection revealed that the leakage came from the castle nut around the instrument stalk itself, not the ICI flange proper. BG&E engineering concluded that, as the borated primary coolant leaked out, it flashed to steam. Some boric acid accumulated around the leakage exit sites. The remainder was entrained in containment air flows and eventually plated out on the surfaces of the CAC cooling coils, which were cooler and damper than other areas in the containment. BG&E concluded that the root cause of the leakage was the
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failure of the gasket in the ICI stalk assembly due to insufficient compression of the gasket.
This was the same cause attributed to a nearly identical problem with leaking ICI flanges found in Unit 2 during its recent refueling outage.
BG&E performed followup evaluations to confirm the initial CAC operability determination.
While several long-term accident scenarios were still under evaluation at the end of the period, BG&E's preliminary results indicated that even with,CAC ali flow completely
blocked, the scrubbing action of the accident (main steam line break, rupture of the reactor coolant system hot or cold leg) would return cooler performance to an acceptable level prior to the fans being required for accident mitigation. BG&E also found that the boric acid powder had no detrimental affect on other safety-related components in the containment, j
since almost all of the powder was concentrated in the CACs.
Following successful cleaning of the CACs, engineering personnel recommended to BG&E
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management that Unit 1 be returned to service and that the ICI gaskets be replaced during i
the next refueling outage, currently scheduled for early 1994. As an interim compensatory measure, BG&E implemented a CAC performance monitoring program. The inspectors were informed that if CAC performance was found to be degraded, the cooler could be j
cleaned while the plant operated. After review by the Plant Operations and Safety Review Committee (POSRC) and approval by the Plant General Manager, Unit I was restarted on June 28 and reached full power on June 29.
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The inspectors concluded that BG&E's determination of operability of the CACs was thorough, rigorous, and supported the conclusion that the coolers could perform their
designed functions for short-term accident scenarios (several long-term scenarios are not yet complete). The evaluation of possible options for the repair of the leaking ICI flanges in j
Unit I was comprehensive, used good operability judgment, and was accompanied by a j
strong questioning attitude and nuclear safety perspective. The monitoring program
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developed to assess CAC performance and provide early detection of degradation was
satisfactory. Based on the above, inspectors concluded that BG&E's decision to restart Unit I without repairing the ICI flange leaks had no adverse safety consequences.
l 8.0 SAFETY ASSESSMENT AND QUALITY VERIFICATION 8.1 Plant Operations and Safety Review Committee The inspectors attended several Plant Operations and Safety Review Committee (POSRC)
meetings. TS 6.5 requirements for required member attendance were verified. The meeting agendas included procedural changes, proposed changes to the TS, Facility Change Requests, and minutes from previous meetings. Items for which adequate review time was not
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available were postponed to allow committee members time for further review and comment.
Inspectors noted that POSRC review of events occurring this period was comprehensive and probing. Overall, the level of review and member participation was excellent in fulfilling the POSRC responsibilities. No unacceptable conditions were identified.
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8.2 Review of Written Reports The inspector reviewed LERs and other reports submitted to the NRC to verify that the details of the events were clearly reported, including accuracy of the description of cause and adequacy of corrective action. The inspector determined whether further information was required from the licensee, whether generic implications were indicated, and whether the event warranted onsite followup. The following LER was reviewed with respect to the requirements of 10 CFR 50.73 and the guidance provided in NUREG 1022:
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Units 1 and 2:
,93-002 Revision 1 Missed Surveillance Requirements Due to Software Manual Error l
The LER revision was submitted to report the cause of the event, which was still under f
investigation when the original LER was submitted, and to update the analysis of event and
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corrective actions. The inspectors determined that it was an accurate supplement to the
original LER.
8.3 Comoletion of Unit 2 Refueling Outage During this period, BG&E completed the Unit 2 refueling outage begun on February 19. In
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addition to refueling, some of the major tasks comprising the outage included:
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main turbine overhaul
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steam generator eddy current testing
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containment air cooler cleaning j
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two emergency diesel generator overhauls
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refueling water tank leak repair
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main steam safety valves overhaul
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dual saltwater header outage
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main steam isolation valves overhaul
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a RCP motor replacement j
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main turbine governor and throttle valve overhaul
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turbine bypass valves replacement
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approximately 50 major modifications and over 2200 maintenance orders.
The outage was originally scheduled for 105 days. The actual outage was 113 days, partly l
because the time required to perform equipment testing following outage maintenance and systems restoration exceeded planning estimates. The outage site radiation exposure goal was not met, primarily due to additional repair work required following the discovery of boric acid leakage from the in-core instrumentation flanges; however, the individual exposure goal and personnel contamination incident goals were met.
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BG&E clearly focused on shutdown safety during the outage. One result was that no
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shutdown safety events occurred. Some evidence of BG&E's focus included:
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Calvert Cliffs Instruction (CCI) 314, " Conduct of Lower Mode Operations," was revised based on experience gained from the 1992 outage.
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Enhancements of shutdown safety measures were implemented as a result of BG&E's self assessment following the 1992 outage.
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Specific attention was given by outage and operations management to maximize the availability of electrical power supplies, reactor coolant system inventory control,
safety related systems for shutdown cooling, containment closure, and essential
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equipment required for safety. This included a review of equipment and plant status
at each shift turnover, j
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Areas and equipment critical to shutdown safety were marked by special barricades
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and signs to prevent entry without the shift supervisor's permission.
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Temporary diesel generators were installed to provide backup electrical power during
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high risk evolutions.
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A drill was held to verify power supplies and operator preparedness to implement containment closure on short notice.
j Based on direct observation, inspectors concluded that BG&E effectively implemented
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shutdown safety measures during the outage.
Inspectors attended the Startup Review Board (SURB) meetings conducted 'to support the
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heatup and startup of Unit 2. The SURB was composed of site managers and involved a
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vigorous questioning of the entire site organization to determine the readiness of Unit 2 to
come out of the refueling outage. The board functioned effectively to overview the startup
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efforts and focus actions toward safety concerns.
8.4 Plant Shutdown Decisions On two occasions during the period, BG&E conservatively elected to shutdown the units.
BG&E shutdown Unit 2 to repair a small non-pressure boundary reactor coolant system leak from a vent plug on 2-PDT-111B, a reactor coolant loop flow transmitter. BG&E also -
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shutdown Unit 1 to clean the containment air coolers following identification of an abnormal trend in containment temperature (see section 7.2). The inspectors assessed BG&E's decisions to shutdown the units as prudent and indicative of a strong safety perspective.
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9.0 FOLLOWUP OF PREVIOUS INSPECTION FINDINGS
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i Licensee actions taken in response to open items and findings from previous inspections were
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reviewed. The inspectors determined if corrective actions were appropriate and thorough and j
previous concerns were resolved. Items were closed where the inspectors determined that.
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corrective actions would prevent recurrence. Those items for which additional licensee i
action was warranted remained open. The folicwmg item was reviewed.
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9.1 (Undate) Unresolved Item 50-317 and 318/92-27-02 j
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This issue involved inadequate Appendix R separation between the control room heating,
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ventilation and air conditioning (h AC) units. BG&E discovered other plant areas where a postulated Appendix R fire could result in the simultaneous loss of both trains of control room HVAC. Review of this issue is documented in section 7.1.
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F 10.0 MANAGEMENT MEETING
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During this inspection, periodic meetings were held with station management to discuss
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' inspection observations and findings. At the close of the inspection period, an exit meeting
.!l was held to summarize the conclusions of the inspection. No written material was given to the licensee and no proprietary information related to this inspection was identified.
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10.1-Preliminar_v inspection Findines I
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A non-cited violation was identified with regard to procedural control of the position oflow -
j pressure feedwater heater high level dump valves during turbine startup. The issue is,
H documented in section 2.2.
10.2 Attendance at Manacement Meetines Conducted b.y Reeion Based Inspectors
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i Inspection Reporting Date Subiect Report No.
Inspector 6/4/1993 EDG Project 50-317/93-14 S. Chaudhary 50-318/93-14 6/18/1993 Eng, rech Sup 50-317/93-17 A. Lohmeier 50-318/93-17 6/25/1993 Procurement 50-317/93-18 A. Finkel 50-318/93-18
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7/2/1993 EDSFI Followup 50-317/93-21 R. Bhatia
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50-318/93-21 7/2/1993 Security 50-317/93-19 R. Albert 50-318/93-19
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