IR 05000445/1998002
| ML20217F615 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 04/24/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20217F577 | List: |
| References | |
| 50-445-98-02, 50-445-98-2, 50-446-98-02, 50-446-98-2, NUDOCS 9804280204 | |
| Download: ML20217F615 (25) | |
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ENCLOSURE 2 U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket Nos.:
50-445 50-446 l
License Nos.:
NPF-87 NPF-89 Report No.:
50-445/98-02 50-446/98-02 Licensee:
TU Electric I
Facility:
Comanche Peak Steam Electric Station, Units 1 and 2 Location:
February 15 through March 28,1998
Inspector (s):
Anthony T. Gody, Jr., Senior Resident inspector l
Harry A. Freeman, Resident inspector Thomas R. Meadows, License Examiner Approved By:
Joseph I. Tapia, Chief, Branch A Division of Reactor Projects I
Attachment:
Supplemental lnformation
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9804280204 9804p4
{DR ADOCK 05000445 PDR
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EXECUTIVE SUMMARY Comanche Peak Steam Electric Station, Units 1 and 2 NRC inspection Report 50-445/; 50-446/
The resident inspection included aspects of licensee operations, engineering, maintenance, and
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plant support. The report covers a 6-week period of resident inspection.
Ooerations i
J The conduct of operations continued to be characterized by excellent operator
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performance during evolutions and transients. The recent plant shutdown using a new process was wellimplemented, inspectors observed close monitoring by the reactor
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operators and effective management by shift supervision.
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Maintenance The licensee thoroughly addressed the fuel handling errors during the previous outage.
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Corrective actions included: defining each position's responsibilities, improving communications, and improving fuel handling equipment performance.
The administrative procedure for control of switchyard activities was not adequate to l
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prevent the inadvertent actuation of safety systems during a normal shutdown for refueling and resulted in an inadvertent boration. This was a 10 CFR Part 50, Appendix B, Criterion V violation.
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While performing reactor trip breaker response time testing, technicians failed to follow q
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the procedure in that the wrong logic selector switch was repositioned during the test and the breaker failed to trip when tested. The licensee stopped the test and corrected the mistake.
While the unit was in Mode 4, a contract technician racked out the Train A source range
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detector during a time when the Train B detector was out of service.
The licensee exceeded the procedural limit for hoist pretension during new fuel receipt.
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Investigation by the licensee revealed that this problem involved long standing work control problems; however, the closed deficiency resolution did not reflect any of the identified issues. This was a Technical Specification 6.8.1 violation for failure to follow procedures.
Enginetting
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The licensee failed to consider the affect that significantly increased starting frequencies of the safety injection pumps had on their equipment qualification design bases in their corrective actions. The equipment qualification design bases for the pumps assumed
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two start cycles per month (960 total) over the 40 year life of the plant. The inspectors estimated that during Unit 1, Cycle 6, each Si pump was started about 560 times. This was a 10 CFR Part 50, Appendix B, Criterion XVI violation for inadequate corrective action.
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-3-Plant Suonort The licensee's removal of locks from the containment personnel airlock doors was a
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violation of Technical Specification 6.12.2. Upon notification, the locks were immediately replaced. The locks were absent for three days.
Unsecured bookshelves could have blocked access to the technical support center
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during a seismic event. The bookshelves were immediately relocated to another location.
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Biport Details i
Summary of Plant Status
I Unit 1 Unit 1 began the report period at 100 percent power. On March 20, the licensee commenced a downpower for the sixth refueling outage. Following a cooldown and a brief period of reduced inventory operations, the reactor vessel head was removed on March 28. At the end of the report period, fuel assemblies were being removed from the reactor vessel and placed in the spent fuel pool.
Unit 2 Unit 2 began the report period at 100 percent power. On February 25, reactor power was reduced to 43 percent following a lightning-induced turbine runback during a severe thunderstorm. Power was restored to 100 percent on February 27. On March 7, reactor power j
was again reduced to approximately 62 percent following a lightning-induced turbine runback during another severe thunderstorm. Power was restored to 100 percent on March 8. Later, on March 8, a main turbine and subsequent reactor trip occurred following a loss of the turbine plant cooling water system when an automatic makeup system failed during a system feed and bleed for chemistry control. The unit was restarted on March 9 and was restored to 100 percent power on March 10 where it remained at the end of the report period.
I. Operations
Conduct of Operations 01.1 General The conduct of operations observed was characterized by good command, control, and communications with some isolated exceptions noted below. Overall, the inspectors observed operators use good self-verification techniques and appropriately use operator aids. One notable miscommunication was identified by the inspectors during the report period and is discussed in Section 01.4 below.
01.2 Unit 2 Liahtnina-Induced Turbine Runbacks a.
Insoection Scooe (92901. 37551)
The inspector reviewed the plant response to severe thunderstorms on February 25 and March 7 and the subsequent licensee corrective actions.
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Observations and Findinas j
l On February 25, while operating at 100 percent power during severe thunderstorms, Unit 2 experienced two automatic turbine load reductions (runbacks). The first turbine runback resulted in an automatic reactor power reduction and rnanual stabilization from fullload to 90 percent. The second turbine runback resulted in a reduction and manual i
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-2-stabilization at 56 percent power. These transients subsequently resulted in a reactor negative axial flux difference greater than the limits specified in plant Technical Specification 3.2.1. This required operators to reduce reactor power to less than 50 percent until the axial flux difference penalty minute accumulation was less than
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60 minutes for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. On March 7, while operating at 100 percent power during
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severe thunderstorms, Unit 2 again experienced an automatic turbine runback.
Following manual operator actions to minimize the impact on the plant and prevent exceeding the reactor negative axial flux difference limits, the plant was stabilized at about 62 percent power.
Minor waterhammers were experienced during and after both runbacks. A review of the plant logs and discussions with operators revealed that operators responded
appropriately by modifying plant conditions to prevent further waterhammers following
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the runbacks. Several balance-of-plant relief valves lifted and failed to re-seat. This is a I
common occurrence following a significant transient with two-phase flow through relief valves. The relief valves were immediately isolated and operators were appropriately stationed at the manualisolation valves for equipment protection. One notable observation was that very little damage occurred to balance-of-plant equipment during the transient, which indicates a significant improvement from previous transients. The
inspector attributed this to good operator response and modifications to the heater drain system.
The licensee's investigation revealed no distinct root cause for the lightning-induced runbacks. Nevertheless, the licensee believed that the runbacks were most likely caused by lightning-induced transients in temperature instruments associated with the over-temperature delta-temperature runback circuitry. The inspector questioned the j
system engineer on the results of troubleshooting, which showed that the cold leg resistance temperature detector insuiation resistance on Channels 2 and 4 was low (13 and 28 meg-ohms, respectively) but within the acceptance criteria. Low cable insulation resistance could result in induced currents on cabling between the containment and auxiliary building during lightning strikes. These degraded cable resistance measurements were consistent with measurements made following previous lightning-induced transients and were dispositioned by the licensee as acceptable. The l
inspector agreed with the licensee's determination that even though the cable insulation resistance was lower than others, it was still within acceptance criteria.
To minimize the potential for lightning-induced plant transients, the licensee implemented a change to the abnormal operating procedure for severe weather. The procedure
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i change instructs operators to remove the automatic runback fuses whenever a severe thunderstorm waming is issued. Since implementing the procedure change, several severe thunderstorms with lightning have occurred and no transients were induced. The inspector agreed with the licensee's determination that the turbine runback circuitry provided a non-safety related equipment protective function and that no postulated accidents relied on that circuit function. Therefore, the licensee's decision to remove this protective function during severe thunderstorms was allowed by regulations and was effective in preventing plant transient ?
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Insoection Scoce (92901. 93702)
The inspector responded to the site and reviewed the events leading up to and following a turbine and reactor trip which occurred on March 8.
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Observations and Findinas
' Discussion Following the plant transients discussed in Section O1.1 above, Unit 2 was restored to 100 percent power on March 8. At 1609 on March 8 a turbine plant cooling water system feed and bleed was started to reduce system conductivity following a biocide addition during the previous week.
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The oncoming operating crew took the watch at about 1800 on March 8. Each watch station appropriately discussed the ongoing feed and bleed evolution and all
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watchstanders noted that the evolution was going smoothly. No compensatory measures or special instructions were established for this evolution. The Unit 2 unit supervisor stated that he had noted early in the watch that they had received a turbine j
plant cooling water system head tank low level alarm, and that he physically verified that the makeup valve opened and that the head tank level was increasing. The unit supervisor began preparations for a fairly comprehensive surveillance test planned later during the shift. Since a motor that had been recently replaced on one of the containment fan ccoler units was going to be started during the slave relay test, a containment entry was also planned to obtain vibration data and observe the startup.
The unit supervisor indicated that during preparations for these activities, an additional I
head tank low level alarm (this alarm occurred about 2-hours prior to the trip) had been received. The unit supervisor observed that the reactor operator responded to the alarm
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and verified that the makeup valve had opened, and that the head tank level was increasing. The unit supervisor acknowledged the reactor operator and physically verified from the supervisor's desk that the makeup valve had opened, but did not look at head tank level. The alarm demin;; several minutes later, which implied that the head tank level had increased.
During the pre-evolutionary brief for the surveillance an'; the containment entry, a turbine plant cooling water system pump trip and subsequent ;oss of turbine plant cooling water occurred. Personnel involved in the brief included a reactor operator, the unit supervisor, the shift manager, and other personnel involved in the surveillance and testing activities.
One reactor operator was monitoring the control boards at the time the turbine plant cooling water was lost. Head tank level was found below six percent and, since insufficient head was available to the turbine plant cooling water pumps, the standby pump did not star !
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-4-The unit supervisor immediately ordered the operator to manually open the makeup valve and head tank level immediately increased. Once head tank level was above six percent, the unit supervisor ordered the turbine plant cooling water pumps manually started. Not sure if the generator primary water temperatures would remain below the trip setpoint, the unit supervisor then announced, " prepare for a turbine and reactor trip."
The reactor operator then referenced the emergency operating procedures.
Subsequent to the unit supervisors announcement, a turbine trip on high main generator primary water temperature and a resultant reactor trip occurred. The plant responded as designed during the trip. All the auxiliary feedwater pumps started from the steam generator shrink associated with the rapid downpower. While implementing the emergency operating procedures, the reactor operator recommended securing the turbine-driven auxiliary feedwater pump to minimize the reactor coolant system cooldown. The unit supervisor reviewed steam generator levels on the plant computer, agreed with the reactor operators recommendation, and ordered the turbine-driven auxiliary feedwater pump secured. The reactor operator secured the turbine-driven auxiliary feedwater pump and it automatically restarted because the automatic start signal had not yet cleared. This resulted because more than one steam generator level was below 35 percent. Once three steam generator levels were clearly above 35 percent, the turbine-driven auxiliary feedwater pump was secured.
Observations The inspector responded to the site following the trip and noted that the plant had been properly stabilized in Mode 3. Plant management and system engineers had responded to the site and were in the process of reviewing plant data and performing system walk-downs. Few problems occurred as a result of the trip and recovery efforts were not complicated. The inspector focused on three aspects of the plant trip: (1) circumstances surrounding the loss of turbine plant cooling water, (2) automatic restart of the i
turbine-driven auxiliary feedwater pump, and (3) performance of the turbine-dnven
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auxiliary feedwater pump during the restart.
Findinas Through interviews, the inspector found that the unit supervisor and reactor operator
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conducting the turbine plant cooling water system feed and bleed evolution were attentive to their watchstations. The inspector could not determine if the pre-evolutionary l
brief being conducted at the time of the feed and bleed evolution contributed to the reactor operator not identifying the decreasing head tank level without an alarm. The inspector concluded that, short of placing a dedicated watchstander on the turbine plant cooling water system feed and bleed evolution, it was unreasonable to expect that the silent failure of the head tank makeup system could be identified by the reactor operator.
In response to the event, the licensee modified turbine plant cooling water system feed and bleed procedures to preclude this type of inadvertent loss of head tank level from occurring. The inspector reviewed the procedure change and concluded that the new
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feed and bleed would, indeed, prevent a loss of head tank level but could be significantly less efficient in maintaining turbine plant cooling water system chemistry.
The inspector found that the operators appropriately entered both abnormal and emergency operating procedures during the transient. The reactor operator's effort to minimize reactor coolant system cooldown and the potential for an unwanted safety injection actuation was appropriate. A discussion with the reactor operator revealed that he was very aware of reactor coolant system conditions throughout the transient. The reactor operator recalled steam generator levels, pressurizer levels, and reactor coolant system pressure with sufficient detail to indicate that he had been very attentive to the control boards. The inspector found that both the senior reactor operator and reactor operator verified that steam generator level indications were sufficient to secure the turbine-driven auxiliary feedwater pump. However, neither the senior reactor operator or reactor operator verified that the automatic start signal for the turbine driven auxiliary feedwater pump had cleared prior to securing the pump.
A seview of the turbine-driven auxiliary feedwater pump start data and a discussion with the system engineer revealed that the turbine came fairly close to the overspeed trip setpoint during the second start. Turbine speed exceeded 4600 revolutions per minute (RPM). wnile the overspeed trip is set at 4750 RPM, and the normal running speed is 4T.00 RPM. The inspector agreed with the system engineer's position that the inadverter.( automatic start actually demonstrated that the turbine governor valve was working well. During this type of automatic restart, with the turbine still rolling (before the hydraulic system is reset), the turbine govemor valve is fully open and doesn't begin to close until the turbine speed exceeds 4200 RPM.
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Conclusions The inspector concluded that events leading up to the trip of Unit 2 could have been prevented by enhancing the turbine plant cooling water system feed and bleed evolution.
Although both operators and supervision were attentive to their duties, a failure of the turbine plant cooling water makeup system was not identified until cooling pumps tripped.
Plant recovery efforts by the operating crew were timely but insufficient to prevent a turbine and unit trip. Although operators and supervision demonstrated the appropriate focus on preventing an inadvertent safety injection and were attentive to steam generator level indications, the turbine-driven auxiliary feedwater pump was secured too early. The conditions under which the automatic restart of the turbine-driven auxiliary feedwater pump occurred, demonstrated that the governor valve was operating well. Subsequent changes to the procedure for conducting a turbine plant cooling water system feed and bleed were effective in preventing similar events.
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-6-01.4 Unit 1 Midloco Ooerations Observations
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Insoection Scoce (71707)
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The inspector observed Unit 1 control room activities during reduced reactor coolant system inventory operations.
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Observations and Findinas The inspector observed that operators were attentive and aware of plant conditions and
or:goirig outage maintenance. Communications were generally good with consistent use of three-way communication techniques such as command, repeat back, and acknowledgment. One miscommunication was identified by the inspectorjust prior to entering reduced inventory operations. The reactor operator was asked by the inspector what reactor coolant system level indications were available and he responded that only the extended wide range instrument was available. The inspector then asked the senior reactor operator what level indications were available and he indicated that both the extended wide range and wide range level instruments were in service. After pointing out to the senior reactor operator that the reactor operator believed only one level instrument was available, the senior reactor operator informed the reactor operator that both level instruments were available. The inspector found that the senior reactor operator had not effectively communicated that the wide range level instrument was placed in service during the watch.
The inspectors confirmed that the operators were familiar with residual heat removal system pump vortex and cavitation limits. Operators were also aware of criticallimits such as the amount of time it would take for boiling to occur U cooling were lost. One notable observation was that senior reactor operators routinely quizzed reactor operators on system limits and their bases. The inspector found this to be a good practice.
Operator Knowledge and Performance 04.1 Resoonse to Failed Fuel Radiation Monitor Alarm a.
Insoection Scoce (71707)
The inspector observed operators respond to a Unit 2 failed fuel monitor alarm and questioned the unit supervisor on the bases for the alarm response procedure on February 27.
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Observations and Findinas The inspector observed operators respond to a Unit 2 failed fuel alarm which spiked above its alarm setpoint. The alarm occurred after restoration to 100 percent power following the plant transient discussed in Section 01.2 above. The inspector noted that the alarm immediately cleared and that operators implemented Procedure ABN 102,
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" Failed Fuel." The unit supervisor immediately contacted the chemistry department to take a sample of reactor coolant to ascertain if any fuel damage was evident. The results of the reactor coolant sample indicated that no fuel damage was present and that the failed fuel monitor spike was most likely a crud particle. This was verified by the inspector through the review of chemisiry logs.
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department. The unit supervisor understood why it was important to place particular attention to a failed fuel alarm after the transient from the day before.
04.2 Unit 1 Shutdown for Refuelino Outaae 6
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Insoection Scone (717075 l'
The inspector observed the licensee shutdown Unit i for entry into the sixth refueling outage. The inspector observed the evolution and evaluated procedural compliance,
command, control, and communications and determined if control room formality was '
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Observations and Findinas On March 20, the licensee shutdown Unit 1. The licensee decided to conduct this shutdown in a different manner. The licensee's plan was to place control rods in l
automatic, reduce the generator reference load on the controller, and initiate a slow i
boration to control axial flux difference. This process would allow operators better overview of plant parameters and worked well in the simulator. During previous
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shutdowns, operators manually controlled the rods, the load reduction and the boration.
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process allowed operators to monitor rather than control plant parameters.
Operators referred to the procedures in a step by step manner. The unit supervisor had
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distractions were kept to a minimum.
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Conclusions
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l-The inspector concluded that the Unit 1 shutdown was conducted in a planned and deliberate manner with substantial oversight provided by both operators and management. The quality and professionalism of plant operations was notabl.
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Operator Training and Qualification 05.1 Ooerator Outaae Preoaration Trainina a.
Insoection Scooe The inspectors reviewed the pre-outage operator training, including the lessons learned from previous outages and events, b.
Observations and Findinas The inspectors verified that specialized draindown evolution and outage "just in time" training was provided to the appropriate crews by the following training simulator scenarios:
LO44.G98.lPO, " Rapid Shutdown"
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LO44.G98.X05, "Cooldown to Solid Operations"
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The inspectors verified that the operating crews were trained and evaluated in fuel handling and refueling operations during the latest requalification cycle. The inspectors found that no specific midloop operational training was performed in the simulator.
fl. Maintenance M1 Conduct of Maintenance M1.1 General Comments in general, maintenance and surveillance activities were performed by knowledgeable individuals and were characterized as professional. The inspectois found the planning and preparation for the Unit 1 outage thorough and focused on plant and personnel safety. Some notable errors involving inadequate self and independent verification were identified by the licensee and are discussed in Section M4 below.
M1.2 Maintenance and Surveillance Observations (61726. 62707)
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Insoection Scoce The inspectors reviewed and/or observed the conduct of both plant surveillances and maintenance during the report period. The inspectors observed all or portions of the following work activities:
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Unit 1 Heater Drain System Design Modification
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Unit 2, Train B Safeguards Slave Relay K631 Actuation Test
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Unit 2 Channel Calibration of Neutron Flux Power Range N44
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l Replace Faulty Module in Solid State Isolation Cabinet, Train B
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-9-H The inspectors evaluated the following emergent surveillances which were conducted after untested contacts were found during the licensee's NRC Generic Letter 96-01,
" Testing of Safety-Related Logic Circuits," (GL 96-01) review:
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Unit 1, Train A Sequencer Load Actuation Test, Safety Chiller and Recirculation
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Pump 5 l
Unit 1 Train A Safety injection Sequencer Load Actuation Test, Safety Chiller
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and Recirculation Pump 5 i
Unit 1, Train B Sequencer Load Actuation Test, Safety Chiller and Recirculation
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Pump 6 l
Unit 1 Train B Safety injection Sequencer Load Actuation Test, Safety Chiller
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and Recirculation Pump 6 L
Unit 1 Train A Safety injection Sequencer Load Actuation Test, Auxiliary l
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l Feedwater Actuation to Split Flow Bypass Valves Unit 1, Train B Safety injection Sequencer Load Actuation Test, Auxiliary
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Feedwater Actuation to Split Flow Bypass Valves l
Unit 2, Train A Sequencer Load Actuation Test, Safety Chiller and Recirculation
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Pump 6 Unit 2, Train B Safety injection Sequencer Load Actuation Test, Safety Chiller
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and Recirculation Pump 6 Unit 2, Train A Solid State Safeguards Sequencer Blackout Actuation Test,
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Safety Chiller and Recirculation Pump 5
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Unit 2, Train B Solid State Safeguards Sequencer Blackout Actuation Test, Safety Chiller and Recirculation Pump 6 l
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' Observations and Findinas The inspectors found the work performed during the above activities well controlled and conducted in a professional manner. Pre-work briefings were timely and thorough.
Excellent three-way communications were observed throughout the performance of the L
work. Individual work groups reviewed the work steps and discussed the potential l,
consequences and apprordts responses. Operators and technicians performing the work read the steps aloud before performing them and demonstrated good self-verification. The inspectors observed technicians adhere to electrical safety precautions in an excellent manner. The interiors of cabinets were found clean and
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I-electrical terminations were well constructed.
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Surveillance procedures to test previously untested contacts which were identified during the licensee's GL 96-01 review were clearly written and concise. The inspector found that the licensee implemented the surveillance procedures in a well controlled manner consistent with previously observed conservative decision making. Each surveillance j
was evaluated by the licensee for it's potential risk to safe plant operations prior to being approved and all other surveillance activities involving any risk were canceled till completion of the emergent surveillance procedures. Operators appropriately entered the Technical Specification Limiting Condition for Operation (TS LCO) prior to conducting the surveillance and promptly exited the TS LCO when the surveillance was completed.
Inspection followup of the licensee's GL 96-01 findings will be continued as an Unresolved item (50-445(446)/9802-01).
M2 Maintenance and Material Condition of Facilities and Equipment M2.1 Materia! Condition a.
Insoection Scoce The inspector conducted periodic plant tours and reviewed equipment performance information to ascertain the condition of selected facilities and equipment.
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Observations and findinas i
During several thorough tours of the plant, the inspector found the condition of facilities and equipment to be excellent. Leakage of systems potentially containing contaminated liquid was maintained at a very low level. Valve packing and stems were clean and free of boron accumulation. What few leaks existed were properly controlled by a drip containment administratively tracked by the radiation protection department. Bearing lubrication systems were continuously maintained at the proper level by both operators l
and maintenance personnel. Small steam leaks were identified and repaired quickly before they could become safety hazards. Vibration of important equipment was
monitored frequently and equipment showing signs of degradation were monitored more frequently. The licensee's use of thermography to identify high resistance connections and degraded equipment prior to problem manifestation was notable.
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M4 Maintenance Staff Knowledge and Performance M4.1 Unit 1 Inadvertent Flux Doublina Actuation l
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Insoection Scooe (61726)
l The inspector reviewed the licensee's immediate and planned corrective actions i
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following an inadvertent source range nuclear instrument flux doubling actuation during switchyard operations.
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Observations and Findinos On March 21, during switching activities in the switchyard, an expected electrical transient resulted in a source range nuclear instrument flux dcubling actuation and an automatic boration of the Unit 1 reactor coolant system from the refueling water storage tank while in Mode 2 following a planned shutdown. Since ope rators had already
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planned to conduct an emergency boration soon after the source range nuclear instrument flux doubling actuation occurred, the impact to the plant was minimal.
Operators immediately restored the automatically repositioned valves, and shortly thereafter, the emergency boration was conducted as planned.
The inspectors reviewed the events leading up to the actuation and found that procedures did not adequately control switchyard activities to preclude the inadvertent automatic actuation of safety-related equipment. According to operations management, Glen Rose Transmission (GRT) personnel received authorization from the control room to enter the switchyard, but were instructed not to perform switching activities until they received specific authorization from the control room. The inspector was told by the i
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scheduled maintenance action response team (SMART) 2 manager, formerly the electrical maintenance manager, that GRT personnel contacted the load diepatcher about the switching activity and were given permission by the load dispatcher to proceed.
Without receiving authorization from the control room, the GRT personnel proceeded to perform the switching activity which caused the source range nuclear instrument flux doubling actuation.
Station Administrative Procedure (STA) 617, "High Voltage Switching and Clearance,"
Revision 4, states that, "high voltage switching activities should not be performed while in Mode 2 with the source range detectors (nuclear instruments) energized." The inspector found that the statement in STA 617 was treated as a note, not a required step, and as a result, the source range flux doubling activation was not bypassed prior to switching activities.10 CFR Part 50, Appendix B, * Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," Criterion V, " Instructions, Procedures, and Drawings," states " activities affecting quality shall be prescribed by documented-instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings."
Contrary to the above, STA 617 did not prescribe adequate instructions for the control of switching activities while in Mode 2 to preclude actuation of safety systems. This is a violation of 10 CFR Part 50, Appendix B, Criterion V (50-445/9802-02).
To ascertain if this licensee-identified violation met enforcement discretion criteria, the inspector reviewed the licensee's immediate and planned corrective actions and found them to be insufficient to preclude this event from recurring. Immediate corrective actions involved reinforcing management expectations with GRT personnel on governing
activities in the switchyard. Planned corrective actions included strengthening notes in procedures involving high voltage switching activities, plant shutdown, and operation of the ex-core nuclear instrument systems. The inspector was concerned that no absolute procedural controls were planned regarding switching in Mode 2 and discussed the
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I-12-concern with the operations support manager. The operations support manager indicated he would consider further enhancements to the procedures. The inspector will review the licensee's corrective actions following their response to the violation.
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Conclusions Switchyard activities were not adequately controlled. As a result, an inadvertent flux doubling activation occurred while in Mode 2. This occurred as a result of an inadequate
procedure. Other switchyard controlinadequacies have occurred and have been i
previously discussed in NRC Inspection Reports 50-445(446)/9504,50-445(446)/9527, end 50-445(446)/9720.
M4.2 Unit 1 inadvertent Removal of Wrono Source Rance Detector a.
Insoection Scooe (61726)
The inspector reviewed the licensee's immediate and planned corrective actions following an inadvertent withdrawal of the Unit 1, Train A source range nuclear
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instrument detector during activities supporting replacement of the Train B source range nuclear detector.
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Observations and Findinos With Unit 1 in Mode 4 on March 21, technicians were replacing the Train B source range nuclear instrument detector, and inadvertently racked out the Train A source range detector while the Train B source range instrument was out of service. This resulted in both trains of source range nuclear instrumentation being out of service for approximately 4 minutes. Technical Specification 3.3.1, " Reactor Trip System Instrumentation," requires that two channels of source range nuclear instruments be operable while in Modes 3,4, or 5. With one less than the minimum required channels, Technical Specifications require that the inoperable channel be restored within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />.
With no channels operable, a source range instrument must be restored within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />.
At the expiration of the allocated time limits, the Technical Specifications direct that the reactor trip breakers be opened and that all operations involving positive reactivity changes be suspended. The inspector reviewed the operator's response and concluded that the Technical Specification limiting conditions for operation were satisfied.
Technical Specification 6.8.1 requires that written procedures be established, implemented, and maintained as recommended by Appendix A of Regulatory Guide 1.33, Revision 2. Regulatory Guide 1.33, Revision 2, Section 9 specifies that procedures be developed for planning and performing maintenance that can affect the performance of safety-related equipment. Contrary to the above, the licensee failed to property implement maintenance procedures governing the replacement of the Unit 1, Train B source range nuclear detecto *
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The licensee's immediate corrective actions included restoring the Train A source range nuclear instrument to service, writing a Operations, Notification, and Evaluation (ONE)
Form, and counseling the technicians. The ONE Form was classified as a plant incident and a performance enhancement review committee meeting was appropriately held.
This issue will remain unresolved until the inspector completes a review of the licensee's corrective actions (50-445/9802-03).
M4.3 Unit 1 Switch Misoositionino Durina Solid State Protection System Testino a.
Insoection Scope (61726)
The inspector reviewed the licensee's immediate and planned corrective actions following an inadvertent mispositioning of a switch during reactor trip breaker response time testing.
b.
Observations and Findinas On March 21, during the performance of Unit i surveillance Procedure PPT-SI-99068,
" Reactor Trip Breaker Response Time Test, Train B," a Train B solid state protection system logic switch was incorrectly positioned. Step 8.4.3 directed the operator to position the logic test panel logic "A" selector switch to clockwise position seven. Both the operator and independent reviewer (test engineer) inadvertently read the step to position the logic test panel logic "C" selector switch to clockwise position seven. In Step 8.4.6, the logic test panel Channel ll and Channel ill manual input function test push
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. buttons were pushed to trip the reactor trip and bypass breaker. When the breakers
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@d to onen, the test was appropriately stopped.
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Test engineers reviewed the position of switches and found that they had inadvertently read Step 8.4.3 incorrectly. After carefully reviewing the status of the test, the logic "C"
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selector switch was retumed to it's correct position, and the test continued from Step 8.4.3 to it's satisfactory completion.
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Technical Specification 6.8.1 requires that written procedures be established, implemented, and maintained as recommended by Appendix A of Regulatory Guide 1.33, Revision 2. Regulatory Guide 1.33, Revision 2, Section 8 specifies that specific procedures for surveillance tests, inspections, and calibrations be written.
Contrary to the above, the inspector concluded that the licensee failed to follow the
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Unit 1 surveillance Procedure PPT-SI-99068, " Reactor Trip Breaker Response Time
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Test, Train B," Step 8.4.3.
The inspector reviewed the immediate corrective actions taken by management which included requiring written statements from all personnelinvolved, writing a ONE Form, and counseling the individuals on independent verification. The ONE Form was initially l
classified as a plant incident report which would have required a performance enhancement review committee review but was later reclassified as requiring a human j
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-14-performanca enhancement screen. After reviewing the circumstances, the inspector agreed with this decision and concluded that corrective actions were sufficient.
Therefore, 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 (50-445/9802-04).
M5 Maintenance Staff Training and Qualification MS.1 Fuel Handlina Trainina a.
Insoection Scone (62707. 92902)
l, On March 20, the inspector attended fuel handling training conducted by the licensee for all fuel handling supervisors and contractor personnel involved in the upcoming refueling outage in Unit 1. The inspector attended the training to evaluate the licensee's attempts to prevent fuel handling errors, b.
Observations and Findinas in the previous refueling outage in Unit 2, several fuel handling errors occurred as documented in inspection Report 50-445(446)/9720. These errors included damage to a new fuel assembly, core alterations conducted prior to establishing proper communications, and lowering a fuel assembly into a previously filled location.
The inspector found that the licensee had thoroughly addressed the areas of concem that had contributed to the previous outage errors. These included thoroughly defining each position's responsibilities, ensuring that the contractor's communications met the-licensee's standards, and that the licensee's and contractors fuel handling procedures were consistent with each other. Additionally, the licensee made equipment modifications to allow better control during fuel handling operations.
M7
_ Quality Assurance in Maintenance Activities
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M7.1 Human Performance Imorovements a.
Insoection Scone (62707)
The inspector reviewed the licensee's efforts to improve human performance during the new fuel receipt process following a number of precursor type events.
l b.
Observations and Findinas On February 17, during new fuel receipt and inspection, tension applied to fuel assembly J-15 prior to loosening the top and bottom clamping frames exceeded the 100 to 500 pounds specified in Procedure RFO-201, " Receipt, inspection, and Storage of New Fuel and Insett Core Components," by approximately 800 pound.
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The licensee wrote ONE Form 98-201 to document the issue and the work control review initially classified the ONE Form as requiring a deficiency and engineering resolution assigned to the nuclear engineering department. The deficiency resolution (DR) closure was assigned to the SMART Team 3 manager, formerly the mechanical maintenance manager, and the engineering resolution (ERR) was assigned to a nuclear engineer. A deficiency resolution is used for conditions that constitute deficiencies or violations of L
procedures which did not render the quality of an item unacceptable and do not require a root cause determination.
On February 23, during new fuel receipt and inspection, a 1-1/4 inch socket came off the impact wrench and landed on the top grid strap of a new fuel assembly. The damage to L
the new fuel assembly was minor and was later determined to not preclude use in the Unit 1 reactor.
The licensee wrote ONE Form 98-220 to document the issue and the work control review initially classified the ONE Form as one requiring a deficiency resolution assigned to the nuclear engineering department.
Following the second event, the SMART Team 3 manager conducted an informal performance enhancement meeting and found several issues. He found inat the hoist operators and nuclear engineers involved in new fuel receipt were aware that it was easy
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and fairly common to slightly exceed the torque limits prescribed in Procedure RFO-201, and that the 1-1/4 inch socket fel! off the impact wrench all the time. The inspectors found the SMART Team 3 managers efforts to understand the root causes of the incidents good.
l The inspector reviewed the abovementioned ONE Forms and found that ONE
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Form 98-201 had been closed and ONE Form 98-220 was still open. A review of the closure information for ONE Form 98-201 revealed that there was no mention of the findings made by the SMART Team 3 manager as expected. Instead, under the generic implications column, the inspector found the statements, "This is an isolated case." and
"No further action is required." The inspector discussed these findings with the nuclear engineering manager who was responsible for closing the ONE Form. The nuclear engineering manager indicated that corrective actions included reemphasizing the
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expectations that nuclear engineers do not have the authority to authorize deviations i
from procedures and changing the procedure to give the hoist operators a larger band.
i The nuclear engineering manager indicated that he would include these corrective
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l actions in the closure of ONE Form 98-220.
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The failure to follow Procedure RFO-201, was contrary to the requirements contained in.
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Technical Specification 6.8.1 which states, in part, that written procedures be established, implemented, and maintained as recommended by Appendix A of Regulatory Guide 1.33, Revision 2. Regulatory Guide 1.33, Revision 2, Section 9, specifies that procedures be developed for planning and performing maintenance that can affect the performance of safety-related equipment. This is a l
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violation (50-445/9802-05). The inspectors will review the licensee's overall corrective actions following their response to the violation.
l Ill. Engineering E1 Conduct of Engineering l
E1,1 General Comments The inspectors focused on the engineering support of continued plant operations and the evaluation of degraded plant conditions identified in ONE Forms. Overall, the inspectors noted that engineering adequately supported the continued safe operation of the facility
- and the sixth Unit i refueling outage in a professional and technically correct manner.
Several ONE Forms were reviewed by the inspectors during the report period and no notable performance issues were identified.
E4 I
Engineering Staff Knowledge and Performance
' E4.1 - Unit 1 Safety Iniection Pumo Operation a.'
Insoection Scooe (37551)
The inspector reviewed the effectiveness of corrective actions implemented by the licensee to address emergency core cooling system check valve leakage and its impact on both Units 1 and 2.
b.
Observations and Findinas in NRC Inspection Reports 50-445(446)/9610, 50-445(446)/9617, and 50-445(446)/9705, the inspector discussed various aspects of the emergency core cooling system check valve leakage issues. These issues involved licensee identified and corrected weaknesses in check vane maintenance, temporary modifications to reduce emergency core cooling cystem pressure, inspector identified weaknesses in communicating compensatory measures to operators, and an inspector observation that the excessive operation of safety injection pumps to refill safety injection accumulators because of the leakage was a necessary challenge to safety equipment. All of these issues, with the exception of the safety. injection pump motor cycling, had been adequately corrected by l
the licensee and evaluated by the inspectors.
u During a review of outage plans, the inspector noted that no additional safety injection pump maintenance.was scheduled for the sixth Unit 1 refueling outage. The inspector was concerned that the impact of excessive cycling of the Unit 1 safety injection pumps would require additional maintenance. Each pump had been started approximately 560 times during the past cycle. In addition, Cycle 6 of Unit 1 was not the only time the safety injection pumps were routinely started to refill safety injection accumulators because of (
' leaking check valves.' The inspector asked the licensee how many times the safety L
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The inspector reviewed the equipment qualification data packages for the safety injection pump, the safety injection pump motor, and certain safety injection system motor-operated valves. The inspector found that the equipment qualification data :
package for the Westinghouse " Life Line D" motor (EEQSP-AE-2-01, Revision 3), which j
is used for the residual heat removal, charging and safety injection pumps, specified that the most limiting case was 1992 start cycles for the charging pump motor.
The basis for the 1992 start cycles was contained in the plant specific cycling requirement Calculation (lMT-CYCLE-133) which analyzed the total number of starts for pre-operational testing, normal plant @ rations, operability testing, refueling operatior's, maintenance, and design bases accident cycling requirements, and added a 10 percent
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. margin. The inspector noted that the design basis assumptions in the normal plant operations portion of the analysis stated, in part, that "the charging pumps may be conservatively operated twice a month." Therefore, the total numuar of analyzed starts during normal operations would be 960. This inspector was concuned that when the number of starts during previous operating cycles were added to the estimated 560 starts i
during Unit 1, Cycle 6, the number of safety injection pump motor starts may exceed their
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design basis assumptions.
i Section 2.4 of FSAR Appendix 3A states that, "this equipment shall be replaced before their qualified lives expire. As an attemative to replacement, it may be possible to extend i
qualified lives through additional testing or analysis." The licensee failure to identify that they were potentially operating the safety injection pump motors outside their design basis assumptions and to take the appropriate corrective actions was a violation of J
10 CFR Part 50, Appendix B, Criterion XVI (50-445(446)/9802-06).
10 CFR 50.49 states, in part, that "Each holder of... a license for a nuclear power plant,... shall establish a program for qualifying... electric equipment."
10 CFR 50.49(e)(5) states, in part, " equipment must be replaced or refurbished at the
. end of this designated life unless ongoing qualification demonstrates that the item has additional life." The inspector reviewed the licensee's procedures for the equipment I
qualification program and found no procedural requirements to review changes in postulated service conditions of equipment or any requirements to track the number of cycles. The inspector considered the lack of provisions to identify when equipment was being operated under service conditions beyond those specified in their design bases and predict when they would need to be replaced, refurbished, or requalified, a program weakness.
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Conclusions The licensee failed to identify that operation of the safety injection pump motors was not consistent with their design bases during check valve leakage corrective actions. The licensee's equipment qualification program did not contain provisions to predict when equipment that was being operated at increased service conditions would need to be replaced, refurbished, or requalif ed. This was a program weakness.
IV. Plant Suonort P2 Status of Emergency Planning Facilities, Equipment, and Resources P2.1 Access to the Technical Sucoort Center a.
Insoection Scooe (71750)
The inspector performed a routine tour of the technical support center and assessed the condition of the facility and equipment. During the tour, the inspector identified a seismic concern which could have resulted in an inability to occupy the technical support center.
The inspector reviewed the licensee's corrective actions.
b.
Observations and Findinos While touring the technical support center on February 27, the inspector identified that the bookshelves located in the hallway that leads to the technical support center were not securely fastened to the floor or wall. These bookshelves were approximately the same height as the width of the hallway, and during a seismic event, could have fallen and blocked the door providing access to the hallway. Since this is the only door which provides access to the technical support center, a seismic event could have precluded entry. The licensee wrote a ONE form and immediately removed the bookshelves.
The licensee also identified that the bookshelves and lockers, also in the hallway, could fall and hit Class 1E conduit and that the placement of these items did not meet the requirements of Procedure STA-661,"Non-Plant Equipment Storage and Use inside Seismic Category l Structures." The lockers were moved from the vicinity of the conduit.
Since the bookshelves contained the technical reference manuals, which may be needed during the response to an emergency, the inspector verified that the manuals were still within the vicinity of the technical support center. The inspector found that the manuals r
I were located in an adjacent room.
c.
Conclusions Unsecured bookshelves, placed in front of the access door leading to the technical support center, could have fallen during a seismic event. The licensee's response to the seismic concem was prompt and appropriate.
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R1 Radiological Protection and Chemistry Controls R1.1 General Comments The inspectors observed good radiological practices being implemented by all plant personnel. Workers were familiar with their radiological work permit requirements.
R4
' Staff Knowledge and Performance R4.1 Removal of Locks from Containment Access Hatches
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a.
Insoection Scone (71750)
I The inspector determined whether the radiation protection manager's decision to remove the locks from the Unit 1 and Unit 2 conteinment access hatches complied with plant l
. Technical Specification 6.12.2.
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Observations and Findinos On March 6, the radiation protection manager informed the inspector that he had the locks removed from the Unit 1 and Unit 2 containment access hatches for personnel
i safety reasons several days earlier. The inspector immediately questioned whether the l
decision was appropriate because plant Technical Specification 6.12.2 stated, in part,
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that areas accessible to individuals with radiation levels greater than 1000 mrem /hr at -
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30 centimeters (12 inches) but less than 500 rads in one hour at one meter from the -
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i-radiation source or from any surface which the radiation penetrates shall be provided i
with locked doors to prevent unauthorized entry.
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The inspector found that both the Unit 1 and Unit 2 containment buildings contained
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areas that met or exceeded the above radiation levels. In addition, the licensee posted both containment buildings as locked high radiation areas. The inspector concluded that.
removing the locks from the Unit.1 and Unit 2 containment hatches, which were doors j
capable of being locked, from March 3 to March 6, was a violation of Technical l
Specification 6.12.2. (50-445(446)/9802-07)
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Quality ' ssurance in Radiological Protection and Chemistry issues R7 A
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R7.1 Unit 1 Refuelino Outaae Crud Burst and Cleanuo
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Insoection Scooe i
The inspector reviewed the crud burst management efforts and its affect on maintaining i
dose as low as reasonably achievable (ALARA).
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Observations and Findinas
- The licensee performed a controlled crud burst following the shutdown of Unit 1 for the
. sixth refueling outage. The crud burst cleanup was a critical path activity which delayed securing reactor coolant pumps and the remaining part of the outage work. On
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March 25, already slightly behind projected outage schedules, reactor coolant Cobalt-58 l
activity was approximately 2 micro-curies per milliliter and decreasing slowly._ The goal
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was to secure reactor coolant pumps when the Cobalt-58 activity reached 1 micro-curie.
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per milliliter. Outage management recommended that the cleanup time be extended in
order to add additional hydrogen peroxide because no dissolved oxygen or hydrogen peroxide residual was being measured. This was indicative of additional nickel inventory present in the reactor coolant which was consuming the dissolved oxygen. The unexpected nickel was believed to be a result of a hydrogen concentration fluctuation, which occurred after the reactor coolant system was placed in a solid condition. Nickel is i
a major contributor to the radiation dose in the plant.
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Conclusion The inspector concluded that the management decision to continue the crud burst l
cleanup was an example of conservative decision making and would, in the long run, help maintain dose ALARA.
S1 Conduct of Security and Safeguards Activities j
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Throughout the inspection period, the inspectors observed alert security officers j
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February 25, the inspectors noted that many security cameras were adversely affected.
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The inspectors observed security personnel appropriately respond as required by the -
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security plan.~
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V. Management Meetings
X1 Exit Meeting Summary -
The inspectors presented the results of the inspection to licensee management on March 31,1998.~ The licensee' disagreed that the safety injection pump motor issue described -
in Section E4 above was a violation. The licensee believed that since it was not known
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that they had exceeded the qualified number of cycles, no violation existed. The L
- inspector reiterated that the violation was not because they had exceeded the qualified L
. life of the safety injection pump motor but because their corrective actions failed to -
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recognize that they were operating the motor inconsistent with their' design basis._ No j
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proprietary information was identified.
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ATTACHMENT SUPPLEMENTAL INFORMATION PARTIAL LIST OF PERSONS CONTACTED Licensee M. R. Blevins, Vice President, Nuclear Operations J. R. Curtis, Radiation Protection Manager S. L. Ellis, Smart Team 1 Manager M. L. Lucas, Maintenance Manager j
D. R. Moore Operations Manager D. J. Reimer, Technical Support Manager i
C. L. Terry, Senior Vice President and Principal Nuclear Officer R. D. Walker, Regulatory Affairs Manager i
INSPECTION PROCEDURES USED IP 37551 Onsite Engineering IP 61726 Surveillance Observations IP 62707 Maintenance Observations IP 71707 Plant Operations IP 71750 Plant Support Activities IP 92901 Followup - Plant Operations IP 92902 Followup - Maintenance IP 93702 Prompt Onsite Response To Events At Operating Power Reactors ITEMS OPENED AND CLOSED Ooened 50-445(446)/9802-01 URI Untested contacts identified during licensee's NRC Generic Letter 96-01, " Testing of Safety-Related Logic Circuits."
50-445/9802-02 VIO Inadequate control of switchyard activities.
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50-445/9802-03 URI Inadvertent removal of source range detector dunng maintenance.
50-445/9802-04 NCV Inadvertent switch misposition during solid state protection system testing.
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t 50-445/9802-05 VIO Tension applied to fuel assembly during new fuel receipt exceeded procedural limits.
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50-445(446)/9802-06 VIO Inadequate corrective actions resulting in failure to identify potential operation of the safety injection pump motor outside its design basis.
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50-445(446)/9802-07 VIO Failure to control a locked high radiation area in accordance with technical specification requirements due to removal of containment l
access hatch locks for three days.
Closed 50-445/9802-04 NCV inadvertent switch misposition during solid state protection system testing.
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